Insights into the pore structure and implications for fluid flow capacity of tight gas sandstone: A case study in the upper paleozoic of the Ordos Basin

Abstract Tight gas sandstone is characterized by varied pore structures, controlling the fluid flow and influencing the gas productivity. A combination of casting thin section, scanning electron microscopy, pressure-controlled porosimetry, X-ray computed tomography, nuclear magnetic resonance, X-ray diffraction, and grain size analysis is conducted on the Permian aged tight gas sandstone in the Daniudi area of the Ordos Basin to investigate the overall pore structure, its controlling factors, and its influences on the fluid mobility. Pores of tight gas sandstone are in a wide size range 65 nm–100 μm dominated by Gaussian and bimodal distribution patterns and can be divided into intergranular and intragranular pores according to the fractal features. Varied pore structures are attributed to the differences in compaction and cementation. High framework grain content and large grain size benefit the intergranular porosity preservation, resulting in larger pore volumes, greater pore radii, and better connectivity. Calcite and clay cements dominate the tightening of tight gas sandstone. According to the connection between pore structure and its main geological controlling factors, the grain-supported intergranular pore model with high rigid grain content, large grain size, and dominant intergranular porosity, compaction intergranular pore model with relative low rigid grain content, smaller grain size, medium cement content, and mixed intergranular and intragranular porosities, and cementation intragranular pore model with small grain size, high cements content, and dominant intragranular porosity are defined. Correlation analyses indicate that the reservoir quality and fluid mobility are controlled by pore structures. The porosity exhibit a strong positive dependence on the average pore volume, while permeability is determined by median pore radius, coordination number, and intergranular pore proportion. Movable fluids occur in a wide pore range between 96 nm and 98 μm, with their minimum and upper bound radii positively correlated with permeability. Movable porosity can serve as a direct indicator for fluid flow capacity, which is determined by the movable porosity contribution of intergranular pores. The increasing negative influence of intragranular pores on fluid flow should be taken into account with decreasing permeability and increasing clay content. The grain-supported pore model is deduced to be characterized by the highest fluid mobility, indicating a great tight gas production potential.