Pore characterization in shales is challenging owing to the wide range of pore sizes and types present. Haynesville-Bossier shale (USA) was sampled as a typical clay-bearing siliceous, organic-rich, gas-mature shale and characterized over pore diameters ranging 2 nm to 3000 nm. Three advanced imaging techniques were utilized correlatively, including the application of Xe+ plasma focused ion beam scanning electron microscopy (plasma FIB or PFIB), complemented by the Ga+ FIB method which is now frequently used to characterise porosity and organic/inorganic phases, together with transmission electron microscope tomography of the nano-scale pores (voxel size 0.6 nm; resolution 1–2 nm). The three pore-size scales each contribute differently to the pore network. Those <10 nm (greatest number), 10 nm to 100 nm (best-connected hence controls transport properties), and >100 nm (greatest total volume hence determines fluid storativity). Four distinct pore types were found: intra-organic, organic-mineral interface, inter-mineral and intra-mineral pores were recognized, with characteristic geometries. The whole pore network comprises a globally-connected system between phyllosilicate mineral grains (diameter: 6–50 nm), and locally-clustered connected pores within porous organic matter (diameter: 200–800 nm). Integrated predictions of pore geometry, connectivity, and roles in controlling petrophysical properties were verified through experimental permeability measurements.

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As the fastest growing energy sector globally, shale and shale reservoirs have attracted the attention of both industry and scholars. However, the strong heterogeneity at different scales and the extremely fine-grained nature of shales makes macroscopic and microscopic characterisation highly challenging. Recent advances in imaging techniques have provided many novel characterisation opportunities of shale components and microstructures at multiple scales. Correlative imaging, where multiple techniques are combined, is playing an increasingly important role in the imaging and quantification of shale microstructures (for example, one can combine optical microscopy, SEM/TEM and X-ray radiography in 2D, or XCT and 3D-EM in 3D). Combined utilization of these techniques can characterize the heterogeneity of shale microstructures over a large range of scales, from macroscale to nanoscale (~10 0-10-9 m). Other chemical and physical measurements can be correlated to imaging techniques to provide complementary information for minerals, organic matter and pores. These imaging techniques and subsequent quantification methods are critically reviewed to provide an overview of the correlative imaging workflow. Applications of the above techniques for imaging particular features in different shales are demonstrated and key limitations and benefits summarized. Current challenges and future perspectives in shale imaging techniques and their applications are discussed.

The physical mechanisms that control the flow dynamics in organic-rich shale are not well understood.The challenges include nanometer-scale pores and multiscale heterogeneity in the spatial distribution of the constituents. Recently, digital rock physics (DRP), which uses high-resolution images of rock samples as input for flow simulations, has been used for shale. One important issue with images of shale rock is sub-resolution porosity (nanometer pores below the instrument resolution), which poses serious challenges for instruments and computational models. Here, we present a micro-continuum model based on the Darcy-Brinkman-Stokes framework. The method couples resolved pores and unresolved nano-porous regions using physics-based parameters that can be measured independently. The Stokes equation is used for resolved pores. The unresolved nano-porous regions are treated as a continuum, and a permeability model that accounts for slip-flow and Knudsen diffusion is employed. Adsorption/desorption and surface diffusion in organic matter are also accounted for. We apply our model to simulate gas flow in a high-resolution 3D segmented image of shale. The results indicate that the overall permeability of the sample (at fixed pressure) depends on the time scale. Early-time permeability is controlled by Stokes flow, while the late-time permeability is controlled by non-Darcy effects and surface-diffusion.

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