 |
| Exxon Mobil’s Point Thomson field (left) holds an estimated 8 Tcfg and associated liquids, or about 25% of the gas reserves on Alaska’s North Slope (photo courtesy of Exxon Mobil). The Polar Pioneer (center) at work in the Barents Sea, Norway (photo by Harald Pettersen, courtesy of Statoil). At Melkøya, Norway (right), Snøhvit gas is landed, processed and shipped (photo by Helge Hansen, courtesy of Statoil). |
|
Based on recent seismic surveys, the Arctic region—primarily offshore in Alaska, Canada, Russia and Norway—has the potential to contribute significant volumes of oil and gas, as much as 20% of the world’s undiscovered hydrocarbons. However, the Arctic may be the most challenging energy frontier that the industry has faced. Remote locations, harsh weather, moving sea ice and a short drilling season add to the cost, complexity and risk of operating in the Arctic. The region is also a focal point for enviromental advocates, who believe that any development will do irreparable harm. And efforts by Western companies to team with Russia, to explore and develop its Arctic fields, have been blocked, at least temporarily, by sanctions imposed because of the Ukrainian crisis.
The oil and gas industry has operated in the Arctic successfully, and responsibly, since the 1920s, with Alaska, northern Canada, and Norway setting the pace for safe, prolific production. However, Alaskan output has declined in recent years, and offshore exploration efforts have been stalled by technical difficulties, legal action and environmental concerns. Meanwhile, Norway’s most recent Arctic exploration campaigns have not found commercial reserves.
RUSSIA
Russia’s Arctic contains huge potential reserves of oil and gas, totaling more than 100 Bboe. Although not technically in the Arctic, the Bazhenov shale play, in Siberia, is thought to hold several times as much oil as the Bakken, and the fields off Sakhalin Island continue to produce over 9 MMbbl of oil and 0.5 Tcf of LNG per year (11 mtpa). Russia, which relies on oil and gas revenue for half of its governmental budget, needs Western technical expertise, project management skills and long-term investment to develop its Arctic resources. Supermajors—like BP, Shell, Total and Exxon Mobil—see the potential and have made substantial investments, and created JVs with Russian entities, to develop Russian reserves.
Exxon Mobil (XOM) has made the biggest strategic bet on the Russian Arctic. In 2011, Rosneft and XOM executed a strategic cooperation agreement, to conduct joint exploration and development in Russia, the U.S. and other countries. The agreement called for a $3.2-billion investment in the exploration and development of East Prinovozemelskiy Blocks 1, 2 and 3, in the Kara Sea, and the Tuapse Trough License Block, in the Black Sea. In addition, the agreement provides Rosneft with an opportunity to gain equity interest in a number of XOM’s exploration and operating assets in the Gulf of Mexico, Texas and Canada.
In 2012, Rosneft and Exxon formed JVs to develop the Kara Sea and Black Sea blocks, and Rosneft subsidiaries acquired 30% interests in XOM’s La Escalera Ranch project in West Texas, 20 offshore blocks in the western Gulf of Mexico, and its Harmattan acreage in the unconventional West Cardium formation in Alberta. In 2013, Roseneft and XOM expanded the cooperation agreement, to include an additional 600,000 km2 for exploration in seven blocks in the Russian Arctic, and the potential purchase by a Rosneft affiliate of 25% of the Point Thomson project in Alaska, Fig. 1.
 |
| Fig. 1. Rosneft/Exxon Mobil exploration areas in the Russian Arctic. The blocks outlined in green were included in the August 2011 announcement of the strategic cooperation agreement. The blocks outlined in red were included in the February 2013 announcement of the agreement’s expansion. |
|
Kara Sea project. Rosneft’s website notes that its seismic program in the Kara Sea found 30 promising structures, with a total estimated reserve base of 87 Bbbl, and it could ultimately hold more oil than Saudi Arabia. The joint Kara Sea project between Rosneft and XOM spudded the Universitetskaya-1 well on Aug. 9, despite looming U.S. sanctions. As the project kicked off, Bloomberg reported that Russian President Vladimir Putin said, “Today, commercial success is driven by efficient international cooperation…and despite certain current political difficulties, pragmatism and common sense prevail.”
Universitetskaya-1, the world’s northernmost well, was drilled 250 km offshore by the West Alpha semisubmersible, upgraded for harsh environment drilling, in 266 ft of water toward a target depth of 7,710 ft. The rig was anchored in place, and it was supported by a dedicated ice-class, oil spill response vessel, and other ice-class and ice-breaker vessels, with spill response and ice management capabilities. In addition to standard well control systems, an enhanced, subsea well-capping device provided additional protection. This first well, at an estimated cost of $700 million, is part of a 40-well program planned through 2018.
On Sept. 20, XOM agreed to “wind down” operations by Oct. 10, as ordered by the U.S. government. On Sept. 27, Rosneft reported that the well had struck oil “comparable to Siberian Light oil,” after drilling to a depth of 6,932 ft. Rosneft’s very preliminary estimate for the resource base discovered by the well is 11.9 Tcfg and more than 733 MMbbl of oil. In announcing the discovery, Rosneft CEO Igor Sechin made a point of acknowledging the Western companies that participated in the well. “This is our united victory,” he said. “It was achieved, thanks to our friends and partners from Exxon Mobil, Nord Atlantic Drilling, Schlumberger, Halliburton, Weatherford, Baker Hughes, Trendsetter, FMC.”
By mid-October, all XOM and U.S. contractor companies had ceased operations on the Kara Sea project, in compliance with the sanctions. XOM’s extensive experience with Arctic and hostile-environment drilling is a necessary ingredient for success in the Kara Sea. It may be months, perhaps years, before the impasse ends, but with so much oil to be produced, one should expect XOM to resume the exploration program, and its ongoing partnership with Rosneft, when sanctions are lifted.
Gazprom projects. Gazprom has had its own successes and setbacks in exploring and developing offshore Arctic fields. Gazprom’s Shtokman field, with potential reserves of 3.8 Tcfg and 410 MMbbl of condensate, was discovered in 1988, but it has not yet been developed. The field is 340 mi from shore, in an area of the Barents Sea prone to icebergs. The most recent of several project plans includes subsea wells, an FPSO, an LNG terminal near Murmansk, and a pipeline from the Barents Sea to the Baltic. Although foreign partners Statoil and Total have pulled out of the Shtokman project, Gazprom expects it to produce by 2019. However, the project would require gas prices near $14/MMbtu, so it may remain dormant for quite some time.
Discovered in 1989, Gazprom’s Prirazlomnoye field, in the Pechora Sea, is being developed in shallow water, from an ice-resistant permanent platform, which was installed 37 mi offshore in 2011; it achieved Russia’s first offshore Arctic production in December 2013. The project calls for 40 directional wells to develop the field, with resources of more than 500 MMbbl of oil. The field is serviced by two ice-breaking tankers that transport oil to an FSO vessel in Kola Bay, near Murmansk. In September, Gazprom reported that it had produced the first million barrels from the field. Protesters from a Greenpeace vessel boarded the platform in 2012, leading to the arrest of 30 activists from 18 countries, on piracy charges. They were held for two months before the Kremlin released them. “If we do not stop this Arctic oil rush, we risk not only the environment but our ability to shake off the power structures of the last century,” Greenpeace International Executive Director Kumi Naidoo said in a statement.
Yamal project. Russia’s most significant onshore development in the Arctic, the Yamal LNG project, also has been hampered by U.S. and EU sanctions. The Yamal peninsula has huge gas and condensate reserves that are being developed by Gazprom, Rosneft and Novatek. The LNG plant, which is slated to have three trains, is under construction, with more than 6,000 workers on site. The $15-billion project is owned by Novatek (60%), along with Total (20%) and CNPC (20%).
Sanctions placed on Novatek, and its billionaire co-owner Gennady Timchenko, have blocked financing in dollars, so Total announced that it would seek loans in other currencies, to advance the project. Funding may have to come from China or the Russian government. Technip—the project’s EPC—also may face bans on importing gas-cooling equipment from Western companies, so liquefaction technology from China may have to be substituted, to keep construction on schedule. Novatek expects the Yamal plant to begin exports in 2018, to buyers in Europe and Asia, with the goal of eventually exporting 800 Bcf of LNG per year (16.5 Mtpa).
U.S. ARCTIC
While no activists have been arrested for piracy in Alaska, environmental concerns have constrained exploration and development in U.S. Arctic waters. On Sept. 17, Arctic sea ice reached its minimum coverage for the year, the sixth lowest area since satellite observation began in 1979. The disappearing ice created an emergency for 35,000 walruses that came ashore from the Chukchi Sea, near the village of Point Lay in northwestern Alaska. The areas of walrus foraging coincide with lease blocks administered by the Bureau of Ocean Energy Management (BOEM), and the massing walruses were cited by environmental activists as another reason to stop exploration.
For decades, Arctic operating companies have taken many steps to protect wildlife and their habitats. Alaskan operators have sponsored long-term environmental studies of wildlife, and the condition of the permafrost. Extensive efforts to assure safety and environmental protection during E&P activities include: conducting seismic surveys with solid streamers, or on ice, to minimize the impact on whales; modifying drilling equipment to operate at extreme temperatures and withstand the pressures of floating ice; redundant well control equipment and procedures; and ice monitoring programs involving satellites, radar, computer simulation, on-vessel observers, icebreakers and ice-class spill response vessels.
North Slope. Alaska’s North Slope has been the most prolific energy development in the Arctic, with more than 17 Bbbl of oil produced since 1977 (equal to roughly half of today’s entire U.S. oil reserve figure). There are around 1,500 wells producing about 548,000 boed from Prudhoe Bay, Kuparuk and Milne Point fields. All crude oil and condensate is transported by the Trans Alaska Pipeline System (TAPS), 800 mi south to the Valdez Marine Terminal.
North Slope production has been declining for the past 26 years, and it is now falling at a rate of 5% per annum. The 48-in. Alyeska Pipeline reached peak flow in 1988, with more than 2 MMbopd of North Slope production transported. Now, at about a quarter of these peak levels, the oil flows more slowly through the pipeline and cools more quickly. In 1988, oil took four days to traverse the pipeline from Prudhoe to Valdez, and reached its destination at 120°F. In 2014, transit through the pipeline takes 18 days, and the arriving crude can have a temperature as low as 32°F, Fig. 2.
 |
| Fig. 2. The 48-in. Alyeska Pipeline reached peak flow in 1988 with more than 2 MMbopd of North Slope production. Now, with about a quarter of these peak levels, the oil flows more slowly through the pipeline and cools more quickly ( chart courtesy of Alyeska Pipeline Service Company). |
|
As an interim solution, the Alyeska Pipeline Service Company has added additional heaters, at four points along the line, to forestall freezing; it also has increased the frequency of pigging, to remove wax buildup. The pipeline operators are developing a “cold dry flow” option, with improved oil/water separation before the crude enters the pipeline.
North Slope operators also are investing in projects to increase production and flow through the pipeline. Output from Prudhoe Bay field, alone, has exceeded 12 Bbbl, surpassing estimates from the 1960s that the field held just 9.6 Bbbl of recoverable oil.
North Slope operators have been leaders in applying directional, horizontal and extended-reach drilling, multi-lateral completions and coiled tubing, and drilling using hybrid rigs. BP also has tested multi-stage hydraulic fracturing to enhance production from the Sag River reservoir in Prudhoe Bay, with at least two test wells completed and under evaluation. North Slope operators have developed fields using gravel islands, including Endicott field in the Beaufort Sea, which operates efficiently with a reduced footprint, compared to onshore fields, and Northstar Island in Prudhoe Bay, whose 15 wells have been producing for 13 years.
More viscous oil. The North Slope was developed, based on light oil production, but it also has substantial reserves of more viscous crude. BP plans to invest more than $1 billion to develop more viscous reserves and modify infrastructure to handle them. At Milne Point, which produces 17,000 bpd of light oil from 116 wells, BP conducted a heavy oil pilot project to test the Ugnu deposit, estimated to have 18 MMbbl of oil-in-place, of which only 10% may be recoverable. Two horizontal wells, completed using the cold, heavy oil production with sand (CHOPS) method, each produced more than 500 bopd for extended periods, delivering more than 100,000 bbl to TAPS. BP is evaluating results for commercial development.
BP also is evaluating options for developing Liberty field in the Beaufort Sea. The discovery well, drilled in 1997, identified 100 MMbbl of recoverable oil. The operator is considering production from a gravel island, connected to shore by a subsea pipeline. BP plans to submit a Development Plan of Production to BOEM by the end of 2014.
North Slope gas. About 8 Bcfgd is produced from the North Slope and reinjected to maintain reservoir pressure. Aside from NGLs transported through TAPS, there is no means to bring North Slope gas to market. In February 2013, BP, Exxon, Conoco Phillips and TransCanada agreed to combine efforts on a feasibility study for an LNG export facility, the Alaska Major Gas Sales/LNG project. If commercially viable, the project could start up sometime after 2023.
Exxon’s Point Thomson field—on the shore of the Beaufort Sea, 60 mi east of Prudhoe Bay—holds an estimated 8 Tcfg and associated liquids, or about 25% of the gas reserves on the North Slope. Point Thomson is an important element of the Alaska Major Gas Sales initiative. The Point Thomson Initial Production System, now under construction, involves drilling the first three extended-reach wells to develop offshore reservoirs from land, and it is expected to produce 10,000 bcpd for delivery through a newly constructed, 22-mi connector pipeline to TAPS. The NGLs will be separated from dry gas, and re-injected into the reservoir. Initial production is expected in 2016.
Beaufort and Chukchi Seas. Since 2012, Shell has spent an estimated $6 billion exploring in the Beaufort and Chukchi Seas. Shell completed top-hole drilling on two wells in 2012, in the Beaufort and Chukchi Seas, marking the industry’s return to offshore drilling in the Alaskan Arctic after more than a decade. Drilling was cut short in the Chukchi Sea after a 360-sq-mi ice mass came within 5 mi of the rig. After the drilling season, Shell’s Kulluk rig ran aground in a storm while being towed south for repairs; it subsequently was sold for scrap.
A second rig, the Noble Discoverer, which worked for Shell in its 2012 Arctic campaign, had been boarded by Greenpeace activists, in New Zealand, during February of that year, while it was drilling a well before moving to Alaska. During the 2012 drilling program, the rig subsequently had mechanical and air quality problems, and was sent to South Korea for repairs.
In July 2014, Shell submitted plans to BOEM for the 2015 season that call for two rigs to be drilling simultaneously in the Chukchi Sea. Shell’s plans, and its application for permits to drill, are under review by federal regulators. Shell had contracted Transocean’s Polar Pioneer for its cancelled 2014 drilling campaign. If BOEM approves the plans, and the Polar Pioneer is available, the semisubmersible would be likely to avoid the problems encountered by the older rigs that Shell employed during 2012.
In September 2014, Shell and ConocoPhillips asked regulators to scale back spill response requirements, including deployment of a spare rig on standby to drill a relief well; having enough containment booms for a worst-case spill; and prohibiting use of surfactants to disperse some of the spilled crude. Meanwhile, environmental advocates continue to protest any oil and gas development in U.S. Arctic waters, and federal lawsuits are pending.
ICE CLASS ASSETS
One constraint on development in the offshore Arctic is the limited number of ice class-rated drillships and floating units capable of operating in areas with sea ice. The American Bureau of Shipping (ABS) conducts programs with the Memorial University of Newfoundland in St. John’s, to study ice, its movement, and its effect on vessels and drillships, as well as ice management techniques. ABS also classes vessels for all types of service, including working in sub-Arctic, Arctic and Polar regions. To date, ABS has classed only six drillships and two floating structures, still in service, as ice-class vessels.
“Each ice-class drillship needs a fleet of icebreakers and ice-capable support vessels,” said James Bond, director of shared technology at ABS,” and there aren’t that many assets available. Vessels built for warmer-weather service aren’t easy to upgrade. The cold environment of the Arctic has special steel requirements that have to be built into the hull. Weatherization is important, too, for all aspects of operation, and that requires modified equipment, as well as the right procedures and training. It’s no small task.”
ARCTIC NORWAY
The Norwegian Barents Sea, where Statoil has drilled more than 100 exploration wells since 1980, is considered the “workable Arctic,” because it is warmed by the Gulf Stream and seldom has sea ice.
Statoil’s Snøhvit, the first offshore development in the Barents Sea, was discovered in 1984 and comprises three fields in 1,000 ft of water, 87 mi northwest of Hammerfest. Development began in 2004, and production started in 2007 from two fields, with the third to come on-line in 2015. The Snøhvit project is the first major development on the NCS without a fixed or floating production unit. All producing wells have subsea wellheads and are tied back to a plant at Melkøya that separates natural gas from CO2 in the production stream; the CO2 is sent back to the offshore field via a separate pipeline, for reinjection into a sandstone formation at 8,350 ft. Once Snøhvit reaches full production, this carbon capture project will reduce CO2 emissions by 700,000 t/year.
Goliat oil and gas field, operated by Eni Norge, 53 mi northeast of Hammerfest, is being developed according to a plan that calls for 22 wells, drilled from eight templates, and connected to a circular fixed floating production and storage facility. Oil will be transported to shore by tanker, and produced water and associated gas will be reinjected. Production from Goliat is expected in third-quarter 2015.
Statoil made the Aasta Hansteen gas discovery in 1997, in 4,625 ft of water in the Vøring area, 186 mi from land. The field’s estimated recoverable volume of gas is 1.7 Tcf, and it is expected to eventually produce 130,000 boed with start-up in 2017. Development drilling will commence in 2016; it will produce to a spar designed by Technip.
2014 exploration campaign. Explorers in the Norwegian Arctic have had mixed results in recent drilling campaigns. In the Hoop area, 186 mi north of Hammerfest, OMV made the Wisting Central oil discovery in 2013, followed by the Hanssen find in 2014, identifying potential reserves of 200 MMboe to 400 MMboe, Fig. 3.
 |
| Fig. 3. Hoop-area wells in the Norwegian Barents Sea. OMV struck the Wisting Central oil discovery in 2013, followed by the Hanssen find in 2014. Of Statoil’s three Hoop-area wells, Apollo and Atlantis were dry holes, while Mercury hit only a small gas discovery (map courtesy of Statoil ). |
|
Statoil’s results in the Arctic have been disappointing this year. Of Statoil’s three Hoop area wells—drilled to the north of Wisting Central—Apollo and Atlantis were dry holes, while Mercury made only a small gas discovery. In May, the Transocean Spitsbergen was boarded by Greenspeace activists, as the rig was enroute to begin the Hoop area exploration program. No one was hurt during the protest, and, after legal action, the Norwegian government allowed drilling to proceed.
Statoil’s Pingvin prospect well, drilled near the Johan Castberg and Havis discoveries of 2011-2012, made a small oil discovery. So far, insufficient hydrocarbons have been found in the area to justify investing in the infrastructure to bring production to shore.
“We are naturally disappointed with the results of this summer’s drilling campaign in the Hoop area,” said Irene Rummelhoff, Statoil senior V.P. for exploration on the Norwegian Continental Shelf. “However, it is important to understand that Hoop is a frontier area of more than 15,000 km2, with only six wells completed to date,” Rummelhoff said. “We know from experience that exploring for hydrocarbons in the Barents Sea takes time and stamina.”
OIL AND GAS PRICES
Arctic E&P is expensive, and the economic viability of projects there depends on sustained, high commodity prices. The surge in North American oil and gas production, with the prospect of crude and LNG exports, contrasted with sluggish economies in Europe and China, has put downward pressure on oil and gas prices. If these trends continue, many of the projects described in this article may be delayed or shelved. However, the region has huge potential, and it is of great, long-term importance to the economies of the Arctic nations and the world. It may take decades, but the technical, political and environmental challenges of developing Arctic oil and gas resources are likely to be overcome. 
|
