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Vol. 13, No. 26 Week of June 29, 2008
Providing coverage of Alaska and northern Canada's oil and gas industry

Thomson revisited

Opposing view on how much oil recoverable; whether focus should be on gas

Kristen Nelson

Petroleum News

There seems to be general agreement on the gas resource at Point Thomson, an undeveloped field on the eastern side of Alaska’s North Slope: some 8 trillion to 10 trillion cubic feet, although there is disagreement on whether that gas is a requirement for a successful North-Slope-to-market gas pipeline.

Then there’s the oil — both the liquids in the condensate at the high-pressure reservoir and the oil rim — with estimates of recoverable oil varying widely.

The companies that have been involved at Point Thomson say getting oil out of the reservoir is going to be difficult and costly; the Alaska Department of Natural Resources Division of Oil and Gas and its consultant, PetroTel, say the oil that could be recovered is the equivalent of another Alpine field, the third-largest oil field on the North Slope; the Alaska Oil and Gas Conservation Commission, responsible for ensuring maximum recovery of hydrocarbon resources, thinks the answer is somewhere in between.

The Alaska Legislature, contemplating a vote on the administration’s recommendation of a license to TransCanada under the Alaska Gasline Inducement Act, wanted the different sides assembled in one place.

That occurred June 18 in Anchorage, when Chevron and ExxonMobil sat down with the division and AOGCC; the division’s consultant, PetroTel, joined in by phone.

ExxonMobil is the operator at Point Thomson, a unit formed in 1977 and terminated by the Alaska Department of Natural Resources in late 2006 for lack of field development. There is ongoing litigation between the state and Point Thomson leaseholders over the termination. The state is also in the process of taking back the leases, although ExxonMobil has begun the permit process for proposed 2008-09 winter drilling.

The drilling is part of a 23rd plan of development proposed by the Point Thomson working interest owners in response to the unit termination; the proposed plan was rejected by the Alaska Department of Natural Resources in early June.

The Anchorage gathering was part of a series of hearings throughout the state on a license proposed by the administration under AGIA, passed 59-1 by the Legislature last year.

The administration solicited applications and received five: Only one, from TransCanada, was found to be complete.

After evaluation by DNR and the Department of Revenue, the departments’ commissioners recommended that the state issue an AGIA license to TransCanada, providing $500 million in matching funds for specified work toward a natural gas pipeline from the North Slope to market, and a dedicated state coordinator for the permits needed by the project.

The Legislature must vote up or down on granting the AGIA license and is holding hearings on the issue.

The Point Thomson show

Point Thomson has become a major sideshow at the hearings: Until recently everyone agreed that gas from the field would be necessary for the pipeline — and that shipment of gas from Point Thomson would begin early in the line’s life.

There have been different proposals for development at Point Thomson, but the major fact has been that there was no gas pipeline and — until recently — no plans to build one.

When plans ratcheted up in recent years for a gas pipeline, the state and the Point Thomson working interest owners began to bump heads on development. The owners said the focus should be on a gas blowdown, to feed gas sales, with limited recovery of liquids from the condensate. The Division of Oil and Gas wanted the oil developed first.

Because Point Thomson is classified as an oil field, based on the volume of liquid in the condensate, AOGCC has to set a gas offtake rate for the field, and in the course of that process will have to decide how the gas and liquids should be produced to maximize hydrocarbon recovery.

When DNR terminated the unit the administration looked at whether a gas pipeline could proceed without Point Thomson gas and concluded that while the volume through a gas pipeline would be lower, and the tariff higher, a gas pipeline without Point Thomson would work.

Major North Slope producers — BP, ConocoPhillips and ExxonMobil — disagree. The companies hold most of the gas at Prudhoe Bay; all three are involved at Point Thomson. Chevron, a major Point Thomson owner, is a very minor Prudhoe owner.

Recoverable oil volume

AOGCC Commissioner Cathy Foerster was asked whether AOGCC agreed with the oil rim recovery rate, more than 50 percent, proposed by the division’s consultant, Anil Chopra, president of PetroTel, or with the 5 percent oil rim recovery rate discussed by Craig Haymes, Alaska production manager for ExxonMobil Production Co.

Foerster said the commission had done only “a cursory review of some of the assumptions and conclusions” in the PetroTel report and hadn’t reviewed ExxonMobil’s analysis in its entirety.

“We are in the process right now of performing our own independent analysis of Point Thomson using Gaffney Cline,” she said.

While the commission has not finished its analysis, Forester said it’s been her experience that the truth usually lies somewhere in the middle when separate technical teams do an analysis.

With an analysis such as that for Point Thomson, involving “the small amount of data that we have” and requiring assumptions and forecasts “the only thing you can guarantee is that neither one will be right,” she said.

But based on “the data that we’ve looked at so far and the part of the analysis that we have done independently at the AOGCC,” she expects the recovery rate to be “somewhere between the two and probably closer to Exxon.”

Forester said AOGCC was at Exxon’s mercy for its study; Haymes said ExxonMobil’s goal was to get all of the data to the commission by the end of the year.

Forester said the commission expects to be able to finish its study within six months of having all the data.

PetroTel recovery focus

PetroTel’s Chopra defended the consultancy’s work, saying there was plenty of data to define a full field plan of development for both oil and gas resources. Based on the gas, and the volume of liquids in the condensate, “there’s about 660 million barrels of oil in the gas cap,” he said, and 75 percent of condensate liquids should be recoverable using gas cycling.

He said others that have done the work “did not look at recovery through gas cycling” but only through gas blowdown, which could result in 24-25 percent recovery.

The oil rim is the upside, Chopra said, with lab tests showing that if gas was added to the heavy oil rim oil, that oil becomes similar to Kuparuk or Prudhoe oil.

“And if that can be done then there’s another 900 million barrels of oil rim sitting there; there’s no reason why it can’t be produced.

“So that’s the difference between the way we are looking at the field vs. other people are looking at it; we are trying to maximize the value for our clients, which in this case is the State of Alaska, we always do that,” he said.

Exxon: gas doable

Haymes said there is enough data available on Point Thomson to do gas sales development “with relatively low risk. Because when you put straws in that high-pressure reservoir, regardless of the discontinuity, baffles or quality differences, it will drain the gas.”

This is the gas blowdown option.

“If you’re talking about ... development of a very thin, heavy oil column, discontinuous heavy oil column; if you’re talking about cycling, then there is not enough information to bring forward a full field plan of development.”

Haymes said ExxonMobil has not seen the full PetroTel report, just the DNR summary that appears in the AGIA decision documents. He said that summary indicates that economic analysis would be required for optimum engineering and that technical issues remain.

The major owners at Point Thomson, he said, have “tens of thousands” of fields worldwide and “operate or have an ownership in the majority of the high-pressure gas fields in the world.”

Point Thomson is unique, he said, and has unique challenges.

Chopra disagreed. There is information on General Electric’s Web site, he said, that states that high-pressure gas re-injection was done in 1975 at 10,000 psi, in 1995 at 9,150 psi. “High-pressure gas injection is not something that was born yesterday,” he said. “It has been there.” The Point Thomson reservoir is 10,200 psi.

Decision when?

Asked when AOGCC would make a decision on gas offtake, Forester said the commission might gain enough confidence from its studies to grant pool rules for Point Thomson with a gas offtake rate. “It is also possible that at the conclusion of the study we will say this is compelling but we still have questions about the producibility of the oil rim, the success of cycling, how long cycling will need to take.”

So it’s possible, Forester said, that “only by drilling, producing, cycling, testing those two concepts — what’s going on in the cycling area and what’s going on in the oil rim — it’s possible that until those are demonstrated by producing and cycling that we won’t be able to make a ruling.”

As for the risk to the companies, John Zager, Chevron’s Alaska manager, said “we’ve heard a lot of discounting of the risk of developing Point Thomson, and maybe when we’re putting our own money on the table we’re more risk sensitive because we’ve been in cases where we have failed miserably even though we were very confident going in.”

Point Thomson, Zager said, “is one of those places where you really want to go and test the waters before you commit.”

Why different estimates?

Forester said part of the differences in the estimated recovery is the difference you always get from different groups doing estimates: The exploration geologist is the most optimistic, she said; the reservoir engineer doing the modeling looks at the data and comes up with a smaller estimate; but the development engineer, she said, is like the guy on the dock with the scale and the knife — he’ll tell you what your fish weighs, and what it will weigh when it’s been cleaned. What PetroTel did not do in its study, she said, “was put it on the scale and put a knife to it.”

Chopra disagreed — there is a need for resources, he said, and “we are in the business of maximizing the recovery.”



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DNR might allow Exxon to drill at Point Thomson this winter

On June 18 ExxonMobil held a meeting with officials from the Alaska Department of Natural Resources as a precursor to applying for permits for the company’s proposed drilling program at Point Thomson on the eastern North Slope.

The Point Thomson unit is in litigation following termination by DNR. Exxon said the purpose of the meeting was to explain the drilling program and get feedback from the regulators on finalizing permit applications.

Nan Thompson, petroleum manager for DNR’s Division of Oil and Gas, told Petroleum News June 19 that DNR would evaluate the permit applications and might issue some permits, depending on what activities were being permitted, what leases were involved and the status of ongoing litigation.

At the start of the meeting DNR read a statement setting out its position with regard to the meeting, Thompson said.

“The purpose of this pre-application meeting is to listen to the applicant’s presentation, learn why the permits are needed and understand which leases would be impacted by issuance of permits,” DNR told attendees. “The fact that DNR is holding this meeting should not be construed as meaning that DNR agrees with Exxon’s legal position with respect to the validity of the leases.”

Investment could be lost if state wins lawsuit

Thompson said DNR also made it clear that the state would not be responsible for any expenditure that Exxon and its partners incur as a result of any permitted drilling activities.

“If DNR issues any of the requested permits, the applicant should understand that the legal status of the leases continues to be litigated,” the statement said. “Any expenditures made by the applicant or others with respect to obtaining permits and/or conducting permitted operations will not be recoverable from DNR, nor may the consideration and/or issuance of permits be considered a waiver of DNR’s rights in any manner.”

The program that Exxon wants to permit involves drilling a total of up to nine wells, with potentially six wells on the Point Thomson unit No. 3 pad, two wells from an ice pad on the west side of the field and one well from the North Staines River No. 1 pad on the east side of the field. A disposal well in the PTU No. 3 pad may also be required at some time in the future, Exxon said.

First well this coming winter

Exxon said that it plans to drill the first well in the Point Thomson unit No. 3 pad in the 2008/-9 winter exploration season. The subsequent drilling sequence and locations would depend on drilling results, permitting and logistical considerations.

DNR permitting requirements include a land use permit, lease operations permit and an Alaska Coastal Management Program review. Permits are also required from the Alaska Department of Environmental Conservation, the Alaska Oil and Gas Conservation Commission, the U.S. Environmental Protection Agency, the U.S. Fish and Wildlife Service and the North Slope Borough.

Exxon said that it expects to submit most permit applications on or before July 1. The company is likely to submit its oil discharge prevention and contingency plan and the application for an air quality limit for the Point Thomson camp in mid July.

—Alan Bailey