Sea Floor Separation

Fact Sheet - Sea Floor Separation

Intro to Produced Water
Technology Descriptions
Fed & State Regulations
Technology Identification

The most desirable way of minimizing produced water involves technologies that prevent the water from entering the well. The fact sheets covering mechanical blocking devices and water shutoff chemicals describe such technologies. However, for most wells, these technologies are not practical or feasible. Operators can still minimize water production with technologies that do not impede produced water from entering the well, but instead, reduce the volume of water brought to the land surface or the platform. This type of technology is predicated upon separating oil and water remotely.

Lifting water to the platform represents a substantial expense for operators. Platform space and weight constraints further restrict treatment options and increase costs. This fact sheet describes sea floor separation technology. A separate fact sheet introduced technologies that remotely separate oil and water (or gas and water) in the well bore, or, by design, produce oil and water through separate pump and tubing systems.

Sea floor (also called seabed) separation involves a large module that sits on the sea floor. Fluids from one or more wells are sent there for separation. The oil is lifted to a platform or to a floating production and storage and offloading (FPSO) vessel, while the water is typically pumped directly to an injection well.

Experience with Sea Floor Separation 
As of the end of 2006, only one sea floor separation unit has been used in full-scale operations. A Norwegian company, ABB, developed a subsea separation and injection system (SUBSIS) that separates the produced fluids from an offshore well at a treatment module located on the sea floor. The SUBSIS module weighs 400 tons. It is 17 meters long and wide, and 6 meters high.

SUBSIS module diagram
SUBSIS module; 
Source: ABB
  SUBSIS module photo
SUBSIS module; 
Source: ABB

The first figure shows a drawing of the SUBSIS module. The second figure shows a photo of the actual SUBSIS module. The people near the top of the photo are dwarfed by the unit.

The SUBSIS began full operation in August 2001 at Norsk Hydro's Troll field, about four kilometers from the Troll C platform. It operates at a water depth of 350 meters. Initial results indicated that 23,000 bpd of produced fluids were separated into 16,000 bpd of oil and gas and 7,000 bpd of water. The water was injected directly from the SUBSIS unit into a dedicated injection well (Wolff 2000; Offshore 2000).

Von Flatern (2003) reports the results of a year-long trial of the SUBSIS. The SUBSIS handled a maximum flow of 60,000 bpd and a typical flow of 20,000 bpd. The oil concentration in the separated water stream dropped from an initial level of about 600 ppm to 15 ppm. Because the water injected from the SUBSIS did not need to come to the surface at the Troll platform and occupy some of its water handling capacity, the Troll platform was able to produce an additional 2.5 million bbl of oil during the year-long trial (von Flatern 2003).

Petrobras continues development of a subsea unit called vertical annular separation and pumping system (VASPS). A VASPS unit was used successfully to separate gas from other fluids at the Marimba field in the Campos basin (do Vale et al. 2002). Additional technology improvements are underway to allow oil/water separation. This is part of the PROCAP 2000 program designed to improve production in deep water in the Campos Basin. The system is being designed to operate in 2008 at water depths ranging from 800-1,500 m, at the Marlim field in the Campos basin. The VASPS's main features include a modular configuration, small size, and reduced weight to allow handling by a wider range of installation vessels. During the Marlim field tests, the system will be installed at 872 m, and as close as possible to the wellhead to minimize heat loss in the flow line. By the end of 2005, Petrobras had developed three different designs. They are currently in the final stages of technical evaluation.

In late 2005, Statoil proposed increasing the production at its Tordis field by managing produced water at a subsea separator.

The challenges posed by sea floor systems include:

  • Subsea systems are costly to implement,
  • The technology is new, which increases implementation risks, and
  • In light of the costs, they are better suited for use in relatively young reservoirs.

do Vale, O.R, J.E. Garcia, and M. Villa, 2002, "VASPS Installation and Operation at Campos Basin," OTC paper 14003, presented at the Offshore Technology Conference, Houston, TX, May 6-9.

Offshore, 2000, "ABB Looking to Progress Subsea Processing into Ultra-Deepwater," Offshore, Vol. 60, Issue 8, Aug. 1.

Offshore, 2006, "Subsea Separation, Reinjection System Solves Problem of Produced Water," Vol. 66, Issue 9, September.

Von Flatern, R., 2003, "Troll Pilot Sheds Light on Seabed Separation," Oil Online (, May 16.

Wolff, E.A., 2000, "Reduction of Emissions to Sea by Improved Produced Water Treatment and Subsea Separation Systems," SPE#61182, presented at the Society of Petroleum Engineers International Conference on Health, Safety, and Environment, Stavanger, Norway, June 26-28.

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