While it seems most Arctic exploration activity has slowed, it really depends on where you look. Bruce McMichael reports.
Gazprom Neft’s Prirazlomnoye facility, in the Russian Arctic. Photos from Gazprom Neft.
About 22% of the world’s undiscovered oil and natural gas reserves are believed to lie within the Arctic Circle. Huge technical, environmental, and legal challenges suggest that this figure is unlikely to change in the short- to medium-term, while a rolling series of good news, bad news stories has created a “will they, won’t they” atmosphere of development.
With the ongoing impact of US-produced shale gas and oil, volatile global prices and the legislative fallout of environmental disasters such as the Deepwater Horizon disaster of April 2010 in the Gulf of Mexico, exploration sputters across the Arctic.
Opening up remote, challenging frontier areas such as the Arctic brings significant logistical challenges ranging from using nuclear-powered icebreakers to cut through meters of pack ice sheets to delivering equipment from drilling rigs to pipes, chemicals and people. Communications are complicated and expensive, generally requiring satellite connections, and remote medical services are likewise expensive and complex to arrange. Wherever you are in the Arctic, it’s a frontier play without infrastructure.
Discovery to production
On average, fields in the Arctic region have taken 13 years from discovery to production, one of the longest industry lead-times. To date, close to 40 fields have been developed from an estimated 180 discovered fields, onshore and offshore.
This estimate, by the US Energy Information Administration, puts potential assets in territory claimed by littoral states and a couple of extras: Russia, the US, Norway, Canada, Denmark (Greenland), Finland, Iceland and Sweden. Finland and Sweden do not border the Arctic Ocean and are the only Arctic countries without jurisdictional claims in the Arctic Ocean and adjacent seas.
To date, most exploration and development has been in frontier areas close to existing infrastructure or offshore, including the Russian and Norwegian sectors of the Barents Sea, Sakhalin Island in Russia’s far east, and Alaska’s Beaufort and Chukchi Seas.
The high profile exit of Shell from its Alaskan exploration program in the Chukchi Sea earlier this year and French oil major Total’s decision to relinquish its 25% stake in the Shtokman Phase 1 field development in the Russian sector last year created the impression that big oil was backing away from Arctic development.
However, activity in the Russian sector of the Arctic has continued. Norway is also an aggressive investor, with around one-third of offshore spend in the Arctic expected to originate from Oslo and Stavanger, according to a 2012 report by Infield. It said, in the latter part of a 2012-2018 forecast period, most of the projected spending would be on the back of the Eni-operated Goliat project as well as the development of Statoil’s Johan Castberg development, (Read more: Keeping cool, cutting costs).
Much of Russia’s investment has been in the sub-Arctic region, in fields surrounding Sakhalin Island. This area was expected to draw around 20% of Arctic area spending capex in 2012-2018, according an Infield report.
Russian focus has also been on the Russian Arctic continental shelf. In 2013, the Prirazlomnoye facility came onstream. It is expected to yield 5 million-ton of Arco (Arctic Oil), a high density, high sulphur oil, between 2016-2017.
“The Prirazlomnoye project has yet to reach its design capacity. There are plans to drill and launch nine extraction wells in 2016-2017, which would produce more than 5 million-ton of oil,” said Minister of Natural Resources and Environment Sergei Donskoi, in June 2016.
This summer, Gazprom Neft said two further production wells (its third and fourth) had come online at Prirazlomnoye, plus the second and third injection wells. As a result, production had breached 6000-tonne/d. In total, some 32 wells are expected in the field.
In 2014, Rosneft also made the Universitetskaya-1 (Victory) discovery in the Kara Sea, with partner ExxonMobil, despite EU and US sanctions.
However, progress in the Russian Arctic could be slowed by a recent government decision to ban new licenses for offshore field development on the continental shelf. The decision appeared to be aimed at focusing the country’s efforts on gas production from existing developments, such as those in the Yamal Peninsula area, focused on LNG development, given global trends towards resource use and amid “the macroeconomic instability we face right now,” Donskoi told a mid-September meeting with Russian President Vladimir Putin. Gazprom and Rosneft are currently the only firms allowed to hold offshore exploration and production licenses.
The Noble Discoverer, used by Shell in its last Alaska drilling campaign. Photo from Shell/Flickr.
Alaska start and stop
Supermajor Shell drilled its Burger J exploration well in the Chukchi Sea, offshore Alaska, in July 2015, and while shows of oil and gas were reported, they were not found in sufficient quantities to justify spending more on top of the US$7 billion already invested over two drilling campaigns. Operations were abandoned within a year.
At the end of 2015, the US government “froze,” at least until the end of 2016, exploration drilling off the coast of Alaska, while revoking existing permits (Shell until 2020 in the Chukchi Sea and Norway’s Statoil until 2017) in the Beaufort Sea.
Then, just before May 2016, Shell and ConocoPhillips officially pulled out of Arctic exploration, and the acreage was returned to the US government shortly ahead of a 1 May due date to pay rent to keep holdings that lie in the Chukchi Sea north of Alaska. However, Shell held onto the lease containing the Burger J find, at a potential cost of $132,456 over the next four years, according to Curtis Smith, a company spokesman, because there is “value in the data the company gathered during its 2015 exploratory drilling.”
Companies generally have to give the US government the geological information they glean from oil and gas development in federal waters, but they can get an extra 2-10 years to turn over that data as long as they still hold the territory.
Other companies that relinquished rights include Statoil, which had a sizeable chunk of 16 leases, Italy’s Eni (four leases, Chukchi Sea) and Canada’s Iona Energy (one, Chukchi Sea).
Shell said it had indefinitely halted oil exploration in the US Arctic, although it is hoping to get a lease extension from 2017.
In the 2017-2022 US offshore leasing program, there are leases available in the Beaufort Sea scheduled for 2020, and Chukchi in 2022, however it remains to be seen if the sales will continue. Industry associations have called for the US government to have the leases remain in the program.
In 1996, offshore the eastern coast of Canada, the ExxonMobil-operated Hibernia platform was installed on the seabed, 315km southeast of St. John’s, with an expected lifespan of 20 years. However, ongoing development of satellite fields, including the Hibernia South Extension, have significantly increased oil reserves, and production is now expected to continue for a further two decades years. The ongoing success of Hibernia is expected to encourage further exploration drilling and the company now has successfully bid for more than 1.5 million hectares of offshore licenses.
First oil production at Exxon’s Sable Offshore Energy Project (SOEP) started in 1999, the development of five natural gas fields near Sable Island, 225km off the east coast of Nova Scotia. Field decommissioning is expected to start in 2017.
The Norwegian Petroleum Directorate estimates that the Barents Sea holds almost half of Norway’s undiscovered 18 billion bbl of hydrocarbons. While less hostile than other parts of the Arctic, due to the regional effect of the Gulf Stream weather system, the Barents Sea remains a remote area with minimal infrastructure and only two fields in production to date: Statoil’s Snøhvit subsea gas field and Eni’s Goliat floating oil project.
Norway is getting closer to the development of other regional fields, among them Lundin Petroleum’s Gotha, with an expected 100 MMboe in reserves, and Johan Castberg, which is believed to hold 550 MMbbl, with a greenlight production cost of above $45/bbl (OE: August 2016).
A third discovery in the Barents Sea is Wisting. In May, Austria’s OMV announced it had successfully completed drilling and testing of its Central II appraisal well on Wisting. The horizontal well was drilled about 310km north of Hammerfest and is the northernmost oil discovery in Norway. Wisting Central II is the fifth well in the production license (PL) 537, which was awarded in the 20th licensing round in 2009.
More exploration could follow, thanks to the 23rd licensing round, which saw three new license areas issued in the Barents Sea, acreage previous out of bounds to the industry, alongside seven other licenses. Statoil won four operated licenses, Lundin picked up three operated licenses, and Det Norske, Centrica and Cairn Energy, were each awarded one operated license.
In August, Statoil announced it will conduct a major exploration campaign in several parts of the Barents Sea in 2017.
“For 2017, we see promising prospects in different parts of the Barents Sea. For example, we want to explore the Blåmann prospect in the Goliat area, Koigen Central in PL718 on Stappen High and the Korpfjell prospect in PL859 that was awarded in the 23rd licensing round,” said Jez Averty, Statoil’s head of exploration on the Norwegian continental shelf, at the time.
Engineers have built gravel islands from which oil is produced in shallow waters offshore Alaska – including Texas-based Hilcorp’s Northstar Island and Eni’s Spy Island.
Hilcorp is also planning the Liberty project, approximately 5.5 mi (8.6km) offshore in the Beaufort Sea’s barrier islands in 6m of water. If developed, Liberty would be the first producing oil-field entirely in the federal outer continental shelf off Alaska. According to US Bureau of Ocean Energy Management (BOEM), Hilcorp estimates that the Liberty contains approximately 150 MMbbl of recoverable crude oil.
BOEM is conducting an environmental review of the project and expects to release a draft Environmental Impact Statement next summer, said John Callahan, a spokesman for the agency.
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