The mineral composition of shale plays a crucial role in determining the quality of shale reservoirs. Since shale typically consists of tightly packed fine-grained minerals, accurately identifying its mineral composition has become a key research focus (Loucks and Ruppel, 2007; Macquaker et al., 2014). Currently, rock slice identification and X-ray diffraction (XRD) are the most effective methods for the qualitative and quantitative analysis of shale minerals (He et al., 2023). Although rock slice identification offers lower magnification, making it challenging to observe fine minerals such as clay, it still provides critical, rapid information on the shapes, contact relationships, and structural features of mineral particles within the rock. XRD, on the other hand, accurately quantifies the mineral content of shale, detailing the composition and relative proportions of minerals such as quartz, feldspar, clay, and carbonates (Raef et al., 2018).

The integration of scanning electron microscopy (SEM) with other high-resolution imaging technologies is crucial for identifying minerals in shale reservoirs. This approach provides superior resolution compared to earlier methods and allows for non-destructive observation of rock samples. SEM, with its backscattered imaging and large view field stitching method, when combined with X-ray energy dispersive spectroscopy (EDS) and advanced data and image processing from micro-area mineral analysis systems, enables precise nano-level characterization and quantitative analysis of mineral composition, particle size, and morphology (Figure 4). Additionally, cathodoluminescence (CL), which is used in conjunction with electron microscopy, helps determine the origin and formation processes of minerals, which supports the reconstruction of paleogeographic environments (Hackley et al., 2024). Raman spectroscopy, capable of identifying mineral components and assessing diagenetic processes based on crystal orientation, complements SEM in facilitating in situ micro-area analysis of mineral composition and rock structure (Hope et al., 2001). The electron microprobe offers a detailed analysis of trace elements in shale, providing essential insights into the chemical properties and formation environments of minerals (Orberger et al., 2003). X-ray fluorescence (XRF) spectroscopy can accurately analyze the elemental composition of minerals and calibrate the oxide proportions of primary elements. The results from these tests support the verification of mineral identification outcomes obtained through XRD (Hupp and Donovan, 2018). Moreover, the use of X-ray fluorescence for in situ elemental imaging and laser in situ micro-area elemental imaging technology enables accurate characterization and rapid assessment of rock components and structures through extensive scanning (Hua et al., 2022). Fourier-transform infrared spectroscopy (FTIR) is utilized by geologists to analyze both organic and inorganic materials in shale, facilitating a heterogeneous examination of mineral components (Mishra et al., 2018).

The experimental analysis of the mineral matrix effect is also a crucial issue for lacustrine shale reservoir characterization. During the stages of kerogen formation and organic matter preservation, the mineral matrix isolates organic matter via physical adsorption and interlaminar stress, effectively protecting the organic matter. In the stage of organic matter pyrolysis, minerals such as metal oxides and carbonates exhibit catalytic properties, reducing the activation energy required for reactions and accelerating organic matter pyrolysis. The integration of equipment like SEM, TEM, and FTIR with geochemical analysis has elucidated the role of the mineral matrix in preserving organic matter in shale (Salmon et al., 2000). Studies utilizing XRD and FTIR have shown that the mineral matrix not only facilitates the oxidation of kerogen but also lowers the resistance to kerogen oxidation by generating inorganic pores (Yan et al., 2013).

The pore structure in shale reservoirs is characterized by multi-scale features, with notable variations in connectivity and wettability across different pore types. These variations result in complex hydrocarbon flow patterns that deviate from those observed in traditional oil and gas migration (Chalmers et al., 2012). The micro–nano scale pore system plays a pivotal role in hydrocarbon accumulation within shale reservoirs, rendering its systematic characterization essential for the accurate assessment of shale oil (Ross and Bustin, 2009; Fink et al., 2018). As high-precision instruments increasingly pervade this field, the methods for characterizing shale pore structures are evolving toward comprehensive aperture coverage, quantification, and digitization, effectively creating a holistic evaluation system that addresses all scales, apertures, and dimensions. In recent years, the utilization of high-precision equipment such as micro-CT, SEM, FIB-SEM, atomic force microscopy (AFM), transmission electron microscopy (TEM), helium ion microscopy (HIM), and small-angle X-ray scattering (SAXS) has expanded from material research to characterize the microscopic pores of shale (Klaver et al., 2015; Liu W. et al., 2016).

Depending on the characterization dimensions, these methods can be classified into two categories: two-dimensional and three-dimensional characterization (Hou L. et al., 2023). For two-dimensional characterization, the combination of argon ion polishing and FE-SEM serves as the primary experimental method. This approach employs large-area stitching technology to produce high-precision images, achieving exceptional resolution and enabling comprehensive characterization across the entire sample, thereby minimizing the effects of reservoir heterogeneity on the results (Curtis et al., 2012; Wen et al., 2020). If there are stringent requirements for the accuracy of pore structure observations or if the conductivity of the sample fails to meet experimental standards, HIM and AFM can provide superior results. HIM can achieve resolutions exceeding five times that of SEM without requiring conductive treatment of the sample (Wang et al., 2020). Furthermore, atomic force microscopy can characterize ultra-small pores and assess the local elastic modulus of the samples (Javadpour et al., 2012). However, these two devices are relatively more expensive. Compared with two-dimensional methods that primarily utilize electron microscopy, three-dimensional characterization techniques offer a greater diversity of methods and cover a broader research scale. Micro-CT enables the three-dimensional characterization of pore structures across varying scales, achieving resolutions as fine as below 1 micron, making it a commonly used digital core technology (Garum et al., 2020). Utilizing its ability to achieve nanometer-level resolution, FIB can perform three-dimensional slice imaging of designated areas through nano-etching methods. This capability facilitates the creation of three-dimensional models from two-dimensional observations, aiding in the differentiation of organic and inorganic pores and enabling nanoscale three-dimensional characterization (Kelly et al., 2016). Additionally, FIB can be employed for TEM sample preparation, allowing for the precise characterization of sub-nanometer pores (Schulz et al., 2015). SAXS offers several advantages, including a wide measurement range from 0.5 nm to 20 μm, the ability to reflect pore connectivity, rapid detection, and non-destructive testing of samples, providing researchers with essential data on the specific surface area, pore size distribution (PSD), structural dimensions, and interface properties (Leu et al., 2016). Furthermore, some researchers have utilized SANS/USANS technology to evaluate the connectivity and heterogeneity of pores in shale (Chandra et al., 2020).

Each technique possesses distinct advantages and limitations: micro-CT scanning facilitates non-destructive sample analysis but offers relatively lower resolution, whereas FIB-SEM provides higher resolution but is limited to a smaller characterization range (10–20 μm) and is destructive to samples. Consequently, addressing the technical challenges associated with the comprehensive characterization of pore structures through the integration of various instruments is crucial for future research. As technology progresses, the digital core technology derived from these experimental methods is becoming increasingly vital for the quantitative characterization of micro-pores in shale. By precisely identifying and modeling rock pores, fractures, and other features in three dimensions, this approach effectively collects parameters such as porosity, pore size and distribution, pore density, and the proportion of different pore types, thereby facilitating a comprehensive transition from qualitative evaluations to quantitative evaluations (Figure 5).

The distinctions in paleoenvironment and climatic conditions between lacustrine shale and marine shale lead to significant variations in the characteristics and types of organic matter (Xu et al., 2017; Liu et al., 2020). Key indicators, such as the formation mechanism, type, source, and maturity of organic matter, play crucial roles in determining the quality of shale reservoirs in lacustrine basins. Organic matter serves not only as the source of oil and gas generation but also as an essential type of reservoir space (Gao et al., 2016). The physical and chemical properties of organic matter, including porosity, permeability, total organic carbon (TOC), and the degree of thermal evolution, significantly influence the exploitation potential of lacustrine shale (Liu G. et al., 2016).

The quantity of organic matter and the presence of light hydrocarbon fluids in shale are critical indicators for evaluating the potential of shale oil and gas development (Saberi and Hosseini-Barzi, 2024). Traditional geochemical properties such as TOC, free hydrocarbons (S1), and extractable compounds provide only partial insights into these indicators. Moreover, acquiring these properties typically requires destructive sample treatment, which restricts the ability to perform multiple analyses on the same sample. The inherent heterogeneity of lacustrine shale reservoirs complicates the selection of comparable samples, potentially increasing analytical errors. Utilizing nuclear magnetic resonance (NMR) to assess organic matter abundance and light hydrocarbon content in shale preserves sample integrity during pretreatment and enables comprehensive joint testing and analysis on a single sample. It also allows for the dynamic analysis of changes in the chemical composition of kerogen as its thermal maturity evolves (Lee et al., 2020). MALDI-TOF (Matrix-Assisted Laser Desorption/Ionization Time-of-Flight) imaging mass spectrometry can be utilized to elucidate the complex molecular structure of organic matter in shale, thereby assisting researchers in understanding the effects of thermal maturation on the molecular architecture of kerogen (Rudyk et al., 2023). Thermal gravimetric analyzer (TGA) can quantitatively analyze the organic matter in a sample by examining the weight loss intervals, peak positions, and shapes of the thermogram, which facilitates the determination of kerogen composition, TOC content, and thermal maturity (Williams and Ahmad, 2000). Raman band separation (RBS) achieved through Raman spectroscopy exhibits a strong correlation with equivalent vitrinite reflectance, making it a reliable proxy for assessing shale thermal maturity (Figure 6). Additionally, the combined analysis of confocal laser scanning microscopy (CLSM) and fluorescence spectroscopy can quantitatively assess the distribution of organic matter and its influence on the potential for shale gas (Liu et al., 2020).

During diagenesis, organic matter in shale undergoes thermal evolution, transforming into hydrocarbons and generating numerous pores that serve as essential storage for shale oil and gas. To explore the formation and evolution of shale pores, thermal simulation experiments are indispensable. These experiments can be classified into closed, semi-open, and open systems based on their closure characteristics (Yin and Wei, 2019). Closed systems are tailored for specific research objectives, such as examining the effects of temperature, pressure, water medium, and minerals on hydrocarbon generation through pyrolysis. In contrast, open systems focus on analyzing the relationship between pyrolysis temperature and product composition. Semi-closed systems, which can replicate the temperature and pressure conditions of geological strata and collect pyrolysis products, are particularly suited for isothermal pyrolysis simulations and pore evolution.

Shale is characterized by its low porosity and permeability, making the accurate measurement of these properties a central focus and challenge in shale gas exploration and development. Recently, a variety of new technologies, methods, and interdisciplinary approaches have been applied to characterize the physical properties of shale reservoirs (Handwerger et al., 2011; Bohacs et al., 2014; Goral et al., 2020). The primary experimental methods for assessing basic physical properties include gas adsorption analysis using N₂ and CO₂, high-pressure mercury intrusion analysis, nuclear magnetic resonance (NMR) analysis, and helium porosity analysis. Currently, gas adsorption, helium porosity, and nuclear magnetic resonance analyses are commonly employed to assess effective storage capacity, with results from these methods generally showing consistency (Hou L. et al., 2023).

Porosity testing in shale typically entails measuring bulk volume, particle volume, and pore volume. Laser 3D scanning has increasingly supplanted traditional caliper measurements and Archimedes’ immersion method for assessing bulk volume. This advanced technique generates a three-dimensional surface map by scanning the sample with low-frequency pulse waves, thus circumventing limitations related to shape and contamination. Particle volume is commonly determined using a dual-chamber method based on Boyle’s law. However, this method’s susceptibility to environmental conditions and instrument precision can lead to variability in results across different laboratories. Pore volume measurement is performed using either the single-chamber method based on Boyle’s law or a more precise liquid saturation method (He et al., 2023). Moreover, techniques such as NMR and digital core analysis are employed to assess porosity, although their results might be influenced by signal interference and limited observation areas.

The extremely low permeability of lacustrine shale reservoirs renders conventional testing methods inadequate for meeting accuracy requirements. The pulse decay method is currently the most widely used and effective approach for measuring permeability. Additionally, NMR has been employed to assess shale permeability (Zhou et al., 2016). In scenarios where obtaining complete core samples is challenging, a pressure decay method using crushed samples can be utilized.

Fracturability refers to the ability of shale reservoirs to be effectively fractured to enhance production capacity. The brittleness of shale significantly influences its fracturability; typically, higher brittleness correlates with better fracturability. The brittleness index is the primary method for assessing the fracturability of shale reservoirs, and it typically utilizes two key indicators, namely, the elastic mechanical parameters of the rock and the content of brittle minerals. These indicators are primarily derived from geophysical and mechanical testing methods, which include full stress–strain testing instruments, conventional logging data, elemental capture spectrum (ECS), and radioactivity spectrum logging (Jarvie et al., 2007; Rickman et al., 2008; Li et al., 2012). In addition to evaluating mineral components and elastic parameters, researchers have explored calculating the brittleness index through laboratory indentation tests, fracture surface characteristics, rock hardness, and complete stress–strain curves. As research methodologies have diversified, the focus has expanded from analyzing individual brittle minerals, primarily quartz, to include combinations of minerals such as quartz, feldspar, and carbonates (Zhao et al., 2015). Rock mechanics analysis often involves true triaxial or pseudo-triaxial stress experiments, facilitating a comprehensive assessment of shale oil reservoir compressibility based on stress–strain curves, Young’s modulus, and Poisson’s ratio. Micro CT aids researchers in obtaining the distribution patterns of fractures in shale, and combined with fractal calculation methods, three-dimensional modeling, and other technologies, it can provide an accurate visual representation of the results of shale fracture expansion (Figure 7). For samples subjected to fracturing tests, the integration of in situ stress loading systems with high-resolution CT scanning enables real-time monitoring of fracture growth (Wu S. et al., 2020).

Factors influencing the fracturability of shale reservoirs encompass not only intrinsic properties but also the geological environment, indicating that brittleness evaluation is only one aspect of assessing fracturability. Additional key indicators include the extent of natural fracture development, diagenetic alterations, water saturation, and micro-fracture structures (Fan et al., 2023; Li P. et al., 2023). With advancements in micromechanical methods, technologies such as micro-indentation and nano-indentation have been employed to investigate the fracturability of shale reservoirs. Micro-indentation facilitates the evaluation of the mechanical characteristics of shale in its natural state and aligns with macroscopic mechanical methods, effectively complementing each other (Kasyap and Senetakis, 2022). Additionally, nano-indentation allows for the assessment of mechanical and fracture characteristics of shale across varying temperatures and bedding orientations (Zeng et al., 2022).

Lacustrine shale, characterized as a fine-grained sedimentary system, has small particle sizes and is rich in organic matter. The formation model of shale reservoirs significantly diverges from that of conventional sandstone reservoirs. These reservoirs display pronounced vertical and lateral heterogeneity, with scale differences spanning 12 orders of magnitude from micro to macro levels, which complicates their characterization and evaluation (Wu Y. et al., 2020). Consequently, achieving a comprehensive cross-scale evaluation of lacustrine shale reservoirs and establishing connections among minerals, nano-pores, rock types, and geophysical responses, particularly in addressing data coarsening and integrating diverse data types, has emerged as a critical research area that demands significant breakthroughs.

Unlike conventional sandstone and carbonate reservoirs, shale reservoirs are subject to complex interactions between organic and inorganic processes. The generation and expulsion of hydrocarbons from organic matter, coupled with the thermal evolution of inorganic matter during diagenesis, collectively influence hydrocarbon generation, accumulation, enrichment, and production in shale. The behavior of fluids within the micro–nano scale pore-fracture system of shale reservoirs is influenced by factors such as pore diameter, mineral composition, and complex wettability (Li G. et al., 2023). Current experimental evaluations face challenges in fully replicating this intricate process, which impedes a deeper understanding of the patterns of hydrocarbon generation, storage, and enrichment in lacustrine shale reservoirs.

Laboratory conditions cannot fully replicate the underground geological environment, resulting in experimental results that may not accurately reflect the true geological situation. For instance, the measurement of porosity and oil content in shale oil reservoirs is complicated by the rich fluid content under formation conditions, which include high temperature, pressure, and a three-dimensional stress field. While temperature and pressure can be simulated in laboratory experiments, replicating fluid characteristics and the three-dimensional stress field environment remains a significant challenge (Tang et al., 2025). Additionally, field operations can alter the original temperature, pressure, and fluid composition of the formation, significantly impacting the characterization and evaluation of oil and gas content in the reservoir.

The composition of the mineral matrix in lacustrine shale reservoirs is extremely complex and plays essential roles in hydrocarbon generation and preservation. The interaction mechanisms between various minerals and organic matter represent a significant area of study. Experimental analysis and simulations in this field not only require experimental techniques such as in situ characterization and the integration of multiple technologies but also necessitate the development of experimental methods capable of dynamically analyzing various evolutionary stages. These methods should aim to comprehensively assess the impact of critical environmental factors like temperature and pressure on mineral matrix across different geological epochs.

The precise and quantitative characterization of nano-micro pores in terrestrial shale reservoirs is essential for reservoir evaluation. Nano-scientific techniques and evaluation methods, such as helium ion microscopy, transmission electron microscopy, and nano-indentation have proven effective in various fields and are promising for the characterization of shale reservoirs. However, integrating micro and macro scales poses significant challenges as different technical methods are limited by their applicable scales. No single experimental method can seamlessly transition from precise micro–nano scale to reservoir-scale. Future efforts should focus on enhancing cross-scale experimental devices and integrating multiple methods. This integration should include optical microscopy, electron microscopy, micro-area mineral analysis, laser Raman spectroscopy, and CT scanning to comprehensively characterize minerals, pores, fractures, and fluids.

The nanoscale pore system in shale reservoirs, combined with their complex mineral composition and hydrocarbon storage states, necessitates the dynamic evaluation of geological evolution. Experimentally simulating geological evolution can be used in reconstructing geological history, identifying key controlling elements, revealing the dynamics and thermodynamics of geological evolution, and predicting the distribution of favorable geological bodies and sweet spots. Future research directions should focus on simulating fine-grained sedimentation and organic matter enrichment, dynamic hydrocarbon generation and drainage processes, mineral matrix effect, micro- and nano-pore evolution, and the growth of artificial fractures.

Shale oil and gas reservoirs are highly sensitive to stress release, weathering, and other surface conditions, which complicates the accuracy of laboratory evaluations in reflecting true in situ reservoir characteristics. Developing experimental techniques that mimic the in situ conditions can significantly enhance the accuracy and precision of key parameter characterization in shale reservoirs. Consequently, direct or indirect in situ evaluation technologies are essential for accurately characterizing the true state of subsurface shale reservoirs and represent a crucial direction for future development. The advancement of in situ testing technologies should be prioritized, including tests for shale physical properties under formation temperature, pressure, and fluid storage conditions, isothermal adsorption tests, multiphase fluid seepage and drive-off experiments, and competitive gas adsorption experiments.

In the future, the characterization and evaluation of shale reservoirs will generate vast amounts of data across various scales and methods, fostering the integration of intelligent technologies such as big data, artificial intelligence, and cloud computing for the oil and gas industry. The adoption of these technologies will streamline automated data acquisition, processing, and analysis, providing essential support for comprehensive multi-factor experimental evaluations. Machine learning techniques, for example, are employed to analyze the lithofacies characteristics of shale reservoirs based on well logging curves (Hou M. et al., 2023). Techniques such as principal component analysis (PCA) and K-means clustering are utilized to classify geochemical characteristics (Li et al., 2024), offering efficient data analysis solutions to tackle complex mechanistic challenges in shale gas exploration and development.