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• Three main kinds of shales lithofacies are identified. • Clay-rich siliceous shales have the highest TOC content and the largest porosity. • OM related pores contribute 62.6% to the porosity of clay-rich siliceous shales. • Clay-rich siliceous shales are preferable for shale gas exploitation. Shales from Ordovician Wufeng and Silurian Longmaxi groups in the Sichuan Basin were analyzed by using the field emission-scanning electron microscopy, helium pycnometry, and low-pressure gas adsorption experiments. There are mainly three lithofacies in the studied shale reservoirs: clay-rich siliceous shale (S-3), argillaceous/siliceous mixed shale (M-2), and silica-rich argillaceous shale lithofacies (CM-1). The organic-rich S-3 shales have the highest porosity (averaging 5.4%), the largest pore volume (averaging 0.024 mL/g), and the highest specific surface area (averaging 21.6 m2/g). Organic matter (OM) pores contribute 62.6% to the porosity of S-3 shales. M-2 shales have the moderate pore structure with porosity averaging 4.3%, pore volume averaging 0.019 mL/g, and specific surface area averaging 16.7 m2/g. Organic matter and clay minerals contribute 49.5% and 36.8% to the porosity of M-2 shales, respectively. The CM-1 shales have the lowest porosity (averaging 4.1%), the smallest pore volume (averaging 0.017 mL/g), and the lowest specific surface area (averaging 15.6 m2/g). The organic-lean CM-1 shales are dominated by clay mineral pores. Clay minerals contribute 56% to the porosity of CM-1 shales. OM pores are well developed in the S-3 shale lithofacies, while most of OM pores are destroyed or compacted in CM-1 shale lithofacies. The effect of compaction on porosity of CM-1 shales is stronger than that of M-2 and S-3 shales because of the highest clay minerals content and the lowest siliceous minerals content. Considering the pore spaces and hydraulic fracturing operation, the S-3 shales is more suitable to shale gas exploration than M-2 and CM-1 shales. Certainly, the M-2 and CM-1 shales also have certain amounts of hydrocarbon storage capacity, and could be considered as the candidate targets for shale gas exploitation. [ABSTRACT FROM AUTHOR]

Widely developed in shale strata, laminae are the most typical shale sedimentary structure. To investigate their influence on shale gas reservoir quality, we conducted complementary studies by integrating microscopic observations, geochemical analyses, field-emission scanning electron microscopy (FE-SEM) imaging, and mercury intrusion capillary pressure (MICP) techniques. The microscopic observation of thin sections enabled us to detect the laminae characteristics, including the density and maximum thickness of individual lamina, and three types and stages of lamina development were identified. The total organic carbon (TOC) content, mineral composition, natural fracture, pore type, pore size distribution, porosity, permeability, and tortuosity were investigated in these different laminae types using FE-SEM, MICP and geochemical analysis. Combining the laminae characteristics and pore structure, we concluded that the organic pores and total pore area are mainly affected by the TOC content, whereas the development of the laminae controls the inorganic macropore scale and affects the pore size distribution. In addition, we found that the excessive development of shale laminae is not conducive to organic matter accumulation because of the change in redox condition, and because it has an adverse impact on the formation of complex artificial fractures during hydraulic fracturing. • Three laminae types were identified based on quantitative analysis. • Different laminae types show different pore structure characteristics. • Shale laminae influence the formation of natural fractures and artificial fractures. [ABSTRACT FROM AUTHOR]

Tectonism significantly affects the pore characteristics of organic-rich shales. Here, two sets of shales with similar mineral compositions and total organic carbon (TOC) content were used to evaluate the response of pore structure to tectonic deformation through gas adsorption, FE-SEM, and Nano-CT. The stable region shales have superior porosity, pore volume, pore diameter, surface porosity of organic matter (OM), and pore connectivity. However, the deformed region shales show obviously low storage space, pore size, and connectivity. The OM pores of the stable region shales were well preserved due to the support of residual overpressure in the closed shale system. The larger pore size and better pore connectivity enable gas molecule to be much easier to diffusion and flow, thus leading to high yield after hydraulic fracturing. Conversely, the OM pores of the deformed region shales are commonly compressed and even closed, because of the absence of overpressure-associated supporting mechanism in a relatively opened shale system. Shale gas is difficult to transport in this kind of shale reservoir with poor pore structure parameters, resulting in limited yield. Furthermore, our work also provides 3D pore deformation information of shale reservoirs under complex tectonic episodes. • Shale pores were quantitatively evaluated in 2D and 3D under different tectonic preservation condition. • Tectonic deformation influences the shale pore structure and connectivity. • Great preservation condition is beneficial to gas accumulation and engineering renovation. [ABSTRACT FROM AUTHOR]

The distribution and development of faults and fractures in organic-rich shales are important factors for the accumulation or loss of shale gas. In this work, merged three-dimensional seismic data, automated fault extraction, imaging logging, rock core examination, micro-CT scans, and field emission scanning electron microscopy were used to precisely characterize the distribution of faults and fractures of the Wufeng-Longmaxi shales from the Zilichang Block, Jiaoshiba area. The effects of faults and fractures on the accumulation and loss of shale gas were analyzed. The results show that the microfractures of shale samples from the JYA well of the Zilichang Block mainly consisted of intergranular, intragranular, and contraction fractures, and the fracture porosity of the samples is approximately 1.24%. These fractures help to increase the storage space of the shale reservoirs and are conducive for shale gas accumulation. In micro-CT scans, the microfractures were linked in a network-like structure and generally had excellent connectivity. Therefore, the microfractures could enhance the seepage capacity of the shale reservoirs and help the shale gas to migrate to hydraulically induced fractures. As a result, the productivity of the shale reservoirs could be dramatically improved. Macroscopic fractures were found to play a key role in the storage of shale gas. Many natural fractures, mainly are faults and open fractures, have developed in the caprock strata that directly overly the main production layers shales. The shale gas direct seal conditions are poor, which is not conducive to shale gas accumulation. Therefore, the Wufeng-Longmaxi shales in the JYA well is a relatively open shale system, with a formation pressure coefficient and gas saturation value of 0.96 and 37%, respectively. The single-well hydraulic fracturing productivity of the JYA well is low, with an absolute open flow value less than 0.5 × 104 m3/d. • Multiscale faults and fractures were identified. • Faults and macrofractures cause the loss of shale gas. • Microfractures enhance the seepage capacity of shale gas. [ABSTRACT FROM AUTHOR]