In a well without a plunger, gas velocity must be high to remove liquids, [19] but with a plunger, gas velocity can be very low. 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. 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. 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.
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.
Modified from Govier and Aziz. 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. 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. Modified from Phillips and Listiak.
This cycle can occur over hours or days in wells that have stabilized flow rates below the critical unloading rate. Such is the behavior of many wells that are temporarily shut in or blown to atmosphere to unload liquids. 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. 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.
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. Below this rate, liquid fallback will occur and liquids will not be removed adequately. The same well with a reservoir pressure of psia only requires a water column of to 1, ft to shut off flow completely.
So, below critical flow rates, a very small amount of liquid can limit production severely. From Turner et al. 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. After Vogel and Mishra and Caudle.
Read more about early returns on investment. A cost-effective solution in a compact enclosure, our WellPilot F controller regulates the desired plunger speeds by detecting plunger arrival and then accelerating or decelerating the plunger. Adjust to ever-changing conditions. Show search Menu.
Latest Products. New Product Firma. New product Foresite Sense. While it may seem like a complex system, plunger lifts are pretty straight forward in their operations. On to top of the wellhead there is a wing valve control which closes the flow line to the tank battery, this allows the operator to stop the fluid flow through the tubing to the tank battery. Also on the wellhead is a bumper housing and catcher used to release a free-falling gas lift plunger.
Once the gas lift plunger hits the bottom of the well, it will come into contact with a footpiece spring, and thus closes the valve. As the increase in downhole pressure steadily persists, it allows the water and oil to gather above the plunger. Then after either a specific tubing pressure or time frame is reached, the controller will open the flow line motor valve; thus allowing the accumulated fluids and gas within the tubing to again flow to the tank battery.
The pressure change differences throughout the plunger lift valve typically generate travel speeds of around — 1, feet per minute. Each lift will vary in speed depending upon the various options for: bottomhole pressure, choke settings, and fluid loads. The plunger lift moves upward toward the surface fueled by the built-up formation pressure beneath it, and bringing the the fluid located above it as it returns. The catcher located within the bumper housing frees the plunger; and the plunger once again begins to fall and thus restarting the entire process again.
The process is repeated as often or as little as the pressure and settings allow. Figure 1. Two major factors in this are the significant initial upfront costs when using lift systems even for minimal installation options , and the longevity and therefore, profitability of the well. However, before a lease pumper rushes to make the transition from flowing to pumping well; they need to ensure they remember to meet the following requirements:.
Figure 2. The bumper housing and catcher carry out a variety of functions. For instance, the bumper offers a cushioned bumper to halt the plunger as it reaches the end of its journey and into the housing where it receives lubrication for the next journey.
Once there, the arrival unit will register the plunger has reached its topside destination; and will then either signal the controller, or control panel, to close the flowline valve. Once completed, the lease pumper can then engage the catcher allowing the plunger to catch the next time it arrives. Figure 3. Examples of Common Components Found in a Plunger Lift System — from right to left: a housing with lubricator and electronic sensor, bumper, plunger, and a controller.
Production Control Services, Inc. The majority of controllers See Figure 4 have the ability to operate with either pressure cycles or time control. Timers can be utilized for specific shut-in times. By decreasing formation gas loss and having this available flexibility, controllers provide the most ideal method for a majority of wells and lease pumpers.
Figure 4. There are many perks for transforming a minimally producing plowing well into well with a lift system. In many situation, there are significant benefits for choosing a plunger lift system over the other available options.
These can include:. 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.
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