It has been more than 40 years since the first oil was produced in the offshore Arctic, and such are the enormity of the hurdles faced when working in the area that very little has developed since then. Harsh climatic conditions, ice, darkness, vast distances from support and distribution, high costs, and a lack of technology and experience all add up to what is one of the 21st century’s greatest technological challenges when it comes to recovering the world’s last oil and gas reserves.
While such challenges are severe, for some Arctic areas they are not insurmountable. Statoil, Norway’s largest energy company, has been present in the region for more than 30 years, mostly in the southern Barents Sea. According to Rúni M Hansen, vice-president of the Arctic unit, the key to any successful E&P activities in the area is a cautious, long-term approach.
"We work on a step-by-step basis," he says. "We do not move faster than the technology available. It is not a sprint; it is a marathon, and we are in no rush."
As Hansen explains, when building an Arctic ‘technology road map’, Statoil divides the area into three zones:
- Workable: The northern Norwegian Sea, the southern Barents Sea and east coast Canada, for example, where, although conditions are cold and harsh, there is little or no ice. Here, technological solutions are based on known technology and any needs are within reach in the short to medium term.
- Stretch: The north-east Barents Sea, for example, where there is seasonal ice. Here, technology requires major innovation and is achievable within the medium to long term.
- Extreme: Areas such as north-east Greenland, where there is almost year-round heavy ice and a short open season. Technology is hard to visualise, and requires a long-term focus and investment.
"We are operating in the workable Arctic, mainly the Barents Sea, where we have drilled over 100 wells," explains Hansen. "In the stretch Arctic, we can see a future, one that requires more investment. However, in the extreme Arctic, it’s hard to see any production taking place within the next 20 years."
Statoil’s pioneering offshore development in the Barents Sea is Snøhvit, which was discovered in 1984 and came onstream in 2007. Lying 150km north-west of Hammerfest, it includes the Snøhvit, Askeladd and Albatross wells, which together produce 5.75 billion cubic metres of liquid natural gas a year. Although the field lies 70° north with freezing temperatures and turbulent seas, it is operational throughout the year thanks to the warm current of the Gulf Stream and technology created especially for the Norwegian Continental Shelf (NCS).
Statoil is one of the leading subsea operators. One of Snøhvit’s key features is that the whole installation lies under the sea’s surface, at depths of 250-345m. The facilities are controlled remotely onshore, so few staff are required to work at the installation, and it is overtrawlable, so no fishing equipment can be damaged. As well as this, instead of using tankers to take the gas to its destination, once extracted, it is transported through a 143km multiphase subsea pipeline, the world’s longest, to Hammerfest.
"Logistics are very important, especially in ice-prone areas," says Hansen. "Using such a long pipeline is difficult and depends on the installation."
Indeed, the Snøhvit pipeline posed several challenges; for example, due to the high pressure and low temperature on the seabed, the pipe is at risk of the formation of ice plugs. However, this has been avoided by adding antifreeze at the wellheads and by heating the pipeline electrically.
Slowly moving north
Although the oil and gas industry has been present in the offshore Arctic since the 1970s, it’s still early days when it comes to extracting oil and gas there. While most of Statoil’s work is in the southern Barents Sea, the firm is exploring further north.
"It takes time and investment to plan and develop an installation no matter where it is, but in the Arctic, it takes even longer," says Hansen. "We will not go to a place where we don’t have the technology to cope with the conditions. First, we need to clarify an area’s energy potential and then work out its future development."
Towards the end of 2014, the energy major completed an extensive exploration programme in the Barents Sea. The venture began by drilling five wells within the vicinity of the Johan Castberg field, 100km north of Snøhvit. But while the campaign uncovered fewer commercial discoveries than was originally hoped for, the drillers were able to test a variety of geological plays and collect new seismic data, while also proving that the company could operate safely and efficiently in the area.
"The Barents Sea exploration programme was a significant building block for the future of exploration in the Arctic," says Hansen. "Some of the results were disappointing, but we proved more volumes and conducted important seismic surveys. We are still evaluating the extensive data we collected; from this, we will decide on the way forward."
The discoveries were drilled using Seadrill’s West Hercules and Transocean’s Spitsbergen rigs, which had been ‘winterised’ to cope with the sub-Arctic conditions. But to drill in less hospitable regions outside the temperate summer months would require tailor-made rigs.
"In the Arctic, our needs for now are in the workable Barents Sea, and ‘normal’ rigs like West Hercules suit this environment," explains Hansen. "But going into more ice-prone areas requires a specially designed rig that can be operated in harsh weather and in darkness, ensuring ease for people working in a cold environment."
As part of its technology strategy, Statoil had been looking into developing such apparatus – the Cat I project, a floating rig that would operate in a range of water depths and have integrated operations in drifting ice. Functions would include a management system to reduce ice impact, optimised drilling, increased rig availability and dynamic positioning. However, the project was postponed in 2014 due to other priorities within the firm.
The exploration programme also went further into the Hoop area, which, at over 300km from shore, is the northernmost area that has been drilled on the NCS. Three wells were drilled, and again, while small discoveries were made, it is the seismic data retrieved that will prove invaluable when it comes to developing logistical and operational solutions, and creating an ice-management strategy.
"Ice management is crucial for Arctic activities, and again, we rely on our experience and our step-by-step approach when planning ahead," says Hansen. "We were in Greenland and Newfoundland 15 years ago, where here is drifting ice. There, we learnt how important it is to have a system for how to handle drifting ice.
"We have also been collaborating with universities and institutions on ice monitoring and management to see how ice behaves in different places."
All heads together
Working with others is a factor that Statoil considers crucial to the future of energy recovery in the Arctic, especially when it comes to the environment’s sensitivity to industry operations and potential oil spills. The company employs several environmental monitoring methods at its NCS installations.
"Studies are carried out in each zone every three years," explains Knut Rostad, Statoil’s press spokesperson. "This includes analysis of marine life, water and sediment using visual monitoring and sonar technology. But while these reports provide information about the environmental conditions, they do not allow us as operators to initiate measures at an early stage should there be any detrimental emissions."
So, in 2011, Statoil embarked upon a project with a consortium comprising Kongsberg Oil & Gas, Det Norske Veritas and IBM to create an integrated environmental monitoring system that can be used as part of its daily operations.
The system uses sensor technology, such as cameras, acoustics and sniffers, to detect and gauge emissions, chemical or otherwise, from the installation into the sea. The sensors can be placed on the seabed – before, during and after a seabed operation – and will provide status reports on the environmental conditions.
"The system will become increasingly relevant as an increasing share of production takes place subsea and in areas at vast distances from any infrastructure," says Rostad. "It will allow us to stop operations when the environment is extra sensitive – such as when fish are spawning, for example."
Among its efforts to reduce its environmental footprint, Statoil is a sponsor of the Arctic Oil Spill Response Technology Joint Industry Programme, which was formed to improve oil spill response capabilities. But what has become clear is that to make any significant progress in the Arctic requires working with others – whether that be with other energy companies, academia or local communities.
"No one can survive in the Arctic alone," says Hansen. "Collaboration is key in developing equipment, knowledge and technology. The industry is good at pulling together for the good of all of us, as with the joint industry programme, but working with local communities is a necessary relationship."
Much of Statoil’s Arctic workforce comprises locals, whose extensive knowledge of the area is proving invaluable. In many cases, the firm has agreements with the governments for the use of lifeboat organisations and state-run units as part of its emergency response plans, as well as for help in clearing up any spills. But it is not a one-way relationship.
"We recognise the value of building local competence," Hansen explains. "I am from the Faroe Islands, so I understand the effect our industry has on these communities. Many people depend on fishing as a livelihood but would like another trade that doesn’t fluctuate so much.
"In Hammerfest, there has been a lot of development, and the population is increasing, which is a positive spin-off. All parties get something out of it – together, we can go further."
