OCS Report

MMS 98-0032

Outer Continental Shelf

Estimated Proved and Unproved

Oil and Gas Reserves,

Gulf of Mexico,

December 31, 1996

Suzan M. Bacigalupi

Barbara J. Bascle

Clark J. Kinler

Michael T. Prendergast

Resource Evaluation Office

Reserves Section

U.S. Department of the Interior

Minerals Management Service New Orleans

Gulf of Mexico OCS Regional Office June 1998

iii

Contents

Abstract, v

Introduction, 1

Definition of Resource and Reserve Terms, 1

Reference Standard Conditions for Production and Reserves, 3

MMS Reporting of Reserve and Resource Data, 3

Methods Used for Estimating Reserves, 4

Reserves and Related Data Reported by Area, 5

Reserves Reported by Geologic Age, 8

Historical Exploration and Discovery Pattern and Trends, 12

Field-Size Distribution, 15

Reservoir-Size Distribution, 18

Production Rates and Discovery Trends, 20

Summary and Comparison of Proved Reserves, 23

Conclusions, 24

Contributing Personnel, 24

References, 25

Figures

1. MMS conventionally recoverable petroleum resource classifications, 1

2. Gulf of Mexico MMS reserve classifications, 1

3. MMS reporting of reserves and resources, 3

4. Western Planning Area, Gulf of Mexico, Outer Continental Shelf, 5

5. Central Planning Area, Gulf of Mexico, Outer Continental Shelf, 5

6. Eastern Planning Area, Gulf of Mexico, Outer Continental Shelf, 5

7. Gulf of Mexico, 920 proved fields (749 active and 171 depleted), 7

8. Gulf of Mexico, 85 unproved active fields (52 studied and 33 not studied), 8

9. Gulf of Mexico MMS geologic time scale, 8

10. Pleistocene production trend, 10

11. Pliocene production trend, 10

12. Miocene production trend, 12

13. Oligocene, Cretaceous, and Jurassic production trends, 12

14. Distribution of reserves and production data by geologic age, 12

15. Location of proved fields discovered 1947-1959, Gulf of Mexico OCS, 13

16. Location of proved fields discovered 1960-1969, Gulf of Mexico OCS, 13

17. Location of proved fields discovered 1970-1979, Gulf of Mexico OCS, 13

18. Location of proved fields discovered 1980-1989, Gulf of Mexico OCS, 14

19. Location of proved fields discovered 1990-1996, Gulf of Mexico OCS, 14

20. Annual number of field discoveries by geologic age, 920 proved fields, 14

21. Annual discoveries of original proved reserves by geologic age, 920 proved fields, 14

22. Description of deposit-size classes, 15

23. Field-size distribution of proved fields: (a) 920 fields, GOM; (b) 271 fields, 

Western GOM; (c) 649 fields, Central GOM, 16

24. Field-size distribution of proved oil fields: (a) 164 fields, GOM; (b) 18 fields,

Western GOM; (c) 146 fields, Central GOM, 16

25. Field-size distribution of proved gas fields: (a) 756 fields, GOM; (b) 253 fields, 

Western GOM; (c) 503 fields, Central GOM, 16

26. Field-size distribution of unproved fields: (a) 52 fields, GOM; (b) 26 oil fields, GOM; 

(c) 26 gas fields, GOM, 16
iv

27. GOM field-size distribution, 17

28. Cumulative percent total reserves versus rank order of field size for 920 proved fields, 17

29. Field and reserves distribution by water depth, 17

30. Largest 20 fields based on remaining proved reserves, 17

31. Reservoir-size distribution, 1,562 proved combination reservoirs, 18

32. Reservoir-size distribution, 6,944 proved oil reservoirs, 18

33. Reservoir-size distribution, 12,029 proved gas reservoirs, 18

34. Monthly distribution of oil production, 3,313 completions, (2,367) continuously 

producing completions, 20

35. Monthly distribution of gas production, 3,230 completions, (2,359) continuously 

producing completions, 20

36. Monthly completion and production data, 20

37. Annual oil and gas production, 21

38. Proved reserves and production by field discovery year, 21

39. Annual number of proved oil and gas field discoveries, 21

40. Number of proved fields and mean field size by field discovery year, 22

41. Number of fields and mean water depth by field discovery year, 22

42. Proved oil reserves by reservoir discovery year and annual oil production, 22

43. Proved gas reserves by reservoir discovery year and annual gas production, 22

44. Wells and footage drilled, 23

45. Number of exploratory wells drilled by water depth, 23

Tables

1. Estimated oil and gas reserves for 920 proved and 52 unproved fields by area, 

Gulf of Mexico, Outer Continental Shelf, December 31, 1996, 6

2. Status of oil and gas leases, boreholes, and completions by area, Gulf of Mexico, 

Outer Continental Shelf, December 31, 1996, 7

3. Estimated oil and gas reserves for 920 proved and 52 unproved fields by geologic age,

Gulf of Mexico, Outer Continental Shelf, December 31, 1996, 9

3a. Estimated oil and gas reserves for Pleistocene reservoirs in 478 proved and 23 unproved 

fields by area, Gulf of Mexico, Outer Continental Shelf, December 31, 1996, 9

3b. Estimated oil and gas reserves for Pliocene reservoirs in 262 proved and 15 unproved 

fields by area, Gulf of Mexico, Outer Continental Shelf, December 31, 1996, 10

3c. Estimated oil and gas reserves for Miocene reservoirs in 466 proved and 23 unproved 

fields by area, Gulf of Mexico, Outer Continental Shelf, December 31, 1996, 11

3d. Estimated oil and gas reserves for Oligocene, Cretaceous, and Jurassic reservoirs in 

12 proved and 3 unproved fields by area, Gulf of Mexico, Outer Continental Shelf, 

December 31, 1996, 11

4. Gulf of Mexico fields by rank order, based on original proved BOE reserves, top 60 fields, 19

5. Summary and comparison of proved oil and gas reserves as of December 31, 1995, 

and December 31, 1996, 23

6. Proved oil and gas reserves and cumulative production at end of year, Gulf of Mexico,

Outer Continental Shelf and Slope, 24
*The term "oil" as used in this report includes crude oil and condensate.

v

Abstract

Remaining proved reserves in the Gulf of Mexico Outer Continental Shelf (OCS) as of

December 31, 1996, have been estimated to be 2.74 billion barrels of oil* and 29.4 trillion

cubic feet of gas. These reserves are recoverable from 749 proved active fields. Unproved

reserves as of December 31, 1996, have been estimated to be 1.00 billion barrels of oil and

3.7 trillion cubic feet of gas. These reserves are associated with 52 unproved active fields.

There are 33 unproved active fields not studied. This makes a total of 834 active fields

located in Federal waters.

Original proved reserves are estimated to have been 12.79 billion barrels of oil and 151.9

trillion cubic feet of gas from 920 proved fields in the same geographic area. Included in

this number are 171 fields that are depleted and abandoned; not included are the 85

unproved active fields. Estimates were made for individual reservoirs based on geologic

mapping and reserve evaluation.

The unproved reserves, associated with the 52 unproved active fields, are not added to

proved reserves because of different levels of economic certainty and hydrocarbon

assurance. For any field contained partly in State waters and partly in Federal waters,

reserves are estimated for the Federal portion only.

Unproved Proved

Increasing Hydrocarbon Assurance and Economic Certainty

Resources

Possible Undeveloped

Reserves Reserves

Proved

Developed

Reserves

Unproved

Probable

Reserves

*Development Operations Coordination Document

30 CFR 250.11

Known

D.O.C.D.* Application

Platform

Equipment Installed

Transportation

Production and

Estimated Unproved Reserves Original Proved Reserves

(Modified from various sources)

Undiscovered 

 Resources

Proved Reserves

Increasing Hydrocarbon Assurance

Increasing Economic Certainty

Unknown

 Undrilled

Prospects

 Known

Resources

Possible Probable Undeveloped

Developed

Nonproducing

Economically 

 Recoverable 

Uneconomic

Producing

Discovered Resources 

Unproved

 Reserves

Known

1

Figure 2.C Gulf of Mexico MMS reserve

classifications.

Introduction

This report, which supersedes the Minerals Management

Service (MMS) OCS Report MMS 96-0061 (Bacigalupi

and others, 1996), presents original proved reserves,

cumulative production, remaining proved reserves, and

unproved reserves as of December 31, 1996, for the Gulf

of Mexico (GOM). This report does not consider the

reserves growth phenomena when addressing remaining

proved reserves. A discussion of reserves growth can be

found in OCS Report MMS 96-0047 (Lore and others,

1996). The estimates of reserves for this report were

completed in December 1997 and represent the combined

efforts of engineers, geologists, geophysicists,

paleontologists, and other personnel of the MMS Gulf of

Mexico Region, Office of Resource Evaluation, in New

Orleans, Louisiana.

As in previous reports, standard methods of estimating

reserves were used, including volumetric calculation and

performance analyses.

Definition of

Resource and Reserve Terms

The MMS definitions and classification schema

concerning reserves reflect those of the Society of

Petroleum Engineers (SPE) and the World Petroleum

Congress (WPC), 1996. SPE definitions have been used

since 1988. The MMS definitions and classification

schema concerning resources are modified as referenced

by the U.S. Department of the Interior (DOI), 1989. The

MMS petroleum resource and reserve classifications are

presented in figures 1 and 2.

Figure 1.C MMS conventionally recoverable

petroleum resource classifications.

Field

A field is an area consisting of a single reservoir or

multiple reservoirs all grouped on, or related to, the same

general geological structural feature and/or stratigraphic

trapping condition. There may be two or more reservoirs

in a field that are separated vertically by intervening

impervious strata, or laterally by geological barriers, or

both. The area may include one OCS lease, a portion of

an OCS lease, or a group of OCS leases with one or more

wells that have been approved as producible by the MMS

pursuant to the requirements of Title 30 Code of Federal

Regulations (CFR) 250.11, Determination of Well

Producibility. A field is usually named after the area and

block on which the discovery well is located. Field names

or field boundaries may be changed when additional

geologic and/or production data support such a change.

Using geological criteria, the MMS designates a new

producible lease as a new field or assigns it to a

preexisting field. A further explanation of field naming

convention can be found on page 5 and in the Field

Naming Handbook available on the Gulf of

Mexico Region*s Internet homepage at

http://www.gomr.mms.gov. 

Undiscovered Resources

Hydrocarbons estimated on the basis of geologic

knowledge and theory to exist outside of known

accumulations are undiscovered resources.

Undiscovered resources can exist in prospects (unleased

acreage and undrilled leased acreage) or in known fields

(undrilled reservoirs).

Discovered Resources

Hydrocarbons whose location and quantity are known or

estimated from specific geologic evidence are discovered

resources. Discovered resources include known
2

resources, unproved reserves, and proved reserves

depending upon economic, technical, contractual, or

regulatory criteria.

Known Resources

Hydrocarbons associated with reservoirs penetrated by

one or more wells that are not currently qualified under

the MMS regulations as capable of producing in paying

quantities pursuant to 30 CFR 250.11 are known

resources. Known resources can exist on active,

relinquished, or expired leases and fields.

Reserves

Those quantities of hydrocarbons which are anticipated to

be recovered from known accumulations from a given

date forward are reserves. All reserve estimates involve

some degree of uncertainty. The uncertainty depends

chiefly on the amount of reliable geologic and engineering

data available at the time of the estimate and the

interpretation of these data. The relative degree of

uncertainty may be conveyed by placing reserves into one

of two principal classifications, either unproved or

proved.

Unproved Reserves

Those quantities of hydrocarbons which can be

estimated with some certainty to be potentially

recoverable from known reservoirs, assuming future

economic conditions and technological developments,

are unproved reserves. The MMS Gulf of Mexico

Regional Field Names Committee designates a new

producible lease as a new field or assigns it to a

preexisting field. The reserves associated with new

producible leases qualified pursuant to 30 CFR

250.11 are initially considered unproved reserves.

Unproved reserves are less certain to be recovered

than proved reserves and may be further subclassified

as possible and probable reserves to denote

progressively increasing certainty in their

recoverability. This report does not present

individual estimates for possible and probable

reserves.

Unproved possible reserves are those

unproved reserves which analysis of geological

and engineering data suggests are less likely to

be commercially recoverable than probable

reserves. After a well on a lease qualifies, the

reserves associated with the lease are initially

classified as unproved possible because the only

direct evidence of economic accumulations is a

production test or electric log analysis.

Unproved probable reserves are those

unproved reserves which analysis of geological

and engineering data suggests are more likely

than not to be commercially recoverable. Fields

that have a Development Operations

Coordination Document (DOCD) on file with the

MMS would be classified as unproved probable.

Proved Reserves

Those quantities of hydrocarbons which can be

estimated with reasonable certainty to be

commercially recoverable from known reservoirs and

under current economic conditions, operating

methods, and government regulations are proved

reserves. Establishment of current economic

conditions includes consideration of relevant

historical petroleum prices and associated costs and

may involve an averaging period that is consistent

with the purpose of the reserve estimate. Proved

reserves must have either facilities operational at the

time of the estimate to process and transport those

reserves to market, or a commitment or reasonable

expectation to install such facilities in the future.

The application for a permit to install a platform is

considered such a commitment. Proved reserves can

be subdivided into undeveloped or developed.

Proved undeveloped reserves exist where

there is a relatively large expenditure required to

install production and/or transportation facilities

and a commitment has been made by the

operator to develop the field. Proved

undeveloped reserves are reserves expected to be

recovered from yet undrilled wells or from

existing wells where a relatively large

expenditure is required for field development.

Proved developed reserves are expected to be

recovered from existing wells (including reserves

behind pipe). Reserves are considered developed

only after the necessary production and

transportation equipment has been installed, or

when the costs to do so are relatively minor.

Proved developed reserves are subcategorized as

producing or nonproducing. This distinction is

made at the reservoir level.

PROVED DEVELOPED PRODUCING

reserves are in reservoirs that have produced

any time during the 12 months before the

reporting date. Once the first reservoir in
Reservoir

Sand

Reporting /

Evaluation

 Level

Pool

Play

Chronozone

Area

Undiscovered

 Resources Discovered Resources 

Proved

Reserves

Unproved

 Reserves Unknown Known Known

Resources

Increasing Hydrocarbon Assurance and Economic Certainty

Field

Reservoir

Progressively aggregated Geologically

Series

System

Gulf of Mexico

Region

Planning

Area

Offshore Atlas

MMS Internal Field Studies

National 

Assessment

Progressively aggregated Geographically

 Estimated Proved and 

Unproved Oil and Gas

 Reserves 

MMS Internal Field Studies

3

Figure 3.C MMS reporting of reserves and

resources.

a field begins production, the reservoir and through the region level). The most detailed studies of

the field are considered proved developed discovered resources are MMS individual field studies.

producing. These studies are based on analysis at the reservoir level

PROVED DEVELOPED NONPRODUCING

reserves are in reservoirs that have not

produced during the 12 months prior to the

reporting date. This category includes offproduction reservoirs behind pipe and

reservoirs awaiting workovers or

transportation facilities. If all reservoirs in

a field are off production, the field is

considered proved developed nonproducing.

Reference Standard Conditions

for Production and Reserves

Production data are the metered volumes of raw liquids

and gas reported to the MMS by Federal unit and lease

operators. Oil volume measurements and reserves are

corrected to reference standard conditions of 60 °F and

one atmosphere (14.696 pounds per square inch absolute

[psia]); gas measurements and reserves are corrected to

60 °F and 15.025 psia. To convert gas volumes to

14.696 psia, multiply by 1.022 (DOE, 1989).

Continuously measured volumes from production

platforms and/or leases are allocated to individual wells

and reservoirs on the basis of periodic well test gauges.

These procedures introduce approximations in both

production and remaining reserves data.

MMS Reporting of 

Reserve and Resource Data

OCS reserve estimates have been published by the Gulf

of Mexico Region annually since 1977, presenting endof-year totals starting with 1975. From 1977 to 1981 the

estimates were published as United States Geological

Survey (USGS) Open-File reports. The 1982 report was

a joint publication between the USGS and the newly

formed MMS, which assumed the OCS mission

responsibilities at that time. The MMS has continued the

reporting since 1983. The first report provided by the

MMS that also includes unproved reserve estimates was

published in 1995. 

Figure 3 shows the relationship of evaluated data to

hydrocarbon assurance. The data are progressively

aggregated on both a geologic and a geographic basis at

each step of the evaluation process (the reservoir level

(an example being a single fault trap in a single sand) and

are used as the basis for the reporting of discovered and

undiscovered resources. The geologic aggregation begins

at the top of the figure at the reservoir level and

progresses downward through the sand, pool, play,

chronozone, series, and system to the regional level.

Reservoirs correlated to a specific sand are aggregated to

form the sand reporting level, which becomes the basis

for further aggregations of data. A play is defined

primarily (though not exclusively) by depositional style,

geologic age at the chronozone level, and geographic area.

Pools are based on the same characteristics of a play, but

are specific to an individual field. Fields may contain one

or more pools, with each pool representing a separate

play. The geographic aggregation begins at the bottom of

the figure, also at the reservoir level, and progresses

upward through the field, area, and planning area to the

regional level.

This report, Estimated Proved and Unproved Oil and

Gas Reserves, presents reserve data from the field level

up to the series level. This report is based on aggregation

of MMS internal field studies completed at the reservoir
4

and sand levels. All of the reservoir level data have been the reserve estimate. As a field is depleted and

linked to the sand, pool, play, chronozone, and series level abandoned, the original proved reserves are assigned a

to support the Offshore Atlas Project (OAP). value equal to the amount produced. Currently, there are

The Atlas of Northern Gulf of Mexico Gas and Oil

Reservoirs, Volume 1: Miocene and Older Reservoirs

and Volume 2: Plio-Pleistocene Reservoirs, released in

1997, provide a detailed geologic reporting of oil and gas

proved reserves. Reserve data on every productive sand,

as of December 1994, have been placed into 72 proved

geological plays in Federal waters. This was the first

MMS release of such a comprehensive framework of

geologic and reserve data and the associated attributes for

each specific chronozone, play, pool, and sand. Series

and system levels can also be evaluated with the data

provided.

The MMS Summary of the 1995 Assessment of

Conventionally Recoverable Hydrocarbon Resources

of the Gulf of Mexico and Atlantic Outer Continental

Shelf, also known as the National Assessment, addresses

undiscovered resources. To maintain credibility, an

estimate of undiscovered resources must be based on

discovered resources. The OAP supported this report by

providing a framework of hydrocarbon plays that allowed

for the logical extension of existing production rather

than just a conceptual estimate. This summary report,

made available in August 1996, contains resource

estimates at the chronozone, series, system, and province

(era) levels by planning area, water depth, and region. A

more detailed report with resource estimates at the play

level will be released in 1998.

For information on these reports, contact the Gulf of

Mexico Region*s Public Information Office at 1-800-

200-GULF or 504-736-2519, or visit the GOM Region*s

Internet homepage at http://www.gomr.mms.gov.

Methods Used for

Estimating Reserves

Reserve estimates from geological and engineering

analyses have been completed for the 920 proved fields.

Reserves accountability is dependent on the drilling and

development phases of fields. When a field is in the

unproved category, geophysical mapping and limited well

data are the basis for defining reservoir limits. Once a

field is moved into the proved category and more data

become available, the reserve estimate is re-evaluated.

Well logs, well file data, seismic data, and production

data are continually analyzed to improve the accuracy of

171 depleted and abandoned fields.

Estimation of reserves is done under conditions of

uncertainty. The method of estimation is called

deterministic if the estimate is a single "best estimate"

based on known geological, engineering, and economic

data, and probabilistic when the known geologic,

engineering, and economic data are analyzed

probabilistically and the estimate determined from

continuous probability distributions (SPE/WPC, 1996).

Reserve estimates in this report are deterministic. 

Methods used for estimating reserves can be categorized

into three groups: analog, volumetric, and performance.

The accuracy of the original proved reserve estimate

improves as more reservoir data become available to

geoscientists and engineers. Resources are based on

analogy with similar fields, reservoirs, or wells in the

same area. Reserve estimates in this report are based

primarily on volumetric and performance methods.

Analog

In the estimation of resources by analogy, geoscientists

use seismic data to generate pictures of the size and shape

of subsurface formations. Before any wells have been

drilled on a prospect, estimates of undiscovered resources

are based on analogy with similar fields, reservoirs, or

wells in the same area. The seismic data help

geoscientists identify prospects, but do not provide

enough direct data to estimate resources. The effective

pore space, water saturation, net hydrocarbon thickness,

pressure, volume, and temperature data, necessary to

complete resource estimates for prospects, come from

nearby field and reservoir well data. After one or more

wells are drilled and found productive, a volumetric

estimate is done. Resource estimates are not included in

this report. 

Volumetric

In a volumetric reserve estimate, data from drilled wells

and seismic surveys are used to develop geologic

interpretations. The effective pore space (porosity), water

saturation, and net hydrocarbon thickness of the

subsurface formations are calculated through evaluation

of well logs, core analysis, and formation test data.

Subsurface formations are mapped to determine area and

net hydrocarbon thickness for each reservoir. Reservoir

pressure, fluid volume, and temperature data from
East Breaks Garden Banks

Alaminos Canyon Keathley Canyon

NG 15-8 

High

Galveston

Brazos

Matagorda

Mustang

North

Padre

Island

Corpus

Island

Island

Island

Christi

South

Padre

Island

 Port

 Isabel

T E X A S 

N

G U L F O F M E X I C O

Galveston

Christi

Corpus

Sabine

Pass

o

o

Cameron

Ship South

Timbalier

Grand

Isle

West

DeltaSouth

Pass

Main

Pass

Breton

Sound

Chandeleur

Mobile

Viosca 

Green 

Canyon

Lund

NG 15-9 NG 16-7

South

Pelto

New Orleans

LOUISIANA

MISSISSIPPI

Lake 

Charles

N

Sabine 

Pass

ALABAMA

G U L F O F M E X I C O

Viosca

Knoll

Marchand

Bay

Mississippi 

Canyon

Ewing 

Bank

Atwater

Knoll(Slope)

Walker 

Ridge

Shoal

East

Vermilion

South

Marsh

Island

Cameron

West

Island

Eugene

o

Pensacola

Destin Dome

De Soto Canyon

Lloyd Ridge

Henderson

NG 16-8

NG 16-11

Apalachicola

Florida Middle

The Elbow

Vernon Basin

Gainesville

Tarpon

Springs

Saint

Petersburg

Howell Hook

Rankin

Charlotte Harbor

Pulley Ridge

Dry

Tortugas

Miami

Key 

West

NF 17-1

Miami

Tampa

ALABAMA GEORGIA N

FLORIDA

G U L F O F M E X I C O

Pensacola

Ground o

o

5

formation fluid samples are used to determine the change

in volume of oil and gas that flow from higher pressure

conditions deep underground to lower pressure conditions

at the surface. All of these data are compiled, analyzed

and applied to standard equations for the calculation of

hydrocarbons in place within the reservoirs. Standard

recovery factor equations are then applied to the

hydrocarbon in place estimates to calculate original

proved and unproved reserves.

Performance Methods

In performance-technique methods, reserves are estimated

using mathematical or graphical techniques of production

decline curve analysis and material balance. These

techniques are used throughout the oil industry in

assessing individual well, reservoir, or field performance

and in forecasting future reserves. In decline analysis, a

plot of daily production rate against time is most

frequently used. Once a well or reservoir can no longer

produce at its maximum capacity, the production rate

declines. This production rate plotted against time can be

extrapolated into the future to predict the remaining

reserves. Another type of decline analysis is daily

production rate plotted against cumulative oil production,

which can also be used to predict remaining reserves.

The declining daily rate is extrapolated to predict

remaining reserves.

Another performance method, material balance, is used to

estimate the amount of hydrocarbons in place. Given the

premise that the pressure-volume relationship of a

reservoir remains constant as hydrocarbons are produced,

it is possible to equate expansion of reservoir fluids with

reservoir voidage caused by fluid withdrawal minus any

water influx. For depletion-drive gas reservoirs, a plot of

the pressure/gas compressibility factor (P/Z) versus

cumulative gas production gives a good estimate of

original gas-in-place. Original recoverable gas reserves

are extrapolated to an abandonment reservoir pressure. 

Reserves and Related

Data Reported by Area

The Gulf of Mexico has been divided into three

planning areas for administrative purposes; these

planning areas (Western, Central, and Eastern) are

shown in figures 4, 5, and 6, respectively. Each planning

area is subdivided into smaller areas, which in turn

are divided into numbered blocks. Fields in the Gulf

of Mexico are identified by the smaller area name

Figure 4.CWestern Planning Area, Gulf of Mexico,

Outer Continental Shelf.

Figure 5.CCentral Planning Area, Gulf of Mexico,

Outer Continental Shelf.

Figure 6.CEastern Planning Area, Gulf of Mexico,

Outer Continental Shelf.
6

(Reserves: oil expressed in millions of barrels at 60 oF and 1 atmosphere, gas in billions of cubic feet at 60 oF and 15.025 psia.)

Area(s)

(Figs. 4, 5, and 6)

Number of fields Original

proved

reserves

Cumulative

production

through 1996

Remaining

proved

reserves

Estimated

unproved

reserves

Proved

active

prod

Proved

active

nonprod

Proved

expired

depleted

Unproved Expired

nonprod active studied Oil Gas Oil Gas Oil Gas Oil Gas

Western Planning Area

Brazos 28 1 8 0 0 3 14 3,464 8 2,414 6 1,050 - -

Galveston 23 0 19 1 0 4 42 1,820 31 1,385 11 435 - -

High Island and Sabine Pass 83 2 31 4 1 15 367 13,615 278 11,448 89 2,167 - -

Matagorda Island 28 0 0 2 1 2 21 4,837 16 3,618 5 1,219 - -

Mustang Island 20 0 6 1 0 6 8 2,000 4 1,199 4 801 - -

N. & S. Padre Island 6 0 2 0 0 2 0 485 0 382 0 103 - -

Western Slope* 14 0 0 13 11 10 336 2,151 109 883 227 1,268 231 1,433

Western Planning Area Subtotal 202 3 66 21 13 42 788 28,372 446 21,329 342 7,043 231 1,433

Central Planning Area

Chandeleur 8 0 2 0 0 0 0 389 0 289 0 100 - -

East Cameron 42 1 17 3 2 3 312 10,193 260 8,867 52 1,326 - -

Eugene Island 59 1 9 0 0 9 1,513 17,767 1,277 15,185 236 2,582 - -

Grand Isle 12 0 2 2 2 2 927 4,197 857 3,782 70 415 - -

Main Pass and Breton Sound 48 0 8 9 0 7 975 5,339 792 4,261 183 1,078 - -

Mobile 20 2 0 0 0 4 0 2,472 0 589 0 1,883 - -

Ship Shoal 45 0 11 5 1 7 1,255 11,135 1,116 9,952 139 1,183 - -

South Marsh Island 40 1 6 0 0 3 838 13,811 717 11,820 121 1,991 - -

South Pass 12 1 0 0 0 1 1,012 4,100 902 3,221 110 879 - -

South Pelto 6 1 1 0 0 0 140 839 120 686 20 153 - -

South Timbalier 35 1 6 5 2 5 1,374 8,205 1,229 6,576 145 1,629 - -

Vermilion 63 1 13 0 0 6 504 15,595 415 13,613 89 1,982 - -

Viosca Knoll 10 2 0 3 3 2 0 181 0 66 0 115 - -

West Cameron and Sabine Pass 72 2 23 4 3 8 170 17,345 145 15,367 25 1,978 - -

West Delta 19 0 5 0 0 2 1,329 4,914 1,197 4,360 132 554 - -

Central Slope** 32 8 2 29 22 28 1,651 7,069 578 2,511 1,073 4,558 769 2,227

Central Planning Area Subtotal 523 21 105 60 35 87 12,000 123,551 9,605 101,145 2,395 22,406 769 2,227

Eastern Planning Area Subtotal*** 0 0 0 4 4 1 - - - - - - - -

GOM Total

725 24 171

85 52 130 12,788 151,923 10,051 122,474 2,737 29,449 1,000 3,660

920

*Western Slope includes Alaminos Canyon, Corpus Christi, East Breaks, Garden Banks, Keathley Canyon, and Port Isabel.

**Central Slope includes Atwater Valley, Ewing Bank, Green Canyon, Lund, Mississippi Canyon, Viosca Knoll (slope), and Walker Ridge.

***Eastern Planning Area includes Charlotte Harbor, Destin Dome, Pensacola and others. Unproved reserves data are included with Central Planning Area.

Table 1.CEstimated oil and gas reserves for 920 proved and 52 unproved fields by area, Gulf of Mexico,

Outer Continental Shelf, December 31, 1996.

and block number of discovery C for example, East found on the GOM Region*s Internet homepage. For this

Cameron Block 271 Field. As the field is developed, the report, 749 proved active fields and 52 unproved active

limits often expand into adjacent blocks and areas. These fields were studied. Also included were 171 proved

adjacent blocks are then identified as part of the original depleted fields (abandoned with production) to give a

field and are given that field name. Statistics in this complete record of cumulative oil and gas production.

report are presented as area totals compiled under each Not studied were 130 fields expired, relinquished, or

field name. All of the data associated with East Cameron terminated without production and 33 unproved active

Block 271 Field are therefore included in the East fields. In 1996 thirty-two proved fields were depleted and

Cameron totals, although part of the field extends into the 8 unproved fields expired.

adjacent area of Vermilion. There are four exceptions to

the above field-naming techniques: Tiger Shoal and Reserves data and various classifications of fields, leases,

Lighthouse Point, included in South Marsh Island; Coon boreholes, and completions are presented as area totals in

Point, included in Ship Shoal; and Bay Marchand, tables 1 and 2, and the table 3 series. Dashes on these

included in South Timbalier. tables are used to preserve the proprietary nature of data.

There were 834 active fields in the federally regulated "Reserves Reported by Geologic Age," beginning on page

part of the Gulf of Mexico, as listed in the Field Names

Master List (October 1997). An updated list can be

(The table 3 series will be discussed in the section

8.) Figure 7 provides a geographical representation of
N

Garden 

 Banks

East Breaks

Alaminos 

 Canyon

Keathley

Canyon

Green 

Canyon Atwater

Walker

 Ridge Lund

Mississippi

 Canyon

Discovered

1947 -1959

1960 -1969

1970 -1979

1980 -1989

1990 -1996

7

Figure 7.CGulf of Mexico, 920 proved fields (749

active and 171 depleted).

(All statistics associated with fields are presented within area totals compiled under each field name.)

Area(s)

(Figs. 4, 5, and 6)

Number of leases Number

of

boreholes

Number

of active

completions

Proved

active

Proved

depleted

Unproved

qualified

Unproved

active Expired

Drilled Abandoned

Western Planning Area

Brazos 51 17 0 65 227 482 294 191

Galveston 44 31 1 83 432 554 443 148

High Island and Sabine Pass 173 73 3 189 716 2,566 1,470 1,142

Matagorda Island 61 11 2 19 116 520 236 322

Mustang Island 37 7 1 48 313 344 206 160

N. & S. Padre Island 9 5 0 32 245 136 103 54

Western Slope* 31 2 21 684 766 454 271 139

Western Planning Area Subtotal 406 146 28 1,120 2,815 5,056 3,023 2,156

Central Planning Area

Chandeleur 12 3 0 6 23 65 38 27

East Cameron 108 59 2 148 399 1,773 1,060 790

Eugene Island 193 62 0 106 347 3,960 2,173 1,903

Grand Isle 52 9 2 34 102 1,327 885 602

Main Pass and Breton Sound 125 38 6 91 283 2,016 904 1,355

Mobile 34 0 0 26 53 101 41 50

Ship Shoal 150 43 4 105 338 3,057 1,730 1,526

South Marsh Island 102 33 0 74 219 2,260 1,137 1,163

South Pass 51 5 0 24 63 1,931 964 1,034

South Pelto 16 3 0 6 23 330 197 149

South Timbalier 111 28 5 135 318 2,558 1,434 1,375

Vermilion 153 74 0 157 389 2,463 1,471 1,063

Viosca Knoll 15 0 5 69 98 70 30 26

West Cameron and Sabine Pass 185 137 4 275 603 2,814 1,851 1,016

West Delta 65 24 0 45 136 2,112 1,305 1,003

Central Slope** 98 3 37 1,318 985 1,447 860 498

Central Planning Area Subtotal 1,470 521 65 2,619 4,379 28,284 16,080 13,580

Eastern Planning Area Subtotal*** 0 0 6 150 328 47 41 0

GOM Total 1,876 667 99 3,889 7,522 33,387 19,144 15,736

*Western Slope includes Alaminos Canyon, Corpus Christi, East Breaks, Garden Banks, Keathley Canyon, and Port Isabel.

**Central Slope includes Atwater Valley, Ewing Bank, Green Canyon, Lund, Mississippi Canyon, Viosca Knoll (slope), and Walker Ridge.

***Eastern Planning Area includes Charlotte Harbor, Destin Dome, Pensacola and others. Unproved reserves data are included with Central Planning Area.

Table 2.CStatus of oil and gas leases, boreholes, and completions by area, Gulf of Mexico, 

Outer Continental Shelf, December 31, 1996.

locations for the 920 proved fields in the Gulf of Mexico.

Estimates of proved reserves for these fields, both

producing and nonproducing, are presented as area

totals in table 1. Figure 8 provides a geographical

representation of the 85 unproved active fields in the Gulf

of Mexico. Estimates of unproved reserves are presented

as planning area subtotals. The Eastern Planning Area

totals for unproved reserves are included in the Central

Planning Area subtotals. 

The status of Gulf of Mexico OCS Federal oil and gas

leases as of December 31, 1996, is presented in table 2.

There are 5,864 active leases (1,876 proved active, 99

unproved qualified, and 3,889 unproved active) and

8,189 relinquished leases (667 proved depleted and 7,522

expired).
N

Garden 

 Banks

East Breaks

Alaminos 

 Canyon

Keathley

Canyon

Green 

Canyon Atwater

Walker

 Ridge Lund

Mississippi

 Canyon

(Modified from various published and unpublished sources) 

Holocene 

Pleistocene

Pliocene

Miocene

Oligocene

Eocene

Paleocene

Jurassic

Epoch or 

 Series

Triassic 

Informal

Geologic

 Times 

M.Y.A.*

Cenozoic

 Era or 

Erathem

Mesozoic

Tertiary

Period or 

 System

Cretaceous 

Paleogene

Neogene

Quaternary

0.01 

2.8 

5.5

24.8

38

55

63

138

205

~240

10.5

18.5

Valvulineria "H"

Buliminella 1

Textularia "X"

Robulus "E" / 

 Bigenerina "A"

Textularia "L"

Cibicides opima

Gyroidina "K"

Discorbis "B"

Cristellaria "R"

Discorbis zone

Biozones

* Million Years Anum

Chronozones

 (Used in

 Reporting

 Resources)

UPL

MPL 

LPL 

Trimosina "A"

Hyalinea "B"

Angulogerina "B"

Lenticulina 1

Cristellaria "K"

Discorbis 12

 Bigenerina 2 

Textularia "W"

Bigenerina humblei

Cristellaria "I"

Amphistegina "B"

Marginulina "A"

Siphonia davisi

Lenticulina hanseni

UP

LP 

UM 3

UM 1

MM 9

MM 7

MM 4

LM 2

LM 1

LM 4

E

L

O

K

U

TR

Sangamon Fauna

8

Figure 8.CGulf of Mexico, 85 unproved active

fields (52 studied and 33 not studied).

Definitions of the table 2 subgroups follow:

Proved Active C Leases within the designated 749

proved active fields presented in table 1.

Proved Depleted C Leases relinquished after oil and gas

production. The leases associated with the 171 depleted

fields are represented here along with other produced,

relinquished leases that are part of currently active fields.

Unproved Qualified C Leases associated with the 85

unproved active fields. The leases have qualified as

producible under 30 CFR 250.11, but the operators have

not established a commitment to produce. These fields

may be classified as unproved possible or unproved

probable.

Unproved Active C Active exploratory leases not yet

qualified as producible or associated with any field.

Expired C Leases relinquished by the operator without

having produced any oil or gas, although some were once

qualified as producible under 30 CFR 250.11. There are

130 expired fields with no production.

The total number of boreholes drilled and the number of

boreholes plugged and abandoned are also shown i n table

2. There were 1,059 boreholes spudded during 1996,

compared with 959 during 1995, and 918 during 1994.

The last column of table 2 presents the total number of

active completions per area. Active completions are

defined as those with perforations open to the formation

and not isolated by permanent plugs; service wells

(injection, disposal, or water source) are included. The

presence or absence of production or injection is not

considered. The number of boreholes and the number of

active completions as of December 31, 1996, are based

on reports received by the MMS at the time the count was

made in 1997. These numbers may change when all data

have been received, processed, and edited.

Reserves Reported

by Geologic Age

In this report the 920 proved and 52 unproved fields have

been classified at the geologic series level. The different

geologic age classifications in use by MMS are shown in

figure 9. Paleontological examinations of borehole

cuttings, along with regional analysis of geological and

geophysical data, were used in determining the age

classifications. Table 3 shows the distribution of reserves

and production data by geologic age and planning area.

Tables 3a through 3d also show the distribution of

reserves and production data by geologic age, but further

subdivide the planning areas as area totals. Unproved

reserves are not reported as area totals to maintain the

confidential nature of unproved fields.

Figure 9.CGulf of Mexico MMS geologic time

scale.
9

(Reserves: oil expressed in millions of barrels at 60 oF and 1 atmosphere, gas in billions of cubic feet at 60 oF and 15.025 psia.)

Geologic Age

Number of

proved 

reservoirs

Original

proved

reserves

Cumulative

production

through 1996

Remaining

proved

reserves

Number of

unproved

reservoirs

Estimated

unproved

reserves

Oil Gas Oil Gas Oil Gas Oil Gas

Western Planning Area

Pleistocene 1,453 561 11,417 312 8,849 249 2,568 63 176 1,142

Pliocene 2 102 202 44 92 58 110 10 55 282

Miocene 2,152 124 16,712 90 12,386 34 4,326 2 0 5

Oligocene, Cretaceous, and Jurassic 8 1 41 0 2 1 39 3 0 4

Western Planning Area Subtotal 3,615 788 28,372 446 21,329 342 7,043 78 231 1,433

Central Planning Area

Pleistocene 8,218 4,126 49,442 3,278 41,209 848 8,233 52 87 284

Pliocene 5,984 3,532 23,830 2,944 19,276 588 4,554 42 206 272

Miocene 6,092 4,342 48,125 3,383 40,248 959 7,877 40 475 952

Oligocene, Cretaceous, and Jurassic 16 0 2,154 0 412 0 1,742 1 1 719

Central Planning Area Subtotal 20,310 12,000 123,551 9,605 101,145 2,395 22,406 135 769 2,227

Eastern Planning Area Subtotal*** 0 0 0 0 0 0 0 5 0 0

GOM Total 23,925 12,788 151,923 10,051 122,474 2,737 29,449 218 1,000 3,660

***Eastern Planning Area includes Charlotte Harbor, Destin Dome, Pensacola and others. Unproved reserves data are included with Central Planning Area.

Table 3.CEstimated oil and gas reserves for 920 proved and 52 unproved fields by geologic age, 

Gulf of Mexico, Outer Continental Shelf, December 31, 1996.

(Reserves: oil expressed in millions of barrels at 60 oF and 1 atmosphere, gas in billions of cubic feet at 60 oF and 15.025 psia.)

Area(s)

Number of

proved

reservoirs

Original

proved

reserves

Cumulative

production

through 1996

Remaining

proved

reserves

Number of

unproved

reservoirs

Estimated

unproved

reserves

Oil Gas Oil Gas Oil Gas Oil Gas

Western Planning Area

Galveston 23 2 84 1 71 1 13 0 - -

High Island and Sabine Pass 1,267 325 9,380 246 7,983 79 1,397 4 - -

Western Slope* 163 234 1,953 65 795 169 1,158 59 - -

Western Planning Area Subtotal 1,453 561 11,417 312 8,849 249 2,568 63 176 1,142

Central Planning Area

East Cameron 648 228 5,270 187 4,363 41 907 3 - -

Eugene Island 1,750 958 11,653 794 10,112 164 1,541 0 - -

Grand Isle 108 10 1,387 6 1,257 4 130 0 - -

Main Pass and Breton Sound 22 48 129 33 98 15 31 0 - -

Ship Shoal 1,418 776 6,765 703 6,090 73 675 0 - -

South Marsh Island 780 510 3,539 431 2,921 79 618 0 - -

South Pass 201 154 1,262 129 1,062 25 200 0 - -

South Pelto 77 22 22 19 16 3 6 0 - -

South Timbalier 990 340 4,892 280 3,984 60 908 1 - -

Vermilion 810 171 3,482 124 2,619 47 863 0 - -

Viosca Knoll 1 0 0 0 0 0 0 0 - -

West Cameron and Sabine Pass 812 29 7,298 22 6,415 7 883 7 - -

West Delta 169 197 754 175 604 22 150 0 - -

Central Slope** 432 683 2,989 375 1,668 308 1,321 41 - -

Central Planning Area Subtotal 8,218 4,126 49,442 3,278 41,209 848 8,233 52 87 284

Eastern Planning Area Subtotal*** - - - - - - - - - -

GOM Total 9,671 4,687 60,859 3,590 50,058 1,097 10,801 115 263 1,426

*Western Slope includes Alaminos Canyon, Corpus Christi, East Breaks, Garden Banks, Keathley Canyon , and Port Isabel.

**Central Slope includes Atwater Valley, Ewing Bank, Green Canyon, Lund, Mississippi Canyon, Viosca Knoll (slope), and Walker Ridge.

***Eastern Planning Area includes Charlotte Harbor, Destin Dome, Pensacola and others. Unproved reserves data are included with Central Planning Area.

Table 3a.CEstimated oil and gas reserves for Pleistocene reservoirs in 478 proved and 23 unproved fields

by area, Gulf of Mexico, Outer Continental Shelf, December 31, 1996.
N

Garden 

 Banks East Breaks

Alaminos 

 Canyon

Keathley

Canyon

Green 

Canyon

Atwater

Walker

 Ridge Lund

Mississippi

 Canyon

Sigsbee

Escarpment

N

Garden 

 Banks East Breaks

Alaminos 

 Canyon

Keathley

Canyon

Green 

Canyon

Atwater

Walker

 Ridge Lund

Mississippi

 Canyon

Sigsbee

Escarpment

10

(Reserves: oil expressed in millions of barrels at 60 oF and 1 atmosphere, gas in billions of cubic feet at 60 oF and 15.025 psia.)

Area(s)

Number of

proved

reservoirs

Original

proved

reserves

Cumulative

production

through 1996

Remaining

proved

reserves

Number of

unproved

reservoirs

Estimated

unproved

reserves

Oil Gas Oil Gas Oil Gas Oil Gas

Western Planning Area

High Island and Sabine Pass 1 0 4 0 4 0 0 0 - -

Western Slope* 1 102 198 44 88 58 110 10 - -

Western Planning Area Subtotal 2 102 202 44 92 58 110 10 55 282

Central Planning Area

Chandeleur 2 0 15 0 9 0 6 0 - -

East Cameron 154 14 925 10 736 4 189 0 - -

Eugene Island 1,091 413 2,819 364 2,271 49 548 0 - -

Grand Isle 343 344 1,023 310 875 34 148 5 - -

Main Pass and Breton Sound 338 168 1,191 125 1,000 43 191 0 - -

Ship Shoal 650 322 2,322 280 2,046 42 276 7 - -

South Marsh Island 607 140 4,509 121 3,904 19 605 0 - -

South Pass 774 740 2,338 666 1,723 74 615 0 - -

South Pelto 159 66 257 58 223 8 34 0 - -

South Timbalier 494 258 1,694 216 1,201 42 493 1 - -

Vermilion 518 183 3,128 156 2,692 27 436 0 - -

West Cameron and Sabine Pass 156 3 963 2 829 1 134 0 - -

West Delta 578 497 1,147 439 958 58 189 0 - -

Central Slope** 120 384 1,499 197 809 187 690 29 - -

Central Planning Area Subtotal 5,984 3,532 23,830 2,944 19,276 588 4,554 42 206 272

Eastern Planning Area Subtotal*** - - - - - - - - - -

GOM Total 5,986 3,634 24,032 2,988 19,368 646 4,664 52 261 554

*Western Slope includes Alaminos Canyon, Corpus Christi, East Breaks, Garden Banks, Keathley Canyon , and Port Isabel.

**Central Slope includes Atwater Valley, Ewing Bank, Green Canyon, Lund, Mississippi Canyon, Viosca Knoll (slope), and Walker Ridge.

***Eastern Planning Area includes Charlotte Harbor, Destin Dome, Pensacola and others. Unproved reserves data are included with Central Planning Area.

Table 3b.CEstimated oil and gas reserves for Pliocene reservoirs in 262 proved and 15 unproved fields 

by area, Gulf of Mexico, Outer Continental Shelf, December 31, 1996.

Figure 10.CPleistocene production trend. Figure 11.CPliocene production trend.

The Pleistocene production trend is presented in figure 10 beyond the Sigsbee Escarpment. As of December 31,

and corresponds to the Sangamon Fauna and Trimosina 1996, the Pleistocene produced from 478 fields. Original

"A" through Valvulineria "H" biozones. Production proved reserves were 4.69 billion barrels (Bbbl) and 60.9

within the Pleistocene extends from the Galveston area to trillion cubic feet (Tcf). Remaining proved reserves were

east of the modern-day mouth of the Mississippi River. 1.10 Bbbl and 10.8 Tcf.

Pleistocene productive sands are limited to the east and

west because of a lack of sediment influx at the edge of The Pliocene production trend is presented in figure 11

the depocenter. Downdip deepwater Pleistocene and corresponds to the Buliminella 1 through Textularia

production occurs in the East Breaks through Mississippi X biozones. Production within the Pliocene extends

Canyon areas, and well control suggests sands continue
11

(Reserves: oil expressed in millions of barrels at 60 o F and 1 atmosphere, gas in billions of cubic feet at 60 oF and 15.025 psia.)

Area(s)

Number of

proved

reservoirs

Original

proved

reserves

Cumulative

production

through 1996

Remaining

proved

reserves

Number of

unproved

reservoirs

Estimated

unproved

reserves

Oil Gas Oil Gas Oil Gas Oil Gas

Western Planning Area

Mustang Island and N. & S. Padre 8 1 41 0 2 1 39 0 - -

Western Slope* 0 0 0 0 0 0 0 3 - -

Western Planning Area Subtotal 8 1 41 0 2 1 39 3 0 4

Central Planning Area

Main Pass and Breton Sound 1 0 0 0 0 0 0 0 - -

Mobile 15 0 2,154 0 412 0 1,742 0 - -

Viosca Knoll 0 0 0 0 0 0 0 1 - -

Central Planning Area Subtotal 16 0 2,154 0 412 0 1,742 1 1 719

Eastern Planning Area Subtotal*** 0 0 0 0 0 0 0 1 0 0

GOM Total 24 1 2,195 0 414 1 1,781 5 1 723

*Western Slope includes Alaminos Canyon, Corpus Christi, East Breaks, Garden Banks, Keathley Canyon , and Port Isabel.

***Eastern Planning Area includes Charlotte Harbor, Destin Dome, Pensacola and others. Unproved reserves data are included with Central Planning Area.

Table 3d.CEstimated oil and gas reserves for Oligocene, Cretaceous, and Jurassic reservoirs in 12 proved

and 3 unproved fields by area, Gulf of Mexico, Outer Continental Shelf, December 31, 1996.

(Reserves: oil expressed in millions of barrels at 60 oF and 1 atmosphere, gas in billions of cubic feet at 60 oF and 15.025 psia.)

Area(s)

Number of

proved

reservoirs

Original

proved

reserves

Cumulative

production

through 1996

Remaining

proved

reserves

Number of

unproved

reservoirs

Estimated

unproved

reserves

Oil Gas Oil Gas Oil Gas Oil Gas

Western Planning Area

Brazos 427 14 3,464 8 2,414 6 1,050 0 - -

Galveston 387 40 1,736 30 1,314 10 422 0 - -

High Island and Sabine Pass 479 42 4,231 32 3,461 10 770 0 - -

Matagorda Island 435 21 4,837 16 3,618 5 1,219 2 - -

Mustang Island 335 7 1,959 4 1,197 3 762 0 - -

N. & S. Padre Island 89 0 485 0 382 0 103 0 - -

Western Slope* 0 0 0 0 0 0 0 0 - -

Western Planning Area Subtotal 2,152 124 16,712 90 12,386 34 4,326 2 0 5

Central Planning Area

Chandeleur 22 0 374 0 280 0 94 0 - -

East Cameron 283 70 3,998 63 3,768 7 230 0 - -

Eugene Island 437 142 3,295 119 2,802 23 493 0 - -

Grand Isle 475 573 1,787 541 1,650 32 137 1 - -

Main Pass and Breton Sound 850 759 4,019 634 3,163 125 856 0 - -

Mobile 26 0 318 0 177 0 141 0 - -

Ship Shoal 451 157 2,048 133 1,816 24 232 0 - -

South Marsh Island 405 188 5,763 165 4,995 23 768 0 - -

South Pass 218 118 500 107 436 11 64 0 - -

South Pelto 198 52 560 43 447 9 113 0 - -

South Timbalier 594 776 1,619 733 1,391 43 228 2 - -

Vermilion 503 150 8,985 135 8,302 15 683 0 - -

Viosca Knoll 23 0 181 0 66 0 115 2 - -

West Cameron and Sabine Pass 963 138 9,084 121 8,123 17 961 2 - -

West Delta 590 635 3,013 583 2,798 52 215 0 - -

Central Slope** 54 584 2,581 6 34 578 2,547 33 - -

Central Planning Area Subtotal 6,092 4,342 48,125 3,383 40,248 959 7,877 40 475 952

Eastern Planning Area Subtotal*** - - - - - - - 4 - -

GOM Total 8,244 4,466 64,837 3,473 52,634 993 12,203 46 475 957

*Western Slope includes Alaminos Canyon, Corpus Christi, East Breaks, Garden Banks, Keathley Canyon , and Port Isabel.

**Central Slope includes Atwater Valley, Ewing Bank, Green Canyon, Lund, Mississippi Canyon, Viosca Knoll (slope), and Walker Ridge.

***Eastern Planning Area includes Charlotte Harbor, Destin Dome, Pensacola and others. Unproved reserves data are included with Central Planning Area.

Table 3c.CEstimated oil and gas reserves for Miocene reservoirs in 466 proved and 23 unproved fields

by area, Gulf of Mexico, Outer Continental Shelf, December 31, 1996.
N

Garden 

 Banks

East Breaks

Alaminos 

 Canyon

Keathley

Canyon

Green 

Canyon Atwater

Walker

 Ridge Lund

Mississippi

 Canyon

Sigsbee

Escarpment

N

Garden 

 Banks East Breaks

Alaminos 

 Canyon

Keathley

Canyon

Green 

Canyon

Atwater

Walker

 Ridge Lund

Mississippi

 Canyon

Sigsbee

Escarpment

Jurassic

Cretaceous

Oligocene

40 %

24 %

36 %

37 %

--

36 %

30 %

34 %

--

Age

Oil

Original Proved

Reserves 

Cumulative

Production

Pleistocene

Oligocene,

Cretaceous,

and 

Jurassic

Pliocene

Miocene

28 %

35 %

-- 1 %

41 %

16 %

43 %

--

37 %

16 %

41 %

Remaining Proved

Reserves 

Gas Oil Gas Oil Gas

40 %

16 %

43 %

6 %

12

Figure 12.CMiocene production trend.

Figure 13.COligocene, Cretaceous, and Jurassic

production trends.

from south of Mobile Bay in the east to North Padre The Oligocene, Cretaceous, and Jurassic production

Island in the west. Upper Pliocene productive sands also trends are presented in figure 13. These reservoirs are

extend into the deepwater areas of Garden Banks, Green almost entirely Jurassic Norphlet sands. Production

Canyon, Ewing Bank, and Mississippi Canyon. Well within the Jurassic is limited to east of the Mississippi

control suggests Pliocene sands extend at least as far as River in the Mobile area. Well control suggests reservoir

the Sigsbee Escarpment. As of December 31, 1996, the sands continuing eastward into Destin Dome. As of

Pliocene produced from 262 fields. Original proved December 31, 1996, these trends produced from 12

reserves were 3.63 Bbbl and 24.0 Tcf. Remaining proved fields. Original proved reserves were 0 Bbbl and 2.2 Tcf.

reserves were 0.65 Bbbl and 4.7 Tcf. Remaining proved reserves were 0 Bbbl and 1.8 Tcf.

The Miocene production trend is presented in figure 12 Figure 14 shows the percentages of reserves and

and corresponds to the Robulus "E" / Bigenerina "A" production data by geologic age. There is a fairly even

through Cristellaria "R" biozones. Production within the distribution of oil reserves; however, the Pliocene has a 

Miocene extends from east of the Mississippi River to as significantly lower percentage of gas reserves than the

far west as North Padre Island. Miocene productive Miocene and Pleistocene.

sands also extend into deep waters in Viosca Knoll and

Mississippi Canyon. Well control suggests sands

continue beyond the Sigsbee Escarpment. As of

December 31, 1996, the Miocene produced from 466

fields. Original proved reserves were 4.47 Bbbl and 64.8

Tcf. Remaining proved reserves were 0.99 Bbbl and 12.2

Tcf.

Figure 14.CDistribution of reserves and

production data by geologic age.

Historical Exploration and

Discovery Pattern and Trends

In large part, the following section was taken from An

Exploration and Discovery Model: a Historic

Perspective - Gulf of Mexico Outer Continental Shelf

by Gary Lore. The information presented has been

updated to reflect the current database.

It is informative to review the historic exploration and

development activities that resulted in the world-class

hydrocarbon-producing basin that is the Gulf of Mexico.

Each of the four decades of activity will be examined by

reviewing the status of exploration and development

activity and the number of fields and quantities of proved

reserves discovered during each decade. The discovery

year is defined as the year in which the first well
N

Garden 

 Banks

East Breaks

Alaminos 

 Canyon

Keathley

Canyon

Green 

Canyon Atwater

Walker

 Ridge Lund

Mississippi

 Canyon

N

Garden 

 Banks

East Breaks

Alaminos 

 Canyon

Keathley

Canyon

Green 

Canyon Atwater

Walker

 Ridge Lund

Mississippi

 Canyon

N

Garden 

 Banks East Breaks

Alaminos 

 Canyon

Keathley

Canyon

Green 

Canyon

Atwater

Walker

 Ridge Lund

Mississippi

 Canyon

13

encountering significant hydrocarbons reached total

depth. This date may differ from the year in which the

field discovery was announced.

Figure 15 shows the locations of the proved fields

discovered prior to December 31, 1959. As expected,

initial development was in shallower, nearshore waters

concentrated mainly in the areas off central and western

Louisiana. This development primarily reflected the

gradual extension of existing inland drilling and

development technologies into the open-water marine

environments, and the infancy of marine seismic

acquisition activities. Early exploratory drilling in very

shallow water on the shelf utilized barges and platforms.

The mid-1950*s witnessed the introduction of

submersible and jack-up drilling rigs. During this period,

248 exploratory wells were drilled, culminating in the

discovery of 67 proved fields. It was also during this

period that 8 of the top 10 fields in the Gulf of Mexico,

based on original proved reserves, were discovered.

Figure 16 shows the location of the proved fields

discovered in the 1960*s. These discoveries were still

concentrated offshore central and western Louisiana.

Though still confined to the shelf (600 feet [ft] or less),

field discoveries advanced seaward into deeper waters.

The introduction of drillships and semi-submersibles for

exploratory drilling provided the basis for the deepwater

drilling seen today. During this decade, 2,019

exploratory wells were drilled and 136 proved fields

discovered. The ninth largest field in the Gulf of Mexico,

SS 208, was discovered in the sixties.

Figure 17 shows the location of the proved fields

discovered in the 1970*s. This period reflects continued

drilling and development on the shelf, with an increase in

field discoveries on the seaward portion of the shelf,

predominantly in the Pleistocene depocenter. The

introduction of dynamic positioning systems, used on

drillships and semi-submersible drilling rigs, further

opened up deepwater exploration. Frontier drilling on the

shelf-slope margin led to discoveries of new fields that

have been termed the Flexure Trend. During this decade

2,934 exploratory wells were drilled, resulting in the

discovery of 273 proved fields. The largest field in the

Gulf of Mexico, EI 330, was discovered in 245 ft of water

during this decade. Another significant field discovery

was MC 194, the first field in over 1,000 ft of water.

During the 1980*s, development activities occurred over

practically the entire central and western Gulf of Mexico

Figure 15.CLocation of proved fields discovered

1947-1959, Gulf of Mexico OCS.

Figure 16.CLocation of proved fields discovered

1960-1969, Gulf of Mexico OCS.

Figure 17.CLocation of proved fields discovered

1970-1979, Gulf of Mexico OCS.
N

Garden 

 Banks East Breaks

Alaminos 

 Canyon

Keathley

Canyon

Green 

Canyon

Atwater

Walker

 Ridge Lund

Mississippi

 Canyon

1945 1950 1955 1960 1965 1970 1975 1980 1985 1990 1995

0

500

1000

1500

2000

2500

Proved Reserves (MMBOE)

0

500

1000

1500

2000

2500

Proved Reserves (MMBOE)

Pleistocene

Pliocene

Miocene

Oligocene,

Cretaceous,

and Jurassic 

1945 1950 1955 1960 1965 1970 1975 1980 1985 1990 1995

0

5

10

15

20

25

30

35

40

45

Number of Fields

0

5

10

15

20

25

30

35

40

45

Number of Fields

Pleistocene

Pliocene

Miocene

Oligocene, Cretaceous,

and Jurassic 

N

Garden 

 Banks

East Breaks

Alaminos 

 Canyon

Keathley

Canyon

Green 

Canyon Atwater

Walker

 Ridge Lund

Mississippi

 Canyon

14

Figure 19.CLocation of proved fields discovered

1990-1996, Gulf of Mexico OCS.

Figure 21.CAnnual discoveries of original proved

reserves by geologic age, 920 proved fields.

Figure 20.CAnnual number of field discoveries by

geologic age, 920 proved fields.

Figure 18.CLocation of proved fields discovered

1980-1989, Gulf of Mexico OCS.

shelf, as well as on the upper slope, as can be seen in

figure 18. In addition, the first Norphlet fields and a

Miocene shallow bright spot play were discovered in the

eastern Central Gulf of Mexico planning area.

Exploratory drilling had now reached water depths

beyond 6,000 ft, putting the slope within reach. In this

decade, 17 proved fields were discovered in water depths

greater than 1,000 ft.

From 1990 to 1996 (figure 19), 2,440 exploration wells

were drilled, resulting in the discovery of 98 proved

fields. The 1990*s have seen the refinement and

reduction in cost of tension leg platform design, and a

much expanded use of subsea completions. Available

production histories have documented high production

rates for deepwater fields. The expanding use of

horizontal drilling is also increasing productivity of

specific reservoirs. Computer workstation technology

using three-dimensional seismic data sets has allowed for

reduced risk and greater geologic assurance in both

exploration and field development. This has also allowed

for exploration of new plays, such as the Subsalt Play.

Reserve estimates for individual fields discovered in the

1990*s are generally conservative and will experience

significant reserves appreciation. 

Figure 20 shows annual field discoveries by geologic age

for the 920 proved fields. Figure 21 shows annual field

discoveries of original proved reserves by geologic age

for the 920 proved fields. These two figures show several

trends over the last 50 years. From the mid-1940's

through the 1960*s the largest number of fields

discovered were of Miocene age and these fields

contributed the largest reserves additions. This trend

reflected a continuation of the nearshore operating

environment. The decade of the 1970*s saw a large peak

in discoveries of Pleistocene fields and a correspondingly

large addition of Pleistocene age reserves. Technological
2

3

7

6

5

4

1 8

9 15

10 16

11 17

18

13

0.012 to 0.024

14

0.006 to 0.012 

12

19

Class

0.095 to 0.190 777.2 to 1554.4

 0 to 0.006 

0.024 to 0.047

0.047 to 0.095

0.190 to 0.380 

0.38 to 0.76 24.3 to 48.6

0.76 to 1.52

1.52 to 3.04

3.04 to 6.07

6.07 to 12.14

12.14 to 24.3

48.6 to 97.2

97.2 to 194.3

194.3 to 388.6

388.6 to 777.2

Class Class Deposit -size

range *

Deposit -size

range *

Deposit -size

range *

* Million barrels of oil equivalent (MMBOE)

15

advances in seismic data and deeper drilling accounted for original proved reserves. The field-size distribution

the resurgence of Miocene field discoveries and reserve based on estimated unproved reserves for 52 unproved

additions in the decade of the 1980*s. This decade also fields is shown in figure 26(a). There are 26 unproved oil

saw the first Jurassic Norphlet discoveries. Completing fields in figure 26(b) and 26 unproved gas fields in figure

an evaluation of the 1990*s is premature, but the large 26(c). Another 33 unproved active fields were not

discoveries in Pleistocene, Pliocene, and Miocene studied.

deepwater reservoirs will surely play a major role in

future production. Analysis of the 920 proved oil and gas fields indicates

Field-Size Distribution

Reserve sizes are expressed in terms of barrels of oil

equivalent (BOE) and added to the liquid reserves. The

conversion factor of 5,620 standard cubic feet of gas

equals 1 BOE is based on the average heating values of

domestic hydrocarbons. A geometric progression,

developed by the USGS (Drew and others, 1982), was

selected for field-size distribution ranges (figure 22).

Figure 22.CDescription of deposit-size classes.

For the field-size distribution, deposit-class sizes 1

through 7 were combined. In this report, fields are

classified as either oil or gas; however, some fields do

produce both products, making a field type determination

difficult. Generally, fields with a gas/oil ratio (GOR) less

than 9,700 standard cubic feet per stock tank barrel

(SCF/STB) are classified as oil.

The field-size distribution based on original proved

reserves for 920 proved fields is shown in figure 23(a).

Of the 920 proved oil and gas fields, there are 164 proved

oil fields represented in figure 24(a) and 756 gas fields

shown in figure 25(a). The Western Gulf of Mexico

field-size distributions are displayed on figures 23(b),

24(b), and 25(b). Figures 23(c), 24(c), and 25(c) present

the Central Gulf of Mexico field-size distributions of

that the Gulf of Mexico is currently a gas-prone basin.

Figure 27 summarizes the total reserves, the median

(exceeded by 50%), and the mean (arithmetic average)

from the field-size distributions. This figure also

provides information on the largest two field-size ranges

of the proved fields. The GOR (original gas divided by

original oil) of the 164 proved oil fields is 3,156

SCF/STB. The GOR of the 26 unproved oil fields is

1,677 SCF/STB. The average yield (original condensate

divided by original gas) for the 756 proved gas fields is

19.3 barrels of condensate per million cubic feet (MMcf)

of gas. The average yield of the 44 unproved gas fields

is 45.7 barrels of condensate per MMcf.

Figure 28 shows the cumulative percent distribution of

original proved reserves in billion barrels of oil equivalent

(BBOE), by field rank. All 920 proved fields in the Gulf

of Mexico OCS are included in this figure. A

characteristic often observed in hydrocarbon-producing

basins is a rapid dropoff in size from the largest known

field to the smaller ones. Twenty-five percent of the

original proved reserves are contained in the 24 largest

fields. Fifty percent of the original proved reserves are

contained in the 74 largest fields. Ninety percent of the

original proved reserves are contained in the 352 largest

fields.

Figure 29 shows the distribution of the number of fields

and original proved reserves by water depth. The water

depth ranges used in this figure, 651-1,300 ft, 1,301-

2,600 ft, and greater than 2,600 ft, closely approximate

the 200-400 meter, 400-800 meter and greater than 800

meter water depths used in the OCS Deepwater Royalty

Relief Act (DWRRA). Original proved reserves, reported

in million barrels of oil equivalent (MMBOE), are

associated with the 920 proved fields. The 52 unproved

active fields are presented to show current interest and

development. Sixty-seven percent of the original proved

reserves in the Gulf of Mexico are located in less than

200 ft of water. The shelf, generally considered as less

than 650 ft of water, accounts for 92 percent of the

original proved reserves. Development of the slope,

generally considered greater than 650 ft of water, reflects

a sizable amount of original proved reserves associated
14

27 35

69 75 68

100

81

69 68

34

9

Original Proved Reserves, Million Barrels of Oil Equivalent

0

20

40

60

80

100

120

140

160

Number of Fields

0

20

40

60

80

100

120

140

160

Number of Fields

9 9

15

33 42

56

34 43

19

9

2 0

Original Proved Reserves, Million Barrels of Oil Equivalent

0

20

40

60

80

100

120

140

160

Number of Fields

0

20

40

60

80

100

120

140

160

Number of Fields

23

36

50

102

117 124

134

124

88

77

36

9

Original Proved Reserves, Million Barrels of Oil Equivalent

0

20

40

60

80

100

120

140

160

Number of Fields

0

20

40

60

80

100

120

140

160

Number of Fields

0 .38 .76 1.52 3.04 6.07 12.14 24.3 48.6 97.2 194.3 388.6 >

 Largest

45 Fields

 37.9% 

Reserves

0 .38 .76 1.52 3.04 6.07 12.14 24.3 48.6 97.2 194.3 388.6 >

0 .38 .76 1.52 3.04 6.07 12.14 24.3 48.6 97.2 194.3 388.6 >

39,823 MMBOE

12.8 MMBOE

43.3 MMBOE

Total :

Median :

Mean :

( a ) GOM

( b ) Western GOM

( c ) Central GOM

3 3 4 4

12 11 13 16

24

34

16

6

Original Proved Reserves, Million Barrels of Oil Equivalent

0

10

20

30

40

50

Number of Fields

0

10

20

30

40

50

Number of Fields

0 0 0 1 1 1

4 5 4

0

2 0

Original Proved Reserves, Million Barrels of Oil Equivalent

0

10

20

30

40

50

Number of Fields

0

10

20

30

40

50

Number of Fields

3 3 4 5

13 12

17

21

28

34

18

6

Original Proved Reserves, Million Barrels of Oil Equivalent

0

10

20

30

40

50

Number of Fields

0

10

20

30

40

50

Number of Fields

0 .38 .76 1.52 3.04 6.07 12.14 24.3 48.6 97.2 194.3 388.6 >

 Largest

 24 Fields

 52.5%

 Reserves

0 .38 .76 1.52 3.04 6.07 12.14 24.3 48.6 97.2 194.3 388.6 >

0 .38 .76 1.52 3.04 6.07 12.14 24.3 48.6 97.2 194.3 388.6 >

16,379 MMBOE

52.9 MMBOE

99.9 MMBOE

Total :

Median :

Mean :

( a ) GOM

( b ) Western GOM

( c ) Central GOM

GOR : 3,156 SCF/STB

1 1

5 5

3

1

4 3 2 1 0 0

Estimated Unproved Reserves, Million Barrels of Oil Equivalent

0

10

20

30

40

Number of Fields

0

10

20

30

40

Number of Fields

0 0

2 1 1

4 5

6 5

1 1 0

Estimated Unproved Reserves, Million Barrels of Oil Equivalent

0

10

20

30

40

Number of Fields

0

10

20

30

40

Number of Fields

1 1

7 6

4

5

9 9

7

2 1 0

Estimated Unproved Reserves, Million Barrels of Oil Equivalent

0

10

20

30

40

Number of Fields

0

10

20

30

40

Number of Fields

0 .38 .76 1.52 3.04 6.07 12.14 24.3 48.6 97.2 194.3 388.6 >

0 .38 .76 1.52 3.04 6.07 12.14 24.3 48.6 97.2 194.3 388.6 >

0 .38 .76 1.52 3.04 6.07 12.14 24.3 48.6 97.2 194.3 388.6 >

1,651 MMBOE

14.3 MMBOE

31.8 MMBOE

( c ) Unproved gas, GOM

1,171 MMBOE

26.6 MMBOE

45.0 MMBOE

GOR : 1.677 SCF/STB

481 MMBOE

3.9 MMBOE

18.5 MMBOE

Total :

Median :

Mean :

Yield : 45.7 bbl/MMcf

( b ) Unproved oil, GOM

( a ) Unproved, GOM

Total :

Median :

Mean :

Total :

Median :

Mean :

11

24 31

65 63 57

87

65

45

34

18

3

Original Proved Reserves, Million Barrels of Oil Equivalent

0

20

40

60

80

100

120

140

160

Number of Fields

0

20

40

60

80

100

120

140

160

Number of Fields

9 9

15

32 41

55

30 38

15 9

0 0

Original Proved Reserves, Million Barrels of Oil Equivalent

0

20

40

60

80

100

120

140

160

Number of Fields

0

20

40

60

80

100

120

140

160

Number of Fields

20

33

46

97 104 112 117

103

60

43

18

3

Original Proved Reserves, Million Barrels of Oil Equivalent

0

20

40

60

80

100

120

140

160

Number of Fields

0

20

40

60

80

100

120

140

160

Number of Fields

0 .38 .76 1.52 3.04 6.07 12.14 24.3 48.6 97.2 194.3 388.6 >

 Largest 21 Fields

 27.7% Reserves

0 .38 .76 1.52 3.04 6.07 12.14 24.3 48.6 97.2 194.3 388.6 >

0 .38 .76 1.52 3.04 6.07 12.14 24.3 48.6 97.2 194.3 388.6 >

23,443 MMBOE

10.2 MMBOE

31.0 MMBOE

Total :

Median :

Mean :

( a ) GOM

( b ) Western GOM

( c ) Central GOM

Yield : 19.3 bbl/MMcf

16

Figure 23.CField-size distribution of proved fields:

(a) 920 fields, GOM; (b) 271 fields, Western GOM;

(c) 649 fields, Central GOM.

Figure 24.CField-size distribution of proved oil

fields: (a) 164 fields, GOM; (b) 18 fields, Western

GOM; (c) 146 fields, Central GOM.

Figure 26.CField-size distribution of unproved

fields: (a) 52 fields, GOM; (b) 26 oil fields, GOM;

(c) 26 gas fields, GOM.

Figure 25.CField-size distribution of proved gas

fields: (a) 756 fields, GOM; (b) 253 fields, Western

GOM; (c) 503 fields, Central GOM.
Water Depth, Feet

0

2000

4000

6000

8000

10000

12000

Reserves (MMBOE)

0

50

100

150

200

250

300

Number of Fields

Number of unproved 

fields (52)

Number of proved

 fields (920)

Original proved reserves

(39,823 MMBOE)

0-50 51-100 101-200 201-650 651-1,300 1,301-2,600 >2,600

Estimated unproved reserves

 (1,651 MMBOE)

Remaining proved reserves

(7,979 MMBOE)

9303

11211315

22

7

1468

36

1879

238

11

364

1011

24

117

7

780

14

141

4

996

1130

1052

5

20

1116

1

1

245

169

9909

7515

266

197

9860

MC807

VK956

GB426

VK990

MC731

GC205

MC810

EI330

SP089VK783

*******

MO823

EI238

VK825

GC065

MO916

GB387

MI668

MC194

BA105A

0

50

100

150

200

250

300

350

Remaining Proved Reserves (MMBOE)

0

50

100

150

200

250

300

350

Remaining Proved Reserves (MMBOE)

307

252318

192

142

123

111 750 331106

85

126 308 67178 66 65186 283 84

Field size rank by 

Original Proved Reserves

Original Proved Reserves

Field water depth (ft)

> 1,300

651 - 1,300

0 - 650 

20

33 15

46

77

89

104

1 14 109

129

83 19 155 52 159 160 49 28 131

53 %

28 %

38 %

99.9

31.0

31.8

45.0

Fig. 25a 

43.3

Fig. 24a 

Fig. 26c 18.5

Fig. 23a 

Fig. 26a 

Fig. 26b 

12.8 45

52.9

10.2

14.3

26.6

3.9

24

21

Largest Fields Median * Mean * Description 

of Fields 

* Million barrels of oil equivalent (MMBOE)

Number Reserves

Figure

Number

756 Proved Gas

164 Proved Oil

26 Unproved Gas

920 Proved 

52 Unproved

26 Unproved Oil

0 100 200 300 400 500 600 700 800 900

Number of Fields, Rank Order

0

10

20

30

40

50

60

70

80

90

100

Cumulative Percent

0

10

20

30

40

50

60

70

80

90

100

Original Proved Reserves (BBOE)

4.0

8.0

11.9

19.9

0

23.9

35.8

39.8

90% of the original proved 

reserves are in the 352

largest fields

50% of the original proved 

reserves are in the 74

largest fields

27.9

31.8

15.9

25% of the original proved 

reserves are in the 24

largest fields

17

Figure 29.CField and reserves distribution by

water depth.

Figure 30.CLargest 20 fields based on remaining

proved reserves.

Figure 27.CGOM field-size distribution.

Figure 28.CCumulative percent total reserves

versus rank order of field size for 920 proved

fields.

with a few fields. The mean original proved reserves per

proved field in the Gulf of Mexico is 43.3 MMBOE. For

fields in water depths between 651 and 1,300 ft, the mean

original proved reserves per proved field is 46.3

MMBOE. For fields in water depths greater than 1,300

ft, the mean original proved reserves per proved field is

111.9 MMBOE. This is expected, given the economics

associated with deepwater drilling and development.

Figure 30 shows the largest 20 fields based on remaining

proved reserves. The top seven fields lie in water depths

of greater than 1,300 ft and account for 17 percent of the

remaining proved reserves in the Gulf of Mexico.

Estimates of original proved reserves on the slope are

increasing. This trend is expected to continue in the

future due to additional exploration and development. Of

the 43 proved fields in water depths greater than 650 ft,

34 are producing, 2 are depleted, and 7 are undeveloped.

Included in these totals are 8 new proved fields containing

original proved reserves of 412 MMBOE. There are 31

unproved active fields in water depths greater than 650

feet. These fields contain 1,374 MMBOE of estimated

unproved reserves representing 83 percent of the Gulf of

Mexico total. An additional 7 unproved active fields

have not been studied.

Planned deepwater development in the Gulf of Mexico

will likely help slow the trend of declining domestic

production and rising oil imports. Exploration and

development are expected to increase with technological
0.9 0.6

1.2

2.2

3.8

5.7

10.2

15.5

17.7

17

12.4

7.3

3.3

1.3 0.8

0.1

Original Proved Reserves, Million Barrels of Oil Equivalent

0

5

10

15

20

Percent of Reservoirs

0

5

10

15

20

Percent of Reservoirs

0 .006 .012 .024 .047 .095 .19 .38 .76 1.52 3.04 6.0712.14 24.3 97.2 >

1.1 MMBOE

3.4 MMBOE

Median :

Mean :

GOR : 1,477 SCF/STB

Yield : 19.6 bbl/MMcf

48.6

6.5

3.3

4.6

5.6

8.9

12.2

14.8 15

12.7

8.5

4.5

2.1

0.8 0.4 0.1 0

Original Proved Reserves, Million Barrels of Oil

0

5

10

15

20

Percent of Reservoirs

0

5

10

15

20

Percent of Reservoirs

0 .006 .012 .024 .047 .095 .19 .38 .76 1.52 3.04 6.07 12.14 24.3 97.2 >

0.3 MMbbl

1.2 MMbbl

Median :

Mean :

GOR : 1,410 SCF/STB

48.6

1.2 0.7 0.8

1.4

2.3

3.5

4.7

8.1

11.9

15.3

17

13.6

10.2

5.4

2.4

1

0.4 0.1

Original Proved Reserves, Billion Cubic Feet of Gas

0

5

10

15

20

Percent of Reservoirs

0

5

10

15

20

Percent of Reservoirs

0 .006 .012 .024 .047 .095 .19 .38 .76 1.52 3.04 6.07 12.14 24.3 97.2 >

2.6 Bcf

10.6 Bcf

Median :

Mean :

Yield : 10.8 bbl/MMcf

48.6 194.3 388.6

18

advances, expansion of the infrastructure, and the

enactment of the OCS DWRRA. This act gives industry

the incentive to explore and produce deepwater resources.

Table 4 lists the 60 largest proved fields ranked by

original proved reserves based on BOE. Rank, field

name, new discoveries, discovery year, water depth, field

type, field GOR, original proved reserves, cumulative

production through 1996, and remaining proved reserves

are presented. For fields discovered in 1995 and 1996,

the names are replaced with asterisks to preserve the

proprietary nature of the data. In the column labeled

"New Disc", the 40 new fields proved in 1996 are

identified by an asterisk; however, none are in the top 60.

Reserve data for unproved fields will not be listed. A

complete listing of all 920 proved fields, ranked by

original proved reserves, is available on the Gulf of

Mexico Region*s Internet homepage or by contacting the

MMS at 1-800-200-GULF. 

Reservoir-Size Distribution

The size distributions of the proved reservoirs are shown

in figures 31, 32, and 33. The size ranges, which are

based on original proved reserves, are presented on a

geometrically progressing, horizontal scale. These sizes

also correspond with the USGS deposit-size ranges

shown in figure 22; however, for figures 32 and 33, the

proved reserves are presented in MMbbl and Bcf,

respectively. The number of reservoirs in each size

grouping, shown as percentages of the total, is presented

on a linear vertical scale. For the combination reservoirs

(saturated oil rims with associated gas caps), shown in

figure 31, gas is converted to BOE and added to the liquid

reserves. Proved uneconomic reservoirs are excluded

from these distributions, but are included in the table 3

series.

Figure 31 shows the reservoir-size distribution, based on

original proved BOE, for 1,562 proved combination

reservoirs. The median is 1.1 MMBOE and the mean is

3.4 MMBOE. The GOR for the oil portion of the

reservoirs is 1,477 SCF/STB, and the yield for the gas

cap is 19.6 barrels of condensate per MMcf of gas. 

Figure 32 shows the reservoir-size distribution, based on

original proved oil, for 6,944 proved undersaturated oil

reservoirs. The median is 0.3 MMbbl, the mean is 1.2

MMbbl, and the GOR is 1,410 SCF/STB.

Figure 31.CReservoir-size distribution, 1,562

proved combination reservoirs.

Figure 32.CReservoir-size distribution, 6,944

proved oil reservoirs.

Figure 33.CReservoir-size distribution, 12,029

proved gas reservoirs.
Original Cumulative production Remaining

Rank Field New Disc Water Field Field proved reserves through 1996 proved reserves

name disc year depth type GOR BOE Oil Gas Oil Gas Oil Gas

(feet) (SCF/STB) (MMbbl) (MMbbl) (Bcf) (MMbbl) (Bcf) (MMbbl) (Bcf)

1 EI 330 1971 245 O 4600 750.4 412.6 1898.3 353.1 1608.7 59.6 289.6

2 WD 030 1949 49 O 1493 685.2 541.3 808.4 508.6 744.5 32.7 64.0

3 GI 043 1956 139 O 4206 630.2 360.4 1515.9 336.4 1373.9 24.0 142.0

4 TS 000 1958 13 G 88400 617.3 36.9 3261.9 35.5 3039.9 1.4 221.9

5 BM 002 1949 50 O 1062 609.4 512.5 544.4 492.9 490.9 19.6 53.5

6 VR 014 1956 25 G 63092 604.6 49.5 3120.0 46.6 2904.7 2.9 215.3

7 VR 039 1948 38 G 76472 471.2 32.3 2466.7 29.0 2352.8 3.3 113.9

8 MP 041 1956 41 O 5673 469.8 233.8 1326.3 222.4 1222.8 11.4 103.5

9 SS 208 1960 105 O 5878 423.3 206.9 1216.3 195.8 1153.0 11.2 63.3

10 GI 016 1948 53 O 1249 357.4 292.4 365.2 284.3 345.7 8.1 19.5

11 WD 073 1962 179 O 1990 340.0 251.0 499.7 232.8 443.2 18.3 56.5

12 ST 172 1963 98 G 174237 338.2 10.6 1841.5 8.5 1608.1 2.0 233.5

13 SP 061 1967 224 O 1969 331.8 245.7 483.9 219.0 398.4 26.7 85.6

14 SP 089 1969 425 O 4566 331.5 182.9 835.1 148.8 432.1 34.1 403.0

15 GB 426 1987 2864 O 3393 317.6 198.1 672.1 50.9 112.8 147.2 559.3

16 EC 271 1971 171 G 20565 316.1 67.9 1395.4 59.1 1170.2 8.8 225.2

17 EI 292 1964 217 G 91036 315.5 18.3 1669.9 14.9 1487.7 3.4 182.1

18 ST 021 1957 46 O 1598 315.1 245.3 392.1 231.3 362.1 14.0 29.9

19 EI 238 1964 147 G 17356 308.3 75.4 1309.0 54.1 1038.7 21.3 270.3

20 MC 807 1989 2958 O 1164 306.7 254.1 295.8 5.6 6.5 248.5 289.3

21 WC 180 1961 47 G 170379 302.1 9.6 1643.7 9.2 1577.1 0.4 66.6

22 SM 048 1961 100 G 54706 299.7 27.9 1527.6 24.5 1376.1 3.4 151.5

23 SS 176 1956 100 G 21986 291.5 59.3 1304.8 55.9 1199.7 3.5 105.1

24 WC 587 1971 210 G 121264 290.0 12.8 1557.7 11.4 1356.6 1.5 201.1

25 SP 027 1954 63 O 5001 287.8 152.3 761.5 143.7 695.9 8.6 65.6

26 EC 064 1957 49 G 58062 287.6 25.4 1473.5 23.7 1409.5 1.6 64.0

27 WD 079 1966 125 O 3785 287.3 171.7 649.9 155.7 589.1 16.0 60.8

28 MC 194 1975 1023 O 3484 283.0 174.7 608.6 155.5 396.4 19.1 212.2

29 EI 296 1971 214 G 68636 275.3 20.8 1429.9 19.9 1357.7 0.9 72.2

30 SS 169 1960 62 O 5232 262.9 136.2 712.3 113.2 653.4 23.0 59.0

31 ST 176 1963 127 G 13588 259.7 76.0 1032.4 66.0 850.9 10.0 181.5

32 ST 135 1956 130 O 3144 253.6 162.6 511.2 153.0 422.0 9.6 89.3

33 VK 956 1985 3251 O 6990 252.3 112.4 785.9 0.0 0.0 112.4 785.9

34 HI 573 A 1973 341 O 7913 240.3 99.8 789.6 86.5 660.3 13.3 129.3

35 SM 130 1973 215 O 1457 239.6 190.3 277.3 167.1 206.0 23.2 71.3

36 SM 066 1963 124 G 236083 235.6 5.5 1293.2 4.6 1152.5 0.9 140.6

37 SM 023 1960 82 G 38224 224.7 28.8 1100.8 26.7 976.2 2.1 124.6

38 GI 047 1955 87 O 3459 221.4 137.1 474.1 127.4 452.7 9.6 21.4

39 WC 192 1954 57 G 59427 221.2 19.1 1135.8 17.0 1063.9 2.1 71.9

40 PL 020 1951 31 O 5637 213.4 106.5 600.5 93.3 511.5 13.3 89.0

41 SS 222 1966 142 G 12904 211.9 64.3 829.4 59.2 776.0 5.1 53.4

42 VR 076 1949 32 G 208020 210.4 5.5 1151.2 4.3 1036.2 1.2 114.9

43 SP 078 1972 205 G 12506 204.3 63.3 792.1 49.0 694.9 14.3 97.2

44 WC 071 1955 40 G 55358 200.3 18.5 1022.0 17.1 958.8 1.3 63.2

45 SS 113 1955 41 O 3976 196.6 115.2 457.9 105.0 408.5 10.2 49.4

46 VK 990 1981 1448 O 1195 192.7 158.9 189.9 21.2 20.5 137.8 169.4

47 EI 032 1949 12 G 16969 190.5 47.4 804.2 40.4 783.0 7.0 21.2

48 SP 062 1965 331 O 1491 190.0 150.2 224.0 137.5 195.4 12.7 28.6

49 MI 668 1980 95 G 386577 186.1 2.7 1031.0 1.9 707.0 0.8 324.0

50 MI 623 1980 82 G 89925 185.0 10.9 978.6 7.9 728.2 3.0 250.4

51 SS 207 1967 103 O 4336 183.0 103.3 448.0 97.8 363.4 5.5 84.5

52 GC 065 1983 1330 O 1446 178.3 141.8 205.0 88.8 130.7 53.0 74.3

53 WC 533 1973 171 G 19307364 178.1 0.1 1000.8 0.0 895.2 0.0 105.5

54 SS 230 1962 118 O 2863 176.6 117.0 335.0 108.8 280.5 8.2 54.6

55 SM 128 1974 219 O 2149 174.1 126.0 270.7 108.4 223.7 17.5 47.0

56 MP 299 1962 209 O 743 171.7 151.7 112.7 109.4 68.7 42.2 44.0

57 EI 175 1956 84 O 3358 171.1 107.1 359.7 93.7 271.9 13.4 87.8

58 EI 266 1962 163 G 199919 169.5 4.6 926.3 2.9 832.5 1.8 93.9

59 SS 028 1949 13 G 37479 169.4 22.1 828.1 19.6 745.0 2.5 83.1

60 WC 045 1949 33 G 38166 168.2 21.6 824.1 19.9 792.0 1.6 32.1

 There are no New Discoveries (New Disc) in the Top 60 Fields. A complete listing of all proved fields is available in digital format.

19

Table 4.CGulf of Mexico fields by rank order, based on original proved BOE reserves, top 60 fields.
Monthly Production, Barrels of Oil (M=1000)

0

100

200

300

400

500

600

700

800

900

Mean Number of Completions

0

100

200

300

400

500

600

700

800

900

Mean Number of Completions

0 16 32 64 125 250 500 1M 2M 4M 8M 16M 32M 64M125M

Continuously 

producing completions

Intermittently

producing completions

6

3

13 34

72

162

365

612

726

617

386

202

74

(0) (0)

(2) (9)

(23)

(78)

(218)

(402)

(534)

(492)

(330)

(176)

(67)

250M

22

(20) 12

(10)

+

6

(1)

Monthly Production, Thousand Cubic Feet of Gas (M=1000)

0

100

200

300

400

500

600

700

800

900

Mean Number of Completions

0

100

200

300

400

500

600

700

800

900

Mean Number of Completions

2 8 14 31

185

437

583

637

491

288

265

101

17

(0) (2) (3) (10)

(96)

(288)

(446)

(525)

(410)

(168)

(229)

(90)

(15)

62

(27)

107

(50)

0 64 125 250 500 1M 2M 4M 8M 16M 32M 64M 125M 250M 1MM

Continuously 

producing completions

Intermittently

producing completions

2

(0)

500M +

Mean Number of Continuously 

Producing Completions

Highest Producing Rate

 for a Completion

Median Production

Mean Production

Oil Gas

Mean Number of 

Producing Completions 3,313 3,230

2,367 2,359

3,341

(June)

3,249

(September) 

3,291

(April)

3,189

(November)

2,898 bbl

(116 bbl

per day)

57.3 MMcf

(2.1 MMcf

per day)

655,585 bbl

(21,656 bbl 

per day)

3,212 MMcf

(105.7 MMcf

per day)

7,549 bbl

(248 bbl

per day) 

114 MMcf

(3.8 MMcf

per day)

1996

Lowest Monthly Mean Number 

of Producing Completions

Highest Monthly Mean Number 

of Producing Completions

20

Figure 33 shows the reservoir-size distribution, based on

original proved gas, for 12,029 proved nonassociated gas

reservoirs. The median is 2.6 billion cubic feet (Bcf) of

gas, the mean is 10.6 Bcf, and the yield is 10.8 barrels of

condensate per MMcf of gas.

Production Rates

and Discovery Trends

The mean daily production in the Gulf of Mexico OCS

during 1996 was 823,000 bbl of crude oil, 186,000 bbl of

gas condensate, 1.68 Bcf of casinghead gas, and 12.23

Bcf of gas-well gas. The mean GOR of oil wells was

2,039 SCF/STB, and the mean yield from gas wells was

15.22 barrels of condensate per MMcf of gas.

Figures 34 and 35 show the frequency distribution of

monthly production for completions active during 1996.

Since the number of completions within a given range

changes from month to month, the completion numbers

presented are means of the 1996 monthly completion

totals for each production range. The numbers shown in

parentheses are also means of monthly counts for

completions considered to be on continuous production.

Completions off production for more than two days a

month are not counted as continuously producing

completions.

Figure 36 summarizes the data from monthly

distributions of oil and gas production rates. The highest

reported monthly oil production volume was from a

Miocene reservoir with a subsea depth of 16,500 ft,

during the month of September. The highest reported

monthly gas production volume was from a Pleistocene

reservoir with a subsea depth of 11,980 ft, during the

month of March. The mean number of oil completions

producing more than 1,000 bbl per day was 132, and the

mean number of gas completions producing more than 10

MMcf per day was 303.

Annual production in the Gulf of Mexico OCS is shown

in figure 37. The oil plot includes condensate, and the

gas plot includes casinghead gas. Annual oil production

is trimodal, reaching 376 MMbbl per year in 1971, and

350 to 356 MMbbl per year from 1984 through 1986.

From 1986 through 1990 annual oil production declined

23 percent. From 1990 through 1996 annual oil

production rose from 275 MMbbl to 368 MMbbl, a 34

percent increase. Annual gas production is also trimodal,

reaching 4.9 Tcf per year in 1981 and 1990. From 1990

through 1993 gas production declined 6 percent.

Figure 34.CMonthly distribution of oil production,

3,313 completions, (2,367) continuously producing

completions.

Figure 35.CMonthly distribution of gas

production, 3,230 completions, (2,359)

continuously producing completions.

Figure 36.CMonthly completion and production

data.
1945 1950 1955 1960 1965 1970 1975 1980 1985 1990 1995

0

100

200

300

400

500

600

Oil (Million Barrels)

0

1

2

3

4

5

6

Gas (Trillion Cubic Feet)

Annual oil production

Annual gas production

1945 1950 1955 1960 1965 1970 1975 1980 1985 1990 1995

0.0

1.0

2.0

3.0

Billion Barrels of Oil Equivalent

0.0

1.0

2.0

3.0

Billion Barrels of Oil Equivalent

Original proved

 reserves

Remaining proved

 reserves

Cumulative

 production 

1945 1950 1955 1960 1965 1970 1975 1980 1985 1990 1995

0

10

20

30

40

50

60

Number of Fields 

0

10

20

30

40

50

60

Number of FIelds

Proved oil fields

Proved gas fields

Linear Regressions

21

Figure 37.CAnnual oil and gas production.

From 1993 through 1996 annual gas production rose

from 4.6 Tcf to a peak of 5.1 Tcf, an 11 percent increase.

Figure 38 presents original proved reserves, cumulative

production, and remaining proved reserves in BBOE as of

December 31, 1996, summed according to field discovery

year. Field depletion may be estimated by the relative

positions of the cumulative production curve and the

remaining proved reserves curve. For example, if the

value of the remaining proved reserves is higher than the

value of cumulative production for a given year, the

aggregate depletion for fields discovered that year is less

than 50 percent. The plot demonstrates that fields

discovered after 1983, with the exception of 1988, are

less than 50 percent depleted. The current trend is

showing that overall field sizes are decreasing.

Figure 38.CProved reserves and production by

field discovery year.

Figure 39 is a plot of the number of proved gas and oil

fields by discovery year. The annual number of gas fields

discovered has been steadily increasing, while the number

of oil fields discovered has not varied much from year to

year, never exceeding 13 and averaging only about 3.3

discoveries per year. Through 1959, 39 percent of all

fields discovered were oil. This percentage declined

steadily as more gas fields were discovered until only 13

percent of the fields discovered during the 1980*s were oil

fields. This reflects an industry change from oil

production to gas production. The shift from oil to gas

emphasis was fueled by several factors, including

optimism concerning higher anticipated gas prices,

realization of the inevitable decline in the size of oil fields

being discovered, and the introduction of new seismic

technologies that dramatically lowered the risk in

identifying gas reservoirs (Lore, 1994).

Figure 39.CAnnual number of proved oil and gas

field discoveries.

Figure 40 presents the number of proved fields and the

mean field size by field discovery year. This plot shows

that, though the number of discovered fields has typically

been increasing from year to year, the mean size of the

fields has been getting smaller. The mean field size

discovered for the last few years is expected to increase

due to reserves growth in proved fields and reserves

additions in unproved fields discovered in recent years.

Figure 41 presents the number of proved and unproved

fields and the average water depth of the fields discovered

in each year. Clearly, exploration and resulting

production are moving into deeper water, and this trend

is expected to continue.
1945 1950 1955 1960 1965 1970 1975 1980 1985 1990 1995

0.0

0.1

0.2

0.3

0.4

Billion Barrels of Oil Equivalent

0

20

40

60

80

Number of Fields

Mean field size - original 

proved reserves

Number of proved fields

1945 1950 1955 1960 1965 1970 1975 1980 1985 1990 1995

0

400

800

1200

1600

Water Depth (feet)

0

20

40

60

80

Number of Fields

Mean water depth (feet)

Number of fields

1945 1950 1955 1960 1965 1970 1975 1980 1985 1990 1995

0.0

0.2

0.4

0.6

0.8

Oil (Billion Barrels)

0

0.2

0.4

0.6

0.8

Oil (Billion Barrels)

Original proved reserves

Annual production 

1945 1950 1955 1960 1965 1970 1975 1980 1985 1990 1995

0.0

2.0

4.0

6.0

8.0

Gas (Trillion Cubic Feet)

0.0

2.0

4.0

6.0

8.0

Gas (Trillion Cubic Feet)

Original proved reserves

Annual production 

22

Figure 40.CNumber of proved fields and mean

field size by field discovery year.

Figure 41.CNumber of fields and mean water

depth by field discovery year.

Figures 42 and 43 show original proved oil and gas Figure 44 presents the total footage drilled, the total

reserves and annual production by reservoir discovery number of wells drilled, and the number of exploratory

year. All data presented in figure 42 include crude oil and and development wells drilled in the Gulf of Mexico OCS

condensate, and all data presented in figure 43 include each year. All curves show a decline after the 1986

associated and nonassociated gas. The year of discovery collapse in oil prices. A second decline occurred in 1991-

assigned to a reservoir is the year in which the first well 92. Drilling has increased since 1992, reflecting stable

encountering hydrocarbons penetrated the reservoir. For energy prices and improvements in exploration and

comparison with the rate of discoveries, the annual production technology.

production of oil and gas is also shown. Since 1984 new

proved reservoir discoveries, except for 1989 oil Figure 45 presents the number of exploratory wells

discoveries, are no longer offsetting annual production, drilled each year by water depth. The plot shows the

indicating a decreasing trend in remaining proved move toward drilling in deeper water, but also illustrates

reserves. Because of reserves growth, the original proved continued drilling on the shelf.

reserves curve in both figures is expected to increase over

what is shown.

Figure 42.CProved oil reserves by reservoir

discovery year and annual oil production.

Figure 43.CProved gas reserves by reservoir

discovery year and annual gas production.
1945 1950 1955 1960 1965 1970 1975 1980 1985 1990 1995

0

250

500

750

1000

1250

1500

1750

Number of Wells

0

2

4

6

8

10

12

14

Total Footage (Million Feet)

Total footage

Total wells

Development wells

Exploratory wells

1945 1950 1955 1960 1965 1970 1975 1980 1985 1990 1995

0

50

100

150

200

250

300

350

Number of Wells

0

50

100

150

200

250

300

350

Number of Wells

Water depth 0-200 ft

Water depth 201-650 ft

Water depth 651-1,300 ft

Water depth >1,300 ft

23

Figure 44.CWells and footage drilled. Figure 45.CNumber of exploratory wells drilled by

water depth.

Oil

(billion bbl)

Gas

(trillion cu ft)

Original proved reserves:

Previous estimates, as of 12/31/95* 12.01 144.9

Discoveries +0.33 +1.5

Revisions +0.45 +5.5 

Adjustments 0.00 0.0

Net change +0.78 +7.0 

Estimate, as of 12/31/96 (this report) 12.79 151.9

Cumulative production:

Previous estimates, as of 12/31/95* 9.68 117.4

Adjustments 0.00 0.0

Production during 1996 +0.37 +5.1

Net change +0.37

Estimate, as of 12/31/96 (this report) 10.05 122.5

Remaining proved reserves:

Previous estimates, as of 12/31/95* 2.33 27.5

Discoveries +0.33 +1.5

Revisions +0.45 +5.5

Adjustments 0.00 0.0

Production during 1996 -0.37 -5.1

Net change +0.41 +1.9

Estimate, as of 12/31/96 (this report) 2.74 29.4

*Bacigalupi and others, 1996

Table 5.CSummary and comparison of proved oil and gas reserves as of December 31, 1995, and

December 31, 1996.

Summary and Comparison

of Proved Reserves

A summary of proved reserve estimates during the year

and a comparison with estimates from last year*s report

(December 31, 1995) are shown in table 5. Recent

proved field discoveries (10 oil fields and 30 gas fields)

are summarized and tabulated as increases to original

proved reserves. For further clarification, recent field

discoveries are identified as new fields added in the last

year, even though some were discovered before 1996.

Proved reserve estimates are revised as needed, resulting

in increases as additional wells are drilled and new leases

are added to existing fields, and decreases as reservoirs

are depleted and leases relinquished. Complete

reevaluations of existing field studies are conducted based

upon changes in field development and/or production

history. Increases and decreases of proved reserves are

summarized and presented as changes due to revisions.

Based on periodic reviews and revisions of field studies
24

Oil expressed in billions of barrels; gas in trillions of cubic feet. "Oil" includes crude oil and

condensate; "gas" includes associated and nonassociated gas. Remaining proved reserves estimated

as of December 31 each year.

Year

Number of

fields

included

Original

proved

reserves

Historical

cumulative

production

Remaining

proved

reserves

Oil Gas Oil Gas Oil Gas

1975 255 6.61 59.9 3.82 27.2 2.79 32.7

1976 306 6.86 65.5 4.12 30.8 2.74 34.7

1977 334 7.18 69.2 4.47 35.0 2.71 34.2

1978 385 7.52 76.2 4.76 39.0 2.76 37.2

1979* 417 7.71 82.2 4.83 44.2 2.88 38.0

1980 435 8.04 88.9 4.99 48.7 3.05 40.2

1981 461 8.17 93.4 5.27 53.6 2.90 39.8

1982 484 8.56 98.1 5.58 58.3 2.98 39.8

1983 521 9.31 106.2 5.90 62.5 3.41 43.7

1984 551 9.91 111.6 6.24 67.1 3.67 44.5

1985 575 10.63 116.7 6.58 71.1 4.05 45.6

1986 645 10.81 121.0 6.93 75.2 3.88 45.8

1987 704 10.76 122.1 7.26 79.7 3.50 42.4

1988 678 10.95 126.7 7.56 84.3 3.39 42.4

1989 739 10.87 129.1 7.84 88.9 3.03 40.2

1990 782 10.64 129.9 8.11 93.8 2.53 36.1

1991 819 10.74 130.5 8.41 98.5 2.33 32.0

1992 835 11.08 132.7 8.71 103.2 2.37 29.5

1993 849 11.15 136.8 9.01 107.7 2.14 29.1

1994 876 11.86 141.9 9.34 112.6 2.52 29.3

1995 899 12.01 144.9 9.68 117.4 2.33 27.5

1996 920 12.79 151.9 10.05 122.5 2.74 29.4

*Gas plant liquids dropped from reporting system.

Basis of reserves changed from API demonstrated to SPE proved.

Table 6.CProved oil and gas reserves and

cumulative production at end of year, Gulf of

Mexico, Outer Continental Shelf and Slope.

conducted since the 1995 report, the revisions for original submitted by Gulf of Mexico OCS operators, the

proved oil and gas reserves have resulted in a net difference between historical cumulative production for

increase. A net change in the original proved oil and gas successive years does not always equal the annual

reserves is a result of combining both the discoveries and production for the latter year. No comparisons will be

the revisions. made for unproved reserves.

Table 5 demonstrates that the 1996 proved oil and gas

discoveries, adjustments, and field revisions did exceed

production. The remaining proved oil and gas reserves

have increased since 1995.

Table 6 presents all previous reserve estimates by year.

Due to adjustments and corrections to production data

Conclusions

The 920 proved oil and gas fields in the federally

regulated part of the Gulf of Mexico OCS contained

original proved reserves estimated to be 12.79 billion

barrels of oil and 151.9 trillion cubic feet of gas.

Remaining proved reserves, as of December 31, 1996, are

estimated to be 2.74 billion barrels of oil and 29.4 trillion

cubic feet of gas. Estimated remaining proved oil

reserves have increased 17.6 percent and estimated

remaining proved gas reserves have increased 6.9 percent

from last year*s report.

The 52 unproved oil and gas fields studied in the federally

regulated part of the Gulf of Mexico OCS contained

unproved reserves estimated to be 1.00 billion barrels of

oil and 3.7 trillion cubic feet of gas. There are an

additional 33 unproved active fields not included in this

estimate. Included are unproved reserves of 0.09 billion

barrels of oil and 2.4 trillion cubic feet of gas from 26

fields in water depths greater than 1,000 feet. Estimated

unproved oil reserves are 2.7 times annual oil production,

and estimated unproved gas reserves represent 73 percent

of annual gas production. Estimated remaining proved oil

reserves are expected to increase in future years due to

significant moves of unproved reserves into the proved

category.

Contributing Personnel

This report includes contributions from the following

Gulf of Mexico Region, Office of Resource Evaluation,

personnel.

Gerald Crawford 

Eric Kazanis 

Theresa Keller

Christopher Schoennagel

Chee Yu
25

References

Arps, J. J., A. F. Van Everdingen, R. W. Buchwald, and

A. E. Smith, 1967, A Statistical study of recovery

efficiency, American Petroleum Institute, Bulletin D14,

p. 33.

Bacigalupi, S. M., C. J. Kinler, D. A. Marin, and M. T.

Prendergast, 1996, Estimated proved and unproved oil

and gas reserves, Gulf of Mexico Outer Continental

Shelf, December 31, 1995: U. S. Department of the

Interior, Minerals Management Service, Gulf of Mexico

Region, OCS Report MMS 96-0061, New Orleans, 26 p.

Drew, L. J., J. H. Schuenemeyer, and W. J. Bawiec, 1982,

Estimation of the future rates of oil and gas discoveries

in the western Gulf of Mexico, Geological Survey

Professional Paper 1252, United States Government

Printing Office, Washington, D.C., p. 7.

Grab, F. A., and G. L. Smith, 1987, "Estimation of oil

and gas reserves" (chapter 40), In: Howard B. Bradley

(ed.), Petroleum engineering handbook, Houston, Texas,

Society of Petroleum Engineers, p. 40-1 C 40-38.

Lore, G. L. 1994, An Exploration and discovery model;

an historic perspectiveCGulf of Mexico Outer

Continental Shelf, In: K. Simakov and D. Thurston (eds.),

Proceedings of the 1994 International Conference on

Arctic Margins, Russian Academy of Sciences, Magadan,

p. 306-313.

Lore, G. L., J. P. Brooke, D. W. Cooke, R. J. Klazynski,

D. L. Olson, and K. M. Ross, 1996, Summary of the

1996 assessment of conventionally recoverable

hydrocarbon resources of the Gulf of Mexico and

Atlantic Outer Continental Shelf, U.S. Department of the

Interior, Minerals Management Service, Gulf of Mexico

OCS Region, Office of Resource Evaluation, OCS Report

MMS 96-0047, New Orleans, 41 p.

Office the Federal Register, National Archives and

Records Administration, 1992, Code of Federal

Regulations, 30 CFR, Mineral resources, U.S.

Government Printing Office, Washington, D.C.

Society of Petroleum Engineers (SPE) and The World

Petroleum Congress (WPC) Draft Reserves Definitions,

1996, "Definitions for oil and gas reserves," Journal of

Petroleum Technology, August 1996, p. 694-696.

U.S. Department of Energy (DOE), 1989, Conversion

Factors, Monthly Energy, December 1989, p. 132-3.

Calculated from Tables A3 and A5.

U.S. Department of the Interior, Geological Survey and

Minerals Management Service, 1989, Estimates of

undiscovered conventional oil and gas resources in the

United StatesCA Part of the Nation*s energy

endowment, 44 p.

U.S. Department of the Interior, Minerals Management

Service, Gulf of Mexico Region; Bureau of Economic

Geology, University of Texas at Austin; Basin Research

Institute, Louisiana State University; and Geological

Survey of Alabama (Vol. 1), 1997, Atlas of Northern

Gulf of Mexico Gas and Oil Reservoirs, Vol. 1, Miocene

and Older Reservoirs; Vol. 2, Pliocene and Pleistocene

Reservoirs, 199 p. and 78 p.
26

Notice

This report, Estimated Proved and Unproved Oil and Gas Reserves,Gulf of Mexico, December 31,1996, has undergone

numerous changes over the last few years. We are continually striving to provide meaningful information to the users of

this document. Suggested changes, additions, or deletions to our data or statistical presentations are encouraged so we

can publish the most useful report possible. Please contact the Reserves Section Chief at (504) 736-2950 at Minerals

Management Service, 1201 Elmwood Park Boulevard, MS 5130, New Orleans, Louisiana 70123-2394, to communicate

your ideas for consideration in our next report.

For free publication and digital data, visit the Gulf of Mexico Internet homepage.

For information on purchasing hard copies of this publication or digital data from the report contact:

Minerals Management Service

Gulf of Mexico OCS Region

Attn: Public Information Unit (MS 5034)

1201 Elmwood Park Boulevard

New Orleans, Louisiana 70123-2394

(504) 736-2519 or 1-800-200-GULF

http://www.gomr.mms.gov

Gary L. Lore

Regional Supervisor

Resource Evaluation