Despite the high level of shelf activity, the real GOM story has been the recent dramatic growth in deepwater reserves and production, as shown in Figures 1 and 2. While only about 133 deepwater exploration and development wells were drilled in 2006, versus 597 total shelf wells (as reported by James K. Dodson Co.), deepwater production has accounted for 73 percent of total GOM oil and 38 percent of total GOM gas produced in the first eight months of 2006.

The recent string of deepwater GOM exploration successes for 2006 (15 discoveries and 1.5 billion barrels of reserves, according to the energy consulting firm Wood Mackenzie) would suggest that the dramatic increase in deepwater production and development over the last 10 years is only a preliminary stage. In other words, deepwater GOM activity may just be getting started, given the limited exploration to date. Contrary to the perception that the GOM deepwater is restricted to the major oil companies with their deep pockets, much of its deepwater growth has actually been fueled by the non-majors, who have made more GOM deepwater discoveries and hold more deepwater acreage than the majors.

GOM deepwater developments and activity continue to move forward rapidly, despite challenges related to sub-salt seismic imaging, water depth, reservoir pressures and temperatures, reservoir fluids, and reservoir continuity issues.

• Anticipated new GOM deepwater production includes first production from eleven new fields in 2007 and four new fields in 2008, as per the MMS.
• In the western deepwater GOM, Shell has announced a planned development of the Great White (Lower Tertiary), Tobago, and Silvertip fields, which would be serviced by a Perdido regional development host spar located in Alaminos Canyon in 8,000 feet of water. It would be the world’s deepest spar facility, capable of handling 130,000 BOEPD.
• In the eastern deepwater GOM, the Independence Hub platform has been installed in Mississippi Canyon Block 920, with first production from ten fields in Atwater Valley expected in the second half of 2007. The platform is the deepest offshore platform ever installed (8,000 feet of water), and the world’s largest in terms of production capacity (1 BCFPD). At capacity, the platform will provide more than a 10 percent increase in the current natural gas deliveries from the GOM. The I-Hub has space for ten additional subsea fields.
• Also in the eastern deepwater GOM, Petrobras has announced a planned installation of the first FPSO in the GOM, with first oil production from the Cascade and Chinook Lower Tertiary (LT) fields scheduled for late 2009.
• Additional LT deepwater activity includes the testing of Jack-2 (6,000 BOPD from 40 percent of 350 feet of net pay) in Walker Ridge Block 758, and the Kaskida well in Keathley Canyon Block 292, which encountered 800 feet of net pay and is touted as the largest LT discovery to date.

The Lower Tertiary

Much has been made of the recent deepwater LT discoveries and the Jack-2 test. Estimates of recoverable reserves range from 9 to 15 billion BOE overall, with an average 300 to 500 million barrels per field. Despite the significance of the opportunity, however, challenges remain. Of the 19 LT exploratory wells drilled, 12 are considered to be potential commercial discoveries. So while the success rate is relatively high by exploration standards, the possibility for failure remains a factor, given average well costs of $80 to $120 million. Another consideration is that oil quality tends to vary significantly across the play (from 40 degrees API in the western fields, to low gravity, high viscosity with 4 percent sulfur content in the eastern fields).

Other considerations are the high pressures (+/-20,000 psi) and low-permeability, very-fine-grained turbidite sandstones associated with LT reservoirs. In some cases, LT reservoirs will be challenged to produce at economic rates. The primary reason for the Jack-2 test was to prove the LT could flow at economic rates, as it has been the only extended LT test to date. Finally, long lead times will be a definite factor in development, as LT discoveries such as Great White and Cascade are not expected to come on production until 2009 or 2010, and Jack’s first production may not happen before 2012-14.

Production Challenges

Despite the significant successes in the GOM deepwater, challenges persist. First start-up at Thunder Horse (Mississippi Canyon 776, 777, and 778), the largest GOM deepwater discovery to date, has now been delayed to mid-2008. This is due to BP’s decision to rebuild all seafloor production equipment as a result of hydrogen embrittlement. Production from the $1-billion-plus semi-submersible platform (250,000 BOPD and 200 MMCFPD capacity) was originally scheduled to start in mid-2005, but was delayed due to damage from Hurricane Dennis, followed by failure of the subsea manifold in July 2006. The hydrogen embrittlement problem at Thunder Horse has also caused BP to retrieve and modify the subsea manifolds for its Atlantis deepwater development. First production at Atlantis is still scheduled for mid-2007.

In September 2006, BP announced it was “struggling with lower than expected production” from its Mad Dog spar (Green Canyon 782). Apparently only three wells out of a planned 12 were on production, with flowing rates significantly below the spar’s capacity of 100,000 BOPD and 60 MMCFPD. The problems appeared to be related to drilling difficulties. The reservoir is located below 6,000 feet of salt and contains “highly mobile tar deposits” that are affecting the reservoir’s exploitation. More recently, the field was shut-in in February 2007, due to a mechanical failure involving the platform’s water-cooling system. Production from the field is estimated to resume sometime this spring.

Hurricane damage from 2004 and 2005 continues to impact deepwater GOM production. The Typhoon Field (Green Canyon 236 and 237) remains shut-in since the mini-TLP was severed from its mooring and suffered severe damage due to Hurricane Rita in 2005. Helix Energy, the new operator, intends to install a disconnectable floating production system (45,000 BOPD and 70 MMCFPD capacity) to service Typhoon (re-named Phoenix), Boris, and Little Burn fields, with first production expected in mid-2008. Mariner’s Ochre Field (Mississippi Canyon 66) resumed production (10.5 MMCFEPD) recently, after being shut-in for damages caused by Hurricane Ivan in 2004. Mariner’s Pluto Field (Mississippi Canyon 718) was also recently brought on production (40 to 50 MMCFEPD expected peak rate) after delays due to Hurricane Katrina in 2005.

Also, Murphy Oil, operator of the Front Runner Field (Green Canyon 338 and 339), has now indicated that it expects production from the field to range between 9,000 and 9,500 BOEPD for 2007, which is significantly below the spar platform’s capacity of 60,000 BOPD and 110 MMCFPD. Murphy indicated the field has performed below initial forecasts due to unanticipated reservoir compartmentalization issues and the collapse and shut-down of several wells in 2006.

Drilling and Lease Expiration Activity

Although challenges persist in the deepwater, the activity level remains high, as the lure for big reserves (50 billion BOE of undiscovered reserves based on an MMS 2000 assessment) continues to push operators to tackle extreme surface and sub-surface conditions utilizing cutting-edge technology. Overall GOM deepwater development drilling has declined from a high of 108 wells in 2002 to approximately 37 wells in 2006. However, GOM deepwater exploratory drilling has remained fairly constant over the last four years at around 85 wells per year.

Many of the 2,587 deepwater leases issued from 1996-98, corresponding to implementation of the Deepwater Royalty Relief Act, will expire from 2006-08, as shown in Figure 3. Since only a small percentage of these leases have been tested, it will be interesting to watch the industry’s response as they reach the end of their primary terms and presumably become available at future lease sales.

New Technology

The impact of new technology on the GOM deepwater will also continue to play a major role in deepwater development. A study by Statoil, Hydro, and NPD of the Norwegian sector of the North Sea (where approximately 40 percent of production is from subsea wells) concluded that subsea oil and gas recoveries were 15 to 20 percent lower than from wells with direct platform access. A primary reason is that subsea wells must be shut-in when water hits and/or pressure declines significantly, resulting in the loss of “tail” production.

Overall recovery from deepwater reservoirs has the potential to improve significantly with the development of subsea separation and compression technology. The world’s first commercial subsea processing system will be installed in Statoil’s Tordis Field in the Norwegian sector of the North Sea, in the third quarter of 2007. The subsea separation facility and electric pumps, located in 200 meters of water, will separate and reinject produced water, and oil and gas production will be boosted through a multiphase pump to a host platform.

The world’s first subsea compression application is planned for the Ormen Lange Field in the Norwegian Sea. A full-size pilot test program is scheduled for 2009, with qualification of the technology planned by 2011. If the technology proves successful, the 3,500-metric-ton compression station would ultimately be installed in 860 meters of water, at half the cost of a traditional 25,000-metric-ton platform.

Subsea separation and compression could have a profound impact on GOM deepwater production, providing a cost-effective alternative to costly deepwater production floating platform and facility systems, which are vulnerable to GOM hurricanes.

Gene B. Wiggins, P.E., is Chairman and Chief Executive Officer of The Scotia Group, Inc., a geoscience and reservoir engineering consulting firm. He is a former National President of the Society of Petroleum Evaluation Engineers, and may be reached at gwiggins@scotia-group.com.

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