OFFSHORE EUROPE

Jeremy Beckman
London

• Location of Dalton and other Burlington-owned gas fields in the UK sector of the Irish Sea. [40,137 bytes]

Fram and Freja frozen, pending upturn

Cost overruns on big construction projects are affecting smaller field developments in the Norwegian sector. This was one of the reasons cited by Norsk Hydro for freezing work on the Fram prospect in Block 35/11 for up to a year - the oil price slump and full order books at Norwegian yards were other factors.

Fram's economic profile fulfilled Hydro's requirements, but it was under pressure to make cuts following escalating expenses incurred by fabricator Umoe on the Visund and Troll C platforms. Umoe's explanations were accepted by Hydro and its partners, the result being an agreed outlay for the two structures of NKr11.2 billion against the original estimate of NKr7.6 billion combined. Hydro insists that despite the rises, both fields remain financially sound.

Amerada Hess was less convinced about its Freja oilfield prospect, hence its decision to defer the reported NKr1 billion development indefinitely. Freja is a high pressure, high temperature oilfield which would have necessitated two deep production wells. Technically, Farrow added, it is not suited to a floating production, storage, and offloading vessel - Amerada's favored solution for the North Sea - and it also looks prone to hydrate and wax deposition.

Freja, extending over two Norwegian/ Danish offshore blocks, would have been the first joint development in these sectors. However, this type of situation can also frustrate marginal developments, Farrow claimed. He quoted a Statoil official who had calculated that drilling and completion costs are now responsible for 50% of work on small fields. Finding a way to increase the length of subsea tiebacks to existing infrastructure might be the more logical solution, he reasoned.

Subsea work heats up at Tordis

Not all small field work is in abeyance. Saga is preparing a PDO for two fields in the Tordis area called H Central and Southern Triangle Upper Jurassic. Tordis East, a 34 million bbl development, was due onstream last month through the main Tordis manifold.

H Central, to be renamed Tordis West, has been on test since April and is probably larger than Tordis East. Development costs for all three subsea additions is estimated tentatively at NKr1.4 billion, although that may not take into account remedial measures imposed by processing restraints on Gullfaks C.

Elsewhere, Aker Offshore Partner and Statoil are evaluating options for several small satellite fields close to the Sleipner A platform. Norway's authorities are expected to clear Statoil's plans for the 16 million bbl Beta West satellite to be produced via two subsea wells connected to the Beta East template, with output piped from there to the central Yme Field production platform.

The hull for Saga's Snorre B production semi has been awarded to Dragados Offshore in Cadiz, under a $750 million contract. However, plans to install a pilot plant for stripping CO2 out of flue gases from a turbine on this platform have been shelved.

Scandinavian gas network gains credence

International consultants have concluded that a gas network linking grids in Denmark, Finland and Sweden with gas fields in Norway and Russia could be feasible within ten years. The network could also extend to countries in western Europe and the Baltic region.

The study, prepared by a group including Arthur D. Little, was commissioned by seven Nordic energy companies. It claims that the first stage of the network could be installed and operational by 2005, provided that gas prices conform to the European norm. Based on the estimated investment costs, this appears a realistic aim, the authors believe.

One major component of the western European network is the newly operational Bacton-Zeebrugge subsea Interconnector gas line. Although the system is exporting currently below its 20 Bcm capacity, the operators were confident of further purchases once it was seen to function. This has proven to be the case, with Norsk Hydro Energy in The Netherlands acquiring 0.5 Bcm of capacity last month from stakeholder British Gas.

In the Norwegian North Sea, Statoil has broken with tradition by extending laying of a gas trunkline into the winter season. Castoro Sei has just been hired to back up the Solitaire, which was behind with its schedule due to line-dropping incidents this summer. Castoro Sei will lay pipe from a point in the Danish North Sea towards Emden on the German coast. A third laybarge may also be considered, to ensure that the line is ready to deliver first throughput in October 1999.

Third gas field operator in UK Irish Sea

Pioneering North American independents continue to add impetus to UK development activity. The latest entrant in the sector is Burlington Resources, which bought a package of Irish Sea interests from BG last year, including the 'rivers' gas discoveries.

While BG considered these properties peripheral to its global strategy, Burlington wasted no time on subsea studies. Planning for the Dalton and Millom discoveries is now complete, with the UK government recently sanctioning the Dalton scheme as a two-well satellite tied back 10 km to the Morecambe North platform (operated by Centrica, a division of BG). Millom, 12 km north of Dalton, is also expected to clinch approval shortly.

Dalton was discovered in 1990 by a well which tested Carboniferous gas at 90 Mcf/d through a 2-in. choke. Burlington has been scouting for a jack-up to complete this well and also to drill the second producer. UK analysts Wood Mackenzie expect first gas next October, plateauing at 100 MMcf/d in 2000. Stolt Comex Seaway has been contracted for the subsea installations, including hook-up to the christmas tree at Morecambe North.

Burlington's other prospects include Millom West, Calder, Crossans, and Darwen, two of which might require unmanned platforms. Gas in these cases could be piped to BHP's infrastructure in Liverpool Bay to the south. Brown & Root AOC has just been engaged for five years to provide engineering support to Centrica's gas production division HRL. Duties could include work on a new gas compression plant up the coast at South Morecambe.

In the southern North Sea, BG has finally initiated development of the Easington Catchment Area. Delays to this multi-field project stem partly from the sudden decline in UK gas prices two years ago. Under a first £150 million phase, the Neptune and Mercury fields, situated up to 30 miles off the Yorkshire coast, will be developed through subsea wells on Mercury linked to a new unmanned platform on Neptune.

The combined 370 Bcf of reserves will be piped to a new riser tower next to BP's Cleeton complex, and following processing, the gas will then head through BP's pipeline system to its terminal at Dimlington. Brown & Root Ardersier will build the platform and riser tower, while ETPM UK will handle pipeline and subsea services. First gas is due out late 1999.

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