Northwest Europe's Operators Show Creativity In New Developments

BP is installing three platforms this summer as part of a $2.6 billion development of seven fields, with combined reserves of 400 million bbl of oil and 1.1 tcf of gas. The Eastern Trough Area Project will begin production in 1998. Shown is the Mungo field jacket being loaded out from the Kvaerner Oil & Gas yard at Methil, Scotland. Photo courtesy of BP.

• Shown is the main towhead for one of two 7.5-km Britannia pipeline bundles, launched by Smit International BV, Rotterdam. The bundles were installed by Stolt Comex Seaway AS, Aberdeen for joint operators Chevron and Conoco, to connect Britannia's subsea manifold and platform. Photo courtesy of Smit. [1,557 bytes]

• Tail ends of Britannia's bundled pipelines are still evident after insertion into a carrier pipe. The bundles weighed a total 12,000 metric tons and contained a 14-in. production line, an 8-in. test line, a 3-in. methanol line, and a 12-in. line for hot water circulation. Photo courtesy of Smit. [17,509 bytes]

• Britannia platform jacket is being loaded out at the Dragados Offshore SA yard at Cadiz, Spain. The jacket weighs 21,000 metric tons and will be installed this summer in time for first production in 1998. Photo courtesy of Britannia Operator Ltd. [17,295 bytes]

• Texaco's U.K. North Sea Captain oil field was brought into production in March following a £500 million ($800 million) development. Block 13/22a Captain was developed with a wellhead protector platform and oil production and storage ship, with export by shuttle tanker. Texaco aims to brings Captain to peak production of 63,000 b/d of oil this summer. Photo courtesy of Texaco. [11,932 bytes]

• Britannia platform topsides is nearing completion at the Trafalgar John Brown Ltd. yard at Teesside, U.K. The 29,000-metric-ton topsides will have capacity to process 740 MMcfd of gas and 50,000 b/d of condensate. Photo courtesy of Britannia Operator Ltd. [20,578 bytes]

Northwest Europe's offshore operators have boosted their oil and gas production dramatically in recent years, and while the area is now mature, a steady stream of developments continues.

In the boom days of the late 1970s and 1980s, a typical North Sea installation was a large platform, with occasionally a new pipeline or, more commonly, a tie-in to the area's massive export grids.

These days, now that technical developments have enabled operators to justify developments of smaller, once uneconomic, discoveries, it is pointless to talk of a typical offshore development.

Northwest Europe's offshore operators have learned that it is worthwhile to rack their brains for the most economic development concepts. This creativity is reflected in recent development plans.

While operators are now snatching up the small accumulations in and around the mature North Sea producing fields, they are also seeking to develop frontier regions.

Frontier developments have always been challenging for petroleum companies, traditionally because of harsh weather, remote locations, or volatile local politics.

In Northwest Europe at least, wrathful environmental protesters have been added to the list of frontier perils, as U.K. operators have found exploration operations hindered by activists.

West of Shetland

U.K. companies are working to develop the area west of the Shetland Islands, where BP Exploration Operating Co. Ltd. in particular has made a number of large finds in recent years.

Greenpeace, the London-based environmental campaign group, reckons the world can do without developing new areas, contending such development runs afoul of a need to cut emissions of so-called greenhouse gases.

So Greenpeace activists have occupied Rockall, a tiny island off western Britain; hindered seismic survey operations in the West of Shetland area; and mounted protests at headquarters of companies involved in West of Shetland exploration.

The group has lodged papers with the U.K. High Court, claiming the U.K. government's recent issue of exploration licenses for the West of Shetland area breached European Union laws (OGJ, Apr. 14, 1997, p. 30). Greenpeace is looking for a full judicial review. The campaign group is asking the court to suspend exploration licenses until the case is decided. The group is also pursuing action through the European Court.

This Greenpeace campaign has not resulted in such great popular support as did its bid to stop dumping of the Brent spar in 1995.

Foinaven delays

While Greenpeace has failed so far to stall exploration and development work, BP has suffered a number of engineering problems that have delayed first production from Foinaven field.

In May, this first field development in the West of Shetlands offshore area was revealed to be facing further delays, because of failure of installed subsea equipment during pressure testing.

BP initially intended to produce first oil from Block 204/24a Foinaven field late in 1995 but once more had to revise its schedule. The latest problem required retrieval of a subsea manifold and five christmas trees from the seabed.

The operator believed valve seals have been damaged and would leak oil if used. The problem was spotted when BP carried out high pressure testing of subsea equipment using water and dyes.

Four out of 48 valve stems on one of two subsea manifolds leaked, plus three trees from one drilling center and two from the other.

A BP official said high differential pressure between the outside and inside of the equipment affects how the valve seals seat, and leakage suggests the seals had been damaged.

Equipment was retrieved with the Iolair construction semisubmersible vessel, which had installed it. BP did not say when it expects repair work to be completed, but one estimate was by end of September.

This was not the first setback in Foinaven. Last year, BP had to retrieve the first subsea manifold it installed, after cracks appeared on hubs during leak testing (OGJ, Nov. 11, 1996, p. 28).

Clair progress

But all has not been bad news for BP West of Shetland. Clair oil discovery on Block 206/8 appears to be progressing towards development at long last.

Clair was the first discovery West of Shetland, made by BP in 1977.

The find lies in 460 ft of water, and while it has estimated reserves in place of more than 4 billion bbl of oil, making it U.K.'s largest undeveloped offshore accumulation; reserves are pegged at only 100-300 million bbl.

The reason for Clair's lack of progress is complexity of the reservoir; until last year all wells had flowed much below commercial levels on test.

But BP hit upon the idea of using faults in the reservoir as conduits to boost flow in wells. In late summer 1996 BP concluded a well test that yielded more than 15,000 b/d, enough to suggest development is viable.

Now BP has gathered a project team in Aberdeen to deliver a development concept for Clair by yearend, according to license partner Chevron U.K. Ltd.

Chevron said Clair is being moved onto the ''fast track,'' with the intention of achieving U.K. Department of Trade and Industry approval by mid-1998 for first phase development of the find.

A feasibility study has shown conversion of a tanker into a floating production, storage, and offloading (FPSO) ship to be the most economic development plan for Clair.

Early oil exports would be by shuttle tanker, as with BP's Foinaven and Schiehallion developments in deeper water nearby.

One longer-term prospect involves construction of an oil export pipeline, with oil from several fields in the area being sent to a gathering and export platform located in Clair.

Meanwhile, three operators are evaluating systems for collection, transportation, and sale of natural gas from potential field developments west of the Shetland Islands.

The study will be called Aurora project, funded by Conoco (U.K.) Ltd., Texaco Britain Ltd. and Total Oil Marine plc.

The partners, which have exploration interests in the West of Shetland play, will examine options for subsea pipelines, gas landfall sites, and delivery of gas to customers. Texaco has a gas discovery in the area, Victory, with estimated reserves of 300 bcf (OGJ, June 20, 1994, p. 16).

Ekofisk

This year, Phillips Petroleum Co. Norway will enter a hectic period of offshore work in Ekofisk field, which is being redeveloped under a $3 billion program involving installation of two new platforms.

A new drilling platform, known as Ekofisk 2/4X, was installed by Phillips in the field last year. The platform will take over the drilling duties of several platforms currently operational but due to be shut down.

Four fields currently producing through Ekofisk field center will be shut in under redevelopment: Cod, Albuskjell, West Ekofisk, and Edda.

Four other Ekofisk area fields-Ekofisk itself, Eldfisk, Embla, and Tor-plus third party fields Gyda, Ula, Valhall, and Hod, will have their output diverted from the existing Ekofisk transport and processing platform to a new platform performing the same role.

Subsidence of this massive platform is the main reason for the redevelopment. Norwegian Petroleum Directorate threatened to close down Ekofisk in 1998 if Phillips could not transfer operations to new platforms outside the subsidence area.

The new transportation and processing platform, known as Ekofisk 2/4J, is nearly built. The platform jacket was installed in May, and Phillips said the biggest challenge for this year is to get modules for the platform ready for installation in August.

In June, work began on hooking up pipelines laid last year to the 2/4J platform; installing two subsea safety valves on oil and gas export lines to Teesside and Emden, respectively; and installing a Y-piece in the gas export line 10 km south of Ekofisk to connect to a pipeline that will divert third party gas around the new Ekofisk center.

Ireland's first oil

In May, Statoil (U.K.) Ltd. contracted for work in the first oil field development off Ireland: Connemara on Block 26/29 in the Porcupine basin off the west coast.

Connemara has estimated reserves of 20-50 million bbl of oil and was discovered in 350 m of water by BP (OGJ, June 5, 1995, p. 18).

BP subsequently relinquished the block, declaring the discovery noncommercial. Dublin's Aran Energy plc took over the license, and Statoil took over Aran in 1996.

Statoil saw that its multipurpose shuttle tanker/production ship concept could make Connemara development viable. The company intends to use one of a small fleet of such ships under construction (OGJ, Oct. 21, 1996, p. 24).

Although Statoil has not yet received government approval for its development plan, the company has let a $15 million contract to Stolt Comex Seaway SA, Aberdeen, for subsea construction work.

Ireland celebrated temporarily joining the ranks of oil producing countries on July 10 when Statoil began an extended well test in Connemara.

Operating in 375 m of water, J.W. McLean semisubmersible rig is producing and processing oil from the field for delivery by flexible pipeline to Berge Hugin storage tanker, moored 2 km away. The tanker has capacity to hold 640,000 bbl of oil.

Connemara has become considered as potentially viable only because of recent advances in floating production technology, now a common method of developing small finds in deep water.

Mary O'Rourke, Ireland's Minister for Public Enterprise, said, ''The result of the test should enable Statoil to determine whether the field can be put on long term commercial production.

''This would involve drilling a further 8-10 wells over the next year or so and bringing a customized floating production, storage, and offtake facility in May 1998 for production for up to 5 years.''

Once testing is completed, the tanker will deliver the stored oil to Whitegate refinery near Cork. Statoil recently secured a deal to process crude oil at Whitegate, to ensure security of supply to its Irish gasoline station chain.

South of Connemara, Marathon International Petroleum Hibernia Ltd. has joined the western Ireland hydrocarbon hunt with a wildcat on Porcupine basin Block 35/30 spudded in late May.

Jack Bates semisubmersible rig operated in 2,310 ft of water to drill the well to a total measured depth of more than 13,000 ft. License partners, each with a one-third interest, are operator Marathon, Occidental of Ireland Inc., and Phillips Petroleum U.K. Ltd. Marathon is operator of Ireland's only two producing fields, Kinsale Head and Ballycotton (OGJ, June 5, 1995, p. 17).

Denmark/Greenland

Denmark is encouraging exploration of its own frontier territory, particularly off Greenland, where recent seismic surveys have revealed a structure the size of Norway's supergiant Troll reservoir.

Denmark and Greenland are hoping that, like Troll, this structure too holds hydrocarbons.

Norway's Den norske stats oljeselskap AS (Statoil) reported beginning of a seismic survey of the Fylla area in the Davis Strait off western Greenland by Nunaoil, a company owned by the government of Denmark and the Greenland assembly.

Around the end of July, the Thetis survey ship was due to finish collection of 2,000 line km of 2D seismic data. The Fylla license is operated by Statoil, with partners Phillips, Nunaoil, and Denmark's state firm Dopas as partners.

Meanwhile, the Danish government is seeing the results of a move to open the Danish continental shelf further to foreign companies. Amerada Hess AS has let a 1.8 billion Danish kroner ($270 million) contract to Brown & Root Ltd., London, to design, build, and install a production platform in South Arne field off Denmark.

South Arne is due on stream on July 1, 1999, and will be one of the first finds to be developed in the wake of Denmark's program to encourage new operators to work there.

The field has estimated reserves of 60 million bbl of oil and 80 bcf of gas and will be developed with a platform built under an engineering, procurement, fabrication, installation, and commissioning contract.

The platform will consist of a concrete storage base, with capacity of 550,000 bbl of oil, and a topsides able to produce as much as 50,000 b/d of oil and 70 MMcfd of gas.

Lindsay Woodhead, Brown & Root project manager, said, ''The platform will be unusual in that the topsides will be supported on the GBS by one concrete tower and a steel lattice drilling tower/conductor frame. The design saves on cost and shortens the fabrication schedule.''

The 100,000-metric ton concrete gravity base will be built at Scotland's Nigg yard, run by the Brown & Root McDermott Fabricators Ltd. (Barmac) joint venture. Topsides will be built at Barmac's Nigg and Ardersier yards.

Fabrication of the concrete base and topsides is scheduled to begin in September. Installation of the base is slated for March 1999, with topsides to be added in April. Subsurface work will begin with installation of a drilling template this September.

Elgin/Franklin

Off the U.K., operators have begun development of a series of high-pressure/high-temperature (HP/HT) reservoirs in the Central Graben area. Texaco expects to bring the first of these, Erskine, on stream this summer (OGJ, Mar. 17, 1997, p. 36).

But the largest U.K. HP/HT project will be a linked development of Elgin and Franklin, operated by Elf Exploration U.K. plc, and Shearwater, operated by Shell U.K. Exploration & Production.

In March, Elf let a £400 million ($640 million) contract for a jack up production, utilities, and quarters (PUQ) platform to be installed in its Elgin/

Franklin development in the U.K. North Sea.

The contract went to a combine of McDermott Marine Construction Ltd., London; Technip Geoproduction, Paris; and Barmac.

The contract follows award of a front-end engineering design contract to McDermott and Technip last year. The companies are jointly promoting Technip's TPG 500 jack up platform concept.

McDermott said the concept offers substantial cost savings over conventional platform installations (see schematic this page).

''Standard utilities and quarters are incorporated within the basic hull unit,'' said McDermott, ''which provides a large-capacity deck for production equipment.

''This innovative design significantly reduces the need for costly offshore installation and hook-up operations. The platform is towed to location complete, with the utility systems already commissioned onshore, and is 'self installing.'''

The combine's Elgin/Franklin project team will be based at McDermott's Wembley offices. Construction will take place at Barmac's Nigg yard.

Technip will design and procure equipment for the platform hull, legs, and foundations. McDermott is responsible for overall project management, engineering and design of topsides, procurement, and offshore commissioning. Barmac will carry out bulk procurement, fabrication, onshore commissioning, and offshore hook-up and commissioning.

The PUQ platform will be installed in Block 22/30c Franklin field, where water depth is 92 m, bridge-linked to a wellhead platform. An unmanned platform will be installed in Block 29/5b Franklin. Elf has recently let contract for the two smaller platforms.

The PUQ platform will be designed to process 175,000 b/d of liquids and 500 MMcfd of gas at peak. Total development of the two fields is expected to cost £1.5 billion ($2.4 billion), with production start-up due in 2000.

In April, the U.K. Department of Trade and Industry (DTI) approved plans by Elf and Shell to develop Elgin and Franklin and nearby Block 22/30b Shearwater find.

Both developments are due to begin production in 2000, with gas being sent to shore through a new jointly owned pipeline known as the Shearwater and Elgin Area Line (SEAL).

The developments are the second to be sanctioned among a group of central North Sea discoveries. Texaco Ltd. will bring North Sea's first HP/HT field, Erskine, into production this year.

Elgin has estimated reserves of 889 bcf of gas and 244 million bbl of condensate, while Franklin reserves are estimated at 821 bcf of gas and 123 million bbl of condensate.

Elgin and Franklin reservoirs are at a depth of 5,400 m, with reservoir pressures of 1,050 bar and a temperature of 190° C. Water depth in the fields is about 95 m.

Gas will be exported via the SEAL pipeline to Shell's Bacton terminal in Norfolk, while liquids will be exported through a 24-in. pipeline link to the Forties oil pipeline system operated by BP Exploration Operating Co. Ltd.

Jackets for the two wellhead platforms are under construction at the Lewis Offshore Ltd. yard at Stornoway, in the Orkney Islands.

The Galaxy 1 heavy duty jack up spudded the first Elgin development well on Mar. 24, through a template placed on the seabed there last November.

Shearwater

Shell Expro plans to develop Shearwater under a £714 million ($1.15 billion) program, with first production slated for mid-2000.

Shearwater has estimated reserves of 844 bcf of gas and 159 million bbl of condensate and natural gas liquids.

Development will involve two bridge-linked, four-legged steel platforms-one a PUQ platform and one a wellhead platform-standing in 90 m of water.

Production capacity will be 410 MMcfd of gas and 90,000 b/d of liquids. Gas will be exported via the SEAL pipeline, while liquids will join the Forties network via a 24-in. spur line to the same Y-piece link point as Elgin/Franklin liquids.

Construction is being carried out by a combine of AMEC plc, London, and Heerema VOF, Leiden, Netherlands. They will build the platforms at AMEC's Wallsend yard in the U.K., and Heerema's Hartlepool, U.K., and Vlissingen, Netherlands, yards.

The 463-km, 34-in SEAL pipeline will be the longest on the U.K. continental shelf and will take gas from the two PUQ platforms to the Bacton terminal. Capacity will be 922 MMcfd of gas.

SEAL will cost £400 million ($640 million) to build and will deliver gas to the U.K. gas grid at Bacton and to the Interconnector pipeline to Belgium, currently under construction.

Construction is expected to begin in 1998. Elf will be operator of the pipeline during construction, and Shell/Esso will take over operatorship once commercial gas flow begins.

Jotun

In March, Esso Norge AS issued letters of intent for an FPSO and wellhead platform for development of Jotun discoveries on Blocks 25/8 and 25/7 in the Norwegian North Sea.

Esso's Jotun field lies in 126 m of water and covers three discoveries: Elli, Tau West, and Elli South. These have estimated combined reserves of 200 million bbl of oil.

Both Jotun contracts will be for engineering, procurement, construction, installation, and commissioning.

The FPSO contract went to Kvaerner AS, Oslo, which will build the ship's hull at Kvaerner Masa yard in Finland and the topsides at its Rosenberg yard in Stavanger.

The FPSO contract is valued at 2 billion kroner ($310 million). Kvaerner will begin early engineering and preparatory work ahead of approval of the development plan.

The ship is expected to be installed in Jotun field in spring 1999, with production start-up later that year.

The FPSO will have capacity to produce 90,000 b/d of oil and to store almost 600,000 bbl of oil. The 250 m-long ship will be connected to the wellhead platform by eight flow line/umbilical risers.

The 1.5 billion kroner ($230 million) wellhead platform contract was awarded to Heerema Toensberg AS, Toensberg, Norway. The platform will be a four-legged steel structure with 24 well slots.

Topsides engineering will be carried out by ABB Offshore Technology AS, Billingstad, Norway, while topsides fabrication will be at Heerema's Toensberg yard.

The Jotun jacket will be built by Aker at its Verdal yard, while drilling facilities will be provided by Bentec Norge AS, Stavanger.

Jotun oil will be exported by shuttle tankers. The ship's turret and mooring system will be supplied by Bluewater Offshore Production Systems Ltd., Essen, Belgium, and installed by Kvaerner Rosenberg.

Oseberg

In March, Norsk Hydro AS let a 1.6 billion kroner ($240 million) contract to Aker AS, Oslo, for construction of gas processing platform topsides for installation in Oseberg field on Norwegian Blocks 30/6 and 30/9.

Hydro's new gas processing platform will be used to help deplete Oseberg gas reserves, estimated at 115 billion cu m, beginning in October 1999.

Total development cost for Oseberg gas is expected to be more than 4 billion kroner ($600 million), including pipelines and modifications to existing facilities.

Three oil production platforms have been installed in Oseberg field. The new gas platform will be designated Oseberg D and will be bridge-linked to Oseberg A, which in turn is bridge-linked to Oseberg B.

Gas production will involve use of wells already drilled during oil depletion, controlled and maintained from Oseberg B platform using existing drilling facilities.

As Oseberg field comes off its oil production plateau near 2000, more associated gas will be produced. This gas has been reinjected so far, but Hydro reckons it can now recover 75% of reinjected gas.

Oseberg D platform will be installed 100 m from Oseberg A in 109 m of water. It will have capacity to process 32 million cu m/day of gas and reinject some gas.

Oseberg D topsides will weigh 7,500 metric tons and will be completed in spring 1999 for installation that May. Topsides will be built at Aker's Verdal yard. The jacket construction contract will be awarded this fall.

In July, Norsk Hydro let a 280 million kroner ($40 million) contract to Saipem U.K. Ltd., London, for transport and installation of jacket and topsides for Oseberg South platform.

Oseberg South will be developed as a satellite of the main Oseberg field in the Norwegian North Sea and has estimated reserves of 335 million bbl of oil.

Saipem's S7000 crane barge will carry and install the 7,800-metric-ton jacket and 10,200 ton topsides, with work due for completion in May 2000. Oil production is slated to begin in August 2000.

Britannia

Britannia Operator Ltd. (BOL), a joint operating venture of Conoco and Chevron, has been busy in Britannia field, due to begin gas production next year.

Britiannia has estimated reserves of 3 tcf of gas and 145 million bbl of condensate and is expected to produce 740 MMcfd of gas and 50,000 b/d of condensate at peak.

This spring BOL installed a 186-km, 27-in. pipeline to take gas from Britannia platform to the Scottish Area Gas Evacuation (SAGE) system terminal at St. Fergus, north of Aberdeen.

The pipeline was installed by Castoro Sei pipelay barge, operated by European Marine Contractors Ltd., London. The same vessel also installed a 44-km, 14-in. line to take Britannia condensate to a junction with the Forties pipeline system.

BOL reports that Britannia installation is well under way, with the subsea manifold and export pipelines in place, and the platform jacket and topsides nearing completion and scheduled for installation by the end of September.

Galley

Texaco plans to deploy a production semisubmersible unit, formerly used to deplete U.K. North Sea Emerald field, in its development of Galley field on U.K. Block 15/23a.

For Texaco's Galley development, the Emerald Producer semi will be upgraded and have its name changed to Northern Producer. Field development cost is estimated at £140 million ($224 million).

Texaco will lease the vessel from shipping firm Seatankers, which in turn is to award a 10-year management contract to Atlantic Power & Gas Ltd., Aberdeen, to operate the unit during production.

Two development wells will be drilled ahead of first production from Galley, anticipated in first quarter 1998. These are expected to yield a combined 35,000 b/d of oil and 50 MMcfd of gas at peak. A third production well is planned when the field is on stream.

From the subsea wellheads, oil and gas will arrive on the Northern Producer for processing. Oil and gas will be exported in separate pipelines to Texaco's Tartan platform on nearby Block 15/16a.

Galley's oil will join the output from Tartan in a pipeline to Flotta terminal in the Orkney Islands, while gas will be added to Tartan's flow to St. Fergus terminal, north of Aberdeen.

Galley reserves are estimated at 28 million bbl of oil and 40 bcf of gas. Early production will be from the field's northern and southern accumulations. Texaco is planning to deplete eastern and western accumulations in a second phase of development.

Ross

In June, DTI sanctioned a plan by Talisman Energy (U.K.) Ltd. to develop Ross discovery on Blocks 13/28a and 13/29a in the U.K. North Sea.

Ross has estimated reserves of 66 million bbl of oil and 20 bcf of gas. Talisman became operator of Ross last year by acquiring BP's interests in the two blocks.

The find will be developed with an FPSO. Oil will be exported by shuttle tanker, while gas will be exported by a pipeline to be tied-in to the Frigg trunkline.

First production is expected in third quarter 1998. Ten development wells are planned, with combined oil production expected to start at about 40,000 b/d.

The wells will include multilaterals-because Ross is a highly faulted reservoir-in upper Jurassic sands. These will include seven producers plus water and gas injection wells.

Talisman has chartered a production ship from Bluewater Offshore Production Systems Ltd., Essen, Belgium. Bluewater is currently having the hull for the ship built in Japan.

A 6,000-ton topsides is to be built and installed by UIE Scotland Ltd., Clydebank, U.K., under a $75 million contract. The 240-m-long, 100,000 dwt ship, named Bleo Holm, was due to arrive at the yard in August.

Viking

In late March, Conoco received DTI approval to develop four gas accumulations in U.K. North Sea Viking field as satellites of existing platforms.

The four accumulations-F and Fs, which are part of Viking A field; and Gn and Wx, which are part of Viking E field-have combined estimated reserves of 500 bcf of gas.

Development of the four satellites will be known as Viking Phoenix project. Two unmanned platforms will be installed, one to deplete F and Fs and one to deplete Wx and Gn.

Output from the two new platforms is expected to total 300 MMcfd at peak. Field life for the four satellites is estimated at 15 years.

Produced gas will be sent by pipeline to Viking B complex for processing. From Viking B, gas will go to Viking A riser platform for export to Theddlethorpe terminal, Lincolnshire.

F and Fs finds lie on Block 49/12a in 30 m of water. They were discovered in 1973 and 1976, respectively. Wx and Gn finds lie on Block 49/17 in 30 m of water and were discovered in 1969 and 1976, respectively.

The F/Fs platform will be connected to Viking BD platform by a 15-km, 16-in. pipeline. A subsea tee will connect the Wx/Gn platform to this pipeline.

Six production wells will be used, including four new wells to be drilled ahead of first gas, and two appraisal wells, 49/12a-9 and 49/17-12, will be converted to producers.

Conoco said the development wells will be a mixture of deviated, horizontal, and multilateral boreholes, to reduce the number required and to allow use of smaller platforms.

Fracturing techniques will be used on Wx wells to improve productivity. The four accumulations are in Rotliegendes sandstone at depths of about 8,500 ft.

In April Conoco said it would let engineering, procurement, installation, and commissioning contract for the two platforms and a separate contract for the in-field pipeline.

Viking A field began production in 1972, and since then Viking A and B fields have produced more than 2. 8 tcf of gas.

The Viking A riser platform is the only remaining structure in Viking A field. Last year, Conoco completely removed four platforms that had not been upgraded to meet recent U.K. offshore regulations (OGJ, June 3, 1996, p. 20).

Conoco subsequently let the ontract for an undisclosed sum to Brown & Root for two new unmanned wellhead platforms and a reception module in Viking field.

The contract is for engineering, procurement, fabrication, installation, and commissioning of the tripod design platforms and an 800-ton module. Fabrication is slated for completion in April 1998, with installation due in May and first gas in the fourth quarter.

Fulmar SALM

In March, Shell Expro invited contractors to bid for decommissioning and disposal of a single-anchor-leg mooring (SALM) buoy used until recently in U.K. North Sea Fulmar field.

The SALM is a 5,000-ton cylindrical steel structure used to anchor a storage tanker in the field. The tanker and SALM were removed from Fulmar in 1994, when a newer leased tanker took over oil exports.

The SALM is much smaller than the Brent spar loading buoy, which has caused the Shell U.K. Ltd./Esso Exploration & Production U.K. Ltd. joint venture a disposal headache (OGJ, Jan. 20, 1997, p. 24).

A Shell official said the Fulmar SALM is likely to be taken ashore for scrapping, although a contractor may suggest a way of re-using the structure.

Shell/Esso has compiled a draft best practicable environmental option (BPEO) disposal plan and submitted this to DTI for consideration.

The official said the draft BPEO will not be finalized for formal submission to the ministry for approval until contractors' detailed intentions can be incorporated.

Shell/Esso did not set a date for submission of bids by contractors and has no firm schedule for disposing of the buoy; nor will have it a firm idea of disposal costs until contractors' bids are received.

The SALM is currently moored in a fjord near Hjelmeland, northeast of Stavanger. It is 85 m tall and has a draft of 62 m. The official said the buoy could be lifted from the water relatively easily.

The Fulmar storage unit was a converted 210,000-dwt tanker, which was sold last year to Statoil and Smedvig AS,

Stavanger.

Statoil and Smedvig plan to renovate the tanker in the Far East and market it for new field developments.

Shell/Esso has installed a new 16-km pipeline to export as much as 140,000 b/d of oil from Fulmar and the linked Gannet, Auk, and Clyde fields.

The current tanker storage and loading system in Fulmar will remain in service until the export link to the Norpipe trunkline is commissioned (OGJ, Aug. 19, 1996, p. 56).

Brent spar

In late May, Shell/Esso received nine detailed proposals for disposal of Brent spar loading buoy.

The proposals were submitted by six contractors or groups, which were shortlisted in January to develop fully 11 ideas out of an original 30 outline plans submitted (OGJ, Jan. 20, 1997, p. 24).

Shell/Esso said since then a plan to use the derelict buoy's hull as a dock gate and one to use the topsides as an onshore training center have been dropped by the contractor groups concerned.

The operator aims to publish full details of the proposals, including costs, after Det Norske Veritas AS (DNV), Oslo, has carried out an independent evaluation, by about the end of August.

Then Shell/Esso plans to discuss the proposals in public seminars. After this, the company will recommend to DTI its preferred disposal plan.

Eric Faulds, Shell/Esso decommissioning manager, said, ''Now that we've received the nine detailed bids, we can start the long process of comparing them with each other and with the benchmark option of deep-sea disposal.

''We won't be announcing contractors' cost estimates or their calculations on safety or environmental impacts until DNV has ensured that these have been provided on a similar basis and are therefore truly comparable.''

Sedgwick

Off the U.K., Enterprise Oil plc and Marathon Oil U.K. Ltd. agreed on a development of Sedgwick discovery through West Brae facilities, currently under development.

Enterprise's Sedgwick discovery and Marathon's West Brae are to be developed jointly, with output from the combined facilities to be split 67.5% to the Marathon-led group and 32.5% to the Enterprise-led group.

Estimated reserves for the two discoveries are 40 million bbl of oil. A subsea manifold will be installed in West Brae field, and a single well in Sedgwick 2.3 km away will be tied back.

Marathon had already received government approval to develop West Brae as a subsea satellite of its Brae A platform, but a twin development was always envisioned (OGJ, July 22, 1996, p. 29).

First oil is expected in fourth quarter 1997, at a combined initial rate of 30,000 b/d, which is expected to drop to an average 27,000 b/d for 1998.

Combined development cost for West Brae and Sedgwick is £100 million ($160 million). The Transocean Explorer semisubmersible is handling development drilling, which started in April.

Two production wells and a water injector are to be drilled in West Brae, along with the single producer in Sedgwick. Marathon has an option to drill a further producer in West Brae.

Renee and Rubie

Phillips Petroleum Co. U.K. Ltd. is looking to develop two small oil discoveries on U.K. North Sea Blocks 15/27 and 15/28, one of which was first drilled 21 years ago.

Although Phillips has not disclosed reserves figures for the finds, the company says they are too small to justify a stand-alone development. Instead, development had to wait on spare export capacity in a nearby field.

When the larger of the two finds, Block 15/27 Renee, was tested in 1976, it flowed 8,000 b/d of oil. But there was no existing infrastructure nearby to allow economic depletion.

In 1985, Rubie was found on Block 15/28. Phillips bought into the block in 1991 through an asset trade. Meanwhile, Amerada Hess developed the nearest find to Renee/Rubie, about 20 km away on Block 15/21.

Amerada brought Ivanhoe and Rob Roy fields into production in 1989, with two subsea wellhead clusters tied back to a production semisubmersible, AH001.

Oil exports from AH001 went through a 14-in. pipeline to Claymore platform and into the Flotta network. Gas was sent via an 8-in. pipeline to Tartan platform and from there to shore at St. Fergus.

Until recently, while Amerada depleted Ivanhoe, Rob Roy, and later the small Hamish fields, there was no spare capacity on board AH001. Amerada's fields are in decline, however, so there is now room for Renee/Rubie.

Phillips had considered stand-alone development of Renee and Rubie using a floater, but opted instead for a subsea tie-in to the AH001 vessel. Now Phillips is working towards first oil in October 1998.

A phased development is envisioned. For the first year, one production well and a water injector will be used in Renee, along with a single producer in Rubie.

Depending on the first year's production results, a second producer and a second water injector will be brought into operation in Renee. The Rubie wellhead will be connected to a manifold in Renee by a 5-km, 8-in. pipeline.

The Renee manifold will be tied back to AH001 through two 21-km, 8-in. oil pipelines, two 8-in. water injection lines, and a 4-in. gas lift/service line umbilical.

Norwegian projects

Saga Petroleum AS, Sandvika, Norway, reported test results for an appraisal well to Kristin discovery on Norwegian Sea Block 6406/2.

The 6404/2-3 well was drilled to vertical depth of 5,258 m by Transocean Arctic semisubmersible rig operating in 396 m of water.

The well flowed 31 MMcfd of gas and 5,300 b/d of condensate from its deepest pay zone and 26.5 MMcfd of gas and 6,000 b/d of condensate from a shallower pay through a 44/64-in. choke. Results strengthen expectations that Kristin will be commercial. This summer, Saga plans to drill an appraisal well in the southeast part of Kristin.

Saga is also to study feasibility of building a joint pipeline to export light oil from Kristin and nearby Lavrans. The pipeline under consideration would take liquids from these fields; from Aasgard field, currently under development; and Tyrihans, which is being considered for development.

The pipeline would be the first oil export pipeline from this recently opened area and could help make other discoveries in the Haltenbanken region viable for development.

In the Barents Sea off northern Norway, Statoil plans to acquire 3D seismic data over Snoehvit discovery. Geco Beta survey vessel will gather data to aid compilation of a development plan.

Snoehvit has estimated reserves of 5.3 tcf of gas and 115 million bbl of liquids. It has not been developed because of remoteness from markets. Statoil is contemplating a subsea development, with a multiphase pipeline carrying output to an onshore processing and liquefaction plant (OGJ, Oct. 21, 1996, p. 22).

Meanwhile, Norsk Hydro is preparing for further development work in Troll field (see related article, p. 66).

The operator let two contracts for subsea equipment for Troll C platform, due to begin producing oil from the giant Norwegian field's central gas province in September 1999.

Under a 104 million kroner ($14.2 million) contract, the Rockwater AS/Saipem SpA joint venture will transport and install 14 templates and five riser bases, to be installed during 3 years beginning in 1998 by Maxita or Regalia crane vessels.

Also, Hydro let a 111 million kroner ($15.2 million) contract to DSND Subsea AS of Grimstad, Norway, to build and install 16 anchors and to tow out and moor the semisubmersible platform. This will take place in 1999.

U.K. projects

In June, Marathon Oil U.K. Ltd. unveiled an oil discovery on U.K. North Sea Block 16/6b, with a well drilled to 7,150 ft total measured depth that cut 107 ft of net oil pay in Tertiary sands.

The well was drilled roughly 10 km northwest of Marathon's West Brae field but was suspended without testing. Marathon said it plans to appraise the find later this year or in 1998.

ARCO British Ltd. developed Bladon discovery on U.K. North Sea Block 16/21d as a single well tied back to its Blenheim field 5.3 km to the south. Bladon has estimated reserves of 4.5 million bbl of oil and was due on stream in mid-July.

Blenheim was developed with Petrojarl 1 FPSO (OGJ, Apr. 17, 1995, p. 27). Bladon production will boost Petrojarl's throughput to 18,000 b/d. Blenheim produces through three wells. Production fell from a peak of 34,000 b/d, but addition of Bladon output will extend Blenheim field life enough to yield a further 1.5 million bbl of oil.

Among completed developments, Wintershall (U.K.) Ltd. began gas production from Windermere field on U.K. North Sea Block 49/9b. The field was developed with an unmanned tripod wellhead platform tied back to nearby Markham ST1 satellite platform.

From there, gas is exported via J6A platform in the Dutch sector to Den Helder terminal, Netherlands. Daily operation of Windermere will be carried out by Markham and J6A operator Lasmo Nederland BV. One well is currently producing. A second and final well is being completed this summer.

Shell/Esso began oil production from U.K. North Sea Block 21/30 Gannet F field on June 23. Gannet F has estimated reserves of 19 million bbl of oil and is expected to produce as much as 12,000 b/d of oil.

It was developed in conjunction with Gannet E structure, due to come on stream in August, as a subsea satellite tie-back to Gannet A platform 11 km away (OGJ, Aug. 26, 1996, p. 28).

Shell/Esso expects to develop the fields for £80 million ($128 million), £10 million ($16 million) less than the original budget.

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