Long-term licensing plan

Exploration off Norway has thrown up few surprises in recent years. The Energy Ministry's solution is more "predictability" – at least as far as North Sea licensing is concerned. From now on, blocks will be offered each year from pre-defined areas, with a clear forward timetable showing what will be available in the years to come. Most of the acreage will be mature, or close to long-established infrastructure.

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Jeremy Beckman • London

Exploration off Norway has thrown up few surprises in recent years. The Energy Ministry's solution is more "predictability" – at least as far as North Sea licensing is concerned. From now on, blocks will be offered each year from pre-defined areas, with a clear forward timetable showing what will be available in the years to come. Most of the acreage will be mature, or close to long-established infrastructure.

License applications will be invited from Jan. 1 through end-September. The remaining months will be set aside for a review of procedures and acreage that might be considered newly "mature." This year, for instance, parts of the Haltenbanken in the Norwegian Sea have been included in the 143 blocks currently on offer.

The Ministry is hoping its new transparency will arrest the slide in exploration drilling – partly by allowing interested operators to improve their forward planning. But these measures may appeal more to independents geared to tail-end production. The more skeptical majors are generally fixated on Norway's ultra-deepwater tracts, currently off limits to all except trawlers.

Others are more concerned about the slow pace of the proposed Norwegian-UK crossover zone development pact. One company making a real push in this area is Marathon, operator of Brae on the UK side and of exploration acreage west of Heimdal. Here it recently announced a second discovery from a three-well campaign, drilled by the Deepsea Bergen in license 008BS. The well on the Boa prospect, in 120 m of water, encountered a 25 m gas column and a 28 m oil column in Heimdal sandstones. In part the well was also delimiting Norsk Hydro's nearby Kameleon discovery.

Also in the North Sea, Statoil has farmed into 50% of two Esso-operated licenses close to Sleipner West. The two companies now plan a joint exploration effort, said a Statoil spokesman.

Varg not finished

Pertra's recent successful appraisal of Varg South could extend the stay of the main Varg field's FPSO. Sidetrack 15/12-13B found a 35 m oil column within a gross hydrocarbon column of 90 m. The result seems to back Pertra's estimate of 100 MMbbl overlain by a gas cap.

Development through the Varg facilities, including a wellhead platform, could involve extended reach and subsea wells. There may also be gas processing constraints on the FPSO. The main Varg field is facing depletion in 2004.

Norsk Hydro is progressing toward first production from Fram Vest this October, through the Troll C platform 20-km distant. Five wells have been drilled, one more than the original base case, with higher deliverability than was originally foreseen. Tie-in work on the platform includes a new 900-metric-ton process module.

Hydro has plans for at least two more undeveloped finds close to Fram with combined liquids reserves of over 150 MMbbl. However, it has sold its 30% operating interest in the Gjoa field to Gaz de France. At one point, Gjoa was viewed as an ambitious joint project with Fram, involving a 75 km tieback to Troll.

Cleaner water on Statfjord

Statoil is conducting a long-term test of new water treatment technology on its Statfjord B platform.

The CTour system involves injecting produced water with a condensed gas that serves as a detergent, with the mixture being passed through a hydrocyclone. A centrifugal process then separates the condensate out again. Statoil claimed recently in its house magazine that the technology removes over 80% of oil and chemical residues from produced water.

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The wellstream is separated on the platform, with oil directed into the storage tanks and clean water discharged to the sea.
Click here to enlarge image

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Norsk Hydro recently revealed its intention to reinject produced water from the Oseberg complex back into the field's reservoirs, as part of a campaign to reduce harmful discharges to the environment by 80% between 2002-06.

Pipe-in-pipe adapted for Rhum

BP has been cleared by Britain's DTI for a long distance subsea scheme for its high pressure, high temperature Rhum gas field. Rhum, with around 800 bcf recoverable, lies in 110 m of water in northern North Sea block 3/29. Gas will be piped through a 44 km line to BP's Bruce platform, which will be fitted in readiness with a 1,700-ton compression module, currently under construction by Amec in Wallsend, UK.

The pipeline, engineered by JP Kenny, will be a pipe-in-pipe concept comprising a 16-in. inner section and a 22-in. carrier pipe, protected by a high integrity pressure protection system. Flowlines connecting Rhum's four wells to a subsea manifold will be coated with 25% chrome steel. These facilities will have to cope with downhole temperatures and pressures of up to 150° C and 12,000 psi, the sternest to date for a UK subsea project. Development drilling should start mid-2004, with first gas out in late 2005. BP's partner in this project is the National Iranian Oil Co.

Two smaller subsea solutions were also approved on the UK shelf. Centrica is developing the 88 bcf Rose field in the southern gas basin as a single well development for £50 m. According to London-based field analysts Britboss, the gas will feed through the same pipeline installed to take production from ATP's Helvellyn satellite to BP's Amethyst platform. Back in the far north, Total is investing £30 m on what it claims is the UK's longest subsea tieback, at 67 km, to the Alwyn North platform. It could also be argued that this is a straight 13 km flowline connection between the Nuggets N4 accumulation and the existing manifold on N3.

In the central sector, Technip-Coflexip has clinched the subsea installations for Petro-Canada's second operated project on the UKCS. Like Guillemot West, Clapham will produce to the Amerada Hess-operated Triton FPSO. The four manifolded subsea wells will be installed late this year.

Dong looks north and west

Danish oil company Dong is lining up a new batch of projects in Danish and Norwegian waters. In partnership with Amerada, it has been drilling three prospects within tieback reach of the Arne south platform. It has also debated joint development with Amerada, Shell, and ConocoPhillips of four small fields either side of the Danish/Norwegian median line.

Deep in the Danish sector, Dong is putting the finishing touches to Nini/Cecilie, its first operated offshore development. Both of these fields will export oil from individual wellhead platforms to the Siri field production complex. Recently, Dong discovered further oil with the Sofje-1 exploratory well 20-km northeast of Siri.

Gasfield activity in Danish waters has been left to the DUC consortium of AP Møller, Chev-ronTexaco, and Shell. Historically, Dong has bought their entire output as Denmark's monopoly distributor, but this is no longer the case following liberalization of Europe's gas markets. Now an oversupply situation is building up, forcing the DUC and Dong to look at new markets for their gas. Export options include new pipelines taking Danish supplies into the Nogat or Norpipe trunkline systems. A commercial agreement on one of these options is thought to be close.

In Norwegian licenses 122 and 122B, Dong has made a move to buy equity operated by Statoil containing a known gas discovery, Marulk. However, this is a long-term investment, says Dong, with development apparently some years off.

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