A drill rig has been contracted and will be moved in November to Point Thomson, located 60 miles east of Prudhoe Bay, company officials told senior Department of Natural Resources officials March 3.

Drilling on the first of five wells planned for the project will be underway in January.

The drilling project will put about 200 Alaskans to work, Craig Haymes, ExxonMobil's Alaska production manager, told state resources Commissioner Tom Irwin at the hearing.

Haymes said modifications to the drill rig would have to be made to enable it to contain extreme high pressures, in excess of 10,000 pounds per square inch, in the Point Thomson reservoir.

If Irwin approves the plan, work to modify the rig will begin in June and conceptual engineering work will get underway on the overall project, which will produce about 200 million cubic feet of natural gas daily and extract 10,000 barrels of condensates.

The gas would be injected back into the underground reservoir. Condensates would be transported through a new 22-mile pipeline to connect with an existing pipeline built to BP's Badami field. Condensates would be mingled with crude oil and shipped through the Badami and trans-Alaska oil pipelines to market, Haymes said.

It is among a few high-pressure reservoirs that are within the industry's capability to produce, but the project being proposed for Point Thomson is unusual in that other high-pressure fields simply produce gas or oil, where at Point Thomson gas will be injected and recycled through the reservoir to extract the condensate liquids.

Accomplishing that presents technical challenges. For example, gas separation vessels, or tanks, in the project will require steel that is 6 inches thick.

It's not certain that Irwin will approve the plan, however. ExxonMobil and its major partners at Point Thomson, BP, Chevron and ConocoPhillips, are in the middle of a dispute with the state over the status of state oil and gas leases in the field, where about 8 trillion cubic feet of gas and 200 million barrels of liquid condensates have been discovered by past drilling.

The Department of Natural Resources claims the companies reneged on work obligations and in late 2006 moved to terminate the leases. The companies sued and in late December state Superior Court Judge Sharon Gleason halted the termination action and ordered the state to allow the companies to propose a remedy to the dispute.

ExxonMobil and its partners proposed the gas recycling project to the state DNR Feb. 19 as a proposed remedy. Judge Gleason will hold another hearing on the legal dispute in June. If Irwin approves the plan, ExxonMobil will begin work on the project, which aims to have condensates being produced and transported through the trans-Alaska pipeline by 2014.

Haymes said there are several unknowns and technical complications at Point Thomson, the most important being concerns over how efficiently fluids can move through the reservoir rock, which is vital in a recycling project.

There are also questions about the true extent of the oil and gas resource itself.

Eight trillion cubic feet of gas and 200 million barrels of condensates are cited as resource estimates, but actual numbers could prove different. That's because a big part of Point Thomson's underground reservoir extends to the north and out from the shore of the Beaufort Sea.

There are differences in permafrost below the ocean compared to permafrost below land, and those present difficulties in interpreting data from seismic exploration, Haymes said.

Seismic involves sending sonic waves through subsurface rock. The reflections off the rock layers help explorers profile the rocks and spot possible oil and gas traps. Permafrost distorts the sonic waves, and scientists working with the exploring companies have to adjust for that. Drilling planned at Point Thomson will help clear up a lot of those uncertainties.

The proposed development plan schedules drilling early in the project. The first two wells, one drilled to produce “wet” saturated gas and a second to inject dry, or “lean” gas after liquids are removed, will answer the question of how efficiently fluids can move through four miles of reservoir rock between the bottom locations of the two wells.

If the first two wells encounter rock of poor quality there is still time to drill a separate well bore off the first to find better rock, Haymes said.

Another reservoir question can't be answered until production actually starts, however. That is whether there are any barriers, such as a shale layer, between the injection well and the producing well that would block or reduce the flow of gas.

Three more planned wells are intended to test shallow oil accumulations as well as the deeper gas resources in the eastern and western extensions of the Thomson Sand reservoir. If there is change in reservoir pressure in the outer extensions due to production of gas at the core of the reservoir, it will indicate that fluids are flowing through the several miles of rock between the well bottoms.

If this happens, ExxonMobil may be able to convert both wells at the core to injection wells and push gas through the rock to wells at the outer extensions. This would set the stage for an expanded condensate production project, possibly approaching the kind of larger project investigated in 2004, which was hoped to produce 70,000 barrels/day of condensates.

The Point Thomson project will be very expensive because of its remote location and because of the unusual high pressure of the reservoir, which will require heavy steel and special drilling equipment. Point Thomson wells will have to be drilled to a vertical depth of 12,000 feet to reach the gas-bearing Thomson Sand reservoir and, in addition, a lateral distance ranging from 10,000 feet to 15,000 feet from the surface location of the drill rig. The extreme high pressure of the reservoir means that a very heavy, specialized drilling fluid, or mud, must be used. The drill fluid must also be kept at a pressure in the well above that likely to be encountered in the reservoir rock outside the well, to keep oil and gas fluids out of the well. If fluids get into the well and aren't controlled a “blowout” can occur at the surface, with an explosion or fire possible. Point Thomson wells are estimated to cost $60 million to $90 million each, two to three times what the same kinds of wells would cost at Prudhoe Bay.

Another challenge is compressing the produced gas to a high enough pressure, over 10,000 pounds per square inch, to inject it back into the underground reservoir. The pressures are beyond the capabilities of centrifugal compressors used traditionally in the industry, but ExxonMobil believes use of a reciprocating compressor, which involves a piston mechanism, would do the job.

In view of the technical unknowns and the high costs, Haymes said ExxonMobil and its partners believe a carefully phased development to reduce risk is prudent.

“Historically we have looked at large developments at Point Thomson, such as a larger gas recycling project studied in 2004 and 2005,” Haymes said. “This plan mitigates the risks and sets up Point Thomson for the future,” in expanded condensate production and commercial gas production when a gas pipeline is built, he said.

The discovery at Point Thomson was made in 1977 and in the years since 19 exploration wells have been drilled in the area, 14 of which penetrated the main Thomson Sand reservoir. There were 20 well-flow tests but most of these were of short duration. Eight three-dimensional seismic programs have also been done, with the data integrated. Over the years the companies have been about $800 million.