The western sub-depression of the Bozhong Depression, characterized by complex fault systems and multi-stage tectonic activities, produced mixed-source oils that pose significant challenges for oil-source correlation using conventional geochemical methods. A systematic geochemical analysis of biomarker ratios from four oilfields was carried out. Multivariate statistical techniques, including principal component analysis (PCA), hierarchical cluster analysis (HCA), and nonlinear dimensionality reduction approaches such as t-distributed stochastic neighbor embedding (t-SNE) and uniform manifold approximation and projection (UMAP), were applied to unravel the relationships between crude oils and prospective source rocks. Fluid-inclusion analysis and basin modeling were integrated to reconstruct the multi-stage oil-charging history. It was found that t-SNE more effectively reduces high-dimensional nonlinear relationships between crude oils and source rocks, while UMAP produces similar clustering that validates the robustness of t-SNE. Four oil families were recognized and correlated with three key Paleogene source rocks: Dongying Formation Mbrs 3 (Dong 3), and Shahejie Formation Mbrs 3 (Sha 3) and 1 (Sha 1). Specifically, Family 1 oils mainly originate from Dong 3; Family 2 oils show mixed-source contributions from Dong 3 and Sha 3; Family 3 oils are primarily sourced from Sha 3; and Family 4 oils are mainly derived from Sha 1 with a limited contribution from Sha 3. Sha 1 is the significant source rock, while Dong 3 is vital for the oil accumulation in the northern steep slope area. This research demonstrates the efficacy of t-SNE in solving complex oil-source correlation problems, with UMAP offering complementary validation, and provides new insights for petroleum system research in the Bohai Bay Basin and other multi-source basins globally.

The relative contributions of biomarker ratios to end-member mixed oils are intrinsically nonlinear, whereas conventional oil–source correlation techniques (e.g., principal component analysis, PCA) are inherently linear. This mismatch between the nature of the data and the analytical framework limits the extraction of geochemical information in complex regions hosting multi-stage petroleum systems and substantially undermines the reliability of mixed-source oil correlation. To address this problem, we selected the east-dipping flank of the Shijiutuo Uplift in the Bozhong Depression as a case study, an area characterized by multi-source hydrocarbon charging, complex fault systems, and pervasive mixed-source oils. A combined integrating hierarchical cluster analysis (HCA) with kernel principal component analysis (KPCA) and multidimensional scaling (MDS) is proposed. The results show that KPCA effectively captures the nonlinear features of biomarker data, and MDS, as a complementary verification tool, yields clustering results consistent with those of KPCA. The density curves of the dimensionality-reduced data distributions produced by the two methods are morphologically consistent, confirming the robustness of the results. Specifically, HCA successfully assigns the crude oils to two groups (Oil Family I and Oil Family II) on the basis of ten manually screened biomarker ratios. KPCA and MDS effectively discriminate three sets of source rocks: the third member of Shahejie Formation (E2s3), the first member of the Shahejie Formation (E2s1) and the third member of the Dongying Formation (E3d3). Oil Family I derives from a mixed source of E2s1 and E2s3, with E2s3 being the dominant contributor, whereas Oil Family II is sourced predominantly from E2s1. This study demonstrates that KPCA offers greater rationality and accuracy in resolving complex oil-source correlation problems, while MDS serves as effective comparative and validation tools. The proposed approach provides new insights into oil–source correlation in the Bohai Bay Basin and in other multi-source basins worldwide.

Hydrocarbon fluids play crucial roles in Pb-Zn mineralization, yet the contribution of metals from hydrocarbon fluids remains a key research topic. Based on petrographic analyses of sulfide minerals and solid bitumen, combined with LA-ICP-MS analysis of sphalerite, this study investigates hydrocarbon-phase evolution during metal mineralization and the composition of trace elements and rare earth elements (REEs) in sphalerite formed in various hydrocarbon phases. The study focuses on the classical lead-zinc mineralization belt of the Yangtze Block, South China. By comparing the composition of trace elements and REEs in solid bitumen and sphalerite across different hydrocarbon phases, the hydrocarbon contribution to metal mineralization is assessed. The results indicate that hydrothermal activity induced oil cracking in the reservoir, leading to the formation of two distinct types of sphalerites before and after oil cracking, reflecting environments with and without crude oil. Sphalerites formed before and after oil cracking exhibit formation temperatures of 132-252 degrees C and 88-202 degrees C, respectively. Both sphalerites share identical ore-forming fluid sources with similar sulfur and oxygen fugacity and the weak difference in their trace element compositions was caused by the decreasing fluid temperature, suggesting that crude oil did not significantly contribute to ore-forming metals. Moreover, the compositions of trace elements and REEs in both sphalerites differ from those of solid bitumen from oil cracking, further supporting that the metals for mineralization were not from crude oil. Instead, hydrothermal fluids induced rapid oil cracking, causing metals like Pb and Zn in crude oil to precipitate with solid bitumen without mineralization. This study provides direct evidence that metals transported by hydrocarbons precipitate with solid bitumen during oil cracking and do not contribute to Pb-Zn mineralization in medium-to high-temperature hydrothermal systems, disproving previous assumption that inferred metal involvement in mineralization solely based on high metal concentrations in hydrocarbon fluids.

Tight oil reservoirs, characterized by low porosity and permeability, frequently exhibit a significant mismatch between substantial resource potential and constrained production due to the water injection. Gas injection, particularly with CO2 and CO2-hydrocarbon mixture gases, presents a promising enhanced oil recovery strategy. In this study, we employed a high-pressure microfluidic platform to visualize and compare the displacement behavior of pure CO2 and CO2-CH4 (7:3 molar ratio) mixtures under reservoir-representative conditions (75 °C, 18.1 MPa). Results show that pure CO2 achieved superior oil recovery (∼80%), with less residual oil and weaker gas fingering, while the CO2-CH4 mixture displayed pronounced gas channeling, stronger phase separation, and lower oil recovery (∼50%), especially in smaller pores (<500 μm). Residual oil morphology evolved from continuous clusters to disconnected droplets, films, and corner-trapped states, highlighting the interplay between pore geometry, capillarity, and fluid properties. This work provides direct experimental insights into gas injection efficiency in tight formations and evaluating gas-based EOR mechanisms at the microscale.

Hydrocarbon reservoirs in ancient and deeply buried formations typically exhibit complex evolutionary histories. After experiencing high temperatures, pressures, and multiple types of secondary modifications, the geological information carried by hydrocarbons is superimposed and difficult to interpret. Methane carbon isotopes (S13C) in the Sinian natural gas in the central Sichuan Basin are heavier than those of the reservoir solid pyrobitumen (SB) and are considered an 'anomalous' fractionation. Therefore, based on the abundant S13C data of the source rock, SB, and natural gas, this study aimed to interpret the geological significance recorded by the 'anomalous' fractionation combined with the analysis of geological elements and the evolution process of the gas reservoir. The results showed that the combined contributions of multiple source rocks lead to differences in the original S13C of crude oil in paleo-oil reservoirs. Among them, the slope of the paleo-uplift was closer to the Deyang-Anyue rift trough, where the S13C of the main Cambrian source rocks was negatively biased, making the S13C of the paleo-oil reservoirs more negative. During the late thermal evolution, deasphalting was caused by gas produced from oil cracking under high temperatures and pressures. In contrast, the adsorption of clay minerals and gas intrusion due to kerogen degradation in the source rocks had little effect on deasphalting. The S13C values of the bulk SB precipitated by deasphalting were light and similar to those of the contemporaneous oil. However, the cracked gas with substantial negative S13C produced in the early phase completely escaped as the reservoir pressure increased; the traps concentrated only the late cracked gas, which was isotopically heavier than all the SB produced in the different stages. This study provides new insights into the evolution of isotopic fractionation in ancient oil and gas systems involving oil cracking and phase transformation.

Some natural pyrobitumens exhibit optical anisotropy similar to mesophase asphalt, potentially recording critical geological information. However, the significance of their distinctive optical textures remains understudied. Anisotropic pyrobitumen in the Ediacaran Dengying Formation (central Sichuan Basin, southwestern China) provides a key example. This study investigates controls on pyrobitumen optical texture evolution using petrography, scanning electron microscopy, and U-Pb dating. Then, it discusses the relationship between these textures and anomalous thermal events by analyzing their spatial distribution and their geological significance. Results reveal that anisotropic pyrobitumen in Dengying Formation formed from oil cracking caused by Late Permian hydrothermal activity. These pyrobitumen can be divided into two categories based on the optical textures: fibrous and mosaic, reflecting distinct internal physical structures. Fibrous pyrobitumen exhibits more ordered aromatic layers than the mosaic type. Temperature primarily controls optical textures by regulating polycondensation reactions and pyrobitumen viscosity. Although the Gaoshiti and Moxi areas share similar burial histories, Gaoshiti is dominated by highly evolved fibrous pyrobitumen, while Moxi contains predominantly low-evolved mosaic pyrobitumen. This disparity indicates formation of anisotropic pyrobitumen was unrelated to normal burial temperatures but to hydrothermal activity. This study demonstrates that anisotropic pyrobitumen cannot form below 240 degrees C, even over extended durations. Consequently, in situ anisotropic pyrobitumen in deep strata serves as an indicator of paleo-thermal anomalies, with varying textures acting as proxies for relative temperatures within these events. Under identical geological settings, fibrous pyrobitumen typically records higher temperatures than mosaic pyrobitumen.

This study focused on the typical lithofacies of well QY12-1-1 in Qikou Sag, carried out geochemical experiments, multi-temperature pyrolysis experiments and stepwise solvent extraction of soluble organic matter analysis, and established quantitative evaluation techniques for different occurrence states of medium mature shale. Shale oil with different lithologic facies and different occurrence states in the core section of the Shahejie Formation in the Qikou Sag was quantitatively evaluated. An improved four-step pyrolysis scheme of 300°C, 375°C, 400°C, and 600°C was developed to experimentally analyze shale oil core samples. The results indicated that the free oil content of the Es3 shale in the Qikou Sag was 1.1–8.06 mg/g (average of 4.19 mg/g); the mobile oil content accounted for 54.72%. The adsorbed oil content was 2.2–3.73 mg/g, with an average of 2.05 mg/g. The mobile, heavy free, and adsorbed oil contents were high in the thin, medium, and thick-lamellar mixed shale, as well as in the thin and medium-laminated calcareous shale. The mobile, heavy free, and adsorbed oil contents in the thin-layered mixed shale exceeded that in the medium-laminated felsic shale, with the thin-laminated felsic and thick-layered mixed shales exhibiting the content values. The newly established characterization method of hydrocarbons with different occurrence states exhibited good correlation with the conventional pyrolysis methods and the distributed solvent extraction results. Therefore, the proposed method can be used to study the occurrence mechanism of shale oil and a rapid evaluation of shale oil content.

Reservoirs in the Sinian Dengying (DY) to Lower Cambrian Longwangmiao (LWM) formations in the central Sichuan Basin exhibit evident hydrothermal activities with pyrobitumen showing signs of alterations caused by hydrothermal fluids. However, few studies have explored the relationship between hydrothermal fluid activity and the evolution of natural gas accumulation, resulting in a significant lack of understanding of oil and gas accumulation history in the DY Formation. The impact of hydrothermal fluids on oil and gas accumulation in the DY Formation is substantial, and a correct understanding of the natural gas accumulation process and the identification of favorable exploration areas in the DY Formation require further research into hydrothermal cracking gas accumulation. By examining the filling features, optical textures, and structural characteristics of pyrobitumen and conducting geochemical studies on fluid inclusions trapped by hydrothermal minerals, this study explored the genesis of pyrobitumen in the DY to LWM formations. The relationship between hydrothermal fluid activity and oil cracking was also analyzed. The the pyrobitumen in the DY to LWM formations in the central Sichuan Basin were formed during hydrothermal fluid activity, exhibiting the same optical anisotropy characteristics as the mesophase pyrobitumen. Pyrobitumen can be divided into four types: fine-grained mosaic, medium-grained mosaic, coarse-grained mosaic, and streamline types. Its formation temperature exceeded 300 ℃, far surpassing the maximum burial temperature of the strata, indicating its hydrothermal fluid-driven genesis. The hydrothermal fluid activity occurred during the Late Permian and was related to the Emeishan mantle plume. The temperature of the hydrothermal fluids exceeded 300 ℃, leading to crude oil cracking in reservoirs of the DY to LWM formations. This study found that hydrothermal fluid activity advanced the cracking time of crude oil in the paleo reservoirs of the DY to LWM formations to the Late Permian, disrupting the existing accumulation model and helping us re-understand the evolution process of gas reservoirs and identify favorable accumulation areas.

Ultra‐deep Sinian carbonate rocks are rich in natural gas, and the Deng‐4 Member of the Central Sichuan Basin has been shown to have an extremely high degree of thermal evolution. They are characterized by dry gas produced due to the thermal cracking of palaeo‐oil reservoirs (PORs). The distribution of PORs as materials for the formation of cracked gas reservoirs remains unclear. The complex multistage evolution process and limited drilling data make it challenging to precisely and systematically recover a range of PORs. Based on basin and petroleum system modelling (BPSM), the bottom‐up migration and accumulation method was used to investigate the distribution of PORs. Research shows that the PORs in the Sinian Deng‐4 Member were mainly formed in the Early–Middle Triassic under the mixed contribution of Cambrian and Sinian source rocks, and the coupling of palaeostructural and trap settings controlled its accumulation. Generally, the distribution of PORs can be divided into two categories: one is located at the core of the uplift zone and is controlled by structural‐stratigraphic composite traps, whereas the other is controlled by a series of lithologic traps formed in the slope area. Sensitivity analysis showed that the distribution patterns of the PORs were mostly related to the facies conditions (physical characteristics) of the reservoirs. The widely distributed PORs provide necessary and sufficient material conditions for the formation of cracked Sinian gas reservoirs in the Central Sichuan Basin, and the North Slope area has great potential for natural gas exploration in the future.

The Bozhong Sag is the largest petroliferous sag in the Bohai Bay Basin, and the source rocks of Paleogene Dongying and Shahejie Formations were buried deeply. Most of the drillings were located at the structural high, and there were few wells that met good quality source rocks, so it is difficult to evaluate the source rocks in the study area precisely by geochemical analysis only. Based on the Rock-Eval pyrolysis, total organic carbon (TOC) testing, the organic matter (OM) abundance of Paleogene source rocks in the southwestern Bozhong Sag were evaluated, including the lower of second member of Dongying Formation (E3d2L), the third member of Dongying Formation (E3d3), the first and second members of Shahejie Formation (E2s1+2), the third member of Shahejie Formation (E2s3). The results indicate that the E2s1+2 and E2s3 have better hydrocarbon generative potentials with the highest OM abundance, the E3d3 are of the second good quality, and the E3d2L have poor to fair hydrocarbon generative potential. Furthermore, the well logs were applied to predict TOC and residual hydrocarbon generation potential (S2) based on the sedimentary facies classification, using ΔlogR, generalized ΔlogR, logging multiple linear regression and BP neural network methods. The various methods were compared, and the BP neural network method have relatively better prediction accuracy. Based on the pre-stack simultaneous inversion (P-wave impedance, P-wave velocity and density inversion results) and the post-stack seismic attributes, the three-dimensional (3D) seismic prediction of TOC and S2 was carried out. The results show that the seismic near well prediction results of TOC and S2 based on seismic multi-attributes analysis correspond well with the results of well logging methods, and the plane prediction results are identical with the sedimentary facies map in the study area. The TOC and S2 values of E2s1+2 and E2s3 are higher than those in E3d3 and E3d2L, basically consistent with the geochemical analysis results. This method makes up the deficiency of geochemical methods, establishing the connection between geophysical information and geochemical data, and it is helpful to the 3D quantitative prediction and the evaluation of high-quality source rocks in the areas where the drillings are limited.

Shale reservoirs contain petroleum that undergoes losses through oil expulsion and evaporation, with uncertain implications on shale oil reserves and mobility evaluation. This study focuses on understanding the influence of these losses on open‐system pyrolysis, the primary method for assessing shale oil content and mobility. Comprehensive analyses were performed on 26 lacustrine shale samples from the Chang7 Member, encompassing total organic carbon (TOC), programmed pyrolysis, solvent extraction, and gas chromatography–mass spectrometry (GC–MS). The research examines the impact of petroleum losses on petroleum fractions, the oil saturation index (OSI), and multi‐step pyrolysis outcomes. The findings indicate that Chang7 shale with TOC content above 7% experiences more substantial petroleum losses than those with TOC below 7%. Petroleum losses result in significant fractional distillation of crude oil in the shale, leading to the deterioration of shale oil properties and a notable reduction in free oil content in S 1 , ultimately causing a decline in OSI values. As a result, Chang7 shale with TOC below 7% demonstrates a higher potential for shale oil recovery, whereas Chang7 shale with TOC exceeding 7% should be considered more significant as a hydrocarbon source rock. Moreover, multi‐step pyrolysis is not suitable for assessing petroleum mobility in shale with low free oil content (OSI values below 100 mg/g). This limitation arises from the loss of free low‐boiling components in Chang7 shale, and the currently detected low‐boiling pyrolysis products may predominantly exist in an adsorbed state.

The organic matter （OM） enrichment mechanisms and depositional environment characteristics of lacustrine source rocks in the western Bozhong Sag,Bohai Bay Basin in Northeast China remain controversial.To address these issues,based on Rock-Eval pyrolysis,kerogen macerals,H/C and O/C ratios,GC-MS,major and trace elements,the Dongying Formation Member （Mbr） 3 （E 3 d 3 ）,the Shahejie Formation mbrs 1 and 2 (E 2 s 1+2 ),and the Shahejie Mbr 3 （E 2 s 3 ）source rocks in the western Bozhong Sag were studied.The above methods were used to reveal their geochemical properties,OM origins and depositional environments,all of which indicate that E 2 s 1+2 and E 2 s 3 are excellent source rocks,and that E 3 d 3 is of the second good quality.E 3 d 3 source rocks were formed under a warm and humid climate,mainly belong to fluvial/delta facies,the E 3 d 3 sediments formed under weakly oxidizing and freshwater conditions.Comparatively,the depositional environments of E 2 s 1+2 source rocks were arid and cold climate,representing saline or freshwater lacustrine facies,and the sediments of E 2 s 1+2 belong to anoxic or suboxic settings with large evaporation and salinity.During the period of E 2 s 3 ,the climate became warm and humid,indicating the freshwater lacustrine facies,and E 2 s 3 was characterized by freshwater and abundant algae.Moreover,compared with other intervals,the OM origin of E 3 d 3 source rocks has noticeable terrestrial input.The OM origin of the E 2 s 1+2 and E 2 s 3 are mainly plankton and bacteria.Tectonic subsidence and climate change have affected the changes of the depositional environment in the western Bozhong Sag,thus controlling the distribution of the source rocks,the geochemical characteristics in the three intervals of lacustrine source rocks have distinct differences.Overall,these factors are effective to evaluate the paleoenvironmental characteristics of source rocks by biomarkers,major and trace elements.The established models may have positive implications for research of lacustrine source rocks in offshore areas with few drillings.

Deep strata are extremely rich in hydrocarbon resources, and trap oil has undergone a long-term and multistage geological evolution that results in thermal cracking. However, compared with controlled experimental conditions, studies on the thermal cracking process of trapped oil under subsurface geological conditions are relatively scarce. Therefore, the major aim of this study is to reconstruct the oil reservoir cracking process based on an evolutionary study of a typical Ediacaran gas reservoir in China. By evaluating the detailed reservoir petrology, natural gas composition, isotopes, residual solid bitumen (SB) characteristics, fluid inclusion analysis, and in situ U-Pb dating of dolomite, this study combined an oil cracking kinetic model with actual geological elements and evolution to recover the four stages of trap oil cracking. Mutual verification of the forward model and inversion demonstrated that a suitable oil cracking kinetic model can be extrapolated to geological conditions. With an increase in the thermal evolution of the reservoir, the most unstable component in the oil first cracks, and a small amount of gaseous products are preferentially dissolved in the liquid oil. The major components of petroleum undergo thermal cracking and conversion to produce short -chain liquid hydrocarbons and wet gases. A large amount of wet gas generates an abnormally high fluid pressure. Wet gas usually escapes from potential channels (i.e., caprock microfractures and unconformity surfaces), thus dynamically maintaining the energy balance of the trap system and weakening the impact of high pressure on oil cracking. The wet gas products precipitate asphaltene in the oil, thus adjusting the composition and properties of the trap oil. The escape of the initial wet gas products, accompanied by a thermochemical sulfate reduction (TSR) reaction with residual oil, C2H6, and other wet gases as reactants, led to the formation of CH4-rich natural gas with a high drying coefficient in the trap of the highly over -mature evolution stage. Precipitated asphalt and the asphalt directly produced by oil cracking, coke rapidly under high temperatures and pressures to form SB with abnormally high reflectivity. Under geological conditions, oil cracking behavior is generally controlled by a combination of temperature history, tectonic history, fluid pressure background, trap preservation conditions, secondary alteration (e.g., TSR), and oil type, among which the reservoir temperature history remains the most important. Other factors should not be underestimated in a specific region. This study revealed a pathway model for the thermal cracking of trapped oil under real geological conditions, providing references for similar studies and other pathway models in different regions worldwide.

There have been many studies conducted on the Eocene source rocks (Shahejie Formation Mbrs 1 and 3) (E(2)s(1) and E(2)s(3)) of the Bozhong Sag, Bohai Bay Basin in East China. However, Oligocene source rocks (Dongying Formation Mbrs 2 and 3) (E(3)d(2) and E(3)d(3)) have also made significant contributions to petroleum accumulations in this region. Their organic matter (OM) enrichment mechanisms, environmental and ecological variations, and laterally variable facies remain subjects of debate, particularly in the lower Dongying Formation Mbrs 2 (E(3)d(2)(L)). Thus, we investigated the geochemical properties, depositional environments, and OM origins of E(3)d(2)(L) and E(3)d(3) source rocks from seven prospecting wells in southwestern Bozhong Sag. Our findings indicate that E(3)d(2)(L) source rocks are of poor-to-medium quality, whereas E(3)d(3) source rocks are classified as good-to-excellent quality. Notable differences in the geochemical characteristics between E(3)d(2)(L) and E(3)d(3) source rocks were observed. Hierarchical cluster analysis identified five genetic organic facies. The E(3)d(2)(L) source rocks comprises facies D2-, D2-, D2-, and D2-D3, whereas E(3)d(3) contains facies D3 and D2-D3, with D2-D3 being common to both source rocks. Additionally, an integrated OM enrichment model was established to evaluate Oligocene source rocks. The five genetic organic facies exhibit distinctive differences and some similarities regarding redox conditions, water salinity, and OM origins. Their geochemical characteristics within the same intervals display pronounced lateral heterogeneity from deep source rocks deposits to more marginal water depths. The established model provides guidance for the prediction and exploration of effective Oligocene source rocks in the Bohai Sea and research on the Paleogene and Neogene petroleum systems. Moreover, the integration of biomarkers and hierarchical cluster analysis methods for organic facies analysis has significant implications for predicting of source-rock heterogeneity in other lacustrine rift basins.

The Gaotaizi reservoir in the Qingshankou Formation, northern Songliao Basin is one of the most potential tight oil targets in China and it is underlain directly by the OM-rich shales of the Qingshankou Formation. Previous studies indicated a strong oil-bearing heterogeneity in the Gaotaizi reservoir, while the relationship between pore-throat system and oil-bearing property is poorly understood. Thin section, Soxhlet extraction, MICP, fluid inclusion PVTX simulation and basin modelling were combined to investigate the pore-throat structure, and its effect on oil-bearing abundance and the tight oil accumulation effectiveness. Three pore-throat structures in the Gaotaizi reservoir were identified. The pore-throat size distribution (PSD), pore-throat configuration, and the corresponding physical properties became worser from Type I to Type III, as well as the pore types. A close relationship between pore-throat structures and sedimentary facies was established. Type I and II were dominated in mouth bar sand, while Type II, and Type III were mainly distributed in distal sandbars and sheet sand, respectively. The fluid properties and oil-bearing grades in the Gaotaizi tight sandstones were significantly controlled by the pore-throat structures. There were few fluids produced from the tight sandstones with Type III pore-throat structures, whose pore-throat size was almost half of that in tight sandstones with oil production. The dynamic model and ratio of pore containing oil (RPO) parameter were proposed. The residual pressure difference between the source rock and reservoir was 4.1 MPa, and the corresponding lower limit of pore-throat radius for tight oil accumulation was around 180 nm considering the limited buoyancy. Under the same driving force, the RPO of the Type I, II, III pore-throat structure reservoir was 74.4%, 58.0%, 23.3%, respectively, caused by pore-throat structure differences. It shows that an optimal tight oil “sweet spot” formed in the Type I reservoir, and favourable tight oil zones typically developed in the Type II reservoir, whereas only poor tight oil or dry zones developed in the Type III reservoir. This research improves the understanding of continental tight oil enrichment mechanism and provides a reference for optimizing favourable area of tight oil exploration.

专业课程是高校"立德树人"的主战场.以中国石油大学(北京)资源勘查工程专业为例,通过价值引领、需求驱动和多元融合三个维度,实现家国情怀、高阶思维、关键能力、核心知识四个方面的课程教学育人目标,创立了"三维四位"专业课程育人模式.该课程育人模式的应用实践极大地促进了人才培养、教师团队建设、课程资源建设、专业和学科发展,并推广应用到全国油气地质教育领域,取得了显著成效.

The hydrothermal activity in the Ediacaran Dengying (DY) Formation in central Sichuan has modified the reservoirs and paleo-oil reservoirs; however, these modifications are not specific due to the challenges in recovering the hydrothermal scale. This paper classified pyrobitumen in the DY Formation into five categories by optical textures and analyzed the physical structure and trace element composition of the different pyrobitumen using scanning electron microscope, reflectance, and trace elements. Finally, the responses of the trace element concentrations and optical textures of the pyrobitumen to hydrothermal alteration were discussed and used to restore the hydrothermal scale in the central Sichuan Basin. The results show that isotropic, fine-grained, medium-grained, coarse-grained mosaic, and fibrous pyrobitumen develop in the DY Formation. As the optical texture of the pyrobitumen changes from isotropic to mosaic to fibrous, the order degree of aromatic lamella in pyrobitumen gradually increases, the maturity, the maximum reflectance, and the bireflectance of pyrobitumen gradually increase. Except for isotropic pyrobitumen, anisotropic pyrobitumen is subject to varying degrees of hydrothermal alteration. The hydrothermal alteration on pyrobitumen is primarily in the form of material exchange, precipitating illite, salt, and barium-enriched minerals in pyrobitumen pores and enriching some elements (Ba, Cr, Nb, and Sr) in the pyrobitumen. As the optical texture changes from isotropic to mosaic to fibrous, the element enrichment degree gradually increases. Medium-grained mosaic, coarse-grained mosaic, and fibrous pyrobitumen are widely observed in central Sichuan. Therefore, hydrothermal modification on the DY reservoirs and paleo-oil reservoirs is not limited to the deep faults but widely develop in central Sichuan, and should be an essential part of the further study of hydrocarbon accumulation.

Pore structure, as the focus of shale reservoir research, has important influence on the occurrence of shale oil. In this paper, 10 shale core samples from the 7th member of Triassic Yanchang Formation (Chang 7 member) in Huachi area, Ordos Basin were selected to carry out scanning electron microscope (SEM) observation and low-temperature nitrogen adsorption experiment, and the fractal dimension was calculated to quantitatively characterize the pore structure of shale in the research area combined with fractal FHH model. On this basis, the relationship between fractal dimension and pore structure parameters and oil-bearing parameters was discussed, and the main influencing factors of pore development of shale in the Chang 7 member were determined. The results show that the shale of the Chang 7 member in Huachi area has high organic matter abundance, which are good-to-excellent source rocks mainly composed of quartz and clay minerals, with good oil-bearing property (up to the middle oil-bearing level) and mobility. The reservoir space is dominated by intergranular pores, intragranular pores and a small amount of organic pores. There are two types of pore morphology, namely, parallel plate-shaped slit+unilateral slit and ink bottle-shaped + parallel plate-shaped slit. The pores are mainly micropores and mesopores, with macropores less developed. Most samples have fractal characteristics. The fractal dimension D1 of small pores is between 2.264 7 and 2.714 9, and the fractal dimension D2 of large pores is between 2.373 3 and 2.77 7. Among them, D2 has a good correlation with surface area, pore volume, average pore diameter and S1, which can characterize the development characteristics of pore structure and oil-bearing property of shale, while D1 can only characterize the mobility of shale oil. The pore development of shale is mainly controlled by TOC and quartz content, and has a certain relationship with feldspar content, while clay mineral content is not the main influencing factor.

Objectives: The Chang-7 organic-rich shale in the Upper Triassic Yanchang Formation of Ordos Basin, with high abundance of organic matter and good type, is the main source rock of Mesozoic oil system, which has great hydrocarbon generation potential. The enrichment of organic matter in this unit mainly depends on the high paleoproductivity and the sufficient supply of organic matter during the Chang-7 sedimentary period. Many researchers have accepted the occurrence of algal bloom in the Chang-7 period, but there are still no direct and powerful evidences to prove it. In this study, algal fossils characterized by single species and high abundance are found in carbonate nodules and the vicinity of vein pyrite, which provides a good evidence for the algal bloom and strong support for the nutrition of hydrothermal activities during the Chang-7 period. Methods: Microscope and scanning electron microscopy（SEM） are used to observed algae fossils. Energy spectrum analyzer is used to analyze the element composition of algae fossils. Thin section observation is carried out at the State Key Laboratory of Petroleum Resource and Prospecting, China University of Petroleum（Beijing）. SEM observation and energy spectrum analysis are carried out the Microstructure Laboratory for Energy Materials, China University of Petroleum（Beijing）.Results: Many algal fossils have been found on the edge of vein pyrite. They are single species, densely distributed and rich in organic matter.Conclusion: In the vicinity of vein pyrite and carbonate nodules in Chang-7 organic-rich shale, algal fossils have been well preserved due to pyritization, calcitization and dolomitization. These algal fossils are characterized by single genus and species, and high distribution abundance. The discovery of algae fossils has important geological significance. It can not only provide direct and powerful evidence for algae bloom during the Chang-7 sedimentary period, but also provide support for the nutritional role of hydrothermal activities in the same period.

Hydrocarbon-bearing fluid plays a crucial role in the Pb-Zn mineralization process. The hydrocarbon role is still the subject of metallogenic research. This study determined the metal and sulfur sources and the hydrocarbon role in the mineralization instigated by mixing of hydrothermal and hydrocarbon-bearing fluids in the central Sichuan Basin based on petrography, fluid inclusion geochemistry, S and Pb isotope compositions, and changes in hydrocarbon phases and components. The results indicated that hydrothermal input significantly improved the salinity and temperature of reservoir fluids. Hydrothermal stages can be divided into three: (I) pyrite and dolomite, (II) quartz and sphalerite, and (III) galena. Solid bitumen was formed at stage II, and the oil inclusions were converted into gas inclusions from stage I to II, suggesting that the hydrothermal fluids caused the oil cracking. The Pb isotope compositions of pyrite, sphalerite, and galena showed that the Pb-Zn deposit had two metal sources from surface karst and hydrothermal fluids. Raman spectroscopy and sulfur isotope compositions implied that H2S formed during hydrothermal input was generated from TSR resulting from hydrothermal sulfate. The H2S produced by TSR preferentially led to the precipitation of metals (Pb, Zn, and Fe) derived from the hydrothermal fluid, followed by the precipitation of metals derived from the karst fluid. After the metal elements in the reservoir were depleted, the remaining H2S was conserved together with the natural gas in the reservoir. This study unravels the transformation of oil to gas and the H2S generation in the reservoir through hydrocarbon inclusion analysis in the metallogenic study, providing new insight into the Pb-Zn mineralization involving hydrocarbon-bearing fluid participation.