When 2011 began, Hilcorp Energy Co. was unknown to most Alaskans.
By the end of 2012, Hilcorp was the dominant producer in the Cook Inlet basin.
Its quick accession occurred in two deals. In July 2011, the privately held independent Hilcorp purchased the Cook Inlet assets of Chevron affiliate Union Oil Company of California. In April 2012, Hilcorp acquired the Cook Inlet assets of Marathon Oil Corp.
Through exploration work dating back in the 1950s, Chevron/Unocal and Marathon helped make many of the biggest discoveries in the basin, but over the past decade the companies had showed increasingly little interest in investing in further exploration.
Founded in 1989 on a principle of “acquire and exploit,” Hilcorp doubled between 2006 and 2010 and its arrival in Cook Inlet is a step toward doubling again by 2015.
Now the Houston-based company is in the early stages of a campaign to rejuvenate some 20 oil and gas fields across Cook Inlet. A recent slate of short-term gas supply agreements with the major utilities in the region suggests the company is finding success.
On the west side, Hilcorp operates the Lewis River unit, Pretty Creek unit, Stump Lake unit and Ivan River unit. Offshore, Hilcorp operates the Granite Point field, South Granite Point unit, Trading Bay unit, North Trading Bay unit, North Middle Ground Shoal field, South Middle Ground Shoal unit, Kasilof unit and Ninilchik unit. In the northern Kenai, Hilcorp operates the Birch Hill unit, Swanson River unit, Beaver Creek unit, Sterling unit, Cannery Loop unit and Kenai unit, as well as the Wolf Lake and West Fork fields. In the southern Kenai, Hilcorp operates the Deep Creek unit and the Nikolaevsk unit.
Hilcorp also acquired associated platforms, oil and natural gas pipelines and storage facilities, as well as minority interests in two non-operated fields, the ConocoPhillips-operated Beluga River unit and the XTO-operated Middle Ground Shoal oil field.
In 2012, Hilcorp spent some $230 million in Cook Inlet, with 38 percent going to refurbishing old Chevron assets, such as reactivating the Drift River terminal. The company planned to spend $300 million this year on the Chevron and Marathon assets.
The Ivan River unitBetween 1966 and 1979, Unocal, Chevron and Cities Service Oil Co. discovered the four onshore fields Hilcorp operates on the west side of Cook Inlet between Tyonek and the mouth of the Susitna River: Ivan River, Lewis River, Stump Lake and Pretty Creek.
Unocal discovered Ivan River in 1966 with the Ivan River Unit No. 44-01 well, but production only began in 1990, when Enstar Natural Gas Co. built a pipeline to the field. The unit also includes a suspended gas storage operation on ADL 391556.
There are currently five active wells at Ivan River — three producers and two water disposal wells — all drilled by either Unocal or Chevron between 1966 and 2009.
Under a development plan running through June 16, 2014, Hilcorp said it wants to increase existing production while expanding development of the Tyonek, Beluga and Sterling reservoirs, which could include a new well or a sidetrack into the Beluga.
Subsurface mapping“Work is continuing on subsurface mapping throughout the unit and we believe there may be significant reserves remaining at Ivan River,” the company wrote in the plan.
The remaining work outlined in the development plan includes maintenance such as upgrading water disposal pumps and installing a radio tower to improve communication.
In 2012, Hilcorp added perforations to the IRU 41-01 discovery well, which had the highest cumulative production but lowest current production rate of the three producers.
Hilcorp is also evaluating the storage operation it inherited at the field. The Department of Natural Resources allowed Hilcorp to temporarily suspend operations in 2012 because of problems the company identified at the lease. Now, Hilcorp is considering whether to convert the IRU 44-36 disposal well into a gas storage operation into the 71-3 sand interval. The conversion would require the installation of new compression facilities.
Also in 2012 and 2013, Chevron led an effort to clean up an old reserve pit at Ivan River.
Averaging cumulative rates, Ivan River produced 2.6 million cubic feet per day between July 2012 and 2013 and nearly 3 mmcf per day between January 2012 and 2013, according to the Alaska Oil and Gas Conservation Commission. In July 2013, the field produced nearly 70 mmcf, or some 2.2 mmcf per day. Cumulatively, Ivan River had produced nearly 84 billion cubic feet through July 2013.
Lewis River, Stump Lake, Pretty CreekAs with Ivan River, the primary work outlined for Lewis River this year is subsurface mapping, installing a radio tower and potentially upgrading compression facilities.
The current plan runs through June 30, 2014.
Cities Service discovered the field in September 1975 with the Lewis River No. 1 well.
There are currently four active wells at Lewis River — three producers and a disposal well — all drilled by Cities Service, Unocal or Chevron between 1975 and 2001.
Averaging cumulative rates, the Lewis River field produced 1.39 mmcf per day between July 2012 and 2013 and 1.37 mmcf per day between January 2012 and 2013, according to the AOGCC. In July 2013, the field produced 40 mmcf, or 1.3 mmcf per day. The unit produced nearly 1.5 mmcf per day in 2012, according to information from Hilcorp.
Cumulatively, Lewis River had produced nearly 14.1 bcf through July 2013.
Restoring productionAt Stump Lake, Hilcorp is working to restore production. After adding perforations to the SLU 41-33RD well, solids build up forced Hilcorp to take the line producing well offline.
Chevron USA Inc. discovered the field with SLU No. 41-33 in May 1978. After an eight-year shutdown, Chevron sidetracked the discovery well in 2009, restarting production.
In addition to the well work, Hilcorp is conducting subsurface mapping that will form the basis for a multiyear development plan. The current plan runs through June 30, 2014.
The SLU No. 41-33 well produced 335 thousand cubic feet per day in 2012, according to Hilcorp. Cumulatively, the field had produced 6.7 bcf through July 2013.
Pretty Creek is also under evaluation for future development opportunities.
Unocal discovered the field in February 1979 with the Pretty Creek Unit No. 2 well.
After installing a temporary sand separator at the unit in 2011 and 2012, Hilcorp is considering a permanent sand separator, as well as a two-phase separator and an additional water tank to allow production from the well to proceed more effectively.
The current unit plan of development runs through June 30, 2014.
The unit includes a gas storage operation from the Pretty Creek Unit No. 4 well.
The Pretty Creek Unit No. 2 well produced only 36 mcf per day in 2012, but the Pretty Creek Unit No. 4 storage well produced slightly more than 3 mmcf per day, according to Hilcorp. Cumulatively, Pretty Creek had produced some 9.5 bcf through July 2013.
Granite Point and South Granite PointOffshore, from north to south, Hilcorp operates the Granite Point field and South Granite Point unit, the Trading Bay and North Trading Bay units, North Middle Ground Shoal field and South Middle Ground Shoal unit, the Kasilof unit and the Ninilchik unit.
The Granite Point field consists of three un-unitized leases held by production. The state formed the South Granite Point unit over three adjacent leases to the south in 1998.
Since taking over the neighboring Granite Point fields in January 2012, Hilcorp has been working over numerous existing wells from the three offshore platforms at the two fields.
The work from all three platforms includes downhole repairs, re-completions or additional perforations to improve production from the Tyonek formation and the deeper Hemlock oil formation, as well as physical maintenance of the actual platforms.
The Granite Point field contains two platforms: Anna and Bruce.
At Anna, Hilcorp worked on 11 wells and sidetracks in 2012.
The repairs and additional perforations Hilcorp performed on six of those yielded a combined production increase of some 125 barrels of oil equivalent per day, but the work on the remaining five were “unsuccessful.” In one case, on the shut-in AN 9 well, Hilcorp postponed its proposed work because the “risk of mechanical failure” was “too high.”
For 2013, Hilcorp planned to use Rig 428 to repair AN 39RD (one of the unsuccessful 2012 ventures) and AN 32RD2, and to convert the injector AN 38 into a producer. It also plans to convert the AN 17 Tyonek injector into a producer from the deeper Hemlock.
The AOGCC issued a permit for a Granite Point St. 18742-17A well on April 25, 2013.
Moncla rigAt Bruce, Hilcorp worked on six wells and sidetracks in 2012, yielding some 36 to 81 barrels of incremental oil equivalent production per day from three wells. Although one of those wells, BR 3-86, saw production growth between 15 and 40 barrels of oil equivalent per day after the work, Hilcorp described the results as “lower than suspected,” which it said was “probably due to operational problems that occurred during stimulation.” The work on BR 3-86 involved an acid stimulation test using 20,000 gallons of hydrofluoric and hydrochloric acid to remove damage from the wellbore.
Of the remaining three wells, the repairs on two were unsuccessful, and Hilcorp is now listing those wells as candidates for future workovers. A workover on the third was also unsuccessful, and the well is shut-in while Hilcorp evaluates potential repair options.
For 2013, Hilcorp planned to use its newly commissioned Moncla rig in the second half of the year to perform repairs and recompletions on seven Bruce wells. Hilcorp also planned to conduct a chemical tracer test on one well from the platform to gauge the effectiveness of nitrogen injections for enhanced oil recovery operations at the field.
‘Derricks down’The South Granite Point unit hosts the Granite Point platform.
Almost immediately upon arriving in Alaska, Hilcorp launched a “derricks down” project at Granite Point, replacing the existing derrick on the platform with a “modern drilling rig,” as Hilcorp’s senior vice president for Alaska John Barnes described it in May 2012.
From Granite Point, Hilcorp conducted work on five wells and sidetracks in 2012.
The work on three of those wells yielded some 36 barrels of oil equivalent per day of incremental growth. A coiled tubing workover on a fourth, GP 50, initially yielded 60 barrels of oil equivalent, but the well subsequently stopped producing, Hilcorp said. The fifth well also returned to production after a workover, but producing primarily water.
For 2013, Hilcorp planned to use its Moncla rig to perform four workovers from the Granite Point platform, including additional Tyonek perforations or stimulations at three wells. Hilcorp also plans to improve Hemlock oil production from two existing wells.
Cumulatively, Granite Point had produced some 149 million barrels of oil through July 2013, including nearly 1.3 million barrels since Hilcorp took over in January 2012.
Granite Point averaged 2,290 bpd in July 2013, according to the AOGCC.
Trading Bay and North Trading BayTo the south of Granite Point are the Trading Bay and North Trading Bay units.
The neighboring units — and an un-unitized field between them — host seven platforms and Hilcorp is conducting a similar mix of rig and well maintenance at the units.
The Trading Bay unit hosts four platforms — Steelhead, Dolly Varden, King Salmon and Grayling — that produce from four McArthur River field intervals discovered in 1965.
The work at Trading Bay included a “derricks down” program, such as the one at Granite Point, to modernize the drilling equipment at the unit needed for workovers.
With the rig now on-hand, Hilcorp is working through a list of wells it wants to repair and said it may seek out a dedicated rig if it finds enough candidates for new wells and sidetracks. Prior to the arrival of the rig, Hilcorp launched a major repair program.
Restoring waterfloodAt the McArthur River Hemlock oil pool, Hilcorp is working to restore a waterflood program (and thereby increase production) by repairing injectors, installing electric submersible pumps at producers and converting some “redundant” producers to injectors.
At the McArthur River Middle Kenai G-Zone oil pool, Hilcorp is working to improve its waterflood operations by creating “dedicated” completions into the interval. Currently, the Middle Kenai G-Zone completions are comingled with the Hemlock of West Foreland pools. “It will take several years to downspace the G-Zone waterflood and achieve a fully functional waterflood,” Hilcorp said in its most recent development plan.
At the McArthur River West Foreland oil pool, Hilcorp believes that repairing existing wells will improve the management of all three pools. The company proposed no work for a deeper pool in the Jurassic formation during the period, but repaired and recompleted a gas well from the Grayling platform to provide fuel gas for its operations.
After drilling the M-29A well in 2012, Hilcorp completed M-31A in January 2013 and M-31B in February 2013, both from the Steelhead platform, according to the AOGCC.
The McArthur River field averaged 4,311 bpd in July 2013 with cumulative oil production of some 635 million barrels through July 2013, according to the AOGCC.
Expansion requestedIn mid-2013, Hilcorp asked the Department of Natural Resources to include two leases at the Trading Bay field into the Trading Bay unit to accommodate a “newly discovered natural gas deposit” from the Monopod platform on ADL 18731. The expanded unit would prevent “duplicative infrastructure and operation systems,” according to Hilcorp.
The current development plan runs through Aug. 25, 2014.
The North Trading Bay unit currently operates under a prior Marathon Oil plan of development through the end of 2013. The Spark and Spurr platforms at the unit have been in lighthouse mode since in 1992, aside from an attempt at gas production from Spark in 2007. There has been talk in recent years of removing the platforms, but Marathon said, “abandonment operations have been deferred to provide the purchaser, Hilcorp Alaska, sufficient time to evaluate any future utility for the well bores.”
The Middle Ground Shoal fieldsDue east of Trading Bay are the Middle Ground Shoal fields.
Hilcorp operates the North Middle Ground Shoal field and the South Middle Ground Shoal unit and holds a minority interest in the XTO-operated Middle Ground Shoal field.
North Middle Ground Shoal hosts the Baker platform. The state approved a plan for abandoning the lighthoused platform in early 2012, but later in the year Hilcorp amended the plan. It had decided to reactivate the platform to accommodate gas exploration.
In late 2012, Hilcorp perforated the T-40 gas sands at the BA-27 well to test for commercial production, but said the zone appears to be wet. At the BA-18 well, Hilcorp isolated the T-31 gas zone and recompleted two shallower zones, T-24 and T-25. In early 2013, Hilcorp perforated the shallower zones, but found they were unable to produce.
Hilcorp expects the reactivation work to continue through early 2014. Hilcorp restarted gas production in mid-2013 and is studying potential oil production from the platform.
The current development plan for the field runs through May 31, 2014.
The South Middle Ground Shoal unit and its Dillon platform are currently shut-in.
Kasilof and NinilchikThe Kasilof and Ninilchik units are in lower Cook Inlet, produced from the shore.
Union Oil Co. drilled three dry holes at Kasilof in the late 1960s, but other companies, including Mesa Petroleum and Standard Oil Company of California, subsequently found gas at the field. Marathon ultimately brought the Kasilof field online in November 2006, using a 17,000-foot extended reach dual-lateral well drilled from an onshore pad.
After initial drilling results proved the producing area to be smaller than expected, Marathon requested a major contraction at the unit, to 329 acres down from 13,289 acres.
The Kasilof unit continues to operate under a prior Marathon plan of development through the end of 2013. The plan called for drilling projects during the period.
Cumulatively, the field has produced some 4.2 bcf through July 2013.
Ninilchik hugs shoreThe Ninilchik unit hugs the coastline south of Kasilof.
Chevron discovered a Tyonek gas field at the unit in June 1961 with the Falls Creek Unit No. 1 well, and Marathon later discovered two other fields in 2001 and 2002.
While Marathon originally planned a year of regular production from its existing wells at the unit, Hilcorp subsequently amended the development plan to include up to six new wells, including at least one to test the deep oil potential at the traditional gas field.
The heart of the program is three exploration wells — the 12,000-foot SD-8 targeting deep oil, the 2,400-foot PAX-5 targeting the upper Beluga and the 5,500-foot NS-4 targeting the Sterling. It also includes four potential locations — a 12,000-foot SD-9 to appraise the SD-8 well, a 4,000-foot PAX-6 targeting the lower Beluga, a 12,000-foot GO-8 targeting deeper oil and the 12,000-foot FC-5 target the same deeper oil intervals.
The AOGCC issued a permit for the SD-8 well on April 25, 2013.
The results of this exploration work could lead to an expansion of the Falls Creek, Grassim Oskolkoff and Susan Dionne-Paxton participating areas, according to Hilcorp.
Comprehensive unit reviewThe proposed program also included well work on the SD-1, SD-2, SD-5, SD-6, SD-7, PAX-1, PAX-3 and FC-1 wells to increase gas production from the Tyonek and Beluga.
This work, if successful, would likely require expanded facilities, Hilcorp said.
Even with the workload, or more likely because of it, Hilcorp said it would take at least two years to complete a comprehensive review of the oil and gas potential for the unit.
In September 2013, the AOGCC issued a permit for Hilcorp to drill the Frances No. 1 exploration on private land either inside the unit or just outside its eastern boundaries.
Averaging cumulative rates, Ninilchik produced 26.6 mmcf per day between July 2012 and 2013 and nearly 31.2 mmcf per day between January 2012 and 2013, according to the AOGCC. In July 2013, the field produced nearly 518 mmcf, or 16.7 mmcf per day.
Cumulatively, Ninilchik had produced nearly 146 bcf through July 2013.
The Swanson River unit is the biggest success to date for Hilcorp in Alaska.
When Richfield Oil Corp. drilled the Swanson River No. 1 well in April 1957, the company made the first significant oil discovery and justified Alaska’s bid for statehood.
Swanson River oil production began from the Hemlock formation the following year and peaked at 38,323 bpd in November 1967, but had fallen below 1,000 bpd by 2004.
By the time Hilcorp arrived, it was producing some 300 bpd, Hilcorp’s Barnes told Commonwealth North in December 2012.
In addition to drilling plans, Hilcorp started by using a pulling unit for well remediation, and bringing in a workover rig for well work. “There are a lot of wells out there that need to be fixed,” Barnes said. “We’ve scratched the surface and have a long way to go.” The initial work involved sidetracking three existing and repairing eight damaged wells.
By the end of 2012, Swanson River production hit 2,200 bpd. The field produced an average of 2,165 bpd in July, down 11.6 percent from a June average of 2,449 bpd.
Cumulatively, Swanson River had produced some 231 million barrels through July 2013.
Another year of projects
Speaking at an informal meeting of the Alaska House Resources Committee in February 2013, Hilcorp Energy President Greg Lalicker outlined another year of projects.
“This year we’re going to drill seven more wells and we have about 15 workover, recompletion projects,” Lalicker said. “It’s not inconceivable that you’ll see the rate climb another 2,000 to 3,000 barrels per day, by the time we’re all said and done.”
Between January 2012 and mid-September 2013, Hilcorp permitted 10 wells at Swanson River and drilled seven, the latest completed in late May 2013, according to the AOGCC.
In early 2013, Hilcorp acquired the Swanson River Oil Pipeline from the Kenai Pipe Line Co., which gave the producer more control over its destiny at the historic oil field.
In mid-2013, though, Hilcorp paid a civil penalty of $115,500 after failing to notify the AOGCC about changes to drilling permits and for failing to test blowout prevention equipment after it was used to control a well. The incident was one of more than a dozen enforcement actions initiated against the company, according to the AOGCC. “The aggressiveness with which Hilcorp is moving forward with operations appears to be contributing to regulatory compliance issues,” the AOGCC said in an April 2013 order.
In a statement at the time, Hilcorp said that its “investment in Alaska’s resources has certainly brought an increased level of activity to Cook Inlet, but we believe we’re on the right path forward and remain committed to operating safely and responsibly.”
Birch Hill, Beaver, Sterling
The nearby federal units have yet to see the investment directed at Swanson River.
Just north of the Swanson River unit is the Birch Hill unit.
ARCO Alaska Inc. discovered the field in 1965 with the Birch Hill Unit No. 22-25 well, but production has been limited to a short run of some 65 mmcf in that initial year.
South of Swanson River are the Beaver Creek unit and the Wolf Lake and West Fork fields.
Marathon Oil Co. discovered three gas producing intervals at Beaver Creek in 1967 with the Beaver Creek No. 1 well and an oil pool in 1972 with the Beaver Creek No. 4.
Beaver Creek gas production peaked in 1986 at 17.7 bcf per year and Beaver Creek oil production peaked in 1973 at 416,000 barrels per year. In July 2013, Beaver Creek produced 5.3 mmcf per day on average and 154 bpd on average. Cumulatively, Beaver Creek had produced some 212 bcf and 6.2 million barrels of oil through July 2013.
The West Fork and Wolf Lake fields are currently offline.
The West Fork field dates to exploration from 1960, but has produced sporadically through the years. As of July 2013, cumulative production was some 5.7 bcf.
The Wolf Lake field dates to exploration from the late 1990s, but was always one of the smaller fields in the basin. As of July 2013, cumulative production was some 822 mmcf.
The Sterling unit dates to Unocal exploration from the early 1960s, but production has been small-scale and sporadic over the decades, with intervals or even entire fields shut-in at times. The unit produced some 801 mcf per day in July 2013, predominately from the Upper Beluga formation. Cumulatively production through July 2013 is some 14 bcf.
The Kenai gas field
The Kenai unit is due east of Sterling.
Without an amendment from Hilcorp such as the one it supplied for Ninilchik, the unit is operating under a prior Marathon plan of develop running through Feb. 7, 2014.
While Marathon drilled no new wells at the unit in 2012 and planned no new wells for 2013, it performed and planned “numerous non-rig remedial activities” for both years.
Union Oil Company of California discovered the Kenai gas field on Oct. 11, 1959, in a 50-50 partnership with Ohio Oil Co. Those companies eventually became Chevron and Marathon, making Hilcorp now the sole owner of the large gas discovery in Cook Inlet.
Unocal discovered the field with the onshore KU 14-6 well. While the company had been looking for oil, the well initially tested at 12 mmcf per day from two zones in the Sterling formation. The discovery launched the Southcentral natural gas market.
In launching the local gas market, the Kenai gas field also defined two oddities — long-term contracts and cheap prices — that have began to disintegrate in the past decade.
Kenai production peaked in 1982 at 116 bcf per year, but dropped 30 percent in 1984 and 42 percent in 1989 before reaching a low of 10 bcf per year in 1998 and 1999.
2000 course reversal
But Marathon reversed course at Kenai. In 2000 its newly commissioned Glacier No. 1 truck-mounted drilling rig made it quicker to move from one drill site to the next and its Excape completion technology in 2001 allowed the company to stimulate several production zones at the same time using perforating guns placed outside the well casing.
Those efforts lifted production to as high as 28.5 bcf in 2003, according to the state, but in 2012 the field produced some 11.4 bcf from three formations, according to Marathon.
Cumulatively, the Kenai gas field had produced 2.4 trillion cubic feet through July 2013.
The Kenai gas field produced some 16.2 million cubic feet per day in July 2013, according to the AOGCC.
The associated Cannery Loop unit produced an average of 4.7 mmcf per day from the Beluga in July 2013, with cumulative production of 186 bcf through July 2013.
The field dates to exploration from 1959, and the depleted reservoirs at the old field are now home to the Enstar-affiliated Cook Inlet Natural Gas Storage Inc. operation.
The two remaining units in the Hilcorp portfolio are in the southern Kenai Peninsula.
For nearly a decade, the Deep Creek unit was the southern terminus of the regional grid.
Socal drilled the Deep Creek Unit No. 1 well in 1958 in pursuit of oil in the Hemlock formation and a secondary target of Tyonek gas, but chose not to pursue development.
Unocal returned to the field in the early 2000s, forming a unit, acquiring seismic and drilling exploration wells into the Happy Valley gas field at the unit. A discovery announced in November 2003 justified an extension of the Kenai Kachemak Pipeline.
Unocal brought the Happy Valley field online in November 2004 at 3 million to 4 mmcf per day and drilled some 13 wells between 2003 and 2009. The early exploration work suggested additional accumulations at the unit, and a 2007 report from Netherland, Sewell & Associates estimated probable reserves of 22 bcf for the unit area.
The Happy Valley participating area covers only the northern end of the 20,000-plus acre Deep Creek unit. By late 2010, the Unocal parent company Chevron announced plans to sell in Cook Inlet holdings, which stalled plans for exploring the southern end of the unit.
Deep Creek early priority
After Hilcorp took over the Chevron properties in January 2012, the company made Deep Creek one of its early priorities, drilling three wells and working over another four wells.
The wells tested producing and non-producing formations. The 2,005-foot B-14 exploration well tested a target in the Sterling formation above the existing participating area. The 3,069-foot B-15 exploration well tested a target in the Upper Beluga formation, also above the existing participating area. The 4,857-foot B-15 development well targeted the Beluga formation, but “rig limitations” prevented it from reaching its target depth.
The workover program added horizons at existing wells: B-12, B-13, A-11 and A-3.
Hilcorp also commissioned a 3-D seismic survey over 50 square miles of the unit. The survey suggested the resources at Happy Valley were “probably three to four times larger than the current participating area,” Hilcorp’s Barnes told the Anchorage Energy Task Force in June 2013.
Finally, Hilcorp asked the Department of Natural Resources and Cook Inlet Region Inc. to expand the unit to include CIRI leases to the south. The proposal included a drilling commitment, but Hilcorp withdrew the request, calling the discussions “unsuccessful.”
The current plan calls for completing the B-16 well, and drilling two exploration wells from a new C pad into a Sterling and a deeper Beluga target outside the participating area. If successful, the program would justify a new participating area, Hilcorp said.
The plan also calls for numerous workover jobs, including acid treatments.
The Happy Valley field produced some 11 mmcf per day as of early 2013, according to Hilcorp, but the summer rate was closer to 3.7 mmcf per day, according to July 2013 AOGCC figures. Cumulatively, Deep Creek produced 22 bcf through July 2013.
The southernmost field shows how Hilcorp differs from its predecessor.
Unocal discovered gas from the Red pad at the Nikolaevsk unit in 2004, but never developed the field because of its distance from the grid terminus at Happy Valley.
In early 2009, in a bid to extend the unit terms, Unocal proposed two wells at Nikolaevsk, one at the existing Red prospect and another at the associated Blue prospect. The state approved the plan, which extended the unit terms by two years, through March 2011.
Ultimately, Unocal relinquished the Blue prospect rather than drill, and was unable to farm-out the Red prospect, blaming market and infrastructure conditions. With the development of the North Fork field to the south cutting the distance to market, Unocal reached an agreement with the Department of Natural Resources in early 2011 to study a pipeline to North Fork rather than its earlier plan to connect to the grid at Happy Valley.
The evaluations became moot when Hilcorp took over on January 2012.
Instead, in September, Hilcorp and the Enstar affiliate Alaska Pipeline Co. announced an $8.4 million 10-mile pipeline connecting the field to the Anchor Point Pipeline, an extension of the Kenai Kachemak Pipeline that connects to the North Fork Pipeline.
Hilcorp brought the field online from the Red No. 1 in December 2012 at 5 mmcf per day. Cumulatively, Nikolaevsk produced some 378 mmcf through July 2013.
While Hilcorp has no plans to drill new wells during the current development plan that runs through March 2014, the company is evaluating whether work at Red No. 2 could make the well productive. Unocal drilled Red No. 2 in 2004, when it drilled the discovery well.
Hilcorp also plans to acquire seismic over the unit this winter.
How far can Hilcorp go?
When Hilcorp achieved its goal of doubling by 2010, the company gave all its employees a new car. If it meets of its goal of doubling by 2015, each employee will get $100,000.
So, will they get the bonus?
By late 2012, Hilcorp had increased oil production 8 percent at McArthur River, 27 percent at Granite Point, 36 percent at Trading Bay and 122 percent at Swanson River, Hilcorp President Greg Lalicker told the Resource Development Council in November 2012. By May 2013, Hilcorp was touting a 36 percent increase across all fields, including a 412 percent increase at Swanson River and a 157 percent increase at Trading Bay.
However, gas production initially lagged. By late 2012, Hilcorp’s share of Beluga River production was down 11 percent, Trading Bay was down 33 percent and Ninilchik was down 6 percent. The small Deep Creek unit was up 102 percent and a collection of smaller fields primarily located on the west side of Cook Inlet was up 39 percent.
After taking over for Marathon in early 2013, though, Hilcorp pushed its assets to their limits. The test increased gas production from some 65 mmcf per day at the end of January to almost 180 mmcf per day in February, according to Barnes.
Those figures convinced Hilcorp it could supply unmet local demand for the near term.
Gas supply agreements
In the second half of the year, Hilcorp signed agreements to supply Enstar Natural Gas Co., Chugach Electric Association and Matanuska Electric Association into March 2018.
The contracts have been a big relief to local utilities, which have been considering imports to meet local needs, but the region remains on edge. For starters, the lead time needed to arrange imports mean the utilities are continuing to study the matter.
Hilcorp also must deliver on the contracts.
In June 2013, before signing the contracts, Hilcorp Alaska Vice President of Midstream Kurt Gibson told the Anchorage Energy Task Force that some of the gas it expected to deliver was already behind pipe, “but not much. Some of it can be found very quickly if we need to. ... And still another tranche of it is going to require ... more of an effort.” He added, “What we’re saying is, the gas is there and we’ll go get it if you tell us to.”
Once Hilcorp delivers, the contracts will likely impact the local market.
Smaller independents concerned
For starters, smaller independents like Buccaneer Alaska LLC, Cook Inlet Energy LLC and Furie Operating Alaska LLC worry that the contracts will push them out of the market, should they prove up considerably natural gas reserves over the next four years.
The Regulatory Commission of Alaska acknowledged the concern when it recently approved the Enstar contract, but said the contract still served the public interest.
The contracts will also impact pricing in the Cook Inlet.
To resolve competitive concerns after the company acquired the Marathon assets, Hilcorp and Alaska Attorney General Michael Geraghty agreed to a consent decree in November 2012 that prohibits gas exports unless all local needs are met and caps prices through late 2017.
The Enstar contract used the maximum pricing allowed under the consent decree, with base-load prices ranging from $6.86 per mcf at the start to $8.03 per mcf toward the end of the contract, and higher prices from emergency gas supplies and for “swing load” gas.
Those prices have already become benchmarks in the region.
For instance, Buccaneer recently proposed a contract priced 20 cents higher than the consent decree cap, saying it would offset the premium with a 30-cent savings in tariffs.
Still, after worrying for years about the regional system holding out through extreme cold snaps each winter, the utilities certainly want Hilcorp’s employees to get those bonuses.