David Knott
Senior Editor
North Sea operations this year have been plagued by storms, a perennial problem off Northwest Europe,
Even so, operators continued to log progress in placing new fields on stream.
Early in the year, gales and high seas slowed how vulnerable North Sea operations are to weather.
In january a tanker went aground in the Shetland Islands during a storm, production in the Norwegian and U.K. sectors was disrupted, and construction work was halted. Further storms disrupted installation in February.
A tidal waste of U.K. development program completions has followed the 1992 peak in development spending. Seventeen U.K. offshore fields have gone on stream during 1993, compared with Norway's four, Netherlands' three, and Denmark's two.
Scottish Enterprise, Aberdeen, estimated U.K. development spending at 4.7 billion ($7.05 billion) last year and 4.4 billion this year ($6.6 billion). After this peak, U.K. capital outlay is predicted to tail off, falling to less than 3 billion ($4.3 billion) in 1997.
The agency sees 1993 as the development spending peak for western Europe as a whole, at 2.4 billion ($18.6 billion). This will fall to 10.9 billion ($16.35 billion) in 1994 and 10.1 billion ($15.15 billion) in 1995.
U.K.'s new fields rallied British oil production, pushing it back above the 2 million b/d mark. Norway continued to dominate the North Sea in terms of oil flow, however, with production hitting a record average 2.47 million b/d in July.
While analysts predicted a slow decline for the North Sea as a whole, one large oil discovery west of the Shetland Islands and another off mid-Norway raised hopes of more strike in quiet comers of the region.
Britain's government caused a storm of its own in March, when oil industry tax reforms forced U.K. operators to reevaluate their assets. This resulted in development projects being rescheduled, programs to extend the lives of older fields, and a slide in U.K. exploration and appraisal drilling.
Although the boom days are over for the North Sea, some operators are convinced that reduction of development and operational costs could yield opportunities in the region for years to come.
Here are selected highlights of the year's operations in the North Sea:
STORM DAMAGE
Storms early last january caused the U.K.'s biggest oil spill.
On Jan. 5 the Liberian registered Braer tanker was passing between the Orkney and Shetland Islands in a Force 10 gale.
The engine failed and the tanker began to drift. Attempts to attach lines to the ship to enable tugs to tow it out of danger were foiled by high seas. Braer struck rocks just after 11 a.m. (OGJ, Jan. 11, p. 26).
The 89,000 dwt vessel was carrying more than 600,000 bbl of crude oil. Rough weather kept salvage crews from working and prevented aircraft from spraying dispersant.
For 3 weeks salvage teams and cleanup crews were thwarted, until the vessel could be surveyed by divers for the first time Jan. 24. There was no cargo or bunker oil left on board.
Meanwhile, winds gusted to 100 mph in the northern and central North Sea. Oil producers had to shut down fields that relied on offshore loading.
Worst hit was Norway's Den norske stats oljeselskap AS, which lost production from its main fields, Statfjord and Gullfaks, several times during january and February.
Wood Mackenzie Consultants Ltd., Edinburgh, said Statfjord, Gullfaks, and Snorre fields had to defer a combined 7 million bbl of oil and natural gas liquids production in January.
Mobil North Sea Ltd. had to halve U.K. Benyl field production to 55,000 b/d in mid-january but said storage capacity. would enable output at this level until weather improved.
Nevertheless, Beryl suffered most on the U.K. side, with average production for January at 65, 000 b/d, compared with 110,000 b/d last December.
The Shell-Esso combine, with Shell U.K. Exploration & Production as operator, saw production from Kittiwake field average 8,000 b/d in January, compared with 30,000 b/d in December. Production vessels in Buchan and Donan fields, which both average about 12,000 b/d, were pulled out of fields for several days by operator BP Exploration Operating Co. Ltd.
EAST SLEIPNER
Among new fields placed on stream this year, development of Norway's East Sleipner gas field was the most pressured.
Operator Statoil laid its reputation on the line with a promise to deliver East Sleipner gas to European buyers Oct. I as scheduled, despite the sinking of the original gravity base structure for the platform in 1991.
East Sleipner was chosen as the first field to provide gas under the Troll sales contract of 1986. This deal committed Norwegian gas producers to supply 35 tcf, worth 700 billion kroner ($100 billion) at current prices, to Europe during almost 30 years.
On Sept. 29 the last of four production wells was tested to determine production rate. On deadline day, the target field flow of 370 MMcfd was achieved without the need to call on gas from other Norwegian fields.
First production from East Sleipner also gave the Zeepipe trunk line its first commercial use, Most of East Sleipner's gas was sent 830 km to Zeebrugge, Belgium, where it joined Europe's gas pipeline grid. The rest went through the existing Statpipe line to Emden in Germany.
Before East Sleipner began commercial gas production, delivery of condensate to Statoil's gas terminal at Karsto, north of Stavanger, began Sept.19.
Statoil reckons East Sleipner development cost 15 billion kroner ($2.1 billion). Despite the loss of the platform base, that was less than the original 1986 estimate of 18 billion kroner ($2.5 billion).
SCOTT
In the U.K. North Sea Amerada Hess Ltd. placed Scott field on stream Sept. 2. It is the biggest British oil field to be developed this decade.
Amerada Hess figures Scott will meet 10% of U.K. oil needs from reserves of 450 million bbl of oil and 287 tcf of gas.
Among main considerations in Scott development were the need to reach production start-up and production plateau quickly to improve field economics. First oil flow amounted to about 30,000 b/d. Amerada Hess then worked to hit a 180,000 b/d plateau within a month.
To achieve first oil quickly, the company reduced the period of offshore construction, hookup, and commissioning. A two platform development program was chosen. Processing, drilling, and production facilities are located on one platform, bridge-linked to a utilities and quarters platform.
The production platform jacket was installed on Block 15/22 in September 1992 using the DB102 crane barge. The utilities platform jacket was installed alongside last March.
Twelve topsides modules were installed throughout April, with a combined weight of 32,000 metric tons. The largest of these was the 10,360 metric ton process module. The last lift, on May 1, was of the two bridges linking the platforms.
Scott's use of the North Sea's most extensive subsea development allowed early production through predrilled wells. First production was from one of three well clusters tied back to subsea manifolds.
At plateau production, each well is designed to produce at least 25,000 b/d of oil. With seven wells on stream, the platform is designed to process about 200,000 b/d of oil (OGJ, Aug. 30, p. 68).
DRAUGEN
Norske Shell AS became the first company to produce oil commercially in the Norwegian Sea when Draugen field went on stream Oct. 19. Draugen reserves are 580 million bbl of oil and 100 bcf of gas.
The field lies in Block 6407/9, where water depth is 800-900 ft. The platform was towed out of Stavanger May 3. The 830 km journey northward took 10 days and was the longest tow of a fixed platform (OGJ, Aug. 30, P. 49).
Because of lack of infrastructure in the Haltenbanken area, Shell developed Draugen using a monotower platform with oil storage in the base to allow offshore loading into shuttle tankers.
First oil came from a subsea well 9 km from the platform. A second subsea well 3 km away will be placed on stream when tests are complete on the first well. Combined production from the two wells is expected to be 25,00040,000 b/d.
The first of four production wells is about to be drilled from the platform. These will help boost production to a plateau of 95,000 b/d in mid-1994. The platform has slots for 10 production wells.
Three water injectors have been drilled from the platform, as well as a gas injector. Three more water injectors are planned, the first of which is drilling ahead.
The platform's concrete gravity base houses seven oil storage cells which can hold 11 days' output-more than 1 million bbl. Oil will be exported in shuttle tankers leased from development partner Statoil.
Although gas will be used for power generation on the platform, most of it will be reinjected. Future development of gas reserves depends on plans to lay a gas export pipeline from the Haltenbanken area.
Only one other field, Heidrun on Block 6507/7, is so far under development off mid-Norway. Operator Norske Conoco AS expects first oil from Heidrun in 1995.
Heidrun reserves are 750 million bbl of oil and 1.6 tcf of gas. A concrete tension leg platform has been chosen for the development, with offshore loading of oil for export.
GRYPHON
Kerr-McGee Oil (U.K.) plc placed Gryphon oil field on production Oct. 14; less than 10 months after receiving development approval from the U.K. government.
Use of the U.K.'s first purpose built, permanently moored, production vessel enabled the 265 million ($400 million) project to be developed 2 years earlier than originally planned.
Gryphon field lies on U.K. North Sea Block 9/18b. It is expected to yield 96 million bbl of 22 gravity oil during 15-20 years. Peak production is to be 50,000 b/d in mid-1994.
Eight subsea production wells, five of which are extended reach, will be tied back to the Gryphon A vessel. Four water injection wells, an injection water source well, and a dual service gas well also will be used.
The first well produced more than 10,000 b/d of oil. A second well, placed on stream Oct. 19, is expected to hike production to 25,000 b/d.
Kerr-McGee said a floating production, storage, and offloading vessel was preferred to a fixed platform because of flexibility, cost effectiveness, and ability to accelerate oil production from the field.
The floater designed to withstand a 100 year wave while moored, can hold 525,000 bbl of oil and process 60,000 b/d. Offloading to a shuttle tanker can take place at a 600,000 b/d rate.
As many as four shuttle tankers will be available for Gryphon under a contract with Statoil. Most of the time only one shuttle tanker will be required.
EVEREST-LOMOND
Amoco (U.K.) Exploration Co. installed Lomond gas field platform topsides on Block 21/21 last January completing the major infrastructure for a El.2 billion ($1.8 billion) development of Everest and Lomond fields via the new Central Area Transmission System (CATS) gas pipeline.
Development work on Everest and Lomond was slowed by storms more than any other North Sea project. Feb 30 knot winds and 35 ft waves caused the Safe Supporter accommodation vessel to be pulled off anchor alongside the Lomond platform during hookup.
The vessel's anchors were damaged, requiring it to be towed to Bergen for repairs. A team of 100 workers continued hookup work while stationed on West Omikron jack up rig, which arrived to complete tie-backs to the platform.
Then a Danish tanker ran aground near the mouth of the River Tees, close by the shore approach of the CATS pipeline, through which Everest and Lomond gas would be exported.
The 97,000 dwt Freja Svea tanker snagged an anchor in 60 mph winds and 30 ft waves. Although the engine was engaged, the crew could not keep the vessel from running around.
Amoco thought the lost anchor may have damaged the CATS pipe. Once the storm died down, a sonar survey of the inshore stretch of CATS showed no damage.
Amoco sent first gas through the CATS pipeline May 9 to Teesside, England, to power an Enron Corp. power generating station.
Lomond gas went on stream in July, delayed by 2 weeks.
PIPER B
From a safety viewpoint, the event of the year in the North Sea was the return to production of Piper field. Safety systems on the new Piper platform are seen as the benchmark of the new U.K. safety regime.
Elf Enterprise Caledonia Ltd. resumed production from Block 15/17 Piper field, almost 5 years after a fire and explosion damaged the original platform beyond repair and killed 167 men (OGJ, Feb. 8, p. 31).
Redevelopment of Piper was tied in with development of nearby Saltire and Chanter fields, which Elf Enterprise took over, along with Piper, upon purchase of Occidental Corp.'s North Sea assets in 1991.
Elf Enterprise estimated Piper held 172 million bbl of oil and 14 bcf of gas from original reserves of 1 billion bbl of oil and 120 bcf of gas.
Wood Mackenzie estimated Piper redevelopment would cost 9850 million ($1.3 billion), compared with original capital costs of 710 million ($1.1 billion) for the first platform, which began production in December 1976.
Redevelopment using Piper Bravo platform has brought advantages over the original structure, said Elf Enterprise Managing Director Michel Romieu: "Now we have new facilities, which are more competitive and can be further automated to make development costs among the best in the market."
Piper operating costs have been reduced from 5 ($7.50)/bbl with the old platform to 3 ($4.50)/bbl at present. This is 0.7 ($1.05)/bbl less than average operating costs on the U.K. shelf.
Romieu expects Piper operating costs to drop to 2.50 ($3.73)/bbl in 1994.
Elf Enterprise did not escape the effects of storms. The company had to halt production briefly from Claymore and Scapa fields off the U.K. when the Cam Sentinel standby vessel lost power and collided with the Tharos accommodation vessel on Mar. 28.
U.K. GAS BASIN
The Caister-Murdoch system in southern North Sea Quadrant 44 went on stream during the year, opening a new area in the U.K.'s southern gas basin.
Fabrication of the two unmanned platforms was completed in March. Tow-out of Total's Caister platform to Block 44/23a and Conoco's Murdoch platform to Block 44/22a took place early in April (OGJ, Mar. 22, p. 31).
Caister and Murdoch gas production began Oct. 2, with flow expected to reach a 300 MMcfd peak in 1994. Gas moves by pipeline to Conoco's Theddlethorpe, U.K., terminal for delivery to independent gas suppliers. The line has a capacity of 750 MMcfd, which will enable it to handle production from future developments in the area.
Conoco has one discovery west of Murdoch field and is in discussions with Shell over development of Ketch and Schooner fields as satellites (OGJ, Mar. 22, p. 31).
In other activity, ARCO British Ltd. placed Orwell gas field on stream Aug. 3 in U.K. Block 50/26a. Orwell is the longest subsea tie-back development in the world, with the Orwell manifold lying 34 km away from the Thames host platform.
DUTCH ACTION
Nederlandse Aardolie Maatschappij By (NAM), Shell-Esso's Dutch joint venture, brought F/3 field on stream on Oct. I but saw no more than pilot production because of pipeline problems.
F/3 gas is sent ashore through the Nogat pipeline, but construction at the Nogat terminal curtailed gas production.
F/3 was developed using Netherlands' first concrete gravity base structure. This supports a drilling/production deck and bridge-linked accommodation deck. The base's honeycomb cells can store 190,000 bbl of oil. A separate offshore loading platform is nearby.
Unocal Nederland By began oil flow from Horizon field on Block P/9 using a 16 slot wellhead/process platform with capacity of 20,000 b/d. The platform is bridge-linked to a jack up rig providing utilities, accommodation, and helipad.
Oil is sent 30 miles by pipeline to Helder platform on Block Q/1 for further processing. From Helder the oil goes through the main trunkline from the block to a terminal near Amsterdam.
Horizon was aptly named, because horizontal drilling developments since discovery of the field in 1982 made it viable. Five wells are being placed on stream to afford plateau production of 18,000 b/d early next year.
Amoco last August completed installation of a central processing platform in Block P/15 gas field. The platform will take gas from four satellite wellhead protector platforms and three subsea completions.
P/15 production is expected to start later this year at about 470 MMcfd, with gas being sent 25 miles to shore via a new 26 in. diameter pipeline to a new gas terminal on the Hook of Holland.
DANISH FIELDS
Dansk Undergrunds Consortium, the joint venture of operator Maersk Olie & Gas AS, Texaco Denmark Inc., and Shell, placed two fields on stream off Denmark.
Regnar field is a small oil reservoir on Block 5505/17, which was brought on stream in late September. Developed with a single subsea well tied back to Dan field, it is the sector's first subsea field.
Another small oil field, Valdemar on Block 5504/7, went on production in October. Valdemar was developed using an unmanned wellhead platform to handle production from three wells for processing in Tyra field.
Development drilling is under way from Gorm, Skjold, and Dan field platforms. DUC has been drilling in the oil zone in Tyra field.
The Danish Energy Agency forecasts that Danish oil production will total 60 million bbl this year and peak at 62 million bbl next year, largely on account of development drilling. By 1997, however, production will fall to 55 million bbl for the year.
OTHER DEVELOPMENTS
Several of the batch of new U.K. oil fields will export production through BP's Forties pipeline. BP said Forties pipeline will be able to handle I million b/d when upgrading and expansion are complete.
BP shut down the Forties oil pipeline system in late March to tie in the Unity riser platform and 470,000 b/d of production at Kinneil terminal, near Edinburgh.
The 23 day shutdown interrupted the flow from eight fields-Arbroath, Balmoral, Brae, Buchan, Forties, Glamis, Miller, and Montrose-causing 9 million bbl of production to be deferred.
First new throughput for Forties came from Amerada Hess's Scott field. BP expects Agip U.K. Ltd. to send first oil from Tiffany field, expected at about 70,000 b/d through Forties in mid-November, followed by Toni oil in December.
In June, Marathon Oil U.K. Ltd. completed installation of the 28,500 metric ton East Brae platform on U.K. Block 16/3a. First oil is expected mid-December, with exports via Forties rising to 115,000 b/d by 1995.
Chevron U.K. Ltd. launched a floating storage unit (FSU) for Block 16/26 Alba field at Astano SA's Ferrol shipyard in Spain. The 125,000 dwt tanker left the yard in late March (OGJ, Apr. 5, p. 30).
Sea trials took place from then until July, after which the vessel was towed to Alba field, arriving in August. ln June, Chevron saw the Alba platform installed. A 2.7 km pipeline bundle was towed out to Alba field in September. It was installed by Rockwater Ltd., Aberdeen, using remotely operated vehicles.
In the Norwegian sector, Elf Aquitaine Norge AS began predrilling four Froy field development wells in Block 25/5. The Treasure Saga semisubmersible rig spudded the first well early in June and will drill until April 1994. The field is due on stream in January 1995.
Elf also completed installation of subsea equipment on three wellheads comprising Lille Frigg field in Norwegian Block 25/2a. The three high temperature/high pressure wells were tied back during the summer. Lille Frigg is due on stream January 1994.
NELSON
Shell installed topsides for Block 22/6a Nelson field in a 6 day operation during early August. The installation required eight lifts, which were carried out in two phases due to interruption by bad weather.
On Aug. 8 the 9,875 metric ton deck was lifted onto the jacket by contractor Heeremac using the DB102 crane vessel in a 4 hour operation. That evening the 2,120 metric ton drilling module was lowered into place.
Next day the 1,950 metric ton living quarters and drilling derrick were installed. Then the weather worsened and the installation team had to choose between more lifts or starting to in weld the deck to the jacket.
"Having completed the four heaviest lifts, poorer weather was forecast, which would have hampered further lifting operations. So it was decided to begin lifting," said Simon Manktelow, installation engineer at Shell.
"Although none of the lifts required instant welding, once welding had begun we were committed to completion before we could recommence lifting."
After welding was finished Aug. 11, the utilities skid, exhaust tower, derrick top section, and boom were installed in 5 hr.
When Nelson begins production in March 1994 ' it will add 135,000 b/d to Forties throughput. Block 22/11 Nelson field is one of the largest U.K. developments of the 1990s. Proved and probable reserves are put at 480 million bbl of oil and 85 bcf of sales c,as.
Enterprise Oil plc will assume operatorship of Nelson after first oil. This marks the arrival of Enterprise as the newest production operator in the North Sea.
DISCOVERIES
With companies in Norway and U.K. alike coming to terms with maturity of the region, BP and Statoil sprang surprises by disclosing their biggest North Sea discoveries in years (OGJ, Mar. 15, p. 31).
BP announced that appraisal of a Block 204/24a discovery west of the Shetland Islands showed reserves of 250-500 million bbl of oil. This was said to be BP's biggest U.K. find in 5 years.
"The discovery has the potential to open a significant new play in the West of Shetlands province, although there is substantial further work to be done to evaluate its size," said John Browne, managing director of BP Exploration.
BP is leading a group looking to develop Clair field, 75 miles northeast of the latest discovery. And while BP unveiled its new discovery, the U.K. Department of Industry revealed that BP and Shell had been awarded five more blocks near the discovery on a 50-50 basis.
BP completed its largest 3D seismic survey to guide future West of Shetlands exploration drilling. About 2,040 sq km, equal to 10 North Sea blocks, was covered.
Onboard seismic and navigation data processing were said to have enabled early interpretation of data. Also, selection of well location was made within weeks of data being acquired.
The 204/20-1 well was spudded by the Ocean Valiant rig Sept. 14 on a drilling program expected to take 35 days. The new test, 35 km northeast of the 1990 202/24-1 discovery well, is on a block owned 50-50 by BP and Shell and operated by BP.
Days later, Statoil announced a 440 million bbl oil discovery in 1,300 ft of water on Block 6608/10 off mid-Norway. Later named Norne, this strike was said to be Statoil's biggest in 8 years.
Then in June, Statoil said a Norne appraisal well completed in February suggested 100,000-200,000 b/d of oil could be produced from relatively few wells. Another appraisal well is likely to be drilled this winter.
Statoil said it intends to work toward submission of a Norne development plan to the Norwegian government in 1994. Monohull and semisubmersible production systems are being studied, with production capacity of 120,000-150,000 b/d.
At least two wells are planned by Statoil on a 14th round block north of Norne. Kyrre Nese, Statoil's senior vice-president, exploration and production, said heavy exploration is planned in the Norne region.
Copyright 1993 Oil & Gas Journal. All Rights Reserved.
