Point Thomson unit operator ExxonMobil Alaska Production has submitted a two-year plan of development to the Alaska Division of Oil and Gas with continued focus on condensate production and providing information as needed for major gas sales projects.
ExxonMobil and Hilcorp North Slope are the major working interest owners at Point Thomson.
ExxonMobil told the division there were two changes in PTU ownership interests during the 2020-21 two-year POD: ConocoPhillips Alaska’s interest in the PTU was transferred to BP Exploration (Alaska) effective Nov. 1, 2019, and, effective June 30, 2020, Hilcorp Alaska acquired the shares of BPXA and the name of that entity was changed to Hilcorp North Slope.
The new POD, submitted Oct. 1, covers Jan. 1, 2022, through Dec. 31, 2023.
ExxonMobil said the POD provides a summary of operations and development work under the 2020-21 POD and plans for future development, including planning for a major gas sale. The proposal, the company said, is consistent with the Sept. 10, 2018, letter of agreement between the state and the PTU working interest owners (major WIOs then were ExxonMobil, BPXA and ConocoPhillips Alaska), and the March 29, 2012, settlement agreement between the state and the WIOs (major owners the same as in the 2018 letter of agreement).
The 2012 settlement agreement was the result of the state’s insistence that ExxonMobil and the other WIOs develop Point Thomson - or give up the leases. Leaseholders had long demurred, citing lack of a means to transport production. As a result of the settlement, ExxonMobil built a sales oil pipeline, linking Point Thomson to a pipeline built by BP to take Badami oil to connect with North Slope lines taking oil to the trans-Alaska oil pipeline.
ExxonMobil said the primary resource at Point Thomson is “natural gas with entrained condensate, contained within high pressure sands of the Thomson reservoir,” with the field primarily lying offshore under state water and land. There have been 22 wells drilled in and around the PTU since the early 1970s, the company said, with the Thomson reservoir representing some 25% of known and recoverable natural gas resources on the North Slope.
Initial production system
ExxonMobil said it constructed the initial production system, IPS, at Point Thomson in 2012-16. The IPS is a high pressure, 10,000 psi, gas cycling project, the company said, using “industry-first reciprocal injection compressors” with condensate delivered for sale.
Once condensate is removed from the gas, gas is compressed and injected back into the reservoir.
IPS infrastructure, wells and facilities were designed to cycle 200 million standard cubic feet of gas per day and deliver up to 10,000 barrels per day of condensate to the trans-Alaska pipeline through the Point Thomson Export Pipeline.
Three wells are active, two injectors on the Central Pad and a production well on the West Pad. There is also a class 1 disposal well used for produced water and grey water disposal, the company said.
For Jan. 1, 2020, through July 31, 2021, condensate production averaged 8,300 barrels per day, the company said, with a maximum monthly average of 9,600 bpd achieved in May 2020 and a total of 4.8 million barrels of condensate delivered to the trans-Alaska oil pipeline.
Gas production averaged 151.2 million standard cubic feet per day, with 147.2 million standard cubic feet per day reinjected and the remaining gas used as fuel gas in unit operations. In May 2020 a maximum monthly average production of 179.6 million standard cubic feet per day was achieved.
IPS reliability
In earlier years at Point Thomson, where production began in April 2016, there were reliability issues related to the gas injection equipment.
In the 2020-21 POD ExxonMobil said Point Thomson had “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,” and said the unit worked with the equipment manufacturer to identify potential reliability improvements and modifications. The unit “designed and procured a modified component for use in its gas injection system,” with the first of the new components installed in July 2019 and remaining equipment ordered for installation during the 2020-21 POD period.
ExxonMobil also said the unit “is upgrading the lubrication systems and continuing to optimize operations and maintenance practices to further increase reliability and reduce downtime.”
In its current POD, for 2022-23, ExxonMobil said the new components which were installed starting in 2019 “enabled significant reliability improvements in 2020 and 2021.”
Major gas sales
ExxonMobil said in its 2022-23 POD that as described in the 2018 letter agreement, the preferred development at Point Thomson is as a major gas sales project, “such as the Alaska LNG Project or the Qilak LNG Project,” and said the unit plans to continue evaluating “facility modifications and development activities necessary to support any viable MGS project.”
The company said that as PTU operator it has engaged in confidential discussions with the Alaska Gasline Development Corp. on the Alaska LNG Project, “to share knowledge in support of AGDC’s efforts to identify potentially viable commercial structures for the project and to identify further opportunities to improve the competitiveness of the project,” has provided support for Federal Energy Regulatory Commission permitting for the project and AGDC cost reduction studies and continues evaluating “the technical feasibility of required PTU facility modifications, including study of a potential option under which Alaska LNG would initially construct a pipeline from PTU to Fairbanks.”
ExxonMobil also said that as PTU operator it has engaged in confidential discussions with Qilak LNG “to discuss advancing mutual objectives under the Heads of Agreement signed by the parties in October 2019,” received periodic updates on the status of the Qilak LNG project feasibility studies and provided technical support and “conducted evaluations of the technical feasibility of various development scenarios, including assessments of PTU facility modifications and upgrades that would be necessary to supply the PTU gas to the project.”
ExxonMobil provided a list of long-range activities that would be required “to ensure continued alignment with either MGS project.”
Point Thomson expansion planning, required under the 2012 settlement, was suspended under the September 2018 letter agreement.
The company said no additional wells are planned during the 2022-23 POD period.
Reservoir management, facilities
ExxonMobil said reservoir management to date has met expectations, with no indications of reduced reservoir connectivity or capacity. No enhanced oil recovery efforts are planned through 2023.
Central Pad processing facilities have achieved production greater than the 200 million standard cubic feet per day of cycled gas and 10,000 bpd of condensate, the company said, and gas injection compressors have demonstrated “the ability to operate at maximum design capacity based on facility performance rates.”
The 2012 settlement agreement required a debottlenecking program after IPS project startup, the company said, and debottlenecking opportunities have been reviewed “with the assistance of an independent engineering contractor,” evaluating “operating parameters such as separator pressures and hydraulic limits, but no significant debottlenecking opportunities were identified to increase capacity.”
