ACTIVITY IN THE U.S. GULF OF Mexico ran into limits in 1997, while two record-setting lease sales showed that industry interest in the region remained intense. The limits were of drilling equipment, supplies, and crews capable of working in the ultradeep waters that had put the gulf back on the oil and gas industry`s menu of world-class exploration and development theaters.
Operators were using all available rigs capable of working in ultradeep water-greater than 2,700 ft-and waiting for delivery of mobile units being built or upgraded to handle ultradeepwater drilling. Many of the upgrades involved rigs that might otherwise have been working in 1,000-3,000 ft of water. Their withdrawal from service boosted rates for remaining units in that depth range. The kick to drilling costs hurt the already challenging economics of gulf subsalt prospects, many in water close to the 1,000 ft deepwater demarcation level.
With costs rising, activity in the gulf`s shallow waters tended to focus on development work.
Deepwater allure
As they had done the year before, deepwater projects dominated gulf activity in 1997.
In a November speech to the Tulane University Business Forum in New Orleans, Chevron U.S.A. Production Co. Pres. Peter J. Robertson explained the surge in interest in ultradeepwater exploration and development.
"In the early 1990s," he said, "we thought deepwater wells would produce, at best, 3,000 bbl of oil a day. But some of the early drilling showed production rates of more than 10,000 b/d.
"The reservoirs are bigger than we imagined and often are composed of loose sand," which makes production "relatively easy."
Advances in a number of technologies made the work possible, Robertson noted. He cited 3D seismic, directional drilling, measurement while drilling, bits able to cut drilling times in half, and use of magnetic resonance imaging to simultaneously assess porosity and pore content of rock layers.
The keen interest in deepwater gulf prospects cited by Robertson had become evident in production trends by 1997.
The U.S. Minerals Management Service estimated that in 1996, 9.4% of total gulf OCS hydrocarbon production came from water deeper than 1,000 ft, compared with 7% in 1995 and 5.5% in 1994. The deepwater share had increased from a recent low of 1.21% in 1989.
The deepwater share was greater for oil than for gas. Oil`s 1996 deepwater share of total gulf OCS production was 17.3%, up from 13.6% in 1995 and 10.2% in 1994. The gas deepwater share was 5.9% in 1996, 4.1% in 1995, and 3.69% in 1994.
The 1996 production totals were 365.9 million st-tk bbl of oil and 5 tcf of natural gas.
Largely because of the surge in deepwater activity, MMS in 1997 forecast Gulf of Mexico production in 2000 at 13-17 bcfd of gas, compared with 13 bcfd in 1995, and 1.9 million b/d of oil, compared with 945,000 b/d in 1995.
Deepwater landmarks, activity
Armed with technologies that were either less advanced or not available just a few years before, the industry established several deepwater landmarks in 1997.
Shell Deepwater Development set a world water depth record for production when it began producing natural gas in July from its Mensa platform in 5,376 ft of water on Mississippi Canyon Block 687. Mensa also set the world record for tieback distance to its host platform in West Delta Block 143-68 miles. Before Mensa, the world water depth production record was 3,370 ft, held by Petroleo Brasileiro SA for a subsea completion in Marlim field off Brazil.
Mensa`s production capacity is 300 MMcfd of gas.
The previous gulf production water depth record had been set just months earlier by the Ram-Powell tension-leg platform installed in May by a Shell Deepwater Production-Amoco-Exxon joint venture in 3,214 ft of water on Viosca Knoll Block 956. The TLP has capacity to produce 60,000 b/d of oil and 200 MMcfd of gas. Shell began production at the end of September at rates of 56 MMcfd of gas and 7,300 b/d of condensate and expected flow to reach capacity rates early in 1998.
Shell`s Auger platform in 2,864 ft of water on Garden Banks Block 426 held the gulf`s production rate record with averages of 90,000 b/d of oil and 185 MMcfd of gas. Auger production began in 1994.
A combine of Oryx Energy Co. and CNG Producing Co. started output in 1997 from the world`s first production spar-the Neptune unit installed during 1996 in 1,930 ft of water on Viosca Knoll Block 826. Production capacities are 25,000 b/d of oil and 30 MMcfd of gas.
The Neptune spar has a cylindrical hull 705 ft tall and 72 ft wide weighing 12,640 tons. Three-deck topsides weigh 3,600 tons.
Production from another spar, on Chevron`s Genesis field in 2,600 ft of water on Green Canyon Block 205, was to begin late in 1998. Capacities are 55,000 b/d of oil and 72 MMcfd of gas. Genesis represents Chevron`s first deepwater project anywhere in the world.
Another deepwater production start in 1997 was Troika field in 2,721 ft of water on Green Canyon Block 244. Operator BP Exploration and equal partners Marathon and Shell planned a total of five production wells completed subsea, flowing through a subsea manifold to separation and treatment facilities on Shell`s Bullwinkle platform 14 miles away. BP claimed a gulf record for distance of a multiphase flow line. Flow from the first Troika well started at 6,500 b/d of oil equivalent and was expected to rise to 30,000 b/d or more. Total Troika production was expected to peak at 80,000 b/d of oil and 140 MMcfd of gas in 1998.
Activity in 1998, 1999
For 1998, MMS anticipated start of flow through a floating production system from Allegheny field operated by Enserch Exploration in 3,186 ft of water on Green Canyon Block 254, with capacities of 70,000 b/d of oil and 70 MMcfd of gas.
A deepwater landmark due in 1998 was the world`s first installation of a SeaStar TLP-Morpeth-to handle wells completed subsea in 1,500-1,700 ft of water on Ewing Bank Blocks 921, 964, and 965 by British-Borneo Petroleum Syndicate plc. The SeaStar is a multi-use TLP that can be installed and operated at relatively low cost in fields that don`t justify larger, more elaborate systems.
Another deepwater TLP installed in 1997 but not due to start up until 1999 was the Ursa unit in 4,021 ft of water on Mississippi Canyon Block 854. Shell operates the Ursa group, which includes units of BP Exploration, Conoco, and Exxon. Production capacities are 150,000 b/d of oil and 400 MMcfd of gas.
MMS projected a 1999 production start for King`s Peak gas field operated by Amoco Production in 4,990-6,600 ft of water on Mississippi Canyon Blocks 217 and 173 in the central gulf and contiguous Desoto Canyon Blocks 133 and 177 in the eastern planning area. Amoco planned to use seven subsea wells producing to a central subsea manifold on Desoto Canyon Block 177. Twin 8 in. gas lines would carry gas from the manifold to Amoco`s King spar production facility in 5,149 ft of water on Mississippi Canyon Block 84.
MMS also projected a 1999 start of output from Texaco`s Petronius compliant tower in 1,753 ft of water on Viosca Knoll Block 786. The service reported production capacities at 60,000 b/d of oil and 100 MMcfd of gas. Texaco and partner Marathon Oil planned to install a 21-slot, 1,870 ft tower with 12 piles, three at each corner leg, extending from tower legs 450 ft through the mudline into the seabed.
Subsalt activity
Although rising costs for drilling and other services were squeezing the economics of subsalt prospects, the play continued to yield discoveries in 1997.
Amerada Hess and Oryx reported their Penn State Deep well, GB 216 No. 3 on Garden Banks Block 216, cut 123 ft of net pay in four zones at 20,500 ft in 1,450 ft of water. The zones, below a 1996 strike called Penn State Shallow, were not previously productive in the area.
Amerada and Oryx planned to develop Penn State Shallow with a subsea completion tied back to Amerada`s Baldpate compliant tower platform on Garden Banks Block 260, scheduled to start production in the third quarter of 1998.
Amerada earlier in 1997 disclosed a subsalt discovery at its Conger prospect on Garden Banks Block 215. The well, drilled to 21,652 ft in 1,500 ft of water, tapped 300 ft of net pay above and below salt. If commercial, the Conger strike could be developed, like Penn State, with a subsea completion tied back to the Baldpate platform.
Before Amerada and Oryx reported their Penn State Deep discovery, Oil & Gas Journal reported that through the middle of 1997 operators had drilled 29 subsalt wildcats in the preceding 3-1/2 years and made 11 discoveries.
The first subsalt strike to be brought on stream, Mahogany on Ship Shoal Blocks 349 and 359, was producing a total of 16,000 b/d and 22 MMcfd of gas from three wells in mid-1997 for operator Phillips Petroleum and partners Amoco Production and Anadarko Petroleum. Output ultimately was to reach 33,000 b/d of oil and 40 MMcfd of gas from six wells.
Progress on Mahogany`s production build ran about 2 months behind schedule because the 18.6° gravity crude was hotter than expected-176-180° F. rather than the 130-150° anticipated. Phillips had to modify a heat exchanger to cool the oil below the 170° maximum for shipping the crude ashore by pipeline.
Also completed in 1997 was the Enchilada platform on a subsalt discovery by Shell Offshore and partners Amerada Hess and Pennzoil on Garden Banks Block 128. Shell installed the platform early in the year in 718 ft of water. Production capacities are 60,000 b/d of oil and 400 MMcfd of gas.
Construction began later in the year on the Shell-Amerada Hess Salsa platform on Garden Banks Block 172, which in conjunction with the Enchilada facility will develop reserves on Garden Banks Blocks 83, 84, 127, 128, and 172. The Enchilada platform also serves as a throughput hub for oil and gas production from other gulf fields.
Phillips (operator) and Anadarko planned to bring their Agate subsalt discovery on Ship Shoal South Addition Block 361 on stream by mid-1998 with a well tied back to the Mahogany platform.
In addition, Texaco was considering development of its 1995 Gemini discovery in 3,390-4,150 ft of water on Mississippi Canyon Block 292, having declared it commercial in 1996.
Leasing and drilling
The surge in industry interest in deepwater gulf exploration became increasingly evident in leasing activity (Fig. 1).
Outer Continental Shelf Sale 166, held in March, attracted 1,790 bids for 1,032 tracts in the central planning area off Louisiana, Mississippi, and Alabama, the largest numbers in both categories in the history of OCS leasing. The Minerals Management Service rejected 28 bids for not meeting its estimate of fair market value and awarded the remainder to makers of high bids totaling $812 million.
The top 10 bidding companies in OCS Sale 166 and the number of tracts they received were Shell Offshore 113, Chevron U.S.A. 75, Unocal 72, Zilkha Energy Co. 67, Conoco 55, Texaco Exploration & Production 52, Vastar Resources 47, Louisiana Land & Exploration 44, Statoil Exploration (US) 40, and Exxon 38.
MMS Gulf of Mexico Regional Director Chris C. Oynes expressed surprise at the "large number of bids in 6,000-8,000 ft of water."
The central gulf sale drew bids on 412 tracts in water up to 200 m deep, 33 tracts in water 200-400 m deep, 52 tracts in water 400-800 m deep, and 535 tracts in water deeper than 800 m.
The sale also extended a trend of increasing involvement by independent producers in the Gulf of Mexico.
In August, OCS Sale 168 set records for the western gulf for bid total, 1,224, and tracts receiving bids, 804. MMS rejected bids on 26 tracts and awarded the rest to makers of high bids totaling $599,587,041.
Shell Deepwater led successful bidders with 102, followed by BP Exploration 79, Exxon 66, Chevron U.S.A. 64, Unocal 43, Texaco 18, Shell Offshore 14, Amoco Production 13, Conoco 13, and Sun Operating 12.
Oynes again said he was surprised by the number of bids on deepwater tracts, which in Sale 168 ranged to 10,000 ft.
Of the 804 tracts receiving bids, 603 are in more than 800 m of water.
MMS scheduled another offering of central gulf leases, OCS Sale 169, for March 1998. The sale was to include 4,244 blocks in waters as deep as 3,400 m. There were 3,428 tracts in the sale in water depths of 200 m or more.
Boundary dispute
The march of industry interest and operation into deeper and deeper waters pushed the governments of the U.S. and Mexico to complete action on a suspended territorial treaty in the gulf.
The executive branches of both countries had signed a maritime boundary treaty in 1978, but the U.S. Senate did not immediately ratify it. At the time, the treaty raised fears that the U.S. might unnecessarily surrender potential hydrocarbon resources.
As deepwater activity grew in the 1990s, however, the petroleum industry and the U.S. departments of State and Interior pressured the Senate to ratify the 1978 accord. The Senate did so in November 1997.
The treaty specified location of the maritime boundary between the two countries out to 200 miles from their shorelines. But it left to negotiations under the Law of the Sea Convention the handling of two central gulf areas, called "gaps," outside the 200 mile range of either country.
The eastern gap included Cuba and was unlikely to be settled because of the lack of relations between that country and the U.S.
Negotiations over the western gap were to begin in 1998. A needed determination that the area met the legal definition of "continental shelf" was not expected to raise dispute. Division of the gap was less certain. Use of a boundary equidistant from the coastlines of each country was a possibility but not stipulated by the Law of the Sea Convention.
The U.S. had offered leases in the northern part of the western gap in several OCS sales, including Sale 168 in August 1997. In that sale, MMS said it would hold bids for leases in the western gap unopened until Interior Sec. Bruce Babbitt could decide how to proceed.
After ratification of the 1978 treaty and commitment by the governments to begin negotiations over the western gap, Babbitt returned the Sale 168 bids to the companies that made them and withdrew tracts in the western gap from Sale 169 scheduled for March 1998.
Rig limits
Deepwater drilling, while active, was unlikely to rise much in 1998. The MMS reported that in October there were a record high 31 temporary and permanent deepwater rigs drilling in Gulf of Mexico waters deeper than 1,000 ft.
But the interest was most keen in the ultradeep water, and rigs capable of drilling in 3,000 ft or more were all busy. Some relief for ultradeepwater activity was appearing from upgrades.
Removing a deepwater rig from the fleet for 4-12 months to increase its water-depth capacity, however, didn`t ultimately increase fleet size. Upgrades also tightened the market for drilling services in 600-2,000 ft water depths and thus dampened activity in the flex trend and subsalt play.
A number of rigs with ultradeepwater capability were under construction in 1997. But many of them were 2 years from delivery and thus promised no near-term relief.
According to a tally by Offshore Data Services, there were seven semisubmersible rigs on order as of Jan. 21, 1997, with water depth capabilities exceeding 7,000 ft. And there were 14 drillships with that water-depth capacity on order.
One of those drillships entered service early in 1998: the U.S. Navy`s Glomar Explorer, for which Global Marine Inc. held a 30 year lease. A $178 million refurbishment enabled the vessel to drill in 7,500 ft of water. With modification, the ship`s water depth capability could be extended to 10,000 ft.
The other ultradeepwater drillships and semis on order were not due delivery before the last months of 1998.
In response to the shortage of rigs capable of ultradeepwater work, some operators with large deepwater and ultradeepwater lease positions were drilling and suspending wells before reaching ultimate target depths, then moving the rigs and spudding other wells on other leases, getting as many holes started and suspended as possible during the contract periods of their rigs.
Starting a maximum number of wells during a contract period enabled operators to hold deepwater leases, and measurement-while-drilling techniques enabled them to collect large amounts of well data without interrupting drilling. After rigs had moved off-hole, they could shoot vertical seismic profiles to assess strata below the depth at which holes were suspended. They later could reenter and continue drilling the wells that appeared most interesting on the basis of the data.
At least one operator used a position in the tight rig market as a bargaining lever.
Elf Exploration Inc., U.S. unit of Elf Aquitaine of Paris, commissioned Global Marine Inc. to convert a North Sea accommodation vessel, formerly called Polycastle, to a semisubmersible drilling rig able to work in 5,000 ft of water. The semi, renamed Glomar Celtic Sea, entered service early in 1998. Elf had a 3 year, $145,000/day commitment for the rig, which was capable of both anchoring and dynamic positioning.
Early in 1997, Elf worked a one-well swap with Shell under which Shell secured rights to use the Celtic Sea when it became available in return for immediate access to Diamond Offshore`s Ocean Saratoga semi. Elf used the Ocean Saratoga to drill a discovery on its Virgo prospect in 1,132 ft of water on Viosca Knoll Block 823, which it held under a lease near expiration. The 2 Viosca Knoll 823 well cut 376 ft of net hydrocarbon-bearing sands. On an extended drill stem test of one lower zone, the well flowed 22.7 MMcfd of gas and 1,816 b/d of oil through a 38/64 in. choke with 3,826 psi flowing tubing pressure.
Mobile Bay activity
A key development outside the ultradeepwater and subsalt plays was a gas production zoom from Mobile Bay that began in 1996 and was expected to extend into 1998.
New production from Jurassic Norphlet zones below 20,000 ft was expected to increase average production from state and federal leases off Alabama to 1.214 bcfd in 1997 from 864 MMcfd in 1996.
In July, Mobil Exploration & Producing U.S. started flow from Aloe Bay field at 22 MMcfd, raising it to 40 MMcfd by September. In 1998, Exxon Co. U.S.A. planned to start production from its Mobile Block 867. And Chevron USA Production and partners and another operator had filed development and production plans for Destin Dome off Florida in the eastern planning area.
If Chevron won approval and successfully started up Destin Dome production, the Mobile Bay-Norphlet trend was expected to be able to produce 1.4 bcfd through 2005.
Discovered reserves attributed to state and federal leases totaled an estimated 10.5 tcf in 1997, with remaining recoverable reserves of 3-4.4 tcf in Alabama state leases and 1.4-2.1 tcf in federal leases, according to a report by Foster Associates Inc., San Francisco, based on data from the MMS and Alabama Oil & Gas Board. Destin Dome could have 1 tcf or more of reserves.
The overall production increase off Alabama and Mississippi resulted from Norphlet start-ups on federal leases. Until 1996, production from Miocene pays had accounted for about half of federal production off Alabama.
Much of the production gains in 1997 came from fields started up previously in the eastern Mobile Bay OCS area. The region includes blocks operated by Chevron (872 field) and a group involving Unocal, Chevron, and Fremont Energy (the 6-1/4 block 916 unit).
Much 1997 drilling, however, was in the western part of the region off Mississippi where Chevron and Unocal were developing discoveries. Production from western area fields was expected to reach 200 MMcfd by early 1998 and increase after 1998 from wells that hadn`t been completed or spudded by yearend 1997.
Tables 1-3, from the Foster Associates report, summarize activity in the region.
Destin Dome plans
Operators proposed two separate development programs on the Destin Dome off Florida and Alabama.
In August 1997, MMS announced the formal beginning of its review of Chevron`s Destin Dome development production plan, which the company had submitted the previous November. MMS said its review might take 2 years.
Chevron also needed to secure air and water quality permits from federal and state agencies. And approval of the MMS permit depended on an agreement by the government of Florida that the plan was consistent with the state`s coastal zone management plan. Florida has historically resisted offshore oil and gas operations.
Chevron and partners Murphy Exploration & Production Co. and Conoco, each with one-third interest, expected to drill as many as 12 wells on the 11-block Destin Dome unit and produce as much as 300 MMcfd of natural gas. The maximum operations they envisioned in their plan was drilling of 21 wells and production of 450 MMcfd of gas.
Production would come from Norphlet pay encountered at 21,500-25,000 ft subsea. Water depths in the unit range from 100 ft to 500 ft. The unit, designated Destin Dome 56, encompasses Destin Dome Blocks 12-16, 54-57, 99, and 100.
Chevron drilled two natural gas discoveries on Block 56 in 1987 and one on Block 57 in November 1995. The Destin Dome Block 57 No. 1 well flowed at rates as high as 41 MMcfd of gas and would be used as a production well under Chevron`s development plan.
Chevron proposed to start production in March 1999. Flow lines would carry gas from wells to a central processing facility on Block 12, from which a 30 in. export line would carry it to Unocal`s platform on Mobile Block 916.
Connecting pipelines would be laid as needed from there to Shell`s Block 113 platform, Mobil`s Block 823 platform, Exxon`s Block 112 platform, or Chevron`s Block 864 platform to link with existing pipelines to shore.
In the maximum production case, Chevron expected to install 10 single well satellite platforms, four two-well satellite platforms, two eight-pile central processing facility platforms on Block 12, one three-well satellite platform, and one bunkhouse platform.
In September 1997, MMS approved development operations coordination documents submitted by OEDC Exploration & Production LP for Destin Dome Blocks 1 and 2 and Pensacola Block 881. OEDC received the blocks in a transfer from Gulfstar, which made shallow Miocene gas discoveries on them in 1989.
Platform removal
As the world`s most mature offshore producing region, the Gulf of Mexico had by 1997 established a lengthy and varied record of removal of platforms and other structures that had reached the ends of their useful lives. Disposal of gulf equipment, including ocean disposal, did not raise environmental controversy as strong as that which prevented Royal Dutch/Shell from completing plans to scuttle the North Sea Brent spar platform in deep waters of the Atlantic. Part of the explanation for the relative lack of environmental opposition is that gulf production platforms, unlike the Brent unit, do not store oil.
Since removal of the first gulf facility in 1973, a total of 1,503 structures had been removed from the gulf OCS through midyear 1997. A total of 5,375 structures had been installed in federal waters. State waters had 900-1,000 structures.
The average decommissioning rate in the several years preceding 1997 had been about 100 structures/year.
An estimated two thirds of all platform decommissionings on the OCS involve the use of explosives. Regulations require that most structures be severed 15 ft below the mudline.
The effect of explosives on fish populations was the subject of a study by the National Marine Fisheries Service.
Severed fixed platforms were usually taken ashore for refurbishment or scrapping. But sea disposal in "rigs to reefs" programs was increasing.
Because total removal of offshore platforms is considered detrimental to Gulf Coast fishing, the Louisiana Department of Wildlife and Fisheries and the Texas Parks and Wildlife Department support and administer such programs for waters off their states.
Through November 1997, 39 structures had been converted to reefs off Texas since the first one in 1990. Since the Louisiana program began in 1986, 64 structures had been disposed of as reefs at nine sites.
Partial removal, involving cutting off the top of a structure at about 90 ft below sea level, had been used for several platforms off both states and was the likely method of decomissioning deepwater structures. In some cases, severed tops are towed ashore for refurbishment; in others, tops are set on the seabed.
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Production was rising in 1997 from the Mahogany platform, the first Gulf of Mexico development based on a discovery below salt. Photo courtesy of Anadarko Petroleum Corp.
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The Diamond Offshore Ocean Saratoga semi drilled the Virgo discovery for Elf Exploration Inc. early in 1997. Photo courtesy of Elf Exploration.
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