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The discovery of Bozhong 19-6 gas field has opened up a new field of deep gas exploration in Bohai Bay basin, showing great potential for gas exploration in oil-type basins. Taking Bozhong 19-6 gas field in Bohai Bay Basin as an example, takes source rock as the research object, clarifies the characteristics of source rock in Bozhong 19-6 structural belt, studies the relationship between organic and inorganic. The results show that: The clay minerals in Bozhong 19-6 structural belt are dominated by illite. A large number of humic amorphous bodies are enriched on the surface of clay minerals through physical adsorption and chemical bonding, and hydrogenation is carried out. In the later period, under the influence of illite, the source rock mainly undergoes decarboxylation reaction, and a large number of short-chain hydrocarbons are generated by thermal decomposition. The condensed oil and gas formed by accumulation are obviously controlled by the source rocks, inheriting the characteristics of higher plants, showing the characteristics of partial humic type. Under the action of illite, hydrocarbon production increased greatly and then enriched to form the characteristics of the wide distribution of condensate oil and gas. [ABSTRACT FROM AUTHOR]

Overpressure is widely developed in deep petroliferous strata in the hinterland of the Junggar Basin. However, a comprehensive understanding of its origin and effect on hydrocarbon distribution and enrichment remains lacking. In this study, we employ five empirical methods and comprehensive geological analysis to identify the origin of overpressure, and uncover the effect of overpressure on hydrocarbon enrichment. The results indicate that disequilibrium compaction is not a significant factor in overpressure generation. Instead, hydrocarbon generation, pressure transfer and diagenesis are the primary causes. The empirical methods support this conclusion. There is a positive correlation between overpressure intensity and source rock thickness and maturity. Notably, widespread cross‐formational migration of hydrocarbon bearing fluid occurred, with sandstone overpressure exceeding that of adjacent shale in non‐source strata. Furthermore, there is a distinct transformation from smectite to illite near the top of overpressure. Hydrocarbon generation pressurization and pressure transfer significantly effect hydrocarbon enrichment. The overpressure caused by hydrocarbon generation drives hydrocarbon migration and accumulation, establishing an optimal energy configuration between reservoir and cap rock. Faults play a crucial role in hydrocarbon vertical migration and pressure relief. The overpressure in reservoirs can reduce the porosity and permeability thresholds and enhance the charging capacity of oil and gas. [ABSTRACT FROM AUTHOR]

The assessment of highly mature source rocks linked to hydrocarbon generation remains a challenge in oil and gas exploration. However, substantial terrigenous influences and thermal variations have complicated the formation and evolution of source rocks. This study presents an integrated assessment of highly mature source rocks in the Fuxin Basin, based on sedimentological, geochemical, and organic petrological analyses. Two types of oil- and coal-bearing source rocks were deposited in the semi-deep lake and shore–shallow lake facies during the Jiufotang and Shahai periods. The development of source rocks migrated eastward alongside the lacustrine depocenter, influenced by basin evolution related to extensional detachment tectonism. Furthermore, a gradual increase in thermal records was detected from the western to eastern basins. Consequently, thermal decomposition of source rocks in the Jiufotang formation reduced the organic matter (OM) abundance in the central and eastern basins. Meanwhile, OM types of source rocks range from kerogen type-II1/-I to type-II2/-III, with intense hydrogen generation observed from the western to eastern basins. Consequently, the quality and hydrocarbon accumulation of source rocks are influenced by sedimentation and thermal maturity variation. The spatiotemporal variation in mature source rocks enhances the potential for exploring conventional petroleum, coalbed methane, and shale gas across different strata and locations. Our findings illustrate the significance of the sedimentary and thermal effects in characterizing the evolution of highly mature source rocks, which is relevant to determine oil and gas exploration in similar geological settings. [ABSTRACT FROM AUTHOR]

How gabbro affects the generation and expulsion of hydrocarbons in muddy surrounding rocks is clarified by analyzing thin section, major and trace elements, total organic carbon (TOC), pyrolysis, extracts and vitrinite reflectance data from source rocks in the Chunxi area the Dongying Sag, Bohai Bay Basin, eastern China. The results show that a magma intrusion brings copious heat to the source rocks, which promotes abnormal maturation of organic matter (OM) and rapid hydrocarbon generation. The CH4 and H2 produced by gabbro alteration play a role in hydrocarbon generation of source rocks. The hydrothermal process during magma intrusion provides many different minerals to the source rock, resulting in carbonate‐rich surrounding mudstone. The carbonate and clay minerals produced by volcanic mineral alteration jointly catalyze the hydrocarbon generation of the source rock. The high‐temperature baking of the intrusion results in hydrothermal pressurization and hydrocarbon generation pressurization, causing many fractures in the surrounding rock. The generated oil and gas are discharged through the fractures under diffusion and pressure. Mantle‐derived CO2 is also conducive to the expulsion of hydrocarbons because of its strong enrichment capacity for hydrocarbons. [ABSTRACT FROM AUTHOR]

Pyrolysis of organic matter with subsequent analysis of hydrocarbon composition of the resulting products allows obtaining multicomponent distribution spectra of the generation potential by the activation energies of reactions of kerogen transformation into hydrocarbons. Configuration of the spectra depends on the structure of kerogen and is individual for each type of organic matter. Studies of kerogen kinetics showed that the distribution of activation energies is unique for each oil source rocks. The kinetic model of thermal decomposition of kerogen of the same type, for example, marine planktonic (type II), can differ significantly in different sedimentary basins due to the multivariate relationship of chemical bonds and their reaction energy threshold. The developed method for calculating multicomponent kinetic spectra (four-component models are used) based on results of pyrolysis gas chromatography allows obtaining one of the most important elements of modelling the history of oil and gas generation in geological basins. Kinetic parameters of organic matter of oil and gas source rocks influence the onset time of generation and directly reflect differences in the composition and structure of different types of kerogens. The results of determining the kinetic parameters of two high-carbon source rocks occurring across the territory of three oil and gas basins are shown. Generation and updating of the data of kinetic models of certain oil and gas source rocks will increase the reliability of forecasting oil and gas potential using the basin modelling method.

Abstract This study investigates the hydrocarbon generation potential of Jurassic source rocks under ultradeep conditions by utilizing semiclosed system hydrous pyrolysis experiments to simulate the geological processes at play. This study examines four distinct lithologies (shale, mudstone, carbonaceous mudstone, and coal) and three kerogen types (I, II, and III) across a temperature range of 250–650 °C and fluid pressures ranging from 34 to 100 MPa. The results indicate a bimodal distribution in total oil yields, with peak generation observed at approximately 350 °C and 600 °C. This pattern suggests a complex relationship between temperature, pressure, kerogen type, and hydrocarbon output. Notably, while I-Shale and II-Mudstone display higher hydrocarbon efficiency, III-type rocks exhibit superior oil and gas production rates because of their higher total organic carbon content. Research revealed that the oil expulsion rate exceeds 99% at temperatures above 500 °C, with the expelled oil predominantly comprising nonhydrocarbons and asphaltenes. Our findings suggest that Jurassic hydrocarbon source rocks maintain oil and gas potential under ultradeep conditions (high-over maturity stages at depths exceeding 6000 m). Under sustained fluid overpressure exceeding 70 MPa, the hydrocarbon generation peaks of various kerogen types in source rocks are markedly delayed. This phenomenon enables the source rocks to retain the potential for liquid hydrocarbon generation even during the stages of overmaturity. The results significantly enhance the theoretical framework of hydrocarbon generation under ultradeep conditions, thereby providing a crucial extension to the existing thermal boundary theory of hydrocarbon formation. These insights are crucial for the oil and gas industry, directing future exploration efforts towards ultradeep reservoirs and informing the development of new technologies to exploit these resources. This research not only enhances the understanding of subsurface hydrocarbon systems but also has implications for strategies aimed at maximizing resource recovery and managing the environmental impact of deep Earth exploration.

In this study, a non-isothermal heating reactor was used to simulate the hydrocarbon generation process of 1â4 cm sized medium- and low-maturity organic-rich shale under the action of supercritical water. The results show that the increase in pressure had a negative effect on the utilization of organic carbon in shale. As the pressure increased, the overall conversion efficiency of organic carbon decreased. Although higher pressure inhibited both oil and gas production, the inhibition of the gas production process was more significant. The effect of reaction time on oil and gas production differed in stages. Over a 4-h reaction period, the oil and gas production rates gradually increased with longer reaction times, with oil production showing a stronger promotion effect. Beyond 4 h, further extension of reaction time mainly promoted gas production. The increase in pressure and reaction time had opposite effects on the pore structure parameters of shale. Higher pressure led to a decrease in these parameters, while longer reaction times resulted in improved and expanded parameters.

Situated between the petroliferous Cenozoic Zhujiang (Pearl) River Mouth Basin and the mud volcano-rich Mesozoic Dongsha Basin in the middle sector of the northern South China Sea, the Weitan Banks area has been previously mapped as a basement high that is composed of Mesozoic magmatic rocks. In this study, we present several favorable indicators for petroleum geology that were detected from geophysical profiling and benthic sampling in the area. A conspicuous hill was discovered, named "Zhongwei Hill", ∼80 m high above the ∼340 m deep seafloor and ∼1 km broad, in a depression with more than 7 km thick sedimentary strata. The Zhongwei Hill was seismically imaged with a mushroom-shaped structure and containing a cake-like crown, fluid flow pipes, and an ∼10 km broad anticline at depth. Thus, the hill represents a source-plumbing-eruption system. Shallow gas zones linked to deep fracture were found at or near the hill. Stratigraphic correlation indicates that the deep strata comprise the Jurassic and Paleogene strata, the major hosts of hydrocarbon source rocks. In addition to the hill, there are number of mounds from which three bottom water samples were collected and the samples are rich in dissolved methane with concentrations high up to ∼900 nmol/L, much higher than the background level (0.5–2 nmol/L). The benthic samples are rich in coarse sediment clastics, authigenic carbonate nodules, and deep-water habitats likely feeding on methanotrophic community. Given these observations and the context, we propose that the Zhongwei Hill represents a mud volcano, likely thermally driven, that seeps methane from Jurassic and Paleogene source layers, thus poses a favorable clue for significant hydrocarbon generation capacity in transitional zone of the Zhujiang River Mouth Basin and the Dongsha Basin. [ABSTRACT FROM AUTHOR]

The Myanmar region experienced the subduction of the Indian Ocean plate to the West Burma block and suffered from the land–land collision between the Indian continent and the West Burma block that occurred from the Late Cretaceous to the Cenozoic. Its tectonic evolution has been complex; thus, oil and gas exploration is difficult, and the overall degree of research has been low. 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 2D MOVE and Petro-Mod software 2017 for a complex tectonic section in the Northern Central Myanmar Basin. The results show that the maturity threshold depth of the Cretaceous source rocks in the study area is shallow, and the underground depth of 1200 m to 1400 m has reached the hydrocarbon generation threshold, indicating the start of hydrocarbon generation. Since 48 Ma, the Ro of the source rocks has reached 0.7%, became mature quite early. The Late Cretaceous Paleocene and Eocene formation, located in the southeastern part of the study area, migrated and accumulated hydrocarbons towards the western arc zone in the Eocene and Miocene, respectively. It is worth noting that although the oil and gas potential of each layer in the island arc uplift zone is relatively low, which is conducive to the migration and accumulation of oil and gas generated by the source rocks of the depression towards the island arc zone, shallow areas with developed extensional faults should be avoided. This study is the first to conduct a preliminary assessment and prediction of oil and gas resources, which will provide exploration guidance and reference for the study area and its surrounding areas in the future. [ABSTRACT FROM AUTHOR]

In this research, we compared thermochronological and traditional one-dimensional thermal models across the Middle Magdalena Valley (MMV), Eastern Cordillera, and Eastern Llanos Basins in Colombia. These models allow us to relate cooling/heating histories to exhumation events, subsidence, fault activities, and fluid flow. The Eastern Cordillera and Eastern Llanos Basins are discriminated as prospective zones for hydrocarbon (HC) generation. The De Armas Syncline at the MMV basin shows high thermal maturity (127°C), describing rocks completely depleted in terms of HC generation. The eastern zone of this syncline is buried until it reaches temperatures above 150°C. The contrast between thermal models in the Eastern Cordillera basin suggests a possible sediment supply scenario from the west to the east of the Soapaga Fault. In the Eastern Llanos basin, the thermal histories between both models explain the latest uplift and sediment supply processes from the hinterland zone of the Eastern Cordillera to the foothill zone of the Eastern Llanos basin. In terms of thermal evolution, the three basins are different, reaching different levels of burial and HC maturity. However, in terms of cooling events related to exhumation, the basins have similarities as they are controlled by the mountain building of the Eastern Cordillera of Colombia.

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]

Overpressure is always considered as a severe problem in the oil industry. Besides creating life risks through serious accidents while drilling, failure to correctly identify high-pressure intervals causes a significant increase in costs and prolongs the drilling process. Kazhdumi Formation in the Abadan Plain is considered as a high-pressure formation in several wells. Various reasons can cause overpressure problem. Hydrocarbon generation is one cause of abnormal pressure in source rocks. Understanding hydrocarbon generation potential can be a helpful approach since the Kazhdumi Formation is considered as a probable source rock in this area. In this paper, in order to better understand the problem of abnormal pressure in Kazhdumi Formation, geochemical concepts and tools have been applied. To that way, 1D petroleum system modeling of five wells was done, and the thermal maturity level of Kazhdumi Formation was determined and then, compared with drilling records. The results indicate that in wells where this formation has sufficient organic matter and has reached an early mature level, there is an abnormal pressure problem. Otherwise, this formation does not show abnormal pressure. Also, geochemical data are not available in all drilled wells, which makes impossible the assessing of hydrocarbon generation role. Therefore, petrophysical well logs (sonic (DT), neutron (NPHI), density (RHOB), spectral gamma ray (SGR), and resistivity (RES)) as well as 137 sets of geochemical data belonging to 13 wells from 7 oilfields in the Abadan Plain were used to predict geochemical indicators. Using artificial neural networks, geochemical data of a well in Abadan Plain were predicted. This selected well has a high-pressure problem in Kazhdumi Formation, but no geochemical data are available in this well. The results of predicted geochemical data show that the high-pressure phenomenon in this well may also be due to hydrocarbon generation. The precise understanding of the abnormal pressure, resulting from hydrocarbons generation, requires comprehensive studies and a full investigation of the studied area. However, the results of this paper help to predict approximately the behavior of the source rocks before drilling. Acquiring this overview will aid in reducing drilling hazards and costs. [ABSTRACT FROM AUTHOR]

A comprehensive understanding of the characteristics and mechanisms underlying hydrocarbon generation from organic matter has emerged as a pivotal challenge in deciphering the "life mystery" of oil and gas, thereby guiding strategic planning for the global petroleum industry. The swift advancements in materials science, drilling engineering, computer technology, big data, and artificial intelligence have furnished robust methodologies and tools for research into organic hydrocarbon generation. This perspective offers an analysis and synthesis of three distinct research paradigms pertinent to organic hydrocarbon generation: Theoretical analysis, experimental exploration, and numerical simulation. These three research modalities probe the mechanisms of organic hydrocarbon generation across varied scales, with their findings mutually reinforcing and validating each other. This synergy provides invaluable insights that contribute to a holistic understanding of organic hydrocarbon generation, facilitating a comprehensive assessment of the potential of subterranean oil and gas resources. [ABSTRACT FROM AUTHOR]

Jiaojiang sag in the East China Sea Basin is at the earlier exploration stage, where characterizing hydrocarbon generation of source rocks is important to understand oil-gas exploration potential. Utilizing geochemical and basin modeling analysis, hydrocarbon generation capacity and process of the Paleocene E1y, E1l and E1m formations were investigated. Results show that E1y and E1l mudstones are high-quality source rocks with Type II kerogen, which is dominated by both aquatic organisms and terrestrial higher plants deposited in sub-reduced environment. E1m mudstone interbedded with thin carbonaceous mudstone and coal is poor-quality source rock with Type III kerogen, whose organic matter was originated from terrestrial higher plants under oxidized environment. Controlled by burial and maturity histories, E1y and E1l source rocks experienced two hydrocarbon generation stages, which took place in the Late Paleocene and in the Middle to Late Eocene, respectively, and had high hydrocarbon generation capacity with cumulative hydrocarbon volume of 363 and 328 mg/g, respectively. E1m source rock only had one hydrocarbon generation process in the Late Eocene, which had low hydrocarbon generation capacity with cumulative hydrocarbon volume of only 24 mg/g. The future oil-gas exploration in the Jiaojiang sag should focus on hydrocarbon generation center and select targets in the central uplift formed before the Miocene with high-quality traps. [ABSTRACT FROM AUTHOR]

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Abstract Overpressure is always considered as a severe problem in the oil industry. Besides creating life risks through serious accidents while drilling, failure to correctly identify high-pressure intervals causes a significant increase in costs and prolongs the drilling process. Kazhdumi Formation in the Abadan Plain is considered as a high-pressure formation in several wells. Various reasons can cause overpressure problem. Hydrocarbon generation is one cause of abnormal pressure in source rocks. Understanding hydrocarbon generation potential can be a helpful approach since the Kazhdumi Formation is considered as a probable source rock in this area. In this paper, in order to better understand the problem of abnormal pressure in Kazhdumi Formation, geochemical concepts and tools have been applied. To that way, 1D petroleum system modeling of five wells was done, and the thermal maturity level of Kazhdumi Formation was determined and then, compared with drilling records. The results indicate that in wells where this formation has sufficient organic matter and has reached an early mature level, there is an abnormal pressure problem. Otherwise, this formation does not show abnormal pressure. Also, geochemical data are not available in all drilled wells, which makes impossible the assessing of hydrocarbon generation role. Therefore, petrophysical well logs (sonic (DT), neutron (NPHI), density (RHOB), spectral gamma ray (SGR), and resistivity (RES)) as well as 137 sets of geochemical data belonging to 13 wells from 7 oilfields in the Abadan Plain were used to predict geochemical indicators. Using artificial neural networks, geochemical data of a well in Abadan Plain were predicted. This selected well has a high-pressure problem in Kazhdumi Formation, but no geochemical data are available in this well. The results of predicted geochemical data show that the high-pressure phenomenon in this well may also be due to hydrocarbon generation. The precise understanding of the abnormal pressure, resulting from hydrocarbons generation, requires comprehensive studies and a full investigation of the studied area. However, the results of this paper help to predict approximately the behavior of the source rocks before drilling. Acquiring this overview will aid in reducing drilling hazards and costs.

Abstract 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.

The assessment of highly mature source rocks linked to hydrocarbon generation remains a challenge in oil and gas exploration. However, substantial terrigenous influences and thermal variations have complicated the formation and evolution of source rocks. This study presents an integrated assessment of highly mature source rocks in the Fuxin Basin, based on sedimentological, geochemical, and organic petrological analyses. Two types of oil- and coal-bearing source rocks were deposited in the semi-deep lake and shore–shallow lake facies during the Jiufotang and Shahai periods. The development of source rocks migrated eastward alongside the lacustrine depocenter, influenced by basin evolution related to extensional detachment tectonism. Furthermore, a gradual increase in thermal records was detected from the western to eastern basins. Consequently, thermal decomposition of source rocks in the Jiufotang formation reduced the organic matter (OM) abundance in the central and eastern basins. Meanwhile, OM types of source rocks range from kerogen type-II1/-I to type-II2/-III, with intense hydrogen generation observed from the western to eastern basins. Consequently, the quality and hydrocarbon accumulation of source rocks are influenced by sedimentation and thermal maturity variation. The spatiotemporal variation in mature source rocks enhances the potential for exploring conventional petroleum, coalbed methane, and shale gas across different strata and locations. Our findings illustrate the significance of the sedimentary and thermal effects in characterizing the evolution of highly mature source rocks, which is relevant to determine oil and gas exploration in similar geological settings.

The Yingen–Ejina Basin (YEB) located in the western part of the North China Plate is a significant area for petroleum exploration. During the Early Cretaceous, the YEB witnessed the extensive development of source rocks. However, the subsequent tectonic evolution and multi‐stage thermal history of these source rocks have posed challenges to oil and gas exploration in the basin. This study focuses on the Mesozoic and Cenozoic tectonic evolution of the YEB, utilizing Apatite fission track (AFT) and vitrinite reflectance (Ro) data of samples from Well BC‐1 in the Suhongtu Depression, northern YEB. The central ages of six AFT samples ranged from 28 ± 2 to 49 ± 3 Ma with corresponding track lengths between 10.8 ± 1.9 and 12.3 ± 1.5 μm. Combining with the study of Ro and thermal history simulation, the thermal history of the YEB is summarized as follows: In the late Early Cretaceous, the study area experienced tectonic elevation, as evidenced by the discontinuous change in Ro values along the vertical column. Towards the end of the Late Cretaceous, there was a subsidence in the study area. The Ro data indicate that the Early Cretaceous source rocks, although experiencing several tectonic uplifts, had remained within the hydrocarbon generation temperature range, and reached the maximum thermal uplifts before the end of the Late Cretaceous. Therefore, hydrocarbon generation from early Cretaceous source rocks is an important exploration target in the study area and will be the focus of oil and gas exploration in the future. [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]

A new approach is presented in this paper for the dynamic modeling of the chemical and isotopic evolution of C1–3 during the hydrocarbon generation process. Based on systematic data obtained from published papers for the pyrolysis of various hydrocarbon sources (type I kerogen/source rock, type II kerogen/source rock, type III kerogen/source rock, crude oil, and asphalt, etc.), the empirical evolution framework of the chemical and isotopic composition of C1–3 during the hydrocarbon generation process was built. Although the empirical framework was built only by fitting a large amount of pyrolysis data, the chemical and isotopic composition of C1–3 derived from the pyrolysis experiments all follow evolution laws, convincing us that it is applicable to the thermal evolution process of various hydrocarbon sources. Based on the simplified formula of the isotopic composition of mixed natural gas at different maturities (δ13Cmixed), δ13Cmixed = X × n i A × δ 13 C i A + Y × n i B × δ 13 C i B X × n i A + Y × n i B , it can be derived that the cumulative isotopic composition of alkane generated in a certain maturity interval can be expressed by the integral of the product of the instantaneous isotopic composition and instantaneous yield at a certain maturity point, and then divided by the cumulative yield of alkane generated in the corresponding maturity interval. Thus, the cumulative isotopic composition (A(X)), cumulative yield (B(X)), instantaneous isotope (C(X)), and instantaneous yield (D(x)) in the dynamic model, comply with the following formula during the maturity interval of (X0~X). A(X) = ∫ X 0 X C X × D X d x B (X) , where A(X) and B(X) can be obtained by the fitting of pyrolysis data, and D(x) can also be obtained from the derivation of B(X). The dynamic model was applied on the pyrolysis data of Pingliang Shale to illustrate the quantitative evolution of the cumulative yield, instantaneous yield, cumulative isotope, and instantaneous isotope of C1–3 with increasing maturity. The dynamic model can quantify the yield of methane, ethane, and propane, as well as δ13C1, δ13C2, and δ13C3, respectively, during the hydrocarbon generation process. This model is of great significance for evaluating the natural gas resources of hydrocarbon source rock of different maturities and for identifying the origin and evolutionary process of hydrocarbons by chemical and isotopic data. Moreover, this model provides an approach to study the dynamic evolution of the isotope series of C1–3 (including reversed isotopic series), which is promising for revealing the mechanism responsible for isotopic reversal when combined with post-generation studies. [ABSTRACT FROM AUTHOR]

The Myanmar region experienced the subduction of the Indian Ocean plate to the West Burma block and suffered from the land–land collision between the Indian continent and the West Burma block that occurred from the Late Cretaceous to the Cenozoic. Its tectonic evolution has been complex; thus, oil and gas exploration is difficult, and the overall degree of research has been low. 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 2D MOVE and Petro-Mod software 2017 for a complex tectonic section in the Northern Central Myanmar Basin. The results show that the maturity threshold depth of the Cretaceous source rocks in the study area is shallow, and the underground depth of 1200 m to 1400 m has reached the hydrocarbon generation threshold, indicating the start of hydrocarbon generation. Since 48 Ma, the Ro of the source rocks has reached 0.7%, became mature quite early. The Late Cretaceous Paleocene and Eocene formation, located in the southeastern part of the study area, migrated and accumulated hydrocarbons towards the western arc zone in the Eocene and Miocene, respectively. It is worth noting that although the oil and gas potential of each layer in the island arc uplift zone is relatively low, which is conducive to the migration and accumulation of oil and gas generated by the source rocks of the depression towards the island arc zone, shallow areas with developed extensional faults should be avoided. This study is the first to conduct a preliminary assessment and prediction of oil and gas resources, which will provide exploration guidance and reference for the study area and its surrounding areas in the future.

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]

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]

Water, in ultra-deep layers of the earth and in layers receiving abnormally high heat, can exist in a supercritical state. Supercritical water (SCW) can participate in the transformations of organic compounds not only as a solvent but also as a reactant, influencing petroleum formation and the evolution of sedimentary organic matter. Here, we carried out hydrous pyrolysis experiments in both SCW and water vapor (WV) using two organic-rich marine rocks under closed conditions, to quantitatively evaluate the generation potential of hydrocarbons in a supercritical state and to clarify the effect of water phase on hydrous pyrolysis experiments. The results showed that SCW promoted gaseous and liquid hydrocarbon generation and facilitated the cracking of aliphatic hydrocarbons. For gaseous hydrocarbons, the action of SCW became stronger as the temperature increased. For liquid hydrocarbons, the peak yields of bitumen were enhanced by the SCW, and the temperature corresponding to peak yield in SCW was lower than that in WV. These results were attributed to the supply of hydrogen and oxygen from SCW for the petroleum formation and cracking. The δ13C and δD values of gases were also influenced by SCW. However, these values obtained in SCW did not always become positive as their yields increased. Generally, methane (CH4) was enriched in 12C and 1H. The influence of SCW on the isotopic fractionation of ethane (C2H6) and propane (C3H8) was more complex. The water phase is an important factor affecting the experimental results of hydrous pyrolysis. From these findings, it can be concluded that SCW allowed for increased conversion of sedimentary organic matter to gaseous and liquid hydrocarbons in ultra-deep layers and layers affected by volcanic-hydrothermal activity.

Abstract 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 S 2/S 3 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, S 1, 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.

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]

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]

This study focused on Middle Permian Lucaogou Formation saline lake source rocks, utilizing a combination of biomarkers and hydrocarbon generation thermal simulation to analyze their biological compositions, depositional environments, and hydrocarbon generation potential. The Pr/Ph ratio, Ph/nC18 ratio, and Pr/nC17 ratio indicate that the Lucaogou Formation was in a reducing environment during the deposition period, and the lower part of the Lucaogou Formation (P2l1) is more anoxic than the upper part of the Lucaogou Formation (P2l2). The maturity index 20S (%) and ββ (%) reflect that the maturity of organic matter in the P2l1 is slightly higher than that in the P2l2. The G/H index and the ETR index indicate that the stratification of the water column is better during the sedimentary period of Lucaogou Formation and the salinity of the P2l1 is higher than that of the P2l2. The biomarker parameters of nC21−/nC22+, CPI, S/H, and C22T/C21T reflect that the organic matter of the source rocks have a higher abundance of bacteria and algae than higher plants, and the contents of bacteria are more than that of algae. The (7- + 8-MMAs)/Cmax and (C28 + C29 − St)/St parameters indicate that cyanobacteria accounted for a certain proportion of bacteria, and the algae are mainly green algae. The co-evolution of the sedimentary environment and the biological composition reflects the control of the sedimentary paleoenvironment on biological composition. According to the relative content of cyanobacteria, green algae, and Rhodophyta, the source rocks of the upper and lower Lucaogou Formation correspond to the low-salinity type (LS-type) and the high-salinity type (HS-type), respectively. Compared with LS-type source rocks, HS-type source rocks have greater generation potential of oil and weaker gas generation potential. This study is valuable for the accurate assessment of source rocks and holds significant practical implications for the exploration of oil and gas resources. [ABSTRACT FROM AUTHOR]

The Termit Basin is a Cretaceous–Tertiary multi-rift graben, one of the eastern Niger basins. Belonging to this basin, the Dibeilla oil field is one of the most petroliferous oil fields in the Agadem Block. It contains multiple source rocks, but the origin of the hydrocarbons is not fully understood. The source rocks and crude oil samples from seven wells were examined using analytical techniques such as Rock–Eval pyrolysis, GC/GC–MS, vitrinite reflectance measurements, and basin modeling. Results indicate that the Upper Cretaceous (Donga and Yogou formations) and the Eocene Sokor-1 Formation have oil and gas generation potential with II/III and III type kerogens. The former were deposited in a clay-rich anoxic-suboxic marine environment with a mixture of aquatic and predominantly terrestrial organic matter and are thermally mature raching peak of oil-generation. The latter is mainly rich in terrestrial organic material deposited in a more oxic lacustrine to deltaic environment and reaches the early oil-generation stage. The Oligocene Sokor-2 Formation is oil-prone with Type I kerogens that are at an immature to marginally mature stage. The two peak values of paleo-heat (60 mW/m2) are the response of the Cretaceous syn-rifting period with two phases and the Paleogene phase of the rifting cycle, which exerted a significant influence on the source rocks' thermal maturity. The oil-source correlation reveals that oil production and preservation in the basin must extend to the deeper Campanian reservoirs. This is an important discovery that will help increasing the present-day oil production from the Eocene reservoirs of the Niger Termit Basin. [ABSTRACT FROM AUTHOR]

This study focuses on the upper and lower depth limits for kerogen to generate oil/gas worldwide. For the first time, the upper and lower depth limits of the conversion process from kerogen to oil/gas are given by the equations with clear physical significance. The method for obtaining the parameters in the equations is also proposed. The results show that the upper limit of hydrocarbon generation of kerogen mainly depends on the ratio of the minimum dissociation energy and initial molar mass of hydrocarbon generation. The smaller the ratio is, the shallower the upper limit of hydrocarbon generation of kerogen is. The upper depth limit of hydrocarbon generation ranges from 688 m to 4925 m, with an average of 1944 m. The lower limit of hydrocarbon generation mainly depends on the ratio of the dissociation energy and molar mass at the end of hydrocarbon generation. The lower depth limit of hydrocarbon generation is proportional to the above ratio. The lower limit of hydrocarbon generation of kerogen ranges from 2539 m to 16 337 m, with an average of 6926 m. This study not only solves a major controversial issue which is the minimum and maximum depth of drilling required to capture oil/gas but also helps select the location of carbon storage. It will be conducive to the effective utilization of fossil energy and the early realization of global carbon neutralization. • The upper and lower depth limits for kerogen to generate oil/gas worldwide are estimated by the equations with clear physical significance. • The ratio of dissociation energy and molar mass of kerogen is one of the most critical factors for the upper and lower depth limits of oil/gas generated by kerogen. [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]

The 1-D burial and thermal history of the Korotaikha depression in the Timan–Pechora basin was numerically simulated for the sedimentary sequences of three wells: Korotaikhinskaya 1, Labogeyskaya 15, and Khavdeiskaya 1. This made it possible to numerically assess the conversion history of the hydrocarbon (HC) potential of source rocks in the southwestern flank of the Korotaikha depression in the northeastern Timan−Pechora basin. The modern modified kinetic spectrum of vitrinite maturation was used in calculations of the vitrinite reflectance to clarify the thermal history of the sedimentary cover of the study area. The occurrence of episodes of hydrothermal activity follows from comparison of the calculated and measured values of the vitrinite reflectance and explains the jumps in the maturity of organic matter at the boundaries of the unconformity of Quaternary and Triassic sediments, as well as the Permian and Carboniferous sediments. The simulations suggest a high conversion of the initial HC potential of the source rocks of the Silurian and Domanic horizons, Tournaisian, and Visean ages in the Korotaikhinskaya and Labogeiskaya areas and moderate generation in the Havdeyskaya area. The simulation shows that the high grades of the catagenesis (MC5 and higher) of the main source rocks and the significant role of secondary cracking of liquid HC fractions in the central part of the Korotaikha depression (wells Korotaikhinskaya 1 and Labogeyskaya 15) suggest that the possible HC accumulations should contain only gas. Accumulations in the southern part of the depression (Khavdeiskaya area), where secondary cracking was minimal and source rocks occur within the oil window, should contain both oil and gas (due to Permian rocks with terrigenous organic matter). [ABSTRACT FROM AUTHOR]

The marlelimestone rhythmic strata of the Permian Maokou Formation have been identified as hosts of unconventional gas reservoirs with "sourceereservoir" integration. The lack of research on the pore structure evolution of organic-rich carbonate rock restricts gas exploration of these strata. Here, pyrolysis experiments were performed on the Mao-1 carbonate to simulate hydrocarbon generation, expulsion and diagenesis in gray marl from low maturity to overmaturity. The pore structure of this marl is dominated by mesopores and macropores, and the proportion of macropores increases gradually with temperature. The macropores are mainly pores in the organic matter and shrinkage microcracks. Additionally, micropores and mesopores, dominated by clay mineral interlayer pores and pyrite intergranular pores, are developed in the high mature stage and subsequently compressed in the overmature stage. The main contributors to the specific surface area are micropores and mesopores, which are conducive to natural gas adsorption. After the same pyrolysis treatment, the available porosity of grey marl is higher than that of marine/lacustrine shales, and exhibits an obvious decrease in the low mature emature stage. These suggest that the abundant residual oil generated blocked the organic and inorganic pores in the gray marl, providing a pivotal material foundation for the gas generation. Micropores and mesopores developed during the high mature stage ensure the gas accumulation and preservation. The above indicate the organic-rich carbonate at the high matureeovermature stage (Ro = 1.7%e2.5%) in the Sichuan Basin may be a favorable exploration horizon for unconventional oil and gas. [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]

Studies of the South Caspian Basin display that the Early Pliocene sediments define mainly the structural characteristic of the section in this area. The Productive Series consists of deposits accumulated during the Pliocene epoch. It is known that within the basin, the major commercial hydrocarbon accumulations are attributed to the Productive Series of the Early Pliocene and concentrated mainly in the Absheron oil and gas province, Baku archipelago and Low Kur oil and gas provinces. Studies of fluid generation are required for correct planning of geological exploration for oil and gas in these areas. This research work aimed to study the fluid generation processes in the South Caspian Basin by use of 3D modeling. The history of hydrocarbon formation was reconstructed. Fluid generation focuses were studied and the distribution areas of these focuses was clarified. The maturity of the Middle Jurassic and Low Cretaceous sediments and Maikop and Diatom deposits were assessed, the temperature regime of the Maikop and Diatom deposits were analyzed. We also evaluated the hydrocarbon fields’ and mud volcanoes’ relations to the focal areas of small-focused earthquakes. In the South Caspian Basin, the Middle Jurassic, Low Cretaceous, Maykop, and Diatom focuses of fluid generation were outlined and their allocation and time-spatial evolution history were researched. Evaluation of the maturity of Middle Jurassic and Low Cretaceous sediments, Maykop, and Diatom showed neither oil formed at the peak of oil-gas generation with maturity values Ro=0.8ff0.9 %, nor low-maturity gases of the transition zone even within the fluids of gas-condensate fields, while some oil fields had gases of abnormally high maturity of Ro=2.4ff3.09 %. 3D modeling of paleogeotemperatures in Maykop and Diatom suites found that a) both in the western and the eastern part of the South Caspian Basin the temperature in the bottom of Maykop increases by 20 ◦C in comparison to the top of the suite; b) in the west of the trough in the middle portion of Diatom at a depth of 8000 m and in the east of the trough at 9000 m, the temperature reaches 120 ◦C. In the case of small-focused seismicity caused by fluid-generation processes, the latter at the phase conversions are accompanied by high energy output, decompaction, pressing-out of fluids and matters in pseudo-liquefied state into the permeable areas of the media, thus assisting the development of diapiric structures and mud volcanoes.

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.

A new approach is presented in this paper for the dynamic modeling of the chemical and isotopic evolution of C1–3 during the hydrocarbon generation process. Based on systematic data obtained from published papers for the pyrolysis of various hydrocarbon sources (type I kerogen/source rock, type II kerogen/source rock, type III kerogen/source rock, crude oil, and asphalt, etc.), the empirical evolution framework of the chemical and isotopic composition of C1–3 during the hydrocarbon generation process was built. Although the empirical framework was built only by fitting a large amount of pyrolysis data, the chemical and isotopic composition of C1–3 derived from the pyrolysis experiments all follow evolution laws, convincing us that it is applicable to the thermal evolution process of various hydrocarbon sources. Based on the simplified formula of the isotopic composition of mixed natural gas at different maturities (δ13Cmixed), δ13Cmixed = X×niA×δ13CiA+Y×niB×δ13CiBX×niA+Y×niB, it can be derived that the cumulative isotopic composition of alkane generated in a certain maturity interval can be expressed by the integral of the product of the instantaneous isotopic composition and instantaneous yield at a certain maturity point, and then divided by the cumulative yield of alkane generated in the corresponding maturity interval. Thus, the cumulative isotopic composition (A(X)), cumulative yield (B(X)), instantaneous isotope (C(X)), and instantaneous yield (D(x)) in the dynamic model, comply with the following formula during the maturity interval of (X0~X). A(X) = ∫X0XCX×DXdxB(X), where A(X) and B(X) can be obtained by the fitting of pyrolysis data, and D(x) can also be obtained from the derivation of B(X). The dynamic model was applied on the pyrolysis data of Pingliang Shale to illustrate the quantitative evolution of the cumulative yield, instantaneous yield, cumulative isotope, and instantaneous isotope of C1–3 with increasing maturity. The dynamic model can quantify the yield of methane, ethane, and propane, as well as δ13C1, δ13C2, and δ13C3, respectively, during the hydrocarbon generation process. This model is of great significance for evaluating the natural gas resources of hydrocarbon source rock of different maturities and for identifying the origin and evolutionary process of hydrocarbons by chemical and isotopic data. Moreover, this model provides an approach to study the dynamic evolution of the isotope series of C1–3 (including reversed isotopic series), which is promising for revealing the mechanism responsible for isotopic reversal when combined with post-generation studies.

In this study, the hydrocarbon generation of 1â4 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 380â450 °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 22.5â27.5 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 0.5â5 and the reaction time range of 1â12 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.

The southern Sichuan Basin in China holds abundant shale gas resources; however, the shale gas bearing property shows great differences due to the multiple stages of tectonic transformation. The key to revealing the shale gas differential enrichment mechanism is to explore the thermal evolution characteristics during tectonic evolution. Therefore, taking the Luzhou and Changning blocks as an example, which have obvious differences in tectonic evolution, the organic geochemical conditions of Longmaxi shale were firstly compared with the test data. Then, the thermal evolution characteristics under the background differential tectonic uplift-erosion were recovered using basin modeling techniques. The results showed that the two blocks contain similar organic geochemical conditions of the Longmaxi shale. Moreover, the hydrocarbon generation condition in Luzhou Block is greater than that in the Changning Block. Influenced by the differential tectonic evolution, the study area experienced a complex burial history and the formation of multiple unconformities. As a result, the present burial depth of Longmaxi Formation in the Luzhou Block is significantly greater than that in the Changning Block. The thermal evolution history of Longmaxi shale in the study area could be divided into three stages, including a low-temperature stage from Caledonian to Hercynian, a middle-temperature stage from Hercynian to Indosinian, and a high-temperature stage from Yanshanian to Himalayan. In addition, it was found that the Himalayan period is the main stage resulting in the differential gas bearing property of Longmaxi shale in the southern Sichuan area. Under the differential structural modification, the peak time of hydrocarbon generation in the Luzhou Block occurred earlier and the conversion rate was slightly higher than that in the Changning Block. [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]

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]

Illite–smectite (I-Sm) clay minerals widely existed in clay-rich rocks or sediments. Understanding the effects of I-Sm clay minerals on the thermal evolution of organic matters (OMs) may facilitate interpreting hydrocarbon generation levels in petroleum basins and the global organic carbon cycle. In this study, mixed-layer I-Sm mineral rectorite (Rec), end-members montmorillonite (Mnt), and illite (Ilt) were chosen as the typical clay minerals and aliphatic organic compounds with different functional groups were selected as model OMs. Two kinds of OM-clay complexes, including OM-clay mixtures and OM-clay interlayer composite, were prepared. Pyrolysis experiment of OM-clay complexes were conducted via thermogravimetry coupled with Fourier transform infrared spectroscopy (TG-FTIR). TG-FTIR analysis showed that I-Sm clay minerals influenced the main thermal decomposition temperature (TM) and gas products of pyrolyzed OMs. Both Rec and Mnt decreased the TM of OMs and promoted decarboxylation, and the effect of Rec on TM was more obvious. Ilt had no significant effect on the TM and decarboxylation. Physicochemical property of the minerals showed that the solid acidity of the clay mineral was the key factor for the TM and types of thermal decomposition reaction (i.e., decarboxylation and C–C cleavage). Further analysis indicated that the functional groups of OMs affected the pyrolytic behaviors of OMs. OMs with cationic groups can be intercalated into the interlayers of clay minerals, which thus exhibited a high thermal stability. Functional groups such as alkyl chain and carboxyl groups had different binding effect with clay minerals, which leading to a difference of TM. Our results provide new insights into the role of I-Sm clay minerals in hydrocarbon generation in fine-grained sedimentary rocks as well as the geochemical behavior of organic carbon in response to inorganic minerals. [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]

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 Shanxi Formation (Shan 1 and Shan 2 Members) shales show good prospects in shale gas development in the Yan'an area of Ordos Basin. Based on the simulation experiment of hydrocarbon generation of low maturity shale samples, the hydrocarbon generation characteristics of shale samples was studied systematically. Then, combined with the geochemical analysis of shale and gas generation simulation, shale gas potential was evaluated. The results reveal that Shan 1 and Shan 2 shale samples are favorable for shale gas enrichment by and large, with C1–C5 maximum yields of 146.96–160.83 mg/g TOC and 148.48–148.67 mg/g TOC respectively at a heat rate of 20 °C/h and 2 °C/h. The Shan 1 and Shan 2 shales are basically the same in terms of organic carbon production potential of each unit. The carbon isotopic composition of alkane gas reveals that heteroatomic compounds (NSOs) cracking is an important mechanism for shale gas generation of Shanxi Formation shales, and conducive to gas generation at high-to over-mature stages. Given thermal history and kinetic parameters of hydrocarbon generation, the shales of Shanxi Formation reached the maximum gas production potential in the Late Cretaceous, with a maximum yield of 160.3 mg/g TOC under present geological conditions. During geological history, the Shanxi Formation shales went through high-to over-maturity evolution, mainly producing dry gas, and their gas generation capacity was controlled by the organic matter abundance and cracking capacity. The gas generation potential of Shan 2 shale is higher than that of Shan 1, due to its higher TOC.