ExxonMobil in Alaska: The long wait for Point Thomson

Exxon discovers rich North Slope field in 1970s, but technical challenges, lack of gas line preclude development, spawn court fight

Wesley Loy

For Petroleum News

Former Alaska Gov. Wally Hickel included a colorful anecdote about the Point Thomson oil and gas field in his 2002 book, “Crisis in the Commons: The Alaska Solution.”

It was January of 1990, only a few weeks after Hickel took office for his second hitch as governor. The year before, the tanker Exxon Valdez had run aground in Prince William Sound, spilling nearly 11 million gallons of crude oil.

Hickel had a morning meeting in Juneau with Exxon’s top executives at the time, Lawrence Rawl and Lee Raymond.

“When they finally came into my office, I got to the point,” Hickel wrote.

“‘Larry,’ I said, ‘I want Point Thomson back.’ I said it just as clean, simple, and direct as if I had told one of my sons, ‘Eat your oatmeal.’ I watched his eyes, because the eyes reflect the mind, just at the face reflects the heart.

“Very clearly, without animosity, Rawl said, ‘Governor, could you give us a little time?’

“‘Sure, Larry, I’ll give you time, but you know the terms of the lease.’”

Hickel, who died in 2010, was among a long line of Alaska governors who have banged their heads against the brick wall that is Point Thomson.

The field is located on state acreage along the remote Beaufort Sea shoreline some 60 miles east of Prudhoe Bay. Although Exxon discovered Point Thomson with wells drilled in the late 1970s, it has yet to produce any oil or natural gas. It remains one of the largest proven, undeveloped fields not only in Alaska but in North America.

That’s a tremendous frustration for Alaska politicians and economic development boosters, who see Point Thomson as a potential goldmine of taxes, royalties and jobs.

The major stakeholders in Point Thomson — ExxonMobil, BP, Chevron and ConocoPhillips — have their reasons for not yet developing the field, chief among them the lack of a North Slope natural gas pipeline.

Today, Point Thomson is bound up in a court fight with the state, which is trying to break up the Point Thomson unit and reclaim the acreage. But even as the legal struggle continues, lawyers for the state and the companies are trying to talk out a settlement. And drilling resumed at Point Thomson in 2009 after years of inactivity.

Many believe it’s critical to lift the cloud from Point Thomson, as the field is estimated to hold 8 trillion cubic feet of natural gas regarded as critical for supporting a proposed, multibillion-dollar gas line.

Field’s early history

Hydrocarbons were first discovered in the Point Thomson area in 1975 with the Alaska State A-1 well, which tested a zone of the lower Tertiary Flaxman sand and flowed at a rate of 2,507 barrels of oil per day and 2.2 million cubic feet of gas.

A second discovery well, the Point Thomson Unit No. 1, was drilled in 1977 and conducted flow tests in the Lower Cretaceous Thomson sand. One test yielded 2,283 barrels of oil per day and 13.3 million cubic feet of gas.

Six more wells would be drilled over the next seven years to delineate the two Point Thomson discoveries. In the process, other hydrocarbon reservoirs were encountered.

In 1994, BP and Chevron drilled the Sourdough No. 2 well targeting Brookian sands of the Canning formation in the southern portion of the Point Thomson unit, and followed up with the Sourdough No. 3 well in 1996. In a 1997 press release, BP announced a discovery of potentially 100 million barrels of recoverable oil.

Altogether, 17 wells were drilled within the boundaries of the Point Thomson unit between 1975 and 1996.

State officials certified seven wells as “capable of producing oil or gas in paying quantities,” a legally significant designation. The seven are: Alaska State A-1, Point Thomson Unit No. 1, Point Thomson Unit No. 2, Staines River State No. 1, Alaska State C-1, Alaska State F-1 and Sourdough No. 2.

PetroTel Inc., a Plano, Texas, consultant, conducted a resource assessment and field development study for the state in 2008. The firm summed up Point Thomson this way:

“Well log and production or drill stem test data indicate that much of the Point Thomson area is underlain by the Cretaceous (Neocomian) Thomson sand that contains abundant natural gas and hydrocarbon liquids in the form of gas condensate, ranging from 35º to 45º API gravity. In addition to gas and condensate, the Thomson sand also contains a thin and potentially discontinuous oil-rim at the bottom of the reservoir interval that has tested oil as high as 18º API gravity. The Point Thomson area contains the potential of hundreds of millions of barrels of oil in the shallower Tertiary Brookian reservoirs. Another potential productive reservoir is composed of carbonates and bedded metasedimentary strata in the ‘Pre-Mississippian’ basement below the Thomson sand reservoir.”

The push for development

The unit ultimately would grow to 45 leases encompassing 106,201 acres. That was the size of the unit when the state, in December 2006, declared the unit was terminated — an action which remains in dispute in court.

In terms of ownership, 25 lessees took a working interest in the Point Thomson unit, with four companies holding the great majority. The state calculates ownership based on surface acreage. ExxonMobil, the unit operator, holds 52.58 percent; BP 29.19 percent; Chevron 14.31 percent; and ConocoPhillips 2.82 percent. The minor unit owners hold the remaining 1.09 percent.

The unit operator is obliged to submit a periodic plan for exploration or development to the state. The initial plan of exploration covered a five-year period.

In the early years, up to 1983, Exxon and other companies drilled several wells within the unit and the state approved plans of development routinely, often without comment, according to a 2005 analysis of the unit history by a law firm representing the Alaska Gasline Port Authority. The authority, an organization that today counts Fairbanks North Star Borough and the city of Valdez as members, has promoted development of a natural gas pipeline and has accused the major oil companies of “warehousing” gas at Point Thomson.

After 1983, Exxon began to propose plans of development that didn’t include further drilling. Exxon cited the lack of a North Slope gas pipeline as a reason to throttle back on Point Thomson.

According to the Port Authority, Exxon told the state on Oct. 28, 1983: “Sufficient drilling has been accomplished to establish within reason the area and potential commerciality of the field. Further development prior to commencement of construction of a pipeline to market would constitute economic waste through premature expenditure of funds which otherwise could be utilized for exploratory or development activity on other Alaska areas and leases. Additionally, wells drilled and suspended far in advance of commencement of sustained production frequently deteriorate physically to the extent of requiring expensive reworking or even redrilling.”

Kay Brown, the state’s oil and gas director, on Nov. 29, 1983, approved what was the seventh plan of development for Point Thomson, without a drilling requirement. A succeeding director, Jim Eason, also approved plans — extending into 1996 — that didn’t include drilling provisions.

But state officials were beginning to grow tired of waiting for production from Point Thomson — if not the field’s gas, then at least its substantial reserves of petroleum liquids, which could be sent down the trans-Alaska oil pipeline.

Eason, in an article published in the Anchorage Daily News on Dec. 4, 2006, recalled how he had planned to get tough with Exxon at the tail end of Hickel’s term in 1994.

“It was the only decision that I ever took to the governor,” Eason said. “We were going to give them an ultimatum: They needed to produce.”

But time ran out on the Hickel administration before a formal move was made to retake Point Thomson.

Halting hopes for gas cycling

This would be done by bringing gas to the surface, processing it to capture the “condensate” or gas liquids, and then pumping the dry gas back downhole for storage.

Producing these liquids first, as opposed to a quick gas “blowdown,” has important practical advantages for a field such as Point Thomson, the PetroTel study said.

“The majority of the proven hydrocarbon resource in the Thomson sand is contained in the form of gas with entrained liquids known as a retrograde condensate,” the study said. “Retrograde condensate reservoirs tend to be deeper and have higher pressures and temperatures than conventional reservoirs. Due to the abnormally high pressures and temperatures, the fluid in a retrograde condensate reservoir does not behave like those in conventional oil and gas reservoirs.”

Rapid production of gas from such a reservoir, and the resulting loss of pressure, will cause vaporized hydrocarbon liquids to condense and clog pore space, PetroTel said. The result is that “hundreds of millions of barrels of condensate will become trapped in the reservoir and never be produced.”

On May 16, 2002, Exxon’s Alaska production manager at the time, Jack Williams, told a Resource Development Council audience the company was working with regulators on a potential gas cycling project to produce up to 75,000 barrels per day of Point Thomson liquids.

The next year, however, Exxon said the gas cycling project was not economic and would not be pursued.

On Sept. 30, 2005, a landmark decision came down from Mark Myers, then the state’s oil and gas director. He found that the Point Thomson unit agreement was in default because of ExxonMobil’s failure to submit an acceptable plan of development.

Myers didn’t mince words in his assessment of the company’s 22nd plan of development, which proposed additional studies to determine whether a commercially viable production plan could be devised for the field.

“Failure to develop and produce known hydrocarbon accumulations deprives the State of incremental revenue, economic activity and jobs,” Myers wrote. “Should the PTU terminate, the area could be re-leased and unitized again under an acceptable unit plan of development that includes commitments to develop and produce the underlying hydrocarbon accumulations.

“Continuing this 30-year record of non-development and delay of an oil and gas lessee’s obligations to develop and produce its oil and gas leases makes a mockery of the statutory, regulatory and contractual protections for the State as owner of the oil and gas estate. Therefore, the 22nd POD is unacceptable.”

Mike Menge, the state’s natural resources commissioner under Gov. Frank Murkowski, would uphold the Myers decision.

Litigating, drilling, talking

Here are the most significant events of recent years:

• On April 22, 2008, the state natural resources commissioner at the time, Tom Irwin, terminated the Point Thomson unit. The unit designation is important because it keeps alive old leases that otherwise would expire.

• On May 8, 2009, with Irwin’s permission, ExxonMobil spudded the first of two wells on a pair of Point Thomson leases. The company said the wells were part of its “unconditional commitment” to start producing 10,000 barrels a day of condensate from Point Thomson by the end of 2014.

• On Jan. 11, 2010, ExxonMobil, BP, Chevron and ConocoPhillips scored a major victory when Superior Court Judge Sharon Gleason of Anchorage reversed Irwin’s unit termination.

So where do things stand today?

The state appealed aspects of Gleason’s decision to the Alaska Supreme Court, where for several months the case has stood idle as the two sides attempt to negotiate a settlement.

ExxonMobil, on Oct. 27, 2010, announced it had finished drilling the two “development wells,” but has since stacked its rig for transport out of the field. The company is seeking a U.S. Army Corps of Engineers wetlands permit for its proposed gas cycling project.

Negotiations continue, with ExxonMobil executives and Alaska Gov. Sean Parnell publicly agreeing on this much: It’s time to settle the Point Thomson affair.