Controlling Effect of Seepage Channels in Tight Reservoirs on Fluid Flow Capacity Based on Pore–Throat Network Numerical Simulation and Fluid Injection Experiments

Micron-scale pores and their connecting throats govern fluid transport in tight reservoirs, yet seepage channel differences among lithologies remain poorly quantified. This study uses scanning electron microscopy (SEM) images of shale, siltstone, carbonate rock, and conglomerate to extract pore–throat networks and simulate fluid invasion under different minimum throat radii. Flow capacity is quantified by the fluid-accessible pore volume fraction and validated with constant-rate mercury injection (CRMI) and nuclear magnetic resonance (NMR). Shale and siltstone are dominated by fine throats, with a mean throat radius of about 0.2 μm, and contain abundant narrow pathways that are difficult to connect. As the minimum throat radius increases from 0.05 μm to 1.00 μm, the accessible pore volume fraction decreases from about 0.9 to about 0.6, indicating strong sensitivity to throat size. Carbonate rock and conglomerate show larger throats, with a mean radius of about 0.35 to 0.45 μm, and a better-developed connected framework. Under the same conditions, the fluid flow capacity index (Ff) remains relatively stable from about 0.95 to 0.75. Based on these responses, two structure flow control types are proposed: a geometric homogeneity-dominated type for shale and siltstone, and a connectivity-dominated type for carbonate rock and conglomerate. These results quantitatively link microstructural attributes to flow capacity, supporting tight reservoir evaluation and differentiated stimulation strategies.