CAPITAL: London

MONETARY UNIT: Pound

REFINING CAPACITY: 1,784,672 b/cd

OIL PRODUCTION: 2,488,488 b/d

OIL RESERVES: 5.1 billion bbl

GAS RESERVES: 26.6 tcf

A UK Department of Trade and Industry (DTI) task force was working to facilitate the development of 5.6 billion bbl of additional oil during 5 years from UK North Sea marginal discoveries.

Stephen Byers, secretary of state for trade and industry, said the program was intended to maintain UK oil production above 3 million b/d and thereby prolong self-sufficiency.

Byers said the newly formed Leading Oil & Gas Industry Competitiveness (Logic) organization would promote best practices throughout the oil and gas industry supply chain.

He said, "The task force target for the (UK) industry of increasing its share of the world`s market by 50% means increasing exports $3.2 billion/year by 2005. This is challenging but achievable. The task force believes that its proposals have the potential to support up to 100,000 more jobs in 2010 than there would be if no action (were) taken."

The DTI initiative followed a 1999 study by UK offshore operators that predicted investment on the UK continental shelf would fall by more than 50%/year by 2002.

The survey found the average cost of finding and producing a barrel of oil in the UK North Sea was at least $13/bbl, compared with $9/bbl for the Gulf of Mexico and $4/bbl in Malaysia.

The DTI said the UK`s status as a comparatively high-cost exploration and production province was mitigated by a favorable fiscal regime for new fields, political stability, proximity to markets, and a responsive regulatory environment.

Earlier, DTI relaxed its rules to facilitate offshore oil and gas exploration and development.

Although the measures did not reduce taxation, they included streamlined licensing rules and a chance to postpone spending on some drilling commitments.

A joint government-industry task force drafted the measures, which were designed to sustain UK offshore activity through a low oil price period in 1999.

Changes included annual licensing rounds covering half of the available unlicensed acreage, the transfer of obligations on existing licenses onto new licenses nearby, longer production consents, streamlined development plan requirements, and approval of most development plans within 1 month.

GAS markets

In 1999 the UK became the first country to offer all gas and electricity customers a choice of suppliers.

The government said residential gas customers who had changed suppliers saved an average $125/year on their gas bills since competition was introduced, while the overall gas market saved $1.6 billion/year.

DTI published plans for reforming Britain`s electric power market to cut prices to consumers.

Customers had complained about the Electricity Pool pricing arrangement, which set the price at which utilities and industrial customers bought power from generators.

The proposed pricing scheme would be based on computerized trading, including immediate-delivery, futures, and derivatives contract options to enable large-scale electric power users to control their prices.

Wood Mackenzie Consultants Ltd., Edinburgh, said the policy could deter medium-term growth of gas-fired power generation.

It said short-term projects would not be unaffected, and the 6,000 Mw of new capacity that was either being commissioned or under construction would be allowed to proceed. Beyond that, 3,000 Mw more planned capacity was likely to proceed."

However, a further 2,000 Mw of projects that had received partial planning consent, representing more than 70 bcf of (annual) gas demand, were likely to be blocked. Other projects without even partial consent have virtually no chance of going ahead."

Discoveries

Elf Exploration UK PLC had a gas and condensate discovery on Block 29/4d, less than 5 km from Elgin and Franklin fields, which were due on stream in 2000.

A production test on a limited part of the reservoir yielded a flow rate of 23 MMcfd of gas associated with 2,100 b/d of condensate.

Elsewhere, Veba Oil & Gas Ltd. had a gas discovery on Block 21/24. Shell Expro, a joint venture of Shell UK Ltd. and Esso Exploration & Production UK Ltd., was operator of the Guillemot West field on the same block.

Veba said the wildcat was drilled 8.5 km northwest of Guillemot West and flowed 5,894 b/d of oil on test through a 36/64-in. choke.

Interest holders for the block outside the Guillemot license were Veba with 50%, Shell 25%, and Esso 25%.Conoco Inc. had a gas discovery on Block 49/17. Drilled to 10,160 ft in 110 ft of water, it cut 350-370 net ft of hydrocarbon-bearing Rotliegendes sand.

Phillips Petroleum Co. UK Ltd. had a discovery in 250 ft of water on Block 30/7a. The well flowed 4,000 b/d of oil and 42 MMcfd of gas through a 40/64-in. choke at 6,080 psi. It was 4.5 miles from Phillips`s Judy platform.

Fields

Talisman Energy (UK) Ltd. started oil production from Ross field using a floating production, storage, and offloading vessel.

Ross had estimated reserves of 60 million bbl of oil and 20-30 bcf of gas and was expected to produce at a peak of 40,000 boe/d.

Talisman was negotiating with Blake`s operator, Amerada Hess Ltd., to develop Blake as a subsea tie-back to its Ross field.

Talisman began producing Orion oil field, tying the single-well, subsea satellite back to its Clyde platform with a 10-mile, 10-in. pipeline.

Production began at 8,000 b/d of oil and 15 MMcfd of gas. Orion reserves were estimated at 20 million boe.

Phillips Petroleum Co. UK Ltd. began production from Renee field at a rate of 15,000 b/d of oil and 7.5 MMcfd of gas.

Block 15/27 Renee field and nearby Block 15/28b Rubie field were being developed jointly with a subsea system tied back to the AH001 production semisubmersible operated by Amerada Hess Ltd. on Rob Roy and Ivanhoe fields.

Phillips expected oil production from the two fields, with estimated combined reserves of 28 million bbl of oil, to peak at 26,000 b/d.

Phillips planned development of Jade field on Block 30/2c. Jade is a high-pressure, high-temperature gas and condensate field 9 miles north of Phillips`s Judy platform.

It would be developed with an unmanned platform in 260 ft of water, tied back to the Judy platform with a 16-in. multiphase pipeline.

Other projects

Enterprise Oil PLC was developing Cook field on Block 21/20a in 94 m of water. It would be developed with two subsea wellheads tied back with an 8-in. flowline to a floating production and storage facility operated by Shell UK Exploration & Production on Block 21/24.

Cook had estimated reserves of 20 million bbl of oil and 15 bcf of gas and was expected to be developed for $60 million.

Enterprise planned to bring the first well on line in mid-2000. A second well in 2001 would double output to 20,000 b/d.

Elsewhere, Burlington Resources (Irish Sea) Ltd. began gas production from Millom and Dalton fields in the East Irish Sea. Combined production from three wells was 10 MMcfd of gas.

The wells were tied back to the North Morecambe platform operated by Centrica PLC.

Conoco (UK) Ltd. started gas production from Bell field on Blocks 49/22 and 49/23. The field was developed with a single subsea wellhead connected by an 8-in. pipeline to the Callisto South field manifold less than 100 m away.

About 110 MMcfd went to Theddlethorpe via Conoco`s Lincolnshire Offshore Gas Gathering Systems pipeline.

Mobil started oil production from Buckland field on Block 9/18. The 30,000 b/d field was developed as a subsea satellite of Mobil`s Beryl Alpha production platform 10.5 km away on Block 9/13.

Up to 40 MMcfd of associated gas was to be commingled with Beryl field gas and exported via the Mobil-operated Scottish Area Gas Evacuation pipeline to St. Fergus, Scotland.

Enterprise began producing 20,000-b/d Pierce field on Blocks 23/22a and 23/27 with a production and storage ship. Reserves were estimaed a 84 million bbl of oil and 202 bcf of gas. A well drilled on the nearby North Pierce prospect added 20 million bbl of oil reserves.

Kerr-McGee started up Janice field on Block 30-17a in 240 ft of water. It was developed by recompleting two appraisal wells and drilling five more production wells and four water-injection wells.

Reserves were estimated at more than 70 million bbl of 37°-gravity oil. Output was 55,000 b/d. Oil went through a 16-km, 14-in. pipeline to trunklines connecting with Teesside. Associated gas went through a 36-km, 12-in. line to nearby Judy platform.

Conoco started Banff field on Blocks 29/2a and 22/27a at 34,000 b/d. Peak production was expected to be 60,000 b/d and 40 MMcfd of gas.

Processing activity

Phillips-Imperial Petroleum Ltd., Woking, England, began producing ultralow-sulfur diesel (ULSD) as its core product.

ULSD, refined from low-sulfur Ekofisk crude, had a sulfur content of 50 ppm. Production of ULSD followed British Petroleum Co. PLC`s introduction of a similar fuel to the UK market.

Meanwhile, BP Amoco closed a 50,000 tonne/year polybutene plant at Grangemouth, Scotland, as part of a rationalization of the merged companies` assets.

Separately, Conoco Ltd. was spending $145 million to build two desulfurization units at its Humber refinery at South Killingholme for the production of ultralow sulfur gasoline and diesel.

A $55 million gasoline unit was due on stream in early in 2000, and a $90 million diesel unit was due completion in mid-2001.

Transco, the UK gas distribution unit of BG PLC, planned to build a $48 million, 25-mile, 42-in. trunkline between Mawdesley and Warrington in Northwest England. Construction was due to begin in mid-2000 and be completed in October 2001.

Finland`s Imatran Voima Oy and Japan`s Mitsubishi Corp. were building a gas and refinery gas-fired combined heat and power plant at British Petroleum PLC`s Grangemouth, Scotland, refining and petrochemical complex.

The plant would produce 230 tons/hr of steam and 130 Mw-equivalent of electricity.