ON COVER—Atlantis semisubmersible production facility in Green Canyon Block 787. This structure is 

currently the deepest moored floating production facility in the world.
OCS Report 

MMS 2008-013 

Deepwater Gulf of Mexico 2008: 

America’s Offshore Energy Future 

Authors 

G. Ed Richardson 

Lesley D. Nixon 

Christy M. Bohannon 

Eric G. Kazanis 

Tara M. Montgomery 

Mike P. Gravois 

Published by 

U.S. Department of the Interior 

Minerals Management Service New Orleans 

Gulf of Mexico OCS Region May 2008 
iii 

TABLE OF CONTENTS

Page 

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

TABLES ......................................................................................................................................ix

ABBREVIATIONS AND ACRONYMS......................................................................................xi

PREFACE ................................................................................................................................ xiii

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

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

Definitions..............................................................................................................................3

Expanding Frontier ...............................................................................................................4

Seismic Activity .....................................................................................................................4

Technological Advances ..............................................................................................7

Lower Tertiary Activity.........................................................................................................8

Ultra-Deepwater Drilling and Discoveries (≥5,000 ft or ≥1,524 m) ....................................9

Hydrates...............................................................................................................................11

Leasing Activity...................................................................................................................12

Challenges and Rewards.....................................................................................................14

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

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

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

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

2007 Lease Sales..................................................................................................................20

2008 Lease Sales..................................................................................................................21

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

Lease Ownership .................................................................................................................23

Future Lease Activity..........................................................................................................24

Royalty and Rental Rate Increases ....................................................................................26

Royalty Relief.......................................................................................................................27

Environmental Issues .........................................................................................................27

Ocean Current Monitoring .......................................................................................27

Deepwater Shipwrecks .............................................................................................28

Grid Programmatic Environmental Assessments...................................................29
DEEPWATER GULF OF MEXICO 2008: AMERICA’S OFFSHORE ENERGY FUTURE

iv 

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

Drilling Activity...................................................................................................................36

High Pressure, High Temperature .....................................................................................42

New Technology...................................................................................................................42

OmniMAX Anchor and Mudrope..............................................................................43

Pre-set Polyester Mooring for Deepwater Drilling Rigs..........................................43

Disconnectable Internal Turret System...................................................................43

Subsea Pumping and Separation .............................................................................44

Development Systems .........................................................................................................44

Fixed Platform...........................................................................................................44

Compliant Tower.......................................................................................................45

Tension-Leg Platform................................................................................................45

Semisubmersible Production Unit ...........................................................................45

Floating Production Unit (FPU) and Floating Production, Storage, and 

Offloading (FPSO) Facility ..........................................................................47

Spar............................................................................................................................48

Subsea Systems.........................................................................................................48

Subsea Trends .....................................................................................................................48

New Developments ..............................................................................................................50

Independence Hub – Anadarko Petroleum Corporation.........................................51

Atlantis – BP America Inc ........................................................................................51

Shenzi – BHP Billiton...............................................................................................51

Thunder Horse – BP America Inc. ...........................................................................51

Perdido – Shell Exploration and Production Company...........................................52

Cascade-Chinook – Petrobras America Inc..............................................................52

New Pipelines ......................................................................................................................53

High-Integrity Pressure Protection System (HIPPS)........................................................56

RESERVES AND PRODUCTION............................................................................................58

Discoveries ...........................................................................................................................58

Production Trends ...............................................................................................................61

Production Rates .................................................................................................................71

HIGHLIGHTS AND CONCLUSIONS .....................................................................................75

Development Cycle ..............................................................................................................76

Drilling the Lease Inventory...............................................................................................77

America’s Offshore Energy Future.....................................................................................78

CONTRIBUTING PERSONNEL..............................................................................................79

REFERENCES ..........................................................................................................................81

APPENDICES ...........................................................................................................................85

Appendix A. Development Systems of Productive Deepwater Projects ........................85

Appendix B. Lease Sale Related Information.................................................................91

Appendix C. Subsea Completions....................................................................................93

Appendix D. Average Annual GOM Oil and Gas Production.......................................101
v 

FIGURES

Page 

Figure 1. Progressive deepwater 3-D seismic permit coverage................................ 5

Figure 2. Deepwater 3-D seismic permit coverage from 1992 to 2006. ................... 6

Figure 3. Pre-stack depth migration coverage from various industry 

sources. ....................................................................................................... 7

Figure 4. Deepwater stratigraphic section. .............................................................. 8

Figure 5. Deepwater Lower Tertiary trend. ............................................................. 9

Figure 6. Deepwater leases issued. ......................................................................... 13

Figure 7. Deepwater discoveries. ............................................................................ 14

Figure 8. Ownership of deepwater discoveries (includes industry-announced 

discoveries). .............................................................................................. 15

Figure 9. Estimated volume of 125 proved deepwater fields. ................................ 15

Figure 10. Current, potential, and future hub facilities. ......................................... 16

Figure 11. Deepwater royalty-relief zones with planning areas and selected 

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

Figure 12. Active leases by water depth. .................................................................. 19

Figure 13. Comparison of planning area changes. ................................................... 21

Figure 14. Number of leases issued each year, subdivided by DWRRA waterdepth categories. ...................................................................................... 22

Figure 15. Number of leases bid on for each deepwater interval. ........................... 23

Figure 16. Ownership of deepwater leases. .............................................................. 24

Figure 17. Anticipated lease expirations from 2009 to 2018.................................... 25

Figure 18. Grid PEA status. ...................................................................................... 30

Figure 19. The Deepwater Horizon, a dynamically positioned, 

semisubmersible drilling unit.................................................................. 33

Figure 20. The Discoverer Enterprise, a double-hulled, dynamically 

positioned drillship. ................................................................................. 34

Figure 21. The Thunder Horse semisubmersible production facility. ..................... 34

Figure 22. Maximum number of rigs operating in the deepwater Gulf of 

Mexico....................................................................................................... 35
DEEPWATER GULF OF MEXICO 2008: AMERICA’S OFFSHORE ENERGY FUTURE

vi 

Figure 23. Approximate number of deepwater rigs (Gulf of Mexico and 

worldwide) subdivided according to their maximum water-depth 

capabilities. (Inset shows the number of deepwater rigs in 

various locations.) .................................................................................... 36

Figure 24. All deepwater wells drilled by water depth. ........................................... 37

Figure 25. Deepwater exploration wells drilled by water depth.............................. 38

Figure 26. Deepwater development wells drilled by water depth. .......................... 38

Figure 27. Deepwater exploration wells drilled by years......................................... 40

Figure 28. Deepwater development wells drilled by years. ..................................... 41

Figure 29. Deepwater EP’s, DOCD’s, and DWOP’s received since 1994. ................ 42

Figure 30. Location map of currently installed deepwater structures by type. ...... 45

Figure 31. Deepwater development systems. ........................................................... 46

Figure 32. Production systems for currently producing fields, including 

subsea systems......................................................................................... 49

Figure 33. Number of shallow- and deepwater subsea completions each year....... 49

Figure 34. Maximum water depth of subsea completions installed each year. ...... 50

Figure 35. Infrastructure schematic of the Cascade and Chinook Field 

development, Phase I............................................................................... 53

Figure 36. Length of subsea tiebacks........................................................................ 54

Figure 37a. Approved deepwater oil and gas pipelines less than or equal to 12 

inches in diameter.................................................................................... 55

Figure 37b. Approved deepwater oil and gas pipelines greater than 12 inches 

in diameter. .............................................................................................. 55

Figure 38. Oil and gas pipelines with diameters greater than or equal to 20 

inches........................................................................................................ 56

Figure 39. Deepwater oil and gas pipelines.............................................................. 57

Figure 40. Proved reserve additions.......................................................................... 59

Figure 41. Proved and unproved reserve additions.................................................. 59

Figure 42. Average field size using proved and unproved reserves......................... 60

Figure 43. Number of deepwater field discoveries and the resulting number 

of producing fields. ................................................................................... 60

Figure 44. Number of deepwater field discoveries and new hydrocarbons 

found (MMS reserves, MMS resources, and industry-announced 

discoveries). .............................................................................................. 62
FIGURES

vii 

Figure 45. Barrels of oil equivalent added (reserves, known resources, and 

industry-announced discoveries)............................................................. 62

Figure 46. Deepwater projects that began production in 2006 and 2007 and 

those expected to begin production by yearend 2013. ............................ 63

Figure 47. Relative volume of production from each Gulf of Mexico lease. 

(Bar heights are proportional to total lease production in barrels 

of oil equivalent during that interval.).................................................... 64

Figure 48a. Estimated U.S. oil production in 2006. ................................................... 66

Figure 48b. Estimated U.S. gas production in 2006................................................... 66

Figure 49a. Comparison of average annual shallow- and deepwater oil 

production................................................................................................. 68

Figure 49b. Comparison of average annual shallow- and deepwater gas 

production................................................................................................. 68

Figure 50a. Contribution of DWRRA oil production to total oil production in 

water depths greater than 200 m (656 ft). .............................................. 69

Figure 50b. Contribution of DWRRA gas production to total gas production in 

water depths greater than 200 m (656 ft). .............................................. 69

Figure 51a. Contributions from subsea completions toward total deepwater oil 

production................................................................................................. 70

Figure 51b. Contributions from subsea completions toward total deepwater 

gas production. ......................................................................................... 70

Figure 52a. Maximum production rates for a single well within each waterdepth category for deepwater oil production........................................... 72

Figure 52b. Maximum production rates for a single well within each waterdepth category for deepwater gas production. ........................................ 72

Figure 53a. Average production rates for shallow-water and deepwater oil 

well completions....................................................................................... 73

Figure 53b. Average production rates for shallow-water and deepwater gas 

well completions....................................................................................... 73

Figure 54a. Maximum historic oil production rates................................................... 74

Figure 54b. Maximum historic gas production rates. ................................................ 74

Figure 55. Lag from leasing to first production for producing deepwater 

fields.......................................................................................................... 77

Figure 56. The challenge of deepwater lease evaluation. ........................................ 78
ix 

TABLES

Page 

Table 1. List of 2007 Deepwater Discoveries .......................................................... 2

Table 2. List of Deepwater Discoveries in Water Depths Greater than 

5,000 ft (1,524 m) ..................................................................................... 10

Table 3. Number of Active Leases by Water-Depth Interval ............................... 20

Table 4. Royalty Relief for Sale 206....................................................................... 27

Table 5. Grid PEA Status within the Central and Western Planning Areas ...... 31

Table 6. Top 20 Producing Blocks for the Years 2005-2006 ................................. 63
xi 

ABBREVIATIONS AND ACRONYMS

2-D two dimensional 

3-D three dimensional 

AC Alaminos Canyon 

AL Alabama 

API American Petroleum Institute 

AT Atwater Valley 

ATB articulated tug barge 

BA Brazos 

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 

BP British Petroleum 

CDWOP Conceptual Deep Water 

Operations Plan 

CGOM Central Gulf of Mexico 

cm centimeters 

CPA Central Planning Area 

CT compliant tower 

CZM coastal zone management 

DC DeSoto Canyon 

DOCD Development Operations 

Coordination Document 

DP dynamically positioned 

DTS disconnectable turret/buoy 

system 

DWOP Deep Water Operations Plan 

DWRR Deep Water Royalty Relief 

DWRRA Deep Water Royalty Relief Act 

EA environmental assessment 

EB East Breaks 

EC East Cameron 

EEZ Exclusive Economic Zone 

EGOM Eastern Gulf of Mexico 

EI Eugene Island 

EIS environmental impact 

statement 

EP Exploration Plan 

EPA Eastern Planning Area 

ESP electric submersible pump 

EW Ewing Bank 

FL Florida 

FPS floating production system 

FPSO floating production, storage, 

and offloading 

FPU floating production unit 

FR Federal Register

FSHR free-standing hybrid risers 

ft feet 

ft3 cubic feet 

GB Garden Banks 

GC Green Canyon 

GOM Gulf of Mexico 

HI High Island 

HIPPS high integrity pressure 

protection system 

HMPE high modulus polyethylene 

HP/HT high pressure/high 

temperature 

in inches 

ITB integrated tug barge 

KC Keathley Canyon 

km kilometers 

km2 square kilometers 

kn knots 

LA Louisiana 

LL Lloyd Ridge 

m meters 

MAZ multi-azimuth 

Mbo/d thousand barrels of oil per day 

MC Mississippi Canyon 

Mcf thousand cubic feet 

mi miles 

mi2 square miles 

MMbbl million barrels 

MMBOE million barrels of oil 

equivalent 

MMcf/d million cubic feet per day 

MMS Minerals Management Service 

MMscf/d million standard cubic feet per 

day 

MOA Memorandum of Agreement 

MODU mobile offshore drilling unit 

MP Main Pass 

mph mile per hour 

MS Mississippi 

MTLP mini-tension-leg platform 
DEEPWATER GULF OF MEXICO 2008: AMERICA’S OFFSHORE ENERGY FUTURE

xii 

MU Mustang Island 

N north 

NDBC National Data Buoy Center 

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 

PDQ production, drilling, and 

quarters 

PEA programmatic environmental 

assessment 

plets pipeline end terminations 

PN North Padre 

PrSDM Pre-stack depth migration 

psi pounds per square inch 

RAZ rich-azimuth 

RP recommended practices 

SE southeast 

SITP shut-in tubing pressure 

SM South Marsh 

SS Ship Shoal 

ST South Timbalier 

TD total depth 

TLP tension-leg platform 

TVD total vertical depth 

TX Texas 

U.S. United States 

U.S.C. United States Codes 

USCG United States Coast Guard 

USDOE United States Department of 

Energy 

USDOI United States Department of 

the Interior 

VK Viosca Knoll 

VR Vermilion 

VLA vertically-loaded anchor 

WATS wide-azimuth towed streamer 

WAZ wide-azimuth 

WC West Cameron 

WD West Delta 

WGOM Western Gulf of Mexico 

WP Well Protector 

WPA Western Planning Area 

WR Walker Ridge 
xiii 

PREFACE

This is the eighth publication that the Minerals Management Service (MMS) has 

released chronicling the levels of deepwater exploration, development, and production 

activities in the Gulf of Mexico (GOM). 

This year saw a record-setting lease offering – Sale 206. This Central Gulf sale 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. About 67 percent of 

the blocks receiving bids were located in deep water [water depths of ≥1,312 ft or ≥400 m; 

this report considers activities in ≥1,000 ft or ≥305 m as deep water] with approximately 34 

percent of the blocks bid upon in ultra-deep water (water depths of ≥5,249 ft or ≥1,600 m; 

this report considers activities in ≥5,000 ft or ≥1,524 m as ultra-deep water). The sum of 

the high bids for deepwater blocks was over 93 percent of the total. The ultra-deepwater 

blocks accounted for about 54 percent of the total high bids. 

Sale 224 transpired on the same day as Sale 206, and it was the first lease offering in the 

Eastern Gulf since 1988. The MMS received 58 bids from 6 companies on 36 blocks, 

resulting in about $65 million in high bids. This is the first sale where the revenue sharing 

provisions of the Gulf of Mexico Energy Security Act of 2006 start immediately. 

The year 2007 was also a banner year for leasing activity. Sale 205 attracted over $2.9 

billion in high bids by 84 companies on 723 tracts – the third largest total in U.S. offshore 

leasing history. Sale 204 garnered approximately $290 million in high bids by 47 

companies on 282 blocks. 

Deep water has continued to be a very important part of the total GOM production, 

providing approximately 72 percent of the oil and 38 percent of the gas in the region. At 

the end of 2007, there were 130 producing projects in the deepwater GOM, up from 122 at 

the end of 2006. In fact, 15 deepwater fields, including Atlantis, Shenzi, and several 

associated with Independence Hub, began production last year. When Independence Hub 

reaches full capacity, it will represent over 10 percent of the total GOM gas production. 

Proved deepwater fields now number 125, representing a 44 percent increase from the end 

of 2006. For the first time in history, all 20 of the highest producing blocks in the GOM 

were in deep water. 

A record high of 15 rigs were operating in ultra-deep water. The MMS approved 15 new 

technologies for use in the deepwater GOM. In fact, the first floating production, storage, 

and offloading (FPSO) system for use in the U.S. GOM will be installed for the development 

of the Cascade and Chinook Fields in Walker Ridge, with first oil expected in 2010. 

The MMS 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 the drilling and production of fields in ever-deepening 

water depths. 

Lars Herbst

Regional Director 

Gulf of Mexico OCS Region

Minerals Management Service
1 

INTRODUCTION

This Deepwater Gulf of Mexico 2008 Report is the latest edition of the biennial 

publication produced by MMS that highlights the activities and offers trend analyses and 

technological advancements in this important portion of the Gulf. All statistics in this 2008 

report are gleaned from data as of the end of December 2007, except production volumes 

and rates, which were compiled through the end of December 2006 (the most recent, 

complete data available at the time of this publication). 

The passage of the Gulf of Mexico Energy Security Act of 2006 opened new areas for 

leasing in the Central Planning Area (CPA) and Eastern Planning Area (EPA). The MMS 

also altered the administrative boundaries for all three planning areas in the GOM. These 

new boundaries went into effect on July 1, 2007, concurrently with the new Outer 

Continental Shelf Oil and Gas Leasing Program: 2007-2012 (5-Year Program), which 

establishes the offshore lease sales for the Nation. 

Exploratory drilling in 2007 continued to be strong in the deepwater GOM, resulting in 

94 wells. Recent exploration efforts resulted in the announcement of eight new deepwater 

discoveries (Table 1). Three of these discoveries were drilled in ultra-deep water – water 

depths greater than 5,000 ft (1,524 m). Development activities resulted in drilling 48 new 

wells – a 41 percent increase over 2006. Twenty-two of these wells were drilled in water 

depths of 7,500 ft (2,286 m) or greater, representing 46 percent of all development wells 

drilled in 2007. 

Significant milestones have also occurred in deepwater development activity. In 2007, 

15 deepwater fields began production, many of which are associated with Independence 

Hub. Also, MMS approved 15 new technology applications. These technology 

advancements include a subsea separation and boosting system, a gravity-installed anchor 

with mudrope forerunners, and a disconnectable, internal turret system (for use with 

floating production systems). The MMS and the oil and gas industry have continued to 

work together to revise and improve many of the API documents that serve as 

recommended practices to guide operational activities. 

This report is divided into five sections. 

The Background section 

• new seismic technologies, 

• Lower Tertiary activities, 

• ultra-deepwater drilling and discoveries, and 

• hydrates. 

The Leasing and Environment section 

• 5-Year Oil and Gas Program, 

• leasing activities and trends, 

• future leasing activities, including anticipated lease expirations, and 

• regulatory and environmental issues. 
DEEPWATER GULF OF MEXICO 2008: AMERICA’S OFFSHORE ENERGY FUTURE

2 

The Drilling and Development section 

• deepwater drilling activities, 

• information on operational plans, 

• approval of new technologies, 

• deepwater development systems, 

• new deepwater developments, and 

• pipelines and high-integrity pressure protection systems. 

The Reserves and Production section 

• historical deepwater reserve additions, 

• large future reserve additions associated with recently-announced 

discoveries, 

• production trends and rates, 

• comparison of shallow-water and deepwater production, and 

• high deepwater production rates. 

The Highlights and Conclusions section 

• highlights activities that occurred in 2007, 

• drilling to production lag times, and 

• difficulties in evaluating deepwater leases before their lease terms 

expire. 

Table 1 provides a listing of the 2007 announced deepwater discoveries in the GOM. 

Table 1. List of 2007 Deepwater Discoveries 

Project Name Area/Block Water Depth (ft) Operator 

Danny1 GB 506 2,821 Energy Resource Technology 

Droshky (Troika Deep) GC 244 2,920 Marathon 

Isabela MC 562 6,535 BP 

Julia WR 627 7,087 ExxonMobil 

Magellan EB 424 2,767 Mariner Energy 

Noonan1 GB 506 2,715 Energy Resource Technology 

Vicksburg DC 353 7,457 Shell 

West Tonga GC 726 4,674 Anadarko 

DC = DeSoto Canyon EB = East Breaks 

GB = Garden Banks GC = Green Canyon 

MC = Mississippi Canyon WR = Walker Ridge 1

Separate announced discoveries in the same block. 
3 

BACKGROUND

DEFINITIONS

A variety of criteria can be used to define deep water. The threshold separating shallow 

water and deep water can range from 656- to 1,500-ft (200- to 457-m) in water depth. For 

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

1,000 ft (305 m). Similarly, ultra-deep water is difficult to define precisely. For purposes of 

this report, 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 in this report are expressed in meters to be 

consistent with regulatory requirements. All other data in this report 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 all grouped on, or related to, the same general geologic structural 

feature and/or stratigraphic trapping condition. There may be two or more 

reservoirs in a field that are separated vertically by intervening impervious 

strata or laterally by local geologic barriers, or by both. 

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

Gulf of Mexico Outer Continental Shelf, December 31, 2003 report (Crawford et al., 2006). 

This report refers to deepwater developments both as fields (as defined above) and by 

operator-designated 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 

natural gas and oil 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 as capable of 

production or the block where the primary structure is located. Therefore, more than one 
DEEPWATER GULF OF MEXICO 2008: AMERICA’S OFFSHORE ENERGY FUTURE

4 

operator-designated project may be included in a single MMS-designated field. 

Appendix A provides locations and additional information for these fields and projects.

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

“gas” includes both associated and non-associated gas. 

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). 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 2007, there were 130 producing projects in the deepwater GOM, up from 122 at 

the end of 2006 (Peterson et al., 2007). 

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. Deepwater exploration and production grew with tremendous 

advances in technology since those early days. This report focuses on changes during the 

last 16 years, 1992-2007. 

Over these last 16 years, leasing, drilling, and production moved steadily into deeper 

waters. There are approximately 7,443 active leases in the GOM Outer Continental Shelf 

(OCS), 54 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 30 rigs drilling in deep water in 2007, compared with only 3 rigs in 1992. 

Likewise, deepwater oil production rose about 820 percent and deepwater gas production 

increased about 1,155 percent from 1992 to 2006. 

SEISMIC ACTIVITY

A combination of factors, including the DWRRA, key deepwater discoveries, the 

recognition of high deepwater production rates, and the evolution of deepwater 

development technologies, spurred a variety of deepwater activities. One of the first 

impacts was a dramatic increase in the acquisition of 3-dimensional (3-D) seismic data 

(Figure 1). (Note that Figures 1 and 2 illustrate areas permitted for seismic acquisition. 

The actual coverage available may be slightly different than that permitted.) Threedimensional seismic data are huge volumes of digital energy recordings resulting from the 

transmission and reflection of sound waves through the earth. These large “data cubes” can 

be interpreted to reveal likely oil and gas accumulations. The dense volume of recent, highquality data may reduce the inherent risks of traditional hydrocarbon exploration and allow 

imaging of previously hidden prospects. Figure 2 illustrates the surge of seismic activity 

in the deepwater GOM during the last 16 years. Seismic acquisition has stepped into 

progressively deeper waters since 1992. Figure 2 shows the abundance of 3-D data now 

available. These data blanket most of the deepwater GOM, even beyond the Sigsbee 

Escarpment (a geologic and bathymetric feature in ultra-deep water). Note that many 
BACKGROUND

5 

active deepwater leases were purchased before these 3-D surveys were completed [only the 

more sparsely populated two-dimensional (2-D) datasets were available]. 



	



  

 







	



  

 







	



 	 

 







	



 	 

 







	



 
 

 







	



  

 







	



  

 







	



  

 








   

Figure 1. Progressive deepwater 3-D seismic permit coverage. 
DEEPWATER GULF OF MEXICO 2008: AMERICA’S OFFSHORE ENERGY FUTURE

6 



	















   

   




Figure 2. Deepwater 3-D seismic permit coverage from 1992 to 2006. 

The seismic permitting coverage shown in Figure 2 does not tell the whole story of 

geophysical activity in the deepwater GOM. Numerous deepwater exploration targets lie 

beneath an extensive salt canopy, more than 15,000 ft (4,572 m) thick in some places. Salt 

has a very high velocity when compared with the surrounding rocks, and a correction for 

this high velocity zone must be made to best image the sediments below the salt. 

Additionally, the imaging problems are compounded the thicker and more irregular the salt 

bodies are. As industry explored farther and farther out into deep water, one of the major 

technological hurdles has been obtaining quality, subsalt seismic images for adequate 

interpretation. 

Pre-stack depth migration (PrSDM) of seismic data has greatly enhanced the 

interpretation capabilities in the deepwater GOM, particularly for the areas hidden below 

salt canopies. While PrSDM was once used sparingly, the availability of large speculative 

PrSDM surveys allows the widespread use of this technology in the early phases of 

exploration. Subsalt discoveries like Mad Dog, Thunder Horse, North Thunder Horse, 

Atlantis, Tahiti, and Shenzi demonstrate the importance of subsalt exploration in the 

deepwater GOM. Figure 3 provides a good indication of the widespread coverage of 

PrSDM processing through the end of 2006. However, even with the advantages of PrSDM 

data, interpretation challenges, such as poor signal-to-noise ratio of the subsalt events and 

incomplete reservoir illumination, remained. These problems have been addressed mainly 

by such things as improved depth-migration algorithms, better noise attenuation, and 

better velocity models. However, it became apparent that another approach was needed to 

produce seismic images of reservoir-development quality. 
BACKGROUND

7 



		


				




	

(% % (% 	

(% % (% 

Figure 3. Pre-stack depth migration coverage from various industry sources. 

Technological Advances 

It has long been recognized that acquiring seismic data with a range of source-receiver 

azimuths illuminates the subsurface better than acquiring the same data using standard 

narrow-azimuth techniques (e.g., O’Connell et al., 1993). However, the technology required 

to make complex-azimuth acquisitions commercially viable only emerged in recent years. 

Three variations of towed-streamer geometries for acquiring complex-azimuth data are (1) 

multi-azimuth (MAZ), (2) wide-azimuth (WAZ), and (3) rich-azimuth (RAZ). 

In a MAZ survey, a single multi-streamer recording vessel acquires data in multiple 

directions (Hegna and Gaus, 2003). Two to six 3-D surveys are recorded over the same area 

at different azimuths to each other. The individual surveys are processed separately, and 

then combined, resulting in the same subsurface spot being illuminated by many different 

azimuths. In a WAZ (a.k.a. WATS, for wide-azimuth towed streamer) survey, a single 

multi-streamer recording vessel and at least two source vessels shoot each source line 

multiple times in a single direction with increasing lateral offset with each sailing pass. 

Multiple source vessels make it possible to collect data from many different azimuths 

(Sukup, 2002). The RAZ geometry combines aspects of both the MAZ and WAZ methods, 

where multiple source lines are acquired in multiple directions. By combining the MAZ and 

WAZ techniques, any number of vessels in various configurations (WAZ) can be sailed in 

any number of directions (MAZ) (Howard, 2004). 

British Petroleum, with seismic contractor Veritas, conducted the first WAZ survey in 

the GOM at the end of 2004 and beginning of 2005 at Mad Dog (Green Canyon 826 Field). 

At the beginning of 2006, Shell, with seismic contractor WesternGeco, acquired a WAZ 

survey over the Friesian prospect, a 2006 discovery in Green Canyon Block 599. Also 

contracting with WesternGeco, BHP Billiton acquired a RAZ survey during the spring and 

summer of 2006 at Shenzi (Green Canyon 654 Field). Additionally, WesternGeco began the 
DEEPWATER GULF OF MEXICO 2008: AMERICA’S OFFSHORE ENERGY FUTURE

8 

first multi-client WAZ acquisition (E-Octopus project) in July 2006 in Garden Banks, Green 

Canyon, Keathley Canyon, and Walker Ridge. Since then, over 700 blocks have been 

acquired in two phases. A third phase of acquisition began in May 2007, which covers 450 

blocks in Green Canyon. 

With minimal processing, no multiple attenuation, and shot-domain wave equation 

migration using existing velocity models, initial results from the proprietary Friesian and 

Shenzi surveys and from the multi-client E-Octopus Phases I and II surveys show that all 

four survey designs lead to improved subsalt imaging when compared with conventional 

narrow-azimuth surveys with full processing including multiple attenuation (Kapoor et al., 

2007). In general, complex-azimuth surveys improve signal-to-noise ratio and illumination 

in complex subsalt geology and provide natural attenuation of some multiples. Therefore, 

areas of the deepwater GOM where an extensive and thick salt canopy covers potential 

hydrocarbon targets, obscuring their seismic signature, are ideal areas for large-scale, 

complex-azimuth surveys for exploration purposes. In fact, other vendors, including 

CGGVeritas, Petroleum Geo-Services, and TGS, have acquired or are currently acquiring 

several multi-client WAZ surveys in the deepwater GOM. 

LOWER TERTIARY ACTIVITY

Figure 4 indicates that about 99 percent of total GOM proved reserves are in Miocene 

and younger reservoirs; however, recent exploration activities in deep water have 

discovered large reservoirs in sands of Lower Tertiary age (Oligocene, Eocene, and 

Paleocene). Figure 5 shows these discoveries within the bounds of the approximate Lower 

Tertiary trend. The trend has an estimated discovery volume of 2.8 billion barrels of 

producible hydrocarbons, which represents about a 15 percent addition to total GOM oil 

and gas volumes. It is noteworthy that this discovery volume has more than doubled since 

the 2007 Deepwater Report (Peterson et al., 2007). 

However, unique technical challenges have required tremendous industry investment to 

ensure that this frontier play becomes an economically viable trend. Challenges have 

included complex subsalt imaging issues, drilling rig limitations, high pressure/high 

temperature (HP/HT) conditions, and reservoir porosity and permeability anisotropy. 

However, technological advances including WATS data, improved HP/HT environment 

equipment, and next generation semisubmersible drilling vessels, combined with promising 

results from the Jack #2 well test, have facilitated exploration and indicate that Lower 

Tertiary reservoirs have the potential to support commercial production. 

Quaternary Pleistocene 

Pliocene

Miocene

Oligocene

Eocene

Paleocene

Upper

Lower

Upper

164.40 Middle

Time 

(mya) System Subsystem Series Total Proved 

Reserves

Discovered BOE 

All Water Depths

Discovered BOE 

Water Depths >1,000 ft General Deepwater Characteristics

1.77 98.9% 

(52.3 BBOE)

94.2% 

(58.5 BBOE)

84.9% 

(15.6 BBOE)

Large subsalt discoveries in deepwater are associated 

with fold belts and turtle structures.

Tertiary

Upper

23.80

Lower 0.4% 

(0.2 BBOE)

4.5% 

(2.8 BBOE)

15.1% 

(2.8 BBOE)

Over a dozen announced Lower Tertiary 

(Eocene/Paleocene) discoveries this decade in 

deepwater opened a large play area for exploration. 65.00

There is untested, Mesozoic potential on the abyssal 

plain and in eastern Mississippi Canyon. 144.20

Jurassic

Cretaceous

0.7% 

(0.4 BBOE)

1.3% 

(0.8 BBOE) ⎯⎯

Figure 4. Deepwater stratigraphic section. 
BACKGROUND

9 









 

 

 	














	





	





	




 





 


  

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Figure 5. Deepwater Lower Tertiary trend. 

Issues of water depth and proximity to current development infrastructure are being 

overcome through the planned use of the Gulf’s first FPSO system at the Chinook-Cascade 

development in Walker Ridge. Additionally, an expanded pipeline network will tie into the 

Perdido Regional Development hub, which will produce the Great White, Tobago, and 

Silvertip Fields in Alaminos Canyon. Production from both projects is currently planned to 

begin around the end of the decade. 

While attempts to forecast future Lower Tertiary production are complicated by many 

variables, it is clear that technical advances and exploratory successes will continue to 

drive industry interest in the emerging Lower Tertiary trend. 

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

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

5,000 ft (1,524 m) or more in the GOM. At least 13 new drilling rigs are 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 to total depths up to 40,000 ft (12,192 m). Also, all 13 of these new drilling rigs are 

being built with dynamic positioning systems and will not have to be moored to the seafloor. 

Additionally, several drilling contractors have committed to building new ultra-deepwater 

drilling rigs that have not yet been contracted, and some of these new rigs are expected to 

operate in the GOM. 

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 60 additional discoveries in the 

ultra-deep provinces of the Gulf (Table 2). The production from 13 of these discoveries is 

associated with the Independence Hub natural gas processing facility. Another 14 of the 

discoveries are associated with the Lower Tertiary trend. 
DEEPWATER GULF OF MEXICO 2008: AMERICA’S OFFSHORE ENERGY FUTURE

10 

Table 2. List of Deepwater Discoveries in Water Depths Greater than 5,000 ft (1,524 m)

Discovery Area/Block Water Depth (ft)3

 Discovery Year 

Constitution GC 680 5,001 2001 

GC 767 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 

N. Thunder Horse MC 776 5,662 2000 

Thunder Bird MC 819 5,672 2006 

Thunder Hawk MC 734 5,714 2004 

Kaskida2 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 

Thunder Horse MC 778 6,082 1999 

Thunder Ridge MC 737 6,108 2006 

Ariel MC 429 6,134 1995 

Neptune (AT) AT 575 6,203 1995 

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 

Herschel MC 520 6,739 1989 

Fourier MC 522 6,895 1989 

Blind Faith MC 696 6,952 2001 

Jack2 WR 759 6,962 2004 

St. Malo2 WR 678 6,996 2003 

Aconcagua MC 305 7,051 1999 

Mission Deep GC 955 7,068 2006 

Julia2 WR 627 7,087 2007 

Camden Hills MC 348 7,206 1999 

Vicksburg DC 353 7,457 2007 

Shiloh DC 269 7,509 2003 

Coulomb MC 657 7,558 1987 
BACKGROUND

11 

Table 2. List of Deepwater Discoveries in Water Depths Greater than 5,000 ft (1,524 m)

Discovery Area/Block Water Depth (ft)3

 Discovery Year 

BAHA2 AC 600 7,620 1996 

Gotcha2 AC 856 7,714 2006 

Callisto MC 876 7,790 2001 

San Jacinto1 DC 618 7,805 2004 

Great White2 AC 857 8,119 2002 

Q1 MC 961 7,926 2005 

Merganser1 AT 37 7,939 2001 

Spiderman/Amazon1 DC 620 8,055 2004 

Spiderman/Amazon1 DC 621 8,087 2003 

Cascade2 WR 206 8,152 2002 

Vortex1 AT 261 8,344 2002 

Mondo NW Extension1 LL 1 8,351 2005 

Mondo Northwest1 LL 2 8,362 2004 

Jubilee Extension1 LL 309 8,774 2005 

Jubilee1 AT 349 8,778 2003 

Atlas NW1 LL 5 8,807 2004 

Chinook2 WR 469 8,831 2003 

Atlas1 LL 50 8,944 2003 

Cheyenne1 LL 399 8,983 2004 

Tiger2 AC 818 9,004 2004 

Silvertip2 AC 815 9,226 2004 

Tobago2 AC 859 9,627 2004 

Stones2 WR 508 9,571 2005 

Trident2 AC 903 9,721 2001 

AC = Alaminos Canyon 

GB = Garden Banks 

LL = Lloyd Ridge 

AT = Atwater Valley 

GC = Green Canyon 

MC = Mississippi Canyon 

DC = DeSoto Canyon 

KC = Keathley Canyon 

WR = Walker Ridge 1

Projects associated with the Independence Hub natural gas processing facility. 

2

Projects associated with the Lower Tertiary trend. 

3

Average water depth of all wells drilled. 

HYDRATES

In addition to the traditional oil and gas plays in the deepwater GOM, there may be 

significant resources in gas hydrate-bearing sands. The in-place hydrate resource may be 

30 to 300 times greater than conventional oil and gas reserves. A gas hydrate is a cage-like 

lattice of ice that traps molecules of natural gas, primarily methane. Hydrates are formed 

at and just below the seafloor under conditions of low temperature, high pressure, and in 

the presence of natural gas. In the GOM, hydrates occur in water depths greater than 

1,450 ft (442 m). Each cubic foot of hydrate yields 165 ft3 (4.7 m3) of gas at standard 

temperature and pressure. 
DEEPWATER GULF OF MEXICO 2008: AMERICA’S OFFSHORE ENERGY FUTURE

12 

Piston cores have sampled about 100 sites that contain both thermogenic and biogenic 

gas hydrates. Thermogenic gas hydrates are known only in the GOM, whereas biogenic gas 

hydrates are found in many other marine settings around the world. The gas contained in 

thermogenic gas hydrates is derived from deeply buried, organic-rich sediments, or existing 

gas reservoirs, and has migrated upward into the zone of hydrate stability. Thermogenic 

hydrates contain a mixture of complex hydrocarbon gases. Biogenic gas hydrates contain 

gas generated at shallower depths by bacterial decomposition of organic matter, yielding 

primarily methane gas. Gas-hydrate mounds and associated chemosynthetic communities, 

commonly at the edges of deepwater mini-basins, have been observed and sampled by 

research submersibles funded by the MMS at 32 sites in the GOM. 

Many questions remain about the distribution, concentration, reservoir properties, and 

stability of hydrates. Conventional drilling operations do not allow sampling of the upper 

3,000 ft (914 m) of sediment (where hydrates occur). Although conventional 3-D exploration 

and high-resolution seismic data are not specifically designed to detect hydrate deposits, 

interpretive techniques have been used to delineate possible hydrates. 

To gather hydrate data for the GOM, a Joint Industry Project of MMS and seven oil and 

service companies, largely funded by the U.S. Department of Energy (USDOE), conducted a 

35-day expedition in the spring of 2005 to drill, log, and core sediments containing gas 

hydrates. Five separate boreholes were drilled near seafloor hydrate mounds in Atwater 

Valley and Keathley Canyon to depths as great as 1,509 ft (460 m) below mudline. Two 

holes were cored on top of a hydrate mound in Atwater Valley to a depth of 98 ft (30 m) 

below mudline. Downhole log data and pressure cores revealed evidence of gas hydrates in 

all boreholes at levels approximating those predicted by pre-cruise seismic analysis. 

Sediment at both locations was fine grained with stratigraphically controlled hydratebearing intervals in Atwater Valley and steeply dipping, hydrate-filled fractures in 

Keathley Canyon. Because technically recoverable quantities of gas hydrate are probably 

limited to permeable sand reservoirs, a second hydrate drilling initiative with a multi-well 

program at sites in Green Canyon, Walker Ridge, and Alaminos Canyon is planned for 

2008. 

The MMS has played a major role on the site-selection team by using information from 

the in-house sand studies done for the Gas Hydrate Assessment. This MMS assessment is 

the first comprehensive evaluation of gas hydrates on the OCS since a 1995 assessment 

published by the U.S. Geological Survey (USGS) (Collett, 1995). Ultimately, the final 

results of the MMS assessment will provide estimates of the undiscovered in-place, 

technically recoverable, and economically recoverable gas hydrate resources for each OCS 

region (GOM, Atlantic, Pacific, and Alaska). As of February 2008, the preliminary in-place 

results for the GOM have been prepared (USDOI, MMS, 2008). Both MMS and USGS 

studies can be accessed at http://www.mms.gov/revaldiv/GasHydrateAssessment.htm.

LEASING ACTIVITY

The DWRRA encouraged extensive leasing in the deepwater GOM. Figure 6 shows the 

history of deepwater leasing since 1992. Activity slowly increased from 1992 through 1995, 

but immediately after the DWRRA was enacted, deepwater leasing activity exploded. 

Other factors also contributed to this activity, including improved 3-D seismic data 

coverage, key deepwater discoveries, the recognition of high deepwater production rates, 

and the evolution of deepwater development technologies. 
BACKGROUND

13 



		


				 


	











		


				 


	











		


				 


	











		


				 


	















		


				 


	







		


				 


	











		


				 


	











		


				 


	









 

	









	


  

  	

Figure 6. Deepwater leases issued. 

With the passage of the Energy Policy Act of 2005, lease terms for deepwater royalty 

relief were changed. The Act eliminated the existing 1,600-m (5,249-ft) or deeper waterdepth category for royalty relief and established two new royalty suspension categories: 

1,600- to 2,000-m (5,249- to 6,562-ft) and greater than 2,000-m (6,562-ft) water depth. Sale 

196 [Western Planning Area (WPA), August 17, 2005] was the first lease offering to 

implement these “new” royalty-relief provisions. 
DEEPWATER GULF OF MEXICO 2008: AMERICA’S OFFSHORE ENERGY FUTURE

14 

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 the initial exploration and first production. Despite these challenges, deepwater 

operators often reap great rewards. Figure 7 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. 





















       

     



    

                        

        

   

  

  







 

    

     





            

     







 

























 	
















	



	













Figure 7. Deepwater discoveries. 

Figure 8 shows how major and nonmajor oil and gas companies compare in terms of 

deepwater discoveries. In this report, we define major companies to include BP, 

ChevronTexaco, ExxonMobil, and Shell. The grouping of these four entities does not 

indicate a regulatory conclusion or an analysis of production size. It is merely a convenient 

category for the purpose of comparison. In the past, major companies were responsible for 

the majority of discoveries and led the way into the deepest waters. However, the number 

of discoveries by nonmajor companies has surpassed that by major companies. In addition, 

nonmajor companies have made numerous recent discoveries in the deepest waters of the 

frontier. Indeed, nonmajors announced five of the eight deepwater discoveries in 2007. 

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 9 illustrates 

the estimated sizes and locations of 125 proved deepwater fields. This represents a 44 

percent increase in the number of fields from the 2006 Deepwater Report (French et al., 

2006). In addition to their large sizes, deepwater fields have a wide geographic distribution 

and range in geologic age from Pleistocene through Paleocene. 

Figure 10 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 
BACKGROUND

15 

subsea production surfaces and 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. 





 





















 

  

 

 



   



 

      

 



 







  

      

 





        

       

















 













 	






	

	 
	

	

	





Figure 8. Ownership of deepwater discoveries (includes industry-announced discoveries). 

















 





















 		 





















	


   

   














Figure 9. Estimated volume of 125 proved deepwater fields. 
DEEPWATER GULF OF MEXICO 2008: AMERICA’S OFFSHORE ENERGY FUTURE

16 

 	

	 
 	
	












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Figure 10. 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 is prepared that formalizes the alternatives that were 

selected from the final EIS. 

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; Notice of Intent to Prepare an EIS 

• Area Identification 
DEEPWATER GULF OF MEXICO 2008: AMERICA’S OFFSHORE ENERGY FUTURE

18 

• Draft EIS 

• 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 two 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 website at www.mms.gov/ld/

PDFs/GreenBook-LeasingDocument.pdf. 

The MMS has begun its proposed OCS Oil and Gas Leasing Program for 2007-2012. The 

5-Year Program proposes 11 oil and gas lease sales in the GOM—5 sales in the WPA and 6 

sales in the CPA. More information on the 5-Year Program may be gleaned from the 

following MMS’s website at http://www.mms.gov/5-year/WhatIs5YearProgram.htm. 

The GOM Outer Continental Shelf is divided into the three sectors—the Western, 

Central, and Eastern Planning Areas (Figure 11). This figure displays the reconfigured 

administrative planning area boundaries designated by MMS (Federal Register, 2006). 

Sale 204, held on August 22, 2007, was the first offering in the current 5-Year Program that 

utilized these new boundaries. Note that data in this report prior to July 1, 2007, use the 

old planning area delineations. 

WATER-DEPTH INTERVALS

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 illustrated in Figure 11, along with 

the deepwater royalty-relief zones (400, 800, 1,600, and 2,000 m) mandated by the Energy 

Policy Act of 2005. Royalty-relief volumes were changed with the passage of this Act. 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 12 depicts all active leases in the GOM at the end of calendar year 2007. 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 54 percent 

of the leased blocks are located in water depths greater than 1,000 ft (305 m). The limited 
LEASING AND E NVIRONMENT

19 

number of active leases in the EPA is related to leasing restrictions. The approximate 

number of active leases for certain water-depth ranges is shown in Table 3. 

	

	







 	








	

	

	









		












 









 




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Figure 11. Deepwater royalty-relief zones with planning areas and selected bathymetry. 



	



	




	

 




	


	









	





 			


		

	


	



	





 			


		

	




	
	
	 	
	 
	
	

	
 


	
	
 

	
	
 

	
	
 


	
 

Figure 12. Active leases by water depth. 
DEEPWATER GULF OF MEXICO 2008: AMERICA’S OFFSHORE ENERGY FUTURE

20 

Table 3. Number of Active Leases by Water-Depth Interval 

Number of Water Depth 

Active Leases ft m 

3,409 <1,000 <305 

164 1,000-1,499 305-457 

1,912 1,500-4,999 457-1,524 

1,319 5,000-7,499 1,524-2,286 

639 >7,500 >2,286 

Data compiled as of 12/31/2007. 

2007 LEASE SALES

In 2007, two lease sales were held—Sale 204 (WPA, on August 22) and Sale 205 (CPA, 

on October 3). These were the first sales held under the revised planning area boundaries 

of the GOM. Together the two 2007 sales amassed approximately $3.2 billion in high bids 

and about $5.6 billion for all bids received, resulting in the issuance of 956 leases. 

Sale 204 garnered approximately $290 million in high bids on 282 blocks and about $370 

million for all 358 bids received for the sale. Slightly over 64 percent of the bids were for 

blocks in water depths of 800 m (2,625 ft) or greater. This interval also constituted over 85 

percent of the high bids for this sale. The water-depth interval of 800 m to less than 1,600 

m (2,625 ft to less than 5,249 ft) amassed the most number of high bids (108) in the sale. 

Over 52 percent of the high bids were for blocks in water depths of 1,600 m (5,249 ft) or 

more. The MMS considers this interval as ultra-deep water. Sale 204 ultimately resulted 

in the award of 274 leases. Eight high bids were rejected by MMS. The accepted high bids 

for the sale totaled about $287 million. 

Sale 205 was an exceptional lease offering that attracted over $2.9 billion in high bids on 

723 blocks – the third largest total in U.S. leasing history. Only Sale 72 (held in 1983, with 

approximately $3.5 billion in high bids) and Sale 206 (held in 2008, with approximately 

$3.7 billion in high bids) exceeded the level of interest for Sale 205. The sum of all 1,428 

bids for Sale 205 was approximately $5.25 billion. 

About 66 percent of the high bids in Sale 205 were for blocks in water depths of 800 m 

(2,625 ft) or greater. Over 89 percent of the high bid sum for this sale was offered for blocks 

in this water depth range. Approximately 40 percent of the high bids in this sale were in 

ultra-deep water. Clearly, deep water played a major part in this sale. Ultimately, the bids 

on 682 blocks were deemed acceptable by MMS. The bids on 18 blocks were rejected and 

bids on 23 blocks were forfeited by the high bidders. The accepted high bids for the sale 

totaled approximately $2.8 billion. 

The success of Sale 205 was influenced by the reconfiguration of the planning areas 

(Figure 13). Acreage lost in the WPA and EPA was incorporated into the CPA. For leases 

in deep water, 37 percent are attributed to these gained areas. High bids on these leases 

totaled $974.2 million. 
LEASING AND E NVIRONMENT

21 

Figure 13. Comparison of planning area changes. 

2008 LEASE SALES

This year saw a record-setting lease sale. Sale 206, a CPA offering, was held on 

March 19. This sale 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. The sum of all bids for this sale was approximately $5.7 billion. About 67 

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

with approximately 34 percent of the tracts bid upon in ultra-deep water – more than 5,249 

ft (1,600 m).1 The sum of the high bids for deepwater tracts was 93.2 percent of the total. 

The ultra-deepwater high bids accounted for 54.1 percent of the total high bids. 

The EPA Sale 224 was held on the same day as Sale 206. The MMS received 58 bids 

from 6 companies on 36 blocks resulting in about $64.7 million in high bids. The sum of all 

bids received was approximately $72.1 million. All of the blocks receiving bids are located 

in water depths of greater than 2,625 ft (800 m). An estimated 37.5 percent of the high bid 

amount from the sale will go directly to four Gulf producing States. Sale 224 was the first 

sale where sharing provisions of the Gulf of Mexico Energy Security Act of 2006 will start 

immediately. 

 

1 The definitions of deep water and ultra-deep water used here are based on the DWRRA established 

royalty suspension intervals. 
DEEPWATER GULF OF MEXICO 2008: AMERICA’S OFFSHORE ENERGY FUTURE

22 

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 14 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 the water depths of greater than 800 m (2,625 ft), where the greatest royalty 

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

diminished. The number of leases issued in the greater than 800-m water depth interval 

slightly increased from 1999 to 2003, then leveled off until 2005. However, from 2006 to 

2007, a 66 percent increase occurred in the number of leases issued in this water-depth 

range. 

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

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

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

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

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

DWRRA post-DWRRA

Figure 14. Number of leases issued each year, subdivided by DWRRA water-depth categories. 

Figure 15 was derived from the data in Figure 14, but displays the deepwater depth 

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

Figure 15.) 
LEASING AND E NVIRONMENT

23 

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

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

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

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

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

DWRRA post-DWRRA

Figure 15. Number of leases bid on for each deepwater interval. 

These deepwater 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 Mad Dog and Thunder Horse. 

Beginning in 1999, the 1,500-4,999 ft (457-1,524 m) and 5,000-7,499 ft (1,524-2,286 m) 

intervals generally parallel each other, with the 1,500-4,999 ft (457-1524 m) outpacing the 

deeper water range. Through 2003, the ranges steadily increased, then leveled off in 2004 

and 2005, and from 2006 to the present, both intervals steadily increased. An astronomical 

jump occurred from 2006 to 2007 in the greater than 7,500-ft (2,286-m) depth category – 

from 6 to 152 for the number of blocks bid on. 

LEASE OWNERSHIP

Major oil and gas companies (BP, ChevronTexaco, ExxonMobil, and Shell ) blazed the 

trail into deep water in the 1980’s and early 1990’s. Figure 16 illustrates the relative 

leaseholding positions of majors versus nonmajors (as of December 31, 2007). Nonmajors 

began acquiring significant leaseholdings in the mid-1990’s, a trend that continued through 

2007. In fact, the pie chart in Figure 16 shows that nonmajors now hold over 66 percent of 

all of the deepwater leases. 
DEEPWATER GULF OF MEXICO 2008: AMERICA’S OFFSHORE ENERGY FUTURE

24 

	



	



	





	


	

















		 



 !

"#





		 



 !



	
	
	 	
	 
	
	

	
 


	

Figure 16. Ownership of deepwater leases. 

FUTURE LEASE ACTIVITY

The number of leases that will be relinquished, terminated, or expire 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. 

The deepwater arena in the GOM experienced phenomenal leasing activities from 1996 

through 1998. This is especially noticeable in the greater than 800-m (2,625-ft) water depth 

range. During this time, this interval constituted about 47 percent (1996) and 62 percent 

(1997) of the total number of leases awarded from each year’s lease sales. In the 2006 and 

2007 sales, about 40 percent of the total number of leases issued in water depths greater 

than 800 m (2,625 ft) was leases that were expired, terminated, or relinquished from the 

1996 and 1997 sales. 

Figure 17 shows leases that may expire from 2009 to 2018 in two-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 the following water depth intervals are: 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. Appendix B provides a chronological listing of all GOM lease 

offerings arranged by sale number, location, and date. 
LEASING AND E NVIRONMENT

25 





 	


















 	


















 	


























Figure 17. Anticipated lease expirations from 2009 to 2018. 
DEEPWATER GULF OF MEXICO 2008: AMERICA’S OFFSHORE ENERGY FUTURE

26 





 	


















 	


















	



Figure 17. Anticipated lease expirations from 2009 to 2018 (continued). 

ROYALTY AND RENTAL RATE INCREASES

On January 9, 2007, the Secretary of the Department of the Interior, Dirk Kempthorne, 

announced an increase in the royalty rate for new offshore deepwater Federal oil and gas 

leases (Kempthorne, 2007). The royalty rate was increased to 16.7 percent from the 

previous rate of 12.5 percent. This rate change took effect with the first GOM lease sale in 

2007 – Sale 204 in the WPA. 

On February 13, 2008, the Final Notices of Sale (73 FR 30) for Lease Sales 206 and 224, 

which were held consecutively on March 19, 2008, in the CPA and the EPA, respectively, 

included an increase in the royalty rate for deepwater leases to 18.75 percent from the 16.7 

percent rate. The Notices also included changes to rental rates of $6.25 per acre for blocks 

in water depths of less than 200 m (656 ft) and $9.50 per acre for blocks in water depths of 
LEASING AND E NVIRONMENT

27 

200 m (656 ft) or deeper with a possible escalation in the rate if the lease has an approved 

extension of the initial 5-year period. 

ROYALTY RELIEF

Deepwater royalty relief is available in Sale 206. A lease in water depths of 400 m 

(656 ft) or more will receive a royalty suspension according to the water-depth range in 

which the lease is located (Table 4). 

Table 4. Royalty Relief for Sale 206 

Water-Depth Range (m) Royalty Suspension Amount (BOE1

) 

400 to <800 5 million 

800 to <1,600 9 million 

1,600 to 2,000 12 million 

>2,000 16 million 1

Barrels of Oil Equivalent 

There were price thresholds established for this sale above which the relief would end. 

The price thresholds are $35.75 per barrel of oil and $4.47 per Mcf of natural gas; both are 

based on 2006 dollars. The Final Notice of Sale for Sale 224 states there will be no Royalty 

Suspension Provisions offered for the resulting leases. 

ENVIRONMENTAL ISSUES

Ocean Current Monitoring 

The most energetic currents in the Gulf of Mexico affect the ocean from its surface down 

to approximately the 3,281-ft (1,000-m) water-depth level with varying speeds. Currents as 

high as 4 knots (kn) [4.6 miles per hour (mph)] have been observed from the surface to 

1,000-ft (305-m) water depths. These upper currents taper off between 1,000- and 3,281-ft 

(305- and 1,000-m) depths. 

Beneath the 3,281-ft (1,000-m) water-depth level, other currents migrate around the 

deep waters of the GOM. These deep currents were once thought to be minimal and were 

not a major consideration in most structure designs. In 1999, industry reported significant 

currents below 3,000 ft (914 m). This information led to a Safety Alert (USDOI, MMS, 

2000; Notice No. 180) and subsequent studies of deep currents by MMS (Hamilton et al., 

2003 and 2000). These studies revealed significant deep currents of up to 2 kn (2.3 mph) at 

some locations. The Hamilton et al. investigations spawned another deepwater current 

study funded by MMS—the “Exploratory Study of Deepwater Currents in the Gulf of 

Mexico” (Donohue et al., 2006a and 2006b). 

The latest physical oceanographic study, “Full-Water Column Current Observations in 

the Central Gulf of Mexico” (Sheinbaum et al., 2007) provides more insight into the Gulf’s 

currents. Perhaps the most remarkable finding of this study is that the data suggest highly 

coherent motions throughout the water column, which largely decompose into barotropic 

and first baroclinic mode structures. Progressive vector diagrams and vector plots suggest 

an upper layer from the surface down to the 2,625-2,953 ft (800-900 m) depth, a transition 

layer between 2,953-3,937 ft (900-1,200 m), more in tune with the upper layer, and a deep 
DEEPWATER GULF OF MEXICO 2008: AMERICA’S OFFSHORE ENERGY FUTURE

28 

coherent layer below 3,937 ft (1,200 m). This partition is consistent with the 

thermodynamic studies of Rivas et al. (2005 and in review) and the analysis of the deep 

circulation in the Caribbean and Gulf of Mexico of Sturges (2005). The highly coherent 

motions below 3,281 ft (1,000 m), their bottom intensification, and their spectral 

characteristics are definitely reminiscent of topographic Rossby wave motions, as reported 

by Hamilton et al. (2003). Additional information is available on MMS’s website at http://

www.gomr.mms.gov/homepg/regulate/environ/techsumm/rec_pubs.html. 

Incidents have occurred in the deepwater areas of the Gulf that demonstrate the need for 

more accurate data in hindcasting and forecasting events and in daily operations. The 

MMS issued the Notice to Lessees and Operators (NTL) 2007-G17, “Deepwater Ocean 

Current Monitoring on Floating Facilities,” in May 2007 (USDOI, MMS, 2007), which 

superseded NTL 2005-G02. The NTL implemented a program where operators of 

deepwater offshore production facilities and mobile offshore drilling units (MODU’s) collect 

data on ocean currents and submit them to the National Oceanic and Atmospheric 

Administration (NOAA), which makes these data available to the general public on their 

Internet website at http://www.ndbc.noaa.gov/maps/ADCP_WestGulf.shtml. Data collected 

on currents may improve fatigue forecast models and help establish responsible design 

criteria, resulting in increased reliability of deepwater structures, thereby reducing risk to 

human lives, offshore facilities, and the ocean environment. 

Deepwater Shipwrecks 

Oil and gas industry activities on the seafloor in deep water (>1,000 ft or >305 m) have 

yielded an unexpected cultural resource bounty in the form of well-preserved historic 

shipwrecks relating to America’s maritime past. Initial discoveries came as a result of 

high-resolution sonar surveys along pipeline rights-of-way in Mississippi Canyon. The 

MMS requirement for high-resolution sonar surveys of lease blocks was typically waived in 

deep water, allowing companies to substitute 3-D seismic data for their hazards analyses. 

Several important discoveries were made from these pipeline surveys, including the 

remains of the German submarine U-166, the only U-boat lost in the northern Gulf of 

Mexico (http://www.pastfoundation.org/U166/). As a result of a growing inventory of 

shipwrecks discovered along pipeline routes, MMS issued NTL 2006-G07, which expanded 

the area requiring archaeological surveys to include all of Mississippi Canyon and parts of 

Green Canyon, Ewing Bank, and Viosca Knoll. Of the 27 shipwrecks discovered in deep 

water, 11 were reported since this NTL went into effect. 

Some of the deepwater shipwreck discoveries were casualties of World War II submarine 

attacks. In addition to the U-166 mentioned above, the freighter Alcoa Puritan, the 

passenger steamer Robert E. Lee, and the oil tankers GulfPenn and GulfOil are among the 

ships located in water depths of up to 6,500 ft (1,981 m). A recent study conducted by MMS 

found that, besides their historical interest, the wrecks had become thriving biological 

communities; the GulfPenn in particular is hosting dense colonies of Lophelia coral (http://

www.pastfoundation.org/DeepWrecks/ and Church et al., 2007). 

Nineteenth-century sailing vessels are also well represented among the inventory of 

deepwater shipwrecks. Unfortunately, of the five known 19th-century wrecks, three were 

impacted to some degree as a result of industry activities. One of these, dubbed the Mardi 

Gras Shipwreck that was named after the pipeline where it was discovered, was the subject 

of a mitigative data recovery operation in 2007 (http://www.flpublicarchaeology.org/

mardigras/). Another 19th-century wreck was discovered in a pipeline post-lay survey – the 
LEASING AND E NVIRONMENT

29 

pipeline was laid directly across it (Atauz et al., 2006). Although a survey was conducted of 

the pipeline route, the shipwreck fell in the nadir between the left and right sonar 

channels, and its location was inadvertently missed in the analysis. The MMS has 

subsequently required an offset survey line to ensure complete coverage of the proposed 

route’s centerline. A third wooden-hulled wreck was discovered by a pipeline survey near a 

major offshore platform. The pipeline survey was conducted several years after the 

structure was installed. Subsequent investigations showed that a cable from an anchor of 

the drilling rig that was used during exploration or development activities had sliced 

through the stern portion of what appears to be a two-masted brig dating from the first 

quarter of the 19th century. The rig’s anchor narrowly missed this historic vessel, which 

emphasizes the importance of conducting pre-disturbance seafloor surveys. 

Several other shipwrecks have been detected by remote-sensing survey techniques. 

Their age, cultural affiliation, and historic significance remain unknown. The current 

MMS policy mandates that operators must avoid impacts to such potential cultural 

resources. It does not require operators to visually inspect or to identify them unless the 

company’s proposed activities are likely to adversely affect the site. Since under Federal 

law the U.S. Government is not given title to shipwrecks outside State territorial waters, 

there is no requirement nor budget for MMS to investigate and inventory these potential 

resources. It is highly likely, however, that more sites will be located as industry moves 

into ever deeper water. Recent research suggests that the deepwater portions of the U.S. 

Exclusive Economic Zone (EEZ) were regularly traversed by ships as early as the 16th 

century, ships that were taking advantage of prevailing currents and winds, rather than 

hugging the coast as was long believed by historians (Lugo-Fernández et al., 2007). 

Inevitably, ships were lost along these deepwater routes as a result of storms, fires, acts of 

war, or a myriad of other causes and today remain like time capsules lying at the bottom of 

the Gulf. 

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 (Figure 18). Later, another grid was added to 

the system to address the modified Sale 181 Area, making a total of 18 grids for the Gulf. 

Under this strategy, MMS will prepare a programmatic environmental assessment 

(PEA) that analyzes a proposed development project within each of the grids and that 

characterizes the whole grid. These grid PEA’s are comprehensive in terms of the impactproducing factors and in terms of the environmental and socioeconomic resources described 

and analyzed for the entire grid. They also address potential cumulative effects of proposed 

projects 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 for 

the grid. For example, a good candidate for a PEA would be a development plan that 

proposed a new structure that might serve as a “hub” for future developmental activities 

within the grid. 
DEEPWATER GULF OF MEXICO 2008: AMERICA’S OFFSHORE ENERGY FUTURE

30 









































	



	




 

 	





	










	






 



 

 





	






 






	

 

   

    
	
	 
	
	

Figure 18. Grid PEA status. 

Once a grid PEA has been completed, it will serve as a reference document to implement 

the “tiering” and “incorporation by reference” concepts detailed in the implementing 

regulations of NEPA. Future environmental evaluation documents may reference 

appropriate sections from these PEA’s to reduce duplication of issues and effects in the 

documents that were appropriately addressed in the grid PEA’s. This will allow the 

subsequent environmental analyses to focus on specific issues and effects related to the 

proposals being currently evaluated. Table 5 provides specific information about the ten 

completed grid PEA’s. 

While the PEA’s are generally prepared for developmental activities within the grid 

boundaries, MMS also foresaw the need to address proposed exploration activities in the 

EPA. A PEA was prepared that focused on Grid 18, the 256-block modified Sale 181 Area, 

and addressed only exploration activities in this sector of the Gulf. The document serves as 

a reference designed to streamline the processing of environmental evaluations required to 

assess industry exploration plans in this part of the EPA (USDOI, MMS, 2003). 
LEASING AND E NVIRONMENT

31 

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

Grid Project Name Company Plan Area and 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 

AC = Alaminos Canyon EB = East Breaks GB = Garden Banks 

GC = Green Canyon MC = Mississippi Canyon 
33 

DRILLING AND DEVELOPMENT

Deepwater drilling occurs from MODU’s, such as semisubmersible units or drillships 

(Figures 19 and 20), and from stationary rigs located on combination production/drilling 

platforms (Figure 21). Numerous deepwater prospects are waiting to be drilled, and many 

may remain undrilled as the primary lease terms expire because of the limited number of 

rigs available for deepwater drilling in the GOM. In addition, the increased depths to 

which some operators are drilling cause rigs to be under contract for longer periods. 

Industry responded to the limited rig availability by ordering several new 

semisubmersibles in 2007. For example, ENSCO has four dynamically positioned 

semisubmersibles under construction and capable of drilling in 8,500 ft (2,591 m) of water. 

The first is expected to be completed in 2008; all four will be completed by 2010 (http://

www.enscous.com). Additionally, PetroMENA ASA has three deepwater rigs under 

construction and capable of drilling in 10,000 ft (3,048 m) of water. The first two will be 

ready in 2009 and are contracted to Petrobras. The third rig will be ready in early 2010 

and is contracted to Pemex (http://www.petrolia.no). 

Figure 19. The Deepwater Horizon, a dynamically positioned, semisubmersible drilling unit (photo 

courtesy of Transocean). 
DEEPWATER GULF OF MEXICO 2008: AMERICA’S OFFSHORE ENERGY FUTURE

34 

Figure 20. The Discoverer Enterprise, a double-hulled, dynamically positioned drillship (photo courtesy of 

Transocean). 

Figure 21. The Thunder Horse semisubmersible production facility (photo courtesy of BP). 
DRILLING AND DEVELOPMENT

35 

Figure 22 depicts the maximum number of deepwater rigs operating in the GOM from 

1992 through 2007.2 After a peak in 2001, there was a small decline in rig availability 

through 2005. The number of rigs increased slightly in 2006 and has held steady through 

2007. It is predicted that the number of rigs operating in intermediate water depths will 

decrease slightly in the coming years due to increased rig rates overseas. This will be offset 

by an increased number of rigs predicted to be capable of drilling in deep water. 

Figure 23 shows the number of deepwater MODU’s by water-depth categories in the 

GOM and worldwide. It can be seen that almost 43 percent of the rigs operating in the 

GOM are capable of drilling in water depths greater than 7,500 ft (2,286 m). Worldwide, 

the greatest number of rigs operate in the 1,500- to 4,999-ft (457- to 1,524-m) water depth 

range, with only 27 percent operating in water depths greater than 7,500 ft (2,286 m). 

Approximately 29 percent of the world’s fleet of deepwater drilling rigs is committed to 

GOM service. The pie chart within Figure 23 shows the distribution of deepwater rigs by 

major operating area. Most, if not all, of the deepwater-capable drilling rigs are under longterm contractual arrangements. The reader is cautioned not to draw conclusions from the 

rig count differences between Figures 22 and 23. Figure 22 includes platform rigs in 

addition to MODU’s; Figure 23 addresses MODU’s only. Further, not all MODU’s in 

Figure 23 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 shown; 

consequently, year-to-year comparisons may not be valid. 

3

6

11

14

18

26

28 28

33

40

34

29

26

25

30 30

0

5

10

15

20

25

30

35

40

Maximum Number of Deepwater Rigs Operating

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

Year

Figure 22. Maximum number of rigs operating in the deepwater Gulf of 

Mexico. 

 

2 It is important to note that the rig count includes platform rigs operating on deepwater production 

facilities in addition to the MODU’s. The numbers do not distinguish between rigs drilling and those 

in service for completion and workover operations. 
DEEPWATER GULF OF MEXICO 2008: AMERICA’S OFFSHORE ENERGY FUTURE

36 

1

9

10

49

9

30

15

33

0

5

10

15

20

25

30

35

40

45

50

Number of Rigs

1,000 - 1,499 1,500 - 4,999 5,000 - 7,499 > 7,500

Maximum Water Depth Capability (ft)

GOM Rigs

All Rigs Brazil, 25

Africa, 24

North Sea, 

12

GOM, 35

Other, 25

Figure 23. Approximate number of deepwater rigs (Gulf of Mexico and worldwide) subdivided according 

to their maximum water-depth capabilities. (Inset shows the number of deepwater rigs in 

various locations.) 

DRILLING ACTIVITY

The number of deepwater wells drilled generally increased from 1992 through 2001 

(Figure 24). Although there was a general decline from 2001 to 2004, the last three years 

have shown an upward trend. This figure shows that most of the drilling has occurred in 

the 1,500- to 4,999-ft (457- to 1,524-m) water-depth range. Only original boreholes and 

sidetracks 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 wellbore. 

Figures 25 and 26 break down the annual deepwater well counts (shown in Figure 24) 

into exploration and development wells, respectively. This report uses the designation of 

exploration and development wells provided by the operators. The data reflect the 

variations among operators in classifying wells as either exploration or development. After 

decreasing in 2002 and 2003, the number of exploration wells drilled increased through 

2006 and slightly decreased in 2007. Exploratory drilling in the 1,500- to 4,999-ft (457- to 

1,524-m) water-depth range remained the same from 2002 through 2004, but increased in 

2005 and remained relatively level since then. 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 2007. Overall, there has been a decrease in the number of 
DRILLING AND DEVELOPMENT

37 

development wells drilled from 2002 through 2005. Possible reasons for the decrease may 

be the method by which wells are categorized in this report (exploration versus 

development), the retention of exploration 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 has increased over the last 2 years. Remarkably, in 2007, 

46 percent of the total number of development wells were drilled in the greater than 

7,500-ft (2,286-m) water-depth interval. Almost all of these wells are associated with the 

Perdido Regional Development hub. 

21

11

1

26

14

1

19

44

1

22

56

3

24

76

6

1

32

130

12

33

123

10

1

15

118

35

29

144

25

9

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

82

32

24

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

Year

> 7,500 ft

5,000 - 7,499 ft

1,500 - 4,999 ft

1,000 - 1,499 ft

33

41

64

81

107

174

167 168

207 211

191

147 149

120

134

142

Figure 24. All deepwater wells drilled by water depth. 
DEEPWATER GULF OF MEXICO 2008: AMERICA’S OFFSHORE ENERGY FUTURE

38 

1

4

1

3

13

8

37

1

8

37

2

7

49

6

1

17

78

9

20

87

9

10

61

29

8

67

17

9

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

26

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

Year

> 7,500 ft

5,000 - 7,499 ft

1,500 - 4,999 ft

1,000 - 1,499 ft

6

16

46 47

63

104

116

100 101

114

83

74

90

93

100

94

Figure 25. Deepwater exploration wells drilled by water depth. 

20

7

23

1

1

11

7

14

19

1

17

27

15

52

3

13

36

1

1

5

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

18

6

22

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

Year

> 7,500 ft

5,000 - 7,499 ft

1,500 - 4,999 ft

1,000 - 1,499 ft

27 25

18

34

44

70

51

68

106

97

108

73

59

27

34

48

Figure 26. Deepwater development wells drilled by water depth. 
DRILLING AND DEVELOPMENT

39 

Figure 27 illustrates the geographic distribution of deepwater exploration wells. Note 

the progression into deeper water through time. Figure 28 depicts the locations of 

deepwater development wells. Once again, the data reveal a general increase in activity as 

well as a trend toward increasing water depth with time. 

One indicator that MMS has found useful in projecting activity levels is the number of 

plans received. Although the order of plan submission and drilling activities can vary with 

projects, operators generally proceed as follows: 

• file an Exploration Plan (EP), 

• drill exploration wells, 

• file a Conceptual Deep Water Operations Plan (CDWOP), 

• file a Development Operations Coordination Document (DOCD), 

• file a DWOP, 

• drill development wells, then 

• begin production. 

Figure 29 shows the number of deepwater EP’s, deepwater DOCD’s, and DWOP’s 

received each year since 1994 (DWOP’s were not required until 1995). The count of EP’s, 

DOCD’s, and DWOP’s includes only the initial plans. Some shallow-water activities are 

included in the DWOP data because DWOP’s must be filed and approved for developments 

in greater than 1,000-ft (305-m) water depths and for all subsea developments regardless of 

water depth. The discussion of subsea wells later in this report will address the 

significance of shallow-water subsea tiebacks and the effective use of deepwater 

technologies in marginal developments. 

There was a marked increase in EP’s beginning in 1997. The number of EP’s reached a 

peak of 92 in 1999, then hovered near 70 per year through 2005. Since then, EP submittals 

have declined. The number of DOCD submittals reached a high of 28 in 2005. Since then, 

the numbers have declined from that high, but have remained constant. The number of 

initial DWOP’s has remained fairly consistent between 2000 and 2007 ranging from a low 

of 27 in 2007 and a high of 36 in 2001. The decrease in the number of plans received may 

be partially attributed to the complexities of activities associated with deep water, such as 

lack of rig availability, lack of infrastructure, and harsher operating environments. 

Beginning in 1996, the maximum drilling depth increased rapidly, reaching depths 

below 30,000 ft (9,144 m) in 2002. The Transocean Discoverer Spirit drilled the deepest 

well in the GOM to date, Chevron/Unocal’s Knotty Head discovery in Green Canyon Block 

512, reaching a total vertical depth (TVD) of 34,158 ft (10,411 m) in December 2005. The 

recent dramatic increase in TVD may be attributed to several factors, including enhanced 

rig capabilities, deeper exploration targets, and the general trend toward greater water 

depths. 

Chevron holds another world record—drilling in 10,011 ft (3,051 m) of water at its 

Toledo prospect in Alaminos Canyon Block 951 in November 2003. In 2006, a record was 

set for the deepest oil production test on Chevron’s Jack prospect located in Walker Ridge 

Block 758. The Lower Tertiary Wilcox Formation was tested in the interval 26,739 to 

27,292 ft (8,150 to 8,319 m) subsea. 
DEEPWATER GULF OF MEXICO 2008: AMERICA’S OFFSHORE ENERGY FUTURE

40 









   



 









  







 

     











 







 











  

 





 





    

  



 













  



  







 













 

 

 







   

 









  











 





 



















 







 

















 



 







  

  



























 	






  





 











 



  



 



   



 



  







































 

















  



 

 





 







 















 

 



  











 

 



 















    













  

















 

 

























  





 

  



 



  



 





 

 









 



  



























 

  







 









 









 

 









 	














 















 











 

 









 









   



 

















 



 



 





 

  

















 







 





















  







 















    



































 









 























 	


















    





 





 

















 	






	















  

 



 



 

















 







 











  









 



 















  

   









 



   





 







 













 

 













 





  





 





  

  

 









 







 

    

















 







 









 













 	












	











 







  











 









 









     

 



 



 

   















 





















 





  

 



















 







 

 





  



 

   







 







 







 

 







  

 



























 

 







   

  



 

























  

 



 



 





































 	













 













    







 























  











 











 

 









 





  





















 	














   























  

























 

 









 





 



















 

  













 











 







 



   

















 



   

 









 











 





 











 













   



 

 











 

 

 



  

 

  

 

    

 















  

















 







 	

















   




Figure 27. Deepwater exploration wells drilled by years. 
DRILLING AND DEVELOPMENT

41 





 























   











 











 



   





 

















 



 



 



















 	


















  



 



 



















 



















 





 







  

















 











 

 



 









 



 



 

 



 

































 







 



 

 

 

 

 

 

 





























 



 









 



 



  





















 

















  







 



















  



  









 	
















 





 



 

 





 

 



 













 











  







  











  







 

















 



 

 















 	










 



 



 

 



   













 	






	

















 





 

















 



 







 

































 

 









  

  

 











 

 

 



    

 







 

  

 



 



   



 

































 





 





















 







 





 































 













 

  





  





 







 



  



 







 	












	









 

  



   







 

 

 





















   



 

 



 





 

 

  

























  









 















 













 	











 



  

 





  





  







  

 

 













 	








 



















 



  

  







 





 

 

 



























 



 



















 







   



 





















 









 	

















   




Figure 28. Deepwater development wells drilled by years. 
DEEPWATER GULF OF MEXICO 2008: AMERICA’S OFFSHORE ENERGY FUTURE

42 

0

10

20

30

40

50

60

70

80

90

100

Number of Plans Received

Year

Deepwater EP

Deepwater DOCD

DWOP

Deepwater EP 20 19 29 69 80 92 76 67 69 75 51 69 51 35

Deepwater DOCD 2 4 8 6 9 7 12 18 23 10 13 28 10 12

DWOP 0 5 19 30 16 18 28 36 28 28 25 34 32 27

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

Figure 29. Deepwater EP’s, DOCD’s, and DWOP’s received since 1994. 

HIGH PRESSURE, HIGH TEMPERATURE

High-pressure, high-temperature (HP/HT) development is one of the greatest 

technological and regulatory challenges to the oil and gas industry today. The basic 

building blocks of structural integrity are being challenged. Metals and elastomers that 

have been in use for many years now face unique environmental conditions. The MMS is 

working with industry to evaluate the risks and set limits to mitigate these potential 

hazards. The MMS is also sponsoring research and participating in internal and industryrelated conferences to stay at the forefront of new technology, and MMS is actively involved 

in developing options that will best promote human safety and environmental integrity. 

High-pressure, high-temperature compounds the technological challenges faced in 

deepwater exploration and especially in deepwater completion and production. 

Consequently, there is tremendous potential for growth and development in the HP/HT 

area. 

NEW TECHNOLOGY

In 2007, new technology applications addressed all areas of deepwater activities, 

including drilling, completion, production, and workover operations. In addition, MMS 

personnel and members of the industrial community updated API recommended practices 

and other regulatory documents to accompany the new technological advances. 
DRILLING AND DEVELOPMENT

43 

Four examples of technology advancements that MMS approved in 2007 include the 

following: the OmniMAX anchor; the use of pre-set polyester moorings for deepwater 

drilling rigs; a disconnectable, internal turret mooring system for ship-shape floating 

production systems; and various forms of subsea boosting, including subsea pump systems 

that allows enhanced hydrocarbon resource recovery. 

OmniMAX Anchor and Mudrope 

The OmniMAX anchor (U.S. Patent #7,059,263) is a gravity-installed, vertically-loaded 

anchor (VLA) with a high modulus polyethylene (HMPE) mudrope forerunner. Unlike 

other deepwater anchor foundations, the OmniMAX is capable of being loaded in any 

direction – 360o around the axis of the anchor. Under extreme loading and uplift angle 

conditions, the anchor will penetrate deeper into the seafloor to gain the needed holding 

capacity. This anchor technology offers great benefit in the design of mooring systems. It 

has the potential to reduce the risks to the Gulf’s subsea infrastructure in case of stationkeeping damage or partial failure of a mooring system. This technology may even allow 

damaged moorings to survive longer should multiple line failure occur. The anchor’s innate 

ability to receive varying load angle changes without adversely affecting the capacity of its 

foundation is a significant benefit. The MMS approved the use of the OmniMAX anchor 

and mudrope system on December 12, 2007. The first OmniMAX anchor installation for 

offshore oil and gas use in the GOM was completed on December 30, 2007, in Garden Banks 

Block 667 for use with the Ocean Star MODU. This marks the first time a gravity-installed 

VLA was successfully deployed for offshore OCS use. 

Pre-set Polyester Mooring for Deepwater Drilling Rigs 

Although the use of polyester mooring lines for station-keeping on production facilities is 

still considered new technology in the GOM, it is common practice to use this type of 

technology on MODU’s. One stipulation the MMS has required of operators for allowing 

the use of polyester moorings has traditionally been that the synthetic rope may not come 

in contact with the seafloor. This requirement limits particle migration into the loadbearing fibers of the rope. In recent years, the oil and gas industry has requested 

permission to pre-set MODU mooring lines. This procedure results in the rope being laid 

on the seafloor until the rig is connected to the moorings. Since these lines can be inspected 

more frequently (generally after each drilling campaign) compared with those of 

permanently fixed production facilities, MMS was willing to consider these requests. After 

conducting extensive research on the jacket and filter layer of the synthetic rope, MMS has 

granted approval for operators to pre-set polyester mooring lines for MODU’s with the 

stipulation that the lines be visually inspected each time they are retrieved. Polyester 

mooring lines for permanent facilities are still not permitted to touch the seafloor, but MMS 

has extended the time between scheduled insert removals/testing for these facilities. 

Disconnectable Internal Turret System 

The turret is the primary interface between a weathervaning, floating production facility 

and the “stationary” mooring, riser, and subsea systems. The turret acts as the primary 

load path between these systems. Since the production facility may not be designed to stay 

on location during a severe storm or hurricane, the turret can be disconnected to allow the 

facility to sail away from its mooring system. The turret and subsea systems remain on 
DEEPWATER GULF OF MEXICO 2008: AMERICA’S OFFSHORE ENERGY FUTURE

44 

location at a safe depth below the water’s surface. The concept of a disconnectable, internal 

turret system was approved by MMS in the conceptual plan for the Cascade and Chinook 

Fields. The MMS will require that a bubble-tight, shut-down valve remain with the 

submerged buoy and a separate bubble-tight, shut-down valve remain with the facility. 

The MMS will also mandate that the piping located between these valves be able to be 

flushed before a planned disconnection, thus preventing the release of any liquids to the 

Gulf’s waters. 

Subsea Pumping and Separation 

Subsea pumping and separation have been identified by the industry as key enablers in 

improving ultimate recovery from deepwater fields in the GOM. The MMS has approved 

one application for the King Field, which involved subsea pumping operations. The MMS is 

currently evaluating two other applications: the Perdido Regional Development hub for 

subsea pumping and Cascade-Chinook FPSO for a combination of subsea pumping and 

subsea separation. The pumps will boost the operating system pressure, lowering flowing 

tubing pressures at each well, thereby increasing flow rates. Shell, BP, and Petrobras are 

just a few of the many operators using or considering the use of subsea boosting to increase 

production and extend field life, ultimately increasing hydrocarbon recovery. 

Two subsea pumps and associated equipment were installed by BP at the King Field. 

This installation set a new record for both water depth and tie-back distance. The pumps 

are located at a water depth of approximately 5,500 ft (1,676 m) and reside more than 15 mi 

(24 km) from their host, the Marlin tension-leg platform (TLP). The pumps were put into 

service in December 2007. 

DEVELOPMENT SYSTEMS

Development strategies vary for deep water, depending on reserve size, proximity to 

infrastructure, operating considerations (such as well interventions), economic 

considerations, and an operator’s interest in establishing a production hub for the area. 

Appendix A lists the systems that have begun production, and Figure 30 shows the 

location of existing deepwater structures by type in the GOM. Fixed platforms (e.g., 

Bullwinkle) have economic water-depth limits of about 2,000 ft (610 m). Compliant towers 

(e.g., Petronius) may be considered for water depths of approximately 1,000 to 2,000 ft (305 

to 610 m). Tension-leg platforms (e.g., Brutus, Magnolia, and Marco Polo) are frequently 

used in 1,000- to 5,000-ft (305- to 1,524-m) water depths. Spars (e.g., Genesis and Red 

Hawk); semisubmersible production units (e.g., Na Kika); ship-shape, disconnectable 

floating production units (FPU’s); and FPSO systems may be used in water depths ranging 

up to and beyond 10,000 ft (3,048 m). Figure 31 is a graphic representation of the various 

types of production systems. 

Fixed Platform 

A fixed platform consists of a welded tubular steel jacket, deck, and surface facility. The 

jacket and deck make up the foundation for the surface facilities. The jacket is secured by 

piles driven into the seafloor. The height of the platform is dictated by the water depth at 

the intended location. Once the jacket is secured and a deck is installed, additional 
DRILLING AND DEVELOPMENT

45 













 



 









 











 



  

















 		 











	









   

   

 	






 



 	


Figure 30. Location map of currently installed deepwater structures by type. 

modules are added for drilling, production, and crew operations. Large barge-mounted 

cranes are used in positioning and securing the jacket and the installation of the topside 

modules. Economic considerations hinder development of fixed (rigid) platforms in water 

depths greater than 2,000 ft (610 m). 

Compliant Tower 

A compliant tower consists of a narrow tower and a piled foundation. Unlike a fixed 

platform, a compliant tower has greater flexibility and can withstand large lateral forces by 

sustaining significant lateral deflections. It is usually deployed in water depths between 

1,000 and 2,000 ft (305 and 610 m). 

Tension-Leg Platform 

A tension-leg platform (TLP) is a compliant structural system vertically moored and uses 

buoyant components to maintain tension in the mooring system. ConocoPhillips 

successfully installed the deepest TLP in the world at Magnolia (Garden Banks Block 783) 

in December 2004 in 4,674 ft (1,425 m) of water. 

Semisubmersible Production Unit 

A semisubmersible production platform is a floating system that may have drilling 

capabilities. It comprises the following major components: pontoons, columns, and a large 

deck. The pontoons and columns provide buoyancy to the system. Production equipment, 
DEEPWATER GULF OF MEXICO 2008: AMERICA’S OFFSHORE ENERGY FUTURE

46 

Figure 31. Deepwater development systems. 
DRILLING AND DEVELOPMENT

47 

living quarters, and storage space are assembled on the deck. Semisubmersibles are 

permanently moored, using various anchoring techniques, and can be operated in a wide 

range of water depths. 

Independence Hub, the world’s deepest semisubmersible production unit, was installed 

in approximately 8,000 ft (2,438 m) of water. Located in Mississippi Canyon Block 920, this 

facility has the capacity to produce 1 Bcf/d from up to 27 flowlines. Currently, 15 wells are 

on production in 10 different subsea fields. The water depths of the wells range from 7,787 

ft (2,373 m) at San Jacinto to 8,960 ft (2,731 m) at Cheyenne. 

Another deepwater semisubmersible to gain world wide interest is the Thunder Horse 

Facility. As the world’s largest semisubmersible production unit, the 59,500-ton Thunder 

Horse production, drilling, and quarters (PDQ) unit, arrived in the GOM in 2004 from 

Korea. The topside modules, fabricated in Morgan City, Louisiana, were installed in 

Ingleside, Texas. The Thunder Horse unit was nearly 4 years in the making and will 

develop the largest discovery ever made in the GOM. When fully operational, the unit will 

be capable of producing an astounding 250 Mbo/d and 200 MMcf/d. The installation of 

Thunder Horse (Mississippi Canyon Block 778) was delayed by Hurricane Dennis in 2005 

and by metallurgy issues in 2006 and 2007. Thunder Horse is expected to begin limited 

production in 2008 with additional wells going on production in 2009. 

Floating Production Unit (FPU) and Floating Production, Storage, and 

Offloading (FPSO) Facility 

An FPU is traditionally a ship-shape vessel capable of processing production from 

subsea facilities, but without storage capability. Some gas is used to fuel the vessel, and 

the excess gas, along with all the oil, is transported to market via export pipelines. 

Similarly, an FPSO is traditionally a ship-shape vessel capable of processing production 

from subsea facilities, but it has the capacity to store produced fluids and offload via a 

shuttle vessel at a later date. Gas is used to fuel the FPSO with the excess being exported 

via an export pipeline. 

An FPU and FPSO may be moored via conventional mooring lines, synthetic mooring 

lines, or may be dynamically positioned. Mooring lines and risers are connected to the 

vessel via a disconnectable turret/buoy system (DTS) for all the currently proposed GOM 

facilities. This allows the ship to sail to a safer location during an extreme weather event. 

The DTS, including the mooring lines and risers, remain submerged at a pre-determined 

depth after disconnection. This minimizes the impact of extreme weather situations and 

does not impede marine transportation. 

The GOM’s first application for the use of an FPSO was submitted in May 2007. 

Petrobras America Inc. plans to develop the Cascade and Chinook Fields located in Walker 

Ridge with a moored, disconnectable FPSO. Production from the fields’ subsea wells is 

transported via flowlines to the free-standing hybrid risers (FSHR), another first for the 

Gulf. These risers are connected to the FPSO through the DTS. Gas will depart the FPSO 

via an export FSHR to the export pipeline. Oil will be stored on the facility until it is 

periodically offloaded to a shuttle vessel for transshipment to onshore receiving terminals. 

First oil from both fields is expected in 2010 with further expansion possible in the future. 

In anticipation of this application, MMS and the U.S. Coast Guard (USCG) developed a 

new Memorandum of Agreement (MOA) for floating production facilities. This agreement 

lays the groundwork for determining each agencies regulatory responsibility. 
DEEPWATER GULF OF MEXICO 2008: AMERICA’S OFFSHORE ENERGY FUTURE

48 

Another first for the GOM was Energy Resource Technology, Inc.’s application for a 

ship-shape, dynamically positioned (DP), disconnectable turret FPU for the Phoenix 

development. The disconnectable turret system on this facility is not designed as a 

structural mooring component because of the DP capability. Since there is no storage 

capability on the FPU, oil and gas will be transported via export risers to pipelines. 

Spar 

A spar is a vessel with a circular cross-section that sits vertically in the water and is 

supported by buoyancy chambers (hard tanks) at the top, a flooded mid-section structure 

hanging from the hard tanks, and a stabilizing keel section at the bottom. A spar is held in 

place by a catenary mooring system, providing lateral stability. Currently, there are three 

competing versions of spars used in the GOM: classic spar, truss spar, and cell spar. 

Shell Offshore Inc. recently announced that they will be installing the deepest spar 

production facility in Alaminos Canyon. The Perdido Regional Development hub will be 

located in about 8,000 ft (2,438 m) water depth to develop the Great White, Tobago, and 

Silvertip Fields. Once operating at full capacity, Perdido will be capable of handling 

130,000 BOE/d. 

Subsea Systems 

Subsea systems are capable of producing hydrocarbons from reservoirs covering the 

entire range of water depths that industry is exploring. Subsea systems continue to be a 

key component in the success in deep water to date. In fact, 85 percent of all currently 

producing deepwater fields utilize subsea systems (Figure 32). These systems are 

generally multi-component seafloor facilities that allow the production of hydrocarbons in 

water depths that would normally preclude installing conventional fixed or bottom-founded 

platforms. The subsea system can be divided into two major components: the seafloor 

equipment and the surface equipment. The seafloor equipment will include some or all of 

the following: one or more subsea wells, manifolds, control umbilicals, pumping or 

processing equipment, and flowlines. The surface component of the subsea system includes 

the control system and other production equipment located on a host platform that could be 

located many miles from the actual wells. The economics of deepwater development have 

improved by connecting multiple subsea projects to a single hub. For example, the 

Independence Hub facility supports 10 separate producing fields. 

SUBSEA TRENDS

Figure 33 shows the number of subsea completions each year since 1988 (only 

productive wells were counted). There were fewer than 10 subsea completions per year 

until 1993. In 2001 and 2002, dramatic increases in deepwater subsea completions 

occurred. These increases are partially attributable to fields associated with the Na Kika 

floating production facility. At this same time, subsea completions in deep water 

dramatically overshadowed those in shallow water. In 2007, a record was set for the 

highest number of subsea completions in deep water, many of which were associated with 

the Independence Hub facility. The pie chart in Figure 33 shows that deepwater subsea 

wells constitute the majority (63%) of the total subsea well population in the GOM. 
DRILLING AND DEVELOPMENT

49 

Mini-TLP/TLP, 14 Compliant Tower, 3

Spar, 14

Semisubmersible/FPS, 5

Fixed Platform, 5

Subsea, 240

Figure 32. Production systems for currently producing fields, including 

subsea systems. 

0

5

10

15

20

25

30

35

40

45

50

1988 1990 1992 1994 1996 1998 2000 2002 2004 2006

Year

Number of Subsea Completions

Deepwater

Shallow Water Shallow Water

37%

Deepwater

63%

Figure 33. Number of shallow- and deepwater subsea completions each year. 
DEEPWATER GULF OF MEXICO 2008: AMERICA’S OFFSHORE ENERGY FUTURE

50 

The technology required to implement subsea production systems in deep water have 

evolved significantly. This evolution is apparent in Figure 34, which shows that the 

deepest subsea completion was in 350 ft (107 m) of water until 1988, when the water depth 

record jumped to 2,243 ft or 684 m (Green Canyon Block 31 project). In 1996, another 

record was reached with a subsea completion in 2,956 ft (901 m) of water (Mars project), 

followed by a 1997 subsea completion in 5,295 ft (1,614 m) of water (Mensa project). 

Cheyenne, one of the subsea fields tying back to the Independence Hub facility, has the 

deepest subsea completion in the GOM to date, in a water depth of 8,960 ft (2,731 m). Last 

year, a subsea well was completed at a water depth of 8,807 ft (2,684 m) in the Atlas NW 

Field, which is also tied back to Independence Hub. A listing of productive subsea and 

temporarily abandoned completions in the GOM can be found in Appendix C. 

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

195519571959196119631965196719691971197319751977197919811983198519871989199119931995199719992001200320052007

Year

Maximum Water Depth (ft)

GC 31

Mars

Mensa

King's Peak

Camden Hills

Cheyenne

Atlas NW

Figure 34. Maximum water depth of subsea completions installed each year. 

NEW DEVELOPMENTS

Deepwater development is constantly evolving and expanding in the GOM. As new 

discoveries are made, operators must determine the most efficient and economical means of 

recovering those hydrocarbon reserves. Where possible, an operator may decide to use 

subsea technology to control and produce its deepwater wells within a field. The wells will 

be tied back to existing infrastructure through flowlines. Other times, either because of 

operational conditions, logistics, or the magnitude of the discovery, operators may decide to 

install a production facility. While there are over 50 deepwater production facilities 

currently installed, there are many more in the planning and development phases. 
DRILLING AND DEVELOPMENT

51 

Independence Hub – Anadarko Petroleum Corporation 

The world-record-setting Independence Hub project began producing natural gas from 

the ultra-deep waters of the GOM in July 2007. Operated by Anadarko Petroleum 

Corporation and owned by Enterprise (80%) and Helix (20%), Independence Hub is the 

Gulf’s largest and deepest natural gas processing facility with capacity to bring 1 Bcf/d of 

natural gas to American consumers. The layout of the project spans a massive 142 blocks 

or about 1,800 mi2 (over 4,600 km2) in waters of up to 9,000 ft (2,745 m) deep and will 

account for over 10 percent of all natural gas currently produced from the GOM. At yearend 2007, Independence Hub was producing more than 900 MMcf/d from 10 discoveries – 8 

of which are operated by Anadarko. 

Atlantis – BP America Inc 

On December 18, 2007, BP announced that it had completed commissioning of the 

Atlantis semisubmersible platform in the deepwater GOM and commenced the export of oil 

and gas from the deepest moored, floating oil and gas production facility in the world. Gas 

sales have started and oil volumes are increasing as the facility ramps up production. 

Additional wells will continue to be brought on stream, and the facility is expected to reach 

plateau production by the end of 2008. The Atlantis semisubmersible platform is designed 

to process 200,000 barrels of oil and 180 million cubic feet of gas per day. 

Shenzi – BHP Billiton 

In 2006, BHP Billiton sanctioned the development of the Shenzi Field, located in the 

deep waters of the CPA. An early phase of production commenced in October 2007 from the 

western portion of the field, which was previously known as Genghis Khan and acquired 

from the initial leaseholder (Anadarko) earlier in the year. Production from the Genghis 

Khan portion of the field will be transported to the Marco Polo TLP in Green Canyon Block 

608. This TLP is a third-party facility operated by Anadarko. Development of the eastern 

portion of the field (Shenzi) is on schedule to commence production in mid-2009. The 

Shenzi production facility will feature a TLP with a design capacity for 100,000 bo/d and 50 

MMcf/d of natural gas. Together, these projects comprise a six-block development area in 

Green Canyon (Blocks 608, 609, 610, 652, 653, and 654) for which BHP Billiton serves as 

operator, with 44 percent. Other partners in the conjoined projects are Hess and Repsol 

YPF with 28 percent each. 

Thunder Horse – BP America Inc. 

The Thunder Horse project is currently preparing for start up of production in 2008 and 

is one of the key discoveries upon which BP will grow its future deepwater development in 

the GOM. Designed to process 250,000 bo/d and 200 MMcf/d of natural gas, Thunder Horse 

will be the largest producer in the Gulf. The field lies approximately 150 mi (241 km) 

southeast of New Orleans in about 6,000 ft (1,829 m) of water. High-pressure, hightemperature reservoirs in multiple intervals are distributed from 18,000 to 24,000 ft (5,486 

to 7,315 m) subsea. All of the 21 pipeline end terminations (plets) and the temporary 

manifolds have now been installed. Change-out of the first tree (Mississippi Canyon Block 

822 well #3) at drill center 45 by the Enterprise MODU was completed in December 2007. 

The remaining scope of work before first production from the South field includes the 

installation of jumpers and the commissioning of the production system. 
DEEPWATER GULF OF MEXICO 2008: AMERICA’S OFFSHORE ENERGY FUTURE

52 

Perdido – Shell Exploration and Production Company 

The Perdido Regional Development host facility will be located in Alaminos Canyon 

Block 857. Once installed, the direct vertical access truss spar will set a new record as the 

deepest spar in over 8,000 ft (2,438 m) of water depth. The Perdido spar will be capable of 

handling 130,000 BOE/d (100,000 bo/d and 200 MMcf/d) from the wells located directly 

below the structure (part of the Great White Field) as well as subsea tiebacks from other 

portions of the Great White Field and the Silvertip and Tobago Fields. As a part of the 

Perdido development concept, Shell has requested approval for a subsea 

separation/boosting system to enhance overall recovery from the fields. Perdido is expected 

to come on production in 2010. 

Cascade-Chinook – Petrobras America Inc. 

In 2007, Petrobras America Inc. (Petrobras) submitted a DWOP and DOCD to develop 

the Cascade-Chinook Fields with the Gulf’s first FPSO. The Cascade Field (Walker Ridge 

Block 206 Unit – Blocks 205, 206, 249, and 250) is located approximately 250 mi (402 km) 

south of New Orleans and about 165 mi (266 km) from the Louisiana coastline in 

approximately 8,200 ft (2,499 m) of water. The Chinook Field (Walker Ridge Block 425 

Unit – Blocks 425, 426, 469, and 470) is located about 16 mi (26 km) south of the Cascade 

Prospect in approximately 8,800 ft (2,682 m) of water. The FPSO will be located in the 

southeast corner of Walker Ridge Block 249 in a water depth of about 8,200 ft (2,499 m). 

The FPSO will be a converted, double-hulled, ship-shape vessel owned by BW Offshore with 

a storage capacity of approximately 600,000 barrels, a process capacity of 80,000 bo/d, and 

gas export facilities of 16 MMscf/d. 

Petrobras has proposed the use of five new technologies in the development of their 

fields: FPSO with a disconnectable turret; crude oil transportation via shuttle vessels [i.e., 

shuttle tanker, integrated tug barge (ITB), or articulated tug barge (ATB)]; subsea electric 

submersible pump (ESP); FSHR; and a polyester mooring system. 

In the initial development phase, Petrobras proposes to drill and complete two new 

wells in the Cascade Field and a single new well in the Chinook Field. The subsea 

production wells would be tied back to the FPSO using dual 9 5/8-in (24.4-cm) flowlines and 

FSHR’s. Production will be enhanced by subsea booster pumps that are located 

downstream from the gathering manifolds. The FPSO will separate and treat the 

production and store the liquid hydrocarbon within the vessel. Figure 35 is an artistic 

rendering that depicts the proposed two-field development infrastructure and displays the 

FPSO and shuttle vessel in a tandem configuration. Subsequent development phases for 

the project may include up to 24 additional wells. First oil is expected in 2010. 

Produced crude oil will be transported by shuttle vessels from the FPSO to a port along 

the U.S. Gulf Coast. Produced gas will be used to fuel the common process facilities on the 

FPSO. Excess gas will be transported from the FPSO via a FSHR and a 6-in (25-cm) export 

pipeline that will connect to the existing GOM pipeline infrastructure. 

Petrobras is currently considering two tie-in options for their development: the 

“Cleopatra Option” (operated by BP) is located in Green Canyon Block 829 and is 

approximately 43 mi (69 km) from the FPSO, and the “Anaconda Option” (operated by 

Enterprise) is located in Green Canyon Block 606 and is approximately 66 mi (106 km) 

from the FPSO. 
DRILLING AND DEVELOPMENT

53 

Figure 35. Infrastructure schematic of the Cascade and Chinook Field development, Phase I (image 

courtesy of Petrobras and Devon). 

NEW PIPELINES

The pipeline infrastructure to bring deepwater oil and gas onshore also expanded during 

the 1990’s. The pipeline from a subsea completion to the host platform is commonly 

referred to as the tieback. The tieback length varies considerably, as shown in Figure 36. 

Most subsea wells are within 10 mi (16 km) of the host platform, with the Mensa Field 

remaining the current world record holder for a subsea tieback length of 62 mi (100 km) 

from the host platform. The second longest subsea tieback in the world (55 mi or 88 km) is 

Canyon Express, linking the Aconcagua, Camden Hills, and King’s Peak projects to their 

host platform. The Independence Hub is a prime example of the emerging dependence on 

subsea tiebacks. The hub uses 192.7 mi (310 km) of flowlines, with the longest tieback 

stretching over 45 mi (72 km). 
DEEPWATER GULF OF MEXICO 2008: AMERICA’S OFFSHORE ENERGY FUTURE

54 

212

86

91

22

11

5

0

50

100

150

200

250

Number of Tiebacks

< 5 5 - 9 10 - 19 20 - 29 30 - 49 50+

Tieback Length Range (mi)

.

Figure 36. Length of subsea tiebacks. 

Deepwater pipelines approved for installation are shown in Figures 37a and 37b. The 

data include the total length of all pipelines originating at a deepwater development, 

including any shallow-water segments (control umbilicals are excluded). Figure 37a shows 

deepwater pipelines that are less than or equal to 12 in (30.5 cm) in diameter. Gas 

pipelines in deep water account for 61 percent of the total approved miles since 1995. The 

large increase in 2001 in oil and gas pipeline miles reflects approvals for Canyon Express 

(Aconcagua, Camden Hills, and King’s Peak Fields), Horn Mountain, and the BoomvangNansen projects. In 2002, projects associated with the Na Kika floating production facility 

contribute significantly to the mileage. Part of the peak in 2005 is associated with pipelines 

approved for the Independence Hub, Gomez, and Triton projects. Shenzi, Atlantis, 

Independence Hub, and Tahiti contributed to last year’s totals. 

Approval of large pipelines [greater than 12 in (30.5 cm) in diameter] peaked in 1999, 

primarily from the pipelines associated with Hoover (Figure 37b). A dramatic increase 

occurred in 2002 after a brief downturn in activity in 2000 and 2001. The peak in 2002 was 

driven by the approval of the Mardi Gras system. Gas and oil from the Mardi Gras system 

is delivered to onshore processing facilities via the new Cameron Highway pipeline system, 

which has been a very important development in pipeline infrastructure. Both the 

Gunnison and Genghis Khan projects contributed to the 2003 totals, while approvals for 

pipelines associated with Constitution contributed to the totals in 2005. In 2007, the major 

contributor to the oil pipeline mileage was Shenzi, while Poseidon and Triton bolstered the 

gas pipeline mileage. 
DRILLING AND DEVELOPMENT

55 

9

10 18

144

49

101

121

86

108

62

28

89

185

297

162

178

58

70

55

80

102

284

47

110

110

131

0

50

100

150

200

250

300

350

400

450

500

Miles of Pipeline Approved

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

Year

Gas

Oil

Figure 37a. Approved deepwater oil and gas pipelines less than or equal to 12 inches in 

diameter. 

40

41

40

0

39

46 103

65

179

129

25

32

41

42

232

232

156

225

43

11

67

165

53

33

204

167

0

50

100

150

200

250

300

350

400

450

500

Miles of Pipeline Approved

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

Year

Gas

Oil

Figure 37b. Approved deepwater oil and gas pipelines greater than 12 inches in diameter. 
DEEPWATER GULF OF MEXICO 2008: AMERICA’S OFFSHORE ENERGY FUTURE

56 

The infrastructure needed to bring deepwater production online continues to develop 

over time. Figure 38 shows the framework of major oil and gas pipelines in the entire 

GOM. Figure 39 illustrates the existing oil and gas network of pipelines in deep water. 

These figures include new and proposed pipelines through the end of 2007. 

		 

















   

   

	


		


			


Figure 38. Oil and gas pipelines with diameters greater than or equal to 20 inches. 

HIGH-INTEGRITY PRESSURE PROTECTION SYSTEM (HIPPS) 

The longer subsea tiebacks being used to develop marginal deepwater fields pose another 

challenge for industry, namely in the design and installation of pipelines rated for the 

HP/HT well’s shut-in tubing pressure (SITP) of greater than or equal to 15,000 pounds per 

square inch (psi) and/or 350o F (177o C). Rather than relying on the physical strength of 

steel to withstand the SITP, a high-integrity pressure protection system (HIPPS) provides 

alternate over-pressure protection for a pipeline or flowline. The HIPPS employs valves, 

logic controllers, and pressure transmitters to shut down the system before a pipeline is 

overpressured and/or ruptured. 

The MMS has been working with API to formulate the regulatory framework for the 

installation of a HIPPS in the GOM. The API resumed work on its Recommended Practice 

API RP 17 O, High Integrity Pressure Protection Systems (HIPPS), in 2007 (API, in 

preparation). The MMS is actively working with industry to complete this document by the 

end of 2008. To date, MMS has approved the concept of a HIPPS, but a formal application 

has not yet been received. 
DRILLING AND DEVELOPMENT

57 

		  













		 



















	

	


  	

   

   

Figure 39. Deepwater oil and gas pipelines. 
58 

RESERVES AND PRODUCTION

The deepwater GOM has contributed major additions to the total reserves in the GOM. 

Figure 40 shows the proved reserves added each year by water-depth category. Additions 

from the shallow waters of the GOM declined in recent years but, beginning in 1975, the 

deepwater area started contributing significant new reserves. Between 1975 and 1983, the 

majority of these additions were from discoveries in slightly more than 1,000 ft (305 m) of 

water. It was not until 1985 that major additions came from water depths greater than 

1,500 ft (457 m). From 1998 to 2001, significant proved reserves were added in the 5,000- 

to 7,499-ft (1,524- to 2,286-m) water depth range. The year 2002 saw the first substantial 

addition from water depths greater than 7,500 ft (2,286 m). 

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 (TD) 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. 

Figure 41 includes both proved and unproved reserves for each water-depth category. This 

figure shows declining reserve additions in shallow water, similar to Figure 40, but reveals 

significantly more deepwater reserve additions and large significant unproved reserve 

additions in water depths greater than 5,000 ft (1,524 m) beginning in 1998. 

Figure 42 illustrates the most important feature of the deepwater field discoveries, that 

their average size is many times larger than the average size of shallow-water fields. 

Generally over the past 10 years, the field sizes in ultra-deep water are many times larger 

than shallower-water fields. 

It is important to note that MMS has not completed all of the estimates of proved and 

unproved reserves for 2006 and 2007 discoveries in deep water, thus the proved and 

unproved reserves additions and average field size for these years are subject to change in 

future reports. Additionally, some new discoveries on leases for 2006 and 2007 may be 

placed in existing older fields, resulting in changes to proved and unproved reserves 

additions and average field size for previous years. 

DISCOVERIES

Figure 43 shows the number of deepwater fields discovered each year (according to 

MMS criteria) and the number of those that began production through 2006. The number 

of field discoveries for any given year is usually greater than the number of fields that 

actually go on production. The difference between the number of field discoveries and the 

number of those that actually produce increased in the early 2000’s, because these recent 

field discoveries have not had ample time for project approval and design and subsequent 

production. Because of this lag between exploratory drilling and project approval, the full 

impact of recent, large deepwater exploratory successes is not yet reflected in MMS’s proved 

reserve estimates. 
RESERVES AND P RODUCTION

59 

0

500

1,000

1,500

2,000

2,500

3,000

1965196719691971197319751977197919811983198519871989199119931995199719992001200320052007

Year

Million Barrels of Oil Equivalent

> 7,500 ft

5,000 - 7,499 ft

1,500 - 4,999 ft

1,000 - 1,499 ft

0 - 999 ft

Figure 40. Proved reserve additions. 

0

500

1,000

1,500

2,000

2,500

3,000

1965196719691971197319751977197919811983198519871989199119931995199719992001200320052007

Year

Million Barrels of Oil Equivalent

> 7,500 ft

5,000 - 7,499 ft

1,500 - 4,999 ft

1,000 - 1,499 ft

0 - 999 ft

Figure 41. Proved and unproved reserve additions. 
DEEPWATER GULF OF MEXICO 2008: AMERICA’S OFFSHORE ENERGY FUTURE

60 

0

100

200

300

400

500

600

700

800

900

1965196719691971197319751977197919811983198519871989199119931995199719992001200320052007

Year

Million Barrels of Oil Equivalent

> 7,500 ft

5,000 - 7,499 ft

1,500 - 4,999 ft

1,000 - 1,499 ft

0 - 999 ft

Figure 42. Average field size using proved and unproved reserves. 

0

2

4

6

8

10

12

14

16

18

20

22

24

19751976197719781979198019811982198319841985198619871988198919901991199219931994199519961997199819992000200120022003200420052006

Field Discovery Year

Number of Fields

Number of discoveries (MMS qualified)

Number producing

Figure 43. Number of deepwater field discoveries and the resulting number of producing fields. 
RESERVES AND P RODUCTION

61 

In an attempt to capture the full impact of these deepwater exploratory successes, 

Figure 44 adds MMS-known resource estimates and industry-announced discoveries to the 

proved and unproved reserve volumes. The industry-announced discovery 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. The apparent decline 

of proved reserve additions in recent years is caused by the previously mentioned 

developmental lag. 

Figure 45 illustrate the distribution of recent hydrocarbon additions in the GOM, 

categorized by water depth. When comparing MMS proved reserve additions with those of 

the combination of unproved reserve estimates, known resources, and industry-announced 

deepwater discoveries, it can be seen that deepwater exploration has added significantly to 

the GOM hydrocarbon inventory. Last year, however, oil and gas reserves added to the 

GOM decreased sharply from those in 2006. This can be partially attributed to the smaller 

number and size of most of the announced discoveries in 2007, and the fact that MMS has 

not completed all reserve estimates for 2006 and 2007. These decreases are also likely to be 

the result of industry diverting its capital from exploration to appraisal and development. 

PRODUCTION TRENDS

Leasing, drilling, and discoveries—all stepped into deeper waters with time. The final 

piece in the puzzle, production, is no exception. Figure 46 illustrates deepwater projects 

that began production in 2006 and 2007 and those expected to commence production in the 

next 6 years. Ten deepwater projects went online in 2006 and another 15 in 2007, 9 of 

which were associated with the Independence Hub production facility. In addition to the 

projects shown in Figure 46, 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. 

Table 6 shows that for the first time all of the 20 most prolific producing blocks in the 

GOM are located in deep water. Figure 47 illustrates the relative volume of production 

from each GOM lease through time. Notice the large deepwater volumes that first appear 

in 1998 and 1999. More recent production continues to expand over a larger area and into 

deeper waters. 

Figures 48a and 48b illustrate the importance of the GOM to the Nation’s energy 

supply. The GOM supplied approximately 26 percent of the Nation’s domestic oil and 15 

percent of the Nation’s domestic gas production in 2006. A significant portion of the oil 

volume came from the deep water. In fact, beginning in 2000, more oil has been produced 

from the deepwater areas of the GOM than from shallower waters. Total annual GOM gas 

contributions have slightly declined from 2005 to 2006. However, Independence Hub will 

add substantially to the Gulf’s gas contributions in the near future. Production began in 

2007, and when the project reaches full capacity of 1 billion cubic feet of gas per day, it will 

represent over 10 percent of the gas production from the GOM. 
DEEPWATER GULF OF MEXICO 2008: AMERICA’S OFFSHORE ENERGY FUTURE

62 

0

500

1,000

1,500

2,000

2,500

3,000

19751977197919811983198519871989199119931995199719992001200320052007

Discovery Year

Million Barrles of Oil Equivalent

0

5

10

15

20

25

30

Number of Discoveries

Proved reserves

Unproved reserves, resources, and industry-announced discoveries

Number of discoveries

Figure 44. Number of deepwater field discoveries and new hydrocarbons found (MMS 

reserves, MMS resources, and industry-announced discoveries). 

0

500

1,000

1,500

2,000

2,500

3,000

1965196719691971197319751977197919811983198519871989199119931995199719992001200320052007

Year

Million Barrels of Oil Equivalent

> 7,500 ft

5,000 - 7,499 ft

1,500 - 4,999 ft

1,000 - 1,499 ft

0 - 999 ft

Figure 45. Barrels of oil equivalent added (reserves, known resources, and industryannounced discoveries). 
RESERVES AND P RODUCTION

63 



  

    

 

    

 



























	



  

	



 







  	 


	




	





	
 



 	


 




	
 




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Figure 46. Deepwater projects that began production in 2006 and 2007 and those expected to begin 

production by yearend 2013. 

Table 6. Top 20 Producing Blocks for the Years 2005-2006 

Block Project Name Operator Water Depth (ft)1 Production (BOE)2

MC 807 Mars Shell 2,933 46,040,577 

MC 383 Kepler (Na Kika) BP 5,739 40,959,934 

MC 809 Ursa Shell 3,800 37,050,498 

GC 644 Holstein BP 4,340 27,076,950 

MC 127 Horn Mountain BP 5,400 23,957,778 

GB 215 Conger Amerada Hess 1,500 23,906,599 

VK 786 Petronius ChevronTexaco 1,753 23,187,217 

MC 429 Ariel (Na Kika) BP 6,240 23,105,523 

GB 783 Magnolia ConocoPhillips 4,670 22,792,615 

GB 668 Gunnison Kerr-McGee 3,126 22,558,126 

VK 912 Ram-Powell Shell 3,216 22,483,526 

EB 602 Nansen Kerr-McGee 3,580 21,889,299 

MC 765 Princess Shell 3,642 21,531,382 

GC 782 Mad Dog BP 4,420 21,164,896 

MC 522 Fourier (Na Kika) BP 6,940 18,707,968 

MC 763 Mars Shell 2,933 17,929,579 

MC 85 King BP 5,317 15,286,393 

GB 385 Llano Shell 2,610 13,097,959 

MC 538 North Medusa Murphy 2,095 12,989,679 

MC 657 Coulomb (Na Kika) Shell 7,565 12,975,899 

BOE = barrels of oil equivalent EB = East Breaks GB = Garden Banks 

GC = Green Canyon MC = Mississippi Canyon VK = Viosca Knoll 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 2005 through December 2006. 
DEEPWATER GULF OF MEXICO 2008: AMERICA’S OFFSHORE ENERGY FUTURE

64 











 

 	
 	



 
















 

 	
 	



 





 







 




 

	


 







 






 

 	
 	
 


 












Figure 47. Relative volume of production from each Gulf of Mexico lease. (Bar heights are 

proportional to total lease production in barrels of oil equivalent during that 

interval.) 
RESERVES AND P RODUCTION

65 







 

	


 












	



 	



 

 

 

 



 









	



 	



 

 

 

 



 





	



 	



 

 



 



 



 





 

 

Figure 47. Relative volume of production from each Gulf of Mexico lease. (Bar heights are 

proportional to total lease production in barrels of oil equivalent during that 

interval.) (continued). 
DEEPWATER GULF OF MEXICO 2008: AMERICA’S OFFSHORE ENERGY FUTURE

66 

 

	 	


 
 
 
  

 


 
   
 


















	 	 



 

	


 




Figure 47. Relative volume of production from each Gulf of Mexico lease. (Bar heights are 

proportional to total lease production in barrels of oil equivalent during that 

interval.) (continued). 

 Deepwater

GOM

18.5% 

 Shallow-water

GOM

7.1% 

 Other U.S.

74.4% 

 Deepwater

GOM

5.6% 

 Shallow-water

GOM

9.4% 

 Other U.S.

85.0% 

Figure 48a. Estimated U.S. oil 

production in 2006. 

Figure 48b. Estimated U.S. gas 

production in 2006. 
RESERVES AND P RODUCTION

67 

Figure 49a3 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. 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. Starting in 2003, 

deepwater oil production leveled off. In 2006, deepwater oil production accounted for over 

72 percent of total GOM oil production. Figure 49b 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 today. 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 to the 

end of 2006. Appendix D lists historic GOM oil and gas production. 

As discussed previously, the Deep Water Royalty Relief Act had a significant effect on 

deepwater leasing and drilling. Numerous projects with royalty-relief eligibility have come 

online in recent years (Appendix A), but the impact of the DWRRA on deepwater 

production began to show in 2002. Note that pre-DWRRA production refers to production 

from leases that have been approved to receive royalty relief but were issued before 

November 28, 1995. Figure 50a shows the contribution of deepwater royalty relief 

(DWRR) oil production to total “deepwater” GOM oil production, where “deepwater” is 

defined as 200 m (656 ft), the minimum water depth for which DWRR incentives are 

offered, instead of 1,000 ft (305 m), the definition used elsewhere in this report. Since the 

2006 report (French et al., 2006), the amount of oil production subject to royalty suspension 

has slightly decreased. Figure 50b displays total “deepwater” gas production along with 

gas production subject to royalty relief. The volume of natural gas subject to royalty relief 

under the DWRRA increased rapidly in 2002, reaching its peak in 2005. Note that in these 

figures, pre-DWRRA production refers to production from leases that have been approved to 

receive royalty relief but were issued before November 28, 1995. 

During 2006, approximately 300,000 barrels of oil and 1.4 billion cubic feet of gas came 

from deepwater subsea completions each day. Subsea completions currently account for 

about 30 percent of deepwater oil production and about 40 percent of deepwater gas 

production. Figure 51a shows that very little deepwater oil production came from subsea 

completions until mid-1995, after which subsea production generally increased until mid2002. Since then, levels have decreased slightly and have remained relatively steady. 

Deepwater gas production from subsea completions began in mid-1993, generally increased 

until early-2004, and has subsequently decreased (Figure 51b). 

 3 The dip in production in 2005 shown on this and some of the production graphics is the result of 

hurricane activity (Hurricanes Katrina and Rita). Production has quickly rebounded. 
DEEPWATER GULF OF MEXICO 2008: AMERICA’S OFFSHORE ENERGY FUTURE

68 

0

200

400

600

800

1,000

1,200

195019541958196219661970197419781982198619901994199820022006

Year

Thousand Barrels of Oil per Day

Shallow-water oil

Deepwater oil

Figure 49a. 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 49b. Comparison of average annual shallow- and deepwater gas production. 
RESERVES AND P RODUCTION

69 

0

200,000

400,000

600,000

800,000

1,000,000

1,200,000

Jan-92 Jan-93 Jan-94 Jan-95 Jan-96 Jan-97 Jan-98 Jan-99 Jan-00 Jan-01 Jan-02 Jan-03 Jan-04 Jan-05 Jan-06

Month

Barrels of Oil per Day

Total oil production >200 m (656 ft)

Contribution of pre-DWRRA production

Contribution of DWRRA production 

Figure 50a. Contribution of DWRRA oil production to total oil production in water depths 

greater than 200 m (656 ft). 

0

1,000,000

2,000,000

3,000,000

4,000,000

5,000,000

6,000,000

Jan-92 Jan-93 Jan-94 Jan-95 Jan-96 Jan-97 Jan-98 Jan-99 Jan-00 Jan-01 Jan-02 Jan-03 Jan-04 Jan-05 Jan-06

Month

Thousand Cubic Feet per Day

Total gas production >200 m (656 ft)

Contribution of DWRRA production

Contribution of pre-DWRRA production

Figure 50b. Contribution of DWRRA gas production to total gas production in water depths 

greater than 200 m (656 ft). 
DEEPWATER GULF OF MEXICO 2008: AMERICA’S OFFSHORE ENERGY FUTURE

70 

0

100,000

200,000

300,000

400,000

500,000

600,000

700,000

800,000

900,000

1,000,000

1,100,000

1,200,000

Jan-92 Jan-93 Jan-94 Jan-95 Jan-96 Jan-97 Jan-98 Jan-99 Jan-00 Jan-01 Jan-02 Jan-03 Jan-04 Jan-05 Jan-06

Month

Barrels of Oil per Day

Subsea Oil

Total Deepwater Oil

Figure 51a. Contributions from subsea completions toward total deepwater oil production. 

0

500,000

1,000,000

1,500,000

2,000,000

2,500,000

3,000,000

3,500,000

4,000,000

4,500,000

5,000,000

Jan-92 Jan-93 Jan-94 Jan-95 Jan-96 Jan-97 Jan-98 Jan-99 Jan-00 Jan-01 Jan-02 Jan-03 Jan-04 Jan-05 Jan-06

Month

Thousand Cubic Feet of Gas per Day

Subsea Gas

Total Deepwater Gas

Figure 51b. Contributions from subsea completions toward total deepwater gas production. 
RESERVES AND P RODUCTION

71 

PRODUCTION RATES

High well production rates have been a driving force behind the success of deepwater 

operations. Figure 52a illustrates the highest deepwater oil production rates for single 

wells (monthly production divided by actual production days). In the 1,500- to 4,999-ft 

(457- to 1,524-m) water depth interval, several large step increases have occurred as wells 

came online from fields such as Auger and Mars, culminating in a record maximum single 

well production rate of over 41,500 bo/d from Troika. After this time, major peaks have 

occurred for wells from Ursa and Brutus. In ultra-deep water, a Horn Mountain well 

established the record with over 32,000 bo/d in 2002. Wells at Kepler (Na Kika) came close 

to this record in 2005. Figure 52b shows maximum production rates for gas from single 

wells. In the 1,500- to 4,999-ft (457 to 1,524-m) water-depth interval, a well at Popeye set a 

record with over 143 MMcf/d in 1998. This record stood until 2002, when a single well at 

Mica surpassed this rate, with almost 145 MMcf/d. A single Mensa well holds the 

maximum gas production rate for the deepwater GOM at about 158,000 MMcf/d in 2004. 

Figure 53a shows that the average deepwater oil completion currently produces at 

about 20 times the rate of the average shallow-water [less than 1,000 ft [305 m)] oil 

completion. The average deepwater gas completion currently produces at about 7 times the 

rate of the average shallow-water gas completion (Figure 53b). Deepwater oil production 

rates increased rapidly from 1996 through 1999 and remained relatively steady since that 

time. Deepwater gas production rates rose from 1996 to mid-1998, remaining relatively 

steady through 2004. It has declined overall since that time. 

Figures 54a (oil) and 54b (gas) compare maximum historic 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 54a also shows that maximum oil rates were 

significantly higher off the southeast Louisiana coast than off the Texas coast. Note that 

the pink bar in Walker Ridge is associated with the Jack #2 well test. Figure 54b

illustrates the high deepwater gas production rates relative to the rest of the GOM. Some 

of the highest gas production rates are in Mississippi Canyon. 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 2008: AMERICA’S OFFSHORE ENERGY FUTURE

72 

0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

45,000

Jan-92 Jan-93 Jan-94 Jan-95 Jan-96 Jan-97 Jan-98 Jan-99 Jan-00 Jan-01 Jan-02 Jan-03 Jan-04 Jan-05 Jan-06

Month

Barrels of Oil per Day

1,000 - 1,499 ft

1,500 - 4,999 ft

≥ 5,000 ft

Bullwinkle

Auger

Mars

Troika

Ursa

Horn Mountain

Brutus

Kepler (Na Kika)

Figure 52a. Maximum production rates for a single well within each water-depth category 

for deepwater oil production. 

0

20,000

40,000

60,000

80,000

100,000

120,000

140,000

160,000

180,000

Jan-92 Jan-93 Jan-94 Jan-95 Jan-96 Jan-97 Jan-98 Jan-99 Jan-00 Jan-01 Jan-02 Jan-03 Jan-04 Jan-05 Jan-06

Month

Thousand Cubic Feet of Gas per Day

1,000 - 1,499 ft

1,500 - 4,999 ft

≥ 5,000 ft

Diamond

Popeye

Mensa

Mensa

Mica

Figure 52b. Maximum production rates for a single well within each water-depth category 

for deepwater gas production. 
RESERVES AND P RODUCTION

73 

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

Jan-92 Jan-93 Jan-94 Jan-95 Jan-96 Jan-97 Jan-98 Jan-99 Jan-00 Jan-01 Jan-02 Jan-03 Jan-04 Jan-05 Jan-06

Month

Barrels of Oil per Day

Shallow water

Deepwater

Figure 53a. Average production rates for shallow-water and deepwater oil well 

completions. 

0

5,000

10,000

15,000

20,000

25,000

30,000

Jan-92 Jan-93 Jan-94 Jan-95 Jan-96 Jan-97 Jan-98 Jan-99 Jan-00 Jan-01 Jan-02 Jan-03 Jan-04 Jan-05 Jan-06

Month

Thousand Cubic Feet of Gas per Day

Shallow water

Deepwater

Figure 53b. Average production rates for shallow-water and deepwater gas well 

completions. 
DEEPWATER GULF OF MEXICO 2008: AMERICA’S OFFSHORE ENERGY FUTURE

74 



		



 

		





 











	





	

	 


 	









 	 

	

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Figure 54a. Maximum historic oil production rates. 

  		 		



 









	


 
 	





	

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Figure 54b. Maximum historic gas production rates. 
75 

HIGHLIGHTS AND CONCLUSIONS

Highlights from this report include 

• 54 percent of all GOM leases are located in deep water. 

• Sale 206 attracted approximately $3.7 billion in high bids – the most since 

Federal offshore leasing began in 1954. The sum of the high bids for 

deepwater blocks was 93.2 percent of the total. 

• Sale 224 was the first lease offering in the Eastern Gulf since 1988. This 

is also the first sale where the revenue sharing provisions of the Gulf of 

Mexico Energy Security Act of 2006 start immediately. 

• Sale 205 was an exceptional lease offering that attracted over $2.9 billion 

in high bids on 723 blocks – the third largest total in U.S. offshore leasing 

history. 

• A record high of 15 rigs were operating in ultra-deep water (≥5,000 ft or 

1,524 m) in 2007. 

• At least 13 new drilling rigs are 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. 

• There were eight industry-announced discoveries in 2007, including one in 

the Lower Tertiary. 

• Of the 52 discoveries in ultra-deep water, Lower Tertiary rocks were 

encountered approximately 27 percent of the time. 

• There are 125 proved deepwater fields in the GOM, representing a 44 

percent increase since the end of 2006. 

• Nonmajor companies have made more deepwater discoveries and hold 

more deepwater acreage than the major companies. 

• There were 130 producing projects in the deepwater GOM at the end of 

2007. 

• For the first time, all of the 20 most prolific producing blocks in the GOM 

are located in deep water. 

• Deepwater oil production rose about 820 percent and deepwater gas 

production increased about 1,155 percent from 1992 to 2006. 
DEEPWATER GULF OF MEXICO 2008: AMERICA’S OFFSHORE ENERGY FUTURE

76 

• Several fields associated with the Independence Hub production facility 

came online in 2007. When the hub is at full capacity, the gas production 

will represent over 10 percent of the total GOM gas production. 

• Cheyenne, one of the subsea fields tying back to Independence Hub, has 

the deepest production in the GOM to date, in a water depth of 8,960 ft 

(2,731 m). 

• The first FPSO for use in the U.S. GOM will be installed for the 

development of the Cascade and Chinook Fields in Walker Ridge, with 

first oil expected in 2010. 

• Another first for the GOM will be the installation of a ship-shape, 

dynamically positioned, disconnectable turret FPU for the Phoenix 

development in Green Canyon, with a planned production startup in the 

third quarter of 2008. 

• The Perdido Regional Development hub will produce the Great White, 

Tobago and Silvertip discoveries in Alaminos Canyon beginning in 2010. 

Once installed, the truss spar will set a new record as the deepest spar in 

over 8,000 ft (2,438 m) of water depth. 

• The Atlantis semisubmersible platform in the deepwater GOM is the 

deepest moored, floating oil and gas production facility in the world. 

• Deepwater subsea wells constitute 63 percent of the total subsea well 

population in the GOM. 

The future of deepwater GOM exploration and production remains very promising. 

Factors contributing to the increase in deepwater activity include several key discoveries 

(including those recent discoveries in the Lower Tertiary Trend), the recognition of high 

production rates, the evolution of development technologies, and a rise in oil and gas prices.

The remainder of this report combines historic leasing, drilling, development, reserve, 

and production data, revealing overall trends in deepwater activity and expectations. 

DEVELOPMENT CYCLE

There is often a considerable lag between leasing and first production. These lags are 

not unusual with complex deepwater developments. Figure 55 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 productive 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 1997. The decreasing lags for leases issued after 1997 are partially the result of 

continued lease evaluation by industry and subsea tiebacks to existing hubs. 

Figure 55 indicates that, as industry gains experience in the deepwater areas of the 

Gulf, the time between leasing and production is reduced. Noteworthy is the reduction in 

time from lease acquisition to first well drilled from the 1980’s to the 1990’s. Developments 
HIGHLIGHTS AND C ONCLUSIONS

77 

near accessible infrastructure and the use of proven development technologies can also 

reduce the lag between leasing and production. However, as new discoveries move into 

dramatically deeper water depths, and with many new discoveries being far from existing 

infrastructure, an increase in lag time between leasing and production should be 

anticipated. Conditions such as high temperature and high pressure in wells will 

complicate drilling and development operations, resulting in longer lags as well. 2.8 0.31.1 0.7 4.85.76.36.8 6.0 3.74.1 3.3 2.7 1.9 1.4 0.7 1.9 2.8 3.6 0.9 1.6 1.7 3.9 2.0 0.9 1.1 1.8 1.7 1.4 1.3 1.5 1.2 6.5 3.4 2.4 8.5 5.5 5.5 4.5 3.2 1.8 2.3 1.4 1.7 1.2 1.7 1.1 1.2

0.0

2.0

4.0

6.0

8.0

10.0

12.0

14.0

16.0

1974-751976-771978-791980-811982-831984-851986-871988-891990-911992-931994-951996-971998-992000-012002-032004-052006-072007-08

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-2005

Leases still in primary term

Figure 55. Lag from leasing to first production for producing deepwater fields. 

DRILLING THE LEASE INVENTORY

Figure 56 illustrates the magnitude of the deepwater lease inventory and industry’s 

ability to evaluate this large number of leases. The annual historic lease data from 1984 

through 2007 are indicated by the solid colored lines and depict the number of active leases, 

the number of leases drilled, and the number of leases expiring undrilled. Future projected 

values for expiring leases and leases drilled are depicted in the dotted lines. These 

projected values assume that, after the year 2007, all leases will expire unless drilled and 

that 60 untested deepwater leases will be drilled each year. 

Of the deepwater leases acquired in the 1996-2007 sales, over 3,700 are still active, with 

more than 1,870 of these active leases located in ultra-deep water (≥5,000 ft or ≥1,524 m). 

Only 272 wells have been drilled on 124 ultra-deepwater leases from these sales; 47 of these 

resulted in announced discoveries. The available deepwater drilling rig fleet, even with its 

projected additions, will challenge industry’s ability to evaluate their lease inventory. 
DEEPWATER GULF OF MEXICO 2008: AMERICA’S OFFSHORE ENERGY FUTURE

78 

0

500

1,000

1,500

2,000

2,500

3,000

3,500

4,000

4,500

5,000

1985198619871988198919901991199219931994199519961997199819992000200120022003200420052006200720082009201020112012201320142015201620172018

Year

Number of Leases

Leases drilled

Leases expiring

Active leases (as of year-end)

Figure 56. The challenge of deepwater lease evaluation. 

Other factors play a significant role in the industry’s ability to evaluate their GOM lease 

inventory, including alternative deepwater exploration and development targets 

throughout the world, capital limitations, and limited qualified personnel. 

AMERICA’S OFFSHORE ENERGY FUTURE

The deepwater GOM will play an important part in the Nation’s future energy supply. A 

large inventory of active deepwater leases is available to the industry for exploration. 

Traditional deepwater minibasin plays, and new ultra-deepwater plays near and even 

beyond the Sigsbee Escarpment, beneath thick salt canopies, and in lightly explored Lower 

Tertiary reservoirs are all being actively explored and developed. New technology is also 

advancing to facilitate ultra-deepwater activities. Likewise, growth in deepwater 

infrastructure will occur. All of these factors will ensure that the deepwater GOM will 

remain one of the world’s premier oil and gas basins. 
79 

CONTRIBUTING PERSONNEL

This report includes contributions from the following individuals: 

Pat Adkins 

Kim Altobelli 

Pat Bryars 

Carole Current 

Eric Hawkins 

Jack Irion 

Stephen Kovacs 

Deborah Miller 

Stephen Pomes 

Mike Prendergast 

Terry Rankin 

Bill Shedd 
81 

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M. Kilgour, N. Morris, and J. Moore. 2007. Archaeological and biological analysis of 

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Collett, T.S. 1995. Gas hydrate resources of the United States. In: Gautier, D.L., G.L. 

Dolton, K.L. Takahashi, and K.L. Varnes, eds. 1995 National assessment of United 

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Cranswick, D. and J. Regg. 1997. Deepwater in the Gulf of Mexico: America’s new frontier. 

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New Orleans, LA. OCS Report MMS 97-0004. 41 pp. 

Crawford, T.G., G.L. Burgess, C.J. Kinler, M.T. Prendergast, K.M. Ross, and N.K Shepard. 

2006. Estimated oil and gas reserves, Gulf of Mexico, December 31, 2003. U.S. Dept. of 

the Interior, Minerals Management Service, Gulf of Mexico OCS Region, New Orleans, 

LA. OCS Report MMS 2006-069. 48 pp. 

Donohue, K., P. Hamilton, K. Leaman, R. Leben, M. Prater, D.R. Watts, and E. Waddell. 

2006a. Exploratory study of deepwater currents in the Gulf of Mexico. Volume I: 

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Mexico OCS Region, New Orleans, LA. OCS Study MMS 2006-073. 86 pp. 

Donohue, K., P. Hamilton, K. Leaman, R. Leben, M. Prater, D.R. Watts, and E. Waddell. 

2006b. Exploratory study of deepwater currents in the Gulf of Mexico. Volume II: 

Technical report. U.S. Dept. of the Interior, Minerals Management Service, Gulf of 

Mexico OCS Region, New Orleans, LA. OCS Study MMS 2006-074. 430 pp. 

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. 2008a. Outer Continental Shelf (OCS) Central Gulf of Mexico (GOM) 

Planning Area Oil and Gas Lease Sale 206: Final Notice of Sale, Wednesday, 

February 13, 2008. 73 FR 30, pp. 8347-8353. 
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Federal Register. 2008b. Outer Continental Shelf (OCS) Eastern Gulf of Mexico (GOM) 

Planning Area Oil and Gas Lease Sale 224: Final Notice of Sale, Wednesday, 

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French, L.S., G.E. Richardson, E.G. Kazanis, T.M. Montgomery, C.M. Bohannon, and M.P. 

Gravois. 2006. Deepwater Gulf of Mexico 2006: America’s expanding frontier. U.S. 

Dept. of the Interior, Minerals Management Service, Gulf of Mexico OCS Region, New 

Orleans, LA. OCS Report MMS 2006-022. 144 pp. 

Hamilton, P., T.J. Berger, J.J. Singer, E. Waddell, J.H. Churchill, R.R. Leben, T.N. Lee, and 

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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. 

Hegna, S. and D. Gaus. 2003. Improved imaging by pre-stack depth migration of multiazimuth towed streamer seismic data. 65th European Association of Geoscientists & 

Engineers Conference and Exhibition. Expanded abstracts. C02. 

Howard, M.S. 2004. Rich azimuth marine acquisition. European Association of 

Geoscientists & Engineers Research Workshop: Advances in Seismic Acquisition 

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Kapoor, J., M. Moldevaneau, M. Egan, M O’Briain, D. Desta, I. Atakishiyev, M. Tomida, 

and L. Stewart. 2007. Subsalt imaging: The RAZ-WAZ experience. The Leading Edge. 

26(11):1414-1422. 

Kempthorne, D. 2007. Kempthorne may offer areas in the North Aleutian Basin, Central 

Gulf of Mexico for leasing; increase royalty rate for offshore oil and gas leases. Press 

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press/2007/pressdoi0109.htm

Lugo-Fernández, A., D.A. Ball, M. Gravois, C. Horrell, and J.B. Irion. 2007. Analysis of the 

Gulf of Mexico’s Veracruz-Havana route of La Flota de la Nueva España. Journal of 

Maritime Archaeology 2:24-47. 

O’Connell, J., M. Kohli, and S. Amos. 1993. Bullwinkle: A unique 3-D experiment. 

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Peterson, R.H., G.E. Richardson, C.M. Bohannon, E.G. Kazanis, T.M. Montgomery, L.D. 

Nixon, M.P. Gravois, and G.D. Klocek. 2007. Deepwater Gulf of Mexico 2007: Interim 

report of 2006 highlights. U.S. Dept. of the Interior, Minerals Management Service, 

Gulf of Mexico OCS Region, New Orleans, LA. OCS Report MMS 2007-021. 74 pp. 

Rivas, D., A. Badan, and J. Ochoa. 2005. The ventilation of the deep Gulf of Mexico. 

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Rivas, D., A. Badan, J. Sheinbaum, J. Ochoa, and J. Candela. In review. Vertical velocity 

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85 

APPENDICES

APPENDIX A. DEVELOPMENT SYSTEMS OF PRODUCTIVE DEEPWATER PROJECTS

Year of 

First 

Production 

Project Name3 Operator Block 

Water 

Depth 

(ft)4 System Type DWRR5

1979 Cognac Shell MC 194 1,023 Fixed Platform 

1984 Lena ExxonMobil MC 280 1,000 Compliant Tower 

19881 GC 29 Placid GC 29 1,540 Semisubmersible/ 

Subsea 

19881 GC 31 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 BP MC 109 1,100 Fixed Platform 

1992 Alabaster ExxonMobil MC 485 1,438 Subsea 

19931 Diamond 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/Pompano II BP VK 989 1,290 Fixed Platform/ 

Subsea 

1994 Tahoe/SE Tahoe Shell VK 783 1,500 Subsea 

19952 Cooper Newfield GB 388 2,097 Semisubmersible 

19951 Shasta 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 

19961 Rocky 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 BP 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 

19991 Dulcimer Mariner GB 367 1,120 Subsea Yes 
DEEPWATER GULF OF MEXICO 2008: AMERICA’S OFFSHORE ENERGY FUTURE

86 

Year of 

First 

Production 

Project Name3 Operator Block 

Water 

Depth 

(ft)4 System Type DWRR5

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 Marlin BP VK 915 3,236 TLP 

1999 Penn State Amerada Hess GB 216 1,450 Subsea 

1999 Pluto Mariner MC 674 2,828 Subsea Yes 

1999 Ursa Shell MC 809 3,800 TLP 

1999 Virgo TotalFinaElf VK 823 1,130 Fixed Platform Yes 

2000 Allegheny South Eni GC 298 3,307 Subsea 

2000 Black Widow Mariner EW 966 1,850 Subsea Yes 

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 Northwestern Amerada Hess GB 200 1,736 Subsea Yes 

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 Einset Shell VK 872 3,500 Subsea Yes 

2001 EW 878 Walter EW 878 1,585 Subsea Yes 

2001 Ladybug ATP GB 409 1,355 Subsea Yes 

2001 Marshall ExxonMobil EB 949 4,376 Subsea 

20011 MC 68 Walter MC 68 1,360 Subsea 

2001 Mica ExxonMobil MC 211 4,580 Subsea 

2001 Nile BP VK 914 3,535 Subsea 

2001 Oregano Shell GB 559 3,400 Subsea 

2001 Pilsner Unocal EB 205 1,108 Subsea Yes 

2001 Prince El Paso EW 1003 1,500 TLP Yes 

2001 Serrano Shell GB 516 3,153 Subsea 

20012 Typhoon10 ChevronTexaco GC 237 2,107 TLP Yes 

2002 Aconcagua TotalFinaElf MC 305 7,100 Subsea Yes 

2002 Aspen BP GC 243 3,065 Subsea Yes 

2002 North Boomvang7 Kerr-McGee EB 643 3,650 Spar Yes 
APPENDIX A 

87 

Year of 

First 

Production 

Project Name3 Operator Block 

Water 

Depth 

(ft)4 System Type DWRR5

2002 West Boomvang7 Kerr-McGee EB 642 3,678 Subsea Yes 

2002 East Boomvang7 Kerr-McGee EB 688 3,795 Subsea Yes 

2002 Camden Hills Marathon MC 348 7,216 Subsea Yes 

2002 Horn Mountain BP MC 127 5,400 Spar Yes 

2002 King BP MC 84 5,418 Subsea 

2002 King Kong Mariner GC 472 3,980 Subsea Yes 

2002 King's Peak BP DC 133 6,845 Subsea Yes 

2002 Lost Ark Noble EB 421 2,960 Subsea Yes 

2002 Madison ExxonMobil AC 24 4,856 Subsea 

2002 Manatee Shell GC 155 1,939 Subsea Yes 

2002 Nansen Kerr-McGee EB 602 3,685 Spar/subsea Yes 

2002 Navajo Kerr-McGee EB 690 4,210 Subsea Yes 

2002 Princess Shell MC 765 3,642 Subsea 

20021 Sangria Hydro GOM GC 177 1,487 Subsea Yes 

2002 Tulane Amerada Hess GB 158 1,054 Subsea Yes 

2002 Yosemite Mariner GC 516 4,150 Subsea Yes 

20032 Boris10 BHP Billiton GC 282 2,378 Subsea Yes 

2003 Dawson8 Kerr-McGee GB 669 3,152 Subsea Yes 

2003 Durango8 Kerr-McGee GB 667 3,105 Subsea Yes 

2003 East Anstey/Na Kika BP MC 607 6,590 Semisubmersible/

Subsea6

2003 Falcon Marubeni EB 579 3,638 Subsea Yes 

2003 Fourier/Na Kika BP MC 522 6,940 Semisubmersible/

Subsea6

2003 Gunnison Kerr-McGee GB 668 3,058 Spar/subsea Yes 

2003 Habanero Shell GB 341 2,015 Subsea 

2003 Herschel/Na Kika BP MC 520 6,739 Semisubmersible/

Subsea6

2003 Matterhorn TotalFinaElf MC 243 2,850 TLP Yes 

2003 Medusa Murphy MC 582 2,223 Spar Yes 

2003 North Medusa Murphy MC 538 2,095 Subsea Yes 

20032 Pardner Anadarko MC 401 1,139 Subsea Yes 

2003 Tomahawk Marubeni EB 623 3,412 Subsea Yes 

2003 Zia Devon MC 496 1,804 Subsea 

2004 Ariel/Na Kika BP MC 429 6,240 Semisubmersible/

Subsea6

2004 Coulomb/Na Kika Shell MC 657 7,591 Semisubmersible/

Subsea6 Yes 
DEEPWATER GULF OF MEXICO 2008: AMERICA’S OFFSHORE ENERGY FUTURE

88 

Year of 

First 

Production 

Project Name3 Operator Block 

Water 

Depth 

(ft)4 System Type DWRR5

2004 Devil’s Tower Eni MC 773 5,610 Spar Yes 

2004 Front Runner Murphy GC 338 3,330 Spar Yes 

2004 Glider Shell GC 248 3,440 Subsea 

2004 Hack Wilson Kerr-McGee EB 599 3,650 Subsea Yes 

20042 Harrier Pioneer EB 759 4,114 Subsea Yes 

2004 Holstein BP GC 645 4,340 Spar 

2004 Kepler/Na Kika BP MC 383 5,759 Semisubmersible/

Subsea6

2004 Llano Shell GB 386 2,340 Subsea Yes 

2004 Magnolia ConocoPhillips GB 783 4,670 TLP 

2004 Marco Polo Anadarko GC 608 4,300 TLP Yes 

2004 MC 837 Walter MC 837 1,524 Subsea 

2004 Ochre Mariner MC 66 1,144 Subsea 

20042 Raptor Pioneer EB 668 3,710 Subsea Yes 

2004 Red Hawk Kerr-McGee GB 876 5,300 Spar Yes 

2004 South Diana ExxonMobil AC 65 4,852 Subsea 

2005 Baccarat W and T 

Offshore GC 178 1,404 Subsea Yes 

2005 Citrine LLOG GC 157 2,614 Subsea Yes 

2005 GC 137 Nexen GC 137 1,168 Subsea Yes 

2005 K2 Anadarko GC 562 4,006 Subsea 

2005 Mad Dog BP GC 782 4,420 Spar 

2005 Swordfish Noble VK 962 4,677 Subsea 

2005 Triton/Goldfinger Eni MC 728 5,610 Subsea Yes 

2006 Constitution Kerr-McGee GC 680 4,970 Spar Yes 

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 Yes 

2006 Lorien Noble GC 199 2,315 Subsea 

2006 Rigel Eni MC 252 5,225 Subsea Yes 

2006 Seventeen Hands Eni MC299 5,881 Subsea Yes 

2006 SW Horseshoe Walter EB 430 2,285 Subsea Yes 

2006 Ticonderoga Kerr-McGee GC 768 5,272 Subsea Yes 

2007 Atlantis BP GC 787 7,050 Semisubmersible 

2007 Atlas-Atlas NW/ 

Ind. Hub Anadarko LL 50 8,934 FPS/Subsea9

 

2007 Cheyenne/Ind. Hub Anadarko LL 399 8,951 FPS/Subsea9 
APPENDIX A 

89 

Year of 

First 

Production 

Project Name3 Operator Block 

Water 

Depth 

(ft)4 System Type DWRR5

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/Subsea9 

2007 Merganser/Ind. Hub Anadarko AT 37 8,015 FPS/Subsea9 

2007 Mondo NW/Ind. Hub Anadarko LL 1 8,340 FPS/Subsea9 

2007 Neptune BHP Billiton GC 613 4,232 TLP 

2007 Q/Ind. Hub Statoil Hydro MC 961 7,925 FPS/Subsea9 

2007 San Jacinto/Ind. Hub Eni DC 618 7,850 FPS/Subsea9 

2007 Shenzi11 BHP Billiton GC 652 4,300 TLP/Subsea 

2007 Spiderman/Ind. Hub Anadarko DC 621 8,087 FPS/Subsea9 

2007 Vortex/Ind. Hub Anadarko AT 261 8,344 FPS/Subsea9 

2007 Wrigley Newfield MC 506 3,911 Subsea 

2008 Blind Faith ChevronTexaco MC 650 6,989 Semisubmersible 

2008 Danny Remington Oil 

& Gas GB 506 2,700 Subsea 

20081 GB 302 Walter GB 302 2,410 Subsea 

2008 MC 241 Walter MC 241 2,415 

2008 MC 161 Walter MC 161 2,924 Subsea 

2008 Mirage ATP MC 941 4,000 Spar 

20082 Phoenix10 Helix GC 237 2,679 FPU 

2008 Raton Nobel MC 248 3,290 

2008 Thunder Horse BP MC 778 6,037 Semisubmersible 

2008 Valley Forge LLOG MC 707 1,538 Subsea 

2009 Great White Shell AC 857 8,000 Spar 

2009 Isabela BP MC 562 6,500 Semisubmersible 

2009 Longhorn Eni MC 502 2,442 Subsea 

20091 Morgus ATP MC 942 3,960 Subsea 

20091 Navarro ATP GC 37 2,019 

2009 Tahiti ChevronTexaco GC 641 4,000 Spar 

2009 Telemark ATP AT 63 4,385 Subsea 

2009 Thunder Hawk Murphy MC 736 6,050 Semisubmersible 

2009 Unreleasable 

2009 Unreleasable 

2010 Cascade Petrobras WR 206 8,152 FPS0/Subsea12 

2010 Chinook Petrobras WR 469 8,831 FPS0/Subsea12 

2010 Gotcha Deep Total AC 856 7,815 
DEEPWATER GULF OF MEXICO 2008: AMERICA’S OFFSHORE ENERGY FUTURE

90 

Year of 

First 

Production 

Project Name3 Operator Block 

Water 

Depth 

(ft)4 System Type DWRR5

2010 Silvertip Shell AC 815 9,226 Subsea 

2010 Tobago Shell AC 859 9,627 Subsea 

2010 Unreleasable 

2010 Unreleasable 

2011 Unreleasable 

2011 Unreleasable 

2011 Unreleasable 

2012 Unreleasable 

2013 Puma BP GC 823 4,129 

2014 Unreleasable 

2015 Unreleasable 

AC = Alaminos Canyon AT = Atwater Valley DC = DeSoto Canyon 

EB = East Breaks EW = Ewing Bank GB = Garden Banks 

GC = Green Canyon LL = Lloyd Ridge MC = Mississippi Canyon 

VK = Viosca Knoll WR = Walker Ridge 1

 Projects off production, lease(s) expired. 

2

 Projects off production, lease(s) active. 

3 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. 

4 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). 

5 Indicates projects with one or more leases, which may be subject to thresholds, to receive Deep Water Royalty Relief 

(DWRR). 

6 Na Kika semisubmersible is located in Mississippi Canyon Block 474 in 6,378 ft (1,944 m) of water. 

7 2004 Report referred to the entire area as Boomvang. 

8 Included in 2004 Report with Gunnison. 

9 Independence Hub FPS is located in Mississippi Canyon Block 920 in 7,920 ft (2,414 m) of water. 

10 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 late 2008. The new project name is Phoenix. 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 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. 
91 

APPENDIX B. LEASE SALE RELATED INFORMATION

Table B-1. Chronological Listing of GOM Lease Sales by Sale Location and Sale Date 

Sale 

Number Sale Location Sale Date 

1 LA1 10/13/1954

1S LA 10/13/1954

2 TX 11/09/1954

3 TX, LA 7/12/1955

6 LA2 8/11/1959

7 TX, LA 2/24/1960

8 LA3 5/19/1960

9 LA 3/13/1962

10 TX, LA 3/16/1962

11 LA2 10/09/1962

12 LA2 4/28/1964

13 SUL-TX4 12/14/1965

14 LA2 3/29/1966

15 LA2 10/18/1966

16 LA 6/13/1967

17 SA-LA5 9/05/1967

18 TX 5/21/1968

19 LA2 11/19/1968

19A LA2 1/14/1969

20 SUL-LA6 5/13/1969

19B LA2 12/16/1969

21 LA2 7/21/1970

22 LA 12/15/1970

23 LA2 11/04/1971

24 LA 9/12/1972

25 LA 12/19/1972

26 TX, LA 6/19/1973

32 MAFLA7 12/20/1973

33 LA 3/28/1974

34 TX 5/29/1974

S1 TX, LA 7/30/1974

36 LA 10/16/1974

37 TX 2/04/1975

38 TX, LA 5/28/1975

38A TX, LA 7/29/1975

41 GOM 2/18/1976

44 TX, LA 11/16/1976

47 GOM 6/23/1977

45 TX, LA 4/25/1978

65 GOM 10/31/1978

Sale 

Number Sale Location Sale Date 

51 TX, LA 12/19/1978

58 GOM 7/31/1979

58A GOM 11/27/1979

A62 GOM 9/30/1980

62 GOM 11/18/1980

A66 GOM 7/21/1981

66 GOM 10/20/1981

67 GOM 2/09/1982

69 GOM 11/17/1982

69A GOM 3/08/1983

72 CGOM 5/25/1983

74 WGOM 8/24/1983

79 EGOM 1/05/1984

81 CGOM 4/24/1984

84 WGOM 7/18/1984

98 CGOM 5/22/1985

102 WGOM 8/14/1985

94 EGOM 12/18/1985

104 CGOM 4/30/1986

105 WGOM 8/27/1986

110 CGOM 4/22/1987

112 WGOM 8/12/1987

SS8 CGOM 2/24/1988

113 CGOM 3/30/1988

115 WGOM 8/31/1988

116 EGOM 11/16/1988

118 CGOM 3/15/1989

122 WGOM 8/23/1989

123 CGOM 3/21/1990

125 WGOM 8/22/1990

131 CGOM 3/27/1991

135 WGOM 8/21/1991

139 CGOM 5/13/1992

141 WGOM 8/19/1992

142 CGOM 3/24/1993

143 WGOM 9/15/1993

147 CGOM 3/30/1994

150 WGOM 8/17/1994

152 CGOM 5/10/1995

155 WGOM 9/15/1995
DEEPWATER GULF OF MEXICO 2008: AMERICA’S OFFSHORE ENERGY FUTURE

92 

Sale 

Number Sale Location Sale Date 

157 CGOM 4/24/1996

161 WGOM 9/25/1996

166 CGOM 3/05/1997

168 WGOM 8/27/1997

169 CGOM 3/18/1998

171 WGOM 8/26/1998

172 CGOM 3/17/1999

174 WGOM 8/25/1999

175 CGOM 3/15/2000

177 WGOM 8/23/2000

178-1 CGOM 3/28/2001

178-2 CGOM 8/22/2001

180 WGOM 8/22/2001

Sale 

Number Sale Location Sale Date 

181 EGOM 12/05/2001

182 CGOM 3/20/2002

184 WGOM 8/21/2002

185 CGOM 3/19/2003

187 WGOM 8/20/2003

189 EGOM 12/10/2003

190 CGOM 3/17/2004

192 WGOM 8/18/2004

194 CGOM 3/16/2005

196 WGOM 8/17/2005

197 EGOM 3/16/2005

198 CGOM 3/15/2006

200 WGOM 8/16/2006

1 Sale 1 was an oil, gas, and sulfur lease sale offshore Louisiana. 2

 These were oil and gas drainage lease sales offshore Louisiana. 

3

 Sale 8 was a salt lease sale offshore Louisiana. 

4

 Sale 13 was a sulfur and salt lease sale offshore Texas. 

5

 Sale 17 was a salt lease sale offshore Louisiana. 

6

 Sale 20 was a sulfur and salt lease sale offshore Louisiana. 

7

 Sale 32 was an oil and gas lease sale offshore Mississippi, Alabama, and Florida. 8

 Sale SS was a sulfur and salt lease sale in the CGOM. 

 LA = oil and gas lease sale offshore Louisiana (unless otherwise footnoted) 

 TX = oil and gas lease sale offshore Texas 

 GOM = oil and gas lease sale in the Gulf of Mexico 

 CGOM = oil and gas lease sale in the Central Gulf of Mexico Planning Area 

 EGOM = oil and gas lease sale in the Eastern Gulf of Mexico Planning Area 

 WGOM = oil and gas lease sale in the Western Gulf of Mexico Planning Area 

Table B-2. Lease Sale Schedule from the 5-Year Program for 2007-2012 

Sale 

Number Sale Location Sale Date 

204 WGOM 8/22/2007

205 CGOM 10/03/2007

206 CGOM 3/19/2008

2241 EGOM 3/19/2008

207 WGOM 2008

208 CGOM 2009

210 WGOM 2009

Sale 

Number Sale Location Sale Date 

213 CGOM 2010

215 WGOM 2010

216 CGOM 2011

218 WGOM 2011

2202 Mid-Atlantic 2011

222 CGOM 2012

1

 Sale 224 is not a Section 18 sale, but was mandated by Gulf of Mexico Energy Security Act of 2006. 

2

 This lease sale would only be held if the President chooses to modify the withdrawal in the area and Congress discontinues the

annual appropriations moratorium in the Mid-Atlantic. 
93 

APPENDIX C. SUBSEA COMPLETIONS

Area Block API Number Operator 

First 

Completion 

Date 

Water 

Depth 

(ft) 

AC 24 608054000501 Exxon Mobil Corporation 2/3/2002 4,856

AC 65 608054000302 Exxon Mobil Corporation 12/31/2003 4,852

AT 37 608184003405 Kerr-McGee Oil & Gas Corporation 5/26/2006 7,933

AT 349 608184004500 Anadarko Petroleum Corporation 11/24/2006 8,730

AT 426 608184001701 Mariner Energy Inc 4/3/2007 6,617

AT 574 608184006300 BHP Billiton Petroleum (GOM) Inc 7/4/2007 6,213

AT 574 608184006500 BHP Billiton Petroleum (GOM) Inc 8/15/2007 6,211

AT 575 608184006100 BHP Billiton Petroleum (GOM) Inc 10/10/2007 6,251

BA A 17 427044034500 Hydro Gulf of Mexico, LLC 8/10/2003 140

DC 133 608234000200 ATP Oil & Gas Corporation 10/15/2001 6,376

DC 618 608234001000 Eni US Operating Co Inc 7/14/2007 7,823

DC 618 608234001200 Eni US Operating Co Inc 6/6/2007 7,787

DC 620 608234000900 Anadarko Petroleum Corporation 8/5/2006 8,055

DC 621 608234000801 Anadarko Petroleum Corporation 9/21/2006 8,087

DC 621 608234001303 Anadarko Petroleum Corporation 3/27/2007 8,087

EB 112 608044015700 Eni US Operating Co Inc 5/1/1996 638

EB 117 608044016102 Apache Corporation 4/11/1996 570

EB 157 608044015200 Eni US Operating Co Inc 5/23/1996 941

EB 161 608044022600 Union Oil Company of California 7/23/2001 1,107

EB 168 608044023000 Walter Oil & Gas Corporation 12/15/2001 500

EB 205 608044021800 Union Oil Company of California 6/1/2001 1,081

EB 430 608044019202 Walter Oil & Gas Corporation 3/13/2005 2,285

EB 464 608044020901 Noble Energy Inc 10/22/2007 2,722

EB 579 608044023500 Marubeni Offshore Production (USA) Inc 11/18/2002 3,453

EB 598 608044025400 Kerr-McGee Oil & Gas Corporation 6/10/2007 3,345

EB 602 608044019001 Kerr-McGee Oil & Gas Corporation 7/15/2001 3,678

EB 602 608044022000 Kerr-McGee Oil & Gas Corporation 8/11/2001 3,678

EB 623 608044023400 Marubeni Offshore Production (USA) Inc 12/30/2002 3,412

EB 646 608044023200 Kerr-McGee Oil & Gas Corporation 4/11/2003 3,905

EB 668 608044024101 Marubeni Offshore Production (USA) Inc 5/26/2005 3,710

EB 688 608044022101 Kerr-McGee Oil & Gas Corporation 1/10/2002 3,788

EB 688 608044022400 Kerr-McGee Oil & Gas Corporation 12/13/2001 3,795

EB 690 608044022801 Kerr-McGee Oil & Gas Corporation 2/18/2002 4,202

EB 759 608044022301 Marubeni Offshore Production (USA) Inc 11/1/2004 4,114

EB 945 608044016200 Exxon Mobil Corporation 3/31/2002 4,628

EB 945 608044017700 Exxon Mobil Corporation 11/20/1999 4,638

EB 945 608044017804 Exxon Mobil Corporation 9/25/2003 4,639

EB 946 608044018000 Exxon Mobil Corporation 5/31/2000 4,657

EB 946 608044018100 Exxon Mobil Corporation 3/8/2000 4,651

EB 948 608044017601 Exxon Mobil Corporation 5/6/2001 4,376

EB 949 608044019301 Exxon Mobil Corporation 4/2/2001 4,376

EC 57 177034047100 Merit Energy Company 12/9/1984 52
DEEPWATER GULF OF MEXICO 2008: AMERICA’S OFFSHORE ENERGY FUTURE

94 

Area Block API Number Operator 

First 

Completion 

Date 

Water 

Depth 

(ft) 

EC 316 177044107400 Remington Oil and Gas Corporation 4/7/2007 201

EC 316 177044109601 Remington Oil and Gas Corporation 10/5/2007 201

EC 335 177044030300 Energy XXI GOM LLC 7/15/1976 272

EC 347 177044101300 Apache Corporation 1/3/2001 291

EC 374 177044101700 Energy Resource Technology Inc 7/17/2002 425

EC 378 608074015700 El Paso E&P Company LP 1/27/1997 495

EI 106 177094121001 Devon Energy Production Company LP 7/20/1998 40

EI 294 177104126801 B T Operating Co 10/6/1991 214

EI 346 177104160500 Apache Corporation 5/10/2006 307

EI 349 177104100500 NCX Company LLC 11/23/1990 337

EI 386 177104147500 Tarpon Offshore LP 2/24/2002 417

EI 390 177104149001 Walter Oil & Gas Corporation 2/11/2004 377

EI 391 177104160200 Remington Oil and Gas Corporation 6/22/2006 398

EI 395 177104157700 Walter Oil & Gas Corporation 3/3/2004 517

EW 868 608104011502 Walter Oil & Gas Corporation 9/21/2004 685

EW 871 608104011000 Walter Oil & Gas Corporation 11/13/2000 932

EW 871 608104011300 Walter Oil & Gas Corporation 4/13/2001 724

EW 878 608105009500 Walter Oil & Gas Corporation 7/26/2000 1,523

EW 878 608105009601 Walter Oil & Gas Corporation 9/25/2000 1,523

EW 878 608105010001 Walter Oil & Gas Corporation 5/13/2007 1,559

EW 913 608104011700 Walter Oil & Gas Corporation 10/13/2004 685

EW 917 608105006500 Marathon Oil Company 4/8/1998 1,195

EW 921 608105007903 Eni US Operating Co Inc 3/29/1999 1,696

EW 921 608105008104 Eni US Operating Co Inc 8/16/2002 1,692

EW 921 608105009801 Eni US Operating Co Inc 1/25/2005 1,712

EW 948 608104012902 Energy XXI GOM LLC 2/10/2007 730

EW 963 608105006000 Marathon Oil Company 5/25/1998 1,740

EW 963 608105006800 Marathon Oil Company 6/29/1998 1,758

EW 966 608104010001 Mariner Energy Inc 5/12/2000 1,853

EW 989 608104013302 W & T Offshore Inc 2/2/2007 523

EW 991 608104009300 Walter Oil & Gas Corporation 7/6/1996 765

EW 1006 608105004102 Walter Oil & Gas Corporation 3/1/2002 1,884

EW 1006 608104012100 Walter Oil & Gas Corporation 6/23/2003 1,851

EW 1006 608104012200 Walter Oil & Gas Corporation 8/27/2003 1,854

GB 108 608074020600 Kerr-McGee Oil & Gas Corporation 7/17/1999 619

GB 117 608074013500 Flextrend Development Company LLC 7/16/1996 922

GB 117 608074014901 Flextrend Development Company LLC 5/5/1997 924

GB 139 608074064501 W & T Offshore Inc 11/25/2002 550

GB 152 608074020800 Walter Oil & Gas Corporation 7/7/1999 619

GB 158 608074021702 Hess Corporation 1/28/2002 1,050

GB 161 608074015801 McMoran Oil & Gas LLC 9/20/1999 972

GB 161 608074017500 McMoran Oil & Gas LLC 11/17/1999 970

GB 184 608074065100 Offshore Shelf LLC 7/12/2000 698

GB 195 608074082800 Mariner Energy Inc 9/5/2007 690

GB 200 608074021100 Hess Corporation 11/29/2000 1,736
APPENDIX C 

95 

Area Block API Number Operator 

First 

Completion 

Date 

Water 

Depth 

(ft) 

GB 201 608074023701 Hess Corporation 11/2/2002 1,736

GB 201 608074027002 Hess Corporation 9/5/2005 1,736

GB 205 608074027100 Nexen Petroleum USA Inc 8/5/2005 1,330

GB 215 608074020101 Hess Corporation 2/19/2001 1,457

GB 215 608074017202 Hess Corporation 12/30/2002 1,464

GB 216 608074081901 Hess Corporation 5/22/1999 1,456

GB 216 608074022600 Hess Corporation 6/20/2001 1,481

GB 235 608074010600 W & T Offshore Inc 11/10/1994 785

GB 302 608074082700 Walter Oil & Gas Corporation 1/19/2006 2,410

GB 341 608074025401 Shell Offshore Inc 6/14/2003 2,013

GB 341 608074019107 Shell Offshore Inc 10/15/2007 2,006

GB 385 608074023102 Shell Offshore Inc 4/13/2004 2,610

GB 409 608074016300 ATP Oil & Gas Corporation 5/12/2001 1,355

GB 409 608074063501 ATP Oil & Gas Corporation 9/21/2006 1,360

GB 472 608074020903 Shell Offshore Inc 10/21/2001 3,380

GB 506 608074028202 Remington Oil and Gas Corporation 5/15/2007 2,715

GB 506 608074028601 Remington Oil and Gas Corporation 8/13/2007 2,821

GB 516 608074022402 Shell Offshore Inc 11/21/2001 3,400

GB 559 608074019901 Shell Offshore Inc 8/3/2001 3,400

GB 559 608074022103 Shell Offshore Inc 9/2/2001 3,400

GB 559 608074023901 Shell Offshore Inc 3/18/2003 3,393

GB 602 608074014401 Shell Offshore Inc 12/28/1999 3,708

GB 602 608074019401 Shell Offshore Inc 8/16/1999 3,693

GB 602 608074019301 Shell Offshore Inc 2/27/2001 3,708

GB 625 608074066006 Kerr-McGee Oil & Gas Corporation 4/27/2006 2,965

GB 667 608074065803 Kerr-McGee Oil & Gas Corporation 5/20/2003 3,105

GB 668 608074067500 Kerr-McGee Oil & Gas Corporation 1/3/2006 3,137

GB 877 608074023002 Kerr-McGee Oil & Gas Corporation 8/8/2003 5,334

GB 877 608074024402 Kerr-McGee Oil & Gas Corporation 9/6/2003 5,334

GC 20 608114021300 Shell Gulf of Mexico Inc 12/10/1999 880

GC 50 608114038500 Nexen Petroleum USA Inc 5/5/2004 922

GC 50 608114043400 Nexen Petroleum USA Inc 10/5/2005 690

GC 60 608114020101 Mobil Oil Exploration & Production 6/22/1996 868

GC 112 608114024501 Shell Offshore Inc 10/10/1999 1,968

GC 113 608115012701 Marubeni Oil & Gas (USA) Inc 9/1/1999 2,045

GC 113 608115013100 Marubeni Oil & Gas (USA) Inc 7/17/1999 1,968

GC 116 608115008600 Shell Offshore Inc 1/11/1996 2,046

GC 116 608115012200 Shell Offshore Inc 2/14/1998 2,046

GC 137 608114039202 Nexen Petroleum USA Inc 3/31/2004 1,168

GC 155 608114031100 Shell Offshore Inc 6/23/2002 1,939

GC 157 608114037100 LLOG Exploration Offshore Inc 4/25/2005 2,614

GC 157 608114043801 LLOG Exploration Offshore Inc 11/11/2005 2,614

GC 157 608114043900 LLOG Exploration Offshore Inc 5/8/2006 2,614

GC 195 608114037603 Deep Gulf Energy LP 7/11/2006 1,844

GC 200 608114021800 Shell Offshore Inc 11/10/1997 2,670
DEEPWATER GULF OF MEXICO 2008: AMERICA’S OFFSHORE ENERGY FUTURE

96 

Area Block API Number Operator 

First 

Completion 

Date 

Water 

Depth 

(ft) 

GC 200 608114021600 Shell Offshore Inc 12/7/1997 2,670

GC 200 608114020501 Shell Offshore Inc 6/29/1998 2,670

GC 200 608114021901 Shell Offshore Inc 2/27/1999 2,670

GC 200 608114028900 Shell Offshore Inc 1/25/2001 2,672

GC 237 608114024100 Energy Resource Technology Inc 6/13/2001 2,025

GC 237 608114024704 Energy Resource Technology Inc 6/10/2003 1,982

GC 237 608114025203 Energy Resource Technology Inc 9/6/2005 1,987

GC 243 608114034000 Nexen Petroleum USA Inc 12/28/2002 3,048

GC 243 608114041600 Nexen Petroleum USA Inc 7/4/2004 3,050

GC 243 608114045701 Nexen Petroleum USA Inc 11/25/2006 2,980

GC 243 608114027608 Nexen Petroleum USA Inc 7/19/2007 3,048

GC 244 608114021701 Marathon Oil Company 3/2/1998 2,670

GC 254 608115009001 Eni US Operating Co Inc 8/16/2000 3,234

GC 254 608115008001 Eni US Operating Co Inc 11/4/2001 3,226

GC 282 608114030804 Energy Resource Technology Inc 11/22/2002 2,386

GC 282 608114033701 Energy Resource Technology Inc 8/1/2003 2,370

GC 297 608115009400 Eni US Operating Co Inc 9/11/2001 3,308

GC 298 608114042105 Eni US Operating Co Inc 5/20/2006 3,307

GC 338 608114042400 Walter Oil & Gas Corporation 1/11/2007 3,278

GC 473 608114027302 Eni US Operating Co Inc 3/20/2006 3,926

GC 516 608114030101 Eni US Operating Co Inc 10/2/2001 3,839

GC 518 608114039401 Anadarko Petroleum Corporation 7/18/2006 3,993

GC 562 608114036403 Anadarko Petroleum Corporation 4/22/2005 4,006

GC 562 608114033605 Anadarko Petroleum Corporation 7/3/2006 3,925

GC 596 608114035704 Chevron USA Inc 7/3/2007 4,029

GC 640 608114033003 Chevron USA Inc 4/25/2007 4,017

GC 743 608114041200 BP Exploration & Production Inc 4/28/2006 6,830

GC 743 608114040102 BP Exploration & Production Inc 3/18/2007 6,824

GI 32 177174011700 GOM Shelf LLC 3/9/1980 98

HI A 308 427114085500 Tarpon Operating & Development LLC 8/16/2004 212

HI A 309 427114070100 SPN Resources LLC 1/24/1995 213

HI A 336 427114086100 Tarpon Operating & Development LLC 12/31/2004 235

HI A 343 427114082501 Tarpon Operating & Development LLC 2/26/2005 257

HI A 345 427114083000 Seneca Resources Corporation 7/26/2003 238

HI A 378 427114075700 Offshore Shelf LLC 7/28/1996 360

HI A 466 427094116100 Remington Oil and Gas Corporation 6/23/2007 175

HI A 531 427094106900 McMoran Oil & Gas LLC 8/25/1999 194

HI A 531 427094109100 McMoran Oil & Gas LLC 3/24/2001 194

HI A 540 427094115700 Walter Oil & Gas Corporation 1/4/2006 220

HI A 544 427094113200 Energy Resource Technology Inc 9/6/2003 234

HI A 573 427094053700 Apache Corporation 9/17/1980 350

LL 1 608244000401 Anadarko Petroleum Corporation 2/11/2007 8,340

LL 5 608244000200 Anadarko Petroleum Corporation 1/15/2007 8,807

LL 50 608244000101 Anadarko Petroleum Corporation 12/20/2006 8,953

LL 309 608184005200 Anadarko Petroleum Corporation 11/17/2006 8,774
APPENDIX C 

97 

Area Block API Number Operator 

First 

Completion 

Date 

Water 

Depth 

(ft) 

LL 399 608244000600 Anadarko Petroleum Corporation 10/13/2006 8,960

MC 28 608164018600 BP Exploration & Production Inc 4/21/1995 1,290

MC 28 608174051900 BP Exploration & Production Inc 6/30/1996 1,853

MC 28 608174052000 BP Exploration & Production Inc 4/24/1998 1,853

MC 28 608174051600 BP Exploration & Production Inc 8/16/1996 1,853

MC 28 608174051704 BP Exploration & Production Inc 6/26/2001 1,853

MC 66 608174100101 Mariner Energy Inc 9/3/2003 1,144

MC 68 608174088600 Walter Oil & Gas Corporation 6/3/2000 1,337

MC 72 608174051800 BP Exploration & Production Inc 2/14/1997 1,853

MC 72 608174051500 BP Exploration & Production Inc 4/27/1996 1,853

MC 84 608174096500 BP Exploration & Production Inc 2/5/2003 5,418

MC 85 608174090100 BP Exploration & Production Inc 6/15/2001 5,173

MC 85 608174090801 BP Exploration & Production Inc 5/13/2001 5,317

MC 148 608174109900 Apache Corporation 9/1/2006 550

MC 161 608174106702 Walter Oil & Gas Corporation 8/23/2005 2,924

MC 167 608174088802 Exxon Mobil Corporation 12/29/2004 4,318

MC 211 608174088900 Exxon Mobil Corporation 11/22/2000 4,317

MC 211 608174099200 Exxon Mobil Corporation 8/28/2002 4,318

MC 217 608174090900 ATP Oil & Gas Corporation 1/7/2002 6,390

MC 217 608174091001 ATP Oil & Gas Corporation 8/22/2001 6,420

MC 241 608174111401 Walter Oil & Gas Corporation 4/28/2007 2,427

MC 248 608174109201 Noble Energy Inc 10/13/2007 3,368

MC 278 608174091504 Walter Oil & Gas Corporation 5/24/2005 560

MC 292 608174050900 Noble Energy Inc 5/25/1999 3,405

MC 292 608174083201 Noble Energy Inc 8/25/1999 3,393

MC 292 608174083301 Noble Energy Inc 9/24/1999 3,393

MC 299 608174091202 Eni US Operating Co Inc 5/13/2005 5,881

MC 305 608174083400 ATP Oil & Gas Corporation 7/12/2002 7,073

MC 305 608174091700 ATP Oil & Gas Corporation 5/1/2002 7,096

MC 305 608174098201 ATP Oil & Gas Corporation 8/15/2002 7,067

MC 305 608174087501 ATP Oil & Gas Corporation 9/11/2002 7,001

MC 321 608174089100 Walter Oil & Gas Corporation 9/15/2000 567

MC 322 608174093800 Walter Oil & Gas Corporation 7/8/2001 680

MC 348 608174086801 ATP Oil & Gas Corporation 5/31/2002 7,202

MC 348 608174084801 ATP Oil & Gas Corporation 2/15/2002 7,209

MC 354 608174044700 Exxon Mobil Corporation 7/5/1993 1,460

MC 355 608174044900 Exxon Mobil Corporation 5/29/1993 1,460

MC 355 608174044800 Exxon Mobil Corporation 9/11/1993 1,458

MC 355 608174084301 Exxon Mobil Corporation 7/2/1999 1,458

MC 357 608174053801 Newfield Exploration Company 2/25/1998 445

MC 383 608174094702 BP Exploration & Production Inc 8/26/2002 5,739

MC 383 608174094601 BP Exploration & Production Inc 8/11/2002 5,735

MC 400 608174096101 Apache Corporation 6/13/2005 1,139

MC 429 608174051300 BP Exploration & Production Inc 10/23/2002 6,240

MC 429 608174095402 BP Exploration & Production Inc 2/2/2003 6,101
DEEPWATER GULF OF MEXICO 2008: AMERICA’S OFFSHORE ENERGY FUTURE

98 

Area Block API Number Operator 

First 

Completion 

Date 

Water 

Depth 

(ft) 

MC 429 608174084404 BP Exploration & Production Inc 2/19/2003 6,134

MC 506 608174106101 Newfield Exploration Company 1/20/2007 3,682

MC 520 608174054601 BP Exploration & Production Inc 7/1/2002 6,738

MC 522 608174096900 BP Exploration & Production Inc 11/26/2002 6,932

MC 522 608174097000 BP Exploration & Production Inc 12/16/2002 6,934

MC 522 608174085802 BP Exploration & Production Inc 12/31/2002 6,940

MC 522 608174110100 BP Exploration & Production Inc 7/26/2007 6,933

MC 538 608174101301 Murphy Exploration & Production Co USA 2/16/2005 1,849

MC 608 608174098400 BP Exploration & Production Inc 7/22/2002 6,623

MC 657 608174087203 Shell Offshore Inc 5/1/2004 7,565

MC 661 608174083900 Pogo Producing Company 11/13/2001 854

MC 674 608174054404 Mariner Energy Inc 12/29/1999 2,710

MC 674 608174105502 Mariner Energy Inc 3/22/2005 2,799

MC 686 608174099600 Shell Offshore Inc 3/12/2003 5,318

MC 686 608174110901 Shell Offshore Inc 4/21/2007 5,377

MC 687 608174054000 Shell Offshore Inc 11/20/1998 5,292

MC 705 608174086001 Pogo Producing Company 12/24/2001 854

MC 707 608174103902 LLOG Exploration Offshore Inc 9/11/2007 1,538

MC 711 608174089600 ATP Oil & Gas Corporation 8/11/2006 2,951

MC 711 608174111901 ATP Oil & Gas Corporation 7/26/2007 2,950

MC 730 608174054200 Shell Offshore Inc 11/4/1997 5,295

MC 755 608174057300 ATP Oil & Gas Corporation 12/11/2005 2,975

MC 755 608174106203 ATP Oil & Gas Corporation 3/23/2007 2,904

MC 762 608174111201 Shell Offshore Inc 7/24/2007 2,902

MC 763 608174047700 Shell Offshore Inc 8/8/1997 2,945

MC 764 608174058701 BP Exploration & Production Inc 4/6/2000 3,283

MC 765 608174100501 Shell Offshore Inc 7/18/2003 3,642

MC 765 608174098802 Shell Offshore Inc 12/29/2003 3,642

MC 766 608174096302 Shell Offshore Inc 9/11/2003 3,637

MC 771 608174102404 Eni US Operating Co Inc 1/20/2005 5,413

MC 772 608174099100 Eni US Operating Co Inc 3/16/2005 5,380

MC 777 608174110400 BP Exploration & Production Inc 4/12/2007 5,610

MC 806 608174049501 Shell Offshore Inc 1/3/2005 2,945

MC 806 608174099002 Shell Offshore Inc 4/2/2007 3,003

MC 807 608174038800 Shell Offshore Inc 3/25/1996 2,956

MC 822 608174098601 BP Exploration & Production Inc 11/10/2004 6,034

MC 837 608174092401 Walter Oil & Gas Corporation 6/22/2001 1,524

MC 898 608174106000 Shell Offshore Inc 10/31/2006 4,036

MC 899 608174091600 Shell Offshore Inc 8/13/2001 4,393

MC 899 608174058002 Shell Offshore Inc 7/24/2001 4,393

MC 899 608174087807 Shell Offshore Inc 10/31/2001 4,389

MC 934 608174083501 Shell Offshore Inc 11/13/1999 3,875

MC 934 608174083700 Shell Offshore Inc 9/1/2001 3,875

MC 934 608174083601 Shell Offshore Inc 3/10/2000 3,875

MC 935 608174106800 Shell Offshore Inc 2/4/2006 3,853
APPENDIX C 

99 

Area Block API Number Operator 

First 

Completion 

Date 

Water 

Depth 

(ft) 

MC 935 608174107300 Shell Offshore Inc 2/28/2006 3,851

MC 961 608174106601 Hydro Gulf of Mexico, LLC 10/10/2007 7,925

MP 149 177254058901 Walter Oil & Gas Corporation 9/6/1994 220

MP 150 177254069600 Walter Oil & Gas Corporation 12/3/2000 245

MP 185 177244091901 Magnum Hunter Production Inc 9/19/2006 155

MP 187 177244092500 Magnum Hunter Production Inc 11/2/2006 142

MP 200 177244092200 Magnum Hunter Production Inc 5/3/2007 163

MP 211 177244093100 Magnum Hunter Production Inc 5/20/2007 178

MP 232 177244093000 Magnum Hunter Production Inc 2/7/2007 178

MP 241 177244092900 Magnum Hunter Production Inc 6/16/2007 186

MP 260 177244081400 Devon Energy Production Company LP 4/26/1999 315

MP 263 177244089600 Magnum Hunter Production Inc 3/31/2003 280

MP 280 177244091200 Dominion Exploration & Production Inc 2/9/2005 307

MU 806 427024024500 Apache Corporation 11/30/1995 164

PN 996 427134009900 Prime Offshore L L C 11/14/2003 159

PN A 9 427134050200 Newfield Exploration Company 11/5/2003 201

SM 116 177084094000 Remington Oil and Gas Corporation 1/9/2006 196

SM 195 177084093200 Tarpon Operating & Development LLC 2/25/2005 300

SP 32 177212050500 Devon Louisiana Corporation 6/12/2002 115

SS 321 177124057000 ATP Oil & Gas Corporation 5/29/1997 323

ST 177 177154007800 Chevron USA Inc 11/6/1976 144

ST 219 177164033700 Walter Oil & Gas Corporation 3/9/2006 158

ST 248 177164029700 Union Oil Company of California 6/4/2002 178

ST 260 177164029501 Walter Oil & Gas Corporation 5/9/2002 288

ST 288 177164033500 Mariner Energy Inc 2/2/2006 408

VK 738 608164036601 McMoran Oil & Gas LLC 9/24/2000 809

VK 783 608164013401 Shell Offshore Inc 4/8/1991 1,494

VK 783 608164022400 Shell Offshore Inc 12/20/1996 1,451

VK 783 608164022501 Shell Offshore Inc 1/22/1997 1,451

VK 783 608164022301 Shell Offshore Inc 12/20/1996 1,450

VK 783 608164044900 Shell Offshore Inc 10/8/2007 1,142

VK 784 608164023200 Shell Offshore Inc 6/30/1996 1,750

VK 825 608164033201 Kerr-McGee Oil & Gas Corporation 10/16/1998 1,722

VK 825 608164034400 Kerr-McGee Oil & Gas Corporation 8/29/1999 1,711

VK 862 608164021600 Walter Oil & Gas Corporation 11/15/1995 1,067

VK 862 608164044800 Walter Oil & Gas Corporation 7/12/2007 1,060

VK 862 608164044700 Walter Oil & Gas Corporation 7/10/2007 1,060

VK 869 608164042300 Kerr-McGee Oil & Gas Corporation 1/1/2004 2,033

VK 869 608164043000 Kerr-McGee Oil & Gas Corporation 12/29/2004 2,423

VK 873 608164033601 Shell Offshore Inc 12/29/2001 3,463

VK 914 608164028403 BP Exploration & Production Inc 3/15/2001 3,535

VK 915 608164040200 BP Exploration & Production Inc 4/17/2002 3,460

VK 915 608164038301 BP Exploration & Production Inc 8/30/2004 3,460

VK 917 608164040001 Noble Energy Inc 10/4/2007 4,370

VK 961 608164043100 Noble Energy Inc 8/24/2004 4,677
DEEPWATER GULF OF MEXICO 2008: AMERICA’S OFFSHORE ENERGY FUTURE

100 

Area Block API Number Operator 

First 

Completion 

Date 

Water 

Depth 

(ft) 

VK 962 608164039901 Noble Energy Inc 8/24/2004 4,677

VK 986 608164022800 Walter Oil & Gas Corporation 12/23/1995 893

VK 986 608164040800 Walter Oil & Gas Corporation 5/26/2002 895

VK 1003 608164044600 Newfield Exploration Company 5/6/2007 4,858

VR 116 177054107201 W & T Offshore Inc 4/19/1998 55

VR 332 177064091100 Forest Oil Corporation 10/19/2002 223

WC 593 177024182300 Newfield Exploration Company 10/29/2006 253

WC 638 177024116900 McMoran Oil & Gas LLC 11/6/1998 373

WD 45 177190038402 Nexen Petroleum USA Inc 12/8/1981 50

WD 107 177194056400 Walter Oil & Gas Corporation 1/2/1996 222

WD 107 177194058000 Walter Oil & Gas Corporation 2/18/1995 250

WD 107 177194082500 Walter Oil & Gas Corporation 11/4/2006 192
101 

APPENDIX D. 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 

1987 310 17 328 4,481 44 4,525 

1988 288 13 301 4,539 38 4,577
DEEPWATER GULF OF MEXICO 2008: AMERICA’S OFFSHORE ENERGY FUTURE

102 

Year 

ShallowWater Oil 

(MMbbl) 

Deepwater 

Oil 

(MMbbl) 

Total GOM 

Oil 

(MMbbl) 

ShallowWater Gas 

(Bcf) 

Deepwater 

Gas 

(Bcf) 

Total GOM 

Gas 

(Bcf) 

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 243 315 558 3,879 1,178 5,057

2002 219 348 567 3,237 1,312 4,549

2003 211 350 561 3,000 1,425 4,425

2004 187 348 535 2,604 1,396 4,001

2005 141 326 467 1,960 1,190 3,150

2006 130 343 473 1,818 1,095 2,913
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.