Despite oil price uncertainties, the deepwater Gulf of Mexico continued to be the hottest US exploration play in 1999.
The momentum continued from the previous year, in which deepwater gulf oil and gas production set a record.
The US Minerals Management Service said that in the 1994-98 period oil production from waters deeper than 1,000 ft increased 279%, while gas production grew 252%. Oil output increased from 42 million bbl in 1994 to 159 million bbl in 1998. Gas production increased from 159 bcf in 1994 to 560 bcf in 1998.
MMS said that in 1998 oil production in the deepwater gulf rose 47% vs. 1997 production. And it said 11 more deepwater development projects went on flow in 1999.
MMS Director Walt Rosenbusch said, "The 1998 increase is significant and of national importance. The rising amount of production coming from the deep water has great momentum and will continue to play a key role in our national energy strategy.
"While total domestic production of oil declined some 410,000 b/d from 1994 to 1998, the decline would have been nearly twice as large if the deepwater production had not increased by 321,000 b/d," he added.
Meanwhile, the PIRA Energy Group predicted growth in gas production from the deepwater gulf during 1999-2001 would offset declines from the shallow-water gulf.
For shallow-water gas, PIRA said the declining number of producing wells (net) has outweighed the increase in average productivity of those wells, resulting in an overall decrease in output since 1997.
PIRA predicted shallow-water production would decline dramatically through 1999 and 2000 as a result of declining productivity of older wells and reduced drilling. It said the Eastern Gulf would be the dominant growth area for deepwater gas, and during 1998-2001 the region`s output would increase 1.6 bcfd over the period, accounting for about two thirds of total incremental production.
Deeper water
The US Energy Information Administration reported that dramatic advances in offshore drilling technology had tripled the water depth record for production on the Outer Continental Shelf from 1,760 ft in 1989 to 5,376 ft in 1997.
Since then, operators drilled in depths exceeding 7,000 ft. Technological advances also lessened the time between discovery and initial production for offshore projects, enhancing economic returns.
EIA said development times for deepwater prospects declined from 10 years for a discovery in 1984 to roughly 2 years for fields discovered in 1996.
EIA said prospects for gas supplies from the offshore showed potential for substantial growth. Recoverable gas resources in undiscovered fields in the federal waters of the gulf were estimated to be 96 tcf as of the end of 1995, with an additional 37 tcf to be proven in already known fields.
Combined with the 29 tcf in reserves already proved for this area, that was equivalent to the 1997 estimate of 165 tcf in proved reserves for the US as a whole.
EIA said, "Recovery of this huge resource depends on the underlying technology and economics. In addition to developing new technology, companies have directed their efforts at improving potential profitability by aggressively managing costs, accelerating project development, and increasing well productivity."
Fields in water deeper than 10,000 ft might provide more than 1.9 bcfd by 2002, up from 0.4 bcfd in 1997, said EIA.
It said the Deep Water Royalty Relief Act, by increasing the probability of economic success in waters deeper than 200 m, stimulated bidding for offshore leases since it took effect in 1996.
Lease sales
Low oil prices deflated the two federal Gulf of Mexico lease sales held in 1999.
In the Central Gulf sale held in March 1999, only 207 of the 3,806 blocks drew bids. In the previous Central Gulf sale, held in 1988, operators had bid on 794 blocks of 4,180 offered.
The 1999 sale resulted in apparent high bids totaling $171,804,696. About 43% of the blocks receiving bids were in 800 m of water or more. About 51% of the bids were for blocks in 200 m of water or less.
MMS said operators submitted a total of 2,720 bids, exposing $199,638,752, down 85% from the previous sale`s total.
Smaller firms dominated the sale. Sonat Exploration GOM Inc. was the most active bidder, with high bids on 22 tracts totaling about $5.7 million. Vastar Resources Inc. filed high bids on 18 tracts totaling $12.2 million.
The top bid was $16,577,900 for Walker Ridge Block 121. Joint bidders Marathon Oil Co. and Kerr-McGee Oil & Gas Corp. submitted the only bid for the tract.
The August 1999 sale of Western Gulf tracts also was lackluster.
Of the 3,747 blocks offered, 153 drew a total of 177 bids. Apparent high bids totaled $94,649,044.
About 44% of the bids were for blocks in less than 200 m of water, 6% for 200-400 m, 8% for 400-800 m, and 42% for tracts in more than 800 m.
The deepest-water block to receive a bid was Keathley Canyon 842 in 3,049 m of water.
The top bid in the sale was $11,283,000 for Garden Banks 877, submitted by Kerr-McGee.
Crazy Horse
BP Amoco PLC and Exxon Mobil Corp. claimed what they called the biggest deepwater Gulf of Mexico discovery to date.
They said the Crazy Horse discovery had reserves of at least 1 billion boe.
The liquids-gas split was not quantified, but both companies called Crazy Horse an oil find.
The discovery well was drilled to 25,782 ft in 6,000 ft of water on Mississippi Canyon Block 778.
BP Amoco was operator, with a 75% interest, of the three blocks that encompass the Crazy Horse structure. Exxon Mobil had 25%.
BP Amoco also announced three other deepwater gulf oil discoveries in the southern Green Canyon area. BP Amoco`s share of the combined reserves was about 600 million bbl.
BP Amoco`s partner in the Atlantis discovery was BHP Petroleum (Americas) Inc. In the Mad Dog discovery its partners were BHP and Unocal Corp., and in the Holstein discovery the partner was Shell Exploration & Production Co.
Mad Dog
BP Amoco and partners said their Mad Dog ultradeepwater strike could be one of the gulf`s biggest discoveries.
The oil and gas find was drilled on Green Canyon Block 826 in 6,734 ft of water and encountered 300 ft of net hydrocarbons, mostly oil. The discovery well was drilled to 22,400 ft.
The well was on a 21/2-block unit owned by operator BP Amoco 63.56%, Unocal Corp.`s Spirit Energy 76 unit 25%, and BHP 11.44%.
The unit, in the southeastern portion of the Green Canyon area, covers blocks GC 825, 826, and the southern half of 782.
BHP said Mad Dog was believed to extend into adjacent blocks Green Canyon 738, 739, 781, the northern half of 782, and 783, owned 56% by BP Amoco and 44% by BHP.
Spirit Energy estimated that, within the unit on which the discovery well was drilled, Mad Dog`s gross resource potential was greater than 400 million boe and could be 800 million boe.
Spirit Energy said, "Mad Dog is, without question, a very significant discovery."
Mad Dog was on a trend that BHP termed the Atwater Foldbelt and Unocal called the Eastern Foldbelt and Salt Canopy.
BHP said previous discoveries on the trend were Atlantis on Green Canyon 699 and the Neptune feature on Atwater Valley Block 575. BHP owned 100% working interest in 21 blocks in the Walker Ridge area, into which it said the Atwater Foldbelt extends for about 60 miles.
Spirit Energy 76 and Conoco Inc. had a discovery at their K2 prospect north of Mad Dog on the same trend.
They said the Green Canyon Block 562 field was a high-quality hydrocarbon reservoir in 3,900 ft of water. They did not release production test data.
More drilling was planned in 2000. Conoco and Spirit Energy each held 50%.
Mirage
Vastar had a significant oil discovery at its deepwater Mirage prospect on Mississippi Canyon Block 941.
The well was drilled to a measured depth of 16,600 ft in 3,927 ft of water. The well cut about 300 ft of net oil pay in five intervals and was the deepest well yet in the Mars basin, said Vastar.
Vastar said pay was in Miocene sands, which were productive elsewhere in the Mars basin, and the gravity was in the mid-20°s, which was typical of Mars basin crudes.
Vastar had 75% and Spirit Energy 25%. The well was 12 miles south of Vastar`s 1998 King discovery on Mississippi Canyon Block 764.
Mirage`s drilling program included a sidetrack well drilled to a measured depth of 22,435 ft. At the deepest point, that measured depth translated into 21,744 ft TVD. The deepest previous well in the Mars basin was 19,828 ft TVD.
Vastar said initial drilling in the area indicated reserves of more than 100 million boe.
It said the well, including the sidetrack portion, cost $65 million. About $10 million of that was due to weather delays.
Brutus
Shell was proceeding with the $900 million development of its Brutus oil and gas discovery in the deepwater gulf`s Green Canyon area.
Brutus field covered Green Canyon Blocks 158 and 202. Development called for a tension-leg platform in 2,985 ft of water.
Brutus was Shell`s fifth TLP in the gulf and would be the 17th deepwater project in the gulf in which Shell was involved.
Shell drilled the Brutus discovery well on Block 158 in December 1988. An appraisal well followed in 1994 on the same block; in 1997, a third well was drilled.
Shell was focusing on Plio-Pleistocene sands reserves at 12,500-17,500 ft. Installation of the eight-slot TLP, which would serve as a hub for any future subsea projects to be developed by Shell in the area, was slated for mid-2001.
Production was expected to start in late 2001, reaching a peak capacity of 100,000 b/d of oil and 150 MMcfd of gas. Gross recovery of Brutus reserves was estimated at more than 200 million boe with a 70:30 oil-to-gas ratio.
Brutus would have complete separation, dehydration, and treatment facilities. They would be capable of processing 100,000 b/d of oil and condensate, 300 MMcfd of gas, and 30,000 b/d of produced water. Oil and gas would be transported via pipelines due to be installed in 2000.
OIL production would go through an 18-in. line 26 miles to the South Timbalier 301 B platform. From there, it would move through the existing Amberjack system.
GAS output would move through an 18-in., 24-mile system to the Manta Ray offshore gathering system.
Ursa output
Shell claimed a water-depth record for an oil and gas production platform with the start-up of its Ursa TLP in 3,800 ft of water.
Ursa was on Mississippi Canyon Block 809. It produced 13,000 b/d of oil and 20 MMcfd of gas from its first well.
Design production rates were 150,000 b/d of oil and 400 MMcfd of gas. The water depth for Ursa beat the previous record for a permanent oil and gas production platform set by the Ram-Powell TLP in 3,214 ft of water in 1997.
Total project cost was $1.45 billion, excluding lease costs. Reserves were estimated at 400 million boe.
Interest owners were Shell 45%, BP Amoco 23%, and Conoco Inc. and Exxon Mobil Corp. 16% each.
Shell also claimed a Gulf of Mexico production record with a well at Ursa field.
On Sept. 8, 1999, the A-7 well produced 39,317 b/d of oil and 60.67 MMcfd of gas, or 50,150 boe/d. That topped the previous record of 46,475 boe/d at the Troika development, also in the gulf.
Shell said the record was achieved by executing a frac-and-pack at a rate of 40 bbl/min and by using shunt tubes to ensure a solid pack, in addition to using 51/2-in. tubulars.
More discoveries
Elf Exploration Inc. had a discovery with a gross thickness exceeding 200 ft on its Aconcagua prospect in 7,073 ft of water on Mississippi Canyon Block 305.
It did not disclose whether the find was oil or gas, but the well logged multiple pay sands and cut additional sands with productive potential. Elf held 50%, and Mariner Energy and Pioneer Natural Resources USA Inc. each had 25%.
Chevron USA Production Co. and BHP confirmed their Typhoon deepwater discovery in 2,000 ft of water.
Green Canyon 237 No. 1 cut 310 net ft of oil pay through several horizons. The discovery was on adjoining Block 236. Chevron and BHP were 50-50 partners.
Seagull Energy Corp. had a discovery on East Cameron Block 152. The hole hit 43 ft of pay at 9,600-9,700 ft and flowed 9.9 MMcfd of gas and 910 b/d of condensate through a 17/64-in. choke. Seagull and Spinnaker Exploration Co. LLC each had 50%.
Shell had its third deepwater oil and gas discovery in the Auger basin. A well drilled on Shell`s wholly owned Oregano prospect on Garden Banks Block 559 found commercial hydrocarbons. It was drilled in 3,393 ft of water to a measured depth of 19,500 ft.
The well was 8 miles south of Shell`s Auger TLP. Other Shell discoveries in the area included Cardamom, Serrano, Habanero, and Macaroni. Basin Exploration Inc. had a discovery on West Delta Block 63. The well, drilled to 13,920 ft TVD, cut 117 net ft of oil and gas condensate pay in multiple Miocene sands below 11,000 ft TVD. Basin had 50%, and Duke Energy Hydrocarbons LLC had 50%.
Elf had a deepwater discovery on Mississippi Canyon Block 243 in 2,835 ft of water. The Matterhorn prospect cut 370 gross ft of oil-bearing reservoirs in two zones. On test, the well flowed 6,640 b/d of 36°-gravity oil and associated gas. Elf held 100% of the block.
Marathon had a gas discovery on its Camden Hills prospect on Mississippi Canyon Block 348. The MC348-1 well cut 200 ft of gas pay and was drilled to 15,080 ft TD in 7,200 ft of water.
Onwers were Marathon 50.03%, WI Inc. 33.3%, and Total Exploration & Production USA Inc. 16.67%.
Apache Corp.`s West Cameron 615 A-4 flowed 35 MMcfd of gas through a 38/64-in. choke. The discovery was drilled directionally to a total vertical depth of 6,669 ft and a measured depth of 11,951 ft. It cut 180 ft of true-vertical-thickness pay in two Pleistocene zones. Apache had 75% and Santa Fe Snyder Corp. 25%.
Apache had a discovery at High Island 86 No. 1, a dual completion, which flowed a combined 17.5 MMcfd from Miocene IO and JB sands. Interests were Apache two thirds and Remington Oil & Gas Corp. a third.
Other finds
Forest Oil Co. had a strike at High Island Block 116. B-2 was drilled to 15,975 ft TD and 13,694 ft TVD and cut 412 net ft (TVD) of pay. Owners were Forest 54.75% and Louis Dreyfus Natural Gas Corp. 45.25%.
Murphy Oil Corp. had a deepwater discovery on the Medusa prospect on Mississippi Canyon Block 582. The well, which was drilled in 2,100 ft of water, cut two intervals with more than 120 ft of total pay after reaching 16,241 ft measured depth. Owners were Murphy 60%, Callon Petroleum Co. 15%, and British-Borneo Petroleum Inc. 25%.
Vastar found oil on its Horn Mountain prospect on Mississippi Canyon Block 127. Partners were Vastar with two-thirds interest and Occidental Petroleum Corp. with the rest.
The well, drilled to 14,677 TD, cut 285 ft of net pay in two primary and two secondary zones in the Miocene. The primary intervals hold 33°-gravity oil. The well was sidetracked downdip, which confirmed a hydrocarbon column at least 500 ft thick.
Chieftain International Inc. had a find on High Island Blocks A-510 and A-531 off Texas. The well was drilled to 11,107 ft TD and cut more than 260 net ft of pay in multiple zones. Chieftain and Tana Oil & Gas Corp. each had 50%.
Chieftain and Equitable Production Co. had an oil discovery on South Timbalier Block 196. It was drilled to 12,098 ft TD and encountered more than 110 net ft of hydrocarbon-bearing pay in five zones. Each firm had 50%.
Kerr-McGee and its 50-50 partner Agip Petroleum Exploration Co. Inc. found gas on Garden Banks Block 184.
The well, drilled to 14,625 ft in 692 ft of water, was in the Flex trend area and had an estimated 40 bcf of gas reserves. The partners planned to develop the well as a subsea tie-back to an existing production facility on the shelf.
Shell had a discovery on the Habanero prospect on Garden Banks Block 341 in 2,000 ft of water. The well, drilled to a measured depth of 21,158 ft, found 200 ft of net pay in two zones.
Partners were operator Shell 55%, Murphy 33.75%, and Callon Petroleum Co. 11.25%.
Developments
Chevron and its partners, Exxon Mobil and PetroFina Delaware Inc., had first oil at the deepwater Genesis facility. Production began at 30,000 b/d of oil and about 20 MMscfd of gas.
Total Offshore Production Systems (TOPS), a joint venture of R&B Falcon Corp. and Intex Engineering Inc., claimed the first 15,000-psi subsea completion in 880 ft of water on Green Canyon Block 20.
The Gyrfalcon well was drilled in March 1997 by Shell, which retained a net profit interest in the field.
Anadarko Petroleum Corp. let contracts for its Tanzanite development on Eugene Island Block 346. The 16-slot drilling and production platform would have capacity for 40,000 b/d of oil and 350 MMscfd of gas and was due installation in July 2000.
Kerr-McGee started production at Ewing Bank 910 and West Cameron 638 fields. Production from Ewing Bank 910 was to peak at 16,000 b/d of oil and 23 MMcfd of gas in mid-1999. Production from West Cameron 638 was expected to reach 20 MMcfd.
Kerr-McGee had 40% of both developments. Petrobras America Inc. had the rest of Ewing Bank 910, and Petrobras had 33.33% and Burlington Resources Oil & Gas Co. 26.67% of West Cameron 638.
Texaco Exploration & Production Inc. and Chevron began production from the Gemini deepwater subsea development.
Gemini`s wells, manifold, and flowlines were in 3,400 ft of water on Mississippi Canyon Blocks 292 and 247. Production was 200 MMcfd and 3,000 b/d of condensate in early 2000. Texaco had 60% and Chevron 40%.
Elf installed the jacket of the Virgo production platform on Viosca Knoll Block 823 off Louisiana. The platform was in 1,130 ft of water.
Owners were Elf 64%, Coastal Oil & Gas Corp. 16.2%, Pogo Producing Co. 10.8%, and Nippon Oil Exploration USA Ltd. 9%.
Leviathan Gas Pipeline Partners LP let contract for its Moses TLP, part of its Sunday Silence field development on Ewing Bank Blocks 958, 959, 1002, and 1003 in 1,500 ft of water. The platform would process 25,000 b/d of oil and 55 MMcfd of gas.
Samedan Oil Corp. began production from two blocks off Louisiana. Vermillion 335 was producing 900 b/d of oil and condensate and 14.5 MMcfd of gas. Owners were Samedan 50%, Murphy 35%, and Walter Oil & Gas Corp. 15%.
The second field, West Cameron 600, was producing 13 MMcfd and 15 b/d of condensate. Samedan held a 100% interest.
Texaco began production from Vermilion 379 field in 350 ft of water. Output was 1,041 b/d of oil and 18.1 MMcfd of gas from six wells. Owners were Texaco 50%, Samedan 25%, and Petrobras 25%.
Delmar Systems Inc., Broussard, La., and Shell Deepwater Development Inc. claimed a world mooring-depth record with the Transocean Marianas semisubmersible drilling rig, which was moored in 6,940 ft of water on Mississippi Canyon Block 522. The vessel used a suction-anchor system and Delmar`s single-vessel installation procedure.
BP Amoco and Shell began production from the Marlin TLP on Viosca Knoll Block 915. The TLP was in 3,240 ft of water. Production was due to reach 40,000 b/d of oil and 250 MMcfd of gas in 2000. BP Amoco had 75% and Shell 25%.
GAS pipeline
Coastal Corp. applied to the US Federal Energy Regulatory Commission to build and operate a 1.1-bcfd gas pipeline serving the growing Florida market.
The 744-mile line would originate near Mobile, Ala., and cross the Gulf of Mexico with more than 400 miles of 36-in. line to Manatee County, Fla.
In Florida, 292 miles of mainline and laterals, ranging in size from 16 in. to 36 in., would deliver gas to electricity generation plants. The line would terminate on Florida`s East Coast.
Construction of the $1.6 billion project was due to start in June 2001. The line would go into service a year later.
Coastal said 10 nonaffiliated utility and power-production customers made long-term, binding commitments for capacity on the system.
Coastal said the Gulfstream Natural Gas System would be an economic delivery system for Florida`s increasing gas demand.
The Florida Public Service Commission had predicted the state would need more than 9,600 Mw of additional generating capacity by 2007, and Coastal said its project could meet half of that.
Coastal also increased its Mobile Bay area midstream holdings. Its Coastal Field Services Co. subsidiary bought an additional 27.9% of Mobile Bay Processing Partners, bringing its ownership to 42.4%.
The partnership owns a gas processing plant and cogeneration facility near Coden, Ala. The 40-Mw cogeneration facility supplies the power requirements of the 600 MMcfd processing plant.
Also, the subsidiary Coastal Dauphin Island Co. bought a further 27.6% of Gulf Coast NGL Pipeline, bringing its ownership to 42.1% in a gas liquids line between Mobile Bay and fractionators in Louisiana.
Liquids line
Enterprise Products Partners LP planned to develop a $245 million, 160,000 b/d natural gas liquids pipeline system along the Gulf Coast.
Enterprise signed a letter of intent to acquire a 263-mile, 10-in. liquids pipeline extending from Sorrento, La., to Mont Belvieu, Tex.
The seller would be Concha Chemical Pipeline Co., an affiliate of Shell. Enterprise would acquire Concha`s line through Entell NGL Services LLC, a 50-50 joint venture of Enterprise and Tejas Natural Gas Liquids LLC, another Shell affiliate.
Upon completion of a previously announced NGL alliance between Shell and Enterprise, Entell would become a wholly owned unit of Enterprise, with Tejas taking an equity stake in Enterprise.
The pipeline moved chemical-grade propylene from Sorrento to Mont Belvieu, but Enterprise planned to convert part of it into batch service and move chemical-grade propylene, mixed NGL, or NGL products such as ethane, propane, normal butane, isobutane, and natural gasoline.
Enterprise planned to expand the capacity of the pipeline to 75,000 b/d from 35,000 b/d.
Enterprise would continue to transport propylene in the pipeline for Shell Chemical Co. through a long-term exchange agreement.
Enterprise was considering building or buying other pipelines to complete its planned 160,000 b/d system. It expected to finish the larger system expansion in second half 2000.
Enterprise said that due to a lack of pipelines, NGLs produced in Louisiana and Mississippi had limited access to the US`s largest NGL market at Mont Belvieu and therefore traded at a discount. It said the situation would be exacerbated by expected increases in deepwater gulf gas production.
OIL pipeline
Enbridge Inc., Calgary, and LOOP LLC, New Orleans, proposed a pipeline to carry 600,000 b/d of crude oil from Louisiana to Texas.
The companies intended to build the $400 million line to meet growing demand for heavy, sour oil by western Gulf Coast refiners
Project operator Enbridge and partner LOOP completed feasibility and engineering studies on the proposed Alligator pipeline and expected completion in late 2001.
Alligator would consist of a 275-mile, 36-in. pipeline from the St. James, La., hub to Texas City, Tex.
The system would link crude oil supplies delivered to the Louisiana Offshore Oil Port (LOOP) with western Gulf Coast refiners.
Alligator would have capability to expand to 900,000 b/d. The western Gulf Coast had about 3.5 million b/d of refining capacity.
The project would use existing LOOP marine terminal facilities, including a transfer station and oil port 20 miles south of Grand Isle, La., in 110 ft of water in the gulf.
From this port, a subsea pipeline transports oil to LOOP`s eight underground salt caverns at Clovelly, La. The caverns have a potential storage capacity of up to 45 million bbl of oil. The caverns are connected to the St. James hub via pipeline.
Other pipelines
East Breaks Gathering Co. LLC signed a deal with Exxon Mobil and BP Amoco to own and operate an 85-mile, 20-in. gas pipeline from the producers` Alaminos Canyon Block 25 production facility to High Island Offshore System on High Island Block A-573.
The $90 million line would have capacity of more than 400 MMcfd. East Breaks Gathering involved Leviathan 40%, ANR Pipeline Co. 40%, and Natural Gas Pipeline Co. of America 20%.
Tejas Energy LLC and Leviathan formed Nemo Gathering Co. LLC to build a 24-mile, 20-in. gas-gathering pipeline in the deepwater gulf. Tejas had 66.08% and Leviathan 33.92%.
The Nemo line would connect Shell`s planned Brutus project on Green Canyon Block 158 with the interconnect of Manta Ray Offshore Gathering system at a Leviathan-owned platform on Ship Shoal Block 332. Brutus was due on flow in late 2001.
A 20-in. pipeline was rerouted through a platform on Main Pass Block 69 for Shell affiliate Equilon Enterprises LLC.
Global Divers & Contractors Inc. performed the work in what it called the largest series of mechanical pipeline connectors ever used in one project application. The project increased flow volumes in the 20-in. line.
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A drawing of Shell Deepwater Development Systems Inc.`s Brutus tension-leg platform.
