Offshore in depth

Three years ago, with the price of oil above $100, the prospects for subsea processing looked bright. Although adoption of the technology lagged expectations, a growing number of operators and suppliers were beginning to share a vision of future offshore developments that would move most or all of the processing of produced oil, gas and water from the topsides to the seabed, delivering hydrocarbons to export lines without bringing them to the surface. Extensive subsea processing could increase recovery rates, reduce the cost of deepwater development, make marginal fields economically attractive, and potentially reduce the environmental footprint. In a 2013 presentation, subsea consultant INTECSEA suggested that subsea processing would reduce costs and increase recovery on the vast majority of deepwater projects.

The subsea processing vision. Statoil calls this vision the “subsea factory,” FMC Technologies has named it “all subsea,” and Total refers to it as “DEPTH” (Deep Export and Production Treatment Hub). The logic of subsea processing continues to be valid, but costs remain high, and there are several technology gaps that must be filled before the vision can become a complete reality. While sanctioning of new deepwater investment has been throttled back in the current “lower for longer” era, operators and service companies have recently taken important incremental steps toward achieving the subsea processing vision.

Subsea processing (in order of difficulty) includes boosting, separation, water treatment and reinjection, gas compression, sand handling, gas sweetening, oil polishing and stabilization, and fiscal metering. Of more than 5,000 subsea wells in 1,500 fields worldwide, some form of subsea processing is being applied on fewer than 100 wells, mostly using boosting technology. Such slow adoption can be attributed in part to the industry’s reluctance to accept new approaches, but significant technology gaps remain. And Statoil has noted that the cost of subsea systems has increased by 250% in the past decade, making it harder to justify investment. Still, the potential prize is great; Statoil estimates that subsea processing can increase hydrocarbon recovery by at least 10 percentage points, adding millions of barrels of production.

Notable projects. More than 20 projects in Norway, the UK, the Gulf of Mexico, West Africa and Brazil are using some form of subsea processing. Notable milestones include Petrobras’ and Shell’s application of gas/liquid separation and boosting on several fields offshore Brazil; Statoil’s separation, boosting and water injection at Tordis; Shell’s deepwater separation and boosting at Perdido and Stones in the Gulf of Mexico; and OneSubsea’s 3-MW, single-phase booster pumps employed by Chevron at Jack/St. Malo.

Total’s Pazflor project, which started up off Angola in 2011, uses FMC Technologies’ gas/liquid separation systems to service 25 subsea producing wells, enabling the production of heavy oil from the field’s Miocene reservoirs.

At Gullfaks South, Statoil has installed two 5-MW wet gas axial contra-rotating compressors on the seabed to handle gas and condensate produced from the South Brent reservoir. The combined product is sent 15 km to the Gullfaks C platform, which provides power and control to the subsea compressors via umbilical. Statoil estimates that subsea processing will increase field recovery by 22 MMboe.

At Åsgard, Statoil estimates that subsea dry gas compression will increase recovery by 280 MMboe from Mikkel and Midgard fields. Installed in 2015, the subsea installation includes a shared scrubber and condensate pump, and two 11.5-MW compressor trains. The compressor trains convey gas and condensate over a 40-km step-out to the Åsgard B platform, which hosts a 900-t power module and variable speed drives for compressors and pumps.

Technology gaps. Major technology gaps to achieving the “all subsea” vision include solutions for water treatment, H2S and CO2 removal, oil polishing, stabilization and storage, and chemical injection, as well as heating to prevent hydrate formation.

Power distribution for large subsea fields distant from land or host platforms poses a particular challenge. HVDC used for long-distance transmission will need conversion to HVAC to power subsea equipment, and subsea variable speed drives (VSD) will need to be placed close to well clusters. Siemens has proposed its Subsea Power Grid System concept, comprised of building blocks that make up an integrated power system.

GE Oil & Gas developed, tested and qualified a subsea power distribution system to transmit electricity 120 km to Shell’s Ormen Lange development offshore Norway, which was put on hold in 2014. ABB also is working on a power distribution system to drive subsea equipment provided by Aker Solutions, its alliance partner. Cables developed and manufactured by JDR Cable Systems, for long-distance power transmission from offshore wind farms, can be adapted for long step-out subsea fields.

Standardization. To bring subsea processing costs down, Statoil, among others, has advocated equipment standardization so that modules would not require bespoke design for each project, and systems provided by various vendors could be readily combined to “plug and play.” From a service company perspective, FMC Technologies recommends cross-industry collaboration, along with increased R&D funding from oil companies to develop products for a limited-volume market.

The way forward. Looking ahead, Statoil has described its pathway to the “subsea factory,” with needed technology developed by 2020 for use in new deepwater developments during the next decade. In the meantime, analysts at Rystad and INTECSEA expect operators to focus on selecting the right brownfield candidates to apply gradually improving subsea processing components. 

About the Authors

Ron Bitto

Contributing Editor

Ron Bitto has more than 30 years of experience as a technology marketer and writer in the upstream oil and gas industry. RON.BITTO@GMAIL.COM