Deepwater development and offshore oil spills claimed the spotlight at the Offshore Technology Conference in Houston last week.
Rounding up OTC action:
- Companies involved in deepwater projects in the Gulf of Mexico and off Brazil updated their progress.
- One panel discussed prospects for ultradeepwater development in the Gulf of Mexico.
- The North Sea exploration and development boom shows no sign of subsiding, said energy officials from the U.K. and Norway.
- Another panel focused on how energy policy affects offshore activity by contrasting a drilling surge in the North Sea with a drilling slump in the Gulf of Mexico.
- C. Russel Luigs, chairman of Global Marine Inc., said about 130 idle offshore rigs worldwide--although "junkers"--remain a drag on contractor rates.
- Exxon U.S.A. reported status of the third year of cleanup efforts related to the March 1989 Exxon Valdez spill in Prince William Sound off Alaska.
- U.S. Coast Guard and Texas Land Office officials reviewed effects of other recent offshore oil spills on state and federal spill response legislation.
AUGER DETAILS
Carl Wickizer, manager of Shell Offshore Inc., outlined progress of developing Auger field in the ultradeepwater Gulf of Mexico with a tension leg platform (TLP).
Shell will install the Auger TLP in 2,860 ft of water on Garden Banks Block 426 in the Gulf of Mexico. Project cost is $1.3 billion.
Part of that project entails installation of a new deepwater design riser tension system. The tensioner is still undergoing testing.
Auger TLP will be attached to the seafloor by 12 tubular tendons, each 26 in. diameter and 1.3 in. wall thickness. A derrick barge will lower and connect 240 ft sections to erect the 2,760 ft tendons.
The tendon system is designed with redundancy so loss of any corner tendon will not cause undue stress on the mooring system. Shell believes external inspection of the tendons will be sufficient but continues to study internal inspection methods.
Because development drilling will span 10 years, Shell will mount a permanent rig on Auger, calling for simultaneous drilling and producing operations. Shell will drill with a subsea blowout preventer stack and use a 26 in. riser for shallow holes and a 21 in. riser for deep holes.
The production pipeline will use a catenary riser and a J-lay system Shell developed specifically for Auger, because the project is in water depths exceeding capacity of conventional S-lay pipelines.
DEEPWATER BRAZIL
Petroleos Brasileiro SA's (Petrobras) innovative deepwater development in the Campos basin's supergiant Marlim field continues to set records.
Its second subsea well in the Marlim prepilot, involving a guidelineless Christmas tree, is being completed in 752 m (2,466 ft) of water. The previous water depth production record of 721 m was set by the first well in the prepilot (OGJ, Mar. 11, p. 38).
Alfeu de Melo Valenca, appointed president of Petrobras Apr. 2, said Petrobras is now in better financial shape and is again able to invest in development of its supergiant fields in the deepwater Campos basin.
About 70% of identified Brazilian oil reserves lie in deep water.
Valenca is optimistic about his company securing the funds needed to meet the state company's goal of producing 1 million b/d of oil in the mid-1990s. Petrobras' 1991 budget is $2.4 billion.
Valenca said improvement in the Petrobras financial situation stems from government moves to cut Petrobras subsidies for domestic refined products and lower investment and operating costs resulting from simpler development concepts--thus reducing time for implementing offshore projects, especially in deepwater. He estimates Campos deepwater development costs at $8-10/bbl.
Joao Carlos Franca de Luca, Petrobras exploration and production director, said a number of technologies are being considered to cut deepwater development costs. These include wet and dry atmospheric manifolds, hybrid floating production systems, TLPs, and multiphase pumps.
ULTRADEEPWATER
Panelists from Exxon, Shell, Ocean Drilling and Exploration Co., Reading & Bates Drilling Co., and Sonat Offshore Drilling concurred that, while technology exists to build drilling rigs for ultradeepwater, construction is not yet cost effective.
Shell holds the world deepwater drilling record with 7,520 ft on Mississippi Canyon Block 657.
Presently, no rigs are capable of drilling in water much deeper than 7,500 ft. As of 1985, only eight wells have been drilled in water deeper than 5,000 ft.
John Baker, senior staff engineer for Exxon Co. U.S.A., said presently 21 operators hold 670 leases in water deeper than 4,500 ft. The leases cost more than $350 million, but only 12 wells have been drilled on the acreage.
Don Ray, vice-president of engineering for Sonat Offshore Drilling, said 18 operators in the Gulf of Mexico hold 120 leases in water deeper than 7,500 ft and five operators hold 10 leases in water deeper than 10,000 ft, the deepest of which is 10,650 ft.
The primary term for these leases is 10 years. Ten percent of the leases will expire in 1996 and 70% will expire in 1997-99.
Ray believes the real challenge for ultradeepwater projects is economics.
The estimated cost to upgrade an existing rig for deepwater is $80-100 million and to construct a new deepwater rig $250 million, he said.
High new rig construction costs would require very high day rates. The earliest delivery of an ultradeepwater rig would be in the late 1990s.
Without extra equipment or modifications, Ray said, 17 units in the Gulf of Mexico's deepwater fleet can drill in 3,000 ft of water, eight in 4,000 ft, six in 5,000 ft, two in 6,000 ft, and one in 7,500 ft.
Odeco's Mark Childers said building a unit to drill in ultradeepwater would cost about $200 million and take 4-6 years to build, provided a suitable shipyard was available. However, converting an existing semisubmersible for ultradeepwater service would cost $100-120 million and take a couple of years to complete.
Among technical problems with the huge ultradeepwater drilling units are the need for very large deck loads, large mud systems, riser storage space, and motion compensators.
Another problem with development of ultradeepwater acreage is lack of production systems for these depths.
A complete production platform for 2,700 ft of water would cost about $295 million installed, panel members concluded. A platform for 10,000 ft of water would cost $360 million. The cost difference is primarily in the mooring systems. Either platform would take about 4 years to build.
NORTH SEA ACTION
John Wakeham, U.K. secretary of state for energy, cited last year's record 224 exploratory and appraisal wells drilled and 25 significant discoveries in the U.K. North Sea.
He estimated the value of 18 new development projects approved in 1990 at a record--4.8 billion ($8.2 billion).
Wakeham also announced approval of two major North Sea development projects (see story, p. 38).
Wakeham said the value of new orders placed for goods and services for the U.K. continental shelf last year had its biggest annual increase--up 60% from 1989's level to 6.2 billion ($10 billion).
In the current U.K. licensing round, 67% of the 120 blocks on offer received applications, the biggest percentage in more than a decade.
In the current frontier round, the U.K.'s first, the government received 13 applications covering 66 blocks from groups involving 37 companies.
"That undoubtedly represents an exceptionally promising start towards encouraging the development of the unexplored, largely deepwater areas, to the north and west of the Shetland islands," he said.
SNORRE DEVELOPMENT
Lars Bjerke, senior vice-president of Saga Petroleum AS, Oslo, reviewed development of Snorre field in Norwegian waters--one of the world's major offshore projects--and described how a much smaller field could be developed.
Bjerke said Snorre field will produce 190,000 b/d of oil from 40-48 wells from a tension leg platform in 350 m of water.
Reserves are 770 million bbl of oil and 247 bcf of gas. Development costs will be $6/bbl. Production will begin in fall 1992.
By contrast, Tordis field, which Saga also is developing, has 110 million bbl of reserves that will be produced from a subsea facility through the northern Gullfaks platform. Development costs will run $4/bbl, Bjerke said. Production will start in 1994.
The Gullfaks connection was a key to this development, Bjerke said, noting such arrangements will become more common because existing production facilities, pipelines, and other production systems are more accessible in the North Sea.
However, he noted, such linkups aren't free, and new field developers wanting to tie into existing facilities with other operators must have alternative production options, such as floating storage, to use as negotiating tools.
Operating costs for Snorre are expected to run $150 million/year, about $2.15/bbl of oil produced.
ENERGY POLICY EFFECTS
Matthew R. Simmons, president of Simmons & Co. International, pointed to the contrast in activity level between the North Sea and Gulf of Mexico, saying, "The Gulf of Mexico risks becoming a dumping ground for all the old drilling equipment in the world, while areas such as the North Sea corner all the new equipment and state of the art technology."
In past gulf slumps, Simmons said, most of the idle rigs remained stacked in Sabine Pass.
"Today, if the rigs are any good, they are literally saying adieu' to this marketplace."
Simmons blamed the gulf's doldrums on several abnormally warm winters in the U.S. and lack of an energy policy to stabilize markets for offshore exploration and development. He praised the U.K. and Norway for doing what the U.S. has not: providing constant and reliable access to exploration acreage and enacting tax policies that shield operators from the effects of wide oil price swings.
And he predicted a "golden era" of North Sea technical advances.
Conventional platforms will continue to dominate field development in the region, increasing in number by about 50% to more than 60 by 2001. But the number of floating production systems will double to 12 during the period, and the number of subsea projects will jump to 41 from 12.
"When new forms of field development are coupled with horizontal and other performance drilling techniques and other technical advances that have driven down the cost per barrel of offshore oil and gas development, advanced the water depth of commercial offshore exploitation, and enabled smaller fields to be commercially viable, the offshore has indeed become a truly technical area with the North Sea leading the way," Simmons said.
LOW RATE LEVER
Glomar's Luigs contends operators use idle offshore rigs as a lever to get low rates on good equipment.
As a result of this and a falloff in natural gas drilling, he said, many good Gulf of Mexico rigs are now going to the North Sea, where rig utilization is running about 92%.
In the past 24 months, panel members pointed out, 15 rigs with an average age of 7.9 years entered the North Sea, while seven rigs with an average age of 12.9 years departed. In the same period, the Gulf of Mexico lost 35 rigs and gained five with an average age of 13 years. Two rigs recently entering the gulf are more than 16 years old.
Luigs said the drilling industry has lost money the past 7 years. With contractors not meeting costs during this period, he said, "There has been a transfer of capital from drilling contractors to operators."
Although Glomar still conducts engineering on advanced rig designs, Luigs said his company would not begin construction on a new rig unless it had a 5 year contract that would return 15% on investment.
A company would be "loony" to build a rig on speculation or on the basis of a short term project, he said. He pointed out that a new, first class offshore rig would cost about $150 million.
EXXON CLEANUP
Cleanup of Prince William Sound, soiled in the 258,000 bbl Exxon Valdez spill, is nearly complete, Otto Harrison, Exxon Co. U.S.A.'s manager of Alaskan operations, reported.
On Apr. 26, the company began shoreline surveys of 577 locations with six survey teams of Exxon personnel, scientists, state and federal officials, and cleanup workers. Exxon will spend about $22 million on the surveys.
Harrison said Exxon teams have finished surveying about 200 sites in Prince William Sound. They have found little surface oil and minor amounts of subsurface oil, which the National Oceanic and Atmospheric Administration (NOAA) has determined is nontoxic.
"We hope to wrap all of that up this summer," he said.
In the same situation, Harrison said that Exxon again would use hot water to clean the shoreline. Critics have charged the treatments, involving water heated to 140 F., did more environmental harm than good.
Harrison said the main objective of Exxon and the 14 state and federal agencies with which it dealt in responding to the crisis decided unanimously soon after the spill to reduce the threat of gross contamination to birds and animals. That meant hot water cleaning.
The number of decision-makers involved in the spill response made decision making difficult, he said.
Harrison suggested that a contingency plan should be set in place for future spills, but estimated it will take 3-4 years to develop and implement one.
"We had to go get permits for everything," he noted, including a permit to burn logs.
BIOREMEDIATION POTENTIAL
Harrison called bioremediation the biggest technical advance resulting from the cleanup and called on industry and government to set in place the infrastructure necessary to respond to major spills.
Controlled burning has some potential for handling crude spills, although it is an option only during the first 4872 hr after a spill, before light ends vaporize, he said.
NOAA is studying seven setaside beaches that were contaminated and left uncleaned to provide a basis for comparison with areas that were cleaned.
Natural forces, especially winter storms, have helped the cleanup. Last winter there were fewer storms than normal, but the storms that did occur came during high tide and were therefore most efficient, Harrison reported.
Storms that came soon after the spill emulsified sortie of the oil but didn't break it down into microdroplets. No significant amount of oil entered the water column, so there was no fish kill.
Claims of lasting damage to Prince William Sound are based on minute changes in material concentrations, Harrison said. Effects of oil can be found, he acknowledged, "but you have to look for them."
Harrison said bald eagles returned to Prince William Sound during the past nesting season. Recent salmon and herring catches have broken or approached records.
"It looks to us like restoration is almost complete," he said.
SPILL CLEANUP DEVELOPMENTS
Texas Land Commissioner Garry Mauro said state officials had gained valuable experience last year dealing with spills in the Gulf of Mexico and Galveston Bay.
The Mega Borg tanker in June 1990 discharged about 69,000 bbl of Angolan crude into the Gulf of Mexico. In July 1990, a barge operated by Apex Towing Co. leaked 12,500 bbl of catalytic cracking feedstock into Galveston Bay after colliding with the Shinoussa tanker.
As a result of those accidents, state officials have written protocols for testing such experimental spill treatments as bioremediation. Mauro also said state officials were modeling contingencies in advance to trim response times in spills.
MEGA BORG AFTERMATH
U.S. Coast Guard Rear Admiral James M. Loy outlined the federal Oil Pollution Act of 1990 (OPA) passed by Congress in the aftermath of the Exxon Valdez and Mega Borg oil spills.
Loy said OPA requirements involve more than 50 major regulatory activities in three primary categories: prevention, preparedness, and response. Additional infrastructure and strength associated with OPA funding give the Coast Guard considerably greater capability to deal with spills, he said,
The Coast Guard's Loy said responses to the Mega Borg and Apex barge accidents had satisfied many critics of the country's ability to deal with major oil spills. Most of the oil spilled by the Mega Borg was consumed in the inferno that followed the explosion aboard the tanker, with little oil reaching the Texas coast.
"That (coastal contamination) didn't occur, largely as a result of the well coordinated response by the state and Galveston County officials," he said. "Looking back, I think there are far fewer who would challenge the role of the onscene coordinator and what he was able to accomplish in the Gulf Coast spills."
If Apex Towing's barge had spilled oil in the gulf instead of Galveston Bay, Loy contends, the national response system would have coped with that spill as effectively as it dealt with Mega Borg.
Loy praised state officials in Texas and Louisiana for passing "very thoughtful packages of spill legislation."
"Both have established funds that provide flexibility for the states to continue cleanup efforts," he said. "If the federal onscene coordinator is prosecuting a spill and in his estimation has cleaned it up, the states now have the wherewithal to go further."
With respect to double bottom hulls, Loy said analyses in the wake of Exxon Valdez suggested that about 60% of the oil would have spilled in any event. Effectiveness of double hulls depends largely on the type of accident in which crude carriers have been involved, he said.
TEXAS SPILL RESPONSE
Mauro said passage by the Texas Legislature in March 1991 of the Oil Spill Prevention & Response Act of 1991 (Ospra) provides a framework within which state officials could respond effectively to large oil spills.
"For 18 months, we will fill in that framework, and in 3 years we will have one of the best state plans in the nation for dealing with catastrophic oil spills," he said. "Between now and then, we will have a good deal of exposure--less exposure than we had 6 months ago, but we're not ready to deal with an oil spill like you and I want to be ready for in the future."
Ospra requires the state to establish regional ready response sites, equipped and manned fulltime, along the Texas coast.
"The good news is that with federal law and state law that we are in the process of filling out, we're going to replace that equipment," he said. "But in the short run, we're not in very good shape."
Mauro said last year's spills off the Texas coast also changed the way industry and the public thinks of spills.
"The public now understands that it's not a question of whether an oil spill might occur, but when, where, and how much," he said.
"I will guarantee you somewhere on the Texas Gulf Coast today, there's an oil spill right now, even as we speak," Mauro said. "Most of them are very minor and are contained very quickly.
"But we don't know when the next one's going to be big and cause us serious problems."
Copyright 1991 Oil & Gas Journal. All Rights Reserved.