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To determine the occurrence of mineral oil hydrocarbons (MOH) in food contact papers in China, and to investigate the potential sources of MOH contamination, a total of 159 food contact papers and raw materials were analysed by off-line solid-phase extraction-gas chromatography flame ionisation detection (SPE-GC-FID) and a GC-MS method. The migration of MOH from food contact papers into Tenax, olive oil or 50% ethanol under the worst foreseeable conditions of use was determined. The results indicated that the occurrence of MOH in China is of a potential health risk concerning the migration of mineral oil saturated hydrocarbons (MOSH) and mineral oil aromatic hydrocarbons (MOAH) which were detected in 82.6% and 50.4% of samples, respectively. Migration of MOSH from 47.9% of samples was higher than 2 mg/kg and migration of MOAH from 32.2% samples exceeded 0.5 mg/kg in case of the worst foreseeable condition of use. The highest mean migration of MOSH and MOAH were found in packaging papers for long-term storage (more than 6 months), with mean migration of 91.2 mg/kg and 1.4 mg/kg, respectively. Migration of MOH from printed paper was considerably higher than that of unprinted paper, validating previous findings that the printing ink is the predominant source of MOH contamination in food contact papers. Migration of MOH from paper bowls used for packing instant noodles was relatively low, suggesting the internal hollow layer may be acting as a functional barrier that could block the transfer of MOH (up to C28) through the gas phrase, even though the outer layer was made from recycled paper. High concentrations of MOSH and MOAH were also detected in de-foamers, adhesives and rosin sizing agents, indicating that the MOH contamination caused by the use of raw materials and additives should also be taken into consideration.

Petroleum hydrocarbons (PHCs) can be biodegraded into CO 2 , and PHC-contaminated aquifers are always deemed as carbon sources. Fortunately, some carbon fixation microorganisms have been found in PHC-contaminated sites. However, most of the studies are related to volatile short-chain PHC, and few studies focus on long-chain PHC-contaminated sites. To reveal the carbon fixation microorganisms in these sites, in the study, a long-chain PHC polluted site in North China was selected. Through hydrochemical and metagenomics analysis, the structure and capacity of carbon fixing microorganisms in the site were revealed. Results showed that there were many kinds of carbon fixed microorganisms that were identified such as Flavobacterium, Pseudomonas. HP/4HB, rTCA, and DC/4HB cycles were dominated carbon fixation pathways. The long-chain PHC were weakly correlated with carbon fixation microorganisms, but it may stimulate the growth of some carbon fixation microorganisms, such as microorganisms involved in rTCA cycle. PRACTITIONER POINTS: The microorganisms with carbon fixation gene exist in the aquifer contaminated by long-chain petroleum hydrocarbon. Microorganisms that have the ability to degrade petroleum also have the ability to carbon fixation. Long-chain petroleum hydrocarbon may promote the growth of carbon fixation microorganisms., (© 2024 Water Environment Federation.)

The interactive effects between the emerging contaminant antibiotic resistance genes (ARGs) and the traditional pollutant total petroleum hydrocarbons (TPHs) in contaminated soils remain unclear. The synergistic removal of TPHs and ARGs from composted contaminated soil, along with the microbial mechanisms driven by the addition of biogas slurry, have not yet been investigated. This study explored the impact of biogas slurry on the synergistic degradation mechanisms and bacterial community dynamics of ARGs and TPHs in compost derived from contaminated soil. The addition of biogas slurry resulted in a reduction of targeted ARGs and mobile genetic elements (MGEs) by 9.96%-95.70% and 13.32%-97.66%, respectively. Biogas slurry changed the succession of bacterial communities during composting, thereby reducing the transmission risk of ARGs. Pseudomonas, Cellvibrio, and Devosia were identified as core microorganisms in the synergistic degradation of ARGs and TPHs. According to the partial least squares path model, temperature and NO 3 - indirectly influenced the removal of ARGs and TPHs by directly regulating the abundance and composition of host microbes and MGEs. In summary, the results of this study contribute to the high-value utilization of biogas slurry and provide methodological support for the low-cost remediation of contaminated soils., Competing Interests: Declaration of competing interest The authors declare that they have no known competing financial interests or personal relationships that could have appeared to influence the work reported in this paper., (Copyright © 2024 Elsevier Inc. All rights reserved.)

The source of oil and gas in the Tarim Basin's platform has always been controversial. The Lower Cambrian Yurtusi Formation and the Xidashan Formation–Xishanbulak Formation argillaceous source rocks are an important set of oil source series in the basin. Based on the principle of conservation of matter, this paper calculates the hydrocarbon expulsion amount of the source rock. Using a phase state hydrocarbon expulsion amount characterization model, the paper reconstructs the evolution process of the hydrocarbon expulsion phase state of the source rock. According to the characterization model of hydrocarbon expulsion dynamics, the relative contribution of each force to hydrocarbon expulsion is evaluated. The hydrocarbon expulsion geologic model of argillaceous source rocks in the Lower Cambrian in the Tarim Basin is established. The results show that this set of source rocks can serve the main source rocks in the basin. The hydrocarbon expulsion of the Lower Cambrian argillaceous source rocks in the Tarim Basin can be divided into three stages. In the first stage, the hydrocarbon expulsion phase is dominated by the water‐soluble and diffusion phases. The conversion of clay minerals into dehydration and diffusion forces is the main driving force for the hydrocarbon expulsion. In the second stage, the oil and gas expulsion present the characteristics of multiphase and multidynamic coexistence. In the third stage, the phase state of oil and gas expulsion is mainly free phase. The capillary force difference and the thermal expansion force of the fluid rock are the main driving forces for oil and gas expulsion. The research results of this paper can deepen the understanding of the hydrocarbon expulsion mechanism of the set of source rocks, and then guide oil and gas exploration. [ABSTRACT FROM AUTHOR]

The mass fraction of total organic carbon (TOC) is one of the key indicators for evaluating the hydrocarbon generation potential of shale source rocks. Experimental measurements to evaluate the TOC content require significant cost and time. Furthermore, the experimental data are often fragmented and may not provide an accurate depiction of the source rocks throughout the entire block. To solve the above problems, this paper proposes to use the combination of conventional logging data and experimental data after an in-depth study of the geophysical characteristics of hydrocarbon source rocks in the Ordos Basin. A quantitative model between logging data and source rocks is established, and then the continuous distribution value of the TOC content in the hydrocarbon source rock interval is calculated. Firstly, the mud shale formation of the Permian–Shanxi Formation in the Upper Paleozoic, located in the Jingbian area of the Ordos Basin, is selected as the research target using the "Jinqiang method". The model is constructed by selecting appropriate logging curves (acoustic time difference logging, resistivity logging, and density logging) and experimental results based on the response relationship between logging data and TOC data. This method provides more accurate and comprehensive data for source rock studies, combining experimental sampling to contribute to a better evaluation of TOC in source rock. The shale hydrocarbon source rock logging data from 10 wells are selected, and the model is used to realize the full-well section of the logging data to find the hydrocarbon source rock TOC, which is compared with the TOC data from the experimental core tested at a sampling point. The results demonstrate that the model is highly effective and accurate, with a mere 2.7% percentage error observed across 185 sample data points. This method greatly improves the accuracy and completeness of TOC evaluation compared with the results of previous studies and provides a guide for subsequent TOC logging evaluation of source rocks in other areas. With the study in this paper, continuous TOC values of source rocks are obtained, discarding the TOC values representing the whole set of hydrocarbon source rocks with a limited number of sample averages. This method can reflect the contribution of the layers with high and low organic matter abundance, and the calculated reserves are more accurate. By utilizing the measured TOC values of the study area to invert the model to find the parameters, this study contributes to the decision-making of hydrocarbon exploration in domestic and international basins. [ABSTRACT FROM AUTHOR]

It is well known that the existing horizontal-well-drilling and hydraulic fracturing technology used to achieve large-scale, cost-effective production from immature to low–moderate-maturity continental shale in China, where the organic matter mainly exists in solid form, is fairly ineffective. To overcome the obstacles, in situ conversion technology seems feasible, while implementing it in the target layer along with estimating the amount of expected recoverable hydrocarbon in such shale formations seems difficult. This is because there are no guidelines for choosing the most appropriate method and selecting relevant key parameters for this purpose. Hence, based on thermal simulation experiments during the in situ conversion of crude oil from the Triassic Chang 73 Formation in the Ordos Basin and the Cretaceous Nenjiang Formation in the Songliao Basin, this deficiency in knowledge was addressed. First, relationships between the in situ-converted total organic carbon (TOC) content and the vitrinite reflectance (Ro) of the shales and between the residual oil volume and the hydrocarbon yield were established. Second, the yields of residual oil and in situ-converted hydrocarbon were measured, revealing their sensitivity to fluid pressure and crude oil density. In addition, a model was proposed to estimate the amount of in situ-converted hydrocarbon based on TOC, hydrocarbon generation potential, Ro, residual oil volume, fluid pressure, and crude oil density. Finally, a method was established to determine key parameters of the final hydrocarbon yield from immature to low–moderate-maturity organic material during in situ conversion in shales. Following the procedure outlined in this paper, the estimated recoverable in situ-converted oil in the shales of the Nenjiang Formation in the Songliao Basin was estimated to be approximately 292 × 108 tons, along with 18.5 × 1012 cubic meters of natural gas, in an area of approximately 8 × 104 square kilometers. Collectively, the method developed in this study is independent of the organic matter type and other geological and/or petrophysical properties of the formation and can be applied to other areas globally where there are no available in situ conversion thermal simulation experimental data. [ABSTRACT FROM AUTHOR]

Low-to-medium maturity lacustrine shale oil resources have enormous potential and are projected to play a crucial role in the massive scale-up of crude oil production in China in the near future. The in-situ conversion process is currently the only effective means of utilizing this resource. Nevertheless, significant scientific challenges and technological bottlenecks still exist. Under this circumstance, the National Natural Science Foundation of China approved an integrated project of the Enterprise Innovation and Development Joint Fund titled "The Mechanism of Low-to-medium Maturity Lacustrine Shale Oil Resource Formation and its in-situ Conversion and Exploitation". This project aims to systematically investigate the entire process of in-situ conversion for low-to-medium maturity shale oil resources and lay a solid scientific and technological foundation for advancing the smooth implementation of on-site pilot trials. This paper presents the latest progress in this field and summarizes the existing scientific and technological challenges that need to be addressed. With the foundational support of the above project, our research team has made significant progress in several fields, including the formation mechanisms of organic matter superrich shale, low-to-medium maturity shale oil enrichment area evaluation, heat and mass transfer dynamics, coupled fluid field and hydrocarbon expulsion efficiency, exploitation methods, among others. Despite these theoretical advances, several major challenges were identified, which help to further focus on the critical scientific issues, determine the in-situ conversion technique-developing direction, and formulate a feasible implementation plan for future resource utilization. [ABSTRACT FROM AUTHOR]

Affected by Tianshan uplift, the southern Junggar Basin has experienced multi-stage tectonic movements and formed many large-scale anticlines with zonal distribution. The key to hydrocarbon exploration is to accurately implement anticline traps. This paper is guided by the fault-related folds theory to tectonically interpret several seismic profiles in the southern Junggar Basin and then summarize the anticline types and their hydrocarbon accumulation characteristics. This paper showed that the southern Junggar Basin has a tectonic assemblage pattern of "multi-detachment layers and multi-phase superposition". According to the superimposed shape of the anticlines, they could be divided into overthrust anticlines, compound anticlines and multiple superimposed anticlines, and the horizontal and vertical positions of the different types of anticlines are different. The hydrocarbon accumulating characteristics of the different types of anticlines are shown to be different. The highs of the overthrust anticlines and compound anticlines are stable, and the degree of exploration is relatively high. Although the degree of exploration of multiple overlapping anticlines is low, multiple layers can be exploited simultaneously in the process of oil development, with great hydrocarbon potential. The characteristics of hydrocarbon accumulation in the southern Junggar Basin are discussed in order to provide guidance for efficient hydrocarbon exploration. [ABSTRACT FROM AUTHOR]

Mineral oil hydrocarbon (MOH) contamination of various foods in the past few decades has raised much concern due to its potential adverse health effects. Since infant formulas (IF) is the major food source for infants, it is necessary to understand MOH contamination level in IF and consequent potential food safety risks. Data on the contamination of IF by mineral oil are lacking in China. On the other hand, the analysis of MOH in food is difficult. There is no harmonised standard analytical method for testing MOHs in IF. GC-FID/MS was chosen as the analytical tool being more convenient for surveys at a national level. Fifty-one IFs comprising dairy milk-based IFs (n = 39) and goat milk-based IFs (n = 12), including different stages (Stage 1, 2 and 3), package type (metal cans and paper boxes) were collected in China market in 2018 for this survey. 17 of 51 IFs were found positive, but trace levels MOAH were found (≤0.7 mg/kg). For the positive samples, all the MOSH and MOAH hump fell into the C16-C25 fraction. MOH humps were found in all the 12 goat milk-based IFs, even 4 samples are reported with quantifiable values which are higher than the method defined LOQ. The highest quantifiable MOH contamination level of goat milk-based IFs were MOSH = 3.5 mg/kg and MOAH = 0.7 mg/kg. Further root cause analysis of contamination is highly recommended to control the MOH contamination for goat milk-based IFs. [ABSTRACT FROM AUTHOR]

Transitional shale gas, rich in resources, is expected to be a practical contributor to the increase in shale gas reserves and production in China. Its exploration prospect has been demonstrated by several wells in the Daning-Jixian block on the eastern margin of the Ordos Basin. In this paper, the Lower Permian Shanxi Formation (P1s) and Taiyuan Formation (P1t) in the eastern margin of Ordos Basin were compared for organic geochemical parameters, revealing that the overflow fan + lagoon combination (OLC) of the third sub-member of the second member of Shanxi Formation (P1s23) and the marine + lagoon combination (MLC) of the first member of Taiyuan Formation (P1t1) are the most favorable shale gas intervals. The two intervals were comparatively analyzed with respect to mineral composition, brittleness, caprocks, and preservation conditions. It is found that the OLC of P1s23 has a similar porosity to and much lower permeability than the MLC of P1t1 (or MLC1) and a BET surface area of 10–15 m2/g, which is smaller than the MLC1 (15–20 m2/g). Moreover, OLC has a brittle mineral content equivalent to MLC1 but a brittleness index of 33.73–62.36 (avg. 49.86), smaller than MLC1 (53.34–58.27, or avg. 55.85). OLC contains sandstones at both the roof and floor, with a higher permeability than shale in the interval, which cannot serve as good physical seals. In contrast, MLC1 contains limestones with lower permeability at the roof and floor, which, together with the overlying coal seams, have hydrocarbon generation capacity and can physically seal the MLC1 shale but also fill it with hydrocarbons, making MLC1 have higher gas content and superior for shale gas exploration than the OLC shale. Due to the multi-lithologies developed in transitional facies, besides the organic matter enrichment, and reservoir characteristics, it is necessary to find a suitable lithological combination to ensure the gas in shale can be better preserved and retained. [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]

In the process of diagenesis and burial of sedimentary basins, basin fluid activities participate in the process of hydrocarbon accumulation and metal mineralization. Understanding the evolution of basin fluid is of great significance in revealing the related hydrocarbon accumulation and mineralization. Paleo-reservoirs are closely associated with Carlin-type gold deposits in the Nanpanjiang-Youjiang Basin, South China. Calcite, the fluid activity product, is closely related to bitumen and gold-bearing pyrite. By integrating petrographic, cathode luminescence, and fluid inclusion analysis, as well as the relevant chronological results of predecessors, this paper attempts to establish the relationship between fluid evolution, hydrocarbon accumulation, and gold mineralization. Two types of calcite (black/gray and white) developed in the Banqi-Yata-Laizishan area, the Nanpanjiang-Youjiang Basin. Black/gray calcite is symbiotic with bitumen and features dark red colors in cathode luminescence. Many hydrocarbon inclusions developed along with fluid inclusion analysis at low homogenization temperatures (65.7~173.1 °C). Combining the previously reported U-Pb ages (~250–230 Ma) of this kind of calcite with some geochemistry data on the associated reservoir and gold deposit, this calcite records the consecutive hydrocarbon accumulation and Carlin-type gold mineralization from the Late Permian to the Late Triassic periods controlled by Indosinian tectonic movement. The white calcite featuring bright red in cathodoluminescence is symbiotic with gold-bearing pyrite and realgar, and the associated fluid inclusions have high homogenization temperatures (128.2~299.9 °C). Combined with regional tectonic background and isotopic chronology (~140–106 Ma), it seems to record the early Cretaceous Carlin-type gold mineralization controlled by the subduction of the paleo-Pacific plate in the late Yanshanian period. [ABSTRACT FROM AUTHOR]

The possibilities offered by the use of variational mode decomposition–based Hilbert marginal spectrum and the differential cepstrum for gas‐bearing detection are studied in this paper. We propose a novel variational mode decomposition–based Hilbert marginal differential cepstrum for hydrocarbon detection. Variational mode decomposition–based Hilbert marginal spectrum is first computed. Then discrete cosine transform is carried out to the differential logarithmic variational mode decomposition–based Hilbert marginal spectrum to obtain the variational mode decomposition–based Hilbert marginal differential cepstrum. For hydrocarbon detection, the seismic amplitude anomaly section is generated by extracting the first and second common quefrency sections. Compared with the traditional Fourier‐based cepstrum, the wavelet‐based cepstrum and the Berthil cepstrum, it has the ability to effectively reveal more detailed frequency‐dependent amplitude anomalies with high accuracy and resolution. Model tests and field data applications from a carbonate reservoir in China show that the variational mode decomposition‐based Hilbert marginal differential cepstrum can provide a better gas‐prone interpretation. The proposed method can be a complementary approach to current cepstrum‐based hydrocarbon detection methods and the spectrum decomposition methods. [ABSTRACT FROM AUTHOR]

The Dongpu Depression is a secondary salt‐bearing tectonic unit in the Bohai Bay Basin, eastern China. The depositional environment of this depression regarding its Paleogene strata is clearly different in plane, including the saltwater environment (SE) in the north, the freshwater environment (FE) in the south and the brackish water environment (BE) in the middle. The result of oil and gas exploration in the Dongpu Depression shows that more than 90% of the proven oil reserves are distributed in the northern saltwater environment. Previous studies indicate that the organic geochemistry characteristics and the hydrocarbon generation capacity of the source rocks are very clearly diverse under different environments, which results in the significant differences in the proved reserves between the north and the south. In order to further explore the differences in the hydrocarbon generation capacity of the source rocks under distinct depositional environments and the mechanism of their occurrence, three samples from different depositional environments (W18‐5 for SE, H7‐18 for BE, CH9 for FE) were used for confined gold tube pyrolysis experiments. The results show that the CH4 yields of W18‐5, H7‐18 and CH9 increase with increasing temperature, the maximum yields being 405.62 mg/g TOC, 388.56 mg/g TOC and 367.89 mg/g TOC, respectively. The liquid hydrocarbon yields of W18‐5, H7‐18 and CH9 firstly increase with increasing temperature and then decrease after the critical temperatures. The maximum yields of C6–14 are 149.54 mg/g TOC, 140.18 mg/g TOC and 116.94 mg/g TOC, the maximum yields of C14+ being 852.4 mg/g TOC, 652.6 mg/g TOC and 596.41mg/g TOC, respectively for W18‐5, H7‐18 and CH9. To summarize, the order of hydrocarbon potential from high to low is W18‐5, H7‐18 and CH9. On this basis, through analyzing the influencing factors of hydrocarbon differences, this paper reveals that the saltwater environment is characterized by 4 factors: higher salinity, halophilic algae, high paleo‐productivity and a strongly reducing environment, which are beneficial to the enrichment of organic matter and lead to the formation of high levels of sapropelite and exinite. According to the variation of oil and gas components in the pyrolysis experiments, the hydrocarbon generation process is divided into three stages: kerogen cracking, oil cracking and C2–5 cracking. Combined with hydrocarbon generation characteristics and stages, the evolutionary model of hydrocarbon generation for source rocks under different environments is established. [ABSTRACT FROM AUTHOR]

Organic macerals are the basic components of organic matter and play an important role in determining the hydrocarbon generation capacity of source rock. In this paper, organic geochemical analysis of shale in the Chang 7 member of the Yanchang Formation was carried out to evaluate the availability of source rock. The different organic macerals were effectively identified, and the differences in hydrocarbon generation and pore-forming capacities were discussed from two perspectives: microscopic pore development and macroscopic hydrocarbon generation through field emission scanning electron microscopy (FE-SEM) and energy-dispersive spectrum (EDS) analyses, methane isotherm adsorption, and on-site analysis of gas-bearing properties. The results show that the source rock of the Chang 7 member has a high abundance of organic matter and moderate thermal evolution and that the organic matter type is mainly type I. Based on the morphology of the organic matter and the element and pore development, four types of hydrogen-rich macerals, including sapropelite and exinite, and hydrogen-poor macerals, including vitrinite and inertinite, as well as the submacerals, algae, mineral asphalt matrix, sporophyte, resin, semifusinite, inertodetrinite, provitrinite, euvitrinite, and vitrodetrinite, can be identified through FE-SEM and EDS. A large number of honeycomb-shaped pores develop in sapropelite, and round-elliptical stomata develop in exinite, while vitrinite and inertinite do not develop organic matter pores. The hydrogen-rich maceral is the main component of organic macerals in the Chang 7 member of the Yanchang Formation. The weight percentage of carbon is low, so it has good hydrocarbon generation capacity, and the organic matter pores are developed and contribute 97% of the organic matter porosity, which is conducive to hydrocarbon generation and storage. The amount of hydrogen-poor maceral is low, and the weight percentage of carbon is low, and the organic matter pores are not developed, which is not conducive to hydrocarbon generation and storage. [ABSTRACT FROM AUTHOR]

Mineral oil contaminants migrated from food contact materials have raised much concern in the past few decades. However, survey data of the occurrence of mineral oils in foods are only available for a limited variety of foods, which do not include the contaminants in Chinese milk powders. Thus, to conduct an analysis of mineral oils migrated into milk powder products from different packaging materials, 50 Chinese commercial samples (including 38 infant formulas), which were packaged in metal cans, paper containers, paper boxes and aluminium foil-plastic bags, were analysed. Mineral oil saturated hydrocarbons (MOSH), polyolefin oligomeric saturated hydrocarbons (POSH) and aromatic hydrocarbons (MOAH) migrated into those samples were extracted and quantitatively analysed by on-line liquid chromatography coupled with gas chromatography (LC-GC). The results indicated no surface MOAH was detected in any of the samples, while 33 samples contained MOSH/POSH with surface contents of 0.10 ~ 5.09 mg kg -1 . Moreover, the amounts of those MOSH/POSH are closely related to packaging materials, among which the surface contamination values of products in metal cans were the lowest, followed by products in paper containers and boxes, and the values of samples in aluminium foil-plastic bags were the highest. In addition, the surface MOSH/POSH content exhibited a positive correlation with fat content in the samples due to their similar polarities.

The Yinggen‐Ejinaqi Basin (YEB) is located in the central‐southern part of the Central Asian Orogenic Belt (CAOB). Tectonically, the basin is situated at the intersection between the eastern and western CAOB, where Late Palaeozoic strata were well exposed. Hence, it offers a great opportunity to study the deep strata of the eastern CAOB. In this paper, based on extensive studies of Upper Palaeozoic field outcrops and reanalysis of associated geochemical and geochronological data in previous research, the local stratigraphic correlation is established, and the tectonic evolution, sedimentary filling, sedimentary characteristics, and petroleum system of the YEB are discussed. It is revealed that: (a) The filling characteristics of the Upper Palaeozoic strata in YEB are closely related to the closure of the Paleo‐Asian Ocean (PAO). YEB underwent subduction‐related compression during the initial extensional phase of the fore‐arc basin from the Viséan to the Serpukhovian (late Early Carboniferous). During the Bashkirian–Sakmarian interval (Late Carboniferous to Early Permian), it was in subduction‐related fore‐arc and postarc rifting phases. During the Artinskian–Capitanian (Early‐Middle Permian) times, it was in an intracontinental rifting‐depression phase. During the Wuchapingian (Late Permian), it was in an intracontinental compressional phase. Tectonostratigraphy, tectonic evolution, and hydrocarbon potential assessments of the study area show that the Zhusileng Hangwula‐Tost Ul tectonic zone (ZHTUTZ) and southwestern part of Querrshan‐Atasbogd tectonic zone (QATZ) are identified as the main prospective areas for the exploration in the YEB. (b) According to the tectonostratigraphic analysis, tectonic evolution and hydrocarbon system of Carboniferous–Permian in the YEB, the YEB has similar attributes to the basin province in western CAOB (e.g., Santanghu and Junggar basins) and eastern CAOB (Erlian, Songliao Basin). To explore commercial oil and gas in the deeper strata (Carboniferous–Permian) of the eastern CAOB basins, further tectonostratigraphic analyses and comprehensive assessment on hydrocarbon potentials are necessitated in the near future. [ABSTRACT FROM AUTHOR]

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INTRODUCTION The study focused on the influence of tar concentrations, smoking regimen, and smoking behavior, on benzo[a]pyrene (B[a]P) emission from cigarette mainstream smoke and related health hazards to determine the key factors influencing B[a]P reduction and protection of the smoker's health. METHODS A locally popular brand of cigarettes in Beijing was selected with tar concentrations of 1, 3, 5, 8, 10, and 11 mg/cigarette. Two different machine smoking regimens, the Canada Intense (HCI) regimen and the International Organization for Standardization (ISO) regimen, were adopted to collect the cigarette mainstream smoke. The B[a]P emission concentrations were then measured by gas chromatography and mass spectrum. RESULTS The average B[a]P emission was 8.14--17.6 ng/cigarette for the HCI regimen and 0.92--3.46 ng/cigarette for the ISO regimen. As expected, the tar concentrations and B[a]P emissions exhibited a positive relation in both the HCI and ISO regimens, the cancer risk and non-cancer risk increased with an increase in tar concentrations for both the ISO and HCI regimens, and the smoking behavior also affected the B[a]P emissions with a tendency of VB (ventilation blocking) > HVB (half ventilation blocking) > DP (deep puff), under the same smoking regimen. Under the same conditions, the cancer risk and non-cancer risk in men were 1.19 and 1.11 times, respectively, higher than in women. CONCLUSIONS The smoking regimen influences the B[a]P emission relatively more than the cigarette tar concentration and smoking behavior. The cancer risk and non-cancer risk are higher in men than in women that possibly due to longer smoking duration and greater smoking intensity. [ABSTRACT FROM AUTHOR]

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

Highlights • Cumulative-In-Situ-Injection-Production is a novel method for reservoir development. • Simulation results indicate CIIP is an efficient energy-supplement method. • CIIP is applicable to many kinds of tight reservoirs with highly irregular fractures. • Technology for Electric fluid regulation system of CIIP still need to be improved. Abstract Water flooding and gas injection are two traditional secondary development methods for tight oil reservoirs. Water injection has the problem of small injectivity due to low permeable reservoir matrix while gas injection brings about severe breakthrough because of obvious viscosity difference between gas and oil. These traditional approaches that supplement energy between wells are not highly effective. To fill this gap, this paper proposes an efficient energy-supplement method, continuous in-situ injection and production (CIIP), among fractures for multistage fractured horizontal well (MFHW) in tight oil reservoirs. CIIP divides hydraulic fractures into two kinds, in which odd fractures are used for production while even fractures are for injection. CIIP has three main advantages over traditional water flooding: firstly, it switches displacement interval from between injection and production wells to between hydraulic fractures; secondly, CIIP has a better injectivity compared to traditional water flooding at the same injection pressure; and thirdly, CIIP improves sweep efficiency thereby improving oil recovery. In this paper, a workflow is developed to evaluate the performance of CIIP in a case study. Reservoir properties and micro-seismic (MS) mapping data are analyzed to provide fundamental parameters for building a numerical simulation model, and then history matching is achieved to validate the model. The simulation considers two scenarios of hydraulic fractures: the uniform and non-uniform fractures. Uniform-fracture simulation aims to investigate the mechanisms of CIIP under three fracture models; different fracture half-lengths and the situation of existing high permeable channels between injection and production fractures are also included in uniform-fracture simulation. Non-uniform-fracture simulation, whose fractures are interpreted according to MS mapping results, is devised to demonstrate CIIP's superiority in a realistic way. This study is based on a theoretical approach and the results wait to be further proven in the field. Simulation results demonstrate that CIIP is an efficient energy-supplement method. It helps to maintain reservoir pressure near the initial condition during the thirty-year simulation. Meanwhile, even if ten injection wells are added, CIIP still injects 55% more water than water injection (WI) at the same injection pressure. Uniform-fracture simulation indicates that CIIP has a 2.23% more oil recovery than WI and a 3.74% than depletion. Besides, the influence of high permeable channels between injection and production fractures is insignificant and we can still expect CIIP's good performance when hydraulic fractures hit local natural fractures. The non-uniform-fracture simulation demonstrates that CIIP performs well too when hydraulic fractures are randomly distributed. It also finds outs that the presence of primary fractures in which proppant concentrates is essential to CIIP while the role of natural fractures is trivial compared to the hydraulic fractures. In a word, CIIP is a promising technology for tight oil reservoir development. [ABSTRACT FROM AUTHOR]

The Qiangtang Basin is one of the largest Mesozoic petroliferous basins in China that is still unexploited for the petroleum industry. The basic geological issues and synthesis of the Qiangtang Basin related to the Tethyan evolution are still poorly understood. This volume presents 20 research papers to address the tectonic settings, basin evolution, and sedimentary environments of the Qiangtang Basin, which are key factors for a better understanding of the overall petroleum system. The Qiangtang Basin holds a Precambrian base developed in response to the Paleo-Tethys Hol Xil-Jinshajiang Ocean evolution, with enhanced sedimentary basin infilling during the opening and expansion of the Neo-Tethys Bangong-Nujiang Ocean in the Mesozoic. The Paleozoic basin framework of the Qiangtang demised as the Paleo-Tethys Ocean closed at the latest Permian, while the Early-Middle Triassic foreland basin underwent a negative basin inversion during the Late Triassic. The latter initiated a new sedimentary filling cycle of the Qiangtang Basin, which was triggered by the active extensional rifting and the onset of the bimodal volcanic eruption. Recent scientific exploratory drilling (QK-1 well) found that the Qiangtang Basin is characterized by multiple source rocks, of which the upper Triassic Bagong Formation and the lower Quse Formation exhibit the most hydrocarbon generation potential. The development of high quality and quantity source rocks in the Qiangtang Basin is ensured by regional to global-scale bottom-water anoxia and high primary productivity in the eastern Tethys realm in the Late Triassic and the Early Jurassic. The main reservoirs in the Qiangtang Basin include the Middle Jurassic reef-beach facies, the Upper Triassic carbonates, and the Lower Jurassic terrestrial clastic rocks. Two very-thick caprocks of gypsum in the Lower Jurassic and gypsum mudstones in the Middle Jurassic strata are found during the scientific drilling, which is interpreted as favorable regional-scale seals for petroleum entrapment in the Qiangtang Basin. [ABSTRACT FROM AUTHOR]

In the central Tarim Basin, numerous hydrocarbon deposits were found along ultra-deep strike-slip faults, and its evolving progress and formation mechanism are research hotspots. The Paleozoic small-angle X-type strike-slip fault in the Tabei Uplift is the research subject in this article. Based on high-precision three-dimensional seismic data, three structural deformation layers were revealed: the rift system, weak strike-slip deformation and salt tectonics in the deep structural layer (Sinian-Middle Cambrian), the strong strike-slip deformation and karst-dissolution structure in the middle structural layer (Upper Cambrian-Middle Ordovician), and echelon normal faults in the shallow structural layer (Upper Ordovician-Carboniferous). The formation and evolution of strike-slip faults is jointly controlled by the distribution pattern of basement rift and the activities of surrounding orogenic belts, which can be divided into three stages. In the Middle to Late Cambrian, the initial subduction of the Paleo-Asian and Proto-Tethyan oceans precipitated the emergence of two sets of small-angle X-type strike-slip faults, striking NW and NE above the grooves of Precambrian rifts, influenced by local weak compressive stress. Affected by the closure of peripheral paleo-ocean, strike-slip faults deformed considerably in the Middle-Late Ordovician and were reactivated in the Silurian-Carboniferous, forming en-echelon normal faults in the shallow layer. The layered deformation structure of the strike-slip faults significantly affects the accumulation of hydrocarbons. The differential hydrocarbon enrichment of faults in the Tabei Uplift is collectively influenced by the distribution of source rocks and the migration of oil and gas. The topographical features of the Tabei Uplift, along with the distribution of strike-slip faults across tectonic units, have rendered the NE direction the preferential pathway for hydrocarbon migration. Additionally, impacted by the development of en echelon faults, the NE-trending faults offer superior conditions for hydrocarbon preservation and charging condition, compared to the NW-trending faults. [ABSTRACT FROM AUTHOR]

Recent advances in hydrocarbon exploration have been made in the Member Deng-2 marginal microbial mound-bank complex reservoirs of the Dengying Formation in the western Sichuan Basin, SW China, where the depositional process is regarded confusing. The microfacies, construction types, and depositional model of the Member Deng-2 marginal microbial mound-bank complex have been investigated using unmanned aerial vehicle photography, outcrop section investigation, thin section identification, and seismic reflections in the southwestern Sichuan Basin. The microbialite lithologic textures in this region include thrombolite, dendrolite, stromatolite, fenestral stromatolite, spongiostromata stone, oncolite, aggregated grainstone, and botryoidal grapestone. Based on the comprehensive analysis of "depositional fabricselithologyemicrofacies", an association between a fore mound, mound framework, and back mound subfacies has been proposed based on water depth, current direction, energy level and lithologic assemblages. The microfacies of the mound base, mound core, mound flank, mound cap, and mound flat could be recognized among the mound framework subfacies. Two construction types of marginal microbial mound-bank complex have been determined based on deposition location, mound scale, migration direction, and sedimentary facies association. Type Jinkouhe microbial mound constructions (TJMMCs) develop along the windward margin owing to their proximity to the seaward subfacies fore mound, with a northeastwardly migrated microbial mound on top of the mud mound, exhibiting the characteristics of large-sized mounds and small-sized banks in the surrounding area. Type E'bian microbial mound constructions (TEMMCs) primarily occur on the leeward margin, resulting from the presence of onshore back mound subfacies, with the smaller southwestward migrated microbial mounds existing on a thicker microbial flat. The platform margin microbial mound depositional model can be correlated with certain lateral comparison profile and seismic reflection structures in the 2D seismic section, which can provide references for future worldwide exploration. Microbial mounds with larger buildups and thicker vertical reservoirs are typically targeted on the windward margin, while small-sized microbial mounds and flats with better lateral connections are typically focused on the leeward margin. [ABSTRACT FROM AUTHOR]

The distribution characteristics and main controlling factors of hydrocarbon phases in deep strata from petroliferous basins are important for the evaluation of oil–gas resources and decision-making regarding exploration. The distribution characteristics and controlling factors of the Ordovician hydrocarbon phases are systematically analyzed in the Tazhong I block, Tarim Basin, NW China. The results show that the Ordovician reservoirs in the Tazhong I block are characterized as multi-phase reservoirs with a lateral co-existence of condensates, normal oil reservoirs, and heavy oil reservoirs. From east to west, gas-rich in the fault belt and oil-rich in the platform area are presented. Meanwhile, there are regular variations in the geochemical characteristics of the Ordovician hydrocarbon, showing decreasing trends in the gas/oil ratio (GOR), wax contents, dryness coefficients, methane contents, and methane carbonate isotope values (δ13C1) and an increasing trend in oil densities. Because the same Cambrian–Lower Ordovician source for the Ordovician hydrocarbon is observed in the Tazhong I block, the regular variations in the hydrocarbon phases and geochemical characteristics can be interpreted as records of gas invasion, biodegradation, multi-stage filling, thermal cracking, and thermochemical sulfate reduction (TSR) rather than controlled by the source rock organofacies. This indicated that different kinds of secondary processes for a diversity of the hydrocarbon phase can appear in one region. Our re-construction of the Ordovician hydrocarbon accumulation model in the Tazhong I block encourages future exploration to target gas reservoirs in the fault belt and oil reservoirs in the platform area. [ABSTRACT FROM AUTHOR]

Continental shale in China is a key exploration target with regard to unconventional hydrocarbons. Systematic research on the mineral composition, organic geochemistry, and hydrocarbon mobility has been performed in the Da'anzhai (J1dn) lacustrine shale oil reservoirs, clarifying the factors controlling shale oil accumulation. The results suggest that J1dn consists of three sub-members, with an organic-rich interval developed within the second sub-member. Three types of lithological associations have developed within the organic-rich interval: Type 1 represents the interbedding relationship between shale and shell limestone and Type 2 represents shale with intercalated limestone, followed by Type 3. The brittleness index of the J1dn continental organic-rich shale is relatively low. The porosity of the Da'anzhai lacustrine shale ranges between 0.5% and 10.5% (average value of 5.89%). The porosity is predominantly due to inorganic pores, with a small amount being attributable to nanoscale microfractures and organic pores. The average porosity of the shell limestone is only 1.2%, but fractures at the micron and centimeter scales are well developed. The organic matter in the J1dn continental shale is mainly II1–II2, with maturity in the oil generation stage. The average oil saturation of the J1dn continental shale is 3.15%, with most samples having oil saturation of less than 4%. The J1dn continental shale has great exploration potential with regard to shale oil. Type 1 shale oil is affected by multiscale fractures, including bedding fractures, and has the best mobility. The high hydrocarbon generation capacity of lacustrine shale, coupled with the multiscale fractures within shell limestone and shale, is the principal controlling factor for hydrocarbon enrichment. Based on exploration practices, the Type 1 shale association may represent the optimal interval for future shale oil exploration in the Da'anzhai Member. [ABSTRACT FROM AUTHOR]

Geothermal energy is one of the cleanest sources of energy which is gaining importance as an alternative to hydrocarbons. Geothermal energy reserves in China are enormous and it has a huge potential for exploitation and utilization. However, the development of the geothermal industry in China lags far behind other renewable energy sources because of the lack of fiscal and taxation policy support. In this paper, we adopt the system dynamics method and use the causal loop diagram to explore the development mechanism of fiscal and taxation policies in the geothermal industry. The effect of the fiscal and taxation policy on the development of the geothermal industry is analyzed. In order to promote sustainable development of the geothermal industry in China, the government should pay more attention to subsidies for the geothermal industry in the life-cycle stage of the geothermal industry. Furthermore, a plan is necessary to provide a reasonable system of fiscal and taxation policies. [ABSTRACT FROM AUTHOR]

Significant volumes of hydrocarbons have been produced from karstified Infracambrian dolomites in a 'buried hill' structure at depths of 5860m to 6027m and reservoir temperatures of 190-201°C in well Niudong-1 in the Baxian depression, Bohai Bay Basin. This is the deepest oil and gas discovery made in eastern China so far and structures at similar depths are targets for exploration elsewhere in the Bohai Bay Basin. However the origin and accumulation of the hydrocarbons at Niudong-1 is not clear: they may have been generated from highly mature lacustrine source rocks in the Sha-4 Member of the Eocene Shahejie Formation; or they may have been derived from thermal cracking of previously-accumulated oil. This paper investigates the organic geochemistry of the Sha-4 Member source rocks and the crude oils produced from well Niudong-1. Analyses of molecular parameters show that the hydrocarbons originated from the pyrolysis of organic matter in Sha-4 Member source rocks, rather than from cracking of previously accumulated oil. Infracambrian dolomites at the Niudong-1 location may have been charged with low-maturity oil around 34 Ma ago, when the Sha-4 Member source rocks were buried to depths of about 3500m and first entered the oil window. During further rapid burial to more than 5500m starting at about 15Ma, these source rocks became highly mature and generated significant volumes of light oil and gas. Overpressures in the source rock interval forced these hydrocarbons to migrate into unconformably-underlying Infracambrian dolomite reservoir rocks at the Niudong-1 structure. Significant risks are associated with future exploration of deep 'buried hill' structures in the Bohai Bay Basin. Not all the structures were charged with oil, and accumulations were not necessarily preserved during Neogene burial as the reservoirs may have been breached by faulting. [ABSTRACT FROM AUTHOR]

Abnormal pressure is considered significant for the migration and accumulation of oil and gas. The purpose of this study is to present the lateral and vertical distribution of underpressure conditions in the Huimin Depression determined using the drill stem tests (DSTs) and the well log data. This paper also provides the origins of the underpressure both qualitatively and quantitatively, as well as the effects of the underpressure on the distribution of hydrocarbons. The results show two vertical underpressure units at depths of 1,500–2,500 m and 3,000–4,000 m with a pressure coefficient of 0.8–0.95. Laterally, the underpressure is mainly distributed in the Northern Tectonic Uplift Belt (NTUB) and Southern Slope Belt (SSB). The rock dilation and temperature reduction caused the pressure reductions of 3–4 and 1–3 MPa, respectively. The diffusion of natural gas plays a limited role on the underpressure. An analysis of the lateral seals of faults indicates that the underpressured regions developed in areas with faults with shale gouge ratio (SGR) values larger than 0.6. We propose that the widely distributed underpressure in the Huimin Depression is related to rock dilation, temperature reduction, and fault sealing. An analysis of hydrocarbon migration and reservoirs showed the pumping effect provided by the deficient pressure could make underpressured regions the primary targets for hydrocarbon accumulation, and in the Huimin Depression, underpressure might be more important than overpressure. [ABSTRACT FROM AUTHOR]

Recently, with the ongoing development of the express industry, the consumption of waste plastic express bags has been increasing year by year, which has brought considerable pressure on municipal waste management. At the same time, in China, where coal is the main energy resource, the upgrading of low-rank coal is a more reliable and prospective way. An effective method for waste treatment and resource upgrading by synergistic co-liquefaction of waste plastic express bags and low-rank coal in a supercritical water-ethanol system has been developed. The effects of different experimental factors (temperature, residence time, plastic-coal ratio, water-ethanol ratio) on the conversion ratio and synergistic effect of co-liquefaction were investigated. The results showed that elevated temperature, lower water-ethanol ratio as well as suitable residence time, and plastic-coal ratio of 1:1 were conducive to the conversion ratio. Temperature ≥375 °C and suitable plastic-coal ratio (1:1) had a significant positive synergistic effect on the conversion ratio, whereas the other conditions exhibited no or negative synergistic effect on the conversion ratio. The maximum conversion ratio and positive synergistic efficiency were 85.11% and 12.25% at 425 °C, 60 min, water-ethanol ratio of 1:1, and plastic-coal ratio of 1:1, respectively. It was observed after FT-IR and elemental analysis based on the solid residue that the oxygen-containing functional groups in the residue disappeared, the oxygen content decreased, the carbon content increased, and the higher heating value (HHV) increased significantly, and the residue could be further used (such as gasification or pyrolysis) without the need for landfill. The GC-MS results of the oil products suggested that the oil products contained high content of hydrocarbons and phenols, as well as esters, alcohols, and other compounds. The hydrocarbons and phenols mainly derived from the decomposition of long chains in plastics and the decomposition of aromatic structures in coal, and the hydrocarbon and phenolic contents produced at 400 °C were 27.74% and 32.62%, respectively. Thus, the oil product can be used further as a chemical raw material. It cannot be ignored that the ethanol medium after reaction can also be further recycled by rotary evaporation. The synergistic co-liquefaction of waste plastic express bags and low-rank coal based on supercritical water-ethanol system is a promising method for waste treatment and resource upgrading. [Display omitted] • A synergistic co-liquefaction for waste express bags and low-rank coal was developed. • Ethanol can improve the synergistic efficiency of co-liquefaction. • The maximum conversion ratio of co-liquefaction reached 85.11% at 425 °C, 60 min. • Oil products from co-liquefaction contained hydrocarbons and phenolic compounds. [ABSTRACT FROM AUTHOR]

With the global expansion of shale oil and gas exploration, analyzing the geochemical characteristics of different types of shale has seized extensive attention. Taking the Chang 7 Member and Shanxi Formation in the Ordos Basin as examples, this study investigated the geochemical and hydrocarbon expulsion characteristics of different types of shale. The results show that the Chang 7 shale is mainly type I. The total organic carbon (TOC) distribution of the Chang 7 shale in the study area was between 0.72% and 27.5%, with an average of 7.46%, and the vitrinite reflectance (Ro) ranged from 0.45% to 1.28%. It is a good source rock in immature to mature stages. The Shanxi shale is mainly type III. The TOC distribution of the Shanxi shale was between 0.6% and 58.5%, with an average of 8.92%, and the Ro distribution was between 0.42% and 2.39%, indicating good immaturity over mature source rock. The average hydrocarbon expulsion efficiencies of the Chang 7 shale calculated using the hydrocarbon generation potential method and the original hydrocarbon generation potential method were 82.49% and 94.81%, respectively. Simultaneously, a correlation analysis of hydrocarbon expulsion efficiency with organic matter abundance, maturity, and type found that when TOC was less than 5%, hydrocarbon expulsion efficiency increased with increased organic matter abundance and maturity. When the TOC exceeds 5%, the hydrocarbon expulsion efficiency is mainly related to maturity. The hydrocarbon expulsion efficiency of the sapropelic shale was much higher than that of the humic shale. This study is significant for evaluating shale gas and shale oil resources in similar areas. [ABSTRACT FROM AUTHOR]

Over the past decade, cooperation between China and Kazakhstan in the oil and gas sector has developed significantly. For China, security of its energy supply is a key strategic objective. This paper analyzes the evolution of Sino-Kazakh oil and gas relations, assesses their long-term prospects, and explores how Chinese demand for oil and gas could divert Kazakhstan’s hydrocarbon resources from other energy markets. The netback approach has been used to assess the prices that China will need to offer other producers in Kazakhstan. Sino-Kazakh energy and economic cooperation could create a good basis for free economic zones and development of beneficial ties for both countries. [ABSTRACT FROM PUBLISHER]

The Tarim Craton of NW China hosts abundant hydrocarbon resources within clastic reservoirs characterized by a complex entrapment and fill history. In this paper, we review the processes of hydrocarbon accumulation in typical clastic reservoirs from the literature, and combine this with new research from six hydrocarbon-bearing regions (the Yakela Faulted-Uplift, the southern slope of the Tabei Uplift, the Tazhong Uplift, the northern slope of the Tazhong Uplift, the southern margin of the Bachu Uplift, and volcanic reservoirs) to identify the key controls on hydrocarbon accumulation and distribution in reservoirs of the Tarim Craton. Favorable reservoir–trap configurations exist on structural highs created during the evolution of paleo-uplifts and paleo-slopes in the region, with hydrocarbons accumulating in both structural (fault, salt dome, and thrust-fault anticline) and combined structural-primary stratigraphic traps. Vertical hydrocarbon migration occurred via deep–shallow superposed faults, and (rarely interpreted) fault textures in volcanic conduits. Unconformity surfaces and sand bodies provided pathways for both limited lateral redistribution and significant long-distance (>100 km) migration of hydrocarbons. The prospectivity of upper Paleozoic sandstone facies and paleogeography was controlled by denudation of the paleo-uplifts, and these reservoirs are most likely to host giant oil and gas fields in the region. • Differential hydrocarbon accumulation process of six clastic hydrocarbon abundance zones in Tarim Craton. • Favorable structural reservoir–trap configurations exist on structural highs created during the evolution of Paleo uplifts/slopes. • Vertical hydrocarbon migration occurred via deep–shallow superposed faults, and fault textures in volcanic conduits. • The prospectivity of upper Paleozoic sandstone facies and paleogeography was controlled by denudation of the paleo-uplifts. [ABSTRACT FROM AUTHOR]

Abstract This paper uses coal-measure shales from Carboniferous-Permian in Yushe-Wuxiang Block as an example to study the physical properties of transitional coal measure shales, including geochemical properties (e.g. total organic carbon content (TOC), organic matter maturity and hydrocarbon generation potential); mineral composition determined by X-ray diffraction (XRD) and pore structure characteristics determined by gas adsorption methods. The results indicated that the transitional coal measure shales in Yushe-Wuxiang area mostly comprise type III kerogen and are mostly in the over-mature stage, with shales in the range of 1.86%–3.36% R o. The TOC of transitional shales varied significantly, ranging from 0.10% to 34.37%. Clay minerals and quartz are major minerals in transitional shales, while the predominant clay minerals are illite-smectite mixed clay (I/S) and kaolinite. The total pore volume (TPV) and pore specific surface area (SSA) of investigated mud shales varies from 0.0071 to 0.023 cm3/g and 8.4059–18.2888 m2/g, respectively. The transitional shales mostly provide mesopores and macropores, whereas the micropores provide the main SSA. The TOC content has a distinct effect on the porosity and micropores volume but contributes little to the TPV and volumes of macropores and mesopores. Clay minerals are positively correlated with porosity, TPV and volumes of each class of pores, while quartz has an opposite effect. In the over-maturity stage, the increase of organic matter maturity will inhibit the development level of pores in shale. For the coal measure shales, I/S and illite contribute most to the pore development. Highlights • TOC is positively correlated with porosity and micropore volume. • Clay minerals are positively correlated with pore volumes. • Quartz inhibits the development level of transitional coal measure shales. • The development and evolution of pores was mainly attributed to the presence of I/S and illite. [ABSTRACT FROM AUTHOR]

In order to study the distribution pattern of hydrocarbons in the shallow layer of the slope area outside of the source in the hydrocarbon-bearing basin, we built a method to predict the favorable site of the fault that adjusts hydrocarbon to the shallow layer in the slope area outside of the source based on the investigation of the mechanism of hydrocarbon adjustment along a conduit fault to a shallow layer. The predicted favorable site is found to be the overlapping area of three sites: the locations of the sand carrier with a lateral supply of hydrocarbon, the transport sites of conduit faults, and the hydrocarbon leakage parts of overlying regional mudstone seal rock. We applied the method in a case study of the favorable sites of the Zhaobei Fault that adjust the hydrocarbon from the lower sub-member within the first member of Shahejie Formation (Es1L) to the shallow Guantao Formation in the Qikou Sag of Bohai Bay Basin. Our prediction shows that the favorable sites are mostly located in the middle part of the Zhaobei Fault with very limited distribution in the east, which are conducive to the oil and gas supplied by the underlying sand carrier in the Es1L Formation to convergence and accumulation in the shallow Guantao Formation. This result is consistent with the distribution of the hydrocarbon in the Guantao Formation located in the middle parts of the Zhaobei Fault, proving that this method is feasible for the prediction of the favorable sites of the fault that adjust hydrocarbon to the shallow layer in the slope area outside of source. [ABSTRACT FROM AUTHOR]

Bozhong Sag, the largest hydrocarbon generation sag in the Bohai Bay Basin, is characterized by presence of the third member of the Shahejie Formation (E2s ³ ), which serves as a significant source rock. While previous studies have provided insights into the source material, sedimentary environment, and thermal maturity of the E2s ³ source rocks, further investigation is required to deepen our understanding of sedimentary events and biological sources. In this research, nine mudstone core samples from the southwestern Bozhong Sag were thoroughly analyzed using organicinorganic geochemistry and organic petrology. The results reveal the following key findings: (1) The middle and lower sections of the third member of the Shahejie Formation are characterized by high-quality source rocks, with the lower section exhibiting superior quality. The increase in water salinity during warm and humid climates, and the detection of 24-n-propylcholestane compounds reflected the occurrence of transgression events in the E2s ³ . These transgressions gradually increased from the lower sections to the middle sections of the E2s ³ . (2) The studied samples exhibit abundant presence of 4α-methyl-24-ethylcholestanes, 24-n-propylcholestanes, 2α-methylhopanes, oleananeabundant algainite, and a small amount of vitrinite. This diversity of hydrocarbon-forming organisms in the E2s ³ source rocks is evident. (3) The moderate marine incursion in the lower part of the E2s ³ results in nutrient elements that promote the flourishing of bacteria and algae, providing an abundant material basis for the formation of high-quality source rocks. However, the large-scale marine incursion in the middle of the E2s 3 weakens water eutrophication, resulting in a decrease in the quality of source rocks compared to the lower part of the E2s 3 . [ABSTRACT FROM AUTHOR]

Fluid inclusion signal strength and visual inclusion abundance are generally lower along migration pathways than in charged reservoirs from the same area. A zone that displays strong fluid inclusion stratigraphy (FIS) hydrocarbon indications and high visualized petroleum inclusion abundance, indicates paleo-charge or in some cases a migration pathway, e.g, where inclusion abundance is enhanced by extensive microfracturing. In this study, fluid inclusion data are interpreted in seven offshore wells of the Lamu Basin to enhance the understanding of hydrocarbon generation, migration and migration pathways. The study also examines the interrelationship among rock texture, rock composition and trapped fluid distribution in the study area. The studies were based on FIS analyzed data courtesy of Fluid Inclusion Technologies (FIT) Inc. in USA laboratories. FIT conducted analysis on 391 samples from the Paleocene to Upper Jurassic (Kiboko-1 well), 249 from the Paleoecene to Campanian (Kubwa-1 well), 106 from the Maastrichtian to Turonian (Mbawa-1 well), 59 from the Eocene to Campanian (Pomboo-1 well), 26 form the Lower Eocene to Maastrichtian (Simba-1 well), 16 from the Eocene toMaastrichtian (Kipini-1 well) and 11 from the Maastrichtian to Campanian (Kofia-1 well). It also made analysis on sidewall core sample plates, with 44 from the Maastrichtian to Campanian (Kubwa-1 well), 108 from the Campanian to Upper Jurassic (Kiboko-1 well) and 8 from the Campanian (Pomboo-1 well) for petrographic evaluation. For photomicroscopy, thin sections were examined under a petrographic microscope using Ultra Violet (UV) fluorescence and microthermometry, in order to verify the presence of petroleum bearing inclusions in the rock samples and to explore textural relationships that may yield additional information on the timing of hydrocarbon migration or generation. Gas shows in Mbawa-1 well is a result of generated hydrocarbons from the carbonate interbeds in the Upper Cretaceous. Gas shows are pockets trapped in the thin carbonate rich beds. There is low abundance of upper-low, moderate and uppermoderate gravity liquid petroleum inclusions in Kubwa-1 well (central deep offshore). The low abundance suggests migration events rather than paleo-accumulations, possibly involving several discrete charges. Despite sufficient vitrinite reflectance and total organic carbon (TOC) content, the temperatures are still insufficient for hydrocarbon generation in the southern deep offshore in the region where Kiboko-1 well is located. There is no sufficient evidence for access to mature source rocks in the deep offshore basin. [ABSTRACT FROM AUTHOR]

The Bohai Bay Basin is a Meso-Cenozoic rifted basin where the Paleozoic buried hills with great hydrocarbon potentials are well developed. The reservoir space types are complex and diverse due to tectonic activities, making fracture distribution highly heterogeneous. Reservoir identification and mapping is challenging due to their large burial depth and poor resolution of seismic data. An integration of well-logging, seismic data interpretation and core observation is applied to identify three structural unit types in the study area, that is, fault breccia zone, fault cataclastic zone, and fault massive rock zone. A comprehensive well-logging identification template and a comprehensive discriminant function M for the reservoir are established based on the well-logging response characteristics. A M value greater than 0.12 indicates a fault breccia zone, that between 0.04 and 0.12 marks a fault cataclastic zone, and that in the range from 0.02 to 0.04 represents a fault massive rock zone. A seismic prediction method with multi-parameter fusion is proposed in the study. The large-scale fractures are mapped by coherenceclutter parameters, while small fractures are predicted via waveform indication inversion. The spatial distribution of "fault-fracture reservoirs" is precisely mapped by frequency fusion technology. It is found that the fault breccia zones usually occur close to the fault planes, while the fault cataclastic zones are slightly away from the fault planes. The hydrocarbon abundance of the breccia zones is greater than that of the fault cataclastic and fault massive rock zones. [ABSTRACT FROM AUTHOR]

Organic-rich rocks have received increasing attention for they are essential for evaluating hydrocarbon potential and unravelling the interaction between Earth surface environments and the biosphere. In this paper, we performed a combination of mineralogical, inorganic and organic geochemical analyses on a 200-m core of the Permian Lucaogou Formation organic-rich rocks obtained from Santanghu Basin, NW China, to investigate paleoenvironmental conditions, organic matter accumulation, and hydrocarbon potential. The redox- and salinity-sensitive proxies (e.g. V/Cr, V/(V + Ni) and Sr/Ba, Rb/K, B/Ga, and B content), together with the wide distribution of pyrite and carbonate minerals in these dark, thinly laminated organic-rich rocks, suggest that dysoxic-anoxic, brackish-saline, alkaline conditions prevailed during the deposition of the Lucaogou Formation in the Santanghu Basin. The occurrence of hydrothermal minerals, including strontianite and barite, and enrichments of B (up to 158.0 ppm), Mn (up to 1291 ppm), and certain incompatible elements (Li (up to 923 ppm), Rb (up to 848 ppm), Sr (up to 1760 ppm), Hf (up to 12.7 ppm)) as well as Ni vs. Co vs. Zn and Fe vs. Mn vs. (Cu + Co + Ni) × 10 ternary diagrams demonstrate that the Lucaogou Formation received hydrothermal input during deposition, which suggests hydrothermalism was the source of brine that has caused the salinization of the water column. The positive correlation of HI value and TOC content, together with redox-sensitive proxies, illustrates primary productivity in surface water and preservation in anoxic bottom water collectively contributed to the enrichment of organic matter. Moreover, the positive correlation between silicate mineral content and TOC content and the negative correlation between carbonate content and TOC content suggest that terrigenous input as the main source of nutrients promoted organic matter accumulation, while carbonate constituents acted as a diluent to organic matter accumulation during deposition of the Lucaogou Formation. The faint positive correlation between TOC content and hydrothermal intensity indicator (Cr/Zr) seems to indicate that hydrothermal fluids may provide an additional source of nutrients for organic matter accumulation. In addition, the oil generation capacity of Lucaogou Formation, with abundant oil-prone organic matter (Type I/II 1 kerogen with HI values ranging from 421.18–918.41 mg HC/g TOC) in the early mature to mature stage (T max values ranging from 435 to 451 °C), is considerable. The Rock-Eval oil saturation index (OSI S 1 /TOC × 100) values range from 6.04–164.07 mg HC/g TOC, suggesting the Lucaogou Formation contains producible oil. The high brittle mineral (including quartz and carbonates) contents (> 50% wt%) and traces of clay minerals (< 5 wt%) imply that the Lucaogou Formation is likely to respond well to hydraulic stimulation. Consequently, the Lucaogou Formation in Santanghu Basin is expected to be a potential lacustrine shale oil play. [ABSTRACT FROM AUTHOR]

Relatively to petroleum exploration on an anticline or in fault block areas in continental basins, the identification of hydrocarbon traps on a synclinalic structure is a challenging task. In order to locate prospects in synclinal areas of Lishu Depression, this study analyzes the structural development of the Qikeshu syncline, describes the sedimentary facies, the sandbody distribution patterns and localizes potential Lishu Depression traps in the syncline based on seismic and well data. Furthermore, the paper summarizes the hydrocarbon trap spatial distribution and discusses the key points points in identifying hydrocarbon traps in faulted-syncline structures of a continental basin. The obtained results show that the tectonic movements at the end of the Barremian and Maastrichtian Ages bounded each limb of the Qikeshu syncline and reoriented paleo-delta lobes deposited in the syncline area. The modifications of the delta lobe affected the distribution of favorable sandbodies and potential hydrocarbon traps. The development of lithologic traps is correlated with the sandbody vertical stacking patterns in a sedimentary sequence. In faulted and folded structures of this continental basin, the post-depositional tectonic modification of paleo-sedimentary bodies strongly influences hydrocarbon play conditions. The petroleum exploration should thus focus on structural history and sedimentary factors, in order to analyze the lithologic and fault-controlled combination traps. [ABSTRACT FROM AUTHOR]

Oil adsorption on the pore surface of tight shale affects the transport and even recovery of oil through shale reservoir. In this paper, an innovative model evaluating the n -alkane adsorption on shale was developed theoretically according to the hydrocarbon vapor adsorption (HVA) process and was verified by the n -decane (i.e., n -C 10 ) adsorption on continental oil shale obtained from the Dongying sag of the southeastern Bohai Bay basin of China. The model considered the multilayer adsorption of hydrocarbon and the microscopic characteristics of the shale pore system. For a case study, several parameters in the models were determined by low temperature nitrogen adsorption/desorption (LT-N 2 A/D) and HVA tests combined with recently reported molecular dynamics simulation. Next, optimal values of the coefficients k and β were determined by fitting the experimental data with the model and were used to calculate the n -C 10 adsorbed amount under 0.8 P / P 0 and 298.15 K condition. Simultaneously, the n -C 10 condensed (i.e., free-phase-like) amount was obtained. The primary results demonstrate that (1) n -C 10 adsorbed amount is obviously lower than condensed amount and varies from 0.097 to 0.619 mg/g (mean 0.311 mg/g), accounting for 1.68–3.76% (mean 2.32%) of the total amount. (2) Both the adsorbed and condensed amounts are directly controlled by total pore volume, which are mainly contributed by organic matters and secondarily by pyrite and siderite in shale. The model will be potential useful to evaluate the shale oil adsorption. [ABSTRACT FROM AUTHOR]

• The sedimentary environment transitioned from clastic shore-shelf of the lower Ediacaran to carbonate platform to mixed shelf of the upper Ediacaran except for the glaciogenic Hangelchaok Formation. • The Ediacaran slop break belt was first identified along the west and south margins of the Manjar sag. • High-quality source rocks and karstic dolostone in Ediacaran indicate great potential for hydrocarbon exploration. The Late Neoproterozoic was an important period for the breakup of Rodinia and the assembly of Gondwana. The Neoproterozoic succession developed under the extensional setting is critical for understanding the early tectono-sedimentary evolution of the Tarim Basin and possibly exhibits considerable hydrocarbon potential. In this paper, the stratigraphic correlation of the Ediacaran is conducted across the whole Tarim Basin, based on the latest wells, seismic data and field investigations. The paleogeographic distribution and hydrocarbon potential of the Ediacaran are thoroughly discussed. The Lower Ediacaran succession is mainly distributed in northern and southwestern Tarim Basin and marginal outcrop areas, but absent in the whole Central Rise. With sea level rising, the Upper Ediacaran succession gradually moved toward Central Rise with the exception of the Tazhong Uplift and the eastern Bachu Uplift. During Early Ediacaran, depositional environment in the Tarim Basin was mainly clastic shore-shelf, with a large denuded region extending from Bachu-Tazhong Uplift to Tadong Uplift. The range of the erosional area gradually diminished during Late Ediacaran. Accordingly, the Tarim Basin was dominated by carbonate platform and mixed shelf. Slope break belt between carbonate platform and mixed shelf was identified around the Manjar sag for the first time. The Ediacaran black mudstone and shale in northeastern and southwestern Tarim, which formed in deep-water environment and have relatively high values of TOC (mostly ranging from 0.3% to 1.2%), can serve as high-quality source rocks. The Upper Ediacaran dolostones altered by paleokarst could be potential reservoir rocks. Our research findings, combining with previous geological results, suggest that the Ediacaran succession in Tarim Basin has great potential for hydrocarbon exploration. [ABSTRACT FROM AUTHOR]

Cuticular hydrocarbons of Cerambycidae species can function as signals for sex recognition. Little is known about the copulatory signals of the juniper bark borer Semanotus bifasciatus, a major economic threat to Platycladus orientalis Franco in China. Here, we investigated the cuticular hydrocarbons of both sexes of S. bifasciatus to determine the chemically mediated mating signals using the solid‐phase microextraction (SPME) technique with carbowax/divinylbenzene fibers (CAR/DVB) and then analyzed by coupled gas chromatography‐mass spectrometry (GC‐MS). A series of aliphatic saturated straight‐chain n‐alkanes (n‐C23 to n‐C28), internally branched monomethylalkanes at carbons 3, 11, or 13, and dimethylalkanes were identified, which showed no qualitative differences in either sex and were similar in the samples with SPME fiber extraction and those with hexane extraction. The bioassay showed that 11‐methylpentacosane (11‐MeC25), 11‐methylhexacosane (11‐MeC26), and 11‐methylheptacosane (11‐MeC27) have sex‐specific recognition functions that triggered more mating attempts at a female‐specific ratio of 100:4:60 than at a male‐specific ratio of 100:85:50. In addition, the female‐specific ratio of 11‐methylalkanes can elicit about 70% of male mating attempts within about 60 s, whereas live females elicit about 98% of male mating attempts within 25 s. The discrepancy in the initiation of mating attempts by synthetic mixtures and live females suggests that the methyl isomers 3‐MeC25, 3‐MeC27, and/or 11,15‐diMeC27 may also be involved in the mating behavior of S. bifasciatus. These results suggest that 11‐MeC25, 11‐MeC26, and 11‐MeC27 constitute the contact sex pheromone of S. bifasciatus, with the presence or absence of 11‐MeC26 in particular playing an important role in mate recognition by males. [ABSTRACT FROM AUTHOR]

Evaluating the hydrocarbon generation potential of highly mature organic matter is a key and critically challenging area of research in petroleum geochemistry. To explore this issue, we used negative ion electrospray ionization-Fourier transform-ion cyclotron resonance-mass spectrometry to investigate the molecular evolution of N-containing compounds in Carboniferous-lower Permian source rocks with a range of maturities in the northwestern Junggar Basin, China. The N1 compounds formed from on-fluorescent chlorophyll catabolites (NCCs), which record the characteristics of the residual soluble organic matter. These components remain in the source rocks after hydrocarbon generation and expulsion, and enable evaluation of the hydrocarbon generation potential. The newly defined indexes of molecular evolution, which are the polymerization index P1 ([DBE 18+DBE 15]/[DBE 12+DBE 9]_N1) and alkylation index R1 (RC6–35/RC0–5), combined with the vitrinite reflectance (VRo) and paleo-salinity index (β-carotane/nCmax), can identify the factors that control the evolution of highly mature organic matter. The main factor for source rocks deposited in a weakly saline environment is the maturity, but for a highly saline environment both the maturity and salinity are key factors. The high salinity inhibits the molecular polymerization of organic matter and extends the oil generation peak. Given the differences in the bio-precursors in saline source rocks, we propose a new model for hydrocarbon generation that can be used to determine the oil generation potential of highly mature organic matter. [ABSTRACT FROM AUTHOR]

A sample from the Jurassic Tamulangou Fm. and two comparison samples from the Cretaceous Fm. were used to document the hydrocarbon generation kinetics and phase behaviors at two heating rates using the confined gold tube system. The results show that the different heating rates affect the reaction rates, paths and levels of organic matter evolution. The average activation energy and dominant frequency activation energy of liquid hydrocarbon are significantly lower than those of gaseous. Moreover, igneous intrusion had a positive effect on the blooming, enrichment and preservation of organic matter, promoting a Ro increase of 0.09%–1.07% in the Jurassic Tamulangou Fm. Two models were used to simulate the normal and abnormal evolution caused by thermal events combined hydrocarbon generation kinetic parameters. Thermal simulation analysis shows that oil generation was initially slow and then increased rapidly until a burial depth of 1500 m was reached at ~128 Ma. The largest hydrocarbon expulsion began at ~120 Ma, corresponding to a burial depth of 2450 m. The maximum cumulative yield is 510 mg/g TOC, and it is still in the peak period of hydrocarbon generation, which demonstrates a favorable potential for hydrocarbon exploration. [ABSTRACT FROM AUTHOR]

A mature understanding of the sandstone gas reservoir in the Xiaoheba Formation in the southeastern Sichuan Basin remains lacking. To assess the reservoir characteristics and the origin of the high-quality reservoir in the Xiaoheba Formation, this paper uses systematic field investigations, physical property analysis, thin section identification, scanning electron microscopy and electron microprobe methods. The results indicate that the Xiaoheba sandstone is an ultra-tight and ultra-low permeability reservoir, with an average porosity of 2.97% and an average permeability of 0.56×10−3 μm2. This promising reservoir is mainly distributed in the Lengshuixi and Shuangliuba regions and the latter has a relatively high-quality reservoir with an average porosity of 5.28% and average permeability of 0.53×10−3 μm2. The reservoir space comprises secondary intergranular dissolved pores, moldic pores and fractures. Microfacies, feldspar dissolution and fracture connectivity control the quality of this reservoir. The relatively weak compaction and cementation in the interbedded delta front distal bar and interdistributary bay microfacies indirectly protected the primary intergranular pores and enhanced late-stage dissolution. Late-stage potassium feldspar dissolution was controlled by the early-stage organic acid dissolution intensity and the distance from the hydrocarbon generation center. Early-stage fractures acted as pathways for organic acid migration and were therefore important factors in the formation of the reservoir. Based on these observations, the area to the west of the Shuangliuba and Lengshuixi regions has potential for gas exploration. [ABSTRACT FROM AUTHOR]

Recent drilling data from the northern Songliao Basin reveal considerable hydrocarbon exploration potential in deep-seated small-scale faulted basins. In this paper, the Shahezi Formation of the northern Xujiaweizi Fault Depression within the Songliao Basin was investigated as a case study. Sequence stratigraphy, sedimentary systems and the hydrocarbon exploration potential of the small-scale faulted basin were investigated through observations and descriptions of cores; analyses of conventional log curves, imaging data and logging data; and interpretations of 3-D seismic profiles. Four third-order sequences, mainly controlled by sediment supply and fault activity, were identified based on unconformities at the basin margins and in sedimentary successions. System tracts in the third-order sequences were also recognized through lithological associations and geophysical response characteristics. The distributions of sedimentary systems, including fan deltas, braided deltas, lacustrine deposits, subaqueous fans, volcaniclastic deposits and incised-valley deposits, in the sequence framework are associated with basin evolution. During the early stage of the Shahezi Formation (SQ1 and SQ2), the sedimentary area was mainly covered by fan deltas, and lacustrine deposits were not very developed. Additionally, incised-valley systems formed on basin margins and subaqueous fans formed along basin-controlled faults. During the middle stage (SQ3), fan delta deposits on gentle slopes were gradually replaced by braided delta deposits, and the sizes of lacustrine facies increased with basin expansion. In the late stage (SQ4), the basin and lacustrine deposit areas reached their maximum sizes, and braided deltas became the dominant sedimentary systems on gentle slopes. With continuous sediment supply, fan and braided deltas migrated forward, and the lacustrine system was locally distributed. In this small-scale faulted basin, the lacustrine mudstones and coal seams widely developed in SQ4, especially in SQ4-HST, and they also exhibited good source rock properties for gas generation. Sandbodies of fan deltas and braided deltas in the upper Shahezi Formation, exhibiting good contact relationships with underlying source rocks, can be favourable reservoirs for hydrocarbon accumulation, as confirmed by the newly drilled Well Songs9H (with a daily gas production of 20×10 4 m 3 ). However, due to low porosity and permeability (averages of 4.7% and 0.28×10 −3 µm 2 , respectively), these reservoirs may need fracturing for commercial hydrocarbon production. [ABSTRACT FROM AUTHOR]

Purpose: To review the epidemiologic literature examining pesticide exposure and liver cancer incidence.Methods: A search of the MEDLINE and Embase databases was conducted in October 2015. Eligibility criteria included examining hepatocellular carcinoma (HCC) or primary liver cancer, pesticides as an exposure of interest, and individual-level incidence. The review was performed according to Preferred Reporting Items for Systematic Reviews and Meta-Analyses (PRISMA) guidelines.Results: Forty-eight papers were assessed for eligibility and 15 studies were included in the review. The majority of studies were conducted in China and Egypt (n = 8), used a case-control design (n = 14), and examined HCC (n = 14). Most studies showed no association between self-reported and/or occupational exposure to pesticides and liver cancer risk. Six studies demonstrated statistically significant positive associations, including three biomarker-based studies (two using pre-diagnostic sera) that reported higher serum levels of dichlorodiphenyltrichloroethane (DDT) were associated with increased HCC risk. Studies indirectly measuring pesticide exposure using self-reported exposure, occupation, job-exposure matrices, or geographic residence demonstrated inconsistent results. These studies were limited by exposure assessment methods, lack of confounder information, minimal case confirmation, selection bias, and/or over-adjustment.Conclusions: There is mixed evidence suggesting a possible association between specific pesticides and HCC risk, with the strongest evidence observed in biomarker-based studies. In particular, organochlorine pesticides, including DDT, may increase HCC risk. Future research should focus on improved pesticide exposure assessment methods, potentially incorporating multiple approaches including biomonitoring while considering the chemicals of interest, historical exposure to address latency periods, and examining specific chemicals and exposure pathways. [ABSTRACT FROM AUTHOR]