Operational issues associated with

grid-connected photovoltaics

Adam Junid, Simin Li

October 13, 2008

Abstract

This report investigates operational issues associated with grid-connected

photovoltaics. Topics addressed include technical characteristics, safety,

reliabililty, optimal power transfer, power quality and inverter loadow

control and coordination. Operational issues yet to be resolved by ex-

isting standards, and possible future operational issues with respect to

Australian electricity industry restructuring are also highlighted.

1

Acknowledgements:

We thank:

• Dr Iain McGill for his help and explanations on ELEC9715 (ElectricityIndustry Operation and Control) topics

• Phil Gates of Energy Australia for sharing with us his practical experiencewith industrial grid-connected PV generation stations

• Phuong Nguyen at the UNSW School of Photovoltaic and Renewable En-ergy Engineering for her explanation of the physics behind amorphoussilicon degradation in sunlight, i.e. how sunlight causes dangling bonddepassivation (dehydrogenation) which reduces conductor mobility

2

Acronyms and Abbreviations

ANSI

American National Standards Institute, www.ansi.org

AS

Australian Standard, www.standards.org.au

ASTM

American Society for Testing and Materials

BS

British Standards

CE

Conformité Européenne

DG

Distributed Generation

MPPT

Maximum Power Point Tracking (or Tracker) [Wikipedia, 2008l]

MRET

Mandatory Renewable Energy Targets[Wikipedia, 2008k]

NEM

National Electricity Market (Australia)

PCC

Point of Common Coupling

PV

Photovoltaic

REC

Renewable Energy Certicate [Australian Government, 2005]

Std

Standard

3

THD

Total Harmonic Distortion.

VRLA

Valve Regulated Lead Acid

4

Glossary

Anti-islanding Protection

Measures and inverter-control designs done to prevent islanding [Spooner, 2001].

Conformité Européenne (CE)

A marking (CE) certifying that a product has met EU health, safety, andenvironmental requirements, which ensure consumer safety.

Distributed Generation (or On-site/Embedded Generation)

The generation of electricity from many small energy sources [Wikipedia, 2008d].

Duty Cycle

The fraction of time that a system is in an "active" state [Wikipedia, 2008e]. Italso can be seen as the fraction of energy a PV system actually supplies, relativeto a continuous supply of its rated energy.

Grid

An alternative term for an Electricity Distribution Network[AS4777-1, 2005,item 4.4, p5].

Grid-connected Photovoltaics

PV systems electrically connected to utility grids, to which they may exportpower to.

Feed-in (buyback) tari

Payment a PV generator operator receives for supplying each MWh of PV-generated electricity to the grid.

Hotstick

An electrically insulative rod or pole used by linemen to perform measurementsor tests on live lines while keeping a safe distance from it.

Initial Acceptance Period

A warranty period, typically one to two years, when new equipment is operatedand monitored for defects. Defects found within this period are to be rectiedat no additional cost to the equipment owner

Inverter

A device that uses semiconductor devices to transfer power between a d.c. sourceor load and an a.c. source or load [AS4777-1, 2005, item 4.7, p5].

5

Island (or Islanding)

Occurs when the grid is disconnected or fails and one or more grid-connectedPV system inverters maintains power supply to a section of the distributionnetwork outside the PV System consumers' installation [AS4777-1, 2005, item4.9, p5].

Maximum Power Point Tracking (MPPT)

A technique that PV inverters use to get maximum power from the PV array.Any given PV module or string of modules will have a maximum power point,which denes current that the inverter should draw from the PV array in orderto get maximum power [Wikipedia, 2008h].

National Electricity Market

The name of the Australian wholesale electricity market and associated elec-tricity transmission grid [Wikipedia, 2008g].

Photovoltaics (PV)

Solar power technology that uses solar cells to convert energy from the sun intoelectricity. Photovoltaics is also the eld of study relating to this technology[Wikipedia, 2008b].

Rejuvenation project (or Equipment Renewal project)

An engineering, construction and commissioning project to replace aging equip-ment of particular plant or generator station with newer equipment of a similarrating or capacity.

Revamp project (or Capacity Upgrade project)

An engineering, construction and commissioning project to increase the gener-ation capacity of particular plant or generator station.

Total Harmonic Distortion (THD)

A percentage measurement of power quality poorness, in terms of the ratioof distorting waveform (harmonic) magnitudes to the fundamental waveform.THD can be specied and measured for either voltage or current. Voltage THDhas the general form [Wikipedia, 2008c]:

VTHD =√

V2+V3+V4+...+Vn

V1

Abbreviations for voltage and current THD are THDV and THDIrespectively.

Valve Regulated Lead Acid (VRLA)

A type of battery technology where battery electrolyte does not require distilledwater top-up.

6

Contents

1 Introduction 15

1.1 Grid-connected PV operation: Basic issues . 17

1.1.1 Rated vs practical output . . . . . . . 17

1.1.2 Output variation with sunlight angle

and MPPT . . . . . . . . . . . . . . . . 17

1.1.3 Inverter importance and matching it

with PV array . . . . . . . . . . . . . . 18

1.1.4 Location of grid-connected PV gen-

erators . . . . . . . . . . . . . . . . . . . 18

1.1.5 Power quality and DC leakage . . . . 18

1.1.6 Safety and anti-islanding protection . 19

2 Grid-connection operation issues 20

2.1 Anti-islanding . . . . . . . . . . . . . . . . . . . 20

2.1.1 When utilities may allow islanding . . 21

2.2 Fault protection . . . . . . . . . . . . . . . . . 21

2.3 Impulse, transient and swell protection . . . . 23

2.4 Synchronisation and restart from outage . . . 24

2.5 Waiting times before restart . . . . . . . . . . 24

2.6 Power ow . . . . . . . . . . . . . . . . . . . . . 24

2.6.1 Control and power factor . . . . . . . 25

2.6.2 Metering . . . . . . . . . . . . . . . . . 25

2.6.3 Inverter eciency . . . . . . . . . . . . 25

2.6.4 Inverter auto-shuto and switch-on

strategies . . . . . . . . . . . . . . . . . 26

2.7 Loadow integration with grid . . . . . . . . . 26

2.7.1 Loadow and fault simulations . . . . 26

2.7.2 Industrial grid-connected PV: Bidding

in the NEM, derivatives, generation

ramping rates . . . . . . . . . . . . . . 27

2.7.3 Residential and commercial grid-connected

PV: Opportunity for retailers to prot

by oering competitive power buy-

back rates . . . . . . . . . . . . . . . . . 27

2.8 Harmonics . . . . . . . . . . . . . . . . . . . . . 27

2.9 Earthing and lightning protection . . . . . . . 28

2.10 Protection from the environment . . . . . . . 29

2.11 Cost . . . . . . . . . . . . . . . . . . . . . . . . 29

7

3 PV array operation issues 31

3.1 Earthing and Lightning protection . . . . . . 31

3.2 Fault and resonance protection . . . . . . . . 31

3.3 Lifespan . . . . . . . . . . . . . . . . . . . . . . 31

3.4 Eciency and degradation . . . . . . . . . . . 31

3.4.1 Variance with temperature . . . . . . 31

3.4.2 Variance with time . . . . . . . . . . . 31

3.4.3 Degradation with sunlight and time . 32

4 Overall operation practice 33

4.1 Reliability . . . . . . . . . . . . . . . . . . . . . 33

4.2 Maintenance and their costs . . . . . . . . . . 33

4.3 Monitoring . . . . . . . . . . . . . . . . . . . . 34

4.3.1 Monitoring during Initial Acceptance

periods . . . . . . . . . . . . . . . . . . 34

4.4 End-of-life disposal . . . . . . . . . . . . . . . . 34

4.5 Operation issues during repair or upgrading 34

5 Operational issues undergoing research and devel-

opment 36

5.1 Technical issues . . . . . . . . . . . . . . . . . . 36

5.1.1 Nuisance tripping and inverter response

to voltage swell, dips and frequency

deviations . . . . . . . . . . . . . . . . . 36

5.1.2 Inverter supression of its current surges

during reconnections and voltage dips 37

5.1.3 Inverter withstand of grid restart volt-

ages . . . . . . . . . . . . . . . . . . . . 37

5.1.4 DC overvoltage immunity test and

acceptance criteria . . . . . . . . . . . 37

5.1.5 DC earth fault trip function accep-

tance criteria . . . . . . . . . . . . . . . 38

5.1.6 Inverter immunity to unbalanced cur-

rent . . . . . . . . . . . . . . . . . . . . 38

5.1.7 Inverter immunity to excessive har-

monics . . . . . . . . . . . . . . . . . . . 38

5.1.8 Inverter noise and radiation limits . . 40

5.1.9 Inverter power export coordination

and control due to network constraints 41

5.1.10 Grid restoration works in a future of

grid-connected PV proliferation . . . . 41

5.2 Commercial issues . . . . . . . . . . . . . . . . 42

5.2.1 Grants and rebates . . . . . . . . . . . 42

8

5.2.2 Estimating the value of grid-connected

PV in the NEM . . . . . . . . . . . . . 43

6 Summary 48

9

List of Figures

1. Figure 1: Plots of PV module costs and amounts sold per year

2. Figure 2: MW capacity installed each year for grid-connected PV versusother technologies

3. Figure ??: Photos of grid-connected PV arrays

4. Figure 4: Grid-connected PV system setup with recommended points forTHD metering

5. Figure 5: A summary of mandatory protection functions for grid-connectedPV inverters

6. Figure 6: Cuto time limits, based on maximum and mimimum voltagesand frequencies agreed on by the local utility service

7. Figure 7: Inverter output control schematics for (a) voltage-controlled and(b) current controlled inverters

8. Figure 8: Inverter-sourced transient voltage limits upon grid disconnection

9. Figure 9: Inverter waiting (monitoring) times prior to restart

10. Figure 10: Inverter eciency curves

11. Figure 11: Inverter-sourced current harmonic limits

12. Figure 12: Voltage harmonic limits (at AC point of coupling with inverterconnected) to meet AS4777

13. Figure 13: Numbers of defects per 100 installations recorded within theGerman 1000- PV-roof programme caused by dierent EM phenomena

14. Figure 14: Inverter cost reduction between 1998 and 2002

15. Figure 15: Rule-of-thumb maintenance schedule for grid-connected PVsystems

16. Figure 16: Alternative cuto time criteria to support grid stability

17. Figure 17: IEC 61727 discriminated maximum trip time to voltage devi-ations

18. Figure 18: IEEE 929 disconnection timing requirements

19. Figure 19: Table of current distortion limits from IEEE 519

20. Figure 20: Waveforms of inverter with high AC coupling to DC node

21. Figure 21: Proposed DG monitoring and control diagram for draft IEEE1547.3 Standard

22. Figure 22: A comparison of payback times for a 2kW grid-connected PVsystem in Australia costing $26,000: Existing rebate scheme vs higherbuyback rates

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23. Figure 23: Plots of NEM demand and pricing for 23-25 September 2008

24. Figure 24: List of grid-connected PV stations and estimations of genera-tion value

25. Figure 25: Estimated annual values of grid-connected PV power

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List of relevant Standards 1

• DR 03389 Installation of photovoltaic (PV) arrays (New draft 2003)

• AS 4509.1-1999 Stand-alone power systems - Safety requirements

• AS 4509.2-2002 Stand-alone power systems - System design guidelines

• AS 4509.3-1999 Stand-alone power systems - Installation and maintenance

• AS 4777.1-2002 Grid connection of energy systems via inverters - Instal-lation requirements

• AS 4777.2-2002 Grid connection of energy systems via inverters - Inverterrequirements

• AS 4777.3-2002 Grid connection of energy systems via inverters - Protec-tion requirements

• AS 4086.1-1993 Secondary batteries for use with stand-alone power sys-tems - General requirements

• AS 4086.2-1997 Secondary batteries for use with stand-alone power sys-tems - Installation and maintenance

• IEC 60950:2001 Safety Standard for Information Technology Equipment

• IEC 61173:1992 Overvoltage protection for photovoltaic (PV) power gen-erating systems Guide

• IEC 61683:1999 Photovoltaic systemsPower conditionersProcedure formeasuring the eciency

• IEC 61724:1998 Photovoltaic system performance monitoringGuidelinesfor measurement, data exchange and analysis

• IEC 61727:2004 Photovoltaic (PV) systems Characteristics of the utilityinterface

• IEEE Std. 929-2000 - Recommended Practice for Utility Interface of Pho-tovoltaic (PV) Systems

• IEEE Std. 937-2000: Recommended Practice for Installation and Main-tenance of Lead-Acid Batteries for Photovoltaic (PV) Systems

• IEEE 1145-1990 - IEEE Recommended Practice for the Installation andMaintenance of Nicket- Cadmium Batteries for Photovoltaic (PV) Systems

• IEEE 1547-2003 - Standard for Interconnecting Distributed ResourcesWith the Electric Power System2

1Taken from web and IEEE sources [UNSW-ACRE, 2003, Lynn, 2005]2Harmonised with UL1741 in 2005[Zgonena, 2004].

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Executive Summary

Operational issues for grid-connected photovoltaics include safety, reliability,optimal power transfer, power quality, loadow coordination and commercialissues.

Safety, reliability, optimal power transfer and power quality are ad-dressed by diligent design, installation and maintenance by operations sta,which include:

• Design checks prior to installation of new PV equipment for revamp andrejuvenation projects, for example:

1. Ensuring design compatibility between existing and new PV systems

2. Checking best practice and deciding on performance and Initial Ac-ceptance criteria

3. Checking and vetting installation safety procedures

• Initial Acceptance period monitoring to ensure specications are met

• Periodic maintenance, e.g. array cleaning, continuity checks, battery dis-charge tests (if applicable)

• Logging operational performance to support cost-benet analysis for fu-ture upgrades or replacements

• Reviewing updated national standards to ensure equipment compliance

Commercial-wise, utilities have found that maintenance costs for grid-connectedPV are often expensive due to array locations at dicult to access locations,e.g. high roofs. In addition, inverter failures have been higher than expected,although the ndings are qualied by the fact that inverter selection may havebeen overly driven by initial capital cost saving priorities3. These higher than ex-pected maintenance costs and relatively lower feedback taris in Australia havecontributed to the slower penetration rate of grid-connected PV, compared toGermany and Spain (for example) [Gates, 2008].

Long-term issues of grid-connected PV loadow coordination are still being in-vestigated as more PV systems connect to grids. PV station operation costsare practically zero, and PV station operators tend to get dispatched no matterhow low the spot price4. Financial derivatives for electricity (also called swapoptions) will also reect daytime-only availability of PV systems without bat-tery banks. Inverter control of PV power output enables PV operators to oernear-instantaneous up and down-ramp times during sunlight (i.e. during thePV operational duty cycle).

Future Australian electricity market restructuring will potentially open up moreoptions for operators of small grid-connected PV systems. For example:

3This is often the case in most projects that need initial funding to be given the go-ahead.4A grid-connected industrial PV station generator operator in the NEM may choose to bid

in at negative prices to fulll derivative contract (or swap option) obligations.

13

• By oering higher buy-back rates, retailers could encourage more grid-connected PV use, and this could become a mechanism for retailers to en-courage the creation of more carbon credits under carbon trading schemes

• If retailers choose to link buy-back rates to NEM spot prices, it couldencourage even more use of grid-connected PV, and could have benecialeects such as:

1. Grid-connected PV operators installing large battery banks to boosttheir PV system's power export during high prices

2. Grid-connected PV manufacturers innovating to design inverter andbattery conditioner control to charge batteries during low spot prices5,and export more power during high spot prices [McGill, 2008, Slide35]

3. Battery-backed grid-connected PV systems operating as another bueragainst volatile NEM spot prices

4. Battery-backed grid-connected PV systems possibly being used asanother mechanism to control network ow, coordinate transmissionconstraints and possibly reduce network expenditure [McGill, 2008,Slide 21]

As grid-connected PV systems proliferate6, it is foreseen that future gridrestoration procedures may need additional safety precautions, toolsand monitoring systems, because inverter anti-islanding cuto mechanisms oralgorithms have been known to fail under certain conditions [Woyte et al, 2003].

To further address safety, reliability, optimal power transfer and power qual-ity, more work and agreement is needed for inverter standards in Australia interms of:

• Cuto timing discrimination

• Immunity to harmonics and transient surges (DC and AC side)

• Immunity to voltage swells and imbalanced current (AC side)

• Suppression of inverter-caused surges

• Immunity to grid-reconnection voltage surges

• Earth fault trip acceptance criteria (e.g. reset time)

• Noise and radiation limits

• Inverter power export coordination and control due to network constraints(e.g. draft IEEE 1547.3 Std)

• Monitoring and checking for islanding power containment in case of anti-islanding protection failure

5With charging power coming from either the PV array, the grid, or both6The probability of failure increases with the number of grid-connected PV systems in-

stalled.

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1 Introduction

Australia's grid-connected photovoltaic (PV) capacity totaled 1.15MW in 2002[Schaap, 2003]. Since 2002, commercial [Wikipedia, 2008a], industrial [EGM, 2003]and Solar City [Schroeder, 2000] residential projects have added at least an-other 2.26MW grid-connected PV capacity, reecting a general trend of in-creased PV applications:

Figure 1: Plots of PV module costs and amounts sold per year (Taken from[Antonio et al, 2002, p16]).

As a fraction of total grid generation, grid-connected PV capacity is still marginal7

however, because:

• Non-PV generators in general have much higher MW ratings

• Actual power from grid-connected PV generators are reduced by inverterineciencies [Lakeland Electric, 2000]

• Less than optimal sunlight intensities and angles result in only 20% PVduty cycle [Wikipedia, 2008d]

7In 2007 it was reported that grid-connected PV produced less than 0.1% of nationalgrid power[SMH, 2007]. But the actual gure as a percentage of installed generation capacity

is much lower at 0.005% [Tagaza, 1998]. See Section 5.2.2 for estimates of grid-connected PVcontribution to the Australian NEM.

15

Figure 2: MW capacity installed each year for grid-connected PV versus othertechnologies (Taken from [Antonio et al, 2002, p8])

Despite the above operational shortcomings, grid-connected PV appears to bea relatively fast-growing (Figure 2), attractive technology because of:

• Low maintenance cost (moving parts)

• Practically zero operational variable cost

• Zero operational emissions that contribute to RECs

• Expectations that as its technology matures, it will achieve $/MWh costscomparable to coal-red and gas turbine plants in 2020 [Owen, 2004, Table1]

• Increasing aordability [Watt et al, 2004, 2.1] and generous buyback ratesin countries like Germany and Switzerland [Nowak et al, 1998]

• It can be mounted relatively unobtrusively [Clean Energy Council, 2007](Figure 3)

While applications have become widespread in Germany and Japan [Watt et al, 2007],grid-connected PV has had relatively less penetration in Australia mainly be-cause of low-cost fossil-fuel availability to meet national energy needs. On theother hand, future emission trading (and penalty) schemes slated for Australia[SMH, 2008] will make the application of grid-connected PV much more attrac-tive in future, due to its zero operational emissions characterstic.

16

Figure 3: Photos of grid-connected PV arrays (Taken from [ESDEPS, 2002,UNSW EM, 2005]).

This report addresses grid-connected PV operational issues, in particular withinAustralia. Topics addressed below include technical characteristics (Section 1.1),safety, reliability, optimal power transfer, power quality, loadow coordinationand control (Sections 2-3) and maintenance practice (Section 4). Existing andfuture operational issues yet to be resolved by existing standards or regulationswill also be highlighted (Section 5).

1.1 Grid-connected PV operation: Basic issues

Basic characterstics of grid-connected PV that operators should be aware of aredescribed below.

1.1.1 Rated vs practical output

In practice, prior to installation, PV generation stations are rated based onsunlight prole measurements at its proposed location. In most cases, actualoutput from PV arrays falls short of design calculations to due to unnaccountedfor array geometry and other unknowns [Scoeld et al, 2002]. Poor inverter per-formance8 and unreliability [Palomino et al, 2002] may also result actual powerfed from PV arrays to the grid to be as low as 10-20% [Lakeland Electric, 2000].As technology and design standards mature, it is foreseen that inverters will be-come more reliable [Hudson et al, 2002b] and aordable to address these short-comings [Spooner, 2001].

1.1.2 Output variation with sunlight angle and MPPT

PV array power output is at maximum when normal to sunlight, and decreasesas sunlight slants away9. Operators of grid-connected PV systems may adjustPV array angles to optimise timing of peak sunlight intensity. For example,arrays may be slanted slightly westwards if maximum peak shaving contributionis required in late afternoon [Lakeland Electric, 2000]..

8This includes mis-tracking of the PV arrays' peak voltages (which are constantly chang-ing), mis-tracking of the grid's power factor, and mis-matching of the PV system and gridpower factors[Lakeland Electric, 2000].

9Active sun tracking mechanisms have also been designed[Wai et al, 2008].

17

1.1.3 Inverter importance and matching it with PV array

A important link between the PV array and the grid is the inverter, andthe operator should choose it well. PV system behavior (including reliabil-ity, safety and power quality) rely heavily it. Another crucial circuit withinthe inverter10is its MPPT, which is operates the inverting process at an op-timal voltage for maximum power conversion from DC to AC.Inverter MPPTtest algorithms may dier from model to model, but broadly they ensure op-timal power conversion [Mekhilef et al, 2004] throughout a PV array's outputdynamics [Hudson et al, 2002b].

Because PV array designs have dierent earthing and connection topologies[Spooner et al, 2008], it is essential that the inverter design be matched to thearray wiring and output parameters [Hudson et al, 2002b].11

1.1.4 Location of grid-connected PV generators

Most grid-connected PV generators appear to be concentrated at hotter, sun-nier, lower population density outback areas [Australian Greenhouse Oce, 2008].This may impact operational manpower if operations sta have to travel longerdistances to service (or revamp) the PV generator site.

1.1.5 Power quality and DC leakage

Inverters tend to produce some degree of harmonics [Xantrex, 2008] (see 2.8 be-low). While there are manufacturers claiming inverters with zero THD [SRE, 2008]and grid-friendly self-commutated inverters may have the functionality to con-trol harmonics [Ishikawa, 2002], operators planning to have PV inverters pow-ering a majority of loads at a transformer secondary side node should measureactual THD and assess its impact on sensitive loads connected to that node. Aconservative rule-of-thumb before THD may become a concern for sensitive-loadoperations is when the sum of inverter and power electronics load ratings startto exceed 1

10 th the total load demand on that node [Lakeland Electric, 2000].

10For the purpose of this report, inverter and power conditioning unit refer to the sameDC-AC converter that has an MPPT for optimal power conversion.

11Large PV array generation farms have multi-string inverters for each PV array string setfor optimal eciency should one or more arrays get shaded by clouds, etc[Batrinu et al, 2006].

18

Figure 4: Grid-connected PV system setup with recommended points for THDmetering (Taken from [ESDEPS, 2002, Final Report, Fig 4.19, p31]).

Operators and designers should also check non-zero DC current injection frominverters into the grid against AS4777 [AS4777-2, 2005, 4.9, p7]12, and take mea-sures to prevent upstream transformer core saturation13 due to this [Spooner, 2001].

1.1.6 Safety and anti-islanding protection

The most common safety concern for grid-connected PV operations is islandedPV power during utility power outages (see Section 2.1 below), or at least con-trolling its consequences. Current AS4777 practice is to cuto islanded powerfrom entering grid loads during utility trips within 2 seconds [AS4777-3, 2005].AS4777.3 also places limits on current-controlled inverter voltage transients justafter utility trips occur.

Another safety concern for older PV arrays is that internal corrosion may causeearthing leakage currents [Atmaram et al, 1991, 3.3].

12AS4777.2 DC current injection limits into the AC grid are 0.5% of the inverter's ratedcurrent or 5mA, whichever is greater.

13Saturated transformer cores will overheat and may produce excessiveharmonics[Ishikawa, 2002, 3.7, p8]

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2 Grid-connection operation issues

An important safety issue for grid-connected PV involve inverters and theirprotection systems. A summary of required inverter circuit protection functionsis as follows [Ishikawa, 2002, 4.1, p10]14:

Protection function DC side AC side

Overpower√

Overvoltage√ √

Undervoltage√ √

Overcurrent√ √

Earth Fault√ √

Frequency increase√

Frequency decrease√

Figure 5: A summary of mandatory protection functions for grid-connected PVinverters[Ishikawa, 2002, 4.1, p10]

In Australia, existing inverter design practice is to cuto power during gridpower outages, voltage swells, or o-spec frequency, as dened by the followingtable [Spooner, 2001]:

Vrms Time limit (s) Frequency Time limit (s)

< Vmin 2 < fmin 2Vmin- Vmax No limit fmin- fmax No limit> Vmax 2 > fmax 2

Figure 6: AS4777 default cuto time limits, based on maximum and mimimumvoltages and frequencies

While the more common grid-connection operation practice is described in thefollowing sections, it must be noted that in all cases, local electricity serviceprovider agreement on inverter and protection settings are required prior toactual operation [AS4777-1, 2005, 2, p4].

2.1 Anti-islanding

During grid outages, grid-connected PV systems are designed to disconnectfrom the grid to prevent loads outside the PV system receiving islanded power[Spooner, 2001]. Reasons behind anti-islanding [AS4777-3, 2005, 5, p6-8] are to:

• Protect utility grid operations personnel from electrical power hazardsduring outage restoration

14Some inverters also have built in overtemperature protection[Ishikawa, 2002, 4.1, p12]

20

• Protect grid loads from receiving ospec voltages

• Protect other utility grid customers from malfunction and/or re risksassociated with ospec voltages

• Prevent damage to the inverter when utility power gets switched back onand is out of phase with the inverter's power

Practical inverter systems built to AS 4777, IEC 61727 and IEEE 929 [Hudson et al, 2002a]have anti-islanding cuto times either factory or user settable. Apart from

anti-islanding protection activation via voltage and frequency windows, manyinverters have one or more other islanding detection methods, such as:

• Rate of frequency change monitoring [Ishikawa, 2002, 4.2, p10]

• Slip mode frequency shift monitoring [Smith et al, 2004]

• Active frequency shift monitoring [Smith et al, 2004]

• Phase displacement monitoring (also called Phase jump monitoring [Ishikawa, 2002,4.2, p10])

• Three-phase voltage drop check [Ishikawa, 2002, 4.2, p10]

• Grid impedance estimation [Ciobotaru et al, 2007]

2.1.1 When utilities may allow islanding

Islanding may be a preferred option at rural areas having high amounts of grid-connected PV and Distributed Generation [Ledwich, 2002, Slide 9]15, particu-larly if the grid-connected PV system has supporting battery banks to maintainadequate power to grid loads [Nishikawa et al, 2003, Fig. 2]. Predicted con-sequences of inverter islanding during utlility outages should be simulated byloadow analysis software before being procured and installed for operation.There should also be measures (such as switching procedures with synchronisa-tion panels at main substations) to ensure that inverters will not be damagedby out-of-phase waveforms from utility power upon grid restoration.

For constant voltage operation during grid outages, voltage-controlled invertersshould be selected for operation [Ishikawa, 2002, p5].

2.2 Fault protection

AS4777 allows fault protection16 to be implemented by inverters having protec-tion built-in (e.g. circuit device gate blocking), or appropriately rated circuitbreaker or fuse protection installed externally [AS4777-1, 2005, 5.2, p9]17. There

15The practice in Europe is that islanded inverters continue to supply power if the outputvoltage can be kept above 0.8 of the nominal voltage and the maximum harmonic distortionis less than 10%. Otherwise the inverter should disconnect automatically[ESDEPS, 2002].

16Recommended cuto time for faults (short circuit) is 5 milliseconds[ESDEPS, 2002]17It must be noted that surge tests specied by IEC are done at either a specied current

(at low voltage) or specied voltage (at low current), but none of their tests replicate theactual surge energy from a real grid. Consequently, there is still likelihood of inverter damageshould it experience large energy switching surges from a grid. Hence it is good practice toprotect already protected inverter AC sides with a suitably sized external breaker or fuseswitch.

21

are many dierent manufacturer-recommended inverter-array fault protectionschemes [Spooner et al, 2008]18, depending on manufacturer-specic earthingtopology. Typically, integrated or combined protection systems are type-testedfor the protection setup installed [SMA, 2006]. Operations sta should pay par-ticular attention to the type-testing requirements for fault protection for newor upgraded capacity equipment in revamp projects, because conventional fuseand breaker sizing19 may not work for a current controlled source such as a PVarray.

Grids with large numbers of grid-connected PV should have fault simulationand protection discrimination analysis run to check:

• Fault current contributions from voltage-controlled inverters (Figure 7a)20

• The eect a current-controlled inverter's (Figure 7b)21 low output impedancecharacteristic has on fault current levels [ESDEPS, 2002, Final Report,p64]22

• That grid-connected PV loadow responses will not delay relay action forhigh-impedance faults [Ledwich, 2002, Slide 6]

18Some manufacturers do not recommend earthing the array, some recommend earthing itvia the inverter[Spooner et al, 2008]

19Such as the sizing methods in AS3000 or IEE Wiring Rules20Voltage-controlled inveters are less common in grid-connections and more common in

standalone systems21Current-controlled inverters are more common in grid-connections22PV Arrays are a current-controlled source[Wikipedia, 2008i] and because of this, conven-

tional over-current protection systems may not work[Spooner et al, 2008].

22

Figure 7: Inverter output control schematics for (a) voltage-controlled and (b)current controlled inverters (Taken from [Rashid, 2001, p555])

2.3 Impulse, transient and swell protection

Industrial inverters are typically equipped with surge protection on the DCside [Xantrex, 2008, Ishikawa, 2002]. AS4777.2 governs grid impulse protection[AS4777-2, 2005, 4.7, p7], inverter-sourced transient suppression [AS4777-2, 2005,4.8 and Appendix C], and inverter-sourced transient suppression testing (SeeFigure 8 [AS4777-2, 2005, Table 3] below).

23

Duration, s Line-to-neutral, V Line-to-line, V

0.0002 910 15800.0006 710 12400.002 580 10100.006 470 8100.02 420 7200.06 390 6700.2 390 6700.6 390 670

Figure 8: Inverter-sourced transient voltage limits upon grid disconnection from[AS4777-2, 2005, Table 3]

Inverters without voltage swell detection and cuto may be at risk of damageshould voltage swells exceed manufacturer's specied limits for more than a fewseconds. Operators in areas prone to excessive swell magnitudes and durationsmay need to protect their inverters with appropriately rated swell protection[Current Technology, 2008, Mungkung et al, 2007].

2.4 Synchronisation and restart from outage

AS4777.3 compliant inverters will have auto-synchronization and auto - recon-nection with restored utility grid power [AS4777-3, 2005, 5.6, p8]. Inverters forthe EU market must also be able to withsand grid restart voltage surges of 1.5times the nominal voltage [ESDEPS, 2002].

2.5 Waiting times before restart

Waiting times before inverter restart (after outages, faults or low-sunlight) mayor may not be user-settable, and can vary considerably [ESDEPS, 2002]:

Restart condition Waiting (monitoring) time

Restart after low sunlight 10 seconds - 20 minutesRestart after fault or outage 5 seconds - 4 minutes

Figure 9: Inverter waiting (monitoring) times prior to restart from[Ishikawa, 2002, p9,13]

2.6 Power ow

Power ow through the inverter may be in either direction [AS4777-3, 2005, 4.3,p6], and is dependent on available PV power23, grid conditions and the grid-connected PV system setup. For example, a grid-connected PV system operated

23A recent hybrid unipolar-bipolar modulation scheme has shown that real power canstill be exported at very low PV array generation levels, by absorbing grid reactivepower[Zheng et al, 2008].

24

in conjunction with a battery bank and UPS may allow power ow from theutility grid to charge its batteries during night or low sunlight conditions. Mostinverters utilise MPPT control schemes [Cavalcanti et al, 2005, IV] to obtainoptimal power output24 through a range PV array voltages [Ishikawa, 2002, 3.8,p8].

2.6.1 Control and power factor

Inverter control of power ow and its power factor (as seen by the grid) willvary from PV system to PV system [Ishikawa, 2002, 3.5, p7]. AS4777 allows arange of 0.8 leading to 0.95 lagging [AS4777-3, 2005, 4.4, p6]25. Power factorsbeyond this range may be allowed if the local utility requires power factor controloutside this range to support local grid conditions. To prevent power factordeterioration at the PCC as seen by the grid, inverters should be designed toinject both real and reactive power [Huang et al, 2004, Section 1].

2.6.2 Metering

Power ow metering will give an indication of how much the operator is savingas well as how eciently the inverter is converting theoretical PV array powerto grid power. Detailed monitoring of grid-connected PV system performanceparameters and eciency trending will require reference to IEC 61724.

2.6.3 Inverter eciency

Inverter eciency plays a large role in long-term return on investment. SincePV arrays operate at non-maximum rated output most of the time, inverters aredesigned to operate at maximum eciency along a wide, non-maximum rangeof PV array output [Ishikawa, 2002, Fig 3.3, p8]:

24For maximum real power output, the inverter's AC current output has to be in phasewith the grid current[Chen et al, 2008, Part I].

25In practice, most PV inverters designed for utility-interconnected service operate close tounity power factor[IEC 61727, 2004, 4.7, p17]

25

Figure 10: Inverter eciency curves (Taken from [Ishikawa, 2002, p8])

2.6.4 Inverter auto-shuto and switch-on strategies

Most inverters will shuto at night or after a period of time when PV arraypower drops below a pre-set value [Ishikawa, 2002, 3.9, p9]. If inverter controlpower is from the DC side, it will shuto (and switch on) naturally. However, ifinverter control power is sourced from the AC side, it's control circuits may drawa small amount of power consumption from the grid at night [Ishikawa, 2002,3.10, p9-10].

2.7 Loadow integration with grid

2.7.1 Loadow and fault simulations

Grid operators who have PV stations grid-connected should perform loadow,fault current and protection discrimination simulations to check:

• The eect the PV systems (and future capacity upgrades) have on distri-bution system loadow and available transmission capacity

• The eect PV system transients voltages have on distribution system pro-tection devices (to prevent undesired trips)

• Various grid fault scenarios to ensure that no islanding power occurs

26

2.7.2 Industrial grid-connected PV: Bidding in the NEM, deriva-tives, generation ramping rates

Since PV station operation costs are practically zero, it behooves PV stationoperators to bid and get dispatched no matter how low the spot price is (as longas it is above zero26). Financial derivatives for electricity (also caled swap op-tions) will also reect daytime-only availability of PV systems without batterybanks. Inverter control of PV power output allows grid-connected PV oper-ators to oer near-instantaneous up-ramp and down-ramp times during theiroperating duty cycle.

2.7.3 Residential and commercial grid-connected PV: Opportunityfor retailers to prot by oering competitive power buy-backrates

The restructuring of the Australian electricity market has potentially opened upmore options for operators of small grid-connected PV systems. For example:

• By oering higher buy-back rates, retailers may be able to encourage moregrid-connected PV use. Thus higher buyback rates could become a mech-anism for retailers to earn carbon credits under a future carbon tradingscheme

• If retailers choose to link buy-back rates to NEM spot prices, it mayencourage even more use of grid-connected PV, which in the long termcould have benecial eects, such as:

Grid-connected PV operators choosing to add large battery banks toboost their PV system's power export during high prices

Grid-connected PV manufacturers innovating to design inverter andbattery conditioner control to charge batteries during low spot prices27,and export more power during high spot prices, benetting grid-connected PV owners even more

Battery-backed grid-connected PV systems behaving as a naturalhedge for retailers against volatile NEM spot prices [NEMMCO, 2008c,Item 7: Photovoltaic Feed-in Taris Project]

Battery-backed grid-connected PV systems possibly being used asanother mechanism to control network ow and coordinate transmis-sion constraints

2.8 Harmonics

Inverter-sourced current harmonic limits, governed by AS4777.2, are as follows[AS4777-2, 2005, Tables 1,2]28:

26A grid-connected industrial PV station generator operator in the NEM may choose to bidin at negative prices to fulll derivative contract (or swap option) obligations.

27With charging power coming from either the PV array, the grid, or both28The voltage harmonic limits used to type-test the inverter to check its current harmonic

limits are also in AS4777.2[AS4777-2, 2005, Table B1], and have a THDV specication of 5%.

27

Harmonic order number Limits (% of fundamental)

3,5,7,9 4%11,13,15 2%17,19,21 1.5%

23,25,27,29,31,33 0.6%2,4,6,8 1%

10,12,14,16,18,20,22,24,26,28,30,32 0.5%

Figure 11: Inverter-sourced current harmonic limits from [AS4777-2, 2005, Ta-bles 1,2]

Inverter-sourced THDV limits are often manufacturer-specic or compliant withIEEE519 [IEEE 519, 1992]. To achieve the above current harmonic limits, thegrid-connected PV system, once connected, should also meet the following volt-age harmonic limits [Spooner, 2001, 6.6]:

Harmonic order number Limit (percentage of fundamental)

3 0.9%5 0.4%7 0.3%9 0.2%

even harmonics 210 0.2%11 50 0.1%

THD (to the 50th harmonic) 5%

Figure 12: Voltage harmonic limits (at AC point of coupling with inverter con-nected) to meet AS4777 (Taken from [Spooner, 2001, 6.6])

2.9 Earthing and lightning protection

Inverters having earthing circuitry to eliminate DC current leakage will requirea good earthing connection, preferably 4Ω or less [Shell, 2002], depending onmanufacturer recommendations. As mentioned in Section 2.2 above, there aremany dierent manufacturer-recommended inverter-array earthing and faultprotection schemes [Spooner et al, 2008]29. Australian Standards so far havenot prescribed or recommended a particular type earthing scheme because of itsmanufacturer-specicity. However, the following are the more common earthingpractices in Europe:

• To reduce risk of equipment failure (see Figure 13) due to potential dif-ferences during lightning strikes, the inverter's metallic enclosures andmetallic stands (if applicable) should be earthed [Shell, 2002]

29Some manufacturers do not recommend earthing the array, some recommend earthing itvia the inverter[Spooner et al, 2008]

28

• DC and AC ground should be common [IEC 61173, 1992, ESDEPS, 2002]

• The DC cable to the inverter should be shielded, and the shielding earthedto reduce inverter frequency coupling resonance [ESDEPS, 2002, "EMCand Safety Design for Photovoltaic Systems",]

• DC cable between array and inverter should be equipped with an earthedsurge protective shunt device [IEC 61173, 1992] for lightning protectionand a common-mode choke [ESDEPS, 2002] to reduce inverter frequencycoupling resonance

Defects due to 1995 1996 1997

Lightning & thunderstorm 2.3 1.8 3.0Overvoltage 1.6 0.8 0.7

Low quality of grid 0.5 0.6 0.1Emissions at radio frequencies - - 0.1

Figure 13: Numbers of defects per 100 installations recorded within the Ger-man 1000- PV-roof programme caused by dierent EM phenomena (Taken from[ESDEPS, 2002, Final Report, Table 4.1, p11]).

2.10 Protection from the environment

Operators need to ensure that inverters installed outdoors have an adequateenclosure IP Code rating [Wikipedia, 2008j] to prevent water ingress. For out-door installations, it is also advisable to install the inverter enclosure away fromsunlight (or with a hood) to:

• Reduce thermal expansion cycling

• Prevent overheating which could derate the inverter [Watt et al, 2004]

2.11 Cost

A survey by Ishikawa [Ishikawa, 2002, Fig 5.1, p14] showed that grid-connectedPV inverter cost has gone down over the years:

29

Figure 14: Inverter cost reduction between 1998 and 2002 (Taken from[Ishikawa, 2002, Fig 5.1, p14])

We can see that for greater dollar per kW cost-savings on inverters, it behoovesoperators to size their PV generation as large a kW capacity as possible.

30

3 PV array operation issues

3.1 Earthing and Lightning protection

Similar guidelines from Section 2.9 apply. IEC61173 [IEC 61173, 1992] andAS1768 practice are also referred [UNSW-FBE et al, 2005]. Salient points30:

• PV array metallic chassis (if applicable) should have an earthing connec-tion as close as possible to the array31

• The DC cable to the inverter should be shielded

3.2 Fault and resonance protection

Methods of PV array fault protection include fuses, breakers and bypass diodes[Spooner et al, 2008, item 6]. However, IEC 60364 clause 712.433.2 recommendsthat PV array protection schemes and sizing be manufacturer-recommended be-cause conventional fuse and breaker sizing may not work for a current controlledsource such as a PV array. The operator should be satised that risks fromearth current leakage [Atmaram et al, 1991, item 3.3] or capacitative shocks[Myrzik et al, 2003, IIB] are minimized and perform safety checks during main-tenenance (includin de-energisation or isolation) in case such hazards exist.

3.3 Lifespan

PV arrays have lifespans anywhere between 15 and 30 years, and the operatorshould examine its performance parameters [IEC 61724, 1998] closely near itsestimated life-end to decide on whether the arrays should be replaced.

3.4 Eciency and degradation

3.4.1 Variance with temperature

PV array eciency tends to decrease with increasing temperature32, thus whencomparing PV array performance trends, it is vital that the array temperaturebe taken into account [IEC 61724, 1998].

3.4.2 Variance with time

PV arrays that do not get periodic washing or cleaning will, over time, collectdust and debris that may block sunlight and reduce array output. PREGA, whooperates Siemens arrays, recommends array cleaning every 3 months [PREGA, 2005].

30Array earthing recommendations are still subject to manufacturer requirements due tosome manufacturer specications disallowed array earthing[Calais et al, 2002].

31PV chassis earthing is another area where compliance with wiring rules maybe dicult due to dierent manufacturers having dierent framing and earthingarrangements[Spooner et al, 2008, item 7].

32However, power output due to sunlight intensity increase has been shown to outweigheciency loss due to temperature increase caused by it[Nishioka et al, 2003].

31

3.4.3 Degradation with sunlight and time

Amorphous silicon photovoltaic cells degrade with sunlight exposure and time[Atmaram et al, 1991, item 1]. The operator should be aware of such charac-terstics when estimating payback periods.

32

4 Overall operation practice

4.1 Reliability

Manufacturer warranty periods for inverters can range anywhere from 1 to 10years [Xantrex, 2008], which is shorter than typical PV array lifespans (15 to30 years). Operators should take into account possible inverter replacement intheir system lifetime and reliability-based maintenance costs.

Another reliability issue involves the conversion of DC to AC power. Ideallythe inverter MPPT circuitry optimises the inverter operating point to ensurePV array output is equal to the nominal power load on the inverter. But ifthe array feeds in more than the nominal rated input power of the inverter,large harmonic distortions can occur on the AC-side and possibly cause inverterdamage [ESDEPS, 2002, Final Report, 4.4.4.3.1, p70]. Operations sta shouldbe alert for such array-inverter sizing mismatches.

4.2 Maintenance and their costs

A suggested maintenance schedule is as follows [PREGA, 2005]33,34:

Maintenance activity Periodicity

PV array cleaning Every 3 monthsBattery uid top-up Conventional Lead-Acid: every 6 monthsBattery replacement Conventional Lead-Acid: every 3 years

Inverter As per manufacturer recommendation

Figure 15: Rule-of-thumb maintenance schedule for grid-connected PV systemsfrom [PREGA, 2005]

If the grid-connected PV system is tted with a battery powered UPS system[AS4777-1, 2005, g 3, p8], it is considered good practice to perform batterydischarge tests during the day (when there is PV power) to check, record andtrend battery capacity availability.

One PV station operator in Australia [Gates, 2008] noted that maintenancecosts for troubleshooting PV arrays and their DC connections are high due tolabour costs at dicult to access locations, e.g. high roofs. In addition, inverterfailures have been higher than expected, although the ndings were qualied bythe fact that inverter selection may have been overly driven by initial capitalcost savings35. These higher than expected maintenance costs and relatively36

lower feedback taris in Australia have contributed to the slower penetrationrate of grid-connected PV.

33Maintenance-free batteries do not require top-up34VRLA battery manufacturers have claimed 15 year battery lifespans[Wolong, 2008]35This is often the case in most projects that need initial funding to be given the go-ahead.36Relative to Germany and Spain for example.

33

4.3 Monitoring

Monitoring of grid-connected PV operation data will depend on:

• How closely operation sta desire to track their PV system's actual per-formace and cost savings relative to predicted calculations. Daily MWh,PV array current ow and array temperature monitoring would be helpfulin this respect

• How crucial remote monitoring is to determine whether the PV systemis operating within design parameters. Remotely monitored data couldrange from a simple check on inverter power ow, inverter temperature,array string connectivity [Lepley et al, 2004] and other parameters givenin IEC61724 [IEC 61724, 1998]

4.3.1 Monitoring during Initial Acceptance periods

Operators should monitor their newly installed grid-connected PV systems' re-liability and availability during contract Initial Acceptance periods37. This toensure the inverters do not nuisance-trip. Monitoring of the inverter's anti-islanding protection mechanism should also be done (See Section 4.5).

4.4 End-of-life disposal

PV arrays typically have heavy metal content and there is need for environmen-tally friendly disposal at the end of their lifespan [Wikipedia, 2008d]. PV arraysslated for disposal may be replaced with higher capacity (or higher eciency)ones, subject to available inverter rating.

4.5 Operation issues during repair or upgrading

Salient issues for grid-connected PV owners or large-scale grid-connected PVstations during system upgrading or rejuvenation projects:

• Revamp or rejuvenation project design work and procedures should bereviewed by owner and/or operations sta prior to procurement. Thisincludes:

Protection schemes, including protection discrimination calculations(and conductor sizing) against governing rules and standards beforecommissioning of newly upgraded equipment (see Section 2.2).

Inverter sizing, based on array ratings

Inverter choice, including modularity [Chen et al, 2008, Part I] (basedon future plans for system expandability)

Isolation38 and protection devices between the house (or PV genera-tion plant) and the grid

37To avoid contract disputes, it is a good idea for operators to state PV system availabilitycriteria into their contract clauses for Initial Acceptance

38Including, for example, an isolated section between grid and house (or plant) to enabletesting of the inverter's anti-islanding protection without actually having to trip the grid (seeIEC 60364 clause 712.536.2.1.1).

34

PV array deterioration rate and annual derating calculations (partic-ularly if the PV cells are amorphous silicon [Atmaram et al, 1991])

Mechanical issues such as wind loading and foundation sizing

• Isolation and energisation procedures should also be reviewed prior tocommissioning new equipment

• PV arrays and their wiring in particular should be handled carefully, forthey are live while the arrays are exposed to light [Spooner et al, 2008]39

• Some inverters have been reported to fall short of manufacturer specica-tions under certain operation conditions [Chicco et al, 2004]. Operationssta may wish to verify inverter performance at factory acceptance testsunder worst case40 simulations prior to site acceptance and installation

39DC cable termination may require either operation of PV array isolation switch (IEC60364 clause 712.536.2.2.5) and/or covering of the arrays away from light

40A suggested worst case test for lightning immunity can be taken from [ESDEPS, 2002,p66]:

Inverter DC sides should withstand a 1.2/50ms surge-immunity test of at least two timesthe maximum DC voltage plus 2kV

Inverter AC sides should be tested with a 1.2/50ms surge-immunity test of at least 6kVbetween the 2 AC input lines, and every input line to earth

35

5 Operational issues undergoing research and de-

velopment

5.1 Technical issues

5.1.1 Nuisance tripping and inverter response to voltage swell, dipsand frequency deviations

Existing AS4777 inverter cuto criteria shown in Figure 6, Section 2 may besusceptible to nuisance trips in areas prone to large voltage and frequency de-viations. Its strict cuto timing also may obviate the ability of grid-connectedphotovoltaics to stabilise grids that are heading into instability. To address thisissue, alternative cuto criteria has been proposed by Spooner [Spooner, 2001,Table 2]:

Voltage (Vrms) Time limit (s) Frequency (Hz) Time limit (s)

< Vmin 2 < fmin 2Vmin≤V < 87% of Vn 60

87% of Vn ≤V ≤106% of Vn no limit fmin- fmax no limit106% of Vn < V ≤Vmax 60

> Vmax 2 > fmax 2

Figure 16: Alternative cuto time criteria to support grid stability (Taken from[Spooner, 2001])

Analogously, IEC 61727 also prescribes staggered (discriminated) maximum triptime41 criteria based on how far voltages deviate from norm (Figure 17), as doesIEEE 929 (Figure 18)

Voltage (at point of utility connection) Maximum trip time

V < 0.5× Vnominal 0.1 s50 %≤ V < 85 % 2.0 s85 % ≤V ≤110 % Continuous operation

110 % < V < 135 % 2.0 s135 % ≤V 0.05 s

Figure 17: IEC61727 discriminated maximum trip time to voltagedeviations[IEC 61727, 2004, Table 2, p19]

41Dened as the time between the ospec condition occurring and inverter cuto.

36

Condition Voltage Frequency Max Trip Time

A 0.5 Vnom fnom 6 cyclesB 0.5 Vnom < V < 0.88 Vnom fnom 2 sC 0.88 Vnom ≤V ≤1.10 Vnom fnom -D 1.10 Vnom < V < 1.37 Vnom fnom 2 sE 1.37 Vnom ≤V fnom 2 cyclesF Vnom f< fnom - 0.7 Hz 6 cyclesG Vnom f> fnom + 0.5 Hz 6 cycles

Figure 18: IEEE 929 disconnection timing requirements[Hudson et al, 2002a,Table 1]

Standards Australia has invited public feedback [AS4777-3, 2005, Appendix A]on such cuto time limits. New cuto time limits in future may enhance Sus-tained Operation at areas having unstable supply. It will be interesting to seewhat criteria will be adopted as a future standard.

5.1.2 Inverter supression of its current surges during reconnectionsand voltage dips

There is no existing AS specifying inverter current surge limits during inverterreconnection to a live grid, or during voltage dips. A study by ESDEPS suggests:

• Current surge during reconnection to a live grid be inverter-limited tothrice the nominal household PV load current within a 10ms timeframe[ESDEPS, 2002, Final Report, p65]

• Current surge during 100% transient voltage dips be limited to twice thenominal household PV load current within 1ms of the dip [ESDEPS, 2002,Final Report, p66]

5.1.3 Inverter withstand of grid restart voltages

AS appears to be silent on this criteria too. As mentioned in Section 2.4,[ESDEPS, 2002] suggests that Inverters for the EU market must withsand gridrestart voltage surges of 1.5 times the nominal voltage.

5.1.4 DC overvoltage immunity test and acceptance criteria

There is no existing AS specifying DC overvoltage immunity limit tests for in-verters and acceptance criteria. An EU-funded ESDEPS study [ESDEPS, 2002,4.4.4.3.1, p70] has suggested:

• No disconnection of the inverter at 1.1 ×nominal DC power input atMPPT area

• No inverter damage42 at 1.5 × nominal DC power input at MPPT area

42If the inverter does not disconnect, acceptance criteria includes the inverter reachingthermal stability

37

5.1.5 DC earth fault trip function acceptance criteria

Cuto time for DC earth faults are not specied in AS either, and ESDEPS'study [ESDEPS, 2002, 4.4.4.3.2, p70] has suggested the following criteria:

• Automatic cuto within 50 ms of earth fault

• Lockout until the disconnection of the ground-fault

• No inverter damage

5.1.6 Inverter immunity to unbalanced current

There have been no standard inverter tests for unbalanced grid current immu-nity, or unbalanced current limits specied for inverters. Prolonged unbalancedcurrent may result in inverter components of a certain phase failing prematurely.

5.1.7 Inverter immunity to excessive harmonics

Most grid-connected PV systems operate as a current source, injecting currentinto the utility. To some extent, this characteristic helps reduce grid THDI .On the other hand, based on existing AS, it is unclear [Calais et al, 2002] towhat extent inverters must be able to tolerate the following43:

i) AC side THDV

IEEE519 species a grid THDV limit of≤ 3%, and AS4777.2 type-tests invertersat a THDV limit of 5% [AS4777-2, 2005, Table B1]. However, in practice,particularly at areas having islanded local distributed generation, THDV limitshave been known to be as high as 8% [Shell, 2002].

ii) AC side THDI

IEEE519 also prescribes THDI limits, based on fault current levels at particulardistribution nodes:

43If the inverter has active ltering functions [Meinhardt at al, 2000, item 5], it may havehigher THD tolerance levels

38

Figure 19: Table of current distortion limits from IEEE519 (Taken from[IEEE 519, 1992, Table 10.3, p78])

However, in practice, particularly at areas having islanded local distributedgeneration, THDI limits have been known to be as high as 64%.

iii) DC side coupling and harmonics

AC coupling to the inverter DC node has also been observed in inverters havingpoor harmonic isolation:

39

Figure 20: Waveforms of inverter with high AC coupling to DC node (Takenfrom [ESDEPS, 2002, Fig 4.4, p14]).

Such AC-DC coupling on unshielded, unearthed DC lines have been known tomake the DC line act as an antenna [ESDEPS, 2002, Fig 4.25, p37]. Invertermanufacturer-published maximum THDV and THDI immunity limits would behelpful for operators facing such conditions. For example, such published datawould be referred to when deciding on which inverters to procure for revamp orrejuvenation projects.

5.1.8 Inverter noise and radiation limits

It is unclear what the national limits are on inverter acoustic noise. Individualinverters emit noise between 30-57dB [Ishikawa, 2002, Annex A] at a character-istic high pitch of 15.75kHz [ESDEPS, 2002], which is also its nominal frequencyof electromagnetic radiation. Studies by ESDEPS of available inverters in theEU market have found that a signicant share of PV inverters currently avail-able on the market produce signals at radio frequencies above the (CE) limitsfor household devices [ESDEPS, 2002, 5, p113]Long-term hearing nerve damage (including tinnitus or acoustic neuroma) risk

occurs to persons working long-term in a room having noisy radiation suchas those caused by inverters. There are also no national standards that governEMC radiation limits at 15.75kHz. To address such concerns, it is recommendedthat:

• A dedicated, reasonably soundproof, concrete rebar-earthed room be in-stalled to house inverters at grid-connected PV installations

• AC and DC cabling to and from inverters should be kept as short aspossible [ESDEPS, 2002, p44]

40

• Existing and proposed EMC standards be adopted for photovoltaic equip-ment operation [ESDEPS, 2002, Final Report, Table 4.6 and Figures 4.38,4.46]

5.1.9 Inverter power export coordination and control due to networkconstraints

In future, as more grid-connected PV stations with sophisticated loadow fea-tures (such as power output based on electricity market spot prices) get installed,the grid operator may require centralised coordination of each PV installationto prevent possible distribution network overload (such as when all PV invertersattempt to ramp-up generation simultaneously). The next draft IEEE 1547.3standard is intended to address such operation control issues:

Figure 21: Proposed DG monitoring and control diagram for draft IEEE 1547.3Standard (Taken from [Basso, 2003, , Slide 21])

5.1.10 Grid restoration works in a future of grid-connected PV pro-liferation

As grid-connected PV systems proliferate, it is foreseen that future grid restora-tion procedures may need additional safety precautions, because inverter anti-islanding cuto mechanisms or algorithms have been known to fail under certain

41

conditions [Woyte et al, 2003], and the probability of failure increases with thenumber of grid-connected PV systems installed:

• Utilities may wish to install remote monitoring of each grid-connected PVhouse inverter or kWh meter to check that it isn't operating or runningduring grid restoration works

• For line restoration works, utilities may need dierent live-line detectiontools, e.g. hotsticks which can detect live-line electrical elds at less than200V, in case there are inverters still injecting currents resulting in lowo-spec voltages

5.2 Commercial issues

5.2.1 Grants and rebates

The Australian government's Solar Homes and Communities Plan oers rebatesto new grid-connected PV operators at $8 per watt capped at 1kW, and another$5 per watt, capped at 1kW for operators upgrading (revamping) their existinggrid-connected PV system to higher ratings [Energy Matters, 2007]. There isalso a grant scheme of up to $50,000 for schools installing grid-connected PV.This plan will run until 2012, and has recently been criticised for not beingas cost-eective as an enforcment of higher buyback rates [SMH, 2008]. Thefollowing capital expenditure payback earning projections serve to illustratethis:

42

Figure 22: A comparison of payback times for a 2kW grid-connectedPV system in Australia costing $26,000: Existing rebate scheme vshigher buyback rates (Generated using approximate pricing data from[Clean Energy Council, 2007, Nowak et al, 1998, Energy Matters, 2007,Australian Government, 2005, Australian Government, 2006, CEC, 2003,NEMMCO, 2008, NEMMCO, 2008b])

It is uncertain whether the Solar Homes and Communities Plan will change after2012. However, NEMMCO is planning to allow consumers in Victoria and SouthAustralia choose their retailer for feed-in tari agreements [NEMMCO, 2008c,7. Photovoltaic Feed-in Taris Project]. It will be interesting to see whetherthis policy will evolve into schemes that involve higher buyback rates of up to5-6 times market prics as seen in Germany and Switzerland [Nowak et al, 1998].

5.2.2 Estimating the value of grid-connected PV in the NEM

Taking the NEM's load demand curve for 23-25 September 2008 as an example(Figure 23), total grid-connected PV power supplying the NEM, based on avail-able data (Figure 24) can be calculated during peak load to be approximately:

2.46MW25.8GW ≈ 0.01%

43

Figure 23: Plots of NEM demand and pricing for 23-25 September 2008(Taken from [NEMMCO, 2008b] with data from [Wikipedia, 2008a, EGM, 2003,Schroeder, 2000])

44

The grid-connected PVMWp can be approximated, trended and projected basedon available data (Figure 24), and translated into a value (Figure 25).44

44These are rough calculation methods, which may not take into account grid-connectedPV that were not veriable by the authors.

45

Figure 24: List of grid-connected PV stations and estimations ofgeneration value [Wikipedia, 2008a, EGM, 2003, Schroeder, 2000,Macquarie Generation, 2008, SMH, 2007].

46

Figure 25: Estimated annual values of grid-connected PV power[Wikipedia, 2008a, EGM, 2003, Schroeder, 2000, Macquarie Generation, 2008,SMH, 2007].

A similar rough calculation can be done to estimate REC value45 generatedby grid-connected PV, taking into account REC calculation procedures (e.g.rounding-down) and zone factors [Australian Government, 2006]. One way tofund or subsidise possible higher feed-in taris in future would be to levy taxeson REC sales. Incentives such as REC tax deductions or rebates could beapplied for retailers oering higher feed-in taris. More cost-benet studies46

could be done on this approach and its implementation.

45Studies have shown that REC market values have ranged between $32 - $40 per MWh[Australian Government, 2005], a range reasonably close to average NEM spot market pricesfor electricity.

46This ties in with the ideal intent of maximising the value and benet of energy delivered,given all its delivery costs [McGill, 2008, Slide 6].

47

6 Summary

Operational issues for grid-connected photovoltaics include safety, reliability,optimal power transfer, power quality, loadow coordination and commercialissues.

Safety, reliability, optimal power transfer and power quality are ad-dressed by diligent design, installation and maintenance by operations sta,which include:

• Design checks prior to installation of new PV equipment for revamp andrejuvenation projects, for example:

1. Ensuring design compatibility between existing and new PV systems

2. Checking best practice and deciding on performance and Initial Ac-ceptance criteria

3. Checking and vetting installation safety procedures

• Initial Acceptance period monitoring to ensure specications are met

• Periodic maintenance, e.g. array cleaning, continuity checks, battery dis-charge tests (if applicable)

• Logging operational performance to support cost-benet analysis for fu-ture upgrades or replacements

• Reviewing updated national standards to ensure equipment compliance

Commercial-wise, utilities have found that maintenance costs for grid-connectedPV are often expensive due to array locations at dicult to access locations,e.g. high roofs. In addition, inverter failures have been higher than expected,although the ndings are qualied by the fact that inverter selection may havebeen overly driven by initial capital cost saving priorities47. These higher thanexpected maintenance costs and relatively lower feedback taris in Australiahave contributed to the slower penetration rate of grid-connected PV, comparedto Germany and Spain (for example) [Gates, 2008].

Long-term issues of grid-connected PV loadow coordination are still being in-vestigated as more PV systems connect to grids. PV station operation costsare practically zero, and PV station operators tend to get dispatched no matterhow low the spot price48. Financial derivatives for electricity (also called swapoptions) will also reect daytime-only availability of PV systems without bat-tery banks. Inverter control of PV power output enables PV operators to oernear-instantaneous up and down-ramp times during sunlight (i.e. during thePV operational duty cycle).

Future Australian electricity market restructuring will potentially open up moreoptions for operators of small grid-connected PV systems. For example:

47This is often the case in most projects that need initial funding to be given the go-ahead.48A grid-connected industrial PV station generator operator in the NEM may choose to bid

in at negative prices to fulll derivative contract (or swap option) obligations.

48

• By oering higher buy-back rates, retailers could encourage more grid-connected PV use, and this could become a mechanism for retailers to en-courage the creation of more carbon credits under carbon trading schemes

• If retailers choose to link buy-back rates to NEM spot prices, it couldencourage even more use of grid-connected PV, and could have benecialeects such as:

1. Grid-connected PV operators installing large battery banks to boosttheir PV system's power export during high prices

2. Grid-connected PV manufacturers innovating to design inverter andbattery conditioner control to charge batteries during low spot prices49,and export more power during high spot prices [McGill, 2008, Slide35]

3. Battery-backed grid-connected PV systems operating as another bueragainst volatile NEM spot prices

4. Battery-backed grid-connected PV systems possibly being used asanother mechanism to control network ow, coordinate transmissionconstraints and possibly reduce network expenditure [McGill, 2008,Slide 21]

As grid-connected PV systems proliferate50, it is foreseen that future gridrestoration procedures may need additional safety precautions, toolsand monitoring systems, because inverter anti-islanding cuto mechanisms oralgorithms have been known to fail under certain conditions [Woyte et al, 2003].

To further address safety, reliability, optimal power transfer and power qual-ity, more work and agreement is needed for inverter standards in Australia interms of:

• Cuto timing discrimination

• Immunity to harmonics and transient surges (DC and AC side)

• Immunity to voltage swells and imbalanced current (AC side)

• Suppression of inverter-caused surges

• Immunity to grid-reconnection voltage surges

• Earth fault trip acceptance criteria (e.g. reset time)

• Noise and radiation limits

• Inverter power export coordination and control due to network constraints(e.g. draft IEEE 1547.3 Std)

• Monitoring and checking for islanding power containment in case of anti-islanding protection failure

49With charging power coming from either the PV array, the grid, or both50The probability of failure increases with the number of grid-connected PV systems in-

stalled.

49

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