A review of 289 completions in Ochiltree County, Texas, shows 137 classified gas completions currently produce with the aid of artificial lift. Two methods of artificial lift, beam pumping units and plunger lift, were identified in the review. The study revealed that 130 gas wells produce with the aid of a plunger lift, while only 7 gas wells produce with the aid of a beam pumping unit. This paper reports on historical results obtained from using plunger lift systems. The historical results are compared to published methods for predicting liquid loading and plunger lift production responses. An evaluation of the historical plunger lift production responses and installation workover costs show that an impressive 32 BCF of reserves were added at a cost of less than $0.06/MCF.
Artificial lift is a requirement in gas wells when velocities in the production string drop below a critical rate. Below the critical rate, liquids migrate down the tubing and collect at the bottom of the completion. This liquid build-up condition effectively increases the bottom hole flowing pressure and in many cases results in killing the well. The most obvious surface condition of this phenomena is "heading" on the gas sales chart.
With the ongoing emphasis on optimizing production while lowering lifting costs, many operators are evaluating methods of artificial lift in tight gas sands. Techniques to remove wellbore liquids from gas wells have become increasingly more sophisticated. Experience has shown that continuous removal of wellbore liquids can significantly increase gas production. The plunger provides a mechanical interface between wellbore liquids and produced gas. Liquids are brought to the surface by the movement of the plunger traveling from the bottom of the well to the surface. This interface eliminates liquid fall-back, increasing the efficiency of the gas to lift liquid and remove liquids from the wellbore. The increased efficiency results in lower flowing bottom hole pressures. Gas stored in the tubing/casing annulus provides the energy to lift the plunger and the wellbore liquids to surface.
In this study, conventional tubing plunger lift systems are evaluated. The typical well configuration consists of a bottomhole spring located at depth inside the tubing. On the surface, a lubricator and catcher are mounted above the master valve. The plungers use high efficiency steel pad-type seals.