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Progressing cavity pump (PCP) systems
Progressing cavity pumping (PCP) systems derive their name from the unique, positive displacement pump that evolved from the helical gear pump concept first developed by Rene Moineau in the late 1920s.   Although these pumps are now most commonly referred to as progressing cavity (PC) pumps, they also are called screw pumps or Moineau pumps. They are increasingly used for artificial lift, and have been adapted to a range of challenging lift situations (e.g., heavy oil, high sand production, gassy wells, directional or horizontal wells). This page provides an introduction to PCP systems.
Progessive cavity (PC) pumps initially were used extensively as fluid transfer pumps in a wide range of industrial and manufacturing applications, with some attempts made to use them for the surface transfer of oilfield fluids. However, it was not until after the development of synthetic elastomers and adhesives in the late 1940s that PC pumps could be applied effectively in applications involving petroleum-based fluids. Except for several limited field trials, it was not until the late 1970s that a concerted effort was made to use PC pumps as a method of artificial lift for the petroleum industry. Over the past two decades, with the technical contributions and persistence of many individuals and companies, PCP systems have experienced a gradual emergence as a common form of artificial lift.    Although precise numbers are difficult to obtain, it is estimated that more than 50,000 wells worldwide currently are being produced with these systems.
PCP configuration overview
The two key features that differentiate PCP systems from other forms of artificial lift are the downhole PC pumps and the associated surface drive systems. Although other major components, such as the production tubing and sucker rod strings, are found in other downhole lift systems, the design and operational requirements typically differ for PCP applications. Also, many additional equipment components may be used in conjunction with PCP systems to contend with specific application conditions.
The basic surface-driven PCP system configuration illustrated in Fig 1 is the most common, although electric and hydraulic downhole drive systems and various other hybrid PCP systems are also available (see Alternative PCP system configurations). The downhole PC pump is a positive displacement pump that consists of two parts:
- Helical steel “rotor”
- “Stator” comprised of a steel tubular housing with a bonded elastomeric sleeve formed with a multiple internal helix matched suitably to the rotor configuration
The stator is typically run into the well on the bottom of the production tubing, while the rotor is connected to the bottom of the sucker rod string. Rotation of the rod string by means of a surface drive system causes the rotor to spin within the fixed stator, creating the pumping action necessary to produce fluids to surface.
- High overall system energy efficiency, typically in the 55 to 75% range.
- Ability to produce high concentrations of sand or other produced solids.
- Ability to tolerate high percentages of free gas.
- No valves or reciprocating parts to clog, gas lock, or wear.
- Good resistance to abrasion.
- Low internal shear rates (limits fluid emulsification through agitation).
- Relatively low power costs and continuous power demand (prime mover capacity fully utilized).
- Relatively simple installation and operation.
- Generally low maintenance.
- Low profile surface equipment.
- Low surface noise levels.
PCP systems, however, also have some limitations and special considerations:
- Limited production rates (maximum of 800 m3/d [5,040 B/D] in large-diameter pumps, much lower in small-diameter pumps).
- Limited lift capacity (maximum of 3000 m [9,840 ft]). Note that the lift capacity of larger displacement PC pumps is typically much lower.
- Limited temperature capability (routine use to 100°C [212°F], potential use to 180°C [350°F] with special elastomers).
- Sensitivity to fluid environment (stator elastomer may swell or deteriorate on exposure to certain fluids, including well treatment fluids).
- Subject to low volumetric efficiency in wells producing substantial quantities of gas.
- Sucker rod strings may be susceptible to fatigue failures.
- Pump stator may sustain permanent damage if pumped dry for even short periods.
- Rod-string and tubing wear can be problematic in directional and horizontal wells.
- Most systems require the tubing to be pulled to replace the pump.
- Vibration problems may occur in high-speed applications (mitigation may require the use of tubing anchors and stabilization of the rod string).
- Paraffin control can be an issue in waxy crude applications (rotation as opposed to reciprocation of the rod string precludes use of scrapers for effective wax removal).
- Lack of experience with system design, installation, and operation, especially in some areas.
Many of these limitations continue to change or be alleviated over time with the development of new products and improvements in materials and equipment design. If configured and operated properly in appropriate applications, PCP systems currently provide a highly efficient and economical means of artificial lift.
Use of a PCP system should be evaluated for situations that are:
- High-viscosity oil wells
- High-sand-cut wells
- Low-productivity wells
- Gassy wells
- Directional- and horizontal-well applications
- Hostile fluid conditions
- High-speed operations (see discussion of impact in Rod and tubing design for PCP systems
- Coalbed-methane and water-source wells
- Elevated-temperature applications
While PCP systems can operate at greater depths and temperatures than indicated above, those listed are potentially good applications where a PCP should be evaluated.
- Moineau, R.J.L. 1932. Gear Mechanism. US Patent No. 1,892,217.
- Moineau, R.J.L. 1937. Gear Mechanism. US Patent No. 2,085,115.
- Cholet, H. 1997. Progressing Cavity Pumps. Paris, France: Inst. Francais du Petrole.
- Lea, J.F., Anderson, P.O., and Anderson, D.G. 1988. Optimization Of Progressive Cavity Pump Systems In The Development Of The Clearwater Heavy Oil Reservoir. J Can Pet Technol 27 (1). PETSOC-88-01-05. http://dx.doi.org/10.2118/88-01-05
- Gaymard, B., Chanton, E., and Puyo, P. 1988. The Progressing Cavity Pump in Europe: Results and New Developments. Presented at the Offshore South East Asia Show, Singapore, 2-5 February 1988. SPE-17676-MS. http://dx.doi.org/10.2118/17676-MS
- Matthews, C.M. and Dunn, L.J. 1993. Drilling and Production Practices To Mitigate Sucker-Rod/Tubing-Wear-Related Failures in Directional Wells. SPE Prod & Oper 8 (4): 251-259. SPE-22852-PA. http://dx.doi.org/10.2118/22852-PA
- Wright, D. and Adair, R. 1993. Progressive Cavity Pumps Prove More Efficient in Mature Waterflood Tests. Oil & Gas J. 91 (32): 43.
- Clegg, J.D., Bucaram, S.M., and Hein, N.W.J. 1993. Recommendations and Comparisons for Selecting Artificial-Lift Methods. J Pet Technol 45 (12): 1128–1167. SPE-24834-PA. http://dx.doi.org/10.2118/24834-PA
- Saveth, K.J., Klein, S.T., and Fisher, K.B. 1987. A Comparative Analysis of Efficiency and Horsepower Between Progressing Cavity Pumps and Plunger Pumps. Presented at the SPE Production Operations Symposium, Oklahoma City, Oklahoma, 8-10 March 1987. SPE-16194-MS. http://dx.doi.org/10.2118/16194-MS
- Eson, R. 1997. Optimizing Mature Oil Fields Through the Utilization of Alternative Artificial Lift Systems. Presented at the SPE Western Regional Meeting, Long Beach, California, 25-27 June 1997. SPE-38336-MS. http://dx.doi.org/10.2118/38336-MS
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