Frosty prospects

December 4, 2013

Plans for arctic exploration and development continue apace—but will there be resources available? Elaine Maslin reports.

The size of the arctic offshore challenge is significant, both in scale and complexity, with relatively little activity carried out to date. Technology, resources, environmental protection and project economics, not to mention the harsh conditions, are just some of the challenges faced by operating in arctic regions.

Image: Drilling in the Barents Sea comes with wintry conditions—life aboard the semisubmersible Polar Pioneer during drilling on Skrugard. Photo: Harald Pettersen, Statoil.

In some cases this has led to projects delays and cost overruns, however, activity continues.

To date, acreage has been offered under license off the US state of Alaska, Canada, Greenland, Norway and Russia. The largest acreage offered has been off Russia, at 1.5 million sq km, or 77% of the total, most of which is in the hands of Rosneft, says Geir Utskot, arctic manager, Schlumberger.

“To put this into context, the total size of the US Gulf of Mexico is 445,000sq km, and of this area, only about 155,500sq km has been licensed,” he told the recent SPE Arctic & Extreme conference in Moscow. “The entire Gulf of Mexico could fit inside the Kara Sea and is roughly equivalent to 5% of the arctic region.”


Drilling has been undertaken in the Barents, Baffin Bay, and Chukchi Seas. Seismic acquisition has been carried out in the Kara, Barents, Laptev and Chukchi Seas.

Most of the drilling has been offshore Norway, with more than 20 wells in the last three years, compared to two wells off Greenland and one off Russia, according the Maxim Nachaev, director, consulting/Russia, IHS Cera.

Image: Transocean’s semisubmersible Polar Pioneer facility was used to drill on Skrugard in the Barents Sea and is lined up to support Shell’s potential 2014 drilling campaign in the Chukchi Sea. Photo: Harald Pettersen, Statoil.

Most recently, OMV opened a new oil play, with its Wisting Central discovery in the Hoop area in the Barents Sea. Activity levels are expected to remain high, following the award of licenses in the 22nd round, and plans to open the Barents southeast area in the next licensing round.

More than 40 wells are likely to be drilled in the arctic by 2020, depending on the economic situation, said Nachaev, who also spoke at the SPE Moscow event.

Among those planning to drill in the region in 2014 is Statoil, which plans to drill two operated wells in the same area as Wisting Central—the Atlantis and Apollo prospects, along with further appraisal drilling around the Johan Castberg fields (Skrugard/Havis).

To date, Shell has yet to confirm if it will go ahead with a drilling program in the Chukchi Sea, offshore Alaska, in 2014. Last month [November], the company submitted revisions to its previously approved exploration plan, in order to “keep the company’s 2014 exploration options viable.”

ExxonMobil, in partnership with Rosneft, plans to drill in the Kara Sea in the summer of 2014, Utskot says. Cairn Energy, with joint venture partners, has yet to determine (as of press time) whether the Pitu prospect will be drilled in 2014.


Currently, there are four groups of projects being developed in the arctic, Nachaev says.

These are: the Snøhvit (Snow White) field in the Barents Sea; fields developed through inclined drilling in Russia; Prirazlomnoye, in the Pechora Sea, Russia; and fields in north Alaska, also developed through inclined drilling. Of those, only Snøhvit, a 140km subsea tieback to shore, and Prirazlomnoe are offshore.

ImageShtokman, facing delays.

Next year, ENI’s Goliat oil field is due to come on stream. It will be the first Norwegian Barents Sea oil development, produced through a subsea development connected to a Sevan floating production system.

Goliat was due to be followed by the Barents Sea Johan Castberg development, previously known as Skrugard – Havis. Operator Statoil recently said it was delaying its investment decision, setting likely first production back from 2018 to 2020, Utskot says.

In the Russian sector, the Shtokman project has been repeatedly set back, due to low gas prices. Statoil pulled out of the project in 2012.


All arctic projects, on- and offshore, endure huge delays in all phases, from exploration to commissioning, Nachaev says, with projects taking 10-25 years to be brought onstream. Budgets have also been extended, by factors of two to three, and even four, of the original plan. Prirazlomnoye, for example, was budgeted at under US$1 billion in 1996. The final cost is about US$4 billion, four times higher than the original estimate, Nachaev says. “This is not unique,” he says, pointing to delays and cost overruns offshore Norway.

Image: An artist’s illustration of Sevan floatingproduction unit being built for ENI’s Goliat field in the Barents Sea. Photo Courtesy: ENI.

“Most arctic fields take about 40 years to get to production,” says Utskot, including dates for some early Canadian onshore developments. Norman Wells, onshore Canada, took 64 years from discovery, in 1921, to production. Offshore, Snøhvit took 23 years from discovery to first production, Goliat will have taken 14 years when it comes onstream next year, while Shtokman, if it comes online in 2022, its latest estimated date, will have taken 34 years.

Not all projects take so long. “Bent Horn [onshore Canada] was put on production very fast in arctic terms [11 years]. The idea was for it to power a mine in the high arctic,” Utskot says. “Skrugard-Havis [Johan Castberg] will be a fast development [nine years], even when delayed to 2020, because Statoil has developed a plug and play system for fields with specific parameters.”


The level of resources required for operating in the arctic could be hindrance to activity in the icy region.

Shell’s 2012 Alaska drilling campaign involved 22 vessels and 2000 personnel, Mitch Winkler, manager, arctic, Shell International Exploration and Production Inc., told SPE Arctic & Extreme. “There are not that many vessels available offshore Russia,” says Utskot. The number could be reduced to 10, using purpose built vessels, but without them the vessels available have to be used, which means more are needed, he says.

Russia, where a majority of the estimated arctic resources are predicted to be found, has a number of ice-breakers under construction, but the country does not have a significant offshore support vessel operator, because of the limited offshore operations carried out to date, Mikko Niini, managing director of Finland’s Aker Arctic says. Longer term, Niini, who also spoke at SPE Moscow event, predicts the existing small operators could be built up, or a global player could establish operations in the region.

Before then, the level of resources could be tested. “Next summer ExxonMobil will be drilling in the Kara Sea, and this is going to take up a lot of the resources,” Utskot says. Norway’s Westshore predicts vessels could leave the North Sea and Norwegian Sea to meet the demand, with up to 12 support vessels required for the Kara 2014 drilling campaign.

ExxonMobil has a contract to use the West Alpha semisubmersible in Norway/ Russia from August 2014 to July 2016, on a US$527,000 day rate, with an option out to July 2017, at a higher $549,000 rate.

Utskot says there is reason to believe there will not be as much activity as hoped in Norwegian sector, due to lack of resources, specifically rigs, qualified to work in the area, exacerbated by some of those resources moving to Russia.

Project economics, specifically where the resource is gas, will also hold projects back, Nachaev says. While gas is cheaper in other regions, such as the US, due to shale gas, expensive offshore Russian arctic gas will be held back.

Low gas prices have not helped Russia’s Shtokman development. A second phase at Snøhvit is on hold awaiting additional reserves to underpin its viability. Johan Castberg was due to come onstream in 2018 but its first production date was set back by Statoil earlier this year, due to uncertainties related to the resource estimate and investment level and an increase in petroleum taxation levels by the Norwegian government.

The Federal government in Russia is considering tax breaks for projects on the arctic shelf, Nachaev says. The proposal is for the rate to be set at between 1-30%, with gas in the most difficult seas receiving the minimum 1%, starting January 1, 2016, on new offshore fields.

Despite this, major production in the Russian arctic shelf will not start until after 2025, he says, due to international markets, with production ramping up after 2030.

Changing the tax rate will be important to incentivize investment, he says. However, although the reduced rates for new fields have been proposed, the tax system in Russia has been very volatile, he impeding confidence. Localization requirements and insufficient logistics capability also provided limitations.

Public acceptance is also a requirement for arctic operations, says Statoil’s Helge Lund. “These days we have to own up to a fair amount of public skepticism about our industry, and especially surrounding increased activity in the Arctic,” he told the recent Arctic Safety, Managing Risk in the High North conference in Norway.

“So, to succeed in these areas, we have to embrace an approach that is prudent and demonstrates that we can exploit resources responsibly. I believe we are best served by maximum transparency in and understanding of our activities.” OE