Norway is experiencing one of its quietest offshore weather window programs on record.
Only two fields are due on stream this year. BP Petroleum Development Norway's Gyda field came on stream early, while Amoco Norway's small Hod satellite field is scheduled to start up shortly.
However, there is plenty of construction work in progress onshore that should guarantee more-active weather window programs in future years.
An annual study of undiscovered reserves in Norwegian waters by the state company, Den norkse stats oljeselskap AS (Statoil), is optimistic.
According to the study, 5.9 billion bbl of oil and 31.95 tcf of gas might remain to be discovered in the Norwegian North Sea. A year ago Statoil was projecting 2.39 billion bbl of oil and 16-77 tcf of gas.
The state company is more cautious about the future role of the Haltenbanken area and Barents Sea.
Other operators are making favorable reevaluations of Norwegian North Sea prospects. Europeans evidently share this renewed enthusiasm and are prepared to back it with money.
During the first half of 1990, two U.S. based companies withdrew from the Norwegian scene, selling their interests to European groups.
Neste Oy, the aggressive Finnish state oil, gas, and petrochemical company, agreed to buy ARCO Norge AS, which had 125 million bbl of oil reserves and 640 bcf of gas reserves but no production.
By the mid-1990s Neste should be lifting 21,000 b/d from Brage and Heidrun fields.
Unocal Corp. sold its local subsidiary to Total Marine Norsk for $322 million. The French company acquired 60 million bbl of oil and 195 bcf of gas plus 12,000 b/d of production from Veslefrikk field.
Industrial unrest continues to simmer throughout the North Sea. There is an undercurrent of discontent in the U.K. sector. In Norwegian waters, offshore production was temporarily stopped last month by a strike in support of better wages and conditions.
The strike was rapidly declared illegal, and the workforce was required to return to work immediately. For the first time, union instructions were disobeyed, and unofficial action continued on a number of platforms.
Production is now back to normal. The union claim has gone to arbitration that both sides are obliged to accept. However, the discontent is unabated, and further problems could arise.
WHAT'S IN PROGRESS
BP Norway's Gyda field is producing 44,000 b/d, and Amoco Norway is in the final stages of starting up Hod field, developed as a satellite of Valhall,
While unmanned satellite field developments are common throughout most of the North Sea, they are rare in Norwegian waters.
Amoco Norway is showing benefits of the unmanned unit with Hod. The jacket, topsides and pipeline link to nearby Valhall field were installed this summer. The Soviet-owned Kolskaya jack up has started development drilling.
Output from the $100 million unit will build to 25,000 b/d and 30 MMcfd of gas.
Amoco is also expanding capacity of its Valhall platform.
A Pilot waterflood of the chalk reservoir is in progress, and the company has increased the number of well slots on the platform to 30 from 24 to accommodate new producers and injection wells if a commercial waterflood project is approved.
Phillips Petroleum Co. Norway's Ekofisk field is proving to be Norway's most durable producer.
The production complex in the southern part of Norwegian waters, on stream since 1971, was originally designed for a 25-30 year life. But Lars Takla, Phillips Norway's engineering manager, said the platforms may have to stay in operation for 70 years-or more in the case of the main Ekofisk field.
One factor behind extension of Ekofisk's life is success of the waterflood project. Takla said 40,000 b/d of oil flow is being generated from the Platform 2/4K waterflood project out of total production of 144,000 b/d. This is 30-40% better than anticipated.
Phillips is extending the waterflood to other parts of the field via installation of a water injection module on Platform 2/4W and increasing capacity of Platform 2/4K to 500,000 b/d from 375,000 b/d.
The Maersk Guardian jack up started the six well injector drilling program on 2/4W in March. Phillips expects to start injecting water shortly, building volumes to 120,000 b/d.
On Platform 2/4K, Phillips is increasing the number of injection wells to 18 from 13 and adding process equipment. The increased capacity should be available in May next year.
The project also includes two new production wells and Ekofisk's first gas from the 2/4A platform.
DEVELOPMENTS PLANNED
New development projects are coming forward.
Norsk Hydro has received approval to develop 250 million bbl Brage field west of its successful Oseberg project.
Brage's development was delayed by the previous Labor administration's attempt to create a waiting list for projects in an attempt to prevent rapid offshore expansion from overheating the domestic economy.
The resurrected project is leaner and cheaper than originally designed. Norsk Hydro estimates it will spend $1.3 billion on an integrated drilling and production platform and related pipelines.
Production will start in early 1994 and peak at 80,000 b/d. Brage also has 99 bcf of gas reserves. First gas production will be injected.
Saga Petroleum, Oslo, expects first production from the Norwegian sector's first tension leg platform (TLP) at the end of 1992.
Saga chose a TLP for 770 million bbl Snorre oil field because of the flexibility it allowed for a two stage development.
The project requires 93 wells drilled from several locations. Saga expects to produce most of the reserves from the Statfjord formation from the TLP and a subsea template in 985 ft of water in the southern part of the field.
After 14 years of production, the company could move the platform to a northern site and resume operations. It might also keep the TLP in the southern part of the field and install two subsea templates in the northern area.
The 40,000 metric ton topsides will handle output from a subsea production system. The unit will contain first stage separation, with the main processing and export carried out from nearby Statfjord platforms expected to develop spare capacity during the next 3 years. Production will build to a peak of 170,000 b/d within 2 years of start-up.
Snorre will require substantial water injection. About half its 40 wells will be water injectors. Peak injection will be 380,000 b/d.
A plan by Statoil to exploit the two largest satellites of Statfjord field with subsea production systems has run into problems with the Norwegian government.
Statoil and the Ministry of Petroleum and Energy cannot agree on tax treatment of the two reservoirs. As a result, Statoil has postponed this summer's start of fabrication work on the subsea systems, and the 1993 date for first oil has been abandoned.
Elf Aquitaine Norge's Frigg field in the Norwegian North Sea provides a good example of a large investment in production and transportation infrastructure that will become grossly underused during the early part of the 1990s. The main Frigg field has started a major decline. One processing platform has been shut in, and production by the end of this year and early 1991 will have dropped to a third of last year's 700 MMcfd.
Frigg now handles gas from three satellite fields. Elf is investigating three other outlying fields that could add reserves of 400 bcf of gas and 150 million bbl of oil.
In one of the accumulations, on Block 25/2, Elf is investigating a concrete riser structure that would provide manifolding and control systems for two subsea templates. Production from the field would be transported to the main Frigg field through a 13 1/2 mile, 10 in. line.
In Froy field, where the bulk of the oil reserves are found, Elf is looking at a design from Aker Offshore for a lightweight, minimum-facilities wellhead platform that would normally be unmanned.
The Frigg facilities are progressively being shut down as reserves enter the final stage of depletion. The CDP-1 platform is being decommissioned this year. The next major step will come in 1992-93 when compression on the Esso Norway-operated Odin satellite is commissioned, while compression on the main field is cocooned, the flare removed, and output from the DP-2 platform allowed to decline.
During the same period the Northeast Frigg satellite will be shut in, with the East Frigg satellite closing down the following year. Elf estimates that Frigg and Odin will be finally shut in during 1996-97.
The TPI treatment platform is now acting as an unmanned riser platform after a mothballing operation during 1989.
HALTENBANKEN DEVELOPMENTS
Development of Haltenbanken has been delayed by Norway's lengthy political debate over disposal of gas.
Key to development in the area is Heidrun field, operated by Norske Conoco, which wants to use the world's first concrete-hulled TLP to develop the 750 million bbl of reserves. The path toward development has been cleared by Statoil's decision to participate in an 830,000 metric ton/year methanol plant that will utilize all the field's associated gas.
Oil production from the TLP will be 200,000 b/d, with the methanol plant requiring about 72 MMcfd of gas. Government approval for the project is expected later this year, which would enable production to start in 1995.
In addition to its role as a production facility for Heidrun, the TLP will act as a regional center for other gas developments.
The TLP design includes a 5,000 metric ton regional process module and six spare lines from other fields.
Oil from Heidrun will be exported directly by tanker. The Conoco group currently favors a custom-built storage and off loading vessel permanently moored about 2 miles from the TLP. But there is an alternative plan for subsea concrete storage tanks and a subsea tanker loading system.
The methanol plant, to be operated by Statoil with an 80% interest with Conoco holding the remaining 20%, will be constructed at the landfall for the Heidrun pipeline. Two routes for the line are under consideration.
First hydrocarbons from Haltenbanken will come from Norske Shell's Draugen field in fall 1993.
Shell plans the first deepwater monotower off northern Europe. The unit will stand in 885 ft of water. The reservoir holds an estimated 428 million bbl of oil and 176 bcf of gas reserves. Oil will be exported through a tanker-loading system.
Norsk Hydro is evaluating development prospects for Njord field, which has 290 million bbl of oil and 280 bcf of gas. The field is 15 miles west of Draugen.
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