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Subsea processing overview

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Subsea processing using subsea separation and pumping technologies has the potential to revolutionize offshore oil and gas production. When combined with relatively mature subsea production technologies (see subsea chapter on well systems, manifold, pipeline, power and control umbilical, and so on), it can achieve the following:

  • reduce development cost
  • enhance reservoir productivity
  • improve subsea system reliability and operability

Between 1970 and 2000, millions of dollars were spent to develop subsea separation and pumping systems. But because of unresolved technical issues, along with a lack of confidence and clear understanding of the costs and benefits, industry did not rush to deploy the technology on a commercial basis. However, as the industry has moved into remote deep and ultradeep water, various degrees of subsea processing are becoming more common. In deep water, the technology can enable hydrocarbon recovery from small reservoirs that are subeconomic by conventional means, making small fields economically viable and large fields even more profitable.

The benefits of subsea processing have been recognized for several decades. However, with production limited to shallow waters, the risk of deploying a new technology was too great compared to the potential rewards. Topside processing facilities were relatively inexpensive, and conventional technologies were adequate to achieve acceptable reservoir performance and project economics. Consequently, subsea processing remained an academic interest until the 1990s.

Conventional technologies

Among conventional artificial-lift systems, gas lift is closest in principle to subsea processing. Electric submersible pump (ESP) systems, which degas and pump the resultant liquid at the wellbore, should be compared with downhole processing. Both subsea separation and gas lift function by reducing the hydrostatic head of the fluid column. However, unlike subsea separation, gas lift can never achieve the low gas hydraulic pressure gradient. As more gas is injected, additional pressure drop imposed by flow-induced friction overtakes the benefit of lower fluid density. In vertical parts of tubing or pipeline, lift-gas injection can actually reduce flow efficiency. Because gas lift does not improve horizontal flows, gas lift has limited applications for long-distance tiebacks or highly deviated wells.

Driven by economics

The compelling reason for subsea processing is to improve field development profitability. Benchmark data of deepwater (> 300 m water depth) offshore developments clearly indicate two primary contributing factors for superior economics:

  • Higher production and reserves per well.
  • Ability to process production at an existing platform (i.e., subsea tieback to a host platform).

In conjunction with mature subsea well technologies, subsea processing can enable superior economics.

Subsea processing composition

Existing applications

Despite all the interest, there is no “real” subsea processing system in commercial operation as of 2002. The North Sea Highlander/Tartan subsea slug catcher has many of the attributes and may qualify as one. The Highlander field was developed in 1983 as a subsea tieback with production piped to the Tartan A platform for processing (Fig. 1a).[1]

To overcome the terrain-induced slugging in the 8-mile pipelines and flow dynamics in the 150-m risers, the operator installed a slug catcher at the base of the Tartan platform to separate the fluid phases. The gas flows up to the deck in a gas riser under natural pressure, while the liquid is pumped to the platform by a separator riser (Fig. 1b). After overcoming initial problems with pump seals, the system had operated well.

Development pilots

Numerous subsea processing systems have been tested over the last several decades. The world’s first prototype seabed separation unit was tested in 1969 on the Zakum field offshore Abu Dhabi. Despite a few difficulties, reports indicate the system performed well for 3 years before being decommissioned. A separation system was tested in 600 m of water in the Gulf of Mexico, between 1972 and 1973.[2]

British Offshore Engineering Technology (BOET)

The BOET group developed a prototype subsea separation and pumping unit (SSPU) which operated on Hamilton Brothers’ Argyll field for a short period in 1989. The 5,000 B/D prototype was designed as a two-stage separation system with three-phase horizontal separators. The system was tested with produced fluids from the Argyll subsea manifold and tendered by the Deepsea Pioneer semisubmersible rig floating overhead (Figs. 2a and 2b).[3] Gas from the SSPU free-flowed to the rig for venting. Oil and water were pumped by electric motor-driven pumps to the surface for final processing.

Kvaerner Booster Station

In addition to the previously mentioned field tests, many other systems were tested in a dry dock under simulated conditions. In the late 1980s, Goodfellow Assocs. developed and tested a design. Bardex tested its Glass system in the early 1990s. Norwegian engineering giant Kvaerner developed the Kvaerner Booster Station (KBS) in the early 1990s. The 10,000-B/D prototype system has a two-phase vertical centrifugal sebrtor, electric-motor-driven axial compressor for the gas, and centrifugal pump for the liquid (Figs. 3a and 3b).[4] The modular design of the system is intended for ease of maintenance and deepwater installation. Kvaerner tank-tested the KBS extensively in 1993 with simulated fluids, diesel, and nitrogen.[5]

Vertical Axial Separation and Pumping System (VASPS)

In the early 1990s, British engineering concern Baker Jardin led a joint industry project to develop the VASPS. The system is unique in that the separation and pumping unit fits inside a 30-in. surface casing of a “dummy” well (Figs. 4a and 4b).[6] To achieve its compactness, the vertical separator uses centrifugal acceleration developed by a helix. The unit resembles a well in that the separated liquid is pumped with an ESP through a “tubing” string, while the gas flows along a piping annulus.[7] A 1:3 scale unit was tested in 1985 onshore with live produced fluids.[8] Ultimately there are plans to test a full-size unit offshore Brazil.

Alpha Prime

Other companies involved in the development of subsea processing systems include a small U.K. engineering company, Alpha Thames Engineering. With support of the European Union and major oil companies, Alpha Thames developed the AlphaPrime concept in the early 1990s. The innovative concept uses an isolation mechanism that allows incoming flowlines and outgoing product pipelines to be isolated and detached from a self-contained retrievable process module. The lightweight module is designed for easy retrieval for repair and maintenance, process reconfiguration, or equipment upgrade using diverless techniques (Figs. 5a and 5b).[9] Because the process module is intended to be totally self-contained, it can be tested as a complete system before subsea installation. This should greatly enhance its reliability by reducing potential interface problems. The AlphaPrime process module is to be entirely electrically powered and controlled. By eliminating the need for hydraulic power, the system will be virtually insensitive to water depth and thus suitable for ultradeepwater applications.

A fully developed and robust AlphaPrime system would give subsea processing a tremendous boost. However, despite multimillion-dollar development programs throughout the 1990s, leading to a dockside submerged test in 1999, key mechanical and electrical components that make up the system were still not ready for field use as of 2002.

Troll Pilot

As of 2002, the Troll “C” Pilot (offshore Norway) may be the only subsea separation system in operation. It is based on ABB Offshore Technology’s Subsea Separation and Injection System (SUBSIS) design. The system has the capability to remove and dispose of the water produced by Troll subsea well templates S1 and S2, and to pipe the gas and oil as a mixed stream to Troll “C” platform for further processing (Fig. 6).[10]

The 3-m-diameter by 9-m-long horizontal separator has the capacity to handle approximately 3,400 Sm3/D of oil at 57% water cut. Limited by the 2 MW of electric power available, water injection capacity is 6,000 Sm3 /D. The 250-ton system, submerged in 350 m of water, was installed in early 2000 (Fig. 7). Although not fully functional in 2002, many parts of the system have been commissioned.


The value of seabed processing must be evaluated on a case-by-case basis. It is highly influenced by characteristics of the reservoir and whether production acceleration and improved recovery can be achieved. For a new deepwater play, seabed processing may enable regional development of multiple fields through a single host platform and common export pipelines. In a mature area, the technology may allow economical tieback of marginal discoveries. As with most decisions in the petroleum industry, net present value (NPV) is a good measure of the attractiveness of using subsea processing. The analysis must weight the value of potential production gain and the Capital expenditure (CAPEX) and operating expense (OPEX) savings against the uncertainties and risks associated with an emerging technology.


One of the problems with basing a development on emerging technology is estimating the cost of prototype or “first-of-a-kind” equipment. Although most of the components that make up a subsea processing system already exist, packaging and components integration are still evolving, which makes establishing their cost difficult. In addition, each system will be unique and will undoubtedly require new installation procedures and tools. Availability of deepwater installation vessels is limited. Their costs are driven by market demand, mobilization and demobilization requirements, and the degree of special outfitting.

Equipment life

The expected life of subsea equipment can have a huge impact on project economics. Because of high intervention costs and potential loss of production, reliability and availability of the system must be kept high. Unfortunately, with less-than-mature technology and new equipment design, there is little or no track record for guidance. Simulated endurance tests of key components will help estimate mean time between failures. However, there is no substitute for actual field testing. The key to improved subsea system availability is to keep it simple, with as few moving parts as possible, and to pay attention to details.

Cost of intervention and maintenance

Deepwater intervention will be costly because of the need for specialized equipment and support infrastructure. Keeping the subsea equipment light and compact will allow the use of less costly and more abundant dive-support vessels rather than having to use heavy-lift vessels. Depending on water depth, this may mean keeping module weight to less than 100 tons. High-maintenance items such as pumps may be designed for individual retrieval to lessen lifting requirements. In general, the design should strive for system retrieval, thereby allowing the system to be tested as an integral unit prior to reinstallation. This will minimize interface problems when the system is restarted on the seabed.

Comparison to conventional developments

Subsea processing may be the enabler to offshore development, but in most instances, it will have to add value to the project when compared to conventional methods. Until the technology gains maturity and develops a sufficient and satisfactory operating record, the value addition must be significant to overcome the inherent new technology risks.

What’s in store

As the industry advances into ever-deeper water, use of subsea processing will become inevitable. Cost of surface production platform will become prohibitively high, making subsea tieback to a shallower water host platform or a regional hub that serves many subsea fields an economic necessity. Given the distance limit of direct tieback and associated flow assurance challenges, companies will accept seabed processing as a workable solution that can add significant value to their assets.

Studies have shown that the first application of a new technology, even with good planning, will experience significant cost overruns and extensive delays. Subsequent applications will benefit from the initial experiences and will perform much closer to expectations. This has led to industry’s desire to be the “fast follower” rather than the leader. The “you first” attitude may explain why there is not yet a commercial seabed-processing installation.

Although the potential benefits of subsea processing are well recognized and discussed in numerous publications, the uncertainties surrounding prototype cost and operating reliability are high. Until more systems are field tested, installed, and have an operating history, the perception of high intervention costs will prevail. Subsea processing is at the emergence stage where subsea well and production systems were in 1975. As more systems are tested and operating subsea, the technology will gain critical mass and morph into commercial products. That will drive even more innovations and technological improvements in the following:

  • hardware
  • packaging
  • system integration
  • installation techniques

In spite of the inherent risks of new technology, the economic and operating advantages of subsea processing are too compelling to ignore. Industry’s continuing drive to make marginal deepwater developments economic and larger fields more profitable is the catalyst for the development and commercialization of emerging technologies such as subsea processing.


  1. Smith, G.D. and Batcherer, G.H. 1987. Overview of the Highlander Field Development. SPE Prod Eng 2 (4): 313-318. SPE-13970-PA.
  2. Sombre, R.M. 1989. Subsea Separator Gets First North Sea Test. Ocean Industry (November).
  3. Songhurst, B.W. and Edwards, W.G. 1989. Subsea Separation: An Economic Production Method for Sub Marginal Fields. Presented at the Offshore Europe, Aberdeen, United Kingdom, 5-8 September 1989. SPE-19228-MS.
  4. Dahl, T. 1992. Kvaerner Booster Station—a Subsea Processing System. Scandinavian Oil-Gas Magazine (September–October).
  5. Cotton, J.L. and Stinessen, K.O. 1994. A Booster Station: Results Of Extensive Testing And Post-Test Inspection. Presented at the Offshore Technology Conference, Houston, Texas, 2-5 May. OTC-7513-MS.
  6. Baker, A.C. and Entress, J.H. 1991. The VASPS Subsea Separation and Pumping System. Paper presented at the 1991 ICHEME—Subsea Separation and Transport III Conference, London, 7–9 May.
  7. Baker, A.C. and Entress, J.H. 1991. The VASPS Subsea Separation and Pumping System Applied to Marginal Field Developments. Presented at the Offshore Europe, Aberdeen, United Kingdom, 3-6 September 1991. SPE-23049-MS.
  8. Benetti, M. and Villa, M. 1997. Field Tests on VASPS Separation and Pumping System. Presented at the Offshore Technology Conference, Houston, Texas, 5-8 May. OTC-8449-MS.
  9. Appleford, D.E. and Taylor, M.A. 1998. Evaluating the Feasibility of Subsea Separation in Deepwater Fields and Its Effects on the Necessary Infrastructure. Paper presented at the Deeptec 1998 Conference, Aberdeen, 26–27 January.
  10. Stomquist, R. and Gustafson, S. 1998. SUBSIS—World’s First Subsea Separation and Injection System. ABB Review No. 6, 4–13, M122,

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See also

PEH:Subsea and Downhole Processing

Subsea processing benefits

Subsea processing technology

Subsea processing design

Subsea process configurations

Downhole processing overview