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PCP systems for high viscosity oil production

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Production of high-viscosity fluids can result in significant flow losses through the production tubing and surface piping. In some instances, the pressure requirements generated because of flow losses can exceed the hydrostatic head on a well. Pressure losses in the system accumulate and are reacted at the pump, where they cause additional pump pressure loading, leading directly to increased rod-string axial loads and system torque. It is critical that system design account for the “worst-case” flow losses, particularly the selection of the pump (pressure rating), rod string (torque capacity), and prime mover (power output).


Over the past decade, progressive cavity pump (PCP) systems have become a very popular artificial-lift method for producing heavy oil (API gravity < 18°) wells throughout the world.[1][2] Fluid viscosity under downhole conditions can range from a few hundred centipoise to > 100,000 cp in these applications, and the production rates also vary significantly although low rates are far more typical. In Canada, for example, the low gas/oil ratio (GOR), heavy oil wells generally have low productivities (< 10 m3/d [63 B/D]), whereas recent heavy oil field developments in eastern Venezuela using horizontal wells have demonstrated very high productivities (> 500 m3/d [2,000 B/D]). These latter applications have prompted revolutionary developments in large-volume PCP systems.

Effects of Viscousity

Fig. 1 shows a good example of the effects that viscous flow losses and water slugging can have on pump loads in a heavy oil well. The axial and torsional loads on the well were monitored in real time with a purpose-built PCP system dynamometer unit.[3] The data show that the axial load and torque values remained relatively constant at about 45 kN and 1100 N•m [10,050 lbf and 800 ft•lbf], respectively, over the first hour of the monitoring period. Over the next 2 hours, both loads declined significantly, with the torque dropping to less than one-half the initial value. The loads subsequently increased again but remained somewhat below the initial load levels. Fluid samples taken regularly during the monitoring period confirmed that the well had gone from initially producing heavy oil at a very low water cut to producing a large slug of water with relatively little oil during the period. Representative water-cut values are shown at different times in Fig. 1. Because the only significant difference during the operating period was the viscosity of the fluid being produced, these results clearly demonstrate the pronounced effect that flow losses can have on PCP system loads.

Methods to minimize flow losses

Several alternative methods are available to minimize flow losses. Because most of the pressure drop usually occurs in the production tubing, it is important to ensure that the rod/tubing annular flow area is not overly constricted. This is most easily accomplished through the use of large-diameter tubing. However, tubing sizing must also take into account:

  • Casing limitations
  • Economics
  • Sand transport considerations that favor small-diameter tubing

Streamlining of the rod string

Streamlining of the rod string is another effective way to minimize tubing flow restrictions. Large-diameter centralizers and/or a number of sucker-rod guides can contribute to significant incremental flow losses and should be avoided when flow losses are an issue. Continuous rod provides the lowest-pressure-drop alternative.

Consideration of surface piping flow losses

Surface piping flow losses should also be considered. Use of small-diameter flowlines and 90° elbows and tees should be avoided. Because of the logarithmic effect that temperature typically has on viscosity, surface flow losses are usually quite temperature sensitive, so insulated systems or buried flowlines are a necessity in cold climates. These alternatives should also be considered in hot climates to preserve heat and to avoid daily temperature variations in long flowlines.

Diluent injection

In certain situations, changing the equipment configuration is not an option. Other methods must be implemented to reduce flow losses. This can be accomplished by reducing the viscosity of the produced fluid, typically by injecting diluent (light petroleum products or water) down the annulus (to reduce pressure losses in the tubing) or into the flowline near the wellhead (to reduce flowline losses). Note that if viscosity-reducing additives are injected down the annulus, special caution must be taken to ensure that they will not damage the stator elastomer.

Optimal elastomer selection and pump sizing

Elastomer selection and pump sizing are important in heavy oil applications to achieve optimal performance and pump run lives. It is normally preferred to start with medium-NBR elastomers in these applications because of the superior mechanical properties of these materials. However, in heavy oil applications in which the pumps are prone to swelling (e.g., eastern Venezuela), consideration should be given to the use of high nitrile elastomers. Several vendors have recently introduced soft elastomers (i.e., < 65 shore A hardness) for heavy oil service to facilitate effective sealing while allowing high concentrations of sand to pass through the pump without causing damage. Because slippage rates decrease and pump efficiencies increase with higher fluid viscosities, PC pumps can typically be sized with bench-test efficiencies of 70 to 80% at speeds of 100 to 150 rpm (i.e., at rated pressure without consideration for swell or thermal expansion) without negatively affecting performance. In new applications, optimal sizing criteria can be determined only on a trial-and-error basis by varying pump sizing and subsequently tracking both short-term and long-term performance. There is a tradeoff between sizing pumps more tightly to permit a larger degree of wear to be tolerated before a significant loss in efficiency is incurred and relaxing the fit to reduce the elastomer stresses and prevent elastomer fatigue failures. As a result, it is preferable to start by sizing pumps in the middle and adjusting the sizing criteria based on the types of failures that occur.

Flexible power transmission

Production from heavy oil wells can also be highly variable in nature. To respond to the changing operating conditions, it is important to have a flexible power transmission system. Hydraulic systems are quite common because they provide variable speed capability with a high turndown ratio that is often necessary to facilitate the low pump speeds typically required. Electronic systems (electric motors with speed control systems) can also be effective as long as they have the ability to operate within the lower speed ranges.


  1. Dunn, L.J., Matthews, C.M., and Zahacy, T.A. 1995. Progressing Cavity Pumping System Applications in Heavy Oil Production. Presented at the SPE International Heavy Oil Symposium, Calgary, Alberta, Canada, 19-21 June 1995. SPE-30271-MS.
  2. Wild, A.G. 1991. Pumping Viscous Fluids With Progressing Cavity Pumps. Paper presented at the 1991 Intl. Pump Conference: Meeting the Pump Users’ Needs, Regents Park, London, 17–19 April.
  3. Matthews, C.M., Dunn, L.J., and Zahacy, T.A. 1993. Real Time Monitoring of Fluid Rates, Fluid Viscosity and Polished Rod Loads in Progressing Cavity Pump Installations. Paper presented at the 1993 CIM/CHOA Heavy Oil and Oil Sands Symposium, Calgary, 9 March.

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See also

Progressing cavity pump (PCP) systems


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