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Choosing the right inverter for grid-connected PV systems
Article · January 2004
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PHOTOVOLTAICS
Choosing the right inverter
Inverters are a key
component in the
production of electricity
with grid-connected PV
systems, with AC–DC
conversion efficiency and
maximum power point tracking
efficiency being among the
essential parameters. In this
article, Miguel Alonso Abella and
F. Chenlo look at the most relevant
criteria for selecting a gridconnected PV inverter.
osts must be reduced and efficiencies must be
increased: these are two of the main priorities if PV
systems are to maximize their potential in carbon-free
energy generation. Much effort continues to be
dedicated to improving existing PV technology, and to
developing new ones, in order to achieve these goals.Yet there
are other, equally important considerations in PV development
that affect costs and efficiency, namely the balance-of-system
costs (‘BOS’), and inverters – a central part of grid-connected
systems.
Inverters are the power electronic devices that are directly
connected to the PV array (on the DC side) and to the
electrical grid (on the AC side), and essentially convert the DC
energy produced by the array into the AC energy required by
the grid. In addition to high efficiencies for DC–AC conversion
and maximum power point tracking, inverters should produce
AC energy at the required quality – with low total harmonic
distortion of current, a high power factor (close to unity) and
a low level of electromagnetic interference – to maximize the
transfer of energy from the array to the grid.Inverters must also
comply with safety requirements for users, equipment and the
grid itself.
The main characteristics that inverters must fulfil, and the
testing procedures that they must comply with, are covered by
the international standards IEEE 929-2000, EN 61727 and UL
1741.1–3 The other relevant standard for grid-connected
systems is IEC 60364-7-712, and there are further guidelines
and requirements applied in different countries.4–8
C
INVERTER TYPES AND SYSTEM CONFIGURATIONS
PV inverter technology has evolved rapidly over the last
decade, in line with general development in the PV sector,
The right back-up: an inverter is essential for every grid-connected
PV array SOLARWORLD
132 ● RENEWABLE ENERGY WORLD ● March–April 2004
Choosing the
right inverter
for grid-connected PV systems
PHOTOVOLTAICS
Choosing the right inverter
especially in Europe, the US and Japan. In all these regions, a
considerable number of PV installations are small-scale,
building-integrated systems, connected to the grid. These are
owned by private users, but local subsidies and incentives
support the generation of renewable energy. Over the last
decade, PV prices have dropped by 50%, and efficiency and
reliability have increased.To reduce the cost-to-efficiency ratio
further, new inverter designs have appeared in the market, as
shown in Figure 1.9–10 A general classification of inverter types
is as follows:
•
•
•
•
modular concept, in which PV string arrays are connected to
inverters in the power range 1–3 kW, to feed energy into the
AC grid in a parallel configuration. Large-scale PV installations
have also been built using string inverters, for instance at the
Mont-Cenis Academy in Germany.12
Transformerless string inverter technologies
have a growing market share in Europe
central inverters
string inverters
module integrated inverters (AC modules)
multi-string inverters.
AC module and multi-string inverters
An AC module is an integrated combination of a single solar
module13 and a single inverter. Recently,10 though, the design
concept of multi-string inverters has come onto the market,
and these are intended as an intermediate approach between
string inverters and AC modules. Multi-string inverters14–15
contain, in one unit, various independent DC–DC and
maximum power tracking converters, which feed the energy
into a common DC–AC inverter. PV strings of different nominal
data (i.e. nominal power, number of modules in each string,
manufacturer and so on), different size or different technology,
and strings with different orientations (east, south or west),
inclination or shadowing, can be connected to one common
inverter, while each working at their individual maximum
power point.
DC cabling reduction and the minimization of shadowing
and mismatch losses associated with string, multi-string or AC
module inverters are factors that are dealt with by the
simplicity and high efficiency of central inverters. One of the
unresolved questions is how AC modules can be connected to
the network.16 While connection to a regular outlet reduces
costs and facilitates installation, safety standards do not always
allow this, and utilities can be averse to the idea of having
generators connected to normal electrical sockets in users’
homes. Another factor relating to safety and regulations is
whether or not a galvanic insulation
transformer is installed (in high frequency, or
low frequency).
Central inverters
Central inverters are commonly used in large-scale PV
installations, with a power range of 20–400 kW, where PV
arrays are connected in parallel strings, and the DC–AC
conversion is centralized into one common inverter. Linecommutated inverters, based on thyristors, were originally
developed for the first grid-connected applications, but have
been replaced by self-commutated inverters using insulated
gate bipolar transistors (IGBTs), or field-effect transistors
(FETs) for low power. Pulse-width modulation (PWM) and
digital signal processing (DSP)-based conversion controllers
have improved the quality of the generated energy, with nearly
sinusoidal current output, and this avoids the use of large
reactive compensation units. Recently, inverters with a space
vector modulation control have also been implemented, and
much effort has also been focused on developing new inverter
topologies, to obtain high partial-loads efficiency.
String inverters
The string inverter concept was introduced11 onto the
European market in summer 1995 when SMA launched the
SWR 700 Sunny Boy inverter. String inverters are based on a
central inverter
AC modules
+
=
grid
=
=
=
=
=
=
=
=
=
=
=
The inverter market
–
string inverter
+
=
–
+
=
–
+
=
–
=
grid
grid
multi-string inverter
west
MPPT, DC—DC
=
–
PV—size 1
south
MPPT, DC—DC
=
DC—AC
=
–
PV—size 2
MPPT, DC—DC
=
–
east
PV—size 3
FIGURE 1. Basic design concepts for PV installations – central, string, multi-string or
AC module inverters
134 ● RENEWABLE ENERGY WORLD ● March–April 2004
grid
Of the available products – a full market
review has been published in Photon
International17 – there are more string-type
than central inverters. Furthermore,
according to world PV market forecasts,18 it is
string inverters rather than central inverters
that are likely to be the most relevant
configuration for PV grid connection in the
near future. Transformerless string inverter
technologies have a growing market share in
Europe,10 being comparable with lowfrequency (LF) inverters; the share for
high-frequency (HF) inverters is small, at
around 3%, but is also increasing.
Nevertheless, with demand for large-scale
PV systems increasing, manufacturers are at
present reporting a trend towards inverters of
a higher power range.19 Various companies
PHOTOVOLTAICS
Choosing the right inverter
also plan to offer more central inverters. One new concept is
connection of various inverters in parallel in a ‘master–slave’
relationship.10,17 In this, the master inverter controls how many
slaves are operating according to available solar irradiance,
allowing increase of the overall system efficiency at low levels
of irradiance.
Recent design concepts10 include the ‘team’, developed by
Sunny Team, ‘MIX’, from Fronius, and ‘HERIC’, developed by
Fraunhofer ISE and implemented by Sunways.20–22 All of these
are for string inverter applications,and are designed to increase
partial-load efficiencies. The ‘team’ design features several
string inverters operating in a master–slave relationship.At low
levels of irradiance, the whole array of strings is connected to
just one inverter, but with increasing irradiance the PV array is
progressively divided into smaller units, until every string
inverter is operating independently. In the ‘MIX’ concept
(Master Inverter eXchange), the string inverter includes two
power stacks placed in one housing, and, in the event of low
irradiance, the inverter works in a similar way to a smaller one
in a similar way to an inverter in a smaller system. One power
stack, the master, assumes the ‘leadership’, and the other power
stack, the slave, starts working if there are higher levels of
irradiance and one power unit cannot manage the work alone.
If the master stops working for any reason, the slave can easily
take over the master’s role, and the system will continue to
produce energy. The HERIC (Highly Efficient & Reliable
Inverter Concept) is based on a new inverter topology, which
has shown greater efficiency (97%)23 than other PWM controls.
Market share and prices
Figure 2 shows results from a market survey carried out by
Photon International;24 23 companies responded, comprising
inverter manufacturers selling products in Germany. The data
include the total sales record of both on-grid and stand-alone
inverter companies. However, it should be noted that more
than 20 manufacturers of large and small inverters were not
included: amongst these were Sharp, Sanyo, Mitsubishi and
Omron from Japan,25 US-based Xantrex,26 and European
manufacturers Mastervolt (Netherlands) and Ingeteam (Spain).
Grid-connected installations27 in 2002 totalled 144 MWp in
Japan and 22 MWp in the US, compared with 85 MWp in
Germany and 30 MWp in the rest of Europe.
DC-to-AC efficiency is the most important
parameter for grid-connected PV generation
There is wide variation in price between inverters, as the
technology used by different inverters varies considerably.
Inverter-specific costs range from €0.5/Wp for transformerless
topologies up to €2.6/Wp for AC module inverters,15 and from
€1175/kWp for a 1 kW plant to €975/kWp in a 5 kW plant.14
Considering an average price of €3.6/Wp for both
monocrystalline silicon and polycrystalline silicon PV modules,
and an average of €0.70/WAC (equivalent to €0.56/Wp) for the
inverters, the cost of the inverter represents around 16% of the
cost of PV installations with a nominal power below 5 kW.
(WAC is the amount actually fed into the AC grid, after some
losses in conversion from the Wp amount.) This 16% would
decrease to around 10% for large-scale PV plants.
TABLE 1. Guide for inverter prices for grid-connected PV applications
Nominal power < 1 kW
1–10 kW
10–100 kW > 100 kW
Price (€/kW)
1200–1800
600–1000
500–600
350–500
DC–AC ELECTRICAL EFFICIENCY
136 ● RENEWABLE ENERGY WORLD ● March–April 2004
Ot
he
rs
NK
F
Ka
co
Sp
ut
ni
k
Su
n
Po
we
r
Si
em
en
So
s
la
r-f
ab
rik
Ai
xc
on
Su
nw
ay
s
Fr
on
iu
s
SM
A
Sales (MW/year)
The DC–AC electrical conversion efficiency is the most
important parameter for grid-connected PV generation, and the
process is representative of different inverters. Of all the design
and construction characteristics of inverters, it is the use or not
of a galvanic insulation transformer that most influences the
DC–AC conversion efficiency. In some countries, local
regulations require galvanic insulation or its equivalent
between the AC on the grid side and the DC generated on the
PV side.This can be achieved using 50 Hz LF
transformers, or HF transformers. As will be
discussed later, the presence or absence of
120
110
LF or HF transformers in the inverters
100
influences not only the size, weight, ease of
installation and material costs, but also the
80
earthing and safety measures to be adopted in
70
the PV system, and the control of DC
60
injection feed into the grid.
Inverters with an LF transformer can
40
achieve DC–AC efficiency of 92%, while those
18.8
16
15
20
12
with an HF transformer typically achieve a
12.2
10.9
10.1
7.5
6
7
6.4
5.5
4.5
3 4.5 2.6 4.5 2.5 3
2.3
maximum efficiency of 94%. By removing the
0
insulation transformer, the efficiency can be
increased by two percentage points. Inverters
with HF insulation need more electronic
components than LF inverters, and in the past
2001
2002
this sometimes meant that the reliability of
HF inverters was insufficient (reliability and
FIGURE 2. PV inverter market in Germany, in MWp sold per year. Data include inverters for
on-grid and stand-alone PV systems. Units sold in 2001 were SMA: 35,000; NKF: 25,000;
number of components are usually indirectly
Fronius: 5450. Source: adapted from Photon International, March 200224
proportional parameters, especially with new
designs). However, this is no longer the case,
PHOTOVOLTAICS
Choosing the right inverter
thanks to ongoing improvements in both designs and
components.
A second point is that inverters using LF transformers
always avoid DC current injection into the grid (by definition,
an LF transformer does not allow DC current though it). For HF
transformers, therefore, it is necessary to implement DC
current measuring devices and corresponding control for the
injection of DC current. In countries such as Spain, there is
discussion as to whether the standards should allow the use of
HF inverters or not,with regard to DC current injection.Should
there ever be an inverter fault, LF inverters will never inject DC
current into the grid, but there can be a possibility of HF
inverters (in devices measuring DC current and/or control
fault) injecting DC current into the grid. The issue has been
addressed by asking the HF inverter manufacturer for
additional certification, in the event that an HF inverter may
inject DC current.
This normalized efficiency28 is usually known as European
Efficiency, ηE, and is valid for irradiance levels in central
Europe. It is defined as a function of the efficiency at defined
percentage values for nominal AC power.This is shown in the
following equation:
As an example, where this equation has η10%, it represents
the efficiency at 10% of the nominal inverter power. It is worth
mentioning that,even at this time,it is possible to find inverters
available on the market with different efficiencies, as seen in
Table 2.
It should be mentioned that ηE is an appropriate way of
describing efficiency for fixed (i.e. non-tracking) PV systems. In
some countries, the number of tracking systems is increasing
considerably – for example, almost half of the total capacity
installed in Spain with nominal power below 5 kW is mounted
on tracking systems – and in these cases, the European
Efficiency could be redefined as the efficiency value at
between 80% and 100% of the nominal power.
Inverters introduced onto the market more recently can
Rooftop PV installation at Moltkebahnhof, Aachen in Germany ERSOL
TABLE 2. Experimental inverter efficiencies for different string inverters;
values used are representative of state-of-the-art technology
AC power
Efficiency by inverter type (%)
(% of nominal) HF
LF (old
LF (new
Transformerless
technology)
technology)
5
77.5
84.8
85.1
86.7
10
85.8
90.4
88.9
91.5
20
91.0
92.0
92.3
94.2
30
93.1
92.5
93.1
94.6
50
93.8
90.9
93.4
95.0
100
93.3
90.0
92.8
94.2
ηΕ
92.3
90.8
92.6
94.2
operate at a wide range of DC voltages.The DC input voltage
also has a slight influence on the DC–AC conversion efficiency
for those inverters with a high efficiency at partial loads.
Inverter manufacturers would rather increase the DC
operating voltage to achieve better efficiency-to-cost ratios and
increase the efficiency at partial loads using low-currentcarrying semiconductors.11 That is the main reason extra-low
voltage (ELV, i.e. below 120 volts DC4,29) protection is not used,
a fact that complicates safety measures.Actually, the tendency
in Europe (though not in the US or Japan) has in recent years
been to increase the DC operating voltage; for a given inverter
design, the effect of decreasing the DC operating voltage is an
increase in efficiency, due to low self-consumption in the
control circuits. On the other hand, it is easier to design
inverters with high efficiency by increasing the operation
voltage.
MAXIMUM POWER POINT TRACKING EFFICIENCY
The DC power input to an inverter depends on which point in
the current–voltage (I–V) curve of the PV array it is working at.
Ideally, the inverter should operate at the maximum power
point (MPP) of the PV array.The MPP is variable throughout the
day, mainly as a function of environmental conditions such as
irradiance and temperature, but inverters directly connected to
PV arrays have an MPP tracking algorithm to maximize energy
transfer. The MPP tracking efficiency, ηMPPT, can be defined as
the ratio of the energy obtained by the inverter
from a PV array, to the energy obtained with ideal
MPP tracking over a defined period of time.This is
shown in the equation:
where PDC is the DC input power to the inverter
and Pm is the MPP.
Many MPP tracking algorithms have been
proposed,30 based variously on, amongst other
parameters, incremental conductance, parasitic
capacitance, constant voltage, voltage with
temperature correction, and fuzzy logic control.
Nevertheless the ‘perturb and observe’-based
algorithms are in practice the most commonly
used, due to ease of implementation. Such
algorithms are based on a perturbation of a PV
138 ● RENEWABLE ENERGY WORLD ● March–April 2004
PHOTOVOLTAICS
Choosing the right inverter
array’s operating voltage by a small increment, ∆V, after
particular intervals of time and the resulting change in power,
∆P, is measured. If ∆P is positive, then the next incremental
perturbation of voltage is positive; if ∆P is negative, the next
incremental perturbation is negative. Nevertheless, this
algorithm can have some limitations, and these can reduce the
MPP tracking efficiency in certain operating conditions.At very
low levels of irradiance – for instance, during sunrise and
sunset – the power curve becomes very flat and makes it very
difficult to distinguish the true location of the MPP. Another
factor is the impossibility of defining the exact MPP, since the
inverter ∆P oscillates around this point.The tracking algorithm
can exhibit erratic behaviour under rapidly changing
irradiance levels. Partial shadowing can also influence MPP
tracking behaviour, but this problem can be overcome by using
different times for perturbation, as a function of the power
variation in time, or by performing alternate voltage
perturbations. (See page 142 for experimental data on this.)
CURRENT TOTAL HARMONIC DISTORTION AND POWER
FACTOR
The total harmonic distortion,THD,of the current generated by
the PV inverter is regulated by the international Standard IEC
61000-3-2. Electromagnetic compatibility31–32 and ‘CE’ marking
is regulated by the EU Directives 89/336/CEE and 93/68/CEE.
Inverters for grid-connected PV systems must generate
energy at a defined quality.33–34 The standards referred to above
require a THD of ≤ 5% for the harmonic spectra of the current
waveform (measured up to harmonic number 49) while the
140 ● RENEWABLE ENERGY WORLD ● March–April 2004
THD of the voltage is lower than 2%. It is interesting to note
that, because of the high commutation frequency of the IGBT
in the inverter bridges, harmonics are presented at multiples of
that commutation frequency, which is usually much higher
than the harmonic number 50 required by the standards.The
AC power operation level for which this requirement must be
fulfilled is not actually mentioned, so is generally considered to
be the nominal power; inverters’THD output current increases
at power levels below nominal. Figure 3 presents a typical
example of the current THD being below 5% for power levels
above 50% of nominal, and considerably increasing as the
operation power decreases. The power factor, also related to
the quality of generated energy, is close to unity (≥ 0.999) for
power operation levels above 20% of nominal power in IGBTbased inverters.There are not even any technological barriers
to voluntary control of the power factor with the objective of
generating or consuming reactive energy.The improvement of
grid quality (reactive power by phase displacing and
harmonics control) has being studied more recently and
implemented35 in inverters for new, larger, centralized gridconnected PV, as for instance, in the form of Siemens SINVERT
system.
DC CURRENT INJECTION
The THD of the generated current’s waveforms is related to DC
current injection into the electrical grid via the PV inverters.
The adverse effect of DC injection into the general grid16,36 by
customers can shift the mains transformers’ operating point
towards possible saturation, which might result in high
Choosing the right inverter
100
PHOTOVOLTAICS
1.2
90
Current THD (%)
70
0.8
60
50
0.6
40
0.4
30
20
Power factor
1
80
0.2
10
0
0
0
20
40
60
80
100
AC power (% nominal power)
Power factor
Current THD
FIGURE 3. Current THD and power factor vs AC power (AC voltage
THD < 2%)
primary current that could trip the fuses and thus cause a
power outage to that section of the network. Transformer
lifetime and efficiency may also be reduced, while DC causes
cathodic corrosion of cabling.The protective operation of typeA residual current devices (RCDs)4,37 are adversely affected by
DC as well, and type-B (AC- and DC-sensitive) should be used
instead.
PV inverters usually include a large, heavy 50 Hz LF
transformer, which inherently avoids DC being injected onto
the grid and also provides galvanic insulation. LF transformers
are an important part of the total material cost of an inverter
(around 15%), as well as considerably increasing the inverter
weight and decreasing its DC–AC conversion efficiency. As a
result, manufacturers have looked at ways of removing LF
transformers in more recent years, and though the design of
transformerless inverters to avoid DC current injection does
have some technical complexities, these are being solved with
new techniques for current sensing and electronic control.
Inverters with HF galvanic insulation offer an intermediate
approach as far as safety,38 earthing and system configurations
are concerned, as the use of LF or HF – or indeed, no
transformer – has an influence on the type of device used to
protect against indirect contacts on the DC side, and the
method of installation. In any case, the manufacturers of both
transformerless and HF inverters must provide the certificates
of compliance required by the national and international
requirements. Even though LF transformers are inherently
protected (in terms of DC current injection) against any
possible inverter fault, transformerless or HF inverters depend
on an electronic control circuit for this function.Manufacturers
must guarantee that there will be no DC current injection in
the case of any possible fault, but this is a controversial point
at present that is regulated differently from country to country.
While some national standards do not make reference to the
point, others do not permit the installation of transformerless
inverters, and HF inverters are only allowed with additional
certificates.
Limits of 5 mA (0.025% of the rms output current for a
5 kW system, based on the IEC 61000-3-239) or 0.5% (UL17413)
are being adopted in the UK and US respectively.
March–April 2004 ● RENEWABLE ENERGY WORLD ●
141
PHOTOVOLTAICS
Choosing the right inverter
ISLANDING PREVENTION
Islanding40 is the electrical phenomenon that occurs in a
section of a power network disconnected from the main
supply where the loads in are entirely powered by PV systems.
Still a controversial subject in the international standardization
of grid-connected PV systems, islanding is undesirable in terms
of public safety and that of the electricity distributor’s staff, the
VARIATION IN MPP TRACKING EFFICIENCY
300
200
150
100
50
0
7:40:09
10:45:40
13:50:36
16:55:31
20:00:26
Local time
VDC (inverter)
VMPP (theoretical)
FIGURE B. MPP voltage variation along a day corresponding to Figure A.
Ideal (MPP voltage of the PV array, VMPP[theoretical]) and operation
(voltage at the inverter input, VDC[inverter]) values are presented
of the intrinsically dynamic character of the MPP tracking
algorithms. Sampling frequency and the selected period of
evaluation can seriously influence the results.
Inverters with ‘anomalous’ behaviour can reduce daily MPP
tracking efficiency to 50%–60% (meaning 40%–50% energy
losses), or even lower if the inverter stops. Daily MPP tracking
efficiency depends on irradiance profiles as well; efficiency also
decreases on windy or cloudy days, and is better on sunny
days. Table A presents a summary of test results.
afternoon
80
TABLE A. Daily measured values of MPPT efficiency from tested
inverters
Type of day
MPPT efficiency
Maximum
Minimum
Sunny days
96%
86%
Cloudy days
94%
42%
morning
60
40
20
0
0
500
1000
1500
2000
FIGURE A. MPP tracking efficiency as a function of DC operating power
for a string inverter
In this case, although there is no significant effect on energy
generation ( η MPPT = 91%), the continual stopping and starting
cycles can leave the user with a bad impression of the
technology. Inverter ‘B’ also presents operation instability, and
it is operating far from the optimal MPP voltage of the PV
generator, η MPPT= 86%. MPP tracking efficiency is often a
difficult parameter to evaluate, 9, 42 even in laboratory
conditions, by conventional monitoring systems based on data
averages over time intervals of the order of minutes, because
142 ● RENEWABLE ENERGY WORLD ● March–April 2004
DC voltage A (V)
DC power (W)
400
90
350
85
300
80
250
75
200
70
150
65
100
60
50
55
0
DC voltage B (V)
MPP tracking efficiency (%)
100
250
DC voltage (V)
Experimental daily values for η MPPT, obtained from inverter tests
in the CIEMAT PV Laboratory, are typically in the range of
80%–98%, as shown in Figure A. While there is not a great
deal of difference between products from different
manufacturers in the field of DC–AC conversion efficiency, this
is not the case for the MPP tracking efficiency. For most of the
tested inverters, η MPPT should be improved for inverter
operation at low levels of irradiance (sunrise and sunset), when
it is difficult for the inverters to find the optimal value for MPP
voltage. This can be clarified by representing it in terms of
operating and MPP voltages, as in Figure B. In some cases,
this behaviour can be improved by limiting the wide tracking
range of the MPP voltage to a narrower range close to the
possible MPP voltage variation as a function of the
configuration of the installed PV array. This can only be
performed for inverters that allow the default internal
operational parameters to be modified through the control and
monitoring software supplied. Nevertheless, choosing an
inverter for a defined installation needs to be done carefully.
Some inverters available on the market demonstrate MPP
tracking algorithms which should be considerably improved,
being the cause of considerable energy generation losses.
Figure C shows two examples of this. Inverter ‘A’ presents a
general tendency to operate close to the MPP, but shows
unstable behaviour that can cause inverter stop–start cycles.
50
Local time (arbitrary units)
VDC (operation) inverter
A
VDC (operation)
inverter B
VDC (operation)
inverter
A
VMPP (theoretical)
VDC (operation)
inverter B
FIGURE C. Inverters with MPP tracking problems
VMPP (theoretical)
Choosing the right inverter
quality of supply, and the possible damage to equipment in the
event of automatic or manual re-closure of the distribution
system to a power island. (A good recent study of the issues
can be found in Progress in Photovoltaics: Research and
Applications 2003.41) Islanding prevention is therefore also
usually included in the inverter. Passive techniques (detecting
voltage and frequency changes) are not sufficient to prevent
islanding under perfectly balanced load conditions in both
active and reactive power, and should be combined with active
techniques (based for example on frequency shift, impedance
monitoring by current injection, monitoring of phase jumps
and harmonics, positive feedback methods, or unstable current
and phase controllers). Many different prevention methods are
documented and applied, and are being improved over the
course of time, and at least 16 patents have been granted or are
still pending worldwide.41 Some of these, for example grid
monitoring by current pulse injection, have proved to be
inconvenient, particularly when there are multiple inverters
operating in parallel, degrading grid quality and having a
negative influence on detection of islanding due to mutual
interference. In other cases, the limits of voltage and frequency
operation range are extended – these parameters are usually
software configurable – by the installers, and even ENS (a
sophisticated mains monitoring device – which is mandatory
in Germany) is disabled in order to operate on weak grids.
Islanding laboratory tests42–43 as required by the standards
IEEE 929 (2000) and UL 1741,2–3 are based in resonant
simulated load circuits,44 with a defined quality factor, the ‘Qfactor’. Nevertheless, these tests are difficult to perform, especially for
high power level inverters which need large laboratory
PHOTOVOLTAICS
infrastructures.Testing circuits and their parameters vary according to
country, and test results largely depend on testers’ technical skill.
Several studies have been performed to evaluate the
probability of islanding and associated risk,41, 45 and these
conclude that, for low density of PV generation, islanding is
virtually impossible as load and generation never match.
Nevertheless, for grid sections with a high density of PV
generation, active islanding protection methods are needed in
addition to voltage and frequency control, to keep the risk of
PV introduction onto networks negligible (compared with the
estimated annual risk by electric shock without PV). Most PV
inverters incorporate both active and passive islanding
protection, but there are not many instances in which the PV
penetration in grid sections is high enough, although standard
requirements should not be relaxed in relation to this.
POWER LIMITATION OPERATION
The optimal ratio between the nominal power of the PV array
and the inverter has been largely analysed in the literature.46–47
The differences between nominal power and operation power
of the PV array require that inverters should be protected from
over-power operation – for instance when the power
generated by the array is higher than the maximum DC power
input for the inverter. Power limitation losses can be
minimized, if not considered in the PV system design and
sizing, by inverters with internal algorithms necessary to
maintain maximum DC power input – by moving input power
away from the MPP – in those cases where the PV array MPP is
higher that the inverter’s maximum input power.
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143
PHOTOVOLTAICS
Choosing the right inverter
Some other inverters on the market do not have these
power limitation features, and in such circumstances simply
stop operating, and at best try to restart after some time. Power
limitation control can be performed by different procedures,
which are in some ways inter-related, namely keeping the
temperature in the inverter bridge, the current or the working
power below maximum, predefined values. Figure 4 shows an
example of this power limitation behaviour. First when DC
power input reaches a defined value, the inverter limits the
power to a constant value. After some time, the inverter
temperature increases, and a second process is necessary to
maintain the temperature at a constant, maximum permissible
value.
SAFETY ASPECTS
contacts, or to make potential contacts safe. These include
insulation of live parts, protection by means of enclosures or
barriers, double or reinforced insulation (class II IEC 60417-1),
and use of extra-low voltage (SELP or PELV). Other methods,
meanwhile, are based on power shutdown by automatic
protection devices. Generally speaking, however, systems must
use a combination of both types of method.The effects of the
current on people will depend mainly on its intensity, its
frequency, their exposure time, their body resistance and the
contact voltage (issues covered in IEC 60364 and IEC 60479-1).
Protection of the DC side of an installation is
a controversial issue in the PV community
In contrast to conventional electricity generation, PV
generation is not centralized but distributed, and opening the
DC electrical circuit for example, will not in itself prevent the
presence of dangerous voltages. PV arrays are not readily
turned off by opening positive and negative poles at the
inverter input: as they are generally distributed across an area
on an array frame, roof, or the exterior surface of a building,
they are live while exposed to light.38
Safety measures for conventional AC electrical installations
have been widely studied48 and are fully standard. Prevention
of electric shock basically depends on the kind of earthing
system used in the distribution network (such as that defined
in IEC 60364). The most commonly used is referred to as TT
(earthed neutral). Indirect contact protection is usually performed
by RCDs, as is earthing for the frames of loads and electrical
equipment. For some special applications where a high level of
service continuity is required (for instance, in hospital
operating theatres) the IT (insulated neutral) is used,and in this
case, the first fault is secure and a permanent insulation monitoring
device (or ‘IMD’) is used to signal the risk and protect against
indirect contact. The standards have made it mandatory for
electrical installations to protect against direct and indirect
contacts. Some protection methods are designed to avoid
144 ● RENEWABLE ENERGY WORLD ● March–April 2004
DC power (W)
DC voltage (V)
The protection of the DC side of a PV installation is at
present one of the most controversial issues amongst the PV
community, in part due to the lack of explicit regulations, and
also because it is not of immediate practical concern. Some
standards are being developed that address this issue, under
IEC 62109-1 and EL-042, DR 03389,49–50 while system
configurations for earthing and insulation have also been
analysed.38,50 Different combinations of earthed and unearthed
PV arrays and inverter DC–AC insulation transformer are also
possible. In each of these, reasonable safety levels can be
achieved with regard to electric shock, fire hazard and
equipment safety, with different associated advantages and
disadvantages.
In the US, the National Electrical Code, NEC,51 requires all
PV installations with system voltages above 50 V DC to be
earthed. Ground fault protection (‘GFP’) devices are used to
measure the earth leakage current, in order to disconnect from
the ground (that is,unearth the installation),in the case of fault.
Stray leakage currents may be an issue in the sensitivity of this
protection.
Floating PV arrays and inverters with insulation
transformers are commonly used in Europe. PV
installations using extra-low voltages are
400 power break point
2300
intrinsically safe from electric shock, though
380
this does limit the number of modules that can
2100
be connected in series, and would have
360
1900
noticeable economic impact (in terms of
340
1700
temp. break point
cabling size) for relatively high power systems
320
1500
(i.e. 2.5 kWp). Furthermore, as it is easy to
300
obtain better inverter DC–AC conversion
1300
280
efficiencies at 300–500 V DC, building1100
260
integrated PV installations usually operate at
900
240
voltage levels in this range. Personnel safety
700
220
requirements are addressed by using a floating
200
500
PV array configuration combined with class II9:36:00
10:48:00 12:00:00 13:12:00 14:24:00 15:36:00 16:48:00
reinforced insulation for materials and
Time
installation and an IMD, usually with a built-in
inverter.An external device of the same type as
PDC (theoretical MPP)
VDC
the IMD used in the IT (impedance-earthed
PDC
VDC (theoretical MPP)
neutral) arrangement for standard AC
installations could also be used. Floating PV
FIGURE 4. Power limitation is performed working away from the PV array MPP as a function
array configuration is safe with respect to the
of the input power or inverter temperature
first earth fault, but requires immediate
Choosing the right inverter
PHOTOVOLTAICS
maintenance after that, as a potential second
GPB
fault cannot be made safe.At the same time,
when an insulation fault is detected
LV/MV
(between either pole or between both of
DC
them and the earth) the IMD provides a
AC
visual and/or audible alarm, and no other
(1)
action is taken. In that way, the installers
(2)
IMD
Uc
RF
pass on to the users themselves the
responsibility for immediate detection and
RG
RN
fixing of the fault, or asking the maintenance
team (if there is one) to carry this out.
During the time between a fault
FIGURE 5. Illustration of an earth fault in a PV system with floating PV array and an inverter
occurring, the operator being alerted, and
with insulation transformer. Other system earthing and insulation configurations are
the repair, the system does present a number
possible,38 and different protection devices should be used in each one. (1) is the first
of hazards. It is worth mentioning that, with
insulation fault, (2) the second; MV/LV is the medium voltage/low voltage transformer, and GPB
AC, conventional IT systems, the continuous
is the general protection box
presence of a skilled maintenance team with
the necessary equipment is required for
immediate action against the first fault.
would not in itself be completely safe, in terms of protecting
Despite the system earthing and insulation configuration, against indirect contact. Furthermore, putting the PV array in
and because of the difficulty of turning off the PV array, the an open circuit does not eliminate but increase the voltage
main questions that are raised are as follows:
source if the array is still exposed to the sun. Therefore,
additional measures should be investigated in order to increase
• what protection device or method should be used?
the degree of safety in the case of the first insulation fault, as
• what shutdown methods should be used?
this fault might be a short circuit to the ground of both of the
• where should these methods be applied?
array’s poles at the inverter input. The influence on potential
‘hot spot’ damage in the PV array should also be looked at. Hot
In the event that there is no immediate maintenance spots can be produced when the PV array short circuits to the
equipment available, the existence of an automatic device to ground, and are a risk for the PV modules.While the separation
open the PV array (and stop the inverter) at the inverter input of the PV array into small, extra-low voltage zones which can
March–April 2004 ● RENEWABLE ENERGY WORLD ●
145
PHOTOVOLTAICS
Choosing the right inverter
Grid-connected PV systems need an inverter to convert their DC output into the AC
required by the grid ISOFOTON
be opened in case of fault would increase the level of safety
incrementally, this would also considerably complicate the
installation and increase the costs.
Figure 5 illustrates the case of a system with a floating DC
side, class II-reinforced insulation, and an inverter with a
DC–AC insulation transformer.The inverter feeds the energy to
a TT electrical distribution network with the medium
voltage/low voltage (MV/LV) transformer’s neutral point
connected to the ground. An RCD should be installed in the
general protection box (GPB), in order to protect the AC side
against indirect contact. After the first insulation fault (1), the
IMD provides a visual and/or audio alarm. If a second fault (2)
happens due to indirect contact before the first is repaired, a
defined contact voltage, Uc, can be higher than the
conventional voltage limit (the maximum acceptable contact
voltage).This limit is known as the ‘safety’ voltage (IEC 60479),
UL, and is a function of the number of PV modules between the
two faults, creating an unsafe situation. In the case of the PV
array short circuiting to the ground when the first fault is
detected by the IMD, additional protection is given unless a
cable in the DC circuit is broken and there is a risk due to PV
module voltage.
frequent and can damage the inverter, while other domestic
electrical loads are not affected. Further efforts should be made
by inverter manufacturers to increase the MTFF. In some
countries, varistors (an electronic component for protecting
circuits against excessive voltage) additional to those included
in the inverter are installed on the DC side. Inclusion in the AC
side should also be investigated.
Further important aspects of maximizing the energy yields
(kWh/kWp) fed into the grid by a PV system regarding the
inverter are grid fault immunity and automatic restarting, and a
low level of self-consumption during no-load operation. Other
aspects to consider include polarity inversion protection, and
resistance to AC and DC cycling. The inverter should have a
minimal influence on the system’s number of peak sun hours
in a given location, having both high efficiency and reliability.
IN CONCLUSION
The inverter is a key element in grid-connected PV systems. Its
operational characteristics, as analysed in this article, can
influence the overall performance of the system considerably,
and two equivalent systems, with PV generators of the same
nominal power installed in the same way in a given location,
exposed to the same solar radiation, can still generate quite
different energy values if different inverter models are used.
Differences in DC–AC conversion efficiency curves are not so
relevant among inverter models, nor among manufacturers
representative of the state of the art, and essentially these
depend on the use or not of an insulation transformer and its
type. Nevertheless the maximum power tracking efficiency
can demonstrate behavioural differences, and this will cause
considerable energy generation losses on a daily basis.
Miguel Alonso Abella and F. Chenlo are respectively researcher and
head of the PV laboratory, at CIEMAT, Madrid, Spain.
e-mail: miguel.alonso@ciemat.es
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Grid-connected inverters usually have software for setting
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monitoring of such external signals as irradiance and
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capabilities in these fields.
The degree of physical protection of electrical apparatus –
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While inverters with IP65 protection can be used outdoors, it
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There have been significant improvements in PV system
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