Pub Date : 2023-10-04DOI: 10.1109/JPHOTOV.2023.3319592
Shweta S Pal;Frank H C van Loenhout;Jelle Westerhof;Rebecca Saive
Bifacial modules combined with optimally positioned ground reflectors (albedo) can boost photovoltaic (PV) yield. Yet, a rigorous understanding and benchmarking of the reflector performance is missing, which leads to errors in power yield and economic estimates, thus hampering PV market penetration. Here, we address this impediment by establishing an experimentally validated reverse ray tracing (RRT) approach, combined with empirically derived parameters. First, we determine the spectro-angular reflection of a wide class of ground reflectors (diffuse, glossy, and specular). These parameters were fed into our RRT software, that simulated the PV yield, which was then experimentally validated with a model PV system. The validated framework enables determining an upper limit to PV yield enhancement and current mismatch within modules exposed to different kinds of reflectors. Our approach helps assessing already-existing natural and exotic reflectors, and inspire novel reflectors for enhanced PV yield and economic benefits.
{"title":"Understanding and Benchmarking Ground Reflectors for Bifacial Photovoltaic Yield Enhancement","authors":"Shweta S Pal;Frank H C van Loenhout;Jelle Westerhof;Rebecca Saive","doi":"10.1109/JPHOTOV.2023.3319592","DOIUrl":"10.1109/JPHOTOV.2023.3319592","url":null,"abstract":"Bifacial modules combined with optimally positioned ground reflectors (albedo) can boost photovoltaic (PV) yield. Yet, a rigorous understanding and benchmarking of the reflector performance is missing, which leads to errors in power yield and economic estimates, thus hampering PV market penetration. Here, we address this impediment by establishing an experimentally validated reverse ray tracing (RRT) approach, combined with empirically derived parameters. First, we determine the spectro-angular reflection of a wide class of ground reflectors (diffuse, glossy, and specular). These parameters were fed into our RRT software, that simulated the PV yield, which was then experimentally validated with a model PV system. The validated framework enables determining an upper limit to PV yield enhancement and current mismatch within modules exposed to different kinds of reflectors. Our approach helps assessing already-existing natural and exotic reflectors, and inspire novel reflectors for enhanced PV yield and economic benefits.","PeriodicalId":445,"journal":{"name":"IEEE Journal of Photovoltaics","volume":"14 1","pages":"160-169"},"PeriodicalIF":3.0,"publicationDate":"2023-10-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"https://ieeexplore.ieee.org/stamp/stamp.jsp?tp=&arnumber=10272316","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"135954718","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"OA","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The absence of practical models for estimating the impact of air pollution on solar output presents a challenge for forecasting of solar electricity production and creates more uncertainty for financing and insuring solar plants. While the physics of irradiance attenuation due to aerosols are well understood, complex atmospheric conditions and lack of detailed atmospheric measurement make them impractical for industry or small-scale solar users to calculate its impact on PV power generation. Simple, empirical models to quantify the overall effect from real-world observations are scarce. In this study, we make use of both the experimental approach as well as large-scale real-world observational data from more than 15 sites to empirically evaluate the impact of air pollution on PV production using only common weather parameters. We show that the impact of PM2.5 on irradiance and, hence, PV output is approximately linear at low and moderate levels of PM2.5, with a 100 μg/m 3 increase corresponding to a reduction of around 15 ± 5% relative under clear sky conditions, which is broadly consistent with previous preliminary results reported from literature. This effect saturates at higher PM2.5 concentrations beyond 300 μg/m 3 and is reduced at high cloud coverage. The methodology developed in this study represents a viable path towards establishing a common ground for standards. The results obtained are the most comprehensive so far in terms of breadth and depth among similar empirical studies using ground-based observations. They provide a basis for establishing a functional model for industry practitioners in the PV community.
{"title":"Toward the Development of an Empirical Model of Air Pollution Impact on Solar PV Output for Industry Use","authors":"Haohui Liu;Yele Sun;Congyi Tan;Cyrus Ho;Lu Zhao;Anders Hove","doi":"10.1109/JPHOTOV.2023.3317636","DOIUrl":"https://doi.org/10.1109/JPHOTOV.2023.3317636","url":null,"abstract":"The absence of practical models for estimating the impact of air pollution on solar output presents a challenge for forecasting of solar electricity production and creates more uncertainty for financing and insuring solar plants. While the physics of irradiance attenuation due to aerosols are well understood, complex atmospheric conditions and lack of detailed atmospheric measurement make them impractical for industry or small-scale solar users to calculate its impact on PV power generation. Simple, empirical models to quantify the overall effect from real-world observations are scarce. In this study, we make use of both the experimental approach as well as large-scale real-world observational data from more than 15 sites to empirically evaluate the impact of air pollution on PV production using only common weather parameters. We show that the impact of PM2.5 on irradiance and, hence, PV output is approximately linear at low and moderate levels of PM2.5, with a 100 μg/m\u0000<sup>3</sup>\u0000 increase corresponding to a reduction of around 15 ± 5% relative under clear sky conditions, which is broadly consistent with previous preliminary results reported from literature. This effect saturates at higher PM2.5 concentrations beyond 300 μg/m\u0000<sup>3</sup>\u0000 and is reduced at high cloud coverage. The methodology developed in this study represents a viable path towards establishing a common ground for standards. The results obtained are the most comprehensive so far in terms of breadth and depth among similar empirical studies using ground-based observations. They provide a basis for establishing a functional model for industry practitioners in the PV community.","PeriodicalId":445,"journal":{"name":"IEEE Journal of Photovoltaics","volume":"13 6","pages":"991-997"},"PeriodicalIF":3.0,"publicationDate":"2023-10-03","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"71903008","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2023-10-02DOI: 10.1109/JPHOTOV.2023.3318828
Haohui Liu;Lu Zhao
Underperformances in PV solar farms pose great risks to project returns and financial health. It is important to adopt proactive asset management and O&M practices to ensure good performance. Among the various possible causes of underperformance, those due to external factors such as snow, soiling, and extraordinary shading from vegetation growth can usually be mitigated. However, there is a lack of cost effective and reliable method to detect these phenomena. In this work, we explore the possibility of utilizing inverter MPPT voltage readings available from common SCADA and monitoring systems to detect vegetation shading. It is found that vegetation shading can cause significant deviation in voltage characteristics. This includes increased discrepancy among MPPT inputs, decrease in voltage level, and excessive voltage fluctuation under clear sky. Based on these signature patterns, it is possible to design algorithms to detect vegetation growth episodes and issue performance alerts to remote operators.
{"title":"Using Inverter MPPT Voltage to Detect Vegetation Shading in Solar Farms","authors":"Haohui Liu;Lu Zhao","doi":"10.1109/JPHOTOV.2023.3318828","DOIUrl":"https://doi.org/10.1109/JPHOTOV.2023.3318828","url":null,"abstract":"Underperformances in PV solar farms pose great risks to project returns and financial health. It is important to adopt proactive asset management and O&M practices to ensure good performance. Among the various possible causes of underperformance, those due to external factors such as snow, soiling, and extraordinary shading from vegetation growth can usually be mitigated. However, there is a lack of cost effective and reliable method to detect these phenomena. In this work, we explore the possibility of utilizing inverter MPPT voltage readings available from common SCADA and monitoring systems to detect vegetation shading. It is found that vegetation shading can cause significant deviation in voltage characteristics. This includes increased discrepancy among MPPT inputs, decrease in voltage level, and excessive voltage fluctuation under clear sky. Based on these signature patterns, it is possible to design algorithms to detect vegetation growth episodes and issue performance alerts to remote operators.","PeriodicalId":445,"journal":{"name":"IEEE Journal of Photovoltaics","volume":"13 6","pages":"979-985"},"PeriodicalIF":3.0,"publicationDate":"2023-10-02","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"71903004","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2023-10-02DOI: 10.1109/JPHOTOV.2023.3319022
Christian Breyer;Ayobami Solomon Oyewo;Alejandro Kunkar;Rasul Satymov
The Caribbean and Puerto Rico are lagging in ramping renewable energy (RE) capacities. Energy system transition pathways reaching 100% RE by 2050 for Puerto Rico and the Caribbean are analyzed for all energy supplies. Islands are often limited in available land; therefore, scenario variations are considered, including offshore floating photovoltaics (PV). The results for Puerto Rico clearly indicate the enormous benefits of reaching 100% RE, as the levelized cost of electricity (LCOE) can be reduced from more than 100 €/MWh in 2020 to 47.4 €/MWh in 2050, and the levelized cost of energy, including all energy sectors, declines from 79 to 53 €/MWh, respectively. PV reaches 81% of all electricity supply, leading to 33.4 GW installed capacity, thereof 17.5 GW offshore floating PV due to area limitation. Without area limitation, the total system cost would be about 2.7% lower. The key metrics for the Caribbean development from 2020 to 2050 are as follows: electricity generation from 110 to 677 TWh, PV supply share from 2% to 92%, PV capacity from 1 to 332 GW, thereof 19% prosumer, 81% utility-scale with up to 38% offshore floating PV, and LCOE from above 100 to 31.9 €/MWh. The prosperity of Puerto Rico and the Caribbean is closely related to solar PV, the dominating source of energy in their Solar-to-X Economy.
{"title":"Role of Solar Photovoltaics for a Sustainable Energy System in Puerto Rico in the Context of the Entire Caribbean Featuring the Value of Offshore Floating Systems","authors":"Christian Breyer;Ayobami Solomon Oyewo;Alejandro Kunkar;Rasul Satymov","doi":"10.1109/JPHOTOV.2023.3319022","DOIUrl":"https://doi.org/10.1109/JPHOTOV.2023.3319022","url":null,"abstract":"The Caribbean and Puerto Rico are lagging in ramping renewable energy (RE) capacities. Energy system transition pathways reaching 100% RE by 2050 for Puerto Rico and the Caribbean are analyzed for all energy supplies. Islands are often limited in available land; therefore, scenario variations are considered, including offshore floating photovoltaics (PV). The results for Puerto Rico clearly indicate the enormous benefits of reaching 100% RE, as the levelized cost of electricity (LCOE) can be reduced from more than 100 €/MWh in 2020 to 47.4 €/MWh in 2050, and the levelized cost of energy, including all energy sectors, declines from 79 to 53 €/MWh, respectively. PV reaches 81% of all electricity supply, leading to 33.4 GW installed capacity, thereof 17.5 GW offshore floating PV due to area limitation. Without area limitation, the total system cost would be about 2.7% lower. The key metrics for the Caribbean development from 2020 to 2050 are as follows: electricity generation from 110 to 677 TWh, PV supply share from 2% to 92%, PV capacity from 1 to 332 GW, thereof 19% prosumer, 81% utility-scale with up to 38% offshore floating PV, and LCOE from above 100 to 31.9 €/MWh. The prosperity of Puerto Rico and the Caribbean is closely related to solar PV, the dominating source of energy in their Solar-to-X Economy.","PeriodicalId":445,"journal":{"name":"IEEE Journal of Photovoltaics","volume":"13 6","pages":"842-848"},"PeriodicalIF":3.0,"publicationDate":"2023-10-02","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"71902901","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Bifacial photovoltaic (PV) modules can generate power even from rear-side solar irradiance. Consequently, the rear side of the bifacial PV module must not be hindered by structures. However, structures such as beams are often installed behind modules to ensure structural strength and for various other reasons. In such cases, the output power of the bifacial module is reduced because of partial shading on the rear side. This study entailed an analysis of the albedo dependence of the bifacial gain losses in bifacial modules due to inherent partial shading produced by rear-side support structures (e.g., mounting, frame, and beams). An analysis method combining ray tracing and electrical circuit simulation was implemented and verified through field experiments. The results demonstrate that the bifacial gain decreases nonlinearly at high albedo when the beam is closely attached to the rear side of the module. This loss is reduced by half upon placing the beam at a distance equivalent to the thickness of the beam from the module. The results also indicate the mismatch loss caused by each part of the module's support structure.
{"title":"Albedo-Dependent Bifacial Gain Losses in Photovoltaic Modules With Rear-Side Support Structures","authors":"Shuto Tsuchida;Yuki Tsuno;Daisuke Sato;Takashi Oozeki;Noboru Yamada","doi":"10.1109/JPHOTOV.2023.3317970","DOIUrl":"https://doi.org/10.1109/JPHOTOV.2023.3317970","url":null,"abstract":"Bifacial photovoltaic (PV) modules can generate power even from rear-side solar irradiance. Consequently, the rear side of the bifacial PV module must not be hindered by structures. However, structures such as beams are often installed behind modules to ensure structural strength and for various other reasons. In such cases, the output power of the bifacial module is reduced because of partial shading on the rear side. This study entailed an analysis of the albedo dependence of the bifacial gain losses in bifacial modules due to inherent partial shading produced by rear-side support structures (e.g., mounting, frame, and beams). An analysis method combining ray tracing and electrical circuit simulation was implemented and verified through field experiments. The results demonstrate that the bifacial gain decreases nonlinearly at high albedo when the beam is closely attached to the rear side of the module. This loss is reduced by half upon placing the beam at a distance equivalent to the thickness of the beam from the module. The results also indicate the mismatch loss caused by each part of the module's support structure.","PeriodicalId":445,"journal":{"name":"IEEE Journal of Photovoltaics","volume":"13 6","pages":"938-944"},"PeriodicalIF":3.0,"publicationDate":"2023-09-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"71903030","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2023-09-29DOI: 10.1109/JPHOTOV.2023.3311896
Maxime Mussard;Heine N. Riise;Marie S. Wiig;Sigrid Rønneberg;Sean E. Foss
Owing to the well-known temperature dependence of photovoltaic (PV) module performance, it is important to correct the performance ratio with respect to temperature. In this study, temperature coefficients given by the manufacturer for three different PV cell technologies are compared with experimentally obtained temperature coefficients for a PV park situated in southern Norway. Three irradiance estimation methods are used to calculate these experimental temperature coefficients. The results show that they can differ significantly from the ones provided in the datasheet of the manufacturer for all three PV systems, but whether the temperature coefficient value increases or decreases depends on the systems and/or the irradiance estimation method. Furthermore, by analyzing nine clear sky days at different times of the year, it is found that the seasonality of the performance ratio can be significantly reduced when employing the experimental temperature coefficient rather than the datasheet temperature coefficient. As such, it may be more relevant to correct the performance ratio with experimental temperature coefficients rather than with the temperature coefficient from the system datasheet, especially for systems that experience large temperature differences. It is also found that the irradiance estimation method can significantly impact the experimental temperature coefficient. This study shows that the choice of irradiance estimation method and temperature coefficient can affect the performance interpretation of solar PV systems and must then be considered carefully.
{"title":"Influence of Temperature Coefficient and Sensor Choice on PV System Performance","authors":"Maxime Mussard;Heine N. Riise;Marie S. Wiig;Sigrid Rønneberg;Sean E. Foss","doi":"10.1109/JPHOTOV.2023.3311896","DOIUrl":"https://doi.org/10.1109/JPHOTOV.2023.3311896","url":null,"abstract":"Owing to the well-known temperature dependence of photovoltaic (PV) module performance, it is important to correct the performance ratio with respect to temperature. In this study, temperature coefficients given by the manufacturer for three different PV cell technologies are compared with experimentally obtained temperature coefficients for a PV park situated in southern Norway. Three irradiance estimation methods are used to calculate these experimental temperature coefficients. The results show that they can differ significantly from the ones provided in the datasheet of the manufacturer for all three PV systems, but whether the temperature coefficient value increases or decreases depends on the systems and/or the irradiance estimation method. Furthermore, by analyzing nine clear sky days at different times of the year, it is found that the seasonality of the performance ratio can be significantly reduced when employing the experimental temperature coefficient rather than the datasheet temperature coefficient. As such, it may be more relevant to correct the performance ratio with experimental temperature coefficients rather than with the temperature coefficient from the system datasheet, especially for systems that experience large temperature differences. It is also found that the irradiance estimation method can significantly impact the experimental temperature coefficient. This study shows that the choice of irradiance estimation method and temperature coefficient can affect the performance interpretation of solar PV systems and must then be considered carefully.","PeriodicalId":445,"journal":{"name":"IEEE Journal of Photovoltaics","volume":"13 6","pages":"920-928"},"PeriodicalIF":3.0,"publicationDate":"2023-09-29","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"71903081","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2023-09-19DOI: 10.1109/JPHOTOV.2023.3309933
Michael G. Deceglie;Timothy J Silverman;Ethan Young;William B. Hobbs;Cara Libby
Cracks can form in silicon solar cells in an otherwise intact photovoltaic module due to mechanical stresses such as rough handling or hail. The immediate impact on power due to these cracks can be readily measured, but it is also known from accelerated testing that the cracks can worsen over time. However, it is not clear how to predict the extent of future field degradation due to cracked cells, which requires a calibrated accelerated test. We describe progress toward such a test. In particular, we report on the outdoor aging of modules with cracked cells for nearly two years. We find that modules with cracked cells degraded in the field an average of 0.5% absolute more than uncracked modules over a period of 21 months. We also characterize the modules with multitemperature electroluminescence and find that the degradation is associated with cell fragments that become electrically isolated. We compare the weathering outdoors with the two types of accelerated tests: thermal cycling and a novel accelerated test, dynamic mechanical acceleration (DMX). DMX can apply thousands of pressure cycles at a frequency of approximately 10 Hz and pressures <200 Pa, which are relevant to the wind-driven pressure cycles experienced by modules outdoors. We find that the thermal cycles designed to reproduce the cumulative temperature change from the field overestimate field degradation and can excite noncell-crack degradation. DMX results were promising, reproducing degradation levels similar to those observed outdoors over 21 months with a test that can be performed in less than an hour.
{"title":"Field and Accelerated Aging of Cracked Solar Cells","authors":"Michael G. Deceglie;Timothy J Silverman;Ethan Young;William B. Hobbs;Cara Libby","doi":"10.1109/JPHOTOV.2023.3309933","DOIUrl":"https://doi.org/10.1109/JPHOTOV.2023.3309933","url":null,"abstract":"Cracks can form in silicon solar cells in an otherwise intact photovoltaic module due to mechanical stresses such as rough handling or hail. The immediate impact on power due to these cracks can be readily measured, but it is also known from accelerated testing that the cracks can worsen over time. However, it is not clear how to predict the extent of future field degradation due to cracked cells, which requires a calibrated accelerated test. We describe progress toward such a test. In particular, we report on the outdoor aging of modules with cracked cells for nearly two years. We find that modules with cracked cells degraded in the field an average of 0.5% absolute more than uncracked modules over a period of 21 months. We also characterize the modules with multitemperature electroluminescence and find that the degradation is associated with cell fragments that become electrically isolated. We compare the weathering outdoors with the two types of accelerated tests: thermal cycling and a novel accelerated test, dynamic mechanical acceleration (DMX). DMX can apply thousands of pressure cycles at a frequency of approximately 10 Hz and pressures <200 Pa, which are relevant to the wind-driven pressure cycles experienced by modules outdoors. We find that the thermal cycles designed to reproduce the cumulative temperature change from the field overestimate field degradation and can excite noncell-crack degradation. DMX results were promising, reproducing degradation levels similar to those observed outdoors over 21 months with a test that can be performed in less than an hour.","PeriodicalId":445,"journal":{"name":"IEEE Journal of Photovoltaics","volume":"13 6","pages":"836-841"},"PeriodicalIF":3.0,"publicationDate":"2023-09-19","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"71902899","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2023-09-18DOI: 10.1109/JPHOTOV.2023.3311890
Kinza Maham;Petri Kärhä;Erkki Ikonen
A solar cell is characterized using a solar simulator and a reference cell in accordance with standard testing conditions. Deviations between the spectral responsivities of the reference cell and the cell being studied, and deviations of the spectral irradiance of the light source used from the specified air mass 1.5 introduce systematic errors in the calibration of solar cells. These errors are corrected with the so-called spectral mismatch (SMM) correction factor. We demonstrate a Monte Carlo simulation-based analysis of the uncertainties present in an SMM correction factor taking into account the possible spectral correlations of the input parameters, such as the spectral irradiance and the spectral responsivities of the reference cell and the solar cell under test. We also perform a detailed uncertainty analysis of the subcomponents of the SMM factor mainly arising from the spectral irradiance incident on the solar cell. In order to test our estimates, we present a comparison of the uncertainties by six other independent calculations carried out by other institutes. We obtain the worst-case, average, and best-case scenario uncertainties of the SMM correction factor by assuming components to be severely correlated, partially correlated, and not correlated, respectively. The corresponding expanded uncertainties ( k $=$ 2) are 1.26%, 0.44%, and 0.06%. The worst- and best-case uncertainties lie at the maximum and minimum extremes of the uncertainties estimated by the participants, while the uncertainty estimate obtained assuming partial correlations is close to the median and mean of all results.
{"title":"Spectral Mismatch Uncertainty Estimation in Solar Cell Calibration Using Monte Carlo Simulation","authors":"Kinza Maham;Petri Kärhä;Erkki Ikonen","doi":"10.1109/JPHOTOV.2023.3311890","DOIUrl":"https://doi.org/10.1109/JPHOTOV.2023.3311890","url":null,"abstract":"A solar cell is characterized using a solar simulator and a reference cell in accordance with standard testing conditions. Deviations between the spectral responsivities of the reference cell and the cell being studied, and deviations of the spectral irradiance of the light source used from the specified air mass 1.5 introduce systematic errors in the calibration of solar cells. These errors are corrected with the so-called spectral mismatch (SMM) correction factor. We demonstrate a Monte Carlo simulation-based analysis of the uncertainties present in an SMM correction factor taking into account the possible spectral correlations of the input parameters, such as the spectral irradiance and the spectral responsivities of the reference cell and the solar cell under test. We also perform a detailed uncertainty analysis of the subcomponents of the SMM factor mainly arising from the spectral irradiance incident on the solar cell. In order to test our estimates, we present a comparison of the uncertainties by six other independent calculations carried out by other institutes. We obtain the worst-case, average, and best-case scenario uncertainties of the SMM correction factor by assuming components to be severely correlated, partially correlated, and not correlated, respectively. The corresponding expanded uncertainties (\u0000<italic>k</i>\u0000 \u0000<inline-formula><tex-math>$=$</tex-math></inline-formula>\u0000 2) are 1.26%, 0.44%, and 0.06%. The worst- and best-case uncertainties lie at the maximum and minimum extremes of the uncertainties estimated by the participants, while the uncertainty estimate obtained assuming partial correlations is close to the median and mean of all results.","PeriodicalId":445,"journal":{"name":"IEEE Journal of Photovoltaics","volume":"13 6","pages":"899-904"},"PeriodicalIF":3.0,"publicationDate":"2023-09-18","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"71902923","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2023-09-15DOI: 10.1109/JPHOTOV.2023.3311891
Marco Nicoletto;Alessandro Caria;Fabiana Rampazzo;Carlo De Santi;Matteo Buffolo;Giovanna Mura;Francesca Rossi;Xuanqui Huang;Houqiang Fu;Hong Chen;Yuji Zhao;Gaudenzio Meneghesso;Enrico Zanoni;Matteo Meneghini
Based on combined electrical analysis, microscopy investigation, and two-dimensional simulations we investigate the influence of V-pits on the turn-on voltage and current-voltage characteristics of high periodicity InGaN-GaN multiple quantum wells solar cells. Experimental measurements indicate that the sample with the thinnest p-GaN layer presents an early turn-on, which is not present for thicker p-GaN layers. Through technology computer aided design (TCAD) simulations, we show that the early turn-on is due to the insufficient V-pit planarization, as demonstrated by scanning electron microscopy and transmission electron microscopy analysis. V-pits penetrate the junctions, and locally put the quantum well region in closer connection with the p-side contact. The results provide insight on the role of V-pits on the electrical performance of high-periodicity quantum well devices, and demonstrate the existence of a trade-off between the need of a thin p-GaN (to limit short-wavelength absorption) and a thicker p-GaN, to favor V-pit planarization.
{"title":"Influence of V-Pits on the Turn-On Voltage of GaN-Based High Periodicity Multiple Quantum Well Solar Cells","authors":"Marco Nicoletto;Alessandro Caria;Fabiana Rampazzo;Carlo De Santi;Matteo Buffolo;Giovanna Mura;Francesca Rossi;Xuanqui Huang;Houqiang Fu;Hong Chen;Yuji Zhao;Gaudenzio Meneghesso;Enrico Zanoni;Matteo Meneghini","doi":"10.1109/JPHOTOV.2023.3311891","DOIUrl":"https://doi.org/10.1109/JPHOTOV.2023.3311891","url":null,"abstract":"Based on combined electrical analysis, microscopy investigation, and two-dimensional simulations we investigate the influence of V-pits on the turn-on voltage and current-voltage characteristics of high periodicity InGaN-GaN multiple quantum wells solar cells. Experimental measurements indicate that the sample with the thinnest p-GaN layer presents an early turn-on, which is not present for thicker p-GaN layers. Through technology computer aided design (TCAD) simulations, we show that the early turn-on is due to the insufficient V-pit planarization, as demonstrated by scanning electron microscopy and transmission electron microscopy analysis. V-pits penetrate the junctions, and locally put the quantum well region in closer connection with the p-side contact. The results provide insight on the role of V-pits on the electrical performance of high-periodicity quantum well devices, and demonstrate the existence of a trade-off between the need of a thin p-GaN (to limit short-wavelength absorption) and a thicker p-GaN, to favor V-pit planarization.","PeriodicalId":445,"journal":{"name":"IEEE Journal of Photovoltaics","volume":"13 6","pages":"891-898"},"PeriodicalIF":3.0,"publicationDate":"2023-09-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"71902922","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":3,"RegionCategory":"工程技术","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Pub Date : 2023-09-15DOI: 10.1109/JPHOTOV.2023.3313109
Mason Mahaffey;Arthur Onno;Carey Reich;Adam Danielson;Walajabad Sampath;Zachary C. Holman
There are few doping concentration measurement techniques that are contactless and usable for all semiconductors. In this article, we demonstrate the use of injection-dependent quasi-steady-state photoluminescence to simultaneously measure the external radiative efficiency, minority-carrier lifetime, and activated dopant concentration of solar cell absorber layers. We first demonstrate this measurement on Si, for which established lifetime and doping measurement techniques exist, and determine a doping density of 4.2 × 10 15 cm −3 , which is within a factor of 2 from the 2.1 × 10 15 cm −3 value calculated from quasi-steady state photoconductance. Then, we demonstrate the use of the technique to measure doping concentrations of CdSeTe over two orders of magnitude and of perovskite down to nearly 10 14 cm −3 —materials that are much more difficult to accurately assess with other techniques.
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