SPE Journal最新文献

{"title":"Hybrid Approach Using Physical Insights and Data Science for Stuck-Pipe Prediction","authors":"Tatsuya Kaneko, Tomoya Inoue, Yujin Nakagawa, Ryota Wada, Shungo Abe, Gota Yasutake, Kazuhiro Fujita","doi":"10.2118/218013-pa","DOIUrl":"https://doi.org/10.2118/218013-pa","url":null,"abstract":"Summary Early detection of stuck-pipe incidents is crucial because of the enormous costs of recovering from such incidents. Previous studies have leaned significantly toward a physics-based or data science approach. However, both approaches have challenges, such as the uncertainty of the physics-based model and the lack of data in the data science approach. In this study. we propose a hybrid approach using physical insights and data science and discuss the possibility of stuck-pipe prediction. The proposed method comprises two steps. In the first step, a data-driven model with physical insights is trained using the historical data of the in-situ well to estimate some of the drilling variables. In the second step, the risk of stuck-pipe occurrence (hereafter referred to as sticking risk) is calculated based on the historical and current measured data and the estimation of the trained model. This approach is expected to overcome the limitations of the previous methods as it allows the construction of a detection model tuned to the in-situ well. In the case studies, models for estimating the topdrive torque and standpipe pressure were constructed. The performance of the models is discussed using actual drilling data from drilling fields, including 21 stuck-pipe incidents during drilling operations. The proposed method was first examined using short-term output. The output confirmed that the sticking risk increased shortly (up to 20 hours) before the stuck-pipe incident occurred in 15 cases. This increase in sticking risk was consistent with physical considerations. Subsequently, this study examined the long-term output over several months; this was rarely done in previous studies. Even within this long-term output, some cases had good performance with only a few false alarms, while others had problems with many false alarms. For cases of low performance, several model improvements, such as adding mud information or making the learning and threshold-setting methods more robust to outliers, were found to have the potential to improve performance. The novelty of our research lies in creating a broad framework for the stuck-pipe prediction by using both physical insights and data science methods. The proposed hybrid approach demonstrated the potential to reduce false alarms and improve interpretability compared with previous methods. The framework is highly extensible, and further performance improvements can be expected in the future.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":"64 5-6","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"135455373","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":"Drill-In Fluid Optimization for Formation Damage Control Considering Salt Dissolution in Saline-Lacustrine Reservoirs","authors":"Qigui Tan, Bin Yang, Lijun You, Yili Kang, Haoping Peng, Fuquan Song, Chong Lin","doi":"10.2118/218018-pa","DOIUrl":"https://doi.org/10.2118/218018-pa","url":null,"abstract":"Summary Salt dissolution induced by drill-in fluid loss is a frequent occurrence in saline-lacustrine reservoirs, which can potentially result in serious formation damage. In light of this, an experimental study was conducted to investigate the salt mineral dissolution and dynamic damage in the rock samples collected from a saline-lacustrine carbonate reservoir and the response of pore-fracture structures using the in-situ drill-in fluids. The study further involved analyzing the formation-damage-control (FDC) ability of the in-situ drill-in fluids. The results indicated that although salt dissolution significantly increased the pore size of the tight matrix and the width of natural fractures, improving the conductivity of seepage channels, the increase in pore-fracture size may have greatly aggravated the drill-in fluid loss during the process. The continuous serious filtrate loss, lower pressure-bearing capacity of the plugging zone, and lower permeability recovery rate (PRR) of rock indicated poor FDC performance of in-situ brine drilling fluids for the salt-dissolved core samples. The FDC performance of drill-in fluids for saline-lacustrine carbonate reservoirs was optimized based on the response of reservoir pore-fracture structure to salt dissolution and the theory of slightly underbalanced activity. The experimental results showed that the optimized drill-in fluids had better FDC ability, with an average PRR increase of 14.04%. Field application indicated that the optimized drill-in fluids reduced the drill-in fluid loss by 76.48%, shortened the drilling cycle by 45.20%, and increased the initial production capacity per well by 7.70%. This study can provide insightful guidance to optimize the FDC performance of drill-in fluids for saline-lacustrine hydrocarbon reservoirs during drilling.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":"129 3","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"135566148","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":"Visual Laboratory Tests: Effect of Operational Parameters on Proppant Transport in a 3D Printed Vertical Hydraulic Fracture with Two-Sided Rough Surfaces","authors":"Jun Li, Xu Han, Siyuan He, Mingyi Wu, Xinqian Lu","doi":"10.2118/218007-pa","DOIUrl":"https://doi.org/10.2118/218007-pa","url":null,"abstract":"Summary Hydraulic fracturing technology is an effective measure that can improve oil and gas production and achieve enormous economic benefits owing to it phenomenally increasing the oil recovery from the low intrinsic permeability of the compact rock. Good placement and distribution of the proppant in the hydraulic fractures can provide successful stimulation for a well, which is essential for applying the hydraulic fracturing process. Previous studies extensively explored proppant placement, distribution, and operational factors in simplified smooth surface fracture models. However, the operational factors such as pump rate, proppant concentration, proppant size, fluid viscosity, and inlet condition (pulse time) involved in proppant placement and distribution in realistic rough surfaces of fractures are not clearly understood. In particular, the law of proppant transport in a two-sided rough surface of fracture with changes in the aforementioned operational factors was unclear. Hence, in this study, we investigated the effect of these operational factors on proppant placement and transport in both the smooth surface fracture model and the two-sided rough surface fracture model. The results suggested that the traditional law of proppant transport drawn on the smooth surface fracture model did not apply to the two-sided rough surface model. It is suggested that selecting corresponding variables was needed to reduce the risk of proppant bridging and offer a better channel ratio.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":"9 2","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"135371874","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":"Investigation of Carbonate Matrix Damage and Remediation Methods for Preformed Particle Gel Conformance Control Treatments","authors":"Abdulaziz A. Almakimi, Junchen Liu, Baojun Bai, I. Hussein","doi":"10.2118/210311-pa","DOIUrl":"https://doi.org/10.2118/210311-pa","url":null,"abstract":"Preformed particle gels (PPGs) have been widely applied to control excessive water production in mature oil fields with fractures or fracture-like features, especially in sandstones, but with limited attention to carbonates. However, a vital concern arises regarding the potential damage of PPGs on the adjacent matrix that might promote negative results. This paper comprehensively evaluates PPGs’ potential damage to the carbonate matrix and seeks design optimization solutions. Filtration tests were applied to compare PPGs’ penetration into the matrix under different sets of conditions. The filtration regimes were defined by filtration curves, and the gel damage on the matrix was determined by permeability measurement results. Experiments were conducted to investigate the efficiency of an oxidizer as a remediation method to remove the damage. The qualitative description of gel particles’ invasion and plugging behavior in the carbonate matrix was presented based on the analysis of filtration test results and permeability measurements. The results show that the swollen gel filtration curves can be divided into three regions: prior-filter-cake, filter-cake-building, and stable stages according to the gel particles’ response to the injection pressure and effluent flow rates. PPGs can form cakes on the rock surface to prevent particles’ further penetration into the carbonate matrix, and the penetration was only limited to less than a few millimeters. The smallest gel particles (50–70 US mesh size) were more likely to form external and internal filter cakes at higher pressure values (700 psi) and result in more damage to the matrix. To restore the matrix permeability after filtration tests, oxidizer soaking proved to be a reliable solution. In all, the results indicated that unintentional matrix permeability damage induced by gel injection is generally unavoidable but conditionally treatable.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":"68 1","pages":""},"PeriodicalIF":3.6,"publicationDate":"2023-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139301611","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":"Nonionic Surfactant Blends for Enhanced Oil Recovery in High-Temperature Eagle Ford Reservoir","authors":"Elsie B. Ladan, David S. Schechter","doi":"10.2118/218382-pa","DOIUrl":"https://doi.org/10.2118/218382-pa","url":null,"abstract":"Nonionic surfactants have proven successful and cost-effective in enhancing production from conventional and unconventional reservoirs. However, studies into the mechanism and performance of nonionic surfactants have been limited to reservoirs with temperatures below 200°F due to the temperature-dependent physiochemical properties, especially cloudpoint (CP). In this study, nonionic-ionic surfactant blends were designed to create nonionic systems with cloudpoint temperatures (CPTs) above 300°F for wettability alteration in high-temperature reservoirs like the Eagle Ford Shale in Texas, USA. Through CP, wettability, interfacial tension (IFT), and spontaneous imbibition experiments, 22 commercial surfactant samples (individual and blends) were investigated. Results showed that the amount of ionic cosurfactant affected thermal stability, with increasing concentration leading to increasing CPT. Wettability alteration was dependent not only on temperature but also on the class of ionic cosurfactant. Cationic cosurfactants were superior at improving nonionic surfactants’ thermal stability. However, they resulted in oil-wet contact angles (CAs) with increasing temperature. On the other hand, anionic cosurfactants displayed better synergy in terms of wettability alteration, creating strongly water-wet and intermediate-wet CAs at high temperatures. Therefore, the focus was placed on nonionic-anionic surfactant blends for the reservoir samples used in this study. Stable surfactant blends with CPTs from 316°F to 348°F were successfully created for enhanced oil recovery (EOR) applications at high-temperature conditions. Spontaneous imbibition studies using these blends indicated improved recovery by up to 173%. This work validates and builds upon previous studies of surfactant performance, wettability alteration, and IFT while providing new insight into nonionic surfactant blends at temperature conditions not currently available in the literature. It also serves as a template for the surfactant screening and selection process when considering nonionic surfactants.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":"208 1","pages":""},"PeriodicalIF":3.6,"publicationDate":"2023-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139304580","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":"Proof of Concept in a Full-Scale Field Test for the Novel Micro-Turbine Drilling Technology from a Cased Borehole in Granite Rock","authors":"Niklas Geissler, Florian Garsche, Vitalii Samus, Berker Polat, Francesca Di Mare, Rolf Bracke","doi":"10.2118/218378-pa","DOIUrl":"https://doi.org/10.2118/218378-pa","url":null,"abstract":"Summary Exploration risks of geothermal projects are high, as required economic production rates are often not achieved. Stimulation methods from the oil and gas industry, such as radial jet drilling (RJD), which can be used to cost-effectively create flow paths around a main borehole, are usually not applicable in geothermal applications due to especially hard reservoir formations. Because of that, a novel technology called micro-turbine drilling (MTD®) has been developed, which allows for the drilling of micro-sidetracks from cased boreholes even into very hard reservoir rock. The approach is based on the principles of the RJD operation. However, instead of a jetting nozzle, a microdrilling turbine is used to drive a bit that mechanically drills rock. This study presents the results of the proof of concept for MTD, which was conducted in the BedrettoLab in Switzerland at a depth of up to 1,053 ft (321 m) in granite rock.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":"50 8","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"135615523","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 System to Detect Oilwell Anomalies Using Deep Learning and Decision Diagram Dual Approach","authors":"P. E. Aranha, L. G. O. Lopes, E. S. Paranhos Sobrinho, I. M. N. Oliveira, J. P. N. de Araújo, B. B. Santos, E. T. Lima Junior, T. B. da Silva, T. M. A. Vieira, W. W. M. Lira, N. A. Policarpo, M. A. Sampaio","doi":"10.2118/218017-pa","DOIUrl":"https://doi.org/10.2118/218017-pa","url":null,"abstract":"Summary Detecting unexpected events is a field of interest in oil and gas companies to improve operational safety and reduce costs associated with nonproductive time (NPT) and failure repair. This work presents a system for real-time monitoring of unwanted events using the production sensor data from oil wells. It uses a combination of long short-term memory (LSTM) autoencoder and a rule-based analytic approach to perform the detection of anomalies from sensor data. Initial studies are conducted to determine the behavior and correlations of pressure and temperature values for the most common combinations of well valve states. The proposed methodology uses pressure and temperature sensor data, from which a decision diagram (DD) classifies the well status, and this response is applied to the training of neural networks devoted to anomaly detection. Data sets related to several operations in wells located at different oil fields are used to train and validate the dual approach presented. The combination of the two techniques enables the deep neural network to evolve constantly through the normal data collected by the analytical method. The developed system exhibits high accuracy, with true positive detection rates exceeding 90% in the early stages of anomalies identified in both simulated and actual well production scenarios. It was implemented in more than 20 floating production, storage, and offloading (FPSO) vessels, monitoring more than 250 production/injection subsea wells, and can be applied both in real-time operation and in testing scenarios.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":"25 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"135456015","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":"Fiber Stiffness: An Essential Parameter of the Effectiveness of Fiber-Based Lost Circulation Materials—A CFD-DEM Numerical Investigation","authors":"Cassian Henriques, A. Dahi Taleghani","doi":"10.2118/218377-pa","DOIUrl":"https://doi.org/10.2118/218377-pa","url":null,"abstract":"Fiber materials have become an attractive choice for lost circulation material (LCM) applications recently. While there has been significant attention on the size, aspect ratio, and size distribution of fibers, the stiffness or basically the effect of their deformability on the sealing capability has not been studied rigorously. Experimental evaluations of fibers with different material properties could be a cumbersome, time-consuming, and expensive process. Most laboratory studies are limited to one or just a few different types of materials. Hence, a novel two-way-coupled computational fluid dynamics and discrete element method (CFD-DEM)-based numerical model is used to overcome this limitation and to simulate motion, collision, deformation, and finally entanglement of individual LCM fibers moving with the fluid along a fracture. Fiber stiffness is determined by the Young’s modulus, the fiber diameter, and the fiber length. Therefore, we investigate this effect in a parametric study with a focus on the impact of the length, diameter, and Young’s modulus of the fiber on their sealing capability. An in-depth analysis reveals that the bridging mechanism for fiber LCM changes with the stiffness of the fiber. Two distinct bridging mechanisms dependent on the fiber stiffness for fiber LCMs are identified. Based on the simulation results, we developed a conceptual model for the different mechanisms that fibers use for bridge initiation. It is also observed that in determining LCM effectiveness, both the fiber stiffness and the fiber dimensions go hand in hand. Stiff fibers were associated with greater maximum plugging pressures (MPPs). The effect of using a mix of soft and stiff fibers on fracture plugging effectiveness has been evaluated. The fiber LCM effectiveness as a consequence of the bending stiffness on bridging larger fractures is also investigated. lost circulation materials, fibers, fracture sealing, bridging mechanism","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":"4 1","pages":""},"PeriodicalIF":3.6,"publicationDate":"2023-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139303701","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":"Investigation of the Effect of Residual Oil and Wettability on Sulfonated Polymer Retention in Carbonate under High-Salinity Conditions","authors":"Umar Alfazazi, Nithin Chacko Thomas, Emad Walid Al-Shalabi, Waleed AlAmeri","doi":"10.2118/207892-pa","DOIUrl":"https://doi.org/10.2118/207892-pa","url":null,"abstract":"Summary Polymer flooding in carbonate reservoirs is greatly affected by polymer retention, which is mainly due to adsorption by polymer-rock surface interactions. Consequently, this leads to a delay in polymer front propagation and related oil recovery response. This work investigates the effects of residual oil (Sor) and wettability on sulfonated-based (ATBS) polymer retention under the conditions of high salinity and moderate temperature. Polymer single- and two-phase dynamic adsorption tests as well as bulk and in-situ rheological experiments were conducted on outcrop carbonate cores in the presence of a high-salinity brine of 243,000 ppm at a temperature of 50°C. A total of four corefloods were conducted on Indiana limestone core samples with similar petrophysical properties. Overall, polymer adsorption was found to be low and within the acceptable range for application in carbonate reservoirs in the absence and presence of Sor. Furthermore, the polymer adsorption and in-situ rheology tests highlighted the significance of oil presence in the core samples, where retention was found to be around 40–50 µg/g-rock and 25–30 µg/g-rock in the absence and at Sor, respectively. An additional 50% reduction in retention was observed on the aged core sample that is more oil-wet. Polymer retention/adsorption was measured by double slug and mass balance techniques, and the results from both methods were in agreement with less than 7% difference. Inaccessible pore volume (IPV) was also calculated based on the double slug method and was found to be in the range of 23% to 28%, which was qualitatively supported by in-situ saturation monitoring obtained from an X-ray computed tomography (CT) scanner. The ATBS-based polymer showed excellent results for applications in carbonate without considerable polymer loss or plugging. This paper provides valuable insights into the impacts of residual oil and wettability on polymer adsorption, supported by CT in-situ saturation monitoring, which is necessary to avoid unrepresentative and inflated polymer retentions in oil reservoirs.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":"84 11","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"135270651","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 Hybrid Data-Physics Framework for Reservoir Performance Prediction with Application to H2S Production","authors":"Olwijn Leeuwenburgh, Paul J. P. Egberts, Eduardo G. D. Barros, Lukasz P. Turchan, Fahad Dilib, Ole-Petter Lødøen, Wouter J. de Bruin","doi":"10.2118/218000-pa","DOIUrl":"https://doi.org/10.2118/218000-pa","url":null,"abstract":"Summary Model-based reservoir management workflows rely on the ability to generate predictions for large numbers of model and decision scenarios. When suitable simulators or models are not available or cannot be evaluated in a sufficiently short time frame, surrogate modeling techniques can be used instead. In the first part of this paper, we describe extensions of a recently developed open-source framework for creating and training flow network surrogate models, called FlowNet. In particular, we discuss functionality to reproduce historical well rates for wells with arbitrary trajectories, multiple perforated sections, and changing well type or injection phase, as one may encounter in large and complex fields with a long history. Furthermore, we discuss strategies for the placement of additional network nodes in the presence of flow barriers. Despite their flexibility and speed, the applicability of flow network models is limited to phenomena that can be simulated with available numerical simulators. Prediction of poorly understood physics, such as reservoir souring, may require a more data-driven approach. We discuss an extension of the FlowNet framework with a machine learning (ML) proxy for the purpose of generating predictions of H2S production rates. The combined data-physics proxy is trained on historical liquid volume rates, seawater fractions, and H2S production data from a real North Sea oil and gas field, and is then used to generate predictions of H2S production. Several experiments are presented in which the data source, data type, and length of the history are varied. Results indicate that, given a sufficient number of training data, FlowNet is able to produce reliable predictions of conventional oilfield quantities. An experiment performed with the ML proxy suggests that, at least for some production wells, useful predictions of H2S production can be obtained much faster and at much lower computational cost and complexity than would be possible with high-fidelity models. Finally, we discuss some of the current limitations of the approach and options to address them.","PeriodicalId":22252,"journal":{"name":"SPE Journal","volume":"8 6","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-11-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"135371875","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}