Statoil proves virtual "extension" of Skarv

Mid-Norway is shaping up for another mid-size development, following confirmation of gas reserves in the PL/159 licence.

Aug 1st, 1999

Mid-Norway is shaping up for another mid-size development, following confirmation of gas reserves in the PL/159 licence. The semisubmersible Byford Dolphin was effectively appraising BP Amoco's 1998 discovery Skarv, 7 km to the southwest. The new well - spudded 170 km off the Helgeland coast in 392 meters of water - encountered gas in Jurassic sandstones. Two sidetracks then were drilled into an eastern extension of the structure, in a failed attempt to prove the additional presence of an oil leg.

Flow rates from the discovery, named C-Fangst, were not disclosed, but over 200 meters of core were retrieved for the next appraisal phase. Operator Statoil has not given up hope of finding oil.

Skarv itself should be undergoing further appraisal drilling via the West Alpha semisubmersible. Reserves here, based tentatively on last year's discovery well, are 250 million bbl of oil and 1 tcf of gas. However, reservoirs in this region are notoriously difficult to map, according to the Norwegian Petroleum Directorate.

Both fields are within touching distance of infrastructure serving the Norne and Heidrun installations, stationed respectively 30 km north and 50 km south of C-Fangst. Last month, Statoil was due to kick off a program for extending plateau production from Heidrun (onstream in 1995) by a further four years. Current maximum production there is 210,000 b/d.

Under the plan, three new subsea wells will be drilled in the northern part of the Heidrun North accumulation, with associated flowlines tied back to the Heidrun TLP. Associated gas from the main reservoir has been either exported to a methanol plant on Norway's west coast or reinjected. But from October 2000, excess volumes will be directed into the Åsgard trunkline system via a new spur line to be laid from Heidrun.

Wells boost reserves in North Sea strongholds

North Sea well results are hardly in the Angolan golden block league. But those operators still bothering to drill are producing the goods in their own back yard. For example:

  • Esso Norge located a new pool of oil just north of the main Balder reservoir. The well, drilled by Maersk Jutlander, hit its target in an Eocene sandstone formation. Balder's long-delayed floating production, storage, and offloading (FPSO) vessel should be a candidate to process the oil, depending on volume. Also, Balder is thought to be under study for subsea separation.
  • Phillips' 2/7-3 Ebba well, drilled by the same jackup, encountered a 195 ft net hydrocarbon column in the Jurassic and 120 ft net in the Rotliegendes. A subsequent Jurassic interval production test flowed 4,300 b/d of 42° API oil and 7.6 MMcf/d of gas on a 24/26-in. choke, with a flowing wellhead pressure of 5,813 psi. The nearest platform is the unmanned Embla wellhead installation, 8km to the east.
  • In southern Dutch offshore block P/9c, Clyde is understood to have met gas with a well drilled close to Unocal's Horizon oilfield. The well was targeting Bunter and Rotliegendes horizons. Clyde, which has a history of fast-tracking developments, could employ its infrastructure to the north in block P16.
  • Finally, Conoco notched another gas find in the southern North Sea, on the E-plus prospect in UK block 49/17. The well, drilled in 110 ft of water by Glomar Adriatic VI to a depth of 10,160 ft in Rotliegendes sandstone, intersected net hydrocarbon bearing sections of 350-370 ft. Conoco is already talking in terms of a dedicated, unmanned platform exporting the gas through its LOGGS or Viking trunklines.

Decommissioning draws nearer at Ekofisk, Frigg

Elf Petroleum Norge has initiated public consultation in the lead-up to decommissioning of its Frigg platforms. Production is due to wind down within two years. The base case is complicated by the platform's locations on both sides of the UK-Norwegian North Sea median line, so two governments will be involved in the process.

Statoil plans to dismantle and remove Ekofisk's 2/4-S riser platform, formerly the tie-in point for the Statpipe and Norpipe gas trunklines. It was shut down last summer when these lines were linked by the new Ekofisk bypass line. A recent review recommended that the platform's topsides and bridge to the Ekofisk central complex be removed by the end of 2000. Seabed subsidence has moved the topsides 7-8 meters closer to the water line than when the platform was installed. Removal of the jacket, however, can be delayed safely until other platforms on the field are decommissioned.

Another redundant Norwegian riser platform, 2/4-G - used to push oil from Valhall to the Ekofisk Tank - may end up being transferred to BP Amoco's Tambar Field. Tambar is under review for development via a tieback to the Ula Field complex. Water depths, at 70 meters, are roughly the same as at 2/4-G's current location. If the idea is followed through, wellhead facilities would be added to the platform with existing riser equipment likely removed. Present weight of the topsides and jacket is 4,000 tons combined.

Statoil has gone a step further by having its entire Veslefrikk platform towed back to the shore, for a mid-term production upgrade. The semisubmersible arrived at the Aker Stord yard in June, and is due to resume service on the field in late August.

The scope of the upgrade included improving the platform's buoyancy and stability, replacing eight steel sections in the hull's crack zone (between the pontoon and columns), and expanding gas-handling capacity. A small module has also been installed to process condensate from the Huldra Field from 2001. Following this NKr1 billion outlay, Statoil hopes to extend production from Veslefrikk for a further seven years until 2015.

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