Zhongbo Liu

Liquid loading is inevitable during mature gas-well production, leading the liquids to accumulate at the bottomhole and additional pressure loss. Accurately predicting the liquid-loading initiation is crucial to gas-well production optimization. Significant efforts have been made to model liquid-loading behavior. However, few mechanistic models are capable of easily and accurately tackling the complicated non-uniform liquid-film distribution in the slanted section of horizontal wells. Based on liquid-film inversion, this study developed a simple and comprehensive model to calculate liquid-loading initiation for horizontal gas wells. First, the models for film thickness and critical velocity in the vertical pipe are developed. Then, considering the effect of inclination and velocity difference in liquid-film thickness and liquid-holdup distribution between vertical and inclined pipes, the relationship in vertical and inclined pipes between liquid holdup, liquid-film thickness, and angle correction term is established based on the liquid-holdup correlation for horizontal and inclined pipes described in the empirical model developed by Beggs and Brill, so that the thickness of the film and the corresponding critical velocity at any inclination can be calculated. Finally, the new modified model has been evaluated against both experimental and field-measured data set. In comparison to the Luo et al.’s model, the proposed model has been proven to be simple, accurate, and well-performed in predicting the liquid-accumulation initiation in horizontal wells.

Wellbore pressure gradient in gas wells is significant in designing deliquification technologies and optimizing production. At present, no model has yet to be established specifically for gas wells at a wide gas flowrate range. When calculating pressure gradient in a specific gas field, engineers must evaluate these widely used models and get the best performance model at a certain range. To establish a more comprehensive model in horizontal gas wells, an experimental study was conducted to investigate the flow behavior of liquid-gas two-phase flow at different gas and liquid velocities and inclined angles in a 50 mm visual pipe. The evaluation of these widely used models against the experimental data shows that no model can predict liquid holdup at different gas velocity ranges, and huge deviations due to several reasons can be observed. After conducting a comprehensive analysis, a new liquid holdup correlation was proposed based on the Mukherjee–Brill model by correlating from the experimental results, which have parametric ranges closer to the production of gas wells. This new model adopts a new dimensionless gas velocity number to characterize flow similarities and better scale up pressure from the experiment to the gas wells. By validating against experimental data and field data, the results indicate that the new two-phase flow model has stable performance and can accurately predict pressure gradients at different ranges of pressure and gas/liquid velocities.