Northwest Europe's Offshore Activity Still Brisk Despite Mandated Slowdown In Norway

Aug. 17, 1998
The Thialf crane barge installs a central processing platform on U.K. North Sea Block 22/24a as part of BP's Eastern Trough Area Project (ETAP). Photo courtesy of BP. The Swan transportation barge, operated by Dockwise NV of Meer, Belgium, in April carried the Siri field storage tank from a Korean shipyard to Stavanger for outfitting. Norway's Statoil is developing Denmark's Siri field with a production jack up platform mounted on the 14,500 ton storage tank. Photo courtesy of
David J. Knott
Senior Editor
The Thialf crane barge installs a central processing platform on U.K. North Sea Block 22/24a as part of BP's Eastern Trough Area Project (ETAP). Photo courtesy of BP.
Northwest Europe's offshore operators remain busy despite a mandated slowdown in Norway.

While currently low oil prices have led some operators to talk of possible project deferrals, fabrication yards and drilling rigs are working flat out, forcing Norway's government to put a freeze on new projects.

Early in the year Norway deferred 12 oil field developments and reduced oil exports as part of a plan to buoy crude prices, but these are not expected to hold back a production boom for long (OGJ, Mar. 16, 1998, p. 34).

Wood Mackenzie Consultants Ltd., Edinburgh, said the cutbacks won't inflict lasting damage on Norway's oil industry.

The analyst said some production will be lost this year because of development delays caused by overly ambitious time and cost targets, heavy contractor workloads, and unexpected fabrication and reservoir problems.

Aasgard, Varg, and Tordis ist have all been hit by development delays, while Norne and Njord, which were brought on stream in late 1997, have suffered start-up problems.

Norne production was halted for several weeks after operator Statoil AS discovered that installed skimmers were inadequate for water conditions in the field. Norsk Hydro AS experienced problems with development drilling in Njord.

"Although several development programs have suffered serious delays," said Wood Mackenzie, "total oil and natural gas liquids production has been maintained on a par with end-1997 output (almost 3.3 million b/d).

"This is a result of better than expected production performance from mature fields, particularly Ekofisk, where output has recently been increasing. Despite the delays, production is expected to increase strongly towards the end of the year, mainly as a result of increased production from Norne and Njord, and several of the delayed developments coming on stream."

Production peaks

The U.K., Norway, and Denmark are expected to post record average oil production levels this year, while the decline of production offshore the Netherlands is set to continue.

Wood Mackenzie reckons total oil production offshore Northwest Europe will average 6.57 million b/d in 1998, compared with 6.08 million b/d in 1997.

The analyst anticipates U.K. oil production will reach a record 2.84 million b/d on average this year, a rise of 310,000 b/d on last year. This includes roughly 100,000 b/d for onshore production, mainly from Wytch Farm field.

Twenty-two U.K. fields are expected to be brought on stream in 1998, contributing about 160,000 b/d to oil production.

Norwegian oil output, too, is expected to reach a new high average in 1998: 3.44 million b/d, compared with 3.3 million b/d in 1997.

Denmark's oil production will rise to a record 257,000 b/d in 1998 from last year's 231,000 b/d. Dutch offshore oil production averaged 31,000 b/d in 1997 and is anticipated to fall to 29,000 b/d this year.

New developments

Once again, U.K. operators have been the most active in preparing new field developments, mainly of small accumulations.

In January Mobil North Sea Ltd. let a £10 million ($16 million) contract to Odebrecht-SLP Engineering Ltd., Lowestoft, U.K., to build a production platform for Malory gas field in the southern North Sea.

The platform will be an 860 metric ton minimum-facilities structure tied back to Mobil's Lancelot field export pipeline to Bacton terminal, where produced gas will be processed. First gas production from Malory is expected in October 1998 at a rate of 45 MMcfd.

ARCO British Ltd. received U.K. Department of Trade & Industry (DTI) approval to develop its Waveney gas discovery on North Sea Block 48/17c.

The field will be developed with a minimum-facilities platform tied back 8.2 km to the Lancelot export pipeline to Bacton terminal, Norfolk. ARCO let contract for an undisclosed sum to SLP Engineering Ltd., Lowestoft, U.K., to build the platform according to the Sea Harvester design.

In March a U.K. joint venture of Amerada Hess Ltd., Shell U.K. Exploration & Production, and Texaco North Sea U.K. Co. received DTI approval for a combined development of Bittern, Guillemot West, and Guillemot Northwest fields.

Bittern straddles blocks operated by Amerada and Shell, while Guillemots West and Northwest are operated by Texaco. The fields will be developed with a floating production, storage, and offloading (FPSO) vessel (OGJ, Nov. 17, 1997, p. 32). First oil is expected in third quarter 1999. Plateau production is anticipated to be 100,000 b/d of oil.

In May Mobil secured DTI approval for a £150 million ($240 million) development of its North Sea Block 9/18 Buckland discovery. The find will be developed as a subsea satellite of Beryl A platform, with three production wells and two water injectors.

First oil and gas are anticipated in October 1999. Mobil said Buckland production is expected to reach 40,000 b/d of oil equivalent. Buckland's reserves are believed to be 30 million bbl of oil and 29 bcf of gas.

Also, Marathon Oil U.K. Ltd. agreed to process and transport crude oil from Larch field, to be developed by Lasmo plc, on its Brae A platform on U.K. North Sea Block 16/7.

Larch will be developed as a subsea satellite of Brae and will be the 14th third-party field to use Brae facilities. Larch, due on stream later this year, is expected to produce up to 17,000 b/d of oil and 12 MMcfd of gas.

Crude oil and natural gas liquids will be exported through the Brae-Forties pipeline to Cruden Bay, north of Aberdeen, while gas will be exported through the Scottish Area Gas Evacuation pipeline to St. Fergus terminal, also north of Aberdeen.

In May, Amerada Hess received DTI approval to develop the Flora discovery on North Sea Blocks 31/26a and 31/26c. License partner Premier Oil plc, London, said the pre-Cretaceous formation lies 8.5 km north of Amerada's Fife field.

Flora will be developed as a subsea satellite of the Uisge Gorm production, storage, and offloading ship, which is producing from Fife and Fergus fields. Development will require two horizontal production wells, tied back to the ship through a thermally insulated pipeline, and a vertical water injector. First oil is anticipated in October 1998, and peak production is expected to be 20,000 b/d.

In June, Saga Petroleum AS persuaded the government to lift its delay on Snorre B development, enabling the company to place contracts.

Saga let contracts amounting to 7.5 billion kroner ($1 billion) for the platform, subsea production equipment, infield flow lines and risers, and laying of export pipelines. Under the revised schedule, first oil is now anticipated in August 2001.

Saga let a 5.5 billion kroner ($730 million) contract to Kvaerner Olje & Gas AS and Aker Maritime AS, both of Oslo, for engineering, procurement, and construction of the semi, which will have capacity to produce and process 11,000 b/d of oil.

The subsea production contract was let to ABB Offshore Technology AS, Oslo, valued at 1.2 billion kroner ($160 million). The subsea development will comprise 27 wells producing through four manifolds.

Infield flow lines and risers will be provided by Coflexip Stena Offshore Norge AS, Stavanger, under a 475 million kroner ($65 million) contract, while European Marine Contractors Ltd., London, will lay an export pipeline under a 250 million kroner ($35 million) program.

New finds

Operators in both the U.K. and Norway have disclosed discoveries this year, with a Norwegian Sea strike by Amoco Norway Oil Co. appearing to be the biggest.

In January, ARCO announced test results for a gas discovery well on U.K. North Sea Block 14/26a. The 14/26a-6 well flowed more than 40 MMcfd of gas at a flowing tubing pressure of 1,800 psi. ARCO said flow rates were limited by surface facilities.

Tom Murphy, ARCO's development engineering manager, said: "We have further work to do to quantify the discovered reserves size, but the find is expected to be significant. We aim to drill an appraisal well as soon as practical in 1998."

At the same time, Esso Norge AS disclosed test results for a well on Block 16/7 in the North Sea off Norway. The 16-7-7S well flowed a maximum 556 cu m/day of condensate and 265,000 cu m/day of gas through a 44/64-in. choke. The find is 12 km southwest of Sleipner A platform. Esso said the reservoir lies at a vertical depth of almost 3,000 m in the Skaggerak formation.

In May, Monument Oil & Gas plc, London, disclosed test results from an appraisal well on Block 21/28a Fyne discovery in the U.K. North Sea. Monument said the 21/28a-8 well encountered 36 ft of oil and gas pay and flowed from a selected 15 ft interval at a rate of 1,080 b/d of 21.4? gravity oil through a 32/64-in. choke.

Monument plans to drill an appraisal well this year for the Pilot oil find on neighboring Block 21/27a, where it has a 32.5% interest.

License partners are considering joint development of Fyne and Pilot. Monument is operator and 75% interest holder in Fyne, with partner Halliburton Energy Development holding 25%.

Amoco announced its major Norwegian Sea oil strike in May. It reckons the field could have reserves of 200-500 million bbl of oil equivalent (boe).

Amoco drilled a rank wildcat on Block 6507/5, in a structure called Donatello between the producing Norne and Heidrun oil fields.

The Maersk Jutlander semisubmersible rig drilled the well in 327 m of water to a vertical depth of 4,198 m in an early Jurassic formation.

The operator said the 6507/5-1 well encountered more than 140 m of net oil and gas pay in Jurassic and Cretaceous formations. Three separate drill stem tests were run.

Two tests in Jurassic sands flowed at rates of 5,400 b/d of oil and 5.3 MMcfd of gas through a 1-in. choke and 1,120 b/d of condensate and 26.2 MMcfd of gas through a 40/64-in. choke.

The company said that while uncertainty remains as to the Donatello oil/gas ratio, preliminary estimates suggest reserves in the Jurassic formations alone could amount to 200-500 million boe.

The Cretaceous layer test produced 5,800 b/d of oil and 7.8 MMcfd of gas through a 36/64-in. choke. Amoco cut 300 m of core from the well. It said other prospects on the license area are being evaluated.

L. Richard Flury, president of Amoco's exploration and production division, said: "This is a very encouraging discovery, which may prove to be of great importance to Amoco in Norway as well as to Amoco Corp."

Block 6507/5 license interest holders are operator Amoco and Statoil 30% each, Enterprise Oil Norge AS 25%, and Mobil Exploration Norway Inc. 15%.

Work in progress

In January, Shell U.K. Exploration & Production chose a disposal plan for the Brent spar loading buoy after more than 2 years of controversy.

The operator submitted to DTI a proposal by the Wood-GMC consortium of contractors to dismantle the spar's hull in a Norwegian fjord and use pieces to build a quay extension.

The Wood-GMC proposal was one of six picked by Shell for detailed development from a list of 30 outline plans submitted by 19 contractors and consortia (OGJ, Jan. 20, 1997, p. 24).

The Wood-GMC proposal is to raise the spar slowly in the water so that the hull can be sliced into rings after topsides have been removed for scrapping.

Wood-GMC is a joint venture of Wood Group plc, Aberdeen, and Maritime GMC AS, Stavanger. The venture's disposal plan is estimated to cost £21.5 million ($34.5 million).

In February, BP Exploration Operating Co. Ltd. completed decommissioning of Donan field on U.K. North Sea Block 15/20 and brought subsea equipment to shore for recycling or reuse.

Donan yielded 15.3 million bbl of oil from April 1992 to December 1997. It was developed with two subsea producers tied back to the Seillean production, storage, and offloading ship.

Reading & Bates (U.K.) Ltd., Aberdeen, bought Seillean from BP in August 1996 and is seeking a new charter. Coflexip Stena Offshore Ltd., Aberdeen, plugged the two producers, cut their casing to below the seabed, and recovered wellheads using its Seawell construction ship.

In March, just as Phillips Petroleum Co. Norway neared completion of a massive redevelopment of Ekofisk field necessitated by seabed subsidence, the same problem hit another operator, though on a smaller scale.

Saga installed ten buoys on the Vigdis field subsea template as a temporary measure to stop its sinking in soft sand. The 260 metric ton manifold has been fitted with buoys attached with a remotely operated vehicle (ROV) to lifting points on the frame. Saga says the template is now stable but will be stabilized permanently during the summer.

Phillips expected to shut down Ekofisk in August to switch most of the field operations to two new platforms while earlier platforms sink below the 100 year wave safety height (see related story, p. 51).

In April BP completed installation of topsides for Eastern Trough Area Project (ETAP) platforms in the U.K. North Sea. The £1.6 billion ($2.6 billion) development involves seven fields with combined reserves of 400 million bbl of oil and 1.1 tcf of gas (OGJ, Jan. 22, 1996, p. 21).

A two-platform central processing facility was located in Marnock field, and a normally unmanned platform was placed in Mungo field. The other fields-Machar, Monan, Heron, Skua, and Egret-will produce through subsea manifolds tied back to the central processing unit. First production is expected in the summer.

In May, Statoil towed out a steel oil storage tank for installation on the seabed in Siri field offshore Denmark. Water depth is 65 m. The 315,000 bbl capacity tank was built in Korea and completed by Kvaerner Rosenberg AS, Stavanger.

A drilling shaft has been fixed to the top of the tank to accommodate drilling of production and injection wells by the Noble George Sauvageau jack up, which began in late May. The Siri platform is being built at the Rosenberg yard, scheduled for installation this autumn.

In June, Shell/Esso announced a plan to install two crude oil storage tanks on the seabed near U.K. North Sea Kittiwake platform on Block 21/18a.

Shell/Esso said DTI approved the plan, which is intended to reduce Kittiwake's downtime. Kittiwake oil is exported by shuttle tanker, and in bad weather the tanker has to move away from the loading buoy.

Two cylindrical tanks on a support frame, with capacity to hold a total of 19,000 bbl of oil-roughly half of Kittiwake's peak daily production-were to be installed this summer 70 m from the platform.

Water depth in Kittiwake field is 85 m. The tanks will be lifted into place by the Heerema Thialf crane barge (formerly DB 102). They are designed to be retrieved for recycling or reuse at the end of the field's life.

In June, Shell/Esso approached DTI for approval of onshore disposal of the Fulmar field loading buoy by a method proposed by Heerema Marine Contractors, Leiden, Netherlands.

The Heerema plan is essentially a reversal of the installation procedure, which it carried out in 1981, and was chosen from 12 onshore scrapping and reuse proposals submitted by five contractors.

The buoy is a 5,150 metric ton single anchor leg mooring unit, positioned on U.K. North Sea Block 30/11 during 1981-94 to load crude oil from Fulmar, Auk, and Gannet fields into shuttle tankers.

Shell/Esso said Heerema intends to move the Fulmar buoy in its vertical position to a fabrication yard only 500 m away from its mooring position. The yard is operated at ?rdal Mekaniske Verkstad AS (?MV).

Heerema will lift the buoy onto the quay with a heavy lift crane barge and maneuver it into a horizontal position. ?MV will be subcontracted to scrap and recycle the buoy.

Meanwhile, BP installed a jacket and topsides for secondary development of Bruce field on U.K. North Sea Block 9/9b.

During June, the Thialf crane barge installed a 3,200 metric ton steel jacket and 2,750 ton topsides in the field. The new platform will be bridge-linked to the existing platform. Next, BP will install a 213 ton subsea manifold and 6 km pipeline bundle.

The 13-well subsea development will begin production from the western area of Bruce field, with first production due in autumn this year. BP says Bruce Phase II will give access to a further 728 bcf of gas and 61 million bbl of liquids.

Bruce was brought into production in 1993 and currently produces up to 688 MMcfd of gas. Estimated reserves are 2.6 tcf of gas and 212 million bbl of liquids.

In late June, Statoil let two contracts for upgrades to existing platforms to enable future development work.

The operator let an 800 million kroner ($105 million) contract to Aker Maritime ASA, Oslo, to upgrade the Veslefrikk B production semisubmersible in the Norwegian North Sea.

Work will include upgrading the hull and expanding production facilities to handle condensate from neighboring Huldra field, earmarked for development.

In summer 1999, the floater will be towed to Aker's Stord yard for upgrading, which is due for completion by September 1999. Aker will continue working on the vessel after it has been returned to the field to prepare for first Huldra condensate delivery in summer 2001.

Statoil also let a $62 million contract to Kvaerner Oil & Gas AS, Stavanger, for modifications to the Heidrun platform in the Norwegian Sea. Work will start immediately for completion by July 2002.

The platform water injection capacity will be raised, gas handling equipment will be installed so gas can be exported through the Aasgard transport system, and Heidrun north flank satellites will be hooked up.

New production

A number of new fields have begun production this year, again with U.K. operators completing the most, if not the largest.

Shell/Esso claimed it has completed the world's longest subsea tie-back of an electrical submersible pump (ESP) with first production from Gannet E oil field, brought on stream on Jan. 13.

Gannet E sends produced oil to the Gannet A platform 14 km away through a pipeline shared with Gannet F, brought into production in June 1997 (OGJ, Aug. 26, 1996, p. 28).

Shell/Esso said the project gave industry worldwide a tried and tested method for development of satellite fields. The ESP was developed by Reda Production Services Ltd., Inverurie, Scotland. Reda will monitor operation of the Gannet E ESP in real time from Inverurie, enabling it to advise on best operating conditions for the pump.

Shell Expro said Gannet E and F were developed for a total of £80 million ($130 million). Gannet E output is expected to reach a peak of about 14,000 b/d of oil within 3-4 weeks.

Gannet E reserves are estimated at 23 million bbl of oil. Gannet F has estimated reserves of 19 million bbl of oil and has reached peak production of 18,000 b/d.

Texaco North Sea U.K. Co. began oil production from Block 15/23a Galley field on Mar. 25 and is looking to extend the development.

Galley was developed with a production semisubmersible previously used in Emerald field. The vessel is leased from Seatankers and operated on behalf of Texaco by Atlantic Power & Gas Ltd., Aberdeen.

Under this first phase of development three wells will deliver oil and gas from Galley's northern and southern accumulations. Peak production from these wells is expected to be 35,000 b/d of oil and 50 MMcfd of gas.

Galley has estimated reserves of 28 million bbl of oil and 40 bcf of gas. First phase development is expected to last 4 years.

Development of Galley's western and eastern accumulations is being planned by Texaco and will involve drilling of further subsea production wells. Peak output from the later wells is expected to be 15,000 b/d.

The semi has capacity to process 55,000 b/d of well fluids. After separation, oil is exported by pipeline to the Flotta terminal in the Orkney Islands by way of Texaco's Tartan platform. Gas is sent to Tartan for transportation to St. Fergus terminal near Aberdeen for processing.

Galley lies in 495 ft of water. The reservoirs lie at a depth of about 13,000 ft in an Upper Jurassic sandstone formation.

Shell/Esso produced first oil in U.K. North Sea Mallard field on Apr. 2. Mallard has estimated reserves of 25 million bbl of oil and 17 bcf of gas and is expected to produce 16,000 b/d of oil and 11 MMcfd of gas at peak.

The field was developed as a satellite of Kittiwake platform 15 km away with two subsea wells. Block 21/19 Mallard, in 280 ft of water, is a high pressure, high temperature field.

Ranger Oil Ltd. began oil production in U.K. North Sea Columba E field on May 24. The field was developed with a single extended reach well drilled from nearby Ninian Southern platform.

Block 3/7 Columba E began production at 9,000 b/d of oil. Ranger expects by year-end to decide whether to extend field development by further drilling and water injection. Columba E estimated reserves are 20 million bbl of oil, though the operator claims significant upside potential through water injection.

Also in May, Saga began a 6-month production test of H-Central formations with a well drilled by the Scarabeo 5 semisubmersible rig on North Sea Block 34/7 offshore Norway.

The 34/7-26A well was tied back to the Gullfaks C platform via a subsea template in nearby Tordis East field. The 26A well is expected to add 15,000 b/d of oil production to the 70,000 b/d currently flowing from Tordis East. Saga said a decision on development of H-Central will be taken once the long term test has been completed.

Statoil joined the ranks of Danish producers in June with start-up of oil production in Block 5604/22a Lulita field. The Norwegian state firm developed Lulita with two subsea wells tied back to the Harald platform operated by Dansk Undergrunds Consortium (DUC).

Initial output from Lulita was 8,500 b/d of oil, but this is expected to rise to 10,000 b/d. Meanwhile, Statoil continued development of Denmark's Siri field with a production and quarters platform mounted on a seabed crude oil storage tank.

License awards

In May, Denmark's Ministry of Environment & Energy awarded 17 licenses for offshore exploration and production, with foreign firms accounting for many license interests.

The awards follow Denmark's fifth offshore licensing round, opened in summer 1997 to continue the country's recent policy of attracting investment from international industry (OGJ, Nov. 18, 1996, p. 29).

The licenses cover a total area of 6,341 sq km in the western part of Denmark's offshore sector. The ministry said operators of fifth round licenses have committed to spend a total 1.7 billion Danish kroner ($250 million) on exploration over 6 years.

The operators have committed to drill 13 exploration wells in total, with a further eight promised if discoveries are made. They have also pledged to carry out seismic and geological surveys.

Wood Mackenzie said existing players offshore Denmark were awarded much acreage, including DUC partners Maersk Olie & Gas AS, Dansk Shell AS, and Texaco Denmark Inc.; Amerada Hess AS; Denerco Oil AS; and Enterprise Oil Denmark Ltd.

Seven new entrants accounted for more than a quarter of new license interests: Clam, a joint venture of Marathon Oil Co. and Burlington Resources Oil & Gas Co., Houston; Marathon; Saga; Veba Oel AG, Hamburg; Kerr-McGee Corp.; ARCO; and Samedan Oil Corp., Ardmore, Okla., for which Brabant Petroleum Ltd., Tonbridge, U.K., will act as operator.

In June, the U.K.'s DTI opened its 18th offshore licensing round, offering only mature areas that it hopes new technology can make attractive.

Science, Energy & Industry Minister John Battle said the new round comprises blocks made available once again by operators following a government campaign to make them release "fallow" acreage.

DTI set a deadline of Sept. 11, 1998, for receipt of applications for all unlicensed acreage in the U.K.'s northern, central, and southern North Sea areas, plus the northern half of the Irish Sea, Liverpool Bay, and Morecambe Bay.

"Interest is expected in particular from companies keen to use new data acquisition and processing techniques to locate structures similar to recent finds in other sectors of the North Sea or to identify new resources close to producing fields which may extend the life of their existing offshore infrastructure," Battle said.

Phillips Norway prepares to prune old Ekodish platforms

PHILLIPS PETROLEUM CO. NORWAY INTENDS TO submit during the third quarter of 1999 a plan for cessation of operations in old sections of Ekofisk field in the Norwegian North Sea.

This autumn, a new processing and transportation platform and a new drilling platform will take over the bulk of drilling, production, and processing operations in the field after seabed subsidence put existing installation topsides below the 100 year wave safety height level required by Norwegian offshore regulations.

Phillips will need to remove 14 offshore installations and pipelines in decommissioning Ekofisk I. Originally, Phillips intended to submit two separate cessation plans.

The first, dealing with topsides of Ekofisk 2/4 P, Ekofisk 2/4 R, and Ekofisk 2/4 Tank nbs(old processing and transportation ) platforms, was to be submitted to the authorities in the first half of 1998.

The main plans, covering the remainder of the platforms, was to be submitted in third quarter 1999. But a structural survey of the northern platforms and bridges showed them to be in better condition than anticipated.

Hence Phillips decided to integrate all the units into one two-part plan, which will be submitted to the government next year. Phillips expects a decision from the Ministry of Petroleum & Energy by 2001.

Phillips is looking to sell as many of the platforms as possible for reuse. Cod will be the first Ekofisk area platform to be touted to test the market. The operator sees the Gulf of Mexico, the Far East, South America, and offshore West Africa as potential markets for second-hand platforms.

U.K. offshore operators launch drill cuttings initiative

U.K. OFFSHORE OPERATORS ASSOCIATION (Ukooa) is studying the best way to deal with drill cuttings that oil companies have dumped on the seabed.

Ukooa's Drill Cutting Initiative is intended to build on a body of work by operators by implementing further research and inviting suggestions by marine scientists, environmental groups, fishermen, and other interested parties.

Announcing the program, James May, director general of Ukooa, said: "Our initiative is to bring today's thinking and today's openness to a challenge remaining from the past. We recognize that dealing with drill cuttings residues is a key aspect of the industry's long-term environmental challenge."

Heading up the cuttings task force will be Eric Faulds, decommissioning manager at Shell U.K. Exploration & Production, a man with great experience dealing with difficult environmental debate through his leadership of the Brent Spar disposal project.

"It's important to go about this in a carefully considered way," said Faulds, "because it's clear that there are no easy answers. Although a number of companies have well-developed ideas, there is no proven technology for removing old drill cuttings, and without developing new environmentally acceptable removal techniques trying to move them could cause more environmental harm than leaving them in place. Cleaning or treating cuttings in place, at great depths on the seabed, is also surrounded by unknowns."

Ukooa says the challenge of tackling cuttings and mud traces grew over the last 30 years. Through the initiative Ukooa members-virtually all U.K. offshore operators-will fund studies to assess the accumulations, their environmental characteristics, and how to deal with them. The Norwegian operators' association OLF is also considering joining the Ukooa initiative.

"Research has now shown," said Ukooa, "that synthetic muds are not breaking down naturally in seawater as quickly as expected, and in a further move to minimize impacts, operators in the U.K. are phasing out discharging cuttings contaminated with synthetic muds by the end of the year 2000.

"These cuttings will be reinjected back into wells or taken ashore for treatment. The new ways of working will involve a commitment of some £50 million/year ($80 million/year) in extra costs by the offshore industry."

Ukooa says options for dealing with drill cuttings include removing them completely or treating them in place on the seabed.

"Removal methods could include pumping, dredging, and the use of specially designed underwater vehicles," said Ukooa. "However, the techniques need to be developed and proven, and a particular issue is avoiding environmental impacts from disturbing the cuttings, which may be greater than from leaving them in place.

"Treatments in place could involve capping the cuttings with impermeable material to close them off or bioremediation in which 'bugs' are introduced to accelerate the natural breakdown of any hydrocarbons. Although this technique is proving useful on land, its possibilities as deep, cold ocean floors are as yet unknown."

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