## Abstract

The All India Survey of Photovoltaic Module Reliability 2014 is an enhanced version of the survey conducted in the previous year, with detailed characterization of PV modules including current-voltage, infrared and electroluminescence imaging, visual inspection, insulation resistance test and interconnect breakage test. More than a thousand modules were inspected in the field and the main results of the survey are presented in this paper. The average Pmax degradation rate for the so-called ‘good’ modules (Group X) is 1.33%/year which is higher than that commonly projected by manufacturers, and widely employed in financial calculations. Modules falling in the ‘not-so-good’ category (Group Y) show even higher degradation rates, and it is at least partly due to higher number of micro-cracks in the modules, and increased degradation of the packaging materials like encapsulant, backsheet, etc. Modules in ‘Hot’ climates degrade faster than modules in the ‘Non-Hot’ climates. Degradation in fill factor is the primary cause for performance degradation in the young modules (ages <5 years), whereas short-circuit current degradation is the main contributor to power degradation in the older modules. Small installations (<100 kWp capacity) show higher degradation than large systems, which may be partly due to lack of proper due diligence by the owner at the time of procurement and installation.

## Survey Statistics and Methodology

A total of 1148 modules were inspected in the six different climatic zones of India. India has a large geographic stretch, and different areas of the country experience very different climates –hot and dry, hot and humid, composite, moderate, cold and dry, and cold and cloudy [12]. This has been shown in Figure 1, along with the 19 locations marked in black dots, where 51 individual sites were surveyed by us during the 2014 All-India Survey. The details of sites and modules inspected in different climatic zones are given in Table 1. These comprised 983 c-Si modules and 165 thin film modules. Around 70% of the modules were young (0–5 years in age), around 20% were in the 10–20 years age group, and the remaining was older than 20 years. Almost 50% of the inspected modules had rated power >100 Wp, and 80% modules were connected to MPPT inverters.

 Figure 1. Climatic zones of India as per Bansal and Minke [12]. The black dots indicate the locations surveyed.

Table 1. Site summary
Climatic zone Number of sites surveyed Number of modules surveyed
Hot and Dry (Hand D) 15 194
Warm and Humid (Wand H) 10 333
Composite (Comp) 9 308
Moderate (Mod) 8 135
Cold and Sunny (C and S) 6 56
Cold and Cloudy (Cand C) 3 122
Total 51 1148

The methodology adopted for the survey has been explained in detail elsewhere [13, 14], but is being briefly mentioned here. At every site, the first activity was to clean the modules using water, followed by current-voltage (I-V) characterization of individual modules using PVPM and SolmetricI-V tracers. Infrared (IR) thermography was performed next using FLIR E-60 Infrared camera, with the module short-circuited for about 5 min. Interconnect breakage was tested, using Togami Cell Line Checker. Insulation resistance was measured both under dry and wet conditions, by applying a high voltage (1000 V DC) between the shorted module terminals and the module frame. Based on the above measurements, some of the modules were selected for further tests like dark I-V, dark IR, and electroluminescence (EL) measurement. EL was taken in the late afternoon or after sunset, in the presence of ambient light, using the “Image Difference Technique” which has been described elsewhere [15]. Dark I-V was performed with the module covered, using a programmable DC power supply. For dark IR, the module was forward biased at rated short circuit current, and IR images were taken from the back side.

## Analysis of Survey Data

 Figure 2. Histogram of Pmax degradation rate of (A) ‘All’ modules, (B) Group X modules, and (C) Group Y modules.
 Figure 3. Manufacturer-wise and site-wise Pmax degradation rates. A through Z are the different manufacturers and 1, 2, etc. are the different sites for each manufacturer. Note that site 1 for manufacturer A is not the same as site 1 for other manufacturers, etc.

Figure 4 shows EL images of some representative modules of Groups X and Y. Group X modules have lesser number of cracks as compared to group Y modules. According to Kontges et al., cracks can be classified into three categories [16]:

 Figure 4. Electroluminescence images of some Group X modules (A), (B) and Group Y modules (C), (D) taken in the field.
1. Mode A cracks which are basically hair-line cracks, not associated with any dark area,
2. Mode B cracks which are associated with a gray (not very dark) area in the cell,
3. Mode C cracks which are associated with a dark area in the cell.

Table 2 shows the statistics for the 51 modules (consisting of a total of 1416 cells), for which we took the EL measurement. Many of these modules are older than 10 years, and have <60 cells per module. From Table 2, we can see that modules in Group Y have a larger number of cracks as compared to Group X modules. Hence, cracks in the cells are likely to be one of the reasons behind the higher degradation rate observed in group Y modules. Table 3 gives the statistics for modules affected (in percentage) by various types of visual defects, for Groups X and Y in different age groups. The values in brackets indicate the number of samples in the respective category. It can be seen that in most cases, a larger percentage of Group Y modules are affected as compared to Group X modules, which indicates that the material quality and/or manufacturing process is inferior in case of Group Y modules, which has led to higher Pmax degradation rates.

Table 2. Percentage of cells affected by different types of cracks in Group X and Group Y modules
Percentage of cells affected by different types of cracks Total no. of cells
Mode A cracks Mode B cracks Mode C cracks
Group X 2.4% 14.1% 3.2% 972
Group Y 29.7% 42.3% 14.2% 444

Table 3. Statistics of major visual defects for Group X and Group Y modules (the sample size is given in brackets)
Type of visual defect Age groups
Young (<5 years) Old (>5 years)
1. Higher value in the category is indicated in bold.

Discoloration X: 9% (82) X: 88% (148)
Y: 18% (219) Y: 92% (135)
Front-side delamination X: 9% (82) X: 31% (148)
Y: 16% (219) Y: 43% (135)
Snail trails X: 35% (82) X: 0% (148)
Y: 26% (219) Y: 0% (135)
Metallization discoloration X: 38% (82) X: 90% (148)
Y: 54% (214) Y: 99% (135)
Backsheet degradation X: 26% (82) X: 77% (148)
Y: 31% (219) Y: 90% (135)

In the following sub-sections, the effect of system size, climate, technology, and age on the module performance will be discussed in detail.

### Module size, system size and installation based variation

The inspected modules varied widely in their rated capacity, ranging from 10 Wp to 386 Wp. The smaller size modules (<100 Wp) are mostly old, while the larger wattages (>100 Wp) are seen only in recently installed systems. Figure 5 shows the variation in the power degradation rate for two categories of modules, with size <100 Wp and >100 Wp. In this and subsequent figures, each data point refers to an individual module, the number on top indicates the number of modules, the red horizontal bar shows the mean value, the diamond represents the 95% confidence interval, and the error bars refer to error due to name plate tolerance (left) and measurement and translation (right). If relevant, the symbols are color coded to represent climatic zone, and open or filled representing young (<5 years) or old (>5 years) modules. We can see that when considering modules from ‘All’ sites (refer Fig. 5A), the smaller capacity modules show less degradation on the average as compared to the larger size modules. However, the same comparison done only considering Group X modules does not show such a wide difference, as seen in Figure 5(B), which indicates that for the good sites, the degradation rate does not depend on module size. On the other hand, for the ‘not so good’ sites (Group Y), there is a very strong dependence, with the larger size modules (which are Young in age) showing much higher degradation rates.

 Figure 5. Effect of module size on Pmax degradation rate for (A) ‘All’ modules (B) Group X modules.

To understand the effect of the system size (as distinct from module size) on the degradation rate, the surveyed sites have been segregated into two groups– small/medium systems (size ≤100 kWp), and large systems (size more than 100 kWp). Figure 6 shows the effect of system size on the performance degradation rate of surveyed modules. It is evident that large systems show lower degradation in performance as compared to smaller systems, the reason for which may be attributed to the greater due diligence and better installation practices adopted for the large systems, which may be lacking in the case of smaller systems. If we compare the mounting location – roof-mounted versus ground-mounted (Figure 7) – we come to the conclusion that roof-mounted systems show higher degradation rates than ground-mounted systems. This may be due to lack of proper due diligence on part of small PV system installers and owners which might result in use of lower grade materials, and also since roof-mounted modules tend to run hotter.

 Figure 6. Effect of system size on Pmax degradation rate for ‘All’ modules.
 Figure 7. Effect of installation type on Pmax degradation rate for ‘All’ modules.

Figure 8 shows the percentage of modules which passed or failed the dry insulation resistance test for small/medium systems and large systems. It is evident that the modules in large installations perform slightly better than small/medium installations, and 100% of the modules in the large installations have passed the dry insulation test.

 Figure 8. Percentage of modules passed or failed dry insulation resistance test for small/medium and large installations.

The severity level of material degradation has been quantified based on the degree (intensity) of the defect and the affected fractional area, estimated by visual inspection. The degree of the discoloration can be light (yellow) or dark (brown), and the fractional cell area can range between 0 and 1. The discoloration index for the module is calculated as given below:

 ${\displaystyle {\begin{array}{cl}&{\mbox{Discoloration}}\quad {\mbox{Index}}\quad ({\mbox{DI}})\\&\quad ={\frac {{\mbox{Degree}}\quad {\mbox{of}}\quad {\mbox{discoloration}}\times {\mbox{Affected}}\quad {\mbox{area}}\quad {\mbox{of}}\quad {\mbox{cell}}}{{\mbox{normalizing}}\quad {\mbox{factor}}}}\end{array}}}$
(1)

where degree of discoloration = 1 for light/yellow discoloration, = 2 for dark/brown discoloration; normalizing factor = 2 (based on maximum possible value of numerator).

Based on the discoloration index, the modules can be grouped into 5 categories as follows, with the severity of discoloration ranging from ‘Nil’ to ‘Very High’ as given in Table 4.

 Discoloration index 0 0–0.25 0.25–0.5 0.5–0.75 0.75–1 Discoloration category Nil Low Medium High Very high

Similarly, modules have also been classified into five severity categories for the other defects like delamination, snail trails, etc. The severity levels in increasing order of magnitude are ‘Nil’, ‘Low’, ‘Medium’, ‘High’ and ‘Very High’. Detailed explanation of the methodology for arriving at the severity levels is given in a separate publication [17]. Table 5 shows the average severity level of the major visual defects found in the surveyed modules for small and large installations. Severity of front-side delamination and backsheet degradation is higher in the Young modules from small installations as compared to large installations. Among the Old modules, the severity of discoloration, delamination, metallization discoloration, and backsheet degradation are all higher for the modules in small installations, but the number of samples is very small for large installations to give a definitive picture. Overall, it may be said that severity of these defects points toward manufacturing and/or installation related issues with the modules in small installations.

Table 5. Severity levels of major visual defects for ‘All’ modules (the sample size is given in brackets)
Type of visual defect Size of installation Age groups
Young Old
1. a

Excluding glass–glass modules which have negligible discoloration.

2. b Excluding All-Back-Contact modules in which metallization is concealed.
Discoloration Small Low (519) Medium (361)a
Large Low (50) Nil (5)
Front-side delamination Small Low (519) Low (399)
Large Nil (50) Nil (5)
Snail tracks Small Medium (519) Nil (399)
Large Medium (50) Nil (5)
Metallization discoloration Small Low (514)b Medium (399)
Large Low (50) Low (5)
Backsheet degradation Small Low (519) Medium (399)
Large Nil (50) Low (5)

Table 6 shows the result of analysis of infra-red images for 136 modules belonging to Group X, which have been segregated based on the type of mounting and the climatic zone. In the hot zone, modules mounted on the roof have on an average 5°C higher temperature as compared to modules on the ground. It should be noted that the modules on the rooftop were placed on open racks, and not directly on roof. Based on the above discussion, it is evident that the modules on rooftops, usually in small installations, run hotter, besides having material quality and installation related issues, which results in a higher degradation rate.

Table 6. Translated module temperatures for different types of mounting
Translated module temperature (°C) Hot zones Nonhot zones
Roof Ground Roof Ground
Median 67.63 60.85 49.20 46.35
Average 65.52 59.75 46.14 45.76
No. of samples 37 37 40 18

### Climatic zone variation

 Figure 9. Comparison of Pmax degradation rate with respect to six-zone classification system for Group X modules, for (A) all system sizes (B) Small system sizes (<100 kWp) (C) Large system sizes (>100 kWp).
 Figure 10. Comparison of Pmax degradation rate with respect to hot and nonhot zone for Group X modules, for (A) all system sizes (B) Small system sizes (<100 kWp) (C) Large system sizes (>100 kWp).

Table 7 shows the effect of hot cells and module temperature on the modules power degradation rate in the hot and nonhot climatic zones. The mode of the temperature histogram (Tmode, as shown in Fig. 11B) of a module has been considered as the modules representative temperature. The difference in the maximum cell temperature of the module (Tmax in Fig. 11B) from the modal temperature (Tmode in Fig. 11B) is referred to as module ∆T. For a meaningful comparison, the module temperatures measured in the field need to be translated to reference conditions of 1000 Wm−2 irradiance and 40°C ambient temperature [18, 19]. The following relation is used to translate the module ∆T to the reference conditions:

 ${\displaystyle {\mbox{Translated}}\quad module\quad \Delta T={\frac {Module\quad \Delta T\times 1000}{{\mbox{Measured}}\quad {\mbox{Irradiance}}}}.}$
(2)

Table 7. Effect of Hot Cells on power degradation rate of PV modules
Parameter (average of many samples) Hot zone Nonhot zone
Without hot cells With hot cells Without hot cells With hot cells
Power degradation rate (%/year) 1.39 2.02 1.39 1.70
Normalized module ∆T (°C) 6.8 24.7 5.7 18.9
Normalized maximum cell temperature (°C) 68.8 86.1 50.3 58.6
No. of samples 10 18 14 17

 Figure 11. Infrared (IR) image of a PV module, (A), and its temperature histogram extracted from the IR image, (B), showing mode of 63°C and maximum temperature of 79°C, so the module ΔT is 16°C [20].

If the translated module ∆T is >10°C, we have considered the module to be having Hot Cells [21]. We can see from Table 7 that modules with Hot cells are degrading faster than modules without Hot cells, and this degradation rate is higher in the hot zone as compared to the nonhot zone. This trend agrees well with the normalized (translated) module ∆T, which is found to be highest for modules with hot cells in hot zones. The maximum cell temperature is also highest for this category. Modeling and simulation [22] results show that there is very little heat transfer from the Hot cells to the surrounding connected cells. These Hot cells are created under short-circuited condition usually due to mismatch in photo-currents. Figure 12 plots the power degradation rate versus the normalized module ∆T, which shows a positive correlation between the two.

 Figure 12. Correlation of power degradation rate with normalized module ΔT.

Table 8 shows the average severity of visible defects for Group X modules. The severity levels in increasing order of magnitude are ‘Nil’, ‘Low’, ‘Medium’, ‘High’ and ‘Very High’. Detailed explanation of the methodology for arriving at the severity levels is given in a separate publication [17]. Among the Old modules, the average severity of discoloration, delamination, metallization discoloration, and backsheet degradation are all higher for modules in Hot zones as compared to nonhot zones. Among the Young modules, snail tracks are more severe in hot zones than the nonhot zones. Hence, it can be said that, in general, modules in hot zones show more severe material degradation than modules in the nonhot zones.

Table 8. Average severity of visual degradation in hot and nonhot climates for Group X modules (the sample size is given in brackets)
Type of visual defect Climatic zone Age groups
Young Old
Discoloration Hot Low (51) High (155)
Nonhot Low (64) Medium (34)
Front-side delamination Hot Nil (51) Low (193)
Nonhot Low (64) Nil (34)
Snail tracks Hot Medium (51) Nil (193)
Nonhot Low (64) Nil (34)
Metallization discoloration Hot Low (46)** Medium (193)
Nonhot Low (64) Low (43)
Backsheet degradation Hot Low (51) Medium (155)
Nonhot Low (64) Low (34)

The percentage of Group X modules affected by interconnects breakage in different climatic zones and age groups are presented in Table 9. Interconnect breakage test has been performed on crystalline silicon modules, using Togami Cell Line Checker. It has not been found in the young modules, and among the old modules, those in the hot and dry climate seems to be affected the most, followed by the warm and humid climate. This is due to stress caused by thermal expansion and contraction as a result of daily thermal cycling. Also moisture induced corrosion causes loss of adhesion strength. Such a trend is also reported in literature for modules installed in the USA [10, 23].

Table 9. Percentage of modules affected by interconnect breakage in different climatic zones and age groups (the sample size is given in brackets)
Climatic zone 0–5 years 5–10 years 10–20 years 20+ years
Hot and Dry NA NA 100% (20) 2.6% (38)
Warm and Humid 0% (24) 28% (39) 54% (26) NA
Composite NA NA 34% (30) NA
Moderate 0% (31) NA 16% (12) NA
Cold and Sunny 0% (33) NA 35% (17) NA
Cold and Cloudy NA NA NA NA

Based on the above discussion, it can be concluded that climate has a significant influence on the performance degradation rates, with modules degrading faster in hot zones as compared to the nonhot zones. Modules in the hot zones suffer from faster packaging material degradation and higher incidence of interconnect breakages as compared to modules in nonhot zones.

### Technology based variation

 Figure 13. Pmax degradation rate for different technologies for Group X modules.
 Figure 14. Pmax, Isc, Voc, and FF degradation of different technologies for Group X modules.

The predominant defect observed in young crystalline silicon modules is snail trails, which is mostly due to cracks in the solar cells. The cracks tend to increase the series resistance of the modules, and may also cause power loss (depending on the type of crack) [16]. In case of thin film modules, the predominant defect is white spots, which form due to embedded impurities during the manufacturing process owing to improper cleaning of the substrate glass [26]. For the old crystalline silicon modules, the predominant visual defect is encapsulant discoloration, which reduces the short circuit current, and corrosion of metallization, which reduces the fill factor.

### Age based variation

The influence of module age on the degradation rate of c-Si modules is shown in Figure 15. In the young modules, FF degradation is the primary cause of degradation in Pmax, whereas in the old modules, Isc degradation is the main reason. Pmax degradation rate is higher for old modules as compared to young modules in case of Group X but this trend reverses for ‘All’ c-Si modules. Another interesting fact which emerges is that whereas in old modules Pmax degradation is dominated by Isc degradation due to encapsulant browning, in young modules it is dominated by FF degradation probably due to series resistance caused by more cracks as shown below in Table 11. This indicates that the young modules in Group Y have higher degradation rates than the old modules, which suggests that the raw materials and/or manufacturing process and/or installation practices are not optimized or well-controlled.

 Figure 15. Effect of age on Pmax, Isc, Voc and FF degradation of crystalline silicon modules for (A) Group X, and (B) ‘All’.

With aging, the materials in the module degrade due to one or more of the various environmental factors like UV radiation (from sunlight), daily temperature cycling, humidity, etc. The percentage of modules affected by interconnects failure in hot and nonhot zones have been shown in Table 10. The young modules do not have any interconnect breakage, whereas a high percentage of old modules show breakage, particularly in the Hot zones. Temperature cycling (hot in daytime and cooler at night) has been identified as one of the major causes of interconnect failure in the field [10]. Also, with aging, there is increase in encapsulant discoloration, delamination, corrosion and backsheet degradation, as evident from Tables 3, 5 and 8.

Table 10. Interconnect failures for Group X modules (the sample size is given in brackets)
Climatic zone Young modules Old modules
Hot zones 0% (24) 43% (153)
Nonhot zones 0% (64) 28% (29)

From Table 11, it is evident that percentage of cracked cells in young modules is more than that in old modules, which hints that the transportation and/or installation practices for young modules has not been carefully undertaken. Also, the present day modules have thinner cells, which make them more susceptible to cracks as compared to the cells in the older modules.

Table 11. Percentage of cells affected by different types of cracks in young and old modules
Percentage of cells affected by different types of cracks Total no. of cells
Mode A cracks Mode B cracks Mode C cracks
Young modules 37.9% 14.9% 12.2% 408
Old modules 0% 26.2% 4.4% 1008

## Acknowledgments

This research is based upon work supported in part by (a) the National Centre for Photovoltaic Research and Education funded by Ministry of New and Renewable Energy of the Government of India through the Project No. 31/17/2009-10/PVSC dated 29th September 2010 and (b) the Solar Energy Research Institute for India and the U.S. (SERIIUS) funded jointly by the U.S. Department of Energy subcontract DE AC36-08G028308 (Office of Science, Office of Basic Energy Sciences, and Energy Efficiency and Renewable Energy, Solar Energy Technology Program, with support from the Office of International Affairs) and the Government of India subcontract IUSSTF/JCERDC-SERIIUS/2012 dated 22nd November 2012. The authors acknowledge assistance from the various State Renewable Energy Development Agencies and from S. P. Gonchaudhuri, and Hemant Lamba, who provided encouragement and valuable inputs for the survey.

## Conflict of Interest

None declared.

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