Geoenergy Science and Engineering最新文献

{"title":"Cuttings vs cores: are cuttings a reliable predictor of caprock porosity?","authors":"Joel P. Bensing ,&nbsp;David Misch ,&nbsp;Lukas Skerbisch ,&nbsp;Wolfgang Hujer ,&nbsp;Thomas Gumpenberger","doi":"10.1016/j.geoen.2025.214180","DOIUrl":"10.1016/j.geoen.2025.214180","url":null,"abstract":"<div><div>Repurposing depleted oil and gas fields for underground storage may play an important role in the energy transition. Existing sample materials collected during the exploration and development phases of oil and gas fields may prove useful for answering questions for the safe repurposing of depleted fields. In the case of questions for caprock integrity, drill cuttings are typically available whereas core material is often not. In this study, porosity is measured on both cutting and core samples from the caprock interval of the same well. Porosity was measured by three different methods, and in each method the cuttings show much higher porosity than the core samples. Furthermore, comparison of the data to published mudstone compaction trends (porosity-depth trends) from the basin also indicate excess porosity for the cuttings samples. Based on scanning electron microscopy (SEM) images, the cuttings have persistent dilated grain contacts (intergranular cracks) that are not observed in the core samples. This indicates the excess porosity is due to volumetric changes and damage in the cuttings samples. Based on the results of this study, cutting samples from seal rock intervals are likely to produce erroneously high porosity values, and core pieces or well-established basin-wide trends are a better predictor of seal rock porosity.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"257 ","pages":"Article 214180"},"PeriodicalIF":4.6,"publicationDate":"2025-09-02","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145010876","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Research on shale acid fracturing reservoir simulation technology: A critical review","authors":"Ning Qi ,&nbsp;Jianfeng Liu ,&nbsp;Xuesong Li ,&nbsp;Ping Jiang ,&nbsp;Aihua Li","doi":"10.1016/j.geoen.2025.214157","DOIUrl":"10.1016/j.geoen.2025.214157","url":null,"abstract":"<div><div>The production potential of shale reservoirs is significantly influenced by the application of reservoir stimulation technology. Compared to conventional hydraulic fracturing reservoir reforming techniques, acid fracturing emerges as a promising alternative due to its remarkable permeability enhancement effects, reduced difficulty in fracturing deep shale formations, enhanced propensity for intricate seam network formation, and effective propping without the need for proppant. This comprehensive review presents an in-depth analysis of the existing literature on shale acidizing. The review delves into the specific changes observed in shale's mineral composition, microstructure, mechanical properties, gas adsorption characteristics, and wettability following acidification. It critically analyses various numerical simulation methods (e.g., FEM, XFEM, BEM, FDM, DEM, etc.) and models (e.g., Two-scale continuum model, Fractal model, Lumped model, etc.) employed in shale acidification and fracturing simulations. Field case studies demonstrate that acid fracturing is highly effective in shale reservoirs with high carbonate mineral content and well-developed natural fractures, yet it yields limited long-term benefits in silica-dominated reservoirs. Future research should focus on optimizing acid system designs, developing multiphysics coupled models, and investigating synergistic effects between CO₂ fracturing and acid fracturing to advance efficient shale reservoir stimulation technologies. In conclusion, this review synthesizes the current challenges encountered in shale acid fracturing theoretical research and field applications, while simultaneously identifying key areas for future research endeavors.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"257 ","pages":"Article 214157"},"PeriodicalIF":4.6,"publicationDate":"2025-09-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145049127","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Fluid pressure induced shear slip and permeability changes in fractured wellbore cement","authors":"Mahya Hatambeigi ,&nbsp;Ishtiaque Anwar ,&nbsp;David L. Lord ,&nbsp;David Hart ,&nbsp;Mahmoud Reda Taha ,&nbsp;John C. Stormont","doi":"10.1016/j.geoen.2025.214179","DOIUrl":"10.1016/j.geoen.2025.214179","url":null,"abstract":"<div><div>Fluid pressure changes can induce shear displacements within a fractured wellbore cemented annulus which may, in turn, alter the fracture permeability and consequently the leakage rate through the wellbore system. This study examined the effects of fluid pressure on shear displacements and permeability of fractured cement samples through a series of pore pressure induced shear tests. The samples were subject to shear stress in a triaxial cell, and a fluid pressure gradient was maintained across the sample. The fluid pressure was increased, reducing the normal stress and fracture shear strength, which eventually induced fracture shear slip. The shear displacement was measured, and the fracture permeability and hydraulic aperture were interpreted. The fluid pressure at which the shear displacements occur was found to depend on the applied external stress, and the fracture permeability changed significantly with the shear displacements. A shear slip criterion and fracture friction coefficient of μ=0.66 were interpreted from the pore pressure induced shear tests. Direct shear tests on comparable samples produced relatively higher friction coefficient which was attributed to the accumulation of wear products in the fracture. Results from the experimental work were used as input to an analytical model to evaluate the possibility of pore pressure induced shear displacement under external stress and internal pressure conditions of a fractured cemented annulus associated with an underground storage facility. Additionally, the critical pore pressure that could cause shear slip in the cement fracture was found to be impacted by the fracture location and orientation.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"257 ","pages":"Article 214179"},"PeriodicalIF":4.6,"publicationDate":"2025-08-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145005278","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Effect of rice husk ash on the compressive strength and microstructural characteristics of low-density cement slurry under different temperature conditions","authors":"Shaojun Zheng ,&nbsp;Huaimeng Gu ,&nbsp;Tianle Liu ,&nbsp;Tian Dai ,&nbsp;Guosheng Jiang ,&nbsp;Hao Xu ,&nbsp;Hourun Lai ,&nbsp;Mingsheng Chen ,&nbsp;Tao Wan","doi":"10.1016/j.geoen.2025.214178","DOIUrl":"10.1016/j.geoen.2025.214178","url":null,"abstract":"<div><div>This study investigated the potential of highly doped (50 %) rice husk ash (RHA) as a sustainable alternative to conventional oil well cement and hollow glass microsphere (HGM) in formulating a novel, environmentally friendly, low-density cementing slurry (LDCS) for wellbore applications in deepwater oil and gas wells. Two groups of LDCSs were evaluated in this study, G100H20 and G100H20R50, which were doped with 0 % and 50 % RHA. The mechanical properties, mineral composition and microstructural characteristics of LDCS cured at 20 °C, 50 °C and 80 °C for 1, 7, 28, 56 days were characterized by X-ray Diffraction (XRD), thermogravimetric analysis (TGA), X-ray micro-computed tomography (Micro-CT) and scanning electron microscope-energy dispersive spectrometer (SEM-EDS), etc. Besides, a comparative analysis of Material Sustainability Indicators (MSIs) and associated costs was conducted. The results showed that the compressive strength of G100H20R50 is lower than G100H20 when cured at 20 °C and 50 °C. However, the compressive strength of G100H20R50 exceeds G100H20 when cured at 80 °C for 56 d. The introduction of RHA inhibits the transformation of the hydrated C-S-H gel to the porous α-type hydrated dicalcium silicate crystals (α-C₂-S-H) and optimizes the pore size distribution of the cement slurries. The internal curing effect of RHA extends the hydration time and improves the durability of the cement system. MSIs and cost analyses show that G100H20R50, prepared with zero net CO₂ emissions and low-cost RHA, is both environmentally friendly and economical, reducing the environmental impact of RHA.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"257 ","pages":"Article 214178"},"PeriodicalIF":4.6,"publicationDate":"2025-08-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145005277","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Surrogate model for fracture propagation in heterogeneous reservoirs based on generative neural networks","authors":"Yutong Wu ,&nbsp;Zhonghui Liu ,&nbsp;Yuxuan Liu ,&nbsp;Liansong Wu ,&nbsp;Xinggui Yang ,&nbsp;Jianchun Guo","doi":"10.1016/j.geoen.2025.214169","DOIUrl":"10.1016/j.geoen.2025.214169","url":null,"abstract":"<div><div>Accurate and efficient simulation of fracture propagation patterns is crucial for optimizing hydraulic fracturing design. However, the impact of rock mechanics heterogeneity and interfaces on fracture propagation is highly complex. Traditional numerical simulation methods often suffer from slow convergence, high computational cost, and the need for manual adjustments of physical parameters under heterogeneous conditions, making fracture propagation simulation a challenging task. To address these issues, this study proposes a fracture propagation prediction method based on a generative neural network named Fracture Propagation GAN (FPGAN). By employing the FPGAN model as a surrogate for fracture propagation simulation, the efficiency of simulating fracture propagation under heterogeneous conditions is significantly enhanced while maintaining the accuracy of the original images. Fracture propagation time-series images under various mechanical parameters were generated using the Finite Discrete Element Method (FDEM) to construct both basic and complex datasets of fracture propagation images. The FPGAN model was trained on these datasets to enable rapid prediction of fracture morphologies under heterogeneous conditions. Experimental results demonstrate that the FPGAN model can predict hydraulic fracture propagation images for any given combination of mechanical parameters within 1 min, achieving computational efficiency improvements of several orders of magnitude compared to traditional numerical methods. The proposed FPGAN model provides a robust foundation for analyzing the influence of different mineral compositions on fracture generation and exhibits significant potential in hydraulic fracture propagation simulation.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"257 ","pages":"Article 214169"},"PeriodicalIF":4.6,"publicationDate":"2025-08-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145005276","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"A physics-boosted transfer learning framework for fracturing pressure prediction with scarce data","authors":"Lei Hou ,&nbsp;Jiangfeng Luo ,&nbsp;Egor Dontsov ,&nbsp;Zhengxin Zhang ,&nbsp;Alexander Valov ,&nbsp;Fengshou Zhang ,&nbsp;Xiaobing Bian ,&nbsp;Liang Fu","doi":"10.1016/j.geoen.2025.214176","DOIUrl":"10.1016/j.geoen.2025.214176","url":null,"abstract":"<div><div>Accurately predicting fracturing pressure is critical for optimizing the safety and efficiency of hydraulic fracturing operations, particularly in newly developed blocks where data scarcity poses significant challenges. Traditional machine learning methods require large, high-quality datasets to train algorithms. To address these limitations, this study presents physics-boosted transfer learning frameworks designed to enhance fracturing pressure prediction in data-scarce scenarios. By integrating a gated recurrent unit (GRU) deep learning model with physical modeling principles, three transfer learning frameworks were developed and evaluated, including a pure data-driven framework, a hybrid-modelling framework, and a physics-informed framework. Field data from only three shale gas wells were utilized to train the GRU algorithm – simulating real-field data-scarcity scenarios. Fine-tuning technologies are optimized based on the pure data-driven framework. The physics-informed framework demonstrated superior performance, achieving root mean square errors (RMSE) as low as 2–3 MPa, significantly outperforming both the pure data-driven and hybrid frameworks in terms of accuracy, stability, and adaptability. By bridging the gap between data-driven methods and physical modeling, this new framework offers a robust solution, for improving operational safety and cost-effectiveness in hydraulic fracturing, particularly under data-scarce conditions.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"257 ","pages":"Article 214176"},"PeriodicalIF":4.6,"publicationDate":"2025-08-27","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144989917","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Rapid screening of saline aquifers for CO2 sequestration: A focus on storage capacity and injectivity index","authors":"Milad Balvayeh ,&nbsp;Ali Ramezani ,&nbsp;Behzad Rostami","doi":"10.1016/j.geoen.2025.214174","DOIUrl":"10.1016/j.geoen.2025.214174","url":null,"abstract":"<div><div>This study aims to develop a robust and accurate method for evaluating the storage capacity and injectivity index for CO₂ storage in saline aquifers. The screening out procedure includes defining objective functions assessing candidates' feasibility, such as storage capacity and injectivity. Aquifers should be able to store a large volume of CO₂ and enable efficient CO₂ injection. To achieve this, each objective's technical parameters need to be identified and understood. Researchers reviewed past studies to identify global key parameters and their ranges. Based on the information, a series of simulations were conducted using design of experimental and statistical techniques to further investigate the most important parameters. The results of the simulations show that compressibility, depth, and pressure gradient have the greatest impact on storage capacity. Graphs were created using these parameters to quickly estimate storage efficiency. Within the studied parameter range, the maximum storage efficiency, defined as the ratio of storable pore volume to total pore volume, was approximately 14 %. For injectivity, permeability, thickness, and depth were identified as the most important parameters. The flow capacity, which is the product of permeability and thickness (kh), was used for screening in this section. It was determined that structures with kh values less than 900 mD-m are almost uneconomical for projects. Conversely, flow capacity values above 15000 mD-m indicate favorable conditions for project implementation. For other values, the economic feasibility of the project can be assessed without further simulation by using the estimated equations and graphs derived from the study. Finally, after reviewing and comparing the model results with operational cases, it was determined that the presented model has the ability to be quickly and practically used in the field.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"256 ","pages":"Article 214174"},"PeriodicalIF":4.6,"publicationDate":"2025-08-27","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144921602","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Advancing CO2 solubility prediction in aqueous solutions: A machine learning approach for CCUS application","authors":"Gideon Gyamfi,&nbsp;Xiaoli Li","doi":"10.1016/j.geoen.2025.214175","DOIUrl":"10.1016/j.geoen.2025.214175","url":null,"abstract":"<div><div>Accurately predicting CO₂ solubility in aqueous solution (pure water and brines) is essential for optimizing carbon capture, utilization, and storage (CCUS) processes. In this study, the experimental dataset consists of various salts, specifically sodium chloride (NaCl), calcium chloride (CaCl₂), magnesium chloride (MgCl₂), potassium chloride (KCl), sodium bicarbonate (NaHCO₃), sodium sulfate (Na₂SO₄), potassium carbonate (K₂CO₃), and magnesium sulfate (MgSO₄). The comprehensive dataset encompasses a range of pressures (0.1–50 MPa), temperatures (274–453 K), and salinity levels (0–15 mol/kg). The objective is to develop a robust predictive model for CO₂ solubility utilizing advanced machine learning methodologies, specifically Random Forest (RF), Gradient Boosting (GB), and an Ensemble algorithm. Data preprocessing entails standardization, outlier elimination, and the conversion of salinity to ionic strength via the Debye-Hückel method. Additionally, hyperparameter optimization and cross-validation are employed to enhance the robustness of the model and mitigate overfitting. Among the implemented models, the Ensemble model exhibits the best performance, statistically, achieving R-square values of 0.9916, 0.9832, and 0.9934 and mean squared error values of 0.0078, 0.0122, and 0.0056 for training, validation, and testing datasets respectively. Sensitivity analyses of feature importance indicate that pressure is the predominant factor influencing CO₂ solubility, followed closely by ionic strength and temperature. Furthermore, the study identifies potassium carbonate (K₂CO₃) as exhibiting a notably high affinity for CO₂, especially at a temperature of 353 K. Visualizing predictive trends in CO₂ solubility across varying concentrations of ionic strength, temperature, and pressure substantiates the models’ capacity to accurately capture the intricate interactions among these parameters. These results provide a robust and accurate framework for predicting CO₂ solubility, advancing CCUS strategies, and enhancing understanding of CO₂ behavior in brine systems under diverse conditions.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"257 ","pages":"Article 214175"},"PeriodicalIF":4.6,"publicationDate":"2025-08-27","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"145010878","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Improved approach for modelling reaction kinetics for organic-rich shales, particularly oil shales","authors":"David A. Wood","doi":"10.1016/j.geoen.2025.214177","DOIUrl":"10.1016/j.geoen.2025.214177","url":null,"abstract":"<div><div>Two methods are compared to calculate credible reaction kinetic distributions that fit S2 pyrogram curves generated by multi-heating rate pyrolysis analysis of oil shales. The fixed-<em>A</em> method constrains all reactions in the distribution to conform to a single frequency factor. The variable <em>E-A</em> (Var <em>E-A</em>) method allows the activation energy (<em>E</em>) and <em>A</em> to vary independently for each reaction. The reaction kinetics are important as they determine the temperature ranges at specific heating rates at which oil and gas products are generated. This study evaluates the two kinetic fitting methods using published pyrogram details from three samples of kerogen extracts from oil shale (China, Jordan, U.S.A) and one whole rock oil shale sample (China). The component reactions of the Var <em>E-A</em> solutions conform to the lower end of an empirically observed <em>E-lnA</em> trend defined by a large number of organic-rich shale formations; the fixed-<em>A</em> solutions do not. The temperature ranges of some Var <em>E-A</em> solution reactions are broader than those of the fixed-<em>A</em> solution, meaning that fewer reactions are required to provide effective pyrogram fits. The Var <em>E-A</em> solutions provide more credible explanations of the aromatization processes governed by first- and second-order reactions. involved in forming bitumen, oil/gas products and carbon residues during the thermal maturation of kerogen. A conceptual model is proposed to explain this. The differences between the fixed-<em>A</em> and Var <em>E-A</em> kinetic solutions have important implications for the design of in-situ conversion processes (ICP) for generating oil and gas products from oil shales.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"256 ","pages":"Article 214177"},"PeriodicalIF":4.6,"publicationDate":"2025-08-27","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144912387","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Newtonized sparse channel estimation for mud pulse telemetry","authors":"Zitong Sha ,&nbsp;Jiang Zhu ,&nbsp;Jiaxun Lu ,&nbsp;Yanbing Fu ,&nbsp;Xingbin Tu ,&nbsp;Zhujun Zhang ,&nbsp;Yan Wei ,&nbsp;Fengzhong Qu","doi":"10.1016/j.geoen.2025.214167","DOIUrl":"10.1016/j.geoen.2025.214167","url":null,"abstract":"<div><div>With the growing demand for oil and gas resources, exploration has expanded into ultra-deep, offshore, and unconventional fields, necessitating high-speed and reliable real-time data transmission during drilling. Traditional mud pulse telemetry (MPT) systems, limited to communication rates of 0.5–5 bps, fail to meet these requirements, prompting the development of systems capable of achieving 12 bps or more. This study introduces a precise channel estimation method, newtonized orthogonal matching pursuit (NOMP), to reveal the detailed characteristics of mud pulse channel, including attenuation, distortion, and multi-path effects in mud pulse channels. The performance of the NOMP method is demonstrated through simulations, showcasing its superior accuracy and adaptability compared to traditional methods. The NOMP channel estimation method is employed to analyze representative MPT scenarios, including 5000 m water circulation, 3000 m real well, and 1600 m while-drilling experiments. Based on the channel estimation results, we summarize the characteristics of arrival paths across various scenarios and reveal the Poisson distribution of the arrival delays. In all simulations and experiments, the mean square error of NOMP is lower than that of traditional method. In all conducted simulations and experiments, NOMP demonstrates superior performance compared to traditional methods in terms of channel estimation accuracy, computational complexity, and robustness.</div></div>","PeriodicalId":100578,"journal":{"name":"Geoenergy Science and Engineering","volume":"256 ","pages":"Article 214167"},"PeriodicalIF":4.6,"publicationDate":"2025-08-27","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"144921600","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}