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Vol. 13, No. 25 Week of June 22, 2008
Providing coverage of Alaska and northern Canada's oil and gas industry

PTU not another Alpine

BP, Chevron, Exxon dispute state’s Point Thomson analysis, say gas main resource

Kristen Nelson

Petroleum News

The oil at Point Thomson is not the equivalent of another Alpine field, ExxonMobil and Chevron told Alaska legislators June 17. The loss of Point Thomson oil if gas were produced first as described in a Department of Natural Resources report is based on erroneous assumptions about how much oil could be recovered from the field under any scenario, they said.

Gas is the primary resource at Point Thomson, not oil, and Point Thomson gas is necessary for a successful gas pipeline, the companies said.

BP did not testify, but delivered a similar message in a June 16 letter to legislators.

Up until three weeks ago, everyone believed Point Thomson gas was necessary for a gas pipeline, said Craig Haymes, ExxonMobil Alaska production manager, adding that the Point Thomson leaseholders don’t understand how that can have changed so rapidly, since the field contains 25 percent of known North Slope natural gas.

John Zager, Chevron’s Alaska general manager, agreed: Reserves to back a 4.5 billion-cubic-foot-a-day line are insufficient, “in fact there’s insufficient reserves to back a 3.5 bcf-a-day pipeline” — and that’s with Point Thomson included, he said, referring to the total gas that would be needed over the life of the line.

The state has said the gas pipeline would be economic without Point Thomson gas, although the tariff would be higher for a 3.5 bcf line than for 4.5 bcf.

Zager said it’s not just throughput but also the reserves behind the line, and asked if anyone would commit to firm transportation on a line that didn’t have enough resources to back it.

“People talk about this yet-to-be-found gas like it’s a bankable commodity; it’s not,” he said.

Without Point Thomson, needed gas resources to back a gas pipeline are “significantly” larger, Zager said.

And then there’s the issue of blowing down Prudhoe Bay. If Prudhoe is providing the only gas, and earlier than with Point Thomson gas, there could be a loss of otherwise producible Prudhoe oil, he said.

ExxonMobil is the largest leaseholder at Point Thomson and the unit operator. Chevron and BP also hold large acreage positions; ConocoPhillips holds a smaller stake and there are more than 20 minority interest holders. DNR terminated the unit for lack of production in late 2006, a decision confirmed by current DNR Commissioner Tom Irwin earlier in June.

Oil recovery issue

Haymes said ExxonMobil has not seen the PetroTel report done for DNR, the source of the assertion that the oil at Point Thomson is the equivalent of another Alpine, just DNR’s summary; he said they’d asked for a copy of the actual report.

The summary, published as part of the Alaska Gasline Inducement Act decision document, “appears to be based on very selective and limited data,” he said. It also isn’t based on the companies’ most recent data, since data sharing between the Point Thomson leaseholders and DNR has been stalled over the last three years by litigation, Haymes said.

PetroTel estimated gas in place at Point Thomson at 8.5 trillion to 10.4 trillion cubic feet, with associated condensate of 490 million to 600 million barrels and a potential oil rim of 580 million to 950 million barrels.

“The report provides an estimate of recoverable liquids and gas, but it does not consider that fundamental necessary technical work that has yet to be done,” Haymes said.

“Based on our review of that summary report, no sound technical conclusions could be made on the producible resource,” he said.

PetroTel estimated a recovery factor of up to 50 percent from the oil rim, Haymes said.

But “the oil rim is thin, discontinuous and heavy oil — molasses,” he said.

PetroTel assumed horizontal wells would be used to develop the reservoir. “We’re not aware of anywhere in the world that anybody has drilled horizontal wells in this pressure reservoir with this deviation. And we did research last week to confirm that,” he said.

The issue, Haymes said, is that today’s technology doesn’t allow drilling of horizontal wells at the pressure encountered in Point Thomson and at the required deviation.

The Point Thomson owners “don’t believe the recovery of this heavy oil will be more than 5 percent — nowhere near 50.”

Point Thomson is a high-pressure, 10,200 psi, retrograde condensate field that straddles the coast 60 miles east of Prudhoe Bay.

Gas sales recovers 90 percent

Work done by the owners concluded that “90 percent of the resource will be recovered through gas sales development. So the cycling project and the oil delineation will chase 10 percent of the resource,” Haymes said. That 90 percent includes gas and oil, and the condensate that falls out of the gas when temperature and pressure are reduced, he said.

The Point Thomson owners proposed a 23rd plan of development in February to meet state demands for unit development. Wells would test cycling — producing gas, stripping condensate and reinjecting the gas — and also the deeper oil rim and shallower Brookian oil accumulations. The initial phase would produce 10,000 barrels per day.

Haymes said the risk with the cycling project, rejected by DNR earlier in June, is that the reservoir may not be homogeneous and the gas may not flow between injector and production wells.

Wells at the field will cost $60 million to $100 million for the most complex wells, compared to current Prudhoe Bay costs of $6-$8 million per well, he said, and will take 90 to 120 days to drill, compared to a current average of 20 days at Prudhoe Bay.

The flank wells — those targeting the oil rim — can test communication in the reservoir, Haymes said. If those wells are in communication with the more central wells, they can be used for injection and production could be doubled or tripled quickly.

Results from earlier drilling are conflicting, with variation in reservoir size, he said, and drilling won’t tell us much; what is needed is production.

Haymes said some information would come quickly from the work proposed in the 23rd plan of development.

By monitoring reservoir pressure from the flank wells, “within six weeks of production we will know whether we have a small tank (connected reservoir) at Point Thomson or not. And if we have a small tank, we’ve all got a problem. But in six weeks we’ll know that after turning on production,” he said.

Strictly theoretical

Vince LeMieux, Chevron’s manager of Alaska new ventures, told legislators he looked at DNR’s summary of the PetroTel report, and “the work that was done there was strictly theoretical.”

“It’s not that the work is wrong,” he said, but it doesn’t take into consideration economics or factors like location and type of wells, and “reaches a conclusion that is very optimistic, both in the original hydrocarbons that are in place but particularly in the recoverable hydrocarbons.”

What the report doesn’t address, he said is “the practical recoverable reserve that you could get to.”

As for another Alpine at Point Thomson, LeMieux said “incremental recoverable liquids at Point Thomson are substantially less than 500 million barrels,” and if you accelerate Prudhoe Bay gas because Point Thomson has been taken off the table, “you may actually end up with less oil produced on the slope as a result of this.”

There has also been reference to seismic data providing evidence of field continuity, he said. “What you’re really worried about in the continuity of the field is how the rocks are put together — the stratigraphy, the actual detail within the reservoir. And you can’t access that from seismic.

“You can learn more about the structure; you can learn something about the faulting, but you’re not going to — in this case — learn about the stratigraphy, which is absolutely critical to understanding how this field will be developed.”

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