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Downhole processing overview

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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. With these technologies, the following are possible:

  • gas/liquid separation
  • oil/water separation
  • water injection and disposal
  • gas injection

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.

Historical perspective

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
  • 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.

Reasons to use 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 electric submersible pumps (ESPs) are now being used on the surface for water-injection booster pumps.[1] Compact separation equipment is also used both on the surface and downhole.

Field applications

Two independent studies published in 1999 looked at the performance of downhole oil/water separation (DOWS) and downhole gas and water separation (DGWS) installations. The first, undertaken by Argonne National Laboratory, CH2M-Hill, and the Nebraska Oil & Gas Commission and funded by the US Department of Energy (DOE), looked at data from 37 DOWS installations by 17 operators in the US and Canada.[2] The second, undertaken by Radian International for the Gas Research Institute (now Gas Technology Institute), looked at 53 DGWS installations by 34 operators in the U.S. and Canada.[3] The results of these two analyses were that performance has been mixed (Table 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.[4] As with all new technology, there is a learning curve, and progress has been made as this equipment was installed and tested.

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.[2]

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. 25 The Texaco well employed the first TAPS system,[5] 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.[4]

The downhole auger separator for gas/liquid separation was field-tested in a well on the North Slope of Alaska in 1994.[6] 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.[7] 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.[8] 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.[8]

Future of downhole processing

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
  • 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.


  1. Williamson, J., Laule, B., Hefley, M. et al. 1998. First North Slope Installed Water Injection Booster using Below Grade Electrical Submersible Pump (ESP). Presented at the SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, 27-30 September 1998. SPE-49120-MS.
  2. 2.0 2.1 Veil, J.A., Langhus, B.G., and Belieu, S. 1999. Feasibility Evaluation of Downhole Oil/Water Separation (DOWS) Technology. Prepared for US DOE, Office of Fossil Energy, NPTO, by Argonne National Lab, CH2M-Hill, and Nebraska Oil & Gas Conservation Commission (January 1999). (Available online at
  3. 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.
  4. 4.0 4.1 4.2 Lang, K. 2000. Managing Produced Water. Petroleum Technology Transfer Council, State of the Art Technology Summary, PTTC Network News, 6, 3rd Quarter.
  5. Wacker, H.J. et al. 1999. Test Proves Out Triple-Action Pump in Downhole Separation. Oil & Gas Journal 97 (40): 49.
  6. Weingarten, J.S., Kolpak, M.M., Mattison, S.A. et al. 1997. Development and Testing of a Compact Liquid-Gas Auger Partial Separator for Downhole or Surface Applications. SPE Prod & Oper 12 (1): 34-40. SPE-30637-PA.
  7. Weingarten, J.S. 2000. Field Results of Separation-Vessel and Multiphase-Flowline Debottlenecking Using an In-line Gas/Liquid Auger Separator. SPE Prod & Oper 15 (3): 196-200. SPE-65072-PA.
  8. 8.0 8.1 Wojtanowicz, A.K., Shirman, E.I., and Kurban, H. 1999. Downhole Water Sink (DWS) Completion Enchance OIL Recovery in Reservoirs with Water Coning Problem. Presented at the SPE Annual Technical Conference and Exhibition, Houston, Texas, 3-6 October 1999. SPE-56721-MS.