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Plunger lift is used primarily in low rate, high gas-oil ratio (GOR) wells. This page focuses on the features desired in key equipment required to operate a plunger lift operation. 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. The plunger seal is the interface between the tubing and the outside of the plunger, and probably is the most important plunger design element. Most plungers do not have a perfect seal; indeed, turbulence from a small amount of gas slippage around the plunger is necessary to keep liquids above and gas below the plunger. A more efficient seal limits slippage and allows the plunger to travel more slowly, which reduces the energy and pressure required to lift the plunger and liquid load. Less efficient seals allow excessive slippage, and so increase the energy and pressure required to operate the plunger. The velocity at which the plunger travels up the tubing also affects plunger efficiency (Figure 1). Very low velocities increase gas slippage and lead to inefficient operation and possible plunger stall.
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. Plunger lift operation requires available gas to provide the lifting force, in sufficient quantity per barrel of liquid for a given well depth. The minimum GLR requirement is approximately 400 scf/bbl per 1,000 ft of well depth and is based on the energy stored in a compressed volume of 400 scf of gas expanding under the hydrostatic head of 1 bbl of liquid. One drawback to this rule of thumb is that it does not consider line pressures.
Plunger lift is used for recovery, primarily in high gas-oil ratio (GOR) wells, in many countries. Applications include wells with depths of 1,000 to 16,000 ft, producing bottomhole pressures of 50 to 1,500 psia, and liquid rates of 1 to 100 B/D. These are common ranges of application, but not necessarily limits of operation. The most common plunger lift applications are for liquid removal in gas wells, but plungers also are used successfully for oil production in high gas liquid ratio (GLR) oil wells, in conjunction with intermittent gas lift operations,    and to control paraffin and hydrates. In fact, plungers have been installed on wells for the sole purpose of preventing paraffin or hydrate buildup, thereby reducing paraffin scraping or methanol injection.
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. For reference, Figure 1 is a full wellbore schematic of major plunger-lift components, and Figure 1 is a plunger-lift troubleshooting guide. Numbers represent rank in order of most likely solution. There are many plunger-lift manufacturers and equipment options, so quality and design vary. 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.
Introduction Plunger lift has become a widely accepted and economical artificial-lift alternative, especially in high-gas/liquid-ratio (GLR) gas and oil wells (Figure 1.1). 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. Figure 1.1--Plunger installed in Canada. 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. A plunger changes the rules for liquid removal. In a well without a plunger, gas velocity must be high to remove liquids, but with a plunger, gas velocity can be very low. Thus, the plunger system is economical because it needs minimal equipment and uses the well's gas pressure as the energy source. Used with low line pressures or compression, plunger lift can produce many types of wells to depletion. In recent years, the advent of microprocessors and electronic controllers, the studies detailing the importance of plunger seal and velocity, 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. 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.
Plunger lift has become a widely accepted and economical artificial lift alternative, especially in high-gas/liquid-ratio (GLR) gas and oil wells (Figure 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. Figure 1--Plunger installed in Canada. In recent years, the advent of microprocessors and electronic controllers, the studies detailing the importance of plunger seal and velocity, and an increased focus on gas production have led to a much wider use and broader application of plunger lift.
For a low-pressure well with solids and/or heavy oil at a depth of less than approximately 6,000 ft and if the well temperature is not high (75 to 150 F typical, approximately 250 F or higher maximum), a PCP should be evaluated. Even if problems do not exist, a PCP might be a good choice to take advantage of its good power efficiency. If the application is offshore, or if pulling the well is very expensive and the well is most likely deviated, ESPCP should be considered so that rod/tubing wear is not excessive. There is an ESPCP option that allows wire lining out a failed pump from the well while leaving the seal section, gearbox, motor, and cable installed for continued use.
Summary The objective of this study is the experimental and theoretical investigation of the fall mechanics of continuous flow plungers. Fall velocity of the two-piece plungers with different sleeve and ball combinations and bypass plungers are examined in both static and dynamic conditions to develop a drag coefficient relationship. The dimensionless analysis conducted included the wall effect, inclination, and the liquid holdup correction of the fall stage. A fall model is developed to estimate fall velocities of the ball, sleeve, and bypass plungers. Sensitivity analysis is performed to reveal influential parameters to the fall velocity of continuous flow plungers. In a static facility, four sleeves with different height, weight, and outer diameter (OD); three balls made with different materials; and a bypass plunger are tested in four different mediums. The wall effect on the settling velocity is defined, and it is used to validate the ball drag coefficient results obtained from the experimental setup. Two-phase flow experiments were conducted by injecting gas into the static liquid column, and the liquid holdup effect on the drag coefficient is observed. Experiments in a dynamic facility are used for liquid holdup and deviation corrections. The fall model is developed to estimate fall velocities of the continuous flow plungers against the flow. Dimensionless parameters obtained in the experiments are combined with multiphase flow simulation to estimate the fall velocity of plungers in the field scale. Reference drag coefficient values of plungers are obtained for respective Reynolds number values. Experimental wall effect, liquid holdup, and inclination corrections are provided. The fall model results for separation time, fall velocity, total fall duration, and maximum flow rate to fall against are estimated for different cases. Sensitivity analysis showed that the drag coefficient, the weight of plungers, pressure, and gas flow rate are the most influential parameters for the fall velocity of the plungers. Furthermore, the fall model revealed that plungers fall slowest at the wellhead conditions for the range of gas flow rates experienced in field conditions. Lower pressure at the wellhead had two opposing effects; namely, reduced gas density, thereby reducing the drag and gas expansion that increased the gas velocity, which in turn increased the drag. Estimating fall velocity of continuous flow plungers is crucial to optimize ball and sleeve separation time, plunger selection, and the gas injection rate for plunger-assisted gas lift (PAGL). The fall model provides maximum flow rate to fall against, which is defined as the upper operational boundary for continuous flow plungers. This study presents a new methodology to predict fall velocity using the drag coefficient vs. Reynolds number relationship, wall effect, liquid holdup, deviation corrections, and incorporating multiphase flow simulation.