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Division of O&G approves Point Thomson POD
Two-year plan says compression improvements underway; one update completed, more updates in works; goal is 10,000 bpd production Kristen Nelson Petroleum News
The Alaska Department of Natural Resources’ Division of Oil and Gas has approved the 2020-21 Point Thomson unit plan of development.
In a Nov. 7 approval letter, acting division Director Tom Stokes said while Point Thomson operator ExxonMobil Alaska Production has so far been unsuccessful in consistently producing 10,000 barrels per day of condensate from the field, as described in the 2012 Point Thomson unit settlement agreement, the division “believes EMAP is diligently working to resolve the production reliability issues” and so finds the 2020-21 POD “necessary and advisable to protect the public interest.” Stokes also said the division appreciates the company’s “continued efforts to consider LNG opportunities and willingness to share information about those efforts.”
The 2020-21 POD was submitted Oct. 2 and covers two years: Jan. 1, 2020, through Dec. 31, 2021.
ExxonMobil and BP are the major working interest owners at Point Thomson
Production began in 2016 In its POD ExxonMobil said the company constructed the Point Thomson initial production system from 2012-16 and began production in 2016. The high-pressure gas cycling project utilizes “industry-first reciprocal injection compressors,” the company said, with condensate separated from gas and the gas compressed and reinjected into the reservoir. The condensate is transported through the Point Thomson Export Pipeline for delivery to the trans-Alaska oil pipeline. The IPS is designed to cycle 200 million cubic feet of gas per day and deliver up to 10,000 barrels per day of condensate for sale.
The field has three active wells, with gas and condensate produced from the PTU 17 well on West Pad and the PTU-15 and PUT-16 on Central Pad used for gas reinjection. The field also has a class 1 disposal well used for produced water and gray water disposal, the company said.
From Jan. 1, 2018, through July 31, 2019, condensate production averaged 5,200 bpd, a total of 3 million barrels delivered for sale during that period, with maximum monthly average production of 10,700 bpd in December 2018. Gas production averaged 96 million cubic feet per day for the period, with 93 million reinjected into the reservoir and the remaining used as fuel gas to support unit operations. Maximum monthly average production of 199 million cubic feet per day was in December 2018.
Reliability issue ExxonMobil said that in the current reporting period the field “experienced issues related to its gas injection equipment, which is based on leading edge technology designed to handle gas reinjection at the high pressures of the Point Thomson reservoir.”
It said they were working with the equipment manufacturer “to investigate potential reliability improvements using existing equipment and modifications to improve future performance” and had “designed and procured a modified component” for use in the Point Thomson gas injection systems.
The first of the new components was installed in July, the company said, and remaining equipment has been ordered and is expected to be received and installed during the POD period.
Alaska Oil and Gas Conservation Commission records show an uptick in condensate production, presumably following installation of the new component, with a July average of 4,201 bpd (30 days of production during the month), an August average of 3,345 bpd (21 days of production) and a September average of 5,038 bpd (30 days of production).
These volumes are still down from the year’s high of 9,674 bpd on March.
ExxonMobil said it is also upgrading lubrication systems at Point Thomson “and continuing to optimize operations and maintenance practices to further increase reliability and reduce downtime.”
“Reliability of production has been an ongoing concern because of reported issues with gas injection equipment,” Stokes said in the division’s approval letter. He said the 2012 Point Thomson unit settlement agreement “requires the IPS to have an objective of a minimum of 10,000 barrels of condensate per day,” and while the average for the reported period was 5,200 bpd, he noted that the company “reports that additional work to improve reliability of gas injection has been completed and more new components will be installed,” with design and installation of the first of new components occurring in July.
Major gas sales A major gas sale was a premise of the 2012 Point Thomson settlement agreement.
In 2018 the Point Thomson Unit Letter Agreement made some modifications.
The 2012 settlement defined an Alaska LNG project as including a gas treatment plant, large diameter pipeline, liquefaction facilities, marine terminal and required transmission pipelines and other facilities to liquefy Alaska North Slope natural gas for export and also providing natural gas for in-state deliveries, and said the project must be one advanced by the state, a state-owned project such as the Alaska Gasline Development Corp., a public corporation and government entity as defined in statute or an entity in which a state-owned entity holds a controlling equity share.
The Sept. 10, 2018, letter agreement suspended “dates, deadlines, terms, conditions, undertakings, commitments, submittals, and obligations,” required biennial PODs for Point Thomson which would address “ongoing IPS or other unit exploration, development, and operations, including activities in furtherance of the Alaska LNG Project” as described in the 2012 settlement agreement.
The extension provided in the 2018 letter agreement “shall continue until DNR provides notice to all parties to the Settlement Agreement that either: (1) there is a Final Investment Decision on an Alaska LNG Project; or (2) work on the Alaska LNG is no longer progressing.”
If DNR issues a suspension notice - declaring that work on the Alaska LNG project has stopped - the Point Thomson unit working interest owners “will resume work on the suspended portions of the PTU POD.” The unit owners would then have 30 months to commit to a Point Thomson unit expansion or sanction a major gas sale.
The 2012 settlement agreement had a deadline at the end of 2019 for sanction of a Point Thomson expansion if a major gas sale wasn’t sanctioned by June 2016. There was agreement on an expansion plan in late 2017 - requiring increase of Point Thomson condensate production to 30,000 bpd or moving natural gas to Prudhoe Bay for reinjection.
MGS report In its POD, ExxonMobil lists steps the unit owners and operator took in 2018 and 2019 to promote and support a potential MGS project, including:
*Confidentiality agreement to allow disclosure of information to AGDC in connection with an Alaska LNG project;
*Sharing with AGDC information related to design and routing of a gas transmission line from Point Thomson to Prudhoe;
*Confidential discussions with AGDC and potential partners on financing and/or investing in MGS project;
*Two Point Thomson owners (BP and ExxonMobil) provided funding, technical support for permitting for Alaska LNG; and
*Unit owners continued evaluation of technical feasibility of potential MGS projects.
“The PTU owners anticipate undertaking appropriate planning and activities to position the Unit for an MGS consistent with AGDC progress on the Alaska LNG project,” ExxonMobil said. “These activities will be based on prior work done by the PTU operator to prepare for an MGS,” with timing and scope “dependent upon the MGS project milestones and activity.”
A preliminary list of long-range activities required to ensure alignment with an Alaska LNG project include:
*Coordinate design activities, execution of unit well development to “deliver the MGS project design volumes over time.”
*Coordinate design activities, execution to “efficiently meet the MGS project design rate and gas specification.”
*Progress Point Thomson permitting associated with MGS to achieve MGS startup milestone.
*Progress commercial agreements, well planning, engineering, permitting to support MGS.
ExxonMobil noted that the 2018-19 POD anticipated work activities related to Point Thomson expansion. Consistent with the letter agreement that work was suspended in September 2018. “However, the technical and commercial work streams were brought to a position where they could be quickly resumed in connection with an expansion project,” the POD says.
Reservoir management ExxonMobil said that to date reservoir performance at Point Thomson has been in line with expectations, with “no indications of reduced reservoir connectivity or capacity since production commenced.”
Dry gas is reinjected for pressure maintenance, to aid condensate recovery and conserve gas for future development, the company said. “No other EOR efforts are planned through 2021.”
The company said the IPS central pad processing facilities have produced production in excess of design rates of 200 million cubic feet of cycled gas and 10,000 bpd of condensate. “The gas injection compressors have demonstrated the ability to operate at maximum design capacity based on facility performance data.”
The 2012 settlement agreement provides that after IPS startup, unit “owners shall identify and pursue debottlenecking work to increase the capacity of the installed facilities,” the POD says.
The unit operator “reviewed debottlenecking opportunities with the assistance of an independent engineering contractor” during the 2018-19 POD, ExxonMobil said, including a review of operating parameters “such as separator pressures and hydraulic limits, but no significant debottlenecking opportunities were identified to increase capacity beyond those possible with current facilities, wells, and operations.”
When fully operational, the company said, “the facility has consistently produced greater than” the 200 million cubic feet per day design rate.
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