PEH:Subsea and Downhole Processing
Petroleum Engineering Handbook
Larry W. Lake, Editor-in-Chief
Volume VI – Emerging and Peripheral Technologies
H.R. Warner Jr., Editor
Copyright 2007, Society of Petroleum Engineers
Chapter 4 – Subsea and Downhole Processing
As easily accessible petroleum basins have matured, exploration and development have expanded farther offshore and to remote areas. New development challenges are in deep water and in marginal fields with smaller reserves. The facilities required in these new developments are similar in function to conventional processing facilities, but the packaging requirements can be quite different. Process facilities can now be placed literally anywhere between the reservoir and the product pipeline, including subsea and downhole. Obviously, minimizing surface equipment size and weight reduces costs for deepwater platforms. In addition, the trend of tying smaller fields to a larger processing facility, in a hub-and-spoke arrangement, has led to novel production approaches. Oil/water or liquid/gas can be partially separated closer to the reservoir to reduce the size of surface equipment, eliminate or reduce the size of flowlines, or to facilitate pumping. Remote pumps or compressors can either reinject unwanted fluids or transport produced fluids to a distant central processing facility. Subsea and downhole equipment can accomplish these tasks when surface facilities would be prohibitively expensive. What subsea and downhole processing have in common is that each is a means of processing produced fluids remotely to reduce facility development costs, in more harsh and confined environments than is typical of surface equipment.
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 reduce development cost, enhance reservoir productivity, and improve subsea system reliability and operability.
Over the period from 1970 to 2000, millions of dollars have been 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 has not rushed to deploy the technology on a commercial basis. However, as the industry moves 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.
Why Subsea Processing?As oil and gas production moves into deeper water, the cost of surface production platforms becomes prohibitively high. The industry has found that surface facilities must be kept to a minimum and shared by satellite fields to be commercial. Subsea processing is a key toward a cost-effective, "hub-and-spoke" development (Fig. 4.1), allowing the industry to operate successfully in deeper water.
Subsea processing refers to the separation of produced fluids into gas and liquid—or gas, oil, and water—for individual phase transport and disposal (in the case of water). The liquid stream can be pumped to a central facility for final processing. The gas stream can be transported under natural pressure, or pressure boosted (compressed) to the host facility.
The current practice is to flow produced fluids from subsea wells directly back to a central surface processing facility in multiphase (gas, oil, and water) pipelines, known as a "subsea tieback" field development. Because reservoir pressure is the only source of energy to overcome all the impediments to flow [e.g., pressure drop through the formation, wellbore, tubing (friction and static head), tree, flowline, and so on] well productivity for normally pressured reservoirs tends to be low, and the "tieback" distance is typically limited to less than 25 miles. In addition, multiphase pipelines potentially have many flow-assurance problems, like fluid slugging, hydrate formation, wax deposition, and solids dropout (see the chapter on flow assurance).
Subsea processing offers a technical solution to many of these problems. It can accomplish the following:
- Improve well productivity with greater pressure drawdown.
- Increase ultimate recovery by extending economic life.
- Eliminate fluid surges by use of single-phase pipelines.
- Avoid gas hydrates with no inhibition or with reduced inhibitor dosage.
- Prevent solids dropout by allowing higher liquid-flow velocities.
- Allow online pigging to control wax deposition in oil pipelines.
- Reduce capital and operating costs by reducing surface processing needs.
Improved Reservoir Productivity. A key benefit of subsea processing (separation and liquid pumping) is greater pressure drawdown, which results in higher production rates and greater oil and gas recovery. Separating the produced fluids on the seabed allows the liquid to be pressure-boosted with an efficient conventional mechanical pump. Single-phase pumping overcomes the static backpressure of the fluid column from the seafloor to the surface, and it avoids the excessive pressure drop and surges of multiphase flow.
As illustrated in Figs. 4.2 (left) and 4.2 (right), for a typical deepwater development in 6,000 ft of water, flowing tubing pressure at the seabed may be 1,800 psi, even with a separator inlet pressure of only 200 psi on the platform. Much of the 1,600-psi pressure drop takes place because of hydrostatic head of the fluid (gas and liquid) column. If the separator can be located at the seabed, a significant portion of the 1,600 psi can be used as additional reservoir pressure drawdown. Assuming a modest productivity index (PI) of 5 bbl/psi, a production increase of 8,000 B/D per well may be realized. As reservoir pressure declines, reduced backpressure may extend the productive life of the field and increase ultimate hydrocarbon recovery. Because productivity and reserves recovered per well are key to field economics, use of subsea processing can greatly enhance the value of some deepwater developments.
With subsea separation and liquid pumping, most of the energy required to transport the produced fluid is supplied by mechanical means rather than totally by reservoir pressure. Subsea liquid pumps are currently available for most applications. Separator gas can flow long distances under natural pressure. As advances are made into large-capacity subsea power supply and compressor systems, subsea gas compression will become another viable option, enabling smaller pipeline size and even longer transport distances.
Flow Assurance. Flow-assurance problems such as multiphase flow, hydrate formation, and wax deposition are detrimental to deepwater and long-distance subsea tieback projects. In a direct tieback, fluid slugging, excessive pipeline pressure drop, and startup dynamics can cause major operational difficulties and require large investments in topside facilities. Gas hydrate formation is difficult to avoid in the high-pressure, cold deepwater environment. Using insulated and heated bundles and large quantities of chemical inhibitors are costly and not effective under all circumstances. With waxy crude production, pipeline plugs are a constant challenge. Because there is no universal inhibitor for wax, finding an effective chemical for a particular crude is always uncertain and sometimes not possible. Regular round-trip pigging (in a dual pipeline system, sending a pig from the host platform to the subsea well manifold and returning it by a crossover into the other pipeline) is the only reliable solution. But this method of pigging requires production shutdown that can be lengthy because of difficulties in restarting the wells and re-establishing flow.
Subsea processing can be a cost-effective solution to flow-assurance problems. In a subsea system depicted in Fig. 4.3, wellstreams are separated and transported in separate pipelines, which eliminates multiphase flow and associated problems. Separator gas entering the pipeline is saturated with water; therefore, hydrate formation is still a concern. However, the amount of water that must be inhibited to prevent hydrates is relatively small and very predictable. This eliminates the need for overinjection of inhibitor to combat water slugs and allows the use of the more environmentally friendly inhibitor, glycol, which can be easily recovered and regenerated at the host platform. Unlike methanol, glycol has a very low vapor pressure and is less prone to vaporization losses.
Topside Facilities Limitations. With subsea processing, produced fluids arrive at the host platform already separated into their respective phases, so the need for large slug catchers and separators is reduced or eliminated. Degassed oil and water may be further separated at the seabed, and the produced water reinjected back into subsea wells. Seabed separation and water reinjection increase oil pipeline capacity, reduce pipeline internal corrosion and water treatment on the surface, and reduce overall power demand. This is the natural progression from two-phase (gas-liquid) separation as the field matures and water production increases.
Unmanned and Minimum Facilities Developments. One way to reduce field development costs and improve project economics is to increase well productivity and reduce facility costs. As discussed earlier, subsea processing can improve well productivity and increase ultimate recovery. It can also enable unmanned minimum production facilities developments that do not need costly pipelines. An illustration of such an infrastructure independent system is shown in Fig. 4.4.
An infrastructure independent development for a remote deepwater field is built around subsea processing. Fluids produced by subsea wells are separated in a subsea separation system. The gas is routed to the surface for conversion to liquefied natural gas (LNG) or compressed natural gas (CNG) and tanker transport. Separated oil is routed to a seabed-grounded tank, where it is stored until sufficient volume has accumulated for tanker offtake. A local unmanned buoy can provide power and control functions. Most of these technologies either are being, or have been, deployed in some form. Subsea wells are well accepted and commonly used. Subsea processing technologies are beginning to be employed with the advent of deepwater developments.
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.
Existing ApplicationsDespite 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. 4.5a).
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. 
BOET. The British Offshore Engineering Technology (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. 4.6a and 4.6b).  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.
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. 4.9a and 4.9b).  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.
Gas/Liquid Separation and Liquid Pumping. By separating the gas and liquid phases and pumping the liquid stream, this simplest of systems will capture most of the benefits of subsea processing. It will reduce backpressure to the wells and eliminate problems associated with multiphase flow. Although the liquid (oil and water) stream must still be processed at the host platform, two-phase separation may be the best compromise for cost, function, operability, and maintainability. Two keys to success for subsea systems are weight and reliability. Gas/liquid separation can be achieved in a relatively small vessel (see the chapter on separators). Typically, vapor/liquid equilibrium can be achieved with liquid residence time of 1 minute or less, in contrast to oil and water separation, which requires 5 minutes or more. In addition, compact designs based on cyclonic principles are available for gas/liquid separation, which allows those units to be even smaller. Because the subsea vessels for deep water must be designed for external collapse pressure (because of seawater hydrostatics), compact vessels can significantly reduce system weight and cost. In addition, the lighter and more compact separator will allow whole system retrieval without heavy-lift vessels, making installation, retrieval, and maintenance costs lower. Reliability will improve because the facilities can be tested as an integrated system on the surface prior to installation.
Water Separation and Disposal. With some reservoirs, water breakthrough can significantly reduce pipeline capacity and increase surface treating costs. For existing facilities, such as Troll "C," where limited platform space makes expansion of the water separation and treatment system difficult and costly, subsea separation and water injection may be an attractive solution. In the Troll Pilot (see previous discussion), produced water is removed in a three-phase separator and injected in subsea disposal wells. Supplemental injection pressure is provided by electric-motor-driven subsea pumps. Oil and gas are commingled and transported to the host platform in a mixed-phase pipeline. Whether or not to transport separated oil and gas in a single-phase pipeline is an economic decision. The value of the production uplift, flow-assurance benefits, and operability improvement must outweigh the extra cost of a two-pipeline system. Because Troll is in relatively shallow water, produced-water removal at the seabed has the greatest impact on flow-induced friction, while the reduction in hydrostatic gradient is less significant. Troll chose to use a single mixed-phase pipeline. For deepwater fields or longer tieback distance, the economics may be different.
Three-Phase Separation. The ultimate goal of subsea processing is to achieve efficient gas/oil/water separation, gas compression, oil pumping, and water disposal. This would transfer the bulk of the production facilities to the seabed and enable lower separator pressure than otherwise can be achieved. But before embarking on such an ambitious goal, one should consider the following:
- The larger and heavier three-phase separator that would be required, and the implication that it has on modularization, installation, and maintenance options.
- Heat input or chemical demulsifier injection that may be required to effect good oil/water separation.
- Water quality and monitoring required to maintain adequate disposal-well injectivity.
- Technology required to supply the large amount of power for gas compression.
- Operation and maintenance of relatively complex compression equipment.
Given the developing state of subsea processing, it is better to start with simple systems that yield the largest impacts and progress slowly into the more complex systems. Until the industry has gained confidence and greater know-how on equipment marinization, deepwater installation, mechanical equipment operations, and maintenance, the risks associated with subsea three-phase processes are quite high.
Design ConsiderationsReservoir Characterization. The value of subsea processing is determined primarily by reservoir characteristics and water depth. Well productivity index (barrel per psi drawdown or PI), which is a function of reservoir permeability, is one of the keys. A high PI will leverage the reduced backpressure provided by subsea processing to higher production rates. This can have enormous economic implications for low-pressure reservoirs in deep water. With depletion-drive type reservoirs, the benefit will increase with time as reservoir pressure declines. Increasing water production will make the pressure-boosting effects of subsea processing more dramatic. For reservoirs without competent source rocks, good completion design is imperative to take advantage of the greater pressure-drawdown opportunity. If the well is choked back to avoid excessive sand production or formation damage, the full potential of subsea processing will not be realized. Because subsea processing can only impact the fluid column from the seabed to the surface, shallow reservoirs in deep water play to its strength. This is illustrated by Fig. 4.12 for a typical depletion reservoir.
As depicted in Fig. 4.12, the incremental recovery factor for subsea separation decreases with reservoir depth. Pressure boosting is most efficient when applied at the source. As reservoir depth increases and/or water depth decreases, downhole processing is more beneficial.
Water Depth and Tieback Distance. The benefits of subsea processing increase with water depth and tieback distance. However, they also present greater technological challenges. Water depth has the greatest impact on liquid pumping. Because the separated oil must be pumped to the surface, the subsea pump must be able to generate high enough pressures to overcome the hydrostatic head of the liquid column and the flow-induced friction in the pipeline. In most applications, this would require multistaged centrifugal pumps operating at the low end of their flow range. The high-head, low-flow requirements narrow the operating range of the available subsea pumps, making pump selection difficult. Although for most fluids the liquid-pumping energy requirement is much less than that of gas compression, it is still a challenge to supply subsea, given the state of the technology. Electric motors or hydraulic turbines may be used to drive the pump. However, both types of systems have limitations.
Until the challenges associated with subsea gas compression can be solved, gas must be piped to the host platform under natural pressure. Given the low specific gravity of gas, water depth, which impacts pressure drop because of fluid head, should not be an issue. However, long-distance tieback can be a challenge. Subsea processing provides greatest benefit at low seabed separator pressure, so the gas pipeline must be sized for minimum pressure drop. That usually means larger diameter, and thus higher cost. Gas leaving the separator on its way to the pipeline is at its hydrocarbon and water dewpoints. It is important for pipeline hydraulic performance that heat exchange with the seawater environment and gas phase equilibrium be carefully balanced to avoid excessive liquid condensation in the pipeline.
Separation Philosophy. As discussed in the process configuration section, subsea processing can range from simple two-phase separation to a complex gas/oil/water separation for individual phase transport and/or disposal. The choice depends on what one is trying to achieve with the system, how difficult the fluids are to separate, expected value to be gained by the project, and risk tolerance. Separation philosophy will drive the system design and ultimately the success of the project. The state-of-the-art should be carefully considered at the time of decision. Subsea technologies are advancing rapidly. What was once deemed high-risk (i.e., subsea well systems) is common practice today. All forms of subsea separation may well be at that mature state by the time they are needed.
Capacity of Topside Facilities. A driving force for subsea processing is the lack of topside capacity at existing host platforms and high cost for facility expansions. Because of fluid slugging potentials, direct tieback using multiphase flow pipelines may require unacceptably large slug catchers. Space may not be available for the additional phase-separation and water-treating facilities. With partial or full processing on the seabed, the need for topside facilities may be significantly reduced. Availability and cost of topside capacity may influence the degree of preprocessing that makes sense on the seabed. As with most engineering decisions, life-cycle economics (capital and operating costs) will dictate the most cost-effective design.
Operating Range and Turndown Requirement. Production rates will vary over the life of the field, as gas/oil ratio and water cut increase and reservoir pressure declines. All production systems must function over the expected operating range. In fact, some systems are asked to operate out of their design range because it is nearly impossible to predict with accuracy field performance before first production. It is not unusual for topside facilities to be modified to accommodate out-of-the-range operations, sometimes only shortly after startup. The consequence of missing the mark with subsea processing can be very costly. Whereas surface facilities are easily accessible, subsea system interventions may require special equipment that is not readily available, such as Remote Operating Vehicles (ROVs), heavy-lift vessels, dedicated tools, and instruments. Protracted loss of production and callout costs could doom the economics of a project. All these factors must be addressed in the subsea system design and the risk mitigated with robust and flexible engineering and equipment selection. It is imperative that a best effort be made to define the expected operating range and the equipment turndown capability required. It may not be possible for certain pieces of equipment to operate efficiently over the life of the project. In this case, a thorough contingency plan, perhaps with the system designed for scheduled equipment replacement, needs to be developed and taken into account in determining the project economics.
Instrumentation and Monitoring. In many ways, operations of subsea facilities may be more stable because there is less opportunity for operator tinkering. By their remote nature, subsea systems are engineered with a high degree of automation. Nuisance trips because of human errors should be reduced. However, the consequences of instrumentation failure are much more serious. System reliability will depend on the robustness of the instrumentation and quality assurance/quality control (QA/QC) of the installation. When these systems fail, as they inevitably will, a well-designed monitoring system will speed problem identification. The importance of proper control system design, instrument selection, and installation cannot be overemphasized.
Well-Test Requirement. How and what well-test data are to be acquired (for reservoir management and well-system diagnostics) are always contentious with subsea well and processing systems. To reduce equipment count and cost, some have proposed a system of well test by difference, that is, to shut in a well, and the loss of production is attributed to that well. The drawback is that production is lost during the test period, and bringing back the well may be problematic. Others have proposed using a dedicated well-test system, such as a separate test separator and manifold, similar to those facilities on the surface. The components for subsea well-test separation system are available and essentially the same as for the main separation system, but add tremendous complexity, size, cost, and potential risk of failure to the overall system. A more cost-effective option may be the use of subsea multiphase meters. A meter installed on each wellstream can provide individual real-time production data. These nonintrusive devices are submarine versions of their well-proven surface counterpart. Although they are not yet commonplace items (only a few dozen in service as of 2002), they are gaining acceptance in the subsea community. Meter performance, quality, and reliability have improved, while the cost has dropped with successive generations.
Technology ComponentsSubsea processing is not a single technology, but the integration of complementary technologies that include fluid chemistry, process, separation, rotating equipment, power transport and distribution, instrumentation, and control, all in a subsea context. 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 (i.e., rapid heat loss to a colder ambient, long flow lines, and tall risers) may be more dramatic and detrimental.
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, and cost. For two-phase separators, the design-limiting parameter is usually the gas rate, which is controlled by gas-liquid ratio, temperature, and 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, or 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.
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, and 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.
Marinization. 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.
Driverless 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. 4.13.
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 separator, pump, electrical or control systems (Fig. 4.14).
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. 4.15 is an illustration of the pig launcher for the East Spar project in Australia.
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. 4.16) have been developed that can be used topside or on the seafloor.  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.
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 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. 4.17). 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.
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. 4.18). More ambitious designs with a capacity of 36 kV are under consideration.
Variable Speed-Control Electric Motor. A primary method of controlling centrifugal pump output is to vary its speed. 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. 4.20). Actuators for isolation and modulating service should be available in a few years.
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.  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.  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.
Instrumentation. 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.
Water-in-Oil. 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.
Flowmeters. As discussed in an earlier section, multiphase meters for subsea service are available. 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.
Compression. 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.  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: expansion cooling, condensate separation, and gas pressure recovery in a single static unit (Fig. 4.23). 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: http://www.twisterbv.com. 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.
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 CAPEX and OPEX savings against the uncertainties and risks associated with an emerging technology.
CAPEX. 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 hardware, packaging, system integration, and 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.
What is Downhole Processing? Many oilfield processes normally employed on the surface may be adapted to downhole conditions. Examples include phase separation, pumping, and compression. Sometimes the design specifications for downhole processes may be looser than surface processing because control is more difficult. Partial processing, in which fluids are separated into a relatively pure phase stream and a residual mixed-phase stream, are most common. Gas/liquid separation, oil/water separation, water injection and disposal, and gas injection are possible with these technologies. Downhole separation technology is best suited for removing the bulk (50 to 90%) of the gas or water, with downstream surface or subsea equipment being used to "polish" the streams for complete separation. In the case of gas separation, even with complete separation downhole, dissolved gas will evolve from the liquid phase as the pressure drops when the oil flows to surface. Because of this dissolved gas, it is not possible to obtain a pure liquid phase at the surface. In addition, some gas in the liquid phase is often desirable, to help lift the liquid up the tubing.
Reasons for Downhole Processing. The reasons for downhole processing are as diverse as the challenges facing a new or mature oil or gas field. It can provide a supplement/alternative to surface processing or improve well hydraulics. Existing surface facilities may have limited capacity and require some form of debottlenecking. They may have high water-handling costs, such as chemicals. Gas can be separated and reinjected downhole, debottlenecking surface reinjection compressors. Downhole processing may reduce the size and weight of surface facilities, which is desirable for offshore and remote areas. Remote wells may be drilled far from existing production facilities, requiring transportation of fluids at significant operational and capital cost. Surface transportation and processing of produced fluids incurs greater environmental risks of spills or emissions. To increase well production, water can be separated and reinjected downhole to unload gas wells and improve hydraulics. Gas may also be separated from oil streams downhole to improve tubing hydraulics at very high gas fractions. Some researchers are investigating the concept of a downhole water sink, in which water below the oil/water contact is produced and reinjected to reduce coning and increase oil recovery. In multilateral wells, one leg of the well can be used as a water or gas injector, providing greater offset from the producing leg.
Well Completions for Downhole Processing. For the lowest costs and ease of maintenance, placement of downhole processing equipment through tubing is desirable. Otherwise, a workover rig is required to pull the tubing to install or replace the equipment. Usually, wireline or coiled-tubing placement through tubing is a more cost-effective alternative, but sometimes finding equipment that will fit within even the casing diameter is a challenge. Because many wells that may benefit from downhole processing are existing, mature wells, the feasibility of retrofit is a consideration. Even when retrofit is possible, usually installation of this equipment is easier and more effective if the well is designed for this possibility from the beginning. Another factor in both new and existing wells is the integrity of the completion. This is particularly important when water or gas is reinjected in the same wellbore that is producing. If there is not adequate zonal isolation by a good cement bond, the injected fluid can "short-circuit" back to the producing zone. When this happens, the benefits of downhole processing are not achieved.
Influence of Downhole Equipment Development on Surface Equipment Design. The small size required of downhole equipment has led to revolutionary changes in the size of surface processing equipment. Development of equipment that must be only a few inches in diameter is on a radically different scale from that of most surface equipment. Examples of this influence have been seen in new equipment designs for cyclonic phase separation, pumping, and gas compression. The crossover flow of technology development between subsurface and surface equipment has recently increased. For example, downhole ESPs are now being used on the surface for water-injection booster pumps.  Compact separation equipment is also used both on the surface and downhole.
A conventional development normally involves many wells feeding through flowlines to a central processing facility that is designed to separate oil, gas, and water from each other and prepare each stream for sale or reinjection/disposal. Onshore, or in shallow water, large equipment is preferred because it is more tolerant of upsets, and smaller size and weight have no significant advantage. But most convenient, easily accessible reservoirs have already been discovered and developed. New exploration often focuses on areas farther offshore and in remote areas that are more difficult to develop.
Drivers for downhole processing include remote wells, cost of deepwater production structures, long-distance or subsea pipeline costs, chemical costs for water handling, corrosion, and environmental concerns. Capital and operating costs can be reduced by taking advantage of existing facilities and bringing smaller "satellite" fields into that existing infrastructure. But that infrastructure may have processing limits that require some upstream (i.e., downhole) separation and disposal of either gas or water to allow oil to enter the facility. In new developments, partial processing downhole may reduce the size and weight required for surface equipment. Emulsion and corrosion chemical costs are often determined by the amount of water production and may be reduced if water is removed downhole within the well itself. Emissions of greenhouse gases may be reduced by downhole processing as an alternative to flaring or venting produced gas.
Use of downhole equipment has been driven by the hydraulics and production requirements of individual wells rather than by the overall development plan. Examples of this are the various forms of artificial lift: ESPs, rod pumps, progressive cavity pumps (PCP), jet pumps, and even gas lift. Prior to 1992, no downhole processing was performed except that related to conventional artificial lift of wells. Since then, new downhole separation technology has been conceived, with field installations and tests following, as described hereafter. Even now, application of the technology is sparse and would still be characterized as proving the technology rather than routine application. As is the case with most new technology development, many of the field tests were done with wells that were already so marginal that there was little to lose. By 2002, there were approximately 50 downhole water separation/injection installations and approximately 60 downhole gas/liquid separation installations. Increasingly, though, downhole processing is gaining wider use and is being considered as part of overall field development strategy.
Technology FundamentalsGas/Liquid Separation and Injection. The most common method of separating liquid (oil or water) and gas is by density difference. Because of the relatively large differences in density between liquids and gas, this separation is normally easier than oil/water separation, where the densities of the phases are much closer. In a conventional vessel, the force of gravity allows liquid droplets to settle from the gas within a designed residence time. Special internal vanes in the upper portion of the vessel may be used to promote droplet coalescence and improve gas quality. Sometimes antifoam chemicals are required to reduce foaming. In more compact separator designs, various cyclonic devices are used to impart a rotation on the fluid flow, effectively centrifuging the fluids and accelerating separation. Because of space limitations downhole, centrifugal separation, either by rotating or stationary blades, is usually required except for relatively low-rate wells.
Gas separation upstream of ESPs is conventional technology that has been practiced since these pumps were invented. Some of the power supplied to the pump is used to spin a rotor in the gas separator, which centrifuges the fluids and separates gas from the liquids. This is discussed in more detail in the section of the Handbook that addresses ESPs. Gravity separation of gas in the wellbore for rod pumping is also conventional and discussed elsewhere.
Newer gas/liquid separator designs have also been developed. The auger separator uses stationary auger blades to impart rotation for separation.  As the fluid is forced to follow the path of the stationary auger blades, the rotation forces the liquid to the outside wall. Part of the gas is then drawn out of the center and ported to the annulus by a crossover tool. The advantage is that no moving parts are required and the equipment can be placed through tubing. A schematic of the auger separator downhole installation and a photo of the internals is shown in Fig. 4.24.
Fig. 4.24—Downhole auger separator.
ESPs are another alternative for water injection, and would be configured as a bottom-discharge system with the pump below the motor rather than in the conventional motor-on-bottom design. ESPs provide for very high disposal rates and are generally more economical in deeper wells. Another alternative is a rod-string-powered progressive cavity pump.
Downhole pumping of liquids is common with ESPs, jet pumps, and rod pumps. Now compression of gas downhole is being attempted as well. The subsurface processing and reinjection compressor (SPARC) is under development for downhole gas separation, compression, and reinjection. A turbo-expander is used to recover energy from part of the separated flow stream, and it uses that energy to compress the other fraction. Because of the small diameters available in a well, the rotational speeds of the turbine and compressor are very high—on the order of 100,000 rpm. Preliminary engineering has been done, engineering development of the components and control systems are ongoing, and field testing is planned. 
Oil/Water Separation and Injection. The most common application for downhole water/oil separation is water injection, either into the reservoir for enhanced recovery [waterflood or water-alternating-gas (WAG) miscible flood], or into a dedicated disposal zone which may lie either above or below the producing zone. Possible benefits of downhole disposal include the following:
- Reduced energy to pump water to the surface.
- Water-handling system debottlenecking without adding or modifying existing surface equipment.
- In some cases, lower chemical costs for scale inhibitors, corrosion inhibitors, and emulsion breakers.
- Less water handling on the surface, and therefore a lower risk of large surface spills.
- Increased oil rates and recovery through reduction of water coning from aquifer.
Bulk oil/water separation is predominantly based on density difference. Two basic types of downhole oil/water separation (DOWS) systems have been developed: hydrocyclone separation combined with a downhole ESPs or a rod pump, and gravity separation with production by rod pump.  Although gravity separation in the wellbore may be possible for low-rate wells, hydrocyclones are far more effective compact separation devices because the rotation centrifuges the fluids, accelerating gravity separation beyond 1 "g." The hydrocyclone systems can handle up to ten times the volume of water that can be handled with gravity systems, which have a limit of approximately 1,000 BFPD. The principles of hydrocyclone operation are the same as those for surface hydrocyclones, discussed in the separation section of the Handbook. The downhole challenge is not so much with the hydrocyclones, but with the passageways to port the separated fluids within a very confined tubing or casing diameter. The outlet streams from a hydrocyclone are a clean water stream and an oil stream with reduced water cut compared to the original fluid mixture. The water cut of the separated oil stream is typically in the range of 10 to 50%, vs. up to 90% for the original mixture.
A hydrocyclone system separates oil from water and uses one or two pumps to inject the water and lift the oil to surface. Two modes of operation are possible: the "pump-through" system (Fig. 4.27), in which reservoir fluids are pumped into the separator, and the "pull-through" system (Fig. 4.28), in which the reservoir provides the pressure to enable flow through the separator and the separated fluid volumes are pumped in their respective directions. A second booster pump can be incorporated into the pump-through system, as shown in Fig. 4.27, to provide additional lift of fluids to surface. One advantage of pump-through systems is that free gas is dispersed, compressed, and put back into solution by the pump upstream of the separator. Another advantage is that one submersible pump may be sufficient, reducing equipment cost and simplifying controls. The advantage of pull-through systems is that emulsions are minimized because the fluid is not sheared by the pump before separation. Single-tube hydrocyclones have hydraulic capacities ranging from 500 to 2000 BFPD. For high flow-rate wells, several hydrocyclones can be combined, with the outlets from each flowing into manifolds, as shown in Fig. 4.29.
Fig. 4.27—Pump-through system with booster pump.
Fig. 4.28—Pull-through system.
Fig. 4.29—Multistage pump-through system. 
A special application of downhole water separation and reinjection is the deliberate production of water from an underlying aquifer to prevent water coning into the oil zone perforated interval.  Perforating the aquifer zone in a dual completion and producing this water provides a hydraulic "sink," depleting water pressure near the wellbore, and reducing the driving force for coning. This approach is applicable when water production is attributed to coning, but not when water production is caused by waterflooding. Physical models and reservoir simulation indicate that this can increase recovery by as much as 70%, as well as shorten recovery time significantly. The tradeoff for this is that more total water must be handled. Downhole reinjection into a separate disposal zone allows this additional water to be produced without having to be handled on the surface.
Screening Criteria: Rules of Thumb
As with most technology, proper candidate selection is key to success. Separation equipment operating ranges, wellbore design, and reservoir geology all affect how well downhole separation will work. The economics are often determined by the number of and locations of the wells and by the overall geographical development plan. It is important to recognize that downhole processing is not a substitute for prudent profile control of wells through workovers, gel polymer treatments, cement squeezes, and so on. The following discussion applies to both gas/liquid and water/oil processing, followed by sections that discuss screening criteria specific to each.
From an equipment standpoint, gas/liquid separation is much easier than oil/water separation. This generally means that it is a more robust application. The same considerations relevant to surface separation apply—foaming tendency, emulsion formation, fluid density, and viscosity should be considered when evaluating the feasibility of a downhole process.
All separation and pump equipment has an expected lifetime that is typically much shorter than the lifetime of the well. The cost of replacing or repairing the equipment must be considered as well as the initial capital cost. Some equipment can be placed through tubing by wireline or coiled tubing, which is usually most cost-effective. Replacing other equipment requires that the tubing be pulled by a rig. These workovers are relatively inexpensive onshore, more expensive in the shallow offshore, but can be very expensive for deepwater subsea wells. Well completions originally designed for downhole processing work best, but a number of the systems can be retrofitted in existing wells.
For downhole injection, a suitable injection zone is required. It must be hydraulically separate and have a high enough injectivity that the desired volumes can be injected, either with pumps/compressors or by natural overpressure. The relative locations of these zones determine the required well completion and feasibility of downhole processing.
Many other factors are important when deciding to perform processing in a well vs. a centralized facility. Centralized facilities tend to become more economical as the number of wells increases. The centralized facility may be a typical surface processing plant or a satellite processing facility (surface or subsea) that performs partial processing and sends the partially processed stream to a traditional facility for polishing. Downhole processing is also favored when wellbore hydraulics limit production.
The economics of downhole processing are driven also by the geographic location of the wells and the proximity of the individual wells to each other and to the processing facilities. Downhole processing is more economical for remote wells, where transportation costs to facilities are high.
Gas/Liquid. Gas may be separated in a number of ways, depending on well flow rate and completion design. For low-rate wells, gravity separation in the wellbore can be achieved, with the liquids flowing to the tubing that extends below the perforations and the gas flowing up into the annulus. This is common for beam-pumped wells and some ESP completions. Standard Stokes' law settling calculations, those used for surface separator design, can be performed to determine whether gravity separation is feasible for the gas and liquid production rates. The centrifugal gas separators upstream of ESPs provide a more active method of separating gas, and they work well when rates are too high for gravity separation and when ESPs are already planned for artificial lift. The auger separator is an alternative centrifugal separator with no moving parts. It performs a less complete separation than the ESP rotating separators, typically removing 60 to 80% of the gas, vs. almost 100% for an ESP separator.
Tubing and casing size are very important. These often determine whether the equipment can be placed through tubing or require that the tubing be pulled by a workover rig. These tubular sizes also determine the maximum separator and pump equipment diameters. Diameter restrictions may dictate that several stages of ESPs and hydrocyclones are required for the expected production rate.
An economic comparison of various DGWS technologies with conventional water separation facilities showed that the selection of an appropriate DGWS tool is primarily a function of water flow rate and well depth.  That study provided the following approximate rules of thumb:
- For water production rates less than 50 B/D, conventional surface disposal is most cost-effective.
- Bypass tool systems are more cost-effective in the 25- to 250-B/D range, up to a maximum depth of about 8,000 ft.
- A modified plunger system was shown to be most cost-effective for 250 to 800 B/D over approximately the same depth range.
- For high water rates (> 800 B/D) and at depths below 6,000 ft, ESP systems are typically more cost-effective.
The same study also determined that a DGWS system stands the best chance of success when it is installed in a well with the following:
- Well-cemented casing.
- Minimal sand production.
- Water with little scaling potential.
- Water production of at least 25 to 50 B/D.
- Disposal costs greater than U.S. $25 to $50/D.
- A low-pressure, high-injectivity disposal zone below the producing interval.
The full report,  which is available on CD and includes an interactive economic model to facilitate evaluation of candidate wells, is available from the Gas Technology Inst. at www.gastechnology.org/.
Oil/Water. Hydrocyclones are the oil/water separators of choice for downhole applications, and the equipment limitations are similar to those for surface hydrocyclones. Some of these limitations are as follows:
- Separation is more difficult for heavier (low API gravity) oils because the density difference between low API gravity oil and water is small. The minimum density difference is 2 API or 0.02 g/cm3. Separation is also more difficult when droplet sizes are small, such as in water-polishing applications. Small droplets experience high viscous forces, which retard separation, compared to the density difference.
- Gas fraction is limited to approximately 10% by volume. If more gas is present, it must be separated upstream of the hydrocyclone.
- The water cut must be high enough so that the mixture forms a water-external emulsion. This water-cut level varies with individual oil and water properties, but normally occurs at relatively high water-cut levels—greater than 50%. Manufacturers of downhole hydrocyclones recommend that the water cut be 75% or higher.
- The propensity of an oil/water mixture to form an emulsion also affects the hydrocyclone performance. Some emulsions are very difficult to break without chemicals and/or heat. Chemicals may be added at the pump intake or by chemical squeeze into the formation. Many emulsions are formed by fluid flow and shear in chokes and valves and so may be less common downhole, where temperatures are also higher than on the surface.
- Viscosity must also be considered. Viscosity may be high either because the oil has a low API gravity or because temperatures are low. The maximum allowable inlet fluid viscosity is approximately 10 cp.
- Hydrocyclones transform pressure energy into rotational kinetic energy to centrifuge the fluid. Because of this, some pressure drop is required. This is typically in the range of 50 to 200 psi. High bottomhole pressures caused by surface production bottlenecks are favorable.
Placement in a wellbore constrains downhole equipment to diameters much smaller than typical of surface equipment. Downhole hydrocyclone equipment requires a minimum casing size of 5½ in. (internal diameter of approximately 4½ in.). The diameter restrictions may limit production rate through the separator or may require that a series of multiple hydrocyclone tubes be used. A single hydrocyclone tube has a hydraulic capacity of approximately 500 to 2,000 BFPD. Typical flow rates with multiple tubes are 500 to 4,000 B/D in 5½-in. casing with 2 hydrocyclone tubes, 1,500 to 1,000 B/D in 7-in. casing with five tubes, and 5,000 to 20,000 B/D in 9 5/8-in. casing with ten tubes. 
When produced water is injected downhole, there are the usual concerns about water injection. To minimize formation damage, the water must be compatible with the clays in the injection zone and with the native water. Otherwise, clays will swell or scale will precipitate, reducing permeability in the critical near-wellbore region and therefore lowering injectivity. Oil carryover lowers water relative permeability, and must be small enough to avoid injectivity losses, unless injection pressure is above the injection zone's hydraulic fracture gradient.
Many wells that produce water also produce solids. Most downhole separation systems will tolerate some solids. PCPs are more tolerant of solids production than ESPs. At low concentrations, solids affect injectivity more than separation efficiency. Produced solids tend to separate with the water phase. If the water is reinjected, those solids are likely to plug the pores of the injection zone, reducing injectivity, or settle in the wellbore. This problem can be avoided by providing sand control (gravel pack or chemical consolidation), installing the equipment only in wells not expected to produce solids, injecting above fracture pressure, or installing downhole desanders.
To prevent short-circuit recycling of the injected water in the wellbore, the injection zone must be hydraulically isolated from the production zone by a good cement job. The two zones must also be hydraulically separate in the formation away from the wellbore. Natural faults and fractures must be considered when determining that the two zones are totally separated hydraulically. The permeability of the injection zone must be high enough that the desired water volume can be injected with the pump horsepower or natural overpressure that is available.
Field ApplicationsTwo independent studies published in 1999 looked at the performance of DOWS and DGWS installations. The first, undertaken by Argonne Natl. Laboratory, CH2M-Hill, and the Nebraska Oil & Gas Commission and funded by the U.S. Dept. of Energy (DOE), looked at data from 37 DOWS installations by 17 operators in the U.S. and Canada.  The second, undertaken by Radian Intl. for the Gas Research Inst. (now Gas Technology Inst.), looked at 53 DGWS installations by 34 operators in the U.S. and Canada. The results of these two analyses were that performance has been mixed (Table 4.1). Depending on the definition of "success," somewhere between 45 and 65% of the installations could be considered successful. However, as operators and equipment vendors gain experience in selecting candidate wells and as equipment design improvements are made, indications were that the overall performance of this technology should improve. As with all new technology, there is a learning curve, and progress has been made as this equipment was installed and tested.
Table 4.1—Results of Downhole Separation and Disposal Studies
In the DOE study, all of the installations where pre- and post-installation water-production data were available showed a decrease in the volume of water brought to the surface. In 22 of 29 trials, the reduction exceeded 75%. The top three gravity-separator installations exhibited increases of between 100 and 235% in oil production. The best three hydrocyclone installations showed increases between 450 and 1,160% in oil production.
A number of DOWS installations have been carried out since the Argonne/DOE study was completed. Marathon installed one in Wyoming, Phillips Petroleum completed the first offshore installation in the China Sea, and Astra installed two in Argentina. The DOE project continued with three field trials operated by Texaco, Unocal, and Avalon Exploration. The Texaco well employed the first TAPS system, a beam-pump-powered gravity-separation system designed to operate at high injection pressures. The Unocal well project, the first hydrocyclone-equipped DOWS installation in east Texas, was designed to gather data and had its DOWS equipment removed. As with many DOWS installations, the technical and economic success of that installation was mixed. The Avalon well, located north of Oklahoma City, Oklahoma, was the first DOWS test in an oilfield dewatering project. Recently, some operators found that it can be profitable to pump large volumes of water from watered-out wells, if the reservoir's dual porosity system allows unrecovered oil to drain into a fracture system that is drawn down by the removal of water. This had only been feasible in fields with an existing water disposal infrastructure. The test evaluated the feasibility of economically dewatering wells in fields without that infrastructure, using an ESP DOWS system.
The downhole auger separator for gas/liquid separation was field-tested in a well on the North Slope of Alaska in 1994. This field test showed that the equipment could be successfully placed and retrieved by wireline through 4½-in. tubing in an existing well. The auger successfully separated gas, which flowed to the surface through the tubing/casing annulus. Subsequent applications of this separator design have all been on the surface. It has been used to provide lift gas to wells where no lift-gas infrastructure exists and to debottleneck multiphase flowlines and gas-handling facilities.
The downhole sink concept to eliminate water coning has been evaluated in five field tests. The tests showed that water coning could be controlled and that oil production rate increased. None of the tests was long enough to evaluate its effect on recovery, however. Numerical reservoir simulators and physical model tests have been used to extrapolate the results to predict the additional recovery. For the field examples studied, the models predicted as much as 70% more oil recovery, at the expense of handling approximately twice the water volume.
Engineering and Design Issues
The engineering calculations used for downhole processing are much the same as those used for surface processing, wellbore flow hydraulics, and reservoir modeling. Because of this, the recommended engineering analyses will be discussed, without going into the specifics of the calculations, which are presented in detail in other sections of the Handbook.
Tubing/Casing Sizes, Length, and Diameter Constraints. The maximum equipment diameter is determined by the minimum diameter of any component of the well completion that will be above the installed equipment. For equipment placed inside or through tubing, this restriction is often the subsurface safety valve. For equipment that is run on the tubing string and placed in the casing, the restriction may be a casing patch that has a smaller ID than the casing itself. Standard recommended clearances that are used for other well completions operations apply. If the well is deviated and the equipment is long, the tool length compared to the dogleg radius must be evaluated using standard calculations to make sure that the equipment can navigate the curve.
Hydraulics/Nodal Analysis. Downhole processing obviously changes the flow in the well. Nodal analysis should be used to predict the operating conditions for downhole separation with or without downhole injection. This analysis combines the hydrocarbon-zone productivity, the injection-zone injectivity, and tubing/annulus multiphase hydraulics to predict the operating state of the well. This can also be used to predict the expected production increase because of unloading the well of water downhole.
Flow Modeling Through Separator/Pump/Compressor. As part of the hydraulics and nodal analysis modeling, the pressure changes of the fluid as it flows through the separator, pump, or compressor assembly are required. Pump and compressor curves must be generated and integrated into the hydraulics modeling. These calculations are also required to evaluate the feasibility of the desired outcome and equipment sizing for each application. Normally, these will be generated and provided by the equipment vendor.
Reservoir Injection Modeling. The permeability and initial skin of the injection zone should be established by conventional well-testing methods to establish initial injectivity. The reservoir volume of the injection zone should also be established, if possible, to predict pressure increases that the additional water or gas injection will generate over time. For screening purposes, estimates of these values can be made from core, log, or geophysical data, but field buildup/drawdown measurements are recommended before proceeding with detailed design and installation. The decision of whether to inject above or below fracture pressure must be made, and the fracture pressure must be estimated or measured. Acid or fracture stimulation of the injection zone may be required to remove drilling damage or increase injectivity.
Instrumentation, Monitoring, and Control. Some data collection is required to confirm that the separation/injection process is operating correctly. Surface measurement of produced fluid rates is standard. Some installations have measured water-injection rates using downhole turbine, orifice, or venturi meters. Power consumption of downhole pumps can be measured and used to estimate fluid volumes pumped. Downhole pressure and temperature measurements validate the hydraulics modeling and are very useful. A slipstream of the injected water is sometimes produced to the surface through small tubing to provide samples of the injected water and measure oil carryover. Also, at initial installation, a baseline production history is usually available for comparison. Tubel and Herbert discusses intelligent-well completion concepts and presents a field-case history of monitoring and control for downhole water/oil separation and injection.
Control of downhole processes is still evolving, with more options becoming available. Applications have recently relied on surface control of the downhole equipment. In downhole processing, fluid temperature, pressure, composition, and flow rates change, but generally are stable over a much longer period of time than in surface processes. In addition, most downhole processing is based on partial separation, where minor process fluctuations are less critical. Because of these factors, manual control is a viable option. Alternatively, pumps and valves can be controlled automatically, based on measurements of pressure, flow rates, and power consumption. Process upsets that result in injection of oil into the water injection zone damage injectivity. The process control should be designed to accommodate minor upsets to avoid damaging the formation.
Solids Production. Many wells that produce water also produce solids that can pose problems for water injection. These solids normally separate with the water phase and either fall to the bottom of the well or are injected with the water. If they settle in the wellbore, they can block perforations across the injection zone if sufficient accumulation capacity is not provided in the rathole. Wellbore cleanouts may be required to restore injectivity. If the solids are injected into the formation, they may plug the pore throats, also reducing injectivity. Sometimes the completion can be designed to prevent solids production by incorporating a screen or gravel pack, but often this impairs productivity and is not desirable. Alternatively, solids can be handled by providing a downhole desander.
Metallurgy/Materials. Materials for the downhole equipment must be chosen to withstand a corrosive wellbore environment if water is produced. Carbon dioxide or hydrogen sulfide in the gas phase should also be considered when choosing the appropriate metallurgy and seals. Solids production requires materials of greater hardness to prevent erosion, particularly in areas of the equipment where velocities are high and rotation or direction change occurs. The downhole desander contains titanium hydrocyclone cones and flow-measurement orifices.
Surface Chemistry and Emulsions. Some oil-and-water combinations form stable emulsions that are very difficult to break. Samples of produced oil and water should be taken and tested for emulsion formation. Shearing of fluids upstream of the separator should be minimized for those prone to emulsion formation. A means of providing chemical emulsion-breaker injection may have to be designed into the downhole system. Alternatively, squeeze treatment of chemicals into the production zone may be an alternative solution.
Separation Calculations. Sufficient residence time must be provided to separate the fluid phases. For gravity separation, the Stokes' law settling calculations that are presented in the separator design section of the Handbook should be used. Most separators that use centrifugal separation are proprietary, and the separation calculations for those are most commonly performed by the equipment vendors.
Range of Operating Conditions/Turndown/Change in Productivity and Injectivity Over Time. All process equipment has an operating range for successful performance and maximum efficiency. Gravity separation is less sensitive to rate changes; centrifugal separation is more sensitive. The equipment manufacturers can provide the range of operating conditions for the planned installation. When selecting equipment, recognize that flow conditions will change over time. Hydrocarbon production declines, water cut increases, and injectivity declines. This will eventually require modification of the equipment unless the equipment can be controlled from the surface to adapt to these changes. Depending on the rate of change of the operating conditions and the equipment life, the required design modifications may be integrated with normal maintenance and replacement schedules.
Geological Consideration for Downhole Injection
The location of the injection zone relative to the production zone determines the well completion configuration and feasibility of the process. For water injection, the well completion is simpler if injection is below the production zone. For equipment that is placed through tubing, the production zone and the injection zone should both be below the tubing tail.
The injection zone is usually a clean, porous sandstone, ideally with depleted pressure. The permeability and pressure of the injection zone must be compatible with the planned injection rates and with the injection pressure that is available. For water injection, low clay content is desirable because it reduces the chances of clay swelling or particle migration caused by nonnative water. The salinity of the injected water should be checked with that of the native water to prevent clay reactions that may reduce permeability. The compositions of the injected water and native water in the injection zone should be determined and evaluated for scale formation potential when they mix. Scale reduces injectivity and may be difficult, or impossible, to remove.
The injection and production zones are usually hydraulically separate. Otherwise, the equipment may be simply cycling fluids near the wellbore. Pressure-transient (interference test) or pressure surveillance data can be used to evaluate this. Applications may exist where the zones are not hydraulically separate, as in reinjection of gas into the gas cap or water into an aquifer. In these cases, careful reservoir modeling should be done to ensure that the desired results will be achieved.
With proper design, downhole processing equipment can be placed and retrieved using normal well completion procedures, whether run on tubing or placed though tubing by wireline or coiled tubing. Normally the well is killed before running the completion, but if safety is addressed and equipment length is short enough, placement by wireline through tubing into a live well may be possible. For through-tubing operations, gauge runs should be made to ensure that the equipment will clear the restrictions in the tubing.
Placement of this equipment will also affect other unrelated well operations such as production logging, squeeze cementing, acid treatments, or hydraulic fracture stimulations which either require equipment to be lowered into the casing below the tubing or involve pumping corrosive or erosive materials. The downhole process equipment will probably have to be pulled to perform these operations.
Downhole process control is more challenging than control of surface equipment because the equipment development is less mature, the equipment is remote from the surface, and the space in a well is very restricted. Control of downhole equipment is similar to control of remote, unmanned facilities, with the added challenge that the equipment must fit in spaces that are inches in diameter. In general, the less control a process or piece of equipment requires, the more robust the application is likely to be. Downhole control valves are under development that can be controlled electronically from the surface, by wires or telemetry. Some processes can be controlled at the surface by valves that control tubing and annulus pressure or by regulating power to downhole pumps. Pressure and temperature are easily measured downhole, and processes based on these measurements should be reliable. Single-phase flow measurement is reasonably reliable, using orifice, venturi, or even turbine meters. Multiphase flow measurement in the well is still under development and is generally less accurate than single-phase flow measurement. Separated water quality may be measured by sampling of the water by a capillary tube to surface. Development of downhole water-cut meters is in progress.
The critical stages of most processes are startup and shutdown. For applications involving fluid injection, these are when problems with injectant fluid quality are most likely to occur. These are also normally the times that are hardest on rotating equipment such as compressors and pumps. The less often the equipment has to be stopped and restarted, in general, the more reliable its performance will be. In design of downhole injection systems, where the injection and production zones are both open to the wellbore, care must be taken that the fluids do not crossflow between zones when the system is shut down. Crossflow between these zones when the equipment is being placed in the well and retrieved must also be considered. Well completion techniques need to prevent crossflow without damaging the formations.
Safety and environment are always important concerns and should be reviewed carefully in these installations because the technology is still evolving and is not yet routine. Conventional hazard assessment is appropriate. In many ways, the safety risk is lower downhole than with vessels, pumps, or compressors on the surface because, obviously, no personnel operate in the vicinity of the equipment. But other issues specific to downhole applications include unintentional overpressure of tubulars, broaching of injected or produced fluids to the surface around the well, and well control/safety valves.
Before January 2000, United States regulators at the federal and state levels were not consistent in classifying DOWS and DGWS installations that simultaneously inject water and produce hydrocarbons. Some states had chosen to classify DGWS wells as Class II injection wells or regulate them as such (Texas, California, Colorado, and Oklahoma). Four states had chosen to regulate DOWS wells with requirements similar to regular Class II injection wells (Texas, Oklahoma, Louisiana, and Colorado). Other states had not yet decided how to deal with the problem.
The U.S. Environmental Protection Agency provided guidance on the issue of wells with downhole separators on 5 January 2000. The EPA classified them as Class II enhanced recovery wells. This determination was based on the fact that fluid was injected and production of hydrocarbons was enhanced. Both DGWS and DOWS installations were included in this definition. In the United States, a permit must be obtained from the appropriate federal or state agency before installation of equipment that would cause a well to be classified as a Class II enhanced recovery well. In most cases, the states have primacy in establishing standards.
As with reinjection of water using surface pumps, care must be taken that the injected water is confined to the injection zone. But as long as this requirement is met, many of the other risks of surface handling are diminished because less water is produced to the surface. Remember that available downhole separation equipment provides only partial separation of oil and water. As a result, some water must be produced to the surface with the oil, and so water handling on the surface is not completely eliminated.
Downhole gas injection can be used to reduce flaring or venting when gas-handling facilities are not available, thus reducing greenhouse gas emissions.
Downhole equipment usually costs less than surface equipment, but several factors must be considered when assessing the overall economics. Most downhole equipment has a shorter life than surface equipment, or has a greater repair/replacement cost because it is not as accessible. If it blocks access to the production zone, the equipment may have to be removed and replaced when other well operations are to be performed. The expected life and frequency of repair/replacement of the equipment must be estimated. Then, the cost of replacing the equipment must be calculated. This will result in a projected operation and maintenance cost that can be combined with the capital cost for an overall economic evaluation.
Downhole processing is most economical when the costs of transportation or surface processing of the "waste" fluid (water or gas) is high. When downhole processing can increase production by assisting lift, the benefits increase significantly. The revenue from this added production is often much greater than the capital cost differences. As the number of wells increases, the economics of downhole processing lessen, as long as the wells are close together and the surface facilities are not at their fluid-handling limits. This is because more downhole units must be installed and maintained, compared to a single central processing unit. If additional injection/disposal wells must be drilled, however, this would offset some of the centralized processing benefit.
Estimated Future of Technoloty for the Next Decade
In the next decade, technology will continue to be developed that will make downhole processing more attractive for a wider range of applications. Several technology and cost barriers must be overcome for downhole processing to have widespread acceptance and use. The first is metering of the quality and volume of the injectant stream. These must be known for reservoir management, well surveillance, and prevention of formation damage. The equipment costs must also decrease. Much of this equipment is still in the prototype stages and has not yet gained the economic benefits of scale. The candidates for this technology are often marginal wells, where costs are critical. In the next decade, more experience will be gained that will increase understanding of how to best apply these technologies. The field results to date have been unpredictable and mixed, but the best results demonstrated the upside promise of this technology. Greater understanding of candidate selection is required. Subsurface production will not be one of those technologies that will be used everywhere. It fits certain niche conditions, so candidate selection is key.
Technology is advancing quickly, and many developments will occur over the next few years. Downhole meters will be developed and refined. Control systems will become more intelligent and reliable. Multilateral well technology will continue to advance, providing greater opportunity for multiple uses of the same wellbore. Downhole compressors for gas reinjection or for artificial lift are likely to be proven feasible.
As existing fields mature and new exploration focuses on remote or offshore areas, the economic incentive for local processing will increase. Downhole processing will be a viable part of the development in these new, challenging areas. It will also be an added option for keeping mature wells producing longer.
Downhole processing has been tested and the equipment proven in a number of field installations. Water/oil separation, water injection, and gas/liquid separation systems have already been developed and proven in the field. Gas compression and downhole metering are progressing rapidly. Additional technology development is required to gain wider experience, but this equipment has been evolving rapidly. Candidate selection is key. Where applicable, though, the technology has the potential to extend the lives of existing mature wells and to improve the economics of new wells in deep water and in remote satellite areas.
The authors gratefully acknowledge the work of Karl Lang, the U.S. DOE, and the Gas Technology Inst., who all compiled a great deal of downhole field-test and equipment information.
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SI Metric Conversion Factors
|bbl||×||1.589 873||E – 01||=||m3|
|cp||×||1.0*||E – 03||=||Pa•s|
|ft||×||3.048*||E – 01||=||m|
|ft3||×||2.831 685||E – 02||=||m3|
|in.||×||2.54*||E + 00||=||cm|
|in.3||×||1.638 706||E + 01||=||cm3|
|kW-hr||×||3.6*||E + 00||=||J|
|mile||×||1.609 344*||E + 00||=||km|
|psi||×||6.894 757||E + 00||=||kPa|
|ton||×||9.071 847||E – 01||=||Mg|
Conversion factor is exact.