Plunger lift is a method of artificial lift that uses a free piston traveling up and down inside the tubing in a cyclic manner. The piston serves to increase the efficiency of lifting liquids in gas/liquid production by reducing liquid fallback through the gas. Presented here is a description of a dynamic model of plunger lift operations that, as opposed to previous methods of analysis, includes calculation of the plunger velocity as the plunger and liquid slug travel up the tubing. Also, an analysis of plunger cycles in a high gas/liquid ratio (GLR) well is presented to indicate the maximum rate of slug buildup and the maximum casing pressure necessary to lift the plunger and accumulated liquids. The information presented allows a more detailed engineering approach to analyzing the performance of a plunger-lifted well.
Plunger lift is a method of using the energy of a gas/liquid well in a more efficient manner by allowing a free piston to travel up and down the tubing in a cyclic manner. The piston serves to reduce the fallback of liquids and to bring them to the surface with the plunger.
This method is most useful when high-GLR wells are produced and when liquid accumulations are removed from gas wells. As gas reservoirs begin to lose pressure, the gas phase becomes less efficient in bringing any liquids present to the surface. If liquids are allowed to accumulate, the liquid holdup in the tubing will increase until the well loads up and dies.
Other solutions to liquids removal include installation of smaller tubing size, rod pumping, or the use of a compressor. However, the use of a plunger can be a less expensive and, in some cases, a more permanent solution to removing liquid from a gas well as long as the natural GLR remains high. This discussion centers on intermittent cycles for gas wells, whereas most previous work focused on continuous cycles for optimal liquid production.
The following includes a discussion of previous methods that have been used to determine pressure requirements to lift a plunger with a given associated amount of well liquids.
A paper often mentioned in conjunction with plunger lift was written by Foss and Gaul1 in 1965. This paper presents some discussion of equipment and general operations, including field performance. The mathematical analysis presented is a sum of forces on the plunger at surfacing conditions only. The assumptions used in their analysis included neglecting plunger friction, gas column weight, casing tubing friction loss, and pressure differences caused by fluid entry below the plunger. Also included in the analysis are the assumption of a 1,000-ft/min rise velocity determined from field data and a 2,000-ft/min fall velocity for the plunger through gas. A fall velocity of 172 ft/min through liquid was used. These figures for plunger velocity were used to determine plunger cycle time and the resultant production figures possible for continuous cycling.
Hacksma2 presented a discussion of the use of Foss and Gaul's data in conjunction with an inflow performance relationship (IPR) curve from example wells. In his presentation, Hacksma identified in detail the plunger lift performance of wells with less than optimal gas, optimal gas, and more than optimal gas available per slug of liquid lifted by the plunger. The optimal plunger cycle was identified as a plunger-lifted well that has gas available to lift the plunger and liquid slug as soon as the plunger falls to the bottom of the well.