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BP offers “attractive terms” on Slugger unit, needs one more partner to drill exploration well State exploration plan calls for a well drilled, completed, suspended or abandoned by May 15 or BP and partners face loss of unit, leases and fine By Kay Cashman PNA Publisher
Time is running out for the eastern North Slope’s Slugger unit. The exploration plan approved by the state for the 79,508 acre unit says that operator BP Exploration (Alaska) Inc. must drill a well at Slugger this winter — specifically, “must drill through the Kemik interval and complete, suspend or abandon Slugger No. 1 well by May 15, 2003” — or pay a $430,000 penalty. BP also faces termination of 11 of the unit’s 14 leases, which will be “beyond their primary terms” on May 15, Carol Lee, petroleum land manager for the state Division of Oil and Gas, told PNA Sept. 9. (See adjacent lease chart.)
BP spokesman Ronnie Chappell says BP is short one partner to help fund a Slugger exploration well. He said his company is offering “very attractive terms” for a working interest in the unit, which BP estimates holds some 280 million barrels of oil.
“BP’s future exploration focus is on acreage close to existing infrastructure. While Slugger is an interesting prospect, it does not fit this strategy,” Chappell said, referring to BP’s decision last year to close its frontier exploration office in Alaska and to concentrate on infield exploration where the company has had its most success.
At the annual Meet Alaska conference on Jan. 25, BP Exploration (Alaska) President Steve Marshall said his company had had a number of exploration disappointments in Alaska, including lower than anticipated production from its only eastern North Slope producing unit, Badami, 35 miles east of Prudhoe Bay.
Badami was expected to hold 120 million barrels of recoverable oil and produce approximately 35,000 barrels per day at its peak. Instead, the unit is producing in the range of 2,000 barrels a day.
Anadarko backed out But Chappell said that “BP wants to stimulate activity on its (Slugger) leases” and has “worked extensively to secure third-party funding” for the well.
The northern border of the Slugger unit is just 12 miles from Badami’s processing facilities, which BP has said could be used to process and ship Slugger crude to Endicott, 26 miles to the west, and then to the trans-Alaska oil pipeline. (See story this issue about the Badami pipeline tariff.)
The Slugger No. 1 will be the first well drilled in the unit, although BP has conducted a complete reprocessing of the W. Thomson 3-D Seismic Survey which encompassed the Slugger unit.
BP (42 percent) and the other two leaseholders in Slugger, Chevron USA Inc. (33 percent) and Phillips Alaska Inc. (25 percent), have already farmed out part of their working interest in the unit to independents Forest Oil Corp. and Andex Resources LLC in exchange for a disproportionate share of the costs of Slugger No.1. In exchange, Andex and Forest will each receive approximately a 20 percent working interest in the eastern North Slope unit.
But those farm-ins were “not sufficient to fund the well,” Chappell said.
Anadarko Petroleum Corp. was talking to BP about farming into the Slugger unit last spring but has decided not to do so, Anadarko spokesman Mark Hanley told PNA in late August. He elected not to comment on the reason for his company’s decision.
Bob Howard, vice president of Chevron’s Alaska business unit, told PNA Sept. 9 that his firm is “monitoring the situation very closely. We are concerned by the lack of interest in Slugger. There is a fair share of risk along with reward. … Another partner will clearly have to be obtained. We’re not ready to take on more working interest in this project than we already have.”
Last year, a Chevron representative told PNA, “One of the reasons we like Slugger is it should ring the cash register faster than our other North Slope exploration prospects since, if successful, the production will likely be processed at the existing Badami facilities.”
Chevron is a partner in the ExxonMobil operated Point Thomson unit, which is four miles northeast of Slugger and scheduled to come on line in late 2006.
On July 11, ExxonMobil filed paperwork with the state to build a 22-mile common carrier pipeline that would carry sales quality condensate from Point Thomson’s central processing facility to a connection point with the existing Badami sales oil pipeline at the Badami central processing facility. ACMP review not yet initiated In addition to finding one more partner, if BP is going to drill an exploration well in the Slugger unit this winter, it must complete its permitting for the project.
“We initiated the permitting process on Slugger in 2001, then suspended work with an intention of resuming it this year, contingent on funding,” BP spokesman Paul Laird told PNA Sept. 9. Since Slugger exploration has not yet been funded, BP has not yet resumed the permitting process, he said.
Part of that process will involve an Alaska Coastal Management Program review, which is handled by the state Division of Governmental Coordination.
Glenn Gray, lead project analyst for oil and gas reviews for DGC, told PNA Sept. 9 that there is still time for a review to be approved for this winter’s drilling season.
BP has no serious contenders for Slugger at this time, Laird said. Four-way closure at Slugger When BP began advertising Slugger and two Badami satellites last year it published a brochure — “BP Exploration Alaska Farm-in Opportunities” — inviting companies to invest for drilling in the winters of 2003 and 2004. (Farm-ins are generally handled by a unit’s operator.)
In the brochure, the prospects’ well depths were listed as 11,500-13,000 true vertical depth, deeper than the Badami unit wells which range from 10,500 to 10,700 TVD.
Well depth at Red Dog, a prospect just east of the Badami unit on the western edge of the ExxonMobil operated Point Thomson unit is 12,379 feet. Point Thomson wells vary in depth from 13,200 to 14,100 TVD.
Within the Point Thomson unit discoveries have been made in both lower Tertiary turbidite sands (Exxon Alaska State A-1, 1975 and BP Sourdough No. 2, 1994) and the lower Cretaceous Point Thomson Sands (Exxon Point Thomson No. 1, 1977).
The Badami field, which was discovered by Conoco in 1990 and began producing in August 1998, produces from lower Tertiary turbidite sands.
The Union Leffingwell No. 1 well, located approximately three miles east of the Slugger unit, was completed on Aug. 8, 1984. It targeted the Lower Mississippian Kekiktuk formation which proved non-productive.
Technical presentations to the state Division of Oil and Gas suggest a four-way closure within the Slugger unit, state paperwork said. Total project costs: $12-13.50 per barrel Well costs, BP said in its brochure, were estimated to be $16 million to $19 million per initial exploration well, with completion running $500,000 to $1 million.
Development wells were expected to cost $5 million to $11 million each.
BP’s total project cost estimates, including everything from finding and development to transport to the West Coast, was listed as $12-13.50 per barrel.
When PNA asked Bill Van Dyke, resource manager for the state of Alaska’s Division of Oil and Gas, about the quality of BP’s data on Slugger and the two nearby Badami satellites, he said, “I suspect BP has real good geological and geophysical data on these prospects and that — along with their record on the North Slope — is a plus. Different companies view them and risk a little differently but as far as data goes, BP will have a n good data set.”
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