The interaction process among hydraulic fractures and natural fractures, bedding planes, and other discontinuities during shale fracturing determines the complexity of the fracture network that is formed. However, the current conclusions and understanding of the mechanisms underlying the interaction between hydraulic and natural fractures, as well as their primary controlling factors, fail to meet the requirements of hydraulic fracturing operations, thereby restricting the efficient development of shale gas resources. Therefore, in this study, a coupled thermal‒hydraulic‒mechanical finite element numerical model that is based on the maximum tensile stress and the Mohr‒Coulomb criterion is established, thereby considering rock deformation, fluid flow, and heat transfer. The reliability of this model is validated on the basis of previous research. This model is subsequently employed to simulate the propagation behavior of hydraulic fractures in shale with well-developed bedding. The results indicate that when hydraulic fractures propagate to the bedding, five propagation modes may occur: arrest, diversion, diversion and crossing, crossing and diversion, and direct crossing. These modes are controlled by factors such as the mechanical properties of the shale matrix and bedding, geostress, bedding dip angle, temperature, and fracturing fluid injection rate. During fracture propagation, increases in the elastic modulus ratio between the rock matrix and the bedding, the bedding dip angle, and the temperature are favorable for hydraulic fractures turning along the bedding, whereas increases in the difference in vertical stress and the injection rate are favorable for hydraulic fractures directly crossing the bedding. Second, on the basis of four influencing factors, namely, the shale matrix and bedding elastic modulus ratio, bedding dip angle, difference in vertical stress, and temperature, propagation criteria for hydraulic fractures along the bedding under various combinations of influencing factors are established. The results provide theoretical reference data for the design and optimization of fracturing in shale with well-developed bedding.

Despite significant exploration breakthroughs, the exploration potential and targets of the Permian shale gas in the Yangtze region, South China remain poorly understood due to factors such as complex sedimentary facies variation, differentiated source rock-reservoir combination conditions, and varying tectonic activity-induced preservation conditions. A systematic investigation of the characteristics and distribution, exploration potential, and preservation conditions of the Permian shale sequences, proposes the exploration prospects and targets of the Permian shale gas in the Yangtze region. The results indicate that the studied Permian shales in the Yangtze region are of two types, namely the marine and marine-continental transitional shales, which comprise three suites of organic-rich shales, i. e., the Gufeng, Longtan (Wujiaping), and Dalong formations. The shale distribution is governed by the continental-margin (intracontinental) rift basins and intracratonic depression basins. Specifically, the marine-continental transitional shales of the Longtan Formation are mainly seen in the intracratonic depression basins in the western and southeastern parts of the Yangtze region, while the marine shales of the Gufeng (Wujiaping) and Dalong formations occur predominantly in the continental-margin (intracontinental) rift basins along the northern margin of the Yangtze region. The marine shales exhibit high brittle mineral content, high total organic carbon (TOC) content, well-developed organic pores, and high gas content. In contrast, the marine-continental transitional shales show high TOC content, moderate thermal evolution, well-developed inorganic pores, and generally low, highly variable gas content. Tectonic activities and associated preservation conditions represent critical factors controlling the exploration potential of the Permian shale gas in the Yangtze region. Areas with weak tectonic deformations, such as the western Hubei Province and the Sichuan, Jianghan, and Subei basins, exhibit favorable preservation conditions, thus holding considerable exploration potential. To address geological engineering challenges and accelerate the exploration and production of the Permian shale gas in the Yangtze region, it is recommended to intensify research on fine-grained sedimentary facies zone delineation, dynamic evolutionary patterns of shale gas enrichment, comprehensive evaluation metrics for shale gas preservation conditions, and adaptive technical systems for reservoir stimulation.

Strong tectonic activities and diagenetic evolution encourage the development of natural fractures as typical features in deep tight sandstone reservoirs of foreland thrust belts. This study focused on the Jurassic in the southern Junggar Basin to comprehensively analyze the fracture characteristics and differential distribution and, ultimately, addressed the controlling mechanisms of tectonism and diagenesis on fracture effectiveness. Results revealed that the intensity of tectonic activities determines the complexity of tectonic fracture systems to create various fracture orientations when they have been stronger. The intense tectonic deformation would impact the stratum occurrence, which results in a wide range of fracture dip angles. Moreover, as the intensity of tectonic activities and deformations weakens, the scale and degree of tectonic fractures would decrease continuously. The control of tectonism on fracture effectiveness is reflected in the notable variations in the filling of multiple group fractures developed during different tectonic activity periods. Fractures formed in the early stages are more likely to be filled with minerals, causing their effectiveness to deteriorate significantly. Additionally, the strong cementation in the diagenetic evolution can cause more fractures to be filled with minerals and become barriers to fluid flow, which is detrimental to fracture effectiveness. However, dissolution is beneficial in improving their effectiveness by increasing fracture aperture and their connectivity to the pores. These insights can refine the development pattern of natural fractures and contribute to revealing the evolutionary mechanisms of fracture effectiveness in deep tight sandstone reservoirs of foreland thrust belts.

Lacustrine shale oil reservoirs of the Upper Triassic Chang 7 Member in the Ordos Basin have demonstrated significant potential for hydrocarbon resources. Natural fractures play a crucial role in hydrocarbon enrichment and production. Outcrops, cores, borehole image logs, thin sections, and FE-SEM images were used to investigate the types and characteristics of natural fractures in the Chang 7 Member. The factors controlling fracture development and the mechanisms of bedding-parallel fracture formation were revealed by integrating TOC analysis, XRD analysis, and rock pyrolysis. Results show that natural fractures in the study area include high-angle tectonic fractures and nearly horizontal bedding-parallel fractures. Brittle minerals and bed thickness control the occurrence and attributes of tectonic fractures. High TOC content and thermal maturity positively affect the development of bedding-parallel fractures, formed through the conversion of organic matter to hydrocarbons or the smectite-to-illite transformation. Additionally, the dominant orientations of tectonic fractures intersect the present-day maximum horizontal principal stress at a small angle, resulting in large apertures and good effectiveness. Bedding-parallel fractures contribute to enhance porosity and provide favorable pathways for lateral hydrocarbon migration. Collectively, this study could provide valuable insights for finding promising exploration areas in lacustrine shale oil reservoirs in the Ordos Basin and worldwide.

Large-scale organic-rich shales are usually formed in saline basins rather than freshwater basins. However, the Ordos Basin, as a typical freshwater lacustrine basin, has a maximum total organic carbon content (TOC) of 30 % in its Triassic Chang 7 Member shale, way above the average TOC content of shales in saline basins, leaving the main controlling factors a hot topic for discussion. The multiple tuff layers occurred frequently in high TOC sections of the member indicate intense volcanic events and a subtle connection between the events and the high TOC value. Analysis of main and trace elements of the shale confirms the impact of volcanic events as indicated by the relatively higher content of elements enriched in clay minerals like Al and K, of elements as proxy of paleo-productivity and reducing environment including Ni, Cr and V, as well as of high field strength elements (Zr, Th, and Hf). The upper parts of these tuff are even richer in organic matter with increasing hydrocarbon generation intensity that indicates the elevated paleoproductivity. There are trends of Fe_HR/Fe_T ≥ 0.38 and Fe_py/Fe_HR ≤ 0.8 in organic-rich shale but with Fe_py/Fe_HR up to 0.8 with the increase of TOC. The (EF_Mo/EF_U) (auth) ratios is 1-3 when the TOC is greater than 6 %. Both the iron speciation and (EF_Mo/EF_U) (auth) ratios indicate that there was an euxinic environment for Mo and Fepy enrichment, but the sulfate reduction strength was low (SRI ≤ 1.375). In summary, the input of volcanic materials and inorganic elements into the freshwater increased paleoproductivity and promoted the formation of a reducing environment. This is favorable for the organic-rich matter accumulation and preservation. The upper shales of the tuff-bearing section are suggested to be one of the key targets for future exploration and development in the basin.

The abundance of organic matter and the types of shale laminae are the key in shale oil exploration. The sedimentary facies of terrestrial shales features complex variation and strong heterogeneity, making accurate identification of deposition rate facing more challenges. The deposition rates of organic-rich shales in typical terrestrial basins of China are mostly above 5 cm/kyr, and those of the organic-rich shales in saline lacustrine basins may reach up to 40 cm/kyr. The high-precision chronostratigraphic framework combined with the statistical tuning of cyclostratigraphy can trace the variation of deposition rate with burial depth. The relative deposition rate of shales can be determined by the rare earth element (REE) assemblage pattern, crystal size distribution, and the abundance of typical interstellar dust elements, etc. Comparison of deposition rates of different types or ages of stratigraphic sequences has to take perturbations such as stratigraphic integrity and differential compaction into consideration. Deposition rate is an important factor influencing the enrichment of organic matter in shale, and the critical threshold for organic matter dilution by deposition rate is usually less than 5 cm/kyr. The flocculation of sediment particles is usually under the effect of hydrodynamic conditions and water salinity, and the various deposition rates for different types of fine-grained sediment are conducive to the formation of shale laminae. The study of deposition rate requires an integration of advanced theories and methods, including geochronology, petrology, cyclostratigraphy, geochemistry, and physical simulation of sedimentation, to gain a deeper understanding of the mechanisms of shale deposition and evolution. Revealing the interrelationship between terrestrial shale deposition rate and shale oil accumulation is of certain guiding significance to shale oil exploration.

Rock-Eval pyrolysis has been widely used in assessing source rocks from the very beginning. Although this approach can evaluate oil content, hydrocarbon generation, as well as the abundance, type, and thermal maturity of organic matter in a simple and rapid way, it is noteworthy that this technique has some limitations in application, and improper interpretation of pyrolytic data may bring more risks to shale oil/gas exploration. This study summarizes three main pitfalls commonly seen in previous publications based on massive experimental results. First, the use of hydrogen index (HI), oxygen index (OI), the temperature of maximum pyrolysis yields (T_max), and the ratio of S₂/S₃ to discriminate kerogen of diverse types should target source rocks with maturity less than 1.35 % R_o; the feasibility of the technique to highly-to-overmature source rock samples is limited. Second, the validity of T_max depends on the area of S₂ and whether it is in normal distribution, and the accuracy of T_max relies on kerogen type and thermal maturity; moreover, residual hydrocarbon and pyrite content have some effects on the accuracy of T_max. To obtain accurate T_max values, the maturity of source rocks of types Ⅰ, Ⅱ, and Ⅲ should not be larger than 1.70 % R_o. Third, the oil saturation index (OSI) has been used to indicate the mobility of shale oil, and a value larger than 100 mg/g TOC suggests sweet spots of shale oil. However, it should be noted that OSI could not directly provide information on the saturation of oil in shale. OSI values are generally smaller than 100 if the rocks are very organic-rich, and a small TOC value could also lead to a large OSI value (more than 100 mg HC/g TOC). Besides, only a few shales bear OSI higher than 100 mg HC/g TOC, although many of the shales have been proven commercially successful. Therefore, the applicability of OSI larger than 100 mg HC/g TOC as a parameter for shale oil mobility merits further consideration. We suggest using individual OSI criteria for different types of sedimentary basins and shale formations. Moreover, the loss of light hydrocarbons during the storage and preparation of rock samples is strongly dependent on rock lithofacies, and thus, classified assessment should be adopted for shale oil reservoirs of multiple lithofacies.

China has significant potential for the exploration of lacustrine shale oil, which serves as an important alternative resource for conventional oil and gas. However, the development and recovery of lacustrine shale oil face significant constraints due to the lack of fundamental research, unclear mechanisms of its formation and accumulation, and the absence of standardized criteria for evaluating “sweet spots”. To address these issues, the authors proposed a set of simplified standards for lacustrine shale oil classification, taking into account previous research and the practical conditions of exploration and development. Based on the storage space and type of reservoir rocks, shale oil reservoirs are commonly classified into three major types, namely interbedded sand-shale, fractured shale, and pure shale, with the last type being taken as the focus of discussion in this paper. The pure shale type can be classified into laminated, bedded and massive shale oil reservoirs based on the sedimentary structure. Although the grain size was not taken as one of the parameters for shale oil classification, we kept the traditional three terminal element category and mixed category of minerals, and removed further subdivided subcategories; the Rock-Eval S₁ was used instead of TOC and R_o to divide shale oil reservoirs into three types: low oil content, medium oil content and high oil content; the formation pressure coefficient less than 0. 8 is defined as abnormally low pressure, 0. 8 ~ 1. 2 is classified as normal pressure, and greater than 1. 2 is classified as abnormally high pressure; the crude oil viscosity is not involved in the classification of shale oil reservoir types. In addition, this study designated type Ⅰ, Ⅱ and Ⅲ sweet spots, and discussed the representative types of shale oil reservoirs in typical continental basins in China. This paper enhances our understanding of the assessment standards, the type of rocks and the distribution of “sweet spots” in shale oil reservoirs. As a result, this research contributes to the advancement of shale oil exploration and development, providing valuable insights for future endeavors in this field.

To reveal the mechanical properties and microfracturing mechanisms of shales, we investigate shales in the Silurian Longmaxi Formation in the southern Sichuan Basin using X-ray diffraction (XRD) analysis, together with triaxial compression, micro-computed tomography (micro-CT) and scanning electron microscopy (SEM) tests. The results indicate that the mechanical properties and reservoir physical properties of shale are significantly influenced by its mineral composition and confining pressure. Specifically, an increase in the brittle mineral content enhances its elastic modulus and peak stress, indicating positive correlations between these mechanical properties and the brittle mineral content. In contrast, higher clay mineral content increases the shale plasticity while reducing its rock strength. As confining pressure increases, fractures in the shale gradually close, and the pores deform and contract, leading to reduced porosity. A higher confining pressure results in greater compression. Two dominant types of fractures form during shale damage: boundary fractures occurring at interfaces between mineral grains and internal fractures occurring within grains. For shales with similar mechanical properties, increasing confining pressure shifts their dominant fracture type from boundary to internal fractures. Additionally, higher confining pressure causes the boundary and internal fractures to evolve into fracture zones, leading to an increased fracture density in the shale.

The lacustrine shale oil reservoirs of the Fengcheng Formation in the Mahu Sag, Junggar Basin have burial depths exceeding 4 500 m.Natural fractures in these reservoirs, serving as important storage spaces and seepage channels, are critical to the enrichment and high yield of shale oil. There is a lack of systematic study on their effectiveness evaluation despite existing characterization of these fractures in previous works, severely restricting the further exploration and exploitation of shale oil in the Mahu Sag. Given this, we conduct a systematic study on the distribution patterns and effectiveness evaluation of natural fractures in the study area using formation microresistivity imaging (FMI) logs. The results indicate that there exist two types of natural fractures in the lacustrine shale oil reservoirs in the study area: cross-layer fractures and intralayer fractures. The cross-layer fractures are characterized by a large scale, with heights generally reaching up to several meters or above, and their distribution is governed by faulting. The intralayer fractures are found within brittle beds, and their heights are limited by the thickness of rock layers, largely less than 50 cm. Vertically, the fracture density in a single well is positively correlated with the brittle mineral content. Laterally, the fracture density gradually decreases with increasing distance from faults. Fractures with different orientations exhibit greatly varying degrees of filling. The NW-SE-trending fractures, among others, are mostly not filled with minerals, thus boasting high effectiveness. As the burial depth increases, fracture apertures generally trend downward. The evaluation results reveal that the NEE-SWW-trending fractures exhibit the largest aperture and, accordingly, the highest effectiveness.