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PCP system operations

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The following topic describes the installation, monitoring, troubleshooting and failure analysis of the Progressive Cavity Pumping systems (PCP) used in the oil and gas industry.

PCP system installation and startup

Adherence to proper installation procedures for both downhole and surface equipment is key to the successful operation and performance of a PCP system. Given the many different types of equipment available and the number of system configuration alternatives, it is advisable to review the product manuals provided by PCP equipment vendors to obtain detailed installation instructions and system operating information for specific installations. The well-servicing guide books available from some service companies also provide useful information. Although the following list highlights a few key system installation and startup considerations, it is not intended to be comprehensive, and the appropriate equipment manuals should be consulted in all cases:

  • Confirm that the equipment at the wellsite is configured properly for making the following connections: stator to tubing, tubing to drive head, rotor to sucker rods, and sucker rods to drive shaft or polished rod. Ensure that the stator outside diameter (OD) is sufficiently under the casing drift diameter and that the rotor major diameter is less than the tubing-string drift diameter. Also, check to ensure that the size of any rod guides or centralizers is appropriate for the selected tubing size and weight.
  • Visually inspect the various equipment components, new or used, for any signs of physical or chemical damage.
  • Ensure that proper handling procedures are followed for all equipment components.
  • Ensure that the tubing string is made up properly to API 5C1 specifications (i.e., makeup torque levels) to prevent backoff problems. This is especially important if a tubing anchor is not used. If the production tubing is of a smaller diameter than the pump stator, run at least one joint of larger-diameter tubing above the pump to allow for the eccentric motion of the rod string above the pump, and then swage down.
  • Ensure that the rod-string connections are cleaned, undamaged, and made up to the proper API torque specifications (power tongs will likely be required for larger rod string sizes).[1] Proper makeup is essential to prevent failures during production operations, so it is recommended that every connection be validated by use of a makeup calibration card available from the rod manufacturers. Installation of at least two rod centralizers directly above the pump is recommended for directional-well applications. Record the type and position of all centralizers used.
  • In hollow-shaft-drive installations, ensure proper spaceout of the rod string so that polished-rod stickup above the polished-rod clamp is minimal (≈ 30 cm [1 ft] maximum). Adequate spaceout allowance is also required for thermal expansion of the rod string in higher-temperature applications in which a tubing anchor is used.
  • Give special attention to wellhead alignment, especially in cases in which hammer union connections are used. The use of flanged wellhead equipment is recommended.
  • If possible, start the pump slowly and increase speed gradually after a minimum of 5 minutes. Note that after startup it is normal to hear some noise generated by the rods if rod guides are not used. The noise should subside once the produced fluid reaches surface. Continue to monitor the system operation until it is clear that the unit is functioning properly.
  • If possible, record torque and speed with time during startup to obtain breakaway torque information.

PCP system monitoring and automation

Well monitoring typically refers to the periodic or continuous measurement of production parameters and evaluation of the pumping system operating conditions. Reasons for well monitoring include production optimization, failure detection, and production accounting. Production parameters include:

  • Fluid rates
  • Gas rates
  • Water cuts
  • Sand cuts
  • Fluid levels

Operating parameters include:

  • Tubing-head pressure
  • Casing-head pressure
  • Rotational speed
  • Hydraulic pressure
  • Motor current
  • Polished-rod loads

Additional production performance parameters, such as pump efficiency, can be calculated from measured values of the production and operating parameters and installed equipment specifications.

Depending on equipment type and application, a variety of methods are available to obtain measurements of the production and operating parameters. The accuracy or frequency of the measurements required for production optimization varies considerably, depending on the parameter and application. The cost and accuracy of the various methods available to measure the individual parameters can also vary considerably.

Automated Monitoring and Control Systems

Relatively few PCP systems are operated with any sort of fully automated control system, although the use of electronic speed control (ESC) systems has grown considerably. In most cases, measurements of such key parameters as fluid level and polished-rod torque are taken infrequently. These data are generally used by the operator to make decisions regarding changing the pump speed on a particular well. In many cases, there may be periods between these assessments where either the pump runs too fast and the well becomes pumped off, which increases the potential for pump damage, or the pump runs too slow and the system does not produce fluid at the maximum rate possible. Therefore, from both workover and production perspectives, there is considerable incentive to optimize the production process by automating the measurement of a few key production and operation parameters and implementing a system that uses the data to control the pumping system. Potential benefits of implementing such a system include the following:

  • Provide accurate, timely data for use in analysis of individual well production performance.
  • Provide operators with a means to visually assess current well conditions and performance from remote locations.
  • Provide immediate identification of existing or potential problems that could lead to downtime.
  • Provide access to historical data for use with production optimization software tools.
  • Increase the time available to operators and engineers for identifying and implementing production optimization programs.

The first and probably most beneficial step toward fully automated well monitoring and control is implementing a pumpoff control system. Most operators base their operating strategies on the bottomhole pressure they wish to maintain. The common practice is to try to pump the well at the rate which maintains the bottomhole pressure at the lowest level possible without running the pump dry or causing it to produce large quantities of gas. Usually, this strategy is implemented by periodically checking the annular fluid level and adjusting the pump speed according to the interpreted results. However, this approach suffers from inaccuracies in the methods used to measure fluid levels and the relatively long periods that are typical between actual measurements.

The preferred approach is to measure bottomhole pressure directly with a downhole pressure gauge or an automatically actuated acoustic device. The gauge can be suspended on wireline, strapped to the tubing string, or permanently installed on the well casing. The output from the downhole gauge can be displayed at surface for manual reading, or better yet, it can be processed and stored by a data logging system at a given time interval. The data acquired can be interpreted and used by the operator to adjust the pump speed. A more effective use of the data is in conjunction with a variable-speed controller and a feedback control system. The operating speed of the downhole pump can be adjusted automatically by a feedback control system, thereby ensuring that the bottomhole pressure in the well is maintained at the desired level. Other available systems measure pump temperature, fluid rate, or axial loads as a means to control pumpoff.[2][3][4]

Providing fluid rate, polished-rod torque, polished-rod axial load, and various other parameters as additional feedback to a control system is conceivable. Certain consistent decisions can be made automatically by software algorithms, and accurate data can be made available to the operator so that more complex optimization and diagnosis decisions can be made.

Often, motor line current is measured and used to estimate rod-string torque. However, the relationship between current and torque depends on the efficiency and power factor of the motor. When speed remains constant, the current draw will often vary linearly with changes in torque demand. This indicates that the motor efficiency–power factor product remains relatively constant over what is usually a small torque range. However, when an ESC system is introduced, speeds and loads usually change significantly over time. These changes can result in large variations in motor efficiency and power factor. This is illustrated in Fig. 1, which shows, for a single well, the variation in polished-rod torque, motor efficiency-power factor product, and motor output power with line current. At high currents, with the motor loaded near its rated power of 30 kW [40 hp], the motor efficiency-power factor product is ≈ 70%. This corresponds to a motor efficiency of 90% and a power factor of 0.8, which are close to nominal for full-load conditions. Unfortunately, as the current draw decreases, the motor efficiency-power factor product declines to ≈ 30%. Thus, when the motor was operating at low-load conditions, the efficiency and power factor were also very low. Consequently, torque values determined from nominal motor efficiencies and power factors may be artificially high. Depending on the conditions, this might result in a well operating at a lower speed than necessary on the basis of prescribed torque limits. Therefore, caution is required when polished-rod torque is determined from motor line current.


Most PCP equipment vendors provide information describing troubleshooting procedures and suggestions for solving problems that may be encountered with their equipment. To assist in the diagnosis and correction of operational problems that may be encountered in PCP system installations, Table 1 outlines several problematic operating scenarios and provides some possible explanations and corresponding actions or strategies that may be taken to solve the problems. In some cases, the source of a particular operational problem may be easily addressed; in other situations, the problem may be quite difficult to diagnose and expensive to resolve, especially if a workover is required. It is important to consider all the information available because further problems can be caused if the diagnosis is incorrect and the wrong mitigation strategy is taken. Specific troubleshooting actions may be taken to determine the actual source of a problem if the system remains operational. For example, some additional backpressure can be applied to the system by partially closing the flowline valve to test the pressure integrity of the pump (e.g., if a worn or damaged pump condition is suspected). In such a case, the pump is likely okay if the flow rate remains constant and the system torque increases proportionally. Another technique is to implement speed changes to diagnose problems associated with well inflow or gas interference conditions.

Pump failure analyses

When a PC pump is pulled during a workover, it should be sent to a pump shop for a thorough examination and pump test. Usually, the pump components are first cleaned and visually inspected. Inspection of the rotor involves examining the condition of the threads and pin, assessing the amount and location of any wear, and identifying the presence of any heat checking. Although equipment is available to perform a full examination of the internals of a stator (e.g., bore-scope camera), not all vendors have these systems, and stator inspections are often limited to the visual checking of the long stator cavity for signs of damage or deterioration from the two ends. The elastomer surface typically is examined as carefully as possible to locate any areas of worn, hardened, cracked, torn, swollen, or missing rubber. If the rotor and stator components show no evidence of failure, the pump will subsequently be bench tested. If the test results show that the pump is within the accepted performance guidelines for the particular application, it will usually be sent back to the field for redeployment. Pumps that are tested but do not meet the guidelines may be retested with a new rotor if the stator appears to be in good condition. The stator will be scrapped if further testing provides evidence that it has sustained permanent damage (e.g., severe wear or loss of rubber).

Observations made during failed-pump inspections typically provide information that is crucial to the accurate determination of the root cause of failures. This knowledge is usually essential for establishing appropriate remedial actions to achieve improved pump run lives. The failure attributes provide clear indications of the physical mechanisms that resulted in damage to either the rotor or stator. The following sections provide descriptions of the unique damage characteristics associated with different types of pump failure mechanisms.

Stator fatigue failure

Fatigue failures are characterized by missing rubber primarily along the rotor/stator seal lines. The regions of torn or missing rubber are typically shiny and irregular (Fig. 2). Fatigue failures can be attributed to excessive cyclic deformation of the elastomer. As the material properties degrade, shear stresses can more readily generate cracks in the elastomer that subsequently propagate and eventually cause pieces of the rubber to separate from the pump. Excessive hysteretic heat buildup can accelerate material damage and associated crack growth. The loss of material along the rotor/stator seal lines leads to increased slip and a rapid decline in pump performance. Stators that have missing rubber as a result of fatigue damage are not suitable for reuse and must be scrapped.

Stator wear

Stator wear usually can be attributed to the forced movement of abrasive solids along the stator cavities, although some wear can also occur because of the normal interaction of the rotor and stator during pump operation. Worn stators are characterized by the presence of roughened worn surfaces, usually along the minor diameter. The rate of abrasive wear is related most strongly to the quantity and abrasiveness (i.e., size, shape, and hardness) of the solid particles contained in the produced fluid. Wear rates are also influenced by elastomer type. Soft stator materials are more likely to deform instead of tearing as solids pass through the pump. Stator wear is also proportional, but not necessarily linear, to the amount of interaction that occurs between the rotor and stator; consequently, stators tend to wear out more quickly at higher rotational speeds. Stator wear produces a gradual decline with time in volumetric efficiency and fluid rate. This effect is most pronounced when producing low-viscosity (< 100 cp [100 mPa•s]) fluids. Stators damaged by significant wear cannot be repaired and should be scrapped.

Rotor wear

Rotor wear results from normal pumping action. Depending on the downhole conditions and exposure time, the severity of the wear rates can vary dramatically. Normal abrasive wear can be identified by the presence of erosion marks in the chrome plating along the major diameter of the rotor. Extreme abrasive wear is characterized by material loss through the surface coating and into the underlying base metal of the rotor. Examples of coating wear and severe base metal wear are shown in Fig. 3. Worn rotors can be rechromed and reused as long as the wear has not progressed through the chrome surface. Rotors that have sustained base-metal wear usually must be scrapped.

In some cases, base-metal wear is observed only on the top section of a rotor. This usually indicates contact between the upper portion of the rotor and the production tubing and can be attributed to the rotor being landed too high above the tag bar.

Stator fluid incompatibility

Fluid incompatibility and gas permeation can pose serious problems for stator elastomers. Signs of damage caused by fluid incompatibility include swelling, softening, or surface blistering of the stator elastomer. Visible swelling is the most common, occurring to some extent in many different applications. The compatibility between the elastomer and produced fluid determines the degree of swelling and the rate of any subsequent deterioration in mechanical properties. Badly swollen stators will often fail pump tests as a result of excessive torque or poor performance and must be scrapped. Stators that are only slightly swollen may be paired with a smaller-diameter rotor and reused.

Gas permeation and rapid decompression

In gassy wells, stators are prone to severe damage under rapid decompression conditions (e.g., shutdown events) that facilitate the expansion of any gas that has diffused into the elastomer. The damage is caused when the force exerted by the pressurized gas trapped within the elastomer exceeds the tear strength, which leads to subsurface tearing of the material. These failures are characterized by a number of very soft, typically raised bubble areas or blisters on the stator cavity surface.

Rotor fluid incompatibility

Fluid incompatibility also occurs with rotors, but to a much lesser extent than with stators. Incompatibility can be identified by discoloration of the rotor and, in some cases, pitting of the base metal. It usually results from corrosive or acidic fluids attacking the chrome coating. Removing the outer chrome coating makes the rotor more susceptible to abrasive wear and may produce a noticeable increase in friction torque because of the loss of the smooth surface finish. Unless the rotor has extensive pitting, it usually can be rechromed and reused.

High temperature stator damage

Stators that have failed because of exposure to high temperatures typically exhibit elastomer surfaces that are hard, brittle, and extensively cracked. Fig. 4 shows an example of a stator damaged by high-temperature operation. Causes of excessive heat include:

  • Running the pump dry
  • High produced-fluid temperatures
  • Heat generation within the pump

Heat damage usually produces a rapid decline in the pump’s volumetric efficiency. Stators that have failed because of high-temperature damage cannot be repaired and must be scrapped.

Rotor heat-cracking damage

Heat cracking can be identified by fine cracks in the chrome plating of the rotor, primarily along the major diameter, although cracking may extend over the entire surface. Heat cracking is the result of differential expansion of the chrome and base metal in response to temperature changes. These cracks are considered normal, and minor heat cracking does not appear to affect PC pump performance negatively, although the slightly roughened surface may affect pump life. Most operators reuse rotors that have sustained minor heat cracking.

Stator debris damage

Occasionally, stators will exhibit damage in the form of large gouges or tears in the elastomer. This type of damage can be attributed to large foreign particles, such as pebbles, perforation plugs, or metallic debris, passing through the pump. In many cases, debris damage may go undetected unless an internal camera is used or caliper inspection is performed. Depending on the degree of damage, the pump may or may not be suitable for reuse.

Stator high-pressure wash

High-pressure wash or channeling is a common stator damage mechanism characterized by worm-like holes or groves cut in the elastomer (Fig. 5). These channels develop during production when a large sand particle or other debris becomes embedded in the elastomer material, creating a small orifice across the rotor/stator seal through which fluid passes at high velocity, eroding and cutting away the stator rubber. Because the channeling damages the pressure integrity of the pump, stators with extensive pressure-wash damage are not recommended for reuse.

System failure analysis

A thorough analysis should be conducted after each downhole equipment failure incident to identify the circumstances during design, manufacturing, installation, and operation that likely resulted in the failure. Over time, this will lead to a valuable database of information that can be used to optimize PCP system design and operation for a particular well or field.


  1. API Spec. 11B, Specification for Sucker Rods. 1990. Washington, DC: API.
  2. Quijada, E., Brunings, C., and Mena, L. 1998. Automated Diagnostic of Progressive Cavity Pumps. Paper 1998.067, UNITAR.
  3. Carvalho, P.G., Morooka, C., Bordalo, S. et al. 2000. An Intelligent System for Progressing Cavity Pumps. Presented at the SPE Annual Technical Conference and Exhibition, Dallas, Texas, 1-4 October 2000. SPE-63048-MS.
  4. Mena, L. and Klein, S. 1999. Surface Axial Load Based Progressive Cavity Pump Optimization System. Presented at the Latin American and Caribbean Petroleum Engineering Conference, Caracas, Venezuela, 21-23 April 1999. SPE-53962-MS.

Noteworthy papers in OnePetro

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External links

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See also

Progressing cavity pump (PCP) systems

PCP system components

PCP system design


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