Govindasamy Tamizhmani

The 2025 International Technology Roadmap for Photovoltaics (ITRPV) projects that bifacial modules will dominate the photovoltaic (PV) market, reaching roughly 60–80% global share between 2024 and 2035, while monofacial PV modules will steadily decline. Current industry practice is to route the cable bundles along structural members such as main beams or torque tubes, thereby preventing rear-side shading but resulting in two key drawbacks: increased cable length and decreased system reliability due to cable proximity with rotating members and pinch points. Both effects contribute to higher system costs and reduced cable reliability. An alternative method involves suspending cable bundles directly behind the modules using hangers. While this approach mitigates excess length and risk of cable snags, it introduces the possibility of partial rear-side shading, which could possibly cause performance loss and hot-spot formation due to shade-induced electrical mismatch. Experimental evidence indicates that this risk is minimal, as albedo irradiance typically represents only 10–30% of front-side irradiance as reported in the literature and is largely diffuse, thereby limiting the likelihood of significant directional shading. This study evaluates the performance and reliability impacts of hanger-supported cable bundles under varying experimental conditions. Performance metrics assessed include maximum power output (Pmax), short-circuit current (Isc), open-circuit voltage (Voc), and fill factor (FF), while hot-spot risk was evaluated through measurements of module temperature uniformity using infrared imaging. Each cable (1X) was 6 AWG with a total outer diameter of approximately 9 mm. Experiments covered different cable bundle counts/sizes (2X, 6X, 16X), mounting configurations (fixed-tilt and single-axis tracker), and albedo conditions (snow-covered and snow-free ground). Measurements were conducted hourly on clear days between 8:00 and 16:00 from June to September 2025. The results consistently show that hanger-supported cable bundles have a negligible shading impact across all hours of the day and throughout the measurement period. This indicates that rear-side cable shading can be safely and practically disregarded in performance modeling and energy-yield assessments for the tested configurations, including fixed-tilt systems and single-axis trackers with or without torque tube shading and with various hanger sizes and cable-bundle counts. Therefore, hanging cables behind modules is a cost- and reliability-friendly, safe and recommended practice.

This study investigates the influence of array height, irradiance, and wind speed on temperature difference and thermal gradients in photovoltaic (PV) arrays operating in hot, arid conditions. A field experiment was conducted in Mesa, Arizona (latitude 33° N), using two fixed-tilt PV module arrays installed at different elevations—one at 1 m and the other at 2 m above ground level. Each array comprised seven monocrystalline PV modules arranged in a single row with an 18° tilt angle optimized for summer performance. Data were collected between June and September 2025, and the analysis was restricted to 10:00–13:00 h to avoid shading and ensure uniform irradiance exposure on both arrays. Measurements included module backsheet temperatures at the center and edge modules, ambient temperature, plane-of-array (POA) irradiance, and wind speed. By maintaining identical orientation, tilt, and exposure conditions across all PV configurations, the influence of array height was isolated by comparing module operating temperatures between the 1-m and 2-m installations (inter-array comparison). Under the same controlled conditions, the setup also enabled an examination of how the intra-array comparison affects temperature gradients along the PV modules themselves, thereby revealing edge-center thermal non-uniformities. Results indicate that the 2 m array consistently operated 1–3 °C cooler than the 1 m array, confirming the positive impact of elevation on convective cooling. This reduction corresponds to a 0.4–0.9% improvement in module efficiency or power based on standard temperature coefficients of crystalline silicon modules. The 1 m array exhibited a mean edge–center intra-array temperature gradient of −1.54 °C, while the 2 m array showed −2.47 °C, indicating stronger edge cooling in the elevated configuration. The 1 m array displayed a broader temperature range (−7 °C to +3 °C) compared to the 2 m array (−5 °C to +2 °C), reflecting greater variability and weaker convective uniformity near ground level. The intra-array temperature gradient became more negative as irradiance increased, signifying intensified edge cooling under higher solar loading. Conversely, wind speed inversely affected ΔT, mitigating thermal gradients at higher airflow velocities. These findings highlight the importance of array height (inter-array), string length (intra-array), irradiance, and wind conditions in optimizing PV system thermal and electrical performance.

This study investigates the influence of array height, irradiance, and wind speed on temperature difference and thermal gradients in photovoltaic (PV) arrays operating in hot, arid conditions. A field experiment was conducted in Mesa, Arizona (latitude 33° N), using two fixed-tilt PV module arrays installed at different elevations—one at 1 m and the other at 2 m above ground level. Each array comprised seven monocrystalline PV modules arranged in a single row with an 18° tilt angle optimized for summer performance. Data were collected between June and September 2025 and the analysis was restricted to 10:00–13:00 h to avoid shading and ensure uniform irradiance exposure on both arrays. Measurements included module backsheet temperatures at the center and edge modules, ambient temperature, plane-of-array (POA) irradiance, and wind speed. By maintaining identical orientation, tilt, and exposure conditions, the evaluation isolated the effect of height on module operating temperature and intra-array thermal gradients. Results indicate that the 2 m array consistently operated 1–3°C cooler than the 1 m array, confirming the positive impact of elevation on convective cooling. This reduction corresponds to a 0.4–0.9 % improvement in module efficiency or power based on standard temperature coefficients of crystalline silicon modules. The 1 m array exhibited a mean edge–center temperature gradience of −1.54°C, while the 2 m array showed −2.47°C, indicating stronger edge cooling in the elevated configuration. The 1 m array displayed a broader temperature range (−7 °C to +3°C) compared to the 2 m array (−5°C to +2°C), reflecting greater variability and weaker convective uniformity near ground level. The temperature gradience became more negative as irradiance increased, signifying intensified edge cooling under higher solar loading. Conversely, wind speed inversely affected ΔT, mitigating thermal gradients at higher airflow velocities. Overall, elevating PV arrays enhances convective heat transfer, reduces module temperature, and improves reliability and power output. These findings highlight the importance of array height, array length, irradiance, and wind conditions in optimizing PV system thermal and electrical performance.

Bifacial photovoltaic (PV) modules have the advantage of using light reflected off of the ground to contribute to power production. Predicting the energy gain is challenging and requires complex models to do so accurately. Often, module degradation over time is neglected in models for the sake of simplicity or is underestimated. Comparing outdoor and indoor current–voltage (I–V) performance for bifacial modules is more challenging than for monofacial modules, as there are additional variables to consider such as rear albedo non-uniformity, cell mismatch, and their effects on temperature. This challenge is compounded when heterogeneous degradation modes occur, such as polarization-type potential-induced degradation (PID-p). To examine the effects of PID-p on I–V predictions using an empirical data-driven approach, 16 bifacial PERC modules are installed outdoors on racks with different albedo conditions. A subset is exposed to high-voltage biases of −1500 V or +1500 V. Outdoor data are traced at irradiance ranges of 150–250 W/m², 500–600 W/m², and 900–1000 W/m². These curves are corrected using control module temperature, wire resistivity, and module resistance measured indoors. We examine several methods to transform indoor I–V curves to accurately, and more simply than existing methods, approximate outdoor performance for bifacial modules without and with varying levels of PID-p degradation. This way, bifacial performance modeling can be more accessible and informed by fielded, degraded modules. Distributions of percent errors between indoor and outdoor performance parameters and Mean Absolute Percent Errors (MAPEs) are used to assess method quality. Results including low-irradiance data (150–250 W/m²) are discussed but are filtered for quantifying method quality as these data introduce substantial errors. The method with the most optimal tradeoff between low MAPE and analysis simplicity involves measuring the front side of a module indoors at an irradiance equal to plane-of-array irradiance plus the product of module bifaciality and albedo irradiance. This method gives MAPE values of 1–6.5% for non-degraded and 1.6–5.9% for PID-p degraded module performance.

Potential-induced degradation (PID) presents a critical reliability issue for solar photovoltaic (PV) modules, with three primary types identified in the literature, namely, PID_s (shunting type), PID_p (polarization type), and PID_c (corrosion type). Electrochemical/electrical impedance spectroscopy (EIS) is a highly effective but underutilized technique for differentiating between these PID mechanisms. When used alongside conventional I–V measurements (e.g., I_sc, V_oc, and FF), EIS offers direct insights into parameters such as R_s, R_p, and C_p, making it a valuable tool for PID type differentiation. In this study, two four-cell glass–glass modules were investigated using p-base PERC monofacial cells with EVA and POE encapsulants. Results indicate that V_oc and FF remained nearly unchanged under +1000 V stress for both EVA and POE modules, suggesting a minimal impact of PID stress on these parameters. However, I_sc was reduced by approximately 8.5% in the EVA module and 10% in the POE module. For the POE module, surface recombination (PID_p) is likely responsible for the I_sc loss, as R_s, R_p, and C_p showed no significant variation. Conversely, in the EVA module, the combined effects of surface recombination and junction recombination (PID_jr) are the probable cause of the I_sc loss, as evidenced by remarkable changes in R_p and C_p. The observed decrease in R_p for the EVA module is attributed to reduced dynamic diode resistance rather than ohmic shunt resistance. This reduction is linked to recombination currents induced by junction trap centers, formed by the positive voltage PID stress in the encapsulant, which contains trace amounts of oxidizable species such as CH₃COOH and/or H₂O. The objective of this study is to evaluate the impact of PID stress on the electrical characteristics of glass–glass PV modules with different encapsulants, utilizing a combined EIS and I–V approach to distinguish between PID mechanisms. The findings highlight the critical role of the encapsulant type in determining PID susceptibility, with the EVA module exhibiting significant degradation linked to junction recombination losses. These insights underscore the necessity of optimizing encapsulant materials to enhance PV module durability and reliability in real-world applications.

This paper presents an extended, accelerated reliability evaluation of forty microinverters, module-level power electronic (MLPE) units for photovoltaic (PV) modules. The forty microinverters were stressed at two static temperatures (65 °C and 75 °C) with two input power profiles (fixed and cyclic power). These power profiles were employed to replicate field-use conditions closely. The accelerated testing was performed for an extended duration (over a period of 15,000 h) to determine the acceleration factor and estimate the service life of microinverters in field-use conditions. Electrical performance and thermal data were continuously monitored during the experiment for all the microinverters. The accelerated stress testing had no failures even after 15,000 h of operation. Using the Arrhenius life-stress model along with average field-measured temperature and military handbook-based analysis, it was estimated that the microinverters should be able to survive for 24–48 years during their service life in field conditions, with a reliability of 74%, having a lower one-sided confidence bound of 95%, obtained using the classical success run approach. Moreover, the lifetime of microinverters was statistically analyzed using a Weibull distribution model. Weibull slope factors were used to estimate a range of characteristic lifetime periods and the reliability of the microinverters with a 95% lower one-sided confidence limit, demonstrating a similar or even exceeding the lifetime of the associated PV modules of 25 years.

Hotspots pose a significant long-term reliability challenge in photovoltaic (PV) modules that can have a detrimental impact on the efficiency, safety, and financial viability of a PV system. This paper aims to evaluate the endurance of hotspot stress in pristine and prestressed glass–glass (GG) modules. The accelerated prestressing was conducted for 600 thermal cycles (TC600) to represent decades of field exposure. GG modules are quickly becoming an alternative to the traditional glass–backsheet (GB) modules that have been the industry standard. Unlike other conventional studies that subject only pristine modules to hotspot stress, this paper evaluates the performance of an accelerated/simulated field-aged GG module (using TC600) and a pristine GG module. Pre- and post-characterizations were performed before and after each test to determine changes in electrical performance and observe any defects in GG modules. During the hotspot test, an approximately 200 °C maximum cell temperature was observed with a cell shading of 25% (the worst-case shading ratio). After the hotspot test, electroluminescence imaging indicated that most cells in the prestressed GG module exhibited severe damage whereas no significant defects were evident in the pristine GG module where the prestressed GG module degraded 8.2% and the pristine GG module degraded 1.5% in maximum power. These findings are critical for the industry, considering that GG bifacial modules will dominate the market.

The operating temperatures of photovoltaic (PV) modules can be impacted by the selection of specific packaging materials, e.g., backsheets and encapsulants. This research focuses on the evaluation of operating temperature reduction of one-cell modules by comparing conventional Tedlar/polyester/Tedlar (TPT) backsheet with novel thermally conductive backsheets (TCBs) materials. A large number of one-cell modules with two TCB types (TCB_A and TCB_B) and baseline TPT type were fabricated and installed in three different climatic conditions of the hot-dry desert in Arizona (high and low wind speed locations) and North Carolina (temperate with low wind speed location). In this study, these two TCBs were compared with conventional TPT backsheet in terms of performance, lifetime and levelized cost of energy (LCOE). The field results were analyzed for thermal performance of TCBs compared to TPT at three sites for two and half years. This study concludes that the thermal and electrical performances of the PV modules can be improved by using TCB_A in hot and dry climate sites and TCB_B at temperate climate sites. Therefore, the lifetime of TCB-based modules is expected to be higher than TPT-based modules. Using backsheet-specific power degradation levels and assuming the same cost for both types of backsheets, the LCOE of modules using TCBs is estimated to be lower than that of TPT.

Accurate modeling of photovoltaic (PV) performance requires the precise calculation of module temperature. Currently, most temperature models rely on steady-state assumptions that do not account for the transient climatic conditions and thermal mass of the module. On the other hand, complex physics-based transient models are computationally expensive and difficult to parameterize. In order to address this, a new approach to transient thermal modeling was developed, in which the steady-state predictions from previous timesteps are weighted and averaged to accurately predict the module temperature at finer time scales. This model is informed by 3-D finite-element analyses, which are used to calculate the effect of wind speed and module unit mass on module temperature. The model, in application, serves as an added filter over existing steady-state models that smooths out erroneous values that are a result of intermittency in solar resource. Validation of this moving-average model has shown that it can improve the overall PV energy performance model accuracy by as much as 0.58% over steady-state models based on mean absolute error improvements and can significantly reduce the variability between the model predictions and measured temperature times series data.

An indoor soil deposition method has been developed to simulate natural soil deposition on glass coupons or one-cell and multicell photovoltaic (PV) modules. This method uses variable ambient humidity, coupon/module temperature, and dust composition within a single custom-made chamber to create a natural and uniform soil deposition layer. Antisoiling (AS) coatings from two different manufacturers were applied on two one-cell monocrystalline silicon modules. Three layers of Arizona road dust have been deposited on the one-cell modules with AS coatings and an uncoated one-cell reference module at varied humidity levels. The soiled modules were exposed to an open-circuit subsonic wind tunnel at varying speeds and the effectiveness of AS coatings have been quantified using the transmittance gain. Transmittance loss resulting from the AS coating has been measured and compared with the transmittance of the uncoated reference module using a reflectance spectrophotometer. Reflectance measurements have also been taken to compare the transmittance loss of Arizona road dust and soil collected from PV modules’ superstrates. The soiled one-cell modules were then exposed to rain from a rain simulator. The transmittance gain due to rain exposure is quantified using a rain gain and rain coefficient. These tests cumulatively may be used to help develop a test standard for evaluating the effectiveness of AS coatings.