Petroleum最新文献

{"title":"Effect of monovalent/divalent ions and SiO2-based nanocomposite dosage on thermochemical stability of HPAM polymeric solutions","authors":"Jhon F. Gallego ,&nbsp;Lady J. Giraldo ,&nbsp;Henderson I. Quintero ,&nbsp;Hugo A. García ,&nbsp;Karol Zapata ,&nbsp;Samira Heidari ,&nbsp;Masoud Riazi ,&nbsp;Camilo A. Franco ,&nbsp;Farid B. Cortés","doi":"10.1016/j.petlm.2024.07.001","DOIUrl":"10.1016/j.petlm.2024.07.001","url":null,"abstract":"<div><div>This study evaluated the effect of monovalent and divalent ions and the dosage of a SiO₂-based nanocomposite on the thermochemical stability of HPAM polymeric solution. Chelating amine–functionalized NPs (AFNPs) were used to enhance the thermochemical stability of HPAM based on capturing monovalent/divalent ions after seven days at 70°C. Different polymer solutions prepared with calcium chloride dihydrate (CaCl₂·2H₂O) at 2000 mg/L and sodium chloride (NaCl) at 10000 mg/L, and two different dosages of HPAM (1000 and 2000 mg/L) were assessed in the presence and absence of AFNPs at dosages of 200, 500 and 1000 mg/L. The nanocomposite was characterized by N₂ adsorption, Fourier-transformed infrared spectrophotometry (FTIR), thermogravimetric analysis (TGA), dynamic Light Scattering (DLS), and Zeta potential (ZP). Stability tests over time confirmed the positive effect of nanocomposite on increasing the thermochemical stability of polymer solutions. Results revealed that adding 0, 200, and 500 mg/L of nanocomposite to the polymeric solution at 1000 mg/L of HPAM, 10000 mg/L of NaCl, and 2000 mg/L of CaCl₂·2H₂O led to the viscosity reductions of 73.5%, 18%, and less than 1% after 7 days (70°C), respectively. Nanocomposite at 200 mg/L reduces the polymer degradation in the presence of the two salts evaluated separately, i.e., 20% for 10000 mg/L of NaCl and 15% for 2000 mg/L of CaCl₂·2H₂O. The adsorption tests on AFNPs and SiO₂ NPs concluded that AFNPs had higher adsorption of cations in comparison to SiO₂ NPs and that greater adsorption of cations is related to a reduction in polymer degradation.</div></div>","PeriodicalId":37433,"journal":{"name":"Petroleum","volume":"10 4","pages":"Pages 719-735"},"PeriodicalIF":4.2,"publicationDate":"2024-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141712075","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Multiphase flow challenges in drilling, completions, and injection: Part 1","authors":"C.E. Obi ,&nbsp;A.R. Hasan ,&nbsp;M.A. Rahman ,&nbsp;D. Banerjee","doi":"10.1016/j.petlm.2024.05.001","DOIUrl":"10.1016/j.petlm.2024.05.001","url":null,"abstract":"<div><div>This review addresses the diverse applications of multiphase flows, focusing on drilling, completions, and injection activities in the oil and gas industry. Identifying contemporary challenges and suggesting future research directions, it comprehensively reviews evolving applications in these multidisciplinary topics. In drilling, challenges such as gas kicks, cutting transport, and hole cleaning are explored. The application of immersion cooling technology in surface facilities for gas fields utilized in integrated bitcoin mining is also discussed. Nanotechnology, particularly the use of nanoparticles and nanofluids, shows promise in mitigating particulate flow issues and controlling macroscopic fluid behavior. Nanofluids find applications in drilling for formation strengthening and mitigating formation damage in completions as highlighted in this work, as well as in subsurface injection for enhanced oil recovery (EOR), waterflooding, reservoir mapping, and sequestration tracking. The review emphasizes the need for techno-economic analyses using multiphase flow models, particularly in scenarios involving fluid injection for energy storage. Addressing these multiphase flow challenges is crucial for the future of energy diversity and transition initiatives, offering benefits such as financial stability, resilience, sustainability, and reliable supply chains. The first part of this review presents the application of multiphase (typical gas, liquid, solid) flow models and technology for drilling, completion, and injection operations. While the second part reviews the applications of multiphase particulate (nanofluid) flow technology, the use of computational fluid dynamics (CFD), machine learning (ML), and system modeling for multiphase flow models in drilling, completions, and injection operations.</div></div>","PeriodicalId":37433,"journal":{"name":"Petroleum","volume":"10 4","pages":"Pages 557-569"},"PeriodicalIF":4.2,"publicationDate":"2024-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141026376","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Nanoparticle-stabilized CO2 foam flooding for enhanced heavy oil recovery: A micro-optical analysis","authors":"Arifur Rahman ,&nbsp;Ezeddin Shirif ,&nbsp;Farshid Torabi","doi":"10.1016/j.petlm.2024.06.002","DOIUrl":"10.1016/j.petlm.2024.06.002","url":null,"abstract":"<div><div>Surfactant flooding is a well-known chemical approach for enhancing oil recovery. Surfactant flooding has the disadvantage that it cannot withstand the harsh reservoir conditions. Improvements in oil recovery and release are made possible by the use of nanoparticles and surfactants and CO₂ co-injection because they generate stable foam, reduce the interfacial tension (IFT) between water and oil, cause emulsions to spontaneously form, change the wettability of porous media, and change the characteristics of flow. In the current work, the simultaneous injection of SiO₂, Al₂O₃ nanoparticles, anionic surfactant SDS, and CO₂ in various scenarios were evaluated to determine the microscopic and macroscopic efficacy of heavy oil recovery. IFT (interfacial tension) was reduced by 44% when the nanoparticles and SDS (2000 ppm) were added, compared to a reduction of roughly 57% with SDS only. SDS-stabilized CO₂ foam flooding, however, is unstable due to the adsorption of SDS in the rock surfaces as well as in heavy oil. To assess foam's potential to shift CO₂ from the high permeability zone (the thief zone) into the low permeability zone, directly visualizing micromodel flooding was successfully executed (upswept oil-rich zone). Based on typical reservoir permeability fluctuations, the permeability contrast (defined as the ratio of high permeability to low permeability) for the micromodel flooding was selected. However, the results of the experiment demonstrated that by utilizing SDS and nanoparticles, minimal IFT was reached. The addition of nanoparticles to surfactant solutions, however, greatly boosted oil recovery, according to the findings of flooding studies. The ultimate oil recovery was generally improved more by the anionic surfactant (SDS) solution including nanoparticles than by the anionic surfactant (SDS) alone.</div></div>","PeriodicalId":37433,"journal":{"name":"Petroleum","volume":"10 4","pages":"Pages 696-704"},"PeriodicalIF":4.2,"publicationDate":"2024-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141405929","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Novel phase field model of hydraulic fracture propagation in poroelastic media and numerical investigation of interaction between hydraulic fracture and natural fracture","authors":"Sang Yu ,&nbsp;Yi Song ,&nbsp;Shouyi Wang ,&nbsp;Yongjun Xiao ,&nbsp;Junjie Hu ,&nbsp;Yiting Wang ,&nbsp;Liangping Yi ,&nbsp;Zhaozhong Yang","doi":"10.1016/j.petlm.2023.01.003","DOIUrl":"10.1016/j.petlm.2023.01.003","url":null,"abstract":"<div><div>A novel numerical model is established to study the hydraulic fracture extend in poroelastic media with natural fractures based on the phase field method. In this new model, the poroelasticity parameter (Biot's coefficient, Biot's modulus, and porosity) of rock is a function of the phase field value. Therefore, a new phase field evolution equation is derived. The finite element numerical discretization method and Newton–Raphson (NR) iterative method are adopted to establish the corresponding numerical solution iterative scheme. The stability and correctness of the model were verified by a series of numerical simulation cases. The fluid pressure within the fracture, the fracture length, and the fracture width calculated by the model that regards the poroelasticity parameter as a constant would be larger, longer, and smaller, respectively, compared with those calculated by the model established in this study. The effect of certain formation factors and engineering factors on the intersection behavior between hydraulic fracture and natural fracture is investigated based on the established model.</div></div>","PeriodicalId":37433,"journal":{"name":"Petroleum","volume":"10 4","pages":"Pages 672-695"},"PeriodicalIF":4.2,"publicationDate":"2024-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88026927","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Estimation of SARA composition of crudes purely from density and viscosity using machine learning based models","authors":"Anand D. Kulkarni ,&nbsp;Pratiksha D. Khurpade ,&nbsp;Somnath Nandi","doi":"10.1016/j.petlm.2024.06.001","DOIUrl":"10.1016/j.petlm.2024.06.001","url":null,"abstract":"<div><div>Accurate characterization of crude oils by determining the composition of saturates, aromatics, resins and asphaltenes (SARA) has always been a challenging task in the petroleum industry. However, conventional experimental methods for determination of SARA composition are labour intensive, time-consuming and expensive. In the present study, artificial neural network (ANN) models were developed to predict the SARA composition from easily measurable parameters like density and viscosity. A dataset of 216 crude oil samples covering wide range of geographical locations was compiled from various literature sources. The ANN models with one hidden layer and six neurons are trained, tested and validated using MATLAB neural network toolbox. Results obtained on analysis revealed reasonably good accuracy of prediction of SARA components except for aromatics. The performance of developed ANN models was compared with various correlations reported in literature and found to be better in terms of mean squared error and coefficient of determination. The developed models hence provide a cost-effective and time-efficient alternative to the conventional SARA characterization techniques.</div></div>","PeriodicalId":37433,"journal":{"name":"Petroleum","volume":"10 4","pages":"Pages 620-630"},"PeriodicalIF":4.2,"publicationDate":"2024-12-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141414131","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Investigation of pore structure alteration and permeability enhancement of shale matrix by supercritical water treatment after hydraulic fracturing","authors":"Yili Kang ,&nbsp;Peisong Li ,&nbsp;Wangkun Cao ,&nbsp;Mingjun Chen ,&nbsp;Lijun You ,&nbsp;Jiang Liu ,&nbsp;Zhehan Lai","doi":"10.1016/j.petlm.2022.05.002","DOIUrl":"10.1016/j.petlm.2022.05.002","url":null,"abstract":"<div><p>Shale gas reservoirs are unconventional tight gas reservoirs, in which horizontal wells and hydraulic fracturing are required to achieve commercial development. The fracture networks created by hydraulic fracturing can increase the drainage area extensively to enhance shale gas recovery. However, large volumes of fracturing fluid that is difficult to flow back to the surface and remained in the shale formation, will inevitably lead to damages of the shale formations and limit the effectiveness of stimulation. Supercritical water (SCW) treatment after hydraulic fracturing is a new method to enhance shale gas recovery by using appropriate heat treatment methods to the specific formation to convert the retained fracturing fluid into a supercritical state (at temperatures in excess of 373.946°C and pressures in excess of 22.064 MPa). An experiment was conducted to simulate the reaction between shale and SCW, and the capacity of SCW treatment to enhance the permeability of the shale was evaluated by measuring the response of the shale porosity and permeability on SCW treatment. The experimental results show that the shale porosity and permeability increase by 213.43% and 2198.37%, respectively. The pore structure alteration and permeability enhancement of the shale matrix were determined by analyzing the changes in pore structure and mineral composition after SCW treatment. The mechanisms that affect pore structure and mineral composition include oxidative catalysis decomposition of organic matters and reducing minerals, acid-catalyzed decomposition of carbonate minerals and feldspar minerals, hydrothermal catalysis induced fracture extension and cementation weakening induced fracture extension. SCW treatment converts harm into a benefit by reducing the intrusion of harmful substances into the shale formation, which will broaden the scope and scale of shale formation stimulation.</p></div>","PeriodicalId":37433,"journal":{"name":"Petroleum","volume":"10 2","pages":"Pages 265-274"},"PeriodicalIF":0.0,"publicationDate":"2024-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://www.sciencedirect.com/science/article/pii/S2405656122000451/pdfft?md5=c75b04cced6f21452f74642907fd950b&pid=1-s2.0-S2405656122000451-main.pdf","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91095546","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"A hybrid machine learning approach based study of production forecasting and factors influencing the multiphase flow through surface chokes","authors":"Waquar Kaleem ,&nbsp;Saurabh Tewari ,&nbsp;Mrigya Fogat ,&nbsp;Dmitriy A. Martyushev","doi":"10.1016/j.petlm.2023.06.001","DOIUrl":"10.1016/j.petlm.2023.06.001","url":null,"abstract":"<div><p>Surface chokes are widely utilized equipment installed on wellheads to control hydrocarbon flow rates. Several correlations have been suggested to model the multiphase flow of oil and gas via surface chokes. However, substantial errors have been reported in empirical fitting models and correlations to estimate hydrocarbon flow because of the reservoir's heterogeneity, anisotropism, variance in reservoir fluid characteristics at diverse subsurface depths, which introduces complexity in production data. Therefore, the estimation of daily oil and gas production rates is still challenging for the petroleum industry. Recently, hybrid data-driven techniques have been reported to be effective for estimation problems in various aspects of the petroleum domain. This paper investigates hybrid ensemble data-driven approaches to forecast multiphase flow rates through the surface choke (viz. stacked generalization and voting architectures), followed by an assessment of the impact of input production control variables. Otherwise, machine learning models are also trained and tested individually on the production data of hydrocarbon wells located in North Sea. Feature engineering has been properly applied to select the most suitable contributing control variables for daily production rate forecasting. This study provides a chronological explanation of the data analytics required for the interpretation of production data. The test results reveal the estimation performance of the stacked generalization architecture has outperformed other significant paradigms considered for production forecasting.</p></div>","PeriodicalId":37433,"journal":{"name":"Petroleum","volume":"10 2","pages":"Pages 354-371"},"PeriodicalIF":0.0,"publicationDate":"2024-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://www.sciencedirect.com/science/article/pii/S2405656123000366/pdfft?md5=bfbc1ac106deb5949c0fb09de0b85ec9&pid=1-s2.0-S2405656123000366-main.pdf","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88698110","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Leakage and diffusion characteristics of underground hydrogen pipeline","authors":"Wenkang Zhang,&nbsp;Guanghui Zhao","doi":"10.1016/j.petlm.2023.06.002","DOIUrl":"10.1016/j.petlm.2023.06.002","url":null,"abstract":"<div><p>Soil corrosion and hydrogen embrittlement are the main factors of hydrogen pipeline failure. The gas escapes, diffuses and accumulates in the soil and enters the atmosphere when leak occurs. The mechanism of gas diffusion in buried pipelines is very complicated. Mastering the evolution law of hydrogen leakage diffusion is conducive to quickly locating the leakage point and reducing the loss. The leakage model of the underground hydrogen pipeline is established in this paper. The effect of leakage hole, soil type, pipeline pressure, pipeline diameter on hydrogen leakage diffusion were investigated. The results show that when the hydrogen pipeline leaks, the hydrogen concentration increases with the increase of leakage time, showing a symmetrical distribution trend. With the pipeline pressure increase, hydrogen leakage speed is accelerated, and longitudinal diffusion gradually becomes the dominant direction. As the leakage diameter increases, hydrogen leakage per unit of time increases sharply. Hydrogen diffuses more easily in sandy soil, and its diffusion speed, concentration, and range are higher than that in clay soil. The research content provides a reference and basis for the detection and evaluation of buried hydrogen pipeline leakage.</p></div>","PeriodicalId":37433,"journal":{"name":"Petroleum","volume":"10 2","pages":"Pages 319-325"},"PeriodicalIF":0.0,"publicationDate":"2024-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://www.sciencedirect.com/science/article/pii/S2405656123000378/pdfft?md5=8fdd518068c30907b6a649155aae6f9b&pid=1-s2.0-S2405656123000378-main.pdf","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85133866","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Asphaltene onset pressure measurement and calculation techniques: A review","authors":"Sherif Fakher,&nbsp;Amr Yousef,&nbsp;Aseel Al-Sakkaf,&nbsp;Shams Eldakar","doi":"10.1016/j.petlm.2023.04.001","DOIUrl":"10.1016/j.petlm.2023.04.001","url":null,"abstract":"<div><p>Asphaltene precipitation can result in several production, operational, and transportation problems during oil recovery. If asphaltene precipitates and deposits, it can reduce reservoir permeability, damage wellbore equipment, and plug the pipelines. It is therefore extremely important to evaluate the conditions at which asphaltene precipitation occurs; this is referred to as the asphaltene onset pressure. Asphaltene onset pressure has been measured using many different experimental techniques. There have also been many attempts along the years to predict asphaltene onset pressure using mathematical correlations and models. This research provides an up-to-date comprehensive review of the methods by which asphaltene onset pressure can be measured using laboratory experiments and mathematical models. The research explains the main mechanisms of all the laboratory experiments to measure asphaltene onset pressure under static conditions and how to conduct them and highlights the advantages and limitations of each method. The research also provides a summary of the commonly used mathematical models to quantify asphaltene onset pressure directly and indirectly.</p></div>","PeriodicalId":37433,"journal":{"name":"Petroleum","volume":"10 2","pages":"Pages 191-201"},"PeriodicalIF":0.0,"publicationDate":"2024-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://www.sciencedirect.com/science/article/pii/S2405656123000202/pdfft?md5=0797f321455963448035d12a584912b3&pid=1-s2.0-S2405656123000202-main.pdf","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87610133","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}

{"title":"Studying the effect of surfactant assisted low-salinity water flooding on clay-rich sandstones","authors":"Saeed Khezerloo-ye Aghdam ,&nbsp;Alireza Kazemi ,&nbsp;Mohammad Ahmadi","doi":"10.1016/j.petlm.2023.09.006","DOIUrl":"10.1016/j.petlm.2023.09.006","url":null,"abstract":"<div><p>Sandstone reservoirs often contain clay particles that can cause damage and reduce permeability during low-salinity water flooding. In this study, the effect of surfactants on fine migration in clay-rich sandstones and its impact on oil recovery was investigated.</p><p>First, the impact of surfactants on interparticle forces in fine-matrix, fine-fine, and oil-matrix systems was modeled. The results showed that both CTAB (cetyltrimethyl ammonium bromide) and QS (quillaja saponin) cause EDL compaction, weakening the repulsive forces. However, SDS (sodium dodecyl sulfate) and TX (triton X-100) do not affect the EDL. Next, the effect of surfactants on IFT reduction and wettability alteration was experimentally investigated. All surfactants reduced IFT due to the surface excessive concentration mechanism. The wettability alteration experiment illustrated that although QS and CTAB compact EDL around oil and matrix particles leading to attraction force augmentation, they both alter wettability through adsorption on matrix and carboxylic groups present in crude oil, respectively.</p><p>Surfactant aqueous solutions were then injected into various clay-rich sandstone sanpacks, which resulted in increased oil recovery. However, the mechanisms leading to enhanced oil recovery variedby surfactant type. CTAB increased recovery by 10% through IFT reduction and wettability alteration, while SDS and TX increased recovery by 12% and 9%, respectively, through wettability alteration and extreme fine migration. In contrast, partial fine migration in the QS flooding experiment reached a recovery increase of 18%. Permeability trends through experiments were also recorded. During CTAB injection, permeability did not reduce, while QS aqueous solution reduced rock permeability to 5 mD. SDS and TX reduced the magnitude of permeability to 2 mD.</p><p>In conclusion, this study demonstrates that surfactants can effectively improve oil recovery in clay-rich sandstones by altering the interparticle forces, reducing IFT, and changing wettability. The results suggest that the type of surfactant used should be carefully selected to achieve the desired recovery increase without affecting the permeability of the reservoir.</p></div>","PeriodicalId":37433,"journal":{"name":"Petroleum","volume":"10 2","pages":"Pages 306-318"},"PeriodicalIF":0.0,"publicationDate":"2024-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://www.sciencedirect.com/science/article/pii/S2405656123000640/pdfft?md5=db1c947c4dd6b393aad4cbc74d35ac13&pid=1-s2.0-S2405656123000640-main.pdf","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"135389456","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}