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Exxon’s Point Thomson will be North Slope’s first high-pressure condensate field
Kristen Nelson PNA Editor-in-Chief
The state has been talking to the Point Thomson unit owners about developing the eastern North Slope field for years. This year, in conjunction with an expansion of unit acreage, the major owners (field operator ExxonMobil Production Co. and BP Exploration (Alaska) Inc., Chevron U.S.A. Inc. and Phillips Alaska Inc.) agreed to field development, in late August, as reported by PNA.
The companies applied for expansion-contraction early this year. In response, the state asked for “sustained commercial production” by 2008. The unit’s 18th plan of development, submitted in September, was accepted by the state. That 18th plan of development commits field owners to continuous drilling by 2006. The expansion-contraction agreement commits field owners to the completion of seven development wells by 2008.
A different kind of field What kind of a field is Point Thomson? PNA talked to petroleum manager Bill Van Dyke and petroleum reservoir engineer Mike Kotowski — both with the Department of Natural Resources Division of Oil and Gas — about Point Thomson.
Point Thomson is a high-pressure condensate reservoir. It’s different from a field like Alpine, which is a traditional black oil reservoir, said Van Dyke.
And different than fields that have been developed up until now on the North Slope Kotowski said.
“Because of the high pressure, the wells will be relatively more expensive to drill because they’ll probably be an extra string or two of casing set and the tubing will be rated for higher pressure, the well heads will be rated for higher pressures,” Van Dyke said.
The drilling mud will also be more expensive, Kotowski said, “because it will take heavier materials to contain the reservoir pressure.”
Even the surface flow lines will have to be rated for higher pressure, Van Dyke said.
The Point Thomson owners are talking about doing a gas cycling project, he said, extracting condensates — gas liquids — from the gas and then reinjecting the gas.
With reservoir pressures at Point Thomson at some 10,000 pounds per square inch, compared to about 4,000 pounds at Prudhoe Bay, “they’ll need compressors that can handle those higher pressures,” Van Dyke said.
“And the bottom line is, compression horsepower is very expensive,” Kotowski said, both to buy and to run.
Some gas could be sold If gas wasn’t reinjected at Point Thomson, reservoir pressure would drop and condensates would fall out in the reservoir, limiting recovery of liquids. But if the gas sales project goes forward, Van Dyke said, “they can sell some of the gas, then they won’t have to reinject it all, which would probably make the economics look better.”
Most of the production at Point Thomson will be gas, with condensate in it, Van Dyke said. The Point Thomson condensate liquid is high quality, lighter components — NGLs, gasoline and kerosene weight — not too much heavy oil, he said, pretty valuable compared to Prudhoe Bay crude
“Ninety-five percent of it’s going to be gaseous stuff that’s going to have to go back in the ground if there’s no gas sale. And only about 5 percent will be the liquids that you’re going to sell. So you have to put 95 percent of it back in the ground — if you do a gas cycling project.”
Van Dyke said that when you produce Point Thomson, you have to produce gas, and then do something with it: sell it, take it to Prudhoe Bay and store it there or reinject it.
If you didn’t need to maintain reservoir pressure, “you could just send that whole stream to Prudhoe Bay and process it over there,” recover the liquids and send them down the oil pipeline and put the gas into the Prudhoe reservoir or send it down a gas pipeline.
If the gas went to Prudhoe, Kotowski said, the owners would “just make a gas balancing agreement that would account for the gas.”
Economic analysis, as well as physical Kotowski said the Point Thomson owners will probably do “an economic and physical analysis of what’s going to be the loss in gas as well as liquid reserves if they don’t reinject as compared to the compression cost of reinjection.” Cost of horsepower injection will be compared to the liquid loss to determine “the most economic depletion plan,” he said.
Gas cycling will recover most of the Point Thomson liquids in the condensate, Van Dyke said, and that will be balanced against the cost of building and running the project.
Point Thomson is probably not any different than a condensate field elsewhere in the world, Van Dyke said, “the liquids are valuable and it makes sense to make that investment, to strip out all those liquids first, and then you come back 10 or 20 years later and sell the gas.”
“I think a better way of characterizing it — it’s no different than any other condensate field in the world except for its higher pressure. …that’s the big difference,” Kotowski said. “It’s no different than any other condensate reservoir. Other than it’s high pressure and its remote location.”
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