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Providing coverage of Alaska and northern Canada's oil and gas industry
June 2021

Vol. 26, No.23 Week of June 06, 2021

The Explorers 2021: Great Bear Pantheon seeks conventional target

The new partnership is looking for conventional targets in central North Slope.

Eric Lidgi

for Petroleum News

Great Bear Pantheon’s exploration program in Alaska started unconventionally.

Great Bear Petroleum Operating LLC arrived in the state about a decade ago with a big idea. It wanted to find and develop the source of the North Slope’s prolific oil fields.

In the years since, and now with the help of London-based Pantheon Resources Plc, the company has pivoted somewhat toward a more conventional program: targeting oil fields contained in some of the same formations that also host those prolific fields to the north.

The new approach recently received encouraging news - with the results of the Alkaid program in 2019 and then with the results of the Talitha program earlier this year. Those results have convinced the company to proceed with appraisal and possibly development.

In late 2020, the state formed the neighboring Talitha and Alkaid units in the central North Slope, south of the Prudhoe Bay unit, along the Dalton Highway. The unit agreements include plans for exploration and development work in the near future that could potentially expand North Slope production south of the legacy fields in the basin.

A new approach

The progress of the past two years builds off more than a decade of work by Great Bear Petroleum, which in turn builds off a half century of limited work by other operators.

The leases within the current Alkaid and Talitha units are lightly explored.

ARCO drilled Toolik Federal 1 and Toolik Federal 2 wells in the vicinity of the current units in 1969. Both wells targeted deeper oil in the region. The company returned with the North Franklin Bluffs Unit 1 well in 1973 to target shallower natural gas. Mobil also looked for shallower gas in the region with the West Kadleroshilik 1 well in 1974.

ARCO drilled the Pipeline State 1 well within the current unit boundaries in 1988, again targeting deeper oil. Conoco drilled the Sequoia 1 well in 1991 and Eni US Operating Co. drilled the Maggiore 1 well in 2007, both testing deeper oil outside the current unit area.

All those earlier wells represented an older way of thinking about the North Slope.

Great Bear Petroleum LLC began its Alaska program in 2010, when it bid more than $8 million for 105 tracts covering more than 500,000 acres at a state lease sale. The haul accounted for 92% of the high bids in the sale. The company was more successful than it had intended, forcing it to cull to stay below a state-imposed 500,000-acre limit.

At the time, then Division of Oil and Gas Director Kevin Banks compared the Great Bear acquisition to the results from a lease sale the year prior, when the Armstrong Resources LLC subsidiary 70 & 148 LLC also dominated, also took a large block of leases south of the Kuparuk River unit and also briefly became the largest leaseholder in Alaska.

Looking back, the early 2010s represented a moment when smaller players were considering new ideas for the North Slope. Through various partnerships, Armstrong helped launch the trend toward exploration and development of the Nanushuk formation, which now accounts for much of the planned development on the North Slope. Similarly, Great Bear wanted to bring the emerging trend of unconventional prospects to Alaska.

The principals - Ed Duncan and Bob Rosenthal - both had experience in the Alaska oil industry and knowledge of the North Slope’s geology. They wanted to replicate the successes of the Eagle Ford shale and the Barnett shale in the Lower 48, where companies were drilling into source rock and using advances in hydraulic fracturing to extract hydrocarbons from geology once thought too tight to produce. “It’s new to Alaska but it’s not new to resource play exploitation in the Lower 48,” Duncan said in 2010.

Hydrocarbons are created when organic materials deep within the earth encounter extreme temperatures and pressures. Once created, hydrocarbons migrate and accumulate based on their particular properties and also on the nature of different rock formations.

The process always leaves some oil behind, trapped in source rocks. Those rocks were once too tight to produce, but advances in well stimulation have made that oil viable.

The oil found in prolific North Slope fields like Prudhoe Bay and Kuparuk was presumably created elsewhere. Great Bear believed that “elsewhere” was the deep shale to the south. It believed it could launch 50 years of development by proving up its idea.

Early on, Great Bear was proposing a program unlike anything seen before in Alaska, and policymakers were both incredibly intrigued and incredibly skeptical with the claims.

The company envisioned three 15-year phases, each featuring 3,000 wells drilled from one-acre pads, with 200 wells to a pad. The program would require 20 rigs, drilling year-round. It would cost approximately $2 billion each year, at a rate of $10 million per well.

For comparison: at that time, only about 1,000 wells had been drilled in the main Prudhoe Bay field, throughput on the trans-Alaska oil pipeline was hovering around 550,000 barrels per day and the state usually only had between 20 and 30 rigs at any given time.

Why so many wells? Hydraulic fracturing is limited in its reach. It only produces oil contained in the thin fractures it creates. By comparison, the legacy oil fields of the North Slope are mostly conventional reservoirs - think: giant underground pools. With sufficient pressure, and accommodating geology, one well can drain a relatively large area.

The entire Alaska oil industry was developed around these conventional plays. For example, unitization is designed in part to protect correlative rights, making sure that one leaseholder doesn’t surreptitiously drain away all the oil contained under a neighboring lease. What good is a unit when it comes to hundreds of thousands of oil-saturated rocks?

Great Bear also envisioned incredible rates of production: starting at 200,000 barrels per day by 2020 and reaching a peak of 600,000 barrels per day by 2056. The company even claimed it could produce 1 million barrels per day, simply by drilling more quickly.

If other players joined Great Bear in the region, Duncan told lawmakers in early 2011, the state might even need to build a second trans-Alaska oil pipeline to handle the flow.

Alcor and Merak

In pursuit of that goal, Great Bear proposed a six-well and lateral test program. The wells were named after the stars in the Ursa Major constellation, also known as the Great Bear: Alcor No. 1, Merak No. 1, Mizar No. 1, Megrez No. 1, Dubhe No. 1 and Alioth No. 1.

The program began in the summer of 2012 - unusually for the Slope, Great Bear was able to take advantage of the road system to allow for some year-round exploration - when the company drilled the 10,812-foot Alcor 1 well and 11,094-foot Merak 1 well.

“I can tell you with absolute confidence that where we thought we would find oil in these source rocks, we found oil,” Duncan said in September 2012. Around the same time, he told a shale conference that the company would be producing oil by the end of the year.

But the challenge of source rock development is less in finding oil than in producing it commercially. By the end of the year, the company had only completed the vertical section of two wells and collected 600 feet of core but had not drilled the laterals.

“Certainly operations took a little bit longer than we expected, particularly on Alcor, and the lab analysis quite frankly has taken much longer than we had hoped,” Duncan said.

Great Bear plugged and abandoned both wells and spent several years evaluating its drilling results and conducting seismic. It returned to exploration in 2014-15, when it proposed a three-well program targeting conventional and unconventional resources.

The idea was to use near-term conventional production to generate cash flow that would finance the complexity of bringing unconventional development into a new basin.

In early 2015, Great Bear drilled the Alkaid 1 well. The well targeted the Kuparuk formation, but operations were ended before the entire Brookian had been penetrated.

Flooding along the Dalton Highway prevented the company flow testing the Alkaid well that season. By the time the company suspended the well and demobilized equipment, all zones had been logged and sidewall cores had been taken at the deepest zones, confirming indications of oil in three major zones, from some 4,000 feet to 8,100 feet.

The company again turned to seismic acquisition, looking to bolster its understanding of a relatively underexplored and under-mapped section of the North Slope. But the suspension of exploration tax credits during the Walker administration prompted Great Bear Petroleum to further delay its exploration activities in the central North Slope.

Pantheon arrives

Pantheon Resources acquired two Great Bear subsidiaries in early 2019. The deal gave Pantheon a majority stake and operatorship of more than 250,000 acres of Great Bear leases, mostly located immediately south of the Prudhoe Bay and Kuparuk River units.

Pantheon announced plans to raise $16 million plus expenses to help fund the acquisition and related exploration activities. While some of those funds would go toward existing exploration activities at its East Texas properties, most would go toward a suite of projects in Alaska. The goal of the program, the company said at a 2019 annual meeting, was “to prove up acreage … and sell at a significant premium to a larger company.”

The Alaska projects included revisiting the Alkaid well and participating in the Winx No. 1 well on leases south of the Colville River unit and the village of Nuiqsut. Winx No. 1 was operated by 88 Energy Inc., profiled elsewhere in this edition of The Explorers.

In early statements, Pantheon said that its newly acquired acreage had “an estimated P50 technically recoverable resource (gross) of 2 billion barrels oil” in which $200 million has been invested to date, including more than 1,000 square miles of 3D seismic. The acreage reportedly contained two discovery wells with six hydrocarbon-bearing zones.

Alkaid

The newly formed Great Bear Pantheon re-entered and flow tested Alkaid 1 in early 2019. The well produced 108 barrels of 38° API oil and 300 barrels of water over 24 hours from the Upper Brookian formation. The company estimated that the main zone of interest in the Brookian contained 240 feet of net pay within 400 feet of reservoir rock.

“Such flow rates are considered to be an excellent result and indicate the potential for materially higher flow rates when wells are drilled in the typical manner for Brookian wells in Alaska - horizontally, stimulated and with larger intervals perforated,” Pantheon said in a March 24, 2019. statement, referring to the vertical Alkaid No. 1 well.

Secondary targets in the West Sak and Ugnu formations were both wet.

The program also prompted the company to change its view of the nearby Phecda prospect. Instead of a separate venture, it now saw Phecda as an Alkaid appraisal well.

“These two projects will now likely be part of a single development plan, favorably located adjacent to the Dalton Highway and TAPS pipeline,” the company said. “The better than expected results in the zone of interest will also impact the pre-drill P50 technically recoverable resource estimates which will be assessed in the near future.”

In later announcements, Pantheon said that combining the prospect essentially doubled the P50 recoverable reserves - to a range of 90-135 million barrels, from 59 million barrels of oil. The estimated combined oil in place was increased 50% to 900 million barrels from 595 million barrels. The recovery factor also bumped up slightly.

The results prompted the company to review its pre-drill conceptual development plans at the Alkaid prospect and also to formulating plans for future farm out discussions.

By that summer, Pantheon was telling investors that it planned to implement a phased production program at Alkaid and could bring the field into production as early as 2021.

For the initial phase, the company said it would bring mobile production units to the area to process approximately 1,500 barrels of oil per day from three to four delineation wells and would then truck the oil north along the Dalton Highway to Pump Station No. 1 of the trans-Alaska oil pipeline. As the project advanced toward a full-scale development with as many as 50 wells, the company would construct a standalone processing facility.

While trucking oil year-round has occasionally been used as a short-term solution in Cook Inlet, it is nearly impossible across much of the North Slope due to the lack of permanent roads. The location of Alkaid along the Dalton Highway changed everything.

A month later, the company moved its timeline. Positive conversations with state and federal regulators had led the company to believe it could bring production online as soon as the summer of 2020, “subject to completion and timing of a successful farmout.”

Over the summer, Pantheon opened a data room and released investor updates designed to market the project, but neither successfully enticed a partner to join the project.

In October 2019, Pantheon announced it was buying out minority partners Halliburton Energy Services LLC and Red Technology Alliance LLC’s 25% interest in the six leases of the Alkaid/Phecda prospect. Pantheon said that the acquisition was important for improving ongoing farm-out discussions. But a potential partner remained elusive, especially given the epic uncertainty of 2020 - first the pandemic, then the price crash.

Talitha

The results of Alkaid also increased Pantheon’s confidence in the Talitha prospect.

Great Bear Pantheon drilled 10,456-foot Talitha No. A in January 2021 and reported oil shows and potentially productive zones in all five formations: the Kuparuk, Lower Basin Floor, Upper Basin Floor Fan sequences, Slope Fan and Shelf Margin Deltaic horizons.

In early 2019, around the time of the acquisition, Pantheon described the Talitha well as a re-drill of Pipeline State No. 1 from 1986. The Talitha well would appraise oil sands seen in the plugged and abandoned ARCO well and would also “test a topset exploration play analogous to recent major discoveries in the area” using techniques that “far surpass what was available in the 1980s.” The company said that 900 million barrels of oil in place had been discovered in three zones and estimated 1.7 billion barrels of exploratory upside.

“ARCO drilled the well looking for a thick, clean sand and instead found a thick zone of interbedded, laminate-type sands and shale,” Pantheon Technical Director Bob Rosenthal said during a June 2019 webcast to share additional results. “The sands were oil-bearing but at the time given the … $10 price of oil and the fact completion technology wasn’t as advanced as it is today, the well was plugged and abandoned. … With today’s horizontal drilling technology we believe we have a significant discovery” at the Talitha prospect.

Early results led the company to shift its approach. Initially, it had prioritized the Shelf Margin Deltaic. But instead the company is looking at a secondary target in the Kuparuk.

After attempting to test the well from the open well bore, Pantheon drilled a sidetrack approximately 80 feet from the original wellbore and perforated the sidetrack between 10,069 feet and 10,085 feet measured depth. The sidetrack encountered significantly higher than expected reservoir pressure and collected “exceptionally light oil.” The results promoted the company to consider “a more methodical approach to ongoing operations,” the company reported in a six-month financial report released March 30.

“Fracking and testing operations are now underway,” the company reported.

Work plans

The state Division of Oil and Gas formed the Talitha unit in late 2020 based on the potential of the Kuparuk C and Brookian formations. Both formations are conventional. They are the same formations that host many of the large producing fields to the north.

In its first plan of exploration, Great Bear Pantheon proposed drilling the Talitha A well in early 2021 and the Talitha B well in early 2022, as well as some seismic reprocessing.

Given the lack of exploration in the unit, the state required Great Bear Pantheon to post a $3.3 million performance bond by September 2021. Failure to post the bond would result in automatic termination of the unit. To recover the bond, the company would need to drill a well within two years, or two wells within four years, of the formation of the unit.

The state also approved the neighboring Alkaid unit to the north of Talitha.

The accompanying Plan of Exploration proposed an 8,000-foot Alkaid No. 2 well to the bottom of the Brookian formation with a 10,000-foot lateral to the southwest. The project would begin with infrastructure construction in June 2021 with drilling to follow.

The company intends to conduct a long-term flow test of the Alkaid No. 2 well over a six-month to nine-month period starting September 2022. The flow test would be designed to establish the initial production rate, the slope of the decline curve and the rate at which the decline curve levels off in order to accurately predict the production tail.

Great Bear Pantheon also intends to conduct non-drilling activities, including reprocessing some 50 square miles of merged seismic information collected between 2012 and 2016, as well as other modeling activities and engineering work to consider possibilities for connecting a future development to the trans-Alaska oil pipeline.

The company is also considering a potential Alkaid No. 3 well in 2022. The well would depend on the current non-drilling activities, as well as the results of Alkaid No. 2. As currently envisioned, it would be similar in depth and design to the Alkaid No. 2 well but with a lateral to the northeast. A similar long-term flow test would also be conducted.

A schedule included with the plan calls for starting construction of the Alkaid No. 3 well in early 2022 with the production test occurring over the second half of the year.






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