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PCP systems for high sand cut wells

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Sand and other solids production can cause problems in PCP systems by accelerating equipment wear, increasing rod torque and power demand, or causing a flow restriction by accumulating around the pump intake, within the pump cavities, or above the pump in the tubing. Also, given its specific gravity of ≈ 2.7, even moderate volumes of sand can substantially increase the pressure gradient of the fluid column in the production tubing.


Sand production is frequently a byproduct of oil production, especially in some primary heavy oil operations (e.g., Canada) where it is an important part of the recovery process. In such operations, sand influx is usually most severe during the initial stage of production when the volumetric sand cuts can exceed 40%. Subsequently, the sand cuts often stabilize at ≤ 3%. In high-rate applications (e.g., Venezuela), even low sand cuts can equate to significant volumes of produced sand over time.

Handling sand production

With proper system design and operation, progressing cavity pump (PCP) systems can effectively handle produced fluids with significant sand cuts under reasonably steady-state conditions. Severe operational problems (equipment failures, shutdowns requiring workovers) generally develop due to short periods of rapid sand influx (slugging). Although some slugging occurs naturally, sudden sand influx can also be initiated by operating practices that cause fairly rapid changes in bottomhole pressure. The pressure variations affect inflow rates and can disturb stable sand bridges that develop around perforations, causing the bridges to collapse and sand to flow into the wellbore. For example, experience has shown that large changes in pump speed can precipitate sand slugging. Therefore, large adjustments in pump speed should be made gradually over a few days to allow the well time to stabilize. If possible, other practices that produce sudden variations in bottomhole pressure, such as well loading or casing gas blowdown, should also be avoided. Workover operations that cause swabbing of a well (e.g., rapid pulling of the production tubing string within the perforated interval) are often followed by periods of high sand production. Changes in the produced-fluid conditions can also precipitate sand influx. For example, a sudden increase in water production or a slug of higher-viscosity fluid can lead to a breakdown of stable sand arches, causing a slug of sand to enter the wellbore.

Handling sand accumulation in the tubing

Sand accumulation inside the tubing just above the pump is a common problem. It leads to increased pump discharge pressures, reduced fluid rates, and in severe cases, increased potential for sudden pump failure. Sand buildup occurs when the produced-fluid stream cannot carry all the sand up the tubing to surface. Therefore, it is very important to assess the sand-handling capabilities of a PCP system design for applications in which sand production is expected. Sand settling and fluid transport velocities (in vertical pipes) can be assessed by comparing the fluid drag forces calculated using well-established methods[1] with the weight of the sand particles or particle conglomerates as appropriate.

Handling sand build-up in the pump intake region

Sand buildup in the pump intake area causes decreased production rates and, in severe cases, pump failure due to complete blockage of the intake. One effective way to minimize sand accumulation around the intake is to provide a sump below the pump where excess sand can settle. Deeper sumps provide a larger buffer, and therefore it will take longer before sand accumulates to the pump level. Certain pump intake designs also contribute to sanding problems. Restricted intakes tend to produce stagnant flow regions where the sand will settle out. For sandy applications, the pump intake should be configured so that fluids can readily flow (i.e., limited bends, channels) from the wellbore into the pump intake.

Dealing with operational issues caused by sand production

Operational problems associated with sand settlement and bridging, both above and below the pump, occur most commonly in directional and horizontal wells. The ability of the produced fluid to transport sand improves with increasing fluid viscosity and flow velocity. Initial system design should consider whether the lowest anticipated production rate will be capable of moving the sand up the tubing, and allowances should be made for slugs of sand entering the system. Decreasing the tubing size and increasing the flow rate are the easiest ways to improve sand transport capability. However, the use of smaller-diameter tubing must be evaluated in terms of its effect on flow losses. Injecting a fluid down the annulus and pumping at higher rates or introducing fluid into the tubing above the pump (recirculation system) are two possible ways to increase tubing flow rates. Because water has a low viscosity, it is often more effective (but more costly) to inject produced or blend oil.

Another recommended practice for operations prone to sand production is to build excess capacity into the equipment design to allow for the associated peak loading condition. If a system normally operates at full capacity in terms of torque, power, etc., any incremental loading will cause either a reduction in speed or a complete system shutdown, which may allow sand to settle out above the pump and necessitate a workover if the rotor cannot be freed.

Handling wear caused by sand

Produced sands tend to be highly abrasive, causing accelerated wear of the pump, rod string, and tubing. Because abrasive wear is directly proportional to the number of revolutions, the use of larger-displacement pumps operated at lower speeds can help to extend equipment life. However, large-displacement pumps may not handle the sand as effectively as small-displacement pumps. Stator wear can be minimized by choosing an elastomer with good abrasion resistance. Although the standard chrome coating used on most rotors generally provides good wear resistance, double-thickness chrome coatings are commonly specified for abrasive applications. Alternatively, special coatings designed to withstand abrasive wear are also available and have shown superior performance in service.[2] Note that chrome-coated rotors with visible wear can be repaired by replating as long as the underlying base metal has not been worn.


  1. Govier, G.W. and Aziz, K. 2008. The Flow of Complex Mixtures in Pipes, second edition. Richardson, Texas: Society of Petroleum Engineers.
  2. Delpassand, M.S. 1997. Progressing Cavity (PC) Pump Design Optimization for Abrasive Applications. Presented at the SPE Production Operations Symposium, Oklahoma City, Oklahoma, 9-11 March 1997. SPE-37455-MS.

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See also

Progressing cavity pump (PCP) systems


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