Tight sandstone is rich in micron- and nano-scale pores, making the two-phase flow of gas and water complex. Establishing reliable relative permeability and productivity models is an urgent issue. In this study, we first used a slip model to correct the gas phase’s no-slip Hagen–Poiseuille equation for nano- and micropores. Then, combined with the fractal theory of porous media and the tortuous capillary bundle model, we established two-phase relative permeability models for nanopores and micropores. These relative permeability models comprehensively consider the gas slippage effect, the initiation pressure gradient, the pores’ fractal characteristics, and water film mechanisms. Based on these models, we developed a three-region coupling productivity model for water-bearing tight gas reservoirs with multi-stage fractured horizontal wells. This productivity model considered the micro- and nano-scale effects and the heterogeneity of fracture networks. Then, the model was solved and validated with a field case. The results indicated that the three-region composite unsteady productivity model for water-bearing tight gas reservoirs, which incorporated micro- and nano-scale effects (with consideration of micro-scale and nano-scale phenomena in the fluid flow), could accurately predict a gas well’s productivity. An analysis of the factors influencing productivity showed that ignoring the micro- and nano-scale effects in water-bearing tight gas reservoirs will underestimate the reservoir’s productivity. The initial water saturation, the two-phase flow’s initiation pressure gradient, and capillary force are all negatively correlated with the productivity of gas wells, while the conductivity of the fractures is positively correlated with gas well productivity.

Tight gas reservoirs possess unique pore structures and fluid flow mechanisms. Delving into the flow and imbibition mechanisms of water in fractured tight gas reservoirs is crucial for understanding and enhancing the development efficiency of such reservoirs. The flow of water in fractured tight gas reservoirs encompasses the flow within fractures and the imbibition flow within the matrix. However, conventional methods typically separate these two types of flow for study, failing to accurately reflect the true flow characteristics of water. In this study, micro-CT imaging techniques were utilized to evaluate the impact of matrix absorption and to examine water movement in fractured tight gas deposits. Water flooding experiments were conducted on tight sandstone cores with different fracture morphologies. Micro-CT scanning was performed on the cores after water injection and subsequent static conditions, simulating the process of water displacement gas in fractures and the displacement of gas in matrix pores by water through imbibition under reservoir conditions. Changes in gas–water distribution within fractures were observed, and the impact of fracture morphology on water displacement recovery was analyzed. Additionally, the recovery rates of fractures and matrix imbibition at different displacement stages were studied, along with the depth of water infiltration into the matrix along fracture walls. The insights gained from this investigation enhance our comprehension of the dynamics of fluid movement within tight gas deposits, laying a scientific foundation for crafting targeted development plans and boosting operational efficiency in such environments.