The prediction of thin-bedded, favorable sand bodies within the Triassic Baikouquan Formation fan delta on the western slope of the Mahu Sag is challenging due to their strong spatial heterogeneity. To address this, we propose an integrated workflow that synergizes seismic sedimentology with geologically constrained seismic inversion. This study leverages well logging, core data, and 3D seismic surveys. Initially, seismic attribute analysis and stratal slicing were employed to delineate sedimentary microfacies, revealing that the fan delta front subfacies comprises subaqueous distributary channels, interdistributary bays, and distal bars. Subsequently, the planform distribution of these microfacies served as a critical constraint for the Seismic Waveform Indicative Inversion (SWII), effectively enhancing the resolution for thin sand body identification. The results demonstrate the following: (1). Two NW-SE trending subaqueous distributary channel systems, converging near the BAI65 well, form the primary reservoirs. (2). The SWII, optimized by our workflow, successfully predicts high-quality sand bodies with a cumulative area of 159.2 km2, primarily located in the MAXI1, AIHU10, and AICAN1 well areas, as well as west of the MA18 well. This study highlights the value of integrating sedimentary facies boundaries as a geological constraint in seismic inversion, providing a more reliable method for predicting heterogeneous thin sand bodies and delineating future exploration targets in the Mahu Sag.

Research on hydrocarbon accumulation in the Cambrian of the Penglai gas-bearing area of paleo-uplift within the central Sichuan Basin remains relatively insufficient. In this study, the hydrocarbon charging history and accumulation evolution model of the Longwangmiao Formation of the Penglai gas-bearing area were established through the integration of petrography, fluid inclusion geochemistry (including microthermometry and Laser Raman spectroscopy), and basin simulation techniques. The findings indicate that the pores in the Longwangmiao reservoirs are extensively filled with solid bitumen. Additionally, multiple generations of diagenetic minerals, such as dolomite, quartz, and pyrite, indicate a complex fluid evolution history. The simulation of the hydrocarbon generation history, combined with homogenization temperatures and salinities of fluid inclusions within diagenetic minerals, reveals that the study area has undergone three crucial hydrocarbon accumulation evolution stages: (1) From the Early Triassic to the Early Jurassic (250–175 Ma), mature oil charged the reservoir, leading to paleo-oil accumulation. (2) From the Late Jurassic to the Late Cretaceous (159–98 Ma), crude oil underwent thermal cracking into gas. (3) From the Late Cretaceous to the present (82–0 Ma), continuous uplift has led to the adjustment of the gas reservoirs. These findings provide critical insights into the gas accumulation patterns and offer guidance for identifying high-potential exploration targets of the paleo-uplift within the central Sichuan Basin.

Bedding-parallel fractures represent a crucial flow-path network in shale oil reservoirs, yet their timing of opening and driving mechanisms remain subjects of long-standing debate. This study investigates the origin and opening mechanisms of bedding-parallel fractures within the Paleogene Funing shale oil reservoir of the Huazhuang area, Subei Basin, eastern China. A combination of petrography, fluid-inclusion analysis, PVTx paleo-pressure modeling, hydrocarbon generation history modeling, and reflectance measurements was employed. The results reveal the presence of abundant oil inclusions and bitumen within the bedding-parallel veins, indicating that the initiation of fracture was essentially synchronous with the oil emplacement. The studied Funing shale, with vitrinite reflectance values of 0.85% to 1.04%, is mature, identifying it as an effective oil-prone source rock. Thermal maturity of bitumen is comparable to that of the host shale, suggesting a local oil source. Homogenization temperatures (Th) of coeval aqueous inclusions record fracture opening temperatures of approximately 100–150 °C, consistent with oil-window conditions. By integrating Th data with burial history modeling, the timing of fracture formation and coeval oil injection is constrained to the peak period of local hydrocarbon generation, rather than the Oligocene Sanduo tectonic event. This indicates that fracture opening was primarily associated with hydrocarbon generation rather than tectonic compression. Petroleum-inclusion thermodynamic modeling demonstrates that the bedding-parallel fracture opening occurred under moderate to strong overpressure conditions, with calculated paleo-pressure coefficients of ~1.35–2.36. This finding provides direct paleo-pressure evidence supporting the mechanism of bedding-parallel fracture opening driven by fluid overpressure created during oil generation. These oil-bearing, overpressured fluids facilitated the initial opening and subsequent propagation of fractures along the bedding planes of shales. Concurrently, the precipitation of the calcite veins may have been triggered by pressure drop associated with the expulsion of some coexisting aqueous fluids. This study provides evidence addressing the debated mechanisms of bedding-parallel fracture opening in organic-rich shales, highlighting the critical role of oil generation-induced overpressure.

Highly fractured siliciclastic reservoirs that had experienced hydrocarbon accumulation failure proximal to igneous intrusive bodies were encountered in the Subei Basin, China. Within the Paleocene Funing Formation, pervasive reservoir pyrobitumen indicates a paleo-oil accumulation. Publicly available burial history shows that the reservoirs reached a maximum burial temperature (?140 degrees C) in the present day, which is much cooler than the commonly presumed oil-generation high-temperature limit (at least 160 degrees C). This is interpreted as resulting from a scenario whereby igneous activity forced in-reservoir thermal cracking following initial oil charge. Petrographic textures indicate two distinct phases of oil inclusion trapping: an early phase synchronous with silica diagenesis and a later phase occurring after silicification and carbonate cementation and concurrently with fracturing. The older oil inclusions record the initial oils that served as precursors to the pyrobitumen, while the younger generation was likely formed during oil cracking. Fissure calcites containing primary oil inclusions yield a laser ablationmulticollector-inductively coupled plasma-mass spectrometry U-Pb age of 44.3 +/- 1.5 Ma, coinciding with the published timing of volcanism. Homogenization temperatures from aqueous inclusions lie between 177.1 degrees C and 198.3 degrees C, broadly consistent with clumped isotope temperatures (195.5 degrees C +/- 6.5 degrees C) of fissure calcites and with bitumen Raman-derived temperatures (163.7 degrees C- 212.9 degrees C). These observations suggest that rising temperatures that accompanied the mid-Eocene igneous intrusion resulted in the initial oils being in situ thermally cracked into short-chain hydrocarbons and pyrobitumen. The resulting volumetric expansion, in conjunction with reduced permeability from pyrobitumen deposition, led to hard overpressures, consequent fracturing, and hydrocarbon leak-off.

Despite the ubiquity of hydrothermal fluid circulation in the crust, its timing is difficult to precisely determine using traditional thermometric dating due to strongly disturbed geothermal fields. We present a case study from the mid-Permian hydrocarbon-bearing dolostone reservoirs, situated proximally to strike-slip faults in the central Sichuan Basin (China), to highlight the utility of carbonate in-situ U-Pb geochronology in delineating the timing of hydrothermal fluid flow. Matrix and void-filling cement dolomite phases were identified in the porous Maokou Formation carbonates. Predominantly manifesting as saddle dolomites along fractures, these cements yielded statistically homogeneous U-Pb ages (242.5 +/- 3.1 Ma, 238.9 +/- 8.2 Ma, 244 +/- 15 Ma, and 239.2 +/- 6.5 Ma), slightly postdating the established stratigraphic timeline (ca. 273 to 259 Ma). The narrow temporal span suggests early emplacement following a short burial, compatible with the petrographic observation of burial stylolites crosscutting saddle dolomites. Integrating shallow emplacement depths inferred from a comparison between the dolomite U-Pb ages and a published burial history, with fluid-inclusion microthermometry, elucidates the hy-drothermal system that was once present in this field. The pervasive occurrence of hydrofracturing, along with dolomite geochemical indicators represented by bell-shaped (REE + Y) PAAS patterns and elevated Y/Ho ratios, provide additional evidence for the hydrothermal fluid injection and resulting dolomitization. The dolomites' positive Eu anomalies and the parent fluids' 18O enrichment indicate a source from deeper basinal pore waters that have interacted significantly with ambient rocks. The overlying Triassic evaporites may have provided Mg -rich brines, mixing into the circulating hot fluids responsible for hydrothermal dolomitization. Our dolomite U-Pb ages coincide with the seismically estimated timing of transtensional strike-slip fault activation. This temporal correspondence, combined with spatial associations and lateral slickensides along fracture planes, suggests that the hydrothermal fluid movement is highly relevant to the active strike-slip faults. This observation reveals a previously unrecognized early-middle Triassic, structurally controlled hydrothermal activity in the region. We propose that this episode of hydrothermal circulation was driven by extensional tectonism in response to the spreading of the Proto-Tethys Ocean. This finding is not in line with the earlier research that considered late Permian Emeishan volcanism to have been the main trigger for hydrothermal fluid influx. The long-standing view regarding hydrothermal dolomitization in this region may need to be re-evaluated.

In the overpressured Yanan Sag of Qiongdongnan Basin, South China Sea, four structures contain varying gas volumes despite overall similarities in geological conditions. One notable difference, however, is their varying pressure characteristics. We investigated the nature and cause of the overpressure as well as its relation to natural gas migration-accumulation in the four structures. Well logs, drill-stem tests (DSTs), and mud weights, reveal two zones of overpressure in the YC21-1 and YC26-1 structures that contain no economic gas reservoirs. There is one zone of overpressure in the YC13-1 structure, whereas the YC13-4 structure is hydrostatically pressured. Cross-plot analysis of density and sonic logs indicates a mild to moderate overpressure section in the Neogene strata, interpreted as resulting from disequilibrium compaction and clay diagenesis.

In the Precambrian dolomites in the central Sichuan Basin, a substantial paleo-oil system previously existed, which has since evolved into a dry gas system that is currently in place. The genesis of this paleo-oil system remained poorly understood, leaving uncertainties regarding the timing of oil charging and associated source rocks. Integration of Re-Os geochronometry with basin modeling allows temporal-spatial constraints on the ancient petroleum system to be established. Two texturally distinct generations of reservoir bitumen were identified. Late-generation bitumen yielded a geologically meaningful Re-Os age of 189 & PLUSMN; 20 Ma (MSWD = 10.4, 2 & sigma;), distinct from the previously documented Re-Os ages such as the 414 & PLUSMN; 44 Ma reported by Shi et al. (2020). This new age, along with the -414 Ma, aligns within uncertainties with the two relative timings derived from our independent basin model (ca. 450-390 Ma and 260-180 Ma), revealing two temporally distinct oil generation-migration events. The date of -189 Ma also lends support to the previous oil charge timing inferred from fluid inclusions. We evaluated the imprecisions of these two Re-Os ages and considered them to result from a narrow spread in 187Re/188Os, and variations in initial Os isotopic compositions (Osi) due to the giant size of the petroleum system and a long duration of oil generation from source kitchen over a large geographical area in this play. Effects of asphaltene precipitation, due to upliftinduced decompression of the migrating oils, may also have contributed to the scatter. Separating the samples based on Osi produced a higher precision age (184.1 & PLUSMN; 5.7 Ma, Model 1) with an MSWD of 0.97.The first oil charge is relatively weak as shown by the basin model and observed bitumen volumes, and it had not been well preserved due to significant reservoir exhumation by Caledonian tectonism. Consequently, the younger oil charge is considered to be the principal precursor to the current dry gas accumulations. Os isotope histories for four potential source units were constructed using publicly available Re-Os data. Comparisons between bitumen and rock Os compositions tend to support the lower Cambrian Qiongzhusi Formation as the predominant source unit for the two major paleo-oil charges. However, contributions from the Duoshantuo, Dengying, and Maidiping source rocks can not be precluded. Overall, these new observations allow temporalspatial constraints to be placed on the complex evolution, from paleo-oil generation to destruction and dry gas generation.

长期以来沉积地层因缺乏稳定放射性同位素计时，其地层的绝对年龄标定成为地层学和石油地质学研究中的颈瓶.运用定量旋回地层学的理论和方法，结合顺层纤维状方解石超低浓度U-Pb定年约束，重新厘定了苏北盆地高邮凹陷古近系主要界面绝对年龄，得到了与前人不同的“三垛运动”时限和“二元”裂陷构造变革面与太平洋板块俯冲转向的时间（～50Ma）耦合关系.分析认为，高邮凹陷三垛组顶界年龄为34.0Ma，底界年龄为43.3Ma；戴南组底界年龄为50.5 Ma；阜二段底界年龄为56.5 Ma；阜一段的底界年龄为66.0 Ma.位于洼陷区的永38井三垛组残留地层持续时间为8.28 Ma，抬升剥蚀起始年龄为34.06 Ma，结束年龄为23.03 Ma，剥蚀时限为11.03 Ma.而隆起和斜坡带三垛组开始剥蚀的时间要早于34.06 Ma，剥蚀的时限会更长一些.阜四段方解石脉超低浓度U-Pb定年结果为53.1±3.7 Ma.这些结果表明：（1）苏北盆地高邮凹陷～50 Ma和～23.03 Ma界面是太平洋板块俯冲转向和印度板块与欧亚板块碰撞的构造响应，高邮凹陷沉积中心在始新世晚期（34.06 Ma）就开始抬升，历经11.03 Ma的剥蚀，主要原因可能与印度-欧亚板块碰撞在华南陆块总体表现以挤压为主而缺乏NE向深部幔隆的远距离效应有关；（2）烃源岩层系中发育的顺层纤维状方解石脉超低浓度U-Pb定年结果可以作为其地层的沉积年龄，从而为沉积盆地定量旋回地层学分析提供了锚点约束.

Ultra‐deep marine carbonate reservoirs is an important field for oil and gas exploration, and it is also a hot research topic in recent years. However, their hydrocarbon episodic charging model is still under debate up to now. A great breakthrough has been made in the newly discovered ultra‐deep fault‐karst oil reservoir in the Shunbei area of Tarim Basin. Based on quantitative gas chromatogram‐mass spectrometry, stable carbon isotopes of reservoir oils, microthermometry and confocal laser scanning analyses of fluid inclusions, the reservoir oil origin and hydrocarbon charging history in Shunbei No. 1, No. 5 and No. 7 strike‐slip fault zones are expounded. The results showed that the Ordovician reservoir oil derives from the source rocks within the Cambrian Yuertusi Formation deposited in a highly anoxic bottom water environment. There were four stages of hydrocarbon charging in the study area, in the late Caledonian, late Hercynian–Indosinian, middle Yanshanian and late Himalayan. During this period, the force‐field strength of the charged oil gradually decreased, and the early‐stage charged crude oil with low maturity and high force‐field strength preferentially accumulated in the Yijianfang Formation, while the late‐stage charged crude oil with high maturity and low force‐field strength preferentially accumulated in the Yingshan Formation. This study reveals the history and differences of petroleum accumulation in the Shunbei fault zones, which is significance for understanding the hydrocarbon distribution in ultra‐deep marine carbonate reservoirs.

The Lower Cambrian Qiongzhusi black shale of the Middle-Upper Yangtze region is considered the best candidate for shale gas exploration after the breakthrough of shale gas development in the Upper Ordovician Wufeng-Lower Silurian Longmaxi Formations because of its high total organic carbon（TOC） content and high hydrocarbon-generating potential. The high-quality argillaceous source rock is mainly distributed in the Mianyang-Changning trough in Sichuan, the Xiang’exi trough in western Hunan and western Hubei, and the deep-water shelf and slope basins in eastern Sichuan and northern Guizhou, with source-rock intervals mainly developed at the bottom of the troughs and in the middle and upper parts of the deep-water shelf and slope basins, as indicated by TOC profile studies. In this paper, fluid inclusion analysis and super-low-concentration U-Pb dating were performed on collected shale specimens, in combination with comprehensive literature research, to investigate the hydrocarbon generation history in the Lower Cambrian Qiongzhusi stage. In addition, the shale gas composition and isotopic characteristics are discussed. There are two possible modes of shale gas generation and accumulation:（1） Source rock developed in western Hunan, western Hubei and eastern Sichuan experienced a single-stage oil/gas generation process, where oil generation started in the late Caledonian（430 Ma）, at temperatures of 95.7-105.2 ℃, followed by crude oil cracking in the late Hercynian（270 Ma）, at ～144.7℃, wet gas secondary cracking in the early Yanshanian（270-130 Ma）, at 215.3 ℃, and shale gas leakage from the late Yanshanian to present（130-0 Ma）.（2） Source rock from southern Shaanxi and southern, central and southwestern Sichuan experienced a two-stage oil/gas generation process, where the 1st and 2nd stage oil generation occurred at 421.5 Ma and 262.4-256.4 Ma, at temperatures of 115.8-128.9 ℃ and 137.1-150.0 ℃, respectively; crude oil and/or kerogen cracking in the Mianyang-Changning trough started in the Late Hercynian（259.4±3.0 Ma）, at ～140 ℃, on average, followed by wet gas secondary cracking in the middle-late Yanshanian（175-133 Ma）, at ～220 ℃, with ongoing shale gas accumulation and reservoir adjustment due to favorable preservation conditions. The differential hydrocarbon generation is controlled by regional tectonic and depositional evolution. Shale gas in the study area is mainly oil-type gas of organic origin, generated from kerogen and crude oil cracking. Due to the development of faults in northern Guizhou and southeastern Chongqing, the early-stage shale gas was washed by surface and atmospheric water, causing changes in its elemental and isotopic compositions and resulting in nitrogen enrichment and decrease of δ 13 C 1 value.

The high-quality reservoirs in the Shahejie Formation of the Laizhou Bay Sag, Bohai Bay Basin, Eastern China formed in the Paleogene saline lacustrine environment and show complex diagenetic evolutionary processes caused by alternating acid and alkaline fluids. Through observations under an optical microscope and a scanning electron microscope, casting thin sections, and plane porosity measurements, this study investigated the diagenesis differences in the third member of the Shahejie Formation (Es3 Member) in the root and central portions of a fan delta in the E12 structure in the eastern Laizhou Bay Sag, respectively. The Es3 reservoirs in the well A-1 which have no any hydrocarbon shows, are relatively tight, and have high argillaceous content, poor particle sorting, strong mechanical compaction, and intense carbonate cementation due to long-term activities of alkaline fluids. Moreover, they were not altered by organic acid due to the far lateral distance from source rocks. By contrast, the Es3 reservoirs in the well A-2 with hydrocarbon accumulations, contain an anomalously high porosity zone due to the superimposition of five episodes of alternate acid-alkaline fluids. The diagenetic fluids controlling the formation of the high-quality Es3 reservoirs are sourced from connate saline pore waters, gypsum dehydration, salt diapir, and organic acid. Moreover, chlorite coats in the reservoirs in the well A-2 inhibit secondary overgrowth of quartz and, thus, protect primary pores. The chlorite coats and alkaline-acid dissolution alterations are critical to the formation of the high-quality reservoirs in well A-2.

Economically viable accumulations of hydrocarbons hosted in the Precambrian rocks are globally rare, as a protracted history available for them to escape or be destroyed due to various processes including thermal and bacterial degradations and tectonic disruption. A recent gas discovery in the late Ediacaran dolomites of the Sichuan Basin (SW China) provides an opportunity to understand the formation and preservation of ancient petroleum systems. Paleo fluid pressure-temperature-composition (P-T-X) conditions from deep burial to exhumation are evaluated from microthermometry and Raman data obtained from fluid inclusions. We identified three texturally distinct generations of gas-bearing fluid inclusion assemblages (FIAs), which delineate an operating petroleum system where gas remigrated during exhumation that followed oil cracking during deep burial. The older FIAs (types 1 and 2) show a petrographic association with bitumen and are interpreted to be the result of thermal cracking. Type 1 FIAs formed through in-situ cracking of pre-existing oil inclusions and have recorded the paleo oil charge during the middle Triassic to early Jurassic. Type 2 FIAs were trapped during the prolonged intra-reservoir oil cracking that occurred between the late Jurassic and late Cretaceous. Our pore pressure calculations indicate overpressured conditions, a result of active gas generation during thermal cracking. Lithostatic overpressures accumulated and were sustained under weak tectonic compression prior to peak burial. Type 3 FIAs have been interpreted as reflective of the gas-bearing system reactivation during exhumation. These FIAs indicate the relative reduction in the proportion of aqueous to gas inclusions, which may be due to a decrease in water saturation following gas emplacement. Uplift processes during early exhumation likely facilitated breaching of the system and remobilization of fluids, resulting in gas escape and overpressure release. The drastic increase in formation water salinity, which was documented in the fluid inclusion dataset, points to the arrival of hypersaline brine during the Eocene to Oligocene. This brine could have originated either from the lower Cambrian evaporated CaCl2 seawater or from the dissolution of the lower-middle Triassic halite. From the late Miocene to present, progressively exhumed reservoirs may have received an influx of relatively fresh water from shallow aquifers, as shown by the correspondence between P-T-X records and present-day reservoir conditions.

In recent years, newly discovered ultra-deep fault-karst reservoirs in the Shunbei area of the Tarim Basin have greatly increased the prospectivity of the basin and become a hotspot for further hydrocarbon exploration. In this study, the diagenetic sequences of the Lower-Middle Ordovician reservoir were established through observation of thin sections under transmitted light, reflected light, and cathode luminescence. The hydrocarbon charge history in the Shunbei area was reconstructed and associated with a series of diagenetic events using fluid inclusion microthermometric measurements combined with one-dimensional basin modeling. The results show that the Shunbei area has experienced three hydrocarbon charging episodes in total, in the late Caledonian, late Hercynian, and late Himalayan. Finally, the relationship between measured QF-535 factors and the API gravity of crude oil was used to quantify the level of contribution of each of the petroleum charging episodes to the No. 1, No. 5, and No. 7 fault zone reservoirs. The contribution of early hydrocarbon charging episodes gradually increases from west to east in the Shunbei area. This increase was driven by different tectonic events throughout geological history and the subsequent evolution of paleo-structural patterns. This study has a significant impact on marine carbonate reservoir evaluation in strike-slip fault zones in China.

The microscopic differences in characteristics and formation mechanism of shale oil reservoirs in the upper and lower sweet spot sections of the Lucaogou Formation in the Jimsar Depression, which has been identified as a national shale oil demonstration area in China, are still unclear. In this study, the characteristics and the main controlling factors of reservoir differences in different sweet spots of Lucaogou Formation were specified based on core observation, thin-section observation, X-ray diffraction, Rock-Eval, microscopic fluorescence of hydrocarbon inclusions, and temperature measurement of saline inclusions. Results show that the Lucaogou Formation mainly develops dissolution and primary intergranular pores. The dissolution transformation leads to obvious differences between the upper and lower sweet spots. Specifically, the upper sweet spot section mainly develops primary intergranular pores and partially develops dissolution pores; the lower sweet spot section mainly develops dissolution pores, including intergranular, intragrain, and intergranular pores. Geochemical data such as inclusions indicate that hydrocarbon generation began in the Triassic, and a large number of hydrocarbons were charged in the Middle-Late Jurassic-Early Cretaceous. As the key fluid that triggers reservoir dissolution modification, it is mainly derived from organic acids generated by thermal evolution of source rocks within shale formations. The scale and quality of source rocks in the lower sweet spot are better than those in the upper sweet spot. The former has stronger hydrocarbon generation potential, which lays a foundation for the scale difference of organic acid output in the upper and lower sweet spots. At the same time, the source rocks in the lower sweet spot are more mature due to magmatic-hydrothermal upwelling. This condition accelerates the release of organic acids from source rocks, which results in the scale difference of dissolution effects in the upper and lower sweet spots.

The mechanisms leading to the formation of bedding-parallel calcite beef veins have been widely debated, with discussions centered on timing or burial depth of vein generation, source of the vein material, driving forces for vein initiation and widening, and growth direction and mechanism. To address these issues, a comprehensive study of drill core samples containing beef veins in the mature Eocene lacustrine Hetaoyuan Formation in the Biyang Sag, Nanxiang Basin, China was undertaken through a combination of microstructural observation, isotopic geochronological, geochemical, and fluid inclusion analyses, as well as basin modeling. X-ray diffraction and total organic carbon content analyses indicate that most of the beef veins accumulated in calcite-rich laminated shales with high organic matter contents. These beef veins yielded an absolute laser ablation−multi-collector−inductively coupled plasma−mass spectrometry U-Pb age of ca. 41.02 ± 0.44 Ma, which corresponds to a burial depth of 500−800 m. Such a shallow burial depth suggests that the full compaction and consolidation of sediments would not yet have been achieved, which is compatible with the following observations: (1) plastic deformation of shale laminae adjacent to the veins, and (2) a beef vein formation temperature of ∼59 °C derived from fluid-inclusion microthermometry. The radio-isotopic age of the beef veins is ∼1−3 m.y. younger than the stratigraphic age of the host rock (ca. 43.1 Ma) but earlier than the model-derived timing of oil generation (ca. 35.8 Ma) and tectonic extrusion (ca. 23.0−13.0 Ma). The beef vein formation predated bacterial sulfate reduction, as evidenced by crosscutting relationships with carbonate concretions, pyrite framboids, and apatite pellets. A two-stage formation model for these beef veins is proposed. When burial depth of laminated shales rich in organic matter and calcite reaches the methanogenic zone, overpressure triggered by biogenetic gas generation results in horizontal hydrofracturing, initiating cracks that act as gas expulsion pathways. Once all the generated gas has migrated, the opened fractures close again due to overburden load. The materials fed by pressure solution of host-rock calcite fractions then mobilized into the unhealed horizontal fractures by diffusion. Subsequently, by a force of crystallization, antitaxial, displacive growth of calcite fibers commenced, contemporaneous with fracture dilation, eventually leading to the formation of bedding-parallel beef veins.

Improved understanding of subsurface paleo-fluid circulation history can assist in reconstructing associated pore evolution of carbonate reservoirs. Multi-stage dolomite cements generated by basinal fluids over time were investigated using a combination of petrography, geochemistry, fluid-inclusion studies, LA-ICP-MS U-Pb geochronology, and seismic interpretation. This study aims to gain clues about diagenetic, hydrothermal and paleo-oil filling events within the Ediacaran Dengying Formation, Sichuan Basin, China. Four main phases of dolomite cementation were petrographically, geochemically and geochronologically distinguished that can be ascribed to major tectonic events throughout the basin evolution. The earliest dolomite generation occurs as fibrous dolomite crust (FDC) growing along the karst vug wall, interpreted as marine diagenetic cement formed in a submarine environment during the Late Ediacaran, most likely from the influx of seawaters following the uplift and subaerial exposure related to the Tongwang movement. In situ U-Pb ages obtained from the other three generations of cement dolomites are interpreted to coincide with the timing of repeated strike-slip fault movements as indicated by the seismic data, suggesting a direct link between cement emplacement and regional tectonic-thermal events. Sub-vertical extension dolomite veins (EDV), representing the second generation, are considered as being syntectonic, generated from slightly modified connate seawaters at a shallow to moderate burial depth in a transtensional stress regime during the Cambrian taphrogenesis. Two generations of saddle dolomite cements, SD1 and SD2, have recorded two major episodes of hot fluids circulating in the Dengying Formation. The SD1, filling in hydraulic fractures and vugs, formed during the third phase of cementation, as a result of a hydrothermal event associated with Caledonian exhumation. Deep-seated hot brines squeezed into the Dengying reservoirs along the sub-vertical strike-slip faults combined with some meteoric waters that percolated downward, are deemed responsible for precipitating SD1. The SD2 is the youngest cement present, which is interpreted to have formed during the ingress of deeper, hot, hypersaline brines arising from the late Permian hydrothermal activity likely triggered by the eruption of Emeishan flood basalts. Cross-cutting relationships between bitumen phases and different dolomite generations indirectly define the dates of two paleo-oil charging events. The first episode of paleo-oil charging occurred during the Late Ediacaran to Early Cambrian, likely sourced from underlying Ediacaran Doushantuo shales. Late oil emplacement occurred after the Late Permian, in agreement with the reported bitumen Re-Os age and the age inferred through fluid-inclusion analysis. Primary source rocks generating this phase of oil were considered as the Cambrian Qiongzhusi shales, because basin modeling-derived date of oil window matches with the second oil filling time.

To date, few isotope age constraints on primary oil migration have been reported. Here we present U-Pb dating and characterization of two fracture-filling, oil inclusion-bearing calcite veins hosted in the Paleocene siliciclastic mudstone source rocks in Subei Basin, China. Deposition age of the mudstone formation was estimated to be ca. 60.2-58.0 Ma. The first vein consists of two major phases: a microcrystalline-granular (MG) calcite phase, and a blocky calcite phase, each showing distinctive petrographic features, rare earth element patterns, and carbon and oxygen isotope compositions. The early MG phase resulted from local mobilization of host carbonates, likely associated with disequilibrium compaction over-pressuring or tectonic extension, whereas the late-filling blocky calcite phase was derived from overpressured oil-bearing fluids with enhanced fluid-rock interactions. Vein texture and fluorescence characteristics reveal at least two oil expulsion events, the former represented by multiple bitumen veinlets postdating the MG calcite generation, and the latter marked by blue-fluorescing primary oil inclusions synchronous with the blocky calcite cementation. The MG calcite yields a laser ablation-inductively coupled plasma-mass spectrometry U-Pb age of 55.6 +/- 1.4 Ma, constraining the earliest timing of the early oil migration event. The blocky calcite gives a younger U-Pb age of 47.8 +/- 2.3 Ma, analytically indistinguishable from the U-Pb age of 46.5 +/- 1.7 Ma yielded by the second calcite vein. These two ages define the time of the late oil migration event, agreeing well with the age estimate of 49.7-45.2 Ma inferred from fluid-inclusion homogenization temperature and published burial models. Thermodynamic modeling shows that the oil inclusions were trapped at similar to 27.0-40.9 MPa, exceeding corresponding hydrostatic pressures (23.1-26.7 MPa), confirming mild-moderate overpressure created by oil generation-expulsion. This integrated study combining carbonate U-Pb dating and fluid-inclusion characterization provides a new approach for reconstructing pressure temperature-composition-time points in petroleum systems.

This study examines sealed fractures in core samples from the Paleocene organic-rich lacustrine shales of the Gaoyou Depression, Subei Basin, China, using a multi-pronged approach to elucidate the interplay between fracture propagation and fluid circulation in shaly successions. Based on petrography, geochemistry, and geochronology of fracture-filling minerals, four generations of vein emplacement (denoted Types A-D) were identified. These were attributed to successive episodes of burial diagenesis, tectonism, and uplift occurring at different phases of basin evolution. These vein generations were then inserted into the temporal-spatial frame-work derived from basin modeling, leading to a reconstruction of the fracture diagenesis history in the Funing shales. Two of the vein generations contain evidence for two phases of oil migration marked by two types of oil inclusions with different fluorescence. It has been shown that the studied lacustrine shales were deposited at ca. 60.2-58.0 Ma. The earliest vein generation, represented by antitaxial beef calcite veins sub-perpendicular to shale bedding, propagated in incompletely consolidated shales within a regional thrust regime related to the Wubao Movement. The vein nucleation during a short-lived burial following initial deposition was also evidenced by the presence of monoliquid inclusions in the veins and calcite LA-ICP-MS U-Pb age (57.7 +/- 3.7 Ma). Tectonic compressive stress together with overpressures arising from horizontal and vertical disequilibrium compaction were interpreted as being responsible for this fracturing episode. The second vein generation is bedding-parallel, oil inclusion-rich stretching calcite veins with a crack-seal texture, formed concurrently with kerogen maturation and early oil generation at moderate burial depths. The vein crack-seal fills containing yellow fluorescing oil inclusions provide evidence for episodic oil expulsion in response to cyclic rises and drops in pore pressure during the oil window. Bedding-parallel beef calcite veins characterized by antitaxial growth represent the next vein generation, emplaced during the maximum burial period (ca. 41.9 +/- 2.7 Ma). The vein fibers have tracked the horizontal displacement of the wall rocks, likely related to lateral shortening before or at the initiation of Late Eocene basin inversion. The first three vein generations were generated in a relative closed fluid system, with vein fill sourced locally. Host-rock carbonate components and/or earlier diagenetic carbonates were dissolved and then mobilized into these veins. By contrast, the last vein generation with blocky calcite and barite cementation is associated with input of externally derived hydrothermal fluids. The evidence comes from abnormally high fluid-inclusion homogenization temperature (Th) and salinity data, as well as the fact that Ba and sulfate were sourced from the underlying evaporite layers rather than local shales. We thus infer that cross-stratal faulting during the uplift related to the Sanduo Movement resulted in the opening of initial hydraulically closed fluid system. This episode of tectonically-driven hydrothermal circulation from deeper locations in the basin into the Funing shales led to the mixing of oil-bearing pore fluids with exotic basinal hot brines. This also accounts for the presence of abundant blue-green fluorescing oil inclusions and significantly elevated fluid salinity. Overall, this study emphasizes that during basin evolution, differences in tectonic settings and the diagenetic boundary conditions under which veins formed results in different fracturing mechanisms and associated fluid-flow regimes in shale sequences, with consequent effects on vein attributes and mineralization.

Deposits of biodegraded heavy oils are commonly encountered within the Eocene reservoir units in the North Slope of the Biyang Sag, Nanxiang Basin, eastern China. Oil physical property data and biomarkers show that these biodegraded oils occur only above burial depth equivalent to about 62 degrees C. This is much cooler than the cutoff temperature of biodegradation (about 80 degrees C), which has been interpreted within a complex petroleum evolution history that includes an early oil filling, significant uplift, a second phase of filling, and late-stage biodegradation. We use a new combination of fluid-inclusion analysis and calcite LA-ICP-MS U-Pb dating to obtain a temporal constraint on oil migration in the siliciclastic reservoirs. Two generations of oil inclusions, each showing a distinct fluorescence color (yellow and blue-green), were trapped before and after quartz cementation, respectively, which indicates multi-stage oil charge events. The early oil charge, marked by hydrostatic conditions and low-salinity pore waters, occurred during the late Eocene to early Oligocene burial period, corresponding to peak oil generation by basin modeling. The reservoirs were then refilled at a moderate-overpressure regime by higher maturity oils accompanied by high-salinity waters during the early Miocene exhumation. Reservoir sandstonehosted, yellowish calcite veins, characteristic of 13C depletion and oil odor, contain primary blue-green fluorescent oil inclusions and bitumens, consistently pointing to precipitation from petroleum-derived fluids. LA-ICPMS U-Pb dating of these vein calcites yields a U-Pb age of 19.6 +/- 1.2 Ma, representing the latest timing of the second oil charge event in the North Slope. The isotope age of the fissure calcites near fault zones coincides well with the indirect age estimate based on fluid-inclusion homogenization temperature and the regional uplift stage. This scenario suggests that the Miocene tectonic compression not only triggered the recharge of oils but also facilitated the initiation or re-activation of faults that acted as conduits for oil migration. Reconstructed burial models show a continuous burial followed by significant uplift and erosion in this region. Since some reservoirs with maximum paleotemperature less than 80 degrees C were not sterilized during burial, the contained oils suffered from extensive biodegradation, presumably during the middle Miocene to present day. Thus, the shallower shutoff depth of biodegradation in this region was most likely ascribed to the paleopasteurization during burial, as opposed to later fresh oil replenishment or influx of shallow aquifers.

Table S1: LA-ICP-MS U-Pb contents (ppm), and 238U/206Pb-207Pb/206Pb ratios of the microcrystalline-granular calcite (MGC) and blocky calcite (BC) in vein samples FSX1-1 and FSX1-2; Table S2: LA-ICP-MS rare earth element (REE) data (ppm) for calcite cements in vein samples FSX1-1 and FSX1-2.