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Plunger design considerations and selection

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Plunger lift is used primarily in low rate, high gas-oil ratio (GOR) wells. This page focuses on the features desired in key equipment required to operate a plunger lift operation.

Plunger design and selection

Desirable features in a plunger include efficient sealing, reliability, durability, and the ability to descend quickly.[1][2] Rarely does a plunger exhibit all these characteristics, though. Usually a plunger that excels at one aspect sacrifices others. A wide variety of plungers is available to accommodate differences in well performance and operating conditions.

Plunger seal and velocity

The plunger seal is the interface between the tubing and the outside of the plunger, and probably is the most important plunger design element. Most plungers do not have a perfect seal; indeed, turbulence from a small amount of gas slippage around the plunger is necessary to keep liquids above and gas below the plunger. A more efficient seal limits slippage and allows the plunger to travel more slowly, which reduces the energy and pressure required to lift the plunger and liquid load. Less efficient seals allow excessive slippage, and so increase the energy and pressure required to operate the plunger.[2]

The velocity at which the plunger travels up the tubing also affects plunger efficiency[2][3][4] (Fig. 1). Very low velocities increase gas slippage and lead to inefficient operation and possible plunger stall. High velocities tend to push the plunger through the liquids. High velocities:

  • Waste well pressure
  • Cause equipment wear
  • Increase well backpressure

Target velocities allow just enough slippage to provide a good seal.

Target velocities have been be determined for various plunger types on the basis of each plunger’s sealing ability.[4] Better-sealing plungers operate efficiently at low velocities of 400 to 800 ft/min, whereas poor-sealing plungers must travel at 800 to 1,200 ft/min to maintain an adequate seal. Brush and/or pad plungers have the best seal, and bar stock plungers have the worst.

Reliability and durability

Reliability refers to the ability of the plunger to repeat performance over time or in adverse environments. Many plungers have internal moving components (e.g., pads, seals, valve rods, and bypasses) that might fail in the presence of sand or corrosive environments. Other plungers (e.g., brush or bar stock plungers) have no internal moving components and generally are more reliable.

Durability is a plunger’s ability to operate over many cycles with minimal wear and breakage. Typically, metal sealing plungers such as pad plungers are longer wearing, whereas brush plungers with fiber sealing elements wear quickly. Small-diameter plungers (for 1 1/4-in. or 1 1/2-in.-outside diameter (OD) tubing) tend to break more easily than larger-diameter plungers (those for 2 3/8-in. or 2 7/8-in.-OD tubing).

Plunger wear reduces the sealing efficiency of plungers over time. Inspect plungers periodically, typically every 1 to 3 months, depending on operating conditions and plunger type. Inspect new installations monthly until normal wear is determined. On the basis of such inspection results, plunger replacement can be documented and predicted.

Rapid plunger descent

Rapid plunger descent is a desirable plunger characteristic for wells that build pressure quickly. These wells typically are ready to operate as soon as the plunger reaches bottom. A plunger that falls more quickly can help to reduce shut-in times and buildup pressures, yielding lower average bottomhole pressures. In wells that require additional buildup after the plunger is on bottom, rapid plunger descent is not beneficial.

Typical plunger fall velocities range from 500 to 1,000 ft/min in tubing that contains only dry gas, but have been reported as low as 200 ft/min and as high as 2,000 ft/min, depending on such conditions as the type of plunger, condition of the tubing, and deviation of the well. In liquid, fall times typically are 150 to 250 ft/min, but have been reported as low as 25 to 50 ft/min.[2][4][5][6]

Plungers that seal poorly or that have built-in bypasses have the highest fall velocities. Better-sealing plungers fall more slowly. An internal bypass can be built into most plungers to increase fall velocity.

Other plunger characteristics

Plungers are built with either an internal or external fishing neck to enable slickline retrieval. Plungers might need to be retrieved when stuck, when the well loads because of equipment malfunction, or when a plunger wears out and will not surface.

There are many misconceptions regarding plunger design and choice. Weight sometimes is incorrectly perceived to be the most important consideration in plunger design.[4] This misconception stems from the incorrect belief that 1 psia is equivalent to 1 lbm, such that a 10-lbm plunger would require 10 psia, for example, or a 50-lbm plunger would require 50 psia. Actually, a 10-lbm plunger requires just over 3 psia to move in 2 3/8-in. tubing (ignoring friction). Although the weight of the plunger does affect the pressure requirements, the seal and liquid-slug size play a more important role in determining efficient plunger operation and required buildup pressure.

Plunger types

Of the many plunger types that are available, the most common ones are:

  • Bar stock
  • Wobble washer
  • Sealed pad
  • Retractable pad
  • Brush
  • Internal bypass
  • Side-pocket mandrel

Plungers can be manufactured in a combination of these types. Lengths and diameters also can be adjusted to meet installation requirements.

Bar stock

A bar stock plunger (Fig. 2) is a piece of metal (solid or hollow) whose surface is machined with grooves, spirals, or other shapes to create turbulence and thus the seal, between it and the tubing wall. The bar-stock-plunger seal is one of the least efficient available.

Wobble washer

A wobble washer plunger (Fig. 2) is similar to a length of bolt that is full of loose-fitting washers. Its sealing characteristics are comparable to those of a bar stock plunger, but the side-to-side movement of its loose washers sometimes allows it to travel through tubing anomalies that would stick a bar stock plunger. The wobble washer plunger can be less durable than a bar stock or brush plunger, and should it fail in the well, retrieving all its washers can be difficult.


Pad plungers are popular because of their durability and efficient seal. A pad plunger (Figs. 3 and 4) incorporates spring-loaded metal pads that are fitted on a mandrel that expands to maintain contact with the tubing walls. The pads improve the sealing ability of the plunger by providing less bypass area for gas slippage, but because of this the pad plunger falls more slowly than other plungers. Pad plungers are available with one set or multiple sets of pads. In general, the more sets of pads, the better the seal, but the fit of the pad against the tubing wall also can improve the seal.

Sand can create problems for most pad plungers, because the sand has a tendency to deposit behind the pads. When this happens, the pads are unable to retract and the plunger might become stuck.

Sealed pad

A sealed pad plunger (Fig. 5) is an improved version of the pad plunger. In a normal pad plunger, gas can slip behind the pads, making the seal less efficient. The improved plunger has seals behind the pads, eliminating gas slippage. The seals may be made up of metal, rubber, polymer, or a tortuous path that creates turbulence behind the pads. Take care that the sealing material is compatible with well fluids.

Retractable pad

A retractable-pad plunger seals well when unloading liquid, and falls very quickly. This type of pad plunger is built with a shift rod that enables the pads to retract and expand. The pads retract when the plunger reaches the surface and contacts a strike plate in the catcher. The plunger then has a much smaller than normal OD, which helps it to descend quickly. It might even be able to fall against flow. When the plunger drops to the bottom of the well, the shift rod strikes the plunger stop and causes the pads to expand, readying the plunger to lift the next liquid load. Because of its internal moving parts, the retractable-pad plunger is less durable and can become stuck if the pads fail to expand when the plunger reaches the bottom of the well.


A brush plunger seals very well and falls rapidly, but its bristles may wear quickly. A brush plunger (Figs. 3 and 4) is similar to a pipe cleaner. Bristles made of a fiber appropriate for well conditions are attached to a central mandrel. The OD of the bristles can be adjusted for varying tubing diameters and can be specified to be larger or smaller than the tubing diameter. In most cases, new brush plungers have bristle diameters slightly larger than the tubing so that the bristles maintain constant contact with the tubing. This, coupled with the high turbulence created when gas flows through the bristles, gives the plunger excellent sealing characteristics.

Brush-fiber material and stiffness affect plunger durability and influence what diameter is chosen. A stiff bristle will wear longer, but can be cut so large that it prevents the plunger from falling. A softer bristle can be built with an oversized brush diameter for increased seal, but tends to wear out more quickly. Material selection is important in wells with high temperatures because some nylon-fiber material melts at higher temperatures.

Internal bypass

An internal bypass can be built into any type of plunger (Figs. 6 and 7). As with the retractable-pad plunger, in an internal-bypass plunger there is a shift rod that causes the bypass to open at the surface and close at the plunger stop. There are variations of the shift-rod mechanism that require a special lubricator with a permanent rod built into the shock-spring strike plate. An even newer variation is a two-piece plunger, which includes a ball and cylinder that fall separately but rise as a single unit. The bypass also allows the plunger to fall more quickly. These types of plungers sometimes are used without any surface control because of their ability to freely cycle while the well is flowing.

Side-pocket mandrel

The side-pocket-mandrel plunger (Fig. 8) is designed for use with gas lift side-pocket mandrels. It is longer than other plungers (5 to 20 ft), with seals on both ends, and is used to bridge large inside diameter (ID) increases across gas lift mandrels. Such ID increases can cause excess gas slippage or plunger stall on shorter plungers, preventing operation. The side-pocket-mandrel plunger always keeps either the top or bottom seals in contact with normal tubing ID, allowing a continuous seal in the tubing as the plunger passes through the large ID. This specialty plunger also can be used when a packer, blast joints, subs, or other equipment is installed with an ID that is larger than the tubing ID.

Evaluation of control methods

Plunger controller

A plunger controller controls the shut-in, unloading, and flow periods of a plunger system. It does this by operating one or more surface control valves to shut in and flow the well. Different controllers use various set points and well data to determine the lengths of these periods. Controllers can be either manually set devices, such as timers or differential-pressure controls, or self-adjusting systems, such as electronic “smart” controllers that operate on the basis of time, pressure, and/or plunger velocity.

Manual on/off timer

A manual on/off timer controls the plunger system according to preset shut-in and flow times. Originally, manual timers were wind-up pinwheel models that actuated a pneumatic valve. Newer versions use electronic clocks and a solenoid to actuate the valve. The operator programs them with appropriate predetermined on and off times. Frequently these times are determined through a long trial-and-error process, during which operators must make small changes each day to optimize the well. If operating conditions are static, the on/off timers may provide efficient plunger operation, but when conditions change (e.g., if line pressure increases), the operator must make changes to the settings. To keep the plunger running in all conditions requires a program that assumes the worst-case conditions, such as the highest line pressures experienced during normal operations. Such conservative programming of the manual on/off timer minimizes the chances of well loading, but causes higher average bottomhole pressures and, therefore, lower production rates.

Pressure differential controller

Pressure-differential controllers monitor tubing, casing, and line pressures to determine shut-in and flow periods. Early versions of a pressure controller simply monitored casing pressure. When a high casing pressure was reached, the well opened. When the well blew down to a low casing pressure, it was shut in again. If operating conditions varied, the control set points had to be reset.

Newer controllers use tubing, casing, and line pressure, as well as the design criteria presented earlier in this chapter (and below) to calculate when sufficient casing pressure has been reached to open the well. Eq. 1 calculates required casing pressure:




The well is opened when it meets this calculated required casing pressure. Once the plunger has reached the surface, tubing and casing pressures are used to calculate a differential pressure that gives an estimate of slug size. When a preset differential pressure is reached, it is assumed that an adequate liquid load is in the tubing, and the well is shut in.

Automation and remote monitoring have helped make this type of controller more dependable. The ability of some pressure-differential controllers to make adjustments on the basis of changing operating conditions improves well performance. Without this capability, a program that assumes the worst-case operating conditions must be used.

Automated on/off timer based on plunger velocity

Adding microprocessors and plunger-velocity tracking to on/off timers was a major advance in controller technology (Fig. 9). These automated controllers monitor plunger velocity to continually optimize the well, eliminating the time-consuming trial-and-error process.[7]

The importance of plunger velocity and efficient velocities for various plunger types has been discussed already. In essence, a plunger must travel at the correct velocity to lift liquids efficiently. If the plunger ascends faster than the target velocity, then more energy was available than was required to lift the plunger, either because the liquid load was too small or because pressure buildup was too great for operating conditions. In such a situation, the automated controller would decrease the shut-in time (to decrease pressure buildup) and increase the flow time (to increase the liquid load).

Conversely, if the plunger ascends more slowly than the target velocity, then too little energy was available to lift the plunger efficiently, either because the liquid load was too large or there was not enough casing pressure available. The automated controller then would increase the shut-in time (to increase pressure buildup) and decrease the flow time (to reduce the liquid load).

The controller increases and decreases shut-in and flow times on the basis of user-set time increments. For example, an operator might set the controller to decrease the shut-in time by three minutes and increase flow time by two minutes every time the plunger ascends too fast. In this manner, the controller slowly adjusts until the well is optimized. This slow adjustment will optimize the well, but it also can be an issue in that it takes the controller many cycles to react to changing conditions. The problem can be partially remedied by using a controller that allows for proportional adjustments. In proportional adjustments, if the target plunger velocity is missed by a small amount, the changes to shut-in and flow times also might be small. If the target velocity is missed by a larger amount, the changes might be larger. This allows a well to react quickly to fast or slow plunger velocities.

A drawback with time-based plunger-velocity controllers is that a target velocity can be reached with either large slugs and long shut-in periods, or small slugs and short shut-in periods. As discussed earlier, production will be higher with short shut-in periods, but the controller might assume that the well is optimized with large slugs and long shut-ins. Good initial controller setup can help to prevent this problem, but it is important for the operator to check the controller periodically to make sure it is operating with the minimum amount of shut-in time, and to make a manual adjustment, if necessary.

Combination automated on-off and pressure monitoring

One of the most efficient controllers currently available monitors flow rates, pressure differential, and plunger speed. It is efficient because it reacts quickly to changing well conditions. To determine flow time, this combination controller compares the flow rate of the well to a calculated critical or unloading rate. The well is allowed to flow a specific length of time in relation to this flow rate and then is shut in. While the well is flowing, the controller constantly recalculates the critical rate on the basis of actual tubing pressure, which allows quick reaction to changing flowing conditions.

To determine shut-in time, the casing, tubing, and line pressures are monitored. Like an advanced pressure-differential controller, the combination controller uses plunger design equations to determine when the casing pressure has reached the minimum needed to open the well and operate the plunger. Thus, the controller allows the plunger to operate as soon as the well is ready.

Using these parameters alone is an efficient means to control plunger lift, but it can be further optimized by using plunger velocity with flow and shut-in multipliers. The flow multiplier is an adjustment to the critical flow rate. A flow multiplier of 1.0 flows the well until it reaches critical flow rate. A flow multiplier of 0.9 flows the well until it falls to 90% of the critical flow rate (resulting in a longer flow time). A flow multiplier of 1.1 flows the well until it is at 110% the critical flow rate (shorter flow time). If the plunger ascends too quickly, the controller lowers the flow multiplier. If the plunger ascends too slowly, the flow multiplier is increased. The shut-in time is changed similarly with a casing-pressure multiplier.


All the plunger controllers discussed here can be used with a venting option. With a venting system, the controllers typically will switch to venting if the plunger does not reach the surface in a specified period of time. The manual controller requires an operator to determine when the controller vents. An automated controller uses flowing conditions to determine when and how long the well should vent and, over time, attempts to eliminate venting by making changes to shut-in and flow times. For automated controls, venting is a preventative measure to keep the plunger operating during short periods of high line pressures. Venting is discussed in more detail in Plunger lift applications.

This is optional; not found in all installations.

High-line pressure delay

High-line-pressure delay prevents the plunger from operating against abnormally high line pressures, which cause the plunger to load and die. Although optional, this delay feature is recommended with all applications. With high-line-pressure delay, a pressure transducer or switch gauge monitors surface pressures and shuts in the well when pressures are too high for the plunger to operate. Automated controllers incorporate a delay that requires the high pressure to continue for a period of time (usually 5 to 15 minutes) before shutting in the well. Once line pressure drops, the controller typically will return the well to the start of the shut-in cycle.

This option is very useful in gathering systems that use a single compressor. When the compressor stops running for any reason, high-line-pressure delays at individual wells override control of the plunger control valve and shut in the well, then automatically reset the well, making compressor downtime easier for the operator to handle.

This is optional; not found in all installations.

Acoustic fluid-level/plunger descent tracking

Acoustic fluid-level devices can be used to track plunger descent and liquid-load sizes.5,6 Analysis equipment is being developed that will automatically track plunger descent, using acoustic signals sent from the wellhead or by listening to the impact the plunger has with each tubing collar, and will use this measurement to determine the exact minimum shut-in time required for each cycle. This is useful for operating the well with the least amount of shut-in time, for making sure the plunger is on bottom before attempting to flow the well, and for troubleshooting plunger problems.

This equipment also may be used with tubing/casing-flow plunger lift. The casing purge cycle can be managed more efficiently by determining exactly when the fluid has been transferred from the casing annulus to the tubing.

This is optional; not found in all installations.

Remote control/telemetry

Adding the ability to monitor and make adjustments remotely will improve any plunger-lift controller. Several manufacturers have incorporated electronic flow measurement, pressure monitoring, computer software, and either phone, radio, or Internet communications into their plunger systems (Figs. 10 through 12). Case studies have shown that adding remote control increases production, even on wells that previously had been equipped with self-adjusting electronic controllers.[8] One advantage is the ability to view production and pressure data on a very small time scale, such as 1-min increments. This makes diagnostic work very easy because all stages of the plunger cycle can be analyzed for pressure or flow anomalies. Also, viewing the data remotely enables quick diagnostics on many wells, as well as the ability to use experts who cannot be on site. Remote control allows immediate adjustments to the system when troubleshooting. As with all artificial-lift equipment, better accessibility leads to quicker response time and an increased understanding of the operations taking place.

This is optional; not found in all installations.

Missed-trip protection

Some controllers have missed-trip protection, a feature that can save operator time and prevent equipment damage by shutting in the well in situations involving repeated plunger nonarrival and/or slow arrival. If the plunger fails to surface a preset number of times, usually five or fewer, the system can be automatically suspended and the well shut in, which keeps the well from loading and dying and gives it time to build pressure. The operator then can restart the plunger system immediately upon arriving at the well, whereas if the well is not automatically shut in, the operator might have to make additional trips back to the well.

Missed-trip protection also prevents dry plunger trips when there is damage to the plunger sensor or sensor line. If the sensor or sensor line is damaged, the controller will not recognize plunger arrivals. On the basis of this perception, automated controllers will try to make the plunger surface by making adjustments (flowing less and shutting in longer), leading to very fast plunger arrivals. In such situations, if the controller is allowed to continue to adjust, the plunger velocity can become so high that the plunger and the lubricator/catcher will be damaged.

Controllers with this capability also can shut in the well when the plunger arrivals repeatedly have been at a slower than targeted velocity. This is usually not as useful. If the plunger velocity is slower than ideal, an automated controller should be able to adjust to bring the plunger back to the target velocity. If a system problem is causing the slower trips, then the plunger eventually will fail to arrive. The missed-trip protection would then shut in the well.

This is optional; not found in all installations.

Swab mode

Some controllers incorporate a swab mode, which is used primarily in wells that have been worked over with completion fluids or chemically treated, such that it might be necessary to remove the additional liquids before starting normal plunger operation. In swab mode, the well is shut in immediately upon plunger arrival at the surface. This tends to conserve well pressure and produce many small liquid loads. In this manner, the additional fluids are “swabbed” with the plunger.

Controllers operate in swab mode by requiring the plunger to make a preset number of consecutive arrivals at or above the target velocity before flow time is allowed. Shut-in time adjustments usually continue, while flow time adjustments are suspended. When the plunger arrival criterion has been met, the additional well liquids are assumed to be unloaded, and the controller resumes normal operation.

This is optional; not found in all installations.

Evaluation and modification of production facilities

Surface production facilities and equipment

Surface equipment (e.g., separators, heater treaters, and compressors) should be sized to handle the high instantaneous flow rates that accompany cyclical plunger-lift flow. Proper plunger-system operation can minimize these fluctuations (by operating at the minimum shut-in period), but flow rates still will vary.

Monitor pressures from the wellhead through all surface equipment to the sales point and beyond, and use these pressure nodes to identify and eliminate restrictions and leaks. Piping, connections, valves, check valves, and even chokes sometimes are already in place, and are overlooked when plunger lift is installed. Every restriction increases the pressure necessary to operate the plunger lift and potentially reduces well production. Eliminate leaks upstream of the control valve to enable effective static-pressure buildup. Leaking equipment can allow liquid entry into the wellbore during the shut-in cycle, loading the well or preventing efficient plunger operation.

Dehydration can be very difficult in single-well applications. If initial rates are too high, glycol could be forced out of the dehydrator and lost. Minimize the loss of dehydration fluid by installing pressure-differential controllers or bypasses or by using desiccant-type dehydrators.


Electronic flow measurement (Fig. 12) is very beneficial for plunger-lifted wells. Electronic measurement more accurately records cyclical production rates, increasing the profitability of plunger-lift applications. Dry-flow paper-chart recorders (Fig. 13) are difficult to integrate if production has a wide sweep on the chart or over-ranges the recorder, or if the chart time cycle is too long.

Larger-range springs and orifice plates help to keep differentials within a measurable range. The orifice plate should be capable of measuring the peaks and valleys of the plunger flow. Install as large an orifice plate as possible; as with the motor valve and other surface equipment, an orifice plate that is too small can act as a choke. Small plates also can become bowed or damaged if subjected to high differentials at the beginning of a cycle.

Pressure-differential controls

A pressure-differential control (PDC) limits the maximum flow rate through production equipment of a plunger-lifted well. The PDC uses an orifice to measure differential pressure and flow rates, and throttles the plunger control valve. Using a PDC can prevent overranging of measurement equipment, solve dehydration problems, and even remedy surface-equipment sizing problems.

The drawback to using a PDC is that it effectively is a choke, and so increases the pressure required to operate the system. It chokes the well only when a specific flow rate is exceeded, and the temporary loss in flow rate might be less costly than replacing surface equipment.

High-low pressure control pilots

High-low-pressure control pilots also can be incorporated with plunger-lift control valves. Although they do not control flow rates, they are effective at limiting maximum surface flowing pressures. If well flowing pressures exceed the surface-equipment allowable operating pressures, the high/low pilot will protect the equipment by shutting in the well.


  1. Hacksma, J.D. 1972. User’s Guide to Predicting Plunger Lift Performance. Proc., Nineteenth Annual Southwestern Petroleum Short Course, Lubbock, Texas (1972) 109–118.
  2. 2.0 2.1 2.2 2.3 Mower, L.N., Lea, J.F., E., B. et al. 1985. Defining the Characteristics and Performance of Gas-Lift Plungers. Presented at the SPE Annual Technical Conference and Exhibition, Las Vegas, Nevada, 22-26 September 1985. SPE-14344-MS.
  3. Morrow Jr., S.J. and Rogers Jr., J.R. 1992. Increasing Production Using Microprocessors and Tracking Plunger-Lift Velocity. Presented at the SPE Mid-Continent Gas Symposium, Amarillo, Texas, 13-14 April 1992. SPE-24296-MS.
  4. 4.0 4.1 4.2 4.3 4.4 Phillips, D.H. and Listiak, S.D. 1998. How to Optimize Production from Plunger Lift Systems. World Oil (May): 110.
  5. McCoy, J.N. et al. 2001. Plunger Lift Optimization By Monitoring And Analyzing Wellbore Acoustic Signals And Tubing And Casing Pressures. Proc., Forty-Eighth Annual Southwestern Petroleum Short Course, Lubbock, Texas, 80–87.
  6. Rowlan, O.L. et al. 2001. Optimizing Plunger Lifted Wells By Acoustically Tracing the Plunger Fall. Proc., Forty-Eighth Annual Southwestern Petroleum Short Course, Lubbock, Texas, 104–114.
  7. Lusk, S. and Morrow, S.J. Jr. 2000. Plunger Lift: Automated Control Via Telemetry. Proc., Forty-Seventh Annual Southwestern Petroleum Short Course, Lubbock, Texas, 73.
  8. Morrow Jr., S.J. and Rogers Jr., J.R. 1992. Increasing Production Using Microprocessors and Tracking Plunger-Lift Velocity. Presented at the SPE Mid-Continent Gas Symposium, Amarillo, Texas, 13-14 April 1992. SPE-24296-MS.

Noteworthy papers in OnePetro

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See also

Plunger lift

Plunger lift applications

Plunger lift design and models

Plunger lift installation and maintenance