This paper discusses the principle of plunger lift and its possible applications.
Typical applications are:
Removal of Liquids from Gas Wells
Hi-Ratio Oil Well Production
Paraffin and Hydrate Control
Increased Efficiency of Intermittent Gas Lift Wells
Some advantages of this system are low initial cost, very little maintenance and that there is no external source of energy required in most cases. Limitations such as mechanical conditions, gas and liquid volumes and depths are also discussed. There will be a brief section concerning the various types of equipment available.
The principle of the plunger is basically the use of a free piston acting as a mechanical interface between the formation gas and the produced liquids, greatly increasing the well's lifting efficiency.
The successful operation of these systems is predicated on the assumption that the wells have no packer or have communication between the tubing and the casing at the bottom of the production string. The purpose of this paper is to describe the applications of this system to certain production problems. production problems. A typical installation consists of a stop and spring set at the bottom of the tubing string and a lubricator and catcher on the surface acting as a shock absorber at the upper end of the plunger's travel. The plunger runs the full length of the tubing between the stop and lubricator. The system is completed with the addition of a controller (time and/or pressure) and motor valve with the ability to open or close the flowline pressure) and motor valve with the ability to open or close the flowline (see Fig. 1).
Operation of the system is initiated by closing in the flowline and allowing formation gas to accumulate in the casing annulus through natural separation. The annulus acts primarily as a reservoir for storage of this gas.
After pressure builds up in the casing to a certain value, the flowline is opened. The rapid transfer of gas from the casing to the tubing in addition to gas from the formation creates a high instantaneous velocity that causes a pressure drop across the plunger and the liquid. The plunger then moves upward with all of the liquids in the tubing above it. Without this mechanical interface, only a portion of the liquids would have been recovered.
Almost all gas wells at some time during their flowing life are subject to producing liquids. As long as the conditions are such that wells are able to sustain a sufficient velocity in the tubing, liquids are carried out with the gas as multiphase flow.
Below a certain "critical velocity," liquids tend to migrate down the tubing and start to collect at the bottom. Turner, et al, shows that this critical velocity is a function of flowing well head pressure, type of liquid (water, condensate, etc.) temperature and conduit size (see Fig. 2).
For a while the well is able to unload the small slugs on its own. The surface indications are "heading" recorded on the sales chart. If no remedial measures are taken, the problem will worsen until the well loads up and dies.
Other indications of liquid loading problems are sharply decreasing production decline curves for both gas and liquids. Any well that must be production decline curves for both gas and liquids. Any well that must be "blown down" periodically is most certainly experiencing liquid loading.