Kuparuk 2022: Technology key to recovering more oil from Greater Kuparuk Area

What remains is more technically challenging, more expensive to get out of the ground

Kay Cashman

Petroleum News

Since its December 1981 startup through the end of 2009, the Kuparuk River field on Alaska’s central North Slope produced 2.19 billion barrels of oil. Excluding satellites the Kuparuk field averaged 104,145 barrels per day in 2009. Entering 2010 Kuparuk was the nation’s third largest producing oil field behind No. 1 Prudhoe and Shell’s Mars-Ursa development in the Gulf of Mexico, per Energy Information Administration ranking.

But Kuparuk like its big neighbor to the east, Prudhoe, was still in decline in early 2010. ConocoPhillips Alaska was working to squeeze every possible drop of oil out of Kuparuk and its satellite fields - West Sak, Tarn, Meltwater and Tabasco.

These satellites produced an additional 37,600 barrels per day in 2009. As of Jan. 1, 2010, ConocoPhillips Alaska owned about 55% of Kuparuk, with BP Exploration (Alaska), or BPXA, holding 39%, Chevron 5% and ExxonMobil the rest. Among its accomplishments in 2009, ConocoPhillips Alaska told the State of Alaska in an annual report, that it had implemented a nine-well coiled tubing drilling program generating a “peak incremental oil rate” of 4,300 barrels per day.

The company said 21 laterals were drilled and completed in the wells. A workover program added 6,000 barrels per day. Optimizing Kuparuk output was a delicate dance involving primary production, waterflooding, miscible gas enhanced oil recovery, and immiscible gas flooding.

To some extent, Kuparuk was dependent on Prudhoe, and this dependency likely would increase, ConocoPhillips Alaska said in its annual report to the state. During 2009, Kuparuk imported an average of 18,391 barrels per day of Prudhoe natural gas liquids to make miscible injectant, which greatly enhanced its production.

FACING A GAS PROBLEM

Entering 2010 Kuparuk faced a looming problem - insufficient gas. Field gas production was expected to decline significantly in coming years, which would leave Kuparuk short of gas for enhanced oil recovery and short of fuel for field operations. “The most technically feasible known alternative gas source is Prudhoe Bay,” said the ConocoPhillips Alaska report to the State of Alaska.

Prudhoe, unlike Kuparuk, had a vast gas cap. Gas imports from Prudhoe Bay were expected to begin around 2015. “The plan is to utilize imported Prudhoe gas as fuel gas only and not introduce any of this gas into the production system, either by injection or in the gas lift system,” the company told the state. “This is due to corrosion concerns relating to the relatively high CO2 content (10-12%) of Prudhoe gas.”

WEST SAK AND TARN

Of Kuparuk’s four satellites, West Sak and Tarn were the biggest producers going into 2010. West Sak, a vast heavy oil deposit overlying the Kuparuk field, produced an average of 18,866 barrels per day in 2009, and tallied about 46 million barrels through 2009.

Waterflooding the reservoir to maintain pressure and improve sweep was the main enhanced oil recovery method used for the West Sak oil pool, ConocoPhillips Alaska said. Activity was more robust at the Tarn satellite, southwest of the Kuparuk River field. Tarn produced 14,063 barrels per day in 2009 via 53 development wells on two drill sites. The field, which began production in 1999, had produced almost 100 million barrels of oil, top among the Kuparuk satellites.

More than 15 new wells and sidetracks could be drilled as part of a future infill and peripheral development drilling program,” ConocoPhillips Alaska’s annual report to the state said. “Targeted areas include the thinner distal lobes that previously were considered uneconomic.” One well under consideration for 2011 “may be drilled as a horizontal well with multi-stage frac completion. This would be the first application of this technology at Tarn.”

MELTWATER AND TABASC0

The other two Kuparuk satellites, Meltwater and Tabasco, had contributed smaller volumes of oil through the end of 2009, ConocoPhillips Alaska said. Meltwater, about 10 miles south of Tarn, had begun production in 2001 and made 2,715 barrels of oil per day in 2009. The field had 19 wells on a single drill site, and over its lifetime had produced 14.1 million barrels.

With original oil in place of 222 million barrels, Meltwater showed a “large incremental target for additional development,” the report said. A 3D seismic survey of Meltwater was completed in 2008, and “horizontal or undulating wells to help connect multiple reservoir sands will be considered.”

Tabasco, a heavy oil field on Kuparuk’s western flank, had 12 development wells and produced 1,948 barrels a day in 2009. Since startup in 1998 it had produced 15.6 million barrels.

Geological and reservoir simulation models would help “evaluate alternative recovery strategies and additional development opportunities” for Tabasco, which the company was waterflooding.

NO EXPLORATION IN 2010

In its March 7, 2010 annual report, parent ConocoPhillips said it would not explore in Alaska in 2010; rather its focus would be development drilling at Kuparuk, Alpine maintenance and preparing for future Chukchi Sea exploration.

Helene Harding, then-ConocoPhillips Alaska vice president of North Slope operations and development, told the Resource Development Council on Nov. 18, 2010, that the company’s projection in 2003 was that West Sak viscous oil production would be at more than 30,000 barrels per day by 2010. But in September 2010 West Sak output was some 18,000 barrels per day, Harding said, noting that even with oil at $50 a barrel in 2003 the company was a lot more bullish about the future at that time than it was in 2010.

On the fiscal side in Alaska “in the last three years alone we’ve had three increases in our taxes and the last one, ACES, ended up … taking away our upside. “And when you’re in a risk-and-reward business like we’re in, when you take away the upside it’s extremely hard to compete for dollars,” Harding said. As far as the company’s plans for 2010, she said safe operation was key as well as operating in an environmentally sound way. “In addition, it’s very important for us to run level and operate our fields as efficiently as we can and continue to drive costs down and out of the system.”

The Alaska Department of Revenue had estimated that $40 billion in investment would be necessary to deliver projected core-field production over the next 10 years, Harding said. “We need to look at these core fields. … That’s the health of our business,” she said. At the time Harding managed the Kuparuk River and Alpine fields.

A 30% recovery rate was the original Kuparuk target, “and now it looks like we’re going to be closer to about 40%. And we’re continuing to work on technology and challenges to enhance that and make it even better,” Harding said. But Kuparuk was nearing 30 years of age and with many years of remaining life “we’re putting investment dollars towards the maintenance of our pipelines, our wells and our infrastructure.”

The company launched its first next-generation coiled tubing drilling rig at Kuparuk in May 2010 (Nabors rig CDR2-AC), Harding said. “This rig is used for infield drilling and we are using 4D or time-lapse seismic technology to help determine areas in the field where we have leftover production,” she said. Harding said that for ConocoPhillips Alaska “to deliver the next 30 years at Kuparuk we really do need an attractive fiscal structure” because projects at Kuparuk are “going to have to compete across the United States and the world for investment dollars.”

JOHANSEN: CHALLENGING, BUT NOT DAUNTING

Effective April 1, 2010, Trond-Erik Johansen, previously president of ConocoPhillips’ Southeast Asia Exploration and Production, was named to head ConocoPhillips Alaska, replacing Jim Bowles who had died Feb. 13 of that year in a snow machining accident.

Alaska had a world-class resource base, but production was declining, and it would take cooperation between government and industry to put more oil in the trans-Alaska oil pipeline, Johansen told attendees of the Resource Development Council’s annual conference Nov. 17, 2010, in Anchorage. Reservoirs now producing on the North Slope “are what I would call the easy oil,” Johansen said.

What the companies want to produce now is “more difficult” and “more expensive to get out of the ground,” he said. West Sak, the viscous oil field overlying the Kuparuk River field, was challenging to produce. “It takes more money; it takes more technology; it takes a lot of effort to get it out of the ground,” Johansen said.

Shallower still was Ugnu, the heavy oil accumulation overlying West Sak. “You ought to know it costs a lot of money; it takes a lot of technology; it takes a lot of patience - very, very high breakeven costs - to get this oil into the plant and out to the market,” he said. In both the West Sak and the Ugnu, however, there was “a lot of oil, billions of barrels.” It would take cooperation between industry and state and federal government, Johansen said, “and it is challenging, but it is not daunting.”

PRODUCTION DECLINE

Why was production dropping in Alaska and rising in the Lower 48? “Is it because there is no oil in Alaska? No; there’s lots of oil in Alaska,” Johansen said. “It is because there was a lot of cheap oil in the Lower 48? No,” he said. In the Lower 48, oil production grew 3% from 2003 to 2010; Alaska production declined 36% over the same period, he said.

Lower 48 oil production increased when oil prices rose, powered by an increase in oil rigs operating in the Lower 48. In Alaska, however, the rig count dropped from 2003 to 2005 and had been flat ever since, he said. And for those who said that Alaska was a mature region and that production decline was to be expected, Johansen noted that Alaska had only had serious production for a few decades, compared to Texas which had had commercial production for almost a hundred years. Yet during 2003-2010, Texas production declined only 1%.

TURNAROUND AHEAD

Alaska needed the right environment in place for more production, “like you see today happening in the Lower 48,” he said. Johansen said he was “pretty optimistic” that there would be a turnaround in Alaska “because of technology and because of smart decisions between the industry and the state and the federal government to put the framework in place to make sure we can go after it.” But that wasn’t happening yet.

ConocoPhillips Alaska had drilled at least one exploration well in Alaska every year starting in 1965, Johansen said. “This year (2010) is the first year we didn’t drill an exploration well; and we’re not going to drill one next year, either,” he told conference attendees.

UNLOCKING MORE OIL AT KUPARUK

In the first half of 2011 as debate over a new tax regime that would encourage oil company investment in Alaska was being waged in Juneau, ConocoPhillips Alaska continued to work at unlocking new resources in the Kuparuk River oil field. But with the oil lying in two major reservoir zones - the Kuparuk A and C zones - and with a multiplicity of geologic faults fracturing the reservoir into multiple compartments, teasing as much oil as possible from the Kuparuk reservoir sands proved a significant challenge.

Although the company had used water to flush oil into production wells, the compartmented nature of the reservoir and the complexities of production from the two reservoir zones had limited the effectiveness of this conventional “waterflood” technique, Bryn Clark of ConocoPhillips Alaska told the Pacific Section, American Association of Petroleum Geologists, in Anchorage on May 10, 2011.

Multiple lateral wells were being drilled out from older well bores, with the first quadrilateral well being drilled in 2005, she said. And in 2011 it was possible to drill lateral wells up to 3,500 feet long, with up to five laterals extending from a single parent well, Clark said. Techniques such as the use of an agitator to shake the well pipe, and the planning of a well trajectory to cause the well to slope somewhat downhill towards its end, helped drillers to maximize the length of a well, she said.

Although coiled tubing drilling initially targeted the relatively thick and straightforward sands of the C zone, ConocoPhillips Alaska was now drilling multilateral coiled tubing wells in the more challenging A sands, where waterflood techniques had proven especially difficult to apply, Clark said.

A new drill-bit steering technology implemented in 2009 had enhanced the accuracy with which a well could intercept a specific sand body. Drillers had also developed techniques for steering a drill bit through difficult underground geology, perhaps, for example, causing the bit to penetrate an unstable shale layer at a steep angle to prevent the shale from sending the bit off course.

However, in mid-2010 it was still only possible to run two types of well logs - gamma ray and resistivity logs - through a coiled tubing well.

URGENCY NEEDED

Johansen told the Anchorage Chamber of Commerce Oct. 10, 2011, that there was still a lack of urgency in the state about the need to increase production through the trans-Alaska oil pipeline. Alaska development, Johansen said, competed poorly with projects elsewhere. At Kuparuk, Prudhoe and Alpine, the North Slope’s big conventional oil fields, the easy oil had been found, Johansen said. While those fields were very mature, there was a lot of oil left, but producing it required going into new horizons and smaller pockets, and it would take longer to produce it.

The number of production drilling rigs was the same as five years ago, he said, but less and less oil was produced from each well drilled. And 2011’s spend, Johansen said, was 70% maintenance capital and 30% development capital: 10 years prior those numbers were reversed.

In 2011 the trans-Alaska oil pipeline was moving 600,000 barrels per day from the North Slope as compared to 1 million bpd in 2003, and throughput was continuing to fall, he said. “While we can’t do anything with geology or geography, can we do something with the fiscal environment?” “I can’t,” Johansen said.

With the progressivity element in Alaska’s production tax, there was less and less profit to companies taking the development risk, he said.

DESIGNED WELLS AT KUPARUK

Nick Olds, then-ConocoPhillips Alaska’s new vice president, North Slope operations and development, told the Resource Development Council’s annual conference Nov. 14, 2011, in Anchorage that the state’s oil and gas tax system must be changed to compete for investment dollars. But he also talked about some of the opportunities that the company saw in Alaska.

At Kuparuk, he said, the company was looking at designed wells. Over the last few months ConocoPhillips Alaska had implemented “what we call an octa-lateral, four laterals going out one way, four going out the other way,” Olds said. That’s complex, he said, and required a technology investment. And also at Kuparuk “the targets are smaller, they’re higher risk and so we need to continue to use innovation and technology to go after them,” which also required a good business climate, Olds said.

There were also opportunities south of Kuparuk, he said. “They are some small satellite developments that are years in front of us,” but required the company to ask if the size was there, if the risk was acceptable and if the business climate was there to support the work. And heavy oil, with a billion barrels at Kuparuk, would require “significant technology to advance it. Currently there’s not a commercial application to unlock that potential,” he said.

TAX BILL PASSES

Then-Gov. Sean Parnell’s oil tax change, which eliminated the progressivity enacted under former Gov. Sarah Palin in ACES, Alaska’s Clear and Equitable Share, and changed the way credits were offered, passed April 14, 2013. The belief of the governor and legislators who voted for the bill was that because it reduced the government take in Alaska, making the state more competitive with comparable oil producing areas, it would lead to more investment by oil and gas companies in Alaska, ultimately increasing - or at least slowing decline - of North Slope oil production.

CONOCO PHILLIPS TO INCREASE INVESTMENT

In an April 17, 2013 press conference after the new tax legislation passed, ConocoPhillips said it would increase its investments in Alaska. With the improvements to the state’s severance tax system, the company said it was planning new work on the North Slope, including bringing an additional rig in Kuparuk in the spring and working with co-owners on funding a new drill site (2S) on the southwest flank of the Kuparuk River unit. Johansen called those “some examples of the activities ConocoPhillips plans to kick off in the near future” to help bolster oil production.

ConocoPhillips reported its 2012 Alaska spending at $828 million, up from $774 million in 2011, with work on the Alpine West or CD-5 development in NPR-A accounting for much of the increase in 2012.

Petroleum News reported in February 2013 that the company had applied for a U.S. Army Corps of Engineers permit to build a drill site and access road for the 2S project, which would develop a discovery ARCO Alaska made with the KRU 21-10-08 well in the late 1980s. ConocoPhillips Alaska appraised the discovery with the Shark Tooth No. 1 well in 2012.

On Nov. 20, 2013, Johansen said under the previous tax regime government take in Alaska, including royalties, at $100-a-barrel oil, was 79%, compared to Texas at 5% and North Dakota at 57%. And while the governor’s tax bill was criticized by many Democrats, looked at competitively it was still 10-15% higher than Texas and North Dakota, both of which had growing production rates, while Alaska’s production continued to decline, Johansen said. He described the relationship between Alaska and the oil industry as symbiotic: for industry to be successful, the state needed to be successful.

APPLIES FOR A NEW VISCOUS DEVELOPMENT

ConocoPhillips Alaska added another project to those it announced following passage of oil tax reform by the Alaska Legislature in spring 2013. The company said Feb. 18, 2014, that it had submitted permit applications for a development targeting the West Sak reservoir at Kuparuk River. The new viscous oil development, 1H NEWS, Northeast West Sak, included a nine-acre extension to existing drill site 1H, which would support new wells and associated facilities.

First oil was expected in 2017 for the $450 million project, with production expected to peak at 9,000 barrels of oil per day. There would be some 150 jobs during construction. In addition to plans for the new 1H NEWS project, Johansen said ConocoPhillips Alaska, had “also added two rigs to the Kuparuk fleet.” Alaska Oil and Gas Conservation Commission records showed 68.3 million barrels of West Sak production at Kuparuk through the end of 2013.

Appraisal drilling was done in the NEWS area, north and northwest of the core area, in 2005-06 at drill sites 1Q and 3J and from an ice pad north of drill site 1H. A NEWS participation area was approved by the Alaska Division of Oil and Gas in 2009.

KUPARUK EUR UP 75% SINCE STARTUP

Improved technology over the past three decades increased the amount of recoverable oil at the Kuparuk oil field by 76%, ConocoPhillips said at its analyst day on April 10, 2014. Originally expected to recover some 1.5 billion barrels of oil, a series of technologies over the years had increased that estimated ultimate recovery figure to 2.5 billion barrels. The technologies included hydraulic fracturing, enhanced oil recovery, coiled tubing drilling and 4D seismic. “If we hadn’t done that we would’ve run out of oil at Kuparuk back in the 1990s,” Executive Vice President of Technology and Projects Al Hirshberg told analysts.

BILLIONS OF BARRELS LEFT

In May 2014, Johansen said 3.75 billion barrels of conventional oil remained in the Kuparuk field, with a further 15 billion barrels of heavy oil in the Kuparuk River unit. In 2013, Kuparuk production averaged 85,700 barrels of oil per day, ConocoPhillips said. During that year ConocoPhillips completed a 14-well coiled tubing drilling program that generated a peak rate of 4,520 barrels per day of incremental oil. The company also completed one conventional well, its plan of development for 2014 said.

NEW-BUILD ROTARY RIG

On July 28, 2014, ConocoPhillips Alaska announced it had contracted with Doyon Drilling for a new drilling rig, Doyon 142, the first new-build rotary rig the company had added to the Kuparuk River rig fleet since 2000. The rig was scheduled to begin drilling in early 2016.

Mike Wheatall, then-ConocoPhillips Alaska manager of drilling and wells, said the company had signed a five-year contract for the rig. Aaron Schutt, president of Doyon Ltd., said building the rig was an opportunity to both make money for Doyon’s shareholders and to employ those shareholders.

“Long-term contracts for drilling around the world are actually quite rare,” Schutt said. Wheatall said the five-year contract for Doyon 142 was the period of time Doyon considered “sufficient to justify the capital investment needed to build the rig.” Doyon said North Slope rigs cost more than $100 million.

KUPARUK EXPANSION APPROVED

An Aug. 20, 2015, news release from ConocoPhillips reported that the first wells were spud at the new Kuparuk River unit drill site 2S in the second quarter, with production startup expected in fourth quarter. The company also said work was advancing at the viscous oil development 1H NEWS. Shortly thereafter Alaska’s Division of Oil and Gas approved a Kuparuk River unit expansion requested by ConocoPhillips Alaska, expanding the total size of the North Slope unit by some 2,560 acres.

KUPARUK DS 25 IN PRODUCTION

ConocoPhillips Alaska said Oct. 12, 2015, that Kuparuk River unit drill site 2S, the first new drill site at the field in more than 12 years, was on production - under budget and ahead of schedule. “Drill site 2S is one of the key projects that we announced after passage of tax reform,” then-ConocoPhillips Alaska President Joe Marushack said. “The $475 million project created about 250 jobs during construction with numerous contractor companies and trades involved,” he said.

ConocoPhillips Alaska said that at peak production the project would produce some 8,000 bpd. The announcement said the project included 14 new development wells, a new gravel road and a new drilling site capable of handling 24 wells. The project also included power lines, pipelines and other new surface facilities. The new drill site was near the DS 2K pad, 1.5 miles east of the Tarn road.

More 4D seismic

A major effort in 2014 was seismic acquisition. Over the past decade, ConocoPhillips Alaska had been relying heavily on seismic information to identify potential targets for additional development within the existing Kuparuk field. In 2014 the company completed 4D processing over a 60-square-mile area of the field and licensed a 47-square-mile speculative 3D survey in the north end of the unit. It also undertook four seismic reprocessing efforts. ConocoPhillips Alaska said the WBA/Kalubik Depth Migration project would “better image” the western side of the Kuparuk field. The company expected to complete the project in the third quarter.

Torok MORE OIL IN TOROK

On July 22, 2016 the Alaska Oil and Gas Conservation Commission approved a new oil pool at the Kuparuk River unit, the Kuparuk River-Torok Oil Pool. The ruling allowed ConocoPhillips Alaska to proceed with an oil development program from the existing DS 3S and could lead to additional pads in the future. ConocoPhillips Alaska applied for the pool in late March 2016, after several years of exploration and appraisal activity in the northwest corner of the Kuparuk River unit.

The commission held a meeting in early May 2016 where company representatives provided testimony The company originally referred to the accumulation as the “Moraine” interval, but the commission decided to name the pool after the “Torok” formation present in the region.

A development program from DS 3S could access between 100 million and 500 million barrels of oil in place, according to estimates included in the Area Injection Order. A primary recovery was expected to be approximately 5%, with certain enhanced recovery programs increasing that recovery rate to a range of 13 to 55%.

DRILLING STARTS FOR IH NEWS

Drilling in ConocoPhillips Alaska’s1H NEWS development in the Kuparuk River unit began the week of Aug. 7, 2017, then-company spokeswoman Lowman told Petroleum News. The new development targeted the production of viscous oil from the northeastern sector of the West Sak formation in the unit, using wells drilled from the Kuparuk 1H drill site. The $460 million project was still expected to result in peak production of 8,000 barrels of oil per day. First oil from the development was planned for late 2017, Lowman said.

The development has involved the construction of a nine-acre extension to the existing 1H site, as well as surface facilities to support four new pentalateral production wells and 15 injection wells, Lowman said. The surface facilities included a new pipe header, wellhead infrastructure, modules, tanks and tie-ins to the existing pipeline infrastructure.

A pentalateral well has five lateral wells extending horizontally from a main well bore. Retrieving difficult-to-flow viscous oil from the unconsolidated sands of the West Sak was challenging. Over the years ConocoPhillips Alaska had honed the techniques required for viable viscous oil production. Techniques that originally involved the use of hydraulic fracturing combined with downhole pumps had evolved over the years into an approach in which multilateral, horizontal production wells thread through the reservoir sands and in which downhole pump designs had evolved. Injector wells drove oil into the producers. Water had been used as the injection fluid, although in 2016 ConocoPhillips obtained approval from the Alaska Oil and Gas Conservation Commission for the use of a viscous reducing water-alternating-gas injection technique.

Given the technical difficulties involved in viscous oil production, economically viable production was challenging in an era of relatively low oil prices.

However, ConocoPhillips and the other Kuparuk working interest owners felt confident that the 1H NEWS development would prove profitable. “Despite low oil prices, this is a project that ConocoPhillips and its co-owners believe is a viable investment,” Lowman said.

NEWS FIRST OIL AT NEWS

There was tremendous opportunity for ConocoPhillips Alaska on the North Slope, but there were challenges and capital was scarce, Lisa Bruner, then the company’s vice president of North Slope operations and development, told the Resource Development Council’s annual conference Nov. 15, 2017, in Anchorage. An example of both opportunity and challenge was 1H NEWS, the Northeast West Sak development at 1H pad in the Kuparuk River unit.

The company took the opportunity of the conference to announce the startup, on Nov. 4, 2017, two months early, of viscous oil production from 1H NEWS.

Bruner said 1H NEWS, which involved in-fill wells in the West Sak field, was sanctioned in 2015. But in 2016, when oil dropped to $28 a barrel, the project was significantly challenged, was put on hold and teams working on it went back to the drawing board. She said ConocoPhillips went back to work on the project early in 2017, with facilities installed through the last winter season and drilling beginning in August.

The 19-well development, with four producers, cost some $400 million to develop and involved a 9.3-acre expansion of the existing 1H drilling site. “1H NEWS is an exciting project for us,” Marushack said in a press release.

“Viscous oil is more challenging to produce, but state-of-the-art technologies are allowing us to pursue projects like this that put more oil in the pipeline.” He called the project another example of what the company does well, “bringing good projects online safely with new production and revenues for Alaska.” It was the largest investment in viscous oil at Kuparuk since 2004.

HORIZONTAL MULTILATERALE

1H NEWS would be developed with horizontal multilateral wells supported by vertical injectors. Bruner said the first pentalateral well was online at 1H NEWS and was the first rotary-drilled pentalateral with access to all laterals, provided through junctions installed at each lateral which gave the company access with coiled tubing drilling to clean out any sand which accumulated over time. The well was still cleaning up, Bruner said, but was likely to be the highest producing well out of West Sak. There were a couple of historic West Sak wells that peaked at more than 5,000 bpd, she said, and the new pentalateral was believed to be on its way to that, with more than 29,000 feet of horizontal section.

LEGACY FIELDS

At a Nov. 8, 2017, ConocoPhillips analyst and investor meeting, Al Hirshberg, then ConocoPhillips executive vice president of production, drilling and projects, said the company was undergoing a renaissance in legacy assets in Alaska, with increased capital to pursue infrastructure-led programs around the company’s core position.

Bruner called the company’s legacy fields its bread and butter and said while they were not easy fields to run because of aging infrastructure, they provided needed infrastructure for infill drilling and optimization. She said coiled tubing drilling at Kuparuk accounted for more than 22% of production there, some 19,000 bpd, with 130 CTD wells drilled since 2009. The company was also seeing results from rotary drilling, with two of the longest wells at Kuparuk, more than 25,000 feet lateral.

Despite an overall reduction of development activity, ConocoPhillips Alaska experienced a notable increase in oil production at the Kuparuk River unit in 2017. The second most productive unit in Alaska produced 109,100 barrels per day in 2017, up from an average of 103,000. The main Kuparuk oil field produced 84,100 bpd in 2017, up from 78,100 bpd in 2016. The remaining oil production came from the four Kuparuk satellites, although only the West Sak satellite reported a slight increase in 2017.

MOVING FROM DIESEL TO GASOLINE

In early 2018 the state approved plans by ConocoPhillips Alaska to install two new gasoline tank skids and other equipment at the Kuparuk River oil field. The division said the tanks would provide gasoline fuel for vehicles as ConocoPhillips “transitions away from diesel-powered pickup trucks in the Kuparuk field.”

WATER INJECTION FOR MELTWATER

In April 2018 AOGCC approved a request from ConocoPhillips Alaska to change to a new technique that would increase oil production at the Meltwater field in the Kuparuk River unit. The commission issued an area injection order allowing the company to inject seawater and produced water into the oil reservoir for the satellite, agreeing that water injection would increase ultimate recovery from Meltwater.

ConocoPhillips Alaska was injecting natural gas into the reservoir to encourage oil production. However, that resulted in an increasing gas to oil ratio in the produced fluids. In addition to impacting the oil production at Meltwater, a test performed in 2017 showed that the high ratio had been causing the backing out of 900 barrels per day of production elsewhere in the unit, the commission said in its order. The company wanted to switch to water injection by converting the gas line to Meltwater, between the Meltwater pad and the Kuparuk 2N pad, for the carriage of water.

Modeling indicated that low pressure waterflood would increase ultimate oil recovery by 1 to 2%, ConocoPhillips told AOGCC. The use of water injection should extend field life by five to 10 years, the company said.

CORING UP KUPARUK

ConocoPhillips and BP said July 3, 2018, that ConocoPhillips was acquiring BP’s 39.2% interest in the Greater Kuparuk Area and BP’s 38% interest in the Kuparuk Transportation Co., including the Kuparuk Pipeline, which moves oil to the trans-Alaska oil pipeline.

At the same time ConocoPhillips was selling BP a subsidiary with a 16.5% interest in the Clair field in the United Kingdom. Excluding customary adjustments, the transaction prices were expected to be cash neutral to both companies. (Various regulatory approvals were required and received.) “These transactions are significant for ConocoPhillips because they continue our strategy of coring up our legacy asset base in Alaska, while retaining an interest in the Clair Field in the U.K.,” said ConocoPhillips Chairman and CEO Ryan Lance.

“We have a long history of creating value in Alaska and an ongoing commitment to invest in our legacy assets … Likewise, we are committed to maximizing the value of our assets in the U.K. North Sea, including continued investment in our operated assets in the Central North Sea,” Lance said.

ConocoPhillips Alaska was already the majority working interest owner at Kuparuk at 55.3% followed by BP at 39.2%, Chevron at 4.9% and ExxonMobil at 0.6%, giving the company 94.5% at Kuparuk once the deal with BP closed.

SECOND NEWS PHASE

ConocoPhillips Alaska’s success with North East West Sak, or NEWS, led it to plan an expansion into a second phase of development called Eastern NEWS, scheduled for startup in 2023. Michael Driscoll, then-ConocoPhillips Alaska’s supervisor of viscous development, said in an interview in early September 2018 that the company’s latest West Sak development in its NEWS project boasted five horizontal producing legs, each about 7,000 feet in length that fed oil into the vertical well was now producing about 10,000 bpd with three producers currently online.

A fourth well would start producing in mid-September 2018, which would boost output. ConocoPhillips Alaska had estimated peak production at 8,000 bpd initially. Driscoll said the higher production was a result of better-than-expected reservoir performance and growing experience in working with the reservoir. ConocoPhillips Alaska had also reduced the cost of the project by 45%, he said, through aggressive efforts at cost-cutting and managing development more efficiently. The lower production cost was the result of a concentrated effort to cut West Sak expenses after oil prices plummeted in 2015. NEWS was just beginning development then, “but management halted the program and told us to find ways to cut costs,” Driscoll said.

The team got creative. Among several measures, water-based drilling fluids were substituted in the plan, for at least some wells, in lieu of more expensive oil-based drilling fluids. This change was made after the company determined the water-based fluid could be as safe and effective as oil-based fluid. These steps made ConocoPhillips Alaska more confident it could put viscous into the company’s long-term North Slope development plans.

The company new phase, Eastern NEWS, would be in an adjacent area. Driscoll believed the same kind of incremental technical leaps that had made West Sak viscous oil economically viable could be applied at Ugnu, the huge heavy oil resource that has also been identified in the Kuparuk area. Ugnu oil is even thicker and more difficult to produce. In June 2019 ConocoPhillips Alaska made public its agreement to purchase 100% ownership in the North Slope Nuna prospect from Caelus Natural Resources.

Five miles southwest of the Oooguruk unit and just east of the Colville River within the northern section of the Colville-Kuparuk fairway, the Nuna prospect included 11 tracts covering 21,000 acres. As a result of the Nuna No. 2 discovery well drilled during the 2012-13 winter drilling season, former operator Pioneer Natural Resources increased its estimate of the areal extent of and ultimate oil recovery from Nuna, a Torok formation prospect in the Brookian sequence, to between 75 million and 100 million barrels of oil.

A Caelus spokesman in 2017 said that Nuna could result in production of some 25,000 bpd with a field life of 20-30 years. In its June 17, 2019, announcement of the acquisition, ConocoPhillips Alaska would appraise Nuna over the next several years, with a goal of making a final investment decision.

“This transaction represents an attractive addition to our expanding North Slope position and will allow ConocoPhillips to cost effectively develop Nuna utilizing Kuparuk River unit infrastructure,” Marushack said. “We believe this acquisition could lead to more oil production, more revenue for the state and more jobs for Alaskans.”

HATFIELD ON NUNA

During a conference call on July 30, 2019, Michael D. Hatfield, ConocoPhillips president for Alaska, Canada and Europe, provided what he described as a “little bit of color” on the Nuna prospect. “It’s a discovered resource on 21,000 acres that’s in our backyard. It’s immediately adjacent to Kuparuk. … It’s $100 million for a 100 million barrels. It’s something we’re very pleased about. It will be developed from pads both that exist at Kuparuk and a pad at Nuna where there is … already a gravel … road to that pad in place,” Hatfield said. “The remaining facilities at Nuna can be built in a single ice road season.

So, we’ll have appraisal over the next couple years and target first oil in the 2022 timeframe,” he said. “The development will be using existing drilling and completion technology and then the development itself will be incorporated as part of our Kuparuk program, so it won’t be incremental to that,” Hatfield said.

The June 2019 leasing report from Alaska’s Division of Oil and Gas showed working and royalty interests in Nuna prospect leases being transferred from Caelus Natural Resources to ConocoPhillips Alaska. West of the central North Slope, Nuna lies immediately south of the Eni-operated Oooguruk unit and immediately west of the ConocoPhillips-operated Kuparuk River unit.

CORE FIELDS RIVAL NEWBIES

In his presentation at the Resource Development Council’s annual conference in Anchorage in November 2019, Scott Jepsen talked about the North Slope’s reemergence as an oil province due to big new oil discoveries at Willow and Pikka, expanding the depiction of the renaissance by adding the North Slope’s three major producing, or core, fields -- Prudhoe Bay, Kuparuk and Alpine/Colville River -- to the new fields. Furthermore, Jepsen, who then was a senior vice president at ConocoPhillips Alaska, said that the capital investment planned for the three core fields in the next 10 years rivaled that proposed for new discoveries -- $11 billion for the core fields compared to $13 billion.

And while the three older core fields were “not the shiny new toy out there that gets so much attention,” they were vital to present and future oil production in Alaska, he said. At the time the three core fields yielded 80% of the oil production that was coming from the North Slope, Jepsen said. It was “critical that the infrastructure that these fields support stays healthy,” because “the economics of the new fields are reliant” on the continued health of the core fields.

AND THEN CAME COVID-19

In the face of plunging oil demand and price and the advent of the coronavirus, Alaska giant ConocoPhillips said March 18, 2020 that it was taking a long-range approach and sticking to its current 10-year plan with a mere 10% cut. The company was reducing capital spending just $700 million worldwide from a $7 billion budget, including about $200 million in Alaska and $400 million in the Lower 48 states.

In an investor’s market update conference call on March 18, 2020, ConocoPhillips said it would trim drilling programs in the Kuparuk River unit and the western North Slope Alpine area, including the laying down of two rigs. “Our industry is clearly experiencing an unprecedented event brought about by simultaneous supply and demand shocks,” top company exec Lance said in the conference call. “The actions we are now taking reflect an acknowledgement of current events as well as uncertainty around the timing and path of a recovery.”

TAKING METHODICAL APPROACH

Lance said ConocoPhillips was in a strong position to take a methodical approach, as it ended 2019 with more than $14 billion in liquidity, including cash, cash equivalents, short-term investments and availability under the company’s revolving credit facility.

“We continue to monitor market conditions and consider various scenarios to inform any future actions. We have a significant level of flexibility between our capital, operating costs and share repurchase program, but we are choosing to exercise only a portion of it at this time. We believe that the highest-value longer-term response is price-path dependent,” he said.

“If anything, I think we have a greater conviction around our 10-year plan because it really is a philosophy of how to run an E&P business in a volatile market environment,” Lance said.

DEMOBILIZE RIGS

On April 8, 2020 ConocoPhillips said it was demobilizing its North Slope rig fleet and ceasing exploration in the National Petroleum Reserve-Alaska. “Due to the heightened Covid-19 risk to our North Slope workforce, we are taking action to significantly reduce the number of personnel on the Slope in a managed fashion,” Lowman told Petroleum News. “To do this, we are making the difficult decision to demobilize our rig fleet. Given the high degree of uncertainty on how the situation plays out, we can’t say how long these measures will be in place.”

When it filed plans of development in June for the five Kuparuk River unit participating areas, ConocoPhillips Alaska told Alaska’s Division of Oil and Gas that it planned to indefinitely suspend the Meltwater participating area, drill site 2P, in 2021. The company cited low production at Meltwater, and back-out issues at CPF-2 which were estimated to cost some 600 bpd of production due to water cycling requirements to keep the Meltwater crude oil pipeline warm. On July 30, 2021 the division approved suspension of operations at Meltwater, DS-2P.

KUPARUK 25 MORE YEARS

ConocoPhillips Alaska prefaced its newly filed Kuparuk unit plan of development with a warning that the plan was “envisioned prior to Covid-19 and the market downturn.”

“The nature and extent of impacts to previously planned activities is very uncertain and will depend in part on the duration and severity of public health and market conditions,” the company said in the POD submitted to Alaska’s Division of Oil and Gas May 1, 2020. It covered Aug. 1, 2020 through July 31, 2021. But while there might not have been a lot of activity in the POD period, in discussing facilities issues the company said it was looking at upgrades to support another 25 years of Kuparuk production.

At the time there were 46 drill sites for Kuparuk and 878 active wells, 506 producers and 372 injectors, with average oil production in 2019 of 73,000 bpd, water production of 557,000 bpd and water injection 675,000 bpd. Activities for calendar year 2019 included: 22 coiled tubing drilling wells, including five West Sak wells, for a peak incremental oil rate of approximately 2,100 bpd gross.

GKA APPRAISALS

ConocoPhillips Alaska said the overlying Nuna Moraine was being tested for productivity and waterflood performance, with a two-well pilot drilled in late 2018 and two follow-up well pairs planned to further de-risk waterflood performance.

“Coupled with results from special core analyses, this dynamic data will guide future plans for Nuna Moraine.” The company said in its POD that it brought the 1H-Ugnu-401 well back online in April 2019. The well had been shut-in in 2016 because of electric submersible pump problems, which the company said it was continuing to troubleshoot “in an effort to determine if higher oil production rates can be sustained.” Alaska Oil and Gas Conservation Commission records show the 1H-Ugnu-401 produced 822 barrels in April 2019 but nothing since.

ISAACSON TAKING REINS

Marushack also told RDC attendees he was retiring at the end of January 2021 after 38 years with ConocoPhillips. Erec S. Isaacson, who has been with ConocoPhillips for nearly 35 years, would be replacing him. In 2006, Isaacson moved to Alaska, first holding the position of manager, Alaska exploration, and later as vice president, commercial assets, with accountability for non-operated, pipeline and Cook Inlet assets. He began his career with Phillips Petroleum Co. in Bartlesville, Oklahoma, in 1986 as a geophysicist in upstream technology. He held various exploration and development positions in the company, including assignments in Houston, Odessa and Stavanger.

HITTING RESET IN 2021

In a presentation at Meet Alaska in late March 2021, Isaacson described 2021 as “hitting reset.” The company would focus on lowering costs and engaging stakeholders and would also resume regular development drilling, as well as progress on $1.1 billion in projects across the North Slope: Greater Mooses Tooth No. 2 construction, Alpine expansion, Willow permitting, Nuna development and ongoing work at the Eastern NEWS (North East West Sak) at the Kuparuk River unit. Nine months before Covid-19 hit ConocoPhillips Alaska was planning a few years of appraisal as part of its Kuparuk River program, leading to first oil in 2022 In his Meet Alaska presentation, Isaacson put the timeline for first Nuna oil at the “mid-2020s.”

GKA EXPLORATION

On the exploration side, ConocoPhillips Alaska said it continued to monitor two existing horizontal producer/injector well pairs at the Torok (Moraine) reservoir for long-term deliverability and waterflood, using the information to determine optimal inter-well spacing. “Based on the performance of these wells, a new well pair is planned to be drilled in 2022,” the company said.

COYOTE, NEW GKA FIND

Alaska got encouraging news in the June 30, 2021 ConocoPhillips market update, including the planned development of a new North Slope oil discovery, Coyote, which was on the western side of Kuparuk, and to the east of Nuna. Later that morning at RDC’s annual luncheon in Anchorage Isaacson said Coyote was a Brookian topset above the Nuna Torok discovery, describing Coyote as shallow.