Impacts of nanopore structure and elastic properties on stress-dependent permeability of gas shales

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This paper presented the stress-dependent porosity and permeability measurements of shale in lower Silurian Longmaxi Formation using a PoroPDP-200 Pulse decay permeameter. The pore structure was investigated by mercury injection and nitrogen adsorption measurements. Micron-sized fractures and nanopore structure of shale samples were identified through mercury saturation curves and adsorption–desorption isotherms. Uniaxial and triaxial tests were conducted so as to measure the elastic parameters of the shale samples. Three analytical models of pore compressibility were displayed to investigate the effects of pore geometry and rock elastic properties on pore compressibility. Pulse-decay permeability measurements revealed that an exponential function could describe the permeability deterioration upon applied effective stress. The stress-dependent permeability of shale was more sensitive than sandstone because of the high pore compressibility. It could be observed from analytical models that pore compressibility increased with a decreasing pore aspect ratio and Young's modulus. Microfractures were identified by the shape of mercury capillary pressure curves. The nanopores of the shale samples were dominated by a slit-shaped geometry (low aspect ratio), which was observed by hysteresis loop of nitrogen adsorption analysis (Type H3). Uniaxial and triaxial tests results showed that static Young's modulus of shale samples were sensitive to total organic carbon (TOC) and montmorillonite-illite mixed layer content. Pore compressibility was sensitive to the aspect ratio, yet insensitive to Young's modulus above 20 GPa. When the Young's modulus was less than 20 GPa, pore compressibility was both sensitive to aspect ratio and Young's modulus. The stress-dependent permeability data of samples with micron-sized fractures could also be fitted to the Walsh model, which showed that the permeability of microfractures in shale samples were more sensitive to effective stress than hydraulic fractures because of the fracture scale. These results showed that reservoir engineers could accurately predict the stress-dependent permeability in shale, and estimate the gas flow properties in macro-scale and micro-scale pores and fractures.