WEATHER WINDOW ACTIVITY SLOWS OFF NORTHWEST EUROPE

Field development off Northwest Europe during the summer weather window saw a gear change downward from the brisk pace of 1993's window.

Last year was marked by severe storms, yet operators completed one of the most productive drilling and development seasons since the North Sea opened to the oil industry.

Weather around the North Sea has been relatively calm this year. So has the pace of work in one of the slackest weather windows in years.

The slow pace of work occurred largely because much of the major infrastructure needed for development is in place. What's more, friction between governments and operators put the brakes on development in some sectors.

Yet while the two main producing regions, Nor-way and the U.K., have come to terms with the effects of maturity, both regions have seen exploration that is enhancing new plays.

Although development is in the doldrums off Northwest Europe, production is not. This year has seen North Sea production reach new heights.

PRODUCTION

U.K. oil production reached its highest level since April 1988 as the maintenance season drew to a close. Figures published by Wood Mackenzie Consultants Ltd., Edinburoh, show that U.K. offshore oil flow averaged 2.59 million b/d in September compared with 2.43 million b/d in August, when U.K. production surpassed Norway's to reverse the trend of the past 2 years.

Norwegian production rebounded to average 2.67 million b/d in September from 2.1 million b/d in August, This was near peak Norwegian production of 2.68 million b/d achieved in May. The upswing marked the end of most summer maintenance pro,-rams.

Danish oil production averaged 176,000 b,d during September, up 4,000 b/d from August. Dutch offshore production remained flat at 50,000 b/d for September, down 2,000 b/d from August.

Wood Mackenzie said, "The current level of U.K. production is due to the combined effects of completion of the summer shutdown season and, more important, the near full contribution of many of the fields which have commenced production oxier the last 12 months or so."

East Brae, Alba, Nelson, and Beinn fields steadily increased production since starting up last December, January, February, and March, respectively.

Throughout 1990 and into early 1994, U.K. operators brought on stream a number of large new fields that may represent the last major field developments off the U.K. (OGJ, Nov. 1, 1993, p. 23).

The trend toward lower cost developments and the smaller size of fields being found on the U.K. shelf combined to make giant platforms a less attractive option than floating production systems, subsea development, and, increasingly, extended reach drilling from existing platforms.

LANDMARKS

Among this year's production milestones, Chevron U.K. Ltd. produced its billionth barrel of oil from U.K. North Sea's Ninian field on the morning of Oct. 2. Ninian, which went on stream in December 1978, is estimated to have contained original oil in place of about 2.5 billion bbl.

"Only two other U.K. fields, Brent and Forties, have reached this milestone," said Charles Smith, managing director of Chevron U.K. "Ninian now ranks as the first Chevron operated field outside the U.S. to have surpassed the billion barrel mark."

Satellite development of nearby Lyell, Staffa, and Strathspey fields for third parties has extended the life expectancy of Ninian. Last year, Chevron said four more fields with combined reserves of 100 million bbl of oil will also be developed as Ninian satellites (OGJ, Dec. 13, 1993, p. 24).

Last month, Ranger Oil (U.K.) Ltd. completed the first development well on the D terrace of Columba field, which lies in U.K. North Sea Block 3/7a. The well was drilled from Ninian Southern platform in Block 3/8a.

Columba partner Sun Oil Britain Ltd. said the well was drilled to 18,500 ft. It was producing 11,000 b/d of oil on an extended test that will continue to yearend. Sun estimated Columba D terrace reserves at 13-20 million bbl of oil.

Another landmark showed up in November when Norway's Den norske stats oljeselskap AS disclosed it will have to shut down one of three Statfjord platforms to keep production from the field profitable beyond 2003. That marked Statfjord's addition to a list of aging giant fields made up of Forties, Brent, and Ekofisk, all of which are undergoing some stage of transformation.

Statoil said shutdown of Statflord A platform will enable the field to be operated profitably until the production license expires in August 2009. Statoil reckons 2.9 billion bbl of the field's 3.9 billion bbl oil reserves will have been produced by yearend 1994.

BRENT PROJECT

Shell U.K. Exploration & Production (Shell Expro), operating company for the Shell U.K. Ltd.-Esso Exploration & Production U.K. Ltd. combine, has begun a massive program to redevelop Brent oil field as a gas producer.

Brent Bravo platform was shut down for about a year beginning last July 1 as part of a 1.3 billion ($1.95 billion) redevelopment program that calls for closure of each of the field's four platforms.

This year the DB 102 heavy lift barge removed accommodation and process modules and the flare stack from Brent B and replaced them with new units.

The new accommodation unit was built to meet recent offshore safety rules that require a temporary safe refuge in living quarters isolated from production equipment and protected by fire and blast walls.

The new process module contains low pressure production equipment. This will be needed when depressurization of the Brent reservoir begins in 1997 to take gas of out solution, enabling recovery of otherwise unreachable oil and gas reserves.

While the old modules were off the platform, Shell Expro undertook strengthening work but found the amount of strengthening needed was much larger than expected.

Extra strengthening involved an additional E20 million ($30 million) outlay, but Shell Expro believes this will be recouped in work on the other Brent platforms with the help of "hands on" experience on Brent B.

Major lifts were completed on Brent B late in October. Hook-up is expected to continue until about August, when Brent Charlie will be taken out of service for a similar year long program.

Shell Expro advanced a 100 million ($150 million) refurbishment of Dunlin A platform this season, involving replacement of the accommodation unit and processing equipment.

EKOFISK

Phillips Petroleum Co. Norway has begun preparing for redevelopment of giant Ekofisk oil and gas field, a 1968 discovery.

Ekofisk redevelopment calls for two new platforms to be installed by 1998 to take over activities currently carried out on platforms that are sinking below a safe level because of seabed subsidence.

Although no installation work has taken place this year, Ekofisk has dominated the thoughts of Phillips. The company hopes its redevelopment plan will win final acceptance when debated by Noay's Storting (parliament), which was scheduled for last week.

Phillips is pondering the choice of a steel or concrete structure for the transportation and storage platform it intends to place on operation in 1998.

The company apparently is under pressure from Oslo to consider the concrete option even though a concrete structure might lead to delay of start-up by at least a year. That will take it beyond the time limit for safe operation of the platform set by the Norwegian Petroleum Directorate (NPD).

A Phillips official said a steel jacket would enable seabed installation work to proceed ahead of topsides completion. But a concrete platform would require base structure and topsides to be installed in the field at the same time, thus causing a delay.

Meanwhile, Phillips continues development and exploration drilling in the Ekofisk area, The Maersk Guardian jack up rig is working in Eldfisk field on Block 2/7. The rig will drill two development wells with horizontal sections.

Next March the rig will move 2 km away on the same block to drill a 4,300 m new pool wildcat on the Edgar chalk prospect. Phillips also has options to drill two more wells in Ekofisk area next year.

HEIDRUN

The most impressive Northwest European project under development this year is Heidrun field off Norway in the Norwegian Sea. Heidrun will be only the second field on production off Central Norway when it goes on stream next year.

Heidrun is being developed with the world's first concrete tension leg platform (TLP). It lies in 350 m of water on Block 6507/7.

Also a first for Norway, Heidrun will rely on oil offloading directly into shuttle tankers for export with no oil storage capacity in the field's permanent structures.

Conoco Norway Inc. operates Heidrun. The company estimates field reserves at 750 million bbl of oil, 9.35 billion cu m of associated gas, and a gas cap containing 37 billion cu m (OGJ, Aug . 15, p. 62).

Norwegian Contractors AS, Oslo, installed four foundation units during the summer to tether the TLP. A pioneering installation method was used and is likely to see further use next summer when BP Exploration Operating Co. Ltd. installs its Harding field gravity base structure.

Heidrun foundation installation took place during 18 days ending July 26. The four 21,000 metric ton foundation units were towed out to the field, then slowly flooded with seawater to begin a controlled descent to the seabed.

An umbilical control cable to surface enabled control of ballasting, positioning, and seabed penetration. Ballasting and descent took less than 12 hr (OGJ, Aug. 15, p. 40).

Heidrun's five major topsides modules have been mated to the structure's concrete hull in a fjord off Stavanger. During September the modules were floated on barges over the almost submerged hull and fixed onto two support beams.

The five modules, weighing a total 38,000 metric tons, were installed in 7 days ending Sept. 18. By Sept. 22, remaining equipment, including lifeboat stations and flare modules, had been installed, boosting total topsides weight to 40,370 metric tons.

Hook-up and commissioning of the TLP began in the fjord last month. Conoco aims to float out the structure next June ready for installation on the field.

DUNBAR

The largest current project in the U.K. North Sea is development of Dunbar field, involving installation of an 8,600 metric ton topsides on a 9,200 metric ton, four legged steel jacket.

Dunbar platform was installed in Block 3/14a as a satellite of North Alwyn field. Dunbar in turn will have two satellite subsea field developments, Ellon and Grant (OGJ, Aug. 15, p. 68).

Estimated Dunbar reserves are 134 million bbl of oil and 26 billion cu m of gas. The platform, installed in 14-3 m of water, has production capacity of 50,000 b/d of oil and 9 million cu m/day of gas.

By early November, operator Total Oil Marine plc had completed hookup and commissioning on Dunbar platform, expected on stream by yearend.

Development of Dunbar relied on tender assisted drilling. At least 16 production wells are thought necessary to deplete the complex reservoir, while a further six are expected to be needed for water or gas injection.

Six Dunbar field wells, along with two in Ellon field, were predrilled. A Total official said in early November the rig had begun reentry of predrilled wells to prepare them for production.

Total intends for early production to involve two wells in Dunbar and one in Ellon field. Total originally slated first oil from Dunbar by yearend, but the company now expects first production sooner than that.

NEW PRODUCTION

Early in the year Chevron brought on stream Alba after development work during the 1993 season was delayed by teething troubles with emergency shutdown systems (OGJ, Jan 31, p. 46).

Toni field was brought on stream by Agip (U.K.) Ltd. last January as a subsea satellite of Tiffany field, which started production late last year.

First oil from Nelson field in February perhaps marked the end of the era of large oil production platforms for the U.K. sector (OGJ, Feb. 28, p. 29).

Beinn field was developed by extended reach drilling from North Brae field by Marathon Oil U.K. Ltd. The field had been on extended production test since December 1992, so first oil was a nominal occurrence (OGJ, Nov. 29, 1993, p. 28).

This year's new production has come from relatively small fields.

Off the U.K., BP developed Medwin field by means of a single extended reach well from Clyde platform.

West Gullfaks field off Norway also was developed with extended reach wells by Statoil from Gullfaks B platform. Also off Norway, Elf Norge as brought on stream Lille Frigg as a subsea satellite of Frigg field.

Back in U.K. waters, BP started production from Machar field but only as a 1 year extended production test to determine reservoir behavior as a prelude to full scale development of Machar and eight other fields in the Eastern Trough Area Project.

In mid-August, Mobil North Sea Ltd. reported that Excalibur gas field in U.K. North Sea Block 48/17a was brought on stream ahead of the October deadline. The 250 bcf field was developed using a wellhead platform sending gas to nearby Lancelot field for processing and export.

In September, Clyde Petroleum plc, Ledbury, U.K., announced first gas production from Q8-B gas field off Netherlands in the only new production reported from the Dutch sector this year.

Q8-B gas is produced from a single well tied back to an unmanned, reusable platform. Gas moves through a 9 km, 8 in. pipeline to Q8-A gas field, where it joins an existing line to Clyde's onshore processing plant at Ijmuiden. Clyde said the field was brought on stream 10 months from project sanction at a cost of 9 million ($13.5 million).

In October, Statoil began production from East Statfjord field as a subsea satellite of giant Statflord field. Development involves six wells tied back to Statfjord C platform via two subsea templates and four water injection wells operating through a separate template. First production was from one well, although three more have been completed. East Statfiord reserves are estimated at 155 million bbl of oil and 130 bcf of gas.

Shell Expro began production Oct. 1 from Galleon gas field in the southern U.K. North Sea. The 200 million ($300 million) development program involved a wellhead platform sending gas to a new metering and compression platform in the Clipper complex 8 miles away. Galleon reserves are estimated at 1.4 tcf of gas, with production at rates of as much as 190 MMcfd.

Hamilton Oil Co. Ltd., London, began commercial gas production Oct. 1 from Johnston field in U.K. North Sea Blocks 43/26a and 43/27. Plateau production is expected to be 53 MMcfd.

The 58 million ($87 million) development involved installation of a 200 metric ton subsea wellhead template with four well slots and a 12 in. pipeline to North Ravenspurn processing platform 7 km away.

WEST OF SHETLAND

While development levels have been relatively low off Northwest Europe this year, activity in the area west of the U.K.'s Shetland Islands has been comparable with the "good old days." BP has been most active in drilling West of Shetland.

A milestone on the way to opening this new play came early in August, when BP disclosed a contract for conversion of a support vessel to a production ship for development of Foinaven field (OGJ, Aug. 8, p. 75).

Foinayen, due on stream in late 1995 or early 1996, will be the first field development west of the Shetland Islands.

Amerada Hess Ltd. early in October confirmed that BP's Schihallion field discovery extends into a block on which it is operator. Block 204/20 Schiehallion field was discovered last year by BP and has estimated reserves of 250-500 million bbl of oil.

Amerada's 205/25a-2 well was drilled 3 km southwest of BP's discovery well in 1,140 ft of water using the Sonat Arcade Frontier semisubmersible rig.

Amerada disclosed Oct. 3 that its well tested hydrocarbons from several horizons. It flowed at a maximum 5,304 b/d of 27' gravity oil on test, with a gas:oil ratio of 320:1.

An Amerada official said it is too early to decide whether well results will affect field reserves estimates. The company plans talks with others involved in Schiehallion before deciding on further drilling plans.

The Amerada official also said the company's Stronsay discovery, which lies on the border of Blocks 204/30a and 205/26a about 30 km south of Schiehallion, has been identified as two structures in different formations. These have tentatively been named Solan, which lies in Jurassic sands, and Strathmore, which lies in Triassic.

Further drilling of Solan and Strathmore is slated for next year. Amerada said estimated reservoirs are 100-250 million bbl in total for the two reservoirs (OGJ, June 20, p. 16).

In October, BP Exploration Operating Co. Ltd. sent almost half a million barrels of oil from Foinaven field to market following an extended well test. This was the first oil produced and saved from the area.

The Ocean Guardian semisubmersible rig reentered BP's 204/24a-4 appraisal well and carried out an extended well test from Aug. 15 to Sept. 29. The well flowed as much as 20,000 b/d of 26' gravity oil on test with an average flow rate of 17,800 b/d.

A total 437,000 bbl of oil was processed during the test and stored in the Vigdis Knutsen tanker. When the test was complete, the oil was sent to BP's Rotterdam refinery.

BP recently spudded two more wildcats West of Shetland. Wood Mackenzie said the start of development drilling in Foinaven is likely before yearend.

The analyst said 18 companies have nominated 63 full and 13 partial blocks for inclusion in the 16th U.K. offshore licensing round. Award of licenses is expected next summer.

DEVELOPMENT APPROVALS

During the summer, Norway's operators imposed a moratorium on major field developments, with Norne, Njord, and Visund field projects shelved until the government offered improved economics (OGJ, Sept. 26, p. 29).

In the end, government relaxed licensing terms a little. While operators complained terms were still too tight, Statoil was first to end the deadlock by submitting a development plan for Norne field to the Ministry of Industry & Energy on Sept. 21.

Development cost for Nome is officially quoted as 9.8 billion kroner ($1.3 billion). However, project engineers have said this figure may be reduced by 20-30%, judging by bids for a proposed production ship development (OGJ, May 23, p. 23).

Norne production is expected to reach a plateau of 150,000 b/d of oil. Operating costs are expected to be about 620 million kroner ($85 million)/year.

Next applications for major Norwegian field developments are likely to be for Vigdis and Njord fields.

Vigdis operator Saga Petroleum AS intended to submit an application by the end of October. This will detail a subsea tieback to Snorre field to develop reserves estimated at 180 million bbl of oil and 70 bcf of gas.

Njord operator Norsk Hydro as intended to invite bids during October for a floating production system development of the field. Njord is estimated to hold reserves of 280 million bbl of oil and 1.6 tcf of gas.

Depending on cost estimates, Hydro intends to judge field commerciality before submitting a development application in February 1995.

Meanwhile, Norwegian gas field development may be encouraged because Norway's Gas Supply Committee (FU), which decides what fields will supply gas for particular contracts, announced in late October that operators have until Aug. 1, 1995, to submit proposals for meeting existing European sales commitments.

FU plans to submit to the Ministry of Industry & Energy by Oct. 30, 1990, recommendations on phasing in of new gas fields. Statoil and Saga recently submitted a plan for joint development of Norwegian Sea gas fields to meet current gas sales requirements (OGJ, Oct. 31, p. 20).

U.K. operators have seen development plans approved by Department of Trade &- Industry (DTI) throughout the year, with Armada, Ganymede and Calhsto, Bessemer and Day, and Barque fields among a flurry of planned gas developments (OGJ, Aug. 15, p. 56).

In September, BP won DTI approval for development of Harding field, previously known as Forth, in Central North Sea Block 9/23b.

Estimated Harding reserves are 185 million bbl of oil and 200 bcf. First production is slated for December 1995, with plateau flow expected at 64,000 b/d of oil. Gas will not be recovered until oil production has ended.

Harding is being developed using a jack up production platform perched on a concrete gravity base storage unit (OGJ, Aug. 15, p. 56).

In September, Shell Expro secured DTI approval for development of East Sean field in U.K. North Sea Block 49/25a. East Sean field reserves are estimated at 130 bcf of gas.

Shell Expro said the 25 million ($37.5 million) development will involve production through two extend.ed reach wells drilled from the existing Sean field wellhead platforms. One well was completed in August, and a second was spudded shortly after. First gas is slated for November at as much as 60 MMcfd.

In October, ARCO British Ltd. received DTI approval to develop Gawain gas field in North Sea Block 49/24. ARCO will carry out design work, while drilling will be carried out by equal partner Mobil North Sea Ltd.

Gawain development will involve three extended reach wells tied back via subsea template to Thames field by a 12 in. pipeline. Design will be similar to that of ARCO's recent Orwell field development, so costs will be significantly less than the 100 million outlay ($150 million) for Orwell. Gawain reserves are estimated at 190 bcf of gas, with first production slated for Oct. 1, 1995.

EXPLORATION DRILLING

NPD figures show 12 discoveries have been made so far this year off Norway, with total reserves estimated to be 75-135 million metric tons of oil equivalent (see map, OGJ, Sept. 26, p. 31).

An NPD official said more drilling will be needed to firm up the estimate figures and establish commercial viability of the finds. This is expected to have to wait on current talks between government and operators over ways to reduce development costs.

The official said largest of this year's finds is thought to be Statoil's gas/condensate discovery on Block 34/11, which lies next to the block holding Gullfaks and South Gullfaks fields.

However, Statoil sees the 34/11 discovery as one of several undeveloped gas finds in the vicinity. Based on the discovery well, reserves are tentatively pegger at more than 2 tcf of gas and 125 million bbl of condensate.

A Statoil official said the find was only likely to jump ahead of other nearby ga; discoveries in the development queue if the prospect of exploiting the condensate makes field economics more attractive.

The Ross Rig semisubmersible drilled the discovery well to 4,556 m. The well discovered gas in middle Jurassic sandstone. Statoil is considering an appraisal well for next year.

In mid-September, Esso Norge AS announced an oil discovery on Block 25/8 off Norway, which a company official described as a very good reservoir.

The find was made by the Dyvi Stena semisubmersible drilling for Enterprise Norge AS under a farmout agreement to earn a 50% interest in Esso's license. The 25/8-5S well was spudded July 21 as the first of a three well program to be drilled by Enterprise on the block. It was drilled to 3,395 m measured depth.

Enterprise perforated and tested a 31 m zone in a Paleocene formation. This flowed at a sustained rate of 7,000 b/d of 36' gravity oil through a 2 in. choke.

Esso has already made two discoveries on the block, although neither has been placed on production. The Balder prospect, 28 km south of the new find, is being evaluated for development.

"It would be hard to beat Balder for reservoir complexity," Esso said. "Balder has been mapped and thoroughly drilled. A team is evaluating development options, including floating production systems."

The Hermod discovery is thought to be one of the biggest off Norway in recent years. Although only one well has been drilled in Hermod, NPD has estimated reserves at about 60 million metric tons of oil equivalent. Esso said further mapping and appraisal is necessary.

Of the new discovery NPD has said it is too early to estimate its size, but it is viewed as "very interesting." Enterprise will drill a second well next year to appraise the find.

The Esso official said that, on an excitement scale of 1-10, the new find is rated between 5 and 10 by the company. NPD said these finds may lead to development of a new North Sea oil province in Norway's Balder area.

Although U.K. attention has been drawn to West of Shetland drilling, operators have had successes in mature areas and in new plays. Conoco (U.K.) Ltd. drilled the first well on U.K. Block 49/16 in 20 years and gauged 73.4 MMcfd of gas during tests.

In September, ARCO booked success with a well drilled 2 miles west of its Block 44/18 Tyne discovery in the U.K. southern North Sea. The 44/18-4 new pool wildcat flowed 46.5 MMcfd of gas through an 11/64 in. choke.

The find was made in Carboniferous sandstone with a well drilled by the Rowan Halifax jack up to 13,273 ft. ARCO said results from this well will help determine a schedule for development of Tyne.

In October, Elf Exploration U.K. plc spudded a wildcat on Block 111/29 of the U.K. Irish Sea. Elf said this is the first wildcat in the area.

Maersk Vinlander semisubmersible rig was expected to take 6-8 weeks to drill the well, after which it will leave the area. Elf said Mobil North Sea Ltd. plans to earn a 50% interest in the block.

Early this month, Marathon Oil U.K. Ltd. disclosed the first hydrocarbon discovery in St. George's channel off South Wales in the U.K. Irish Sea. The company completed two tests on its 103/1-1 well, drilled in 318 ft of water to target Jurassic below 7,500 ft.

The first test of 124 ft of perforated interval flowed at a stabilized rate of 21 MMcfd of gas, 120 b/d of 42' gravity liquid hydrocarbons, and 55 b/d of water with flowing tubing pressure of 800 psi through a ; '/64 in. choke.

A second test included the initial interval and an extra 15 ft of perforated interval about 75 ft below the original pay. It flowed 19 MMcfd of gas, 70 b/d of liquid hydrocarbons, and 215 b/d of water with flowing tubing pressure of 986 psi through a 72/64-in. choke.

A Marathon official said the company was encouraged by the find but cautious. Further seismic surveys and appraisal drilling will be required to assess commerciality of the reservoir.

Further drilling can take place from mid-1995 at the earliest. Seismic surveys are under way and are expected to be complete easy in December.

DENMARK, NETHERLANDS

Denmark and Netherlands throughout the year have seen relatively little action compared with previous years.

Denmark is waiting for block applications under a fourth offshore licensing round, with new terms designed to attract new operators to the region.

Denmark's Ministry of Energy has extended the deadline for applications 1 month to Jan. 2, 1995.

Development drilling is reported in Tyra, Gorm, and Skjold fields, although no new fields have been placed on stream this year.

Activity off Denmark is expected to increase next year as work gets under way to bring Harald and Svend fields into production in 1997. Both will be small platform developments tied back to Tyra field.

Apart from Q8-B field, which operator Clyde reckons is the smallest find placed on stream in the region, activity off Netherlands has been stalled.

Government and operators agree that incentives are needed to encourage development of Netherlands' small gas fields, but they cannot agree what the terms should be. A ninth exploration licensing round slated for April 1995 is not expected to revive interest in the sector to a great degree (OGJ, Aug. 1, p. 23).