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Vol. 19, No. 46 Week of November 16, 2014
Providing coverage of Alaska and northern Canada's oil and gas industry

The Producers 2014: Hilcorp hitting early stride in Cook Inlet basin

The dominant producer continues to rejuvenate old oil and gas fields while also improving efficiencies

Eric Lidji

For Petroleum News

The speed with which Hilcorp Alaska LLC became the dominant force in Cook Inlet will certainly prove to be among the most important moments in the history of the basin.

The privately held Houston-based independent owned no oil or gas assets in Alaska at the start of 2011. By the end of 2012, it was the largest producer in the Cook Inlet region.

That transition came through two acquisitions.

Hilcorp picked up the Cook Inlet assets of Union Oil Company of California in July 2011 and the Cook Inlet assets of Marathon Oil Co. in April 2012. With those two deals, Hilcorp became the operator of some 20 oil and gas fields across the Cook Inlet basin.

On the west side, Hilcorp operates the Lewis River, Pretty Creek, Stump Lake and Ivan River units. 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 southern Kenai Peninsula, Hilcorp operates the Deep Creek and Nikolaevsk units. In the northern Kenai Peninsula, Hilcorp operates the Birch Hill, Swanson River, Beaver Creek, Sterling, Cannery Loop and Kenai units, as well as the small Wolf Lake and West Fork fields.

Through the deals, Hilcorp also acquired a minority interest in the ConocoPhillips-operated Beluga River unit and the XTO-operated Middle Ground Shoal oil field.

And of course Hilcorp also acquired considerable infrastructure, including several platforms, pipelines and storage facilities. In just one sign of how the deal is changing the region, Hilcorp is now consolidating four independent gas pipelines into a single entity.

The Ivan River unit

Between 1966 and 1979, Unocal, Chevron and Cities Service Oil Co. discovered the four onshore fields Hilcorp now 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.

To date, these fields have not received the same attention Hilcorp has devoted to other assets in its portfolio. But a multi-year field study under way could identify opportunities.

At Ivan River, Hilcorp had considered drilling a new well or sidetrack in 2013. Instead, the company performed some maintenance work on a booster compressor engine.

The proposed well or sidetrack remain possibilities for this year but seem unlikely given that Hilcorp is currently conducting a “comprehensive field study.” The company has said it would provide state officials with updates on the field study by the end of the year.

That said, Hilcorp may work over the IR 41-01 well to improve production from the Sterling-Beluga participating area and may convert one of two disposal wells to a producer. Those efforts would come on top of regular maintenance and repair work.

The Ivan River unit produced some 2.28 million cubic feet per day in 2013, which is on par and potentially even a slight increase from production rates in the previous year.

Averaging monthly production, the Ivan River unit produced 1.8 million per day in July 2014. Cumulatively, the unit produced more than 88.7 billion cubic feet through July 2014.

The unit also includes a legacy storage facility on ADL 391556. The state agreed to suspend the storage operations in 2012, after Hilcorp identified damage at the IRU 44-26 injection well. Hilcorp said it “recognizes the importance of gas storage facilities in Cook Inlet” and is continuing to evaluate options for either converting or reactivating the well.

Lewis River, Stump Lake, Pretty Creek

At Lewis River, Hilcorp did not drill any wells, perform any workovers or conduct any facility improvements in 2013 and said it did not plan any of those activities for 2014.

The unit produced some 1.3 million cubic feet per day in 2013, all from the LCU C-01RD well. The rate is a slight decrease from a 2012 rate of nearly 1.5 mmcf per day.

Averaging monthly production, the Lewis River unit produced nearly 1.2 mmcf per day in July 2014. Cumulatively, the unit produced more than 14.6 bcf through July 2014.

Hilcorp is continuing to analyze ways to bring the Stump Lake unit back online.

After an eight-year shutdown, Chevron returned Stump Lake to production in 2009 by sidetracking the original discovery well. Hilcorp added perforations to the SLU 41-33RD well, but the build-up of solids forced the company to suspend production again.

Cumulatively, the Stump Lake unit produced more than 6.6 bcf through July 2014.

Similarly, the Pretty Creek unit is under evaluation for future development options.

Cumulatively, the Pretty Creek unit produced more than 9.5 bcf through July 2014.

The Trading Bay fields

At the southern end of the west side, Hilcorp operates three offshore fields: the Trading Bay unit and the nearby McArthur River field and the North Trading Bay unit.

At the Trading Bay unit in 2013, Hilcorp conducted a nine-well workover campaign with Rig 56 at the Monopod platform into the Tyonek and the deeper Hemlock formations.

The program helped increase production to 5,740 barrels of oil equivalent per day by the end of the year, up from 822 barrels of oil equivalent per day at the beginning of the year.

Hilcorp planned a five-well workover campaign for 2014.

Hilcorp drilled the Trading Bay M-34 well in July.

At the McArthur River field in 2013, Hilcorp conducted a 10-well workover campaign, which helped increase production to 4,372 boepd by the end of the year, up from 3,824 boepd at the beginning of the year.

Hilcorp also conducted one workover at the Grayling gas sands, where 2013 production fell to 5,842 boepd from 8,381 boepd.

Hilcorp planned a major workover campaign for the McArthur River field this year, including five wells with the Moncla 404 Rig at the King Salmon platform, seven wells with the MAK No. 1 rig from the Dolly Varden platform, two wells with Rig 428 at the Steelhead platform and five wells with the Moncla 301 Rig at the Grayling platform.

Hilcorp also scheduled considerable maintenance activity for all five platforms this year.

Averaging monthly production, Trading Bay produced nearly 2,900 bpd and McArthur River produced some 4,730 bpd in July 2014. Cumulatively, the unit produced nearly 105 million barrels and the field produced more than 636 million barrels through July 2014.

The North Trading Bay unit was operating under a prior Marathon Oil plan of development through the end of 2013 and Hilcorp performed no drilling or well work.

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. Hilcorp said it is unlikely to return either to production this year. But the company is conducting reservoir engineering and geological studies through the end of 2017 that may identify future opportunities.

Among those opportunities is the possibility of using the Spurr platform to further develop the Kokanee fault block located outside the North Trading Bay unit boundaries.

Marathon had been moving toward decommissioning and removing the platforms, and had been submitting abandonment plans to state officials since 2009. But Hilcorp believes “additional evaluation and analysis may yield development and production opportunities which Hilcorp finds preferable to abandonment and believes there is value in maintaining the platforms to support future exploration and development.”

Granite Point

To the north, Hilcorp operates the Granite Point field and South Granite Point unit.

Since acquiring the fields, Hilcorp has been working over wells using the three offshore platforms: Anna and Bruce at Granite Point and Granite Point at South Granite Point.

Those activities slowed some in 2013.

A sidetrack of the AN-17 well at the Anna platform was the only drilling or workover activity Hilcorp performed at Granite Point in 2013. The resulting production increase offset a small decline in production from the Bruce platform. Granite Point started 2013 at 1,495 boepd and finished the year at 1,603 boepd. This year, Hilcorp planned a three-well workover campaign at the Bruce platform but had no drilling or well work activities planned for the Anna platform.

Hilcorp performed three workovers from the Granite Point platform in 2013, which helped lift production to 1,066 boepd up from 1,019 boepd over the course of the year. The 2014 plans call for some additional work at GP-54, which Hilcorp worked over and brought online at 450 bpd.

While Hilcorp planned various maintenance activities at the three platforms this year, the biggest development at the two fields is an effort to consolidate and expand the units, similar to a scenario the state approved at the Trading Bay unit in August 2013. Hilcorp said that it intended to submit a formal application for the idea sometime this year.

Hilcorp completed the Granite Point State 18742-17A oil well in February 2014.

Averaging monthly production, the Granite Point field produced 2,665 bpd in July 2014. Cumulatively, the unit produced more than 150 million barrels through July 2014.

North and South Middle Ground Shoal

To the east, Hilcorp operates the offshore North Middle Ground Shoal field and Baker platform and the offshore South Middle Ground Shoal field and Dillon platform.

The state approved a plan for abandoning the lighthoused Baker platform in early 2012, but Hilcorp amended the plan later in the year, having decided to reactivate the platform to pursue gas exploration. Early workover efforts failed to yield much optimism, but a workover in 2013 returned the BA-14 well to production. It now provides fuel gas to its majority partner XTO Energy Inc., which operates the nearby Middle Ground Shoal field.

The program for 2014 included additional well work to add electric submersible pumps to existing wells and to conduct subsurface studies to identify future opportunities.

A fire at the Baker platform in October 2014 was fought by the Nikiski Fire Department, the Alaska Department of Environmental Conservation, the U.S. Coast Guard, CISPRI, Offshore Marine Services and Hilcorp. The cause was still unknown as The Producers went to print. Gas production at the platform was shut-in.

Unocal decommissioned the Dillon platform in 2003. But Hilcorp is undertaking a multi-year field study through mid-2016 to evaluate the possibility of reactivating the platform.

The study includes re-mapping relevant horizons, compiling well histories, building reservoir simulation models and potentially shooting 3-D seismic over the field.

The Kasilof unit

Kasilof and Ninilchik are coastal units produced from the shore.

After Union Oil Co. drilled three dry holes at Kasilof in the late 1960s, other companies, including Mesa Petroleum and Standard Oil Company of California, subsequently found gas at the field. Ultimately, Marathon brought the Kasilof unit into production in November 2006, using a 17,000-foot extended reach dual-lateral well drilled from an onshore pad. After initial drilling 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.

Of the three wells in the Kasilof participating area - Kasilof No. 1, Kasilof South No. 1 and KAS-1 - only the seasonally produced KAS-1 has ever been reliably productive.

Hilcorp did not drill any wells or perform any major well work at Kasilof last year after formally acquiring the unit from Marathon in February 2013. The company suspended production from April through October 2013 because of “the seasonal lack of market demand for gas” in the summer in Southcentral. The well produced 2,299 thousand cubic feet per day at the start of the year but only 1,609 mcf per day by the end of the year.

This year, Hilcorp “anticipates limited production of KAS-1” because “no new drilling programs are justified, and current opportunities to enhance production are limited.”

The only maintenance activities Hilcorp had planned for 2014 was to run a capillary string to 13,000 feet to reduce “liquid loading” that has been “inhibiting sustained gas flow” from the KAS-1 well, the company said in a March 2014 plan of development.

Given the declining production and lack of foreseeable opportunities for development, Hilcorp told the state that it might use the Kasilof facilities to assist another asset in its portfolio, probably the nearby Ninilchik unit. “Existing facilities may be downsized to accommodate the reduced production capacity of the (Kasilof participating area) while benefitting the production of Hilcorp’s other assets that are currently not producing.”

Cumulatively, Kasilof produced some 4.3 bcf through July 2014.

The Ninilchik unit

The Ninilchik unit follows the coastline south of Kasilof.

Chevron discovered a Tyonek gas field in the area in June 1961. Marathon later discovered two other fields in 2001 and 2002 and pursued a development program.

The state formed the Ninilchik unit in 2001 and expanded it to include the former Falls Creek unit in 2003. Also in 2003, the state formed three participating areas at the unit: Falls Creek, Grassim Oskolkoff and Susan Dionne, which was expanded in 2007.

After acquiring the unit in early 2013, Hilcorp devoted considerable attention to Ninilchik, launching an exploration campaign and subsequently expanding existing developments.

Under its 2013 development plan, Hilcorp drilled four exploration wells: Susan Dionne No. 8, Paxton No. 5, Frances No. 1 and Falls Creek No. 5. The program primarily targeted gas but included some of the first oil exploration work at the field in decades.

The program prompted two major developments.

First, Hilcorp built a Bartolowitz pad at the unit and proposed a five-well development program. Second, Hilcorp said it would likely form two participating areas in 2015.

The 12,000-foot Susan Dionne No. 8 well was non-commercial for oil, but Hilcorp completed the well as a producer from both the Susan Dionne participating area and the Beluga formation on a tract basis. The results led Hilcorp to build the Bartolowitz pad in August 2013 and drill the Frances No. 1 exploration well later in the year.

Although Frances No. 1 was also non-commercial for oil, the well showed a “strong potential” for gas production. In August 2014, Hilcorp proposed a five-well development program from the Bartolowitz pad - two this year and up to three more by 2017.

The development proposal called for drilling the 10,000-foot Frances No. 2 well in October and the 10,000-foot Frances No. 3 well in November, with the Frances No. 4, Frances No. 5 and Frances No. 6 wells coming in subsequent years, as necessary.

Another large outcome from the exploration program is the “likely” expansion of the participating areas at the unit. The results of Frances No. 1 and Falls Creek No. 5 have led Hilcorp to consider applying for a Falls Creek Beluga participating area; results of Paxton No. 5 have led Hilcorp to consider forming a Susan Dionne/Paxton Beluga participating area.

In 2013, Hilcorp recompleted the SD-2 and SD-7 wells to help establish the boundaries of the participating area and bolster its application for a new participating area. And Hilcorp added perforations adjacent to existing open intervals in the SD-5 and SD-6 wells. The SD-2 recompletion failed, and Hilcorp drilled a sidetrack in December 2013.

Hilcorp proposed a six-well development program at Ninilchik in its 2014 development plan: Frances No. 2 and No. 3, PAX-6 and PAX-7, Falls Creek No. 6 and GO-8.

The 10,000-foot Frances No. 2 and Frances No. 3 wells form the initial phase of the proposed development program at the Bartolowitz pad. The 9,000-foot Falls Creek No. 6 would follow up on Frances No. 2 to further appraise the Tyonek and Beluga formations north of the Falls Creek pad. The 10,000-foot PAX-6 and PAX-7 wells also would target the Tyonek and Beluga formations and would likely require Hilcorp to expand the existing Paxton pad. The 6,500-foot GO No. 8 would target the Sterling and Beluga formations above the Grassim Oskoloff participating area, west of the GO pad.

The Alaska Oil and Gas Conservation Commission issued permits for a Paxton No. 7 well on Aug. 28, a Paxton No. 8 well on July 30 and a Frances No. 3 well on Aug. 28.

The 2014 program also called for recompleting the Falls Creek No. 3 well, bringing Paxton No. 1 back online or converting it to produce from the Beluga pool and evaluating the GO-7 well with an eye toward converting it to produce from the Beluga pool.

Averaging monthly production, Ninilchik produced some 37.1 mmcf per day in July 2014. Cumulatively, the unit produced 157 bcf through July 2014.

Deep Creek

The Deep Creek and Nikolaevsk units are in the southern Kenai Peninsula.

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 million cubic feet per day and drilled some 13 wells between 2003 and 2009. The early exploration work suggested additional accumulations at the unit. 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.

Since taking over the unit in early 2012, Hilcorp has made Deep Creek one of its early priorities. In 2013, the company drilled the Happy Valley B-14, Happy Valley B-15 and Happy Valley B-16 wells from the existing B pad. The first wells two tested formations above the existing production at the unit, but Hilcorp was unable to reach the target depth of 5,560 feet with the B-16 well and planned to sidetrack the well at the end of this year.

Hilcorp acquired some 47 square miles of 3-D seismic in early 2013. The survey suggested the resources at Happy Valley were “probably three to four times larger than the current participating area,” Hilcorp’s John Barnes told the Anchorage Energy Task Force in June 2013. The company also improved facilities to “expand and optimize production,” as the company told state officials in a March 2014 development plan.

The 2013 drilling campaign convinced the state to defer a pending contraction of the unit until November 2014. Given the exploration work to date, Hilcorp has asked the state to defer the contraction again, this time through the end of 2015. Hilcorp said the expansion would give the company time to complete exploration work and, based on the results of that work, potentially expand the unit or establish additional participating areas.

In August 2014, Hilcorp proposed a four-well development program from a to-be-constructed C pad. The program called for drilling the 6,000-foot HVC-17 in the fourth quarter and the 5,000-foot HVC-18 in the first quarter of 2015 to target the Sterling and Beluga formations outside the Happy Valley participating area, and drilling the HVC-19 and HVC-20 wells “in 2015 or later,” according to Hilcorp. The company has also proposed a Middle Happy Valley No. 1 exploration well further to the south in 2015.

Hilcorp also planned to work over four wells this year: adding perforations to HVB-12, stimulating the Beluga perforations in HVB-13, running a velocity string in HVB-14 and performing various work on HVA-7. The work was planned for the first three quarters.

Averaging monthly production, Deep Creek produced 8.6 million cubic feet per day in July 2014. Cumulatively, the unit produced 26.5 bcf through July 2014.

Nikolaevsk

Unocal discovered gas from a well at 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 conditions and infrastructure limitations.

In early 2011, as development of the nearby North Fork unit cut the distance to market, Unocal reached an agreement with the Department of Natural Resources to study a pipeline to North Fork rather than its earlier plan to connect to the grid at Happy Valley.

In September 2012, Hilcorp and the Enstar affiliate Alaska Pipeline Co. announced an $8.4 million pipeline running 10 miles from 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 605 million cubic feet through July 2014.

The well produced 2.5 mmcf per day at the start of 2013. Hilcorp suspended production from April to October 2013 because of seasonal demand restrictions. Production had fallen to 796 thousand cubic feet per day by the end of the year. Hilcorp installed extra compression in early 2014 to support a depleted reservoir.

Last year, Hilcorp told the state it was evaluating whether maintenance activities at Red No. 2 could make the well productive. Those activities did not occur in 2013. In a current plan of development running through May 2015, Hilcorp said it anticipates performing the work during this development year. The well work would stimulate open perforations in the Tyonek formation “in an attempt to establish commercial gas production.”

Averaging monthly production, Nikolaevsk produced 477 thousand cubic feet per day in July 2014. Cumulatively, the unit produced 605 million cubic feet through July 2014.

The Kenai unit

Hilcorp operates three units near the city of Kenai: Kenai, Cannery Loop and Sterling.

The Kenai unit was the first major natural gas discovery in the Cook Inlet basin.

Union Oil Company of California and Ohio Oil Co. discovered the onshore field in 1959, a few years after a major oil discovery at the Swanson River unit to the northeast. In Cook Inlet, those companies eventually became Chevron and Marathon, respectively.

They brought the field online in 1961 with a pipeline into Anchorage and later delivered surplus volumes to the Swanson River unit for enhanced oil recovery, to the Kenai liquefied natural gas terminal for export and to the Agrium fertilizer plant in Nikiski.

Through early February 2014, work at the unit was proceeding under an existing plan of development filed by pervious operator Marathon Oil. The U.S. Bureau of Land Management was unable to provide a current plan of development for the current year.

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.

According to AOGCC records, Hilcorp drilled three development wells at Kenai in 2014, through September: Kenai Beluga Unit 43-07Y in May and the Kenai Beluga Unit 11-08Z and Kenai Beluga Unit 23-05 in July. The company also permitted at least three other development wells: Kenai Beluga Unit 32-08, Kenai Beluga Unit 22-32 and the Kenai Deep Unit 10. All six wells are targeting either the Tyonek formation, the upper Tyonek Beluga formation, or, in the case of some wells, both formations simultaneously.

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. A renewed development program starting in 2000 lifted production to 28.5 bcf in 2003, according to the state. Production was down to 11.4 bcf by 2012, according to Marathon.

Averaging monthly production, Kenai produced 54.5 mmcf per day in July 2014. Cumulatively, the unit produced some 2.4 trillion cubic feet through July 2014.

Cannery Loop and Sterling

The Cannery Loop unit is just north of Kenai.

While initially a gas producing field, Cannery Loop currently plays a more important regional function as the home of the Cook Inlet Natural Gas Storage Alaska Inc. facility, also called CINGSA. The storage operation uses the depleted Sterling C reservoir.

But Hilcorp operates Cannery Loop production from three other reservoirs: the Beluga Gas pool, the Upper Tyonek Gas pool and the Tyonek D Gas pool. After taking over the unit in February 2013, Hilcorp amended an existing plan of development to accommodate an exploration well into the Hemlock and West Foreland formations.

Those oil-bearing formations flowed small amounts of oil during a 1987 test well, according to Hilcorp, but the zones have “large amounts of risk associated with reservoir productivity” and the well was “under evaluation” in a March 2014 plan of development.

Hilcorp did not drill at Cannery Loop in 2013 and only worked over one well, the CLU 8 into the Beluga. The goal was to test a previously unidentified gas interval, but the well flowed more water than gas. “The well is online at a lower rate,” according to Hilcorp.

The 2014 plan of development did not include drilling or well work, although Hilcorp planned to install compression on at least one well and expand infrastructure capacity.

Averaging monthly production, Cannery Loop produced 10.2 mmcf per day in July 2014. Cumulatively, the unit produced 190 bcf through July 2014.

To the east of Cannery Loop is the Sterling unit.

The unit dates to Unocal exploration from the early 1960s. Production has been small-scale and sporadic over the decades, with intervals and reservoirs shut-in at times.

Cumulatively, the Sterling unit produced nearly 14.4 bcf through July 2014.

Beaver Creek, Wolf Lake and West Fork

Due north of Sterling is the Beaver Creek unit and the Wolf Lake and West Fork fields.

Marathon discovered gas producing intervals in the Beluga, Sterling and Tyonek formations at Beaver Creek in 1967 and oil pool in 1972. Gas production peaked in 1986 at 17.7 bcf per year and oil production peaked in 1973 at 416,000 barrels per year.

Averaging monthly production, the Beaver Creek unit produced nearly 19 mmcf per day in July 2014. Cumulatively, the unit produced more than 216 bcf through July 2014.

The BLM was unable to provide a plan of development for the current year of work at Beaver Creek. Earlier this year, Hilcorp told the AOGCC that it planned to drill eight wells or sidetrack and perform six well workovers at the unit within the next few years.

In March 2014, Hilcorp completed the Beaver Creek Unit 14A gas production well into the Beluga and the Beaver Creek Unit 1B gas production well into the Tyonek.

This year, through the end of September, Hilcorp applied for permits to drill at least seven additional gas production wells into the Beluga formation at Beaver Creek.

To accommodate this renewed focus, AOGCC approved a vertical expansion of the official Beluga pool dimensions to include all potentially gas-bearing sands in the pool and an easing of restrictions on well spacing, which Hilcorp said would allow development of isolated areas within the reservoir that are currently being bypassed.

The West Fork field dates to exploration from 1960, but has produced sporadically through the years. As of July 2014, cumulative production was nearly 6 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 2014, cumulative production was some 822 mmcf.

Swanson River and Birch Hill

To the north of Beaver Creek are the Swanson River and Birch Hill units.

Richfield Oil Corp. discovered the Swanson River oil field in April 1957. It was the first significant oil discovery in the state and helped Alaska justify its bid for statehood.

Oil production at Swanson River 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. The field was only producing some 300 bpd by the time Hilcorp took over as operator.

Swanson River became a model for how Hilcorp approached its Cook Inlet portfolio: a drilling campaign combined with a thorough effort to sidetrack or repair existing 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.

Averaging monthly production, the Swanson River unit produced some 2,200 bpd in July 2014. Cumulatively, the unit produced nearly 232 million barrels through July 2014.

At an informal meeting of the Alaska House Resources Committee in February 2013, Hilcorp Energy President Greg Lalicker outlined plans to drill seven more wells and perform 15 workovers, with production expected to jump another 2,000 to 3,000 bpd.

Between January 2012 and September 2013, Hilcorp permitted at least 10 wells at the unit and drilled at least eight, completing the latest in September 2013, according to the AOGCC. By late 2013, Swanson River oil production had risen to some 2,500 bpd.

The BLM was unable to provide a plan of development for the current year of work at Swanson River. This year, through September, Hilcorp drilled two oil wells and permitted two more oil wells, all within the first half of the year, according the AOGCC.

Work to date at Swanson River has focused on increasing oil production. But in August 2014, the BLM posted a notice of staking by Hilcorp for a proposed gas production well at the unit - SRU 41B-33. Staking notices show where a company is interesting in drilling. Hilcorp must get an actual drilling permit before it could proceed with the well.

The Birch Hill unit is north of Swanson River.

ARCO Alaska Inc. discovered the Birch Hill field in 1965 and produced some 65 million cubic feet in that initial year. The field has been offline ever since. The BLM was unable to provide a plan of development for the current year of activities at Birch Hill, but Hilcorp had not permitted any new wells at the unit through September 2014, according to the AOGCC.



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