U.K. NORTH SEA DEVELOPMENT PROSPECTS TALLIED

Sept. 13, 1993
Reflecting a trend toward marginal developments, more than 80 new oil and gas fields, with estimated reserves totaling 5.7 billion bbl of oil and 13 tcf of gas, are likely to be developed the next 20 years in the central and northern U.K. North Sea. That's the view of Grampian Regional Council (GRC), Aberdeen, which forecasts increased use of subsea and floating production systems to develop fields generally smaller than those producing today. In other U.K. North Sea action: British

Reflecting a trend toward marginal developments, more than 80 new oil and gas fields, with estimated reserves totaling 5.7 billion bbl of oil and 13 tcf of gas, are likely to be developed the next 20 years in the central and northern U.K. North Sea.

That's the view of Grampian Regional Council (GRC), Aberdeen, which forecasts increased use of subsea and floating production systems to develop fields generally smaller than those producing today.

In other U.K. North Sea action:

  • British Petroleum Co. plc plans to jump North Sea spending by 10% in order to hike its U.K. output by 6%.

  • BP also contends recent changes to the U.K. Petroleum Revenue Tax regime, advances in technology and continuing cuts in development and operating costs are key to the long term prospects of North Sea oil and gas developments.

  • Amerada Hess Ltd. produced first oil Sept. 1 from Scott field, which it claims will be the largest oil field development in the U.K. North Sea in the 1990s.

  • BP Exploration Operating Co. Ltd. started up Hyde gas field I month ahead of schedule.

DEVELOPMENT OUTLOOK

The number of U.K. North Sea fields GRC expects to begin development in the next 20 years equals the number developed to date and currently under development, albeit with about one third of the oil reserves and slightly more than half the gas reserves.

GRC noted 67 fields have been developed in the U.K. North Sea to date, with combined reserves totaling 15.6 billion bbl of oil and 19 tcf of gas. Another 13 fields currently under development are due on stream the next 3 years, with reserves totaling 2.5 billion bbl of oil and 2.5 tcf of gas.

The council pegged U.K. domestic demand for oil at about 1.7 million b/d, a level it expects to continue next year but then grow by 1-1.5%/year after 1994-95, as the country emerges from recession.

U.K. gas demand is expected to grow from the current 6 bcfd to 9 bcfd after 2000. Residential and commercial use will increase slowly, but most of the increase will come in the industrial and power generation markets.

Of the existing fields and the 13 under development, about two thirds are expected to continue producing to 2000.

Based on a survey of operators' intentions, the council said 49 new fields are likely to be developed the next 10 years.

It cited 30 fields as candidates for development to 2003 (Table) and said another 45 fields could be developed in 2002-11.

"More and more of the North Sea will already have been explored, and more unfavorable conditions could be encountered in those areas remaining," said the council.

"But there will still be momentum for new discoveries as well as good economic reasons for continuing tying in small reservoirs within reach of existing infrastructure."

BP SPENDING BOOST

BP Exploration Operating Co. Ltd. plans to increase capital spending on North Sea operations by 10% each of the next 3 years, up from 1 billion/year ($1.5 billion/year) spent in 1992-93.

John Browne, managing director of BP Exploration, said this would raise the company's U.K. production of oil and gas by more than 6% in 1995. Oil would account for about 80% of that increase.

BP's current U.K. production averages 500,000 b/d of oil equivalent.

Browne said BP has brought one major U.K. project on stream each year in the last few years. This rate would be maintained to 1996.

Browne told the Offshore Europe conference in Aberdeen last week the extra investment is largely due to reduced taxation making some new developments more attractive and making further development work on existing fields worthwhile.

BP plans infill and development of satellite reservoirs in Forties and Magnus fields, while Andrew and Forth fields are being developed more quickly than originally planned.

BP required 2 rig-years for drilling in 1992 and will require 6 rig-years to complete drilling scheduled for 1994. Two rigs will be employed west of Shetland to confirm discoveries and explore recently acquired acreage.

Andrew field development is being accelerated, said Browne, with first oil now planned for 1994. The Eastern Trough area project for joint development of five fields and four satellites is now scheduled for first output in 1995, while field development west of the Shetlands Islands is now slated for start-up in 1996.

Seismic surveying of BP's Shetlands area acreage is under way and will guide exploration and appraisal drilling in 1994. BP intends to use two rigs west of Shetland for part of next year.

NORTH SEA COST CUTTING

"Our current calculation is that, given a further 30% reduction in capital costs and a 50% reduction in operating costs over the next 20 years, it is possible to raise the total volume recoverable from the North Sea by 25%, from around 60 billion bbl to around 75 billion bbl," Browne said.

"The cost targets sound substantial, but they are little more than the cost reductions the industry has collectively achieved since 1986, when the oil price fall triggered a fundamental reappraisal of everything that was being spent. Capital costs have fallen in that period by somewhere around $1.50/bbl on average, or 25%."

Advances in technology will radically increase recovery from fields, said Browne. The industry norm is now about 45% recovery, but this could be raised to 60-70% within 20 years.

"Twenty years ago the typical fields being developed in the North Sea contained several hundred million bbl," said Browne.

"Now, if the field is reasonably close to existing infrastructure and rigs, a 10 million bbl discovery can be developed successfully and profitably.

"We will still be pushing that limit lower because there is a great prize in accumulations smaller than that. The present estimate is that there are 2,000 pools of 1-10 million bbl. That means a total of at least another 4 billion bbl of oil and gas."

SCOTT FIRST OIL

The first Scott well to go on stream is in the easternmost of three clusters of wells that are connected through subsea manifolds to a processing and drilling platform on Block 15/22.

A second bridge linked platform holds utilities and quarters.

Amerada said first oil was 4 months ahead of its original schedule. Initial production would be limited to 30,000 b/d for about a week, so that the export pipeline to BP's Unity platform can be purged of water.

When the pipeline is purged, six other wells will go on stream, with the aim of hitting plateau production of 180,000 b/d within 3 weeks of first oil (OGJ, Aug. 30, p. 68).

Oil from Scott will be exported via BP's Forties pipeline to Cruden Bay near Aberdeen and from there on to Kinneil oil terminal near Edinburgh for processing.

Gas will be exported via the SAGE pipeline to the Mobil North Sea Ltd. terminal at St. Fergus. All Scott gas production is under contract to Mobil Gas Marketing.

Scott field reserves are 450 million bbl of oil and 287 bcf of gas. Capacities of production facilities are 194,000 b/d of oil, 124 MMcfd of gas, and 310,000 b/d of water injection.

Field partners are operator Amerada Hess 35.27%, Deminex U.K. Oil & Gas Ltd. 21.67%. Amoco (U.K.) Exploration Co. 12.88%, Enterprise Oil plc 12.88%, Mobil 10%, Kerr-McGee Oil (U.K.) plc 3.42%, and Pict Petroleum plc 1.88%.

HYDE GAS FIELD START-UP

Hyde field ties on Block 48/6 and was developed with an unmanned steel platform producing from two extended reach wells.

Gas is sent via a 14 in. pipeline to West Sole complex 7 miles away and from there to Easington terminal, Humberside, for treatment.

First production on Sept. 1 was at a rate of 45 MMcfd, though BP said this will build up to 77 MMcfd during winter peak demand. Field reserves are estimated at 140 bcf of gas.

All Hyde gas is contracted to Alliance Gas, the independent U.K. gas supplier formed by BP, Den norske stats oljeselskap AS (Statoil), and Norsk Hydro AS.

Hyde field partners are BP 55% and Statoil 45%.

Copyright 1993 Oil & Gas Journal. All Rights Reserved.