The pore structure of unconventional gas reservoirs, despite having a significant impact on hydrocarbon storage and transport, has historically been difficult to characterize because of a wide poresize distribution (PSD), with a significant pore volume (PV) in the nanopore range. A variety of methods is typically required to characterize the full pore spectrum, with each individual technique limited to a certain pore size range.In this work, we investigate the use of nondestructive, low-pressure adsorption methods, in particular low-pressure N 2 adsorption analysis, to infer pore shape and to determine PSDs of a tight gas siltstone reservoir in western Canada. Unlike previous studies, core-plug samples, not crushed samples, are used for isotherm analysis, allowing an undisturbed pore structure (i.e., uncrushed) to be analyzed. Furthermore, the core plugs used for isotherm analysis are subsamples (end pieces) of cores for which mercury-injection capillary pressure (MICP) and permeability measurements were previously performed, allowing a more direct comparison with these techniques. PSDs, determined from two isotherm interpretation methods [Barrett-Joyner-Halenda (BJH) theory and density functional theory (DFT)], are in reasonable agreement with MICP data for the portion of the PSD sampled by both. The pore geometry is interpreted as slot-shaped, as inferred from isotherm hysteresis loop shape, the agreement between adsorption-and MICP-derived dominant pore sizes, scanning-electron-microscope (SEM) imaging, and the character of measured permeability stress dependence. Although correlations between inorganic composition and total organic carbon (TOC) and between dominant pore-throat size and permeability are weak, the sample with the lowest illite clay and TOC content has the largest dominant pore-throat size and highest permeability, as estimated from MICP. The presence of stress relief-induced microfractures, however, appears to affect laboratory-derived (pressure-decay and pulse-decay) estimates of permeability for some samples, even after application of confining pressure.On the basis of the premise of slot-shaped pore geometry, fractured rock models (matchstick and cube) were used to predict absolute permeability, by use of dominant pore-throat size from MICP/adsorption analysis and porosity measured under confining pressure. The predictions are reasonable, although permeability is mostly overpredicted for samples that are unaffected by stressrelease fractures. The conceptual model used to justify the application of these models is slot pores at grain boundaries or between organic matter and framework grains.

The pore structure of unconventional gas reservoirs, despite having a significant impact on hydrocarbon storage and transport, has historically been difficult to characterize due to a wide pore size distribution, with a significant pore volume in the nanopore range. A variety of methods are typically required to characterize the full pore spectrum, with each individual technique limited to a certain pore size range. In this work, we investigate the use of non-destructive, low-pressure adsorption methods, in particular low pressure N2 adsorption analysis, to infer pore shape, and to determine pore size distributions of a tight gas/shale reservoir in Western Canada. Unlike previous studies, core plug samples, not crushed samples, are used for isotherm analysis, allowing an undisturbed pore structure to be analyzed. Further, the core plugs used for isotherm analysis are subsamples (end pieces) of cores for which MICP and permeability measurements were previously made, allowing a more direct comparison with these techniques. Pore size distributions determined from two isotherm interpretation methods (BJH Theory and Density Functional Theory), are in reasonable agreement with MICP, for that portion of the pore size distribution sampled by both. The pore geometry is interpreted to be slit-shaped, as inferred from isotherm hysteresis loop shape, the agreement between adsorption- and MICP-derived dominant pore sizes, SEM imaging and the character of measured permeability stress-dependence. Although correlations between inorganic composition and total organic carbon (TOC) and dominant pore throat size and permeability are weak, the sample with the lowest illite clay and TOC content has the largest dominant pore throat size and highest permeability, as estimated from MICP. The presence of stress-relief-induced microfractures, however, appears to affect lab-derived (pressure-decay and pulse-decay) estimates of permeability, even after application of confining pressure. Based on the premise of slit-shaped pore geometry, fractured rock models (matchstick and cube) were used to predict absolute permeability, using dominant pore throat size from MICP/adsorption analysis and porosity measured under confining pressure. The predictions are reasonable, although permeability is mostly over-predicted for samples that are unaffected by stress-release fractures. The conceptual model used to justify the application of these models is slot pores at grain boundaries.