BP managing decline at existing profit centers
Kristen Nelson Petroleum News Editor-in-Chief
Production is not just downhill at BP’s existing exploration and production profit centers (those with declining reserves as opposed to the company’s new profit centers, which are under development and have growing reserves).
There are offsets to declining production, Tony Hayward, the company’s chief executive upstream, said at a BP strategy presentation March 29.
In Alaska, decline in existing North Slope fields is “offset by further viscous oil development,” and in the company’s North American gas business, “production decline is mitigated as we develop incremental gas reserves including tight gas in and around existing fields,” Hayward said.
New projects are coming on stream in the existing North Sea profit center, and production is expected to grow in South America as BP continues to develop the Cerro Dragon oil field in Argentina.
Without new projects at existing profit centers, production from those centers would be declining at a 5 percent rate, he said, but with new projects that decline has been cut to 3 percent.
BP also plans to increase operating efficiency from 87 percent to 89 percent over the next four years — it was improved from 86 percent to 87 percent over the last three years. And drilling performance has been improved, with a 25 percent reduction in days per 10,000 feet since 2001. That alone reduced costs by an estimated $350 million, Hayward said. Improved reservoir management In the existing profit centers, improved recovery through leading-edge technology has grown reserves, including use of 4-D seismic at the Andrew field which helped BP add some 15 million barrels of incremental reserves and at the Valhall field in Norway where 600 million barrels of oil equivalent have been produced from a field that in 1982 had estimated reserves of about 250 million boe. In 2003, Hayward said, “we installed the world’s first full-scale life-of-field seismic system to allow us to monitor the movement of fluid through the reservoir on a continuous basis.” Recoverable reserves at Valhall are now estimated at more than 1 billion boe.
At the Milne Point field in Alaska, a comprehensive injection management model for the Kuparuk reservoir optimized waterflood response and reduced natural decline from 17 percent a year to less than 10 percent, increasing recovery by some 4 percent and adding some 40 million barrels of reserves.
The company has also reduced cash costs for existing profit centers from $4.1 billion in 2002 to $3.8 billion in 2004 with the divestiture of high-cost assets and restructuring of major operating centers. Deepwater Gulf on schedule Major projects are on track at BP’s new profit centers, Hayward said. Startups in 2003 included the Atlantic LNG Train 3 in Trinidad, the Xikomba and Jasmin projects in Angola and NaKika in the Gulf of Mexico.
2004 startups include: Atlas Methanol in Trinidad, second quarter; commissioning of In Salah in Algeria under way, with mid-2004 first gas sales expected; Northwest Shelf Train 4 in Australia on track for first gas into the plant and first gas sales as spot cargoes in the third quarter; the Kizomba A floating production, storage and offshore loading facility has sailed from Korea with first oil planned for late 2004; and in the deepwater Gulf of Mexico, the Holstein spar is on the Gulf Coast and is planned for installation in mid-year with startup before the end of the year.
Major projects are scheduled to start up in 2005 and 2006: Mad Dog, Thunder Horse and Atlantis in the deepwater Gulf; Kizomba B and Dalia in Angola; Central Azeri and West Azeri in Azerbaijan, along with Baku-Tbilisi-Ceyhan pipeline; and Train 4 LNG in Trinidad. Capturing the market In gas, BP’s goal is “to move our gas resources into markets with the same ease as oil does today,” said Ralph Alexander, the BP executive in charge of gas, power and renewables.
BP’s goal is to capture liquefied natural gas markets “ahead of supply.” Alexander said BP has some 500 million cubic feet a day more in market than BP gas to supply that market. “In the short run, these markets will be supplied by BP’s arrangements with all three Middle East producers,” Alexander said. In the longer term, this gas could come from Tangguh, or from Trinidad, Angola and Egypt as gas is available from those sources.
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