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An Overview of Factors Affecting the Performance of Solar PV Systems
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1
An Overview of Factors
Affecting the Performance of Solar PV Systems
Dr. K.V. Vidyanandan, Senior Member, IEEE
Power Management Institute, NTPC Ltd., NOIDA, India.
kvvidyas@gmail.com, kvvidyanandan@ntpc.co.in

Abstract—The output power generated by a photovoltaic
module and its life span depends on many aspects. Some of
these factors include: the type of PV material, solar radiation
intensity received, cell temperature, parasitic resistances, cloud
and other shading effects, inverter efficiency, dust, module
orientation, weather conditions, geographical location, cable
thickness etc. This paper reviews few of the major factors that
significantly affect the performance of solar PV systems.
Index Terms— fill-factor, irradiance, parasitic resistances,
shading, cell temperature.
I. INTRODUCTION
S
OME 173 countries around the world presently have
renewable energy (RE) targets in place and 146
countries have support policies [1]. Many countries have set
target of 30% RE based electricity generation by 2030 [2].
India, going one step ahead, is aiming to achieve 40% power
from non-fossil based resources by 2030 [3]. The share of
RE, in particular wind and solar PV, in the global power
system is increasing exponentially. India has an ambitious
target of achieving 175 GW of RE based power by 2022,
with 100 GW from solar, 60 GW from wind, 10 GW from
biomass and 5 GW from small hydro [4]. The world total
capacity of solar PV as of 01 Jan. 2016 was 227 GW,
representing 1.3% of world electricity with a cumulative
growth rate of 41% between 2000 and 2015 [5]. In India, as
of 30 Nov. 2016, grid connected solar PV capacity was 8875
MW and its share in the power system was 2.86%. [6].
II. OVERVIEW OF SOLAR ENERGY
Solar radiation represents the entire electromagnetic
spectrum consists of highly energetic gamma rays followed
by x-rays, ultraviolet, visible light, infrared, microwave and
weak radio waves. These radiations described in terms of a
stream of massless particles called photons, travels at the
speed of light and contain a definite amount of energy.
Radiations are differentiated based on the amount of energy
available in the photons [7]. A part of the electromagnetic
spectrum is shown in Fig. 1.
380-720 nm. Light consisting of shorter wavelength (e.g.
blue light) contains high energy photons, and longer
wavelength (e.g. red light) contains low energy photons.
III. PHOTOVOLTAIC (PV) TECHNOLOGIES
Photovoltaic cells are semiconductor devices which
convert energy of light into electricity. A semiconductor is a
substance, usually a simple element or a compound, that can
conduct electricity under some conditions but not always,
making it a good medium for the control of electric current.
Silicon, a group IV element, is the most commonly used
semiconductor for PV cells. Other materials from a
combination of group III and group V (called III-V semiconductors), or from group II and group VI (called II-VI
semiconductors) are also used. Examples of compound
semiconductors: GaAs (Gallium Arsenide), GaP (Gallium
Phosphide), AlAs (Aluminum Arsenide), AlP (Aluminum
Phosphide) and InP (Indium Phosphide). The conduction
property of pure semiconductor is altered by a process called
doping to produce p-type and n-type material. A PV cell is
made up of combining p-type and n-type semiconductors.
Schematic of a PV cell is shown in Fig. 2 and its working
is as follows. When photons hit the p-n junction (Fig. 3),
electrons are knocked loose from the valence band and
raised to the conduction band overcoming the band-gap
energy, Eg. (The valence band is the highest range of
electron energies in which electrons are not free to move
and the conduction band is the lowest range of electron
energy in which they are free to move). In case of silicon,
the energy gap is 1.12 eV. That means photons with energy
level 1.12 eV and above will result in cell current, while
energy level below 1.12 eV will pass through without
absorption. The lifting of electron from valence band to
conduction band results in a hole in the valence band. The
free electrons in the conduction band and holes in the
valence band are responsible for the current flow, when the
PV cell is connected across a load.
Fig. 2. Schematic of a PV Cell.
Fig. 1. Electromagnetic Spectrum.
The energy of photons in electron volt (eV) is related to
the wavelength of the radiation. Gamma-rays have the most
energetic photons whereas radio waves have photons with
low energies. Wavelength of visible light ranges between
Fig. 3. Energy bands.
A cell is the basic building block of a PV system with
power output of around 4 W. To get higher outputs, many
cells are connected in series to form a module. A module
may have 48, 60, 72, or higher number of cells in series. For
higher power outputs, modules are connected in series and
parallel as arrays. Fig. 4 shows a typical PV cell and a
module. Data sheet of a 72 cell module is shown in Table 1.
2
Fig. 4. A single cell and a 72 cell crystalline PV module.
Table 1. Datasheet of a Solar PV Module
Maximum Power, Wp (P max)
295
W
No of cells per module
72
no.
Voltage at Pmax (Vmax)
36.4
V
Current at Pmax (Imax)
8.11
A
Open-circuit voltage (Voc)
44.9
V
Short circuit current (Isc)
8.76
A
Temp. coefficient of Isc (α)
0.0681
%/oC
Temp. coefficient of Voc (β)
-0.2941 %/oC
Temp. coefficient of P max (γ)
-0.3845 %/oC
o
NOCT (Nominal Operating Cell Temp.) 46 ± 2
C
Efficiency
15.2
%
Fill-Factor (FF)
0.73 – 0.78
The PV datasheet values are derived at STC (Standard
Test Conditions). STC represents; irradiance: 1000 W/m2,
module temp.: 25 °C, wind speed: 0 m/s, AM 1.5, and light
incidence angle: 0°. Air mass (AM) represents the optical
path length of the Earth's atmosphere. At sea level during
mid-day, AM is 1.0. AM 1.5 means the light has to travel
atmospheric depth of 150% than that at mid-day.
Basic arrangement of a PV based power generation
system is shown in Fig. 5. Major components of the system
are: PV array, inverter(s), a step up transformer in case of
high voltage grid connection and optional trackers.
Fig. 5. Basic arrangement of a solar PV generation system.
A PV system generates DC power, which is converted
into AC power by using centralized inverters, commonly
called String Inverters. In a 1000 V inverter, a string may
have 18 to 20 modules connected in series to get around 650
to 750 V DC. These inverters may be of transformer-based
(TB) or transformer-less (TL) type. TL inverters are more
compact, lightweight and have higher efficiency 97%
(nearly 2% more than TB inverters). Latest PV inverters use
a control philosophy called maximum power point tracking
(MPPT) to optimize the PV power output. Maximum power
point represents a unique point on the Current-Voltage (I-V)
and the Power-Voltage (P-V) curves at which a PV module
produces its maximum power corresponding to the available
solar radiation. The location of MPP is searched using
complex algorithms. TL inverters usually have two MPPT
trackers as against one MPPT in TB inverters.
For representing the electrical behaviour of a PV cell, it
is usually modeled as an equivalent circuit consisting of a
photo-current source (Iph) in parallel with a single diode D
(or two diodes for more detailed analysis), a shunt resistor
(Rsh) and a series resistor (Rs) in the load branch [9]. The
single diode model (shown in Fig. 6) is used by the
manufacturers to represent the PV data. The I-V and P-V
characteristics of a PV module are shown in Fig. 7.
Fig. 6. Single-diode model of Fig. 7. Current-Voltage & Powera solar PV cell.
Voltage curves of a PV module.
A wide range of PV technologies are currently available.
Popular among them include silicon based mono and poly
crystalline, thin-film technologies of amorphous silicon (aSi), cadmium telluride (CdTe), copper-indium-galliumdiselenide (CIGS), multi-junction & emerging technologies
such as Organic PV (OPV) and Concentrating PV (CPV)
technologies. PV types differ according to the material,
manufacturing process, efficiency and cost. Crystalline
silicon modules represent about 85% of the global PV
market. Space requirements for crystalline PV are around 7 8 m2/kW (4.5 - 5 acres/MW) and for thin-film PV, it is
around 10 - 15 m2/kW (9 - 10 acres/MW) [10]. Table 2
shows a comparison of common PV technologies.
Table 2. Comparison of Common PV Technologies
Mono-Si
Poly-Si
Thin Film
Most efficient Less efficient Least efficient
Efficiency
(18 - 22%)
(14 - 18%)
(10 - 12%)
From single
By fusing Si
Many layers
Manufacturing
Si crystal
crystals
of PV material
Standard
Moderately
Suitable for
High temp.
temperature
high temp.
Area need/kW
Least
Less
Large
Energy yield
Hi due to high Hi due to high Lo due to low
per unit area
Si content
Si content
Si content
Performance
Low
Low
Moderate
at low light
Gap between
15 - 20%
15 - 20%
22 – 28%
Voc and Vmp (less is better)
Temperature
Low
High
High
Coefficients
(Lo is better)
70 - 80%
Fill-factor
70 - 80%
60 - 68%
(Hi is better)
Several factors affect the energy efficiency of a PV cell.
These are: wavelength (colour) of the light, cell temperature,
surface reflection and recombination of holes and electrons.
The theoretical maximum energy conversion efficiency
possible for a single junction PV cell is limited by the
Shockley-Queisser (SQ) limit, which is 33.7% [11]. As
reported in the “Solar Cell Efficiency Tables (version 49)”,
as of Nov. 2016 under STC, the highest efficiency reported
for single-junction mono-crystalline Si was 26.3 ± 0.5%
with fill-factor (FF): 83.8% and for poly-crystalline; it was
21.3 ± 0.4% at FF: 80% [12]. An efficiency of 28.8 ± 0.9%
was reported for GaAs (thin film) at FF: 86.5%. Breakup of
various losses in a typical solar PV cell with an overall
conversion efficiency of 17% is shown in Fig. 8 [13].
Fig. 8. Energy conversion efficiency and losses in a PV cell.
3
For improving the efficiency of a PV cell over the SQ
limit, several means are being tried. These include: (i) use of
more than one semiconductor material in a cell, (ii) use of
more than one junction in a cell, in which energy of
individual colour of lights is absorbed by using a different
material, (iii) concentrator photovoltaics (CPV) in which
lenses and mirrors are used to focus sunlight onto multijunction cells and (iv) PV-thermal hybrid collector (PVT),
which converts solar radiation into heat and electric energy.
IV. FACTORS AFFECTING PERFORMANCE OF PV SYSTEMS
The outdoor performance of a PV module is influenced
by many factors. Some of these issues are related to the
module itself and others are related to the location and
environment. Few of these major factors are: material
degradation, solar irradiance, module temperature, parasitic
resistances, fill-factor, shading, soiling, PID, tilt-angle etc.
a. Degradation of PV Module
Manufacturers of solar PV systems usually guarantee the
performance life of 25 years for the modules. As shown in
Fig. 9, warranty curve typically promises that the modules
will generate at least 90% of rated capacity in the first 10
years and around 80% in the next 10-15 years.
Solar PV panels usually degrade at a faster rate in the
first few years of their life. In general, rated power output of
solar panels typically degrades at about 0.5%/year. Thinfilm PV modules (a-Si, CdTe and CIGS) degrade faster than
Si crystalline based modules [14]. These degradation
processes may be chemical, electrical, thermal or
mechanical in nature. Table 3 shows the average yearly
output loss reported in various PV module technologies,
which were manufactured after year 2000. Early degradation
of PV modules may be due to design flaws, poor quality
materials or manufacturing issues. In most cases, module
failures and performance losses are due to gradual
accumulated damages resulting from long-term outdoor
exposure in harsh environments.
Fig. 9. Life span of a typical solar PV module.
Table 3. Average Yearly Output Loss of PV Cells
Output loss
PV Cell Type
(%/year)
Monocrystalline Silicon (mono-Si)
0.36
Cadmium Telluride (CdTe)
0.4
Polycrystalline Silicon (poly-Si)
0.64
Amorphous Silicon (a-Si)
0.87
Copper Indium Gallium Selenide (CIGS)
0.96
b. Variation in Solar Radiation
The performance of PV modules under varying light
conditions will differ significantly, which in turn has a
severe impact on the yield of PV systems. Variations in the
intensity of solar radiation falling on a PV module affect
many of its parameters, including Isc, Voc, power, FF and
efficiency. Fig. 10 shows the current, voltage and power
output of a module with varying irradiance.
Fig. 10. Impacts of variations in Irradiance on the Current and
Output Power of a PV module.
c. Module Temperature
A PV cell, like any other semiconductor device, is very
sensitive to temperature. The efficiency and power output of
a PV cell reduces with increase in its temperature. This is
mainly due to the increase in internal carrier recombination
rates caused by increased carrier concentrations. The
temperature of a PV module increases with increasing solar
radiation and air temperature but reduces with increasing
wind speed. During summer noon time when the irradiance
is very strong, PV module temperatures may reach 60-65 ºC.
The impacts of temperature on current, voltage and
power output of PV cell are shown in Fig. 11. From the
normalized values of current, voltage and power at 25 oC,
with increase in temperature, cell current increases slightly,
but voltage drops at larger rate, leading to the larger drop in
the power output. If cell temperature falls below 25oC, the
current falls slightly but voltage and power increases. In
general, up to about 0.5% loss of efficiency per degree
Celsius increase in temperature is typical in silicon cells.
Fig. 11. Impacts of temperature on a PV cell performance.
The voltage Voc decreases by about 0.1 to 0.3 V for each
degree K rise in temperature and current Isc increases by
about 2.3 to 4 mA/K. With increase in cell temperature, the
reduction in voltage is much more than the corresponding
increase in current. The overall effect of this is a reduction
in the power output at a rate of about 0.4 to 0.5% per degree
rise in temperature. These impacts are shown in Fig 12. The
temperature coefficients of current, voltage and power of
few crystalline silicon PV modules of different make
installed in NTPC stations are shown in Table 4.
Fig. 12. Impact of cell temperature on the I-V and P-V
characteristics of a 240 Wp PV module.
Table 4. Comparison of Temperature Coefficients of PV Modules
P‟Blair
235
Mono
2.28
Current
mA/K
Temp.
-133.26
Voltage
Coeff.
mV/K
-0.4846
Power
%/K
Location
Rating (Wp)
Module Type
Dadri
240
Poly
4.4
mA/K
-123
mV/K
-0.47
%/K
F‟Bad Singrauli
230
240
Poly
Mono
0.05
0.04
%/K
%/oC
-0.34
-0.35
%/K
%/oC
-0.43
-0.42
%/K
%/oC
PMI
295
Poly
0.068
(%/oC)
-0.294
(%/oC)
-0.384
(%/oC)
4
The level of impacts of temperature on PV modules will
vary depending upon the type of semiconductor used. To
reduce the temperature related issues on PV modules, the
following aspects could be considered.
i. Keep sufficient gap between the modules and the roof
(or ground) to allow convective air flow to cool them.
ii. Ensure that panels and supporting structure are of lightcoloured so that heat absorption will be less.
iii. Use perforated base structure to increase cooling.
iv. Do not keep inverters below and close to the modules.
v. Use cooling fans
In a rooftop PV system mounted close to the roof floor,
the module temperature may reach about 150% of the
ambient temperature, whereas in a properly ventilated
system, such as a pole mounted module, the rise in
temperature will be in the range of about 120%.
d. Fill-Factor
The fill-factor of a PV cell is defined as the ratio of the
maximum power to the product of Voc & Isc. Based on the IV curve shown in Fig. 13a, fill-factor can be represented as
Fill-Factor 
Vmax . Imax
area A

Voc . Isc
area B
(1)
Graphically, fill-factor is a measure of the squareness of
the PV cell and is also the area of the largest rectangle
which will fit in the I-V curve. A good quality PV module is
expected to have fill-factor above 70%. A lesser fill-factor
indicates larger value of Rs or lesser value of Rsh, increased
recombination current in the space charge region and
increased reverse saturation current of the junction Io, all
these conditions representing increased losses. Increasing
cell temperature reduces the fill-factor as shown in Fig. 13b.
monitoring the quality and evaluating the performance of a
PV system. PV module data sheets usually do not provide
the values of Rs and Rsh, but they can be calculated. Table 5
shows the calculated values of Rs and Rsh for few of the PV
modules used in NTPC stations.
Table 5. Calculated values of Parasitic Resistances of PV Cells
PMI
P‟Blair Dadri F‟Bad Singrauli
Power (Wp)
295
235
240
230
240
Silicon Type
Poly
Mono
Poly
Poly
Poly
No. of cells
72
60
60
60
60
Rs/cell
6.610
7.017 7.383
7.15
(m) 7.181
Rsh/cell ()
4.529
3.674
3.535 3.818
3.543
f. Shading
Shading results in mismatches in the generated currents
of individual cells of a module. Even partial shading on a
single cell can significantly reduce the power output of the
entire module as if all the cells were shaded. A shaded cell
produces much less current than the unshaded ones. Since
cells in a module are connected in series, same current has
to flow through all the cells. If more current than the shaded
capability is forced through a shaded cell, it will be overheated and might be damaged.
A common solution to avoid hot-spot heating of PV cells
due to shading is by using Bypass Diodes. A bypass diode is
connected across a sub-string of cells in the module. During
normal operation with uniform light falling on each cell, the
bypass diode will acts as an open switch. However, when
current mismatches occur due to shading, the diode
connected across the shaded sub-string will act as a closed
switch and thus bypasses that sub-string. PV modules with
60 or 72 cells usually have 3 bypass diodes (Fig. 15a).
Another outcome of shading of PV cells is the distortion
of the I-V and P-V curves, shown in Fig. 15b. This results in
inefficient operation of string inverter MPPT controller.
(a)
(b)
Fig. 13. a. Fill-factor of a module, b. Impact of temperature on FF.
e. Parasitic Resistances
The series and shunt resistances of a PV cell, called
Parasitic Resistances, results in increased I2R losses, which
eventually results in reduced module efficiency. The series
resistor (Rs) represents the internal resistance of the PV cell.
It comprises of the resistance of metal contacts, fingers,
impurities, and resistance of the semiconductor itself [15].
The shunt resistor (Rsh) represents the leakage resistance and
is responsible for the leakage current. The impacts of Rs and
Rsh on the I-V curve of a PV cell are shown in Fig. 14. The
resulting reductions in area of the I-V curve leads to a
reduction in fill-factor, and thereby drop in cell efficiency.
Fig. 14. Impacts of parasitic resistances on I-V characteristic.
For optimum performance of a PV module, Rs must be as
low as possible and Rsh must be as high as possible. The
knowledge of these resistance values is important for
Fig. 15a. Arrangement of
bypass diodes in a PV module.
Fig. 15b. Shaded array
string I-V and P-V curves.
In string inverters many series connected modules are
treated as a single unit (Fig. 16a). The MPPT controller in
these inverters is at the string level and it responds to the
least efficient module of the string. This will leave some
modules operating below their MPP, leading to loss of
efficiency. The solution to correct this issue is that the
MPPT algorithm must take into account the entire voltage
range of the string in order to detect the presence of a global
maximum instead of local maximum. Inverters with this
capability are known as the Shade-Tolerant String Inverters.
A Micro-Inverter is another effective solution to reduce
the negative impacts of partial shading. In this scheme (Fig.
16b), each module has its own inverter that is connected in
parallel to the common AC bus. Due to parallel connection,
mismatches in currents between different modules will not
be an issue. Micro-inverters are usually connected below
each module. They feature the MPPT at the module level
which increases array production by about 20%. However,
micro-inverters are more expensive than string inverters.
5
(a)
(b)
Fig. 16. Arrangement of a). String Inverter and b). Micro-Inverter.
g. Soiling
Soiling is the accumulation of dust, dirt, and other
contaminants on a PV module. It leads to the formation of a
thin screen over a module and thus reduces the light falling
on one or many cells. Dust represents minute solid particles
of diameter less than 500 μm. Dust settlement depends on
factors such as dust properties (shape, size, weight), weather
conditions (rain, humidity, snow), location (coastal or dusty
area), module tilt angle, surface finish and wind speed.
Permanent soiling can occur if humidity condensate sticks
dust to the surface, particularly at the bottom of a tilted
module. Collection of dust and the growth of lichens along
the module frame produce partial shadings on the bottom
row cells and may damage the coating and seals.
Soiling in PV system may result into an annual power
loss of 5-17% or more. At PMI-Noida premises (lati: 28.54o
N, module tilt: 25o), after an exposure period of 2 weeks
without cleaning, nearly 10% reduction in PV output was
noticed during April-May months. Impacts of dust will be
higher near highways and desert areas but will be less in
areas with frequent rains. A rooftop PV system experiences
lesser soiling losses as compared to a ground mounted
system. The impact of different densities of dust on the
radiation received by a PV module and the reduction in the
maximum power under dust with respect to that of the clean
module is shown in Fig. 17a & Fig. 17b, respectively [16].
Fig. 17. Impact of dust density on solar radiation & PV output.
Smaller size dust such as engine exhaust, cement etc.
results in larger performance loss as against larger size dust.
For the same dust type, finer particles have greater impact
than coarser particles. This is due to the greater ability of
finer particles to reduce the inter-particle gap and thus
blocking the light path more than that for larger particles.
Power losses due to soiling of PV modules can be greatly
reduced by regular cleaning. Many methods are available for
PV cleaning. This include: manual washing, cleaning robot,
self-cleaning glass, electrostatic curtain etc. The simplest
among these is by regular wiping and cleaning with water.
The frequency of cleaning will vary depending up on the
location, season and module mounting. Soiling is a major
factor for increasing O&M expense of PV plants.
h. Potential Induced Degradation
Potential Induced Degradation (PID) is a performance
degradation mechanism in PV systems due to stray currents,
leading to gradual loss of power up to 30% or more. PID
generally occurs in PV systems with ungrounded inverters.
There are two issues with PID: i) loss of useful generated
power and ii) degradation of the front surface passivation,
leading to increased recombination and cell damages. PID
occurs only a few years after installation of the PV system.
In a PV string with 15-20 modules connected in series to
raise the DC voltage, some cells in the end-string modules
will experience large potential difference (V) with respect
to the module frame, which is at ground potential. This V
can cause some electrons from the PV cells to go free and
discharge through the grounded frame, leading to leakage
current flow through the encapsulant (insulation) and glass.
Various paths for leakage current from cells to grounded
frame are shown in Fig. 18. The outcome of PID is a drop in
the shunt resistance Rsh of a PV module, which will reduce
the maximum power point and open circuit voltage, leading
to a reduction in the fill-factor and cell efficiency. This is
shown in Fig. 19. The impact of PID will be accelerated at
higher temperatures and when the top glass becomes wet
and conductive during high humidity conditions.
Fig. 18. Paths of leakage
currents due to PID.
Fig. 19. Impacts of PID on PV
cell performance.
i. PV Module Orientation and Tilt Angle
In locations in the northern hemisphere (e.g. India), PV
modules must be oriented towards the true south, which is
different from magnetic south shown by a compass. In other
directions, there will be some blocking by shade and hence,
as shown in Fig. 20, the intensity and duration of sunlight
will vary significantly. A module oriented northward will be
always under some shade and its impact will be more severe
during winter. This is the worst case and must be avoided.
1. Poor location
(some shade always)
2. Good location
(shade in the
morning
& evening)
3. Excellent location
(never in shade)
Fig. 20. Impact of shade due to orientation of a PV system.
At solar noon (Sun is at its highest elevation in the sky),
Sun radiation striking the earth is most intense. During other
periods, the radiation strikes at a lesser angle. This causes
the energy to be spread over a larger surface area, leading to
a reduction in its intensity (Fig. 21). If the Sun is at 45°, the
surface area covered is 40% more and the intensity is
reduced by 30% than the area covered by an angle of 90°.
For capturing optimum solar energy, a PV module must
always point to the direction of the Sun so that the incident
light will be perpendicular to the module. However, this will
not be always possible due to the daily and seasonal
6
variations in the Sun‟s position. By using single axis
trackers, PV performance can be optimized against daily
variations in Sun‟s position from morning to evening and by
using dual axis trackers, performance can be optimized
against both daily and seasonal variations.
Module tilt angle is the angle between a PV module and a
horizontal surface. For small scale PV systems, modules are
usually fixed at some inclination. Several algorithms are
available to calculate the optimum tilt angle [17]. As a rule
of thumb, tilt angle is generally set at  ±15o, where,  is the
latitude angle, „+‟ for winter and „-‟ for summer period.
During the months of March and September, tilt angle will
be almost same as latitude angle; while during summer, tilt
is to be decreased and during winter, it is to be increased.
Adjusting module tilt twice a year produce more output than
a completely fixed system, and adjusting tilt four times a
year produces little more energy. For further optimization,
the tilt angle setting for different seasons is given in Table 6.
Table 6. Calculation of Optimum Module Tilt Angle
Period
March / Sept.
Winter
Summer
Tilt Angle Setting
Latitude - 2.5o
(Latitude x 0.9) + 29o
(Latitude x 0.9) - 23.5o
Tilt at Noida
26o
54.7o
2.2o
The suggested module tilt angle during various seasons at
Noida (lati: 28.57o N) is shown in Fig. 22. In some PV
designs, provision is available to change the angle manually
in steps. For example, in the 5 MWp PV plant of NTPC at
Port Blair (lati: 11.67o N), three slots are provided for
manual tilting in steps of 12.5o, i.e., +12.5o and -12.5o,
where,  is the latitude in degrees.
preserve water for evening peaks and summer periods. This
will also help in saving transmission cost of PV power due
to the already available lines of the hydro station. In Brazil,
work is in progress to install 350 MW floating PV array at a
dam in Amazon [18]. In India, few small scale canal-top PV
systems are already in service. At present 50 MW canal-top
and 50 MW canal-bank PV projects in India are in different
stages of execution, spreading in 8-states: A.P., Gujarat,
Karnataka, Kerala, Punjab, U.P., Uttarakhand and W.B [19].
Another major step forward for clean energy is the Solar
Roadways by using PV panels to form a smart highway [20].
This will include: parking lots, sidewalks, motorways, cycle
paths, playgrounds, garden paths etc. The solar road is made
by covering existing roads with PV panels. These panels are
strong enough to withstand heavy vehicles and are skidresistant to reduce accidents. The Netherlands had installed
the world‟s first solar road (a 230 feet cycle path) in 2014
and the French government is planning to install solar PV
panels on 1000 km of road over the next five years.
Research level efficiencies of many PV technologies
have been published by National Renewable Energy Lab.
(NREL), USA [21]. This includes (i) multi-junction cells,
(ii) single-junction gallium arsenide, (iii) crystalline silicon,
(iv) thin-film technologies, and (v) emerging PVs. The list
covers 26 types with the highest efficiency of 46% reported
for multi-junction cells. Though many new cell technologies
are being developed, increasing efficiency of the established
technologies is the best solution for PV cost reduction.
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Fig. 21. Impact of
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V. WAY FORWARD IN SOLAR PV AND CONCLUSIONS
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One major drawback associated with solar PV systems is
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PV systems require large areas to the tune of 10 times as
compared to a thermal power plant. In order to limit the use
of land space for harnessing solar energy, new concepts
such as floating PV system, solar roads etc. are emerging.
Floating PV systems, also known as floatovoltaics, are
installed over water bodies such as lakes, ponds, reservoirs,
canals etc. Countries such as Japan, Brazil etc. are already
having few MW level floatovoltaics. A floating PV system
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body. The reported increase in generation from a floating
PV is about 10% as compared to identical land based
systems. Besides, the impacts of dust will be less severe on
water bodies. Additionally, PV panels over the water bodies
will reduce the water evaporation and limit algae growth.
Further advantage of floating PV system, if installed over
large water reservoirs of hydro power plants, is that PV can
supplement hydro power during day time and thus helps to
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Published in: Energy
Scan
A house journal of Corporate Planning, NTPC Ltd.,
issue 27, pp. 2-8, Feb. 2017, New Delhi.