August 2022

Regional report: The Arctic- Breaking the circle

A longtime hotbed of global politics, Arctic E&P operations these days are more fractured than ever. Hydrocarbon-triggered opposition from activists and governments, national geopolitical interests, and the omnipresent demand to produce oil and gas have shattered the circle into pieces.
Mike Slaton / Contributing Editor

A longtime hotbed of global politics, Arctic E&P operations these days are more fractured than ever. Hydrocarbon-triggered opposition from activists and governments, national geopolitical interests, and the omnipresent demand to produce oil and gas have shattered the circle into pieces. 

On one side, Russia is all in on Arctic development, even as sanctions stymie funds and technology, and war darkens insights into its energy operations. On the other side of the pond, Canada continues its moratorium on Arctic development, begun in 2014. 

Next door, the U.S. Arctic is the target of protest, legal challenges and governmental obfuscation. Technology advances and discoveries face a “Groundhog Day” of endless meetings, reviews and revisions that challenge investment with delays and costs. 

Fig. 00. The Transocean Enabler (left) drilling in the Johan Castberg area. Image: Equinor. Johan Castberg FPSO arriving at Aker Solutions Stord 11 (center). Image: Equinor.   Ice surrounds the Priazlomnoye (right) project. Image Gazprom.neft.
Fig. 00. The Transocean Enabler (left) drilling in the Johan Castberg area. Image: Equinor. Johan Castberg FPSO arriving at Aker Solutions Stord 11 (center). Image: Equinor. Ice surrounds the Priazlomnoye (right) project. Image Gazprom.neft.

Perhaps the brightest northern light is in the Barents Sea, where Norway is conducting lease sales, making discoveries and doggedly pursuing production. 


ANWR. The E&P outlook for the Alaska National Wildlife Refuge (ANWR) has gone downhill since the first-ever lease sale in January, with several companies recently relinquishing their claims. Their exits further diminish the poor showing at the long-anticipated sale and leave only two of three leaseholders from January. The sale was quickly suspended by the Biden administration, and a new environmental review process was set in motion. 

Chevron and Hilcorp cancelled legacy leases that predate the January sale. The leases were from a deal between Chevron and BP that led to drilling the refuge’s KIC-1 test well, a tight hole named after the Kaktovik Inupiat Corp. 

The companies reportedly paid $10 million to Arctic Slope Regional Corp. (ASRC) to terminate their 1984 obligations for leases, in a tract of Alaska Native corporation-owned land within ANWR near the city of Kaktovik, according to the Anchorage Daily News (ADN). A formal agreement was created in October 2021 and finalized earlier this year, reports ADN. “Chevron’s decision to formally relinquish its legacy lease position was driven by the goal of prioritizing and focusing our exploration capital in a disciplined manner, and in the context of our entire portfolio of opportunities,” said spokeswoman Deena McMullen. 

Regenerate Alaska, the only true oil company to acquire a tract in the Jan. 6 sale, also cancelled its lease, leaving Knik Arm Services, an Anchorage real estate investment firm, and the state-owned Alaska Industrial Development and Export Authority holding the remaining leases. 

ASRC said it is disappointed that “the current political environment” forced the companies to give up their leases, reported ADN. 

The Alaska Industrial Development and Export Authority’s Executive Director, Alan Weitzner, told The Washington Post that he is not surprised the oil companies decided to leave the refuge, in the face of repeated obstacles from the federal government, which “creates a time sink for corporations within that area.” 

“In my mind, it’s very unfortunate that these major investors in the state of Alaska are not being allowed to continue to pursue development, and are being really pushed to look elsewhere, in large part outside of the U.S. There are delays and just outright denials of requests for permitting to ultimately pursue the activities that you need to do,” he said. 

NPR-A. The Department of Interior (DOI) signed a new Record of Decision (ROD) to guide management of the National Petroleum Reserve in Alaska (NPR-A). The April decision reverts to the 2013 IAP, but DOI says it includes more protective lease stipulations and operating procedures for threatened and endangered species from the 2020 IAP/EIS. The plan includes some lands near existing leases in the Greater Moose’s Tooth and Bear Tooth unit and Umiat, and it continues to make land near Teshekpuk Lake unavailable. 

The ROD follows the Bureau of Land Management’s (BLM’s) January announcement that it would review the area’s 2020 Integrated Activity Plan (IAP). Initiated in November 2018 to develop environmentally responsible management for leasing and development, the plan was published last June. But it was delayed in January, when “an abundance of stakeholder requests” resulted in BLM extending public comment and review. 

The revised plan makes approximately 11.8 million acres (52%) of the NPR-A subsurface area available for oil and gas leasing. The remaining approximately 11 million acres (48%), including most of the Special Areas and coastal areas of the Beaufort Sea, are closed to oil and gas leasing. 

In doing so, the plan makes lands available for pipelines and other infrastructure necessary for owners of offshore leases in the state or federal waters of the Chukchi and Beaufort Seas, to bring oil and gas across the NPR-A to the Trans-Alaska Pipeline System. It also prohibits new infrastructure on lands containing sensitive wildlife habitats. 

Alaskan Senators Lisa Murkowski and Dan Sullivan (both R-Alaska) reacted negatively to BLM’s reversion to an earlier plan. “This shortsighted decision closes millions of acres to responsible energy development, deliberately upending a careful balance in the management of the reserve and more broadly across Alaska lands,” they said in a joint statement. “The Biden administration’s move abandons the 2020 version of the IAP, which was developed in partnership with the North Slope Borough and in consultation with North Slope Tribes and Alaska Native Corporations. It comes mere weeks after President Biden pledged to “work like the devil to bring gas prices down.” 

Willow Project. Possibly on the good side of events, a revised environmental review of ConocoPhillips’s proposed Willow Master Development Plan in the NPR-A was released by BLM in July. The draft supplemental environmental impact statement (SEIS) presents a range of alternatives, including a “no action” alternative. The document forms the basis for a BLM decision on the Willow Project, to be made after public comments and analysis. 

Fig. 1. Two recent discoveries south of Johan Castberg.
Fig. 1. Two recent discoveries south of Johan Castberg.

The SEIS was prepared to address so-called deficiencies identified by the U.S. District Court for Alaska, when it cancelled the Trump administration’s approval of the Willow Project. 

The BLM describes the draft SEIS as including a “corrected and expanded analysis of potential climate impacts” associated with the Willow Project. This includes addressing the court’s finding that the original analysis “failed to consider downstream foreign emissions resulting from the consumption of oil produced by the project.” 

An alternative being considered for the Teshekpuk Lake Special Area (TLSA) involves a modified infrastructure that would reduce the Willow Project’s potential footprint, by eliminating two of the five proposed drill sites, including the northernmost proposed drill site and its associated infrastructure in the TLSA. 

The alternative would require relinquishing lease rights in the TLSA, an environmentally sensitive wetland that includes part of the Bear Tooth Unit and the proposed Willow Project. BLM says the alternative also defers analysis of a fourth potential drill site, which would require additional review that is not considered in the new alternative. 

In the new draft, BLM will also “reinitiate consultation under the Endangered Species Act (ESA) concerning listed species, including polar bear.” This includes consideration of mitigation measures and updates to the range of alternatives. 

The draft SEIS was developed following a public scoping comment period and involved eight cooperating agencies (the U.S. Fish and Wildlife Service, Army Corps of Engineers, Environmental Protection Agency, Inupiat Community of the Arctic Slope, North Slope Borough, State of Alaska, Native Village of Nuiqsut, and City of Nuiqsut) and external stakeholders. Additional public and virtual meetings are planned, as well as a hearing on the project’s potential to impact subsistence resources and activities. 

ConocoPhillips spokesperson Dennis Nuss, quoted by Reuters, called Willow “a strong example of environmentally and socially responsible development that offers extensive public benefits.” 

Senator Murkowski also voiced support for the Willow project, observing, “The Willow project has gone through several extraordinarily stringent environmental reviews and will adhere to Alaska’s world-class safety and environmental standards. It’s no wonder the project has such broad support from Alaskans—including the Alaska Federation of Natives, the Alaska AFL-CIO, the Alaska Chamber of Commerce and Alaska Native stakeholders across the North Slope.” 

Kuparuk. In addition to Willow politics, ConocoPhillips has been busy developing assets elsewhere in NPR-A. Its Fiord West Kuparuk reservoir produced first oil on May 18 from a record-setting horizontal well, a month after setting a new drilling record for a land-based rig. The 35,526-ft, TMD, well was drilled using the Doyon 26, the largest mobile land rig in North America. Able to drill in excess of 40,000 ft, the rig greatly extends the wellbore reach from a single pad. The capability enables development of 154 mi2 of reservoir from a 14-acre drilling pad, versus 55 mi2 using a conventional rig. 

Fiord West Kuparuk is a satellite development of Alpine field that is being developed from the existing CD2 pad in the Colville River Unit. Extended-reach drilling reduces the infrastructure footprint, eliminating a new gravel pad, additional pipelines and more roads. A small expansion of an existing pad was made to accommodate the rig. “This project opens a new era we call ‘growth without gravel’, where we can use extended reach technology to access 60% more acreage from a single pad, dramatically reducing our footprint and enabling us to safely produce from environmentally sensitive areas,” said Erec Isaacson, president of ConocoPhillips Alaska. 

The CD2-310 well is an injector that will be pre-produced for five to six months, prior to being converted to permanent injection service. Data from the well will aid in optimizing the design of the next well. The well’s flowrate is being increased progressively and is currently producing close to 10,000 bopd, exceeding expectation. “Extended-reach technology has been a game-changer for ConocoPhillips,” said Vincent Lelarge, vice president, Alaska Asset Development. “It’s how we are able to responsibly develop fields like Fiord West Kuparuk, with minimal footprint on the tundra and the surrounding environment.” Lelarge said ConocoPhillips has worked collaboratively on the Doyon 26 rig since 2011, when use of an extended-reach drilling rig was being evaluated. The rig arrived on the North Slope in 2020. 

Moose’s Tooth. ConocoPhillips’s Greater Moose’s Tooth No. 2 (GMT2) drill site produced first oil last year. GMT2 is the second project in the Greater Moose’s Tooth Unit. Located in the northeast NPR-A, it is about 8 mi southwest of GMT1. It is a satellite development of Alpine field and is connected to the existing Alpine production center in the Colville River Unit (CRU) for processing, via GMT1 and CD5 infrastructure. 

ConocoPhillips says it submitted permit applications for drilling at GMT2 in August 2015. The BLM completed a Supplemental Environmental Impact Statement with a Record of Decision on Oct. 16, 2018. The BLM, ASRC and Kuukpik Corporation share land and mineral rights for the project. 

Fig. 2. The Johan Castberg field will include an FPSO and an extensive subsea development, with 30 wells distributed on 10 templates and two satellite structures. First oil is expected in 2024. Image: Equinor.
Fig. 2. The Johan Castberg field will include an FPSO and an extensive subsea development, with 30 wells distributed on 10 templates and two satellite structures. First oil is expected in 2024. Image: Equinor.

GMT2 has a 14-acre drilling pad, an 8-mile gravel road and pipeline facilities connected to the existing CRU. The pad is planned to have 36 wells initially, with capacity for up to 48 wells. Peak production is estimated at about 30,000 boed. Total project cost is roughly $1.4 billion, gross, including construction and drilling expenses. At peak construction during the past three winter seasons, ConocoPhillips says the project created about 700 jobs, resulting in more than 600,000 direct construction man-hours. 


Leasing. The Barents Sea is the focus of 2022 lease sales planned by the Norwegian Ministry of Petroleum and Energy. Its Awards Predefined Areas (APA) 2022 licensing round involves only 28 Barents Sea blocks. The government and Norway’s Socialist Left Party agreed not to include three Barents Sea blocks: 7426/10, 11 and 12. The offering is down from 2021, when a total 84 blocks were added—four in the North Sea, 10 in the Norwegian Sea and 70 in the Barents Sea. 

“Access to new, attractive exploration acreage is a pillar in the government’s policy for further development of the petroleum industry,” said Norwegian Minister of Petroleum and Energy Terje Aasland. “In this year’s proposed APA round, we are facilitating new discoveries in the years ahead. New discoveries are crucial for ensuring jobs, value creation and production.” 

Equinor. Discoveries in the Barents Sea are adding to Equinor’s assets. Two recent successes are in close proximity to each other, as well as to Johan Castberg field, to which Equinor and partners Vår Energi and Petoro may ultimately tie them, Fig. 1. The most recent is Skavl Stø exploratory well 7220/8-3. It was drilled by the Transocean Enabler rig in early June, at a site five km south-southeast of Johan Castberg field discovery well 7220/8-1. Preliminarily estimates put the find’s recoverable resources at between 5 MMboe and 10 MMboe. 

Skavl Stø is the 13th exploration well in the Castberg license. The production license was awarded in the 20th licensing round in 2009. Equinor plans to further develop the asset, along with Snøfonn North and previous discoveries Skavl (2014) and Isflak (2021). The Skavl Stø discovery was preceded by Snøfonn Nord exploratory well 7220/8-2 S. Discovered in late May, the well is also about 5 km south-southeast of the Johan Castberg field discovery well. Preliminary estimates indicate there are recoverable resources between 37 MMboe and 50 MMboe. 

The Snøfonn Nord discovery was made one year after the Isflak discovery in the same area, but it is probably somewhat bigger, says Equinor. The well was drilled by the Transocean Enabler rig, which was then moved 800 m further west, in PL 532, to drill the Skavl Stø exploration well. “Snøfonn Nord is an exciting discovery in the vicinity of the Johan Castberg development and can add valuable volumes to the installation in the future,” says Kristin Westvik, Equinor’s senior vice president for exploration and production north. 

Last year, Equinor and partners Vår Energi and Petoro used the Transocean Enabler rig to drill exploration well 7220/7-4 in production license 532, about 10 km southwest from the Johan Castberg field discovery well 7220/8-1. Recoverable resources are estimated at between 31 MMboe and 50 MMboe. Further development toward the planned infrastructure for Johan Castberg field will be considered at a later stage, says Equinor. Johan Castberg will start producing in 2022. The Johan Castberg FPSO arrived in Norway on April 8 and has been anchored at Aker Solutions’ quay on Stord, where the turret and processing modules are being installed. 

The field development concept includes an FPSO vessel and an extensive subsea development, with a total of 30 wells, distributed on 10 templates and two satellite structures, Fig. 2. The production vessel and subsea facility are designed for producing 190,000 bopd and achieving a 30-year productive life. Recoverable volumes are estimated at between 450 MMboe and 650 MMboe. 


Getting E&P news out of Russia is more difficult than usual. Company websites that typically carry operational information are often limited or completely dark. For instance, Gazprom’s website has been down since April. To wrap up this report, here are a few items that are filtering down: 

Russia’s industry relations took another hit in March, when the Norwegian Oil and Gas Association suspended Russian members Rosneft and Lukoil over the invasion of Ukraine. The move comes about ten years after the delineation of Norwegian-Russian Arctic waters. In a March statement, the association said, “In the light of the situation in Ukraine, the board of Norwegian Oil and Gas have decided to suspend the membership of the Russian companies Lukoil Overseas North Shelf AS and RN Nordic Oil AS.” RN Nordic is a regional subsidiary of Rosneft. 

Rosneft’s Vostok Oil project started construction of an Arctic oil terminal at the Bukhta Sever port. Aimed at facilitating development of the Northern Sea Route, the port will become Russia’s largest oil terminal, supported by 102 reservoirs by 2030. The company said the project is comparable in size to the exploration of West Siberia in the 1970s or the U.S. Bakken oil region over the past decade. In addition, the company says production drilling began at the northern Payakha oil field, also part of Vostok Oil. 

Novatek’s Yargeo joint venture has won the license to survey, explore and develop production at the North Yarudeyskoye oil and gas condensate field, in the Yamal-Nenets autonomous region in the Arctic. The region is Russia’s main gas-producing area, with North Yarudeyskoye estimated to have 93.5 MMboe. The greater Yarudeyskoye field began producing in 2015 and quickly accounted for nearly a third of Novatek’s liquids production.  

About the Authors
Mike Slaton
Contributing Editor
Mike Slaton is a contributing editor.
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