NW Europe's offshore operators filling in development puzzle

David Knott
Senior Editor

John Shaw semisubmersible rig drilled an oil strike for Amerada Hess off the U.K. with the 20/5c-6 new-pool wildcat. The well flowed more than 8,600 b/d of oil on test and was suspended for future use. Amerada plans further appraisal. Photo courtesy Amerada Hess.

During the North Sea weather window, Stanislav Yudin crane ship removed four platforms from Conoco's Viking A field in the southern North Sea. The project was one of four small abandonments carried out while Shell/Esso works out what to do with Brent spar. Photo courtesy Conoco.

This year, Northwest Europe's offshore operators have mainly been filling in some of the smaller pieces in the region's massive field developments jigsaw puzzle.

While none of the projects has matched the giant developments of old, they have generally presented challenges in terms of innovations required to make them viable.

In exploration, there has been a return to Irish waters, and operators have been busy in new plays in the Norwegian Sea and West of Shetland areas.

Wood Mackenzie Consultants Ltd., Edinburgh, said U.K. production has been hit by delays and problems in bringing fields on stream-namely Liverpool Bay, Foinaven, Harding-and unforeseen operational problems in Beryl, Magnus, Nelson, and Scott fields. The biggest surprise for the U.K. concerned delays with Foinaven, the first West of Shetland development, operated by BP Exploration Operating Co. Ltd.

U.K. output averaged 2.54 million b/d in the first half, more than the 2.5 million b/d a year ago but below the expected 2.66 million b/d.

Norwegian oil production has been above 3 million b/d for most of the summer, although platform maintenance work cut flow. Danish output reached a new peak of 215,000 b/d in August, and Dutch output recently fell to 32,000 b/d because of problems in Logger field.

After last year's dramatic Brent spar dumping about-face, operator Shell U.K. Exploration & Production has drawn up a list of 30 new proposals in search of a less controversial abandonment scheme (OGJ, Aug. 19, p. 39).

Meanwhile, Norwegian and U.K. operators pushed through a handful of abandonments, all of which involved complete removal of installations.

Well test trend

One noticeable recent trend among North Sea producers, which has been particularly evident this year, is the use of extended well testing and early production schemes ahead of full-scale development planning.

In early October, Norsk Hydro AS reported completion of a successful extended well test in its Hermod discovery on North Sea Block 25/11 off Norway. Hydro produced almost 500,000 bbl of 19 gravity oil, at a rate of as much as 20,000 b/d. Treasure Saga semisubmersible reentered the 25/11-21 well in May to sidetrack the well and later carry out testing.

Hermod has estimated reserves of 440-520 million bbl of oil, with a gas/oil ratio of 15.8. The discovery is not near infrastructure, the nearest field being Heimdal, 50 km away on Block 25/4. Hydro is working on Hermod development ideas and intends to complete its plans in second quarter 1997 in time to receive a development permit by yearend 1997.

Hydro said water depth in Hermod is 120-130 m, so both fixed and floating production systems are viable. The choice will depend on the number of wells the various options can support. The company is considering development using two fixed platforms, a fixed platform and a floater, or two floaters and linked subsea wellheads. First production is anticipated in 2000.

The official said reserves in the field can be reached from a central location, but development will require a high number of wells and artificial lift.

Produced gas and water would be reinjected, he noted: "The exploitation strategy depends on pressure maintenance by water injection." The development wells would include dual and multilateral completions.

In October, Conoco (U.K.) Ltd. started oil production from Banff field on Block 29/2a, with Sedco 707 converted semisubmersible rig producing oil directly into Stena Savonita shuttle tanker. Banff field reserves are estimated at 20-110 million bbl of oil.

A Conoco official said the idea of early production is to pin down estimated reserves more accurately and help in the selection of a full-scale development method.

Conoco received outline bids from a number of contractors in August for full development of the field. The company requires contractors to propose the development option and expects to make a decision by yearend.

In May, Saga Petroleum AS received government approval for a 6-month production test of H Central reservoir near East Tordis field, currently under development in the Norwegian North Sea.

The idea was to produce about 3 million bbl of oil to determine the extent of oil-bearing sand and ascertain communication within the reservoir. However, H Central's early production will now be delayed until next year.

A Saga official explained that pilot production from East Tordis is now scheduled to take place ahead of H Central. East Tordis will produce in March and April using a production semisubmersible and tanker, while H Central's pilot is now slated for mid-1997.

BP has been the most active in major well tests, completing a second pilot scheme in Machar discovery, one of seven U.K. fields to be developed as the Eastern Trough Area Project (ETAP).

The Machar pilots each yielded 7 million bbl of oil, with the first checking well rates under natural depletion and this year's pilot testing flow rates with waterflooding (OGJ, June 24, p. 24).

BP also set out to prove that West of Shetland's Clair field-which has enormous reserves in place but has showed poor and inconsistent flow rates on test-could produce 15,000 b/d of oil in 45 days.

Key to an extended well test this summer was a theory that faults within the reservoir could be used as funnels to boost oil depletion rates.

BP's test was successful, but further appraisal drilling rather than pilot production is likely to come next for enigmatic Clair (OGJ, Oct. 14, p. 40).

In October, Ranger Oil (U.K.) Ltd. disclosed results of an extended well test it carried out in U.K. North Sea Pierce discovery, where BP is operator. This has encouraged the partners to predict first oil production in mid-1998 (OGJ, Oct. 21, p. 26).

Development work

Off Norway, Den norske stats oljeselskap AS (Statoil) installed all the subsea equipment required for development of Norne field on Norwegian Sea Block 6608/10, one of the largest recent North Sea finds.

This summer, Statoil installed five subsea templates, along with pipelines, risers, and anchors, in readiness for arrival of the production ship in the field next April.

The vessel is currently at the Aker AS yard at Stord, south of Bergen, where 24 modules weighing a total 12,000 metric tons were lifted onto the hull in mid-October.

A Statoil official said the first production well in Norne field has been completed, and the company aims to have four or five wells ready for first oil, expected in mid-July 1997 (OGJ, Oct. 3, 1994, p. 30).

Operators have been keenly watching development of Erskine field on U.K. North Sea Block 23/26 by Texaco Ltd., which is scheduled to become Britain's first high temperature/high pressure development.

The company has just completed drilling the second of three production wells in readiness for first production in October 1997. Erskine will be developed with an unmanned platform linked by pipeline to Lomond platform, at an anticipated cost of £ 290 million ($435 million).

The 2,500-metric ton Erskine jacket was installed earlier this year. Santa Fe Monitor jack up moved in shortly afterwards to begin drilling the first producer through the jacket in cantilever position.

Topsides are expected to arrive from the McNulty Offshore Services Ltd. yard at South Shields, U.K., in April 1997. Drilling of three further production wells will take place once the field is on stream and will take 1 year.

This summer Texaco laid a 30-km, 16-in. pipeline from Erskine to Lomond, operated by Amoco (U.K.) Ltd.

Untreated well fluids will be sent via this insulated pipeline, for processing on Lomond platform and export of liquids via the Forties system and gas through the Central Area Transmission System trunkline to Teesside.

Texaco has also been completing development of Captain field on U.K. Block 13/22a. Captain is another field requiring an innovative cocktail of technologies. Its shallow, unconsolidated reservoir and heavy oil will be produced with a production/storage ship and wells with horizontal sections and electric submersible pumps.

In October, British Gas plc claimed to have drilled the world's longest well from a semisubmersible rig, with the eighth development well of its Armada project on U.K. North Sea Blocks 16/29 and 22/5 (OGJ, Oct. 21, p. 28).

Hydro completed a second dual-lateral well in Oseberg field, where earlier this year it became the first Norwegian operator to begin production with a dual-lateral well (OGJ, May 20, p. 30).

Hydro said development of oil reserves in the Troll field's central gas province will likely involve about 10 dual-lateral wells. Hydro recently confirmed a plan to install a third platform in Troll (OGJ, Sept. 2, p. 32).

Foinaven hitch

In October, BP reported that progress on subsea work in development of Foinaven field was set to resume after problems with a subsea manifold.

BP had installed the first of two manifolds on the seabed, but this had to be recovered for examination after cracks appeared on hubs during leak testing in May.

A team of experts established that the cracks were caused by a combination of overall stresses in the hub connections and hydrogen embrittlement induced by the cathodic protection system.

The problem has been overcome by reducing stress levels in the metal and local shielding of the cathodic protection system. Meanwhile, BP intended to install the second manifold in place of the first.

In addition to the manifold, BP also recovered flexible connectors, used to link rigid flowlines to the manifold and risers. No faults were found on more than 70 flexible connector hubs recovered, while hubs on rigid flowlines were pressure-tested without any failures.

Dave Brookes, subsea manager on Foinaven, said, "We are now satisfied that the hub stress levels are such that there will be no repetition of cracking. As a precaution, everything will be hydro-tested over an extended period, and we are confident that the system is now fit for full field life."

Meanwhile, flexible risers and umbilicals were installed in another part of the field, and the flexible connectors removed for examination are also being relaid with the Iolair and Semi 1 construction vessels.

Petrojarl Foinaven production and storage ship is due to arrive in the field immediately after completing sea trials. The ship is slated to start pulling risers as soon as it is anchored.

New production

This year, North Sea companies brought on stream a giant gas project and a host of smaller projects.

First was North Hamilton gas field in U.K.'s Irish Sea area, part of the Liverpool Bay project developed by BHP Petroleum Ltd. Once on stream, however, the group of fields built production more slowly than anticipated (OGJ, Jan. 22, p. 21).

Shortly afterwards, Elf Petroland BV began gas production from J3 Charlie field off the Netherlands, as a single-well satellite of Markham field, and Shell/Esso saw first oil from Pelican, a subsea satellite of U.K. Cormorant field (OGJ, Jan. 29, p. 48).

Statoil began oil production from Norway's smallest stand-alone development to date. Block 9/2 Yme was developed with a jack up rig and storage tanker.

Development was delayed from last year after conversion of the rig ran into problems at the construction yard. No sooner had oil begun flowing than Yme's crew of contractors' staff went on strike (OGJ, Apr. 8, p. 32).

Denmark's Dansk Undergrunds Consortium brought Svend and Roar fields into production. After recent appraisal programs, Danish operators are looking to boost development activity (OGJ, Sept. 2, p. 32).

BP's Harding field, developed with a jack up production rig mounted on top of a concrete gravity base storage tank, came on stream in May. Bad weather had delayed installation of the rig (OGJ, May 13, p. 38).

Soon afterwards, BP started oil and gas production from South Magnus field, a subsea satellite of Magnus platform in the northern U.K. North Sea (OGJ, June 10, p. 40).

Then BP brought U.K. Block 16/28 Andrew field on stream, in what the company views as a seminal development.

While Andrew's technology was conventional for the North Sea, the company's management of the development process, particularly its relationship with contractors, was key to making the project viable (OGJ, July 8, p. 22).

In July, Elf Petroland began production from another small Dutch gas field. L7H field on Block L7 was developed by extended-reach drilling from the block's central processing complex (OGJ, July 29, p. 52).

In October, Statoil saw completion of development of the supergiant Troll and "merely enormous" West Sleipner gas fields.

Completion of Troll development, with its pioneering use of horizontal well sections through a thin reservoir and innovative platforms, ended one of the North Sea's most exciting development stories. Troll gas is expected to be delivered to mainland Europe for at least 50 years (OGJ, Oct. 7, p. 43).

After its October start-up, Conoco's Banff pilot output is expected to peak at 35,000 b/d of oil from two wells. The tanker has capacity to hold 750,000 bbl of oil.

Conoco said the early-production phase is expected to last 6 months, while production under the full field development is scheduled to begin in first half 1998.

Also off the U.K., Shell/Esso began gas production from Schooner, Mobil North Sea Ltd. brought on line first oil and gas from Nevis, and Amerada drew first oil from Fergus field (OGJ, Oct. 14, p. 38).

Later in October, Shell/Esso began oil production from Teal, South Teal, and Guillemot A fields, using Anasuria production, storage, and offloading ship, the largest of its type, with capacity to store 850,000 bbl of oil and to produce 60,500 b/d of oil and 36 MMcfd of gas (OGJ, Mar. 6, 1995, p. 33).

Also, Amerada Hess last month began oil production from Telford field on U.K. North Sea Blocks 15/21 and 15/22. Telford was developed as a subsea satellite of its Scott platform 9 km away. Telford has four production wells and three water injectors tied back through two manifolds.

In late October, Agip (U.K.) Ltd. also disclosed first oil and gas production from Thelma and Southeast Thelma fields on U.K. Block 16/17. They are subsea satellites of Tiffany platforms, expected next year to reach plateau output of 25,000 b/d of oil and 29 MMcfd of gas.

Exploration

By early October, Arthur Andersen & Co., London, reckoned 100 wildcats had been spudded in 1996 throughout Northwest Europe, of which 66 were off the U.K.

Much exploration activity has been appraisal of recent discoveries and exploration of new plays, particularly in the Norwegian Sea and U.K.'s West of Shetland area.

Statoil and partner Saga have been drilling development wells and probing the area around their Aasgard project discoveries, which have been sanctioned for development with an oil production ship and a gas production semisubmersible.

Most recently, Saga has reported problems with its 6406/2-3 well near the Aasgard area, which was shut in for about a month from late September after encountering gas intrusion problems.

Gustav Dunsaed, Saga's drilling operations manager, said, "We cut the string at a depth of 3,800 m and cemented the well before pulling the downhole safety valve for inspection and repair.

"A cement plug was set at the bottom of the well to kill the flow. Once the well was dead, we decided to continue cementing up to 2,800 m before retrieving the blowout preventer and spudding a sidetrack."

On Block 6407/1, Statoil completed an appraisal well in Tyrihans North discovery, which it is now eyeing as a potential development in the wake of Aasgard (OGJ, Sept. 16, p. 23).

West of Shetland exploration activity has been running high, reported Arthur Andersen, with Shell, BP, Esso, Conoco, Kerr-McGee Oil (U.K.) plc, and Total Oil Marine plc among well operators.

However, none of the companies has disclosed well results, and all wells West of Shetland have been declared tight holes. This has led to speculation that the region's recent exploration has not been as successful as hoped.

There have been no major North Sea discoveries disclosed this year, but operators have disclosed a steady stream of test results pointing to small but commercial finds.

For example, ARCO British Ltd. tested 37 MMcfd of gas and 600 b/d of condensate from a southern North Sea well, which it reckons could be developed quickly via nearby infrastructure (OGJ, Apr. 29, p. 31).

Saga found oil and gas on Norwegian Block 34/7 near Tordis field. The well flowed 6,600 b/d of oil and 3.7 MMcfd of gas, encouraging the operator to think of a tieback to Tordis (OGJ, Oct. 7, p. 46).

Saga also found oil near Statfjord field on Norway's Block 33/9, and has pegged reserves at 30-40 million bbl of oil. The find is thought to be commercial because of nearby production facilities (OGJ, Aug. 12, p. 40).

Meanwhile, Amerada Hess reported a strike off the U.K. with its 20/5c-6 new-pool wildcat, which flowed more than 8,600 b/d of oil on test and was suspended for future use. Amerada plans further appraisal of the find, which lies 12 km from nearest infrastructure, but says it is too early to think of development options (OGJ, Aug. 12, p. 27).

Ireland has seen a recent upturn in drilling activity. Enterprise Oil plc, London, drilled two wildcats in the Slyne Trough off western Ireland. The first well discovered oil shows, and the Block 18/20-1 deviated well encountered gas shows in early October. Petrolia semisubmersible had drilled to total measured depth of 4,372 m in 350 m of water, but Enterprise said mechanical problems then prevented it completing preparations to test the discovery well. John McGoldrick, Enterprise's Atlantic Margin area manager, said, "We are disappointed that mechanical problems prevented us carrying out a flow test. However, we are encouraged by the data gathered from our Irish drilling program and will now review the results to determine the best way forward."

In the U.K. Irish Sea, Elf Exploration U.K. plc and British Gas plc had planned to drill wildcats off South Wales, but their intentions were thwarted by U.K. Department of Trade & Industry (DTI), which refused licenses, allegedly following the Sea Empress tanker grounding earlier this year.

However, Marathon Oil Manx Ltd. completed a wildcat off the Isle of Man as a tight hole, and plans other wells in the area (OGJ, June 10, p. 33).

Further north, Esso U.K. drilled a dry hole that was interesting for how information about the well was handled (OGJ, May 6, p. 46).

Germany's RWE-DEA AG struck oil on Block F/2 off the Netherlands and tested 9,700 b/d in what may have been the sector's highest well return to date. However, while the company has described the find as promising and declined to comment on estimated reserves, one report put the discovery at 20-50 million bbl of oil.

Redevelopments

In late October, Shell/Esso resumed oil production from Brent Charlie platform, second of three major installations to be upgraded under redevelopment of U.K. Brent field (OGJ, Apr. 12, 1993, p. 28).

Oil production from Brent C is expected to reach 80,000 b/d by yearend, while gas production is expected to resume this month.

Shell/Esso refurbished Brent B platform last year and is preparing Brent D for shutdown next spring to replace production plant for low-pressure gas operation and to upgrade accommodations.

Phillips Petroleum Co. Norway reckons to be about halfway through a redevelopment of giant Ekofisk field off Norway, undertaken because of subsidence of the central processing platform.

David Smith, manager of engineering and construction at Phillips Norway, said Ekofisk redevelopment involves connecting four fields-Ekofisk, Eldfisk, Embla, and Tor-plus third party fields Gyda, Ula, Valhall, and Hod into one new process and transportation platform, called 2/4J, and shutting in four fields-Cod, Albuskjell, West Ekofisk, and Edda.

Smith said current drilling facilities will be replaced by one new 50-slot wellhead platform. Topsides for this platform, weighing 8,100 metric tons, were installed in mid-August by giant crane barge DB 102.

The 2/4J platform is expected to be installed next year, so production can begin through new facilities ahead of a closure deadline in 1998 for the existing central platform (OGJ, Dec. 19, 1994, p. 146).

Abandonments

The derelict Brent Spar loading buoy overshadowed last year's North Sea action, as campaign group Greenpeace led a protest campaign that resulted in dumping of the spar being aborted (OGJ, Nov. 27, 1995, p. 23).

This year the buoy has been moored in a Norwegian fjord, while operator Shell/Esso looks for a less controversial disposal plan. Meanwhile, other abandonments have gone ahead.

Northeast Frigg lay on Block 25/1, and was developed using a six-well subsea manifold, tied back to Frigg TCP2 platform, with a 150 m articulated control tower to govern well operations.

In July, Elf removed NE Frigg's articulated control tower and flare column and moored the tower in the fjord outside Tau, near Stavanger, about 200-300 m from where the deck and tower will be re-used (OGJ, Aug. 12, p. 28).

Throughout the summer and finishing Oct. 1, Conoco removed four of five platforms in North Viking A gas field on U.K. Block 49/12.

The four platforms that were removed had not been upgraded under new U.K. offshore safety regulations, implemented in the wake of the Piper Alpha platform blast of 1988 (OGJ, June 3, p. 18).

Around the same time, Shell/Esso decommissioned Leman BK compression platform, one of 15 platforms in Leman gas field in the southern North Sea.

The DB 102 heavy-lift vessel was used to remove three platform modules, a module support frame, and then the jacket.

A Shell official said topsides were removed in early October and taken to the Able U.K. Ltd. yard on Teesside for dismantling and recycling. The jacket was removed and taken to Able's yard later in the month.

Odin field operator Esso Norge AS took modules from the platform to shore for dismantling and recycling, after earlier trying to persuade government to approve a fish reef disposal plan.

In October, Aker AS, Oslo, and Saipem SpA, Milan, removed the Odin platform's five modules in two consignments, which were loaded onto the S-7000 heavy lift vessel for removal to Stord yard.

The jacket is slated for removal next year. Aker is working on opportunities for re-using the modules and equipment from the platform in new projects.