A Dynamic Plunger Lift Model for Gas Wells

Abstract

Abstract Many low volume gas wells produce at suboptimum rates due to liquid loading. This situation is 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 utilize reservoir energy to remove these accumulated liquids from the wellbore and improve production. Unfortunately, the lack of 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. Introduction 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 an appropriate installation and well production characteristics, the gas produced by the reservoir is primarily stored 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 certain time, when the casing pressure at the wellhead is believed to be adequate, the flowline valve opens and production begins. The 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. The 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 generally called afterflow in oil wells and blowdown for 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. The use of 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 as 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, however, of plunger lift systems are the complexity of the lifting process and a lack of understanding of optimizing and troubleshooting the lift method. P. 295^