Early degradation of silicon PV modules and guaranty conditions

TL;DR: Findings of PV plant evaluations carried out during last years are presented, showing the possible degradation of PV modules and hidden manufacturing defects.

About: This article is published in Solar Energy.The article was published on 2011-09-01 and is currently open access. It has received 321 citations till now.

Summary

1. Introduction

• The global yearly photovoltaic installed power all over the world is continuously expanding in recent years, rising from less than 1 GW in 2003 to more than 7.2 GW in 2009.
• This increase was reflected in global world cumulative capacity, which approached 16 GW at the end of 2008.
• Nevertheless, the development of the German market in 2009 and the continuous progression of other countries have permitted the PV market to continue to develop, with about 15% growth in 2009.
• This period coincided with a time of great dynamism in markets, high demand of PV cells and modules, and silicon shortage, which forced manufacturers to adjust their procedures in order to meet the demand.

/./. Early degradation

• Apart from long-term studies that detect problems in field-aged PV modules (Reis et al., 2002; Parretta et al., 2005) in recent years problems have been detected in plants operating for short periods of time (Carr and Prior, 2004; Gi-Hwan Kang et al., 2010) .
• PV module design is changing and developing, as the PV industry works to decrease costs for solar cells and panels and to improve reliability.
• Gautam and Kaushika (2002) considered 165 years as the maximum lifespan of a cell.
• Additionally, qualification tests are performed on a small number of samples, making them insignificant with respect to annual production.
• In these cases, possible reasons could be failures in manufacturing quality control, faulty PV plant design, faulty plant and/or module operation, or defects that appear after a certain time of operation that are not possible to detect with the current standards, as the standards can not cover all degradation mechanisms.

1.2. Review of IEC61215 standard

• Qualifications tests included in the IEC61215 standard have a relatively short duration and are performed on a sample of eight modules selected from the whole population of the modules production.
• First, these initial tests are performed on all of the modules: -Preconditioning.
• If one of these modules fails, the design does not pass the qualification sequence.
• With respect to visual defects, the following are considered to be major visual defects: (c) A crack in a cell which propagation could remove more than 10% of that cell's area from the electrical circuit of the module.
• (d) Bubbles or delaminations forming a continuous path between any part of the electrical circuit and the edge of the module.

2.1. Visual inspection

• Visual inspection, the first step of analysis, allows some defects to be detected by sight.
• More than 1000 lux of illumination should be received according to test conditions for part 10.1 of the IEC61215 norm (International Electrotechnical Commission, 1987) .
• Reflections should be avoided, as they may lead to defective images.
• The inspection should be done from different angles to differentiate the layer where the defect could appear and to avoid errors due to reflected images.
• A single photo taken from only one position is not enough because it could contain a reflected image and lead to a detection error.

2.2. Indoor and outdoor power measurement

• Power decreases are not always detected within the entire population; rather, a power test must be applied individually to a set of suspicious modules.
• This test can be performed in a solar simulator (indoor measurement) or under sunlight exposure (outdoor measurement).
• Nevertheless, when using artificial light, it is difficult to precisely reproduce the spectral distribution of the sunlight (IEC60891).
• Usually, temperature will be higher than 25 °C, and the irradiation will not have the same spectrum or the same level.
• Rosella and Ibáñez (2006) proposed a variation of STC measurements for determining a more realistic method.

2.3. Infrared images (IR)

• This test consists of the detection of areas with higher temperature than the rest (hot spots).
• The method used is based on the property of every material to emit electromagnetic radiation whose wavelength and relative maximum is related to the temperature of the material.
• The radiation relative maximum depends on the temperature, as previously mentioned, but only three different temperature ranges are taken into account: 2-2.5 (im for temperatures over 1000 C that includes a part of visible radiation, and another two ranges; 3.5-4.2 (im and 8-14 (im for lower temperatures.
• Krenzinger and Andrade (2007) suggested a method to perform the correction accurately by taking into account the errors due to reflections and the sky temperature.
• Detectors based on the IR measurement method need to know the ambient temperature in order to perform corrections.

2.4. Lock in thermography (LIT)

• This method is also non-destructive and useful in finding lateral power loss using an injection of current.
• A current is injected into the solar cell.
• If the cell has shunt defects, they appear as local temperature modulations.
• It is possible to detect different kinds of shunt defects using different modulations of the currents injected.
• This test can be performed in dark conditions (DLIT) or under illumination (ILIT).

2.5. Electroluminescence (EL) and photoluminescence (PL) imaging techniques

• In contrast to images obtained by detecting the infrared radiation caused by the thermal effect, a luminescence image is obtained from photons emitted by the recombination of excited carriers into a solar cell (Kirchartz et al., 2009) .
• The excitation can be achieved by means of an injected current, which provokes an electroluminescence (EL) effect.
• The excitation can also be obtained by means of a radiation incident over the solar cell, in which case the light obtained is due to a photoluminescence (PL) effect (Kasemann et al., 2008) .
• The detectable defects are different from those detected using thermograph images, as the resolution of the images is better than those obtained only by the thermograph technique.

2.6. Resonance ultrasonic vibrations (KUV) technique

• This technique detects deviations in the characteristic frequency of the response after an ultrasonic excitation of the wafer.
• It has been demonstrated that the resonance frequency decreases and bandwidth of the resonance frequency increases when a crack appears in a cell (Belyaev et al., 2006) .
• This system is useful to detect cracks in standalone cells and, with some limitations, could be applied to entire PV modules.

3.1. Yellowing and browning

• This usually consists of a degradation of the EVA or the adhesive material between the glass and the cells.
• It causes a change in the transmittance of the light reaching the solar cells and thus a decrease in the power generated.
• In the tests performed, the importance of this defect on the module's power loss cannot be assessed.
• This should mean that yellowing appears in polymeric encapsulant instead of in the adherent element (usually EVA) but also that EVA was not present in the same way in both areas of the PV module where different polymeric encapsulant was used.
• Fig. 1 shows an example of how the yellowing effect appears only over an area but not in adjacent areas.

3.2. Delamination

• Delamination consists of the loss of adherence between different layers of the PV module and the subsequent detachment of these layers.
• Delamination is a major problem because it can lead to two effects: a light decoupling where reflection increases as well as water penetration inside the module structure.
• Skoczek et al. (2008) studied how this kind of defect and others such as bubbles and loss of mechanical energy could appear after some of the tests performed in IEC61215 norm.
• Oreski and Wallner (2005) tested different backsheet layers with damp heat test (85 °C and 85HR) and in some of the materials tested embrittlement was found after aging.
• When moisture enters, different chemical reactions occur, and some cause degradation of different parts of the module.

3.3. Bubbles

• This kind of defect is similar to delamination, but in this case, the lack of adherence of the EVA affects only a small area and is combined with the blowing of areas where this adherence has been lost.
• A bubble usually is due to a chemical reaction where some gasses are released.
• Ble forms an air chamber, and although the air temperature in the chamber appears lower than in the adjacent cells, the cell temperature is actually higher because the heat of the cell is less dissipated.
• The bubbles are caused by a detachment between part of the cell and the glass.
• This kind of defect is not very common on the front side of the module.

3.4. Cracks in cells

• In order to save silicon and reduce the manufacturing cost the silicon solar cell market has varied the thickness and area of cells in the last few years.
• This reduction of thickness and increase in area make the cells more fragile and susceptible to fractures during their manipulation, module lamination and storage.
• Sometimes different colour lines can be perceived in the cell, although the cracks are not visible by sight.
• When modules with these different coloured lines are tested by electroluminescence, there is good accordance between these lines and the micro-cracks observed by EL.

3.5. Defects in anti-reflective coating (ARC)

• Apart from strategies such as texturing the cell surfaces, the performance of the cells that form a PV module can be improved by adding an anti-reflective coating in order to maximize the light that reaches the active area of the cell.
• The materials normally used are silicon dioxide and silicon nitride, and the thickness is chosen such that only a minimal part of the light escapes.
• During the life of the PV module, the anti-reflective coating (ARC) receives radiation that could induce a change in the ARC colouring (Fig. 6 ).
• The light that reaches the cells may be lower than expected.
• A followup of the affected modules should be done in order to detect whether this defect leads to another more severe defect.

3.6. Hot spots

• The cause of the hot spot could be a variety of cell failures, including partial shadowing, cells mismatch or failures in the interconnection between cells (Molenbroek et al., 1991) .
• Shadowing can cause hot spots if the module is not adequately protected.
• To prevent cell overheating and hot spots, bypass diodes are placed in connection boxes, limiting the reverse voltage that can reach a shaded cell, thereby limiting the temperature.
• Another thermal test consists of the operation of the PV module at extreme conditions such as short-circuit conditions.
• The module should work alone, and the electrical connectors positive and negative of the module are short-circuited.

3.7.1. Lines and blemishes in the cells

• Another defect consisting of a broken ribbon can also be detected.
• The other defect can be observed using a microscope.
• The defect in the lower left image is only detectable using a microscope.

3.7.2. Detachment of the frame

• The detachment of the frame consists of a separation of the frame from the rest of the module.
• Snow or ice accumulation on the module can also cause a frame detachment.
• Manufacturers tend to also provide a list with the measured maximum power obtained in STC of every PV module supplied known as a "flash list" (as it is usually obtained using a sun simulator based on flash light).
• The I-V curve of every string can be obtained by accessing the leads of the diodes in the connection box as they normally are parallel of each string.
• A power loss higher than the guaranteed loss can only be detected by periodically measuring a representative sample of the total population of the solar plant.

4. Conclusions

• The first step should consist of a visual inspection in order to detect defects such as bubbles, delamination, detachment of the frame, decolouring or any strange figures that may appear on the cells and that may indicate a defect.
• The next step should consist of a thermal analysis using an IR camera to detect any areas of the solar plant that are hotter than usual or any specific PV modules that present hot spots.
• Foremost power analyses, thermal tests and EL tests should be performed.
• Cracks in he cells could appear during the manufacturing of the cells but also during the lamination process or even during the storage or installation of the module.