A Dynamic Plunger Lift Model for Gas Wells
- Sandro Gasbarri (U. of Oklahoma) | Michael L. Wiggins (U. of Oklahoma)
- Document ID
- Society of Petroleum Engineers
- SPE Production & Facilities
- Publication Date
- May 2001
- Document Type
- Journal Paper
- 89 - 96
- 2001. Society of Petroleum Engineers
- 3.1.5 Plunger lift, 4.1.2 Separation and Treating, 2.4.3 Sand/Solids Control, 3.1.1 Beam and related pumping techniques, 5.2.1 Phase Behavior and PVT Measurements, 5.3.2 Multiphase Flow, 3.1.6 Gas Lift, 4.3.4 Scale, 4.2 Pipelines, Flowlines and Risers, 3.2.5 Produced Sand / Solids Management and Control, 3.1 Artificial Lift Systems, 4.6 Natural Gas, 4.1.5 Processing Equipment
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Many low-volume gas wells produce at suboptimum rates because of liquid loading caused by an accumulation of liquids in the wellbore that creates additional backpressure on the reservoir and reduces production. Plunger lift is an artificial lift method which can use reservoir energy to remove these accumulated liquids from the wellbore and improve production. Lacking a thorough understanding of plunger lift systems leads to disappointing results in many applications. This study develops a plunger lift model that couples the dynamic nature of the mechanical plunger lift system with the reservoir performance. The model takes advantage of previous work and incorporates frictional effects of the liquid slug and the expanding gas above and below the plunger. The model considers separator and flowline effects and includes modeling of transient production behavior after the liquid slug has arrived at the surface. An improved understanding of plunger lift dynamics can lead to improved efficiency, increased production and recovery, and extended well life.
A free piston or plunger traveling up and down the tubing has been used for different applications in oil and gas production for decades. The most widespread use is in conventional plunger lift. This method is an artificial lift technique characterized by the use of reservoir energy stored in the gas phase to lift fluids to the surface. Fig. 1 is a schematic of a typical plunger lift installation. The plunger acts as an interface between the liquid slug and the gas which helps reduce the characteristic ballistic-shape flow pattern of the higher velocity gas phase breaking through the liquid phase during production.
With appropriate installation and well-production characteristics, gas produced by the reservoir is stored primarily in the tubing-casing annulus while a liquid slug is accumulated in the tubing. During this condition, called the buildup stage, the flowline valve at the surface is closed with some gas also accumulated in the tubing above the liquid slug. After a time, when the casing pressure at the wellhead is believed to be adequate, the flowline valve opens and production begins. Gas at the top of the liquid slug expands and the plunger, along with the accumulated liquid, begins traveling up the tubing in a period called the upstroke stage. Gas stored in the tubing-casing annulus expands and provides the energy required to lift the liquid slug. As the plunger approaches the surface, the liquid slug is produced into the flowline.
In some cases, especially for gas wells, additional production after the plunger has surfaced is appropriate, increasing the flowing time for each cycle. Such a period is called afterflow in oil wells and blowdown in gas wells. After this period of flow, the flowline is closed, the buildup stage starts again, and the plunger falls to the bottom of the well starting a new cycle.
Using the plunger as a solid interface between the expanding gas in the annulus and the liquid slug helps prevent gas breaking through the slug and decreases liquid fallback. Liquid fallback is undesirable because it represents volume loss from the original liquid slug during each cycle. The additional liquid increases the bottomhole flowing pressure and, hence, decreases production.
In general, plunger lift installations are used to produce high gas-liquid ratio (GLR) oil wells or for unloading liquids in gas wells. Major advantages over other artificial lift methods for lifting liquids, such as sucker rod pump installations, are the relatively small investment and reasonable operating costs. Limitations include having a sufficient GLR to supply the energy for lifting liquids from the wellbore, and sand-production problems. The main disadvantages of plunger lift systems, however, are the complexity of the lifting process and a lack of understanding of optimizing and troubleshooting the lift method.
Several authors have addressed the modeling of plunger lift installations. Static models have been proposed and are accepted widely for design due to their simplicity.1-3 Dynamic models also have been published to describe the phenomena of a plunger lift cycle.4-10 Accuracy of the dynamic models does not always outweigh the time and data required for designing and analyzing plunger lift system performance.
The dynamic model developed in this paper overcomes some of the assumptions used in previous models. It includes reservoir performance, gas expansion with friction effects, and the transient behavior of the gas above the slug when the surface valve is opened. It also incorporates a blowdown or afterflow period for production after the liquid slug surfaces. The upstroke modeling includes a transition phase that accounts for the production of the slug to the flowline.
Plunger Lift Model
Fundamental conservation equations were used to derive the model, which analyzes the dynamics of the plunger lift system using properties in multiple control volumes, one next to the other, including the flowline, tubing, and annulus. The model is divided into upstroke, blowdown, buildup, and reservoir performance components.
The upstroke component separates the dynamics of the plunger and liquid upstroke from the boundary conditions given by the gas system above the slug and the gas system behind the plunger. The blowdown component produces the slug to the separator and accounts for additional gas production after the plunger surfaces. The buildup component describes the increase in system pressure, the accumulation of fluids (liquids and vapors) in the system during shut-in, and accounts for the downstroke behavior of the plunger. Finally, the reservoir performance component describes the influx of fluids into the wellbore throughout the plunger cycle.
To model the dynamics of the system during the upstroke, three different elements are used. Fig. 2 is a schematic of the system being modeled. The liquid slug traveling from the bottom of the well to the surface is analyzed as a separate element with given boundary conditions consisting of the pressures at the top of the slug and at the bottom of the plunger which are determined in the second and third elements. The pressure at the top of the slug is obtained by analyzing the gas expansion above the slug when the valve is opened. The pressure at the bottom of the plunger is determined by analyzing the gas expansion in the tubing below the plunger and in the tubing-casing annulus.Plunger and Liquid Slug Dynamics.
For the liquid slug traveling through the tubing, a control volume occupied by the liquid contained in the slug with average properties is used. As Lea4 originally did in his work, the equation of momentum is applied for a single-phase liquid, assuming the liquid density is constant. If no liquid is gained or lost from the control volume shown in Fig. 3, the equation of momentum can be solved for the acceleration of the slug in the tubing.
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