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PCP systems for hostile fluid conditions

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In many applications, the constituents of the produced fluids pose the greatest difficulty in the successful use of progressive cavity (PC) pumps.[1] In fact, the current use of PCP systems in many medium- and light-oil wells can be attributed to the recent development of new elastomers that can withstand the produced-fluid chemistry, allowing reasonable pump run lives to be achieved. However, further developments and improvements are required because there are still relatively few PCPs used in fields producing light oils with gravities > 40°API. The presence of different quantities of carbon dioxide, methane and hydrogen sulfide gases, aromatics, and paraffins in the produced fluids, as well as different downhole temperature conditions, requires that special consideration be given to elastomer selection, pump sizing, and well operation. Aromatics such as benzene and toluene typically induce swelling of the stator elastomer, which makes pump sizing more difficult, whereas H2S can cause extended vulcanization, which results in hardening and eventual breakdown of the elastomer material. Diffusion of a significant quantity of gas (in particular, CO2) into the stator elastomer can lead to blistering or fracturing of the rubber because of rapid decompression of the pump during shutdowns.

Pump selection

Pump selection should be based on geometry considerations and stator elastomer properties to minimize the swell potential, although some swelling of the elastomer is inevitable in most cases. Depending on the type of elastomer and the downhole conditions, total elastomer swelling can exceed 3 to 4 vol% in extreme cases, although much lower percentages are usually required for a pump to operate effectively and have a reasonable run life. Performing swell tests is highly recommended to assist in pump selection and sizing when fluid compatibility is expected to be an issue. Experience has shown that the swelling process can be quite gradual, with it sometimes taking up to 6 months for the stator to reach the maximum swell condition. To compensate for the substantial swelling expected in some challenging well applications, pumps may be sized so loosely that they cannot generate any flow at pressures below their rated capacity in a standard bench test. In such cases, the sizing process is usually a delicate balance because, if pumps are fit too loosely, they will not be able to generate sufficient head to produce fluid to surface for a long period of time. One approach used to avoid low initial pumping efficiency because of loose sizing requirements is to complete the initial pump installation with a tighter-fit rotor and then occasionally to replace the rotor with progressively smaller sizes as the stator swells. However, this approach obviously requires additional workovers, which must be justified by the economics of the operation and comparison to other practical options.

Given the many parameters that can influence pump life, it is highly recommended that operators maintain a detailed database of all pump testing and field performance records to establish optimal pump selection and sizing criteria. This information is also crucial in terms of monitoring failure causes and effectively guiding pump replacement decisions as well conditions change.

Issues and remedies

Gas expansion

The most common problem associated with gas diffusion into a stator is the damage caused by expansion of the gas trapped within the elastomer as a result of the rapid decompression that may occur under shutdown conditions. Elastomer selection is obviously important under such conditions because some materials are much less prone to damage than others. Although the options available to prevent rapid decompression and potential damage to the pump are limited, use of drive systems with brakes that prevent rapid drainage of the tubing during shutdown events is highly recommended in these situations. There was also a unique check valve product available previously that prevented the fluid column in the tubing from draining through the pump in the event of a shutdown. Caution should be exercised when attempting to restart such wells immediately after a shutdown to avoid a high-torque-overload condition and potential pump damage. It is also very important to avoid multiple restart attempts in rapid succession because this may lead to reduced brake effectiveness, rod-string failures, or severe pump damage. If a high-torque condition can be attributed to stator swelling/expansion, the options are to load the tubing string to surface before attempting a restart or simply leaving the well shut down for several hours (perhaps a full day) to give the elastomer time to relax.


The fluids produced in light-oil applications often contain substantial quantities of paraffin. As fluid temperature declines through the production system, the waxes precipitate and accumulate on the inside of the tubing and flowlines. If the buildup becomes large enough to severely restrict flow, additional flow losses are generated that increase the operating torque and power requirements of the drive system. Because of the rotational nature of PCP systems, scrapers are not effective at cleaning wax from the tubing. Although chemical and hot-oil treatments are available to remove wax, operators must ensure these treatments will not damage the stator elastomer.


The combination of CO2 and high water cuts may accelerate corrosion of the rod and tubing strings, leading to failures of these components. The rotary interaction of the rod string against the tubing, even in “vertical” wells, results in a corrosion/erosion process whereby the material that would otherwise provide a protective film is constantly removed, leaving a fresh surface exposed for further corrosion attack. Given the mechanisms involved, in many cases the problems cannot be resolved by use of conventional rod guides or continuous-rod strings, although operators have successfully used standard rod strings equipped with spin-thru centralizers or rod guides to prevent additional failures in some wells. It is also important to instruct field personnel to handle and install the rod strings carefully in such wells because any surface damage will increase the potential for corrosion and corrosion/fatigue failures to occur. The use of rod strings made with special materials may help to mitigate these corrosion problems, but they are usually costlier. Some recently developed tubular products with liners or coatings have also proven to be successful in reducing corrosion-related failures. Corrosion inhibitors can also be used, but they must be compatible with the stator elastomer.

Well Treatment

Different well stimulation treatments are commonly used by operators to improve production. When contemplating treatment of a well produced with a PCP system, particular attention must be paid to the chemistry of any fluids that may come into contact with the pump. For example, the fluids commonly used in acidizing jobs will remove the chrome from standard rotors. Other chemicals may be incompatible with the elastomer and cause stator failure.


  1. Matthews, C.M., Alhanati, F.J.S, and Dall’Acqua, D. 1997. PC Pumping System Design Considerations for Light Oil Applications. Paper presented at the 1997 Progressing Cavity Pump Workshop, Tulsa, 19 November.

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See also

Progressing cavity pump (PCP) systems


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