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Plunger lift

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Plunger lift has become a widely accepted and economical artificial-lift alternative, especially in high-gas/liquid-ratio (GLR) gas and oil wells (Fig. 1). Plunger lift uses a free piston that travels up and down in the well’s tubing string. It minimizes liquid fallback and uses the well’s energy more efficiently than does slug or bubble flow. As with other artificial-lift methods, the purpose of plunger lift is to remove liquids from the wellbore so that the well can be produced at the lowest bottomhole pressures.



History

In recent years, the advent of microprocessors and electronic controllers,[1][2][3][4] the studies detailing the importance of plunger seal and velocity,[5] and an increased focus on gas production have led to a much wider use and broader application of plunger lift. Microprocessors and electronic controllers have increased the reliability of plunger lift.[1][2][4] Earlier controllers were on/off timers or pressure switches that needed frequent adjustment to deal with operating-condition changes such as line pressures, plunger wear, variable production rates, and system upsets. This frustrated many operators and caused failures, and thus limited plunger use. New controllers contain computers that can sense plunger problems and make immediate adjustments. Techniques with telemetry, electronic data collection, and troubleshooting software continue to improve plunger-lift performance and ease of use.[4]

Traditionally, plunger lift was used on oil wells—as the wells started to load or as a means of gas lift assist—and many early articles discussed optimization of liquid production.[6][7][8][9] Plunger lift have become more common on gas wells, and papers from the 1980s onward have focused on this aspect.[10][11][12][13][14][15][1][16] In the 1980s, several studies were conducted in the field and on test wells to verify 1950s and 1960s models and to better understand plunger operation. Morrow and Rogers,[1] Mower et al.,[5] Lea,[17] and Rosina[18] (among others) presented papers that verified and modified earlier models presented by Beeson et al.[7] and Foss and Gaul.[9]

Description

Whether in a gas well, oil well, or gas lift well, the mechanics of a plunger-lift system are the same. The plunger, a length of steel, is dropped through the tubing to the bottom of the well and allowed to travel back to the surface. It provides a piston-like interface between liquids and gas in the wellbore and prevents liquid fallback—a part of the liquid load that effectively is lost because it is left behind. Because the plunger provides a “seal” between the liquid and the gas, a well’s own energy can be used to lift liquids out of the wellbore efficiently.

THIS TEXT COPIED IN FROM ARTIFICIAL LIFT CHAPTER _ FIX IT Plunger lift commonly is used to remove liquids from gas wells or produce relatively low volume, high GOR oil wells. Plunger lift is important and, in its most efficient form, will operate with only the energy from the well. Fig. 3 shows a schematic of a plunger lift installation. A free-traveling plunger and produced-liquid slug is cyclically brought to the surface of the well from stored gas pressure in the casing-tubing annulus and from the formation. In the off cycle, the plunger falls and pressure builds again in the well. A new two-piece plunger (cylinder with ball underneath) can lift fluids when the components are together, but both components are designed to fall when separate. Use of this plunger allows a shut-in portion of the operational cycle that is only a few seconds long, resulting in more production for many wells.



There is a chamber pump that relies on gas pressure to periodically empty the chamber and force the fluids to the surface, which is essentially a gas-powered pump. There are variations of gas lift and intermittent lift, such as chamber lift. Not all possible variations of artificial lift can be discussed; however, the principles presented apply to the selection of all methods that might be considered.

Benefits and applications

A plunger changes the rules for liquid removal. 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.[10][11][12] Thus, the plunger system is economical because it needs minimal equipment and uses the well’s gas pressure as the energy source.[13][14][15] Used with low line pressures or compression, plunger lift can produce many types of wells to depletion.[11][13][6] 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.

Purpose

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. 2). 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.



Declining pressure

As reservoir pressures decline and flow rates/velocities decrease, the lifting mechanism changes.[20] Liquids no longer are entrained in mist and begin to coalesce on the walls of the production tubing. The liquids still might move up and out of the well, but somewhat less-efficiently than in mist form.

Heading or slugging

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. When enough liquids stall, liquid “slugs” are formed that inhibit gas flow. The well begins a cyclic process of unloading liquids that commonly is referred to as “heading” or “slugging.” Liquid collects on the tubing walls, increases hydrostatic backpressure, restricts gas flow, and further decreases gas velocity. 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. 3).



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. In intermittent gas lift, a rule of thumb is that 5 to 7% of the liquid load is left behind for every 1,000 ft of depth. In a 10,000-ft well, that can be 70% of the liquid load! 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. The well sometimes will continue to produce at low flow rates, or it might stop flowing completely (known as “loaded,” “logged-off,” or “dead”). 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.1 critical-flow-rate correlation (Fig. 4), a well that produces gas and water in 2 3/8-in. [1.995-in. inner diameter (ID)] tubing to a 100-psia surface pressure requires approximately a 320 Mscf/D flow rate to prevent fallback and unload liquids. Below this rate, liquid fallback will occur and liquids will not be removed adequately. The same well with a reservoir pressure of 500 psia only requires a water column of 800 to 1,000 ft to shut off flow completely. That hydrostatic pressure is equivalent to < 4 bbl of water in 2 3/8-in. tubing! So, below critical flow rates, a very small amount of liquid can limit production severely.



Production

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.[6][1][2] However, practical experience and plunger-lift models show that lifting large liquid slugs requires higher average bottomhole pressure, however, so the goal of plunger lift should be to shut in the well for the minimum time period and to produce only as much liquids as can be lifted at this minimum buildup pressure (Fig. 8).



The absolute minimum shut-in time, regardless of other operating conditions, is the time it takes the plunger to reach bottom. (The exception to this rule is specialized plungers that fall while the well is flowing.) Plungers typically fall 200 to 1,000 ft/min in dry gas, and 20 to 250 ft/min in liquids.[5][9][23] Total fall time depends on plunger type, amount of liquid in the tubing, the condition of the tubing (e.g., crimped, corkscrewed, corroded), and the deviation of the tubing or wellbore.

The length of the flow period during and after plunger arrival is used to control liquid loads. In general, a short flow period brings in a smaller liquid load, and a long flow period brings in a larger liquid load, so that the well can be flowed until the desired liquid load has entered the tubing. A well with a high GLR might be capable of long flow periods without requiring more than minimum shut-in times. In such case, the plunger could operate as few as one or two cycles per day. Conversely, a well with a low GLR might never be able to flow after plunger arrival, and might require 25 or more cycles per day. In practice, if the well is shutting in for only the minimum amount of time, it can be flowed as long as possible to maintain target plunger rise velocities. If the well is shutting in for longer than the minimum time, there should be little or no flow after the plunger arrives at the surface.

Improvements

Plunger lift improvements have enabled its use for a broader range of well types and conditions, allowing its application even in extremely low-pressure wells (< 100 psia), wells with high liquid production (> 100 B/D), deep wells (16,000+ ft), slimhole wells (2 7/8- to 3 1/2-in. casing), and wells with packers. Operators have successfully used plunger lift in paraffin-, scale-, sand-, and hydrate-production environments.

Gas slippage

A plunger that more completely seals against the tubing and travels at the proper ascent velocity minimizes gas slippage around the plunger. Reducing gas slippage allows the well to operate more efficiently at lower bottomhole pressures, which in turn increases production.

Velocity data

Efficient ascent velocities for various plungers range from 500 to 1,000 ft/min. These velocity data have been used successfully to improve methods for controlling and optimizing plunger-lift cycles and to produce highly efficient plungers.

Cycles

In its simplest form, plunger operation consists of shut-in and flow periods. The flow periods are divided into periods of unloading and flow after plunger arrival. The lengths of these periods vary with application, producing capability of the well, and pressures. In specialized cases that use plungers that can fall against flow, there might not be a shut-in period. When using plunger lift, however, unloading relies less on critical flow rates and much more on the well’s ability to store sufficient gas pressure to lift the plunger and a liquid slug to surface. The piston-like interface the plunger provides between liquid and the gas acts as a seal between the two, preventing fallback and allowing the well’s energy to build up sufficiently to lift liquids out of the wellbore. Thus, liquids can be removed efficiently, even when gas velocity is very low. A plunger cycle starts with the shut-in period that allows the plunger to drop from the surface to the bottom of the well (Fig. 5). At the same time, the well builds gas pressure that is stored in either the casing, the fracture, or the near-wellbore region of the reservoir. The well must be shut in long enough to build sufficient reservoir pressure to provide energy to lift both the plunger and liquid slug to the surface against line pressure and friction. When this pressure has been reached, the flow period is started and unloading begins.



Initial Stage

In the initial stages of the flow period, the plunger and liquid slug begin traveling to the surface. Gas above the plunger quickly flows from the tubing into the flowline, and the plunger and liquid slug follow up the hole. The plunger arrives at the surface, unloading the liquid. Initially, high rates prevail (often three to four times the average daily rate) while the stored pressure is blown down. The well now can produce free of liquids, while the plunger is held at the surface by the well’s pressure and flow. As rates drop, so do velocities. Eventually, velocities drop below the critical rate, and liquids begin to accumulate in the tubing. The well is shut in, and the plunger falls back to bottom to repeat the cycle.

Shut-in and open

There are many common names for these periods. Shut-in also is known as a “closed,” “off,” or “buildup” period. The time during which the plunger travels up the hole also is called an “open,” “on,” “unloading,” or “flow” period. The flow period after the plunger reaches the surface is known variously as an “open,” “on,” “flow,” “afterflow,” “blowdown,” or “sales” period. The pressure response of a well on plunger lift helps explain the plunger lift cycles. Figs. 6 and 7 and the discussion below describe a typical pressure response for a well with tubing and no packer and for which surface tubing and casing pressures can be measured. Fig. 6 shows three pressures—casing, tubing, and line—and the instantaneous flow rate of a well during a plunger cycle. Fig. 7 shows the same pressures and rate over a period of several days.



Maximum pressure

By the end of the shut-in period, the well has built up to the maximum casing pressure, and to a tubing pressure that is lower than the casing pressure. The difference between these is equivalent to the hydrostatic pressure of the liquid in the tubing. When the well is opened, the tubing pressure quickly drops to line pressure while the casing pressure slowly decreases until the plunger reaches the surface. As the plunger nears the surface, the liquid on top of the plunger might surge through the system, causing spikes in line pressure and flow rate. This continues until the plunger reaches the surface. After the plunger surfaces, a large increase in flow rate will produce higher tubing pressures and an increase in flowline pressure. Tubing pressure then will drop to very near line pressure. Casing pressure will reach its minimum either upon plunger arrival, or afterward while the casing blows down and the well produces with minimal liquids in the tubing. If the well stays above the critical unloading rate, casing pressure will remain fairly constant or might decrease further. As the gas rate drops, liquids become held up in the tubing and casing pressure increases. Upon shut-in, the casing pressure builds more rapidly. How quickly depends on the inflow performance and reservoir pressure of the well. As the flowing gas friction ceases, the tubing pressure will increase quickly from line pressure and eventually will track casing pressure (minus the liquid slug). Casing pressure will continue to increase toward maximum pressure until the well is opened again.

Operator experience

The well operator must be able to understand the system. Plunger lift can be a difficult process to visualize because it comprises liquid and gas movement downhole during flowing and shut-in periods. Operators must understand the mechanism for oil- and (especially) gas-well loading, have a basic understanding of inflow performance, and be able to troubleshoot wells on the basis of tubing and casing pressures and flow performance. Even with electronic controllers, operators are necessary for finding initial plunger-lift operating ranges, choosing appropriate plunger types, and performing basic maintenance and troubleshooting. An operator without these skills will have trouble even with the best plunger-lift candidates.


References

  1. 1.0 1.1 1.2 1.3 1.4 Morrow Jr., S.J. and Rogers Jr., J.R. 1992. Increasing Production Using Microprocessors and Tracking Plunger-Lift Velocity. Presented at the SPE Mid-Continent Gas Symposium, Amarillo, Texas, 13-14 April 1992. SPE-24296-MS. http://dx.doi.org/10.2118/24296-MS.
  2. 2.0 2.1 2.2 2.3 2.4 Phillips, D.H. and Listiak, S.D. 1998. How to Optimize Production from Plunger Lift Systems. World Oil (May): 110.
  3. Christian, J., Lea, J.F., and Bishop, R. 1995. Plunger Lift Comes of Age. World Oil (November): 43.
  4. 4.0 4.1 4.2 Lusk, S. and Morrow, S.J. Jr. 2000. Plunger Lift: Automated Control Via Telemetry. Proc., Forty-Seventh Annual Southwestern Petroleum Short Course, Lubbock, Texas, 73.
  5. 5.0 5.1 5.2 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.
  6. 6.0 6.1 6.2 Hacksma, J.D. 1972. User’s Guide to Predicting Plunger Lift Performance. Proc., Nineteenth Annual Southwestern Petroleum Short Course, Lubbock, Texas, 109–118.
  7. 7.0 7.1 Beeson, C.M., Knox, D.G., and Stoddard, J.H. 1955. Plunger Lift Correlation Equations and Nomographs. Paper AIME 501-G presented at the 1955 AIME Petroleum Branch Annual Meeting, New Orleans, 2–5 October.
  8. Lebeaux, J.M. and Sudduth, L.F. 1955. Theoretical and Practical Aspects of Free Piston Operation. J Pet Technol 7 (9): 33-37. SPE 396-G. http://dx.doi.org/10.2118/396-G.
  9. 9.0 9.1 9.2 Foss, D.L. and Gaul, R.B. 1965. Plunger Lift Performance Criteria with Operating Experience—Ventura Avenue Field. Drilling and Production Practices, 124-140. Dallas, Texas: API.
  10. 10.0 10.1 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. http://dx.doi.org/10.2118/10882-MS.
  11. 11.0 11.1 11.2 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.
  12. 12.0 12.1 Lea Jr., J.F. and Tighe, R.E. 1983. Gas Well Operation With Liquid Production. Presented at the SPE Production Operations Symposium, Oklahoma City, Oklahoma, 27 February-1 March 1983. SPE-11583-MS. http://dx.doi.org/10.2118/11583-MS.
  13. 13.0 13.1 13.2 Ferguson, P.L. and Beauregard, E. 1988. Extending Economic Limits and Reducing Lifting Costs: Plungers Prove To Be Long Term Solutions. Proc., Thirty-Fifth Annual Southwestern Petroleum Short Course, Lubbock, Texas, 233–241.
  14. 14.0 14.1 Sanchez, D. and Ary, B. 1996. Case Study of Plunger Lift Installation in the San Juan Basin. Proc., Forty-Third Annual Southwestern Petroleum Short Course, Lubbock, Texas, 8–13.
  15. 15.0 15.1 Brady, C.L. and Morrow, S.J. 1994. An Economic Assessment of Artificial Lift in Low-Pressure, Tight Gas Sands in Ochiltree County, Texas. Presented at the SPE Mid-Continent Gas Symposium, Amarillo, Texas, 22-24 May 1994. SPE-27932-MS. http://dx.doi.org/10.2118/27932-MS.
  16. 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. http://dx.doi.org/10.2118/18868-MS.
  17. Lea, J.F. 1982. Dynamic Analysis of Plunger Lift Operations. J Pet Technol 34 (11): 2617-2629. SPE-10253-PA. http://dx.doi.org/10.2118/10253-PA.
  18. Rosina, L. 1983. A Study of Plunger Lift Dynamics. MS Thesis, University of Tulsa, Tulsa.
  19. 19.0 19.1 Turner, R.G., Hubbard, M.G., and Dukler, A.E. 1969. Analysis and Prediction of Minimum Flow Rate for the Continuous Removal of Liquids from Gas Wells. J Pet Technol 21 (11): 1475-1482. SPE-2198-PA. http://dx.doi.org/10.2118/2198-PA.
  20. 20.0 20.1 Govier, G.W. and Aziz, K. 1972. The Flow of Complex Mixtures in Pipes. New York City: Van Nostrand Reinhold Company.
  21. Vogel, J.V. 1968. Inflow Performance Relationships for Solution-Gas Drive Wells. J Pet Technol 20 (1): 83-92. http://dx.doi.org/10.2118/1476-PA.
  22. Mishra, S. and Caudle, B.H. 1984. A Simplified Procedure for Gas Deliverability Calculations Using Dimensionless IPR Curves. Presented at the SPE Annual Technical Conference and Exhibition, Houston, Texas, 16-19 September 1984. SPE-13231-MS. http://dx.doi.org/10.2118/13231-MS.
  23. McCoy, J.N. et al. 2001. Plunger Lift Optimization By Monitoring And Analyzing Wellbore Acoustic Signals And Tubing And Casing Pressures. Proc., Forty-Eighth Annual Southwestern Petroleum Short Course, Lubbock, Texas, 80–87.

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See also

PEH:Plunger lift

Plunger lift applications

Plunger lift design and models

Plunger design considerations and selection

Plunger lift installation and maintenance