Loading In Gas Wells Research Articles

A New Approach for Accurate Prediction of Loading in Gas Wells Under Different Flowina Conditions

Summary Several authors have introduced various mathematical equations to calculate the critical flow rate necessary to keep gas wells unloaded. The most widely used equation is that of Turner et al.1 However, Turner's equation required empirical adjustment with different ranges of data which made the application rather questionable. In this paper we present a new approach for calculating the critical flow rate necessary to keep gas wells unloaded. This approach still adopts Turner's basic concepts, but considers different flow conditions that result in different flow regimes. Hence it explains the previous discrepancies of Turner's equation (the droplet model) with different data ranges, and presents a new set of equations that eliminates the need for empirical adjustment and better matches actual data records.

Case Histories: Identification of and Remedial Action for Liquid Loading in Gas Wells Intermediate Shelf Gas Play

This paper describes how liquid loading in gas wells inhibited gas production in the Intermediate Shelf gas play in southwest Texas. Actual production in the Intermediate Shelf gas play in southwest Texas. Actual case histories are used to illustrate how to identify and remedy liquid loading in low-volume gas wells. Methods such as plunger lift, beam pump, small-ID tubing, foam injection, and flow controllers are discussed and illustrated. Introduction In the Intermediate Shelf area of southwest Texas, Amoco Production Co. drilled more than 200 gas wells from 1974 through 1976. The wells were drilled to develop Wolfcamp- and Canyon-age sands in Crockett, Schleicher, Sutton, and Edwards counties. The producing sands occur at depths ranging from 3,000 to more than 7,500 ft and are characterized by very low permeability. Many of the wells produce small volumes of water along with the gas. The majority of the wells produce at gas rates too low to unload continually even small water production rates. As a result, gas well productivity is restricted. This paper describes the results of efforts to define the liquid-loading problem and to develop corrective measures to maximize producing rates.Generally, field experience has confirmed that critical velocities occur near 1,000 ft/min as cited in the literature. Case histories will be presented to demonstrate minimum gas producing rates required to unload produced liquids at various tubing pressures. Field data and graphs of wellhead pressure pressures. Field data and graphs of wellhead pressure vs. critical gas rates will be presented for various tubing sizes, which will illustrate operating conditions where liquid loading can become a factor.To eliminate or minimize liquid loading, several methods have been used. Plunger lifts, small-ID tubing, and beam pumping equipment have been used extensively. Operating conditions where each was found to have application will be outlined along with documentation of results. Other methods of liquid unloading that have been attempted include soap injection, downhole flow controllers, and intermitting well flow. These results are presented.In gas reservoirs where a liquid phase is associated with a gas phase, the presence of the liquid phase can affect significantly a gas well's flowing characteristics. Liquid loading in gas wells occurs when formation water and/or condensate are not removed continuously from the wellbore. To initiate mist or drop flow in the wellbore, the gas phase must provide an adequate amount of transport energy for the continuous removal of liquids. Hydrostatic back-pressure exerted by even small accumulations of liquid in the wellbore can restrict gas well productivity severely. productivity severely. Five basic methods were implemented to remedy liquid loading in the Intermediate Shelf gas play (Fig. 1): pumping units, plunger lifts, small-ID tubing, soap injection, and flow controllers. This paper presents several case histories and discusses the presents several case histories and discusses the various means used to identify and remedy liquid loading on gas wells in the play.At the time of this study, Amoco's portion of the Intermediate Shelf gas play consisted of 137 producing wells located near Sonora, TX, in the producing wells located near Sonora, TX, in the southeastern portion of the Permian basin. JPT P. 685