With the agreement between the state and the leaseholders over much-disputed Point Thomson on Alaska's North Slope, unit operator Exxon Mobil has filed a plan of operations with Alaska's Division of Oil and Gas. The division wants public comments on the proposed plan by June 22.
Although the Point Thomson field is very large -- it contains 300 million barrels of liquid oil and natural gas condensate and 8 trillion to 9 trillion cubic feet of natural gas, according to the Alaska Department of Natural Resources -- the field has yet to produce any oil or gas. Exxon discovered the field in 1977.
While being accused by some of "warehousing" the huge resource that the field contains and being challenged by the state for not developing Point Thomson leases, Exxon has over the years put forward several plans for development in the unit, none of which has ever comes to pass.
The Point Thompson field presents some development challenges.
Although there are known oil pools within the Point Thomson unit, the field consists mainly of a high-pressure gas condensate reservoir.
The field could be operated as a conventional gas field, but the production of condensate from the field requires a procedure known as gas cycling. In gas cycling, the reservoir pressure is maintained by injecting produced gas back into the reservoir, thus flushing condensate in vapor form to the surface.
Because of the temperature and pressure conditions in the reservoir, much of the condensate would liquefy underground and remain trapped unless the reservoir pressure is maintained through the cycling process.
The production of condensate is desirable because it has a higher economic value than natural gas and, in liquid form, it could be mixed with crude oil for export through the trans-Alaska oil pipeline. At this point, there is no means of getting gas from the North Slope to market.
In 2008, Exxon proposed a modest-scale gas-cycling development that would enable some condensate production while also providing a means of verifying the feasibility of gas-cycling in the Point Thomson reservoir.
In justifying the relatively small scale of its proposal, the company cited significant unknowns in a Point Thomson development, including the possibility of pressure could not be maintained between gas injection and oil production wells; the possibility that the reservoir may not be contiguous but broken up by impermeable rock; the difficulty of injecting gas into an exceptionally high pressure reservoir; and the difficulty of drilling long reach directional wells into that high subsurface pressure (much of the reservoir is offshore and will need to be drilled from onshore).
In 2009, with the dispute between Exxon and the state still raging, Exxon moved ahead with the drilling of two initial wells, an injection well and a production well, at an existing gravel pad at Point Thomson. In October 2010 the company announced that the drilling had been successful but did not elaborate on what it had found.
The plan of operations that Exxon has now submitted looks essentially to be a rerun of the plan that it proposed in 2008. The plan entails the drilling of a disposal well and up to five wells, including the two wells already drilled, from three gravel pad. Using long reach drilling, the three pads would enable well access to the west, central and eastern sections of the reservoir.
"Wells drilled from the proposed pad locations will be at or very near the technical limits of drilling reach," the operations plan says.
Produced hydrocarbons will be delivered to a central processing facility on the central pad.
At the processing facility, hydrocarbon liquids will be recovered and stabilized for delivery by pipeline to the trans-Alaska oil pipeline.
Produced water will be injected into a disposal well, while produced gas will be compressed to 10,000 pounds per square inch for re-injection into the reservoir as part of the gas cycling process. The processing facility will be able to handle 200 million cubic feet of gas per day for the recovery of 10,000 barrels per day of condensate, the operations plan says.
By ALAN BAILEY
Petroleum News