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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]

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]

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]

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]

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]

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]

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]

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]

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]

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]

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

Overpressure is widely developed in marine sediments; it is not only a critical factor related to hydrocarbon accumulation, but also a serious safety issue for oil/gas exploration and exploitation. Although the mechanisms for overpressure development in sedimentary basins have been intensively studied, some new mechanisms are proposed for overpressure development with the advancements in marine geological investigation, e.g., natural gas hydrate formation and microbial activity. In this study, the mechanisms for overpressure development are reviewed and further classified as being related to associated physical, chemical, and biological processes. The physical overpressure mechanisms include disequilibrium compaction, hydrate formation sealing, degasification, buoyancy, hydrothermal pressuring, tectonic movement, overpressure transfer, etc. The chemical overpressure mechanisms are ascribed to hydrate decomposition, diagenesis, hydrocarbon generation, etc. The biological overpressure mechanisms are mainly induced by microbial gas production and microbial plugging. In gas hydrate-bearing sediments, overpressure is a critical factor affecting the formation and distribution of gas hydrate. The mechanisms for overpressure development in marine gas hydrate systems are associated with permeability deterioration due to hydrate formation and free gas accumulation below bottom-simulating reflectors (BSR). In marine sediments, overpressure developments are generally related to a sediment layer of low permeability above and natural gas accumulation below, and overpressure is mainly developed below a sulphate–methane interface (SMI), because methane will be consumed by anaerobic oxidation above SMI. [ABSTRACT FROM AUTHOR]

Hydrocarbon exploration under thrust belts is a challenging frontier globally. In this work, 1-D thermal maturity modeling of the Paleozoic–Mesozoic basement in the northern margin of the Western Outer Carpathians was carried out to better explain the thermal history of source rocks that influenced hydrocarbon generation. The combination of Variscan burial and post-Variscan heating due to elevated heat flow may have caused significant heating in the Paleozoic basement in the pre-Middle Jurassic period. However, the most likely combined effect of Permian-Triassic burial and Late Triassic–Early Jurassic increase of heat flow caused the reaching of maximum paleotemperature. The main phase of hydrocarbon generation in Paleozoic source rocks developed in pre-Middle Jurassic times. Therefore, generated hydrocarbons from Ordovician and Silurian source rocks were lost before reservoirs and traps were formed in the Late Mesozoic. The Miocene thermal overprint due to the Carpathian overthrust probably did not significantly change the thermal maturity of organic matter in the Paleozoic–Mesozoic strata. Thus, it can be concluded that petroleum accumulations in the Late Jurassic and Cenomanian reservoirs of the foreland were charged later, mainly by source rocks occurring within the thrustbelt, i.e., Oligocene Menilite Shales. Finally, this work shows that comprehensive mineralogical and geochemical studies are an indispensable prerequisite of any petroleum system modelling because their results could influence petroleum exploration of new oil and gas fields. [ABSTRACT FROM AUTHOR]

Lacustrine mudrocks are composed of minerals and organic matter (OM). The origin and preservation of OM are two controlling factors of the hydrocarbon generation capacity of mudrocks. It is a key method in source rock research to study the deposition process from the view of the OM and sedimentary environment. Following this idea, the reason for the discrepancy in hydrocarbon production between the northern and the southern part of Dongpu Sag is analyzed and discussed. The lacustrine mudrocks of the Shahejie Formation in Dongpu Sag are sampled and analyzed for information about mineralogy, microstructure, elemental geochemistry, and OM characteristics. The mudrocks are then divided into three lithofacies: silt-rich massive mudstone, homogeneous massive mudstone, and laminated mudstone. Each lithofacies shows distinct characteristics, and the hydrocarbon generation ability of them increases in sequence. Further discussion that the differences in hydrocarbon generation are caused by the sedimentary environment. The water depth, salinity, and reducibility of the sedimentary environments of these three lithofacies increase in sequence, as well. The correlation analysis indicates that it is the environment that controls the origin, accumulation, and preservation of OM in each lithofacies and then causes the great differences in hydrocarbon generation capacity. In Dongpu Sag, the proportion of laminated mudstone is much higher in the northern part, which leads to greater oil/gas production than the southern part. In research of source rocks, both the lithofacies characteristics and the sedimentary environments that control the characteristics should be studied. [ABSTRACT FROM AUTHOR]