CAPITAL: LONDON
MONETARY UNIT: POUND
REFINING CAPACITY: 1,771,040 B/CD
OIL PRODUCTION: 2,536,900 B/D
OIL RESERVES: 5 BILLION BBL
GAS RESERVES: 26.8 TCF
With few large field developments on the horizon in the UK North Sea, the government in 2000 was seeking methods to encourage production of smaller oil and gas deposits.
The UK North Sea government-industry competitiveness body Logic chose the Nisus consortium for development design of BP's marginal Wood field, the first discovery to advance under the "satellite accelerator" program.
The Nisus consortium consisted of Global Marine Integrated Services Reservoir Management Ltd., Stolt Offshore Ltd., and Wood Group Engineering Ltd.
BP did not develop Wood field, an oil and gas discovery, because it was "subeconomic under current development scenarios." It had estimated recoverable reserves of 10 million boe. It was on Block 22/18-6 between Arbroath and Marnock fields in the central North Sea.
Wood was the first of five undeveloped UK North Sea discoveries earmarked in 2000 to be brought to market under the Logic scheme. The other four were Solan, Strathmore, Kestrel, and Kessog.
Total reserves for the five fields (found by BP, Amerada Hess Ltd., and Shell UK Exploration & Production) were estimated at more than 200 million boe and could lead, according to Logic, to "as much as £500 million of new development investment."
Logic said plans were being prepared for a second set of satellite accelerator projects, involving a "wider group of operators."
The UK launched the satellite accelerator initiative with the goal of developing 300 North Sea discoveries undeveloped because of marginal reserves, technological challenges, or poor economics.
The Logic (Leading Oil & Gas Industry Competitiveness) initiative was launched in September 1999 by the UK Department of Trade & Industry.
The UK Energy Ministry said it would accept applications from oil companies to develop two blocks containing gas discoveries in the eastern Irish Sea.
Kerr McGee North Sea UK Ltd. previously held Blocks 113/28 and 113/29 under a petroleum production license but relinquished them in 1999.
The government-industry task force Pilot listed the blocks in its Undiscovered Discoveries initiative.
Pilot established the Undeveloped Discoveries Work Group in March 2000 to "identify and categorize undeveloped discoveries in the UKCS" while "identifying potential clusters and issues hindering development (and) working towards framing three collaborative projects for action in 2000/2001."
West of Shetlands
The government approved four major North Sea field development projects by BP, Kerr-McGee Corp., and Ranger Oil Ltd. that would translate into an investment of just under £1 billion.
The projects included a £320 million gas pipeline linking the deepwater West of Shetland region with BP's northern North Sea Magnus field installation and a plan to develop Kerr-McGee's West of Shetland Leadon field via a floating production, storage, and offloading vessel (FPSO).
The government also approved BP's planned £210 million investment in its Foinaven field, and another by Ranger Oil of £75 million to develop Kyle field.
BP's Magnus gas pipeline project, which would provide the first transportation infrastructure from the West of Shetlands region, built on plans that BP studied for over a year.
It would transport gas reinjected into its Foinaven, Schiehallion, and Loyal deepwater fields in the West of Shetlands area to the Sullom Voe terminal, where the gas would displace liquid fuels in power generation. Remaining gas would be enriched with natural gas liquids at the terminal before being transported to Magnus, where the NGL-gas mixture would be injected to boost production and reserves.
BP expected the $500 million project would increase Magnus's oil reserves 50 million bbl, extend its field life "several years beyond 2015," and substantially curb CO2 emissions by reducing flaring.
Magnus, in 186 m of water, came on stream in 1984 and was flowing at 70,000 b/d. It was the most northerly field in the UK sector.
Kerr-McGee planned to develop Leadon, Birse, and Glassel fields with subsea horizontal wells tied back to an FPSO. Development costs were $600-700 million.
Kerr-McGee expected first flow from the Leadon area fields in early 2002, with peak production of 50,000 b/d by the end of the year.
The second BP project, at Foinaven field, would boost production by 85 million bbl through additional drilling. BP was producing 200,000 b/d from Foinaven and Schiehallion.
Howe, Halley, Beauly
Enterprise Oil PLC planned to develop its 30-55 million bbl Howe field.
The Howe discovery was in 90 m of water in the Central graben area of the North Sea, 12 km from Enterprise's Nelson field.
Well 22/12a-8 encountered 161 ft of Upper Jurassic Fulmar reservoir section, the uppermost 83 ft being oil-bearing.
Enterprise owned 60% of Howe, with Intrepid Energy North Sea Ltd. and OMV UK Ltd. each holding 20%.
Talisman Energy Inc. said the government approved its plans to develop Halley oil field on Block 30/12 in the central North Sea.
It planned two extended-reach wells from the Fulmar platform. Talisman had a 12.71% interest in Fulmar field, operated by Royal Dutch/Shell Group.
Initial production from Halley was expected to be 18,000 b/d starting in mid-2001.
Talisman said the field holds 11 MMboe, and development costs would be below $7/boe. The expected field life was 5 years.
Talisman had 60% of Halley and Amerada Hess Ltd. 40%.
Talisman also began production of 12,000 b/d from Beauly field on Block 16/21. Beauly, with reserves of 3 million bbl, was developed with a single horizontal well tied back 5 km to the Balmoral floating production vessel. Talisman was operator with 60%, and Summit North Sea Oil Ltd. had 40%.
Kappa, Cook
Conoco Inc. said two appraisals confirmed discoveries in the central North Sea that could yield estimated gross reserves of more than 100 million boe.
Conoco was evaluating the fields, one oil and the other gas, and planned to begin production in late 2003 or early 2004.
The Kappa oil discovery, which also had a small gas cap, was in Block 15/29b and extended into Block 21/4a-North. It was 16 miles from the Britannia production platform and 13 miles from the Chevron Corp.-operated Alba oil field. Conoco held 23% in Alba.
Kappa was discovered late in 1999 and confirmed by the 15/29b-13 well, which encountered 135 ft of hydrocarbons. A 25-ft interval of reservoir was perforated and flowed 1,400 b/d of oil through a 24/64-in. choke.
Conoco said each Kappa production well could produce up to 20,000 b/d.
The gas discovery, made in 1985 in Block 21/3a, was 26 miles from Britannia and 23 miles from Alba. It was confirmed by the 21/3a-7, which encountered a 120-ft gas column. A drillstem test of an 87-ft interval flowed at a rate of 20 MMcfd through a 44/64-in. choke. Once developed, the field would peak at 100-200 MMcfd.
Conoco said the development would add to its holdings around the Britannia gas-condensate field, the largest in the UK, in which the company had a 51% interest.
Conoco had 80% of 15/29b and 86% of 21/4a-North. It had 75% of Block 21/3a and was operator in both. Chevron UK Ltd. was a partner in both licenses.
Enterprise Oil PLC put Cook oil field on stream at 10,000 b/d. Output was expected to reach 20,000 b/d in 2001.
Cook, on UK Block 21/20a, had estimated reserves of 20 million boe of oil and 15 bcf of gas. The field was discovered in 1983, and development approval for the £59 million project was granted in May 1999.
Production was tied back to the Anasuria FPSO. Oil export would be via shuttle tanker and gas export via the Fulmar pipeline to St. Fergus.
Enterprise was operator with 25.77%. Amerada Hess Ltd. had 28.46%, British Borneo North Sea Ltd. 20%, Shell UK Ltd. 12.885%, and Esso Exploration & Production UK Ltd. 12.885%.
Blake, Captain
Talisman awarded contracts for the development of Blake field and the linked tie-in to the Bluewater Group's Bleo Holm FPSO, which was producing nearby Ross field.
The contract, valued at £15-20 million, covered engineering, hookup, installation and commissioning of a water injection module, a produced water-cooling medium module, and a compression package, as well as upgrades to the existing process separators and other modifications to the Bleo Holm.
Plans were to move the Bleo Holm from Ross field, modify it, and return it to resume production from Ross and bring Blake onstream by late 2001. Blake reserves were estimated at 50-75 million bbl.
Texaco North Sea UK Co. and the Korea Captain Co. Ltd. began production from the second phase (Area B) of their Captain field development in Block 13/22a.
The $500 million expansion project would bring production from 60,000 b/d to 85,000 b/d during 2001.
Area B was developed subsea with a single unitized 18-slot manifold connected via pipelines to a processing platform bridge-linked to the existing Captain platform. The platform consisted of a 4,000-tonne jacket, 5,500-tonne topside, and 75-m bridge.
Captain field, 90 miles northeast of Aberdeen, came on stream in March 1997. Texaco had 85% and Korea Captain 15%.
Brigantine, Skene, Elgin
The UK approved development for Shell Expro's Brigantine gas fields in the southern North Sea.
Shell planned to produce Brigantine, a three-field cluster estimated to hold 280 bcf of gas, through a pair of its low-cost Trident design platforms at a cost of £100 million.
The oil company expected production rates of 130 MMcfd from Brigantine A, B, and C fields via four wells. Produced gas would be transported via a 19-km pipeline to the nearby Corvette platform and then on through existing infrastructure to the Shell-ExxonMobil Corp. natural gas terminal at Bacton.
Shell's choice of the Trident platform concept for Brigantine was a lightweight (500 tonne) normally unmanned installation that could be installed with a drilling rig. Designed in-house for marginal fields, the Trident platform was first used on Shell's southern North Sea Skiff field.
ExxonMobil Corp. planned a $400 million development of Skene field.
Mobil North Sea Ltd. (MNSL), would operate Skene, a gas-condensate field on Block 9/19 in 380 ft of water. Skene was expected to produce up to 180 MMcfd plus 25,000 b/d of associated liquids when production began in early 2002. Reserves were estimated at 95 million boe.
The field would be developed with a subsea manifold tied back by bundled pipeline to MNSL's Beryl Alpha platform 9 miles away. Gas would be exported from Beryl through the Scottish Area Gas Evacuation pipeline to the Mobil gas processing plant at St. Fergus. The oil and condensate would be combined with Beryl crude and exported by tanker.
Mobil North Sea held 38.22% of Skene, Kerr-McGee Corp. 33.33%, Enterprise 15.89%, Amerada Hess 9.07%, and OMV (UK) Ltd. 3.49%.
TotalFinaElf SA installed the production-utilities-quarters platform for its Elgin-Franklin production development. The platform was installed at Elgin field in the Central Graben area.
Elgin and Franklin fields had complex, high-temperature (190° C.), high-pressure (1,100 bars) reservoirs. TotalFinaElf would produce gas condensate. Reserves were 800 million boe.
Deals
Venture Production Co. Ltd. said its production would rise 14,000 b/d after it acquired TotalFinaElf Exploration PLC's interests in eight fields in the central and southern North Sea.
The fields were Tiffany, Toni, Thelma, Southeast Thelma, and Mallard oil fields, and Audrey, Ann, and Alison gas fields. The assets were on Blocks 16/13, 16/17, 21/19, 49/6, and 49/11.
Consort Resources Ltd. agreed to buy interests in several North Sea fields from TXU Corp. for £138 million.
The interests included 64.2% in and operatorship of Johnston gas field, 14.75% of Ravenspurn North gas field, 11.24% of Welland field, 4.83% of Schooner field, and 30% of the Eagles/ETS pipeline system.
Marathon Sakhalin Ltd. and Shell Sakhalin Holdings BV completed their swap of Marathon's 37.5% interest in Sakhalin Energy Investment Co. Ltd., which operated the Sakhalin project off Russia, to Shell in exchange for Shell's 28% interest in the BP-operated Foinaven field in the West of Shetlands area.
Included were Shell UK's interests in discoveries and prospects on license areas adjacent to Foinaven.
Conoco acquired the assets of Saga UK Ltd. from Norsk Hydro AS for $540 million. The portfolio included producing fields Britannia, Alba, and Gryphon and several exploration licenses that Norsk Hydro acquired through its purchase of Saga Petroleum AS.
Conoco's oil production was expected to increase 10% and its gas flow 30%.
Gas prices
Continental European natural gas prices were indirectly responsible for a UK price spike in the summer of 2000, said a report for a government-industry task force.
The study, by energy consultants ILEX PLC, said UK gas market dynamics had changed since the opening of the UK-continental Interconnector gas pipeline in October 1998.
It said continental gas prices had become a major influence on UK gas prices. "When the oil price rises or falls, continental gas prices follow, usually with a time lag of around 6-9 months. This then affects gas prices in the UK as a result of the link to continental market through the Interconnector.
"This is not just a UK issue. Higher oil prices have fed through to increased gas prices across all of the European and North American gas markets."
ILEX said that because supplies from Norway, Holland, and the former Soviet Union were indexed to the oil price, which rose in 2000 to over $30/bbl, gas contract prices in Europe shot up. That made the UK a cheaper source of gas, resulting in a 20% jump in the volume of gas being traded to Europe both through long-term contracts and on the developing spot market at Zeebrugge, Belgium.
It said the UK supply-demand position was tightened by export deals, and the price of the exports became the marker for the UK spot market. That was despite the fact the overall percentage increase in gas supply contract prices to industrial and commercial consumers was generally lower than those seen in the spot market.
Potential
Wood Mackenzie Consultants Ltd. said despite the maturation of the UK Continental Shelf (UKCS), there remained substantial reserves to be developed.
It said reserves totaled 7.2 billion boe, excluding analysis of the export routes in the Southern Gas basin.
However, certain fields holding the reserves were not likely to be commercially viable in the medium term, the analyst said. This was due to the fields' location relative to existing infrastructure or their technical complexity, or both.
"Indeed, some discoveries, such as gas finds to the west of Shetlands, are currently considered to be 'stranded reserves' as they are unlikely to be developed until gas pipeline infrastructure is emplaced in the region, which is thought unlikely in the near term."
Wood Mackenzie also said that infrastructure in the UKCS had been instrumental in economic development. "Its continued upkeep remains key to the level of development activity and, indeed, maintenance of production levels in the future."
About half of the UKCS pipeline network included in its analysis, said Wood Mackenzie, was expected to operate at less than 50% of capacity through 2000. "In total, some 46.5% of oil pipeline capacity and 47.1% of gas pipeline capacity is expected to remain unutilized through 2000.
"Indeed, under current commercial field development plans, many of the pipelines are expected to see additional declines in throughput volumes in the medium term, and this may marginalize their existence going forward. Consequently, it is the commercialization of the undeveloped reserve base of the UKCS that would ultimately decide the fate of these systems," Wood Mackenzie said.
In addition to this factor, the majority of the UK infrastructure was operated by a relatively small group of companies, the analyst said. "The pipeline systems outside of the SGB are currently operated by just 10 companies, of which nearly 60% are operated by BP Amoco PLC, Royal Dutch/Shell, and TotalFinaElf SA."
Wood Mackenzie said 52 companies held equity in the 3.1 billion boe of potentially viable undeveloped reserves within 50 km of existing UK pipeline infrastructure.
"However, around 50% of these reserves (1.5 billion boe) are held by just six companies." This group of six also owns "substantial interests" in most of the pipelines offshore, the analyst noted.
In order to better enable upstream companies to access potential undeveloped reserves from the UKCS, Wood Mackenzie suggested industry forge a path incorporating more mergers, acquisitions, joint ventures, and alliances; advances in technology; and better efforts at self-regulation.
