Natural Gas Industry B最新文献

{"title":"A technical review of chemical reactions during CCUS-EOR in different reservoirs","authors":"Ali Satea ,&nbsp;Ye Tian ,&nbsp;Zuhao Kou ,&nbsp;Bo Kang ,&nbsp;Yulong Zhao ,&nbsp;Liehui Zhang","doi":"10.1016/j.ngib.2025.05.002","DOIUrl":"10.1016/j.ngib.2025.05.002","url":null,"abstract":"<div><div>Geochemical reactions play a vital role in determining the efficiency of carbon capture, utilization, and storage combined with enhanced oil recovery (CCUS-EOR), particularly through their influence on reservoir properties. To deepen the understanding of these mechanisms, this review investigates the interactions among injected CO₂, formation fluids, and rock minerals and evaluates their implications for CCUS-EOR performance. The main results are summarized as follows. First, temperature, pressure, pH, and fluid composition are identified as key factors influencing mineral dissolution and precipitation, which in turn affect porosity, permeability, and CO₂ storage. Second, carbonate minerals, such as calcite and dolomite, show high reactivity under lower temperature conditions, enhancing dissolution and permeability, while silicate minerals, including illite, kaolinite, quartz, and K-feldspar, are comparatively inert. Third, the formation of carbonic acid during CO₂ injection promotes dissolution, whereas secondary precipitation, especially of clay minerals, can reduce pore connectivity and limit flow paths. Fourth, mineral transformation and salt precipitation can further modify reservoir characteristics, influencing both oil recovery and long-term CO₂ trapping. Fifth, advanced experimental tools, such as Computed Tomography (CT) and Nuclear Magnetic Resonance (NMR) imaging, combined with geochemical modeling and reservoir simulation, are essential to predict petrophysical changes across scales. This review provides a theoretical foundation for integrating geochemical processes into CCUS-EOR design, offering technical support for field application and guiding sustainable CO₂ management in oil reservoirs.</div></div>","PeriodicalId":37116,"journal":{"name":"Natural Gas Industry B","volume":"12 3","pages":"Pages 264-278"},"PeriodicalIF":4.2,"publicationDate":"2025-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144501779","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Improved equation of state model for the phase behavior of CO2–hydrocarbon coupling nanopore confinements","authors":"Yuan Zhang ,&nbsp;Zijing Niu ,&nbsp;Fangfang Yang ,&nbsp;Zhanwei Ma","doi":"10.1016/j.ngib.2025.05.005","DOIUrl":"10.1016/j.ngib.2025.05.005","url":null,"abstract":"<div><div>In shale reservoirs, fluids are often confined within nanopores, leading to apparent effects on the properties and phase behavior of the fluid. However, previous studies have primarily focused on the effect of capillary pressure or adsorption on well performance, and only a very limited number of studies have researched the complex and coupled impact of confinement on capillarity, adsorption, and interactions between fluid molecules and pore walls. Therefore, in this study, an effective method is developed for evaluating the coupled effects of nanopore confinement on CO₂ injection performance. First, a comprehensive thermodynamic model that incorporates adsorption, capillary pressure, and molecule–wall interaction in nanopores by modifying the Peng-Robinson equation of state (PR-EOS) is proposed. Subsequently, the calculated critical properties of different components are validated against experimental measured data, illustrating that the developed model can accurately predict the properties of the components of CO₂–hydrocarbon systems. Numerical simulations of field-scale case studies were then performed and calibrated using a modified phase equilibrium model. Typical fluid properties were inputted to investigate the effect of nanopore confinement on the CO₂ injection performance. The results of this study show that the ultimate recovery factor increases by approximately 4.61 % at a pore size of 10 nm, indicating that nanopore confinement is advantageous to well performance. Light hydrocarbons undergo more intense mass transfer than heavy hydrocarbons. Furthermore, as the pore radius decreased from 100 nm to 10 nm, the CO₂ storage coefficient increased by 2.8 %. The findings of this study deepen the collective understanding of the effect of nanopore confinement on CO₂ displacement and storage, which has significant field-scale applications.</div></div>","PeriodicalId":37116,"journal":{"name":"Natural Gas Industry B","volume":"12 3","pages":"Pages 316-327"},"PeriodicalIF":4.2,"publicationDate":"2025-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144501783","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"A review of helium resources and development","authors":"Zhongjun Hu ,&nbsp;Jingyu Li","doi":"10.1016/j.ngib.2025.05.008","DOIUrl":"10.1016/j.ngib.2025.05.008","url":null,"abstract":"<div><div>Due to its unique properties, helium is critical in scientific research and industrial innovation, particularly in cryogenics; however, its scarcity necessitates efficient resource utilization. Through a review of the historical development of the helium industry, this study comprehensively evaluates the value, sources, production methods, supply dynamics, and sustainability challenges of helium. The processes and mechanisms of helium enrichment, along with effective exploration methods, are systematically analyzed here. We recommend focusing on the development of technologies for helium preservation, recovery, and extraction, particularly the extraction technology for helium-poor fields. Market analysis indicates that no imminent crisis in the global helium supply is expected before 2060. Thus, enhancing helium resource protection technologies is essential to improve its economic utilization and management while providing a timely reference for the scientific community.</div></div>","PeriodicalId":37116,"journal":{"name":"Natural Gas Industry B","volume":"12 3","pages":"Pages 356-367"},"PeriodicalIF":4.2,"publicationDate":"2025-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144501786","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Identification and classification of solid–liquid flow patterns in deviated and horizontal annuli","authors":"Di Yao ,&nbsp;Xiaofeng Sun ,&nbsp;Jingyu Qu","doi":"10.1016/j.ngib.2025.05.010","DOIUrl":"10.1016/j.ngib.2025.05.010","url":null,"abstract":"<div><div>During horizontal well drilling, the interaction between drilling fluid and cuttings entering the annulus generates diverse flow patterns. These solid–liquid two-phase flow patterns must be accurately predicted to optimize the determination of hydraulic parameters and improve the efficiency of cuttings transport. Accordingly, this study identified flow patterns and conducted transition experiments under different inclination angles using a visualized wellbore annulus apparatus (120 mm outer diameter/73 mm inner diameter). Through direct visual observations, four primary flow patterns were systematically classified on the basis of the solid–liquid two-phase flow behaviors identified in the experiments: stable bed (SB), sand wave (SW), sand dune (SD), and bed load (BL) flows. The experimental data were then used to construct flow pattern maps with solid/liquid phases as axes, after which the transition boundaries between different flow patterns were established.</div><div>The morphological characteristics and transition mechanisms of SB, SW, SD, and BL flows were systematically analyzed to develop three predictive models of the fluid dynamics principles governing these flow patterns’ transitions: (1) A transition boundary model of SB and SW flows was established using Kelvin–Helmholtz stability, for which a stability analysis of solid–liquid two-phase flow in deviated and horizontal annuli was carried out. (2) A transition boundary model of SW and SD flows was constructed through an analysis of the geometric features of sand waves in the annuli, with the critical ratio of the average height of a cuttings bed to its height after erosion being 0.45. (3) A traditional critical velocity model was refined by adjusting the von Karman constant to account for the effect of solid volume concentration, yielding a boundary model for the transition of SW or SD flow into BL flow. All the models were experimentally validated. Finally, we integrated the models to develop a unified method for identifying and classifying the patterns typifying solid–liquid two-phase flow in deviated and horizontal annuli.</div></div>","PeriodicalId":37116,"journal":{"name":"Natural Gas Industry B","volume":"12 3","pages":"Pages 386-404"},"PeriodicalIF":4.2,"publicationDate":"2025-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144502446","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"The influence of stress and natural fracture on a stimulated deep shale reservoir using the boundary element method","authors":"Songze Liao ,&nbsp;Ziming Zhang ,&nbsp;Jinghong Hu ,&nbsp;Yuan Zhang","doi":"10.1016/j.ngib.2025.05.004","DOIUrl":"10.1016/j.ngib.2025.05.004","url":null,"abstract":"<div><div>Hydraulic fracturing plays a critical role in enhancing shale gas production in deep shale reservoirs. Conventional hydraulic fracturing simulation methods rely on prefabricated grids, which can be hindered by the challenge of being computationally overpowered. This study proposes an efficient fracturing simulator to analyze fracture morphology during hydraulic fracturing processes in deep shale gas reservoirs. The simulator integrates the boundary element displacement discontinuity method and the finite volume method to model the fluid-solid coupling process by employing a pseudo-3D fracture model to calculate the fracture height. In particular, the Broyden iteration method was introduced to improve the computational efficiency and model robustness; it achieved a 46.6 % reduction in computation time compared to the Newton-Raphson method. The influences of horizontal stress differences, natural fracture density, and natural fracture angle on the modified zone of the reservoir were simulated, and the following results were observed. (1) High stress difference reservoirs have smaller stimulated reservoir area than low stress difference reservoirs. (2) A higher natural fracture angle resulted in larger modification zones at low stress differences, while the effect of a natural fracture angle at high stress differences was not significant. (3) High-density and long natural fracture zones played a significant role in enhancing the stimulated reservoir area. These findings are critical for comprehending the impact of geological parameters on deep shale reservoirs.</div></div>","PeriodicalId":37116,"journal":{"name":"Natural Gas Industry B","volume":"12 3","pages":"Pages 298-315"},"PeriodicalIF":4.2,"publicationDate":"2025-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144501781","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"CO2 flooding effects and breakthrough times in low-permeability reservoirs with injection–production well patterns containing hydraulic fractures","authors":"Nanlin Zhang ,&nbsp;Bin Cao ,&nbsp;Fushen Liu ,&nbsp;Liangliang Jiang ,&nbsp;Zhifeng Luo ,&nbsp;Pingli Liu ,&nbsp;Yusong Chen","doi":"10.1016/j.ngib.2025.05.007","DOIUrl":"10.1016/j.ngib.2025.05.007","url":null,"abstract":"<div><div>Comprehensive studies on CO₂ breakthrough times and flooding effects are crucial for optimizing CO₂ flooding strategies. This study utilized numerical simulations to investigate the effects of hydraulic fractures, permeability, and CO₂ injection rates on CO₂ breakthrough times and cumulative oil production. Nonlinear relationships among the respective variables were established, with Sobol method analysis delineating the dominant control factors. The key findings indicate that although hydraulic fracturing shortens CO₂ breakthrough time, it concurrently enhances cumulative oil production. The orientation of hydraulic fractures emerged as a pivotal factor influencing flooding effectiveness. Furthermore, lower permeability corresponds to lower initial oil production, while higher permeability corresponds to higher initial daily oil production. When reservoir permeability is 1 mD, oil production declines at 1000 days, and at 2 mD, it declines at 700 days. At a surface CO₂ injection rate of 10,000 m³/d, the daily oil production of a single well is approximately 7.5 m³, and this value remains relatively stable over time. The hierarchical order of influence on CO₂ breakthrough and rapid rise times, from highest to lowest, is permeability, well spacing, CO₂ injection rate, porosity, and hydraulic fracture conductivity. Similarly, the order of influence on cumulative oil production, from highest to lowest, is well spacing, porosity, permeability, CO₂ injection rate, and hydraulic fracture conductivity. This paper analyzed the impact of geological and engineering parameters on CO₂ flooding and oil production and provided insights to optimize CO₂ injection strategies for enhanced oil recovery.</div></div>","PeriodicalId":37116,"journal":{"name":"Natural Gas Industry B","volume":"12 3","pages":"Pages 339-355"},"PeriodicalIF":4.2,"publicationDate":"2025-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144501785","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Study on influences of geological and gas source conditions on gas-chimney hydrate accumulation using a reservoir numerical simulation method","authors":"Liang Zhang ,&nbsp;Fuyang Li ,&nbsp;Lu Yu ,&nbsp;Songhe Geng ,&nbsp;Chunjie Li ,&nbsp;Yujie Sun","doi":"10.1016/j.ngib.2025.05.003","DOIUrl":"10.1016/j.ngib.2025.05.003","url":null,"abstract":"<div><div>The Shenhu Area in the South China Sea is rich in oil and gas resources and has many vertical gas chimneys, making it an excellent geological environment for hydrate accumulation. This paper examines the geological conditions governing these gas-chimneys. A numerical simulation method based on the partial-equilibrium reaction model of hydrate was applied to simulate the migration of methane gas and the resultant hydrate formation when the gas enters the hydrate stability zone under the seabed through gas-chimneys. The dynamics of this gas-chimney hydrate accumulation were analyzed, and the influences of different factors—namely, the fluid supply time, rate, and temperature—on the formation temperature and ultimate distribution of the hydrate reservoir were evaluated. The simulation results indicate that the accumulation of hydrate via gas-chimneys is significantly affected by the temperature of the gas source, the transfer state of the methane gas, and the number of cycles of alternating gas–water invasion. Hydrate accumulation takes shape in an annular or semi-annular distribution pattern divided by fluid state as follows: a two-phase gas–water zone, a three-phase gas–water–hydrate zone, a two-phase water–hydrate zone, and a phase of water passing from the inside to the outside. Formation inclination and reservoir heterogeneity can greatly affect the distribution shape and abundance of the hydrate. A high fluid supply temperature, frequent alternating invasions of gas and water, and long-term pore-water invasion at a high rate can jointly cause a large central hydrate-free zone. In contrast, a long-term supply shutdown during the alternating gas–water invasion process, and a high gas rate with a low water rate in the gas-dominant invasion stage, foster the accumulation of hydrate in great abundance and with considerable thickness. The results of this study can help us understand the accumulation of hydrate through gas chimneys in the Shenhu Area.</div></div>","PeriodicalId":37116,"journal":{"name":"Natural Gas Industry B","volume":"12 3","pages":"Pages 279-297"},"PeriodicalIF":4.2,"publicationDate":"2025-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144501780","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Gas occurrence characteristics in marine-continental transitional shale from Shan23 sub-member shale in the Ordos Basin: Implications for shale gas production","authors":"Guangyin Cai ,&nbsp;Yifan Gu ,&nbsp;Dongjun Song ,&nbsp;Yuqiang Jiang ,&nbsp;Yonghong Fu ,&nbsp;Ying Liu ,&nbsp;Fan Zhang ,&nbsp;Jiaxun Lu ,&nbsp;Zhen Qiu","doi":"10.1016/j.ngib.2025.05.009","DOIUrl":"10.1016/j.ngib.2025.05.009","url":null,"abstract":"<div><div>Pore structure characteristics, gas content, and micro-scale gas occurrence mechanisms were investigated in the Shan₂³ sub-member marine-continental transitional shale of the southeastern margin of the Ordos Basin using scanning electron microscope images, low-temperature N₂/CO₂ adsorption and high-pressure mercury intrusion, methane isothermal adsorption experiments, and CH₄-saturated nuclear magnetic resonance (NMR). Two distinct shale types were identified: organic pore-rich shale (Type OP) and microfracture-rich shale (Type M). The Type OP shale exhibited relatively well-developed organic matter pores, while the Type M shale was primarily characterized by a high degree of microfracture development. An experimental method combining methane isothermal adsorption on crushed samples and CH₄-saturated NMR of plug samples was proposed to determine the adsorbed gas, free gas, and total gas content under high temperature and pressure conditions. There were four main research findings. (1) Marine-continental transitional shale exhibited substantial total gas content in situ, ranging from 2.58 to 5.73 cm³/g, with an average of 4.35 cm³/g. The adsorbed gas primarily resided in organic matter pores through micropore filling and multilayer adsorption, followed by multilayer adsorption in clay pores. (2) The changes in adsorbed and free pore volumes can be divided into four stages. Pores of &lt;5 nm exclusively contain adsorbed gas, while those of 5–20 nm have a high proportion of adsorbed gas alongside free gas. Pores ranging from 20 to 100 nm have a high proportion of free gas and few adsorbed gas, while pores of &gt;100 nm and microfractures are almost predominantly free gas. (3) The proportion of adsorbed gas in Type OP shale exceeds that in Type M, reaching 66 %. (4) Methane adsorbed in Type OP shale demonstrates greater desorption capability, suggesting a potential for enhanced stable production, which finds support in existing production well data. However, it must be emphasized that high-gas-bearing intervals in both types present valuable opportunities for exploration and development. These data may support future model validations and enhance confidence in exploring and developing marine-continental transitional shale gas.</div></div>","PeriodicalId":37116,"journal":{"name":"Natural Gas Industry B","volume":"12 3","pages":"Pages 368-385"},"PeriodicalIF":4.2,"publicationDate":"2025-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144501787","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Integrated wellbore-surface pressure control production optimization for shale gas wells","authors":"Xingyu Zhou ,&nbsp;Liming Zhang ,&nbsp;Ji Qi ,&nbsp;Yanxing Wang ,&nbsp;Kai Zhang ,&nbsp;Ruijia Zhang ,&nbsp;Yaqi Sun","doi":"10.1016/j.ngib.2025.03.011","DOIUrl":"10.1016/j.ngib.2025.03.011","url":null,"abstract":"<div><div>Shale gas wells often face challenges in maintaining continuous and stable production due to their coexistence with high- and low-pressure wells within the same development block, which leads to issues involving mixed-pressure flows. Traditional pipeline optimization methods used in conventional gas well blocks fail to address the unique needs of shale gas wells, such as the precise planning of airflow paths, pressure distribution, and compression. This study proposes a pressure-controlled production optimization strategy specifically designed for shale gas wells operating under mixed-pressure flow conditions. The strategy aims to improve production stability and optimize system efficiency. The decline in production and pressure for individual wells over time is forecasted using a predictive model that accounts for key factors of system optimization, such as reservoir depletion, wellbore conditions, and equipment performance. Additionally, the model predicts the timing and impact of liquid loading, which can significantly affect production. The optimization process involves analyzing the existing gathering pipeline network to determine the most efficient flow directions and compression strategies based on these predictions, while the strategy involves adjusting compressor settings, optimizing flow rates, and planning pressure distribution across the network to maximize productivity while maintaining system stability. By implementing these strategies, this study significantly improves gas well productivity and enhances the adaptability and efficiency of the gathering and transportation system. The proposed approach provides systematic technical solutions and practical guidance for the efficient development and stable production of shale gas fields, ensuring more robust and sustainable pipeline operations.</div></div>","PeriodicalId":37116,"journal":{"name":"Natural Gas Industry B","volume":"12 2","pages":"Pages 123-134"},"PeriodicalIF":4.2,"publicationDate":"2025-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143886561","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Hybrid genetic algorithm for parametric optimization of surface pipeline networks in underground natural gas storage harmonized injection and production conditions","authors":"Jun Zhou ,&nbsp;Zichen Li ,&nbsp;Shitao Liu ,&nbsp;Chengyu Li ,&nbsp;Yunxiang Zhao ,&nbsp;Zonghang Zhou ,&nbsp;Guangchuan Liang","doi":"10.1016/j.ngib.2025.03.009","DOIUrl":"10.1016/j.ngib.2025.03.009","url":null,"abstract":"<div><div>The surface injection and production system (SIPS) is a critical component for effective injection and production processes in underground natural gas storage. As a vital channel, the rational design of the surface injection and production (SIP) pipeline significantly impacts efficiency. This paper focuses on the SIP pipeline and aims to minimize the investment costs of surface projects. An optimization model under harmonized injection and production conditions was constructed to transform the optimization problem of the SIP pipeline design parameters into a detailed analysis of the injection condition model and the production condition model. This paper proposes a hybrid genetic algorithm generalized reduced gradient (HGA-GRG) method, and compares it with the traditional genetic algorithm (GA) in a practical case study. The HGA-GRG demonstrated significant advantages in optimization outcomes, reducing the initial cost by 345.371 × 10⁴ CNY compared to the GA, validating the effectiveness of the model. By adjusting algorithm parameters, the optimal iterative results of the HGA-GRG were obtained, providing new research insights for the optimal design of a SIPS.</div></div>","PeriodicalId":37116,"journal":{"name":"Natural Gas Industry B","volume":"12 2","pages":"Pages 234-250"},"PeriodicalIF":4.2,"publicationDate":"2025-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"143886570","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}