Alonso Refs

132 ● RENEWABLE ENERGY WORLD ● March–April 2004

PHOTOVOLTAICS Choosing the right inverter

Inverters are a keycomponent in theproduction of electricity

with grid-connected PVsystems, with AC–DC

conversion efficiency andmaximum power point trackingefficiency being among theessential parameters. In thisarticle, Miguel Alonso Abella and F. Chenlo look at the most relevantcriteria for selecting a grid-connected PV inverter.

Costs must be reduced and efficiencies must beincreased: these are two of the main priorities if PVsystems are to maximize their potential in carbon-freeenergy generation. Much effort continues to bededicated to improving existing PV technology, and to

developing new ones, in order to achieve these goals.Yet thereare other, equally important considerations in PV developmentthat affect costs and efficiency, namely the balance-of-systemcosts (‘BOS’), and inverters – a central part of grid-connectedsystems.

Inverters are the power electronic devices that are directlyconnected to the PV array (on the DC side) and to theelectrical grid (on the AC side), and essentially convert the DCenergy produced by the array into the AC energy required bythe grid. In addition to high efficiencies for DC–AC conversionand maximum power point tracking, inverters should produceAC energy at the required quality – with low total harmonicdistortion of current, a high power factor (close to unity) anda low level of electromagnetic interference – to maximize thetransfer of energy from the array to the grid.Inverters must alsocomply with safety requirements for users, equipment and thegrid itself.

The main characteristics that inverters must fulfil, and thetesting procedures that they must comply with, are covered bythe international standards IEEE 929-2000, EN 61727 and UL1741.1–3 The other relevant standard for grid-connectedsystems is IEC 60364-7-712, and there are further guidelinesand requirements applied in different countries.4–8

INVERTER TYPES AND SYSTEM CONFIGURATIONS

PV inverter technology has evolved rapidly over the lastdecade, in line with general development in the PV sector,

The right back-up: an inverter is essential for every grid-connected PV array SOLARWORLD

for grid-connected PV systems

Choosing theright inverter

especially in Europe, the US and Japan. In all these regions, aconsiderable number of PV installations are small-scale,building-integrated systems, connected to the grid. These areowned by private users, but local subsidies and incentivessupport the generation of renewable energy. Over the lastdecade, PV prices have dropped by 50%, and efficiency andreliability have increased.To reduce the cost-to-efficiency ratiofurther, new inverter designs have appeared in the market, asshown in Figure 1.9–10 A general classification of inverter typesis as follows:

• central inverters• string inverters• module integrated inverters (AC modules)• multi-string inverters.

Central invertersCentral inverters are commonly used in large-scale PVinstallations, with a power range of 20–400 kW, where PVarrays are connected in parallel strings, and the DC–ACconversion is centralized into one common inverter. Line-commutated inverters, based on thyristors, were originallydeveloped for the first grid-connected applications, but havebeen replaced by self-commutated inverters using insulatedgate bipolar transistors (IGBTs), or field-effect transistors(FETs) for low power. Pulse-width modulation (PWM) anddigital signal processing (DSP)-based conversion controllershave improved the quality of the generated energy,with nearlysinusoidal current output, and this avoids the use of largereactive compensation units. Recently, inverters with a spacevector modulation control have also been implemented, andmuch effort has also been focused on developing new invertertopologies, to obtain high partial-loads efficiency.

String invertersThe string inverter concept was introduced11 onto theEuropean market in summer 1995 when SMA launched theSWR 700 Sunny Boy inverter. String inverters are based on a

modular concept, in which PV string arrays are connected toinverters in the power range 1–3 kW, to feed energy into theAC grid in a parallel configuration. Large-scale PV installationshave also been built using string inverters, for instance at theMont-Cenis Academy in Germany.12

AC module and multi-string invertersAn AC module is an integrated combination of a single solarmodule13 and a single inverter. Recently,10 though, the designconcept of multi-string inverters has come onto the market,and these are intended as an intermediate approach betweenstring inverters and AC modules. Multi-string inverters14–15

contain, in one unit, various independent DC–DC andmaximum power tracking converters, which feed the energyinto a common DC–AC inverter.PV strings of different nominaldata (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 commoninverter, while each working at their individual maximumpower point.

DC cabling reduction and the minimization of shadowingand mismatch losses associated with string, multi-string or ACmodule inverters are factors that are dealt with by thesimplicity and high efficiency of central inverters. One of theunresolved questions is how AC modules can be connected tothe network.16 While connection to a regular outlet reducescosts and facilitates installation, safety standards do not alwaysallow this, and utilities can be averse to the idea of havinggenerators connected to normal electrical sockets in users’homes. Another factor relating to safety and regulations is

whether or not a galvanic insulationtransformer is installed (in high frequency, orlow frequency).

The inverter marketOf the available products – a full marketreview has been published in PhotonInternational17 – there are more string-typethan central inverters. Furthermore,according to world PV market forecasts,18 it isstring inverters rather than central invertersthat are likely to be the most relevantconfiguration for PV grid connection in thenear future. Transformerless string invertertechnologies have a growing market share inEurope,10 being comparable with low-frequency (LF) inverters; the share for high-frequency (HF) inverters is small, ataround 3%, but is also increasing.

Nevertheless, with demand for large-scalePV systems increasing, manufacturers are atpresent reporting a trend towards inverters ofa higher power range.19 Various companies



grid

AC modules

= = = =

= = = =

= = = =

grid

string inverter

=

=

=

+–

+–

+–

grid

central inverter

=+

–

multi-string inverter

west

south

east

grid

MPPT, DC—DC

DC—AC

PV—size 2

PV—size 1

PV—size 3

=–

MPPT, DC—DC=

–

MPPT, DC—DC=

–

=

FIGURE 1. Basic design concepts for PV installations – central, string, multi-string or AC module inverters

Transformerless string inverter technologieshave a growing market share in Europe

also plan to offer more central inverters. One new concept isconnection of various inverters in parallel in a ‘master–slave’relationship.10,17 In this, the master inverter controls how manyslaves are operating according to available solar irradiance,allowing increase of the overall system efficiency at low levelsof irradiance.

Recent design concepts10 include the ‘team’, developed bySunny Team, ‘MIX’, from Fronius, and ‘HERIC’, developed byFraunhofer ISE and implemented by Sunways.20–22 All of theseare for string inverter applications,and are designed to increasepartial-load efficiencies. The ‘team’ design features severalstring inverters operating in a master–slave relationship.At lowlevels of irradiance, the whole array of strings is connected tojust one inverter, but with increasing irradiance the PV array isprogressively divided into smaller units, until every stringinverter is operating independently. In the ‘MIX’ concept(Master Inverter eXchange), the string inverter includes twopower stacks placed in one housing, and, in the event of lowirradiance, the inverter works in a similar way to a smaller onein a similar way to an inverter in a smaller system. One powerstack, the master,assumes the ‘leadership’, and the other powerstack, the slave, starts working if there are higher levels ofirradiance and one power unit cannot manage the work alone.If the master stops working for any reason, the slave can easilytake over the master’s role, and the system will continue toproduce energy. The HERIC (Highly Efficient & ReliableInverter Concept) is based on a new inverter topology, whichhas shown greater efficiency (97%)23 than other PWM controls.

Market share and pricesFigure 2 shows results from a market survey carried out byPhoton International;24 23 companies responded, comprisinginverter manufacturers selling products in Germany.The datainclude the total sales record of both on-grid and stand-aloneinverter companies. However, it should be noted that morethan 20 manufacturers of large and small inverters were notincluded: amongst these were Sharp, Sanyo, Mitsubishi andOmron from Japan,25 US-based Xantrex,26 and Europeanmanufacturers Mastervolt (Netherlands) and Ingeteam (Spain).

Grid-connected installations27 in 2002 totalled 144 MWp inJapan and 22 MWp in the US, compared with 85 MWp inGermany and 30 MWp in the rest of Europe.

There is wide variation in price between inverters, as thetechnology used by different inverters varies considerably.Inverter-specific costs range from €0.5/Wp for transformerlesstopologies 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 bothmonocrystalline silicon and polycrystalline silicon PV modules,and an average of €0.70/W

AC(equivalent to €0.56/Wp) for the

inverters, the cost of the inverter represents around 16% of thecost of PV installations with a nominal power below 5 kW.(W

ACis the amount actually fed into the AC grid, after some

losses in conversion from the Wp amount.) This 16% woulddecrease to around 10% for large-scale PV plants.

TABLE 1. Guide for inverter prices for grid-connected PV applicationsNominal 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

The DC–AC electrical conversion efficiency is the mostimportant parameter for grid-connected PV generation,and theprocess is representative of different inverters.Of all the designand construction characteristics of inverters, it is the use or notof a galvanic insulation transformer that most influences theDC–AC conversion efficiency. In some countries, localregulations require galvanic insulation or its equivalentbetween the AC on the grid side and the DC generated on the

PV side.This can be achieved using 50 Hz LFtransformers, or HF transformers. As will bediscussed later, the presence or absence of LF or HF transformers in the invertersinfluences not only the size, weight, ease ofinstallation and material costs, but also theearthing and safety measures to be adopted inthe PV system, and the control of DCinjection feed into the grid.

Inverters with an LF transformer canachieve DC–AC efficiency of 92%,while thosewith an HF transformer typically achieve amaximum efficiency of 94%. By removing theinsulation transformer, the efficiency can beincreased by two percentage points. Inverterswith HF insulation need more electroniccomponents than LF inverters,and in the pastthis sometimes meant that the reliability ofHF inverters was insufficient (reliability andnumber of components are usually indirectlyproportional parameters, especially with newdesigns). However, this is no longer the case,



Sale

s (M

W/y

ear)

120

0

20

40

60

80

100

110

70

1510.9 12

7.516

712.2

6.4 64.5 4.53 4.52.6 32.5 5.52.3

18.8

10.1

SMA

Froniu

s

Sputni

k

Sun Pow

er

Siemen

s

Solar-f

abrik

Aixcon

Sunway

sKac

oNKF

Others

2001 2002

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;Fronius: 5450. Source: adapted from Photon International, March 200224

DC-to-AC efficiency is the most importantparameter for grid-connected PV generation

thanks to ongoing improvements in both designs andcomponents.

A second point is that inverters using LF transformersalways avoid DC current injection into the grid (by definition,an LF transformer does not allow DC current though it).For HFtransformers, therefore, it is necessary to implement DCcurrent measuring devices and corresponding control for theinjection of DC current. In countries such as Spain, there isdiscussion as to whether the standards should allow the use ofHF inverters or not,with regard to DC current injection.Shouldthere ever be an inverter fault,LF inverters will never inject DCcurrent into the grid, but there can be a possibility of HFinverters (in devices measuring DC current and/or controlfault) injecting DC current into the grid. The issue has beenaddressed by asking the HF inverter manufacturer foradditional certification, in the event that an HF inverter mayinject DC current.

This normalized efficiency28 is usually known as EuropeanEfficiency, η

E, and is valid for irradiance levels in central

Europe. It is defined as a function of the efficiency at definedpercentage values for nominal AC power.This is shown in thefollowing equation:

As an example, where this equation has η10%

, it representsthe efficiency at 10% of the nominal inverter power. It is worthmentioning that,even at this time, it is possible to find invertersavailable on the market with different efficiencies, as seen inTable 2.

It should be mentioned that ηE

is an appropriate way ofdescribing efficiency for fixed (i.e.non-tracking) PV systems. Insome countries, the number of tracking systems is increasingconsiderably – for example, almost half of the total capacityinstalled in Spain with nominal power below 5 kW is mountedon tracking systems – and in these cases, the EuropeanEfficiency could be redefined as the efficiency value atbetween 80% and 100% of the nominal power.

Inverters introduced onto the market more recently can

operate at a wide range of DC voltages.The DC input voltagealso has a slight influence on the DC–AC conversion efficiencyfor those inverters with a high efficiency at partial loads.Inverter manufacturers would rather increase the DCoperating voltage to achieve better efficiency-to-cost ratios andincrease the efficiency at partial loads using low-current-carrying semiconductors.11 That is the main reason extra-lowvoltage (ELV, i.e.below 120 volts DC4,29) protection is not used,a fact that complicates safety measures.Actually, the tendencyin Europe (though not in the US or Japan) has in recent yearsbeen to increase the DC operating voltage; for a given inverterdesign, the effect of decreasing the DC operating voltage is anincrease in efficiency, due to low self-consumption in thecontrol circuits. On the other hand, it is easier to designinverters with high efficiency by increasing the operationvoltage.

MAXIMUM POWER POINT TRACKING EFFICIENCY

The DC power input to an inverter depends on which point inthe current–voltage (I–V) curve of the PV array it is working at.Ideally, the inverter should operate at the maximum powerpoint (MPP) of the PV array.The MPP is variable throughout theday, mainly as a function of environmental conditions such asirradiance and temperature,but inverters directly connected toPV arrays have an MPP tracking algorithm to maximize energytransfer.The MPP tracking efficiency, η

MPPT, can be defined as

the ratio of the energy obtained by the inverterfrom a PV array, to the energy obtained with idealMPP tracking over a defined period of time.This isshown in the equation:

where PDC

is the DC input power to the inverterand P

mis the MPP.

Many MPP tracking algorithms have beenproposed,30 based variously on, amongst otherparameters, incremental conductance, parasiticcapacitance, constant voltage, voltage withtemperature correction, and fuzzy logic control.

Nevertheless the ‘perturb and observe’-basedalgorithms are in practice the most commonlyused, due to ease of implementation. Suchalgorithms are based on a perturbation of a PV



TABLE 2. Experimental inverter efficiencies for different string inverters;values used are representative of state-of-the-art technologyAC 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

Rooftop PV installation at Moltkebahnhof, Aachen in Germany ERSOL

array’s operating voltage by a small increment, ∆V, afterparticular intervals of time and the resulting change in power,∆P, is measured. If ∆P is positive, then the next incrementalperturbation of voltage is positive; if ∆P is negative, the nextincremental perturbation is negative. Nevertheless, thisalgorithm can have some limitations, and these can reduce theMPP tracking efficiency in certain operating conditions.At verylow levels of irradiance – for instance, during sunrise andsunset – the power curve becomes very flat and makes it verydifficult to distinguish the true location of the MPP. Anotherfactor is the impossibility of defining the exact MPP, since theinverter ∆P oscillates around this point.The tracking algorithmcan exhibit erratic behaviour under rapidly changingirradiance levels. Partial shadowing can also influence MPPtracking behaviour,but this problem can be overcome by usingdifferent times for perturbation, as a function of the powervariation in time, or by performing alternate voltageperturbations. (See page 142 for experimental data on this.)

CURRENT TOTAL HARMONIC DISTORTION AND POWERFACTOR

The total harmonic distortion,THD,of the current generated bythe PV inverter is regulated by the international Standard IEC61000-3-2. Electromagnetic compatibility31–32 and ‘CE’ markingis regulated by the EU Directives 89/336/CEE and 93/68/CEE.

Inverters for grid-connected PV systems must generateenergy at a defined quality.33–34 The standards referred to aboverequire a THD of ≤ 5% for the harmonic spectra of the currentwaveform (measured up to harmonic number 49) while the

THD of the voltage is lower than 2%. It is interesting to notethat, because of the high commutation frequency of the IGBTin the inverter bridges,harmonics are presented at multiples ofthat commutation frequency, which is usually much higherthan the harmonic number 50 required by the standards.TheAC power operation level for which this requirement must befulfilled is not actually mentioned, so is generally considered tobe the nominal power; inverters’THD output current increasesat power levels below nominal. Figure 3 presents a typicalexample of the current THD being below 5% for power levelsabove 50% of nominal, and considerably increasing as theoperation power decreases. The power factor, also related tothe quality of generated energy, is close to unity (≥ 0.999) forpower operation levels above 20% of nominal power in IGBT-based inverters.There are not even any technological barriersto voluntary control of the power factor with the objective ofgenerating or consuming reactive energy.The improvement ofgrid quality (reactive power by phase displacing andharmonics control) has being studied more recently andimplemented35 in inverters for new, larger, centralized grid-connected PV, as for instance, in the form of Siemens SINVERTsystem.

DC CURRENT INJECTION

The THD of the generated current’s waveforms is related to DCcurrent injection into the electrical grid via the PV inverters.The adverse effect of DC injection into the general grid16,36 bycustomers can shift the mains transformers’ operating pointtowards possible saturation, which might result in high



primary current that could trip the fuses and thus cause apower outage to that section of the network. Transformerlifetime and efficiency may also be reduced, while DC causescathodic corrosion of cabling.The protective operation of type-A residual current devices (RCDs)4,37 are adversely affected byDC as well, and type-B (AC- and DC-sensitive) should be usedinstead.

PV inverters usually include a large, heavy 50 Hz LFtransformer, which inherently avoids DC being injected ontothe grid and also provides galvanic insulation. LF transformersare an important part of the total material cost of an inverter(around 15%), as well as considerably increasing the inverterweight and decreasing its DC–AC conversion efficiency. As aresult, manufacturers have looked at ways of removing LFtransformers in more recent years, and though the design oftransformerless inverters to avoid DC current injection doeshave some technical complexities, these are being solved withnew techniques for current sensing and electronic control.Inverters with HF galvanic insulation offer an intermediateapproach as far as safety,38 earthing and system configurationsare concerned, as the use of LF or HF – or indeed, notransformer – has an influence on the type of device used toprotect against indirect contacts on the DC side, and themethod of installation. In any case, the manufacturers of bothtransformerless and HF inverters must provide the certificatesof compliance required by the national and internationalrequirements. Even though LF transformers are inherentlyprotected (in terms of DC current injection) against anypossible inverter fault, transformerless or HF inverters dependon an electronic control circuit for this function.Manufacturersmust guarantee that there will be no DC current injection inthe case of any possible fault, but this is a controversial pointat present that is regulated differently from country to country.While some national standards do not make reference to thepoint, others do not permit the installation of transformerlessinverters, and HF inverters are only allowed with additionalcertificates.

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

Choosing the right inverter PHOTOVOLTAICS

Power factor Current THD

Curr

ent T

HD (%

)

Pow

er fa

ctor

100

0

10

20

30

40

50

60

70

80

90

1.2

0

0.2

0.4

0.6

0.8

1

AC power (% nominal power)

0 20 40 60 80 100

FIGURE 3. Current THD and power factor vs AC power (AC voltage THD < 2%)

ISLANDING PREVENTION

Islanding40 is the electrical phenomenon that occurs in asection 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 standardizationof grid-connected PV systems, islanding is undesirable in termsof public safety and that of the electricity distributor’s staff, the



Experimental daily values for ηMPPT, obtained from inverter testsin the CIEMAT PV Laboratory, are typically in the range of80%–98%, as shown in Figure A. While there is not a greatdeal of difference between products from differentmanufacturers in the field of DC–AC conversion efficiency, thisis not the case for the MPP tracking efficiency. For most of thetested inverters, ηMPPT should be improved for inverteroperation at low levels of irradiance (sunrise and sunset), whenit is difficult for the inverters to find the optimal value for MPPvoltage. This can be clarified by representing it in terms ofoperating and MPP voltages, as in Figure B. In some cases,this behaviour can be improved by limiting the wide trackingrange of the MPP voltage to a narrower range close to thepossible MPP voltage variation as a function of theconfiguration of the installed PV array. This can only beperformed for inverters that allow the default internaloperational parameters to be modified through the control andmonitoring software supplied. Nevertheless, choosing aninverter for a defined installation needs to be done carefully.Some inverters available on the market demonstrate MPPtracking algorithms which should be considerably improved,being the cause of considerable energy generation losses.

Figure C shows two examples of this. Inverter ‘A’ presents ageneral tendency to operate close to the MPP, but showsunstable behaviour that can cause inverter stop–start cycles.

In this case, although there is no significant effect on energygeneration (ηMPPT = 91%), the continual stopping and startingcycles can leave the user with a bad impression of thetechnology. Inverter ‘B’ also presents operation instability, andit is operating far from the optimal MPP voltage of the PVgenerator, ηMPPT= 86%. MPP tracking efficiency is often adifficult parameter to evaluate,9, 42 even in laboratoryconditions, by conventional monitoring systems based on dataaverages over time intervals of the order of minutes, because

of the intrinsically dynamic character of the MPP trackingalgorithms. Sampling frequency and the selected period ofevaluation can seriously influence the results.

Inverters with ‘anomalous’ behaviour can reduce daily MPPtracking efficiency to 50%–60% (meaning 40%–50% energylosses), or even lower if the inverter stops. Daily MPP trackingefficiency depends on irradiance profiles as well; efficiency alsodecreases on windy or cloudy days, and is better on sunnydays. Table A presents a summary of test results.

TABLE A. Daily measured values of MPPT efficiency from testedinvertersType of day MPPT efficiency

Maximum Minimum

Sunny days 96% 86%

Cloudy days 94% 42%

VARIATION IN MPP TRACKING EFFICIENCY

MPP

trac

king

effi

cien

cy (%

)

100

0

20

40

60

80

DC power (W)

morning

afternoon

2000150010000 500

VDC (inverter) VMPP (theoretical)DC

vol

tage

(V)

300

Local time

20:00:2616:55:3113:50:3610:45:407:40:090

50

100

150

200

250

VDC (operation) inverter A

VDC (operation) inverter B

VMPP (theoretical)

DC v

olta

ge A

(V)

DC v

olta

ge B

(V)

400

350

300

250

200

150

100

50

0

90

85

80

75

70

65

60

55

50Local time (arbitrary units)

FIGURE A. MPP tracking efficiency as a function of DC operating powerfor a string inverter

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

VDC (operation) inverter A VDC (operation) inverter B

VMPP (theoretical)

FIGURE C. Inverters with MPP tracking problems

quality of supply, and the possible damage to equipment in theevent of automatic or manual re-closure of the distributionsystem to a power island. (A good recent study of the issuescan be found in Progress in Photovoltaics: Research andApplications 2003.41) Islanding prevention is therefore alsousually included in the inverter. Passive techniques (detectingvoltage and frequency changes) are not sufficient to preventislanding under perfectly balanced load conditions in bothactive and reactive power,and should be combined with activetechniques (based for example on frequency shift, impedancemonitoring by current injection, monitoring of phase jumpsand harmonics,positive feedback methods,or unstable currentand phase controllers). Many different prevention methods aredocumented and applied, and are being improved over thecourse of time,and at least 16 patents have been granted or arestill pending worldwide.41 Some of these, for example gridmonitoring by current pulse injection, have proved to beinconvenient, particularly when there are multiple invertersoperating in parallel, degrading grid quality and having anegative influence on detection of islanding due to mutualinterference. In other cases, the limits of voltage and frequencyoperation range are extended – these parameters are usuallysoftware configurable – by the installers, and even ENS (asophisticated mains monitoring device – which is mandatoryin Germany) is disabled in order to operate on weak grids.

Islanding laboratory tests42–43 as required by the standardsIEEE 929 (2000) and UL 1741,2–3 are based in resonantsimulated load circuits,44 with a defined quality factor, the ‘Q-factor’. Nevertheless, these tests are difficult to perform, especially forhigh power level inverters which need large laboratory

infrastructures.Testing circuits and their parameters vary according tocountry, and test results largely depend on testers’ technical skill.

Several studies have been performed to evaluate theprobability of islanding and associated risk,41, 45 and theseconclude that, for low density of PV generation, islanding isvirtually impossible as load and generation never match.Nevertheless, for grid sections with a high density of PVgeneration, active islanding protection methods are needed inaddition to voltage and frequency control, to keep the risk ofPV introduction onto networks negligible (compared with theestimated annual risk by electric shock without PV). Most PVinverters incorporate both active and passive islandingprotection, but there are not many instances in which the PVpenetration in grid sections is high enough, although standardrequirements should not be relaxed in relation to this.

POWER LIMITATION OPERATION

The optimal ratio between the nominal power of the PV arrayand the inverter has been largely analysed in the literature.46–47

The differences between nominal power and operation powerof the PV array require that inverters should be protected fromover-power operation – for instance when the powergenerated by the array is higher than the maximum DC powerinput for the inverter. Power limitation losses can beminimized, if not considered in the PV system design andsizing, by inverters with internal algorithms necessary tomaintain maximum DC power input – by moving input poweraway from the MPP – in those cases where the PV array MPP ishigher that the inverter’s maximum input power.



Some other inverters on the market do not have thesepower limitation features, and in such circumstances simplystop operating,and at best try to restart after some time.Powerlimitation control can be performed by different procedures,which are in some ways inter-related, namely keeping thetemperature in the inverter bridge, the current or the workingpower below maximum, predefined values. Figure 4 shows anexample of this power limitation behaviour. First when DCpower input reaches a defined value, the inverter limits thepower to a constant value. After some time, the invertertemperature increases, and a second process is necessary tomaintain the temperature at a constant, maximum permissiblevalue.

SAFETY ASPECTS

In contrast to conventional electricity generation, PVgeneration is not centralized but distributed, and opening theDC electrical circuit for example, will not in itself prevent thepresence of dangerous voltages. PV arrays are not readilyturned off by opening positive and negative poles at theinverter input: as they are generally distributed across an areaon 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 installationshave been widely studied48 and are fully standard. Preventionof electric shock basically depends on the kind of earthingsystem used in the distribution network (such as that definedin IEC 60364).The most commonly used is referred to as TT(earthed neutral). Indirect contact protection is usually performedby RCDs, as is earthing for the frames of loads and electricalequipment.For some special applications where a high level ofservice continuity is required (for instance, in hospitaloperating theatres) the IT (insulated neutral) is used,and in thiscase, the first fault is secure and a permanent insulation monitoringdevice (or ‘IMD’) is used to signal the risk and protect againstindirect contact. The standards have made it mandatory forelectrical installations to protect against direct and indirectcontacts. Some protection methods are designed to avoid

contacts, or to make potential contacts safe. These includeinsulation of live parts, protection by means of enclosures orbarriers, 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 automaticprotection devices. Generally speaking, however, systems mustuse a combination of both types of method.The effects of thecurrent on people will depend mainly on its intensity, itsfrequency, their exposure time, their body resistance and thecontact voltage (issues covered in IEC 60364 and IEC 60479-1).

The protection of the DC side of a PV installation is atpresent one of the most controversial issues amongst the PVcommunity, in part due to the lack of explicit regulations, andalso because it is not of immediate practical concern. Somestandards are being developed that address this issue, underIEC 62109-1 and EL-042, DR 03389,49–50 while systemconfigurations for earthing and insulation have also beenanalysed.38,50 Different combinations of earthed and unearthedPV arrays and inverter DC–AC insulation transformer are alsopossible. In each of these, reasonable safety levels can beachieved with regard to electric shock, fire hazard andequipment safety, with different associated advantages anddisadvantages.

In the US, the National Electrical Code, NEC,51 requires allPV installations with system voltages above 50 V DC to beearthed. Ground fault protection (‘GFP’) devices are used tomeasure the earth leakage current, in order to disconnect fromthe ground (that is,unearth the installation), in the case of fault.Stray leakage currents may be an issue in the sensitivity of thisprotection.

Floating PV arrays and inverters with insulationtransformers are commonly used in Europe.PVinstallations using extra-low voltages areintrinsically safe from electric shock, thoughthis does limit the number of modules that canbe connected in series, and would havenoticeable economic impact (in terms ofcabling size) for relatively high power systems(i.e. 2.5 kWp). Furthermore, as it is easy toobtain better inverter DC–AC conversionefficiencies at 300–500 V DC, building-integrated PV installations usually operate atvoltage levels in this range. Personnel safetyrequirements are addressed by using a floatingPV array configuration combined with class II-reinforced insulation for materials andinstallation and an IMD, usually with a built-ininverter.An external device of the same type asthe IMD used in the IT (impedance-earthedneutral) arrangement for standard ACinstallations could also be used. Floating PVarray configuration is safe with respect to thefirst earth fault, but requires immediate



PDC (theoretical MPP)

PDC

VDC

VDC (theoretical MPP)

DC v

olta

ge (V

)

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ower

(W)

400 power break point

temp. break point

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9:36:00 10:48:00 12:00:00 13:12:00 14:24:00 15:36:00 16:48:00

FIGURE 4. Power limitation is performed working away from the PV array MPP as a functionof the input power or inverter temperature

Protection of the DC side of an installation isa controversial issue in the PV community

maintenance after that,as a potential secondfault cannot be made safe.At the same time,when an insulation fault is detected(between either pole or between both ofthem and the earth) the IMD provides avisual and/or audible alarm, and no otheraction is taken. In that way, the installerspass on to the users themselves theresponsibility for immediate detection andfixing of the fault,or asking the maintenanceteam (if there is one) to carry this out.

During the time between a faultoccurring, the operator being alerted, andthe repair, the system does present a numberof hazards. It is worth mentioning that, withAC, conventional IT systems, the continuouspresence of a skilled maintenance team withthe necessary equipment is required forimmediate action against the first fault.

Despite the system earthing and insulation configuration,and because of the difficulty of turning off the PV array, themain questions that are raised are as follows:

• what protection device or method should be used? • what shutdown methods should be used?• where should these methods be applied?

In the event that there is no immediate maintenanceequipment available, the existence of an automatic device toopen the PV array (and stop the inverter) at the inverter input



would not in itself be completely safe, in terms of protectingagainst indirect contact. Furthermore, putting the PV array inan open circuit does not eliminate but increase the voltagesource if the array is still exposed to the sun. Therefore,additional measures should be investigated in order to increasethe degree of safety in the case of the first insulation fault, asthis fault might be a short circuit to the ground of both of thearray’s poles at the inverter input.The influence on potential‘hot spot’ damage in the PV array should also be looked at. Hotspots can be produced when the PV array short circuits to theground,and are a risk for the PV modules.While the separationof the PV array into small, extra-low voltage zones which can

(1)(2)

RF Uc

RG

IMD

DCAC

GPB

RN

LV/MV

FIGURE 5. Illustration of an earth fault in a PV system with floating PV array and an inverterwith insulation transformer. Other system earthing and insulation configurations arepossible,38 and different protection devices should be used in each one. (1) is the firstinsulation fault, (2) the second; MV/LV is the medium voltage/low voltage transformer, and GPBis the general protection box

be opened in case of fault would increase the level of safetyincrementally, this would also considerably complicate theinstallation and increase the costs.

Figure 5 illustrates the case of a system with a floating DCside, class II-reinforced insulation, and an inverter with aDC–AC insulation transformer.The inverter feeds the energy toa TT electrical distribution network with the mediumvoltage/low voltage (MV/LV) transformer’s neutral pointconnected to the ground. An RCD should be installed in thegeneral protection box (GPB), in order to protect the AC sideagainst indirect contact.After the first insulation fault (1), theIMD provides a visual and/or audio alarm. If a second fault (2)happens due to indirect contact before the first is repaired, adefined contact voltage, U

c, can be higher than the

conventional voltage limit (the maximum acceptable contactvoltage).This limit is known as the ‘safety’ voltage (IEC 60479),U

L,and is a function of the number of PV modules between the

two faults, creating an unsafe situation. In the case of the PVarray short circuiting to the ground when the first fault isdetected by the IMD, additional protection is given unless acable in the DC circuit is broken and there is a risk due to PVmodule voltage.

OTHER CHARACTERISTICS

Grid-connected inverters usually have software for settingparameters and monitoring which allow recording of systemoperation and remote on-line visualization,and this can includemonitoring of such external signals as irradiance andtemperature. Different manufacturers’ products have differentcapabilities in these fields.

The degree of physical protection of electrical apparatus –IP,as defined under IEC 60529 – is also an important parameter.While inverters with IP65 protection can be used outdoors, itis recommended that these be located out of direct sunlight,while other types of inverter need to be installed withinadditional protection boxes or even indoors.

There have been significant improvements in PV systemreliability over the past 10 years.The mean time to first failure,MTFF, of an inverter should theoretically be about 50 years,52

provided it is not exposed to excessive temperature. However,values have been reported in the range of 5–10 years52–54 – ashorter lifespan than other major PV system components,which are designed to operate in excess of 25 years. Someinverter faults, as yet not documented, seem to arise on the ACside; on some weak grids, AC over-voltages and outages are

frequent and can damage the inverter, while other domesticelectrical loads are not affected.Further efforts should be madeby inverter manufacturers to increase the MTFF. In somecountries, varistors (an electronic component for protectingcircuits against excessive voltage) additional to those includedin the inverter are installed on the DC side. Inclusion in the ACside should also be investigated.

Further important aspects of maximizing the energy yields(kWh/kWp) fed into the grid by a PV system regarding theinverter are grid fault immunity and automatic restarting, and alow level of self-consumption during no-load operation. Otheraspects to consider include polarity inversion protection, andresistance to AC and DC cycling. The inverter should have aminimal influence on the system’s number of peak sun hoursin a given location, having both high efficiency and reliability.

IN CONCLUSION

The inverter is a key element in grid-connected PV systems. Itsoperational characteristics, as analysed in this article, caninfluence the overall performance of the system considerably,and two equivalent systems, with PV generators of the samenominal power installed in the same way in a given location,exposed to the same solar radiation, can still generate quitedifferent energy values if different inverter models are used.Differences in DC–AC conversion efficiency curves are not sorelevant among inverter models, nor among manufacturersrepresentative of the state of the art, and essentially thesedepend on the use or not of an insulation transformer and itstype. Nevertheless the maximum power tracking efficiencycan demonstrate behavioural differences, and this will causeconsiderable energy generation losses on a daily basis.

Miguel Alonso Abella and F. Chenlo are respectively researcher andhead of the PV laboratory, at CIEMAT, Madrid, Spain.e-mail: [email protected]

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