Evaluation of PV Module Field Performance. John Wohlgemuth, Timothy Silverman, David C. Miller, Peter McNutt, Michael Kempe and Michael. Deceglie.
Evaluation of PV Module Field Performance John Wohlgemuth, Timothy Silverman, David C. Miller, Peter McNutt, Michael Kempe and Michael Deceglie National Renewable Energy Laboratory, Golden, CO, 80401
Abstract
-
This paper describes an effort to inspect and
evaluate PV modules in order to determine what failure or degradation modes are occurring in field installations. This paper will
report
on
the
results
of
six
site
Sacramento Municipal Utility District Tucson Electric Power
(TEP)
visits,
(SMUD)
Springerville,
including
the
Hedge Array,
Central Florida
Utility, Florida Solar Energy Center (FSEC) , the TEP Solar Test Yard, and University of Toledo installations. The effort here makes use of a recently developed field inspection data collection protocol,
and
the
results
were
input
into
a
corresponding
database. The results of this work have also been used to develop a draft of the IEC standard for climate and application specific accelerated stress testing beyond module qualification.
Index Terms
-
PV module field inspections, durability,
reliability
I. INTRODUCTION PV module reliability work usually starts by identifying field degradation or failure modes. Once failure modes are identified, accelerated stress tests can be developed to duplicate observed failures or degradation. These accelerated stress tests are then used to improve product reliability and to "qualify" products for use in the terrestrial environment. The International PV Quality Assurance Task Force (PVQAT) effort to develop climate specific accelerated stress tests is based on identifying module wear out mechanisms and developing accelerated stress tests to duplicate field damage. In support of the PVQAT effort, NREL has evaluated the performance of the modules in a number of PV systems. This paper will report on the results of these field inspections.
wizard) with guidance on what information to collect and what to photodocument. The studies reported in this paper were used to improve the field inspection data collection protocol and initially populate a database using the results. We have found that an infrared (lR) camera is a useful tool for identifying modules with problems [2]. For best results we take the IR images while the modules are operating near peak power. In this way, we can see what areas are heating up more than the surrounding areas and which areas are not carrying current. Once a potential problem has been identified by visual inspection or thermal imaging, it is important to evaluate what effect the observed defect has had on module performance. Use of a portable IV curve tracer can provide an estimate of module performance. Because we usually do not have previous measurements of the modules, we have to compare our results to the module specification or its nameplate. III. PV ARRAYS EVALUATED This paper will report on the six site inspections shown in TABLE I. Two of the sites were utility-scale systems while the others were smaller demonstration systems, often consisting of multiple smaller arrays. The oldest arrays contained only crystalline silicon modules, but the later arrays included all of the commercially available thin film technologies. Several results are subject to module replacement and maintenance occurring since installation. IV. OBSERVATIONS OF ARRAYS
II. METHODOLOGY In selecting PV systems of interest we requested information about the construction of the system and its performance history. In many cases, especially for older systems, the data on performance over time is either not available at all or is of suspect quality, often because the measurement equipment and irradiance sensors have not been maintained adequately. Once on site, we perform visual inspections with photography, thermal imaging, and IV characterization. NREL has developed a visual inspection data collection tool to guide the inspection of the modules [1]. We developed this tool to provide a "standard" method for the collection of data. By using the tool we have improved the consistency of data collection and made it possible to summarize the resultant data in spreadsheet format. The data collection tool guides the module inspector through the process (similar to a software
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A.
Hedge, SMUD (Sacramento, CA) In 1993, Sacramento Municipal Utility District (SMUD) installed 210 kW of Siemens M55 monocrystalline Si modules at the Hedge substation. In 1994 SMUD added 108 kW of Advanced Photovoltaic Systems (APS) EP55 a-Si modules, 102 kW of Solarex MSX-120 multicrystalline Si modules and 107 kW of additional Siemens M55 modules [3]. In April, 2014 NREL staff visited and inspected the site. The owner's output data from sunny days shows that 3 of the 4 arrays were fairly stable from 2009 to 2014 producing more than 80% of the initial power. Because the trackers were not working correctly (they are pointing east) the original Siemens array is now producing only 25% of what it was 5 years ago. Tracker failure probably overshadows all of the others in terms of total energy lost. Observations of defects are given below: APS a-Si:. Distribution of IV curves with about 113 of the measured modules down 15% in short circuit current. There
did not appear to be any correlation between the observed defects and the lost power. • Cracked substrate glass (often from the sinking foundation). • TCO delamination/TCO corrosion (Figure 1) • Discolored/thinning TCO
• • • • • •
Fig. 1. TCO Corrosion in APS a-Si Module
Siemens M55 from 1994: Distribution of IV curves with some near original power and others with collapse of fill factor. In this case there was correlation between the observed defects and lower fill factor. • Shattered superstrate glass (often from electrical arc) • Burnt j-box (from electrical arc in loose internal wire) • Corroded cells (typically at cracks) accompanied by burnt backsheet, torn backsheet, delaminated backsheet. • Cracked cells • Hot spots/ hot cells • Localized delamination (encapsulation/cell interface, particularly at corners of cell and busbars) (Figure 2) • EVA discoloration (including some severe)
Corroded cells (typically at cracks) Cracked cells Burnt and cracked backsheet Hot spots/hot cells (Figure 3) Localized delamination (encapsulation/cell interface) Mild EVA discoloration
Fig. 3. Overheated solder bonds (right) in Solarex module
B.
Springerville, TEP (Springerville, AZ) The Springerville system consists of 3 PV technologies: ASE America's ASE 300 DGF (Si-ribbon), BP Solarex's MST-43 (a-Si) and some of the earliest commercial First Solar CdTe modules [4]. One problem with this installation was the placement of the racks close to the ground (and vegetation), resulting in shading and damage to the glass during mowing. Observations of defects are given below: CdTe • Broken glass (3 out of a subset of 450) • Extruding edge seals resulting in voids (Figure 4) • Corrosion at hot spots • Rail bond detachment
Fig. 4. Failure of edge seal in glass/glass module.
a-Si •
Fig. 2. Delamination and discoloration in 1994 Siemens M55 Module
• •
The original (1993) Siemens M55 array was not functional at the time of inspection because of maintenance, so our evaluation was limited to a visual inspection. That array did not have many of the defects observed in the 1994 Siemens array, with almost no discoloration or delamination. It is likely that some change in raw materials and/or process led to the discoloration and delamination in the newer batch of modules. Solarex MSX-120: No useful IV curves taken • Shattered superstrate glass (2 instances) • Burnt j-box (loose internal wire)
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Delamination at hot spots Broken glass (17 out of a subset of 400 modules) TCO Corrosion on all modules (Figure 5)
Fig. 5. TCO corrosion in BP Solarex a-Si module
ASE Crystalline Si • Broken glass (28 out of 1350, mostly from mowing ) • Delamination (in modules built from 112001-9/2001) with minimal delamination in modules built after that • Arc faults (Figure 6)
Fig.
8. Corrosion of cell metallization (including gridlines and
ribbon) in Mobil Solar Module
D.
Fig. 6. Arc fault,subsequently destroying ASE c-Si module.
Central Florida Utility Demo (Ocala, FL) This system consists of 3 small (�5 kW) demonstration arrays constructed in a remote site in Florida. The fIrst array of Mobil Solar EFG modules (Ra 180) was installed in 1990. A Kyocera multicrystalline Si array (LA 661K94) was added soon after. A third array of BP Solar monocrystalline Si modules (BP 275) was added in 1998. By the time of the NREL visit in 2013 , the inverters had failed and the systems had been off line for at least 5 years. Observations of defects are given below: Kyocera Crystalline Si • No visible defects - The cells, backsheet and encapsulant looked like new C.
FSEC (Cocoa, FL) This system consists of two small arrays constructed on the Florida Solar Energy Center property. The first array of 30 Siemens Solar ST40 CIGS modules was installed in 2002 [5]. The modules have glass/glass construction with no edge seals. The second array of 20 Siemens M55 monocrystalline Si modules was installed (on movable trailers) in 2000. NREL visited the site in 2014. Observations of defects are given below: CIGS: IV curves taken by FSEC showed major power loss due to a huge scatter in fIll factor. Modules with hot spots and corroded scribe lines were the worst performing. • Hot spots within cells with cracks in glass through the hot spots (Figure 9) • Corrosion of scribe lines • Discoloration/corrosion of TCO
BP Solar Crystalline Si • EVA discoloration over center of all cells (Figure 7) • Yellow/brown regions over labels • Cracked cells (Figure 7) • Some small delamination of the backsheet from EVA Fig. 9. Hot spot and resulting discoloration in CIGS Module
M55 - monocrystalline Si • Delamination of encapsulant from cell surface especially along tabbing ribbons in all modules (Figure 10) • Cracked cells (3 cells out of 20 modules) • Localized hot spots near edge of cell (in 5 out of 20 modules)
Fig. 7. EVA discoloration and cracked cell in BP Solar c-Si Module
Mobil Solar Crystalline Si • Corrosion of cell metallization accompanied by delamination (probably between cell and EVA) (See Figure 8 ) • EVA discoloration over center of cells • Backsheet almost completely delaminated from EVA
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Fig. 10. Delamination of Siemens M55 Module at FSEC
E.
TEP Solar Test Yard (Tucson, AZ)
The Tucson Electric Power (TEP) system consists of a number of small arrays deployed at various times starting in 2001 [6]. During the visit in 2014 we inspected 11 different c Si arrays and 3 different thin film arrays. Observations of defects are given below: 11 Types of c-Si Modules at TEP • 3 out of the 11 module types had EVA discoloration. When discoloration occurred all of the modules were affected. • 2 of the module types had no observable defects. • 1 module type had lost all of its labels. • 3 module types had burn marks - all of these types suffered significant power loss. (Figure 11) • 2 module types had severe blistering of the backsheet (trapped gas) impacting most of those modules. • ASE Americas modules had delaminations over the junction boxes similar to Springerville. (Figure 12) • ASE modules were the only c-Si glass/glass construction and were the only c-Si modules to exhibit any corrosion of cell metallization (in 6 out of 72) always associated with delamination. (Figure 13)
Fig. 13. Corrosion and delamination in corner of ASE glass/glass module
3 Types of Thin Film Modules at TEP • CIGS (Glass/glass) had no visual defects but 20% power loss due to lower fill factor. • CIGS (discrete cells on substrate) had no major visual defects but the modules suffered from low voltage. • a-Si (glass/glass) had 1 module out of ISO with broken glass, bar graph corrosion of the TCO on a majority of the modules (Figure 14) and power losses of 22 to 32%.
Fig. 11. Bum mark in the back of c-Si module. Fig. 14. Bar graph corrosion of TCO in BP Solar a-Si module.
University o/Toledo (Toledo, OH) The University of Toledo system consisted of 108 CdTe modules deployed in 2006. NREL visited the array in September 2014 [7]. Observations of defects are given below: • Broken front glass (2) and broken back glass (1). • About 7S% of the modules had visible delamination at the intersection of the bus tapes (Figure ISa). Most of these modules had a hot spot at this location identified with the IR camera. (Figure ISb) • Overall output power was about 6% below nameplate. Those without hot spot heating along the bus tape still met the nameplate rating.
F.
Fig. 12. Delamination of ASE modules over the J-box
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humid and hot dry climates without exhibiting visual defects after more than 10 years of deployment.
Areo/Siemens/Shell Modules Modules from this group were inspected at Hedge, FSEC and TEP. These modules showed more consistent discoloration than those from any other module manufacturer due to their use of "standard cure" EVA, the equivalent of STR A9918, long after most other manufacturers had switched to the fast cure formulation. We also observed more delamination with M55 modules (Figure 10), which is likely related to their use of a 2 step lamination process - with cross linking performed in a low temperature oven without atmospheric control. Two issues with this process are whether the primer ever achieved its activation temperature or whether the flux residues were able to outgas correctly. The third defect observed for these products was localized hot spots seen at Hedge and FSEC but not at TEP. Occasional failure of solder bonds probably indicates periodic issues with process control. C.
Fig. 15a. Delamination of bus tape in CdTe module.
tempt'C 50
40
30
20
10
Fig. 15b. Hot spot at delamination of bus tape.
V. COMPARISON OF SAME MODULE TYPES AT DIFFERENT SITES To better understand our observations, we will compare the results for the same module types at different locations.
Mobil SolariASE Modules Mobil SolariASE America modules were inspected at Springerville, Central Florida and TEP. The modules in central Florida had polymer backsheets and we believe from the discoloration pattern that they had an EVA encapsulant. The 300-DGF/50 modules at Springerville and TEP were glass/glass construction and from their literature and the inspection results we believe these modules had an ionomer encapsulant. It is the ionomer that exhibited delamination over the junction boxes (See Figure 12) in the MobillASE modules. The observation that modules fabricated after Sept, 2001 did not exhibit this delamination indicates a process/material change that solved the problem. Corrosion in these modules was facilitated by delamination allowing direct exposure of cell materials to environmental moisture. Just using glass/glass construction does not necessarily eliminate moisture ingress into the modules.
D.
Solarex/BP Solar C-Si Modules Modules from these 2 companies were inspected at Hedge, Central Florida and TEP. The Hedge array exhibited the greatest variety of defects likely because it contained many more modules than the other systems and because it was installed early in the Solarex product history. Major issues of concern were burnt j-boxes, preswnably due to loose wires (an installation issue), and hot spots, due to failed solder bonds. Typically older Solarex and BP Solar modules exhibited some discoloration, but typically less than seen for Arco/Siemens products. Even the moderate discoloration ceased after the switch to less susceptible EVA formulations.
A.
B. Kyoeera Modules Kyocera modules were inspected at the Central Florida and TEP arrays. None of the modules inspected showed any visual defects. These were both small arrays, so the statistical sampling size is not significant. It is encouraging to see that well designed and fabricated modules can survive in both hot
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E.
Glass/glass a-Si by BP Solar and APS. Glass/glass a-Si modules were inspected at Springerville and TEP (BP Solar) and at Hedge (APS). While these were not all built by the same manufacturer, the module construction is very similar. In all three cases, the major defects were broken glass (to be discussed in the next section) and TCO corrosion. The TCO corrosion for the BP Solar modules (Figures 5 and 14) had a different appearance than that for the APS modules (Figure 1); this is more likely to be a result of the mounting systems used. The BP Solar modules all had metal frames while the APS modules were frameless. TCO corrosion is usually attributed to high voltage effects, indicating that a voltage stress test is necessary for evaluating the long term performance of thin film modules. VI. DEFECTS OBSERVED IN MULTIPLE MODULE TYPES To better understand our observations, we will assess several failure modes that we saw on different module types.
A.
Glass Breakage We observed glass breakage at almost all of the sites, although it was more obvious at the 2 utility scale
installations, both of which had a probable cause. Springerville had a rack system that was very low to the ground. It was clear that a lot of damage came from mowing. SMUD had issues with settling of the foundations. There appear to be more thin film modules with broken glass than c-Si, but the reasons are complicated because: 1) Most of the thin film modules have two pieces of glass while most of the c-Si modules only have one piece of glass and a frame. This results in a higher probability for thin film modules to have broken glass. 2) Most thin film modules use annealed glass while the c Si modules have tempered glass. While the tempered glass is harder to break, once it does break, it cracks into small pieces making it very obvious that the glass has broken. On the other hand it was the back glass that was broken on many of the superstrate thin film modules. This is both harder to observe and not immediately catastrophic to both the mechanical and electrical functioning of the module. Therefore broken back glass thin film modules may be left in the field while broken front glass c-Si modules may be replaced quickly. Sometimes it is obvious what has caused the glass breakage, e.g., a clear impact site. Other times it is not as obvious. Did the electrical failure cause the glass to break due to overheating or did the electrical failure result because of loss of isolation due to the glass breaking first? For tempered glass in particular fractography can often, but not always identify the location where the breakage began.
B.
Encapsulant Discolorationfor crystalline Si Modules Most of the earliest arrays have modules that exhibit EVA discoloration. This phenomenon was evaluated and reported on by STR [8]. While the technology is now available to eliminate discoloration as a defect [9], many module manufacturers are using new, low cost EVA formulations with no established product history. What is needed then, is a UV exposure test incorporated into an IEC standard to identify any new encapsulants that might have the potential to discolor. Hot Spots and Solder Bond Failures A number of crystalline Si modules had hot spots caused by failure of solder bonds. These were more prevalent in the larger systems with higher system voltages, but they were also observed in the smaller systems for particular module types. C.
the defects we observed in this effort. The module qualification tests (IEC 6121S and 61646) are not particularly well designed to test for this failure. A more robust test for delamination is under development as part of IEC 62892, Climate Specific Testing. VII. CONCLUSIONS For c-SI visual observations appear to correlate well with power degradation for: • Discoloration with lower Isc • Burns, broken cells, and delaminations with lower fill factor. • Evidence of heat around bus bars with complete loss of voltage from individual strings. . For thin film modules, visual observations correlate well with power degradation for corrosion and delamination of bus tape. There were several instances of significant power loss in thin film modules with no apparent visual indication. From these observations we have concluded that we need to improve our reliability testing to assess for potential degradation due to discoloration of encapsulants, broken cells, delaminations, and failure of solder bonds and interconnect ribbons References [I] C.E. Packard, lH. Wohlgemuth, and S. R. Kurtz, "Development of a visual inspection data collection tool for evaluation of fielded PV module condition". Tech Report TP-5200-56154,NREL,2012. [2] P. McNutt,lH. Wohlgemuth, D.C. Miller, B. Stoltenberg, "Results of I-V Curves and Visual Inspection of PV Modules Deployed at TEP Solar Test Yard",NREL PVMRW,2014. [3] D.E. Osborn,"Field Performance of Amorphous Silicon (a-Si) Laminate Photovoltaic Installations at SMUD and other Large Scale Deployments",Proc. ASES Solar Conf,2003. [4] L.M. Moore,H.N. Post,"Five Years of Operating Experience at a Large, Utility-scale PV Generating Plant",PIP,16,2008,249-259. [5] E. Schneller,N. Shiradkar, N.G. Dhere,"Performance Analysis of CIGS Thin-Film Photovoltaic System After 10 Years in the Hot and Humid Climate of Florida",NREL PVMRW,2014. [6] E.S. Kopp, V.P. Lonij, A.E. Brooks,P. L. Hidalgo-Gonzalez,A. D. Cronin,"I-V Curves and Visual Inspection of 250 PV Modules Deployed over 2 Years in Tucson",Proc IEEE PVSC 2012. [7] T. Silverman, J. Wohlgemuth,D. Miller,M. Kempe,and P. McNutt, "Review of observed degradation modes and mechanisms from fielded modules",NREL PVMRW,2015. [8] W. W. Holey and S.C. Agro,"Advanced EVA-Based Encapsulants",NRELlSR-520-25296,1998.
D. Delaminations Delamination was observed for at least one type of module at each of the 6 sites. It is probably the least studied of
[9] John H. Wohlgemuth,Michael D. Kempe and David C. Miller. h "Discoloration of PV Encapsulants",39t IEEE PVSC,2013.
TABLE I: PV ARRAYS EVALUATED FOR THIS PAPER Arra
location
S rin erville, TEP, AZ Central Florida TEP, AZ FSEC,FL Hed e, SMUD, CA Univ of Toledo, OH
Demonstration Demonstration Demonstration Utility Demonstration
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IS kW 2S kW 2.S kW SOOkW 12 kW
Technolo ies Re resented
Year Installed
CdTe a-Si EFG-Si Mono-Si, Multi-Si, EFG-Si Mono-Si, Multi-Si, EFG-SI, CIGS and a-Si Mono-Si and CIGS Mono-Si, Multi-Si and a-Si CdTe
2001 1990 2000 2002 1993 2006
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