Plunger lift installation and maintenance: Difference between revisions

==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.  

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File:Vol4 Page 860 Image 0001.png|'''Fig. 2—Plunger-lift troubleshooting guide. (Taken from Phillips and Listiak.) Numbers represent rank in order of most likely solution.'''<ref name="r1" />

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==Equipment quality and metallurgy==

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.  

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File:Vol4 Page 861 Image 0001.png|'''Fig. 3—Cutaway of a gauge ring. (Courtesy of Ferguson Beauregard.)'''

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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===

*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:  

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.  

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File:Vol4 Page 862 Image 0001.png|'''Fig. 4—Effect of tubing size on plunger lift. (Taken from Phillips and Listiak.)'''<ref name="r1" />

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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:

*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.  

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File:Vol4 Page 863 Image 0001.png|'''Fig. 5—Effect of tubing depth on plunger-lift production. (Taken from Phillips and Listiak.)'''<ref name="r1" />

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Setting the tubing high above the perforations is another common mistake<ref name="r1" /> ('''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.  

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:  

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.  

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.  

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.  

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.

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File:Vol4 Page 865 Image 0001.png|'''Fig. 7—Bumper-spring assemblies (left to right): tubing stop, collar stop, seat-cup assembly. (Courtesy of Ferguson Beauregard.)'''

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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.  

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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:  

*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

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File:Vol4 Page 867 Image 0001.png|'''Fig. 9—Effect of wellhead ID on plunger lift. Large changes in wellhead ID might cause the plunger to get caught in the wellhead or to stall. Sample dimensions show the difference between one type of pad plunger’s ODs and tubular/valve IDs'''

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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.  

===Lubricator/catcher assembly===

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.  

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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.  

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.  

==See also==