Royal Dutch Shell’s efforts to drill for offshore oil in the Arctic, one of the harshest environments on Earth, have so far been a lesson in humility. Last season’s drilling program was marred by numerous delays, equipment failures and a towing mishap that left the company’s $290-million Kulluk drill rig grounded off the coast of Alaska during a fierce storm.
The oil giant’s $5-billion Arctic program was unceremoniously suspended in February before a single offshore well was completed (Shell had planned to drill as many as 10 wells in the Chukchi and Beaufort seas over the next few years, but was only able to start two). Adding insult to injury, Shell was publicly criticized by the U.S. Department of the Interior, which demanded a detailed plan to address issues ranging from logistics to oversight of contractors before any further drilling would be allowed to go ahead. “Shell screwed up in 2012,” Ken Salazar, the recently resigned Secretary of the Interior, was quoted as saying. Undeterred, Shell recently signed a memorandum with Russia’s Gazprom that includes offshore exploration in Russia’s Arctic shelf.
With an estimated 30 per cent of the world’s undiscovered natural gas and 13 per cent of its undiscovered oil, the Arctic, and Shell’s struggles there, highlight both the risks and rewards oil companies face in a world where most easy-to-access hydrocarbons have already been tapped. But some of the dangers could soon be ameliorated as the industry races to minimize the use of vulnerable floating platforms, and focuses instead on equipment that can be bolted directly to the sea floor, where it’s relatively protected from ice and violent weather. “Our vision of the future is that a lot of things you now see on platforms and oil rigs can be moved to the sea floor—the processing, separation and boosting,” says Patrick Kimball, a spokesperson for Houston-based FMC Technologies, one of several oil-services companies leading the charge into the deep. “When there’s ice covering the surface six months of the year, this approach offers advantages because everything’s on the sea floor and monitored with remotely operated vehicles,” Kimball says.
It’s an intriguing vision of the future, and one that also promises to be more cost effective. But it also raises some questions about the safety of all that remote equipment. BP’s disastrous underwater spill in the Gulf of Mexico three years ago took months to bring under control, and much longer to clean up. Responding to a similar catastrophe in the ice-choked Arctic, some fear, could prove to be well beyond the industry’s grasp.
Subsea technology is already in use, to varying degrees, around the world. A study last year by market research firm ASDReports estimated that spending on subsea production and processing systems infrastructure hit $9 billion in 2012. Other firms have estimated that total spending on subsea equipment will reach $139 billion by 2015.
To date, the main driver for moving equipment to the sea floor has been economic. In some cases, multiple wells are tied to a single surface vessel called a floating production, storage and off-loading unit, which looks like a cross between a freighter and an oil rig. More advanced operations deposit building-sized, yellow machinery on the bottom to separate oil and gas from seawater and sand, rather than pumping it all to the surface. Other machines process hydrocarbons so they’re easier to transport through pipelines. Among the first such operations was one implemented by Norwegian oil company Statoil in its North Sea Tordis field. Similar technologies are also being employed off the west coast of Africa, the coast of Brazil, as well as in the Gulf of Mexico.
The next piece of the puzzle, being worked on by both Statoil and Shell, is adding a subsea compressor to help boost production from deep-water wells, which tend to yield about 25 per cent less than surface wells because of the challenges associated with extracting oil and gas thousands of metres below the waves. Shell is currently testing a massive compressor in a water-filled pit in Norway that it intends to use for its Ormen Lange deepwater project in the Norwegian Sea. “Platforms will not become obsolete,” Mathias Owe, Shell’s manager for the project, recently told Reuters. “But for new developments, if they can be reached from shore, subsea will be a good challenger, particularly in harsh environments like the Arctic.”
How, exactly, the technology will be employed depends on the situation at hand. David Williams, a spokesperson for Shell Canada, says every oil field is different and therefore eschews a one-size-fits-all approach. “It depends on what you find to some extent,” he says. “You take into account the distance from the shore, whether it’s mainly gas or mainly oil and how the economics will work.”
With fewer floating rigs to be swamped by storms and fewer people working on platforms to be injured by malfunctioning equipment, the industry touts subsea technology as being safer than traditional offshore production methods. But building an oil factory on the sea floor carries significant risks of its own. Most subsea fields are so deep humans can’t visit them safely—even in submarines. All the installation and maintenance work is done by remotely operated vehicles swimming in near-freezing temperatures and total darkness. Kimball is among the first to admit that the design and engineering challenges are incredibly complex. “It has to be very sturdy because there’s tremendous pressures down there, both from the ocean and the pressure of the reservoir,” he says. “And you have to balance those forces in a salt-water environment that’s corrosive.” He compares subsea equipment to that used to explore outer space when it comes to safety and reliability—namely because the cost of failure is so high. “When they downsized the shuttle program here in Houston, we hired a bunch of quality engineers from NASA.”
If an accident does happen, particularly in the Arctic, authorities want to be sure oil companies will be capable of cleaning it up. As part of the approval process for its U.S. Arctic drilling program, Shell was required to deploy a containment dome that could be used to collect hydrocarbons in the event of a blowout like the one BP suffered at its Macondo well in the Gulf of Mexico. A hose connected to the dome would deliver the oil and gas to a surface vessel where it could be collected or flared off. But things didn’t go smoothly. Shell faced difficulties getting its oil-spill-response ship certified, and a test of the dome in Puget Sound in September was plagued with problems, including a remotely controlled submersible that became tangled in rigging and a malfunction that caused the dome to submerge so fast it crumpled like a beer can.
Despite the setbacks, Shell remains upbeat about its Arctic prospects even as one of its rivals, ConocoPhillips, recently suspended its own Arctic program, citing uncertainty over federal regulations. “I think we took some important steps in 2012,” Williams says. “We got our program under way and we completed the drilling part of the exploration safely after looking at it for many years.” It remains to be seen, however, whether those early steps can be followed up with working subsea wells and a safe, reliable system to process and transport the oil and gas they produce—either above the waves or below.