Imaging-Based Characterization of Calcite-Filled Fractures and Porosity in Shales

Abstract

Gas-and liquid-rich shales exhibit structural and compositional features across a broad range of length scales from meters to nanometers. This laboratory characterization effort of a shale sample aids hydrocarbon resource and reserves estimation, and improves understanding of flow behavior including potential geological carbon dioxide storage. Multiscale laboratory-imaging techniques were applied to characterize pore and microfracture structure of a Barnett Shale sample including connectivity and heterogeneity. X-ray computed tomography (CT) illuminated the krypton (Kr)-accessible porosity of centimeter-sized shale cores. Transmission X-ray microscopy (TXM) imaged micrometer-sized shale samples, and high-resolution scanning electron microscopy (SEM) revealed pore, fracture, and textural features. Registration of 190 lm resolution CT images with micrometer to nanometer resolution TXM and SEM images improved physical understanding of transport through organic-rich shale. Results focus on calcite-filled fractures and the calcite/shale-matrix interface as well as the distribution of micrometer-and nanometer-scale porosity. Fractures are likely both natural and induced. For the sample studied, pore accessibility determined by CT imaging corresponds with open microfractures that cross calcite-filled fractures and adjacent shale matrix. Such observations are made with corresponding micrometer-to nanometer-scale SEM images as well as compositional data. Taken together, these data indicate that calcite-filled fractures in this core act as a barrier to flow parallel to bedding except where breached by numerous open fractures. In contrast, these filled fractures enhance vertical flow, that is, flow between laminations. A region containing porosity and organic matter (with dimensions of tens to hundreds of nanometers) determined by 3D nanocharacterization with TXM and focused ion beam/SEM at the filled-fracture/shale-matrix interface facilitates this observed gas transport along the wall of the fracture fill. Areas adjacent to calcite-filled fractures and carbonaceous laminations within the shale matrix of the study sample are most readily accessed by Kr and may therefore be more readily produced than comparatively clay-rich laminations. The numerous open fractures and sheet pores within the calcite fracture fill, as well as the inherent weakness of the porosity and organic matter at the fracture-fill/shale-matrix interface, are indicative of its susceptibility to reopening and fracturing.

Correlative multi-scale imaging of shales: a review and future perspectives

“…Fractures can be imaged using OM/SEM (Gale et al 2014;Gasparrini et al 2014) and XCT in 2D and 3D respectively (Kobchenko et al 2011;Vega et al 2014;Carey et al 2015) (Figure 8 a-b). SEM (Chalmers et al 2012;Wu and Aguilera 2012;Vega et al 2014) and 3D-EM (Torsaeter et al 2012;Chen et al 2015) are commonly used for micro-scale imaging of fractures. Where fractures are cement-filled, combining optical microscopy with SEM imaging can provide mineralogical and microstrucutre information.…”

“…Where fractures are cement-filled, combining optical microscopy with SEM imaging can provide mineralogical and microstrucutre information. Some scholars (Vega et al 2014;Ma 2016) have demonstrated the connectivities and heterogeneity of fractures and their distribution with minerals by using XCT (Figure 8 c). Recently, XCT is used for fracture characterisation because the sample can be imaged internally and also because image processing techniques enables the quantification and spatial distribution of shale components.…”

“…Using X-ray microtomography and nanotomography (Kanitpanyacharoen et al 2012;Zhang et al 2012;Vega et al 2014), silt-size minerals and silt-size organic matter can be imaged in 3D. Three phases including pyrites, minerals, and micropores (and fractures and kerogen) in Posidonia Shale (Figure 9 c) were quantified using x-ray microtomography (Kanitpanyacharoen et al 2012).…”

“…Some shale components cannot be clearly imaged using XCT because they are smaller than the spatial resolution of the technique or lower than the contrast resolution; this is a particular problem when more than one small component is mixed. For example, clay minerals and granular minerals mixed in one phase and kerogen and pores mixed in another phase (Figure 9 d) in Barnett Shale (Vega et al 2014). 3D-EM would be required to image these regions (Curtis et al 2010;Zhang et al 2012;Ma et al 2016).…”

Shale Gas Well, Hydraulic Fracturing, and Formation Data to Support Modeling of Gas and Water Flow in Shale Formations

“…Shale gas formations have heterogeneous mineralogy and structure (Vega et al, ). The rocks are characterized by extremely low permeability, low porosity, nanometer‐scale pore sizes, and high organic matter content (Chalmers et al, ; Clarkson et al, ).…”