Deliverable 5.2. Lifetime Degradation Mechanisms. Thomas Friesen SUPSI. 16/03/2015 Version Final Checked by Johannes Stöckl (AIT)

Transcription

1 WP5 Deliverable 5.2 Lifetime Degradation Mechanisms Thomas Friesen SUPSI 16/03/2015 Version Final Checked by Johannes Stöckl (AIT) This project has received funding from the European Union s Seventh Programme for research, technological development and demonstration under grant agreement No

2 CONTENTS LIFETIME DEGRADATION MECHANISMS Procedures and Tools for Laboratory and Field Testing D5.2 SUMMARY INTRODUCTION: MOTIVATION AND OBJECTIVE OF D PV MODULE MODEL AND PARAMETERS FOR THE DEGRADATION MECHANISM PV MODULE SIMULATION APPROACH AND REQUIREMENTS WITHIN THE PRPROJECT ONE DIODE STANDARD MODEL FOR PV MODULE DETERMINATION OF DEGRADATION FACTORS INFLUENCING ELECTRICAL MODULE PARAMETERS INDOOR TEST PROCEDURES FOR DEGRADATION MECHANISM TESTS IN ACCORDANCE TO IEC STANDARDS DEVELOPMENT OF NEW INDOOR TESTS CORRELATION BETWEEN INDOOR AND OUTDOOR DEGRADATION EFFECTS - EXTRACTION OF PARAMETERS FOR SIMULATION ENVIRONMENTAL CONDITIONS AND DEGRADATION MECHANISMS DEGRADATION PARAMETERS AND VALUES FOR THE SIMULATION CONSEQUENCES OF THE DEGRADATION DISTRIBUTION OF SAME MODULE TYPES ON THE POWER DEGRADATION CASE STUDIES TISO 10 KW PV SYSTEM EXPERIENCE AT THE SWISS PV MODULE TEST CENTRE (SPVMTC) PV MODULES FROM OTHER INSTALLATION SITES CONCLUSIONS REFERENCES Page 2 of 39

3 Summary. This work analyses the degradation mechanisms and modes given by the one diode model for a PV module. The aim is to determine the parameters necessary for simulation tool, developed in the previous work packages and to determine the possible time dependence for each degradation mode. Furthermore, as far as possible some values for the single degradation rates are given. Chapter one and two discusses in general the definition of reliability of PV modules and explains the one diode model. Afterwards, the parameters used in the one diode model are analysed with respect to their degradation behaviour and some functions for the lifetime are proposed. Chapter 3 gives indication about the indoor testing possibilities and chapter 4 discuss the correlation between the climatic conditions at the installation site and their impacts on the degradation rate. In the last section different case studies are discussed. Page 3 of 39

4 1. INTRODUCTION: MOTIVATION AND OBJECTIVE OF D5.2 PV modules are energy-producing components and therefore the base of the PV system. The modules should work over the whole lifetime, today stated for at least 25 years, without any replacement. Therefore, reliable PV modules are a key issue of profitable PV systems. Profitable PV systems should have low maintenance costs, high energy production, low power degradation effects and low failures rates. These factors lead to a low Levelized Cost of Energy (LCoE) [1], defined as = where Inv is the initial investment for the system, M n the annual maintenance cost, E n the energy production in the year n and N are the years of operation. This deliverable focuses on the lifetime degradation mechanisms influencing the yearly energy production E n. We analyze the different degradation mechanisms and define them within the possibilities of the current state of knowledge qualitative and quantitative for simulation methods. As shown in Figure 1 the degradation parameters should be included in the modelling of the PV module. The irradiation model determine the energy production of the PV system, the climatic conditions as humidity and temperatures influence the degradation behavior of the PV modules and consequently of the PV system. (1) FIGURE 1: INTEGRATION OF THE DEGRADATION PARAMETERS OF THE PV MODULES IN THE MODELLING FLOW For general understanding, some important terms related to the lifetime of a PV module are explained first. The reliability of a component is defined in literature [PAS2011] as: If a component operates as required for a required period without failure, it has met an acceptable target of reliability. In the case of a PV module it means that if the output power of the module is higher than a predefined value, in general the guaranteed value, then the module is considered to work properly. If the power produced by the module is lower, then the module is considered to have failed. The durability of a component is usually the minimum time before the occurrence of wear out failures [PAS2011]. For a PV module it means the time when the guaranteed power value is reached, today usually stated as 80% after 25 years of operation. So the lifetime of a PV module is determined by both, his reliability and his durability. Some further important definitions are: Page 4 of 39

5 A defect is defined as an irregularity that spoils the appearance of an object causing weakness or failure such as a bubble in the encapsulation of the cells. This defect will not necessarily cause into a failure of the module, but could decrease the output power. A failure is defined as the cessation of normal or expected operation of a component. For a PV module failures can be divided into two categories: catastrophic failures caused by a sudden and total failure for example glass breakage or a short circuit and failures of the PV module due to the degradation. The degradation of initial values or characteristics is a gradual process over a long period of time caused by environmental conditions and material properties. The failure mechanism is a physical, chemical, or other process that may lead to failures (IEC ) and the failure or degradation mode by which the item is observed to fail. A typical example is the yellowing of the encapsulant. The degradation process of a PV module could be a not reversible process such as yellowing of EVA or a reversible process such as soiling or dust. In the past years even degradation effects on particular types of PV modules such as the polarization induced degradation (PID) can be classified as reversible [sunpower]. Further failures can be intrinsic failures, related to the design or the manufacturing process of the PV module. Extrinsic failures are described as being related to the application and handling of the component during the operation. Other exceptional ambient conditions which can cause a fast degradation of the power output of the PV module are the corrosion from ammonia in farms or salt corrosion near the sea. To test the resistance of the PV modules to these special ambient stresses two relevant IEC qualifications standards can be consulted: the IEC61701 for salt mist corrosion and IEC for ammonia corrosion resistance. FIGURE 2: FAILURE MECHANISM AND MODES FOR PV MODULES The degradation behavior, i.e. the reliability and durability, of a PV module in the field starts with the product design and the production process. In this phase, where all the raw materials, components, assembly and production technology are decided, the condition of future degradation of the module in the PV system is defined. The IEC standard IEC gives guidelines for the design and material selection. The testing procedures for the qualification are defined in IEC61215and IEC61646 for c-si and thin film modules respectively and the IEC The product qualification and certification in accordance to the IEC standards reduce the infant mortality shown in Figure 3. Page 5 of 39

6 After the development phase, the module must be fabricated and installed in the PV system. The following four lifetime steps will influence the degradation of a PV module installed in the system: I. Production process and quality control II. Shipment of the module to the PV systems installation site III. Installation of the PV module in the system IV. Operational conditions: climatic conditions as temperature, humidity and irradiation, climatic stresses FIGURE 3: THE WELL KNOW BATH TUB CURVE COMPOSED OF THE FIRST PART OF INFANT MORTALITY, A SECOND PHASE OF CONSTANT FAILURE RATES AND THE THIRD PART OF THE WEAR OUT OF THE PV MODULES. In the procedure defines a variety of terms in relation to quality and reliability and the lifetime steps of a module. This work will focus mainly on the intrinsic degradation of the PV module causing the wear out phase of the module life as shown in figure 2. These effects are predictable and therefore could be introduced in a simulation model. Steps II and III shipment and installation of the PV modules causes mainly failures from external influences and are not predictable in a model. Each PV installation is an individual case because the module type, system configuration, shipment and installation conditions and atmospheric condition are unique. The degradation of the PV system can be predicted only for some of these influences, in particular for the climatic conditions. However, this work gives some indication how this parameters could be integrated in the model. Page 6 of 39

7 2. PV MODULE MODE DEGRADATION MECHANISM 2.1. PV MODULE SIMUL EL AND PARAMETERS FOR THE LATION APPROACH AND REQUIREMENTS WITHIN THE PRPROJECT The goal of the Performancee Plus project is the development of tools for the PV system performance prediction as defined in D2.3. Therefore the modelling of the yearly energy production E n is an important component of the simulation. In equation (1) of the LCoE the yearly energy production E n in dependence of the number of years n can be expressed more in detail as follows = 1 (2) where E 0 is the initial energy production and D n (n) the annual degradation rate of the PV system. As we will see, the total annual degradation rate D n is a composition of different degradation rates caused by single degradation modes. D n usually varies during the operational time and therefore is itself a function of years. Figure 4 shows an example of the PV module power degradation composed from several single degradation mechanisms. FIGURE 4: EXAMPLE OF DEGRADATION OF A PV MODULE COMPOSED OF MANY POSSIBLE DEGRADATION MECHANISM. [TASK132014] The main interest of the PV system owner is the economical return of the PV system. Consequently the knowledge of the electrical performance of the PV system over his expected lifetime and the expected degradation losses are fundamental for the economic forecast. The starting point to determine the PV system degradation rate is the degradation behavior of the single PV module and statistical distribution of the module characteristics as shown in Figure 5. From this information s the string behavior over time can be modeled and in a second step the PV system performance can be predicted. Page 7 of 39

8 FIGURE 5: SCHEMATIC FLOW OF THE YEARLY PERFORMANCE PREDICTION STARTING FROM THE DEGRADATION PARAMETERS AND STATISTICAL DISTRIBUTION OF THE SINGLE PV MODULES In Deliverable 1.2 and Deliverable 2.3 of the project the one diode model is used for the simulation of the PV module and systems. Therefore the same approach is used in this deliverable ONE DIODE STANDARD MODEL FOR PV MODULE To describe the operation of a PV module the well-known one diode model based on the equivalent circuit showed in shown in Figure 6 is used [WEN2009]. The model describes a single cell, but can be extended to the whole module if the cells are considered identical. For the purpose of this work we can assume this simplification. FIGURE 6: ONE DIODE MODEL OF THE PV MODULE WITH THE DIODE CURRENT I D, THE PHOTOCURRENT I PH, THE SERIES RESISTANCE R S AND THE SHUNT RESISTANCEE R SH. Equation (3) describe the current I and voltage V curve of the PV module with the one diode standard model =!"#$ % & ' ( ) * + 1, & ' ( ' (- (3) With the diode factor N and the Boltzmann constant K. R s is the seriess and R sh the shunt resistance of the module, I ph the photo and I d the diode current. The maximum power P max is the key parameter used for the electrical characterization of the PV module, other important parameters are the short circuit current I sc, the open circuit voltage V oc and the fill factor FF. P max is calculated with. /01 = (4) Page 8 of 39

9 I sc is the short circuit current, means the current at V = 0. For an ideal module with low resistivity losses, the short-circuit current and the light-generated current I ph are identical. The open-circuit voltage V oc of the PV module is the sum of the open circuit voltage of the single cells in series. The V oc of the cell corresponds to the amount of forward bias due to the bias of the solar cell junction with the light-generated current. FIGURE 7: IV CURVES OF A PV MODULES WITH PARASITIC RESISTANCE DEGRADATION. THE SLOPE CHANGES WITH THE DEGRADATION OF THE SERIES AND SHUNT RESISTANCE The fill factor FF given by the empirical equation 22 = & 67 89& :; <.>? & (5) is the relation between the ideal maximum power defined by I sc x V oc and the real maximum power P max defined by Pmax = I MP x V MP The parasitic resistance R s and R sh are of equal importance as current and voltage for the electrical characterization of the PV module [DYK2004]. The series resistance R s of a PV module is the sum of the single ohmic resistances in the electrical circuit as cell solder bonds, emitter and base regions, cell metallization, cell-interconnect busbars and resistances in junction-box terminations. The series resistance R s is the inverse of the slope of the IV curve at the open circuit point, as shown in Figure 7. The shunt resistance R sh represents any parallel high-conductivity paths (shunts) through the solar cell or on the cell edges and recombination s in the semiconductor material. These would be due to crystal damage and impurities in and near the junction, and give rise to the shunt current. These shunt paths lead currents away from the intended load and their effects are detrimental to the module performance. The shunt resistance R sh is the inverse of the slope of the IV curve at the short circuit point, as shown in Figure 7. Page 9 of 39

10 2.3. DETERMINATION OF DEGRADATION FACTORS INFLUENCING ELECTRICAL MODULE PARAMETERS This section presented the parameters of the one diode model which determine the power output of the PV module. We assume that the diode current I D in equation (1) has no degradation and is stable with time. So the standard model suggests that the main factors which contribute to the power output degradation of a PV module are: I ph for the current, V oc the open circuit voltage and the two internal resistance R s and R sh. All four parameters have an impact on the fill factor and the maximum power output of the PV module and consequently on the energy production DEGRADATION OF THE SHORT-CIRCUIT CURRENT ISC The photo current I ph is generated by the photons arrived in the p-n junction of the cell and as shown in cap. 2.2 equal to the short circuit current I sc at V=0. Figure 8 shows possible losses of the photons to their way to the p-n junction reducing the generated current and there are discussed more in detail. The degradation modes with possible equations and trends are summarized in table 1. FIGURE 8: DEGRADATION OR FAILURES MODES REDUCING THE PHOTOCURRENT IPH. ARG: ANTI REFLECTION COATING OF THE GLASS. ARC: ANTI REFLECTION COATING OF THE CELL a. Front glass corrosion One effect which could reduce the incidence light to the PV cell is the glass corrosion. This effect was reported in the past when Cerium was added to the glass to reduce the UV transmittance. Voltage induced glass corrosion was also reported in [FERR2012]. The loss of generated current I ph is linear to the transmittance loss of the front glass and could have a lower limit value I lim. In this case after N years of operation the degradation stops and the annual degradation factor DG GC becomes 0. A general expression is: = /01 B CD (6) With = /01 9E/ with I lim the limit current value, which becomes 0 if there is no limit and D GC is 0 if n > N. b. Degradation of antireflective coating of the front glass Page 10 of 39

11 The antireflective (AR) coating of the front glass, used in most PV modules, can gain 4 to 6% of light transmittance over different incidence angles. The degradation of the AR coating caused by delamination or corrosion of the AR coating can reduce the light reaching the p-n junction and therefore the generated photocurrent I ph. The losses should be linear with the degradation and the area of the module affected from corrosion or delamination. The maximum possible loss in this case is equal to the gain of 4 to 6%. A general expression is: = /01 B F' (7) With = /01 9E/ with I lim the limit current value, which becomes 0 if there is no limit and DG AR is 0 if n > N. c. Degradation of the antireflective coating on the cell The reflectivity for the incidence light of bare silicon is about 35%. These reflection losses can be reduced by texturing the surface, reducing the reflectivity or by adding an anti-reflective (AR) coating on the cell. The single treatments reduce the reflectivity to 10%, the combination as state of the art PV cells reduce the reflectivity of a PV cell to 3%. Texturing of the cell is not influenced by degradation effects, but the AR coatings can suffer degradation. The degradation of the AR coating may be attributed to interdiffusion of species from the cell s emitter region to the AR coating and vice versa. The effect of the degradation of the AR coating of a cell reduce the incoming light and hence produce less current. Degradation of AR coatings is observed as a brightening in the color of the cell. The maximum possible loss in this case is equal to the gain of 10% and the losses should be linear to the degradation level. A general expression is: = /01 F' (8) With = /01 9E/ with I lim the limit current value and DC AR is 0 if n > N. d. Yellowing and browning of the encapsulant Yellowing usually consists of a degradation of the encapsulation material or the adhesive material between the glass and the cells caused by UV exposure and humidity at temperature above 50 C [ORES2009]. The color change from white to yellow in the material and sometimes from yellow to brown causes a change in the transmittance of the light reaching the solar cells and thus a decrease in the generated photo current. The brown encapsulant absorbs a significant fraction of sunlight in the UV and visible region thereby reducing the photon availability required for current generation. Until today there is no clear relation between the color change of the encapsulant and the entity of electrical performance losses. Some possible correlation reported are: - Yellowing of encapsulant with a limit value and slight power loss = /01 G 1 " 8( HIJ ) )K (9) Page 11 of 39

12 - Browning with continuous power loss up to 50% ()= /01 (1 L ) (10) The power loss of a PV module is determine on one side by the transmittance loss and on the other side from the area of the module affected from the degradation. e. Delamination of the encapsulant Delamination is the loss of adherence between the different layers of the PV module. If the incoming light finds a delaminated area on his way to the PV cell transmittance losses can increase due to the optical decoupling. The power loss should be proportional to the delimited area of the PV module and have a limit. ()= /01 M (11) With = /01 9 and I l = 0 if no limit and D DEL = 0 for n > N TABLE 1: SUMMARY OF THE PHOTO CURRENT LOSSES CAUSES BY DIFFERENT DEGRADATION MODES Degradation effect Equation Power degradation ()= /01 CD A Glass DG GC corrosion With = /01 9E/ and I l = 0 if no limit and DG GC = 0 for n > N B DG AR Degradation of the AR coating of the glass with limit value ()= /01 B F' With = /01 9E/ and DG GC = 0 for n > N C DC AR Degradation of the AR coating of the cell with limit value ()= /01 F' With = /01 9E/ and DC AR = 0 for n > N Page 12 of 39

13 D E D DIS Constant discoloration of encapsulant D DIS Discoloration with a limit value ()= /01 (1 L ) ()= /01 G (1 " 8(HIJ ) )K with = /01 < D DEL Constant ()= /01 M F delamination increase with limit value With = /01 9 and I l = 0 if no limit and D DEL = 0 for n > N The total degradation of the photo current generated in the pn junction is given by the sum of the single contribution I ph i listed in table 2. ) ()= EN E () (12) Figure 9 shows a possible degradation behavior of the photocurrent I ph over the PV module lifetime. The red curve shows a module with overlapping degradation modes and the green curve is a module with one degradation mode. FIGURE 9: EXAMPLES OF POSSIBLE I PH DEGRADATION OVER THE PV MODULE LIFETIME. IN THE FIRST PART THE MODULE IS AFFECTED FROM ALL DEGRADATION MODES, THEN THE GLASS CORROSION STOPS AND LATER THE AR COATING OF THE CELLS (RED). THE GREEN CURVE REPRESENT A MODULE WITH DEGRADATION DUE TO DISCOLORATION DEGRADATION OF THE OPEN CIRCUIT VOLTAGE VOC The V oc degradation of a PV module is caused by broken interconnects, broken cells and solder bond which increase the series resistance. For the degradation of open circuit voltage V oc Page 13 of 39

14 5 4 ()=5 < (1 4 ) (13) With the degradation D oc rate of the open voltage. Most publications report a low or no degradation of the open voltage, mostly less than 10% of the open circuit voltage V oc [JORD2011, FRIE2012, SAMP2009] DEGRADATION OF THE SERIES RESISTANCE RS The series resistance R s of the c-si PV module is composed from the single resistance of the PV cells and their interconnections in the module as shown in Figure 10. Further the series resistance of the assembled PV module will increase due to soldering of the bus bar and installing junction boxes. The series resistance in the cell is given by the p-n region of the diode and can be seen as an electronic component. The p-n diode, in particular of crystalline silicon, should not degrade. The contributions of the interconnections to the series resistance can increase due to corrosion or oxidation of the cell metallization, interconnections and bus bars. The degradation of the series resistance could be caused by cracked or broken interconnects and weak solder bonds which increase the series resistance. FIGURE 10: SOURCES FOR THE SERIES RESITANCE IN A PV MODULE (LEFT). LINEAR INCREASE OF THE SERIES RESISTANCE DUE TO DEGRADATION (RIGHT) The degradation in the field is caused by oxidation or corrosion effects or by mechanical stresses which can cause weakening of the electrical connections. We assume that the series resistance increase linear with a degradation rate D RS with n in years O 3 ()=O 3< (1+ '3 ) (14) R S0 initial series resistance in Ω at n = 0 D Rs degradation rate of the series resistance R s DEGRADATION OF THE SHUNT RESISTANCE RSH The shunt resistance R sh represents any parallel high-conductivity paths (shunts) through the solar cell or on the cell edges as shown in Figure 11. These would be due to crystal damage and impurities in and near the junction, and give rise to the shunt Page 14 of 39

15 current. These shunt paths lead currents away from the intended load and their effects are detrimental to the module performance especially at low irradiance levels. FIGURE 11: SOURCES OF THE SHUNT RESITANCE IN A PV MODULE (LEFT). DECREASE OF THE SHUNT RESITANCE DUE TO DEGRADATION (RIGHT) O 3 ()=O 3< (1 " ( JQ ) ) (15) R sh0 shunt resistance at n = 0 D sh n degradation rate of the shunt resistance time in years 2.4 TEMPERATURE DEPENDENCE OF THE DEGRADATION RATES The temperature of the PV module is important acceleration factor for chemical reaction and the diffusion of the water vapor and oxygen in the polymeric materials. The acceleration factor A of the chemical reactions with increasing temperature T can be expressed with the Arrhenius equation: R ~ " 8T U V (16) where E a is the activation energy of the chemical reaction. Therefore the degradation rates should have temperature dependence and should be considered in the simulation. A higher operational temperature of the module causes a general increase of the degradation rates. Page 15 of 39

16 3. INDOOR TEST PROCEDURES FOR DEGRADATION MECHANISM This section describe first the standard tests in accordance to IEC (International Electrotechnical Commission) which can give evidence about the degradation mechanism of a PV module and second some new testing procedures which are under development in IEC working groups TESTS IN ACCORDANCE TO IEC STANDARDS The most relevant testing procedures for PV modules are described in: IEC terrestrial c-si PV modules design qualification and type approval IEC terrestrial thin film PV modules design qualification and type approval The IEC qualification and test procedures were developed for the type approval of PV modules to ensure a safe operation over a long time, stated in 25 years and not for the forecast of the performance during their lifetime. The IEC and IEC standards focus on the design qualification and for this purpose climatic and mechanical testing are requested, which could give some indication about the degradation behavior of PV modules under test CLIMATIC TESTING The IEC and IEC standards define three climatic tests as shown in Figure 12to simulate the environmental influence on a PV module: The damp heat test 1000 hours at 85 C and RH 85% The humidity freeze test 10 cycles of 20 h 85 C/85% RH and 4 h -40 C The thermal cycling test 200 cycles of 6 h from -40 C to 85 C without RH control (a) (b) (c) FIGURE 12: (A) DAMP HEAT TEST. (B) THERMAL CYCLING. (C) HUMIDITY FREEZE CYLCE Each climatic test points to specific failures and degradation mechanism and are discussed in the following. a) During the damp heat test the PV module is exposed for hours to a high humidity at high temperatures, so the water vapor can penetrate deeply in the PV module. The penetration speed and depth depends from the module design, e.g. if glass/glass or glass/backsheet design and from the materials used in the module, e.g. EVA, PVB, edge sealant. Some research groups developed models to calculate the diffusion of water vapor into the model for different modules designs [KOEH2010]. Page 16 of 39

17 The humidity increase in the module influences the module performance as follows: Decrease of the shunt resistance of the PV module due to change of the internal resistivity of the lamination material Increase of the seriess resistance due to corrosion effects Optical degradation of the lamination due to transparence lossess Delamination of encapsulation material In Figure 13 (a) the degradation of the power over the exposure modules types is shown. (a) (b) time of different FIGURE 13: (A) POWER DEGRADATION OF DIFFERENT MODULE TYPES IN FUNCTION OF THE EXPOSURE TIME IN THE DAMP HEAT TEST [HERR2011]. (B) ELECTROLUMINESCENCE IMAGES OF A MODULE AFTER 1000 H, 2000 H, 3000 H OF DAMP HEAT (FROM LEFT TO RIGHT) AT 85 C/85%RH, FEATURING -1%,-4%, AND -28% DEGRADATION OF OUTPUT POWER, RESPECTIVELY [HERR2011]. Figure 13 indicates an important fact: all IEC certified modules are stable within the 5% power degradation limit after 1000 hours of damp heat test as requested by the IEC standard. To give an indication about the degradation value and to distinguish different module designs extended tests up to 3000 or 4000 hours are necessary. In addition the measurement intervals should be shorter than the standard 1000 hours for a better determination of the degradation behavior. As a result of extreme temperatures changes during the thermal cycling test, the electrical connections in the PV module are particularly stressed. Many publications about the electrical degradations exist and some models are available [PARK 2014]. Thermal stresses can weaken the electrical connections and soldering s in the module and therefore increases the contact resistivity s. The serial resistance R s increase and consequently the maximum power of the module decrease. Page 17 of 39

18 FIGURE 14: P MAX LOSSES IN FUNCTION OF THE NUMBER OF TEST CYCLES AND TEMPERATURE DIFFERENCES. THE DEGRADATION OF THE P MAX IS LINEAR WITH THE CYCLE NUMBER. [PARK 2014] c) The humidity freeze testt is a combination of the thermal and humidity stress. The total humidity stress at 85% RH last 200 hours instead of 1000 hours in the damp heat test and stresses due to the temperature changes are also much less, 10 instead of 200 cycles. The combination of thermal and humidity stress in the humidity freeze test point out some design problems. The condensed water on the PV module surface could cause mechanically damages in the assembly during the freezing phase. The weak performance of a module regarding humidity penetration or electrical connections emerge generally in the damp heat test or the thermal cycling test due to the longer stress time. The IEC climatic tests have pass/fail criteria after a defined exposure time and therefore they do not determine the tendency of degradation. Figure 15 points out that a module can pass the test at the defined exposure time, but could have a lower performance in the wear out phase then a module which failed after the standard test time (green curve and red curve in Figure 15). FIGURE 15: THE GRAFIC SHOW THE POINT OF PASS/FAIL CRITERIA FOR THE DAMP HEAT (DH), THERMAL CYCLING (TC200) AND THE HUMIDITY FREEZE TEST (HF 10). THESE POINTS GIVE NO INFORMATION ABOUT THE POWER DEGRADATION IN THE WEAR OUT PHASE. The IEC standard test procedures as damp heat and thermal cycling could give some evidence about the degradations mechanism and magnitude of the degradation rate of a specific PV module. The degradation in the damp heat test reveals degradation behavior Page 18 of 39

19 by humidity penetration and should influence mainly the R sh. The thermal cycling reveals problems with the electrical connections of the module and gives indication about the series resistance R s. To improve the information about the degradation rate the test time should be increase up to failure of the module and the measurement intervals shortened. Also a statistic over more modules of the same type should be helpful for the characterization of the degradation. The IEC standard requires only two samples for each climatic test, which are not necessary representative for the whole module production MECHANICAL TESTING The aim of the mechanical load test in accordance to the IEC is to investigate the ability of the PV module to withstand static snow and wind loads. The IEC qualification requires also the hail resistance test. These tests simulate climatic influence which can cause catastrophic failures, but have minor or no contribution to the intrinsic power degradation of the PV module. The specific requirements for the PV modules in special climatic areas as high snow loads, e.g. over the IEC limits of 2400 Pa, or installation sides with high hail storm frequency, should be considered in the phase of PV module selection DEVELOPMENT OF NEW INDOOR TESTS POTENTIAL INDUCED DEGRADATION TEST In the last years the potential induced degradation (PID) appears on field modules and some PV systems show degradation of more than 30% during the first years of operation. A big research effort was done to understand the PID effect and many publications on this argument were published [KOCH2013, NAUM2012, HOFF2014]. The causes of PID are first the electrical layout of the PV system, secondly specific climatic conditions and third the design and material of the PV module. The electrical layout in particular the grounding of the PV system can be solved by optimizing the system configuration, in particular the grounding. The second and third causes of PID are influenced by the climatic conditions and therefore important factors for the module degradation. To determine whether a PV module design and the used material combination is PID sensitive, the technical specification IEC TS is in preparation. The test procedure consists in exposing the module under positive and negative system voltage usually 1000 V to a relative humidity of 85% at a temperature of 60 C for 96 hours. The power degradation of the module is measured after the test and the module degradation is made visible with the EL photography. The PID is correlated mainly to the shunt resistance R sh degradation[task ], but also to series resistance degradation and therefore with the loss of performance over the lifetime. Today the correlation between the degradation in the field and the indoor PID degradation is not clear and subject of further investigations. Page 19 of 39

20 (a) (b) FIGURE 16: ELECTROLUMINESCENT PHOTOGRAPHY OF PV MODULES BEFORE AND AFTER PID TEST IN ACCORDANCE TO THE IEC DRAFT (LEFT). IV CURVE AFTER PID TEST FROM THE PV MODULE SHOWN LEFT. THE PMAX IS REDUCED BY 50% (RIGHT) DYNAMICAL LOAD TESTING The dynamical load test defined in the draft IEC provides a method to determine how well a PV module performs under dynamical load stresses as wind solicitation. The draft standard specifies that the module mounted as described from the manufacturer is submitted to 1000 cycles with a cycle s time of 20 to 60 sec and a force of ± 1000 Pa. The test should give indication about the performance losses caused by interconnection and bonding defects as well to the sensitivity to cell cracking. The performances losses are particular measurable if thermal cycling tests are performed after the dynamical load test as shown in Figure 17 [TANA2013]. Page 20 of 39

21 (a) (b) (c) FIGURE 17: (A) INITIAL ELECTROLUMINESCENT PHOTOGRAPHY. (B) ELECTROLUMINESCENT PHOTOGRAPHY AFTER DYNAMICAL LOAD TEST (DML 1000 CYCLES) AND 200 THERMAL CYCLES (TC;-40 C / 85 C). (C) PERFORMANCE VALUES AFTER DML AND DML + TC [TANA2013] Page 21 of 39

22 4. CORRELATION BETWEEN INDOOR AND OUTDOOR DEGRADATION EFFECTS - EXTRACTION OF PARAMETERS FOR SIMULATION The aim of this work is the determination of degradation parameters for a simulation tool useful to predict the energy production over the whole lifetime of the PV module. The local environmental operation conditions of the PV systems as humidity, temperatures, irradiation and others important factors are known. These values can be taken from meteorological databanks. Their influence on the degradation effects are discussed in part 4.1. The second necessary parameters set for the simulation are the values for the degradation parameters discussed in chapter 3. These parameters are the most difficult to determine and an approach is discussed in part 4.2. The third part of this chapter treats the statistical aspects of the power distribution of one module type out of production and the consequences on the power degradation during the lifetime. FIGURE 18: FLOW DIAGRAM FOR THE DETERMINATION OF DEGRADATION PARAMETERS AND VALUES 4.1. ENVIRONMENTAL CONDITIONS AND DEGRADATION MECHANISMS Table 2 gives an overview of the degradation mechanism of the installed PV module caused by the environmental conditions. For the forecast of the energy production not only the macroscopic climatic conditions as humidity, ambient temperature and irradiation should be considered, but the microscopic conditions as humidity on the module surface and thermal stresses are of equal importance as shown in Figure 19 [KOEH2011]. Page 22 of 39

23 FIGURE 19: MICROCLIMATIC CONDITIONS ON THE PV MODULE (LEFT) THE MODULE TEMPERATURE IS HIGHER THAN AMBIENT TEMPERATURE AND (RIGHT) SHOWS THAT THE HUMIDITY ON THE MODULE SURFACE IS LOWER THAN THE AMBIENT HUMIDITY DUE TO DRYING DURIBG THE DAY The microscopic conditions on the module are determined by his installation conditions and obviously the macroscopic climatic conditions. For example an integrated PV system works at higher temperatures than an open rack module, but is less exposed to humidity. TABLE 2: DEGRADATION MECHANISM IN THE FIELD AND CORRELATION TO THE DEGRADATION MODES AND DEGRADATION OF THE ONE DIODE PV MODEL PARAMETERS Degradation mechanism Degradation mode Humidity Delamination Corrosion PID X X AR corrosion X X Bubbles X Irradiation Yellowing X Module temperature changes Snow Wind Mechanical stresses Mechanical stresses Mechanical stresses Degradation parameter R sh R s I sc V oc Breakage X X X X X X X X X HUMIDITY The humidity on the module surface diffuses in the module and will change some module properties, as shown in Figure 20: The shunt resistance decrease due to the moister content in the encapsulation material The humidity in the module can cause some delamination with the consequence of I sc reduction The humidity in the module can cause the corrosion of the bus bars, electrical connections and grids with consequent increase of the series resistance R s Page 23 of 39

24 Humidity can cause the corrosion of the AR coating on the PV cell and therefore a reduction of the I sc (a) (b) (c) FIGURE 20: (A) BUS BAR CORROSION. (B) DELAMINATION. (C) AR CORROSION IRRADIATION The solar irradiation, in particular the UV A and UV B component, can induce the change of color of the encapsulation material. The changes can be from light yellow with little influence on the light transmittance to dark brown with very high losses up to 30 50%. The EVA and PVB yellowing in the field are affected by: Formulation of materials Manufacturing process, e.g. gel content UV filtering properties of superstrate Air and moisture permeability FIGURE 21: EVA BROWNING (LEFT). DISCOLORATION OF THE EVA WITH VARIOUS SUPERSTRATE [PERN2008] PV MODULE TEMPERATURE EXCURSION, SNOW AND WIND The first impact of static snow loads, dynamical wind loads or temperatures changes from night today is the mechanical stress on the electrical connections in the modules as shown in figure 22 (b). The continuous changes of the gaps, see figure 22 (a) induce a force on the soldering and can weaken the solder bonds. This causes an increase of the series resistance of the module. Page 24 of 39

25 (a) FIGURE 22: (A) MECHANICAL STRESS TO THE CELL INTERCONNECTIONS CAUSED BY THE THERMAL EXPANSION [DIET2013]. (B) DISCONNECTIONS OF BUS BARS AFTER 200 THERMAL CYCLES [HERR2011] (b) The second and important impact of the mechanical stress is the detachment of cracked cell areas from the connection path. In this case these areas don t contribute to the current of the module and in Figure 23 an example of a module before and after 200 thermal cycles is shown. FIGURE 23: DETACHMENT OF AN AREA OF CELLS AFTER 200 THERMAL CYCLES FROM -40 C TO 85 C (LEFT: INITIAL / RIGHT: AFTER 200 TC) 4.2. DEGRADATION PARAMETERS AND VALUES FOR THE SIMULATION For the prediction of the energy production over the lifetime first we have to determine which degradation parameters to insert in the tool and secondly which values we have to use for each specific degradation parameter. The first step could be determined by the installation conditions of the PV system. In desert climates or façade system we have to consider mainly the R s degradation due to thermal stresses; in humid and warm climate we have to consider the I ph and R sh degradation due moisture diffusion and yellowing. The values for the degradations for a specific module type to use in the model are much more difficult to determine DEGRADATION OF IPH In chapter 2.3 the single degradation mechanism for the I ph are described. In literature a wide range of publication are available and following some example: A 25 years old module from the field was analysed cell by cell and power loss of up to 50% is reported in [PARK2013]. The power loss is due the I sc decrease, whereas the V oc and the FF are constant over all cells in the module. The fact that the FF is not affected from browning confirms that the series and shunt resistance of the module is not deteriorated by the discoloration of the lamination material. The value of the annual degradation rate Page 25 of 39

26 D DIS can be up to 2%/year if the I sc loss is 50% after 25 years of operation as reported in [PARK2013]. The P max losses attributed to optical losses, delamination and yellowing, are about 20% over the lifetime of 20 years resulting in a degradation rate of 1% / year [SAMP2011] DEGRADATION OF THE SERIES AND SHUNT RESISTANCE In literature no systematic measurements for the series und shunt resistance degradation could be found. For standard PV module typical values for the series resistance are about 0.5 Ω to 1 Ω and should be well above 100 Ω for the shunt resistance. Values for degraded modules measured in the SWISS PV module test centre and in [KAPL2010] go up to 2 to 5 Ohms for the series resistance and shunt resistance can decrease to less than 100 Ω. Some results for the ARCO Solar modules from the TISO 10 kw system at SUPSI are reported in chapter INFLUENCE OF THE RS AND RSH DEGRADATION ON THE FILL FACTOR The fill factor is determined by the parasitic resistance in the PV module and therefore the degradation of the fill factor can be expressed directly with the R s and R sh degradation as follows. The fill factor of a PV module in dependence of the series resistance can be expressed by in a simplified expression [WEN2009] 22 3 =22 < (1 (7 & 67 O 3 ) (17) with FF 0 as fill factor not affected by the series resistance. This equation can be transformed in the year-dependent formula 22 3 ()=22 < (1 (7 () & 67 () O 3()) (18) The fill factor FF sh in dependence of the shunt resistance can be expressed by 22 3 =22 < (1 & 67 ' (- ) (19) This equation can be transformed in the time-dependent formula 22 3 (W)=22 < (1 & 67(X) (7 ' (- (X) ) (20) The degradation of the fill factor and P max of PV modules are treated in some publications [FRI2013, SAMPL2001, JORD2013] AGGREGATE DEGRADATION OF A PV MODULE Table 3 gives some possible values for the single degradations rates. Page 26 of 39

27 TABLE 3: SUMMARY OF THE DEGRADATION PARAMETERS AND POSSIBLE VALUES AND LIMITS Degradation Value I sc (Yellowing) I sc (Browning) R s R sh V oc < 1% / Y up to 2%/ Y 10 % / Y up to 5%/ Y < 0.1 % / Y Limit 90% of initial P max after < 10 Y No limit Comment / Example No limit From 0.5 Ω to 5 Ω in 20 Y No limit From 500 Ω to 100 in 20 Y No limit The simulation of the P max degradation of a PV module composed of all degradation modes can be done with EXCEL. Based on the values summarized in table 3 a calculation with 0.1%/Y for I sc, 0%/Y for V oc, 10%/Y for R s and 20% for R sh is shown in Figure 24. FIGURE 24: CALCULATION OF THE P MAX DEGRADATION WITH FOLLOWING LOWING DEGRADATION RATES 0.1%/Y FOR I SC, 0%/Y FOR V OC,, 10%/Y FOR R S AND 20% FOR R SH Page 27 of 39

28 4.3. CONSEQUENCES OF THE DEGRADATION DISTRIBUTION OF SAME MODULE TYPES ON THE POWER DEGRADATION Like all industrial products PV modules are subject to variations in production: lamination process, power of cells, soldering and others parameters lead to a variation of the final product. The variation results in a power distribution of the manufactured modules and therefore they are measured and classified in power classes as shown in figure 25. The variations originated by the production process are not only relevant for the output power of the module but should influence in the same way his annual degradation rate discussed in the previous sections. The distribution of the module power in a PV system during the lifetime is determined by: - Initial power distribution of the PV modules after production - Distribution of the annual degradation rate Usually the initial power distribution of a module type is a segment of a Gaussian distribution as shown in Figure 25 and can be approximated by a rectangular distribution. FIGURE 25: DISTRIBUTION OF THE POWER P MAX AFTER THE PRODUCTION PROCESS. THE POWER CLASS IS A PART OF THE GAUSSIAN DISTRIBUTION. [ROES2012] In literature no information is available about the distribution of the degradation rates of brand new PV modules of the same type. In figure 26 (a) shows the distribution of the annual degradation rate of the TISO modules [FRIE 2012] and in figure 26 (b) annual degradation rates on system levels are shown [JORD2011]. It can reasonable be assumed that the degradation distribution on system level is similar to the one on PV module level. The shape of the Gamma distribution represents the curve shown in Figure 26. (a) (b) FIGURE 26: (A) DISTRIBUTION OF THE ANNUAL DEGRADATION RATE (%/Y) FOR THE HOLE LIFETIME AND THE TWO PERIOD FROM AND (B) ANNUAL DEGRADATION RATES OF PV SYSTEMS [JORD2011] Page 28 of 39

29 It is possible to calculate with a Monte Carlo simulation the module power distribution over the lifetime for the PV systems starting from the initial distributions for the module power and the annual degradation rate. Two Monte Carlo simulation results are shown in Figure 27. (a) (b) FIGURE 27: (A) POWER DISTRIBUTION AFTER 5/10 AND 25 Y ASSUMING A RECTANGULAR INITIAL POWER DISTRIBUTION AND A GAMMA DISTRIBUTION FOR THE DEGRADATION RATE. (B) POWER DISTRIBUTION AFTER 5/10 AND 25 Y ASSUMING A RECTANGULAR INITIAL POWER DISTRIBUTION AND DEGRADATION RATE The Figure 27(a) and (b) differs in the assumption of the annual degradation rate distribution, (a) is a gammaa distribution and (b) a rectangular distribution, both with a minimum degradation rate of 0.2%/Y and maximum value of 2%/ /Y for the gamma distribution and 0.9%/Y for the rectangular distribution. The results for the power distribution after 5, 10 and 25 years of operation is clearly visible. The widening of the power distribution is confirmed by the results of the TISO 10 kw PV system at SUPSI shown in figure 28 (a) and the shape suggest that the initial degradation distribution is in fact similar to a gamma distribution. In figure 28(b) a log normal distribution, similar to the gamma distribution, is assumed for the degradation [BOHN]. The results are comparable with the results of a gamma distribution and reflect also the TISO results. (a) (b) FIGURE 28: (A) MEASURED DISTRIBUTION OF THE PMAX OF THE TISO 10 KW SYSTEM. (B) CALCULATED POWER DISTRIBUTION WITH THE ASSUMPTION OF A LOGNORM DISTRIBUTION Page 29 of 39

30 5. CASE STUDIES 5.1. TISO 10 KW PV SYSTEM The TISO 10 kw plant at SUPSI was connected to the grid in May 1982 as the first of its kind in Europe. The system worked for 27 years almost without interruptions; the plant underwent configuration changes only a few times during this period, mainly because of inverter breakdowns. Due to a change in location at the end of 2008, the disassembling of the system was begun, and 18 months later the plant was reinstalled in a new configuration on a different roof on the Trevano Campus. Between 1982 and 2010 the IV curves of 18 selected modules were measured regularly. Performance measurement, visual inspection and insulation testing were performed on all modules of the plant in 2001 and 2009/2010. TABLE 4: TECHNICAL DETAILS OF ARCO SOLAR ASI PV MODULES INSTALLED IN THE TISO 10 KW PLANT P max 37 Watt Tolerance P max ± 10 % Cell technology Mono crystalline Si Number of cells 35 Cell size Ø mm Module efficiency 10.6 % Front glass 3 mm tempered Encapsulant PVB / EVA Back sheet Tedlar metal Junction box Moisture proofed plastic box Edge sealant Butyrol hot melt Frame Al Table 5 summarizes the results of the visual inspection in 2001 and In this work we look in particular to the discoloration of the encapsulation material which causes the current losses and the delamination and oxidation effects for the resistance degradation. TABLE 5: SUMMARY OF THE MODULE DEFECTS IN PERCENTAGE OF THE TOTAL OF THE VISUAL INSPECTIONS IN 2001 AND 2008 (MULTIPLE DEFECTS PER MODULE) Defect Yellowing 97% 97% Oxidation JB 93% 100% Hot spot 26% 33% Cracks 22% 22% Backsheet 20% 95% Delamination 92% 92% Sealant 76% 90% Grid oxidation 93% 100% Figure 29 shows the distribution of the annual degradation rate of all 284 ARCO Solar modules for the two periods ; and over the entire lifetime. The average degradation rate of all plant modules over the 28 years is 0.38 %/year. In the first period ( ), the degradation rate was 0.27% per year and in the second period ( ) 0.64% per year. The performance ratio of the system decreased by Page 30 of 39

31 about 20% in the 27 years reinstallation of the plant. of operation, and increased by 10% after maintenance and From the graphs in Figure 29 the following conclusions can be drawn: - The distribution of the annual degradation rate can be approximated with a Gamma function - The mean values are at 0.5 %/year with minimum values of 0.1 %/year and maximum values of 2%/year as confirmed from literature values [JORD2011] - The measurements show that the annual degradation rates are not constant with time and increase with increasing operating time. This fact suggests that the annual degradation rate is a sum of single degradation rates caused by the different degradation mechanism. (b) (a) (c) FIGURE 29: DEGRADATION RATES OF THE PV MODULES FOR THE THREE PERIODS OF OPERATION: (A) (B) (C) ( ASSUMED NOMINAL VALUE W IN 1982). Figure 30 shows the losses of I sc, V oc and FF of all 284 ARCO Solar modules in function of the power degradation from 1982 to The measurements resultss confirm that the V oc degradation is as expected very low and the degradation of P max is caused mainly by I sc and FF degradation. Page 31 of 39

32 FIGURE 30: DEGRADATION OF FF, I SC AND V OC IN FUNCTION OF THE POWER DEGRADATION P MAX FOR THE 284 ARCO SOLAR MODULES YELLOWING OF ENCAPSULANT MATERIAL AND ISC DEGRADATION Yellowing is the major visual change of the modules and was already recognized at 50% of the modules in In % of the modules were yellowed, and this high level remained stable until FIGURE 31: WHITE AND YELLOW ARCO SOLAR MODULES IN UPPER ONE WITH VERY SLIGHT YELLOWING. LOWER ONE WITH DARK YELLOWING/BROWNING. (THE SPECTRAL RESPONSE AND IV CURVES ARE SHOWN IN FIGURE 32) The discoloration of the encapsulation materials took place with different yellowing levels in the first years of the lifetime and was stable till today as shown in figure 31 [FRIE2013]. Figure 32 shows the spectral response of the white and the yellow module measured in 2001 and 2015 with the corresponding IV curve. The measured modules are this shown in figure 31. In 2001 the I sc from the yellow module was 1.3% lower than the white module with a power reduction of 4.5 %. In 2015 the difference in I sc between the dark yellow and the white module was 8.6 % with a power reduction of 3%. Page 32 of 39

33 0,6 Lifetime Degradation Mechanisms (16/03/2015) Absolute SR [A/W] 0,5 0,4 0,3 0,2 White 0, Wavelength [nm] Yellow FIGURE 32: SPECTRAL RESPONSE MEASURED IN 2015 (LEFT) AND IN 2001 ON A WHITE AND YELLOWED MODULE. SECOND LINE SHOWS THE RELATIVE IV CURVES PARASITIC RESISTANCES DEGRADATION OF THE MODULES The series resistances of the ARCO Solar modules measured in 2008 ranged from Ω to Ω. In the datasheet the initial value is declared with 1 Ω. The distribution of the degradation in 2008 shown in Figure 33 (a) is very similar to a gamma distribution with some outliners and the average increase of the series resistance is 76 %, means 2.72 %/Y. The shunt resistance measured in 2008 is shown in Figure 33 (b). These values are taken from the IV curve measurement with the IIIa flasher and an electronic load from PASAN. The shunt resistance is extrapolated from the IV curve and is affected from a high uncertainty. The initial value from the ARCO solar datasheet is 500 Ω and the values in 2008 shows a degradation to values around 200 Ω. Page 33 of 39

34 (a) (b) FIGURE 33: (A) INCREASE OF THE SERIES RESISTANCE OF THE TISO MODULES FROM 1982 TO INITIAL VALUE OF R S 1 Ω FROM ARCO SOLAR DATASHEET. (B) INCREASE OF THE SERIES RESISTANCE OF THE TISO MODULES FROM 1982 TO INITIAL VALUE OF R SH 500 Ω FROM ARCO SOLAR DATASHEET EXPERIENCE AT TH XPERIENCE AT THE SWISS PV MODULE TEST CENTRE (SPVMTC) Modules with a variety of defects and failures arrive from the field at the test laboratory. The tested modules are mainly the worst case modules out of the field, because PV system owners send modules mostly in case of an evident loss in energy production or obvious visual defects. However, a common problem is that for those degraded modules no initial measurements are available. With our experience in the laboratory we can indicate a ranking of degradation effects and failures, but it is not possible to give absolute failures distribution or degradation rates. The most common failures and degradation mechanisms in the field are delamination, PID and cell cracks. Yellowing of encapsulation and corrosion of electrical connections are less common. Page 34 of 39

35 Many quality issues investigated at the SPVMTC are related to delamination due to poor quality in production or cell checks due to shipment or during the installation of the modules.. These failures are not related to the intrinsic degradation of a PV module and for this reason they are not relevant in a degradation model. Modules with an intrinsic degradation mechanism, which are arriving at the SPVMTC are normally PID affected. Here the degradation rates are about 20 to 30% in the first years of operation, but usually they are not well documented PV MODULES FROM OTHER INSTALLATION SITES In 2003 a 2.65 kwp BIPV system was installed on a roof in the Swiss Midlands. The system consists of 13 large area PV modules with a power of 204 Wp each connected to each other through two strings. The modules are customer-specific with a size of 90 x 245 cm, a 4 mm front glass and a standard polymer back sheet. All modules were framed in a solar-collector aluminium frame and integrated into the roof. Until 2011 the PV plant worked well and no significant degradation could be observed over those first 8 years. However, by the end of 2011 a strong degradation was perceived in the performance ratio of the PV plant. [DITT2015] 1.00 PR 1 (2 Strings, Module 6 to 13) PR 2 (1 String, Module 1 to 5) Performance Ratio [-] Date [mm.yyyy] FIGURE 34: POWER DEGRADATION OF A SMALL 2.65 KW PV SYSTEM. AFTER 10 YEARS OF OPERATION THE PERFORMANCE DECREASED ABOUT 20%. The analysis of the modules revealed a poor quality of the cell interconnection as visible from the electroluminescence photography and the thermography. The performance values out of the IV curve are summarized in table 6. The initial series resistance are not known but according to theoretical values a high increase is obvious and the shunt resistance values are very low. Unfortunately due to the missing data no degradation rates can be given. TABLE 6: INITIAL PERFORMANCE OF TWO MODULES COMPARED TO THE MEASUREMENTS IN 2014 New module 2014 New module 2014 Module n. 8 Module n. 12 P max (W) FF I sc (A) Page 35 of 39

36 V oc (V) R s (Ω) NA R sh (Ω) NA NA 39 NA FIGURE 35: ELECTROLUMINESCENCE PHOTOGRAPHY (EL) AND THERMOGRAPHY (IR) OF TWO MODULES OUT OF THE SYSTEM WITH HIGH CONTACT RESISTANCES. In this case the degradation of the PV modules can be attributed mainly to the degradation of the series resistance. The degradation of the series resistance was particular strong due to the mechanical stress sensitive design and a weak soldering. The consequence of the high contact resistance is shown in figure 36. The burn mark corresponds to a weak contact. FIGURE 36: BURN MARK ON THE BACK SIDE OF THE MODULE IN CORRESPONDENCE TO A WEAK CONTACT Page 36 of 39

37 6. CONCLUSIONS The goal of this work is to give some indication about the power degradation of PV modules in the field over their lifetime. To take into account the degradation in a simulation tool it should be define the parameters, the time functions and the values of the degradation rate.. The first step is the definition of the parameter necessary for simulation tools. This work proposes to use the parameters of one diode model, I sc, V oc, R s and R sh. In the second step the time dependence over years, of this parameters are defined. This step could be supported by the field experience and indoor measurements reported in literature. In chapter 2 possible function are given. The following information are necessary to predict the performance of the PV system: Climatic conditions at the installation site Values for each degradation rate Statistical distribution of power and degradation rates If all this information are well known a prediction can be done, but unfortunately today there is a lack of information and data availability. FIGURE 37: PROPOSED FLOW FOR THE PERFORMANCE PREDICTION OF A PV SYSTEM Page 37 of 39