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Abstract The novel pathogen, Elizabethkingia anophelis, has gained attention due to its high mortality rates and drug resistance facilitated by its inherent metallo-β-lactamases (MBLs) genes. This study successfully identified and outlined the functions of the B3-Q MBLs variant, GOB-38, in a clinical sample of E. anophelis. The T7 expression system was employed to stimulate the expression of recombinant protein in Escherichia coli, followed by an analysis of the biochemical properties of purified GOB-38. Our findings indicate that the enzyme GOB-38 displays a wide range of substrates, including broad-spectrum penicillins, 1–4 generation cephalosporins, and carbapenems, potentially contributing to in vitro drug resistance in E. coli through a cloning mechanism. It is important to highlight that GOB-38 exhibits a distinct active site composition compared to GOB-1/18, featuring hydrophilic amino acids Thr51 and Glu141 at both ends of its active center instead of hydrophobic alanine, potentially indicating a preference for imipenem. Furthermore, the co-isolation of Acinetobacter baumannii and E. anophelis, two opportunistic pathogens, from a single lung infection is noteworthy. Our in vitro co-culture experiments suggest that E. anophelis, carrying two MBL genes, may have the ability to transfer carbapenem resistance to other bacterial species through co-infection.

Abstract Background Tropheryma whipplei pneumonia is an infrequent medical condition. The clinical symptoms associated with this disease are nonspecific, often resulting in misdiagnosis or missed diagnosis. Therefore, sharing and summarizing the experiences in the diagnosis and treatment of this disease can deepen global understanding and awareness of it. Case presentation The patient is a 78-year-old married Han Chinese female who was admitted to the hospital after experiencing fever, dry cough, and fatigue for 4 days. A lung computed tomography scan revealed inflammatory exudation in the lower left lung, accompanied by pleural effusion. The bronchoalveolar lavage fluid was subjected to further analysis using metagenomic next-generation sequencing, which identified 41 genetic sequences associated with Tropheryma whipplei. Consequently, she was diagnosed with Tropheryma whipplei pneumonia. After initiating treatment with doxycycline and biapenem, the patient’s symptoms showed significant improvement. Upon discharge, the patient continued treatment with a combination of doxycycline and hydroxychloroquine, which was discontinued after 4 days. At 12-month follow-up, the patient reported overall good health, with no symptoms of fever, cough, or any other discomfort. Conclusion Tropheryma whipplei pneumonia is a rare condition with nonspecific symptoms. The application of metagenomic next-generation sequencing technology in pulmonary infections helps to rapidly identify rare pathogens, providing a solid foundation for precise and effective antibacterial treatment for patients.

The Well Mitan-1 has achieved a major breakthrough in the exploration of Ordovician subsalt natural gas in the mid-eastern Ordos Basin, demonstrating a high-yield industrial gas flow in fourth member of the Majiagou Formation of Ordovician (O1m4). Despite this success, there are ongoing disputes regarding the origin of the natural gas found in Well Mitan-1. Measured results show that the natural gas in Well Mitan-1 is mainly composed of alkane gas (95.18 %). The gas drying coefficient (C1/C1-5) is measured at 0.947, and the H2S content is 3.49 %, with a small amount of N2 and CO2 in the non-hydrocarbon gas. The carbon isotopic compositions of methane, ethane, and propane in the natural gas are −45.5 ‰, −26.4 ‰, and −24.3 ‰, respectively. Based on the regional geological background, the characteristics of potential source rocks and the geochemical characteristics of natural gas, it is considered that the natural gas in Well Mitan-1 is self-generated and self-accumulated oil-associated gas in Ordovician subsalt carbonate rocks. However, certain geochemical anomalies, such as the lighter methane carbon isotope value (δ13C1) and coal-type gas characteristics in ethane carbon isotope (δ13C2), raise questions. Further insights from thermal simulation experiments on hydrocarbon generation and the analysis of residual gas in rocks suggest a close relationship between the special geochemical characteristics of Well Mitan-1 and the presence of gypsum rocks. The ubiquitous gypsum rock serves a dual purpose: acting as an effective caprock, facilitating the retention of early-generated natural gas, and promoting the generation of heavy hydrocarbon gases (C2+) and H2S. The relatively low H2S content (less than 5 %) and higher C2+ content indicate that thermochemical sulfate reduction (TSR), if present, is not strong enough to significantly impact methane. The δ13C2 is identified as a potentially sensitive parameter for identifying TSR.

A significant amount of natural gas resources has been discovered in the Ordovician reservoirs under a thick layer of gypsum-salt strata as a result of ongoing research into deep natural gas in China’s Ordos Basin, however, the genetic type and source of the Ordovician sub-salt natural gas remain contentious. These limits understanding how the geochemical properties of the natural gas in Ordos Basin have evolved and how to best guide future exploration and development. Based on the components, carbon and hydrogen isotopic ratios of natural gas from the latest exploration wells, combined with the geological background, this study systematically analyzed the genetic types and sources of sub-salt natural gas of the central and eastern Ordos Basin. The results show that the Ordovician natural gas is mainly composed of hydrocarbon gases with low content of heavy hydrocarbons and dryness (CCH4/CCH4+) above 0.95, belonging to typical dry gas. Non-hydrocarbon gases mainly include N2 and CO2, and some natural gas samples contained H2S. The Ordovician sub-salt natural gas is primarily a self-generating and self-preserving oil-cracking gas with relatively high maturity (Ro ranging from 1.5% to 2.1%) mixed with coal-derived gas generated from upper-Paleozoic coal with relatively low maturity (Ro ranging from 1.1% to 1.5%). Due to the dual-source hydrocarbon supply, the Ordovician sub-salt reservoirs provide favorable gas accumulation conditions and development prospects. This study offers a reasonable explanation for the anomalous geochemical characteristics of the Ordovician sub-salt reservoirs in the Ordos Basin, and also may serve as a guide for future exploration of natural gas in the carbonate gypsum-salt sedimentary system in other basins.

This study aimed to explore the epidemic, clinical characteristics, and molecular and virulence attributes of Klebsiella pneumoniae serotype K54 (K54-Kp). A retrospective study was conducted on 328 strains of Klebsiella pneumoniae screened in a Chinese hospital from January 2016 to December 2019. The virulence genes and antibiotic resistance genes (ARGs) were detected by PCR, and a drug sensitivity test was adopted to detect drug resistance. Multilocus sequence typing (MLST) and PFGE were performed to determine the clonal correlation between isolates. Biofilm formation assay, serum complement-mediated killing, and Galleria mellonella infection were used to characterize the virulence potential. Our results showed that thirty strains of K54-Kp were screened from 328 strains of bacteria, with an annual detection rate of 2.29%. K54-Kp had a high resistance rate to antibiotics commonly used in the clinic, and patients with hepatobiliary diseases were prone to K54-Kp infection. MLST typing showed 10 sequence typing, mainly ST29 (11/30), which concentrated in the B2 cluster. K54-Kp primarily carried virulence genes of aerobactin, silS, allS, wcaG, wabG, and mrkD, among which the terW gene was closely related to ST29 (p

The Melut Basin is an important petroliferous basin in African Continent. The northern part of the basin is characterized by far-source oil accumulation with the oil generation in the Lower Cretaceous and the oil accumulation in the Paleogene. Clarifying the formation conditions and controlling factors of the far-source oil accumulations is the key to improve the exploration success rate and seek new potential areas of far-source oil accumulations in the Melut Basin. Based on the study of regional petroleum geological conditions and the analysis of key oil accumulations, the formation conditions, types, characteristics and potential exploration areas of far-source oil accumulations in the Melut Basin have been systematically studied. The results show, ①The north Melut Basin develops two types of far-source oil accumulations with different hydrocarbon charging patterns and accumulation modes in the Paleogene Yabus Formation, the far-source fault-lithology combination oil accumulations within the oil kitchen and the far-source fault-block oil accumulations outside the oil kitchen; ②The formation of far-source oil accumulations of the Yabus Formation inside oil kitchen depends on the coupling of three geological conditions, that is, the "two strong and one weak" three-stage rifting cycles, creating conditions for the formation of the Paleogene Yabus-Adar far-source reservoir-caprock combination; the development of oil-rich sag, providing necessary oil supply for the Yabus far-source traps; and the multi-stage rifting activities, providing vertical migration pathways for hydrocarbon charging in the Yabus far-source traps; ③The far-source oil accumulations inside oil kitchen are mainly charged by the vertical hydrocarbon infilling through the oil-source faults, and the oil-source faults are the main controlling factor for the hydrocarbon accumulation. The identification of oil-source faults and the evaluation of the lateral sealing capability of trap-controlling faults are the key elements for the far-source fault-block traps inside oil kitchen; ④The far-source oil accumulations outside oil kitchen are mainly charged by lateral hydrocarbon infilling from the oil-rich sag. The transportation ridges formed by sand-rich strata, fault blocks and paleo-uplifts control the hydrocarbon accumulation of far-source traps outside oil kitchen. The identification of transportation ridges and the study on the hydrocarbon charging extent are the main evaluation focus of far-source traps outside oil kitchen. The research results successfully guided the exploration deployment and in-depth exploration of far-source oil accumulations in the Melut Basin, and have a great implication on the exploration of far-source oil accumulations in the other petroliferous basins.

The hydrocarbon source rocks of the marine carbonates of the Ordovician Majiagou Formation in the Ordos Basin are generally in the high-overmature stage and are, therefore, not suitable for hydrocarbon thermal simulation experiments. Their hydrocarbon generation potential and hydrocarbon generation characteristics are not clearly understood. Meanwhile, Nordic Cambrian carbonates are similar in lithology, parent material type, and sedimentary age, and are in the low evolution stage, which is suitable for hydrocarbon thermal simulation experiments. Therefore, in this study, we selected the Nordic carbonates for the gold tube thermal simulation experiment to analyze the content and geochemical characteristics of the thermal simulation products. The experimental results are also compared and analyzed with the characteristics of thermal simulation products of Pingliang Formation mud shale (contemporaneous with the Majiagou Formation) and Shanxi Formation coal (in the upper part of the Majiagou Formation), which are similar to the Majiagou Formation in the Ordos Basin. The results showed that the Nordic carbonate has different hydrocarbon production characteristics from the mud shale of the Pingliang Formation of the same parent material type, and although the hydrocarbon production yields of the two are not very different, the carbonate still produces methane at 600 °C. The hydrocarbon production yield of the Nordic carbonates is almost equivalent to that of type-II2 kerogen, indicating that the hydrocarbon production yield is not related to lithology and only to the organic matter type; however, the Nordic carbonate can produce a large amount of H2S. The alkane carbon isotope changes are mainly controlled by the degree of thermal evolution, showing gradual heaviness with increasing temperature. No carbon isotope sequence reversal occurred during the thermal simulation, and its distribution range is roughly the same as that of the alkane carbon isotope composition of the mud shale of the Pingliang Formation. The ethane carbon isotope composition is as heavy as −21.2‰ at the high-temperature stage, showing similar coal-type gas characteristics. The addition of calcium sulphate (CaSO4) causes the TSR reaction to occur, which has a significant impact on the methane content under high maturity conditions, reducing its content by more than 50% at 600 °C. However, the addition of CaSO4 increases the yield of heavy hydrocarbon gases, such as ethane, and promotes the production of C6-14 hydrocarbons and C14+ hydrocarbons at high-temperature stages, and the addition of CaSO4 substantially increases the yield of H2, CO2, and H2S. The thermal simulation results have implications for the hydrocarbon formation mechanism of the early Paleozoic marine carbonate formation system in the stacked basins of the Ordos Basin and the Tarim Basin in China.

The Turpan-Hami Basin has been considered as the most typical coal-derived-oil basin in China for a long time. However, with the deepening exploration, this theory has caused increasing controversy and some scholars doubt that Permian or Jurassic dark mudstone may be the main source rocks. The origin uncertainty even restricts deciding the exploration direction. Taking the reservoirs of the northern piedmont belt as an example, this paper analyzed oil sources by the geochemical characteristic comparison of inclusions, crude oil, and source rocks. Combined with the previous studies, the hydrocarbon accumulation model is established. The results show that the geochemical characteristics of the inclusions and oil in most areas are obviously different. Most reservoirs are mixed-source reservoirs. The oil sources varied in different regions. In the area near Bogeda, C19+20TT and C28 sterane content in oil are high, indicating that coal and Permian lacustrine mudstone are main contributors. Far away from Bogeda, bounded by the thick coal seam of Xishanyao Formation, oil sources are quite different. Above it, C19+20TT is high and gammacerane and pregnane are low, C29>>C28>C27sterane, indicating that coal and carbonaceous mudstone are main sources. Under that, C21TT and C23TT content in the inclusions are high, C29≥C27>C28sterane, while C19+20TT and pregnane content in the oil are also high, indicating that it is a mixed oil system mainly derived from Jurassic lacustrine mudstone and coal. Lacustrine mudstone has higher contribution. This phenomenon is mainly related to different fault styles in different zones. Near Bogeda, strong stress caused vertical large faults developed, which connected Jurassic reservoirs and Permian source rocks. Far from Bogeda, the faults sliped along the thick coal seam, It is difficult for deep hydrocarbon to enter the shallow layer. In the future, it should be considered to look for the traps with relatively high-quality reservoir-cap combinations for exploration in the hydrocarbon supply window of effected hydrocarbon kitchens.

Tight sandstone gas reservoirs commonly contain water, so liquid loading often appears near wellbores, leading to production decline and even shutdown of gas wells. Therefore, the study on the change of water saturation near wellbores is of great significance to understanding the water production mechanisms of gas wells. In this paper, a set of physical simulation experiment procedures of identifying the change of water saturation near wellbores was designed according to the principle of radial well seepage of gas wells, and the production performance after vertical well fracturing in gas reservoirs was simulated by connecting tight cores with a diameter of 10.5 cm, 3.8 cm and 2.5 cm in series in a descending order of distance. According to the depressurizing production mode of gas wells, tubes with small diameters of 20, 30, 40 and 50 μm were used to simulate gas well tubing to control the gas production rate. And the change of water saturation near wellbore in the process of depletion production and its influencing factors were investigated. Finally, combined with actual data of production wells, the water saturation and water production of gas wells near wellbores and in different zones were calculated at the above four different small diameters of tubes and the changes thereof were also analyzed. The following results were obtained. First, each gas production rate corresponds to a critical water saturation. When the initial water saturation is lower than the critical value, the formation water flowing near the wellbore and in the middle zone can be carried out along with the production of gas and no liquid loading is formed. Second, when the initial water saturation is higher than the critical value, a large amount of formation water migrating from the far-wellbore zones accumulates near the wellbore, and thus liquid loading occurs at the bottom hole. Third, when the initial water saturation is equal to the critical value, the higher the gas production rate is, the more easily liquid loading tends to form near the wellbore. Fourth, for the same water saturation, water production increases and recovery factor decreases with the increase of gas production rate. In conclusion, the cumulative water production chart of a gas well generated by the physical simulation experiment method proposed in this paper agrees well with the water production behavior of the corresponding gas well. The research results are conducive to the effective prediction of gas well water production and can be used as guidance for the reasonable gas well water control. Keywords: Tight sandstone gas reservoir, Near the wellbore, Water saturation, Tube with a small diameter, Plane radial seepage, Physical simulation experiment, Water production rate of gas well, Gas production rate, Water control