OFFSHORE EUROPE

Norwegian offshore sector spending is set to climb 30% this year to NKr 37.6 billion, according to the latest survey of oil company intentions by the Federation of Norwegian Business and Industry.

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Norway gas projects gaining impetus

Norwegian offshore sector spending is set to climb 30% this year to NKr 37.6 billion, according to the latest survey of oil company intentions by the Federation of Norwegian Business and Industry. Some big development projects are starting to come together: ExxonMobil's Ringhorne and Norsk Hydro's Grane are underway, and Kvitebjørn is close to joining them.

Operator Statoil has modified its original Kvitebjørn development plan, based around a steel processing platform. After re-mapping the field, Statoil now wants to extend the scheme to include the reserves on Kvitebjørn's flanks, which would mean raising well numbers from nine to 11. This would push the likely project cost up a further NKr 500 million to NKr 10 billion, including the associated outlay on trunklines and gas treatment facilities onshore at Kollsnes. However, the platform concept will not be altered.

Another new gas-condensate project run by Statoil is the 20 Bcm gas, 30 million bbl oil Mikkel in the Norwegian Sea. This will be developed as a subsea satellite to the Åsgard B gas production semisubmersible, with well flow transferred via existing facilities on the Midgard Field.

Statoil had considered Norske Shell's Draugen platform as an alternative host. Recovery under that scenario might have been greater, but so would the capital expenditure. The scheme for Mikkel, due to be submitted for approval to the government next month, has a projected cost of NKr 2 billion, with four producer wells to be drilled. Production should begin by October 2003, with the gas piped to shore through the Åsgard transport line.

Statoil and ExxonMobil have also been working on a plan to tie the latter's 67 million BOE Sigyn gas-condensate Field in North Sea block 16/17 to the Sleipner A platform 12 km away. This plan also calls for four subsea wells, with an estimated overall cost of $170 million. Dagny and Gudrun are other satellites in contention for development through Sleipner.

Rev discovery could rescue Varg

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A computer-generated image of the proposed platform for the shallow water Clair Field, west of the Shetlands. At a recent Institute of Petroleum conference in London, BP's Martyn Smith said that development of Clair would help the company realize its target of 300,000 b/d of oil production from the Shetlands area. He expected sanction for this long-delayed project to be granted later in the year.
Click here to enlarge image

When Norsk Hydro and Statoil split the spoils from their joint buy-out of Saga Oil, Hydro seemed to draw the short straw in Varg. This had been a high cost, low return project due to a wild reserves over-estimate. Field life prospects looked dim, and Saga had leased the floating producer in an attempt to cut its losses. Hydro, however, may have saved the situation with a new discovery 5 km south of the floater, in block 15/12.

The semisubmersible Scarabeo 6, drilling in 87 meters of water, found hydrocarbons in Upper Jurassic sandstone, but the scope of the find was uncertain. Hydro had viewed the well on the Rev prospect as a pre-ordained success, drawing up a fast-track development in anticipation. Varg currently produces 26,000 b/d. If the new discovery is connected, that could prolong output for a further two years through to 2004.

Last month, Statoil was due to spud another important appraisal well on its Svale discovery in mid-Norwegian block 6608/10, using the semisubmersible Borgland Dolphin. Svale was discovered last year by the drillship West Navion, but the reserve extent was unclear. If the latest well points to a total beyond 100 million bbl, Statoil will push for a standalone solution also encompassing the nearby Falk Field. A low-end outcome will likely result in a 10 km tieback south to the floating producer on Norne. Either way, a PDO (prodution development order) should follow this summer.

In the same area of the Norwegian continental shelf (CS), Statoil is investigating the feasibility of re-injecting produced water into the Heidrun reservoir. Tests have started on the Heidrun TLP's A-43 well at an injection rate of 15,700 b/d (equivalent to 40% of total water produced from the field). Norwegian operators need to find new ways of disposing of contaminants, in light of Norway's requirement for zero discharge by 2005. If the trial scheme is successful, Statoil may commission permanent facilities to re-inject all of Heidrun's produced water.

Statoil looks again at Siri

In the Danish sector, Statoil is to re-appraise the oil potential east of the Siri complex. Last year, rising rig rates caused it to postpone plans to tap the 6-7 million bbl Siri East structure via small wellhead installation. Next month, however, it will examine Stine, another small structure 7 km east of the Siri production platform, using the jackup Noble George Sauvageau. If the outcome proves favorable, Statoil will follow up with a producer well on Stine or another part of Siri, which would be tied in to the platform. Currently, production from Siri is due to wind down from 2005 onwards. Denerco's latest Danish sector well, Connie-1, found unspecified oil quantities in Paleocene sandstones, a short distance west of last December's Connie discovery (also Denerco-operated).

Ensco 70, which drilled Connie-1, had earlier proved up further oil for state group Dong via the second appraisal well on last summer's Nini discovery. Nin-3 found hydrocarbons in Paleocene sands, before being terminated in Chalk. Both sets of discoveries are regarded as imminent development candidates.

Well confirms Howe's potential

Enterprise Oil may have found a potential new satellite for its Nelson Field complex in the UK Central North Sea. Well 22/12a-8, drilled by the semisubmersible Sedco 711, was appraising the Howe oil discovery, 12 km from the Nelson platform. It encountered 161 ft of Upper Jurassic Fulmar reservoir section, of which the top half was oil-bearing.

All main objectives of the well were met, including detection of a clear oil-water contact. Preliminary estimates suggest recoverable potential in the range 30-55 million bbl of oil. The well has since been suspended for future use, either as a producer or a water injector.

Other UK continental shelf operators advancing incremental production plans include Shell UK Expro, which is moving towards a two-well, 7.5 km subsea tieback to Tern for its problematic Kestrel oil accumulation in the northern sector. Farther south, Shell's Fulmar platform will act as host for Talisman's Halley development in block 30/12b. Two extended reach wells, one a producer, one a water injector, will be drilled from the platform into the 11 million BOE field, which was discovered by Amoco in 1981. Talisman also wants to produce the Hannay Field as a tieback to its own Buchan platform.

In Liverpool Bay, offshore northwest England/north Wales, BHP plans to boost gas throughput via a single-well subsea completion on Hamilton East, connected to its Hamilton North platform via a 6.6 km, 8-in. flowline and umbilical. Subject to planning consent, the well will be drilled this summer by the jackup Santa Fe Monitor, leading to first gas later this year, following modifications to the platform.

There are numerous other neglected gas accumulations in this part of the Irish Sea, in part due to their hydrogen sulfide content, but also because of competition from the giant Morecambe Bay gas fields to the north. However, rising gas prices across Europe have led to re-evaluation of the area's potential. In anticipation, Britain's Depart-ment of Trade and Industry recently made available blocks containing two undeveloped fields discovered by Kerr-McGee. Infastructure in the area continues to grow following Burlington's recent investments on the Millom fields.

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