Offshore Northern Europe Last North Sea Giant Platforms Top Northwest Europe's Action
David Knott
Senior Editor
This year some of the largest oil and gas production platforms ever built have been towed out from construction yards and installed in North Sea fields.
They can be viewed as the last projects from an age of splendor in North Sea offshore engineering.
In their wake, several major developments have been lined up on both sides of the North Sea. These later designs are more prosaic, showing that the age of cost efficiency is here to stay.
Increasingly, new development plans depend on use of existing infrastructure or on new designs and working practices to keep development costs low.
This is a symptom of maturity of the North Sea as an oil and gas province, although new opportunities exist. Norway, the U.K., Denmark, and Ireland have all offered new acreage for exploration this year.
The giants
The big platforms towed out this year include what may become the last of Norway's concrete giants.
Troll A
The 430 m tall, four-legged concrete platform was towed at a speed of 1-2 knots by 10 tugs. During the journey the platform had a freeboard of 142 m. Bad weather delayed the 180 mile tow for several days.
Eventually the 1.05 million metric ton platform was maneuvered over its intended resting place, and ballast water was pumped in to drive its 19 skirt piles 36 m into the seabed.
Drilling of 40 production wells began in June, with completion due by the end of 1997. First gas is slated for Apr. 1, 1996.
The platform is expected to produce 30 tcf of the field's 46 tcf of gas reserves in the eastern end of the massive Troll reservoir.
Troll B
While the Troll A platform was on its way to East Troll, a massive concrete semisubmersible was being prepared for towout to handle oil production from western Troll.
Operator for West Troll development is Norsk Hydro AS. When Hydro set out to develop West Troll, reserves were estimated at 420 million bbl of oil. A thin oil layer in the West Troll gas province was then thought unviable.
Hydro opted to develop West Troll with the largest catenary moored production semisubmersible ever built. The unit weighs 190,000 metric tons.
Eight production wells have been drilled, so the Troll B platform will be able to reach plateau production of 190,000 b/d of oil within a few weeks of first flow, scheduled for Oct. 1.
On July 5, Hydro reported that Troll B had begun a 30-36 hr towout to its intended position in Block 31/2 off Norway. Nine tugs were used.
Anchoring in the field was complete in mid-July, after which tensioning began of 13 preinstalled risers for production, gas injection, and oil and gas export.
The Troll B platform's journey and mooring passed without major mishap. Earlier, however, installation of the oil export pipeline from West Troll had run into problems.
In June Norway's Den norske stats oljeselskap AS (Statoil), operator of the Troll oil export pipeline project, had to restart laying an oil pipeline from Mongstad terminal to the field after the first section of pipe was dropped from the lay barge.
A mechanical fault in a safety clamp on the Castoro Sei lay barge, which should have secured the pipe on the vessel, was said by Statoil to have been the likely cause.
Pipe-laying had reached 1.3 km from shore when a 500 m section of pipe was dropped in a loop outside the pipeline route. The line has to be cut close to the landfall point and retrieved before laying can begin again.
Statoil said the repair would take about 2 weeks and will not delay start-up of Troll field oil exports. The 16 in. pipeline will be 86 km long and will lie deeper than any other Norwegian installation, reaching 540 m in parts.
In late June Hydro announced a plan to develop the thin oil zone in West Troll's gas province. This plan effectively doubled estimates of West Troll's oil reserves to more than 1 billion bbl.
Hydro will drill as many as 54 horizontal wells in the gas province's 13 m thick oil layer. Oil wells in the north of the province are expected to be produced via a new production semisubmersible, smaller than Troll B.
Wells in the southern sector of the province would be tied back via a number of subsea manifolds to the Troll B platform. Hydro intends to submit a development plan for oil in the gas province during 1996, with a view to starting production in 1999.
Heidrun
Around the time Troll A was being towed out, Norske Conoco AS was christening the world's first concrete tension leg platform (TLP) in preparation for towout to Heidrun field in the Norwegian Sea.
Block 6507/7 Heidrun field is industry's northernmost offshore oil and gas field development. Production from the 220,000 metric ton platform is expected to begin in August from wells drilled prior to installation.
Heidrun reserves are estimated at 750 million bbl of oil and 1.6 tcf of gas. Peak production of 200,000 b/d of oil is expected to be reached this year.
Installation of the Heidrun unit also had its problems. On May 3 Conoco dropped the second of 16 TLP tethers.
The 270 m long tether was being towed to the field when straps holding buoys at either end of the tether gave way. The tether had to be laid on the seabed for later recovery.
Conoco installed a spare tether and used buoys to refloat the sunk unit, which it towed to Norway for tests.
Key projects
While the three Norwegian giant developments were entering the countdown to first production, the U.K. and Norway announced progress on further major field development plans.
West of Shetland
BP Exploration Operating Co. Ltd. announced June 14 that it had let a 14 million ($21 million) contract to Atlantic Frontier Alliance to begin design and engineering work for a production ship for Schiehallion field.
Schiehallion will be BP's second development in the U.K. West of Shetland hot spot. First oil is slated for late 1997.
The development concept is similar to that of Fionaven field, which will use a floating production storage and offtake unit linked to clusters of subsea wellhead manifolds. Export will initially be by shuttle tankers.
Schiehallion development will involve a new unit. The tender proposal for the Schiehallion production ship anticipates capacity to produce and store up to 225,000 b/d of oil, to a maximum 970,000 bbl cargo. Gas treatment capacity is specified as 400 MMcfd.
The contractors' alliance comprises Brown & Root Ltd. of Aberdeen, Single Buoy Moorings Inc. of Marly, Switzerland, and Harland & Wolff Ltd., the Belfast shipyard, which will build the vessel.
Colin Maclean, manager of programs at BP Exploration, said Schiehallion development will cost 750-1,000 million ($1.2-1.6 billion). Schiehallion field has reserves of 250-500 million bbl of oil.
An extended well test is under way in Schiehallion, with a semisubmersible rig producing 20,000 b/d of oil into a shuttle tanker. A similar test will be performed later this year of the Clair discovery.
Njord Field Development (99569 bytes)
Njord
In early June Norsk Hydro let contracts for subsea equipment and a storage tanker for development of Njord field in the Norwegian Sea.
The company will develop Njord with a semisubmersible, which will produce from 10 wells into a tanker moored 2.5 km away (see figure).
Block 6407/7 Njord field has estimated reserves of 220 million bbl of oil and 5 billion cu m of gas.
A Norsk Hydro official said development cost will be 5.9 billion kroner ($890 million). Hydro has slated first production for Oct. 1, 1997, but this depends on quick government approval of the development plan.
In March Hydro let contract to Aker AS, Oslo, to build the production unit according to its P45 concept. The rig will have capacity to produce 65,000 b/d of oil and 10 million cu m/day of gas (OGJ, Mar. 27, p. 31).
In May Hydro let a 330 million kroner ($50 million) contract to Kvaerner AS, Oslo, for subsea christmas trees and control and hook-up systems for the wells. Delivery will start in May 1996.
The operator also signed a letter of intent for construction by Finland's Kvaerner-Masa Yards Oy of a tanker to store up to 690,000 bbl of crude oil. The contract is worth 470 million kroner ($70 million).
Kvaerner said offloading into shuttle tankers will be through a flexible hose in the storage tanker's stern. Offloading will occur at rates up to 8,000 cu m/hr.
The storage unit will be unmanned during normal operation. A crew will land by helicopter to offload the cargo every 10 days.
The Hydro official said three production wells will be drilled in the field next year, ahead of installation of the floater. A drilling rig will be chartered early next year.
Twelve wells will be drilled from the platform. Full development of Njord will require 10 producers, four gas injectors, and a water injection well.
The official said some of the wells will have U-shaped profiles, while most will have horizontal sections to maximize production from Njord's complex reservoir.
Aasgard
This year Statoil and Norwegian independent Saga Petroleum AS have been progressing development of three oil and gas fields in the Norwegian Sea, which are seen as key to opening the gas reserves of the area.
Aasgard development will bring onto production three fields: Smoerbukk and South Smoerbukk in Block 6506/12, and Midgard in Block 6407/2.
In March Statoil hiked its estimate of oil reserves in the Smoerbukk discovery, based on results of an appraisal well, to 553 million bbl from 289 million bbl earlier.
This took estimated total reserves for the Aasgard development to 792 million bbl of oil and 198 billion cu m of gas. The reserves hike did little to change the development proposal, for which Statoil was studying floaters and fixed platforms for a two platform development (OGJ, Jan. 23, p. 17).
In June Statoil announced oil production in Aasgard will be handled by a production ship. A decision on whether to produce gas through a concrete gravity base platform or a production semisubmersible has yet to be made.
Oil production is expected to begin in October 1998 from 20 wells, reaching a peak of about 220,000 b/d. Depending on a gas sales contract, gas production is expected to start in October 2000 at a rate of 12 billion cu m/year.
A total of 61 wells is planned for Aasgard: 41 in Smoerbukk field and 10 each in South Smoerbukk and Midgard. A pilot production well will be drilled next year to help fine-tune drilling plans for Smoerbukk, said to be a complex reservoir.
ETAP
In June BP Exploration let first contracts leading to development of seven North Sea oil and gas fields under its Eastern Trough Area Project (ETAP).
The seven fields have total estimated reserves of 400 million bbl of oil, 65 million bbl of natural gas liquids, and 1.45 tcf of natural gas. Peak production is expected to be 200,000 b/d of oil and 580 MMcfd of gas.
ETAP involves development of BP's Mungo, Marnock, Machar, and Monan discoveries and the Heron, Skua, and Egret finds of Shell U.K. Ltd. Total development cost is expected to be more than 1 billion ($1.6 billion).
BP first announced plans to develop ETAP fields, which lie in the southeast corner of Quadrant 22 and in Quadrant 23, in May 1993. First production is slated for fourth quarter 1998.
Two years ago BP's Medan and Shell's Scoter discoveries were listed as development prospects (OGJ, May 17, 1993, p. 18). A BP official said these were not in the current development plan but could be brought in later.
The development will comprise two small steel platforms in Block 22/24a Marnock field, one for processing and one housing utilities and accommodation, and an unmanned satellite platform in Block 23/16a Mungo.
Machar, Monan, Heron, Skua, and Egret fields will be developed with subsea production manifolds tied back to Marnock platform.
A BP spokesman said oil will be exported from Marnock to the Forties pipeline system tie-in on the Unity platform.
Gas export options were said to include a new pipeline to St. Fergus terminal north of Aberdeen, for which BP has started talks over landfall sites, and the Central Area Transmission System (CATS) pipeline operated by Amoco (U.K.) Ltd.
BP began a 10 month production test in Block 23/26a Machar field in 1994 by means of a subsea wellhead tied back to a semisubmersible rig converted for production.
Oil was produced directly into a shuttle tanker, and production was stopped while the tanker was away. The official said 7 million bbl of oil was produced from Machar during the trial (OGJ, May 23, 1994, p. 26).
BP has been involved in continuous discussions with U.K. Department of Trade & Industry over the development plan. The official said ETAP partners will seek approval of the development plan toward the yearend.
On June 15 BP announced contracts worth "tens of millions of pounds" for early design and engineering work on ETAP.
"We are awarding pre-sanction contracts now," said Dr. Chris Gibson-Smith, chief executive of BP Exploration Europe, "so that ETAP teams can work with contractors to establish firm costs prior to any development decisions being taken, and to allow us to form a risk-reward alliance."
BP was equal partner to operator Texaco Ltd. in a plan to develop Erskine field in Block 23/26a, which lies near Machar.
The BP spokesman said Erskine development had never been considered under the ETAP plan because Erskine is a high temperature/high pressure reservoir requiring special platform technology.
Erskine has estimated reserves of 330 bcf of gas and 75 million bbl of condensate. It will be developed with an unmanned platform tied back to Amoco's Lomond platform. Gas will move via CATS and liquids through Forties.
Britannia
In July Chevron U.K. Ltd. and Conoco (U.K.) Ltd. announced that gas from North Sea Britannia field, the U.K.'s largest undeveloped gas field, will be piped to St. Fergus terminal near Aberdeen for processing.
The Scottish Area Gas Evacuation (SAGE) terminal at St. Fergus, operated by Mobil North Sea Ltd., will be expanded in a 70 million program in readiness for first Britannia gas in fourth quarter 1998.
Britannia has estimated reserves of 2.6 tcf of gas and 140 million bbl of condensate and natural gas liquids. Peak output is expected to be 740 MMcfd of gas and 70,000 b/d of condensate. Field life is put at 30 years.
Gas will be exported to the SAGE terminal through a new 200 km pipeline to be installed during 1996-97. Condensate will be sent ashore via the Forties pipeline system operated by BP.
At the SAGE terminal, Britannia gas will be separated into sales gas and NGLs, said Chevron. NGLs will be sent for further processing in either the BP or Shell U.K. Exploration & Production pipeline systems, for which negotiations are under way.
Jim Briggs, Britannia development director, said project partners will pay a competitive tariff giving long term use of the SAGE terminal for Britannia and any future gas satellites.
New facilities at the terminal will include a bypass train, which will add more than 740 MMcfd throughput capacity to the current 1.15 bcfd capacity of SAGE's two process trains.
Britannia field is centered on Block 16/26, where a steel drilling, production, and accommodation platform will be installed. A subsea production center will be tied back to the platform, and a second subsea center may be added.
The Sedco 711 and Sovereign Explorer semisubmersibles are currently drilling development wells in the field. The 711 is drilling nine through a template on the platform site, and Explorer is drilling eight at the site of the subsea center.
Chevron and Conoco have a tight timetable for Britannia development and hope to complete pre-drilling work 20% faster than for the best appraisal drilling project on record.
Key to this plan is cooperation between crews of the two rigs, according to Sovereign Explorer's Operations Engineer Scott McLeod.
"The team was able to perfect the technique of batch setting to a depth of 2,500 ft on all 17 wells," said McLeod. "This meant concentrating on continuous improvement."
Interconnector
In early June the European Commission approved a plan to build a 440 million ($660 million) gas pipeline from the U.K. to Belgium, which is intended to lead to first exports of Britain's gas to continental Europe.
Next stage in approval of the project will be a pipeline treaty between the British and Belgian governments.
Philip Nolan, managing director of Interconnector (U.K.) Ltd., the company created by partners to manage the project, said he hoped a treaty would be finished soon.
Construction of the Interconnector is to begin in winter 1996. The 240 km, 40 in. line will run from Bacton, U.K., to Zeebrugge, Belgium. First gas throughput is scheduled for October 1998.
Nolan said the company has identified sites for terminals in both countries. He hoped planning applications to local authorities would be well under way by yearend.
The Interconnector is unusual for Europe's gas industry because companies had to commit to the project before sales contracts were fixed, said Nolan.
Nine companies booked a total of 20 billion cu m/year of gas throughput in the Interconnector, with British Gas plc having the largest share at 40% (OGJ, Dec. 19, 1994, p. 26).
Wood Mackenzie Consultants Ltd. raised doubts about the viability of the project earlier this year. The analyst said high U.K. gas prices and lack of third party access by British gas firms to continental pipelines would curb potential exports of U.K. gas (OGJ, Apr. 3, Newsletter).
In-field projects
Conoco announced a plan to invest 85 million ($125 million) in a new compression platform to bring throughput capacity of the U.K. North Sea Caister Murdoch complex to 750 MMcfd of gas.
This will enable Conoco to handle third party processing, in addition to handling up to 300 MMcfd of gas from Caister and Murdoch fields, which came into production in October 1993.
The new platform will be a four-legged steel structure housing two 38,000 hp compressor modules and with room to add a second compression unit. It will be installed in summer 1996, 40 m southwest of Murdoch platform and linked by a bridge.
Conoco said the new capacity will enable the system to handle gas from Shell's Schooner field when it comes on stream in second half 1996.
Also, Conoco has reached agreement in principle with Shell to transport gas from its nearby Ketch prospect. Other potential customers were said to be Conoco's own Boulton discovery and Hunter discovery operated by Total Oil Marine plc, Conoco's partner in the Caister Murdoch development.
In other action, Lasmo Nederland BV began to drill a deviated well from its Markham field platform in Dutch offshore Block J6-A to test a nearby gas prospect known as J3a-Charlie. The Neddrill 9 jack up spudded the well from J6-A platform on June 19. Lasmo and Block J3a license partner Elf Petroland BV have agreed that any commercial discovery would be produced via the J6-A platform. Lasmo is pursuing other third party developments in the Markham area.
In mid-June Amoco Norway Oil Co. let a 330 million kroner ($53 million) contract to Heerema Offshore Construction Group Inc., Geneva, for engineering, procurement, construction, and installation of a steel wellhead platform in Valhall field. The new platform will be bridge-linked to the existing Valhall processing platform and will enable Amoco to deplete the outer edges of the reservoir. The platform will be delivered in May 1996 and is to be producing early in third quarter 1996.
The abandonment issue
In late June, Elf Petroleum Norge AS issued calls for tender to dispose of a steel and concrete tower, which will be the first abandonment of a Norwegian offshore installation.
Northeast Frigg field was developed by Elf with a six wellhead subsea manifold and an articulated control tower placed 150 m away from the manifold. It was shut down in May 1993 (OGJ, Mar. 20, p. 31).
Elf intends to deballast and tow ashore the control tower and lift the tower's foundations and the subsea installations. The tower and foundations will be stripped of all metals, and remaining concrete will be dumped.
The operation will take place next summer, but Elf expects there to be no environmental backlash because, while 7,000 metric tons of concrete from the tower will be dumped, the 4,700 metric tons of steel from the tower and 1,000 metric tons of steel from the subsea equipment will be recycled.
Elf Petroleum Norge AS says the disposal plan was approved by parliament in May, before the Brent Spar issue arose.
In the U.K. sector, operator Shell U.K. Exploration & Production hit major problems with environmental action group Greenpeace over plans to dump the derelict Brent Spar loading buoy in deep water off Northwest Britain this summer.
Shell aborted its disposal plans in the face of mounting protests against Shell gasoline stations in Europe and pressure from the German and Dutch governments.
The climbdown was not appreciated by the British government, which indicated that Shell would have to work hard to persuade it that onshore disposal is a better option, having already persuaded it to accept dumping (OGJ, June 26, Newsletter).
The spar arrived in Norway's Erfjord on July 11 for temporary mooring. Shell will now review abandonment options and consider new offers for disposal.
In the light of the Brent Spar furor, Wood Mackenzie Consultants Ltd., Edinburgh, has calculated that onshore abandonment of U.K.'s giant steel platforms would cost 2 billion ($3.2 billion) more than partial removal.
Wood Mackenzie said Shell's attempt to dump Brent Spar brought the issue of abandonment into public focus. The analyst reckons Shell's about turn in the face of consumer and political pressure from continental Europe could impact decommissioning of other North Sea installations.
"Shell U.K.'s decision to forgo tax allowances for any expenditure incurred additional to the original deepwater disposal plan could set an uncomfortable precedent," said Wood Mackenzie.
"Government could arguably approve a low cost decommissioning plan on the basis that the companies' preferred options might have undue regard to a company's public image. In this manner government could seek to reduce the tax rebate liabilities of the abandonment program."
Wood Mackenzie calculates that 7.4 billion ($11.8 billion) in 1995 terms, or 12.8 billion ($20.5 billion) in money of the day terms, will need to be spent to decommission the U.K.'s fields in production and yet to be developed.
This estimate is based on application of International Maritime Organization rules, which require 55 m of clear water above any dumped structures.
Of the U.K.'s 219 offshore platforms in place, Wood Mackenzie said 160 will have to be completely removed as they either lie in shallow water or weigh less than 4,000 metric tons.
The remaining 59 platforms could be partially removed to give 55 m clearance with the substructure stump left in place. Ten of these platforms were said to have concrete substructures.
"Applying an indicative incremental cost, for full rather than partial abandonment, of 40 million to each of the 49 large deepwater steel platforms could add 2 billion to costs imposed on upstream companies."
Licensing
In early July, the U.K. Department of Trade & Industry awarded 53 new blocks under its 16th offshore exploration round, taking the overall number of blocks awarded under the round to 79.
Twenty six blocks in the West of Shetland exploration hot spot were awarded in May, so companies could plan and implement exploration programs during this year's weather window (OGJ, May 29, p. 24).
Announcing the awards, Richard Page, junior minister for energy, said the latest licenses are for acreage in the North Sea and to the west and south of Britain.
"Today's awards will result in the shooting of more than 3,500 sq km of 3D seismic surveys," said Page, "and more than 4,000 line km of 2D seismic surveys.
"Companies have also committed themselves to drill 13 wells in the next 2 years and a further nine during the rest of the 6 year phase of the licenses. In the whole round, 7,500 sq km of 3D seismic surveys will be carried out and 50 new wells drilled (OGJ, July 17, p. 21)."
Nineteen oil companies have applied for exploration acreage in Norway's 15th round of offshore licensing, which closed for applications on June 20.
"Applications have been submitted for all areas that were announced," said Minister of Industry & Energy Jens Stoltenberg, "although the interest has been especially focused in new exploration areas in the Voering and Moere basins in the Norwegian Sea."
The ministry said deep water and new geology were the challenges in these westernmost parts of the Norwegian Sea, while the challenge in Haltenbanken blocks nearer to shore is management of the total resource base.
For North Sea acreage the challenge was said to be to phase in new discoveries with available capacity in existing infrastructure.
The ministry said negotiations with companies will start in early autumn, with a view to awarding production licenses around yearend.
In mid-July, the government of the Isle of Man, which lies halfway between Britain and Ireland in the Irish Sea, awarded licenses to explore six offshore blocks under its first licensing round.
Blocks 112/13, 14, 15, 19, and 20 to the north of the island were awarded to operator Elf Exploration U.K. plc 35%, Enterprise Oil plc 35%, and Amerada Hess Ltd. 30%.
Block 112/29, which lies southeast of the island, was awarded to operator Marathon Oil U.K. Ltd 40%, Phillips Petroleum Co. U.K. Ltd. 40%, and Seagull U.K. Ltd. 20%.
An Elf official said the company plans to acquire seismic data this year and intends to drill one well on the acreage it operates during 1996.
Marathon Exploration Manager Bob Piotrowski said his company's block adds to a portfolio of acreage west of Britain. The company discovered gas off South Wales last year and is planning further drilling off Southeast Ireland.
A Marathon official said the company plans to drill a wildcat in 1996 and expects to acquire seismic data on the block this year. In April, Denmark's Ministry of Environment & Energy awarded nine exploration licenses covering 40 North Sea blocks to seven groups involving 16 companies (OGJ, Apr. 24, p. 42).
Eased licensing terms were intended to attract new companies to Denmark, and the ministry claimed the move was a success: "Licensees see potential for discoveries ranging from a few million bbl of oil equivalent to about 1.1 billion bbl of oil equivalent."
In March, Ireland's government announced award of eight exploration licenses covering 32 blocks in the Porcupine basin off western Ireland. The awards represent a return to Ireland for the majority of the recipients.
New licensing terms, coupled with geologists' recent study of new plays in areas which have so far showed poor drilling results, have raised the level of excitement about Irish prospects not seen since the 1960s (OGJ, June 5, p. 17).
Outlook
Twenty years ago on June 18, the first U.K. offshore oil was landed at Isle of Grain refinery, Kent. Tim Eggar, minister for Industry & Energy, said: "Since then over 1.8 billion metric tons of oil have been produced. Production is already greater than the 1975 total proven reserves of 1.3 billion metric tons."
The Department of Trade & Industry reckons U.K. offshore production to date represents one fifth of estimated maximum reserves. Hamilton Oil, subsequently BHP Petroleum Ltd., produced Britain's first offshore oil from North Sea Block 30/24 Argyll field. Argyll was developed with the world's first production semisubmersible rig and ceased production in 1993.
The outlook for Britain's oil industry is still good, according to Aberdeen-based Grampian Regional Authority, which published a report claiming that 100 new fields could be developed off the U.K. in the next 15 years.
Eighty-one oil and gas fields have been developed off the U.K. to date, said the council, and 17 more are due on stream in the next 4 years.
"Even with a conservative oil price forecast," said the council, "a further 80 fields are still forecast to be developed over the next 15 years."
The council said many fields will be developed by means other than fixed platforms over the next 10 years. Single wells, subsea manifolds, and floating production facilities capitalizing on the North Sea's mature infrastructure were listed as options to platforms.
"Most future fields will have substantially smaller reserves than those now in production," said the council. "Britain should be self-sufficient in oil until the turn of the century."
Wood Mackenzie calculated earlier this year that Norway could have 22 new oil and gas developments in production by the end of 2000, during which year they could yield 1.26 million b/d of oil and 2.86 bcfd of gas.
Norway's North Sea sector will see the bulk of the new developments, said the analyst, but the Norwegian Sea holds some of the most interesting prospects, including Norne, Njord, and Aasgard (OGJ, May 1, p. 50).
Norsk Hydro beginning to tow its Troll B concrete semisubmersible platform from Hanoeytangen toward its location in West Troll field in Block 31/2 off Norway. The platform was anchored in mid-July prior to tensioning of 13 preinstalled risers for production, gas injection, and oil and gas exports. Photo courtesy of Norsk Hydro.
The 85,000 metric ton concrete gravity structure for BP's Harding platform left Scotland's Hunterston yard in late April. A production jack up will be installed on top of the base to give a platform capable of producing 64,000 b/d of oil and storing up to 500,000 bbl. Photo courtesy of BP Exploration.
The 430 m tall Troll A platform, with a 142 m freeboard during towout by Norske Shell, was described as the largest object ever moved. Photo courtesy of Norske Shell.
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