Degradation and Failure Mechanisms of PV Module Interconnects

5 Degradation and Failure Mechanisms of PV Module Interconnects Yang Hu 1 and Roger H. French 2 GE Renewable Energy, San Ramon, CA, United States 2 Case Western Reserve University, Case School of Engineering, SDLE Research Center, Materials Science and Engineering, Cleveland, OH, United States 1

5.1 Introduction to PV Modules Interconnection, Degradation, and Failures The crystalline silicon (c-Si) wafer-based solar cells have been successfully transitioned from the research laboratory to mass production to become the dominant technology in commercialized solar photovoltaic (PV) modules [1]. In this chapter, we will focus on degradation and failure mechanisms of the c-Si cell interconnections in commercialized c-Si PV modules. The screen printed silver (Ag) front contact aluminum (Al) back surface field (Al-BSF) cell has been the dominant commercial solar cell architecture. But the Al-BSF architecture is now being superseded by the passivated emitter rear contact cell (PERC), which is similar from an interconnection perspective. The assembly and manufacturing process of front Ag contact silicon solar cells involves screen printing the front metal electrode and the back aluminum contacts on the cell using fritted glass paste materials, followed by soldering highly conductive lead/tin solder-coated ribbon along the front-side silver busbar [2]. The ribbon extends from 1 cell to the next and is soldered to the back of a neighboring cell to enable the current flow from the front side of one cell to the back side of the next cell in a series connection [3]. The manufacturing process of PV module interconnections involves the use of infrared reflow soldering, induction soldering, or even hand soldering. The soldered joint provides good electrical contact between the solar cells and electrodes, but it can induce high mechanical stress and thermal shock which can induce microcracking in the cells. The stringing ribbon connects solar cells with each other to form strings, while the bussing ribbon connects

strings of solar cells to form a module. The bus ribbon is soldered inside junction box with bypass diodes to protect the module from hot spot and shading effects. The leads coming out of the junction box are the output interface of the PV module. The failures of cell interconnection in c-Si PV modules have been reported as a key reliability challenge [3e6]. The interconnect ribbon is a wide and flat-shaped copper (Cu) metal wire soldered by tin-lead-silver (SnPbAg) on the front side of one PV cell and the back side of neighboring PV cell, as shown in Fig. 5.1. Metallic corrosion, induced by hygrothermal stress on screen-printed silver metal busbars or grid lines, is well known to lead to power degradation of c-Si PV modules [7e9]. The degradation of solder joints during the module’s field operation due to temperature cycling has been

Figure 5.1 Solder interconnection between ribbon wire and silicon solar cell. From J.S. Jeong, N. Park, C. Han, Field failure mechanism study of solder interconnection for crystalline silicon photovoltaic module, Microelectronics Reliability 52(9e10) (2012) 2326e2330.

Durability and Reliability of Polymers and Other Materials in Photovoltaic Modules. https://doi.org/10.1016/B978-0-12-811545-9.00005-7 Copyright © 2019 Yang Hu & Roger H. French. Published by Elsevier Inc. All rights reserved.

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reported as one major contributor to PV module’s interconnection failures. Extreme solder cracks can result in the PV module’s open circuit failure [6,10,11]. In a PV module, all the cells and their interconnections are encapsulated between the glass front sheet and the polymeric backsheet. The difference in thermal expansion coefficients of the ribbon and silicon results in the variation of cell-to-cell spacing at different temperatures. Thus, stress can accumulate in the interconnect ribbon, and especially the part between two cells where the ribbon adopts the sigmoid shape of the front surface to back surface “tab.” Furthermore, stress from the interconnection can be concentrated at the edge of solar cell where the ribbon is bent. As a result, interconnect ribbon failure originating from metal fatigue is a common failure mode in flat-plate PV modules [12e14]. The degradation of the solder joint at the electrical connection of the string bypass diode in the junction box may also be induced by repeated thermal cycling over lifetime. Severe heat damage, even up to PV electrical fires, has occurred at junction box and may be exacerbated by DC arcing at the interconnection crack caused by solder joint fatigue. We will describe here the three typical interconnection degradation and failure mechanisms of silicon as solder: front-side silver grid corrosion, solder joint degradation, and interconnect ribbon fatigue. In addition, there has been increased recent interest in replacing the copper ribbon interconnect with electrically conductive adhesives (ECAs), used with PV cells that overlap each other (referred to as “shingled” cells), and the reliability issues of these will also be discussed.

5.2 Front-Side Silver Grid Corrosion The standard front-side metallization of crystalline silicon solar cell is done by screen printing silver containing paste on solar cell’s front surface and heat treated to form an ohmic contact [2]. In order to minimize the shading of metallization on the front surface, the silver gridline width is less than 100 mm after firing [15,16]. Under accelerated reliability tests and long-term outdoor exposure, front-side metallization is a known weakness of PV modules [17e20]. The damp heat (DH) test, at 85
C and 85% relative humidity [21], is a common and crucial test for PV

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Figure 5.2 Electroluminescence images of photovoltaic modules exposed in 85
C/85% relative humidity (RH) test for 3000 h.

modules qualification testing. Because of the high humidity during the DH test, polymeric and metallic compounds of PV modules may degrade, inducing discoloration, delamination, or corrosion [22e24]. A frequently observed degradation phenomenon after DH test is the dark outer area of each solar cell in the electroluminescence (EL) image [20]. This DHinduced degradation (DHID) is typically accompanied by serious decreases in module performance. A similar dark region is detected in PV modules that went through long outdoor exposures. Fig. 5.2 shows the EL image of a PV module subjected to exposure in 85
C and 85% relative humidity test conditions for 3000 h. The dark regions along the edge of each solar cell were observed. Although the EL dark area’s distribution depends on the architecture of PV modules, the root cause of such degradation is moisture ingress into PV module and acetic acid (HAc) generated from the hydrolysis decomposition of ethylene vinyl acetate (EVA) [20]. The corrosion of front-side metallization corrosion is primarily caused by a high concentration of HAc. The acetic acid attacks the silver gridline and solar cell interface, which is the critical current path for PV electronic current.

5.2.1 Mechanisms The front-side Ag grid is screen printed with an Ag paste containing fritted (ground) glass particles. Ag paste contains Ag particles of an average size of 1 mm (80%e90%), glass frit (0%e5%), an organic solvent (3%e15%), a cellulose resin (3%e15%), and inorganic additives and surfactants (1%e2%) [25]. The additives are supposed to lower the co-fire temperature, help minimize the shrinkage mismatch with the

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dielectric, and increase mechanical strength. The glass frit dissolves the antireflective coating on the front surface of the cell and makes ohmic contact between the Ag paste and the pen junction. Peike et al. showed in 2013 that the failure mechanism of DHID is due to a loss of the electrical contact between emitter and front-side metallization [20]. They suggested that DHID originates presumably from an attack of HAc on the glass frit inside the front-side contact. As the current standard module encapsulation material of c-Si solar cells, EVA is known to degrade under the presence of humidity [26]. HAc is a by-product of the EVA hydrolysis. The currentevoltage curve measurement of the aged PV module showed a decreased series fill factor (FF) caused by an increased series resistance. Moreover, the spatial distribution of the series resistance (Rs) calculated from luminescent images showed a significantly increased series resistance in the EL dark region. Therefore, grid corrosion or a reduced conductivity between the emitter and the grid is the most likely cause of the DHID [20]. Kraft et al. demonstrated the dissolution of the glass layer underneath the silver gridline metallization by immersing solar cells into aqueous HAc solution. In standard lead glass, lead oxide is present, which is observed to corrode in the presence of HAc. According to the Pourbaix diagrams, the following reaction is probable: PbO þ 2CH3 COOH/ðCH3 COOÞ2Pb þ H2 O. (5.1)

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Lead oxide reacts in the presence of acetic acid to lead acetate, which is highly soluble in water. Water transports into the modules through the backsheet, diffuses at the cell front side from the edges to the center of the cell and moves the HAc present within the EVA encapsulation to the contacts [17,20]. Moisture transports more acetic acid into the vicinity of the glassesilver interface and removes the lead acetate compound. The corrosion process can be accelerated by negative voltage applied to the front contact even at low HAc concentration. This behavior can be explained by the reduction of the dissolved lead in the presence of electrons at a suitable potential, which will remove the lead from the system and release the HAc. This electrochemically driven dissolution cycle is shown in Fig. 5.3 as a schematic drawing at the contact interface. The reaction is particularly strong where the transport distance between the place of lead dissolution (glass layer) and the place of lead reduction (bulk silver) is very short. This leads to a quick spreading gap formation between the glass and silver inside the contact. This is the origin of the adhesion loss due to the presence of acetic acid. The dissolution mechanism explains the observation that high-series resistance cell area is highly correlated to the dark area in EL images. The kinetic analysis for PV and electrical characteristics was conducted experimentally by detecting the electrical signal concerned in contact gap formation by HAc vapor. This signal seems to be a crucial “aging signature” in PV modules.

Figure 5.3 A schematic drawing of the dissolution mechanism at the glass silver boundary layer in the contact. This mechanism causes poor contact adhesion and works efficiently if a voltage is applied to the contacts, due to the redeposition of the dissolved species. From A. Kraft, L. Labusch, T. Ensslen, I, Du¨rr, J. Bartsch, M. Glatthaar, et al., Investigation of acetic acid corrosion impact on printed solar cell contacts. IEEE Journal of Photovoltaics 5(3) (2015) 736e743.

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5.2.2 Characterization The gap evolved by the dissolution of the glass layer underneath the silver grid lines of the solar cell may be monitored by the alterations of capacitance and/or impedance under alternating current loading conditions (Fig. 5.4). Experimentally, Tanahashi et al. mounted PV cells soldered with cell interconnect ribbons in a chromatography chamber filled with HAc vapor under high humidity and high temperature (Fig. 5.5). This exposure system was constructed by reference to Kempe’s previous work [26]. PV minimodules (c.4 W, 180  180 mm) are assembled with the same type of PV cell plus extra EVA, backsheet, and glass. The DH test of PV minimodules was carried out at 85
C/85% relative humidity over 3000 h. The characteristics of AC impedance were evaluated by an LCR meter with frequency scanning function [28]. The degradation profile of minimodules is divided to two phases by the electrical characteristics. First, the generating power (Pmax) was rapidly declined with decreasing in FF after a short-time lag (phase I), and thereafter the gradual reduction of Pmax with that of Isc (phase II) was observed (Fig. 5.6). It is worth noting that at phase I, the development of a new capacitance C3 with higher capacitance than C2

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(capacitance derived from pen junction) was identified by AC impedance spectroscopy (Fig. 5.6). Simultaneously, the increase of series resistance, RS, in DC and R1 in AC measurement was identified by analysis for dark IeV curve and AC impedance spectrum. The resistance R3, which is developed with the new capacitance C3, increased through phase I. The degradation evolution is also observed through the evolution of EL images (Fig. 5.7). Bright “cloud”-like area and bright points semi-uniformly distributed in the lower EL brightness background were observed in the initial EL image of the sample cell. The bright area clears away during phase I and is replaced by sparsely distributed bright points only on finger electrodes under dark EL background. This result suggests that the gap underneath the finger electrodes developed and grew during phase I (shown in Fig. 5.8). However, the direct contact of silver and emitter surface still appears to remain. These contact points are shown as an Ag pillar in Fig. 5.8. In phase II, the series resistance (Rs and R1), the novel impedance-derived resistance R3, and FF stay nearly constant (Fig. 5.6). However, Pmax and Isc decreased during the whole duration of phase II. It should be noted that Isc decreases as the EL image “cloud”-like brightness disappears, and EL brightness was limited to the area near the busbar on the PV

Figure 5.4 Formation of the gap underneath the finger electrode on a p-type c-Si photovoltaic cell by corrosion, and the respective AC equivalent circuits modeled under dark conditions. Intact contact between the front electrode (orange) (dark gray in print versions) and the emitter of the Si wafer (yellow) (light gray in print versions) is illustrated in (A), and the corroded contact with formed gap is demonstrated in (B). From T. Tanahashi, N. Sakamoto, H. Shibata, A. Masuda, Localization and characterization of a degraded site in crystalline silicon photovoltaic cells exposed to acetic acid vapor. IEEE Journal of Photovoltaics 8(4) 2018 997e1004. https://doi.org/10. 1109/JPHOTOV.2018.2839259.

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Figure 5.5 Experimental setup for the exposure of bare photovoltaic (PV) cells to acetic acid (HAc) vapor. From N. Tanahashi, H. Sakamoto, A. Shibata, Masuda, Localization and characterization of a degraded site in crystalline silicon photovoltaic cells exposed to acetic acid vapor. IEEE Journal of Photovoltaics 8(4) (2018) 997e1004. https://doi.org/10. 1109/JPHOTOV.2018.2839259.

cell. From this observation, it is assumed that some alteration with addition of forward directional diode and/or increase of resistivity occurs at the Ag pillars (Fig. 5.8). The current pass between emitter and silver finger consists of two routes: direct contact via Ag pillars and electron tunneling via nano-Ag colloids dispersed in glass layer [30,31]. Therefore, it is assumed that the FF reduction during phase I is due to dissolution of glass layer that contains dispersed nanosilver particles. In phase II, the PV cells begin to lose the diode blocking characteristic in reverse bias after 24 h of exposure to HAc vapor and 85
C/85% relative humidity. This result together with the Isc decrease suggests the electrical property of the Ag pillars have changed. Similar progression in phases of IeV curve and AC impedance parameters were observed in the PV cell encapsulated in a conventional module architecture (Fig. 5.9). The ingress of moisture onto PV cells within a module progresses from the periphery to the central area in a constant humidity damp heat test [32]. The

degradation of a PV cell caused by moisture starts from the periphery area first, and then subsequently occurs in the central area of PV cell under DH test [20,33]. Because nonuniform degradation phases can occur within one PV cell, the electrical signal from each region in different degradation phases may combine together and lose their characteristic features when the signal is obtained from a whole PV cell. An example of this feature loss is described by the development of impedance C3 and R3 where the increase of impedance in areas at degradation phase I is combined with the existing high impedance at areas at degradation phase II. However, the signal of phase transition still can be detected. Therefore, the degradation process identified on a bare PV cell exposed to HAc vapor, which seems to be spatialisotropically degraded, is able to be captured as an “aging signature” even in a PV cell laminated in a PV module, which seems to be spatial-anisotropically degraded under the DH stress. The acceleration factor between power loss observed in bare PV cells exposed to HAc vapor at 85
C/85% relative humidity (Fig. 5.6) and in PV

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Figure 5.6 A plot of the phase transition during degradation in photovoltaic cells exposed to acetic acid vapor. From T. Tanahashi, N. Sakamoto, H. Shibata, A. Masuda, Electrical detection of gap formation underneath finger electrodes on c-Si PV cells exposed to acetic acid vapor under hygrothermal conditions. In: 2016 IEEE 43rd Photovoltaic Specialists Conference (PVSC), 2016, pp. 1075e1079, https://doi.org/10.1109/PVSC.2016.7749778.

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module exposed to DH test conditions (Fig. 5.9) is roughly estimated as 100. The acceleration factor between PV modules’ power loss in DH conditions and in tropical climate conditions has been estimated to be 23 [34,35]. Using these estimations, 2300 times acceleration is induced between exposed bare PV cell to HAc vapor and outdoor exposure for PV modules in a tropical climate. However, there are some problems of simply applying the product of two acceleration factors. First, HAc is a by-product of EVA hydrolysis. Its concentration inside PV modules is strongly affected by the vapor transport rate of the backsheet and edge seal if present. The time required for the moisture to reach the center of the PV cell’s front side in a PV module is about 2000e3000 h even under DH stress condition [36,37]. This time is not considered when a PV cell is directly exposed to HAc vapor. Second, HAc concentration is not uniform in a PV module. Since the amount of HAc in each region within PV module depends on the concentration of moisture, the anisotropic degradation observed in PV module is not reflected in the exposure of PV cell to HAc vapor [38,39]. Finally, the combined effects of temperature and humidity on the hygrothermal degradation of PV modules have yet to be completely resolved. It has not been elucidated whether the time to failure of PV modules under hygrothermal conditions are determined by the exponential corrosion model or the power law model [35,40,41]. However, the “aging signature” detected in PV modules over a

Figure 5.7 Evolution of electroluminescence image during degradation in photovoltaic cells exposed to acetic acid vapor. From T. Tanahashi, N. Sakamoto, H. Shibata, A. Masuda, Electrical detection of gap formation underneath finger electrodes on c-Si PV cells exposed to acetic acid vapor under hygrothermal conditions. In: 2016 IEEE 43rd Photovoltaic Specialists Conference (PVSC), 2016, pp. 1075e1079, https://doi.org/10.1109/PVSC.2016.7749778.

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Figure 5.8 A diagram of the putative degradation process on c-Si photovoltaic cells exposed to acetic acid vapor. From T. Tanahashi, N. Sakamoto, H. Shibata, A. Masuda, Electrical detection of gap formation underneath finger electrodes on c-Si PV cells exposed to acetic acid vapor under hygrothermal conditions. In: 2016 IEEE 43rd Photovoltaic Specialists Conference (PVSC), 2016, pp. 1075e1079, https://doi.org/10.1109/PVSC.2016.7749778.

long-term outdoor exposure is also easily identified in a PV cell under an accelerated test. The signature will be available as an index to estimate their degradation level/phase induced in the installed environment [42]. Especially, it is assumed that the parameters specified from AC impedance spectrum are not convoluted with other degradation mechanisms caused by light irradiation on PV cells (e.g., discoloration of encapsulant). Further research is needed to fully correlate module failure in the field to accelerated testing results.

5.3 Thermo-Putative Degradation and Mechanical Failure of Solder Joints

Figure 5.9 IeV curve and AC impedance parameter of a photovoltaic minimodule as function of the damp heat stress duration. From T. Tanahashi, N. Sakamoto, H. Shibata, A. Masuda, Electrical detection of gap formation underneath finger electrodes on c-Si PV cells exposed to acetic acid vapor under hygrothermal conditions. In: 2016 IEEE 43rd Photovoltaic Specialists Conference (PVSC), 2016, pp. 1075e1079, https://doi.org/10.1109/PVSC.2016.7749778.

Solder joint interconnects serve two important purposes: (1) form the electrical connection between the solar cell and copper ribbon and (2) form the mechanical bond that holds the copper ribbon attached to silicon cells. Thermal fatigue of solder joints that attach the module’s stringing ribbon to its solar cells is one typical mechanism of PV modules degradation and ultimate failure. The presence of cracks at the solder joint reduces the area of connection intersection, thus increasing the series resistance. Grain coarsening is also reported as evidence of solder joint thermal fatigue after long-term field exposure [24,43]. The key materials used in the PV module soldering are PbSn, and a solder joint is connecting silicon cell, Ag-based grids, and copper interconnect ribbon. The thermal fatigue problem is

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critical for the solder joints reliability, due to the coefficient of thermal expansion (CTE) mismatch of the joint materials.

5.3.1 Mechanisms Ag leaching into solder and long-term solder joint fatigue are two major mechanisms that cause solder joint failures in c-Si solar cell [44]. Metals such as Ag and Cu are easily dissolved into solder. The dissolution speeds of Ag and Cu, when immersed to PbSn solder, are 10 and 0.09 mm/s at 260
C [45]. At the PnSn solder joint connected on Ag electrode, it was found that Ag dissolved into solder forms Ag3Sn compound with rigid and brittle characteristics [46]. The fatigue crack was observed at the interface of PbSn solder and the region of solder mixing with Ag3Sn after 250 thermal cycles from þ85 to 40
C [47]. The cross-sectional view of the solder joint with a crack observed by optical microscopy after 1000 thermal cycles from þ85 to 40
C is shown in Fig. 5.10 [44]. Ag electrode is used to connect to Cu ribbon interconnection by solder. There are two interfaces, Agesolder interface and Cuesolder interface. The crack shown in Fig. 5.10 occurred between the Ag and solder interface. The compound of Ag3Sn is formed by the dissolution of Ag into solder. The crack at the interface of Ag3Sn and solder is easily created by large thermal expansion difference between the Cu ribbon and Si cell. A SEM image of a crack generated at the rear side of the solar cell inside the PbSn solder is shown in Fig. 5.11 [44]. From the SEM image, the grain size of the PbSn solder sandwiched by Ag electrode and Cu ribbon becomes larger than the solder at the back side

Figure 5.10 The cross-sectional view of Cu ribbon interconnection crack under optical microscope. From U. Itoh, M. Yoshida, H. Tokuhisa, K. Takeuchi, Y. Takemura, Solder joint failure modes in the conventional crystalline si module. Energy Procedia 55 (2014) 464e468.

Figure 5.11 The cross-sectional view of solder bond crack observed by SEM [44].

of the Cu ribbon, which is not sandwiched by the Ag electrode. It clearly shows that the Pb and Sn grains initiate growth during the thermal cycles. The large CTE differences between the Cu and solder joint introduce thermal stress during thermal cycles. The solder joint failure is observed visually as microcracks initially. In the PbSn solder, there are two grains of a-Pb and b-Sn. The grain size grows as the number of thermal cycles increase. The bonding strength decreases with increasing thermal cycles. The crack grows at the interface between the large grains.

5.3.2 Characterization Generally, fatigue modeling consists of four primary steps which provide a basis for an otherwise confusing process [48]. First, a theoretical or constitutive equation is defined as the basis for modeling. Appropriate assumptions need to be made in constructing the constitutive equation. Second, the constitutive equation is translated into a finite element analysis (FEA) program (e.g., COMSOL multiphysics software) [49], and a model is created. The FEA program calculates the predicted stresse strain values for the system under study and returns stress values for the simulated conditions. Third, the FEA results are used to create a model predicting the number of cycles to failure (Nf). Fourth, the model or results must be tested and verified using thermal cycling data. These four steps describe the general process for fatigue modeling.

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In recent research, N. Bosco et al. have developed an FEM of a flat plate c-Si module to calculate the accumulation of inelastic strain energy density within the solder joint for cyclic temperature exposure [50,51]. These works elucidated the effect of different PV module design and materials as well as the climatic conditions on PbSn eutectic solder joint thermal fatigue durability. The thickness of the solder layer itself has the largest influence on its damage accumulation. If the solder layer is half as thick, the damage accumulated would be approximately twice as much [50]. Increasing the thickness of the copper ribbon and silicon would also increase solder joint damage [50]. Three meteorological factors impact the rate of solder fatigue: mean daily maximum cell temperature, mean daily maximum cell temperature change, and number of temperature reversals across a characteristic temperature 56.4
C. In order to accumulate the equivalent amount of 25 years field exposure damage, in the most damaging city (Chennai, India), it would require 630 accelerated thermal cycles (e40 to 85
C) [51].

5.4 Ribbon Fatigue Interconnect ribbon failure is another common failure mode in flat plate PV modules. Interconnect ribbon fatigue leads to power degradation in terms of increase in the series resistance Rs. Ribbon wire for PV modules is wide and flat shape metal wire flashed copper and solder as shown in Fig. 5.12. The width of

Figure 5.12 Image of the copper ribbon wire for photovoltaic modules. From J. Jeong, N. Park, W. Hong, C. Han, Analysis for the degradation mechanism of photovoltaic ribbon wire under thermal cycling. In: Photovoltaic Specialists Conference (PVSC), 2011 37th IEEE, IEEE, 2011, pp. 003159e003161.

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the ribbon is constrained to minimize the shadowing loss in a cell. The increase in the width of interconnection ribbon cross section increases the shadowing losses proportionally [52]. The thickness of ribbon strip is limited by buildup stresses in the solder joint. Cracks originated from ribbon fatigue reduce the cross-sectional area of the wire and increase the Rs of the module.

5.4.1 Mechanisms The driving force of this type of failure is known to be metal fatigue, originated from thermally and mechanically induced strain [12,14]. In a typical buildup of a standard crystalline module, as shown in Fig. 5.1, the copper ribbons are soldered to connect the front Ag electrode of a solar cell and the back-side contact of the next solar cell. Through the lamination process, all the cells are encapsulated with the polymeric layer (EVA) sandwiched by glass cover sheet and polymer backsheet. The CTE of glass is almost two times higher than that of c-Si cells. Therefore, a change in temperature generates stress, which leads to a displacement of solar cells in the flexible layer of EVA and loads the copper ribbon in between. At moderate temperatures (above 20
C), EVA is far above the glass transition point. There has a very low modulus of elasticity influence in the intercell displacement. Due to the higher CTE of glass, the cells are pulled apart when temperature rises. As experimentally showed by Meier et al. [54], the growth of the gap is linear to the temperature increase. During cooling, the opposite effect leads to a shrinkage of the gap. In the low-temperature regime (below 20
C), EVA has a much higher modulus of elasticity. The cells are tensioned by polymer during cooling process. Therefore the thermal expansion of the glass has less impact on the PV cells. Although copper ribbon has a higher CTE than glass, the part of ribbon between the two cells is still tensioned by the cell displacement during temperature change, since only a small part of the ribbon can freely expand, the rest is soldered to the cell. At the gap between cells, ribbon is bent during contraction. This bending leads to regions of increased stress, and plastic strain occurs even at low displacement amplitudes. Hardening effects of the copper distribute the stress to the next surrounding and generate a region of hardened material where microcracks are formed in following thermal cycles. Finally, these microcracks combine into large crack and grow in

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subsequent thermal cycles until the cross section of the ribbon is reduced to a level that is not able to withstand the applied stress and rupture occurs.

5.4.2 Characterization N. Bosco et al. has experimentally demonstrated that in a better designed PV modules (i.e., copper ribbons soldered to solar cells with some offset) ribbons experience less strain than designed modules (i.e., ribbons soldered to the edge of the cells) [14]. In a more robust design, the ribbon was soldered 10 mm away from the cell edge on the front side and 15 mm away from the cell edge on the back side (Fig. 5.13). Compared to the design that soldered the ribbon right at the edge, the effective gauge length of the interconnect ribbons soldered with offsite is 25 mm longer; therefore, they experience proportionally less strain for a similar amount of cellecell deflection. The experimental result showed that with the ribbons soldered without an offset significant failures occurred roughly 40% faster than the ribbons soldered with an offset.

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5.5 Electrically Conductive Adhesives in Novel Cell Interconnection Strategies Advances in PV module technology have always been pursued in research and development, but many times these new approaches do not thrive in the market because of the challenges of lab-based qualification and real-world lifetime performance [55]. Two cell technology approaches, which both aimed to replace ribbon-based cell interconnection, are back-contact cells such as metal or emitter wrapthrough (WT) and more recently shingled full or sliced (half or “sliver”) cells [56]. Both of these approaches have the goal of incorporating a new material class, ECAs, into PV modules [57]. ECAs offer the promise of reduced module assembly costs, which is an ongoing industry goal, but bringing new technologies to commercial scale with demonstrated reliability is a large challenge. Efforts from 2000 to 2010 focused on commercializing WT cells in PV modules were unsuccessful, due to cost and reliability issues [58]. The current focus on shingled cells appears to be progressing well into commercial production.

5.5.1 Wrap-Through Cells and Their Interconnection

Figure 5.13 Illustration of the solder point at interconnect ribbon on each cell with and without an offset. From N. Bosco, T.J. Silverman, J. Wohlgemuth, S. Kurtz, M. Inoue, K. Sakurai, et al., Evaluation of dynamic mechanical loading as an accelerated test method for ribbon fatigue. In: Photovoltaic Specialists Conference (PVSC), 2013 IEEE 39th, IEEE, 2013, pp. 3173e3178.

Back-contact cells remove the need for front-side cell metallization and their associated busbars but introduce more complexity in having to accommodate the front and backside interconnections on the cell backside [59]. The fabrication and manufacturing advantages were considered positively in the early 2000s, with the idea that pick and place automated assembly methods used in the consumer electronics industry would simplify module manufacturing [58,60]. This approach relies on a polymeric cell “carrier sheet” with printed or electroplated metallization, analogous to a printed wiring or circuit board. The cells are then placed onto ECA droplets on the wiring spots and allowed to cure. There is a distinct set of challenges in shifting the industry from metallic solder-based cell connection and replacing it with polymeric adhesive cell connections, for example, the qualification and

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reliability standards are all focused on the metallic solder failure mechanisms, and the current test conditions are be wholly inappropriate for an ECA [61]. In addition, such dramatic changes in not only materials but also interconnect geometries can lead to undesirable changes from familiar electrical characteristics [62]. These back-contact cell technologies appear to have been broadly rejected by high-volume manufacturers at this time, possibly due to high costs and the qualification and reliability issues that arise.

5.5.2 Shingled Cells and Subcells Interconnected With ECAs More recently, shingling of cells in the PV cells is being pursued as a new technology option for manufacturers [63]. This follows the industry-wide shift from Al-BSF cells to PERC cells, in which both of these cells utilize the same front- and back-side metallization as has been commercial for 30 years (refer Chapter 4). Shingling provides advantages of increasing voltages, decreasing current, and the associated I2R losses in a module. Shingling is also compatible with bifacial cells [64], such as the bifacial PERC cells that have recently been commercialized [65,66]. And in these shingled cell modules, ECAs play an important role in enabling a new interconnection architecture [67].

5.5.3 Performance of PV Modules Utilizing ECAs The performance of PV modules using ECAs has been successful enough to motivate ongoing research and development, for example, during the period of research focusing on the back-contact cell approaches [68]. And in the case of shingled cells, initial results for performance and reliability have been positive and motivated increased research efforts [69].

5.5.4 Qualification and Reliability of ECA Materials and PV Modules With the positive performance of shingled cell modules using ECAs, there critical issues of reliability and lifetime performance have become the focus of research. For example, the necessary material properties of ECAs for shingled cell PV modules

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are critical as are electrical and mechanical criteria [70]. At the same time, qualification tests for PV module ECAs do not exist. There is still much work necessary on developing the database of ECA materials testing results to define the necessary qualification tests, guide materials selection, inform manufacturing processes [71]. It is advantageous that many materials systems, such as silicones, have a long and broad history of use, and that ECAs were studied for the back-contact cells in the early 2000s. This historic information rapidly informs the current ECAs for shingled cell modules [57]. In addition, it is essential to develop models and methods to optimize ECA selection and development for shingle cell modules, and this work is proceeding apace [72]. And the PV research community is now starting to establish the foundation of reported ECA failures in module tests, identify both root causes, and characterization methods to address these [73]. For example, electrical studies inform back-contact cells current studies [74]. And similarly, mechanical tests and failures can help inform the PV community [75,76]. Novel interconnect approaches, such as ECAs for shingled cell PV modules, look today to be promising and are actively being researched, but their true role in our terawatt PV power system has yet to be established.

5.6 Conclusions This chapter reviewed the major degradation and failures of interconnections in silicon PV modules, which include solder joint thermomechanical fatigue and interconnect ribbon fatigue. Ag leaching into solder and long-term thermal fatigue are identified as two major causes of solder failures. Fatigue of metal, induced by mechanical loads on ribbon wire due to thermal cycles, leads to interconnect ribbon failures. In addition, the recent interest in novel interconnect strategies, such as the use of ECAs to replace the tinned copper ribbons, opens up large new areas of both module cost and performance. These ECAs represent a new manifold of degradation mechanisms for these new interconnection materials and new module architectures, for which we do not have sufficient field or lab experience to make predictions of 30 year lifetime performance.

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Acknowledgments The authors acknowledge the SETO Office, our academic and industrial collaborators, and all the students.

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