* Alaskan oilfields may produce without platforms in a decade
* All subsea solutions cost less to operate and produce more
* Oil firms still reluctant as technology untested
* Statoil, Shell at forefront of drive
By Balazs Koranyi
OSLO, Jan 7 (Reuters) - Lying at the bottom of a giant water-filled pit in western Norway, a thousand-tonne gas compressor is humming along, going through gruelling tests as engineers prepare it to change oil and gas production for good.
The compressor, a prototype for Royal Dutch Shell’s massive Ormen Lange natural gas field in the Norwegian Sea, will help make platform-free offshore production, the Holy Grail for oil firms, a reality within a decade.
The new technology will have particular meaning for places such as Alaska, where the grounding of Shell’s Kulluk rig on New Year’s Eve stirred opposition to rigs in environmentally delicate and technologically challenging places.
Oil companies have steadily moved offshore equipment to the bottom of the seabed, away from ice and storms, because it squeezes more out of fields, costs less to operate and eliminates much of the risk associated with rigs.
But oil firms still need to overcome a few hurdles before they can put everything on the sea bed and several companies are racing to find a solution within a decade.
“By the time the real Arctic fields in the ice-infested waters of Alaska and Siberia are ready for development, the technology will be there for platform-free production,” says Tore Halvorsen, the subsea chief of FMC Technologies.
“The game changer is to have fluid extracted, processed and directly exported from the field without intervention from a platform... We’re not far from that.”
The International Energy Agency estimates that of the 2,700 billion barrels of recoverable oil left, 45 percent are offshore and that energy firms will gradually move to deeper waters as reservoirs in shallow waters get depleted.
It predicts that by 2035, deep-sea production will almost double to 8.7 million barrels a day, driven by developments in the U.S. part of the Gulf of Mexico, Brazil, and West Africa.
Demand is so high that Quest Offshore, a consulting firm, predicts that orders for subsea trees, complex equipment attached to wells and considered an industry-wide demand indicator, will rise by 23 percent a year through 2015.
Investors have also taken notice, rewarding some firms with share price rises. Aker Solutions, a large oil services company, has been a clear winner with a 79-percent share-price increase over the past 12 months.
Shares of Subsea 7, a construction firm, are up 24 percent over the same period while Technip has risen 19 percent and Cameron is up 16 percent. FMC, valued well above its competitors, is down 16 percent.
Pushing the limits of subsea innovation, Shell and Norway’s Statoil are now racing to build the world’s first subsea gas compression unit, a key building block in the “subsea factory,” which would all but eliminate the need for many platforms.
Statoil has already committed to subsea compression at its Aasgard field by 2015 but the unit will receive power from a nearby platform.
However, Shell’s Ormen Lange, 120 kilometres out to sea, would get its power from the shore so it could become the world’s first field with complex processing and compression done on the sea floor and no support platform.
Compressors on the sea bed are closer to the reservoir and already under immense pressure from the water, so they need less power to take out more oil and gas.
“This means you’re squeezing out more, an extra 5-10 percent, possibly more or less, depending on the specifics,” says Alan Brunnen, the subsea chief of Aker Solutions, which is working with both Shell and Statoil on subsea compression.
“And compared to having a semi-submersible platform in deepwater, there is a saving somewhere between 20 and 50 percent on the capex, depending on how deep it is or how big the platform would be,” he added.
If the technology succeeds, Arctic developments could be the main beneficiaries.
The U.S. Geological Survey estimates that the Arctic holds 90 billion barrels of oil in reserves plus 47 trillion cubic metres of gas.
But its harsh environment makes production especially risky and politically sensitive.
Shell has already spent $4.5 billion preparing for extraction activities in the Alaskan Arctic but has yet to complete a single well as it struggles to overcome political, regulatory and technological hurdles.
“Subsea compression in the Arctic reduces the risk because you can operate under ice and you’re not dependent on operating the facility in a very difficult environment,” Statoil’s subsea chief Bjoern Kaare Viken said. “It means no people offshore, no helicopter flights, no vessels.”
Statoil already operates the Arctic Snoehvit natural gas field in Norway’s Arctic and it estimates that subsea compression at Aasgard, which beat out a platform solution, will squeeze out another 280 million barrels of oil equivalent.
“Platforms will not become obsolete but for new developments, if they can be reached from the shore, subsea will be a good challenger, particularly in harsh environments, like the Arctic or high risk areas where you don’t want people to operate,” said Mathias Owe, Shell’s manager for the Ormen Lange subsea compression project.
The biggest obstacle for subsea-only production is how to provide power to installations. Platforms usually generate their own electricity as getting power much further than a 100 kilometres distance from the shore becomes difficult.
Swiss engineering firm ABB is this year finishing a 106-kilometre 75-megawatt cable to Eni’s Goliat platform in the Arctic but subsea experts say the technology will soon be there to get power 500-600 kilometres offshore, a distance that would cover most of the Alaskan projects under consideration.
Another challenge is the difficulty in processing oil, because its property can change rapidly as it cools. This requires more complex equipment than gas and could take a few years longer to master.
And servicing equipment hundreds of miles from the shore, deep under water is a huge challenge, particularly in case of new technology without a long track record.
“Oil firms are a group of very conservative people who are all looking to be the second adapter of new technology,” Aker Solutions’ Brunnen said. “And the first time you put (all subsea systems) together, it will probably take twice as long and cost four times as much as you think.”
Still, the next step is what Statoil dubbed the subsea factory, finishing development of compression, the last big building block, then integrating them into one unit.
“We know they work one by one, wells, the manifolds, the oil boosting systems, the separations system, produce reinjection system, seawater injection system, compression, now we have to put it together,” Statoil’s Viken said.
“It’s not impossible but it has never been done,” he said. “Our plan is to install the subsea factory by 2020.”
Once the integration is complete, the technology can be standardized, eventually creating smaller and more portable modules that can be deployed more rapidly and on a smaller scale, allowing firms to develop fields previously considered too small to make a platform worth while.