Last year was a breakthrough year for subsea compression. Elaine Maslin surveys the projects that came online and discovers what became of Ormen Lange.
Subsea compression at Ormen Lange. How it could have looked. Image from Statoil.
After some 30 years in development, subsea compression is finally proving its worth offshore Norway, at least in part.
Late September, Statoil, which installed the world’s first subsea gas compression system on the Åsgard field, said the system had been “running like a Swiss clock with practically no stops or interruptions,” with close to 100% system regularity, since it came onstream a year earlier.
It has already helped increase production by some 16 MMboe and is expected to boost recovery from the Mikkel and Midgard reservoirs by as much as 306 MMboe, corresponding to a medium-sized field on the Norwegian Continental Shelf (NCS) and extending the fields’ life to 2032. The recovery rate from the Midgard and Mikkel reservoirs on Åsgard has been raised from 67% to 87% and from 59% to 84%, respectively.
Meanwhile, the Gullfaks wet gas compression project, which came online after the Åsgard project, on Statoil’s Gullfaks field, also offshore Norway, has had a slower start, having been taken offline after a subsea cable leak was discovered in December. Both compressors installed on the project were removed (OE: October 2016). Statoil has said, following evaluation of the umbilical involved, it would be looking to reinstall the system by mid-2017.
A third project had also been a contender to be one of the first subsea compression projects – Ormen Lange, a 120km step out offshore Norway. However, while its operator, Shell, halted the project in 2014, citing costs and reservoir data, it continued work on a pilot project to demonstrate the feasibility of subsea compression.
OE revealed in August that the subsea power distribution system on this project had been qualified and, late August during ONS, GE Oil & Gas said that the whole system had been qualified, at Shell’s test facility at Nyhamna, Norway. GE described it as the world’s first subsea gas compression system with a full subsea power supply, transmission and distribution system, using GE’s Blue-CTM compressor (a centrifugal compressor designed for subsea).
Ormen Lange was discovered in 1997 and has been producing since 2007, in 600-1100m water depth in the southern part of the Norwegian Sea, about 130km northwest of Kristiansund.
An aerial view of the Nyhamna facility. Photo from Shell.
Clare McIntyre, Ormen Lange business opportunity manager, says that Shell is still looking at the options for the development. “[In 2014,] we took a step back. The cost was too high and it was not going to be economic,” she says. “We have time and will take time. We want to find an economic solution that gives the best solution and we are still very much in a period of looking widely at different technologies.” McIntyre says that despite stopping the project in 2014, Shell continued the pilot project. “The technology from the pilot is one of the concepts we could consider for the future,” she says. “It is in the running, along with a number of other concepts.” But, to be a contender, costs will have to come down, which could potentially be helped by Statoil’s experience on Åsgard.
While other concepts will be looked at for Ormen Lange, Shell said that it was installing two new compressors at Nyhamna to raise the output capacity at the field and McIntyre says that even a floating facility could be considered. McIntyre says that Shell also sees the value of subsea compression technology.
“We see the benefit for other fields in the future, along with subsea separation, or a Gullfaks-type of wet gas compression solution, for example,” she says.
Late September, Shell said that the two new compressors at Nyhamna would increase output capacity to 70 MMcm/d, from the current ca.50 MMcm/d. Separately, Shell said it’s also planning to increase capacity at the gas processing plant to 84 MMcm/d, from 70 MMcm/d, to accommodate the future output from Statoil’s Aasta Hansteen development, which is expected to start production in Q4 2018.
McIntyre says a lot of the work has focused on debottlenecking Nyhamna. “We believe there is a lot more we can get out using the existing facilities,” she said during ONS.
Meanwhile, in case it has a failure on Åsgard, Statoil has a complete 12 module spare train sitting on a quayside in Norway, plus process intervention equipment at the ready.
Torstein Vintersto, vice president, project management, Statoil, told ONS that the project has given the operator a new tool in its kit, complete with intervention systems, and lessons learned during the first phase of operations. Through an online system developed by Statoil, the firm is able to go in to the highly instrumented system at any time, online, to see what is happening.
“We see significant cost reduction potential through simplification, standardization and industrialization,” he told ONS. That should be music to Shell’s ears.