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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 Pabdeh Formation represents organic matter enrichment in some oil fields, which can be considered a source rock. This study is based on the Rock–Eval, Iatroscan, and electron microscopy imaging results before and after heating the samples. We discovered this immature shale that undergoes burial and diagenesis, in which organic matter is converted into hydrocarbons. Primary migration is the process that transports hydrocarbons in the source rock. We investigated this phenomenon by developing a model that simulates hydrocarbon generation and fluid pressure during kerogen-to-hydrocarbon conversion. Microfractures initially formed at the tip/edge of kerogen and were filled with hydrocarbons, but as catagenesis progressed, the pressure caused by the volume increase of kerogen decreased due to hydrocarbon release. The transformation of solid kerogen into low-density bitumen/oil increased the pressure, leading to the development of damage zones in the source rock. The Pabdeh Formation's small porethroats hindered effective expulsion, causing an increase in pore fluid pressure inside the initial microfractures. The stress accumulated due to hydrocarbon production, reaching the rock's fracture strength, further contributed to damage zone development. During the expansion process, microfractures preferentially grew in low-strength pathways such as lithology changes, laminae boundaries, and pre-existing microfractures. When the porous pressure created by each kerogen overlapped, individual microfractures interconnected, forming a network of microfractures within the source rock. This research sheds light on the complex interplay between temperature, hydrocarbon generation, and the development of expulsion fractures in the Pabdeh Formation, providing valuable insights for understanding and optimizing hydrocarbon extraction in similar geological settings. [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]

Shale oil yield, movability, and reservoir brittleness are three factors that must be focused on for shale oil exploration and development. The yield and composition of hydrocarbons and mineral composition have changed significantly during diagenesis, affecting the yield and movability of shale oil and the brittleness of the rock. In this study, the source rocks at different depths in the Dongying Sag were subjected to hydrous pyrolysis, and the yield and composition of pyrolyzed hydrocarbons and mineral composition were systematically analyzed. The brittleness index (BEI), weighted average specific surface area (SSAWA), and polarity index (PI) have been established to quantitatively characterize the brittleness and adsorption capacity of rock as well as the mobility of shale oil. The results suggest that diagenetic evolution controls rocks' brittleness and adsorption capacity by changing their mineral composition. In the low-temperature stage, the mineral transformation is not obvious, and the BEI and SSAWA fluctuate in a small range. In the high-temperature stage, the rapid smectite illitization leads to an increase in the brittleness and a decrease in the adsorption capacity. In addition, the nonpolar components such as saturates and aromatics in the pyrolyzed hydrocarbons gradually increased with the increasing temperature, enhancing the mobility of the shale oil. Based on the three evaluation indexes of BEI, PI, and SSAWA, and combined with the changes in hydrocarbon yields during hydrous pyrolysis, we comparatively analyzed the differences in the mobility and yields of original soluble organic matter as well as pyrolyzed hydrocarbons of the source rocks at different depths. Based on the above results, it can be concluded that the shale in the depth range of 3300–3795 m is a favorable area for shale oil exploration and development in the study area. This work suggests that predicting the sweet spot for shale oil exploration and development requires more attention to the impact of diagenetic evolution on the composition of minerals and hydrocarbons. [ABSTRACT FROM AUTHOR]

Petroleum was the most-consumed energy source in the world during the past century. With the continuous global consumption of conventional oil, shale oil is known as a new growth point in oil production capacity. However, medium–low mature shale oil needs to be exploited after in situ conversion due to the higher viscosity of oil and the lower permeability of shale. This paper summarizes previous studies on the process of kerogen cracking to generate oil and gas, and the development of micropore structures and fractures in organic-rich shale formations during in situ conversion. The results show that the temperature of kerogen cracking to generate oil and gas is generally 300–450 °C during the oil shale in situ conversion process (ICP). In addition, a large number of microscale pores and fractures are formed in oil shale formation, which forms a connecting channel and improves the permeability of the oil shale formation. In addition, the principles and the latest technical scheme of ICP, namely, conduction heating, convection heating, reaction-heat heating, and radiation heating, are introduced in detail. Meanwhile, this paper discusses the influence of the heating mode, formation conditions, the distribution pattern of wells, and catalysts on the energy consumption of ICP technology in the process of oil shale in situ conversion. Lastly, a fine description of the hydrocarbon generation process of the target formation, the development of new and efficient catalysts, and the support of carbon capture and storage in depleted organic-rich shale formations after in situ conversion are important for improving the future engineering efficiency of ICP. [ABSTRACT FROM AUTHOR]

Affected by the complex mechanism of organic–inorganic interactions, the generation–retention–expulsion model of mixed siliciclastic–carbonate sediments is more complicated than that of common siliciclastic and carbonate shale deposited in lacustrine and marine environments. In this study, mixed siliciclastic–carbonate shale from Lucaogou Formation in Junggar Basin was selected for semi–closed hydrous pyrolysis experiments, and seven experiments were conducted from room temperature to 300, 325, 350, 375, 400, 450, and 500 °C, respectively. The quantities and chemical composition of oil, gases, and bitumen were comprehensively analyzed. The results show that the hydrocarbon generation stage of shale in Lucaogou Formation can be divided into kerogen cracking stage (300–350 °C), peak oil generation stage (350–400 °C), wet gas generation stage (400–450 °C), and gas secondary cracking stage (450–500 °C). The liquid hydrocarbon yield (oil + bitumen) reached the peak of 720.42 mg/g TOC at 400 °C. The saturate, aromatic, resin, and asphaltine percentages of bitumen were similar to those of crude oil collected from Lucaogou Formation, indicating that semi–closed pyrolysis could stimulate the natural hydrocarbon generation process. Lucaogou shale does not strictly follow the "sequential" reaction model of kerogen, which is described as kerogen firstly generating the intermediate products of heavy hydrocarbon compounds (NSOs) and NSOs then cracking to generate oil and gas. Indeed, the results of this study show that the generation of oil and gas was synchronous with that of NSOs and followed the "alternate pathway" mechanism during the initial pyrolysis stage. The hydrocarbon expulsion efficiency sharply increased from an average of 27% to 97% at 450 °C, meaning that the shale retained considerable amounts of oil below 450 °C. The producible oil reached the peak yield of 515.45 mg/g TOC at 400 °C and was synchronous with liquid hydrocarbons. Therefore, 400 °C is considered the most suitable temperature for fracturing technology. [ABSTRACT FROM AUTHOR]

Among the several existing geochemical methods in hydrocarbon exploration, the technique linking total organic carbon content (TOC) and Rock–Eval pyrolysis is most widely used, largely as a result of its capacity to rapidly provide vital information regarding the identification of source rocks and their defining characteristic, as well as thermal maturity levels and generative potentials. In this study, data from prospective source units within the southern depocenter of the Pletmos Sub-basin were analyzed using this geochemical method. Cutting samples from six wells in Block 11a were subjected to organic geochemical analysis to understand the occurring hydrocarbon scenario. Based on the results of the investigation, five notable source rock intervals of Kimmeridgian to Turonian ages were identified. The source rocks are shales with both indigenous and non-indigenous organic matter. Their TOC values show a fair to excellent petroleum generating potential, with the Aptian and Kimmeridgian intervals having the highest and lowest, respectively. The Hydrogen Index (HI), along with S2/S3 ratio values, typifies a predominance of mixed type II/III (oil/gas-prone) with some type III (gas-prone) and II (oil-prone) kerogens. The trends of the maturity parameters Tmax and Ro (vitrinite reflectance) indicate maturities ranging from immature to a late stage of maturity (dry gas window). Two observed breaks in the Ro profile reveal a possible link of maturity to high heat flow that is allied to sedimentation and tectonic uplift during the Late Cretaceous. Generally, based on TOC, S1, and HI, the petroleum potential trend increases with increasing depth, with a striking display of mixed hydrocarbon generating potential. Interpreted hydrocarbon typing is thus recommended to support the well-testing analysis. [ABSTRACT FROM AUTHOR]

In traditional kerogen pyrolysis experiments, the effects of minerals and rock fabric on the pyrolysis products were ignored. To further clarify the role of the mineral matrix and rock fabric on hydrocarbon generation and retention, a closed anhydrous pyrolysis experiment was conducted on core plugs, powdered rock and kerogen from a clay-rich sample of Maoming oil shale within a temperature range of 312 °C to 600 °C, at a fixed pressure of 30 Mpa. The experiment's results showed that the yields of heavy hydrocarbons (C14+) generated from the core plugs and powdered rock were obviously lower than that of kerogen, which may be caused by the retention effect of clay minerals in raw shale. The yields of gaseous hydrocarbons generated from core plugs were lower compared with powdered rock due to the retention of C2+ hydrocarbons by the intact rock fabric and the preferential generation of methane. Light hydrocarbon (C6-14) yields generated from the core plugs and powdered rock were higher than kerogen, which may be the consequence of the cleavage of extraction bitumen and the interactions with kerogen. Moreover, the ratios of iso to normal paraffin (iC4/nC4, iC5/nC5) of the core plugs and powdered rock were higher than kerogen. Our experimental results show that kerogen pyrolysis in a confined system may overestimate the hydrocarbon generation potential due to the negligence of the retention effect of minerals and the rock fabric, especially in the source rocks rich in clay minerals. [ABSTRACT FROM AUTHOR]

Lacustrine microcrystalline dolostones in the ancient records have been commonly interpreted as of an evaporitic origin, on the basis of their numerous occurrences in modern evaporative shallow lakes. This interpretation obscures the forming mechanisms of dolostones formed in a deep lacustrine setting, where dolostones interbedded with shale become a focus of hydrocarbon source rocks in recent years. In this study, an alternative non-evaporitic origin of dolomite is interpreted for a Permian lacustrine laminated dolostone. The dolostones are thinly intercalated with tuffaceous shales and composed mainly of volumetrically abundant, low-ordered, subhedral to euhedral, microcrystalline dolomites with a variable amount of pyroclastics. Evidence for evaporation (e.g., the presence of halite, gypsum and shrinkage cracks) and typical methanogenic microfossils is absent. Instead, our dolostones are unevenly and locally distributed as thin beds or lenses and intercalated with tuffaceous shale and have a formation temperature ranging from 31.4 to 73.8 °C, as estimated from dolomite clumped oxygen? isotope thermometry. In addition, the dolostones have a87Sr/86Sr ratio similar to that of the mantle (0.705154 on average) and extremely negative δ18O (−2.9‰ to −24‰) and positive δ13C (5.1‰–10.8‰) values. A lateral trend of increasing formation temperature of the dolostone toward the volcanic center correlates with the trends of: 1) an increasing amount of pyroclastics, euhedral dolomite crystals, Fe, and TOC, and an increasingly positive δEu value, and 2) decreasing values of 87Sr/86Sr and δ18O. The correlation suggests that a local temperature increase and frequent elemental (Fe and Mg) cycling between the conditions of dolomite supersaturation and undersaturation, which are controlled by episodic volcanic-hydrothermal activities are the causes for dolomite nucleation and growth, resulting in the formation of massive dolostone during deposition and shallow burial. The process also affected organic matter accumulation and local transformation to immature or early mature hydrocarbon during deposition and early burial. The results establish a volcanism-controlled temperature range for primary dolomite nucleation and growth, as well as hydrocarbon generation in a deep lake environment during the period of deposition and early burial, and provide insights on shale oil exploration in petroliferous rift basins. • Temperature (31.7 to 73.8 °C) for microcrystalline dolomite formation in a Permian lake was estimated using clumped isotope. • Relative high temperature and cycling super to undersaturation related subaqueous eruption induced dolomite growth. • Local and relatively high temperature played a critical role in enhancing transformation from organic matter to hydrocarbon. • Microcrystalline dolostones with a moderate to large amount of pyroclastic grains formed in a rift basin can be a oil target. • This research documented a deep lake formed dolostone, and provide insights on shale oil exploration in similar rift basin. [ABSTRACT FROM AUTHOR]

The Shahejie Formation (Fm) in the Bohai Bay Basin is well-known for its substantial conventional resource potential and long-term history of exploration. Shale oil has been confirmed as a sustainable resource following breakthroughs in shale exploration in the first and third members of the Paleogene Shahejie Fm (Mbr1 and Mbr3) in Qikou Sag, particularly Mbr3, which has a more desirable output. However, the limited distribution of exploration wells for shale oil around the southwest of Qikou Sag calls for a comprehensive evaluation of shale oil (or gas) potential in all of Qikou Sag. Here, we clarify the shale oil (or gas) resource potential and areas favorable for exploration in Mbr3 by using a hydrocarbon generation potential model (HGPM) based on the material balance method and the principle of hydrocarbon (HC) generation dynamics. Apart from the quantified characteristics of the oil generation process of Mbr3 source rocks, the source rocks of both Mbr1 and Mbr3 were compared to interpret the discrepancies in HC generation. The results show that Mbr3 source rocks have high-quality geological and geochemical features, a thickness of 1200 m, and adequate organic matter (1.66% TOC on average, dominated by kerogen II&III, and in the mature stage). The threshold of expulsion is Ro = 0.78%; correspondingly, HC generation potential (Qg), HC expulsion potential (Qe), and retention potential (Qr) are, at maximum, 605.89, 169.65, and 436.24 mg HC/g TOC. The intensity of HC generation (Ig), expulsion (Ie), retention (Ir), and effective retention (Ire) is focused on the main depression and the Qibei Sub-sag and can reach as high as 250 × 104, 65 × 104, 170 × 104, and 110 × 104 t/km2, respectively. The resource potential for the retention of shale was calculated to be 13.3 × 108 t (movable shale oil and gas 8.0 × 108 t), and conventional and tight oil or gas resources were calculated to be 4.7 × 108 t (equivalent oil resources). Favorable exploration targets are spread around the main depression and the Qibei Sub-sag. There are disparities in the thermal process and thermal generation, and expulsion features between Mbr1 and Mbr3 source rocks are derived from kerogen-type and non-isolated deposit environments. Thus, a quantitative, advanced evaluation and a comparison offer more precise exploration predictions of shale in this Fm and further boost the low-risk exploration process. [ABSTRACT FROM AUTHOR]

Conventional and tight unconventional oil and gas resources in the Huizhou Depression have shown broad exploration prospects, which mainly originate fromWenchang Formation source rocks. Thus far, studies on Wenchang Formation source rocks mainly focused on the geochemical characteristics and conventional petroleum resource evaluation; however, the correlation of conventional, tight, and shale oil and gas, and their resources are still unknown. In fact, the formation of conventional, tight, and shale oil and gas are intrinsically related, which allows for a more objective evaluation to consider the three types of oil and gas resources simultaneously in the whole dynamic process of both hydrocarbon generation and expulsion, as well as reservoir tightness history. In this work, based on geological and geochemical analyses, the improved hydrocarbon generation potential method was utilized to establish a hydrocarbon generation and expulsion model of the Wenchang Formation source rocks. Then, combined with the reservoir tightness history, the conventional, tight, and shale oil and gas resources were evaluated. The results show that the Wenchang Formation source rocks are distributed in the whole depressions, with a thickness of 50-1850 m and an average total organic carbon content of 2.2%. The organic matter is mainly type II and is mature-high maturity. The Wenchang Formation source rocks reached hydrocarbon generation threshold and expulsion threshold at a vitrinite reflectivity of 0.43% and 0.65%, respectively, and the reservoir evolved completely tight at 2.3 Ma. Overall, the Lower and Upper Wenchang Formation contain a large amount of conventional, tight, and shale oil and gas resources. [ABSTRACT FROM AUTHOR]

In situ mining is a practical and feasible technology for extracting oil shale. However, the extracted oil shale is subject to formation stress. This study systematically investigates the pyrolysis–mechanics–seepage problems of oil shale exploitation, which are subject to thermomechanical coupling using a thermal simulation experimental device representing a closed system, high-temperature rock mechanics testing system, and high-temperature triaxial permeability testing device. The results reveal the following. (i) The yield of gaseous hydrocarbon in the closed system increases throughout the pyrolysis reaction. Due to secondary cracking, the production of light and heavy hydrocarbon components first increases, and then decreases during the pyrolysis reaction. The parallel first-order reaction kinetic model shows a good fit with the pyrolysis and hydrocarbon generation processes of oil shale. With increasing temperature, the hydrocarbon generation conversion rate gradually increases, and the uniaxial compressive strength of oil shale was found to initially decrease and then increase. The compressive strength was the lowest at 400 °C, and the conversion rate of hydrocarbon formation gradually increased. The transformation of kaolinite into metakaolinite at high temperatures is the primary reason for the increase in compressive strength of oil shale at 400–600 °C. (ii) When the temperature is between 20 and 400 °C, the magnitude of oil shale permeability under stress is small (~10−2 md). When the temperature exceeds 400 °C, the permeability of the oil shale is large, and it decreases approximately linearly with increasing pore pressure, which is attributed to the joint action of the gas slippage effect, adsorption effect, and effective stress. The results of this research provide a basis for high efficiency in situ exploitation of oil shale. [ABSTRACT FROM AUTHOR]

In this study, the hydrocarbon generation of 1–4 cm sized shale in supercritical water (SCW) was investigated. The results showed that temperature was the most important factor affecting the hydrocarbon generation of organic-rich shale in the presence of supercritical water. In the temperature range of 380–450 °C, the optimum oil generation temperature was 430 °C. The produced oil component became heavier with increasing temperature. Increasing temperature was beneficial to gas production and improved the selectivity of H2 and CH4. In the pressure range of 22.5–27.5 MPa, oil and gas production decreased with increasing pressure. The influence of pressure on conversion path was almost negligible. Pressure affected the hydrocarbon generation of shale in supercritical water by affecting hydrocarbon expulsion. In the water-shale mass ratio range of 0.5–5 and the reaction time range of 1–12 h, increasing both parameter ranges was conducive to the hydrocarbon generation of oil shale. The selectivity of H2 increased and that of CH4 and CO2 decreased with increasing water-shale mass ratio. The selectivity of CH4 and C2H6 increased with increasing reaction time. [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]

As a typical lacustrine shale oil, Gulong shale oil has enormous resource potential. The current lack of understanding regarding the formation process of this oil has affected its development. This study uses a low-mature shale sample from the first member of the Qingshankou Formation in the Songliao Basin and analyzes the hydrocarbon generation, expulsion, and retention characteristics by conducting hydrous pyrolysis in a semiclosed system. The results show that the formation process of the Gulong shale oil can be divided into three stages. The slow hydrocarbon generation stage occurs when organic matter maturity (Ro) < 0.8 %, and only a small amount of hydrocarbons is generated by kerogen cracking. The products are mainly heavy components (C 15+), with retained oil composing the majority of them. The rapid oil generation stage occurs when Ro is of 0.8 %–1.1 %, where a large amount of kerogen is cracked to generate hydrocarbons and reaches its peak when Ro is 1.1 %. Most of generated light component oil (C 6 –C 14) is expelled, and retained oil is mostly composed of heavy components (C 15+); Ro > 1.1 % indicates the stage of oil cracking and rapid gas generation. Light component oil (C 6 –C 14) and gaseous hydrocarbons (C 1 –C 5) are formed when heavy components oil (C 15+) begins to crack. The light-to-heavy ratio of the hydrocarbon products (C 1 –C 14 /C 15+) rapidly increases with maturity. The hydrous pyrolysis experiment in a semiclosed system is more in line with actual geological conditions of Qingshankou Formation compared to other experimental systems and can simultaneously consider the influence of geological factors such as temperature, pressure, hydrocarbon expulsion, and formation water. • The formation process of the Gulong shale oil can be divided into three stages. • Hydrocarbon generation peak of the Qingshankou Formation shale occurs when Ro is 1.1 %. • Hydrous pyrolysis experiment in semiclosed system is more in line with actual geological conditions. [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]

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]

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Abstract The Upper Triassic Chang 7 Shale and the Mississippian Barnett Shale, two remarkable shale systems that are considered promising unconventional shale oil/gas targets in China and the USA, respectively, have different kerogen types that formed under lacustrine and marine environments. In this study, seventy-six and ninety-seven drilled core samples were collected separately from the Zhang 22 Well (Ordos Basin) and the Mesquite #1 well (Fort Worth Basin), respectively, for determining the hydrocarbon generation, retention and migration behaviors as well as the intrasource fractionation in the two shale successions. Geochemical indications of potentially producible oil as indicated by the oil crossover effect and the T max shift phenomenon as well as the geochemical and molecular compositions of retained hydrocarbon suggest two categories of intervals in the Chang 7 and Barnett shale systems, namely, the "in-source sweet spot" and the "generative unit". Oils retained in the "in-source sweet spot" have migrated from the adjacent "generative unit" and have been subjected to stratigraphic fractionation over geological time. These oils are proportionally rich in aliphatic fraction and moderate chain length moieties, which significantly improve the fluid mobility and producibility. The oil quality improved by fractionation, the weak adsorptive affinity of oil to organic matter, and the good shale frackability all provide promise for the exploration and production potential of shale oil from the Chang 7 and the Barnett Shale systems. Highlights • 76 and 97 samples are collected from Zhang 22 well in Ordos Basin and Mesquite #1 well in Fort Worth Basin. • They are analyzed in the same laboratory to compare the differences and similarities in hydrocarbon retention. • "Generated units" and "in-source sweet spots" are identified using geochemical approach. • Oils in "in-source sweet spots" contain more mobile fractions which increase shale oil productivity. • "In-source sweet spots" are promising targets for shale oil exploitation from a geochemical perspective. [ABSTRACT FROM AUTHOR]

The last decade witnessed rapid growth of shale oil and gas production. Increasing numbers of shale reservoirs have been explored and developed. Since hydrocarbon generation is an important process in forming a shale reservoir, it has attracted great attention from researchers. However, previous works mainly focus on geochemical changes during the hydrocarbon generation process, and investigations of the change of other parameters are insufficient. In this study, we intend to fill this gap in the literature by examining the mechanical properties evolution of organic-rich shales during an artificial hydrocarbon generation experiment. Continuous stiffness measurement (CSM) and microindentation test are used to measure the mechanical properties of rocks. The result of CSM shows the influence of indentation depth on Young's modulus. Three stages are identified, and a displacement of 4000 nm–6000 nm is determined to be appropriate for measuring bulk mechanical properties. Microindentation results of shales at different hydrocarbon generation stages exhibit a hill-like trend. The Young's modulus with an initial value of 42.15 GPa increases as the hydrocarbon generation proceeds, reaches a maximum value of 46.49 GPa, and then begins to decrease and reaches the lowest value of 37.41 GPa. Indentation hardness and estimated fracture toughness by an energy-based method show similar trends to Young's modulus. Scanning electron microscope observation of post-hydrocarbon-generation samples may provide an explanation of the hill-like trend. • Young's modulus variation with displacement can be identified as three stages. • Young's modulus exhibits a hill-like trend as hydrocarbon-generation proceeds. • Relationships between Young's modulus, indentation hardness and fracture toughness are explored. [ABSTRACT FROM AUTHOR]

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 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]