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Downhole processing candidate screening

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As with most technology, proper candidate selection is key to success. The following all affect how well downhole separation will work:

  • separation equipment operating ranges
  • wellbore design
  • reservoir geology

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.

Overall considerations

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—those evaluating the feasibility of a downhole process should consider:

  • foaming tendency
  • emulsion formation
  • fluid density
  • viscosity

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 situations

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 electric submersible pump (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 electric submersible pumps (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 downhole gas/water separator (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.[1] That study provided the following approximate rules of thumb[2]:

  • 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,[1] which is available on CD and includes an interactive economic model to facilitate evaluation of candidate wells, is available from the Gas Technology Institute.

Oil/water situations

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.[3]

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


  • 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.

Engineering and design issues

The engineering calculations used for downhole processing are much the same as those used for the following:

  • surface processing
  • wellbore flow hydraulics
  • 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 pages of this wiki.

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. Ref. 4[4] 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 the following:

  • measurements of pressure
  • flow rates
  • 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.[5]


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[5] 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.

Operational considerations

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

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
  • 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.

Safety and environment concerns

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
  • well control/safety valves

Environmental considerations

Before January 2000, United States regulators at the federal and state levels were not consistent in classifying DOWS (unidentified acronym) and DGWS (unidentified acronym) 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
  • 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.[6]

The US Environmental Protection Agency (EPA) 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.[6]

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.

Economic considerations

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.


  1. 1.0 1.1 Gas Technology Inst. 1999. Technology Assessment and Economic Evaluation of Downhole Gas/Water Separation and Disposal Tools. GRI-99/0218, report prepared for Gas Research Inst., Radian Intl.
  2. Lang, K. 2000. Managing Produced Water. Petroleum Technology Transfer Council, State of the Art Technology Summary, PTTC Network News, 6, 3rd Quarter.
  3. Baker Hughes Centrilift Product Information Packet for Downhole Water Separation and Injection Equipment (2000).
  4. Tubel, P. and Herbert, R.P. 1998. Intelligent System for Monitoring and Control of Downhole Oil Water Separation Applications. Presented at the SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, 27-30 September 1998. SPE-49186-MS.
  5. 5.0 5.1 Danyluk, T.L., Chachula, R.C., and Solanki, S.C. 1998. Field Trial of the First Desanding System for Downhole Oil/Water Separation in a Heavy-Oil Application. Presented at the SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, 27-30 September 1998. SPE-49053-MS.
  6. 6.0 6.1 Lang, K. 2000. Managing Produced Water. Petroleum Technology Transfer Council, State of the Art Technology Summary, PTTC Network News, 6, 3rd Quarter.

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See also

Downhole processing overview

Downhole processing technology

Subsea processing overview