ON COVER — The cover features an artist's rendering of the Thunder Horse project and its

associated development and production systems. Note the semisubmersible processing, drilling,

and quarters platform in the center of the picture. (Image courtesy of BP Exploration Inc. and

Exxon Mobil Corporation)
OCS Report

MMS 2002-021

Deepwater Gulf of Mexico 2002:

America’s Expanding Frontier

Richie D. Baud

Robert H. Peterson

G. Ed Richardson

Leanne S. French

Jim Regg

Tara Montgomery

T. Scott Williams

Carey Doyle

Mike Dorner

U.S. Department of the Interior

Minerals Management Service New Orleans

Gulf of Mexico OCS Region April 2002

iii

Contents Page

Preface ix

Introduction 1

Definitions 2

Expanding Frontier 4

Seismic Activity 5

Leasing Activity 10

Environmental Activity 15

Floating Production, Storage, and Offloading Systems 18

Challenges and Rewards 22

Leasing 31

Bidding and Leasing Trends 31

Lease Ownership 35

Drilling and Development 45

Drilling Activity 45

Development Systems 57

Subsea Trends 63

Pipelines 67

Reserves and Production 71

Discoveries 71

Reserve Potential 77

Production Trends 80

Companies and Production 83

Production Rates 88

Summary and Conclusions 98

Development Cycle 98

Drilling the Lease Inventory 104

Expanding Frontier 107

Contributing Personnel 110

References 111

Appendix A - Announced Deepwater Discoveries and Fields

 (sorted by project name) 113

Appendix B - Announced Deepwater Discoveries and Fields

 (sorted by discovery date) 117

Appendix C - Companies Defined as Majors in this Report 121

Appendix D - Subsea Completions 123

Appendix E - Deepwater Studies Program 128

Appendix F - Average Annual GOM Oil and Gas Production 131

Appendix G - Number of Deepwater Production Facilities Installed Each Year

 (including plans through 2004) 133
iv

Figures Page

1. The Gulf of Mexico OCS is divided into Western, Central, and Eastern Planning

Areas. 3

2. Progressive deepwater 3-D seismic permit coverage. 6

3. Deepwater Gulf of Mexico 3-D seismic permit coverage from 1992 through 2001. 8

4. New deepwater plays in the Gulf of Mexico. 9

5. Deepwater leases issued in the Gulf of Mexico. 11

6. Active leases in the Gulf of Mexico. 13

7. Total active leases by year and water-depth range. 14

8. Environmental and deepwater administrative features. 16

9. Grid EA’s completed and in progress. 17

10. ROV surveys including known chemosynthetic communities. 19

11. Artist’s rendition of an FPSO system with subsea trees and flowlines. 20

12. FPSO EIS area of consideration and deferral FPSO proposal areas. 21

13. Deepwater discoveries in the Gulf of Mexico. 23

14. Ownership of deepwater discoveries. 25

15. Estimated volumes of 53 proved deepwater fields. 26

16. Onshore service bases for existing deepwater structures. 27

17. Onshore service bases for pending deepwater plans. 28

18. Oil and gas pipelines with diameters greater than or equal to 20 inches. 29

19. Deepwater oil and gas pipelines in the Gulf of Mexico. 30

20. Number of leases issued each year subdivided by DWRRA water-depth

categories. 32

21. Percentage of leases issued each year within each DWRRA water-depth category. 33

22a. Number of leases bid in each deepwater interval. 34

22b. Total bid amounts in deepwater intervals. 34

22c. Average bid amount per block in deepwater intervals. 34

23. Rejected shallow- and deepwater Gulf of Mexico bids. 36

24. Ownership of deepwater leases. 38

25. Leasing impact of recent company mergers. 40

26. Anticipated lease expirations in the Gulf of Mexico. 42

27a. The Ocean Confidence, a Class III, dynamically positioned, submersible drilling rig. 46

27b. The Deepwater Pathfinder, a dynamically positioned drillship. 47

28. Average number of rigs drilling in the deepwater Gulf of Mexico. 48

29. Approximate number of deepwater rigs (GOM and worldwide) subdivided

according to their maximum water-depth capabilities. 48

30. All deepwater wells drilled in the Gulf of Mexico, subdivided by water depth. 49

31. Ultra-deepwater (5,000 ft or greater) wells drilled in the Gulf of Mexico. 49

32. Deepwater exploratory wells drilled in the Gulf of Mexico, subdivided by water

depth. 51

33. Deepwater development wells drilled in the Gulf of Mexico, subdivided by water

depth. 51

34. Deepwater exploratory wells drilled in the Gulf of Mexico. 52

35. Deepwater development wells drilled in the Gulf of Mexico. 54
v

Figures – continued Page

36. Deepwater EP’s, DOCD’s, and DWOP’s received in the Gulf of Mexico since

1992. 56

37. Maximum wellbore true vertical depth (TVD) drilled in the total GOM each year. 58

38. Maximum water depth drilled each year. 58

39. Deepwater development systems. 59

40. Three different versions of TLP’s: a SeaStar installed at ChevronTexaco’s

Typhoon field, a MOSES installed at El Paso’s Prince field, and a conventional

TLP installed at Shell’s Ursa field. 61

41. Two competing versions of the production spar. 62

42. GOM deepwater production facilities installed each year (including plans through

2004). 64

43. Mensa Project subsea equipment layout. 65

44a. Number of subsea completions each year. 66

44b. Maximum water depths of subsea completions each year. 66

45. Number of shallow- and deepwater subsea completions each year. 68

46. Length of subsea tiebacks. 69

47. Water depth of subsea tiebacks. 69

48. Approved deepwater oil and gas pipelines (a) less than or equal to 12 inches in

diameter, and (b) greater than 12 inches in diameter. 70

49. Proved reserve additions. 72

50. Proved and unproved reserve additions. 73

51. Average field size using proved and unproved reserves. 74

52. Number of deepwater field discoveries and resulting number of producing fields. 75

53. Number of deepwater field discoveries and new hydrocarbons found (MMS

reserves, MMS resources, and industry-announced discoveries). 76

54. BOE added (reserves, known resources, and industry-announced discoveries). 78

55. Creaming curve for shallow- and deepwater areas of the GOM (includes reserves,

resources, and industry-announced discoveries). 79

56. Reserves and future discovery volumes in the deepwater GOM. 79

57. Relative volume of production from each Gulf of Mexico lease. 81

58. Comparison of average annual shallow- and deepwater (a) oil production and (b)

gas production. 84

59. Contributions from subsea completions toward total deepwater (a) oil production

and (b) gas production. 85

60. Comparison of major companies and nonmajor companies in terms of deepwater

(a) oil production and (b) gas production. 86

61. Percentage of deepwater (a) oil production and (b) gas production from nonmajor

oil and gas companies. 87

62. Contributions from each major oil company toward total deepwater (a) oil

production and (b) gas production. 89

63. Maximum production rates for a single well within each water-depth category for

deepwater (a) oil production and (b) gas production. 90

64. Maximum historical oil production rates for Gulf of Mexico wells. 91

65. Maximum historical gas production rates for Gulf of Mexico wells. 92
vi

Figures – continued Page

66. Maximum oil production rates for Gulf of Mexico wells that produced over 5,000

BOPD. 94

67. Maximum gas production rates for Gulf of Mexico wells that produced over

75,000 MCFPD. 96

68. Deepwater projects that began production in 2001 and those expected to begin

production by yearend 2005. 99

69. Deepwater lease activity and oil prices. 100

70a. Lag from leasing to first well for producing deepwater fields. 102

70b. Lag from leasing to qualifying for producing deepwater fields. 102

70c. Lag from leasing to first production for producing deepwater fields. 102

71. Lag from leasing to first well, lease qualification, and first field production

for all drilled deepwater wells. 103

72. Activity on deepwater leases. 105

73a. Relationship between number of leases bid and number of leases drilled, 1974-

1991. 106

73b. Relationship between number of leases bid and number of resulting producing

leases, 1974-1991. 106

73c. Relationship between number of leases drilled and number of resulting producing

leases, 1974-1991. 106

73d. Relationship between number of qualifying leases and number of resulting

producing leases, 1974-1991. 106

74. Anticipated effect of rig constraints on lease evaluations. 108
vii

Tables Page

1. Completed and pending grid PEA’s within the Central and Western

Planning Areas of the Gulf of Mexico. 15

2. Development Systems of Productive Deepwater GOM Fields. 60

3. Top 20 producing blocks for the years 2000–2001. 80

ix

Preface 

This publication is the third that Minerals Management Service (MMS) has released describing

the astonishing levels of deepwater (greater than or equal to 1,000-foot depths) oil and gas

activity in the Gulf of Mexico (GOM). Earlier versions of the publication in 1998 and 2000

chronicled the emergence of massive exploration and development in the GOM. A certain level

of maturity has now been reached—the deepwater GOM is an expanding frontier.

While only 16 deepwater projects were on production in early 1997, this number grew to 51 by

the end of 2001. A record 14 deepwater projects initiated production during 2001, and another

13 are projected to begin in 2002. The MMS estimates that, by the end of 2001, deepwater oil

production had risen 500 percent and gas production had risen 550 percent since 1995. Fiftynine percent of all oil production in the Gulf now comes from the deepwater.

Many different types of production-system technologies are now in use. There is a strong

reliance on subsea tiebacks in deepwater and, surprisingly, in shallow water, with 38 subsea

projects now producing throughout the GOM and more than 200 wells installed to date. With

this reliance on subsea production technology and a growth of the pipeline infrastructure,

operators have established numerous production hubs to support this expanding frontier. The

Auger tension-leg platform (TLP), installed in 1994, now supports 3 separate subsea tieback

developments – Macaroni (1999), Serrano (2001) and Oregano (2001). Shell began production

from Brutus in 2001, the seventh TLP in the GOM. Installation of the unique class of small

TLP’s at the Typhoon and Prince fields shows the continued progression of floating productionsystem technology. The installation of the world’s first truss spars at the Boomvang and Nansen

fields, and the ongoing construction of five more, further demonstrates this progression.

In a sense, production of oil and gas is only now hitting its stride, and large increases in

production are on the horizon for 2004-2006. Estimates by MMS of the substantial resource

potential in deepwater will likely grow again when a new resource assessment is released.

Ultra-deepwater activity (greater than or equal to 5,000-foot depths) continues to accelerate;

Unocal’s announcement of a significant discovery at their world-record well on the Trident

project (9,727 feet of water) serves to accentuate the unfolding potential of the deepwater GOM.

Chris C. Oynes

Regional Director

Minerals Management Service

1

Introduction 

The deepwater Gulf of Mexico (GOM) is an important oil and gas province and an integral part

of the Nation’s oil and gas supply. For purposes of this report, deepwater is defined as water

depths greater than or equal to 1,000 feet (ft). A major milestone was reached in early 2000

when more oil was produced from the deepwater GOM than from the shallow-water GOM.

Deepwater oil production continues to increase and is rapidly approaching the all-time shallowwater GOM record set in 1971. In addition, deepwater drilling reached record levels in 2001.

Deepwater development activities are expected to continue increasing. Included in this trend is

an increasing number of ultra-deepwater (water depths greater than or equal to 5,000 ft)

exploration and development activities. The average sizes of deepwater GOM field discoveries

are several times larger than the average shallow-water field discoveries. In fact, since the last

version of this report (Baud et al., 2000) some of the largest hydrocarbon accumulations ever

discovered in the GOM were found in the deepwater area. The deepwater fields are some of the

most prolific producers in the GOM.

This report is divided into five sections.

The Introductory section discusses

• highlights of current deepwater GOM activity.

The Leasing section discusses

• historical water-depth and bidding trends in deepwater leasing,

• lease holdings of major oil companies compared with those of nonmajor oil companies,

• the impact of company mergers on deepwater exploration, and

• future deepwater lease activity.

The Drilling and Development section discusses

• deepwater rig activity,

• historical drilling statistics,

• the transition to deeper wells and deeper water,

• deepwater development systems, and

• the progress of deepwater infrastructure development.

The Reserves and Production section discusses

• historical deepwater reserve additions,

• large future reserve additions associated with recently announced discoveries,

• discoveries in new, lightly tested plays with large potential,

• potential for numerous, large future deepwater field discoveries,

• historical trends in deepwater production,

• deepwater production from various companies, and

• high deepwater production rates.
2

The Summary and Conclusions section discusses

• increasing deepwater oil and gas production and anticipated new fields,

• expected increases in deepwater discoveries; these expectations are based on drilling

of the large deepwater lease inventory,

• lags between leasing, drilling, and initial production,

• difficulties evaluating deepwater leases before their terms expire, and

• significant changes since the 2000 report.

Definitions

The Gulf of Mexico OCS is divided into the Western, Central, and Eastern Planning Areas

(figure 1). 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 1, along with the

congressionally mandated Deepwater Royalty Relief Act (DWRRA) zones (200, 400, and

800 m) for reference.

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-tobe 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 paper 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 have not been evaluated by MMS and the reliability of estimates can vary

widely.

More detailed definitions may be found in the annual Estimated Proved and Unproved Oil and

Gas Reserves, Gulf of Mexico, December 31, 1999 report (Crawford et al., 2002).

Throughout, this report refers to several deepwater fields by operator-designated project names.

Appendices A and B provide locations, operators, and additional information regarding these

fields. The field’s identifying block number corresponds to the first lease qualified by MMS as

capable of production. Note that the term “oil” refers to both oil and condensate throughout this

report and “gas” includes both associated and nonassociated gas. All production volumes and

rates reflect data through May 2001 (the most recent complete data at the time of this writing).

4

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. There were favorable economics, recent deepwater discoveries, and intense

leasing at that time. In February 1997 there were 16 producing deepwater fields, up from only 5

at the end of 1992. Industry was rapidly advancing into deepwater and, indeed, many of the

anticipated fields have begun production since the 1997 report. The previous version of this

report (Baud et al., 2000) highlighted dramatic advancements from 1997 through 1999. These

advances have continued at a rapid pace since then.

At the end of 2001, there were 51 producing fields in the deepwater Gulf of Mexico, up

38 percent in just 12 months and up 59 percent in the two years since Baud et al., 2000.

Deepwater production rates have risen by well over 100,000 barrels of oil per day (BOPD) and

400 million cubic ft of gas per day (MMCFPD), respectively, each year since 1997.

The dramatic shift toward high activity levels in the deepwater GOM occurred during the last

few years, although it had been developing for over two decades. Deepwater production began

in 1979 with Shell’s Cognac field, but it took another five years before the next deepwater field

(Exxon’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 continued to grow at an ever-increasing rate, leading to a flurry of activity in the past

five years. This report focuses on changes during the last ten years, 1992-2001.

The growth in deepwater activity spans all phases of exploration and development, including

leasing, drilling, and production. There are approximately 7,400 active leases in the Gulf of

Mexico Outer Continental Shelf (OCS), 53 percent of which are in deepwater. (Note that lease

statuses may change daily, so the current number of active leases is an approximation.) Contrast

this to approximately 5,600 active Gulf of Mexico leases in 1992, only 27 percent of which were

in deepwater. On average, there were 43 rigs drilling in deepwater in 2001, up from only 3 rigs

in 1992 and 28 rigs in 1999. Likewise, deepwater oil production rose over 800 percent and

deepwater gas production increased about 1,500 percent from 1992 to 2001.

All phases of exploration and development moved steadily into deeper waters over the past ten

years. This trend is observable in seismic activity, leasing, exploratory drilling, field discoveries,

and production. Major oil companies dominated deepwater leasing activity until 1996, when the

activity of nonmajor companies increased. Major oil companies continue to dominate deepwater

oil and gas production. A surge in production from nonmajors had been expected (Baud et al.,

2000) when anticipated discoveries on their 1996 through 1999 lease acquisitions began

production. Production from nonmajor companies has remained flat, however.

The OCS Deep Water Royalty Relief Act (DWRRA; 43 U.S.C. §1337) has had a significant

impact on deepwater GOM activities. This legislation provides economic incentives for

operators to develop fields in water depths greater than 200 m (656 ft). These incentives include

the automatic suspension of Federal royalty payments (for new leases issued 1996-2000) on the

initial 17.5 million barrels of oil equivalent (MMBOE) produced from a field in 200-400 m (656-
5

1,312 ft) of water, 52.5 MMBOE for a field in 400-800 m (1,312-2,624 ft) of water, and

87.5 MMBOE for a field in greater than 800 m (2,624 ft) of water. Reduction of royalty

payments is also available through an application process for some deepwater fields that were

leased prior to the DWRRA but had not yet gone on production. The automatic suspension

volume provision of the DWRRA expired on November 28, 2000. Leases acquired between

November 28, 1995, and November 28, 2000, will retain the incentives until their expiration.

Exploration and production incentives have continued in the post-DWRRA years for leases in

water depths greater than 800 m (2,624 ft). Royalty relief volumes will range from 9 MMBOE

in water depths of 800-1,599 m (2,625-5,246 ft) to 12 MMBOE of relief in depths greater than

1,600 m (5,249 ft). Royalty relief is granted to individual leases, not fields as in the DWRRA.

Post-DWRRA provisions are subject to change for each lease sale.

Seismic Activity

The DWRRA spurred a variety of deepwater activities. One of the first impacts was a dramatic

increase in the acquisition of 3-D seismic data (figure 2). (Note that figures 2 and 3 illustrate

areas permitted for seismic acquisition. The actual coverage available may be slightly different

than that permitted.) Three-dimensional 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, high-quality data greatly reduces the inherent risks of hydrocarbon

exploration. Figure 2 illustrates the surge of seismic activity in the deepwater Gulf of Mexico

during the last six years. Seismic acquisition has stepped into progressively deeper waters since

1992. Figure 3 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 active deepwater leases were purchased before these 3-D

surveys were completed (only the more sparsely populated 2-D data sets were available).

The seismic permitting coverage shown in figure 3 does not tell the whole story of geophysical

activity in the deepwater GOM. Pre-stack depth migration (PrSDM) of seismic data has greatly

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

below salt canopies. While PrSDM was once used sparingly, the availability of large nonproprietary PrSDM surveys allows the widespread use of this technology in early phases of

exploration. Industry is spending tens of millions of dollars to process seismic data to enhance

the imaging capability of existing 3-D surveys.

Time-lapse seismic surveys (also known as 4-D) will likely be the next significant seismic

technology to be applied routinely in the deepwater GOM. The technique can be applied to

characterize reservoir properties, monitor production efficiency, and estimate volumetrics from

inception through the life of the field (Shirley, 2001). The high cost of drilling deepwater wells

and challenges associated with re-entry of deepwater wells may promote the use of 4-D

technology in the deepwater GOM.

Modern seismic data often generate new ideas leading to surges in leasing and drilling activities.

Figure 4 illustrates several deepwater plays in the GOM. Although the traditional deepwater

mini-basin plays are far from mature (especially considering the Thunder Horse and North
L93-007

WESTERN

L93-020

SHELL

L93_021

L94_028

WESTERN

L93-032

L93_052

L93-064

EXXON

L93_069

L93_088

WESTERN

PHASE VI

SECTION 2

L93_101 WESTERN

PHASE 1B

T93-029

WESTERN

Figure 2. - Progressive deepwater 3-D seismic permit coverage.

1992-1993

1994-1995

6
Figure 2. - continued - Progressive deepwater 3-D seismic permit coverage.

1996-1997

1998-1999

2000-2001

7
1992-2001

Figure 3. - Deepwater Gulf of Mexico 3-D seismic permit coverage from 1992 through 2001.

8

10

Thunder Horse discoveries in southern Mississippi Canyon), the Mississippi Fan Foldbelt,

Perdido Foldbelt, and Tertiary Fan/Mesozoic Plays show that the deepwater arena is still very

much a frontier area. Although sparsely tested, the Mississippi Fan Foldbelt Play shows great

potential with announced discoveries at three locations (Mad Dog in Green Canyon Block 826,

Neptune in Atwater Block 575, and Atlantis in Green Canyon Block 699). The Mississippi Fan

Foldbelt Play also continues northward beneath the Sigsbee salt canopy. Industry-announced

successes at K2-Timon (Green Canyon Block 562) and Champlain (Atwater Block 63) expand

this exploration play to a large area north of the Sigsbee Escarpment. The first announced

discovery within the Perdido Foldbelt Play occurred during 2001 at the Trident prospect

(Alaminos Canyon Block 903). The Tertiary Fan/Mesozoic Play is heavily leased but remains

untested. These new plays are large in areal extent, have multiple opportunities, and contain

potentially huge traps with the possibility of billions of barrels of hydrocarbons.

Leasing Activity

The DWRRA encouraged extensive leasing in the deepwater GOM. Figure 5 shows the recent

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

after the DWRRA was enacted, however, deepwater leasing activity exploded. (Other factors

also contributed to this activity, including improved 3-D seismic data coverage, several key

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

deepwater development technologies.) Deepwater leasing activity slowed in 1998 and 1999 but

has steadily increased since then.

The GOM leasing status is shown in figure 6. In contrast to the analogous figure in the previous

edition of this report, fewer deepwater leasing voids remain. There are about 3,500 active leases

in water depths less than 1,000 ft, about 160 active leases in 1,000-1,499 ft water depth, about

1,620 active leases in 1,500-4,999 ft water depth, about 1,320 active leases in 5,000-7,499 ft

water depth, and about 820 active leases in water depths of 7,500 ft and greater. The abrupt

termination of active leases south of the Alabama-Florida state line approximates the eastern

edge of Lease Sale 181 acreage. Lease Sale 181 occurred in December 2001, the first Eastern

Gulf lease sale since 1988. The lack of activity in the eastern GOM is caused by leasing

restrictions.

The lease area for Sale 181 is more than 161 km (100 miles) offshore from the State of Alabama

and is adjacent to the Central Planning Area. Of the 233 tracts in the sale area (approximately

1.3 million acres), the MMS received 190 bids on about 547,000 acres. The MMS awarded 95

leases (about 41% of the tracts offered) in Sale 181. All of these leases are located in water

depths greater than 1,600 m (5,250 ft). The high bid per acre for Sale 181 was approximately

$622, as compared with about $93 for the Western Gulf Sale 180 in August 2001, and

approximately $185 for the Central Gulf Sale 178, Part 1 in March 2001.

Figure 7 shows the historic total active leasing trends by water-depth range. Notice the dramatic

increase in active leases for the greater than 800 m range. In 2001, for the first time in GOM

history, the total active leases in this range outnumber those in shallow water (less than 200 m).



Figure 7. - Total active leases by year and water-depth range.

14

0

500

1000

1500

2000

2500

3000

3500

4000

4500

Number of Active Leases

1994 1995 1996 1997 1998 1999 2000 2001

Year

< 200 m

> 800 m

200-400 m 400-800 m

Water Depth 1994 1995 1996 1997 1998 1999 2000 2001

< 200 m 3753 3652 3867 4235 4300 3596 3459 3366

200-400 m 181 184 216 276 304 262 257 220

400-800 m 270 301 386 509 605 443 423 392

> 800 m 916 1012 1491 2298 3002 3282 3304 3424
15

Operators contend with numerous obstacles when venturing into the deepwater arena. Figure 8

illustrates natural features and manmade zones that require special considerations for oil and gas

activities. Although the topographic features are located primarily along the shelf break, they

may be obstacles to pipelines from deepwater developments to the shelf infrastructure.

Environmental Activity

The nature of the deepwater GOM requires extensive scientific knowledge and environmental

considerations. The Environmental Studies Program (ESP), initiated in 1973, gathers and

synthesizes environmental, social, and economic information concerning offshore oil and gas

activities. The ESP expanded its focus to address unique issues as industry moved into

deepwater. For example, studies were initiated to evaluate the sensitivity of chemosynthetic

ecosystems. Refer to Appendix E for a listing of selected deepwater environmental studies.

A biologically based grid system was developed as part of a comprehensive strategy to address

deepwater issues in compliance with the National Environmental Policy Act (NEPA). The grid

system divided the Gulf into 17 areas or "grids" of biological similarity (figure 9). Under this

strategy, the MMS will prepare a programmatic environmental assessment (PEA) to address a

proposed development project within each of the grids. These grid PEA’s are comprehensive in

terms of the impact-producing factors and in terms of the environmental and socioeconomic

resources described and analyzed for the entire grid. Other information on publicly announced

projects within the grid is discussed, as well as any potential effects expected from their future

developmental activities. Projects selected for the grid PEA’s are representative of the types of

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

proposed development of a new surface structure that might serve as a "host" for future

development within the grid.

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

"tiering" concept detailed in NEPA's implementing regulations. Future environmental

evaluations may reference appropriate sections from the PEA to reduce duplication of issues and

effects addressed in the grid NEPA document. This will allow the subsequent environmental

analyses to focus on specific issues and effects related to the proposals.

Table 1 below shows the status of the grid PEA’s.

Table 1. - Completed and pending grid PEA’s within the Central and Western

Planning Areas of the Gulf of Mexico.

Grid Project Company Plan Area & Blocks

 4*

10*

12

15*

Nansen

Holstein

Medusa

Matterhorn

Kerr-McGee

British Petroleum

Murphy

TotalFinaElf

N-7045

N-7216

N-7269

N-7249

EB 602, EB 646

GC 644, GC 645

MC 538, MC 538

MC 243

*Indicates completed grid PEA’s.

 EB = East Breaks

 GC = Green Canyon

 MC = Mississippi Canyon


18

To implement its deepwater strategy further, the MMS issued Notice to Lessees and Operators

(NTL) No. 2001-G04, Remotely Operated Vehicle Surveys in Deepwater, with an effective date

of June 1, 2001. The NTL requirements apply to activities in water depths greater than 400 m

(1,312 ft) in the Central and Western Planning Areas of the GOM.

Operators submit a remotely operated vehicle (ROV) survey plan as an integral part of an

Exploration Plan (EP) or a Development Operations Coordination Document (DOCD) that has a

surface structure in one of the 17 grid areas. The MMS will notify an operator in the EP or

DOCD approval letter if the operator needs to conduct the ROV survey. The decision to require

the survey is based on whether or not the grid area that contains the proposed activities has

already received adequate ROV-survey coverage. Figure 10 shows the locations of existing

ROV surveys.

Exploration and development activities in deepwater may have localized impact on benthic

communities. A description of these potential impacts is available in Gulf of Mexico Deepwater

Operations and Activities: Environmental Assessment (USDOI, MMS, 2000). The MMS

believes that sensitive benthic communities such as chemosynthetic communities are protected

by the existing review process, relying on NTL’s and mitigative measures that require avoidance

of sensitive communities.

The ROV-monitoring surveys are intended to verify the effectiveness of mitigative measures and

to ensure that previously unknown, high-value benthic communities do not exist in the vicinity

of proposed activities. New information could lead to changes in the review process and in the

mitigative measures required.

Floating Production, Storage, and Offloading Systems

The MMS prepared, under contract, an environmental impact statement (EIS) to evaluate

potential environmental effects of floating production, storage, and offloading (FPSO) systems in

water depths greater than 200 m in the Central and Western Planning Areas in the GOM

(USDOI, MMS, 2001). The EIS analyzed the most likely configuration of a ship-shaped,

permanently moored FPSO with one million barrels of oil storage (figure 11). The EIS evaluated

a ten-year period, the years 2001 through 2010. A regulatory framework and a risk analysis were

completed on a parallel path to the EIS to enhance the technical review of an FPSO-based

project. The FPSO system presents industry with a viable deepwater production and

transportation option in areas where other development systems may be infeasible because of

economic or technical concerns.

The EIS was prepared as a programmatic document to examine the fundamental issues

associated with the proposed use of FPSO’s in the GOM. A project-specific review would be

necessary before an FPSO would be permitted to operate in the GOM.

The Record of Decision for this EIS was signed by MMS on December 13, 2001, and announced

on January 2, 2002. Approved was the general concept of using FPSO’s in the GOM Outer

Continental Shelf except within the U.S. Coast Guard (USCG) designated lightering-prohibited

areas (figure 12). The excluded area comprises 471 blocks along the shelf edge from Galveston

20

 Figure 11. – Artist's rendition of an FPSO system with subsea trees and flowlines. (Courtesy of Intec Engineerin

22

to New Orleans. Proposals for the use of FPSO’s in this area will not be accepted by the MMS

for a two-year period to allow continuing MMS and USCG discussion on potential protective

measures for that sector.

Challenges and Rewards

Significant challenges exist in deepwater 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 13 shows the history of discoveries in the deepwater GOM. There is

a shift toward deeper water with time, and the number of deepwater discoveries continues at a

steady pace. Note that the first frame of this figure represents a 10-year span, whereas the other

frames represent shorter spans. Figure 14 shows how major and nonmajor oil and gas companies

compare in terms of deepwater discoveries. (Appendix C lists those companies defined as

majors.) To date, majors are responsible for about two-thirds of the deepwater discoveries.

Additionally, discoveries by nonmajor companies tend to be in the shallower portions of the

deepwater, while majors tend to dominate the ultra-deepwater frontier areas.

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 15 illustrates the estimated sizes and

distributions of 53 proved deepwater fields. In addition to their large sizes, deepwater fields

have a wide geographic distribution and range in geologic age from Pleistocene through

Paleocene. Note that only recently have reservoirs older than Miocene been encountered.

The growing number of large deepwater fields on production requires increasing support from

onshore service bases. Most producing deepwater fields have service bases in southeast

Louisiana (figure 16). Pending Plans of Exploration (EP’s) and Development Operations

Coordination Documents (DOCD’s) filed with MMS indicate that support from southeast

Louisiana will grow significantly and that additional support will come from southwest

Louisiana, Mississippi, and the Texas coast (figure 17). Although expanding along the Gulf

Coast, shore-based support for deepwater operations is likely to remain concentrated in

southeastern Louisiana.

The infrastructure needed to bring deepwater production online continues to develop over time.

Figure 18 shows the framework of major oil and gas pipelines in the shallow-water GOM.

Figure 19 illustrates the existing network of deepwater pipelines.








31

Leasing 

Until the mid-1990's, leasing activities in the Gulf of Mexico were focused on shallow-water

blocks located on the continental shelf (water depths of 200 m or less). For example, in 1992

there were only 28 leases issued in water depths of greater than 200 m. These leases represented

approximately 14 percent of the total number of leases issued for that year. Figure 20 shows the

magnitude of the DWRRA impact, with tremendous deepwater leasing activity from 1996

through 1998 in water depths greater than 800 m (where the greatest royalty relief was

available).

Bidding and Leasing Trends

The Gulf experienced a lull in leasing activities in 1999 – about a four-fold decrease compared

with the 1998 levels. However, interest is rekindling in blocks in the 200 m or less range and the

greater than 800 m range, evidenced by increasing leasing activities in 1999-2001. Note that

shelf leasing has once again outpaced leasing in water depths greater than 800 m. From 1999

through 2001, leasing activities on the shelf constituted 50, 59, and 48 percent of the leases

issued in each of the respective years (figure 21). Some of the resurgent interest in 2001 may be

the result of the recent royalty suspension program for new deep-gas development in water

depths less than 200 m. Note that during this same interval, leasing activities in the greater than

800 m range constituted 41, 34, and 41 percent of the leases issued for these years.

Sale 182 was the latest lease offering in the Central Planning Area of the Gulf of Mexico. The

sale transpired on March 20, 2002. A total of 506 tracts received bids, about 40 percent of which

were in deepwater.

The water-depth categories depicted in figures 20 and 21 are based on the divisions used in

DWRRA. These figures include shallow- and deepwater leasing trends for a ten-year period.

Figure 22a was derived from the data in figures 20 and 21 but displays the deepwater categories

used elsewhere in this report (shallow-water data are excluded from figure 22a). The deepwater

data show the rapid increase in leasing activity that began in 1995. Notice that three water-depth

intervals (1,500-4,999 ft, 5,000-7,499 ft, and greater than 7,500 ft) had annual increases in lease

activity, and each was the most active leasing interval in successive years. Although GOM

leasing activity plummeted in 1999, there has since been a steady increase in bidding for all

water-depth ranges, with the greatest increases occurring in the 1,500-4,999 ft interval.

Figure 22b shows the total amount of money bid annually for each water-depth range. Large

financial investments were made by the oil and gas industry from 1996 through 1998.

Interestingly, in the 5,000-7,499 ft range, the number of bids received dropped from 503 in 1997

to 281 in 1998, yet the bid amounts increased slightly. All bidding activity and corresponding

bid amounts were depressed in 1999; however, in 2000 and 2001, activity levels increased.

Notable increases were seen in the 1,500-4,999 ft and the greater than 7,500 ft intervals.

Figure 22c illustrates the average bid price for deepwater leases through time. Overall, the

average bid price for all deepwater leases steadily increased from 1992 through 2001. In 2001,

industry bid high amounts per block in water depths greater than 7,500 ft. Interest in these leases
Figure 20. - Number of leases issued each year subdivided by DWRRA water-depth categor

261

466

509

620

525

265

325

4

15

25

52

66

44

35

16

14

17

36

30

103

110

99

58

17

28

7

24

39

712

1,110

135

186

165

176

771

171

0

200400600800

10001200

1992 1993 1994 1995 1996 1997 1998 1999 2000 

Year

Number of Leases Issue

 < 200 m 200-400 m 400-800 m > 800 m

Number of Leases Issued

Year

32
0%

10%20%30%40%50%60%70%80%90%

100%

1992 1993 1994 1995 1996 1997 1998 1999 2

Year

Percentage of Leases

Figure 21. - Percentage of leases issued each year within each DWRRA water-depth catego

400-800 m

200-400 m

> 800 m

< 200 m

33
4

24

306 68 00

14

56

15 1

28

212

65

9

53

388

304 121

30

484

503

243

24

261

281

329

6

83

53

33

12

124

64

25

23

256

95

110

0

100200300400500600

Number of Leases Bid 

1992 1993 1994 1995 1996 1997 1998 1999 2000 2001

Lease Year

1,000-1,499 ft1,500-4,999 ft 5,000-7,499 ft >7,500 ft

Figure 22a. - Number of leases bid in each deepwater interval. 

$0

$100$200$300$400$500$600

Bids in Millions of Dollars

1992 1993 1994 1995 1996 1997 19

Lease Year

Figure 22b. - Total bid amounts in dee

1,000-1,499 ft1,500-4,999 ft5,000-7,499 ft>7,500 ft

-

0.501.001.502.002.503.003.50

Average Bid Amount in

 Millions of Dollars

1992 1993 1994 1995 1996 1997 1998 1999 2000 

Lease Year

Figure 22c. - Average bid amount per block in deepwater intervals.

1,000-1,499 ft1,500-4,999 ft 5,000-7,499 ft >7,500 ft

 DWRRA 

DWRRA post- DWRRA

34
35

was likely caused by several significant discoveries, very large structural traps, and the improved

feasibility of developing ultra-deepwater fields.

As the value of deepwater leases increased throughout the 1990’s, the MMS rejected an

increasing number of deepwater high bids that it viewed as insufficient (figure 23). Apparent

also in figure 23 is the fact that tracts with rejected bids moved into increasingly deeper waters

over time. From 1992 through 1995, almost all rejected bids were on the shelf. In 1996-1997,

bid rejects were evenly divided between shallow- and deepwater. In 1998-1999, however, an

increasing number of bids were rejected in deepwater. This trend continued in 2000-2001 but at

reduced numbers. The rejection trend reflects the fact that, as more deepwater fields began

production, they provided analogs (with high production rates, thick reservoir sections, and

production infrastructure) and thus reduced the risk on leased deepwater blocks, leading to the

increased net present worth of many unleased blocks.

Lease Ownership

A handful of major oil and gas companies blazed the trail into deepwater in the 1980’s and early

1990’s. In this report, we define major companies to include BP, ChevronTexaco (merger not

yet filed with MMS), ExxonMobil, and Shell. Appendix C shows the companies and

subsidiaries combined to form these majors. (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.) Figure 24 illustrates the relative lease-holding positions of majors

versus nonmajors. Note that majors dominated deepwater leasing in 1992-1993. In 1994-1995,

majors still dominated leasing in the deepest waters, leading the charge into this frontier. In

1996, nonmajors began acquiring significant lease holdings, a trend that continued to grow

through 2001.

The type of companies active in deepwater clearly changed with the increased presence of

nonmajor oil and gas companies. Another change in deepwater lease ownership came with the

wave of company mega-mergers. Figure 25 shows the impact on lease holdings caused by

several mergers. The industry mergers increased the diversity of lease holdings for the merged

companies. For example, while some companies were heavily focused on the deepwater GOM

prior to the mergers, their merger partners may have been focused primarily on shallow-water

prospects. The combination of these entities yielded a larger leasehold position in all water

depths and frequently a broader geographic range across the GOM.

Since the deepwater arena is already heavily leased, the number of leases that are relinquished or

expire will influence activity in future lease sales. Given the fact that most companies can only

drill a small percentage of their active leases, potentially high-quality leases may expire without

being tested. The turnover of these leases often results in re-leasing at higher prices, “farm-outs”

to nonmajors, opportunities for nonmajors to gain a lease position and, potentially, more rapid

exploration and development of the acreage.

Figure 26 shows leases that will expire in the coming years, assuming 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 are five years for blocks in less than 400 m, eight








44

years for blocks in 400-799 m, and ten years for blocks in 800 m or greater. Therefore, in the

absence of primary lease term extensions, all active shallow-water leases will expire before 2008

(explaining the absence of expiring shallow-water leases in certain frames of figure 26). The

2002 and 2003 lease sales will offer only a handful of expired deepwater leases because of

depressed leasing activity in 1992 and 1993. The availability of previously leased blocks should

increase again in 2004 and 2005 and, beginning in 2006-2007, a significant number of deepwater

leases (2,175) will become available, resulting from the leasing boom that began in 1996 and

continued through 1998. A decreasing number of deepwater tracts will become available via

expiration in the 2008 to 2011 year interval. The lease expiration projections will pressure

leaseholders to drill and evaluate their holdings and will provide opportunities for other

companies to enter an active play by acquiring leases as they expire or by obtaining “farm-outs”

from companies with excess acreage.
45

Drilling and Development 

Deepwater drilling occurs from mobile offshore drilling units (MODU’s), such as

semisubmersible units or drillships (figures 27a and 27b), and from platform rigs. There are

numerous deepwater prospects waiting to be drilled, and there will be many that remain undrilled

before the primary lease terms expire because of the limited number of rigs available for

deepwater drilling. Figure 28 depicts deepwater rigs operating in the GOM from 1992 through

2001.1 The MMS has noted a steady increase in deepwater rig activity; the average number of

deepwater rigs operating in the GOM during 2001 represents a 34 percent increase over the

previous year. This major increase can be attributed to several deepwater MODU’s entering

service. However, there are few new deepwater MODU’s under construction. On the basis of

statistics gathered during the first quarter of this year, MMS projects rig use to drop in 2002, then

rebound in 2003-2004. This projected rebound reflects new production facilities expected to

have platform rigs and reflects anticipated drilling activity related to leases nearing expiration.

Figure 29 shows the number of deepwater MODU’s by water-depth categories in the GOM and

worldwide. Approximately 50 percent of the world’s fleet of deepwater drilling rigs is

committed to GOM service (Maksoud, 2001; Harding and Albaugh, 2001). The pie chart within

figure 29 shows the distribution of deepwater rigs by major operating area. The number of GOM

rigs capable of operating in water depths beyond 7,500 ft tripled from 4 to 13 since the 2000

edition of this report (Baud et al., 2000). Most, if not all, of the deepwater-capable drilling rigs

are under long-term contractual arrangements. The reader is cautioned not to draw any

conclusions from the rig count differences between figures 28 and 29. As mentioned above,

figure 28 includes platform rigs in addition to MODU’s; figure 29 addresses MODU’s only.

Further, upgrades to MODU’s that increase their water-depth capability will alter the rig counts

shown, so the reader is also cautioned about using these data to draw conclusions from year-toyear comparisons.

Drilling Activity

The number of deepwater wells drilled has steadily increased since 1992. 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. Figure 30 shows that most of the drilling has occurred in the

1,500-4,999 ft water-depth range. Drilling from 1998 through 1999 remained at the 1997 level;

however, a significant increase in the number of wells drilled in ultra-deepwater (greater than

5,000 ft) began in 1999, as shown in figure 31. The increases in ultra-deepwater wells during

1999 and again in 2001 coincide with the addition of several new drilling rigs capable of

 

1

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

addition to the MODU’s. About one-third of all rigs are platform rigs. The numbers do not distinguish between rigs

drilling and those in service for completion and workover operations.
46

Figure 27a. – The Ocean Confidence, a Class III, dynamically positioned, submersible drilling rig. How

may be deployed for some applications. (Photograph courtesy of Diamond Offshore Drill
47

Figure 27b. – The Deepwater Pathfinder, a dynamically positioned drillship (Photograph

courtesy of Transocean SedcoForex).
3 4

21

39

13

34

13

26

0

5

10

15

20

25

30

35

40

Number of Rigs

1000-1499 1500-4999 5000-7499 >7500

Maximum Water Depth Capability (ft)

GOM rigs

Worldwide rigs

3

6

11

14

18

26

28 28

32

43

36

38

40

0

10

20

30

40

50

Average Number of Deepwater Rigs Drillin

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

Year

Figure 28. - Average number of rigs drilling in the deepwater Gulf of Mexico.

Figure 29. - Approximate number of deepwater rigs (GOM and worldwide)

 subdivided according to their maximum water-depth capabilities.

 Inset shows the number of deepwater rigs in various locations.

48

Estimated

Estimated

Estimated

GOM (50) W. Africa (7)

Brazil (27)

Other (19)

Average Number of Deepwater Rigs Drilling

Number of Rigs

Year

Maximum Water Depth Capability (ft)
1

11

22

1

14

26

1

44

20

3

56

26

1

6

80

26

12

128

32

1

10

125

33

37

119

16

9

27

146

31

6

50

127

25

0

50

100

150

200

250

Number of Wells Spudded

1992 1993 1994 1995 1996 1997 1998 1999 2000 2001

Year

 1,000-1,499 ft

 1,500-4,999 ft

 5,000-7,499 ft

 >7,500 ft

1 1 1

3

7

12 11

37 36

56

0

10

20

30

40

50

60

Number of Wells Spudde

1992 1993 1994 1995 1996 1997 1998 1999 2000 2001

Year

Figure 30. - All deepwater wells drilled in the Gulf of Mexico,

 subdivided by water depth.

Figure 31. - Ultra-deepwater (5,000 ft or greater) wells drilled

 in the Gulf of Mexico.

49

34

41

65

85

113

172 169 172

213 208

Number of Wells Spudded Number of Wells Spudded

Year

Year
50

operating in water depths approaching 10,000 ft. Notice in figure 30 the increasing contribution

of wells in water depths exceeding 7,500 ft.

Figures 32 and 33 further break down the deepwater well counts into exploratory and

development wells, respectively. Exploratory wells are defined in this report as those numbered

1 through 5 in the MMS database. There has been an average 19 percent increase in the number

of exploratory wells drilled each subsequent year beginning with 1997. Exploratory drilling in

water depths greater than 7,500 ft was limited to just two wells during 1992-1998. Fifteen wells,

which represent approximately 5 percent of the total deepwater exploratory well count, have

been drilled in the last two years. Development drilling from 1997 through 2001 has decreased

to a level 36 percent below the peak in 1997. Possible reasons for the decrease may be the

method by which wells are categorized in this report (exploratory versus development), the

retention of exploratory wells for production purposes, and the lag from exploration to first

production. The complexity of the deepest water developments may also be a factor, requiring

operators to spend more time in planning and design. Most development drilling was in the

1,500-4,999 ft water-depth range; there are no development wells in water depths exceeding

7,500 ft. Figure 34 illustrates the geographic distribution of deepwater exploratory wells. Note

the progression into the western GOM and into deeper water through time. Figure 35 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 exploratory wells,

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

• file a Development Operations Coordination Document (DOCD),

• drill development wells,

• file a Preliminary DWOP, then

• begin production.

Figure 36 shows the number of deepwater EP’s, deepwater DOCD’s, and DWOP’s received each

year since 1992 (DWOP’s were not required until 1995). The count of EP’s and DOCD’s

includes initial, supplemental, and revised plans; only the initial submittals (Conceptual Part) of

the DWOP’s are shown. 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 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 – the effective use of

deepwater technologies in shallow-water marginal developments.

There was a sharp increase in deepwater exploratory plan submittals from 1992 through 1999.

The number of EP submittals in 2000 was nearly identical to 1999, with a 10 percent decline in

2001. The number of deepwater DOCD submittals also showed a general increase during this
7

20

7

22

23

14

31

20

2

49

20

01

70

17

42

15

3

37

9

4

43

20

11

31

18

0

20

40

60

80

100

120

140

160

Number of Wells Spudded

1992 1993 1994 1995 1996 1997 1998 1999 2000 2001

Year

 1000-1499 ft

 1500-4999 ft

 5000-7499 ft

 > 7500 ft

1 4

2

1 7

4

1

21

6

3

25

6

1 4

31

6

11

58

15

1

10

83

18

34

82

7

9

23

103

11

6

39

96

7

0

20

40

60

80

100

120

140

160

Number of Wells Spudded

1992 1993 1994 1995 1996 1997 1998 1999 2000 2001

Year

 1000-1499 ft

 1500-4999 ft

 5000-7499 ft

 > 7500 ft

Figure 32. - Deepwater exploratory wells drilled in the Gulf of

 Mexico, subdivided by water depth.

Figure 33. - Deepwater development wells drilled in the Gulf of

 Mexico, subdivided by water depth.

51

7 12

28 34

42

84

112

123

146 148

27 29

37

51

71

88

57

49

67

60




 











 















 

  



 

 































 



 





 

 

  

  



0

20406080

100120140160180

Number of Plans Received

1992 1993 1994 1995 1996 1997 1998 1999 2000 

Year

 Deepwater EP's

Deepwater DOCD'sDWOP's

Figure 36. - Deepwater EP’s, DOCD’s, and DWOP’s received in the Gulf of Mexico since 

56
57

time, although not quite as dramatic when considered for the interval of 1992 through 2001. The

number of DWOP’s doubled (18 to 36) from 1999 to 2001.

There has been a gradual increase of true vertical depth (TVD) through time, whereas the

progression into greater water depths has been very rapid. Figure 37 shows the maximum TVD

of wells drilled each year since 1947 (when drilling in the Gulf of Mexico OCS began). The

maximum TVD increased gradually from 13,636 ft in 1948 to 26,978 ft in 1998. The recent

dramatic increase in TVD to a record 29,680 ft in 2000 may be attributed to several factors,

including enhanced rig capabilities, deeper exploration targets, and the general trend toward

greater water depths.

Figure 38 shows the maximum water depth drilled in the total GOM each year since 1947.

Deepwater drilling began in 1974 (1,024 ft); significant water depth records occurred in 1976

(1,986 ft), 1984 (3,534 ft), and 1987 (7,500 ft). The most recent water-depth accomplishment is

the world record established in October 2001 by Unocal; the Trident prospect (Alaminos Canyon

Block 903) was drilled in 9,727 ft of water. There are approved plans for wells in water depths

greater than 10,000 ft that could be drilled in the near future.

Development Systems

Development strategies vary for deepwater 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. Figure 39 shows the

different systems that can be used to develop deepwater discoveries. Table 2 lists the systems

that have begun production. The blocks referenced in Table 2 represent the MMS field

designations, which sometimes differ from the facility locations. Fixed platforms (e.g., 

Bullwinkle) have economic water-depth limits of about 1,400 ft. Compliant towers (e.g.,

Petronius) may be considered for water depths of approximately 1,000 to 3,000 ft. Tension-leg

platforms (TLP’s) (e.g., Brutus and Typhoon) are frequently used in 1,000 to 5,000-ft water

depths. Figure 40 shows three competing versions of TLP’s used in the GOM, along with a

photograph of the larger Ursa TLP operated by Shell. Examples of the SeaStar TLP are

Morpeth, Allegheny, and Typhoon; the first MOSES TLP was installed to develop El Paso’s

Prince field. Spars (e.g., Genesis) and semisubmersible production units (e.g., Thunder Horse, as

shown on the cover of this report) may be used in water depths ranging up to 10,000 feet.

Figure 41 shows the two competing versions of spars used in the GOM to date. Examples of the

conventional spar design include Neptune, Genesis, and Hoover. The world’s first truss spar was

installed by Kerr-McGee at their Nansen development during 2001.

A Floating Production, Storage, and Offloading (FPSO) system is an offshore production facility

that is typically ship-shaped and stores crude oil in tanks located in the hull of the vessel. The

crude oil is periodically offloaded to shuttle tankers or ocean-going barges for transport to shore.

The FPSO would use one of the following arrangements to remain at the production location:

fixed mooring (anchored to the seafloor, similar to a spar), turret mooring (allowing the FPSO to

weathervane around a fixed point), or dynamically positioned (relying on thrusters to maintain

the location). An FPSO could be used to develop a discovery in water depths ranging from
58

Figure 37. – Maximum wellbore true vertical depth (TVD) drilled in the

 total GOM each year.

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

Maximum Water Depth (ft)

1947 1953 1959 1965 1971 1977 1983 1989 1995 2001

Year

Figure 38. – Maximum water depth drilled each year.

0

5,000

10,000

15,000

20,000

25,000

30,000

Maximum Well TVD (ft)

1947 1953 1959 1965 1971 1977 1983 1989 1995 2001

Year
59

 Figure 39. – Deepwater development systems.
60

Table 2. – Development Systems of Productive Deepwater GOM Fields.

* Indicates fields that are no longer on production.

Year of First

Production Field Nickname System Type Block Water Depth (ft) Operator

1979 Cognac Fixed Platform MC 194 1,023 Shell

1984 Lena Compliant Tower MC 281 1,017 ExxonMobil

1988* Unnamed FPS GC 75 2,172 Oryx

1988* Unnamed Semi-Submersible GC 29 1,554 Placid

1989 Bullwinkle Fixed Platform GC 65 1,330 Shell

1989 Jolliet TLP GC 184 1,724 Conoco

1991 Amberjack Fixed Platform MC 109 1,050 BP

1993* Diamond Subsea MC 445 2,095 Oryx

1993* Seattle Slew Fixed Platform/Subsea EW 914 1,019 Tatham

1993 Zinc Subsea MC 354 1,475 ExxonMobil

1994 Auger TLP GB 426 2,863 Shell

1994 Pompano/Pompano II Fixed Platform/Subsea VK 990 1,440 BP

1994 Tahoe/ Tahoe II Subsea VK 783 1,391 Shell

1995* Cooper Semi-Submersible GB 387 2,260 EEX

1995 Unnamed Subsea VK 862 1,043 Walter

1996 Mars TLP/Subsea MC 807 2,992 Shell

1996 Popeye Subsea GC 116 2,065 Shell

1996 Rocky Subsea GC 110 1,719 Shell

1997 Mensa Subsea MC 731 5,276 Shell

1997 Neptune/Thor Spar/Subsea VK 825 1,866 Kerr McGee

1997 Ram-Powell TLP VK 956 3,243 Shell

1997 Troika Subsea GC 244 2,679 BP

1998 Arnold Subsea EW 963 1,752 Marathon

1998 Baldpate Compliant Tower GB 260 1,604 Amerada Hess

1998 Morpeth/Klamath TLP/Subsea EW 921 1,747 Agip

1998 Salsa Subsea GB 171 1,121 Shell

1999 Allegheny TLP/Subsea GC 254 3,194 Agip

1999 Angus Subsea GC 112 1,901 Shell

1999 Diana Subsea EB 945 4,670 ExxonMobil

1999 Dulcimer Subsea GB 367 1,123 Mariner

1999 Genesis Spar GC 205 2,597 ChevronTexaco

1999 Gemini Subsea MC 292 3,488 ChevronTexaco

1999 Macaroni Subsea GB 602 3,691 Shell

1999 Pluto Subsea MC 718 2,748 Mariner

1999 Unnamed Subsea EW 1006 1,832 Walter

1999 Ursa TLP MC 810 3,877 Shell

1999 Virgo Fixed Platform VK 823 1,136 TotalFinaElf

2000 Europa Subsea MC 935 3,880 Shell

2000 Hoover Spar AC 25 4,806 ExxonMobil

2000 Marlin TLP VK 915 3,300 BP

2000 Northwestern Subsea GB 200 1,261 Amerada Hess

2000 Petronius Compliant Tower VK 786 1,753 ChevronTexaco

2001 Brutus TLP GC 158 2,952 Shell

2001 Einset Subsea VK 873 3,584 Shell

2001 Crosby Subsea MC 899 4,400 Shell

2001 Ladybug Subsea GB 409 1,357 ATP

2001 Madison Subsea AC 24 4,854 ExxonMobil

2001 Marshall Subsea EB 949 4,376 ExxonMobil

2001 Mica Subsea MC 211 4,337 ExxonMobil

2001 Nile Subsea VK 914 3,535 BP

2001 Oregano Subsea GB 559 3,400 Shell

2001 Prince TLP EW 958 1,493 Argo

2001 Serrano Subsea GB 516 3,359 Shell

2001 Typhoon TLP/Subsea GC 236 2,679 ChevronTexaco

2001 Unnamed Subsea EW 878 1,585 Walter

2001 Unnamed Subsea MC 68 1,214 Walter
61

Figure 40. – Three different versions of TLP’s (left to right): a SeaStar installed at ChevronTexaco’s Typhoon fiel El Paso’s Prince field, and a conventional TLP installed at Shell’s Ursa field. (Photographs courtesy 

 El Paso, and Shell, respectively.)
62

Figure 41. – Two competing versions of the production spar. A conventional spar is shown in the artist’s draw

 installed at Kerr-McGee’s Neptune field. The middle graphic shows the truss spar planned for BP development. The photograph at the right is the world’s first truss spar, installed at the Nansen fie (Photographs courtesy of Oryx, BP, and Kerr-McGee, respectively.)
63

several hundred feet to well beyond 8,000 ft, although historically nearly all have been installed

in less than 3,000 ft of water.

A marginal deepwater field that is remote from established pipeline infrastructure would be a

likely FPSO-based development scenario in the GOM. To date, no operator has proposed the

use of an FPSO to develop a GOM discovery in U.S. waters.

Figure 42 shows the different types of production systems installed each year (the pie chart

within figure 42 shows all the deepwater development systems that are producing). Data values

can be found in appendix G. At least seven deepwater production facilities (primarily truss

spars) are under construction or pending installation at this time.

Subsea systems (e.g., Mensa), as shown in figure 43, 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 to the success in deepwater to date. These systems are

generally multi-component seafloor facilities that allow for 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, 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.

Subsea Trends

Figure 44a shows the number of subsea completions each year since 1955 (only productive wells

were counted). There were fewer than five subsea completions per year until 1989. This number

increased dramatically throughout the 1990’s. The number of subsea wells installed in 2000

appears anomalous. While it is not possible to identify specifically why there were so few

subsea completions, the trend is consistent with deepwater start-ups as shown in table 2 (11 in

1999; 5 in 2000; 14 in 2001). Drilling activities and permitting of deepwater developments

(figure 36) remained at high levels during this one-year decline, implying that subsea well

installations are likely to remain close to 1999 and 2001 levels. Well complexity, deeper water

discoveries, project schedules, equipment availability, and other challenges will affect the

number of yearly subsea well installations. The pie chart within figure 44a shows that shallowwater subsea wells are a significant contribution to the subsea well population in the GOM.

Shallow-water subsea wells accounted for 136 of the 218 total subsea wells in the GOM by

yearend 2001. Operators have found subsea tiebacks to be valuable for shallow-water marginal

fields because of the extensive infrastructure of platforms and pipelines. Nonmajor companies

have installed nearly all of these shallow-water subsea wells, led by Walter Oil and Gas

Corporation with 32 wells.

The technology required to implement subsea production systems in deepwater evolved

significantly in the last decade. This evolution is apparent in figure 44b, which shows the

deepest subsea completion was in 350 ft of water until 1988, when the water depth record

(GOM) jumped to 2,243 ft (GC 75 field). In 1996 another record was reached with a subsea
1979

1984

1

Fixed Platform

Compliant Tower

Other FPS

FPSO

Truss Spar

Spar

Small TLP

TLP

0

1

2

3

Number Installed

Number Installed

Compliant Tower (3)

Fixed Platform (7)

Spar (3)

TLP (11) Subsea (38)

Figure 42. - GOM deepwater production facilities installed each year (including plans through 2004). Ins production systems for currently producing fields (including subsea systems).

64
65

Figure 43. – Mensa Project subsea equipment layout (courtesy of Shell).

12” flowline to

host platform

Electrical

Distribution

Structure

Subsea Manifold

Flowline Sled

Mens

MC 

Control Umbilicals
66

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

Maximum Water Depth (ft)

1955 1960 1965 1970 1975 1980 1985 1990 1995 2000

Year

HI A573

GC 75

Mars

Mensa

King’s Peak

Figure 44b. – Maximum water depths of subsea completions each year.

Figure 44a. – Number of subsea completions each year.

0

5

10

15

20

25

Number of Subsea Completions

1955 1960 1965 1970 1975 1980 1985 1990 1995 2000

Year

Shallow water

 62%

Deepwater

 38%
67

completion in 2,956 ft of water (Mars field), followed by a 1997 subsea completion in 5,295 ft of

water (Mensa field). Mensa has the deepest production in the GOM to date. Production from

water depths greater than 7,000 ft is expected in summer 2002 from multiple wells in the

Aconcagua and Camden Hills fields. A listing of productive subsea completions in the GOM

Outer Continental Shelf can be found in Appendix D.

The breakdown of shallow-water and deepwater subsea wells is shown in figure 45. There have

been 218 subsea completions installed, 82 of these (38%) in deepwater. Since 1996, there have

been 115 subsea completions, with 60 installed (52%) in deepwater. Figure 45 demonstrates the

increasing reliance of industry on subsea technology, to develop both shallow-water and

deepwater fields, beginning in the late 1980’s.

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 46. Most subsea wells

are within 10 miles of the host platform, with the Mensa field remaining the current world record

holder for a subsea tieback length of 62 miles from the host platform. The second longest subsea

tieback in the world (55 miles) is Canyon Express, linking Aconcagua, Camden Hills, and

King’s Peak projects to their host platform. Figure 47 shows the number of subsea tieback

projects by water-depth range, illustrating the preponderance of projects in water depths less than

2,500 ft.

Deepwater pipelines approved for installation are shown in Figures 48a and 48b. The data

include the total length of all pipelines originating at a deepwater development, including any

shallow-water segments (control umbilicals are excluded). Figure 48a shows deepwater

pipelines that are less than or equal to 12 inches in diameter. The dominance of gas pipeline

miles approved in deepwater is surprising – 67 percent of the total since 1990. The large

increase in 2001 in both oil and gas pipeline miles reflects approvals for Canyon Express

(Aconcagua, Camden Hills, and King’s Peak fields), Horn Mountain, and the Boomvang-Nansen

projects. Installation of large pipelines (greater than 12 inches in diameter) has fallen

significantly since peaking in 1999 (Figure 48b). The peak in 1999 was driven by the approval

of the Hoover, Petronius, and Ram-Powell projects.
0

2468

10121416

Number of Subsea Completions

1955 1960 1965 1970 1975 1980 1985 1990 1995 

Year

Shallow waterDeepwater

Figure 45. – Number of shallow- and deepwater subsea completions each year.

68
69

Figure 46. – Length of subsea tiebacks.

66

35

28

5 4

2

0

10

20

30

40

50

60

70

Number of Pipeline Segments

< 5 5 - 10 10 - 20 20 - 30 30 - 50 >50

Tieback Length Range (miles)

74

31

23

8

4

0

10

20

30

40

50

60

70

80

Number of Projects

<1,000 1,000 - 2,499 2,500 - 4,999 5,000 - 6,999 >7,000

Water Depth Range (ft)

Figure 47. – Water depth of subsea tiebacks.
26 20

39 68 52 65

128

18

40

42

244

95

77

142

137

108

96

29

155 196

397

0

100

200

300

400

500

Miles of Pipeline Approved

1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001

Year

Gas

Oil

50

8

40

41

43 39

74

103

68

179

129

25

32

42

76

0

100

200

300

400

500

Miles of Pipeline Approved

1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 2001

Year

Gas

Oil

(b)

(a)

Figure 48. – Approved deepwater oil and gas pipelines (a) less

 than or equal to 12 inches in diameter, and

 (b) greater than 12 inches in diameter.

70
71

Reserves and Production 

The deepwater GOM has contributed major additions to the total reserves in the GOM.

Figure 49 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 of water. It was not until 1984

that major additions came from water depths greater than 1,500 ft.

There is often a significant lag between a successful exploratory well and its hydrocarbons being

produced. The success of an exploratory 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 TD (total depth) date of

the field’s first well that encountered significant hydrocarbons. Hydrocarbon reserves are still

considered unproved until it is clear that the field will go on production. Then the reserves move

into MMS’s proved category. Figure 50 includes both proved and unproved reserves for each

water-depth category. This figure shows declining reserve additions in shallow water, similar to

figure 49, but reveals significantly more deepwater reserve additions and large significant

unproved reserve additions in water depths greater than 5,000 ft beginning in 1998.

Figure 51 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. During the last

10 years, the average shallow-water field added approximately 6 MMBOE of proved and

unproved reserves. In contrast, the average deepwater field added over 64 MMBOE of proved

and unproved reserves. In the most active deepwater exploration area, water depths between

1,500 and 7,499 ft, the average deepwater field contributed more than 73 MMBOE (12 times

more than the average shallow-water field addition).

Discoveries

Figure 52 shows the number of deepwater fields discovered each year, according to MMS

criteria, since 1975. (See appendices A and B for listings of deepwater fields and discoveries.)

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 late 1990’s, since these recent field

discoveries have had little time to reach production. Because of this lag between exploratory

drilling and first production, the true impact of recent, large deepwater exploratory successes are

not yet reflected in MMS proved and unproved reserve estimates.

In an attempt to capture the impact of these deepwater exploratory successes, figure 53 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
0

500

1,0001,5002,0002,5003,000

Million Barrels of Oil Equivalent

Figure 49. – Proved reserve additions.

>7,500 ft 5,000-7,499 ft1,500-4,999 ft1,000-1,499 ft 0-999 ft

>7,500 ft 5,000-7,499 ft 109 61,500-4,999 ft 65 42 424 65 492 152 739 402 134 6 43 304 155 130 34 1,000-1,499 ft 305 105 66 163 141 145 20 25  0-999 ft 590 1140 1172 532 508 279 2670 780 1798 2096 917 891 466 367 571 749 241 560 477 779 459 164 248 465 118 167 87 11 112 84 73 81 114 

1965 1966 1967 1968 1969 1970 1971 1972 1973 1974 1975 1976 1977 1978 1979 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 

72
0

500

1,0001,5002,0002,5003,000

Million Barrels of Oil Equivalent

Figure 50. – Proved and unproved reserve additions.

>7,500 ft 5,000-7,499 ft1,500-4,999 ft1,000-1,499 ft 0-999 ft

>7,500 ft 46 1 5,000-7,499 ft 109 44 15 160 3 1,500-4,999 ft 67 42 428 163 511 187 891 457 151 6 52 331 202 163 93 1,000-1,499 ft 305 106 66 163 172 206 20 33  0-999 ft 592 1151 1181 553 510 279 2686 783 1813 2122 937 925 466 372 583 751 241 567 477 809 474 170 252 567 118 167 87 11 114 84 74 89 118 

1965 1966 1967 1968 1969 1970 1971 1972 1973 1974 1975 1976 1977 1978 1979 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1

73
0

50

100150200250

Million Barrels of Oil Equivalent

Figure 51. – Average field size using proved and unproved reserves.

>7,500 ft 5,000-7,499 ft1,500-4,999 ft1,000-1,499 ft 0-999 ft

>7,500 ft 46 1 5,000-7,499 ft 109 44 15 80 3 1,500-4,999 ft 67 143 54 170 47 223 152 151 6 52 166 67 54 23 1,000-1,499 ft 152 53 66 163 172 52 20 11  0-999 ft 49 50 98 39 46 47 117 56 58 52 27 26 22 19 22 38 16 18 23 12 14 8 7 11 6 5 9 2 9 6 5 5 7 

1965 1966 1967 1968 1969 1970 1971 1972 1973 1974 1975 1976 1977 1978 1979 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1

74
0

2468

101214

Number of Fields

1975 1976 1977 1978 1979 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 19

Field Discovery Year

Number of discoveriesNumber producing DWRR

Figure 52. - Number of deepwater field discoveries and resulting number of producing fields.

75
0

500

1,0001,5002,0002,5003,000

1975

1976

1977

1978

1979

1980

1981

1982

1983

1984

1985

1986

1987

1988

1989

1990

1991

1992

1993

1994

1995

1996

1997

1998

Field Discovery Year

Million Barrels of Oil Equivalent

Proved reservesUnproved reserves, resources, and industry-announced discoveries Number of deepwater discoveries

DWRRA 

Figure 53. - Number of deepwater field discoveries and new hydrocarbons found (MMS reserves, MMS  industry-announced discoveries).

76
77

MMS proved reserve numbers. The apparent decline of proved reserve additions in recent years

is caused by the previously mentioned developmental lag.

Figure 54 illustrates the distribution of recent hydrocarbon additions in the GOM, categorized by

water depth. The combination of industry-announced deepwater discoveries and MMS estimates

illustrates that deepwater exploration is adding significantly to the GOM hydrocarbon inventory.

These large additions show the excellent potential for continued growth in deepwater activity

levels.

Reserve Potential

This report has examined the history of reserve growth in the GOM. Figure 54 illustrates results

of the latest drilling in the GOM, suggesting very significant production volumes in the near

future. Predicting future discoveries is more difficult. To address the amount of hydrocarbons

yet to be discovered in the GOM, this report will briefly examine one indicator – the “creaming

curve” – and one detailed study – 2000 Assessment of Conventionally Recoverable Hydrocarbon

Resources of the Gulf of Mexico and Atlantic Outer Continental Shelf as of January 1, 1999

(Lore et al., 2001), commonly known as the 2000 Assessment.

The creaming curve, figure 55, shows the discovered and implies the undiscovered hydrocarbon

volumes in the GOM. The creaming curve plots “cumulative number of fields by discovery

date” against “cumulative discovered hydrocarbon volumes.” Many such curves demonstrate

that the largest fields tend to be discovered early in the exploration cycle. This phenomenon

results in a curve having a steep slope during the early (immature) phase of exploration and

becoming flatter in the mature phase of exploration, when smaller fields are generally

discovered.

Figure 55 contains two creaming curves. The shallow-water GOM is characterized by a curve

typical of a mature trend. The recent slope of the curve is very flat since, in general, smaller

fields are being discovered. Unless a dramatic new exploration play is recognized, only limited

reserves will be added. This prediction is supported by figures 49, 50, 51, and 54, all of which

show a decline in field discovery size and added reserves from the shallow-water GOM over the

last 20 years.

The deepwater creaming curve contains fewer field discoveries; however, these fields tend to be

large, resulting in a curve with a steep slope. This slope indicates an area that is still in an

immature exploration phase with many large fields awaiting discovery. The limited number of

discoveries, steep slope of the curve, and large amount of hydrocarbon volumes already

discovered support this prediction.

A more quantitative and geologic-based estimate of future discoveries in the GOM is the 2000

Assessment, summarized in figure 56. The deepwater is expected to have ultimate reserves of

approximately 71 billion barrels of oil equivalent (BOE), of which 56.4 billion BOE remains to
0

500

1,0001,5002,0002,5003,000

Million Barrels of Oil Equivalent

Figure 54. – BOE added (reserves, known resources, and industry-announced discoveries).

>7,500 ft 5,000-7,499 ft1,500-4,999 ft1,000-1,499 ft 0-999 ft

>7,500 ft 51 4  5,000-7,499 ft 109 65 46 44 227 4 1,500-4,999 ft 69 52 469 251 517 216 1057 627 222 16 55 402 281 164 622 1,000-1,499 ft 306 120 67 163 188 258 36 26 2 43  0-999 ft 599 1161 1197 555 524 280 2790 789 1839 2161 972 935 472 416 593 757 268 606 511 866 509 210 287 905 153 202 136 15 145 90 100 111 133 

1965 1966 1967 1968 1969 1970 1971 1972 1973 1974 1975 1976 1977 1978 1979 1980 1981 1982 1983 1984 1985 1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 

78
0

5,000

10,000

15,000

20,000

25,000

30,000

35,000

40,000

45,000

0 100 200 300 400 500 600 700 800 900 1000 1100

Cumulative Number of Fields by Discovery Date

Million Barrels of Oil Equivalent

Figure 55. - Creaming curve for shallow- and deepwater areas 

 of the GOM (includes reserves, resources, and 

 industry-announced discoveries).

49.895

4.963

6.85

3.265

15.005

19.796

7.889

28.717

0

10

20

30

40

50

60

0-200 200-800 800-1600 >1600

Water-Depth Intervals in Meters

 Billion Barrels of Oil Equivalent (grown volumes)

Total Reserves

Mean Resources

Figure 56. - Reserves and future discovery volumes in the deepwater

 GOM (from Lore et al., 2001).

Shallow-water 

cumulative volumes

79

Deepwater cumulative volumes
80

be discovered.2 Compare this with the shallow-water ultimate reserves of approximately

65 billion BOE, of which 15.2 billion BOE remain to be discovered.

Production Trends

Seismic acquisition, leasing, bid rejects, drilling, and discoveries—all stepped into deeper waters

with time. The final piece in the puzzle, production, is no exception. Figure 57 illustrates the

relative volume of production from each GOM block through time. Notice the large deepwater

volumes that first appear in 1996 and 1997. Table 3 shows that the most prolific blocks (on a

BOE basis) are currently in the deepwater GOM.

Table 3. - Top 20 producing blocks for the years 2000–2001.

Block Project Name Owner Water Depth (ft) Production (BOE)*

MC 807 Mars Shell 3,327 78,035,724

GB 427 Auger Shell 2,953 51,878,082

GC 200 Troika BP 2,828 49,193,970

MC 809 Ursa Shell 3,947 44,113,351

GB 260 Baldpate Amerada Hess 1,759 27,450,880

ST 37 Unnamed ChevronTexaco 59 19,632,336

GC 113 Angus Shell 2,713 15,893,963

MI 622 Unnamed BP 89 15,265,265

MC 853 Ursa Shell 4,052 15,039,580

EW 873 Unnamed Marathon 988 13,925,569

VK 956 Ram Powell Shell 4,059 13,734,616

MC 934 Europa Shell 3,904 13,495,243

VK 912 Ram Powell Shell 3,294 13,383,491

MC 28 Pompano/Pompano II BP 1,972 12,665,320

GB 426 Auger Shell 2,884 11,985,662

GC 161 Genesis ChevronTexaco 2,772 11,909,477

VK 786 Petronius ChevronTexaco 2,539 11,689,383

GC 205 Genesis ChevronTexaco 2,828 11,442,541

MO 824 Unnamed ExxonMobil 49 11,327,104

SM 222 Unnamed ChevronTexaco 16 11,296,799

*cumulative production from January 2000 through May 2001

 

2 The forecasts were based on the MMS report Atlas of Gulf of Mexico Gas and Oil Sands (Bascle, 2001). Each

producing field and reservoir in the GOM was assigned to a hydrocarbon play. The 2000 Assessment then forecast

the number of hydrocarbons remaining to be discovered in the GOM on the following factors:

1) the number and size of discovered accumulations in an established play

2) an estimate of the number of undiscovered accumulations in a play

3) lognormal size distribution for these accumulations

The MMS then predicted the size of undiscovered accumulations in each play. Frontier or conceptual plays were

modeled on similar but more mature plays. The undiscovered accumulations were then aggregated for all 92 plays

in the 2000 Assessment. To compare reserve numbers from mature fields, recent field discoveries, and estimates

from undiscovered fields, cumulative growth factors were used in the 2000 Assessment. It has been widely observed

that a field’s size “grows” throughout its lifespan. Reasons for this growth may vary widely, but may include areal

extension of existing reservoirs, discovery of new reservoirs, improvement in production procedures, and the natural

conservatism of early estimates. A detailed discussion of reserve appreciation and cumulative growth factors may

be found starting on page 49 of the 2000 Assessment. The estimated ultimate recovery volumes were then used for

the forecasts in the 2000 Assessment.


83

Figure 58a 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 is now at its lowest

level since 1967. The deepwater GOM oil production, however, is in the midst of a dramatic

increase similar to that seen in the shallow-water GOM during the 1960’s. Melancon et al.

(2002) predict that this production surge has not yet peaked. This strong increase in deepwater

oil production more than offsets recent declines in shallow-water oil production. In 2001,

deepwater oil production accounted for 59 percent of GOM oil production.

Figure 58b shows similar production trends for gas. Shallow-water gas production rose sharply

throughout the 1960’s and 1970’s, then remained relatively stable over the next 15 years before

declining steadily from 1996 through today. Although the deepwater gas production increase has

not been as dramatic as with oil, the steady increase in deepwater gas production that occurred in

the past few years offsets the shallow-water decline. Appendix F lists historical GOM oil and

gas production rates. These trends in oil and gas production indicate that the deepwater GOM is

an expanding frontier.

A significant portion of deepwater production comes from subsea completions. Figure 59a

shows that very little deepwater oil production came from subsea completions until mid-1995,

but by the fall of 1996 that production had risen to about 20 percent. Deepwater subsea oil

production increased through 1999, representing almost 30 percent of all deepwater oil

production in January 2000. However, a surprising trend of declining deepwater subsea oil

production occurred in 2000 and early 2001. Deepwater gas production from subsea

completions (figure 59b) showed a similar trend. No deepwater gas production came from

subsea completions in early 1993, but by mid-1994 these accounted for over 40 percent of

deepwater GOM gas production. Gas production from subsea completions increased from 1996

through 1999, but declined in 2000 and early 2001. These oil and gas production declines are

likely related to the anomalously small number of subsea completions in 2000 (figure 43 and

table 2). However, numerous subsea projects began production in 2001, and many more are

expected in the next few years. Therefore, we do not anticipate a continued decline in oil and

gas production coming from subsea completions. Subsea completions currently account for

about 20 percent of deepwater oil production and about 25 percent of deepwater gas production.

Companies and Production

Deepwater oil and gas production was confined almost entirely to major oil and gas companies

through 1996 (figures 60a and 60b). (Production volumes in figures 60a-b and 61a-b are

attributed to companies on the basis of their percentage of lease ownership. For example, if

Shell owned 75 percent of a particular lease in July 1997, then 75 percent of that lease’s

production was attributed to Shell that month.) In 1998 and 1999 nonmajor companies

significantly increased their deepwater oil production. However, in 2000 and early 2001

nonmajor oil production leveled off while major oil companies continued their steep increases in

oil production. Figures 61a and 61b show that nonmajor oil and gas companies contributed

about 15 percent of deepwater oil production from 1992 through 1997. Nonmajor companies

increased their share of deepwater oil production in 1998 and early 1999. In contrast, nonmajor

companies accounted for about 40 percent of deepwater gas production in early 1994. This
1947

1949

1951

1953

1955

19571959

1961

1963

19651967

1969

1971

1973

19751977

1979

1981

1983

19851987

1989

1991

19931995

1997

1999

2001

0

200

400

600

800

1,000

1,200

Thousand Barrels of Oil Per Day

Year

Deepwater

Shallow water

1947

1949

1951

19531955

1957

1959

1961

19631965

1967

1969

1971

19731975

1977

1979

1981

19831985

1987

1989

1991

19931995

1997

1999

2001

0.0

2.0

4.0

6.0

8.0

10.0

12.0

14.0

Billion Cubic Feet of Gas Per Day

Year

84

(b)

Figure 58. - Comparison of average annual shallow- and deepwater

 (a) oil production and (b) gas production.

(a)

Deepwater

Shallow water
0

500,000

1,000,000

1,500,000

2,000,000

2,500,000

3,000,000

3,500,000

Thousand Cubic Feet of Gas Per Day

Jan-92 Jan-93 Jan-94 Jan-95 Jan-96 Jan-97 Jan-98 Jan-99 Jan-00 Jan-01

Date

Deepwater subsea completions

Total deepwater gas

0

100,000

200,000

300,000

400,000

500,000

600,000

700,000

800,000

900,000

Barrels of Oil Per Day

Jan-92 Jan-93 Jan-94 Jan-95 Jan-96 Jan-97 Jan-98 Jan-99 Jan-00 Jan-01

Date

Deepwater subsea completions

Total deepwater oil

85

(b)

(a)

Figure 59. - Contributions from subsea completions toward total deepwater

 (a) oil production and (b) gas production.
0

100,000

200,000

300,000

400,000

500,000

600,000

700,000

Jan-92 Jan-93 Jan-94 Jan-95 Jan-96 Jan-97 Jan-98 Jan-99 Jan-00 Jan-01

Date

Barrels of Oil Per Day

Figure 60. - Comparison of major companies and nonmajor

 companies in terms of deepwater (a) oil production

 and (b) gas production.

(a)

86

Majors

Nonmajors

0

500,000

1,000,000

1,500,000

2,000,000

2,500,000

3,000,000

Jan-92 Jan-93 Jan-94 Jan-95 Jan-96 Jan-97 Jan-98 Jan-99 Jan-00 Jan-01

Date

Thousand Cubic Feet of Gas Per Day

(b)

Majors

Nonmajors
0.0

5.0

10.0

15.0

20.0

25.0

30.0

35.0

Jan-92 Jan-93 Jan-94 Jan-95 Jan-96 Jan-97 Jan-98 Jan-99 Jan-00 Jan-01

Date

Percentage

0.0

5.0

10.0

15.0

20.0

25.0

30.0

35.0

40.0

45.0

50.0

Jan-92 Jan-93 Jan-94 Jan-95 Jan-96 Jan-97 Jan-98 Jan-99 Jan-00 Jan-01

Date

Percentage

(a)

(b)

Figure 61. - Percentage of deepwater (a) oil production and (b) gas

 production from nonmajor oil and gas companies.

87
88

percentage declined steadily until 1998 (primarily because of Shell’s increased deepwater gas

production). Nonmajor companies slightly increased their share of deepwater gas production in

1998 and early 1999, but this trend ended in mid-1999. Nonmajor companies currently own

about 25 percent of deepwater GOM oil and gas production.

Figures 62a and 62b display production contributions from each major oil and gas company.

Shell and BP were the driving forces behind increasing deepwater production, with Shell as the

clear leader in both oil and gas production. Shell’s dominance in deepwater oil production began

before 1992 and has continued. Shell also led in deepwater gas production, including a dramatic

increase in 1997. Although BP’s deepwater oil production started slightly behind Shell’s, their

oil production increases paralleled one another throughout the 1990’s (in part because Shell and

BP have joint ownership in several large deepwater fields). Since mid-1999, however, Shell’s

deepwater oil production increase has outpaced that of other major companies. ExxonMobil

currently runs a distant third in terms of deepwater GOM oil production, but is slightly ahead of

BP in deepwater GOM gas production.

Production Rates

High well production rates have been a driving force behind the success of deepwater operations.

Figure 63a illustrates the highest deepwater oil production rates (daily averages from a full

month of production). For example, a well within Shell’s Bullwinkle field produced about 5,000

BOPD in 1992. In 1994, a well within Shell’s Auger field set a record, producing about 10,000

BOPD. From 1994 through mid-1999, maximum deepwater oil production rates continued to

climb, especially in water depths between 1,500 and 4,999 ft. Since mid-1999, the maximum

production rates have declined. Note that there is currently no production in water depths greater

than 7,500 ft and only minimal liquid production in water depths greater than 5,000 ft (from

Shell’s Mensa field, which primarily produces gas). Figure 63b shows similar production rates

for gas. Maximum deepwater gas production rates hovered around 25 MMCFPD until a well in

Shell’s Popeye field raised the deepwater production record to over 100 MMCFPD in 1996.

Since then, the deeper waters have yielded even higher maximum production rates. In 1997,

Shell’s Mensa field showed the excellent potential for ultra-deepwater production rates. Note

that the steep fluctuations in production rates within the 5,000-7,499 ft water depths probably

relate to the limited number of wells producing in this depth range. That is, when the only well

on production is shut in for a short period of time, there are no other wells to become the

maximum producer during the lull. Since the third Mensa well commenced production in late

1998, the maximum production rates in the 5,000-7,499 ft water-depth range have stabilized at

approximately 90 MMCFPD. The record daily oil and gas production rates (for a single well)

remain at 36,520 BOPD (Ursa) and 196 MMCFPD (Mensa), respectively. Although excellent

production rates are characteristic of deepwater reservoirs, record production rates are not

expected to change significantly.

Figures 64 (oil) and 65 (gas) compare maximum historical production rates for each lease in the

GOM. That is, the well with the highest historical production rate is shown for each lease.

These maps show that many deepwater fields produce at some of the highest rates ever

encountered in the GOM. Figure 64 also shows that maximum oil rates were significantly higher

off the southeast Louisiana coast than off the Texas coast. Figure 65 illustrates the high
Jan-92 Jan-93 Jan-94 Jan-95 Jan-96 Jan-97 Jan-98 Jan-99 Jan-00 Jan-01

0.0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

Billion Cubic Feet of Gas Per Day

Date ChevronTexaco

BP

ExxonMobil

Shell

Jan-92 Jan-93 Jan-94 Jan-95 Jan-96 Jan-97 Jan-98 Jan-99 Jan-00 Jan-01

0

50

100

150

200

250

300

350

Thousand Barrels of Oil Per Day

Date ChevronTexaco

ExxonMobil

BP

Shell

Figure 62. - Contributions from each major oil company toward total

 deepwater (a) oil production and (b) gas production.

(b)

(a)

89
Jan-92 Jan-93 Jan-94 Jan-95 Jan-96 Jan-97 Jan-98 Jan-99 Jan-00 Jan-01

0

20,000

40,000

60,000

80,000

100,000

120,000

140,000

160,000

180,000

200,000

 1,000-1,499 ft

 1,500-4,999 ft

 5,000-7,499 ft

Jan-92 Jan-93 Jan-94 Jan-95 Jan-96 Jan-97 Jan-98 Jan-99 Jan-00 Jan-01

0

10,000

20,000

30,000

40,000

 1,000-1,499 ft

 1,500 -4,999 ft

 5,000-7,499 ft

Figure 63. - Maximum production rates for a single well within each

 water-depth category for deepwater (a) oil production

 and (b) gas production.

(a)

(b)

1,000-1,499 ft

5,000-7,499 ft

Bullwinkle

Auger

Mars

Troika

1,500-4,999 ft

Auger

Mensa

Bullwinkle

5,000-7,499 ft

1,500-4,999 ft

1,000-1,499 ft

Popeye

90

Ursa

Date

Date

Barrels of Oil Per Day Thousand Cubic Feet of Gas Per Day


93

deepwater gas production rates relative to the rest of the GOM. Note also the excellent

production rates from the Norphlet trend (off the Alabama coast) and the Corsair trend (off the

Texas coast).

Figures 66 (oil) and 67 (gas) highlight the most prolific fields and illustrate that, since 1996,

deepwater oil and gas fields comprise the majority of these fields. Note that in 2000-2001, high

production rates occur off the Texas coast at the Diana and Hoover fields.




98

Summary and Conclusions 

This report has discussed

• the importance of the deepwater to overall Gulf of Mexico (GOM) oil and gas

production,

• the historical trend in deepwater leasing toward increasing water depths and increased

bid values,

• deepwater lease holdings of major oil and gas companies compared with nonmajor

companies, showing the increased presence of nonmajor companies,

• the impact of company mergers on deepwater lease holdings,

• future deepwater lease availability and anticipated lease expirations,

• substantial increases in deepwater rig activity leading to significant increases in

deepwater drilling and rapid leaps toward deeper waters,

• the increase in deepwater development activity,

• the progression of infrastructure development, which includes hubs, pipelines, and

subsea systems reaching into ever deeper waters,

• the anticipated large deepwater reserve additions, especially when unproved reserves,

known resources, and recent industry-announced discoveries are considered,

• the large increase in average deepwater field sizes when compared with same-year

shallow-water discoveries,

• the potential for numerous, future large deepwater field discoveries,

• the increasing contribution of deepwater oil and gas production toward total GOM

production,

• the domination by major oil companies in deepwater production, led by Shell and BP,

and

• the very high deepwater production rates compared with shallow-water production

rates.

The remainder of this report combines historical leasing, drilling, development, reserve, and

production data, revealing overall trends in deepwater activity and expectations.

Figure 68 illustrates deepwater projects that began production in 2001 and those expected to

commence production in the next four years. Fourteen deepwater projects began production in

2001, the largest single-year increase in history. Many more projects are expected to begin

production in the next few years. Several are not shown in figure 68 because operators requested

that the information remain confidential.

Development Cycle

Deepwater leasing activity accelerated in the late 1990’s after Congress enacted the Deep Water

Royalty Relief Act. The full effect of this leasing, however, will not be realized for several years

because there can be considerable lags between leasing and first production, as illustrated in

figure 69. There was considerable lease activity in the late 1980’s. (Note that historic deepwater

leasing shows no clear relation to average oil prices.) Acreage at Auger (Garden Banks 426

field) was acquired in 1985 as part of this early activity. The first Auger well was drilled soon

30 4

11

32

201

539

863

405

102

2072

395

332

0

500

1000150020002500

1974-75 1976-77 1978-79 1980-81 1982-83 1984-85 1986-87 1988-89 1990-91 1992-93 1994-95 1996-97 1

Year Leases Acquired

Number of Leases

 Number of leases Average U.S. oil price

Auger=GB426Thunder Horse=MC778

Auger leased (1985)

1st Auger well (1987) 1st Auger production (1994)

Figure 69. - Deepwater lease activity and oil prices (oil prices from Monthly Energy Review, Apr February 2002; Basic Petroleum Data Book, 1996).

100 Thunder Horse leased (1988) 1st Thunder Horse well (1999)
101

after in 1987. Even though Auger was leased and drilled early, first production did not begin

until 1994, approximately 10 years after the initial lease acquisition. Acreage at Thunder Horse

(Mississippi Canyon 778) was acquired in 1988; however, the discovery was not drilled until

1999, and production is not anticipated until 2005. These lags are not unusual with complex

deepwater developments. In contrast, other deepwater fields such as Typhoon (Green Canyon

236) have achieved short cycle times, a product of infrastructure location and use of proven

development technologies.

Figures 70a-c demonstrate average lags associated with deepwater operations. These figures use

data only from deepwater leases that have become productive. Figure 70a shows the average

number of years it took to drill a well from the time the lease was issued. Figure 70b shows the

average length of time from lease issue to qualification3

 of the lease as productive. Figure 70c

illustrates the lags between leasing, qualification, and first production. Figure 71 uses a slightly

different population; it plots the lag for all leases drilled, all leases that qualified, and productive

leases. There is a declining number of leases in each succeeding category in figure 71 because

the number of leases drilled is higher than the number qualified, and the number of qualified

leases is higher than the number of productive leases. The bar heights in figure 71 represent the

total time elapsed since the leases were awarded.

There are two lags represented in figures 70a–c and 71. First, there is a lag between a deepwater

discovery and the operator’s request for lease qualification. Operators sometimes announce

discoveries to the public long before qualifying the lease as productive with MMS (and thereby

being granted field status). The second lag depicted in figures 70a-c and 71 is the lag between

leasing and subsequent operations (drilling, qualifying, and production). Note that, since

deepwater leases are in effect for 8 or 10 years, the data are incomplete beyond 1991. The

apparent decreasing lags for leases issued after 1991 are explained by the fact that the lease

evaluation process has not yet been completed.

The data show an increase from 1976 to 1987 in the number of years before the first well is

drilled (figure 70a). This is probably a reflection of two factors. First, the earliest deepwater

leases purchased were of very high interest to the lessees and, therefore, were drilled quickly.

Second, increasing lease inventories during the late 1980’s meant that many leases could not be

evaluated early in their lease terms (increased deepwater leasing in the mid- to late 1980’s was

probably related to the introduction of area-wide leasing, the drop in minimum required bid from

$150/acre to $25/acre, and the advent of 3-D seismic technology). Figure 70b shows similar

trends in the lags between lease issue and lease qualification. Exceptions include the long lags

between first drilling and qualifying from 1974 to 1979. During the 1980’s there was also a

gradual increase in the lag between drilling of the first well and qualifying the lease. During

most of the 1980’s, it took 10 to 11 years for the average field to come on production. It is

important to note, however, that the time between drilling the first well and the beginning of

production dropped significantly throughout the 1980’s. That is, operators brought fields online

in about ten years, despite the fact that the first wells were not drilled, on average, until about the

fourth year of the lease term by the late 1980’s. Note that the time from lease to first production

 

3

 An operator may request a “Determination of Well Producibility” from MMS. A successful MMS determination

then “qualifies” the lease as producible. Not all qualified leases ultimately begin production.
Figure 70a. - Lag from leasing to first well for producing deepwater fields.

2.41

0.29 1.14

3.63 3.96 4.75

3.22

4.43

2.19 1.84 1.60 0.32

0.72 0.57

0.00

2.00

4.00

6.00

8.00

10.00

12.00

1974-75 1976-77 1978-79 1980-81 1982-83 1984-85 1986-87 1988-89 1990-91 1992-93 1994-95 1996-97 1998-99 2000-01

Year Lease Acquired

Number of Years

Years to first well

Figure 70b. - Lag from leasing to qualifying for producing deepwater fields. 

1.90

1.89

3.59

2.76

0.20

5.19

1.39

0.94

0.81

0.85

0.97 1.50

0.64

0.27

0.00

2.00

4.00

6.00

8.00

10.00

12.00

1974-75 1976-77 1978-79 1980-81 1982-83 1984-85 1986-87 1988-89 1990-91 1992-93 1994-95 1996-97 1998-99 2000-01

Year Lease Acquired

Number of Years

Additional time to qualify lease

Years to first well

Figure 70c. - Lag from leasing to first production for producing deepwater fields.

6.97

3.42

2.37

8.53 5.53 4.56

1.20

2.25

1.40

1.28

1.27

1.33 0.82

0.07

0.00

2.00

4.00

6.00

8.00

10.00

12.00

1974-75 1976-77 1978-79 1980-81 1982-83 1984-85 1986-87 1988-89 1990-91 1992-93 1994-95 1996-97 1998-99 2000-01

Year Lease Acquired

Number of Years

Additional time to first production

Additional time to qualify lease

Years to first well

102
 

02468

1012

1974-75 1976-77 1978-79 1980-81 1982-83 1984-85 1986-87 1988-89 1990-91 1992-93 1994-95 1996-97 

Number of Years

Years to fiYears to quYears to fi

29

1

10

16 92

134

40

72

39

27

33

48

Number of leases drilled 

Year Lease Acquired

103

Figure 71. - Lag from leasing to first well, lease qualification, and first field production for all drilled deepw
104

has decreased from ten to seven years, based on the latest complete data (1988-1991)—leases

that have exceeded their primary terms.

Figures 70a and 71 show early indications of interesting trends in the deepwater development

cycle, defined here as the time necessary to drill and develop acquired leases. One example is

that the first wells on deepwater leases were drilled about four years into their lease terms during

the late 1980’s and through 1991. The trends resulting from the large lease sales from 1996

through 1998 will not become evident for several more years.

In summary, the latest complete data indicate a four-year average lag between leasing and initial

drilling. There is an additional two-year average lag before the well is qualified, and a total of

seven years from lease issuance until production begins.

Drilling the Lease Inventory

The combination of huge deepwater lease inventories and a limited rig fleet dedicated to the

GOM means that numerous leases remain untested when their terms expire. Figure 72 shows

historical lease activity trends. As mentioned previously, these data are complete only through

1991, since most deepwater leases beyond that time are still under their primary terms and still

under evaluation. Over 90 percent of leases acquired in 1974-1975 and 1978-1979 were drilled.

About 70 percent of leases acquired in 1974-1975 later qualified (indicating they discovered

hydrocarbons) and about 50 percent came on production. Although less than 15 percent of the

leases issued in 1976-1977 were ever drilled, all those drilled came on production. The

percentage of leases drilled decreased rapidly throughout the 1980’s as lease inventories swelled.

As the percentage of leases drilled decreased, so did the percentage of issued leases that qualified

and the percentage that actually produced. Through 1991, less than 10 percent of issued

deepwater leases were drilled and less than 5 percent produced.

Deepwater economics differ significantly today from the economics of the late 1980’s.

Deepwater development technology was then still in its infancy and the extraordinary deepwater

production rates were yet to be realized.

Although the percentage of leases drilled decreased during the late 1980’s, the actual number of

leases issued and drilled generally increased, resulting in higher numbers of discoveries and

producing leases. These relationships among leasing, drilling, and production of offshore

deepwater blocks are shown in figures 73a-d. These figures use the same data set as in figures

70a-c, that is, two-year intervals of leases that have produced and are past their primary terms.

Figures 73a-b show that the number of leases issued correlates poorly with the number drilled

and the number produced. In contrast, the number of deepwater leases drilled correlates well

with the number of those leases that later produced (figure 73c). Similarly, the number of leases

that qualified as capable of production relates strongly with the number of those that eventually

produced (figure 73d).
Figure 72. - Activity on deepwater leases.

2125

400

105

410

865

336

540

209

39

30 7

11

0%

10%20%30%40%50%60%70%80%90%

100%

1974-75 1976-77 1978-79 1980-81 1982-83 1984-85 1986-87 1988-89 1990-91 1992-93 1994-95 1996-97 1998-

Year Lease Acquired

Percent of Leases with Each Activity

 Percent leases drilled Percent leases qualified Percent leases productive Number of leases bid

105
Figure 73b. - Relationship between number of leases bid and number of resulting

 producing leases, 1974-1991.

0

200

400

600

800

1,000

0 5 10 15 20 25 30 35

Number of Producing Leases

Number of Leases Bid

Figure 73c. - Relationship between number of leases drilled and number of

 resulting producing leases, 1974-1991.

0

50

100

150

0 5 10 15 20 25 30 35

Number of Producing Leases

Number of Leases 

Drilled

Figure 73d. - Relationship between number of qualifying leases and number of

 resulting producing leases, 1974-1991.

0

20

40

60

80

0 5 10 15 20 25 30 35

Number of Producing Leases

Number of Qualifying 

Leases

Figure 73a. - Relationship between number of leases bid and number of leases

 drilled, 1974-1991.

0

200

400

600

800

1,000

0 20 40 60 80 100 120 140 160

Number of Leases Drilled

Number of Leases Bid

106
107

Figure 74 shows the number of deepwater leases issued each year since 1992. This figure also

projects the exploratory evaluation of these leases, assuming that

• each lease is drilled four years into its primary lease term (average from figure 74),

• 10 to 20 percent of these leases are eventually drilled (estimates from figure 72),

• future lease acquisitions will not significantly impact drilling of the existing lease

inventory, and

• 67 untested deepwater leases can be drilled each year.4

History indicates that approximately 10 percent of the deepwater leases are evaluated, yet only

5 percent of the leases issued from 1996 through 1997 have been drilled. The effect of a limited

rig fleet on the ability to evaluate leases challenges operators to test their lease inventory. 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 personnel qualified to work on new drilling rigs.

Expanding Frontier

The future of deepwater GOM exploration and production is very promising. As shown in

figure 74, industry is in the heart of the exploratory evaluation of the exceptional number of

leases acquired in 1996 through 1998, and the frontier is expanding. The high number of wells

drilled on previously undrilled leases is likely to result in numerous deepwater discoveries.

Traditional deepwater minibasin plays are far from mature, as several recent discoveries attest,

and new deepwater plays near and even beyond the Sigsbee Escarpment show that the deepwater

GOM is an expanding frontier. As shown in figure 55, the immature deepwater creaming curve

predicts that numerous large undiscovered fields remain. The 2000 Assessment indicates that

more than 50 billion recoverable BOE remain to be discovered (Lore et al., 2001).

 

4

Deepwater drilling reached record levels in 2001 with an average 43 rigs active, 208 wells drilled, and a total of 67

leases initially drilled.
0

200400600800

100012001400

1992 1993 1994 1995 1996 1997 1998 1999 2000 2001 2002 2003 

Year

Number of Leases

Figure 74. - Anticipated effect of rig constraints on lease evaluations.

108

20 percent o

10 percent of 

deepwater leases issued

rig capabilities
109

The deepwater arena has made great strides in the last few years, establishing itself as an

expanding frontier. The previous edition of this report (Baud et al., 2000) documented the

advancements made in deepwater exploration and development since 1974. Several remarkable

achievements have been made since this report was last published.

• The number of drilling rigs working in deepwater has increased from 28 to 43.

• The number of ultra-deepwater capable rigs has increased from 18 to 26 (44 %) and

the number of ultra-deepwater wells increased from 37 to 59 (59%).

• There was a 59 percent increase in the number of producing deepwater fields.

• Deepwater production rates rose more than 100 MMBOPD and 400 MMCFPD each

year since 1997.

• Deepwater oil production is rapidly approaching the all-time shallow-water oil

production record established in 1971.

• New deepwater drilling added over 4 billion BOE, a 49 percent increase, to the GOM

oil and gas inventory.

• Several deepwater discoveries were made in very lightly tested plays. The Trident

(AC 903) well is the first significant discovery in the Perdido Foldbelt play.

The large volume of active deepwater leases, the increased drilling program, and the growing

deepwater infrastructure all indicate that the deepwater GOM will increase in importance as an

integral part of this Nation’s energy supply and will remain one of the world’s premier oil and

gas basins.
110

Contributing Personnel 

This report includes contributions from the following individuals.

Pat Adkins

Kim Altobelli

Eric Batchelder

Roy Bongiovanni

Donna Bourg

Pat Bryars

Mike Conner

Scott Edwards

Eric Kazanis

Ralph Klazynski

Connie Landry

Debbie Miller

Leslie Nixon

Paul Post

Mike Prendergast

Terry Rankin

Chris Schoennagel

Janice Todesco

Chee Yu
111

References 

Bascle, B. J., L. D. Nixon and K. M. Ross, 2001, Atlas of Gulf of Mexico Gas and Oil Reservoirs

as of January 1, 1999. Minerals Management Service, Gulf of Mexico OCS Region. OCS

Report MMS 2001–086, CD–ROM.

Basic Petroleum Data Book: Petroleum Industry Statistics, 1996. American Petroleum Institute.

Vol. 16. No. 1.

Baud, R. D., R. H. Peterson, C. Doyle, and G. E. Richardson, 2000, Deepwater Gulf of Mexico:

America’s Emerging Frontier. Minerals Management Service, Gulf of Mexico OCS Region.

OCS Report MMS 2000-022. New Orleans. 89 p.

Cranswick, D., and J. Regg, 1997, Deepwater in the Gulf of Mexico: America’s New Frontier.

Minerals Management Service, Gulf of Mexico OCS Region. OCS Report MMS 97-0004. New

Orleans. 41 p.

Crawford, T. G., B. J. Bascle, C. J. Kinler, M. T. Prendergast, and K. M. Ross, 2002, Estimated

Oil and Gas Reserves, Gulf of Mexico, December 31, 1999. Minerals Management Service, Gulf

of Mexico OCS Region. OCS Report MMS 2002-007. New Orleans. 26 p.

Harding, B. W., and E. K. Albaugh, 2001, “2001 Worldwide Survey of Deepwater Drilling

Rigs.” Poster 29. Offshore, July 2001.

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

Klazynski, 2001, 2000 Assessment of Conventionally Recoverable Hydrocarbon Resources of the

Gulf of Mexico and Atlantic Outer Continental Shelf as of January 1, 1999. Minerals

Management Service, Gulf of Mexico OCS Region. OCS Report MMS 2001-087. New

Orleans. 652 p. (CD–ROM only).

Maksoud, J., “Drilling Contractors direct cash flow into new units, upgrades, conversions,”

Offshore, July 2001. pp. 46-50.

Melancon, J. M., R. Bongiovanni, and R. D. Baud, 2002, Gulf of Mexico Outer Continental Shelf

Daily Oil and Gas Production Rate Projections From 2002 Through 2006. Minerals

Management Service, Gulf of Mexico OCS Region. In press. New Orleans.

Monthly Energy Review, April 1997. Energy Information Administration, Office of Energy

Markets and End Use, U.S. Department of Energy. DOE/EIA-0035(97/04).

Monthly Energy Review, February 2002. Energy Information Administration, Office of Energy

Markets and End Use, U.S. Department of Energy. www.eia.doe/emeu/aer/txt/tab0516.htm.

Shirley, K., 2001, “Time is Proving the Value of 4D.” AAPG Explorer. Vol. 22. No. 9.
112

U.S. Dept. of the Interior, Minerals Management Service. 2000. Gulf of Mexico Deepwater

Operations and Activities: Environmental Assessment. U.S. Dept. of the Interior, Minerals

Management Service, Gulf of Mexico OCS Region, New Orleans, LA. OCS EIS/EA MMS

2000-001.

U.S. Dept. of the Interior, Minerals Management Service, 2001. Proposed Use of Floating

Production, Storage, and Offloading Systems on the Gulf of Mexico Outer Continental Shelf:

Western and Central Planning Areas, Final Environmental Impact Statement. Prepared under

MMS contract 1435-01-99-CT-30962. OCS EIS/EA MMS 2000-090.
113

Appendix A – Announced Deepwater Discoveries and Fields (sorted by project name).

Project Name Block Water Depth (ft) Field Discovery

Date*

Month of First

Production

Year of Last

Production

ACONCAGUA MC 305 7,377 21-Feb-99

ALABASTER MC 397 1,551 Apr-92

ALLEGHENY GC 254 3,411 01-Jan-85 Oct-99

AMBERJACK MC 109 1,532 01-Jul-84 Oct-91

ANGUS GC 112 2,034 08-Jun-97 Sep-99

ANSTEY MC 607 6,704 12-Nov-97

ARIEL MC 429 6,288 20-Nov-95 Oct-93

ARNOLD EW 963 1,971 12-Jun-96 May-98

ASPEN GC 243 3,149

ATLANTIS GC 699 5,432 12-May-98

AUGER GB 426 2,883 01-May-87 Apr-94

BAHA AC 600 10,975 23-May-96

BALDPATE GB 260 1,758 01-Nov-91 Sep-98

BISON GC 166 2,555 01-Mar-86

BLIND FAITH MC 696 6,941

BOURBON MC 311 1,466 Mar-80

BRUTUS GC 158 3,090 01-Mar-89

BULLWINKLE GC 65 1,404 01-Oct-83 Jul-89

CAMDEN HILLS MC 348 7,528 04-Aug-99

CERVEZA LIGERA EB 160 1,358

CHAMPLAIN AT 63 4,631 11-Feb-00

COGNAC MC 194 1,345 01-Jul-75 Aug-79

COOPER/LLANO GB 387 2,706 01-Mar-89 Sep-95 1999

COULOMB MC 657 7,767 01-Nov-87

CYCLOPS AT 008 3,392 26-Apr-97

DEVIL'S TOWER MC 773 5,701 13-Dec-99

DIAMOND MC 445 1,633 05-Dec-92 Oct-93 1999

DIANA EB 945 4,746 01-Aug-90 May-00

DIONYSIS VK 864 1,597 01-Oct-81

DULCIMER GB 367 1,112 09-Feb-98 Apr-99

DURANGO GB 667 3,014

EAST BOOMVANG EB 688 3,847 01-May-88

EINSET VK 873 4,107 01-Mar-88 Apr-01

EL TORO GC 69 2,263 13-Sep-84

ENTRADA GB 782 4,642

EUROPA MC 935 4,070 22-Apr-94 Feb-00

FIREBIRD MC 705 1,266

FOURIER/HERSCHEL MC 522 7,137 01-Jul-89

FRONT RUNNER GC 338 3,447

FRONT RUNNER S GC 339 3,539

FUJI GC 506 4,326 30-Jan-95

GEMINI MC 292 4,786 07-Sep-95 May-99

GENESIS GC 205 2,827 01-Sep-88 Jan-99

GOMEZ MC 755 3,123 19-Mar-86
114

Project Name Block Water Depth (ft) Field Discovery

Date*

Month of First

Production

Year of Last

Production

GUNNISON GB 668 3,205 29-May-00

HAWKES MC 509 4,174

HOLSTEIN GC 644 4,418 11-Feb-99

HOOVER AC 25 4,907

JOLLIET GC 184 2,083 01-Jul-81 Nov-89

K2 GC 562 4,231 21-Sep-99

KEPLER MC 383 5,920 01-Aug-87 Apr-92

KING MC 84 5,622

KING KONG GC 472 3,943 01-Feb-89

KING'S PEAK DC 133 6,665 01-Mar-93

LADY BUG GB 409 1,591 13-May-97

LENA MC 281 1,624 01-May-76 Jan-84

LEO MC 546 2,945 01-Feb-86

LOST ARK EB 421 2,740

MACARONI GB 602 3,759 21-Jan-96 Aug-99

MAD DOG GC 826 7,137 24-Nov-98

MADISON AC 24 4,923 25-Jun-98

MAGNOLIA GB 783 4,717 03-May-99

MARATHON GC 153 2,463 01-Apr-84

MARCO POLO GC 608 4,320

MARIA VK 739 1,096 Mar-01

MARLIN VK 915 4,100 01-Jun-93 Feb-01

MARQUETTE GC 52 1,027 May-90

MARS MC 807 3,326 01-Apr-89 Jul-96

MARSHALL EB 949 4,526 30-Jul-98

MATTERHORN MC 243 3,323 01-Sep-90

MEDUSA MC 582 2,880 17-Oct-99

MENSA MC 731 5,546 01-Dec-86 Jul-97

MICA MC 211 4,549 01-May-90

McKINLEY GC 416 4,221 14-Jul-98

MIGHTY JOE YOUNG GC 737 4,429

MIRAGE MC 941 4,346

MORGUS MC 942 4,376

MORPETH/KLAMATH EW 921 1,860 01-May-86 Mar-99

MOSQUITO HAWK GB 269 1,246 06-Mar-96

MUSTIQUE GB 240 1,027 Jan-96

NANSEN EB 602 3,913 25-Sep-99

NARCISSUS MC 630 4,250

NEPTUNE (AT) AT 575 6,373 26-Sep-95

NEPTUNE/THOR VK 825 1,932 01-Nov-87 Mar-97

NILE VK 914 3,910 30-Apr-97 Apr-01

NIRVANA MC 162 4,169 30-Nov-94

NORTH BOOMVANG EB 642 3,933 13-Dec-97

NORTHWESTERN GB 200 1,935 14-May-98 Nov-00

OREGANO GB 559 3,582 27-Mar-99

PETRONIUS VK 786 2,539 14-Jul-95 Jul-00
115

Project Name Block Water Depth (ft) Field Discovery

Date*

Month of First

Production

Year of Last

Production

PIMENTO GB 236 1,315

PLUTO MC 718 3,004 20-Oct-95 Dec-99

POMPANO VK 990 1,670 01-May-81 Oct-94

POPEYE GC 116 2,545 01-Feb-85 Jan-96

POSEIDON GC 691 4,595 27-Feb-96

PRINCE EW 958 1,522 20-Jul-94

PRINCESS MC 765 3,880

PROSPERITY VK 742 1,551 08-Aug-97 Sep-98

PTOLEMY GB 412 1,515 01-Jul-84

RAM-POWELL VK 956 4,057 01-May-85 Sep-97

RED HAWK GB 877 5,334

ROCKEFELLER EB 992 4,848 28-Nov-95

ROCKY GC 110 1,788 07-Aug-87 Jan-96

SALSA GB 171 1,427 18-Apr-84 Aug-98

SANGRIA GC 177 1,879 27-Oct-99 Nov-89

SEATTLE SLEW EW 914 1,019 01-Aug-84 Aug-93 1997

SERRANO GB 516 3,454 23-Jul-96

SHASTA GC 136 1,289 Nov-95

SNAPPER EB 165 1,148

SPEND-A-BUCK GB 161 1,328

SPIRIT VK 780 1,250 Sep-98

SUPERTRAMP MC 026 1,433 27-May-94

TAHOE VK 783 1,689 01-Dec-84 Jan-94

THUNDER HORSE MC 778 6,442 01-Apr-99

THUNDER HORSE NORTH MC 776 5,700

TICK GB 189 1,135

TIMBER WOLF MC 555 4,749

TRIDENT AC 903 9,687

TROIKA GC 244 3,175 30-May-94 Nov-97

TULANE GB 158 1,358

TYPHOON GC 236 2,539 01-Oct-84

URSA MC 810 4,077 01-Oct-90 Mar-99

VIRGO VK 823 1,637 02-May-97 Nov-99

WEST BOOMVANG EB 643 3,929 31-Oct-99

YUKON GC 60 1,135 Sep-96

ZINC MC 354 1,515 01-Aug-77 Jul-93

EB 157 1,194

EB 158 1,368

EB 377 2,555 01-Oct-85

EW 1006 1,952 26-Jan-88 Mar-99

EW 871 1,000

EW 878 1,850 03-Jul-00

EW 991 1,355

GB 208 1,506 01-Sep-91

GB 224 1,069

GB 254 1,942 23-Jul-93 Sep-98

GB 302 2,430 01-Feb-91
116

Project Name Block Water Depth (ft) Field Discovery

Date*

Month of First

Production

Year of Last

Production

GB 379 2,227 01-Jul-85

GC 141 1,715

GC 147 1,364 01-May-88

GC 162 2,804 01-Jul-89

GC 21 1,401 01-Oct-84

GC 228 2,713 01-Jul-85

GC 27 0 01-Jul-89

GC 29 1,837 01-Jan-84 Nov-88 1990

GC 39 2,434 01-Apr-84

GC 463 4,136 01-Dec-98

GC 70 2,280 01-Jun-84

GC 75 2,670 01-May-85 Nov-88 1989

MC 68 1,604 09-Dec-75 Jan-01

MC 113 2,473 01-Jan-76

MC 285 3,280 01-Sep-87

MC 455 1,633 01-Feb-86 Nov-90

MC 486 1,463 Nov-90

MC 709 2,680 01-Feb-87

MC 929 2,430 01-Nov-87

PI 525 3,506 30-Apr-96

VK 741 1,345

VK 827 2,739 08-Nov-98

VK 862 1,184 01-Oct-76 Dec-95
117

Appendix B – Announced Deepwater Discoveries and Fields (sorted by discovery date).

Project Name Block Water Depth (ft) Field Discovery

Date*

Month of First

Production

Year of Last

Production

COGNAC MC 194 1,345 01-Jul-75 Aug-79

MC 068 1,604 09-Dec-75 Jan-01

MC 113 2,473 01-Jan-76

LENA MC 281 1,624 01-May-76 Jan-84

VK 862 1,184 01-Oct-76 Dec-95

ZINC MC 354 1,515 01-Aug-77 Jul-93

POMPANO VK 990 1,670 01-May-81 Oct-94

JOLLIET GC 184 2,083 01-Jul-81 Nov-89

DIONYSIS VK 864 1,597 01-Oct-81

BULLWINKLE GC 65 1,404 01-Oct-83 Jul-89

GC 29 1,837 01-Jan-84 Nov-88 1990

GC 39 2,434 01-Apr-84

MARATHON GC 153 2,463 01-Apr-84

SALSA GB 171 1,427 18-Apr-84 Aug-98

GC 70 2,280 01-Jun-84

AMBERJACK MC 109 1,532 01-Jul-84 Oct-91

PTOLEMY GB 412 1,515 01-Jul-84

SEATTLE SLEW EW 914 1,019 01-Aug-84 Aug-93 1997

EL TORO GC 69 2,263 13-Sep-84

GC 21 1,401 01-Oct-84

TYPHOON GC 236 2,539 01-Oct-84

TAHOE VK 783 1,689 01-Dec-84 Jan-94

ALLEGHENY GC 254 3,411 01-Jan-85 Oct-99

POPEYE GC 116 2,545 01-Feb-85 Jan-96

GC 75 2,670 01-May-85 Nov-88 1989

RAM-POWELL VK 956 4,057 01-May-85 Sep-97

GB 379 2,227 01-Jul-85

GC 228 2,713 01-Jul-85

EB 377 2,555 01-Oct-85

MC 455 1,633 01-Feb-86 Nov-90

LEO MC 546 2,945 01-Feb-86

BISON GC 166 2,555 01-Mar-86

GOMEZ MC 755 3,123 19-Mar-86

MORPETH/KLAMATH EW 921 1,860 01-May-86 Mar-99

MENSA MC 731 5,546 01-Dec-86 Jul-97

MC 709 2,680 01-Feb-87

AUGER GB 426 2,883 01-May-87 Apr-94

KEPLER MC 383 5,920 01-Aug-87 Apr-92

ROCKY GC 110 1,788 07-Aug-87 Jan-96

MC 285 3,280 01-Sep-87

MC 929 2,430 01-Nov-87

COULOMB MC 657 7,767 01-Nov-87

NEPTUNE/THOR VK 825 1,932 01-Nov-87 Mar-97

EW 1006 1,952 26-Jan-88 Mar-99

EINSET VK 873 4,107 01-Mar-88 Apr-01
118

Project Name Block Water Depth (ft) Field Discovery

Date*

Month of First

Production

Year of Last

Production

GC 147 1,364 01-May-88

EAST BOOMVANG EB 688 3,847 01-May-88

GENESIS GC 205 2,827 01-Sep-88 Jan-99

KING KONG GC 472 3,943 01-Feb-89

BRUTUS GC 158 3,090 01-Mar-89

COOPER/LLANO GB 387 2,706 01-Mar-89 Sep-95 1999

MARS MC 807 3,326 01-Apr-89 Jul-96

GC 162 2,804 01-Jul-89

GC 27 0 01-Jul-89

FOURIER/HERSCHEL MC 522 7,137 01-Jul-89

MICA MC 211 4,549 01-May-90

DIANA EB 945 4,746 01-Aug-90 May-00

MATTERHORN MC 243 3,323 01-Sep-90

URSA MC 810 4,077 01-Oct-90 Mar-99

GB 302 2,430 01-Feb-91

GB 208 1,506 01-Sep-91

BALDPATE GB 260 1,758 01-Nov-91 Sep-98

DIAMOND MC 445 1,633 05-Dec-92 Oct-93 1999

KING'S PEAK DC 133 6,665 01-Mar-93

MARLIN VK 915 4,100 01-Jun-93 Feb-01

GB 254 1,942 23-Jul-93 Sep-98

EUROPA MC 935 4,070 22-Apr-94 Feb-00

SUPERTRAMP MC 026 1,433 27-May-94

TROIKA GC 244 3,175 30-May-94 Nov-97

PRINCE EW 958 1,522 20-Jul-94

NIRVANA MC 162 4,169 30-Nov-94

FUJI GC 506 4,326 30-Jan-95

PETRONIUS VK 786 2,539 14-Jul-95 Jul-00

GEMINI MC292 2,539 07-Sep-95 May-99

NEPTUNE (AT) AT 575 6,373 26-Sep-95

PLUTO MC 718 3,004 20-Oct-95 Dec-99

ARIEL MC 429 6,288 20-Nov-95 Oct-93

ROCKEFELLER EB 992 4,848 28-Nov-95

MACARONI GB 602 3,759 21-Jan-96 Aug-99

POSEIDON GC 691 4,595 27-Feb-96

MOSQUITO HAWK GB 269 1,246 06-Mar-96

PI 525 3,506 30-Apr-96

BAHA AC 600 10,975 23-May-96

ARNOLD EW 963 1,971 12-Jun-96 May-98

SERRANO GB 516 3,454 23-Jul-96

CYCLOPS AT 008 3,392 26-Apr-97

NILE VK 914 3,910 30-Apr-97 Apr-01

VIRGO VK 823 1,637 02-May-97 Nov-99

LADY BUG GB 409 1,591 13-May-97

ANGUS GC 112 2,034 08-Jun-97 Sep-99

PROSPERITY VK 742 1,551 08-Aug-97 Sep-98

ANSTEY MC 607 6,704 12-Nov-97
119

Project Name Block Water Depth (ft) Field Discovery

Date*

Month of First

Production

Year of Last

Production

NORTH BOOMVANG EB 642 3,933 13-Dec-97

DULCIMER GB 367 1,112 09-Feb-98 Apr-99

ATLANTIS GC 699 5,432 12-May-98

NORTHWESTERN GB 200 1,935 14-May-98 Nov-00

MADISON AC 24 4,923 25-Jun-98

McKINLEY GC 416 4,221 14-Jul-98

MARSHALL EB 949 4,526 30-Jul-98

VK 827 2,739 08-Nov-98

MAD DOG GC 826 7,137 24-Nov-98

GC 463 4,136 01-Dec-98

HOLSTEIN GC 644 4,418 11-Feb-99

ACONCAGUA MC 305 7,377 21-Feb-99

OREGANO GB 559 3,582 27-Mar-99

THUNDER HORSE MC 778 6,442 01-Apr-99

MAGNOLIA GB 783 4,717 03-May-99

CAMDEN HILLS MC 348 7,528 04-Aug-99

K2 GC 562 4,231 21-Sep-99

NANSEN EB 602 3,913 25-Sep-99

MEDUSA MC 582 2,880 17-Oct-99

SANGRIA GC 177 1,879 27-Oct-99 Nov-89

WEST BOOMVANG EB 643 3,929 31-Oct-99

DEVIL'S TOWER MC 773 5,701 13-Dec-99

CHAMPLAIN AT 63 4,631 11-Feb-00

GUNNISON GB 668 3,205 29-May-00

EW 878 1,850 03-Jul-00

EB 157 1,194

EB 158 1,368

EW 991 1,355

GB 224 1,069

GC 141 1,715

MC 486 1,463 Nov-90

MC 68 1,604 Jan-01

VK 741 1,345

ALABASTER MC 397 1,551 Apr-92

ASPEN GC 243 3,149

BLIND FAITH MC 696 6,941

BOURBON MC 311 1,466 Mar-80

CERVEZA LIGERA EB 160 1,358

CHAMPLAIN AT 63 4,382

DURANGO GB 667 3,014

ENTRADA GB 782 4,642

FIREBIRD MC 705 1,266

FRONT RUNNER GC 338 3,447

FRONT RUNNER S GC 339 3,539

HAWKES MC 509 4,174

HOOVER AC 25 4,907

KING MC 84 5,622
120

Project Name Block Water Depth (ft) Field Discovery

Date*

Month of First

Production

Year of Last

Production

LOST ARK EB 421 2,740

MARCO POLO GC 608 4,320

MARIA VK 739 1,096 Mar-01

MARQUETTE GC 52 1,027 May-90

MIGHTY JOE YOUNG GC 737 4,429

MIRAGE MC 941 4,346

MORGUS MC 942 4,376

MUSTIQUE GB 240 1,027 Jan-96

NARCISSUS MC 630 4,250

PIMENTO GB 236 1,315

PRINCESS MC 765 3,880

RED HAWK GB 877 5,334

SHASTA GC 136 1,289 Nov-95

SNAPPER EB 165 1,148

SPEND-A-BUCK GB 161 1,328

SPIRIT VK 780 1,250 Sep-98

THUNDER HORSE NORTH MC 776 5,700

TICK GB 189 1,135

TIMBER WOLF MC 555 4,749

TRIDENT AC 903 9,687

TULANE GB 158 1,358

YUKON GC 60 1,135 Sep-96
121

Appendix C – Companies Defined as Majors in this Report.

Group Name Company Name MMS Number

Amoco Corporation 02244

Amoco Foundation, Inc. 01679

Amoco Pipeline Company 00751

Amoco Production Company 00114

ARCO Pipe Line Company 00486

Atlantic Richfield Company 00967

BP Amoco Corporation 02367

BP Exploration & Oil Inc. 01680

BP Exploration & Production Inc. 02481

BP Prod. Corp. 02350

Sohio Alaska Petroleum Company 00113

Vastar Offshore, Inc. 02316

Vastar Pipeline, LLC 02317

Vastar Resources, Inc. 01855

* Atlantic Richfield Company 00002

* The Atlantic Refining Company 00002

* Amoco Canyon Company 00735

* BP Alaska Exploration Inc. 00301

* BP Exploration Inc. 00593

* BP Exploration U.S.A., Inc. 00120

* BP Oil Company 01680

* BP Oil Corporation 00120

* Sohio Natural Resources 00113

* Sohio Petroleum Company 00113

BP

* Sohio Petroleum Company 00593

Chevron Corporation 02335

Chevron Oil Company of the Netherlands 01443

Chevron Pipe Line Company 00400

Chevron U.S.A. Inc. 00078

Chevron U.S.A. LP 02544

* Chevron Oil Company 00078

* Chevron PBC, Inc. 01750

* Gulf Oil Corporation 00112

Equilon Pipeline Company LLC 01107

Four Star Oil & Gas Company 00005

Texaco Inc. 00040

Texaco Exploration and Production Inc. 00771

Texaco Trading and Transportation, Inc. 02020

* Getty Oil Company 00005

* Getty Pipeline, Inc. 01107

* Getty Reserve Oil, Inc. 00578

* Texaco Oils Inc. 00857

* Texaco Pipeline Inc. 01107

* Texaco Producing Inc. 00771

ChevronTexaco**

* Texaco Seaboard Inc. 00025
122

Group Name Company Name MMS Number

Exxon Asset Holdings LLC 02356

Exxon Asset Management Company 02295

Exxon Mobil Corporation 00276

Exxon Mobil Oil Corporation 00039

Exxon Mobil Pipeline Company 00103

Mobil Corporation 02221

MOBIL E&P U.S. DEVELOPMENT CORPORATION 02203

Mobil E&P U.S. Development Fund, L.P. 02209

Mobil Eugene Island Pipeline Company 00883

Mobil Exploration and Producing North America Inc. 01055

Mobil Foundation, Inc. 01933

MOBIL OIL EXPLORATION & PRODUCING SOUTHEAST

INC.

00540

Mobil Producing Texas & New Mexico Inc. 00565

Mobil-TransOcean Company 00637

* Exxon Corporation 00276

* Exxon Pipeline Company 00103

* Mobil GC Corporation 00565

* Mobil NOC Inc. 00021

Exxon Mobil

* Superior Oil Company 00047

Mississippi Canyon Gas Pipeline, LLC 02254

Shell Consolidated Energy Resources Inc. 01940

Shell Frontier Oil & Gas Inc. 01728

Shell Gas Gathering, LLC 02253

Shell Gas Pipeline Company 01070

Shell Land & Energy Company 01967

Shell Offshore Inc. 00689

Shell Offshore Properties and Capital II, Inc. 02128

Shell Oil Company 00117

Shell Pipe Line Corporation 00124

Shell Seahorse Company 02147

SWEPI LP 00832

* Shell Deepwater Development Inc. 02139

* Shell Deepwater Production Inc. 02140

* Shell Energy Resources Inc. 00688

* Shell Gas Gathering Company 02168

Shell

* Shell Western E&P Inc. 00832

* Denotes companies that are no longer qualified with the MMS.

** The MMS has not received official documents for the Chevron-Texaco merger.
123

Appendix D – Subsea Completions.

Area Block API Number Operator Completion Date Water Depth (ft)

BA A 7 427044011600 Texaco 10/5/84 120

DC 133 608234000200 Amoco Production Company 9/12/01 6376

EB 112 608044015700 Agip Petroleum Co. Inc. 5/1/96 638

EB 117 608044016102 Vastar Offshore, Inc. 4/25/97 570

EB 157 608044015200 Agip Petroleum Co. Inc. 5/23/96 941

EB 161 608044022600 Union Oil Company of California 6/24/01 1107

EB 168 608044016600 Walter Oil & Gas Corporation 7/16/97 450

EB 168 608044023000 Walter Oil & Gas Corporation 12/6/01 500

EB 205 608044021800 Union Oil Company of California 5/2/01 1081

EB 948 608044017601 ExxonMobil Corporation 4/11/01 4376

EB 949 608044019301 ExxonMobil Corporation 3/12/01 4376

EC 235 177034047300 Chevron U.S.A. Inc. 11/16/86 121

EC 328 177044080800 Louis Dreyfus Natural Gas Corp. 2/13/97 243

EC 341 177044067100 Walter Oil & Gas Corporation 10/21/88 275

EC 378 608074015700 Sonat Exploration GOM Inc. 1/27/97 495

EC 380 177044102600 Walter Oil & Gas Corporation 6/15/01 538

EI 175 177090073200 Vastar Resources, Inc. 5/12/66 88

EI 175 177090073300 Vastar Resources, Inc. 2/15/66 90

EI 175 177090084200 Vastar Resources, Inc. 10/25/67 87

EI 175 177090086800 Vastar Resources, Inc. 11/13/73 83

EI 175 177090087100 Vastar Resources, Inc. 2/21/68 90

EI 175 177090088000 Vastar Resources, Inc. 8/8/69 87

EI 175 177090089700 Vastar Resources, Inc. 4/4/75 83

EI 175 177090090500 Vastar Resources, Inc. 6/25/68 90

EI 179 177094088700 Kerr-McGee Corporation 11/29/91 97

EI 215 177094016400 PennzEnergy 9/17/76 103

EI 248 177094112300 Walter Oil & Gas Corporation 1/25/97 155

EI 294 177104126801 TDC Energy Corporation 10/6/91 214

EI 300 177104102700 Amoco Production Company 3/18/83 212

EI 301 177104134000 Amoco Production Company 9/4/91 232

EI 301 177104136700 Amoco Production Company 5/2/94 231

EI 320 177104128700 Forest Oil Corporation 12/8/94 244

EI 322 177104134100 Amoco Production Company 8/21/96 242

EI 331 177104046800 Shell Offshore Inc. 8/17/75 242

EI 331 177104047700 Shell Offshore Inc. 1/30/76 242

EI 349 177104100500 Marathon Oil Company 11/23/90 337

EI 364 177104138000 LL&E Company 3/28/96 357

EW 868 608104011500 Walter Oil & Gas Corporation 9/1/01 685

EW 871 608104011300 Walter Oil & Gas Corporation 3/10/01 724

EW 878 608105009500 Walter Oil & Gas Corporation 7/3/00 1523

EW 878 608105009601 Walter Oil & Gas Corporation 8/25/00 1523

EW 914 608105002200 Tatham Offshore, Inc. 8/11/93 946

EW 917 608105006500 Marathon Oil Company 4/8/98 1195

EW 963 608105006000 Marathon Oil Company 5/25/98 1740

EW 963 608105006800 Marathon Oil Company 6/29/98 1758
124

Area Block API Number Operator Completion Date Water Depth (ft)

EW 965 608105006200 British-Borneo Exploration, Inc. 5/13/98 1694

EW 989 608104008600 Kerr-McGee Corporation 11/2/94 565

EW 989 608104008701 Kerr-McGee Corporation 9/28/95 565

EW 999 608104003202 Placid Oil Company 7/20/89 1462

EW 1006 608105004100 Walter Oil & Gas Corporation 8/17/97 1884

GB 70 608074007000 Newfield Exploration Company 7/4/95 755

GB 70 608074007001 Newfield Exploration Company 9/29/97 750

GB 71 608074013000 Newfield Exploration Company 4/30/95 750

GB 108 608074020600 Kerr-McGee Oil & Gas

Corporation

7/17/99 619

GB 117 608074013500 Flextrend Development Company 7/16/96 922

GB 117 608074014901 Flextrend Development Company 5/5/97 924

GB 134 608074062900 ATP 12/10/97 520

GB 152 608074020800 Kerr-McGee Oil & Gas

Corporation

7/7/99 619

GB 161 608074015801 PennzEnergy E&P L.L.C. 9/20/99 972

GB 172 608074018200 Shell Offshore Inc. 7/31/98 693

GB 172 608074018401 Shell Offshore Inc. 1/25/99 693

GB 172 608074019700 Shell Offshore Inc. 4/27/99 663

GB 179 608074063700 Walter Oil & Gas Corporation 10/12/97 712

GB 216 608074081901 Amerada Hess Corporation 5/22/99 1456

GB 224 608074061800 Kerr-McGee Oil & Gas

Corporation

5/22/91 742

GB 235 608074010600 LL&E Company 9/25/96 785

GB 240 608074013100 Mariner Energy, Inc. 1/29/96 832

GB 367 608074064100 Mariner Energy, Inc. 2/28/99 1122

GB 387 608074014001 EEX Corporation 3/3/96 2081

GB 388 608074005400 EEX Corporation 3/19/95 2097

GB 388 608074008401 EEX Corporation 7/11/97 2097

GB 388 608074015601 EEX Corporation 2/25/97 2096

GB 602 608074014401 Shell Deepwater Development

Inc.

12/28/99 3708

GB 602 608074019401 Shell Deepwater Development

Inc.

8/16/99 3693

GC 20 608114021300 Reading & Bates Development

Co.

12/10/99 880

GC 29 608114009100 Placid Oil Company 6/17/89 1526

GC 31 608114004701 EP Operating Limited Partnership 8/7/88 2243

GC 31 608114009600 EP Operating Limited Partnership 5/17/89 2234

GC 60 608114019800 Mobil Oil E&P Southeast Inc 6/7/96 870

GC 60 608114020101 Mobil Oil E&P Southeast Inc 6/22/96 868

GC 72 608115008500 Shell Deepwater Production Inc. 1/11/96 2040

GC 110 608114020600 Shell Offshore Inc. 1/23/96 1730

GC 113 608115012701 Shell Deepwater Development

Inc.

9/1/99 2045

GC 113 608115013100 Shell Deepwater Development

Inc.

7/17/99 1968

GC 116 608115008600 Shell Deepwater Production Inc. 1/11/96 2046

GC 116 608115012200 Shell Deepwater Production Inc. 2/14/98 2046

GC 136 608114020000 Texaco 11/21/95 860

GC 136 608114020401 Texaco 12/20/95 1040

GC 200 608114020501 BP Exploration & Oil Inc. 6/29/98 2670
125

Area Block API Number Operator Completion Date Water Depth (ft)

GC 200 608114021600 BP Exploration & Oil Inc. 12/7/97 2670

GC 200 608114021800 BP Exploration & Oil Inc. 11/10/97 2670

GC 200 608114021901 BP Exploration & Oil Inc. 2/27/99 2670

GC 200 608114028900 BP Exploration & Production Inc. 12/16/00 2672

GC 201 608114027501 BP Exploration & Production Inc. 6/5/00 2672

GC 254 608115008301 British-Borneo Exploration, Inc. 3/5/99 3225

GC 254 608115009000 British-Borneo Exploration, Inc. 8/1/99 3234

GI 41 177174009500 Vastar Resources, Inc. 11/8/78 91

GI 41 177174009600 Vastar Resources, Inc. 10/18/85 91

GI 41 177174009700 Vastar Resources, Inc. 10/8/78 91

GI 43 177174009800 Vastar Resources, Inc. 8/1/78 114

GI 47 177174009300 Vastar Resources, Inc. 5/14/78 88

GI 47 177174018500 Vastar Resources, Inc. 5/20/86 97

GI 109 177184009600 Walter Oil & Gas Corporation 6/7/00 280

HI A 309 427114070100 Coastal Oil & Gas Corporation 1/24/95 213

HI A 320 427114077400 Walter 3/17/97 237

HI A 325 427114064000 Pennzoil E&P Company 7/11/89 231

HI A 325 427114064100 Pennzoil E&P Company 8/6/89 231

HI A 327 427114071200 Hall-Houston Oil Company 10/3/94 220

HI A 370 427114065100 Kerr-McGee Oil & Gas

Corporation

3/20/93 375

HI A 373 427114065000 EOG Resources, Inc. 6/10/92 375

HI A 378 427114075700 Kerr-McGee 7/28/96 360

HI A 378 427114080601 Kerr-McGee 4/1/99 332

HI A 441 427094109900 Remington Oil and Gas

Corporation

8/29/00 168

HI A 519 427094093200 Coastal Oil & Gas Corporation 5/20/91 220

HI A 573 427094053700 Union Oil Company of California 9/17/80 350

HI A 587 427094089602 PANACO, INC. 10/30/90 467

MC 335 608174084301 Exxon Corporation 7/2/99 1458

MC 28 608164018600 BP Exploration & Oil Inc. 4/21/95 1290

MC 28 608174051600 BP Exploration & Oil Inc. 8/16/96 1853

MC 28 608174051704 BP Exploration & Oil Inc. 4/7/01 1853

MC 28 608174051900 BP Exploration & Oil Inc. 6/30/96 1853

MC 28 608174052000 BP Exploration & Oil Inc. 4/24/98 1853

MC 29 608174052302 BP Exploration & Production Inc. 10/1/01 1853

MC 72 608174051500 BP Exploration & Oil Inc. 4/27/96 1853

MC 85 608174090100 Amoco Production Company 12/22/00 5173

MC 85 608174090801 BP Exploration & Production Inc. 4/8/01 5317

MC 217 608174090900 BP Exploration & Production Inc. 1/1/01 6390

MC 217 608174091001 Amoco Production Company 1/21/01 6420

MC 278 608174091502 Walter Oil & Gas Corporation 4/14/01 560

MC 292 608174050900 Texaco 5/25/99 3405

MC 292 608174083201 Texaco 8/25/99 3393

MC 292 608174083301 Texaco 9/24/99 3393

MC 321 608174089100 Walter Oil & Gas Corporation 8/27/00 567

MC 322 608174093800 Walter Oil & Gas Corporation 6/16/01 680

MC 322 608174094201 Walter Oil & Gas Corporation 7/24/01 680

MC 354 608174044700 Exxon Corporation 7/5/93 1460
126

Area Block API Number Operator Completion Date Water Depth (ft)

MC 355 608174044800 Exxon Corporation 9/11/93 1458

MC 355 608174044900 Exxon Corporation 5/29/93 1460

MC 357 608174053801 Newfield Exploration Company 2/25/98 445

MC 401 608174032901 Kerr-McGee Oil & Gas

Corporation

8/25/93 1367

MC 401 608174034600 Kerr-McGee Oil & Gas

Corporation

7/25/93 1700

MC 441 608174037601 EEX Corporation 4/17/93 1438

MC 441 608174038400 EEX Corporation 11/20/92 1531

MC 441 608174040002 EEX Corporation 1/26/93 1531

MC 441 608174040100 EEX Corporation 12/27/92 1531

MC 441 608174041500 EEX Corporation 7/3/93 1438

MC 445 608174042900 Kerr-McGee Oil & Gas

Corporation

10/4/93 2094

MC 445 608174047300 Kerr-McGee Oil & Gas

Corporation

7/23/94 2095

MC 485 608174041600 EEX Corporation 5/24/93 1438

MC 686 608174054100 Shell Deepwater Production Inc. 7/12/97 5292

MC 687 608174054000 Shell Deepwater Production Inc. 11/20/98 5292

MC 730 608174054200 Shell Deepwater Production Inc. 11/4/97 5295

MC 807 608174038800 Shell Deepwater Production Inc. 3/25/96 2956

MC 837 608174092401 Walter Oil & Gas Corporation 5/19/01 1524

MC 899 608174058002 Shell Deepwater Development

Inc.

3/25/01 4393

MC 899 608174087807 Shell Offshore Inc. 9/21/01 4389

MC 899 608174091600 Shell Deepwater Development

Inc.

6/4/01 4393

MP 131 177254060100 ATP Oil & Gas Corporation 11/3/98 165

MP 145 177254047300 OXY USA Inc. 12/18/89 213

MP 149 177254058901 Walter Oil & Gas Corporation 9/6/94 220

MP 150 177254069600 Walter Oil & Gas Corporation 11/2/00 245

MP 260 177244081400 Santa Fe Snyder Corporation 4/26/99 315

MP 262 177244076100 CXY Energy Offshore Inc. 12/15/96 283

MP 281 177244069100 Walter Oil & Gas Corporation 7/28/94 293

MP 291 177244056600 Allied Natural Gas Corporation 4/5/95 272

MU 806 427024024500 Vastar Resources, Inc. 6/13/97 164

MU A 124 427124010700 Walter Oil & Gas Corporation 9/20/93 381

PN 1010 427014005000 Walter 6/27/99 128

SM 61 177074029400 Chevron U.S.A. Inc. 5/26/84 130

SM 67 177074039000 Cockrell Oil Corporation 6/16/84 130

SS 176 177114099800 Chevron U.S.A. Inc. 9/29/90 100

SS 204 177110067000 Union Pacific Resources

Company

5/18/95 103

SS 204 177110067200 Union Pacific Resources

Company

3/28/83 100

SS 204 177110081400 Union Pacific Resources

Company

2/10/69 103

SS 217 177110055500 Kerr-McGee Corporation 3/2/71 114

SS 269 177124010700 Union Oil Company of California 5/16/76 187

SS 274 177122001100 Apache Corporation 10/1/69 219

SS 274 177124008600 Apache Corporation 3/30/75 210

SS 276 177124058800 Forest Oil Corporation 6/17/98 215
127

Area Block API Number Operator Completion Date Water Depth (ft)

SS 316 177124043400 Hall-Houston Oil Company 6/17/91 295

SS 317 177124038600 Newfield Exploration Company 12/13/90 295

SS 321 177124057000 ATP Oil & Gas Corporation 5/29/97 323

SS 326 177124058700 Walter Oil & Gas Corporation 5/11/98 364

SS 361 177124054900 Phillips Petroleum Company 7/8/98 405

ST 169 177154032600 Samedan Oil Corporation 4/27/80 88

ST 169 177154062300 Samedan Oil Corporation 6/1/85 102

ST 177 177154007800 Chevron U.S.A. Inc. 11/6/76 144

ST 231 177164019900 SOCO Offshore, Inc. 6/25/98 238

VK 783 608164013401 Shell Deepwater Production Inc. 11/10/93 1494

VK 783 608164021701 Shell Deepwater Production Inc. 7/18/96 1142

VK 784 608164023200 Shell Deepwater Production Inc. 6/30/96 1750

VK 825 608164033201 Kerr-McGee Oil & Gas

Corporation

10/16/98 1722

VK 825 608164034400 Kerr-McGee Oil & Gas

Corporation

8/29/99 1711

VK 862 608164021600 Walter Oil & Gas Corporation 11/15/95 1067

VK 915 608164038300 Amoco Production Company 4/2/01 3460

VK 944 608164032200 Elf Exploration, Inc. 12/5/97 730

VK 986 608164022800 Walter Oil & Gas Corporation 12/23/95 893

VR 215 177054028500 Newfield Exploration Company 10/10/79 140

VR 246 177054034600 Chevron U.S.A. Inc. 5/24/82 155

VR 302 177064021701 CXY Energy Offshore Inc. 2/20/77 197

VR 320 177064064200 ORYX Energy Company 11/12/91 206

WC 192 177004055500 Diamond Shamrock 7/11/82 54

WC 459 177024062900 Conoco Inc. 5/16/85 135

WC 548 177024106000 Walter Oil & Gas Corporation 6/14/94 185

WC 584 177024085700 Walter Oil & Gas Corporation 3/3/89 237

WC 592 177024106301 Walter Oil & Gas Corporation 12/17/95 252

WC 638 177024116900 Kerr-McGee Oil & Gas

Corporation

11/6/98 373

WD 45 177190038200 CXY Energy Offshore Inc. 2/11/59 50

WD 45 177190038300 CXY Energy Offshore Inc. 2/26/59 72

WD 45 177190038402 CXY Energy Offshore Inc. 12/8/81 50

WD 62 177194027900 Mesa Operating 8/13/85 130

WD 70 177190062800 Vastar Resources, Inc. 2/2/58 143

WD 70 177190063000 Vastar Resources, Inc. 10/5/61 143

WD 71 177190061900 Vastar Resources, Inc. 7/24/61 142

WD 77 177194065504 ATP Oil & Gas Corporation 8/29/99 187

WD 106 177194056800 Walter Oil & Gas Corporation 1/5/95 234

WD 106 177194070300 Walter Oil & Gas Corporation 5/29/01 254

WD 107 177194056400 Walter Oil & Gas Corporation 1/2/96 222
128

Appendix E – Deepwater Studies Program.

Active Studies [MMS Study Number]

Deepwater Program: Marathon - Case study (Numerical Modeling) (Subscription) [16073 B]

Deepwater Program: Conoco - Eddies (EJIP - data) (Membership) [16074 B]

Deepwater Program: Assessment and Reduction of Taxonomic Error in Benthic Macrofauna

Surveys: An Initial Program Focused on Shelf and Slope Polychaete Worms [16801 C]

Deepwater Program: Labor Migration and the Deepwater Oil Industry in Houma [16804 G]

Deepwater Program: Observation of Deepwater Manifestation of Loop Current Rings [16805 B]

Deepwater Program: Deepwater Currents at 92° W [16807 B]

Deepwater Program: Summary of the Northern Gulf of Mexico Continental Slope Studies

[17037 C]

Deepwater Program: An Analysis of the Socioeconomic Effects of OCS Activities on Ports and

Surrounding Areas in the Gulf of Mexico Region [19957 G]

Deepwater Program: Labor Migration and the Deepwater Oil Industry [19958 G]

Deepwater Program: Offshore Petroleum Platforms: Functional Significance for Larval Fish

Across Longitudinal and Latitudinal Gradients [19961 M]

Deepwater Program: Potential Spatial and Temporal Vulnerability of Pelagic Fish Assemblages

in the Gulf of Mexico to Surface Oil Spills Associated with Deepwater Petroleum Development

[19962 M]

Deepwater Program: Assessing and Monitoring Industry Labor Needs [30898 G]

Deepwater Program: Benefits and Burdens of OCS Deepwater Activities on Selected

Communities and Local Public Institutions [30899 G]

Deepwater Program: Development of a Deepwater Environmental Data Model [30917 I]

Deepwater Program: OCS-Related Infrastructure in the Gulf of Mexico [30955 G]

Deepwater Program: Northern Gulf of Mexico Continental Slope Habitats and Benthic Ecology

[30991 C]

Deepwater Program: Bluewater Fishing and Deepwater OCS Activity: Interactions Between the

Fishing and Petroleum Industries in Deepwaters of the Gulf of Mexico [31011 M]

Deepwater Program: Study of Subsurface, High-Speed Current Jets in the Deep Water Region

of the Gulf of Mexico [31026 B]

Deepwater Program: Analysis and Validation of a Mechanism that Generates Strong Mid-depth

Currents and a Deep Cyclone Gyre in the Gulf of Mexico [31027 B]
129

Active Studies [MMS Study Number] (Continued)

Deepwater Program: Modeling and Data-Analysis of Subsurface Currents on the Northern Gulf

of Mexico Slope and Rise: Effects of Topographic Rossby Waves and Eddy-Slope Interaction

[31028 B]

Deepwater Program: Cross-Shelf Exchange Processes and the Deep-Water Circulation of the

Gulf of Mexico: The Dynamical Effects of Submarine Canyons and the Interactions of Loop

Current Eddies with Topography [31029 B]

Deepwater Program: Effects of Oil and Gas Exploration and Development at Selected

Continental Slope Sites in the Gulf of Mexico [31034 E]

Deepwater Program: Joint Industry Project, "Gulf of Mexico Comprehensive Synthetic Based

Muds Monitoring Program" [31069 E]

Deepwater Program: Supply Logistics of OCS Oil and Gas Development in the Gulf of Mexico

- Evaluation of Technological and Economic Parameters of Ports as Supply and Manufacturing

Bases [31154 G]

Deepwater Program: Offshore Data Search and Synthesis on Highly Migratory Species in the

GOM and the Effects of Large Fish Attracting Devices (FADS) [BRD-M0202]

Deepwater Program: The Technology and Economics of Deepwater Production Projects

[31019 G]

Deepwater Program: Exploratory Study of Deepwater Currents in the Gulf of Mexico [31152 B]

Completed Studies [MMS Study Number]

Deepwater Program: The Fate and Effects of Synthetic-Based Drilling Fluids and Associated

Cuttings Discharged into the Marine Environment [15240E]. Report Number *2000-064 -

Environmental Impacts of Synthetic-Based Drilling Fluids

Deepwater Program: Workshop for Modeling Demographic and Socioeconomic Change in

Local Coastal Areas in the Gulf of Mexico Region [19959 G]

Deepwater Program: Literature Review: Environmental Risks of Chemical Products Used in

Deepwater Oil & Gas Operations [30900 E]. Report Number *2001-011 - Deepwater Program:

Literature Review, Environmental Risks of Chemical Products Used in Gulf of Mexico

Deepwater Oil and Gas Operations, Volume I: Technical Report and Report Number 2001-012

Deepwater Program: Literature Review, Environmental Risks of Chemical Products Used in

Gulf of Mexico Deepwater Oil and Gas Operations, Volume II: Appendices

Deepwater Program: Deepwater Physical Oceanography Reanalysis and Synthesis of Historical

Data [30910 B]. Report Number 2001-064 - Deepwater Physical Oceanography Reanalysis and

Synthesis of Historical Data: Synthesis Report
130

Completed Studies [MMS Study Number] (Continued)

Deepwater Program: Gulf of Mexico Deepwater Information Resources Data Search and

Literature Synthesis [30916 I]. Report Number *2000-049 - Deepwater Gulf of Mexico

Environmental and Socioeconomic Data Search and Literature Synthesis, Volume I: Technical

Narrative and Report Number *2000-050 - Deepwater Gulf of Mexico Environmental and

Socioeconomic Data Search and Literature Synthesis, Volume II: Annotated Bibliography

Study in the Procurement Process [MMS Study Number]

Deepwater Program: Understanding the Processes that Maintain the Oxygen Levels in the Deep

Gulf of Mexico [85080 K]

Note: The * before the MMS publication number indicates that the report is available at our web

site – http://www.gomr.mms.gov/homepg/regulate/environ/deepenv.html.
131

Appendix F - Average Annual GOM Oil and Gas Production.

Year Shallow-water Oil

(MBOPD)

Deepwater Oil

(MBOPD)

Total GOM Oil

(MBOPD)

Shallow-water

Gas (BCFPD)

Deepwater Gas

(BCFPD)

Total GOM Gas

(BCFPD)

1947 0 0 0 0.0 0.0 0.0

1948 0 0 0 0.0 0.0 0.0

1949 0 0 0 0.0 0.0 0.0

1950 1 0 1 0.0 0.0 0.0

1951 1 0 1 0.0 0.0 0.0

1952 2 0 2 0.1 0.0 0.1

1953 3 0 3 0.1 0.0 0.1

1954 7 0 7 0.2 0.0 0.2

1955 11 0 11 0.2 0.0 0.2

1956 19 0 19 0.2 0.0 0.2

1957 32 0 32 0.3 0.0 0.3

1958 54 0 54 0.4 0.0 0.4

1959 81 0 81 0.6 0.0 0.6

1960 111 0 111 0.8 0.0 0.8

1961 152 0 152 0.9 0.0 0.9

1962 210 0 210 1.2 0.0 1.2

1963 264 0 264 1.5 0.0 1.5

1964 305 0 305 1.8 0.0 1.8

1965 373 0 373 2.0 0.0 2.0

1966 481 0 481 2.7 0.0 2.7

1967 574 0 574 3.5 0.0 3.5

1968 695 0 695 4.4 0.0 4.4

1969 801 0 801 5.3 0.0 5.3

1970 902 0 902 6.6 0.0 6.6

1971 1,030 0 1,030 7.5 0.0 7.5

1972 1,023 0 1,023 8.2 0.0 8.2

1973 1,003 0 1,003 9.1 0.0 9.1

1974 926 0 926 9.4 0.0 9.4

1975 849 0 849 9.4 0.0 9.4

1976 823 0 823 9.7 0.0 9.7

1977 777 0 777 10.3 0.0 10.3

1978 756 0 756 11.6 0.0 11.6

1979 720 2 721 12.8 0.0 12.8

1980 711 14 725 13.0 0.0 13.1

1981 711 10 721 13.4 0.0 13.4

1982 748 36 784 12.7 0.0 12.8

1983 805 72 877 11.1 0.1 11.2

1984 904 68 972 12.4 0.1 12.5

1985 902 58 960 11.0 0.1 11.1

1986 922 52 974 11.0 0.1 11.1

1987 851 47 897 12.3 0.1 12.4

1988 790 36 825 12.4 0.1 12.5

1989 742 27 769 12.6 0.1 12.7

1990 719 33 752 13.4 0.1 13.4

1991 745 63 807 12.7 0.2 12.9
132

Year Shallow-water Oil

(MBOPD)

Deepwater Oil

(MBOPD)

Total GOM Oil

(MBOPD)

Shallow-water

Gas (BCFPD)

Deepwater Gas

(BCFPD)

Total GOM Gas

(BCFPD)

1992 733 102 835 12.5 0.2 12.7

1993 745 101 845 12.4 0.3 12.8

1994 746 115 860 12.8 0.4 13.2

1995 794 151 945 12.6 0.5 13.1

1996 813 198 1,010 13.2 0.8 13.9

1997 830 297 1,128 13.1 1.0 14.1

1998 781 436 1,217 12.3 1.5 13.8

1999 741 617 1,357 11.5 2.3 13.9

2000 690 743 1,433 10.8 2.7 13.6

2001* 620 930 1,550 10.7 3.2 13.9

* estimated
133

Appendix G – Number of Deepwater Production Facilities Installed Each Year (including

plans through 2004).

Year Fixed

Platform

Compliant

Tower

TLP Small TLP Spar Truss Spar Other FPS FPSO

1979 1 0 0 0 0 0 0 0

1980 0 0 0 0 0 0 0 0

1981 0 0 0 0 0 0 0 0

1982 0 0 0 0 0 0 0 0

1983 0 1 0 0 0 0 0 0

1984 0 0 0 0 0 0 0 0

1985 0 0 0 0 0 0 0 0

1986 0 0 0 0 0 0 0 0

1987 0 0 0 0 0 0 0 0

1988 0 0 0 0 0 0 1 0

1989 1 0 1 0 0 0 0 0

1990 0 0 0 0 0 0 0 0

1991 1 0 0 0 0 0 0 0

1992 1 0 0 0 0 0 0 0

1993 0 0 0 0 0 0 0 0

1994 1 0 1 0 0 0 0 0

1995 0 0 0 0 0 0 1 0

1996 0 0 1 0 0 0 0 0

1997 0 0 1 0 1 0 0 0

1998 1 1 0 1 0 0 0 0

1999 1 0 2 1 1 0 0 0

2000 0 1 0 0 1 0 0 0

2001 0 0 1 2 0 2 0 0

2002 0 0 0 0 1 1 0 0

2003 0 0 0 0 0 3 1 0

2004 0 0 1 2 0 1 2 0

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.