Controls of anisotropy and pore connectivity on gas retainment and flow in deep shale of Longmaxi Formation

A comprehensive understanding of pore-scale anisotropy and connectivity is critical for evaluating shale gas storage and flow behavior. However, the pore-scale coupling between pore anisotropy and gas permeability remains poorly quantified, particularly in deep shale systems. This study integrated small-angle neutron scattering (SANS), directional gas permeability testing, mercury intrusion capillary pressure (MICP), Wood’s metal (WM) injection and field-emission scanning electron microscopy (FE-SEM) to systematically investigate four deep Longmaxi Formation shale samples. Results indicate that total organic carbon (TOC) and mineralogical composition (quartz and clay content) are the primary controls on nanopore alignment, connectivity and pore anisotropy. Shales with high TOC and quartz content exhibit relatively isotropic pore network connectivity, whereas those with low TOC and high clay content display profound pore anisotropy in their connectivity. Bedding-parallel microfractures are the main contributors to directional gas permeability variations, with horizontal-to-vertical gas permeability ratios ranging from 7.58 to 16.43, highlighting significant gas flow direction dependence (gas permeability anisotropy). Modulus-corrected mercury intrusion and imaging analyses further reveal that nanoconfined pores exhibit limited connectivity, and fracture–matrix connectivity is limited. These findings provide new insights into the role of pore-scale directional connectivity and fracture–matrix decoupling in controlling gas migration and retention in deep shale reservoirs.