Crystalline Silicon PV Module Field Failures

8 Crystalline Silicon PV Module Field Failures 1

8.1 Introduction In 1982, the first photovoltaic megawatt-scale power station went on-line in Hesperia, California. It has a 1-MW capacity system, developed by ARCO Solar, with modules on 108 dual-axis trackers [1]. Since then, with the efforts of all the solar players around the world and global awareness for the need of green energy, the field deployment increased significantly. At the end of 2016, the world’s cumulative PV capacity had surpassed 303 GW, according to a report from Greentech Media [2]. Among the installations, technology wise, crystalline silicon (c-Si) by far is the most predominating player: by 2013, almost 91% of installations are crystalline silicon technology [3]. Thus this chapter will cover the field failures for the crystalline silicon PV modules. Globally, solar power is now able to cover approximately 1.8% of power demand. The United States alone installed 14.8 GWdc of PV in 2016, an increase of 97% from 2015, and 1.4% of electricity generated in the United States in 2016 came from solar facilities [4]. Typical crystalline PV modules are composed of front glass (sometimes transparent fluoropolymers), encapsulant (majority is EVA, other less popular encapsulants include PVB, silicones, ionomers, polyolefins, etc.), PV cells (monocrystalline and multicrystalline), busbar interconnect (tin lead or pure tin coated copper busbars), which includes smaller cell to cell connectors and bigger string to string connectors, sealants (Jbox sealant and frame sealant), junction box sets (including junction box base, lid, diodes, cable, connectors, and pottant), and labels. Former chapters discuss in depth about the degradation of the major components such as PV cells, interconnect, encapsulant, and backsheet in the PV modules. This chapter will cover all the major failures observed in the real field. All the component materials and the interfaces in between the different layers have different degradation

Shuying Yang 1 and Long Jiang 2 Tesla Inc, Fremont, CA, United States 2 NDSU, Fargo, ND, United States

mechanisms and failure modes. All the degradations are stress factors related. The real environmental stresses include: heat (temperature), humidity (relative humidity), irradiation (sunlight, UV and visible light), system voltage level, wind, snow, hail, soiling, shading, thunderstorm, lightning, coastal environment, farm land environment, etc. The majority of the stresses occur for the lifetime of the PV modules (usually greater than 25 years per module manufacturers’ warranty term). Fig. 8.1 shows a simplified version of the stresses mentioned above. For the simplified climate classifications (from the Ko¨ppenGeiger climate classification), the open-air climates in geographical areas of the world include: ocean, equatorial, arid, warm temperate, snow, and polar as per IEC60721-2-1. One can find PV module installations in four out of the six aforementioned areas: equatorial, arid, warm temperate, and snow regions. However, the commonly used climate zone terms used in the PV industry are: Hot & Humid (A-climate), Hot & Dry (B-climate), Moderate (Cclimate), and Cold & Snow (D&E-climate) [5]. The performance and failures of PV modules are definitely location (environmental stress) dependent. For example, Rajiv Dubey et al. studied 63 modules installed in 26 sites in India, and found that: (1) discoloration of encapsulant is the most widely observed degradation, followed by corrosion of metallization materials, interconnects, and output terminals; (2) discoloration is most prevalent in the Hot & Dry climatic zone, since discoloration is accelerated by high temperatures; (3) discoloration is not very prevalent in the Cold & Dry climate of Hanle, despite the higher amount of UV radiation at 4500 m altitude; (4) delamination is seen in older (>10 years old) modules, irrespective of climatic conditions; (5) corrosion of metallization materials, interconnects, and output terminals is seen predominantly in the Hot & Humid zone; the amount of discoloration of encapsulant is directly corelated

Durability and Reliability of Polymers and Other Materials in Photovoltaic Modules. https://doi.org/10.1016/B978-0-12-811545-9.00008-2 Copyright © 2019 Shuying Yang & Long Jiang. Published by Elsevier Inc. All rights reserved.

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Rain, hail, snow, lightning from mother nature

High voltage system stress

Figure 8.1 Common environmental stresses for PV modules. Redrawn from W. Gambogi, Performance and Durability of Photovoltaic Backsheets and Comparison to Outdoor Performance, 2013. Available at: https://www.nist.gov/sites/default/files/documents/el/building_materials/Gambogi.pdf

with reduction in Isc short-circuit current (as expected), leading to loss of power; (6) corrosion is corelated with increase of series resistance, and thereby reduction of fill factor, leading to loss of power; and (7) delamination results in higher operating temperature of the module, which can lead to faster degradation [6]. Since the initial 1 MW field deployment in 1982, there have been many studies regarding field failures of PV modules. Just to name a few here: in 2013, National Centre for Photovoltaic Research and Education (NCPRE) & Solar Energy Centre of India published the 237-page report “All-India Survey of Photovoltaic Module Degradation: 2013” [6]. It covered 63 modules of four types of technology with field installation ranging from 0 to 30 years: among which, 57 modules are crystalline silicon type, 11 modules have been less than 5 years in field, five modules between 6 and 10 years, majority 41 modules from 11 to 20 years, and six modules over 20e 30 years. A subgroup of the organization IEA PVPS (International Energy Agency Photovoltaic Power Systems Program) has initiated the program “Subtask 3.2: Review of Failures of Photovoltaic Modules” [7]. They published a 133-page report on this topic, open to the whole PV world, in 2014. Subsequently, in 2017 they published another in-depth review report “Assessment of Photovoltaic Module Failures in the Field” [8] based on the PV field failure database they

created, with data from expert data acquisition, voluntary reporting, and long-term outdoor studies. This database covered about 422 MW modules installed over the world, of which, 61.3% is from Europe, 12.5% from Austria, and 7.6% from USA. This review of PV module field failures will refer to the previously mentioned literature and the author’s personal experiences with three solar module manufacturers as well as a GW-level EPC solar farm. It is meant to facilitate a widespread awareness of what might go wrong for PV modules in the field for various groups of policy makers, manufacturers, installers, and large and small-scale consumers. Hopefully these entities continue to make new testing standards/methods and modify existing standards/ methods to better address the failure modes in the field, and ultimately the manufacturers can deliver better, safer, more reliable, and more cost-effective solar products.

8.2 Observed Field PV Module Failures: Visual PV module failure was defined as “An effect that (1) degrades the module power and which is not reversed by normal operation or (2) creates a safety issue.” [7,8]. However, in this chapter, the PV module failure will have a much broader range than this

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definition. Any visual (and cosmetic), mechanical, electrical (safety) insulation, and performance related defects/degradation will be labeled as failures. Depending on when the failure happens the failures can be characterized as infant failures, midlife failures, and wear-out failures [9]. Recently, NREL and IEA PVPS came up with a visual inspection data collection tool for PV module field survey to assess the field PV module conditions. This tool is meant for consistent and comprehensive evaluation of PV modules with regard to their field performance and appearance (degradation and failures) [5,10]. This tool is in the format of an excel table, named as “160,815_PV-failure_survey_ blank__1_.xlsm” [10]. Table 8.1 lists details about 29 possible kinds of failures related to PV modules [10]. If a new type of defect is found that cannot be adequately described by the options available in the table, a section entitled “Other” is available for recording anomalous observations at the end of the excel table. From the study of Ko¨ntges et al. [7], infant-mortality failures occur in the beginning of the working life of a PV module. Flawed PV modules fail quickly and dramatically impact the costs of the module manufacturer and the installer. Fig. 8.2 shows the distribution of the failure types at the start of the working life (data provided by a German distributor). The most important failures in the field are junction box failures, glass breakage, defective cell interconnect, loose frame, and delamination. Fig. 8.3 shows the failure distribution of PV modules that have been in the field for 8 years. This study shows a quite high rate of defect interconnections in the modules and failures due to PV module glass breakage. The relative failure rates of j-box and cables (12%), burn marks on cells (10%), and encapsulant failure (9%) are comparably high. In Ref. [7], Marc Ko¨ntges shows the occurrence of failures over the years of operation and the power degradation rate. For the visual failures, the cell crack failures are mostly reported in the very early stage of PV system operation from year 1 to year 2. Systems with PIDs failure are mainly reported during year 3 and year 4. Disconnected cells or strings in the module are reported after year 4 and the occurrences spread over the whole operation time. Discoloring of encapsulant spreads over the years, but power relevant discoloring starts only after year 3, with a high accumulation after 18 years of system operation. Defect bypass diodes spread over the first 10 years of operation.

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Table 8.1 Pull Down Module Failure List From Ref. [10] Module Failure No failure Delamination Defect backsheet Defect junction box Junction box detached Frame breakage/bow/defect Discoloring of pottant Cell cracks Burn marks Potential induced shunts (often named PID) Potential induced corrosion (often with thin film modules) Disconnected cell or string interconnect ribbon Defective bypass diode/wrong dimensioned Corrosion/abrasion of the AR coating Glass breakage Isolation failure CdTe: back contact degradation Hail / glass breakage/cell breakage Snow load / deformed frame/glass-/cellbreakage Storm / deformed frame/glass-/cell-breakage Direct lightning stroke / defect glass/frame and defect bypass diodes Animal / bite/corrosion/dirt Biofilm soiling Dust soiling Humidity corrosion/silver finger corrosion Failure due to external fire Failure due to internal fire Theft/vandalism Other Unknown

With the above general discussion about PV module failures, the following sections detail the major field-observed module failures, from the front side to the backside of the modules, using Table 8.1 as a reference for failure description.

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Figure 8.2 Failure rates due to customer complaints in the first 2 years after delivery. The rate is given relative to the total number of failures. The PV modules were delivered by a German distributor in the years 2006e10. The statistics are based on a total volume of approximately two million delivered PV modules. Redrawn from Richter11 of M. Ko¨ntges, S. Kurtz, C. Packard, U. Jahn, K.A. Berger, K. Kato, T. Friesen, H. Liu, M.V. Iseghe, Review of Failures of Photovoltaic Modules, 2014. Available at: http://iea-pvps.org/fileadmin/dam/ intranet/ExCo/IEA-PVPS_T13-01_2014_Review_of_ Failures_of_Photovoltaic_Modules_Final.pdf.

8.2.1 Field Failures Related to Glass The typical glass used in PV modules is tempered solar glass (low-iron glass) which has great transmission and physical strength. It breaks into small chunks under impact, reducing the risk of human body injuries due to glass breakage. It provides physical protection for the encapsulated PV cell systems underneath and serves as the optical path for the photon to reach PV cells for the photovoltaic reaction. To gain higher power output and less soiling effect, some PV module manufacturers also use glass with an antireflection coating (ARC) and antisoiling coating. The two glass failure types are: (1) physical breakage of the glass and (2) optical efficiency degradation. Potential reasons for glass breakage include: impact (hail/stones/snow/gun shots/ vandalism), crushing, self-explosion of glass due to defects from glass manufacturing, excessive mechanical

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Figure 8.3 Field study of PV module failures found for various PV modules of 21 manufacturers installed in the field for 8 years. The rate is given relative to the total number of failures. Approximately 2% of the entire fleet is predicted to fail after 11e12 years. Redrawn from DeGraaff11 of M. Ko¨ntges, S. Kurtz, C. Packard, U. Jahn, K.A. Berger, K. Kato, T. Friesen, H. Liu, M.V. Iseghem, Review of Failures of Photovoltaic Modules, 2014. Available at: http://iea-pvps.org/fileadmin/dam/ intranet/ExCo/IEA-PVPS_T13-01_2014_Review_of_ Failures_of_Photovoltaic_Modules_Final.pdf.

stress due to improper mounting/framing, and excessive thermal stress (overheating) due to hotspot thermal stress (hotspots from PV cells and hotspots from poor/partial soldering of the electrical connections including soldering of PV cell to busbars, busbars to bussing ribbon, bussing ribbon to junction box connection, and connections inside the junction box). Optical efficiency degradation/loss includes any factors that impact the efficiency of light passing through the glass: shading, soiling, ARC glass coating degradation, glass surface scratching, etc. Fig. 8.4 shows the glass breakage due to over tightened screws and poor clamp design [7]. In Fig. 8.5 glass is broken due to overheating of the poor soldered bussing ribbon. The breakage originates from the brown spot, whose color can be attributed to the overheated, half-burned encapsulant. One can clearly see the breakage paths in the glass, which radiate outward from the overheated brown spot. In addition to the thermal stress from poor soldering, glass can also break due to the thermal stress

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Figure 8.4 Glass breakage caused by over tightened screws (left) and poor clamp design (right) (Figure 4.3.1 of Ref. [7]).

Figure 8.5 Glass broken due to the hotspot caused by poor bussing ribbon soldering.

from intrinsic shunting defects of poor quality cells. In Fig. 8.6 the breakage originates from a cell corner (circled in red) due to the cell hotspot at this location. Correspondingly, a burning spot on the backside of the module can be observed (circled in black). Although glass breakage does not necessarily impact the power output significantly, it definitely poses safety risks. Besides the catastrophic glass breakage failures, the most commonly observed failures related to glass are shading, soiling, and glass surface scratches. Any obstacle blocking the sunlight directly reaching the module front surface is categorized as shading. Popular shading items include: trees, poles, neighborhood buildings, next row trackers/modules, clouds, soiling, bird sitting on or near modules, bird droppings, etc. Depending on the degree, size, and duration of

Figure 8.6 Left: glass breakage due to hotspot cell and right: backside of the module showing burnt backsheet at the same location.

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shading, some shading may activate diodes, leading to power loss; some shading may cause local hotspots, leading to long term power degradation; some may not lead to any significant power output impact. Based on Rajiv Dubey et al.’s study on 63 modules installed on 26 sites in India [6], the module power can be degraded by up to more than 5%. The soiled modules showed a higher temperature (w10
C) compared to the cleaned module, as shown in Fig. 8.7. The higher module temperature will lead to a lower power output and also accelerate module material degradation, especially of the encapsulant and backsheet. Fig. 8.8 shows the field modules with bird droppings. Fig. 8.9 shows the modules shaded by nearby trees, which is very common for residential installations. The soiling is not permanent, it can be fully recovered or at least partially recovered by natural raining, snowing, thunderstorm or wind, or by arranged cleaning. However, as a rule of thumb, one should avoid shading as much as possible in solar system design/installation to gain more power harvesting and avoid system cost for cleaning. Despite its hard surface, glass can still be scratched. Fig. 8.10 shows a module glass with surface scratches. Most likely this glass has an ARC or antisoiling coating, which is relatively easier to be scratched than noncoated glass. Lastly, glass corrosion can happen when water (dew) dissolves some of the sodium from the top surface of sodaelime glass, leading to the production of an alkali that can then corrode the glass silicate structure (Fig. 8.11). This will reduce the transmittance of the glass and thus lower the power output of the modules. Haziness has been observed in many modules installed in India, which is likely caused by this reason.

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Figure 8.8 One of the most popular field observation: bird droppings.

Figure 8.9 Modules shaded by nearby trees.

8.2.2 Field Failures Related to Encapsulants Encapsulant is the layer underneath the glass in a PV module. The encapsulant in a PV module

Figure 8.7 Optical (left) and infrared (right) images of a set of soiled and cleaned modules [6].

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functions as physical insulation to separate cells and cell strings and provides thermal conduction for the heat to transfer. There are five different classes of encapsulantsdionomer, thermoplastic polyurethane (TPU), polyvinyl butyral (PVB), ethylene vinyl acetate (EVA), and polydimethylsiloxane (PDMS) (24 of Ref. [6]). Among these EVA is by far the most popular one due to its low cost, long history, and wide availability to the industry. Commercial EVA is commonly formulated with EVA resin, crosslinking agent, adhesion promoter, UV absorber, and antioxidant. The degradation process and mechanisms of encapsulants have been discussed in detail in Section 6.2, Chapter 6. In this section the focus will be on field failures of the encapsulants.

Figure 8.10 Module glass with surface scratches.

8.2.2.1 Encapsulant Yellowing/Browning

Figure 8.11 Module with hazy glass due to surface corrosion (p. 251 of Ref. [6]).

provides electrical insulation and physical protection for the PV cells from environmental stress. It couples the front glass with the cells beneath to allow maximum light to pass on to the solar cells. It also

Discoloration of encapsulant is one of the most common types of visual degradation observed by Rajiv Dubey et al. [6], shown in Table 8.2 and John Wohlgemuth et al. [11,12], shown in Fig. 8.12. Almost all modules older than 10 years in India are affected by encapsulant yellowing. The highest percentage of modules suffering from discoloration was found in the Hot & Dry zone, followed by the Hot & Humid zone. Overall, modules placed in the Hot zones appear to be more prone to discoloration than in other zones of India. Discoloration of encapsulant is a major factor in reducing the short-circuit current, and hence the power output. Natural sunlight reaches front encapsulant right after it passes the front glass. Usually front glass is UV transparent (except the cerium oxide containing glass which is not popularly used in PV), which means all the UV irradiation can reach the encapsulant. Earlier EVA (before 1990) was not correctly formulated and was prone to

Table 8.2 Percentage of Modules Affected by Discoloration of Encapsulant in Various Climatic Zones (Numbers in Bracket Indicate the Sample Size in the Respective Zone) Climatic Zone

1e5 years Old

6e10 years Old

11e20 years Old

21e30 years Old

50% (4)

67% (3)

90% (2)

50% (2)

Hot & Dry

no module

100% (1)

100% (6)

100% (3)

Composite

20% (5)

no module

100% (6)

100% (1)

Temperate

no module

0%(1)

100% (1)

no module

Cold

no module

no module

67% (3)

no module

Hot & Humid

Redrawn from Table 8.2 of R. Dubey, S. Chattopadhyay, V. Kuthanazhi, J.J. John, B.M. Arora, A. Kottantharayil, K.L. Narasimhan, C.S. Solanki, V. Kuber, J. Vasi, All-India Survey of Photovoltaic Module Degradation, 2013. Available at: http://www.ncpre.iitb.ac.in/research/pdf/All_ India_Survey_of_Photovoltaic_Module_Degradation_2013.pdf.

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Percentage of Studies 0

25

50

75

100

Discoloration/Browning Delamination Corrosion Glass breakage J-box Cell breakage Cracked backsheet Hot spot Soiling Mismatch LID

Figure 8.12 Observed changes in fielded PV modules (Fig. 1 of [12]).

degradation with a symptom of yellowing/browning. The most notorious degradation incident happened at the mirror-enhanced PV installation at Carrisa Planes Power Plant, CA in the late 1980s [13,14]. Severe EVA browning was observed as shown below in Fig. 8.13A after only 6 months of installation. The annual power output degraded by greater than 45% from 1986 to 1990 (original: w6 MW) [15]. The perimeter areas of the PV cells show no sign of browning because of the oxygen bleaching effect [15]. In India, Rajiv Dubey et al. found that 71% of

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the 63 surveyed modules (spans from 0 to 30 years of installation) showed encapsulant browning [6]. By 1996e97 it had been found that EVA discoloration could be mediated through different EVA formulations (i.e., the use of different additives) and by using UV blocking glass [13]. Shuying Yang and Kent Whitfield [16] found that the degradation of the Isc of the modules is proportionally related to the yellowness index of the encapsulant. One can assess the Isc degradation (thus power output) qualitatively by observing the encapsulant yellowness or quantitatively if one can measure the yellowness index of the aged encapsulant. Jordan and Kurtz found that discoloration of EVA in PV modules was expected to induce a power loss through Isc degradation up to 0.5%/year [17]. Ko¨ntges even found that the loss could reach up to 1%/year in Hot & Humid or Moderate climates [18]. Nevertheless, power losses of up to 10%/year have been observed for mirror enhanced PV modules installed in desert environments [19]. Some studies [20,21], report constant degradation rates while others suggest that the degradation rate increases with time over larger time spans [22,23]. This increase is due to the broadening of the light frequency range (from yellow to brown) that is blocked by discolored EVA. Typically, Isc losses of 10% are observed over the first decade of exposure for the modules prone to yellowing [20,21].

Figure 8.13 A close-up look of the modules with severe EVA browning. These cells are from EVA laminated PV panels in V-trough concentrator in Carrisa Plains power plant after 6 months of installation. The cell perimeter area without browning is due to the oxygen bleaching effect (p. 25 of Ref. [15]).

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8.2.2.2 Delamination of Encapsulant/PV Cells When the adhesion between the encapsulant and PV cells is degraded, delamination can happen at their interface. The delamination of encapsulant on the top surface of the PV cells manifests itself as white patches on the cells, in contrast to the blue color of the antireflective coating of the cells. The delaminated area reflects much of the incident light and reduces the light input to the affected cells. In addition, the thermal conductivity is reduced due to the delamination and hence the local temperature of the affected areas is usually higher than that of the unaffected ones, as shown in Fig. 8.14. The gap space created in the delaminated region serves as an accumulation site for moisture and oxygen, which can accelerate the corrosion of the fingers and busbars at the delamination site. Moreover, the new interfaces between the air gap lead to about 8% of light reflection loss (up to 4% at a single air/polymer interface) [7]. Similar observation has been made on field aged modules with delaminated solar cells [24]. Delamination can take different shapes. Figs. 8.15 and 8.16 show that delamination occurs along cell cracks as evidenced by the blue color. It can also appear like wide-spreading bubbles on the cells (Fig. 8.17) or massive delamination over large areas of the cells as shown in Fig. 8.18. Based on the results from Rajiv Dubey et al. [6], the modules installed more than 10 years are prone to delamination with about more than 30% of the modules being affected. They also showed that the Isc degradation rates of modules with delamination were higher than those without, suggesting that the delaminated modules

Figure 8.15 Multicrystalline PV modules show severe cell cracks and delamination along the cracks after 5 years of installation on a rooftop in Northern California.

would suffer higher rates of degradation as compared to the unaffected modules.

8.2.2.3 Delamination Between Encapsulant and Glass The delamination between glass and encapsulant is a commonly observed visual failure for PV modules. Any delamination will result in about 8% optical loss due to the reflection loss at the two new interfaces of glass/air and air/encapsulant, thus resulting in significant power loss. The air pockets serve as space for moisture ingress, which leads to further delamination. The factors affecting the durability of the glass/encapsulant interface include UV, temperature, moisture, and build-in stresses in the

Figure 8.14 Delamination seen as the light blue region in the bottom left corner of a module installed in a Composite zone in 1999 (left) and its infrared image (right) (Fig. 8.10 of [6]).

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Figure 8.18 Severe encapsulant/PV cell delamination and yellowing on the modules installed in a Hot & Humid zone for 18 years (p. 179 of Ref. [6]). Figure 8.16 Delamination (light blue [light gray in print version] region seen along the edges of the solar cell and crisscrossing the center of the solar cell) in a PV module installed in Hot & Dry climate in India in 2000 (Fig 8.11 of Ref. [6]).

laminate. Fig. 8.19 shows glass/encapsulant delamination over the junction box area for AES modules installed for 15 years at The Tucson Electric Power (TEP) Springerville [25]. The ionomer encapsulant in the 300-DGF/50 modules had poor adhesion to glass. It is worth noting that in EVA encapsulation, the adhesion promoter intended for the glass interface is usually the least stable additive, limiting the shelf life of the commercial EVA to about 8e24 h on the production floor after the package is opened.

Figure 8.17 Delamination (bubbles) in a PV module installed in Hot & Dry climate in 1988 in India (Fig. 8.12 of Ref. [6]).

8.2.3 Field Failures Related to PV Cells The PV cell is the core of a PV module since it is the component that converts solar energy to electricity. It is also the most expensive component in the BOM of the PV modules. The durability of the PV cells is very important to the long-term performance of the PV modules. The commonly observed PV cell field failures include: PV cell cracks, snail trails, hotspot, silver (Ag) finger oxidation/corrosion, potential induced degradation (PID), and light induced degradation (LID). Readers can refer to Chapter 4 for the details of PV cell degradations.

Figure 8.19 Delamination of ASE modules over the junction box area. The modules were installed in 2000 at the Tucson Electric Power (TEP) Springerville (Fig. 12 of Ref. [25]).

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8.2.3.1 PV Cell Silver Finger Oxidation The PV cell silver fingers refer to the fine silver lines across the surface of the solar cell and are meant to gather the charge carriers for exporting the electricity out from the modules. The cell busbars refer to the relatively wider Ag path perpendicular to all the fine silver fingers on the surface of a PV cell. The cell to cell connector is also referred to as busbars. The string to string connector is referred to as interconnect bussing ribbons. These metallization and interconnects should be of low electrical resistance to prevent power loss while conducting the current. However, it has been found that PV modules in the field suffer from corrosion/oxidation in the long run, which increases the series resistance and lowers the power output of the module. Corrosion of the metallization can be inferred from the discoloration of the fingers and/or the busbars. Fig. 8.20 shows modules with lightly oxidized Ag fingers. These modules were installed in Northern California for about 5 years. Fig. 8.21 shows modules with heavily oxidized Ag fingers and busbars from modules

Figure 8.21 Severe oxidation/corrosion and burn marks on the Ag fingers, busbars, and interconnects of modules installed in India for 25 years, Fig. 8.16 of Ref. [6].

installed in India for 25 years [BC036]. It was found that the modules installed in Hot & Humid areas have a higher tendency to suffer from oxidation/corrosion.

8.2.3.2 PV Cell ARC Coating Degradation Bare silicon has a high surface reflection of over 30%. The reflection is reduced by texturing and by applying antireflection coatings (ARC) to the cell surface [11]. The most commonly used coating material is silicon nitride. The ARC coatings often surfer from degradation in the field when the quality of the coatings is not good. Fig. 8.22 shows ARC coating degradation (evidenced with a lighter color and a rougher surface) on the modules installed in Northern California for 5 years. This ARC coating degradation will impact the module power output.

8.2.3.3 PV Cell Cracks and Snail Trails

Figure 8.20 Modules with light Ag finger oxidation. Modules were installed in Northern California for about 5 years.

PV cells used in crystalline silicon modules usually have a thickness around 200 mm. Though silicon material usually is strong, it is brittle and can be easily broken by external forces. Fig. 8.23 shows a 72-cell module with 58 cracked cells due to mishandling during transportation. The IeV testing results show that the module suffers a w40% power loss, w18% Isc loss, and a w31% Voc loss. The cells

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Figure 8.22 ARC coating degradation demonstrated as lightened colors and roughened surfaces.

can be damaged in each step of module manufacturing from ingot to PV module installation, and manufacturers usually take extra care with handling to avoid cell damage. EL testing is usually used to identify cracks on the cells. Cell microcracks are usually not visible to human eyes, thus cell damages that occur after the modules leave the last EL monitoring station of the module processing line (packaging, shipping, unpacking, and installation) can only be noticed after snail trail phenomena or system power under performance occur several months (or years) later. A snail track (snail trail) is a visible defect which is caused by discoloration of the silver paste of the front side metallization of silicon solar cells. The defect appears like a snail track on the front glass of the PV module. The discoloration occurs at the edge of the solar cell and usually traces the invisible cell cracks. The discoloring typically occurs 3 months to 1 year after module installation and is generally caused by moisture ingress through the microcracks.

Figure 8.23 Module with massive cell cracks due to mishandling during transportation.

The moisture leads to deposition of silver from fingers and busbars into EVA [9]. In a 2.97 MW Italian site, about 56% of the modules showed severe snail trails after two and half years. Among the 17 modules tested, 60% of the modules showed more than 4.4% Pmax loss. It was shown that the module power output loss became noticeable if there were more than three cells with significant broken cells/snail trails (in active cracked cell area >8% of the total cell area [7]). Fig. 8.24 shows some snail trail examples found on different cells from different field installations.

8.2.3.4 Cell Hotspots Current common PV modules are built with multiple cells in a string (12 cells in a substring is the most popular configuration) connected in series. Whenever there is a cell current performance mismatch, either due to cell intrinsic shunting defects, shading, or soiling, there is a risk of causing cell hotspots. Hotspot heating occurs when a large number of series connected cells cause a large reverse bias across the poor performance cell, leading to large dissipation of power in the poor cell. Essentially the entire generating capacity of all the good cells is dissipated in the poor cell. The enormous power dissipation occurring in a small area results in local overheating or “hotspots” [26]. Hotspots are rarely stable and will usually intensify until total failure of the panel performance in terms of electricity production and/or safety failure. This extreme localized heat will burn encapsulant, busbars, and backsheet, and sometimes break the glass given time.

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Figure 8.24 Snail trail examples on different cells from different field installations.

Defects from cell manufacturing often lead to cell shunting. The defects include incomplete edge isolation, crystalline defects intersecting junction, metal-decorated cracks, overfiring, pn junction “punch through,” scribe line shunts incomplete removal or redeposition, metal particles and bridges on the backside, and print alignment errors [27]. In addition, module manufacturing (cell soldering, lay up, lamination, and handling) and module packaging, shipping, and installation can add additional stresses to the PV cells. A cell with significant shunts will

leak reverse current and exhibit extremely localized heating at each defect. The temperature rise near a defect can vary from mild (1e80
C) to extreme (>200
C), but equilibrium is reached within 10 s [27,28]. Fig. 8.25 shows some pictures with different degrees of overheating: some with minor browning of the encapsulant and some with severe burning of the encapsulant and backsheet [28]. In addition to hotspots due to cell shunting, another common phenomenon is shading induced hotspots. Fig. 8.26 shows a solar farm with partial

Figure 8.25 Cell hotspots due to intrinsic shunting observed in field modules [28].

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Figure 8.26 Partial shading on a solar farm at Sitara (left) and the FLIR image of a shaded module showing a hotspot (right).

shading at Sitara. The black areas circled in red are the shading from right front rows of the modules. One hotspot found in the shaded area is as high as 95
C, see the FLIR image on the right hand side. This recurring shading due to daily tracker/sun movements significantly degrades the shaded modules. Thus proper system design of the solar farm should be implemented to avoid such kind of damaging shading effect. This cell overheating/hotspot leads to backsheet browning/burning, browning from cell side (thermal oxidation of the PV cell (Ag finger oxidation), encapsulant and backsheet oxidation), and glass breakage as shown in Fig. 8.27. At site Sitara, about 4% glass breakage was due to the hotspot from shading. The study by Larue et al. shows that the hotspot induced by shading can be as high as of 500
C [29].

It is also known that the hotspots caused by partial shading of a module can lead to long-term degradation. Rajiv Dubey et al. studied the degradation rates of shaded and unshaded modules and they found that the shaded modules degraded almost three times faster than the unshaded ones (median degradation rate of the shaded modules is 1.6%/year whereas the value of the unshaded ones is just 0.56%) [6]. This interesting information is the first field observation of the deleterious effect of partial shading on the longterm performance of modules.

8.2.3.5 Potential Induced Degradation (PID) Potential induced degradation, as the term suggests, is the module performance degradation due to voltage stress on PV modules. In a system, the

Figure 8.27 Partial shading induced hotspots observed from the backsheet side (first three photos) and the glass side (last three photos).

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modules are under high system potential (600 V in USA, 1000 V and even 1500 V in other parts of the world). The extent of the voltage bias degradation is linked to the leakage current or coulombs passing from the silicon active layer through the encapsulant and glass to the grounded module frame in conventional p-type c-Si PV modules [30]. The degradation mechanism known as polarization found in the first generation high performance n-type c-Si modules from SunPower was discussed in 2005 [31]. PID in thin-film modules is principally attributed to sodium ion migration when the solar cells are negatively biased. Readers can refer to the comprehensive review regarding the PID mechanisms in both c-Si and thin-film PV modules published by Wei Luo et al. in 2016 [32]. The PID effect may cause a power loss of up to 30% according to Wikipedia [31]. Usually PID does not show any visual signs on the modules. However, one can use IV, electroluminescence (EL), and IR imaging to detect its existence. Fig. 8.28 (top) shows the EL and IR images of PID affected modules in a solar farm [33], the bottom image shows the IR images of the whole array under illumination which is affected by the PID effect [34].

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The PID affected modules usually have dark cells in EL along the module perimeter and these dark cells show higher temperatures than the rest of the module in the thermal image. The IV results indicate that the Voc of the affected modules varies depending on the severity of the PID effect. In a European solar farm suffering PID, 10% lower power harvesting was reported for some defect inverters, the Voc of the modules ranged from 25.3 to 40.9 V, and a clear low tail can be seen on the Voc distribution shown in Fig. 8.29. The solution to the PID for this specific site was to implement negative grounding of the system (formerly there was no grounding in the system) to prevent further degradation. Another site in Italy reported a much larger degree of PID. More than 6000 modules were affected and the Voc, Vmpp, and FF of the affected modules degraded significantly. The root causes were found to be poor PECVD of the Si3N4 process during cell manufacturing, poor module encapsulation, and floating installation. Corrective actions included improving the PECVD process, using PID free EVA encapsulant, implementing 85
C/85% relative humidity (RH) PID monitoring, and implementing negative grounding on the site.

Figure 8.28 Top: the electroluminescence and thermographic images of the module with the highest negative potential in a PID affected solar farm [35]; Bottom: operating module array investigated by thermography under illumination. The negative module voltage decreases from the right to the left side, and the power losses heating the modules in the shunted areas are also increasing from the right to the left [34].

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Figure 8.29 Voc distribution of an European site suffering PID.

8.2.3.6 Light Induced Degradation (LID) LID occurs in crystalline silicon cells within the first few weeks of outdoor exposure and it can reduce Isc by 1%e5% and Pmax by up to 15% (18 of Ref. [6]). In amorphous silicon modules, LID can continue for a few months and result in a reduction in efficiency of 10%e30% (41 of Ref. [6]). The LID effect in crystalline silicon solar modules has been generally attributed to boroneoxygen defects in the boron doped P-type wafer manufactured by the Czochralski (CZ) process. This phenomenon is more obvious for the passivated emitter rear cell (PERC) cells than for the normal multicrystalline and monocrystalline aluminium backsurface field (Al-BSF) cells. Up to 4% of power loss was observed for the PERC modules deployed in Europe for less than 1 year.

8.2.4 Field Failures Related to Cellto-Cell Busbars and String-toString Bussing Ribbons For commercial c-Si PV modules, the conductors for the cell to cell and string to string connection usually are copper cores coated with solder (Sn60Pb40, Sn96.5Ag3.5, or pure Sn). These components can be easily corroded/oxidized with

moisture/oxygen/heat and sometimes with an encapsulant degradation byproduct such as acetic acid. Corrosion of the current-carrying metallic conductors in the modules affects the series resistance of the module, which in turn lowers the fill factor (FF) and also the power output of the modules. Rajiv Dubey et al. made an effort to correlate the series resistance of the surveyed modules with the degree of corrosion observed in the field. The electrical IeV data of the modules were extrapolated to the standard test conditions. Then the slope of the IeV curve near the open circuit voltage point (where I z 0) was calculated from the extrapolated data, as shown in Fig. 8.30 [6]. The inverse of the slope was indicative of the series resistance. The series resistance of the modules showed a positive correlation to the level of corrosion qualitatively since it is not practically possible to measure the extent of corrosion in the PV module in the field. The median value of series resistance for the modules with no apparent corrosion was 0.85 U whereas it was greater than 1 U for all the modules with corrosion in metallization and/or output terminals (significantly higher in some cases). The most severely corroded module showed a series resistance of up to 12 U. Fig. 8.31 shows the severely corroded busbars and bussing ribbon in Rajiv Dubey et al.’s study.

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3.0 Corrected I-V Curve Ι2

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5

10

15

20

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Figure 8.30 Calculation of the series resistance from the PV module IeV curve, Fig. 8.49 of Ref. [6].

Another rare failure related to bussing ribbon is broken ribbon. Interconnects break due to stress caused by thermal expansion and contraction or due to repeated mechanical stress. Early modules suffered open circuits due to broken interconnects [35]. It was only reported once with five modules affected out of 30,000 modules installed in Mexico, as shown in Fig. 8.32 (all modules from one supplier). The root cause was found to be bad quality of one batch ribbon.

8.2.5 Field Failures Related to Backsheet The backsheet is meant to provide physical and electrical insulation to the fragile PV cells and live

electrical circuit inside the module laminate. It also serves as a barrier layer for moisture and UV radiation. Its outdoor durability is critical to the lifetime of PV modules. Different PV manufacturers have been using different materials as a backsheet. The most common ones are: Tedlar-PET-Tedlar (TPT) composites, Tedlar-PET-EVA (TPE) composites, PVDFPET-EVA (PPE) composites, PET-PET-EVA composites, fluorine coating-PET-EVA composite, etc. Polyethylene terephthalate (PET) is an electrical insulator with a high mechanical strength and low moisture penetration, but hydrolyzes (breaks down in the presence of water) easily and degrades rapidly on UV exposure (33 of Ref. [6]). The PVF film has high UV resistance and also serves to protect the PET

Figure 8.31 Corrosion (seen as red [gray in print version], green [light gray in print version], and black discoloration) in the string interconnect of a PV module installed in a Hot & Dry zone in India in 1988, Fig. 8.17 of Ref. [6].

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Figure 8.32 Broken bussing ribbon observed in field modules in Mexico.

layer underneath from the ambient moisture. Usually people use backsheet with an outer layer of fluoropolymer for its strong weatherability. However, due to the high cost of fluoropolymer, some PV manufacturers also use non-fluoropolymer backsheet to save cost. The degradation mechanism of backsheet has been discussed in detail in Section 7.2 Chapter 7. In the following sections the most common backsheet failures are described, including: yellowing due to UV aging, cracking due to hydrolysis and/or thermal stress, interlayer delamination or encapsulant delamination due to poor adhesion, etc.

8.2.5.1 Backsheet Cracks The UV durability requirement dictated by the older version (before 2016) of IEC61730 and UL1703 is very limited. Only 15 kWh of UV dosage is required to meet the standards, which is significantly insufficient considering that the annual UV

(A)

dosage in Arizona is about 340 kWh. Fig. 8.33A shows a PV module after 5 years installation in Italy. Cracks can be observed on almost all the modules. The location of the cracks, i.e., at the gaps between cells, indicates poor UV resistance of the backsheet material. The cracked modules failed the wet insulation test, suggesting high safety risk of the modules. Severe cracking was also observed on a 4-year old module with a PET outer layer in the backsheet as shown in Fig. 8.33B [36]. About 9% of module power degradation was observed for the defective module. The backsheet degradation was determined to be due to the reflected UV/visible light from the ground and the hydrolysis effect from moisture in the field.

8.2.5.2 Backsheet Yellowing/Browning Backsheet yellowing and browning is another defect commonly observed in the field. Fig. 8.34

(B)

Figure 8.33 (A) Backsheet crack after 5 years installation in Italy; (B) Severe cracks on a 4-year old module in Spain with a PET outer layer on the backsheet [36].

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severe yellowing and loss of w4% power [36]. Destructive analysis confirmed yellowing of the inner polyethylene layer and associated adhesive layers in the PVDF/PET/PET/PE backsheet structure. Due to the above observed early failures of backsheet, Dupont proposed a more proper UV durability qualification test, as shown in Table 8.3 [36]. Authors believe this is a more appropriate way to qualify backsheet UV durability for PV modules.

8.2.5.3 Backsheet Delamination and Bubble Formation

Figure 8.34 Backsheet yellowing observed on the modules installed in Europe after one and half years.

shows a one and half year field installation with very obvious browning of the backsheet (Europe, 2013). Over 82,000 modules were affected in total. The backsheet is a TPT type from a Japanese supplier. Though at the time of report there was no significant power degradation due to the browning, it is a very unpleasant aesthetic issue for residual applications. The browning was most likely caused by the UV transparent front EVA that was used to achieve a slightly higher power output. It allowed a higher dosage of UV to reach the inner layer of the backsheet, leading to the earlier failure of the backsheet. Fig. 8.35 shows a module removed from a commercial MW power plant after 2 years of service for

Due to poor adhesion of encapsulant to the inner side of the polymeric backsheet, backsheet delamination and bubble formation are observed in the field. Delamination and bubble formation can increase the thermal resistance of the affected location, which will in turn increase the operating temperature of the solar cells and may lead to hotspot formation, culminating in severe degradation in power output in the long run. The study of Rajiv Dubey et al. [6] shows that bubbles and delamination have been seen in the modules installed in the Hot & Humid zone and Composite zone, which hints that high humidity can aid in bubble formation. Fig. 8.36 shows minor backsheet delamination and bubble formation for a newly installed module in the field. In the worst case of backsheet adhesion degradation in the field, the backsheet was observed as total separation from the module, as shown in Fig. 8.37 [15]. This will definitely impose safety risks in addition to power loss

Figure 8.35 Backsheet yellowing observed for modules after 2 years installation.

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>3000 h UV (junction box side)

temperate climate (25 year equivalent)

550 kWh/m2 (4600 h)

desert condition (6e16 year equivalent)

550 kWh/m2 (4600 h)

tropical condition (7e19 year equivalent)

550 kWh/m2 (4600 h)

temperate condition (10e26 year equivalent)

1, 2, 3

assess durability

1, 2, 3

assess durability

* IEC 61,215 UV preconditioning, 15 kWh/m2 (280e385 nm), front exposure only, w70 days outdoors.

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Fig. 8.38 [6]. The study [6] shows that chalking has been found only in some modules in the 11e20 years age bin (and not in other age groups). Modules older than 20 years did not show chalking, which hints that the backsheet material might have been changed by the PV module manufacturers about a decade back. Chalking has been seen in all climatic zones except the cold zone, where the low temperatures prevent thermal degradation of the backsheet.

8.2.5.5 Moisture Ingress from Backsheet

Figure 8.36 Backsheet delamination/bubble formation for the newly installed module in the field.

due to the loss of backsheet light reflection and metallic parts corrosion caused by moisture ingress.

8.2.5.4 Backsheet Chalking Failures Chalking refers to the formation of a white powder on the surface of the backsheet due to the photothermal degradation of the backsheet polymer, see

Moisture can penetrate into a PV module from the laminated edges or backsheet, resulting in corrosion and increased leakage current. Corrosion results in the failure of contact between the grid lines and cell, causing loss in electrical performance. The presence of moisture in the module can also increase the leakage current by reducing the electrical resistance material and resulting in degradation of performance. It can also decrease the adhesion strength of bond between various component layers of the module [9]. Fig. 8.39 shows the moisture mark ring in the center of the cells on the BP modules installed in Northern California for about 5 years.

8.2.5.6 Backsheet Damage due to Lightning Lightning strikes can damage the frame, main body, or the diodes of a module, depending on where exactly the lightning strikes. As shown in Fig. 8.40,

Figure 8.37 Severe backsheet delamination from the field module ([15], p. 28).

Figure 8.38 White powder from the outer layer of the degraded backsheet, p. 178 of Ref. [6].

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Figure 8.39 Moisture mark rings in the centers of the cells on the BP modules 5 years after installation in Northern California.

browning of the backsheet with black blister can be observed because of encapsulant and backsheet material breakdown due to a high voltage strike from lightning. This module was newly installed in Lakeland, Florida.

8.2.5.7 Backsheet Physical Damage Rough handling of the modules can accidentally cause the backsheet damage by punching/scratching (Fig. 8.41) [6].

8.2.6 Insulation Patch Failures Insulation patches are used in the PV module manufacturing to isolate the bussing ribbons from the junction box connection. Most commercial products use an EPE (EVA/PET/EVA) structure without

Figure 8.40 Backsheet damage due to lightning strikes in Lakeland, Florida.

intentional UV formulation. Fig. 8.42 shows a crack on the insulation patch (center of the picture) between two bussing ribbons. This is a BP module installed in Northern California after about 5 years. The slight browning at the left-hand side bussing ribbon may indicate a local hotspot, which in turn can cause the cracking of the insulation patch.

8.2.7 Field Failures Related to Sealant The sealant for junction box attachment in PV modules is typically silicone based (one-part or twopart curing type). The adhesion of the silicone to the module backside (either glass or polymeric backsheet) and to the bottom surface of the junction box is

Figure 8.41 Backsheet physical damage due to mishandling, Fig. 8.8 of Ref. [6].

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this module can easily fall apart and interrupt the whole string performance. This will also impose safety concern with fallen down/detached electrical cables/wires.

8.2.8 Field Failures Related to Frame

Figure 8.42 Insulation patch degradation observed from the BP module installed in Northern California after about 5 years.

critical to ensure the long-term outdoor performance of the modules. Fig. 8.43 shows a catastrophic failure of a junction box that has fallen from the module due to adhesion failure between the sealant and module polymeric backsheet. This module was deployed in Northern California for about 5 years. This is a safety hazard since it exposes the live electric parts to the outside environment. Similarly, an aluminum frame attachment sealant is also typically silicone based. Improper processing of the silicone (especially for the two-part silicone sealant) may lead to poor adhesion of the silicone to the aluminium frame. Fig. 8.44 shows a defective module with a loose frame, due to insufficient silicone material in the channel of the frame. Similar failure has also been observed due to improper mixing of the two-part silicone (poorly cured sealant shows lower adhesion strength). The sealant failure sacrifices the safety and performance of the affected modules. With a heavy snow load in the background,

Usually PV modules with a glass-polymeric backsheet structure use anodized aluminum frames. The anodization is meant to prevent corrosion of the Al frame. The frame plays a major role in keeping the different layers of the PV module together and provides mechanical strength and rigidity to allow module mounting. It also serves as a means for the module to be grounded for safety concerns. Grounding of the frame can protect people who touch the module from electric shock in the event of insulation failure of the PV module. Minor damage to the frame alone may not cause any short-term degradation in the PV module, but in the long term, such damage can progress to a state where the outside environment (water and/or dust) can gain access to the solar cells and cause reduction in the power output. Fig. 8.45 shows an extreme case of frame damage while Fig. 8.46 shows corrosion (blackening) of the frame edges (BC036). Rajiv Dubey et al. showed that close to 40% of the modules had some kind of damage or corrosion in the frame [6]. Algae growth on the frame is also observed, especially in the damp and hot areas, as shown in Fig. 8.47 [6].

8.2.9 Field Failures Related to Junction Box Sets The junction box (Jbox) set is the electrical output interface of the PV modules. Usually it is composed of a junction box base where all the

Figure 8.43 Fallen junction box in a module installed in Northern California for about 5 years.

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Figure 8.44 Defect modules with poorly assembled Al frame due to improper sealant dispensing (deficient sealant).

Figure 8.45 Corroded and dented frame of a field PV module in India, Fig. 8.31 of Ref. [6].

Figure 8.46 Corrosion (blackening) of the frame of a field PV module in India, Fig. 8.32 of Ref. [6].

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also related to Jbox failures). An Indian survey in 2013 showed that more than 20% of the Jbox sets have issues [6]. The following sections discuss some popular field failures related to the Jbox set.

8.2.9.1 Failures Related to Electrical Connection Inside the Junction Box

Figure 8.47 Corrosion and algae growth on the frame ([6], p. 155).

electrical connection and diodes sit, the Jbox lid, cables, and connectors. The Jbox housing protects the internal structure from ingress of water and dust. Some of the Jbox sets are also potted for better thermal management and moisture isolation. Jbox related failures are one of the top failure modes observed in the field and it almost always poses safety risks. For example, among the 16 top complaints from a world leading EPC company, eight of them are directly caused by Jbox failures (soldering, diode, connectors, Jbox lid, etc.). Two of them are PID issues, two of them are cell hotspot issues, others include cell delamination, snail trail, backsheet yellowing, and module breakage (the last one is actually

The electrical connection between the module bussing ribbon and Jbox conducting tab usually is achieved by soldering or insertion (mechanical spring clamping). Fig. 8.48 shows an insertion type connection: where the four bussing ribbons coming out of module were inserted into the mechanical slot with spring force. The clamping and soldering quality (some module manufacturers also use welding technology for this connection) is critical to establish a solid reliable long-lasting connection. If the connection quality is poor (e.g., loose clamping, colder soldering or partial soldering), accumulative resistive heating or arcing can increase the temperature of the connection and ultimately result in burning of the encpasulant/backsheet around it. It can also lead to glass breakage due to very high thermal stress caused by the uneven temperature. Fig. 8.49 shows the progress from minor overheating, medium overheating, to the burning of the encapsulant/backsheet and glass breakage due to the poor soldering quality of the connection between the bussing ribbon and the Jbox. These modules were installed in Northern California for about 5 years.

Figure 8.48 Insertion type connection between the module and the Jbox.

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Figure 8.49 Progressive overheating due to the poor soldering quality, from minor browning to burning and glass breakage (left to right).

In addition to the visual defects, this failure also impacts the power output by causing a low sun-facing Voc reading. For example, low power output was reported at one site right after site commissioning. Failure analysis of the affected modules showed a Voc range of 13e30 V (40e43 V expected with a normal good module). Pushing/pulling one or both cables or pressing down the suspected connecting point on the pottant improves the Voc measurement to 40e43 V, indicating a non-solid electrical connection inside the Jbox. Further analysis showed that there was a cold soldering between the module bussing ribbon and the Jbox conducting terminal, as shown in Fig. 8.50. This junction box was potted with a white pottant and minor browning of the white pottant was noticed (right picture), suggesting resistive heating (or

periodic low voltage arcing) due to poor soldering quality. Similar thermal events have also been noticed in the screw connection version Jbox sets, where the cables are connected to the Jbox using screws. The screws have the tendency to unscrew themselves in the field due to the thermal cycling of day and night and seasonal changes, as shown in Fig. 8.51. When the connection becomes loose, the resistive heating can be observed using an IR camera, as shown in Fig. 8.52. Ultimately this hotspot burns off the pottant, Jbox lid, and cable if the connection failure is not corrected promptly, as shown in Fig. 8.53. When burning happens, the module is permanently damaged and the whole string is affected. Thus this failure affects both safety and power output.

Figure 8.50 Cold soldering of the module bussing ribbon to the Jbox connection terminal pad. Affected modules showed low power output with low Voc readings right after site commissioning.

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Figure 8.51 Failure analysis of the hotspot JBox revealed loose screw connection inside.

Figure 8.52 IR imaging of a hotspot Jbox due to loose electric connection inside.

8.2.9.2 Field Failures Related to JBox Base and Lid The plastic housing of the Jbox is often made of polyphenylene ether (PPE), also known as polyphenylene oxide (PPO). The brand name is Noryl under GE/SABIC [37]. The Noryl family of modified PPE resins consists of amorphous blends of PPE resin and polystyrene (PS). They combine the inherent benefits of the PPE resin (i.e., affordable high heat resistance, good electrical insulation, excellent hydrolytic stability, and the ability to use non-halogen fire retardant packages) with the excellent dimensional stability, good processing ability, and low

density of PS. Like most other amorphous thermoplastics, Noryl is sensitive to environmental stress cracking when in contact with many organic liquids. Compounds such as gasoline, kerosene, and methylene chloride may initiate brittle cracks and eventually result in product failure [37]. Field failures of the Jbox lid are observed after about 4 months of deployment (Fig. 8.54). Typical breakage happens to the hooks mating to the Jbox base, with oneethree hooks broken. This Jbox was potted, if not, then there is serious safety risk once the Jbox lid got loose or even fallen down to the ground, exposing the active electrical circuit to the outside environment. The

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Figure 8.53 Jbox failure due to poor electric connection inside the Jbox.

Figure 8.54 Field failures of a Jbox with broken lid hooks (left and middle) and a microscopy image of the broken surface (right).

cross-section of the failure surface showed a typical environmental stress cracking behavior. Usually the Jbox for PV modules is certified with an IP65 rating (ingress protection) or even a higher IP67 rating. An IP65 rating means that the product is “dust tight” and protected against water projected from a nozzle, while an IP67 rating means “dust tight” and capable of withstanding 1 m water immersion for 30 min [38]. When the lids got loose or the original design is not water tight, moisture can get access to the live metal conductor parts and corrosion can happen subsequently. Fig. 8.55 shows severe corrosion of the internal metallic parts of a Jbox in an early design without proper IP ratings [6].

8.2.9.3 Field Failures Related to Diode Bypass diodes are placed in a PV module for bypassing the current flow when a series string of solar cells, owing to shading or mismatched cells, is unable to support the current generated by the

unshaded cells. If the bypass diode is not present, the shaded solar cells would go into reverse bias and start dissipating heat which in turn may lead to hotspots in the long run and damage the solar cells. One of the major reasons for bypass diode failures is overheating. Bypass diode failures can occur due to forward-voltage operation overheating, reverse-bias thermal run-away, or even from overheating by high electricity intensity transients caused by nearby lightning strikes. Diodes may also fail (usually burned) due to cold soldering/poor connection related to the Jbox as discussed in the former section. Diodes can also be damaged by lightning strikes. Fig. 8.56 shows some severely burned Jbox sets and broken diodes due to a lightning strike in Lakeland, Florida: some diodes are totally burned off without any noticeable residue for failure analysis, some diodes are found to be short, and some are open after the strike. When lightning strikes, usually it can destroy some modules immediately like the ones shown in Fig. 8.56 (symptom usually shows up as a

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of diodes overheating, which can lead to hotspots inside the Jbox and ultimately cause burning of the diodes and the Jbox. Fig. 8.57 shows one Jbox with two diodes being turned on, which produces two hotspots with a temperature of 81 and 75
C around the diodes. Visual inspection of this site indicated that over 80% of the modules showed severe snail trails as discussed formerly under Section 8.2.3.4. EL testing of representative defect modules confirmed severe cell damages. Thus, one can conclude that the root cause of the diode overheating is the mismatch of the cells due to cell cracking, and simultaneously, many modules are also observed as underperforming, or even with all three diodes activated. Figure 8.55 A junction box with no sealing shows severe corrosion on the output terminals and bypass diodes. Fig. 8.27 of Ref. [6].

burned Jbox). It can also weaken some diodes at first and gradually, these weakened diodes result in overheating inside the Jbox and ultimately lead to burned diodes. Diodes are designed to be turned on whenever there is shading or non-uniform cell match to protect the substring from getting overheated. However, if the diodes are constantly “turned on,” there is a risk

8.2.9.4 Field Failures Related to Pottant Pottant serves two functions for the PV module: thermal management and moisture protection of the live circuit inside the Jbox. The pottant is usually made of a low viscosity silicone material. The PV module field failure due to the Jbox pottant is seldom reported. Most of the observed pottant failures are related to the thermal events of the Jbox as described in the former sections.

Figure 8.56 Jbox and diode damages due to lightning strikes in Lakeland, Florida.

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Figure 8.57 Thermal images of a Jbox with two diodes activated.

8.2.9.5 Field Failures Related to Cable Cables have the least reported failures among the Jbox set. A whitish cable surface can be observed from a 2 years old installation in Arizona, see Fig. 8.58. This phenomenon was also observed once in a humidity freeze chamber aging test. The behavior is believed to be caused by the incompatibility between some small molecular weight additives and the crosslinked polyethylene matrix. In rare cases where the insertion of the cable to the junction box cable gland is not done properly, the poor connection can result in hotspots or even arcinginduced fire during active operation. Physical damages caused by animals can also happen to the cable,

Figure 8.58 Whitish cables observed in an Arizona site after 2 years of commission.

as shown in Fig. 8.59 [39]. The compromised electrical insulation poses the safety risk of electrification.

8.2.9.6 Field Failures Related to Connectors Connectors are used to connect the terminals of the Jbox output and the PV module. They are normally composed of plastic housing and internal metal connector parts. Failures related to both components have been observed in the field. Due to poor design and/or processing of the plastic housing, connector cracks were observed even before the system connection, about 2 months after installation in the field, see Fig. 8.60. The failure rate is about 0.5%

Figure 8.59 Field cable damage due to wild animal chewing (gutachten).

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Figure 8.60 Connector plastic housing breakage shortly after installation in the field.

(71 out of 13,634 modules) of the total volume in this specific site in California. The cause of the failure was determined to be environmental stress cracking due to too high internal residual stresses from processing and poor design. This failure is a safety hazard since electrical insulation is lost and the high voltage (1000 V) live circuit is exposed to the outside environment. The second failure related to the connectors are mating quality. Tight and stable connections between the connectors guarantee a solid electrical circuit connection. However, loose connection was observed in an Arizona field after about 2 years of commission, as shown in Fig. 8.61. Due to the loose connections, arcing induced fire was observed in some of the defective modules. The root cause for this failure was that during the second EL testing step in the production flow, the stamping formed connectors on the module were slightly pushed open due to the improper size of the EL tester connector (which needs routine maintenance to guarantee perfect mating to the module connectors). Fig. 8.62 compares a normal connector and a defective connector with open crimping. This incident caused connector

failures to all the modules tested by this tester within the first 2 years of installation. The third failure related to the connectors is the field connections between the strings and the home run connectors; the home run connector and the mating module connector may be from different suppliers or even in different types and made of different materials. The cross-mating quality strongly influences the reliability/durability of the connection. Typical failures are caused by using inexact fitting connectors of different types or inaccurately field crimped connectors to connect the PV modules to the extension cables (home run cable), the fuse box, combiner box, or the inverter at the installation site. Fig. 8.63 shows the mismating of an Amphenol connector to an MC4 type connector in the field connection, which leads to an arcing failure. The fourth failure related to the PV connectors is complete disconnection, which leads to an open module and thus loss of power on the whole string (as an example, 18 modules per string for the modules shown in Fig. 8.64). In this case, the complete disconnection was due to the breakage of the male connector’s hooks.

Figure 8.61 Loose connection in the connectors observed in an Arizona site after 2 years of installation. The upper picture shows the correct connection with an adequate gap between the male and female sides; the lower picture shows a wider gap, indicating degraded connection.

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Figure 8.62 Comparison of the connectors: left side: good quality with nice crimping; right side: poor quality with the crimping pushed slightly open.

Figure 8.63 Field fire due to the cross-mating of a field assembled Amphenol connector to the MC4 type module connector. The root cause is improper field crimping of the Amphenol connector.

8.2.9.7 Failures Due to Water Ingress Damage Sixteen modules were found to suffer from Jbox damage at a Thailand site in 2013. Fourteen of them showed broken ribbon as shown in Fig. 8.65. A commonality study showed that all the 14 failed modules were located at the bottom of pallets during shipment. It was suspected that the modules were soaked in water because of poor storage conditions in the rainy season. The IP65 rated Jbox could not survive water soaking and ingress of water led to metal corrosion inside the Jbox. This is one of the key reasons that a majority of the module suppliers increase their JBox and connector IP rating to IP67 (water soaking proof). Module suppliers also changed module packaging stack up from horizontal to vertical to avoid water soaking at installation sites. In summary, we have discussed all the major observed visual failures related to PV modules. Hopefully, this discussion can serve as a guideline for

the solar players (e.g., manufacturer, researchers, customers, standard committees, etc.) to develop better testing protocols for predicting and preventing failures in the field. Among the failures, most of the failures will impact the power output of the modules, to various degrees depending on the extent of the degradation. In the following section PV module power degradation in the field will be briefly discussed.

8.3 Observed Field PV Module Failures: Power Degradation PV modules are commercial products with a designed lifetime of 25 years or even longer. Major module suppliers offer warranty terms for 25 years (with some extending to 30 years), with an annual degradation rate ranging between 0.4% and 0.8%. Table 8.4 summarizes the warranty terms for some major commercial PV module suppliers: where

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Figure 8.64 Complete connector disconnection in the field.

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SunPower offers the lowest annual degradation rate of 0.4% for 25 years, while the others offer 0.7%e0.8% annual degradation rate. The actual power degradation rate in the field is essential to all stakeholders. It is important for PV manufacturers to determine warranty criteria, for investors to make the right financial decisions, for testing agencies (and standard committees) to modify testing methods for specific failure types and for specific regions, and for end customers to understand the risk of investment to have the lowest possible LCOE (leveraged cost of energy). Due to the importance of the actual power degradation in the field, significant research efforts have been made in the industry to determine its value under different situations [6e8,17,46e49]. The following sections summarize the major findings of the studies: (1) ranking of failure modes affecting power degradation; (2) overall annual module power degradation rate; (3) module power degradation rate by installation years; and (4) module power degradation rate by climate zones.

8.3.1 Ranking of Failure Modes Affecting Power Degradation

Figure 8.65 Jbox corrosion failure due to water soaking of the IP65 rated Jbox.

PV module power degradation follows the typical failures of normal products: infant-failures, midlifefailures, and wear-out-failures. Ko¨ntges et al. summarize the major observed field failures affecting power output in the three stages in Fig. 8.66 (Fig. 3.1 of Ref. [7]). In the early stage (infant failure), power degradation due to LID, Jbox/string interconnect contact failures, glass breakage, and loose frame failures is observed; in the midlife stage, power degradation due to glass ARC coating degradation,

Table 8.4 Warranty Terms for Some Commercial Module Suppliers: Values are Allowed Power Degradation Rates per Warranty Module Supplier

1-Year

SunPower

5-Year

25-Year

Annual Degradation

References

5%

13.0%

0.40%

[40]

CSI

2.5%

19.8%

0.70%

[41]

ReneSola

3.5%

20.0%

0.80%

[42]

3%

20.0%

0.70%

[43]

Trina

3.0%

19.3%

0.68%

[44]

SunEdison

2.5%

19.3%

0.70%

[45]

Kyocerasolar

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Figure 8.66 Three typical failure scenarios for wafer-based crystalline photovoltaic modules (Fig. 3.1 of Ref. [7]).

encapsulant discoloration, delamination, cell cracks, PID, diode failure, and busbarecell connection breakage is observed; in the wear-out stage, power degradation is due to glass ARC coating degradation, encapsulant discoloration, delamination, and cell cracks, in addition to degradation due to severe corrosion of the cells and interconnects. In 2017, Ko¨ntges et al. found that independent of climatic zones, some PV module failure modes stand out by causing a large power loss. In the descending order of power loss, these failures are PID, failure of bypass diodes, cell cracks, discoloration of the encapsulant (or pottant) material, and soiling of PV modules in specific outdoor regions [8]. This ranking of failure modes may be due to the fact that appropriate tests for PID, bypass diodes, and discoloration of the pottant material are lacking in the IEC61215, IEC61730, and UL1703 standards regarding design qualification and type approval test and safety standard for crystalline silicon modules. Currently the test methods for all these failure types are still under development, and have not been included in the current revision of the IEC61215. Therefore, we recommend PV module manufacturers to conduct additional tests for PID (IEC/TS 62804-series) and bypass diode (IEC 62979, IEC/TS 62916). The UVdegradation test is slightly tightened in the current IEC 61215 compared to the former one, but there is still no pass/fail criterion for discoloration. The new version IEC-61730-1 ed two and IEC62788-seven to two are under discussion within IEC standard committee and solar experts have much higher requirements compared to the older IEC61730/UL1703 versions. With all these efforts for developing new testing standards, we hope that the field observed

high rank failure modes will get significant improvements for new module products.

8.3.2 Overall Annual Module Power Degradation Rate In order to help the investors to have a better prediction on their return of investment on solar energy, Jordan and Kurtz [17] conducted a thorough review in 2011 on the degradation rates of flat-plate terrestrial crystalline silicon modules and systems based on the published literature about field testing results throughout the last 40 years. 1751 degradation rates, measured on individual modules or entire systems, have been assembled from the literature: Fig. 8.67 shows a summary histogram of degradation

Figure 8.67 Histogram of reported degradation rates for Si based PV. Median, average, and number of reported rates are indicated. The installation time is color-coded by pre-2000 and post-2000. Fig 2(b) of Ref. [17].

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rates reported in this review. The summarized rates are long-term degradation rates and do not include short-term, light-induced degradation. The distribution is skewed toward high degradation rates with a mean of 0.7%/year and a median of 0.5%/year. This histogram is remarkably similar to (though slightly narrower than) the assumed degradation rate distribution Darling et al. used for their calculations for the levelized cost of energy for PV [50]. Based on this power degradation rate distribution and Table 8.4 where a majority of the manufacturers offer 0.7%/ year degradation rate on warranty, about 1/3 of the modules cannot meet the warranty terms. In 2015, Jordan et al. updated the median degradation rate of 0.5%e0.6%/year and mean of 0.8%e0.9%/year with more data collected [51].

8.3.3 Module Power Degradation Rate by Installation Years In the same study [17], Jordan and Kurtz also grouped the average power degradation rates by installation years: 0e10 years, 10e20 years, and >20 years. They found that the median of degradation rates for these three groups are: 0.70%, 0.46%, and 0.43% respectively. It is reasonable for the 0e 10 years to have higher degradation rates than the 10e20 years because infant failures happen in the early stages. Also, modules with high degradation rates are unlikely to be left in the field, thus the data for the >20 years old modules are most likely for high quality modules. Therefore, this group of modules shows the lowest degradation rate. This effect can be seen in Fig. 8.68, which shows the degradation rates from Fig. 8.67 partitioned by the length of field exposure. For the modules with an exposure time of up to 10 years, the rate distribution has a much more pronounced tail and a higher median than the modules exposed for more than 10 years. Chicca et al. compared the M55 crystalline silicon modules from Arco exposed in California (temperate climate) for 28 years and the same type of modules from Siemens exposed in Arizona (Hot & Dry climate) for 18 years. They found that the average power degradation rate for 18 years old module was 1.17%/year while it was 0.39% for the 28 years old module [52]. This study shows that the longer installation years do not necessarily lead to higher degradation rates. Theoretically, to understand

211

Figure 8.68 Degradation rate histogram grouped by outdoor exposure length. The median rate for the exposure length up to 10 years is significantly higher than that for the length of 10 years and longer. Fig. 3 of Ref. [17].

the impact of exposure time to the power degradation rate, one has to analyze the same modules with the same location without maintenance (module replacement) since different environmental stresses will have different impacts on the module performance. The section below will discuss the impact of the climate zones.

8.3.4 Module Power Degradation Rate by Climate Zones As mentioned before, module power degradation is environmental stress dependent. Christopher Raupp et al. [47] studied the degradation rates of approximately 59,000 PV modules from 26 operational PV power plants in various climatological regions of the United States (ArizonadHot-dry; CaliforniadTemperate; ColoradodTemperate; New YorkdCold-dry; and TexasdHot-humid). The systems range from about 1 year to 19 years in age. The evaluated PV power plants represent about 252,000 PV modules of the following commercially available technologies: mono-Si, poly-Si, hetero junction silicon (HIT), amorphous silicon (a-Si), cadmium telluride (CdTe), and copper indium gallium selenide (CIGS). The average annual degradation rates of c-Si modules in hot-dry and hot-humid climates are higher than 1%/year and in temperate and cold-dry climates are lower than 0.7%/year, as

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Figure 8.69 Degradation rates of IeV parameters of c-Si modules in all climates. Redrawn Fig. 4 of C. Raupp, C. Libby, S. Tatapudi, D. Srinivasan, J. Kuitche, B. Bicer, G. Tamizhmani, Degradation Rate Evaluation of Multiple PV Technologies from 59,000 Modules Representing 252,000 Modules in Four Climatic Regions of the United States, IEEE, 2016.

highest degradation rates of 1.29% and 1.55% respectively, while the cold/dry zone has the lowest rate of 0.19%. The hot/dry zone shows the highest degradation rate because the high temperatures of the desert-type climate lead to increased EVA browning which manifests itself in high Isc degradation [6]. The highest rate is also caused by the temperature cycling effect due to the large day/night temperature range in this climatic zone. The temperature cycling effect empirically follows the Coffin-Manson equation: N ¼ d/(Dtemp) b1 [54], where N is the number of cycles needed for the material to reach failures. It is clear that the larger the temperature range, the smaller the number of cycles needed to cause failures. Ideally the same type of modules should be compared to illustrate the climatic zone effects. Chicca et al. studied the same M55 crystalline silicon modules of Arco installed in California (temperate climate) for 28 years and in Arizona (hot-dry climate) for 18 years. As expected, they found that the average power degradation rate for Arizona (hotdry) was 1.17%/year while those for the California (temperate climate) was 0.39%/year [52], as shown Ï

shown in Fig. 8.69. This observation is consistent with the environment stress condition because almost all degradations are thermal and moisture activated: the higher the temperature, the higher the relative humidity, the higher the degradation. Kimball et al. analyzed the time-to-failure data from PV modules subjected to damp heat tests under different temperature and relative humidity conditions and found that the time to failure followed the power law model TTF ¼ A$e (Ea/kT)$RH (n), where TTF is the time in hours to reach 20% module power loss, A ¼ 6.4e10, Ea ¼ 0.89  0.11 eV, and n ¼ 2.2  0.8. The test durations in hours at 85
C/85% RH that is expected to correspond to 25 years of operation in Europe, China, and India are about 1000, 500, and 2000 h respectively [53]. This is also the reason that the current IEC standard committee proposes different testing requirements for the different application fields (BC099). Similar degradation behavior was also observed by Rajiv Dubey et al. in the 2013 Indian module survey. Table 8.5 shows the annual power degradation rates for the five different climate zones in their study: the hot/humid and hot/dry zones show the Ï

Ï

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Table 8.5 The Median Values of the Degradation of the I-V Parameters in the Five Climatic Zones [6] Climatic Zone

Pmax (%/Year)

Isc (%/Year)

Voc (%/Year)

FF (%/Year)

Hot & Humid

1.29

0.98

0.34

0.89

Temperate

0.24

0.34

0.04

0.46

Composite

0.56

0.45

0.17

0.64

Hot & Dry

1.55

0.78

0.20

0.51

Cold & Dry

0.19

0.72

0.11

0.21

Figure 8.70 Comparison of degradation of performance parameters for the same M55 Arco modules installed in Arizona for 18 years and California for 28 years, Fig. 4 of Ref. [52].

in Fig. 8.70, even though the modules in California were exposed 10 years longer than the ones in Arizona. This study definitely demonstrates that module performance is highly climate dependent. The IEA PVPS Task 13 released the report “Assessment of photovoltaic module failures in the field” in 2017 [8], after the study in 2014. They surveyed the industry and collected failure data of PV systems in different climate zones. The power degradation rate caused by a specific module failure mode for a specific climate zone was calculated by converting the measured power loss into a degradation rate. Table 8.6 shows the leading failure modes

in different climate regions and the mean annual power degradation rates caused by them. The most impactful failures on the performance of PV modules for Hot & Humid, Hot & Dry, Moderate, and Cold & Snow are: PID/disconnected cells and strings, defective diodes/burn marks, defective diodes/ disconnected cells and strings, and cell cracks/glass breakage. In summary, this chapter summarizes the major observed field failures of every key BOM components for the typical crystalline silicon PV modules. The most common failures are: junction box failures, glass breakage, defective cell (cell cracks, snail trails, and burn marks) and string interconnect, delamination, loose frame breakage, EVA discoloration, potential induced degradation, and defective bypass diodes. The power degradation of the historical modules is analyzed and is found that about one third of the modules in the field could not meet the regular module warranty terms. The top failures impacting the power degradation are: PID, failure of bypass diodes, cell cracks, and discoloration of the encapsulant and soiling of PV modules. The impact of climate zones on module power degradation is also discussed. It is found that the hot/dry and hot/humid environments have a much higher negative impact on the module power performance compared to the moderate and cold zones. The purpose of this chapter is to provide a summary of PV module failures in the fields and their impacts on power generation, for the PV industry to develop better testing protocols and manufacturing practices to produce more durable PV modules that can achieve 30þ years of field service.

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Table 8.6 The Power Degradation Rates of the Leading Failure Modes for the Different Climate Zones, Information Extracted From Fig. 50 of Ref. [8]

delamination

defective bypass diode

burn marks

PID

defect backsheet

defective bypass diode

disconnected cell=string

PID

defective junction box

cell cracks

glass breakage

disconnected cell=string

Encapsulant discoloring

Cold & Snow

Encapsulant discoloring

Moderate

disconnected cell=string

Hot & Dry

PID

Hot & Humid

6.3

2.2

2.0

1.8

11.0

7.7

7.6

1.7

25.0

19.8

15.8

13.4

7.9

6.8

3.1

1.4

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Further Reading [1] EnergyEfficiency-solar, Photovoltaic Systems Using Micro Inverter?, 2010. Available at: http:// engineering.electrical-equipment.org/energy-effi ciency-solar/photovoltaic-micro-inverter.html.