PLENTY OF ACTION LEFT IN NORTHERN EUROPE'S MIDDLE-AGED OFFSHORE

Aug. 15, 1994
David J. Knott Senior Editor Northern Europe's offshore oil industry this year has begun to reveal several symptoms generally associated with middle age. Though in its prime in terms of oil production, North Sea industry has begun a dramatic slimming program. It has started a search for fresh experiences. And it has begun to revisit the big successes of its youth. Demonstrating these trends:
David J. Knott
Senior Editor

Northern Europe's offshore oil industry this year has begun to reveal several symptoms generally associated with middle age.

Though in its prime in terms of oil production, North Sea industry has begun a dramatic slimming program.

It has started a search for fresh experiences. And it has begun to revisit the big successes of its youth.

Demonstrating these trends:

  • North Sea production is higher than ever before and is reckoned to be approaching a peak that will last a few years, while Norway and the U.K. are both claiming there is much life left in their mature sectors.

  • Norwegian and British operators are looking to cut costs in existing developments and seeking cheaper ways of developing new fields.

  • Norway and the U.K. are opening new areas to development, while Denmark and The Netherlands are reviewing operating terms in a bid to revitalize their offshore industries.

  • Exploration of the U.K.'s West of Shetland area is causing excitement not seen since the early days of North Sea drilling; while Norway's Barents Sea has disappointed again, operators remain hopeful.

  • Redevelopment of the U.K.'s Brent field has begun, while agreement has been reached on terms for redevelopment of Norway's Ekofisk field.

PRODUCTION

North Sea oil and natural gas liquids production reached a record high average of 5.288 million b/d in May. The previous high was 5.23 million b/d, recorded in March, according to Wood Mackenzie Consultants Ltd., Edinburgh.

Norway, keeping its position as the North Sea's largest producer, raised production to a national record average in May of 2.68 million b/d. This was up from 2.56 million b/d in April.

At the same time, U.K. offshore output was at a 5 year high, averaging 2.365 million b/d in May, compared with 2.355 million b/d in April.

Production off Denmark fell to an average 183,000 b/d for May from 193,000 b/d during April. Dutch oil and NGL production rose to an average 63,000 b/d in May from 60,000 b/d in April.

After last year's run of fields coming into production, this year has been relatively quiet.

Chevron (U.K.) Ltd. began production from Block 16/26 Alba field on Jan. 14. Start-up had been delayed from late November because of a software fault in fire-and-gas and emergency shutdown systems aboard the field's storage tanker.

The software continued to cause problems, as did process equipment. Chevron decided to shut down Alba field for 4 days in June to allow modifications aimed at curing "teething troubles." Production restarted June 25.

In January Agip (U.K.) Ltd. began production from Block 16/17 Toni field, which is intended to produce at 20,000 b/d of oil. Toni is a subsea development tied back to nearby Tiffany field, which began production in November 1993.

On Apr. 9 BP began oil production from Medwin field on U.K. Block 30/17b. The field was developed with a single extended reach well drilled from Clyde platform 5.3 km away. First production was 10,200 b/d. Field reserves are estimated at 3 million bbl of oil.

Norway's West Gullfaks field was brought on stream in mid-May by means of an extended reach well drilled from Gullfaks B platform 4 km away. The 12 million bbl satellite is intended to produce 12,500 b/d for processing on Gullfaks B.

Lille Frigg field off Norway was officially brought on stream in early June as a subsea tie-back to Frigg field facilities. Oil production on test during May averaged 8,000 b/d.

BP started production from U.K.'s Machar field on June 3 with a floating production system comprising the converted Sedco 707 drilling rig, linked by flow line to a storage tanker.

BP plans to lift 7 million bbl of oil in a 1 year test. Experience of the behavior of Machar reservoir will help BP fine-tune development of the Eastern Trough Area Project, a nine field development including Machar.

EXPLORATION OUTLOOK

Norwegian Petroleum Directorate said the resources outlook on the Norwegian continental shelf is healthy, though innovation is needed to keep development costs competitive.

New figures from NPD show Norway's total proved recoverable oil and gas reserves amount to 44 billion bbl of oil equivalent, including cumulative production so far (OGJ, Apr. 18, p. 31). Production to date has amounted to 9.5 billion bbl of oil equivalent.

Norway's North Sea fields are estimated to hold 84% of reserves, with 11% in the Norwegian Sea and 5% in the Barents Sea.

Almost all production to date has been from the North Sea area of Norway's shelf.

Arild Nystad, manager of resources at NPD, estimated total resources on the Norwegian shelf to be 10 billion metric tons of oil equivalent. Of this, undiscovered resources were put at 3.7 billion metric tons of oil equivalent, in 200-400 small fields.

Small field development prospects were said to amount to 1.85 billion metric tons of oil equivalent, in 105 fields.

Forty fields were said to have been developed or to be under development off Norway, with reserves amounting to 4 billion metric tons of oil equivalent.

Another 80 fields and discoveries are under consideration, with total potential reserves amounting to 2 billion metric tons of oil equivalent.

Nystad said a recent government white paper proposing new license conditions off Norway recognized the difference in average field sizes of developed and undeveloped fields: 100 million and 25 million metric tons of oil equivalent, respectively.

By 2000 Norway needs to begin bringing small fields into production, said Nystad.

By about 2010, small fields may be producing as much in total as Norway's large fields.

Many of Norway's future small field developments are likely to use production ships, said Nystad. These would deplete one field before moving to another. In the meantime, Norway's operators will have to cut new field development costs by 40-50%.

U.K. TRENDS

In the U.K., Energy Minister Tim Eggar in April announced publication of the 1994 edition of the "Brown Book," the Department of Trade & Industry's (DTI) annual status report on U.K. oil and gas resources.

"Twenty years ago the Brown Book contained predictions that oil production would peak at about 110 million metric tons in 1980 and that by 1990 production would have declined to less than 40 million metric tons," said Eggar.

"Yet in 1993 we produced more than 100 million metric tons of oil, and we can confidently expect to exceed that figure this year. Production is set to remain above 100 million metric tons/year of oil for the rest of this century at least."

DTI estimates that the U.K. has 2.33.8 billion metric tons of discovered oil reserves, including cumulative production, 130-390 million metric tons of potential additional oil reserves, and 560-3,355 million metric tons of undiscovered oil resources.

For gas, DTI reckons the U.K. has 1.6-2.8 trillion cu m of discovered reserves, including cumulative production, 125-280 billion cu m of potential additional reserves, and 300-1,297 billion cu m of undiscovered reserves.

"The report demonstrates that while the U.K. continental shelf is now a mature province it is certainly not stagnating," said Eggar. "After 30 years of exploration a substantial amount of oil and gas remains to be found."

Grampian Regional Council, Aberdeen, says 85 new U.K. offshore oil and gas fields may be developed by 2011. This will add to 77 U.K. offshore fields developed to date and eight currently under development.

The council expects two thirds of the 70 fields currently in production and eight under development to continue producing beyond 2000. Several fields' lives could be extended by redevelopment and tie-in of satellites.

IMPROVING TERMS

The Netherlands this summer will announce improved terms for offshore exploration and production. The Ministry of Economic Affairs said the position of The Netherlands has deteriorated as a result of policy adjustments in the U.K. and Norway.

The operators' group Nederlandse Olie en Gas Exploratie en Produktie Associatie (Nogepa) told the ministry that undeveloped gas fields with estimated reserves of less than 4 billion cu m of gas were not viable under current terms.

Nogepa and the ministry began talks earlier this year on terms that would revive interest in the Dutch sector (OGJ, Feb. 21, p. 36).

By mid-July talks between Nogepa and the ministry had not reached a conclusion. In the meantime, Dutch exploration activity has hit bottom. Wood Mackenzie reported that only 14 exploration wells were completed in 1993, less than half the level throughout the 1980s. This year only three wells have been completed.

Dutch Geological Survey has estimated that 180 billion cu m (6 tcf) of gas remains to be found off The Netherlands. The ministry says 81 gas fields have been developed or are currently under development.

A further 81 gas fields are reckoned to have been discovered but not developed offshore. Wood Mackenzie reckons ?? of these are commercially viable under current conditions. These fields are estimated to hold 52 billion cu m of gas (1.8 tcf), or 38% of Dutch undeveloped reserves.

DEVELOPMENT ACTIVITY

BP Exploration intends to announce this summer detailed plans for the first field development in the West of Shetland region: 250-500 million bbl Foinaven field on Block 204/24a.

Because of the lack of infrastructure and deep water, the field is likely to be developed with a floating production vessel and storage tanker, which will load shuttle tankers.

One estimate of future West of Shetland production is 500,000 b/d of oil by 2005 from as many as seven fields. This would require pipeline transportation, opening the way for deepwater fields being tied back to platform developments in shallower water (OGJ, June 20, p. 16).

BP Exploration currently has three semisubmersible rigs in the West of Shetland area. They are drilling appraisal wells prior to development of the large Foinaven discovery.

Texaco Ltd. recently joined BP drilling in the region. Texaco chartered the Sonat Arcade Frontier semisubmersible rig to drill the Sula Sgeir prospect on Block 202/12.

Foinaven and Norway's Norne field are two of the largest oil fields discovered in the North Sea in the past 10 years. The fact that both are being developed by floaters shows how operators see future developments distant from existing infrastructure (OGJ, May 23, p. 23).

NORNE, HARDING

Norway's Den norsk stats oljeselskap AS (Statoil) plans to develop Block 6608/10 Norne field using the world's largest production ship. Project cost is estimated at $1.3 billion.

However, Statoil announced in July that the development partners have decided to delay submission of a development plan to the Ministry of Industry & Energy until October.

The delay is intended to give a ministry committee studying ways to improve Norway's licensing framework time to make its report. Norne partners want to develop the field without sliding-scale arrangements for state participation.

Statoil hopes the Norne schedule for first oil in late 1997 will not be affected. Since Statoil has already awarded contracts for Norne work, the partners are cooperating with the ministry to ensure the schedule does not slip.

In the Central North Sea, BP Exploration is developing Harding field on U.K. Block 9/23. First oil is scheduled for early 1996. Harding has estimated reserves of 185 million bbl of oil and 200 bcf of gas.

The field will be developed with a three-legged jack up production, drilling, and quarters platform mounted on top of a T-shaped concrete oil storage tank in 110 m of water.

The tank will weigh 80,000 tons and hold up to 500,000 bbl of crude oil. It is being built at Hunterston yard in Scotland under a 50 million ($75 million) contract by a joint venture of Costain Engineering & Construction Ltd., London, and Taylor Woodrow Civil Engineering Ltd., London.

The tank will be lowered to the seabed in July 1995, ready for mating with the topsides, which will arrive in August 1995. Topside facilities are being built by Hyundai Engineering & Construction Co. Ltd. at Ulsan, South Korea.

The 27,000 metric ton topsides will be based on the proprietary TPG-500 design by Technip Geoproduction SA, Paris. The platform will be able to process 64,000 b/d of oil for storage in the base prior to shipment by shuttle tanker.

PUSH FOR GAS

Norway and the U.K. are seeking to advance development of their natural gas industries.

Norway is looking to increase export capacity for developments in progress. The U.K. is developing gas fields and promoting Southern Gas basin exploration in a forthcoming licensing round.

Statoil is likely to decide this summer on a route for a fourth trunk line to take Norwegian gas to Europe. The company expects Norway's gas exports to reach 70 billion cu m/year by 2005, an increase of 15-20 billion cu m/year over current contract volumes. New capacity is needed by 1998 to ship gas to Germany and France.

Most likely proposal will be installation of a 12 billion cu m/year pipeline parallel to the Europipe line, currently under development from Norway's Block 16/11-E riser platform to Emden, Germany.

Statoil is installing an extra pipeline landfall section leading to the Emden terminal, parallel with the Europipe shore approach.

In the U.K. sector, British Gas plc won DTI approval in June for development of the Armada group of fields in the Central North Sea. A 600 million ($900 million) single platform field development will rely on extended reach drilling for simultaneous exploitation of three gas fields.

The Armada fields are Drake on Block 22/5b and Fleming and Hawkins, centered on Block 22/5a. Total reserves are estimated to be 1.2 tcf of gas and 70 million bbl of condensate. Production is scheduled to begin in October 1997 and expected to last 20 years.

Average gas production is expected to be 350 MMcfd. Gas will be processed on the Armada platform and carried by two subsea pipelines to the Central Area Transmission System (CATS) riser platform.

The existing CATS terminal at Teesside will be expanded by operator Amoco (U.K.) Exploration Co. in an 4280 million ($120 million) development that will connect CATS to the national gas grid for the first time.

SOUTHERN U.K. FIELDS

In early June Conoco (U.K.) Ltd. won DTI approval to develop Ganymede and Callisto gas fields in the southern North Sea. First production is slated for fourth quarter 1995. Output is expected to average 180 MMcfd and peak at 300 MMcfd.

Ganymede field will be developed by means of a normally unmanned steel platform on Block 49/22. The field is estimated to hold 250 bcf of gas. Field life is estimated to be 20 years.

Callisto field lies 13 km southeast of Ganymede in the same block and is estimated to have reserves of 70 bcf of gas. Field life is estimated at 20 years. Callisto will be developed as a single well subsea completion tied back to Ganymede platform.

Callisto gas will be sent to Ganymede through a 12 in. diameter pipeline. Gas from Ganymede platform will move through the Lincolnshire Offshore Gas Gathering System (Loggs).

An 18 in. diameter pipeline will run 20 km from Ganymede platform to the Loggs riser platform. From there it will move ashore to Theddlethorpe gas terminal, which was recently expanded (OGJ, Nov. 29,1993, p. 37).

Conoco said the Callisto control system pipeline and manifold will be designed to allow future tie-ins of gas fields. Several other prospects and reservoirs are said to have been identified or proved in the area.

Amoco secured DTI approval in June for a 46 million ($69 million) development of two southern North Sea gas fields.

Block 49/23 Bessemer field and Block 53/5a Davy field will each be developed with newly designed, minimum-facilities platforms tied back to Indefatigable field.

The Amoco Minimum Offshore Supporting Structure (Amoss) is said to be a single-leg, monotower design never before used in the U.K. North Sea and offering significant cost savings over conventional four-legged structures.

Engineering and fabrication work will start in August, with platform installations scheduled for March 1995. Gas production is expected to begin October 1995 at a total maximum 210 MMcfd.

The contract includes an option for a third Amoss platform for an unspecified field. Amoco is considering development of nearby Beaufort field via Indefatigable field facilities (OGJ, Nov. 1, 1993, p. 28).

Shell U.K. Exploration & Production, the operating company for Shell U.K. Ltd. and Esso Exploration & Production U.K. Ltd., won government approval in January for development of South Barque field and a Barque field extension in the Sole Pit area of Quadrant 48.

These will be developed through existing platforms on Barque and Clipper fields. Estimated reserves are 700 bcf of gas, with first production slated for October 1994.

Mobil North Sea Ltd. has completed installation of a gas production platform in Excalibur field in Block 48/17a. Production is expected to begin Oct. 1.

EXPLORATION

Governments of all the North Sea's main producing countries have become aware of the need to make exploration and production terms more attractive to prevent operators' investing elsewhere.

Norway's parliament, Storting, decided June 13 to open up areas near the Norwegian coast, provided drilling plans meet environmental requirements. Earlier this year the government proposed opening six Norwegian Sea basins off central Norway, and the Skaggerak area off the south coast (OGJ, Mar. 28, p. 33).

The Norwegian Sea's Voring and More basins will be completely opened to exploration. Sections of Nordland IV and V farthest from the coast will also be opened, though Nordland VI and Skaggerak will be only partly opened.

Only six wells will be allowed in the Nordland VI area and only four in Skaggerak. Drilling will be restricted to winter, and only one rig will be allowed in each area at a time.

Ministry of Industry & Energy said Storting decreed that the go-ahead for exploration was conditional on tests on the environmental impact of certain chemicals used in drilling.

The ministry is uncertain whether evaluations will be completed in time for the new areas to be offered in its next offshore licensing round.

The ministry said oil companies would be asked by August to nominate areas for inclusion in the 15th licensing round. Blocks on offer are expected to be announced about yearend.

Norway's three oil companies are to pool exploration results from the Barents Sea in a bid to establish whether further drilling is worthwhile.

From Aug. 1 until yearend Statoil, Norsk Hydro AS, and Saga Petroleum AS will consider an exploration alliance. The move arises from a government white paper proposing that future Barents Sea exploration licenses be offered to groups decided by companies themselves rather than groups chosen by the ministry.

Proposals to change license interest arrangements and also award larger areas under each license were said to have come about after the government and industry realized the Barents Sea was losing appeal under existing terms.

A total of 10 billion kroner ($1.4 billion) was said to have been spent on 52 dry holes drilled in the Barents Sea to date.

Statoil probably came nearest to having a commercial Barents Sea oil find, with its Block 7128/4-1 wildcat earlier this year.

It was the first producible oil find in the Barents Sea, but the well flowed only 157 b/d on test.

Statoil said problems during tests meant the results did not reflect the reservoir's potential (OGJ, Feb. 28, p. 30).

The find was seen as confirming Statoil's geological model for the region.

NEW U.K. POUNDS

In the U.K., Eggar in April announced blocks open for bidding under the country's 15th offshore exploration licensing round and also areas available for nomination under 16th and 17th rounds, which will follow in rapid succession.

Fifteenth round acreage comprises all unlicensed blocks in mature gas sectors of the central and southern North Sea.

"The intention of the round is to encourage early exploration in the gas prone areas," said Eggar. "In this way, new gas discoveries can be tied into existing infrastructure."

Another intention is to boost availability of gas for the planned Interconnector pipeline from Bacton in Lincolnshire to Zeebrugge, Belgium. The interconnector is intended to allow exports of U.K. gas to Europe, then imports once U.K. gas runs out (OGJ, Nov. 15, 1993, p. 29).

"I want to see this acreage explored quickly," said Eggar, "with commitments from companies to early drilling in the blocks awarded. I am therefore seeking applications by July 26 with a view to announcing awards this autumn."

Eggar also requested nominations from oil and gas companies for blocks they would like to see offered under a 16th licensing round.

This will cover "sub-mature" areas including West of Shetland, the central North Sea from the Scottish coast out to mature acreage, coastal stretches along the Southern Gas basin, the Irish Sea southeast of the Isle of Man, and the English Channel.

Nominations were due July 26. Eggar expects to announce this autumn blocks offered under the 16th round. Applications for acreage will be required by March 1995, with a view to awards of licenses in summer 1995.

When he announces the 16th round blocks, Eggar also will indicate his intentions for a 17th round, which will comprise frontier acreage.

Nominations will be requested for acreage around the Rockall area northwest of Scotland, the channel between the Hebrides and Scotland's northwest coast, the North Channel between Southwest Scotland and Northern Ireland, and areas off the southwest coast of England.

Evidence of changing U.K. exploration trends came from Jo Armstrong, head of business economics at Royal Bank of Scotland plc, Edinburgh, who said U.K. exploration drilling fell 30% last year, while appraisal drilling dropped 25%.

This could indicate that oil companies are now focusing on confirming existing reserves rather than attempting to find longer term additions," said Armstrong.

"A Department of Trade & Industry survey of intentions has shown operators expect a 16% reduction in the number of new exploration and appraisal wells in the current year, followed by a slight rise in 1995."

Armstrong said the U.K.'s exploration decline was confirmed by DTI's estimate that exploration spending was down 21% in 1993 to 864 million ($1.29 billion) compared with the previous year.

Only 35 exploration and appraisal wells were spudded off the U.K. in the first half of this year, according to Wood Mackenzie, the lowest half-year total since 1981.

The analyst blamed the fall on last year's removal of tax allowances on exploration and appraisal drilling and on low oil prices early this year. In 1990 U.K. exploration and appraisal drilling reached a peak of 214 wells spudded.

MORE ACREAGE

In June Denmark's Ministry of Energy proposed to parliament a fourth licensing round, which will open up more of the country's offshore to oil company participation.

Chief among the ministry's proposals are that:

  • Operatorships may be awarded to foreign oil companies instead of only to state owned Dansk Olie & Naturgas AS (DONG).

  • DONG will not have first refusal on concessions.

  • State participation will be fixed at 20%, with no sliding scale buy-in after development approval.

  • DONG will pay its share of costs.

  • There will be no royalties on any production.

Acreage earmarked for offering to companies ties in the Central Graben area at the western extremity of Denmark's offshore sector. It includes all unlicensed blocks and partial blocks in Quadrants 5603, 5604, 5605, 5503, 5504, and 5505 and in the column of blocks at the western side of Quadrants 5606 and 5506.

The ministry said there will be no formal block nomination prior to the round. Several companies were said to have indicated their choice of acreage to the ministry in what is seen as Denmark's most prospective area.

If the proposals are approved, the ministry expects to open the round in time for applications to be completed by Dec. 1.

New licenses would then be awarded in the new year.

BP's West of Shetland success has encouraged the government of the Faroe Islands, which he northwest of the Shetlands across a deep channel, to open up for oil and gas exploration.

In June Western Geophysical Corp. began a 2 year program to collect 12,000 line km of seismic data covering much of the Faroes' territorial waters. This data will be used to guide a proposed licensing round.

The Faroes' shelf is thought to be a continuation of West of Shetland formations. Operators active in the West of Shetland area have been in discussions about survey data, and Statoil has been meeting Faroes government representatives.

The government of the Isle of Man, halfway between Britain and Ireland in the Irish Sea, has also decided to try for a slice of the oil and gas action.

Companies have been invited to nominate areas within the island's 12 mile territorial limit for offering in a first licensing round. This will be timed to coincide with the U.K.'s 16th round, which will include nearby Irish Sea acreage.

REDEVELOPMENT PROJECTS

Among the North Sea's largest projects are redevelopments of old fields.

On July 1 Shell/Esso closed down Brent B platform for 1 year for major engineering work in a redevelopment of Brent field-one of the biggest offshore projects ever.

The company is preparing to remove accommodation and process modules from Brent B in mid-September. New modules will be installed in late September, bringing safety standards in line with recent regulations and preparing for depressurization of the reservoir to extract oil otherwise unrecoverable (OGJ, Apr. 12, 1993, p. 28).

Brent C and D platforms will also be closed down in turn for similar operations. Shell/Esso hopes the second and third platform refurbishments will take less than a year each because of lessons learned on Brent B.

In July Brent C was shut down to allow installation of a knee-brace to strengthen support for the topsides. The brace comprises diagonal supports installed between the jacket legs and the underside of the deck.

Shell/Esso is also refurbishing Dunlin field facilities on Block 211/23a under a 100 million ($150 million) program. On July 1 Shell/Esso shut down production from Dunlin for 7 weeks to allow major engineering work to take place.

A living quarters module was installed on Dunlin A platform by the DB 102 heavy lift barge. The new accommodation unit contains a temporary refuge to bring the platform in line with U.K. safety regulations.

Dunlin's estimated original reserves of 384 million bbl of oil are more than 80% depleted. The field has been producing about 27,000 b/d recently, having peaked at 115,000 b/d in 1979. The field was expected to be closed down around 2000, but refurbishment was said to extend Dunlin's life expectancy well into the next century.

Redevelopment also is in progress at Ekofisk field in the Norwegian sector. Norway's Ministry of Industry & Energy agreed to the extension of Phillips Petroleum Co. Norway's production license for Ekofisk, enabling the operator to begin the $3 billion project.

The license was to have expired in 2011 but will be extended to 2028 under proposals to be debated in the Storting this autumn.

NPD demanded substantial work on Ekofisk to make the field's tank platform safe after years of seabed subsidence.

The choice of short term or long term redevelopment work depended on license extension.

Government approval will enable Phillips to add two platforms in Ekofisk: a wellhead platform in 1996 and a process and transportation platform in 1998.

These will be linked into the existing Ekofisk complex. As fields in the complex are depleted and platforms become redundant or sink below the wave clearance accepted as safe by NPD, facilities in Ekofisk and satellite fields will be closed down.

Ekofisk field in 2011 will be a much smaller complex than it is now (OGJ, Apr. 4, p. 40). Phillips' next main issue with Norway's authorities is likely to be over abandonment: Can redundant platforms be shut down and left in the field until 2028, or must each structure be abandoned as its useful life expires?

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