Drip Pots. Flow Meters. Flow Meter Accessories. Flow Monitors. Sense Line Protectors. Solenoid Valves. Supply Gas Regulators. Other Accessories. Float Operated Controllers. Temperature Controllers. Back Pressure Regulators. Pressure Reducing Regulators. Differential Pressure Regulators. High Pressure Control Valves.
Liquid Dump Valves. Low Pressure Control Valves. Weight Operated Dump Valves. Ball Valves. Energy Exchange. What is Plunger Lift? In this video, we explain how plunger lift works using this demonstration model. Other methods can be utilized to remove the liquid column from the wellbore. Why is plunger lift considered one of the simplest form of artificial lifts?
It's more cost effective than PCP and rod lift and can typically be installed in about a day. 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.
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.
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. 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. 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. 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 H 2 S 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. 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. 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.
Any gas can be used as the motivating force in plunger operations, even CO 2. When CO 2 breakthrough occurs in a CO 2 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.
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. 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. 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. Excessively high line pressures relative to buildup pressure might increase the requirement.
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, to 8, ft with slug sizes of 0. 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. To use Eqs. 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.
Modified from Ferguson and Beauregard. Chart shows production increase resulting from reducing liquid hydrostatic pressure with a plunger-lift system.
Based on Lea. Several publications have dealt with this approach. Beeson et al. Foss and Gaul [16] derived a force-balance equation for use on oil wells in the Ventura Avenue field in Because p c 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 p c min for gas expansion from the casing to the tubing during the full plunger cycle yields p c max , the pressure required to start the plunger at the beginning of the plunger cycle.
The pressure must build to p c max to operate successfully. The average casing pressure , maximum cycles C max , and gas required per cycle V g can be calculated from p c min and p c max. The equations below are essentially those presented by Foss and Gaul [16] but are summarized here as presented by Mower et al. Also, because this model originally was designed for oilwell operation that assumed the well would be shut in upon plunger arrival, 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. The rule of thumb for calculating the minimum shut-in casing pressure for plunger lift, in psia, is Any reasonable number of cycles can be assumed to calculate pressures.
Using Eq. 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. Taken from Phillips and Listiak. Numbers represent rank in order of most likely solution. 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. Evaluate material used in equipment manufacturing on the basis of the operating environment of each specific application. 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.
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. 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. Often, plunger-lift installation is attempted in unacceptable tubing. Review well records to determine whether an acceptable tubing configuration is in place. 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 Cup sizes can be changed to accommodate profile nipples with different IDs.
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.
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.
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. Courtesy of Ferguson Beauregard. 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. 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. The plunger stops in a spring-loaded receiver in the lubricator. When the plunger is no longer in the flow path, the gas that supplied the lifting energy flows through the lower outlet into the flowline.
The gas flow rate and pressure at the wellhead will begin to drop as produced gas flows out of the well, causing wellbore liquids to start falling back down and accumulating in the wellbore. Once the pressure drops below a preset level, the automatic controller closes the surface valve and releases the plunger, which falls back down to the bottomhole bumper spring.
The cycle begins anew as liquid loads above the plunger and annular gas pressure builds. Controlling the plunger travel speed and cycle times is critical to safety and efficiency. Plunger lift systems provide several economic and environmental benefits compared with other solutions for liquid-loaded gas wells. Because they use the built-up pressure of the well's own gas to effect liquid removal, they typically do not require outside energy sources.
The costs of installing and maintaining a plunger lift system are generally lower than the corresponding costs for beam pumping equipment. Overall maintenance costs are reduced because periodic remedial treatments such as well blowdowns or swabbing —in which toolstrings that have rubber-cupped seals are run up the tubing to carry liquids from the well—may no longer be necessary. And unlike these other remedial measures, plunger lift provides regular fluid removal, which enables the well to continuously produce gas without halting production.
In addition, wells that continuously move water out of the well have demonstrated an increased potential for producing greater volumes of condensate and oil. Because of the regular scraping action of the plunger against the tubing walls, plunger lift systems prevent the buildup of deposits in wells prone to paraffin or scale accumulation. This reduces or eliminates the need for chemical or swabbing treatments.
Moreover, lower methane emissions have been reported when plunger lift systems are used because these systems reduce or eliminate well interventions. While makeup gas or compression can be used to address inadequate GLR and buildup pressure requirements, these systems are most effective in wells where formation gas is the only gas source. Candidate wells should produce at least Wells with a shut-in wellhead pressure that is 1. Seal efficiency is critical for effective plunger lift operations These systems require a uniform inside diameter along the tubing string to allow the plunger to travel freely from the bottom of the well to the surface while carrying well liquids and producing gas.
For wells that produce sand—either from loose, unconsolidated formations or from sand or proppant used in hydraulic fracturing operations—operators run the risk of the plunger sus-taining erosive damage or getting stuck on its way up or down the tubing. While they are commonly associated with increasing gas production in high-GLR wells, plunger lift systems have also been used successfully to boost oil production in high-GLR oil wells.
In addition, they have been used in conjunction with intermittent gas lift operations that produce reservoir fluid sporadically by displacing liquid slugs with high-pressure injection gas. The most desirable wellbore configuration for plunger lift is in wells that have an open annulus. In this configuration, gas in the annular space can work freely on the plunger and liquid slug to provide lift with little restriction. In addition, plunger lift systems can work through coiled tubing installed in the well as a velocity string.
In recent years, plunger lift operations have incorporated automatic electronic controllers. Battery-powered electronic controls that have solid-state circuitry regulate the cycling of the motor valve in response to plunger arrival at the wellhead, line pressures, liquid levels or pressure differentials.
These controllers also help streamline the installation process and save the hours required to manually fine-tune the plunger system. New information technology systems, such as smart automation, online data management and satellite communications, have streamlined plunger lift monitoring and control by enabling operators to manage plunger lift systems remotely, without the need for routine in-person field visits.
Wireless monitoring and control systems that transmit analog or digital signals via radio or from a central processing device are gaining greater acceptance, particularly among operators using plunger lift in many hundreds or thousands of wells. Wireless systems can be set up on location in less than an hour, as opposed to the several days required for conventional wired systems, and without the need for conduits or trenches for buried cables.
The wirelessly transmitted data, which include liquid level, flow, pressure, temperature, plunger location and system alarms, can be monitored remotely and in real time. Operators use this information to optimize their field crew deployments by sending crews to only those wells that require maintenance or repairs, increasing efficiency and reducing costs.
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