Jeremy Beckman • London
Gassco recommends new northern trunkline
Feasibility studies suggest that a new long-distance pipeline to Nyhamna would be the best option for stranded gas fields in the Norwegian Sea. Statoil, Norske Shell, and Norwegian trunkline system operator Gassco came to this conclusion after reviewing various gas-gathering solutions and potential landfall routes.
The processing terminal at Nyhamna on Norway’s west coast currently handles production from the Ormen Lange field, which then feeds through the Langeled system to eastern England. Gassco estimates that a direct pipeline from Statoil’s Luva field – due to start up in 2016 – would cost roughly $1.6 billion, and could also transport future volumes from other fields in the Voering area of the Norwegian Sea. One of these would likely be Norske Shell’s Linnorm (ex-Onyx), expected to enter production in 2017.
An alternative line taking Luva’s gas to a terminal farther north on the Nordland coast, with a spur line south to Nyhamna, would cost over $4 billion, Gassco claims. And the price tag for a third option, a land-based gas liquefaction scheme, looks even more prohibitive at an estimated $10.6 billion.
Yards gain from development upsurge
Gas has started flowing from the Babbage field, via the first production platform on the UK shelf to be installed and operated by Germany’s E.ON Ruhrgas. Babbage is in southern North Sea block 48/2a, 80 km (49.7 mi) off the English east coast. The first development phase involved drilling of three production wells and installation of a 28-km (17.4-mi) pipeline to connect the field to infrastructure in the area. Two further wells will be added in the second phase, with the aim of extending field life to 20 years – E.ON Ruhrgas estimates the total development cost at over $545 million.
E.ON Ruhrgas’ newly onstream Babbage platform in the UK southern North Sea.
Also in the southern sector, RWE Dea has contracted Heerema Vlissingen in the Netherlands for a 5,400-metric ton (5,952-ton) platform for its Breagh A gas field in block 42/13. The same yard is also working on a 3,160-metric ton (3,483-ton) minimum facilities platform for RWE’s Clipper South development, in shallower water. Both installations should be delivered next July.
Heerema Group and Dragados are thought to be in the running for the living quarter deck for ConocoPhillips’ Jasmine gas/condensate project in the central North Sea. Dragados’ yard in Puerto Real, Spain, was awarded the decks for Jasmine’s wellhead platform and the associated Judy riser platform this April.
Various other smaller-scale schemes are under way. Technip will lay a new pipeline to import fuel gas to Fairfield Energy’s Dunlin platform in the northern UK North Sea, supplied via a connection to Enquest’s Thistle-Don line. GDF Suez has commissioned Xodus Group for front-end engineering design for a tieback of the Juliet field to the Amethyst platform in the southern sector. And Fabricom Offshore Services has clinched the FEED for Talisman Energy’s Claymore platform compression upgrade scheme.
Norwegian drillers chasing high stakes
The Norwegian Petroleum Directorate has noted a revival in frontier drilling offshore Norway this summer, identifying five high profile wells in the Norwegian Sea. Among these, Shell has been appraising last year’s deepwater Gro gas discovery, with further commitments on the Dalsnuten prospect in the same area, and an appraisal well on Ormen Lange, due to spud this month.
One of the completed wells, drilled by Wintershall in the Mid-Norwegian Halten Terrace region, found oil and gas in the Maria prospect, close to the Tyrihans gas/condensate development. The well was drilled on Maria’s southern segment, proving oil in the Jurassic sandstone Garn formation. Recoverable reserves could be 75-155 MMboe.
Later this fall, NPD expects Statoil to spud this year’s first exploratory well in the Barents Sea, on the Skrugard prospect in license PL 532. Eni is then scheduled to drill prospects in the Alke area in Pl 489, and in PL 533, west of Lopphogda.
Statoil should also have started work on a well on a previously undrilled region in northern Norway. Well 7220/8-1 is being drilled by the semisubPolar Pioneer in 373 m (1,224 ft) of water, at a location 200 km (124 mi) northwest of Ingoya in Finnmark County and 210 km (130 mi) southeast of Bjornoya. Statoil had to factor in risks from drift ice and icebergs in its application.
UK launches deepwater, aging reviews
Britain’s government has ordered an inquiry into deepwater drilling in UK waters, although activity has been limited so far this year. Malcolm Webb, CEO of industry association Oil & Gas UK, welcomed the announcement: “It presents an excellent opportunity for us to respond to and correct the ill-informed comment and opinion emanating from numerous sources about our industry…It will also give us the opportunity to convey the excellent work now being done through the Oil Spill Prevention and Response Advisory Group (OSPRAG), in which the industry, regulators, and trade unions are engaged to address and learn from the issues arising from the Gulf of Mexico incident.” Recently, OSPRAG stepped up its investigations by contracting Wood Group Kenny to assess subsea capping and containment options for wells on the UK continental shelf.
Oil & Gas UK will also cooperate with a new inspection program for UK offshore installations, introduced by Britain’s Health & Safety Executive (HSE). After 40 years of production from the UK North Sea, more than half the sector’s fixed platforms have exceeded or are close to exceeding their design life, HSE points out. Prolonging aging installations, it adds, runs the risk of serious asset integrity problems.
HSE will address these and other issues under its new Aging & Life Extension Programme (Key Programme 4), which runs through September 2013. KP4 will require duty holders to explain how they are managing the risks of their extension programs. It will also work with the UK offshore industry to implement a common approach to management of ageing installations, enforcing remedial action if necessary.
Morvin tied into Aasgard
Statoil has brought onstream its Morvin subsea development in the Norwegian Sea, using two seabed templates and four production wells. The well stream is exported through a pipeline to the Aasgard B platform 20 km (12.4 mi) to the east. Output should build to 51,000 boe/d when the second well comes online. Morvin, discovered in 2001, has recoverable reserves estimated at 70 MMboe, and a probable life span of 15 years. The development cost is around $1.4 billion.
In the North Sea, Statoil has contracted Aibel to build the deck for its new Gudrun field production platform. Aibel will deliver the deck from its yard in Haugesund in July 2013.
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