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Globally, most organic-rich shales are deposited with volcanic ash layers. Volcanic ash, a source for many sedimentary basins, can affect the sedimentary water environment, alter the primary productivity, and preserve the organic matter (OM) through physical, chemical, and biological reactions. With an increasing number of breakthroughs in shale oil exploration in the Bohai Bay Basin in recent years, less attention has been paid to the crucial role of volcanic impact especially its influence on the OM enrichment and hydrocarbon formation. Here, we studied the petrology, mineralogy, and geochemical characteristics of the organic-rich shale in the upper submember of the fourth member (Es4 1) and the lower submember of the third member (Es3 3) of the Shahejie Formation, aiming to better understand the volcanic impact on organic-rich shale formation. Our results show that total organic carbon is higher in the upper shale intervals rich in volcanic ash with enriched light rare earth elements and moderate Eu anomalies. This indicates that volcanism promoted OM formation before or after the eruption. The positive correlation between Eu/Eu* and Post-Archean Australian Shale indicates hydrothermal activity before the volcanic eruption. The plane graph of the hydrocarbon-generating intensity (S1þS2) suggests that the heat released by volcanism promoted hydrocarbon generation. Meanwhile, the nutrients carried by volcanic ash promoted biological blooms during Es4 1 and Es3 3 deposition, yielding a high primary productivity. Biological blooms consume large amounts of oxygen and form anoxic environments conducive to the burial and preservation of OM. Therefore, this study helps to further understand the organic-inorganic interactions caused by typical geological events and provides a guide for the next step of shale oil exploration and development in other lacustrine basins in China. [ABSTRACT FROM AUTHOR]

The eastern Kuqa Depression in the northern Tarim Basin, NW China, is rich in oil and gas. However, recent exploration has been hindered by a lack of knowledge on the evolution of the petroleum system. To address this, we conducted hydrocarbon generation and accumulation modeling using both the 2Dmove and PetroMod2017 software for a complex tectonic extrusion section in the Kuqa Depression. The results show that the source rocks in the northern slope zone became mature quite early at around 170 Ma, but the thermal maturity evolution stagnated subsequently because of tectonic extrusion and uplift. The source rocks in the central anticline zone, the southern slope zone, and the deep sag zone were of overall low maturity during the Jurassic to Paleogene but rapidly became mature to highly mature with the deposition of the Neogene Jidike and Kangcun formations. The main hydrocarbon generation periods are in the late Neogene and Quaternary, and the main hydrocarbon generation stratum is the lower Jurassic Yangxia formation. The amount of cumulative hydrocarbon generation gradually increases for carbonaceous mudstone, mudstone, and coal source rocks. Sourced from source rocks mainly in the northern slope zone, oil and gas migrated to anticlinal traps along sandstone transport layers and faults. Recent discoveries, such as the Tudong-2 gas field in the central anticline zone, underscore the richness of this region in petroleum resources. Some gas fields were also predicted in lithologic traps in the southern slope zone and the deep sag zone, as well as in fault-related traps in the northern part of the northern slope zone. [ABSTRACT FROM AUTHOR]

Because of the influence of hydrocarbons, especially adsorbed hydrocarbons, on the detection of cracked hydrocarbon (S2) and total organic carbon (TOC), the hydrogen index (HI)‐based hydrocarbon generation model deviates from actual practice. In this study, the shale in the first member of the Qingshankou Formation in the central depression of the Songliao Basin, where in northeastern China, was taken as the research object and a correction method for S2 and TOC was established. By correcting the experimental results of different maturity samples, the actual hydrocarbon generation model has been revealed, the differences before and after correction compared, and the evolutionary characteristics of the adsorbed hydrocarbon content were clarified. The results show that the organic matter enters the hydrocarbon generation threshold at Ro–0.5% and reaches the hydrocarbon generation peak at Ro–1.0% and that the hydrocarbon generation process ends at Ro–1.3%. The hydrocarbon generation model established based on the measured values has a 'lag effect' compared to actual values, and this extends the hydrocarbon generation window of organic matter and delays the hydrocarbon generation peak. With the increase of maturity, adsorbed hydrocarbon content shows the characteristics of 'first increasing, then stabilizing, and then decreasing', and reaches the most abundant stage at Ro of 0.9%–1.3%. [ABSTRACT FROM AUTHOR]

The hydrocarbon source rocks of the marine carbonates of the Ordovician Majiagou Formation in the Ordos Basin are generally in the high-overmature stage and are, therefore, not suitable for hydrocarbon thermal simulation experiments. Their hydrocarbon generation potential and hydrocarbon generation characteristics are not clearly understood. Meanwhile, Nordic Cambrian carbonates are similar in lithology, parent material type, and sedimentary age, and are in the low evolution stage, which is suitable for hydrocarbon thermal simulation experiments. Therefore, in this study, we selected the Nordic carbonates for the gold tube thermal simulation experiment to analyze the content and geochemical characteristics of the thermal simulation products. The experimental results are also compared and analyzed with the characteristics of thermal simulation products of Pingliang Formation mud shale (contemporaneous with the Majiagou Formation) and Shanxi Formation coal (in the upper part of the Majiagou Formation), which are similar to the Majiagou Formation in the Ordos Basin. The results showed that the Nordic carbonate has different hydrocarbon production characteristics from the mud shale of the Pingliang Formation of the same parent material type, and although the hydrocarbon production yields of the two are not very different, the carbonate still produces methane at 600 °C. The hydrocarbon production yield of the Nordic carbonates is almost equivalent to that of type-II2 kerogen, indicating that the hydrocarbon production yield is not related to lithology and only to the organic matter type; however, the Nordic carbonate can produce a large amount of H2S. The alkane carbon isotope changes are mainly controlled by the degree of thermal evolution, showing gradual heaviness with increasing temperature. No carbon isotope sequence reversal occurred during the thermal simulation, and its distribution range is roughly the same as that of the alkane carbon isotope composition of the mud shale of the Pingliang Formation. The ethane carbon isotope composition is as heavy as −21.2‰ at the high-temperature stage, showing similar coal-type gas characteristics. The addition of calcium sulphate (CaSO4) causes the TSR reaction to occur, which has a significant impact on the methane content under high maturity conditions, reducing its content by more than 50% at 600 °C. However, the addition of CaSO4 increases the yield of heavy hydrocarbon gases, such as ethane, and promotes the production of C6-14 hydrocarbons and C14+ hydrocarbons at high-temperature stages, and the addition of CaSO4 substantially increases the yield of H2, CO2, and H2S. The thermal simulation results have implications for the hydrocarbon formation mechanism of the early Paleozoic marine carbonate formation system in the stacked basins of the Ordos Basin and the Tarim Basin in China. [ABSTRACT FROM AUTHOR]

Overpressure is significant to the exploration and exploitation of petroleum due to its influence on hydrocarbon accumulation and drilling strategies. The deep-burial hydrocarbon reservoirs of Jurassic strata in the central Junggar Basin are characterized by intensive overpressure, whose origins are complex and still unclear. In this study, Bowers' method and sonic velocity-density crossplot method based on well logging data were used as a combination for overpressure judgements in geophysics. Furthermore, the corresponding geological processes were analysed in quality and quantity to provide a rational comprehension of the overpressure origins and the model of overpressure evolution and hydrocarbon accumulation processes. The results showed that hydrocarbon generation in the Jurassic source rocks led to overpressure in the mudstones, while hydrocarbon generation in Permian source rocks led to overpressure in the sandstone reservoirs in Jurassic strata by vertical pressure transfer. The burial and thermal history indicated that the aquathermal effect of pore fluids by temperature increase in deep strata is also an important origin of overpressure, while disequilibrium compaction may not be the dominant cause for the overpressure in deep-buried strata. Furthermore, the continuous tectonic compression in both the north--south and west-east trends from the Jurassic period to the present may also have enhanced the overpressure in deep strata. Meanwhile, the developed faults formed by intensive tectonic compression led to pressure transfer from source rocks to the Jurassic reservoirs. Overpressured geofluids with hydrocarbons migrated to sandstone reservoirs and aggravated the overpressure in the Jurassic strata. To conclude, the intensive overpressure in the central Junggar Basin is attributed to the combination of multiple mechanisms, including hydrocarbon generation, the aquathermal effect, tectonic compression and pressure transfer. Furthermore, the developed overpressure indicated hydrocarbon migration and accumulation processes and the potential of oil and gas reservoirs in deeply buried strata. We hope this study will provide a systematic research concept for overpressure origin analysis and provide guidance for petroleum exploration and exploitation in deep-buried strata. [ABSTRACT FROM AUTHOR]

Unraveling the complex relationship between orogenesis and hydrocarbon formation and accumulation is challenging and is often hampered by physical and chemical overprints of younger events. The Permian reservoir in the Longmen Shan orogen, South China, is such an example, and its evolution has been hotly debated. In this study, we use a new combination of paleomagnetic dating analysis and Re–Os isotope dating to try to resolve this. Paleomagnetic dating of the hydrocarbon‐host carbonate indicates two remagnetization events during: (a) the Late Triassic, and (b) the Middle Jurassic–Cretaceous. These two remagnetization events are shown to represent two distinct stages of hydrocarbon accumulation. The paleomagnetic estimates are supported by Re–Os dating of bitumen (∼264 Ma) and oil (∼94 Ma). The two different Re–Os ages are associated with two periods of oil generation. We interpret these data in terms of known geological processes: (a) the ∼260 Ma Dongwu large igneous province caused oil generation, and the Indosinian tectonic event caused the migration and accumulation; and (b) the Late Cretaceous Yanshan orogenic events promoted another generation and entrapment of oil in the same reservoir. This combined approach reliably tracks the sequence of oil generation and accumulation, even when the source rock is uncertain, and multi‐phase accumulation and complex tectonism has occurred. Given that paleomagnetic and Re–Os dating are independent methods which can constrain multiple geological processes, when used together they have the potential to be universally applied. Plain Language Summary: Key to understanding complex geological processes is the dates and sequence of each event. The timing of hydrocarbon formation and accumulation is one such complex geological process that can be difficult to unravel, but critical to evaluate the complex orogenesis and hydrocarbon explorations. In this paper, we combine for the first time two independent dating methods to study hydrocarbon reservoirs of Longmen Shan orogen: (a) paleomagnetic and (b) rhenium‐osmium isotope dating. The two methods identified two periods of hydrocarbon formation, followed by two extended periods of hydrocarbon migration. This combined method is particularly powerful as it is independent of the hydrocarbon source rock and complex geological settings. Moreover, the two methods can provide additional tests for each dating technique. The new combined methods can, therefore, be applied in complex hydrocarbon‐bearing regions worldwide. Key Points: Paleomagnetic and Re–Os isotope data were collected for a hydrocarbon carbonate reservoir to determine the hydrocarbon evolution processesOil accumulations are found to have remagnetized the reservoir carbonates during the Late Triassic and CretaceousTiming of oil generation is constrained by Re‐Os dates of bitumen and oil hosted in carbonates at ∼264 and ∼94 Ma, respectively [ABSTRACT FROM AUTHOR]

A series of natural gas fields have been discovered in the deepwater area of the Qiongdongnan Basin (QDNB) of China. However, the natural gas generation process and mechanism still exist controversy. Hence, two semi-open systematic pyrolysis experiments were conducted on a modified apparatus to study the natural gas generation process and mechanism in the deepwater area of the QDNB in this study, including pressured experiments and non-pressure experiments. In the pressured experiments, a stress pressure ranges from 37.6 to 188.2 MPa and fluid pressure ranges from 14.4 to 96.0 MPa based on the thermal evolution model of the QDNB. In non-pressured experiments, only fluid pressure from 2.0 to 5.0 MPa for a hydrous condition was compared with pressured experiments. The experiment results indicate that the pressured experiments could decrease the generated yields, expulsion efficiencies and expulsion process of the liquid hydrocarbons. Moreover, the suppression effect appears to be stronger under high evolution than that of low-maturity stage. Additionally, liptinite preservation exists during the liquid hydrocarbons and natural gas generation at temperature over 420 °C, whereas the liquid hydrocarbon is cracking to gas at temperature over 500 °C as a function of lithostatic stress, fluid pressure, temperature and time. Hence, pressure plays an important role in influencing expulsion efficiencies and expulsion process of the liquid hydrocarbons and natural gas generation in the high maturity stage. [ABSTRACT FROM AUTHOR]

The Jinyang Basin is a typical volcanic-sedimentary basin, located in the southern peripheral area of the Songliao Basin. Hydrothermal activity is often closely related to the intrusion or eruption of magma. It was recently suggested that dolomite in the Jurassic Beipiao Formation was formed under the influence of magmatic-hydrothermal activity and magmatic-hydrothermal activity might have impacts on the organic matter of the source rocks. No investigation has been aimed at the effect of magmatic-hydrothermal activities on the accumulation of organic matter in the Beipiao Formation source rocks and a comprehensive study is urgent, which would be indicative in unravelling the accumulation mechanism of organic matter and useful in further petroleum exploration. To provide important insights into these issues, we carried out a detailed investigation of geological and geochemical analysis for Wolong (WL) and Dongkuntouyingzi (DK) outcrop shales from the Lower Jurassic Beipiao Formation in the Jinyang Basin. The hydrothermal indicator discrimination diagram (Zn-Ni-Co triangular plot) and rare earth element anomalies (δEu and δCe) indicate that the formation of WL samples is associated with hydrothermal activity, but DK is not. The TOC values suggest that most of the WL and DK samples are good to very good and fair to good source rocks, respectively. The Ro values suggest that both WL (Ro = 1.17%) and DK (Ro = 1.01%) samples have entered the oil-generating stage, and WL samples were influenced by the magmatic activity with higher maturity. The biomarkers such as high steranes/hopanes, high 4-methyl steranes/C29 steranes, low Pr/Ph values and high gammacerane index suggest that WL samples were deposited in an anoxic-prone saline environment with significant contributions of algal sources. Contrarily, the DK samples were deposited in oxic-prone and freshwater paleolake with significant contributions of terrigenous organic matter. The magmatic-hydrothermal activities in the Wolong area brought numerous nutrients to the lake basin, which may facilitated the reproduction of aquatic organisms. At the same time, the magmatic-hydrothermal activities increased the salinity of water and promoted the formation of a water reducing environment, which provided an excellent environment for the preservation and enrichment of organic matter. Therefore, the magmatic-hydrothermal activities in the Wolong area promoted the formation of organic-rich source rocks and the hydrocarbon generation process. [ABSTRACT FROM AUTHOR]

Shale oil content prediction is currently the focus of exploration. Traditional prediction methods are less accurate, and a large number of analytical tests can increase the cost of exploration. Therefore, new methods need to be introduced to accurately predict sweet spot intervals. In this study, a quick and novel convolutional neural network (CNN) method to predict oil content parameters (TOC, S 1 and S 2) is provided based on well logs (SP, GR, CAL, RT, and AC) in the Dongpu Depression, Bohai Bay basin, China. The results showed that the CNN model showed high accuracy in predicting TOC (R2 = 0.73) than the ΔlogR method (R2 = 0.132). The validation sets for S 1 (R2 = 0.72) and S 2 (R2 = 0.67) also show high prediction accuracy. In addition, Well Wen 318 (located in the same formation) was selected as a blind well to test the performance of the model. The micromigration evaluation method is based on the principle of mass balance, which reflects the changes of the original hydrocarbon generation potential (HGP O) and the real hydrocarbon generation potential (HGP R). Combined with the established CNN model and the micromigration evaluation method, we predicted and evaluated the oil content in lower Mbr 3 of the Shahejie Fm and divided four sweet spots. The differential enrichment of shale oil is controlled by micromigration. Samples with high saturated/aromatic ratio and small main peak carbon of saturated hydrocarbon chromatography are more likely to undergo micromigration, which in turn affects the oil content of shale. Shales with high organic matter abundance and good pore connectivity are more susceptible to micromigration, leading to the differential enrichment of shale oil. This study provides a new idea for evaluating hydrocarbon micromigration of shale oil and predicting favorable zones and the grading evaluation of oil content in petroliferous basins around the world. • A novel CNN method to predict oil content parameters is provided based on well logs. • A micromigration evaluation model was established based on hydrocarbon generation & retention. • 4 sweet spots intervals were predicted combined with micromigration evaluation and CNN model. • The differential enrichment of shale oil is explained from the micromigration perspective. [ABSTRACT FROM AUTHOR]

Based on the systematic analyses of samples collected from the western Qaidam basin, the organic geochemical characteristics of representative Paleogene saline lacustrine carbonate source rocks were synthetically studied. The results show that the carbonate source rocks are characterized by total organic carbon (TOC) content varied in the range of 0.07 to 1.57%, with an average of 1%, and hydrocarbon generation potential (S1 + S2) is range from 0.2 to 9.61 mg HC/g rock with an average of 4.6 mg HC/g rock, and organic matters of Types II1 and Type I, which indicated that it belongs to high-quality carbonate source rocks. Meanwhile, the Tmax of source rock range from 409 to 438°C and productivity index (PI) varied in the range of 0.09 to 0.38, which imply that the source rock in immaturity to low-maturity phase. The biomarker compositions are characterized by the Pr/Ph ratio of the source rocks is 0.36, and the gammacerane/αβ-C30 hopane ratio up to 1.25, these data reflect that the presence of a highly reducing saline environment. Meanwhile, a high abundance of C27 sterane and bicyclic terpane indicates that aquatic algae are the main organic parent material. The identification of microscopic organic components of samples also reveals an abundance of the Botryococcus braunii fossil of up to 30% with strong yellow fluorescence. These results, together with comparison research of crude oil and source rocks, show that the saline lacustrine carbonate source rocks from the Yingxi area deposited under an anoxic and saline environment at the stage of low maturity. This study provides guidance for predicting the distributions of high-quality source rocks in the western Qaidam basin. [ABSTRACT FROM AUTHOR]

The nano-scale pore structure of shale is closely related to the self-generated and self-accumulated shale oil and gas. The Bohai Bay Basin is a crucial oil-bearing basin in eastern China, and the Paleogene Shahejie Formation is the most important source rock section in this area. In order to study the internal relationship between hydrocarbon generation evolution and pore structure characteristics of source rocks, we conducted hydrocarbon generation simulation tests with a closed gold tube system, and heated up original rocks from Shahejie Formation in Laizhou Bay Sag, southern Bohai Bay Basin, from 290 °C to 440°C at different heating rates. Besides, we carried out low-temperature N2 adsorption experiments on sample residues, and measured their pore structure characteristic parameters. The results show that with the increase of simulated temperature, the specific surface area and pore volume of nano-pores below 10 nm (which are mainly organic pores) decrease first and then increase, while those of nano-pores above 10 nm increase all the way. The evolution trend of total specific surface area and pore volume is mainly controlled by pores below 10 nm which are mainly organic pores, especially micropores below 2 nm. There are two main factors affecting the development of inorganic pores: (1) Dissolution of organic acids produced by pyrolysis of organic matter in hydrocarbon-generation evolution; (2) Deformation of crystal structure of mineral components under the combined action of temperature and pressure. The experimental results at different heating rates demonstrate that rapid settlement under geological conditions is not conducive to the development of nano-pores, especially micro-pores composed of organic pores. [ABSTRACT FROM AUTHOR]

Organic‐rich shales, deposited in marine‐continental transitional environments, are widely distributed in southern China. The pore evolution of the Late Permian Longtan Formation shale (Guizhou Province) during its diagenesis and organic matter (OM) evolution was quantitatively and qualitatively investigated through thermal simulation, mercury intrusion capillary pressure, gas adsorption, fractal dimension, and field emission‐scanning electron microscopy observation. Diagenesis and OM evolution stage were subdivided on the basis of X‐ray diffraction, rock pyrolysis, and vitrinite reflectance test; moreover, the main controlling factors of pore structure during evolution were also discussed. Shales were heated to different temperatures with their vitrinite reflectance ranged between 1.23% and 3.12%, indicating that organic matter had evolved from a low‐ to a post‐mature stage. According to the changes in clay mineral composition, hydrocarbon generation, and Tmax, we subdivided diagenesis into four parts, each of which has a good correspondence with OM evolution. Pore volume (PV) varied between 0.012162 and 0.033482 cm3/g, while the specific surface area (SSA) varied between 13.3693 and 23.0094 m2/g. Mesopores were the main contributors to the total pore volume, while mesopores and micropores were the main contributors to the total specific surface area. In this study, the evolution of pore structure was not monotonous, but intermittent: The PV and SSA of shale samples first decreased and then increased. Maturity was the most important factor affecting the evolution of pore structure. The abundance of pores in OM, associated with hydrocarbon generation, resulted in large micro‐PV and micro‐SSA; moreover, the composition of clay minerals also influenced the pore structure evolution. The transformation of kaolinite into illite increased the content of illite and illite/smectite mixed layer, hence affecting the overall meso‐PV and meso‐SSA. [ABSTRACT FROM AUTHOR]

Natural gas and condensate derived from Carboniferous-Permian (C-P) coaly source rocks discovered in the Dagang Oilfield in the Bohai Bay Basin (east China) have important implications for the potential exploration of C-P coaly source rocks. This study analyzed the secondary, tertiary, and dynamic characteristics of hydrocarbon generation in order to predict the hydrocarbon potentials of different exploration areas in the Dagang Oilfield. The results indicated that C-P oil and gas were generated from coaly source rocks by secondary or tertiary hydrocarbon generation and characterized by notably different hydrocarbon products and generation dynamics. Secondary hydrocarbon generation was completed when the maturity reached vitrinite reflectance (Ro) of 0.7%–0.9% before uplift prior to the Eocene. Tertiary hydrocarbon generation from the source rocks was limited in deep buried sags in the Oligocene, where the products consisted of light oil and gas. The activation energies for secondary and tertiary hydrocarbon generation were 260–280 kJ/mol and 300–330 kJ/mol, respectively, indicating that each instance of hydrocarbon generation required higher temperature or deeper burial than the previous instance. Locations with secondary or tertiary hydrocarbon generation from C-P coaly source rocks were interpreted as potential oil and gas exploration regions. [ABSTRACT FROM AUTHOR]

Thermal maturation in the shale oil/gas system is inherently complex due to the competitive interplays between hydrocarbon generation and retention processes. To study hydrocarbon generation characteristics from shales within different stages of thermal maturation under the influence of retained oil, we performed Micro-Scale Sealed Vessels (MSSV) pyrolysis on a set of artificially matured lacustrine shale samples from the Shahejie Formation in the Dongpu Depression in Bohai Bay Basin, China. Experimental results show that hydrocarbon yields of shale samples with or without retained oil at various thermal maturities follow different evolution paths. Heavy components (C15+) in samples crack at high temperatures and generally follow a sequence, where they first transform into C6–14 then to C2–5 and C1. Methane accounts for most of the gaseous products at high temperatures in all samples, with different origins. The cracking of C2–5 is the main methane-generating process in samples with retained oil, whereas the source of methane in samples without retained oil is kerogen. In the studied shales, retained oils at early-mature stage retard the transformation of liquid to gaseous hydrocarbon and prompt the cracking of C2–5 to C1 to some extent. TSR reaction related to gypsum in the studied samples is the primary reason that can explain the loss of hydrocarbon yields, especially at high temperatures. In addition, transformation of volatile hydrocarbons to gas and coke also accounts for the loss of generated hydrocarbon, as a secondary factor. [ABSTRACT FROM AUTHOR]

• Deposition regulate mineral-OM association and oil–gas generation material basis. • Diagenesis determine impetus of hydrocarbon generation by affecting illitization. • Clay-OM interactions affect integrated framework of OM preservation and conversion. Although the hydrocarbon generation of mudstones is greatly affected by depositional and diagenetic environments, how they affect the integrated theoretical framework of organic matter (OM) preservation, mudstone formation, and OM diagenetic conversion remains unresolved. Therefore, we addressed this issue from the perspective of clay–OM interactions during mudstone formation and diagenetic evolution. The northern and southern Dongpu Depressions represent two endmembers of depositional (weak vs. strong hydrodynamics and abundant vs. limited terrigenous input) and diagenetic (saline vs. freshwater pore fluid) environments. Results highlighted that the protection of clay minerals on OM preservation was more affected by the depositional fabric than mineral content. For the northern Depression mudstones, the predominance of laminated mudstones and remarkable enrichment of high-hydrogen index OM in the clay-sized fractions indicated the intimate clay-OM associations during mudstone formation, which led to better OM preservation and a higher hydrocarbon generation potential. For the southern Depression mudstones, the scattered distribution of OM particles and inconspicuous OM enrichment in the clay-sized fractions coincided with lower hydrocarbon generation potential. Additionally, the faster smectite illitization accelerated by the saline environment of the northern Depression led to OM desorption. Thus, OM lost the protection of clay minerals and the mineral reactive sites were liberated, both of which were beneficial to hydrocarbon generation. Generally, deposition controlled the material premise and diagenesis determined the hydrocarbon generation impetus. These findings provide a theoretical reference for shale oil accumulation in saline lacustrine systems and can potentially serve as a guide for future oil – gas exploration and development. [ABSTRACT FROM AUTHOR]

Much progress in studies on the quantifications of overpressuring has been made during the past decades, and various quantitative models for the overpressure have been built based on overpressure transfer, tectonic extrusion, disequilibrium compaction, hydrocarbon generation, and other processes. In the Raoyang Depression of the Bohai Bay Basin in China, overpressure is mainly generated due to disequilibrium compaction and hydrocarbon generation. However, the overpressure-generation mechanism varies significantly in the overpressured formations and sags. The overpressure genesis in the Dongying Formation (Ed) occurs by disequilibrium compaction, but the overpressure mechanism in the first member (Es1) and third member (Es3) of the Shahejie Formation is a combination of disequilibrium compaction and hydrocarbon generation. The overpressure is caused by the difference in hydrocarbon generation before and after hydrocarbon expulsion. On the basis of the law of volume conservation, three quantitative models have been established for the under-compacted interval, the hydrocarbon-generation-to-expulsion interval, and the post-hydrocarbon-expulsion interval. The contribution of hydrocarbon generation differs in four sags developed in the Raoyang Depression due to differences in the hydrocarbon-generation capacity. Calculations based on these quantitative models indicated that the contributions of hydrocarbon generation to overpressure at the bottom of the Es1 and Es3 members in the Maxi Sag are 54.3% and 39.1%, respectively. The excessive pressure in the lower strata was stronger than that in the upper strata due to the fact that the contribution ratio of hydrocarbon generation to overpressure in the Es1 member is lower than that in the Es3 member, unlike in the case when the pressure in the upper strata is stronger than that in the lower strata. Therefore, it indicated that hydrocarbon generation plays an important role in the overpressure-generation mechanism. • Overpressure is mainly generated by hydrocarbon generation and disequilibrium compaction in Es1 and Es3. • Three overpressure quantification models for different intervals have been established. • Hydrocarbon generation plays an important role in the overpressure generating mechanism. • The contribution of hydrocarbon generation is related to the hydrocarbon-generation capacity. [ABSTRACT FROM AUTHOR]

Carbonates have been known to act as hydrocarbon source rocks, but their basic geochemical and associated hydrocarbon generation characteristics remain not well understood as they occur with argillaceous source rocks in most cases, and the hydrocarbon generation from each rock type is difficult to distinguish, forming one of puzzling issues within the field of petroleum geology and geochemistry. To improve the understanding of this critical issue, this paper reviews recent advances in this field and provides a summary of key areas that can be studied in future. Results show that carbonate source rocks are generally associated with high-salinity environments with low amounts of terrestrial inputs and low dissolved oxygen contents. Petrographically, these source rocks are dark gray or black, fine-grained, stratified, and contain bacterial and algal bioprecursors along with some other impurities. They generally have low organic matter contents, although these can vary significantly in different cases (e.g., the total organic carbon contents of marine and lacustrine carbonate source rocks in China are generally 0.1%–1.0% and 0.4%–4.0%, respectively). These rocks contain type I and type II kerogen, meaning there is a lack of vitrinites. This means that assessment of the maturity of the organic matter in these sediments needs to use non-traditional techniques rather than vitrinite reflectance. In terms of molecular geochemistry, carbonate source rocks have typical characteristics indicative of generally reducing and saline environments and lower organism-dominated bioprecursors of organic matter, e.g., high contents of sulfur compounds, low Pr/Ph ratios, and dominance of n-alkanes. Most of the carbonate source rocks are typically dominated by D-type organic facies in an oxidized shallow water mass, although high-quality source rocks generally contain A- and B-type organic facies in saline lacustrine and marine-reducing environments, respectively. The hydrocarbon generation model for the carbonate source rocks can involve early, middle, and late stages, with a diversity of hydrocarbons within these rocks, which can be aggregated, adsorbed, enclosed within minerals, or present as inclusions. This in turn implies that the large-scale hydrocarbon expulsion from these rocks is reliant on brittle deformation caused by external forces. Finally, a number of aspects of these source rocks remain unclear and need further study, including the effectiveness of carbonates as hydrocarbon source rocks, bioprecursors, and hydrocarbon generation models of carbonate source rock, and the differences between marine and lacustrine carbonate source rocks. [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]

Bedding-parallel calcite veins (BPCVs) occur widely in Upper Cretaceous lacustrine shales of the Qingshankou Formation in the Northern Songliao Basin, China. Research on the formation processes and geological significance of BPCVs has focused on the sources of fluid, timing of formation, initiation, dilation and growth mechanisms, and on relationships with hydrocarbon generation. In this study, we addressed these issues through a comprehensive study of drill cores containing BPCVs using petrographic observations, isotope geochemistry, rare earth element (REE) analysis, fluid inclusion analysis, in situ U–Pb dating, and basin modeling. BPCVs were observed in medium–high maturity shales with high organic matter contents with heterogeneous compositions. Similarities in δ13C, δ18O, 87Sr/86Sr, and REEs contents between BPCVs and the host shale indicate that locally derived formation fluids driven by chemical gradients were involved in BPCV formation. The in situ U–Pb age dating (70 ± 8.9 Ma and 70.6 ± 9.7 Ma) constrained BPCVs formation to the late Cretaceous, corresponding to a burial depth of ∼1600 m, indicating that the BPCVs formed in the oil window. The latter is also supported by fluid inclusions-derived temperatures (∼76–109 °C). BPCV formation included vein initiation and dilation, and the microstructures, e.g., domal and pincer structures, sigmoidal calcite veins, conjugate en-échelon calcite vein arrays, as well as mechanical crystal twins of the BPCVs, all indicate that tectonic compression influenced fracture development as also indicated in other basins where beef occur. Fluid overpressure caused by hydrocarbon generation, tectonic compression, and clay mineral transformation (mainly smectite to illite conversion) was responsible for vein dilatation. Antitaxial fibrous crystals with smooth crystal boundaries and high aspect ratios, containing sinusoidal solid inclusions as well as median planes, indicate that crystallization force promoted vein growth. Thus, BPCVs can be used as a good indicator of hydrocarbon generation, and horizontal tectonic compression. • Bedding-parallel calcite veins (BPCVs) occur widely in medium–high maturity lacustrine shales of the Songliao Basin. • Locally derived formation fluids driven by chemical gradients were involved in BPCV formation. • The in situ U–Pb age dating indicates that the BPCVs formed in the oil window. • Tectonic compression influenced fracture development, and crystallization force promoted BPCV growth. • BPCVs can be used as a good indicator of hydrocarbon generation, and horizontal tectonic compression. [ABSTRACT FROM AUTHOR]

The central Junggar Basin in western China is unique because it provides insights into the geochemistry of oil from Jurassic coal measures. The analysis of TOC, Rock-Eval pyrolysis, gas chromatography-mass spectrometry (GC-MS), and carbon isotopes was performed to characterize the oil geochemistry and evaluate the hydrocarbon generation potential of source rocks in a coal-bearing formation. Fluid inclusions, fluorescence microscopy, and burial-thermal history were also used to study the oil generation and charging histories. The results show that the mudstone of the Badaowan Formation is the main source rock of the Jurassic and has relatively high hydrocarbon generation potential. The Jurassic oil in the Zhong-4 Block is moderately mature, with an equivalent Ro of about 0.75%. The oil is characterized by heavy carbon isotopes, a predominance of Pr over the Ph, low abundances of trisnorhopane (Ts), tricyclic terpanes and gammacerane, predominance of C 29 steranes among regular steranes, a preponderance of naphthalene and its alkylated analogues in aromatic compounds, and abundant polycyclic compounds. Such geochemical data indicate a contribution of Jurassic humic type organic matter to the oil. The mudstone in the Badaowan Formation started generating hydrocarbons in the Early Cretaceous and reached the peak of hydrocarbon generation in the middle Cretaceous. One major hydrocarbon charging episode is suggested in the Late Cretaceous and another in the early Neogene. The Fukang Depression in the south is the source kitchen, and oil migrates in a direction of southwest to northeast through faults and sandstone carrier beds. • The Jurassic mudstones and oils are mostly within the oil window. • The mudstone in Badaowan Formation is the primary Jurassic source rock. • Unique biomarker characteristics of the Jurassic oil are demonstrated. • The Jurassic oil shows heavy carbon isotopes (δ 13 C > -28‰). • Two major hydrocarbon charging periods for the Jurassic reservoirs are suggested. [ABSTRACT FROM AUTHOR]

Highlights: [•] Pyrolysis of type II kerogens with and without oil expulsion was performed. [•] Generated gas and oil and residual solids in the pyrolysis were characterized. [•] Oil expulsion strongly impacts the amount and composition of oil and gas. [•] Oil expulsion causes residual solids, oil and gas to be more enriched in 13C. [•] Oil expulsion influences data pattern in genesis crossplots. [ABSTRACT FROM AUTHOR]

Sediments originated from volcanic-hydrothermal activities show clear relationship with hydrocarbon generation and accumulation in fine-grained sedimentary rocks at a regional scale. However, the fundamental processes and mechanisms of this relationship are still poorly understood at a microscopic scale to hamper efficient hydrocarbon exploration. In addition, coarse grains common in volcanic lacustrine fine-grained sediments have been traditionally interpreted as diagenetic products during early and late burial. Our study, however, suggests that coarse calcite grains are not diagenetic, but formed by subaqueous explosion. The calcite grains occur in lacustrine fine-grained sedimentary rocks in the middle Permian Lucaogou Formation in the Santanghu intracontinental rift basin, NW China. They are sand sized, angular, mono- and polycrystalline, and discretely scatter in silt to clay-sized non-calcite pyroclastic matrix. The calcite grains and the mud matrix are interpreted as a pyroclastic debris flow deposit. In-situ 87Sr/86Sr ratios (0.704932–0.705840, and 0.705137 on average) of the calcite grains are similar to those of mantle rocks, indicating an origin closely related to mantle-derived fluids. The in-situ δ13C values (4.24‰ to 5.06‰, and 4.57‰ on average) and extremly negative δ18O values (−21.70‰ to −21.18‰, and − 21.49‰ on average) indicate that extensive hydrothermal alteration and microbial activities influenced the formation of the calcite. Element composition and homogenizaiton temperature of fluid incusions of calcite and biomarkers of the mudstone all suggest a relatively low-temperature hydrothermal condition in a saline and reducing environment. Furthermore, hydrocarbon-rich inclusions are rich in the calcite grains and have two modes of occurrence and maturity. They indicate that the organic matter was generated from algae bloom, which was caused by volcanic-hydrothermal activities. Alternatively, the hydrocarbon may have an inorganic origin originated from a mantle source. Our findings provide an alternative interpretation on the origin of coarse calcite grains in fine-grained sedimentary rocks and demonstrate a microscopic relationship between volcanic-hydrothermal activities and hydrocarbon generation and accumulation in a tectonic active rift basin. [ABSTRACT FROM AUTHOR]

Hydrodynamic sorting exerts a first-order control on the quantity, type and molecular composition of sedimented organic matter. Although this physical mechanism has been invoked to explain the varying content and composition of organic matter in global continental margin sediments, it is rarely mentioned in the interpretation of the heterogeneity of source rocks in petroliferous basins. We investigate the controls of hydrodynamic sorting on the differentiation of organic matter content, type and molecular composition, and on the hydrocarbon generation capacity of source rocks in the lower part of the first member of the Eocene Shahejie Formation in the Qibei slope of the Bohai Bay Basin, by using the Rock-Eval pyrolysis, gas chromatography-mass spectrometry and logging interpretation tools. The source rock samples in the northeastern part of the slope generally present a relatively coarse grain size, less organic matter content, and are rich in humic material, whereas the source rocks in the southwestern slope area show opposite trends in these characteristics. Biomarker data demonstrate reducing sedimentary conditions and that the proportion of organic matter input from aquatic organisms versus terrestrial higher plants increases with a reduction in grain size. Pyrolysis data with a hydrogen index model shows that this organic matter-grain size relationship causes a difference in hydrocarbon generation capacity of the source rocks in various regions of the slope. This relationship also plays a role in a migration of the hydrocarbon generation center from a low-lying area in the northeastern slope to a relatively higher area in the southwest. In summary, hydrodynamic sorting is important in the distribution of organic matter pools in the slope area, causing changes in the abundance, type and composition of organic matter in the source rocks in the slope area and profoundly affecting the overall pattern of hydrocarbon generation. • The hydrodynamic sorting mechanism is used to interpret the heterogeneity of source rocks. • The quantity, type and composition of organic matter in source rocks change regularly with grain size. • The hydrodynamic sorting profoundly affects the hydrocarbon generation pattern of source rocks. [ABSTRACT FROM AUTHOR]

Highlights: [•] Input parameters and boundary conditions were customized and simulated. [•] Hydrocarbon generation and migration was modeled on wells, cross-section, and maps. [•] Fluid potential and flow line modeling reveals that structural highs are directions of hydrocarbon migration. [Copyright &y& Elsevier]

Thermal evolution of source rocks and dynamic sealing evolution of cap rocks are both subjected to tectonic evolution. The marine sequences in South China have experienced superposed structural deformation from multiple tectonic events. To investigate the effectiveness of preservation conditions, it is of great importance to understand the controls of key tectonic events on the dynamic evolution of cap rocks. This paper discusses the controls of Late Jurassic-Early Cretaceous (J-K) tectonic event on source and cap rocks in marine sequences in South China based on the relationships between J-K tectonic event and the burial history types of the marine sequences, the hydrocarbon generation processes of marine source rocks, the sealing evolution of cap rocks, the preservation of hydrocarbon accumulations, and the destruction of paleo-oil pools. The study has the following findings. In the continuously subsiding and deeply buried areas during the J-K period, marine source rocks had been generating hydrocarbons for over a long period of time and hydrocarbon generation ended relatively late. At the same time, the sealing capacity of the overburden cap rocks had been constantly strengthened so that hydrocarbons could be preserved. In the areas which suffered compressional deformation, folding and thrusting, uplifting and denudation in J-K, the burial history was characterized by an early uplifting and the hydrocarbon generation by marine source rocks ended (or suspended) during the J-K period. The sealing capacity of the cap rocks was weakened or even vanished. Thus the conditions for preserving the hydrocarbon accumulations were destroyed. The continuously subsiding and deeply buried areas during the J-K period are the strategic precincts of the petroleum exploration in marine sequences in South China. [ABSTRACT FROM AUTHOR]

The process of organic matter transformation into oil and gas is also a balance process of hydrocarbon transformation. This article probes to distinguish the oil expulsion history from gas expulsion history based on the hydrocarbon generation, hydrocarbon residual, and hydrocarbon expulsion processes of the source rocks. In this method, the first step is to study the hydrocarbon expulsion rate by means of hydrocarbon generation potential method; the second step is to study the oil generation rate by means of the heating-pressuring experiment method; the third step is to study the oil residual rate by means of the mathematical method. The difference between the values of oil generation rate and oil residual rate is defined as the oil expulsion rate, while that between the values of hydrocarbon expulsion rate and the gas expulsion rate is defined as the gas expulsion rate. Then, combined with the geological parameters of source rocks, the oil and gas expulsion history can be obtained. This study on Es Source rocks, Nanpu Sag, Bohai Bay Basin, China shows that the primary expulsion period of Es source rocks is Guantao-Minghuazhen period. [ABSTRACT FROM AUTHOR]

Abstract: The Ordos Basin of North China is not only an important uranium mineralization province, but also a major producer of oil, gas and coal in China. The genetic relationship between uranium mineralization and hydrocarbons has been recognized by a number of previous studies, but it has not been well understood in terms of the hydrodynamics of basin fluid flow. We have demonstrated in a previous study that the preferential localization of Cretaceous uranium mineralization in the upper part of the Ordos Jurassic section may have been related to the interface between an upward flowing, reducing fluid and a downward flowing, oxidizing fluid. This interface may have been controlled by the interplay between fluid overpressure related to disequilibrium sediment compaction and which drove the upward flow, and topographic relief, which drove the downward flow. In this study, we carried out numerical modeling for the contribution of oil and gas generation to the development of fluid overpressure, in addition to sediment compaction and heating. Our results indicate that when hydrocarbon generation is taken into account, fluid overpressure during the Cretaceous was more than doubled in comparison with the simulation when hydrocarbon generation was not considered. Furthermore, fluid overpressure dissipation at the end of sedimentation slowed down relative to the no-hydrocarbon generation case. These results suggest that hydrocarbon generation may have played an important role in uranium mineralization, not only in providing reducing agents required for the mineralization, but also in contributing to the driving force to maintain the upward flow. [Copyright &y& Elsevier]

Abstract: The Yuka depression is located in the north margin in Qaidam Basin, Qaidam Basin is an interior formed primarily in the Mesozoic and Cenozoic. There are extensive distribution of good source rocks of middle Jurassic, which have undergone non-uniform uplift, twisting and deep burying. There are different hydrocarbon generation (HG) evolutions. We have studied the history of burying, heating, and hydrocarbon generation of the Jurassic source rocks not just on the basis of tectonic disturbance and deep burying in detail. Meanwhile, Combining with fluid inclusion measurements and the numerical simulation of EASY%Ro, We analysis the evolution process, the tectonic stages and the intensity of the HG of middle Jurassic source rock. The hydrocarbon generation occurred in Yanshanian and Early Himalayan since the middle Jurassic formation. The paper discusses tarp formation and destroys of the oil & gas in Yuka depression. At last, we suggest that the thrust fault of Late Himalayan must be pay more attention, .and the middle or small sizes of oil & gas fields will be discovered in the future exploration. [Copyright &y& Elsevier]

The coupling relationship between volcanic-hydrothermal activities and hydrocarbon generation has been a common understanding in recent years. However, there is a lack of theoretical and practical guidance in the application hydrocarbon production. The fine-grained sedimentary rocks of the middle Permian Lucaogou Formation in the Jimsar Sag in the Junggar Basin, NW China, are critical source rocks and have been simplify regarded as a mudrocks for target for tight oil exploration. Recently studies show that rocks were deposited in an intracontinental lacustrine environment with multiple volcanic-hydrothermal activities. Their complex micro-scale lithological characteristics restrict the understanding and further exploration and development of tight oil. Hence, this study focuses on the detailed lithological and their organic geochemical characteristics of the Lucaogou Formation using microscopic thin-section observation, scanning electron microscopy, X-ray diffraction, Rock-Eval, saturated hydrocarbon chromatography and mass spectrometry. The following key conclusions were obtained. First, the massive mudrocks are sub-divided into lithofacies for hydrocarbon generation, including tuffaceous shale, calcareous shale and dolomitic shale, and, microinterval reservoirs, including dolostone and sedimentary tuff. Second, the origins of organic matter in Lucaogou Formation were mainly plankton, bacteria with minor of land plants. The depositional environment is high salinity and anoxic conditions. Materials derived from volcanic-hydrothermal activities, lacustrine precipitation, and terrestrial transportation mixed with various proportions to form this formation. Third, a mixture of carbonate minerals, felsic minerals and clay minerals is the best source rock, and the higher the mixture, the better. This research not only provides insight into the influence of volcanic-hydrothermal activities on lithology and organic matter enrichment, but also providing a potential scheme for the tight oil exploration and development in similar rifted geological settings. • A mixture lithology of carbonate minerals, felsic minerals and clay minerals is the best source rock. • The better the mixture of carbonate minerals, feldspar minerals and clay minerals, the better the quality of hydrocarbon source rock. • Volcanic-hydrothermal activities are favorable to the enrichment and preservation of organic matter. • The Lucaogou formation was formed in a high salinity and anoxic condition, and the biological source was mainly plankton. [ABSTRACT FROM AUTHOR]

In the brackish water sedimentary environment of the Junggar Basin in Xinjiang, the organic-rich shale and shale oil formation with relatively low maturity, is characterized by relatively high abundance of C 28 regular steranes. However, the biogenic source of organic matter and favorable sedimentary environment for the type of source rock has been thoroughly classified. In this paper, organic geochemical and petrological, analyses of the Lucaogou Formation shale in the Jimusaer Sag, Junggar Basin in the north of Xinjiang Uygur Autonomy Region were carried out. The source rocks in the Lucaogou Formation are mainly composed of two types of maceral including lamalginite (cyanobacteria) and telalginite (green algae), with the former predominantly fueling the high C 28 regular sterane content. Petrological, organic and inorganic geochemical analyses suggest that the lamalginite was developed in low-salinity water while the telalginite was developed in high-salinity water. Based on geochemical and organic petrological characteristics, both the lamalginite and telalginite have good hydrocarbon-generating potential, but in the lower thermal evolution stage of the Lucaogou Formation source rock, telalginite have higher hydrocarbon-generating rate. • Lamalginite (cyanobacteria) is the primary source of C 28 regular steranes. • The lamalginite (cyanobacteria) is more developed when the salinity is low and the telalginite (green algae) is more developed when the salinity is high. • In the lower thermal evolution stage of the Lucaogou Formation source rock, the lamalginite (cyanobacteria) has lower hydrocarbon-generating rate than the telalginite (green algae). [ABSTRACT FROM AUTHOR]

The Dongpu Depression is an important oil-producing area in the Bohai Bay Basin, China. The exploration focus in this area has recently shifted to intervals with greater depths (>3500 m) because of decreasing hydrocarbon production at depths shallower than 3500 m. Deep petroleum resource evaluation is becoming important and the tectono-thermal history is a major part of this evaluation. In this study, Cenozoic tectono-thermal histories of the Dongpu Depression are reconstructed by coupling an inversion method of vitrinite reflectance and apatite fission track data from 13 wells. Moreover, the maturation history of the deep source rocks was modeled based on these histories. The results clearly show that the Dongpu Depression experienced two heat flow maxima during the deposition of the middle parts of the Eocene Shahejie 3 member and the Oligocene Dongying Formation, which exhibit maximum heat flow values of 70.5–77.5 mW/m2 and 64.8–70.0 mW/m2, respectively. These two periods of high heat flow are linked to the rifting events of the Dongpu Depression, corresponding to the intense rifting substage (45-38 Ma) and the later rifting substage (38-27 Ma). Tectonic subsidence analysis revealed that the Dongpu Depression experienced initial syn-rift subsidence during the Paleocene, followed by subsequent thermal subsidence since the Neogene. The maturation history indicates that these source rocks experienced only one hydrocarbon generation phase in the mid-northern sags, and experienced a hydrocarbon generation peak during the Oligocene Dongying Formation deposition. AFT and VR coupling inversion method for tectono-thermal history. [Display omitted] • The coupled inversion method of VR and AFT data is used to reconstruct the tectono-thermal history. • Two maxima of heat flows revealed the two-period rifting events. • The uplift time of the Dongying Movement was approximately 27 Ma. • The main hydrocarbon generation period of the DD occurred during the Dongying Formation deposition. [ABSTRACT FROM AUTHOR]

The Ordovician-Silurian Sichuan, Eocene Bohai Bay and Eocene Nanxiang Basins have been the main productive basins of shale oil and gas in China. Bedding-parallel calcite veins-bearing intervals are found to coincide with the shale gas- and/or shale oil-producing layers. Bedding-parallel calcite veins-bearing shale intervals are demonstrated to be always overpressured, organic-rich, mature and brittle, and they generally have higher porosity, higher permeability and higher gas/oil content than adjacent layers. A systematic study on the genetic mechanism of these veins confirms that the above phenomenon is prevalent in the three above mentioned basins and other sedimentary basins. Bedding-parallel calcite veins are viewed as a proxy for shale reservoir quality. This proxy helps geologists to preliminarily determine the potential shale reservoir layers out of the thick shale successions before systematic organic-inorganic tests, because it can be easily identified in cores, outcrops and well logs, thereby contributing to economic and time-efficient exploration. Therefore, occurrence of bedding-parallel calcite veins in shale reservoir exploration needs further attention, especially in petroliferous basins where shale reservoir exploration is still in its infancy. • Bedding-parallel calcite veins are formed during mature hydrocarbon generation. • Bedding-parallel calcite veins are linked the key elements in shale reservoir evaluation. [ABSTRACT FROM AUTHOR]

• Hierarchical clin/SBA-15 composites were prepared by using clinoptilolite as Al source. • E a of n-C16 aqueous conversion on clin/SBA-15 was 35 kJ/mol, less than that of non-catalytic cracking. • In oil shale conversion derived oil, C35+ were notably declined with catalyst under subcritical water. • Oil shale catalytic conversion produced oil with a strongly aliphatic nature. • The oil product showed H/C ratio rising (1.98 to 2.08) and O/C ratio declining (0.06 to 0.02). The massive reserves of oil shale in China offer the potential to lessen energy dependence on conventional sources. A novel oil shale in situ upgrading process over mineral-based clin/SBA-15 catalysts has been proposed, and catalytic pyrolysis behavior was intensively studied. Clinoplilolite was chosen for clin/SBA-15 preparation. The apparent activation energy E a of hexadecane cracking on clin/SBA-15(3.0) is 90.37 kJ/mol that is 35 kJ/mol less than that of thermal cracking. DSC curves of n-C16 conversion under 3 MPa N 2 reveals that the cracking peak temperature was declined to 365 °C and 372 °C from 417 °C (thermally) on clin/SBA-15 and kaolin/SBA-15, respectively. The extracted kerogen was converted at 280 °C with a biphasic solvent (water and decalin) to mimic the hydrocarbon generation process, and the products were mainly concentrated in C9, C10 and C11. Oil shale conversion was carried out at 280 °C under subcritical water. Non-catalytic converted products mainly contains hydrocarbons (34.01 %), long-chain fatty acids (esters), alcohol, and ketones. Catalytically produced oil have a strongly aliphatic nature, and the hydrocarbon yield is up to 70.50 % for clin/SBA-15. The clin/SBA-15 played a remarkable role on H/C ratio rising (1.98–2.08) and O/C ratio declining (0.10 to 0.04) because of the catalytic decarboxylation. Clin/SBA-15 showed no activity decay on seven-day oil shale aqueous conversion test. [ABSTRACT FROM AUTHOR]

The deep formations (underlying strata of the 3rd Member of Quantou Formation, Upper Cretaceous) in Songliao Basin possess a large natural gas potential, with a proven reserve of more than 200 × 109 m3 (706.3bcf). However, due to deep burial depth, multiple tectonic evolutions, and sets of source rocks, complex gas accumulations and different gas reservoir types developed, which may seriously restrict the natural gas exploration and target selection. This study focuses on the hydrocarbon generation, porosity evolution, and hydrocarbon accumulation processes of the tight sandstone gas (TSG) reservoir in the Cretaceous Shahezi Formation. 1) The timing and cumulative amounts of hydrocarbon generation were ascertained, with the Huoshiling being 143–10 Ma and 108.00 mg/g TOC and the Shahezi being 122–44 Ma and 30.00 mg/g TOC, respectively. 2) The mean original porosity of the Shahezi sandstone was 23.11%, and experienced the porosity decreasing of compaction (avg. = 12.57%) and cementation (avg. = 7.07%), and porosity increasing of dissolution (avg. = 3.25%), and the average present porosity is 6.72%. The sandstone densification (porosity <10%) occurred in the late period of Early Cretaceous (~115–105 Ma). 3) Four main stages of hydrocarbon accumulation in the K 1 sh occurred: I) Early oil accumulation stage (128–114 Ma)，corresponding to the 1st episode of charging; II) Middle oil and gas accumulation stage (111–90 Ma), corresponding to the 2nd episode of charging; III) Late gas accumulation stage (77–67 Ma), corresponding to the 3rd episode of charging; and IV) Adjustment stage (63 Ma–present), corresponding to the uplift stage. The 2nd and 3rd stages were the main gas accumulation stages. 4) Two types of tight sandstone gas reservoirs developed in the K 1 sh: I) tight conventional gas, and II) tight deep gas. The tight deep gas reservoirs, with favorable potentials, are the main exploration targets in the Shahezi Formation of Songliao Basin. • Two sets of coal-bearing source rocks generating gas. • Shahezi sandstone densification occurred in Early Cretaceous. • Three episodes of hydrocarbon charging occurred. • Four main stages of hydrocarbon accumulation occurred. • Two types of tight sandstone gas reservoirs developed. [ABSTRACT FROM AUTHOR]

As one of three cratonic basins in China, the Tarim Basin has the most abundant oil and gas resource, and its Precambrian petroleum system is a new region for hydrocarbon exploration. After conducting numerous field investigations in the Tarim Basin, we discovered the Sinian source rocks with 150m of thickness in Kuruktag area. These source rocks have total organic carbon (TOC) contents between 0.6% and 1.6%, with equivalent vitrinite reflectance (%Ro) between 1.23% and 1.42%. In addition, dark mudstone and a large amount of reservoir bitumen is present in the Upper Sinian outcrops in Aksu region. Biomarkers analysis indicates that reservoir bitumens in the Sinian and Cambrian strata were derived from the Sinian dark mudstones. Meanwhile, biomarkers of the reservoir bitumens from well ST1 in the Lower Cambrian Xiaoerbulake Formation indicate that the bitumen was originated from the Sinian source rocks and subsequently experienced biodegradation influence. Furthermore, a special hydrocarbon charging event with homogenization temperature of 50–60 °C has been elucidated from coeval aqueous phase of oil inclusions from in well ZS5, indicating that the oil and gas charging event in the Sinian source rocks occurred throughout the basin. As a result, the Sinian petroleum system in the Tarim Basin may contain high-quality source rocks, which contribute to the massive amount of Lower Paleozoic oil and gas resources in the basin. This study has important practical significance for oil and gas exploration of the Precambrian petroleum system in the Tarim Basin. • Hydrocarbon generation from Sinian source rocks has been found in the Tarim Basin. • Low-temperature fluid inclusion in Cambrian can only originate from precambrian. • Biomarkers confirm that Sinian source rocks once generated hydrocarbons in history. [ABSTRACT FROM AUTHOR]

As a main coalbed methane-producing area in China, Qinshui Basin has undergone typical tectonic thermal evolution as a result of the destruction of the North China Craton since the Late Paleozoic. This work describes the construction of a comprehensive tectono-thermal model for the southern Qinshui Basin (SQB) with which to reveal the maturation and hydrocarbon generation of the coal-bearing source rocks. The organic geochemical results show that in the present day, the source rocks comprise Type III kerogen containing more than 2.0 wt % TOC and that the R o ranges from 2.05% to 3.24%, suggesting appropriate thermal maturity and excellent gas generation potential. Modeling results indicate that from the Late Carboniferous to the Late Triassic, the coal-bearing strata entered the first rapid subsidence stage and reached a burial depth of about 5000 m in the Late Triassic, with a geothermal gradient of 42 °C/km and maximum temperature of 118 °C. Consequently, the maturity of source rocks increased to the first peak and entered the late oil stage. Due to the destruction of the North China Craton, lithospheric thinning, and associated magmatic activity during the Late Jurassic to Early Cretaceous, the study area experienced an abnormal thermal event, with an average geothermal gradient of 58 °C/km and a maximum heat flow of 124 mW/m2, and the source rocks reached the dry gas stage rapidly, so that secondary large-scale hydrocarbon generation occurred in the Early Cretaceous. Overall, the coal-bearing source rocks of the SQB underwent deep burial thermal metamorphism in the Late Triassic and intense magmatic thermal metamorphism in the Early Cretaceous, and the latter was completely controlled by magmatic events caused by the Craton destruction. • A comprehensive tectono-thermal model for the southern Qinshui Basin was built to reveal the maturation of source rocks. • The organic geochemical results indicate excellent gas generation potential of source rocks. • The studied source rocks underwent deep burial thermal metamorphism and magmatic thermal metamorphism successively. • The tectonic activities control basin evolution and thus determines the hydrocarbon generation and expulsion. [ABSTRACT FROM AUTHOR]

• Cambrian-Ordovician strata experienced rapid subsidence and heating in the Ordovician period. • Source rocks achieved a peak in hydrocarbon generation in the Devonian period. • Source rocks experienced a secondary hydrocarbon generation after the Jurassic. • The eastern Tarim Basin has hydrocarbon potential. The tectono-thermal evolution is an important control on petroliferous basin development; however, this evolution is difficult to reconstruct in sedimentary basins subjected to multiple tectono-thermal events. The Tarim Basin is the largest petroliferous basin in northwestern China and hosts a complex oil–gas system comprising several sets of source, reservoir, and cap rocks that have experienced multiple tectonic, thermal, and sedimentary events. Large oil and gas reserves have been discovered in the central and northern Tarim Basin during the last 30 years, but none in the eastern part of the basin. This is generally attributed to the high thermal maturity reached by source rocks during the Late Ordovician, and subsequent hydrocarbon loss. Therefore, reconstructing the Cambrian–Ordovician tectono-thermal evolution is critical in facilitating successful oil and gas exploration in this region. We compiled equivalent vitrinite reflectance data (n = 178) of source rocks from seven wells in the Tarim Basin, which for Cambrian–Ordovician source rocks are >1.3%, beyond the hydrocarbon generation threshold and in the main gas and dry gas generation stages. The Cambrian–Ordovician source rocks experienced rapid burial and heating during the Caledonian period, entered the hydrocarbon generation stage during the Middle–Late Ordovician, and reached peak hydrocarbon generation at the end-Caledonian period. They might have experienced secondary hydrocarbon generation after the Jurassic. Homogenization temperatures of fluid inclusions (n = 616) from wells GC4, LX1, MD1, and YD2 as well as the modeled thermal evolution reveal a main hydrocarbon generation event during the Caledonian period and a secondary event in the Yanshanian and Himalayan period in other wells (LX1, MD1, and YD2). Hercynian and Indosinian uplift and exhumation in the eastern Tarim Basin controlled the main structures, and faulting created favorable conditions for secondary hydrocarbon generation and migration at this time. Since the Yanshanian and Himalayan, the Tarim Basin has experienced further sedimentation and heating, and the tectono-thermal evolution might have been related to the formation of the Tibetan Plateau. In summary, our reconstruction of the tectono-thermal evolution of Cambrian–Ordovician strata and the hydrocarbon generation history of the Tarim Basin suggests that the eastern Tarim Basin may also have hydrocarbon generation potential and can guide future oil and gas exploration. [ABSTRACT FROM AUTHOR]

Evaporative loss of light hydrocarbons during shale core collection and sample preparation makes it challenging to characterize hydrocarbon retention and accurately evaluate petroleum resources in a shale layer with high thermal maturity. Here, semi-open system pyrolysis experiment was applied to investigate the evolution of hydrocarbon in shales during thermal maturation, using an immature lacustrine shale with total organic carbon (TOC) of 2.13 wt% from the Es 3 Member in Dongpu Depression, Bohai Bay Basin, China. Moreover, Ro measurement, solvent extraction, kinetic study, open-system pyrolysis, thermovaporization-gas chromatography (Tvap-GC) and pyrolysis-gas chromatography (Py-GC) were also conducted on the products from semi-open system pyrolysis experiments. Retained oil in shales consists of free oil (pyrolysis S1) and sorbed oil (involved in pyrolysis S2). A preponderance of sorbed oil retained in the studied lacustrine shale is observed, with its content reaching to more than 4 times larger than that of free oil at a given thermal maturity. As thermal maturity increases, molecular weights of n- alkanes in free oil show a more obvious reduction than sorbed oil. In addition, compared to sorbed oil, free oil is more likely to be retained at higher thermal maturity. Despite of the larger oil generation potential than gas of the immature shale sample, residual hydrocarbon generation potential of heated lacustrine shales is dominated by gaseous hydrocarbon, and consists of >90% of the potential losses before entering into gas window. Change of TOC in lacustrine shales, which roughly characterizes hydrocarbon generation process, is attributed to both the loss of hydrocarbon generation potential and the formation of pyrobitumen. Although hydrocarbon retention in shales is affected by many complex processes and is controlled by various factors, it can be virtually considered as a status when hydrocarbon generation, expulsion and retention during thermal maturation come to a balance. A "retention ratio (RR)" index is thus suggested in this study, based on experimental results from semi-open system and open-system pyrolysis. Application of RR in resource evaluation in a shale play is reasonable especially in high-mature shales, because evaporative loss of light hydrocarbon is considered in this method. • Sorbed hydrocarbon dominates retained hydrocarbons in lacustrine shales. • Oils in free phase tend to be retained at higher maturity than those in sorbed phase. • Compositional changes of free and sorbed oil follow different paths during thermal maturation. • Suggest an "RR" index to estimate retained hydrocarbon in shales. [ABSTRACT FROM AUTHOR]