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Shale reservoir heterogeneity is strong, which seriously affects shale gas reservoir evaluation and reserves estimation. The Longmaxi Formation shale of the Luzhou block in southern Sichuan was taken as an example to characterize the pore distribution of shale over the full scale using micro-computed tomography (CT), focusing on ion beam scanning electron microscopy (FIB-SEM) and small-angle neutron scattering (SANS); further, the heterogeneity of the shale pore distribution over the full scale was explored quantitatively within different scales. The results show that shale micropores are dominated by microfractures that are mainly developed along the bedding direction and associated with organic matter, contributing 1.24% of porosity. Shale nanopores are more developed, contributing 3.57–4.72% porosity and have strong heterogeneity locally at the microscale, but the pore distribution characteristics show lateral homogeneity and vertical heterogeneity at the macroscale. In the same layer, the porosity difference is only 0.1% for the sheet samples with 2 cm adjacent to each other. Therefore, in shale core experiments in which parallel samples are needed for comparison, parallel samples should be in the same bedding position. This paper explores the extent of heterogeneity over the full scale of pore distribution from macro to micro, which has important significance for accurately characterizing the pore distribution of shale and further carrying out reservoir evaluation and estimation of reserves. [ABSTRACT FROM AUTHOR]

The upper Ordovician Wufeng Shale and lower Silurian Longmaxi Shale are part of the Fuling shale gas play located in the south-eastern part of the Sichuan Basin, southern China, representing the first commercial shale gas production project outside North America. We studied the occurrence of porosity at the micro- and nano-scale in samples of contrasting organic richness representing the typical lithofacies from the post-mature part of the Wufeng-Longmaxi gas play. Using a combination of site specific, high-resolution scanning and transmission electron microscopy with bulk measurements based on small angle neutron scattering and cryogenic Argon physisorption, along with conventional organic petrology, we highlight the impact of different types of organic matter (OM) (primary versus secondary) on the development of OM-hosted porosity. The results indicate that at the bulk scale the overall porosity in the samples is proportional to their organic content and organic hosted pore account for 30–40% of the total pore volume of the rocks. Nevertheless, most of the pores identified via electron microscopy imaging seem to reside in the organic matter, indicating that potentially a large part of the pores volume detected by neutron scattering and Argon physisorption is visually not detected. Organic matter focused nanoscale imaging revealed that mesopores are preferentially present in the solid bitumen and not in the primary detrital organic particles. Organic lean samples show low porosity and dominance of micropores, while organic-rich samples show higher porosity and a broader spectrum of pore sizes. Importantly, most of the meso pores are located in organic matter petrographically interpreted as solid bitumen, while detrital organic particles like graptolites show minimal visible porosity under high resolution electron microscopy and pore sizes in the micro pore range (i.e. <2 nm). Distinguishing between primary and secondary OM is therefore important for understanding the creation of an interconnected network of porous OM during hydrocarbon migration. This may have an important control on the estimation of gas in place and the gas transport properties of the shale. [Display omitted] [ABSTRACT FROM AUTHOR]