Ultraviolet fluorescence (UVF) imaging is a widely used technique to analyze encapsulant discoloration, which is one of the prominent degradation modes in photovoltaic (PV) modules. Conventionally, UVF is done during nighttime or in a dark room, but performing UVF imaging during nighttime causes several inconveniences including safety due to snakes and other animals and inconvenient scheduling issues for the plant owners. Similarly, performing UVF imaging indoors requires dismounting the modules from the racks and moving them to the laboratory, which are labor-intensive and time-consuming tasks and could damage the module or may cause the energy loss due to partial/complete plant/array shutdown. Moreover, the manufacturer/installer warranty may be voided if the modules are removed from the racks. An outdoor UVF setup that can be used during the daylight can be a better alternative to the indoor or nighttime setup, provided it ensures there is no leakage of ambient light into the covered testing structure. We propose a unique, portable, and user-friendly outdoor UVF setup design that can tackle the issue of the ambient light leaking in, give uniform UV light, and provide enough room to accommodate the UV light source and camera to capture module images. We also classify the encapsulant discoloration into three classes depending on the discoloration intensity level. Furthermore, using the image processing technique, the percentage of browning was calculated in each cell/module.
Interconnect Metallization System (IMS) degradation of photovoltaic (PV) modules is one among the major degradation modes in the field caused by higher operating temperatures and daily/seasonal/cloud cyclic temperatures. Usually, the acceleration factor (AF) and activation energy (Ea) of IMS degradation are determined based on power degradation data. Using power degradation data may not be fully representative of a specific mechanism since the power drop could be caused by multiple degradation mechanisms. In this paper, we have used the series resistance (Rs) increase, instead of power degradation, to obtain the AF and Ea for IMS degradation mechanism in the damp heat test (85°C/85% RH). The degradation data were sourced from our qualification damp heat test database with 94 crystalline silicon modules, and two field databases of Arizona and New York climates with 615 and 236 crystalline silicon modules, respectively. A 3-step approach was implemented to determine the AF for the damp heat testing. First, the AF for the field-to-field degradation was determined based on Rs degradation rates of the modules in Arizona and New York. Second, the Ea was determined based on the AF, and hourly differences in field-to-field module temperature and relative humidity. Third, the AF was determined based on Rs increase in the damp heat test and the Ea determined using the field data in the second step. A model based on modified Peck’s equation was used to determine a generic AF for the Rs increase in qualification damp heat testing. This approach is useful to predict the service lifetime and reliability of PV modules for specific 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.
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
This paper presents the development of three image processing tools to analyze defects and predict performance of the photovoltaic modules using infrared thermography, electroluminescence and ultraviolet induced fluorescent images of the modules. The MATLAB processing tool uses an algorithm aimed at detecting defects and quantifying them in terms of area affected and intensity of the defect. Each image was studied for visual defects, processed and the results from the three techniques were compared. The algorithms lead to detection of defect location with high accuracy. The size and intensity of the defect was computed based on pixel information that was correlated with performance parameters like short circuit current, fill factor, and series resistance depending on the image processing technique used. The infrared image processing technique aided in hotspot detection and removing outliers with elevated cell temperatures for a correlative study with electroluminescence imaging. Electroluminescence image processing demonstrated linear correlation between the inactive cell area and performance parameters like fill factor and series resistance. Ultraviolet induced fluorescence image processing resulted in precise segmentation of browned area and showed a linear correlation with the short-circuit current drop. Ultraviolet induced fluorescence images indicated at the presence of cracks in cells with non-uniform browning based on the corresponding electroluminescence images. The modules in the study were from three different manufacturers to show that the processing tool can work for the different modules.
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.
In our previous study1, visual inspections and infra-red (IR) scanning were performed on about 2,000 modules that have been operating under the dry and hot Arizona climate for 10 - 17 years. Most of these modules were installed on 1-axis trackers and grid-connected; and some were installed on a fixed latitude tilt rack in a standalone system. The modules
were inspected against a list of historically known field failure modes, but restricted to those that could be visually observed or through IR. An analysis of the data revealed both positive and negative correlations between the failure modes. Failure chains could be constructed from those correlations; such as (1) Discoloration of encapsulant – cell discoloration, and (2) Delamination – broken/chipped cells. This study focuses on modules installed on 2-axis trackers between 8 and 13 years. Statistical degradation analysis is performed on power output data collected throughout the exposure period. The electroluminescence imaging and a more thorough IR scanning are performed on limited (available) samples to complement the visual inspection data from the previous study. This paper also looks into the correlation between those inspection results and the performance degradation data. The objective of this paper is twofold: (1) to present a statistical analysis result of degradation data for field exposed crystalline silicon modules installed on 2-axis trackers between 8 and 13 years. The analysis should provide reliability prediction for up to 30 years of field operation. (2) To investigate the correlation between performance degradation and inspection data. Inspections include visual observations, IR scanning, and electroluminescence imaging.
We examine a proposed test standard that can be used to evaluate the maximum representative change in linear dimensions of sheet encapsulation products for photovoltaic modules (resulting from their thermal processing). The proposed protocol is part of a series of material-level tests being developed within Working Group 2 of the Technical Committee 82 of the International Electrotechnical Commission. The characterization tests are being developed to aid module design (by identifying the essential characteristics that should be communicated on a datasheet), quality control (via internal material acceptance and process control), and failure analysis. Discovery and interlaboratory experiments were used to select particular parameters for the size-change test. The choice of a sand substrate and aluminum carrier is explored relative to other options. The temperature uniformity of ±5°C for the substrate was confirmed using thermography. Considerations related to the heating device (hot-plate or oven) are explored. The time duration of 5 minutes was identified from the time-series photographic characterization of material specimens (EVA, ionomer, PVB, TPO, and TPU). The test procedure was revised to account for observed effects of size and edges. The interlaboratory study identified typical size-change characteristics, and also verified the absolute reproducibility of ±5% between laboratories.
Traditional degradation or reliability analysis of photovoltaic (PV) modules has historically consisted of some
combination of accelerated stress and field testing, including field deployment and monitoring of modules over long time
periods, and analyzing commercial warranty returns. This has been effective in identifying failure mechanisms and
developing stress tests that accelerate those failures. For example, BP Solar assessed the long term reliability of modules
deployed outdoor and modules returned from the field in 2003; and presented the types of failures observed. Out of about
2 million modules, the total number of returns over nine year period was only 0.13%. An analysis on these returns
resulted that 86% of the field failures were due to corrosion and cell or interconnect break. These failures were
eliminated through extended thermal cycling and damp heat tests. Considering that these failures are observed even on
modules that have successfully gone through conventional qualification tests, it is possible that known failure modes and
mechanisms are not well understood. Moreover, when a defect is not easily identifiable, the existing accelerated tests
might no longer be sufficient. Thus, a detailed study of all known failure modes existed in field test is essential. In this
paper, we combine the physics of failure analysis with an empirical study of the field inspection data of PV modules
deployed in Arizona to develop a FMECA model. This technique examines the failure rates of individual components of
fielded modules, along with their severities and detectabilities, to determine the overall effect of a defect on the module's
quality and reliability.
The crystalline silicon photovoltaic (PV) modules under open circuit conditions typically degrade at a rate of about 0.5%
per year. However, it is suspected that the modules in an array level may degrade, depending on equipment/frame
grounding and array grounding, at higher rates because of higher string voltage and increased module mismatch over the
years of operation in the field. This paper compares and analyzes the degradation rates of grid-tied photovoltaic modules
operating over 10-17 years in a desert climatic condition of Arizona. The nameplate open-circuit voltages of the arrays
ranged between 400 and 450 V. Six different types/models of crystalline silicon modules with glass/glass and
glass/polymer constructions were evaluated. About 1865 modules were inspected using an extended visual inspection
checklist and infrared (IR) scanning. The visual inspection checklist included encapsulant discoloration, cell/interconnect
cracks, delamination and corrosion. Based on the visual inspection and IR studies, a large fraction of these modules were
identified as allegedly healthy and unhealthy modules and they were electrically isolated from the system for currentvoltage
(I-V) measurements of individual modules. The annual degradation rate for each module type is determined
based on the I-V measurements.
Building applied photovoltaics (BAPV) is a major application sector for photovoltaics (PV). Due to the negative
temperature coefficient of power output, the performance of a PV module decreases as the temperature of the module
increases. In hot climatic conditions like Arizona, the BAPV module temperature can reach as high as 90-95°C during
peak summer. Considering a typical 0.5%/°C power drop for crystalline silicon modules, about 30% performance drop
would be expected during peak summer because of the difference between rated temperature (25°C) and operating
temperature (~90°C) of the modules. In order to predict the performance of PV modules, it becomes necessary to predict
the module temperature. The module temperature is dictated by air gap between module and roof surface, irradiance,
ambient temperature, wind speed, and wind direction. Based on the temperature and weather data collected over a year
in Arizona, a mathematical thermal model has been developed and presented in this paper to predict module temperature
for five different air gaps (0, 1, 2, 3 and 4 inches) as well as modules with a thermally insulated (R30) back. The
thermally insulated back is expected to serve as the worst case temperature a BAPV module could ever experience. This
paper also provides key technical details on: the specially built simulated rooftop structure; mounting configuration of
PV modules on the rooftop structure; LabVIEW program developed for data acquisition; and a data processing program
for an easy data analysis.
KEYWORDS: Thermal modeling, Solar cells, Temperature metrology, Photovoltaics, Data modeling, Systems modeling, Data acquisition, Manufacturing, Crystals, Silicon
Performance of photovoltaic (PV) modules decreases as the operating temperature increases. This performance drop is
typically higher for the crystalline silicon technologies (~0.5%/°C) as compared to thin film technologies (~0.2%/°C).
The temperature of rooftop modules in hot climatic locations like Arizona could be as high as 95°C depending on the air
gap between the modules and roof surface. There are several thermal models existing to predict the temperatures of
open-rack PV modules but no comprehensive thermal models have been reported for the rooftop PV modules/arrays
based on an extended field monitoring. The primary goal of this work is to quantitatively model the influence of air gap
on the temperature of rooftop modules so that the system integrators could improve their designs to maximize the overall
energy output (kWh/kW) of the rooftop PV systems. To predict the temperature of rooftop PV modules/arrays based on
irradiance, ambient temperature and wind speed conditions, this paper presents five thermal models for each of the five
air gaps (0, 1, 2, 3 & 4 inches) investigated in this work.
KEYWORDS: Data modeling, Systems modeling, Solar energy, Photovoltaics, Shape memory alloys, Solar cells, Solar radiation models, Performance modeling, Climatology, System integration
Prediction of energy production is crucial to the design and installation of the building integrated
photovoltaic systems. This prediction should be attainable based on the commonly available parameters
such as system size, orientation and tilt angle. Several commercially available as well as free downloadable
software tools exist to predict energy production. Six software models have been evaluated in this study
and they are: PV Watts, PVsyst, MAUI, Clean Power Estimator, Solar Advisor Model (SAM) and
RETScreen. This evaluation has been done by comparing the monthly, seasonaly and annually predicted
data with the actual, field data obtained over a year period on a large number of residential PV systems
ranging between 2 and 3 kWdc. All the systems are located in Arizona, within the Phoenix metropolitan
area which lies at latitude 33° North, and longitude 112 West, and are all connected to the electrical grid.
Hot-spot heating occurs in a photovoltaic (PV) module when its operating current exceeds the short-circuit current of a
shadowed or faulty cell in a cell-string. This shadowed/faulty cell could overheat due to reverse bias and become a fire or
electrical hazard. Currently, there are three different test methods used in the industry to identify and address this issue.
These three methods are based on the UL 1703 (intrusive) standard, ASTM E2481-06 (non-intrusive) standard and IEC
61215 (non-intrusive) standard. Comparing and identifying the best test method [in terms of time, cost and complexity]
is of great value to the consumers, PV module manufacturers and test laboratories such as ASU-PTL. The objective of
this paper is to compare these three methods in order to identify the best test method for the modules composed of low
and/or high shunt resistance cells. In this work, 18 modules composed of low and high shunt resistance cells were
investigated in each of the test methods. Out of eighteen (9 mono-Si and 9 poly-Si) modules tested, sixteen modules (9
poly-Si and 7 mono-Si) passed the hotspot tests of all the three standards. The other two modules (mono-Si with voltage
limited cells) passed in the ASTM and IEC methods, but failed in the UL method. These two failures in the UL method
may be explained in terms of standard's worst-case assumption
(open-circuited diodes) of non-sharing of the stress
current by the installed bypass diodes of the modules and/or the extended test duration required in this standard.
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