Jeremy Beckman
London
Explorers affirm mid-Norway potential
Virgin territories figured highly among blocks nominated by oil companies for Norway's 15th licensing round. Of the 150 blocks that gained multiple nominations, 120 were located in mid-Norway alone. The Ministry of Industry and Energy was expected to announce its verdict this month.
Main areas of interest were undrilled parts of the Moere and Voering Basins, and the northern extension of the Nordland area. Interest would have been heightened by Statoil's recent oil and gas discoveries in Moere Block 6204/11, and a reported hydrocarbon find resulting from a BP mid-Norway wildcat targeting a Jurassic prospect.
Previous wells in the vicinity, by Esso and Elf, were dry. However, recent mapping of the Voering Basin suggested the presence of large oil structures. The Norwegian Petroleum Directorate has estimated that up to 16 billion bbl could be uncovered in mid-Norway.
15th round license awards will likely be made in November, and probably to smaller groups: traditionally, half the world's oil companies have been co-opted into each Norwegian license.
The Ministry will be hoping that a new spate of drilling ensues. Analyst Wood Mackenzie estimates just 19 E&A wells were spudded last year off Norway, down 30% from the 1993 level. However, the strike rate per well was three times better in 1994, at 44%. This success level makes finding costs in Norway (translated as $1/boe by WoodMac) very competitive with the rest of the world.
UK opens Far West frontiers
While Norway's Industry and Energy Ministry holds onto southern Skaggerak and northern Barents Sea acreage, its counterpart in the UK, the DTI, has thrown open the floodgates. Britain's 16th licensing round offers 164 blocks in all its developing sectors: companies have also been asked to nominate frontier areas well to the west of Britain as the basis for the 17th round.
Almost 40% of blocks in the current round are situated west of the Shetlands, where interest has been frenzied following major discoveries by BP and Amerada Hess. Pessimists have countered that the costs of development in an area of huge swells and total lack of infrastructure will be prohibitive.
This isn't borne out, however, by Wood Mackenzie's cost analysis of BP's Foinaven Phase 1 floater-based development, which estimates Capex at ٠.75/bbl. That compares with 㾶.41/bbl for Oryx's Hutton, a TLP-produced field in the North Sea with similar reserve quantities to Foinaven's. As for the swells, none of Statoil's Gullfaks installations on the same latitude have yet been swept out to sea.
Any further fast-track production would be welcomed by Britain's government. At a recent North Sea conference organized by IIR in London, Sid Price, senior economist advisor to the DTI, revealed that 12% of the UK's current growth rate (around 3%/year) was due to North Sea oil revenue. It was also responsible for half the improvement in the nation's balance of payments, he claimed.
Operators team up for gas study
Despite the dash for gas across Europe, investment for field operators remains a risky business with returns from gas prices not guaranteed to cover the cost of expensive new pipelines. One answer is to pool resources, which is what four high profile operators are currently contemplating with five large gas-condensate fields in the UK Central North Sea.
The five are Elf's high temperature, high pressure finds Franklin and Elgin; Texaco's Erskine; and Shell/Esso's Shearwater and Puffin. A joint in-house engineering study has been initiated by the four operators to investigate the feasibility of a combined development based on a central platform and with shared pipeline infrastructure. Total gas and condensate reserves are put at 3,600 bcf and 450 MM bbl.
This could be sufficient to justify a dedicated pipeline, possibly to continental Europe, given the French influence of Elf. Alternatively, a tie-in might be arranged to Amoco's UK CATS line.
Recently, Ranger sold its interests in Franklin and Elgin to Shell/Esso. Similar acquisitions from the smaller shareholders in these fields look likely, as the main contenders position themselves for operatorship of any integrated development.
The one complication is Erskine. Texaco is operator for the pre-sanction phase of the project, with BP paying 52% of the costs. The field is due to be unitized, with the development concept and production operatorship determined before the government seals its approval. BP favors a standalone, not normally manned steel platform in 90 meters of water, with unprocessed well fluids flowing 30 km via a multiphase pipeline to Amoco's Lomond platform. One solution could be for BP to lifts its share of the gas independently from Texaco.
Two sectors may share Lulita
Lulita, a small oil and gas field recently declared commercial by Statoil, could turn out to be the first joint Danish/Norwegian development. The field, which lies in two Statoil-operated blocks in Danish waters, as well as AP Moeller's 1/62 license, is thought to extend across the Norwegian median line. A well would be needed to test this theory, with timing dependent on the outcome of unitization talks between the three license groups.
Two scenarios for Lulita as is could be a joint development with Norske Shell's Trym gas/condensate prospect across the median line, or a tie-back to the Harald platform on the Danish side. Lulita's reserves are estimated at 38 MM bbl and 2 bcm of gas.
The Danish sector as a whole is about to witness a temporary flurry of activity, with the Danish Energy Agency predicting a 50% upsurge in exploration and production spending this year to $1 bn. Half of this relates to development work on the Harald, Svend Roar, and Tyra Fields.
Denmark's normally sleepy exploration scene has been roused by Amerada Hess' recent acquisition of Norsk Hydro's Danish upstream subsidiary. Amerada has since bought up British Gas' acreage in its two operated Danish licenses: the company was due to spud its first commitment well.
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