Goldeneye sets tieback standard
Shell and partners Esso, Lasmo, Paladin, and Veba have sanctioned the £300 million Goldeneye gas-condensate development in the UK's Outer Moray Firth. Shell has followed the recent trend of other marginal projects on the UK continental shelf (UKCS) by opting for a relatively small, normally unmanned, platform exporting directly to the shore. The set up was dictated by the field's remoteness from existing pipelines. The platform will cost around $37 million, with Aker Verdal in Norway building the 140-m tall, 3,000-ton jacket while SLP in Lowestoft fabricates the topsides.
Goldeneye, discovered in 1996, contains over 500 bcf of gas and 17 MMbbl of condensates. Produced fluids will be exported directly to St. Fergus on Scotland's east coast for processing through a 105-km subsea pipeline, making this the UKCS' longest tieback to date. Wellstream transfer will be driven by reservoir energy, and there are no plans for compression. No produced water will be discharged from the platform. Onshore processing will be powered by the UK's National Grid, eliminating the need for generators on the platform, and thereby lowering CO2 emissions. The four production wells will be drilled by a jackup in 120 m water depth.
Tott under review
Norske Shell is reported to have found oil and gas with its Tott exploration well 6406/5-1 in the Norwegian Sea. There were rumors that the find was substantial, although these were played down by the Norwegian Petroleum Directorate. The well, drilled by the semisub Transocean Winner in 290 m water depth, encountered hydrocarbons in Jurassic sandstone. The high-pressure/high-temperature (HP/HT) reservoir lies at 4,500-5,000 m water depth.
One block to the north is the HP/HT Kristin development. Operator Statoil is considering installing a 100-km pipeline to take condensate from the new semisubmersible platform on Kristin to the existing liquids reception terminal at Tjeldbergodden, west Norway. Volumes from Tott might have to be included for the scheme to be viable, as its planned capacity is 450,000 b/d. Over time, other fields in the southern Halten Bank could be factored in.
Tjeldbergodden is also one of the proposed sites to receive gas from the giant Ormen Lange Field in the Norwegian Sea. Operator Norsk Hydro, however, favors Nyhamn, 60 km south of Tjeldbergodden, as the landfall site. Hydro has more chance of operating the gas terminal here than at Tjeldbergodden, where Statoil already runs a methanol plant fired by gas from the Heidrun Field. A choice of either site could steer the partners away from subsea facilities operated locally from the shore (the current base case) toward a more conventional scheme with a processing platform.
Norwegian Sea acreage also happened to be the focus of Norway's 17th licensing round, which recently drew applications from 13 oil companies. Awards should be issued mid-year.
Heimdal gas scheme resumes
In the Norwegian North Sea, TotalFinaElf has committed to develop Skirne and Byggve. This follows a deferral last summer due to uncertainty over Norway's gas marketing rules. Now that these have changed, leaving licensees free to sell their gas where they choose, the partners on this license have resumed their plans. The two fields will be tied back to the Heimdal riser platform via two wells feeding into a single 12-in. flowline. Their combined reserves are 6.7 bcm of gas and 10 MMbbl of condensate. Estimated cost of the development is $193 million, with production scheduled to start in October next year.
BP Norge has commissioned a second wellhead platform from Heerema Tonsberg for the northern part of Valhall. This, too, had been placed on hold, following doubts over spare capacity in the oil export line from Ekofisk to Teesside, UK. Delivery is now due in August 2003. The first platform will be installed at the field's southern extremity this summer, as part of the Valhall Flanks project.
Plans for a gas development on the Agat Field have been jeopardized, following an unsuccessful exploration well on the nearby Make North prospect. Operator RWE-DEA and partner Aker Energy were hoping to prove up further gas to justify a platform.
First gas from K1A
TotalFinaElf's K1A platform in the Dutch North Sea.
TotalFinaElf's K1A is the first new gas field onstream this year in the Dutch sector. Gas is being produced through a normally unmanned platform, built by Mercon and HBG Steel Structures, featuring gas separation/processing facilities. Development drilling is still in progress, using the jackup Noble Al White. By mid-2003, production should climb to 20,000 BOE/d. The gas is exported via the Markham complex to the Balgzand terminal in Den Helder, through the WGT trunkline.
Siri expands as host complex
Statoil's Siri platform is set to host three new Danish sector developments. State oil company DONG has submitted plans for its Cecilie and Nini discoveries to the Danish Energy Agency. These call for an unmanned wellhead platform on each of the fields, which have combined oil reserves of 65 MMbbl. Pipelines would be installed between the two platforms, and to Siri, where the oil would be processed. Siri is located 10 km from Cecilie and 31 km from Nini. Development costs are put at just under $300 million, with a probable start to production next summer.
Simultaneously, Statoil plans to develop the much smaller Siri East segment 1 via two subsea wells tied back to the Siri platform. A water injection line could be installed to serve both Siri East and Nini. Statoil would also likely place a subsea water injector on Stine, the western segment (2) of Siri East, which it brought onstream this January via an extended-reach well from the Siri platform.
In time, DONG is expected to assume operatorship of the Siri license as owner of the bulk of the incoming oil. It is also examining the possibility of laying a new westbound trunkline to take gas to the UK from Danish sector fields.
Ramco Energy is building toward its first operated offshore development, off southern Ireland. The Aberdeen-based independent has raised its interest in the Seven Heads Gas Lease Undertaking from 49% to 56.5%, following positive results from an appraisal well (48/24-5A) on the structure. The location was 3.5 km from one of the earlier wells and tested 13.7 MMcf/d. That result, combined with recent technical studies, left Ramco more confident about the reservoir's distribution and continuity, and thereby its commerciality.