Accurate evaluation of the brittleness index (BI) is crucial for optimizing hydraulic fracturing during the extraction of hydrocarbon fluids in hybrid shale reservoirs, yet conventional petrophysical methods face limitations in scalability and generalizability. This study presents an integrated evaluation framework utilizing four ensemble learning algorithms—Random Forest (RF), AdaBoost, XGBoost, and CatBoost—to predict BI from well logging data in the second member of Funing Formation (E1f2) shale from the Gaoyou Sag, Subei Basin, eastern China. A dataset comprising 1295 well logging data points and mineralogical compositions from 174 core samples was used to train and validate the models. These models were optimized by Particle Swarm Optimization (PSO) to resolve nonlinear interdependencies between logging responses and mechanical brittleness. Comparative analysis demonstrates that RF achieves the highest prediction accuracy (R2 = 0.84 on the test set), outperforming CatBoost (R2 = 0.79), AdaBoost (R2 = 0.71), and XGBoost (R2 = 0.65). The superior performance of RF is attributed to its robustness against overfitting and its ability to effectively capture complex nonlinear relationships in logging responses. SHapley Additive exPlanations (SHAP) analysis identifies acoustic (AC) and resistivity (Rt) logs as the most influential predictors, reinforcing their strong physical correlations with mineralogical brittleness. This study represents the application of ensemble learning for BI evaluation in the Funing Formation shale, providing a cost-effective alternative to laboratory-based methods and demonstrating the viability of data-driven approaches for fracturability assessment. The proposed framework offers significant potential for extension to other unconventional reservoirs, contributing to enhanced hydraulic fracturing design and improved reservoir development strategies for unconventional hydrocarbon fluid development.

Located within the Subei Basin, the Gaoyou Sag is abundant in hydrocarbon resources and exhibits significant potential for shale oil exploration and development. However, the organic matter enrichment patterns and palaeoenvironmental evolution of the second member of the Funing Formation (E(1)f(2)) in the Huazhuang area remain poorly understood, particularly regarding the complex origins of organic matter and their coupling with sedimentary environments. To address these issues, representative shale and crude oil samples from the E(1)f(2) interval were systematically analysed using gas chromatography-mass spectrometry, X-ray diffraction and inductively coupled plasma mass spectrometry. The results show that the average pristane/phytane (Pr/Ph) ratio is 0.58, the V/Cr ratio is close to 1 and the average V/(V + Ni) ratio is approximately 0.7. The Sr/Cu ratio is significantly greater than 10 in the lower section but markedly less than 10 in the upper section. The Sr/Ba ratio ranges from 0.06 to 1.23, progressively decreasing from bottom to top. A comprehensive analysis indicates that the lower E(1)f(2) was deposited in a saline lacustrine anoxic environment, while the upper E(1)f(2) transitioned to brackish-water conditions under a warm and humid climate. Based on the distribution of the C-27-C-29 steranes, the organic matter is determined to have been mainly derived from a mixture of lower aquatic organisms and terrestrial higher plants. The warm-humid climate, decreasing water salinity and bottom-water anoxia jointly promoted the enrichment and preservation of organic matter. This study establishes an organic matter enrichment model co-controlled by palaeoclimate and palaeosalinity, providing a theoretical basis for shale oil exploration in similar lacustrine basins.

Hydraulic-fracture transmission across lithologic interfaces governs fracture-height growth and reservoir connectivity in shale–sandstone interbedded reservoirs, yet the coupled effects of mechanical contrast, interface properties, layer geometry, and operational parameters remain insufficiently quantified. A two-dimensional plane-strain hydraulic-fracturing model was developed in ABAQUS by coupling Biot poroelasticity, cohesive-zone damage, and fracture-fluid flow. The model explicitly represents thin, alternating continental shale–sandstone layers, lithology-dependent in situ stress and stiffness, and cohesive interfaces; its implementation was assessed against the KGD solution and published layered-rock fracture morphologies. Under the simulated conditions, increasing the shale-to-sandstone elastic-modulus ratio from 0.4–0.5 to 0.6–0.8 reduced the number of penetrated layers from eight to six. Increasing tensile strength from 4 to 16 MPa reduced the number of penetrated layers from ten to six and the final fracture length from 32 to 21 m, while increasing the maximum aperture from 6.75 to 9.02 mm. A sandstone interlayer thickness of approximately 3 m marked a transition in the present parameter set rather than a universal threshold. Sandstone-centered perforation and higher injection rates promoted vertical connectivity, whereas very high fluid viscosity increased near-wellbore aperture but restricted long-distance fracture-height growth. These results provide a mechanics-based framework for optimizing perforation placement and stage-specific fluid design in continental interbedded shale reservoirs.

Deep-to-ultra-deep marine carbonate reservoirs represent an important frontier for hydrocarbon exploration in the Tarim Basin, yet fluid sources and accumulation processes in the Ediacaran (Sinian) succession remain poorly constrained due to extreme burial depth and complex tectono-thermal evolution. Here, we investigate fracture-vug reservoirs of the Sinian Qigebulake Formation in Well LT3 (Tabei Uplift) using an integrated dataset including petrography and cathodoluminescence, fluid-inclusion microthermometry, fluorescence and Raman spectroscopy, in situ major/trace element analysis and C-O-Sr isotope geochemistry, and LA-ICP-MS carbonate U-Pb dating of authigenic minerals. The paragenetic sequence comprises early dolomite (Dol-I), later dolomite (Dol-II), co-precipitated calcite (Cal-I) and quartz (Qtz-I), and late solid bitumen (Bit). Dolomite veins show PAAS-normalized REE patterns and Sr-87/Sr-86 ratios (0.70918-0.70984; average 0.70942) comparable to the surrounding Sinian marine wall rocks, indicating precipitation from diagenetic fluids dominated by closed-system water-rock interaction. In contrast, Cal-I displays LREE enrichment, pronounced positive Eu anomalies (delta Eu = 4.91-7.21), radiogenic Sr-87/Sr-86 ratios (0.71161-0.71417; average 0.71256), and negative delta O-18(VPDB) values (down to -9.439 parts per thousand), suggesting a large-scale influx of deep-seated, high-temperature, Sr-rich hydrothermal fluids likely linked to fault-assisted fluid circulation. Fluid inclusions record four hydrocarbon charging episodes, evolving from lower- to higher-maturity oils and ultimately to dry gas. Dol-II hosts pale-yellow to pale-blue oil inclusions, whereas Cal-I and Qtz-I predominantly contain deep-blue oil inclusions and methane-rich gas inclusions (Raman peak near 2917 cm(-1)). Carbonate U-Pb ages constrain dolomite precipitation to the Middle Ordovician (similar to 468-463 Ma) and hydrothermal-related carbonate filling to the Early Triassic (similar to 247-244 Ma). Collectively, these results support a time-resolved evolution in which early diagenetic fluid circulation in a marine carbonate system was overprinted by a later hydrothermal pulse that modified pore structures and thermal conditions, followed by late-stage deep burial leading to cracking of retained liquids, widespread bitumen formation, and methane charging. This framework provides new information on the constraints for fluid-rock interaction and hydrocarbon evolution in deep marine carbonate successions.

The widely applied empirical Darcy's law in geotechnical engineering faces significant chal-lenges in describing low-velocity flow processes in low-permeability porous media suchas tight sandstones containing irreducible water. A deep understanding of low-velocitynon-Darcy two-phase flow behavior in low-permeability porous media is essential forevaluating the development of ultra-low-permeability reservoirs. In this study, seven low-permeability three-dimensional digital cores with distinct pore structures were constructedbased on realistic ultra-low-permeability sandstones. Using the lattice Boltzmann method,pore-scale investigations of water displacing oil were conducted. Low-velocity two-phaseflow behavior under varying wettability conditions, pore structures, and fluid viscositieswas simulated. The underlying mechanisms of low-velocity non-Darcy flow in ultra-low-permeability sandstones were examined, leading to a modified low-velocity non-Darcyflow equation. This improved model was subsequently applied to numerical simulations ofultra-low-permeability reservoirs. The results demonstrate that non-Darcy effects manifestprimarily as nonlinearities in seepage curves, representing a marked departure from con-ventional Darcy's law. Low-velocity non-Darcy (LVND) flow is predominantly constrainedby the influence of complex pore-throat structures and capillary forces on fluid distribution.The dynamic equilibrium among capillary forces arising from residual water saturation,viscous forces, and pressure gradients constitutes the fundamental mechanism governingthe onset of LVND flow. Enhanced nonlinear behavior is observed with increasing viscosityof the invading phase and elevated capillary forces. Substantial discrepancies in reservoirproduction dynamics are identified between LVND and classical Darcian regimes. Throughpore-scale numerical simulations, this study systematically elucidates LVND behavior dur-ing bi-phasic flow in low-permeability porous media, while identifying critical controllingfactors. These findings provide scientific rationale and technical support for addressinggeological engineering challenges in tight sandstone formations.

The dryness of natural gas fundamentally reflects the relative abundance of methane versus heavier hydrocarbons, with ethane being the most diagnostic component in methane-rich systems. Therefore, quantitatively determining ethane content in single gaseous hydrocarbon fluid inclusions enables reconstruction of a paleo dryness coefficient recorded by the trapped gas, and provides a direct basis for evaluating compositional fractionation during migration and charge. Here we develop a micro-Raman quantitative workflow for CH4-C2H6 mixed-gas inclusions, using systematic Raman responses of ethane and methane to achieve in situ, non-destructive quantification of ethane, and thus paleo dryness reconstruction.,Calibration was performed using gas-mixture standards with compositions verified by gas chromatography, and instrumental wavenumber drift was corrected by neon-lamp referencing to ensure cross-run comparability. The experiments document clear, reproducible spectral trends: increasing ethane proportion causes a pronounced rise in the ethane-to-methane Raman intensity ratio, accompanied by diagnostic wavenumber migrations of the C–H stretching bands. Temperature- and pressure-related influences on peak position and intensity ratios show consistent directional behavior and can be constrained through calibration and correction, preventing environmental effects from being misinterpreted as compositional changes. The resulting quantitative relationships enable high-precision prediction of ethane/methane ratios within the calibrated range and allow calculation of inclusion paleo dryness coefficients. Application to natural gas inclusions from the study area reveals a systematic spatial ”drying” trend (progressively stronger methane dominance), consistent with migration-related compositional fractionation in tight carrier systems, and provides spectroscopic constraints on charge pathways and preferential migration fairways.

Determining the lower limits of pore and throat sizes for shale oil occurrence is essential for reservoir evaluation, yet existing methods yield a single fixed threshold that fails to capture the heterogeneity of interbedded systems. This study addresses this limitation through integrated characterization of 59 core samples from the Chang 7 Member, Longdong area, Ordos Basin, using high-pressure mercury injection (HPMI), low-temperature nitrogen adsorption (LTNA), nuclear magnetic resonance (NMR), and field emission scanning electron microscopy (FE-SEM). Shale oil predominantly occurs in clay-free dissolution and intergranular pores, with minimal retention in clay intercrystalline pores. Residual oil content shows significant positive correlations with medium pore-throat volume and macropore volume, and negative correlations with fractal dimensions. Based on fractal analysis of pore-throat and pore size distributions, the lower limits for pore-throat sizes mainly vary from 24 to 60 nm (average 43 nm) and pore sizes from 65 to 198 nm (average 138 nm) across samples. These ranges directly reflect pore structure heterogeneity quantified by fractal characteristics, and cannot be reduced to a single threshold without losing critical reservoir information. 2D NMR T1-T2 spectra established for this formation indicate that free oil constitutes 53.4%–82.6% (average 68.4%) of residual oil, substantially exceeding adsorbed oil. Higher quartz and lower clay contents, combined with lower fractal dimensions and better-connected pore networks, correspond to elevated oil content and enhanced free oil enrichment. These results provide a heterogeneity-aware framework for sweet spot identification in continental interbedded shale oil systems.

The innovative application of Raman spectroscopy for single-inclusion carbon isotope analysis represents a key advancement in understanding the migration and enrichment mechanisms of tight gas. In this study, Jurassic Shaximiao Formation reservoirs in the central Sichuan Basin were selected as the research focus. By combining single-inclusion carbon isotope analysis with paleo-pressure reconstruction of fluid inclusions, this work systematically investigates the migration pathways, enrichment patterns, and controlling factors of tight gas accumulation. The results reveal that variations in carbon isotope gradients indicate radial outward diffusion of natural gas from faults. The western Sichuan-Zhongjiang Fault and Bajiaochang Fault serve as the primary vertical migration conduits for natural gas, driven by ancient pressure differentials. Reverse faults formed during the Yanshan period are identified as critical pathways for hydrocarbon accumulation, while normal faults formed during the Himalayan period contribute to secondary migration and redistribution among sandbodies. This study offers a novel and effective approach to reconstructing the accumulation processes and enrichment mechanisms of tight gas reservoirs by integrating Raman-based single-inclusion carbon isotope analysis with paleo-pressure recovery techniques. These findings provide valuable insights into the mechanisms of tight gas enrichment and offer practical guidance for enhancing exploration and development of unconventional gas resources.

The Middle Ordovician Yijianfang Formation in the Shuntuoguole area of the Tarim Basin is an important ultra-deep carbonate exploration target, but favorable reservoir prediction remains difficult because effective storage space is controlled jointly by depositional architecture, diagenetic modification and strike-slip faulting. In this study, formability refers to the capacity of depositional fabrics to create initial pore space, modifiability refers to the potential for diagenetic processes to preserve or enlarge pores, and connectivity refers to the linkage of pores, vugs and fractures into an effective flow network. To clarify these controls, we integrate seismic interpretation, well-log correlation, core and thin-section observations, carbon–oxygen isotopes, elemental logging data and Dionisos-based 3D forward stratigraphic modeling. The Yijianfang Formation is divided into four third-order sequences (SQ1–SQ4), bounded by sequence boundaries (SB1–SB4) and containing maximum flooding surfaces (MFS1–MFS4). MFS4 is correlated with the regional T74 seismic marker. Depositional systems are dominated by restricted and open carbonate platforms, with intraplatform shoals, intershoal areas and lagoonal settings forming the main facies associations. Thickness differentiation and shoal development were strongest during SQ2–SQ3, indicating that these intervals provided the most favorable depositional basis for reservoir formation. Diagenetic modification was facies dependent. Grain-supported shoal facies commonly developed initial intergranular pores but were prone to cement occlusion, whereas micritic intershoal and lagoonal facies had poorer primary porosity but could be enlarged by dissolution along stylolites and microfractures. Exposure-related dissolution and fracture enhancement were preferentially developed near SB3–SB4 and in adjacent rapid facies-transition zones. Late strike-slip fault activity and related fluids further improved reservoir connectivity within damage zones. Therefore, favorable reservoirs are most likely where SQ2–SQ3 shoal complexes, SB3–SB4-adjacent dissolution-prone intervals and strike-slip fault damage zones overlap. This framework supports reservoir prediction by using facies to locate favorable belts, sequence surfaces to select intervals and faults to evaluate connectivity.

The co-evolution of hydrothermal activities, paleoclimate, and marine environments during Neoproterozoic glacial-interglacial cycles is crucial for understanding the biological activity on Earth's history. The Central Hunan region, governed by graben-horst tectonics, may exhibit sedimentary and geochemical patterns distinct from the broader Nanhua Basin. However, this potential heterogeneity has remained poorly constrained. Based on high-resolution inorganic geochemical analyses of drill cores, this study reconstructs the spatiotemporal evolution of interglacial hydrothermal activity, climate variability, salinity, and redox conditions in the Nanhua Basin. The results show that the lower Datangpo Formation exhibits pronounced Hg anomalies, suggesting that hydrothermal input provided an important material source for manganese mineralization. The sedimentary record also identifies multiple intermittent cooling events, highlighting pronounced climatic instability during interglacial periods. During the early stage of Datangpo deposition, the paleo-ocean was characterized by low salinity and weak seawater restriction. As terrigenous input increased and evaporation intensified under warming conditions, salinity progressively increased and transformed into a saline environment, exhibiting a distribution pattern of rising salinity from shallow to deep waters areas. Furthermore, multiple redox proxies indicate a stepwise rise in dissolved oxygen concentrations in the paleo-ocean, consistent with the evolution of paleoclimate and salinity. In summary, episodic hydrothermal activities and paleogeographic configuration jointly regulated the coupled fluctuations of paleoclimate, seawater salinity, and redox condition during the interglacial intervals. These findings offer essential geochemical evidence for understanding the marine environmental evolution in the Nanhua basin.

In water injection development of tight oil reservoirs (TORs), the complex fracture network formed by hydraulic fracturing and water injection induction is the key factor determining the development effectiveness. Accurate inversion of water injection-induced fracture parameters holds significant importance for enhancing reservoir development outcomes. This paper innovatively proposes a parameter inversion framework that integrates the Embedded Discrete Fracture Model (EDFM) with intelligent optimization algorithms. EDFM efficiently characterizes complex unstructured fracture systems while maintaining mass conservation between the matrix and fractures; intelligent optimization algorithms automatically invert parameters such as fracture half-length, orientation, and conductivity. First, a three-dimensional geological model of the TOR is constructed, utilizing EDFM to handle the impact of fractures on the seepage field. Based on considerations of fracture geometry, conductivity, and stress sensitivity, a coupled fluid dynamics model for fractures and matrix is developed. Subsequently, an objective function is built based on water injection production dynamic data, and the Projection-Iterative-Methods-based Optimizer (PIMO) algorithm is employed to achieve efficient inversion of fracture parameters. Taking a TOR in the Ordos Basin as an example for verification, through synthetic model validation, this method significantly improves the accuracy and efficiency of history matching, with inversion results reliably guiding numerical simulation predictions. The results demonstrate that this method can effectively enhance the precision of fracture parameter identification, offering clear advantages in inversion speed and accuracy over traditional trial-and-error approaches. This study provides new insights for modeling induced fractures in TORs and optimizing water injection development strategies.

Clarifying the micro-migration and differential accumulation mechanisms of shale oil in organic-lean hybrid shale (OLHS) is crucial for enhancing continental shale oil accumulation theories. This study examines the second member of the Funing Formation (E1f2) hybrid shale interval in the Gaoyou Sag, Subei Basin, using integrated analytical approaches including organic geochemistry, total scanning fluorescence (TSF), x-ray diffraction (XRD), and fluid inclusion analysis to identify petroleum micro-migration phenomena and elucidate differential accumulation mechanisms. Results from organic geochemistry, TSF, and XRD analyses demonstrate that oil in the E1f2 OLHS exhibits favorable mobility, high oil content, indicating significant exploration potential. Clear petroleum micro-migration pathways exist between different components of the shale system with organic-rich dark laminae serving as hydrocarbon generation sites while light-colored carbonate laminae function as storage zones. Shale oil within source rocks displays dual accumulation mechanisms: in situ accumulation within source layers and non-in situ accumulation through micro-migrated hydrocarbon charging from adjacent source intervals. Differential organic geochemical analysis and fluid inclusion data reveal that shale oil in the E1f2 exploration wells primarily originates from underlying source rocks within a 10–30 m thick interval. In the vein-host rock systems, oils present in fractures, and pores show compositional differences compared to hydrocarbons generated from in situ source rocks, supporting combined in situ and non-in situ accumulation mechanisms. Within the hybrid shale, organic-rich laminae interbedded with carbonate-rich and sandstone laminae form microscopic source–reservoir assemblages where generated hydrocarbons either accumulate in situ or migrate laterally to adjacent layers. This enhances understanding of OLHS petroleum systems.

The high water cut period represents a critical phase in the development of tight oil wells, and accurately forecasting productivity during this stage is essential for effective oilfield development planning. However, traditional reservoir engineering methods find it difficult to handle complex oil-water seepage behaviors and cannot accurately predict the productivity of tight sandstone oil wells in the high water cut period. Therefore, this paper proposes a method for predicting the productivity of tight oil reservoirs based on a hybrid deep learning algorithm, using the geological, engineering, and development parameters of 342 fractured horizontal wells in the Z211 block of Heshui Oilfield. The model was based on the KAN deep learning algorithm, and the WOA meta-heuristic optimization algorithm was used to optimize the KAN model parameters. Combined with multi-dimensional parameters such as oil well geology, engineering and development, an efficient and accurate productivity prediction model was established. Based on the interpretability of the model itself, the key features of the model and the factors affecting productivity are explained in combination with the SHAP (SHapley Additive exPlanations) value and the Pearson coefficient, revealing the changing relationship of productivity and the degree of influence of different parameters on productivity. The results indicate that the KAN-WOA model demonstrates strong performance in both prediction accuracy and robustness for productivity forecasting. For high water cut fractured horizontal wells in tight oil reservoirs, water content and permeability were identified as the primary influencing factors on initial productivity, whereas for low water cut wells, dynamic liquid level, number of fracturing stages, and sand volume were the key determinants. This approach offers a novel data-driven solution for the development and management of tight oil wells, serving as an effective decision-support tool in oilfield development.

The fluid flow in rough fractures (RFs) undergoes a transition from Darcy flow to non-Darcy (nDarcy) flow. Accurately identifying the transition in flow regimes and selecting appropriate flow equations are crucial for comprehensively characterizing flow within fractures in engineering applications. This study employs the spatial frequency method to construct 54 three-dimensional RFs with varying apertures and roughness levels, simulating the complete flow transition process from Darcy to nDarcy flow. A systematic investigation was conducted on the identification of flow regime transitions and the characterization of the non-Darcy coefficient (/1) within RFs. We deduce that the fundamental genesis of nDarcy flow in RFs is the collision between the fluid and the RFs walls, and utilizing E = 0.01 as the criterion for Darcy-to-Forchheimer flow transitions allows for a more accurate determination of its occurrence. A more specific formula to predict the critical Reynolds number (Rec) at the transition of flow regimes was derived. Furthermore, given that the /1 is influenced by inertia, it varies across different Reynolds numbers (Re). Based on 275 sets of /1 for RFs, a unified predictive model for the /1 was proposed considering the fractures geometric characteristics and inertia effects. The proposed model could predict the /1 for different fracture apertures, roughness levels, and Re. The findings provide new insights into nDarcy flow in RFs and lay the groundwork for the broader application of the Forchheimer equation, and achieved better results in engineering applications.

Fluid type and content directly control fluid mobility in tight reservoirs. At present, there are two ways to classify fluid types. One is to classify fluids into movable fluids (MF), capillary-bound fluids (CAF), and clay-bound fluids (CLF). The other is to classify fluids into free fluids and adsorbed fluids. However, the intrinsic relationship between the two fluid classification schemes is still unclear. In order to investigate the pore structure and fluid type characteristics, a series of experiments were performed on the Chang 7 tight sandstone in the Longdong area. The full-scale pore size distribution (PSD) can be obtained by combining low-temperature nitrogen adsorption (LTNA) with nuclear magnetic resonance (NMR). The PSD of Chang 7 tight sandstones primarily ranges from 1 nm to 20 μm. Based on the fractal characteristics, pore system is divided into macropores (mainly >150.8 nm), and micropores (mainly <150.8 nm). MF, CLF, and CAF constitute 11.1-49.7% (avg. 34.6%), 17.3-40.1% (avg. 26.7%), and 32.9-48.8% (avg. 38.7%) of total fluid, respectively. Additionally, macropores are positively correlated with MF and negatively correlated with CAF and CLF, whereas micropores show the opposite trend. By integrating NMR data with theoretical modeling, a clear correspondence between the two fluid classification approaches was established: MF and CAF closely correspond to free fluids, while CLF is strongly associated with adsorbed fluids. Notably, in samples with low porosity and extremely fine pore throats, the combination of centrifugation and theoretical modeling may underestimate the actual free fluid content. MF shows a weak negative correlation with quartz and clay minerals; CAF and CLF are weakly positively correlated with quartz and clay but negatively correlated with feldspar. The occurrence patterns of different fluid types within various pore-throat structures were established, revealing the relationships among mineral composition, pore size, pore-throat structure, and fluid distribution. These findings provide valuable insights into the pore structure and fluid distribution of tight sandstone reservoirs, enhancing the understanding of fluid behavior in unconventional systems.

The Upper Carboniferous Benxi Formation in the Ordos Basin contains thick coal layers, showing good potential for deep coalbed methane exploration. In this study, we analyze the macroscopic coal type, macerals, industrial composition, and pore characteristics to determine the coal-forming environment and reservoir characteristics of deep coal in the Benxi Formation. Macroscopic Benxi coal types show strong vertical heterogeneity, with a lower layer comprising mainly semi-bright coal, overlain by bright coal, and capped with semi-bright coal and gangue. The ash content of the coal also exhibits strong vertical heterogeneity; from bottom to top, it increases, then decreases, then increases again in the uppermost layer. Vitrinite is the main maceral of Benxi coal, exhibiting the lowest concentration in the lower layer, and increasing in the vertical direction. Obvious vertical heterogeneity also exists in the pore characteristics of the coal, with the total pore volume, total specific surface area, and pore size all varying substantially; the upper layer has the highest porosity with most abundant macropores and micropores. Upper Carboniferous Benxi coal was mainly deposited in a saline, peat-swamp environment, under weak hydrodynamic conditions. The lower layer, controlled by fluctuation of sea level, was deposited in aerobic environment with a certain amount of hydrodynamic force, resulting in the formation of low-vitrinite, high-ash, low-porosity coal with strongly heterogenous characteristics. In contrast, the upper layer was deposited in a reducing, high-level swamp environment during the later stage of a retreating sea. During this stage, a bright coal layer with high vitrinite content, low ash content, and high porosity was deposited under stable conditions and weak hydrodynamic force. Therefore, the upper coal layer exhibits good reservoir properties, conducive to the storage and migration of coalbed methane, and is identified as the key layer for exploration and development of deep coalbed methane in the Ordos Basin. This research provides a theoretical basis for upcoming exploration and development of deep coalbed methane in the Benxi Formation, and provides a reference for future theoretical and technical research that will benefit deep coalbed methane development in other areas of the Ordos Basin.

The Early Cambrian period was a pivotal interval in geological history, characterized by significant environmental fluctuations and evolutionary developments among early organisms. The rapid diversification of early animals has been attributed to increasing oceanic oxygenation. However, the patterns of biological activities, oceanic redox conditions, and seawater temperature during this critical period remain unclear and debate. To address this, we analyzed biological assemblages, oxygen isotopes, and major and trace elements in the Niutitang shale from the Yangtiao section in Guizhou Province, South China. Our findings revealed that the Niutitang shale in the Yangtiao section exhibits a diverse biological composition, including planktonic algae, benthic algae, acritarch, sponge spicules, and pogonophorans. Based on the biological composition, the Niutitang Formation could be divided into four distinct members: Niu1 to Niu4. Specifically, the Niu1 and Niu3 members were primarily composed of planktonic algae, while the Niu2 Member dominated by benthic algae and pogonophorans. Paleoclimatic proxies suggest that the environment was relatively cold during the deposition of the Niu 1-2 members, it was relatively warm and dry during the deposition of the Niu 3-4 members. Moreover, the redox conditions at the sediment-seawater interface and within the overlying water column varied significantly across the Niu 1-4 members. The overlying water of Niu1-3 members was oxic condition, which is consistent with abundant fossil records in the black shale. In contrast, the relatively rare fossils of the Niu4 Member may be closely related to the suboxic overlying water column. Notably, the paleo-ocean was affected by multiple phases of hydrothermal activities, leading to a significant trend of cooling ancient seawater temperatures. This temperature gradient is consistent with the occurrence of typical hydrothermal-associated organisms in the Niu2 Member. Furthermore, the redox conditions exhibited a clear coupling with marine productivity, highlighting key factors controlling organic matter enrichment in the Niutitang shales. In summary, the interplay of paleoclimate, seawater temperature, and redox conditions had a substantial impact on biological abundance in South China during the Early Cambrian. This feedback mechanism may provide new insights into how spatial variations in the oceanic environment influenced biodiversity during this critical period.

The carbon isotope sequence of alkanes is a key indicator used to distinguish organic from inorganic gas. A negative carbon isotope sequence (i.e., δ13C1 > δ13C2 > δ13C3 > δ13C4) is a characteristic feature of inorganic gas. Some gas samples from the Qingyang gas field in the southwestern Ordos Basin exhibit a negative carbon isotope sequence, but the geological conditions necessary for the development of inorganic gas are not present. There is currently no reasonable explanation for this phenomenon. This study takes into account the geological background of the Ordos Basin and comprehensively investigates the causes of the anomalous carbon isotope sequence of alkanes in the Qingyang gas field; this is done through an analysis of natural gas geochemical characteristics and adsorption/desorption experiments on high-rank coal. Our results show that: (1) Natural gas from the Qingyang gas field is over-mature coal-type gas derived from Carboniferous‒Permian formations. Its negative carbon isotope sequence is mainly related to the adsorption of gases by coal. During the over-mature stage, the content of heavier hydrocarbon gases (C2+) is very low, and the adsorption capacity of coal for C2+ gases is stronger than that for methane. Heavier hydrocarbon gases (e.g., ethane), with lighter carbon isotope signatures, preferentially desorb, resulting in a relatively light observed carbon isotope composition. Owing to its high abundance, the isotopic composition of methane is impacted relatively little by adsorption. (2) The anomalous geochemical characteristics of over-mature coal-type gas result in the failure of the negative carbon isotope sequence method for identifying inorganic gas; this also invalidates the criterion for classifying oil-type gas and coal-type gas based on thresholds of δ13C2 = - 28‰ and δ13C3 = - 25‰. Additionally, previously proposed empirical formulae (e.g., δ13C2‒Ro and δ13C3‒Ro) are not applicable to over-mature natural gas. Furthermore, the δ13C2-δ2H1 cross-plot method, used for determining the type of source rock, is rendered ineffective because over-mature samples deviate from the coal-type gas range. (3) The methane carbon isotope signature (δ13C1) and gas dryness coefficient (C1/C1-5) are reliable indicators of source rock maturity.

The natural cracking of light oil in deep reservoirs has attracted significant attention in the exploration of ultradeep unconventional oil and gas. However, the mechanisms of microscopic oil cracking and bitumen conversion remain unclear. This study aims to investigate the molecular composition and chemical functional group distribution of organic matter from gold-tube pyrolysis of light oil, using submicron-resolved Optical Photothermal Infrared Spectroscopy (O-PTIR) for in-situ analysis. The results indicate that in the early stages of thermal evolution, asphaltene clusters in residual oil undergo polymerization reactions, leading to an increase in resin and asphaltene content. Point O-PTIR spectra of light oil and asphaltene exhibit similar features, with minimal aromatic (C=C) absorption and dominant CH2 and CH3 bending vibrations. At an EasyRo of 1.81 %, thermal cracking converts some asphaltenes into solid bitumen, which increases the chemical heterogeneity in O-PTIR maps. As thermal maturity progresses, solid bitumen content rises, molecular composition shifts towards polycyclic aromatic hydrocarbons (PAHs), and the microstructure of solid bitumen changes from powdery to crumbly. At EasyRo = 2.40 %, the chemical heterogeneity of solid bitumen peaks with vein-like distributions of aliphatic compounds. Further maturation leads to molecular homogeneity, characterized by pronounced C=C absorption and broad CH2/CH3 vibrational peaks. Branch ratio and pseudo-van Krevelen analyses further demonstrate that residual organic matter during oil cracking is not homogeneous but varies regionally. Understanding these molecular and chemical heterogeneities at the microscale is crucial for elucidating the migration, fractionation, and conversion processes of ultra-deep light oils.

Obtaining core samples from ultradeep hydrocarbon source rocks poses significant challenges, and the more readily available hydrocarbon source rock cuttings are often contaminated to varying degrees by oil-based drilling fluids (OBDF). This makes it difficult to obtain the real geochemical characteristics of ultradeep hydrocarbon source rocks, which is one of the key problems faced by ultradeep oil and gas exploration at present. To address the issue of OBDF contamination in rock cuttings, this study examines rock cuttings from well T in the Kuqa Depression (∼6980 m) and cores from other wells within the same stratigraphic position as examples. By comparing molecular geochemical parameters from both cores and rock cuttings, this study evaluates the decontamination effects of three different treatment methods: twice-extraction method (TEM), extraction method of hydrocarbons from kerogen adsorption (EMHK), and microablation. Results reveal significant differences in biomarker compounds extracted from source rock cuttings processed by TEM. Biomarkers from the first extraction are largely consistent with those of oil-based drilling fluids, which indicates that the rock cuttings have suffered from different degrees of contamination. Big particle rock cuttings exhibit relatively lower contamination levels, and their biomarker compounds from the second extraction are similar to those from the core. On the other hand, biomarker compounds extracted by EMHK differ notably from those in oil-based drilling fluids and exhibit partial similarity with uncontaminated core samples, but certain parameters remain inconsistent, likely due to incomplete pretreatment (e.g., insufficient solvent washing before kerogen making). In contrast, biomarker parameters and GC-MS spectra of surface-stripping powders obtained via microablation initially show contamination similar to OBDF. However, biomarker parameters and GC-MS spectra from the inner portions of big particles processed via microablation closely align with those of uncontaminated cores, reflecting the authentic geochemical characteristics of source rocks. Comparatively, TEM demonstrates incomplete decontamination, and the effectiveness of EMHK is heavily influenced by the thoroughness of pretreatment. Microablation effectively reveals the true biogenic signature of ultradeep hydrocarbon source rocks. Thus, the broader adoption and application of microablation techniques hold great promise for advancing global ultradeep hydrocarbon exploration.