Boosting in the deep

Meg Chesshyre

August 1, 2015

The rewards on offer from subsea boosting technology were spelled out at the MCE Deepwater Development Conference in London this spring by Arne B. Olsen, sales director, pumps and subsea processing at OneSubsea. Meg Chesshyre reports.

Gullfaks South multiphase compressor before load out. Photo by Harald Pettersen - Statoil ASA

Subsea pumping improves field economics by reducing backpressure on the reservoir, increasing well flow rates and total recoverable reserves, explains Arne B. Olsen, sales director, pumps and subsea processing at OneSubsea. Boosting improves flow assurance by increasing velocity in pipelines, increasing temperature, and stabilizing production.

“OneSubsea has been operating in the subsea processing arena longer than any other company in the world, and records today more than 15 years MTTF (mean time to failure) of our pumps,” he says, with the firm’s technology development facilitated by the company’s ability to invest in large realistic test infrastructure.

However, the subsea booster market has been slow to develop and there are a limited number of projects out there, Olsen admits.

The vision

Subsea boosting is still being described a new technology, despite being around now for more than 20 years. The original vision for subsea multiphase pumps was to create a technology that could extend satellite development from fixed platforms out to about 50km. Framo’s first multiphase test rig was in place as early as 1987, at the company’s facility just south of Bergen. Here, the firm selected and tested the helicon-axial pump principle to be used.

The evolution of multiphase pumps from OneSubsea’s successful collaboration with Shell on the Draugen field in the Norwegian sector of the North Sea dates back to 1994. That marked the delivery of the first commercial subsea multiphase pump (650 kW), in 270m water depth on a 9km tie back. This was followed by Statoil’s courageous decision to install subsea electrical pumps on the Lufeng field in the South China Sea in 1997. These pumped some 42 MMbo from 1997-2011.

The first true subsea multiphase pump was installed in 2000 at ExxonMobil’s Topacio field in Equatorial Guinea, and has been in operation for more than 50,000 hours since.

The first subsea water injection pump was installed at the Troll pilot, in the Norwegian sector of the North Sea, in 2001, and the first subsea seawater injection system at Columba E, in the UK North Sea, for CNR in 2006.

The deepest, longest tie back and highest design pressure was installed in 2011, for the Chevron-operated, 2100m (7200ft) water depth Jack/St. Malo development in the US Gulf of Mexico. First oil from Jack/St. Malo was last year. OneSubsea supplied the production and processing systems for the project, including 12, 15,000psi subsea wellhead trees, production controls, four manifolds and associated connection systems, engineering and project management. Through one of its predecessor companies, the firm also supplied three pump stations, three subsea pump control modules and associated and instrumentation equipment. The pump systems, which are comprised of three megawatt single phase pumps, are remarkable for their combination of 13,000psi design pressure and installed water depth.

OneSubsea also delivered the largest differential pressure systems to Total’s 1400m deep GirRI project (130 bar differential pressure) offshore Angola in 4Q 2014.

One the key drivers for the technology has been increasing water depths, with projects, such as Jack/St. Malo, reaching down to 3000m, with a design pressure at 15,000psi, to meet requirements in the Gulf of Mexico and differential pressure evolution at 140 bar.

Wet gas compression

The most recent highlight for OneSubsea, however, has been the delivery in March this year of the world’s first subsea multiphase compressor to Statoil for the Gullfaks South field in the North Sea, Olsen says. The subsea multiphase compressor enables boosting of unprocessed wet gas production fluids, from 0-100% liquid phase, eliminating the need for an upstream separation facility or an anti-surge system, and making it the industry’s only true wet gas compressor. It is expected to increase the recovery rate for the Gullfaks South Brent reservoir by 22 MMboe.