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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]

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]

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 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]