Roger Vielvoye
International Editor
The Norwegian Sea, lying between the Norwegian North Sea and the western flank of the Barents Sea, is set to become Norway's second oil and gas producing province.
Oil is scheduled to start to flow near the end of next year when AS Norkse Shell places on production 428 million bbl Draugen field in Block 6407/9, about 60 miles off the coast of mid-Norway in the frontier sea area known as Haltenbanken.
Two years later, in 1995, Norske Conoco AS will add to the 95,000 b/d from Draugen when it commissions the world's first concrete hull tension leg platform (TLP) in Heidrun field.
The TLP is expected to produce 200,000 b/d of oil and move associated gas by pipeline to the Norwegian mainland to feed a worldscale methanol plant planned for construction at Tjeldbergodden.
The Norwegian government also has been asked to approve a gas pipeline link between Haltenbanken and the gas export infrastructure in the North Sea.
The pipeline, if approved, would allow development of substantial gas reserves off mid-Norway. Latest Norwegian estimates place Haltenbanken gas reserves at 11.15 tcf and oil at 2.39 billion bbl.
Most reserves in the Haltenbanken area are in deep water-more than 1,000 ft. The resulting high costs have presented economic problems to operators and have caused disappointment among political interests in mid-Norway who want to see faster offshore Exploration and development.
TAX PROBLEMS
Norwegian hopes were raised by a plan from Norsk Hydro to develop the small Njord oil field in Blocks 6407/7 and 6407/10 using a production ship. But this scheme fell victim to appraisal of the field's economics, which were not helped by a new tax regime approved be, Storting (parliament) last month.
The tax proposals have been changed in response to lobbying from the petroleum industry. Some measures such as abolition of the government's carried interest in exploration licenses have been welcomed.
The overall effect, however, is to increase Oslo's tax bite. Higher taxes, effective with the start of this year, combined with the prospect of continuing low oil prices do nothing to enhance the prospects for new high cost projects in the area.
Throughout the world oil companies have been forced to be extremely selective in choosing investment targets for the next few years. Potential oil and gas projects off Norway are not immune from this trend, and the population in Central Norway may find that new developments may move forward at a slower pace than they had originally hoped for.
On the strength of Draugen and Heidrun development projects, mid-Norway is developing its oil industry infrastructure. A large supply base has been established at Kristiansund, which aims to become the Stavanger of mid-Norway but on a much smaller scale. Helicopter services are based at Kvernberget, the airport serving Kristiansund.
Shell has established offices in Kristiansund from which it will operate Draugen. State owned Den norske stats oljeselskap AS also has offices in the town.
Conoco will use the Vestbase in Kristiansund and the Kvernberget airport to supply Heidrun but has chosen to build its regional offices at Stjordal at Trondheim airport,
EXPLORATION INTEREST
In addition to Draugen and Heidrun, Haltenbanken's main oil and gas reserves lie in Midgard field with 4.025 tcf of gas and 133 million bbl of condensate, Tyrihans 1.024 tcf and 76 million bbl of condensate, Njord 252 million bbl of oil and 282 bcf, Smorbukk 2.12-2.47 tcf and 126-157 million bbl of oil, and South Smorbukk 157 million bbl of oil and 706 bcf.
Those fields were discovered in the early and mid-1980s. More recently the much smaller Trestakk and Mikkel fields were added to the reserve bank.
Exploration interest has tended to wane during the past few fears. Most of the licensed prospects in the Haltenbanken area have been drilled, and results from surrounding areas have been disappointing.
Industry sources expect interest off mid-Norway in the licensing round that is just getting under way to rebound, mainly as a result of an oil discovery by Statoil in the Nordland II area north of Haltenbanken.
Statoil's Block 6608/10-2 discovery, about 53 miles north of Heidrun field, could hold 200-250 million bbl of oil and about 400 bcf of gas. Water depth in the area is about 1,200 ft.
Industry sources say the field could be developed in the foreseeable future if a market can be found for the gas.
The most likely option is a stand alone field development, almost certainly with a tanker loading system for oil and a pipeline link to Heidrun to transport gas.
The first sign of hydrocarbons in this part of the Norwegian Sea cropped up in 1990 when Statoil tested gas/condensate in the first well in the center of 6608/10.
The latest well on the southern boundary of the block created considerably more interest because of its substantial oil flow.
Statoil drilled the well, 6608/10-2, to 11,988 ft and gauged a maximum rate of 7,328 b/d of 34 gravity oil and 4 MMcfd of gas through a 2 in. choke from Middle and Lower Jurassic sands. The well also flowed 25 MMcfd of gas and 315 b/d of 48 gravity condensate through a 3/4 in. choke (OGJ, Jan. 20, p. 26).
The structure is thought to extend into three adjoining blocks.
Statoil plans to follow up this well with a 3-D seismic survey covering 6608/10 where the company is in partnership with Norsk Hydro, Saga Petroleum AS, Norsk Agip AS, and Enterprise Oil Norwegian AS.
The survey will extend into adjoining Block 6607/12 to the east, operated by Elf Aquitaine Norge for Statoil and Norske Fina AS, and Statoil's Block 6307/3 southwest of the discovery. Partners in this block are Total Marine Norsk AS, Norsk Hydro, and Saga.
West of 6507/3, Norsk Hydro tested gas and condensate this month in two Cretaceous zones at 9,184-10,496 ft in its 6507/2-2 wildcat, drilled to 12,906 ft in the Jurassic. The best gas gauge was 23.66 MMcfd, and the best condensate flow was 882 b/d. Norsk Hydro said the well provides much new information about the Nordland 11 area.
Exploration in other parts of the Norwegian Sea has failed to repeat the success of Haltenbanken.
Norsk Hydro plugged its 6305/12-1 wildcat in the South More area of the southern part of the Norwegian Sea, which has only been very lightly explored. It was only the third well in this part of mid-Norwegian waters. The main target of the well was Jurassic but industry sources say the Triassic also is thought to be prospective in this region.
Last year Statoil plugged without testing its 6201/11-2 wildcat in the South More area.
Statoil also drilled its 6406/12-1S, only the second well in the Trondelag II area southeast of Haltenbanken. The well went to 14,890 ft but found only traces of hydrocarbons.
The first well on Trondelag II was also drilled last year by Saga in adjoining Block 6406/11, but it too was dry.
Last spring Statoil drilled a dry hole at its 6507/8-4 wildcat northeast of Heidrun in north part of Haltenbanken.
GAS DEBATE
The debate over Haltenbanken's role as a gas supply source during the 1990s was instigated by Saga, operator for Midgard gas field in Blocks 6507/11 and 6407/2. A small part of the field extends into Block 6407/3.
Last spring Saga declared the field commercial and proposed a development plan that, if approved by Storting, would see the start of gas shipments in October 1996.
Production of 775 MMcfd would move through a 375 mile pipeline to the North Sea, where it would connect with Frigg field with its twin pipeline links to Britain.
The project requires a sales contract for the gas and backing from the biggest partner, Statoil, which has not approved the declaration of commerciality.
Saga's other partners in Midgard are Norske Shell, Neste Oy, Norsk Hydro, Norsk Agip AS, and Deminex Norge AS.
Until Saga put forward its Midgard development proposal, it generally had been assumed in Norwegian oil and government circles that Haltenbanken gas would be only a minor supplier of feedstock to the methanol plant until the next century when a pipeline link to the North Sea would be laid.
The Saga proposal has not been universally welcomed. Statoil and the other large Norwegian company, Norsk Hydro, favor further gas development in the North Sea to meet short term demand in Britain and continental Europe.
Statoil, which leads the Norwegian gas sales committee responsible for negotiating all export deals, said there is a possibility of 967 MMcfd in additional new sales through the exercise of options on the Troll-Sleipner field contract and from inquiries for gas from Poland, Hungary, Czechoslovakia, and Austria.
Contacts with potential buyers of additional gas are still in an early stage, but if volumes of that level emerge at the same time as a 775 MMcfd contract from Britain, there would be a case for developing Haltenbanken gas and incremental supplies from the North Sea. If British and continental European contracts do not coincide, the case for early development of Haltenbanken gas evaporates.
If Haltenbanken gas development gets the go-ahead, Statoil does not rule out the possibility of a two center gas project with Smorbukk field being developed as well as Midgard in the initial phase.
HEIDRUN FIELD
Heidrun field is the biggest oil discovery off mid-Norway. Straddling Blocks 6507/7 and 6507/8, it holds estimated reserves of 750 million bbl of oil and 1.6 tcf of gas. About 1.3 tcf is in the gas cap and will not be depleted in the first production phase.
The concrete tension leg platform will be set in 1,148 ft of water. Total cost of the development project will be 25.7 billion kroner ($3.97 billion).
The platform, with 56 slots, will have 49 wells. Initial production will be from nine wells predrilled through a subsea template. In addition, there will be six subsea wells drilled for water injection.
Improvements in high angle drilling have enabled Conoco to abandon plans for a subsea production system in the northern part of the field and concentrate on less costly platform wells. Conoco expects to drill wells with a 74 angle from the platform.
Crude oil production is expected to plateau at about 200,000 b/d. Associated gas production is expected to be about 75 MMcfd, which will move ashore by pipeline and be used as feedstock at the methanol plant.
A contract for construction of the concrete hull has been let to Norwegian Contractors. Kvaerner Engineering is undertaking the detailed engineering of the topsides.
Slipforming the hull will start in Norwegian Contractors' Stavanger dry dock in December. The hull is to be mated with the topsides in summer 1994, and the completed unit will be towed to the field in May 1995. Oil production is scheduled for August of that year.
When production starts Statoil will take over as operator from Conoco. This has required close cooperation between the two companies during the design phase, continuing into the construction stage of the project.
Heidrun oil will be exported by tanker. The Heidrun group-Conoco, Statoil, Norsk Hydro, Det Norske Oljeselskap AS, and the Norwegian government-has contracted shipments to Statoil, which operates the world's largest fleet of custom built shuttle tankers.
Oil will be loaded through a permanently moored storage unit. Conoco and Statoil are evaluating a tanker based floater and a Spar style buoy, which also will provide storage. The companies also are evaluating the economic tradeoff of a much less expensive two-tanker system that would load vessels directly from the TLP against possible production losses when tankers cannot load in rough weather. A decision is expected shortly.
In August, the subsea drilling template, under construction at Kvaerner Rosenberg's Stavanger Yard, will be towed to the field and installed by Heeremac's DB102 crane barge.
Transocean Drilling holds a contract to drill nine wells prior to the TLP installation.
The Conoco-Statoil partnership had to wait until last month to get Storting approval for the methanol plant and gas pipeline link from Heidrun, named Haltenpipe.
The 152 mile, 20 in. pipeline will run from the field, passing to west of Midgard field to a landfall on the island of Hiltra. It will then be routed via an inshore sea crossing to the Tjeldbergodden plant site.
The line will have a capacity of 340-435 MMcfd, far in excess of volumes that can be justified by the methanol plant. Various plans have been proposed for gas fired power generating capacity, in mid-Norway to use offshore gas reserves. Surplus power would be exported through the mountains to Sweden.
But those plans have run afoul of the economics of exports and more recently of Norway's proclaimed desire to cut carbon dioxide emissions and its determination that other industrial countries should adopt similar policies.
Against this background it took considerable political pleading from mid-Norwegian interests to ensure that the methanol plant took precedence over national environmental policy objectives. Local enthusiasm for gas fired power generation in mid-Norway probably is not strong enough to win approval for more gas usage in the area.
Haltenpipe is expected to cost about 3.5 billion kroner ($541 million) and will be on stream for start-up of the methanol plant in fourth quarter 1996.
The methanol plant, to be operated by Statoil, will have a capacity of 830,000 metric tons/year. It can be expanded to 1 million tons/year if associated gas from Draugen field is sold to the plant.
About 200,000 tons/year of methanol will be channeled into Statoil's methyl tertiary butyl ether production. After Conoco has taken its share, the rest will be sold on world markets. The unit is expected to cost about 2.4 billion kroner ($371 million).
Statoil has an 81.875% share in the methanol plant with Conoco holding the remainder. Pricing of the gas feedstock will be based on methanol prices.
DRAUGEN MONOTOWER
Shell will develop Draugen field at a cost of 12.4 billion kroner (51.92 billion) using the first concrete gravity based monotower off Norway.
The unit is being slipformed at Vats, north of Stavanger. The single column unit will be mated with the topsides in January 1993 for installation the following summer.
Production is scheduled for autumn 1993,
Work also has started on the offshore loading buoy through which crude will be transferred from the platform to shuttle tankers. The monotower design from Norwegian Contractors allows crude oil storage in the base of the platform.
Shell, which operates on behalf of Statoil and BP Petroleum Development (Norway) Ltd., also is negotiating tariffs for selling the small reserves of gas in the field to the Statoil-Conoco methanol plant.
If sale terms cannot be agreed, Shell has the option to reinject associated gas into the Draugen reservoir until 1999. By that time the company hopes there will be a pipeline to the North Sea.
Draugen lies south of Heidrun, close to the route for the proposed pipeline to Tjeldbergodden.
FUTURE DEVELOPMENTS
In addition to promoting Smorbukk gas field as a rival to Midgard in any Haltenbanken gas development, Statoil is drawing up plans to develop South Smorbukk oil and gas field using a production vessel.
A 5.5 million kroner ($851,000) contract for a conceptual study of the vessel has been awarded to Kvaerner Rosenberg, Stavanger.
The development project is undergoing an optimization exercise at Statoil designed to improve its economics and allow development to proceed.
Copyright 1992 Oil & Gas Journal. All Rights Reserved.
