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Small and complex petroliferous sags have gradually become one of the key areas of succession in the mature exploration areas. Taking Weibei Sag of Bohai Bay Basin as a case, the geological and geochemical characteristics of the source rocks of Kong-2 Member was analyzed, the basin simulation method was used to determine the main hydrocarbon generation area, and investigate its control on the distribution and enrichment of hydrocarbon. The results show that the abundance, type, and maturity of organic matter have a large spatial variation range, and the upper and middle sub-members of Kong-2 Member in the study area are the most important source rocks. The periods of the late deposition of the Sha-4 Member and the structural uplift are the main hydrocarbon generation periods. The Migration of hydrocarbon-generating center from subsidence center to southeast direction, resulting a large amount of hydrocarbon-generating in the slope zone, leading to the main migration and accumulation direction of hydrocarbon in the Zaohu Faulted Nose Belt. Therefore, the hydrocarbon were enriched in the southeast and poor in the central and western regions, so the next favorable exploration areas include Zaohu Faulted Nose Belt, Eastern Wacheng Step Belt, and Southern Northern Sag Belt. [ABSTRACT FROM AUTHOR]

The Dongpu Depression, containing huge amounts of hydrocarbons, is a typical petroliferous province in the Bohai Bay Basin, east China. As one set of the main source rocks, the first member of Shahejie Formation (E2s1) shows huge exploration potential with approximately 0.83 × 108 t resources remaining to be discovered. However, the geochemical characteristics and thermal evolution history of E2s1 source rocks have still not been determined. In this study, the sedimentary features were firstly analysed based on the geological data. Then the organic matter abundance, kerogen type, and thermal maturity of E2s1 source rocks in the present day were evaluated according to the Rock‐Eval pyrolysis, micro‐components of kerogen, total organic carbon (TOC), and vitrinite reflectance analysis. Furthermore, the evolution of thermal history and hydrocarbon generation was determined using the PetroMod procedure. The results show that dark mudstones and salt rocks were well developed in E2s1, which are propitious for organic matter to grow and preserve. E2s1 source rocks contain abundant organic matter and moderate to good generative source rock potential. E2s1 source rocks mainly consist of Type II kerogen and have entered early to maturation stage for hydrocarbon generation. Due to the limited buried depth, E2s1 source rocks only attained lower thermal maturity and generated finite hydrocarbons. The initial rapid subsidence and the second rift after uplift erosion resulted in the higher geo‐temperature at the end of E3d and the present day. Corresponding to the geo‐temperature evolution, there are two stages of hydrocarbon generation for E2s1 source rocks: The first stage was in the late E3d period, and the late stage was from the late Neogene to the present day. Moreover, the hydrocarbon generation rate and quantity of the late stage are much higher than the first stage, indicating the major hydrocarbon generation stage. Due to the limited hydrocarbon generation capacity, oils generated from E2s1 source rocks are low maturity; thus, it cannot migrate for a long distance and only accumulated around the sag belts. [ABSTRACT FROM AUTHOR]

Significant differential hydrocarbon enrichment occurs in depressions in a petroliferous basin. There are multiple depressions in the Bohai Bay Basin, and each depression as a relatively independent unit of hydrocarbon generation, migration and accumulation, contains significantly different hydrocarbon generation conditions and enrichment degree. On the basis of previous documents and a large number of statistical data, this work comparatively analyzed the differential hydrocarbon enrichment and its major controlling factors in depressions of the Bohai Bay Basin. The results show that depressions in the Bohai Bay Basin have various hydrocarbon enrichment degrees, and can be categorized into four types, namely enormously oil-rich, oil-rich, oily and oil-poor depressions. In general, the enormously oil-rich and oil-rich depressions are distributed in the eastern part of the basin along the Tan-Lu and Lan-Liao faults, whereas depressions in the western part of the basin are poor in hydrocarbons. Moreover, the vertical distribution of hydrocarbons is also highly heterogeneous, with Pre-Paleogene strata rich in hydrocarbons in the northern and western depressions, Paleogene strata rich in hydrocarbons in the entire basin, and Neogene strata rich in hydrocarbons in the off-shore areas of the Bohai Bay Basin. From early depressions in onshore areas to the late depressions in offshore areas of the Bohai Bay Basin, the source rocks and source-reservoir-cap rock assemblages gradually become younger and shallower, and the hydrocarbon resource abundance gradually increases. Hydrocarbon supplying condition is the key factor constraining the hydrocarbon enrichment for different depressions, while the main source-reservoir-cap rock assemblage, sufficient hydrocarbons and the transportation capacity of faults control the vertical distribution of hydrocarbons. The main factors controlling hydrocarbon enrichment are different for different layers. The hydrocarbon supplying condition of source rocks is the key controlling factor, whereas the source-reservoir configuration, the main source-reservoir-cap rock assemblages, and the fault transportation are the main factors of hydrocarbon enrichment in the Paleogene, Paleogene and Neogene, respectively. [ABSTRACT FROM AUTHOR]

Based on a thermal pressure simulation experiment under formation conditions, we found that hydrocarbon generation in organic-rich shales can result in extreme overpressure, and that the key factor controlling such overpressure is gas rather than oil. Our experiment was conducted under formation conditions using organic-rich shale samples from the Upper Triassic Chang 7 member of the southern of Ordos Basin with the goal of exploring the overpressure caused by hydrocarbon generation. The results showed that hydrothermal pressures at 73–130 °C ranged from 5.6 to 49 MPa, while those at simulated temperatures of 300–425 °C and vitrinite reflectances of 0.71–1.99% ranged from 23.5 to 116.1 MPa when the system was completely closed. The weights of oil and gas generated in every stage of the experiment were similar, but the volume of gas was up to 1720 times greater than that of oil. The correlation between the volume of oil generated and hydrocarbon generation pressure was poor, but the increased volumes of oil-associated gas during the oil generation stage and gas in the gas generation stage were strongly and positively correlated with hydrocarbon generation pressure. Therefore, gas was the main factor controlling hydrocarbon generation pressures in this study. Higher pressures can exceed the fracture pressures of rocks, resulting in the formation of fractures and leading to the expulsion of oil and gas. The overpressure of a source rock can be transferred into a tight reservoir to become the main driving force for tight oil charging. When the overpressure exceeds 15 MPa, the oil in a reservoir can be charged into <5-nm pore throats, which is important for predicting tight oil potential. • Thermal pressure simulation experiments were conducted under formation conditions. • Hydrothermal and hydrocarbon-induced overpressures reached 49 and 116.1 MPa. • Gas generation in different stages controls hydrocarbon generation pressures. • Tight oil can be charged into <5-nm pore throats when overpressure >15 MPa. [ABSTRACT FROM AUTHOR]

Abstract To better understand gas migration and accumulation in tight sandstone reservoirs, we conducted an integrated petrographic and geochemical analysis of hydrocarbon and aqueous fluid inclusions. This analysis was combined with the burial and multistage hydrocarbon charging histories of the reservoir. The variability in the types of hydrocarbon inclusions in the tight sandstone reservoirs can be mapped to identify phase fractionation during burial and migration. The oil-bearing inclusions resulted from the heterogeneous capture of oil generated during the first hydrocarbon charging period, when the sandstones had not yet reached tight reservoir conditions. The gas-bearing inclusions in the tight sandstone reservoirs formed during the phase fractionation of dissolved and free gas due to unstable pressure conditions. The gas-bearing inclusions are characterized by a varying vapor volume fraction (φ vap). A higher proportion of gas-bearing inclusions with φ vap < 25% was observed near the source rock with TOC content >1.2%. In contrast, in structural highs, a higher proportion of gas-water inclusions with φ vap > 25% was observed, demonstrating that phase fractionation occurred during migration. The GOI data suggest that the dissolved gas migration mainly occurred in the reservoir near the source rock with TOC content >1.2%. The subsequent free gas separation in relation to upward migration and strata uplift caused free gas to migrate farther into the tight sandstone reservoir. Additionally, the gases displayed benzene/n-hexane ratio, methane and ethane δ13C values increasing initially, then decreasing along the migration pathway, recording the phase state evolution of the natural gas during the burial history of the reservoirs. Highlights • The paleopressure evolution has been reconstructed. • The geochemical fractionation effects in high and low surplus pressure zone are investigated. • Phase fractionation during the burial history is revealed by fluid inclusion petrography and microthermometry. [ABSTRACT FROM AUTHOR]

Abstract The Lower Cretaceous Yingcheng Formation in the Longfengshan sag (Songliao Basin, China) represents a typical tight sandstone reservoir that hosts large accumulations of hydrocarbons. The lacustrine sandstones mainly reflect gravity flow deposits making up various lithofacies displaying varying degrees of heterogeneity. This study reports on the links among gravity flow type, diagenetic overprinting and pore-throat characteristics that control reservoir quality. Core observations, especially grain size variations and related sedimentary structures are used to differentiate types of gravity flows. Microscopic observations, cathodoluminescence, scanning electron microscopy, pressure-controlled mercury injection tests and rate-controlled mercury injection tests are used to determine the mineralogy, sedimentary composition and pore-throat characteristics of the tight sandstones. In the study area, the gravity flows are divided into muddy debris flows, sandy debris flows, high-density turbidity flows, low-density turbidity flows and mud density flows. The petrophysical properties of these different gravity flow sediments reflect a range of permeability and porosity characteristics. Because of their mud-dominated textures and related weak compressive strength, mud density flows and muddy debris flows become ineffective as reservoirs during burial. In contrast, for approximately similar burial depths, turbidites and sandy debris flows show better reservoir quality. However, reservoir units with high porosities still possess considerable heterogeneity; this is especially true of some sandy debris flows that possess large amounts of secondary pores but which are not charged with hydrocarbons. In particular, in some poorly sorted sandy debris flows that are characterized by high contents of fine-grained matrix, some of the pore throats are blocked by matrix material. Moreover, the dissolution of feldspars and volcanic debris led to the formation of authigenic clays and quartz, which preferentially developed in pore throats with small radii. This process significantly reduced permeability. Overall, the permeabilities of the sandy debris flows are generally lower than those of the turbidites. Due to their relatively large-radius pore throats, turbidites can be categorized as potential effective hydrocarbon reservoirs in the study area. This research provides significant insights into the characteristics of pore throats within tight reservoirs consisting of gravity flow sediments in lacustrine basinal settings. Highlights • Gravity flow sediments have been categorized based on sediment support mechanism, flow state and sediment characteristics. • Pore-throat characteristics of different kind of gravity flow sediments are addressed. • Depositional texture and host rock buffered diagenesis are the main factors controlling reservoir quality. • Turbidites have the highest reservoir potential. [ABSTRACT FROM AUTHOR]