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Vol. 11, No. 26 Week of June 25, 2006
Providing coverage of Alaska and northern Canada's oil and gas industry

Oil first at Point Thomson?

AOGCC to evaluate development options at Exxon-operated North Slope field

By Kay Cashman

Petroleum News

In September the state agency charged with protecting the public’s interest in hydrocarbon recovery in Alaska will begin evaluating Exxon’s proposed plan to develop the 106,200-acre Point Thomson unit as a gas field rather than as an oil field.

The Alaska Oil and Gas Conservation Commission said in a recent white paper – i.e. statement of position — that the eastern North Slope field should be developed as an oil field if the only consideration were the conservation of Alaska’s hydrocarbon resources.

“In other words, to maximize both oil and gas recovery, produced gas from Point Thomson should be injected back into the reservoir until all of the economically recoverable liquid hydrocarbons have been produced. Only then should the gas be sold,” the agency said in its white paper.

But AOGCC, which is responsible for preventing waste and insuring greater ultimate recovery of oil and gas, said many other factors will – and should – be considered in reaching the best decision for Point Thomson “to maximize benefit to the citizens of Alaska.”

This qualification is unlikely to appease the Murkowski administration and Exxon which propose to develop Point Thomson as a gas field and hold off developing it until a gas pipeline project from the North Slope gets the go-ahead from all parties. Their position is at odds with the recommendation of former state Division of Oil and Gas Director Mark Myers.

Last year Myers denied Exxon’s 22nd development plan for Point Thomson, saying that if Exxon and fellow major leaseholders BP, Chevron and ConocoPhillips didn’t develop the field they should give the acreage back to the state, so that other companies could have a chance to pick up the leases and develop the unit.

Exxon and its partners have held Point Thomson for more than 30 years, claiming the unit was uneconomic. Until recently oil and gas prices supported that argument.

Myers boss, Department of Natural Resources Commissioner Tom Irwin supported his decision and ordered the unit into default.

But Murkowski fired Irwin for disagreements the two had over the gas pipeline contract negotiations between the administration and the three major North Slope oil producers and gas owners, Exxon, BP and ConocoPhillips.

When the new DNR commissioner, Mike Menge, took office, he suspended Irwin’s ruling. Menge said Point Thomson was essential to the development of a North Slope gas line and that Exxon was one of the three participants in a contract that could lead to that pipeline being built.

With almost 350-450 million barrels of oil and condensate and 8 trillion cubic feet of gas, Point Thomson is the largest proven yet still undeveloped field in Alaska.

AOGCC’s ultimate decision will play a large part in determining how best to bring the field’s gas to market.

Its study is expected to take eight or nine months, AOGCC Commissioner Cathy Foerster told Petroleum News June 21, which puts completion in April or May of next year.

Difficult to develop

AOGCC’s white paper said Point Thomson is one of the “most difficult” North Slope fields “to develop and manage properly because the majority of the resources are contained in what is called a retrograde condensate reservoir.

“Retrograde condensate reservoirs around the world tend to be deeper and have higher pressures and temperatures than conventional reservoirs. These abnormally high temperatures and pressures cause the fluids in the reservoir to have unusual properties. Thus, a retrograde condensate reservoir acts differently than a typical oil field such as Prudhoe Bay or a typical gas field such as the Kenai Gas Field. The differences in behavior are technically complex and difficult to describe, understand, and address; yet understanding and addressing these differences are essential to insuring maximum hydrocarbon recovery,” AOGCC said.

“A conventional oil reservoir is typically filled with a liquid hydrocarbon that has some solution gas in it. In such a reservoir all the fluid exists as a liquid, but as it is brought to the surface its pressure drops and some of its solution gas is released. The same thing happens underground. As the pressure decreases in the reservoir, gas in the oil comes out of solution.

“To understand how this works, think of a bottle of soda,” the agency said. “Before the bottle is opened, its contents are under pressure and it appears that there is just liquid in the bottle. However when the cap is removed, the pressure in the bottle is reduced and bubbles will start to form and float to the surface of the soda.

“Conversely, a conventional gas reservoir is typically filled with hydrocarbon gas. The gas may have a small amount of hydrocarbon liquid, called condensate, vaporized in it. This condensate will not drop out as a liquid in the reservoir because the temperature is too high. However it will separate from the gas when the gas is brought to the surface where the temperature is lower.

“This is similar,” AOGCC said, “to what happens when someone blows warm breath onto a cold window and watches it fog up. The water that exists as a vapor inside the warm lungs turns to condensation as it hits the cold window.

“Retrograde condensate reservoirs do not behave in the same ways that conventional oil and gas reservoirs do. Dropping the pressure in the reservoir does not cause gas to form from oil, as is the case in a conventional oil reservoir. Nor does vaporized condensate remain a vapor, as is the case in a conventional gas reservoir.

“Rather, for a retrograde condensate reservoir, as the pressure decreases, liquids drop out of the gas in the reservoir,” AOGCC said.

“When a retrograde condensate field is produced like a conventional gas field, the gas is produced and sold at high rates.

Initially a large amount of condensate is produced with the gas. However the reservoir pressure drops quickly and condensate production drops dramatically because condensate is dropping out in the reservoir instead of at the surface.

“To further the problem,” the agency said, “condensate that drops out in the reservoir is much more difficult to produce than that which remains entrained as a vapor in the gas. The liquid tends to build up and clog the pore spaces in the reservoir rock.

“Also, since this reservoir has never been exposed to liquid before, the rock acts as a sponge and some of the condensate will stick to it and never come out. To make things worse, once the condensate comes out of the gas, very little of it will return to a gaseous state even if the reservoir pressure is later increased.

“In other words,” AOGCC said, “this is a problem that you can’t fix after you cause it; it’s like unringing a bell.

“In addition to lost condensate recovery, if the reservoir pressure is reduced too quickly, the gas recovery will also decrease. The condensate that clogs up the reservoir and won’t come out also blocks the gas from coming out.

“This is similar to an air filter on a car,” the agency explained. “When the filter is new, air will flow through it freely, but as it gets older the pores in the filter begin to clog with dirt (as the pores in the reservoir would clog with condensate) and the air will not flow through as well. Eventually no air at all will flow.”

Maximizing condensate production

So what’s the answer?

In its white paper AOGCC said the solution to maximizing condensate production from a retrograde condensate reservoir is to keep the reservoir pressure high until the condensate has been recovered.

Often this is accomplished through a process known as “gas cycling.”

In this process hydrocarbon gas is produced, the condensate is removed and sold, and the now-lean gas is injected back into the reservoir to maintain pressure and to sweep more condensate to the surface, the agency said.

“As this process continues, the gas produced slowly becomes leaner and the yield of condensate decreases. Eventually the gas is stripped of most of the liquids, and gas sales can be maximized.”

This method delays gas sales, AOGCC said, but results in greater ultimate recovery of both liquid and gaseous hydrocarbons.

Another method used to develop retrograde condensate fields is to inject a substitute gas such as nitrogen or carbon dioxide either to replace or to supplement the produced gas for pressure maintenance.

“Unfortunately, there is currently no substitute gas available to Point Thomson,” the agency noted.

These are just a few of the “more common methods used for developing retrograde condensate fields and each has advantages and disadvantages that must be considered,” AOGCC said.

“Primary depletion as a gas field is the least efficient and results in the lowest hydrocarbon recovery. However, it is the simplest and cheapest method for the operator since it does not require an investment in equipment to recycle the gas.

“Gas cycling, AOGCC said, “yields greater hydrocarbon recovery but may be less attractive to the operator because it has a higher up-front development cost for compression and it has low up-front cash flow due to the deferral of gas sales.”

“Injection of outside substances has the possibility of maximizing both condensate recovery and cash flow, but it is the most expensive method because in addition to compression equipment it requires the purchase of a substitute gas,” the agency said.

Selection of “an optimal method of development must consider all of the unique aspects of the reservoir in question, as well as the practicality and applicability of the various development methods,” AOGCC said.

Will look at similar reservoirs elsewhere

To date Exxon has indicated that the only development scenario that makes sense for Point Thomson is to develop it as if it were a normal gas field, which AOGCC said “would likely result in significant loss of condensate.”

Since AOGCC must determine whether this development option is best for the citizens of Alaska, the agency is working with an outside consultant — Gaffney, Cline, and Associates — which has “extensive retrograde condensate reservoir expertise,” AOGCC said in its white paper.

AOGCC and Gaffney, Cline “are evaluating different development options and developing a sound technical basis for making future decisions on the development of the Point Thomson unit,” AOGCC said.

Foerster said an “important part of our study will be a review of development plans for fields with similar reservoir conditions throughout the world, i.e., a benchmarking study of how retrograde condensate reservoirs are developed elsewhere.

“In other words, if operators are cycling similar reservoirs everywhere else, then perhaps this one should be cycled too. Or if operators throughout the world see this type of reservoir as too tough to cycle, then perhaps we shouldn’t hold Exxon to a higher standard than good industry practice throughout the world,” she said.

The Point Thomson owners have indicated they plan to apply to AOGCC in late 2006 or early 2007 for pool rules and a gas offtake allowable rate.



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Boyd puzzled by Exxon’s position

Kay Cashman

The current situation with the Point Thomson unit is “an odd one because when I was dealing with Point Thomson it was Exxon, as unit operator, who ALWAYS maintained that Point Thomson was a gas cycling project,” Ken Boyd told Petroleum News in a June 21 email. Boyd was state Division of Oil and Gas director for Alaska before Mark Myers.

“I ALWAYS asked (at the planning meetings) if a gas line was required to develop Point Thomson and Exxon (as operator) ALWAYS

said NO. This was a gas cycling project ALWAYS. They said they DID NOT need a gas line to develop Point Thomson. This changed in 2001.”

Boyd left state employment in early 2001. Myers took his place.

In the next plan of development, Exxon “said that a gas cycling project was not economic. NOW they needed the gas line to sell Point Thomson gas,” Boyd said.

“So up until sometime in 2001 I believe Exxon would have agreed with the

AOGCC white paper outcome. Gas cycling WAS their plan. In effect, the

unit was in agreement with the current AOGCC conclusion until 2001,” he said.

“I simply don’t know what changed the mind of the unit. I don’t know why

(or if) the gas cycling project is uneconomic. Perhaps the rising price

of gas had something to do with it (but oil prices went up as well),” Boyd said in his email to PN.

“The essential question becomes: why is a gas cycling project not economic today? Said another way: Is a gas sales project more economic than a gas cycling project? If so, why?” asked Boyd.

According to Cathy Foerster, a reservoir engineer and a commissioner of the Alaska Oil and Gas Conservation Commission, Exxon said that “ in 2001 Exxon re-interpreted their existing data and determined that gas cycling was no longer their preferred option. They mentioned that the new analysis showed greater reservoir and project uncertainty than past analyses had.”

Myers wanted them to drill a well to remove the uncertainty, which Exxon agreed to do.

But in its gas contract negotiations with the Murkowski administration Exxon was able to get out of that obligation.

Boyd said retrograde, condensate reservoirs like Point Thomson are expensive to develop because of the associated high pressure (among other reasons).

“They require exotic and expensive steel for the wells and no doubt these costs have gone up over time,” he said.

“But the value of the resource, both oil and gas, has also increased.

“Recognizing the uncertainty of future commodity prices the question of why one project is superior to the other has not been answered. Presumably the unit owners know that answer," Boyd said.