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Plunger lift installation and maintenance
Plunger lift is commonly used for production of low volume, high gas-oil ratio (GOR) or high gas-liquid ratio (GLR) wells. 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. This page focuses on the installation and appropriate maintenance of plunger lift equipment.
- 1 Plunger lift components
- 2 Equipment quality and metallurgy
- 3 Evaluation of current and possible wellbore configurations
- 4 Evaluation and installation of downhill plunger equipment
- 5 Evaluation and installation of wellhead and plunger surface equipment
- 6 Design considerations and selection of a plunger
- 7 Evaluation of control methods
- 8 Evaluation and modification of production facilities
- 9 References
- 10 Noteworthy papers in OnePetro
- 11 External links
- 12 See also
Plunger lift components
For reference, Fig. 1 is a full wellbore schematic of major plunger-lift components, and Fig. 2 is a plunger-lift troubleshooting guide.
Fig. 2—Plunger-lift troubleshooting guide. (Taken from Phillips and Listiak.) Numbers represent rank in order of most likely solution.
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. 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 inside diameter (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 3 1/2-in. casing), and small tubing (jointed pipe or coiled tubing smaller than 1 3/4-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
- 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-outside diameter (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. 3). There are many varieties of gauge rings. Typically, gauge rings do a good job of finding the smallest ID of the tubing. 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. A few decisions should be carefully weighed:
- Tubing size
- Where to land the end of tubing
- Whether to reuse 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
- 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.
A common misconception is that tubing with larger diameters is more difficult to operate on plunger lift than tubing with smaller diameters (Fig. 4). 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.
Fig. 4—Effect of tubing size on plunger lift. (Taken from Phillips and Listiak.)
Plunger-lift systems can be operated in practically any size tubing, with 2 1/16-in. OD (1 3/4-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.
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. To estimate reservoir quality and to help determine the best spot to land the end of tubing use:
- Reservoir analysis
- Examination of well logs
- Production logs
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. 5). 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.
Fig. 5—Effect of tubing depth on plunger-lift production. (Taken from Phillips and Listiak.)
Setting the tubing high above the perforations is another common mistake (Fig. 5). 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:
- Plain tubing collar
- Mule shoe (standard collar cut at a 45° angle)
- 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.
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 6 and 7). 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.
A tubing stop has slips that bite directly into the tubing, without need of a profile to hold it in place (Figs. 7 and 8). 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.
A collar stop uses a type of slip that can be set only in a collar recess (Figs. 7 and 8). 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.
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
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
(See Figs. 6 through 8.) 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.This is 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. 6) 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. This is optional equipment; not found in all installations.
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.
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. This is optional equipment; not found in all installations.
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. 9). 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)
- 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. 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.
A lubricator/catcher assembly (Fig. 10) 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.
The shock spring (Fig. 10) 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.
The catcher mechanism (Fig. 10) 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 tie the lubricator/catcher assembly into the flowline piping (Fig. 10). 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 (Fig. 10) 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.
Pneumatically actuated motor valves (Fig. 1) 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 selection of a plunger
Desirable features in a plunger include efficient sealing, reliability, durability, and the ability to descend quickly. 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. For more information:Design considerations and plunger selection
Evaluation of control methods
Evaluation and modification of production facilities
- Phillips, D.H. and Listiak, S.D. 1998. How to Optimize Production from Plunger Lift Systems. World Oil (May): 110.
- Hacksma, J.D. 1972. User’s Guide to Predicting Plunger Lift Performance. Proc., Nineteenth Annual Southwestern Petroleum Short Course, Lubbock, Texas (1972) 109–118.
- Mower, L.N., Lea, J.F., E., B. et al. 1985. Defining the Characteristics and Performance of Gas-Lift Plungers. Presented at the SPE Annual Technical Conference and Exhibition, Las Vegas, Nevada, 22-26 September 1985. SPE-14344-MS. http://dx.doi.org/10.2118/14344-MS.
Noteworthy papers in OnePetro
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