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Plunger lift applications

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Plunger lift is used for recovery, primarily in high gas-oil ratio (GOR) wells, 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.[1] [2] [3] [4] [5]


The most common plunger lift applications are for liquid removal in gas wells, but plungers also are used successfully for oil production in high gas liquid ratio (GLR) oil wells, in conjunction with intermittent gas lift operations,[5] [6] [7] [8] 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.[1] [2] [4]

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:[4] [6] [7] [8]

  • 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)
  • Carbon dioxide (CO2 ) floods

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.[9] A flexible brush plunger has been designed to help curve around potential bends in coiled tubing at the bottom of the well. Small coiled tubing (as with any small tubing) has tubing hydraulic problems that make plunger lift difficult:

  • Requires much more pressure to lift the same volume of liquids
  • Has larger pressure losses because of gas friction
  • 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 US (e.g., Ohio and Pennsylvania). Plunger sticking might occur in casing with:

  • Varying weights and IDs
  • With poor casing integrity or condition
  • 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.[5] [6] [7] [8]

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.[5] [6] [7] [8]

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.[10]

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
  • Provide an outside source of supply gas
  • 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:

  • Use an automated controller that continually attempts to minimize and eliminate venting
  • 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, but 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. 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.[6] [7]

Sand production

Wells that produce some sand production 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.[11] This is the case for many low-pressure, high-permeability gas wells. The cycle is like a standard plunger-lift cycle (Fig. 1), 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.

CO2 floods

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.[4]

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.


  1. 1.0 1.1 Beauregard, E. and Ferguson, P.L. 1982. Introduction to Plunger Lift: Applications, Advantages and Limitations. Presented at the SPE Rocky Mountain Regional Meeting, Billings, Montana, 19-12 May 1982. SPE-10882-MS.
  2. 2.0 2.1 Ferguson, P.L. and Beauregard, E. 1983. Will Plunger Lift Work In My Well?. Proc., Thirtieth Annual Southwestern Petroleum Short Course, Lubbock, Texas, 301–311.
  3. Hacksma, J.D. 1972. User’s Guide to Predicting Plunger Lift Performance. Proc., Nineteenth Annual Southwestern Petroleum Short Course, Lubbock, Texas, 109–118.
  4. 4.0 4.1 4.2 4.3 Beauregard, E. and Morrow, S. 1989. New and Unusual Applications for Plunger Lift System. Presented at the SPE Production Operations Symposium, Oklahoma City, Oklahoma, 13-14 March 1989. SPE-18868-MS.
  5. 5.0 5.1 5.2 5.3 Abercrombie, B. 1980. Plunger Lift. In The Technology of Artificial Lift Methods, ed. K.E. Brown, Vol. 2b, 483-518. Tulsa, Oklahoma: PennWell Publishing Co.
  6. 6.0 6.1 6.2 6.3 6.4 Hall, J.C. and Bell, B. 2001. Plunger Lift By Side String Injection. Proc., Forty-Eighth Annual Southwestern Petroleum Short Course, Lubbock, Texas, 17–18.
  7. 7.0 7.1 7.2 7.3 7.4 Morrow, S.J. Jr. and Aversante, O.L. 1995. Plunger Lift: Gas Assisted. Proc., Forty-Second Annual Southwestern Petroleum Short Course, Lubbock, Texas, 195–201.
  8. 8.0 8.1 8.2 8.3 White, G.W. 1982. Combine Gas Lift, Plungers to Increase Production Rate. World Oil (November): 69.
  9. O’Connell, T., Sinner, P., and Guice, W.R. 1997. Flexible Plungers Resolve CT, Slim Hole Problems. Amer. Oil & Gas Reporter 40 (January): 82.
  10. Phillips, D.H. and Listiak, S.D. 1996. Plunger Lift With Wellhead Compression Boosts Gas Well Production. World Oil (October): 96.
  11. Schneider, T.S. and V. Mackey, J. 2000. Plunger Lift Benefits Bottom Line for a Southeast New Mexico Operator. Presented at the SPE Permian Basin Oil and Gas Recovery Conference, Midland, Texas, 21-23 March 2000. SPE-59705-MS.

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See also

Plunger lift

Plunger lift design and models

Plunger design considerations and selection

Plunger lift installation and maintenance