Norway's buoyant offshore industry was stunned when the concrete substructure for Sleipner natural gas field's main production platform sank in the Gandsfjord off Stavanger late last month.
The accident, a blow to Norway's gas sales program in Europe, came with offshore activity in the Norwegian North Sea moving into a new boom period.
Currently, 10 oil and gas fields are under development, and several projects are on the drawing board.
Aker Oil & Gas, a leading offshore firm, says the country's construction industry will be working at capacity for the next 4 years.
Norwegian oil production has been hovering just below 2 million b/d since the beginning of this year, making Norway the North Sea's largest producer, a position formerly held by the U.K.
Gas production averages about 3 bcfd. With European gas demand sharply increasing, Norway is under pressure to increase output from new fields in the mid to late 1990s. The Sleipner setback forces state owned Den norske stats oijeselskap AS (Statoil) to cast around for supplies.
Sleipner was to have begun deliveries to a consortium of continental gas companies in October 1993. Statoil believes it can fill the gap from existing fields in Norwegian waters.
LOST SUPPLIES
In its first year, Sleipner would have supplied an average of 387 MMcfd to the European gas grid.
When the full Troll/Sleipner contract is running at maximum throughput in the early part of the next century, European customers will be receiving about 1.27 tcf/year.
In addition to gas, Sleipner can produce about 130,000 b/d of condensate through a pipeline to the Karsto gas terminal.
Industry sources say that if the 380 ft, four-leg concrete substructure is a total loss, Statoil could need 2 years to replace it.
The concrete unit sank in 650 ft of water in the fjord off the Norwegian Contractors Stavanger construction yard during the operation to ballast the unit in preparation for mating this month with the deck and topsides in a nearby fjord.
Even at that stage there were some doubts about meeting the 1993 start-up. Statoil was forced to abandon the drilling module after a financially troubled French fabrication yard failed to complete the work.
The accident removes a crucial piece from the complex series of projects needed to fulfill contractual requirements of the Troll-Sleipner supply contract.
The platform is the starting point for the first phase of the Zeepipe project to deliver Sleipner and Troll gas to Europe.
Work began this year on the first phase of the system: a 500 mile, 40 in. line from Sleipner to Zeebrugge in Belgium; a 25 mile, 30 in. link to the Statpipe riser platform on Block 16/11; and the 140 mile 20 in. condensate line to Karsto.
To make other gas available, Statoil will reverse flow on the link from the 16/11 riser platform and join this section with the main Zeepipe line, probably through a new steel riser platform that could also serve the Europipe project.
These modifications to the system would allow gas to flow from Statpipe into Zeepipe and ensure that Statoil met its obligations to begin deliveries through Zeebrugge in 1993.
The plan will require additional compression at Statpipe's Karsto terminal.
PROJECTS PROCEED
Statoil indicated that other projects linked to Sleipner would proceed.
The company also was planning to supplement gas production from the main Sleipner field with supplies from the Loke satellite, formerly Sleipner Theta.
The Norwegian government gave Statoil permission to develop the 105 bcf Paleocene reservoir through a 420 million kroner ($61 million) subsea system made up of a four slot subsea manifold tied back to the main Sleipner east production facilities about 5.5 miles to the southwest. Initially, only two slots will be required.
The structure also has an estimated 13 million bbl of liquids.
There is a deeper Jurassic structure with an estimated 100 bcf of reserves, but gas from this reservoir is not included in the gas contract with the Troll partners.
Statoil also was planning to develop the 4.7 tcf of reserves in Sleipner West field, to start up in 1996.
For the first 5 years, the new platform would produce 480 MMcfd to replace output from Sleipner East, which would be reinjected.
NEW PIPELINE
Demand in Europe for new Norwegian gas had put pressure on existing delivery systems even with the Zeepipe network, which is under construction. Zeepipe partners, the equity owners of Troll and Sleipner gas, plan a third pipeline to Northwest Europe.
The 403 mile Europipe will be laid from the Statpipe riser platform in Block 16/11 to a landfall near Emden in northern Germany, close to the Norpipe terminal, where new reception facilities will be built. The new line is to be operational in 1995.
In the second phase of Zeepipe, a 184 mile, 40 in. extension will be built to the Troll gas terminal at Oygarden, north of Bergen. The line is to start up in 1996.
Troll has moved smoothly into the engineering phase. Major contracts have been placed for most major components, including the concrete drilling and first stage separation platform to be installed in 993 ft of water.
Norske Shell, operator for the development phase, said the project is on schedule to produce gas in 1996.
Norske Shell is also operator for 425 million bbl Draugen field in the Haltenbanken area off mid-Norway, which is to produce first oil in 1993. Plateau production will be 90,000 b/d.
The field, in Block 6407/9 about 90 miles north of Kristiansand, will produce through a concrete gravity based production platform under construction by Norwegian Contractors in Stavanger. A tanker loading system will handle the oil.
POWER PLAY
Sinking of the Sleipner platform's substructure overshadowed the power play pitting Statoil and Norsk Hydro against the third Norwegian oil company, Saga Petroleum, over which location should provide new gas reserves for the mid to late 1990s.
Statoil and Norsk Hydro want supplies to come from new developments in the North Sea, taking advantage of existing production and transportation facilities. Saga claims the time is right to begin gas development in the Haltenbanken area based on the 3.8 tcf of reserves in its Midgard field.
Saga's 11 billion kroner ($1.4 billion) development calls for a 410 mile, 32 in. line to link into the North Sea infrastructure.
The field could be on stream by 1995-96. Its development offers considerable political benefits to a government under pressure to bring more oil and gas related development to the mid-Norway region.
HEIDRUN APPROVAL
Conoco Norway Inc. has received the go-ahead to develop Heidrun field's 750 million bbl of oil reserves using the world's first concrete tension leg platform (TLP) at a cost of 25.7 billion kroner ($3.73 billion).
But the Storting (parliament) still has not decided on how the 1.6 tcf of gas should be handled.
Conoco and Statoil, the largest shareholders in Heidrun, have plans for a large methanol plant using Heidrun gas as feedstock.
But with the Labor administration in Oslo attempting to take a world lead in restricting CO2 emissions, the offshore license holders are obliged to study the alternative of reinjecting the gas into a nearby water filled structure.
This idea had been rejected on conservation grounds as large volumes of the gas would be lost.
The government is expected to reach a decision on Heidrun gas utilization by the end of the year.
Meanwhile, Conoco, operator for the development stage, is pushing ahead with the concrete TLP. Statoil will be operator.
Production is scheduled to peak at about 200,000 b/d in 1996. Oil will be pumped into a storage and offloading tanker or a concrete storage tank on the seabed.
The concrete TLP will be installed in 1,150 ft of water over a subsea template with 9 predrilled wells. A further 40 wells will be required, including six subsea water injectors.
Initially, associated gas output of about 75 MMcfd will be piped ashore as feedstock for the methanol plant, if this option is approved. However, 1.3 tcf of the 1.6 tcf of reserves are in a gas cap, much larger volumes from which are not expected before 2006.
STATFJORD PERFORMANCE
A driving force in Norwegian production is the better than planned performance of Statfjord field.
In the first 5 months of the year production averaged 763,000 b/d-100,000 b/d more than anticipated in the original budget.
Work on a number of production wells, modifications of some process areas, and an increase in facilities for treating produced water account for the performance.
Statoil soon will shut down the Statfjord A platform for a month-long maintenance period during which it will bring the unit to safety standards of later generation platforms. It will modify the process area to handle oil and gas from Snorre field and tie in two risers installed earlier.
Statoil is developing two large satellites of the main field to absorb spare processing capacity that will emerge in the mid-1990s. The Statfjord North and East subsea satellites will start up in 1994, producing about 130,000 b/d from 12 wells. Total costs for the two fields will be 7 billion kroner ($1 billion).
Several other satellite fields are being considered for development in the Statfjord/Gullfaks area.
The Huldra satellite could be developed as a subsea project tied back to facilities on the Statfjord B platform.
Statoil also is looking at a floating production system for Gullfaks South oil and gas field, with output processed in Gullfaks.
Statoil has plans for new developments north of the 62nd parallel.
In the Haltenbanken area, a selection of floating production concepts has been put forward by various partners for Smorbukk South field in Block 6506/12, southwest of Heidrun field.
Statoil favors a concrete floater to produce the 160 million bbl of oil and 1 tcf of gas.
Conoco is promoting the TLP concept for the 985 ft water depths. Mobil Norway and Norsk Hydro have proposed a production ship.
A subsea development tied back to Heidrun would also be feasible but has attracted little support.
By the end of the year a single concept will have been selected for presentation to authorities for development approval.
Production of about 60,000 b/d will be handled directly by tanker.
Gas can be reinjected until transportation is available.
On the Tromsoflaket, off the northern tip of Norway, Statoil is preparing a development plan for 3.9 tcf Snohvit gas field at the western end of the Barents Sea. Various options, including floating production, are under consideration.
If technology is available, the partners may opt for a subsea development with the well stream piped 93 miles to shore for processing and liquefaction.
Development work cannot advance until further progress is made by the Norwegian gas sales committee for an LNG contract with ENEL, the Italian state electricity company.
HYDRO BUSY
Norsk Hydro is in the midst of its busiest period of offshore development ever.
It is in final stages of bringing the Oseberg C platform and Oseberg Gamma North oil field on stream and is also working toward first oil production from Brage field, east of Oseberg, in 1993.
Gamma North has a single horizontal subsea well tied back to Oseberg C. The new drilling and production platform is in final stages of hookup and should be on production in October.
Output will build to a peak of 100,000 b/d early next year, taking total output from Oseberg field to about 430,000 b/d. Longer term, Oseberg may become a production center. At least five fields south and west of the main structure could use existing equipment in the next decade.
Other future developments by Norsk Hydro include the oil province in the western part of Troll field and the Njord oil project in the Haltenbanken area.
Approval for both projects could be sought at the end of this year.
Also on the agenda is Visund field in Block 34/8, southeast of Snorre field. Norsk Hydro originally planned to seek government approval at the end of 1992, but a recent appraisal has encouraged the company to think about earlier development. It could go to the government with Troll and Njord if partners approve.
The fourth field scheduled for short term development by Norsk Hydro is Oseberg Beta, now known as Oseberg East. Approval for a satellite development could be sought next year.
TROLL PLANS
The most complex of these developments is extraction of oil from the Troll area. Crude oil has been discovered in a 72-85 ft thick zone known as the oil province and in a separate, much thinner layer only 3949 ft thick under the western part of the gas reservoir.
Oil in place is estimated at 3.7 billion bbl, of which 2.7 billion bbl is in the thin layers under the gas. Recoverable reserves, mainly in the thicker zone, total 440-500 million bbl.
An extended test program last year on the thick oil zone showed that production would be commercial with horizontal wells. A similar program on the thinner zone showed that production was feasible and would be commercial with a $20/bbl oil price.
Norsk Hydro is planning a floating concrete production platform to handle output of about 120,000 b/d from 15 horizontal wells in the thick zone.
The platform will also have capacity for a further 15 horizontal wells for the thin zone.
Providing the government approves the project in first half 1992, Norsk Hydro plans to have the floater on production during 1995, a year ahead of output from the major gas project on the eastern lobe of the field.
The initial application to the government will cover only the thick oil zone. Norsk Hydro says it is still working on an evaluation of the thin zone and favors positioning horizontal wells toward the top of the reservoir to avoid water coning.
The positioning would suffer from gas cusping, and the project would require gas reinjection.
Njord, about 15 miles west of Norkse Shell's Draugen project, will be Norsk Hydro's first development outside the North Sea.
Two development concepts are under consideration.
Norsk Hydro is looking at a ship-based production system or a concrete floater to service 24 wells and about 80,000 b/d of production, 44,000 b/d of water for injection, and reinjection of 210 MMcfd of associated gas. Production start-up is scheduled for 1994/95.
A floating production system is likely for Visund field on Block 34/8. Two structures, thought to hold 150 million bbl of condensate and 2.6 tcf of gas, would be developed via a single production system starting up in 1996-97.
Plans for the Oseberg East satellite, which has reserves of 88-140 million bbl, include a single wellhead jacket tied back to the Oseberg central production system in 1996.
ELF'S PROJECTS
Elf Aquitaine Norge AS is advancing several development projects between Frigg and Heimdal fields in Quadrant 25.
The company awaits a government decision on its three well subsea development plan for the 264 bcf, 22 million bbl Lille Frigg gas-condensate field in Block 25/2a, which could be on stream in 1993 using Frigg production facilities.
Elf has submitted to partners plans to develop Froy field in Block 25/5 using an unmanned, remotely controlled steel or concrete wellhead and separation platform.
Output will be handled through Frigg or Heimdal.
Recently the company found two potential gas-condensate satellites in the same block.
EKOFISK SHUTDOWN
Phillips Petroleum Co. Norway conducted a 2 week shutdown of its central Ekofisk complex in August, halting liquids production through the Norpipe line to Teesside, England, and gas through the Statpipe/Norpipe system.
During the shutdown, Phillips repaired the two gas pipelines and increased capacity of the oil line.
Earlier in the year, Phillips increased capacity of Ekofisk water injection with completion of wells in the 2/4K platform and the 2/4W unit. The Maersk Guardian jack up, after drilling eight injectors on the 2/4W unit, moved to drill a well probing the lightly explored Jurassic under Ekofisk's producing chalk.
Phillips has received official go-ahead to develop Embla field in Block 2/7, about 3 miles south of the Eldfisk platform, formerly known as Southeast Eldfisk.
In the first phase, Phillips will drill 12 wells from an unmanned platform in the northern part of the field, which will produce 50,000-60,000 b/d through Eldfisk processing facilities.
Gas flow of about 80 MMcfd is expected.
The second phase of development, still in the planning stage, could require a second platform in the southern part of the field, where further appraisal may be needed.
Reserves may total 200 million bbl of oil and 300 bcf of gas.
Work has started on conversion of the West Ekofisk platform to a remotely controlled unit. Two or three wells will be sidetracked to increase production.
BALDER TEST
Esso Norge has started test output from Balder field in Block 25/11 using the floating production ship Petrojarl. Output is 7,200-7,400 b/d.
But Balder has a checkered history.
Esso received the exclusive license in 1969 and after an initial drilling program made a first move toward development in 1980. But it withdrew its applications the following year after a disappointing appraisal.
The extended test will last until October.
Esso will review the production experience together with new seismic information. It then will await results of drilling by Norsk Hydro in a recently awarded block containing a number of prospects that could be developed as part of an integrated Balder project.
Esso is unlikely to make a formal application for development approval before 1994, with first production in 1997-98.
Copyright 1991 Oil & Gas Journal. All Rights Reserved.
