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Pierce Field location in the UK Central North Sea.

In the Norwegian North Sea, Saga Petroleum had pre-Christmas joy from its latest well on the northern part of the Varg Field. Well 15/12-A5T2 confirmed the deepest oil-water contact in the field to date, potentially pushing reserves up 50% to 50 million bbl. Varg came onstream a few days later through a wellhead platform linked to a production ship.

Only weeks earlier. Saga had offered the FPSO for lease due to doubts over the field's productive lifespan. That pessimism has not been dispelled by the latest findings. Saga claims that when historical costs are factored in, the project's profitability remains unsatisfactory, with a break-even price of $17/bbl at a 9% rate of return. Further reserves may therefore have to be proven for Varg to move out of the red.

Norway surviving oil price blitz

Most Norwegian fields either in production or coming online this year can still make money, provided that the oil price sinks no lower than $9/bbl. So concludes Wood Mackenzie's latest study, based on analyses using the Excel-based Global Economic Model software.

Older fields, such as Gullfaks, Oseberg, and Statfjord, are being cushioned from the impacts of the downturn by their continued high production rates, coupled with relatively low unit costs. The five mid-Norwegian fields in production can deliver acceptable returns even at $8/bbl, Wood Mackenzie has calculated, reflecting the progress achieved in this region in reducing costs. Current Norwegian efforts to maintain profitability are extending to restructuring of corporate fixed cost operations onshore.

Despite these fine thoughts, BP Norge has contemplated temporary closure of its Ula oilfield (currently outputting 30,000 b/d), claiming it is not profitable at current prices. Statoil has cut its Norwegian exploration budget this year to NKr 1.2 billion, while Norsk Hydro has reportedly halved its planned exploration wells in the sector to six.

Drilling interest may be rekindled next year, however, when Norway launches its 16th offshore licensing round. This will include sought-after acreage in the Halten Bank and Doenna Terrace in the Norwegian Sea, as well as blocks close to the UK median line.

Gasfield schemers now subdued

Norway's Energy Ministry is extending the 100,000 b/d cutback imposed on national oil production last May until the end of June. Thereafter, a host of new fields are lining up to come onstream, eventually pushing Norwegian output back up to record levels.

The same restraints do not apply to gas, particularly in light of reports that Poland wants 500 MMcm of Norwegian gas. Although this initial amount could be met through the Europipe trunklines, longer-term deals could lead to a new pipeline being installed from Western Norway across the Baltic to northwest Poland, according to a story in the Financial Times.

Despite this development, partners in the Kvitebjoern gasfield in the North Sea decided to defer the NKr 5.5 billion project for a year, influenced partly by low gas prices in Europe. However, plans to double gas production at Gullfaks are intact, with Aker Maritime just contracted for the NKr 1.3 billion upgrade of the Gullfaks C platform.

The UK's key gas market remains itself. With domestic needs pretty well tied up through to 2005, the Aurora project partners, working on a solution to stranded Atlantic Margin gas have decided to shelve their studies for the time being. A third phase will not be undertaken unless substantially higher gas reserves come to light from the next set of west Shetland wells.

In the Irish Sea, BHP's Liverpool Bay production looks assured now that long-term gas supply contracts between the partners and customer PowerGen have been renegotiated. The gas is used by a power station nearby in North Wales. PowerGen had become increasingly restless due to the disparity between the price fixed in 1991 and current UK gas prices. These have continued to drift downwards following the recent start-up of the Bacton-Zeebrugge Interconnector pipeline.

Hudson overhaul follows leak

Amerada Hess' Hudson Field in the UK Northern North Sea is back in action, having been virtually redeveloped this past year. It followed detection in late 1997 of a leak in one of the three production lines connecting the Hudson manifold to Shell's Tern platform 11 km away.

Although only one cubic meter of oil seeped out, further checks revealed corrosion in several parts of the system. Having tested and surveyed the pipelines and subsea equipment, the Hudson partners decided to replace the pipelines entirely, in order to safeguard the 50 million bbl still in place. An enhanced integrity management procedure has been set up to protect the pipelines over the remainder of the field's life.

Amoco's Brown became the UK's 200th offshore producing field, and also the fastest discovery-to-development project (two months), when it generated first gas just before Christmas. The deviated discovery well was drilled from Amoco's Davy platform to the target accumulation in October. This was completed early in November, followed by a horizontal sidetrack completed December 21. Only minimal alterations were needed to the platform to handle output peaking at 50 MMcf/d. Gas heads to Bacton via the Indefatigable AT platform.

Chevron learns lesson on Alba

Under-maintenance may have contributed to the collapse of a long-reach well drilled from Chevron's Alba platform. The A27 well was targeted at a prospect four and a half miles away, however problems were encountered when the drill bit was pulled from the hole prior to running 9 5/8-in. casing. Large cuttings had surfaced, indicating collapse of the wellbore.

According to Alba drilling engineer Geoff Holmes, the key lessons were the need to spend more time on hole cleaning during drilling and to undertake more frequent rig equipment inspections. This practice is being applied on the current A28 ERD well, even at the cost of extending the drilling schedule.

Copyright 1999 Oil & Gas Journal. All Rights Reserved.