The presence of shale pore water significantly affects the occurrence and flowability of shale oil, thereby impacting oil recovery. Current experiments encounter obstacles, including the disruptions of the oil occurrence state during drilling, exposing and core sampling, and the inadequacies of current microscopic techniques in precisely characterizing the occurrence and flow properties of shale oil in nanopores. In this study, the occurrence and flow characteristics of shale oil in both kerogen and illite nanopores are investigated using Molecular Dynamics simulations, and the impact of water content was considered. Due to multicomponent competitive adsorption, different components in shale oil exhibit varying flowability. When the pressure gradient increases from 5 MPa center dot nm-1 to 10 MPa center dot nm-1, the flow velocity of light hydrocarbons in kerogen pores rises by 192.8%, while heavy hydrocarbons increase by 168.7%. However, resins and asphaltenes adsorb up to 100% in pores, confining them to the adsorption layer and significantly limit mobility. Due to wettability differences, water forms clusters in kerogen pores, which impedes the flow of heavy hydrocarbons, ultimately leading to a reduction in the total mobility of the shale oil. Water forms films in the illite pores, when water content exceeds 20%, water in the illite exists as water bridges, which impede shale oil flow by occupying pore volume. This work is expected to establish a theoretical foundation for evaluating the sweet spots in water-bearing shale considering both the mobility and producibility of shale oil, and provide valuable insights for the development of flow models in nanoscale porous media in shale.

The occurrence characteristics of pore fluids in shale are closely related to the economic value of shale oil. However, fluid loss from cores inevitably occurs during the process of retrieval from the subsurface to laboratory conditions. Furthermore, the complex pore structure and diverse lithology of shale make the characteristics of pore fluid occurrence and the controlling factors unclear. This study takes Jiergalangtu Sag in the Erlian Basin as an example. An innovative nuclear magnetic resonance (NMR) fluid restoration method has been used to calibrate and investigate the contents and occurrence characteristics of the original and in situ pore fluids. Combined with XRD, Rock-Eval pyrolysis, scanning electron microscopy (SEM), and low-temperature nitrogen adsorption/desorption (LTNA/D), the effects of factors such as mineral composition and pore structure on fluid occurrence have been elucidated. The results indicate that the samples are predominantly argillaceous-rich, with a small amount of felsic-rich and argillaceous lithologies. The pore system is mainly composed of interparticle pores associated with quartz and intraparticle pores within clay minerals, accompanied by a few microfractures. The combination of NMR T2 measurements with SEM and LTNA/D effectively characterizes the full-scale pore size distribution (PSD), which is mainly concentrated within the micropores and minipores. The NMR T1-T2 method can accurately quantify the pore fluids in the selected samples. Approximately half of the capillary-bound water, one-fifth of the capillary-bound oil, and nearly all of the movable oil have been depleted in the as-received (AR) samples. The free oil quantified by NMR is generally higher than that obtained from multistage pyrolysis, while the adsorbed oil exhibits an opposite trend. Organic matter directly controls the oil content, but excessive organic matter restricts oil mobility. Pore water and oil distributions are strongly related to minerals and pore structures. Capillary-bound water and adsorbed oil primarily occupy the micropores and minipores within clay minerals as well as the surfaces of clay minerals. Capillary-bound oil is predominantly enriched in mesopores, and movable oil is generally hosted in macropores. In addition, pore water has a remarkable impact on shale oil occurrence. Specifically, adsorbed oil is the most severely affected; capillary-bound oil is also significantly sensitive to pore water, whereas movable oil is scarcely influenced. This study enhances the understanding of the occurrence mechanisms of pore fluids and provides a scientific reference for evaluating the economic value of shale oil in Jiergalangtu Sag.

Evaluating the adsorbed gas ratio (AGR) in the cumulative/daily production of shale gas is essential for optimizing development strategies, but no widely accepted method exists in the industry. The isotope fractionation method has emerged as a potential tool to achieve this goal. This study conducted isotope fractionation experiments on full-diameter shale under overburden pressure conditions during the shale gas depletion development. The results demonstrate that carbon and hydrogen isotopes during shale gas production exhibit a three-stage fractionation behavior, characterized by "stable (I)-decreasing (II)-increasing (III)". On this basis, an innovative carbon isotope fractionation model for 12CH4 and 13CH4 during mass transport in the dual-porosity medium was established, which effectively reduced the multi-solution of traditional numerical models by simultaneously matching the experimental data of production, pressure, and delta 13C1 value. Quantitative calculations indicate that in Stage I of the isotope fractionation, fracture gas is dominant. In Stage II, the produced gas is contributed by both fracture gas and matrix gas, with free gas dominating the matrix gas and adsorbed gas being secondary (the turning point of Stage II and Stage III (P2) corresponds to an AGR of 48.30% in daily gas production), and a large amount of adsorbed gas still not effectively utilized (P2 corresponds to an adsorbed gas recovery ratio of 18.84%). Starting from Stage III, adsorbed gas gradually replaces free gas and assumes a dominant role. This study is crucial for understanding the dynamic fractionation mechanism during isotopic molecule transport in complex pore-fracture systems and provides technical support for the optimization of development plans.

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.

Understanding the controls on organic matter enrichment in lacustrine shales is a fundamental issue in petroleum geology. Although organic matter enrichment in large, relatively stable lake basins has been well studied, the mechanisms controlling enrichment in small fault-controlled basins remain poorly understood. To address this gap, this study investigates the fourth member of the Cretaceous Aershan Formation (FMAF) in the E'rennaoer Sag, Erlian Basin, as a representative case of a tectonically active lacustrine system. The FMAF in the E'rennaoer Sag is an important lacustrine shale source rock in the Erlian Basin. This study aims to reconstruct its depositional environment and clarify the mechanisms controlling organic matter enrichment. Comprehensive geochemical analyses, including total organic carbon (TOC), Rock-Eval pyrolysis, elemental ratios, and gas chromatography-mass spectrometry (GC-MS) biomarkers, were conducted. The results indicate that the FMAF was deposited under a semiarid to arid paleoclimate, with semi-saline to saline water conditions, and predominantly anoxic bottom waters. Contrary to previous assumptions of overall shallow settings, the FMAF was mainly formed in a relatively deep lacustrine environment, with localized short-term shallowing driven by tectonic and hydrological fluctuations. Organic matter is dominated by Types II1-II2 kerogen derived from mixed terrestrial and algal inputs, and the generally low-TOC content reflects limited primary productivity. Overall, organic matter enrichment in the FMAF was controlled primarily by preservation under reducing, stratified water-column conditions, whereas productivity increases played only a secondary role. These findings enhance the understanding of shale oil accumulation mechanisms in fault-controlled lacustrine basins.

Recent exploration highlights the Gulong Sag as a promising target for tight oil in the Fuyu oil layer. However, the distribution of high-quality reservoirs remains poorly understood due to complex depositional and diagenetic controls, posing significant exploration risks. To address this, this study integrates petrological, mineralogical, and pore structure analyses to elucidate the genetic mechanisms of reservoir quality and identify favorable exploration targets. The sandstones are predominantly fine-grained lithic arkoses and feldspathic litharenites, characterized by abundant volcanic lithic clasts and muddy matrix. Four diagenetic facies were identified based on diagenetic assemblages and pore evolution. The chlorite pore-lining facies and moderate compaction-dissolution facies exhibit the highest reservoir quality (avg. porosity of 10.42% and 9.79%, respectively), benefiting from chlorite coatings that inhibited quartz overgrowth and intense dissolution that created secondary porosity. In contrast, the tightly compacted facies and carbonate-cemented facies represent unfavorable reservoirs (avg. porosity of 7.02% and 6.17%, respectively) due to the occlusion of pore throats by muddy matrix and early carbonate cements, respectively. The distribution of these facies is governed by the coupling of sedimentary environment and diagenetic alteration. Benefiting from superior sedimentary conditions and proximity to source rocks, the first member of the Fuyu oil layer developed extensive favorable facies (chlorite pore-lining facies and moderate compaction-dissolution facies), making it the primary exploration target. This study demonstrates how depositional compositions and diagenetic processes jointly control reservoir quality in tight sandstones, providing important insights for the exploration of analogous tight oil reservoirs.

Understanding the occurrence and enrichment mechanisms of shale oil is essential for the effective exploration of continental basins with complex reservoir characteristics. In this study, an integrated approach combining nuclear magnetic resonance (NMR) with fluid restoration techniques, Rock-Eval pyrolysis, total organic carbon (TOC) analysis, X-ray diffraction (XRD), crude oil composition analysis, and microscopic observation was used to investigate the shale in the Erennaoer Depression of the Erlian Basin. Based on the innovative in-situ fluid content characterization method, the shale micromigration characteristics were quantitatively analyzed by micromigrated hydrocarbons (Delta Q). The coupling relationship between shale pore fluid content, pore structure, and mineral composition was analyzed, elucidating the shale pore fluid occurrence mechanisms. Three dominant shale lithofacies, felsic-rich, felsic, and calcareous, were identified, with interparticle pores at quartz grain edges serving as the primary storage space. Shale oil occurrence is jointly governed by lithofacies, pore structure, and hydrocarbon micromigration. While most samples exhibit minimal micromigration (-200 mg/g TOC < Delta Q < 107 mg/g TOC), interlaminar redistribution is common. In organic-lean shales (TOC < 0.7 %), hydrocarbon generation capacity limits oil content, and no extra-micromigration occurs. In organic-rich shales (TOC >0.7 %), excess hydrocarbons are expelled and stored in interparticle pores of quartz laminae, with free oil content positively correlated with the development of meso- to macropores. Notably, felsic-rich shales with low clay content show evidence of intra-micromigration and preferential accumulation of light-saturated hydrocarbons (C-14-C-18), resulting in Delta Q < -200 mg/g TOC, OSI > 200 mg/g TOC, and T-max < 425 degrees C. These hydrocarbons form multi-scale source-reservoir coupling systems through selective micromigration into adjacent quartz laminae and felsic-rich shale interbeds with low clay, while heavier fractions remain in organic-rich layers. These findings provide new insights into the spatial distribution of shale oil and identify favorable sweet spots in the Erlian Basin, offering a foundation for resource assessment and development strategies in similar shale oil basins.

The pore fluid occurrence predominantly restricts shale oil production. Few studies have addressed both pore oil and water concurrently. In an effort to delineate the distribution of pore fluids within shale oil reservoirs, this study collected diverse shale samples from the Qingshankou Formation in the Sanzhao Sag, Songliao Basin, China. The in-situ pore fluids were initially resurrected under equilibrium moisture conditions and subsequently saturated with light oil. A comprehensive suite of analytical techniques was employed in tandem, encompassing total organic carbon (TOC), Rock-Eval, X-ray diffraction (XRD), scanning electron microscopy (SEM), low-temperature nitrogen adsorption-desorption, and nuclear magnetic resonance (NMR). The occurrence characterizations of pore fluids were clarified by NMR T1–T2 spectra across various states, shedding light on the governing factors. A pattern of pore-fluid occurrence in shale oil reservoirs was proposed. Results indicate that NMR T1–T2 combined with water and oil restoration effectively assesses the distribution of in-situ pore fluids. Capillary-bound water primarily contributes to pore fluids, with nearly half being depleted at the as-received state. Shale oil mainly comprises capillary-bound oil, succeeded by adsorbed and movable oil. The alterations in shale oil occurrence characteristics are synchronous with the depletion of pore fluids. NMR T1–T2 primarily detects the adsorbed oil in shale pores, whereas Rock-Eval is capable of quantifying oil adsorbed on pore surfaces and absorbed within organic matter. NMR T1–T2 offers a more precise technique for quantitatively evaluating shale pore fluids. Micropores (<25 nm) and minipores (25–100 nm) are primarily saturated with capillary-bound water, accompanied by a minor fraction of adsorbed oil. Capillary-bound and movable oil are primarily distributed within mesopores (100–1000 nm) and macropores (>1000 nm), respectively. Consequently, adsorbed oil is significantly influenced by pore water, followed by capillary-bound oil, while movable oil remains largely unaffected. Felsic-rich (FR) shales may represent the optimal lithology for shale oil enrichment, characterized by the development of interparticle pores, a lower Brunauer-Emmett-Teller (BET) specific surface area, and abundant meso- and macropores. These insights into the characteristics of pore fluids in shale oil reservoirs could bolster shale oil exploration in the Sanzhao Sag.

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.

Porosity is a fundamental parameter in characterizing the pore structure of shale oil reservoirs, as it directly affects the accuracy of shale oil reserve estimations. Despite the availability of various measurement techniques, accurately quantifying porosity in such reservoirs remains a significant challenge. In an effort to identify the most effective porosity testing method, this study collected samples from four shale oil reservoir intervals across five sags in three different basins. Five porosity testing methods were employed to detect shale porosity, including helium porosity, low-temperature nitrogen adsorption-desorption (LTNA/D), oil-saturated wetting, and nuclear magnetic resonance (NMR) T2 and T1-T2. NMR T2 porosity acted as a touchstone against which the other methods were compared. The pros and cons of each evaluation technique were explored to select the optimal analysis method for shale oil reservoirs. Results indicate that LTNA/D porosity, derived from powdered samples, commonly fails to reflect shale porosity effectively. Helium porosity, widely used for detecting nanoscale pores, is constrained by extended equilibration times and the retention of residual pore fluids after oil washing and drying, leading to systematic underestimation. In contrast, oil-saturation wetting and NMR T2 exhibit strong agreement, both reflecting pore fluid content. However, residual fluid distribution can also impact the accuracy of NMR T2 measurements. NMR T1-T2 is an innovative technique for quantitatively evaluating shale oil reservoirs. NMR T1-T2 spectrum at the water and oil restoration state can provide accurate shale porosity. NMR T1-T2 porosity estimates generally align with those obtained from T2 porosity. When residual pore fluids are not entirely removable, the NMR T1-T2 method offers a more realistic porosity assessment. The NMR technique is recommended for evaluating the porosity of shale oil reservoirs, and the combination of T2 and T1-T2 can accurately determine the effective and total porosity. This research serves as a valuable reference for accurately determining porosity in shale oil reservoirs. (c) 2025 The Authors. Publishing services by Elsevier B.V. on behalf of KeAi Communications Co. Ltd. This is an open access article under the CC BY-NC-ND license (http://creativecommons.org/licenses/by-ncnd/4.0/).

Reservoir permeability is a critical parameter governing shale-oil mobility. However, permeability values obtained by conventional methods are often overestimated due to fractures, leading to a poor relationship between permeability and pore-throat structure. This study presents an approach to correcting measured permeability by eliminating fracture-related effects. A suite of shale samples with varying lithologies from the Erlian Basin was collected, along with tight sandstones for comparative analysis. Helium porosity, permeability, and mercury intrusion capillary pressure (MICP) measurements were conducted to characterize the pore structure and transport properties. Results demonstrate that matrix permeability, estimated from MICP-derived mercury injection curves, is significantly lower than conventionally measured permeability. A strong correlation was observed between matrix permeability and average pore-throat radius, in contrast to the weak relationship shown by measured permeability. The corrected permeability, taken as the apparent permeability primarily related to pore-throat structures, was subsequently derived from the MICP-based matrix permeability. The corrected apparent permeability correlates well with average pore-throat diameter and porosity, especially in shale reservoirs. The findings provide a basis for refining reservoir classification criteria and offer insights into the spatial distribution of high-permeability zones. This work enhances the understanding of tight shale permeability and contributes to a more accurate assessment of shale-oil producibility.

Accurate prediction of shale pore volume underpins unconventional recovery and CO2 storage, yet limited core datasets and cross-basin covariate shift challenge generalization. We compile 180 samples from multiple Chinese basins with vitrinite reflectance (Ro), total organic carbon (TOC), and seven minerals, and benchmark Random Forest, Extreme Gradient Boosting (XGBoost), Light Gradient Boosting Machine, and Multilayer Perceptron under repeated stratified splits, within-basin holdouts, learning curves, and graded-noise tests. Using a composite of the coefficient of determination (R2), mean squared error (MSE), mean absolute error (MAE), mean absolute percentage error (MAPE), mean bias error (Bias), and Spearman's rank correlation coefficient (rho), XGBoost (R2 = 0.9778, MSE = 1.4473, MAE = 0.8249, Bias = 0.0034, rho = 0.9890) offers the best accuracy-robustness trade-off; it maintains stable performance under mild feature noise and shows consistent gains with increasing training size. We therefore perform post-training uncertainty quantification for XGBoost, using calibrated prediction intervals via quantile regression that achieve 97.22% empirical coverage at 98% nominal confidence with adaptive widths. For deployment, we apply XGBoost to the Hongxing area, where it highlights Subunit 3 in the Second Member of the Wujiaping Formation and the First Submember of the Fourth Member of the Maokou Formation as preferred targets, with mean pore volumes of 11.65 and 11.49 & times; 10-3 cm3/g, respectively. The workflow delivers a scalable, interpretable, and process-consistent approach for basin-level screening while clarifying extrapolation risk. SHAP analysis identifies Ro as the dominant control, with geologically consistent interactions among TOC-quartz/clay and dual calcite/feldspar effects reflecting compaction resistance, dissolution, and cementation.

Efficient exploration and development of shale oil heavily rely on the precise evaluation of multiphase pore fluids within reservoirs. Currently, two-dimensional (2D) nuclear magnetic resonance (NMR) T1-T2 spectra effectively characterize multiphase pore fluids, but prolonged acquisition times restrict their routine application. Conversely, one-dimensional (1D) NMR T2 measurements offer rapid acquisition but suffer from severe signal overlap. To address this limitation, a T2 spectral fluid identification method based on a skewed Gaussian mixture model is introduced in this study. NMR T2 and T1-T2 experiments were conducted on shale samples from the Qingshankou Formation in the Sanzhao Sag under five specific states: as received (AR), water restoration (WR), water and oil restoration (WOR), solvent extracted and dried (Dry), and oil saturated (SO). By extracting T2 projection spectra from the 2D T1-T2 spectra, conversion coefficients between the projections and 1D T2 spectra were established to decouple the overlapping fluid signals. The results indicate that, in the SO state, the ratio of adsorbed oil to bound oil in the 1D T2 spectrum is 2.4999 times that in the T2 projection spectrum, with a conversion coefficient of 0.1179 determined for the (pseudo)-solid component. By applying these conversion factors, the pore fluid signals within the T2 spectra at the WOR state were successfully identified. Under the WOR conditions, capillary-bound water exhibits the highest conversion coefficient (0.5171). Notably, the presence of pore water significantly lowers the conversion factors for adsorbed and bound oil (0.3663 and 0.1491, respectively) compared to the SO state, whereas movable oil demonstrates no significant correlation. Furthermore, the pore size distributions associated with each fluid type were delineated. These findings facilitate more accurate identification of multiphase pore fluids from 1D T2 spectra, providing novel insights into NMR-based fluid evaluation in shale oil reservoirs.

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.

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.

The substantial resource capacity and commercial extraction prospects of the Cambrian Qiongzhusi shale have been increasingly highlighted by recent exploration milestones in the Ziyang region of the Sichuan Basin. To elucidate the in situ gas-content characteristics and their controlling factors across different sublayers of the Qiongzhusi Formation shale, this study conducted field desorption experiments, physical property measurements, and organic petrographic analyses on 211 shale samples from the Ziyang area. A three-dimensional (3D) continuous flow model was constructed based on Fick's diffusion law and Langmuir isothermal adsorption theory. Furthermore, an evaluation methodology for in situ gas content and the adsorbed/free gas ratio was established and validated against measured data from pressurized coring. Our findings suggest the following: (1) The field-desorbed gas content from samples of wells Z1 and Z2 is mostly below 0.4 m3/t, showing a distinct positively skewed distribution, and is positively correlated with total organic carbon (TOC) content and porosity. (2) The developed 3D continuous flow model for porous media incorporates both the actual core geometry and gas flow dimensionality. This overcomes the limitations of traditional gas content restoration methods in their theoretical basis (which considers only diffusion) and assumptions (a one-dimensional (1D) approximation of 3D flow). Calculations indicate that significant errors arise in the 1D continuous flow model when the core height-to-diameter ratio (H/2r) <= 5 (for shorter cores). (3) The USBM method exhibits substantial errors in evaluating in situ gas content, yielding an average value only one-third of that calculated by the 3D continuous flow model. A comprehensive evaluation of wells Z1 and Z2 shows that this error ratio is directly controlled by the gas loss proportion and indirectly influenced by parameters such as rock adsorption capacity and the gas diffusion coefficient. (4) The evaluated in situ gas content in wells Z1 and Z2 ranges from 1.84 to 9.13 m3/t (averaging 3.88 m3/t), with the adsorbed gas ratio (AGR) ranging from 2.3% to 94.7% (averaging 52.0%). The in situ gas content shows positive correlations with TOC content, effective porosity, and Langmuir volume (V L), while the AGR exhibits a negative correlation with effective porosity and a positive correlation with V L, which are identified as the main controlling factors governing the gas occurrence state. (5) An integrated analysis of vertical physical properties and in situ gas characteristics in wells Z1 and Z2 identifies sublayer 5 as the optimal "gas-bearing sweet spot". In well Z1, sublayer 5 is characterized by high TOC content (averaging 1.85%), large effective porosity (averaging 1.87%), and high in situ free gas content (averaging 1.47 m3/t). Similarly, well Z2 exhibits this "triple-high" characteristic (TOC averaging 1.85%, effective porosity averaging 2.70%, in situ free gas content averaging 3.87 m3/t). This study presents significant theoretical and technical insights into the enrichment mechanisms of deep shale gas and optimizing exploration and development strategies.

Quantifying how inorganic and organic porosity co-evolve in shale during burial and later uplift is a key scientific issue for constraining shale-gas occurrence, storage capacity, and enrichment mechanisms. Despite extensive studies, major uncertainties remain regarding (1) quantitatively separating compaction-driven inorganic pore loss from maturity-controlled organic pore generation and (2) restoring porosity under in situ effective stress through geological time. Here we develop an integrated quantitative framework for the Wufeng–Longmaxi shale gas reservoirs in the southern Sichuan Basin, China. Core samples from production wells, in which porosity is primarily controlled by total organic carbon (TOC), were selected to minimize the interference of mineral composition and compaction heterogeneity. Using a TOC–porosity-intercept approach, inorganic porosity was calculated from the intercept of the porosity–TOC linear relationship and its burial evolution was reconstructed with a compaction model constrained by well burial histories. Organic porosity was quantified by extracting organic-matter surface porosity from field-emission scanning electron microscopy (FE-SEM) images using ImageJ, and a maturity-dependent organic porosity evolution model was established from samples spanning different thermal maturities. Total porosity evolution in the Luzhou, Changning, Weiyuan, and Western Chongqing blocks was reconstructed by integrating the inorganic- and organic-porosity models, and in situ porosity was further restored using pressure-confined porosity experiments. Results indicate that inorganic porosity decreases sharply with burial depth, from an initial value of ∼50% to 2.47%–4.05% at maximum burial, mainly controlled by mechanical compaction. Organic porosity increases after entering the hydrocarbon generation window and peaks at 1.54%–1.79%, reflecting pore generation during organic matter transformation. Consequently, total porosity declines to 4.16%–5.76% with increasing burial depth, demonstrating that compaction outweighs hydrocarbon-generation-related porosity creation. Restored in situ porosity fluctuates slightly during subsidence but exhibits an overall decreasing trend, reaching 2.34%–3.78% at maximum burial, and then shows only a modest rebound during late-stage tectonic uplift to 2.49%–4.17% at present. Uncertainties are quantified via bootstrap/Monte Carlo propagation and reported as 95% prediction intervals. These results highlight the coupled controls of compaction, hydrocarbon generation, and tectonic unloading on shale pore evolution and provide a quantitative basis for predicting the distribution of high-quality shale reservoirs.

Hydrocarbon resource potential evaluation represents the primary and core component of whole petroleum system studies. However, compared with the substantial progress achieved in understanding hydrocarbon generation mechanisms, quantitative assessments of hydrocarbon generation amounts from source rocks in the Songliao Basin remain relatively limited. Given that the genetic method is capable of comprehensively reflecting both the intrinsic hydrocarbon generation potential and conversion efficiency of source rocks and is supported by robust geological principles, this study was conducted within a genetic framework. Stratigraphic data and lithological descriptions from more than 2000 wells in the northern Songliao Basin, logging data from 387 wells, and measured basic geochemical data from 201 wells were integrated. Combined with the Delta logR method, original hydrocarbon generation potential restoration techniques, and results from thermal simulation experiments, the planar distributions of key geochemical parameters of the first member of the Qingshankou Formation were systematically characterized. On this basis, the hydrocarbon generation potential and total hydrocarbon generation amounts of different structural units within the Songliao Basin were quantitatively evaluated. The results indicate that the cumulative hydrocarbon generation of the first member of the Qingshankou Formation reached approximately 506.55 & times; 108 t. Among the structural units, the Qijia-Gulong Sag contributed 266.13 & times; 108 t, the Sanzhao Sag 132.71 & times; 108 t, the Longhupao Terrace 66.81 & times; 108 t, and the Daqing Placanticline 40.90 & times; 108 t. These results demonstrate significant heterogeneity in hydrocarbon generation capacity among different structural units, with the Qijia-Gulong Sag identified as the most important hydrocarbon generation center in the study area. This study provides a critical quantitative foundation for whole petroleum system research in the northern Songliao Basin. It not only supplies essential data support for subsequent resource apportionment of conventional and shale hydrocarbons but also offers important constraints for analyses of reservoir-type distribution and hydrocarbon accumulation mechanisms.

Carbon isotope fractionation of methane during gas-water two-phase flow in low-permeability reservoirs is crucial for interpreting natural-gas geochemical signatures and evaluating well production status; however, existing models are mainly developed for a single gas phase and cannot account for the influence of water phase on gas migration and isotope fractionation. To fill this gap, this study, for the first time, developed a carbon isotope fractionation model for gas-water two-phase flow (GWF-CIF model) by establishing a coupled system of partial differential equations that integrates gas-water two-phase flow dynamics, effective-stress evolution, real gas effect, and multi-mechanism gas transport, while systematically accounting for the differential diffusion and adsorption/desorption behavior of 12CH4 and 13CH4. This model enables simultaneous prediction of gas-water two-phase production behavior and dynamic isotope fractionation, providing a novel quantitative framework for reserve evaluation and development optimization of low-permeability gas reservoirs. The model reliability was validated using field test data from two deep coalbed methane (CBM) wells in the Daji area of the Ordos Basin, China. History matching indicates that the model effectively reproduces the evolution of cumulative gas production, cumulative water production, and methane carbon isotopic composition. Simulation results demonstrate the characteristic “water production preceding gas production” behavior and a three-stage methane isotope evolution characterized by an initial stable (Stage I), a middle decreasing (Stage II), and a late increasing (Stage III). Initial water saturation significantly affects isotope fractionation; higher water saturation reduces the fractionation magnitude and delays the timing of turning points for various stages. The 20-year forecast indicates total gas productions of 1229.5×104 m3 and 992.8×104 m3 for the two wells, with free gas contributing 28.4% and 34%, respectively. During the first two stages of isotope fractionation, produced gas is dominated by free gas; after entering the third stage, the adsorbed-gas contribution gradually exceeds that of free gas. The turning point of carbon isotope fractionation can serve as a key indicator for identifying transitions in gas production mechanisms and provides a scientific basis for timing production-enhancement measures. This study provides a theoretical basis for interpreting gas-water flow behavior and isotopic geochemical characteristics in low-permeability gas reservoirs, with significant implications for optimization strategies including CO2 injection, casing-pressure reduction, and secondary refracturing.