ON COVER—Located 150 miles (241 kilometers) southeast of New Orleans in Mississippi Canyon Block 

778 in a water depth of approximately 6,050 feet (1,844 meters), the Thunder Horse platform is the 

world's largest semisubmersible facility. British Petroleum received approval from the Minerals 

Management Service to debottleneck the topside production facilities to 275,000 barrels of oil and 

220 million standard cubic feet of natural gas per day. As of March 20, 2009, production was 

approximately 260,000 barrels of oil and 210.5 million standard cubic feet of natural gas per day from 

seven wells. The Thunder Horse Field is the largest producer in the Gulf of Mexico. (Image courtesy of 

BP America Inc.)
OCS Report 

MMS 2009-016 

Deepwater Gulf of Mexico 2009: 

Interim Report of 2008 Highlights 

Authors 

Lesley D. Nixon 

Nancy K. Shepard 

Christy M. Bohannon 

Tara M. Montgomery 

Eric G. Kazanis 

Mike P. Gravois 

Published by 

U.S. Department of the Interior 

Minerals Management Service New Orleans 

Gulf of Mexico OCS Region May 2009 

iii 

TABLE OF CONTENTS 

Page 

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

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

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

PREFACE ...................................................................................................................................xi

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

WHAT’S NEW .............................................................................................................................3

Exploration Activity ..............................................................................................................3

Production Startups ..............................................................................................................5

181 Area and 181 South Area—Acreage Available for the First Time in 20 Years...........5

New 5-Year OCS Oil and Gas Leasing Program Initiated..................................................7

Royalty and Rental Rate Increases ......................................................................................7

Change in Administrative Boundaries (Sale Boundaries) ..................................................7

BACKGROUND...........................................................................................................................9

Definitions..............................................................................................................................9

Expanding Frontier .............................................................................................................10

Ultra-Deepwater Drilling and Discoveries (≥5,000 ft or ≥1,524 m) ..................................10

Challenges and Rewards.....................................................................................................13

LEASING AND ENVIRONMENT ...........................................................................................17

5-Year OCS Oil and Gas Leasing Program........................................................................17

Water-Depth Intervals ........................................................................................................18

Leasing Activity...................................................................................................................18

Central Lease Sale 206..................................................................................................21

Eastern Lease Sale 224 .................................................................................................21

Western Lease Sale 207 ................................................................................................22

Central Lease Sale 208..................................................................................................22

Leasing Trends ....................................................................................................................22

Future Lease Activity..........................................................................................................23

Grid Programmatic Environmental Assessments .............................................................23

Recent Environmental Studies by MMS ............................................................................28

Deepwater Currents ......................................................................................................28

Sperm Whale Seismic Study .........................................................................................29

Chemosynthetic Communities ......................................................................................29

Deepwater Coral ............................................................................................................30

Deepwater Shipwreck....................................................................................................31

Subsea Processing in Deepwater Environments .........................................................31
DEEPWATER GULF OF MEXICO 2009: INTERIM REPORT OF 2008 HIGHLIGHTS

iv 

DRILLING AND DEVELOPMENT .........................................................................................33

Hurricane Safety-related Notices to Lessees and Operators ............................................33

Plans.....................................................................................................................................34

Rigs.......................................................................................................................................36

Drilling Activity...................................................................................................................37

Development Systems .........................................................................................................40

Industry Involvement and New Technologies....................................................................40

Perdido ...........................................................................................................................42

Cascade and Chinook ....................................................................................................42

Phoenix...........................................................................................................................44

Thunder Horse...............................................................................................................45

RESERVES AND PRODUCTION............................................................................................47

Reserves and Discoveries ....................................................................................................47

Production Trends ...............................................................................................................47

Production Rates .................................................................................................................51

HIGHLIGHTS AND CONCLUSIONS .....................................................................................55

Highlights ............................................................................................................................55

Conclusions ..........................................................................................................................57

America’s Offshore Energy Future.....................................................................................58

CONTRIBUTING PERSONNEL..............................................................................................59

REFERENCES ..........................................................................................................................61

APPENDICES ...........................................................................................................................65

Appendix A. Development Systems of Productive Deepwater Projects ..........................65

Appendix B. Average Annual GOM Oil and Gas Production ..........................................71
v 

FIGURES 

Page 

Figure 1. Geographic distribution of 2008 discoveries by water depth. .................. 4

Figure 2. Map of the portion of the 181 Area offered in Sale 224 and the 

portion of the 181 South Area offered in Sale 208.................................... 6

Figure 3. Deepwater discoveries by year. ............................................................... 14

Figure 4. Estimated volume of proved deepwater fields. ....................................... 15

Figure 5. Current, potential, and future hub facilities. ......................................... 16

Figure 6. Deepwater royalty-relief zones with planning areas and selected

bathymetry. .............................................................................................. 19

Figure 7. Active leases by water depth. .................................................................. 20

Figure 8. Number of leases issued each year subdivided by DWRRA 

water-depth categories............................................................................. 24

Figure 9. Number of leases bid on for each deepwater interval. ........................... 24

Figure 10. Anticipated lease expirations from 2009 to 2019.................................... 25

Figure 11. Grid PEA status. ...................................................................................... 27

Figure 12. Deepwater EP’s, DOCD’s, and DWOP’s received since 1995. ................ 35

Figure 13. Maximum number of platform rigs and MODU’s operating in the 

deepwater Gulf of Mexico in any one year. ............................................. 36

Figure 14. Approximate number of deepwater MODU’s contracted to the 

Gulf of Mexico and worldwide subdivided according to their 

maximum water-depth capabilities......................................................... 37

Figure 15. All deepwater wells drilled subdivided by water depth. ........................ 38

Figure 16. Deepwater exploratory wells drilled subdivided by water depth........... 39

Figure 17. Deepwater development wells drilled subdivided by water depth. ....... 39

Figure 18. Location map of currently installed deepwater structures by type. ...... 41

Figure 19. The BW Pioneer, the double-hulled tanker that will serve as the 

FPSO for the Cascade and Chinook developments. ............................... 43

Figure 20. The Helix Producer I, a conventional ship-shape floating 

production unit......................................................................................... 44

Figure 21. Disconnectable transfer system to attach the Helix Producer I to 

the subsea wells in the Phoenix Field..................................................... 45

Figure 22. Number and volume of deepwater discoveries. ...................................... 48
DEEPWATER GULF OF MEXICO 2009: INTERIM REPORT OF 2008 HIGHLIGHTS

vi 

Figure 23. Deepwater projects that began production in 2007 and 2008 and 

those expected to begin production by yearend 2013. ............................ 49

Figure 24a. Estimated U.S. oil production in 2007. ................................................... 51

Figure 24b. Estimated U.S. gas production in 2007................................................... 51

Figure 25a. Comparison of average annual shallow- and deepwater oil 

production................................................................................................. 52

Figure 25b. Comparison of average annual shallow- and deepwater gas 

production................................................................................................. 52

Figure 26a. Maximum historic oil well production rates. .......................................... 53

Figure 26b. Maximum historic gas well production rates.......................................... 54

Figure 27. Average lag time from leasing to first production for producing 

deepwater fields. ...................................................................................... 57
vii 

TABLES 

Page 

Table 1. Deepwater Discoveries for 2008..................................................................... 3

Table 2. Industry Comments on 2008 Deepwater Discoveries ................................... 3

Table 3. Discoveries in Water Depths Greater than 5,000 ft (1,524 m) ................... 11

Table 4. Number of Active Leases by Water-Depth Interval.................................... 21

Table 5. Grid PEA Status within the Central and Western Planning Areas .......... 27

Table 6. Top 20 Producing Blocks for the Years 2006-2007...................................... 50

ix 

ABBREVIATIONS AND ACRONYMS 

2D two dimensional 

3D three dimensional 

AC Alaminos Canyon 

APD Application for Permit to Drill 

API American Petroleum Institute 

APM Application for Permit to Modify 

AT Atwater Valley 

AVO amplitude variation with offset 

bbl barrels 

BBOE billion barrels of oil equivalent 

Bcf billion cubic feet 

Bcf/d billion cubic feet per day 

BOE barrels of oil equivalent 

BOE/d barrels of oil equivalent per day 

bo/d barrels of oil per day 

bw/d barrels of water per day 

cf/d cubic feet per day 

CID Conservation Information 

Document 

cm/s centimeters per second 

CPA Central Planning Area 

CSA Continental Shelf Associates 

CZM coastal zone management 

DC DeSoto Canyon 

o C degrees Celsius 

o F degrees Fahrenheit 

DOCD Development Operations 

Coordination Document 

DTS disconnectable transfer system 

DVA direct vertical access 

DWOP Deep Water Operations Plan 

DWRRA Deep Water Royalty Relief Act 

EA environmental assessment 

EB East Breaks 

EIS environmental impact 

statement 

EP Exploration Plan 

ESP electric submersible pump 

EW Ewing Bank 

FPS floating production system 

FPSO floating production, storage, and 

offloading 

FPU floating production unit 

FR Federal Register

ft feet 

ft/s feet per second 

GB Garden Banks 

GC Green Canyon 

GGS Global Geo Services ASA 

GOM Gulf of Mexico 

IAD industry-announced discovery 

KC Keathley Canyon 

km kilometers 

km2 square kilometers 

LL Lloyd Ridge 

m meters 

MC Mississippi Canyon 

Mcf thousand cubic feet 

mi miles 

mi2 square miles 

MMbbl million barrels 

MMcf/d million cubic feet per day 

MMS Minerals Management Service 

MODU mobile offshore drilling unit 

MTLP mini-tension-leg platform 

N north 

NEPA National Environmental Policy 

Act 

NOAA National Oceanic and 

Atmospheric Administration 

NTL Notice to Lessees and Operators 

NW northwest 

OCS Outer Continental Shelf 

OCSLA Outer Continental Shelf Lands 

Act 

OSTS Office of Structural and 

Technical Support 

PEA programmatic environmental 

assessment 

psi pounds per square inch 

RP recommended practice 

SAIC Science Applications 

International Corporation 

SE southeast 

SWSS Sperm Whale Seismic Study 

TGS TGS-NOPEC Geophysical 

Company ASA 

TLP tension-leg platform 

U.S. United States 

USDOI United States Department of 

the Interior 

USGS United States Geological Survey 

WP well protector 

WR Walker Ridge 

xi 

PREFACE 

This is the ninth publication that the Minerals Management Service has released chronicling 

deepwater exploration, development, and production activities in the Gulf of Mexico. For this 

report, deep water is considered to be water depths of 1,000 feet (305 meters) or greater. 

Leasing activity in the deepwater Gulf remains strong. Central Sale 206, held on March 19, 

2008, attracted approximately $3.7 billion in high bids—the most since Federal offshore leasing 

began in 1954. The Minerals Management Service received 1,057 bids from 85 companies on 

615 blocks, of which 603 were ultimately awarded. Sixty-nine percent of all blocks receiving 

bids were in 1,000 feet (305 meters) of water or greater. Occurring on the same day as Sale 206, 

Eastern Sale 224 garnered over $65 million in high bids, attracting 58 bids from six companies 

on 36 blocks, of which all were ultimately awarded. All acreage offered was in water depths 

greater than 2,625 feet (800 meters). Western Sale 207, held on August 20, 2008, attracted 

approximately $487 million in high bids. The Minerals Management Service received 423 bids 

from 53 companies on 319 blocks, of which 313 were ultimately awarded. Seventy-eight percent 

of all blocks receiving bids were in 1,000 feet (305 meters) of water or greater. Central Sale 208, 

held on March 18, 2009, attracted approximately $703 million in high bids. The Minerals 

Management Service received 476 bids from 70 companies on 348 blocks. Seventy-two percent 

of all blocks receiving bids were in 1,000 feet (305 meters) of water or greater. 

There were 15 industry-announced discoveries in 2008, almost double the number of 

discoveries in 2007. Deep water has continued to be a very important part of the total Gulf 

production, providing approximately 70 percent of the oil and 36 percent of the gas in the 

region. At the end of 2008, there were 141 producing projects in the deepwater Gulf, up from 

130 at the end of 2007. The 20 highest producing blocks in the Gulf continue to be located in 

deep water. Seven deepwater projects, including Thunder Horse, began production last year. 

The Thunder Horse Field is now the largest producer in the Gulf, with production of 

approximately 260,000 barrels of oil per day. 

The first floating production, storage, and offloading facility in the U.S. Gulf, the BW Pioneer

vessel, will develop the Cascade and Chinook Fields in Walker Ridge, with first oil production 

expected in 2010. This development project will utilize four technologies considered new to the 

Gulf, including free-standing hybrid risers, polyester mooring, electric submersible booster 

pumps, and shuttle tankers for oil export. Another first for the Gulf will be the use of a shipshape, floating production unit, the Helix Producer I vessel, for the Phoenix development in 

Green Canyon, with a planned production startup in 2010. A disconnectable transfer system 

will be used to connect the subsea wells to the Helix Producer I, also a first for the U.S. Gulf. 

Also scheduled to begin production in 2010 are the projects tied back to the Perdido Regional 

Host facility in Alaminos Canyon. The truss spar was installed in over 8,000 feet (2,438 meters) 

of water in August 2008 and sets a record for the deepest spar in the world. Perdido is the first 

application of full, host-scale subsea separation and boosting in the U.S. Gulf. 

The Minerals Management Service is a responsible steward of U.S. offshore resources by 

ensuring the receipt of fair market value for the sale of leases, encouraging conservation, 

evaluating and approving new technology, and regulating drilling and production. 

Lars Herbst 

Regional Director 

Gulf of Mexico OCS Region 

Minerals Management Service

1 

INTRODUCTION 

The Deepwater Gulf of Mexico 2009 report is a condensed and updated edition of the 

biennial deepwater report published by the Minerals Management Service (MMS) 

(Richardson et al., 2008). The 2009 report provides an up-to-date review of activities in the 

deepwater U.S. Gulf of Mexico (GOM), including highlights from 2008. All statistics in this 

report are gleaned from data as of the end of December 2008, except production volumes 

and rates, which were compiled through the end of December 2007 (the most recent 

calendar year of complete production data available at the time of this publication). 

The deepwater GOM is an integral part of the Nation’s oil and gas supply and one of the 

world’s most important oil and gas provinces. Numerous highlights this past year include 

(1) the record-setting Lease Sale 206, which attracted $3.7 billion in high bids—the most 

since Federal offshore leasing began in 1954, (2) exploratory drilling that resulted in 

15 new discoveries, and (3) the number of producing projects in the deepwater GOM at the 

end of 2008 was 141, up from 130 at the end of 2007. 

Detailed statistics and discussions of these and other highlights are presented in this 

report, which is divided into six sections. 

The What’s New section includes: 

• Discoveries in 2008 

• Production startups 

• New acreage available for the first time in 20 years 

• New 5-Year OCS Oil and Gas Leasing Program 

• Increase in royalty and rental rates 

• Sale boundary changes 

The Background section includes: 

• Definition of key terms 

• Ultra-deepwater drilling and discoveries 

• Deepwater discoveries by year 

• Proved field sizes 

• Hub facilities 

The Leasing and Environment section includes: 

• Information on the 5-Year OCS Oil and Gas Leasing Program 

• Leasing activities and trends 

• Sales 206, 224, 207, and 208 statistics 

• Future leasing activities, including anticipated lease expirations 

• Grid programmatic environmental assessments 

• Recent MMS environmental studies 
DEEPWATER GULF OF MEXICO 2009: INTERIM REPORT OF 2008 HIGHLIGHTS

2 

The Drilling and Development section includes: 

• Hurricane safety-related Notices to Lessees and Operators (NTL’s) 

• Information on operational plans 

• Statistics on GOM and worldwide rig availability 

• Deepwater drilling activities 

• Deepwater development systems 

• New GOM technologies and deepwater developments 

The Reserves and Production section includes: 

• Historical deepwater reserve additions 

• Deepwater projects online between 2007 and 2013 

• Information on the top 20 producing blocks 

• Shallow-water and deepwater production comparison 

• High deepwater production rates 

The Highlights and Conclusions section includes: 

• Highlights from 2008 and early 2009 

• Lease acquisition to production lag times 
3 

WHAT’S NEW 

EXPLORATION ACTIVITY

Exploratory drilling in the deepwater GOM has found more than 6.6 billion barrels of oil 

equivalent (BBOE) since 2002, more than double the amount reported in the 2005 

Deepwater Interim Report (French et al., 2005). Exploration efforts in 2008 have resulted 

in 15 new deepwater discoveries (Table 1). Industry comments on many of these 

discoveries are shown in Table 2. Five of these discoveries were drilled in water depths 

greater than 5,000 feet (ft) [1,524 meters (m)] (Figure 1). 

Table 1. Deepwater Discoveries for 2008 

Prospect Name Area/Block Water Depth (ft) Operator 

Diamond LL 370 9,975 Murphy 

Hal WR 848 7,657 Statoil/ExxonMobil 

Tortuga MC 561 6,302 Noble Energy 

Freedom MC 948 6,095 British Petroleum/Noble Energy 

Dalmatian DC 48 5,876 Murphy 

Kodiak MC 771 4,986 British Petroleum 

(unnamed) GC 448 3,266 LLOG 

Gladden MC 800 3,116 Newfield Exploration 

(unnamed) MC 503 3,099 LLOG 

Geauxpher GB 462 2,820 Mariner Energy 

Anduin West MC 754 2,696 Newfield Exploration 

Sargent GB 339 2,180 Deep Gulf Energy 

(unnamed) MC 72 2,013 LLOG 

(unnamed) VK 821 1,030 Walter Oil & Gas 

Shaft GC 141 1,003 LLOG 

Table 2. Industry Comments on 2008 Deepwater Discoveries 

Prospect Name Industry Comments 

Diamond natural gas play was found for sufficient subsea tieback 

Hal subsalt, four-way closure in the Paleogene fold belt play 

Tortuga encountered natural gas in a secondary objective 

Freedom greater than 550 net ft of hydrocarbon-bearing sands 

Dalmatian 120 ft measured depth of net high quality natural gas pay 

Kodiak about 500 net ft of hydrocarbon-bearing sands in Middle & Lower Miocene reservoirs 

unnamed (GC 448) over 85 ft of oil-bearing sand 

Gladden 80 ft of net oil pay 

unnamed (MC 503) over 380 ft of gas and oil pay zones in four separate reservoir packages 

Geauxpher gross proved and probable reserves of approximately 100 Bcf natural gas equivalent 

Anduin West 30 ft of net gas and condensate pay 

Sargent 45 ft of net gas pay 

unnamed (MC 72) over 100 ft of gross gas-filled sand 

unnamed (VK 821) will be a one well subsea tieback to infrastructure on an adjacent block 
4 

Figure 1. Geographic distribution of 2008 discoveries by water depth. 
WHAT ’S NE W

5 

PRODUCTION STARTUPS

Numerous large deepwater projects have transitioned from an exploratory and appraisal 

phase into a production phase. For example, in 2007, Atlantis in Green Canyon Block 787 

[semisubmersible capacity of 200,000 barrels of oil per day (bo/d) and 180 million cubic feet 

per day (MMcf/d)] and the fields tied into the Independence Hub production facility in 

Mississippi Canyon Block 920 [floating production unit (FPU) capacity of 1 billion cubic feet 

per day (Bcf/d)] came online. This trend continued into 2008 and continues for the near 

future, with production startups at: 

• Thunder Horse in Mississippi Canyon Block 778 (semisubmersible capacity of 

275,000 bo/d and 220 MMcf/d) in 2008 

• Tahiti in Green Canyon Block 640 (truss spar capacity of 125,000 bo/d and 

70 MMcf/d) in 2009 

• Thunder Hawk in Mississippi Canyon Block 734 (semisubmersible capacity of 

60,000 bo/d and 70 MMcf/d) in 2009 

• Thunder Horse North in Mississippi Canyon Block 776 (tied back to the 

Thunder Horse facility) in 2009 

• Cascade and Chinook in Walker Ridge Blocks 206 and 469, respectively, 

[floating production, storage, and offloading (FPSO) system oil storage 

capacity of 600,000 barrels, oil processing capacity of 80,000 bo/d, and gas 

export capacity of 16 MMcf/d] in 2010 

• Phoenix in Green Canyon Block 237 (FPU maximum capacity of 45,000 bo/d 

and 72 MMcf/d) in 2010 

• Great White, Silvertip, and Tobago tied into the Perdido Regional Host 

facility in Alaminos Canyon Block 857 [truss spar capacity of 100,000 bo/d 

and 200,000 cubic feet per day (cf/d)] in 2010 

These projects, among others, represent commitments by industry to overcome the 

challenges of drilling and development in the deepwater environment of the GOM. 

181 AREA AND 181 SOUTH AREA—ACREAGE AVAILABLE FOR THE FIRST TIME 

IN 20 YEARS

Acreage for lease in Sale 224 (held on March 19, 2008) and Sale 208 (held on March 18, 

2009) included areas that have been off-limits to exploration until the most recent 5-Year 

Leasing Program (2007-2012) implemented by MMS. The Gulf of Mexico Energy Security 

Act of 2006 mandated that these areas be offered for lease and that the States of Alabama, 

Louisiana, Mississippi, and Texas share a portion of all qualified revenues from leases in 

these new areas. 

Eastern Sale 224 offered approximately 0.5 million acres from what is known as the 181 

Area, and Central Sale 208 offered approximately 4.2 million acres from what is known as 

the 181 South Area (Figure 2). These two sales presented oil companies the first 

opportunity to lease blocks in these areas since 1988. 
DEEPWATER GULF OF MEXICO 2009: INTERIM REPORT OF 2008 HIGHLIGHTS

6 

Figure 2. Map of the portion of the 181 Area offered in Sale 224 and the portion of the 181 South 

Area offered in Sale 208. Also shown are two recent seismic surveys in these areas. 

Two recent seismic datasets are available over the 181 and 181 South Areas (Figure 2). 

TGS-NOPEC Geophysical Company ASA (TGS) and Global Geo Services ASA (GGS) 

entered into a 50-50 joint venture on a 28,000-kilometer (km) [17,398-mile (mi)] multi-client 

2D survey, known as Phase 51. The project was supported by pre-funding from several oil 

companies. TGS and GGS combined acquisition resources to complete the recording of the 

survey in February 2008. Both pre-stack time and depth migration processing were 

performed by GGS-Spectrum. TGS is responsible for marketing and sales of the resulting 

products. 

TGS also recently commenced a multi-client 3D survey over the northern 181 South 

Area. The survey, known as Orion 3D, will cover approximately 175 Outer Continental 

Shelf (OCS) blocks (4,100 km2 or 1,583 mi2) in the Lloyd Ridge area. The exploration 

potential for this area includes seismic attribute plays as well as deeper structural 

opportunities. TGS acquired the Orion 3D survey utilizing the Fugro Geo Barents seismic 

vessel. The data were recorded with 9,000-m (29,528-ft) streamer offsets and were 

processed with both pre-stack time and pre-stack depth imaging. In addition to the full 

offset migrations, partial offset stacks were generated for evaluating amplitude variation 

with offset (AVO). The Orion 3D survey was supported by industry funding. 

The Phase 51 2D and Orion 3D programs are located in close proximity to the 

Independence Hub production facility operated by several independent oil companies. This 

large facility produces gas from a number of discoveries that have been made in the area 

including Spiderman, Cheyenne, Jubilee, and Vortex. 
WHAT ’S NE W

7 

NEW 5-YEAR OCS OIL AND GAS LEASING PROGRAM INITIATED

Lease sales are scheduled as part of the 5-Year Program, officially titled “Outer 

Continental Shelf Oil and Gas Leasing Program.” The current program covers the time 

period from July 2007 through June 2012. Developing a 5-Year Program is a multi-step 

process incorporating public comment and consultation with states and other Federal 

agencies. This process usually takes 2 years to complete. 

In August 2008, the Interior Department issued a Call for Information and Nominations, 

the first step in a multi-step process, to begin a new 5-Year Program covering the time 

period from July 2010 through June 2015. This step included a 45-day comment period, 

which was extended by 3 days and closed September 18, 2008. 

The second step in the process, the issuance of a draft proposed program, took place 

January 15, 2009. The draft proposed program seeks public comment on all aspects of the 

new program for 2010-2015 including energy development and economic and environmental 

issues in the OCS areas. 

For the 2010-2015 draft proposed program, MMS proposes 31 OCS lease sales in all or 

some portion of 12 of the 26 planning areas—4 areas off Alaska, 3 areas off the Atlantic 

Coast, 3 areas in the GOM, and 2 areas off the Pacific Coast. The draft proposed program 

is just a starting place designed to encourage discussions about the OCS areas of greatest 

interest and potential. Any new areas that are included in the final program will not be 

available for leasing until the 5-Year Program has been completed and approved. No area 

can be leased without being included in the then current approved 5-Year Program. 

In February 2009, the Interior Secretary extended the comment period for the draft 

proposed program for an additional 180 days to September 21, 2009, in order to provide 

additional time for input from states, stakeholders, and affected communities. The 

Secretary also requested that MMS and the United States Geological Survey (USGS) 

produce a report on the offshore resources and potential impacts by the end of March 2009. 

Four regional meetings are scheduled, one each for Alaska, the Atlantic Coast, the Gulf 

Coast, and the Pacific Coast, following publication of the report. More information can be 

found on MMS’s Web site at http://www.mms.gov/offshore/salazarregionalmeetings.htm. 

ROYALTY AND RENTAL RATE INCREASES

Lease Sales 206 and 224, held in March 2008, included an increase in the royalty rate for 

deepwater leases to 18.75 percent from the 16.7 percent rate. 

The MMS has increased the rental rates for leases issued in Sale 208, held in March 

2009. The increase in the base rental rate raises rates from $6.25 to $7.00 per acre in water 

depths of less than 200 m (656 ft) and from $9.50 to $11.00 per acre in 200 m (656 ft) or 

deeper. For the first time, rental rates will be escalated for all leases with initial terms of 

more than 5 years. Rental rates will also be escalated for leases with an approved 

extension of the initial lease period. Amounts for each increase and details are listed in the 

Final Notice of Sale (Federal Register, 2009). 

CHANGE IN ADMINISTRATIVE BOUNDARIES (SALE BOUNDARIES) 

On January 3, 2006, MMS published a notice in the Federal Register (2006; 71 FR 1) 

announcing the setting of Federal OCS offshore administrative boundaries beyond State 

submerged lands for planning, coordination, and administrative purposes. More 

information on these administrative boundary changes can be found on MMS’s Web site at 
DEEPWATER GULF OF MEXICO 2009: INTERIM REPORT OF 2008 HIGHLIGHTS

8 

http://www.mms.gov/ld/AdminBoundaries.htm. The planning area boundary changes took 

effect with the 2007-2012 5-Year Program on July 1, 2007. 

Since then, minor modifications have been implemented to avoid splitting some blocks. 

These modifications resulted in boundaries that have a “stair-stepped” appearance. These 

new planning area boundaries will appear on all pertinent maps in this report. 
9 

BACKGROUND 

DEFINITIONS

For purposes of this report, deep water is defined as water depths greater than or equal 

to 1,000 ft (305 m), and ultra-deep water is defined as water depths greater than or equal to 

5,000 ft (1,524 m). Leasing and royalty-relief data used are expressed in meters to be 

consistent with regulatory requirements. All other data are expressed in feet, 

corresponding to operational considerations. A few other definitions are useful at this 

point: 

• Proved Reserves are those quantities of hydrocarbons that can be estimated 

with reasonable certainty to be commercially recoverable from known 

reservoirs. These reserves have been drilled and evaluated and are generally 

in a producing or soon-to-be producing field. 

• Unproved Reserves can be estimated with some certainty (drilled and 

evaluated) to be potentially recoverable, but there is as yet no commitment to 

develop the field. 

• Known Resources in this report refer to discovered resources (hydrocarbons 

whose location and quantity are known or estimated from specific geologic 

evidence) that have less geologic certainty and a lower probability of 

production than the Unproved Reserves category. 

• Industry-Announced Discoveries refer to oil and gas accumulations that were 

announced by a company or otherwise listed in industry publications. These 

discoveries may or may not have been evaluated by MMS, and the reliability 

of estimates can vary widely. 

• Field is defined as an area consisting of a single reservoir or multiple 

reservoirs 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 intervening impervious 

strata or laterally by local geologic barriers or both. 

More detailed definitions may be found in the annual Estimated Oil and Gas Reserves, 

Gulf of Mexico Outer Continental Shelf, December 31, 2004 report (Crawford et al., 2008). 

This report refers to developments both as fields (as defined above) and by operatordesignated project names. It is important to note that the total number of fields, as defined 

by MMS criteria, and the total number of operator-designated projects may not be the 

same. A field name is assigned to a lease or a group of leases by MMS so that oil and 

natural gas resources, reserves, and production can be allocated on the basis of the unique 

geologic feature that contains the hydrocarbon accumulation(s). The field’s identifying 

block number corresponds to the first lease qualified by MMS or the block where the 

primary structure is located. Therefore, more than one operator-designated project may be 

included in a single MMS-designated field. 

Note that the term “oil” refers to both oil and condensate throughout this report and 

“gas” includes both associated and non-associated gas. 
DEEPWATER GULF OF MEXICO 2009: INTERIM REPORT OF 2008 HIGHLIGHTS

10 

EXPANDING FRONTIER

When the original version of this report (Cranswick and Regg, 1997) was published in 

February 1997, a new era for the GOM had just begun with intense interest in the oil and 

gas potential of the deepwater areas. At that time there were favorable economics, recent 

deepwater discoveries, and significant leasing spurred on by the Deep Water Royalty Relief 

Act (DWRRA; 43 U.S.C. §1337). Historically, deepwater production began in 1979 with 

Shell’s Cognac Field, but it took another 5 years before the next deepwater field 

(ExxonMobil’s Lena Field) came online. Both developments relied on extending the limits 

of platform technology used to develop the GOM shallow-water areas. 

Since then, deepwater exploration and production technology has tremendously 

advanced. In February 1997, there were 17 producing deepwater projects, up from only 6 at 

the end of 1992. Since then, industry has been rapidly advancing into deep water, and 

many of the anticipated fields have begun production. At the end of 2008, there were 141 

producing projects in the deepwater GOM, up from 130 at the end of 2007 (Richardson et 

al., 2008). 

Over the last 15 or so years, leasing, drilling, and production moved steadily into deeper 

waters. There are approximately 7,310 active leases in the U.S. GOM, 58 percent of which 

are in deep water. (Note that lease statuses may change daily, so the current number of 

active leases is an approximation.) Contrast this to approximately 5,600 active GOM leases 

in 1992, only 27 percent of which were in deep water. There was a maximum of 31 rigs 

drilling in deep water in 2008, compared with only 3 rigs in 1992. Likewise, deepwater oil 

production rose about 786 percent and deepwater gas production increased about 

1,067 percent from 1992 to 2007. Production from seven deepwater fields began in 2008, 

including Thunder Horse, the largest daily producer in the GOM. Appendix A provides 

locations and additional information for these fields and projects. 

ULTRA-DEEPWATER DRILLING AND DISCOVERIES (≥5,000 FT OR ≥1,524 M) 

In 1986, the first discovery in the GOM in water depths greater than 5,000 ft (1,524 m) 

occurred with Mensa. Since that time, there have been 64 additional discoveries in the 

ultra-deep provinces of the Gulf (Table 3). The production from 13 of these discoveries is 

associated with the Independence Hub natural gas processing facility. Another 15 of the 

discoveries are associated with the Lower Tertiary trend. 

In 2007, MMS reported a record number of 15 rigs drilling for oil and gas in water 

depths of 5,000 ft (1,524 m) or more in the GOM. Although this record has not yet been 

surpassed, MMS expects increased drilling activities in ultra-deep water, with 15 newbuild 

mobile offshore drilling units (MODU’s) contracted for delivery to the GOM in 2009 through 

2011. The MMS expects 2 new drillships and 6 new semisubmersible drilling rigs in 2009, 

5 new drillships and 1 semisubmersible drilling rig in 2010, and 1 new semisubmersible 

drilling rig in 2011. There are also 4 semisubmersible rigs that are currently being 

upgraded to drill in ultra-deep water that are contracted for delivery to the GOM in 2009 

and 2010. The newbuild Stena DrillMAX I drillship and the Seadrill West Sirius

semisubmersible drilling rig were delivered to the GOM in 2008. All of the newbuild 

MODU’s are being built with dynamic positioning systems and will not have to be moored 

to the seafloor. These newbuild MODU’s will be capable of drilling in water depths from 

7,500 to 12,000 ft (2,286 to 3,658 m) and will be capable of drilling wells from 30,000 to 

40,000 ft (9,144 to 12,192 m) below the seafloor. There are several drilling contractors that 
BACKGROUND

11 

have MODU’s in construction for delivery in 2010 and 2011 that are not yet contracted with 

operators, and some of these MODU’s are expected to operate in the GOM under future 

contracts. 

Table 3. Discoveries in Water Depths Greater than 5,000 ft (1,524 m)

Project/Prospect Area/Block Water Depth (ft)1

 Discovery Year 

Constitution GC 680 5,001 2001 

GC767 GC 767 5,116 2004 

Rigel MC 252 5,227 1999 

Ticonderoga GC 768 5,259 2004 

Big Foot WR 29 5,268 2005 

King MC 84 5,303 1993 

Mensa MC 731 5,313 1986 

Red Hawk GB 877 5,329 2001 

Goldfinger MC 771 5,413 2004 

Horn Mountain MC 127 5,422 1999 

Devil’s Tower MC 773 5,532 1999 

Thunder Horse North MC 776 5,662 2000 

Thunder Bird MC 819 5,672 2006 

Thunder Hawk MC 734 5,714 2004 

Kaskida3 KC 292 5,721 2006 

Kepler MC 383 5,741 1987 

La Femme MC 427 5,782 2004 

Seventeen Hands MC 299 5,881 2001 

Dalmatian DC 48 5,876 2008 

Thunder Horse MC 778 6,082 1999 

Freedom MC 948 6,095 2008 

Thunder Ridge MC 737 6,108 2006 

Ariel MC 429 6,134 1995 

Neptune (AT) AT 575 6,203 1995 

Tortuga MC 561 6,302 2008 

Isabela MC 562 6,535 2007 

King's Peak DC 133 6,541 1993 

Anstey MC 607 6,601 1997 

Atlantis GC 743 6,612 1998 

Bass Lite AT 426 6,623 2001 

Fourier MC 522 6,895 1989 

Blind Faith MC 696 6,952 2001 

Jack3 WR 759 6,962 2004 
DEEPWATER GULF OF MEXICO 2009: INTERIM REPORT OF 2008 HIGHLIGHTS

12 

Table 3. Discoveries in Water Depths Greater than 5,000 ft (1,524 m) (continued) 

Project/Prospect Area/Block Water Depth (ft)1

 Discovery Year 

St. Malo3 WR 678 6,991 2003 

Aconcagua MC 305 7,051 1999 

Mission Deep GC 955 7,068 2006 

Julia3 WR 627 7,087 2007 

Camden Hills MC 348 7,206 1999 

Shiloh DC 269 7,509 2003 

Coulomb MC 657 7,558 1987 

BAHA3 AC 600 7,620 1996 

Hal3 WR 848 7,657 2008 

Gotcha3 AC 856 7,714 2006 

Callisto MC 876 7,790 2001 

San Jacinto2 DC 618 7,805 2004 

Q2 MC 961 7,926 2005 

Merganser2 AT 37 7,939 2001 

Spiderman2 DC 621 8,082 2003 

Great White3 AC 857 8,119 2002 

Cascade3 WR 206 8,152 2002 

Vortex2 AT 261 8,344 2002 

Mondo NW Extension2 LL 1 8,351 2005 

Mondo Northwest2 LL 2 8,362 2004 

Jubilee Extension2 LL 309 8,774 2005 

Jubilee2 AT 349 8,778 2003 

Atlas NW2 LL 5 8,807 2004 

Chinook3 WR 469 8,831 2003 

Atlas2 LL 50 8,944 2003 

Cheyenne2 LL 399 8,983 2004 

Tiger3 AC 818 9,004 2004 

Silvertip3 AC 815 9,226 2004 

Stones3 WR 508 9,571 2005 

Tobago3 AC 859 9,627 2004 

Trident3 AC 903 9,721 2001 

Diamond LL 370 9,975 2008 1

 Water depths are approximate and may be the location of a completed well, or an average of 

completed wells, or the location of the discovery well in the block. 2 Projects associated with the Independence Hub natural gas processing facility. 

3 Projects associated with the Lower Tertiary trend. 
BACKGROUND

13 

CHALLENGES AND REWARDS

Significant challenges exist in deep water in addition to environmental considerations. 

Deepwater operations are very expensive and often require significant amounts of time 

between initial exploration and first production. Despite these challenges, operators often 

reap great rewards. Figure 3 shows the history of discoveries in the deepwater GOM. 

There was a shift toward deeper water over time, and the number of deepwater discoveries 

continues at a steady pace. 

In addition to the significant number of deepwater discoveries, the flow rates of 

deepwater wells and the field sizes of deepwater discoveries are often quite large. These 

factors are critical to the economic success of deepwater development. Figure 4 illustrates 

the estimated sizes and locations of 127 proved deepwater fields. In addition to their large 

sizes, the fields have a wide geographic distribution and range in geologic age from 

Pleistocene through Paleocene. 

Figure 5 illustrates existing and potential hubs for deepwater production. For purposes 

of this report, deepwater hubs are defined as surface structures that host production from 

one or more subsea projects. These hubs represent the first location where subsea 

production comes to the surface, and the hubs are the connection point to the existing 

pipeline infrastructure. Note that potential hubs are moving into deeper waters, expanding 

the infrastructure and facilitating additional development in the ultra-deepwater frontier. 
14 

Figure 3. Deepwater discoveries by year. 
15 

Figure 4. Estimated volume of proved deepwater fields. 
16 

Figure 5. Current, potential, and future hub facilities. 
17 

LEASING AND ENVIRONMENT 

5-YEAR OCS OIL AND GAS LEASING PROGRAM

Section 18 of the OCS Lands Act (OCSLA) requires the Secretary of the Interior to 

prepare and maintain a 5-Year Program. The program reflects a proper balance among the 

potential for the discovery of oil and natural gas, the potential for environmental damage, 

and the potential for adverse effects on the coastal zone. The 5-Year Program also must 

provide for the receipt of fair market value by the Federal Government for land leased and 

rights conveyed. 

When approved, the leasing program consists of scheduled lease sales for a 5-year 

period, along with policies pertaining to the size and location of sales and the receipt of fair 

market value. The purpose of a schedule is to increase the predictability of sales in order to 

facilitate planning by industry, affected states, and the general public. The schedule 

indicates the timing and location of sales and shows the presale steps in the process that 

lead to a competitive sealed bid auction for a specific OCS area. To facilitate the scheduling 

of and preparation for sales in the 5-Year Program, the OCS is divided into administrative 

geographical units called planning areas. 

In preparing a new 5-Year Program, the Secretary solicits comments from coastal State 

Governors and localities, tribal governments, the public, the oil and natural gas industry, 

environmental groups, affected Federal agencies, and Congress. The MMS requests 

comments at the start of the process of developing a new program and following the 

issuance of each of the first two versions: (1) the draft proposed program with a 60-day 

comment period; and (2) the proposed program with a 90-day comment period. The third 

and last version, the proposed final program, is prepared with a 60-day notification period 

following submission to the President and Congress. After 60 days, if Congress does not 

object, the Secretary may approve the program. 

In addition to the steps required by Section 18 of the OCSLA, the Secretary must comply 

with the requirements of the National Environmental Policy Act (NEPA). Additional 

scoping may occur and an environmental impact statement (EIS) on the 5-Year Program is 

prepared. During the comment period on the draft EIS, public hearings are held in various 

coastal locations around the Nation. After the receipt of comments, a final EIS is prepared. 

A record of decision that formalizes the alternatives that were selected from the final EIS is 

prepared. 

Each lease sale proposed in the program’s schedule must also undergo a NEPA 

evaluation and presale coordination steps required by Section 19 of the OCSLA. An 

environmental assessment that is specific to the individual lease sale is usually prepared. 

These documents examine new information and changes that have occurred since the final 

EIS was prepared. Consultation is conducted with the states during the process, and 

consistency with each affected state’s Coastal Zone Management (CZM) program is 

determined before the lease offering transpires. 

The listing below shows the major sequential steps in the process after adoption of a 

5-Year Program. 

• Call for Information and Nominations and Notice of Intent to Prepare an EIS 

• Area identification 

• Draft EIS 
DEEPWATER GULF OF MEXICO 2009: INTERIM REPORT OF 2008 HIGHLIGHTS

18 

• Public hearings 

• Final EIS and CZM consistency determination 

• Record of decision 

• Sale-specific NEPA evaluation 

• Proposed Notice of Sale 

• Governor’s comments 

• Final Notice of Sale 

• Sale 

• Decision to accept or reject bids 

• Issuance of leases 

The entire 5-Year Program process takes approximately 2 years to complete. The lease 

sale schedule is reviewed annually after its approval. A more in-depth discussion of the 

leasing process is provided in MMS’s document, Leasing Oil and Gas Resources: Outer 

Continental Shelf. The document is available through MMS’s Web site at http://

www.mms.gov/ld/PDFs/GreenBook-LeasingDocument.pdf. 

The MMS is currently operating under its proposed OCS Oil and Gas Leasing Program 

for 2007-2012. This 5-Year Program proposes 12 oil and gas lease sales in the GOM—

5 sales in the Western Planning Area, 6 sales in the Central Planning Area, and 1 sale in 

the Eastern Planning Area. Detailed schedule information is available from MMS’s Web 

site at http://www.mms.gov/offshore/2007-2012LeaseSaleSchedule.htm. More information 

on the 5-Year Program may be gleaned from MMS’s Web site at http://www.mms.gov/5-

year/WhatIs5YearProgram.htm. 

WATER-DEPTH INTERVALS

The Gulf of Mexico OCS is divided into three sectors—the Western, Central, and Eastern 

Planning Areas (Figure 6). Additionally, many of the data presented in this report are 

subdivided according to water depth. These divisions (1,000, 1,500, 5,000, and 7,500 ft) are 

also illustrated in Figure 6, along with the deepwater royalty-relief zones (400, 800, 1,600, 

and 2,000 m) mandated by the Energy Policy Act of 2005. Not all leases within a colored 

area are eligible for royalty relief because of the differing vintage of leases included within 

the area. 

LEASING ACTIVITY

Figure 7 depicts all active leases in the GOM at the end of calendar year 2008. The pie 

chart inset in this figure highlights the relative percentage of active leases in each 

operational water-depth category used in this report. Note that approximately 57 percent 

of the leased blocks are located in water depths greater than 1,000 ft (305 m), up from 

54 percent in 2007. The limited number of active leases in the Eastern Planning Area is 

related to leasing restrictions. The approximate number of active leases for certain waterdepth ranges is shown in Table 4. 
19 

Figure 6. Deepwater royalty-relief zones with planning areas and selected bathymetry. 
20 

Figure 7. Active leases by water depth. 
LEASING AND E NVIRONMENT

21 

Table 4. Number of Active Leases by Water-Depth Interval 

Number of Water Depth 

Active Leases ft m 

3,096 <1,000 <305 

152 1,000-1,499 305-457 

2,066 1,500-4,999 458-1,524 

1,398 5,000-7,499 1,525-2,286 

598 >7,500 >2,286 

Central Lease Sale 206 

Central Sale 206 was held on March 19, 2008. This sale attracted $3,677,688,245 in 

high bids—the most since Federal offshore leasing began in 1954. The MMS received 1,057 

bids from 85 companies on 615 blocks. The sum of all bids for this sale was $5,740,047,263. 

Sale 206 ultimately resulted in the award of 603 leases. The MMS rejected high bids 

totaling $6,477,661 on 11 blocks as insufficient for fair market value, and one block was 

forfeited when the company withdrew their bid. The accepted high bids for the sale totaled 

$3,671,052,702.40. 

About 67 percent of the blocks receiving bids were located in deep water [400 m (1,312 ft) 

or deeper] with approximately 34 percent of the blocks bid upon in ultra-deep water—more 

than 1,600 m (5,249 ft). The MMS considers water depths greater than 400 m (1,312 ft) 

and 1,600 m (5,249 ft) as deep water and ultra-deep water, respectively, for sale purposes.1 

The deepest block to receive a bid was Lloyd Ridge Block 286 in 3,076 m (10,092 ft) of 

water. The highest bid accepted on a block was $105,600,789 made by Anadarko E&P 

Company, Murphy Exploration & Production Company USA, and Samson Offshore 

Company for Green Canyon Block 432. Funds from the total high bids will be distributed to 

the general fund of the U.S. Treasury, shared with the affected States, and set aside for 

special uses that benefit all 50 States. 

Eastern Lease Sale 224 

Held on the same day as Sale 206, Eastern Sale 224 attracted $64,713,213 in high bids. 

This sale offered 118 whole or partial unleased blocks covering 546,971 acres from what is 

known as the 181 Area (Figure 2). The MMS received 58 bids from six companies on 36 

blocks. The sum of all bids for this sale was $72,137,645. Sale 224 ultimately resulted in 

the award of leases for all blocks bid upon. All of the blocks offered in this sale are located 

in water depths greater than 800 m (2,625 ft). The States of Alabama, Louisiana, 

Mississippi, and Texas will share in 37.5 percent of the high bids on these blocks, as well as 

all future revenues generated from this acreage. 

 

1 The definitions of deep water and ultra-deep water used for lease sales statistics are based on the 

DWRRA established royalty suspension intervals. 
DEEPWATER GULF OF MEXICO 2009: INTERIM REPORT OF 2008 HIGHLIGHTS

22 

Western Lease Sale 207 

Held on August 20, 2008, Western Sale 207 attracted $487,297,676 in high bids. The 

MMS received 423 bids from 53 companies on 319 blocks comprising over 1.8 million acres 

offshore Texas. The sum of all bids received totaled $607,134,968. Sale 207 ultimately 

resulted in the award of 313 leases. The MMS rejected high bids totaling $3,338,272 on six 

blocks as insufficient for fair market value. The accepted high bids for the sale totaled 

$483,959,404. 

Approximately 78 percent of the blocks receiving bids were in deep water [400 m 

(1,312 ft) or deeper], and approximately 21 percent of the blocks receiving bids were in 

ultra-deep water—more than 1,600 m (5,249 ft). The deepest block bid on was Alaminos 

Canyon Block 783 in 2,977 m (9,767 ft) of water. The highest bid accepted on a block was 

$61,110,000 submitted by Statoil Gulf of Mexico LLC for Alaminos Canyon Block 380. 

Funds from the total high bids will be distributed to the general fund of the U.S. Treasury, 

shared with the affected States, and set aside for special uses that benefit all 50 States. 

Central Lease Sale 208 

Held on March 18, 2009, Central Sale 208 attracted $703,048,523 in high bids. The 

MMS received 476 bids from 70 companies on 348 blocks comprising over 1.9 million acres 

offshore Alabama, Louisiana, and Mississippi. The sum of all bids received totaled 

$933,649,315. 

Approximately 70 percent of the blocks receiving bids were in deep water [400 m 

(1,312 ft) or deeper], and approximately 42 percent of the blocks receiving bids were in 

ultra-deep water—more than 1,600 m (5,249 ft). The highest bid received on a block was 

$65,611,235 submitted by Shell Gulf of Mexico Inc. for Mississippi Canyon Block 721. 

Areas for lease in Sale 208 included approximately 4.2 million acres from what is known 

as the 181 South Area in the southeastern portion of the sale area (Figure 2). The 181 

South Area has been off-limits to exploration for over 20 years. A total of 13 blocks received 

bids in this area, and the high bids for these blocks totaled $6,476,545. The States of 

Alabama, Louisiana, Mississippi, and Texas will share in 37.5 percent of the high bids on 

these blocks, as well as all future revenues generated from this acreage. 

LEASING TRENDS

Prior to the mid-1990’s, leasing activities in the GOM were concentrated in the shallowwater blocks located on the continental shelf [water depths of approximately 200 m (656 ft)] 

or less. With the passage of the DWRRA in 1995, royalty-relief incentives were established 

for new leases on the basis of specific water-depth intervals. The water-depth categories 

depicted in Figure 8 reflect the divisions used in the DWRRA. This figure shows the 

magnitude of the DWRRA’s impact on leasing activities. Significant deepwater leasing 

activities began in 1995 and showed remarkable increases from 1996 through 1998, 

especially in water depths greater than 800 m (2,625 ft), where the greatest royalty relief 

was available. During this time, leasing activities on shallow-water blocks diminished. 

After the large lease sales of 1997 and 1998, the number of leases issued in water depths 

greater than 800 m (2,625 ft) dropped by nearly half and remained relatively steady until 

increasing in 2007 and 2008. This increase is due in part to the expiration of the primary 

terms of leases issued in 1997 and 1998, which led to the record setting lease sales in 2007 

and 2008. 
LEASING AND E NVIRONMENT

23 

Figure 9 was derived from the data in Figure 8, but it displays the deepwater depth 

categories used elsewhere in this report. (Shallow-water data are excluded from Figure 9.) 

These data show the rapid increase in leasing activity that began in 1995 and continued 

through 1998. Although leasing activity plummeted in 1999, higher levels of leasing 

activity returned after 2000. Several factors initiated this resurgence, including high oil 

and gas prices and several major discoveries, such as Tahiti, Great White, and Thunder 

Horse. 

FUTURE LEASE ACTIVITY

The number of leases that will be relinquished, terminated, or expired will influence 

activity in future lease sales. Given the fact that most companies can drill only a small 

percentage of their active leases, it is likely that many high-quality leases will expire 

without being tested. Ultimately, an untested and undeveloped lease will expire and 

possibly be leased again. 

Figure 10 shows leases that may expire from 2009 to 2020 in 2-year intervals. The data 

used in creating these figures assume that each lease expires at the end of its primary lease 

term (without a lease-term extension). Note that lease terms vary according to water 

depth. Primary lease terms for water-depth intervals are as follows: 5 years for blocks in 

less than 400 m (1,312 ft); 8 years for blocks in 400-799 m (1,312-2,621 ft) (pursuant to 

30 CFR 256.37, commencement of an exploratory well is required within the first 5 years of 

the initial 8-year term to avoid lease cancellation); and 10 years for blocks in 800 m 

(2,625 ft) or greater. 

GRID PROGRAMMATIC ENVIRONMENTAL ASSESSMENTS

A biologically based grid system was developed by MMS as part of its comprehensive 

strategy to address deepwater issues. The grid system initially divided the Gulf into 

17 areas or “grids” of biological similarity. Since then, 4 grids were added to the system to 

address the modified Sale 181 area and the new eastern boundary of the Central Planning 

Area in effect since 2007 for Sale 205, making a total of 21 grids for the Gulf (Figure 11). 

Under this system and under most circumstances, MMS will prepare a Programmatic 

Environmental Assessment (PEA) that characterizes and analyzes a proposed development 

project within context of the entire grid. Grid PEA’s are comprehensive in terms of the 

impact-producing factors and the environmental and socioeconomic resources described and 

analyzed in it. Grid PEA’s also address potential cumulative effects of projects proposed 

within the grid. Other information on publicly announced projects within the grid is 

discussed, as well as any potential effects expected from future developmental activities. 

Projects selected for the PEA’s are representative of the types of development expected 

within the grid. For example, a good candidate for a Grid PEA would be a proposed 

development of a new surface structure that might serve as a “hub” for future development 

within the grid. 

Once a Grid PEA has been completed, it will serve as a reference document for “tiering” 

and “incorporation by reference” encouraged by the implementing regulations of NEPA. 

Future environmental evaluations may reference appropriate sections from the PEA to 

reduce duplication and to focus on issues and effects related to specific proposals. 

Table 5 shows the status of the Grid PEA’s. 
DEEPWATER GULF OF MEXICO 2009: INTERIM REPORT OF 2008 HIGHLIGHTS

24 

0

200

400

600

800

1,000

1,200

Lease Sale Year

Number of Leases Issued

< 200 m 176 261 466 509 620 525 265 165 325 453 418 474 464 336 292 264 250

200 - 400 m 4 15 25 52 66 44 35 16 14 33 37 15 51 26 29 20 23

400 - 800 m 17 36 30 103 110 99 58 17 28 74 68 67 57 67 61 40 56

> 800 m 7 24 39 171 712 1,110 771 135 186 382 281 333 316 326 381 633 623

1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008

DWRRA post-DWRRA

Figure 8. Number of leases issued each year subdivided by DWRRA water-depth categories. 

0

100

200

300

400

500

600

Lease Sale Year

Number of Leases Bid On

1,000 - 1,499 ft 5 7 11 30 54 27 23 7 10 23 23 16 28 27 31 17 20

1,500 - 4,999 ft 25 62 58 217 423 543 289 87 125 270 206 236 220 210 278 302 354

5,000 - 7,499 ft 1 0 13 49 310 503 307 45 72 101 128 144 125 108 139 242 254

> 7,500 ft 0 0 0 7 61 148 222 16 11 76 6 10 16 58 6 152 80

1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008

DWRRA post-DWRRA

Figure 9. Number of leases bid on for each deepwater interval. 
LEASING AND E NVIRONMENT

25 

Figure 10. Anticipated lease expirations from 2009 to 2019. 
DEEPWATER GULF OF MEXICO 2009: INTERIM REPORT OF 2008 HIGHLIGHTS

26 

Figure 10. Anticipated lease expirations from 2009 to 2019 (continued). 
LEASING AND E NVIRONMENT

27 

Figure 11. Grid PEA status. 

Table 5. Grid PEA Status within the Central and Western Planning Areas 

Grid Project Company Plan Area & Blocks 

3 Gunnison Kerr-McGee N-7625 GB 667, 668 & 669 

4 Nansen Kerr-McGee N-7045 EB 602 & 646 

5 Perdido Shell N-8809 AC 812, 813, 814 & 857 

7 Magnolia Conoco N-7506 GB 783 & 784 

9 Phoenix Energy Resource Technology S-7156 GC 236 & 237 

10 Holstein British Petroleum N-7216 GC 644 & 645 

12 Medusa Murphy N-7269 MC 538 & 582 

13 Marco Polo Anadarko N-7753 GC 608 

15 Matterhorn TotalFinaElf N-7249 MC 243 

16 Thunder Horse British Petroleum N-7469 MC 775-778 & 819-822 
DEEPWATER GULF OF MEXICO 2009: INTERIM REPORT OF 2008 HIGHLIGHTS

28 

RECENT ENVIRONMENTAL STUDIES BY MMS 

Deepwater Currents 

Since 1999 industry has reported significant currents below the 3,000-ft (914-m) waterdepth level. This information led to a Safety Alert (USDOI, MMS, 2000) and subsequent 

studies of deep currents by MMS (Hamilton et al., 2000 and 2003). The Hamilton et al. 

investigations spawned additional deepwater current studies funded by MMS and were 

discussed in the Deepwater Gulf of Mexico 2008 Report (Richardson et al., 2008). In 2008, 

three new studies were made available to the public; these studies focus on currents near 

the Sigsbee Escarpment, in the Eastern GOM and in the northwestern GOM. In October 

2008, MMS awarded a significant new contract to study currents in the deepwater GOM. 

Concentrating on currents near the Sigsbee Escarpment (McKone et al., 2007), 

Louisiana State University deployed four full-water column moorings in the GOM in 

February 2000 and removed the last mooring in June 2004. These moorings were designed 

to measure current, along with temperature, salinity, and pressure at various depths 

throughout the water column. The first two moorings, Deployments 1 and 2, were located 

on top of the Sigsbee Escarpment in approximately 2,200 m (7,218 ft) of water. These two 

mooring were combined to form a single time series. The last two moorings, Deployments 

3 and 4, were positioned at the base of the Sigsbee Escarpment in approximately 3,000 m 

(9,843 ft) of water. Strongest surface currents occurred when the Loop Current or Loop 

Current eddies (both anticyclonic and cyclonic) flowed near or over the mooring. Of the 

24 events investigated in detail, four of the events showed surface to bottom coherence in 

flow, which corresponded with the intensification of a Loop Current frontal eddy cyclone in 

close proximity to the mooring. Relatively strong bottom currents to the northeast occurred 

when a large warm-core anticyclonic Loop Current eddy (ring) passed south of the mooring. 

In May 2008, MMS announced the availability of a new study report, Deepwater 

Currents in the Eastern Gulf of Mexico: Observations at 25.5°N and 87°W (Inoue et al., 

2008). This report presents the analysis of current data collected at 87°W., 25.5°N. in water 

depths of approximately 3,600 m (11,811 ft), within a narrow channel connecting the 

eastern and central basins of the GOM. The mooring is an entire water-column array over 

a nearly flat bottom. The data suggest that the GOM can be viewed as a two-layer system 

with the interface at 700-800 m (2,297-2,625 ft) driven by the Loop Current and coinciding 

with the sill of the Florida Straits. The lower layer tends to have uniform currents in the 

vertical and speeds of 10-30 centimeters per second (0.3-1 feet per second). Short events of 

near uniform currents from top to bottom were observed and coincided with a Loop Current 

extended to its maximum northward position shortly before shedding an eddy. 

Focusing on the northwestern GOM, in a new study report, Study of Deepwater Currents 

in the Northwestern Gulf of Mexico, Volume I: Executive Summary (Donohue et al., 2008a) 

and Volume II: Technical Report (Donohue et al., 2008b), 13 moored arrays, in water 

depths ranging from 500 to 3,200 m (1,640 to 10,499 ft) were used to document upper- and 

lower-layer current, temperature, and salinity fields in the area west of 93° W. longitude, 

north of the Exclusive Economic Zone, and south and east of the 200-m isobath. Moored 

data collection began in March 2004 and ended in June 2005. For the entire field 

measurement interval, satellite remote-sensing observations (altimetry, sea-surface 

temperature, and ocean color) were used to provide a context for the upper-layer field 

measurements and to characterize the associated circulation processes and patterns. The 

objectives of this study were (1) to collect current data to increase our deepwater database 
LEASING AND E NVIRONMENT

29 

and knowledge of the deep circulation in the northwestern GOM; (2) to gather information 

to estimate oceanographic parameters needed to make experimental designs of full-scale, 

physical oceanography studies in deep water; and (3) to provide information to use in oilspill analyses, including the emerging deep spill analysis and other ongoing studies, to help 

evaluate exploration plans and to contribute to the preparation of NEPA documents. 

The MMS awarded a $5.5 million contract to Science Applications International 

Corporation (SAIC) to conduct a 5-year study of the GOM Loop Current in the Eastern 

GOM (USDOI, MMS, 2008a). Nine moorings, or anchored lines, will be placed in Gulf 

waters for approximately 30 months. The instruments attached to the moorings will 

measure current strength, water temperature, and salinity levels. Scientists from the 

Atlantic Oceanographic and Meteorological Lab will join SAIC to study the thermal 

structure of the Loop Current and hope to use this data to more accurately forecast the 

intensification of hurricanes entering the GOM. In addition, scientists from Princeton 

University, the University of Rhode Island and the University of Colorado are part of the 

SAIC team to carry out the state-of-the-art modeling, deep ocean circulation field 

observations, and the remote-sensing observations for this study. 

Sperm Whale Seismic Study 

The MMS released the results of a 6-year, $9.3 million study on sperm whales, an 

endangered species living in the northern GOM. The report, Sperm Whale Seismic Study 

in the Gulf of Mexico: Synthesis Report (Jochens et al., 2008), presents results from the 

Sperm Whale Seismic Study (SWSS) and gives recommendations for future study. The 

SWSS focused on the effects of seismic activities on sperm whales living in an area that is 

highly industrialized with oil and gas exploration and production activities. One finding 

supported by SWSS data is that northern GOM sperm whales are a distinct stock; that is, 

they show genetic differences from other sperm whales world-wide. Also, based on tag 

location data, the Gulf sperm whales showed no discernible seasonal migration. The study 

also did not find any horizontal avoidance of seismic sounds, meaning the whales did not 

alter their visible behavior on the surface when exposed to seismic sounds. Fifteen Federal 

and State agencies, universities, and organizations collaborated to meet the study’s 

objectives: (1) establish baseline information about the whales’ biology and behavior; 

(2) characterize the whales’ habitat and how the whales use their habitat; and 

(3) determine possible changes in the whales’ behavior when they experience human-made 

noise. Data gathered during SWSS provide insights into daily and seasonal movements, 

abundance, group structure, diving and other behaviors, habitat characteristics, and 

response to human-made noise of sperm whales in the northern GOM. This information 

will help MMS evaluate whether whales prefer some locations, what effects human 

activities (such as seismic surveys) may have on the whales and possible mitigation 

measures. 

Chemosynthetic Communities 

The study report, Investigations of Chemosynthetic Communities on the Lower 

Continental Slope of the Gulf of Mexico: Interim Report (Brooks et al., 2008), represents the 

first report for a large multidisciplinary study to investigate chemosynthetic communities 

and deepwater, hard-bottom communities, including deepwater corals, below a depth of 

1,000 m (3,281 ft) in the northern GOM. This project is a collaboration between MMS and 

the National Oceanic and Atmospheric Administration’s (NOAA) Office of Ocean 
DEEPWATER GULF OF MEXICO 2009: INTERIM REPORT OF 2008 HIGHLIGHTS

30 

Exploration and Research sponsored by the National Oceanographic Partnership Program. 

The report compiles detailed information regarding operational procedures, stations 

occupied, sampling activity, and preliminary results. The information in this report is a 

compilation of two cruises. A 2-week reconnaissance cruise was conducted from the vessel 

R/V Gyre from March 11-25, 2006, including drift camera work and trawling and box core 

sampling. A subsequent cruise was conducted on the Wood’s Hole Oceanographic Institute 

research vessel R/V Atlantis and the submersible Alvin from May 7 through June 2, 2006. 

Results reported were obtained by analysis of the sampling information and data during 

these cruises and immediately afterward. New chemosynthetic communities and 

deepwater coral communities were discovered at numerous sites. In February 2007, several 

study sites were mapped in great detail using the C&C Technologies Autonomous 

Underwater Vehicle in preparation for intensive sampling during the 2007 field season. A 

final report is expected in late 2009. 

Deepwater Coral 

The new study report, Lophelia Reef Megafaunal Community Structure, Biotopes, 

Genetics, Microbial Ecology, and Geology (2004-2006) (Sulak et al., 2008), represents 

results from a multidisciplinary project conducted by the USGS supporting the needs of 

MMS and was complimentary and concurrent with a separate MMS study that resulted in 

MMS publication OCS Study 2007-044 by Continental Shelf Associates (CSA) (with the 

same title). Subject areas in the USGS report include demersal fish associated with 

Lophelia coral biotopes, deep-sea coral biodiversity and molecular assessment, expressed 

genes in Lophelia, microbial ecology of Lophelia, deepwater antipatharian sclerochronology, 

and hard structure geological analysis of Lophelia substrate. Field sampling cruises were 

performed at a total of up to five locations in the northern GOM utilizing Harbor Branch 

Foundation vessels and one of the Johnson Sea Link submersibles in 2004 and 2005. The 

R/V Tommy Munro was used for an additional sampling cruise in 2005. Both samples and 

scientists were exchanged between the collaborating projects by CSA/MMS and USGS. 

Results include the first quantitative analysis of fishes associated with Lophelia reefs in the 

GOM, patterns of Lophelia genetic differentiation across 290 km (180 mi) of the northern 

GOM, discovery of new expressed genes in Lophelia, significant differences of bacterial 

molecular analysis between Lophelia sites and unexpected variations in substrate 

mineralogy between Lophelia sites. Results of this study will be utilized to develop 

additional studies of hard-bottom habitats in the deep GOM and will also enhance the 

ability of MMS to protect sensitive deepwater biological features. 

On November 24, 2008, MMS announced a $3.7 million, 4-year study of deepwater corals 

in the GOM (USDOI, MMS, 2008b). The study contract focuses on deepwater coral 

communities that have formed both naturally and on oil and gas platforms and shipwrecks. 

The first round of the project, primarily dedicated to the exploration of shipwreck sites, took 

the researchers to a remarkable discovery of a copper-clad sailing schooner likely dating to 

the early 1800’s. Another wreck site visited, confirmed to be the Gulfoil, a tanker sunk by a 

German U-boat in 1942, was covered with dense thickets of the deepwater coral Lophelia. 

The study marks the first time coral community areas below 1,000 ft (305 m) will be 

investigated using remotely-operated vehicles. Study results will be used by MMS to create 

or modify existing regulatory policies and will help MMS protect these important habitats 

from the potential impacts of oil and gas exploration. The study includes 3 years of field 

work using research vessels and underwater vehicles provided by NOAA’s Office of Ocean 
LEASING AND E NVIRONMENT

31 

Exploration and Research. During the second round of field work, dedicated to exploration 

and sampling of both known deepwater coral habitats and new unknown hard-bottom sites, 

scientists are collecting numerous samples of vibrant corals for analysis. Deepwater corals 

in the GOM have only recently been studied, and there is little information about how coral 

communities are distributed and how rare they may be. This study is designed to address 

that shortfall. 

Deepwater Shipwreck 

The study report, Viosca Knoll Wreck: Discovery and Investigation of an Early 

Nineteenth-Century Wooden Sailing Vessel in 2,000 Feet of Water (Church and Warren, 

2008), details the visual study of a wooden-hulled shipwreck discovered near the Petronius 

oil platform in the GOM. The study was performed by analyzing hours of video acquired 

using a remotely-operated vehicle. The identity and nationality of the vessel remains 

unknown, but the researchers concluded from the visual analysis of the hull remains that 

the ship was most likely a two-masted brig, brigantine, or schooner dating from the first 

quarter of the nineteenth century. The hull of the vessel is sheathed in copper or a 

cupreous alloy, which accounts for the wreck’s state of preservation. In addition to the hull, 

substantial remains of the standing rigging survive, lying along the starboard side. Few 

artifacts could be identified from the video alone, but one significant find included the 

discovery of a rare ship’s stove. The bow of the wreck is partly intact, but the stern is 

disarticulated. The site was found to have been impacted within the last decade, most 

likely by a large anchor cable, which is suggested by a ragged tear through the port side of 

the hull and a drag scar that crosses the wreck. 

Subsea Processing in Deepwater Environments 

The MMS study report, Effects of Subsea Processing on Deepwater Environments in the 

Gulf of Mexico (Grieb et al., 2008), represents the compilation and synthesis of existing 

published and unpublished literature on the environmental effects of subsea operations on 

the deepwater environment. Subsea processing technologies that are currently being 

implemented in deep water include multiphase pumps (Type 1) and partial separation with 

pumping (Type 2). Technologies being developed for future application include 

combinations of separators, scrubbers, and pumps that allow complete separation of 

production stream at the seabed (Type 3). The most advanced systems (Type 4) are likely 

to include multistage separation and fluid treatment with the production of export quality 

oil and gas. The primary difference between surface and subsea technologies is the 

restricted ability to detect and respond to releases in the deepwater environment and the 

extreme temperatures and pressures on the seafloor. A key technological and 

environmental issue involved in the implementation of subsea separation is the handling 

and disposal of produced waters and sands. Options include transport to the surface, 

reinjection into depleted formations, or discharge to the ambient environment. The 

potential impacts and major environmental concerns associated with subsea operations are 

similar to those observed with existing technologies. These include the release of drilling 

fluids and untreated drill cuttings during exploration and production; the catastrophic 

release of large volumes of hydrocarbons or utility fluids due to failures in piping, seals, and 

connections; and the release of untreated produced water and sands. The difference 

between existing and subsea technologies is the restricted ability to detect and respond to 

these releases in the deepwater environment. The advent of subsea technologies also 
DEEPWATER GULF OF MEXICO 2009: INTERIM REPORT OF 2008 HIGHLIGHTS

32 

introduces new environmental issues. These include the existence of large temperature 

differences between operating equipment and ambient conditions, the use of new treatment 

chemicals, the creation of electromagnetic fields associated with the operation of pumps and 

other equipment on the seafloor, and noise. The potential toxic effects of new or 

significantly modified products for treating the production and processing flow streams on 

benthic and free-swimming organisms should be determined. The deeper water habitats 

also exhibit unique features that should be considered in regulating subsea processing. For 

example, the presence of methane hydrates in the seafloor sediments should be identified in 

advance of subsea development activities. New protocols for assessing the existence, 

distribution, and ecological significance of benthic communities in these habitats are 

required. 
33 

DRILLING AND DEVELOPMENT 

HURRICANE SAFETY-RELATED NOTICES TO LESSEES AND OPERATORS

The MMS continually evaluates its regulations to determine which ones need revisions 

or clarifications. The MMS published 25 new Notices to Lessees and Operators (NTL’s) in 

2008; over 25 percent of the NTL’s focus on drilling, development, and/or production 

concerns. The effects of Hurricanes Ivan, Katrina, and Rita during the 2004 and 2005 

hurricane seasons were detrimental to oil and gas operations in the GOM. These effects 

included structural damage to fixed production facilities, semisubmersibles, and jack-up 

rigs. The MMS is concerned about the loss of these facilities and rigs and the resultant 

pollution from future storms. In an effort to reduce these effects, real and potential, MMS 

has set forth guidance, through NTL’s, to improve performance and safety during 

hurricanes. 

NTL 2008-G09 (“Guidelines for Moored Drilling Rig Fitness Requirements for Hurricane 

Season”) (USDOI, MMS, 2008c) provides guidance on the information that operators should 

submit with either Form MMS-123, Application for Permit to Drill (APD), or Form MMS124, Application for Permit to Modify (APM), to demonstrate that a moored drilling rig is fit 

to operate at a specific location during hurricane season. The MMS used this information, 

along with a risk-based assessment program, to calculate an in-depth risk analysis, which 

compared the probability of failure with the consequence of failure. This allowed MMS to 

produce detailed assessments and make consistent decisions with respect to mooring 

requests. 

In 2008, MMS evaluated 63 requests for mooring location approval during hurricane 

season. Thirty-five of these mooring requests were approved as-is, 25 were approved with a 

condition that requires the operator to move off location during the peak of hurricane 

season or change some of the mooring equipment to mitigate the risk involved, 2 requests 

were denied, and 1 was a preliminary review. The success of this program is evident by the 

fact that 14 moored rigs were in the path of hurricane-force winds during the 2008 

hurricane season, but only 2 lost station-keeping ability. This represents only 14 percent of 

the moored rigs going adrift in 2008 versus the 63 percent that went adrift in 2005. The 2 

rigs that did lose station-keeping did not cause any damage to critical infrastructure such 

as pipelines, wellheads, or platforms, which highlights the other advantage of the detail 

assessment program. The MMS and the drilling community are constantly working to 

ensure that no rigs go adrift during a hurricane, but major advancements have been made 

to reduce both the probability and consequence of failure in the past 3 years. 

The MMS’s Office of Structural and Technical Support (OSTS) has also utilized NTL’s to 

instruct operators how to conduct assessments of their fixed and floating production 

facilities in response to the updated metocean criteria published in API Bulletin 2INTMET, “Interim Guidance on Hurricane Conditions in the Gulf of Mexico” (API, 2007a). 

NTL 2007-G27 (“Assessment of Existing OCS Platforms and Related Structures for 

Hurricane Conditions”) (USDOI, MMS, 2007) provides guidance on how to assess certain 

existing OCS platforms and related structures to ensure their structural integrity. The 

NTL requires that facilities meeting specific requirements [e.g., any platform that is subject 

to the Platform Verification Program or installed in water depths greater than 400 ft 

(122 m)] conduct an assessment by performing an Ultimate Strength Analysis in 

accordance with Section 3.3 of API Bulletin 2INT-MET. Section 9 of the same bulletin 

requires the operator to carry out a site-specific study of the hurricane metocean conditions. 
DEEPWATER GULF OF MEXICO 2009: INTERIM REPORT OF 2008 HIGHLIGHTS

34 

The operators of existing floating platforms were asked to conduct an assessment using a 

three-step process outlined in API Bulletin 2INT-EX, “Interim Guidance for Assessment of 

Existing Offshore Structures for Hurricane Conditions” (API, 2007b). The assessment 

included a design level check, survival check, and a robustness check. 

Operators of 92 platforms that were identified as Central Region, high-consequence 

facilities were required to submit the results of the platform assessments by June 1, 2008. 

Operators of the platforms that were deemed not to be in compliance with the updated 

metocean criteria were also required to submit a mitigation plan to bring the facility into 

compliance. Currently, the OSTS is reviewing the assessments submitted by each operator 

and will conduct a review of the mitigation plan to ensure that all the appropriate steps are 

being taken to bring the platforms into compliance. 

PLANS

The NTL’s play an important role in MMS’s ability to communicate with industry and 

therefore require a significant amount of time and effort be dedicated to their development, 

but substantially more energy is focused on reviewing and approving plans submitted by 

operators on a daily basis. Figure 12 shows the number of deepwater Exploration Plans 

(EP’s), deepwater Development Operations Coordination Documents (DOCD’s), and 

Deepwater Operations Plans (DWOP’s) received each year since 1995. The number of EP’s, 

DOCD’s, and DWOP’s includes only the initial plans, not revisions or supplements to plans. 

In addition, the number of DWOP’s received includes only initial Conceptual Plans or 

combined Conceptual Plans/DWOP’s as allowed by the revised 30 CFR 250 Subpart B 

regulations. The MMS requires DWOP’s for developments in water depths greater than 

1,000 ft (305 m) and Conservation Information Documents (CID) for developments in water 

depths greater than 1,312 ft (400 m). Some shallow-water activities are included in the 

data because all subsea developments, regardless of water depth, must file a DWOP. 

The MMS has found the number of plans received to be a useful indicator in projecting 

activity levels. Although the order of plan submission and drilling activities can vary with 

projects, operators generally proceed as follows: 

• File an EP 

• Drill exploratory wells 

• File a Conceptual Plan 

• File a DOCD and CID 

• File a DWOP 

• Install production facilities 

• Drill development wells 

• Begin first production 
DRILLING AND DEVELOPMENT

35 

0

10

20

30

40

50

60

70

80

90

100

Number of Plans Received

Year

Deepwater DOCD

Deepwater EP

DWOP

Deepwater DOCD 4 8 6 9 7 12 18 23 10 13 28 10 12 10

Deepwater EP 19 29 69 80 92 76 67 69 75 51 69 51 35 46

DWOP 5 19 30 16 18 28 36 28 28 25 34 32 27 28

1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008

Figure 12. Deepwater EP’s, DOCD’s, and DWOP’s received since 1995. 

There was a marked increase in EP’s, DOCD’s, and Conceptual Plans or combined 

Conceptual Plans/DWOP’s from 1996 to 1999. Submittals of EP’s reached a peak of 92 in 

1999 and then hovered near 70 per year until 2004. The number of DOCD submittals 

reached a high of 28 in 2005 and has leveled off near 10 submittals from 2006 to 2008. 

There was an increase in the number of initial Conceptual Plans or combined Conceptual 

Plans/DWOP’s submitted from 2004 to 2006 (from 25 to 32) and has averaged just fewer 

than 30 submittals in 2007 and 2008. From 2006 to 2008 all three types of plans leveled off 

in between the high and low values for the past 13 years. 

In addition to the 28 initial Conceptual Plans and combined Conceptual Plans/DWOP’s 

MMS received in 2008, nine supplemental plans were also received that were not included 

in the totals above. Also not included in the totals above are 29 initial/supplemental 

DWOP’s (formally Preliminary DWOP’s), 17 of which were supplemental. Supplemental 

plans are often submitted when an operator wants to tie additional wells into a previously 

approved subsea system or wants to make a modification to the initial plan, such as 

waterflood, gas lift, or subsea pumping, that was not initially approved. The high number 

of supplements indicates that operators are not only looking to increase production from 

new developments but also from existing developments. 
DEEPWATER GULF OF MEXICO 2009: INTERIM REPORT OF 2008 HIGHLIGHTS

36 

RIGS

Figure 13 depicts the maximum number of deepwater rigs operating in the GOM for 

any 1 month period during any 1 year. After a peak in 2001, the number of rigs declined 

through 2005, followed by a slight increase in 2006, and has remained steady until 2008. It 

should be noted that this figure includes platform rigs and MODU’s. 

Figure 14 shows the approximate number of deepwater MODU’s, by water-depth 

categories, that were contracted to the GOM and worldwide (outside of the GOM) in 2008. 

Approximately 53 percent of MODU’s worldwide (not including the GOM) were capable to 

drill in water depths of 1,500 to 4,999 ft (457 to 1,524 m). In the GOM, approximately 

22 percent were capable of drilling in this same water depth range. There is a 

comparatively larger percentage of rigs within the GOM capable of drilling in water depths 

greater than 7,500 ft (2,286 m) compared with worldwide, 44 percent to 19 percent. 

Overall, approximately 21 percent of the worldwide, deepwater fleet are contracted to the 

GOM. 

The reader is cautioned not to draw conclusions from the rig count differences between 

Figures 13 and 14. Figure 13 includes platform rigs in addition to MODU’s and only 

considers rigs which were in operation; Figure 14 addresses only MODU’s. Also, the total 

number of rigs in Figure 14 has increased significantly since the 2008 Deepwater Report 

(Richardson et al., 2008) because of the availability of rig data from additional operating 

companies. Further, not all MODU’s in Figure 14 are operating at any given time, and 

upgrades to MODU’s that increase their water-depth capability will alter the maximum 

water-depth rig counts show; consequently, year-to-year comparisons are even more 

difficult to make. 

14

18

26

28 28

33

40

34

29

26 25

30

29

31

0

5

10

15

20

25

30

35

40

Maximum Number of Deepwater Rigs Operating

1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008

Year

Figure 13. Maximum number of platform rigs and MODU’s operating in the 

deepwater Gulf of Mexico in any one year. 
DRILLING AND DEVELOPMENT

37 

1

11

8

70

11

27

16

25

0

10

20

30

40

50

60

70

Number of MODU's

1,000 - 1,499 1,500 - 4,999 5,000 - 7,499 >= 7,500

Maximum Water Depth Capability (ft)

GOM

Worldwide (non-GOM)

Brazil, 33

North Sea, 

38

Africa, 29

Other, 33 GOM, 36

Figure 14. Approximate number of deepwater MODU’s contracted to the Gulf of Mexico and 

worldwide subdivided according to their maximum water-depth capabilities. Inset 

shows the number of deepwater MODU’s in various locations. 

DRILLING ACTIVITY

Figure 15 shows the number of deepwater wells drilled from 1992 through 2008 by 

water depth category. In 2008, 108 wells were spudded in water depths greater than 

1,000 ft (305 m); nearly 80 percent of the wells were for exploration. Ten of the total wells 

drilled were in water depths greater than 7,500 ft (2,286 m). The number of wells drilled 

generally increased from 1992 through 2001. Conversely, there has been a general decline 

for the last 7 years. Active hurricane seasons influenced the lower number of wells spudded 

in 2005 and 2008. 

Only original boreholes and sidetracks (a new bottomhole location) are included in the 

well counts used in this report. Wells defined as “by-passes” are specifically excluded. A 

“by-pass” is a section of well that does not seek a new objective; it is intended to drill 

around a section of the wellbore made unusable by stuck pipe or equipment left in the hole. 

Figures 16 and 17 further delineate the deepwater well counts into exploratory and 

development wells, respectively. This report uses the designation of exploratory and 

development wells provided by the operators. The data reflect the variations among 

operators in classifying wells as either development or exploratory. Figure 16 shows that 

after decreasing in 2002 and 2003, the number of exploratory wells drilled increased 

through 2006 and has shown a slight downward trend since then. Exploratory drilling in 

the 1,500- to 4,999-ft (457- to 1,524-m) water-depth range remained nearly the same from 
DEEPWATER GULF OF MEXICO 2009: INTERIM REPORT OF 2008 HIGHLIGHTS

38 

2002 through 2004, but increased in 2005 and remained relatively level through 2007. The 

number of wells drilled in 2008 has decreased slightly. From 2005 to 2006, the number of 

wells drilled in the 5,000- to 7,499-ft (1,524- to 2,286-m) water-depth range nearly doubled, 

and it has remained level through 2008. In 2008, Murphy drilled a discovery, Diamond, in 

the Lloyd Ridge Area in 9,975 ft (3,040 m) of water. This represents the third deepest 

water depth for an exploratory well in the GOM. 

Figure 17 shows that overall there has been a decrease in the number of development 

wells drilled from 2002 through 2005. Possible reasons for the decrease may be the method 

by which wells are categorized in this report (exploratory versus development), the 

retention of exploratory wells for production purposes, and the lag from exploration to first 

production. The complexity of developments in ultra-deep water may also be a factor, 

requiring operators to spend more time in planning and design. The total number of 

development wells increased in 2006 and 2007. The remarkable increase in the total 

number of development wells drilled in 2007 in the greater than 7,500-ft (2,286-m) waterdepth interval is mostly associated with the Perdido Regional Host facility. The number of 

wells drilled in 2008 has dropped back to 2005 levels. In 2008, Shell Oil Company set a 

world water depth record in drilling and completing a subsea well 9,356 ft (2,852 m) below 

the GOM’s water surface in the Silvertip project at the Perdido Regional Host facility in 

Alaminos Canyon. 

22

12

1

25

14

1

20

44

1

27

57

3

26

77

6

1

32

131

12

33

126

7

1

16

118

35

29

144

25

8

25

127

53

6

20

126

35

10

20

92

22

13

15

68

49

17

6

88

14

12

9

83

33

9

4

83

34

24

4

70

24

10

0

50

100

150

200

250

Number of Wells Spudded

1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008

Year

> 7,500 ft

5,000 - 7,499 ft

1,500 - 4,999 ft

1,000 - 1,499 ft

35 40

65

87

110

175

167 169

206 211

191

147 149

120

134

145

108

Figure 15. All deepwater wells drilled subdivided by water depth. 
DRILLING AND DEVELOPMENT

39 

2

4

1

3

13

8

37

1

11

37

2

8

50

6

1

17

79

9

20

90

6

10

61

29

8

67

17

8

5

74

30

5

10

44

19

10

7

43

13

11

10

44

20

16

4

64

14

11

5

60

26

9

2

64

27

2

4

49

24

8

0

20

40

60

80

100

120

Number of Wells Spudded 

1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008

Year

> 7,500 ft

5,000 - 7,499 ft

1,500 - 4,999 ft

1,000 - 1,499 ft

7

16

46

50

65

105

116

100 100

114

83

74

90

93

100

95

85

Figure 16. Deepwater exploratory wells drilled subdivided by water depth. 

20 22

1

1

12

7

16

20

1

18

27

15

52

3

13

36

1

6

57

6

21

77

8

20

53

23

1

10

82

16

13

49

9

2

5

24

29

1

2

24

1

4

23

7

2

19

7

22

21

2

0

20

40

60

80

100

120

Number of Wells Spudded

1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 2004 2005 2006 2007 2008

Year

> 7,500 ft

5,000 - 7,499 ft

1,500 - 4,999 ft

1,000 - 1,499 ft

28

24

37

45

70

51

69

106

97

108

73

59

27

34

50

23

8

1

19

Figure 17. Deepwater development wells drilled subdivided by water depth. 
DEEPWATER GULF OF MEXICO 2009: INTERIM REPORT OF 2008 HIGHLIGHTS

40 

DEVELOPMENT SYSTEMS

Development strategies vary for deep water, depending on reserve size and distribution, 

proximity to existing infrastructure, operating considerations (such as well interventions), 

prior company expertise with similar structures, economic considerations, and an operator’s 

interest in establishing a production hub for the area. Appendix A lists the systems that 

have begun production in the deepwater GOM, and Figure 18 shows the location of 

existing deepwater structures by type. Fixed platforms (e.g., Bullwinkle) have economic 

water-depth limits of about 2,000 ft (610 m). Compliant towers (e.g., Petronius) are usually 

deployed in water depths of approximately 1,000 to 2,000 ft (305 to 610 m). Tension-leg 

platforms (TLP’s) (e.g., Brutus, Magnolia, Marco Polo, and Shenzi) are frequently used in 

1,000- to 5,000-ft (305- to 1,524-m) water depths. Spars (e.g., Genesis, Red Hawk, Tahiti, 

and Perdido); semisubmersible production units (e.g., Na Kika and Blind Faith); FPU’s 

(e.g., Phoenix); and FPSO’s (e.g., Cascade and Chinook) may be used in water depths 

ranging up to and beyond 10,000 ft (3,048 m). 

Subsea systems are capable of producing hydrocarbons from reservoirs covering the 

entire range of water depths that industry is exploring. They range in complexity from a 

single subsea well producing to a nearby fixed platform, TLP, or floating production system 

(FPS), to multiple wells producing through a manifold and pipeline system to a distant 

production facility. Subsea systems continue to be a key component in the success in deep 

water to date. In fact, approximately 290 productive wells in deep water are subsea. 

INDUSTRY INVOLVEMENT AND NEW TECHNOLOGIES

The year 2008 has seen a revived effort for MMS and members of industry to work 

collectively on research and guidance documents that will provide valuable information for 

future developments. The MMS was involved in over 35 API committees in 2008. API 

Recommended Practice (RP) 2SK (“Design and Analysis of Station Keeping for Floating 

Structures”) (API, 2008), API RP 2SM (“Design, Manufacture, Installation, and 

Maintenance of synthetic Fiber Ropes for Offshore Mooring”) (API, 2007c), API RP 17O 

(“High Integrity Pressure Protection Systems”) (API, in preparation a), API RP 17G 

(“Completion/Workover Risers”) (API, in preparation b) and the new high-pressure/hightemperature committee [now named PER 15K (“Protocols for Equipment Rated Greater 

Than 15,000 PSI”)] are a few of the committees in which MMS has been actively involved. 

These documents will pave the way for the acceptance of new technologies and practices as 

industry moves to develop prospects in a more challenging environment. 

Another key initiative between MMS and industry, which is designed to increase the 

collective understanding of the challenges in the near future and investigate potential 

solutions, was undertaken by MMS’s Technology Assessment and Research program. In 

2008, MMS commissioned almost $2 million dollars worth of Operational Safety and 

Engineering Research projects. Most notably, MMS contracted 29 research projects, many 

co-funded with other U.S. and international governments or private organizations, focusing 

on the safety of oil and gas development, alternative energy initiatives, and oil-spill 

response. Eight of these projects specifically focused on high-pressure/high-temperature 

concerns, preventing hybrid well failures, and analyzing gas pipeline ruptures. An 

additional four projects will look into alternative energy design standards and inspection 

criteria, and three projects will concentrate on Arctic exploration and production. More 
41 

Figure 18. Location map of currently installed deepwater structures by type. 
DEEPWATER GULF OF MEXICO 2009: INTERIM REPORT OF 2008 HIGHLIGHTS

42 

information on deepwater research projects can be found at MMS’s Web site at http://

www.mms.gov/tarprojectcategories/deepwate.htm. 

The MMS has leveraged the information obtained from these industry meetings and 

research projects to work with operators on the evaluation and installation of new 

technologies for their deepwater developments. Shell Exploration and Production 

Company’s (Shell) Perdido Regional Host facility located in Alaminos Canyon Block 857, 

Petrobras America’s Inc (Petrobras) Cascade and Chinook developments located in Walker 

Ridge Block 206 and 469, respectively, and Energy Resource Technology’s Phoenix 

development located in Green Canyon Block 237 are just a few examples of how the 

increased communication between industry and MMS are leading to exciting new 

developments. 

Perdido 

The Perdido Spar is located 200 mi (322 km) south of Houston, Texas. The truss spar 

sets a new record as the deepest spar in the world at over 8,000 ft (2,438 m) of water. Once 

the development is complete, the spar will have 130,000 barrels of oil equivalent per day 

(BOE/d) capacity and will accept production from 34 wells, 22 direct vertical access (DVA) 

subsea wells, and 12 remote subsea wells from the Great White, Silvertip, and Tobago 

projects. Because of the remote location of the facility in Alaminos Canyon Block 857, 77 mi 

(124 km) of oil export and 107 mi (172 km) of gas export pipeline will be installed with the 

facility. The Spar was installed in August 2008, and the topsides were installed in March 

2009, with first oil around the turn of the decade. 

Shell has extended the limits of existing technology and practices to enable development 

in this ultra-deepwater environment. Perdido represents the first application of full, hostscale subsea separation and boosting, which enables improved recovery by removing about 

2,000 pounds per square inch (psi) of back pressure from the wells. 

The electric submersible pump (ESP)-caisson subsea separation and boosting system 

utilizes a caisson jetted approximately 300 ft (91 m) into the seafloor and a large ESP to lift 

fluids approximately 8,000 ft (2,438 m) to the host processing fluid. The subsea separator is 

configured to utilize cyclonic separation to separate oil and water from the gas phase. The 

separation will occur at the mudline, with liquid pumped via the ESP to the surface in an 

inner tubing string, while the gas free flows to the surface in the annulus. This scheme will 

enable improved recovery and longer well life while also mitigating the risk of hydrates in 

the system. 

Perdido is also the first application of wet tree DVA wells. The wet tree DVA concept 

enables a small host design while enabling a high well count that can be phased in over 

time utilizing a platform-based drilling rig. 

Cascade and Chinook 

Petrobras is poised to bring the first FPSO system to the U.S. GOM in early 2010. 

Because of the ability of the FPSO to perform in extreme water depths and equally extreme 

distances from shore, Petrobras’ project, located in the Walker Ridge Area, 165 mi (266 km) 

offshore, is an ideal location for the FPSO system. The vessel chosen for this distinction is 

a converted double-hulled tanker that has been renamed the BW Pioneer (Figure 19). 

Modifications to the vessel commenced in March 2008 in China, with continuing 

modifications currently being performed in Singapore. The BW Pioneer will have a peak 

production capacity of 80,000 bo/d, 16 MMcf/d, and 16,000 barrels of water per day (bw/d). 
DRILLING AND DEVELOPMENT

43 

Downstream operations will include one gas export pipeline and two dedicated shuttle 

tankers for oil. Each shuttle tanker will be Jones Act compliant vessels with a storage 

capacity of 300,000 barrels (bbl). Unique to the BW Pioneer is a detachable turret buoy 

through which all production flows. The ability to detach during a hurricane or named 

storm will allow the self-propelled BW Pioneer to motor into safe waters, allowing the storm 

to pass, then moving back into position, reattaching to the buoy and resuming production 

with as little downtime as possible. In addition to the FPSO, detachable turret buoy, and 

shuttle tankers for oil export, Petrobras’ project will utilize three other technologies 

considered new to the GOM, including free-standing hybrid risers, polyester mooring, and 

electric submersible booster pumps. 

In April 2008, MMS issued a press release (USDOI, MMS, 2008d) announcing the 

approval of a DOCD for the project. A DOCD outlines the operational plan for developing a 

project, including timelines for drilling wells and installing production facilities as well as 

geological and geophysical information. The document also identifies any specific 

environmental issues that must be addressed, including safety and pollution prevention. 

The next step in the development process is the MMS review of Petrobras’ DWOP. The 

plan, which is expected to be received in early 2009, must be approved before production 

can commence. 

Figure 19. The BW Pioneer, the double-hulled tanker that will serve as the FPSO for the Cascade 

and Chinook developments. (Depiction courtesy of Petrobras.) 
DEEPWATER GULF OF MEXICO 2009: INTERIM REPORT OF 2008 HIGHLIGHTS

44 

Phoenix 

Energy Resource Technology acquired the Typhoon Field in August 2006 following the 

loss of the Chevron operated TLP in Green Canyon Block 237. Energy Resource Technology 

contracted Helix to provide an FPU named Helix Producer I (Figure 20) for redevelopment 

of the newly renamed Phoenix Field. The Helix Producer I is designed to serve smaller 

fields in deep water and can also be used as an early production test vessel. The Helix 

Producer I vessel is a dynamically positioned FPU with a detachable buoy that can quickly 

disconnect and sink to a water depth of 130 ft (40 m). This allows the vessel to move away 

from adverse sea conditions. The ability to move away from a storm with personnel on 

board offered many safety advantages over existing deepwater facilities. A disconnectable 

transfer system (DTS) (Figure 21) was designed and built by Flexible Engineered 

Solutions to attach the Helix Producer I to the subsea wells in the Phoenix Field. Although 

the DTS had been previously used in Asia, the concept was a first for the U.S. GOM. 

Energy Resource Technology has worked with MMS and Flexible Engineered Solutions to 

provide a system that meets or exceeds the operating requirements for the GOM. 

Helix Producer I is currently completing vessel system commissioning in Neorion 

Shipyard in Syros, Greece. The vessel will arrive in Kiewit Offshore Services in Ingleside, 

Texas, in May 2009. The DTS will be connected to the hull, and topside process modules 

will be installed on the vessel. The vessel will sail to Green Canyon Block 237 during the 

fourth quarter of 2009 and begin riser pull in. Once the Helix Producer I vessel has 

demonstrated to United States Coast Guard and MMS that operation of the DTS and 

Certificate of Compliance have been achieved, Energy Resource Technology will commence 

production. 

The developments and associated new technologies mentioned above are just a few that 

have been reviewed by MMS’s petroleum and structural engineers. Approval can be 

granted only after significant research and hazard analyses are conducted. The engineers 

considered many different conditions that can exist offshore and also confirmed that there 

was a proven effective method to shut-down operations in the case of a failure. 

Figure 20. The Helix Producer I, a conventional ship-shape 

floating production unit. (Photo courtesy of Helix 

Energy Solutions.) 
DRILLING AND DEVELOPMENT

45 

Figure 21. Disconnectable transfer system to attach the Helix Producer I to the subsea wells 

in the Phoenix Field. (Photo courtesy of Helix Energy Solutions.) 

Thunder Horse 

Another exciting development that will significantly contribute to our national oil and 

gas reserves is British Petroleum Exploration and Production, Inc’s Thunder Horse. The 

Thunder Horse platform is located about 150 mi (241 km) southeast of New Orleans in 

Mississippi Canyon Block 778 at a water depth of approximately 6,050 ft (1,844 m) and is 

the largest semisubmersible facility in the world at 130,000 tonnes (143,300 U.S. tons) 

displacement and has a deck load capacity of 40,000 tonnes (44,092 U.S. tons). Production 

is from reservoirs between 14,000 and 19,000 ft (4,267 and 5,791 m) below the seabed, with 

reservoir pressures of 13,000 to 18,000 psi and reservoir temperatures of 190o to 270o F 

(88o to 132o C). The Thunder Horse Field is the largest producer in the GOM. As of March 

20, 2009, Thunder Horse was producing approximately 260,000 bo/d and 210.5 MMcf/d from 

seven wells. Prior to commencing production from the seventh well, British Petroleum 

received approval from the MMS New Orleans district to debottleneck the topside 

production facilities to 275,000 bo/d and 220 MMcf/d. Oil and gas is transported to existing 

shelf and onshore pipelines via the Proteus and Endymion oil pipeline systems and the 

Okeanos gas pipeline system, which are part of the Mardi Gras Transportation System, the 

highest capacity deepwater pipeline system ever built. On the adjacent Thunder Horse 

North Field, the Discoverer Enterprise MODU is drilling and completing wells that will 

bring on additional production throughout 2009. 

47 

RESERVES AND PRODUCTION 

RESERVES AND DISCOVERIES

Figure 22 shows the number of deepwater discoveries each year since 1975. Since 1975 

there have been at least 285 deepwater discoveries in the GOM, of which 127 have become 

proved fields, accounting for 11.060 BBOE of proved reserves. In an attempt to capture the 

impact of the deepwater exploratory successes, in addition to MMS proved reserves, 

unproved reserves, and resource estimates, Figure 22 also includes publicly-available, 

industry-announced discoveries (IAD’s). The IAD volumes contain considerable 

uncertainty, are based on limited drilling, include numerous assumptions, and have not 

been confirmed by independent MMS analyses. They do, however, illustrate recent activity 

better than using only MMS-proved reserve numbers. 

There is often a significant lag between a successful exploration well and its 

hydrocarbons being produced. The success of an exploration well may remain concealed 

from the public for several years until the operator requests a “Determination of Well 

Producibility” from MMS. A successful MMS determination then “qualifies” the lease as 

producible and the discovery is placed in a field. The discovery date of that field is then 

defined as the total depth date of the field’s first well that encountered significant 

hydrocarbons. Hydrocarbon reserves are still considered unproved until it is clear that the 

field will go on production. Then the reserves move into MMS’s proved category. 

The increase in proved reserves in 1989 is partially a result of the Mars-Ursa 

discoveries. Likewise, the increase in 1999 is partially a result of the Thunder Horse 

discovery. These two fields, located in Mississippi Canyon, represent two of the largest in 

the GOM based on proved barrels of oil equivalent (BOE) reserves (Crawford et al., 2008). 

The apparent decline of proved reserve additions in recent years is caused by the lag 

between discovery and development. The increase of unproved reserves, resources, and 

IAD’s in 2006 is partially a result of the Kaskida discovery located in Keathley Canyon. In 

the last 2 years, oil and gas volumes added to the GOM decreased sharply from those in 

2006. This is due in part to the fact that MMS has not completed volumetric estimates for 

2007 and 2008 discoveries in deep water. 

PRODUCTION TRENDS

Leasing, drilling, and discoveries all stepped into deeper waters with time. Production, 

the final piece in the puzzle, is no exception. In 2007, approximately 70 percent of the 

GOM’s oil production and 36 percent of its natural gas were from wells in 1,000 ft (305 m) 

of water or greater. Figure 23 illustrates deepwater projects that began production in 

2007 and 2008 and those expected to commence production in the next 5 years. Seven 

deepwater projects went online in 2008: Bass Lite and Neptune in Atwater Valley; and 

Blind Faith, Mississippi Canyon Block 161, Raton, Thunder Horse, and Valley Forge in 

Mississippi Canyon. In addition to the projects displayed on Figure 23, more are likely to 

come online in the next few years but are not shown because operators have not yet 

announced their plans. See Appendix A for a listing of all productive projects. 
48 

0

500

1,0001,5002,0002,5003,000

1975

1977

1979

1981

1983

1985

1987

1989

1991

1993

1995

1997

1999

2001

2003

2005

Discovery Year

Million Barrels of Oil Equivalent

Proved reservesUnproved reserves, resources, and industry-announced discoveriesNumber of discoveries

Figure 22. Number and volume of deepwater discoveries. Volumes include MMS reserves, MMS resources, an

announced discoveries. 
49 

Figure 23. Deepwater projects that began production in 2007 and 2008 and those expected to begin production 
DEEPWATER GULF OF MEXICO 2009: INTERIM REPORT OF 2008 HIGHLIGHTS

50 

Table 6 shows that the 20 most prolific producing blocks in the GOM continue to be 

located in deep water. The total cumulative production numbers on this table are from 

January 2006 through December 2007. With the onset of production from the Thunder 

Horse Field in 2008, it is currently the largest daily producer in the GOM. As of March 20, 

2009, production was approximately 260,000 bo/d from seven wells. 

Table 6. Top 20 Producing Blocks for the Years 2006-2007 

Block Project Name Operator Water Depth (ft)1

 Production (BOE)2

MC 807 Mars Shell 2,933 53,019,685 

MC 383 Kepler (Na Kika) British Petroleum 5,739 39,067,447 

MC 809 Ursa Shell 3,800 35,833,474 

GC 782 Mad Dog British Petroleum 4,420 29,236,814 

GC 644 Holstein British Petroleum 4,340 23,479,322 

VK 786 Petronius ChevronTexaco 1,753 22,756,704 

VK 912 Ram Powell Shell 3,216 21,399,283 

GB 668 Gunnison Kerr-McGee 3,126 19,934,221 

MC 686 Mensa Shell 5,329 19,203,737 

MC 429 Ariel (Na Kika) British Petroleum 6,240 19,035,754 

GB 215 Conger Amerada Hess 1,500 18,676,616 

MC 127 Horn Mountain British Petroleum 5,400 18,672,184 

MC 765 Princess Shell 3,642 18,228,344 

MC 763 Mars Shell 2,933 18,086,449 

EB 602 Nansen Kerr-McGee 3,580 17,605,355 

GB 783 Magnolia ConocoPhillips 4,670 15,126,505 

GC 202 Brutus Shell 2,985 14,899,369 

MC 85 King British Petroleum 5,317 14,841,496 

GC 562 K2 Anadarko 3,970 12,929,509 

MC 773 Devil’s Tower Eni 5,610 12,813,802 1

 Water depths are approximate and may vary depending on the location of the production facility or the location of 

a completed well (average of wells or deepest well site) in the block. 

2

 Cumulative production from January 2006 through December 2007. 

Figures 24a and 24b illustrate the importance of the GOM to the Nation’s energy 

supply. The GOM supplied approximately 25 percent of the Nation’s domestic oil and 

14 percent of the Nation’s domestic gas production in 2007. A significant portion 

(approximately 18%) of the oil volume came from the deepwater GOM. Nine projects tied 

back to the Independence Hub facility came online from July through October of 2007. 

When at peak capacity, production from the hub will add 1 Bcf/d, representing over 

10 percent of the gas production from the total GOM. 

Figure 25a illustrates historic trends in oil production. Shallow-water oil production 

rose rapidly in the 1960’s, peaked in 1971, and has undergone cycles of increase and decline 

since then. Since 1997, the shallow-water GOM oil production has steadily declined and, at 

the end of 2006, was at its lowest level since 1965. It has, however, begun to increase in 

2007. From 1995 through 2003, deepwater oil production experienced a dramatic increase 

similar to that seen in the shallow-water GOM during the 1960’s, offsetting declines in 

shallow-water oil production. In fact, beginning in 2000, more oil has been 
RESERVES AND P RODUCTION

51 

 Deepwater

GOM

17.8% 

 Shallow-water

GOM

7.6% 

 Other U.S.

74.6% 

 Deepwater

GOM

5.0% 

 Shallow-water

GOM

8.8% 

 Other U.S.

86.2% 

Figure 24a. Estimated U.S. oil production 

in 2007. 

Figure 24b. Estimated U.S. gas production 

in 2007. 

produced from the deepwater areas of the GOM than from shallow waters. Starting in 

2003, deepwater oil production basically leveled off. Figure 25b shows similar production 

trends for gas. Shallow-water gas production rose sharply throughout the 1960’s and 

1970’s, and then remained relatively stable over the next 17 years before declining steadily 

from 1997 through 2007. At the same time shallow-water gas production started to decline 

in 1997, deepwater gas production began to increase, helping to offset the declines from 

shallow water. Gas production from deep water has, however, declined slightly from 2003 

through 2007. Appendix B lists historic annual GOM oil and gas production values. 

PRODUCTION RATES

Figures 26a and 26b compare maximum historic daily production rates for each lease in 

the GOM (i.e., the well with the highest historic production rate is shown for each lease). 

These maps show that many deepwater fields produce at some of the highest rates 

encountered in the GOM. Figure 26a also shows that maximum oil rates were 

significantly higher off the southeast Louisiana coast than off the Texas coast. Figure 26b

illustrates the high deepwater gas production rates relative to the rest of the GOM. The 

relatively high gas rates from fields denoted with an asterisk are tied back to the 

Independence Hub facility. The hub’s 1 Bcf/d capacity accounts for over 10 percent of the 

total gas production from the GOM. Note also the excellent production rates from the 

Norphlet trend (off the Alabama coast) and the Corsair trend (off the Texas coast). 
DEEPWATER GULF OF MEXICO 2009: INTERIM REPORT OF 2008 HIGHLIGHTS

52 

0

200

400

600

800

1,000

1,200

195019541958196219661970197419781982198619901994199820022006

Year

Thousand Barrels of Oil per Day

Shallow-water oil

Deepwater oil

Figure 25a. Comparison of average annual shallow- and deepwater oil production. 

0

2

4

6

8

10

12

14

16

195019541958196219661970197419781982198619901994199820022006

Year

Billion Cubic Feet of Gas per Day

Shallow-water gas

Deepwater gas

Figure 25b. Comparison of average annual shallow- and deepwater gas production. 
53 

Figure 26a. Maximum historic oil well production rates. 
54 

 		













 


 





 




 	

 

!"#

 	











  



 



# $ %

&"%'(%!"

$

Figure 26b. Maximum historic gas well production rates. 
55 

HIGHLIGHTS AND CONCLUSIONS 

HIGHLIGHTS

• At the end of 2008, 57 percent of all GOM leases were located in deep 

water. 

• Central Lease Sale 206 attracted approximately $3.7 billion in high bids—

the most since Federal offshore leasing began in 1954. The MMS received 

1,057 bids from 85 companies on 615 blocks, of which 603 were ultimately 

awarded. Sixty-nine percent of all blocks receiving bids were in 1,000 ft 

(305 m) of water or greater. 

• Eastern Sale 224 attracted almost $65 million in high bids. The MMS 

received 58 bids from six companies on 36 blocks, of which all were 

ultimately awarded. Sale 224 offered approximately 0.5 million acres, 

from what is known as the 181 Area, which has been off-limits to 

exploration since 1988. 

• Western Lease Sale 207 attracted approximately $487 million in high bids. 

The MMS received 423 bids from 53 companies on 319 blocks, of which 313 

were ultimately awarded. Seventy-eight percent of all blocks receiving 

bids were in 1,000 ft (305 m) of water or greater. 

• Central Lease Sale 208 attracted approximately $703 million in high bids. 

The MMS received 476 bids from 70 companies on 348 blocks. Seventytwo percent of all blocks receiving bids were in 1,000 ft (305 m) of water or 

greater. Areas for lease in Sale 208 included approximately 4.2 million 

acres, from what is known as the 181 South Area, which has been offlimits to exploration since 1988. 

• There are 15 newbuild MODU’s being built and contracted for use in the 

ultra-deepwater Gulf and will be ready for operation in the next 

2-3 years—they will be capable of operating in water depths up to 12,000 ft 

(3,658 m) and drilling up to 40,000 ft (12,192 m) in depth. 

• Approximately 21 percent of the worldwide, deepwater MODU’s are 

contracted to the GOM. 

• In 2008, 108 wells were spudded in water depths greater than 1,000 ft 

(305 m), and nearly 80 percent were for exploration. 

• Shell Oil Company set a world water depth record in drilling and 

completing a subsea well 9,356 ft (2,852 m) below the water surface in the 

Silvertip project at the Perdido Regional Host facility in Alaminos Canyon. 

• There were 15 industry-announced discoveries in 2008, including one in 

the Lower Tertiary trend. 
DEEPWATER GULF OF MEXICO 2009: INTERIM REPORT OF 2008 HIGHLIGHTS

56 

• Since 1975 there have been at least 285 deepwater discoveries in the 

GOM, of which 127 have become proved fields, accounting for 

11.060 BBOE of proved reserves. 

• In 2007, deep water continued to be a very important part of the total 

GOM production, providing approximately 70 percent of the oil and 

36 percent of the gas in the region. 

• There were 141 producing projects in the deepwater GOM at the end of 

2008, up from 130 at the end of 2007. Seven projects came online in 2008, 

including record production from Thunder Horse. 

• The 20 most prolific producing blocks in the GOM continue to be located in 

deep water. 

• With the onset of production from the Thunder Horse Field in 2008, it is 

currently the largest daily producer in the GOM. As of March 20, 2009, 

production was approximately 260,000 bo/d from seven wells. 

• Nine fields associated with the Independence Hub production facility came 

online in 2007. The hub’s 1 Bcf/d capacity accounts for over 10 percent of 

the total gas production from the GOM. 

• The first floating, production, storage, and offloading (FPSO) system in the 

U.S. GOM, the BW Pioneer vessel, will develop the Cascade and Chinook 

Fields in Walker Ridge, with first oil expected in 2010. Unique to the 

BW Pioneer is a detachable turret buoy, connecting the subsea wells to the 

FPSO. 

• Petrobras’ Cascade/Chinook development project will utilize four 

technologies considered new to the GOM, including free-standing hybrid 

risers, polyester mooring, electric submersible booster pumps, and shuttle 

tankers for oil export. 

• The first ship-shape, dynamically positioned, disconnectable turret floating 

production unit (FPU) in the U.S. GOM, Helix Producer I, will develop the 

Phoenix Field in Green Canyon, with a planned production startup in 

2010. 

• The Perdido Regional Host facility will produce the Great White, Tobago, 

and Silvertip discoveries in Alaminos Canyon beginning in 2010. The 

truss spar was installed in August 2008 and set a new record as the 

deepest spar in over 8,000 ft (2,438 m) of water. 

• Several NTL’s were implemented in 2008 to inhibit the loss of or damage 

to offshore structures during hurricane season. 
HIGHLIGHTS AND C ONCLUSIONS

57 

• The MMS was involved in over 35 API committees in 2008 to pave the way 

for acceptance of new technologies and practices as industry moves to 

develop prospects in a more challenging environment. 

CONCLUSIONS

With complex deepwater developments, it is not uncommon for there to be considerable 

lag time between leasing and first production. The Thunder Horse Field illustrates the lag 

time that can exist between leasing and first production. It was leased in 1988, the first 

well was drilled in 1999, and production began in 2008. Figure 27 demonstrates average 

lags associated with deepwater operations. This figure uses data from only productive 

deepwater leases and illustrates the lags between leasing and qualification and from 

qualification to first production. Operators sometimes announce discoveries to the public 

long before qualifying the lease as producible with MMS (and thereby granted field status). 

Note that, since deepwater leases are in effect for 8 or 10 years, the data are incomplete 

beyond 1998. 2.8

0.3

1.1

0.7

4.8

5.9

6.9

7.3

6.0

3.7

4.2

3.5

2.9

1.9

1.5

0.7

0.8

1.9

2.8

3.6

0.9

1.7

1.8

3.8

1.9

0.9

1.4

2.1

1.8

1.5

1.3

0.9

1.2

0.4

6.5

3.4

2.4

8.5

5.5

5.6

4.3

3.3

1.8

2.5

1.3

1.7

1.3

1.6

1.2

1.2

1.3

0.0

2.0

4.0

6.0

8.0

10.0

12.0

14.0

16.0

1974-751976-771978-791980-811982-831984-851986-871988-891990-911992-931994-951996-971998-992000-012002-032004-052006-072007-082008-09

Year Lease Acquired

Number of Years

Additional time to first production

Additional time to qualify

Years to first well

No production from leases

acquired post-2007

Leases still in primary term

Figure 27. Average lag time from leasing to first production for producing deepwater fields. 

Figure 27 indicates that, as industry gains experience in the deepwater areas of the 

Gulf, the time between leasing and production is reduced. Since 1988, there has been a 

reduction in time from lease acquisition to first well drilled. Developments near accessible 

infrastructure and the use of proven development technologies reduce the lag between 

leasing and production. Conversely, as new discoveries move into dramatically deeper 

water depths, and with many new discoveries being far from existing infrastructure, an 
DEEPWATER GULF OF MEXICO 2009: INTERIM REPORT OF 2008 HIGHLIGHTS

58 

increase in lag time between leasing and production should be anticipated. However, these 

challenges continually push industry to develop new technologies and development 

techniques for the GOM. 

For example, the Lower Tertiary trend is in very deep water, has target depths below 

25,000 ft (7,620 m), has the potential for high-pressure/high-temperature conditions, and 

many of the discoveries underlie a thick salt layer, all of which complicate drilling and 

development operations. The first fields scheduled for production from the Lower Tertiary 

trend in Walker Ridge are Cascade and Chinook. Because these fields are so remote from 

existing infrastructure, they will be developed with subsea wells tied into an FPSO, a first 

in U.S. GOM waters. Another example of development challenges in very deep waters is 

the Perdido truss spar, which will be the hub facility for the Great White, Silvertip, and 

Tobago projects. Because of the remote location of the facility in Alaminos Canyon Block 

857, 77 mi (124 km) of oil export and 107 mi (172 km) of gas export pipeline will be 

installed with the facility. Additionally, Perdido represents the first application of full, 

host-scale subsea separation and boosting. The results of first production from 

Cascade/Chinook and the Perdido facility are scheduled for 2010. These results will impact 

all other operators in the Lower Tertiary trend, both geologically and technologically. 

AMERICA’S OFFSHORE ENERGY FUTURE

The future of deepwater GOM exploration and production remains very promising. The 

large number of active deepwater leases, the development of important new discoveries, the 

growing deepwater infrastructure and new technologies, and the onset of ultra-deepwater 

production are all indicators of this maturing and yet still expanding frontier. All of these 

factors will ensure that the deepwater GOM will remain one of the world’s premier oil and 

gas basins. 
59 

CONTRIBUTING PERSONNEL 

This report includes contributions from the following individuals: 

Pat Adkins 

Asani Brewton 

Deborah Miller 

Mike Prendergast 

Terry Rankin 

61 

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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. 

Federal Register. 2009. Outer Continental Shelf (OCS) Central Planning Area (CPA) Gulf 

of Mexico (GOM) Oil and Gas Lease Sale 208: Final Notice of Sale, Wednesday, 

January 14, 2009. 74 FR 9, pp. 2092-2098. 

French, L.S., E.G. Kazanis, L.C. Labiche, T.M. Montgomery, G.E. Richardson. 2005. 

Deepwater Gulf of Mexico 2005: Interim Report of 2004 Highlights. U.S. Dept. of the 

Interior, Minerals Management Service, Gulf of Mexico OCS Region, New Orleans, LA. 

OCS Report MMS 2005-023. 48 pp. 

Grieb, T.M., T.E. Donn, J. Collins, J. Radde, C. Perez, J.B. Smith, G. Rowe, S. Scott, and 

G.T. Ririe. 2008. Effects of Subsea Processing on Deepwater Environments in the Gulf 

of Mexico. U.S. Dept. of the Interior, Minerals Management Service, Gulf of Mexico 

OCS Region, New Orleans, LA. OCS Study MMS 2008-022. 66 pp. 

Hamilton, P., T.J. Berger, J.J. Singer, E. Waddell, J.H. Churchill, R.R. Leben, T.N. Lee, and 

W. Sturges. 2000. DeSoto Canyon Eddy Intrusion Study: Final Report. Volume II: 

Technical Report. U.S. Dept of the Interior, Minerals Management Service, Gulf of 

Mexico OCS Region, New Orleans, LA. OCS Study MMS 2000-80. 275 pp. 

Hamilton, P., J.J. Singer, E. Waddell, and K. Donohue. 2003. Deepwater Observations in 

the Northern Gulf of Mexico from in-situ Current Meters and PIES. Volume II: 

Technical Report. U.S. Dept. of the Interior, Minerals Management Service, Gulf of 

Mexico OCS Region, New Orleans, LA. OCS Report MMS 2003-049. 95 pp. 

Inoue, M., S.E. Welsh, L.J. Rouse, Jr., and E. Weeks. 2008. Deepwater Currents in the 

Eastern Gulf of Mexico: Observations at 25.5oN and 87oW. U.S. Dept. of the Interior, 

Minerals Management Service, Gulf of Mexico OCS Region, New Orleans, LA. OCS 

Study MMS 2008-001. 95 pp. 

Jochens, A., D. Biggs, K. Benoit-Bird, D. Engelhaupt, J. Gordon, C. Hu, N. Jaquet, 

M. Johnson, R. Leben, B. Mate, P. Miller, J. Ortega-Ortiz, A. Thode, P. Tyack, and 

B. Würsig. 2008. Sperm Whale Seismic Study in the Gulf of Mexico: Synthesis Report. 

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

New Orleans, LA. OCS Study MMS 2008-006. 341 pp. Internet Web site: http://

www.gomr.mms.gov/PI/PDFImages/ESPIS/4/4444.pdf. 

McKone, K., N.D. Walker, and E. Weeks. 2007. Full-water Column Currents Near the 

Sigsbee Escarpment (91-92oW Longitude) and Relationships with the Loop Current and 

Associated Warm and Cold-core Eddies. U.S. Dept. of the Interior, Minerals 

Management Service, Gulf of Mexico OCS Region, New Orleans, LA. OCS Study MMS 

2007-056. 107 pp. Internet Web site: http://www.gomr.mms.gov/PI/PDFImages/ESPIS/

4/4295.pdf. 
REFERENCES

63 

Richardson, G.E., L.D. Nixon, C.M. Bohannon, E.G. Kazanis, T.M. Montgomery, and M.P. 

Gravois. 2008. Deepwater Gulf of Mexico 2008: America’s Offshore Energy Future. 

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

New Orleans, LA. OCS Report MMS 2008-013. 102 pp. 

Sulak, K.J., M.T. Randall, K.E. Luke, A.D. Norem, and J.M. Miller (eds.). 2008. 

Characterization of Northern Gulf of Mexico Deepwater Hard Bottom Communities with 

Emphasis on Lophelia Coral—Lophelia Reef Megafaunal Community Structure, 

Biotopes, Genetics, Microbial Ecology, and Geology. USGS Open-File Report 2008-1148; 

OCS Study MMS 2008-015. 418 pp. Internet Web site: http://fl.biology.usgs.gov/

coastaleco/OFR_2008-1148_MMS_2008-015/index.html. 

U.S. Dept. of the Interior, Minerals Management Service. 2000. Deepwater Gulf of Mexico 

OCS Currents. U.S. Dept. of the Interior, Minerals Management Service, Gulf of Mexico 

OCS Region, New Orleans, LA. MMS Safety Alert Notice No. 180. 

U.S. Dept. of the Interior, Minerals Management Service. 2007. Assessment of Existing 

OCS Platforms and Related Structures for Hurricane Conditions. U.S. Dept. of the 

Interior, Minerals Management Service, Gulf of Mexico OCS Region, New Orleans, LA. 

NTL 2007-G27. 

U.S. Dept. of the Interior, Minerals Management Service. 2008a. MMS Awards $5.5 

Million to Study Gulf’s Loop Current. U.S. Dept. of the Interior, Minerals Management 

Service, Gulf of Mexico OCS Region, New Orleans, LA. MMS News Release No. R-08-

3908. 

U.S. Dept. of the Interior, Minerals Management Service. 2008b. MMS Underway with 

$3.7 Million Deepwater Coral Study. U.S. Dept. of the Interior, Minerals Management 

Service, Gulf of Mexico OCS Region, New Orleans, LA. MMS News Release No. R-08-

3934. 

U.S. Dept. of the Interior, Minerals Management Service. 2008c. Guidelines for Moored 

Drilling Rig Fitness Requirements for Hurricane Season. U.S. Dept. of the Interior, 

Minerals Management Service, Gulf of Mexico OCS Region, New Orleans, LA. NTL 

2008-G09. 

U.S. Dept. of the Interior, Minerals Management Service. 2008d. Minerals Management 

Service Approves Development Plans for First Use of Floating Production Storage 

Offloading Facility in Gulf of Mexico. Press Release #3807, April 29, 2008. U.S. Dept. 

of the Interior, Minerals Management Service, Gulf of Mexico OCS Region, New 

Orleans, LA. Internet Web site: http://www.mms.gov/ooc/press/2008/press0429.htm. 

65 

APPENDICES 

APPENDIX A. DEVELOPMENT SYSTEMS OF PRODUCTIVE DEEPWATER PROJECTS

Year of 

First 

Production 

Project Name1 Operator Block 

Water 

Depth 

(ft) 2

System Type 

1979 Cognac Shell MC 194 1,023 Fixed Platform 

1984 Lena ExxonMobil MC 280 1,000 Compliant Tower 

1988 GC 293 Placid GC 29 1,540 Semisubmersible4

/ 

Subsea 

1988 GC 313 Placid GC 31 2,243 Subsea 

1989 Bullwinkle Shell GC 65 1,353 Fixed Platform 

1989 Jolliet ConocoPhillips GC 184 1,760 TLP 

1991 Amberjack British Petroleum MC 109 1,100 Fixed Platform 

1992 Alabaster ExxonMobil MC 485 1,438 Subsea 

1993 Diamond3 Kerr-McGee MC 445 2,095 Subsea 

1993 Zinc ExxonMobil MC 354 1,478 Subsea 

1994 Auger Shell GB 426 2,860 TLP 

1994 Pompano and Pompano II British Petroleum VK 989 1,290 Fixed Platform/ 

Subsea 

1994 Tahoe and SE Tahoe Shell VK 783 1,500 Subsea 

1995 Cooper3 Newfield GB 388 2,097 Semisubmersible4

1995 Shasta3 ChevronTexaco GC 136 1,048 Subsea 

1995 VK 862 Walter VK 862 1,043 Subsea 

1996 Mars Shell MC 807 2,933 TLP/Subsea 

1996 Popeye Shell GC 116 2,000 Subsea 

1996 Rocky3 Shell GC 110 1,785 Subsea 

1997 Mensa Shell MC 731 5,318 Subsea 

1997 Neptune Kerr-McGee VK 826 1,930 Spar/Subsea 

1997 Ram-Powell Shell VK 956 3,216 TLP 

1997 Troika British Petroleum GC 200 2,721 Subsea 

1998 Arnold Marathon EW 963 1,800 Subsea 

1998 Baldpate Amerada Hess GB 260 1,648 Compliant Tower 

1998 Morpeth Eni EW 921 1,700 TLP/Subsea 

1998 Oyster Marathon EW 917 1,195 Subsea 

1999 Allegheny Eni GC 254 3,294 TLP 

1999 Angus Shell GC 113 2,045 Subsea 

1999 Dulcimer3 Mariner GB 367 1,120 Subsea 

1999 EW 1006 Walter EW 1006 1,884 Subsea 

1999 Gemini ChevronTexaco MC 292 3,393 Subsea 

1999 Genesis ChevronTexaco GC 205 2,590 Spar 

1999 Macaroni Shell GB 602 3,600 Subsea 

1999 Penn State Amerada Hess GB 216 1,450 Subsea 

1999 Pluto Mariner MC 674 2,828 Subsea 
DEEPWATER GULF OF MEXICO 2009: INTERIM REPORT OF 2008 HIGHLIGHTS

66 

Year of 

First 

Production 

Project Name1 Operator Block 

Water 

Depth 

(ft) 2

System Type 

1999 Ursa Shell MC 809 3,800 TLP 

1999 Virgo TotalFinaElf VK 823 1,130 Fixed Platform 

2000 Allegheny South Eni GC 298 3,307 Subsea 

2000 Black Widow Mariner EW 966 1,850 Subsea 

2000 Conger Amerada Hess GB 215 1,500 Subsea 

2000 Diana ExxonMobil EB 945 4,500 Subsea 

2000 Europa Shell MC 935 3,870 Subsea 

2000 Hoover ExxonMobil AC 25 4,825 Spar 

2000 King Shell MC 764 3,250 Subsea 

2000 Marlin British Petroleum VK 915 3,236 TLP 

2000 Northwestern Amerada Hess GB 200 1,736 Subsea 

2000 Petronius ChevronTexaco VK 786 1,753 Compliant Tower 

2001 Brutus Shell GC 158 3,300 TLP 

2001 Crosby Shell MC 899 4,400 Subsea 

2001 Einset3 Shell VK 872 3,500 Subsea 

2001 EW 878 Walter EW 878 1,585 Subsea 

2001 Ladybug ATP GB 409 1,355 Subsea 

2001 Marshall ExxonMobil EB 949 4,376 Subsea 

2001 MC 683 Walter MC 68 1,360 Subsea 

2001 Mica ExxonMobil MC 211 4,580 Subsea 

2001 Nile British Petroleum VK 914 3,535 Subsea 

2001 Oregano Shell GB 559 3,400 Subsea 

2001 Pilsner Unocal EB 205 1,108 Subsea 

2001 Prince El Paso EW 1003 1,500 TLP 

2001 Serrano Shell GB 516 3,153 Subsea 

2001 Typhoon5 ChevronTexaco GC 237 2,107 TLP 

2002 Aconcagua TotalFinaElf MC 305 7,100 Subsea 

2002 Aspen British Petroleum GC 243 3,065 Subsea 

2002 Camden Hills Marathon MC 348 7,216 Subsea 

2002 East Boomvang6 Kerr-McGee EB 688 3,795 Subsea 

2002 Horn Mountain British Petroleum MC 127 5,400 Spar 

2002 King7 British Petroleum MC 84 5,418 Subsea 

2002 King Kong Mariner GC 472 3,980 Subsea 

2002 King's Peak British Petroleum DC 133 6,845 Subsea 

2002 Lost Ark Nobel EB 421 2,960 Subsea 

2002 Madison ExxonMobil AC 24 4,856 Subsea 

2002 Manatee Shell GC 155 1,939 Subsea 

2002 Nansen Kerr-McGee EB 602 3,685 Spar 

2002 Navajo Kerr-McGee EB 690 4,210 Subsea 

2002 North Boomvang6 Kerr-McGee EB 643 3,650 Spar 

2002 Princess Shell MC 765 3,642 Subsea 
APPENDICES

67 

Year of 

First 

Production 

Project Name1 Operator Block 

Water 

Depth 

(ft) 2

System Type 

2002 Sangria3 Hydro GOM GC 177 1,487 Subsea 

2002 Tulane Amerada Hess GB 158 1,054 Subsea 

2002 Yosemite Mariner GC 516 4,150 Subsea 

2003 Boris5 BHP Billiton GC 282 2,378 Subsea 

2003 Dawson8 Kerr-McGee GB 669 3,152 Subsea 

2003 Durango8 Kerr-McGee GB 667 3,105 Subsea 

2003 East Anstey/Na Kika Shell MC 607 6,590 Semisubmersible/ 

Subsea9

2003 Falcon Marubeni EB 579 3,638 Subsea 

2003 Fourier/Na Kika Shell MC 522 6,940 Semisubmersible/ 

Subsea9

2003 Gunnison Kerr-McGee GB 668 3,100 Spar 

2003 Habanero Shell GB 341 2,015 Subsea 

2003 Herschel/Na Kika Shell MC 520 6,739 Semisubmersible/ 

Subsea9

2003 Matterhorn TotalFinaElf MC 243 2,850 TLP 

2003 Medusa Murphy MC 582 2,223 Spar 

2003 North Medusa Murphy MC 538 2,223 Subsea 

2003 Pardner Anadarko MC 401 1,139 Subsea 

2003 Tomahawk Marubeni EB 623 3,412 Subsea 

2003 West Boomvang6 Kerr-McGee EB 642 3,678 Subsea 

2003 Zia Devon MC 496 1,804 Subsea 

2004 Ariel/Na Kika British Petroleum MC 429 6,240 Semisubmersible/ 

Subsea9

2004 Coulomb/Na Kika Shell MC 657 7,591 Semisubmersible/ 

Subsea9

2004 Devil's Tower Eni MC 773 5,610 Spar 

2004 Front Runner Murphy GC 338 3,330 Spar 

2004 GB 208 McMoran GB 208 1,275 Subsea 

2004 Glider Shell GC 248 3,440 Subsea 

2004 Hack Wilson Kerr-McGee EB 599 3,650 Subsea 

2004 Harrier3 Pioneer EB 759 4,114 Subsea 

2004 Holstein British Petroleum GC 645 4,340 Spar 

2004 Kepler/Na Kika British Petroleum MC 383 5,759 Semisubmersible/ 

Subsea9

2004 Llano Shell GB 386 2,340 Subsea 

2004 Magnolia ConocoPhilips GB 783 4,674 TLP 

2004 Marco Polo Anadarko GC 608 4,300 TLP 

2004 MC 837 Walter MC 837 1,524 Subsea 

2004 Ochre Mariner MC 66 1,144 Subsea 

2004 Raptor Pioneer EB 668 3,710 Subsea 

2004 Red Hawk Kerr-McGee GB 877 5,300 Spar 

2004 South Diana ExxonMobil AC 65 4,852 Subsea 
DEEPWATER GULF OF MEXICO 2009: INTERIM REPORT OF 2008 HIGHLIGHTS

68 

Year of 

First 

Production 

Project Name1 Operator Block 

Water 

Depth 

(ft) 2

System Type 

2005 Baccarat W and T Offshore GC 178 1,404 Subsea 

2005 Citrine LLOG GC 157 2,614 Subsea 

2005 GC 137 Nexen GC 137 1,168 Subsea 

2005 K2 Anadarko GC 562 4,006 Subsea 

2005 Killer Bee Walter MC 582 2,223 Subsea 

2005 Mad Dog British Petroleum GC 782 4,420 Spar 

2005 Swordfish Noble VK 962 4,677 Subsea 

2005 Triton and Goldfinger Eni MC 728 5,610 Subsea 

2006 Constitution Kerr-McGee GC 680 4,970 Spar 

2006 Dawson Deep Kerr-McGee GB 625 2,965 Subsea 

2006 Gomez ATP MC 711 2,975 Semisubmersible 

2006 K2 North Anadarko GC 518 4,049 Subsea 

2006 Lorien Noble GC 199 2,315 Subsea 

2006 Rigel Eni MC 252 5,225 Subsea 

2006 Seventeen Hands Eni MC 299 5,881 Subsea 

2006 SW Horseshoe Walter EB 430 2,285 Subsea 

2006 Ticonderoga Kerr-McGee GC 768 5,272 Subsea 

2007 Anduin ATP MC 755 2,904 Subsea 

2007 Atlantis British Petroleum GC 787 7,050 Semisubmersible 

2007 Atlas-AtlasNW/Ind. Hub Anadarko LL 50 8,934 FPS/Subsea10

2007 Cheyenne/Ind. Hub Anadarko LL 399 8,951 FPS/Subsea10

2007 Cottonwood Petrobras GB 244 2,130 Subsea 

2007 Deimos Shell MC 806 3,106 Subsea 

2007 Jubilee/Ind. Hub Anadarko AT 349 8,825 FPS/Subsea10

2007 Merganse /Ind. Hub Anadarko AT 37 8,015 FPS/Subsea10

2007 Mondo NW/Ind. Hub Anadarko LL 1 8,340 FPS/Subsea10

2007 Q/Ind. Hub Hydro GOM MC 961 7,925 FPS/Subsea10

2007 San Jacinto/Ind. Hub Eni DC 618 7,850 FPS/Subsea10

2007 Shenzi11 BHP Billiton GC 652 4,300 TLP/Subsea 

2007 Spiderman/Ind. Hub Anadarko DC 621 8,087 FPS/Subsea10

2007 Tiger DeepGulf Energy GC 195 1,900 Subsea 

2007 Vortex/Ind. Hub Anadarko AT 261 8,344 FPS/Subsea10

2007 Wrigley Newfield MC 506 3,911 Subsea 

2008 Bass Lite Mariner AT 426 6,634 Subsea 

2008 Blind Faith ChevronTexaco MC 696 6,989 Semisubmersible 

2008 MC 161 Walter MC 161 2,924 Subsea 

2008 Neptune BHP Billiton AT 575 4,232 TLP 

2008 Raton Nobel MC 248 3,290 Subsea 

2008 Thunder Horse British Petroleum MC 778 6,037 Semisubmersible 

2008 Valley Forge LLOG MC 707 1,538 Subsea 

2009 Clipper ATP GC 299 3,452 
APPENDICES

69 

Year of 

First 

Production 

Project Name1 Operator Block 

Water 

Depth 

(ft) 2

System Type 

2009 Dorado British Petroleum VK 915 3,236 Subsea 

2009 Geauxpher Mariner GB 462 2,823 

2009 GB 302 Walter GB 302 2,410 Subsea 

2009 Isabela British Petroleum MC 562 6,500 Subsea 

2009 Longhorn Eni MC 502 2,442 Subsea 

2009 MC 72 LLOG MC 72 2,013 

2009 MC 583 Walter MC 583 2,487 

2009 Mirage and Morgus ATP MC 941 4,000 Mini TLP 

2009 Pegasus Eni GC 385 3,498 Subsea 

2009 Tahiti ChevronTexaco GC 640 4,000 Spar 

2009 Thunder Hawk Murphy MC 734 6,050 Semisubmersible 

2009 Thunder Horse North British Petroleum MC 776 5,660 Subsea 

2009 Unreleasable12 

2009 Unreleasable12

2009 Unreleasable12

2010 Caesar and Tonga Anadarko GC 683 4,672 Subsea 

2010 Cascade Petrobras WR 206 8,143 FPSO/Subsea13

2010 Chinook Petrobras WR 469 8,831 FPSO/Subsea13

2010 Droshky Marathon GC 244 2,900 

2010 Great White Shell AC 857 8,000 Spar 

2010 MC 241 Walter MC 241 2,415 

2010 Phoenix5 Helix GC 237 2,679 FPU 

2010 Silvertip Shell AC 815 9,226 Subsea 

2010 Telemark ATP AT 63 4,385 Mini TLP 

2010 Tobago Shell AC 859 9,627 Subsea 

2010 Unreleasable12 

2010 Unreleasable12

2011 Ozona Marathon GB 515 3,000 

2012 Unreleasable12

2012 Unreleasable12

2013 Unreleasable12

2013 Unreleasable12

2013 Unreleasable12

2013 Unreleasable12

2013 Unreleasable12

2013 Unreleasable12

2013 Unreleasable12

2013 Unreleasable12

2013 Puma British Petroleum GC 823 4,129 

2014 Unreleasable12

2016 Unreleasable12
DEEPWATER GULF OF MEXICO 2009: INTERIM REPORT OF 2008 HIGHLIGHTS

70 

1

 Editions of this report prior to 2004 listed deepwater fields rather than projects. A block may be listed under more 

than one project name because of lease relinquishment, expiration, or termination and subsequent re-leasing. Some 

announced discoveries never reached the project stage and are listed under their prospect names. 2

 Water depths are approximate and may vary depending on the location of the production facility or the location of a 

well (average of wells or deepest well site).

3

 Indicates projects that are no longer on production.

4 The semisubmersibles associated with the GC 29 and Cooper projects have been removed.

5 The TLP associated with the Typhoon and Boris projects was destroyed by Hurricane Rita in 2005. Helix is 

scheduled to redevelop the projects with an FPU by early 2010. The new project name is Phoenix.

6 2004 Report referred to entire area as Boomvang. 

7 Includes King South.

8

 Included in 2004 Report with Gunnison.

9

 Na Kika semisubmersible is located in Mississippi Canyon Block 474 in 6,378 ft (1,944 m) of water.

10 Independence Hub FPS is located in Mississippi Canyon Block 920 in 7,920 ft (2,414 m) of water. 

11 The Shenzi project includes the Genghis Khan development. Production commenced from Genghis Khan in October 

2007 and will be transported to the Marco Polo TLP in Green Canyon Block 608 in 4,300 ft (1,311 m) of water. The 

Shenzi portion of the project will feature a TLP in Green Canyon Block 653 in 4,812 ft (1,467 m) of water and is 

scheduled to commence production in mid-2009. 12 Unreleasable—operator has commitment to produce and/or is planning to develop project but has not publicly 

released project information. 13 The Cascade and Chinook Fields will be developed by an FPSO operated by Petrobras. The FPSO will be located in 

Walker Ridge Block 249 in approximately 8,200 ft (2,499 m) of water.
APPENDICES

71 

APPENDIX B. AVERAGE ANNUAL GOM OIL AND GAS PRODUCTION

Year 

ShallowWater Oil 

(MMbbl) 

Deepwater 

Oil 

(MMbbl) 

Total GOM

Oil 

(MMbbl)

ShallowWater Gas 

(Bcf) 

Deepwater 

Gas 

(Bcf) 

Total GOM 

Gas 

(Bcf) 

1947 0 0 0 0 0 0 

1948 0 0 0 0 0 0 

1949 0 0 0 0 0 0 

1950 0 0 0 0 0 0 

1951 0 0 0 2 0 2 

1952 1 0 1 19 0 19 

1953 1 0 1 25 0 25 

1954 2 0 2 60 0 60 

1955 4 0 4 87 0 87 

1956 7 0 7 91 0 91 

1957 12 0 12 93 0 93 

1958 20 0 20 144 0 144 

1959 30 0 30 224 0 224 

1960 41 0 41 281 0 281 

1961 56 0 56 335 0 335 

1962 77 0 77 451 0 451 

1963 96 0 96 561 0 561 

1964 111 0 111 645 0 645 

1965 136 0 136 743 0 743 

1966 175 0 175 992 0 992 

1967 210 0 210 1,285 0 1,285 

1968 254 0 254 1,600 0 1,600 

1969 292 0 292 1,950 0 1,950 

1970 329 0 329 2,402 0 2,402 

1971 376 0 376 2,729 0 2,729 

1972 373 0 373 3,004 0 3,004 

1973 366 0 366 3,312 0 3,312 

1974 338 0 338 3,418 0 3,418 

1975 310 0 310 3,427 0 3,427 

1976 301 0 301 3,556 0 3,556 

1977 284 0 284 3,767 0 3,767 

1978 276 0 276 4,244 0 4,244 

1979 263 1 263 4,668 0 4,669 

1980 260 5 265 4,762 4 4,766 

1981 260 4 263 4,886 3 4,888 

1982 273 13 286 4,650 16 4,666 

1983 294 26 320 4,034 41 4,075 

1984 330 25 355 4,525 39 4,564 

1985 329 21 350 4,024 34 4,058 

1986 336 19 356 4,006 37 4,043 
DEEPWATER GULF OF MEXICO 2009: INTERIM REPORT OF 2008 HIGHLIGHTS

72 

Year 

ShallowWater Oil 

(MMbbl) 

Deepwater 

Oil 

(MMbbl) 

Total GOM

Oil 

(MMbbl)

ShallowWater Gas 

(Bcf) 

Deepwater 

Gas 

(Bcf) 

Total GOM 

Gas 

(Bcf) 

1987 310 17 328 4,481 44 4,525 

1988 288 13 301 4,539 38 4,577 

1989 271 10 281 4,604 32 4,636 

1990 262 12 275 4,876 31 4,906 

1991 272 23 295 4,637 58 4,695 

1992 268 37 305 4,555 87 4,642 

1993 272 37 309 4,536 120 4,656 

1994 272 42 314 4,664 159 4,824 

1995 290 55 345 4,598 181 4,779 

1996 297 72 369 4,799 278 5,077 

1997 303 108 412 4,764 382 5,146 

1998 285 159 444 4,481 560 5,042 

1999 270 225 495 4,211 846 5,057 

2000 252 271 523 3,959 999 4,958 

2001 243 315 559 3,881 1,178 5,059 

2002 219 349 568 3,238 1,285 4,523 

2003 211 350 561 3,000 1,425 4,426 

2004 187 348 535 2,606 1,396 4,003 

2005 141 326 467 1,963 1,189 3,152 

2006 131 339 469 1,823 1,089 2,912 

2007 140 328 467 1,776 1,015 2,791 
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 Minerals Management Service Mission 

As a bureau of the Department of the Interior, the Minerals Management Service's (MMS) 

primary responsibilities are to manage the mineral resources located on the Nation's Outer 

Continental Shelf (OCS), collect revenue from the Federal OCS and onshore Federal and Indian 

lands, and distribute those revenues. 

Moreover, in working to meet its responsibilities, the Offshore Minerals Management Program 

administers the OCS competitive leasing program and oversees the safe and environmentally 

sound exploration and production of our Nation's offshore natural gas, oil and other mineral 

resources. The MMS Minerals Revenue Management meets its responsibilities by ensuring the 

efficient, timely and accurate collection and disbursement of revenue from mineral leasing and 

production due to Indian tribes and allottees, States and the U.S. Treasury. 

The MMS 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 MMS assistance and expertise to economic 

development and environmental protection.