Jeremy Beckman London Saga's 6406/2-1 well in Mid-Norway, likely to be further appraised shortly, may prove to be the most significant discovery this year on the Norwegian shelf. Exploration and appraisal drilling is on the rise in UK waters, where 44 E&A wells were spudded in the first six months of this year against 35 over the same period last year. Some programs have had to be delayed with 70% of the available rig fleet tied up in development drilling: rig contractors, for so long

Jeremy Beckman

Drilling revives in UK, Norway

Exploration and appraisal drilling is on the rise in UK waters, where 44 E&A wells were spudded in the first six months of this year against 35 over the same period last year. Some programs have had to be delayed with 70% of the available rig fleet tied up in development drilling: rig contractors, for so long obliged to cut margins below the bone, are now in a position to dictate over long-term hires.

Not quite the same buoyancy in the Norwegian sector, where according to analyst Wood Mackenzie there were 17 E&A completions up to end-June against 14 in the corresponding '94 period. But there have been notable strikes, led by Saga's 6406/2-1 exploration well off Mid-Norway, which found hydrocarbons in the Lower Jurassic while targeting a southern extension of Smorbukk. Early indications suggest 7 tcf of gas and 440 MM bbl of condensate.

Saga suspended the well in April, but was due to make a re-entry for further tests, followed by a second well appraising the structure's southern extent.

More appraisal and exploration activity is likely soon in the Gullfaks 34/11 area, where Statoil, BP and Norsk Hydro discovered gas a year ago. Reserves could be anywhere from 25-75 bcm, but the trio are keen to arrive at a firm estimate quickly, with competition increasing for suitable fields to meet Norway's gas export commitments.

Pecking order should be established soon, for instance, for the new NorFra gas trunkline to Dunkerque in France, now that the partners have agreed to initiate supplies from the 16/11-E riser platform in the Norwegian North Sea. They have also recommended to the Ministry of Industry and Energy that the diameter of this line be 42 rather than 40 inches, to allow for an expansion in capacity. The NKr9.1 billion line, 860 km long, is scheduled to be laid in summer 1997.

Interesting recent completions in Norway include an appraisal (suspended without testing) of Statoil's Beta oil find in block 9/2: this is likely to be a subsea tie-back to the new production facility at the neighboring Yme Field.

Esso's appraisal well 25/8-6 on its Elly prospect found oil in Paleocene sandstones - enough to increase hopes of a development. And a production test on an appraisal well in Statoil's Rimfaks Field in the Early Jurassic flowed 5,660 b/d and 700 mcf/d gas. This has pushed proven reserves at Rimfaks up to 145 MM bbl: a PDO is expected to be submitted for this and other discoveries near Gullfaks by the end of this year.

One Norwegian oilfield newly onstream is BP's Gyda South, claimed to be the deepest and hottest extended reach well in the North Sea. The well, stretching 7,268 meters from the main Gyda Field platform, was drilled horizontally at a depth of over 4,000 meters and a temperature of 154°C. Initial output is 8,000 b/d.

Oil output set for dual-field boost

Wood Mackenzie puts average oil/NGL production in Norway for the first half of this year at 2.80 MM b/d, up 5% on the same period in 1994. Output has been consolidated since the midway point last year, with three new fields brought onstream and five existing ones reaching plateau production. However, output from two of the stalwart producers, Gullfaks and Statfjord, has declined markedly: down 11% and 18% against 1994's first half.

Heidrun and Troll Oil, due onstream shortly, should push the Norwegian daily total above 3 MM b/d. But Heidrun's start-up will be a month behind schedule, due to various technical hitches: these included an incomplete drilling package which forced operator Conoco to perform over 90,000 unplanned hours of work offshore since late June. The delays have helped push development costs to NKr26.7 billion, NK1.4 billion higher than originally intended.

Reserves at Elf's Lille Frigg gas/condensate field have been downgraded around 40% to just 4.2 bcm of gas and 13.5 MM bbl of liquids. The field, which only came onstream in May 1994, has experienced a higher than expected reservoir pressure drop, possibly caused by weak permeability. There appears to be no easy solution for this development, which has also cost twice as much as originally estimated.

OPEC may regard this as a small mercy. Latest production statistics from Mackay Consultants suggest that global offshore oil output rose 6% to nearly 933 million tonnes, with 85% of that increase coming from the North Sea.

The upswing is not helping the oil price, but it is not relentless: according to Mackay, North Sea output is likely to decline steadily after hitting a peak this year and next.

Shell's five-year spending plan

No signs of a turndown from Shell Expro, however, which reportedly has plans to spend £2.5 billion annually in the UK over the next five years. A large chunk is committed to the Brent Field redevelopment, where conversion of platform facilities to handle reservoir depressurization is expected to prolong the field's life to at least 2008. But Shell Expro is also moving closer to a PDO for its HP/HT gas condensate prospect Shearwater (1 tcf-plus) in the Central North Sea.

In the same general area, BP has acquired Clyde's interests in the Buchan Field, ceding in return percentages of the Ross and Ettrick Fields in the Outer Moray Firth. Buchan is nearing the end of its producing life, whilst the other two are old, but dormant discoveries containing an estimated 85 MM bbl combined.

One reason why they had been shelved was the highly faulted nature of their reservoirs. However, the formation in 1993 of the REDS group (Ross, Ettrick and Donan, which has been in production for some while via the SWOPS vessel) led to re-evaluation studies.

These suggest that Ross could now be economic through use of mult-lateral wells and an FPSO. An extended well test is likely next year, which if successful, could improve prospects for Ettrick, the smaller of the two fields.

Conoco also plans an early production test on its Banff prospect in blocks 29/2a and 22/27a. This salt-diapir structure, discovered in 1991, is thought to contain 135 MM bbl of oil and 100 bcf of gas. The test would follow the drilling and completion of two subsea production wells.

Yet another Central North Sea development is in prospect. Enterprise has completed a well on its Bligh discovery, close to its Nelson Field. The well, to a T/D of 15,205 ft, flowed 15.5 mcf/d gas and 2,400 b/d of condensate from a Jurassic formation.

SAGE selected for Britannia gas

Mobil's SAGE terminal in St Fergus north of Aberdeen has been selected to handle gas from the Chevron/Conoco Britannia development. New facilities will be built, including a bypass train, to increase gas handling capacity by over 740 mcf/d. The two existing trains, currently receiving supplies from the Beryl, Brae, and Scott Fields, have a capacity limit of 1,150 mcf/d.

Construction will take two years and should be finished in time for first production from Britannia late in 1998, via a new 200 km pipeline. This agreement with the 22 owners of the field is thought to be the largest third-party gas processing agreement yet in the North Sea.

Another Britannia contract has gone to Land & Marine and Stolt Comex Seaway to supply and connect bundled flowlines from the platform to the subsea production centre. These bundles will be joined on the seabed to form a 15 km single length, possibly the longest yet installed using this technique.

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