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Division of O&G approves variety of PODs
2024 plans OK'd for several Cook Inlet units operated by Hilcorp, Cook Inlet Energy, and ConocoPhillips Alaska's Colville River Kristen Nelson Petroleum News
The Alaska Department of Natural Resources' Division of Oil and Gas has posted approvals for a number of annual plans of development.
Most were for work in Cook Inlet, including Ivan River, Lewis River, Pretty Creek, Redoubt and West McArthur River.
The largest unit to gain recent POD approval is ConocoPhillips' Colville River unit on the North Slope.
Colville River ConocoPhillips Alaska's 2024 Colville River unit POD, approved April 16, is effective May 16 through May 15. 2025.
At the CRU, the division said, production averaged 35,136 barrels per day during the 2022 calendar year, dropping by 3% to an average of 34,177 bpd in 2023.
AOGCC production data for March, the most recent month available, show Colville averaging 37,098 bpd, 7.7% of North Slope production, up 3.2% from February and up 4.3% from March 2023 when the field averaged 35,581 bpd.
In the 2023 POD, ConocoPhillips drilled and completed five wells in the Narwhal PA at CD4: two injectors and three producers; drilled and completed a producer in the Fiord West Kuparuk PA; anticipated spudding Titan 1 within Fiord West Kuparuk PA; began drilling an exploration well from CD5 to test a Brookian Nanushuk interval; drilled two wells at GMT2 to reinject gas; completed four rig workovers at CD3; competed seven scale inhabitation treatments at the Alpine Pool; converted CD4 to seawater injection; and completed a new fiber optic line installation from CFP2 to ACF and replaced some two-thirds of the seawater import pipeline.
AOGCC records show the agency approved the drilling permit for the Colville River Unit Titan 1 development well Feb. 21. ConocoPhillips planned to spud the well in the first quarter of the year.
For the 2024 POD, the division said ConocoPhillips planned:
*Continued drilling at Titan 1 within the Fiord West Kuparuk PA;
*Continued drilling on the CD5-32X exploration well from the CD5 pad, with plans to acquire "a comprehensive suite of wireline logs and core, and pending positive logging and core results with respect to fluid phase and fluid contacts within the reservoir, the vertical well will be fracture stimulated and tied into the CD5 facilities for extended production testing;"
*Drilling one producer in the Nanuq Kuparuk PA;
*Continued scale inhibition treatments;
*Continued planning for the CD8 pad; and
*Continuing forward with multi-year projects to upgrade and replace fire and gas systems and instrument control and safety systems across the field.
Ivan River On May 8 the division approved Hilcorp Alaska's POD for the Ivan River unit, a westside onshore Cook Inlet unit formed in 1967 by Standard Oil Company of California and taken over by Hilcorp from Union Oil Company of California in January 2012. The division said that over the life of the unit, through the end of March this year, it produced 96.502 billion cubic feet of natural gas.
Production was 2.245 million cubic feet in calendar year 2023, down from 3.602 million cubic feet in calendar year 2022.
In March of this year, the most recent month for which Alaska Oil and Gas Conservation Commission data are available, the field averaged 2.426 million cubic feet per day, 1.2% of inlet production in that month.
During the 2023 POD, June 1, 2023, through May 31, 2024, Hilcorp upgraded the facility from mobile to permanent compression, the division said, and installed three packages for solids knock out, but did not upgrade the water disposal system.
During the 2024 POD, Hilcorp's plans include:
*Maintaining production from the Sterling-Beluga and Tyonek participating areas and continuing to use IRU disposal wells;
*Evaluating recompletion, perforation adds and rig workovers to existing wells;
*Reviewing and evaluating opportunities for delineation wells;
*Doing pad and facility work which would support "drilling efforts for potential grassroots well in 2025";
*Installing a coalescer for the compressor; and
*Doing necessary routine repairs and replacement to maintain production.
Lewis River Lewis River is an onshore westside Cook Inlet gas field, the division said. The unit was formed in 1977 by Cities Service Oil Co. and Hilcorp took over as operator from Union Oil Company of California in January 2012 the division said May 8 in approving the 2024 POD.
From inception through March of this year the Lewis River unit produced 17.235 billion cubic feet of natural gas.
AOGCC data show Lewis River produced 278.31 million cubic feet in 2023, up from 261.72 million in 2022. In March, the most recent month for which AOGCC data are available, Lewis River averaged 1.54 million cubic feet per day, 0.8% of inlet gas production in that month.
The division said Hilcorp brought the LRU C-02 well online during the 2023 POD, June 1, 2023, through May 31, 2024, with initial production of 2 million cubic feet per day from the Tyonek and Beluga sands and installed a line heater and a separator to accommodate production from the well.
Hilcorp's plans for the 2024 POD include:
*Continuing to evaluate drilling of delineation wells within the Sterling-Beluga and Tyonek participating areas;
*Evaluating potential coil cleanout operations and additional Sterling or Beluga perforations;
*Maintaining production; and
*Installing a coalescer for the Lewis River compressor.
Pretty Creek On May 8 the division approved both a 2024 Pretty Creek POD and a POD for Pretty Creek gas storage.
Pretty Creek is a westside onshore Cook Inlet gas field. The division said the unit was formed in 1997 by Union Oil Company of California and Hilcorp became operator in January 2012. Through March of this year the field has produced 9.617 billion cubic feet of gas.
Production ceased in August 2019, the division said, and Hilcorp began work to restore production.
AOGCC data show the field produced 2.08 million cubic feet of gas in 2022, with production in only two months of that year, January and August. In 2023 the field produced 1.25 million cubic feet, with production in just the last five months of the year.
In the 2023 POD, June 1, 2023, through May 31, the division said Hilcorp replaced the reboiler to support unit operations. No delineation or exploration activities were planned.
For the 2024 POD, the division said Hilcorp didn't commit to any specific exploration or delineation activities, but "is evaluating the possibility of drilling up to two development wells targeting Sterling, Beluga and Tyonek sands," in addition to uphole recompletions, additions of perforations and rig workovers.
The Pretty Creek gas storage POD covers the same period.
Both the 2023 and 2024 PODs committed to continuing use of the Pretty Creek gas storage lease for gas storage operations.
In the 2024 POD, Hilcorp plans to continue evaluating installation of a secondary compressor at the Pretty Creek Pad "to allow production down to lower pressures at the surface," but has not determined timing as it "is contingent on the results of native gas production projects in the PC-2 well or any future drill wells" the division said. Hilcorp also plans improvements as needed.
Redoubt On April 16 the division approved the 2024 POD for Cook Inlet Energy's Redoubt unit, covering May 1, 2024, through April 30, 2025.
CIE became operator in December 2009.
Production from Redoubt averaged 440 barrels of oil per day and 114 thousand cubic feet of gas per day from March 1, 2023, through Jan. 31, 2024, the division said, a 47% reduction compared to the comparable period in 2022-23.
AOGCC data show cumulative production through March of this year as 5.99 million barrels of oil and 2.784 trillion cubic feet of natural gas.
During the 2023 POD, the division said CIE replaced failed ESPs in two wells, RU-5B and RU-7B and conducted acid stimulations in both, but an attempt to replace the failed ESP and workover on the RU-2A was unsuccessful. In the 2023 POD period the company "completed a reservoir study and updated the unit's geological and reservoir models and completed the ILI on the subsea pipeline."
The company has been unable to develop the unit's northern and southern fault blocks because of capital constraints and because efforts were redirected toward replace the RU-7B ESP. The company did not flow test the RU-9 well.
In the 2024 POD, CIE's plans include:
*Exploring enhancing production;
*Evaluating retrieving fish, replacing failed ESP in RU-2A well;
*Evaluating effectiveness of acid stimulation of RU-5B;
*Wireline operations on injection wells as needed;
*Flow testing RU-9 well; and
*Survey and inspection of sub-sea lines.
West McArthur River In an April 16 approval of the 2024 POD for Cook Inlet Energy's West McArthur River unit, the division said the unit was formed in July 1990 and includes two participating areas, Area #1 and the Sword PA. CIE became operator in December 2009. As with Redoubt, the 2024 POD period for West McArthur River is May 1, 2024, through April 30, 2025.
AOGCC data show cumulative West McArthur River production through March of this year of 16.09 million barrels of oil and 4.08 trillion cubic feet of natural gas.
The division said that from March 1 2023, through Jan. 31, 2024, West McArthur production averaged 696 barrels of oil per day and 171 thousand cubic feet of natural gas, a 138% increase compared to the comparable period in 2022-23.
In reviewing work in the 2023 plan, the division said CIE sought partners for the Sabre prospect, but "Current capita constraints and lack of involvement from other investors prevented the development of the Sabre project."
CIE did perform acid stimulation work on and replace failed ESPs in the WMRU-28 and Sword-1 wells, completed the free water knock out project, converted WMRU-8 to a disposal well, updated the unit's geological model and completed in-line inspections on the 3-phase 8-inch pipeline.
For the 2024 POD, CIE's plans include:
*Exploring ways to enhance production, manage decline and increase ultimate recovery from existing wells;
*Reduce costs on handling increasing water cuts through disposal and bring WMRU-08 online as a disposal well.
*Continuing to evaluate and update the unit geological model;
*Keeping Sabre open for development and seeking partners for that project;
*Continuing conversion of shut-in wells to produced water injectors through the free water knock out project; and
*In-line inspection on 4-inch crude line and replacement of first mile of 3-phase 8-inch which has higher corrosion risk.
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