Reservoir pressure in the Thomson Sand, the main reservoir at Point Thomson, is 10,200 pounds per square inch. That's very high - about twice as high as in the nearby Prudhoe Bay field - but ExxonMobil manager Bill Meeks said the company has drilled wells in reservoirs with higher pressures elsewhere, some with 15,000 pounds per square inch.

The experience the company has gained with those other wells will be put to work at Point Thomson to ensure wells are drilled safely, Meeks told state Resources Commissioner Tom Irwin in a hearing held by the Department of Natural Resources.

ExxonMobil submitted a plan Feb. 19 to develop a $1.3 billion gas condensate production and gas recycling plant at Point Thomson that would produce 10,000 barrels per day of liquid condensates, which can be blended with crude oil and shipped through the trans-Alaska oil pipeline.

If the state DNR approves the plan, work on the project would begin immediately and should be in production in 2014.

ExxonMobil is engaged in a long-running dispute with the state over Point Thomson development. The state moved to cancel leases held by ExxonMobil and its partners, but in late December state Superior Court Judge Sharon Gleason ordered DNR to hold hearings on possible remedies to the dispute.

The plan proposed by ExxonMobil Feb. 19 is a proposed remedy.

While the company is confident it has the capability to drill Point Thomson wells, it won't happen without challenges, Meeks said.

One of the trickiest parts of the drilling will be to maintain a very high weight of drilling fluids, or “mud,” in the well-bore to contain the 10,500-pound pressures while drilling through the main Thomson Sand rocks, without causing fractures. A heavy mud of 16 pounds per gallon, almost twice as heavy as water, will have to be used in Point Thomson, Meeks told Irwin in the hearing.

“If fractures occur in a rock layer beneath the gas-bearing strata the drilling mud would be lost in the underlying formation, lowering pressure in the well-bore and allowing high-pressure gas from above to come into the well during drilling,” Meeks said. “This has happened before in one of the wells drilled in the 1980's at Point Thomson.”

The margin of error is much tighter in high-pressure formations like Point Thomson than in conventional oil and gas fields, like Prudhoe Bay. “Managing the uncertainty is much more critical,” Meeks said.

The mud is the drillers' main protection against an uncontrolled flow of oil or gas into the well bore. If something happens to the fluid pressure and gas or oil flows into the well, a second line of defense is a “blow-out preventer” at the surface. It is a large and sturdy device the drill team uses to close off the well.

A blowout at the surface could cause damage to the rig and create an explosion, fire or a major spill.

The plan at Point Thomson is to drill five wells, the first two will be gas injection and gas production wells in the core part of the gas reservoir. These would be followed by three gas production wells on the east and west flanks of the reservoir, Meeks said. The three wells on the flanks would also test shallow oil deposits that are known to exist, he said.

“We will learn a lot from those first two wells,” Meeks said. “We can't put on a lot more pressure (with the mud) without reaching the burst point,” the strength limit of the rock, above which fractures could occur.

“Once we get experience with the injection and first production wells, we will have a lot more confidence with the three delineation wells,” Meeks said.

The company has experience with Point Thomson drilling from earlier work in the field, but drillers today have new tools that can assure more safety and precision in drilling. For example, “measure while drilling equipment” installed at near the end of the bit of the drill pipe contains devices that give the drill crew at the surface almost real-time information on where the drill bit is and what rock it is drilling through.

The planned wells also involve extended-reach drilling, where the wells reach out to considerable distances horizontally from the surface location of the rig. The original wells at Point Thomson drilled in the 1970s and 1980s were more conventional wells drilled vertically or at shallow angles.

The field development plan was designed to have the wells done first in an effort to get experience with the new drilling, Meeks said. The schedule was done to give flexibility in case problems are encountered.

Normally production wells are drilled while surface production facilities are being built or even after. In this case the drilling will start in 2009, under ExxonMobil's plan, and be completed by 2012, two years before surface facilities and a pipeline are complete and ready for production.

For example, if the first wells planned in 2009 encounter reservoir rock that is not of sufficient quality to allow gas fluids to pass through, either from injection or production of gas, there is time for the company to drill a “sidetrack” well to find better quality reservoir rock, Meeks said.

A sidetrack well is a new well drilled off underground from an initial well drilled from the surface.

The project proposed by ExxonMobil is to produce about 200 million cubic feet of gas daily and remove condensates, a natural gas liquid, from the gas. The gas, stripped of condensates, would be injected back into the underground reservoir.

The condensates would be shipped through 22 miles of new pipeline to be built to the existing Badami pipeline. It would be mingled with oil from the Badami field, which is operated by BP, and shipped on to the Trans-Alaska Pipeline System at Prudhoe Bay.

ExxonMobil is the operator and one of the major owners of the Point Thomson field. Other major owners are BP, Chevron and ConocoPhillips.