32 Search Results

Here, this study demonstrates the capabilities of an indoor artificial soiling approach developed to closely replicate the natural, cyclic soil accumulation processes in the field-dust suspension, deposition, and sedimentation/cementation-for a subtropical climate. In this work, a near-field environment is replicated in an artificial soiling cubic chamber through controlled regulation of humidity, temperature, dust type, and dust concentration, based on site-specific historical climate data. Two different models (MA and MB) of full-size commercial photovoltaic modules from a single manufacturer, installed side by side in the mid-Atlantic United States, were retrieved and subjected to artificial soiling experiments and various characterization measurements, includingmore » short-circuit current, colorimetry, reflectance, X-ray fluorescence, laser diffraction, and optical microscopy. Both in the field and in our improved field-representative artificial soiling tests, the MA model experienced roughly twice the soiling loss as the MB model. To closely replicate the field soiling losses for a site-specific climate, it is critical to include: 1) The use of field-collected dust with identical dust chemistry and particle distribution instead of standardized ISO 12103 Arizona Road dusts, 2) the use of only a small amount of field-collected dust inside the chamber during the deposition process (e.g., 0.15 g), and 3) the preconditioning of the surface coating for the partial/full dose of UV stress as experienced in the field during sunlight exposure and the abrasion as experienced in the field during regular module cleaning activities, if/as needed. The field-representative artificial soiling method developed here could potentially be adopted for rank ordering of various antisoiling coatings developed by researchers and industry stakeholders.« less

This study investigates the polarization-type potential-induced degradation (PID-p) of bifacial glass/glass p-type passivated emitter rear contact (p-PERC) modules in the field and their recovery behavior. Modules were installed with three mounting configurations providing different albedo conditions. System voltage (–600, –1500, and +1500 V) was applied to the cell circuits, with respect to the grounded module frames. No degradation was observed for positively biased modules, but PID-p was identified on the rear side when cells are negatively biased, with maximum power dropping during the first days and stabilizing at values up to 8% loss. Electroluminescence images revealed a variation of themore » cells' PID-p susceptibility within a module. Three parameters were shown to impact the degradation rate: rear albedo light, voltage, and wetness conditions. Degraded modules were recovered either by (1) a positive bias (+1500 V), (2) outdoor illumination with the front side facing sun, (3) outdoor illumination with the rear side facing sun, or (4) dark storage. A recovery pattern was identified with I–V parameters decreasing to a local minimum before increasing to full recovery. The proposed mechanism is based on the band bending at the rear p-type Si/AlO x/SiN x interface, going from inversion to depletion and accumulation states. Full recovery was achieved in 2–7 h for the modules recovered with the rear side facing sun, four to eight nights for the modules positively biased at night, and 10–20 days for the modules with the front side facing sun. Dark storage showed slower recovery rates as I–V parameters were not improving even after 1 month. Here, the recovery rates were correlated with the net Coulombs transferred during the preceding PID stress: When more Coulombs are transferred during the degradation, the extent of degradation is greater, leading to slower recovery rates.« less

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-inducedmore » 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.« less

This study examines the susceptibility of bifacial glass/glass passivated emitter and rear cell (PERC) modules to potential-induced degradation-polarization (PID-p) in the field. While there are several studies showing PID-p occurring on both front and back faces of bifacial PERC in accelerated tests, we address the yet unclarified behavior in fielded modules. We examine the effects of mounting configuration; specifically, comparing modules mounted near ground and in elevated ground rack configurations. Modules with the cell circuit in -1500 V system voltage configuration, whether mounted on racks about 30 cm above the ground or elevated 2 m high showed mean degradation ofmore » 4.5% to 6% in power under standard test conditions over about 2.5 weeks as measured from the front side of the module. This extent of degradation remained sustained for a duration of about 6 months analyzed. Average daytime temperatures of modules in the various mounting configurations were similar and therefore judged to be insufficient to be a primary influence for the modest PID-p rate differences that we observed among mounting configurations. Increased leakage current in the morning suggests morning dew was sustained longer on modules near the ground measured over six months which would be expected to increase the PID-p rate over the long term. However, the main difference seen between the modules on the various mountings during the initial period with up to 6% mean degradation by PID-p was the approximately two times the irradiance from albedo on the rear of modules mounted in elevated ground rack compared to those on the near ground rack. This difference in incident albedo led to a modestly reduced rate of the development of PID-p of the modules on the elevated ground rack. The difference is attributed to the dissipation of PID-p-causing electrical charge by the albedo incident on the module rear. The behavior could be modeled by a sigmoidal equation with consideration of the differences in the insolation on the module rear.« less

When photovoltaic (PV) modules are installed on rooftops, the module temperature depends primarily on the geographic location and the mounting configuration. If the mounting structure does not provide sufficient airflow in a hot environment, the 98th percentile temperature will exceed 70°C, which according to IEC TS 63126 ED. 1, requires higher levels of thermal stability testing. However, there is no clear way to determine the temperature level needed for a particular location and system design. Here, in this work, we identify a relationship between the module standoff to the rooftop and the module temperature and propose methods to describe amore » minimum standoff for typical PV modules in a simple mounting configuration installed in a given location. For more complex system designs, we show how to determine an equivalent “effective standoff” that can be applied to generic calculations. Lastly, we show measurements and calculations from several systems to demonstrate how this method could work.« less

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/simulatedmore » 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.« less

Electroluminescence, infrared imaging, and current–voltage curve techniques are used to detect and map underperforming cells in a photovoltaic module or the modules in a photovoltaic string. In this work, we present a non-contact electrostatic voltmeter technique to detect and map the underperforming spots in a cell and the cells in a module. This non-contact technique directly maps the charged surface voltage (671mV) of the superstrate glass, and it had an 11-mV difference with the voltmeter values (660mV). Another data set of voltage values obtained by electroluminescence images conversion into a voltage map showed a difference of 7mV with the non-contactmore » voltmeter values. Further, the direct voltage values obtained at various good and poor-performing spots of the cells using this technique are 3.69V and 3.79V and are validated using the voltage values obtained in electroluminescence analysis and the difference in voltage obtained by the two techniques is determined to be less than 2%. In this work, we combine the strengths of two complementary techniques of the electrostatic voltmeter (strength: quantitative) and electroluminescence (strength: spatial mapping) to obtain a quantitative spatial mapping of defects. Furthermore, this work is extendable to detect the poor-performing modules in solar PV power plants.« less

Potential induced degradation (PID) is a significant reliability issue for photovoltaic modules in the field. Conventionally, to detect the PID-affected modules, all the modules in a string are individually disconnected and measured using I-V (current–voltage) tracers. It is extremely time-consuming, expensive and unsafe (if the module connectors are field aged) approach. In our approach, we aim detecting the PID-affected modules quickly, inexpensively and safely without disconnecting individual modules in the string. In this study, contactless electrostatic voltmeter’s (ESV) strength was explored to detect the PID-affected cadmium telluride (CdTe) modules in a string. These contactless measurements on high-voltage PV strings couldmore » make this technique unique and preferable to detect PID-affected modules in a string compared to the I-V curve method. In this work, a CdTe module was stressed for PID using the Aluminum (Al) foil method in a walk-in environmental chamber, which resulted in a reduction of module's peak current (I_max), peak voltage (Vmax), and fill factor (FF), and hence power (Pmax). Outdoor light I-V, EL, and ESV measurements were performed pre- and post-PID to determine the effectiveness of the non-contact ESV technique. Further, the ESV technique successfully detected the change in V_max, and hence Pmax, compared to the pre-and post-PID conditions. A difference of less than 2% was observed in the results of the non-contact and non-interruptive method compared to the conventionally used interruptive voltmeter or I-V tracer method. This technique and the test results demonstrate a significant promise to identify poor-performing modules in PV string without disconnection of individual modules in the string.« less