Will subsea tech join fracking slowdown? There may be too much momentum. Bruce Nichols reports.
Testing for Train 2 of the Asgard subsea compression system was completed in December at Aker Solutions’ dockside yard in Egersund, Norway. It was then moved to a disassembly area for transportation to the offshore installation site.
Subsea oil and gas processing technology takes a big step forward this year when Statoil starts up gas compression systems at Åsgard and Gullfaks, shifting this major component of offshore production from the platform to the seafloor for the first time.
But with oil prices down more than 50% since mid-2014, there is concern further technological advances could slow as leaner cash flows and shrunken capital spending heighten operators’ already conservative approach to risk.
There are reasons for optimism. Deepwater projects are different from onshore shale projects. Onshore shale has a short timeline and already is feeling the effects of lower prices. Deepwater projects are long term, take years to unfold and will be slower to react.
There are so many projects already sanctioned and underway in the Gulf of Mexico, off Brazil and West Africa, that analysts see momentum carrying development forward into a time when oil prices likely will be higher.
“Because of sunk capital, the point-forward breakeven oil prices for these projects is lower, meaning that 2015 and 2016 prices will have short-lived impacts on the commercialization of these fields and will be offset over time as oil price recovers,” says Wood Mackenzie analyst Jackson Sandeen.
Douglas-Westwood also expects a short-lived oil price downturn. The energy research firm sees subsea CAPEX exceeding US$30 billion in 2015, dipping a bit over the next three years, but rising again in 2019 past $35 billion, Houston director Mike Haney told a recent energy industry luncheon.
“Our view is that the oil supply will need to be there, and producers have less spare capacity (than in past downturns),” Haney said.
Even if oil prices don’t return to the loftiest levels, further development of subsea processing – compression, power delivery, pumping and separation – could improve deepwater economics by boosting recovery, lowering per barrel lifting cost and easing the need for expensive offshore platforms.
Compression projects advance
In the area of compression, optimism is high that the Aker-MAN dry-gas compression system at Åsgard and the OneSubsea multiphase wet gas compression system at Gullfaks will succeed. Statoil expects the systems to increase ultimate recovery at Åsgard by 280 MMboe and at Gullfaks by 22 MMboe.
“There’s no reason why it won’t work, but we’re all waiting for it to start up,” said Global Technology Director Phil Cooper of INTECSEA.
The Åsgard system, sitting in 1050ft of water, 125mi off Trondheim, is big. It has two 11.5 megawatt (MW) compressors in a football field-size, 5000-tonne frame that contains separators and two 736-kilowatt (kw) condensate pumps. It will be powered through 25mi of subsea cable from the Asgard B platform. Current cost estimate: $2.3 billion.
“Aker Solutions will deliver advanced subsea processing solutions this year through the Åsgard Subsea Compression project. This represents ground breaking technology that brings us closer to placing a fully-functioning production and processing system on the seafloor. The project is to be delivered in 2015 with testing and final preparations already underway. The Åsgard project is an industrial game-changer that has the potential to significantly impact the subsea production market. We expect to further develop the technology to reduce costs by using more standardized tools and optimized module designs,” said acting Head of Technology at Aker Solutions, Hervé Valla.
FMC Technologies has teamed with Sulzer to compete in subsea boosting. Their new 3.2-mw, 5000-psi helico-axial Sulzer pump, driven by an FMC Technologies permanent magnet motor, is shown in Sulzer’s Leeds, England, test facility.
Gullfaks, in 455ft of water, 125mi off Norway northwest of Bergen, is smaller in scale. It has two 5MW multiphase compressors in a structure 112ft-long, 65ft-wide and 45ft-high and weighs 950-tonne. It will be powered by subsea cable from Gullfaks C about 9mi away. Current cost estimate: $385 million.
Unlike Åsgard, Gullfaks doesn’t remove liquids from the gas stream prior to compression, so it’s simpler. In a sense, Åsgard’s system is a compressor built around a separator, and Gullfaks’ is a multiphase pump bulked up to do compression.
A third Norwegian compression project, Shell’s Ormen Lange, has been canceled, at least for now, due to unfavorable economics. But in design and testing, it took subsea compression a step further.
The Ormen Lange concept had four 12.5MW compressors in 2825ft, powered by 75mi of subsea cable from shore. The Aker-GE built compression pilot system was proven in extensive submerged trials at an onshore facility.
Ormen Lange was to be an important advance in subsea power distribution, an area still in its infancy. For the first time, it would have put a variable speed drive on the sea floor along with a switchgear.
Power transmission, hubs next?
A lot of effort is going into improving power delivery and distribution, developing longer distance transmission capability and seafloor hubs that can distribute power to numerous pieces of equipment. Statoil sees better electrical systems as key to its subsea “factory” concept.
In 2013, Statoil teamed with ABB on a five-year, $100 million project aimed at delivering 100MW through a 375mi cable in water 10,000ft deep. Such a system eventually could be needed in ultra-deep and remote locations, including the Arctic.
Siemens also is running a subsea power qualification program for an ultra-deepwater subsea grid. Other companies, including GE and Schneider Electric, are working on the power challenge.
Issues include that most existing subsea equipment run on alternating current (AC), and there are limits how far AC can be cabled subsea. “You may lose 35% of your power over 100mi,” said James Pappas, president of RPSEA, the Research Partnership to Secure Energy for America.
“After 120mi, it becomes obvious that direct current (DC) is the better way to go,” Pappas said, “But, we do not have any qualified high-voltage wet-mate connectors for DC.”
Others say don’t give up on AC power too soon. ABB points to low-frequency AC, used in railways, as offering potential for longer subsea step-outs than standard AC.
Even at 120mi or less, there are a lot of subsea projects within AC reach, so AC systems should be fully developed before shifting major resources to perfecting subsea DC, said Alisdair McDonald, who heads GE’s power and processing team.
“I think it (DC) is potentially for the future, but we don’t see any business cases today where you’d require that type of system,” McDonald said.
Boosting leads the way
The subsea processing technology farthest advanced is boosting. OneSubsea is the leader with more than 20 years experience and 85 units sold for over 30 projects globally. OneSubsea absorbed subsea pump pioneer Framo Engineering when the organization was formed in 2013 by Schlumberger and Cameron.
ABB delivered this subsea transformer, rated at 19MVA (Megavolt-ampere), for the Åsgard subsea gas compression project offshore of Norway. ABB and others are working to advance subsea power transmission and distribution technology.
Subsea multiphase boosting began in 1993 with the installation of a system at Shell’s Draugen field in 900ft water depth in the Norwegian Sea. A second system was delivered in 2014, featuring two pumps, 2300 kw of power and a design pressure of 3190 pounds per square inch (psi).
OneSubsea’s latest boosting system, operating at Chevron’s Jack-St. Malo project in 7000ft in the Gulf of Mexico, uses a bit more power, 3000 kw, but has four times the shut-in pressure, 13,000 psi.
FMC Technologies, which often teamed with Framo Engineering before it became part of OneSubsea, has now joined Sulzer to challenge OneSubsea’s dominance in boosting.
The team is offering a new 3.2MW, 5000psi helico-axial Sulzer pump driven by an FMC Technologies permanent magnet motor. The motor features a fluid gap in the rotor-stator assembly, reducing friction and increasing efficiency.
Progress in oil-gas-water separation
Subsea separation has less of a track record than boosting, but FMC Technologies is the leader, having installed five of the last six major systems, often using pumps now sold under the OneSubsea brand.
The history of subsea separation goes all the way back to 1969 when an early version was installed by BP and Total in 79ft at the Zakum Field in the Arabian Gulf, but the major advances have come since 2000.
In 2001, an oil-water separation built by ABB was installed in 1116ft water depth at Statoil’s Troll field. Also in 2001, Petrobras started up a gas-liquid system in 1296ft at Petrobras’ Marimba field using a Cameron vertical annular separation and pumping system.
Arguably, the first full-scale system for separating oil, gas and water, with sand-handling capability, was a gravity-based horizontal vessel system built by FMC Technologies and installed in 2007 at Statoil’s Tordis field at a depth of 689ft.
The next big advance was Shell’s Perdido project at 8000ft in the Gulf of Mexico. Since 2011, it has run a caisson-based system, built by FMC Technologies, using submersible pumps from Baker Hughes. Shell put another FMC Technologies caisson system at Parque das Conchas off Brazil, started up in 2013.
Total installed a vertical gravity-based system built by FMC Technologies at Pazflor in 2625ft offshore Angola. It started operation in 2011 and is notable for vessels 30ft tall and 11.5ft in.-diameter with 4in-thick walls to withstand the pressure.
What some consider the most advanced subsea separation system began operation in 2011 at Petrobras’ Marlim project in 2950ft. The horizontal, in-line, cyclonic system built by FMC Technologies avoids the need for big gravity vessels.
“The next frontier is making these systems more compact, more cost-effective and easier to deploy,” said FMC Technologies spokesman Patrick Kimball.
The technologies needed are available or within reach, said Ian Ball, director of Subsea Domain, a consultancy. “It’s more of an awareness and confidence-boosting that’s required,” he said.
“We need to find a way to get more operators to qualify and deploy currently proven technologies to boost their bottom-line. Only by doing that will we get the volume of systems manufacturing and installation to bring down unit costs to where subsea processing becomes commonplace,” he said.
Jon Arve Svaeren, vice president of subsea processing systems at OneSubsea, agrees. “Used in the appropriate situations and applied correctly, this technology has proven a very effective tool for increasing production and recovery, reducing lifting costs per barrel, and that’s important in today’s environment of softening oil prices,” Svaeren said.