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Exxon submits PTU plan New development plan calls for condensate, oil to be produced before natural gas By Kay Cashman Petroleum News
On Feb. 19 ExxonMobil filed a plan with the State of Alaska to develop the Point Thomson Unit, drilling the first of five wells next winter and producing the first oil and condensate via a small-scale gas cycling project by the end of 2014. Point Thomson lies on and offshore the North Slope, east of Prudhoe Bay on the western edge of the Arctic National Wildlife Refuge’s coastal plain.
The filing, which was done by Exxon on behalf of the eastern North Slope unit’s working interest owners, is an attempt to convince the commissioner of the Department of Natural Resources that unit termination is not the best solution for the owners’ failure to meet previous drilling commitments.
Point Thomson leases were unitized in 1977, the oldest leases in the unit dating back to a 1965 state oil and gas lease sale. The last well drilled into the unit’s main reservoir, Thomson Sand, was more than 22 years ago.
In a previous plan of development, filed in 2001 by unit operator Exxon, the company promised to begin Point Thomson development drilling by June 15, 2006, and complete a total of seven wells by June 15, 2008. The state wanted initial production to be condensate and oil because not re-injecting the natural gas via a cycling project first would result in the permanent loss of “tens to hundreds of millions of barrels of oil and condensate,” per the Alaska Oil and Gas Conservation Commission. (AOGCC is the agency responsible for preventing waste and insuring greater ultimate recovery of oil and gas resources in the State of Alaska.)
Point Thomson’s main reservoir is a high-pressure gas condensate reservoir, meaning all of the fluids are in a gaseous state until they are brought to the surface. Point Thomson’s condensate is high quality and has lighter weight components such as natural gas liquids, gasoline and kerosene, with very little heavy oil, which makes it more valuable than the heavier Prudhoe Bay oil. In a gas cycling project, the gas would be produced and the liquids stripped from the gas and shipped down the trans-Alaska oil pipeline. The gas would be re-injected for a later sale, when a gas pipeline has been built to take North Slope gas to Outside markets.
Drilling commitment not met Exxon did not drill any of the seven wells it committed to in 2001, which eventually resulted in termination of the unit by DNR and a 2007 legal battle in Alaska Superior Court where the Point Thomson owners contested DNR’s decision.
On Dec. 27, Judge Sharon Gleason ruled that DNR acted properly when it rejected Exxon’s 22nd plan of development for the Point Thomson unit.
But the judge directed DNR to give the Point Thomson owners one last chance to come up with an “appropriate remedy” — an alternative to unit termination — by holding a DNR administrative hearing. Deadline to file their version of an appropriate remedy for not meeting drilling commitments was 5 p.m., Feb. 19, the day Exxon filed its new plan of development on behalf of itself and the other Point Thomson working interest owners, BP, Chevron and ConocoPhillips.
At a March 3 hearing scheduled by DNR, the companies will have the opportunity to present oral arguments about their new plan to DNR Commissioner Tom Irwin and his hearing officer, Nan Thompson, an attorney who currently serves as petroleum manager for DNR’s Division of Oil and Gas, and who used to chair the Regulatory Commission of Alaska.
Foerster loves new plan What’s most interesting about the new plan is that it calls for a small-scale gas cycling project that produces 10,000 barrels of oil and condensate per day — a far cry from the 60,000-75,000 bpd that was part of previous plans and discussions between the Point Thomson owners and the state, but nonetheless a major concession by the owners.
Until 2004, Point Thomson owners submitted development plans that called for producing the liquids first and re-injecting the natural gas into the reservoir — i.e. gas cycling. In 2004, Exxon and its partners submitted a unit plan that said gas cycling was economically risky and proposed producing the natural gas first, stalling field development until a natural gas pipeline was built.
Cathy Foerster, one of three AOGCC commissioners, is pleased with Exxon’s proposal for Point Thomson development.
“It is the DNR’s decision to make, but I love this plan. It’s good oil field practice. It prevents waste and encourages more ultimate recovery,” she told Petroleum News Jan. 20.
“It’s a small-scale modular project … that can be increased … by adding more modules,” she said. “It’s a test to test the concept. The owners contend there is so much uncertainty that can only be answered with production. They say they need production to see if there is reservoir continuity — they need production to test all the things that could make or break a big project.”
In working with the Point Thomson owners since August 2007 regarding pool rules, Foerster said she has been “pretty blunt with them.”
The owners, she said, have been essentially telling the State of Alaska, “we don’t want to risk our money with gas cycling, but we’re willing to risk your resource.”
If Exxon had proposed to “go into an immediate blowdown (produce gas first), they’d put a larger resource (condensate, oil) at risk forever. … Technically I love this plan,” Foerster said. Exxon proposes to spend $1.3 billion In its new plan, Exxon proposes to begin “a multi-year development and delineation drilling program” in the 2008-09 winter season, spending approximately $1.3 billion on drilling, building production facilities, pipelines and support infrastructure between now and “anticipated” startup by the end of 2014.
In more than one place in its plan, the company refers to its new plan of development as a “firm commitment to drill wells and begin commercial production.”
Exxon describes its plan as “a phased production approach” that includes a “minimum of five wells to further delineate and develop the Thomson Sand reservoir and other hydrocarbon reservoirs” in the unit, specifically evaluating and testing the oil rim that lies below the natural gas in the Thomson Sand. It also proposes to evaluate the Pre-Mississippian and the Brookian “in one or more potential accumulation areas — either Flaxman, Iceberg or Calloway.”
All wells will be designed to be used as producers and injectors if viable, the company said.
Exxon’s plan includes development work for initiating gas sales from the unit, allowing “individual PTU owners … to participate in an open season for a gas pipeline” to Outside markets that the company says “is at least a decade away.”
According to the plan, Point Thomson owners looked at both a large-scale and a small-scale development, electing to go with a “phased development plan” because it would “establish production and revenue prior to gas sales.” It would also “test the key areas of uncertainty,” which Exxon said are:
• Evaluation of the characteristics and performance of the reservoir “to determine subsequent development options,” which could include “gas injection expansion” (gas cycling expansion) “and/or gas sales; and
• Technology “qualification and implementation,” including “key challenges” such as high-pressure gas operations, high-pressure gas separation, extended reach drilling into “abnormally pressured formations, and “high rate” gas well production.
Gas sales conceptual engineering will take place “in parallel with engineering work for the initial production system,” Exxon said.
Two new gravel pads Production facilities will be built at the existing central Point Thomson PTU-3 exploratory gravel pad to minimize environmental impact, and the first two wells — “the central injector and producer wells” for the initial production system — will be drilled to the northwest of PTU-3 and to the southeast of PTU-3, respectively.
A disposal well at PTU-3 is also planned.
The plan also includes two new gravel pads which will be built in the western and eastern areas of the field for delineation wells on those areas.
“Drilling from the western pad will target the Thomson Sand gas and oil legs and the Brookian,” Exxon said. Where “practicable” wells will penetrate the Pre-Mississippian,” the company said. Exxon described the area “west of PTU-1” as an area of the field with “uncertainty as to structure, facies and reservoir rock quality.”
The plan “allows drilling toward the western syncline (graben) and other western targets, including potential horizontal trajectory well bores in the oil column.”
Drilling from the eastern pad will also target the Thomson Sand, including the eastern extent of the oil rim and the Brookian. As with the western area delineation drilling, eastern pad drilling will evaluate structure contacts and facies, including potential horizontal trajectory well bores in the oil column.
Viable wells will be tied back to the central production facilities at PTU-3, the company said.
The initial production system will “be designed to produce at a gas offtake rate of 200 million cubic feet per day,” which will yield the 10,000 bpd of liquids. The processed gas will be compressed and re-injected.
Exxon says “gas production at this level may be achieved from a single production well in the high pressure Thomson Sand reservoir.”
Liquids will be separated and stabilized at the central processing facility, then shipped through a new 22-mile, eight- to 12-inch pipeline to the Badami Unit pipeline tie-in for delivery to the trans-Alaska oil pipeline.
The central processing facility at Point Thomson “will consist of two trains capable of processing 100 million cubic feet and 5,000 barrels per day.”
Other infrastructure will include camps, utilities, a warehousing facility, in-field roads and an airstrip.
The initial production system is not dependent, Exxon said in its plan, on the construction of a permanent off-lease road. Point Thomson pool rules Exxon said in its plan that “a key regulatory requirement” for Point Thomson development is obtaining approval for pool rules from AOGCC. As part of that process, confidential technical data has been shared with the agency via a data room, a process Exxon anticipates being complete by the end of 2008, when a request for pool rules will be submitted by the company.
The data room also provides AOGCC information that is “relevant to gas sales,” Exxon said.
“To ensure owners are able to individually participate in an open season process for a gas pipeline, approval of necessary pool rules to authorize the desired gas offtake rate for the gas depletion development plan will be requested,” Exxon said, noting that the submittal will be “timed so the conservation order could be issued prior to the open season.”
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