N. Sea operators confirm development plans

North Sea operators are pressing field development plans for projects in the Norwegian, British, and Danish sectors.

Norway is also preparing for a new gas project further north in the Norwegian Sea.

Among the projects:

Esso Norge AS submitted to Norway's Ministry of Industry and Energy a plan to develop three finds comprising Jotun field, which lies in 125 m of water on Norwegian North Sea Blocks 25/7 and 25/8.
BP Exploration Operating Co. Ltd. received U.K. Department of Trade and Industry approval to develop the western sector of producing Bruce field, which lies in 120 m of water on U.K. Blocks 9/8a, 9/9a, and 9/9b.
Norway's Den norske stats oljeselskap AS (Statoil) issued a letter of intent to Kvaerner SA, Oslo, for construction of a production platform to develop Siri discovery off Denmark on Blocks 5604/16 and 5605/13.

Meanwhile, Saga Petroleum AS, Oslo, applied to Norway's Gas Supply Committee to deliver gas under existing sales contracts from Lavrans B structure on Block 6406/2 central Norway.

Jotun

Esso intends to deplete Jotun's three structures-Elli, Tau West, and Elli South-with a wellhead platform and production, storage, and offloading ship.

The company anticipates approval of the development plan in second quarter this year and has slated first oil production for 1999.

Jotun development cost is expected to be 5.9 billion kroner ($900 million).

Field reserves are estimated at 190 million bbl of oil.

Plateau production is expected to be 80,000 b/d, with oil to be exported in shuttle tankers.

Bruce

Bruce field was brought on stream in 1993 with a drilling/wellhead platform bridge-linked to a process, utilities, and quarters platform.

BP brought the first-phase development of Bruce to peak production of 50,000 b/d of liquids and 860 MMcfd of gas in 1995.

Original reserves for the first phase development were estimated at 210 million bbl of liquids and 2.6 tcf of gas. Now BP plans to produce an extra 61 million bbl of liquids and 728 bcf of gas under Phase 2.

The company plans to deplete Bruce's western reserves with a subsea development tied back to a new steel platform, which will be bridge-linked to the existing Bruce platforms.

The new platform will house a high-pressure gas compressor and gas injection equipment, which will be used to increase recovery of oil and condensate.

An eight-well subsea manifold will be installed in Bruce's western area in summer 1998. Three new wells drilled this year plus one existing well will be tied back to the manifold.

Production from the first manifold is expected to begin in October 1998. Four further wells will be drilled and tied back here in 1999.

A second eight-well manifold will be installed in summer 2001, with drilling expected to continue into 2003.

BP said gas production from the western area will ensure that Bruce maintains sales of gas at plateau rates well beyond 2000.

Oil and condensate from Bruce are sent by a 254-km, 24-in. pipeline to join the Forties export network. Gas joins the Frigg export line via a 5-km, 32-in. link.

Production from the two manifolds is expected to reach 45,000 b/d of liquids and 450 MMcfd of gas. Bruce Phase 2 is expected to cost £350 million ($560 million).

Siri

Statoil's letter of intent to Kvaerner is for engineering, procurement, construction, and installation of Siri platform.

The contract is expected to be awarded in late March and be worth $230 million.

Kvaerner said Siri platform will consist of a jack up unit with production facilities and living quarters mounted on a steel storage tank on the seabed. The tank will be linked to a loading buoy.

Wood Mackenzie Consultants Ltd., Edinburgh, estimates Siri reserves at 90 million bbl of oil. Peak production is expected to be 50,000 b/d of oil. Siri production is expected to begin late in 1998.

The analyst earlier said the field has estimated gas reserves of 25 bcf and could produce as much as 15 MMcfd. However, Kvaerner said gas and produced water will be reinjected.

Kvaerner said, "Siri is a commercially marginal discovery located in roughly 60 m of water and should continue to produce for 5-12 years. Although innovative for a field of this kind, the development concept is based exclusively on existing technology, known systems, and detailed solutions employed in earlier projects."

Lavrans B

Saga hopes to secure a small allocation of gas for its Lavrans B discovery in quantities already earmarked by the gas supply committee for production from the Norwegian Sea.

Lavrans B lies southwest of Smoerbukk and South Smoerbukk discoveries, under development by Statoil as Aasgard project. It lies west of Tyrihans, also being studied for development by Statoil (OGJ, Sept. 16, 1996, p. 23).

Project Manager Per Gamre said, "Lavrans could start delivering 6 billion cu m/year of lean gas from Oct. 1, 2000. Deliveries should continue at this rate for about 9 years. At the same time, we can recover substantial amounts of condensate and natural gas liquids."

Gamre said Saga is considering development with multilateral wells tied back to a floating production, storage, and offloading unit or tension leg platform, with gas exports via Aasgard to Kaarsto onshore terminal for removal of carbon dioxide and liquids.

Saga said it plans to submit a plan for development and operation of Lavrans to Norway's Ministry of Industry and Energy this summer "to ensure approval at the same time as a possible allocation late in the year."