Offshore Europe

Statoil has confounded the generally depressed view of E&P offshore Norway.

Jeremy Beckman

Statoil upbeat following latest results

Statoil has confounded the generally depressed view of E&P offshore Norway. Last year, its share of production from Norwegian fields hit a new peak of 985,000 boe/d, said Henrik Carlsen, executive vice president for exploration and production. The production rise was due largely to scheduled increases in sales gas contracted to the continent; however, Carlsen was confident that this level could be sustained in 2003, eventually breaching the 1 MMboe/d mark. He claimed the company had also identified many strong exploration prospects throughout the shelf.

At present, Statoil is involved in a record 13 Norwegian development or modification projects. Last December, it also assumed operatorship of the Snorre, Tordis, Vigdis, and Visund fields in the North Sea, making it the sole operator in the Tampen area.

"This will help us form proposals to develop these fields on a combined basis in future, rather than as individual projects, thereby increasing operating efficiencies," Carlsen said. In fact, oil production from the fields is set to decline "pretty fast," he admitted. Statoil's priority is to arrest this decline and initiate development of gas for the first time from Statfjord and Visund. Results of the program will, however, not be evident before 2007-08.

Last year, the company lowered its finding and development costs over the shelf to $5.30/bbl. It wants to maintain that downward trend through application of new technologies.

"Many of the newly discovered gas fields are not as economic to develop as the oilfields," he said, referring basically to the "stranded" deep-water finds farther north. "The other main challenge is to get hold of new exploration acreage. The most interesting areas are the deepwater Norwegian Sea, Nordland VI, and the Barents Sea." While the latter was off limits to drilling last year, Nordland VI may open up at last under the current 18th licensing round, depending on new environmental impact reviews.

This summer, Statoil will spud its first well on the Ellida prospect in 1,000 m of water in the Norwegian Sea, using the West Navion drillship. The location is 60 km northwest of the Ormen Lange gas field, and east of last year's unexpectedly dry wells on the Havsule and Solsikke prospects.

"We will be testing a different geological play to those two," more analogous to Ormen Lange's, Carlsen said.

"We're also focusing on ways of reducing our drilling costs through increased drilling efficiency. For instance, you might pay more initially for an expensive rig, but if it can operate in tough conditions, with very competent people in charge, they can do marvelous things to reduce drilling time and thereby cut costs overall." Another aim is continued reduction of emissions from Statoil's Norwegian offshore operations. Its CO2 emissions in 2002 of 8.9 metric tons are claimed to be a quarter of the world average.

Portents for UK production

Higher petroleum taxes imposed last year are hitting UK field development, and prod-uction targets are proving to be elusive. These were among the warnings the UK Offshore Operators Association issued in its 2002 Economic Report. Ukooa counted 260 oil and gas fields either in production or under development on the UK continental shelf (UKCS), up from 248 in 2001. Total remaining reserves were also 1 Bboe higher, at 11 Bboe. However, there was a fall in planned new developments last year from 148 to 84.

Another discouraging conclusion is that operating costs are set to climb from $4.10/boe last year to $4.90/boe in 2010. As the UKCS is already seen as a high-cost region, this will further damage its competitive rating globally.

The government/industry target of 3 MMboe/d through 2010 is becoming harder to achieve. Ukooa identified a shortfall of 650,000 boe/d. Total oil and gas production between 2002-2010 is now put at 12.9 Bboe, around 370 MMboe below the figure predicted in 2001.

This decline is in spite of a large contribution in the second half of the decade from Buzzard, Britain's largest new discovery since the 1980s. Much of the tail-off is due to a negative re-assessment of the commerciality of remaining gas deposits on the UKCS. This partly explains why the owners of the Interconnector trunkline between Bacton and The Netherlands plan to double import capacity from 2006 to 1.6 bcf/d.

Despite the apparently sluggish picture, the report reveals that $5.1 billion in assets changed hands in the UK sector last year, and BP has since concluded two major property deals with Apache and Perenco. New entrants continue to be attracted; however, the report also points out that the cost of capital for start-up companies on the shelf may be 22-28%, which means they need to also deliver high returns (above 20%) on their new projects. Ukooa believes that unless the government eases its tax take, now between 40% and 70%, its hopes of encouraging more participants may be thwarted.

Venture revives Chestnut

Ukooa's current president is also head of Venture Production, one of the new intake. In March, Aberdeen-based Venture brought onstream Sycamore, its second operated subsea development in "Trees" block 16/12a, which it acquired from Lasmo in 2000. As with its predecessors Larch and Birch, the host platform is Marathon's Brae A in the central North Sea. Sycamore is being developed in phases, ultimately with three oil producers and two water injector wells gathered at a seabed manifold, linked by a 4.5-km flowline and control bundle to the Birch/Larch pipeline.

Venture's strategy is to prove up extra res-erves from others' unwanted assets. In this case, it undertook a comprehensive geological and geophysical reinterpretation over the Sycamore area in mid-2001. Venture has also just become operator of the Chestnut oil field in block 22/21, after acquiring Amerada Hess' 50% interest. Here an extended well test was conducted in 2001 for four months using Brøvig vessel Crystal Ocean, but afterwards, the project went quiet. Venture is now looking for a third party platform in the area for a subsea tieback, with a scheme incorporating water injection. Reserves are around 16.25 MMboe.

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