DRILLING ECONOMICS IN THE Gulf of Mexico, where only a year earlier the chief worry had been availability of rigs and supplies, suffered from low oil and gas prices and operators` budget cuts in 1998.
Global Marine`s Summary of Current Offshore Rig Economics sustained its largest month-to-month drop since June 1986 between August and September 1998. A slump in day rates for jack up rigs led more moderate decreases in rates for semisubmersibles and drillships.
"The offshore drilling business continues to suffer from low oil prices, and shallow-water drilling markets worldwide have been particularly hard-hit," Global Marine Chief Executive Officer Bob Rose said in November. "Day rates for some jack ups drilling on the continental shelf in the U.S. Gulf of Mexico have fallen below $20,000, which is only a few thousand dollars above daily cash operating costs."
Deepwater exploration and development dominated spending and, increasingly, overall drilling during the year. And operators added to a string of discoveries below salt.
Overall drilling
The Minerals Management Service in mid-1998 predicted that more than 50 deepwater fields would have come on stream by 2000.
In July 1998, more wells were being drilled in water deeper than 200 m than in shallower waters. According to MMS statistics, there were 31 wells under way in water depths of 0-200 m and 37 wells in greater depths.
In the deeper category, 16 wells were being drilled in water depths of 201-400 m, 7 in 401-800 m, 1 in 801-1,000 m, and 13 in 1,000 m and more.
Leasing and drilling applications further reflected activity gains in middle and greater water depths.
As of Dec. 14, 1998, operators held 4,213 active leases in waters 0-200 m deep and 4,150 leases in waters of greater depth (282 in 201-400 m, 493 in 401-800 m, 364 in 801-1,000 m, and 3,011 in 1,000 m and more).
On the same date MMS had approved 25,496 applications to drill in water 0-200 m deep and 11,367 in greater water depths. The deepwater applications included 8,524 in 201-400 m, 1,258 in 401-800 m, 233 in 801-1,000 m, and 1,352 in 1,000 m and more.
Shallow water still claimed most of the platform population: 3,462 in 0-200 m, 424 in 201-400 m, 45 in 401-800 m, 4 in 801-1,000 m, and 15 in 1,000 m and more.
"Deep water" was generally construed to involve depths greater than 1,000 ft (300 m), and "ultradeep water" depths exceeding 2,700 ft (800 m).
Deepwater innovation
The deepwater gulf in 1998 retained its status as a breeding ground for innovative development.
British-Borneo Petroleum Syndicate plc, London, started production at the rate of 15,000 b/d from its Seastar monohull tension-leg platform in Morpeth field in 1,700 ft of water.
British-Borneo expected production through the Morpeth TLP to reach 35,000 b/d of oil and 36 MMcfd of gas. The company also intended to use the unit as a hub processing facility.
The low-cost, multiple-use TLP handled production from wells completed subsea on Ewing Bank Blocks 921, 964, and 965. Designed and built by Atlantia Corp., Houston, and installed by J. Ray McDermott Inc., Morpeth Seastar was called the first use of the monohull TLP technology.
British Borneo planned to use a Seastar TLP to develop Allegheny field, where first oil was due in third quarter 1999.
Elsewhere, Shell Deepwater Development Inc. (SDDI) and partners at year-end were preparing to start production in spring 1999 from the Ursa TLP set in 4,000 ft of water on Mississippi Canyon Block 854. Production capacities were 150,000 b/d of oil and 400 MMcfd of gas from 11 Ursa wells. The group had installed the platform in 1997 and late in 1998 was completing a pipeline to shore and drilling production wells.
Amerada Hess Corp., operator of a 50-50 combine with Oryx Energy Co., started production from Baldpate field with a compliant tower platform in 1,650 of water on Garden Banks Block 260 (Fig. 1). Initial rates were 2,000 b/d of oil and 8 MMcfd of gas. When all of the field`s seven predrilled wells were on stream early in 1999, output was to peak at 75,000 b/d of oil equivalent.
When installed, the Baldpate production platform became the world`s tallest freestanding structure in the world. The nonguyed tower measures 1,902 ft from the seafloor to the tip of the 260 ft flare booms. The tower section is 1,320 ft tall. The structure`s compliance, or ability to withstand forces such as those imposed by waves during hurricanes, comes from two axial tubes in each of the tower section`s four legs and an articulation point 500 ft above the seafloor.
Baldpate facilities were designed to handle production of 60,000 b/d of oil, 200 MMscfd of natural gas, and 75,000 b/d of water.
Amerada Hess and Oryx were developing the nearby Penn State Shallow reservoir with two subsea wells tied back to the Baldpate platform. Each of the wells was expected to produce 3,000-5,000 b/d of oil.
The Baldpate tower prematurely submerged during installation in May 1998 but was successfully lifted and, undamaged, set on the 351-ft base section.
Another innovative production scheme didn`t fare so well.
In December 1998 a deck for the Petronius compliant tower platform slipped into the gulf as it was being installed by J. Ray McDermott`s DB50 barge. Petronius, in 1,754 ft of water on Viosca Knoll Block 786, was jointly owned by operator Texaco Inc. and Marathon Oil Co.
The platform`s 3,605-ton south module contained production equipment, waterflood facilities, and crew quarters. It broke from its support, struck a transport barge and the DB50, and sank. The north module had been successfully placed earlier the same day.
Chevron USA Inc. in 1998 let a $3 million, 3-year operations and maintenance contract to Michael Baker Corp. unit Baker Energy, Houston, for the Genesis deepwater drilling-production floating spar platform in 2,700 ft of water on Green Canyon Block 205. The contract covered all production systems and equipment not related to drilling. Genesis production was to start at an initial rate of 12,000 b/d and rise by 2000 to 55,000 b/d of oil and 72 MMcfd of gas.
Chevron and partners Exxon Co. USA and PetroFina Delware Inc. positioned the 28,700-ton, 705-ft cylindrical steel hull of the Genesis drilling and production platform during mid-1998.
Planned deepwater work
Shell Exploration & Production Co. early in 1998 announced plans to develop three deepwater gulf discoveries-Angus, Europa, and Macaroni (Fig. 2).
All three fields, with combined reserves of more than 300 million bbl of oil equivalent, were to be developed subsea and tied back to existing platforms.
Shell planned to develop Macaroni with three subsea wells clustered around a four-well subsea manifold linked by dual pipe-in-pipe flow lines to the Auger TLP 12 miles away on Garden Banks Block 426. Shell Deepwater Development Inc. (SDDI) held 100% interest.
First production from Macaroni, which lies in 3,000 ft of water on Garden Banks Block 602, was due in mid-1999. Peak flow was estimated at 35,000 b/d of oil and 65 MMcfd of gas. Shell estimated ultimate recovery from Macaroni at 78 million bbl of oil equivalent.
Shell planned to develop Angus field, in 2,000 ft of water on Green Canyon Block 113, with a four-well subsea system, possibly tied back to its Bullwinkle fixed platform 12 miles away on Green Canyon Block 65. SDDI held 80% interest and operated Angus field. Marathon held 20%.
Production through an eight-slot manifold was to start in the second quarter of 1999 and peak at 40,000 b/d of oil and 60 MMcfd of gas. Ultimate recovery was estimated at 64 million bbl of oil equivalent.
Europa (SDDI 66%, BP Exploration Inc. 33%, and Conoco Inc. 1%) lies in 3,900 ft of water on Mississippi Canyon Blocks 934, 935, 890, and 891.
Shell, operator, planned to develop the field initially with four subsea wells tied back to its Mars TLP on Mississippi Canyon Block 807 about 20 miles away. The subsea system was to accommodate as many as four more wells in later drilling phases.
Europa was to start flow early in 2000, with production peaking at 60,000 b/d of oil and 45 MMcfd of gas.
Exxon Co. U.S.A. disclosed plans for its first development among 10 deepwater gulf discoveries in which it held interests in 1998. It said the linked development of Hoover and Diana fields would set a world record for drilling-production platform water depth-4,800 ft.
The fields, about 160 miles south of Galveston, Tex., hold reserves estimated at 300 million bbl of oil equivalent.
Exxon planned to use a deep-draft caisson vessel (DDCV) and surface production trees-a first for a development project in such deep water. The DDCV, a catenary-moored steel cylindrical hull, was to float over Hoover field and be able to handle production of as much as 100,000 b/d of oil and 325 MMcfd of gas.
Diana development was to involve six wells tied back to the Hoover facility. New pipelines were needed to carry production ashore.
Installation of the DDCV was due in 1999. Production was to start in 2000. Exxon held two-thirds interest in the fields, BP Exploration the rest.
In other deepwater work, Elf Exploration Inc. started development of its deepwater Virgo discovery in Viosca Knoll Block 823 with a fixed platform set in 1,130 ft of water (Fig. 3).
The four-leg, 12-skirt pile platform was to be able to handle 200 MMscfd of gas, 9,000 b/d of oil, 6,000 b/d of condensate, and 7,500 b/d of water. First production was due by the end of 1999.
Elf held a 64% working interest, Coastal Oil & Gas Corp. 16.2%, Pogo Producing Co. 10.8%, and Nippon Oil Exploration U.S.A. Ltd. 9%.
Elsewhere, the MMS in 1998 granted deepwater royalty relief valued at $143 million to Amoco Corp. for development of King`s Peak field on Desoto Canyon Block 133 field about 120 miles southeast of New Orleans in 6,700 ft of water. Royalties were to be suspended on the first 87.5 million bbl of oil equivalent produced from the field, which contains dry natural gas and lies next to Amoco`s King field, which received royalty relief earlier in the year.
Among deepwater discoveries disclosed in 1998, a British-Borneo Petroleum well on a prospect called Leo, drilled to 18,090 ft TD in 2,500 ft of water on Mississippi Canyon Block 546, penetrated multiple pay zones at 11,500-17,500 ft. It cut 200 ft of net oil and gas pay. Interest holders were operator British Borneo and Spirit Energy 76, 37.5% each, and Petrobras America Inc. and Snyder Oil Corp., 12.5% each. The group planned to drill Spirit Energy 76`s Calypso prospect after abandoning the Leo well pending development plans.
A flex trend appraisal well in 1,500 ft of water cut 300 ft of nethydrocarbon-bearing sands on the Conger prospect, Garden Banks Block 215. Amerada Hess Corp. et al. 5 GB 215 was temporarily suspended pending development decisions. The 4 GB 215, 11/2 miles away, encountered 300 ft of net pay above and below salt in 1997. Conger partners were Amerada and Shell Offshore Inc. 37.5% each and Oryx Energy 25%.
Reading & Bates Development Co. made a discovery on its East Breaks Block 643 North Boomvang prospect. The well, drilled to 12,312 ft MD in 3,668 ft of water, cut a 350 ft gross column with average net oil pay of 40-50 ft. Reading & Bates, operator with 62.5% interest, estimated reserves at 35-45 million bbl of oil equivalent. Norcen Energy Resources Ltd. held the remaining working interest. The operator suspended the well pending a development decision for the nearby East Boomvang discovery.
Subsalt activity
The gulf`s subsalt play yielded more discoveries in 1998, although activity had slowed due to low oil and gas prices and the technical challenges involved.
Subsalt prospecting requires special drilling techniques and enormous computing power to handle complex seismic processing.
At the start of 1998, at least 12 wildcats deliberately drilled to targets below salt had found hydrocarbons.
One of 1998`s subsalt discoveries, Anadarko Petroleum Corp. Tanzanite 1 on Eugene Island South Addition Block 346, flowed on test at rates of 21,917 b/d of 21.9° gravity oil and 29.7 MMcfd of solution gas through a 11/2-in. choke with flowing tubing pressure of 2,679 psi. Flow was from perforations of a 50-ft interval in a 450-ft continuous column. The well was drilled to 14,350 ft TD in 314 ft of water.
Anadarko, operator and 100% interest owner, let contract to Rowan Cos. Inc. for development drilling and planned for production start in the third quarter of 2000. It said seismic data indicated a reservoir with areal extent of 1,000 acres.
Anadarko also led a group that tapped hydrocarbons below salt in the Hickory discovery well on Grand Isle Block 116.
Drilled to 21,600 ft in 320 ft of water, the well cut 300 ft of hydrocarbon pay in multiple sands. It penetrated a salt section about 8,000 ft thick.
Anadarko ran a production liner to total depth and started a delineation well from the same surface location. It expected first production in 2000.
Interests in Grand Isle Blocks 110, 111, and 116, which hold Hickory, were operator Anadarko 50%, Shell 37.5%, and Ocean Energy 12.5%.
In other subsalt activity, Shell Offshore Inc. began oil and gas production from the first subsalt well in Enchilada field on Garden Banks Blocks 83, 84, 127, 128, and 172. The Chimichanga well, on Garden Banks Block 127, came on stream at an initial rate of 20 MMcfd of gas and 2,100 b/d of oil. It was drilled through a 1,300-ft thick salt tablet at 9,269-13,287 ft TVD. Water depth at the well location is 630 ft. Chimichanga was jointly owned by Shell Offshore, Amerada Hess Corp., and Pennzoil Exploration & Production Co.
Also, Phillips Petroleum Co. and Anadarko began production from Agate field through the 20 slot Mahogany field platform on Ship Shoal Blocks 349 and 359. Agate is west of Mahogany on Ship Shoal South Addition Block 361.
Initial Agate flow was 25 MMcfd of gas and 2,500 b/d of condensate from one well completed subsea.
Mahogany production began in December 1996 and averaged 15,000 b/d of oil and 35 MMcfd of gas in mid-1998.
Texaco Exploration & Production Inc. and Chevron U.S.A. Production Co. decided in 1998 on fast-track, subsea development of their Gemini subsalt gas and condensate discovery in 3,400 ft of water on Mississippi Canyon Blocks 291, 292, and 247.
The companies estimated Gemini reserves at 250-300 bcf of gas and 3-4 million bbl of condensate. Production, to start in 1999, was expected to peak at 150-200 MMcfd of gas and 2,000-3,000 b/d of condensate. Texaco, operator, held 60% working interest, Chevron 40%.
The combine planned to drill two development wells, complete an exploratory well, and tie the wells into a subsea manifold. Production would flow in dual 12 in. flow lines from there 27 miles to a Chevron-Texaco processing platformoperatedby Chevron on Viosca Knoll Block 900.
Eastern area
In the eastern producing area of the gulf, Chevron USA Production Co. began bringing on production of natural gas from the first fields in the U.S. gulf to produce from Lower Cretaceous pay.
First such production was from Viosca Knoll 68 No. 2 off Mississippi, which went on stream in April 1998 at a rate of about 15 MMcfd. Chevron planned to bring on other wells from five gas discoveries it had made since 1994 in a trend extending from Mobile Block 991 to Viosca Knoll Block 252. It estimated potential recoverable reserves at more than 600 bcf.
Pay in the discoveries is Lower Cretaceous James, productive in giant onshore Fairway oil and gas field 450 miles northwest of the Chevron play and in a few smaller fields in Texas, Arkansas, Mississippi, and Louisiana. Chevron`s wells in the offshore trend, drilled in about 120 ft of water, encountered the formation at about 15,000 ft.
Chevron called its play the Viosca Knoll Carbonate Trend. First production flowed into facilities designed to handle Miocene gas from about 3,000 ft. Chevron`s Norphlet gas trend lay to the north.
Chevron operated and held dominant working interests in about 75 leases covering more than 350,000 acres in the trend (Fig. 4). The company held 100% working interests in more than half the leases and majority interests in the others, mainly in partnership with Samedan Oil Corp.
Other discoveries
Among gulf discoveries reported in 1998, Vastar Resources Inc. found two new major oil-bearing zones on its King prospect on Mississippi Canyon Block 764. They joined two shallower oil-bearing zones found previously.
The King well, suspended at 17,580 ft MD in February, was reentered, sidetracked, and deepened to 20,796 ft MD. It cut 290 ft of total net pay for all zones. Drilling was suspended pending development plans. Interests were operator Vastar 50%, SDDI 33.33%, and BP Exploration & Oil Inc. 16.67%. SDDI was to become operator after well completion.
On East Cameron Block 157, Andadarko Petroleum A-7 discovered new reserves separated by a fault from the main field reservoir. On test, the well flowed 40 MMcfd of gas and 1,129 b/d of condensate with 2,235 psi flowing tubing pressure. Operator and 100% interest owner Anadarko said existing wells could not have recovered the reserves. Seven wells in the field were producing 70 MMcfd of gas and 1,700 b/d of condensate.
EEX Corp. found gas with the West Cameron Block 204 No. 1, which flowed on test at rates of as much as 30 MMcfd of gas and 86 b/d of condensate through a 40/64-in. choke at 3,415 psi. The well logged about 60 ft of net pay sand at about 10,000 ft. Operator EEX held a 60% interest in the well; Brazilian state firm Petrobras held 40%.
On its Llano prospect on Garden Banks Block 386, EEX cut 200 ft of hydrocarbon-bearing Pliocene and Miocene sands with a sidetracked exploration well for which it claimed a gulf record drilling depth: 27,864 ft. It planned an appraisal well. Partners were Enterprise Oil Gulf of Mexico Inc. 30% and PanCanadian Gulf of Mexico Inc. and Mobil Exploration & Producing U.S. 20% each.
Enron Oil & Gas Co. confirmed a discovery on Eugene Island Block 135 with a well designated A-3, which was drilled to 19,545 ft TD and encountered three gas zones below 18,300 ft. It completed the well in one of the intervals, which flowed 12.5 MMcfd of gas and 725 b/d of condensate through a 25/64-in. choke with flowing tubing pressure of 8,750 psi. Enron held 50%, Seagull Energy Exploration & Production Inc. 20%, and CXY Energy Offshore Inc. and Remington Oil & Gas Corp. 15% each.
Snyder Oil found gas and condensate in Main Pass Block 260 No. 1, drilled to 12,400 ft TD in 314 ft of water. The well found lower Miocene pay between two producing fields. It flowed 25.8 MMcfd of gas and 2,745 b/d of condensate through a 28/64-in choke with flowing pressure of 5,013 psi.
Gathering system
The first major grassroots gathering system along the Louisiana Gulf Coast in more than a decade started up in September 1998 when wet gas from the gulf began flowing through the $350 million Discovery gathering and processing system.
The project involved Discovery Producer Services LLC, an unregulated gathering, processing, and fractionation company, and a regulated, wholly owned subsidiary, Discovery Gas Transmission. Owners of Discovery Producer Services were Williams Cos. Inc. 50%, Texaco Exploration & Production 33.3%, and British Borneo Exploration 16.7%. Texaco subsidiary Bridgeline Gas Distribution LLC was operator.
The system received gas through a new 105 mile, 30 in. main line from the edge of the OCS at Ewing Bank 873 to a cryogenic gas processing plant near Larose, La., 35 miles south of New Orleans. The pipeline had ultimate capacity of 900 MMcfd of gas and a maximum water depth of 785 ft. An extension scheduled for 1999 was to take the pipeline to wells in 3,200 ft of water on Green Canyon Block 254.
The 600 MMcfd Larose plant separated condensate and processed the gas, with capacity to stabilize 7,500 b/d of condensate. Recovered NGL could be fractionated 20 miles north at Discovery`s 42,000 b/d Paradis, La., fractionator.
Another gas-handling project began limited operation in 1998: Destin pipeline and a related gas processing plant under construction at Pascagoula, Miss. The pipeline, operated by Southern Natural Gas Co., originates at a junction platform on Main Pass Block 260 in the gulf, comes ashore near Pascagoula, and connects with five interstate transmission lines (Fig. 5).
At Pascagoula, Amoco Corp. (operator) and Tejas Natural Gas Liquids LLC were building the gas processing plant with capacity to handle 1 bcfd of gas. The plant includes a slug-catcher system able to extract and stabilize as much as 5,000 b/d of condensate from the inlet stream. Downstream of the slug-catcher system, two cryogenic gas plants with inlet capacities of 500 MMcfd each were to be able to recover 24,000 b/d of NGL. The cryogenic plants were to start operations sequentially in 1999.
More projects like Discovery and Destin were likely in the gulf. An Ingaa Foundation study projected spending by the gas industry on gulf pipeline projects over 15 years at $7 billion. The Foster Associates Inc. analysis said 140 companies in 1998 operated 14,112 miles of pipelines in the gulf. Producers owned 45% of the facilities, interstate pipelines 48%, and pipeline affiliates 7%.
At the time of the study, 1,512 miles of new pipeline was planned at a cost estimated at $1.6 billion.
Accident
A fatal drilling accident marred gulf operations on July 17, 1998, when Nabors Industries Inc.`s Rig No. 269 collapsed during installation on an Ocean Energy Inc. platform 10 miles off Louisiana in federal waters.
An employee of Nabors and a contract welder from Cajun Cutters Inc. died at the scene. Attempts by the U.S. Coast Guard and other parties to find a missing employee failed. Twelve workers were evacuated to an area hospital.
The cause of the collapse was not immediately determined.
Lease sales
The offshore producing industry demonstrated its continuing interest in the gulf`s deep waters with its bidding patterns in 1998 Outer Continental Shelf lease sales.
In March, with oil and gas prices slumping and worries growing about availability of deepwater drilling equipment, operators submitted 75 high bids totaling $810,421,404 for 794 central-gulf blocks in OCS Sale 169. More than two thirds of the bids were for blocks in water 2,400 ft or more deep. In all, 87 operators submitted a total of 1,188 bids and exposed $1,349,676,391.
The top bid was $28,005,120 for Green Canyon Block 955 from Sun Operating LP and Statoil Exploration (U.S.) Inc.
In August, operators submitted 486 bids on 3,778 blocks in OCS Sale 171 of tracts in the western gulf. Bids totaled $741,855,047, high bids $553,435,908.
MMS said 91% of the bids were for tracts in 2,400 ft or more of water.
The highest bid came from Unocal Corp. and British Borneo Petroleum Inc. for Alaminos Canyon Block 974-$37,406,500. It was the fifth highest bid made for a Gulf of Mexico block since the start of areawide leasing in 1983. The highest bid was $92.4 million for a Central Gulf block in Sale 72.
Unocal submitted the highest number of winning bids in Sale 171 with 66. Other top five bidders were Texaco Exploration & Production Inc. 61, Vastar Resources Inc. 31, and Burlington Resources Offshore Inc. and Sonat Exploration GOM Inc. 30 each.
MMS planned to hold Sale 172 of Central Gulf of Mexico leases in March 1999, offering 3,758 blocks covering 20.13 million acres 3-200 miles off Louisiana, Mississippi, and Alabama.
The total included 863 blocks in 3-400 m of water offered for 5-year terms and 162/3% royalties; 105 blocks in 400-800 m of water for 8-year terms and 12% royalties; and 2,790 blocks in more than 800 m of water for 10-year terms and 12% royalties.
MMS estimated that the unleased tracts could contain 150-440 million bbl of economically recoverable oil and 1.53-4.39 tcf of gas.
Rental and royalty rates were the same as for 1998`s central gulf sale, but the minimum bid for tracts in more than 800 m of water was increased to $37.50/ acre from $25/acre. It remained $25/acre for shallower-water tracts.
MMS said that 60 blocks in 400-800 m of water, 105 in 400-800 m, and 2,790 in more than 800 m might qualify for royalty suspensions if marginally economic fields were found.
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The tower section of the Baldpate compliant tower weighs 20,200 tons and measures 90 ft by 90 ft.
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