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State revises views on Pt. Thomson oil 2008 PetroTel analysis has been revised, sharply dropping volume of oil viewed as recoverable from condensate, oil rim at field Kristen Nelson Petroleum News
What would the impact of a gas blowdown at Point Thomson be on oil recovery from Alaska’s eastern North Slope retrograde gas condensate field?
The State of Alaska has a different opinion now than it did in May 2008, when as part of the Palin administration’s Alaska Gasline Inducement Act forum in Anchorage the Department of Natural Resources’ Division of Oil and Gas presented a study by PetroTel which projected a difference of 500 million barrels of oil between a gas blowdown at Point Thomson — simply producing the natural gas without extracting condensates — and gas cycling, which would remove condensate from the gas and ship that liquid to market, re-injecting the natural gas to maintain reservoir pressure and allowing for gas production at a later stage of the field’s life.
“The difference is larger than the expected ultimate recovery from the Alpine oil field,” the division said in a May 16, 2008, summary of the PetroTel study.
The Point Thomson owners — at that time primarily ExxonMobil, Chevron and BP — objected, telling legislators at the forum that Point Thomson is no Alpine.
What’s changed? What was wrong with the PetroTel 2008 study, DNR Deputy Commissioner Joe Balash told the Senate Judiciary Committee June 12 in Anchorage, is that it looked at the resource potential at Point Thomson without considering volumes that could economically be recovered.
There are challenges above and below ground, Balash said — how the reservoir performs; how the equipment at the surface can perform.
In the 2008 study, all they wanted to understand was how the reservoir would perform without reference to aboveground constraints, he said. They looked at volumes of 800 million cubic feet a day and cost wasn’t taken into consideration nor was the location of pads around the reservoir. And because the reservoir is underwater off Point Thomson, location of pads is a challenge, he said.
Then there are the mechanical systems themselves — all those things need to be taken into consideration, Balash said.
He compared it to the way the U.S. Geological Survey estimates resources: first there’s the in-place resource; then what is technically recoverable; and finally, what is economically recoverable. That 2008 PetroTel estimate, he said, was somewhere between the first two.
But as you move closer to economically recoverable the numbers drop.
Preliminary analysis In a June 7 letter to Sen. Hollis French, D-Anchorage, chair of the Judiciary Committee, Balash said the 2008 PetroTel study “was a preliminary analysis and was not designed to evaluate optimal developments scenarios.” The Resource Evaluation section of the Division of Oil and Gas contracted with PetroTel in 2007 to “perform geologic and engineering evaluation of the Point Thomson Sand reservoir,” he said, and the goal was a technical assessment, “an independent analysis of the proven and potential hydrocarbon resources contained in the reservoir and gain a better understanding of unique issues associated with development and production of a retrograde gas condensate reservoir.”
He said the 2008 study cannot serve as a realistic basis to review a specific development plan because no consideration was given in that study to potential restrictions such as location or size of surface infrastructure or facilities, development costs, performance of high-pressure facilities, gas handling constraints or market conditions.
Balash said the 2008 study did not consider any economic or operational constraints or the challenges of permitting a full field development.
Oil rim volumes The 2008 study said as much as 400 million barrels of oil could be recovered from the Thomson Sands oil rim, which “lies between an overlying highly mobile Thomson Sands gas cap and an underlying water leg,” Balash said in the letter.
But PetroTel has done work for the state since 2008, he said.
Modeling runs done subsequent to the 2008 report indicate there would be serious challenges in producing “the thin oil column of the main Thomson reservoir” because wells intended to produce that oil “would produce gas instead of oil within a matter of weeks, effectively ending production from the oil rim.”
PetroTel had estimated 400 million barrels of recoverable oil from the oil rim, and that, Balash said, “in retrospect, appears unrealistic given these challenges, the current state of technology, and development costs.”
A review of the 2008 PetroTel study by the Department of Energy said the PetroTel findings were “optimistic and open to question, especially with respect to the recovery predicted for oil from the oil rim.” The DOE concluded that very little of the oil rim oil was recoverable and estimated gas reserves at 8 trillion cubic feet and liquids at 300 million barrels of condensate, a number which the Balash letter characterized as “in stark contrast to the earlier 2008 PetroTel estimates of 620-850 million barrels of petroleum liquids.”
Division’s current understanding Balash said that since the 2008 study was issued the division “has learned much more about the reservoir and the challenges associated with development of the resource within.”
After the 2008 study was completed, the division got access to ExxonMobil’s and BP’s data room, Balash said.
Using information learned from the data room, and in conjunction with PetroTel, the division “concluded that when comparing similar likely scaled full field developments, the potential liquids lost (in blowdown opposed to cycling) would be far less than the estimates contained in the 2008 PetroTel study.”
PetroTel did contract work for the Department of Law beginning in September 2008 and did additional studies and refinements to their earlier modeling.
After an extensive review the division concluded that the potential liquid condensate and oil lost if there were an early blowdown at Point Thomson for a major gas sale “would be significantly less than the estimates found in the 2008 PetroTel study.” Balash said DNR couldn’t disclose the revised estimate “because this information is protected under Alaska law.”
Balash said the proof would be played out in a very public way as the field is developed.
He said there was data and information the state agreed not to make public, but said the administration could explore what information they could share with legislators in a confidential setting.
Original estimates The 2008 PetroTel study estimated 8.5 tcf to 10.4 tcf of gas in place, with associated condensate of 490 million to 600 million barrels and a potential oil rim of 580 million to 950 million barrels.
With a blowdown, PetroTel estimated recovery of 6-7 tcf of gas over a 12-15 year period, but only 127-156 million barrels of liquids, about 26 percent of the in-place volume, with oil-rim oil recovery varying from 30 million to 150 million barrels, a 3-16 percent recovery, depending on the number of wells drilled.
PetroTel told legislators in May 2008 that Point Thomson could be “the third-largest oil field” on the North Slope, after Prudhoe Bay and Kuparuk.
If Point Thomson were developed with gas cycling, 62 percent of the condensate is recovered over a 10-year period (300-370 million barrels) along with 39 percent of the oil rim (225-370 million barrels), and over 20 years of gas recycling, 76 percent of the condensate is recovered (370-450 million barrels) and 43 percent of the oil rim (250-400 million barrels).
Exxon, Chevron, BP disagree In mid-June 2008, ExxonMobil and Chevron told legislators that the PetroTel report was based on erroneous assumptions about how much oil could be recovered from the field under any scenario.
The companies said gas, not oil, is the primary resource at Point Thomson.
BP did not testify, but delivered a similar message in a letter.
ExxonMobil said it hadn’t seen the PetroTel report, but said the published summary of the report appeared to be based on limited data, and said the estimate of recoverable liquids and gas didn’t consider fundamental technical work yet to be done.
Chevron said that based on the published summary of the PetroTel report the work was strictly theoretical and didn’t take into consideration economics or location and type of wells. Chevron called the conclusion “very optimistic” both for hydrocarbons in place and for recoverable hydrocarbons.
Chevron said recoverable barrels at Point Thomson are “substantially less” than the 500 million barrels expected from Alpine, and also said that if production of Prudhoe Bay gas was accelerated because Point Thomson gas was not available for a gas pipeline due to a gas cycling project, the end result could be less overall oil produced on the North Slope.
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