OFFSHORE EUROPE

Jeremy Beckman
London

The Big Boss backhoe dredging vessel loading a hopper barge off the cofferdam at Bacton, UK, at the start of the Interconnector pipeline installation in Feburary 1997 [20,062 bytes].

Europe achieves integrated gas network

A missing link in Europe's gas distribution chain was inserted last month when the Bacton-Zeebrugge Interconnector pipeline began exporting gas to the continent. James Allcock, chairman of the operating company Interconnector (UK), said that the subsea line's primary purpose was "to create a single European market for gas."

During the early 1990s, the rationale appeared to be rather to create new markets for UK North Sea gas, and that may still hold true, with Britain's government putting the brakes on new gas-fired power stations. But the Interconnector's inauguration does coincide conveniently with the newly enforced European Gas Directive, designed to pry open the EU's gas markets and allow greater competition. Allcock forecast that the input of UK gas supplies, in addition to those from Algeria, Norway, The Netherlands, and Russia, would bring about an equilibrium of gas prices across Europe.

Construction of the 235-km subsea line, plus associated reception/compression facilities at either end, was delivered at 10% under the budgeted figure of £450 million. Only 40% of the line's 20 bcm/year capacity has so far been contracted, but Allcock expected gas sales commitments to pick up as liberalization speeds up. According to Interconnector UK's managing director Roger Cornish, other potential exporters are also waiting to see how the new line and plant performs.

The pipeline is designed for a 50-year life, and capacity could be expanded to 22 bcm through extra compression. Cornish put UK mainland needs at 85 bcm/year, which are covered currently by existing transportation pipelines in the central-northern North Sea and the Irish Sea. Security of supply to the UK looks guaranteed for years to come, following clearance for Norway to resume sending gas to Scotland through the Frigg-related transportation network. A further link will be added early in the new century when Norsk Hydro's Heimdal riser platform (recently awarded to Heerema Tonsberg/ABB) is installed, serving as a hub for supplies from Oseberg, Huldra and other fields close to the two countries' offshore median line.

By then, a solution may also be found for the stranded gas across the UK Atlantic Margin. The latest discovery, in Block 205/23 (named Bombardier) was recently broadcast by operator Arco.

Arco, Mobil in upstream merger

Following the full-scale mergers of Hardy/British Borneo and BP/Amoco, Arco and Mobil have gone piecemeal by combining their operations across 75 blocks in the UK southern gas basin. A new management company for the two sets of assets should come into being by next September.

Synergy already exists in the form of joint operatorship in this area of the Gawain subsea field, but otherwise there is little overlap between the two companies' interests. According to analysts Wood Mackenzie, the blocks contain over 20 commercial assets holding remaining reserves of around 1.8 tcf, plus a potential 800 bcf from technical discoveries.

Combined production from the assets is put at 950 MMcf/d, with a total asset value of around £1.3 billion. The two companies also operate two gas transportation systems in the area, called Lapps and Eagles, and a remote production control center at Great Yarmouth.

This is a core area for Mobil, accounting for 35% of its UK interests. It southern sector inventory has lately been swelled by startup of the Malory Field minimum facilities platform, outputting an initial 60 MMcf/d through a single well. For Arco, the sector represents 75% of its UK portfolio, although it has tried to diversify of late into the oil regions further north. Arco had been trying to limit southern sector costs through standardizing on Sea Harvester and other platforms for a new set of field developments. Managing director Steve Suellentrop said the new combined operation would save $8 million a year, roughly 10% of current operating and maintenance costs.

Petroleum tax threat recedes

Britain's chancellor Gordon Brown has backed down from his proposed reforms of the petroleum tax regime, recognizing that it would not be "prudent" (his favorite word) at a time of depressed oil prices. Most of the trade associations that had been critical of the review and its length - 14 months - were diplomatic in their response, with operators' association UKOOA looking forward to detailed dialogue over the UK's future as a stable oil and gas regime.

Brown's statement, in fact, only ruled out a review "at this stage." without revealing what might happen if the oil price recovered. But UKOOA seemed appeased when it anticipated greater commitment by its members to the current 18th licensing round. Sagging exploration drilling has become more of a concern in the UK sector than field development, where levels have held up, despite the warnings of the tax review's detractors.

However, there is concern about the recent $12/bbl oil price, as the government's own analysis shows that the average cost of extracting a barrel of North Sea oil is also $12, excluding royalties and tax. Crine Network is therefore drawing up a new initiative to cut North Sea barrel costs to $10 by 2000, and $8 by 2002, focusing yet again on management of the supply chain, in addition to well engineering improvements.

Further tieback for Statfjord

Sygna, a 60-70 million bbl oilfield extending over two North Sea production licences operated by Statoil and Saga Petroleum, is to be developed and produced by Statoil as a subsea satellite of the Statfjord C platform, 21 km away. If this month's PDO is accepted by the Norwegian authorities, the field could be in production by August 2000.

Among other Norwegian development projects, Statoil and its partners have proposed a simple steel processing platform for the Kvitebjoern Field, with gas piped either to Kollsnes or via Norsk Hydro's Heimdal or Oseberg facilities. The 50 bcm-plus field is being submitted for the next round of Norwegian gas export allocations.

In light of current oil prices, Saga has decided that the five-field Halten Bank South gas-condensate development off mid-Norway would be too large. It has therefore proposed focusing initially on the Kristin Field, where a northerly extension has just been confirmed following an appraisal well into the Jurassic Garn and Ile formations.

The new plan involves a small TLP on Kristin handling gas processing, with NGLs processed on the Åsgard A production vessel, with separate PDOs to be issued for the Lavrans and Tyrihan North/South fields. However, tariffs being sought by Statoil for use of Åsgard's vessel may prove too costly for even the Kristin project in its current form.

Cash flow is a big problem currently for Saga, following an anticipated NKr 2.5 billion write-down - much of this relating to the high price paid for Santa Fe's North Sea interests in 1996, and also to delays to the production ship for the Varg oilfield.

Subsea route for west coast pipeline

Much of Vestprosess, a new pipeline connecting Kollsnes and a new NGL treatment plant in western Norway, is likely to be laid underwater, even though this would extend the route by 15 km. The extra expense may be tolerated because tenders for laying the line overland proved much more costly than anticipated. The project, now costed at around NKr 1.6 billion, could be completed by October 1999, pending approval.