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Vol. 13, No. 24 Week of June 15, 2008
Providing coverage of Alaska and northern Canada's oil and gas industry

Blowdown a loss

State: Producing Point Thomson gas first would mean 500M fewer barrels

Kristen Nelson

Petroleum News

Everyone seems to expect that gas from Point Thomson will be part of what initially fills a gas pipeline taking North Slope natural gas to market.

But Point Thomson, some 60 miles east of Prudhoe Bay, has both oil and gas, and Point Thomson oil has never been produced.

Blowdown at Point Thomson — producing the gas without producing liquids first, the quickest way to get gas into a North-Slope-to-market line — could result in a loss of hundreds of millions of barrels of oil when compared to production with gas cycling.

That is the conclusion of a study commissioned by the Alaska Department of Natural Resources Division of Oil and Gas.

“A gas blowdown scenario could recover over 500 million barrels less than a gas cycling scenario,” the division said in a May 16 summary of the study. “This difference is larger than the expected ultimate recovery from the Alpine oil field.”

Petroleum geologist Julie Houle, with the division’s resource evaluation staff, introduced the study May 30 during the administration’s Alaska Gasline Inducement Act forum in Anchorage.

Houle said the division had a good in-house data set for Point Thomson, and began work with a 3-D geologic model, then contracted with PetroTel for help in understanding the geologic model and to do reservoir modeling.

She said the goal was to understand the Point Thomson reservoir, and when some of the conclusions reached were “surprising” the AGIA team was alerted because results indicated that Point Thomson gas might not be available for initial sales.

Feasible without Point Thomson?

Black & Veatch Corp., a global engineering, consulting and construction company working with the administration’s gas team, did an economic analysis. Deepa Poduval, a principal with the firm, said May 30 that the general perception had been that Point Thomson would have gas available at the beginning of gas sales. Was the project feasible without it?

The state’s conservative case was 4 billion cubic feet a day, compared to the 4.5 bcf base case, but they looked at a scenario — without Point Thomson gas — where a pipeline moved just 3.5 bcf a day, Poduval said.

What they found was that 3.5 bcf a day worked.

The project is “very feasible” without any Point Thomson gas, Poduval said, and would be profitable for both the state and the producers. The pipe would be the same in all three cases, 48-inch diameter, but fewer compressors would be needed for smaller volumes of gas.

The capital cost would drop, but with a lower volume over which to spread the cost, the tariff increases as the volume of gas drops, Poduval said.

Best recovery of liquids from condensate at 30 years

Plano, Texas-based PetroTel Inc., a consulting firm specializing in enhanced oil recovery, reservoir characterization and simulation, did the reservoir model study for the division.

The best oil condensate recovery from the field, according to model cases run by PetroTel, comes after 30 years with 30 wells, 22 producers and eight injectors: 86 percent of the liquids were recovered from the condensate and oil-rim recovery was close to 50 percent, 290-475 million barrels.

With the injectors converted to gas producers for a 30-well gas blowdown, up to 70 percent of remaining recycled gas would be recovered within 12 years after liquids production ended.

Point Thomson is a high-pressure condensate reservoir, with liquids suspended in the gas at pressures of more than 10,000 psi, much higher than encountered elsewhere on the North Slope. In gas cycling the condensate would be brought to the surface, the liquids removed and sold, and the gas re-pressured and reinjected to maintain reservoir pressure. Gas would be produced at the end of liquids production.

That was long the development plan for the reservoir, but a few years ago the Point Thomson owners (ownership at the unit is in litigation) decided gas cycling would not be economic, and proposed to produce the gas for sale in a proposed North-Slope-to-market gas pipeline.

The division objected and DNR concurred; ultimately the Point Thomson unit was terminated, a decision the former owners have appealed. Earlier this year the former owners proposed a small gas cycling project to test whether the reservoir would support a cycling project.

Point Thomson could be third largest oil field on North Slope

While Point Thomson has been characterized as a gas reservoir, specifically “it’s a retrograde gas condensate reservoir with an oil rim,” said Anil Chopra, founder of PetroTel.

He said at the May 30 presentation that gas and condensate have been tested but “consistent production tests” are lacking, in particular “consistent long-term production tests from the thin oil rim are missing.”

Chopra said geologic models indicate gas in place at Point Thomson is 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.

Point Thomson could be “the third-largest oil field” on the North Slope, after Prudhoe Bay and Kuparuk, he said.

Primary depletion — blowdown — simplest for Point Thomson

Chopra said PetroTel ran more than 70 computer simulations, trying to establish the best way to produce Point Thomson. Primary depletion, blowdown of the gas, is easy, he said: “You go and punch holes in the ground and start producing gas.”

He said when blowdown was run in the model, with 22 wells 70 percent of the gas could be recovered in 12 to 15 years. While some of the condensate could be produced, 74 percent was left behind with blowdown, because as reservoir pressure is reduced, liquids drop out of the condensate.

Some 6-7 tcf of gas would be recovered with blowdown, but only 127-156 million barrels of liquids, about 26 percent of in-place volume.

In primary depletion — blowdown — oil-rim oil recovery varied from 3-16 percent (30-150 million barrels), depending on the number of wells drilled.

Pressure should be maintained

Gas cycling is required to maximize recovery, Chopra said.

Ideally you’d maintain reservoir pressure until all economically recoverable condensate and oil are produced.

If pressure is maintained through gas cycling for 10 years, 62 percent of the condensate is recovered (300-370 million barrels) along with 39 percent of the oil rim (225-370 million barrels).

Over a 20-year gas recycling project, 76 percent of the condensate is recovered (370-450 million barrels) along with 43 percent of the oil rim (250-400 million barrels).

Blowdown of the gas cap after 10 and 20 years of cycling recovers 57 percent and 56 percent, respectively (4.8-5.9 tcf) of the original gas in place.

The division’s report said “it became obvious that oil rim development had to be done during a gas cycling phase.” There is uncertainty about the quality of both the oil and reservoir rock in the oil rim, so reservoir pressure must be maintained “to preserve reservoir energy and sustain maximum oil producibility” from the oil rim.

Injecting recycled gas into the oil rim would “help reduce the viscosity, improve swelling, mobilize and displace the oil.” Wells into the oil rim also help with recovery: increasing the number of wells into the oil rim during gas cycling development increases oil recovery. With 13 gas producers, 18 gas injectors and 20 oil-rim producers, recovery of oil-rim oil approached 50 percent after 30 years of cycling — three to 15 times better than oil-rim oil recovery during primary blowdown.

More gas could be used

The division said with production from the oil rim, voidage from the reservoir was increased. Looking at model cases with large-scale oil-rim development of 30 horizontal producers, reinjection of 90 percent of produced gas would not be sufficient to maintain reservoir pressure.

Gas from other fields could be imported and injected into the Thomson reservoir to help maintain reservoir pressure, and this gas could be in the form of carbon dioxide or inert gas such as nitrogen, methane or natural gas.

CO2 is commonly removed from produced gas in a gas treatment plant and if enough CO2 were available for pressure maintenance, it could allow sale of some Point Thomson gas prior to blowdown. The division also said that “CO2 should be fully miscible with the Thomson oil and thus reduce the viscosity and further increase recovery.”

Because CO2 is a greenhouse gas there could be government tax incentives for storing it in a reservoir.

Importation of CO2 would require construction of a gas line to Point Thomson, but, the division pointed out, once blowdown began that line would be available for gas sales.

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