Providing coverage of Alaska and northern Canada's oil and gas industry
February 2010

Vol. 15, No. 7 Week of February 14, 2010

Big Risk, Bigger Rewards: The non-legal risks at Point Thomson

The fighting between the state and the industry over Point Thomson comes down to a challenging and barely understood reservoir

Eric Lidji

For Petroleum News

In coffee shops and op-eds in Alaska, discussion of Point Thomson tends to focus on legal issues: Will the state revoke leases? Will it terminate the unit? Will the companies sue?

Underlying those legal issues, though, are geologic and engineering uncertainties that set off the 30-year dispute between government and industry over the North Slope field.

Now, with ExxonMobil and its partners drilling at Point Thomson for the first time since the early 1980s, those uncertainties are moving to the forefront of the discussion. The drilling program under way is a small-scale effort designed not only to produce hydrocarbons from the eastern North Slope field, but also to answer questions about the geology of the region and the best way to develop the complex resources buried there.

Those answers will determine what risks are and are not acceptable at Point Thomson.

Seven years of exploration

Exxon discovered Point Thomson in the mid-1970s, as construction wrapped up on the trans-Alaska oil pipeline and the North Slope moved toward becoming a producing basin.

Although Exxon drilled numerous wells over the next decade at Point Thomson, much of the information gleaned from those wells remains proprietary, and therefore public knowledge about the region is even scarcer than already limited private knowledge.

The leases at Point Thomson date back to 1965, before the discovery of Prudhoe Bay to the west. Exxon found oil and gas with the Alaska State A-1 well in 1975, and found the oil and gas in the Thomson Sands with the Point Thomson Unit No. 1 well in 1977.

The company performed two flow tests with the PTU No. 1 well, finding a deposit of condensate and a deeper deposit of heavier oil. In delineating those prospects over the following seven years, the company found two more reservoirs at Point Thomson.

Those wells confirmed the existence of a large, high-pressure, gas-condensate pool with a viscous oil rim in a reservoir consisting primarily of the Beaufortian-age Thomson Sandstone; a separate, shallower oil pool exists in younger Brookian sands.

The Point Thomson reservoir — a mix of oil, natural gas and condensate — discovered in 1977 remains to this day the largest proven, but undeveloped field in Alaska. The Alaska Department of Natural Resources currently believes the unit holds some 300 million barrels of liquids and 8 trillion to 9 trillion cubic feet of recoverable natural gas.

While 17 wells were drilled within the boundaries of the Point Thomson unit between 1975 and 1996, none have been drilled into the Point Thomson reservoir since the early 1980s.

A complicated legal battle

That absence of drilling is the basis of a complicated legal battle that began in 2005 and continues on in varying degrees, even as Exxon is currently drilling at Point Thomson.

Between 1977 and 2005, Exxon proposed and the state approved 21 plans of development for Point Thomson that never ultimately resulted in production from the unit.

In 2001, the state agreed to expand the unit if Exxon and the other leaseholders committed to a seven-well drilling timeline, or agreed to pay penalties if they didn’t drill.

At the time, the state wanted Exxon to produce the oil and condensate resources at Point Thomson first, cycling the natural gas through the reservoir to maintain field pressures.

Until 2004, Exxon and its partners agreed, submitting development plans that called for producing the liquids before moving on to the extensive natural gas resources.

Exxon ultimately failed to drill any of the wells outlined in 2001, but paid several fines.

In 2004, Exxon and its partners submitted a plan of development that favored producing the natural gas resources first, saying that gas cycling was economically risky. Because of the lack of a gas pipeline on the North Slope, though, that meant stalling production.

The Alaska Oil and Gas Conservation Commission classified Point Thomson as an oil field, meaning the commission would need to approve any gas off-takes in advance.

In June 2005, Exxon submitted a 22nd Plan of Development for Point Thomson that also called for developing the natural gas first rather than cycling it for liquids production.

Over the course of several years, the state ultimately rejected that plan, then put the unit in default, then terminated the unit and finally took back all of the leases. Those events in turn prompted appeals and lawsuits from Exxon and the other Point Thomson owners.

In February 2008, Exxon submitted a 23rd Plan of Development, calling for a small-scale gas cycling project of 10,000 barrels of liquids per day, a compromise from the gas-first approach Exxon wanted, but less than the 40,000-60,000 bpd it had once proposed.

Point Thomson a rare bird

The debate over the economics of Point Thomson is rooted in the uniqueness of its reservoir, a petroleum system known as a “retrograde condensate reservoir.”

These reservoirs are typically deeper, hotter and under higher pressure than traditional reservoirs, creating challenges where companies try to develop the resources.

In a conventional oil field, oil and gas are mixed together in the reservoir. When a drill bit enters the reservoir and underground pressure begins to fall, the oil and gas separate.

In a May 2007 white paper on Point Thomson, the Alaska Oil and Gas Conservation Commission compared this to a bottle of soda. When closed, the bottle appears to contain only liquid, but when opened, a gas separates from the liquid and rises to the surface.

In a conventional gas field, the gas contains a bit of vaporized hydrocarbon liquid called condensate. As the gas is extracted, the lower temperatures at the surface — compared to the warmer temperatures underground — turn this vaporized condensate into a liquid. The AOGCC compared this to the fog created when someone breathes on a cold window.

These tendencies, though, don’t apply to a retrograde condensate reservoir.

In fields like Point Thomson, a drop in reservoir pressure doesn’t cause the gas to separate from the oil, and condensate doesn’t stay vaporized. Instead, the vapor turns to a liquid underground and clogs up the pores that allow oil and gas to pass to the surface.

Different ways to develop

As a result, there are several strategies for developing these reservoirs.

The first is a conventional approach, where the natural gas is extracted. This is called “blowdown.” At first, the natural gas brings up a large amount of condensate, but at the same time, condensate still underground becomes a liquid and clogs up the pores.

According to the AOGCC, this not only prevents that condensate from ever being produced, but also limits future gas production by essentially locking up the reservoir.

A second approach is called “gas cycling,” where natural gas is extracted from the field, stripped of its condensate and re-injected to maintain the high pressure in the reservoir.

This approach yields a much higher recovery of hydrocarbons than blowdown, but it is also more expensive because it requires building specialized recycling equipment. In addition to the extra construction costs, gas cycling also strains the cash flow of the development effort by delaying the first gas sales until all of the condensate is produced.

A third approach involves replacing the injected natural gas with an outside substance — like nitrogen or carbon dioxide — to maintain pressure without stranding the natural gas.

While this approach yields the highest recovery and the greatest cash flow, it also costs the most, because in addition to expensive recycling equipment, the operator must not only buy a large amount of nitrogen or carbon dioxide, but also get it to the drill site.

Each of these scenarios requires an economic trade-off, forcing an operator to decide whether the additional resource is worth the cost of production, or should be sacrificed.

In most cases, the decision is final, and can’t be undone.

Better to cycle or produce?

The debate over Point Thomson is about which of these approaches to take.

In June 2008 PetroTel Inc. released a state-commissioned study of the Point Thomson region and determined that gas cycling would maximize the recovery of the reservoir.

PetroTel estimated the original gas in place at Point Thomson at somewhere between 8.5 trillion and 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.

By cycling natural gas for 20 years, Point Thomson could yield 620 million to 850 million barrels of liquids — oil and condensate — and then go on to yield 4.8 trillion to 5.9 trillion cubic feet of natural gas, PetroTel concluded. By comparison, the firm estimated that through blowdown, Point Thomson would produce some 210 million to 305 million barrels of liquids and between 6 trillion and 7 trillion cubic feet of gas.

“This incremental recovery of oil is larger than the expected ultimate recovery from the Alpine Oil Field,” the state Division of Oil and Gas noted in a summary of the report.

At a June 17, 2008, legislative hearing, Point Thomson leaseholders challenged that conclusion.

Representatives from ExxonMobil and Chevron told lawmakers that Point Thomson oil reserves didn’t equal another Alpine, and that the estimates of how much oil would be lost if the companies produced the gas resources first was based on false assumptions about how much oil could be recovered from the field under any development scenario.

The companies said gas, and not liquids, were the primary resource at Point Thomson.

Craig Haymes, then ExxonMobil Alaska production manager, said the PetroTel report seemed to be based on limited, selective and, in light of the fact that litigation had kept the state and the companies from sharing data for three years, less than timely information.

“The report provides an estimate of recoverable liquids and gas, but it does not consider that fundamental necessary technical work that has yet to be done,” Haymes said.

As an example, Haymes pointed to the oil rim. PetroTel estimated a recovery factor of up to 50 percent from the oil rim, Haymes said, but “the oil rim is thin, discontinuous and heavy oil — molasses.”

PetroTel assumed horizontal wells would be used to develop the reservoir. “We’re not aware of anywhere in the world that anybody has drilled horizontal wells in this pressure reservoir with this deviation. And we did research last week to confirm that,” he said.

More to the point, though, the companies said the gas at Point Thomson was absolutely necessary to justify the construction of the natural gas pipeline from the North Slope.

Under the PetroTel model, the natural gas at Point Thomson would be tied up for 20 years after the start of condensate production. Under the most optimistic timetables for a natural gas pipeline, Point Thomson gas wouldn’t be available for a decade or more.

The companies said Point Thomson gas represented a quarter of the known reserves on the North Slope. The state said existing reserves at Prudhoe Bay and Kuparuk could be used until Point Thomson became available as a gas field. The companies said that blowing down Prudhoe Bay and Kuparuk posed the same problem of lost oil recovery.

Is PTU a Tarn or a Badami?

The 23rd Plan of Development involves a gas cycling program to test whether the technique will work at Point Thomson, but Haymes said cycling was inherently risky.

No one knows for sure whether the cycling production and injection wells will “communicate.” If not, pumping gas back into the ground won’t maintain field pressure.

Haymes said the geology remains largely unknown at Point Thomson. For example, he said, the location of the field running from onshore to offshore means that the permafrost in the area has changing thickness, making seismic data more challenging to interpret.

Also, the Brookian sequence at Point Thomson comes with an uncertain legacy. The sequence is found at the successful Tarn and Meltwater fields in the Kuparuk River unit, but also at Badami, the notoriously finicky field just west of Point Thomson.

One of the features of the Brookian is turbidites, or layers of sand and silt. In Badami, these layers form “sand lobes” that cut off one reservoir from another. For the past decade, BP, the operator of Badami, has struggled to find a way to develop the field.

If Point Thomson resembles Badami, it could complicate production. However, if Point Thomson resembles Tarn and Meltwater, it could become a significant oil producer.

Much technology and much cash

Either way, Point Thomson is expensive.

In March 2008, Haymes said Exxon and its partners had spent more than $800 million on Point Thomson, without a single producing well or dollar of revenue to show for it.

The 23rd Plan of Development currently in effect is a $1.3 billion gas cycling program to drill five wells at Point Thomson and produce 10,000 barrels per day by the end of 2014.

Exxon and its partners have presented the program as a major technological undertaking.

In a March 2008 administrative hearing, Bill Meeks, ExxonMobil drilling engineering manager, said the pressure of Point Thomson gas was 10,200 pounds per square inch, requiring drilling mud twice as dense as what is used on traditional North Slope wells.

The need for wells to pass at an angle through the reservoir will require additional mud pressure to keep rocks from caving around the well, and therefore those initial Point Thomson wells will test the limits of the technology used to drill difficult wells. “That’s one of the big risks we have at Point Thomson,” Meeks said. “How far can you go?”

The wellhead structures at Point Thomson are rated to 15,000 pounds per square inch, about three times the rating of a typical Prudhoe Bay wellhead. The water-oil-gas separator in the processing facilities will be rated to 3,000 pounds per square inch, requiring six-inch steel walls, with compressors rated to 20,000 pounds per square inch.

The mechanical requirements for drilling in this challenging reservoir — like upgrades to Nabors Rig 27-E — combined with the already increased costs of drilling in an isolated corner of the already isolated North Slope basin, means that Point Thomson wells will cost 10 to 15 times as much as a typical Prudhoe Bay well, according to Haymes.

Exxon cites these details to justify its small-scale production at Point Thomson, saying that a smaller program will test the technology, provide information about the reservoir and allow the company to change gears if gas cycling turns out not to be appropriate.

Or, if gas cycling works as hoped, the small-scale effort can be ramped up. Exxon plans to tie Point Thomson back to infrastructure at Badami with an 80,000-barrel-per-day pipeline, capable of handling the production levels of the original gas cycling program.

Bigger rewards within reach?

Despite ongoing legal issues, Exxon is drilling its first wells at Point Thomson under the new plan of development. The company began in winter 2009 and continued this winter.

The potential rewards of the program are huge. Under the various opinions for the field, Point Thomson could bolster the existing oil pipeline, justify construction of a gas pipeline or become a regional hub for development of the eastern North Slope.

With existing facilities, Point Thomson could even possibly be used to tap oil from the coastal plain of the Arctic National Wildlife Refuge, also known as the 1002 area, without having to touch the surface of the often-debated federal plot to the east of Point Thomson.

And as always with Point Thomson, interesting clues remain.

In June 2009, Exxon announced that it would partner with TransCanada on a state-sponsored natural gas pipeline from the North Slope to southern markets, and the plan those companies submitted to the state includes a gas pipeline from Point Thomson.

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