SPE 164516 An Experimental Study on Liquid Loading of Vertical and Deviated Gas Wells G. Yuan*, E. Pereyra, and C. Sarica, The University of Tulsa, Robert P. Sutton, Marathon Oil Company Copyright 2013, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Production and Operations Symposium held in Oklahoma City, Oklahoma, USA, 23−26 March 2013. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract The main objectives of this experimental study are to explore mechanisms controlling the onset of liquid loading and to investigate effect of well deviation on liquid loading. An experimental study of liquid loading of gas wells has been conducted with air/water flow in a 3-inch pipe at well deviations of 0°, 15° and 30° from vertical. A total of 131 tests have been carried out. Differential pressure gradient and liquid holdup were measured. Flow pattern was observed and videos were captured with a high speed video system. Critical gas velocity which defines the threshold for liquid accumulation in a well (commonly termed liquid loading) has been identified by analyzing different measurements including video captures. Results show different mechanisms for vertical and inclined pipe flows. A minimum pressure gradient criterion can be applied to determine the critical gas velocity. Well deviation angle has an effect on critical gas velocity. Performance analysis for various models has revealed their shortcomings. Introduction Natural gas is considered to be the main source of fossil energy for the next several decades. The share of shale gas in overall natural gas production is increasing significantly and is expected to dominate the natural gas supply. During the production of gas wells, liquid loading is considered one of the most important production problems. Symptoms of liquid loading include liquid slugging at surface equipment, declining or erratic water and gas production rates, and dramatic changes in wellhead pressure. Left unchecked, the water accumulation in the well increases the backpressure against the reservoir and provides a damage mechanism by saturating the near-well area with water. Any or all of these mechanisms reduce gas rate from the well and adversely affect gas recovery. In order to increase the total production from a gas well, it is important to understand the fundamentals of liquid loading process. The concept of critical gas velocity is the key parameter in describing liquid loading. There are three definitions of critical gas velocity used in literature:  The minimum gas velocity at which the largest liquid droplets entrained in the gas core can be transported upward, as used in Turner’s (1969) criterion;  The gas velocity at which the flow pattern changes from annular flow to intermittent flow;  The gas velocity at which liquid film starts to move up along the pipe wall continuously. Turner’s (1969) criterion has been widely used in the industry to predict critical gas velocity for the last several decades. Turner’s criterion is based on a force balance on a single droplet entrained in the gas core. It was proposed that the gas well loads up when the entrained droplet moves downward which is called droplet flow reversal. Turner qualified the use of the model by stating the velocity result should be increased by approximately 20% to ensure liquids do not accumulate in the well. Coleman et al. (1991) adopted the Turner et al. (1969) model to analyze the west Texas field data and found out the 20% adjustment was not needed. Many researchers made refinements and modifications to Turner’s et al. (1969) droplet model to better match different sets of field data with varying degrees of success (Guo et al., 2005 and Zhou et al., 2007). However, recent literature (Westende, 2008 and Belfroid et al., 2008) reported that onset of liquid loading is controlled by liquid film flow reversal rather than droplet flow reversal. This conclusion challenges the widely used Turner’s et al. (1969) droplet flow reversal model. (* - currently with SPT Group – A Schlumberger Company)