Overpressure is developed in both the reservoirs and source rocks of the Huangliu Formation (Yinggehai Basin, South China Sea), with pressure coefficients reaching up to 2.31. This study investigates the mechanisms responsible for overpressure in the source rocks of the Huangliu Formation and reconstructs their temporal evolution. Overpressured mudstones have anomalously high acoustic velocity and low resistivity values. However, the absence of low density values indicates that disequilibrium compaction is not responsible for the observed overpressure. The source rocks in this formation predominantly contain Type III kerogen (gas-prone), with total organic carbon values ranging from 0.4 to 2.56% and with an average value of 0.79%. Overpressured mudstones are buried at depths above 3300-4300 m, and subjected to formation temperatures ranging from 135 to 200 degrees C and the relevant vitrinite reflectance (R-o) of 0.7-1.57%. Models of maturity and hydrocarbon generation history show that mudstones started to become overpressured at 3.5 Ma and that pore pressure is still increasing. This study provides new insights revealing that hydrocarbon generation, rather than disequilibrium compaction, is the primary mechanism driving overpressure development despite the low organic matter content of the source rocks.

Overpressure strongly influences gas migration and trapping in deep high-temperature/high-pressure (HTHP) reservoirs. However, its time-dependent evolution is commonly poorly constrained by direct, quantitative pressure proxies. Here we combine quantitative Raman spectroscopy and microthermometry of fluid inclusions with 1-D burial–thermal modelling to reconstruct multi-stage pore-pressure evolution associated with CH4-CO2 charging in Upper Miocene Huangliu Formation sandstones on the Ledong Slope, Yinggehai Basin. Fluid-inclusion petrography was used to target gas-rich inclusions and petrographically associated aqueous inclusions hosted by quartz microfractures and quartz overgrowths. Raman analyses quantify CH4-CO2 compositions and gas densities using the CO2 Fermi diad splitting and the position of the CO2 v1 band, while dissolved CH4 in aqueous inclusions is quantified using calibrated Raman peak-area methods. Trapping pressures are calculated by integrating Raman-derived densities/compositions with homogenization temperatures of coeval aqueous inclusions and appropriate equations of state; CH4-CO2 mixed-gas inclusions provide an internal consistency check (pressure deviations ≤1.7 MPa). CO2-rich inclusions define three reproducible density populations that correspond to three pressure stages from near-hydrostatic to strong overpressure (~27–47, ~58–74, and ~87–107 MPa). Mapping trapping temperatures onto burial histories indicates three CO2 charge episodes (2.0–1.8 Ma, 1.8–1.6 Ma, and ~1.2 Ma) and two CH4 episodes (~1.5 Ma and ~0.4 Ma). Peak palaeo-pressures approached ∼98% of lithostatic stress, implying that late high-pressure CO2 charging can locally exceed fracture thresholds, generate microfractures, and enhance gas migration and accumulation, while overpressure can be preserved over geological timescales. The reconstructed pressure history is consistent with present measured reservoir pressures, demonstrating that multi-phase quantitative Raman inclusion barometry (CH4, CO2, mixed CH4-CO2, and dissolved gas in aqueous inclusions) provides robust constraints on pressure evolution and pressure-controlled gas enrichment in overpressured basins.

Exploration in the Tazhong Uplift in the Tarim Basin, China, focuses on ultra-deep oil and gas in Cambrian subsalt dolomite reservoirs. Compared to the middle-shallow depth reservoirs, the ultra-deep layers are a result of complex oil and gas charging events and accumulation processes due to their deep burial depth, high temperature, high pressure, and complex geological settings. Therefore, in this study, diagenetic mineral petrology, fluid inclusion microthermometry and laser Raman spectroscopy, as well as U-Pb isotope dating were performed on the Lower Cambrian dolomite succession within well ZH1, combined with the reconstruction of its burialthermal history, to clarify the hydrocarbon charge period(s) and accumulation processes within these ultradeep oil and gas reservoirs. Results indicate that the first period of liquid oil charging mainly occurred in the Late Ordovician to Early Silurian, recorded as primary oil-gas inclusions in coarse-crystalline dolomite cements (dated as 453-435 Ma). These inclusions are characterized by mature oil infill with yellow-brown to blue-white fluorescence, indicating a continuous crude oil charging process. Subsequent natural gas charging mainly occurred in two stages in the Permian. The early-stage II1 reflects oil cracking at high temperature related with Early Permian magmatic activity and natural gas charging related to hydrocarbon generation and expulsion from source rocks. They are recorded as secondary gas inclusions in quartz healed fractures, with a composition of CO2-bearing and methane-dominated natural gas. However, the late-stage II2 was dominated by thermochemical sulfate reduction (TSR)-driven oil cracking and natural gas charging, which occurred during the Middle-Late Permian. The latter is recorded as primary gas inclusions in blocky calcite cements (dated as 263 Ma), with its natural gas characterized by methane gas with high H2S and CO2 content. Compared with the late stage of natural gas charging, the formation fluid during the early natural gas charging stage is characterized by significantly higher temperature and pressure. The phenomenon is likely attributed to abnormally high geothermal temperature resulting from magmatic activity and large amounts of gas charging in a short time. For well ZH1, fault damage to traps may be the main factor for the loss and relocation of late Caledonian liquid oil, and the loss or ineffective accumulation of natural gas in the Late Hercynian. The results of this study give an insight into the hydrocarbon accumulation process of a Cambrian subsalt dolomite reservoir in the Tazhong Uplift area, and provide a reference for future oil and gas exploration in this region. The followed research protocol, however, is certainly of use for carbonate reservoirs worldwide.

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 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.

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.

Continental rifting is often associated with important magmatism, which significantly influences the Earth's climate. In this study, we use comprehensive 3D seismic and borehole datasets from Northern China to document magma intrusion and associated hydrothermal vent complexes (HTVCs) during the Cenozoic. The aim is to understand their impact on Late Oligocene-Early Miocene climate. Both Mesozoic and Cenozoic magma intrusions occurred in the Bohai Bay Basin, Northern China, while Cenozoic magmatism in the Bohai Bay Basin occurred during Late-Oligocene to Early-Miocene, when the final stage of rifting occurred in the region. Methane produced by Cenozoic magma in the Boxing Sag alone is estimated to be 27.2-820 Gt, which accounts for approximately 3-5% of the total methane produced in Northern China (1760-21,100 Gt). Our study suggests that warm climate during late Oligocene was potentially influenced by intensive rifting related sill emplacements in basins such as the Bohai Bay Basin. Giving the extensively developed Cenozoic magmatic intrusions in the Bohai Bay Basin, our results suggest that, similarly to the Paleocene-Eocene thermal maximum (PETM), igneous activity during Late-Oligocene might played a significant role in driving the Late Oligocene Warming event.

This study aims to resolve the genetic origin of crude oils accumulated in the D Subsag and to assess the potential cross-sag hydrocarbon migration from the adjacent Haizhong Sag. The D Subsag, situated on the western margin of the Weixinan Sag in the Beibuwan Basin, is a significant petroleum province with proven reserves exceeding 10 million tons in the Weizhou Oilfield. However, the origin of these oils and the contribution from the Haizhong Sag source kitchen remain poorly constrained, hindering accurate resource assessment. To address this, we integrated organic geochemical analyses of nine source rock samples from the Haizhong Sag (Well H1) and eight crude oil samples from the D Subsag reservoirs. Bulk geochemical and biomarker signatures reveal distinct organic facies within the Paleogene succession. Type III kerogen, characterized by terrigenous higher plant input (high C19+20 tricyclic terpanes and C-29 regular steranes, Pr/Ph > 2.5) deposited under oxic freshwater conditions, dominates source rocks from the third member of the Weizhou Formation (EWZ(3)). In contrast, the second and third members of the Liushagang Formation (Els(2) and Els(3)) contain mixed Type II2-III kerogen with elevated contributions from lacustrine algae and aquatic organisms (elevated C-23 tricyclic terpanes and C-27 regular steranes). Thermal maturity assessment (with T-max of 436 to 448 degrees C) confirms that all source intervals are within the oil generation window. Two genetically distinct oil groups are identified in the EWZ(3) reservoirs. Group 1 oils (Well W4) exhibit a lacustrine algal signature (C-27/C-29 sterane > 1.15; low Pr/Ph 1.54-1.68) that does not correlate with the analyzed Haizhong Sag source rocks, suggesting localized, intra-sag source contributions. In contrast, Group 2 oils (Wells W6 and W6-2) display strong geochemical affinities with the Els(2) and Els(3) source rocks, evidenced by mixed terrestrial/aquatic signatures (& sum;nC(21)(-)/& sum;nC(22)(+) < 1.0). These findings confirm that fault systems acted as conduits for long-distance migration from the Haizhong Sag, while also highlighting a previously unrecognized contribution from local source intervals. This refined petroleum system model provides critical constraints for delineating remaining hydrocarbon potential and reducing exploration risk in the Beibuwan Basin.

Lithium-(Li)-rich brines represent an increasingly important strategic resource and are commonly associated with evaporites. Their formation has traditionally been mainly attributed to evaporation-driven concentration under arid paleoclimatic conditions. This study investigates the genetic mechanism of the thick anhydrite deposits and associated lithium-rich brines in the Middle Triassic Zhouchongcun Formation of the Lower Yangtze region. Through integrating petrographic, elemental, and isotopic geochemistry and fluid inclusion analyses, combined with reconstruction of the stratigraphic burial-thermal history, we demonstrate that the formation and evolution of these evaporates are closely linked to multiple tectonic-thermal events. Petrographic characteristics and carbon-oxygen isotopic data indicate that the anhydrite initially formed in a restricted evaporative environment during the Middle Triassic, with δ13C ranging from -2.9 to -0.4‰ and δ18O values from -8.1 to -5.6‰, showing a significant positive correlation. Fluid inclusion data reveals subsequent complex hydrothermal overprinting. Primary inclusions record homogenization temperatures of 181.3-210.2 °C, corresponding to the peak paleo-temperature reached during early deep burial. In contrast, secondary inclusions yield lower homogenization temperatures of 135.8-174.3 °C, consistent with hydrothermal activity associated with the Yanshanian tectonic-thermal event. Burial-thermal history reconstruction indicates significant heating during the Middle Jurassic, with maximum temperature reached between approximately 150-170 Ma, coinciding with regional magmatic-tectonic activity. These results indicate that the anhydrite underwent intense reworking by medium- to high- temperature hydrothermal fluids during the Yanshanian period, superimposed upon its primary evaporative sedimentary origin. Geochemical data further shows that both fluid inclusions within anhydrite and the formation brines belong to a mixed sodium sulfate-sodium chloride hydrochemical type, supporting a common fluid source The lithium content in secondary inclusions is more than 4.8 times higher than that in primary inclusions, which the lithium content in regional intrusive rocks is 9.4 times higher than background levels, indicating a dominant contribution from Yanshanian magmatic-hydrothermal fluids. Micro-Raman spectroscopy combined with brine ion composition analysis jointly provides additional evidence for substantial hydrothermal input of lithium. Based on these observations, a three-stage genetic model is proposed: (1) sedimentary foundation, characterized by anhydrite precipitation and initial brine formation in a closed evaporative basin during the Middle Triassic; (2) lithium addition via hydrothermal reworking, whereby lithium-rich magmatic-hydrothermal fluids ascended during the Yanshanian event (∼150 Ma), modifying pre-existing anhydrite and enriching brines at temperatures of 150 °C; and (3) structural adjustment and accumulation, involving lithium migration and concentration within anhydrite-dolostone anticline traps during post-Late Cretaceous uplift and cooling under extensional tectonic conditions. This model highlights the key controlling role of medium-low temperature hydrothermal events in the formation of evaporite-type lithium resources and provides a new genetic framework and exploration guide for lithium-rich brines in evaporite basins.

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.

Organic matter (OM)-hosted pores play a crucial role in unconventional shale reservoirs, with their development influenced by OM type and thermal maturity across terrestrial, transitional, and marine deposits. In this study, a comparative analysis of porosity and pore structures is presented using organic petrographical, petrophysical, and mineralogical methods on organic-rich samples from diverse depositional environments. A pore evolution model for these sediments in different settings is proposed. Results show that kerogen particles in terrestrial shales at low and moderate thermal maturity (Dameigou Formation and Qingshankou Formation) are mostly nonporous. Transitional shales (Longtan Formation) contain vitrinite and inertinite, with only some inertinite exhibiting visible primary pores. In marine shales at higher maturity (late oil window; Dalong Formation), the interparticle pore space is occupied by solid bitumen, and secondary porosity is present at higher maturity, approaching the thermal gas generation stage. In over-mature marine shales (Wujiaping and Daye Formations), secondary pores are densely distributed within pyrobitumen. A negative correlation between organic carbon content and pore volume is observed in low-maturity lacustrine and transitional shales due to poorly developed kerogen-bound pores and interparticle pore occlusion by solid bitumen. However, over-mature marine shales exhibit a strong positive correlation due to extensive secondary porosity in pyrobitumen. Thus, pore evolution within OM is controlled by kerogen type and maturity. In oil-prone marine and lacustrine shales, secondary porosity in solid bitumen and pyrobitumen increases with thermal maturity. In contrast, terrestrial kerogen rarely forms solid bitumen and mainly develops micropores rather than mesopores at high maturity.

Extensive studies have demonstrated the formation of overpressured paleo-gas reservoirs in the Precambrian carbonate reservoirs of the Sichuan Basin, followed by the dissipation of overpressure and natural gas during the Yanshanian-Himalayan tectonic uplifts. Currently, no comprehensive framework exists for evaluating the overpressure evolution during uplift. In this study, a multi-approach method including fluid inclusion, microthermometry, Raman spectroscopy, and thermodynamic modeling, was used to investigate pore overpressure evolution and controlling factors in the Ediacaran Dengying reservoir, and its implications for gas accumulation and modification in the southwestern Sichuan Basin (SWSB). Fluid inclusion data and modeling results indicate that the evolution of overpressure and gas pools within the Dengying reservoirs can be divided into three stages: 180-100 Ma, 100-25 Ma, and 25 Ma to present. During the first stage, pressure coefficients increased from 1.36 to 1.57 due to favorable preservation conditions that promoted the formation of paleo-gas pools. The presence of individual bitumen inclusions provides the direct evidence for the occurrence of oil cracking, which contributed to overpressure generation. The second stage is charactered by the modification of paleo-gas pools and overpressure. Over 35 % of the natural gas in the Ziyang area leaked from paleo-gas pools, reducing pressure coefficients from 1.57 to 1.07. Conversely, pressure coefficients in the Weiyuan area increased from 1.35 to 1.91. Tectonic compression and uplift in the Weiyuan area caused a 19.4 % increase in overpressure. Therefore, gas recharge in the paleo-gas pools contributed more significantly to the increase in overpressure. With the rapid uplift of the Weiyuan area, the third stage was characterized by a pressure drop from overpressure to normal pressure due to fault and fracture development, as well as gas leakage. Following the dissipation of overpressure, residual paleo-gas pools were preserved in the Weiyuan field and Ziyang gas-bearing zone.

The Ediacaran Dengying Formation (Z2dn) of the Sichuan Basin, Southwestern China, experienced multi-stage fluid flow, which accompanied the reduction and modification of reservoir porosity. Porosity in the Z2dn carbonate reservoir thus varies in different structural units. Fluid inclusion and implications for reservoir porosity were investigated by combining petrographic, geochemical, fluid inclusion, in-situ U-Pb geochronological, and basin modelling data. Three stages of dolomite cements (CD-1, CD-2, and CD-3) and one stage of dolomite veining (FD) were petrographically, geochemically, and geochronologically distinguished in reservoir rocks, and respectively dated at c. 453 Ma, 336 Ma, and 173 Ma. Two stages of dolomite and quartz cement formation (CD1, CD-2, Qtz-1, and Qtz-2) were subsequently formed at c. 453 Ma, 298 Ma, 182 Ma, and 165 Ma. CD-1, CD-2 cements and FD veins were interpreted as diagenetic fluids and formed in the sealed environment during the Late Ordovician-Early Permian; they led to multi-stage cementation of reservoir intervals and a reduction in porosity. Importantly, the diagenetic sequences between bitumen and dolomite generation phases indirectly define the dates of two oil charging events. The first episode only occurred in the central Sichuan Basin during the Silurian, and its timing is constrained by the absolute ages of CD-1 and CD-2 cements. The second oil charging episode was the most important in the Sichuan Basin and occurred during Indosinian tectonics according to the trapping temperatures of bitumen-bearing inclusions in Qtz-1 veins. Also significantly, oil charge was able to inhibit the precipitation of authigenic minerals in reservoir intervals. Oil cracking in the Z2dn reservoir occurred at 173-165 Ma, accompanied by weak overpressure generation in the southeastern Sichuan Basin and medium-intensity overpressure in the central Sichuan Basin. Once again, it prevented compaction and solution compaction to maintain reservoir porosity. Moreover, CD-3 and Qtz-2 cements were possibly derived from hydrothermal fluid, which led to the dissolution of the Z2dn dolomite reservoir. As corollary, the numerous stages of dolomite cementation recorded here, the recognition of a single episode of oil charge, and weak reservoir overpressures, are the main factor contributing to a lower porosity development in the southeastern Sichuan Basin when compared to the central Sichuan Basin. These results have profound implications to the economic potential of similar oil and gas prospects deep in lower Paleozoic rocks across the world.

Accumulations of large volumes of CO2 related to mantle degassing, metamorphic reactions or magmatic processes have been found in many oil-gas bearing basins around the world . The Huangqiao area of the Lower Yangtze Plate hosts the largest CO2 gas field on mainland China. Throughout geological history, a significant influx of deep mantle-derived CO2 fluid occurred in this area. Understanding the timing of these CO2 charge and their effects on crude oil reservoirs is crucial for interpreting the distribution of present-day resources. The Cenozoic was long believed to be the only period during which CO2 charging occurred in the Huangqiao area, primarily because evidence of earlier CO2 fluid charges had been scarce. To address this, a comprehensive study utilizing petrography, cathodoluminescence, fluorescence and Raman spectrum of fluid inclusions, in-situ U-Pb dating, and basin modeling was conducted to elucidate the timing and interactions between crude oil and deep mantle-derived CO2 in the Permian Qixia Formation of the Huangqiao area. Three distinct phases of calcite veins were identified and dated: 251.7 ± 1.8 Ma, 124.16 ± 1.46 Ma, and 97.68 ± 1.20 Ma to 96.75 ± 0.25 Ma. The earliest CO2 charge, occurring around 251.7 ± 1.8 Ma, corresponds to a period when supercritical CO2 extracted low molecular-weight hydrocarbons from the S1g source rock. This timing aligns with the mass extinction event (251.4 ± 0.3 Ma), a rapid rise in atmospheric CO2 levels, and volcanic activity in the Permian Gufeng and Longtan Formations of the Lower Yangtze Plate, suggesting that the CO2 influx was volcanically driven. Between 124.16 ± 1.46 Ma and 96.75 ± 0.25 Ma, significant portions of the CO2 and crude oil within the Qixia Formation escaped due to tectonic uplift and erosion associated with the collision between the Yangtze Plate and the North China Plate. This research provides the first documentation of early mantle-derived CO2 fluid charges and their role in crude oil extraction from source rocks during transport from the mantle to the Earth's crust. Additionally, the study reconstructs the processes of CO2 and oil accumulation and leakage from the Indosinian to the Yanshanian periods, offering new insights into the evolution of hydrocarbon reservoirs in the Huangqiao area of Lower Yangtze Plate.

Calcite in hydrocarbon reservoirs records abundant information about diagenetic fluids and environments. Understanding the formation mechanisms of calcite is crucial for predicting reservoir characteristics and hydrocarbon migration. This study identifies the types of authigenic calcite present in the Lower Paleozoic carbonate reservoirs of the Bohai Bay Basin through petrographic analysis, cathodoluminescence, and other experimental methods. By integrating electron probe microanalysis, in situ isotopic analysis, and fluid inclusion studies, we further constrain the source of the diagenetic fluids responsible for the authigenic calcite. The results show that there are at least three types of authigenic calcite in the Lower Paleozoic carbonate reservoirs of the Bohai Sea. Calcite cemented in the syn-depositional-to-early-diagenetic stage displays very weak cathodoluminescence, with δ13C and δ18O and paleo-salinity distributions similar to those of micritic calcite. These features suggest that the calcite was formed during burial heating by sedimentary fluids. Calcite filling fractures shows heterogeneous cathodoluminescence intensity, ranging from weak to strong, indicating multiple stages of cementation. The broad elemental variation and multiple cementation events suggest that the diagenetic fluid sources were diverse. Isotopic data show that samples with carbon isotope values greater than −2.9‰ likely formed through water–rock interaction with fluids retained within the strata, whereas samples exhibiting more negative δ13C were formed from a mixed-source supply of strata and mantle-derived fluids. Calcite that fills karst collapse pores exhibits alternating bright and dark cathodoluminescence, strong negative δ18O shifts, and variability in trace elements such as Mn, Fe, and Co. These characteristics indicate a mixed origin of diagenetic fluids derived from both meteoric freshwater and carbonate-dissolving fluids.

The Tarim Basin serves as the major area for deep and ultra-deep oil and gas exploration and development. A significant breakthrough has recently been achieved in the exploration of ancient buried hill-type oil and gas reservoirs within the Cambrian System of the Paleozoic strata in well Tuotan 1, Kuqa Depression, Tarim Basin. Due to the ancient geological age and complex reservoir geology, systematic studies on oil and gas accumulation process and fluid evolution in this area remain insufficient. In this study, methods including biomarker analysis, petrological analysis, in-situ micro-area trace element and strontium isotope analysis, and fluid inclusions were used to determine the fluid origins of vein formation and the timing of multiple-phase of oil and gas charging in the dolomite reservoirs of the Xiaqiulitage Formation. The results revealed that the dolomite reservoirs in Xiaqiulitage Formation, well Tuotan 1 primarily developed two phases of calcite veins that filled fractures and dissolution pores. The first phase of calcite originated from deep, strontium-rich fluids, while the second phase of calcite veins derived from seawater. Two phases of oil-bearing fluid inclusions were predominantly developed within the second-phase calcite veins, comprising secondary blue-white fluorescent oil inclusions and secondary green fluorescent oil inclusions. The integration of fluid inclusion thermometry with single-well burial history reconstruction revealed that the first-phase blue-white fluorescent inclusions recorded oil and gas accumulation during the deposition of the Neogene Jidike Formation (23-20 Ma), while the second-phase green oil inclusions recorded oil and gas accumulation during the deposition of the Neogene Kuqa Formation (5-3 Ma). Oil-source correlation analysis indicated that the two phases of crude oil in the reservoirs of Xiaqiulitage Formation were derived from mixed contributions of lacustrine source rocks in the Triassic Huangsanjie Formation and Jurassic Qakmak Formation. The new findings from well Tuotan 1 in Kuqa Depression demonstrate that ancient strata in the foreland region of the Tarim Basin still retain favorable conditions for large-scale oil and gas accumulation, making buried hill-type oil and gas reservoirs a promising frontier for increasing reserves and production in Kuqa Depression.

In petroliferous sedimentary basins, the interplay between CO2 and hydrocarbons exerts a notable influence on hydrocarbon generation and accumulation. This research focuses on the Huangqiao oil and gas reservoir, which is known for hosting the largest CO2 reserves in China. U-Pb isotopic dating of calcite veins in fractures, carbon and oxygen isotope analyses, along with rare earth element (REE) analysis were applied to elucidate the chronology and origin of inorganic and organic fluids in the studied area. Petrographic observations revealed the presence of various components of fluid inclusions, including gaseous CO2, gaseous CH4, CH4-CO2 mixtures, and hydrocarbon fluids. Besides, through Raman quantitative measurements and thermodynamic simulations, the density, composition, pressure, and temperature characteristics of CH4 and CO2 bearing fluid inclusions were calculated. Based on the entrapment conditions of fluid inclusions and U-Pb dating results, two stages of hydrocarbon charging were identified: an early-Jurassic stage (approximately 200-185 Ma) characterized by mid-maturity oil and CH4 and an early-Eocene stage (approximately 61-41 Ma) marked by high-maturity oil and CH4. CO2 accumulation events were divided into two stages: high-density CO2 fluid activity during the early Eocene (approximately 59-39 Ma) and low-density CO2 fluid activity during the Tertiary-Quaternary (approximately 23-4 Ma). Moreover, deep fluid influx into reservoirs led to hydrothermal alteration, as evidenced by anomalously high homogenization temperatures and vitrinite reflectance. CO2 has an extraction effect on crude oil, where its late entry primarily results in the removal of lighter components, especially CH4. When high-temperature hydrothermal CO2 fluid enters the oil reservoir, it accelerates the cracking of crude oil and alters the fluid's composition. This thermal event also speeds up the source rock's thermal evolution, leading to extraction, pyrolysis, and gas displacement throughout the reservoir's development process. This study presents a comprehensive approach for quantitatively studying geological fluids in petroliferous basins of this nature.

Focusing on the geochronological issues related to the matching relationship between the strike-slip fault activity and the stages of hydrocarbon generation, reservoir formation, and hydrocarbon accumulation, this study aims to quantitatively constrain the tectonic–burial history, hydrocarbon generation history, reservoir porosity evolution history, and hydrocarbon accumulation history by determining the isotopic ages and temperatures of multiphase calcites (particularly the calcites which contain hydrocarbon-bearing fluid inclusions) and quartzs filling the fractures in the Ordovician strata within the non-foreland area of Tarim Basin. Three major findings have been obtained. (1) According to the tectonic–burial history restored under the constraint of the isotopic ages and temperatures, the non-foreland area of the Tarim Basin experienced a continuous burial process during the Cambrian–Ordovician period, with only a minor uplift at the end of the Silurian. Overall, the area was characterized by continuous hydrocarbon generation and a gradual increase in vitrinite reflectance (Ro). (2) While mechanical compaction and pressure-solution during burial progressively reduced the matrix porosity, the strike-slip fault activity during the Middle Caledonian II and III episodes induced physical fragmentation, which created extensive interbreccia pores, fault cavities, and structural fractures as seepage pathways for surface runoff, and, in conjunction with interlayer karstification, led to the development of widespread dissolution vugs. The formation of fracture-vug system in the Ordovician limestone provided effective storage space for hydrocarbons generated during the Late Caledonian and subsequent periods. (3) The Ordovician fault–karst limestone reservoirs underwent four stages of hydrocarbon accumulation: low–medium maturity liquid hydrocarbons during the Middle–Late Caledonian, medium–high maturity liquid hydrocarbons during the Middle–Late Hercynian, high maturity liquid hydrocarbons during the Indosinian, and high–over maturity gas during the Middle Yanshanian. Variations in hydrocarbon accumulation among different strike-slip faults or different segments of the same fault are controlled by differences in source rock maturity across structural units, as well as by the timing of fault activity and fault-related connectivity to hydrocarbon sources. This research also establishes a geochronological framework for investigating strike-slip fault- controlled reservoir formation and hydrocarbon accumulation, facilitating a more accurate determination of the reservoir formation and hydrocarbon accumulation stages, and providing critical insights for evaluating hydrocarbon enrichment zones in fault-controlled reservoirs.

The organic-rich shales in the Upper Permian Longtan Formation (LF) and Dalong Formation (DF) are important hydrocarbon source rocks and have become key targets for shale gas exploration in the Yangtze area, South China. To investigate the provenance, tectonic setting, paleoenvironmental conditions, and mechanisms of organic matter (OM) accumulation, this study presents an integrated petrological and geochemical study of a continuously cored well in the Xiangzhong Depression, South China. The LF was deposited in marine-continental transitional facies under a hot and humid climate with intense chemical weathering. OM is predominantly terrigenous-derived, consisting mainly of vitrinite and inertinite. Multiple geochemical proxies, together with pyrite framboid analyses, suggest that oxic, brackish water conditions, low paleoproductivity, and a high influx of terrestrial material prevailed during the deposition of the LF. In contrast, the DF comprises fully marine sediments, reflecting a depositional setting influenced by a rapid sea-level rise and progressive climatic aridification. These changes resulted in a saline, anoxic water column with enhanced primary productivity and reduced weathering intensity. The relationships between total organic carbon (TOC) content and geochemical indicators suggest that paleoclimate and terrigenous influx are the dominant factors controlling the OM accumulation in the LF, whereas upwelling-induced high productivity was the dominant factor driving OM enrichment in the DF. This study provides a comprehensive dataset on the LF and DF, which exhibit markedly different depositional environments, and aims to address the gap in the evaluation of Permian shale gas potential in the Middle Yangtze region.

Usually, deep oil and gas accumulation is often controlled by strike–slip faults. However, in the Tarim Basin, deep Ordovician oil and gas accumulations are also found in areas far from the fault zone. The process of oil and gas accumulation in deep reservoirs far from strike–slip fault zones is still unclear at present. The source and evolution of Ordovician fluids were analyzed using inclusion geochemical methods and the U–Pb dating technique. The analysis of rare earth elements and carbon–oxygen–strontium isotopes in the reservoirs showed that the reservoirs were weakly modified by diagenetic fluid. The fluid was derived from the fluid formation during the same period as the seawater, and no oxidizing fluid invaded the reservoir. The late oil and gas reservoirs had good sealing properties. The U–Pb dating results combined with homogenization temperature data revealed that the first-stage oil was charged during the Late Caledonian Period, and the second-stage natural gas was charged during the Middle Yanshanian Period. The evolution of the paleo-pressure showed that the charging of natural gas in the Middle Yanshanian was the main reason for the formation of reservoir overpressure. The strike–slip fault zone was basically inactive in the Middle Yanshanian. During this period, the charged natural gas mainly migrated to the reservoir along the unconformity surface and the open strike–slip fault zone in the upper part of the Ordovician reservoir. The source of the fluid shows that the reservoir in the late stage had good sealing properties, and there was no intrusion of exogenous fluid. The overpressure in the reservoir is well preserved at present.