The Tarim Basin boasts significant reserves of deep, high-pressure natural gas. However, these reservoirs encounter challenges as actual development outcomes fall short of planned expectations. Ultra-deep fractured low-porosity sandstone gas reservoirs are characterized by deep burial, dense matrix, and well-developed fractures. Using the DA gas reservoir as an example, this paper conducts multidisciplinary joint research and has developed new dynamic characterization methods such as physical simulation, modeling, and numerical simulation for such water-bearing gas reservoirs. A novel large-scale physical simulation device was developed to more accurately simulate water invasion dynamics, surpassing traditional core-scale models in realism. A comprehensive approach includes field observations, core analysis, imaging logs, well tests, production data, and water invasion simulation experiments, alongside development practice verification, to systematically explores these dynamics. Additionally, the study incorporates geological and numerical simulation methods that account for changes in the dynamic stress and permeability fields, establishing a model for fracture behavior over time and space. This method yields historical and predictive results that align closely with actual production dynamics. Firstly, physical simulation experiments (820*420*50 mm) confirm that large fractures serve as principal flow pathways during triple media permeation, with edge and bottom water advancing swiftly through these channels. The study on DA gas reservoir highlights several key findings regarding its fracture systems and dynamics. Secondly, the north–south fault system is more open and effective than the east–west system, with fracture development peaking at the core, diminishing westward, and least pronounced at the wing. These fractures are less filled and have a smaller angle, mainly occurring around 20 m at the base, influenced by fault planes, micro-faults, and lithology. Numerical modeling indicates that the bottom water in the south rapidly invades the top areas along the north–south oriented fractures, causing the wells in the top areas to encounter water earlier than those in the lower areas of the eastern and western wings. The degree of fracture development in the eastern and western wings is low, and the speed of edge water invasion is relatively slow. Based on water invasion performance, a development strategy of “controlling high areas and draining low areas” is proposed, which is expected to increase the recovery by 5%. Large-scale visual water invasion physical simulations are closer to the actual flow performance in reservoirs compared to core-scale simulations. The “pore-fracture-fault” triple-medium modeling and embedded discrete fracture network numerical simulation methods, compared to traditional dual-medium modeling and numerical methods, align more closely with actual production dynamics and water invasion characteristics. This approach can more rationally guide the formulation of gas field development technical policies, thereby improving the recovery of natural gas and economic benefits.