Marine organic-rich shales frequently exhibit anomalously high uranium (U) concentrations, yet the mechanisms governing its enrichment in overmature formations like the Wufeng–Longmaxi shales remain unclear. This study examines the distribution and enrichment patterns of uranium in the Wufeng–Longmaxi shales in typical wells through integrated geochemical and geophysical analyses, supplemented by natural gamma spectral logging data. Key findings include: (1) Multiple (up to three) uranium enrichment events are identified within the Wufeng–Longmaxi sequence, consistently corresponding to shale gas sweet spots. (2) Uranium content shows a clear dependence on organic matter (OM) type, with algal fragments being the primary host of uranium, likely due to incorporation during early diagenesis. Pore-water redox conditions and pH further govern the reduction of U (U6+) and its subsequent sequestration into organic phases. (3) The equivalent vitrinite reflectance (ERo) of uranium-rich shales is 0.11%–0.17% higher than that of non-uranium-rich shales, suggesting that uranium enrichment may slightly enhance OM thermal maturity. (4) Uranium distribution is collectively controlled by reducing conditions, volcanic eruptions (e.g., tuff layers), and OM type. Additionally, uranium enrichment provides chronostratigraphic markers that may aid in timing marine black shales. These findings thus offer a mechanistic understanding of uranium enrichment in overmature shales, with direct implications for targeting productive intervals in shale gas systems.

Analysis of pyrobitumen in reservoirs can yield key information about hydrocarbon evolution, which may provide vital insights for deep- to ultra-deep hydrocarbon exploration in high- to over-mature petroliferous deep basins. The Ediacaran Dengying Formation in the Penglai area of the Sichuan Basin contains large-scale gas reservoirs, where pyrobitumen is extensively present. To understand the hydrocarbon accumulation and alteration processes in these reservoirs, in this study, we systematically investigated the characteristics of the reservoir pyrobitumen using detailed petrographic analysis and laser Raman spectroscopy. The results indicated that four types of reservoir pyrobitumen are present: pyrobitumen with isotropic (type I), mosaic (type II), fibrous (type III), and honeycomb (type IV) textures. Pyrobitumen in the dolomite reservoirs of the Deng 2 and Deng 4 members of the Dengying Formation often co-occurs with hydrothermal minerals, including saddle dolomite, quartz, and fluorite. The equivalent vitrinite reflectance (Rmc Ro%) calculated indicated that the pyrobitumen is over-mature, with Rmc Ro% values ranging from 3.46% to 3.89%. In addition, significant differences were observed in the Raman parameters between the four types of pyrobitumen: type IV shows the greatest degree of structural ordering, while type II exhibits the highest level of disordering, with types I and III exhibiting intermediate structural ordering. Finally, the spatial distribution of the four types of pyrobitumen indicated that hydrothermal pulses driven by the Emeishan Large Igneous Province toward the end of the Permian Period may be primarily responsible for the extensive cracking of paleo-oil pools, causing the development of types II–IV pyrobitumen and gas generation.

The Nam Con Son Basin (NCSB), offshore southeastern Vietnam, is among the largest and most hydrocarbon-prolific basins in Southeast Asia. While coal-bearing intervals are widely recognized as the primary source rocks, the role of shale- and siltstone-dominated successions has not been fully evaluated. This study integrates bulk geochemistry, organic petrology, and biomarker data from Well A-1X to assess the petroleum potential and depositional environment of shale and siltstone intervals. A total of 94 fine-grained clastic samples (90 shales and 4 siltstones) were analyzed. TOC values for shales range from 0.50 to 2.60 wt.% (mean 1.10 wt.%), with the majority classified as “Good” (1–2 wt.%) according to petroleum geochemical standards. Siltstones yielded TOC between 0.90–1.16 wt.% (mean 0.99 wt.%), confirming fair-to-good organic enrichment despite coarser grain size. Stratigraphically, Oligocene shales are richer (mean 1.30 wt.%) compared to Miocene equivalents (mean 1.05 wt.%), indicating that the Oligocene succession forms the main shale source rock interval in Well A-1X. Thermal maturity, based on vitrinite reflectance, increases with depth. Miocene shales are immature to marginally mature (0.31–0.52%Ro, mean 0.44%Ro), whereas Oligocene shales reach the early oil window (0.46–0.62%Ro, mean 0.57%Ro). Biomarker signatures support these results: shallow Oligocene shales exhibit n-alkane dominance at n-C17–C18 (algal contribution), while deeper intervals show enrichment in long-chain n-C25–C31, reflecting significant terrestrial higher-plant input. Pristane/Phytane ratios of 4–9 suggest deposition under suboxic to oxic deltaic conditions. CPI values averaging 1.03 indicate thermal maturity consistent with early oil generation. Collectively, these findings demonstrate that shale and siltstone intervals in Well A-1X, though less organic-rich than coals, are effective secondary oil-prone sources. Their widespread stratigraphic distribution and confirmed maturity enhance the robustness of the Nam Con Son petroleum system and highlight new opportunities for exploration, particularly in Oligocene reservoirs charged by shale-derived hydrocarbons.

The Nam Con Son Basin (NCSB) is one of the most hydrocarbon-prolific basins in offshore Vietnam. Although shales and siltstones have recently received greater attention, coals remain the dominant source rocks in the basin. This study provides a detailed geochemical characterization of coal seams from Well A-1X, focusing on organic matter composition, maturity, and hydrocarbon generation potential. A total of 12 coal samples were analyzed for TOC, Rock-Eval pyrolysis, vitrinite reflectance (%Ro), and biomarker parameters. TOC values are exceptionally high, ranging from 62.4 to 87.9 wt.%, with a mean of 78.6 wt.%, classifying all samples as Excellent source rocks (Peters & Cassa, 1994). Despite this richness, Rock-Eval hydrogen index (HI) values are relatively low (~150–220 mg HC/g TOC), indicating a gas-prone Type III kerogen typical of higher-plant derived organic matter. Thermal maturity assessments reveal that coals are at the threshold of petroleum generation. Vitrinite reflectance ranges from 0.55–0.62%Ro (mean 0.59), placing them at the early oil window, while Tmax values (437–443 °C) support this interpretation. However, bitumen extracts yield relatively low hydrocarbon fractions (average 18.3% of total extract) compared to shales, suggesting limited liquid hydrocarbon generation potential. Biomarker evidence further confirms terrestrial origin and oxic depositional settings. n-Alkane distributions are dominated by long-chain n-C25–C31 hydrocarbons, characteristic of higher-plant waxes. Pristane/Phytane ratios are consistently high (13–16), indicating strongly oxic conditions typical of delta-plain swamp environments. CPI values of 1.14–1.21 reflect early maturity but preservation of odd-carbon dominance in higher plant waxes. These results demonstrate that coals in Well A-1X are exceptionally organic-rich and regionally important gas-prone source rocks. While they provide limited oil, their vast thickness and continuity make them the primary hydrocarbon source in the Nam Con Son Basin, supplying gas and condensate to regional petroleum accumulations. Their characterization enhances understanding of the basin’s petroleum system and highlights the contrast with shale-dominated intervals.

ABSTRACT Successfully predicting effective migration pathways can greatly improve the accuracy of trap risk evaluations, increase the drilling success rate, and reduce the costs of exploration in general. Combined with modeling, a total of 47 crude oil samples and 24 source rock samples were analyzed to study oil migration pathways in the Cretaceous Napo Fm M1ss member in the X block in the Oriente Basin of Ecuador. The vitrinite reflectance values of 24 source rock samples show that the source rock in the southwest zone is in the oil maturity window and was capable of supplying oil to the X block. The nitrogenous compound ratios of 1,8‐/2,6‐dimethylcarbazole and 1,5‐/2,7‐dimethylcarbazole have a consistent decreasing trend which indicates that oils migrated within the M1ss member from southwest to northeast. Basin modeling of M1ss carrier shows that different oil supply areas have different migration pathways. The migration pathways associated with oil supplies from the southwest region of Block X are restricted to the southwest and central areas. In contrast, those linked to oil supplies from the Fanny fault extend across both the hanging wall and footwall of this fault. Meanwhile, the migration pathways connected to oil supplies from the MariannN and MariannM faults are confined solely to the hanging walls of these two faults. Basin modeling combined with nitrogenous compounds analysis verified the migration pathway distribution in X block which could explain the formation of most accumulations. The traps in the southwest and eastern areas of X block appear to be favorable for future exploration as they are located on a migration pathway.

ABSTRACT To reveal the macroscopic explosion characteristics and gas-solid product characteristics of different coal dust samples, coal dust explosion experiments were conducted in a 20 L spherical vessel. The explosion characteristic parameters, such as the maximum explosion pressure (P ex) and the maximum pressure rise rate (dP/dt)ex were recorded. Meanwhile, the post-explosion coal dust samples and gaseous products were collected and analyzed. The research efforts include gas chromatography analysis of the gaseous products, proximate analysis, and SEM analysis of coal dust samples before and after explosions. The results show that the P ex and (dP/dt)ex initially exhibit a gradual decrease with increasing vitrinite reflectance (R 0), and an increasing trend is observed between medium metamorphic degree coal and high-rank coal. Furthermore, P ex exhibits an initial increase and then a decrease in trend with the rise in coal dust concentration. Proximate analysis indicated that the content of volatile matter and fixed carbon decreases before and after coal dust explosions, while the content of moisture and ash increases. From a microscopic perspective, the microstructure of coal dust transitions from a smooth, block-like structure to a rough, porous configuration before and after an explosion. The residual gas composition analysis reveals that the oxygen concentration dropped below 10% after the coal dust explosion. When the concentration of coal dust is low, the main gaseous products are CO2, with a relatively low amount of CO and CH4, and the gases C2H6, C2H2, and C2H4 are nearly undetectable. However, the concentration of CO and hydrocarbon gases gradually increases at higher coal dust concentrations.

Fluid overpressure is a common phenomenon in sedimentary basins, and overpressure induced by hydrocarbon generation has attracted considerable attention. However, direct temporal constraints are lacking, and the evolutionary process remains poorly understood. Here, we provide absolute chronological constraints on the paleo−fluid pressure evolution in shales of the Sichuan Basin, China, by integrating in situ U-Pb dating with fluid inclusion analysis of bed-parallel calcite veins. Our results reveal that overpressure due to hydrocarbon generation during deep burial evolved in a two-stage, stepwise exponential manner with increasing thermal maturity. During the kerogen gas generation phase (236−156 Ma; Ro [vitrinite reflectance] = 1.3%−2.0%), fluid pressure increased slowly, and the pressure coefficient decreased gradually. Subsequently, during the advanced burial stage, both fluid pressure and the pressure coefficient increased abruptly by up to threefold, associated with oil-cracking gas generation (148−84 Ma; Ro >2.0%). Strong hydrocarbon generation, combined with low permeability, enables fluid overpressure to persist from deep burial through uplift to the present day. Our findings show that under tectonically quiescent conditions, fluid pressure in shale driven solely by hydrocarbon generation increases in a stepwise exponential manner rather than a continuous nonlinear trend and remains largely preserved even during uplift unless disrupted by faulting. This successful application highlights the broad potential of absolute geochronological constraints for refining models of fluid evolution in sedimentary basins.

Understanding coalbed methane (CBM) enrichment patterns is essential for optimizing production capacity. This study evaluates the CBM reservoir-forming characteristics and exploration potential of the Longtan Formation in the Santang Syncline, Zhijin area, to systematically reveal CBM enrichment and high-production patterns. The investigation integrates regional geology, logging, well testing, laboratory analyses, and drainage production data. Results indicate that coal seam vitrinite reflectance (Ro,max) ranges from 3.20% to 3.60%, with metamorphic grade increasing with burial depth. Coal lithotypes consist predominantly of semi-bright coal, with subordinate semi-bright to semi-dull coal and minor semi-dull coal. Coal seam roofs comprise gray-black mudstone and calcareous mudstone, locally developing limestone, while floors consist of bauxitic mudstone. Pore structure analysis reveals greater complexity in coal seams 6 and 14, whereas seams 7 and 16 display simpler structures. Coal seams 5-3 and 6 demonstrate the weakest adsorption capacity and lowest theoretical gas saturation, while other seams exceed 55% gas saturation. Langmuir volume (VL) increases with burial depth, reaching maximum values in coal seam 30. Langmuir pressure (PL) follows a low–high–low trend, with lower values at both ends and higher values in the middle section. Measured gas content is highest in the middle section, moderate in the lower section, and lowest in the upper section. Reservoir condition assessment indicates favorable conditions in coal seams 14, 16, and 21, relatively favorable conditions in seam 7, and unfavorable conditions in seams 6, 30, 32, and 35. Among the three coal groups penetrated, the middle coal group exhibits the most favorable reservoir conditions, followed by the upper and lower groups.

This study provides a comprehensive review of the petroleum systems in the Iranian Zagros and Persian Gulf regions, spanning the Phanerozoic, with the objective of synthesizing geological, geochemical, and basin modeling data to enhance exploration strategies. Three primary petroleum systems are identified: Paleozoic-Triassic, Jurassic-Cretaceous, and Cenozoic, each characterised by distinct source rocks, reservoirs, and seals. The methodology integrates extensive literature reviews and original geochemical analyses, including Rock-Eval pyrolysis, vitrinite reflectance, biomarker studies, carbon isotope and kinetic modeling, to assess source rock maturity, kerogen type, and oil-source correlations. Main results highlight the Paleozoic-Triassic system, driven by Silurian Sarchahan "hot shales," feeding gas-rich Permian-Triassic Dalan and Kangan reservoirs, sealed by Triassic Dashtak evaporites, though challenged by deep burial and high non-hydrocarbon content. The Jurassic-Cretaceous system, contributing over 50% of Iran's oil, features oil-prone Sargelu, Garau, and Kazhdumi source rocks, with reservoirs in the Khami and Bangestan groups, sealed by Hith/Gotnia and Gurpi formations. The Cenozoic system, centered in the Dezful Embayment, relies on the Pabdeh source rock, Asmari reservoir, and Gachsaran seal, with significant vertical migration from underlying Mesozoic systems. Chemometric classification of 21 oil samples reveals three distinct oil families linked genetically to these petroleum systems. Family A oils are attributed to Upper Jurassic to Miocene source rocks, characterised by a high C28/C29 regular sterane ratio. Family B oils correlates to Jurassic or older source rocks, classified as high-maturity ones. Family C oils sourced from the Aptian-Albian Kazhdumi Formation displaying biomarker parameters indicative of anoxic marine conditions.

ABSTRACT Clumped isotopic thermometry of carbonate minerals is a valid method for revealing the thermal history of sedimentary basins. This method has been successfully applied to basins with carbonate strata, whereas its application in basins composed of clastic strata is limited. This study focused on calcite cements in the upper Permian to Triassic terrestrial clastic strata in the Junggar Basin, northwestern China. Petrological, elemental geochemical and clumped isotopic analyses were conducted in combination with vitrinite reflectance analysis and forward thermal modelling. The studied strata contain multiple generations of calcite cement: early‐ and late‐stage calcite. Relatively high δ 13 C values (−6.2‰ to −0.8‰), high δ 18 O values (−15.9‰ to −11.3‰) and low clumped isotopic temperatures (T(∆ 47 ): 31°C–43°C) suggest that the Permian and Triassic early‐stage calcite precipitated during the penecontemporaneous stage. Considering the high MnO contents (2.22%~14.05%), extremely low δ 13 C values (−60.5‰ to −38.4‰) and high T(∆ 47 ) values (95°C–132°C), the late‐stage calcite in the Triassic rocks is explained as the product of the oxidation of hydrocarbons by high‐valence Mn/Fe oxides during mesodiagenesis. The high δ 13 C values (−10.2‰ to −10.7‰) indicate that the late‐stage calcite in the Permian rocks is the product of the decarboxylation of organic acids. Constrained by the T(∆ 47 ) values of the early‐ and late‐stage calcite and forward kinetic modelling, the maximum temperature of the upper Permian is confined to 150°C during the Late Jurassic. The thermal gradient of the study area exhibited an overall decreasing trend from 40°C·km −1 in the late Permian to 22°C·km −1 in the Cenozoic. The results are 2°C–4°C per km higher than those of previous works based on vitrinite reflectance and apatite fission track annealing. This research demonstrates that the combination of clumped isotope thermometry of multistage carbonate cements and kinetic modelling can quantitatively reveal a basin's thermal history.

ABSTRACT The coal bearing lithostratigraphic units of the upper Barakar Formation of the Raniganj basin, India, were reinterpreted as mixed fluvio-tide/wave settings. The RockEval study from the shales in connection with the coal units of Ramnagar, Laikdih opencast-underground and Salanpur was performed to evaluate the source rock potential. The total organic carbon (TOC), S1, S2, Tmax, HI, and OI values indicate that the rocks are good to excellent source rocks. The majority of the organic materials are of Type III or IV, but some mixed sources are also evident. The palaeo-burial temperature calculated from the vitrinite reflectance gives a consistent result of 135°C. The hydrocarbons are indigenous, and the organic matter (OM) is mature enough to produce mainly gas with small potential for oil. But the palaeo-redox condition was fluctuating between oxic to anoxic. By SEM-EDX analysis, it was observed that kaolinite and illite/smectite are the primary clay minerals. Different types of porosities were developed; some of them are partially filled with secondary minerals. Hydrocarbon generation and escape have produced fracture porosity in these rocks. The escaping CH4-bearing fluid carried Ba, derived from dissolution of K-feldspars and/or organic matters, and moved to the interlamellar pores, where mixed with oxic sulfate-rich water to form barite. In some shales, anhydrites are also precipitated as a late diagenetic mineral. This oxic water was responsible for the destruction of some organic matter and reduced the hydrocarbon generating capacity of the rocks. The relative hydrocarbon potential ratio also gives low oxic values and high anoxic values, indicating the fluctuation of redox conditions in the system.

The Upper PermianLongtan Formation in the southern Sichuan Basinexhibits significant shale gas potential, but its paleoenvironmentand organic matter enrichment mechanisms remain poorly constrained.This study integrates vitrinite reflectance, rock pyrolysis, mineralogicalanalysis, and major/trace element geochemistry to elucidate organicmatter accumulation processes. Results indicate overmature shales(Ro average 3.17%) dominated by Type IIIkerogen, with mineral assemblages primarily comprising clay (average62.75% avg.) and quartz (average 22%). Geochemical proxies revealdistinct enrichment of TiO2, TFe2O3, V, Cr, Cu, Ga, and Nb, alongside the depletion of SiO2, Na2O, MnO, and Li. Warm-humid paleoclimate conditions(CIA, Rb/Sr) enhanced terrestrial organic matter input, while elevatedsalinity (Sr/Ba, Th/U) and persistent anoxia (redox-sensitive traceelements) promoted organic matter preservation. Organic matter enrichmentin the Longtan shale was jointly controlled by high productivity underfavorable climatic conditions and effective sequestration in a stratified,saline, and reducing depositional system.

Maturation and organic matter content are critical factors influencing the hydrocarbon generation potential and economic viability of oil shales. Accurate assessment of these parameters is essential for optimizing extraction techniques and evaluating resource quality. While previous studies have individually linked maturation and organic content to dielectric permittivity in the terahertz (THz) range, their combined influence has not yet been thoroughly investigated. In this study, we explore the interdependence between maturation, organic matter content, and THz dielectric properties. Fifteen oil shale samples from two distinct basins were analyzed using Rock-Eval thermal analysis to quantify organic content, vitrinite reflectance to determine thermal maturity, and THz time-domain spectroscopy to estimate dielectric permittivity. Based on these analyses, we propose an empirical model that links these three parameters through a fitted surface, achieving a 75% accuracy in data representation. These findings provide a more robust framework than previous approaches for characterizing oil shales and enhancing resource evaluation.

The Central Sumatra Basin is a back-arc basin and has the hottest geothermal gradient in Indonesia. Hydrocarbon production in this basin began in the 19th century and continues to this day with active production fields and exploration activities. This study aims to analyze the characteristics of the source rock, reconstruct the basin's evolution, and estimate the timing of hydrocarbon generation and expulsion at the North Aman Field in the Central Sumatra Basin. Data from two wells were used, including formation thickness, TOC, Tmax, HI, OI, Rock Eval Pyrolysis, and vitrinite reflectance. The analysis results show that Well NA-1 has source rock quality ranging from poor to excellent, with maturity levels reaching mature (Tmax 426–457°C; Ro 0.64–1.01), while NA-2 ranged from poor to very good and reached post-mature maturity levels (Tmax 406–543 °C; Ro 0.42–1.15). Both wells fall into Kerogen Type II–III, with some Type IV samples. Based on 1D basin modeling, kerogen conversion to hydrocarbons in Well NA-1 began during the Oligocene (32.26 million years ago) and underwent expulsion during the Pleistocene (0.48 million years ago), while in Well NA-2, it began during the Oligocene (32.14 million years ago) and underwent expulsion during the Pleistocene (0.89 million years ago). Overall, the source rocks in Wells NA-1 and NA-2 show potential for producing commercial hydrocarbons.

ABSTRACTThe Yin‐E Basin, located at the junction of the Siberian, Kazakhstan, and Tarim blocks and the North China Craton, has experienced complex tectonic activities and remains one of the underexplored onshore sedimentary basins in China. The Upper Palaeozoic is an important stratigraphic interval for oil and gas exploration, but its source rock thermal evolution lacks systematic research, thus hindering exploration progress. Addressing the frontier topic of very low‐grade metamorphism's role in organic maturation, we studied the clay mineralogy (illite crystallinity: 0.42°–0.25° Δ2θ), illite polymorphism (predominantly 2 M1), and cell parameters (b0: 9.0024–9.0204 Å) of the Upper Palaeozoic source rocks (wells YBC1, BD1 and YBN1) in the Suhongtu Depression, revealing the palaeogeothermal field of the Upper Palaeozoic. These data were combined with basin modelling to quantitatively constrain the thermal evolution history. The results indicate that the Upper Palaeozoic strata primarily underwent prehnite‐pumpellyite‐facies of very low‐grade metamorphism under medium‐low pressure, corresponding to peak temperatures of 211.94°C–226.32°C. The reconstructed palaeotemperature reached 210°C–220°C. By the end of the Permian, all source rocks had reached their maximum thermal maturity (vitrinite reflectance, Ro: 1.42%–2.42%), with the Ba'nan Sag showing significantly higher maturity (Ro: 1.57%–2.42%). This study provides key constraints on the thermal evolution and hydrocarbon generation potential of Upper Palaeozoic source rocks, supporting future exploration in the Yin‐E Basin and adjacent areas.

The Middle Jurassiccoal seams in the Beishan region representan important target for hydrocarbon exploration; however, researchon the associated coal-measure source rocks remains limited. The couplingbetween depositional paleoenvironment and hydrocarbon generation potentialamong various coal-measure lithologies (including coal, associateddark mudstone, and carbonaceous mudstone) within the same or similarsedimentary facies belts is still poorly understood. In this study,the paleoenvironment was analyzed using major and trace element geochemistryto assess its influence on source rock development. Subsequently,organic geochemical methods were employed to evaluate the hydrocarbongeneration potential of the source rocks. The results indicate thefollowing: (1) Major and trace element data show that the coal-measuresource rocks are enriched in CaO, Sr, and U, with Sr contents decreasingin the order of dark mudstone > coal > carbonaceous mudstone.(2)The Middle Jurassic lacustrine basin experienced cyclic water-depthfluctuations (shallow–deep–shallow), with paleosalinitydominated by saline to brackish conditions, a warm and humid paleoclimate,and predominantly reducing paleo-redox conditions. (3) Organic geochemicalanalyses reveal that dark and carbonaceous mudstones have higher organicmatter abundances than coal. The organic matter is primarily TypeII2 kerogen, with minor contributions from Type I and TypeIII. Vitrinite reflectance (Ro) values range from 0.54% to 0.84%,and the average Tmax value is 437 °C,indicating a low-maturity to early mature thermal evolution stage.These findings demonstrate that, within the same coal-measure sourcerock system, lacustrine-swamp facies dark and carbonaceous mudstonesinterbedded with coal represent high-quality hydrocarbon source rocks.Their enhanced hydrocarbon generation potential is attributed to elevatedpaleosalinity, which promotes the preservation of hydrogen-rich maceralssuch as desmocollinite. Currently at a low to early mature stage ofthermal evolution (Ro: 0.54–0.84%), these source rocks possesssignificant potential for generating low-maturity oil and gas. Notably,their hydrocarbon generation potential surpasses that of the coallayers, offering critical theoretical support for Middle Jurassiccoal-measure source rock exploration in the Beishan region.

Relationship between vitrinite reflectance, fluoresence red/green quotients, apatite fission tracks and temperature by joint inversion of three wells

In comparison to shallow coal seams, deep coal seams exhibit characteristics of high temperature, pressure, and in-situ stress, leading to significant differences in reservoir properties that constrain the effective development of deep coalbed methane (CBM). This study takes the Carboniferous deep 8# coal seam in the Yulin area of Ordos basin as the research subject. Based on the test results from core drilling wells, a comprehensive analysis of the characteristics and variation patterns of coal reservoir properties and a comparative analysis of the exploration and development potential of deep CBM are conducted, aiming to provide guidance for the development of deep CBM in the Ordos basin. The research results indicate that the coal seams are primarily composed of primary structure coal, with semi-bright to bright being the dominant macroscopic coal types. The maximum vitrinite reflectance (Ro,max) ranges between 1.99% and 2.24%, the organic is type III, and the high Vitrinite content provides a substantial material basis for the generation of CBM. Longitudinally, influenced by sedimentary environment and plant types, the lower part of the coal seam exhibits higher Vitrinite content and fixed carbon (FCad). The pore morphology is mainly characterized by wedge-shaped/parallel plate-shaped pores and open ventilation pores, with good connectivity, which is favorable for the storage and output of CBM. Micropores (<2 nm) have the highest volume proportion, showing an increasing trend with burial depth, and due to interlayer sliding and capillary condensation, the pore size (<2 nm) distribution follows an N shape. The full-scale pore heterogeneity (fractal dimension) gradually increases with increasing buried depth. Macroscopic fractures are mostly found in bright coal bands, while microscopic fractures are more developed in Vitrinite, showing a positive correlation between fracture density and Vitrinite content. The porosity and permeability conditions of reservoirs are comparable to the Daning–Jixian block, mostly constituting oversaturated gas reservoirs with a critical depth of 2400–2600 m and a high proportion of free gas, exhibiting promising development prospects, and the middle and upper coal seams are favorable intervals. In terms of resource conditions, preservation conditions, and reservoir alterability, the development potential of CBM from the Carboniferous deep 8# coal seam is comparable to the Linxing block but inferior to the Daning–Jixian block and Baijiahai uplift.

The Jurassic Tamulangou Formation in the Hongqi Depression has favorable hydrocarbon generation conditions and great resource potential. This study systematically analyzes the geochemical characteristics and thermal evolution history of the source rocks using data from multiple key wells. The dark mudstone of the Tamulangou Formation has a thickness ranging from 50 to 200 m, with an average total organic carbon (TOC) content of 0.14–2.91%, an average chloroform bitumen “A” content of 0.168%, and an average hydrocarbon generation potential of 0.13–3.71 mg/g. The organic matter is primarily Type II and Type III kerogen, with an average vitrinite reflectance of 0.71–1.36%, indicating that the source rocks have generally reached the mature hydrocarbon generation stage and are classified as medium-quality source rocks. Thermal history simulation results show that the source rocks have undergone two major thermal evolution stages: a rapid heating phase from the Late Jurassic to Early Cretaceous and a slow cooling phase from the Late Cretaceous to the present. There are differences in the thermal evolution history of different parts of the Hongqi Depression. In the southern part, the Tamulangou Formation entered the hydrocarbon generation threshold at 138 Ma, reached the hydrocarbon generation peak at approximately 119 Ma, and is currently in a highly mature hydrocarbon generation stage. In contrast, the central part entered the hydrocarbon generation threshold at 128 Ma, reached a moderately mature stage around 74 Ma, and has remained at this stage to the present. Thermal history simulations indicate that the Hongqi Depression reached its maximum paleotemperature at 100 Ma in the Late Early Cretaceous. The temperature evolution pattern is characterized by an initial increase followed by a gradual decrease. During the Late Jurassic to Early Cretaceous, the Hongqi Depression experienced significant fault-controlled subsidence and sedimentation, with a maximum sedimentation rate of 340 m/Ma, accompanied by intense volcanic activity that created a high-temperature geothermal gradient of 40–65 °C/km, with paleotemperatures exceeding 140 °C and a heating rate of 1.38–2.02 °C/Ma. This thermal background is consistent with the relatively high thermal regime observed in northern Chinese basins during the Late Early Cretaceous. Subsequently, the basin underwent uplift and cooling, reducing subsidence and gradually lowering formation temperatures.

Currently, the Longmaxi shale in the Sichuan Basin is the most successful stratum of shale gas production in China. However, because Longmaxi shale mostly has high over-maturity, a low-maturity sample cannot be obtained for gas generation thermal simulations, and as a result, a gas generation model has not yet been established for it. Therefore, models of other shales are usually used to calculate the amount of gas generated from Longmaxi shale, but they may produce inaccurate results. In this study, a Longmaxi shale sample with an equivalent vitrinite reflectance calculated from Raman spectroscopy (EqVRo) of 1.26% was obtained from Well Yucan 1 in the Chengkou area, northeast Sichuan Province. This Longmaxi shale may have the lowest maturity in nature. Pyrolysis simulations based on gold tubes were performed on this sample, and the gas generation line was obtained. The amount of gas generated during the low-maturity stage was compensated by referring to gas generation data obtained from Lower Silurian black shale in western Lithuania. Thus, a gas generation model of the Longmaxi shale was built. The model showed that the gas generation process of Longmaxi shale could be divided into three stages: (1) First, there is the quick generation stage (EqVRo 0.5–3.0%), where hydrocarbon gases were generated quickly and constantly, and the generation rate was steady. A maximum of 458 mL/g TOC was reached at a maturity of 3.0% EqVRo. (2) Second, there is the stable stage (EqVRo 3.0–3.25%), where the amount of generated gas reached a plateau of 453–458 mL/g TOC. (3) Third, there is the rapid descent stage (EqVRo > 3.25%), where the amount of generated gas started to decrease, and it was 393 mL/g TOC at an EqVRo of 3.34%. This model allows us to more accurately calculate the amount of gas generated from the Longmaxi shale in the Sichuan Basin.