Providing coverage of Alaska and northern Canada's oil and gas industry
November 2017

Vol. 22, No. 47 Week of November 19, 2017

The Producers 2017: A new plan for Exxon at Point Thomson

State official require the company to file revisions to plan to expand condensate production

Eric Lidji

For Petroleum News

ExxonMobil Alaska Production Inc. started production from the Point Thomson unit in April 2016 after decades of deliberation and litigation and years of construction. And as this edition of The Producers was going to print, a new debate was emerging at the unit.

Earlier this year, the local subsidiary of the global energy giant reluctantly proposed a plan to expand condensate production at the eastern North Slope unit and to deliver the resulting gas to the Prudhoe Bay unit. Although the company would prefer to sell its gas through a “major gas sale” associated with a pipeline project, it detailed a plan to expand condensate production, as required under the terms of a 2012 settlement with the state.

But in late August 2017, state Division of Oil and Gas Director Chantal Walsh denied the expansion plan, giving Exxon until the end of October 2017 to submit a suitable revision.

The point of contention was a clause that subjected the eventual sanctioning of the expansion project to “commercial negotiations and a decision to fund,” according to the state, meaning that the working interest owners could ultimately decide not to proceed.

In its proposal, Exxon planned to quintuple its processing facilities, to build a new natural gas pipeline between Point Thomson and Prudhoe Bay, and to drill three new development wells and convert two existing injectors into production wells. The larger facilities would require an expansion of an existing drilling pad at the unit and scrapping portions of the Initial Production System that the company brought online in April 2016.

Under the terms of a development plan submitted to the state in late June 2017, Exxon said it would spend the next two and a half years advancing permitting, design and engineering work and commercial negotiations in order to have a detailed project to submit to its partners for a final decision about sanctioning in late 2019. The company noted that the work it was describing in the plan was not a commitment to the project.

Even so, according to the plan, an Exxon project team has already been studying ways to leverage existing permitting and design work toward the project, has met with the U.S. Army Corps of Engineers to describe the new project and has started negotiating the commercial agreements needed to connect the Point Thomson and Prudhoe Bay units.

According to the state, though, any plan for expanding condensate production is governed by the terms of the 2012 settlement, which requires the company to “begin engineering and permitting” during the 2017-2019 plan of development cycle, and requires any plan to include “work plans for evaluation and selection of an option for development.”

IPS shortcomings

The plan of development Exxon submitted earlier this year included elements pertaining to the existing Initial Production System, as well as the proposed expansion project.

The state accepted the newest plan of development for the Initial Production System but accused the company of failing to meet several commitments outlined in the settlement.

First, condensate production from the Initial Production System at the Point Thomson unit is below an agreed-upon target of 10,000 barrels per day. Condensate production has reached 10,000 barrels on specific days since Exxon brought the unit into production in April 2016, but average daily production over that time has remained short of the goal.

According to the state, the company blamed the shortfall on “difficulties with its gas injection compressor.” In a technical meeting with the state, officials from the company “provided additional detail about the compressor and its design flaws and difficulties in relation to this reservoir,” and told division staff “it was conducting maintenance or repairs on the compressor during periods when production ceased or decreased.”

“Exxon did provide an extensive explanation of its problems with the compressor and the Division remains hopeful that those problems are now resolved and that Exxon will soon meet its production rate obligation,” Walsh wrote in the August 2017 decision.

Second, the state said that the Initial Production System plan of development failed to propose any debottlenecking work, as required under the terms of the settlement.

Third, the state said that Initial Production System plan of development failed to address a proposed East Pad and associated wells, as required under the terms of the settlement.

Expansion plans

If the issue of committing to work is resolved, the actual plan will likely satisfy.

Under its plan, Exxon would expand Point Thomson facilities to handle peak production greater than 50,000 barrels of condensate per day and would deliver 920 million cubic feet per day to Prudhoe Bay along a new 32-inch pipeline running 62.5 miles between the two units. The gas shipments would be used to enhance oil recovery from the Ivishak reservoir at the Prudhoe Bay unit, where Exxon is the largest working interest owner.

The proposed scope of the expansion project, particularly the gas deliveries, “reflects preferred operation during the period of injection into Prudhoe Bay while also installing necessary infrastructure for a potential (major gas sale),” Exxon wrote in its plan.

To accommodate the desired increase in production, Exxon would drill two new production wells from the Central Pad at the Point Thomson unit and one new disposal well, and it would convert the PTU-15 and PTU-16 injection wells to production. The existing PTU-17 well would remain on production, for a total of five production wells.

The additional processing equipment, wells and pipeline connections would likely require an expansion at the southwest corner of the 50-acre Central Pad, according to Exxon.

The expansion system would be able to use a “majority” of the existing Initial Production System utilities, but most of the existing processing facilities would be “mothballed.”

The Initial Production System currently produces condensate and natural gas from three Point Thomson wells, cycles the gas back into the Point Thomson reservoir and delivers the condensate to the trans-Alaska oil pipeline along the Point Thomson Export Pipeline.

The system can cycle some 200 million cubic feet of gas per day through the reservoir and ship 10,000 barrels of condensate per day. In its most recent plan of development, Exxon claimed that the system briefly exceeded both of those figures on Dec. 20, 2016.


Point Thomson is one of the oldest stories on the North Slope.

The original leases were issued around 1965. Exxon discovered oil in the area in 1975 and natural gas in 1977 and formed the Point Thomson unit later that same year.

Exxon and other companies had drilled 17 wells at the unit by 1983, and the results of those wells spawned a debate about the best way to develop the field. Specifically, the company and the state disagreed about the benefits of producing condensate or gas.

Believing Point Thomson was ready for development, the Alaska Department of Natural Resources put the unit into default in 2005 and terminated the unit in late 2006.

The decision launched several years of lawsuits between the state and the company. A court-ordered settlement in early 2012 created a timetable for Exxon to bring the Point Thomson unit into production by early 2016 and for expanding development later.

The Initial Production System was the first part of that timetable. The expansion project is the second part. A future North Slope gas pipeline project remains uncertain.

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