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Vol. 20, No. 47 Week of November 22, 2015
Providing coverage of Alaska and northern Canada's oil and gas industry

The Producers 2015: Hilcorp Alaska LLC

ERIC LIDJI

For Petroleum News

Hilcorp Alaska LLC became a top player in Alaska through three big purchases.

The privately held Houston-based independent acquired the Cook Inlet assets of Chevron subsidiary Union Oil Company of California in July 2011 and the Cook Inlet assets of Marathon Oil Co. in April 2012. Those two deals made Hilcorp the operator of some 20 oil and natural gas fields across the Cook Inlet basin: on the west side - the Lewis River, Pretty Creek, Stump Lake and Ivan River units; offshore - the Granite Point field, South Granite Point unit, Trading Bay unit, North Trading Bay unit, McArthur River field, North Middle Ground Shoal field, South Middle Ground Shoal unit; in the southern Kenai Peninsula - the Kasilof, Ninilchik, Deep Creek and Nikolaevsk units; in the northern Kenai Peninsula - the Birch Hill, Swanson River, Beaver Creek, Sterling, Cannery Loop and Kenai units, as well as the small Wolf Lake and West Fork fields. The deals also gave Hilcorp a minority interest in the ConocoPhillips-operated Beluga River unit and the XTO-operated Middle Ground Shoal field, which Hilcorp acquired from its majority partner this year.

The investment Hilcorp has made at those fields to date - some $300 million a year, compared to some $70 million a year by previous operators, according to the company - has altered the marketplace, taking a region that had been on the verge of importing liquefied natural gas to meet local demand to one that is, at least for the next few years, self-sufficient. The story is the same for oil. Since arriving in Alaska, Hilcorp has more than doubled oil production, to some 13,000 barrels per day up from some 6,000 bpd.

By owning so many fields at once, Hilcorp has also been able to consolidate in ways that were difficult when the region was divided among various players. Those consolidations include joining smaller fields into single units and combining four regional pipelines into a single integrated system, now called the Kenai Beluga Pipeline. The company has also been working to enter the Fairbanks market by attempting to acquire a liquefied natural gas terminal at Point MacKenzie and, as The Producers went to print, was in the running to partner with the Alaska Industrial Development and Export Authority on a plan to bring LNG to the Interior, which currently uses fuel oil as its primary heating supply.

This dominance has brought mixed feelings in Cook Inlet. While many are relieved to finally have an enthusiastic player in the region after decades of declining investment, some smaller independents worry about being crowded out of the local marketplace.

In late 2014, Hilcorp closed on its third major acquisition in Alaska, buying BP Exploration (Alaska) Inc.’s interest in a selection of North Slope properties. Through the deal Hilcorp became operator and owner of the Northstar unit, majority owner and operator of the Endicott field - the Duck Island unit, operator and 50 percent working interest owner of the Milne Point unit alongside BP and a 50 percent working interest owner of the BP-operated Liberty field, in federal waters of the Beaufort Sea. Hilcorp has since become the operator at Liberty.

Even though its North Slope operations are only a few months old, Hilcorp already claims to have flattened production at fields that had previously reported a 15 percent decline rate. And the company has filed a new plan for the stalled Liberty development.

Hilcorp spent $374 million in Alaska in 2014, of which 90 percent went toward Cook Inlet activities. The company has budgeted $340 million for 2015, which, given the level of activity Hilcorp has underway, reflects a concerted effort to cut operating costs.

Over its first four years in Alaska, Hilcorp claims to have made its Cook Inlet operating costs competitive with its Lower 48 operating costs. Now, the company is working to pull off the same feat on the North Slope, which is a harsher and more remote environment.

Founded in 1989 on a principle of “acquire and exploit,” Hilcorp doubled between 2006 and 2010 and its arrival in Cook Inlet was a step toward doubling again by this year.

The Ivan River, Stump Lake, Lewis River and Pretty Creek units

Since arriving in Alaska in 2011, Hilcorp has devoted far fewer resources to its assets at the northern end of the west side of Cook Inlet than it has to other regions in its portfolio.

The company operates four units in a small area along the coastline and inland south of the mouth of the Susitna River: Ivan River, Stump Lake, Lewis River and Pretty Creek.

Hilcorp might begin investing more in the region, soon. This year, Hilcorp will continue a “comprehensive field study” at Ivan River and conclude similar studies of Lewis River and Pretty Creek. Whether those studies will lead to development remains to be seen.

The Ivan River unit

The Ivan River unit hosts both production and storage.

Ivan River operations include the Sterling-Beluga participating area and the Tyonek participating area. In the Sterling-Beluga, Hilcorp produced 566 million cubic feet in 2014 at an average rate of 1.55 million cubic feet per day. In the Tyonek, Hilcorp produced 441 million cubic feet at an average rate of 1.2 million cubic feet per day.

Hilcorp didn’t drill at the unit in 2014 but added perforations to the IRU 44-01 and IRU 41-01 wells in May and June 2014, respectively. Both had “little effect” on production.

This year, Hilcorp is considering a grassroots well or a sidetrack to further develop the Sterling and Beluga reservoirs and a workover of the Sterling-Beluga at and IRU 41-01.

Through July 2015, the unit had produced more than 85.3 billion cubic feet.

Ivan River 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 44-36 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.

The Stump Lake unit

Stump Lake gas production was suspended in 1978, shortly after the unit was formed, and restarted in 1990. After a brief increase, production fell drastically until 2000, when the operations were once again suspended. Chevron returned Stump Lake to production in 2009 by sidetracking the original discovery well. Hilcorp added perforations to the SLU 41-33RD well but suspended production again in 2012 because of a build-up of solids.

In its recent plan of development, Hilcorp said there are currently few opportunities to revive existing wells and no justification for drilling additional wells, which is why the company has asked to keep operations suspended for another year, through May 2016.

Through July 2015, the unit had produced more than 6.6 billion cubic feet.

The Lewis River unit

Other than basic operations to maintain existing production, Hilcorp conducted no activities at Lewis River in 2014 and planned no activities for 2015. The unit produced some 428 million cubic feet throughout 2014, all from the LCU C-01RD well. Daily production declined slightly in 2015 from some 1.17 million cubic feet per day in 2014.

Through July 2015, the unit had produced more than 15 billion cubic feet.

The Pretty Creek unit

The Pretty Creek unit hosts both gas production and storage. Other than basic operations, Hilcorp conducted no activities at Pretty Creek in 2014 and planned none for 2015.

The unit produced 21 million cubic feet in 2014, all from PCU No. 2. Hilcorp injected 228 million cubic feet into PCU No. 4 in 2014, withdrawing 163 million during the year.

Through July 2015, the unit had produced more than 9.5 billion cubic feet.

The Granite Point unit

When Hilcorp acquired its initial Cook Inlet portfolio, the neighboring Granite Point field and South Granite Point unit were independent administrative entities. In early 2015, the Alaska Department of Natural Resources agreed to expand the South Granite Point unit to include the Granite Point field. The larger entity is now called the Granite Point unit.

Mobil Oil Corp. discovered the offshore Granite Point oil field in 1965 with the Granite Point No. 1 well, drilled into the Tyonek and Hemlock formations. The following year, the company installed three platforms - from south to north Granite Point, Anna and Bruce. Sustained production began in 1967 and waterflood operations began in 1971.

All three platforms primarily produce from the Middle Kenai “C” sands of the Tyonek formation, with the Hemlock formation currently producing from one well on the Granite Point platform. According to the state, some 112 wells have been drilled in the field.

Through July 2015, the unit had produced 151 million barrels of oil and more than 135 billion cubic feet of gas, according to the Alaska Oil and Gas Conservation Commission.

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.

The company completed projects at all three platforms in 2014.

At Anna, Hilcorp used Rig 428 to complete the AN-17A uphole sidetrack of a well it had drilled in November 2013. The platform started the year at some 1,221 barrels of oil equivalent per day and ended the year at some 1,195 boepd.

At Bruce, Hilcorp used the Moncla rig 301 to fracture stimulate BR-86-08 and return the well to production. The well had been shut-in since 2010 due to parted tubing. The platform started the year at some 414 boepd and ended the year at some 476 boepd. At Granite Point, the company used the Moncla rig 301 to work over GP-54 and return it to project. The well had been shut-in since 2005, due to parted tubing. The platform started the year at some 1,361 boepd and ended the year at some 1,518 boepd.

This year, Hilcorp planned a much busier workover regime at its expanded unit.

At Anna, the company plans to work over four wells using Moncla 301. The plan calls for recompleting AN-17A to produce from the Tyonek C sands, adding Tyonek C perforations to AN-24RD and AN-11RD and replacing a jet pump cavity in AN-51.

At Bruce, the company plans to use Moncla rig 404 to replace the completion of BR-20RD-42 and work on a lower jet pump in the bottom-hole assembly of BR-42-42.

At Granite Point, the company plans to use Moncla 301 to replace a failed electric submersible pump in GP-54, add a Tyonek C perforation in GP-11-13RD that would comingle with an existing perforation into the Hemlock sands, add a Tyonek C perforation in GP-51 and install an ESP and install an ESP completion in GP-42-23D.

The Trading Bay, North Trading Bay and McArthur River fields

At the southern end of the west side of Cook Inlet, Hilcorp operates three offshore fields: the Trading Bay unit and the nearby McArthur River field and the North Trading Bay unit. Hilcorp currently manages Trading Bay and McArthur River through a single plan of development and appears to desire even greater unity among the three offshore fields.

The Trading Bay unit and McArthur River field are home to the Grayling, Dolly Varden and King Salmon platforms - all named for types of fish common to Alaska waters. In 2014, Hilcorp commissioned the built-for-purpose HAK No. 1 rig for these platforms.

Union Oil Company of California discovered the three oil-bearing reservoirs at Trading Bay in 1965 and brought them online in 1967. The company discovered the Grayling gas sands at the unit in 1968. Today, the unit continues to produce both oil and natural gas.

At Trading Bay, Hilcorp started 2014 producing 342 barrels of oil equivalent per day and finished the year at 192 boepd. The reduction appears to have been largely the result of declining natural gas production because the unit was producing 156 barrels of oil per day at the start of the year 149 bopd by the end.

The Trading Bay unit includes the Undefined Oil Pool, the Tyonek Oil Pool and the Hemlock Oil Pool. Last year, Hilcorp drilled only one new well at the unit, the A-31 production well into the Hemlock. The company worked over seven wells in 2014.

The current plan of development calls for an eight well workover program this year.

Through July 2015, the unit had produced more than 105.7 million barrels of oil and 83 billion cubic feet of gas, according to the Alaska Oil and Gas Conservation Commission.

At the McArthur River field, Hilcorp started 2014 producing 4,372 boepd and finished the year at 5,500 boepd. In the Grayling Gas Sands, the company started the year producing 5,842 boepd and finished the year at 4,556 boepd.

In 2014, the company drilled one well at the McArthur River field, the Steelhead M-34 producer into the Hemlock. The company also performed 19 workover projects. This year, the company plans to drill one well and work over seven existing wells.

Through July 2015, the McArthur River field had produced more than 638.6 million barrels of oil and more than 1.3 trillion cubic feet of gas.

The North Trading Bay unit has the Spark and Spurr platforms. Chevron discovered the accumulation in the Hemlock and “G” formation participating area in 1965 with the Trading Bay No. 1A well and brought the unit online in 1968. The platforms have been light-housed since in 1992, aside from an attempt at gas production from Spark in 2007.

Since acquiring the assets, Hilcorp has been conducting reservoir engineering and geological studies to identify future opportunities. The work is scheduled through 2017.

Marathon had been moving toward decommissioning and removing the platforms, and had been submitting abandonment plans to state officials since 2009. But Hilcorp has said it 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.”

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

In October 2014, Hilcorp drilled the A-31 exploration well from its Monopod platform at the neighboring Trading Bay field. The well encountered “productive hydrocarbons in the Hemlock and Tyonek E zone formations but did not find hydrocarbons in the Tyonek C or D zones,” according to the company, which said it “is now working to reevaluate potential in the Kokanee fault block that would be used to justify platform reactivation.”

The Middle Ground Shoal fields

In the center of the Cook Inlet, Hilcorp operates three neighboring and related offshore fields: North Middle Ground Shoal and its Baker platform, South Middle Ground Shoal and its Dillon platform and Middle Ground Shoal and its “A” and “C” platforms.

Through July 2015, the fields had produced more than 202 million barrels of oil and 94.6 billion cubic feet of gas, according to the Alaska Oil and Gas Conservation Commission.

Middle Ground Shoal

Shell Oil discovered Middle Ground Shoal in 1963 with MGS State No. 1, the first offshore oil completion in Alaska, according to the American Association of Petroleum Geologists. By the time XTO-predecessor Cross Timbers Oil Co. purchased the field from Shell in 1998, Middle Ground Shoal was producing 3,600 barrels per day and falling. By 2006, XTO had drilled 12 penetrations throughout the field, which doubled oil reserves to 24 million barrels and brought production to the range of 3,000 to 4,500 bpd.

That pace slowed as XTO turned its attention to more profitable assets. Despite ongoing maintenance, and various proposals over the years for additional development opportunities including sidetracks and wells into other formations, XTO hasn’t drilled at the field since 2005, according to Alaska Oil and Gas Conservation Commission records.

Still, Middle Ground Shoal remains important to the regional economy. The field accounts for approximately one-eighth of total Cook Inlet oil production, which made XTO among the largest taxpayers in the Kenai Peninsula Borough for many years.

Even so, Middle Ground Shoal was mostly irrelevant to Exxon when, in late 2009, it purchased XTO in an all-stock deal worth $31 billion. Instead, Exxon wanted XTO’s sizable North American natural gas holdings as an entree to the unconventional boom then underway. XTO sold Middle Ground Shoal to Hilcorp Alaska LLC in early 2015.

North Middle Ground Shoal

The state approved a plan in 2012 for abandoning the lighthoused Baker platform, but Hilcorp amended the plan later in the year. The company had decided to reactivate the platform for gas exploration. A workover program in 2013 returned the existing BA-14 well to production. Now, the well provides fuel gas to the Middle Ground Shoal field.

Although Hilcorp neither drilled nor worked over any wells at North Middle Ground Shoal in 2014, and is planning neither for 2015, the company completed a reservoir study last year to determine the future of oil production at the field. The company is in the early stages of planning a seven-well workover program that would finish by the end of 2016.

South Middle Ground Shoal

Previous operator Unocal decommissioned the Dillon platform at the South Middle Ground Shoal unit in 2003. Hilcorp has been undertaking a multiyear study to evaluate the possibility of reactivating the platform in mid-2018, pushed back from a prior deadline of mid-2016. The delay would allow Hilcorp to complete its activities at North Middle Ground Shoal. The study includes re-mapping relevant horizons, compiling well histories, building reservoir simulation models and potentially shooting a 3-D seismic survey. Hilcorp performed no drilling or well work in 2014 and planned none for 2015.

Swanson River unit

Richfield Oil Corp. discovered the Swanson River oil field in April 1957. When oil production began from the Hemlock formation the following year, it helped bolster the case for statehood by giving Alaska a realistic platform on which to build its economy.

Oil production peaked at 38,323 barrels per day in November 1967 but the field was only producing some 300 bpd by the time Hilcorp took over as operator.

The U.S. Bureau of Land Management manages the unit.

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.

Through July 2015, Swanson River had produced 232.6 million barrels of oil and 2.9 trillion cubic feet of gas, according to the Alaska Oil and Gas Conservation Commission.

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.

A survey Hilcorp provided to federal officials for the 2013 and 2014 drilling season, and updated since, proposed activities at 10 idle wells in 2015 and 14 idle wells in 2016.

Through late September, Hilcorp had completed two new oil wells at the unit this year: the Soldotna Creek Unit 41B-04 and the Soldotna Creek unit 21C-04 (from late 2014).

Work to date at Swanson River has focused on increasing oil production. But BLM has recently posted two notices of staking by Hilcorp for proposed gas production wells at the unit - SRU 41B-33 and SRU 212B-15. Staking notices show where a company is interesting in drilling. Hilcorp must get additional permits before it can drill the wells.

The company received Alaska Oil and Gas Conservation Commission permits for two proposed natural gas wells in 2015: Swanson River Unit No. 213-15 and No. 213B-15.

The Beaver Creek unit

Marathon discovered natural gas producing intervals in the Beluga, Sterling and Tyonek formations at the Beaver Creek field in 1967 and an oil pool in 1972. Gas production peaked in 1986 at 17.7 billion cubic feet per year and oil production peaked in 1973 at 416,000 barrels per year. The U.S. Bureau of Land Management manages the unit.

In its 2014 plan for development, Hilcorp said it planned to drill eight wells or sidetracks and perform six well workovers at the unit within the next few years. In its current plan of development, ending March 2016, the company said it drilled seven penetrations - three wells and four sidetracks - in 2014 and conducted maintenance on eight wells.

The wells were drilled at the end of the year and came online in December: BCU 23 into the Beluga, BCU 24 into the Beluga and Tyonek and BCU 25 into the Sterling B4 interval.

The sidetracks were drilled earlier in the year. The BCU 1B sidetrack into the Beluga came online in April 2014. The BCU 14A sidetrack into the Beluga and Sterling came online in May 2014. The BCU 7A sidetrack into the Beluga came online in August 2014. The BCU 12A sidetrack into the Beluga and Sterling came online in September 2014.

To accommodate this renewed focus, the Alaska Oil and Gas Conservation Commission approved a vertical expansion of the official Beluga pool dimensions in 2014 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.

This year, Hilcorp planned no drilling activity at Beaver Creek but described a six-well workover program in its development plan. The program includes work on BCU 25, BCU 12A, BCU 10 and BCU 24 to improve gas production and work on BCU 2 and BCU 3RD to improve well disposal capabilities. The company is also planning a major campaign to upgrade facilities at the unit, similar to a program conducted last year.

Through July 2015, the Beaver Creek unit had produced nearly 6.3 million barrels of oil and nearly 225 billion cubic feet of gas, according to the AOGCC.

The Sterling unit

Union Oil Company of California discovered the first reservoir at the Sterling unit in 1961 with the Sterling Unit No. 32-09 well and brought the unit into production in 1962 from the “A” Zone participating area. The company discovered three more reservoirs in 1998 and 1999: the Upper Beluga, Lower Beluga and Tyonek participating areas.

Over the decades, production has been slow and sporadic. At times, individual intervals, entire reservoirs and even the unit as a whole has been shut-in for stretches. The unit produced approximately 139 million cubic feet of natural gas in 2014 before the SU 41-15RD and SU 32-09 wells went offline and stopped production from the entire unit, according to Hilcorp. In October 2014, the company asked the U.S. Bureau of Land Management for permission to suspend production from the unit for the time being.

At a January 2015 technical meeting with the federal agency, Hilcorp detailed aspects of “a field study to determine the extent and feasibility of extending field life.” While the company has yet to plan any wells, it might conduct a workover campaign to restore production. In March, the company began permitting a workover of the existing and currently shut-in SU 41-15 RD well to add perforations into the Lower Beluga formation.

This year, the company intends to “evaluate and execute” workover projects as they arise and said it would conduct repairs and upgrades including potential pad and production facility expansions, upgrades to piping and electrical systems and increased compression.

Through July 2015, the unit had produced nearly 14.5 billion cubic feet.

The Kenai unit

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 Kenai natural gas field in 1959, a few years after a major oil discovery at the Swanson River field to the northeast. 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. Gas production peaked in the mid-1980s and declined through the late 1990s, when renewed investments led to a bump. Production has been falling somewhat steadily since 2003.

Through September, Hilcorp had drilled two new wells at the unit in 2015: the Kenai Beluga Unit 31-18 and the Kenai Beluga Unit 22-06Y. In 2014, the company drilled as many as five wells at the unit: Kenai Beluga Unit 42-06Y, Kenai Beluga Unit 11-08Z, Kenai Beluga Unit 23-05, Kenai Beluga Unit 43-07Y and Kenai Deep Unit 10.

Through July 2015, the unit had produced more than 2.4 trillion cubic feet.

The Kenai unit is a self-contained petroleum system and one nearly depleted pool is currently being used for gas storage operations. In 2014, Hilcorp produced 1.65 billion cubic feet of natural gas at an average daily rate of 4.5 million cubic feet per day from the storage operation. The company injected 6.33 billion cubic feet of gas at an average rate of 17.3 million cubic feet per day through its storage operations. The company drilled no wells, performed no well work and conducted no major facility improvements at the storage operation in 2014 and planned none of those activities for 2015, according to the most recent plan of development for the storage operation, submitted earlier this year.

The Cannery Loop field

Union Oil Company of California discovered four reservoirs at the Cannery Loop field in 1978 and 1979 with the Cannery Loop Unit No. 1 well. Although originally a federal unit, the U.S. Bureau of Land Management gave the unit to state oversight in 2010.

Initially a producing natural gas field, Cannery Loop currently plays a more important regional function as the site of the Cook Inlet Natural Gas Storage Alaska Inc. facility, also called CINGSA. The storage operation uses the depleted Sterling C reservoir, although recently discovered native gas has created the possibility of future production.

Hilcorp still 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 operatorship in February 2013, Hilcorp amended an existing plan of development to accommodate an exploration well into the Hemlock and West Foreland formations.

Hilcorp did not drill or work over any wells at the Beluga Gas pool in 2014 but intends to drill the CLU No. 14 well into the pool this year. The pool started 2014 at 1,473 barrels of oil equivalent per day and ended the year at 1,024 boepd.

Hilcorp did not drill any wells at the Upper Tyonek Gas Pool in 2014 but completed the CLU No. 13 well in early 2015. Hilcorp also performed some maintenance activity on CLU 01RD, which “seemed to increase production slightly,” according to the company.

Hilcorp did not drill or work over any wells at the Tyonek D pool in 2014 but plans to drill the CLU 15 well into the pool this year. CLU 13 would also target those sands.

In 2014, Hilcorp installed a small compressor at the CLU No. 3 pad and intends to use the equipment at CLU No. 11 in the future. The company is considering a compression installation at the CLU No. 1 pad this year. The company also conducted an unsuccessful repair job on CLU No. 7 and intends to return to the well this year to fix the problem.

Through July 2015, the unit had produced 192.9 billion cubic feet.

The Birch Hill, West Fork

and Wolf Lake fields

Through its two Cook Inlet acquisitions, Hilcorp assumed responsibility for several once-producing oil or natural gas fields that are currently shut-in for various reasons.

The company operates three such fields in the northern Kenai Peninsula.

Birch Hill

ARCO Alaska Inc. discovered the Birch Hill field in the northern end of the Kenai Peninsula in 1965 and produced some 65 million cubic feet that year before suspending production. Although the field has since been shut-in and Hilcorp conducted no activities in 2014, the company told federal officials it plans to revive production in the near future.

Throughout 2012 and 2013, the company conducted and revised planning and engineering design for a road, gathering line and facilities and cleared vegetation from the right of way. In late April 2014, representatives from Hilcorp, the U.S. Bureau of Land Management and the U.S. Fish and Wildlife Service visited the Birch Hill pad, which can currently only be accessed by foot along the proposed road corridor.

Following all those activities, Hilcorp is currently planning to build a snow road, move a workover rig and testing equipment to the pad, remove the plug and test the well this coming winter, if market and weather conditions accommodate. If the test proves the field is non-commercial, the company would re-plug and abandon the well. If the test is successful, Hilcorp would build surface facilities and install a natural gas gathering line.

West Fork and Wolf Lake

The West Fork field dates to exploration from 1960, but has produced sporadically through the years. Through July 2015, the field had produced nearly 6 billion cubic feet.

The nearby Wolf Lake field dates to exploration from the late 1990s, but was always one of the smaller fields in Cook Inlet and stopped producing around 2005 after declining steeply. Through July 2015, the field had produced more than 822 million cubic feet.

The Kasilof unit

Union Oil Co. drilled three dry holes at the Kasilof field in the late 1960s and other companies including Mesa Petroleum and Standard Oil Company of California later discovered gas at the field. Marathon Oil Co. 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 in 2014. The unit started the year at some 2 million cubic feet per day but Hilcorp suspended operations in April 2014 and moved some of the production equipment to other fields.

“The existing intermittent producing well will remain shut in until a smaller and more economic production facility can be installed,” the company said in its current plan of development, filed with state officials in early March 2015. Hilcorp has asked for permission to keep operations suspended through at least May 2016. “At this point in the field’s development, no new drilling programs are justified, and current opportunities to enhance production from existing well bores are limited,” the company wrote in its plan.

In 2014, Hilcorp told the state that it might use the Kasilof facilities to assist another asset, probably the nearby Ninilchik unit, where Hilcorp has been rapidly expanding exploration and development activities. “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,” the company wrote. But no such language appeared in the 2015 plan of development.

Through July 2015, Kasilof had produced 4.3 billion cubic feet.

The Ninilchik unit

Although Ninilchik is a producing unit, many of Hilcorp’s current projects are exploratory in nature. Since acquiring the unit, Hilcorp has built several drilling pads to target potential oil and natural gas accumulations outside of existing participating areas.

As such, sections of the unit are regularly moving from exploration into development.

The Ninilchik unit follows the coastline in the area south of Kasilof in the southern Kenai Peninsula. Chevron discovered a gas field in the Tyonek formation in the area in June 1961. Marathon discovered two other nearby fields in 2001 and 2002 and subsequently 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: Falls Creek, Grassim Oskolkoff and Susan Dionne, which was expanded in 2007. Hilcorp recently has completed an eighth drilling pad and was working on a ninth as The Producers went to press.

Although Hilcorp appears to be shifting its focus at Ninilchik toward development activities, the company proposed three wells in its plan of development for 2015.

The first is the 12,000-foot Blossom No. 1 exploration well to target the Beluga and Tyonek formations from the Blossom pad. The second is the 12,000-foot GO No. 8 exploration well targeting the Beluga and Tyonek north of the Grassim Oskolkoff pad. The third is the 9,000-foot Kalotsa No. 1 development well at the new Kalotsa pad.

The AOGCC issued drilling permits for Blossom No. 1 in late March 2015 and GO No. 8 in June 2015 and had yet to issue a drilling permit for Kalotsa No. 1 by late September.

This year, Hilcorp has been working on the Blossom and the Kalotsa pads - the eighth and ninth at the unit. Blossom will connect to the existing Grassim Oskolkoff pad to the south. Kalotsa, in the southern end of the unit, between the existing Susan Dionne and Paxton pads, will support a two-well program into the Tyonek and Beluga formations.

The 2015 program also includes maintenance work on nine existing wells. Those activities include plans to return shut-in wells to produce, improve performance from old wells by adding perforations and conducting maintenance work on some newer wells.

Through July 2015, Ninilchik had produced 171.6 billion cubic feet.

The Deep Creek unit

Following up on a 1958 exploration program by Standard Oil Company of California, Union Oil Company of California brought the Deep Creek unit online in 2004 at 3 million to 4 million cubic feet per day and drilled some 13 wells between 2003 and 2009.

Despite this initial enthusiasm, investment soon flagged at the onshore unit in the southern Kenai Peninsula. In an eighth plan of development, from December 2010, Unocal offered no plans for further exploration but said it wanted to farm out exploration acreage in the south of the unit. Believing that the unit contained additional accumulations, Alaska Division of Oil and Gas Director Bill Barron required the next plan of development for the unit to include plans for exploring acreage outside the Happy Valley participating area. By the time Hilcorp acquired the unit, the state and Cook Inlet Region Inc., also a subsurface owner in Deep Creek, were on the verge of contracting the unit. Instead, they extended the eighth plan of development to give Hilcorp more time to determine its plans for the unit. The extension gave the company until February 2013, or six months after closing, whichever came first, to file a ninth plan of development with exploration plans.

To start, Hilcorp drilled three development wells at the unit: The 2,005-foot Happy Valley B-14 tested the Sterling formation shallower than the existing participating area; the 3,069-foot Happy Valley B-15 tested the Upper Beluga formation, also shallower than the existing participating area; and the 4,857-foot Happy Valley B-16 well targeted the Beluga formation, although “rig limitations” prevented it from reaching its target depth. In early 2013, Hilcorp acquired some 50 square miles of 3-D seismic over the unit.

The program discovered commercial quantities of gas in the Sterling and Beluga formations, shallower than the producing Beluga/Tyonek pool. Speaking in June 2013, Senior Vice President John Barnes said the field was “making more now than it was shortly after Unocal discovered and developed it” and estimated that the resource at Happy Valley is “probably three to four times larger than the current participating area.”

With the successful program, Hilcorp said it would expand its exploration activities for two years and asked the state to defer contraction of the unit through the end of 2015.

The 2014 plan called for completing the B-16 well, potentially using a sidetrack, and drilling two exploration wells from a newly constructed C pad. The 6,000-foot Happy Valley C-17 well and the 5,000-foot Happy Valley C-18 well would both target the Sterling and Beluga formations outside the Happy Valley participating area. If successful, the exploration program would likely justify a new participating area, Hilcorp has said.

Ultimately, Hilcorp drilled none of those wells in 2014. However, the company processed preliminary data from the seismic survey between March and October 2013 and conducted “pre stack depth mitigation” processing in 2014. As of March 2015, “interpretation of the 3-D data is in progress and will be used to establish the Deep Creek unit’s exploratory and development drilling program throughout 2016,” according to the most recent plan of development. The plan also proposes drilling a Middle Happy Valley No. 1 well, which would require the construction of a new drilling pad at the unit. The company began permitting the Middle Happy Valley pad toward the end of this summer.

In July 2014, Hilcorp proposed construction of a Happy Valley C pad and an accompanying four-well appraisal program to prove up and possibly develop a shallow natural gas accumulation. If successful, Hilcorp said it would initially develop the pad using existing facilities at B pad and potential construct new facilities at the C pad. The company began permitting some of those projects in mid-2014 and the first half of 2015.

Through July 2015, Deep Creek had produced 29.2 billion cubic feet.

The Nikolaevsk unit

Union Oil Company of California 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 end of the regional natural gas transmission grid at Happy Valley, to the north.

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.

Instead, production went the opposite direction.

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 Red No. 1 well online in December 2012 at 5 million cubic feet per day.

Since then, operations have proven tricky.

Red No. 1 was producing 2.5 million cubic feet per day at the start of 2013. Hilcorp suspended production from April to October 2013 because of seasonal demand restrictions. By the end of the year, production had fallen to 796,000 cubic feet per day.

Even though Hilcorp installed a compressor at the field in the first quarter of 2014 to increase production from the Red No. 1 well, production rates declined significantly over the course of the year - from 1.1 million cubic feet per day at the start of the year to 300,000 cubic feet per day at the end of the year. Then the company shut in the field between November 2014 and February 2015 “due to the lack of a market for the gas.”

Hilcorp performed no drilling or major well work activity at the unit last year and has planned no drilling or major well work activity for this year, according to the company.

Through July 2015, Nikolaevsk had produced 690 million cubic feet of gas.

The Milne Point unit

Standard Oil Company of California discovered four Milne Point horizons in the area northwest of the Prudhoe Bay unit in 1969. The unit primarily produces from the Kuparuk oil pool, as well as from the heavier Sag River and Schrader Bluff pools.

An even heavier Ugnu pool has been under evaluation for many years.

Conoco Inc. delineated the field in 1980 and brought it online in November 1985 but suspended operations from January 1987 until April 1989 because of low oil prices.

By the time BP acquired the unit, in 1994, oil production had fallen to 17,000 barrels per day from a peak of 20,000 bpd several years earlier, according to the Alaska Oil and Gas Conservation Commission. BP built the F pad in the northern end of the unit and the K pad in the southeastern corner of the unit, which pushed production to 52,900 bpd by July 1998. But oil production has since fallen back below 20,000 bpd, according to BP.

Through July 2015, Milne Point had produced nearly 326 million barrels of oil.

In its first year as operator, Hilcorp began a major revitalization of Milne Point. In the first three months after formally taking over the unit in December 2014, Hilcorp brought five wells back into operation but nevertheless saw a slight decline in total unit production, which the company blamed on a large backlog of workovers to complete.

In the first half of 2015, the state agreed to extend an existing plan of development submitted previously BP to shift the annual cycle so that it begins in the spring. The current plan of development now runs from January 2015 through the end of July 2016.

With the extension, Hilcorp also proposed some additional activities.

The current plan now calls for drilling as many as six wells across the three main reservoirs and conducting maintenance on as many as 39 existing wells at the unit. The proposed workover program includes wells at B, C, D, E, F, J, K, L and S pads. While some of those efforts were carried over from BP, Hilcorp also announced plans to build a fairly sizable new facility designed to improve the environmental impact of operations.

As of Jan. 31, the Milne Point unit was producing 19,400 barrels of oil per day from the Kuparuk, Schrader Bluff and Sag River formations. The unit had 327 wells, of which only 187 - 108 producers and 79 injectors - were active, according to Hilcorp.

The Schrader Bluff formation

Conoco spent $130 million building four pads and drilling 22 wells at Schrader Bluff and brought the formation online in March 1991 at 3,700 bpd. But oil production had fallen to 2,850 bpd by the time BP took over the unit in early 1994, according to the AOGCC.

After several years of drilling activities without a significant boost in production, BP announced a plan in 1997 to develop Schrader Bluff with seven new or expanded pads, 75 miles of new pipeline and some 300 wells. By 2001, BP decided the program was uneconomic. Instead, BP expanded conventional drilling at E pad, H pad and J pad, lifting production to 12,000 bpd by April 2002, and built S pad in the south of the unit.

While BP had previously proposed a four-well program into the Schrader Bluff in 2013, the company postponed those wells until 2016 “to allow additional planning time due to concerns over reservoir pressure in existing injector wells near the planned targets and complications in defining the completion design,” accord to the plan of development.

So far, Hilcorp appears to be focusing its energies on the Schrader Bluff formation.

Between mid-July and early September, the Alaska Oil and Gas Conservation Commission issued permits for six wells at Milne Point - three development and three service, all targeting the Schrader Bluff formation. The producers would be the Milne Pt Unit SB L-46, Milne Pt Unit SB L-47 and Milne Pt Unit SB J-27. The injectors would be the Milne Pt Unit SB L-48, Milne Pt Unit SB L-49 and Milne Pt Unit SB L-50. The company has contracted the Nordic 3 rig for grassroots wells and rigged workovers.

Through July 2015, the Schrader Bluff had produced nearly 74 million barrels.

The Kuparuk formation

The proposed drilling campaign would be the first at Milne Point since early 2014, when BP drilled at least 17 wells into the Kuparuk formation, according to AOGCC records.

That program, in turn, was the first development program at Milne Point in five years.

In the Kuparuk formation, Hilcorp is mostly continuing waterflood and enhanced oil recovery techniques over the short run. But the company said it is currently evaluating a 2012 seismic survey conducted over the region to “determine if economic accumulations of oil exist near the margins of the existing development patterns,” which could led to infill drilling. The company expects to complete some of this evaluation this year.

Through July 2015, the Kuparuk had produced more than 249 million barrels.

The Sag River formation

Conoco tested the Sag River formation at Milne Point as early as 1980, and BP brought the field into production in 1995. Despite occasional spikes through the years, average annual production has generally been less than 700 bpd. Sag River is the deepest producing interval at Milne Point, with lighter oil than either Schrader Bluff or Ugnu.

But high gas-to-oil ratios and poor pump performance have challenged production.

Prior to the Hilcorp sale, BP had planned a 15-well program at Sag River in 2015 and 2016, according to BP Alaska President Janet Weiss. If successful, BP could potentially drill as many as 200 wells, accessing some 200 million barrels of resources with full development. Now, Hilcorp said it is continuing to study options. The company plugged the K-33 well into the Sag River back to the Kuparuk because of low Sag River production. The current set-up allows the company to switch between the formations.

Through July 2015, the Sag River had produced nearly 2.8 million barrels.

The Ugnu formation

The 20 billion barrel Ugnu formation overlying portions of the Prudhoe Bay, Kuparuk River and Milne Point unit is the most technically challenging field at Milne Point.

Starting in 2007, BP launched a pilot program at S pad to test various techniques for producing heavier oil. The first, called CHOPS, or cold heavy oil production with sand, produces oil-saturated sand and heats the mixture at the surface to separate the oil from the sand. BP also began evaluating an alternate method involving horizontal wells.

Following the launch of a $100 million testing facility, BP brought a horizontal heavy oil test well into operation in April 2011. This initial well surpassed expectations, as did the first CHOPS well completed in late 2012. But BP believes it still must demonstrate the long-term viability of the program and better manage the costs of heavy oil production before Ugnu can become a regular component of the North Slope production picture.

Prior to the sale, BP drilled four test wells, two nearly vertical and two horizontal. The initial production tests produced as much as 500 bpd, BP Exploration (Alaska) technology manager Frank Paskvan told the state Senate Resources Committee in April 2014. But a rotating metal rod used drive the underground pump rotor wore holes in the well casing, Paskvan said. “So we’re doing studies now on artificial lift and hope that will improve the run life, because these workovers and tubing replacements were very expensive and made it difficult to continue the operations of the pilot,” he said.

While Hilcorp now has access to the results of those wells, the company is taking it slow at Ugnu for the moment. The current plan of development calls for working over the S-39 well this year and launching a larger Ugnu drilling campaign sometime in 2016.

Grind and Inject

The amended plan of development also called for constructing a Grind and Inject Facility at the Milne Point unit to create a waste discharge system with fewer surface impacts.

The project includes a facility at Milne Point Unit B Pad, installing surface piping to connect the facility to an injection well and other associated infrastructure requirements.

Hilcorp began permitting the facility this past summer. In filings with the state, the company described a facility capable of processing some 40,000 cubic yards per year.

The company said it was also evaluating a plan to reactive a similar facility at the Northstar unit. Previous operator BP built the facility in 1998 and closed it in 2010.

The Duck Island unit

Sohio Alaska Petroleum Co. discovered the offshore Endicott oil pool in 1978.

After building two compact gravel islands connected to shore by a causeway - the first offshore islands for oil production in the Arctic - BP Exploration (Alaska) Inc. brought Endicott online in July 1986. The field was later incorporated into the Duck Island unit.

Oil production peaked at some 118,000 barrels per day in the early 1990s.

Today, the Duck Island unit includes the Endicott, Eider and Sag River North participating areas at the northern end of the unit and production from the Minke tract at ADL 34633. Through July 2015, the unit had produced more than 480.6 million barrels of oil from those areas, according to the Alaska Oil and Gas Conservation Commission.

Endicott history

The bulk of production comes from Endicott.

BP launched a five-year renewal campaign at the field in 2008. The heart of the program was infrastructure upgrades from wellheads to processing facilities, Endicott Field Manager TJ Barnes told Petroleum News in early 2009. Those efforts, in part, were meant to prepare the facility for an expected influx of oil from the proposed Liberty field.

(For a time, BP planned to use the Endicott facilities to develop the offshore Liberty field through state-of-the-art ultra-extended reaching wells. Those plans have since changed.)

The plan was to use LoSal enhanced oil recovery program first, followed by enhanced oil recovery using carbon dioxide once North Slope gas sales began. “We’ve rebuilt our reservoir models and have developed a comprehensive depletion plan for Endicott,” Alaska Consolidated Team Resource Manager John Denis told Petroleum News in early 2009. “We’re into the fourth year of a program to stabilize and improve the reliability of our facilities and wellstock, we have brought (the safety and integrity Operations Management System) to Endicott, and we have a robust program underway to renew our facilities. With the development of new technologies like LoSal and production from the new Liberty field, we’re looking ahead to a very bright future for Endicott.”

After trademarking the technology in 2005, BP tested its proprietary LoSal technique at the Endicott field between June 2008 and early 2010. The test suggested the possibility to recover as much as 20 percent of the oil remaining in an aging reservoir such as Endicott.

When the five-year renewal campaign ended and plans for developing the Liberty field stalled under technical pressures, Endicott lost its immediacy for BP. The company worked over three wells in 2013 and performed no drilling or maintenance work in 2014.

Using miscible water alternating gas flood injections, Hilcorp realized what it called “modest” production increases in its first months as operator of Duck Island. The unit produced 208,170 barrels of oilin October 2014, before Hilcorp assumed operations, according to figures from the company. This January, the unit produced 258,350 barrels, down from a high of 274,647 barrels in December 2014. The company said it “intends this same progress to continue” through the current reporting period of May 2016.

Endicott plans

In its first year as operator, Hilcorp approached Endicott from two angles.

First, the company launched a monitoring campaign to track the movement of injection fluids through the reservoir. The results of this monitoring will determine whether the company can expand its enhanced oil recovery process “to new patterns in the upper subzones” or whether an alternative enhanced oil recovery process would be viable.

Similarly, Hilcorp is also performing engineering studies to determine whether it should inject water into the gas cap at Endicott. Those studies will likely continue into 2016.

Second, the company planned to once again work over existing wells at the field for the first time since 2013. The company said it is also considering conversions, sidetracks and other maintenance activities at Endicott this year, although these activities have yet to be sanctioned and depend on economics and on the results of studies currently underway.

Hilcorp planned no workovers, sidetracks or notable maintenance at Eider, Sag Delta North or the Minke tract this year but said it would look for opportunities at all three.

The Northstar unit

Shell Western E&P Inc. discovered Northstar in 1984. The state and federal governments jointly formed the Northstar unit in 1990 and expanded it in 2001. BP Exploration (Alaska) built a five-acre gravel island and a subsea pipeline and brought the offshore oil field into production in November 2001. The Northstar participating area at the unit was contracted in 2005 and 2011 and expanded in 2014.

The federal government approved the Fido participating area in 2002 and the state and federal governments jointly approved the Hooligan participating area in early 2015.

Prior to selling the unit, BP was injecting gas into the Ivishak formation to improve reservoir pressure for enhanced oil recovery and was considering a plan to convert one or more production wells at the unit into injection wells to aid with that ongoing effort.

Hilcorp expects Northstar oil production to be “maintained or increased” this year through a combination of maintenance activities and restructuring of existing wells.

The company said it would achieve this goal “through well intervention projects, infrastructure and facility repairs, and other optimization opportunities as they arise, including the evaluation of shut-in wells for potential return to service or utility.” Since taking over the unit, Hilcorp has returned the NS-33A and NS-22 wells to production.

The unit produced 11,100 barrels per day during the first quarter, according to Hilcorp.

Through July 2015, the unit had produced more than 164.8 million barrels of oil.

Northstar plans

This year, Hilcorp plans to recomplete the NS-18 Ivishak producer to target the Kuparuk sands, recomplete the NS-24 Ivishak producer to test the Sag reservoir and fix a surface casing leak at the NS-22 well. The company also plans to convert the NS-28 well to a gas injector targeting the Ivishak, which the company said would optimize the horsepower of existing compressors by reducing injection pressure into the field. The company will soon to start a reservoir simulation model to optimize injections.

Optimizing the injection strategy for the unit gained importance toward the end of last year when Hilcorp discontinued natural gas imports from Prudhoe Bay and began relying on gas produced at Northstar, using some 12 million cubic feet per day in 2015. BP had been investigating the possibility of converting the field to self-sufficiency for gas.

Although Hilcorp has presented no definitive plans, the company suggested it would pursue exploration that could potentially lead to new developments in the unit. That work would depend on “equipment availability, plant capacity, and commercial viability.”

In 2014, BP and its minority partner Murphy Exploration (Alaska) Inc. asked state and federal regulators to expand the Northstar unit to include some 454.62 acres from two state of Alaska leases — ADL 312798 and ADL 312808 along the southern border. The addition was meant to incorporate a proposed Hooligan participating area into the unit.

BP had requested the participating area in late June 2012 and provided additional information to regulators in February and April 2013. The U.S. Bureau of Safety and Environmental Enforcement approved the participating area in February 2014. The Alaska Department of Natural Resource approved the participating area in early 2015.

When state and federal regulators approved the Northstar unit in January 1990 and the Northstar participating area in October 2001, the unit agreement included a provision requiring any acreage outside the participating area to contract after 10 years. By forming the Fido participating area around federal lease OCS-Y-0181, BP was able to reduce the extent of the contraction in the northeast of the unit. But regulators later contracted portions of ADL 312798, ADL 312808 and ADL 312809 along the southern border.

Around November 2010, BP plugged the NS-08 well above the Ivishak to produce from the shallower Kuparuk formation on a tract basis. Using that well and information from other Ivishak wells at the unit, all of which have passed through the Kuparuk, BP mapped out the Hooligan field. The proposed Hooligan participating area would cover the Kuparuk formation at Northstar. Except for the expansion acreage, the reservoir exists entirely within the existing aerial boundaries of the Northstar unit and participating area.

With approval of the Hooligan participating area, BP had said it would continue to test the Kuparuk formation at Northstar through its current development plan, into 2015. In its most recent plan of development, Hilcorp said it would continue Kuparuk sands production.


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