Liquid accumulation in the well bore resulting in reduction or complete cessation of gas well production has been defined as liquid loading. It is a phenomenon that frequently leads to sub-optimal recoveries or costly remedial solutions especially in wet and or retrograde gas development wells. There are a number of options in well completions to predict liquid loading but results from these methods often show discrepancies and are not easy to use because of the difficulties in predicting bottomhole pressure in a multiphase flow. Turner et al. (1969) created the first liquid loading model by using the theory of critical velocity, Guo et al. (2005) is one of the most recent systematic modification of Turners model but did not consider accumulation and kinetic terms which has significant effects on liquid loading. Fadairo et al. (2013), even though considered the accumulation and kinetic terms; made use of an iterative method to obtain the critical flow rate. This paper presents an improved model that describes a systematic approach for estimating liquid loading in a gas well using numerical integration method while considering the accumulation term, kinetic term and time that Turner et al. and Guo et al. neglected. As liquid loading occurs, it is crucial to recognize the problem at early stages and select the suitable prevention method. The new model is more effective when analytically compared with Turner et al. and Guo et al. models. Results show that the flow rate passes through a transient stage till it gets to a certain time where flow becomes stable. It also shows that difference in tubing diameters have effects on the rate of flow. Results further show that at some later stage during production, the minimum energy required to lift liquids out of the wellbore is higher than that required at the initial production stage. The new model is useful for operators to refine their procedures and better manage the risk of liquid loading during natural gas production. (C) 2014 Elsevier B.V. All rights reserved.
