This case study investigates mono-crystalline silicon modules from underperforming portions of a utility-scale photovoltaic power plant. Field-collected I-V curves and electroluminescence imaging suggested that increased series resistance was a primary factor driving module degradation. Selected modules were removed from the field for further analysis, including incremental damp heat accelerated testing, which confirmed a progression in series resistance degradation. Two distinct cell degradation behaviors became apparent during the investigation. Cross-sectional scanning electron microscopy (with elemental analysis) and scanning spreading resistance microscopy identified key differences between the two degradation mechanisms, primarily grid finger width and contact resistance. Additionally, the study highlights the reliability implications of retest requirements in International Electrotechnical Commission 61215 for material changes and how they may have mitigated the degradation observed at this site.

Simultaneous changes in photovoltaic (PV) module architecture-such as increased area, replacing the polymeric backsheet with a glass backsheet, and reducing glass thickness from 3.2 to 2.0 mm-have resulted in a novel failure called spontaneous glass breakage. Spontaneous glass breakage results in front and/or rear glass failure without any obvious cause. The resulting low-energy fracture patterns have raised concerns about the thermal strengthening in 2.0-mm glass. We present validation of a nonde structive method for measuring the glass surface stress in PV modules. We use a scattered light polariscope to examine the glass properties of 11 modules from 6 solar fields, with and without spontaneous glass breakage. Based on a Mann-Whitney test p-value of 1.4 & times; 10(-6), we conclude that there is a correlation between lower surface stress and susceptibility to spontaneous breakage. A Kendall's Tau test p-value of 2.0 & times; 10(-4) indicates a correlation between increased module area and lower surface stress. We find that 2.0-mm glass can be, and often is, fully tempered (surface stress >= 69 MPa), but inspecting the fracture pattern is not a reliable way to assess the amount of thermal strengthening. A combination of factors, not just surface stress, influences glass breakage.

We present a fast, low-cost ultraviolet (UV) spot test to screen photovoltaic modules for UV-induced degradation (UVID). The measurement is based on a fiber-coupled arc lamp that delivers a highly accelerated local UV dose—approximately five years of equivalent field exposure in less than a day. Spot-exposed areas are evaluated using electroluminescence imaging. We test a “known bad” product, which was observed to experience UVID in the field, and a “known good” product which did not exhibit UVID in the field. Results indicate that the method may be useful as a quick and relatively inexpensive quality control screening tool for customers and manufacturers.

Corrosion of the antireflective coating on a photovoltaic cell ("AR(c) corrosion") has previously been observed in studies using hot-humid test conditions with external high-voltage (HV) bias. This study primarily focuses on known vulnerable legacy aluminum back surface field cells in mini-modules (MiMos) put through comparative stepped stress tests. Each cell type had MiMos at +1500 V, -1500 V, or unbiased ("V-oc") potential, which were sequentially subjected to test conditions of 60 degrees C/60% relative humidity (RH) for 96 h, as in International Electrotechnical Commission Technical Specification 62804-1; 70 degrees C/70% RH for 200 h; and 85 degrees C/85% RH for 200 h. Characterizations at each step included visual camera and electroluminescence (EL) imaging, colorimetry, and current-voltage curve tracing. Final characterizations included: Suns-V-oc, spatial mapping of external quantum efficiency, high-resolution photoluminescence, EL, and dark lock-in thermography imaging. Forensics were performed on extracted cores, including scanning electron microscopy (SEM) with energy-dispersive X-ray spectroscopy (EDS), X-ray photoelectron spectroscopy, and scanning Auger microscopy (SAM). Forensics were also conducted on MiMos from previous studies that underwent stepped HV aging and separate outdoor aged full-sized modules. AR(c) corrosion was specifically seen for the glass/encapsulant/cell side of the +1500 V (HV+) stressed MiMos and modules. Appearance, color, and reflectance were the most distinguishing characteristics relative to glass corrosion, gridline corrosion and delamination, and other concurrent degradation modes. SEM/EDS and SAM identified the conversion of silicon nitride to hydrated silica, hydrous silica, or hydrated amorphous silica, which preferentially occurred at the edges and tips of the pyramidal textured cell surface.

This case study investigates mono-crystalline silicon modules from a utility site flagged as underperforming. Field characterizations revealed suspected damp heat induced series resistance driving module degradation. Select modules were removed from the field and incremental damp heat accelerated testing was conducted. A bimodal distribution of cell degradation became apparent. Cross-sectional scanning electron microscopy, energy-dispersive X-ray spectroscopy, and scanning spreading resistance microscopy reveal the most significant differences between the two are grid finger width and contact resistance. We discuss the reliability implications of re-test requirements in IEC 61215 for bill-of-material changes and how they may have mitigated degradation at this site.

A recent trend in commercial PV modules is a transition to n-type silicon cells, including passivated emitter rear totally diffused (n-PERT), tunnel oxide passivated contact (TOPCon), and silicon heterojunction (SHJ). There is evidence via lab studies that some of these cells are more susceptible to UV induced degradation (UVID), yet there is a lack of confirmation that such degradation occurs in the field. Current IEC standards designed to screen for early module failures require only minimal UV exposure (15 kWh/m(2) 280-400 nm, similar to 2-3 months equivalent outdoor exposure). Here, we investigate fielded n-PERT silicon (Si) modules from a commercial utility that show power losses of similar to 2%/year. We present a comprehensive picture of the physics and chemistry of degradation supported by both module and cell electronic characterization (EL, PL, IV, EQE, and DLIT) and materials-level morphological and chemical analysis (SEM, EDS, XPS, FTIR, and HPLC). All sampled site modules show short circuit current (I-sc) and open circuit voltage (V-oc) losses when compared to unfielded spares, with the most severely degraded also having losses in fill factor (FF). We identify two different degradation modes contributing to overall power loss: (1) external quantum efficiency (EQE) measurements show losses in the blue range of the spectra, indicative of cell surface recombination losses, and (2) variations in high series resistance (R-s) at the cell level that are correlated with compositional differences in cell metallization. Using unfielded spares, we were able to reproduce V-oc, I-sc, and EQE losses via a minimum UV stress of 67.5 kWh/m(2) (280-400 nm), 4.5x the exposure currently required in IEC 61215-2 (MQT 10). Degradation continued with additional UV dosage equivalent to the fielded modules (405 kWh/m(2) total), with power loss leveling out at an average of 6.1%. Subsequent 1000 h of 85% RH/85 degrees C damp heat testing showed that cells exposed to UV underwent additional severe series resistance degradation, even those without the susceptible paste composition seen in the field, whereas non-UV exposed cells saw little change. We attribute this to higher concentrations of acetic acid generated on the UV exposed area of the module, leading to degradation of the gridline/cell interface and high R-s. This study is unique in that it reproduces field observed utility scale UVID with an accelerated test and supports the need for standards development for longer UV exposure combined with other stress factors to catch materials interplay within a module package.

The engineering of mixed-solvent formulations and their evaporation conditions are key to reproducible perovskite coatings for high-performance photovoltaics. Here, we report a lumped-parameter evaporation model to predict the evolution of a perovskite ink liquid film over time (solvent ratio, solute concentration, and film thickness). The drying-rate model is validated via in situ film-thickness measurements, and the dicted transient liquid film state is mapped as a process path. These methods allow for the prediction of cess sensitivity to local environmental factors and the understanding and visualization of a broader processing parameter space enabled through the coupling of process and ink engineering. Process maps are applied to create a new framework for scalable perovskite coating development with a goal of improving the reproducibility and transferability of perovskite fabrication. This approach is demonstrated with blade-coated FA0.83Cs0.17PbI3 photovoltaic devices, improving the photovoltaic conversion efficiency from 17.5% 1.7% to 20.3% +/- 0.6%.

The rise of photovoltaics (PV) as a major contributor to energy generation worldwide has also coincided with major changes in module format. In the last ~5 years, utility scale modules have transitioned to a glass-glass package to take advantage of bifaciality, while at the same time decreasing the glass thickness from 3.2 mm to ~2 mm to save on cost and weight. In parallel, modules have continued their trend of increasing in size, with areas of 2.5 - 3 m2 common today. Despite top tier manufacturers testing to current IEC standards, there has been an uptick of modern glass-glass modules spontaneously breaking in the field, sometimes even before the PV plant is brought online. This is of grave concern as even a small number of cracked modules have been observed to cause ground faults and inverter down time. One of multiple possible contributing factors is a change in glass strength, which is dependent on the thickness, flaws, and stress profile from heat treatments of the glass. Our work examines the variability of glass thickness, surface stress, and compression depth in a variety of PV modules, from older glass-backsheet, to more modern glass-glass modules of various sizes. We discuss a procedure developed to get consistent stress measurements on a fully intact module. We find that while most glass panes measured pass ASTM 1048-18 as fully tempered glass, the surface stress of modules known to break in the field is overall lower compared to glass-backsheet and glass-glass modules not known to spontaneously break. Furthermore, we discuss how compression depth, inherently smaller in thinner glass, could contribute to a narrower tolerance of flaws. We discuss how the decrease of both the surface stress and compression depth in modules known to spontaneously break in the field could be one contributing factor increasing probability of failure.

Corrosion of the antireflective coating on the cell ("ARc corrosion") was previously observed in studies using hot-humid test conditions with external high voltage (HV) bias. Because ARc corrosion is not well understood, mini-modules (MiMos) were examined in a comparative experiment using PERC and PERT as well as legacy Al-BSF cells. For separate MiMos with the cell circuit electrical at +1500 V, -1500 V, or unbiased ("Voc"), test conditions in the comparative study included 60 degrees C/60%RH for 96 h, as in IEC TS 62804-1; 70 degrees C/70%RH for 200 h; and 85 degrees C/85%RH for 200 h. Characterizations at each read point included: camera and electroluminescence (EL) imaging, colorimetry, and I-V curve tracing. Characterizations at the final read point included: SunsVoc; spatially mapping external quantum efficiency (EQE); high resolution: photoluminescence (PL), EL, and dark lock-in thermographic (DLIT) imaging. Forensics were performed on extracted cores, including scanning electron microscopy (SEM) with energy-dispersive X-ray spectroscopy (EDS) and scanning Auger microscopy (SAM). Forensics were also conducted on MiMos (stepped HV aging) and full-sized modules (outdoor aging) from previous studies. ARc corrosion was specifically observed for the glass/encapsulant/cell side of +1500 V (HV+) stressed MiMos, where appearance, color, and reflectance were the characteristics most distinguished relative to simultaneously occurring degradation modes. SEM/EDS and SAM identified conversion of silicon nitride to silicon oxide or hydrous silica, preferentially occurring at the edges and tips of the pyramidal textured cell surface.

Current photovoltaic (PV) panels typically contain interconnected solar cells that are vacuum laminated with a polymer encapsulant between two pieces of glass or glass with a polymer backsheet. This packaging approach is ubiquitous in conventional photovoltaic technologies such as silicon and thin-film solar modules, contributing to thermal management, mechanical reinforcement, and environmental protection to enable the long lifetimes necessary to become financially acceptable. Commercial vacuum lamination processes typically occur at 150 degrees C to ensure cross-linking and/or glass bonding of the encapsulant to the glass and PV cells. Perovskite solar cells (PSCs) have emerged as a promising next-generation PV technology that is known to degrade under thermal stresses, especially at temperatures above 100 degrees C. In this study, we determine degradation modes during lamination and engineer internal diffusion barriers within the PSC to withstand the harsh thermal conditions of vacuum lamination. PSCs with self-assembled monolayers at the ITO interface and SnO X layers deposited by atomic layer deposition at the electron extraction side of the device endured vacuum lamination at conditions typical of commercial PV processes (150 degrees C) without degradation. This work demonstrates that perovskite PV can be integrated into the existing module lamination process, enabling future single- and multijunction modules utilizing perovskite absorbers.

Photovoltaic (PV) deployment has grown exponentially over the last decade, and new energy targets set by governments worldwide imply that rate will increase even more rapidly to meet these goals. Concurrently, the design of PV modules and their components continue to evolve over time to maximize power and minimize cost. These facts in combination emphasize the continued need to catch new degradation modes and develop modified or new qualification standards in PV to avoid significant negative impact to our energy infrastructure. Currently, IEC standards designed to catch UV degradation modes in full modules are minimal (3 months equivalent outdoor exposure). Here we investigate fielded n-type Si modules from a commercial utility that show power losses of -2%/yr. All sampled site modules showed Isc and Voc losses when compared to unfielded spares, with the most severely degraded also having losses in FF. EQE measurements further show losses in the blue range of the spectra. Using the un fielded spares, we were able to reproduce Voc, Isc, and EQE losses via UV stress tests. This evidence supports the need for standards development for longer term UV exposure.

Solar energy is the fastest-growing source of electricity generation globally. As deployment increases, photovoltaic (PV) panels need to be produced sustainably. Therefore, the resource utilization rate and the rate at which those resources become available in the environment must be in equilibrium while maintaining the well-being of people and nature. Metal halide perovskite (MHP) semiconductors could revolutionize PV technology due to high efficiency, readily available/accessible materials and low-cost production. Here we outline how MHP-PV panels could scale a sustainable supply chain while appreciably contributing to a global renewable energy transition. We evaluate the critical material concerns, embodied energy, carbon impacts and circular supply chain processes of MHP-PVs. The research community is in an influential position to prioritize research efforts in reliability, recycling and remanufacturing to make MHP-PVs one of the most sustainable energy sources on the market. Metal halide perovskite (MHP) materials could revolutionize photovoltaic (PV) technology but sustainability issues need to be considered. Here the authors outline how MHP-PV modules could scale a sustainable supply chain.

To meet greenhouse gas reduction targets and growing energy needs, massive increases in deployment of key technologies-photovoltaics, wind, electrolyzers, and energy storage- are anticipated over the next two to three decades. The unprecedented scale of this ranging from rapid product development cycles and lagging standards to the demand for the highest levels of system performance and reliability. an initial workshop to bring various renewable energy technologies to examine commonalities across technologies, identify areas for synergistic work, and outline a pathway for degradation science to enable a longlasting clean energy economy. connect reliability data at scale, develop cross-cutting methods, to industry standards.

As solar photovoltaic (PV) devices across the globe reach the end of their approximately 30-year lifetimes, an emerging challenge is how to handle the waste from large volumes of end-of-life (EOL) PV modules. It is projected that the cumulative mass of EOL PV modules could be up to 8 million tonnes (Mt) by 2030 so recovery of high value materials from these EOL modules through a cost efficient recycling process would minimize environmental impacts compared to disposing them in landfills[1]. A typical recycling process for EOL PV modules involves mechanical disassembly, separation of the tempered cover glass and silicon wafer followed by purification and recovery of other constituents such as Pb or Ag with the goal of reinstating the recovered materials as a PV module. However, since new module prices continue to decline and the recovered PV modules typically have a shorter lifetime and lower efficiency, the economic value of using the recovered PV materials to manufacture a new PV module is uncertain[2]. Since silicon, particularly boron-doped, is a promising candidate for next-generation anodes for lithium-ion batteries (LIB), recovering the silicon from PV modules for use in LIB anodes could be an attractive alternative. In this study we leverage the National Renewable Energy Laboratory (NREL)’s expertise in PV Si reliability and access to multiple types of EOL PV modules to study the merits of B-doped silicon recovery from silicon PV panels with regard to silicon anode cycling performance and calendar life. A simple ball milling process was developed to prepare recycled Si from EOL PV modules for use as in a LIB anode. In this talk we will be discussing the recovery efficiency, purification requirements and key anode performance metrics of recycled PV silicon materials. IRENA, I.-P., End-of-Life Management: Solar Photovoltaic Panels 2016: International Renewable Energy Agency and International Energy Agency Photovoltaic Power Systems. A. Wade, P.S., K. Drozdiak, E. Brutsch. Beyond Waste – The Fate of End-of-Life Photovoltaic Panels from Large Scale PV Installations in the EU. The Socio-Economic Benefits of High Value Recycling Compared to Re-Use . in 33rd European Photovoltaic Solar Energy Conference and Exhibition . 2017.

Metal halide perovskite solar cells (PSCs) represent a promising low-cost thin-film photovoltaic technology, with unprecedented power conversion efficiencies obtained for both single-junction and tandem applications 1 – 8 . To push PSCs towards commercialization, it is critical, albeit challenging, to understand device reliability under real-world outdoor conditions where multiple stress factors (for example, light, heat and humidity) coexist, generating complicated degradation behaviours 9 – 13 . To quickly guide PSC development, it is necessary to identify accelerated indoor testing protocols that can correlate specific stressors with observed degradation modes in fielded devices. Here we use a state-of-the-art positive-intrinsic-negative (p–i–n) PSC stack (with power conversion efficiencies of up to approximately 25.5%) to show that indoor accelerated stability tests can predict our six-month outdoor ageing tests. Device degradation rates under illumination and at elevated temperatures are most instructive for understanding outdoor device reliability. We also find that the indium tin oxide/self-assembled monolayer-based hole transport layer/perovskite interface most strongly affects our device operation stability. Improving the ion-blocking properties of the self-assembled monolayer hole transport layer increases averaged device operational stability at 50 °C–85 °C by a factor of about 2.8, reaching over 1,000 h at 85 °C and to near 8,200 h at 50 °C, with a projected 20% degradation, which is among the best to date for high-efficiency p–i–n PSCs 14 – 17 .

ADVERTISEMENT RETURN TO ISSUEPREVEnergy FocusNEXTPackage Development for Reliability Testing of PerovskitesE. Ashley Gaulding*E. Ashley GauldingNational Renewable Energy Laboratory, Golden, Colorado 80401, United States*[email protected]More by E. Ashley Gauldinghttps://orcid.org/0000-0002-1772-1993, Amy E. LouksAmy E. LouksNational Renewable Energy Laboratory, Golden, Colorado 80401, United StatesMore by Amy E. Loukshttps://orcid.org/0000-0001-7797-4493, Mengjin YangMengjin YangNational Renewable Energy Laboratory, Golden, Colorado 80401, United StatesMore by Mengjin Yang, Robert TirawatRobert TirawatNational Renewable Energy Laboratory, Golden, Colorado 80401, United StatesMore by Robert Tirawat, Mickey J. WilsonMickey J. WilsonNational Renewable Energy Laboratory, Golden, Colorado 80401, United StatesMore by Mickey J. Wilson, Liam K. ShawLiam K. ShawNational Renewable Energy Laboratory, Golden, Colorado 80401, United StatesMore by Liam K. Shaw, Timothy J SilvermanTimothy J SilvermanNational Renewable Energy Laboratory, Golden, Colorado 80401, United StatesMore by Timothy J Silverman, Joseph M. LutherJoseph M. LutherNational Renewable Energy Laboratory, Golden, Colorado 80401, United StatesMore by Joseph M. Lutherhttps://orcid.org/0000-0002-4054-8244, Axel F. PalmstromAxel F. PalmstromNational Renewable Energy Laboratory, Golden, Colorado 80401, United StatesMore by Axel F. Palmstromhttps://orcid.org/0000-0001-6633-209X, Joseph J. BerryJoseph J. BerryNational Renewable Energy Laboratory, Golden, Colorado 80401, United StatesRenewable and Sustainable Energy Institute, University of Colorado, Boulder, Colorado 80309, United StatesDepartment of Physics, University of Colorado, Boulder, Colorado 80309, United StatesMore by Joseph J. Berryhttps://orcid.org/0000-0003-3874-3582, and Matthew O. Reese*Matthew O. ReeseNational Renewable Energy Laboratory, Golden, Colorado 80401, United States*[email protected]More by Matthew O. Reesehttps://orcid.org/0000-0001-9927-5984Cite this: ACS Energy Lett. 2022, 7, 8, 2641–2645Publication Date (Web):July 19, 2022Publication History Received18 May 2022Accepted7 July 2022Published online19 July 2022Published inissue 12 August 2022https://pubs.acs.org/doi/10.1021/acsenergylett.2c01168https://doi.org/10.1021/acsenergylett.2c01168newsACS PublicationsCopyright © Published 2022 by American Chemical Society. This publication is available under these Terms of Use. Request reuse permissions This publication is free to access through this site. Learn MoreArticle Views3343Altmetric-Citations3LEARN ABOUT THESE METRICSArticle Views are the COUNTER-compliant sum of full text article downloads since November 2008 (both PDF and HTML) across all institutions and individuals. These metrics are regularly updated to reflect usage leading up to the last few days.Citations are the number of other articles citing this article, calculated by Crossref and updated daily. Find more information about Crossref citation counts.The Altmetric Attention Score is a quantitative measure of the attention that a research article has received online. Clicking on the donut icon will load a page at altmetric.com with additional details about the score and the social media presence for the given article. Find more information on the Altmetric Attention Score and how the score is calculated. Share Add toView InAdd Full Text with ReferenceAdd Description ExportRISCitationCitation and abstractCitation and referencesMore Options Share onFacebookTwitterWechatLinked InRedditEmail PDF (3 MB) Get e-AlertscloseSupporting Info (1)»Supporting Information Supporting Information SUBJECTS:Amorphous materials,Metals,Perovskites,Solar cells,Testing and assessment Get e-Alerts

As sustainable deployment and end-of-life management become a hot topic to timely address in the PV community, a dynamic comparative evaluation of the benefits of circular pathways such as reuse, and remanufacturing, recycling has not been performed holistically beyond material flows or LCA analysis. Energy flows are critical for evaluating energy generation technologies. Previously they have been used to compare renewables to fossil generation and then between PV technologies. This paper quantifies energy flows to evaluate circular pathways for PV. The energy flows tracking manufacturing, generation, and losses complementary to the mass flows of silicon are quantified leveraging the PV ICE framework.

Photovoltaic modules from a utility-scale field experienced power loss by light- and elevated temperature-induced degradation (LeTID). Samples of one of the affected monocrystalline silicon cells were cored and extracted from the module packaging and encapsulation. One of the cell fragments was processed using a regeneration cycle of applying short-circuit-rated current in forward bias at 85°C for 2 weeks, while the other fragment was kept in its outdoor-degraded LeTID state. Both samples were scribed to form 2-mm diameter isolated areas using a femtosecond-pulse-width laser micromachining system. Both isolated areas contained front grid line segments which were wire bonded to larger contact pads, and the samples were probed in a cryostat linked to a deep-level transient spectroscopy (DLTS) system. Using DLTS, a majority-carrier, hole-trap defect was detected on each sample with an activation energy of 0.42 eV. The LeTID-degraded sample, however, had a larger signal corresponding to a trap density of 1.1x1013 cm-3, which was about five times larger than the 2.1x1012 cm-3 trap density of the regenerated sample.

We report on an electrical conduction mechanism for series resistance (Rs) degradation observed in a utility-scale photovoltaic power plant by imaging the local resistance at the Ag/Si interface of the c-Si front metallization. Scanning spreading resistance microscopy imaging with nanometer (nm) scale spatial resolution revealed that the number of point or small-area electrical contacts decreased substantially in a degraded cell compared to an unaffected cell, demonstrating the root cause of Rs degradation. The decrease in electrical contacts is likely caused by a structural change—the Ag particles in contact with the Si cell (or via a nm-thickness tunneling glass layer) aggregate into bulk Ag, and a highly resistive glass frit forms a belt shape at the Ag/Si interface. This resistive belt, with a thickness of ∼1 μm, blocks the current conduction from the cell emitter to the Ag grid. Our microscopy results help to unravel unambiguously the degradation mechanism and demonstrate an example of the multiscale characterization approach for understanding degradation in field-weathered PV module.