State rejects Point Thomson expansion plan
The Alaska Division of Oil and Gas has denied ExxonMobil’s plan to expand the Point Thomson North Slope gas project because it doesn’t live up to a prior settlement between the state and the company, according to Director Chantal Walsh.
In a detailed six-page letter dated Aug. 29, Walsh wrote to ExxonMobil Alaska Vice President Cory Quarles that the Point Thomson Expansion Project Planning Plan of Development, or POD, is far too vague and offers no commitment that the company will live up to the 2012 Point Thomson Settlement Agreement.
Separate from but related to the Expansion Project POD, the division parsed out and approved the Initial Production System POD despite the company not meeting production expectations of natural gas condensates at Point Thomson because of technical challenges.
ExxonMobil submitted a single Point Thomson POD to the state on June 30, but division officials determined it contained two PODs because the 2012 settlement does not spell out what the company must do with its current infrastructure at the large eastern Slope gas field after this year. The settlement does, however, direct the company to start expanding production at Point Thomson by 2019 under one of several scenarios.
PODs are submitted annually by the unit operator company for every oil and gas unit in the state. They detail the company’s work plan for the coming year. The plans are generally adhered to but not strictly enforced by the state if unforeseen factors, such as changes to a project’s economics from external market forces or technical challenges, arise, Walsh noted.
But in the unique case of Point Thomson, development is prescribed by the settlement, which the Division of Oil and Gas considers to be a contract with the state, meaning its terms must be upheld regardless of extenuating circumstances, according to Walsh.
The Point Thomson Settlement, reached under former Gov. Sean Parnell, ended years of litigation between the state and the company in which the state argued ExxonMobil had not fulfilled its responsibility to develop the leases it held for many years. It also set a course for ExxonMobil to develop Point Thomson and start production by May 2016.
The field was discovered in 1977.
ExxonMobil, which operates Point Thomson, and BP, its primary working interest owner partner, spent roughly $4 billion developing the gas field since 2012. Production started in late April 2016.
Gov. Bill Walker, who’d lost to Parnell in the Republican primary in the 2010 governor’s race, promptly sued the state over the settlement in 2012 on the grounds that the settlement over state assets was reached in private negotiations and was not in the best interest of Alaska residents.
He withdrew his appeal to the Alaska Supreme Court in February 2015 shortly after taking office.
Last year Walker’s administration deemed the Prudhoe Bay Unit POD incomplete until BP, as unit operator, and the state reached an agreement that the company would provide more information on its efforts to further the Alaska LNG Project in future PODs.
ExxonMobil outlined its plans to move gas from Point Thomson and inject it into the Prudhoe Bay oil and gas pool as a way to further enhance oil recovery from the large oil field. The reinjection of gas produced during oil production efforts at Prudhoe has been a primary driver behind BP’s ability to extract more than 30 percent more oil — currently about 12.5 billion barrels in total — from the massive field than was expected when it came into production 40 years ago.
Production facilities at Point Thomson would first be expanded to handle production of more than 50,000 barrels per day of the diesel-like condensates and 920 million cubic feet per day of gas.
The current Point Thomson facilities have a production capacity of about 10,000 barrels of condensates and 200 million cubic feet of gas per day.
Moving gas to Prudhoe is one of the options for expanding Point Thomson under the settlement in the event major gas sales — the Alaska LNG Project — was not sanctioned by mid-2016.
While the Alaska Gasline Development Corp. continues to advance the gasline project, it is still uncertain if it will be built.
With an estimated 8 trillion cubic feet of natural gas, Point Thomson holds about a quarter of the gas needed to feed a large gasline; the rest is in the Prudhoe Bay pool.
Point Thomson is one of the highest pressure producing gas fields on Earth, at about 10,000 pounds per square-inch. A positive of the reservoir pressure is that it makes separating the condensates, or natural gas liquids, from the gas much easier.
According to ExxonMobil officials, the liquids essentially “fall out” of the gas once the pressure is relieved. Those liquids are then fed into the Trans-Alaska Pipeline System. The natural gas has so far been reinjected into the Point Thomson reservoir.
Getting the gas from Point Thomson to Prudhoe would require construction of a 62.5-mile, 32-inch diameter gas pipeline between the fields and production would be ramped up with the drilling of three new wells, according to the plan of development.
The two wells now used for gas injection would also be converted to production.
Specifically, Walsh points to the wording the company used in its Expansion POD to justify her ruling.
The POD states that before expansion planning can proceed, the working interest owner companies at Point Thomson and Prudhoe must sign a commercial agreement and fund the work, and according to Walsh, ExxonMobil confirmed that in a technical meeting with division officials.
Company representatives said further that it had “not even approached the Prudhoe working interest owners to begin these discussion, but surmised that the Prudhoe working interest owners were aware of the need for an agreement,” Walsh recalled in her letter.
She noted that BP, ExxonMobil and ConocoPhillips collectively own 99 percent of both fields — Chevron holds 1.6 percent of Prudhoe — and therefore Exxon was, in part, waiting to negotiate with itself.
ExxonMobil corporate spokesman Aaron Stryk wrote in an email that, “We have been, and continue to be, in full compliance with the Point Thomson Settlement Agreement. We are aware of the letter from the Department of Natural Resources, but have not yet reviewed the letter, so we are unable to comment.”
Walsh further emphasized that the need for a commercial agreement is not part of the settlement and the lack of one should not prevent Exxon from continuing expansion planning.
“The POD conditions all FEED (front-end engineering and design) work — the work that the Settlement Agreement requires the Point Thomson Unit WIOs to conduct during this POD period — on whether the WIOs decide to fund the work. Exxon prefaces its discussion of FEED by stating, ‘if funded FEED would progress…’ and then proceeds to refer to activities it ‘would’ do, rather than activities it will do,” Walsh wrote.
“The division questioned Exxon about this language to determine if it was intentional or merely inartful wording. Exxon confirmed at the technical meeting that the WIOs did not intend to proceed with any Expansion Project Planning work unless they both decide to fund the work and enter a commercial agreement for Prudhoe Bay Unit injection. Again, the division understands the importance of the commercial agreement, but it is not an impediment to complying with the Settlement Agreement.”
She continued: “This proposed POD would allow the WIOs to decide that they would rather not pay for planning, and then Exxon would perform no work. This proposed POD would also allow the WIOs to not enter an agreement with themselves for Prudhoe Bay Unit injection, and then Exxon would perform no work.”
Walsh additionally contended that the plan does not comply with the settlement because it is far too vague to be an adequate POD. The Settlement Agreement requires the plan to include the number of wells, their locations and other plans for completion of expansion, while Exxon simply stated it would drill three new wells on the Central Point Thomson pad, without identifying the wells’ targets or completion plans, she wrote.
Similarly, it states Exxon expects to file for permits to do the work with little more detail.
“Scheduling time to apply for permits is not a plan for acquiring them,” Walsh wrote.
She summarized her displeasure with the company by writing that the “POD fails to paint even the most impressionistic picture of what Exxon will do over the next year and a half to engineer and permit an expansion project.”
“The proposed Expansion Project Planning POD fails to provide for Exxon to fulfill this contractual obligation. The proposed POD includes conditions that would give the Point Thomson Unit WIOs control to avoid doing any planning work, effectively nullifying this portion of the Settlement Agreement,” Walsh concluded.
Appeals to Oil and Gas POD rulings usually go to the Department of Natural Resources Commissioner; however, the Settlement Agreement nullifies the administrative appeal and sends Point Thomson disputes directly to the Alaska Superior Court, according to Walsh.
ExxonMobil has until Oct. 13 to submit a revised Point Thomson Expansion POD.
ExxonMobil met its first big deadline at Point Thomson by starting condensate production and natural gas cycling in April 2016. Since then, however, the company has had difficulty meeting the 10,000 barrels per day of condensates production threshold called for in the 2012 Settlement Agreement with the state.
ExxonMobil noted in its proposed Point Thomson POD that production exceeded 10,000 barrels of condensate and 200 million cubic feet of natural gas on Dec. 20, 2016.
Yet, Walsh wrote the company has not met its obligation because production levels have fluctuated wildly in the year-plus since the project came online.
According to Alaska Oil and Gas Conservation Commission data, Point Thomson produced 47,972 barrels of natural gas condensates in April 2016, but that fell to just 7,903 barrels for the entire month of May. Production was then ramped back up to hit 213,845 barrels in December, to average about 7,000 barrels per day for the month.
Production then peaked in January with a daily average of 7,634 barrels, but fell again in June to a total of 8,400 barrels for the month, or just 280 barrels per day.
In July, Point Thomson produced an average of 1,738 barrels per day of natural gas condensates.
The production fluctuations stem from problems ExxonMobil has had with the gas compressor it uses to reinject the natural gas back into the reservoir, according to Walsh’s letter.
“During the technical meeting, Exxon provided additional detail about the compressor and its design flaws and difficulties in relation to this reservoir. By Exxon’s account, it was conducting maintenance or repairs on the compressor during periods when production ceased or decreased,” she wrote.
The company also acknowledged a requirement to pursue, but has not identified work, to “debottleneck” the Initial Production System, as it is directed to in the Settlement Agreement, Walsh noted.
Finally, ExxonMobil has not advanced permitting for an East Pad and associated wells at Point Thomson — another requirement of the deal — beyond what it had done at the time the settlement was reached, she continued.
Walsh wrote that the Oil and Gas Division is “hopeful” the company can resolve the technical issues with the IPS and sustain production at 10,000 barrels per day and the division appreciates its consideration of debottlenecking work.
“While the division remains concerned about the future of the IPS, the proposed POD does generally provide for continued production, which is a benefit to the state. Unitized production like this generally conserves resources, minimizes environmental impacts, and prevents waste,” Walsh summarized. “The proposed POD does not create additional impacts to the land. Thus, despite the division’s continued concerns, the division hereby approves the IPS POD for the period Sept. 30, 2017, through December 31, 2019.”
Elwood Brehmer can be reached at email@example.com.