Thick permafrost layers with sometimes complex geological structures make it difficult for seismic technology to paint clear pictures of what lies below the surface in the Arctic. Shifting sea ice could be lurking, holding the potential to wreak havoc on equipment.

The arctic climate itself poses obstacles for not only equipment, which must be designed to withstand the elements, but also offshore personnel. Then there are preparations needed simply because of the long distance from the mainland. These factors equate to higher costs.

Added to that are environmental and safety concerns given delicate ecosystems, regulatory hurdles, jurisdictional disputes, competition, and environmental foes. There is perhaps no other place in the world that presents as many challenges for oil and gas E&P as the Arctic. Yet the potential bounty keeps the region on companies’ radars.

An estimated 90 Bbbl of the world’s remaining conventional oil resources, 47 Bcm (1,669 Tcf) of natural gas, and 44 Bbbl of NGL may remain to be discovered in the Arctic, according to the US Geological Survey. And now may be as good a time as ever to pursue drilling, some believe, considering climate change is opening doors to the Arctic. Temperatures are increasing, sea ice is decreasing, and glaciers are melting.

Arctic ice extent declined at a rate of 105,000 sq km (41,000 sq miles) per day in July, for example, according to the National Snow & Ice Data Center. The Kara and East Greenland seas lost ice faster than other Arctic areas. The rate was 61% faster than the average 82,000-sq-km (31,660-sq-miles) rate of decline witnessed between 1981 and 2010.

Kara Sea takes spotlight

Companies are rolling out plans but are proceeding judiciously. ExxonMobil is targeting the Kara Sea.

“The first well will be about 600 miles [966 km] north of the Arctic Circle, or about 350 miles [563 km] farther north than the North Slope in Alaska. The sea is generally free of ice by early August,” Patrick McGinn, a spokesman for ExxonMobil, told E&P. “But because of the Kara Sea’s arctic conditions, by around mid-October we will have to leave ahead of the ice, which can return in as little time as a couple of weeks. Further complicating the already complex planning are the remote locations of the wells – some 900 nautical miles [1,440 nautical km] and a multiday trip by supply boats to the drilling rig from support bases.”

ExxonMobil plans to drill one exploration well in the Kara Sea in 2014. In addition to fully winterizing the rigs, the ice-defense system will include multiple advanced icebreaker vessels and an extensive ice-detection system.

“One of the major challenges associated with the Russian Arctic licenses is the sheer scale,” McGinn said. “Very little data exist on some of the licenses, which are similar in size to the acreage the oil and gas industry currently has under lease in the Gulf of Mexico. And each area has significant differences from block to block.”

To expand knowledge of the area, specifically the Kara Sea, ExxonMobil and Rosneft have joined forces to establish an Arctic Research Center. The center will focus on geotechnical and metocean surveys, sea ice management, development concept design and evaluation, and safety and environmental protection. The center also will focus on designing systems that will safely support year-round oil and gas production, McGinn added.

“Since the agreement was signed in June, the initial focus is getting the Rosneft and ExxonMobil staff resources in place, initiating the approved 2013 work activities, and planning the 2014 work program,” he said.

ExxonMobil is providing US $200 million in funding for the center’s initial research work, and Rosneft and ExxonMobil will equally fund the next $250 million to continue their joint research work, McGinn said, noting Rosneft holds a 66.67% interest and ExxonMobil 33.33%.

Partnerships are key

Rosneft and Gazprom are driving exploration efforts in Russia. Combined, the two hold more than 70 licenses, according to an Ernst & Young report on Arctic oil and gas. While Rosneft is anticipated to target the Barents Sea shelf and Okhotsk Sea, Gazprom’s efforts are expected to focus on the Kara Sea. Russia’s Arctic region covers more than 1.2 million sq km (463,323 sq miles).

Given that Gazprom and Rosneft are the only companies able to get new exploration licenses, they have formed joint ventures with others. Rosneft, for example, has sealed Arctic deals with Eni for Barents Sea exploration, Statoil for exploration of the Barents and Okhotsk seas, and ExxonMobil for the Black and Kara seas. Initial exploration costs for the ExxonMobil Black and Kara seas projects alone could run more than an estimated $3.2 billion. Data collection is under way, and drilling operations are set to commence in 2014.

The agreement between Exxon-Mobil and Rosneft grew in scope this year as the two companies agreed to establish foundations to jointly explore seven more blocks covering about 600,000 sq km (231,661 sq miles) in the Chukchi, Laptev, and Kara seas. The plan calls for drilling 14 exploration and appraisal wells as well as conducting 2-D and 3-D seismic surveys over the next 10 years.

Other ExxonMobil-Rosneft joint projects include a tight oil pilot project in West Siberia and work toward an LNG plant in the Russian Far East. By year-end 2013, “the parties will undertake work to determine an LNG plant site, gas liquefaction technologies, and commercial structure of the project. Once this work is finalized, the parties plan to progress engineering definition,” ExxonMobil said in a news release.

Barents has appeal

While Russia holds some of the Arctic region’s largest basins, interest is high in Norway, which experienced its most successful licensing round for Barents Sea acreage in June. The Arctic area received 20 of the 24 licenses awarded. Helping to stimulate interest has been Statoil’s Skrugard and nearby Havis discoveries in 2011. The company said the two could hold between 400 MMbbl and 600 MMbbl of recoverable oil.

“Should further drilling confirm Statoil’s reserve estimate, it would mean that Skrugard could be Norway’s single largest offshore discovery. Skrugard’s gas potential suggests that it could provide feedstock for a second liquefaction train at the Sn?hvit LNG project,” Ernst & Young reported. “Skugard has significant implications for broader Barents Sea exploration given the spate of disappointments in recent years, with all six wells drilled in 2011 failing to yield hydrocarbons.”

The Norwegian Petroleum Directorate (NPD) said the Barents Sea could hold an average of 960 MMcm (33 Bcf) of oil equivalent. About 300 MMcm (10.6 Bcf) more could be gained on the Norwegian Continental Shelf (NCS) when the southeast portion of the Barents Sea is added.

Processes to open this section and offshore areas near Jan Mayen, which could have an average 90 MMcm (3.2 Bcf) of oil equivalent of undiscovered recoverable resources, have started. And, based on the response to the NPD’s recent seismic data offering, there appears to be interest from some of the industry’s major players. The Norwegian government made available seismic data packages for $2 million plus value-added tax from the southeastern part of the NCS in the Barents Sea and the ocean’s areas off Jan Mayen. Companies that have purchased the package include Chevron, Lundin Norway, Shell, Total, and Tullow, among others.

Statoil campaign continues

Statoil has licenses in the Arctic waters of the US, Canada, Greenland, Norway, and Russia with established positions in the Beaufort Sea, Baffin Bay, Chukchi Sea, Shtokman field, and Norwegian Barents Sea, which is the site of a nine-well exploration campaign currently under way. Statoil hopes to pull 1 MMboe/d from new Arctic wells by 2020, according to Ernst & Young.

“After our Skrugard and Havis discoveries we still see attractive opportunities here,” Tim Dodson, exploration vice president for Statoil, said in a prepared statement. “This is a less challenging area, as the Norwegian Barents is one of the only Arctic areas with a year-round ice-free zone. We also see the possibility of utilizing knowledge gained here for Arctic prospects elsewhere later on – just like we’ve already done with Snohvit.” Snohvit, located about 100 km (62 miles) south of Skrugard, is the only LNG facility north of the Arctic Circle.

Statoil started drilling in the Johan Castberg area, targeting four prospects. The first – Nunatak – was finished at the end of June and resulted in a small gas discovery, Statoil spokesman B?rd Glad Pedersen told E&P.

“While it is disappointing to find only gas in Nunatak, we believe in further oil potential in the Johan Castberg area,” he said. “The West Hercules rig is now drilling the second prospect in the Johan Castberg area – Iskrystall. … After completing the four prospects in the Johan Castberg area, the rig will move to the Hammerfest basin to drill the Ensis prospect. The Hammerfest basin is the most mature area in the Norwegian Barents Sea.”

The campaign will then proceed to the Hoop area, where the Apollo and Atlantis prospects will be drilled. “Hoop is a frontier unexplored area with exciting potential,” Pedersen said.

The program comes as part of the company’s heightened Arctic exploration efforts, which included tripling its Arctic research budget to $42 million in 2013. The technology efforts, according to a company press release, include work toward more cost-effective 3-D seismic for evaluating prospects in icy conditions and creating a tailor-made Arctic drill unit.

“Functions here are to include a management system to reduce ice impact, an optimized drilling package for faster drilling and increased rig availability, and solutions to ensure that the rig maintains its position,” Statoil said in a news release. “At present no robust solution for dynamic positioning dedicated for ice operation exists.”

Other Arctic-related R&D efforts include a $30 million integrated environmental-monitoring research program. Statoil said the online seabed monitoring system, which will be the world’s first, can monitor the environment down to 4,000 m (13,123 ft) deep.

Plans slow in US

Meanwhile in the US, Arctic activity has decelerated. Shell, which was setting the pace for drilling in Alaska’s Beaufort and Chukchi seas, announced earlier this year that it was pausing exploration drilling activity for 2013 “to prepare equipment and plans for a resumption of activity at a later stage.”

“We’ve made progress in Alaska, but this is a long-term program that we are pursuing in a safe and measured way,” Shell Oil Co. President Marvin Odum said in a prepared statement. “Our decision to pause in 2013 will give us time to ensure the readiness of all our equipment and people following the drilling season in 2012.”

ConocoPhillips and Statoil also halted plans to drill offshore Alaska.

Shell was able to finish top-hole drilling on two wells in 2012 in the Beaufort and Chukchi seas; however, getting to that point didn’t come without challenges. These included a damaged containment dome, which delayed needed federal government approval to drill, and the grounding of the company’s Kulluk drill unit, which Shell said was caused by “violent weather.”

The operations were the subject of a US Department of Interior (DOI) assessment, which found Shell entered the 2012 drilling season without finalizing key program components. This assessment led to rules that others must now follow in the Alaskan Arctic. These include mandates for operators to understand and plan for Alaskan conditions, maintain management and oversight of contractors, and establish plans with clear objectives in advance of the drilling season. The DOI also has encouraged the industry to work with the government to create an Arctic-specific model for offshore exploration, including drilling and maritime safety as well as emergency response equipment and systems.

If Shell is able to successfully develop its Chukchi and Beaufort seas leases, this could provide the company with its largest source of oil within the next two decades, according to the Center for Strategic and International Studies’ “Arctic Economics in the 21st Century: The Benefits and Costs of Cold.”

“Shell expects to eventually produce as much as 400,000 b/d of oil in the Chukchi Sea and 100,000 b/d in the Beaufort,” the study said. “By extracting just 10% of the oil in the Chukchi and Beaufort seas, the company would supplement its proven oil reserves, currently totaling 4.3 [Bbbl], by an astounding 2.7 [Bbbl].”

DEM IMPROVES MODELING OF ICE/STRUCTURE INTERACTION

James Bond and Han Yu, ABS

Ice load estimates on offshore structures are known to contain greater uncertainty than estimates for other types of environmental loading. And the lack of service experience further undermines confidence in ice load estimates. Existing design standards and codes provide limited guidelines for simple ice/structure interactions, and gaps and uncertainties remain in the assessment of ice loads.

The latest industry standard, ISO 19906 for Arctic offshore structures, considers full-scale measured response data and experience the most reliable for load estimates, which is second to model test findings and numerical results. Unfortunately, full-scale measurement data are very scarce for offshore structures, and model tests can be very costly. In addition, the level of accuracy achieved through model testing is still in question.

Recognizing the value of rapid advances in high-speed computing, ABS has been exploring several numerical methods and recently made the decision to develop two approaches: event-based interaction mechanics and the discrete element method (DEM).

DEM has great potential for simulating ice/structure interaction in relatively dense ice cover conditions. The methodology allows modeling of the motion and effect of a large number of objects of granular and discontinuous material such as the interaction of numerous ice floes and structures in pack ice.

In a partnership with Dalian University of Technology in China, ABS is working to develop and apply DEM for ice/structure interaction problems. The value in DEM is that it can model level ice, pack ice, rubble field, and pressure ridges with 3-D bonded spherical elements considering buoyancy and the drag force of the current. A parallel bonding approach and de-bonding criteria have been adopted to model both freezing and ice breakage.

Researchers have successfully simulated the interaction of simple structures with ice and have validated results against physical ice tests. This is a preliminary step. To take full advantage of advances in computing power and numerical algorithms, the DEM software is currently being adapted to a GPU platform to allow the simulation of millions of ice elements and structure interaction, such as the interaction encountered by a multilegged structure in ice.

It is anticipated that the resulting DEM tool will play a significant role in enabling a better understanding of complicated ice/structure interactions, will provide a cost-effective and practical alternative to physical modeling, and will enhance the current design codes.

The potential benefit of applying this new technology is significant, but more research is needed. As the oil and gas industry prepares to take on new challenges in frontier areas, technology advances like DEM will help close the gaps. Continued joint-research efforts will be critical in the development of solutions that will extend the boundaries of what is possible in Arctic exploration and development.

NOVATEK TAPS YAMAL PENINSULA RESERVES FOR LNG EXPORT

With 906 Bcm (32 Tcf) of proved and probable reserves in the South Tambey field north of the Arctic Circle, Novatek expects LNG exports to begin in 2016.

Scott Weeden Senior Editor, Drilling

The Yamal Peninsula extends into the Kara Sea off the north coast of Western Siberia above the Arctic Circle in the Yamal-Nenets Autonomous Region. The port of Sabetta on the eastern side of the peninsula will be the jumping-off point for Russia’s second LNG export project.

OAO Yamal LNG will have an initial export capacity of 16.5 million metric tons per year (MMmt/y). The first of three 5.5-MMmt/y liquefaction trains that will be built by Technip and JGC Corp. is scheduled for commercial production by year-end 2016. OAO Novatek (80%) and Total (20%) are partners in the project.

“Right now we are developing the infrastructure. We are building a seaport called Sabetta. We are building an airport. The project will be implemented,” Denis Solovev, head of the public relations department for Novatek, told E&P at the 2013 Offshore Technology Conference in Houston in May. “We gave [Technip] the deadline of being operational by the end of 2016, and the company confirmed it will meet that deadline. The second train will be completed by the end of 2017, and the third by the end of 2018.”

The LNG plant will receive feedstock from Novatek’s South Tambey field, which is about 15 km (9 miles) from the facility. The field has been extensively explored with seismic surveys and 58 exploratory wells and has proved and probable reserves of about 906 Bcm. A total of 208 production wells will be drilled from 19 well pads, which will reduce capex and minimize the impact on the environmentally sensitive arctic area. The drilling campaign began in 1Q 2013, Solovev said.

The LNG plant will operate year-round. The bay is icebound during the winter, which means icebreaking ships will be needed. “An Arc 7 Class LNG tanker was designed for the Yamal LNG project. Daewoo Shipbuilding & Marine Engineering was the successful bidder for the tankers. A slot-reservation agreement was signed with options to design, build, launch, equip, complete, and deliver up to 16 LNG carriers,” Solovev said.

Novatek is targeting customers in the Asia-Pacific region. The company plans to use the northern shipping route, which is open six months out of the year. “When it is open water, this route is about 2.5 times shorter than the alternative that goes to the west and south. Even if we are shipping to the west, we still remain profitable,” he said.

Currently, Gazprom is the only company in Russia that can export gas. Novatek has signed an agency agreement with Gazpromexport to sell gas to Novatek’s customers at the prices it sets. The gas will be sold through Gazpromexport for a fixed agency fee, which will be less than 1%. President Vladimir Putin issued a directive to government agencies to change this issue so that companies other than Gazprom can export LNG. This will apply only for LNG, not pipeline exports. Novatek expects a new directive before the end of this year, Solovev said.