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Producers 2024: Hilcorp major North Slope producer
Operates Prudhoe Bay, Point Thomson, Endicott; owns and operates Northstar and Milne Point; adding Nikaitchuq, Oooguruk Kristen Nelson Petroleum News
Hilcorp came to Alaska in 2011 with acquisitions in Cook Inlet, becoming an operator there in 2012, and began working on the North Slope in 2014, acquiring BP Exploration (Alaska)'s working interest in the Duck Island and Northstar units, and 50% of BP's interest in Milne Point, where Hilcorp took over as operator.
In mid-2020, with finalization of a sale announced in 2019, Hilcorp took over BP's remaining North Slope assets, including its interest in Prudhoe Bay, where Hilcorp became operator. The acquisitions included BP's remaining 50% interest in Milne Point and its interest in Point Thomson, where ExxonMobil holds the majority working interest. Hilcorp Alaska took over as operator at Point Thomson in 2022, with ExxonMobil retaining its majority working interest.
Prudhoe Bay The unit at Prudhoe Bay, Alaska's largest oil field, was formed in 1977, following the discovery of oil in the Ivishak and Sag River sandstones in 1968 at Prudhoe Bay State No. 1 and currently includes 254,235 acres. Hilcorp took over as operator of the Prudhoe Bay unit on June 30, 2020, after acquiring BP Exploration (Alaska) from the Standard Oil Co. and changing the name to Hilcorp North Slope.
The share of Prudhoe that Hilcorp acquired from BP is not the largest in the unit. Information on the Alaska Department of Natural Resources' Division of Oil and Gas website shows Hilcorp with an average working interest of 26.36% at Prudhoe, while ExxonMobil Alaska Production holds 36.4%, ConocoPhillips Alaska 36.08% and Chevron U.S.A. 1.16%.
Alaska Oil and Gas Conservation Commission production data for September, the latest available when this section of The Producers was compiled, show Prudhoe averaging 246,803 barrels per day, 55.08% of Slope production, with 81.57% of that volume from crude oil and 18.43% from natural gas liquids. Compared to September 2023, Prudhoe production was up 3.31% this September.
There are 12 participating areas at Prudhoe, with drilling activity largely focused in the Initial Participating Areas -- the oil rim PA and the gas cap PA -- and in the newest development area, the western satellites.
Prudhoe IPA In its April 2024 initial participating areas plan of development, covering July 1, 2024, through June 30, 2025, submitted to the Division of Oil and Gas April 1, Hilcorp North Slope said development began in the IPA in 1968 with the Prudhoe Bay State No. 1 exploration well, with regular production beginning in June 1977 and the beginning of produced water injection that same month, followed by large-scale waterflood for secondary recovery in August 1984 and use of miscible gas for water-alternating-gas injection for tertiary recovery in June 1987.
In its May 2024 approval of the 2024 POD for the IPA, the division said IPA production for calendar year 2023 was some 2,759 billion cubic feet of gas, 53.62 million barrels of black oil and 16.56 million barrels of natural gas liquids -- with the NGLs mixed in with and sold with the black oil.
Daily production in 2023 averaged 146,906 barrels of black oil and 45,355 barrels of NGLs, down from 2022 daily averages of 156,487 barrels of black oil and 48,507 barrels of NGLs.
During calendar year 2023, 827 producers (up from 825 in 2022) and 213 injectors (unchanged from 2022) contributed to production in the IPA, Hilcorp said in its proposed IPA 2024 POD.
"Fluid handling and production in 2023 were affected by significantly increased levels of planned maintenance and downtime compared to 2022," the company said.
IPA 2023 POD Hilcorp had anticipated drilling up to 38 wells in the IPA during the 2023 POD.
The division said that by the April 23, 2024, technical meeting on the 2024 POD, Hilcorp had drilled only 11 wells, nine coil tubing drilling sidetracks and two grassroots wells, with five more scheduled to be drilled by the end of the 2023 POD June 30, 2024.
Hilcorp said in the 2024 POD that the difference was "primarily rig scheduling and availability" and told the division in the technical meeting that the deviation in drilling "was due to not securing an additional CTD rig" and said it anticipated that a second CTD rig would be operational in the IPA by mid-June 2024.
Workovers were completed on an as-needed basis during the 2023 POD, Hilcorp said, with six IPA wells worked over and five more planned by the end of the 2023 POD period.
The company said non-rig well interventions remained relatively high in 2023, with some 426 IPA wells experiencing interventions "excluding annular communication work and subsidence drifts," with most of the work aimed at maintaining well stock or increasing production through enhancements.
Large facility projects included CCP compressor upgrades, GC2 B-Bank slugcatcher internals redesign, Drill Site 18 pipeline construction and H Pad pipeline construction.
IPA 2024 POD During the 2024 POD Hilcorp said it planned "a continued increase in drilling activity" with up to 36 IPA wells "dependent upon rig availability, rig utilization within the PBU, an economic viability."
The company said it has continued to work through the backlog of broken IPA wells and anticipates a reduction in workovers in 2024.
Flat well intervention activity is anticipated.
Major facility projects include the 2024 scope of the CCP compressor upgrades, CCP air inlet housing replacement, FS-2 de-oiler and Eileen West End pipeline.
Prudhoe Western Satellites The Prudhoe Western Satellites are the fields' newest development area.
There are five participating areas in the Western Satellites: Aurora, Borealis, Midnight Sun, Orion and Polaris, with Aurora, Borealis and Midnight Sun producing primarily from the Kuparuk River formation and the Orion and Polaris PAs producing from the Schrader Bluff formation.
Development began at Aurora in 2000, with production starting that year, water injection in 2001 and miscible gas for water-alternating-gas, WAG, injection for tertiary recovery in late 2003.
Borealis development began in 2001 with production that same year, water injection in 2002 and a pilot project for miscible injectant for WAG in 2004 for tertiary recovery.
Midnight Sun development began in 1997 with production in 1998, water injection in 2000 and miscible injectant in 2016.
Orion development began in 2001 with production startup in 2002, water injection in 2003 and Prudhoe Bay MI for WAG for tertiary recovery in October 2006.
Polaris development began in 1997 with production in 1999, water injection in 2003 and Prudhoe Bay MI for WAG used briefly in 2006 and then beginning in 2009 for tertiary recovery.
Western Satellites 2025 POD Hilcorp North Slope's proposed 2025 POD for the Western Satellites, covering calendar year 2025, submitted to the division Oct. 2, breaks out 2023 calendar year production by PA, with Orion accounting for 49.52% of the area's 13.953 million barrels of oil, followed by Polaris at 18.66%, Borealis at 18.32%, Aurora at 11.12% and Midnight Sun at 2.4%.
In its Nov. 27, 2023, approval of the 2024 POD for the western satellites (the division's decision on the 2025 POD had not been released when this issue of The Producers was completed), the division said Hilcorp had completed 14 new drill wells during the 2023 POD, with another four pending, out of its proposal to drill up to 26 new wells and do four rig workovers. The division said the company deferred drilling the remaining wells as it "turned its focus to the drilling of other wells within the PBU based on production efficiency and economics." Hilcorp said this October it had completed five additional wells by the end of the 2023 POD period.
Hilcorp had completed one new well to date under the 2024 POD, with an estimated four pending execution, and said Western Satellite drilling was reduced from the proposed activity of up to 19 wells "due to alternative opportunities identified in the Oil Rim and Gas Cap Participation Areas."
There were also workovers and recompletes of four wells at Aurora and three at Borealis.
Major facility projects under the 2024 POD included beginning construction of the Eileen West End Twin Pipeline Phase 1.
During 2025 Hilcorp said it anticipates completing seven wells, with up to eight additional possible at Orion "depending on rig availability."
Major facility work includes expected completion of the EWE LDF Twin Pipeline Phase 1 and various projects at Gathering Center 2.
The company will also be evaluating new pad development options in 2025, including permitting for construction of Omega Pad, and is evaluating additional pipelines to reduce header pressure and increase gas lift pressure at four pads: L, V, W and Z.
Opportunities for polymer flood and foam WAG flood in the Schrader Bluff formation are being evaluated, along with a project to improve injected water quality to increase injectivity and oil recovery.
Greater Point McIntyre area The Alaska Division of Oil and Gas approved the 2024 POD for the Greater Point McIntyre area Aug. 22, covering Oct. 1, 2024, through Sept. 30, 2025.
GPMA includes six participating areas, the division said: Combined Niakuk, Lisburne, North Prudhoe Bay, Point McIntyre, Raven and West Beach. Initial production from GPMA began in 1986 with Lisburne producing from the Wahoo and Alapah formations.
Combined Niakuk, West Beach, North Prudhoe Bay and Point McIntyre began producing between 1993 and 1994. West Beach produced briefly in 2009, but West Beach and North Prudhoe Bay have been shut-in since 2000 and 2001, respectively.
Point McIntyre and Combined Niakuk produce from the Kuparuk River formation.
Raven began production in 2005 from the Ivishak and Sag River formations. There are also tract operation wells.
The division said GMPA produced 10.333 million barrels of oil and NGLs between April 1, 2023, and March 31, 2024, a slight decline from the same period in the previous year.
Hilcorp had committed to drilling six wells at the GMPA during the 2023 POD period, the division said, including five coil tubing drilling sidetracks and one rotary well at Raven, however no drilling was completed within the GMPA during the 2023 POD period.
The division said sidetracks were deferred in favor of work elsewhere in Prudhoe, while the Raven well was "deferred due to issues following warming up the rig from cold stack," with that well deferred to the four quarter of 2024 or the first quarter of 2025.
No workovers were planned, but the company told the division two were expected to be completed before the end of the 2023 period.
The 2022 POD also saw no wells drilled, although three wells planned for the 2022 POD were drilled in the 2021 POD period after the 2022 POD was submitted, the division said.
Hilcorp said that since taking over operatorship at GPMA, it "has focused on returning the wells to service, optimizing production through the existing surface infrastructure while investing in capacity-expanding and debottlenecking projects, targeting reservoirs that had been under-developed, improving voidage replacement and optimizing the water and MI floods, improving operational efficiency and drilling new sidetracks from underperforming wellbores."
The company's proposed 2024 POD program includes two rotary wells at Raven, and four potential CTD sidetracks at Point McIntyre, a rotary well at Lisburne and two track operation wells targeting the Brookian.
Hilcorp has a list of long-range activities at GPMA evaluating development potential, including in the Brookian; in the Lisburne; in the Niakuk Kuparuk; in the Point McIntyre Kuparuk, Sag River and Ivishak; potential of existing tract operations and other Sag River accumulations offsetting Raven; and continuing to evaluate facility debottlenecking projects.
Milne Point Hilcorp Alaska acquired a 50% working interest in the Milne Point unit from BP Exploration (Alaska) and became operator in 2014. In 2020 Hilcorp acquired BP's remaining assets in Alaska, including the other 50% of Milne, and became 100% working interest owner at the unit.
Milne Point is the largest of the North Slope units in which Hilcorp has 100% or at least a majority working interest ownership and is where the company has had the greatest impact, almost doubling production.
Milne Point development began in the 1980s under Conoco, with Alaska Oil and Gas Conservation Commission production data showing a 0.7 million barrel total for 1985, rising to 7.5 million barrels by 1991, and then dropping to 6.8 million barrels in 1993.
BP took over in 1994, with production at 6.7 million barrels for the year, and grew that to a peak of 20.4 million barrels in 1998, with production leveling off in the range of 18.8 million to 19.7 million barrels per year through 2004, and then dropping off to 7.1 million barrels by 2014.
Hilcorp has been growing Milne Point production since it took over as operator -- growth reflected in the 43rd plan of development for the field which the company filed with the Alaska Department of Natural Resources' Division of Oil and Gas in mid-October.
In its recent PODs Hilcorp has reported average production per day for the calendar year to date based on when the POD is submitted -- Jan. 1 through Sept. 30 for PODs submitted in mid-October.
For the POD submitted in 2021, Milne production averaged 35,757 barrels per day; for the 2022 POD, the average was 37,466 bpd, up 4.78% from the previous year. In 2023 the average was 39,944 bpd, up 6.61% from the previous year, and the most recent POD, using 2024 volumes, shows an average of 43,474 bpd for that same period, up 8.84%.
*43rd POD
Milne produces from the Kuparuk reservoir in the Kuparuk participating area, the Schrader Bluff reservoir in the Schrader Bluff PA and the Sag River reservoir in the Sag River PA. There are also multiple wells on tract operation production.
In the 43rd Milne POD, Jan. 13, 2025, through Jan. 12, 2026, Hilcorp said it anticipates drilling 19 rotary wells, with 18 potential candidates in the Schrader Bluff formation -- half producers, half injectors -- and one in the Kuparuk producer.
The company also expects to do coiled tubing drilling operations on three wells.
It will continue to use the ASR1 rig for well work and workovers "as required to maintain and enhance production."
Major facility projects include H Pad power fluid separation; return gas injection to F and L pads through existing gas injection lines; L and H pad polymer expansion; return water injection to K Pad; CFP A train internals upgrade; and CFP PL 5 upgrade.
Long range the company said it continues to evaluate additional Schrader Bluff drilling opportunities; evaluate performance from the existing S-203 and planned S-204 Ugnu wells to help determine future Ugnu development; evaluate infill drilling opportunities in the Kuparuk formation; and target facility upgrades to increase the production capacity of the unit.
*42nd POD
In the 42nd POD Hilcorp said it originally anticipated drilling 20 wells, and then amended that to 24, with the majority Schrader Bluff wells, and two Kuparuk formation wells and two Ugnu formation wells being considered.
The company said in its Oct. 14 POD submittal that it has drilled 16 of the wells with an additional six anticipated to be completed by the end of the POD period Jan. 12.
Fifteen of the wells drilled to date are in the Schrader Bluff formation, seven producers and eight injectors, with an additional five -- four producers and one injector -- anticipated to be completed by the end of the 42nd POD.
One Kuparuk formation well was drilled, a horizontal producer, and one Ugnu well was anticipated to be drilled by the end of the POD period.
Hilcorp said it anticipated coiled tubing drilling operations on six wells and six, five producers and one injector, were drilled.
There were no planned workover operations, but 20 workovers were completed with an additional 12 planned before the end of the POD period.
Hilcorp said not all of the facility projects anticipated during the 42nd POD have been completed, but two -- E Pad power fluid separation and reactivation of the D Pad transmission line to B Pad -- are expected to be completed before the end of the POD period, while two others are expected to be initiated during the 42nd POD and continued through the 43rd POD -- H Pad power fluid separation and return of gas injection to F and L pads through existing gas injection lines.
Three unanticipated projects were begun under the 42nd POD and will be completed before the end of the period: Solar Titan 130 power generation install at L Pad; CFP B-Train internals upgrade; and J Pad polymer injection expansion.
Operations that deviated from or did not conform to the 42nd POD include R Pad Drillsite construction; CFP 3rd train oil separation; Solar Titan 130 power generation install at L Pad; CFP B Train internals upgrade; and J Pad polymer injection expansion.
Point Thomson Hilcorp Alaska's most recent North Slope operatorship is at Point Thomson, the most easterly of the Slope units. The company took over from ExxonMobil Production, developer of the field, effective Jan. 1, 2022, following agreement by working interest owners in October 2021 and regulatory approval by the state.
ExxonMobil retains its majority working interest in the field, 62.36%. Hilcorp has a 36.99% working interest, with others holding a combined 0.65% interest.
The Point Thomson unit was approved in 1977, although sustained production did not begin until 2016 following litigation resulting in the 2012 PTU Settlement Agreement, modified in September 2018 by the PTU Letter Agreement which provided, among other things, for the biennial PODs.
The September 2018 letter agreement is focused on an Alaska LNG Project and suspends work on evaluation and selection of a PTU expansion project -- a requirement of the 2012 PTU Settlement Agreement -- until the Department of Natural Resources provides notice to all parties in the agreement that either there is a final investment decision on an Alaska LNG Project, or work on the Alaska LNG Project is no longer progressing.
A final investment decision for an Alaska LNG Project would require Point Thomson owners to provide work plans and project activities to develop the reservoir for major gas sales. If, on the other hand, the LNG project is suspended, owners would have 30 months to resume work on suspended portions of the settlement agreement, including a Point Thomson expansion project.
*Point Thomson POD
Point Thomson differs from other units in that its plans of development cover two years.
The most recent plan, submitted by Hilcorp in October 2023 and approved by the division in December 2023, covers calendar years 2024 and 2025.
Hilcorp said the initial participation area at Point Thomson consists of the Thomson reservoir, with gas and condensate produced from the PTU-17 well on West Pad and the PTU-15 and PTU-16 on Central Pad used for gas reinjection.
In reporting on the previous POD, for 2022-23, Hilcorp said no drilling was planned during that period.
Condensate production from Jan 1, 2022, through Aug. 30, 2023, averaged 7,300 barrels per day, with 4.4 million barrels delivered to the trans-Alaska pipeline during that period, while gas production averaged 130.3 million cubic feet per day, with 126.3 million cubic feet per day reinjected and the remainder used as fuel gas for unit operations.
For the 2024-25 POD, Hilcorp said it anticipated reviewing and evaluating internal data for "Area F" of the PTU.
Area F, the state said in its approval, was created by terms of the 2012 settlement agreement and requires submittal of a POD for Area F.
Jade Energy LLC acquired a working interest in a portion of Area F, ADL 343112, in 2018 and submitted a POD in late 2018. The division said that while Jade is not a party to the settlement agreement, the division determined that the Jade POD satisfied the obligation in the settlement agreement, although the settling parties retain an "obligation to maintain an approved POD for Area F or relinquish the acreage."
The Jade POD is on hold pending an agreement with the Alaska Department of Natural Resources and the division. (See coverage of Area F issues in Petroleum News, most recently in April of 2024.)
*PTU production issues
In the 2024-25 POD Hilcorp proposes continuing production from current facilities.
The company said it "anticipates that current oil and gas production from the PTU will be maintained in line with historical decline."
The most recent AOGCC production figures, for September 2024, show Point Thomson averaging 4,678 barrels per day, down from an early peak of 10,725 bpd in December 2018. The facility's rated capacity is 10,000 bpd.
Hilcorp told the division it would continue to evaluate drilling opportunities at Point Thomson, and said that, pending results of internal review, it would convert injector PTU-15 to production.
The company evidently tested this possibility, as AOGCC production data show that in September 2023 Point Thomson production was from the PTU-15, rather than the PTU-17.
In discussing long-range potential at the field, Hilcorp noted declining production from PTU-17 and said "current operable wellstock at Point Thomson is unable to cycle 200 MMSCFD gas and fill the IPS facilities to capacity"
Filling the IPS to capacity would require additional wells, and the company said it "will continue to evaluate drilling opportunities during the 2024-2025 POD Period."
Duck Island The Duck Island unit, Endicott, is one of the smaller fields Hilcorp Alaska operates on the North Slope, an offshore producer with a causeway connecting the main production island and the satellite production island to shore. Endicott accounted for less than 1% of North Slope production in September 2024 at 4,168 barrels per day, the latest month for which Alaska Oil and Gas Conservation Commission production data was available when this issue of The Producers was finalized.
In its Jan. 8, 2024, approval of the latest plan of development for Duck Island, the 42nd, the Alaska Division of Oil and Gas said the unit was formed in 1978. It was developed by BP Exploration (Alaska). Hilcorp, which took over BP's interest in 2014, holds 74.24% working interest and is operator; Chevron USA holds the remaining 25.76% working interest.
In its November 2023 POD submittal for the 42nd POD, Hilcorp said Duck Island unit production is associated with the Kekiktuk reservoir in the Endicott participating area, the Ivishak and Sag River reservoirs in the Eider PA and the Sag River reservoir in the Minke tract operation.
Hilcorp said 2023 production from Jan. 1 through Sept. 30 averaged 5,588 bpd.
Endicott is one of three areas on the North Slope -- along with Northstar and Prudhoe Bay -- with natural gas liquids production. For September 2024, AOGCC data show total Endicott production averaged 4,168 bpd, 95% of that crude and 5% NGLs, with the total down 32.94% from September 2023.
In its current POD, covering Feb. 13, 2024, through Feb. 12, 2025, Hilcorp said long-range development activities include converting "LSZ of Kekiktuk to gravity drainage to increase oil production" and exploring the unit for "remaining Ivishak and Alapah opportunities."
The company said a grass roots well is planned, MPI 2-72, with a second, MPI 2-74, possible dependent on results from the first well. AOGCC records show both wells permitted, with MPI 2-72 completed in July 2024, although AOGCC September production data do not yet show any production from MPI 2-72.
For the previous 41st POD, Hilcorp completed eight rig and non-rig wellwork operations and a number of surface facility operations.
Northstar Northstar is the newest of the North Slope units Hilcorp Alaska took over from BP Exploration, formed in 1999, with four state leases and three federal leases jointly managed by the Alaska Division of Oil and Gas and the federal Bureau of Safety and Environmental Enforcement.
The discovery well was drilled in 1984 by Shell. BP began island construction in the winter of 1999-2000, with regular production beginning in late 2001.
The 5-acre manmade gravel island in the Beaufort Sea is 6 miles offshore, connected to onshore processing facilities by a pipeline.
Hilcorp acquired BP's 100% working interest in Northstar in 2014 in the same deal that gave it BP's share of Endicott and 50% of BP's interest in Milne Point.
The current POD for Northstar, as with Duck Island, covers Feb. 13, 2024, through Feb. 12, 2025.
There are three oil sand accumulations: Ivishak in the Northstar participating area, Ivishak in the Fido PA and Kuparuk in the Hooligan PA.
Northstar is one of three North Slope units reporting both crude and natural gas liquids production to the Alaska Oil and Gas Conservation Commission -- and has the largest percentage of NGL production of the three.
For September, the latest month for which Alaska Oil and Gas Conservation Commission production data was available when The Producers went to print, Northstar averaged 5,159 barrels per day, 52.61% of that in crude, 2,714 bpd, and 47.39% in NGLs, 2,445 bpd, with the total down 2.93% from September 2023.
*19th, 20th PODs
Hilcorp said no grass roots wells, no sidetracks and no workovers were planned in the previous, 19th POD, and while the company did not drill any wells or sidetracks, it did half a dozen workovers, including recompletions, re-perforations, adding perforations and began work on converting an Ivishak producer to gas injection.
Planned facilities work included completing commissioning remaining heat pipes in a ground refrigeration expansion project and continuing repair of the island's coastal defenses; Hilcorp said both projects have been completed.
In the 20th POD, approved by the division in January, Hilcorp said it would explore downdip water injection in the Kuparuk reservoir and review potential coil tubing drilling candidates and determine if CTD "operations are economically viable, or even mechanically feasible, on Northstar Island."
No drilling or workover operations are planned, but surface work includes modifying surface equipment to allow produced water to be routed to the NS-19 well, expanding existing gas lift systems and continuing to repair coastal defenses.
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