David Knott
Senior Editor
The Norwegian Sea off mid-Norway is growing in importance as an oil producing region, with one field on stream and another expected soon to start flowing. However, the regions major potential is thought to lie in gas production.
Norways government knows gas field development projects in deep water require massive spending. So Oslo must decide to source a large volume of gas supplies for future sales contracts from mid-Norwegian fields if those resources are to be developed.
The government faces a dilemma.
To meet sales contracts, it would be easier and cheaper to tap gas from Norways North Sea fields either on production or comparatively cheap and easy to develop.
Yet giving the go-ahead for a major gas project off mid-Norway could be better for long term development of Norways hydrocarbon resources.
Norwegian gas producers are expected in November to recommend to Oslo which fields should fulfill major sales contracts.
On the outcome of governments approval rests a decision on whether to develop the Aasgard gas area, viewed as the key to the future of the Norwegian Sea as a gas play.
The Norwegian Seas most promising strikes are in a region of the 64th and 65th parallels designated as Haltenbank. The region lies off a portion of Norways coastline stretching from Trondheim north to Bronnoysund.
Industry also has drilled gas discoveriesSnow White, Albatross, and Askeladden, for exampleon the Tromsoflaket region of the 71st parallel in the Norwegian Sea off Hammerfest. However, those strikes off Norways Far North are so far from markets there have been no moves toward early development.
Discoveries
Industy's Norwegian Sea Hotspot (83957 bytes)Norways Ministry of Industry & Energy estimates total oil and gas reserves in the Norwegian Sea amount to 2.12 billion metric tons of oil equivalent.
At last months Offshore Europe conference in Aberdeen, ministry officials estimated that about 4 million metric tons of oil have been produced so far.
Reserves in fields slated for development were said to amount to 220 million metric tons of oil equivalent, while discoveries were pegged at 550 million metric tons of oil equivalent. Undiscovered resources were estimated at 1.35 billion metric tons of oil equivalent.
A Norwegian Petroleum Directorate (NPD) report published last February showed industry had drilled 79 wildcats and 28 appraisal wells in the Norwegian Sea.
NPD said all major reservoirs found so far in the Norwegian Sea are in early to middle Jurassic pays except Draugen, which is late Jurassic. Also, all the major finds off mid-Norway are in the Haltenbank area except for Norne, which lies to the north. Only two minor discoveries, 6506/11-2 in Smoerbukk field and 6507/2-2 southwest of Norne, are in Cretaceous sandstones.
The result of this program is one field on production, one field with development approval, five discoveries with development plans, eight discoveries without development plans, two discoveries in relinquished areas, and three new or small discoveries.
NPDs report pegged estimated reserves discovered in the Norwegian Sea at 420 million cu m of oil and condensate and 350 million cu m oil equivalent of gas. NPD said 4 million cu m of oil and no sales gas has been produced so far.
Gunnar Myrvang, state secretary at the Ministry of Industry & Energy, told the Aberdeen conference Norways oil production is expected to reach 3 million b/d in 1996 and to remain at about that level for some years.
Of Norwegian Sea development programs in progress, which are expected to contribute to this plateau, Heidrun field is due on stream shortly and Norne field is to start production in 1997. Njord field, approved by the ministry this year for development, also is due on stream in 1997.
All development programs in progress will rely on shuttle tankers for oil shipments to shore.
Gas plans
Norways gas production also is expected to rise, from the current 30 billion cu m/year to 70 billion cu m/ year after 2000. Norwegian Sea fields may be among those chosen to supply a number of gas sales contracts to European customers.
We have not identified supply sources for one third of these contracts, Myrvang said. In a short time we face an important decision on which fields will supply the contracts.
It could be Oseberg, Troll and South Gullfaks in the North Sea, and it could be Aasgard in the Norwegian Sea. We are expecting a recommendation from the Gas Supply Committee in November, and this will be put before Storting (parliament) for a decision next spring.
State owned Den norske stats oljeselskap AS reckons fields in the Haltenbank area of the Norwegian Sea, including Aasgard, could provide 9-12 billion cu m/year of the extra deliveries under contract to European buyers.
Although it would be cheaper for Norway to meet those contracts with gas from North Sea fields, using much existing infrastructure, there is an argument for development of Norwegian Sea fields under a long term strategy.
Peter Mellbye, executive vice-president of Statoil, outlined the arguments in a Statoil publication.
Aasgard development carries a price tag of 30-35 billion kroner ($4.6-5.4 billion), although main interest holders Statoil and Saga Petroleum AS are looking to cut the bill by 20% in collaboration with Norwegian industry.
Norsk Hydro AS gas reserves in Oseberg fields and Statoils South Gullfaks field have a development edge because they are near gas export pipelines.
Haltenbank should be developed first if were concerned with future revenues, Mellbye said. If investment is the sole issue, however, North Sea fields ought to take priority.
A beginning
Several other oil and gas discoveries followed, mainly on Haltenbank. Draugen oil field was the first of these to see development.
In October 1993, Norske Shell AS became the first company to produce oil commercially in the Norwegian Sea. Shells production came from Draugen field, which holds estimated reserves of 580 million bbl of oil and 100 bcf of gas in 800-900 ft of water.
Shell developed Block 6407/9 Draugen field using a monotower platform with oil storage in the base.
Part of Draugens gas flow powers the platform. The rest is reinjected. Shell plans to sell the gas later, depending on installation of a gas export pipeline from the Haltenbank area.
Haltenbanks second field on production is to be Heidrun on Block 6507/7, currently under development by Norske Conoco AS and due on stream soon. Heidrun reserves are estimated at 750 million bbl of oil and 1.6 tcf of gas.
In mid-September, Statoil said Conoco blamed difficulties in completing a well for a delay in start-up from the planned date of Sept. 21. Statoil, which is due to take over operatorship when production starts, said the problem was expected to be solved in a few days.
Heidrun was developed with a concrete tension leg platform. It too relies on offshore loading for export of oil, but it uses a series of shuttle tankers for continual removal of produced volumes.
The 245 km, 16 in. Haltenpipe gas pipeline moves some of Heidruns gas to Tjeldbergodden on the coast of Norway.
Statoil and Conoco are building a plant designed to produce as much as 800,000 metric tons/year of methanol. The plant, to go on stream in late 1996, will receive about 700 million cu m/year of Heidrun gas for feedstock.
Norne field
Statoil found Norne field on Block 6608/10 in March 1993. With estimated reserves of 440 million bbl of oil, Norne was said to be the companys largest discovery in 8 years.
Later that year, Statoil decided Norne would be developed on a fast track program to yield first oil in 1998, compared with earliest production in 2001 using traditional fabrication management (OGJ, Oct. 25, 1993, p. 99).
In September 1994, Statoil officially gave the green light for Norne development using a production ship connected to subsea wells via flexible risers (OGJ, Oct. 3, 1994, p. 30).
The Norne vessel is to be the worlds largest production ship, at 260 m long and 41 m wide, able to store 720,000 bbl of oil on board and offload into shuttle tankers at up to 50,000 bbl/hr.
Statoil reported in mid-September a further 400 million kroner ($250 million) had been cut from Nornes estimated development cost. That is expected to make the bill less than 7.5 billion kroner ($4.7 billion), down from an original cost estimate of 11.5 billion kroner ($7.2 billion).
Statoil also aims to begin oil production from Norne Apr. 1 1997, 8 months ahead of the original schedule. Production is to reach 170,000 b/d of oil in 380 m of water.
Njord field
Norsk Hydro will use a production semisubmersible rig to develop Njord, with oil flow from 15 wells and oil storage in a tanker moored 2.5 km away.
Block 6407/7 Njord field hold estimated reserves of 220 million bbl of oil and 5 billion cu m of gas. Water depth is 330 m.
A Norsk Hydro official said development cost will be 5.9 billion kroner ($890 million). Hydro has slated first production for Oct. 1, 1997, but this depends on the development plan receiving government approval quickly.
Hydro last March let contract to Aker AS, Oslo, to build the production unit on its P45 design. The rig will be able to produce 65,000 b/d of oil and 10 million cu m/day of gas (OGJ, Mar. 27, p. 31).
Hydro last May let a 330 million kroner ($50 million) contract to Kvaerner AS, Oslo, for subsea christmas trees, control, and hook-up systems for the wells. Delivery will start in May 1996.
Then early in June Hydro let contracts for subsea equipment and a storage tanker. It also signed a letter of intent for construction by Finlands Kvaerner-Masa Yards Oy of a tanker to store as much as 690,000 bbl of crude oil. The contract is worth 470 million kroner ($70 million).
In December, Hydro expects to announce contracts for flexible risers and the marine installation of Njord.
Kvaerner said offloading into shuttle tankers will take place through a flexible hose in the storage tankers stern. Offloading will be at rates of as much as 8,000 cu m/hr.
The storage unit will be unmanned during normal operation. A crew will land by helicopter to offload the cargo every 10 days.
Hydro said three production wells will be drilled in the field next year, ahead of installation of the floater. Twelve wells will be drilled from the platform.
Full development of Njord will require 10 producers, four gas injectors, and a water injection well. Some of the wells will have U-shaped profiles, while most will have horizontal sections to maximize production from Njords complex reservoir.
Gas the key
Development of the Aasgard group, made up of Midgard, Smoerbukk, and South Smoerbukk, is the key to tapping Norwegian Sea gas reserves.
Draugen, Heidrun, and Norne are oil fields, so their development decision has been comparatively straightforward.
Draugen and Heidrun have significant gas reserves, but the other discoveries in the area to date, the Aasgard fields and Tyrihans, have large reserves of gas. To develop these fields requires installation of a major gas export pipeline.
So far, Statoil and development partner Saga have decided that a production ship will be the best means to produce Aasgard oil. But a decision on whether to use a production semisubmersible or a fixed platform for Aasgards gas production has yet to be made.
The oil production ship is expected to have capacity to produce about 175,000 b/d. Gas production alternatives under consideration are a concrete monotower and a production semisubmersible.
A Statoil official explained that the decision on whether to develop Aasgard depends on the ministrys reaction to the November recommendation on gas allocations.
Production only of Aasgards oil reserves is not thought viable. Although oil could be produced from Aasgard for some time without gas sales, there would come a time when gas would have to be lifted to keep the oil flowing.
Statoils hope is to develop Aasgard to begin oil production in 1998 and gas production in 2000. However, if the governments gas supply decision comes down in favor of North Sea fields, Aasgard development will be shelved.
Aasgard debate
Norwegian oil industry opinion appears to be that the best compromise the gas supply committee can reach is to recommend development of Aasgard field and production of gas from the North Seas Oseberg field to meet new supplies commitments.
The points in favor of this solution are:
- Aasgard is a big project with a lot of oil: Norway needs the oil revenues, and Norways contractors are pressing for more fabrication work because the massive Troll and Heidrun platforms have left their yards.
- Politicians in mid-Norway, strongly in favor or bringing more oil industry jobs to the area, are lobbying for Aasgard.
- The petroleum industry needs incentives for further exploration, given the worldwide rivalry among governments to attract oil companies. So Norways 15th licensing round, containing mainly Norwegian Sea acreage, will have little point unless there is a chance to export any gas found and developed there.
- Oil production from giant Oseberg field will dwindle during 2000-2005 if gas is not produced from the field during that period.
Statoil reckons spending on the Norwegian continental shelf will decline sharply in the years to 2000, falling from 50-60 billion kroner ($7.7-9.2 billion) in 1994 to about 10 billion kroner/year ($1.5 billion/year) about the end of the century.
Development of the unitized Aasgard field off mid-Norway could be very important for Norwegian suppliers and provide new jobs, said a Stat- oil house publication last August.
Field installations, embracing a platform and a production ship, represent an investment of roughly 30 billion kroner ($4.6 billion) during 3-4 years. In addition comes spending on transport pipelines and possible land-based facilities, totaling some 5 billion kroner ($770 million).
Points against giving the green light to Aasgard are the comparatively higher cost of fulfilling gas supply contracts and Norways vociferous, influential environmental lobby, which wants to minimize the spread of petroleum activity.
Aasgard plan
Nonpolitical arguments for development of Aasgard got a boost this year when Statoil doubled its estimates of oil reserves in Smoerbukk field. Results of an appraisal well led Stat- oil to hike its estimate of Smoerbukk reserves to 553 million bbl of oil from 289 million bbl.
This increased total reserves estimated for Aasgard development to 792 million bbl of oil and almost 7 tcf of gas (OGJ, Apr. 10, p. 41).
Statoil has a rig drilling an appraisal well in one of the Aasgard fields. The company is laying plans for its drilling program for next year and waiting on the November gas committee recommendation.
If the Aasgard project is given the go-ahead, there will be more or less continuous drilling in the run-up to development, said a Statoil official. We hope to drill another well defined as an exploration well in January, but we would be looking to convert it as a producer.
The official said 60 subsea development wells will be required for Aasgard. Two rigs will be required to drill at the same time during the main development phase.
Statoil plans to submit a plan for development and operation of Aasgard to the Ministry of Industry & Energy by Dec. 15. A final decision on whether to develop Aasgard will be made next spring.
Among the first follow-up decisions from Aasgard field development is likely to be a move to lay an export pipeline for Haltenbank gas fields, moving collected gas south to join the North Sea gas export grid (OGJ, Aug. 28, p. 67).
In common with the rest of Norways oil companies, Statoil is eagerly waiting for the announcement of awards later this year under governments 15th offshore licensing round, which mainly covers acreage in the Norwegian Sea.
If Statoil gets the licenses it has applied for, said the company official, it will be looking to begin a major drilling program in the Voering basin during 1996.
Other discoveries
A number of discoveries have been made in the Norwegian Sea other than the fields slated for development. These are mainly pigeonholed as noncommercial for now, but some could grow more attractive in time.
A Statoil official said development costs off Norway have been falling during the past few years because of new development technologies. For example, with small oil finds such as North Sea Yme, currently under development, use of light movable installations is the key to viability.
However, many of Norwegian Sea finds have large gas reserves. Statoils Mellbye emphasized that development costs would need to be kept to a minimum to justify use of Norwegian Sea fields to supply European gas customers.
Mellbye said, New investment can be reduced or postponed if we use capacity in our terminals at Kollsnes outside Bergen or Karstoe north of Stavanger to process Haltenbank gas.
Conoco has found a number of small reservoirs in the Heidrun area and has spare production capacity on the platform to handle satellite developments (OGJ, May 22, p. 29).
Statoil operates the Tyrihans discovery on Block 6407/1, the companys main development prospect in the area after Aasgard. Tyrihans reserves are estimated at 56 million bbl of oil and 920 bcf of gas.
NPD said the field consists of two structures, North Tyrihans and South Tyrihans, proved in 1983 and 1982, respectively. Water depth is about 325 m.
NPD said production likely would start in South Tyrihans, with North Tyrihans to be phased in later by use of subsea wells. Further mapping of the fields is required for a decision on development options.
The Statoil official said Tyrihans development will become of interest only if there is a gas outlet.
Statoil reported recently that the most noteworthy discovery of the year off Norway has been Sagas Block 6406/2 strike south of Aasgard.
Saga spudded the 6406/2-1 wildcat Oct. 31, 1994, but had to suspend operations because environmental restrictions in the license barred drilling during April-June.
Saga reentered the well Aug. 20 using the Ross Isle semisubmersible rig. On Sept. 21, Saga announced the well had reached a vertical depth of 5,768 m, making it the deepest well by 226 m drilled in the Norwegian Sea. Saga plans to log and test the well during a 2-3 month period.
A Saga official said, while no testing has occurred, the appraisal program is going smoothly. The company hopes reserves may be shown to be about 200 billion cu m of gas and 70 million cu m of condensate.
Testing is expected to be finished by the end of November, after which Saga intends to plan for drilling of another well on the prospect in 1996.
Statoil has two rigs, the Ross Rig and Deepsea Bergen semisubmersibles, drilling in the Norwegian Sea. They are working Smoerbukk and nearby Block 6406/12, respectively.
Statoil plans to drill on Block 6204/10 in the More basin this year. The company made a small discovery on the block last year.
Future exploration
Early in 1994, Norways Ministry of Industry & Energy presented a white paper to Storting that proposed opening new areas of the Norwegian Sea for exploration.
These were the Voring and More basins, which lie far from shore, the Nordland VI area, and the outer regions of Nordland IV and V, which lie near shore (OGJ, Mar. 28, 1994, p. 33).
Development of these areas is expected no earlier than 2005. NPD said some oil companies expect these areas to hold the same volume of hydrocarbons as has been produced off Norway to date.
The ministry is working to open the Norwegian Sea further to exploration under a 15th exploration licensing round that will consist mainly of blocks off mid-Norway.
Myrvang said 40 of 56 blocks on offer in the round are in the Norwegian Sea. The rest are in the North Sea.
We have had applications from all the important companies operating in Norway, Myrvang said. All blocks on offer have been applied for.
The 15th round is key to keeping up Norways production after 2000. What will be found in 15th round licenses areas will not be on stream until well after the turn of the century.
The ministry intends to announce license awards by yearend. There are different priorities in different parts of the Norwegian Sea.
The regions main challenges are high seas and lack of infrastructure, Myrvang said. In the Haltenbank area we need to map new resources. In areas nearer the coast the challenge is to balance fishing and environmental needs with petroleum industry interests.
John Hollis, general manager of BP Petroleum Development Norway AS, said operators hope to find billion barrel fields on blocks offered in the 15th round.
He said, It is not inconceivable that we could see fast track oil developments within 4-5 years arising out of the 15th round. Copyright 1995 Oil & Gas Journal. All Rights Reserved.
