| description abstract | Abstract. Shale gas wells often experience severe wellbore liquid accumulation during mid-to-late production period, leading to a sharp decline in gas production rate as the capacity of liquid-carrying decreases. Installing tubing or pumps can effectively mitigate these losses. However, how to determine the timing and depth of tubing or pump installation remains challenging due to variations in liquid loading along the horizontal wellbore. To fill this gap, an integrated transient multiphase flow model coupling the wellbore and reservoir was established. The novelty of this work is the optimization workflow for rodless artificial lift system installation parameters and production switching strategies, validated by a field case well. Three production scenarios are simulated, including casing production, tubing production, and pump-assisted production. History matching results show that the bottomhole pressure, liquid production rates, and gas production rates match well. Besides, too early installation of tubing may reduce gas productivity significantly. Installing pump as soon as liquid loading occurs in a shale gas well can enhance its liquid-carrying capacity, thereby increasing cumulative gas production rates. Compared to installation on 60th or 160th day, installing the pump on 80th day yields better performance and increases cumulative gas production rates. Besides, pump-assisted production increased cumulative gas production by 16.5% compared to tubing production and by 20.5% compared to casing production. Optimizing pump placement near the horizontal toe increases cumulative gas and water production by 16.9% and 57.8%, respectively. This study provides a theoretical basis for optimizing the placement location and timing of pump installation in shale gas wells, aimed at reducing production losses due to liquid loading. | |
