MISHAPS DOMINATE WEATHER WINDOW ACTIVITY NEWS OFF NORTHWEST EUROPE

Roger Vielvoye
International Editor

Mishaps have dominated news of oil and gas work off Northwest Europe during this year's weather window.

The industry was stunned by the Aug. 28 sinking of the concrete gravity base for the Sleipner A platform in a fjord outside Norwegian Contractors' yard at Stavanger.

Sinking of the $194 million structure was the biggest loss experienced during development of a North Sea field. An investigation by field operator Den norske stats oljeselskap AS determined the sinking was caused by an error in design of the substructure (see story, p. 21).

The accident underscored the degree of risks to which companies are exposed in exploration and production off Northwest Europe.

Weather is another hazard that has not been tamed. A mid-October Force 10 storm hit British and Norwegian sectors, resulting in the death of one offshore worker and disruption of drilling and production operations.

Work related to safety concerns also interrupted North Sea production this year.

Operators completed installation of emergency shutdown valves (ESVS) on oil and gas platforms and pipelines off the U.K. The slowdown in production as a result of the work is over, and production is rebounding. However, a minor explosion in the accommodation module on the Fulmar platform put a brief dent in the August production figures.

The biggest beneficiary of the completion of ESV installations and other remedial work on platforms is the Shell-Esso combine. Production from the four platform Brent field had rebounded to more than 250,000 b/d in August-September for the first time since early 1989.

Production from the U.K. sector now is about 1.96 million b/d and should reach 2 million b/d by yearend. Norwegian production, which hit a peak of 2.11 million b/d in September, is constrained by final stages of an extensive maintenance turnaround. But when work on the Statfjord A platform is complete at the beginning of next month, production will be back to about 2 million b/d.

And when production from Danish and Dutch sectors is included, North Sea flow this winter should be about 4 million b/d.

Drilling activity off Northwest Europe has slipped from its midsummer peak, when 94 mobile rigs were active. Currently, 89 of the 138 available units are drilling, 17 are stacked, and the rest are being used for production or accommodation or are undergoing conversion or maintenance.

Britain and the Netherlands saw declines in their active rig counts this year. Norwegian activity remained unchanged, and for the first time in several years a well was spudded in the German North Sea. ARCO Germany in a 60-40 partnership with Ste. Nationale Elf Aquitaine is looking for gas in Block L/3.

SLEIPNER CHANGES

Statoil plans to install a replacement concrete structure for Sleipner A platform in time for a summer 1993 start of production.

The company hopes that will enable it to end the search for expensive alternate supplies of gas to meet the Sleipner group's obligations to begin deliveries to customers in Northwest Europe Oct. 1, 1993. Statoil is confident a combination of first gas from the new platform and supplies from a subsea satellite drilling program will provide most of the gas needed on that date.

Statoil's decision to order another concrete substructure for the Sleipner platform will allow Norwegian Contractors to deliver the replacement unit for mating with the topsides in spring 1993. A priority program of hook-up, float-out, and installation should put the platform on stream before the end of that summer.

However, wells drilled from Sleipner A platform will not be capable of delivering the 387 MMcfd volumes required in the first year of the sales contract. At first, Statoil thought it would need substantial volumes of gas from other sources in the Norwegian North Sea to make up the shortfall from Sleipner for perhaps 12-18 months.

This could have involved new investment in existing gas fields to make the added volumes available. It also would have called for outlays to increase compression at the onshore terminal for the Statpipe gas pipeline system to deliver the added volumes into the Zeepipe gas pipeline under construction to link Sleipner with Zeebrugge, Belgium.

Sleipner group partners are close to abandoning this expensive backup option because the shortfall of supplies from the main Sleipner platform may last only a few months. Instead, they plan a program of subsea satellite wells predrilled and tied back to the main platform.

Plans also call for accelerated development of Loke satellite field, formerly Sleipner Theta, where a four slot subsea production center is planned. This would start up prior to Sleipner A installation.

The partners also plan to install a new riser platform in Sleipner field to link the Zeepipe system with the main development and a short spur into Statpipe. They dropped plans to lay the Europipe gas pipeline to Germany from the Sleipner riser platform instead of the original proposal to lay it from the Statpipe riser platform.

Statoil estimates total costs, including the riser platform, additional satellite wells, and other expenses associated with ensuring gas supplies are available at about 1.5-2 billion kroner ($225-300 million).

WEATHER WOES

The worker who died during the mid-October storms was crushed by a container as 40 ft high waves battered Shell Exploration & Production's Stadrill semisubmersible.

Nonessential personnel were evacuated from three other semis hit by severe weather. A bridge linking a flotel to Shell's Cormorant Alpha platform was washed away.

Shell Expro also shut in Kittiwake oil field because tanker loading operations had to be suspended. And BP Exploration disconnected the Buchan floating oil production system because of the weather.

Onshore, high winds forced operators at Sullom Voe and Flotta oil terminals to suspend tanker operations, but production from fields feeding oil into the two terminals was unaffected.

EKOFISK MAINTENANCE

Two of the four large crude oil production complexes in the Norwegian North Sea were shut down for maintenance programs during the summer.

In August, Phillips Petroleum Co. Norway began a 2 week maintenance program covering all 24 platforms in the greater Ekofisk area that produce or process about 500,000 b/d of liquids and 1.7 bcfd of gas.

In the first total maintenance shutdown at Ekofisk since 1987, Phillips undertook seven critical jobs:

• Replacing the riser on the 36 in. gas pipeline to the 2/4R platform.

• Replacing valves on the 2/4P pig launcher on the oil pipeline to Teesside, England, to increase capacity.

• Installing tie-ins to the seawater cooling system to enable replacement of gas pipeline coolers.

• Installing a bypass around the unmanned booster station on the oil pipeline to Teesside,

• Repairing an overstressed section of the gas pipeline near the Emden terminal in northern Germany.

Phillips said replacing the gas pipeline riser was the most troublesome job, requiring slightly longer than the planned 2 week shutdown. The work was required by Ekofisk subsidence, which would have made contact between the riser and the platform a problem by yearend.

The Ekofisk shutdown reduced Norwegian production to only 1.43 million b/d in August.

STATFJORD TURNAROUNDS

Norwegian production also fell slightly in June and July during short maintenance periods on the Statfjord B and C platforms.

Field operator Statoil started the shutdown on the Statfjord A platform Oct. 5, and the unit is to be out of action until Nov. 3. In addition to normal maintenance work, Statoil is undertaking a complete safety upgrade on the first generation platform to bring it in line with tougher safety standards for later units.

The company also is taking advantage of the shutdown to modify the platform's process area to accommodate oil and gas from Saga Petroleum's Snorre field, currently under development with the first tension legged platform off Norway. It also will tie in two risers for Snorre oil and gas.

The complex program, which will involve 103,000 manor of work, is on schedule for early November completion.

OSEBERG START-UPS

Norsk Hydro has brought on stream the third platform in Oseberg field.

The 110,000 b/d unit will enable the company to increase field output to about 450,000 b/d.

Oil moves through a dedicated pipeline to Sture, Norway.

Earlier this month Norsk Hydro brought on stream the Oseberg satellite North Gamma, a subsea development using Norway's first horizontal producing well.

Production from the subsea well, which began at 6,500 b/d, moves through a 4.9 mile, 8 in. pipeline to Oseberg C platform, put on stream early in September. The well also is producing about 5.3 MMcfd of gas, which is reinjected into the main Oseberg reservoir.

The North Gamma reservoir at 8,810 ft holds 3.15 million bbl of oil and 123.6 bcf of gas. The 1,968 ft horizontal section was completed in an 85.28 ft thick oil zone underlying the main gas reserves. Eventually the well will produce gas at rates of as much as 52 MMcfd, also for reinjection into Oseberg. The project cost $68.18 million.

Meantime, Norwegian fabrication yards are facing a busy period as new developments in the North Sea and the Haltenbanken area come to fruition.

There also is an outside chance of a new gas development on the western edge of the Barents Sea to service a liquefied natural gas supply contract under negotiation with Italy's state owned electricity authority.

KILDA/LAPWORTH

Progress is being made toward development of Kilda/Lapworth, one of the biggest undeveloped gas/condensate fields in U.K. waters.

Instead of a long struggle for operatorship, the two principal companies involved, Chevron U.K. Ltd. and Conoco U.K. Ltd., have agreed to joint operatorship of the field, which covers five blocks in quadrants 15 and 16.

Joint operatorship is not the only innovation by the two companies in a bid to reduce the amount of time and money spent on preliminary stages of development. They have invited Department of Energy personnel to participate in mapping the field, currently the subject to an extensive 3-D seismic survey.

Chevron and Conoco reckon that intimate knowledge of mapping the field will enhance DOE's ability to handle future applications for commercial development of the extensive and complex reservoir.

NELSON FIELD

In Nelson field, one of the biggest oil development projects under way off the U.K., Enterprise Oil plc has begun drilling eight development wells through a subsea template using the Santa Fe 135 semisubmersible.

The wells will go to 14,000-16,000 ft and deviate from 45 to 70 in an area prone to hole stability problems.

Nelson is to start up in first quarter 1994 and peak at 160,000 b/d of oil and 30 MMcfd of gas.

Enterprise plans to drill 25 production wells, including the eight through the subsea template and five more from the field's southern subsea satellite. There also will be eight water injection wells, including one at the satellite.

CLAIR SUCCESS

On the exploration front this year, the most successful campaign was by a group of eight companies in Clair heavy oil field in the Atlantic Ocean west of the Shetlands.

The group drilled two appraisal wells following an extensive 3-D survey and detailed reservoir and engineering studies last year.

A key problem involving Clair has been low well productivity. The discovery well in 1977 tested 1,500 b/d, but 10 appraisals drilled during 1978-85, while confirming the reservoir's areal extent, were unable to repeat these flow rates.

The 1991 campaign focused on drilling two wells, one vertical and one horizontal, and stimulate them to boost flow rates. This would have been followed by an extended test program in 1992.

An official with the group said, "The results of the two new wells are such that extended well tests are no longer considered necessary or appropriate. We now expect that the 1992 program will include further appraisal drilling to follow up the success of the 1991 program.

"The success of the two 1991 wells illustrates the benefits of a joint approach, with eight companies committed to solving common problems and working together, rather than competing, in using state of the art technology."

Elf U.K. Ltd. drilled the 206/7a-2 horizontal well with the Petrolia semisubmersible. A 1,968 ft horizontal section was cored and open hole tested in fractured basement of pre-Cambrian Lewisian gneiss. It flowed 660 b/d of 23 gravity crude. After acidization, Elf recorded a stabilized flow rate of 2,100 b/d with 250 psi wellhead pressure and gas:oil ratio of 240:1.

BP Exploration's 206/8-8 vertical well was located 1 km northwest of the Clair discovery well. One interval flowed at a sustained rate of 3,100 b/d of 23 gravity crude from a 295 ft interval in the Devonian-Carboniferous "red beds" sequence with 500 psi wellhead pressure psi without stimulation during a 6 day test. Gas:oil ratio was 290:1. A test of a second 295 ft interval in the "red beds" sequence flowed initially at 1,850 b/d, increasing to 3,250 b/d after hydraulic fracture stimulation with 600 psi wellhead pressure and gas: oil ratio of 300:1.

Clair extends over six blocks. Other companies participating in the joint appraisal agreement are Amoco (U.K.) Exploration, Chevron, Conoco, Enterprise, Esso U.K. Exploration & Production, and Mobil North Sea Ltd.

DIAPIR SALT DOME PLAY

The Diapir salt dome play in the southern part of quadrants 22 and 23 and the northern part of quadrant 29 has attracted considerable attention this fall.

Six rigs have been drilling in the area.

Ranger Oil (U.K.) Ltd. drilled a successful wildcat on Block 29/2a, operated by Conoco, as part of a farmout commitment.

The well, drilled to a total depth of 5,760 ft, tested three intervals at a combined stabilized rate of 9,000 b/d of 39 gravity crude and 5.9 MMcfd of gas through a maximum 40/64 in. choke. Combined maximum flow rates of 14,455 b/d and 7.4 MMcfd were achieved on variable choke sizes for short periods.

Ranger has spudded an appraisal, also as part of its farmout commitment.

Other partners in the block are Enterprise, Lasmo, Hardy Oil & Gas (U.K.) Ltd., and Union Jack Oil plc.

RATIONALIZATION CONTINUES

Companies continue to rationalize U.K. offshore acreage, building on core areas in their North Sea operations and selling or exchanging interests in permits that are either too small or do not fit the company's long term E&P strategy.

The process has been in progress throughout the summer with a number of companies building up tax shelter for exploration activities by acquiring production assets, notably in the southern gas basin.

The latest exchange deal was between BP Exploration and Phillips Petroleum Co. U.K. Ltd. BP is enthusiastic about the Diapir province in the Central North Sea, where it is considering a major development and will assume Phillips' 10.9% stake in the BP operated Block 22/25a in the area. In exchange Phillips will acquire BP's 27% stake and operatorship of Block 15/28b east of Phillips' Renee oil discovery in Block 15/27.

In the southern gas area BP will acquire Phillips' 17.5% stake in Block 47/5a, which contains an undeveloped gas discovery and an extension of BP's Hyde gas field, in return for half of BP's 10% holding in the Phillips operated Block 22/4a, which contains the Maggie gas discovery. Phillips also will earn the right to a 35% interest in Block 15/28c by funding 35% of an exploration well next year.

In a separate deal, Phillips agreed to assign its 25% interest in Block 107/14 in exchange for Ultramar's 32.5% interest in Block 30/2c, north of the Phillips operated J Block, 30/7a.

The Maggie/Drake complex also figured in an assets swap between Mobil North Sea Ltd. and British Gas plc earlier this month. Mobil exchanged its Maggie/Drake interests for British Gas' undeveloped acreage in the licenses that contain Pickerill,

Guinevere, and Gawain fields. Later the companies agreed to swap Mobil's remaining acreage in Maggie/Drake for British Gas' acreage in Welland and Pickerill fields.

Copyright 1991 Oil & Gas Journal. All Rights Reserved.