CAPITAL: London

MONETARY UNIT: Pound

REFINING CAPACITY: 1.854 million b/d

OIL PRODUCTION: 2.7 million b/d

OIL RESERVES: 5.2 billion bbl

GAS RESERVES: 27 tcf

The U.K. government awarded 78 North Sea blocks close to existing infrastructure under its 18th offshore licensing round in late 1998.

Awards were made to 44 companies, of which 22 were operators on one or more blocks.

Science, Energy & Industry Minister John Battle said, "The applications showed that companies are still thinking creatively and generating innovative proposals to identify significant new prospects in the North Sea.

"The willingness of companies to test innovative thinking with both further technical analysis and early drilling, where appropriate, confirms that the industry still sees the North Sea as an exploration area with significant potential in undiscovered reserves."

He said many applications were for tracts close to existing developments or infrastructure, where any discoveries could be brought on stream quickly to prolong the life of producing fields.

But he said, "An unexpected number of applications identified strata and structures with previously unrecognized hydrocarbon potential."

The British Office of Fair Trading cleared oil companies of predatory gasoline pricing aimed at removing competition from independent retailers and supermarkets.

"There was no reason to believe that supermarkets or oil companies deliberately set out to remove independent retailers," said John Bridgeman, director general of OFT.

Supermarkets, which responded to the launch of Esso`s Pricewatch program in early 1996 by cutting prices at their retail sites, were also cleared.

Wytch farm

BP Exploration Operating Co. Ltd. set a world record with a 10.1 km horizontal well in Wytch Farm field.

The M-11 well was drilled from an onshore drillsite into a reservoir that extends offshore and was brought into production at a rate of 20,000 b/d of oil.

BP`s extended-reach drilling program at Wytch Farm began in April 1993. M-11 was the 14th horizontal well drilled from sites on Goathorn Peninsula in Pool Harbour.

The company originally intended to deplete the offshore section of the reservoir from an artificial island but decided horizontal wells would be cheaper and more environmentally benign.

The M-11 well was the second Wytch Farm well for which BP claimed the world extended-reach record. The earlier M-5 well set a mark of 8.035 km.

Wytch Farm was Europe`s largest onshore oil field and had two main reservoirs. The Sherwood was a Triassic formation at 1,600 m half under Poole Harbor and half extending out into the nearshore area. Reserves were 436 million bbl of oil. The Bridport was a lower Jurassic structure at 924 m and was being depleted with conventional onshore wells. Reserves were 27 million bbl of oil.

Wytch Farm owners were BP 50.475%, ARCO British Ltd. 17.334%, Premier Oil plc 12.381%, Clyde Petroleum (Dorset) Ltd. 7.429%, Onepm Petroleum Ltd. 7.429%, and Talisman North Sea Ltd. 4.952%.

Discoveries

Conoco (U.K.) Ltd. encountered a significant oil and gas column with a wildcat drilled in the U.K.`s West of Shetland offshore area, according to license partner British-Borneo Petroleum Syndicate plc, London.

Conoco planned to drill another well on Block 204/14 to target the nearby Onslow prospect.

Shell U.K. Exploration & Production, operating joint venture of Shell U.K. Ltd. and Esso Exploration & Production U.K. Ltd., had an oil strike on U.K. North Sea Block 21/12.

Shell/Esso said the 21/12-3 new-pool wildcat was drilled in 279 ft of water to a total measured depth of 9,669 ft. The well flowed 8,200 b/d of 33°-gravity oil.

Owners were Shell and Esso 31.3% each, Burlington Resources Inc. 26%, and Seafield Resources plc 11.4%.

ARCO British Ltd. found gas with its 14/26a-6 well in the central U.K. North Sea.

Operator ARCO said the well flowed 40 MMcfd of gas with flowing tubing pressure of 1,800 psi. Flow rates were limited by surface facilities.

ARCO planned an appraisal well in 1998. ARCO had a 75% interest, and Calgary-based Talisman North Sea Ltd. had a 25% interest in the field. The 14/26a license was next to Talisman`s 13/30a block, which contained the Cromarty gas discovery.

North Sea

ARCO British Ltd. started gas production in Waveney field off the U.K. on Oct. 17. Block 48/17c Waveney field was developed with a two-well unmanned platform tied back by an 8-km, 10-in. pipeline to the Lancelot export line.

Waveney had estimated reserves of 84 bcf of gas and was expected to produce as much as 80 MMcfd. The gas was delivered to Bacton terminal for sale in the spot market. Waveney interest holders were operator ARCO 86% and Oranje-Nassau Energie BV, Amsterdam, 14%.

Amerada Hess Ltd. started Flora field on U.K. Blocks 31/26a and 31/26c as a subsea satellite of the Uisge Gorm production, storage, and offloading ship.

The vessel was moored in Fife field 8.5 km south of Flora, where it was producing about 26,000 b/d of oil from Fife and nearby Fergus fields. Flora was expected to yield 20,000 b/d of oil at peak. Partners were Amerada 85% and Premier Oil plc, London, 15%.

Ranger Oil Ltd. reported first oil at its U.K. North Sea Columba E field. The field was developed with a single extended-reach well drilled from Ninian Southern platform. Block 3/7 Columba E began production at 9,000 b/d.

Interest holders were Ranger 34.06%, Agip (U.K.) Ltd. 25.7%, Oryx U.K. Energy Co. 26.04%, Deminex U.K. Oil & Gas Ltd. 8.4%, and Murphy Petroleum Ltd. 5.8%.

Texaco North Sea U.K. Co. ordered a process and utilities platform for Block 13/22a Captain field. The platform was to boost production to 85,000 b/d from 60,000 b/d and enable development of Captain`s eastern area. Installation of the platform and start of drilling were scheduled for summer 2000.

Phillips Petroleum Co. U.K. Ltd. produced first gas from Delilah field off U.K. Block 48/30. Delilah was developed as a single well tie-back to the Della subsea manifold, which in turn was tied back to the Hewett platform 7 miles away on Block 48/29a. Phillips said first production was at a rate of 19 MMcfd, but Delilah was capable of delivering more than 23 MMcfd.

More developments

Shell U.K. began production from Mallard field. It has reserves of 25 million bbl of oil and 17 bcf of gas and was expected to produce 16,000 b/d of oil and 11 MMcfd of gas at peak.

The field was developed as a satellite of Kittiwake platform 15 km away, with two subsea wells. Mallard was in 280 ft of water on Block 21/19. Interest holders were Shell U.K. Ltd. 38%, Esso Exploration & Production U.K. Ltd. 38%, and Total Oil Marine plc 24%.

A joint venture of Amerada Hess Ltd., Shell U.K. Exploration & Production, and Texaco North Sea U.K. Co. planned a combined development of Bittern, Guillemot West, and Guillemot Northwest fields.

Bittern straddled blocks operated by Amerada and Shell, while Guillemot West and Northwest were operated by Texaco. The fields were to be developed with a floating production, storage, and offloading vessel. First oil was expected in third quarter 1999, and plateau production was anticipated to be 100,000 b/d of oil.

Elf Exploration U.K. plc was developing Elgin and Franklin fields on blocks 22/30c and 29/5b, respectively, in parallel with development of Block 22/30b Shearwater by Shell U.K. Exploration & Production. Start-up was due in 2000.

The two developments were to share a pipeline.

BP Exploration Operating Co. Ltd. began production from its Bruce Phase II development, a subsea tie-back linked to a new compression-reception platform built alongside Bruce platform 6 km away. The new facilities were designed to produce up to 450 MMcfd of gas. BP said the satellite development would provide 728 bcf of gas and 61 million bbl of liquids. Partners were BP 37%, Elf Exploration U.K. plc 31.5%, BHP Petroleum Great Britain plc 16%, Total Oil Marine plc 11.75%, and Deminex U.K. Oil & Gas Ltd. 3.75%.

Mobil North Sea Ltd. began gas production in Malory field, which lies in 60 ft of water on Block 48/12d. Malory had estimated reserves of 75 bcf of gas. The platform had capacity to handle 100 MMcfd of gas, but initial output was 60 MMcfd of gas from a single well. Interest holders were operator Mobil 76% and EDC (Europe) Ltd. 24%.

ARCO British Ltd. started gas production from Deben field and Bure West. Development of the two fields cost $83 million. Both were developed as single-well subsea satellites of a new minimal facilities platform added to ARCO`s Thames field complex on Block 49/28.

Deben had estimated reserves of 33 bcf of gas, and Bure West 31 bcf of gas. Partners were ARCO 43.3%, Agip (U.K.) Ltd. 23.3%, Superior Oil Ltd. 23.3%, and Deminex U.K. Ltd. 10%.

Mobil planned a $240 million development of its North Sea Block 9/18 Buckland discovery as a subsea satellite of Beryl A platform, with three production wells and two water injectors. Start-up was due in late October 1999. Mobil said Buckland production was expected to reach 40,000 b/d of oil equivalent. Buckland`s reserves were believed to be 30 million bbl of oil and 29 bcf of gas.

Marathon Oil U.K. Ltd. agreed to process and transport crude oil from Larch field, to be developed by Lasmo plc, on its Brae A platform on U.K. North Sea Block 16/7.

Larch was to be developed as a subsea satellite of Brae and would be the 14th third-party field to use Brae facilities. Larch was expected to produce up to 17,000 b/d of oil and 12 MMcfd of gas.

Shell U.K. Exploration & Production chose a disposal plan for the Brent spar loading buoy after more than 2 years of controversy. The operator proposed to dismantle the spar`s hull in a Norwegian fjord and use pieces to build a quay extension.

Plans were to raise the spar slowly in the water so that the hull could be sliced into rings after topsides had been removed for scrapping. Disposal was expected to cost $34.5 million.

Other fields

BP installed topsides for Eastern Trough Area Project platforms. The $2.6 billion development involved seven fields with combined reserves of 400 million bbl of oil and 1.1 tcf of gas.

A two-platform central processing facility was located in Marnock field, and a normally unmanned platform was placed in Mungo field. The other fields-Machar, Monan, Heron, Skua, and Egret-would produce through subsea manifolds tied back to the central processing unit.

Shell/Esso claimed it completed the world`s longest subsea tie-back of an electrical submersible pump with first production from Gannet E oil field. Gannet E sent oil to the Gannet A platform 14 km away through a pipeline shared with Gannet F, brought into production in June 1997.

Shell Expro said Gannet E and F were developed for $130 million. Gannet E output was expected to peak at 14,000 b/d of oil. It had reserves of 23 million bbl. Gannet F had reserves of 19 million bbl of oil and had peaked at 18,000 b/d.

Texaco North Sea U.K. Co. began oil production from Block 15/23a Galley field. It was developed with a production semisubmersible previously used in Emerald field.

Three wells would eventually produce 35,000 b/d of oil and 50 MMcfd of gas. Galley had estimated reserves of 28 million bbl of oil and 40 bcf of gas. First phase development was expected to last 4 years. Development of Galley`s western and eastern accumulations was being planned.

BP Exploration Operating Co. Ltd. began oil production from Schiehallion field in the U.K.`s West of Shetland. Production was 30,000 b/d from one well and was expected to peak at 154,000 b/d.

BP was developing Schiehallion and nearby Loyal field with a production, storage, and offloading ship linked to 29 subsea wells tied back to four seabed manifolds.

Burlington Resources Inc. unit Burlington Resources Irish Sea Ltd. let a $25 million subsea contract to Stolt Comex Seaway SA for development of the Dalton project in the Irish Sea.

The work included tying back the Dalton subsea wells to North Morecambe platform by 6.9-km rigid flow lines and well control umbilicals.

Processing activity

BP Chemicals Ltd.`s planned expansion projects worth a combined $850 million at its Grangemouth petrochemicals complex near Edinburgh and at a complex in Hull in northeast England.

The move was part of a plan to increase capacity in a variety of products and followed the start of work on polyethylene and polypropylene plants at Grangemouth.

New projects at Grangemouth were a 270,000 metric ton/year capacity expansion of the KG ethylene cracker, one of two in the complex; construction of a 110,000 ton/year ethanol plant; and building a combined heat and power (CHP) plant to generate up to 130 MW of electric power and 230 tons/hr of steam, mainly for onsite consumption.

The cracker expansion would take Grangemouth`s ethylene capacity to more than 1 million tons/year. It would be completed along with the CHP plant in 2000, while the ethanol unit was due to be completed in 2001.

Also, an existing ethylene pipeline from Grangemouth to Teesside would be extended 151 km to reach Hull, farther down the eastern coast of England.

At Hull, BP planned to build a 250,000 ton/year vinyl acetate monomer (VAM) plant and a 220,000 ton/year capacity ethyl acetate plant, due on stream in 2000 and 2001, respectively.

Petroplus International Inc., Rotterdam, was negotiating to buy Chevron UK Ltd.`s process units and equipment at the 115,000 b/d refinery near Milford Haven, Wales. Chevron shut down the refinery in December 1997 as part of its strategy to withdraw from the U.K. downstream oil business.

Other projects

U.K. electricity utility Eastern Group plc, Ipswich, planned to build a 215-MW combined heat and power (CHP) plant at Deeside, North Wales. The plant would supply electricity and steam to Shotton Paper Co. Construction was slated to begin in early 1999, and plant start-up was anticipated in early 2001.

El Paso Energy International Co., Houston, entered into a 50-50 partnership with Global Energy Inc., Cincinnati, to build and own a gas-fired power plant near Fife, Scotland.

The plant, being built in two phases, would burn synthesis gas produced by gasification. The first phase, which was being commissioned, involved a simple-cycle, 75-MW gas turbine. The second phase would involve the addition of a steam turbine with combined-cycle generating capacity of 120 MW. U.K. utility Powergen was to buy the electricity under a 15-year contract.

BP Energy Ltd. and European Vinyls Corp. (U.K.) Ltd. (EVC), Blackpool, U.K., formed a partnership to build a CHP plant at EVC`s polyvinyl chloride plant.

The $6.4 million plant would have capacity to generate 5 MW of electric power and 15 metric tons/hr of steam and would supply hot exhaust gases for the drying stage of the PVC process.

The plant was expected to reduce EVC`s CO2 emissions by 32,500 tons/year and to reduce power purchase costs by $800,000/year.