Pore geometry in gas shale reservoirs
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Assessing shale formations is a major challenge in the oil and gas industry. The complexities are mainly due to the ultra-low permeability, the presence of a high percentage of clay, and the heterogeneity of the formation. Knowledge and understanding of rock properties, including pore geometry, permeability, and fluid distribution are essential for determining shale’s hydrocarbon storage and recovery. This chapter discusses the microstructural characterization of gas shale samples through mercury injection capillary pressure (MICP), low field nuclear magnetic resonance (NMR) and nitrogen adsorption (N2). High resolution focused ion beam-scanning electron microscopy (FIB/SEM) image analysis is used to further support the experimental pore structure interpretations at sub-micron level. The chapter focuses on three key areas: (i) comparisons of pore size distribution (PSD); (ii) recognizing the relationship between pore geometry and permeability; (iii) effects of clay occurrence on fluid transport properties. MICP and N2 are destructive techniques used as pore size distribution (PSD) measurements. MICP is capable of characterizing the PSD in the range of meso-pores (5 nm < pore diameter > 50 nm: intra- and inter-clays) to macro-pores (pore diameter > 50nm: inter-grains and discontinuities) while N2 can be applied to pores less than 2 nm. NMR is a non-destructive technique that is performed under room conditions. It supposes that the sample is fully or partially water saturated.In contrast with MICP PSD, that provides only "connected" pore throats as tube shapes and no pore body sensu-stricto, NMR PSD provides full experimental characterization of pore geometry, the size of the pore body behind the throats and the isolated pores. The pore body to pore throat ratio is a characteristic that controls fluid flow. The connectivity in the pore system can be represented by the pore body to pore throat size ratio: the lower the ratio, the lower the connectivity; hence the lower will be the permeability/fluid flow. The results demonstrated a complex geometry of the pore network from clay-rich rocks. The siliceous and organic rich gas shales studied are marked by a strong component of clay minerals, mostly made of Kaolinite and illite/smectite (I/S) mixed layers. Three types of shales can be classified according to their clay content: (i) low I/S but high Kaolinite; (ii) high I/S but low Kaolinite; and (iii) high I/S and high Kaolinite. It is understood that I/S acts as a fluid trapping mineral by increasing the pore geometry complexity (surface to volume ratio increase) but generates low porosity made up of micro-porosity. Kaolinite acts as fluid storage by clogging pores and helps to keep high porosity made up of relatively larger pores. The combination of MICP, N2 and NMR forms an ideal approach to overcome each of their individual limits in terms of pore size resolution and the external influences (dehydration/hydration state or sample preparation).
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