Shale oil reservoirs are characterized by tight rocks, nanoscale pore and microfractures, and extremely low permeability. According to fluid mobility, pore fluids can be classified into three types: movable fluids, capillary-bound fluids, and clay-bound fluids. Accurate identification of fluid occurrence types and quantitative characterization of their spatial distribution form the basis for establishing calculation models for key parameters such as effective porosity and movable fluid saturation, and provide important guidance for reservoir development design and productivity prediction. This study was based on a nuclear magnetic resonance (NMR) measurement system and took the shale oil reservoir in the second member of the Funing Formation in Qintong Sag, Subei Basin, as the research object. On the basis of systematically reviewing relevant domestic and international studies, one-dimensional/two-dimensional NMR experiments were conducted on rock samples under multiple states, including water saturation, centrifugation, oven drying, and oil saturation (dodecane). This enabled quantitative determination of the boundary values of the three fluid types in shale oil reservoirs and the establishment of a two-dimensional identification chart of fluid occurrence states based on the NMR T1-T2 spectrum. The results showed that a centrifugation speed of 16 000 r/min could distinguish movable water from bound water in pores, whereas an oven-drying temperature of 70 °C could distinguish capillary-bound water from clay-bound water. The T2 relaxation of indigenous organic matter exhibited a high-amplitude feature, with the main peak located at T2 = 0.15 ms, and the distribution center of the two-dimensional T1-T2 spectrum was located at T2 = 0.03 ms and T1/T2 = 300. The NMR identification chart of fluid occurrence states effectively distinguished the distribution regions of clay-bound water, capillary-bound water, movable water, bound oil, movable oil, and organic matter, and could be used to obtain the saturation values of various fluids. These results provide a scientific basis for mobility evaluation, reserve parameter calculation, and development plan optimization of shale oil reservoirs, and offer important technical references for exploration and development practice in complex shale oil reservoirs.

In order to further guide the exploration and development of oil reservoirs in Tiebiancheng area,the pore throat structure and its complex characteristics of typical samples in Yan 8-Yan 10 layers were quantita-tively analyzed by using experimental methods such as high-pressure mercury injection,scanning electron mi-croscopy,cast thin section,fluorescence observation,oil saturation test and fractal theory,and the control effect of pore throat structure on oil content was discussed.The results show that the Yan 8-yan 10 reservoirs in Tiebiancheng area is mainly composed of lithic sandstone,and the pore types are mainly intergranular pores and feldspar dissolved pores,with micron sized pores widely developed.The average porosity is 14.54％and the average permeability is 0.24 × 10-3 μm2,belonging to medium porosity ultra-low permeability reservoir.The pore throat structure of low permeability reservoir is complex.The larger the sample storage space in this area,the higher the complexity of pore throat structure,which is mostly a combination of large pore and fine throat.The pore throat structure has three fractal segments,which corresponds to the large,medium and small pore throat segments in turn.The average fractal dimensions of each segment are 2.853 5,2.435 8 and 2.449 1,respectively.Although the reservoir capacity of the large pore throat section is high,it does not determine the overall oil saturation of the low-permeability reservoir.The more developed the macropore coarse throat combi-nation,the more homogeneous the distribution of the mesopore throat,which is more conducive to the enrich-ment of oil in low-permeability reservoirs.The radius range of pore throat which is most conducive to oil and gas enrichment is 0.02～1 μm.The research results provide a key scientific basis for further optimizing the oil and gas development strategy in the Tiebiancheng area.

With the increasing global energy demand, natural gas hydrates have become a focus of research and development. The South China Sea deepwater area has abundant natural gas hydrate resources, but its low permeability limits the commercialization process. This paper explores how to enhance gas production from natural gas hydrate reservoirs through a combination of fracturing technology and depressurization using numerical simulations. Numerical experiments were conducted under various well types and fracture configurations to evaluate their effects on cumulative gas production. The fracturing layer was optimized for different well types. We employed the embedded discrete fracture model (EDFM) to characterize the fracture structures in the reservoir and coupled it with a conventional hydrate numerical simulator to simulate different fracture morphologies. The results show that fractures in the three-phase layer provide the most significant production enhancement among all tested layers. Fractures within the three-phase layer deliver the largest production gain among all layers tested. By comparing the development effects of different well types, it is found that the combination of horizontal wells and hydraulic fracturing can effectively improve the recovery of hydrates compared with single well types and traditional exploitation methods. In particular, horizontal wells with stimulated reservoir volume (SRV) yield a big rise in gas production compared with the single-fracture model under identical conditions. Fractures in the three-phase layer shows the most significant improvement in production. Horizontal wells under the three-phase layer achieve about an 88.26% increase in production compared with the single-fracture simulation under the same conditions.

In the high mountain gorge region of western Sichuan, where complex tectonic activity and extreme geomorphic relief result in persistently high geological hazard intensity, landslide distribution in mountainous regions is governed by multiple controlling factors, among which lithological predisposition remains a critical factor in geohazard research. This study provides definitive evidence for the primary lithological control on landslide spatial patterns through integrated analysis of multi-source remote sensing data in Western Sichuan, China. Employing time-series Interferometric Synthetic Aperture Radar (InSAR) displacement monitoring coupled with high-resolution optical interpretation, we systematically identified 119 potential landslides in western Sichuan's complex terrain. Spatial distribution analysis reveals significant lithological dependence: 85 landslides (71.4 %) occurred within soft rock formations, 28 (23.5 %) in soft-hard interbedded strata, and only 6 (5.1 %) in hard rock units. Conditional probability analysis further confirms this lithological hierarchy, demonstrating order-of-magnitude differences in landslide occurrence probabilities between geological units (0.71 for soft rocks versus 0.05 for hard rocks). While slope gradient and orientation were considered, lithology emerges as the dominant controlling factor, evidenced by a 14.2:1 landslide density ratio contrasting soft and hard rock terrains. Our multi-sensor approach validates litho-logical controls through dual validation mechanisms: InSAR-derived deformation patterns exhibit a strong spatial correlation with litho-logical boundaries identified through optical interpretation, while statistical analysis quantitatively distinguishes the influence of lithology from topographic factors. These findings establish a material-centric framework for understanding slope instability mechanisms in stratified mountain systems, providing critical insights for targeted landslide risk management in lithologically heterogeneous regions. (c) 2025 COSPAR. Published by Elsevier B.V. All rights are reserved, including those for text and data mining, AI training, and similar technologies.

Persistent uncertainty in translating low-field nuclear magnetic resonance (NMR) T2 relaxation spectra into geometrically meaningful pore-throat metrics has long hindered the quantitative characterization of tight reservoirs. To address this issue, this study develops an enhanced conversion framework that incorporates scale-dependent pore geometry, enabling more realistic estimation of pore-throat radius distributions. Core samples were collected from the first member of the Shanxi Formation and the eighth member of the Shihezi Formation in the Ordos Basin. A comprehensive experimental dataset was established, including porosity and permeability measurements, X-ray diffraction (XRD) mineral analysis, NMR experiments, high-pressure mercury intrusion (HPMI), and constant-rate mercury injection (CRMI). The results demonstrate that total clay content exhibits weak correlations with pore size and porosity. In contrast, the occurrence and morphology of specific clay minerals exert significant control on pore connectivity and flow behavior. In particular, fibrous illite increases pore-throat complexity, while early chlorite coatings help preserve primary intergranular pores. A single geometric model cannot fully represent the complex pore-throat system in tight sandstones. For pores, a spherical geometry is most appropriate and indeed necessary. Smaller throats connecting these pores often exhibit geometries more consistent with cylindrical shapes. Within the coarse pore size range, large pores dominate the reservoir space and generally exhibit geometries that better conform to a spherical shape. And larger pores dominate the volumetric contribution in the coarse pore-size range. These observations suggest that a scale-dependent composite model could further improve the accuracy of NMR-based pore-size estimations. Therefore, the spherical-pore model provides a physically meaningful framework for characterizing pore structures in tight reservoirs. At the same time, incorporating scale-dependent considerations offers a promising avenue for future methodological development.

The structural characteristics and formation evolution of the Sinian Kaijiang-Xuanhan paleo-uplift play a foundational role in the formation and evolution of the Sichuan Basin. To comprehensively understand the structural characteristics and formation evolution of the Sinian Kaijiang-Xuanhan paleo-uplift, this paper, based on geological, logging, seismic, and drilling, further confirms the existence of the Sinian Kaijiang-Xuanhan paleo-uplift and provides a detailed study of its characteristics. The entire Ediacaran tectonic sedimentary framework of the Sichuan Basin was controlled by this northeast-trending paleouplifted area. The Dengying Formation in the Kaijiang-Xuanhan region and the Mianyang-Anyue-Changning region both exhibit a thinning trend, but the genetic mechanisms are different. The thinning in the former is the result of sedimentary control during the early stages of paleouplift, with the lower parts of the first and second stages being absent; in the latter region, this is due to subsequent erosion. During the deposition periods of the Doushantuo and Dengying formations, the Sichuan Basin was predominantly in a weak compressional state, forming the Kaijiang-Xuanhan paleo-uplift, with the main structural orientation being northeastward. By the late Dengying Formation and early Cambrian, the region experienced a weak extensional state, resulting in the development of the Mianyang-Changning rift, with the main structural orientation being north-northwestward. The Kaijiang-Xuanhan paleo-uplift underwent four stages: the incubation period (before the deposition of the Doushantuo Formation), the peak development period (during the deposition of the Doushantuo Formation), the decline period (during the deposition of the Dengying Formation), and the extinction period (during the Lower Cambrian deposition). The further confirmation and in-depth study of the Sinian Kaijiang-Xuanhan paleo-uplift enhances the understanding of the Neoproterozoic craton of the Sichuan Basin and enriches the theory of the formation and evolution of the Sichuan Basin.

BackgroundNatural fractures serve as both the primary storage space for free gas of deep coalbed methane (CBM) and pathways for hydrocarbon migration. Furthermore, these fractures can enhance the porosity and permeability of strata under the deep, high-pressure condition, significantly amplifying the permeability of coal seams. Therefore, the fine-scale characterization of the planar distribution of natural fractures is crucial to deep CBM production.Objectives and MethodsThis study investigated the No.8 coal seam in the Carboniferous Benxi Formation within the Daning-Jixian block on the eastern margin of the Ordos Basin. Through offset vector tiles (OVT) domain processing of offshore 3D wide-azimuth, broadband, and high-density (WBH) seismic data, this study determined five-dimensional seismic data: time, space (3D coordinates), offset (or shot-to-geophone distance), and azimuth. Then, fracture prediction was conducted through a pre-stack analysis of the azimuthal anisotropy attributes. Results and Conclusionsthis study developed a technical process for the five-dimensional seismic data-based interpretation that combined the methods of elliptical fitting and azimuthal statistics. The results reveal the presence of conjugate fracture systems in the study area: Yanshanian nearly EW/NEE- and Himalayan nearly SN/NNE-oriented fractures. The verification using multi-source data, including formation micro-imaging (FMI) logs, array acoustic logs, and fracturing curves, indicates that the azimuthal statistical method exhibited higher reliability in predicting fracture orientation (coincidence rate: 89 %) and developmental degree (prediction accuracy: 88.5 %). The results of this study have provided successful guidance for the optimization of horizontal well deployment, providing significant technical support for the efficient development of deep CBM. The relevant methodology can be widely applied to other basins bearing deep coal-bearing gas.

Barremian organic-rich black shales are significant source rocks in the eastern Tethyan Qiangtang Basin. Based on petrological, inorganic and organic geochemistry analyses, the black shales are divided into three units from bottom to top. Unit 1 micritic limestones exhibit high total organic carbon (TOC) contents and Type II2 kerogen, indicating a mixture of marine microalgae and land plants. Unit 2 black shales show the highest TOC contents, predominantly Type II1 kerogen suggesting marine microalgal source. In contrast, Unit 3 marls have relatively low TOC contents, Type II2 kerogen, indicating mixed terrestrial and marine OM sources. The black shales show a low organic maturity, and the hydrocarbon generation potential of the black shale and micritic limestone samples is substantially higher than that of the marl samples. Palaeoredox proxies indicate that Unit 1 deposited under dysoxic-anoxic conditions, and Unit 2 formed under anoxic-euxinic conditions, while Unit 3 deposited under oxic-suboxic conditions. Primary productivity proxies reflect high productivity in Units 1 and 2, and low productivity in Unit 3. Rb/K and total sulfur/TOC ratios suggest brackish environment in Units 1 and 2 and brackish or seawater condition in Unit 3. Hydrothermal activity during Unit 2 black shale deposition provided essential nutrients for phytoplankton in the photic zone, leading to high OM production. Upwelling/restriction proxies imply deposition under moderately restricted conditions for Unit 1, strongly restricted conditions for Unit 2, and upwelling/weakly restricted conditions for Unit 3. Palynological analysis indicates a warm, semi-humid to humid temperate climate during deposition of Units 1 and 2, contrasting with a hot, arid to semi-arid climate during Unit 3 marl deposition. OM accumulation of Unit 1 micritic limestone was primarily controlled by stratified dysoxic-anoxic conditions, high primary productivity, warm humid/semi-humid climate, and moderate watermass restriction. For Unit 2 black shale, the main controlling factors were stratified anoxic-euxinic environment, warm humid temperate climate, strongly restricted water condition, and intermittent strong hydro-thermal activity. During Unit 3 marl deposition, low primary productivity, an oxygen-rich water environment leading to OM degradation, combined with a hot arid/semi-arid climate, resulted in organic-lean deposition.

The attributes of Late Paleozoic magmatic events are of paramount significance in elucidating the tectonic evolution of the Ulanhot region, which is located in the middle of the Hegenshan–Heihe tectonic belt (HHTB). This study undertook a comprehensive investigation of the petrography, LA–ICP–MS zircon U–Pb dating, whole rock geochemistry, and zircon Hf isotopes of the Early Carboniferous volcanic rocks. The volcanic rocks are predominantly composed of andesite, schist (which protolith is rhyolitic tuff), and rhyolitic tuff. The results of zircon U–Pb dating reveal that the formation ages of volcanic rocks are Early Carboniferous (343–347.4 Ma). Geochemical characteristics indicate that the andesites possess a comparatively elevated concentration of Al2O3, alongside diminished levels of MgO and TiO2, belonging to the high-K calc-alkaline series. The zircon εHf(t) of the andesites range from −13 to 9.4, while the two-stage Hf model ages span from 697 to 1937 Ma. The felsic volcanic rocks have high contents of SiO2 and Na2O + K2O, low contents of MgO and TiO2, and belong to high-K to normal calc-alkaline series. The zircon εHf(t) values of the felsic volcanic rocks range from −12.8 to 10, while the two-stage Hf model ages span from 693 to 2158 Ma. The Early Carboniferous volcanic rocks exhibit a notable enrichment in large ion lithophile elements (LILEs, such as Rb, K, Ba) and light rare earth elements (LREEs), depletion in high-field-strength elements (HFSEs, including Nb, Ta, Ti, Hf), as well as heavy rare earth elements (HREEs). The distribution patterns of the rare earth elements (REEs) demonstrate a conspicuous right-leaning tendency, accompanied by weak negative Eu anomalies. These characteristics indicate that the andesites represent products of multistage mixing and interaction between crustal and mantle materials in a subduction zone setting. The felsic volcanic rocks originated from the partial melting of crustal materials. Early Carboniferous igneous rocks formed in a volcanic arc setting are characteristic of an active continental margin. The identification of Early Carboniferous arc volcanic rocks in the Central Great Xing’an Range suggests that this region was under the subduction background of the oceanic plate subduction before the collision and amalgamation of the Erguna–Xing’an Block and the Songnen Block in the Early Carboniferous.

The Upper Yangtze Basin developed a set of widespread organic-rich shales during the period from the Late Ordovician to the Early Silurian. The mechanisms controlling the accumulation of organic matter are the subject of much controversy. In the present study, we used various geochemical data, including total organic matter content, mineral composition, and trace and major elements from Well Daoye 1 drilled in the northern Guizhou Province, to evaluate the factors controlling the accumulation of organic matter. The indices such as CIA, Al%, Ti %, U/Th, V/Cr, Ni/Co, U-EF, V-EF, Mo-EF, Cuxs, Nixs, Excess Si, C-vaule, Cu/Al, Ni/Al, Co x Mn, Zr/Cr and Zr/ Al2O3 were calculated from these data to reconstruct the paleoclimate, terrigenous influx, seawater redox conditions, and paleoproductivity. Pyrite framboid size statistics were used as an additional proxy in this study to differentiate redox conditions between the anoxic state of the water column and the water/sediment interface. The results obtained from this study suggest that both the strongly reducing environment of the water column and the enhanced paleoproductivity played key roles in the widespread accumulation of organic matter. We found that the importance of these two factors in controlling the accumulation of organic matter varies under different circumstances through the Ordovician-Silurian transition in the Upper Yangtze Basin. Our study invites a case-by-case investigation when evaluating the controlling factors of organic matter accumulation in different settings.

The Late Ediacaran to Early Cambrian marked a pivotal phase in paleoenvironmental and tectonic shifts. The Sichuan Basin, on the Yangtze platform's western edge, developed the Mianyang-Changning intracratonic sag due to Xingkai taphrogenesis. The Maidiping Formation's black shales, the initial fine-grained clastic deposits from the Early Cambrian, span the Sichuan Basin's western margin. The influence of the intracratonic sag on organic matter accumulation and paleo-marine environment evolution remains unclear. Comprehensive petrological and geochemical analyses on the Qingping section revealed three distinct members within the Maidiping Formation: black shales and silicified dolomite with shales in a restricted basin (lower member), deep-water black shales (middle member), and phosphoritic turbidite sandstone with siliceous phosphorites (upper member). The lower member's organic accumulation arose from restricted ocean circulation, leading to stratified waters and reduced oxygen at depth. The middle member's organic build-up was influenced by enhanced intracratonic sag connectivity with the open ocean, sea-level rise, and increased productivity. The submarine hydrothermal activity might have induced anoxic conditions. The upper member saw a decline in organic matter due to phosphoritic debris and oxygenation. The Maidiping Formation augments the Lower Cambrian source rock, vital for oil and gas exploration in the Sichuan Basin's western margin.

The pore structure and mineral characteristics affect the accumulation and migration of hydrocarbons in shale, which determines the production capacity of shale oil. In this study, shale samples from the Chang 7 member of the Ordos Basin in China were selected to investigate the pore space characteristics, the effect of hydrocarbon accumulation on pore heterogeneity, and the hydrocarbon migration changes based on fractal theory, and a series of experiments were conducted involving X-ray diffraction (XRD), total organic carbon (TOC), Soxhlet extraction, and low-temperature nitrogen (N2) and carbon dioxide (CO2) adsorption. Then, the factors affecting extraction efficiency in shale pores were discussed. The interparticle pores contributed most to the accumulation of shale oil, and the organic matter (OM) pores contributed positively to the adsorption of hydrocarbons. The accumulation of hydrocarbons in the pore space did not increase the heterogeneity of the shale pore structure. The contents, states, and positions of hydrocarbons changed during the extraction process. Hydrocarbons were redistributed on the pore surface after Soxhlet extraction, and the heterogeneity of hydrocarbon adsorption and pore surface roughness were improved. Some heavy hydrocarbons and adsorbed components were pyrolyzed, resulting in the gradual escape of the adsorbed layer in the large pores. However, the free oil in the small pores diffused to the large pores and reaggregated on the surface, restoring a stable adsorption layer. The extraction rate was closely related to the pore throat structure and the wettability of mineral surfaces. The configuration between pores and throats had a crucial influence on the extraction rate. A high proportion of meso-pores, which effectively connect micro- and macro-pores, had a higher diffusion efficiency and a higher extraction rate. The OM pores with high energy adsorption were located in the micro-pores, and the shale oil existed in a dissolved state with high mobile capacity. The wettability of mineral surfaces affected the adsorption behavior during extraction, and strong oil wetting promoted hydrocarbon re-adsorption in clay minerals, so that the volume of micro-pores was smaller after extraction.

The micropore structure of tight sandstone affects the efficiency of CO2 displacement of crude oil. As the pressure changes, the oil displacement efficiency (E d) in segments with different pore radii changes, and the asphaltene precipitation in the pores causes alterations in the pore structure and wettability, which constrain E d. Ten samples of tight sandstone from the Yanchang Formation in the Ordos Basin were selected for this study. A variety of methods, including X-ray diffraction (XRD), casting thin sections (CTS), scanning electron microscopy (SEM), high-pressure mercury intrusion (HPMI), CT scanning, and nuclear magnetic resonance (NMR) combined with CO2 displacement, were used to study the efficiency of crude oil utilization and the amount of asphaltene deposited at different pore-throat radii, and then the impacts of pressure, pore structure, and wettability changes on E d were discussed. The findings indicate that samples have three types: macropore-fine throats (MF), medium pore-tiny throats (MT), and small pore-microthroats (SM). The MT exhibits a favorable configuration. The pore-throat radius of each sample can be divided into two segments, namely, large pore segments (PL) and small pore segments (PS), and the PL has a significant E d. The E d of the MF-type PS is constrained by pressure. The E d of PL is significantly affected by the pressure sensitivity for the MT, while the E d of PL for the SM structure is more affected by pressure. Changes in wettability and the precipitation of asphaltene are the results of the reaction between crude oil and CO2. In the MF, asphaltene precipitates from the PL, while in the MT and SM, asphaltene precipitates both from the PL and PS. The amount of asphaltene precipitation strongly affects the E d in PS. The oil wettability increases more obviously with better pore-throat configurations. This study offers a reference and foundational understanding for evaluating CO2 displacement in tight sandstone reservoirs.

In the Sichuan Basin there is abundant evidence in the lowerCambrian Qiongzhusi Formation and Ediacaran (upper Sinian)Dengying Formation for the existence of the oldest petroleumsystem in China. Here, we discuss the essential elements of thepetroleum system-source rock in the Qiongzhusi Formationand reservoir rock in the Dengying Formation. The source rockin the Qiongzhusi Formation was deposited in a shelf-likemarine environment. More than 100 m (328 ft) of black shalewas deposited in the north-south-striking Mianyang-Changningintracratonic sag. The reservoir rock is composed of dolomiticalgal mound-facies in the Dengying Formation. In the outcrop,the presence of dissolution features (vugs and caverns) and geo-chemical results indicates freshwater karstification during earlydiagenesis with subsequent hydrocarbon charge. Generatedhydrocarbons underwent two distinct phases of evolution fromoil generation and migration during the Permian to thermalcracking to gas beginning in the Late Triassic. Thus, the oldestpetroleum system in the Sichuan Basin is characterized bypaleo-oil and paleogasfields and present-day gasfields, all closelycontrolled by the tectonic evolution of the Sichuan Basin. Thedevelopment of the intracratonic sag in the basin center con-trolled deposition and preservation of the high-quality sourcerock and highly efficient hydrocarbon transformation and expul-sion. The development of the Ordovician-Jurassic Leshan-Longnvsi paleouplift in the basin center focused hydrocarbonmigration to charge the paleo-oil and paleogasfields. Lateral andvertical migration of hydrocarbons was facilitated along unconformities and faults in upper Sinian and lower Cambrianstrata across the Sichuan Basin-in particular, the Weiyuangasfield.

The Middle Permain Maokou Formation (P2m) is a new region of natural gas exploration in the Sichuan Basin, is characterized by bioclastic limestone with localized dolomitization, and karst fractured-vuggy reservoirs. Currently, on the gas source, hydrocarbon accumulation process and control factors in the Sichuan Basin during the Permian are lacking. To bridge this gap, herein, we identified the filling sequence minerals inside the pores/vugs, along with the oil charge of the Maokou Formation using drill cores, thin sections, oil inclusion analysis, and U-Pb dating of calcite cements. The results showed that the reservoir space of the Maokou Formation was predominated by the residual dissolved pores/vugs, fractures, and dissolved fractures. The pores/vugs underwent four stages of mineral filling by very fine-fine (-crystalline, CC1) calcite → fine-medium calcite (CC2: from 256.4 ± 1.7 to 244.1 ± 6.3 Ma) → fibrous calcite (FC; ∼183.9 ± 8.2 Ma) → coarse-macro calcite (CC3; ∼171.5 ± 5.3 Ma). Combined with the homogenization temperature and salty of fluid inclusion, we considered that three stages of oil charge were present in the Maokou Formation reservoirs. The first stage involved the formation of paleo-oil reservoirs during the Late Permian to Early Triassic, corresponding to the high-maturity aqueous inclusions in CC2, with a homogenization temperature of 106.7°C–137.8°C. At that time, the oil generation from the Lower Cambrian Qiongzhusi Formation rocks peaked, and the generated hydrocarbons migrated upward into the Maokou Formation through the strike-slip faults in the basin center. The second stage involved the formation of paleo-oil reservoirs during the Early Jurassic. The Permian source rocks reached the oil generation window with hydrocarbon expulsion, which was consistent with the oil inclusions in FC. The third stage involved the formation of paleo-gas reservoirs during the Middle Jurassic to Early Cretaceous, corresponding to the high-density methane inclusions and bitumen inclusions occurring in CC3, with the homogenization temperature peaking at 151.9°C–178°C. The natural gas in the Middle Permian of the Central Sichuan Basin is predominantly sourced from the Lower Cambrian Qiongzhusi Formation mudstone and partially from the source rocks of the Middle Permian, indicating a significant source-reservoir conduit of the strike-slip faults in the basin center. The findings provide considerable baseline data to advance further research in the Sichuan Basin.

位于扬子地台的西北缘、龙门山北段的四川江油马角坝地区娃娃岩发育一套露头清晰的"绿豆岩"剖面,由于目前关于川北地区"绿豆岩"的岩石学、岩相学以及全岩地球化学数据分析的研究较少,因此本次研究针对四川龙门山北段马角坝中三叠统雷口坡组"绿豆岩"2件样品进行岩石学、岩相学观察、6件全岩地球化学样品的分析测试,结果表明研究区内"绿豆岩"主要发育有四层,厚度为5.5 m,岩性为白云质含火山灰黏土岩,岩样手标本呈灰绿色,质地松软,主要由不规则棱角状、片状水云母和不规则粒状微小石英等中酸性火山碎屑物质及火山灰组成.根据全岩地球化学数据表明,研究区内"绿豆岩"的稀土元素分配模式图整体呈右倾分布,负Eu异常,8Eu=0.654～0.700,Ce负异常,δCe=0.94～0.96.微量元素特征表明研究区内"绿豆岩"形成环境为干燥炎热的微咸水-咸水、亚氧化-还原环境.通过区域对比,认为研究区"绿豆岩"为中三叠世初期形成,而"绿豆岩"中的火山物质来源与与古特提斯洋俯冲消减作用有关,是由俯冲带控制多期构造弧火山喷发造成,初步推测"绿豆岩"火山灰主体来自西部岛弧火山活动的多期次火山活动,与特提斯洋向东俯冲至扬子板块下部有重要相关性.

摘要: 震旦系灯影组核形石白云岩作为典型的前寒武纪微生物碳酸盐岩，是我国古老深层油气勘探的岩石类型之一.核形石成因模式的研究，对研究古水体、恢复古环境及其成储模式有重要指导意义.根据核形石结构特征和成因机制将灯影组核形石分为6类，结合岩石学、沉积学和地球化学等研究手段，开展了四川盆地北缘核形石分布特征和沉积过程的综合研究.结果显示：灯影组二段核形石发育于潮下带-潮间坪环境下，水动力和微生物条件的差异影响着微生物生长、自身钙化作用、微生物膜粘结和捕获作用、化学沉淀作用4种核形石纹层形成机理；进一步体现在水动力条件控制着核形石纹层发育厚度、形态特征和伴生岩石类型，而微生物活动习性控制影响着核形石主微量、稀土元素分异特征：贫藻纹层较富藻纹层有较高的Fe/Mn比、实体藻较非实体藻有较高Cu/Zn比，纹层稀土元素富集度一般低于核心.综上所述，灯二段核形石的形成存在4种机理，且它们被海平面变化下的微生物和水动力条件联合控制. 关键词: 核形石 / 微生物 / 水动力 / 灯影组 / 柳湾剖面 / 岩石学

川中北斜坡中二叠统茅口组岩性主要为生屑灰岩,发育岩溶缝洞型储层.通过岩心观察、镜下薄片鉴定,结合阴极发光特征,确定了茅口组溶蚀孔洞及裂缝中的矿物充填序列.在此基础上对不同期次成岩矿物中捕获的流体包裹体特征进行分析,结合川中北斜坡二叠系埋藏热演化史及成岩矿物U—Pb定年数据,明确茅口组油气成藏过程.结果表明:茅口组储层储集空间以残余溶蚀孔洞及裂缝、溶蚀缝为主;孔洞中见粉—细晶方解石→细—中晶方解石→粗—巨晶方解石3期充填.第二期方解石U—Pb年代学定年时间为晚二叠世(244.1±6.3 Ma),流体包裹体特征表现为高成熟度液烃包裹体与盐水包裹体混生,测得均一温度峰值主要集中在 120～130℃之间,第三期粗—巨晶方解石发育高密度甲烷包裹体及沥青包裹体,其均一温度峰值主要集中在165～170℃之间.川中地区中二叠统茅口组经历了3期成藏事件:第一期为晚二叠世—早三叠世下寒武统筇竹寺组生成的原油充注形成古油藏;第二期为中侏罗世—早白垩世油藏裂解形成气藏;第三期为晚白垩世喜马拉雅期构造抬升气藏调整形成现今混合气藏.中二叠统天然气主要为筇竹寺组烃源岩生成的原油裂解气,混有少量中二叠统自身烃源岩的贡献,川中地区发育的继承性断裂具有较好的沟通源储作用.