Through two expansive acquisitions and two targeted purchases over the past five years, Hilcorp Alaska LLC became the dominant producer in the Cook Inlet region.
The local subsidiary of the Texas-based independent currently operates some 20 units and un-unitized fields in the region. The number occasionally changes as the company consolidates operations. Considered geographically, those holdings can be divided into four informal groups: onshore west side, offshore, northern Kenai and southern Kenai.
While it is difficult to make a comprehensive assessment about a portfolio of that size, Hilcorp appears to be slowing its drilling and workover activities this year, after several years of considerable efforts to improve or restore production at aging oil and gas fields.
The current period of low oil prices could be partially responsible for any deferred investment at oil fields in the portfolio. Any slowdowns in activity at gas fields could be economic or could suggest that Hilcorp is already meeting current supply commitments.
Onshore west sideHilcorp operates five onshore units at the northern end of the west side of Cook Inlet: the Ivan River, Lewis River, Pretty Creek and Stump Lake units; and the larger Beluga River unit.
The first four of those are smaller units, with sometimes-spotty production history. In a recent development plan from March 2016, Hilcorp warned that the four small fields risk becoming marginally profitable under current economic and regulatory environment.
The Ivan River, Lewis River and Pretty Creek units are currently in production, although development activities have slowed in recent years. Hilcorp did not drill any wells or conduct any rig workover operations at the units in 2015 and planned none for 2016.
The Ivan River unit produced some 1.8 million cubic feet per day from the Sterling-Beluga Gas participating area and 1.2 million cubic feet per day from the Tyonek participating area in 2015, according to Hilcorp. By the start of 2014, the unit had produced 84.3 billion cubic feet, according to the Alaska Oil and Gas Conservation Commission. Ivan River produced some 700 million cubic feet that year and 400 million cubic feet in 2015, for a total of 85.4 bcf by the start of this year. The unit produced 200 million cubic feet in the first six months of this year - on pace with 2015 production.
A previous operator established a gas storage operation at the unit in 2011 but Hilcorp relinquished the storage lease last year because of damage to the IRU 44-36 well.
The Lewis River unit currently produces from one well. Hilcorp suspended a disposal well at the unit in 2015. By the start of 2014, the unit had produced 14.39 billion cubic feet, according to the AOGCC. The unit produced some 427 million cubic feet that year and 336 million cubic feet in 2015, for a cumulative total of 15.15 bcf by the start of this year. The unit produced approximately 89 million cubic feet during the first six months of this year, which suggests a notable decline from 2015 production levels.
The Pretty Creek unit produced some 300,000 cubic feet from the Beluga participating area in 2015. The unit includes a storage operation. Hilcorp injected 291 million cubic feet and withdrew 528 million cubic feet during 2015. The storage program complicates production reporting for the unit. According to AOGCC records, cumulative production “declined” from 9.54 billion cubic feet at the start of 2014 to 9.51 bcf at the end of June 2016, which suggests a balance of injection and withdrawals from the unit.
A previous operator suspended the Stump Lake unit shortly after gas production started in 1977. The unit produced from the 41-33 well from 1990 until 2000 and again from 2009 until 2012, when mechanical issues from a workover compromised production. The suspended unit had cumulatively produced some 6.6 billion cubic feet through June 2016.
A state-mandated program to swab the 41-33 well and add perforations if the swabbing failed to restore production failed to restore production. Hilcorp said it would study the feasibility of drilling a new well or conducting a rig workover to fix the problems with 41-33. If the company chose to go in that direction, the program would have to occur in winter to meet seasonal restriction in the surrounding Susitna Flats State Game Refuge.
Another possibility is to connect the Stump Lake unit to the Beluga River unit. “Hilcorp’s increased presence on the west side of Cook Inlet brings new opportunities to make rigs, equipment and manpower available to small-scale operations, such as the Stump Lake unit, that otherwise would not be economic,” the company told the state in a plan of development from March 2016. Without such “critical mass” of projects in the region, “the economic life of the Stump Lake unit has likely passed,” the company added.
While the loss of the Stump Lake unit would have little impact on the overall health of the Cook Inlet region, Hilcorp believes that the state of the small, marginal unit might be a sign of the times. Any development project at Stump Lake would “require substantial fiscal investment with declining economic returns. This situation will eventually spread to other legacy fields throughout Cook Inlet,” the company wrote. Hilcorp also urged state officials “to evaluate regulatory and policy changes that, going forward, will extend the useful life of similarly situated legacy fields while minimizing waste, maximizing existing infrastructure and promoting sound environmental and economic policy.”
Earlier this year, Hilcorp became operator of the Beluga River unit after ConocoPhillips Alaska Inc. sold its one-third working interest to Municipal Light & Power and Chugach Electric Association. The unit is historically one of the most important in the region, providing fuel that generates much of the electrical power used in the Anchorage area.
Beluga River is also one of the oldest fields in the region. When ConocoPhillips filed the 53rd plan of development for the unit in May 2015, it called the legacy field “fully delineated,” suggesting that drilling more wells would fail to yield a worthwhile increase in production rates. The Sterling reservoir had declined to 25 percent of its original pressure, down from 30 percent a year earlier, and deliverability had also declined. There were no new wells drilled at the unit in 2014, 2015 or the first nine months of 2016.
By the start of 2014, the unit had produced 1.272 trillion cubic feet, according to the AOGCC. The unit produced some 25.2 billion cubic feet that year and 21.2 bcf over 2015, for a total of 1.319 trillion by the start of this year. The unit produced 9.3 bcf in the first six months of this year, which suggests a decline from 2015.
With its first plan as operator, Hilcorp proposed a light workload. The company told federal officials it would “conduct routine repairs and replacement of facilities as needed or required to maintain and increase field production.” The potential projects on the docket included small pipeline work, expansions to existing production facilities and the installation of additional disposal, injection or processing equipment “where necessary.”
Even with the declines, the two utilities expect Beluga River production to remain robust enough to meet a significant portion of their natural gas demand over the next decade.
OffshoreHaving acquired several neighboring fields previously owned by multiple companies, Hilcorp has been able to simplify its administrative work by consolidating operations.
Those efforts at consolidations have been most prominent among three offshore clusters: the Granite Point unit, the Trading Bay unit and the Middle Ground Shoal unit. When Hilcorp arrived in Alaska, those three clusters were really seven or eight separate fields.
All three areas contribute both oil and gas to the regional grid and at all three areas Hilcorp is offering a dour outlook for investment under the current economic climate.
After several years of working over existing wells at the two fields, Hilcorp recently merged the Granite Point field into the nearby South Granite Point unit to create the Granite Point unit with two participating areas: Hemlock and Granite Point Sands. The consolidated unit includes three legacy platforms: Granite Point, Anna and Bruce.
In a proposed plan of development submitted in March 2016, Hilcorp told state officials it would maintain existing production rates but was limiting its maintenance program to a single workover project to address complications from a previous workover project at the Anna platform. “Under the present economic climate and limited gas market, Hilcorp does not anticipate any new grassroots or sidetrack drilling projects,” the company wrote.
Hilcorp drilled one sidetrack in 2014 - the Granite Point State No. 18742 17A well - but drilled no wells or sidetracks in 2015 and none in the first nine months of 2016.
By the start of 2014, Granite Point had produced 149.5 million barrels of oil, according to the AOGCC. The unit produced some 1 million barrels that year and 900,000 barrels in 2015 for a total of 151.4 million at the start of the year. The unit produced some 500,000 barrels in the first six months of 2016, which suggests a slight increase from 2015.
By the start of 2014, Granite Point had produced 133.98 billion cubic feet of gas. The unit produced 796 million cubic feet that year and 804 million cubic feet in 2015 for a total of 135.58 bcf at the start of this year. The unit produced some 390 million cubic feet in the first six months of 2016, which suggests a slight decrease from 2015.
To the south, Hilcorp operates the Trading Bay unit, the McArthur River field to its south and the North Trading Bay unit to its north. Those three fields are currently distinct entities, although Hilcorp provides a single plan of development for all three and has expressed an interest in someday merging the Trading Bay and North Trading Bay units.
Hilcorp told the state to expect an “overall decrease” in development at Trading Bay and McArthur River for 2016 because of “the current economic climate and limited market for gas.” The company proposed four sidetracks at McArthur River, and three drilling projects and four workovers at Trading Bay. Trading Bay and McArthur River are home to the Grayling, Dolly Varden, Steelhead, King Salmon and Monopod platforms.
According to the AOGCC, Hilcorp completed the Trading Bay Unit M-34 and A31 wells at McArthur River and Trading Bay, respectively, in 2014, no wells at either field last year, and the Trading Bay State A-27RD2 oil well at McArthur River in late June 2016.
By the start of 2014, the Trading Bay unit had produced 104 million barrels of oil. The unit produced some 1.04 million barrels that year and 1.1 million barrels in 2015, for a total of 106.1 million barrels at the start of this year. The unit produced 434,568 barrels in the first six months of 2016, suggesting a decline from 2015 production levels.
For gas, Trading Bay had produced some 80.2 billion cubic feet by the start of 2014. The unit produced 1.74 billion cubic feet that year and 1.88 bcf in 2015, for a total of 83.8 bcf by the start of this year. The unit produced 654.3 million cubic feet in the first six months of 2016, suggesting a decline from 2015 production levels.
By the start of 2014, McArthur River had produced 635.6 million barrels of oil. The field produced 1.77 million barrels that year and 2.03 million barrels in 2015, for a total of 639.4 million barrels by the start of this year. The field produced 887,455 barrels in the first six months of 2016, which suggests a decline from 2015 production levels.
For gas, McArthur River had produced 1.462 trillion cubic feet by the start of 2014. The field produced 13.3 billion cubic feet that year and 10.5 bcf in 2015, for a total of 1.486 trillion cubic feet by the start of 2016. The field produced 4.5 bcf in the first six months of 2016, which suggests a decline from 2015 production.
The economic climate is also jeopardizing plans at North Trading Bay, where the Spark and Spurr platforms have been lighthoused since in 1992 (aside from a brief attempt at reviving gas production from Spark in 2007). While a previous operator wanted to decommission the platforms as early as 2009, Hilcorp has generally been more hopeful.
This year, Hilcorp told the state, “It is not economically viable or technically feasible to return either platform to production” this year. But Hilcorp still sees possibilities for the platforms. “This alternative remains preferable to abandonment,” the company said.
A range of engineering studies planned for 2016 and 2017 should provide some guidance on how best to preserve the platforms. An alternative proposal would “return the North Trading Bay Unit to production via directional wells drilled from the Monopod Platform and drilling/sidetracks from existing platforms,” according to the plan of development.
After acquiring the Middle Ground Shoal field and its active “A” and “C” platforms from XTO Energy Inc. in 2015, Hilcorp began consolidating the field with its previously acquired North Middle Ground Shoal field and its shut-in Baker platform to the north and its South Middle Ground Shoal unit and lighthoused Dillon platform to the south.
As Producers was going to print, the state was considering a proposal from Hilcorp to merge the two northern fields into the existing South Middle Ground Shoal unit, and the AOGCC was considering a similar proposal to create new pool rules for the larger unit.
The situation at the Middle Ground Shoal fields is slightly brighter than other offshore properties. Pending “a rebounding economic climate and available gas supply market,” Hilcorp plans to reactive the Baker platform in 2017 and might revive the Dillon platform in 2018, the company told state officials in its most recent plan of development. The company is evaluating “intermediate opportunities” to use directional wells from the A and C platforms “to target oil prospects otherwise accessible only from the Baker and Dillon platforms.”
By the start of 2014, the Middle Ground Shoal fields had produced 200.9 million barrels of oil. The fields produced some 679,428 barrels that year and 691,986 barrels in 2015, for a total of 202.3 million barrels by the start of this year. The fields produced 343,446 barrels in the first six months of 2016, which suggests an increase from 2015. For gas, Middle Ground Shoal had produced 110.97 billion cubic feet by the start of 2014. The fields produced some 368.2 million cubic feet that year and 198.3 million cubic feet in 2015, for a total of 111.54 bcf by the start of this year. The fields produced 76.8 million cubic feet in the first six months of 2016, which suggests a decline.
With several maintenance projects, Hilcorp expects production rates to remain steady this year from the two Middle Ground Shoal platforms, but a larger investment program at Platform C is “not feasible under current economic conditions” and might force the company to temporary suspend production sometime this year, the company has said.
Northern KenaiHilcorp operates five federal units and one state unit at the northern end of the Kenai Peninsula: Birch Hill, Swanson River, Beaver Creek, Sterling, Cannery Loop and Kenai.
The Birch Hill unit is currently offline, although plans have been in the works for several years to revive production. Hilcorp prepared preliminary engineering plans in 2012 and 2013 and made a site visit to the Birch Hill pad with federal officials in April 2014.
In its 50th plan of development for Birch Hill filed with the U.S. Bureau of Land Management in March 2015, Hilcorp said it would test an existing Birch Hill well this past winter, if weather and the market accommodated. If the test was successful, Hilcorp said it would eventually build surface facilities and install a natural gas gathering line.
Those plans never came to fruition this year. The company is now extending the project into its current plan of development, with operations planned for the second quarter of 2017. As before, the project depends on the weather supporting snow road construction.
If the well proves to be commercial, Hilcorp expects three-to-six months of planning, design and permitting facilities and an additional three months of actual construction.
As of June 2016, cumulative production at Birch Hill was 65.3 million cubic feet.
To the south of Birch Hill is the Swanson River oil field, which was discovered in 1957.
After Hilcorp arrived in Alaska, the Swanson River oil field became a model for how the company would approach the aging fields in its newly acquired Cook Inlet portfolio: a drilling campaign combined with a thorough effort to sidetrack or repair existing wells.
Through 2012 and 2013, Hilcorp drilled at least eight wells and undertook a major workover campaign, which yielded a noticeable increase in oil production rates.
The pace of activities has slowed since then. Hilcorp drilled four wells and one sidetrack in 2014, two wells and one sidetrack in 2015, and two sidetracks through the first nine months of 2016, according to AOGCC records. While those figures suggest a continual decline, the drilling dates tell a different story. Hilcorp brought a sidetrack online in February 2015, brought two wells online in October 2015 and completed two sidetracks during February and March 2016. The wells in the 2014 program were evenly spaced.
That said, Hilcorp told the state that it had no plans to drill any wells or sidetracks at Swanson River under its current plan of development, which runs from April 2016 to March 2017. The company planned to work over the SCU 33-33 and SCU 44-33 wells during this cycle, and could potentially add two more projects to the list. The company only performed one workover project - on the SCU 12B-09 well - during the previous cycle.
The slowdown in drilling might have impacted production. The unit was producing 3,600 barrels of oil equivalent per day at the start of 2015 and 3,250 barrels of oil equivalent per day by the end of the year, according to figures Hilcorp included in its development plan.
That said, cumulative production has been increasing from year to year.
By the start of 2014, Swanson River had produced 231.2 cumulative million barrels of oil. The unit produced some 800,000 barrels that year and 1 million barrels in 2015, for a total of 233 million by the start of this year. The unit produced 900,000 barrels in the first six months of 2016, which suggests a large increase from 2015. Swanson River is also seeing increased gas production. By the start of 2014, the unit had produced 2.919 trillion cubic feet of gas. The unit produced 2.89 million cubic feet that year and 3.88 million cubic feet in 2015, for a total of 2.926 trillion by the start of this year. The unit produced 2.21 million cubic feet in the first six months of 2016, suggesting an increase over 2015.
Like Swanson River, the Beaver Creek unit to the south is one of the older fields in Cook Inlet, with a gas field discovered in 1967 and an associated oil field discovered in 1972.
Hilcorp drilled four wells and three sidetracks at the unit in 2014, but drilled no wells or sidetracks in 2015 or through the first nine months of 2016. The company performed work on eight wells in 2014, two wells in 2015 and proposed work on one well for the current year. Recent activities at the unit have been focused on upgrading facilities.
As part of its efforts to optimize the unit, Hilcorp sought AOGCC approval to expand the description of the Beluga gas pool and to create a new gas pool in the Tyonek. The company said that it discovered the Tyonek accumulation through its recent activities.
Today, oil production at Beaver Creek is small. By the start of 2014, the unit had produced 6.22 million barrels, according to the AOGCC. The unit produced some 40,000 barrels that year and 50,000 barrels in 2015 to reach 6.31 million by the start of this year. In the first six months of 2016, the unit produced 20,000 barrels, suggesting a decline.
With natural gas production, Hilcorp saw quick results from its large development program. By the start of 2014, Beaver Creek had produced 215 billion cubic feet. The unit produced 4.45 million cubic feet that year and 6.26 million cubic feet in 2015 for a total of 227 bcf by the start of this year. In the first six months of 2016, the unit produced 2.25 million cubic feet, which suggests a decline over 2015 production.
While the Swanson River and Beaver Creek units have been steadfast producers for decades, the equally old Sterling unit to the south has been less reliable throughout its long history. The field was discovered in the early 1960s, with additional intervals discovered in the late 1990s, but production has been spotty. At times, operators have suspended individual intervals, entire pools and even the whole unit for stretches.
As with the Birch Hill unit, Hilcorp has recently been looking for ways to extend the life of the Sterling unit. The most likely option is a future workover campaign.
As has been the case in the past, production is currently sporadic. By the start of 2014, Sterling had produced 14.3 billion cubic feet. The unit produced 139 million cubic feet that year but only 86,000 cubic feet in 2015 and none in the first six months of 2016.
The Kenai unit to the southwest was the first major gas discovery in Cook Inlet, discovered in 1959 and brought online two years later with a pipeline to Anchorage.
The unit continues to remain an important source of gas supplies and continues to receive considerable investment, even several years into Hilcorp ownership of the property.
Hilcorp drilled six wells at the unit in 2014 and three in 2015. In its most recent plan of development, the company proposed a six-well development program split between the Tyonek pool and the Beluga/Upper Tyonek pool for this year. The company had not completed any wells at the unit in the first six months of 2016, according to the AOGCC.
Hilcorp performed work on seven existing wells in 2015. The company proposed a major workover campaign for this year, including as many as 10 coil tubing workovers, as many as five rig workovers and as many as 10 E-line recompletes. The company also suggested it might expand pads and facilities and increase compression this year.
By the start of 2014, the Kenai unit had produced 2.416 trillion cubic feet. The unit produced 19.2 billion cubic feet that year and 22.8 bcf in 2015 for a total of 2.466 trillion cubic feet by the start of this year. In the first six months of 2016, the unit produced 8.4 bcf, which suggests a steep decline over 2015 production.
Cannery Loop is a state-managed unit immediately north of Kenai. Although it began its life as a producing gas field, it has become more important as a regional storage facility.
Hilcorp drilled no wells at the unit in 2014, one well in 2015 and one well in the first six months of 2016. The company started drilling the 2016 well at the end of 2015 and proposed no additional drilling at the unit this year. The company performed no workovers in 2014, two workovers in 2015 and proposed two workovers for 2016.
By the start of 2016, the two most recent wells - CLU No. 13 and CLU No. 5RD - but produced approximately 2.25 million cubic feet per day, according to Hilcorp. The company forecast declining production this year as CLU No. 5RD depleted followed an increased production as the next zone in the well was completed through a workover.
Those increases appear to be occurring.
By the start of 2014, Cannery Loop had produced 187.8 billion cubic feet. The unit produced 3.58 bcf that year and 2.43 bcf in 2015 for a total of 193.9 bcf at the start of this year. In the first six months of 2016, the unit produced 2.68 bcf, which suggests a considerable increase over 2015.
Southern KenaiAt the other end of the peninsula, Hilcorp operates four units: the offshore Kasilof unit, the coastal Ninilchik unit, the onshore Deep Creek unit and the onshore Nikolaevsk unit.
Earlier this year, Hilcorp announced plans to relinquish the Kasilof unit. The decision followed several years where the company suspended operations while it tried to decide whether to return the two-lease unit to regular operation, use the facilities to assist with operations at the nearby Ninilchik unit or permanently discontinue Kasilof operations.
The Kasilof unit produced 4.32 billion cubic feet of gas through June 2016.
The recent programs Hilcorp has undertaken at the Ninilchik and Deep Creek units have occasionally been classified as exploratory, even when work occurred inside the units.
The Ninilchik unit follows the coastline in the area south of Kasilof in the southern Kenai Peninsula. Onshore pads are used to reach offshore targets with directional wells.
After acquiring the unit in 2013, Hilcorp proposed drilling exploration wells from existing drilling pads and building several additional pads in under-developed areas.
The unit currently has nine pads (from north to south): Abalone, Falls Creek, Bartolowits, Blossom, Grassim Oskoloff, Ninilchik State, Susan Dionne and Paxton. The ninth is the Kalotsa pad, which the state approved as The Producers was going to press.
Hilcorp drilled at least five wells and sidetracks at the Ninilchik unit in 2014 and four more in 2015, according to AOGCC records. The company intended to drill the Kalotsa No. 1 well in 2015, but “permitting issues” delayed construction of the Kalotsa pad and pushed the project in 2016. The company also intended to drill the Grassim Oskoloff No. 9 well this year, although the well had yet to be permitted as of September 2016.
By the start of 2014, Ninilchik had produced 149.85 billion cubic feet of gas, according to the AOGCC. The unit produced some 13.68 bcf that year and 13.95 bcf in 2015 for a total of 177.5 bcf by the start of this year. The unit produced 6.26 bcf in the first six months of 2016, which suggests a decline.
All existing developments at the Deep Creek unit are clustered in the Happy Valley participating area, in the northern end of the unit. The state and landowner Cook Inlet Region Inc. believe the southern half could also contain considerable resources and were ready to contract the acreage when Hilcorp acquired the property in early 2012.
Even though Hilcorp has yet to drill at the Middle Happy Valley prospect in the southern end of the unit, its exploration efforts in the northern end convinced the state to repeatedly defer contraction. The state approved a plan of operations for the project in late 2015. Hilcorp deferred the program several months later, citing permitting delays.
In its most recent plan of development, filed in March 2016, the company wrote, “Hilcorp remains committed to building the road and pad required to drill the Middle Happy Valley well, but cannot commit to drilling this exploratory prospect under the current economic and market climate.” Instead, Hilcorp said it would commission a 2-D seismic survey in the southern end of the unit. Combined with existing 3-D seismic, the survey could allow Hilcorp identify other opportunities in the southern end of the unit.
With the Middle Happy Valley project on hold, Hilcorp instead spud the Happy Valley B-17 development well in late November 2015. The directional well started within the participating area but extended beyond its northern boundary. The company completed the well in May 2016, according to AOGCC records. The company said it might drill a B-18 well to further delineate the region, if the B-17 well proved to be commercial.
By the start of 2014, Deep Creek had produced 24.53 billion cubic feet of gas, according to the AOGCC. The unit produced some 3.2 bcf that year and 2.43 bcf in 2015 for a total of 30.17 bcf by the start of this year. The unit produced some 1 bcf in the first six months of 2016, which suggests a decline.
Farther south, Hilcorp also operates the tiny Nikolaevsk unit.
The project was one of the earliest victories for Hilcorp in Alaska. A previous operator discovered natural gas in 2004 but delayed development because of the distance from existing infrastructure in the region. Shortly after acquiring the prospect, Hilcorp commissioned a pipeline to connect the unit to the existing regional transmission grid.
After bringing the unit into production, activities have slowed considerably. Hilcorp performed no drilling or major well work activity at the unit in 2014 or 2015 and planned no activities for 2016, calling the exploration and development potential “limited.”
By the start of 2014, Nikolaevsk had produced 479.1 million cubic feet of gas, according to the AOGCC. The unit produced some 171 million cubic feet that year and 80.8 million cubic feet in 2015 for a total of 731.8 million by the start of this year. The unit produced 18.5 million cubic feet in the first six months of 2016, which suggests a decline.