OTC PRESENTATIONS HIGHLIGHT SPREAD OF SUBSEA TECHNOLOGY

FPSO FABRICATION

Worldwide, installed FPSOs numbered 27 at the beginning of 1995 with another 11 under construction, said a paper written by D. Henery and R.B. Inglis of Shell Internationale Petroleum Mij. BY An FPSO under construction for Barracuda field off Brazil will have the world's largest turret capacity of 34 risers and establish a record water depth by being moored in 2,756 ft of water, PR.B. Carneiro of Brazil's Petrobras reported.

Besides FPSOS, floating production systems in operation, counted by Henery and Inglis, included 21 semisubmersible and four tension leg platforms (TLPs), with another six semisubmersibles and three TLPs under construction.

FPSOs can be deployed in water depths ranging from 98 ft to more than 3,280 ft in practically all environments. Shell sees economic potential for the systems in frontier areas such as West Africa and in shallower water, limited reservoirs, near existing infrastructure.

Turret mooring is favored for FPSOS. Six main types of turrets are being built: three for permanently moored vessels and three for vessels that can be disconnected for bad weather or repairs.

Estimates by Henery and Inglis showed FPSOs can cost from $50 million for a tanker conversion to $700 million for a newbuild, depending on their sophistication. Most FPSOs installed during the 1980s were converted tankers, but newbuilds now represent 40% of the global FPSO fleet.

N.J. Smith, Smith Rea Energy Associates Ltd., said the trend is toward newbuilds. That's because safety rules can easily cause cost overruns from many unknowns involved in converting older vessels. Another trend is toward leased vessels with shared production risks between the vessel owner and producer.

Smith estimated oil production costs for an FPSO range from $4 to $14/bbl with a $6.50/bbl average.

FLOATER TECHNOLOGY

Thomas M. Ehret, chief operating officer of Coflexip Stena Offshore (CSO), said explosive growth around the world in the past couple of years in the use of FPSOs shows that subsea technology has come of age.

In the U.K. North Sea, for example, more calls were issued for FPSO tenders in the past year than in the previous 10 years, he said.

"Basically, the off shore oil and gas industry is going subsea because it has to," Ehret said.

Because subsea technology is not as sensitive to wellhead prices as most other upstream technologies, Ehret said uses of subsea technology are expected to continue accelerating through the end of the century, "whatever the shape of the FPSO, whatever the water depth."

CSO said pending, probable, and possible subsea completions world wide in 1998 could total nearly 250, after reaching a high of about 275 in 1997. World subsea completions in 1993 totaled 84, a 100% increase from 1992. However, a decision to proceed with or scrap only one large subsea project could significantly change the yearly total.

PLATFORMS ABANDONMENTS

The pace of platform abandonments in the Gulf of Mexico is expected to increase rapidly as more fields mature and wells reach their economic limit.

U.S. Minerals Management Service data show there are more than 3,800 structures in the Gulf of Mexico and more than 5,500 structures, including two-pile platforms, in state waters. Structures in the gulf have been in operation an average 15 years, with one-third more than 20 years old.

Federal regulations require the structures to be removed and the sites restored once production ceases.

The outlook for abandonments in the gulf spurred Halliburton Energy Services-and Global Industries Ltd. to announce at OTC that they had formed an alliance to offer a total package of abandonment services to gulf operators.

The alliance, Total Abandonment Services (TAS), New Orleans, will provide services in all facets of the abandonment process, including engineering, project management, well bore plugging and abandonment, structure removal, and site remediation.

In 1992 and 1993, the number of structures removed in the gulf exceeded the number added in the region, said Tom Slocum, TAS program manager.

In addition to handling abandonment projects on a turnkey, day rate, or individual service basis, the new company will help operators secure additional financing or bonding to help cover the cost of abandoning wells or fields.

PROMISE OF DEEP WATER

Support emerged at OTC from the oil industry and U.S. Bureau of Land Management for a bill recently proposed in Congress to provide royalty relief for deepwater production.

Dennis Heagney, vice-chairman of the International Association of Drilling Contractors and president and chief operating officer of Sonat Offshore Drilling Inc., said SB 158, dubbed the Outer Continental Shelf Deep Water Royalty Relief Act, would enable the secretary of Interior to waive royalties for new production in more than 200 m of water if the production otherwise would be uneconomical.

Waived royalties could not exceed the amount the secretary deemed necessary to make the project economical, and royalties would be due on all subsequent production.

Bob Armstrong, assistant Interior secretary for land and minerals management, said the Bureau of Land Management also supports the bill because more economic encouragement is needed if operators are to explore about 3,000 undrilled, leased tracts, including many in the gulf's deepwater frontier.

Heagney said deepwater royalty relief would not cost the U.S. Treasury any money but would create jobs and speed development of advanced equipment and technology.

"Royalty relief for frontier exploration is no giveaway. It is an investment in jobs today, technology for tomorrow, and energy security for the future," Heagney told an OTC press conference.

The promising outlook for the gulf's deepwater areas prompted Rowan Cos. Inc. to announce plans at OTC to design and build the world's largest bottom-supported mobile offshore drilling rig. The new rig, to be named Gorilla Y, is to be capable of operating in the North Sea in water depths to 400 ft.

LeTourneau will build the Gorilla V in Vicksburg, Miss., at an estimated cost of $135 million. Delivery is expected in second quarter 1998.

U.K. COST REDUCTION

Representatives of the U.K.'s Cost Reduction Initiative for the New Era (Crine) reported at OTC early results of the program's effort to enable development of North Sea marginal fields.

Mike Curtis, Crine chairman and engineering director of BP Exploration, said the productive lives of some U.K. North Sea oil and gas fields have been advanced by 25 years because of the initiative, ensuring jobs for the area.

Crine's 3-year target is to reduce capital costs by 30% and operating costs:by 50% from a 1993 basis.

U.K. Energy Minister Tim Eggar praised the savings being achieved through Crine but asserted that the initiative might be of more significance because of the new spirit of cooperation it is revealing in the industry

Eggar noted oil production in the U.K. North Sea in 1994 reached a new high. Similarly, gas wells in the region logged the fifth straight yearly production increase, boosting output to a level 60% greater than in 1989 and posting the largest yearly production total since 1986.

Regarding other indicators of offshore activity in the U.K., Eggar reported that development drilling in the U.K. North Sea in 1994 reached a record with 199 wells spudded. While exploration-appraisal well starts in 1994 in the region were off by 11% from 1993, 20% more exploratory wells were spudded last year than in 1993.

On other topics, Eggar said:

• The U.K.'s announcement last year of the 15th, 16th, and 17th offshore licensing rounds signaled a new approach on the U.K. Continental Shelf. Offering acreage in different offshore areas in each licensing round better reflected the status of exploration and development in the region.

• A bill proposing to deregulate Britain's gas markets has been introduced in the House of Commons that in effect will mean 18.5 million gas consumers in the U.K. will be able to purchase gas from any of several score of suppliers. While using U.S. gas market deregulation as a model, Britain intends to learn from the U.S. experience and avoid some mistakes that created an unacceptable level of disorganization during the process.

PLAN FOR FOINAVEN

BP Exploration & Production Ltd. revealed several elements in its plan to develop Foinaven field, in the Atlantic Ocean about 190 km northwest of the Shetland Islands, where production is to start in first quarter 1996.

BP expects field flow to reach 150,000 b/d by 1997 and about 300,000 b/d by 2000.

BP said the reservoir presents some challenges to field development. The reservoir is shallow at 1,700-1,800 m below the seabed and is thin with a large areal extent. Pay zones are expected to be 10-50 m thick.

BP said Foinaven crude is to be transported by shuttle tanker to the Flotta oil terminal at Orkney, Scotland.

The Petrojarl IV FPSO vessel, to be complete by September, will handle Foinaven crude.

The field is to be developed with wells drilled from two sites, one in the southwest and one in the north. Horizontal, multilateral, and extended reach wells will tap the reservoir.

Two wells will be drilled by this summer, two more by fall, and another by yearend. The wells will be completed with long, complex sand screens and will be gas lifted when necessary.

NORWAY'S OUTLOOK

Norwegian Energy Minister Jens Stoltenberg presented- an optimistic outlook for oil and gas on the Norwegian Continental Shelf (NCS).

Despite challenges to offshore oil and gas exploration and development stemming from unexpectedly low wellhead prices, Stoltenberg cited several reasons for the strong NCS outlook. Among them:

• Oil production in 1995 is expected to average 2.7 million b/d, boosting Norway from its position as the world's third largest oil exporting country to the second largest. Further production increases in 1996 are expected to sustain NCS oil flow at about 3 million b/d to 2000.

• Based on signed supply contracts, NCS gas flow by 2005 is expected to amount to about 62 billion cu m, up from 25 billion cu m in 1994.

• NCS operators have learned to deal better with the region's geological uncertainties and aim to continue trimming costs to allow profitable operations despite low oil and gas prices.

• Norway recently jumped estimates of its oil and gas reserves to about 70 billion bbl of oil equivalent, only 15% of which has been produced.

"More than 60% of wells drilled in 1994 resulted in discoveries, an all time high on the NCS," Stoltenberg said. "On average, the size of the new discoveries is smaller, but the result still is very encouraging."

State owned Statoil no longer will participate in all offshore licenses, he said.

OMAN-INDIA PIPELINE

One of the most ambitious pipeline projects was the subject of an entire technical session and of a luncheon speech.

The Oman-India gas pipeline is to extend 707 miles in its subsea portion from Ras al Jifran, Oman, to Rapr Gadwali, India, traversing water as deep as 3,550 m in the Dalrymple Trough.

The system is envisioned as a twin 24 in., grade X-70 line with 180,000 hp of compression injecting at nearly 6,000 psi, said William B. Foster, senior project manager for Intec Engineering Inc., Houston, and assigned to Oman Oil Co. Inc., Houston, as the pipeline's project manager for marine systems.

Foster said the current budget for a single line is about $3 billion, with more than $5 billion anticipated for the twin system.

Phase 1 of the project focused on determining the line's technical and economic feasibility Several companies, including Bechtel Overseas Ltd., London, Saipem and Snamprogetti of Italy, and J. Ray McDermott, New Orleans and London, examined possible routes and compression scenarios.

In that phase, planners rejected a possible shallow water route along the coasts of Iran and Pakistan for technical reasons. But the feasibility of the line was verified.

Phase 2, currently under way, involves route surveying, preliminary engineering, and requests for proposals to install all facilities. This phase is to end in July

Phase 3, consisting of consolidation of project financing, is set for completion by yearend. The final phase, construction, is to start in January 1996 and be completed in June 1999 with first gas deliveries to India July 1, 1999.

Four deepwater pipelay contractors have been prequalified: Allseas Marine Contractors SA of Switzerland, Colfexip/Stena Offshore Ltd. of Scotland, Saipem of Italy, and a group made up of Hereema, McDermott, and ETPM.

Foster said project installation economics dictated a pipe makeup rate of one joint/hr. Makeup will include welding, nondestructive testing (NDT), and joint coating.

Results of tests on welding and NDT for the project were reported to the technical session by Thomas M. Even of Intec Engineering, Brian Laing of CRC-Evans Automatic Welding, and Dan Hirsch of PCI Energy Services

They said two welding processes each demonstrated a capacity to perform a J-lay weld on tested pipe - 26 in. OD, 41.3 mm WT, X-60 grade - in less than 38 min.

Corrosion research conducted as part of the early phases of the project was the subject of a paper by F. W. Graham and D. S. McKeehan of Intec Engineering Inc., Houston.

Foster noted the unique requirements of the pipe in that the UOE process of manufacture was called for but no pipe with the qualities needed had been produced by this process. Yield strength for the pipe was placed at 85 kips/sq in. (ksi), with tensile strength as 115 ksi.

The severe hydrostatic pressure created by water depths along the route prompted an extensive testing program, the subject of a report by Peter R. Stark and David S. McKeehan of Intec Engineering.

Among the conclusions of the program was that the collapse pressure for the tested 26 in. pipe was greater than the maximum bottom pressure along the anticipated route and that buckle arrestor designs used in the testing program were effective in halting buckle propagation.

Foster said technology for recovering and repairing the pipeline during pipelay and later operations had yet to be developed.

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