PCP system components

A progressing cavity pump (PCP) system includes a variety of components. The basic system includes downhole PC pumps (and appropriate elastomers), along with sucker rod and production tubing strings and surface drive equipment(which must include a stuffing box). A PCP installation may also include different accessory equipment, such as:

• Gas separators
• Rod centralizers
• Tubing-string rotator systems
• Surface equipment control devices

Rod strings and production tubing

Surface-driven PCP systems require a sucker-rod string to transfer the torsional and axial loads from the surface drive system down to the bottomhole PC pump. Although conventional sucker rods continue to be used in many PCP applications, some rod manufacturers have developed products designed especially for PCP applications:

• Larger-diameter rods (e.g., 25.4 mm [1.0 in.] and 37.5 mm [1.5 in.]) to handle the high loads associated with large-displacement PCPs
• Hollow rods designed to handle high loads and to facilitate downhole injection of diluents or treatment fluids
• Rods with different connection designs that minimize the coupling diameter to reduce flow losses (typically, the pin diameter is reduced one size relative to standard rods, e.g., 25.4 mm [1 in.] rods fabricated with 22.2 mm (7/8 in.) pin connections, which allows the use of smaller-diameter couplings)
• Relatively large-diameter (e.g., up to 29.2 mm [1.15 in.]) round continuous rod

Several different rod-string configurations are commonly used in PCP applications. These include continuous rods, standard rods with couplings (including hollow rods), standard rods with centralizers, and standard rods with bonded/molded rod guides. Within these categories are numerous additional variations resulting from differences in centralizer and rod guide design. The centralizers can be divided into two groups based on functionality. The first group consists of “coated” centralizers that have a urethane, plastic, or elastomer sleeve bonded to either a coupling or the rod body. The second group consists of “spin-thru” centralizers that have an outer stabilizer that is free to rotate on either an inner core or the rod body. With the spin-thru design, the rod string rotates inside the stabilizer, which remains stationary against the tubing. Fig. 1 shows several different types of centralizers and rod guides. Continuous-rod products are not currently available in all countries but are used extensively in Canada, Venezuela, and selected regions of the U.S.

The production tubing strings used in most PCP applications are typical of those used in most other oil and gas production operations. The tubulars conform to API product standards, with External Upset Ends (EUE) and Non-Upset (NU) connections and Grade 55 pipe used in most cases. In some situations, large-diameter tubing strings are warranted to contend with high flow losses or to facilitate the use of an alternative PC pumping system. Some special internally coated tubing-string products, including boron-coated tubing and tubing with polyethylene liners, are available for use in applications in which wear and/or corrosion problems may occur.

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  Fig. 1—Examples of spin-through centralizers, coated centralizers, and rod guides.

Surface drive systems

The surface equipment used in a conventional surface-driven PCP system must perform the following functions:

• Suspend the rod string and carry the axial loads
• Deliver the torque required at the polished rod
• Safely rotate the polished rod at the required speed
• Provide for safe release of the stored energy during shutdowns
• Prevent produced fluid from escaping the system

As illustrated in Fig. 2, to facilitate these requirements, all surface equipment systems include:

• A wellhead drive unit (drive head)
• A stuffing box
• Power transmission equipment
• A prime mover

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  Fig. 2—Basic surface equipment for PC pumping systems.

In addition, the surface equipment may also include:

• Safety shutdown devices
• Torque limiters
• Recoil control devices
• Electronic speed control (ESC) and monitoring systems

Wellhead drive units

The wellhead drive unit consists of:

• A wellhead frame
• Thrust bearing
• A polished-rod braking system (in most cases)
• A fixed gear or belt and sheave system(sometimes)

Fig. 3 shows two types of drive heads. In some cases, the wellhead frame threads directly onto the tubing head. However, most of the newer, current designs use flanged connections. This is important especially for applications involving drive systems that are 60 hp or larger. These systems facilitate proper alignment of the drive on the wellhead to help prevent stuffing box leakage and provide sufficient strength to carry the much heavier drive heads and motors used today. The drive heads typically mount onto composite pumping tees, which in turn mount onto the casing head. Note that the wellhead frame usually incorporates the stuffing box assembly and that some units are fabricated to allow mounting of either electric prime movers or hydraulic motors.

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  Fig. 3—Hollow shaft wellhead drive units.

One important function of the drive head is to support the axial rod-string load. The thrust bearing, contained in the wellhead frame, supports this load while allowing the rod string to rotate with minimal friction. Most wellhead frames are available with a variety of thrust bearings to suit different loading applications. The expected life of the thrust bearing is usually quantified by an L₁₀ rating. Within a large sample, the median bearing life is typically between four and five times the L₁₀ life.

Most drive heads have either a hollow shaft or an integral shaft design that facilitates the connection of the drive to the polished rod. With the most common hollow shaft design, the polished rod passes through the entire wellhead and is suspended by a polished-rod clamp that seats into a drive slot on top of the wellhead frame. In a modification of this design, a hexagonal rod substitutes for the polished rod, and the drive unit has a mating hollow shaft through which torque is applied to the rod. Polished rod and stuffing box exposure depends on whether the particular design incorporates an open (Fig. 3a) or closed (see Fig. 3b) frame. The hollow shaft design allows some repositioning of the rod string without removal of the wellhead. This is done by loosening the polished rod clamp, raising or lowering the polished rod as required, and then tightening the clamp. This flexibility to reposition the rod string simplifies rod space-out procedures, flush-bys, and the repositioning of the rod string to prevent wear-related failures. In drives with an integral shaft design, the polished rod threads directly into the drive mechanism as opposed to passing through it. As a result, the only way to reposition the rod string is to add pony rods of different lengths to change the string length. Initial space-out procedures and flush-bys are not easily accommodated with the integrated shaft design.

Drive heads also incorporate a stuffing box that seals on the rotating polished rod to control fluid leakage from the production string and wellhead. The two basic types of stuffing boxes available are conventional and specialty (i.e., rotating) systems. The conventional stuffing boxes function similar to those used with beam-pump systems. They use a special packing material compressed against the polished rod to effect a seal; (i.e., the rod rotates directly against the packing material, so the compressive loading imposed by tightening the stuffing box must balance the resultant friction forces against fluid seal integrity). These stuffing boxes require regular inspection and maintenance (i.e., greasing and tightening). Rotating stuffing boxes are designed to seal differently, typically incorporating an inner sleeve that seals against the polished rod and rotates with it during operation. Additional seals designed to operate in a clean fluid environment provide a seal between the rotating sleeve and the fixed outer housing of the stuffing box. A clean lubricating oil environment is ideally maintained in this interstitial region during operation. One key consideration for stuffing box selection is access for packing material or seal replacement, and another is tightening of the packing as required. To minimize stuffing box leakage and maintenance requirements, it is also important to ensure that the polished rod has not been bent. Some new stuffing box designs rely on injectable packing materials (viscous materials that require an injection pressure of approximately 7 MPa [1,000 psi] that readily facilitate repacking of a stuffing box).

Normally, drive heads are connected to the power transmission equipment by a vertical shaft (Fig. 3b). However, horizontal connections can be facilitated by incorporating right-angle gearboxes directly into the drive head (Fig. 3a). These gearboxes typically enclose gears that provide a reduction ratio of up to 4:1. To prevent gearbox failure, operators should adhere to manufacturer guidelines for maximum gearbox speed and torque.

Power transmission equipment

Power transmission equipment is used to transmit power (torque and speed) from the prime mover to the polished rod. This equipment almost always incorporates some type of speed reduction/torque transfer system that permits the prime mover to operate at a higher speed and lower torque than the polished rod. In some cases, power transmission components, such as gearboxes and fixed speed belts and sheaves, are integrated into the drive head.

Power transmission equipment can be arranged in a variety of different configurations as is illustrated in Fig. 4. The various configurations can include almost any combination of hydraulic equipment, belts and sheaves, and gearboxes to provide the desired operating speed and torque characteristics. Note that power transmission equipment is usually classified as either direct drive or hydraulic on the basis of whether or not it incorporates hydraulic system components.

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  Fig. 4—Alternative configurations of power transmission equipment.

Hydraulic power transmission systems incorporate a hydraulic system between the prime mover and the input shaft of either a gearbox or fixed speed belt and sheave system that is integrated into the drive head. The hydraulic system itself consists of a hydraulic pump connected to the output shaft of the prime mover, various intermediate valves and plumbing, and a hydraulic motor attached to the input shaft of the drive head (Fig. 5a). Note that variable displacement hydraulic pumps and motors are typically used. Additional required components include a hydraulic fluid reservoir and fluid filtration system. All hydraulic equipment, except the hydraulic motor and connecting hoses, is usually mounted on a skid (Fig. 5b). The torque delivered by the hydraulic motor to the drive head is proportional to the hydraulic system pressure and a function corresponding to the hydraulic motor design. The hydraulic system flow rate may be controlled with either prime-mover speed control systems or, more commonly, pump displacement adjustments (i.e., through changes in the swash plate position in variable-displacement pumps) to set the rotational speed of the hydraulic motor. The relationship between prime-mover speed and hydraulic motor speed is a function of the relative displacements of the hydraulic pump and motor. As an alternative, some vendors also sell in-line hydraulic drive units that use high-torque, low-speed hydraulic motors to drive the polish rod directly without any gear or belt and sheave reduction. These units tend to be relatively compact and quiet compared with the more standard systems.

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  Fig. 5—Hydraulic drive system equipment.

Direct-drive power transmission systems can be categorized as mechanical fixed speed, mechanical variable speed, or electronic. Mechanical fixed speed refers to a direct-drive system with a fixed gear ratio powered by a prime mover that can operate at a single speed (i.e., typically an AC electric motor). Mechanical variable-speed systems have either internal combustion prime movers that can operate at variable speeds or a belt and sheave system that accommodates a variety of sheave sizes. To vary pump speed in the latter case, the well must be shut down to permit changing of the sheaves. Electronic systems consist of an electric motor with an ESC system. Fig. 6 shows different types of direct-drive systems.

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  Fig. 6—Direct drive power transmission systems.

The features of the different types of power transmission systems are compared in Table 1. Although hydraulic systems are typically less efficient than direct electric drives, they generally require little field infrastructure and have a high variable-speed turndown rate, which makes them popular for low-rate, high-viscosity applications in which prime-mover speeds are much higher than pump speeds and flexible speed control is desirable. The simplicity of mechanical fixed- and variable-speed systems makes them practical for applications in which fluid rates are relatively stable and speed adjustment requirements are limited. The direct-electric-drive systems typically have better energy efficiency than hydraulic drives, although they typically are more expensive and can be more difficult to repair. Field electrification is usually required for effective use of electric-drive systems.

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  Table 1

Prime movers

The prime mover provides the energy to drive the surface equipment and ultimately the rod string and downhole pump. The amount of power that the prime mover must deliver depends on the power demand at the polished rod and the efficiency of the power transmission system. Typical prime-mover power ratings range from 4 to 75 kW [5 to 100 hp], although higher capacity wellhead units designed to accommodate twin electric motors providing power up to 225 kW [300 hp] have recently been introduced by several vendors in conjunction with new large displacement PC pumps.

The two types of prime movers commonly used to drive PCP systems are internal combustion engines and electric motors. Internal combustion engines (Fig. 6b) have the advantages of a simple setup with minimum capital investment and variable-speed capability. They are often used on wells in remote areas where electricity is not available. In some situations, depending on gas production and composition, it is possible to fuel the engine with produced gas. Nevertheless, electric motors are the most common form of prime mover used for PCP systems because of low maintenance requirements, high efficiency, low energy costs, easy operation, and low noise levels. The major disadvantage of using electric motors for the prime mover is that the cost of powering the motor can be prohibitively high unless the well site is electrified. Another drawback is that speed adjustment is possible only through sheave changes, motor rewiring, or the use of ESC systems.

Most electric motors used as prime movers in PCP applications are three-phase, squirrel-cage induction motors. The operating characteristics of an induction motor are illustrated in the speed-vs.-torque curve in Fig. 7. During motor startup, the difference between the developed torque and load torque determines the rate at which the motor will accelerate up to speed. If sustained, the large current draw during startup would cause permanent motor stator damage. The startup torque capabilities of the system must be well above (e.g., 1.25–1.5×) that required by the system operating load. Note that in PCP applications, the static friction within the pump, combined with initial system inertial loads, can, in some cases, cause the torque required at startup to be substantially higher than the normal operating torque. In particular, the startup or breakaway torque of the pump can be affected by excessive compression set or swelling of the elastomer. Fig. 7 shows that the normal operating range for motors is the linear region below the full-load torque (i.e., torque required to produce rated power at rated speed). Continuous operation at torques above the full-load torque may result in excessive heat generation, which will cause permanent motor damage.

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  Fig. 7—Speed vs. torque characteristics for a squirrel-cage induction motor.

High-efficiency motors designed to NEMA B standards are typically used in PCP applications. They characteristically have startup torques of between 125 and 150% of full load (i.e., for motors with synchronous speeds of 1,200 rpm), breakdown torques of 200% of full load, and a slip of < 5%. In addition, because the motors are unsheltered in most PCP installations, totally enclosed fan-cooled motor enclosures are typically used for these applications. The fans are considered critical for providing adequate cooling to prevent damage to the motor under warm-climate operating conditions. Most PCP drive systems use six pole motors that operate at slightly < 1,200 rpm with supply power of 460 V and 50 to 60 Hz.

Nominal power factors are sometimes quoted by manufacturers based on operation at full load under the rated voltage, current, and frequency conditions. For the induction motors used in PCP applications, nominal power factors typically range from 0.80 to 0.90. However, motors are designed to operate with a maximum power factor when loaded to full capacity, and this is often not the case in the field. Actual power factors can be measured during motor operation with specialized equipment.

Nominal overall energy conversion efficiency values for electric motors are often quoted by manufacturers based on operation at full load under the rated voltage, current, and frequency conditions. In the range of motor sizes used in PCP applications, nominal efficiencies range between approximately 90 and 95%. However, as for the power factor, motors are designed to operate at maximum efficiency when loaded to full capacity. Operation above or below full capacity or deviations from rated conditions will result in lower efficiencies.

Motor power factors and efficiency values may decrease when a motor is used in less-than-ideal operating environments (e.g., high ambient temperatures) or with increased motor age. Thus, differences between summer and winter operating conditions should be taken into consideration with respect to motor performance and efficiency.

Safety shutdown devices

Surface equipment components, such as the hydraulic system or the prime mover, may be at risk of sustaining costly damage if allowed to operate continuously under certain conditions. As a result, surface drive systems usually incorporate devices that automatically shut the system down when adverse conditions exist. For example:

• Hydraulic systems often have a switch to shut the system down if the hydraulic fluid level drops too low
• Internal combustion engines usually have high-engine-temperature and low-oil-pressure shutdown switches
• Many electronic systems are equipped with high-current shutdown switches

Torque limiters

Bottomhole pump seizures resulting from sanding or elastomer swelling, parted tubing, and blocked flowlines can all result in a sudden escalation in rod-string torque. If uninterrupted, the power transmission equipment will continue to increase the applied torque until the rod string or some other component fails. To prevent such failures, torque limiters are installed on the surface equipment to ensure that polished-rod torque cannot exceed some preset limit. Hydraulic systems, for example, typically use a pressure control valve that allows some hydraulic fluid to bypass the hydraulic motor when the system pressure becomes too high. This reduces rod-string speed while allowing the prime mover to keep operating at a safe torque level. Electronic drives either receive torque feedback from a mechanical device on the drive head or determine torque directly with special algorithms. When this operating torque exceeds the preset limit, the electronic drive will reduce the rod-string speed in an attempt to lower torque. If that fails, the drive will eventually shut the prime mover off.

Electronic speed control (ESC) sytems

ESC systems are used to vary the speed of direct-drive systems. ESC systems incorporate an inverter operating from a three-phase power source, a control system that directs and excites the inverter, and an induction motor. Currently, several variations of ESC systems are being used in PCP applications. The primary difference between these systems is in the control system strategy and types of inverters used. Motor speed is controlled by adjusting the frequency of the input power signals generated by the inverter on the basis of the control system algorithms.

Most ESC systems typically operate the electric motor at a speed setpoint, although more advanced systems also allow torque-based control. Three-phase AC power is fed into a rectifier circuit that produces a DC bus. The pulse-width-modulated inverter draws energy from this bus and creates three-phase AC power at the frequency commanded by the control system. Although basic speed control is typically open loop, the more elaborate systems often use closed-loop speed control capabilities. The control modules of more advanced ESC systems may incorporate sophisticated motor algorithms, microprocessors, and digital signal processors to perform a multitude of motor current, magnetic flux, rotor slip, winding resistance, temperature correction, and magnetizing reactance calculations using several different feedback signals from the motor. The system then uses this information to achieve the desired motor operating condition. Fig. 8 shows a block diagram illustrating the typical configuration for these systems.

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  Fig. 8—Block diagram for an electronic speed-control setup.

Most ESC systems allow programming of such basic control options as torque limits, speed ramping, and regenerative braking. More advanced systems include features like automatic restart after fault trips and delays, frequency skipping to avoid resonance, and power-loss ride-through. Many ESC systems also have an optional serial communications interface that enables digital links to programmable logic controllers or computers for remote access to monitoring, adjustment, and control functions.

Rod string backspin control devices

When a surface-driven PCP system is in operation, a significant quantity of energy is stored in the torsional strain of the rods and within the fluid column above the pump within the tubing string. The development and use of larger-displacement and higher-pressure-capacity PC pumps have led to a substantial increase in the magnitude of the torsional strain and fluid energy that become stored in the production system during normal pumping operations. The stored energy is released with backspin of the pump and/or rod string whenever the PCP system is shut down through routine operator intervention or automatic power cutoff in high-torque-overload cases. When the power supply to the drive is lost or interrupted, the potential energy that remains in the system will cause the surface equipment and drive string to accelerate in the direction opposite its normal operating mode. Uncontrolled backspin can lead to surface equipment damage and backed-off rod strings or tubing. These conditions also pose a significant hazard to field personnel working on or near the surface equipment. Thus, it is essential that brakes be used to control the release of rod-string torque and restrict rod recoil to a safe speed. In many applications, if unrestrained by the surface drive/brake equipment, backspin speeds can increase to the point at which the drive-head sheaves or motor fans fragment and “explode” radially outward because of the high centrifugal forces generated.

Typically, two different types of backspin events may occur:

• The seized pump scenario, in which the pump rotor seizes within the stator
• The normal shutdown scenario that occurs during routine shutdowns of the pumping system

Upon shutdown in the seized pump case, the pump has stopped turning and the torsional strain energy (I.e., twists) stored in the rod string causes the surface system to start spinning in the reverse direction until all the energy is dissipated. The response period is generally short, and little or no fluid drains from the production tubing because of the seized-pump condition.Depending upon the horswpower of the system, the amount of built up torsional energy can be substantial. In the normal shutdown case, fluid remaining in the production tubing drains back to the well through the pump, causing both the pump and the drive system to accelerate backward. This continues until the fluid energy in the tubing (i.e., fluid level) is balanced by the fluid column in the annulus and the pump friction, which can take anywhere from several minutes to hours, depending on the circumstances.

Several incidents have occurred in which uncontrolled backspin of a PCP system drive head has led to explosive sheave fragmentation. In a few cases, personnel were struck by sheave fragments and seriously injured. This has led to a heightened awareness by equipment manufacturers and operators of the need to ensure that surface equipment (i.e., particularly the braking system) is properly sized for each application and to implement operating and workover procedures that enhance worker safety.

Most drive heads are equipped with some type of brake system to limit backspin speeds to the allowable speed ratings of the drive-head and sheave components. Table 2 summarizes the major types of recoil control devices used in PCP systems.

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  Table 2

In hydraulic systems, when the rods backspin, the hydraulic motor becomes a pump, causing the hydraulic fluid to flow in the reverse direction through the system. Braking is usually accomplished by forcing the fluid to pass through a flow restriction. Standalone hydraulic constriction devices use a hydraulic pump driven by rod backspin to force fluid through a flow restriction. Torque converters provide braking by forcing vanes to rotate within a viscous fluid. Another basic type of recoil control device uses brake pads activated either mechanically or through the use of a hydraulic pump driven by rod backspin. Regenerative braking has been incorporated into some of the newer ESC systems. With this type of braking, the electric motor is loaded during the backspin, causing it to act as a generator and convert recoil energy into electrical energy. However, the utility of these systems relies on the integrity of the drive-system components (e.g., belts and sheaves) that link the polished rod and electric motor, which poses additional risk of failure.

It is important for operators to ensure that the brake specifications of the drive equipment installed are adequate for their specific application conditions under both backspin scenarios described above. Apart from physical compatibility with the drive system being used, it is important to consider the speed at which the braking device engages, the torque that it can resist, and the energy that it can dissipate safely. If the recoil control device does not engage until the rods reach a relatively high speed or if it cannot handle the amount of torque applied by the rods, it may prove ineffective in preventing excessive backspin speeds.

Auxiliary equipment

This section outlines some auxiliary equipment commonly used with PCP systems. It covers a brief description of the design and application features of each product.

Tag bar assemblies and tail joints

A tag bar or “rotor stop” is normally required to facilitate installation and spaceout of the rod string. Several different tag bar designs are available, but they usually consist simply of a steel rod or bar (approximately 25 mm [1 in.] in diameter) fastened widthwise across the middle of a short (e.g., 0.6 m [2 ft]) perforated tubing pup joint that is threaded to the pump intake. In some designs, the rod is replaced with a steel plate with holes to permit fluid flow. The number and shape of the perforations in the pup joint vary among manufacturers. A large perforated area is particularly important in highly viscous fluid applications to minimize flow losses and to facilitate sand flow to the pump intake. The pump vendor usually supplies a tag bar joint with the PC pump.

Although the tag bar pup joint is usually the bottom component of the tubing string in a PC pump completion, an additional length of tubing is sometimes run below the tag bar as a tail joint to lower the pump intake. For example, in horizontal wells, the pump may be seated in the vertical section to alleviate wear problems while a tail joint is installed to allow fluid to be drawn from the curved or horizontal sections of the wellbore. This technique can also be used effectively to increase the fluid flow velocity below the pump, which can be important for maintaining solids in suspension. In some cases, tail joints can be used to reduce the gas-to-liquid ratio at the pump intake, although the pressure losses through the tail joint may lead to additional solution gas breakout, resulting in little or no improvement in volumetric pump efficiency. If tail joints are used, they should not be centralized and the string should be landed at a position where the intake is on the low side of the wellbore to minimize the amount of free gas that enters the pumping system.

Tubing anchors

Most PCP systems operate in the clockwise direction, so the resistive (i.e., friction) torque in the system tends to unthread the production tubing connections. As a result, tubing anchors are often run below or above the PC pump so that the resistive torque loading is transferred directly to the casing. They also alleviate the need to over-torque the tubing connections during makeup, which can substantially increase the number of makeups possible before thread damage occurs. Tubing anchors should be run with large-volume pumps and in high-speed applications in which the high resistive torques and system vibrations increase the potential for tubing backoff problems. Although several vendors supply conventional tubing anchors that can be used in this application, several manufacturers sell products specifically designed for PC pumping systems that differ from conventional anchors in that they resist torque while providing minimal axial load resistance. This facilitates removal of the tubing string from a well that has sanded in.

Tubing rotators

When tubing wear is a major issue, such as in slant and horizontal wells, tubing rotator systems can be used to substantially improve the service life of the tubing string. Rotating tubing hangers that allow the tubing to be rotated while the pump is in operation have been designed. The tubing is suspended by a thrust bearing, and a rotator mechanism that can be ratcheted manually or can be equipped to rotate the tubing continuously is provided. Rotating tubing hanger products are available from several different vendors.

Tubing drain

Tubing drains provide an alternative means to drain produced fluid from the production tubing string in PCP applications when the rotor cannot be pulled from the stator. These devices are commonly run in wells that are prone to experiencing seized rotors because of a buildup of produced sand above the pump or excessive elastomer swell. The drains are run with the production tubing string and are typically located a few tubing joints above the pump. To activate the drain, the production tubing is pressurized from surface to the point at which the drain “blows” (i.e., a plate ruptures or shear pins fail), allowing the fluid column in the tubing string to drain back to the casing annulus. The existing tubing drain products cannot be reset (i.e., closed) from surface; therefore, the tubing string must be tripped to replace them once they have been activated.

Tubing centralizers

PCP systems can experience severe vibration problems in some wells, particularly those operating at high speeds. Tubing centralizers can be run in conjunction with the production tubing to help stabilize the string and reduce the vibration amplitudes, which helps to mitigate tubing failures caused by backoff and/or fatigue.

Downhole gas separators

Downhole gas separators are used routinely in the oil industry to separate free gas from the production fluid before it enters the pump. Eliminating free gas from the produced fluid reduces its compressibility and therefore increases the volumetric efficiency of the downhole pump (which is determined based on liquid volume only). The gas separators used in PCP applications are normally passive devices that simply create a flow path that encourages the free gas to flow up the casing annulus. As a result, the completion details (e.g., casing size, pump seating location, and use of torque anchors) can have a significant influence on the effectiveness of these devices. Flow losses within the separator may also affect the amount of free gas entering the pump. A gas separator device designed specifically for directional- and horizontal-well applications uses a weighted cam and swivel system to ensure that the intake remains on the low side of the wellbore.

Monitoring and control systems

Since the early 1990s, operators have begun to incorporate field instrumentation and logic functions into process control systems for PCP systems. These systems monitor a variety of production-related parameters, make decisions that are based on their values, and then automatically implement these decisions. For example, some pumpoff control systems measure fluid levels or bottomhole pressures, compare the measured values with preset upper and lower limits, and then adjust the pump speed to maintain the fluid level within the desired range. These systems hold considerable promise for reducing manual monitoring time, decreasing downtime, and increasing productivity.

Pressure and flow switches

Pressure switches are used to shut down the PCP system in the event of either excessive or low flowline pressures to prevent damage to or failure of the surface or downhole equipment. Flow switches are used to control flow rates within prescribed upper and lower limits and to shut down the system if the rates move outside the desired operating range (i.e., usually low-flow conditions).

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See also

Progressing cavity pump (PCP) systems

Downhole PC pumps

Elastomers for PCP systems

PCP system design

Rod and tubing design for PCP systems

PCP power equipment

PCP system operations

PEH:Progressing_Cavity_Pumping_Systems