The primary objective of cement-sheath evaluation devices is to define the presence of set cement in the annulus, regardless of its density, compressive strength, or quality. Accepting the premise that any set cement in the annulus with a compressive strength greater than 0 psi cannot be replaced by squeeze cementing emphasizes that necessity of recognizing ultralow-compressive-strength cement ({lt}100 psi) from cement-sheath evaluation devices. Typically, most bond logging instruments cannot define satisfactorily the presence of these generally low-density, low-compressive-strength cements (such as foamed cement, cements filled with sponge-like microspheres, cements containing hydrogen for control of annular influx, or any cement contaminated with gas percolation). The ultrasonic cement evaluation instruments can define these gas contaminated, unset, or low-quality cements, provided the computing parameters are set and the tools calibrated correctly. This paper provides the mechanisms and data required to calibrate the ultrasonic cement evaluation devices correctly and the correct computing parameters for cement-sheath evaluation. Correct interpretation of the cement quality and quantity in the annulus permits the formulation of intelligent annular squeeze decisions.
{"title":"Guidelines for ultrasonic cement-sheath evaluation","authors":"K. J. Goodwin","doi":"10.2118/19538-PA","DOIUrl":"https://doi.org/10.2118/19538-PA","url":null,"abstract":"The primary objective of cement-sheath evaluation devices is to define the presence of set cement in the annulus, regardless of its density, compressive strength, or quality. Accepting the premise that any set cement in the annulus with a compressive strength greater than 0 psi cannot be replaced by squeeze cementing emphasizes that necessity of recognizing ultralow-compressive-strength cement ({lt}100 psi) from cement-sheath evaluation devices. Typically, most bond logging instruments cannot define satisfactorily the presence of these generally low-density, low-compressive-strength cements (such as foamed cement, cements filled with sponge-like microspheres, cements containing hydrogen for control of annular influx, or any cement contaminated with gas percolation). The ultrasonic cement evaluation instruments can define these gas contaminated, unset, or low-quality cements, provided the computing parameters are set and the tools calibrated correctly. This paper provides the mechanisms and data required to calibrate the ultrasonic cement evaluation devices correctly and the correct computing parameters for cement-sheath evaluation. Correct interpretation of the cement quality and quantity in the annulus permits the formulation of intelligent annular squeeze decisions.","PeriodicalId":22020,"journal":{"name":"Spe Production Engineering","volume":"37 1","pages":"280-284"},"PeriodicalIF":0.0,"publicationDate":"1992-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89509524","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}
This paper investigates the effect of electric submersible pump (ESP) performance tolerances and minor speed variations on the producing rate of wells completed in underpressured reservoirs, and presents ESP design considerations unique for the class of wells. These wells require considerable head to initiate flow and have relatively flat well-load curves. Pumps that operate near their maximum recommended rate have steep performance curves, and this is shown to minimize the effect of an underperforming pump on producing rate. Equations are developed for calculating the effects of pump performance and speed. Application requires evaluating the slopes of the pump-performance and well-load curves at design rate. The usefulness of these equations is demonstrated by practical examples. it is also demonstrated that flow stall can occur easily in underpressured reservoir applications when pumps designed to operate near their minimum recommended rate are installed.
{"title":"Special Considerations for Electric, Submersible Pump Applications in Underpressured Reservoirs","authors":"M. L. Powers","doi":"10.2118/22786-PA","DOIUrl":"https://doi.org/10.2118/22786-PA","url":null,"abstract":"This paper investigates the effect of electric submersible pump (ESP) performance tolerances and minor speed variations on the producing rate of wells completed in underpressured reservoirs, and presents ESP design considerations unique for the class of wells. These wells require considerable head to initiate flow and have relatively flat well-load curves. Pumps that operate near their maximum recommended rate have steep performance curves, and this is shown to minimize the effect of an underperforming pump on producing rate. Equations are developed for calculating the effects of pump performance and speed. Application requires evaluating the slopes of the pump-performance and well-load curves at design rate. The usefulness of these equations is demonstrated by practical examples. it is also demonstrated that flow stall can occur easily in underpressured reservoir applications when pumps designed to operate near their minimum recommended rate are installed.","PeriodicalId":22020,"journal":{"name":"Spe Production Engineering","volume":"19 1","pages":"301-306"},"PeriodicalIF":0.0,"publicationDate":"1992-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88016648","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}
This paper describes a theoretical approach to determine the inhibitor dynamic adsorption isotherm from coreflood experiments. The main feature of the isotherm that contributes principally to the long squeeze life is highlighted. The problems of modeling near-well squeeze treatments and an improved simulator are discussed.
{"title":"Interpretation and theoretical modeling of scale-inhibitor/tracer corefloods","authors":"K. S. Sorble, R. Wat, A. Todd","doi":"10.2118/20687-PA","DOIUrl":"https://doi.org/10.2118/20687-PA","url":null,"abstract":"This paper describes a theoretical approach to determine the inhibitor dynamic adsorption isotherm from coreflood experiments. The main feature of the isotherm that contributes principally to the long squeeze life is highlighted. The problems of modeling near-well squeeze treatments and an improved simulator are discussed.","PeriodicalId":22020,"journal":{"name":"Spe Production Engineering","volume":"2 1","pages":"307-312"},"PeriodicalIF":0.0,"publicationDate":"1992-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88125142","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}
This paper details the subsea corrosion protection system of the tension leg well platform (TLWP), which comprises coatings and cathodic protection (CP). Postinstallation surveys reveal potentials of at least 150 mV more protective than the minimum potential required for protection. The TLWP protection system weighs 434,000 lbm less than the conventional CP design, with 286,000 lbm less on the floating portion of the TLWP.
{"title":"THE TLWP CATHODIC PROTECTION SYSTEM","authors":"S. Evans","doi":"10.2118/20834-PA","DOIUrl":"https://doi.org/10.2118/20834-PA","url":null,"abstract":"This paper details the subsea corrosion protection system of the tension leg well platform (TLWP), which comprises coatings and cathodic protection (CP). Postinstallation surveys reveal potentials of at least 150 mV more protective than the minimum potential required for protection. The TLWP protection system weighs 434,000 lbm less than the conventional CP design, with 286,000 lbm less on the floating portion of the TLWP.","PeriodicalId":22020,"journal":{"name":"Spe Production Engineering","volume":"171 1","pages":"291-294"},"PeriodicalIF":0.0,"publicationDate":"1992-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86800616","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}
Sixty-five percent of the reserves of the Kuparuk River field, the second-largest producing oil field in the U.S., is contained in a 20- to 80-md-permeability sandstone. This paper provides details of stimulation design advances made over the past 3 years in this formation. The design steps for optimizing fracture treatments in a moderate-permeability formation require primary emphasis on fracture conductivity rather than on treatment size or fracture length. This philosophy was used for the 140 new wells documented in this paper. Treatment size was gradually increased once a commensurate increase in fracture conductivity was obtained. Applying the new design to the refracturing of 88 producing wells in the field resulted in an incremental 40,000 BOPD, a significant portion of the field's 300,000 BOPD
{"title":"Optimal fracture stimulation of a moderate-permeability reservoir―Kuparuk River Unit, Alaska","authors":"C. Pearson, A. Bond, M. Eck, K. W. Lynch","doi":"10.2118/20707-PA","DOIUrl":"https://doi.org/10.2118/20707-PA","url":null,"abstract":"Sixty-five percent of the reserves of the Kuparuk River field, the second-largest producing oil field in the U.S., is contained in a 20- to 80-md-permeability sandstone. This paper provides details of stimulation design advances made over the past 3 years in this formation. The design steps for optimizing fracture treatments in a moderate-permeability formation require primary emphasis on fracture conductivity rather than on treatment size or fracture length. This philosophy was used for the 140 new wells documented in this paper. Treatment size was gradually increased once a commensurate increase in fracture conductivity was obtained. Applying the new design to the refracturing of 88 producing wells in the field resulted in an incremental 40,000 BOPD, a significant portion of the field's 300,000 BOPD","PeriodicalId":22020,"journal":{"name":"Spe Production Engineering","volume":"7 1","pages":"259-266"},"PeriodicalIF":0.0,"publicationDate":"1992-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87539422","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}
J. Martins, K. Leung, M. R. Jackson, D. R. Stewart, A. Carr
Tip screenout (TS) fracturing is a means of creating greater propped fracture widths and hence fracture conductivities than can be achieved by conventional fracture treatments. This allows more cost-effective stimulations of higher-permeability reservoirs, especially where non-Darcy pressure losses are significant. This paper presents a procedure to design TSO schedules and reviews field results from the Ravenspurn South gas field, which was developed between 1988 and 1989. Evidence is provided to support the view that TSO pressure responses are indeed the result of processes occurring close to the fracture tip, rather than slurry-enhanced viscosity effects along the fracture length.
{"title":"Tip screenout fracturing applied to the Ravenspurn South gas field development","authors":"J. Martins, K. Leung, M. R. Jackson, D. R. Stewart, A. Carr","doi":"10.2118/19766-PA","DOIUrl":"https://doi.org/10.2118/19766-PA","url":null,"abstract":"Tip screenout (TS) fracturing is a means of creating greater propped fracture widths and hence fracture conductivities than can be achieved by conventional fracture treatments. This allows more cost-effective stimulations of higher-permeability reservoirs, especially where non-Darcy pressure losses are significant. This paper presents a procedure to design TSO schedules and reviews field results from the Ravenspurn South gas field, which was developed between 1988 and 1989. Evidence is provided to support the view that TSO pressure responses are indeed the result of processes occurring close to the fracture tip, rather than slurry-enhanced viscosity effects along the fracture length.","PeriodicalId":22020,"journal":{"name":"Spe Production Engineering","volume":"1 1","pages":"252-258"},"PeriodicalIF":0.0,"publicationDate":"1992-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"72938054","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}
To obtain maximum productivity from unconsolidated formations where sand control is required, it is important to understand the mechanics of gravel packing. This paper describes a finite-element, numerical simulator that can predict gravel placement in the perforations and annulus of a wellbore. The equations for the simulator include mass and momentum conservation. Wellbore geometry, physical properties, and fluid and gravel-pack properties are simulator input. Experiments in a 100-ft full-scale wellbore model for three gravel-packing configurations have been successfully simulated. These configurations are a circulating pack with a washpipe, a squeeze pack, and a circulating/squeeze pack with a washpipe and a lower telltale screen. The low cost, speed, and extrapolation capabilities of the numerical simulator will greatly enhance our ability to predict gravel placement in a wellbore.
{"title":"Numerical simulation of gravel packing","authors":"P. Winterfeld, D. Schroeder","doi":"10.2118/19753-PA","DOIUrl":"https://doi.org/10.2118/19753-PA","url":null,"abstract":"To obtain maximum productivity from unconsolidated formations where sand control is required, it is important to understand the mechanics of gravel packing. This paper describes a finite-element, numerical simulator that can predict gravel placement in the perforations and annulus of a wellbore. The equations for the simulator include mass and momentum conservation. Wellbore geometry, physical properties, and fluid and gravel-pack properties are simulator input. Experiments in a 100-ft full-scale wellbore model for three gravel-packing configurations have been successfully simulated. These configurations are a circulating pack with a washpipe, a squeeze pack, and a circulating/squeeze pack with a washpipe and a lower telltale screen. The low cost, speed, and extrapolation capabilities of the numerical simulator will greatly enhance our ability to predict gravel placement in a wellbore.","PeriodicalId":22020,"journal":{"name":"Spe Production Engineering","volume":"3 1","pages":"285-290"},"PeriodicalIF":0.0,"publicationDate":"1992-08-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79343709","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}
This paper presents a graphical technique to evaluate asymmetry of hydraulically fractured wells. This technique is based on a new analytical solution for the pressure behavior of a finite-conductivity, asymmetrically fractured well during the pseudolinear flow period and the known bilinear flow solution. A semianalytical solution for transient flow toward finite-conductivity, asymmetrically fractured wells producing at constant rate is also presented. This solution was used with the analytical solution to analyze the pseudolinear flow pressure behavior. An expression relating dimensionless fracture conductivity, C{sub fD}, and asymmetry factor, a, with a parameter calculated from analysis of well-test data, {beta}{sub a}, was developed by combining the pseudolinear and bilinear flow solutions; a graph of a vs. {beta}{sub a} with C{sub fD} as a parameter is then constructed. The parameters {beta}{sub a} and C{sub fD} are calculated as follows: {beta}{sub a} = 0.309 m{sup 2}{sub bf}/(b{sub Lf}m{sub Lf}) and C{sub fD} = 2.944 m{sub Lf}m/m{sup 2}{sub bf}, with m{sub bf} as the slope of the bilinear {Delta}p-vs-t{sup 1/4} straight line, m{sub Lf} and b{sub Lf} as the slope and intercept of the pseudolinear {Delta}p-vs-t{sup 1/2} straight line, respectively, and m as the slope of the semilog {Delta}p-vs.-log t straight line obtained during themore » pseudoradial flow period. Correlations developed apply indistinctly to oil and gas wells. Published field data were reanalyzed with the technique presented here and asymmetry was detected.« less
{"title":"Evaluation of Fracture Asymmetry of Finite-Conductivity Fractured Wells","authors":"F. Rodríguez, H. Cinco-Ley, F. Samaniego-V.","doi":"10.2118/20583-PA","DOIUrl":"https://doi.org/10.2118/20583-PA","url":null,"abstract":"This paper presents a graphical technique to evaluate asymmetry of hydraulically fractured wells. This technique is based on a new analytical solution for the pressure behavior of a finite-conductivity, asymmetrically fractured well during the pseudolinear flow period and the known bilinear flow solution. A semianalytical solution for transient flow toward finite-conductivity, asymmetrically fractured wells producing at constant rate is also presented. This solution was used with the analytical solution to analyze the pseudolinear flow pressure behavior. An expression relating dimensionless fracture conductivity, C{sub fD}, and asymmetry factor, a, with a parameter calculated from analysis of well-test data, {beta}{sub a}, was developed by combining the pseudolinear and bilinear flow solutions; a graph of a vs. {beta}{sub a} with C{sub fD} as a parameter is then constructed. The parameters {beta}{sub a} and C{sub fD} are calculated as follows: {beta}{sub a} = 0.309 m{sup 2}{sub bf}/(b{sub Lf}m{sub Lf}) and C{sub fD} = 2.944 m{sub Lf}m/m{sup 2}{sub bf}, with m{sub bf} as the slope of the bilinear {Delta}p-vs-t{sup 1/4} straight line, m{sub Lf} and b{sub Lf} as the slope and intercept of the pseudolinear {Delta}p-vs-t{sup 1/2} straight line, respectively, and m as the slope of the semilog {Delta}p-vs.-log t straight line obtained during themore » pseudoradial flow period. Correlations developed apply indistinctly to oil and gas wells. Published field data were reanalyzed with the technique presented here and asymmetry was detected.« less","PeriodicalId":22020,"journal":{"name":"Spe Production Engineering","volume":"187 1","pages":"233-239"},"PeriodicalIF":0.0,"publicationDate":"1992-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"72732498","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}
This paper reports that in-situ growth of cellular material is known to cause formation damage. Bacterial reproduction and polysaccharide production are the key factors that segregate bacterial formation damage from fines and particulate damage. Carefully controlled experiments conducted on both high- and low-permeability ceramic cores showed that bacteria can plug the pore space and damage the cores. However, further experimentation demonstrated that polysaccharide production is largely responsible for this damage. This conclusion is based on a comparison of two experimental systems: core plugging from bacterial replication and polymeric production and plugging of the porous medium caused solely by cell division with no polysaccharide production. In light of these results, the interpretation of reservoir plugging resulting from the presence of bacteria requires further scrutiny.
{"title":"Effect of Bacterial Polysaccharide Production on Formation Damage","authors":"R. Lappan, H. Fogler","doi":"10.2118/19418-PA","DOIUrl":"https://doi.org/10.2118/19418-PA","url":null,"abstract":"This paper reports that in-situ growth of cellular material is known to cause formation damage. Bacterial reproduction and polysaccharide production are the key factors that segregate bacterial formation damage from fines and particulate damage. Carefully controlled experiments conducted on both high- and low-permeability ceramic cores showed that bacteria can plug the pore space and damage the cores. However, further experimentation demonstrated that polysaccharide production is largely responsible for this damage. This conclusion is based on a comparison of two experimental systems: core plugging from bacterial replication and polymeric production and plugging of the porous medium caused solely by cell division with no polysaccharide production. In light of these results, the interpretation of reservoir plugging resulting from the presence of bacteria requires further scrutiny.","PeriodicalId":22020,"journal":{"name":"Spe Production Engineering","volume":"109 1","pages":"167-171"},"PeriodicalIF":0.0,"publicationDate":"1992-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79194904","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}
Successful stimulation using CO{sub 2} foam with methanol has revived the economically marginal Canyon gas-sand reservoir of Sterling County, TX. Field experience in the Conger (Penn) field demonstrated that CO{sub 2} foam (1) lessened the water required in the fluid and (2) provided a gas assist to help remove water and lower interfacial tension (IFT). The low pH of the fluid, combined with additional clay stabilization, iron control, and enhanced water recovery additives, proved helpful in initial well response and subsequent performances. Since the CO{sub 2}-foam fracture treatments were administered, production from Sterling County Canyon gas sands met or surpassed initial rates, even though formation pressure in the field declined 33.2%. Stimulation is essential for commercial production in these sands. However, water blockage, caused by stimulation, was encountered in designing an effective completion technique for a tight formation with reduced bottomhole pressure (HBP). Production in tight, low-pressure gas wells can be completely blocked if formation pressure does not exceed the capillary pressure increase caused by injected fracture fluid. Original stimulation techniques consisted mainly of gelled-water fracture treatments containing 65,000 lbm of 20/40-mesh sand with a maximum concentration of 2 1/2 lbm/gal. In many cases, several weeks of swabbing were requiredmore » to ensure continuous flow. After the fracture treatments, about 40% water recovery was realized throughout the field. This paper discusses CO{sub 2}-foam fracture treatments and job design and presents case histories from several Conger (Penn) field CO{sub 2}-foam fracture treatments.« less
{"title":"CO2 -Foam Fracturing With Methanol Successfully Stimulates Canyon Gas Sand","authors":"J. Craft, S. Waddell, D. G. Mcfatridge","doi":"10.2118/20119-PA","DOIUrl":"https://doi.org/10.2118/20119-PA","url":null,"abstract":"Successful stimulation using CO{sub 2} foam with methanol has revived the economically marginal Canyon gas-sand reservoir of Sterling County, TX. Field experience in the Conger (Penn) field demonstrated that CO{sub 2} foam (1) lessened the water required in the fluid and (2) provided a gas assist to help remove water and lower interfacial tension (IFT). The low pH of the fluid, combined with additional clay stabilization, iron control, and enhanced water recovery additives, proved helpful in initial well response and subsequent performances. Since the CO{sub 2}-foam fracture treatments were administered, production from Sterling County Canyon gas sands met or surpassed initial rates, even though formation pressure in the field declined 33.2%. Stimulation is essential for commercial production in these sands. However, water blockage, caused by stimulation, was encountered in designing an effective completion technique for a tight formation with reduced bottomhole pressure (HBP). Production in tight, low-pressure gas wells can be completely blocked if formation pressure does not exceed the capillary pressure increase caused by injected fracture fluid. Original stimulation techniques consisted mainly of gelled-water fracture treatments containing 65,000 lbm of 20/40-mesh sand with a maximum concentration of 2 1/2 lbm/gal. In many cases, several weeks of swabbing were requiredmore » to ensure continuous flow. After the fracture treatments, about 40% water recovery was realized throughout the field. This paper discusses CO{sub 2}-foam fracture treatments and job design and presents case histories from several Conger (Penn) field CO{sub 2}-foam fracture treatments.« less","PeriodicalId":22020,"journal":{"name":"Spe Production Engineering","volume":"44 1","pages":"219-225"},"PeriodicalIF":0.0,"publicationDate":"1992-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90536415","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}
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