Over the course of their lifetime, photovoltaic (PV) modules develop defects and experience performance degradation due to local environmental stresses. The defect type and rate of degradation depend upon cell technology, module construction type, module manufacturing quality control, installer workmanship, and the installed environment. Defects can be purely cosmetic, can cause performance degradation and/or can cause safety risks. Testing labs and other applied researchers typically report the type and number/distribution of defects observed in each PV plant they have investigated. Simply reporting the observed number of defect types and their percent distribution in a plant is of little use to stakeholders, unless each defect is quantitatively correlated with the corresponding degradation rate per year or safety risk. A quantitative correlation can be achieved using a risk priority number (RPN) approach to assess the risk associated with module defects and determine the appropriate action, such as panel removal for safety reasons or warranty claims for material defects. Understanding the climate dependence of degradation rates and defects is valuable for predicting power output and assessing the financial risk of future projects in specific climatic regions. In this study, the influence of climatic condition on RPN for different types of defects, including encapsulant discoloration and solder bond degradation, has been analyzed. The performance degradation rate data and visual inspection data obtained from seven crystalline-silicon PV plants, aged between 3 and 18 years, were used to calculate the RPN for each defect in three climatic conditions (hot-dry, cold-dry, and temperate). The RPN data were, in turn, used to identify the defects with the greatest effect on performance in each of the three climatic regions
The performance and degradation rate of photovoltaic (PV) modules primarily depend on the technology type, module design and field operating conditions. The metastability is a known phenomenon in the CIGS (copper indium gallium diselenide) module technology and it depends on the light exposure and operating temperature. This work aims to understand the metastability influence on the performance of CIGS modules exposed outdoor at three different operating temperatures at a fixed insolation over three years. Two types of CIGS modules from two different manufacturers have been investigated in this study. The three different temperatures were achieved by placing three CIGS modules per manufacturer at three different airgaps on a south facing mock rooftop tilted at 20°. The airgaps were 3”, 1.5” and 0”, and the 0” airgap module was thermally insulated to obtain a higher operating temperature. Throughout the test period over three years, all the modules were maintained at maximum power point using a setup containing optimizers and power resistors. The performance characterizations were carried out before and after exposure using both outdoor natural sunlight and indoor solar simulator. The influence of superstrate type and installation height on the soiling loss have also been investigated.
Failure modes and degradation rates of PV modules in a specific climate are primarily dictated by the module design and field-specific climate stressors such as temperature, UV and humidity. To identify the long-term design issues and predict lifetime of PV modules, the plant owners, investors and researchers typically utilize long-term indoor accelerated tests such as extended/modified IEC 61215 tests. Though the indoor accelerated tests can appropriately be designed for the environmental stressors of a specific climate, several challenges are encountered and they include: capital and operating costs of multiple walk-in environmental and weathering chambers for commercial size modules; only statistically insignificant number of commercial modules can be tested at a time due to size limitation of the chambers, and; multiple climate-specific temperatures and multiple humidity profiles used in the long-term accelerated tests prevent performing conventional IEC 61215 test profiles inside the same chamber. All the above-mentioned challenges can be adequately addressed using a novel climate-specific field accelerated testing setup presented in this work. This test program has been designed specifically for the hot-dry desert climate where the environmental stressors are temperature and UV with little or no influence from humidity. This program can easily be modified for the other climatic conditions, e.g. test setup for a hot-humid condition can include temperature, UV and humidity. In the current outdoor accelerated test program for hot-dry desert climate, the temperature acceleration is achieved by inserting heavy thermal insulators on the backside of the modules and the UV acceleration at higher operating temperatures are achieved by using a V-trough solar concentrator on the thermally insulated PV modules installed on a 2-axis tracker. An acceleration factor of about 12-15 is expected depending on the activation energy of the climate-specific degradation mechanism, e.g. encapsulant browning and solder bond degradation.
Potential-induced degradation (PID) has been one of the critical reliability issues in solar photovoltaic (PV) industry last several years. There are several PID mechanisms, but most well-known failure mechanism is the junction shunting, called PID-s. Cell p-n junction is shunted by sodium ion migration from PV module glass, which is due to leakage current caused by high potential difference between solar cell and aluminum frame of the module. Various methods preventing or reducing PID-s have been developed and used by the PV industry; however, those methods can be applied only at the manufacturing plants. We present a method of suppressing or preventing PID by interrupting surface conductivity of the glass, which can be applied to the field installed PV modules. In our previous study, we chose flexible Corning Willow Glass strips with ionomer adhesive to interrupt the surface conductivity of one-cell PV modules and multi-cell commercial PV modules. By applying the flexible Corning Willow Glass strips on the glass surface close to the frame inner edges, we experimentally demonstrated that PID-s can be practically eliminated in the full size commercial modules. In the current study, we investigated the surface conductivity interrupting technique by applying hydrophobic materials (instead of Corning Willow Glass) on the glass surface close to the inner edges of the frame. The module without any hydrophobic material suffered with 29% of power loss after the PID stress test whereas the module with hydrophobic material suffered with only 15% of power loss after the PID stress test. The current investigation indicates that the PID degradation can be significantly reduced using the hydrophobic materials but not eliminated as observed with the flexible Corning Willow Glass.
The determinations of performance ratio (per IEC 61724 standard) and degradation rate (using slope of performance ratio over time) of photovoltaic (PV) modules in a power plant are computed based on the power (Pmax) temperature coefficient (TC) data of the unexposed modules or the exposed modules during the commissioning time of the plant. The temperature coefficient of Pmax is typically assumed to not change over the lifetime of the module in the field. Therefore, this study was carried out in an attempt to investigate the validity of this assumption and current practice. Several 18-19 years old field aged modules from four different manufacturers were tested for the baseline light I-V measurements and dark I-V measurements to determine the power temperature coefficient and series resistance for each module. Using the dark I-V and light I-V data, the series resistances (Rs) and shunt resistances (Rsh) were calculated in order to determine their impact on fill factor (FF) and hence on Pmax. The result of this work indicates a measurable drop in fill factor (FF) as the series resistance (Rs) increased which in turn increases the temperature coefficient of Pmax. This determination goes against the typical assumption that the temperature coefficient of (Pmax) for aged modules does not change over time. The outcome of this work has a significant implication on the performance ratio and degradation rate determinations based on the temperature coefficient of Pmax of new modules which is not an accurate practice for analyzing field aged modules.
Potential-induced degradation (PID) is known to have a very severe effect on the reliability of PV modules. PID is caused due to the leakage of current from the cell circuit to the grounded frame under humid conditions of high voltage photovoltaic (PV) systems. There are multiple paths for the current leakage. The most dominant leakage path is from the cell to the frame through encapsulant, glass bulk and glass surface. This dominant path can be prevented by interrupting the electrical conductivity at the glass surface. In our previous works related to this topic, we demonstrated the effectiveness of glass surface conductivity interruption technique using one-cell PV coupons. In this work, we demonstrate the effectiveness of this technique using a full size commercial module susceptible to PID. The interruption of surface conductivity of the commercial module was achieved by attaching a narrow, thin flexible glass strips, from Corning, called Willow Glass on the glass surface along the inner edges of the frame. The flexible glass strip was attached to the module glass surface by heating the glass strip with an ionomer adhesive underneath using a handheld heat gun. The PID stress test was performed at 60°C and 85% RH for 96 hours at −600 V. Pre- and post-PID characterizations including I-V and electroluminescence were carried out to determine the performance loss and affected cell areas. This work demonstrates that the PID issue can be effectively addressed by using this current interruption technique. An important benefit of this approach is that this interruption technique can be applied after manufacturing the modules and after installing the modules in the field as well.
The transmission level of the incident light on the photovoltaic (PV) modules depends on the angle of incidence (AOI)
and air/superstrate interface. The AOI dependence for the air/glass interface has already been well established. When the
glass superstrate is covered by a soil/dust layer, the air/glass interface is altered and thereby changes the AOI dependence
to air/soil/glass interface. In this work, PV modules retrieved from the field that had different dust densities have been
measured for the dependence of the AOI curves on the dust gravimetric densities. It was determined that the AOI curve
is inversely related to the soil density. The critical AOI for the air/glass interface is about 57° and it shifts dramatically as
the soil gravimetric density (g/m2) increases. The measured AOI curves were then fitted and validated with the
analytical/empirical models reported in the literature.