XR-EE-ES_2011_011_dig

Degree project in

Comparison of existing PV models andpossible integration under EU grid

specifications

Ioannis-Thomas K. Theologitis

Stockholm, Sweden 2011

XR-EE-ES 2011:011

Electric Power SystemsSecond Level

Comparison of existing PV models and

possible integration under EU grid

specifications

Ioannis-Thomas K. Theologitis

Master of Science Thesis

KTH School of Electrical Engineering

Division of Electrical Power Systems EPS-2011

SE-100 44 STOCKHOLM

COMPARISON OF EXISTING PV MODELS AND

POSSIBLE INTEGRATION UNDER EU GRID

SPECIFICATIONS

Ioannis-Thomas Theologitis

Royal Institute of Technology (KTH), Sweden

©2011

School of Electrical Engineering

Kungliga Tekniska Högskolan

SE-100 44 Stockholm

Sweden The author is officially enrolled to the Sustainable Energy Engineering Master Program

(SEE) and belongs to the School of Industrial Engineering and Management and the

Department of Energy Technology.

The picture of the front cover is taken from the second edition of the book “Planning &

Installing Photovoltaic Systems – A guide for installers, architects and engineers”, published

by Earthscan and copyrighted by The German Energy Society (Deutsche Gesellshaft für

Sonnenenergie (DGS LV Berlin BRB) in 2008. ISBN-13: 978-1-84407-442-6

“Αποσκότισόν με”

-Διογένης-

“Take me out of the dark”

-Diogenes-

It was the answer to Great Alexander, when he stood in front of Diogenes and asked him what favour

he needs. Diogenes, as a cynic philosopher, answered this phrase to Alexander implying that he was

blocking the sun with his body. Cynics believed that the happiness is hidden in simple things as the

energy and warmth of the sun and not in material goods.

MSc Thesis Project Abstract

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iv

Abstract

This master thesis investigates the capabilities of a generic grid-connected photovoltaic (PV)

model that was developed by DIgSILENT and is part of the library of the new version of

PowerFactory v.14.1. The model has a nominal rated peak power of 0.5 MVA and a designed

power factor cosφ=0.95. A static generator component, which includes the PV array, the DC

bus with the capacitor, the inverter and the control frame, is used to model the PV system.

The PV array is considered to operate at the MPP and the generator with cosφ=1.

The thesis begins with a short review of the current status of the PV sector, focusing mostly

on the types of PV systems and the necessary components that are used in grid-connected

systems. Since the PV inverter is the key component, special reference is made to the

different technologies applied and to the multifaceted role that inverters should play

nowadays supporting the grid’s stability. Technical restrictions and requirements are

presented highlighting primarily the German Grid Code for the MV network, which is the

benchmark for the analysis of the role and behaviour of the PV model in question. Germany

is regarded a very good example to base the study on due to its leading position and

experience in the renewable area and its thorough grid specifications.

The main part of the report includes a detailed description of the structure of the generic

model, presenting the operating procedure of its components as well as model assumptions

and simplifications. Various simulations in variable solar irradiation, frequency and voltage

conditions are performed in order to conclude in its capabilities. The static voltage support

is investigated under cloud effect situation where the changes in active power output of the

PV array can influence the voltage stability of the grid at the PCC. The active power control

is examined by forcing the grid frequency to deviate beyond specified limits and observing

the active power output results. At last, the dynamic voltage support capability (LVRT) is

examined by simulating four different short circuit events creating four different voltage

dips. The ability of the PV inverter to stay connected and to provide reactive current when

necessary is seen. The external grid component is designed to represent a strong grid.

The results showed that the model is capable for active power reduction and LVRT

behaviour. However, the absence of reactive power control makes it inapplicable for static

voltage support. Thus, a PI controller is implemented in order to supply constant reactive

power in steady state operation and support the grid stability.

At last two different interconnections were built using a slightly modified version of the

same generic model with a rated power 1 MVA. The control scheme remained the same.

Both configurations were examined statically and dynamically and their results were

compared. Small differences were found in terms of reactive power consumption/injection

at the PCC.

Keywords: Grid-connected Photovoltaic, PV inverter, Grid codes for PV, PV model, DIgSILENT

MSc Thesis Project Sammanfatning

KTH, June 2011

v

Sammanfatning

Det här examensarbetet undersöker förmågan av en generisk nätanslutna solcell (PV)

modell som utvecklades av DIgSILENT och det är en del av biblioteket av den nya versionen

av PowerFactory v.14.1. Modellen har en nominell beräknat maximal effekt på 0.5 MVA och

en utformad effektfaktor på cosφ=0.95. En stillastående generator beståndsdel, som

innehåller PV uppställningen, DC bussen med kondensatorn, strömväxlaren och kontroll

ramen, som användes för att utforma PV systemet. PV uppställningen förväntas att

användas vid MPP-en och generatorn med cosφ=1.

Examensarbetet inleder med en kort genomgång av det nuvarande läget av PV sektorn, som

fokus för det mesta på PV system sorter och de viktiga beståndsdelarna som användas i

nätanslutna system. Eftersom PV strömväxlaren är den viktigaste beståndsdelen, är särskild

hänvisning görs till de olika tillämpade tekniker och den mångfacetterade roll som

växelriktare bör spela nuförtiden stödja nätets stabilitet. Tekniska begränsningar och krav

presenteras för att belysa främst på den tyska GC för MV nätet, vilket är utgångspunkten för

analysen av den roll och beteende av PV modellen i fråga. Tyskland anses ett mycket bra

exempel att basera studien på grund av sin ledande ställning och erfarenhet inom förnybar

området och dess grundliga specifikationer nätet.

Den huvuddelen av rapporten innehåller en detaljerad beskrivning av strukturen för den

generiska modellen, som presenterar fungerande förfarandet av dess komponenter samt

modellantaganden och förenklingar. Olika simuleringar i varierande solstrålning, frekvens

och spänning villkor utförs i syfte att ingå i sin förmåga. Den statiska spänningen

understödet undersökas under moln effekt situation där förändringar i aktiv uteffekt PV

uppställningen kan påverka spänningsstabilitet i rutnätet på den PCC. Den aktiva effekten

kontroll undersöks genom att tvinga nätfrekvens att avvika utöver angivna gränsvärden och

observera det aktiva resultatet uteffekt. Äntligen är den dynamiska spänning stöd kapacitet

(LVRT) undersöks med hjälp av simulerad fyra olika kortslutning händelser skapa fyra olika

spänningsfall. Förmågan hos PV strömväxlaren att hålla kontakten och ge reaktiva

strömmen vid behov ses. Det externa komponent i nätet utformats för att representera en

stark rutnät.

Resultaten visas att modellen har kapacitet för aktiv effekt minskning och LVRT beteende.

Men gör det saknas styrning av reaktiv effekt inte tillämpas under statisk spänning stöd.

Därför är en PI-regulator som genomförs för att leverera konstant reaktiv effekt i konstant

drift och support för stabila nät.

Äntligen två olika sammankopplingar byggdes med en något modifierad version av samma

generiska modell med en nominell effekt 1 MVA. Kontrollschemat förblevs densamma. Båda

konfigurationerna undersöktes statiskt och dynamiskt och resultaten jämfördes. Små

skillnader fanns i form av reaktiv effekt förbrukning / insprutning i PCC. Nyckelord: Nätanslutna solcell, PV strömväxlare , Nät koder för PV, PV modell, DIgSILENT

MSc Thesis Project Acknowledgements

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Acknowledgements

At first I wish to thank all the people, who, in whichever way, assisted me to complete this

interesting project for my master thesis and made this period an important benchmark for

my future professional expectations. From Energynautics GmbH1, Dr Thomas Ackermann,

who gave me the opportunity to complete the thesis in his company, Dr Eckehard Tröster,

for his patience with all my questions, his valuable advices and insight that gave direction to

my work, Rena Kuwahata, who was the initial contact with the company and the person that

facilitated my work and life in the new environment, Dr Nis Martensen and Stanislav

Cherevatskiy, who shared their experiences in the field whenever those were asked for and

in general I wish to thank all the rest of the personnel, who were part of my everyday life

the last five months, ensuring a friendly and highly professional environment.

Furthermore, I would like to thank Prof. Lennart Söder for the fruitful pre-presentation and

his valid comments and of course Giannis Tolikas for undertaking the translation of the

abstract to Swedish. Since it is likely that I forget some people that offered their helped for

the completion of this project, I feel obliged to thank them as well.

Special thanks should be paid to Panagiotis Giagkalos and Kyriakos Liotsios, who were my

classmates, colleagues, but most of all my friends during the last two years of this master. It

is important to realize that anytime you can find people that you can count on. May this

friendship lasts and don’t leave time and distance to wear it, rather strengthen it through

personal or professional common experiences.

To Angela Maria Castaño Garcia, for this beautiful journey that still goes on. Her support

during this time was more that I could ask for. As far as the thesis concerned, her

contribution and effort to the final format of the report was significant.

At last, to my beloved family, my parents Konstantinos and Efterpi, and my brother

Charalampos, who deserve my eternal gratitude for all that have offered me. Their constant

support in every aspect is scarcely reflected on these few sentences here. However, any

success in my life so far is mostly charged to them and consequently any success in the

future will have their signature as well.

Such moments, I feel the need to give space and mention all the people that left something

valuable to me. Old friends from Greece that never forget, new friends from different parts

of the world, people I met for short period, all of them are the people that with one way or

another made this time worth living it again. You are my personal ark. Thank you all and

wish you the best.

1 http://www.energynautics.com/

MSc Thesis Project Table of Contents

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Table of Contents

ABSTRACT........................................................................................................................ . IV

SAMMANFATNING ........................................................................................................... V

ACKNOWLEDGEMENTS .................................................................................................... VI

TABLE OF CONTENTS ...................................................................................................... VII

LIST OF FIGURES .............................................................................................................. IX

LIST OF TABLES ............................................................................................................... XII

NOMENCLATURE ........................................................................................................... XIII

1 INTRODUCTION ......................................................................................................... 1

1.1 THE DRIVING FORCE ....................................................................................................... 2

1.2 OVERVIEW OF THE THESIS REPORT ................................................................................ 4

1.3 OBJECTIVES .................................................................................................................... 5

1.4 LIMITATIONS .................................................................................................................. 6

2 BACKGROUND .......................................................................................................... 8

2.1 PV SYSTEMS – OVERVIEW .............................................................................................. 8

2.1.1 I-V CHARACTERISTICS ............................................................................................. 9

2.2 GRID-CONNECTED PV SYSTEMS ................................................................................... 11

2.3 PV INVERTER ................................................................................................................ 12

2.3.1 WHAT IS AVAILABLE – CURRENT STATUS ............................................................ 13

2.3.2 ISSUES WHEN CHOOSING INVERTER ................................................................... 16

2.3.3 ADDITIONAL REQUIREMENTS – ANCILLARY FUNCTIONS .................................... 18

2.4 LOW VOLTAGE RIDE THROUGH (LVRT) REQUIREMENT ............................................... 18

2.4.1 REACTIVE POWER AND ITS IMPORTANCE ........................................................... 19

2.5 GRID REQUIREMENTS FOR PV SYSTEMS ...................................................................... 19

2.5.1 THE NEW GERMAN GRID CODE ........................................................................... 20

2.5.2 THE SITUATION IN THE REST OF EUROPE ............................................................ 25

2.5.3 FURTHER INTERNATIONAL AND EUROPEAN REQUIREMENTS FOR PV ............... 25

3 METHODOLOGY ...................................................................................................... 27

3.1 DESCRIPTION OF THE TOOLS ........................................................................................ 27

3.2 WAYS FOR SIMULATING PV WITH POWERFACTORY .................................................... 27

4 MODEL DESCRIPTION .............................................................................................. 31

4.1 THE BASE MODEL ......................................................................................................... 31

4.2 THE PV GENERATOR ..................................................................................................... 33

4.2.1 THE CONTROL FRAME OF THE PV GENERATOR ................................................... 36

4.3 INVESTIGATION UNDER GERMAN GCS ......................................................................... 48

4.3.1 STEADY STATE CONDITION .................................................................................. 48

MSc Thesis Project Table of Contents

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4.3.2 ACTIVE POWER CONTROL .................................................................................... 52

4.3.3 DYNAMIC VOLTAGE SUPPORT ............................................................................. 55

4.4 SUMMARY .................................................................................................................... 62

5 FURTHER ANALYSIS & DISCUSSION .......................................................................... 64

5.1 ADDITION IN THE CONTROL SYSTEM OF THE PV MODEL ............................................. 64

5.2 MODEL ADJUSTMENT AND INTERCONNECTION CASES ............................................... 67

5.2.1 ADJUSTMENT OF THE PV MODEL ........................................................................ 67

5.2.2 FIRST CASE ............................................................................................................ 70

5.2.3 SECOND CASE ....................................................................................................... 75

5.2.4 COMPARISON OF BOTH CASES ............................................................................ 78

6 CONCLUSIONS ......................................................................................................... 81

7 REFERENCES ............................................................................................................ 83

8 APPENDIX ............................................................................................................... 87

8.1 PARAMETERS USED IN THE PV MODEL ........................................................................ 87

8.2 THE DSL CODE IN MAIN BLOCKS OF THE PV MODEL ..................................................... 89

8.3 RESULTS OF LVRT STUDY IN BOTH INTERCONNECTION CASES .................................... 91

8.3.1 FIRST CASE ............................................................................................................ 91

8.3.2 SECOND CASE ....................................................................................................... 94

MSc Thesis Project List of Figures

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List of Figures

FIGURE 1.1: INCREASE OF RENEWABLE ENERGY SOURCES IN GERMANY 1990-2009 ............... 2

FIGURE 1.2: CUMMULATIVE INSTALLED GRID CONNECTED AND OFF GRID PV POWER IN 26

COUNTRIES THAT PARTICIPATE IN THE IEA PVPS ............................................................... 3

FIGURE 1.3: WORLD PV CELL/MODULE PRODUCTION FROM 1990 TO 2009 ............................ 4

FIGURE 1.4: ANNUAL PHOTOVOLTAIC INSTALLATIONS FROM 2000 TO 2009 .......................... 4

FIGURE 2.1: TYPES OF PV SYSTEMS ........................................................................................... 9

FIGURE 2.2: TYPICAL I-V CHARACTERISTIC ................................................................................ 9

FIGURE 2.3: THE EFFECT OF SOLAR RADIATION AND TEMPERATURE ON THE I-V CURVE ....... 10

FIGURE 2.4: THE EFFECT OF THE INTERCONNECTION OF PV MODULES ON THE I-V CURVE .... 11

FIGURE 2.5: PRINCIPLE OF CONNECTING PV SYSTEMS TO THE GRID WITH A SINGLE-PHASE

AND THREE-PHASE INVERTER .......................................................................................... 13

FIGURE 2.6: FB INVERTER TOPOLOGY ..................................................................................... 15

FIGURE 2.7: INVERTER’S OPERATING RANGE .......................................................................... 17

FIGURE 2.8: ACTIVE POWER CONTROL REQUIREMENT FOR GRID-TIED GENERATORS ........... 22

FIGURE 2.9: EXAMPLE OF COSΦ(P)-CHARACTERISTIC ............................................................. 23

FIGURE 2.10: FAULT-RIDE-THROUGH CAPABILITY .................................................................. 24

FIGURE 2.11: REACTIVE CURRENT INJECTION REQUIREMENTS IN THE EVENT OF NETWORK

FAULTS ............................................................................................................................. 24

FIGURE 3.1: PV ARRAY AS DC CURRENT SOURCE ..................................................................... 28

FIGURE 3.2: PV MODEL WITH BATTERY ................................................................................... 29

FIGURE 3.3: PV INVERTER AS PWM COMPONENT ................................................................... 29

FIGURE 3.4: PV SYSTEM AS STATIC GENERATOR ...................................................................... 30

FIGURE 4.1: THE BASE PV MODEL ............................................................................................ 31

FIGURE 4.2: THE EXTERNAL GRID SETTINGS ............................................................................. 32

FIGURE 4.3: SIMPLE EQUIVALENT OF A SHORT CIRCUIT ON THE GRID .................................... 32

FIGURE 4.4: PV GENERATOR POWER FLOW CHARACTERISTICS UNDER NORMAL STEADY-

STATE OPERATION ........................................................................................................... 34

FIGURE 4.5: CAPABILITY CURVE OF THE INVERTER .................................................................. 35

FIGURE 4.6: MAXIMUM REACTIVE POWER LIMITS IN THREE VOLTAGE LEVELS ...................... 36

FIGURE 4.7: THE CONTROL FRAME OF THE PV GENERATOR .................................................... 37

FIGURE 4.8: THE STRUCTURE OF IRRADIANCE SLOT ................................................................ 38

FIGURE 4.9: SOLAR IRRADIATION INCREMENT ........................................................................ 38

FIGURE 4.10: EFFECT OF SOLAR IRRADIANCE IN THE PV CHARACTERISTICS ............................ 39

FIGURE 4.11: EFFECT OF SOLAR IRRADIANCE IN THE PV POWER OUTPUT .............................. 39

FIGURE 4.12: TEMPERATURE INCREMENT IN THE PV ARRAY ................................................... 40

FIGURE 4.13: EFFECT OF THE OPERATION TEMPERATURE IN THE PV VOLTAGE ...................... 40

FIGURE 4.14: THE PHOTOVOLTAIC ARRAY MODEL .................................................................. 41

FIGURE 4.15: THE ELECTRICAL EQUIVALENT OF AN IDEAL SOLAR CELL ................................... 42

FIGURE 4.16: THE DC BUS BAR AND CAPACITOR MODEL ......................................................... 44

FIGURE 4.17: THE ACTIVE POWER REDUCTION CONTROL ....................................................... 45

FIGURE 4.18: THE MAIN CONTROLLER MODEL ........................................................................ 47


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FIGURE 4.19: THE BASIC STRUCTURE OF A PLL ........................................................................ 47

FIGURE 4.20: SOLAR RADIATION DROP .................................................................................... 49

FIGURE 4.21: SET OF CONSTANT POWER FACTOR ................................................................... 50

FIGURE 4.22: ACTIVE AND REACTIVE POWER CHANGE DURING A CLOUD EFFECT .................. 50

FIGURE 4.23: VOLTAGE DEVIATION DURING A CLOUD EFFECT ................................................ 51

FIGURE 4.24: ACTIVE AND REACTIVE CHANGE IN THE LV BUS ................................................. 52

FIGURE 4.25: CHANGE IN THE “SPEED” PARAMETER TO CREATE OVERFREQUENCY ............... 53

FIGURE 4.26: THE OVERFREQUENCY EVENT ............................................................................ 53

FIGURE 4.27: THE ACTIVE POWER REDUCTION OF THE GENERATOR DUE TO OVERFREQUENCY

.......................................................................................................................................... 54

FIGURE 4.28: THE ACTIVE AND REACTIVE POWER VALUES IN THE LV BUS DURING THE

OVERFREQUENCY EVENT ................................................................................................. 54

FIGURE 4.29: THE ACTIVE AND REACTIVE POWER VALUES IN THE MV BUS DURING THE

OVERFREQUENCY EVENT ................................................................................................. 55

FIGURE 4.30: TESTS PERFORMED FOR DYNAMIC VOLTAGE SUPPORT ..................................... 56

FIGURE 4.31: EQUIVALENT PLAN OF A GRID WITH FAULT (A) AND THE ELECTRICAL CIRCUIT

REPRESENTATION (B) ....................................................................................................... 56

FIGURE 4.32: BEHAVIOUR OF THE PV MODEL IN 100% VOLTAGE DIP ..................................... 58

FIGURE 4.33: BEHAVIOUR OF THE PV MODEL IN 80% VOLTAGE DIP ....................................... 59



FIGURE 4.36: POSSIBLE DYNAMIC MPP CONTROL ................................................................... 63

FIGURE 5.1: THE CONSTANT Q CONTROL IMPLEMENTATION TO THE MODEL ........................ 64

FIGURE 5.2: THE SWITCHING FUNCTION WRITTEN IN DSL INSIDE THE CURRENT LIMITER ...... 65

FIGURE 5.3: THE CONSTANT Q SET IN THE PV GENERATOR ..................................................... 66

FIGURE 5.4: THE ACTIVE POWER CHANGE OF THE PV GENERATOR ......................................... 66

FIGURE 5.5: THE Q CONTROL RESPONSE TO THE ACTIVE POWER CHANGE ............................. 67

FIGURE 5.6: VOLTAGE VARIATION IN THE LV BUS WITH THE Q CONTROL ............................... 67

FIGURE 5.7: THE FIRST SET UP OF THE PV POWER PLANT OF 20 MVA ..................................... 69

FIGURE 5.8: THE SECOND SET UP OF THE PV POWER PLANT OF 20 MVA3 ............................... 69

FIGURE 5.9: THE FIRST CONFIGURATION AS BUILT IN POWERFACTORY .................................. 70

FIGURE 5.10: P-Q CURVE-FIRST CASE ....................................................................................... 73

FIGURE 5.11: THE SECOND CONFIGURATION AS BUILT IN POWERFACTORY ........................... 76

FIGURE 5.12: P-Q CURVE-SECOND CASE .................................................................................. 77

FIGURE 5.13: P-Q CURVES-BOTH CASES ................................................................................... 79

FIGURE 8.1: THE DSL CODE OF EACH PV MODULE ................................................................... 89

FIGURE 8.2: MAIN PART OF DSL CODE IN THE ACTIVE POWER REDUCTION BLOCK ................. 90

FIGURE 8.3: THE DSL CODE IN THE PI CONTROLLER BLOCK ...................................................... 90

FIGURE 8.4: THE DSL CODE IN THE REACTIVE POWER SUPPORT BLOCK .................................. 90

FIGURE 8.5: THE DSL CODE IN THE CURRENT LIMITER BLOCK .................................................. 90

FIGURE 8.6: BEHAVIOUR OF THE FIRST INTERCONNECTION IN 100% VOLTAGE DIP ............... 91

FIGURE 8.7: BEHAVIOUR OF THE FIRST INTERCONNECTION IN 80% VOLTAGE DIP ................. 92



FIGURE 8.10: BEHAVIOUR OF THE SECOND INTERCONNECTION IN 100% VOLTAGE DIP ........ 94

FIGURE 8.11: BEHAVIOUR OF THE SECOND INTERCONNECTION IN 80% VOLTAGE DIP .......... 94


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MSc Thesis Project List of Tables

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List of Tables

TABLE 2.1: NEW REQUIREMENTS FOR GRID TIED GENERATORS ............................................ 21

TABLE 4.1: VOLTAGE DIP TESTS FOR GENERATING UNITS TYPE-2 .......................................... 55

TABLE 4.2: TESTS PERFORMED WITH THE PV MODEL ............................................................. 56

TABLE 4.3: FAULT CONDITIONS IN EACH TEST ........................................................................ 57

TABLE 4.4: AGGREGATION OF THE RESULTS OF ALL TESTS ..................................................... 61

TABLE 5.1: PARAMETERS FOR THE CONSTANT Q CONTROL THAT ADDED IN THE ................. 65

TABLE 5.2: LINES USED IN THE FIRST CONFIGURATION .......................................................... 71

TABLE 5.3: RESULTS OF THE LOAD FLOW STUDY FIRST CASE ................................................. 72

TABLE 5.4: FAULST CONDITIONS IN EACH TEST FIRST CASE.................................................... 74

TABLE 5.5:AGGREGATION OF THE RESULTS FOR DYNAMIC VOLTAGE SUPPORT FIRST CASE 74

TABLE 5.6: LINES USED IN THE SECOND CONFIGURATION ..................................................... 75

TABLE 5.7: RESULTS OF THE LOAD FLOW STUDY SECOND CASE ............................................. 77

TABLE 5.8: AGGREGATION OF THE RESULTS FOR DYNAMIC VOLTAGE SUPPORT SECOND

CASE ..................................................................................................................................... 78

TABLE 5.9: LOAD FLOW RESULTS OF BOTH CASES .................................................................. 79

TABLE 5.10: REACTIVE POWER SUPPLY OF BOTH CASES AT PCC IN SEVERAL

VOLTAGE DIPS .......................................................................................................................... 80

TABLE 8.1: PARAMETERS IN PV ARRAY SLOT .......................................................................... 87

TABLE 8.2: PARAMETERS IN DC BUSBAR AND CAPACITOR SLOT ............................................ 87

TABLE 8.3: PARAMETERS IN ACTIVE POWER REDUCTION SLOT ............................................. 87

TABLE 8.4: PARAMETERS IN MAIN CONTROLLER SLOT ........................................................... 88

MSc Thesis Project Nomenclature

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Nomenclature

AC Alternate Current

AI Anti-Islanding

AM Air Mass

ASTM American Society for Testing and Materials

BDEW Bundesverband der Energie-und Wasserwirtschaft (Federal Association of

Energy and Water)

CSI Current Source Inverter

DC Direct Current

DIgSILENT DIgital SImuLator for Electrical NeTwork

DIN Deutsches Institut für Normung (German Standardisation System)

DSL Dynamic Simulation Language (DIgSILENT Simulation Language)

eEURO European efficiency

EMI Electromagnetic Interference

EN European Normalization

EU European Union

FB Full Bridge

FiT Feed in Tariff

FRT Fault ride through

GCs Grid Codes

HV High Voltage

IEA International Energy Agency

IEC International Electrotechnical Commission

IEEE Institute of Electrical and Electronic Engineers

IGBT Insulated Gate Bipolar Transistor

IK or ISC Short circuit current

Impp Current at maximum power point

MOSFET Metal Oxide Semiconductor Field Effect Transistor

LV Low Voltage

LVRT Low Voltage Ride Through

MPP Maximum Power Point

MV Medium Voltage

NPC Neutral Point Clamped

PCC Point of Common Coupling

PF Power Factor

PLL Phased Locked Loop

p.u. per unit

PV Photovoltaic

PVPS Photovoltaic Power Systems

PWM Pulse Width Modulation

RET Renewable Energy Technology

RMS Root Mean Square

MSc Thesis Project Nomenclature

KTH, June 2011

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STC Standard Test Conditions

THD Total Harmonic Distortion

UL Underwriters Laboratories

VDE Verband der Elektrotechnik Elektronik Informationstechnik (Association of

Electrical Engineers)

VDN Verband der Netzbetreiber (Association of network operators)

Vmpp Voltage at maximum power point

VOC Open circuit voltage

VSI Voltage Source Inverter

Wp peak Wattage

MSc Thesis Project Introduction

KTH, June 2011

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1 Introduction

In the coming decades and taking into account the continuous population growth, the

energy demand will probably double [1], if not more, bringing the societies to the brink of

energy shortage. Even if the improvement of energy efficient technologies is significant, the

future demand will not be able to be balanced if new sources would not be introduced and

innovative technologies (either passive or active) would not be exploited. Due to the use of

fossil fuels, major side-effects both in the environment and social life, have already caused

an outburst, sounding the alarm for cleaner and carbon-free energy sources. The renewable

energy sources, as carbon-free sources, appear to be a feasible alternative to conventional

fuels. This shift is not a current phenomenon and mankind has already exploited the sun,

the wind, the water and the earth to produce clean energy in order to address its needs and

provide better quality of services.

Since 1997 and the introduction of the White Paper by the European Commission, the

formation of a renewable energy policy has begun. The overall objective was to reduce the

dependence on fossil fuel imports and increase the security of supply moving towards a low

carbon economy [2]. Over these years the orientation of the EU has changed from indicative

targets, referring to electricity and transport fuel, to specific targets that are legally

established by a legislation pattern. What is more, change has occurred towards redefinition

of the infrastructure policy that plays a key role to the growth of Renewable Energy

Technologies (RET) [3]. Nowadays, it is common belief from all the stakeholders involved

(government, producer and the end user) that the benefits of a society, where renewable

sources account increasingly to the consumption needs, are multiple. Strengthening the

national and local economy, jobs creation, better life quality and of course less harmful

contribution to the environment are some of the strongest arguments in favour of RET.

In 2001, the EU “Renewable Electricity Directive” together with the “Biofuels Directive” that

was signed two years after, set quite ambitious goals for the member states by 2010.

Unfortunately, the 21% of renewable electricity production was met only by very few

countries (i.e. Denmark, Germany, Poland et al.), however it gave boost to many economies

and the sector of renewable energies experienced significant growth with the ‘electricity

production’ enjoying the biggest share [3]. In the year 2009 almost 61% of the new

electricity generating capacity that was connected to the grid in the EU was from RET [4],

while in 2010 the total electricity share in the EU reached 18.5%. This number, even if it is

promising, is still far from the 37% that the Member States have set for 2020. Nevertheless,

today the conditions are more favorable for higher and faster growth rates. There is a much

more organized research field dedicated to the renewable technologies, better and more

flexible legislation framework with number of incentives and support mechanisms and also

a more open-minded industry.

It is inevitable though that with changes, new problems are acquired and need to be

addressed. The high penetration of renewables in the electricity supply system could create


KTH, June 2011

2

issues of instability to the grid, which is not designed to receive such integration. The

problem requires an immediate attention in order to meet the target of 2020 or even

exceed it. There are researches [4] that present scenarios for 2030 and 2050, when

renewable electricity supply could be 68% and 100% respectively. It is understood then that

more modern electricity grid system should be adopted, which means expansion of the grid

but more important implies urgent modification of the already existing one.

Improved technical specifications, the so-called Grid Codes (GCs), which will ensure the

proper and safe function of the electrical grid should be introduced and facilitate the

interconnection of electricity systems and the reinforcement of the grid. Problems like

bottleneck in the grid should be overcome so as grid operators to exchange kWh when

excess of electricity is produced from one and is needed by another one. Deregulation-

based energy market for the support of the distributed generation can be the compass of

the reformation of energy scenery.

1.1 The driving force

Among the RET, the lights have turned to wind turbines and solar PV technologies. Taking

into consideration the fact that countries such as Germany and Spain enjoy a leading

position in the renewable energy sector, tangible results can be withdrawn about the

situation in Europe in general if those countries used as study cases. In figure 1.1 the

aggregated renewable energy capacity in Germany is shown, proving that mainly the focus

is on the wind technology and PV. As far as the PV installations concerned, there is a

dramatic change since 2004, when the feed-in tariff policy mechanism and relevant

subsidies have been in effect. Only in 2008 around 1.5 GWp were installed in Germany [5],

while in September of 2010 the total number of installed capacity was 15 GWp, which is the

30% of the total RET installed and the 37.5% of the minimum load of electricity in 2009 as is

seen in figure 1.1.

Figure 1.1: Increase of Renewable Energy Sources in Germany 1990-2009 [5]


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In 2009, an improved version of the feed-in law was introduced specifying that for new PV

power plants the feed-in tariffs will be reduced from 8% to 10% per year. The main reason

for this change was to force the reduction of the investment cost in PV systems and lead to

grid parity [5].

From the above, it is understood that the conditions are very favourable for the expansion

of RET and especially of PV systems, which is the concern of this project. The Thesis focuses

on grid connected PV systems and their advantage as a power generation unit. The

tendency in industrialized countries is to connect the PV systems to the grid since there is

almost everywhere an electrical network available. Figure 1.2 illustrates this tendency. The

multifunctional role of the PV system and specifically of the grid tied inverter is highlighted

in the Thesis. PV inverter is the main component of the system and is responsible for the

power injection to the grid. Until now, its conventional role was to convert the DC power to

AC power and feed-in the maximum possible active power to the grid. Moreover, in case of

a grid failure it was designed to disconnect until the conditions stabilize again to reconnect.

However, the high penetration of photovoltaics to the distribution network has raised new

requirements for the modern PV inverters. Their role has become much more significant not

only for the PV system but now also for the grid that is connected to.

Figure 1.2: Cummulative installed grid connected and off grid PV power in 26 countries that participate in the

IEA PVPS [6]

The phenomenon of PV being one of the fastest growing sector in the RET industry is not

only European but worldwide. In figure 1.3 is obvious that there is a steady rise in PV

production around the world, which is being followed by a steady rise in PV installations,

which can be seen in figure 1.4.


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Figure 1.3: World PV Cell/Module Production from 1990 to 2009 [7]

Figure 1.4: Annual Photovoltaic Installations from 2000 to 2009 [7]

The new setting that is being shaped because of the reasons mentioned so far makes the PV

field even more interesting and every study around on-grid systems more challenging.

1.2 Overview of the Thesis report

The project in question is part of the initiative of Energynautics GmbH2 to fulfil a study

concerning modelling and simulating large scale PV systems in relation to their impact on

2 For further information about the company refer to Acknowledgements


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5

the power system. The project’s objectives are limited due to tight time constraints and are

presented below in the same chapter. Nevertheless, the thesis tries to cover important

aspects in theory and present realistic results through iterative simulations, aggregating

some knowledge as far as the characteristics of larger penetration concerned.

In the following chapter the theoretical approach is undertaken and basic background is

presented. A brief overview of PV systems and some important characteristics are included

and give place to a deeper analysis of the PV inverter and its modern role. A major part of

this chapter is being covered by the reference of current GCs, principally those of Germany.

In the third chapter the methodology of the study is explained as well as the tool that was

used to model the PV and perform simulations.

Chapter four is dedicated to the model with capacity 0.5 MVA that is used in this thesis and

built by the company DIgSILENT. The control system is explained thoroughly and the choice

of the configuration, inputs, outputs and parameters is justified. Its ability to be used as a

generic model for PV systems that comply with the German GCs is investigated through

simulations.

Next chapter is dedicated to present an interconnection of the generic model in order to

achieve a higher power output. The basic model was first modified by changing appropriate

parameters in terms of rated peak power and consequently active power output. The new

PV model of 1 MVA was used to create two different configurations of 20 MVA each. Load

flow calculations and dynamic behaviour in case of a fault are presented with pasting

relevant graphs. All the important results are, almost catholically, exported graphs from the

simulation program. In the same chapter and after each result, a short discussion on the

findings is taking place.

In the conclusion chapter a general aggregation of the results is deployed. It is commented

whether or not the objectives were met and further suggestions for future work are offered.

1.3 Objectives

The main aim of this thesis, presented also above, is to group together some basic

knowledge, concerning the requirements that a grid connected photovoltaic system should

fulfill in order to comply with certain codes, particularly with the German GCs, and how the

integration of such decentralized power systems affect the behavior of the distribution

network. More specifically, the objectives set for this project are:

• Provide a sufficient background and assessment for integrated PV systems.

Important violations and technical constraints of MV and LV network are presented

as well as the positive impact that PV systems have and the technological

perspective that offer with the allotment of ancillary services. The key component

for these services is the PV inverter, which covers the biggest share of the analysis.

From the grid codes perspective, all the references concern the German grid code


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and mainly the provisions of the new German Transmission Code for Medium

Voltage networks.

• Give a description of the tool used to model the full PV system, meaning the

network, the PV generator, the inverter and the control system. The tool used for

the simulations is the PowerFactory of DIgSILENT.

• Train for the use of PowerFactory and understand number of features that are useful

for modeling and simulating PV systems.

• Understand and analyze a generic PV model and its compliance with the German

GCs. Furthermore, examine, through simulations the shortcomings of the model.

• Customize the PV model in order to provide higher power output.

• Create two different interconnected PV configurations with the use of the modified

PV model and study their behavior in case of faults.

• Recommend related future work.

1.4 Limitations

In the thesis, due to the broadness of the subject, several limitations were delineated with a

sole purpose of presenting some facts in a conceivable and precise way and not correlating

general cognition without any clear purpose. Some important limitations, following the

objectives above, are:

• No stand alone systems are examined. The models are grid tied PV systems,

meaning that no energy storage is taking into account.

• The attention is turned more to the electrical grid, meaning that the behaviour of

the grid and the role of the inverter in this part are the basic considerations. No

study is carried out as far as the suitable choice of an inverter according to the PV

systems arrangement (number of modules per strings, number of strings per

inverter or shading phenomena).

• The PV inverter is single-stage, meaning that there is no DC-DC boost converter

involved and no studies are being undertaken concerning double-stage inverters.

• No real grid is taken into account for the study rather than an external grid

component from the software used, where only the short-circuit power, the

voltage factor and R/X ratio are defined. The grid is assumed strong and no

comparison with weak grids is taking place.


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• No power quality studies (e.g. harmonics) are performed.

• The purpose of the study of the two different configurations is not to conclude in

an optimum design.

MSc Thesis Project Background

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2 Background

2.1 PV systems – Overview

Before studying the particularities of grid connected systems it is thoughtful to introduce

very briefly the current status and some basic terminology of the photovoltaic technology

and systems, singling some known key concepts that are the basis of this sector. In figure

2.1 the different kind of PV systems are presented. As it is seen the two basic categories are:

� The stand-alone systems, which are usually implemented in rural and remote areas

in developing countries where no access to the grid is possible. However, the low

cost production and innovative ideas have led to numerous of applications in

industrialized countries as well (e.g. roof top systems, PV-glazing, solar traffic

lighting, solar parking ticket machines, solar chargers, telecom et al.). Stand-alone

systems are usually supported by storage systems (e.g. batteries) in order to meet

the load in times when the solar irradiation is not enough for the PV to cover the

whole need.

� The grid-connected systems, which are PV systems connected to the local

distribution grid and supply it with power. The connection is via an inverter that

converts the DC to AC and also secures the synchronization with the grid in voltage

and frequency. The PV systems can be connected directly to the public grid or first to

the house grid covering the electricity demand of the house and then supplying any

excess to the public grid. Most of the systems are of large scale (above 100 kW), but

small roof top on-grid systems are very common in countries with favourable FiT

law. In general there is no separate energy storage beside the grid, but there are

configurations that they use batteries [9] to increase the PV self-consumption and

with it the availability of the system and provide a better back-up mode when grid

failure occurs. Nevertheless the additional benefits of those systems should balance

the extra investment and maintenance cost in order to be more competitive.


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Figure 2.1: Types of PV systems [8]

2.1.1 I-V Characteristics The identity of a PV unit, either cell, module or array is the current and voltage curve or as

usually found on texts I-V curve or PV characteristic curve. A typical shape of the

characteristic under STC is seen in figure 2.2, showing the basic points. Those are the short-

circuit current (IK), the open-circuit voltage (Voc) and the maximum power point (MPP) and

are defined below.

Figure 2.2: Typical I-V characteristic [8]


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� The maximum power point (MPP) is the point where the PV cell, module or array

supplies the maximum possible power. At this point the voltage and current are

defined as maximum power voltage (Vmpp) and maximum power current (Impp)

respectively. The MPP is given in peak watts (Wp) and is strongly affected by the

irradiance level as well as the operating temperature of the PV.

� The short-circuit current (IK) is the maximum current that can flow from a PV when

the voltage across the terminals is zero, meaning that are either connected to each

other or an abnormal low-resistance connection has occurred. The short-circuit

current is strongly affected but the incoming irradiation as it is seen in figure 2.3 and

is approximately 5 to 15 per cent higher than the Immp [8]. Typical values of short-

circuit current of various PV modules and under STC can be found in the

specifications of the product [10].

� The open-circuit voltage (VOC) is the voltage between the two terminals of the PV

when no external load in connected to it. The VOC is influenced by the operating

temperature of the PV array which is of course linked to the ambient temperature.

This can also be seen in figure 2.3. Typical values of open-circuit voltage can also be

seen in [10].

The STC is a standard test of uniform conditions related to IEC 60904/DIN EN 60904

standards, which categorize the PV modules according to their I-V characteristics [8]. In

brief, those are: vertical irradiance E of 1000 W/m2, cell temperature T of 25°C with a

tolerance of ± 2°C and a defined air mass AM =1.5. AM defines the shape of solar light

spectrum, in an approximate way, at a specific position of sun in comparison to that at

zenith at sea level, which considers to be 1. AM increases as the zenith - sun angle increases

since the light passes through “more atmosphere” and the attenuation (scattering and

absorption is greater.

Figure 2.3: The effect of solar radiation and temperature on the I-V curve [8]


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A PV system, which is an interconnection of PV modules in series and in parallel, has its own

I-V curve depending on how many PV modules are connected in series (strings) and how

many are connected in parallel. Below it can be seen how the characteristic is formed by

adding PV modules to the system. Furthermore, figure 2.4 points out that only PV modules

with the same electrical characteristics are used in the interconnection in order to avoid

power losses in the final system.

Figure 2.4: The effect of the interconnection of PV modules on the I-V curve

2.2 Grid-connected PV systems

Grid connected systems were explained in the previous section 2.1 as one of the two types

of PV systems. In this part of the chapter a more detailed reference will be attempted since

they cover the highest share of the installed photovoltaic capacity, either as on-grid

domestic systems or power plants. Such PV systems consist mainly of the following

components [8], [11], [12]:


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� The PV modules that interconnect together forming the desirable system. The PV

array is basically the generator of the system and specifically the static generator as

it will be presented later on, since there is no rotating part.

� The mounting system, which for PV power plants is a stone or concrete pad

foundation with metal or timber frames attached on it. The mounting system should

above all ensure the designed angle of the PV system with the sun’s incident

irradiation. When the system is implemented in an open field, sometimes the

mounting should be within some requirements for environmental reasons.

� The DC cabling.

� The PV combiner/junction box, which is the place where all the strings are

connected together and end up to the main DC cable. This box contains also

important safety components as string diodes, fuses, isolations and the DC main

switch to protect the system and the maintainer from accidents in case of faults.

These protections together with the equivalent ones from the AC side are also found

in literature as the balance of the system.

� The PV inverter, which transforms the DC current to AC and supplies it to the grid

(mostly distribution), fully synchronised in frequency and voltage with it. The

significance of this component is high and the full modern role is described in the

following section of the chapter.

� The AC cabling and necessary protection.

� The meter cupboard, which is the system’s data monitor involving supply and feed

meter, displaying the flow energy between the PV and the grid or/and the load.

In large PV power plants, there can be additional components that improve the efficiency of

the system or ensure better control and monitoring. For instance, cooling pipes in the back

of the PV array to reduce the operating temperature and increase the MPP or remote

monitors that allow real-time performance, output values and potential faults to be

displayed in a the owner’s computer are some examples of such components.

2.3 PV inverter

The PV inverters that are studied in this thesis are the grid-tied ones. They are also found as

utility-intertie or synchronous inverters. The labelling exists, because there is often a

misunderstanding that there are no inverters for stand-alone systems or that both types of

inverters are the same. In fact there are and they can connect to the grid, but only to import

power from the grid and not supply [11].


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2.3.1 What is available – Current status

PV inverters can be categorised in various ways according to the topology, the operation

principle, the type of the connection to the grid and by application. Based on the connection

to the grid inverters can be:

� Single-phase inverters refer to inverter structures applied in small scale roof-top

systems (of until 5 kWp).

� Three-phase inverters refer to larger systems, which is mostly the case for on-grid PV

systems and are connected of course to a three-phase supply system. The basic

three-phase inverter consists of three single line inverters, which are connected to

each load terminal. So, it is not actually a true three-phase inverter and this is

because a three-wire topology will require relatively high DC voltage values (around

600 V for a 400 V three-phase grid) and is limited to 1000 V due to safety reasons in

installation procedures. Also the monitoring and control for islanding requirement

becomes more difficult in relation to three single phase connections [14]. The inverter as an electronic oscillator is required to generate a pure sine wave

synchronized to the grid as stated before.

Figure 2.5: Principle of connecting PV systems to the grid with a single-phase and three-phase inverter [8]

According to the size and the application, inverters can be central, string, multistring and

module kind [11], [14].

� Central inverters are connected with more than one or all the parallel strings of PV

modules and can be of some kW until one MW of power range.

� String inverters are connected to each string of the PV array seperately and their

range of power is a few KW (0.4 - 2 kW).

� Multi-string inverters are a rather new concept according to which, several strings

of different configation (different PV modules) and orientation can be connected


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together. For this reason, necessary DC-DC converters are used to provide the same

output signal to the input of the multi-string inverter. Multi-string inverters increase

the efficiency of the system since every string can track its own MPP. Their range

varies from 1.5 kW to 6 kW.

� Module-type inverters are connected to each module seperately transforming it in a

PV AC module. Their use is still limited and their range is from 50 to 400 W.

Taking into consideration that the PV modules produce DC power at a low voltage, the

system’s output requires some adjustment to be fed as AC power at the votage of the grid

as cited before. The inverters used for this adjustment and apply diferent operation-

principle are [8], [13]:

� Line-commutated. Such invertrs use switching devices (thyristor bridge or IGBT) that

control the switch-on time only. The switch-off time is done by reducing the circuit

current to zero by using the voltage of the grid. The name line-commutated

represents exactly this grid controlled dependance, meaning the inverter uses the

voltage of the grid to decide the turn on and turn off time of these thyristors. One

disadvantage is that they produce a square wave current output, which introduces

undesirable harmonic components, which can be reduced by the use of filters. This

principle is used today less especially in single phase inverters.

� Self-commutated. Such inverters are more complicated and use switching devices

(IGBT and MOSFET) that can control the switch-on and switch-off time and adjust

the output signal to the one of the grid. The self-commutated inverters are the

predominant technology in PV power sources because of their ability to control the

voltage and current output signal (AC side), regulate the power factor and reduce

the harmonic current distortion. Especially, since the role of PV inverter has become

more vital, this operation principle is offering the capabilty to cover the multiple

services and increase the resistance to the grid disturbances. Depending on the type

of pulse they control, either voltage or current, self-commutated are divided to

voltage source and current source inverters.

• Voltage source inverters (VSI). VSI realize the DC side as a constant voltage

source and the output current is changing with the load. For this reason is

normally connected to the grid with an inductance so as not to supply with

current infinitely when there is not voltage or phase match between

inverter and grid.

• Current source inverters (CSI). Respectively, CSI the DC source appears as a

constant current input and the voltage is changing with the load. The

protection filter is normally a capacitance in parallel with the DC source.

Self-commutated inverters produce very good sine wave outputs with the use PWM

technic and low pass filters [8].


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Another basic criterion for categorizing PV inverters is whether or not use galvanic isolation

(transformer) to connect to the grid. There are many advantages and disadvantages in each

type to be considered, with Electromagnetic Interference (EMI) being one of the most

important issue. Inverters with low-frequency transformers (50 Hz) or high frequency

transformers (10 kHz to 50 kHz) have the DC circuit seperated from the AC circuit, offering

recuction of EMI. However, the big size especially when using low frequency transformers,

the lower efficiency of the inverter due to transformer losses and the extra cost turn the

attention to transformless topologies and their improvement to work in higher power

ranges than today [8]. Transformless topologies still need more innovative and complicated

solutions to become competitive especially in terms of electrical safety. Furthermore, in

cases when the the DC output of the PV system is not as the one of the grid or higher, a

step-up DC-DC converter is needed. Thus, part of the losses that were avoided from not

using a transformer are compensated by the use of the converter. Nevertheless, almost all

the typical applied inverter structures today need a boosting and require a DC-DC converter

[14].

In general, there are numerous different topologies of inverters that could apply in grid

connected systems. Today, big manufacturing companies promote their own designs and

variations, which are derivatives of two main converter families [14]:

� H-bridge or FB topology. Figure 2.6 shows the original structure of this topology,

which is used in the most typical complete PV structures nowadays. Based on that

many designs have been patented offering a wider range of choices (e.g. H5 Inverter

of SMA, HERIC Inverter of Sunways, REFU Inverter etc).

� NPC topology. It is a more modern topology and the one that was connected to the

grid without transformer. In general and in comparison with the FB topology, NPC

can produce lower switch losses and harmonics, improving the efficiency of the

inverter [15]. However, is rather unbalanced and require double voltage input in

comparison with the FB topology [14].

Figure 2.6: FB inverter topology [14]


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2.3.2 Issues when choosing inverter It is obvious that selecting the right inverter technology for the PV system is an issue with

many parameters, technical and economical. If there is no clear purpose from the operator

of the power plant then the choice is always the one that combines the best possible

efficiency output with the best possible cost (investment, operation and maintenance).

However, there are PV power systems that aim to the highest energy output for covering

partly or fully a load need and others that aim to support and optimize a weak grid.

Therefore, the system’s basic configurations (PV array, control systems, inverter etc) should

be approached and analyzed differently. Even so, no matter the objective of the system,

basic considerations should be addressed when selecting a PV inverter and these

considerations should be examined under the technical requirements and specifications

(grid codes) of each country. Below these issues are presented [16].

� Efficiency. This is a basic issue in every system, but mostly in PV systems where the

highest energy yield is the priority. The current efficiency of the inverters is very high

in every topologies, reaching the 92% and 94% in inverters with transformers and

even higher without galvanic isolation. As rule of thumb an improvement of 1% can

result in 10% more power output over a year [16]. Standby power losses during

periods of negligible load need to be assessed, because they affect the overall

efficiency. Since inverters operate at different efficiencies depending on the load,

every inverter is expressed with different efficiency curve. A reliable method to

evaluate the overall efficiency of the inverter is the European Efficiency standard or

else eEURO. This standard takes into consideration the amount of time (in percentage)

that the inverter is expected to work at partial load/level of irradiation. Even if this

standard is valid for irradiance levels of Central Europe, it is a sufficient way to

compare different inverters [11]. The euro-efficiency is defined by (2.1)

5% 10% 20% 30% 50% 100%0.03 0.06 0.13 0.1 0.48 0.2EUROη η η η η η η= + + + + + (2.1)

Explaining a factor of the above component e.g. 0.03, it means that the inverter is

operating at 5% for a duration of 0.03 and the total operating time.

� Safety. Refers mainly to Anti-Islanding (AI) protection. Unintentionally islanding takes

place when PV inverters don’t disconnect from the utility after it has been shut

down. This is due to the fact that there are load circuits that happen to resonate at

the frequency of the grid. So the inverter continues to put voltage on the grid making

it unsafe especially for the utility workers. Isolation transformers and other AI set-

ups are defined by standards (e.g. VDE 0126, IEEE 1574) [14]. Similar protection is

required against over-currents, surges, under- and over-frequency and under- and

over-voltages for DC input and AC output.

� Power Quality. This issue is actually a general requirement for all grid-connected

inverters and not only PV ones. It refers to variations in voltage magnitude,

frequency limits, harmonic content in the waveforms and other parameters. The

THD limits are set by international and local standards (usually less than 8%). The


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total harmonic distortion is given by (2.2) [17]. In general the harmonic content must

be low to protect both loads and utility equipment. The waveform and power factor

must be acceptable to the utility.

402

2

1

hh

X

THDX

==∑

(2.2)

1

hX harmonics

X fundamental

==

� Electromagnetic Interference. It should be as low as possible in order to comply with

the limits of relevant local requirements.

� Compatibility with the array. Both array and inverter need to be compatible and the

inverter should be able to withstand the maximum array current and voltage. The

VOC of the array should also be well within the inverter’s tolerable voltage range. The

MPP range of the inverter should also match the operating voltage of the array.

These compatibility issues can be seen in figure 2.7. As far as the MPP tracker

requirements concerned, those should be of high efficiency during steady state, fast

tracking in sudden changes of solar radiation and stable operation at very low

irradiation levels [14].

Figure 2.7: Inverter’s operating range [8]

� Lightning and voltage impulse protection. These must comply with local provisions.


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� Other. Issues like size, weight, construction and materials, protection against local

weather conditions, terminals, and instrumentation should be addressed in

conjunction with local rules.

2.3.3 Additional requirements – Ancillary functions

The additional requirements have been “enforced” by GCs due to the increasing penetration

of photovoltaics into the grid and basically impose additional functions and technical

improvements concerning the grid support. Summarily these new roles are:

• Voltage control

• Active power control

• Reactive power compensation

• Harmonic compensation

• Fault ride-through

Those new services of the PV inverters will be presented more deeply later on in the “new

German Grid Code” section.

2.4 Low voltage ride through (LVRT) requirement

In general, the definition of LVRT or FRT includes the requirements that a power generating

unit tied to the grid should meet, in case of a voltage dip due to a fault or sudden load

change in the grid. The impact of the voltage dip can be described according to the voltage

level reduction and its duration.

In this case, the power generation unit is a PV system, connected with the grid through the

inverter, which is in fact the device that should be capable for LVRT. The possible scenarios

during a voltage dip (or power dip) are:

� Immediate disconnection from the grid, when the fault occurs and throughout its

duration. The inverter shall reconnect again after the fault is cleared.

� Stay connected to the grid during the fault.

� Stay connected but support the grid only with reactive power (reactive current)

during the fault. After the clearance of the fault the unit should consume the same

reactive power as before the fault.

From the above three scenarios, the one that will be applied depends on the decision of the

grid operator under respective grid codes. Until recently PV systems were designed with the

sole purpose to provide the best possible active power to the grid. Therefore, the PV

inverter topologies and control systems were orientated mostly to the MPP tracking and


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even if they were designed to provide reactive current, during a fault they were

disconnecting from the grid under technical standards as IEEE 1547 and VDE 0126-1-1 [17].

However, due the extensive PV penetration into the grid, as described in the introduction

chapter, the requirements have been modified. The PV inverters should stay connected to

the grid and support it with reactive power, when needed, contributing to the power quality

and prevent voltage instabilities. The disconnection-reconnection scenario is aggravating for

the components of the system reducing possibly their lifetime or causing even greater

instabilities to the grid especially in large scale integration. Moreover, after disconnection

the PV unit will be connected again when the grid is stabilized, meaning that the time that is

off the grid the loss of active power could be of great significance especially on grids where

the share of PV power is high.

2.4.1 Reactive power and its importance

The high importance of the reactive power was perceived after major blackouts (e.g. Ohio in

2003) that occurred due to voltage drops (and subsequent current rise) in electricity lines,

when one line was cut off and the remaining ones could not bear the load. Reactive power,

in general, can be seen as a tool to provide smoothly real power and has a strong effect on

the voltage of the system. It is a circulating power in the grid that doesn’t do any useful

work.

In PV systems the importance became obvious after the growth of PV systems connected to

the LV and MV as well. The existing grid was not designed for such high penetration of

interconnected PV and a violation of voltage limits in times of high solar irradiation was

possible. For this reason PV inverters should be able to provide reactive power in order to

reduce the voltage rise along the feeder [18]. As mentioned above, in case of voltage

collapse the inverter should be able to provide reactive current and stabilize the grid within

some time frames defined by grid codes. Nevertheless, reactive power compensation for

the PV inverters hasn’t been part of many local GCs. German utilities, though, have defined

and analysed the supply methods of reactive power, which are stated below the “the new

German Grid Code” section.

The specificity of the PV systems to be close to the location where the reactive power could

be needed is an advantage considering the fact that reactive power does not travel far in

comparison to the active power [19].

2.5 Grid requirements for PV systems

The need of improved and new technical specifications, as stated in previous parts of this

report, is the requirement that will ensure smoother penetration of PV systems, without

compromising the power quality and stability of the grid. The GCs represent these

requirements and address to network operators, project designers as well as component

manufacturers (mostly PV inverter manufacturers) in order to design their products


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according to some uniform guidance [20]. Photovoltaic power systems affect mostly the low

and medium-voltage network and only approximately 1% of the high voltage network is fed

by PV power [5], meaning that the demand for grid stability reflects the low and the

medium voltage networks.

The growth of the renewable generation and the expansion of distributed generators, have

aroused awareness to many countries. However the introduction of effective grid codes is a

rather difficult task with problems that cause significant delays in the process [14]. Some of

those problems are the different features among the different generators, the void

legislation pattern and the lack of production management in the field. The PV industry is

even more sensitive to such problems, because of the wide range of different PV inverter

technologies and designs and their multitask role in comparison to the conventional one

they had until now [14].

Due to the different grid characteristics there are many different GCs that have been

introduced around the world. Countries as China, Australia and India have different

requirements among them. Even inside Europe there are many differences. Concerning the

PV field the requirements usually follow the requirements of wind power systems or the

general provisions that apply to the generators that produce electricity close to the end

users of power (distributed generation).

2.5.1 The new German Grid Code

The situation in Germany is examined selectively, because its GCs directives are the most

updated and specific ones. The Federal association of Germany has introduced in June 2008

a new code referring to the connection and operation of distributed power generation

plants to the medium voltage power grid. This code was published as a consequence of the

Transmission Code of 2007, which covers the requirements of systems connected to the

high-voltage grid (transmission network) [21]. The PV power plants that were excluded from

the provisions of the Transmission Code are now affected by this new medium voltage grid

code reforming their static and dynamic requirements as well. Since January 1st 2011 all the

new PV plants should comply with this code, while existing units can still operate according

to their initial requirements [20]. The following table 2.1 summarizes the new requirements

based on the definitions of the HV in VDN, MV in BDEW and LV in Network Technology/Grid

operated with VDE (Netztechnik/Netzbetrie beim VDE) grid codes. The operating

requirements are given at the PCC.


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Table 2.1: New requirements for grid tied generators [22]

Static Voltage Support

Under continuous operation and when the system operator requires it, the unit must be

capable to participate in the static voltage support in order to keep the voltage within

acceptable limits when slight deviations occur. The participation is has to do with reactive

power injection capabilities which are described below. These voltage limits are different in

every level of voltage but are usually between +12% and -13% of the nominal voltage [23].

The IEEE-1547 standard requires for the utility interactive inverters +10% and -12% at the

PCC [24].

Active Power control

Active power control or active power throttling [21] or active power derating [22] or active

power curtailment [14], [23] as it is found in the literature refers to the ability of the

generating plant to reduce/adjust its power output as required by the network operator or

even disconnect the PV plant in order to avoid potential dangers regarding the stability of

the system and human personnel. Some cases of controlling the active power could be:

unsafe system operation, unintentional islanding, frequency deviation or maintenance after

a grid failure.

In Germany the active power is required to be changed with a ramp rate of 10% per minute,

or smaller, of the rated active power capacity until any level is necessary. However, it

cannot be lower than 0.1 p.u [14]. The power plant should not disconnect from the grid for

any setpoint over 10%. The control is implemented normally in two ways [20][21]:

� Automatically, when an overfrequency is detected.


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22

� Manually, with the use of an adequate signal by the operator, which represents a

setpoint (e.g. 100%, 60%, 30% and 0%). There is no physical interference in the

control unit, only the use of the control signal.

As far as the first way concerned, the control unit should follow the below figure 2.8.

According to this figure the PV system should reduce the power output when the frequency

exceeds the value 50.2 Hz. The slope or gradient of reduction should be 40% of the

instantaneous last value of power just before the 50.2 Hz. Besides the upper frequency

limitation, the value 50.05 is the lower limit below which the PV system can increase again

the active power feed-in. The grey areas in the figure set where the plant should disconnect

from the grid, what is to say below 47.5 Hz and above 51.5 Hz.

Figure 2.8: Active power control requirement for grid-tied generators [20][21]

Reactive Power control

The reactive power was discussed in a different part of this thesis, in an attempt to

emphasize its importance to the safe operation of the grid. The German GCs state that the

generating units should be able to provide reactive power support in every operating point

by adjusting the power factor at the PCC, at least in a value of 0.95 both leading and lagging

for all the power levels. The investigated reactive power supply methods are [18][20][25]:

� A fixed power factor (cosφ).

� A cosφ(P) function, where the provided power factor depends on the

instantaneous active power output of the inverter. In figure 2.9 an example is seen,

as well as the limitations (0.95underexcited to 0.95overexcited)

� A fixed reactive p ower.


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� A Q(U) droop function, where the provided reactive power depends on the voltage

at the PCC.

Figure 2.9: Example of cosφ(P)-characteristic [20]

Nowadays, PV systems are mainly designed to provide active power, since reactive power

contributes to losses in the lines, transformers and inverter. For this reason and in order to

comply with the above requirement the inverter should be oversized. What is to say, taking

into account the above power factor of 0.95 an inverter able to supply 475 KW should be of

500 kVA apparent power.

Dynamic Voltage Support

When referring to dynamic voltage support, it is simply implied the requirements what a PV

system should fulfil under fault conditions and grid disturbances and also which should be

its behaviour after the restoration of the fault. These requirements are [14], [20]-[22]:

� Fault-Ride-Through requirement, which is mainly LVRT that described before.

During a voltage drop the PV should remain connected to the grid even if the

voltage at the PCC drops to zero. As seen in the figure 2.10 the system is required

to stay on grid for 150 ms and inject reactive power. The time chosen is typically

the operating time of the protection relays. However if the voltage continues being

lower than 30% of the nominal, the unit can disconnect since there are no

requirements for that duration (above 150ms). Borderline 1 is placed to distinguish

the normal operation, since above it the voltage dips may not create any instability

and the system should stay connected. However, in the area below the borderline

2 there is a possibility of short or longer disconnection. In the area that is defined

between the two borderlines the PV generator should stay connected and provide

reactive power after arrangement with the system operator. A short-time

disconnection of up to 2 s is also within arrangement.


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Figure 2.10: Fault-Ride-through capability [20]

� Reactive current injection requirement. During the fault and as described above

the PV should support the grid (voltage support) by feeding-in reactive power or

absorbing. In the German GCs the required reactive current is defined as presented

in figure 2.11.

Figure 2.11: Reactive current injection requirements in the event of network faults [20]

As it is obvious in the figure, a deadband of 10% of voltage variation is used, where no

current is injected. The purpose of this deadband is to improve the stability of the grid. The

response time of the reactive current controller should be preferably less than 20 ms

(maximum 30 ms). In case the fault does not apply in the same way in each phase


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(asymmetrical fault), the reactive current should not cause voltage increment above 10% of

the nominal voltage in the non faulty phases.

2.5.2 The Situation in the Rest of Europe

There are other European countries that have developed in detail their own GCs. Scotland,

Ireland and Denmark are some examples of countries that have released specific codes that

determine FRT, power factor and dynamic requirements that can be found in detail in [23].

However, these directives are mostly reflect wind power systems or other renewables

connected to distribution system and there is no specific reference for PV systems to

comply with. The case that could be excluded is Spain where, since 1st January 2011, grid

requirements are in effect covering also the photovoltaics [28]. In France the case is similar,

while in Greece GCs codes are under investigation [20].

2.5.3 Further International and European requirements for PV

Beside the local GCs, there are number of worldwide standards that are being developed by

international organisations in order to promote uniform-based requirements that could

boost up the PV market even more and facilitate the interconnection of distributed systems

among neighbour countries. Some important of those standards are presented briefly below

[14]:

� IEEE 1547 – Interconnection of Distributed Generation. This standard is the result

of effort to establish an interconnection standard that applies to all technologies. It

comes as continuity from the IEEE 929-2000 and the UL 1741 that covered

recommended practices for utility interface of small-scale PV systems and listed

important safety and grid performance requirements that influenced a lot the PV-

inverter technologies. IEEE 1547 gives base on technical specifications and testing

standards, setting mandatory provisions for power quality, dc current injection and

AI requirements for interconnected generators of up to 10 MW.

� IEC 61727 – Characteristics of Utility Interface. This standard is more specific for

PV systems and refers to on-grid systems operating in parallel with the utility and

utilize static non-islanding inverters and also to PV systems interconnected to the

distribution system. A more specific standard, IEC 62116, has been implemented

also, defining the testing procedures of AI measures that cited in the IEC 61727.

� EN 50160 – Public Distribution Voltage Quality. It defines the main voltage

parameters and the acceptable deviation ranges at the PCC in the MV and LV

network and under normal operation. Those parameters affect highly the control

and design of the PV inverters in order to withstand voltage disturbances. Thus, the

PV inverter should be designed to comply with [14]:

• The voltage harmonic levels. Maximum THD is 8%.

• The voltage unbalances (three-phase inverters). Maximum unbalance is

3%.


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• Voltage amplitude variations. Maximum ± 10%

• Frequency variations. Maximum ± 1%

• Voltage dips: duration less than 1 s at 60 % dip

The above parameters should be fulfilled during the 95% of the testing period,

while for 5% of the period other wider ranges apply. The specific variations in

voltage and frequency are describes in the local GCs.

MSc Thesis Project Methodology

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3 Methodology

The method applied in this thesis and meeting the objectives was based on creating a

sufficient background by continuous literature review of a number of scientific papers,

articles, reports and books. The necessary information were filtered and used to provide a

theoretical overview over the grid connected photovoltaic systems and support with

discussion the simulation results. Furthermore, during this bibliographical research the first

acquaintance with the modelling tool was made, by studying tutorials and useful parts of

the technical manual.

Since the theoretical needs have been satisfied, the practical part was initiated that covers

an examination of a PV model of DIgSILENT at first, a modification of it and a development

of two interconnected systems.

3.1 Description of the tools

The study that was carried out in this project was a simulation study of a PV on-grid system.

The model as well as the simulation was performed using the PowerFactory tool of

DIgSILENT. The respective company has applied years of experience in modelling power

systems and the simulation tool is considered to be one of the most powerful in the field.

DIgSILENT provides the ability to the user to simulate load flow, RMS fluctuations and

transient events in the same environment. PowerFactory has a quite comprehensive library

of models for electrical power system components such as generators, motors, relays etc, as

well as many passive network elements such as lines, terminals, transformers etc. Those

built-in models can correspond to predefined types that are part of the library or user-

defined data types. What is more, it is possible to create new models with DSL and by using

mathematical formulas that describe the behaviour of the model.

The version used is the latest one (version 14.1), which very more adequate for distributed

generation modelling. Load flow studies and RMS dynamic simulations were the functions

that used in this thesis.

3.2 Ways for simulating PV with PowerFactory

Until now three methods have been used to model a PV system itself with PowerFacory,

regardless the type of control. In each method different elements/components are used


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depending on the user’s experience and the type of study that is performed. Below those

methods are deployed in short.

DC Current Source

In this method the PV array is represented as a DC current source connected to a DC

terminal. This is a simple way to simplify the PV array and focus on the grid and its

behaviour. In parallel with the current source a shunt filter is used, which is the capacitor for

these models. The below figure 3.1 shows the set-up as it was captured from a model.

Figure 3.1: PV array as DC current source

DC Voltage Source

In fact DC voltage source is used to model PV systems with storage requirements and not to

represent the PV array itself. The battery can be considered as a source of real voltage. The

source voltage represents the open circuit voltage between its terminals [26]. An example

from the PowerFactory library is shown in figure 3.2.


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Figure 3.2: PV model with battery

PWM converter

As seen in figure 3.2 and more clearly in figure 3.3, PWM converter can be used to model a

PV inverter. The PV array is again modelled as a DC current source connected to a DC

terminal and a PWM PV inverter is used to create a sine wave. This converter represents a

self-commutated, voltage sourced converter [26].

Figure 3.3: PV inverter as PWM component

Static generator

The PV system is modelled as a static generator, since there is no rotating part in the PV

array. The static generator is used for other similar generators, without rotor, such as fuel

cells, storage etc. Since the generator is connected to an AC terminal, it includes the PV

array, the DC terminal and the PV inverter, which are normally presented as DSL user-

defined models in the general frame. A more detail reference is done in the following


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chapters, because in this Thesis the component used for modelling the PV system is the

static generator.

Figure 3.4: PV system as static generator

MSc Thesis Project Model Description

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4 Model Description

4.1 The base model

The basic PV system that is analysed in this Thesis is developed by a static generator. It is a

generic model that was built by DIgSILENT as part of a past study and is available in the

newest version of the PowerFactory tool. The template consists of the PV generator with

number of control systems and design features, which are integrated in it and also a LV

terminal of nominal voltage 0.4 KV that the generator is connected with. The capacity of the

system is 0.5 MW.

The model is being examined thoroughly and its features are being presented below. Some

additional information about the DSL code and the parameters used are found in the

Appendix. The model is being analyzed in accordance with the German GCs and its

possibility to serve the needs of PV on-grid systems in Germany. Below in figure 4.1 the

system-model is pasted and highlighted inside the red box. The rest of the configuration,

which includes an external grid, a MV bus bar of 33kV nominal voltage and a step up

transformer of 0.5 MVA rated power, were just built in order to serve the needs of the

examination.

Figure 4.1: The base PV model


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The external grid that is used in the system is a component of the program. The values that

are used for the calculations in the study are the minimum short circuit values as seen in

figure 4.2. In general, the minimum values are used to determine where to set the fault

pickup level. The minimum short circuit current is the smallest current that can run at a

given point and the circuit breaker should be able to sense that fault at that point [27]. The

maximum values of short circuit currents are calculated to determine the breaking capacity

of the circuit breakers. Both minimum and maximum values are defined by the IEC standard

(IEC 60909) [27].

Figure 4.2: The external grid settings

The assumption that the short circuit power is 30 times higher than the capacity of the solar

power is used [28]. This value is considered a good estimation. In order to determine how

much of PV capacity can be installed in a certain grid, load flow studies are necessary to

check the voltage rise at the PCC.

From this value and using (4.1) [29], the initial short circuit current is calculated

automatically by the program. Figure 4.3 is a simple representation of a short circuit.

Figure 4.3: Simple equivalent of a short circuit on the grid [29]


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'''' '' ''3

3kQ

kQ nQ kQ kQ

nQ

SS U I I

U= ⇔ = (4.1)

where,

33 ( nominal voltage)nQU kV MV=

The c-factors, or else voltage factors, are according to IEC 60038 for MV up to 35 kV [27],

[29]. Voltage factors refer to voltage regulation and imply that the pre-fault voltage

(nominal) would be approximately 5% lower than the no-load voltage. The voltage factors

cmax and cmin define the allowance for system voltages. Here the cmin value is used, which is

used for minimum currents. As far as the R/X ratio concerned, based on the conclusions of

[30], at low values (<0.4) reactive power is more effective for voltage regulation in

distribution networks, while for values above 1.8 active power has a larger impact. In this

case a value of 0.3 is assumed.

4.2 The PV generator

The PV generator under normal steady-state operation and flow injects 448.84 kW and 0

kVar as seen in figure 4.4, implying PF=1 at the point of connection with LV terminal. The

active power is at the MPP and is defined by the parameters of the PV array and the data

sheets of the PV modules used in the array. In table 9.1 the values of Vmpp and Impp of the PV

modules are given for STC and are 35V and 4.58A respectively. Taking into account that 20

modules are per strings and 140 modules in parallel then the following calculation gives the

input active power result.

(35 20 modules ) (4.58 140 modules ) 700 641.2 448.84 series parallelV A kW⋅ ⋅ ⋅ = ⋅ = (4.2)


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Figure 4.4: PV generator power flow characteristics under normal steady-state operation

The active power operation limits refer to the inverter (AC side), which is able to inject 475

kW, due to the 0.95 PF that the PV generator is designed to operate. Concerning the

reactive power limits of the inverter, those are defined by the capability curve, which is

implemented in the generator, shown in figure 4.5 and explained below.


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Figure 4.5: Capability curve of the inverter

In the above graph a, the complete capability curve of the PV generator (or PV inverter) is

seen, which includes manufacturing constraints and limitations defined by the operator and

the GCs. The x-axis is the active power in p.u. values, while the y-axis suggests the reactive

power in p.u. values.

To begin with, the blue line is the power limit of the inverter. The inverter cannot operate

outside this curve since it is limited by the nominal power of the generator (0.5 MVA in this

case). Thus, it is considered to be a manufacturing constrain. I should be stated that the

injected power is limited by the nominal current of the inverter, meaning that is impossible

to operate at maximum active and reactive power at the same time. As far as the black line

concerned, it is the limit of the active power injection by the engine itself due to the

designed power factor (0.95 in this case), as explained before.

Finally, the red lines are the maximum values (limits) of possible reactive power injection.

Those limits are defined by the manufacturer and here are given for three voltage levels as

it is seen in graph b of the same figure. The nominal AC voltage (green lines in graph b) and

the two voltage limits, maximum (blue lines in graph b) and minimum (red lines in graph b)

for normal operation. The lines of graph b are drawn according to the values of the matrices

in figure 4.6.

The inverter can supply reactive power within the limits (-Qmax and +Qmax) according to the

system operator, the control system and method that is used. In the green marked area in


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graph a, the requirements according to the medium voltage GC is shown. The inverter

should supply reactive power within the defined PF limits and of course the maximum limits

(the capability) should cover this area.

Concerning the use of the reactive capability curve, it is used by setting the local voltage

control to a setpoint (0.95 p.u., 1 p.u. or 1.05 p.u.) and running load flow calculations

considering the reactive power capability settings. The static generator tries then to reach

the voltage setpoint by feeding or consuming reactive power until either the voltage

reaches the setpoint or the reactive power reaches its limit. The reactive power capability

curve is expressed in p.u. values, so it is scaled according to the rated power of the static

generator.

Figure 4.6: Maximum reactive power limits in three voltage levels

The area that is highlighted in red circle in figure 4.5 and figure 4.6 is a situation where the

reactive power is limited in a certain active power value and voltage due to the nominal

apparent power (0.5 MVA) and the PF (0.95) of the generator.

As mentioned before, the inverters are not designed to provide reactive power. For this

reason they are normally over-sized to provide some amount of reactive power even in

maximum active power production in order to compensate for the absorbance by the

transformers. Under no solar conditions, they can provide voltage support at no extra cost

[31].

4.2.1 The Control Frame of the PV Generator

The control frame of the PV system is shown in figure 4.7. At first glance it is obvious that

there are blocks for modeling the DC bus bar and the PV array itself since in the electrical

diagram of figure 4.1 these components are integrated in the static generator. The basic

schematic consists of 11 slots, which have been numbered in order to be more obvious to

the reader.


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Figure 4.7: The control frame of the PV generator

Solar Radiation (Slot 1)

In the second chapter of this Thesis the influence of the solar irradiation to the PV array

current and consequently to the power output was presented. The existence of this slot is to

to comprehend with all the potential change of irradiance (dE) per second and integrate

them over a period of time (see figure 4.8).


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Figure 4.8: The structure of irradiance slot

This is of great importance when examining ramp rates and dynamic behaviours of the PV

system during cloud effects. Below in figure 4.9 a simple case of solar radiation increment is

presented, while in figure 4.10 its effect on the PV output characteristics are seen.

Figure 4.9: Solar irradiation increment


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Figure 4.10: Effect of solar irradiance in the PV characteristics

From the above, it is clear the high effect solar irradiance has on the PV array current (~ 70 A

more). On the other hand the voltage output and the Vmmp of the array are not influenced

much from this rise (less than 10 V). Therefore, as expected the PV power output increases

when the solar irradiation increases. This is shown in figure 4.11. This result is not entirely

correct, because with the rise of the incoming radiation, the operating temperature of the

PV array is rising also, especially when there are no cooling mechanisms (fans, heat

exchangers etc). In fact the PV power output will start decreasing slightly after a point, since

the array voltage will decrease.

Figure 4.11: Effect of solar irradiance in the PV power output

In this case and under normal operation, no shading effects are taken into account, so the

constant value of this slot is irradiance of 1000 W/m2, which corresponds to the STC


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irradiance. The upper limit of the integrator is set to 1400 W/m2, which is related to the

mean solar power above Earth atmosphere (1366 W/m2) [32].

Temperature (Slot 2)

Similar reasoning follows the temperature slot. Temperature is the second important factor

that influences the power output of the PV system by affecting the voltage of the array. An

integrator is used also here for the potential temperature changes in the cell/module per

second. Such changes can be seen in figure 4.12. The effect in the voltage output is

presented in figure 4.13. However the temperature that is used here is 25 oC which is the

STC temperature.

Figure 4.12: Temperature increment in the PV array

Figure 4.13: Effect of the operation temperature in the PV voltage


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Photovoltaic model (Slot 3)

This slot consists of five other blocks which are presented in figure 4.14. The main

component of this model is the one that is enclosed in blue contour, which is the model

description of one PV module of the whole array. Then according to the way that is

interconnected with identical modules the final outputs of the PV array are calculated,

which are the array current and the array voltage at MPP, as described in (4.2). The inputs

are the operating temperature “theta” and the irradiance “E” that are defined in slots 1 and

2 as seen above, as well as the voltage at the DC bus bar, meaning the operating voltage of

the PV array, which is denoted as Uarray here. In brief, the voltage is passing through a low

pass filter to attenuate the high frequency signals in case of abnormal operation, so under

normal conditions is deactivated. The “filtered” voltage then is devided by the number of

modules that are connected in series in order to achieve the voltage per module.

Figure 4.14: The photovoltaic array model

Inside the PV module an algorithm is used and presented in Appendix (figure 9.1) by

captions taken from DIgSILENT. This algorithm is calculating the voltage and current at MPP

taking into consideration the temperature and solar irradiation dependency. Since all the

parameters are given at STC, corrections should be made in all voltages (VOC and Vmpp) and

currents (Ik and Impp) according to the operating temperatures of the module. The factors au

and ai from table 9.1 are provided by the module manufacturer and are used in the

following equations:


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voltage correction 1 ( )STCau T T= + − (4.3)

current correction 1 ( )STCai T T= + − (4.4)

These correction factors are used to determine with the following equations in figure 9.1 all

the voltages and currents when the PV array operates in real temperatures, in order to

determine undesired voltage and current levels. For instance, early in the morning or in cold

places the Voc is much bigger than in times with high irradiance and high temperatures. Such

voltage ranges can be harmful for the inverter. The calculation procedure is based on the

modifications of ASTM E1036-96 [33].

The equivalent circuit for the ideal solar cell that is used as a model for calculating the

current output is shown in figure 4.15. The equations, found in [34], that follow the below

figure are used in the DSL code to determine the current output. Such models of course

have a low approximation quality, since important parameters as Rs and Rp that affect the

efficiency of the cell are omitted. Rs refers to losses due to poor conductivity and poor

external connection, while Rp refers to losses due to poorly rectifying devices and has to do

with leakage of current through the cell and around the edges [35].

Figure 4.15: The electrical equivalent of an ideal solar cell [34]

0( 1)T

U

UphI I I e= − − (4.5)

0

0

ln( )phT

I I IU U

I

− += (4.6)

0

oc

T

U

UkI I e

−

= ⋅ (4.7)

ph kI I= (4.8)


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0

where,

short circuit current

reverse bias saturation current

open circuit voltage

U thermal voltage (=kT/q) and is around 25.85 mV at 300 K

k

oc

T

I

I

U

==

==

Power Measurement (Slot 4)

This slot is used to represent an active power measurement. A PQ measurement device is

used in the connection point of the PV generator and is implemented in this slot. The output

value that is used is the active power measurement, pist, which is used as an input to the

“DC Busbar and Capacitor model” slot.

Slow Frequency Measurement (Slot 5)

Similar to slot 4, a frequncy measurement device is used and implemented to slot 5.

However, the device that is used is a PLL device and is described biefly later on (slot 10).

One of the outputs of PLL is fmeas, that is used as an input value to the “Active Power

Reduction” block. This value is a clear value of frequency regardless of instantaneous

disturbances, over a period of time [31]. For this reason is called slow frequency, so as to

reflect this slow dynamic function.

DC Busbar and Capacitor Model (Slot 6)

The slot consists of four blocks, see figure 4.16, and represents the DC bus to which the PV

array and the DC side of the inverter are connected. There are two inputs and one output

from the model. The one input is the Iarray that comes from the PV model. The other one is

the active power pist measured in slot 4. The output is the input DC voltage of the PV

inverter. This values is denoted as udc or Uarray and is the value that enters the PV module

model (slot 3).

The function of this slot is rather simple. The active power measured in the connection point

of the static generator is devided with the udc and the current that runs the DC bus is

calculated in A. The magnitude of units is not the same, so attention should be paid for

transforming the MW to A. The DC current is now subtracted from the PV array current in

order to find the differential current that runs in the capacitor, which is connected in

parallel with the DC bus. This current is transformed in p.u. using the nominal current as

base. The nominal current is not known, however is calculated knowing the nominal DC

voltage and the nominal power of the PV. The p.u. current enters an integrator in order to

calculate the voltage across the capacitor, which is the voltage of the DC bus and input of

the inverter. The calculation in the integrator is similar to the one shown in (4.9) and is valid

for any capacitor. At last the voltage is transformed to V units.


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Current Voltage relation−

( )

( )du t

i t Cdt

= (4.9)

Figure 4.16: The DC bus bar and capacitor model

AC Voltage (Slot 7)

Slot 7 represents a voltage measurement device in the connection point of the PV

generator. The output value is uac and refers to the voltage in the LV bus. The value is used

as an input to the “Controller” slot.

Active Power Reduction (Slot 8)

This slot represents one of the main requirements that the PV inverters should meet

according to the German GCs. It is described by the equations in figure 9.2, which are

implemented in the “over frequency power reduction” block that is seen in figure 4.17. The

equations follow the needs described in the analysis of the new German GC and figure 2.8

and its function is examined thoroughly later on in the 4.3.2 paragraph. It has one input,

which is the frequency measurement from slot 5 and one output pred, which is an input to

the main Controller. The frequency, which passes through a filter as well, is the variable that

will trigger the function, when excess of active power in the grid will cause over frequency

situation.


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Figure 4.17: The active power reduction control

Controller (Slot 9)

The Controller is the main part of the PV control frame. In figure 4.18 is seen that consists of

several different blocks. The Controller has four inputs and two outputs. The outputs are the

two components idref and iqref, which will be inputs in the static generator slot where, in

fact, will be used by the PV inverter to modulate and control the active and reactive power

respectively.

Starting with the active power control part, the vdcref is the value that was calculated by the

PV array model and is denoted by Umpp-array. This value is the desired voltage at MPP for the

input of the inverter (DC side). This value passes first through a low-pass filter to atenuate

high-frequency components and then ends to a lower limit block. Inside that block (Max in

the figure), it is compared with the minimum operating value of the inverter U_min, which is

set to be 333 V. According to figure 2.7 the inverter has a low limit voltage on the DC side

below which is turned-off (turned-off voltage level). By this comparison inside that block the

voltage that is chosen vdcref0 is above the U_min. This value is then compared (subtracted)

with the actual voltage of the DC side of the inverter, udc, which is here seen as vdcin and

also with the value dvdcref, which is the difference vdcref0 - vdcin. The result of this

comparison is denoted with dp and is also a voltage that passes through a low-pass filter.

Finally, the dpd value enters a PI controller with proportional gain Kp and integration time Tip

and the id component that regulates the active power is calculated. The PI controller is

limited by two parameters, id_min and id_max, and the variable pred from the slot 8. The


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46

parameters represent the minimum and maximum active current limits respectively, while

pred represents the reduction due to overfrequency. Under normal operation pred is equal

with 1.

On the other hand and as far as the reactive power control part concerned, the uac value

that is measured by the voltage measurement device as described above, passes through a

low-pass filter and is compared with a reference value, uac0 which is the voltage in the

steady state condition (no fault). Both values refer to the voltage on the AC side of the

inverter. The comparison (difference) gives duac, which shows the voltage deviation or

voltage dip in the connection point of the PV generator. This voltage change is the input of

the “Reactive Power Support” block that follows the principle of figure 2.11. The equations

that seen in figure 9.4 define a deadband of 10% of the nominal voltage and determine the

iq component as in (4.10)

q aci K du= (4.10)

The factor K is what is denoted as droop in the parameters table 9.4. The definition of iq is

written according to the Transmission Code 2007 and the System Service Ordinance

SDLWindV. The “Reactive Power Support” block is limited by the maximum reactive current

(iq_max) and minimum reactive current (iq_min).

At last the calculated values of iq and id together with duac enter the current limiter block in

which the reference values of these components are calculated. The limiter sets the

maximum allowed value of ablosute current and the maximum absolute value or reactive

current in normal operation, as limits.


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Figure 4.18: The main controller model

Phase Measurement (Slot 10)

This slot contains a PLL device from the library of PowerFactory. PLL is a closed loop

structure, which contains an internal oscillator that is synchronized by being phased-locked

to some particular grid power signal. Normally, as well as in this case, this element is able to

measure the frequency and phase of a voltage in the system. The measurement point is the

LV bus bar as shown before is slot 5. The basic structure of a PLL is seen in figure 4.19 and

explained shortly below.

Figure 4.19: The basic structure of a PLL [14]


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� Phase detector generates a signal proportional to the phase difference between v

and v’.

� Loop filter is a low-pass filter to cut the high-frequency AC components from the

phase detector.

� Voltage controlled oscillator generates an AC signal, whose frequency is shifted

compared to a given frequency, as a function of the input filtered voltage that is

produced by the loop filter.

Static Generator (Slot 11)

With this slot the static generator component that was described in the section 4.2 (The PV

generator) is matched.

4.3 Investigation under German GCs

In this part of the Thesis number of simulations were run in order to investigate the

compliance of the model with the German GCs. The model was tested for its “static voltage

support” and “reactive power injection” behaviour under normal opearation, it’s active

power control capability, FRT compliance and dynamic support. Each study is run seperately

and presented below.

4.3.1 Steady state condition

As presented before in this Thesis, during the citation of the new German GC, the PV system

is required to participate actively in the voltage support by injecting reactive power to the

PCC. The voltage variations in this case are a result of active power variations from the PV

generator. It is a fact that the PV array output cannot be controlled or predicted with

accuracy since it is strongly resulted by the incoming irradiation and the general weather

conditions of the location of the power plant, which affect the output behaviour of the PV

array (I-V characteristics). Cloud effects, wind speed and dust can influence the power

output significantly resulting in voltage variations at the PCC, which may cause problems

especially in cases where the grid is week. Even the decrement in solar radiation from noon

to sunset can affect the voltage at the PCC. The magnitude of the variation depends on the

PV generator capacity. In this case the grid is assumed strong (30 times higher than the PV

capacity), however an investigation is necessary.

The methods of providing reactive power are four. Here, is examined if the PV generator is

able to fulfill this requirement and with which of the four ways is able to provide the

reactive power. The power factor limits (0.95leading to 0.95lagging), set by the GCs, are taken

into consideration.


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After a closer look to the control frame of the PV model that was presented above, it is easy

to see that there is no Q control function in the system. Only the active power is controlled

according to the German codes and the reactive power supply during the fault (dynamic

support). This can be proved by running a simple simulation, which is presented below.

The simulated event is a parameter event, where the solar irradiation was set to drop

(maybe due to a cloud effect) to 50%. This drop that is seen in figure 4.20 of course implies

drop to the active power output of the PV array. The drop starts at the 5 sec and the cloud

effect lasts for 5 seconds as well.

Figure 4.20: Solar radiation drop

To perform the investigation, a contant power factor of 0.95 inductive (lagging) was set in

the PV generator as seen in figure 4.21 in the load flow tab. The choice of the method fixed

power factor is random and serves the purpose of the study. The generator in a simple load

flow with full capacity (448.84 kW) is injecting 147.53 kVar of reactive power. The expected

result would be that with the active power drop, the reactive power would drop as well in

order to maintain the fixed power factor constant during the voltage variation. If this way of

providing reactive power is not part of the control system, then at least the power factor

should be in compliance with the GC limits to justify the presence of another type of control

(fixed Q, cosφ (P) function or Q (U) droop function). However, the simulation showed

different results, which are presented in figure 4.22.


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Figure 4.21: Set of constant power factor

The active power decrement and the reactive power change at the PCC were plotted in

figure 4.22 for the duration of the event, to observe if the power factor was kept constant.

Furthermore, the voltage deviation due to active power change is seen in figure 4.23.

Figure 4.22: Active and reactive power change during a cloud effect


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Judging by the graphs and the two different points A and B, it is concluded that the power

factor doesn’t remain constant. Moreover, performing the necessary calculations with the

use of (4.11) and (4.12), it is found that no Q control is implemented in the system.

2 2( ) [ )] [ ( )]Apparent power S active power P reactive power Q = ( + (4.11)

( )

(cos )( )

active power Ppower factor

apparent power Sϕ =

(4.12)

Calculations:

2 24.999 point A: 0.898 0.243 0.93 . .

0.898 cos 0.966

0.93

s S p u

ϕ

= + =

= =

2 29.948 point B: 0.399 0.281 0.488 . .

0.399 cos 0.818

0.488

s S p u

ϕ

= + =

= =

The power factor in point B is found 0.818, which is outside the specified limits, meaning

that the model is not capable for static voltage support according to the German GCs. The

voltage change is almost insignificant as seen in figure 4.23, however the reactive power

supply is not according to the GCs. The voltage starts slightly above 1 p.u. due to the fixed

power factor.

Figure 4.23: Voltage deviation during a cloud effect

Furthermore, plotting the active and reactive power behaviour in the LV terminal, where the

generator is connected, the same behaviour is observed. As seen in figure 4.24 at the right

plot, which is a zoom version of the reactive power (green line) of the left plot, the injection

is very small of rate of 10-4, meaning that the results in the MV bus bar are influenced from


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the transformer, which absorbs reactive power regardless of the loading [36]. This

stengthens the argument that there is no Q control for the normal operation of the PV

generator.

Figure 4.24: Active and reactive change in the LV bus

The same results were observed when the solar radiation was set to increase. The active

power increased, while the reactive power was decreased. The voltage decreased slightly as

well.

4.3.2 Active power control

The active power control in case of frequency deviations is also a requirement that a PV

model should meet. In the analysis of the model, it was seen that the model has a seperate

slot for this operation. An active power reduction value due to overfrequency is calculated

(pred) which is set as “limiting input signal” in the PI controller for the id component.

However, to investigate the validity of the function, is thoughtful to create an over

frequency event and see the results of the active power generation.

In order to create a frequency change with PowerFactory the possibilities are more than

one. One way is to use an AC voltage source component with an adequate frame instead of

the external grid and change the frequency, which is an input value in this component.

Another possibility would be to disable the PLL, initialize the frequency using a DSL

command, inc(), and then change it through a parameter event. However in this case a third

solution was chosen which doesn’t require any changes in the model. Based on the

consideration that the grid is like an AC synchronous generator, by changing the speed of

the rotor the frequency is changed. As seen in figure 4.25 a parameter event was set and

the speed was changed from 1 p.u. to 1.04 p.u. The change occurs in the 7th second and the

simulation runs for 10 seconds.


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Figure 4.25: Change in the “speed” parameter to create overfrequency

As seen in figure 4.26 the 0.4 p.u. change in the speed of the rotor created an overfrequency

of 2 Hz, which is enough in order to evaluate the active power reduction, since the upper

limit as shown before is 50.2 Hz.

Figure 4.26: The overfrequency event

Indeed, when the frequency changed the power reduction came into operation and the

value pred changed from 1 p.u. (no reduction) to 0.281 p.u. (71.9% reduction) as seen in

figure 4.27. According to the theory, the reduction step is 40% of the active power per Hz.

In this study the excess in frequency is 52-50.2=1.8 Hz, meaning that the reduction should

be of 1.8 ⋅ 40%=72%.


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Figure 4.27: The active power reduction of the generator due to overfrequency

The reduction of around 72% in active power is seen when perform power measurements in

LV and MV buses in figure 4.28 and figure 4.29 respectively. The reactive power is not

affected, appart from some slight increment in the MV bus due to the transformer

absorbance.

Figure 4.28: The active and reactive power values in the LV bus during the overfrequency event


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Figure 4.29: The active and reactive power values in the MV bus during the overfrequency event

4.3.3 Dynamic voltage support

As explained before, the dynamic voltage support covers LVRT and reactive current injection

requirements. It has been seen already that seperate block is available in the control

scheme of the PV model. In order to examine the behaviour of the PV model under different

voltage dips, four different simulation tests were undertaken based on [37]. The German

technical guidelines for generating units define specific standards for test in order to

examine LVRT behaviour. Table 4.1 displays these tests for type-2 generators (no

synchronous generator is connected), while in table 4.2 the performed tests with the PV

generator are shown. These conditions are seen also in figure 4.30 with different colours in

comparison with figure 2.10. Type-1 generators refer to directly coupled synchronous

generators and their LVRT analysis is based on different tables.

Table 4.1: Voltage dip tests for generating units type-2 [37]

Test-number Maximum line-to-line voltage U/Un Duration of fault [ms]

1 ≤ 0,05 ≥ 150

2 0.20 – 0.25 ≥ 550

3 0.45 – 0.55 ≥ 950

4 0.70 – 0.80 ≥ 1400


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Table 4.2: Tests performed with the PV model

Test-number Maximum line-to-line voltage U/Un Duration of fault [ms]

1 0 150

2 0.2 550

3 0.5 1000

4 0.8 1500

Figure 4.30: Tests performed for dynamic voltage support

For achieving voltage drops of certain percentage a short-circuit event is simulated with the

fault impedance to be adjusted properly. To avoid multiple iterations and testing of

different fault resistances, in order to acquire the desirable voltage dip, an approximate

method was used. This method follows figure 4.31, which is taken from [29] and adjusted.

Figure 4.31: Equivalent plan of a grid with fault (a) and the electrical circuit representation (b)

The above figure 4.31 is described by (4.13) and the values seen in figure 4.2.


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''

''3 3nQ nQ

kQ Q

Q kQ

cU cUI Z

Z I= ⇔ = (4.13)

2 2

''

, where / 0.3 (taken from figure 4.2)

voltage after the voltage dip (e.g. with voltage dip of 80% 20% 33 )

and are taken from the figure 4.2

Q Q Q Q Q

nQ nQ

kQ

Z R X R X

U MV U kV

c I

= + =

= → = ⋅

It should be noted that this method is not accurate. If the calculation procedure will be done

for each test, deviations from the correct value of resistance will be seen. However, it gives

a sufficient range based on which, number of iterations can be avoided. At the end table 4.3

was obtained, which describes the fault impedance in each test. The precision of second

decimal is not necessary since changes are seen in the order of half unit.

Table 4.3: Fault conditions in each test

Test-number Voltage dip [%] Resistance [Ohm] Reactance [Ohm]

1 100 0 0

2 80 1 3.33

3 50 4.17 13.9

4 20 16.5 55

Test 1

Test 1 refers to a voltage dip of 100%. That means that the voltage at the PCC in the MV bus

is 0 p.u. The duration of the fault is 150 ms following figure 4.30. The results are seen below

in figure 4.32. The main concern and requirement for the PV inverters is to observe the

ability of reactive power injection and see the voltage level in the LV bus, where the PV

generator is connected. Each graph from the figure is explained below.


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Figure 4.32: Behaviour of the PV model in 100% voltage dip

Graph a: The active power at the PCC drops to 0 during the fault, while before and after the

fault the value is 0.898 p.u., which corresponds to 0.449 MW (the base is 0.5 MW).

Moreover, the reactive power in the MV in non-fault state is found -0.049 p.u. (24.5kVar),

meaning that the transformer is absorbing reactive power from the grid. During the fault

the reactive power is 0, since it is compensated by the PV generator, which provides a

constant reactive current. This function is seen clearer in graph c.

Graph b: The voltage in the MV bus drops to 0 due to the pure short-circuit fault. However,

in the LV bus (the AC side of the inverter) the voltage is 0.057 p.u., which is around 22.8 V.

Before and after the fault both buses obtain values close to nominal (0.997 p.u.).

Considering these values and based on figure 2.11 and the “Reactive Power Support” block

in figure 4.18 the following simple calculations can be performed:

before fault during the fault 0.997 . . 0.057 . . 0.94 . .ac ac acdu u u p u p u p u= − = − = (4.14)

and since the droop parameter is 1 (table 9.4) the reactive current that is injected from the

PV generator is iq=0.94 p.u, which leads to

during the fault during the fault during the fault 0.057 0.94 0.053ac qq u i= ⋅ = ⋅ = (4.15)

Graph c: The PV generator before and after the fault supplies the LV bus with 0.898 p.u.

active power, which corresponds to 0.449 MW. This value is the same with the one in the

MV bus, which implies that the losses are insignificant, since there is only one transformer


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and no lines in this simple grid plan. During the fault the real power is 0. Furthermore, and

only during the fault the, PV injects 0.053 p.u. reactive power as calculated above in (4.15),

which is 26.5 kVar.

Graph d: The voltage change in the DC side of the PV inverter is seen. In a voltage dip of

100%, the PV inverter obtains the Voc of the array, which is 876 V based on table 9.1

(Appendix), where 20 (modules in series) x 43.8 V (open circuit of a module UI0)=876 V.

In conclusion, it can be said that the German grid code requirements are fulfilled during the

100% voltage dip. The PV generator is able to remain connected to the LV bus and provide

reactive current for the whole duration of the fault. The response time is instant after the

fault according to the needs. After the clear of the short-circuit the voltage stabilizes almost

directly in compliance with the GCs.

Similar conclusions are found in the other tests. The results are seen in the graphs and more

clearly in the aggregative table 4.4 below.

Test 2


is 6.6kV. The duration of the fault is 550 ms. The results are seen below in figure 4.33.



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Test 3




Test 4




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Table 4.4: Aggregation of the results of all tests

Voltage

dip [%]

Voltage

level in the

LV bus

[p.u.]

Injected

active power

by the PV

[p.u.]

Injected

reactive

current by the

PV [p.u.]

Injected

reactive

power by the

PV [p.u.]

Voltage

level in

the DC

bus [V]

100 0.057 0 0.94 0.053 876

80 0.239 0.057 0.753 0.182 872.6

50 0.527 0.279 0.463 0.249 857.2

20 0.807 0.652 0.188 0.155 815.7

Seeing the results of the above table, interesting conclusions can be drawn. Starting with

the most expected outcomes, when the voltage drop becomes bigger the active power

injection of the PV generator is less, while in a pure three-phase fault (100% voltage dip) the

injected active power is 0. Also the voltage in the DC bus bar increases reaching the VOC at

100% voltage dip. As far as the reactive current injection and the voltage level in the

connection point of the PV generator concerned, which is the actual purpose of this

investigation, it is seen that the reactive current injection is bigger when the voltage dip is

bigger. If those results seen in conjunction with figure 2.11, moving further from the

deadband of 10%, meaning bigger voltage dip, the reactive current should be bigger.

Therefore, the results are in accordance with the GCs. On the other hand, the reactive

power injection is dependent on two inversely proportional factors, the voltage level and


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the reactive current. Thus, the maximum value should be at 50%, which is the case as seen

in the table 4.4.

The reactive current injection and LVRT requirements are fulfilled in each of the 4 tests that

the PV model was examined. The voltage stabilizes almost instantly after the fault clearance

ensuring that the PV is capable of dynamic voltage support.

4.4 Summary

During chapter 4 the PV model was investigated according to the German GCs. The

investigation included static and dynamic behaviour and results were presented for both LV

and MV buses. Summarizing the capabilities of this generic model, it could be said that the

generic model is equipped with basic functions in order to address the new requirements.

Active power reduction and dynamic voltage support are met as seen from the results.

However, the lack of reactive power control during normal operation for static voltage

support is considered to be a significant shortcoming.

As far as the ideal solar cell model that the PV array calculations were based on concerned,

for such studies, where the focus is on the impact on the power system, is acceptable. If the

study requires deep analysis and very detailed results, changes should be done and different

solar cell models should be considered such as with Rs or with Rs and Rp or two diode

models.

At last, an issue that was not mentioned during the analysis is that the model has no real

MPP logic implemented. It is assumed that the model works at MPP and a simplified

approximation is used only for the MPP voltage and current by taking into account the

dependency on the irradiance and the temperature with the use of correction factors. For

better performance, the control system could be improved by adopting a more complicated

technique. One way could be adding a block (controller), which will control the vdref signals

as it is seen in figure 4.36. The vdref is the desired voltage at MPP for the input of the

inverter (DC side).


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Figure 4.36: Possible dynamic MPP control

MSc Thesis Project Further Analysis & Discussion

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5 Further Analysis & Discussion

5.1 Addition in the control system of the PV model

It was concluded before that one of the most important weaknesses of the model is the lack

of ability to respond properly to active power variations caused normally by solar irradiation

variations, an attempt was made at this point to implement such function. The approach

that was followed is consistent with simplified methods that used in other PV models built

by DIgSILENT and especially in generic wind turbine models. In figure 5.1 the control

addition is seen inside the red dashed lines and is a constant Q operation mode.

Figure 5.1: The constant Q control implementation to the model

The principal that is used is similar to the one used for the active power control. The control

is done through a PI controller and the switching between fault and non fault current is in

the "Current Limiter" block. The switching for the two operations is seen in figure 5.2, while

the parameters used for the control are seen in table 5.1.


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Table 5.1: Parameters for the constant Q control that added in the “Controller” model

Constant Q control

Parameter Symbol Value

Reactive Power Control Gain [p.u.] Kq 0,6

Reactive Power Control Time Constant [s] Tq 0,5

Measurement delay [s] Tmq 0,001

Maximum Reactive Power Limit (lagging) Qmax 0,296

Minimum Reactive Power Limit (leading) Qmin -0,296

The selected reactive power limit values in the above table were based on the capability

curve of the generator and the manufacture’s settings as presented in figure 4.6 for voltage

0.95 p.u. (worst case). Concerning the values of gain, Kq, and time constant Tq those were

defined after a number of iteration and checking the response of the control to be as close

as possible to the desired value Q that was set. It should be noted that the tuning is not the

optimum one and the trial-and-error method is not always the most accurate one. Tuning

the controller can be rather complicated depending on the application; however for this

study the method is sufficient.

Figure 5.2: The switching function written in DSL inside the current limiter

In order to test the effectiveness of the implemented control a similar method as in the

paragraph 4.3.1 is used. At first through the static generator the method of supplying

constant reactive power is set as seen in figure 5.3. The value of 93.5 kVar (0.187 p.u.)

corresponds to a PF of 0.98, meaning that is within the required limits. Then, a parameter

event is set, changing the instantaneous solar irradiation, which leads to active power

output change. This change is seen in figure 5.4, where it is implied that there is first an

irradiation drop and then an increment above 1000 W/m2, since it is assumed that in steady

state the PV array operates under STC conditions.


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Figure 5.3: The constant Q set in the PV generator

Figure 5.4: The active power change of the PV generator

The results at the bus where the generator is connected are presented in figure 5.5 and

should be seen in comparison with the ones presented in figure 4.24, where there was no

control. The response of the PV generator to the active power drop is almost instant. There

is a small spike at the moment of the event and then the controller tries to regulate the

reactive power supply stabilizing it at 0.187 p.u. (the set value) after a period of one second.

The same response is seen during the increment of the solar irradiation.


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Figure 5.5: The Q control response to the active power change

The spikes in figure 5.5 at the moment of the event change the reactive power within a

value of power of 10-5, meaning that there is no actual effect that violates the required PF

limits. Figure 5.6 show the voltage variations in the LV bus. The change of 10-3 p.u. during

the changes is insignificant.

Figure 5.6: Voltage variation in the LV bus with the Q control

5.2 Model adjustment and interconnection cases

5.2.1 Adjustment of the PV model

In order to adjust the PV model to the needs of the specific task that is analysed later on,

some changes in the configuration of the PV array took place. As mentioned before, the

model is generic, meaning that is open for any kind of changes needed. The objective is only

to change the rated peak power of the model to 1 MVA for load flow calculations and


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dynamic simulations and consequently change the active power output. The modified static

generator (inverter) was based taking into consideration a real commercial central PV

inverter, at least as far as the maximum input and output values of voltage and current

concerned. The full technical data of this inverter can be found in [38].

To achieve that, the following modifications were done:

� In the parameters of the “Photovoltaic model” (slot 3 and table 9.1) the number of

modules in parallel, parameter “nParallelModules”, was set to 290 instead of 140. All

the other values remained unchanged considering the same type of modules in the

modified PV array. The modified array has still VMMP=700 V but the current now is

IMMP=1328.2 A. Judging by [38] the values remain within acceptable and realistic

limits and give maximum power output of 929.740 kW. The change through the

parameters was necessary for the RMS simulations.

� The rated power was changed in the static generator’s basic data as well. The rated

power was set 1 MVA and with the PF 0.95 of the engine the active power

operational limits were set to 950 kW in the capability curve. The active power in

steady state load flow under normal conditions was set 929.740 W, which is the

value defined by the above new configuration. The generator is assumed again to

work at MPP. The change in the static generator data was necessary for the load

flow calculations.

� In the parameters of the “DC Busbar and Capacitor” model, table 9.2, the capacity

was set to double than the previous one, meaning 0.0344 and the rated power

value, Pnen, that is used to define the voltage input of the inverter was set to 1 MW.

� The rated power of the transformer was also changed to 1 MVA in order to satisfy

the needs of the new generator.

The modified generator fulfils the same requirements and behaves the same under both

static and dynamic conditions since no interventions took place in the basic control systems

and no active or passive components were added to the frame of the model. However, the

adjustment “hides” an important assumption. The maximum reactive power limits of the

new inverter remained the same. In reality it is most likely that they would be different.

The modified generator and the transformer are used to create two different models of 20

MVA each. The first model is set by connecting 20 times the generator in series, through

lines. Then the whole plant is connected to the MV bus via a line. In the second set up

another method is applied by connecting the generator 20 times to a common MV bus, like

a star. Since, different number and types of AC lines are used the behaviour of each plant is

examined and the results are compared. Draft designs of both set ups are seen in figure 5.7

and figure 5.8.

The external grid in both cases was modified in terms of short-circuit power value, which

was set 600 MVA. The same assumption of 30 times more than the power plant’s capacity

was made as before.


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Figure 5.7: The first set up of the PV power plant of 20 MVA3

Figure 5.8: The second set up of the PV power plant of 20 MVA3

3 The figure 5.7 and figure 5.8 were made using symbols from figures used in [8]


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5.2.2 First Case

The first configuration was built in DIgSILENT and seen in figure 5.9. It shows a connection,

where each PV generator (with transformer) is connected with the next one via an AC line

(cable). Judging by figure 5.7 and figure 5.9 each of these lines will support different current.

To be more specific, line 19_20 that connects the 19th and 20th generator will carry the

current that the 20th PV generator produces (Iflowed), line 18_19 that connects 18th generator

with the previous ones (19th and 20th) will carry the current that both 20th and 19th PV

generators produce and so on. Since all the generators are the same, then line 18_19 will

theoretically support 2 x Iflowed and finally the line connected to the PCC will carry 20 x Iflowed,

assuming that all the generators are undergoing the same conditions (irradiance,

temperature etc).

Figure 5.9: The first configuration as built in PowerFactory

The amount of nominal current that is carried by each cable defines the type and the

diameter of the cable. In general terms, more current requires a bigger cable (in

diameter/cross-sectional size) to support it. Different diameter means different impedance,


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capacitance and inductance of the cable. So it is vital to conclude to the best possible choice

of cables for the PV system. In this case the selection of cables was made from the types of

lines that the library of PowerFactory offers and according to the nominal current that they

support. Table 5.2 shows all the lines used in the configuration, the nominal current of those

lines and the nominal current that the lines should support.

Aluminium cables were used (Al), which together with the copper ones (Cu) are the most

common types. However, no study for the best type (material) of cable was conducted in

this thesis. The column “nominal current” from table 5.2 was filled from the data of each

type of cable used, while the “current support without voltage drop” was filled using (5.1),

which defines the nominal current of each PV generator that the line should be able to

support. Thus, based on where the line is used in the configuration, meaning which

generators connects, the nominal current (Iflowed) is multiplied with a factor of 1 or 2 or 3 etc

as explained at the beginning of this paragraph 5.2.2. The citation “without voltage drop” is

used, in order to mark the fact that no voltage drop effect across the line was taken into

account due to impedance change.

1

3 20flowed

MWI

kV=

⋅ (5.1)

Table 5.2: Lines used in the first configuration

Selection of lines - 1st

case

Number Lable Type

Nominal current

(ground, kA)

Current support

without voltage drop (kA)

1 Line (PCC) Al 0.635 0.576

2 Line 1-2 Al 0.635 0.5472

3 Line 2-3 Al 0.565 0.5184

4 Line 3-4 Al 0.565 0.4896

5 Line 4-5 Al 0.51 0.4608

6 Line 5-6 Al 0.51 0.432

7 Line 6-7 Al 0.456 0.4032

8 Line 7-8 Al 0.456 0.3744

9 Line 8-9 Al 0.397 0.3456

10 Line 9-10 Al 0.353 0.3168

11 Line 10-11 Al 0.32 0.288

12 Line 11-12 Al 0.282 0.2592

13 Line 12-13 Al 0.238 0.2304

14 Line 13-14 Al 0.238 0.2016

15 Line 14-15 Al 0.195 0.1728

16 Line 15-16 Al 0.166 0.144

17 Line 16-17 Al 0.139 0.1152


KTH, June 2011

72

18 Line 17-18 Al 0.139 0.0864

19 Line 18-19 Al 0.139 0.0576

20 Line 19-20 Al 0.139 0.0288

Load flow study

Before performing similar studies, as presented in chapter 4 for the generic model, load

flow calculations were conducted. The purpose was to investigate the behaviour of the

power plant when the active power output decreases in conjunction with the voltage

deviation at the PCC in a strong grid. By power plant, the 20 PV generators, the transformers

and the lines as a whole unit are referred. The decrement reflects the active power output

dependence on the solar irradiation. In this case it was assumed that all the PV generators

undergo the same reduction step of active power, which is 20% as seen in the first column

of table 5.3. The results of active and reactive power were summarized, showing how the

power plant is behaving in order to maintain approximately the same level of voltage at the

PCC. The maximum voltage deviation is considered to be +/- 5%. The relevant Q curve in p.u.

values is drawn based on the results of the table and shown in figure 5.10 presenting the

reactive power injection ability in steady state operation.

Table 5.3: Results of the load flow study-first case

Operating

ability of the

PV power

plant [%]

Nominal

power of

the PV park

[MW]

Injected active

power by each

PV generator

[kW]

Injected active

power by the PV

power plant at the

PCC [MW]

Injected reactive

power by the PV

power plant at

the PCC [MVar]

100 20 929.27 18.378 -1.169

80 16 743.79 14.736 -0.690

60 12 557.84 11.078 -0.314

40 8 371.89 7.402 -0.047

20 4 185.95 3.710 0.115

0 0 0 0 0.168

Judging by the results of the above table, it can be concluded that the more active power

the PV plant unit is injecting, the more reactive power consumes from the grid in order to

maintain approximately the same voltage level around 1 p.u. When the PV power plant is

operating at 20% and 0% injects reactive power to the grid due to the consumption of the

transformers and lines. As seen in figure 5.10 the power plant starts consuming reactive

power when more than 0.35 p.u. active power is injected, which is almost 7 MW. The PF

was around 0.99 in all cases.

At this point it should be pointed out that this model and also the second configuration are

simple interconnected set-ups. They should not be confused with aggregative models, since

for such purpose further assumptions and changes should be applied that are not covered in

this thesis. However, when performing aggregative techniques load flow studies are


KTH, June 2011

73

necessary in order to define the capability curve of the aggregative model at the PCC and

under normal operation. Lines and transformers as mentioned before in this report affect

the reactive power limits at the PCC regardless of the capability curve of each generator and

for this reason, the “new” limits should be defined. A valid way to estimate the reactive

power margins is to use the U-Q curve method as described in [28]. Briefly, the method

includes load flow calculations in different active power outputs and in various voltages in

the respective bus (PCC). Then, the reactive power versus the voltage is plotted. For steady

state operation, the reactive power limits at 0.95 p.u. and 1.05 p.u. voltage are the ones of

interest.

Furthermore, according to the German GCs the aggregative model should provide reactive

power within 0.95underexcited to 0.95overexcited limits. Thus, the obtained limits from the U-Q

curves should include the reactive power values at 0.95underexcited to 0.95overexcited area as in

figure 4.5. In a different way power factor corrections should be made by connecting

capacitors (that supply reactive power) or inductors (that consume reactive power).

Figure 5.10: p-q curve-first case

Static voltage support

All the generators used in the configuration follow the same control frame. That means that

the static voltage support addition that was presented in section 5.1 counts for this case as

well. The results should be the same as before since the control refers to the point of

connection of the PV generator, which is the LV bus and no change was made there. Notice,

that in an aggregative model the static voltage control should be examined at the PCC. That

means that first the total influence of the equivalent distribution network (including lines,

transformers etc), as that is seen at the PCC, on the reactive power should be calculated.


KTH, June 2011

74

Active power control

Similarly, no change took place in the active power control blocks, meaning that identical

results were found after performing the same simulation as in 4.3.2. Assuming the same

power reduction in each PV generator consequently means approximately the same

reduction at the PCC in p.u. values.

Dynamic voltage support

The dynamic voltage support was examined using the same method as described in the

4.3.3 chapter. However, due to the fact the grid is different the fault impedances are

different as well. The values of resistance and reactance that were used in this case to

create the desired voltage dips are presented in table 5.4.

Table 5.4: Fault conditions in each test-first case

Test-number Voltage dip [%] Resistance [Ohm] Reactance [Ohm]

1 100 0 0

2 80 0.045 0.15

3 50 0.19 0.63

4 20 0.75 2.5

After running the simulation the results were summarized in table 5.5. The relative graphs

taken by PowerFactory are found in the Appendix in the 8.3.1 section.

Table 5.5: Aggregation of the results for dynamic voltage support-first case

Voltage

dip [%]

Voltage

level in

the LV

bus

[p.u.]

Injected

active

power by

the PV

generator

[p.u.]

Injected

reactive

current by

the PV

generator

[p.u.]

Injected

reactive

power by

the PV

generator

[p.u.]

Injected

active

power by

the power

plant

[p.u.]

Injected

reactive

power by

the power

plant

[p.u.]

100 0.064 0 0.934 0.059 0 0.062

80 0.245 0.060 0.747 0.184 0.055 0.209

50 0.534 0.284 0.456 0.243 0.284 0.284

20 0.812 0.659 0.182 0.148 0.659 0.181

The above table presents similar results with the ones found in chapter 4.3.3. When the

voltage drop becomes bigger the active power injection of the PV generator is less. In

voltage dip of 100% the active power injection is 0. The reduction of the active power in the

LV bus is followed by a power reduction at the PCC as it is seen in the 6th column. As far as

the reactive current injection and the voltage level at the connection point of the PV

generator concerned, the results show that the reactive current injection is bigger when the

voltage dip is bigger as found also in the previous LVRT analysis. Furthermore, the reactive


KTH, June 2011

75

power injection by each PV generator has again its maximum value at 50% due to the

dependence on the two inversely proportional factors, the voltage level and the reactive

current. This behaviour is repeated at the PCC for the whole power plant as it is seen in the

last column of table 5.5.

The LVRT requirements are fulfilled in each of the 4 tests that the PV configuration was

examined. The voltage stabilizes almost instantly after the fault clearance ensuring that the

PV is capable of dynamic voltage support (short-circuit support).

5.2.3 Second Case

The second configuration was built and seen in figure 5.11. This one shows a connection,

where each PV generator (with transformer) is connected in a common (central) bus via an

AC line (cable). Judging by figure 5.8 and figure 5.11 each of these lines will support the

same current. What is to say, line_1 that connects the 1st generator will carry the same

current with line_2 that connects the 2nd PV generator with the common bus and so on.

Since all the generators are the same and it is assumed that they undergo the same

conditions (irradiance, temperature etc), the produced Iflowed, will be the current that all the

20 lines (line_1 to line_20) will support. Finally the line connected to the PCC will carry 20 x

Iflowed. The choice of the lines was again from the library of PowerFactory and using the (5.1).

Table 5.6 presents the two types of lines used.

Table 5.6: Lines used in the second configuration

Selection of lines – 2nd

case

Number Lable Type

Nominal current

(ground, kA)

Current support

without voltage drop (kA)

1 to 20 Line 1-Line 20 Al 0.139 0.0288

2 Line (PCC) Al 0.635 0.576


KTH, June 2011

76

Figure 5.11: The second configuration as built in PowerFactory


KTH, June 2011

77

Load flow study

A simple load flow study as in the first case was carried out using the same levels of active

power output. The results are seen in table 5.7 and the relevant graph in figure 5.12.

Table 5.7: Results of the load flow study-second case

Operating

ability of the

PV power

plant [%]

Nominal

power of

the PV park

[MW]

Injected active

power by each

PV generator

[MW]

Injected active

power by the PV

power plant at the

PCC [MW]

Injected reactive

power by the PV

power plant at

the PCC [MVar]

100 20 929.27 18.532 -1.071

80 16 743.79 14.841 -0.651

60 12 557.84 11.375 -0.328

40 8 371.89 7.434 -0.081

20 4 185.95 3.723 0.076

0 0 0 0 0.129

Figure 5.12: p-q curve-second case

Judging by the results of the above table, the same conclusions can be drawn for the

behaviour of the second PV interconnection. More active power by the PV plant unit results

to more reactive power consumption from the grid in order to maintain approximately the

same voltage level around 1 p.u. Again at 20% and 0% of operating ability the unit injects

reactive power to the grid due to the consumption of the transformers and lines. In figure

5.12 is seen that the power plant starts consuming reactive power when more than 0.30

p.u. active power is injected, which is almost 6 MW. The PF was around 1 in all cases.


KTH, June 2011

78

Static voltage support

Like in the first case the results were the same as in section 5.1

Active power control

Like in the first case the results were the same as in the section 4.3.2.

Dynamic voltage support

In order to facilitate the comparison between the two cases, the same voltage dips were

simulated in this model as well. The grid is considered identical with the one in the first

configuration, meaning that the values of table 5.4 were used for the fault impedance. The

LVRT results are presented in table 5.8, while the graphs are found in section 8.3.2.

Table 5.8: Aggregation of the results for dynamic voltage support-second case

Voltage

dip [%]

Voltage

level in

the LV

bus

[p.u.]

Injected

active

power by

the PV

generator

[p.u.]

Injected

reactive

current by

the PV

generator

[p.u.]

Injected

reactive

power by

the PV

generator

[p.u.]

Injected

active

power by

the power

plant

[p.u.]

Injected

reactive

power by

the power

plant

[p.u.]

100 0.064 0 0.933 0.059 0 0.054

80 0.246 0.060 0.747 0.184 0.058 0.198

50 0.535 0.286 0.457 0.244 0.284 0.271

20 0.813 0.659 0.182 0.148 0.659 0.163

The above table verifies that the second configuration fulfils the LVRT requirement. At the

PCC the maximum value of reactive power injection is found at 50% voltage dip.

5.2.4 Comparison of both cases

Two different PV set-ups were built and simulated. The main purpose of this study was to

compare the reactive power behaviour due to the different configurations, which impose

different use of lines in the system. In the below table 5.9 the results of both load flow

studies are summarized. It is seen that in the 2nd

case, the power plant consumes less

reactive power in order to maintain the voltage level. The difference when both plants work

at 100% is almost 100 kVar. Also at 20% and 0%, when the plants inject reactive power, in

the second case the injection is lower. These differences are due to the fact that the

consumption of the lines in the second case is less (the transformers are the same and work

with the same loading). The second case uses smaller cables, while the first one uses bigger

cables. Seeing the configurations as a whole unit (aggregative) the first one has greater

influence in the reactive power flow due to its bigger line-capacitance.


KTH, June 2011

79

Table 5.9: Load flow results of both cases

Operating

ability of the

PV power

plant [%]

Nominal

power of

the PV park

[MW]

Injected active

power by each

PV generator

[MW]

Injected active

power by the PV

power plant at the

PCC [MW]

Injected reactive

power by the PV

power plant at the

PCC [MVar]

1st

Case 2nd

Case 1st

Case 2nd

Case

100 20 929.27 18.378 18.532 -1.169 -1.071

80 16 743.79 14.736 14.841 -0.690 -0.651

60 12 557.84 11.078 11.375 -0.314 -0.328

40 8 371.89 7.402 7.434 -0.087 -0.081

20 4 185.95 3.710 3.723 0.115 0.076

0 0 0 0 0 0.168 0.129

The results can also be compared easily by observing the curves in figure 5.13. From the

graph is obvious that in the first case the plant starts injecting reactive power at 7 MW,

while in the second case, when the plant injects 6 MW, proving that the consumption of

reactive power of the lines in the first case is greater.

Figure 5.13: p-q curves-both cases

Similar conclusions can be drawn looking the injected reactive power by both set-ups in case

of voltage dips. Table 5.10 shows, that even if the injected reactive current and power by

each generator is the same in both configurations, the total reactive power behaviour at the

PCC differs, showing larger consumption of reactive power in the first case.


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80

Table 5.10: Reactive power supply of both cases at PCC in several voltage dips

Voltage dip [%] Injected reactive power by the power plant [p.u.]

1st

Case 2nd

Case

100 0.062 0.054

80 0.209 0.198

50 0.284 0.271

20 0.181 0.163

MSc Thesis Project Conclusions

KTH, June 2011

81

6 Conclusions

This chapter summarizes the findings of the presented master thesis project “Comparison of

existing PV models and possible integration under EU grid specifications”. Solar power and

especially grid-tied photovoltaic power is expected to play a significant role as an energy

source among other renewables like wind power and hydropower that enjoy the leading

positions. Europe is turning attention to PV power and Germany as a strong player in the

area will influence things notably. PV applications still live their pre-mature days and there

are many, mostly technical, aspects to be studied and improved. Efficiency of the

components, inverter topologies, control schemes and aggregation techniques are some of

the major research areas.

This thesis report focuses on the static and dynamic behaviour of on-grid PV systems and

their interaction with the power grid. A generic model built by DIgSILENT is selected to be

presently examined. The PV system is modelled by a static generator and the control

scheme is implemented in it. The model of the PV array is based on the ideal model of a PV

cell and takes into consideration the voltage and current correction factors based on the

operating temperature and solar radiation.

The control is structured according to the requirements of the German GC for the MV

distribution network. Active power reduction requirement is effectively adjusted and

operates in case of over-frequency events. The reduction is occurred in less than 50 msec.

The LVRT requirement is tested under four different voltage dips of different duration each

according to the German technical guidelines for type-2 generating units. The results

support the capability of the PV model in question to remain connected when a voltage dip

occurs and provide reactive current when it is needed according to the GC. Thus, the grid

stability is improved at the PCC, there is no loss of active power since active power is

provided again the moment the grid is stabilized and no burden on the lifetime of the

components due disconnection-connection and grid is occurred.

As far as the static voltage support concerned, initially the model had no relevant control.

For this reason, a PI controller is implemented to the main control scheme providing

reactive power with the constant-Q method. The controller shows sufficient behaviour

when changes of the irradiance take place, which cause changes in the active power supply

affecting the voltage at the terminal that the generator is connected. However, the need of

more proper tuning is necessary. The switch between static voltage support and dynamic

voltage support in case of a fault is inside the current limiter block and ensures reactive

power support in any occasion.

The study of the two interconnected models shows that the choice of the configuration and

consequently the choice of lines, affects the reactive power at the PCC. This is of great

importance in aggregative studies, where the equivalent line should have the characteristics

(capacitance, impedance etc) of all the lines of the network that has been substituted.

MSc Thesis Project Conclusions

KTH, June 2011

82

Judging by the objectives set at the beginning of this project, it can be said that all of them

where addressed during this study and analysed to the extent of the time constraints given

for such projects. However, in such multifaceted areas there are numerous of issues that

require deeper analysis and further research. Some important issues concerning this model

and in general the “PV on-grid systems” field are:

� Additional studies should be conducted concerning the reactive power support in

voltage variations under normal operation. Concerning this generic model, the

constant-Q method that was implemented can be further improved and moreover,

the other three methods (fixed cosφ, cosφ (P) function or Q (U) droop function) can

also be applied, by building a controller with four modes of operation and making it

possible to switch to which ever mode the plant operator decides.

� The PV array model is based on the ideal model of PV cell making the results of

voltage and current output rather simplified. Cell model with one or two diodes and

taking into consideration the Rs and Rp resistances would provide more accurate and

tangible results.

� MPP logic would have been also an issue of concern for future studies. Besides the

simplified techniques for correcting the voltage and current in changeable irradiance

and temperature, more advanced methods could be applied e.g. MPP tracking with

fuzzy logic.

� Research studies should be done in terms of power quality. So far, there are no

results for the harmonic distortion or possible flicker effects that this PV model can

cause.

� The model has been tested under the German GCs, which are considered being the

most detailed. However, it would be interesting to examine the model under other

GCs especially nowadays that countries like France and Italy have increased their

installed capacity significantly. Regarding the Spanish GCs, some studies have been

conducted by [28].

� The model has been tested only under voltage dip-types of grid fault. Additional

studies under other types of faults e.g. unsymmetrical fault scenarios can be

conducted.

Rounding up the conclusions of this thesis, in response to the fact that policies and

incentives have brought PV systems to the fore, the research area has to be expanded.

Better solar radiation forecasting and cloud effect studies can be initiated, aggregative

studies can be undertaken, ant-islanding control schemes can be improved and numerous

other areas can be evolved in order to thrust the PV market, encourage the high PV

penetration, while securing the stability and normal operation of the power system.

MSc Thesis Project References

KTH, June 2011

83

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energy.org/PageFiles/What_We_Do/activities/CEB_Power_Systems_Simulation_Trai

ning,_Colombo,_Sri_Lanka/Course_ppts/lecture_41.pdf , as accessed 07.04.2011

[37] Fördergesellschaft Windenergie und andere Erneuerbare Energien (FGW e.V.),

“Bestimmung der Elektrischen Eigenschaften von Erzeugungseinheiten am Mittel-,

Hoch- und Höchstspannungnetz“, Technische Richtlinien für Erzeugungseinheiten6,

Germany, 22.03.2010

[38] SMA Solar Technology, Sunny Central 1000MV, Technical data, available at

http://www.sma.de/en/products/solar-inverters/sunny-central/sunny-central-

800mv-1000mv-1250mv.html , as accessed 04.05.2011

Throughout this report and especially from chapter 4 until chapter 9, figures, graphs, tables,

parameters and parts of the software environment PowerFactory of DIgSILENT have been

used as captions. There is no specific bibliographic reference, however it is mentioned several

times that the subject of test and the results are products of the simulation tool in question.

5 Photovoltaic Engineering – Handbook for Planning, Development and Application

6 “Determining the electrical properties of generating units at medium, high and very high voltage grid”,

Technical Guidelines for generating units.

MSc Thesis Project Appendix

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8 Appendix

8.1 Parameters used in the PV model

Table 8.1: Parameters in PV array slot

PV Array


Open circuit voltage of module in STC [V] UI0 43,8

MPP voltage of module in STC [V] Umpp0 35

MPP current of module in STC [A] Impp0 4,58

Short-circuit current of module in STC [A] Ik0 5

Temperature correction factor (voltage) [1/K] au -0,0039

Temperature correction factor (current) [1/K] ai 0,0004

Number of modules connected in series [-] nSerialModules 20

Number of modules connected in parallel [-] nParallelModules 140

Time constant of module [s] Tr 0

Table 8.2: Parameters in DC Busbar and Capacitor slot

DC Busbar and Capacitor


Capacity of the capacitor on DC busbar [s] Capacity 0,0172

Initial DC voltage [V] Udc0 700

Nominal DC voltage [kV] UdcN 1

Rated Power [MW] Pnen 0,5

Table 8.3: Parameters in Active power reduction slot

Active power reduction


Start of active power reduction [Hz] fUp 50,2

End of active power reduction [Hz] fLow 50,05

Gradient of active power reduction [%/Hz] gradient 40

PT1-Filter Time Constant [s] Tfilter 0,01


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Table 8.4: Parameters in main Controller slot

Controller


Gain of the active power PI controller [-] Kp 0,005

Integration time constant of the active power PI controller [s] Tip 0,03

Measurement delay [s] Tr 0,001

Time delay MPP-Tracking [s] Tmpp 5

Deadband for AC voltage support [p.u.] deadband 0,1

Static for AC voltage support [-] droop 1

i_EEG = 0 according to TC2007; i_EEG = 1 according SDLWindV

[-] i_EEG 1

Minimum active current limit [p.u.] id_min 0

Minimum allowed DC - voltage [V] U_min 333

Minimum reactive current limit [p.u.] iq_min -1

Maximum active active current [p.u.] id_max 1

Maximum reactive active current [p.u.] iq_max 1

Maximum allowed absolute current [p.u.] maxAbsCur 1

Maximum absolute reactive current in normal operation [p.u.] maxIq 1


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8.2 The DSL code in main blocks of the PV model

Figure 8.1: The DSL code of each PV module


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Figure 8.2: Main part of DSL code in the active power reduction block

Figure 8.3: The DSL code in the PI controller block

Figure 8.4: The DSL code in the reactive power support block

Figure 8.5: The DSL code in the current limiter block


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8.3 Results of LVRT study in both interconnection cases

8.3.1 First case

Figure 8.6: Behaviour of the first interconnection in 100% voltage dip


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8.3.2 Second case

Figure 8.10: Behaviour of the second interconnection in 100% voltage dip



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