Hydrocarbon exploration and exploitation have progressively shifted toward 10000-meter-deep onshore plays, 1000-meter-deep offshore plays, unconventional plays, and residual oil in mature oilfields. The emerging frontiers are characterized by diverse reservoir types, complex geological conditions, and considerable difficulties in exploration and development, posing challenges such as incompatibilities between existing methodological and technical systems and exploration and exploitation targets to research on well logging geology. This study presents a summary of the evolution of research on well logging geology in terms of depth, scale, span, and dimension for hydrocarbon exploration and exploitation. The results indicate that logging geology research is gradually advancing towards in-depth interdisciplinary integration and multidimensional development. The integration of geology, logging, seismology, engineering, and artificial intelligence (AI) can enhance the efficiency of hydrocarbon exploration and exploitation while reducing costs and risks. In the development of deep to ultra-deep onshore plays at depths of about 10000 m, the combination of logging and geology allows revealing the genetic mechanisms of reservoirs and analyzing major factors controlling reservoir quality, thereby achieving a comprehensive reservoir evaluation. For unconventional hydrocarbon reservoirs, research on well logging geology enables the identification of the geological characteristics of millimeter-scale laminae, as well as analyses of subtle variations in oil-bearing properties and oil mobility within micro- to nano-scale pore throats. On the spatial scale, logging technology allows for the detection of wellbores, near-well areas, and far-well regions, achieving the characterization of point-line-plane-volume full-space geological information. On the temporal scale, logging technology enables the analysis of changes in log data before and after fracturing or water injection, thus contributing to fine-scale hydrocarbon development. Driven by AI empowerment, the future integration of multidisciplinary dimensions, that is, geology, well logging, seismology, and engineering, will further expand the application domains and scope of well logging geology, accelerating its development. This will offer robust technical support for future hydrocarbon exploration and exploitation.

China's lacustrine shale oil reserves are abundant, making it a key area for future exploration and development. Most lacustrine shales feature a mix of mineral compositions and interlayer sedimentary structures. High-quality reservoirs exhibit significant heterogeneity, which influences the stress distribution during fracturing, leading to complex fracture network patterns. This complexity presents challenges for the comprehensive well logging evaluation of the geological-engineering "double sweet spots" in shale oil, severely restricting efficient development. This study focuses on the impact of shale sedimentary layering on the radial slowness of dipole shear waves. It employs rock physics experiments combined with advanced well logging techniques to explore the relationship between reservoir anisotropy caused by sedimentary layering and reservoir quality, thereby establishing a logging evaluation method for vertical identification of "sweet spots" in lacustrine shale oil. The shales in the Fengcheng Formation of the Mahu Sag into three types according to sedimentary structure scale: laminated, interlayer, and massive. Each type has different mineral compositions, affecting reservoir quality and fracturing potential. Laminated shales develop more fractures under stress along the beddings, showing moderate anisotropy, with reservoir capacity dependent on intercrystalline porosity within carbonate layers. Interlayer shales easily form complex fracture networks, exhibiting significant anisotropy, and their reservoir capacity depends on the porosity within sandy bands. Massive mudstones have the fewest fractures under stress, appearing isotropic with reservoir capacity dependent on matrix pore size. The intensity of reservoir anisotropy correlates positively with storage capacity and the propensity to form irregular and complex fracture networks during hydraulic fracturing. In sections without natural fractures, a larger difference between fast and slow shear waves corresponds to a radial profile shift towards warm tones, indicating stronger anisotropy and better reservoir quality, thus forming complex fracture networks during fracturing. Conversely, a smaller difference leads to a profile energy shift towards cooler tones, indicating stronger isotropy and poorer reservoir quality, hindering the formation of complex fracture networks during hydraulic fracturing. In sections with natural fractures, the difference between fast and slow shear waves exhibits erratic behavior, showing a cross-pattern in radial profiles, indicating strong anisotropy. The presence of natural fractures can synergize with induced fracture networks to form more complex systems, significantly enhancing reservoir productivity.

Research of the in-situ stress field can provide theoretical guidance and technical support in well design, fracture stimulation of wells and fracture effectiveness evaluation. It is crucial to summarize the in-situ stress field analysis and related loging evaluation methods. The study summarizes the components of in-situ stress field and its well-logging response mechanism, and presents the log suite consisting of sonic transit time, resistivity and image logs as the most sensitive to in-situ stress responses. The time and magnitude of paleotectonic stress field can be determined by acoustic emission experiment. The maximum paleotectonic stress magnitude can be recovered by using resistivity log, sonic transit time log and fracture density. The in-situ stress field can be described in respect of orientation and magnitude. The orientation of in-situ stress field can be determined by using the image logs to pick up borehole breakouts and induced fractures, and the array acoustic logs to derive shear wave splitting. The magnitude of the in-situ stress field can be determined through hydraulic fracturing combined with acoustic emission experiment. The in-situ stress can be calculated through models or methods including the combined spring model built on the in-situ stress field description, realizing in-situ stress field analysis. The analytical results can better help analyze fault properties, evaluate reservoir quality and fracture effectiveness, predict reservoir distribution, as well as be of practical value to the engineering fields like hydraulic fracturing of unconventional hydrocarbon reservoirs.

The northern structural belt of Kuqa Depression is adjacent to the South Tianshan orogenic belt, which are characterized by complex geological conditions. The reservoir quality of the Jurassic Ahe Formation is controlled by sedimentation, diagenesis, and tectonics, and show complex pore structure and strong heterogeneity, thereby hindering effective natural gas exploration and development. Core, thin sections, cathodoluminescence (CL), scanning electron microscopy (SEM), conventional well logs and image logs are used to characterize the petrological characteristics and pore systems. Then a comprehensive analysis integrating sedimentation, diagenesis, and tectonics is performed to unravel the reservoir formation mechanism and distribution of reservoir quality. Results show that reservoir properties are generally environmentally selective. Coarse grained sandbodies (gravelly sandstones) formed in high depositional-energy have the best physical properties, while fine sandstone and mudstone with low depositional energy is easily to be tightly compacted, and have poor reservoir quality. Porosity usually decreases with compaction and cementation, and increases due to dissolution. Clay minerals filling pores result in a deterioration of the pore structure. Microfracture formed by fracturing can connect the matrix pores, effectively improving the reservoirs’ permeability. The differential distribution of fractures and in-situ stress plays an important role in modifying reservoir quality. The in-situ stress has obvious control over the matrix physical properties and fracture effectiveness. The matrix physical properties are negatively correlated with the value of horizontal stress difference (Δσ). As the value of Δσ increases, the pore structure becomes more complex, and the macroscopic reservoir quality becomes poor. The smaller the strike divergence between the natural fracture and SH_max, the lower the value of Δσ in the fracture layers is, and the better the fracture effectiveness is. Under the control of ternary factors on the reservoir, sedimentation-diagenesis jointly affect the matrix reservoir quality, while fractures and in-situ stress caused by tectonism affect the permeability and hydrocarbon productivity of the reservoir. Affected by ternary factors, reservoir quality and hydrocarbon productivity show obvious differences within the various structural location. Reservoir quality in tight sandstones can be predicted by integrating sedimentation, diagenesis, and tectonics (fracture and in-situ stress) in a compressional tectonic setting like Kuqa Depression. The research results will provide insights into the efficient exploration of oil and gas in Kuqa Depression as well as similar compressional tectonic settings elsewhere.

With the development of unconventional hydrocarbon, how to improve the shale oil and gas recovery become urgent. Therefore hydraulic fracturing becomes the key due to the complicated properties of the reservoirs. The pore structure not only plays an essential role in the formation of complex fracture networks after fracturing but also in resource accumulation mechanism analyses. The lacustrine organic-rich shale samples were selected to carry out petrophysical experiments. Scanning Electron Microscopy (SEM) and X-ray Diffraction were performed to elucidate the geology characteristics. MICP, 2D NMR, CT, and N₂ adsorption were conducted to classify the pore structure types. The contribution of pore structure to oil accumulation and hydrocarbon enrichment was explained through the N₂ adsorption test on the original and extracted state and 2D NMR. The results show that micropores with diameter less than 20 nm are well-developed. The pore structure was divided into three types. Type Ⅰ is characterized by high porosity, lower surface area, and good pore throat connectivity, with free oil existing in large pores, especially lamellation fractures. The dominant nano-pores are spongy organic pores and resources hosted in large pores have been expelled during high thermal evolution. The content of nano-pores (micropores) increases and the pore volume decreases in Type Ⅱ pore structure. In addition, more absorbed oil was enriched. The pore size distribution of type Ⅱ is similar to that of type Ⅰ. However, the maturity and hydrocarbon accumulation is quite different. The oil reserved in large pores was not expelled attributed to the relatively low thermal evolution compared with type Ⅰ. Structural vitrinite was observed through SEM indicating kerogen of type Ⅲ developed in this kind of reservoir while the type of kerogen in pore structure Ⅰ is type Ⅱ. Type Ⅲ pore structure is characterized by the largest surface area, lowest porosity, and almost isolated pores with rarely free oil. Type Ⅰ makes the most contribution to hydrocarbon accumulation and immigration, which shows the best prospect. Of all of these experiments, N₂ adsorption exhibits the best in characterizing pores in shales due to its high resolution for the assessment of nano-scale pores. MICP and NMR have a better advantage in characterizing pore space of sandstone reservoirs, even tight sandstone reservoirs. 2D NMR plays an essential role in fluid recognition and saturation calculation. CT scanning provides a 3D visualization of reservoir space and directly shows the relationship between pores and throats and the characteristics of fractures. This study hopes to guide experiment selection in pore structure characterization in different reservoirs. This research provides insight into hydrocarbon accumulation of shales and guidance in the exploration and development of unconventional resources, for example for geothermal and CCUS reservoirs.

Fine-grained sedimentary rocks, which serve as the source rocks and reservoirs of tight/shale oil and gas, are the focus and frontiers of petroleum geology. The log-based assessments of these rocks hold great significance for the exploration and exploitation of unconventional hydrocarbons. In this study, the advances in both domestic and international log-based assessment techniques are systematically analyzed for fine-grained sedimentary rocks. The analytical results indicate that the combination of conventional and emerging logging techniques allows for the assessment of more than seven properties of fine-grained sedimentary rocks, including lithology, physical and electrical properties, oil-bearing capacity, oil mobility, wettability, brittleness, and source rock property. The log-based assessment of fine-grained sedimentary rocks has, therefore, further evolved into the assessment of their reservoir property, oil-bearing capacity, oil mobility, and fracability, collectively known as the "new four properties". Specifically, the reservoir property of these rocks is assessed based on parameters such as lithology, lithofacies, pore type, microscopic pore structure, lamellation, total porosity, and effective porosity. Their oil-bearing capacity is assessed using parameters like clay mineral content, TOC content, free hydrocarbon content, oil saturation, oil occurrence, and movable oil content. The oil mobility in fine-grained sedimentary rocks is assessed according to parameters such as maturity, formation pressure, crude oil density and viscosity, and gas/oil ratio. The fracability of these rocks is assessed using parameters like the respective compositions and contents of clay and brittle minerals, Young's modulus, Poisson's ratio, and the maximum and minimum principal stresses. The formation micro-imaging (FMI) logging slicing technology enables the manual identification and assessment of meter-, millimeter-, and even micron-scale laminae in fine-grained sedimentary rocks. Additionally, log data facilitate the identification and assessment of the lithofacies of fine-grained sedimentary rocks. The techniques and methods for log-based assessments of fine-grained sedimentary rocks are evolving from conventional and emerging logging techniques toward artificial intelligence approaches based on mathematical statistics.