FULL DEVELOPMENT AGENDA TAKES SHAPE FOR PROJECTS OFF NORWAY

Norway has a broad menu of development projects approved by the government or under review.

Figures released by the Norwegian Petroleum Directorate (NPD) show that oil and gas reserves totaling 1.3187 billion metric tons lie in fields approved for development on the Norwegian continental shelf.

Another 1.0794 million tons of oil equivalent reserves he in discoveries currently under evaluation.

These figures compare with initial reserves in producing fields estimated at 2.0648 tons of oil equivalent, roughly half of which have been recovered.

At present rates of depletion, this gives Norway enough reserves for 17 years of oil production and III years of gas production.

NPD has approved 12 fields that are in various stages of development.

Here's a rundown of Norway's key development prospects.

EMBLA

Phillips Petroleum Co. operates Embla field in Block 2/7.

When it was discovered in 1974 the formation age was assumed to be Jurassic. Confirmation drilling in 1988 showed it to be older.

Estimated reserves are 208 million bbl of oil, 370 bcf of gas, and 1.6 million ton of natural gas liquids.

The original plan was to develop the field in stages, starting with an 18 slot wellhead installation. After processing on Eldfisk, production would move to Ekofisk. From there oil would be carried to Teesside, U.K., and gas would go to Emden, Germany.

But geology and reservoir conditions have caused such problems that development plans will be reevaluated later this year.

Investment for the first stage was estimated at 2.1 billion kroner ($360 million), operating costs at 23 million kroner/year ($4 million/year).

SLEIPNER EAST

Located in Block 15/9, Sleipner East is operated by Den norske stats oljeselskap AS (Statoil). Estimated reserves are 125 million bbl of oil, 1.8 tcf of gas, and 10 million tons of NGL. Recovery would be enhanced by injection of gas, probably from Sleipner West.

When the Sleipner A gravity base sank last year, the field license holders revised Sleipner East's development plans to meet their gas sales obligations under the Troll agreement.

Development changes include a new riser installation and subsea production to drain the northern part of the field.

The field will now start production in October 1993. Gas will go by pipeline to Zeebrugge, Belgium, and Emden. Condensate will go to Karstoe, Norway, once a pipeline has been laid from Sleipner A.

Development costs total 18 billion kroner ($3 billion). Total operating costs, without transportation, are estimated at 8.2 billion kroner ($1.4 billion).

LOKE

Operated by Statoil just north of Sleipner East, Loke field will be developed via a subsea installation tied back to Sleipner A.

It is scheduled to come on stream in October 1993. Gas will be sold under the Troll sales contract.

Reserves are estimated at 13.2 million bbl of oil and 102 bcf of gas in the field's Heimdal reservoir and a probable 12.6 million bbl of oil and 180 bcf of gas in the Triassic reservoir. The Triassic reservoir has not been approved for development.

Loke's Heimdal reservoir has pressure communication with Sleipner East. Coordinated development will prevent large volumes of hydrocarbons being trapped in the water zone between the two fields.

LILLE-FRIGG

Lille-Frigg gas/condensate field, in Block 25/2, is operated by Elf Aquitaine Norge. The reservoir, part of the Brent group, is on a fault block that is an extension of the Heimdal ridge.

Estimated reserves are 247 bcf of gas and 2.7 million tons of NGL.

The field will be developed as a subsea tie-in to Frigg, with three production wells. Treatment will take place on the Frigg platform. From there gas and NGL will be transported to Frigg in the U.K. Stabilized condensate will go by pipeline to Oseberg, Norway.

Production is to start in October 1993. The field development cost will be 1.9 billion kroner ($330 million), with total operating costs of 1.8 billion kroner ($310 million).

BRAGE

Most of Brage field lies in Block 31/4, with extensions into Blocks 30/6 and 31/7. The field operator is Norsk Hydro Produksjon AS, although Statoil holds more than one half of the interest.

The NPD estimates recoverable reserves at 290 million bbl of oil and 60 bcf of gas. This is slightly more than the operator's estimates.

Development will involve an integrated platform on a steel jacket, with production scheduled to begin in January 1994. Production will reach a plateau of 82,000 b/d of oil within the first year. Oil will be transported by pipeline to Oseberg, while a gas pipeline will be tied into Statpipe.

Total development cost is 10.6 billion kroner ($1.8 billion). Operating cost is put at 520 million kroner/year ($90 million/year).

TROLL

Troll field spreads into Blocks 31/2, 3, 5, and 6 and is operated in its first stage of development by AS Norske Shell, although Statoil, the main interest holder, will take over when the field begins production. This is scheduled for 1996 (OGJ, June 22, p. 32).

Troll has estimated reserves of 46 tcf of gas and 400 million bbl of oil. Troll East, first to be developed, is a dry gas reservoir holding two thirds of the field's gas. Troll West, which has not received NPD approval for production, contains gas and oil.

Troll East will be developed by a wellhead platform with a concrete base. It will send output via two pipelines to an onshore processing terminal at Kollsnes, Norway. Sales gas will be sent from the terminal through Zeepipe for mid-European buyers.

The platform will have a capacity of 2.3 bcfd, almost equivalent to Norway's overall production during 1991. Total investment costs have been put at 27.8 billion kroner ($4.79 billion), with operating costs of 830 million-1.15 billion kroner ($140-200 million).

TORDIS

Saga Petroleum AS operates Tordis, which lies in Block 34/7 and holds reserves of 118 million bbl of oil, 42 bcf of gas, and 500,000 tons of NGL.

Development will involve subsea wells tied back to the Gullfaks C platform for processing. Five wells will be producers, and two will inject water.

Production is to start in late 1994. Gas will be sold under the Troll contract, probably traveling from Gullfaks A via Statpipe to Karstoe. The oil will move to Gullfaks A.

Total investment is estimated at 3.4 billion kroner ($590 million), while operating costs will total 3 billion kroner ($520 million).

STATFJORD EAST

Statfjord East, operated by Statoil, lies in Blocks 33/9 and 33/12.

Statfjord East and Statfjord North will have a common project organization and use the same processing equipment on the Statfjord C platform.

Production from the east field will begin in the fourth quarter of 1994 and last until 2007. As many as 10 production and water injection wells will be used to drain reserves estimated by NPD at 122 million bbl of oil and 100 bcf of gas. Gas will be sold under the Troll sales contract.

Two subsea production templates and a water injection template will be used, tied back to Statfjord C. A horizontal well may be used to enhance oil recovery.

Investment costs are put at 3.37 billion kroner ($580 million), operating costs at 70 million kroner/year ($12 million/year).

STATFJORD NORTH

Statoil is operator of Statfjord North, which lies in Blocks 33/9 and 33/12. Production will begin in second quarter 1994 and last until 2009.

The operator estimates total reserves at 174 million bbl of oil. Some 70 bcf of associated gas will be recovered with the oil.

The field will be developed as a satellite of Statfjord C with two production templates and one for water injection. Six production wells and four water injection wells will be used. Gas will be sold under the Troll agreement. Investment costs are estimated at 3.65 billion kroner ($630 million). Operating costs will be 75 million kroner/year ($13 million/year).

SNORRE

Snorre field lies in Blocks 34/4 and 34/7. Operated by Saga Petroleum AS, it contains 750 million bbl of oil and 250 bcf of associated gas. The oil lies in two reservoirs, Statfjord and Lunde, in a highly faulted area.

Existence of additional reserves is uncertain, so the development plan is based on the two major sources. The field is also in the greatest water depths of any North Sea project, nearly 1,000 ft in the south and 1,300 ft in the north and east, Snorre's first phase development will comprise a steel tension leg platform in the south and a subsea installation in the center of the field. Production will be driven by water injection.

Oil will be separated out on the 190,000 b/d capacity Snorre TLP. It will then be transported to Statfjord for further processing.

Phase Two, which will develop the northern end of the field, will involve one of two options. Saga might move the TLP north and hook up another subsea production unit. In the other option, it would leave the TLP in place and deplete the northern reaches by means of two subsea units with 24 wells each.

Phase One investment costs are 23.5 billion kroner ($4.1 billion). Operating costs will total 1.1-1.6 billion kroner ($190-280 million).

DRAUGEN

Norske Shell operates Draugen field in Block 6407/9. It's the first field on the Haltenbanken off mid-Norway to be approved for development '

Recoverable reserves are 430 million bbl of oil and 65 bcf of gas.

A fixed concrete platform with an integrated deck will be used, along with subsea installations. Seven oil storage cells in the platform column will be able to hold 1 million bbl of oil, prior to transportation to shore by tankers. Gas will be reinjected until a transportation plan is in place.

Processing capacity on the platform will be 135,000 b/d. Production is scheduled to begin in October 1993. The 125,000 dwt tanker Knutsen has been chartered from 1993 for 15 years.

One possibility for transport of the gas is to link Draugen to the Halten-pipe gas line, which will be laid from Heidrun to shore and is scheduled for start-up in 1996.

HEIDRUN

Conoco Norway Inc. is operator of Heidrun, another Haltenbanken field, which lies in Blocks 6507/7 and 8.

The field will be developed with a concrete tension leg platform installed over a subsea template with 56 well slots. This will accommodate 35 producers, 11 water injection, and two gas injection wells. Reserves estimates for the field vary. NPD says there are 547 million bbl of oil and 1.35 tcf of gas. Conoco says there are 749 million bbl of oil and 1.59 tcf of gas.

Production capacity will be 220,000 b/d of oil and, initially, 165 MMcfd of gas. Also, gas injection capacity will be 150 MMcfd, while 330,000 b/d of water injection will be possible.

Several concepts for storage of produced oil have been considered, though it looks as though a shuttle service involving three or four storage tankers will be the preferred option (OGJ, July 27, Newsletter).

Investment costs are estimated at 25.6 billion kroner ($4.4 billion), with operating costs of 1.2 billion kroner/year ($207 million/year).

EKOFISK DISCOVERIES

Small discoveries are under consideration for development in the Ekofisk area as satellites to existing installations.

Mjolner field in Block 2/12, operated by Norsk Hydro, is estimated to hold 16.7 million bbl of oil. It may be developed as a remote wellhead platform.

Trym, in Block 3/7 with Shell as operator, has recoverable reserves of about 450 bcf of dry gas and 85 million bbl of condensate.

Sorost Tor, in Block 2/5, is operated by Amoco Norway Oil Co. Reserves are thought by NPD to be 16 million bbl of oil and 70 bcf of gas. A development approach has not been decided.

Mime, 7 km north of Cod field, is operated by Norsk Hydro. Long-term production tests have taken place via a subsea completion tied back to Cod. Reserves are estimated at 5.6 million bbl of oil and 7 bcf of gas.

Statoil is operator of the 9/2 Gamma discovery, which lies in Block 9/2 away from existing infrastructure. Reserves are estimated to be 40 million bbl of oil.

SLEIPNER, BALDER AREA

Sleipner West lies in Block 15/8, operated by Statoil, and 9, operated by Esso Norge AS.

A development plan has been submitted to bring the field on stream in 1996, so that produced gas can be injected into Sleipner East. A simple production platform will be tied back to a processing platform next to Sleipner A. Reserves are 4.2 tcf of gas and 240 million bbl of condensate.

Statoil's 15/12 Beta discovery is thought to have reserves of 95-125 million bbl of oil. A preliminary plan proposes production start in 1995-96.

Balder, operated by Esso, is thought to have 220 million bbl of oil reserves. Test results are under study.

FRIGG AREA

Froy field in Block 25/2, operated by Elf, holds reserves of 95 million bbl of oil, 104 bcf of gas, and 89 million tons of oil equivalent of NGL. Development plans propose a wellhead platform with five production and four water injection wells, coming on stream in early 1995.

Skirne and Bygge are in Block 25/5, with Elf as operator. Reserves are 300 bcf of gas and 10 million bbl of condensate. The fields are likely to be developed jointly as subsea satellites to Frigg field, with production starting about 1997.

Peik is in Block 24/6, where Total Norge AS is operator. Reserves are 450 bcf of gas and 15 million bbl of condensate. This could be an unmanned monotower or subsea development, tied into the Frigg platform.

Hild, operated by Total, lies in Blocks 29/6, 29/9, 30/4a, and 30/7a. It contains 350 bcf of gas and 25 million bbl of condensate. It will be either a subsea development or an unmanned platform, tied back to Frigg field.

Discovery 25/2-5, operated by Elf, has no plan for development. It is thought to hold 33 million bbl of oil and 67 bcf of gas and would probably be tied in to Froy.

OSEBERG, TROLL AREA

Oseberg East, operated by Norsk Hydro, lies in Block 30/6b and holds reserves of 130 million bbl of oil and 20 bcf of gas. Development will probably be by wellhead platform with processing at the Oseberg field center. Start-up is scheduled for 1997.

Huldra is a gas field northwest of Veslefrikk in Block 30/2. Operated by Statoil, the field holds reserves of 600 bcf of gas and 30 million bbl of condensate. Start-up will be late 1996 at the earliest.

GULLFAKS, STATFJORD, SNORRE

Gullfaks South, 34/10 Beta, and 34/10 Gamma are prospects in Block 34/10 operated by Statoil.

Reserves totaling 225 million bbl of oil, 3.76 tcf of gas, and 3 million tons of condensate are estimated. A development plan is being prepared.

The Saga-operated Vigdis field in Block 34/7a is estimated to have reserves of 200 million bbl of oil and 90 bcf of gas. It would be a subsea satellite of Snorre field.

Visund, operated by Norsk Hydro, is thought to have 80 million bbl of recoverable oil, 1.5 tcf of gas, and 70 million bbl of condensate. A floating production system is proposed.

MID-NORWAY DISCOVERIES

Norsk Hydro's Njord field, in Blocks 6407/7 and 6407/10, is estimated have reserves of 190 million bbl of oil and 250 bcf of gas. A floating production system is being considered.

Midgard, in Blocks 6507/2a and 6507/11, is believed by operator Saga to have recoverable reserves of 4 tcf of gas and 100 million bbl of condensate. Subsea production controlled from a monotower is thought the most likely plan.

Smorbukk South is in Block 6506/12, operated by Statoil. Reserves are estimated at 170 million bbl of oil and 400 bcf of gas. The field is a candidate for a floating production system.

BARENTS SEA

About 8.8 tcf of recoverable gas is said to have been proved in the Troms area of the Barents Sea.

Snohvit is the first likely development in the remote area.

An LNG scheme is under consideration; no development will occur until a sales agreement has been concluded. Negotiations are taking place, with Italy, the U.S., and Canada identified as prospective markets.

Snohvit's reserves are 40 million bbl of oil, 3.25 tcf of gas, and 50 million bbl of condensate. Two development concepts are being studied: a floating platform with subsea tie-backs, linked to an onshore LNG terminal; and a subsea production system with boosters to pump output directly to an onshore LNG plant.

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