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LONG-TERM DURABILITY OF SOLAR PHOTOVOLTAIC MODULES
Chibuisi Chinasaokwu Okorieimoh, Brian Norton, Michael Conlon
Dublin Energy Lab, Technological University Dublin, School of Electrical and Electronic Engineering,
Kevin Street, Dublin 8, Ireland.
Keywords: Durability, Solar, Photovoltaic, Ultraviolet Radiation
Abstract
Solar photovoltaic (PV) panels experience long-term performance degradation resulting in lower
like-per-like efficiencies and performance ratios when compared with their initial performance.
Manufacturers of solar photovoltaic modules usually guarantee the life span for more than 20
years. It is therefore necessary to track and mitigate degradation of PV modules over this period
to satisfy such guarantees and beyond this period to identify maintenance and repair
requirements. Degradation of solar PV modules makes them less efficient, less reliable and,
ultimately, inoperative. This paper reviews relevant literature to discuss:
• causes of efficiency reductions in photovoltaic cells;
• ways to achieve long-term durability of solar photovoltaic modules;
• how viability of solar photovoltaic modules is affected by degradation;
• the remedies to solar photovoltaic (PV) degradation.
INTRODUCTION
Solar photovoltaic cells convert solar energy into electrical energy through the photovoltaic
effect. Solar energy can reduce emissions of carbon dioxide (CO2) associated with the generation
from fossil fuels as the only CO2 emissions are those embodied in their manufacture (Norton,
1999). The electricity generated by solar PV is more environmentally friendly as it is carbon-
emission free at the point of generation when compared to fossil fuel generation. Solar PV panels
experience long-term performance degradation resulting in lower like-per-like efficiency and
performance ratios when compared with their initial performance.
Reducing rates of PV module degradation aims to maintain efficiency of solar PV systems (Li,
2016). As manufacturers usually guarantee the life span of PV modules for more than 20 years
(Li, 2016), it is therefore necessary to track and mitigate the degradation of PV modules over this
period. Both during and beyond this period knowing degradation behavior is essential for
operation, maintenance and repair.
DISTINGUISHING TRANSIENT PERFORMANCE CHANGES FROM LONGER-TERM
DEGRADATION
PV module output varies with solar irradiance and module temperature. It is also affected by
shading, rain and dust (Dunlop and Halton, 2006; Tiwari et al, 2011). All these variations are
transient on a variety of timescales and/or reversible. Degradation refers to loss of output due
to physical degradation or damage to the PV cell, the effects are not reversible. It refers to effects
that will ultimately require the replacement of a PV cell for the system to return to its initial
performance. Degradation is measured by changes mean efficiency and/or performance ratio
over the long-term as illustrated indicatively in Figure 1. It can also be observed in perturbation
caused by cell failure in the current-voltage (I-V) curves for an array.
Initial mean efficiency
Number of PV modules Degraded mean efficiency
PV Efficiency (%)
Figure 1: Degradation on Solar PV system
This paper discusses the long-term durability of solar photovoltaic modules with particular
emphasis on;
1. how to achieve long-term durability of solar photovoltaic modules;
2. what affects the durability of solar photovoltaic modules;
3. what are the remedies to solar photovoltaic (PV) degradation;
4. how the durability and reliability of PV modules can be improved.
Individual module degradation can be attributed to intrinsic property changes in the PV materials
caused by external effects such as (i) potential induced degradation (PID) (Pingel et al, 2010), and
(ii) light induced degradation (LID) (Sopori et al, 2012).
The outdoor operation of cells as part of a module in an array means mechanisms external to
solar cell such as corrosion in interconnections and solder bonds play a significant role in
performance degradation (Li, 2016). This makes it important to determine the degradation rates
under outdoor operational conditions rather than indoor testing of isolated modules. (Li, 2016),
classified the major difficulties in evaluating degradation rates of PV modules from real
operational data into:
i. large fluctuations of the operational data due to uncontrollable external parameters
such as weather conditions like solar radiation, rain, cloud movement, wind velocity
and ambient temperature together with unexpected changes of factors external to
PV systems such as unexpected shading, inverter problems and control failures.
ii. systematic ‘degradation’ in the measurement of PV module operational performance
caused by control sensor drifting with time as a result of electronic ageing of
components such as the drifting of irradiance sensors. The energy output of a PV
system depends on weather conditions (Osterwald et al, 2002), (Tiwari et al, 2011),
(Li et al, 2013). According to Osterwald et al (2002), the degradation rate of silicon PV
modules is around -0.7% per year of maximum power rating.
DEGRADATION RATES
Jia et al (2014) investigated performance degradation of the following types of PV modules:
monocrystalline silicon (m-Si) (such as glass-back sheet with frame and glass-glass without
frame), heterojunction crystalline silicon, monocrystalline silicon back-contact, multi-crystalline
silicon, double-junction “micromorph” silicon, single-junction/double-junction amorphous
silicon (a-Si), cadmium telluride (CdTe), and copper indium gallium diselenide (CIGS) as seen in
Figure 2, three years outdoor monitoring data showed the degradation paths of each module.
Figure 2: Mean annual degradation rates (%) of performance ratios (PRs) and the I–V
curve components: short-circuit current (ISC), open-circuit voltage (VOC ), and fill factor (FF)
for ten module types (Jia et al, 2014).
Statistical decomposition techniques were used to draw out paths for the performance ratio (PR),
short-circuit current (ISC ), open-circuit voltage (VOC), and fill factor (FF). Degradation rates for the
monocrystalline silicon (m-Si) modules were found to be equal to or less than -0.8% per year as
a result of the decrease in ISC . Multi-crystalline silicon modules exhibited a higher degradation
rate of -1.0% per year. The a-Si, micromorph silicon and CdTe modules showed a degradation
rate of about -2% per year. The CIGS module showed a degradation rate of -6% per year higher
than CdTe.
The study of annual degradation rates of recent crystalline silicon photovoltaic modules were
carried out by Tetsuyuki and Atsushi (2017). Six crystalline silicon PV modules connected to an
electric power grid were analysed. Three indicators were used for the annual degradation rates
of the different crystalline silicon PV: energy yield, performance ratio and indoor power. The
performance of the module was evaluated from electricity output measurements taken over 3
years. The following trends were found in the three indicators; energy yield: 0.0, -0.4% per year,
0.0, 0.1% per year, 1.5% per year and 0.5% per year, performance ratio: 0.0, -0.4% per year, -
0.1% per year, 0.0, 1.4% per year and 0.5% per year and indoor power: 0.1% per year, -0.3% per
year, 0.2% per year, 0.0, 0.7% per year and 0.6% per year were similar. The performance of the
newly installed PV modules were found to decrease by over 2% as a result of initial light-induced
degradation (LID) after installation (Tetsuyuki and Atsushi, 2017).
The power output of an outdoor PV module has been shown to reduce as a result of thermal
cycling causing crack formation between solders and metals (Nochang et al, 2014). Dunlop and
Halton (2006) studied degradation of PV modules in outdoor conditions for 22 years. They
monitored the electrical power outputs of monocrystalline silicon, polycrystalline silicon and
amorphous silicon modules. They found 8% to 12% decrease of maximum power output of the
PV modules (Pmax) after 20 years outdoor exposure. Their research showed that about 80% of
the reduction was due to corrosion and the remaining 20% was attributed to dust accumulating
on the PV modules.
An experimental study of degradation modes and their effects on photovoltaic module was
conducted after 12 years of field operation (Saadsaoud et al, 2017). Their investigation found
that degradation led to annual reductions in output power ranging between 2.08% and 5.2%.
Short circuit current (Isc) reduced by between 2.75% and 2.84% annually. The open-circuit voltage
(Voc ) was found to be the least affected, with annual reductions ranging between 0.01% and
4.25%.
DEGRADATION INFLUENCES
The existence of only one highly degraded PV module in a PV system, reduces daily output from
(Takatoshi et al, (2018):
i. 19.8kWh to 18.7kWh during sunny days;
ii. 11.3kWh to 10.8kWh during partly cloudy sunny days; and
iii. 5.5kWh to 5.3kWh during cloudy days.
Pramod et al (2016), investigated degradation of mono-crystalline photovoltaic modules after 22
years of outdoor exposure. They studied 90 mono-crystalline silicon PV modules installed on the
rooftop of the National Institute of Solar Energy (NISE) near New Delhi, India after 22 years of
outdoor operation. They carried out visual inspection, thermal imaging, current-voltage
characteristic curve analysis and insulation resistance measurement and in addition calculation
of the degradation rate. The mean power reduction rate of 90 PV modules over the period of 22
years was found to be about 1.9% per year at a peak rate of power reduced by 4.1% per year and
the minimum rate of power reduction was 0.3% per year. The result of electrical resistance of
insulation measurements of 90 PV modules (both in dry and wet conditions) showed that only 2
PV modules showed insulation electrical resistance of less than 400MΩ in dry conditions. Analysis
of electrical parameters shown in Figure 3 indicated that there was degradation of short circuit
current, from 0.4% to 3.7% per year with a mean value of 1.8% per year. The open circuit voltage,
ranged from 0.8% to 2.1% per year with a mean value of 1.4% per year and fill factor, ranged
from 0.7% to 2.6% per year with a mean value of 1% per year. The maximum power, Pmax
reduction rate ranges from 0.3% to 4.1% per year with a mean value of 1.9%/year. The reduced
power output was mainly due to the degradation in short circuit current.
Figure 3: Degradation rates for different electrical parameters (Pramod et al, 2016).
Where; ISC , short-circuit current; VOC, open-circuit current; Pmax, maximum power and FF,
fill factor.
DIAGNOSIS OF DEGRADATION MECHANISMS
The reliability and degradation of solar PV modules was investigated by David et al (2017) as part
of a case study of polycrystalline modules in Ghana. Fourteen polycrystalline modules were
installed on the concrete roof in a hot humid environment. They were evaluated after continuous
outdoor exposure for 19 years. They used a visual inspection checklist to document the physical
state of the modules. The PV modules were also evaluated by current-voltage (I-V)
characterization and thermal imaging. Their results showed that the modules were found to be
in good physical state with the exception of some bubbles developing on the front side. There
was insignificant corrosion found at the edge of the cells. The performance change of the PV
modules over the exposure duration was: nominal power, 21% to 35%; short circuit current, 5.8%
to 11.7%; open circuit voltage, 3.6% to 5.6% and 11.9% to 25.7% for fill factor respectively.
Zhengpeng et al (2011) carried out a study on PV module durability under high voltage biased
damp hot and humid conditions. They made use of ten photovoltaic module technologies which
comprisal (i) five thin-film technologies and (ii) five silicon wafer based technologies. The PV
modules were subjected to accelerated ageing tests in a climate dark chamber under
temperature conditions of 85⁰C and relative humidity of 85% and electrical bias for a period of
650 hours (27 1/12 days). They applied a bias voltage of ±1000V DC between the active circuit of
each module and the module frame. Their results showed biased stressing conditions in damp
heat could significantly degrade the electrical performance and cause several defects including
delamination, glass surface deterioration, frame corrosion, and metal grid discoloration,
depending on module type and bias polarity.
Table 1: Typical faults associated with PV modules
Manufacturing
defects
• hot spots (bad soldering)
(Kuitche et al,
2014);
• micro-cracks “snail trail” (Köntges et al,
2008);
• contamination (discolouration) (Köntges
et al, 2008).
Installation faults
(PVTRIN, 2011)
o incorrect design of the PV system;
o low inverter and module ventilation;
o loose or very tight cables;
o sensors placed badly;
o lack of lightening protection;
o actions that lead to corrosion.
Degradation
connection issues with solder bonds (Li,
2016);
sensor drifting and packaging of
materials (Li, 2016);
delamination (Zhengpeng et al, 2011);
micro-cracks (Köntges et al, 2008).
Catastrophic failure
fire outbreak;
failing of tree branches.
PV modules can be damaged by weather, temperature variations, soiling effect and ultraviolet
exposure. Typical faults are summarised in Table 1. Performance monitoring of PV systems aims
are to maintain the power output from PV systems thus increasing economic viability (Parveen
and Saurabh, 2019). To evaluate the degradation of PV modules, Parveen and Saurabh (2019)
suggested a clustering-based technique with different arrangements. They estimated the
performance ratio (PR) of the PV modules without physical inspection on-site, making the
suggested model useful for real-time estimation of PR. This may, in turn, lead to stronger
forecasting of PV array power output. Their model calculated the degradation in output solar
power for amorphous silicon (a-Si), polycrystalline silicon (p-Si), and silicon hetero-junction with
an intrinsic thin layer (Si-HIT) over three years. The degradation rate for a-Si was lowest at 0.85%
per year, and was highest for Si-HIT technology at between 0.95% and 2.03% per year. Their
results showed good agreement with the standard procedure used for performance evaluation
in a similar earlier study but as data was taken from a range of other studies, furthers corrections
for environmental factors may be necessary. Therefore, the suggested model has an advantage
over other methods that real-time estimation is possible as it does not require physical inspection
and imaging.
To create a PV panel simulation which is effective under changed environmental conditions,
Murari et al (2017) developed a model using MATLAB of an equivalent circuit. This allowed them
to perform joint simulation of a PV device with power electronics interfaces. Such simulations
allow optimization of the design of solar arrays and power systems.
Spagnolo et al (2012), Krenzinger and De Andrade (2007), Buerhop et al (2011) King et al (2000)
and Ancuta and Cepisca (2011) have stated that observations using imaging methods, such as
infrared (IR) thermography are valuable tools for inspecting PV-plants. This method is efficiently
relevant to inaccessible roof mounted PV systems as well as to extended field plants because it
is fast, reliable, contact free, non-destructive and involves measurements during operating
conditions but requires no clouds and no wind. Many infrared (IR)-based analysing methods are
used to investigate PV-modules (Breitenstein et al, 2003). Another method for image failure of
PV-modules is electroluminescence (Johnston et al, 2009). Köntges et al (2008), for instance,
employed this method in order to analyse the influence of micro-cracks in PV-modules on power
loss.
Buerhop-Lutz and Scheuerpflug (2015) inspected PV-plants using an aerial, drone-mounted
infrared thermography system. They carried out their measurement using an unpiloted drone
(Multikopter), a lightweight infrared (IR)-camera PI 450 (Optris), a visible camera GoPro and
equipment for navigation. They presented frequently detected failure modes of installed PV-
modules by focusing on crystalline modules from residential and industrial roofs as well as from
solar parks in the field.
CONCLUDING OBSERVATIONS
When a PV module maintains acceptable efficiency for a long duration:
• More energy are produced over a module life;
• The installation is more economically viable as the same initial cost provides for
a longer period of energy generation;
• Manufacturers and/or installers have lower outlays to satisfy insurance of
performance guarantees;
• Inspection and maintenance costs are lower;
• Enhanced reliability provides more inherent resilience to electricity generation;
• The expected warranty of 20-25 years is assured;
• There is less environmental impact as the rate of PV module disposal is reduced.
When installed PV system costs were high, electricity (market interventions such as feed-in
tariffs) were made. They encourage take-up by providing favourable revenue for electricity sold
to the grid. They also paid-back the cost of installation, usually in less than twenty years
(McCormack and Norton, 2013). As PV generated electricity prices reach grid-parity, the need for
such market interventions is obviated. The drivers underlying PV generation are also changing;
there is greater interest in PV electricity self-consumption and in security of electrical supply
(Casillo-Cagigal et al, 2011). Both the latter require assured long-term PV performance; thus
understanding factors determining durability and reliability of PV systems will become more
important in initial design. This is also likely to lead to innovations in diagnostics in system
operation.
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