Many years in the works, subsea gas compression technology made its commercial debut off Norway last year, first at Statoil’s Aasgard field and, just months later, in a system for wet gas compression at the Gullfaks development.
By placing the boosting equipment on the seabed, closer to the subsea wells, Statoil says it will be able to recover significantly more gas from its reservoirs. The technology also eliminates the need for major platform modifications to accommodate topsides compression modules.
The Shell-operated Ormen Lange field, also off Norway, was a strong contender to be the first subsea compression site. In 2006, the field partners, led at the time by Hydro, asked GE to supply subsea compression for the dry gas development, which ties back to an onshore processing plant at Nyhamna. In 2009, GE introduced the Blue-C subsea compression unit, a marinised, vertically oriented version of its gas compression technology. The unit, along with a subsea power distribution system, was installed in a test pit at Nyhamna in 2011.
In 2014, halfway into the four-year pilot programme, Shell and the Ormen Lange field partners, citing economic constraints, announced that a concept selection for offshore compression, either subsea or platform-based, would be postponed and other options considered.
“The Ormen Lange licence group believes in the subsea compression technology, and still regards the qualification of this technology to be an important stepping stone for the Ormen Lange future development alternatives,” the chairman of the project’s management committee, Odin Estensen, said at the time, adding that subsea compression technology “is a key contributor for ongoing and future field developments on the Norwegian continental shelf.”
KEY ELEMENT: A subsea variable speed drive (VSD) controls the speed of each individual compressor. Subsea VSDs for compressors and pumps were qualified and tested for Ormen Lange.
Test success
Ormen Lange lies 120 kilometres north-west of Kristiansund in water depths of 850 to 1100 metres (2800 to 3600 feet). Aasgard, by contrast, is in depths of 300 metres (990 feet) and lies 200 kilometres off the coast. The subsea compression system receives power from the Aasgard A platform 40 kilometres away.
“What was unique about Ormen Lange versus Aasgard was the step-out distance,” says Alisdair McDonald, head of subsea power and processing at GE Oil & Gas. “The gas compression station was to be about 120 kilometres offshore from the Nyhamna facility. Due to that step out distance, it wasn’t possible to have topsides variable speed drives, so the decision was made to investigate the potential for subsea power electronics.
“That’s where GE and the power conversion team collaborated with Shell and the licence to develop that technology,” he explains. “That gave us the possibility to put the compressor 120 kilometres from shore.”
The Ormen Lange pilot programme “had about 90%-plus GE technology”, McDonald says: the Blue-C, which he describes as “the world’s first specifically designed subsea centrifugal gas compressor”, along with a subsea power system that included variable speed drives (VSDs) and subsea switch gear.
“This was to be the world’s first subsea gas compression system with a subsea power supply, transmission and distribution system,” he says.
For the 12.5 megawatt Blue-C compressor used in the pilot programme, GE assembled a subsea power distribution system comprising a main subsea transformer, distribution switchgear unit, VSD transformer, compressor VSD unit, pump VSD, and a 145-kV version of the company’s MECON-DM connector developed specifically for the pilot.
“Because Ormen Lange is a 120-kilometre step-out, the most economical way of getting power there was to have a single cable supply multiple loads, and to increase the voltage level of that cable to ensure that you get enough power to meet all the needs of the compressors and the pump,” says Kristin Elgsaas, senior product manager for GE Oil & Gas’ subsea power business.
The subsea compression concept called for enough power to run up to four 12.5 MW compressor units and the pump, she says.
“This system allows you to transfer power in the range of 100 MW or more. We’re talking quite significant power levels.”
GE developed subsea switchgear technology — the system of electrical switches that may be used to disconnect power from electrical equipment — that transfers power from a single high-voltage cable to the individual compressors and VSDs in the compression system. An “uninterruptable” power supply, Elgsaas says, ensures that in the event of a power failure there would be enough energy stored locally to safely shut down the compressors.
While the electrical components tested at Nyhamna may not be used in a subsea gas compression system there, Elgsaas says the pilot paved the way for a range of future applications.
“With the Ormen Lange technology, we can actually pick the components we need to make short, medium and long stepouts. I think, in that sense, from a technology perspective it’s kind of generically applicable across the subsea power portfolio.”
The power supply equipment “was in (the pit) for years, and thousands and thousands of hours”, she says. “It performed very well and the results were what we wanted them to be.”
“Now that we have more confidence in subsea compression, we can look at simplifying our system design.” Alisdair McDonald, GE Oil & Gas
TEST SITE: GE conducted trials for the subsea compression and power distribution systems at the Shell-operated Ormen Lange gas processing plant in Nyhamna.
Forward thinking
Last May, in an appearance at the Offshore Technology Conference in Houston, officials from Aker Solutions, which designed both the Ormen Lange pilot system and the working system installed at Aasgard, and operator Statoil said future iterations of subsea compression will be smaller, easier to deploy and simpler in design. McDonald says GE is directing research and development toward that goal.
“Aasgard was a very large system,” he says. “It was designed to have contingency built in for almost any eventuality. So now that we have more confidence in subsea compression, we can look at simplifying our system design. That means removing some of what we now believe are unnecessary levels of redundancy. We can potentially reduce the module sizes. Or we can combine two modules into one to try and reduce the number of modules and improve the availability of the system.
“We have some concepts where we can actually fit a full 12.5-megawatt compression system into the tree slots in a manifold,” McDonald continues. “I think that’s a reflection of how much the technology has evolved since the start of the programmes at Ormen Lange and Aasgard, and I think it has the potential to fundamentally change the economics of subsea gas compression.
“If you go from a system that weighs more than 5000 tonnes to a system that could be less than 2000 tonnes, that has a huge impact on the economics.”
GE is also developing new technology in wet gas compression through a joint industry project with Statoil and Chevron. The company is testing a modified compressor at Statoil’s K-Lab subsea compressor test facility Kaarsto, Norway. A wet gas compression system eliminates the need for a scrubber and variable speed drive upstream of the pump, enabling the system to be scaled down considerably.
The trade-off is an increased risk of erosion due to liquid droplets being dashed against internal surfaces of the compressor after passing through impellers spinning at a rate of more than 10,000 RPM, says Jorgen Corneliussen, engineering manager in GE’s subsea power & processing division.
“There are many challenges when you send liquid through your compressor rather than separating it out. There’s a big difference in weight. Liquid is much heavier than gas. That means that if you add even just a little liquid, the weight of what you send through grows tremendously. It’s a completely different momentum on the machine and different forces acting on it.”
Liquid in gas “challenges the robustness” of the compressor and has a tendency to accumulate in places, such as seals, where it can create vibrations, he says.
“With the Ormen Lange technology, we can actually pick the components we need to make short, medium and long step-outs.” Kristin Elgsaas, GE Oil & Gas
To build a 2.8-MW prototype compressor for the K-Lab trial, engineers chose a harder material for the seals, adapted a titanium nitride coating from GE’s aviation business for some internal components, and redesigned the impeller and blades so that the unit produces smaller liquid droplets and directs them away from erosion-prone surfaces. The programme has received technical support from Norwegian University of Science and Technology.
The topsides-mounted prototype is being used to prove the redesigned impeller blades, McDonald points out — a subsea version would be based on the 12.5-MW Blue-C technology.
With the technology behind subsea compression demonstrated, the challenge for suppliers now lies in making an economic case for it in an era of straitened development budgets. GE, like other large providers, is seeking ways to better integrate its in-house technology and services, and to seek out third-party solutions when it makes more sense to do so, says McDonald.
Both the wet gas compressor qualification and, on a much larger scale, the Ormen Lange subsea compression pilot allowed GE to draw on technologies from different parts of the company and from within the oil and gas business unit.
“The environment has changed since Aasgard and Ormen Lange,” he says. “Now, at $50 per barrel oil, it’s really more important than ever that we use technology to take costs down. That’s been our principle focus over the last two or three years–to see what we can do to simplify our designs and to use technology to make that happen.”
“Technology acceptance takes a bit of time. It was quite brave having three subsea compression projects running in parallel before one was even deployed.” Jorgen Corneliussen, GE Oil & Gas
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