<p>Massive liquid injection into tight sandstone enhances flow channels and energy recovery. However, the coupling among fluid injection, microscopic pore-structure response, and flow evolution remains insufficiently understood. Furthermore, the effects of key controlling factors are still unclear. Here we employ online nuclear magnetic resonance (NMR) to quantitatively track microfracture response and flow behavior during this process. Stress analysis and grey relational analysis (GRA) are used to interpret the mechanical mechanism and summarize the relative controls of key influencing factors on flow capacity. The results indicate that microfractures open in tension because pore pressure reduces effective normal stress on fracture surfaces and concentrates stress near weak zones, with the opening direction perpendicular to effective minimum principal stress. Relative fracture toughness decreases with pore pressure, and the difference between matrix and fracture rocks narrows at high pore pressure. Matrix rocks respond more strongly because pre-existing fractures guide fluid preferentially and delay pressure sweep into the matrix, resulting in porosity and permeability increase of 9.69–17.22% and 2.13–2.42 times higher. Bound water occupies effective flow space at low pore pressure and redistributes fluids in micro- and mesopores as capillary and viscous forces compete, while high pore pressure promotes microfracture opening in matrix rocks near the injection. When bound water coexists with fractures, lagging fluid migration increases interphase pressure and mobilizes water films, gradually releasing flow paths. These findings suggest that bound water saturation should be prioritized in massive liquid injection, followed by dynamic control of shear stress and pore pressure.</p>