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Subsea processing technology

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Subsea processing is not a single technology, but the integration of complementary technologies that include the following, all in a subsea context:

  • fluid chemistry
  • process
  • separation
  • rotating equipment
  • power transport and distribution
  • instrumentation

Some of the technologies, such as mechanical and control devices commonly used in subsea well and manifold systems, are well developed and can be considered off-the-shelf items. Others, such as subsea power-distribution systems, are still in the product development stage. Many of the emerging products are well-proven surface components modified for subsea application. As in any integrated system, a shortcoming in any one of the links will impair the performance of the whole. Successful implementation requires all the skill sets to work seamlessly and with greater than ever attention to QA/QC in components manufacturing, installation, and system integration.

Process technology

A clear understanding of the process and all its parameters is the first step toward a successful design. As in surface facilities, knowledge of the produced fluid properties, rheology, and flow characteristics are critical. Luckily, whether the process is carried out on the surface or a thousand meters subsea, the process is the same. However, effects of the environmental conditions may be more dramatic and detrimental. Such environmental conditions include:

  • rapid heat loss to a colder ambient
  • long flow lines
  • tall risers

Fluid properties

Understanding of the produced fluid properties is especially critical to the design of subsea separation systems, because vessel size has such a significant impact on:

  • system installation
  • retrievability
  • cost

For two-phase separators, the design-limiting parameter is usually the gas rate, which is controlled by:

  • gas-liquid ratio
  • temperature
  • pressure

Fluids with high foaming tendency will complicate the design and may require mechanical or chemical solutions. For subsea applications, a passive mechanical foam-breaking device (such as a low-shear inlet momentum breaker) is preferred over the more costly to install and operate chemical injection systems.

For three-phase separation, the more complex oil/water emulsion/dispersion chemistry will come into play, along with the viscosities of the oil and water and changes in water cut with time. Whether an oil/water mixture will form a stable emulsion or a more manageable dispersion often depends on the small concentrations of surface-active impurities in the fluid. These impurities can be injected chemicals such as:

  • corrosion inhibitors
  • naturally occurring compounds
  • corrosion products
  • formation fines

Addition of heat or surface destabilizing chemicals is the general solution. Once the emulsion is broken, different types of mechanical packs may be used to accelerate droplets coalescence and settling.

Flow assurance

Constituents of produced petroleum fluids can be deposited on pipe walls when subjected to cold seawater environment. These depositions can reduce pipeline hydraulic efficiency and, in severe situations, impede flow. Many oils contain high concentrations of paraffin and waxes dissolved in the oil under reservoir conditions. Light hydrocarbons (i.e., methane, ethane, propane, and so on) increase the solubility of waxes in oil. These gaseous components will break out of the oil as pressure drops below the bubblepoint. The resulting reduction in solubility, along with cooling of the fluid through heat loss to the environment, causes waxes to precipitate out of the supersaturated solution and stick to the cold pipe wall. Over time, buildup of thick layers and plugs can result.

There are chemical inhibitors available for wax precipitation. However, because of the complex and numerous waxy compounds that are found in oils, there is no guarantee that an effective inhibitor can be found for a particular crude. The search is by trial and error. The only sure way to prevent wax deposition is to maintain the system temperature above its wax appearance point. Methods to heat and insulate subsea pipelines have been developed, but they are costly and often not practical for long deepwater pipelines. Short of keeping the wax in solution, regular and frequent mechanical scraping is effective in keeping deposits at a manageable level.

Hydrate formation

In gas/water or gas/oil/water systems, hydrate formation is the main concern. Hydrates are compounds made up of loosely bonded light hydrocarbon (methane, ethane, and propane) and water molecules. Hydrate formation is enhanced by cold temperature, high pressure, and turbulence. Hydrates resemble snowflakes and can clump together to form plugs in pipes. Effective inhibitors are available if a pipeline must operate within the hydrate-formation envelope (i.e., low temperature and/or high pressure). Methanol and ethylene glycol are the two most commonly used. The amount needed is a function of the amount of water that must be inhibited and temperature depression (degrees below the hydrate formation temperature, at system pressure, that the gas is expected to cool). Water inhibited by methanol or glycol in the proper amount will not form hydrates. However, only methanol, with its high vapor pressure, is effective in breaking hydrate crystals once they are formed. Because inhibitors are injected at a steady rate, and water production from a well often comes in slugs, having inhibitor at the required concentration in the water phase is almost impossible to achieve. The main reason methanol is overwhelmingly used in the field is because of its ability to prevent and to remedy all hydrate formation.

Flow dynamics

Surges in multiphase pipelines are unavoidable. Slugging severity depends on:

  • fluid velocity
  • pipeline length
  • elevation changes

It is almost impossible to design a pipeline to avoid surges over its entire useful life. As production declines, the lower velocities will exacerbate fluid surges. Slugging is especially damaging in offshore pipelines. Large slugs of liquid followed by gas often occur in the riser, swamping inlet separators and starving the compressors. Some have proposed the use of feed-forward controllers to restrict flow when liquid slugs are detected, but their effectiveness is largely unproven. At present, large separators or slug catchers are the only dependable solution. Subsea processing, in conjunction with single-phase pipelines, can be an alternative solution with multiple benefits.

Subsea technology

Processing on the seafloor is becoming possible because of the tremendous advances in subsea production technology since the 1980s. The proliferation of subsea wells, especially in deepwater, has provided economic incentives for hardware development and growth in support services. Readily available subsea connectors and control modules, along with well-proven installation tools and procedures, form the bases on which seafloor processing systems are built.


Most subsea process equipment is derived from modification of proven surface components for submarine service (marinization). Whether the separator, pump, or instrumentation is installed topside or on the seafloor, the process is the same. Consequently, the process side of the equipment is already subsea-capable. It is the external side of the facility that must be marinized for the seawater environment at its intended depth of service, and efficient remote installation and intervention. Many of the marinization techniques have been proven with subsea production equipment. However, subsea processing requires more instrumentation and controls, and a much larger source of power for pressure boosting. At present, development of easy-to-install and reliable subsea connectors for control umbilical and high-voltage electrical systems are proving to be the biggest challenges.

Diverless connection

Most subsea processing applications are beyond diver-assist water depths, making diverless equipment installation and connections a necessity. Fortunately, much of the technologies already exist for subsea wells and manifolds, and they can be readily adopted for process systems. Some of these technologies are shown in Fig. 1.

Retrievable module

Mechanical equipment will wear out and must be repaired and maintained. In addition, process conditions may change over time, making equipment modification or replacement necessary. However, the heavy, hard-to-retrieve support structure and piping will generally not be affected. Therefore, most seafloor processing systems are of retrievable modules design. Components that are susceptible to wear and premature failure are contained in retrievable modules, while static and relatively benign pieces are fixed with the base structure. Method of isolation ranges from ROV(Remote Operating Vehicles)-actuated multiported connectors to simple check-valve arrangements. Modules are generally designed for workboat retrievability and driven by vessel availability and cost. Size and weight limitations are based on equipment common to the area and water depth of the application.

Structure and manifold

The base structure and manifold for seafloor processing are borrowed from those for satellite wells systems, although they may be larger in size and contain more functions. They are generally made up of the same components reconfigured for process application. The difference is usually in the retrievable modules, which contain the unique process equipment such as the following, represented in Fig. 2:

  • separator
  • pump
  • electrical
  • control systems

Protective cover

Subsea equipment has to be protected from dropped objects during normal operations and periods of intervention. This is especially important for sensitive seafloor-processing facilities. Because of their retrievable modular design, protective covers are configured on an individual module basis so that a module can be removed while the others remain protected. With the development of strong, lightweight composite materials, protective covers can be effective without being overly cumbersome.

Subsea pig launcher

To prevent potentially catastrophic plugs from wax and other deposits in pipelines, capability for regular pigging is desirable. (Note: A “pig” is a sphere or cylinder, often containing scrapers, which is injected into the pipeline at the beginning with a “pig launcher” and collected in a “pig receiver” at the end.) With subsea separation and liquid pumping, pigging operations do not have to impact production. Subsea pig launchers with rechargeable pig cartridges have been developed by a number of vendors. Although the technology is still evolving, it has been applied in the North Sea and Australia. Designs for rechargeable cartridges with as many as 12 pigs are available, depending on required line size and water depth. Fig. 3 is an illustration of the pig launcher for the East Spar project in Australia.

Separation technology

The heart of a seafloor processing system is the separator. Functionally, a subsea separator is no different from a topside unit. However, because of high cost of heavy-lift vessels and the remote nature of the installation, it needs to be lightweight and maintenance-free (or require minimum maintenance).

Gravity separation

Traditional separators depend on gravity to achieve phase separation. When fluid velocity is reduced to the terminal velocity of the liquid droplets, phase separation will take place. With few enhancements, a gravity separator is no more than a wide spot in the flow path. A separator can be configured vertically or horizontally as long as it provides the volume to reduce flow velocity to the required level. Because gravitational pull is relatively weak, gravity separators tend to be relatively large. In most cases, size does not impose a huge cost penalty for topside applications, but for high-cost seafloor installation and intervention, more compact solutions are needed.

Compact separator

Numerous compact separator designs (Fig. 4) have been developed that can be used topside or on the seafloor.[1] Most depend on centrifugal acceleration to speed up phase separation. For ease of operation and maintenance (no moving parts), the static cyclone is especially attractive for seafloor applications. Use of cyclone separators can significantly reduce the size of the pressure vessel.

Sand handling

No process facilities can tolerate the huge amount of formation solids that comes with wellbore failures. But for the steady, small volume of fine particulates often produced with oil and gas, offshore producers have learned it is best to keep the solids suspended in the liquid phase until the stream reaches shore. Not only is it difficult to desand offshore, but also disposal of the solids is problematic and costly. For seafloor processing systems, keeping the sand suspended and moving is probably the best strategy as well. Use of a vertical cyclone separator will help facilitate this strategy. Depending on the expected size and shape of the particles, erosion resistance liners or construction material may be advisable. Special care should be taken with pump-seals selection and maintaining smooth piping configurations.

Vessel design for collapse pressure

Structural design criteria for seafloor separators will be different from their topside counterpart. For vessels intended for deep water, the key design criterion is most likely the external collapse pressure at depth. Based on American Society of Mechanical Engineers (ASME) vessel codes, vessel walls can be quite thick, causing even small-diameter vessels to be very heavy. Use of high-strength steel and stiffening rings may help reduce vessel wall thickness and weight. It should be recognized that existing ASME vessel codes were not developed for the large collapse-pressure differential that deepwater separators may experience. More research and development is needed to improve our understanding of this new operating environment. Technologies developed by the defense industry for submarines and ROVs may be applicable.

Pump selection

Once phase separation is accomplished on the seafloor, the liquid will have to be pressure-boosted for transport to the host platform or surface facilities. A mechanical pump is best suited for the task. Efficient pumps are available for subsea applications. However, a pump, being a dynamic machine, will require regular lubrication and maintenance. For remote subsea installations, proper pump selection is imperative for longevity and success of the subsea process operation.

Multistage centrifugal pump

Most seafloor oil- and water-pumping service will fall in the realm of multistage centrifugal pumps. Only multistage centrifugals have the operating envelope to meet the high-flow and high-head requirements. Unlike the packing on reciprocating pumps, the seals on centrifugal pumps are more reliable in the seawater environment and more forgiving to the abrasion that may be caused by sand in the produced fluid.

Water injection

For production with a high water cut, it may be desirable to remove and dispose of the water subsea. If a formation can be found that can accommodate water containing a small amount of residue oil, water injection may be a cost-effective disposal option. Produced water from a gravity separator tends to have upward of 200 ppmv of residue oil droplets. Cyclone liquid/liquid separator can reduce that concentration significantly, but at the loss of simplicity. Multistage centrifugal pump will be needed for the injection service.

Pump driver

In field operations that include waterflooding, some have proposed and used hydraulic turbines to drive subsea pumps. High-pressure injection water is the power source for the turbines. Control is achieved by bypassing more or less water through the turbine. Complex systems of actuated control valves facilitate the required function. The attraction of water turbines is that power input to the system is transferred to topside. Most operators favor electric-motor-driven centrifugal pumps (Fig. 5). Flow control can be accomplished through variable-speed motor control in combination with pump-discharge recycling or discharge throttling. Although an electric pump system can be more compact and less complex to operate than a water turbine, it does require a high-voltage power source.

Subsea Power Distribution

This is one of the key technologies for the success of seafloor processing. Current subsea production systems depend on integrated umbilicals to supply high- and low-voltage power from the host platform. Each end user would have a separate set of electric cables within the bundle. Their motor control and distribution centers are located topside. Because of relatively low voltage of some power consumers, step-out distance is limited. A high-voltage subsea transmission and power distribution system would reduce the number of cables and umbilicals required by the more complex seafloor processing facilities, providing greater flexibility and enabling optimized system design.

High-voltage connector

A reliable, subsea-mateable, high-voltage connector continues to be a challenge for the industry. To support the large loads that subsea processing equipment imposes while enabling reasonable stepout distance, connectors upward of 11 kV are required. The ability for final mating underwater is crucial for installation and maintenance flexibility. A number of vendors have 11 kV connector designs or prototypes under test (Fig. 6). More ambitious designs with a capacity of 36 kV are under consideration.

Switch gear and transformer

Subsea processing facilities will have different voltage demands:

  • high voltage for pump motors
  • intermediate voltage for valve actuators
  • low voltage for instrumentation and controls

To use one high-voltage power supply cable, a subsea power distribution system of switch gear and transformers will be needed. Prototype systems comprising surface electrical components that have been marinized and packaged for subsea installation have been tested. One such system is ABB’s Subsea Electrical Power Distribution System (SEPDIS) system, pictured in Fig. 7, which can be installed without the aid of guidelines.

Control system

Control of processing facilities on the seafloor is the same as on the surface, except that it all must be done remotely. The lack of ready access and high cost of intervention are challenges.

Variable speed-control electric motor

A primary method of controlling centrifugal pump output is to vary its speed. electrical submersible pumps (ESPs) have been installed in subsea wells with variable-speed motor control, with their controllers located on a surface tender. Variable-speed motor control based on high-voltage AC frequency control is being developed for underwater installation, but none are currently in use. The hope is that variable-frequency controllers should perform well once they are marinized. A frequent cause of failure of such equipment onshore has been inadequate heat dissipation. With the infinite heat sink of the cold subsea environment, one would assume that developing an effective heat dissipation system is achievable.

Electric valve actuator

Variable-speed motor control for subsea water injection or pipeline transfer pumps, by itself, may not be adequate to meet the flow and pressure requirement of the process. To keep performance within the operating envelope of the pump, discharge-flow modulating control may also be required. Current technology is hydraulically actuated valves controlled by electrohydraulic or direct hydraulic systems. Development of an all-electric valve actuator, which is inherently water-depth-insensitive, will avoid the complexity of a subsea hydraulic system. A number of vendors have prototype designs under test (Fig. 8). Actuators for isolation and modulating service should be available in a few years.

Umbilical for power, control, and chemical injection

A subsea umbilical may be used to supply the following to the seabed processing facilities:

  • high-voltage power
  • remote-control and monitoring signals
  • chemical inhibitor

Integrated umbilicals for subsea production service are available commercially and are well-proven (Fig. 9).[2] However, they are designed to transport a limited amount of power. To supply the large amount of high-voltage power required by a prime mover in a seabed processing system, separate power cables will probably be needed, leaving the umbilical to provide control and chemical injection functions.

Power and control buoy

Long electric power cables and umbilicals are costly and have inherent physical limitations. Problems include:

  • cable size
  • maximum voltage
  • voltage loss
  • AC line noise

Use of unmanned buoys to provide local-well and seabed-processing control functions, chemical storage and injection, and high-voltage power generation may be a solution (Fig. 10).[3] Communication with the host platform or shore base can be achieved by simple, line-of-sight radio links if the step-out distance is less than 20 miles (30 km). For longer distances, Immarsat C band satellite system will be required. In either case, communication systems with satisfactory performance and reliability are commercially available. Depending on usage rate, chemicals may be stored in the buoy hull or in a separate gravity structure on the seabed beneath the buoy. Supply is replenished by boat shipment.

Although well-control and chemical-injection buoys are accepted technologies, with at least two major systems in operations today, supplying the power required for subsea processing will stretch the limits of the technology. Power requirement for subsea processing is considerably greater than that for well control. For example, power demand of Western Mining Corp.’s East Spar well-control buoy in Australia is approximately 5 kW.[4] The buoy has four 7-kW diesel generator sets (one running, three standby) onboard. Diesel storage capacity is 20 m3. A supply boat from shore refills the tank at roughly 12-month intervals.[5]

A typical seabed processing facility may require upward of 1 MW of power. Supply and storage of the amount of diesel required to fuel that level of power generation would not be practical. Studies have been done on natural-gas-fueled power genset in the 1- to 3-MW size. Produced gas processed by the seabed separator is used for fuel. Ocean Resource Ltd., designer of the East Spar and Mossgas (Indian Ocean, offshore South Africa) well-control buoys, is confident that a system can be engineered. No new technology is needed. It is a repackaging of existing hardware for the novel service, similar to subsea separation and liquid pumping itself. However, it has not yet been accomplished.


Monitoring requirement for subsea processing facilities are the same as those on topside. Strategically located pressure and temperature sensors are needed to monitor the processes. The condition of prime mover and mechanical equipment are monitored for performance and predictive maintenance, with typical monitoring functions including the following:

  • Temperature in the motor.
  • Vibration of the motor bearings.
  • Vibration of the pump bearings.
  • Level and pressure in the pump/motor pressure and volume compensator.

The instrumentation required for these monitoring functions is essentially the same as those for topside application. However, redundancy philosophy must be evaluated with regard to the number of penetrations and communication paths that must be designed for submarine service and their failure potential.

Level monitoring

The heart of a separator control system is the level detector. Nucleonic instruments are preferred for gas/liquid and oil/water level monitoring. Nucleonic density profilers based on Geiger-Mueller tubes are field-proven for topside service. They are able to detect emulsion bands, foam, and even sand level in the bottom of separators. Other nucleonic profilers based on scintillator detectors have been used with good results for oil/water level monitoring. For reliability, dual redundant-level instruments, utilizing different measuring principles, may be desirable. Capacitive and inductive level instruments are not suited for this application because of the similarity in the dielectric constant for hydrocarbon gas and liquid. Ultrasonic-level instruments may not be suitable to detect gas/liquid interface because of potential interference from foam. As an alternative to nucleonic, differential-pressure instruments may be the best method to detect gas/liquid level, especially when a vertical separator is used to provide a high liquid head.


For three-phase separation systems, it will be desirable to monitor the water-in-oil concentration in the processed liquid stream. Many topside devices based on capacitive and inductive properties of the fluid are available, although these standard products must be repackaged for subsea service. There is no reliable continuous monitoring device to measure residual oil in water, even for topside applications. The available instruments may be marinized and used in a subsea system to indicate changes in performance, rather than for absolute measurements.


As discussed in an earlier section, multiphase meters for subsea service are available.[6] In addition, it may be desirable to monitor the individual streams after separation. Most gas and liquid meters based on ultrasonic and rotary displacement principles are suitable. But again, these conventional topside products must be repackaged for service in a deepwater, subsea environment.

Gas handling

Gas leaving the separator will probably be at low pressure and at its water and hydrocarbon dewpoints. In an oil production system, Joule-Thomson cooling will not lower the temperature of the gas significantly because of the high heat capacity and mass of the oil (and water, if any). Because separation takes place on the seabed, there is not much opportunity for seawater cooling, either. Therefore, the gas entering the pipeline will be at a moderate temperature and a low pressure.


It may be necessary to increase the pressure of the separator gas to transport it to the host platform. As discussed earlier, compression will greatly add to the complexity of the seabed processing system and probably should be avoided, given the infant stage of seabed processing technology. However, if it is deemed impossible to transport the gas in a reasonably sized pipeline, subsea compression is a viable option. The 1990 vintage Kvaerner Booster Station included an electric-motor-driven axial compressor provided by Nuovo Pignone, and the system was tested satisfactory.[7] Therefore, a precedent has been established for seabed gas compression. Nuovo Pignone and Kvaerner are currently developing a 2.5-MW centrifugal compression module for subsea service as part of the Norwegian DEMO2000 program. Conceptual design of a larger 5 MW unit is also in progress. The well-known DEMO 2000 program launched in Norway in 1999 is aimed to qualify and eventually market deepwater E&P technology through a pilot demonstration. As indicated by the rating of the pilot units (2.5 and 5 MW), gas compression is very power-intensive. This is inherent to the nature of gas thermodynamics and not necessarily because of mechanical inefficiency. Providing the large amount of power required subsea is a big technological challenge, perhaps more so than the compressor development. Design options for gas transport under natural pressure should be exhausted before serious consideration is given to subsea compression.

Hydrate inhibition

With or without compression, the gas entering the subsea pipeline will be saturated with water vapor. Water condensation may take place along the length of the pipeline as the deepwater environment cools the gas. Depending on operating pressure, hydrate formation may become a problem. Chemical inhibition is the most cost-effective option to prevent hydrate formation. Because water condensation in the pipeline can be adequately predicted and the amount is relatively small, steady injection of ethylene glycol can be very effective. The glycol/water solution can be scrubbed from the gas at the host platform, and the glycol can be regenerated and reused to minimize losses.

Dewpoint control

Not only is the gas saturated with water vapor as it enters the pipeline, but it is also at its hydrocarbon dewpoint. Like moisture, hydrocarbon compounds can condense with cooling along the pipeline. Depending on composition and system equilibrium, the amount of liquid can be considerable, and pipeline pressure drop and flow dynamics will be adversely affected. To prevent this from happening, separator gas may be dewpoint-controlled prior to entering the pipeline. This can be achieved by the standard gas-plant process of expansion cooling, followed by liquid knockout. The recovered liquid can be injected into the separator liquid stream and transported with the oil. A number of subsea expanders/compressors are being developed. Most are based on the well-known principle of isentropic expansion with a turbo-expander. One device that uses revolutionary technologies and has the potential to be very favorable for seabed applications is the Twister.

The Twister supersonic gas separator combines the three gas-conditioning functions in a single static unit (Fig. 11):

  • expansion cooling
  • condensate separation
  • gas pressure recovery

It is especially well suited for subsea service because of its compact design and lack of moving parts. Performance of the device, based on aero, fluid, and thermodynamic principles, has been demonstrated through advanced computational fluid dynamics and field trials. Shell Technology Investments Partnership markets the technology. More information can be obtained at Twister’s website: (link). Standard topside versions of Twister are commercially available. Units appropriate for seabed applications are being developed and expected to be available soon.

The Twister has the capability to lower the water and hydrocarbon dewpoints of the gas and to recover water and hydrocarbon condensate in one device. The gas-conditioning package would include the Twister and an engineered system to preprocess and inject the recovered liquids for pipeline transportation and/or disposal.


  1. Davies, S. 2000. Modular Subsea Processing Concepts Employing Compact Technologies. Paper presented at the 2000 Seabed and Downhole Technologies Conference, Aberdeen, 21–22 March.
  2. Hickok, D. 1996. Production Control Systems Deep Water Installation and Maintenance Features. Presented at the International Petroleum Conference and Exhibition of Mexico, Villahermosa, Mexico, 5-7 March 1996. SPE-35350-MS.
  3. Campbell, P.F., Lawlor, C.D.F., and Inglis, A.E. 1996. The East Spar Development - Novel Subsea Production System Allow Optimum, Low Cost Development of this Remote Field Australia and Control Buoy Offshore Western. Presented at the Offshore Technology Conference, Houston, Texas, 6-9 May. OTC-8178-MS.
  4. Casey, M.D. and Lawlor, C.D.F. 1996. Development and Testing of a Novel Subsea Production System and Control Buoy for the East Spar Field Development, Offshore Western Australia. Presented at the SPE Asia Pacific Oil and Gas Conference, Adelaide, Australia, 28-31 October 1996. SPE-36966-MS.
  5. Cottrill, A. 1997. Brainstorming Alliance Makes East Spar Fly. Offshore Engineering (February).
  6. Edwards, W.G. 1993. Subsea Metering for Fiscal, Allocation and Well Test Applications. Subsea International 93.
  7. Mariani, A., Valter, Q. and Kjell, O. 2001. The Nuovo Pignone/Kvaerner SCCM Subsea Centrifugal Compressor Module for Deepwater Applications. Paper presented at the 2001 Deep Offshore Technology Conference, Rio de Janeiro, 17–19 October.

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See also


Subsea processing benefits

Subsea processing design

Subsea process configurations

Subsea processing overview

Downhole processing overview