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Lithofacies and micropore characteristics of shale reservoir directly affect the exploration and development of natural gas. To determine the development potential of shales of the Longmaxi Formation in the Western Hunan‐Hubei Region, the lithofacies types and micropore structure characteristics of the Longmaxi Formation shales have been systematically studied in this paper, based on ordinary thin sections, argon ion polishing–scanning electron microscopy, physical property testing, x‐ray diffraction whole‐rock and clay mineral analysis, isothermal nitrogen, and carbon dioxide adsorptions. According to the principle of 'laminar structure + total organic carbon (TOC) + mineral composition of felsic, clay, and carbonate minerals', eight types of shale lithofacies were identified. The effective porosity of the Longmaxi shale ranges from 1.8% to 14.4%, with a peak range from 3% to 6%, while the permeability ranges from 0.001 to 1.27 mD, with an average of 0.106 mD. Combined with the isothermal adsorption experiments, the proportion of mesopores is the largest in the Longmaxi shale, followed by macropores and micropores. Moreover, the pore diameters of mesopores are concentrated between 3 and 10 nm, while those of micropores are concentrated between 0.4 and 0.9 nm. The pore volume of shale is most developed when the content of brittle felsic minerals is 50% ~ 75% and the content of clay minerals is 25% ~ 50%, and the TOC content is positively correlated with the pore volume and specific surface area. There are significant differences in the pore development characteristics of different lithofacies. The shale reservoir space analysis indicates that micropores are controlled by TOC content and clay minerals, while the macropores are controlled by depositional intergranular pores, TOC content, and felsic content, as well as diagenetic pyrite mould pores, microfractures pores, and intercrystalline pores. On the other hand, mesopores are related to a mix of depositional and diagenetic factors with dominant contribution of intergranular pores, intercrystalline pores, organic pores, and intergranular shrinkage fractures pores. It is found that the pore development of massive organic‐rich siliceous shale lithofacies has the best reservoir quality, including well‐connected intergranular pores, intercrystalline pores, organic pores, and shrinkage fractures. Therefore, the massive organic‐rich siliceous shale lithofacies is the dominant fine‐grained reservoir lithofacies in the studied area. Based on understating the pore characteristics of different lithofacies, this study can provide a scientific basis for the prediction of favourable sweet spots of shale gas reservoir in the Longmaxi Formation, western Hunan‐Hubei Region. [ABSTRACT FROM AUTHOR]

Southern China is affected by multi-stage tectonic activities, with strong fold deformation, complex fault systems and poor shale gas preservation conditions. Here, we used shale samples from the lower Silurian Longmaxi shale in the complex tectonic area of Southern China, to study the relationship between differential structural deformation, and pore structure and adsorption capacity. According to the deformation mechanism of the shale, it is further divided into brittle-slip rheological deformation (BD) and ductile-slip rheological deformation (DD). The results show that all micro-fractures can be observed under scanning electron microscopy in deformed shale samples, but in shale samples with different types of rheological deformation, the micro-fractures have large differences in scale, fracture length and lateral connectivity. The micro-fractures developed in DD shales are small in scale and short in fracture length, but have strong local connectivity. In contrast, brittle minerals are more developed in BD shales, and interlayer shearing has formed micro-fractures with large fracture length and good lateral connectivity, which is beneficial for later fracturing. In these two types of deformed shales, pores in organic matter are rare, and sporadic organic pores have small pore size and poor connectivity. The total pore volume (1.8–2.4 × 10−2 cm3 g–1) of BD shale samples is higher than that of DD shale samples (0.8–1.6 × 10−2 cm3 g–1). There is a positive correlation between total pore volume and quartz content. In addition, the specific surface area (12–18 m2 g–1) of DD shale samples is larger than that of BD shale samples (6–12 m2 g–1). [ABSTRACT FROM AUTHOR]

The mechanical properties and failure modes of shale that contains bedding were analyzed under coupled seepage pressure and stress. In the numerical model, seven sets of shale samples with different dip‐bedding values were considered, and a seepage‐stress coupling numerical simulation was carried out. The results showed that the compressive strength of shale exhibited obvious anisotropy with increase in the bedding angle, and the compressive strength decreased with an increase in the osmotic pressure. The elastic modulus of shale showed an increasing trend with increase in the bedding angle, while the osmotic pressure had little effect on the elastic modulus of shale. The results also showed that weak bedding had a significant impact on the shale failure mode. When the osmotic pressure was 4 MPa, the shale fracture mode showed five failure modes. When the osmotic pressure was 8 MPa, the shale fracture mode exhibited four failure modes. When the osmotic pressure was 12 MPa, the shale fracture mode showed four failure modes. As the osmotic pressure increased, the osmotic pressure played a leading role in the shale rupture process. The spatial distribution of the acoustic emission demonstrated some self‐similarity patterns, and its fractal characteristics were analyzed. It was found that the fractal dimension better reflects the rupture damage to the shale. The larger the fractal dimension is, the more severe the rupture of shale. [ABSTRACT FROM AUTHOR]

Natural fractures not only improve the physical properties of shale reservoirs but also promote the formation of hydraulic fracturing networks. The accurate identification of natural fractures in shale reservoirs is of a great significance to the exploration and development of shale gas. In this paper, the Lower Cambrian Niutitang Formation in Cen'gong block of northern Guizhou Province is taken as the research horizon. A variety of conventional logging parameters are selected to identify the natural fractures in the Niutitang Formation of three shale gas wells in the study area by combining R/S analysis method. Fracture locations can be accurately determined by calculating the second derivatives of lg(R/S) function. Considering the sensitivity of logging parameters to natural fractures, the analytic hierarchy process (AHP) is used to assign the corresponding weight to each logging parameter. A new parameter, fracture development coefficient, is introduced to quantitatively characterize the development degree of natural fractures. The results of R/S analysis are compared with those of core fracture observation and statistics. The results show that R/S analysis has a good effect on shale fracture identification, and the effect of fracture identification of three wells presents the following order: TM‐1 > TX‐1 > CY‐1. There is a positive correlation between fracture development coefficient and fracture linear density, indicating that the larger the fracture development coefficient is, the more developed the shale fractures are. Therefore, the fracture development coefficient can be used to characterize the degree of fracture development. In addition, we also analyze the errors of the identification results of R/S analysis and compare this method with conventional logging method. R/S analysis based on conventional logging is an accurate and efficient fracture identification method, which provides a new idea for the study and quantitative characterization of the natural fractures in shale reservoirs. [ABSTRACT FROM AUTHOR]

The existence of bedding in shale plays an important role in the physical properties and destruction processes of shale. In order to study the failure mechanism of shale with different dip angles under the coupling of seepage and stress, the study uses RFPA2D‐Flow software to advance the seepage‐stress coupling numerical simulation for seven groups of different bedding direction shale. Research shows that (1) the compressive strength and elastic modulus of shale are significantly affected by the bedding directions. The compressive strength can be observed with the apparent anisotropy of the shale compressive strength with the change of the bedding angle α; the elastic modulus increase with the increase in α as a whole. (2) The ultimate failure mode of shale under different bedding angles can be divided into V type (0°), inverted V type (15°), multi‐line type (30°), oblique type I (45°, 90°), and oblique N type (60°, 75°); the failure of shale in each group direction is mainly tensile failure with a small amount of shear failure. It can be found that the spatial distribution of acoustic emission (AE) reflected the macroscopic failure mode of shale. (3) The fractal dimension can well reflect the failure mode of the sample. From the trend of the dip‐fractal dimension curve, the fractal dimension of the multi‐line type reach to maximum, which is 1.41 699, and the D value of the oblique type I is the smallest, between 1.28 191 and 1.286 181. And the values of the inverted V type, V type and oblique N type, between 1.286 181 and 1.41 699. Therefore, the larger the value is, the more complex the shale failure mode is. [ABSTRACT FROM AUTHOR]

The Upper Ordovician Wufeng‐Lower Silurian Longmaxi shale is widely distributed in the Sichuan Basin and its periphery, which is the key stratum for marine shale gas exploration and development (E&D) in China. Based on sedimentary environment, material basis, storage space, fracability and reservoir evolution data, the reservoir characteristics of the Wufeng‐Longmaxi shale and their significance for shale gas EE&D are systematically compared and analyzed in this paper. The results show that (1) the depocenter of the Wufeng (WF)‐Longmaxi (LM) shale gradually migrates from east to west. The high‐quality shale reservoirs in the eastern Sichuan Basin are mainly siliceous shales, which are primarily distributed in the graptolite shale interval of WF2‐LM5. The high‐quality reservoirs in the southern Sichuan Basin are mainly calcareous‐siliceous and organic‐rich argillaceous shales, which are distributed in the graptolite shale interval of WF2‐LM7. (2) Deep shale gas (the burial depth >3500 m) in the Sichuan Basin has high‐ultrahigh pressure and superior physical properties. The organic‐rich siliceous, calcareous‐siliceous and organic‐rich argillaceous shales have suitable reservoir properties. The marginal area of the Sichuan Basin has a higher degree of pressure relief, which leads to the argillaceous and silty shales evolving into direct cap rocks with poor reservoir/good sealing capacity. (3) Combining shale gas exploration practices and impacts of lithofacies, depth, pressure coefficient and brittle‐ductile transition on the reservoir properties, it is concluded that the favorable depth interval of the Wufeng‐Longmaxi shale gas is 2200∼4000 m under current technical conditions. (4) Aiming at the differential reservoir properties of the Wufeng‐Longmaxi shale in the Sichuan Basin and its periphery, several suggestions for future research directions and EE&D of shale gas are formulated. [ABSTRACT FROM AUTHOR]

In this paper, the supercritical gas molecule adsorption characteristics of methane in shale are quantitatively described by using the lattice theory. The results show that the methane adsorption capacity predicted by this theory is high, with the average absolute error 0.003 3 mmol·g−1. There is a near-linear positive relationship between the adsorption potential between methane and the solid surface (ϵs) and the experimental temperature. The value of the average potential between the adsorbate molecules (ϵa) is distributed in −0.841–1.791 kJ·mol−1, and the absolute value of ϵais significantly smaller than the absolute value of ϵs, indicats that the potential energy between the adsorbate molecules is significantly smaller than that between the adsorbate molecules and the pore surface of shale. When the temperature is relatively low (T= 308.55 K), the value of ϵs/ϵais 7.5 times; with the increases of the temperature, the magnification will gradually decrease and keep stabilize (3.37 times). [ABSTRACT FROM PUBLISHER]

We identified the sources of quartz in shales of the Niutitang Formation in the Cen'gong block, northern Guizhou Province, China, based on thin-section studies using a scanning electron microscope (SEM), rock cores and field observations. By analyzing the petrology, total organic carbon (TOC), major elements, and illite “crystallinity”, we investigated the formation of silica in the Niutitang shales. Our results show that the quartz in the Niutitang shales consists mainly of detrital quartz, biogenic quartz, and quartz that transformed from clay minerals. The amount of excess SiO 2 in the Niutitang shales was approximately 5–35%, and the Al/(Fe + Al + Mn) and Si/(Si + Al + Fe) ratios ranged from 0.45 to 0.85 and from 0.7 to 0.91, respectively, which indicates that the silica was not solely biogenic. The values of excess SiO 2 , Al/(Fe + Al + Mn), Si/(Si + Al + Fe), and TOC increased with increasing quartz content, which implies that increasing quartz concentrations were associated with gradual increases in biogenic quartz and decreases in detrital quartz. Quartz from different sources can result in varying rock geomechanical properties and fracture abundance. Compared with pure biogenic quartz or detrital quartz, an appropriate proportion of mixed biogenic quartz and detrital quartz can make rocks more brittle and therefore lead to more fractures. [ABSTRACT FROM AUTHOR]

The Bianmachong Formation above the Niutitang Formation in the Lower Cambrian of South China, which was mainly deposited in a marine and transitional environment, has highly brittle characteristics and is an important shale layer for shale gas exploration, but the current level of exploration is low. This paper discusses in depth the development characteristics and dominant factors of fractures and their significance for the shale reservoir in Є 1 b 2 (middle member of the Bianmachong Formation of lower Cambrian) of the Cen'gong block in Guizhou Province based on the observations of outcrops, cores, polished thin sections and scanning electron microscope chips, as well as statistics on the fracture characteristic parameters and a test data analysis of corresponding samples. The results show that overlaps of organic-rich shale and tight sandstone vertically have created favorable generation conditions for shale gas and tight sandstone gas in Є 1 b 2 shale. Є 1 b 2 shale has similar sedimentary environment, mineral composition and organic type as American marine shale but exhibits differences in terms of the abundance of organic matter and degree of thermal evolution. The TOC content of Є 1 b 2 shale is mainly 1–2% and over-maturation. Multiple types and periods of fractures are abundant in Є 1 b 2 shale. They are mainly structural fractures, such as high dip-angle shear, bedding, tension-shear, interlayer and slip fractures. The micro fractures are mainly interlayer fractures, grain boundary fractures and organic matter contraction fractures. Structure is one of dominant factors for the fractures development, but others also have a strong correlativity, such as the lithology, abundance of organic matter, formation thickness, mechanical properties and mineral content. Under the same structural background, the content of brittle minerals such as feldspar, pyrite and quartz is higher. The brittleness is higher in shale, and more fractures are generated, which contributes to reservoir heterogeneity. The TOC content of Є 1 b 2 shale has positive correlations with the content of quartz and the total gas content, which is also positively correlated with fracture development in the cores, and the source of organic matter is siliceous organisms. For over-maturation and organic-rich shale, a high TOC content and a high silica content are beneficial for micro pores and fractures to be preserved. In addition, the fracture development is positively correlated with the total and free gas contents in Є 1 b 2 shale. Micro pores and fractures exist in internal minerals, such as calcite, quartz, and pyrite, as well as in their intervals with fracture surfaces, which reduce the capacity of fractures to resist tension and shear. The fractures are prone to rupture again. In addition, filled fractures make a greater contribution to the reservoir space of Є 1 b 2 shale through dissolution. [ABSTRACT FROM AUTHOR]

Reservoirs where tectonic fractures significantly impact fluid flow are widespread. Industrial-level shale gas production has been established from the Lower Cambrian Niutitang Formation in the Cen'gong block, South China; the practice of exploration and development of shale gas in the Cen'gong block shows that the abundance of gas in different layers and wells is closely related to the degree of development of fractures. In this study, the data obtained from outcrop, cores, and logs were used to determine the developmental characteristics of such tectonic fractures. By doing an analysis of structural evolution, acoustic emission, burial history, logging evaluation, seismic inversion, and rock mechanics tests, 3-D heterogeneous geomechanical models were established by using a finite element method (FEM) stress analysis approach to simulate paleotectonic stress fields during the Late Hercynian—Early Indo-Chinese and Middle-Late Yanshanian periods. The effects of faulting, folding, and variations of mechanical parameters on the development of fractures could then be identified. A fracture density calculation model was established to determine the quantitative development of fractures in different stages and layers. Favorable areas for shale gas exploration were determined by examining the relationship between fracture density and gas content of three wells. The simulation results indicate the magnitude of minimum principal stress during the Late Hercynian — Early Indo-Chinese period within the Cen'gong block is −100 ∼ −110 MPa with a direction of SE-NW (140°–320°), and the magnitude of the maximum principal stress during the Middle-Late Yanshanian period within the Cen'gong block is 150–170 MPa with a direction of NNW-SSE (345°–165°). During the Late Hercynian — Early Indo-Chinese period, the mechanical parameters and faults play an important role in the development of fractures, and fractures at the downthrown side of the fault are more developed than those at the uplifted side; folding plays an important role in the development of fractures in the Middle-Late Yanshanian period, and faulting is a secondary control. This 3-D heterogeneous geomechanical modelling method and fracture density calculation modelling are not only significant for prediction of shale fractures in complex structural areas, but also have a practical significance for the prediction of other reservoir fractures. [ABSTRACT FROM AUTHOR]