Single phase

Elaine Maslin

May 1, 2016

Switzerland-headquartered Sulzer is promoting single-phase boosting supported by subsea separation. The industrial engineering and manufacturing firm launched itself into the subsea separation business in 2014, when it bought Ascom and ProLabNL. Both companies are based in the Netherlands and both have been involved in a technology qualification program with ExxonMobil. This has involved creating a compact subsea system, which includes compact inline separation and boosting.

ExxonMobil’s subsea processing vision, incorporating Sulzer technology. Image from ExxonMobil via Sulzer. 

Subsea separation could enable an increase in production, through more efficient liquids boosting, enabling longer range gas compression from shore, cost efficient hydrate management, riser slug reduction and access to reserves otherwise to challenging to reach.

Putting separation on the seafloor would also reduce topsides infrastructure and could pave the way to subsea water re-injection, further reducing topside process equipment.

For ExxonMobil, the drive towards seafloor separation was due to its portfolio including Arctic and deep water resources (11% of its resource base in 2013), according to a presentation by the firm. Exxon’s Upstream Research Co. led a project to qualify, at ProLabNL, a compact separation system for application in 3000m water depth and internal pressures up to 690 bar, while making sure the qualification criteria was wide enough to incorporate multiple field possibilities.

Ascom was heavily involved, producing an inline de-sander and its HiPer MixedFlow two-stage de-oiling hydro cyclones and Canty oil/water monitors.

The work of its subsidiary companies led Sulzer – which also supplies subsea multiphase pumps, water injection pumps and hybrid pumps – to look at the wider industry potential for single-phase pumping.

Rombout Swanborn, head upstream, Sulzer, presented the case for single-phase subsea boosting supported by subsea separation at the Offshore Energy conference and exhibition in Amsterdam late 2015.

Subsea separation brings “inherent advantages over the conventional way of boosting,” i.e. multiphase boosting, according to Swanborn.

For multiphase boosting applications, variable speed drives are currently required topside, as well as power, monoethylene glycol injection facilities, to combat flow assurance issues, multiphase risers, a re-injection system, all supported by umbilical systems, as well as the multiphase pumps on the seafloor. In this scenario production and produced water is transported to the host facility with water treated and then pumped back down to the seafloor and re-injected. This is “complex, energy inefficient and limited reliability,” Swanborn says.

Using separation before boosting reduces topsides facilities and power requirement, just gas and liquid risers are required, with no or minimal need to deal with gas hydrates. On the seafloor, additional equipment includes sand management, which is an area requiring some development, he admits, with either removal required or remixing it into the oil for removal topside, and a produced water reinjection system, which is the main area in which the industry has been held up in its adoption of subsea separation and re-injection.

Swanborn is not deterred. “Single-phase boosting can bring advantages, I think,” he says. “It’s an easier way to get long step-out distances. In some long step-outs it is really the only possibility. It mitigates certain flow assurance risks, e.g. hydrate formation, uses lower subsea energy requirements, and makes subsea water re-injection possible, at the same time as de-bottlenecking topsides three phase separation and produced water treatment, and enabling smaller flowlines to the host. It also absorbs transient flow conditions and has less complexity on the seafloor.”

“Many operators are looking at single-phase boosting systems,” Swanborn adds, to gain these benefits, and on both brown- and green oil and gas fields.