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Petroleum Engineering Handbook

Larry W. Lake, Editor-in-Chief

Volume IV - Production Operations Engineering

Joe Dunn Clegg, Editor

Chapter 16 – Plunger Lift

Scott D. Listiak SPE, EOG Resources Inc. Daniel H. Phillips SPE, ConocoPhillips Co.

Pgs. 839-886

ISBN 978-1-55563-118-5
Get permission for reuse

Plunger lift has become a widely accepted and economical artificial-lift alternative, especially in high-gas/liquid-ratio (GLR) gas and oil wells (Fig. 16.1). Plunger lift uses a free piston that travels up and down in the well’s tubing string. It minimizes liquid fallback and uses the well’s energy more efficiently than does slug or bubble flow. As with other artificial-lift methods, the purpose of plunger lift is to remove liquids from the wellbore so that the well can be produced at the lowest bottomhole pressures. [CD edition includes video clips— Basic Plunger Animation and Plunger Lift System.]

Whether in a gas well, oil well, or gas lift well, the mechanics of a plunger-lift system are the same. The plunger, a length of steel, is dropped through the tubing to the bottom of the well and allowed to travel back to the surface. It provides a piston-like interface between liquids and gas in the wellbore and prevents liquid fallback—a part of the liquid load that effectively is lost because it is left behind. Because the plunger provides a "seal" between the liquid and the gas, a well’s own energy can be used to lift liquids out of the wellbore efficiently.

A plunger changes the rules for liquid removal. In a well without a plunger, gas velocity must be high to remove liquids,[1] but with a plunger, gas velocity can be very low.[2][3][4] Thus, the plunger system is economical because it needs minimal equipment and uses the well’s gas pressure as the energy source.[5][6][7] Used with low line pressures or compression, plunger lift can produce many types of wells to depletion.[3][5][8]

In recent years, the advent of microprocessors and electronic controllers,[9][10][11][12] the studies detailing the importance of plunger seal and velocity,[13] and an increased focus on gas production have led to a much wider use and broader application of plunger lift. Microprocessors and electronic controllers have increased the reliability of plunger lift.[9][10][12] Earlier controllers were on/off timers or pressure switches that needed frequent adjustment to deal with operating-condition changes such as line pressures, plunger wear, variable production rates, and system upsets. This frustrated many operators and caused failures, and thus limited plunger use. New controllers contain computers that can sense plunger problems and make immediate adjustments. Techniques with telemetry, electronic data collection, and troubleshooting software continue to improve plunger-lift performance and ease of use.[12]

Traditionally, plunger lift was used on oil wells—as the wells started to load or as a means of gas lift assist—and many early articles discussed optimization of liquid production.[8][14][15][16] Plunger lift lately has become more common on gas wells, and papers from the 1980s onward have focused on this aspect.[2][3][4][5][6][7][9][17]

In the 1980s, several studies were conducted in the field and on test wells to verify 1950s and 1960s models and to better understand plunger operation. Morrow and Rogers,[9] Mower et al.,[13] Lea,[18] and Rosina[19] (among others) presented papers that verified and modified earlier models presented by Beeson et al.[14] and Foss and Gaul.[16] Importantly, for example, these studies clarified the relationship between plunger seal and velocity, indicating that a plunger that more completely seals against the tubing and travels at the proper ascent velocity minimizes gas slippage around the plunger. Reducing gas slippage allows the well to operate more efficiently at lower bottomhole pressures, which in turn increases production. The studies also found that efficient ascent velocities for various plungers range from 500 to 1,000 ft/min. These velocity data have been used successfully to improve methods for controlling and optimizing plunger-lift cycles and to produce highly efficient plungers.

These improvements have enabled plunger lift to be used for a broader range of well types and conditions, allowing its application even in extremely low-pressure wells ( < 100 psia), wells with high liquid production ( > 100 B/D), deep wells (16,000 + ft), slimhole wells (2 7/8- to 3 1/2-in. casing), and wells with packers. Operators have successfully used plunger lift in paraffin-, scale-, sand-, and hydrate-production environments.

Success in plunger lift systems depends on proper candidate identification, proper well installation, and the effectiveness of the operator. Candidate identification primarily consists of choosing a well with the proper GLR and adequate well-buildup pressure; however, makeup gas or compression can be used to amend unmet GLR and buildup-pressure requirements.

Proper well installation is important. A plunger must travel freely from the bottom of the well to the top and back to the bottom, carry well liquids, and produce gas with minimal restriction. Problems with tubing, the wellhead, or well configuration can cause failure.

The well operator must be able to understand the system. Plunger lift can be a difficult process to visualize because it comprises liquid and gas movement downhole during flowing and shut-in periods. Operators must understand the mechanism for oil- and (especially) gas-well loading, have a basic understanding of inflow performance, and be able to troubleshoot wells on the basis of tubing and casing pressures and flow performance. Even with electronic controllers, operators are necessary for finding initial plunger-lift operating ranges, choosing appropriate plunger types, and performing basic maintenance and troubleshooting. An operator without these skills will have trouble even with the best plunger-lift candidates.

Basic Operation

Purpose of Plunger Lift

Early in the life of a liquid-producing gas well or high-GLR oil well, rates and velocities usually are high enough to keep the wellbore clear of liquids (Fig. 16.2). At this point, liquids typically are produced as a mist entrained in the gas stream. The high turbulence and velocity of these gas rates provides an efficient lifting mechanism for the liquids and the well produces at steady flow rates.

As reservoir pressures decline and flow rates/velocities decrease, the lifting mechanism changes.[20] Liquids no longer are entrained in mist and begin to coalesce on the walls of the production tubing. The liquids still might move up and out of the well, but somewhat less-efficiently than in mist form.

As gas rates and velocities continue to drop, the effect of gravity on the liquids becomes more apparent. Liquids on the tubing walls that were moving upward begin to stall, and gas slips through the center of the liquid. When enough liquids stall, liquid "slugs" are formed that inhibit gas flow. The well begins a cyclic process of unloading liquids that commonly is referred to as "heading" or "slugging." Liquid collects on the tubing walls, increases hydrostatic backpressure, restricts gas flow, and further decreases gas velocity.

In a short period of time, the reservoir might build sufficient gas pressure under the liquid slugs to overcome the hydrostatic pressure and force the slug back up the tubing. This gas expands, partially carrying liquid, partially slipping through the liquid. Much of the liquid is carried out of the wellbore, and the well flows at higher rates because of a decrease in hydrostatic pressures. Eventually, the liquid left behind in the tubing and the new liquid from the reservoir form slugs, and the process repeats (Fig. 16.3).

Whereas mist flow is an efficient method of removing wellbore liquids, severe heading is not. The reason for this inefficiency is that gas tends to flow through liquids rather than to push them up and out of the wellbore, especially at low velocities. In intermittent gas lift, a rule of thumb is that 5 to 7% of the liquid load is left behind for every 1,000 ft of depth. In a 10,000-ft well, that can be 70% of the liquid load! This fallback exerts hydrostatic backpressure on the reservoir, restricting gas production.

Left alone, heading can occur for weeks or possibly several months, depending on reservoir permeability, reservoir pressure, and liquid inflow. Eventually, a well will cease heading and stop producing liquids (or most liquids) altogether. The well sometimes will continue to produce at low flow rates, or it might stop flowing completely (known as "loaded," "logged-off," or "dead"). At this point, the liquids are not moving out of the well, and any production gas merely is bubbling through a static liquid column.

According to the Turner et al.[1] critical-flow-rate correlation (Fig. 16.4), a well that produces gas and water in 2 3/8-in. [1.995-in. inner diameter (ID)] tubing to a 100-psia surface pressure requires approximately a 320 Mscf/D flow rate to prevent fallback and unload liquids. Below this rate, liquid fallback will occur and liquids will not be removed adequately. The same well with a reservoir pressure of 500 psia only requires a water column of 800 to 1,000 ft to shut off flow completely. That hydrostatic pressure is equivalent to < 4 bbl of water in 2 3/8-in. tubing! So, below critical flow rates, a very small amount of liquid can limit production severely.

When using plunger lift, however, unloading relies less on critical flow rates and much more on the well’s ability to store sufficient gas pressure to lift the plunger and a liquid slug to surface. The piston-like interface the plunger provides between liquid and the gas acts as a seal between the two, preventing fallback and allowing the well’s energy to build up sufficiently to lift liquids out of the wellbore. Thus, liquids can be removed efficiently, even when gas velocity is very low.

Plunger-Lift Operation and Cycles

In its simplest form, plunger operation consists of shut-in and flow periods. The flow periods are divided into periods of unloading and flow after plunger arrival. The lengths of these periods vary with application, producing capability of the well, and pressures. In specialized cases that use plungers that can fall against flow, there might not be a shut-in period; however, most wells require some shut-in, which is the basis of the discussion below.

A plunger cycle starts with the shut-in period that allows the plunger to drop from the surface to the bottom of the well (Fig. 16.5). At the same time, the well builds gas pressure that is stored in either the casing, the fracture, or the near-wellbore region of the reservoir. The well must be shut in long enough to build sufficient reservoir pressure to provide energy to lift both the plunger and liquid slug to the surface against line pressure and friction. When this pressure has been reached, the flow period is started and unloading begins.

In the initial stages of the flow period, the plunger and liquid slug begin traveling to the surface. Gas above the plunger quickly flows from the tubing into the flowline, and the plunger and liquid slug follow up the hole. The plunger arrives at the surface, unloading the liquid. Initially, high rates prevail (often three to four times the average daily rate) while the stored pressure is blown down. The well now can produce free of liquids, while the plunger is held at the surface by the well’s pressure and flow. As rates drop, so do velocities. Eventually, velocities drop below the critical rate, and liquids begin to accumulate in the tubing. The well is shut in, and the plunger falls back to bottom to repeat the cycle.

There are many common names for these periods. Shut-in also is known as a "closed," "off," or "buildup" period. The time during which the plunger travels up the hole also is called an "open," "on," "unloading," or "flow" period. The flow period after the plunger reaches the surface is known variously as an "open," "on," "flow," "afterflow," "blowdown," or "sales" period.

Pressure Response During Plunger Cycles

The pressure response of a well on plunger lift helps explain the plunger lift cycles. Figs. 16.6 and 16.7 and the discussion below describe a typical pressure response for a well with tubing and no packer and for which surface tubing and casing pressures can be measured. Fig. 16.6 shows three pressures—casing, tubing, and line—and the instantaneous flow rate of a well during a plunger cycle. Fig. 16.7 shows the same pressures and rate over a period of several days.

By the end of the shut-in period, the well has built up to the maximum casing pressure, and to a tubing pressure that is lower than the casing pressure. The difference between these is equivalent to the hydrostatic pressure of the liquid in the tubing.

When the well is opened, the tubing pressure quickly drops to line pressure while the casing pressure slowly decreases until the plunger reaches the surface. As the plunger nears the surface, the liquid on top of the plunger might surge through the system, causing spikes in line pressure and flow rate. This continues until the plunger reaches the surface. After the plunger surfaces, a large increase in flow rate will produce higher tubing pressures and an increase in flowline pressure. Tubing pressure then will drop to very near line pressure. Casing pressure will reach its minimum either upon plunger arrival, or afterward while the casing blows down and the well produces with minimal liquids in the tubing. If the well stays above the critical unloading rate, casing pressure will remain fairly constant or might decrease further. As the gas rate drops, liquids become held up in the tubing and casing pressure increases.

Upon shut-in, the casing pressure builds more rapidly. How quickly depends on the inflow performance and reservoir pressure of the well. As the flowing gas friction ceases, the tubing pressure will increase quickly from line pressure and eventually will track casing pressure (minus the liquid slug). Casing pressure will continue to increase toward maximum pressure until the well is opened again.

Obtaining Maximum Production on Plunger Lift

In a well with plunger lift, as with most wells, maximum production occurs when the well produces against the lowest possible bottomhole pressure. On plunger lift, the lowest average bottomhole pressure almost always is obtained by shutting in the well for the minimum time.[8][9][10] However, practical experience and plunger-lift models show that lifting large liquid slugs requires higher average bottomhole pressure, however, so the goal of plunger lift should be to shut in the well for the minimum time period and to produce only as much liquids as can be lifted at this minimum buildup pressure (Fig. 16.8).

The absolute minimum shut-in time, regardless of other operating conditions, is the time it takes the plunger to reach bottom. (The exception to this rule is specialized plungers that fall while the well is flowing.) Plungers typically fall 200 to 1,000 ft/min in dry gas, and 20 to 250 ft/min in liquids.[13][16][23] Total fall time depends on plunger type, amount of liquid in the tubing, the condition of the tubing (e.g., crimped, corkscrewed, corroded), and the deviation of the tubing or wellbore.

The length of the flow period during and after plunger arrival is used to control liquid loads. In general, a short flow period brings in a smaller liquid load, and a long flow period brings in a larger liquid load, so that the well can be flowed until the desired liquid load has entered the tubing. A well with a high GLR might be capable of long flow periods without requiring more than minimum shut-in times. In such case, the plunger could operate as few as one or two cycles per day. Conversely, a well with a low GLR might never be able to flow after plunger arrival, and might require 25 or more cycles per day. In practice, if the well is shutting in for only the minimum amount of time, it can be flowed as long as possible to maintain target plunger rise velocities. If the well is shutting in for longer than the minimum time, there should be little or no flow after the plunger arrives at the surface.


Plungers currently are being used in many countries. Applications include wells with depths of 1,000 to 16,000 ft, producing bottomhole pressures of 50 to > 1,500 psia, and liquid rates of 1 to > 100 B/D. These are common ranges of application, but not necessarily limits of operation.[2][3][8][17][24]

The most common plunger-lift applications are for liquid removal in gas wells, but plungers also are used successfully for oil production in high-GLR oil wells, in conjunction with intermittent gas lift operations,[24][25][26][27] and to control paraffin and hydrates. In fact, plungers have been installed on wells for the sole purpose of preventing paraffin or hydrate buildup, thereby reducing paraffin scraping or methanol injection.[2][3][17]

For this use, when plunger lift is installed, paraffin, hydrates, and salt should be removed so that the plunger will travel freely up and down the tubing. Given initially clean tubing, a plunger excels at preventing formation of such deposits because of the scraping action of the plunger against the walls of the tubing, along with slugs of warm reservoir fluids.

Wellbore configurations for plunger lift include wells with an open annulus (most desirable), wells with packers, slimhole wells (2.875-in. and 3.5-in. casing), deviated wells, wells with coiled tubing, and wells with no tubing (casing plungers). Also, plunger lift is used in conjunction with intermittent gas lift, external gas supplies/injection, wellhead compression, vent options to tanks or low-pressure systems, some sand production, tubing/casing flow control (three-valve controllers), and carbon dioxide (CO2 ) floods.[17][25][26][27]

Typical Plunger Installation: Tubing With Open Annulus

Most commonly, plunger lift is applied in a gas or oil well with sufficient pressure and GLR to operate the system without additional supply gas. It is desirable to have tubing with no packer in the well. The annular space provides a storage area (volume chamber) for the gas under pressure and allows this gas to work freely on the plunger and liquid slug. Gas can flow from the casing to the tubing and provide lift with little restriction, and inflow from the reservoir is not relied on as the plunger moves up the hole. Because the stored-gas pressure provides the means to lift the plunger and liquid slug, adequate GLR and well pressures are critical.

Packers and Slimhole Completions

Some success has been experienced with plunger lift in gas wells with packers and slimhole completions. These installations are more difficult than those in a well with tubing and an adequate open annulus and will require higher bottomhole pressure and GLR. Because an annular volume is not available, gas must be stored in the near-wellbore region or in a natural or hydraulic fracture. The near-wellbore region must be large enough to store the volume necessary to operate the plunger and must be able to deliver that volume with minimal restriction or loss of energy through the reservoir and perforations. In addition, plunger-controller options that use the casing pressure cannot be used.

In some instances, production in wells with packers can be improved by shooting several holes in the tubing and allowing communication between the tubing and casing. In this manner, the casing annulus can be used, but because packers may be set high above the producing interval, wells may see increased hydrostatic backpressure in the loaded portion of the casing below the packer. In addition, scale and debris might easily plug the perforated holes. It is important to shoot enough holes to provide adequate flow area from the casing to the tubing.

Some slimhole wells have been equipped with small tubing in an attempt to gain annular volume. This may or may not provide improved plunger performance, depending on the annular volume obtained and the reduced hydraulic efficiency of plunger lifting in smaller tubing.

Deviated Wells

Theoretically, plunger lift can be run successfully in wellbores up to a 60° deviation. Several installations exist in 20° deviations. Because the plunger is small, it can handle some dogleg severity, but in this type of installation, be especially aware of plunger fall times. The greater the deviation, the more slowly the plunger falls and the longer it takes to get to the bottom. Fall times in deviated wells can be measured with slickline, by acoustic measurement, or by examining well production characteristics with various minimum shut-in times. Excessive fall times can reduce or prevent plunger-lift production.

Coiled Tubing

Nontapered coiled tubing can be plunger lifted. Larger coiled-tubing strings are very applicable to plunger lift, especially when the flash is removed. Flash on coiled tubing is a byproduct of welding during the manufacturing process. It is a thin bead of material that runs the inside length of the coiled tubing at the weld seam and upsets the smooth, continuous ID of the tubing. Plungers cannot seal against flash (except for some special brush plungers). The flash can be removed during manufacturing, but this must be specified.

Special plungers have been made for coiled tubing.[28] A flexible brush plunger has been designed to help curve around potential bends in coiled tubing at the bottom of the well; however, small coiled tubing (as with any small tubing) has tubing hydraulic problems that make plunger lift difficult. Smaller tubing requires much more pressure to lift the same volume of liquids, has larger pressure losses because of gas friction, and creates more backpressure on the formation. In addition, small-plunger equipment is less durable and might fail frequently.

Casing Plungers

Casing plungers act more like true pistons. The casing plunger has a synthetic sealing element that forms a seal against the walls of the casing and eliminates gas or liquid slippage. The well must only overcome the weight of the plunger, the liquid slug, and friction of the seal against the casing. Because large casing diameters are used (mostly 4.5-in. or greater), wellbore hydrostatics work in favor of this method. Larger slugs can be lifted with a lower pressure requirement. When the casing plunger reaches the surface, an internal bypass is opened to allow the plunger to fall against flow. This method has been used successfully in some areas of the U.S.A. (e.g., Ohio and Pennsylvania). Plunger sticking might occur in casing with varying weights and IDs, with poor casing integrity or condition, and with the reaction of some sealing elements to produced fluids (e.g., CO2, condensate).

Intermittent Gas Lift

Plungers work well with intermittent gas lift by reducing liquid fallback. The same amount of liquid then can be lifted with less gas volume and pressure, and wells can be lifted from greater depths. Long plungers with seals at both ends might be required to maintain plunger seal across gas lift mandrels.[24][25][26][27]

External Gas Supplies

Using makeup gas with plunger lift will increase the range of operation. A compressor or gas lift system can be used to supply external gas pressure and volume. This allows plungers to work at much lower pressures and GLRs. Injection-gas systems have been installed successfully to convert pumping fields to plunger lift with gas assist. Operators have used this technique to reduce costs caused by pumping failures and difficulty in pumping high-GLR oil wells.[24][25][26][27]

Wellhead Compression

It is not always possible to install centralized compression, and a single wellhead compressor might be necessary for production. Even with a compressor, wells still might experience liquid loading. To alleviate this problem, a plunger system can be installed in conjunction with wellhead compression. When using an electric compressor, the plunger controller can be used to control the compressor. During the shut-in period, the compressor is turned off. During the unloading and flow periods, the compressor is turned on.[29]

For a gas-engine-driven compressor, the installation is somewhat more difficult. A gas compressor cannot easily be automated to start and stop, so it is desirable to keep the gas engine running during both the flowing and shut-in periods. When flowing, the compressor simply sends gas to the sales pipeline. For shut-in periods, a bypass can be installed on the compressor that allows gas to circulate. The controller that operates the motor valve can be used to control an additional sales/bypass valve. To avoid potential problems with this setup, such as overheating of the circulating gas or insufficient supply gas to keep the compressor running, shut in the well for the minimum amount of time necessary to operate the plunger. Other possible solutions are to use a plunger with a bypass that can travel to bottom while the well is flowing, which reduces or eliminates shut-in; to provide an outside source of supply gas; and to improve the cooling capacity of the compressor.

Vent Options to Tanks or Low-Pressure Systems

Lower-pressure wells that do not meet plunger-lift pressure requirements at current line pressures might be able to operate if temporary vent or low-pressure cycles are used. Such a well can be set up to flow to a lower pressure while the plunger is ascending with the liquid load. Once unloaded, the well can be switched into the sales line until loading begins again.

Venting also is effective where gathering systems have large swings in line pressures. When line pressures increase erratically, the well can vent automatically to keep the plunger operating and to keep the well from loading and dying. If a well is vented correctly, only a small portion of the gas above the plunger will be lost to the atmosphere.

Before considering venting, however, take a few important precautions. First, use an automated controller that continually attempts to minimize and eliminate venting. Second, evaluate where the vented gas will flow. Venting to the atmosphere is the simplest option, albeit the least desirable one because it involves environmental-impact, government regulatory, and safety considerations. For example, if the surface equipment malfunctions, will liquids be discharged? If poisonous gases such as hydrogen sulfide (H2S) are present, venting directly to atmosphere can create additional safety hazards. Open atmospheric discharges might not be allowed in certain areas.

Vent tanks can be used to ensure that system upsets do not cause liquid spills. A combination high-/low-pressure separator is an option that will catch fluids and reduce venting pressures before sending vented gases to a tank; however, using vent tanks has drawbacks. For example, if downcomers or downspouts are used, rapid gas entry might cause liquid to be blown out of the tank hatch. Also, a vent line that is improperly piped into the tank can generate static electricity. Furthermore, if the thief hatch is blown open, oxygen might enter the tank, increasing the chances of reaching explosive mixtures in the tank.

The best venting option is to use a lower-pressure gathering system, or possibly a vapor-recovery system with a vent tank; however, if a low-pressure system is available and has sufficient capacity, producing to that system would be preferable over venting to it.

Plungers installed in marginal applications require more venting by design. When this is the case, consider alternate applications or artificial-lift methods. Possible alternatives to venting are to assist the plunger with injected gas down the casing or down a parallel tubing string.[25][26]

Some Sand Production

Wells that produce some sand can operate with plunger lift. Selecting a plunger with a brush-type seal, or a loose-fitting plunger with a poorer seal will allow sand production and help prevent the plunger from sticking in the tubing. An effective technique is to use a brush plunger that has a standard bristle outer diameter and smaller (downturned) metal ends. Installing sand traps at the surface or using sand-friendly seats on motor valves can prevent sand damage to seats and trims that would prevent the motor valve from closing. With sand, plungers also are prone to getting stuck in the lubricator and require cleaning at the surface. Some wells might require periodic downhole cleanouts.

Good plunger operation can reduce sand production relative to poor plunger operation. Short shut-in periods reduce pressure buildups, which leads to more consistent production and less-intense production surges. In some wells, sand production decreases with time; in others, continued sand production might make plunger lift impossible or uneconomical.

Tubing and Casing Flow

In some plunger-lift applications, casing-annulus flow improves production. If pressures and flow rates are such that the gas friction in the tubing chokes the well, casing flow might be beneficial.[30] This is the case for many low-pressure, high-permeability gas wells. The cycle is like a standard plunger-lift cycle (Fig. 16.9), but with two additional periods. After the shut-in and unloading periods, the casing annulus is opened to flow. Before shutting in the well again, the casing annulus is closed and the tubing left open to allow accumulated liquids in the casing to be transferred to the tubing.

Take care that the casing flow does not cause the tubing to cease flowing. Place a pressure-differential device or other type of choke on the casing outlet to keep sufficient flow up the tubing. If the tubing stops flowing, the plunger will drop, but probably will not reach the plunger stop by the time the casing purge cycle begins. Even if it does reach the stop, there might not be enough energy for the plunger to lift any liquid to the surface. Either way, the well eventually will load up.

This type of system is more difficult to operate than standard plunger installations. Their operation will benefit from knowledgeable operators and automatically adjusting plunger controllers.


Any gas can be used as the motivating force in plunger operations, even CO2 . When CO2 breakthrough occurs in a CO2 flood, GLRs might increase substantially, which leads to pumping problems and possible well-control problems. When the GLR meets the minimum requirement, plunger lifting wells might alleviate some of these problems and help reduce field pumping costs.[17]

Other Methods

Development and testing of new and improved plunger-lift methods is ongoing. Variations of the applications discussed above, as well as combinations of these plunger-lift techniques with other concepts and methods of artificial lift, continue to transform plunger-lift capabilities and to expand the limits and applications for this technology.

Design and Models

Plunger-lift systems can be evaluated using rules of thumb in conjunction with historic well production, or with a mathematical plunger model. Because plunger-lift systems typically are inexpensive and easy to install and test, most are evaluated by rules of thumb.

GLR and Buildup Pressure Requirements

The two minimum requirements for plunger-lift operation are minimum GLR and well buildup pressure. Plunger-lift operation requires available gas to provide the lifting force, in sufficient quantity per barrel of liquid for a given well depth. The minimum GLR requirement is approximately 400 scf/bbl per 1,000 ft of well depth and is based on the energy stored in a compressed volume of 400 scf of gas expanding under the hydrostatic head of 1 bbl of liquid.[3] One drawback to this rule of thumb is that it does not consider line pressures. Excessively high line pressures relative to buildup pressure might increase the requirement. The rule of thumb also assumes that the gas expansion can be applied from a large open annulus without restriction, but slimhole wells and wells with packers that require gas to travel through the reservoir or through small perforations in the tubing will cause a greater restriction and energy loss, which increase the minimum GLR requirement to as much as 800 to 1,200 scf/bbl per 1,000 ft.

Well buildup pressure is the bottomhole pressure just before the plunger begins its ascent (equivalent to surface casing pressure in a well with an open annulus). In practice, the minimum shut-in pressure requirement for plunger lift is equivalent to one and a half times the maximum sales-line pressure, although the actual requirement might be higher. This rule of thumb works well in intermediate-depth wells (2,000 to 8,000 ft) with slug sizes of 0.1 to 0.5 bbl/cycle. It does not apply reliably, however, to higher liquid volumes, deeper wells (because of increasing friction), and excessive pressure restrictions at the surface or in the wellbore.

An improved rule of thumb for minimum pressure is that a well can lift a slug of liquid when the slug hydrostatic pressure (phs) equals 50 to 60% of the difference between shut-in casing pressure (pcs) and maximum sales-line pressure:




This rule of thumb accounts for liquid production, can be used for wells with higher liquid production that require slug sizes of more than 1 to 2 bbl/cycle, and is regarded as a conservative estimate of minimum pressure requirements. To use Eqs. 16.1a and 16.1b, first estimate the total liquid production on plunger lift and number of cycles possible per day. Then, determine the amount of liquid that can be lifted per cycle. Use the well tubing size to convert that volume of liquid per cycle into the slug hydrostatic pressure, and use the equations to estimate required casing pressure to operate the system (see example below).

A well that does not meet minimum GLR and pressure requirements still could be plunger lifted with the addition of an external gas source. At this point, design becomes more a matter of the economics of providing the added gas to the well at desired pressures. Several papers in the literature discuss adding makeup gas to a plunger installation through existing gas lift operations, installing a field gas supply system, or using wellhead compression.[11][14][16][24][25][26][27][29]

Estimating Production Rates With Plunger Lift

The simplest and sometimes most accurate method of determining production increases from plunger lift is decline-curve analysis[3] (Fig. 16.10). Gas and oil reservoirs typically have predictable declines, either exponential or hyperbolic. Initial production rates usually are high enough to produce the well above critical rates (unloaded) and establish a decline curve. When liquid loading occurs, a marked decrease and deviation from normal decline can be seen. Unloading the well with plunger lift can re-establish a normal decline. Production increases from plunger lift will be somewhere between the rates of the well when it started loading and the rate of an extended decline curve to the present time. Ideally, decline curves would be used with critical-velocity curves to predetermine when plunger lift should be installed. This would enable plunger lift to maintain production on a steady decline and to never allow the well to begin loading.

Another method for estimating production is to build an inflow performance (IP) curve on the basis of the backpressure equation (Fig. 16.11).[4][10][21][22] This is especially helpful if the well has an open annulus and is flowing up the tubing, and if the casing pressure is known. The casing pressure closely approximates bottomhole pressure. Build the IP curve on the basis of estimated reservoir pressure, casing pressure, and current flow rate. Because the job of the plunger lift is to lower the bottomhole pressure by removing liquids, estimate the bottomhole pressure with no liquids. Use this new pressure to estimate a production rate with lower bottomhole pressures.


Plunger-lift models are based on the sum of forces acting on the plunger while it lifts a liquid slug up the tubing (Fig. 16.12). These forces at any given point in the tubing are:

Stored casing pressure freely acting on the cross section of the plunger.

Stored reservoir pressure acting on the cross section of the plunger, based on inflow performance.
  • The weight of the fluid.
  • The weight of the plunger.
  • The friction of the fluid with the tubing.
  • The friction of the plunger with the tubing.
  • Gas friction in the tubing.
  • Gas slippage upward past the plunger.
  • Liquid slippage downward past the plunger.
  • Surface pressure (line pressure and restrictions) acting against the plunger travel.

Several publications have dealt with this approach. Beeson et al.[14] first presented equations for high-GLR wells in 1955, on the basis of an empirically derived analysis. Foss and Gaul[16] derived a force-balance equation for use on oil wells in the Ventura Avenue field in 1965. Lea[18] presented a dynamic analysis of plunger lift that added gas slippage and reservoir inflow, and mathematically described the entire cycle (not just plunger ascent) for tight-gas/very high-GLR wells.

Foss and Gaul’s methodology[16] was to calculate (pc)min , the casing pressure required to move the plunger and liquid slug just before it reaches the surface. Because (pc)min is at the end of the plunger cycle, the energy of the expanding gas from the casing to the tubing is at its minimum. Adjusting (pc)min for gas expansion from the casing to the tubing during the full plunger cycle yields (pc)max , the pressure required to start the plunger at the beginning of the plunger cycle. The pressure must build to (pc)max to operate successfully.

The average casing pressure RTENOTITLE, maximum cycles Cmax, and gas required per cycle (Vg) can be calculated from (pc)min and (pc)max . The equations below are essentially those presented by Foss and Gaul[16] but are summarized here as presented by Mower et al.[13] The Foss and Gaul model is not rigorous—it assumes constant friction associated with plunger rise velocities of 1,000 ft/min; does not calculate reservoir inflow; assumes a value for gas slippage past the plunger; assumes an open, unrestricted annulus; and assumes that the user can determine unloaded gas and liquid rates independently of the model. Also, because this model originally was designed for oilwell operation that assumed the well would be shut in upon plunger arrival, RTENOTITLE is only an average during plunger travel. The net result of these assumptions is an overprediction of required casing pressure. If a well meets the Foss and Gaul criteria, it is almost certainly a candidate for plunger lift. For a full description of the Foss and Gaul model and for a description of improved models, see the references.[4][13][16][19][31]

Basic Foss and Gaul[16] Equations (Modified by Mower et al.[13] and Lea[18])

Required Pressures











Foss and Gaul suggested an approximation where K and plh + plf are constant for a given tubing size and a plunger velocity of 1,000 ft/min (Table 16.1).

Gas (Mscf) Required per Cycle




Maximum Cycles


Examples of Rules of Thumb and Foss and Gaul Calculations

The examples of rules of thumb and of Foss and Gaul calculations in this section use the well data in given in Table 16.2.

Example of Rule-of-Thumb GLR Calculation The minimum GLR (Rgl) = 400 scf/bbl per 1,000 ft of well depth. The well’s GLR is:



where qg is given in scf. The well GLR is > 400 scf/bbl per 1,000 ft and is adequate for plunger lift.

Example of Rule of Thumb for Casing Pressure Requirement to Plunger Lift (Simple)

The rule of thumb for calculating the minimum shut-in casing pressure for plunger lift, in psia, is:



With 800 psia of available casing pressure, the well meets the pressure requirements for plunger lift; however, this is the absolute minimum pressure required for low liquid volumes, intermediate well depths, and low line pressures.

Example of Rule of Thumb for Casing Pressure Requirement (Improved)

For this case, assume 10 cycles/day, equivalent to a plunger trip every 2.4 hours. Any reasonable number of cycles can be assumed to calculate pressures.

At 10 cycles/day and 10 bbl of liquid, the plunger will lift 1 bbl/cycle. The slug hydrostatic pressure (phs) of 1 bbl of liquid in 2 3/8-in. tubing with a 0.45-psi/ft liquid gradient is approximately 120 psia. Using Eq. 16.1b, the required casing pressure, in psia, is calculated as:



With 800 psia of available casing pressure, the well meets the pressure requirements for plunger lift.

Example of Foss and Gaul Type of Method to Determine Plunger-Lift Operating Range

In determining plunger-lift operating range, use Foss and Gaul K and plh + plf values for 2 3/8-in. tubing and average rise velocities of 1,000 ft/min. Calculate new friction factors if velocities are more or less than 1,000 ft/min.

Calculate the constants At, pp, Aa, Ra, Fgs, L, and Vt:

Area of tubing, ft2:



Differential pressure required to lift plunger, psi:


where At is given as in.2. Therefore:


Area of annulus, ft2:



Ratio of total area to tubing area (Eq. 16.8):



Lea[18] -modified Foss and Gaul[16] slippage factor [Foss and Gaul used a 15% factor (1.15) that could be translated to approximately 2% per 1,000 ft [18]]:



Length of 1 bbl of fluid in the tubing, ft/bbl (5.615 = scf in 1 bbl):



Volume of tubing above the slug (use for various slug sizes) (Eq. 16.10, but here in Mscf):


Assume some values for S (bbl) and construct Table 16.3. (Table 16.3 in the CD version of this chapter is an interactive electronic spreadsheet.)

It was given that the estimated production when unloaded is 200 Mscf/D with 10 B/D of liquid (GLR = 200/10 = 20 Mscf/bbl), and that the available casing pressure (or the pressure to which the casing will build between plunger cycles) is 800 psia. The available casing pressure, pc, is equivalent to the calculated (pc)max —or the pressure required to lift the assumed slug sizes. The well GLR is equivalent to the calculated required GLR. The maximum liquid production is a product of the slug size (S) and the maximum cycles per day (Cmax). Importantly, Cmax is not a required number of plunger trips, but rather the maximum possible on the basis of plunger velocities. In reality, most wells operate below Cmax because well shut-in time is required to build any casing pressure. In Table 16.3, note that the casing pressure (pc)max of 810 psia, the GLR of 20 Mscf/bbl, and the production rate of 10 B/D occur at slug sizes between 0.1 and 2.5 bbl. The well will operate on plunger lift.

Equipment Installation and Maintenance

A plunger lift candidate must meet GLR and pressure requirements, but the method of installation and the mechanical setup of the well also are extremely important. Installation is a frequent cause of system failure.[10] The following are key elements in the proper installation of a plunger system:

  • Equipment quality and metallurgy.
  • Evaluation of current and possible wellbore configurations.
  • Tubing and wellbore preparation.
  • Evaluation and installation of the downhole plunger equipment.
  • Evaluation and installation of wellhead and plunger surface equipment.
  • Design considerations and selection of a plunger.
  • Evaluation of control methods.
  • Evaluation and modification of production facilities.

For reference, Fig. 16.13 is a full wellbore schematic of major plunger-lift components, and Fig. 16.14 is a plunger-lift troubleshooting guide.

Equipment Quality and Metallurgy

There are many plunger-lift manufacturers and equipment options, so quality and design vary. Neither American Petroleum Inst. (API) standards nor those of similar agencies govern plunger-equipment specifications at this time. Purchasers have the ultimate responsibility for investigating the manufacturing process. Manufacturers who use International Organization for Standardization (ISO) 9000/9001 standards or equivalents help to ensure that customers will receive a quality product.

Evaluate material used in equipment manufacturing on the basis of the operating environment of each specific application. Carbon/carbon steel can be used in most installations; however, an appropriate grade of stainless steel might be necessary for some or all of the components in corrosive environments (e.g., H2S or CO2). Bottomhole temperature is another factor to consider. The minor ID expansion of tubing in a deeper, hotter well might affect the choice of material, as well as type of equipment. Some fiber and plastic materials used in brush and pad plungers have a maximum operating temperature.

Evaluation of Current and Possible Wellbore Configurations

The two typical installation scenarios are those in which existing wellbore configurations are used and those in which the wellbore is reconfigured to take full advantage of the plunger-lift system. Setting the tubing at the proper depth and with an open annulus offers the greatest chance of success. Other installations can work, but require sacrifices in production rates and longevity. One of the biggest factors affecting plunger-lift success is the forcing of applications into unfavorable configurations, such as wells with packers (with or without holes shot in tubing for communication), highly deviated wells (> 20 to 60°), slimhole wells (2 7/8-in. and 3½-in. casing), and small tubing (jointed pipe or coiled tubing smaller than 1¾-in. ID).

Keeping plunger lift in mind when originally completing a well is ideal. If a plunger is considered to be a potential lift method, then proper tubing, wellhead, and surface piping can be installed initially, making plunger lift inexpensive and effective.

Tubing and Wellbore Preparation

Often, plunger-lift installation is attempted in unacceptable tubing. Problems can arise from use of tubing that is degraded or worn (trash/fill, holes, crimps, scale, tight spots, pitting, and/or rod cut), has ID variations (out of place nipples, oversized or undersized blast joints, and/or mixed strings), is set at the wrong depth (too high or too low), or is undersized. Review well records to determine whether an acceptable tubing configuration is in place.

Sickline Tubing-Integrity Checks

Perform a slickline inspection even if records indicate that the wellbore has an acceptable tubing configuration for plunger installation. Tagging for fill and gauging the tubing are the minimum requirements for this inspection.

To tag for fill, run a small-OD tool (e.g., a sinker bar or sample basket) out of the end of the tubing. This ensures that the perforations are not covered and that the end of tubing is not plugged. At the same time, an end-of-tubing locator can be run to verify tubing depth. This is more important when well records do not clearly indicate the tubing depth.

Next, inspect the tubing ID with a gauge ring (Fig. 16.15). There are many varieties of gauge rings. Typically, gauge rings do a good job of finding the smallest ID of the tubing; however, they do a poor job of drifting the tubing because they usually are shorter than the plunger. Longer gauge rings can be built that mirror plunger sizes. Another option is to use the plunger selected for the specific well to drift the tubing. An even better option is to machine a hollow gauge ring with the same length and OD dimensions as the chosen plunger. The hollow gauge ring allows for quicker slickline trips in and out of the hole than does a solid plunger or solid gauge ring.

If the tubing gauges to the proper ID, plunger-lift equipment can be installed. If not, run a broach and/or swage to try to clean the tubing of obstructions or to bend the tubing walls out to the proper ID. A broach is a hardened piece of round steel with grooves, much like a round file. Broaches often are built in the shape of a swage. They are most effective on light scale buildup or similar light deposits. Smooth swages often are used when crimped tubing is suspected. The risk in running broaches and swages is the possibility of their getting stuck. A broach is more likely than the smooth swage to become stuck in crimped tubing. It might be less risky to use coiled tubing with a bit or scraper for slimhole or permanent-packer installations, where a stuck broach might become a permanent obstruction.

Considerations for Changing or Reconfiguring Tubing

If the current wellbore configuration is unacceptable, tubing may be reconfigured or a new string of tubing may be run. Decisions on the tubing size, where to land the end of tubing, and whether to reuse tubing should be weighed.

Used Tubing. Reusing tubing might be possible if the tubing has good integrity. Tubing that is pitted, rod-cut, or has weak pins is not recommended because it might fail prematurely, inhibit plunger rise and fall, and/or prevent an effective plunger seal. One solution is to line the tubing with an insert lining. Lined tubing is an uncommon application, but has very good sealing and friction characteristics and has been used successfully. Choose a durable lining that holds up against plunger wear and is designed for well temperatures and fluids.

Tubing Size. A common misconception is that tubing with larger diameters is more difficult to operate on plunger lift than tubing with smaller diameters (Fig. 16.16). The larger tubing actually is easier to operate because of the increased cross-sectional area, which has better hydraulics. A larger plunger, like a larger hydraulic cylinder, requires less pressure to move. Large tubing also holds more liquid per foot of height, thereby unloading larger volumes with a lower pressure requirement. The smaller tubing requires higher pressures to lift the same amount of liquids. Friction also can be more of a problem with smaller tubing.

Plunger-lift systems can be operated in practically any size tubing, with 2 1/16-in. OD (1¾-in. ID) or larger being more desirable. There is also a benefit in using "standard" equipment. Because of their abundance, 2 3/8-in. and 2 7/8-in. external-upset-end (EUE) tubing usually are the sizes of choice.

Tubing Depth. Evaluate each well for correct placement of the tubing. Place the end of the tubing very near a gas productive interval, typically in the middle to top perforations. Single pay zones with narrow perforated intervals are the easiest to correctly place tubing. Multiple commingled zones and/or large perforated intervals ( > 500 ft) require additional analysis because bottomhole pressure and pressure differentials between zones come into play. Use reservoir analysis, examination of well logs, and production logs to estimate reservoir quality and to help determine the best spot to land the end of tubing. Often, trial and error ultimately decide the best tubing depths, and may take a few attempts to get right, especially on wells with large perforated intervals and wells with low bottomhole pressures.

The most common setting mistake is to set the tubing too deep (Fig. 16.17). In this case, gas and liquid must flow below the perforations before entering the tubing. On shut-in, liquids end up above the plunger in the tubing, and between the plunger and perforations in the casing. When the well is opened, the plunger rises with liquids above, but the liquid in the casing enters the tubing behind the plunger. This additional liquid places increased backpressure on the well, is lifted inefficiently, might prevent the plunger from surfacing, and might load up the well. Even if the plunger operates, the well might still produce at much lower than expected flow rates. Tubing that is set too deep can either be raised or perforated higher to remedy the problem. Use slickline or electric line to shoot holes in the tubing at a shallower depth. If perforated, move the plunger stop to above the holes.

Setting the tubing high above the perforations is another common mistake[10] (Fig. 16.17). The large-ID casing will load more easily, leading to a permanent gas-cut liquid column between the end of tubing and the perforations. Higher backpressure and lower flow rates from these zones are the result.

Tools Run on the End of Tubing. Downhole plunger equipment can be maintained with slickline, so a re-entry guide might be desirable. Re-entry guides facilitate smooth return of slickline tools back into the tubing string. Re-entry tools can be as simple as a plain tubing collar, a mule shoe (standard collar cut at a 45° angle), or a specially designed guide shoe. Installing notched collars on the end of the tubing is discouraged because notches often are bent inward when tubing is run into the well. Slickline tools run in this situation are more likely to become stuck.

Drifting Tubing in the Hole. Ideally, to eliminate the possibility of crimps and other imperfections, the new or used tubing would be drifted as it is run in the well. Machine the drift to the same length and OD as the plunger that will be used. Build a standard fishing neck with a horizontal hole in the neck, to which a length of cotton rope can be attached. The rope should be longer than the average length of the stands of tubing being run in the well. As each stand of tubing is run in the wellbore, the drift can be safely lowered from the rig floor down the tubing. If tubing is overtightened or was crimped by tongs as it was made up, the drift will not fall, indicating that the stand of tubing being inspected should be pulled and replaced. Running the tubing with the plunger bottomhole assembly in place keeps the drift from being run out of the tubing or lost. Using cotton rope makes fishing easier, should the rope break.

Often, the mistake is made of drifting on the rig sand line after running the entire tubing string. The results of this are misleading because the weight of the sand line can force the drift through spots that are too small for smooth plunger travel.

Evaluation and Installation of Downhill Plunger Equipment

The bottomhole assembly may contain one or a combination of a plunger stop, bumper spring, standing valve, and strainer nipple. If tubing has not yet been run in the well, the bottomhole assembly can be run in place from the surface. If the tubing is in place, slickline can be used, or the stop can be dropped from the surface.

Plunger Stop

A plunger stop is placed inside the bottom of the tubing string to keep the plunger from falling through the tubing into the wellbore. Plunger stops can be set in a profile nipple, directly in the tubing walls with a slip assembly, or in the collar recesses of a tubing string.

Seat-Cup Stop Assembly. The seat-cup stop assembly has cups and a no-go similar to an insert sucker-rod pump and is installed in a profile nipple (Figs 16.18 and 16.19). Cup sizes can be changed to accommodate profile nipples with different IDs. It is very common for these stops to be built with a standing valve and/or bumper spring integrated into the assembly. These are the most common stops run because of ease of installation and retrieval.

A seat-cup stop is the only stop that can be dropped from the surface; however, it might still be desirable to run the stop on slickline to verify the setting force and depth, especially when a standing valve is integrated into the stop. Proper setting is necessary to ensure that the standing valve functions as desired.

Tubing Stop. A tubing stop has slips that bite directly into the tubing, without need of a profile to hold it in place (Figs. 16.19 and 16.20). It is useful when profile nipples are not run in a tubing string, or where the stop will be set some distance above the seating nipple (such as when tubing is too deeply set and will be perforated more shallowly). This stop can be set with slickline, with no need to pull tubing or install a profile nipple.

Collar Stop. A collar stop uses a type of slip that can be set only in a collar recess (Figs. 16.19 and 16.20). It can be set in most types of tubing that have space between the tubing collars. The collar stop is like the tubing stop, except that setting depths are limited to even tubing lengths. The collar stop actually is the easiest stop to unseat, and it can be unseated by high gas-flow velocities. Poor-quality stops might unseat more easily.

Pin Collar. The pin-collar type of stop is a collar with a pin welded inside it. It is screwed to the bottom of the tubing string, and its pin acts as a permanent stop. These are more common in smaller-ID tubing strings used as siphon or velocity strings. The benefits of using a pin collar include lower cost, minimum pressure drops, and simplicity. Because the pin collar is permanent, however, slickline cannot be run to tag the bottom of the well, clean out fill from the bottom of the well, or run tools out the end of the tubing. Also, the pin collar cannot be replaced without pulling tubing.

Bottomhole Bumper Spring (Optional Equipment; Not Found in All Installations)

(See Figs. 16.18 through 16.20.) A spring installed on the plunger stop prevents damage to the plunger, stop, or tubing, if the plunger descends in completely "dry" tubing (tubing without liquid). Damage is more likely with poorly sealing plungers (e.g., bar stock or wobble washer plungers), which fall at much higher velocities. The bumper spring absorbs the plunger impact in these cases.

Standing Valve (Optional Equipment; Not Found in All Installations)

For plunger lift to be effective, produced liquids need to stay in the tubing when the well is shut in. Installing standing valves between the plunger stop and bumper spring (Fig. 16.18) will keep liquid accumulations in the tubing. Standing valves are more common in wells with low bottomhole pressures, where liquids may easily and quickly flow back into the formation because of gravity segregation of the gas and liquid.

A disadvantage of standing valves is that they eliminate the ability to equalize the tubing and casing, should the well load with liquids because of a system upset. Some valves have notched seats to allow some liquid slippage past the valve and to allow long-term equalization. Other problems with standing valves include increased pressure drops across the valve and sand or scale deposition that can plug the valve or prevent it from closing.

Strainer Nipple (Optional Equipment; Not Found in All Installations)

Running a strainer nipple on the bottom of the tubing will prevent sand, scale, and other debris from entering the tubing. It might also plug, inhibiting plunger operation.

Evaluation and Installation of Wellhead and Plunger Surface Equipment


The wellhead should have the same or very close to the same continuous ID from the tubing through the wellhead. It is common to have variations in wellhead IDs, especially around tubing hangers, backpressure threads, or blast joints set just below the surface (Fig. 16.21). When wellhead IDs are significantly larger IDs than that of the tubing, the plunger can stall, which prevents unloading or keeps automated controllers from sensing the plunger arrival. Some tubing adapters have areas large enough for shorter plungers to turn and hang in the wellhead. Smaller-ID restrictions can cause impact damage to the wellhead and plunger. ID changes can be solved by changing wellheads, installing sleeves in tubing hangers (especially in the backpressure-valve threads), and minimizing wellhead height by reducing the number of master valves, flow tees, and swab valves.

It is better to flange, rather than thread, master-valve adapters and master valves because threaded adapters are more prone to breaking with system upsets. If a plunger ascends without a liquid slug, it can reach speeds that can cause damage to the surface equipment. It is more desirable to keep this damage above the master valve, especially because this valve is the last isolation valve between the well and the atmosphere. A slip-type wellhead with the master valve screwed directly to the tubing string is a possible exception. The strength and durability of 8-round threads for EUE tubing is much greater than that of normal line-pipe threads; however, in any application, flanged master valves are preferable.

In some installations with no packer, it is desirable to connect the casing to the tubing and flowline. During normal operation, the casing remains shut-in, but, if the system is upset and the well loads and dies, the tubing and casing can be equalized. Equalizing allows liquid to reach a common level in the tubing and casing, reducing hydrostatic head in the tubing. Gas that migrates into the casing during shut-in then can more easily and quickly displace liquids back into the formation. Equalizing can be used to bring a plunger installation back on line more quickly, or to prevent swabbing to unload the well.

Lubricator/Catcher Assembly

A lubricator/catcher assembly (Fig. 16.22) is used to receive the plunger at the surface. It is built with a shock spring, catcher mechanism, and flow ports. The lubricator is built with O-ring seals, and usually is made to seal when hand-tightened (which facilitates plunger inspection). The lubricator/catcher size should match the tubing and wellhead ID, and its installation should be plumb. If the lubricator is not plumb, the ascending force of the plunger will try to straighten the assembly, causing metal fatigue and failure.

Shock Spring. The shock spring (Fig. 16.22) absorbs the impact of the plunger at the surface, especially in the event of a dry ascent. The shock spring should be easily accessible and replaceable, because a good shock spring will extend plunger life. Premature spring wear might indicate very high plunger velocities and incorrect controller settings.

Catcher Mechanism. The catcher mechanism (Fig. 16.22) can be manually or automatically set to catch the plunger at the surface. This facilitates periodic plunger inspections and proper shut-in of plunger-lifted wells.

Flow Ports. Flow ports tie the lubricator/catcher assembly into the flowline piping (Fig. 16.22). Dual flow ports are preferred over single flow ports. Because the plunger is held in the wellhead by well flow, it tends to ride just above or across from the single flow port. This tends to create flow restrictions and the possibility of hydrate formation in the wellhead in colder climates.

Catcher Extension (Optional Equipment; Not Found in All Installations). Attaching an extension to the catcher improves cushioning at plunger arrival. The extension consists of additional tubing placed between the top flow port and the shock spring. When the plunger passes the flow ports and enters the extension, the loss of the driving force of the gas and the compression of gas above the plunger slows it down. The extra length allows the plunger to stop with less impact on the shock spring. The longer the extension, the greater this benefit. Extensions are more prevalent with plungers in small tubing, where the small equipment increases possibility of plunger damage. Extensions also may be used where a long plunger, such as the side-pocket-mandrel plunger, is used.

Plunger Sensors

Plunger sensors (Fig. 16.22) are placed on the lubricator/catcher to sense when the plunger has reached the surface. Simple controllers use the sensor strictly to count the number of times the plunger has reached the surface. More-sophisticated controllers make cycle adjustments on the basis of sensor data for plunger arrival and ascent velocity.

Different types of sensors are available, but most are either acoustic or magnetic. Sensor dependability is imperative when controllers use plunger speed as a criterion for adjusting cycle times. In many cases, sensor failure causes well shut-in by the controller, or well loading and dying.

Sensors are susceptible to stray electrical currents, such as those produced by cathodic protection. Such currents may cause erratic sensing of plunger arrivals. Insulating the lubricator and sensor from stray currents caused by cathodic protection or installing capacitance to level current fluctuations can improve performance.

Motor Valves

Pneumatically actuated motor valves (Fig. 16.13) commonly are used to shut in and flow a plunger-lifted well, but electric motors, pneumatic diaphragms, and hydraulic operation can be used. Maintain the seat and trim on these motor valves in good condition. If the valves leak even a small amount, the well might load and die. Consider the seat and trim size when selecting and installing a motor valve. If sized too small, the seat and trim can act as a choke to the well and prevent plunger arrival.

Design Considerations and Plunger Selection

Desirable features in a plunger include efficient sealing, reliability, durability, and the ability to descend quickly.[8][13] 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.[13]

The velocity at which the plunger travels up the tubing also affects plunger efficiency[9][10][13] (Fig. 16.23). 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, and 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.[13] 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 1¼-in. or 1½-in.-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.[10][13][23][32]

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.[10] 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, and 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. 16.24) 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. 16.24) 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. Pad plungers are popular because of their durability and efficient seal. A pad plunger (Figs. 16.25 and 16.26) 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. 16.27) 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.

Brush. A brush plunger seals very well and falls rapidly, but its bristles may wear quickly. A brush plunger (Figs. 16.25 and 16.26) 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. 16.28 and 16.29). 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. 16.30) 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 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. 16.1b 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. 16.31). These automated controllers monitor plunger velocity to continually optimize the well, eliminating the time-consuming trial-and-error process.[9]

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.

Venting (Optional; Not Found in All Installations)

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 the Applications section of this chapter.

High-Line Pressure Delay (Optional; Not Found in All Installations)

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.

Acoustic Fluid-Level/Plunger Descent Tracking (Optional; Not Found in All Installations)

Acoustic fluid-level devices can be used to track plunger descent and liquid-load sizes.[23][32] 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.

Remote Control/Telemetry (Optional; Not Found in All Installations)

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. 16.32 through 16.34). Case studies have shown that adding remote control increases production, even on wells that previously had been equipped with self-adjusting electronic controllers.[12] 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.

Missed-Trip Protection (Optional; Not Found in All Installations)

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.

Swab Mode (Optional; Not Found in All Installations)

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.

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. 16.34) 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. 16.35) are difficult to integrate if production has a wide sweep on the chart or overranges 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; however, 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.


a = variable equaling approximately 50 to 60% of the difference between shut-in casing pressure and maximum sales-line pressure
Aa = cross-sectional area of annulus, ft2
At = cross-sectional area of tubing, ft2 or in.2
Cmax = maximum number of plunger round trips possible per day
d = tubing diameter, in.
dci = casing inner diameter, in.
dti = tubing, inner diameter, in.
dto = tubing, outer diameter, in.
D = deepest point of plunger travel (well depth), ft
fg = Darcy-Weisbach friction factor for gas flow through the tubing
Fgs = Foss and Gaul slippage factor of gas lost past plunger on rise cycle [approximately 2% per 1,000-ft depth ( = 1 + D/1,000 × 0.02); Foss and Gaul used 1.15 factor on 8,000-ft wells.]
fl = Darcy-Weisbach friction factor for the liquid slug
gg = gas specific gravity
K = gas friction in tubing
L = the length of one barrel of liquid in the tubing, ft/bbl
pc = casing pressure, psia
RTENOTITLE = average casing pressure during operation, psia
(pc)max = the pressure required to start the plunger at the beginning of the plunger cycle, psia
(pc)min = the casing pressure required to move the plunger and liquid slug just before it reaches the surface, psia
pcs = casing pressure at shut-in, psia
phs = slug differential hydrostatic pressure, psi
pl = line pressure, psia
plf = differential pressure required to overcome liquid friction per barrel, psi/bbl
plh = differential pressure required to lift liquid weight per barrel, psi/bbl
= maximum line pressure during plunger ascent, psia
pp = differential pressure required to lift plunger weight, psi
pR = reservoir pressure, psia
pt = tubing pressure, psia
qg = gas flow rate, Mscf/D
ql = liquid flow rate, B/D
R = specific gas constant (air), 53.3 lbf-ft/(°R-lbm)
Ra = ratio of annulus + tubing cross-sectional area to the annulus cross-sectional area
Rgl = gas/liquid ratio, scf/bbl
S = volume of load (slug) above plunger, bbl
RTENOTITLE = average gas temperature in the well during plunger ascent, °F
v = velocity, ft/sec
RTENOTITLE = average velocity of plunger falling through gas, ft/min (typically 200 to 1,200 ft/min)
RTENOTITLE = average velocity of plunger falling through liquid, ft/min (typically 50 to 250 ft/min)
RTENOTITLE = average rise velocity of plunger, ft/min (typically 400 to 1,200 ft/min)
Vg = volume of gas required per cycle, Mscf
Vt = volume of the tubing above the liquid load, Mscf
Wp = plunger weight, lbm
Z = gas factor
γl = liquid gradient, psi/ft


The authors wish to express their appreciation to ConocoPhillips and EOG Resources for supporting the publication of this chapter, and to Gary Thomas, James Lea, Norm Hein, Bill Myers, Jack Rogers, Bill Elmer, Daniel Sanchez, Larry Vinson, and Scott Williams for their support and help in preparing the presentation materials. Thanks to Ferguson Beauregard; Gulf Publishing; Multi Products Co.; Opti-Flow LLC; Pacemaker Plunger Co.; Plunger Lift Systems Inc.; The Southwestern Petroleum Short Course; Van Nostrand Reinhardt; and Weatherford International Ltd. for providing pictures, diagrams, and consultation, and to Jay Simmons of Sugar Mountain Design Co. for figure animation in CD version.

SI Metric Conversion Factors

bbl × 1.589 873 E – 01 = m3
cp × 1.0* E – 03 = Pa•s
ft × 3.048* E – 01 = m
ft2 × 9.290 304* E – 02 = m2
ft3 × 2.831 685 E – 02 = m3
°F (°F – 32)/1.8 = °C
°F °F + 459.67 = °R
in. × 2.54* E + 00 = cm
in.2 × 6.451 6* E + 00 = cm2
in.3 × 1.638 706 E + 01 = cm3
lbf × 4.448 222 E + 00 = N
lbm × 4.535 924 E – 01 = kg
mL × 1.0* E + 00 = cm3
psi × 6.894 757 E + 00 = kPa
U.S. gal × 3.785 412 E – 03 = m3


Conversion factor is exact.