A systematic comparative analysis of shale reservoir characteristics of the Wufeng-Longmaxi (O₃ w-S₁ l) and Niutitang (Є₁ n) Formations in southeastern Sichuan Basin and its neighboring areas was conducted with respect to mineralogy, organic geochemistry, pore structure, methane sorption, brittleness, and fractures. Results indicate that (1) organic matter (OM)-hosted pores that are hundreds of nanometers to micrometers in size in the Longmaxi shale are well-developed in migrated OM rather than in the in situ OM, and they are the dominant reservoir spaces. Furthermore, the total organic carbon (TOC), brittleness, organic pores, and bedding fractures have good synergistic development relationships. However, there are fewer OM-hosted pores in the Niutitang shale; they are smaller in size, usually less than 30 nm, and have a more complicated pore structure. The intergranular pores in cataclastic organic-inorganic mineral fragments are the dominant reservoir spaces in the Niutitang shale and are coupled with stronger methane sorption and desorption capacities. (2) The piecewise correlation between TOC and brittleness indicates the significant differences in pore and fracture characteristics. When the TOC [ ], the TOC, brittleness, organic/inorganic pores, and fractures synergistically develop; when the TOC [ ], even though the increase in ductility reduces the number of fractures, the lower cohesive strength, internal friction angle, and weaker surfaces of interlayer fractures and cataclastic minerals promote the development of slip fractures, which significantly improves the fracture effectiveness and reservoir spaces for free and absorbed shale gas. (3) The Longmaxi, Wufeng, and Niutitang shales formed and evolved in different evolutionary stages. With the evolution of hydrocarbon generation, diagenesis, tectonic deformation, and pressure, the size and proportion of OM-hosted pores gradually decrease. At the same time, the complexity of the pore-fracture structure, the methane adsorption/desorption capacity, and the proportion of inorganic pores and fractures increase.

Typical unconventional gas/liquid plays of China were studied using field-emission/focused ion beam scanning electron microscopy (SEM) for clay mineralogy and microstructural development. The SEM microstructural investigations of clay-rich shale and mudstone reservoirs provided significant information about clay mineral type, size, distribution and aggregates, which allows for interpretations regarding porosity preservation and petrophysical variability. The major clay-hosted porosity types are interparticle clay pores, intraparticle clay pores and aggregate pores. Interparticle clay pores occur in open spaces of the clay aggregates and include four subtypes: (1) elongated pores, (2) packed pores, (3) jagged pores and (4) card-house pores. Intraparticle clay pores are present within clay particles and have mostly secondary origin. These pores are diagenesis dependent and are restricted to secondary illite particles during the transformation of clay minerals from smectite to illite. Intraparticle clay pores constitute only isolated porosity and could not contribute to hydrocarbon molecule storage and migration. Aggregate pores were predominantly encountered in association with organic–clay and pyrite–clay aggregates. In places, organic–pyrite–clay aggregates can also display polymerization, but they do not contribute significantly to overall porosity and permeability. Combining SEM morphological analyses with the software ImageJ is critical in clay microstructure and porosity analyses via semi-quantitative characterization of the 3D pore surface, 2D pore profile, pore quantity, pore size, areal porosity, etc. These visual and semi-quantitative results highlight the significance of jagged pores and pyrite–clay aggregate pores in shale gas/liquid reservoirs because they may be important facilitators of gas storage and transmission.

This study systematically analyzes reservoir formation mechanisms under deep burial conditions, integrating macroscopic observations from representative ultra-deep clastic reservoirs in four major sedimentary basins in central and western China. Developing effective clastic reservoirs in ultra-deep strata (6000–8000 m) remains a critical yet debated topic in petroleum geology. Recent advances in exploration techniques and geological understanding have challenged conventional views, confirming the presence of viable clastic reservoirs at such depths. Findings reveal that reservoir quality in ultra-deep strata is preserved and enhanced through the interplay of sedimentary, diagenetic, and tectonic processes. Key controlling factors include (1) high-energy depositional environments promoting primary porosity development, (2) proximity to hydrocarbon source rocks enabling multi-phase hydrocarbon charging, (3) overpressure and low geothermal gradients reducing cementation and compaction, and (4) late-stage tectonic fracturing that significantly improves permeability. Additionally, dissolution porosity and fracture networks formed during diagenetic and tectonic evolution collectively enhance reservoir potential. The identification of favorable reservoir zones under the sedimentation–diagenesis-tectonics model provides critical insights for future hydrocarbon exploration in ultra-deep clastic sequences.

As an unconventional oil and gas reservoir, the diagenesis and evolution of continental shale controls the formation and occurrence of inorganic and organic pores. In order to quantitatively characterize the pore characteristics of a continental shale reservoir and their influence on the evolution of the diagenesis stage, the characteristics of organic and inorganic pore types of continental shale in the Da’anzhai section of the lower Jurassic Ziliujing Formation were identified by means of X-ray diffraction mineral composition analysis and argon ion polishing scanning electron microscope measurements and observations, and the influence control of the diagenesis stage on the pore development of the continental shale reservoir and its control were clarified. The results show the following: ① The organic matter pores in continental shale are developed in large quantities, including organic matter pores in the mineral asphalt matrix and organic matter pores in the kerogen; the pore types of inorganic minerals are very rich, the main pore types are linear pores between clay minerals, intergranular (intergranular) pores, and intragranular corrosion pores, and microcracks are also developed. ② When affected by compaction diagenesis, the inorganic pores of continental shale decrease with an increase in the burial depth and diagenesis degree. ③ The burial depth of continental shale is 2000–3000 m in the middle of diagenetic stage A, and a large number of organic matter pores and dissolved inorganic pores develop at this depth, meaning that the total porosity of shale increases significantly. The burial depth of continental shale is 3000–4000 m at diagenetic stage B, where kaolinite and other clay minerals are dehydrated and converted into illite, the brittleness of shale is increased, and the interior of the shale is subject to external stress, causing microcracks to form. In the late diagenetic stage, when the buried depth of the continental shale is more than 4000 m, the organic matter is subject to secondary cracking and hydrocarbon generation, the organic pores of shale increase in number again, and the inorganic pores decrease in number due to compaction. In conclusion, we found that the burial depth is the main control factor for the development of pores and microfractures in continental shale reservoirs; diagenesis caused by burial depth is the main factor affecting the development of pores and microfractures in continental shale reservoirs; and the shale burial depth in this case is more than 3500 m, which is in the middle of diagenetic stage B. Inorganic porosity in shale is reduced, and the number of microfractures is increased. When the shale is buried more than 4000 m deep in the late diagenetic stage, the thermal evolution of organic matter in shale is high, and methane gas is generated in large quantities, which is conducive to the formation and development of organic matter pores in continental shale.

Characterization of pore structure and heterogeneity is crucial for exploring and evaluating shale oil and gas resources. Existing methodologies exhibit various limitations, and intuitive, quantitative description techniques are lacking. To address these issues, shales from the second member of the Funing Formation (E₁f₂) in the Subei Basin were studied in this study. A comprehensive research methodology was employed that combined petrological analysis, physical structure testing, and SEM images supplemented with multifractal analysis and partial least squares regression (PLSR) data processing to achieve nuanced qualitative and quantitative characterization of the heterogeneity in lacustrine shale pore structures. This study revealed that E₁f₂ shale pores predominantly consist of mesopores (2–50 nm) and macropores (>50 nm). A positive correlation was observed between the development of mesopores and calcite content, while a negative correlation exists with orthoclase content. Conversely, a positive correlation with plagioclase content was found in macropore development. The growth in total pore volume is inhibited by the total organic carbon (TOC) content. Employing multifractal methods to analyze pore morphology data extracted from scanning electron microscopy (SEM) images facilitated a quantitative characterization of the heterogeneity within the pore structures. The results showed that organic-medium mixed shale (OMMS) has the strongest heterogeneity. The weakest heterogeneity is exhibited by the organic-medium calcareous shale (OMCS). PLSR analysis indicates that the structural heterogeneity of the E₁f₂ shales is positively correlated with TOC content and negatively correlated with orthoclase content. Additionally, the type of pore influences the degree of heterogeneity. Increasing the total and macropore volume reduces the heterogeneity, while increasing the micropore (<2 nm) volume enhances it in the E₁f₂ shales.

Nanopores in shale are critical controls on shale gas storage and transport, and their formation, transformation, and preservation during geological evolution have long been major research topics in unconventional oil and gas geology. Considerable progress has been made in understanding the evolution of shale nanopore structures during sedimentation, diagenesis, and hydrocarbon generation from organic matter. However, the modification of shale nanopores by tectonic stress and the underlying mechanisms remain insufficiently understood. Organic-rich shale formations in South China commonly serve as regionally important detachment layers and have undergone multiple phases of tectonic activity involving diverse deformation mechanisms. Repeated and intense modification of their primary structures has resulted in exploration risks associated with low $in-situ$ gas contents and complex preservation conditions. This study systematically analyzes the multiscale structural deformation of shale during tectonic deformation and investigates the intrinsic relationships and mechanisms linking tectonic deformation to the evolution of shale nanopore structures. Physical simulation experiments for shale deformation and experimental techniques for the high-resolution characterization of shale nanopore structures are also reviewed. The findings provide a scientific basis for marine shale gas exploration in tectonically complex areas surrounding the Sichuan Basin.