The Producers 2018: Hilcorp dominates Cook Inlet production

Company operates nearly 20 fields spread across all four segments of the basin

Eric Lidji

for Petroleum News

Hilcorp Alaska LLC remains the dominant producer in the Cook Inlet basin. The local subsidiary of the Texas-based independent operates about 19 fields and units - a number that seems to fluctuate each year due to acquisitions, consolidations and terminations.

On the west side of Cook Inlet, Hilcorp operates the Ivan River, Lewis River, Pretty Creek and Beluga River units. Offshore, the company operates the North Cook Inlet unit, the Granite Point unit, the Middle Ground Shoal unit, the Trading Bay unit and the North Trading Bay unit and associated McArthur River field. In the southern Kenai Peninsula, the company operates the Ninilchik, Deep Creek and Nikolaevsk units. In the northern Kenai Peninsula, the company operates the Birch Hill unit, the Swanson River unit, the Beaver Creek unit, the Sterling unit, the Kenai unit and the Cannery Loop unit.

Offshore

Hilcorp is in the early stages of redeveloping the North Cook Inlet unit.

The company acquired the unit from ConocoPhillips Alaska Inc. in late 2016 and quickly asked the state for permission to extend an existing plan of development to June 2018.

A plan of development filed in April 2018 represents the first full plan from Hilcorp since it took over the unit and takes a measured approach to activities at North Cook Inlet.

Hilcorp is not planning any exploration or delineation activities at North Cook Inlet in the coming development year, which runs through May 2019. Instead, the company will launch a “comprehensive field study” to evaluate the remaining potential of the Beluga and Sterling sands and to determine the need for future wells, sidetracks and perforations.

The company intends to study the potential of developing deep oil prospects at North Cook Inlet. Previous operators and farm-in partners over the years have considered a similar venture at the field, but Hilcorp is going one step further by installing a subsea oil pipeline as part of its efforts to extend natural gas transmission across Cook Inlet.

The proposed program for the upcoming year includes work on the Tyonek platform that accesses offshore targets at North Cook Inlet. The program also includes a structural assessment in advance of planned upgrades to the rig and other infrastructure, preparation for upgraded living quarters, natural gas pipeline and oil pipeline work in advance of the Cook Inlet Pipeline Cross Inlet Extension Project and other transmission infrastructure.

Even without development work, Hilcorp expects production to be “maintained and enhanced” through the coming development year. The unit produced approximately 16.2 million cubic feet per day in 2017, up from 13.8 million cubic feet per day in 2016.

The production increase came despite the lack of drilling or workover activities at the unit last year. Hilcorp shot perforations into abandoned intervals at the A-03, A-09 and A-12 wells in the fall of 2017. Hilcorp subsequently opened the productive Sterling A and Stray sands at the A-09 well and identify the previously unproduced Sterling X sand.

The success of the perforation program convinced Hilcorp to cancel plans to add compression capacity at the associated Tyonek platform to increase production volumes.

To the southwest, Hilcorp is not planning any exploration or delineation at the Granite Point unit over the coming development year running through May 2019 but plans to use the results of its 2017 drilling program to identify future drilling opportunities at the unit.

The company expects Granite Point production to be “maintained or enhanced” over the coming year. The unit produces from three platforms: Granite Point, Anna and Bruce.

The Granite Point platform produced 311.1 million cubic feet of gas and 492,500 barrels of oil in 2017. The Anna platform produced 240 million cubic feet of gas and 276,400 barrels of oil in 2017. The Bruce platform produced 201.6 million cubic feet of gas and 110,100 barrels of oil in 2017. Adding those platform-level figures together, the Granite Point unit produced 752.7 million cubic feet of gas and 879,000 barrels of oil in 2017.

The unit produced 2,408 barrels of oil per day in 2017, down from 2,530 bpd in 2016.

Hilcorp drilled two sidetracks in 2017. The company completed the GP-11-24RD well to the C5 sand and completed the GP-24-13RD2 well to the C7 sand. A plan to sidetrack the MUCI-02 well to the C7 sand was set aside as more information became available.

The Granite Point unit was created in 2015 from the former South Granite Point unit and Granite Point field. The unit is associated with the Granite Point Production Facility.

Farther to the southwest, Hilcorp is planning a two-well and one-sidetrack program at the Trading Bay unit and associated McArthur River field in the year ending May 2019.

At McArthur River, the company plans to drill the M-22 well targeting the Grayling gas sands and the M-35 well and M-25L1 lateral targeting the upper West Foreland sand.

At the Trading Bay unit, the company plans to sidetrack the A-04RD well into the North Trading Bay unit, targeting the Hemlock and Tyonek G-zone sands. If successful, the sidetrack would be used to return the former North Trading Bay unit to production. The unit had previously produced from the now lighthoused Spark and Spurr platforms.

Going into the previous year at the McArthur River field, Hilcorp announced plans to drill as many as three new wells from the Steelhead platform targeting the upper West Foreland oil pool - M-35, M-36 and M-37 - four sidetracks from the King Salmon platform - K-06RD2, K-24RD3, K-03RD2 and K-26RD2 wells - and no workovers.

Instead, the company drilled no new wells, three of the four sidetracks and 15 unplanned workover operations spread across all four platforms at the field. The operations included completing wells, preparing for sidetracks, repairing pumps and adding perforations.

The company explained that the three sidetracks successfully targeted the upper West Foreland oil pool, which made the three proposed grassroots wells unnecessary. The company cancelled the K-26RD2 sidetrack based on the productivity of the existing well.

The field produced 1.703 million barrels of oil and 7.2 billion cubic feet of natural gas in 2017, down from 1.797 million barrels of oil and 8.5 billion cubic feet of gas in 2016.

Going into the previous year at the Trading Bay field, Hilcorp announced plans to sidetrack the A-04RD well at the Monopod platform. The work was postponed to the current year to allow for additional evaluation of existing seismic to define the target.

The company instead installed deep-set electric submersible pumps in the A-13 and A-18 wells at Monopod. The company credited the work with improving production rates.

Due east, Hilcorp operates four drilling platforms at the Middle Ground Shoal unit: the active Platform A and Platform C and the currently dormant Baker and Dillon platforms.

Although the company is not planning any drilling activities at any of the four platforms during the current development year, running through May 2019, the company is evaluating the economics of a plan to reactivate the drilling rigs on Platform A and Platform C. If approved, the company could begin drilling in the 2019 development year.

The company had originally planned to drill rotary sidetracks at the C-23-26RD, C-33/26RD and C-34-26RD wells at Platform C during the 2017 development year.

But the work was contingent on the results of an In-Line Inspection program on associated pipelines. The inspection program was required under the terms of a consent agreement with the U.S. Pipeline and Hazardous Materials Safety Administration following a disruption to fuel gas supply pipelines at the Middle Ground Shoal unit. The inspection led to several repair projects on two pipelines associated with the unit.

The three sidetracks were postponed because Platform C was shut-in during the year.

The Division of Oil and Gas approved the development plans for Platform A and Platform C but rejected the development plans for the Baker and Dillon platforms, citing the “lack of work” planned and the “lack of production” currently.

The unit produced 308,649 barrels of oil and 83.1 million cubic feet of gas in 2017, down considerably from 680,900 barrels of oil and 158 million cubic feet of gas in 2016.

West side

The future of the sub-region depends largely on the results of a “comprehensive field study” launched during the development year that ended May 31, 2018. The study remains ongoing, and the company has said that its preliminary results are confidential.

While the study could lead to renewed investment in the region, it could also presumably lead to lower investment. The state terminated the Stump Lake unit in late 2017 after Hilcorp determined that it was not feasible to return the suspended field to production.

The three smaller units in the region - Ivan River, Lewis River and Pretty Creek - have been in a holding pattern for years. Hilcorp did not drill any wells or sidetracks and did not conduct any workover operations at the three units during the 2017 development year, and it is not planning any development work at the units for the 2018 development year.

Ivan River unit production declined to 651,000 cubic feet per day in 2017 from 750,000 cubic feet per day in 2016, according to Hilcorp. The unit was formed in 1967, came online in 1990 and had cumulative production of 86.1 billion cubic feet through the end of 2017. The unit produced almost exclusively from the Tyonek participating area in 2017, with no production reported from the Sterling-Beluga Gas participating area. The IRU 14-31 and IRU 13-31 wells at the unit are currently used as regional disposal wells.

Lewis River unit production increased to 137 million cubic feet per day in 2017 from 128 million cubic feet per day in 2016, perhaps as a result of a new sand separator which was added upstream of the compressor on Lewis River 0lRD well during the year. The unit was brought into production in 1984 and had cumulative production of 15.4 billion cubic feet through the end of 2017. The unit produced exclusively from the Lewis River Gas Pool No. 2, with no production reported from the Lewis River Gas Pool No. 1 participating area.

Pretty Creek unit production was “intermittent and variable” in 2017 but only averaged about 28,000 cubic feet per day, according to the Division of Oil and Gas. The unit came online in 1986 and had cumulative production of 9.51 billion cubic feet through the end of 2017. The Pretty Creek unit produced exclusively from the Beluga participating area.

A storage operation injected 32 million cubic feet and withdrew 172 million cubic feet.

Just south of that cluster of units is the federally managed Beluga River unit, which remains an important link for regional electricity markets. Hilcorp operates the unit on behalf of partners Municipal Light & Power and Chugach Electric Association.

Hilcorp is not planning any drilling at the Beluga River unit during the current development year but is planning several undefined workover projects for later this summer. In its previous plan, the company made no firm drilling commitments and ultimately did not drill, focusing instead on overhauling seven compressors at the unit.

The unit produced 14.9 billion cubic feet in 2017, down from 17.4 billion in 2016.

Southern Kenai Peninsula

Hilcorp expects a reduction in its drilling activities at the Ninilchik unit, although a change in market conditions during the year could lead to a dramatic uptick in work.

The company plans to drill the Pearl No. 2A delineation well from a new drilling pad on private land outside of the unit. The well is scheduled for late in the development year, which runs through the May 2019. The well was deferred from the previous year.

According to Hilcorp, the results of Pearl No. 2A will likely require changes to the configuration of both the Ninilchik unit and the associated participating areas.

A field study of the Grassim Oskolkoff participating area in early 2018 identified six potential locations and a re-evaluation of the Blossom No. 1 exploratory well. The results suggested that the Blossom No. 1 well might have missed its target due to geologic faulting. Unless market conditions change, the company does not expect to drill the six Grassim Oskolkoff wells or sidetrack Blossom No. 1 during the current development year.

The company is planning a workover operation to return the GO No. 6 well to production and is considering workover projects on the Paxton No. 8, SD No. 6 and GO No. 7 wells.

The drilling program conducted in the recently completed year included an active program at the Kalotsa prospect and a series of stratigraphic wells at the Pearl prospect.

Hilcorp completed construction work on the Kalotsa drilling pad in 2017. The company brought the Kalotsa No. 1 and Kalotsa No. 2 wells into production in February and March 2017, respectively. Both wells have been producing from the Tyonek formation.

The company completed the Kalotsa No. 3 and Kalotsa No. 4 wells in August and September 2017 and said it had identified “significant potential” in the Beluga and Tyonek formations in both wells. But in response to what it considers to be a lack in near-term market demand, the company plans to “systematically identify unbooked/unproven sands in the lower Tyonek until demand warrants production from the larger sands.”

The Kalotsa program “allowed for reallocation and additions” of the Susan Dionne-Paxton participating area. The process began last year and carried into this year.

The company deferred the GO No. 9 well in favor of other projects and also deferred workover operations at several wells but completed a workover on the GO No. 8 well.

The Ninilchik unit produces from three participating areas and one tract operation.

The Falls Creek participating area produced between 2.5 million and 2.8 million cubic feet per day in 2017. The Grassim Oskolkoff participating area produced between 1.6 million and 3.65 million cubic feet per day in 2017. The Susan Dionne-Paxton participating area produced between 15.4 million and 18.7 million cubic feet per day in 2017. A tract operation from eight active wells in the Beluga and Tyonek pools produced 8 million and 8.9 million cubic feet per day in 2017. Combined, those production figures yield a range between 27.5 million and 34.05 million cubic feet per day in 2017.

Hilcorp also completed seven stratigraphic test wells in the Ninilchik unit area - Pearl No. 1A, Pearl No. 2, Pearl No. 3, Pearl No. 4, Pearl No. 5, Pearl No. 6 and Pearl No. 7 - between July and August 2017. The company used the test wells to design the Pearl No. 2A well and to begin the process of configuring the unit and the participating area.

In the current development year at the Deep Creek unit, running through July 2019, Hilcorp plans to complete all or some of the work left unfinished this past year.

The program was unfinished due to technical complications, according to the company.

The purpose of the program is to set forth new exploration targets, most likely in the Sterling and Beluga formations, in advance of the 2018 and 2019 drilling season.

The company had intended to complete four of six planned stratigraphic test wells in the vicinity of the unit by June 2017 but only completed two - DC SW 3 and DC SW 4. The company blamed the shortcoming on “unexpected high water flow rates from the Sterling Formation at shallow depths” from the two wells and on “unusually muddy conditions.”

Although the results of the two wells are confidential, Hilcorp told state officials that the limited program “significantly helped our exploration and development efforts.”

The scope of the upcoming program convinced state oil and gas officials to once again defer until May 31, 2019, a long-proposed contraction of the Deep Creek unit.

The company is currently considering a plan to access the two remaining well locations later this year, during the brief window immediately after freeze-up but before the first major snow. The company drilled the two previous wells in mid-October 2017.

The company also said it was progressing plans to drill at Middle Happy Valley and C Pad within the Happy Valley participating area but could not commit to the project “operational and economic risk associated with such exploratory efforts is reduced.”

The Deep Creek unit produced 5.94 million cubic feet per day from the Tyonek and Beluga formations in the Happy Valley participating area in 2017, down from 6.25 million cubic feet per day in 2016. The unit was formed in 2001, brought online in 2004 and had produced approximately 34.6 billion cubic feet cumulatively through 2017.

After years where Nikolaevsk unit operations were in a holding pattern, Hilcorp reported a significant increase in production last year as the result of fracture stimulation activities.

The company credits the stimulation of the Red No. 1 well in March 2017 with increasing natural gas production to 600,000 cubic feet per day in 2017, up from 154,000 cubic feet per day in 2016. The results were short lived. The well produced 232,000 cubic feet per day before the operation and 2.3 million cubic feet per day immediately following the operation. But production had fallen to 850,000 cubic feet per day by June 2017 and eventually to “pre-stimulation levels,” reaching 540,000 cubic feet day by March 2018.

Prior to conducting the operation, Hilcorp had estimated that the fracture stimulation would add between 1 million to 3 million cubic feet per day from the Tyonek formation.

Hilcorp generally produces at the Nikolaevsk unit intermittently during winter months and during periods of low market demand, which might explain the bump in early 2018.

In a plan of development submitted to the state in May 2018, Hilcorp did not propose any drilling or workover projects at the Nikolaevsk unit during the coming development year.

Northern Kenai Peninsula

The company is expecting a light year of development work at those units.

The company plans to drill between one and three new wells or sidetracks at the Swanson River unit during the current development year, which runs through March 2019.

The company listed one potential well, SCU 33-33RD, in its newest development plan and described the other two wells as “possible.” The company is also planning workover activities at two existing wells: SCU 322C-04 and SCU 44-04. (The Swanson River unit and Soldotna Creek unit were once separate administrative entities but have been managed together since 1963. Some well names still reflect those earlier designations.)

In addition to its drilling plans, Hilcorp is continuing a field study of the Hemlock formation at the Swanson River unit to identify remaining reserves, particularly in the Upper Hemlock. “The inventory of sidetrack candidates will be vital for economically reaching these smaller/less economic targets,” the company explained in its plan.

In its previous development year, running through March 2018, Hilcorp had initially planned to drill one well, SRU 241-33, and potentially four additional wells or sidetracks, and it had also planned to conduct workover activities at an existing well, SCU 44-33.

The company brought the SRU 241-33 well into production in September 2017 and reported cumulative production of 16.6 million cubic feet by March 2018. The company described the four additional wells or sidetracks as “not possible” during the year. The company ultimately cancelled its proposed workover activities at SCU 44-33, choosing instead to recomplete the existing SRU 32C-15, SCU 22B-04 and SCU 12B-09 wells.

The Swanson River unit produced 6.69 billion cubic feet of natural gas and 691,200 barrels of oil in 2017, entering the year at 4 million cubic feet and 1,850 barrels per day and finishing the year at 4 million cubic feet and 1,750 barrels of oil per day. The decline fell short of company goals to maintain or increase production through development.

To the southwest, Hilcorp is not planning any new wells at the Beaver Creek unit during the current development year but did propose a new sidetrack, BCU-05RD2. The company is also not planning any workover activities at the unit during the current year.

The company received an AOGCC permit for BCU-05RD2 on July 11, 2018. As of late September, AOGCC had not listed the well on its weekly “complete wells” list.

In its previous development plan, Hilcorp proposed no new drilling projects. The company initially proposed a workover project targeting Sterling B3 gas production at the BCU 25 well but later redirected the capital toward other projects in its portfolio.

The Beaver Creek unit produced 57,800 barrels of oil and 4.72 billion cubic feet of natural gas in 2017, according to figures provided by the company in the plan.

Farther to the southwest, Hilcorp is not planning any drilling or workover activities at the Kenai unit. In its plan for the previous development year, Hilcorp proposed as many as eight new wells at Kenai - four wells in the Deep Tyonek participating area, two wells targeting the Beluga/Tyonek gas pool, and as many as two additional unidentified wells or sidetracks. The company also proposed as many as 10 coil tubing workover projects, as many as 10 e-line recompletions and as many as five rig workover projects at the unit.

Hilcorp ultimately drilled three new wells during the year.

The company drilled the KBU 32-06 well into the D-4B interval of the Tyonek formation in April 2017. The well was producing 460,000 cubic feet per day in March 2018. The company drilled the KU 14-05 well into the D-6B interval of the Tyonek formation in May 2017. The well was producing 190,000 cubic feet per day in March 2018. The company drilled the KU 11-07X well into the D-3B interval of the Tyonek formation in August 2017. The well was producing 3.9 million cubic feet per day in March 2018.

Given the “exceptional results” of these three development wells and also “current gas market constraints,” Hilcorp deferred the three remaining wells in its proposed drilling program for 2017 as well as the 25 proposed workover operations to “future years.”

In the Cook Inlet basin, Hilcorp also operates the Birch Hill unit at the northern end of the Kenai Peninsula, but the U.S. Bureau of Land Management has yet to approve the plan for 2018. The previous development plan included a proposal to test an existing well at the unit in the hopes of returning it to production over a three-to-six-month period.