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State to Thomson owners: develop or explore Alaska tells Point Thomson unit owners they must drill an exploration well by June, if they decide not to start development drilling Kristen Nelson Petroleum News Editor-in-Chief
The Alaska Division of Oil and Gas has given the Point Thomson unit owners an alternative to starting development drilling by June 2006. Instead, the division said July 27, the owners can drill an exploration well by that date.
The 2006 development drilling requirement is part of the deal the owners struck with the state when they expanded the unit a few years ago.
Point Thomson unit operator ExxonMobil started discussing an extension of the development drilling commitments with the state this summer, a proposal which was included in the 22nd plan of development for the unit, submitted July 1. That plan calls for development drilling to begin, not by June 15, 2006, as previously agreed, but “three to three and one-half years before field startup,” with field startup tied to major gas sales and a gas pipeline yet to be constructed. In other words the Point Thomson owners now view Point Thomson as a gas resource. But there are also liquids in the high-pressure condensate reservoir, and shallower oil plays in the unit, a combination of valuable resources.
“Point Thomson is a world-class asset and if it weren’t already under lease you’d have every major oil company in the world lined up to acquire it,” Mark Myers, director of the Alaska Division of Oil and Gas, told Petroleum News. He said Aug. 9 that the state wants to see the full value of Point Thomson developed: it wants to see condensate developed first, before the gas is produced for sale.
“We’d like to see something similar to Prudhoe, if possible,” he said. “Produce condensate first before going to a gas blow down scenario.” But ExxonMobil, he said, doesn’t believe a gas cycling project (producing the condensate, stripping off the liquids for sale and re-injecting the gas) is economic. “Exxon is saying they want to go directly to a gas blow down scenario.” Division wants drilling Myers told ExxonMobil in a July 27 letter that the division “is not inclined” to accept the proposal in the plan of development, which would extend the drilling commitment dates — and the expansion leases to which the drilling commitments are tied — until gas pipeline negotiations are completed, “and for the term of any resulting contract.”
Myers said the division “does not intend to relieve” the owners of the Point Thomson unit of the drilling plan they committed to when the division agreed to the second expansion of the unit. That drilling commitment required the owners to begin development drilling by June 15, 2006, and to complete seven development wells by June 15, 2008.
Myers told ExxonMobil the division would enforce the expansion agreement if the owners fail to meet the work commitment: that means the expansion acreage would contract out of the unit.
The exploration/delineation well the division has asked for would delineate the Thomson Reservoir west of the Point Thomson Unit No. 1 well, evaluate connectivity and continuity within the reservoir and “evaluate the extent of and the hydrocarbon properties within the oil rim.”
“There is too much geologic uncertainty on the western side of the field and that uncertainty is leading the Point Thomson owners to view the cycling project as uneconomic,” Myers told Petroleum News. He said the division is “willing to accommodate” the owners “if they acquire the data to prove that assumption. … The (exploration) well will answer those key geologic questions,” he said.
In the July 27 letter the division also asked ExxonMobil to apply to the Alaska Oil and Gas Conservation Commission for pool rules and a depletion plan for the Thomson reservoir. The commission determines physical waste issues, Myers said, and it may not let Exxon do a gas blow down without first producing the condensate. “If you cycle the gas first and produce condensate out,” Myers told Petroleum News, “you ultimate produce more condensate and less gas.” The reverse is also true: if you go directly to a gas blow down without producing the condensate first, “you’ll ultimately produce less condensate because you’re depleting reservoir pressure and dropping out liquids in the reservoir that you will never recover.”
That’s an issue of physical and economic waste, and physical waste is determined by the commission. “We don’t honestly know if AOGCC will allow a gas blow down scenario first.”
The division has also asked ExxonMobil to restart permitting and to compare core samples from wells at Badami west of Point Thomson with appropriate Point Thomson wells “to evaluate the Brookian reservoirs” at Point Thomson. Doing the math ExxonMobil told the division on Aug. 3 that the modifications to the proposed plan suggested in Myers’ July 27 letter “would represent significant additional commitments” by the Point Thomson unit owners, and will require the owners to “discuss and consider the suggestions in some detail.” ExxonMobil said it would likely want to consult with the division during August, and should be able to respond by the end of the month. The 2001 expansion-contraction agreement brought the unit to some 116,607 acres, with 40,364 acres added and 7,572 acres contracted out of the unit. In 2003 the unit owners paid the state $940,000 and relinquished leases at the Red Dog prospect on the western edge of the unit, rather than deepen the Red Dog No. 1 well.
It would cost the Point Thomson owners $20 million to back out of the development drilling commitment in the 2001 expansion agreement with the state, in addition to the loss of the expansion acreage. But former division Director Ken Boyd said in a 2004 interview that a well in the western part of Point Thomson would be expensive, maybe in the $30 million range.
—Kay Cashman contributed to this story.
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