Quantitative evaluation of pore-scale oil-water spatial distribution is pivotal for understanding fluid mobility and enhancing recovery in shale reservoirs. However, existing methodologies, such as Chart, Centrifugal, and Heating methods, primarily quantify total free/adsorbed fluid contents but fail to quantify the spatial distribution differences of oil-water in the pores between samples. To bridge this gap, we propose a novel mathematical model that quantitatively resolves the pore volumes occupied by four distinct spatial distribution patterns: "full of oil", "water-wrapped oil", "oil-wrapped water", and "full of water". This model is established based on centrifugal experiments and 2D nuclear magnetic resonance (NMR) data from 23 sealed shale cores from the Paleogene Shahejie Formation, Bohai Bay Basin. Our results reveal that "full of water" pores dominate (avg. 43.99 %), followed by "full of oil" pores (avg. 32.29 %) and "water-wrapped oil" pores are minimally developed with only 4.42 %. Fluid spatial distribution patterns are governed by pore wettability and pore-scale capillary dynamics during the hydrocarbon generation and micro-migration. The model also introduces a wettability assessment based on wetted pore surface area (PSA), showing strong correlation with traditional pore volume (PV) methods, and successfully quantifies adsorbed oil/water film thicknesses (0.50-4.63 nm and 0.61-2.33 nm, respectively). The model-derived oil-film thickness aligns remarkably with independent low temperature N2 adsorption (LTNA) measurements, providing robust validation. This study significantly enhances the mechanistic understanding of shale oil occurrence and provides quantitative insights critical for optimizing hydraulic fracturing design and EOR strategies in shale reservoirs.

Confronted with the challenges of ever‐increasing global demand for oil and gas, coupled with the depletion of conventional resources, the strategic importance of unconventional oil and gas resources is becoming increasingly significant, with shale oil being particularly crucial. Immature to low‐maturity shale oil reserves are extremely abundant, constituting over 80% of the world’s total shale oil resources. Thus, the efficient enhancement and development of immature to low‐mature shale oil is of profound importance for ensuring future energy supplies and reshaping the global energy landscape. This review begins with an in‐depth analysis of the microscopic conversion mechanism and reaction pathway of immature to low‐maturity shale oil at the molecular structural level. Building on this foundation, it systematically summarizes and analyzes the current main in situ upgrading methods, including thermal upgrading and catalytic synergistic thermal upgrading combined with catalysts, which essentially rely on heat to drive the thermal cracking and hydrogenation reactions of organic matter. However, these methods typically encounter challenges such as high energy consumption, elevated costs, and substantial environmental impacts, which limit their widespread adoption and application. In contrast, microbial upgrading technology exhibits significant advantages by achieving upgrading through environmentally friendly and low‐energy biological processes. The primary mechanisms include direct biological conversion, where microorganisms directly metabolize organic components in shale, degrading or converting them into lighter hydrocarbons with improved mobility and lower viscosity, and indirect biological promotion, which alters the properties of reservoir rocks, thereby promoting the release of organic matter and enhancing its effective contact with the external modification environment. Although the microbial upgrading of immature shale oil remains in its foundational development stage, lacking in mechanistic and systematic research, existing studies have demonstrated progress in the application of microbial technology for shale oil extraction. This progress is achieved through the screening and optimization of microbial communities to enhance shale oil recovery rates. Consequently, this review explores the future development directions of microbial technology in the field of shale oil and gas extraction in its final section, aiming to promote the widespread application of this green and low‐carbon technology.

As global energy demand continues to rise, shale oil has become an indispensable unconventional resource. The Bonan subsag was renowned for its oil richness. This study evaluates the potential of shale oil in the Es3L subsection of the Bonan subsag within the Jiyang Depression of the Bohai Bay Basin, China, through geochemical analysis and pyrolysis experiments. By analyzing total organic carbon (TOC) and conducting hydrocarbon generation simulations, correction methods for light and heavy hydrocarbons to accurately assess shale oil content were developed. The results indicate that a TOC greater than 2.4% was a crucial criterion for shale oil resource enrichment, while the movable oil content was a key factor for effective development. The middle section of the Es3L sub-member in Well L69 (2981–3041 meters) has been identified as the primary target for further exploration and development, providing a promising pathway to enhance shale oil production in the region. This study offered a robust framework for shale oil assessment that can be applied to other target areas to optimize resource extraction.

Accurate quantification of shale pore structure is critical for evaluating reservoir space, controlling hydrocarbon storage, and guiding engineering development. However, whether solvent extraction disrupts pore structure during current pore measurement practices remains to be validated. This study innovatively adopts extraction time as a metric, integrating multiple techniques-nuclear magnetic resonance (NMR), gas chromatography, low-temperature nitrogen adsorption, and gas-measured porosity-to dynamically monitor extraction efficiency, organic matter composition, and pore structure responses during the treatment of shale samples with different properties using various organic solvent combinations. The results demonstrate that the coupling of solvent properties, rock characteristics, and time jointly controls the extraction efficiency of shale samples. Over 7 days, >80% of soluble fluids can be removed. High-maturity, clay-rich samples exhibit an anomalous decline in gasmeasured porosity after 7 days of extraction, contrasting with the sustained increase in low-maturity, carbonaterich samples. In low-maturity, carbonate-rich samples, pores < 20 nm continuously expand due to organic matter leaching, while pores > 20 nm exhibit fluctuating changes caused by organic fragment throat clogging. In highmaturity, clay-rich samples, the swelling of clay-organic complexes leads to systematic contraction of pores > 8 nm. These observations demonstrate that shale pore evolution under solvent extraction disturbance is governed by a dynamic coupling of fluid migration, mineral swelling, and pore-throat blockage. This study provides the first systematic, time-resolved evaluation of solvent extraction-induced pore structure disturbance in shales, offering critical guidance for developing extraction protocols that minimize damage to original pore systems.

Shale oil content is commonly evaluated using Rock-Eval pyrolysis S1, but conventional S1 may underestimate total oil content because light hydrocarbons can be lost during storage and heavy hydrocarbons may remain undetected below 300 °C. This study evaluates the shale oil sweet spot interval of the lower Es3 sub-member (Es3L) in the Bonan subsag, Jiyang Depression, Bohai Bay Basin, by integrating organic geochemical data, open-system hydrocarbon generation simulation, gold-tube pyrolysis, and corrected oil-content calculation. The results show that correction of both light and heavy hydrocarbon losses improves the quantitative estimation of total shale oil content. A three-segment relationship between corrected total oil content and TOC defines the enrichment threshold for the Es3L shale, with TOC > 2.4% indicating enriched shale oil resources. Movable oil content, calculated from the difference between total oil content and adsorbed oil content, further constrains sweet spot identification. The interval of 2981-3041 m in Well L69 satisfies both enrichment and movability criteria and is therefore identified as the preferred sweet spot interval. The proposed workflow provides a practical framework for shale oil sweet spot evaluation in the Bonan subsag and comparable lacustrine shale systems.

Identification, quantification, and mobility assessment of shale pore fluids are crucial for shale oil development. Conventional coring often leads to fluid loss. This study used cryogenically preserved, sealed core samples, combined with core exposure, centrifugation, drying, and solvent extraction, applying a dual-cutoff T-2 relaxation approach (T-2c1 = 0.28 ms, T-2c2 = 0.61 ms) and a Gaussian mixture model to quantify fluid states and corresponding pore sizes. Results show significant fluid loss during core exposure, while solvent extraction cannot fully remove trapped fluids. Pore fluids are classified as immobile (17.09%), borderline mobile (21.99%), and mobile (60.92%). Medium-to-large pores (25-1000 nm) mainly host free oil and mobile water, whereas small pores (<25 nm) contain adsorbed oil and bound water, with similar to 25 nm as the lower threshold for mobile fluid. This framework provides a quantitative basis for evaluating shale fluid mobility and producibility, aiding sweet spot identification and hydraulic fracturing optimization.

The Gulong Sag in the Songliao Basin is an important region of China where significant breakthroughs have been achieved in the exploration of medium-and high-maturity lacustrine shale oil.However,the major controlling factors and evolution patterns of shale reservoirs in this sag remain poorly understood.This study focuses on shales in the 1st member of the Qingshankou Formation(also referred to as the Qing 1 Member)in the Gulong Sag.By integrating multiple analytical techniques,including Rock-Eval pyrolysis,X-ray diffraction(XRD),scanning electron microscopy(SEM),nitrogen adsorption,high-pressure mercury injection(HPMI),and nuclear magnetic resonance(NMR),we systematically analyze the organic geochemical characteristics of the shales,as well as the reservoir space types and their sizes and distribution patterns.The analytical results show that the shales in the sag contain organic matter dominated by high-quality Type Ⅰ kerogen.These shales were deposited in a semi-deep to deep lacustrine anoxic environment and are currently in oil generation state with moderate to high maturity.Reservoir development in the shales is jointly governed by the sedimentary environment,diagenesis,organic matter type,and thermal evolution.Specifically,intense compaction and cementation in the early stage lead to substantial loss of primary pores.With an increase in thermal maturity,the dissolution of minerals such as feldspars,together with the hydrocarbon generation of organic matter,collectively contribute to secondary pore growth.Consequently,reservoir spaces in the shales progressively evolve into an organic-matter-and clay-hosted composite pore system dominated by nano-scale pores.The reservoir space evolution pattern of shales in the Qing 1 Member established in this study provides an important theoretical basis for shale oil exploration in the Gulong Sag.Furthermore,other relevant patterns and research approaches involved in this study may provide references for the exploration of other shale oil plays.

Focusing on the medium- to high-maturity shale oil play of the Qingshankou Formation in the Gulong Sag (Songliao Basin, NW China), pressure-retained, full-closure, and conventional core samples (including long-term stored core samples) with varying thermal maturities were collected, to visually demonstrate the changes in oil content and retained hydrocarbon composition during exposure. The factors influencing the evaporative loss of light hydrocarbons were investigated. We utilized T1-T2 nuclear magnetic resonance (T1-T2 NMR), thermal desorption-gas chromatograph (TD-GC) and Rock-Eval analysis techniques to examine pressure-retained core samples during exposure. A fitting formula was established to describe the relationship between oil content and exposure time. The evaporation of oil content in sample H1-1 (Ro = 1.55%) was best modeled using a power-law decay, whereas an exponential decay provided a better fit for the samples B5-1 (Ro = 1.20%) and G5-1 (Ro = 1.32%). The oil content detected by T1-T2 NMR was significantly higher than that obtained by TD-GC, with Rock-Eval analysis yielding the lowest values. During the exposure of pressure-retained core samples, nearly all nC9- alkanes were lost, nC10–14 showed substantial loss, and nC15+ alkanes experienced partial evaporation in higher maturity samples. Thermal maturity controls the evaporative loss of light hydrocarbons in shale, as reflected in oil composition and pore structure. In high maturity shale, organic matter has minimal impact on hydrocarbon loss, while variations in mineral composition often lead to changes in pore structure. The evaporation rate of block samples is lower than that of powdered samples, with smaller particle sizes exhibiting faster loss rate. Higher temperatures and lower humidity in storage facilitate hydrocarbon diffusion. The research enhances the understanding of light hydrocarbon evaporation processes and offers new insights for evaluating in situ oil content and composition.

This review systematically synthesizes global advancements in shale oil exploration and development, while analyzing current progress in microstructural characterization technologies. It further elucidates the synergistic evolution of geological characteristics, hydrocarbon accumulation mechanisms, engineering practices, and technological innovations. By contrasting marine and continental shale oil systems across dimensions of resource distribution, reservoir heterogeneity, and pore network architecture, the study reveals fundamental distinctions between North America’s large-scale development paradigm and China’s breakthrough strategies for continental shale oil. Key findings demonstrate that North America’s marine shale oil achieved commercialization through horizontal well fracturing technological innovations, with homogeneous reservoir properties and engineering compatibility driving a production capacity of 4.8 million barrels per day in 2021. China’s continental shale oil reservoirs contain technically recoverable resources of (30–60) × 108 tons, yet exhibit sub-5

Previous lamina combination schemes have mainly focused on individual laminae or vertically stacked classification of different laminae, leaving room for further exploration at the lamina scale and in terms of genetic mechanisms. Focusing on the shale of the Qingshankou Formation in the Songliao Basin, this study employed a comprehensive range of experimental methods, including polarized light microscopy thin-section identification, field emission scanning electron microscopy, and quantitative mineral analysis by X-ray diffraction (XRD), to conduct systematic and in-depth research on lamina types, mineral compositions, morphological characteristics, and stacking patterns. The results showed that: (1) the shale in the study area mainly developed four types of laminae: clay-mineral-rich, felsic-mineral-rich, carbonate-mineral-rich, and mixed-mineral laminae. (2) Based on the principle of “dominant lamina thickness + lamina morphology + lamina mineral composition”, a classification scheme for continental shale lamina combinations was established, dividing the shale in the study area into four main types of lamina combinations: thinly interbedded argillaceous type, characterized by thin clay laminae with frequent interbedding; thickly interbedded mixed type, characterized by alternations of thick mixed or felsic laminae with thick clay laminae; thickly interbedded felsic type, dominated by relatively thick felsic laminae, often accompanied by silt-sized particles; and altered mixed type, significantly affected by diagenetic epigenetic modification, with notable changes in the original lamina structure. (3) Based on lamina thickness, mineral composition, and morphological characteristics, their genetic mechanisms were identified to include hydrostatic suspension settling, collapse gravity flow, hyperpycnal flow, and post-depositional alteration, and a corresponding developmental model for lamina combinations was established accordingly. This study classified lamina combinations based on genesis, effectively revealing the key parameters and development patterns of different lamina combinations, providing a solid geological basis for in-depth investigation of shale oil enrichment mechanisms and for further screening and prediction of favorable intervals.

Differences in hydrocarbon generation composition and apparent kinetic characteristics (i.e., pre-exponential factors and activation energies) among various types of organic matter are primarily controlled by kerogen structure, which is jointly governed by maceral composition and depositional environment. However, previous studies have largely focused on individual kerogen types, and systematic comparisons of differential hydrocarbon generation composition and their controlling mechanisms remain limited. In particular, such comparative studies are scarce for kerogens formed under frequently fluctuating lacustrine depositional settings in the Songliao Basin. In this study, representative kerogens of different types and coal samples from the Songliao Basin were investigated using an integrated approach combining thermal simulation experiments, organic petrography, elemental geochemistry, and organic geochemistry. For the first time, the hydrocarbon generation potential and kinetic characteristics of different kerogen types formed under a highly variable lacustrine depositional regime were systematically compared, and their differential enrichment mechanisms were elucidated. The results indicate that Type I kerogen from the First Member of the Qingshankou Formation exhibits the highest oil- and gas-generating potential, with gaseous hydrocarbons mainly derived from the secondary thermal cracking of generated oil. In contrast, type Ⅱ1 kerogen from the Second Member of the Nenjiang Formation, although also of algal origin, shows a slightly lower oil-generating capacity due to the presence of abundant telalginite remains and minor terrestrial input, reflecting the early influence of water-body fluctuations on organic precursor composition. Type Ⅱ2 kerogen and coal samples predominantly generate methane-rich gas, indicating deposition in nearshore or terrestrially influenced, hydrodynamically active environments where organic matter is dominated by higher-plant lignin and cellulose, favoring methane generation during thermal evolution. Activation energy distributions further capture the manifestation of these genetic differences in thermal evolution behavior. Type I kerogen exhibits the narrowest activation energy range, reflecting high structural homogeneity and relatively low thermal stability. Type Ⅱ1 kerogen shows a slightly broader distribution, consistent with increased precursor mixing. Coal samples display both the highest activation energies and the widest distribution ranges, corresponding to their complex inertinite–vitrinite assemblages and high degrees of aromatic condensation, whereas Type Ⅱ2 kerogen falls between Type Ⅱ1 kerogen and coal, exhibiting distinct transitional characteristics. This study provides a robust basis for understanding differential hydrocarbon generation and accumulation mechanisms in lacustrine organic matter and offers important insights for comprehensive source rock evaluation within the complete petroleum system of the Songliao Basin.

Abstract Understanding shale pore structure across nano- to mesoscales is essential for reservoir evaluation, which supports effective geological exploration and development. However, this understanding remains constrained by data fragmentation across different methods and by the limited integration of small-angle neutron scattering (SANS), which can improve cross-scale shale pore structure characterization at high resolution and nondestructively. In this work, we developed AI-4-SPS, a comprehensive database system comprising a data set, an artificial intelligence (AI) knowledge extraction module, and an AI query agent. The data set compiles data over 250 shale samples from more than 160 publications. Samples cover major Chinese basins and U.S. basins. The data set includes mineralogy, total organic carbon, and porosity and connectivity data from SANS, mercury intrusion porosimetry, and nuclear magnetic resonance. In experiments, AI-4-SPS can assist in shale SANS experiment design, data interpretation, and data comparison with other pore structure characterization methods. In pore structure analysis, AI-4-SPS can assist with data comparison among multiple methods across different areas. Comparative analysis revealed similar SANS porosities between Chinese and U.S. samples. By integrating SANS and MIP porosity through overlapping nanoconnected pore volumes, we refined shale total porosity estimates and partitioned the pore size distributions. Comparison showed that Chinese shales exhibited higher pore connectivity, which was driven by nanoconnected pores. In contrast, meso-connected pores prevailed in U.S. samples, contributing to greater shale oil productivity. The flexibility of the AI knowledge extraction model enables extraction of any user-defined data from publications, including lithofacies characterization, fluid transport, and fracture characterization.

Accurate prediction of hydrocarbon composition is essential for evaluating hydrocarbon quality and recoverability. However, research on pre-drilling prediction of subsurface fluid phase behavior for medium to high-maturity shale oil remains limited. Given that compositional kinetics can effectively evaluate and predict the compositional evolution of shale oil and gas reservoirs, this study focuses on the first member of the Qingshankou Formation (K2qn1) in the Songliao Basin. Based on gold-tube hydrocarbon generation simulation experiments, a compositional generation and cracking kinetic model, and a methane correction model derived from pressurized coring, we accurately predicted the phase behavior of medium to high maturity shale oil in the Songliao basin. The results indicate that the difference in methane content between natural and experiment samples is not caused by migration-induced fractionation. Instead, it is likely due to the relatively high temperature and pressure in the experiments, which may cause hydrocarbon fluids to enter a single gas phase prematurely, thereby suppressing methane generation. The discrepancy between the corrected predicted phase diagram and the PVT experiment phase envelope is attributed to light hydrocarbon loss during PVT experiments, as supported by phase envelope simulations under varying degrees of light hydrocarbon depletion. The predicted phase diagram shows that the present day Gulong Sag is a volatile oil reservoir and that a single episode of hydrocarbon migration and fractionation occurred around 66 Ma. This study provides a basis for assessing the phase behavior, mobility, and recoverability of medium-to high-maturity shale oil and gas reservoirs under geological conditions.

Nuclear Magnetic Resonance (NMR) technology serves as a critical tool for fluid evaluation in shale reservoirs; however, its accuracy relies on reliable conversion of relaxation signals to fluid volume. Current research predominantly focuses on identifying hydrogen-containing components while neglecting systematic calibration of quantitative conversion relationships. This study establishes a free-state/nano-pore coupled calibration method, constructing a comprehensive calibration framework using multiple hydrogen-nucleus-density fluids (crude oil + formation water + crude oil components). Validation was achieved through fluid dynamic loss experiments on sealed core samples and distillation-extraction tests. Key findings include: (1) Free-state calibration reveals that the crude oil-formation water combination better replicates in-situ characteristics. The calibration coefficient kvalue increases from 3,590.9 to 6,027.1 (a 68 % rise) with thermal maturity (R0: 0.7 %-1.67 %), yet decreases from 4,350.8 to 3,816.5 (a 12.3 % reduction) with increasing salinity, showing statistically high consistency (R2 = 0.89) with the crude oil component calibration model; (2) Under shale nano-pore confinement, the calibration conversion coefficient (k) for crude oil decreases slightly (6.5 %), while that for formation water increases modestly (5.29 %); (3) Quantitative results from this calibration system demonstrate high consistency between NMR and distillation-extraction evaluations. This research overcomes prior limitations in free-state fluid calibration, elucidates quantitative regulatory patterns of thermal maturity and salinity on k-values, quantifies nano-pore confinement effects on conversion coefficients, and ensures accuracy via a dedicated calibration coefficient verification model. The framework advances shale fluid quantification from "empirical estimation" to in-situ precision quantification, providing technical support for target zone optimization.

To study the influence of magnesium alloy anisotropic deformation on damage behavior, the Hill48 yield criterion is applied to describe the anisotropic deformation, and three ductile damage criteria are used to predict the damage phenomenon. The parameters of the Hill48 yield criterion are calibrated by 0, 45, and 90° uniaxial compression stress–strain curves of ZA21EX magnesium alloy, and then, the compression experiment modeling is conducted based on the Hill48 yield criterion. As a comparison, the isotropic model is established using the compression stress–strain curve in the 0° direction. Considering the friction between the compression head and the contact surface of the compression samples, the stress–strain states of the Hill48 yield model and the isotropic model are significantly different, which affects the prediction of the cumulative damage values of the three ductile damage criteria. This paper analyzes the influence of the anisotropic yield criterion from two aspects: the integrand and the integral domain of the ductile damage criteria. Among them, the Freudenthal criterion and the Cockcroft and Latham criterion could correctly predict the initial location and the path of damage; the Rice and Tracey criterion predicts one more initial damage location than experimental results and cannot show the damage path clearly.

The Upper Triassic Xujiahe Formation (T(3)x) represents a critical terrestrial source rock system in the Sichuan Basin, exhibiting pronounced vertical and lateral heterogeneity. Previous stratigraphic subdivisions relied primarily on lithological correlations rather than a systematic sequence stratigraphic framework. This approach has led to significant inconsistencies in source rock evaluation. Furthermore, recent discoveries of large gas fields, coupled with data from newly drilled wells, necessitate a comprehensive reassessment of this system. In this study, we re-evaluate the geochemical characteristics and spatial distribution of these source rocks within a newly established sequence stratigraphic framework. This assessment utilizes a robust dataset comprising total organic carbon (TOC) content, Rock-Eval pyrolysis, and vitrinite reflectance (Ro) measurements. The results indicate that the source rocks of the New Member 5 (T(3)x(5)) in the slope belt of Central Sichuan exhibit the highest hydrocarbon generative potential. These rocks are characterized by high organic abundance (with 40% of samples showing TOC >= 2.0 wt.%), are dominated by Type III and II2 kerogen (humic-sapropelic), and have reached the mature to high-maturity stage (Ro ranging from 1.0% to 1.7%). Notably, the cumulative thickness of these high-quality source rocks reaches 100 similar to 150 m. Specifically, the T(3)x(5) intervals in the Qiulin and Tianfu areas are identified as the most favorable hydrocarbon-generating centers. This reassessment under the new stratigraphic division provides a refined theoretical basis for future exploration targeting the Xujiahe Formation in the Sichuan Basin.

Amounts and micro-distributions of adsorbed and free oil in shale matrix pores dramatically impact the mobility of shale oil, which are important aspects of understanding shale oil exploitation potential. Quantitative evaluation on the storage behavior of adsorbed and free oil has always been a challenge. In this study, a centrifugation and 2D NMR methods was employed to evaluate the amounts of adsorbed and free oil (taking n-dodecane as an example) for high-brittleness lacustrine shales from the Dongying sag of China. Based on the multi-temperature centrifugation test, adsorbed oil amount gradually decreases and free oil amount gradually increases as the temperature increases. In comparison, adsorbed and free oil amounts analyzed by 2D NMR differ significantly from the centrifugation results. Further, under the constraints of the centrifugation results, the 1D NMR T-2 spectrum was used to determine the micro-distributions of adsorbed and free oil. The results show that there are three peaks (P-1, P-2 and P-3) on the NMR T-2 spectra. Peak P-1 indicates adsorbed oil, and Peak P-3 has a free oil ratio of > similar to 80 %; while in peak P-2, adsorbed and free oil coexist, and the ratio of adsorbed oil increases rapidly with the decrease in T-2 value. According to the conversion law between the adsorbed and free oil, a prediction on the adsorbed and free oil amounts under in-situ reservoir temperature condition was achieved. The adsorbed (free) oil amount at reservoir temperature is overall close to the result obtained from the 2D NMR method at 20 degrees C. This research provides a systematic theory and method to insight into the storage capacities, micro-distributions and conversion law of adsorbed and free oil in shale matrix pores.

Shale laminae record depositional processes and exert a fundamental influence on pore systems, which are jointly shaped by diagenesis, hydrocarbon generation, and tectonism. Understanding lamina-scale heterogeneity is therefore essential for evaluating reservoir quality in lacustrine shale. This study investigates the Shahejie Formation shales of the Jiyang Depression using integrated petrographic observations, SEM imaging, and quantitative image analysis. Lamina types are classified on the basis of rock composition and carbonate mineralogy. To further reveal their reservoir significance, we propose a framework of Composition-Structure Units (CSUs), which is used to characterize the roles of different lamina types in controlling pore development and reservoir quality. Results show that clay-rich and micritic calcite laminae are enriched in organic matter and act as hydrocarbon-generating layers; felsic-rich, sparry calcite, and dolomitic laminae contain mesoporedominated reservoirs functioning as hydrocarbon-storage layers; and mixed mineral laminae integrate diverse minerals and organics with multi-modal pore systems, demonstrating self-generation and self-storage potential. Representative lamina associations, such as clay-rich + felsic-rich + sparry calcite + mixed mineral laminae, form favorable generation-storage-migration configurations. These associations delineate advantageous lithofacies for shale oil enrichment and provide a practical reference for exploration and development. By highlighting the coupling relationships between laminae types, CSUs, and pore structures, this study offers new insights into reservoir quality assessment in lacustrine shale.

The coexistence of adsorbed and free gas in nanopores is an important characteristic in shale gas reservoir, while the coexistence mechanism between adsorbed and free gas is still unclear. Gas adsorption ratio (GAR) can be utilized as a characteristic parameter of reflecting the coexistence of adsorbed and free gas in nanoporous shales. In this study, we developed a theoretical model to describe the GAR according to the quantum physisorption theory, and established an experimental method for evaluating the GAR using two shales from the southern Sichuan basin of China. Further, the coexistence mechanism of adsorbed and free gas in nanoporous shales was investigated by experimental data and the theoretical model. Key findings are as follows: (1) the GAR is equal to P1 x P2, where P1 is the probability of achieving adsorption of each molecule; P2 is the probability of gas molecules participating in adsorption. The P2 is primarily impacted by the minimum potential energy unit (E0), while the P1 is mainly impacted by gas temperature. (2) Under experimental temperature (30.6 degrees C) condition, GARs were obtained as 80.06 % (core S1) and 77.85 % (core S2). During the whole isothermal adsorption process, about 81-83 % of gas molecules participate in adsorption, and the probability of achieving adsorption for each molecule participating in adsorption is about 0.95-0.96, which microscopically explains the high GAR values. (3) The GAR is independent of gas pressure during isothermal adsorption process. Gas temperature is the most important factor leading to the conversion between adsorbed gas and free gas and plays a dominant role in the GAR variation. This study is of great help to re-understand the microscopic occurrence of methane in shale nanopores.