IOR 2019 – 20th European Symposium on Improved Oil Recovery最新文献

{"title":"Alkylpyrazines - from the “Dinner Table” to the Oilfield: A New Class of Partitioning Tracers","authors":"Mario Silva, M. Ould Metidji, Helge Stray, T. Bjørnstad","doi":"10.3997/2214-4609.201900063","DOIUrl":"https://doi.org/10.3997/2214-4609.201900063","url":null,"abstract":"A partitioning inter-well tracer test (PITT) is a dynamic tool to measure the residual oil saturation (SOR) in the swept volumes of oilfields. Knowledge about SOR is an important parameter in the design of many IOR projects. Such projects are increasingly important to satisfy the global demand for hydrocarbons, as the worldwide number of mature oilfields steadily grows and very few large hydrocarbon rich basins are left unexplored. By performing a PITT before and after an IOR project is implemented, the performance of such project can also be evaluated.\u0000PITTs were first used in hydrogeology and introduced in the oil industry in the early 1970s. PITTs never became a routine tool for the characterization of oil reservoirs, however have been receiving increasing attention in recent years. The first PITTs were performed with tracer compounds successfully used in hydrogeology or selected based on the easiness of their analysis. This led often to unsuccessful tests, as the behaviour of the tracers was not well understood in the conditions encountered on the oilfield. Furthermore, environmental regulations on oil&gas production were introduced in recent years (as for example, on the Norwegian continental shelf) which restrict the chemicals possible to use as tracers. The small number of compounds thoroughly investigated and qualified for use as PITT tracer is one of the major obstacles for the dissemination of this technology. It is therefore important to develop new, functional, and environmentally acceptable partitioning tracers. \u0000Alkylpyrazines are heterocyclic aromatic compounds which are major natural constituents of flavour and aroma of many roasted and fermented foods and beverages. Their worldwide annual production is limited to a few tons primarily used by the food industry. Both scientific studies and legal guidelines consider the use of alkylpyrazines as flavour or odor agents in food products to be safe. Many alkylpyrazines exhibit physico-chemical properties which make them interesting oil/water partitioning tracer candidates. \u0000In the present work, we present the studies and laboratory testing performed on selected alkylpyrazines. Experimental and physical-chemical data was analysed to assess the possibility of using compounds from this class of chemicals as inter-well oil/water partitioning tracers. Results suggest that these alkylpyrazines, used primarily as food additives, can be transferred from “the dinner table to the oilfield” as a new class of partitioning tracers to measure SOR in the inter-well region.","PeriodicalId":373825,"journal":{"name":"IOR 2019 – 20th European Symposium on Improved Oil Recovery","volume":"117 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-04-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"127349992","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":"Surfactant Flooding in Offshore Environments","authors":"J. Southwick, E. V. D. Pol, C. H. Rijn, D. W. Batenburg, A. A. A. Manap, A. Mastan, N. Zulkifli","doi":"10.2118/190296-MS","DOIUrl":"https://doi.org/10.2118/190296-MS","url":null,"abstract":"A low complexity chemical flooding formulation has been developed for application in offshore environments. The formulation uses seawater with no additional water treatment beyond that which is normally performed for water flooding (filtration, de-oxygenation, etc.). The formulation is a mixture of an alkyl propoxy sulfate (APS) and an alkyl ethoxy sulfate (AES) with no cosolvent. With seawater only (no salinity gradient) the blend of APS and AES gives substantially higher oil recovery than a blend of APS and internal olefin sulfonate (IOS) in outcrop sandstone.\u0000\u0000It is shown that the highest oil recovery is obtained with surfactant blends that produce formulations that are underoptimum (Winsor Type 1 phase behavior) with reservoir crude oil. Also, these underoptimum formulations avoid high injection pressures seen with optimum formulations in low permeability outcrop rock. The formulation recovers a similar amount of oil in reservoir rock in the swept zone. Overall recovery in reservoir rock is lower than outcrop sandstone due to greater heterogeneity, which causes bypassing of crude oil.","PeriodicalId":373825,"journal":{"name":"IOR 2019 – 20th European Symposium on Improved Oil Recovery","volume":"26 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-04-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125864332","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":"Reduction of Surfactant Adsorption: A Study of Dynamic Surfactant Adsorption/Desorption in Shaly-sandstone Reservoir","authors":"F. Srisuriyachai, M. Pancharoen, R. Laochamroonvoraponse, Y. Vathanapanich","doi":"10.3997/2214-4609.201900171","DOIUrl":"https://doi.org/10.3997/2214-4609.201900171","url":null,"abstract":"Summary Chemical Enhanced Oil Recovery (CEOR) has been implemented in many oilfields in several past decades. The techniques may be costly but they yield good benefits to specific type of reservoir. Sirikit (S1) oilfield, located in the north of Thailand, is one of the good examples that could positively response to the techniques based on screening criteria for CEOR. Surfactant flooding, which is one of the CEOR techniques, may be the most suitable for Sirikit oilfield as it can lower the interfacial tension (IFT) between oil and injected water to the ultra-low condition and hence, oil can be liberated as emulsion form. Fluid flow abilities are improved and at the same time, residual oil saturation is greatly reduced. Following the EOR master plan for S1 field, laboratory study has been carried out to determine chemical formulation that is suitable for S1 crude and formation water. It was, however, discovered recently that surfactant loss due to adsorption could turn the surfactant flooding project in Sirikit oilfield ineffective and uneconomic. From the study, the cause of high surfactant adsorption is revealed. As reservoir formation in Sirikit oilfield is sandstone but it contains high portion of illite and kaolinite, surface charge of rock is found to be positive instead of negative, coming from numbers of calcium and magnesium ions bound with extremely large surface of clays. Depletion of surfactant therefore, occurs through the precipitation of anionic surfactant with these divalent ions. Based on mechanism of surfactant loss, the suggestion to reduce surfactant adsorption is made. Sodium hydroxide which is a strong base is recommended to co-inject with anionic surfactant in this case as strong base can quickly provide negative charge to neutralize positive charge of clay surface. However, higher concentration of strong base will result in electrolytic force that eventually causes surfactant monomers to adhere onto rock surface, causing higher possibility for surfactant adsorption. Form the experiment, reducing concentration from 0.5 to 0.1% by weight helps decreasing retaining surfactant onto rock surface from 0.90 to 0.38 milligram per gram of rock. Sodium carbonate which is a moderately strong base can also reduce surfactant adsorption but due to weaker charge properties compared to sodium hydroxide, surfactant monomers tend to permanently adsorb onto rock surface, resulting in lower degree of desorption and as a consequence, retaining adsorbed surfactant onto rock surface is high.","PeriodicalId":373825,"journal":{"name":"IOR 2019 – 20th European Symposium on Improved Oil Recovery","volume":"31 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-04-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"115250078","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":"Flexible Coiled Polymer Dynamics in a Single Pore Throat with Effects of Flow Resistance and Normal Stresses","authors":"E. Eguagie, S. Berg, J. Crawshaw, S. De, P. Luckham","doi":"10.3997/2214-4609.201900118","DOIUrl":"https://doi.org/10.3997/2214-4609.201900118","url":null,"abstract":"We investigate the challenges involved in the use of polymer flooding as a chemical enhanced oil recovery (cEOR) technique for improving mobility ratio and enhancing macroscopic sweep efficiency. Flexible coiled polymers in porous media undergo stretching in a spatially heterogeneous structure. Due to the viscoelasticity of these polymers, they stretch continuously depending on their previous deformation until their elastic limit is reached and relaxation occurs. Previous research has proposed that at a certain critical flow rate, the relaxation of polymers cause an increase in viscosity and in turn a better mobility for enhancing microscopic sweep in porous media. However, others have reported that the increased viscosity in porous media is not so much related to the elasticity but more on the normal stresses that occur when polymers are sheared in porous media flow. One similar fact is that as increased viscosity is observed an enhanced pressured drop occurs and the flow becomes highly unstable even at laminar flow regime. This unstable flow is termed the elastic instability or turbulence but the details of this kind of turbulence, its consequences and applicability on the impact of oil recovery is not understood.\u0000In this work, we experimentally investigate the flow behaviors of flexible coiled polymers of hydrolyzed polyacrylamide (HPAM) based on a single pore throat geometry using a microfluidic device. The aim is to adequately parameterize the effects of the normal stress difference in shear and extension as a function of the geometry and intrinsic characteristics of the polymer solutions at different Deborah (De) numbers. Hence, we carry out pressure drop and particle image velocimetry experiments and results showed a critical De at which polymer viscosity increases as well as the normal stress difference. It was also observed that the flow resistance might be a function of both the elasticity and the normal stresses in shear flow, however, extensional stresses cannot be neglected.\u0000\u0000Keywords: Porous media · Rheology · EOR/IOR · Microfluidics","PeriodicalId":373825,"journal":{"name":"IOR 2019 – 20th European Symposium on Improved Oil Recovery","volume":"6 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-04-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"128285697","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":"Radial Injectivity of an Associative Polymer for EOR","authors":"T. Skauge, K. Djurhuus, T. Zimmermann, C. Bittner, R. Reichenbach-Klinke","doi":"10.3997/2214-4609.201900143","DOIUrl":"https://doi.org/10.3997/2214-4609.201900143","url":null,"abstract":"Hydrophobically modified polyacylamides (HMPAMs), also known as associative polymers, have high potential as EOR chemicals due to their specific chemical properties. However, the strength of hydrophobic interactions also leads to more complex flow behavior. Mostly, polymer injectivity is studied in linear coreflood experiments. However, in reality the polymer injection occurs in radial flow. The main difference is that linear flow has constant pressure gradient and thereby constant shear rate, while radial flow has a position dependent pressure gradient and therefore a shear gradient in the near-well region. For complex non-Newtonian polymers like HMPAMs this may have large implications for injectivity.\u0000The influence of relatively weak hydrophobic interactions on flow properties was studied by radial injection of a semi-dilute solution of associative polymer under high injection rates. Radial flow was achieved by injection in a well placed in the center of a 30 cm diameter, 3 cm thick disc cut from Bentheimer outcrop sandstone. Bentheimer was chosen due to the high homogeneity of the rock. Pressure ports were positioned between the injection well and the rim to allow determination of the pressure decay curve during flow. Effluent was collected and analyzed for mechanical degradation.\u0000The radial injection of the associative polymer showed shear thinning behavior at all rates, including at near-well equivalent rates. This means that this polymer can be injected with relatively low pressures and will gain viscosity as it propagates further from the well. Interestingly, this is different from the observations in linear core floods. Disruption and regeneration of weak hydrophobic interactions appears to be the main cause of the change in rheological behavior between linear and radial flow. The associative polymer showed excellent shear stability with only moderate viscosity reduction at extreme injection rates. The results confirm the need for in-situ measurements of polymer rheology not only in linear but also radial flow as input data for injectivity modeling. \u0000The experiments reveal that the associative polymer has different rheological behavior in bulk, linear and radial flow. The near-Newtonian behavior at near-well injection rates combined with building of viscosity at lower rates further from the well is beneficial for application in polymer flooding. This is to our knowledge the first systematic investigation of an associative polymer in radial flow. The results have major implications for polymer flood modeling and flood design, particularly for injections in vertical wells where injectivity is critical.","PeriodicalId":373825,"journal":{"name":"IOR 2019 – 20th European Symposium on Improved Oil Recovery","volume":"7 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-04-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"128991725","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":"SmartWater Synergy with Chemical EOR: Polymer Effects on SmartWater Spontaneous Imbibition","authors":"A. AlSofi, A. Fuseni, Z. K. Kaidar, S. M. Alenezi","doi":"10.3997/2214-4609.201900141","DOIUrl":"https://doi.org/10.3997/2214-4609.201900141","url":null,"abstract":"Summary Synergy between EOR processes has the potential for achieving more effective application. Previously, we demonstrated Smart water's slight negative-impact on polymer and chase brine injectivity, positive impact on polymer retention, and negligible impact on polymer acceleration. We also demonstrated polymer's positive effects on Smart water's surface potentials, contact angles, and oil recoveries. Herein, we further investigate this synergy focusing on polymer's possible effects on SmartWater spontaneous imbibition. We also revisit singlephase displacement observations with regard to polymer injectivity and retention using bench-top experiments. The main experimental program consisted of spontaneous-imbibition and sorption measurements. A supplementary experimental program included polymer filterability and adsorption tests to provide additional insights on this synergistic SmartWater/Polymer process. Results showed the superiority of SmartWater as an imbibition fluid compared to the higher-salinity injection water. With polymer addition, the lower-salinity SmartWater upheld its superiority. Accounting for viscosity variations, sorption rates into powdered rock packs were actually very comparable with and without the polymer. In core plugs, and with both brines, polymer addition yielded further water imbibition above that obtained with polymer-free solutions. Still imbibition was much more effective with SmartWater even in the presence of the polymer. At the same polymer concentrations, polymer adsorptions onto the rock were comparable with both SmartWater and the higher-salinity injection water. However, at equivalent viscosities, polymer adsorption onto the rock was lower with SmartWater than with the higher-salinity injection water. These static adsorption results could provide an additional explanation to the substantially lower retention observed with the lower-salinity SmartWater in dynamic retention tests. At the same polymer concentration, the solutions in both brines exhibited comparable filtration ratios. However, for solutions of equivalent viscosities, the solution in the higher-salinity conventional injection water exhibited higher filtration ratio. This discrepancy with single-phase displacement results can be explained based on differences of the main mechanism contributing to permeability reduction (adsorption layer versus mechanical plugging). In conclusion, the favorable SmartWater/Polymer synergy extends to spontaneous imbibition. Polymer solutions, in both SmartWater and injection water yielded additional imbibition in tertiary mode. However, with injection water the additional imbibition after polymer addition is much smaller than with SmartWater.","PeriodicalId":373825,"journal":{"name":"IOR 2019 – 20th European Symposium on Improved Oil Recovery","volume":"10 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-04-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"127040970","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":"Creating Insitu EOR Foams in Naturally Fractured Reservoirs by the Injection of Surfactant in Gas Dispersions – Lab Confirmation","authors":"A. Ocampo, A. Restrepo, J. Mejía, J. Valencia, H. Sánchez","doi":"10.3997/2214-4609.201900145","DOIUrl":"https://doi.org/10.3997/2214-4609.201900145","url":null,"abstract":"The present work presents the conceptual basis and experimental evaluation for a new technique to create insitu blocking foams in naturally fractured reservoirs by the injection of the foaming agent dispersed in a non-condensable gas stream. This work represents a further development of a previous paper (SPE-190219-MS; Ocampo et al, 2018) which presents a similar development for matrix dominated systems. Equivalent to previous work, the main objective is simplifying the operation and reducing costs for the deployment of EOR foams in gas injection based projects, and overcoming the limited reservoir volume of influence achieved by the surfactant alternated gas (SAG) technique.\u0000An extensive and systematic experimental work was performed using fluids and low porosity naturally fractured rock representative of the Piedemonte area (Colombia, South America). The experiments were devised to investigate the effect of the dispersed chemical (surfactant) concentration and the gas velocity on the ability to create blocking foams at high pressure and temperature through the naturally fractured rock at a stress state representing open fracture conditions. The main physical mechanism behind this new technique is again the transfer of foamer droplets dispersed in the gas stream into the water present in the hydrocarbon reservoir. This transfer occurs because of the contrast in foamer concentration between the dispersed phase and the in-situ water.\u0000Results herein show reductions in gas mobility between 50% and 66%, along with increases in oil recovery factor between 10% and 34%, when the foamer chemical is dispersed in the gas stream, compared with the base gas flooding process performed on the described rock at residual oil and water saturations. This condition is obtained as far as the gas velocity is closed to rates equivalent to the velocities experienced near wellbore in the target reservoir, and the concentration of the active chemical is above 800 ppm (five times the concentration required to create blocking foam in the matrix system; Ocampo et al, 2018). Successful experiments with this new foam technique showed similar incremental recovery factors and stability periods as foams created by the SAG technique at higher chemical concentrations on the same rock fluid system. \u0000The experimental results encouraged the progression and approval of a field pilot application of this foams technique this year in a Colombian Piedemonte gas condensate field characterized by the presence and dominance of the natural fractures both in the production and hydrocarbon gas injection performance.","PeriodicalId":373825,"journal":{"name":"IOR 2019 – 20th European Symposium on Improved Oil Recovery","volume":"61 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-04-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"123657481","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":"Multiscale Study of Chemically-tuned Waterflooding in Carbonate Rocks using Micro-Computed Tomography","authors":"M. Tawfik, Z. Karpyn, R. Johns","doi":"10.3997/2214-4609.201900074","DOIUrl":"https://doi.org/10.3997/2214-4609.201900074","url":null,"abstract":"Summary Carbonate reservoirs host more than half of the remaining oil reserves worldwide. Due to their complex pore structure and intermediate to oil-wet nature, it is becoming more challenging to produce the remaining oil from these formations. Over the past two decades, chemically-tuned waterflooding (CTWF) has gained the attention of researchers worldwide. Experimental, numerical, and field studies in this area suggest that changes in injected water salinity and ion composition have the potential to increase oil recovery both in sandstone and carbonate reservoirs via wettability alteration. However, the physico-chemical mechanisms involved in improving oil recovery by CTWF remain poorly understood. This could be attributed to the interplay of several mechanisms at the pore-scale resulting in the incremental oil recovery observed at the macro-scale. It is also mainly due to the lack of consistent experimental data across different scales (i.e.: field scale, core-scale, and pore-scale), reducing the possibility of drawing accurate correlations across length-scales. This study proposes multiscale experimental measurements to investigate the effect of oil composition on the performance of CTWF, where continuum-scale floods are performed to investigate the effect of oil composition on oil recovery from oil-wet carbonate rocks by CTWF. In parallel, in-situ pore-scale measurements of wettability and interface curvature alteration are performed. X-ray microtomography is used to perform direct measurement of changes in interfacial curvatures and in-situ 3D contact angle distributions at the micro-scale at different stages of the CTWF. The study also aims at finding a correlation between the magnitude of improvement in oil recovery at the macro-scale and the corresponding magnitude of wettability alteration at the pore-scale at different conditions. This allows for a better understanding of the physico-chemical mechanisms controlling CTWF, which helps advance currently existing CTWF models, as well as result in more well-informed candidate reservoir selection and the development of a workflow to determine the optimum injection brine properties for a given crude oil-brine-rock system.","PeriodicalId":373825,"journal":{"name":"IOR 2019 – 20th European Symposium on Improved Oil Recovery","volume":"391 1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-04-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133154941","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":"Enhanced Oil Recovery from High-Viscosity Oil Deposits by Chemically Evolving Systems","authors":"L. Altunina, V. Kuvshinov, I. Kuvshinov, L. Stasyeva","doi":"10.3997/2214-4609.201900175","DOIUrl":"https://doi.org/10.3997/2214-4609.201900175","url":null,"abstract":"","PeriodicalId":373825,"journal":{"name":"IOR 2019 – 20th European Symposium on Improved Oil Recovery","volume":"121 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-04-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133580918","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":"Experimental Investigation of Immiscible N2 WAG in Saline Reservoir at Ultra-High Water-Cut Stage","authors":"D. Kong, Z. Lun, Y. Li, S. Xu, H. Yu, H. Guo","doi":"10.3997/2214-4609.201900176","DOIUrl":"https://doi.org/10.3997/2214-4609.201900176","url":null,"abstract":"","PeriodicalId":373825,"journal":{"name":"IOR 2019 – 20th European Symposium on Improved Oil Recovery","volume":"5 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-04-08","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"127851162","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}