David Knott
International Editor
Oil companies have grown to accept the maturity of the North Sea as an oil province. Operators are increasingly facing tests of innovation and cost control in developing new fields.
In the last year, however, three of the oldest and most important North Sea developments have been given a new lease on life. Redevelopment plans for Ekofisk, Brent, and Forties fields show that application of recent technology to aging assets can be as worthwhile as development of new projects.
On July 1, Phillips Petroleum Co. Norway submitted a long-term safety plan for the processing and transportation tank platform in giant Ekofisk field, which will involve installing a new processing platform in 1998.
Phillips also outlined plans for a radical redevelopment of Ekofisk field, depending on the Norwegian government's extending the production license beyond the current expiration date in 2011.
Norwegian Petroleum Directorate (NPD) said last October that Ekofisk would be closed down by winter 199596 if safety problems arising from seabed subsidence and inadequate maintenance were not solved (OGJ, Oct. 19, 1992, p. 42).
To meet NPD's safety requirements with the production license as it stands, Phillips committed to installing new processing facilities on a separate platform in 1998 and to performing all additional modifications needed to continue safe operations on Ekofisk's tank platform.
One estimate put the cost of a new processing platform at $1 billion (OGJ, Apr. 12, p. 27). Transportation and storage of oil and gas would continue to be handled by the existing tank platform, modified as required by NPD.
Phillips said 600,000 b/d of oil passes through Ekofisk to Teesside, U.K., and more than 2 bcfd of natural gas is sent to Emden, Germany.
EKOFISK II
By the end of the year, Phillips also intends to submit to the Norwegian Ministry of Industry & Energy a plan to redevelop Ekofisk under a new production license in a project costing up to $4 billion.
"In addressing the NPD's concerns regarding safety issues at Ekofisk, we are considering a comprehensive plan to build new facilities called Ekofisk II," said Knut Am, managing director of Phillips Norway.
"We have considered future production, processing, and transportation well beyond the present license expiry date in the year 2011."
Ekofisk II would involve removal of all tank platform functions to new platforms. The present tank platform would be shut down on completion of new facilities.
Am said Ekofisk II envisions optimum long-term redevelopment of the Ekofisk Complex provided that the licensees are assured participation in the project for its economic life.
Phillips is evaluating its Ekofisk reservoir management strategy to ensure maximum ultimate recovery of oil and gas from the field, said Am. Remaining oil reserves are believed to be 1.3 billion bbl.
Although detailed technical solutions have not been completed, said Am, the preliminary cost estimate for the Ekofisk II plan is in the range of $3-4 billion. He expected the plan to be discussed in Parliament during 1994 in order to meet the planned 1998 start-up.
Ekofisk field partners are: operator Phillips 36.96%; Fina Exploration Norway Inc. 30%; Norsk Agip AS 13.04%; Elf Petroleum Norge AS 7.594%; Norsk Hydro AS 6.7%; Total Norge AS 3.547%; Den norske stats oljeselskap AS (Statoil) 1%; Elf Rex Norge AS 0.855%; and Norminol AS 0.304%.
BRENT REDEVELOPMENT
In April, Shell U.K. Ltd. and Esso U.K. plc announced they would redevelop the largest U.K. oil field, Brent in North Sea Block 211/29, at a cost of 1.3 billion ($1.95 billion).
Shell/Esso operating company Shell U.K. Exploration & Production will begin next year a 5 year program involving major refurbishment on three steel platforms and upgrading of a fourth to act as an export center.
Key to redevelopment will be a lowering of pressure in the Brent reservoir, which will give Shell/Esso access to 34 million bbl of oil and 1.5 tcf of gas that would otherwise remain in place (OGJ, Apr. 12, p. 28).
The plan hikes Brent's ultimate recoverable reserves to nearly 2 billion bbl of oil, over 5.5 tcf of gas, and some 620 million bbl of NGLs It will change Brent from the U.K.'s biggest oil producer and third biggest gas producer, with output peaking in 1985-86 at 416,000 b/d and gas output set at 500 MMcfd in 1986, into a major gas field.
Production from Brent was originally slated to end in 1998, but redevelopment will extend field life at least 10 years.
"The Brent redevelopment is a landmark in world oil history," said Shell Expro Managing Director Chris Fay. "It is a daunting task, far more difficult than developing a new field."
Brent platform substructures will not be replaced by Shell/Esso, but the plan to depressurize requires replacement of complete gas processing modules on three platforms.
While Brent Bravo, Charlie, and Delta platforms in turn undergo major topsides work, with each being out of action for about a year, Brent Alpha will be used to deplete the southern part of the reservoir at high pressure.
Once this is complete, Alpha will act mainly as a gas gathering point until production is wound down early next century.
FORTIES FACELIFT
BP Exploration Operating Co. Ltd. has been producing oil from Forties, the first U.K. North Sea oil field, since September 1975. When plateau production of 500,000 b/d was passed in the early 1980s, other oil producers took up spare capacity in the Forties pipeline and processing system to minimize outlay in developing fields nearby.
Forties lies in North Sea Blocks 21/10 and 22/6 in 420 ft of water, with original reserves of 2.5 billion bbl. Four fixed steel production and drilling platforms and a smaller minimum-facilities platform produce oil for export by pipeline to Cruden Bay and further transport across land to the Grangemouth refinery and to an export terminal at Hound Point.
Inspection of the existing 32 in. Forties pipeline in 1989 revealed corroded sections would need to be replaced. BP decided to replace the pipeline completely rather than interrupt production through the Forties system, opting for a 36 in. pipeline capable of handling 1 million b/d of oil.
Extra capacity offshore meant two booster stations would be required on the landward tine from Cruden Bay to the Kinneil terminal next to Grangemouth refinery. A third gas processing train would be needed at Kinneil and an eighth storage tank and a second loading berth at Hound Point. A new 40 in. pipeline from the tank farm to the berths was needed to meet the increased loading requirement.
By the time the Forties facelift is completed in late 1993, BP will have spent $675 million. This includes construction and installation of a new riser platform, known as Unity, 3 miles west of Forties Charlie on Block 21/9.
Charlie platform is the main gathering point for Forties oil destined for pipeline export to Cruden Bay. The unmanned Unity platform was installed to handle fluids from Bruce, Scott, and Nelson fields as they come on Stream, and other future projects.
CURRENT DEVELOPMENTS
The North Sea is coming to the end of a period of heightened activity, with a number of major field developments approaching conclusion. These include the Troll, Scott, and Nelson projects, detailed elsewhere in this report.
Among other key projects is Draugen field in the Norwegian Sea, destined to be the first producing field off central Norway. Operator Norske Shell AS towed out the Draugen platform from Stavanger May 3 on a 10 day, 830 km journey said to be the longest tow of a fixed platform.
The concrete gravity base structure touched the seabed on Norwegian Sea Block 6407/9 early on May 17, where it was stabilized and grouted over the following 10 days.
On July 17 the construction vessel Regalia arrived at the field. The vessel's 364 beds plus 140 on the Draugen platform allow a 500 man team to work on final construction and commissioning, in readiness for first oil in October.
All subsea production installation work is complete. Fixed pipework has been installed between the platform and loading buoy. This will be followed by installation of flexible pipes and umbilicals from the subsea production wells, one gas injector, and a water injector.
First production will be from the two subsea wells. Six more production wells will be drilled from the platform during the fall, once commissioning has been completed.
Statoil saw installation of Sleipner A platform on Norwegian sector Block 15/9 completed in early July by Aker AS, Oslo.
The platform was positioned on the seabed June 15, after which Aker subsidiary Norwegian Contractors anchored the platform's concrete base to the seabed using large quantities of grout.
Statoil aims to begin gas deliveries from Sleipner on Oct. 1 as required under the Troll sales contract agreed in 1986. Development became a race against time when the original base structure sank during trials, and a near-duplicate replacement had to be built (OGJ, Oct. 28, 1991, p. 19).
West Sleipner field will be developed with two normally unmanned platforms linked by a bridge to Sleipner A (OGJ, May 10, p. 34).
NEW PRODUCTION
Phillips Petroleum Co. Norway began production from Embla field on Block 2/7 in May. The first well produced 9,000 b/d. Phillips is bringing three predrilled wells on stream to hike total output to 35,000 b/d.
Embla is the eighth field to send production through the Ekofisk complex with oil sent to the Eldfisk platform 5 km to the north for processing before export via the central Ekofisk tank platform.
Amoco (U.K.) Ltd. saw first gas delivered from Everest field on Block 22/10 in May. This marked completion of a twin fields and pipeline development linked to direct sale of gas for power generation.
Amoco announced first gas from Block 21/21's Lomond field in July, bringing combined output of Everest/Lomond to 200 MMcfd. Enron Corp. buys Everest/Lomond gas to power its 1,875,000 kw combined cycle cogeneration plant at Teesside (OGJ, Apr. 19, p. 23).
BP Exploration Operating Co. Ltd. set production under way on the U.K. sector's largest gas field, Bruce on Blocks 9/8a, 9/9a, and 9/9b. Bruce reserves are estimated at 2.6 tcf of gas and 220 million bbl of liquids.
First production was from the oil zone at 5,500 b/d. Total liquids output is expected to jump to 80,000 b/d in October as condensate is produced from the gas zones. Gas sales will start at 430 MMcfd in October, though this will rise to 530 MMcfd in 1994, some 10% of total U.K. gas requirements (OGJ, May 24, p. 36).
Conoco (U.K.) Ltd. saw first production from Block 3/2's Lyell field in April at 10,000 b/d. This will be raised to 18,000 b/d during the year as further wells are tied in to South Ninian platform, where operator Chevron U.K. Ltd. handles output from Lyell, Staffa, and soon Strathspey for third party operators (OGJ, Apr. 12, p. 31).
Amerada Hess Ltd. brought North Sea Hudson field on stream July 19, with 20,000 b/d of oil flowing from the first well. A second well started flow 24 hr later, taking total production to 38,000 b/d.
First phase production from the U.K. Block 210/24a field is handled by the Petrojarl 1 production ship. From November 1994 production will be through six subsea wells tied back to Tern platform 7 miles east. Tern is operated by Shell Expro (OGJ, Dec. 14, 1992, p. 26).
Two North Sea gas fields were brought on stream by Mobil North Sea Ltd., which used normally unmanned production platforms with combined capacity of 200 MMcfd. Block 48/17's Lancelot field has gas reserves of 210 bcf. Block 48/17b's Guinevere field has gas reserves of 75 bcf.
A pipeline carries gas over 4 miles from Guinevere to Lancelot, where it joins a 20 in. pipeline to Bacton gas terminal operated by Phillips Petroleum Co. U.K. Ltd.
EXPLORATION
BP Exploration Operating Co. Ltd. attracted U.K. industry attention in March when it claimed to have made the largest U.K. discovery in 5 years.
A Block 204/24a-2 appraisal well also drew the spotlight onto the area west of the Shetland Islands, where BP is leading a group of companies still discussing development of Clair field some 20 years after its discovery (OGJ, Mar. 15, p. 31).
Statoil is growing excited about its Norne discovery in 1,300 ft of water on Norwegian Sea Block 6608/10. With reserves estimated at 440 million bbl of oil and well tests that suggest production from the reservoir could be viable at 100,000-200,000 b/d, Statoil believes Norne is its biggest prospect in 8 years (OGJ, Mar. 15, p. 32).
The company said further drilling and interpretation of 3D seismic data could increase reserves estimates to above 600 million bbl of oil.
British operators are turning to exploration areas outside mature North Sea acreage, according to Wood Mackenzie Consultants Ltd., Edinburgh. Analyzing the results of the 14th offshore licensing round, Wood Mackenzie said only 27 blocks were awarded out of 136 offered in mature areas.
Most awards in mature blocks were for southern gas basin licenses. Conoco (T-I.K.) Ltd. and Total Oil Marine plc stimulated interest in this area by opening up Quadrant 44 with infrastructure to develop Caister and Murdoch fields (OGJ, Mar. 22, p. 31).
Marginal prospects received most attention, said Wood Mackenzie, accounting for 80% of all acreage awarded. This round carries only 93 commitment wells, compared with 167 commitment wells on 74 licenses awarded 2 years ago in the 12th round.
PRODUCTION FORECAST
Norway continues as the leading North Sea oil producer. Average crude and condensate output in April hit a record 2.44 million b/d, compared with U.K. oil output the same month of 1.75 million b/d.
At press time the most recent figures available from Wood Mackenzie showed Norwegian oil and NGL production averaged 2.36 million b/d in May, when production from the U.K. was 1.8 million b/d, from Denmark 156,000 b/d, and from the Netherlands 27,000 b/d.
Mackay Consultants, Inverness, predicted that North Sea oil production will increase by about 41% between 1991 and 1995 to reach 5.5 million b/d. Every producing country except Germany will see an increase over the period, said Mackay. Increases will be 44.4% in the U.K., 38.9% in Norway, 28.3% in the Netherlands, and 26.7% in Denmark. German production will drop by 8.5%.
North Sea gas output will also rise. Mackay predicted 1995 gas production of 140 billion cu in, up 30% from the 1991 level. Again, all producing countries but one will see an increase; this time, the decline will be for Ireland.
The output growth is seen as a result of the high level of development activity over the past 5 years, but the current level of activity is said to be much lower. Offshore oil output is expected to tail off after 1995.
Total offshore expenditure in the North Sea was estimated at $32.5 million in 1991. Mackay expects this to fall away to $27.5 million at constant 1992 values for 1995.
"The U.K. sector will continue to be the largest market, but it will account for most of the fall in expenditure," said Mackay. "Norway's share of the overall North Sea market will rise significantly, and in fact Norwegian oil production now exceeds that of the U. K.
"We are not predicting a substantial fall in North Sea activity, but our view is that the peak, as measured in offshore expenditure, was reached in 1990-91 and that the general trend for the rest of the 1990s will be of a slow decline."
Copyright 1993 Oil & Gas Journal. All Rights Reserved.