OCS Report

BOEMRE 2011-045

Outer Continental Shelf

Estimated Oil and Gas Reserves

Gulf of Mexico OCS Region

December 31, 2007

U.S. Department of the Interior

Bureau of Ocean Energy Management,

Regulation and Enforcement

Gulf of Mexico OCS Region

BOEMRE
ON COVER- Independence Hub located in Mississippi Canyon Block 920 in 7,920 feet of water 

(from http://www.drillingcontractor.org). 
 OCS Report 

BOEMRE 2011-045 

Outer Continental Shelf 

Estimated Oil and Gas Reserves 

Gulf of Mexico OCS Region 

December 31, 2007

 

Authors 

T. Gerald Crawford 

Grant L. Burgess 

Steven M. Haley 

Peter F. Harrison 

Clark J. Kinler 

Gregory D. Klocek 

Nancy K. Shepard 

Resource Evaluation Office 

Reserves Section 

 Published by

U.S. Department of the Interior

Bureau of Ocean Energy Management, 

 Regulation and Enforcement New Orleans 

Gulf of Mexico OCS Region September 2011
Estimated Oil and Gas Reserves, Gulf of Mexico OCS, December 31, 2007 

ii
iii

TABLE OF CONTENTS

 Page 

FIGURES.............................................................................................................................v 

TABLES..........................................................................................................................vii 

ABBREVIATIONS AND ACRONYMS......................................................................................ix 

ABSTRACT....................................................................................................................... xi 

INTRODUCTION................................................................................................................. 1 

BACKGROUND.................................................................................................................. 3 

 Definition of Resource and Reserve Terms................................................................................. 3 

 Field............................................................................................................................ 4 

 Resources....................................................................................................................... 4 

 Reserves....................................................................................................................... 5 

 Reference Standard Conditions for Production and Reserves........................................................... 6 

METHODOLOGY................................................................................................................ 7 

 Methods Used for Estimating Reserves.....................................................................................7 

 Analog......................................................................................................................7 

 Volumetric.............................................................................................................. 8 

 Performance Methods................................................................................................. 8 

RESERVES AND RELATED DATA BY PLANNING AREA............................................................ 9 

RESERVES BY GEOLOGIC AGE.......................................................................................................................15 

RESERVES BY RESERVOIR DEPTH........................................................................................ 21 

 

 Deep Gas................................................................................................................................21 

 Deep Oil..................................................................................................................................21 

FIELD-SIZE DISTRIBUTION................................................................................................. 25 

RESERVOIR-SIZE DISTRIBUTION........................................................................................ 33 
Estimated Oil and Gas Reserves, Gulf of Mexico OCS, December 31, 2007 

iv

DISCOVERY AND PRODUCTION PATTERNS AND TRENDS..................................................... 35 

 Discovery of Proved Fields.................................................................................................35 

 Production and Completion Trends........................................................................................ 37 

 Production Rates............................................................................................................. 38 

 

SUMMARY AND CONCLUSIONS..........................................................................................45 

 Comparison of Proved Reserves...........................................................................................45 

 Conclusions.......................................................................................................................47 

CONTRIBUTING PERSONNEL............................................................................................... 49 

REFERENCES................................................................................................................... 51 

APPENDICES.................................................................................................................... 53 

 Appendix A. Comparison of New and Previous Planning Areas..................................................53 

 Appendix B. Reserves Tables Prior to Planning Area Boundary Changes.......................................55 
v

FIGURES

 Page 

Figure 1. BOEMRE GOM production and reserves............................................................................................1 

Figure 2. BOEMRE conventionally recoverable petroleum resource classifications..................................3 

Figure 3. BOEMRE reserve classifications.......................................................................................3 

Figure 4. BOEMRE GOM OCS Planning Areas................................................................................. 10 

Figure 5. Proved fields discovered.................................................................................................12 

Figure 6. Unproved fields discovered............................................................................................. 12 

Figure 7. BOEMRE GOM biostratigraphic chart........................................................................... 16 

Figure 8. Proved reserves trends................................................................................................. 18 

Figure 9. Distribution of proved reserves and production data by geologic age....................................... 19 

 Figure 9(a). Proved oil reserves and production data, BBO..........................................................19 

 Figure 9(b). Proved gas reserves and production data, Tcf........................................................... 19 

 Figure 9(c). Proved BOE reserves and production data, BBOE....................................................19 

Figure 10. Deep gas reservoirs by datum depth summed to field level....................................................... 22 

 Figure 10(a). Gas reservoirs datum depth 15,000 - 17,999 ft..........................................................22 

 Figure 10(b). Gas reservoirs datum depth 18,000 - 20,000 ft..........................................................22 

 Figure 10(c). Gas reservoirs datum depth > 20,000 ft.....................................................................22 

Figure 11. Deep oil reservoirs by datum depth summed to field level...................................................... 23 

 Figure 11(a). Oil reservoirs datum depth 15,000 - 17,999 ft...........................................................23 

 Figure 11(b). Oil reservoirs datum depth 18,000 - 20,000 ft...........................................................23 

 Figure 11(c). Oil reservoirs datum depth > 20,000 ft...................................................................... 23 

Figure 12. Field-size distribution of proved fields: (a) GOM, 1,251 fields; (b) Western GOM, 

 343 fields; (c) Central and Eastern GOM, 908 fields,........................................................... 26 

Figure 13. Field-size distribution of proved oil fields: (a) GOM, 229 fields; (b) Western GOM, 

 20 fields; (c) Central GOM, 209 fields...............................................................................................27 

Figure 14. Field-size distribution of proved gas fields: (a) GOM, 1,022 fields; (b) Western GOM, 

 323 fields; (c) Central and Eastern GOM, 699 fields........................................................... 28 

Figure 15. Field-size distribution of unproved fields: (a) GOM unproved BOE, 53 oil and gas fields; 

 (b) GOM unproved oil, 35 fields; (c) GOM unproved gas, 18 fields........................................29 

Figure 16. Cumulative percent total reserves versus rank order of field size for 1,251 proved fields............... 30 

Figure 17. Largest 20 fields ranked by remaining proved reserves........................................................ 31 

Figure 18. Reservoir-size distribution, 2,278 proved combination reservoirs............................................33 
Estimated Oil and Gas Reserves, Gulf of Mexico OCS, December 31, 2007 

vi

Figure 19. Reservoir-size distribution, 8,051 proved oil reservoirs......................................................34 

Figure 20. Reservoir-size distribution, 17,731 proved gas reservoirs.................................................... 34 

Figure 21. Location of proved fields discovered 1975-1989........................................................................36 

Figure 22. Location of proved fields discovered 1990-1999........................................................................36 

Figure 23. Location of proved fields discovered 2000-2007.......................................................................37 

Figure 24. Annual oil and gas production................................................................................... 38 

Figure 25. Annual number of proved oil and gas field discoveries......................................................... 39 

Figure 26. Proved reserves and production by field discovery year.......................................................39 

Figure 27. Number of proved fields and mean field size by field discovery year...............................................40

Figure 28. Number of proved and unproved fields and mean water depth by field discovery year....................40 

Figure 29. Proved oil reserves by reservoir discovery year and annual oil production..................................41 

Figure 30. Proved gas reserves by reservoir discovery year and annual gas production................................ 41 

Figure 31. Proved BOE reserves water depth categories by reservoir discovery year................................ 42 

Figure 32. Number of wells and total footage drilled by year............................................................ 42 

Figure 33. Number of exploratory wells drilled by water depth..........................................................43 

Figure 34. Number of development wells drilled by water depth.........................................................43 
vii

TABLES

Table 1. Estimated oil and gas reserves for 1,251 proved and 53 unproved fields by area, 

 December 31, 2007............................................................................................................................... 11 

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

 December 31, 2007............................................................................................................................... 13 

Table 3. Estimated oil and gas reserves for 1,251 proved and 53 unproved fields by geologic age, 

 December 31, 2007............................................................................................................................... 15 

Table 4. Description of deposit-size classes....................................................................................................... 25 

Table 5. Field-size distributions......................................................................................................................... 30 

Table 6 Field and reserves distribution by water depth..................................................................................... 31 

Table 7. Proved fields by rank order, based on proved BOE reserves, 

 Top 50 fields........................................................................................................................................ 32 

Table 8. Monthly completion and production data............................................................................................. 37 

Table 9. Summary and comparison of proved oil and gas reserves as of December 31, 2006, 

 and December 31, 2007........................................................................................................................ 45 

Table 10. Proved oil and gas reserves and cumulative production at end of year, 

 1975-2007............................................................................................................................................. 46 
viii
ix

ABBREVIATIONS AND ACRONYMS

AAPG American Association of Petroleum 

Geologists 

AL Alabama 

Bbbl Billion barrels 

Bbl barrels 

BBO billion barrels of oil 

BBOE billion barrels of oil equivalent 

Bcf billion cubic feet 

BOE barrels of oil equivalent 

BOEMRE Bureau of Ocean Energy 

Management, Regulation and 

Enforcement 

CFR Code of Federal Regulations 

CPA Central Planning Area 

DOCD Development Operations 

Coordination Document 

DOI U.S. Department of the Interior 

0

F degrees Fahrenheit 

FL Florida 

ft feet 

GOM Gulf of Mexico 

GOMR Gulf of Mexico Region 

GOR gas oil ratio 

LA Louisiana 

m meters 

Mcf thousand cubic feet 

mi miles 

MMbbl million barrels 

MMBOE million barrels of oil equivalent 

MMcf million cubic feet 

MMS Minerals Management Service 

MS Mississippi 

N north 

NM nautical mile 

OAP Offshore Atlas Project 

OCS Outer Continental Shelf 

OCSLA Outer Continental Shelf Lands Act 

PDN proved developed non-producing 

PDP proved developed producing 

psia pounds per square inch 

PU proved undeveloped P/Z

 pressure/gas compressibility factor 

RE Resource Evaluation 

SCF/STB standard cubic feet per stock tank 

barrel 

SE southeast 

SPE Society of Petroleum Engineers 

SPEE Society of Petroleum Evaluation 

Engineers 

Tcf trillion cubic feet 

TVDSS true vertical depth subsea 

TVT true vertical thickness 

TX Texas 

U.S. United States 

USGS United States Geological Survey 

WPA Western Planning Area 

WPC World Petroleum Congress 
x
xi

ABSTRACT

This is the annual publication that presents the Bureau of Ocean Energy Management, Regulation and 

Enforcement (BOEMRE) estimates of proved reserves in the Gulf of Mexico Outer Continental Shelf. As 

of December 31, 2007, it is estimated that there are 20.43 billion barrels of oil and 184.6 trillion cubic feet 

of gas from 1,251 proved fields. Proved reserves are the total of the cumulative production plus remaining 

proved reserves. This number includes 22 proved fields that were added during 2007. It also includes the 

298 proved fields that have produced and expired. It does not include the 53 unproved active fields. 

Estimates are derived for individual reservoirs from geologic interpretation and reserve evaluation. 

Cumulative production from the proved fields accounts for 15.55 billion barrels of oil and 169.5 trillion 

cubic feet of gas. Remaining proved reserves are estimated to be 4.88 billion barrels of oil and 15.1 

trillion cubic feet of gas. These reserves are recoverable from 953 proved active fields. 

Unproved reserves are estimated to be 4.12 billion barrels of oil and 7.3 trillion cubic feet of gas. These 

reserves are associated with the 53 unproved active fields and the unproved reserves in proved fields. In 

total, there are 1,006 proved and unproved active fields located in Federal waters. The unproved reserves 

associated with the proved and unproved active fields are not added to proved reserves because of 

decreasing levels of economic certainty and hydrocarbon assurance. For any field spanning State and 

Federal waters, reserves are estimated for the Federal portion only. 

In addition to the proved and unproved reserves discussed above, there are an estimated 1.69 billion 

barrels of oil and 9.5 trillion cubic feet of gas that are not presented in the tables and figures of this report. 

This oil and gas occurs on leases that have not yet qualified (and therefore have not been placed in a 

field) or they occur as known resources in proved fields and in unproved fields. As additional drilling and 

development occur, additional hydrocarbon volumes will become reportable, and BOEMRE anticipates 

future proved and unproved reserves to increase. 

 

The estimates of reserves for this report were completed in January 2010 and represent the combined 

efforts of engineers, geologists, geophysicists, paleontologists, and other personnel of the BOEMRE Gulf 

of Mexico Region, Office of Resource Evaluation, in New Orleans, Louisiana. 
Estimated Oil and Gas Reserves, Gulf of Mexico OCS, December 31, 2007 

xii
1

INTRODUCTION

Title VI Section 606 of the Outer Continental Shelf Lands Act September 18, 1978, requires the Secretary of the 

Interior to conduct a continuing investigation for the purpose of determining the availability of all oil and natural gas 

produced or located on the Outer Continental Shelf (OCS). The Department of the Interior’s (DOI), Bureau of Ocean 

Energy Management, Regulation and Enforcement (BOEMRE), is the federal agency responsible for overseeing the 

safe and environmentally responsible development of energy and mineral resources on the OCS. This responsibility 

includes the Federal portion of Gulf of Mexico (GOM) waters. The acronym GOM used throughout this report refers 

only to Federal waters. BOEMRE Reserves inventory, a major component of the Resource Evaluation (RE) Program, 

 is the basic foundation for energy supply forecasting, public policy decisions, independent assessment/verification, 

and the assuring of fair value in public/private transactions. For an overview of the Reserves Inventory Program visit 

BOEMRE’s Web site at http://www.boemre.gov/revaldiv/ReserveInventory.htm.

This report supersedes the MMS OCS Report, Estimated Oil and Gas Reserves, Gulf of Mexico, December 31, 2006 

(Crawford et al., 2009). It presents estimated proved reserves, cumulative production, remaining proved reserves, 

and unproved reserves as of December 31, 2007, for the GOM. Figure 1 represents the percentages of cumulative 

production, remaining proved reserves, unproved reserves and resources in the GOM presented in this report. 

Estimates of reserves growth (an observed phenomenon that occurs when there is an incremental increase through 

time in the estimates of proved reserves) as well as undiscovered and known resources are not presented in detail in 

this report. 

 

As of December 31, 2007, the 1,251 proved oil and gas fields in the federally regulated part of the GOM OCS 

contained proved reserves estimated to be 20.43 billion barrels of oil (BBO) and 184.6 trillion cubic feet (Tcf) of gas. 

 Cumulative production from the proved fields accounts for 15.55 BBO and 169.5 Tcf of gas. Remaining proved 

reserves are estimated to be 4.88 BBO and 15.1 Tcf of gas for the 953 proved active fields. Remaining proved oil 

reserves have decreased 7 percent and the remaining proved gas reserves have decreased 11 percent from the 2006 

report. Unproved reserves in the federally regulated part of the GOM OCS are estimated to be 4.12 BBO and 7.3 Tcf 

of gas. Unproved reserves in water depths greater than 1,000 feet (ft) represent 95 percent of the total unproved oil 

and 53 percent of the total unproved gas. Estimated unproved reserves for oil are 8.3 times the 2007 annual oil 

production. For gas, the estimates are 1.4 times greater than the 2007 annual gas production. 

In addition to the proved and unproved reserves discussed above, there are an estimated 1.69 BBO and 9.5 Tcf of gas 

that are not presented in the subsequent tables and figures of this report. This oil and gas occurs on leases that have 

not yet qualified (and therefore have not been placed in a field) or they occur as known resources in proved fields, or 

as known resources in unproved fields. As further drilling and development occur, additional hydrocarbon volumes 

will become reportable, and BOEMRE anticipates future proved and unproved reserves to increase. 

 7.57 (BBOE)

 5.42 (BBOE)

 3.38 (BBOE)

45.71 (BBOE)

Cumulative Production

Remaining Proved Reserves

Unproved Reserves

Resources Not Presented

5%

74%

9%

12%

15.55 Bbbl - Oil

169.5 Tcf - Gas

4.88 Bbbl - Oil

15.1 Tcf - Gas

4.12 Bbbl - Oil

 7.3 Tcf - Gas

1.69 Bbbl - Oil

 9.5 Tcf - Gas

Figure 1. BOEMRE GOM production and reserves. 
Estimated Oil and Gas Reserves, Gulf of Mexico OCS, December 31, 2007 

2
3

BACKGROUND

Definition of Resource and Reserve Terms

The BOEMRE definitions and classification schema concerning reserves reflect those approved by the Board of 

Directors, Society of Petroleum Engineers (SPE), Inc., and the Executive Board, World Petroleum Congresses 

(WPC), March 1997. The BOEMRE definitions and classification schema concerning resources are modified as 

referenced by the DOI (USGS-MMS, 1989). The BOEMRE petroleum resource and reserve classifications are 

presented in Figures 2 and 3. 

(Modified from U.S. Bureau of Mines and U.S. Geological Survey, 1980)

Increasing Hydrocarbon Assurance

Increasing Economic Certainty

Undiscovered 

Resources 

Proved Reserves

Not Within

Known 

Fields

Known

Resources Possible Probable Undeveloped Developed

Nonproducing Economically 

Recoverable

Uneconomic

Producing

Discovered Resources

Unproved

Reserves

Undrilled Prospects Drilled Prospects

Within 

Known 

Fields

Not Within

Known 

Fields

Within Known Fields

Undiscovered 

Technically

Recoverable Resources

(Modified from U.S. Bureau of Mines and U.S. Geological Survey, 1980)

Increasing Hydrocarbon Assurance

Increasing Economic Certainty

Undiscovered 

Resources 

Proved Reserves

Not Within

Known 

Fields

Known

Resources Possible Probable Undeveloped Developed

Nonproducing Economically 

Recoverable

Uneconomic

Producing

Discovered Resources

Unproved

Reserves

Undrilled Prospects Drilled Prospects

Within 

Known 

Fields

Not Within

Known 

Fields

Within Known Fields

Undiscovered 

Technically

Recoverable Resources

 Figure 2. BOEMRE conventionally recoverable petroleum resource classifications. 

Unproved

Possible

Reserves

Proved

Undeveloped

Reserves

Increasing Hydrocarbon Assurance and Economic Certainty

Known

Resources

Proved

Developed

Reserves

Unproved

Probable

Reserves

Discovery on 

Active Lease

Development

Plan

Development

Expenditure

Production and

Transportation

Equipment

Installed

Unproved Reserves Proved Reserves

Lease Expiration

Undiscovered

Technically

Recoverable

Resources

Geologic

Evidence

of Existence

Unproved

Possible

Reserves

Proved

Undeveloped

Reserves

Increasing Hydrocarbon Assurance and Economic Certainty

Known

Resources

Proved

Developed

Reserves

Unproved

Probable

Reserves

Discovery on 

Active Lease

Development

Plan

Development

Expenditure

Production and

Transportation

Equipment

Installed

Unproved Reserves Proved Reserves

Lease Expiration

Undiscovered

Technically

Recoverable

Resources

Geologic

Evidence

of Existence

 Figure 3. BOEMRE reserve classifications. 
Estimated Oil and Gas Reserves, Gulf of Mexico OCS, December 31, 2007 

4

Field 

A field is an area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same general 

geologic structural feature and/or stratigraphic trapping condition. There may be two or more reservoirs in a field 

that are separated vertically by impervious strata, laterally by local geologic barriers, or by 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 BOEMRE pursuant to the requirements of Title 30 Code of Federal Regulations 

(CFR) 250.115/116, Determination of Well Producibility (Federal Register, 2007). A field is usually named after 

the area and block on which the discovery well is located. Field names and/or field boundaries may be changed 

when additional geologic and/or production data initiate such a change. Using geological criteria, BOEMRE 

designates a new producible lease as a new field or assigns it to an existing field. A further explanation of field 

naming convention can be found in the “Reserves and Related Data Reported by Area” section on page 9 and in the 

Field Naming Handbook available from BOEMRE’s GOMR Web site: 

http://www.gomr.boemre.gov/homepg/offshore/fldresv/fldnmhbk/fldnmhbk.html.

 

Resources 

Concentrations of naturally occurring liquid or gaseous hydrocarbons that can conceivably be discovered and 

recovered are called resources. Normal use encompasses both undiscovered and discovered resources. 

Undiscovered Resources 

Hydrocarbons estimated on the basis of geologic knowledge and theory to exist outside of known accumulations 

are undiscovered resources. Undiscovered resources analogous to those in existing fields producible with current 

recovery technology and efficiency, but without any consideration of economic viability, are undiscovered 

technically recoverable resources. 

Discovered Resources 

Hydrocarbons whose location and quantity are known or estimated from specific geologic evidence are discovered 

resources. Discovered resources include known 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 on leases that are active, 

expired, relinquished, or terminated are identified as known resources. 

 

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 that can be estimated with some certainty to be potentially recoverable from 

known reservoirs, assuming future economic conditions and technological developments, are unproved reserves. 

The BOEMRE GOMR Field Names Committee designates a new producible lease as a new field or assigns it to 

an existing field. The reserves associated with new producible leases qualified pursuant to 30 CFR 250.115/116 
Background 

5

are initially considered unproved reserves. Unproved reserves are less certain to be recovered than proved 

reserves and are 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 BOEMRE 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 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 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 planned development 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 a field begins production, the reservoir and 

the field are considered proved developed producing. 

Proved Developed Nonproducing Reserves are in reservoirs that have not produced during the 12 months 

prior to the reporting date. This category includes off-production 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. 

Remaining proved reserves are the quantities of proved reserves currently estimated to be recoverable. 

Estimates of remaining proved reserves equal proved reserves minus cumulative production. 

Note: The BOEMRE definitions and classification schema concerning reserves for future Estimated Oil 

 and Gas Reserves reports will be based upon the 2007 update of reserves definitions currently being 

 adopted world-wide under the Petroleum Resource Management System. 
Estimated Oil and Gas Reserves, Gulf of Mexico OCS, December 31, 2007 

6

Reference Standard Conditions for Production and Reserves

Production data are the metered volumes of raw liquids and gas reported to the BOEMRE by Federal unit and lease 

operators. Oil and gas volume measurements and reserves are corrected to reference standard conditions of 60°F and 

one atmosphere (14.73 pounds per square inch absolute [psia]). Prior to September 1998, gas was reported at 15.025 

psia. Beginning with the production month of September 1998, gas production was reported at a pressure base of 

14.73 psia. BOEMRE is in the process of converting all historical gas production to the 14.73 pressure base. 

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. 
7

METHODOLOGY

Methods Used for Estimating Reserves 

The Reserves inventory component of the RE Program assigns new producible leases to fields and establishes field 

limits. The RE Program also develops independent estimates of original amounts of natural gas and oil in discovered 

fields by conducting field reserve studies and reviews of fields, sands, and reservoirs on the OCS. The Program 

periodically revises the estimates of remaining natural gas and oil to reflect new discoveries, development 

information and annual production. 

This report, Estimated Oil and Gas Reserves, Gulf of Mexico, December 31, 2007, is based on aggregation of 

BOEMRE internal field studies completed at the reservoir and sand levels. All of the reservoir level data have been 

linked to the sand, pool, play, chronozone, and series level to support the Offshore Atlas Project (OAP). 

Two additional reports address GOM reserves. The MMS OCS Report, Atlas of Gulf of Mexico Gas and Oil Sands as 

of January 1, 1999(Bascle et al., 2001) provides a detailed geologic reporting of oil and gas proved and unproved 

reserves. The MMS OCS Report, 2000 Assessment of Conventionally Recoverable Hydrocarbon Resources of the 

Gulf of Mexico and Atlantic Outer Continental Shelf as of January 1, 1999 (Lore et al., 2001) also known as the 

National Assessment, and its update, Assessment of Undiscovered Technically Recoverable Oil and Gas Resources of 

the Nation’s Outer Continental Shelf, 2006 (Lore, 2006) address proved and unproved reserves, reserves 

appreciation, and undiscovered resources. For information on these reports, contact the BOEMRE’s GOMR Public 

Information Office at 1-800-200-GULF or visit BOEMRE’s GOMR Web site at http://www.gomr.boemre.gov. 

Reserve estimates from geological and engineering analyses have been completed for the 1,251 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 the reserve 

estimate. As a field is depleted and/or abandoned, the proved reserves of productive reservoirs are assigned a value 

equal to the amount produced and the reserve estimate of non-producing reservoirs is converted to known resources. 

Currently, there are 298 proved expired, depleted fields. 

Estimation of reserves is done under conditions of uncertainty. Deterministic estimates provide a single “best 

estimate” based on known geological, engineering, and economic data. Probabilistic estimates generate a continuous 

range of estimates and their associated probabilities when the known geoscience, engineering, and economic data are 

used (SPE/WPC/AAPG/SPEE, 2007). 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 proved reserve estimate improves as more reservoir data become available to geoscientists and 

engineers. Reserve estimates in this report are based primarily on volumetric and performance methods. 

Analog 

In the estimation of resources/reserves by analogy, geoscientists use seismic data to generate maps of the extent of 

subsurface formations. Estimates of undiscovered resources are based on analogy with similar fields, reservoirs, or 

wells in the same area before any wells have been drilled on a prospect. The seismic data help geoscientists identify 

prospects and resources, but do not provide enough direct data alone to estimate reserves. 
Estimated Oil and Gas Reserves, Gulf of Mexico OCS, December 31, 2007 

8

The effective pore space, water saturation, net hydrocarbon thickness, pressure, volume, and temperature data, all 

necessary to complete resource estimates for prospects, come from nearby field and reservoir well data. After one or 

more wells are drilled and found producible, a volumetric estimate is done. These estimates, while incorporating 

existing data, still rely on some information obtained from analogs. 

Volumetric 

In a volumetric reserve estimate, data from drilled wells and seismic surveys are used to develop geologic models. 

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 formation fluid samples are used to determine the change in volume of oil and gas that flow 

from higher pressure and temperature conditions deep underground to lower pressure and temperature 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 in-place 

estimates to calculate proved and unproved reserves. 

Performance Methods 

In performance-technique methods, reserves are estimated by 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 production, which can also be used to predict remaining reserves. The declining daily rate is 

extrapolated to predict remaining reserves. 

Material balance, another performance method, 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 provides an estimate of gas-in-place. Recoverable gas reserves are extrapolated to an abandonment 

reservoir pressure. 
9

RESERVES AND RELATED DATA BY PLANNING AREA

The GOM OCS is divided into three planning areas for administrative purposes (Figure 4). This figure displays the 

reconfigured administrative planning area boundaries designated by BOEMRE (Federal Register, 2006). Appendix 

A provides further detail about planning area boundary changes. Each planning area is subdivided into protractions, 

which in turn are divided into numbered blocks. Fields in the GOM are identified by the protraction area name and 

block number of discovery – for example, East Cameron Block 271 (EC 271) Field. 

As the field is developed, the limits may expand into adjacent blocks and areas. These adjacent blocks are then 

identified as part of the original field and are given that field name. Statistics in this report are presented as area 

totals compiled under each field name. All of the data associated with EC 271 Field are therefore included in the 

East Cameron (EC) totals, although part of the field extends into the adjacent area of Vermilion (VR). There are four 

exceptions to the above field-naming techniques: Tiger Shoal and Lighthouse Point, included in South Marsh Island 

(SM); Coon Point, included in Ship Shoal (SS); and Bay Marchand, included in South Timbalier (ST). 

Through December 31, 2007, there were 1,006 proved and unproved active fields in the federally regulated part of 

the GOM. A list, updated quarterly, of the active and expired fields can be found in the OCS Operations Field 

Directory is available from BOEMRE’s GOMR Web site (USDOI, 2007). There were 953 proved, active (producing 

and non-producing) fields and 53 unproved active fields studied. Included are the 298 proved expired, depleted 

fields, abandoned after producing 3.1 percent barrels oil equivalent (BOE) of the total cumulative oil and gas 

production. Not studied were 87 fields expired, relinquished, or terminated without production. These fields may 

also be included in the Indicated Hydrocarbon List (Hasseltine, 2008) that can be found by visiting the BOEMRE’s 

GOMR Web site at http://www.gomr.boemre.gov/homepg/offshore/gulfocs/hclist/hclist.html. In 2007, 42 proved 

fields expired including 28 proved fields that had no production during the year. 

Reserves data and various classifications of fields, leases, boreholes, and completions are presented as area totals in 

Tables 1, 2, and 3. (Table 3 will be discussed in the section “Reserves by Geologic Age,” beginning on page 15.) 
Estimated Oil and Gas Reserves, Gulf of Mexico OCS, December 31, 2007 

10

N

Figure 4. BOEMRE GOM OCS Planning Areas. 
Reserves and Related Data by Planning Area 

11

Table 1. Estimated oil and gas reserves for 1,251 proved fields and 53 unproved fields by area, 

 December 31, 2007.

Proved Proved Proved

active active expired

prod nonprod depleted Oil Gas BOE Oil Gas BOE Oil Gas BOE Oil Gas BOE

Western Planning Area

Alaminos Canyon 3 1 0 3 2 225 399 296 65 106 84 160 293 212 226 268 273

Brazos 21 2 15 0 3 10 3,604 651 10 3,463 626 0 141 25 0 28 5

East Breaks 17 2 0 2 3 252 2,123 629 191 1,698 493 61 425 136 16 89 32

Galveston 21 7 20 1 3 69 2,219 464 56 2,005 412 13 214 52 0 46 9

Garden Banks 6 0 2 0 2 42 359 106 21 262 68 21 97 38 0 1 0

High Island and Sabine Pass 74 5 48 2 9 402 15,529 3,165 387 15,079 3,070 15 450 95 0 91 16

Matagorda Island 22 0 7 0 2 25 5,180 946 23 5,031 918 2 149 28 1 295 54

Mustang Island 11 2 16 0 5 9 1,805 330 7 1,700 309 2 105 21 13 138 38

N.& S.Padre Island 11 0 7 1 0 0 619 111 0 568 101 0 51 9 0 1 0

West Cameron and Sabine Pass 14 3 6 0 0 30 2,403 458 28 2,316 441 2 87 18 2 81 16

Western Planning Area (Other)* 0 0 0 0 1 0 0 0 0 0 0 0 0 0 0 0 0

Western Planning Area Subtotal 200 22 121 9 30 1,064 34,240 7,156 788 32,228 6,522 276 2,012 634 258 1,038 443

Central Planning Area

Atwater Valley 4 1 0 4 3 60 517 152 0 27 5 60 490 147 108 291 160

Chandeleur 6 3 4 0 0 0 372 67 0 356 64 0 16 3 0 4 1

East Cameron 41 6 19 0 0 355 10,881 2,291 330 10,502 2,198 25 379 93 4 137 28

Eugene Island 72 6 10 0 3 1,651 19,579 5,135 1,600 18,974 4,976 51 605 159 35 214 73

Ewing Bank 17 0 0 0 2 359 709 486 279 564 380 80 145 106 53 108 72

Garden Banks 20 3 5 1 2 615 3,638 1,263 508 3,052 1,051 107 586 211 68 151 95

Grand Isle 14 1 6 1 1 993 4,904 1,865 956 4,670 1,787 37 234 78 19 116 40

Green Canyon 31 3 4 12 16 2,669 3,724 3,332 941 2,354 1,360 1,728 1,370 1,972 760 595 866

Main Pass and Breton Sound 57 11 22 0 5 1,124 6,757 2,326 1,046 6,283 2,164 78 474 162 6 18 9

Mississippi Canyon 39 3 4 9 7 3,600 9,613 5,310 1,644 6,428 2,788 1,956 3,185 2,522 535 2,078 905

Mobile 22 3 8 0 2 0 2,205 393 0 1,913 341 0 292 52 0 47 8

Ship Shoal 54 2 12 1 2 1,400 12,212 3,573 1,354 11,802 3,454 46 410 119 21 183 53

South Marsh Island 38 7 6 0 0 945 14,424 3,512 880 13,794 3,334 65 630 178 14 298 67

South Pass 9 1 3 0 0 1,089 4,384 1,869 1,058 4,247 1,813 31 137 56 1 6 2

South Pelto 9 0 0 0 0 163 1,219 380 150 1,080 342 13 139 38 4 14 6

South Timbalier 45 5 11 3 1 1,646 10,855 3,577 1,503 9,520 3,197 143 1,335 380 1 28 6

Vermilion 56 8 20 0 2 570 16,394 3,487 535 15,895 3,363 35 499 124 17 343 78

Viosca Knoll 33 1 17 3 5 552 3,393 1,156 445 2,949 970 107 444 186 80 210 117

West Cameron and Sabine Pass 62 8 24 0 0 195 18,392 3,467 178 17,308 3,258 17 1,084 210 10 403 82

West Delta 19 3 2 0 3 1,382 5,587 2,376 1,352 5,395 2,312 30 192 64 12 78 26

Central Planning Area (Other)** 8 0 0 9 2 1 642 115 0 137 25 1 505 90 2,113 486 2,200

Central Planning Area Subtotal 656 75 177 43 56 19,369 150,401 46,132 14,759 137,250 39,182 4,610 13,151 6,950 3,861 5,808 4,894

Eastern Planning Area Subtotal*** 0 0 0 1 1 0 0 0 0 0 0 0 0 0 0 491 87

856 97 298

1,251

 *Western Planning Area (Other) includes Corpus Christi, Keathley Canyon, and Port Isabel.

 **Central Planning Area (Other) includes Lund, Keathley Canyon, Walker Ridge, and others.

 ***Eastern Planning Area includes DeSoto Canyon, Destin Dome, Lloyd Ridge, and others.

(Fig. 4) Expired 

nonprod

Number of fields Unproved 

reserves Area(s) Unproved 

active

Proved

reserves

GOM Total: 53 87 20,433 184,641 53,288 15,547 169,478 45,704 4,886 15,163 7,584 4,119 7,337 5,424

Cumulative 

production 

through 2007

Remaining

proved

reserves

Figure 5 provides a geographical representation of locations for the proved fields discovered in the GOM beginning 

in 1975 (year of the first Estimated Oil and Gas Reserves Report). The bar heights in the figure are relative to the 

total proved reserves BOE for each proved field by decade. 

Figure 6 provides a geographical representation of the unproved active fields discovered in the GOM. Estimates of 

unproved reserves are presented as planning area subtotals. The bar heights in the figure are relative to the total 

unproved reserves BOE for each unproved field by decade. 
Estimated Oil and Gas Reserves, Gulf of Mexico OCS, December 31, 2007 

12

TX

N AL

FL

LA

MS

1975 – 1989

1990 – 1999

2000 - 2007

Figure 5. Proved fields discovered. 

TX

N AL

FL

LA

MS

1975 – 1989

1990 – 1999

2000 - 2007

Figure 6. Unproved fields discovered. 
Reserves and Related Data by Planning Area 

13

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

 December 31, 2007. 

Area(s)

(Fig. 4) Proved Proved Unproved Unqualified

active depleted qualified active Drilled Abandoned

Western Planning Area

Alaminos Canyon 12 1 8 417 345 55 34 8

Brazos 33 56 0 68 370 593 454 136

East Breaks 35 6 2 338 486 383 257 119

Galveston 33 72 1 111 620 661 576 106

Garden Banks 7 4 0 142 218 102 82 20

High Island and Sabine Pass 153 197 2 246 1,063 3,597 2,722 974

Matagorda Island 42 44 0 44 172 650 459 239

Mustang Island 25 30 0 44 441 480 371 127

N.& S.Padre Island 15 16 1 53 343 197 153 59

West Cameron and Sabine Pass 33 45 0 45 225 532 421 159

Western Planning Area (Other)* 0 0 0 270 247 12 12 0

Western Planning Area Subtotal 388 471 14 1,778 4,530 7,262 5,541 1,947

Central Planning Area

Atwater Valley 9 0 5 277 471 100 79 11

Chandeleur 6 16 0 17 36 90 69 25

East Cameron 103 157 0 103 660 2,373 1,832 746

Eugene Island 200 143 0 112 519 5,605 4,126 1,721

Ewing Bank 33 8 0 64 249 374 272 115

Garden Banks 41 25 1 358 786 585 444 136

Grand Isle 47 34 1 38 159 1,581 1,197 515

Green Canyon 85 17 16 619 813 1,103 794 263

Main Pass and Breton Sound 144 113 0 86 432 2,923 1,809 1,334

Mississippi Canyon 132 22 16 445 817 1,506 1,012 441

Mobile 41 13 0 16 101 183 119 65

Ship Shoal 162 99 1 122 526 3,943 2,643 1,419

South Marsh Island 121 87 0 84 359 3,056 2,063 1,089

South Pass 40 20 0 16 110 2,242 1,507 944

South Pelto 22 4 0 4 32 424 303 153

South Timbalier 132 73 4 113 507 3,493 2,403 1,306

Vermilion 137 169 0 139 634 3,320 2,545 1,017

Viosca Knoll 59 29 3 83 394 617 397 189

West Cameron and Sabine Pass 168 229 0 189 813 3,302 2,502 916

West Delta 87 50 0 35 198 3,040 2,182 887

Central Planning Area (Other)** 50 0 14 1,036 448 99 74 15

Central Planning Area Subtotal 1,819 1,308 61 3,956 9,064 39,959 28,372 13,307

Eastern Planning Area Subtotal*** 0 0 2 90 328 44 41 0

GOM Total: 2,207 1,779 77 5,824 13,922 47,265 33,954 15,254

 *Western Planning Area (Other) includes Corpus Christi, Keathley Canyon, and Port Isabel.

 **Central Planning Area (Other) includes Lund, Keathley Canyon, Walker Ridge, and others.

 ***Eastern Planning Area includes DeSoto Canyon, Destin Dome, Lloyd Ridge, and others.

Number of leases Number 

of 

boreholes

Number 

of active 

completions Expired

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

The status of GOM OCS Federal oil and gas leases as of December 31, 2007, is presented in Table 2. There are 

8,108 active leases (2,207 proved active, 77 unproved qualified, and 5,824 unqualified active) and 15,701 expired 

leases (1,779 proved depleted and 13,992 expired). 

Definitions for the lease subgroups of Table 2 are: 

Proved Active — Leases within the designated 953 proved active fields presented in Table 1. 

Proved Depleted — Leases relinquished after oil and gas production. The leases associated with the 298 depleted 

fields are represented here along with other produced, relinquished leases that are part of currently active fields. 
Estimated Oil and Gas Reserves, Gulf of Mexico OCS, December 31, 2007 

14

Unproved Qualified — Leases associated with the 53 unproved active fields. The leases have qualified as producible 

under 30 Code of Federal Regulations (CFR) 250.115/116, but the operators have not established a commitment to 

produce. These fields may be classified as unproved possible or unproved probable. 

Unqualified Active — Active exploratory leases not yet qualified as producible or associated with any field. 

Expired — Leases expired, terminated, or relinquished by the operator without having produced any oil or gas, 

although some were once qualified as producible under 30 CFR 250.115/116. There are 87 expired fields with no 

production. 

The total number of boreholes drilled and the number of boreholes plugged and abandoned are also shown in Table 

2. There were 596 boreholes spudded during 2007, compared with 760 boreholes spudded during 2006, and 816 

during 2005. 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 listed in this report are based on 

reports received by the BOEMRE at the time the count was made in 2010. These numbers may change as data are 

received, processed, and edited. 
15

RESERVES BY GEOLOGIC AGE

In this report, the 1,251 proved and 53 unproved fields have been classified at the geologic series level. The different 

geologic age classifications currently in use by BOEMRE are shown in Figure 7. Paleontological examinations of 

borehole cuttings, along with regional analysis of geological and geophysical data, were used in determining the age 

classifications. In 2003 hundreds of additional foraminiferal and nannofossil bioevents were incorporated into an 

update of the BOEMRE Biostratigraphic Chart to aid in geologic mapping, stratigraphic correlation, and 

paleobathymetric zonation. (Go to: http://www.gomr.boemre.gov/homepg/whatsnew/papers/biostratchart.pdf) Using 

standardized global stratigraphic concepts, this updated version of the chart incorporates the latest information 

currently used as biostratigraphic datum markers by industry paleontologists for the Mesozoic and Cenozoic 

geologic provinces. This biostratigraphic chart update reduces the disjoint between the industry/academia 

biostratigraphic naming convention and the BOEMRE-standard chronozone naming convention, hence BOEMRE 

reserves allocations. Figures displaying trend information in this report are color-coded to match the series in the 

biostratigraphic chart. 

Table 3 shows the distribution of reserves and production data by geologic age and planning area. Please note that 

this report contains the term “Span Ages,” which is used to denote a geologic age classification that spans more than 

one series. 

Table 3. Estimated oil and gas reserves for 1,251 proved and 53 unproved fields by geologic age 

 December 31, 2007. 

 Oil Gas BOE Oil Gas BOE Oil Gas BOE Oil Gas BOE

Western Planning Area

Pleistocene 1,190 179 7,999 1,602 163 7,727 1,538 16 272 64 33 1 62 12

Pliocene 977 570 7,072 1,828 480 6,489 1,635 90 583 193 47 17 123 39

Miocene 2,546 163 18,857 3,518 144 17,990 3,344 19 867 174 154 15 585 119

Pre-Miocene 8 1 37 8 1 22 5 0 15 3 0 0 0 0

Span Ages 3 151 275 200 0 0 0 151 275 200 15 225 268 273

Western Planning Area Subtotal 4,724 1,064 34,240 7,156 788 32,228 6,522 276 2,012 634 249 258 1,038 443

Central Planning Area

Pleistocene 3,549 1,204 20,347 4,825 1,099 19,438 4,558 105 909 267 276 72 429 148

Pliocene 9,628 6,551 49,910 15,433 5,829 46,868 14,169 722 3,042 1,264 623 279 1,310 512

Miocene 11,663 10,107 77,107 23,827 7,772 69,069 20,063 2,335 8,038 3,764 841 692 3,039 1,233

Pre-Miocene 38 0 2,147 382 0 1,845 328 0 302 54 7 10 61 21

Span Ages 48 1,507 890 1,665 59 30 64 1,448 860 1,601 60 2,808 969 2,980

Central Planning Area Subtotal 24,926 19,369 150,401 46,132 14,759 137,250 39,182 4,610 13,151 6,950 1,807 3,861 5,808 4,894

Eastern Planning Area

Pre-Miocene 0 0 0 0 0 0 0 0 0 0 1 0 491 87

Eastern Planning Area Subtotal 0 0 0 0 0 0 0 0 0 1 0 491 87

GOM Planning Areas

Pleistocene 4,739 1,383 28,346 6,427 1,262 27,165 6,096 121 1,181 331 309 73 491 160

Pliocene 10,605 7,121 56,982 17,261 6,309 53,357 15,804 812 3,625 1,457 670 296 1,433 551

Miocene 14,209 10,270 95,964 27,345 7,916 87,059 23,407 2,354 8,905 3,938 995 707 3,624 1,352

Pre-Miocene 46 1 2,184 390 1 1,867 333 0 317 57 8 10 552 108

Span Ages 51 1,658 1,165 1,865 59 30 64 1,599 1,135 1,801 75 3,033 1,237 3,253

GOM Total 29,650 20,433 184,641 53,288 15,547 169,478 45,704 4,886 15,163 7,584 2,057 4,119 7,337 5,424

Area

Number of 

proved 

reservoirs

Number of 

unproved 

reservoirs reserves reserves

Proved Unproved

 Cumulative 

 production 

 through 2007 reserves

 proved

 Remaining

Data from the producing reservoirs were used to generate Table 3 and the proved reserve trends for each geologic 

age presented in Figure 8. The Pleistocene proved reserves trend presented in Figure 8 corresponds to the 

Globorotalia flexuosa through Uvigerina hispida biozones. Production within the Pleistocene extends from the 

Galveston area to east of the modern-day mouth of the Mississippi River. Deepwater Pleistocene production occurs 

in the East Breaks through Mississippi Canyon areas, and well control suggests sands continue beyond the Sigsbee 

Escarpment. Through December 31, 2007, the Pleistocene produced from 402 fields. Proved reserves were 1.38 

BBO and 28.3 Tcf. Remaining proved reserves were 0.12 BBO and 1.2 Tcf. 
Estimated Oil and Gas Reserves, Gulf of Mexico OCS, December 31, 2007 

16

Foraminifer & Ostracod (O) Nannoplankton

Globorotalia inflata

Globorotalia flexuosa Emiliania huxleyi (base of acme)

Sangamon fauna Gephyrocapsa oceanica (flood)

Gephyrocapsa caribbeanica (flood)

Helicosphaera inversa

Trimosina "A" Gephyrocapsa parallela

Pseudoemiliania ovata

Stilostomella antillea Pseudoemiliania lacunosa "C" (acme)

Trimosina "A" (acme)

Hyalinea "B" / Trimosina "B"

Angulogerina "B" Calcidiscus macintyrei

Uvigerina hispida

Globorotalia crassula (acme) Discoaster brouweri

Lenticulina 1

Globoquadrina altispira

Textularia 1

Buccella hannai (acme) Sphenolithus abies

Buliminella 1 Sphenolithus abies "B"

Globorotalia plesiotumida (acme) Discoaster quintatus

Globorotalia menardii (coiling change right-to-left) Discoaster quinqueramus

Textularia "X" Discoaster berggrenii "A"

Robulus "E"

Bigenerina "A" Minylithus convallis

Cristellaria "K" Catinaster mexicanus

Bolivina thalmanni Discoaster prepentaradiatus (increase)

Discorbis 12

Bigenerina 2 Helicosphaera walbersdorfensis

Uvigerina 3 Coccolithus miopelagicus

Globorotalia fohsi robusta Discoaster kugleri

Textularia "W" Discoaster kugleri (acme)

Globorotalia peripheroacuta Discoaster sanmiguelensis (increase)

Bigenerina humblei

Cristellaria "I" Sphenolithus heteromorphus

Cibicides opima Sphenolithus heteromorphus (acme)

Cristellaria / Robulus / Lenticulina 53 Helicosphaera ampliaperta

Amphistegina "B" Discoaster deflandrei (acme)

Robulus 43 Discoaster calculosus

Cibicides 38

Cristellaria 54 / Eponides 14

Gyroidina "K" Reticulofenestra gartneri

Catapsydrax stainforthi Sphenolithus disbelemnos

Discorbis "B" Orthorhabdus serratus

Marginulina "A" Triquetrorhabdulus carinatus

Siphonina davisi Discoaster saundersi

Lenticulina hanseni

Helicosphaera recta

Robulus "A" Dictyococcites bisectus

Heterostegina texana Sphenolithus delphix

Camerina "A"

Bolivina mexicana

Nonion struma

Textularia warreni Sphenolithus pseudoradians

Ismolithus recurvus

Hantkenina alabamensis Discoaster saipanensis

Camerina moodybranchensis Cribrocentrum reticulatum

Sphenolithus obtusus

Nonionella cockfieldensis Micrantholithus procerus

Discorbis yeguaensis Pemma basquensis

Discoaster lodoensis

Chiasmolithus californicus

Globorotalia wilcoxensis Toweius crassus

Discoaster multiradiatus

Morozovella velascoensis Fasciculithus tympaniformis

Vaginulina longiforma

Vaginulina midwayana

Globorotalia trinidadensis Chiasmolithus danicus

Globigerina eugubina

Micula decussata

Abathomphalus mayaroensis Micula prinsii FAD

Rosita fornicata

Dicarinella concavata Lithastrinus moratus

Hedbergella amabilis Stoverius achylosus

Dicarinella hagni

Planulina eaglefordensis

Rotalipora cushmani Lithraphidites acutus

Favusella washitaensis

Rotalipora gandolfii

Hayesites albiensis

Cythereis fredericksburgensis (O) Braarudosphaera hockwoldensis

Ammobaculites goodlandensis

Dictyoconus walnutensis

Eocytheropteron trinitiensis (O) Rucinolithus irregularis

Orbitolina texana

Rehacythereis? aff. R. glabrella (O)

Ticinella bejaouaensis

Choffatella decipiens

Schuleridea acuminata (O) Diadorhombus rectus

Polycostella beckmanni

Gallaecytheridea postrotunda (O)

Epistomina uhligi

Epistomina mosquensis Stephanolithion bigotii bigotii

Alveosepta jaccardi Stephanolithion bigotii maximum

Paalzowella feifeli Stephanolithion speciosum

Reinholdella crebra

Watznaueria crucicentralis

JU

Middle JM

Abbreviated BOEMRE Gulf of Mexico biostratigraphic chart illustrating chronostratigraphy, biostratigraphy, and BOEMRE chronozones codes. For the complete chart visit : 

http:/www.gomr.mms.gov/homepg/whatsnew/papers/biochart.pdf. 

M

e

s

o

z

o

i

c

C

r

e

t

a

c

e

o

u

s

Jurassic Upper

KUU

KLU

Comanchean

Lower

KUL

KML

KLL Coahuilan

Upper Gulfian

Paleocene Upper LU

Lower LL

Eocene

Upper EU

Middle EM

Lower EL

Upper OU

Lower OL

MLM

Lower

MUL

MML

MLL

PU

Lower PL

Miocene

Upper

MUU

MLU

Middle

MUM

MMM

PLU

Middle PLM

Lower PLL

C

e

n

o

z

o

i

c

Quaternary Pleistocene

Upper

T

e

r

t

i

a

r

y

N

e

o

c

e

n

e

Pliocene

Upper

P

a

l

e

o

g

e

n

e

Oligocene

Chronostratigraphy Biostratigraphy BOEMRE 

Chronozone

Province System Subsystem Series

Holocene

Figure 7. BOEMRE GOM biostratigraphic chart. 
Reserves by Geologic Age 

17

The Pliocene proved reserves trend presented in Figure 8 corresponds to the Globorotalia crassula (acme) through 

Globorotalia plesiotumida (acme) biozones. Production within the Pliocene extends from south of Galveston in the 

west to south of Mobile Bay in the east. Pliocene deepwater production extends into the areas of East Breaks, 

Garden Banks, Green Canyon, Ewing Bank, and Mississippi Canyon. Well control suggests Pliocene sands extend at 

least as far as the Sigsbee Escarpment. Through December 31, 2007, the Pliocene produced from 547 fields. 

Proved reserves were 7.12 BBO and 57.0 Tcf. Remaining proved reserves were 0.81 BBO and 3.6 Tcf. 

The Miocene proved reserves trend presented in Figure 8 corresponds to the Globorotalia menardii (coiling change 

right-to-left) through Lenticulina hanseni biozones. Production within the Miocene extends from North Padre Island 

in the west to east of the Mississippi River. Miocene productive sands also extend into deepwater from East Breaks 

and Garden Banks in the west to Ewing Bank, Green Canyon, Viosca Knoll, Mississippi Canyon, Atwater Valley, 

Destin Dome, Desoto Canyon, and Lloyd Ridge in the east. Wells indicate sands continue beyond the Sigsbee 

Escarpment. Through December 31, 2007 the Miocene produced from 722 fields. Proved reserves were 10.27 BBO 

and 96.0 Tcf. Remaining proved reserves were 2.35 BBO and 8.9 Tcf. 

The Pre-Miocene proved reserves trend presented in Figure 8 includes the Oligocene, Eocene, and Paleocene in the 

Tertiary series, and the Cretaceous and Jurassic series. These reservoirs include Jurassic Norphlet sands and Lower 

Cretaceous Carbonates. Production within the Jurassic is limited to east of the Mississippi River in the Mobile area. 

Well control suggests Pre-Miocene reservoir sands extend eastward into Destin Dome. Through December 31, 2007, 

these trends produced from 24 fields. Proved reserves were less than 0.01 BBO and 2.2 Tcf. Remaining proved 

reserves were less than 0.01 BBO and more than 0.3 Tcf. 

The proved reserves in the 7 fields that Span Ages include reservoirs from the Upper Pleistocene to the Lower 

Paleogene. Proved reserves were 1.66 BBO and 1.2 Tcf. Remaining proved reserves is essentially the same as proved 

reserves (1.60 BBO and 1.1 Tcf). 
Estimated Oil and Gas Reserves, Gulf of Mexico OCS, December 31, 2007 

18

Pleistocene Pliocene Miocene Pre-Miocene

Figure 8. Proved reserves trends. 
Reserves by Geologic Age 

19

Figures 9(a), 9(b), and 9(c) present proved reserves and production data by geologic age. This figure matches the 

chronostratigraphy by the BOEMRE in the abbreviated GOM biostratigraphic chart presented in Figure 7. This 

figure demonstrates that Miocene is the predominant reserves trend in the GOM, with the largest amount of proved 

reserves, cumulative production, and remaining proved reserves. 

Cumulative 

Production

Remaining 

Reserves

Total 

Reserves

SPAN AGES 0.059 1.598 1.658

PRE-MIOCENE 0.001 0.000 0.001

MIOCENE 7.916 2.354 10.270

PLIOCENE 6.309 0.812 7.121

PLEISTOCENE 1.262 0.121 1.383

TOTAL 15.548 4.886 20.433

Proved Oil (BBO)

0 5 10 15 20 25 30

1

2

3

4

5

 Cumulative Production Remaining Reserves 

 9(a). Proved oil reserves and production data, BBO. 

Cumulative 

Production

Remaining 

Reserves

Total 

Reserves

SPAN AGES 0.030 1.134 1.165

PRE-MIOCENE 1.867 0.317 2.185

MIOCENE 87.058 8.907 95.965

PLIOCENE 53.357 3.624 56.981

PLEISTOCENE 27.165 1.180 28.346

TOTAL 169.478 15.163 184.641

Proved Gas Reserves (TCF)

0 20 40 60 80 100 120

1

2

3

4

5

 Cumulative Production Remaining Reserves 

 9(b). Proved gas reserves and production data, Tcf. 

Cumulative 

Production

Remaining 

Reserves

Total 

Reserves

SPAN AGES 0.065 1.800 1.865

PRE-MIOCENE 0.333 0.057 0.390

MIOCENE 23.407 3.939 27.345

PLIOCENE 15.803 1.457 17.260

PLEISTOCENE 6.096 0.331 6.427

TOTAL 45.704 7.584 53.288

Proved BOE Reserves (BBOE)

0 5 10 15 20 25 30

1

2

3

4

5

 Cumulative Production Remaining Reserves 

 9(c). Proved BOE reserves and production data, BBOE. 

Figure 9. Distribution of proved reserves and production data by geologic age. 
Estimated Oil and Gas Reserves, Gulf of Mexico OCS, December 31, 2007 

20
21

RESERVES BY RESERVOIR DEPTH

In the last few years, operators have not only moved their operational activities farther offshore, but are also 

developing exploration targets that are deeper beneath the sea floor. The prolific Wilcox sands found onshore are 

being targeted in ultra-deep plays on the shelf and in deepwater. For this report, deep gas reservoirs and deep oil 

reservoirs are defined as a reservoir with a datum depth (the subsea depth to the average depth of the reservoir) at or 

greater than 15,000 ft true vertical depth subsea (TVDSS). The reservoirs were aggregated to the field level for this 

analysis. While only 3.6 percent of all proved oil and gas reservoirs have a datum depth of 15,000 ft TVDSS or 

greater, these reservoirs account for 15.5 percent of the total proved reserves in the GOM. 

Deep Gas 

The interest in deeper gas targets was spurred, in part, when the Federal Government offered shallow water deep gas 

royalty relief incentives beginning with leases acquired in Central Gulf Lease Sale 178 in 2001. On January 26, 2004, 

a new incentive for existing leases was published. This rule provided for royalty suspensions for wells drilled to deep 

depths on existing shallow water [less than 200 meters (656 ft)] leases. Deep depths were defined as 15,000 ft or 

deeper TVDSS when a well is completed and produces from a reservoir entirely below that depth, or as 18,000 ft 

TVD SS when a well without completions penetrates a reservoir target entirely below that deeper depth. Since the 

initial ruling, additional modifications have been added to encourage exploration. More information is available from 

the BOEMRE Web site at http://www.boemre.gov/econ/econROYSWDG.htm. Industry announced three deep shelf 

discoveries in 2007: the Butch Cassidy prospect in South Timbalier (ST) and the Flatrock and Hurricane Deep 

prospects in South Marsh Island (SM). One deepwater discovery, the Danny Noonan prospect in Garden Banks (GB) 

was announced.

Figure 10 shows gas reservoirs at datum depths 15,000 to 17,999 ft, 18,000 to 19,999 ft, and 20,000 ft or greater. 

The size of the bubble corresponds to proved recoverable reserves at the field level as of December 31, 2007. The 

proved reserves from reservoir depths of 15,000 ft or greater is 4.8 percent of all proved gas reserves. Mobile Block 

823 (MO 823) Field contains the reservoir with the largest proved gas reserves on the shelf. Mississippi Canyon 

Block 731 (MC 731) Field contains the reservoir with the largest proved gas reserves in deepwater. 

Deep Oil 

Below a depth of 18,000 ft oil reservoirs are primarily restricted to deep water and contain significant volumes. In 

2007 industry announced five deepwater deep oil discoveries: Droshky in Green Canyon (GC), Isabela in Mississippi 

Canyon (MC), Vicksburg in Desoto Canyon (DC), West Tonga in GC, and a Lower Tertiary discovery 

announcement at the Julia prospect in Walker Ridge (WR). 

Figures 11 shows oil reservoirs at datum depths 15,000 to 17,999 ft, 18,000 to 19,999 ft, and 20,000 ft or greater. 

The size of the bubble corresponds to proved recoverable reserves at the field level as of December 31, 2007. The 

proved reserves from target depths of 15,000 ft or greater is 10.7 percent of all proved oil reserves. South Pass Block 

89 (SP 89) Field contains the reservoir with the largest proved oil reserves on the shelf. Green Canyon Block 640 

(GC 640) Field contains the reservoir with the largest proved oil reserves in deepwater. 
Estimated Oil and Gas Reserves, Gulf of Mexico OCS, December 31, 2007 

22

AL

FL

TX LA MS

N

AL

FL

TX LA MS

N

Figure 10(a). Gas reservoirs datum depth 15,000 - 17,999 ft. 

AL

FL

TX LA MS

N

AL

FL

TX LA MS

N

 Figure 10(b). Gas reservoirs datum depth 18,000 - 20,000 ft. 

AL

FL

TX LA MS

N

AL

FL

TX LA MS

N

 Figure 10(c). Gas reservoirs datum depth > 20,000 ft. 

 Figure 10. Deep gas reservoirs by datum depth summed to field level. 
 Reserves by Reservoir Depth 

23

N

AL

FL

Figure 11(a). Oil reservoirs datum depth 15,000-17,999 ft. 

AL

FL

N

Figure 11(b). Oil reservoirs datum depth 18,000-20,000 ft. 

AL

FL

N

Figure 11(c). Oil reservoirs datum depth > 20,000 ft. 

Figure 11. Deep oil reservoirs by datum depth summed to field level. 
Estimated Oil and Gas Reserves, Gulf of Mexico OCS, December 31, 2007 

24
25

FIELD-SIZE DISTRIBUTION

Reserve sizes are expressed in terms of BOE. Gas reserves are converted to BOE and added to the liquid reserves for 

the convenience of comparison. 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 (Attanasi, 

1998), was selected for field-size (deposit-size) distribution ranges (Table 4). 

In this report, fields are classified as either oil or gas; 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. 

Table 4. Description of deposit-size classes. 

Class Deposit-size 

range* Class Deposit-size range* Class Deposit-size range*

1 0.031 - 0.062 10 16 - 32 18 4,096 - 8,192

2 0.062 - 0.125 11 32 -64 19 8,192 - 16,384

3 0.125 - 0.25 12 64 - 128 20 16,384 - 32,768

4 0.25 - 0.50 13 128 - 256 21 32,768 - 65,536

5 0.50 - 1.00 14 256 - 512 22 65,536 - 131,072

6 1 - 2 15 512 - 1,024 23 131,072 - 262,144

7 2 - 4 16 1,024 - 2,048 24 262,144 - 524,288

8 4 - 8 17 2,048 - 4,096 25 524,288 - 1,048,576

9 8 - 16 *Million Barrels of Oil Equivalent (MMBOE)

The field-size distribution based on proved BOE reserves for 1,251 proved fields is shown in Figure 12(a). Of the 

1,251 proved oil and gas fields, there are 229 proved oil fields represented in Figure 13(a) and 1,022 gas fields 

shown in Figure 14(a). The Western Gulf of Mexico field-size distributions are displayed on Figures 12(b), 13(b), 

and 14(b). Figures 12(c), 13(c), and 14(c) present the Central GOM field-size distributions of proved reserves 

including one field in the Eastern GOM. The field-size distribution, derived from unproved reserves for 53 unproved 

fields, is shown in Figure 15(a). There are 35 unproved oil fields in Figure 15(b) and 18 unproved gas fields in 

Figure 15(c). All unproved active fields were studied. 

Analysis of the 1,251 proved oil and gas fields indicates that the GOM is historically a gas-prone basin. Table 5

presents the median (exceeded by 50%) and the mean (arithmetic average) reserves from the field-size distributions. 

This figure also provides information on the largest two field-size ranges from Figures 12-15. The cumulative GOR 

of the 229 proved oil fields is 2,555 SCF/STB. The GOR of the 35 unproved oil fields is 608 SCF/STB. The yield 

(condensate divided by gas) for the 1,022 proved gas fields is 23.1 barrels (Bbl) of condensate per million cubic feet 

(MMcf) of gas. The yield of the 18 unproved gas fields is 2.8 Bbl of condensate per MMcf. 
Estimated Oil and Gas Reserves, Gulf of Mexico OCS, December 31, 2007 

26

11 12

20

39

77

125

143

152 150 153 157

104

69

29

9 1

0

50

100

150

200

Number of Fields

 < 0.062 < 0.125

 < 0.25

 < 0.5

 < 1 < 2 < 4 < 8

 < 16 < 32 < 64

 < 128 < 256 < 512

 < 1,024 < 2,048 < 4,096 < 8,192

Proved Reserves, Million Barrels of Oil Equivalent

( a ) GOM Total: 53,288 MMBOE

Median: 19.8 MMBOE

Mean: 42.6 MMBOE

Largest 10 Fields 

14% of Reserves

5 2 5 9

30 36

53 49 46

33

51

13 8 3

0

50

100

150

200

Number of Fields

 < 0.062 < 0.125

 < 0.25

 < 0.5

 < 1 < 2 < 4 < 8

 < 16 < 32 < 64

 < 128 < 256 < 512

 < 1,024 < 2,048 < 4,096 < 8,192

Proved Reserves, Million Barrels of Oil Equivalent

( b ) Western GOM Total: 7,156 MMBOE

Median: 6.5 MMBOE

Mean: 20.9 MMBOE

6 10 15

30

47

89 90

103 104

120

106

91

61

26

9 1

0

50

100

150

200

Number of Fields

 < 0.062 < 0.125

 < 0.25

 < 0.5

 < 1 < 2 < 4 < 8

 < 16 < 32 < 64

 < 128 < 256 < 512

 < 1,024 < 2,048 < 4,096 < 8,192

Proved Reserves, Million Barrels of Oil Equivalent

( c ) Central and Eastern GOM Total: 46,131 MMBOE

Median: 12.7 MMBOE

Mean: 50.8 MMBOE

Figure 12. Field-size distribution of proved fields: (a) GOM, 1,251 fields; (b) Western GOM, 343 fields; 

 (c) Central and Eastern GOM, 908 fields. 
 Field-Size Distribution 

27

3 1 1

4

8

12 14

21

30

36

39

37

15

7

1

0

10

20

30

40

50

Number of Fields

 < 0.062 < 0.125

 < 0.25

 < 0.5

 < 1 < 2 < 4 < 8

 < 16 < 32 < 64

 < 128 < 256 < 512

 < 1,024 < 2,048 < 4,096 < 8,192

Proved Reserves, Million Barrels of Oil Equivalent

( a ) GOM Total: 25,002 MMBOE

Median: 49.8 MMBOE

Mean: 108.0 MMBOE

Largest 8 Fields 

25% of Reserves

1 1 1 2 3

6 4

1 1

0

10

20

30

40

50

Number of Fields

 < 0.062 < 0.125

 < 0.25

 < 0.5

 < 1 < 2 < 4 < 8

 < 16 < 32 < 64

 < 128 < 256 < 512

 < 1,024 < 2,048 < 4,096 < 8,192

Proved Reserves, Million Barrels of Oil Equivalent

( b ) Western GOM Total: 1,170 MMBOE

Median: 39.0 MMBOE

Mean: 58.5 MMBOE

3 1 1

3

8

11 13

19

27

30

35 36

14

7

1

0

10

20

30

40

50

Number of Fields

 < 0.062 < 0.125

 < 0.25

 < 0.5

 < 1 < 2 < 4 < 8

 < 16 < 32 < 64

 < 128 < 256 < 512

 < 1,024 < 2,048 < 4,096 < 8,192

Proved Reserves, Million Barrels of Oil Equivalent

( c ) Central GOM Total: 23,833 MMBOE

Median: 55.3 MMBOE

Mean: 114.0 MMBOE

Figure 13. Field-size distribution of proved oil fields: (a) GOM, 229 fields; (b) Western GOM, 20 fields; 

 (c) Central GOM, 209 fields. 
Estimated Oil and Gas Reserves, Gulf of Mexico OCS, December 31, 2007 

28

11 9

19

38

73

117

131 138 129 123 121

65

32

14

2

0

50

100

150

200

Number of Fields

 < 0.062 < 0.125

 < 0.25

 < 0.5

 < 1 < 2 < 4 < 8

 < 16 < 32 < 64

 < 128 < 256 < 512

 < 1,024 < 2,048 < 4,096 < 8,192

Proved Reserves, Million Barrels of Oil Equivalent

Total: 28,285 MMBOE

Median: 7.0 MMBOE

Mean: 27.7 MMBOE

Largest 16 Fields 

 20% of Reserves

( a ) GOM

5 2 5 9

29 36

52 48 44

30

45

9 7 2

0

50

100

150

200

Number of Fields

 < 0.062 < 0.125

 < 0.25

 < 0.5

 < 1 < 2 < 4 < 8

 < 16 < 32 < 64

 < 128 < 256 < 512

 < 1,024 < 2,048 < 4,096 < 8,192

Proved Reserves, Million Barrels of Oil Equivalent

( b ) Western GOM Total: 5,987 MMBOE

Median: 6.2 MMBOE

Mean: 18.5 MMBOE

6 7 14

29

44

81 79

90 85 93

76

56

25

12 2

0

50

100

150

200

Number of Fields

 < 0.062 < 0.125

 < 0.25

 < 0.5

 < 1 < 2 < 4 < 8

 < 16 < 32 < 64

 < 128 < 256 < 512

 < 1,024 < 2,048 < 4,096 < 8,192

Proved Reserves, Million Barrels of Oil Equivalent

( c ) Central and Eastern GOM Total: 22,299 MMBOE

Median: 7.9 MMBOE

Mean: 31.9 MMBOE

Figure 14. Field-size distribution of proved gas fields: (a) GOM, 1,022 fields; (b) Western GOM, 323 fields; 

 (c) Central and Eastern GOM, 699 fields. 
 Field-Size Distribution 

29

2 1 1

4

1

8

4

10

9

4

2

4

2

1

0

5

10

15

Number of Fields

 < 0.062 < 0.125

 < 0.25

 < 0.5

 < 1 < 2 < 4 < 8

 < 16 < 32 < 64

 < 128 < 256 < 512

 < 1,024 < 2,048 < 4,096 < 8,192

Unproved Reserves, Million Barrels of Oil Equivalent

( a ) GOM unproved BOE Total: 3,629 MMBOE

Median: 9.1 MMBOE

Mean: 68.5 MMBOE

Largest Field 

38% of Reserves

1

2

4

9

7

4

1

4

2

1

0

5

10

15

Number of Fields

 < 0.062 < 0.125

 < 0.25

 < 0.5

 < 1 < 2 < 4 < 8

 < 16 < 32 < 64

 < 128 < 256 < 512

 < 1,024 < 2,048 < 4,096 < 8,192

Unproved Reserves, Million Barrels of Oil Equivalent

( b ) GOM unproved oil Total: 3,470 MMBOE

Median: 22.8 MMBOE

Mean: 99.1 MMBOE

Largest Field 

40% of Reserves

2

1

4

1

6

1

2

1

0

5

10

15

Number of Fields

 < 0.062 < 0.125

 < 0.25

 < 0.5

 < 1 < 2 < 4 < 8

 < 16 < 32 < 64

 < 128 < 256 < 512

 < 1,024 < 2,048 < 4,096 < 8,192

Unproved Reserves, Million Barrels of Oil Equivalent

( c ) GOM unproved gas Total: 159 MMBOE

Median: 2.2 MMBOE

Mean: 8.9 MMBOE

Largest Field 

 55% of Reserves

Figure 15. Field-size distribution of unproved fields: (a) GOM unproved BOE, 53 oil and gas fields; 

 (b) GOM unproved oil, 35 fields; (c) GOM unproved gas, 18 fields. 
Estimated Oil and Gas Reserves, Gulf of Mexico OCS, December 31, 2007 

30

Table 5. Field-size distributions. 

Number Reserves %

1,251 Proved Fig. 24a 9.8 42.6 10 14%

229 Proved Oil Fig. 25a 49.8 108.0 8 25%

1,022 Proved Gas Fig. 26a 7.0 27.7 16 20%

53 Unproved Fig. 27a 9.1 68.5 1 38%

35 Unproved Oil Fig. 27b 22.8 99.1 1 40%

18 Unproved Gas Fig. 27c 2.2 8.9 1 55%

Largest Fields

* Million barrels of oil equivalent (MMBOE)

Description of 

Fields

Figure 

Number Median* Mean*

Figure 16 shows the cumulative percent distribution of proved reserves in billion barrels of oil equivalent (BBOE), 

by field rank. All 1,251 proved fields in the GOM OCS are included in this figure. A phenomenon often observed in 

hydrocarbon-producing basins is a rapid drop-off in size from that of largest known field to smallest. Twenty-five 

percent of the proved reserves are contained in the 25 largest fields. Fifty percent of the proved reserves are 

contained in the 86 largest fields. Ninety percent of the proved reserves are contained in the 421 largest fields. 

0%

10%

20%

30%

40%

50%

60%

70%

80%

90%

100%

0 100 200 300 400 500 600 700 800 900 1,000 1,100 1,200

Number of Fields, Rank Order

Cumulative Percent

0

5

10

15

20

25

30

35

40

45

50

Billion Barrels of Oil Equivalent

90% of the proved reserves are in 

the 421 largest fields

50% of the proved reserves are in 

the 86 largest fields

25% of the proved reserves are in 

the 25 largest fields

 Figure 16. Cumulative percent total reserves versus rank order of field size for 1,251 proved fields.

Table 6 shows the distribution of the number of fields and proved reserves by water depth. A field’s water depth is 

determined by averaging the water depth of the wells drilled in the field. The water depth ranges used in this figure 

are less than 500 ft, 500-999 ft, 1,000-1,499 ft, 1,500-4,999 ft, 5,000-7,499 ft and greater than or equal to 7,500 ft. 

Proved reserves, reported in MMBOE, are associated with the 1,251 proved fields. The 53 unproved active fields are 

presented to show recent activity. Proved reserves in the GOM are located in less than 500 ft of water accounts for 85 

percent of the proved reserves. Development beyond 500 ft reflects a sizeable amount of proved reserves associated 

with a few fields. The mean proved reserves per proved field in the GOM is 42.6 MMBOE. For water depths less 

than 500 ft it is 38.4 MMBOE; for 500-999 ft it is 23.6 MMBOE; for 1,000-1,499 ft it is 57.1 MMBOE, for 1,500-

4,999 ft it is 80.2 MMBOE; for 5,000-7,499 ft it is 148.8 MMBOE; and greater than or equal to 7,500 ft it is 36.0 

MMBOE. 
 Field-Size Distribution 

31

Table 6. Field and reserves distribution by water depth. 

Water 

Depth 

Range 

(Feet)

Number of 

Proved 

Fields 

Proved 

Reserves 

(MMBOE)

Remaining 

Proved 

Reserves 

(MMBOE)

Number of 

Unproved 

Fields

Unproved 

Reserves 

(MMBOE)

< 500 1,062 40,785 1,995 11 99

500 - 999 54 1,273 107 1 8

1,000 - 1,499 22 1,257 126 1 0

1,500 - 4,999 80 6,416 2,469 24 1,085

5,000 - 7,499 21 3,125 2,496 9 2,185

>= 7,500 12 432 391 7 251

Totals: 1,251 53,288 7,584 53 3,629

Figure 17 shows the largest 20 fields ranked in order by remaining proved reserves. Eighteen of the 20 fields lie in 

water depths of greater than or equal to 1,500 ft and account for 57 percent of the remaining proved reserves in the 

GOM. 

The trend of increasing estimates of proved reserves in water greater than 500 ft is expected to continue with 

additional exploration and development. Of the 189 proved fields in water depths greater than 500 ft, 158 are 

producing, 22 are depleted, and 9 have yet to produce. There are 42 unproved active fields in water depths greater 

than 500 ft. These fields contain 3,530 MMBOE, representing 97 percent of the GOM total of estimated unproved 

reserves. 

731

621

553

503

450

208 200 193 182 161

87 80 72 71 69 65 63 44 43 42

0

100

200

300

400

500

600

700

800

Remaining Proved Reserves, 

Million Barrels of Oil Equivalent

MC778

GC743

MC807MC776

GC640GC644

AC857

GC654GC826

MC696

GC562

MC084

ST176

MC773

AT575

EB602

MC383

ST021

GB260

GC680

>= 7,500 ft

5,000 - 7,499 ft

1,500 - 4,999 ft

1,000 - 1,499 ft

500 - 999 ft

< 500 ft

4

7

1

11

14

40 60 65 52 85

133 44 18 132 199 77 104 19 76 246

Field Size Rank by

Proved Reserves

Remaining Proved Reserves

 Figure 17. Largest 20 fields ranked by remaining proved reserves. 

Table 7 lists the 50 largest proved fields ranked by proved reserves expressed in BOE. Rank, field name, field 

nickname, discovery year, water depth, field classification, field type, field GOR, proved reserves, cumulative 

production through 2007, and remaining proved reserves are presented. A complete listing of all 1,251 proved fields, 

ranked by proved reserves, is available by contacting the BOEMRE at 1-800-200-GULF or from BOEMRE’s 

GOMR Web site at http://www.gomr.boemre.gov/homepg/pubinfo/freeasci/geologic/estimated2007.html. 
Estimated Oil and Gas Reserves, Gulf of Mexico OCS, December 31, 2007 

32

Table 7. Proved fields by rank order, based on proved BOE reserves, top 50 fields. 

Oil Gas BOE Oil Gas BOE Oil Gas BOE

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

1 MC807 MARS-URSA 1989 3,392 PDP O 1,417 1,238.3 1,755.3 1,550.6 809.9 1,057.7 998.1 428.4 697.6 552.5

2 EI330 1971 247 PDP O 4,229 429.7 1,817.2 753.0 423.9 1,807.0 745.4 5.8 10.1 7.6

3 WD030 1949 48 PDP O 1,622 574.2 931.4 739.9 565.0 892.1 723.7 9.2 39.3 16.2

4 MC778 THUNDER HORSE 1999 6,080 PU O 776 642.7 498.4 731.4 0.0 0.0 0.0 642.7 498.4 731.4

5 GI043 1956 140 PDP O 4,262 381.7 1,626.6 671.1 362.7 1,545.4 637.7 19.0 81.2 33.5

6 BM002 1949 50 PDP O 1,038 529.9 549.9 627.7 524.9 540.1 621.0 4.9 9.8 6.7

7 GC743 ATLANTIS 1998 6,413 PDP O 647 558.6 361.4 623.0 1.6 0.9 1.7 557.1 360.5 621.2

8 TS000 1958 13 PDP G 83,291 39.3 3,275.4 622.1 37.7 3,161.2 600.2 1.6 114.2 22.0

9 VR014 1956 26 PDP G 64,006 48.1 3,081.0 596.4 47.9 3,058.9 592.2 0.3 22.2 4.2

10 MP041 1956 42 PDP O 5,676 266.2 1,510.5 534.9 254.4 1,458.0 513.9 11.7 52.6 21.1

11 MC776 N.THUNDER HORSE 2000 5,665 PU O 1,142 419.5 471.2 503.3 0.0 0.0 0.0 419.5 471.2 503.3

12 VR039 1948 38 PDP G 80,722 31.6 2,552.5 485.8 31.3 2,544.5 484.0 0.4 7.9 1.8

13 SS208 1960 102 PDP O 6,217 220.3 1,369.5 464.0 217.1 1,342.3 455.9 3.2 27.2 8.1

14 GC640 TAHITI 2002 4,266 PDP O 487 414.0 201.6 449.9 0.0 0.0 0.0 414.0 201.5 449.8

15 GB426 AUGER 1987 2,860 PDP O 3,575 235.3 841.3 385.0 217.4 776.4 355.5 17.9 64.9 29.5

16 WD073 1962 178 PDP O 2,466 265.3 654.2 381.7 260.4 635.9 373.6 4.8 18.3 8.1

17 GI016 1948 53 PDP O 1,269 303.6 385.2 372.2 300.1 378.7 367.5 3.5 6.5 4.7

18 ST176 1963 127 PDP G 15,772 96.4 1,519.7 366.8 82.9 1,193.6 295.3 13.5 326.1 71.5

19 ST021 1957 46 PDP O 1,775 276.8 491.3 364.2 249.0 401.7 320.4 27.8 89.6 43.7

20 SP061 1967 219 PDP O 1,923 269.3 517.7 361.4 261.6 507.9 351.9 7.7 9.8 9.4

21 EI238 1964 147 PDP G 16,211 92.1 1,492.6 357.7 86.9 1,439.5 343.0 5.2 53.0 14.6

22 ST172 1962 98 PDP G 121,506 15.7 1,913.2 356.2 11.6 1,837.7 338.6 4.1 75.5 17.5

23 SP089 1969 424 PDP O 4,437 192.0 852.1 343.6 189.4 836.5 338.2 2.6 15.5 5.4

24 WC180 1961 49 PDP G 136,936 13.3 1,827.1 338.4 12.9 1,786.4 330.7 0.5 40.7 7.7

25 SS169 1960 63 PDP O 5,420 163.5 886.0 321.1 156.8 838.6 306.0 6.6 47.4 15.1

26 MC194 COGNAC 1975 1,022 PDP O 4,174 179.9 751.1 313.6 177.3 741.6 309.3 2.6 9.5 4.3

27 SM048 1961 101 PDP G 55,952 28.6 1,600.7 313.4 27.9 1,518.7 298.1 0.7 82.0 15.3

28 EC064 1957 50 PDP G 57,750 27.3 1,574.1 307.3 26.7 1,547.0 302.0 0.5 27.0 5.3

29 EI292 1964 212 PDP G 85,166 19.0 1,616.7 306.6 18.4 1,611.4 305.2 0.5 5.3 1.5

30 EC271 1971 171 PDP G 18,827 70.4 1,325.6 306.3 68.0 1,312.0 301.5 2.4 13.5 4.8

31 SS176 1956 101 PDP G 19,876 65.2 1,295.2 295.6 63.8 1,270.1 289.8 1.3 25.1 5.8

32 SP027 EAST BAY 1954 65 PDP O 5,229 151.5 792.2 292.5 150.3 763.5 286.2 1.2 28.7 6.3

33 WC587 1971 211 PDP G 111,893 13.9 1,554.0 290.5 12.9 1,531.5 285.4 1.0 22.6 5.0

34 ST135 1956 129 PDP O 3,626 172.3 624.9 283.5 166.2 587.6 270.8 6.1 37.2 12.8

35 WC192 1954 57 PDP G 59,659 23.7 1,411.3 274.8 22.5 1,365.2 265.5 1.1 46.0 9.3

36 EI296 1971 214 PDP G 69,512 20.5 1,425.7 274.2 20.3 1,417.1 272.5 0.2 8.6 1.7

37 WD079 1966 124 PDP O 3,805 162.7 619.1 272.9 160.8 610.9 269.5 1.9 8.2 3.3

38 HI573A 1973 341 PDP O 7,686 111.4 856.2 263.7 108.5 851.8 260.1 2.9 4.4 3.7

39 MI623 1980 83 PDP G 98,994 13.9 1,372.8 258.1 13.4 1,346.9 253.0 0.5 25.9 5.1

40 GC644 HOLSTEIN 1999 4,340 PDP O 1,234 209.6 258.7 255.6 40.4 41.6 47.8 169.2 217.1 207.8

41 GI047 1955 88 PDP O 3,747 151.8 568.9 253.0 145.4 529.4 239.6 6.4 39.5 13.5

42 PL020 1951 33 PDP O 5,768 117.8 679.7 238.8 109.2 616.1 218.8 8.6 63.6 20.0

43 SP078 1972 203 PDP G 11,471 78.3 897.9 238.0 74.4 887.2 232.3 3.9 10.8 5.8

44 MC084 KING/HORN MT. 1993 5,300 PDP O 1,170 195.7 228.9 236.5 131.2 142.3 156.6 64.5 86.6 79.9

45 SM023 1960 82 PDP G 38,736 29.9 1,159.3 236.2 29.5 1,145.2 233.3 0.4 14.1 2.9

46 SM130 1973 214 PDP O 1,341 187.1 251.0 231.8 183.6 246.6 227.5 3.5 4.4 4.3

47 GC244 TROIKA 1994 2,762 PDP O 2,005 170.3 341.5 231.0 161.3 321.2 218.5 9.0 20.3 12.6

48 SM066 1963 124 PDP G 255,966 4.9 1,250.4 227.4 4.8 1,222.1 222.3 0.1 28.3 5.1

49 VK956 RAM-POWELL 1985 3,254 PDP O 8,909 87.8 782.5 227.1 83.2 760.5 218.5 4.7 22.0 8.6

50 VR076 1949 31 PDP G 141,473 8.7 1,224.8 226.6 7.6 1,178.8 217.4 1.0 46.0 9.2

 (For proved fields not qualified in 2006 the names are replaced with asterisks to preserve the proprietary nature of the data.)

 (Field class: PDP - Proved Developed Producing; PDN - Proved Developed Non-Producing; PU - Proved Undeveloped)

 (Field type: O - Oil; G - Gas)

Rank Field 

name

Disc 

year

Field 

Nickname

Cumulative production 

through 2007

Remaining 

Field proved reserves

class

Water 

depth 

(feet)

Field 

type

Proved 

reserves Field 

GOR 
33

RESERVOIR-SIZE DISTRIBUTION

The size distributions of the proved reservoirs are shown in Figures 18, 19, and 20. The size ranges are based on 

proved reserves and are presented on a geometrically progressing horizontal scale. These sizes correspond with the 

USGS deposit-size ranges shown in Table 4 with a modification to reflect small reservoirs in a finer distribution. For 

Figures 19 and 20, the proved reserves are presented in million barrels (MMbbl) and billion cubic feet (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 

18, gas is converted to BOE and added to the liquid reserves. 

Figure 18 shows the reservoir-size distribution, on the basis of proved BOE, for 2,278 proved combination 

reservoirs. The median is 0.9 MMBOE and the mean is 2.9 MMBOE. The GOR for the oil portion of the reservoirs 

is 1,190 SCF/STB, and the yield for the gas cap is 21.4 Bbl of condensate per MMcf of gas. 

Figure 19 shows the reservoir-size distribution, on the basis of proved oil, for 8,051 proved undersaturated oil 

reservoirs. The median is 0.3 MMbbl, the mean is 1.8 MMbbl, and the GOR is 1,219 SCF/STB. 

Figure 20 shows the reservoir-size distribution, on the basis of proved gas, for 17,731 gas reservoirs. The median is 

2.1 Bcf of gas, the mean is 8.5 Bcf, and the yield is 12.0 Bbl of condensate per MMcf of gas. 

0.1 0.2 0.2 0.7 1.2

2.0

3.6

6.8

8.5

13.4

16.5 16.9

13.5

8.8

4.4

2.2

0.8 0.3

0

5

10

15

20

25

Percent of Reservoirs

0.000 - 0.0010.001 - 0.0020.002 - 0.0040.004 - 0.0080.008 - 0.0160.016 - 0.0310.031 - 0.0620.062 - 0.1250.125 - 0.250

0.25 - 0.500.50 - 1.00

1 - 22 - 44 - 8

8 - 16

16 - 3232 - 64

64 - 128

128 - 256

Proved Reserves, Million Barrels of Oil Equivalent

 Median: 0.9 MMBOE

 Mean: 2.9 MMBOE

 GOR: 1,190 SCF/STB

 Yield: 21.4 bbl/MMcf

Figure 18. Reservoir-size distribution, 2,278 proved combination reservoirs. 
Estimated Oil and Gas Reserves, Gulf of Mexico OCS, December 31, 2007 

34

2.2

1.1 1.6

2.4

3.9

4.7

7.0

10.3

12.8

14.6

13.9

10.9

6.9

4.0

2.2

0.9 0.5 0.2 0.1

0

5

10

15

20

25

Percent of Reservoirs

0.000 - 0.0010.001 - 0.0020.002 - 0.0040.004 - 0.0080.008 - 0.0160.016 - 0.0310.031 - 0.0620.062 - 0.1250.125 - 0.250

0.25 - 0.500.50 - 1.00

1 - 22 - 44 - 8

8 - 16

16 - 3232 - 64

64 - 128

128 - 256

Proved Reserves, Million Barrels of Oil

 Median: 0.3 MMBOE

 Mean: 1.8 MMBOE

 GOR: 1,219 SCF/STB

 Figure 19. Reservoir-size distribution, 8,051 proved oil reservoirs. 

1.7

0.9 1.3 1.9

2.9

4.6

6.5

9.6

12.8

15.0 15.0

12.2

8.1

4.5

1.9

0.8 0.3 0.1

0

5

10

15

20

25

Percent of Reservoirs

0.0000 - 0.00580.0059 - 0.01170.0117 - 0.02340.0234 - 0.04690.0469 - 0.09380.0938 - 0.1875

0.1875 - 0.375

0.375 - 0.750

0.75 - 1.501.50 - 3.00

3 - 6

6 - 12

12 - 2424 - 4848 - 96

96 - 192

192 - 384384 - 768

Proved Reserves, Billion Cubic Feet of Gas

 Median: 2.1 MMBOE

 Mean: 8.5 MMBOE

 Yield: 12.0 bbl/MMcf

Figure 20. Reservoir-size distribution, 17,731 proved gas reservoirs. 
35

DISCOVERY AND PRODUCTION PATTERNS AND TRENDS 

It is informative to review the historic exploration and development activities that resulted in the world-class 

hydrocarbon-producing basin that is the GOM. Activity in the GOM will be examined by reviewing the status of 

exploration and development, the number of fields and quantities of proved reserves discovered during each decade. 

The discovery year for a field is defined as the year in which the first well reached total depth and encountered 

significant hydrocarbons. This date may differ from the year in which the field discovery was announced. 

Discovery of Proved Fields 

The BOEMRE first reported estimates of the GOM’s oil and gas reserves in 1975 (USGS Open File Report 77-71 

(Bryan and Knipmeyer, 1977). As expected, initial development was in shallow, nearshore waters concentrated 

mainly in the Federal waters off central and western Louisiana. This 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. Though still confined 

to the shelf (656 ft or less), field discoveries in the 1960’s and early 1970’s advanced seaward into deeper waters. 

Prior to 1975, 3,827 exploratory wells were drilled, culminating in the discovery of 342 proved fields. It was also 

during this period that 5 of the top 10 fields in the GOM, based on proved reserves, were discovered, the largest 

being West Delta Block 30 (WD 30). 

Figures 21-23 depict locations of proved fields beginning in 1975 with bar heights proportional to total proved 

reserves in BOE. 

Figure 21 shows the location of the proved fields discovered from 1975 through 1989. This period reflects 

continued drilling and development on the shelf, with an increase in field discoveries further offshore, predominantly 

of Pleistocene age. Development activities occurred over practically the entire central and western GOM shelf, as 

well as on the upper slope. In addition, the first Norphlet fields and a Miocene shallow bright spot play were 

discovered in the eastern Central GOM planning area. Exploratory drilling had reached water depths beyond 6,000 

ft. During this period, 6,175 exploratory wells were drilled, resulting in the discovery of 536 proved fields. Thirtyeight of these fields were discovered in water depths greater than 1,000 ft. Deepwater activity is discussed in more 

detail in MMS OCS Report, Deepwater Gulf of Mexico 2008: America’s Offshore Energy Future (Richardson et al., 

2008). Significant discoveries in the GOM occurred during this time period: MC 194, the first field in over 1,000 ft 

of water; and, the largest field in the GOM, MC 807, in 3,400 ft of water. 

For the 1990’s (Figure 22), 4,126 exploration wells were drilled, resulting in the discovery of 223 proved fields (53 

were discovered in water depths greater than 1,000 ft). The 1990’s saw the refinement and reduction in cost of 

tension leg platform design and an expanded use of subsea completions. Available production histories have 

documented high production rates for deepwater fields. The expanding use of horizontal drilling increased 

productivity of specific reservoirs. Computer workstation technology using three-dimensional seismic data allowed 

for reduced risk and greater geologic assurance in exploration and field development, as well as exploration of new 

plays. The fourth largest field in the GOM, MC 778, was discovered during this time period. 

From 2000 to 2007 (Figure 23), 2,936 exploration wells were drilled, resulting in the discovery of 150 proved fields. 

Nearly 30 percent of those fields were in greater than 1,000 ft of water. Reserve estimates for field discoveries 

during this period may have significant increases because of increased well control, reservoir management, and infield exploration. MC 776, the eleventh largest field in the GOM, was discovered during this time period. 
Estimated Oil and Gas Reserves, Gulf of Mexico OCS, December 31, 2007 

36

N TX

AL

FL

LA

MS

Figure 21. Location of proved fields discovered 1975-1989. 

N TX AL

FL

LA

MS

Figure 22. Location of proved fields discovered 1990-1999. 
Discovery and Production Patterns and Trends 

37

N TX AL

FL

LA

MS

Figure 23. Location of proved fields discovered 2000-2007. 

Production and Completion Trends 

The mean daily production in the GOM OCS during 2007 was 1.06 MMbbl of crude oil, 0.22 MMbbl of gas 

condensate, 1.68 Bcf of casinghead gas, and 6.06 Bcf of gas-well gas. The mean GOR of oil wells was 1,580 

SCF/STB, and the mean yield from gas wells was 36.27 Bbl of condensate per MMcf of gas. 

Table 8 summarizes the data from monthly distributions of oil and gas production rates. The highest reported 

monthly oil production volume was from a Span Ages reservoir in GC 826 with a subsea depth of 21,300 ft, during 

the month of January. The highest reported monthly gas production volume was from a Miocene reservoir in 

MC 731, with a subsea depth of 15,395 ft, during the month of July. The mean number of oil completions producing 

more than 1,000 bbl per day was 199, and the mean number of gas completions producing more than 10 MMcf per 

day was 98. 

Table 8. Monthly completion and production data. 

2007

Mean Production Volume

Mean Producing Rate

Median Production Volume

Median Producing Rate

Field Field

Highest Production Volume 740,232 bbl 4,344 MMcf

Highest Producing Rate (23,878 bbl per day) (140.1 MMcf per day)

Highest Producing Month (January) (July)

Highest Production Volume Trend (SPAN AGES) (MIOCENE)

Highest Production Volume Subsea Depth (21,300 feet) (15,395 feet)

Mean Number of Producing Completions

Mean Number of Continuously Producing 

Completions

2,537

(98 > 10MMcf per day)

Highest Monthly Mean Number of Producing 

Completions

Lowest Monthly Mean Number of Producing 

Completions

Oil Gas

2,584

(199 > 1,000 bbls per day)

1,938

2,721

(November)

2,331

(January)

12,450 bbl

(457 bbl per day)

2,129 bbl

(77 bbl per day) (0.9 MMcf per day)

GC826 MC731

2,586

1,789

(December)

2,395

(January)

72.1 MMcf

(2.7 MMcf per day)

22.2 MMcf
Estimated Oil and Gas Reserves, Gulf of Mexico OCS, December 31, 2007 

38

Production Rates 

Annual production in the GOM OCS is shown in Figure 24. The oil plot includes condensate and the gas plot 

includes casinghead gas. From 1986 through 1990, annual oil production declined 23 percent. From 1990 through 

2002, annual oil production increased 106 percent, from 275 MMbbl to 567 MMbbl. From 2002 to 2007 annual oil 

production decreased 18 percent to 468 MMbbl. 

From 1990 through 1993, annual gas production declined 5 percent. From 1993 through 2001, annual gas 

production rose from 4.7 Tcf, peaking at 5.1 Tcf in 1997, a 9-percent increase. Annual gas production reached at 

least 5.0 Tcf per year from 1996 through 1999 and in 2001. From 2001 to 2007, annual gas production declined 46 

percent to 2.8 Tcf. For further analysis of the gas production decline, see the MMS OCS Report, Gulf of Mexico Oil 

and Gas Production Forecast: 2007-2016 (Brewton et al., 2007), available from BOEMRE’s GOMR Web site at

http://www.gomr.boemre.gov/PDFs/2007/2007-020.pdf. 

0

100

200

300

400

500

600

19751977197919811983198519871989199119931995199719992001200320052007

Year

Oil (Million Barrels)

0

1

2

3

4

5

6

Gas (Trillion Cubic Feet)

Annual oil production

Annual gas production

Figure 24. Annual oil and gas production. 

Figure 25 is a plot of the number of proved gas and oil fields by discovery year. The annual number of gas fields 

discovered peaked in 1984, and has steadily declined through 2007. The number of oil fields discovered has not 

varied much from year to year, never exceeding 11, and averaging only about 3.7 discoveries per year. 

Figure 26 presents proved reserves, cumulative production, and remaining proved reserves in BBOE as of December 

31, 2007, 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 1996 are less 

than 50 percent depleted. 
Discovery and Production Patterns and Trends 

39

0

10

20

30

40

50

60

70

80

Number of Fields

19751977197919811983198519871989199119931995199719992001200320052007

Year

Proved gas fields

Proved oil fields

Figure 25. Annual number of proved oil and gas field discoveries. 

0.0

0.5

1.0

1.5

2.0

2.5

Billion Barrels of Oil Equivalent

19751977197919811983198519871989199119931995199719992001200320052007

Year

Remaining proved reserves

Cumulative production

Figure 26. Proved reserves and production by field discovery year. 

Figure 27 presents the number of proved fields and the mean field size by field discovery year. This plot shows that 

the number of discovered fields steadily declined since 1997, and the mean size of the fields has been getting smaller 

except for 1989 and for the period 1998 through 2002. The mean field size discovered is expected to increase 

because of reserves growth and additions in proved fields and reserves from unproved fields that become proved. 
Estimated Oil and Gas Reserves, Gulf of Mexico OCS, December 31, 2007 

40

0.00

0.02

0.04

0.06

0.08

0.10

19751977197919811983198519871989199119931995199719992001200320052007

Year

Billion Barrels of Oil Equivalent

0

20

40

60

80

100

Number of Fields

Number of proved fields

Mean field size - proved

reserves

Figure 27. Number of proved fields and mean field size by field discovery year. 

Figure 28 presents the number of proved and unproved fields and the average water depth of the fields discovered in 

each year. For 2001, the mean water depth for the fields discovered peaked at nearly 3,200 ft. Since 1995, the mean 

water depth has been greater than 1,000 ft, indicating that exploration and resulting production have moved into 

deeper water. 

0

1,000

2,000

3,000

4,000

19751977197919811983198519871989199119931995199719992001200320052007

Year

Water Depth (feet)

0

20

40

60

80

100

Number of Fields

Number of unproved fields

Number of proved fields

Mean water depth

Figure 28. Number of proved and unproved fields and mean water depth by field discovery year. 
Discovery and Production Patterns and Trends 

41

Figures 29 and 30 show proved oil and gas reserves and annual production by reservoir discovery year. Data 

presented in Figure 29 include crude oil and condensate, and data presented in Figure 30 include associated and 

nonassociated gas. The year of discovery assigned to a reservoir is the year in which the first well encountering 

hydrocarbons penetrated the reservoir. For comparison with the rate of discoveries, the annual production of oil and 

gas is also shown. In five of the last ten years, annual proved reserves additions for oil have exceeded annual oil 

production, resulting in an increase in remaining proved oil reserves. Since 1985, annual gas production has 

exceeded annual proved reserve additions for gas. In general, annual proved gas reserve additions have declined 

since the mid 1970’s. 

0.0

0.5

1.0

1.5

19751977197919811983198519871989199119931995199719992001200320052007

Year

Billion Barrels

0.0

0.5

1.0

1.5

Billion Barrels

Proved oil reserves

Annual oil production

Figure 29. Proved oil reserves by reservoir discovery year and annual oil production. 

0.0

2.0

4.0

6.0

8.0

19751977197919811983198519871989199119931995199719992001200320052007

Year

Trillion Cubic Feet

0.0

2.0

4.0

6.0

8.0

Trillion Cubic Feet

Proved gas reserves

Annual gas production

Figure 30. Proved gas reserves by reservoir discovery year and annual gas production. 
Estimated Oil and Gas Reserves, Gulf of Mexico OCS, December 31, 2007 

42

Figure 31 presents proved reserves in BBOE for water depth categories by reservoir discovery year. From 1975 to 

1985 the majority of reserves discovered were in less than 500 ft of water. From 1999 through 2002 the majority of 

reserves discovered occurred in greater than 1,500 ft of water. Since 2003 the majority of reserve discoveries have 

returned to less than 500 ft of water. As mentioned earlier, reserves are expected to increase because of reserves 

growth and additions in proved fields and reserves from unproved fields that become proved. 

0.00

0.50

1.00

1.50

2.00

Billion Barrels of Oil Equivalent

19751977197919811983198519871989199119931995199719992001200320052007

Years

>= 7,500 ft

5,000 - 7,499 ft

1,500 - 4,999 ft

1,000 - 1,499 ft

500 - 999 ft

< 500 ft

Figure 31. Proved BOE reserves water depth categories by reservoir discovery year. 

Figure 32 presents the total footage drilled and the number of exploratory and development wells drilled in the GOM 

OCS each year. Since 2000 the number of exploratory wells drilled has remained mostly constant. The number of 

development wells drilled per year has decreased, and the total footage drilled has decreased. 

0

500

1,000

1,500

2,000

19751977197919811983198519871989199119931995199719992001200320052007

Year

Number of Wells

0

5

10

15

20

Total Footage Drilled (Million Feet)

Exploratory wells

Development wells

Total footage

Figure 32. Number of wells and total footage drilled by year. 
Discovery and Production Patterns and Trends 

43

Figure 33 presents the number of exploratory wells drilled each year by water depth category. The plot shows an 

increase of drilling in deeper water, but also illustrates continued drilling in water depths less than 500 ft. From 1997 

through 2007, the number of exploratory wells drilled in water depths less than 500 ft decreased by nearly 50 

percent. Exploratory wells drilled in water depths greater than 1,000 ft have more than doubled since 1995. 

0

100

200

300

400

500

600

700

800

Number of Exploratory Wells

19751977197919811983198519871989199119931995199719992001200320052007

Year

>= 7,500 ft

5,000 - 7,499 ft

1,500 - 4,999 ft

1,000 - 1,499 ft

500 - 999 ft

< 500 ft

Figure 33. Number of exploratory wells drilled by water depth. 

Figure 34 presents the number of development wells drilled each year by water depth category. For water depths 

less than 500 ft development drilling peaked in 2000 to nearly 800 wells. For water depths greater than 1,000 ft 

development drilling peaked in 2001 to nearly 150 wells. From 2000 to 2007, the number of development wells 

drilled in water depths less than 500 ft decreased nearly 70 percent. Development wells drilled in water depths 

greater than 1,000 ft have decreased nearly two-thirds since 2001. 

0

200

400

600

800

1,000

1,200

1,400

Number of Development Wells

19751977197919811983198519871989199119931995199719992001200320052007

Year

>= 7,500 ft

5,000 - 7,499 ft

1,500 - 4,999 ft

1,000 - 1,499 ft

500 - 999 ft

< 500 ft

Figure 34. Number of development wells drilled by water depth. 
Estimated Oil and Gas Reserves, Gulf of Mexico OCS, December 31, 2007 

44
45

SUMMARY AND CONCLUSIONS

 

A summary of the proved reserve estimates for 2007 and a comparison with estimates from the previous year’s report 

(December 31, 2006) are shown in Table 9. There were 22 proved fields added during 2007 (2 oil fields and 20 gas 

fields), which are summarized and tabulated as increases to proved reserves. Note that 18 of the proved fields added 

were discovered prior to 2006. 

Comparison of Proved Reserves 

Proved reserve estimates are revised as additional wells are drilled and new leases are added to existing fields, and as 

reservoirs are depleted and leases relinquished. Complete reevaluations of existing field studies are conducted on the 

basis of changes in field development and/or production history. Revisions of proved reserves are summarized and 

presented as changes in Table 9. Based on periodic reviews and revisions of field studies conducted since the 2006 

report, the revisions for proved oil and gas reserves have resulted in a net increase. A net change in the proved oil 

and gas reserves is a result of combining the discoveries and the revisions. 

Table 9 demonstrates that the 2007 proved oil and gas discoveries and field revisions did not exceed production, 

resulting in a net decrease in remaining proved reserves. The remaining proved reserves decreased 6 percent for oil 

and decreased 11 percent for gas since the 2006 report. 

Table 9. Summary and comparison of GOM proved oil and gas reserves as of 

December 31, 2006, and December 31, 2007. 

Oil Gas BOE

(billion bbl) (trillion cu ft) (billion bbl)

Proved reserves:

20.30 183.6 52.97

Discoveries 0.01 0.5 0.10

Revisions 0.12 0.5 0.21

20.43 184.6 53.28

Cumulative production:

15.08 166.7 44.74

Discoveries 0.00 0.0 0.00

Revisions 0.47 2.8 0.97

15.55 169.5 45.71

Remaining proved reserves:

5.22 16.9 8.23

Discoveries 0.01 0.5 0.10

Revisions 0.12 0.5 0.21

Production during 2007 -0.47 -2.8 -0.97

Estimate, as of 12/31/2007 (this report) 4.88 15.1 7.57

*Crawford et.al., 2009

Previous estimates, as of 12/31/2006*

Estimate, as of 12/31/2007 (this report)

Previous estimates, as of 12/31/2006*

Estimate, as of 12/31/2007 (this report)

Previous estimates, as of 12/31/2006*

Table 10 presents all previous reserve estimates by year. Because of adjustments and corrections to production data 

submitted by Gulf of Mexico OCS operators, the difference between historical cumulative production for successive 

years does not always equal the annual production for the latter year. No comparisons are made for unproved 

reserves. 

 
Estimated Oil and Gas Reserves, Gulf of Mexico OCS, December 31, 2007 

46

Table 10. Proved oil and gas reserves and cumulative production at end of year, 1975-2007. 

 Oil Gas BOE Oil Gas BOE Oil Gas BOE

1975 255 6.61 59.9 17.27 3.82 27.2 8.66 2.79 32.7 8.61

1976 306 6.86 65.5 18.51 4.12 30.8 9.60 2.74 34.7 8.91

1977 334 7.18 69.2 19.49 4.47 35.0 10.70 2.71 34.2 8.80

1978 385 7.52 76.2 21.08 4.76 39.0 11.70 2.76 37.2 9.38

1979 * 417 7.71 82.2 22.34 4.83 44.2 12.69 2.88 38.0 9.64

1980 435 8.04 88.9 23.86 4.99 48.7 13.66 3.05 40.2 10.20

1981 461 8.17 93.4 24.79 5.27 53.6 14.81 2.90 39.8 9.98

1982 484 8.56 98.1 26.02 5.58 58.3 15.95 2.98 39.8 10.06

1983 521 9.31 106.2 28.21 5.90 62.5 17.02 3.41 43.7 11.19

1984 551 9.91 111.6 29.77 6.24 67.1 18.18 3.67 44.5 11.59

1985 575 10.63 116.7 31.40 6.58 71.1 19.23 4.05 45.6 12.16

1986 645 10.81 121.0 32.34 6.93 75.2 20.31 3.88 45.8 12.03

1987 704 10.76 122.1 32.49 7.26 79.7 21.44 3.50 42.4 11.04

1988 † 678 10.95 126.7 33.49 7.56 84.3 22.56 3.39 42.4 10.93

1989 739 10.87 129.1 33.84 7.84 88.9 23.66 3.03 40.2 10.18

1990 782 10.64 129.9 33.75 8.11 93.8 24.80 2.53 36.1 8.95

1991 819 10.74 130.5 33.96 8.41 98.5 25.94 2.33 32.0 8.02

1992 835 11.08 132.7 34.69 8.71 103.2 27.07 2.37 29.5 7.62

1993 849 11.15 136.8 35.49 9.01 107.7 28.17 2.14 29.1 7.32

1994 876 11.86 141.9 37.11 9.34 112.6 29.38 2.52 29.3 7.73

1995 899 12.01 144.9 37.79 9.68 117.4 30.57 2.33 27.5 7.22

1996 920 12.79 151.9 39.82 10.05 122.5 31.85 2.74 29.4 7.97

1997 957 13.67 158.4 41.86 10.46 127.6 33.17 3.21 30.8 8.69

1998 984 14.27 162.7 43.22 10.91 132.7 34.52 3.36 30.0 8.70

1999 1,003 14.38 161.3 43.08 11.40 137.7 35.90 2.98 23.6 7.18

2000 1,050 14.93 167.3 44.70 11.93 142.7 37.32 3.00 24.6 7.38

2001 1,086 16.51 172.0 47.11 12.48 147.7 38.77 4.03 24.3 8.35

2002 1,112 18.75 176.8 50.21 13.05 152.3 40.15 5.71 24.6 10.09

2003 1,141 18.48 178.2 50.19 13.61 156.7 41.49 4.87 21.5 8.70

2004 1,172 18.96 178.4 50.70 14.14 160.7 42.73 4.82 17.7 7.97

2005 1,196 19.80 181.8 52.15 14.61 163.9 43.77 5.19 17.9 8.38

2006 1,229 20.30 183.6 52.97 15.08 166.7 44.74 5.22 16.9 8.23

2007 1,251 20.43 184.6 53.28 15.55 169.5 45.71 4.88 15.1 7.57

 + Basis of reserves changed from demonstrated to SPE proved.

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.

 Proved reserves Historical cumulative production Remaining proved 

reserves

 * Gas plant liquids dropped from system

Year

Number of 

fields 

included
Summary and Conclusions 

47

Conclusions 

As of December 31, 2007, the 1,251 proved oil and gas fields in the federally regulated part of the GOM OCS 

contained proved reserves estimated to be 20.43 BBO and 184.6 Tcf of gas. Cumulative production from the proved 

fields accounts for 15.55 BBO and 169.5 Tcf of gas. Remaining proved reserves are estimated to be 4.88 BBO and 

15.1 Tcf of gas for the 953 proved active fields. Remaining proved oil reserves have decreased 7 percent and the 

remaining proved gas reserves have decreased 11 percent from the 2006 report. 

Unproved reserves in the federally regulated part of the GOM OCS are estimated to be 4.12 BBO and 7.3 Tcf of gas. 

Unproved reserves in water depths greater than 1,000 feet (ft) represent 95 percent of the total unproved oil and 53 

percent of the total unproved gas. Estimated unproved reserves for oil are 8.3 times 2007 annual oil production, and 

for gas are 1.4 times 2007 annual gas production. 

In addition to the proved and unproved reserves discussed above, there are an estimated 1.69 BBO and 9.5 Tcf of gas 

that are not presented in the tables and figures of this report. This oil and gas occurs on leases that have not yet 

qualified (and therefore have not been placed in a field) or they occur as known resources in proved fields, or as 

known resources in unproved fields. As further drilling and development occur, additional hydrocarbon volumes will 

become reportable, and BOEMRE anticipates future proved and unproved reserves to increase.
Estimated Oil and Gas Reserves, Gulf of Mexico OCS, December 31, 2007 

48
49

CONTRIBUTING PERSONNEL

This report includes contributions from the following Gulf of Mexico Region, Office of Resource Evaluation, 

personnel. 

David W. Absher 

Eric G. Kazanis 

Kellie K. Lemoine 

Lesley D. Nixon 

Robert M. Surcouf, Jr. 

Chee W. Yu 

Blake A. Zeringue 
Estimated Oil and Gas Reserves, Gulf of Mexico OCS, December 31, 2007 

50
51

REFERENCES

Attanasi, E.D., 1998, Economics and the National Assessment of United States Oil and Gas Resources, U.S. 

 Geological Survey Circular 1145, United States Government Printing Office, Washington, D.C.,Table A-4, p. 

29. 

Bascle, B.J., L.D. Nixon, and K.M. Ross, 2001, Atlas of Gulf of Mexico Gas and Oil Sands as of January 1, 1999, 

 U.S. Department of the Interior, Minerals Management Service, Gulf of Mexico OCS Region, Office of 

Resource 

 Evaluation, OCS Report MMS 2001-086, New Orleans, 342 p. Web site: 

 http://www.gomr.boemre.gov/homepg/gomatlas/atlas99.html

Brewton, A., L. Almasy, R. Baud, R. Bongiovanni, T.M. DeCort, A.G. Josey, E.G. Kazanis, T. Riches Jr., M. 

 Uli, F. Yam, Gulf of Mexico Oil and Gas Production Forecast: 2007-2016, U.S. Department of the Interior, 

 Minerals Management Service, Gulf of Mexico Region, OCS Report MMS 2007-020, New Orleans, 23 p. 

 Web site: http://www.gomr.boemre.gov/PDFs/2007/2007-020.pdf

Bryan, F.T., and Knipmeyer, J.H., 1977, Estimated Oil and Gas Reserves, Gulf of Mexico Outer Continental Shelf, 

 January 1, 1976: U.S. Geological Survey Open-File Report 77-71, 10p. 

Crawford, T.G., G.L. Burgess, S.M. Haley, P.F. Harrison, C.J. Kinler, G.D. Klocek, and N.K. Shepard, 2009,

Estimated Oil and Gas Reserves, Gulf of Mexico, December 31, 2006, U. S. Department of the Interior, 

Minerals Management Service, Gulf of Mexico Region, OCS Report MMS 2009-064, New Orleans, 48 p. Web 

site: http://www.gomr.boemre.gov/homepg/offshore/fldresv/resvmenu.html

Federal Register. 2006. Federal Outer Continental Shelf (OCS) administrative boundaries extending from the 

Submerged Lands Act boundary seaward to the limit of the United States Outer Continental Shelf. 

Tuesday, January 3, 2006. 71 FR 1, pp. 127-131. 

Hasseltine, G.H., 2008, Indicated Hydrocarbon List, Central, Western, and Eastern Gulf of Mexico, U. S. 

Department of the Interior, Minerals Management Service, Gulf of Mexico Region. Web site: 

http://www.gomr.boemre.gov/homepg/offshore/gulfocs/hclist/hclist.html

Lore, G.L., D.A. Marin, E. C. Batchelder, W. C. Courtwright, R. P. Desselles, Jr., and R. J. Klazynski, 2001, 

2000 Assessment of Conventionally Recoverable Hydrocarbon Resources of the Gulf of Mexico and Atlantic 

Outer Continental Shelf as of January 1, 1999, U.S. Department of the Interior, Minerals Management Service, 

Gulf of Mexico OCS Region, Office of Resource Evaluation, OCS Report MMS 2001-087, New Orleans, 652 

p. Web site: http://www.gomr.boemre.gov/homepg/offshore/gulfocs/assessment/assessment.html

Lore, G.L. 2006, Assessment of Undiscovered Technically Recoverable Oil and Gas Resources of the Nation’s 

 Outer Continental Shelf, 2006, U.S. Department of the Interior, Minerals Management Service, Resource 

 Evaluation Division, 6 p. Web site: 

http://www.boemre.gov/revaldiv/PDFs/2006NationalAssessmentBrochure.pdf

Office of the Federal Register, National Archives and Records Administration, 2007, Code of Federal Regulations, 

 30 CFR, Mineral Resources, U.S. Government Printing Office, Washington, D.C. Web site: 

 http://ecfr.gpoaccess.gov/cgi/t/text/text-idx?&c=ecfr&tpl=/ecfrbrowse/Title30/30tab_02.tpl

 

Richardson, G.E, L.D. Nixon, C.M. Bohannon, M.P. Gravois, E.G. Kazanis, and T.M. Montgomery, 2008, 

 Deepwater Gulf of Mexico 2008: Deepwater Gulf of Mexico 2008: America’s Offshore Energy Future, U.S. 

 Department of the Interior, Minerals Management Service, Gulf of Mexico Region, OCS Report MMS 

 2008-013, New Orleans, 102 p. Web site: http://www.gomr.boemre.gov/PDFs/2008/2008-013.pdf
Estimated Oil and Gas Reserves, Gulf of Mexico OCS, December 31, 2007 

52

Society of Petroleum Engineers (SPE), World Petroleum Congress (WPC), American Association of Petroleum 

 Geologists (AAPG), and Society of Petroleum Evaluation Engineers (SPEE), 2007, Petroleum Resource 

 Management System, 49 p. Web site: http://www.spe.org/spe-app/spe/industry/reserves/prms.htm

U.S. Department of Energy (DOE), 1989, Conversion Factors, Monthly Energy, December 1989, p. 132-133. 

U.S. Department of the Interior, Minerals Management Service, Gulf of Mexico Region, Gulf of Mexico OCS Deep 

 Gas Update: 2001-2002, OCS Report MMS 2003-026, New Orleans, 8 p. Web site: 

 http://gomr.boemre.gov/PDFs/2003/2003-026.pdf

U.S. Department of the Interior, Minerals Management Service, Gulf of Mexico Region, OCS Operations Field 

 Directory, 2007, New Orleans, 178 p. Web site: 

http://www.gomr.boemre.gov/homepg/offshore/fldresv/mastlist/mastlist.html

U.S. Geological Survey and Minerals Management Service, 1989, Estimates of Undiscovered Conventional Oil and 

 Gas Resources in the United States–A Part of the Nation’s Energy Endowment, 44 p.
53

APPENDICES

APPENDIX A. Comparison of Previous and New Planning Areas 

The BOEMRE implemented the planning area boundary realignments as initially described in the Draft Proposed 

Program for the Revised Program Outer Continental Shelf Oil and Gas Leasing Program 2007-2012 (Revised 

December 2010). BOEMRE has developed offshore administrative lines from each adjoining coastal state. 

BOEMRE undertook this task in light of the increasing number and type of both traditional and non-traditional 

energy, alternative energy-related, and other activities on the OCS. BOEMRE has used, to the extent practicable, the 

updated National Baseline (or Supreme Court fixed baselines where they exist) to derive offshore administrative 

boundaries in compliance with accepted cartographic practice. For this task, BOEMRE has used the computational 

software known as CARIS LOTS "Limits and Boundaries." This software was specifically designed to meet 

international standards for calculating marine boundaries, including United Nations Convention on the Law of the 

Sea requirements. Additional details can be accessed at http://edocket.access.gpo.gov/2006/pdf/05-24659.pdf. 

As a result of the realignment of some planning areas to follow the new administrative lines, the areas formerly 

included in the Eastern and Western Gulf Planning Area are now part of the Central Gulf Planning Area. In order to 

be able to address mapping and programming requirements of BOEMRE's Technical Information Management 

System and to offer the areas that have blocks divided by administrative lines, substantive programming changes 

were required. (See Figure A-1 modified from http://www.boemre.gov/ld/lateral/Gulf_Plan.pdf ). 

N

Note:

The Maritime boundaries and limits shown above, 

as well as the division between planning areas, are 

for initial planning purposes only and do not 

necessarily reflect the full extent of U.S. sovereign 

rights under international and domestic law.

GULF OF MEXICO NAD 27 FEDERAL OUTER 

CONTINENTAL SHELF (OCS) 

ADMINISTRATIVE BOUNDARIES

LEGEND 

January, 2010

Projection Geographic

North American Datum 1927

Offshore Administrative Boundaries

Previous Planning Area Boundaries

U.S. 200 NM Limit 

N

Note:

The Maritime boundaries and limits shown above, 

as well as the division between planning areas, are 

for initial planning purposes only and do not 

necessarily reflect the full extent of U.S. sovereign 

rights under international and domestic law.

GULF OF MEXICO NAD 27 FEDERAL OUTER 

CONTINENTAL SHELF (OCS) 

ADMINISTRATIVE BOUNDARIES

LEGEND 

January, 2010

Projection Geographic

North American Datum 1927

Offshore Administrative Boundaries

Previous Planning Area Boundaries

U.S. 200 NM Limit 

N

Note:

The Maritime boundaries and limits shown above, 

as well as the division between planning areas, are 

for initial planning purposes only and do not 

necessarily reflect the full extent of U.S. sovereign 

rights under international and domestic law.

N

Note:

The Maritime boundaries and limits shown above, 

as well as the division between planning areas, are 

for initial planning purposes only and do not 

necessarily reflect the full extent of U.S. sovereign 

rights under international and domestic law.

GULF OF MEXICO NAD 27 FEDERAL OUTER 

CONTINENTAL SHELF (OCS) 

ADMINISTRATIVE BOUNDARIES

LEGEND 

January, 2010

Projection Geographic

North American Datum 1927

Offshore Administrative Boundaries

Previous Planning Area Boundaries

U.S. 200 NM Limit 

 Figure A-1. Comparison of GOM OCS Administrative and Planning Area Boundaries.
Estimated Oil and Gas Reserves, Gulf of Mexico OCS, December 31, 2007 

54
55

APPENDIX B. Reserves Tables Prior To Planning Area Boundary Changes

In previous Estimated Oil and Gas Reserves Reports, reserves were reported by planning area and by shelf (less 

than or equal to 650 ft of water) and slope (greater than 650 ft of water). As indicated in Appendix A, BOEMRE 

realigned some planning areas to follow new administrative lines in 2007. Figure B-1 presents the status of the 

number of blocks and acres by planning area prior to the realignment in 2007 in the GOMR. Figure B-2 is a 

GOMR active lease map that presents the status of blocks and acres by planning area after the 2007 realignment. As 

a result of this change, the Central Planning Area gained 3,296 blocks and 18.65 million acres from the Western and 

Eastern Planning Areas. This change made it difficult to compare reserves by planning area in some tables from 

previous reports. For this report Appendix B presents comparable reserve tables for the previous planning area 

boundaries. 

Figure B-1. Pre-2007 GOM Planning Areas. 
Estimated Oil and Gas Reserves, Gulf of Mexico OCS, December 31, 2007 

56

Figure B-2. 2007 GOM Planning Areas. 
Appendix B 

57

Table B-1 presents the estimated oil and gas reserves for the 1,251 proved fields and 53 unproved fields as of 

December 31, 2007 by the planning area boundaries prior to 2007. In comparing Table B-1 to Table 1 (page 11) in 

this report the Central Planning Area’s gained 920 MMBOE of proved reserves and 1,491 MMBOE of unproved 

reserves from the Western and Eastern Planning Areas. 

Table B-1. Estimated oil and gas reserves for 1,251 proved and 53 unproved fields, GOM OCS, 

 December 31, 2007 (Pre-2007 Planning Areas). 

Proved Proved Proved

active active expired

prod nonprod depleted Oil Gas BOE Oil Gas BOE Oil Gas BOE Oil Gas BOE

Western Planning Area

Alaminos Canyon 3 1 0 3 2 224 399 295 64 106 84 160 293 211 226 268 273

Brazos 21 2 15 0 3 10 3,604 652 10 3,463 626 0 141 26 0 28 5

East Breaks 17 2 0 2 3 251 2,123 629 190 1,698 493 61 425 136 16 89 32

Galveston 21 7 20 1 3 69 2,219 464 56 2,005 412 13 214 52 0 46 9

Garden Banks 26 3 7 1 4 657 3,998 1,368 529 3,314 1,119 128 684 249 68 152 95

High Island and Sabine Pass 74 5 48 2 9 403 15,529 3,166 388 15,079 3,070 15 450 96 0 91 16

Matagorda Island 22 0 7 0 2 25 5,180 946 23 5,031 918 2 149 28 1 295 53

Mustang Island 11 2 16 0 5 9 1,805 330 7 1,700 309 2 105 21 13 138 38

N.& S.Padre Island 11 0 7 1 0 0 619 111 0 568 102 0 51 9 0 1 0

Western Planning Area (Other)* 0 0 0 1 1 0 0 0 0 0 0 0 0 0 1,342 297 1,395

Western Planning Area Subtotal 206 22 120 11 32 1,648 35,476 7,961 1,267 32,964 7,133 381 2,512 828 1,666 1,405 1,916

Central Planning Area

Atwater Valley 4 1 0 4 3 60 517 152 0 27 5 60 490 147 108 291 160

Chandeleur 6 3 4 0 0 0 373 67 0 356 64 0 17 3 0 4 1

East Cameron 41 6 19 0 0 355 10,881 2,291 330 10,502 2,198 25 379 93 4 137 28

Eugene Island 72 6 10 0 3 1,651 19,578 5,135 1,600 18,974 4,976 51 604 159 35 214 73

Ewing Bank 17 0 0 0 2 359 709 485 279 564 380 80 145 106 53 108 72

Grand Isle 14 1 6 1 1 993 4,904 1,865 956 4,670 1,787 37 234 78 19 116 40

Green Canyon 31 3 4 12 16 2,669 3,723 3,332 941 2,354 1,360 1,728 1,369 1,972 759 595 866

Main Pass and Breton Sound 57 11 22 0 5 1,124 6,756 2,326 1,046 6,283 2,164 78 473 162 6 18 9

Mississippi Canyon 39 3 4 9 7 3,601 9,613 5,310 1,645 6,428 2,788 1,956 3,185 2,522 535 2,077 905

Mobile 22 3 8 0 2 0 2,205 393 0 1,913 341 0 292 52 0 47 8

Ship Shoal 54 2 12 1 2 1,400 12,212 3,573 1,354 11,802 3,454 46 410 119 21 183 53

South Marsh Island 38 7 6 0 0 945 14,424 3,512 880 13,794 3,334 65 630 178 14 298 67

South Pass 9 1 3 0 0 1,089 4,383 1,869 1,058 4,247 1,813 31 136 56 1 6 2

South Pelto 9 0 0 0 0 163 1,219 380 150 1,080 342 13 139 38 4 14 6

South Timbalier 45 5 11 3 1 1,646 10,855 3,577 1,503 9,520 3,197 143 1,335 380 1 28 6

Vermilion 56 8 20 0 2 570 16,394 3,487 535 15,895 3,363 35 499 124 17 343 78

Viosca Knoll 33 1 17 3 5 552 3,394 1,156 445 2,949 970 107 445 186 80 210 117

West Cameron and Sabine Pass 76 11 30 0 0 225 20,795 3,926 206 19,624 3,698 19 1,171 227 12 484 98

West Delta 19 3 2 0 3 1,382 5,587 2,376 1,352 5,395 2,312 30 192 64 12 78 26

Central Planning Area (Other)** 0 0 0 6 1 0 0 0 0 0 0 0 0 0 762 147 788

Central Planning Area Subtotal 642 75 178 39 53 18,784 148,522 45,212 14,280 136,377 38,546 4,504 12,145 6,666 2,443 5,398 3,403

Eastern Planning Area Subtotal*** 8 0 0 3 2 1 643 115 0 137 25 1 506 90 10 534 105

856 97 298

1,251

 *Western Planning Area (Other) includes Corpus Christi, Keathley Canyon, and Port Isabel.

 **Central Planning Area (Other) includes Lund, Keathley Canyon, Walker Ridge, and others.

 ***Eastern Planning Area includes DeSoto Canyon, Destin Dome, Lloyd Ridge, and others.

(Figs. 4, 5, and 6) Expired 

nonprod

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

Number of fields

Unproved 

reserves

Area(s) Unproved 

active

Proved

reserves

GOM Total: 53 87 20,433 184,641 53,288 15,547 169,478 45,704 4,886 15,163 7,584 4,119 7,337 5,424

Cumulative 

production 

through 2007

Remaining

proved

reserves

 
Estimated Oil and Gas Reserves, Gulf of Mexico OCS, December 31, 2007 

58

Table B-2 presents the status of oil and gas leases, boreholes, and completions as of December 31, 2007 by the 

planning area boundaries prior to 2007. In comparing Table B-2 to Table 2 (page 13) in this report the Central 

Planning Area gained a total of 1,643 leases from the Western and Eastern Planning Areas. 

Table B-2. Status of oil and gas leases, boreholes, and completions by area, GOM OCS, 

 December 31, 2007 (Pre-2007 Planning Area Boundaries). 

Area(s)

(Fig. 4) Proved Proved Unproved Unqualified

active depleted qualified active Drilled Abandoned

Western Planning Area

Alaminos Canyon 12 1 8 417 345 55 34 8

Brazos 33 56 0 68 370 593 454 136

East Breaks 35 6 2 338 486 383 257 119

Galveston 33 72 1 111 620 661 576 106

Garden Banks 48 29 1 500 1,004 687 526 156

High Island and Sabine Pass 153 197 2 246 1,063 3,597 2,722 974

Matagorda Island 42 44 0 44 172 650 459 239

Mustang Island 25 30 0 44 441 480 371 127

N.& S.Padre Island 15 16 1 53 343 197 153 59

Western Planning Area 10 0 2 652 442 26 23 0

Western Planning Area Subtotal* 406 451 17 2,473 5,286 7,329 5,575 1,924

Central Planning Area

Atwater Valley 9 0 5 277 471 100 79 11

Chandeleur 6 16 0 17 36 90 69 25

East Cameron 103 157 0 103 660 2,373 1,832 746

Eugene Island 200 143 0 112 520 5,605 4,126 1,721

Ewing Bank 33 8 0 64 253 374 272 115

Grand Isle 47 34 1 38 159 1,581 1,197 515

Green Canyon 85 17 16 619 812 1,103 794 263

Main Pass and Breton Sound 144 113 0 86 433 2,923 1,809 1,334

Mississippi Canyon 132 22 16 445 816 1,506 1,012 441

Mobile 41 13 0 16 101 183 119 65

Ship Shoal 162 99 1 122 526 3,943 2,643 1,419

South Marsh Island 121 87 0 84 359 3,056 2,063 1,089

South Pass 40 20 0 16 111 2,242 1,507 944

South Pelto 22 4 0 4 32 424 303 153

South Timbalier 132 73 4 113 503 3,493 2,403 1,306

Vermilion 137 169 0 139 634 3,320 2,545 1,017

Viosca Knoll 59 29 3 83 393 617 397 189

West Cameron and Sabine Pass 201 274 0 234 1,038 3,834 2,923 1,075

West Delta 87 50 0 35 198 3,040 2,182 887

Central Planning Area 24 0 10 514 220 44 36 0

Central Planning Area Subtotal 1,785 1,328 56 3,121 8,275 39,851 28,311 13,315

Eastern Planning Area Subtotal*** 16 0 4 230 361 85 68 15

GOM Total: 2,207 1,779 77 5,824 13,922 47,265 33,954 15,254

 *Western Planning Area (Other) includes Corpus Christi, Keathley Canyon, and Port Isabel.

 **Central Planning Area (Other) includes Lund, Keathley Canyon, Walker Ridge, and others.

 ***Eastern Planning Area includes DeSoto Canyon, Destin Dome, Lloyd Ridge, and others.

Number of leases Number 

of 

boreholes

Number 

of active 

Expired completions

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

59

Table B-3 presents the proved fields affected by the GOM planning area boundary change. There were a total of 65 

fields (60 proved and 5 unproved) that had a planning area change. For the proved fields, 23 moved from Central to 

Western Planning Area, 29 moved from Western to Central Planning Area, and 8 moved from Eastern to Central 

Planning Area. For the unproved fields (not shown in the Table B-3 because of proprietary nature), 2 fields moved 

from the Western to Central Planning Area and 3 fields moved from the Eastern to Central Planning Area. 

 Table B-3. Proved fields affected by planning area boundary change. 

Field 

Name

Area 

Code Block

Pre-2007 

Planning 

Area

New 

Planning 

Area

Nickname Field 

Name

Area 

Code Block

Pre-2007 

Planning 

Area

New 

Planning 

Area

Nickname

DC133 DC 133 E C King's Peak GB783 GB 783 W C Magnolia

DC618 DC 618 E C San Jacinto GB877 GB 877 W C Red Hawk

DC621 DC 621 E C Spiderman/Amazon LL001 LL 1 E C Mondo NW

GB065 GB 65 W C LL005 LL 5 E C Atlas NW

GB070 GB 70 W C Seastar LL050 LL 50 E C Atlas 

GB072 GB 72 W C Spectacular Bid LL399 LL 399 E C Cheyenne

GB083 GB 83 W C Enchilada/Elmer PE881 PE 881 E C

GB108 GB 108 W C WC297 WC 297 C W

GB161 GB 161 W C Spend A Buck WC310 WC 310 C W Bases Loaded

GB171 GB 171 W C Salsa WC359 WC 359 C W

GB189 GB 189 W C Tick WC398 WC 398 C W

GB197 GB 197 W C WC416 WC 416 C W

GB200 GB 200 W C Northwestern WC417 WC 417 C W

GB205 GB 205 W C WC420 WC 420 C W

GB208 GB 208 W C WC424 WC 424 C W

GB236 GB 236 W C Pimento WC442 WC 442 C W

GB240 GB 240 W C Mustique WC472 WC 472 C W

GB244 GB 244 W C Cottonwood WC492 WC 492 C W

GB260 GB 260 W C Baldpate WC498 WC 498 C W

GB302 GB 302 W C GB302 WC518 WC 518 C W

GB367 GB 367 W C Dulcimer WC540 WC 540 C W

GB379 GB 379 W C WC543 WC 543 C W

GB387 GB 387 W C Llano WC546 WC 546 C W

GB388 GB 388 W C Cooper WC547 WC 547 C W

GB409 GB 409 W C Ladybug WC587 WC 587 C W

GB426 GB 426 W C Auger WC589 WC 589 C W

GB462 GB 462 W C Geauxpher WC592 WC 592 C W

GB516 GB 516 W C Serrano WC615 WC 615 C W

GB559 GB 559 W C Oregano WC635 WC 635 C W

GB602 GB 602 W C Macaroni WC663 WC 663 C W
Estimated Oil and Gas Reserves, Gulf of Mexico OCS, December 31, 2007 

60
Appendix B 

61
Notice

This report, Estimated Oil and Gas Reserves, Gulf of Mexico, December 31, 2007, 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) 736-2918 at the 

Bureau of Ocean Energy Management, Regulation and Enforcement, 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 Web site. The report can be accessed as an Acrobat 

.pdf (portable document format) file, which allows you to view, print, navigate, and search the document with the 

free downloadable Acrobat Reader 9.0. Digital data used to create the tables and figures presented in the document 

are also accessible as Excel 97 spreadsheet files (.xls; using Microsoft's Excel spreadsheet viewer, a free file viewer 

for users without access to Excel). These files are made available in a zipped format, which can be unzipped with 

the downloadable WinZip program. 

For information on this publication contact: 

Bureau of Ocean Energy Management, 

Regulation and Enforcement 

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.boemre.gov

David W. Cooke 

Regional Supervisor 

Resource Evaluation 

The Department of the Interior Mission

As the Nation's principal conservation agency, the Department of the Interior has 

responsibility for most of our nationally owned public lands and natural resources. This 

includes fostering sound use of our land and water resources; protecting our fish, wildlife, and 

biological diversity; preserving the environmental and cultural values of our national parks and 

historical places; and providing for the enjoyment of life through outdoor recreation. The 

Department assesses our energy and mineral resources and works to ensure that their 

development is in the best interests of all our people by encouraging stewardship and citizen 

participation in their care. The Department also has a major responsibility for American Indian 

reservation communities and for people who live in island territories under U.S. administration. 

The Bureau of Ocean Energy Management, 

Regulation and Enforcement Mission

As a bureau of the Department of the Interior, the Bureau of Ocean Energy Management, 

Regulation and Enforcement (BOEMRE) is the federal agency responsible for overseeing the 

safe and environmentally responsible development of traditional and renewable ocean 

energy and mineral resources on the Outer Continental Shelf (OCS). 

Moreover, in working to meet its responsibilities, the Offshore Energy and Minerals 

Management Program administers the OCS competitive leasing program and conducts and 

oversees world-class research and environmental reviews to support decision-making 

regarding offshore conventional and renewable energy development. 

The BOEMRE strives to fulfill its responsibilities through the general guiding principles of: (1) 

being responsive to the public's concerns and interests by maintaining a dialogue with all 

potentially affected parties and (2) carrying out its programs with an emphasis on working to 

enhance the quality of life for all Americans by lending BOEMRE assistance and expertise to 

economic development and environmental protection.