CAPITAL: London
MONETARY UNIT: Pound
REFINING CAPACITY: 1,825,750 b/cd
OIL PRODUCTION: 2,620,000 b/d
OIL RESERVES: 5 billion bbl
GAS RESERVES: 26,839 bcf
The oil industry in Britain was facing the possibility that the Labor government might raise taxes in 1998.
The government was reviewing its North Sea oil taxes with an eye toward increasing them.
OIL executives met with Treasury officials in late 1997 to argue that a higher fiscal burden would lessen government tax revenue by depressing investment and contracting offshore and service industries.
They said the current tax rules were appropriate since North Sea profits were falling, development costs were rising, and more lucrative hydrocarbon basins were opening elsewhere.
The new Labor government carried out an election promise to impose a "windfall" tax on utilities privatized under the previous Conservative government. It announced changes which would raise $8.32 billion/year in taxes.
The government awarded 114 exploration blocks, mainly in frontier areas northwest of Britain, under its 17th offshore licensing round.
The blocks were grouped into 25 tranches, shared among 14 operators and a total of 22 license partners.
Fourteen were west of the Hebrides, seven were north of the Shetland Islands, and four were in the North Sea.
The government had offered a total of 275 blocks to companies, grouped into 68 tranches or license areas.
The Department of Trade and Industry said the next licensing round, the 18th, would cover mature areas in the northern, central, and southern U.K. North Sea, along with the Morecambe and Liverpool Bay areas of the Irish Sea.
Following the 18th round, there will be an annual licensing round offering acreage in a mixture of mature and semi-mature offshore provinces. A frontier licensing round would be held in the fall of 2000.
The U.K. government`s Office of Gas Supply (Ofgas) planned to open all of Britain to competition for residential natural gas service in five stages during 1998.
Two pilot projects in 1997 gave 2 million homes in southwestern and southeastern England a choice of gas suppliers. Fourteen companies had joined British Gas Trading in supplying these areas. Under the pilots, 370,000 residential customers gave their business to new suppliers.
BG plc accepted a pricing formula set by Ofgas for transportation of gas through the U.K. national grid by BG`s Transco unit, ending a long battle between BG and Ofgas.
The Monopolies and Mergers Commission recommended a 21% cut in Transco`s third party transportation charges, but Ofgas approved cuts of 25%.
Under the final deal, Ofgas will allow 50% of Transco`s income from independent gas suppliers to vary with throughput, as recommended by MMC.
Wytch Farm
BP Exploration Operating Co. Ltd. was producing Wytch Farm oil field in southern England partially through 35 extended reach wells from onshore drilling sites around Poole Harbor.
The field had two main reservoirs: onshore Bridport, developed with conventional wells; and offshore Sherwood, depleted with long reach wells.
Bridport had estimated reserves of 30 million bbl of oil, Sherwood had estimated reserves of 420 million bbl of oil, and the undeveloped Frome reservoir had estimated reserves of 4 million bbl of oil.
Offshore, the U.K. had several discoveries in 1997.
Shell U.K. Exploration & Production disclosed an oil find straddling Blocks 22/28d, 22/23b, and 22/28a, the latter operated by Phillips Petroleum Co. U.K. Ltd.
Shell Expro said the find upgrades the reserves potential of the area following the 22/23b-5 well drilled by Phillips. The earlier find, dubbed Kate, flowed on test from two intervals at a combined rate of 11,500 b/d of oil and 22 MMcfd of gas.
Amoco (U.K.) Exploration Co. had a discovery on its Appleton Beta prospect on Block 30/11b. The well flowed 6,329 b/d of oil and 13.4 MMcfd of gas. It was near Amoco`s Halley find.
BG Exploration & Production Ltd. had a discovery on Block 13/24b which flowed 32° gravity oil at a maximum 2,600 b/d on a 40/64 in. choke. License interests were operator BG 50%, Amerada Hess Ltd. 30%, and Rigel Petroleum (NI) Ltd. 20%.
West of Shetlands
BP was delayed again in producing oil from Block 204/24a Foinaven field.
It had to retrieve a subsea manifold and five christmas trees from the seabed after it determined valve seals have been damaged and would leak oil if used.
Four out of 48 valve stems on one of two subsea manifolds leaked, plus three trees from one drilling center and two from the other.
In 1996 BP had to retrieve the first subsea manifold it installed after cracks appeared on hubs during leak testing.
Clair field on Block 206/8 was moving toward development. BP found the field in 1977 in 460 ft of water. Reserves in the complex reservoir were 100-300 million bbl.
A feasibility study showed a floating production ship was the most economic development plan for Clair. Early oil exports would be by shuttle tanker, as with BP`s Foinaven and Schiehallion developments in deeper water nearby.
Meanwhile, three operators were evaluating systems for collection, transportation, and sale of gas from potential field developments west of the Shetland Islands.
Called the Aurora project, the study was funded by Conoco (U.K.) Ltd., Texaco Britain Ltd., and Total Oil Marine plc.
The partners, which have exploration interests in the West of Shetland play, examined options for subsea pipelines, gas landfall sites, and delivery of gas to customers. Texaco had a gas discovery in the area, Victory, with estimated reserves of 300 bcf.
BP had a discovery on Block 204/19 in the West of Shetland. Flows were not announced. The find was named Suilven.
Central Graben area
Texaco brought Erskine gas/condensate field on flow with a $465 million development using an unmanned platform. Production goes to the Lomond platform 30 km away for processing and export.
Development drilling was to continue until six production wells had been completed in late 1998 and production peaks at 120 MMcfd of gas and 29,600 b/d of condensate.
Erskine had reserves of 330 bcf of gas and 75 million bbl of condensate. The reservoir is at 15,000 ft in Jurassic sand.
Texaco said Erskine, on Blocks 23/26b and 23/26a, was the U.K. North Sea`s first high-pressure, high-temperature gas field. Operator Texaco and BP developed the field in a 50-50 partnership.
The largest high-pressure/high-temperature project was the linked development of Elgin and Franklin, operated by Elf Exploration U.K. plc, and Shearwater, operated by Shell U.K. Exploration & Production.
Elf let a $640 million contract for a platform for Elgin/Franklin. Total development of the fields was expected to cost $2.4 billion, with production start-up due in 2000.
Elgin had estimated reserves of 889 bcf of gas and 244 million bbl of condensate, while Franklin reserves were estimated at 821 bcf of gas and 123 million bbl of condensate.
Shell Expro planned to develop Shearwater under a $1.15 billion program, with first production slated for mid-2000. Shearwater had estimated reserves of 844 bcf of gas and 159 million bbl of condensate and natural gas liquids.
Development will involve two bridge-linked, four-legged steel platforms in 90 m of water. Production capacity will be 410 MMcfd of gas and 90,000 b/d of liquids.
Liquids from the three fields will join the Forties network via a 24-in. spur line. Gas will go to shore through a new Shearwater and Elgin Area Line (SEAL) to the Bacton terminal.
The 463-km, 34-in SEAL pipeline will be the longest on the U.K. continental shelf. Capacity will be 922 MMcfd. SEAL will cost $640 million. Construction was due to begin in 1998.
Viking
Conoco was developing four gas accumulations in Viking field as satellites of existing platforms.
The four accumulations were F and Fs, which were part of Viking A field, and Gn and Wx, which were part of Viking E field. They have combined reserves of 500 bcf of gas.
Development of the four satellites will be known as Viking Phoenix project. Two unmanned platforms will be installed, one to deplete F and Fs and one to deplete Wx and Gn.
Output from the two new platforms was expected to total 300 MMcfd at peak. Field life for the four satellites was estimated at 15 years.
Produced gas will be sent by pipeline to Viking B complex for processing. From Viking B, gas will go to the Viking A riser platform for export to the Theddlethorpe terminal, Lincolnshire.
F and Fs finds lie on Block 49/12a in 30 m of water. They were discovered in 1973 and 1976, respectively. Wx and Gn finds lie on Block 49/17 in 30 m of water and were discovered in 1969 and 1976, respectively.
The F/Fs platform will be connected to Viking BD platform by a 15-km, 16-in. pipeline. A subsea tee will connect the Wx/Gn platform to this pipeline.
Six production wells will be used, including four new wells to be drilled ahead of first gas, and two appraisal wells, 49/12a-9 and 49/17-12, will be converted to producers.
Viking A field began production in 1972, and since then through 1997 Viking A and B fields had produced more than 2.8 tcf of gas.
The Viking A riser platform was the only remaining structure in Viking A field.
Renee and Rubie
Phillips Petroleum Co. U.K. Ltd. planned to develop two small oil discoveries on Blocks 15/27 and 15/28, one of which was drilled 21 years ago.
When the larger of the two finds, Block 15/27 Renee, was tested in 1976, it flowed 8,000 b/d of oil. But there was no existing infrastructure nearby.
In 1985, Rubie was found on Block 15/28. Phillips bought into the block in 1991 through an asset trade. Meanwhile, Amerada Hess developed the nearest find to Renee/Rubie, about 20 km away on Block 15/21.
Amerada brought Ivanhoe and Rob Roy fields into production in 1989, with two subsea wellhead clusters tied back to a production semisubmersible.
OIL exports from the semi went through a 14-in. pipeline to Claymore platform and into the Flotta network. Gas was sent via an 8-in. pipeline to the Tartan platform and from there to shore at St. Fergus.
While Amerada depleted Ivanhoe, Rob Roy, and later the small Hamish fields, there had been no spare capacity on the semi.
Decline of Amerada`s fields made room for Renee/Rubie.
Phillips had considered stand-alone development of Renee and Rubie using a floater but opted instead for a subsea tie-in to the vessel. Phillips was working towards first oil in October 1998.
Sedgwick
Enterprise Oil plc and Marathon Oil U.K. Ltd. began producing oil from Sedgwick and West Brae fields, developed jointly but operated independently by Enterprise and Marathon, respectively.
The fields lie on Blocks 16/16a and 16/7a. A single subsea well in Sedgwick was tied back to the West Brae subsea manifold, which exports oil and gas to Marathon`s Brae A platform for processing and export to shore.
Peak output from the fields was expected to be 27,000 b/d of oil. The fields have combined reserves of 40 million bbl of oil and were developed for $160 million.
Shell Expro brought on stream Kingfisher oil and gas field. Peak production will be 37,000 b/d of condensate and 160 MMcfd of wet gas. Kingfisher, a satellite of the existing Brae B platform, will deliver condensate into the Forties blend pipeline stream.
Marathon Oil U.K. Ltd. found oil on Block 16/6b with a well, drilled to 7,150 ft total measured depth, that cut 107 ft of net oil pay in Tertiary sands.
The well was drilled about 10 km northwest of Marathon`s West Brae field but suspended without testing.
Brent return
Shell Expro, operating joint venture of Shell U.K. Ltd. and Esso Exploration & Production U.K. Ltd., resumed production from Brent D platform.
Delta platform was the last of three platforms in the field to be shut down for extensive upgrading under a $2 billion redevelopment program begun in 1993.
Redevelopment involved replacing much of the process equipment on three platforms to operate at lower gas pressures and renovating Brent A platform to act as a gas gathering platform.
Shell/Esso wanted to reduce pressure in the Brent reservoir to help in exploiting remaining oil pockets and transforming the field into one of Europe`s largest gas producers.
Brent D output was expected to build gradually and plateau at about 50,000 b/d of oil and 220 MMcfd of gas. With Delta back on line, Brent was expected to produce an average 160,000 b/d of oil and more than 600 MMcfd of gas.
Armada
BG Exploration & Production Ltd. began gas production from Armada field on Block 22/5b.
Development of Armada cost $690 million. The original budget was $860 million, but this was cut through incentive deals with contractors.
The operating cost for Armada was also expected to be among the lowest in the North Sea at less than $3/bbl, largely due to the small platform crew of only 29 persons.
Armada development involves one steel platform depleting three fields-Fleming, Drake, and Hawkins-with combined reserves estimated at 1.2 tcf of gas and 70 million bbl of condensate.
Up to 450 MMcfd of gas will be produced and exported via Everest field riser platform through the Central Area Transmission System pipeline to Teesside, U.K.
Condensate and gas liquids will be separated on Armada platform and exported at rates of as much as 26,000 b/d via Everest and the Forties oil pipeline system to Cruden Bay, Scotland.
Armada interests were operator BG 45.27%, Amoco (U.K.) Exploration Co. 18.2%, Fina Exploration Ltd. 12.53%, Phillips 11.45%, Yorkshire Electricity Ltd. 6.97%, and Agip (U.K.) Ltd. 5.58%.
Other developments
Phillips Petroleum United Kingdom Ltd. and partners began producing the Judy/Joanne project in 1997 at a 40,000 b/d average. Produced gas was reinjected for production and delivery to Enron Europe Ltd. beginning in September 1999.
Conoco (U.K.) said an appraisal well for its Buckland discovery on Block 9/18a flowed 4,265 b/d of oil and 4.4 MMcfd of gas from Beryl sandstones through a 40/64-in. choke.
Total Oil Marine plc increased reserve estimates in Alwyn North field after testing two wells. An appraisal well flowed 18 MMcfd of gas and 1,800 b/d of condensate, proving a further extension of the reservoir.
The 3/9a-11 exploratory well found a separate structure to the south and flowed 18 MMcfd of gas and 1,000 b/d of condensate.
Reserves were then estimated at 1 billion bbl of oil equivalent, of which 250,000 boe had been produced. Original reserves were pegged at 200 million bbl of liquids and 950 bcf of gas when the field came on stream in 1987.
Enterprise Oil plc, London, boosted its reserves at Nelson field by 25 million bbl of oil with a delineation well on the western edge.
The Block 22/11 field went on flow in early 1994. Original reserves were estimated at 480 million bbl of oil and 85 bcf of gas.
Enterprise successfully removed a World War II bomb found alongside its Nelson platform.
Amerada, Shell, and Texaco will use a floating production, storage, and offloading ship for development of Bittern and Guillemot West fields.
Bittern straddles Blocks 29/1a and 29/1b, operated by Shell and Amerada, respectively. Guillemot West crosses five blocks: Texaco`s Blocks 21/24 and 21/29a and Shell`s 21/29b, 21/25, and 21/30.
The companies have not disclosed reserves estimates. Oil from Bittern and Guillemot West will be moved by shuttle tankers. Gas will move through a pipeline to the Fulmar trunkline.
More fields
Chevron U.K. Ltd. will boost fluids-handling capacity at its Alba platform to 390,000 b/d from 240,000 b/d by installing three new modules weighing a total of 1,700 metric tons. A water injection well will be connected by a new 6-km pipeline to the platform. Chevron upgraded Alba topsides to hike output capacity to 100,000 b/d from 75,000 b/d.
Talisman Energy (U.K.) Ltd. will develop its Ross discovery on Blocks 13/28a and 13/29a. The field had estimated reserves of 66 million bbl of oil and 20 bcf of gas.
It will be developed with a floating production vessel and oil will be moved by tanker. Gas will go via pipeline to be tied in to the Frigg trunkline. First production was expected in third quarter 1998.
Ten development wells were planned, with combined oil production expected to start at about 40,000 b/d.
Shell U.K. Exploration & Production began production from Block 21/30 Gannet F field, which had estimated reserves of 19 million bbl of oil and was expected to produce as much as 12,000 b/d of oil.
It was developed in conjunction with the Gannet E structure, a subsea satellite tie-back to the Gannet A platform 11 km away. Shell Expro developed the fields for $128 million.
ARCO British Ltd. developed the Bladon discovery on Block 16/21d as a single well tied back to its Blenheim field 5.3 km to the south. Bladon had estimated reserves of 4.5 million bbl of oil.
Blenheim was developed with a floating production system. Bladon production will boost Petrojarl`s throughput to 18,000 b/d. Blenheim produces through three wells.
Production fell from a peak of 34,000 b/d, but addition of Bladon output will extend Blenheim field life enough to yield a further 1.5 million bbl of oil.
Offshore projects
Elf Exploration U.K. plc started oil production from Iona field on Block 15/17. First oil flowed at a rate of 4,400 b/d.
Iona, formerly known as South Piper, was developed with extended-reach wells drilled from Elf`s nearby Saltire A platform.
Conoco and Chevron planned to bring the Britannia gas field on flow in 1998.
Britannia had estimated reserves of 3 tcf of gas and 145 million bbl of condensate and was expected to produce 740 MMcfd of gas and 50,000 b/d of condensate at peak.
A 27-in. gas pipeline was laid 186 km to St. Fergus, north of Aberdeen, and a 44-km, 14-in. line was laid to take condensate to the Forties pipeline system.
Texaco will use a production semisubmersible to develop Galley field on Block 15/23a. Cost was estimated at $224 million.
Two development wells were drilled to produce 35,000 b/d of oil and 50 MMcfd of gas at peak. Production will go to Texaco`s Tartan platform on nearby Block 15/16a.
Galley reserves were estimated at 28 million bbl of oil and 40 bcf of gas. Early production will be from the field`s northern and southern accumulations. Texaco was planning to deplete eastern and western accumulations in a second phase of development.
Wintershall (U.K.) Ltd. began gas production from two-well Windermere field on Block 49/9b. The field was developed with an unmanned tripod wellhead platform tied back to nearby Markham ST1 satellite platform.
North Sea platforms
Kerr-McGee Oil (U.K.) plc planned to develop its Janice discovery in 300 ft of water on Block 30/17. Janice field had estimated reserves of 70 million bbl of oil.
Development will require tying back subsea horizontal production and injection wells to a floating production unit. The floater will be a converted semisubmersible accommodation unit.
First production was due in third quarter 1998. Output was expected to peak at 55,000 b/d. Kerr-McGee said the floater had excess capacity, so it can act as a hub for future developments in the area.
Lasmo planned to develop Larch field on Block 16/12a as a subsea satellite of nearby Brae A platform, operated by Marathon Oil U.K. Ltd. First oil was slated for early 1998 from two wells.
Larch had estimated reserves of 10 million bbl of oil and 10 bcf of gas. Lasmo said the nearby North Larch and Maple prospects could be developed through Larch, while development of the nearby Pine and Elm finds will depend on the success of the Larch project.
Amerada Hess Ltd. began production from Block 21/11 Dauntless field and started up Block 21/16 Durward, developed jointly with a production, storage, and offloading ship.
The fields were 7 km apart and were developed with subsea production units tied back to the production ship, which was moored between the two fields.
Combined initial production was 25,000 b/d. Estimated reserves for Durward and Dauntless fields were 30 million bbl and 13 million bbl of oil, respectively.
Conoco (U.K.) Ltd. began oil production from MacCulloch field on Block 15/24 with an floating production ship.
The field had reserves of 58 million bbl of oil. Production was expected to peak at 60,000 b/d of oil and 12 MMcfd of associated gas.
OIL from MacCulloch was metered on the ship and transported by pipeline to Piper B platform, 30 km northwest, operated by Elf. Associated gas also was exported to Piper B by pipeline.
Mobil North Sea Ltd. announced production of 8,000 b/d of oil and 4 MMcfd of gas from Katrine field on Block 9/13a, under an extended well test.
Production was achieved by completion of an appraisal well drilled from nearby Nevis field, itself a subsea satellite of Mobil`s Beryl Alpha platform.
Enterprise Oil plc will begin producing Pierce field in the central North Sea in mid-1998 at 20,000 b/d. The field lies on Blocks 23/22a and 23/27. Proven plus probable reserves were 84 million bbl of oil and 202 bcf of gas.
Transportation
BG plc will separate its gas storage business from its Transco gas transmission business for U.K. customers. New business unit BG Storage carries out all BG`s peak and seasonal gas storage operations.
The unit was based in Solihull, U.K., and operates seven sites: liquefied natural gas storage facilities near Bristol, Strathclyde, Rochester, Manchester, and Mid-Glamorgan; a salt cavern at Hornsea; and offshore Rough gas field.
Shell U.K. Ltd. bought a 50% share in U.K. gas marketing joint venture Quadrant Gas Ltd. from partner Esso U.K. plc.
Quadrant, the first independent marketer to deliver natural gas to industrial and commercial users in U.K.`s liberalized gas market, holds a 6% share of U.K.`s commercial and industrial gas market.
Mobil North Sea Ltd. was building a $40 million compression plant at U.K.`s Bacton gas terminal, operated by Phillips Petroleum Co. U.K. Ltd.
The plant will handle gas from Mobil`s Lancelot area fields, centered on southern Block 48/17. The plant was due to go into operation on Oct. 1, 1998.
Lasmo plc planned to remove the 8-in. Staffa field pipeline, used to take oil 9 km to Ninian southern platform from Staffa Block 3/8b subsea satellite.
Staffa was shut in in 1994 when the pipeline clogged with hydrates.
Processing activity
British Petroleum Co. plc planned to expand its Grangemouth refinery and petrochemical complex near Edinburgh.
The refinery had crude distillation capacity of 205,000 b/d. The petrochemical plant had capacity to produce 600,000 tons/year of ethylene and 450,000 tons/year of polyethylene.
BP Chemicals intends to make Grangemouth a world-scale petrochemical complex, with capacity to produce 1.2 million tons/year of ethylene after a series of upgrades to the twin cracker plant.
By then, polymer production capacity is expected to amount to 1 million tons/year through addition of polyethylene capacity and construction of a new polypropylene plant.
Shell U.K. Ltd. was negotiating with Chevron Corp. to buy 450 service stations and other interests operated by Chevron subsidiary Gulf Oil (Great Britain) Ltd. Shell had 1,600 U.K. stations.
The deal would make Shell the U.K.`s largest marketer, ahead of Esso Petroleum Co. Ltd.
Chevron decided to sell its Gulf refining and marketing operation after a planned merger between the Gulf unit and Elf Oil U.K. Ltd. fell apart.
Chevron was closing Gulf`s 115,000 b/d refinery at Milford Haven, South Wales. It sold its 50% share in Pembroke Cracking Co. to joint venture partner Texaco Ltd.
U.K. Health and Safety Executive reported on a 1994 explosion at Pembroke Cracking Co.`s refinery at Milford Haven, Wales.
Lightning struck the refinery, causing a fire that forced shutdown of all units except the fluid catalytic cracker.
HSE said a combination of management, equipment, and control system failures led to the release of 20 metric tons of hydrocarbons from the cracker flare`s knockout drum.
The Environment Agency began criminal proceedings against Milford Haven Port Authority and the harbor master as the result of the spill of 70,000 metric tons of oil from the tanker Sea Empress in 1996. The tanker ran aground three times in a bungled rescue attempt.
Other energy
BP Energy Ltd. won a $46 million contract from food producer H.J. Heinz Ltd. to design, build, and operate a combined heat and power plant at its Harlesden, U.K., plant.
The contract calls for a 4.8-MW capacity plant to provide Heinz with electricity and steam for 11 years. The project was expected to reduce the site`s energy costs by almost $800,000/year.
U.K. electricity generator Scottish Power plc, Glasgow, and electricity supplier Seaboard plc plan to build a 500-mw, combined-cycle gas turbine power plant at Shoreham Harbor on Britain`s south coast.
The $320 million plant will be owned 50-50. It will be built on the site of a former coal-fired power plant.
U.K. Department of Trade and Industry approved Saltend Cogeneration Co.`s plan for a gas-fired combined heat and power plant at the Saltend, Hull, petrochemical complex of BP Chemicals Ltd.
The 1,200-mw plant will provide steam and electricity for the chemical plant, with excess electricity delivered to the national grid.
Scotland`s Dundee Energy Recycling Ltd. planned to build a $68 million waste-to-energy plant at Baldovie, Dundee, the first in the U.K.
It will burn 120,000 metric tons/year of waste to generate as much as 8.3 mw of electric power for delivery to the national grid.
U.K.`s Department of Trade and Industry approved plans by Powergen plc, London, to build a 500-mw gas-fired power plant alongside an existing 1,920-mw coal-fired plant at Cottam, Nottinghamshire.
The new unit will be operated as a development and test center. Powergen and partner Siemens plc, Bracknell, U.K., will work on a new 500-mw nominal capacity industrial gas turbine, designed for high thermal efficiency with low nitrogen oxides emissions.
