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Producers 2020: Hilcorp launches a new era
With the acquisition of Prudhoe Bay, Hilcorp now leads Alaska development
Eric Lidgi for Petroleum News
When Hilcorp Alaska LLC acquired a stake in four midsize North Slope oil fields from BP Exploration (Alaska) Inc. in 2014, it looked like an expansion of its previous work.
A large privately held independent, Hilcorp had acquired a significant percentage of the producing Cook Inlet basin through two acquisitions in 2011 and 2012 - one from Union Oil Co. of California and the other from Marathon Oil Corp. The company was known for rejuvenating aging oil fields, and it quickly pursued that strategy in Cook Inlet. Its investments yielded flat or growing production at fields that had long been in decline.
Even after those big deals, Hilcorp continued to display an eagerness for acquiring properties as they became available. It was living its mission to “acquire and exploit.”
BP appeared to be going a different direction. An integrated multinational major with a long history in Alaska, the company had increasingly been narrowing its activities in Alaska, focusing on its responsibilities at the Prudhoe Bay unit. The company stopped wildcat exploration; it continued to make big investments in its North Slope properties, although to varying degrees by project.
Seen that way, the 2014 deal between Hilcorp and BP seemed like a perfect marriage. It allowed an eager newcomer to grow, and it allowed an established company to focus.
Hilcorp became the operator and 50% working interest owner of the Milne Point unit, the operator and majority working interest owner of the Duck Island and Northstar units, and a 50% working interest owner of the undeveloped offshore Liberty field.
But many in the oil patch wondered whether the company was actually auditioning for a much bigger gig.
Regardless of its intentions, its actions made a convincing case.
Within a few months of taking over the properties, Hilcorp devoted considerable resources to the Milne Point unit, just as it had done with its legacy Cook Inlet fields.
The company drilled more wells in more places. It renewed the focus on viscous oil. And it even commissioned a new drilling pad. In the six years since the sale in 2014, the two partners have invested approximately $700 million to date and drilled more than 60 wells.
The results have been dramatic. Milne Point was producing 18,400 barrels per day when Hilcorp took over the field in November 2014. By early 2020, production had reached 34,000 barrels per day with forecasts suggesting 40,000 barrels per day by year-end.
Prudhoe dreams In view of those successes, it was natural to wonder what might be possible if Hilcorp was given the opportunity to apply its methods to other aging fields in the basin.
Milne Point may be large by Lower 48 standards, but it is relatively small by North Slope standards. The mighty Prudhoe Bay unit produces some 280,000 barrels per day. That’s about seven times the rate Hilcorp is forecasting for Milne Point for the end of this year.
Ever since the announcement of the deal, the oil patch has been speculating on what strategy we might see in the next few years. Speaking to Petroleum News Publisher Kay Cashman toward the end of 2019, a retired unnamed BP Exploration (Alaska) executive pointed to the different management structures of the companies as a source of change.
Hilcorp is thought to have roughly half the levels of management between low-level employees and top executives compared to BP, which could lead to greater investment in technology and equipment. “That’s what Hilcorp did at the Milne Point field when they took over from BP five years ago - they’ll go after the big prize at Prudhoe, which is viscous oil. … Lower operating costs … will mean more oil for Hilcorp and the other Prudhoe partners (ExxonMobil and ConocoPhillips), but it will also mean more oil down TAPS and more revenues for the State of Alaska,” the former executive explained.
As that comment suggests, the Prudhoe Bay field has always been seen as a keystone of the North Slope oil industry - and by obvious extension, the broader economy of Alaska.
Exploration work by the U.S. Geological Survey in the 1920s, and around World War II, created great interest in the North Slope basin in the early 1950s, as turmoil in several Middle East countries prompted some companies to reconsider remote American plays.
Territorial Alaska ranked high for its potential. Then the discovery of the Swanson River oil field in the Cook Inlet basin in 1957 made the economic case for Alaska statehood.
BP opened its Alaska field office in downtown Anchorage in 1959. The company spent the better part of a decade studying and exploring corners of the North Slope, without much success, before finally completing the Prudhoe Bay State No. 1 discovery well in 1968 - and discovering the largest producing conventional oil field in North America.
The discovery of the Prudhoe Bay oil field justified the construction of the trans-Alaska oil pipeline, which eventually came online in 1977. The pipeline created a path to market for the massive Kuparuk River oil field, the second largest oil field in North America.
Without the Prudhoe Bay unit, and by extension the trans-Alaska oil pipeline and the Kuparuk River unit, it is hard to imagine how any of the smaller oil fields across the North Slope could have been developed. While many of those fields would be considered elite properties if they were located in the Lower 48, their position in the wilderness of Arctic Alaska increases the cost of development, making many uneconomic on their own.
In fact, even today, more than 60 years after the discovery of the Prudhoe Bay oil field and the expansion of infrastructure in several directions, many significant North Slope oil fields remain stubbornly beyond the reach of economic development - at least as-of-yet.
The importance of the Prudhoe Bay unit can also be seen in its longevity.
No exploration work in Alaska has yet knocked Prudhoe Bay from its perch as the largest discovery. And even with decades of declining production, it continues to be the most productive field in Alaska. It has even remained one of the 10 most productive fields in the United States, despite the emergence of major unconventional plays in the Lower 48.
Those distinctions reflect not only the tremendous size of the original resource, but also the incredible technological advances that have allowed operators to keep the field alive.
If recent history is any guide, Hilcorp will be continuing that recent spirit of persistence and resourcefulness is as it takes over as operator of the storied Prudhoe Bay field.
The deal As the rumored sale of the Prudhoe Bay unit started to become a reality, the oil patch wondered whether BP Exploration (Alaska) Inc. might split the complex field - selling the west side assets to ConocoPhillips Alaska Inc. and selling the east side to Hilcorp.
But when BP finally announced the terms of the deal in late August 2019, Hilcorp had acquired everything. For the sum of $5.6 billion, the largest private oil and gas producer in the United States would own a major stake in the largest oil field in North America.
And although Prudhoe Bay was the obvious headline, the deal covered much more.
Hilcorp acquired the remaining interests in the Milne Point unit and the Liberty unit. The company originally acquired partial ownership and operatorship of those units in the 2014 deal.
Hilcorp also acquired a 32% non-operating interest in the ExxonMobil-operated Point Thomson unit. It also acquired an interest in exploration leases in the 1002 area of the Arctic National Wildlife Refuge, including a 50% stake in the KIC well.
Hilcorp also acquired ownership interests in several midstream assets: a 49% stake in the Trans Alaska Pipeline System and the Alyeska Pipeline Service Co., a 50% stake in the Milne Point Pipeline and a 32% stake in the Point Thomson Pipeline.
Hilcorp also acquired a 25% interest in the Prince William Sound Oil Spill Response Corp., which was created following the Exxon Valdez Oil Spill in 1989.
Even after the announcement, the question of operatorship remained unresolved.
The issue was one with a long history.
For decades following the discovery and commissioning of the field, ARCO Alaska Inc. operated the east side of the Prudhoe Bay unit, while BP operated the west side.
In the wake of the big corporate mergers of the late 1990s and early 2000s, operatorship changed. For the past two decades, BP Exploration (Alaska) has operated the entire Prudhoe Bay unit, although it only holds a 26% interest in the unit. ConocoPhillips and ExxonMobil each own a 36% interest, leaving 2% to minority owners.
The $5.6 billion announcement explicitly mentioned the 26% interest but not the operatorship, leaving many in the oil patch to wonder whether the unit would once again be split geographically or whether ConocoPhillips might even take over as operator.
But for reasons that may not come to light for a while time, if ever, the parties decided that Hilcorp would slip into the role BP was departing: 26% owner, full operator.
Added to its Cook Inlet holdings, the deal made Hilcorp a dominant player - perhaps the dominant player - in the Alaska oil industry. Few companies have ever owned so much.
The Prudhoe Bay unit As was the case with Milne Point, it will take a few years before Hilcorp’s new strategy at the Prudhoe Bay unit is fully reflected in the commitments of its plans of development.
But if its experience in Alaska to date is any guide, the influence of Hilcorp at the largest oil field in the state will be felt quickly and will increase gradually over the coming years.
The operations of the Prudhoe Bay unit have typically been administered by three separate plans of development, each submitted at different points in the year: for the Initial Participating Areas, the Greater Point McIntyre Area and the Western Satellites.
BP Exploration (Alaska) filed the Initial Participating Areas and the Greater Point McIntyre Area plans of development before turning over operatorship of the unit to Hilcorp. Hilcorp filed an amendment to an earlier plan of development for the Western Satellites shortly after becoming operator in July.
PBU: Initial Participating Areas The Initial Participating Areas, or IPA, is the largest of the three administrative regions at the Prudhoe Bay unit. It covers the initial oil and gas caps discovered at the unit.
The IPA is beginning its 43rd year of continuous operation and its 32nd year since peak production in the late 1980s. “With over 1400 wells, the field is well developed,” BP explained in its plan of development. “Minimizing natural decline is the constant goal.”
In its plan, BP presented a five-point strategy for managing the IPA: optimizing production in line with facility constraints, enhancing recovery through well work, managing pressure through injection, optimizing flooding and drilling new wells.
The IPA produced 165,030 barrels of crude oil and condensate per day in 2019, down from 174,200 bpd the previous year. The company had forecast crude oil and condensate production between 147,000 and 165,000 bpd for the current year. By comparison, the company had forecast a production range between 150,000 and 187,000 bpd for 2019.
The IPA also produced 43,600 barrels of natural gas liquids per day in 2019, equal to the year prior. The company forecast NGL production between 35,000 and 50,000 bpd for 2020, higher than the range of 30,000 to 46,000 bpd the company had predicted for 2019.
BP described its current development drilling strategy at the IPA as “focused,” meaning limited and targeted toward specific opportunities or regions. For example, of the 27 wells the company drilled at the IPA in 2019, eight were associated with Flow Station 2.
The company proposed a smaller plan for this year, with 17 wells. The decline would largely come from a decrease in coil tubing drilling. The company had expected to use coiled tubing rigs for wells in other part of the unit or to conduct rig workover jobs.
The company acquired seismic data in 2019 and is now merging the results with previously acquired data sets. The results should guide drilling and other field operations.
Even though well maintenance was crucial to the BP strategy at the IPA, well work has been declining. The company performed approximately 880 jobs in 2019, of which 316 increased production rates. The year prior, the company had performed approximately 900 jobs, of which 360 increased production rates. This year, the company announced plans to perform approximately 800 jobs, of which 300 would increase production rates.
PBU: Greater Point McIntyre Area BP submitted its IPA plan of development in late March, just as states were beginning to shut down over the COVID-19 pandemic, leading to a historic drop in oil prices.
The plan did not mention the pandemic. By the time the company submitted its Greater Point McIntyre Area plan in late June, the pandemic had become a central element.
The plan covers four producing fields: Point McIntyre, Lisburne, Raven and Niakuk. The plan also includes two suspended fields: North Prudhoe Bay and West Beach.
“As a result of the combination of COVID-19 presence in Alaska and the unprecedented drop in oil price, BPXA is re-leveling PBU activity for the remainder of 2020. Activity plans during the upcoming plan year beginning October I, 2020 through September 30, 2021 are uncertain,” the company wrote, noting that it would meet regulatory obligations.
The Point McIntyre field produced 13,800 bpd of crude oil, condensate and natural gas liquids during the year ending March 31, 2020, down from 16,700 bpd the year prior.
The company reported no drilling, workovers, or rate-adding activities for 2019 and announced no firm plans for the current year, although “active wellwork and scale inhibition programs” continue, according to the most recent plan of development.
The Lisburne field produced 11,800 bpd of crude oil, condensate and natural gas liquids in the year ending March 31, 2020, up slightly from 11,500 bpd the year prior.
During the development year, BP drilled three wells - L3-06, L5-03 and L5-27 - and started a fourth - L5-07. The company also completed the L3-22A sidetrack and worked over the L1-31 well. The company performed rate adding non-rig projects on 21 wells.
In addition to L5-07, BP was considering four rotary and two coil tubing drilling well locations in the near future. “Several additional Lisburne drilling locations are being considered for possible future drilling but are contingent on the continued performance of the wells drilled during the 2015-2019 period, the results of the current planned wells, and the business environment. Additional rate-adding non-rig interventions are planned,” the company noted, referring to the period following the North Prudhoe seismic survey.
The Raven field produced 1,440 bpd of crude oil, condensate and natural gas liquids during the year ending March 31, 2020, up slightly from 1,370 bpd the year prior.
The increase came in part from the NK-08B well brought online in May 2019. The well “has experienced stable production through the reporting period,” according to BP.
The company announced no firm drilling or workover plans for the coming year, other than noting the importance of the North Prudhoe seismic survey for guiding future plans.
The Niakuk field produced 900 barrels per day of crude oil, condensate and natural gas liquids during the year ending March 31, 2020, down from 1,100 bpd in the year prior.
The company performed nine rate-adding jobs to six Niakuk wells during the year. The company made no firm drilling or workover commitments for the current year, but it said the North Prudhoe seismic survey was being used to study “subsurface areas of interest.”
The North Prudhoe Bay field and West Beach field have been shut-in since the early 2000s. North Prudhoe Bay had produced 2.1 million barrels cumulative of crude oil and condensate before the WB-03 well was taken offline in February 2000. West Beach produced 3.37 million barrels of crude oil before it was taken offline in early 2001.
Although the company announced no plans to bring either field back into production, it noted that both fields were contained within the North Prudhoe seismic survey area.
PBU: Western Satellites As with the other administrative regions of Prudhoe Bay, the immediate development plans for the Western Satellites were made uncertain by the change in operatorship.
BP Exploration (Alaska) submitted its 2020 development plan for the region in the latter half of 2019, after it announced plans to sell Prudhoe Bay to Hilcorp but before the deal had closed. State officials approved that development plan before the end of the year.
But in August 2020, a month after closing, Hilcorp requested a three-month extension, through March 2021. The extension would “allow for time to become familiar with PBU Western Satellites” before submitting a revised plan of development by February 1.
The Western Satellites include five participating areas: Aurora, Borealis, Midnight Sun, Orion and Polaris. The first three produce primarily from the Kuparuk River formation, while the other two produce primarily from the more viscous Schrader Bluff formation.
The Aurora, Borealis and Midnight Sun fields all produce from the Kuparuk formation.
At the Aurora field in 2019, BP drilled a sidetrack of the S-105A well. The company also completed 66 workover projects, of which 20 yielded increases to field production rates.
Those projects were responsible for an uptick in production. Aurora produced 5,291 barrels of oil per day in the year ending June 30, 2019, up from 4,609 bpd the year prior.
At the Borealis field in 2019, BP completed 70 workover projects, of which 21 yielded increases to field production rates. Even so, oil production declined. Borealis produced 5,905 bpd in the year ending June 30, 2019, down from 7,914 bpd in the year prior.
At the Midnight Sun field in 2019, BP sidetracked the E-100 well into the Sambuca block, removing it from Midnight Sun production. Midnight Sun produced 1,394 barrels of oil per day in the year ending June 30, 2019, up from 1,158 bpd the year prior.
The 2020 plan included no firm development commitments for either the Aurora, Borealis or Midnight Sun fields. But the plan called for continuing well work to mitigate production declines at all three fields and potentially drilling infill wells, as appropriate.
The Orion and Polaris fields produce from the viscous Schrader Bluff formation.
At the Orion field in 2019, BP completed 65 workover projects, of which 20 yielded increases to field production rates. Overall, oil production increased. Orion produced 4,955 bpd in the year ending June 30, 2019, up from 3,900 bpd in the year prior.
At the Polaris field in 2019, BP completed 31 workover projects, of which seven yielded increases to field production rates. Even so, oil production declined. Polaris produced 3,969 bpd in the year ending June 30, 2019, down from 4,158 bpd in the year prior.
Toward the end of 2019, in response to comments from the state, BP submitted an amendment to its plan, calling for drilling three new wells by early 2020. The program included the S-202 multilateral producer and the S-201 and S-210A vertical injectors.
The program is something of a pilot initiative to test well design and completion technologies in the southern S Pad region. If viable, the work could be expanded.
For many years, BP has discussed the possibility of an I Pad project at the Orion and Polaris fields. The project currently hinges on the results of sand control technology, which could also be used in other areas of the fields, such as M Pad and S Pad.
The Milne Point unit The most likely guide to the future of Prudhoe Bay is the nearby Milne Point unit.
In the years since it first acquired assets from BP, Hilcorp has directed most of its North Slope resources toward Milne Point, increasing activity, infrastructure and production.
The work not only included increased attention to aging wells. Hilcorp also increased grassroots drilling activities and quickly announced new pad permitting efforts. The company recently brought the new Moose Pad into production in just two years, under budget and without incident. Moose Pad is the first new pad at Milne Point since 2002.
The results are clear: Hilcorp says it is on track to double production at Milne Point. The unit was producing 18,400 barrels of oil per day when the company took over as operator in November 2014. Hilcorp expects production to reach 40,000 bpd by the end of 2020.
The unit produced some 25,541 bpd in 2019, up from approximately 20,839 bpd in 2018, according to Alaska Oil and Gas Conservation Commission figure. The unit produced 34,000 bpd in late January - the highest average production recorded since May 2008.
The production increases at the Milne Point unit are “an important milestone for the state of Alaska and Hilcorp,” Hilcorp Energy Co. President Jason Rebrook said in the first quarter of this year. “By empowering our employees closest to the wellhead, driving efficiencies, and innovating, we’re increasing production at Milne Point and putting more oil in TAPS. Our goal is to apply these successes at Prudhoe Bay and beyond.”
Hilcorp fell slightly short of its drilling projections for the development year, completing 25 wells at the unit in 2019, down from the 29 wells it had forecasted in its previous plan.
The company completed 14 Moose pad wells targeting the Schrader Bluff formation. The program included 10 producers (M-10, M-12, M-14, M-15, M-16, M-17, M-18, M-20, M-21 and M-22), two injectors (M-11 and M-13) and two water wells (M-04 and M-06).
Hilcorp completed nine penetrations at seven wells at the E Pad, all targeting the Schrader Bluff formation in its 2019 campaign. The program included the E-37, E-41, E-42 and E-42L1 producers and the E-36, E-38, E-39, E-39L1 and E-40 injectors. The company also completed the S-201 and S-203 production wells into the Ugnu formation.
In addition to its drilling work, Hilcorp expected to reach its target of 16 workover projects in 2019. The work primarily involved changing out electric submersible pumps.
In its plan for the current year, Hilcorp proposed drilling 28 wells. The program would include 18 wells at Moose Pad and 10 wells at S Pad, targeting the Schrader Bluff, Ugnu and Kuparuk formations. The company is also proposing 20 workovers at Milne Point.
Through the first eight months of 2020, Hilcorp had completed 18 wells at the unit and received permits for another eight wells, nearly the entire planned drilling program.
As it proceeds with its initial Moose Pad development, Hilcorp is also advancing preliminary work for a proposed Raven Pad and an expansion of its existing S Pad.
The Duck Island and Northstar units Although unable to match the successes at Milne Point, the Duck Island and Northstar units are beginning to see some maintenance activities with an eye toward optimization.
Even so, oil production is declining at both fields.
Hilcorp conducted approximately nine workover projects at the Duck Island unit in 2019 and completed several facility projects designed to improve overall field operations.
The company is projecting a decline in work this year, with no new drilling and just three workover projects. The workovers could return some suspended wells to production.
The unit experienced a slight decline in oil production last year. The main Endicott field produced approximately 6,338 bpd in 2019, down from approximately 6,487 bpd in 2018, according to the AOGCC. The field produced some 6,251 bpd in the first half of 2020.
Hilcorp conducted two workovers at the Northstar unit in 2019, converting the NS-07 Ivishak producer into a Kuparuk C producer and the NS-17 Ivishak injector to a Kuparuk C injector. The company also advanced its Northstar Propane Chiller Project to improve natural gas liquids recovery from the field. The project is continuing into this year, too.
The company is planning two workover projects this year. One would acidize one or more Kuparuk wells to improve operations. The other would repair surface casing.
The unit produced some 7,610 bpd in 2019, down from 8,211 bpd in 2018, according to the AOGCC. The unit produced some 6,418 bpd in the first half of this year.
The Liberty field The biggest and hardest project in the Hilcorp portfolio on the North Slope is the Liberty unit, which BP failed to bring into production after decades of ambitious attempts.
Under the current strategy, Hilcorp wants to develop the offshore field from a gravel island in the federally managed Outer Continental Shelf of the Beaufort Sea. The $1 billion project could produce for 30 years, reaching a peak of 70,000 barrels per day.
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