Gulf of Mexico's deep waters passed shelf, slope in oil flow during 2000

Deepwater wells, those in greater than 1,000 ft of water, were producing more than 700,000 bo/d on the Gulf of Mexico Outer Continental Shelf during 2000, exceeding the output from shelf and slope wells for the first time.

The production came from hydrocarbon trends and plays that were conceived, leased, and drilled from the mid-1980s through the late-1990s.

A Minerals Management Service study said the deepwater gulf had become a major world petroleum province. It noted that in the early 1990s, some industry observers considered the Gulf of Mexico a "dead sea" in terms of petroleum production.

"Most of the early indicators pointed to an oil and natural gas basin nearing the end of its productivity," said MMS. "Many thought the gulf would only attract the small investor, and there appeared to be little potential for new discoveries."

However, it said the gulf had re-emerged as an area of major importance, due to deepwater exploration success.

MMS said there were more than 7,600 active leases in the gulf, half of which were in deep water. In 1992, there were 5,600 active leases, only 27% of which were in deep water.

MMS said technology developments and high-production-rate wells had lowered the costs of finding, producing, and delivering deepwater oil and natural gas to market. Areas of the gulf once thought beyond reach—water depths greater than 5,000 ft—were being explored and developed. It said a new generation of drillships and techniques allowed drilling in water as deep as 10,000 ft.

More than 40% of rigs capable of working in deep water were either working in the gulf or committed to do so, MMS said.

It said that in 1990, 4% of gulf oil production, and less than 1% of gas output, was from deepwater areas. By the end of 1999, those figures had risen to more than 50% for oil and 20% for gas.

In the early 1990s, gulf oil output was 300-315 million bbl/year. It rose to almost 500 million bbl in 1999.

"This is due in part to more accurate methods to locate hydrocarbon deposits in deep water and beneath salt formations in the seabed, coupled with less-costly means of developing these properties," said MMS.

Production potential from deepwater reserves was estimated at 2 billion bbl of oil and 6 tcf of gas.

In a separate report on future offshore supplies, MMS said shelf gas production would likely peak at 4.35 tcf in 2003 before declining at an average rate of 4%/year through 2020.

"Increased drilling and nonassociated gas completions in the shallow shelf area may reduce the present decline rate in net production from the area," said MMS.

It expected deepwater gas production in the gulf to increase steadily to 2.2-2.9 tcf/year during that period. Production from the slope area—in 200-1,000 m of water—would increase through 2005 before declining slightly, MMS said. But production from deeper gulf waters would increase through 2015 and may possibly equal production from the shelf a few years later.

MMS actions

The MMS issued revised guidelines to help operators submit oil and gas exploration and development plans.

Federal law required a company to obtain MMS approval of either an exploration plan or a development plan. The MMS Gulf of Mexico regional office received 600-700 plans/year.

MMS said guidance regarding E&D regulations previously was contained in 12 different documents. The guidance, a Notice to Lessees and Operators, updated the older guidelines and consolidated them into one document.

MMS issued a final environmental impact statement examining the possible effects of floating production, storage, and offloading (FPSO) systems proposed for use in the development of deepwater oil and gas resources in the gulf.

FPSOs store crude from deepwater wells until it can be transferred to shuttle tankers or oceangoing barges for transport to shore.

MMS said potential FPSO site-specific impacts were essentially the same as with other deepwater development and production systems. Most of the risk of oil spills was associated with the shuttle tankers, not the FPSO itself, and that risk was comparable to the risks from other deepwater systems and from pipelines.

MMS suspended royalties on the first 87.5 million boe that Chevron USA Inc. produced from Green Canyon Block 236 field off Louisiana.

The field, named Typhoon, was 173 miles southwest of New Orleans, and was partially in water deeper than 800 m. Chevron operated the leases in the Green Canyon Block 236 field, which also includes Block 237. Green Canyon was the fifth field to get royalty relief from MMS since 1995.

The Deep Water Royalty Relief Act allowed MMS to grant royalty suspensions on fields in water deeper than 200 m.

Lease sales

MMS scheduled a long-awaited eastern gulf sale for December 2001.

Sale 181 would be the first eastern Gulf sale since 1988. If held, it would be the only eastern Gulf sale until 2012.

The proposed sale area included 1,033 blocks covering 5.949 million acres in the western portion of the eastern Gulf, starting 15 miles off the Alabama coastline and extending south into the deepwater region.

The sale area was adjacent to the Mississippi Canyon region of the central Gulf, which had prolific gas production. The MMS estimated the sale area could contain up to 370 million bbl of oil and 3.2 tcf of gas.

Oil companies were interested in the DeSoto Canyon and the Destin Dome areas along the boundary between the eastern and central Gulf areas, which may be associated with Mississippi Canyon production. Water depths in the sale area were 108-10,980 ft.

Sales in the eastern Gulf had been few because of Florida's objection to drilling within 100 miles of its coastline.

MMS noted the proposed sale area was "at least 100 miles offshore Florida," as well as 15 miles off the Alabama coast and 64 miles off Louisiana.

The Destin Dome dispute may affect leasing. Chevron Corp. USA, Conoco, and Murphy Exploration & Production filed suit in a federal claims court after the US blocked development of the Destin Dome gas field 25 miles off Pensacola, Fla., in the eastern gulf.

The three companies were equal partners in the project, with Chevron serving as operator. The US Department of Energy had said the field contained potential reserves of up to 2.6 tcf of dry gas.

In March 1998, Chevron filed an appeal with the US Secretary of Commerce seeking to override Florida officials' attempts to block development of Destin Dome. A review by the Commerce Department had tied up the appeal.

The suit alleged that the Environmental Protection Agency stopped processing necessary environmental permits for that project, pending a decision by Commerce.

In other action, MMS planned to include blocks in the Western Gap in a lease sale in 2001.

It first began offering leases in the Western Gap, which falls just beyond the US exclusive economic zone, in 1983, but suspended offering the blocks in 1997 after Mexico complained the gap was not delineated by treaty.

The two nations approved a treaty in 2000 that gave Mexico 62% of the region, or 3,179 sq nautical miles, and the US had 38%, or 1,913 sq nautical miles. The two governments also agreed on a 1.4-mile wide buffer zone along the border, which would remain free from development by either side for 10 years.

Discoveries

Noble Affiliates Inc., Ardmore, Okla., had a deepwater discovery at its Lost Ark prospect on East Breaks Block 421 in 2,700 ft of water.

The well was drilled to 7,770 ft TVD/MD. Noble said it found a pay section with high porosity and permeability at 6,695-7,770 ft. It planned to develop Lost Ark via subsea completion tied back to an existing host platform.

Noble had 48.4%, Forest Oil Corp. 50%, and Noble Drilling Exploration Co.1.6%.

McMoRan Exploration Co., New Orleans, reported success at two exploration wells.

McMoRan's third well on Eugene Island Block 193, on the North Tern deep prospect, found gas pay at 16,460-613 ft and 16,790-952 ft. The company said the sands were twice as thick as indicated by 3D seismic data, and reserves could be 100 bcf or more.

The well would be completed using the Eugene Island 193-A platform. Production was estimated at 50 MMcfd of gas. McMoRan had a 53.4% working interest.

On Main Pass Block 986, a step-out 1 mile northwest of the discovery on the Shiner prospect found pay at 2,668-88 ft.

McMoRan said the discovery and stepout could produce more than 25 MMcfd of gas. It had a 71.3% working interest.

Kerr-McGee Corp., Oklahoma City, had an oil discovery in the deep water at its Gunnison prospect area on Garden Banks Block 668.

The 17,000-ft well, drilled in 3,150 ft of water, encountered 275 ft of net pay in three main zones.

Kerr-McGee had 50%, Canadian Occidental Petroleum Ltd. 30%, and Cal Dive International Inc., 20%.

Typhoon, Na Kika

BHP Petroleum Pty. Ltd. planned its first deepwater development in the gulf, Typhoon field.

BHP and operator Chevron Corp. each held half of the field, in 2,000 ft of water 62 miles off Louisiana on Green Canyon Blocks 236 and 237.

Typhoon would be developed through subsea completion and tie-back of four existing appraisal wells. A small tension-leg platform would be built and installed as a host facility.

Production from Typhoon was expected to start in late 2001, less than 4 years after discovery, and peak at 40,000 b/d of oil and 60 MMcfd of gas. BHP estimated the commercial life of the field at 6-8 years.

Two export pipelines would transport Typhoon's oil and gas to shore.

Shell and BP planned to spend $1.26 billion to develop six widely spaced deepwater oil and gas fields using the first floating, multiarm subsea production system in the gulf.

Output from the project, Na Kika, was to start by mid-2003 in the eastern Mississippi Canyon (MC) area.

Na Kika ultimately was to recover more than 300 MMboe. It would initially involve development of five fields: Ariel (MC 429), East Anstey (MC 607), Fourier (MC 522), Herschel (MC 520), and Kepler (MC 383). Shell's Coulomb field (MC 657), primarily gas, would be tied back to the host facility as capacity permitted, probably around 2005.

Shell/BP discovered the five fields in 1987-97, and Shell found Coulomb in 1988. Kepler, Ariel, and Herschel fields were mainly oil, and Fourier and East Anstey were primarily gas.

Coulomb is 25 miles east of the planned site for the Na Kika floating production system. Shell did not specify a block for the floating production system but said it would be centered on the Na Kika fields. The fields were in 5,800-7,600 ft of water.

Shell would be preproduction operator responsible for the design, fabrication, and installation of the production host facilities and subsea systems plus drilling and completion of the 10 development wells. BP would be post-production operator, handling host facilities operation and satellite field surveillance.

Peak rates were expected to reach 325 MMcfd of gas and 100,000 b/d of 25-29°-gravity oil, with oil and gas trans-ported by pipeline to shore. Development drilling would start at Kepler field in 2001.

Crazy Horse

BP and ExxonMobil Corp. had a major discovery, Crazy Horse North, in the deepwater gulf 5 miles northwest of Crazy Horse field.

BP had 75% and ExxonMobil 25% of both fields. They said that Crazy Horse would produce 1 billion bbl, making it the largest ever opened in the Gulf.

Crazy Horse North was on Mississippi Canyon Block 776 and on a separate structure than Crazy Horse. The companies said Crazy Horse North would rank as one of five largest fields in the Gulf.

The wildcat found 581 ft of hydrocarbons in three intervals. The hole, in 5,640 ft of water, went to 26,046 ft TD.

BP said the completed Crazy Horse 2 appraisal encountered 675 net ft of pay in three primary intervals. That well, on Mississippi Canyon Block 822, reached 29,060 ft TD. It was drilled in 6,300 ft of water 1.5 miles southeast of the discovery.

BP said the Crazy Horse discovery, drilled on Mississippi Canyon Block 778, found 520 net ft of pay in three intervals. It was drilled to 25,770 ft TD in 6,000 ft of water.

Plans were under way for a phased development of Crazy Horse. Initial production was expected by 2005 from a 250,000-b/d floating production unit.

Gulfstream

The Federal Energy Regulatory Commission approved the construction of the $1.7 billion Gulfstream gas pipeline from Mobile Bay, Ala., across the Gulf of Mexico to central Florida.

It would be the largest pipeline construction project in the gulf. Completion was due in 2002.

Gulfstream Natural Gas System LLC would build and operate the 753-mile, 1.13 bcfd line supplying gas distribution companies and power generators in central and eastern Florida.

FERC said Florida needed additional gas supplies to meet substantial increases in consumption driven by population growth.

Gulfstream had proposed building supply area facilities in Alabama and Mississippi. It planned to install the 437 miles of 36-in. concrete-coated pipe across the gulf to Manatee County, Fla., beginning in the second half of 2001. From there, 292 miles of mainline and laterals, ranging from 16-in. to 36-in., would extend across Florida and terminate in Palm Beach.

Affiliates of Duke Energy Corp. and Williams bought Coastal Corp.'s interests in Gulfstream, suspending their own Alabama-to-Florida project, the Buccaneer pipeline.

Gulfstream awarded Stolt Offshore SA a contract to install the offshore portion of the line from Mobile Bay, Ala., to Tampa Bay, Fla. Stolt said this was the largest offshore pipelay project to date in the Gulf of Mexico.

Hydrates problem

Williams of Tulsa faced a technical challenge with a shallow-water platform that would accept deepwater production from remote subsea wells in up to 7,200 ft of water, the gulf's deepest subsea development.

The challenge was flow assurance to the shallow-water platform. Williams planned to use a process for the recovery and reuse of chemical methanol as a hydrate inhibitor for the project.

The methanol would be used in nine subsea wells in three deepwater fields: Aconcagua, Camden Hills, and Kings Peak. The subsea wells were 55 miles south of Williams' proposed shallow-water platform.

The owners of the three fields—TotalFinaElf E&P USA Inc., Marathon Oil Co., BP, Pioneer Natural Resources USA Inc. and Mariner Energy Inc.—approved a project known as Canyon Express to develop the gas-gathering system and infrastructure, which would tie back the deepwater wells to the Williams Canyon Station host platform in 299 ft of water.

Production of 500 MMcfd of gas from the subsea wells was expected by summer 2002.

Industry uses methanol in cold waters to inhibit the formation of hydrates, which can block production flow. The Williams project was unusual because of its expanded application and reuse of methanol.

The Williams Canyon Station project included the storage, regeneration, and distribution of 1,900 b/d of methanol.

If the methanol were not recovered, it would cost $60,000/day to produce 500 MMcfd from the deepwater subsea wells.

The recovery process would allow Williams Energy to recover 80-90% of the chemical for reinjection.

A 110-mile, closed loop, 12.75-in. diameter pipeline would gather production from the wells to Williams Canyon Station host platform.

The company said tie-back of the subsea wells to the host platform presented technical challenges, as hydrates could plug the line at any point. Equally significant was the 7,200-ft water depth, where temperatures below 40° F. can cause hydrates to form at the wellhead.

Gathering lines

Deepwater Holdings LLC said gas began flowing through its East Breaks Gathering System in the deepwater gulf. The pipeline was installed in water depths ranging from 440 ft to 4,700 ft.

Deepwater Holdings was a joint venture equally owned by subsidiaries of Houston-based El Paso Energy Partners LP and Coastal Corp.'s ANR Pipeline Co.

The 85-mile, 20-in. system, which had a design capacity of more than 400 MMcfd of gas, was transporting gas from a deep draft caisson vessel (DDCV) platform on Alaminos Canyon Block 25 to High Island Block A-573, where it tied into Deepwater Holdings' High Island Offshore System. From there, the gas moved to tie into ANR's pipeline system at West Cameron Block 167, and to Coastal Corp.'s 1.2 bcfd Eunice gas processing and fractionation plant in Louisiana.

The gas came from the Hoover-Diana project on East Breaks 945, 989, 946, and 988, which was tied back subsea to the DDCV on Alaminos Canyon 25. The Hoover-Diana project was owned by ExxonMobil Corp., 66.7%, and BP Amoco PLC, 33.3%.

Williams's Field Services unit acquired the Black Marlin Pipeline System off Texas for $9.3 million.

Blue Dolphin Energy Co. previously held 50% of the system; MCNIC Pipeline and Processing Co. held 33.33%; and WBI Holdings Inc., a subsidiary of MDU Resources Group Inc., held 16.67%.

The 75-mile natural gas and condensate gathering line with related onshore facilities serves the High Island area. The agreement also included a new 3-mile lateral from High Island Block A-5 to a connection with the Black Marlin line in A-6.

Dauphin Island Gathering Partners (DIGP), a joint venture pipeline company, began transportation service from two gulf fields.

Dauphin Island moved gas to the Mobile Bay Processing Partners' plant near Coden, Ala., for processing and redelivery to interstate markets.

In July, DIGP began providing gathering and transportation service on a lateral from the Main Pass 265 platform, which connected four of Coastal Oil & Gas Corp.'s Main Pass area production blocks. Initial production of 25 MMcfd of gas was expected to increase to at least 70 MMcfd.

DIGP also began service to El Paso Production Co. and Chevron USA Production Co. from Viosca Knoll Block 385.