Reasons for low flowback behaviors of water-based fluids in tight sandstone gas reservoirs

Water-based working fluids are widely applied in the development of tight gas formations. However, these fluids’ flowback rate is generally low than 50%, resulting in a large amount of water retention to dramatically decline the gas delivery. Typical tight sandstone core samples are selected in this study to perform the gas-driven water displacement experiment to investigate the underlying mechanisms for the low water flowback behaviors in tight gas reservoirs. Results show that the average water flowback rate for 15 tight sandstone samples by gas-driven water displacement is obtained to be only 31.31%, which in turn causes an average gas permeability damage rate of 58.94%. Analysis suggests that multiscale pore structures, ultra-low connate water saturation phenomenon, filling of hydrophilic clay minerals, and insufficient pressure drop contribute to the congenitally unfavorable geological factors of low water flowback capacity. On the other hand, irreversible formation damages like water phase trapping, salting out issues, and residual water film effect caused by water retention are the main elements that restrict water removal during a gas-flow drying process. The findings of this study provide useful insights into the control mechanisms of low water flowback behaviors and the formation damages induced by water invasion in tight sandstone gas reservoirs.