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Abstract

Plunger Lift is a cyclic method of artificial lift that uses a plunger to establish an interface between the liquid accumulated in the production tubing and the reservoir or annulus gas pressure that will be used to lift the fluid in wells. In this work, the maximum possible liquid production rate that plunger lift will tolerate for a given depth and tubing size has been placed on a quantitative basis by means of simple equations obtained from correlations of field data. The predictive tool developed in this study can be of immense practical value for petroleum engineers to have a quick check on the maximum possible liquid production rate that plunger lift will tolerate for a given well depth and tubing size at various wells without opting for any expensive field trials. In particular, petroleum and production engineers would find the proposed method to be user-friendly with transparent calculations involving no complex expressions.

Introduction

Plunger lift is an intermittent artificial lift method that usually uses only the energy of the reservoir to produce the liquids (McCoy et al, 2003). A plunger is a free-travelling piston that fits within the production tubing and depends on well pressure to rise and solely on gravity to return to the bottom of the well. Plunger lift operates in a cyclic process with the well alternately flowing and shut-in (Gasbarri and Wiggins, 2001). 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, therefore plunger lift 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 (Lea, 1999; Lanchakov et al, 2000)

One type of a typical installation of plunger lift is shown in figure 1. Plunger-lift operations are difficult to optimize owing to a lack of knowledge concerning tubing, casing, and bottom hole pressures; liquid accumulation in the tubing; and the location of the plunger (Pagano 2006; Pagano and Eikenberg, 2006).

Because expense is involved in trying out some method of lift in a well, it is desirable to be able to predict in advance if plunger lift will work or not in a well. Even though plunger lift is not too expensive, additional equipment options can increase the initial costs(Lea et al 1999; Lea at al 2000) . Also, downtime for installation, adjustments to see if the plunger installation will perform, and adjustments to optimize production well all add to the costs (Gardner, 2009), therefore  it worthwhile to be able to predict in advance the maximum possible production rate using a plunger lift system.