A Multiscale Characterization of Pore Network Heterogeneity and Its Influence on Reservoir Properties in the Permian Shihezi H8 Formation, Ordos Basin, China

The Ordos Basin, contains significant unconventional gas resources that are present in ultra-tight sandstones. However, the optimal extraction of these reservoirs largely depends on a thorough understanding of the subsurface factors that influence permeability and fluid flow at different scales. The Permian Shihezi H8 Formation in the Ordos Basin contains significant tight gas sandstone reservoirs that require thorough characterization of the complex pore network for optimal exploitation. This study integrates petrographic, mercury injection capillary pressure (MICP), scanning electron microscopy, nuclear magnetic resonance (NMR) and porosity-permeability analysis of core samples from the Tianciwan area to understand pore structure development and its influence on fluid flow properties. Results from thin sections of 6 wells revealed that Permian Shihezi H8 formation is quartz-rich (43.1%) lithic arenites with grains averaging 180-300 μm, indicating fluvio-deltaic deposition. Extensive feldspar dissolution (1.6-23.5%) generated microporosity. MICP on 60 cores showed 97.79% of pore throats were ≤1 μm, with a maximum size of 13.29 μm. NMR T2 cut-offs differentiated reservoirs into Type I (1.49-1.55 ms), Type II (4.995 ms), and Type III (0.091 μm). Porosities ranged from 3.4-8.6%, with Type I exhibiting the lowest (3.4-7.0%) and Type III the highest (8.6%), implying variable water saturation. Permeability measurements on 60 cores averaged 0.342 mD (0.030-1.941 mD), positively correlating with porosity. Type I and II reservoirs showed moderate permeability (0.144-0.270 μm), while Type III had poor connectivity (0.091 μm) and low permeability (<0.1 mD). Mercury injection capillary pressure and nuclear magnetic resonance techniques distinguished pore structure heterogeneity among wells. NMR T2 cut-offs and porosities differentiated microporous versus mesoporous-dominated pore networks, correlated to depositional and diagenetic facies. Microporous reservoirs exhibited lower porosities and water saturations compared to mesoporous analogs, implicating decreased extra phase water occupancy. Heterogeneous pore networks resulted in stratified fluid distributions that influenced permeability and producibility. Microporous Type I reservoirs exhibited lower water saturation compared to mesoporous Type III.  Understanding the relationship between pore network characteristics and fluid distributions is crucial for exploiting tight sandstone reservoirs. Reservoir characterization helps develop tailored strategies for hydrocarbon containment and flow based on heterogeneous pore-scale controls.