microgrid safety and protection strategies
TRANSCRIPT
IN DEGREE PROJECT ELECTRICAL ENGINEERING,SECOND CYCLE, 30 CREDITS
, STOCKHOLM SWEDEN 2017
Microgrid Safety and Protection Strategies
ARYUDHA DUTA HARTONO
KTH ROYAL INSTITUTE OF TECHNOLOGYSCHOOL OF ELECTRICAL ENGINEERING
i
Microgrid Safety and Protection
Aryudha Duta Hartono
EI270X Degree Project in Electrotechnical Theory and Design
December 2017
Supervisors
Andrew Kitimbo, Vattenfall Research and Development
Edel Wallin, Vattenfall Research and Development
Nathaniel Taylor, KTH School of Electrical Engineering
Tin Rabuzin, KTH School of Electrical Engineering
Examiner
Prof. Hans Edin, KTH School of Engineering
Royal Institute of Technology
Department of Electrical Engineering
Electromagnetic Engineering
Stockholm 2017
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“If we did all the things we are capable of, we would literally astound ourselves”
Thomas A. Edison
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Abstract
One of the challenging issues with the Microgrid is that the bidirectional power flow provided
by the distributed generator (DG) which modify the fault current level. Furthermore, the
inverter based-renewable energy source (IB-RES) limits the total fault current contribution
to the grid due to its thermal capability. Since Microgrid should be able to operate in grid-
connected and islanded mode, protection strategies are needed to solve this challenging issue.
By only having IB-RES and battery storage system, the fault condition and normal
operation cannot be distinguished. Apart from fault clearing issue, there is a consideration to
study the fault isolation in the Microgrid under the limited fault current provided by IB-RES.
To have fault isolation capability, the intelligent electrical device (IED) is needed. The first
step is to find a method that can detect a fault under the fault level modification constraint.
This thesis presents a zero and negative sequence current protection to detect a fault.
However, to make it selective, this protection will be applied directionally. It is common that
the distribution grid has unbalanced load operation, thus providing zero and negative
sequence component in the grid. To apply the directional zero and negative sequence current
protection, the unbalanced load flow is simulated to distinguish the fault and normal
operation under unbalanced load condition.
Safety and regulation are discussed briefly in this thesis. It is important that each of the
IB-RES has fault ride-through (FRT) capability that follows a regulation. However, this
regulation is expected to have a coordination with the proposed protection in the Microgrid
so the reliability, selectivity, and sensitivity can be achieved in grid-connected and islanded
mode. This thesis shows the coordination between fuses, IED, and inverter FRT capability.
After providing a protection strategy, the adaptability of the proposed protection is
assessed regarding of Microgrid expansion. The result shows that by applying the scheme
and following the grading margin requirement that is presented in this thesis, the Microgrid
expansion will not disrupt the proposed protection coordination. Since it is known that the
distribution grid is expanding its load capacity and microgeneration in continuous basis, it is
convenient that the proposed protection in the IED is expected to be adaptable, means that it
has a fixed IED setting when the grid is expanded.
The analysis is performed by electrical transient analysis program (ETAP) and Matlab
Simulink. The short circuit analysis, sequence-of-operation, and unbalanced load flow are
simulated by ETAP, while the protection stability is simulated by Matlab Simulink.
Keywords: IB-RES, grid-connected mode, islanded mode, short circuit, IED, directional
zero and negative sequence current protection, unbalanced load flow, protection
coordination, fault ride-through
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Sammanfattning
Ett problem som finns med microgrid är att de distribuerade produktionsgeneratorerna har
ett dubbelriktat effektflöde som modifierar felströmmen. Dessutom, inverterbaserade
förnyelsebara energikällor (IB-RES) begränsar det totala felströmsbidraget på grund av dess
termiska kapacitet. Eftersom microgrids ska vara operativ vid både anslutning till externt nät
samt önätsdrift behövs skyddsstrategier för att kunna hantera fel, speciellt vid önätsdrift.
Om endast IB-RES och batterilager används kan feldrift och normal drift inte särskiljas.
Bortsätt från felhantering är det viktigt att studera felbortkoppling för microgrid under
begränsad felström som fås av IB-RES. För att kunna åstadkomma felbortkoppling behöver
en IED (från engelskans Intelligent Electronic Device). Det första steget är att finna en metod
för att kunna detektera fel under fel nivå modifiering. Denna avhandling tittar på att använda
noll- och minusföljds ström sekvensskydd för att detektera fel. För att göra skyddet selektivt
kommer det att titta på riktningen av effektflödet. I distributionsnät är det vanligt att ha
obalanserade laster vilket medför noll- och negativa sekvenskomponenter i nätet. För att
tillämpa riktningsskydd för noll och negativ sekvens ström simuleras ett obalanserat
effektflöde för att särskilja på feldrift och normal drift vid obalanserad last.
Säkerhet och förordningar diskuteras kortfattat i denna avhandling. Det är viktigt att varje
IB-RES har en feltålighet som följer vissa förordningar. Denna förordning förväntas
samordna det föreslagna skyddet i micronåt så att pålitlighet, selektivitet och känslighet kan
åstadkommas vid nätanslutning och önätsdrift. Denna avhandling visar samordningen mellan
säkringar, IED och feltåligheten för växelomriktare.
Anpassningsförmågan för det föreslagna skyddet bedöms med avseende på expansion av
microgrid. Resultatet visar att en expansion av ett microgrid inte kommer att störa den
föreslagna samordningen om skyddsmetoden och tidsfördröjningskravet som presenteras i
denna avhandling följs. Eftersom det är känt att distributionsnätet kommer att fortsätta öka
sin lastkapacitet och mikrogenerering, är det lämpligt att skyddet förväntas vara
anpassningsbart vilket innebär att det har en fast IED inställning när nätet expanderas.
Analysen genomförs med mjukvarorna electrical transient analysis program (ETAP) och
Matlab Simulink. Kortslutningsanalysen, arbetssekvensen och obalanserad lastflöde
simuleras av ETAP, medan skyddsstabiliteten simuleras av Matlab Simulink.
Nyckelord: IB-RES, grid-connected mode, islanded mode, short circuit, IED, zero and
negative sequence current protection, unbalanced load flow, protection coordination, fault
ride-through
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Acknowledgement
This thesis report is the result of degree project work in EI270X Electrotechnical Theory and
Design at KTH, which is the requirement of Master degree program in Electric Power
Engineering at Kungliga Tekniska Högskolan (KTH) – Royal Institute of Technology
Stockholm, Sweden. This thesis is a cooperation between KTH and Vattenfall; the thesis
project is carried out at Vattenfall Research and Development.
I would like to express my gratitude to Professor Hans Edin, my examiner, for the
approval of this degree project.
I would like to express my thanks and gratitude to Nathaniel Taylor, my supervisor from
KTH, for his encouragement, positive attitude, and patience to support the thesis. It is always
a pleasure to have hours of discussion with him. Special thanks to Edel Wallin, my supervisor
from Vattenfall, to have me aboard on Microgrid project team for six months; there is always
a new and exciting thing to be discovered. The future is in front of our sight, it is a matter of
who will take the opportunity in the first place. I would also like to appreciate Andrew
Kitimbo, my supervisor from Vattenfall, to always keeping the direction of the thesis. I am
really grateful for Tin Rabuzin, my supervisor from KTH, to spare some of his time
contributing to the thesis project.
I also want to mention Derek Smith and Daniel Ting for giving me the opportunity to use
ETAP for my simulation study. Hopefully, the cooperation between KTH and ETAP would
strengthen the relationship between industry practice and academic in the future.
I would like to thank all of my colleague from Vattenfall R&D and Vattenfall
Eldistribution for providing the positive working environment.
My parents and sister deserve many thanks for their support throughout the whole winter
in Sweden.
At last, but not least, I would like to thank those without whom my work would have
been impossible to accomplish.
Aryudha Duta Hartono
Desember 2017
KTH-Stockholm
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List of Abbreviations
RES Renewable Energy Sources
PV Photovoltaic
IB-RES Inverter Based-Renewable Energy Sources
PCC
DG
Point of Common Coupling
Distributed Generation
FRT Fault Ride Through
LV Low Voltage
IED Intelligent Electrical Device
MCCB Molded Case Circuit Breaker
SAIFI System Average Interruption Frequency Index
SAIDI System Average Interruption Duration Index
IGBT Insulated Gate Bipolar Transistor
OC Overcurrent
ETAP Electrical Transient Analysis Program
SLG Single-Line-to-Ground
LL Line-to-Line
LLG Line-Line-to-Ground
3-P Three-Phase
PE Power Electronic
LVRT Low Voltage Ride-Through
EPS Electrical Power System
HVRT High Voltage Ride-Through
ULF Unbalance Load Flow
CIM Current Injection Method
DSO Distribution System Operator
ESS Energy Storage System
TCC Time Current Characteristic
CT Current Transformer
VT Voltage Transformer
EI Extremely Inverse
TMS Time Multiplier Setting
TD Time Dial
ms miliseconds
s seconds
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Contents
ABSTRACT .......................................................................................................................................... V SAMMANFATTNING ......................................................................................................................... VII ACKNOWLEDGEMENT ....................................................................................................................... IX LIST OF ABBREVIATIONS .................................................................................................................... XI LIST OF FIGURES .............................................................................................................................. XIX LIST OF TABLES ................................................................................................................................ XXI 1 CHAPTER 1: INTRODUCTION ........................................................................................................ 1
1.1 BACKGROUND ................................................................................................................................. 1 1.2 RESEARCH OBJECTIVES ...................................................................................................................... 2 1.3 THESIS OUTLINES ............................................................................................................................. 2
2 METHODOLOGY .......................................................................................................................... 3
2.1 SHORT CIRCUIT AND SEQUENCE-OF-OPERATION STUDY .......................................................................... 3 2.2 CHOOSE A PROTECTION SCHEME TO DETECT A FAULT WITHIN THE MICROGRID ............................................ 3 2.3 UNBALANCED LOAD FLOW ANALYSIS ................................................................................................... 3 2.4 ADDING THE DIRECTIONAL ELEMENT TO THE PROPOSED PROTECTION SCHEME ............................................ 3 2.5 SIMULATING FAULT RIDE-THROUGH CAPABILITY .................................................................................... 4 2.6 ASSESSING THE COMPLETE PROTECTION STRATEGY ................................................................................ 4 2.7 SIMULATING THE ADAPTABILITY OF THE MICROGRID PROTECTION ............................................................. 4 2.8 CONCLUDING THE THESIS .................................................................................................................. 4
3 THEORY ....................................................................................................................................... 5
3.1 MICROGRID PROTECTION CHALLENGES ................................................................................................ 5 3.1.1 Fault Level Modification .................................................................................................... 5 3.1.2 Blinding Protection ............................................................................................................ 5 3.1.3 Sympathetic/False Tripping ............................................................................................... 5
3.2 QUALITIES OF A PROTECTION ............................................................................................................. 6 3.2.1 Reliability ........................................................................................................................... 6 3.2.2 Selectivity .......................................................................................................................... 6 3.2.3 Sensitivity .......................................................................................................................... 7
3.3 AVAILABLE SOLUTIONS FOR THE MICROGRID PROTECTION ....................................................................... 7 3.3.1 Adaptive Protection ........................................................................................................... 7 3.3.2 Differential and Symmetrical Component Protection........................................................ 8 3.3.3 Voltage-based Protection .................................................................................................. 8
3.4 POWER FLOW STUDIES ..................................................................................................................... 9 3.4.1 Representation of Cables ................................................................................................. 10 3.4.2 Unbalanced Load Flow Analysis ...................................................................................... 10
3.5 SHORT CIRCUIT PRINCIPLE ............................................................................................................... 11 3.5.1 The Symmetrical Components of Unsymmetrical Phasor ................................................ 11 3.5.2 Unsymmetrical Faults ...................................................................................................... 12 3.5.3 Single-Line-to-Ground Fault ............................................................................................ 12 3.5.4 Line-to-line Fault ............................................................................................................. 13 3.5.5 Line-line-to-Ground Fault ................................................................................................ 14 3.5.6 Transformer Zero Sequence Equivalent Circuit ................................................................ 14
3.6 FAULT RIDE-THROUGH CAPABILITY.................................................................................................... 15 3.7 FUSE – RELAY COORDINATION .......................................................................................................... 15 3.8 GRADING MARGIN ......................................................................................................................... 17
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4 CHAPTER 4: MODELLING ............................................................................................................ 18
4.1 POWER FLOW STUDY ..................................................................................................................... 18 4.1.1 Bus Types ......................................................................................................................... 18 4.1.2 Unbalanced Load Flow .................................................................................................... 19 4.1.3 Cables .............................................................................................................................. 20 4.1.4 Transformer ..................................................................................................................... 20
4.2 SHORT CIRCUIT AND SEQUENCE-OF-OPERATION STUDY ........................................................................ 20 4.2.1 Utility Grid ....................................................................................................................... 20 4.2.2 Loads ............................................................................................................................... 20 4.2.3 Transformer ..................................................................................................................... 20 4.2.4 Inverter ............................................................................................................................ 20
5 CHAPTER 5: SHORT CIRCUIT AND SEQUENCE OF OPERATION ANALYSIS OF THE EXISTING
PROTECTION ........................................................................................................................................... 21
5.1 GRID-CONNECTED MODE ................................................................................................................ 21 5.1.1 Bus: B-T125-Y21 – SLG Fault ............................................................................................ 21 5.1.2 Bus: B-T125-04 – SLG Fault .............................................................................................. 22
5.2 ISLANDED MODE ........................................................................................................................... 23 5.2.1 Bus: B-T125-Y21 – SLG Fault ............................................................................................ 23 5.2.2 Bus: B-T125-Y11 – SLG Fault ............................................................................................ 23
5.3 CONCLUSION FOR THE SHORT CIRCUIT AND SEQUENCE-OF-OPERATION STUDY OF THE EXISTING PROTECTION . 23
6 CHAPTER 6: FAULT DETECTION METHOD USING DIRECTIONAL ZERO AND NEGATIVE SEQUENCE
CURRENT PROTECTION ........................................................................................................................... 25
6.1 UNBALANCED LOAD FLOW ANALYSIS ................................................................................................. 25 6.1.1 Case – 1: 20% Unbalance with Maximum Aggregated Load........................................... 25 6.1.2 Case – 2: 20% Unbalance with Maximum Load Capacity ................................................ 26 6.1.3 Case – 3: Maximum Negative and Zero Sequence Current ............................................. 26 6.1.4 Case – 4: Connecting 1 Phase Load with a Third of the Maximum Load Capacity .......... 27
6.2 PROTECTION ZONE ANALYSIS ........................................................................................................... 28
7 CHAPTER 7: MICROGRID PROTECTION STRATEGY....................................................................... 32
7.1 SOLUTION – 1: APPLYING 1 IED TO REPLACE FUSE F-L2-1 .................................................................... 32 7.1.1 Phase OC ......................................................................................................................... 32 7.1.2 Directional Zero and Negative Sequence Current Protection .......................................... 33 7.1.3 Qualities of Protection ..................................................................................................... 33 7.1.4 Discussion ........................................................................................................................ 33
7.2 SOLUTION – 2: APPLYING 2 IEDS WITHIN THE MICROGRID .................................................................... 34 7.2.1 Phase OC ......................................................................................................................... 35 7.2.2 Directional Zero and Negative Sequence Current Protection .......................................... 35 7.2.3 Qualities of Protection ..................................................................................................... 35 7.2.4 Discussion ........................................................................................................................ 36
7.3 SOLUTION – 3: APPLYING 3 IEDS WITHIN THE MICROGRID .................................................................... 36 7.3.1 Phase OC ......................................................................................................................... 37 7.3.2 Directional Zero and Negative Sequence Current Protection .......................................... 38 7.3.3 Qualities of Protection ..................................................................................................... 38 7.3.4 Discussion ........................................................................................................................ 38
7.4 MICROGRID EXPANSION AND THE PROTECTION ADAPTABILITY ................................................................ 42 7.4.1 High Penetration PVs in each of the Customer ................................................................ 42 7.4.2 Adding Connection to the Main Bus (B-T125-04) ............................................................ 43
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7.4.3 Discussion ........................................................................................................................ 44
8 CHAPTER 8: CONCLUSIONS ........................................................................................................ 45
8.1 GENERAL CONCLUSIONS .................................................................................................................. 45 8.2 FUTURE RESEARCH AND RECOMMENDATION ....................................................................................... 45
REFERENCES ..................................................................................................................................... 47 A.1 APPENDIX I ......................................................................................................................... - 2 -
A.1-1 CUSTOMER LOAD DATA ........................................................................................................... - 2 - A.1-2 INVERTER DATA ...................................................................................................................... - 2 - A.1-3 TRANSFORMER DATA ............................................................................................................... - 2 - A.1-4 UTILITY GRID .......................................................................................................................... - 2 - A.1-5 CABLE DATA .......................................................................................................................... - 3 - A.1-6 FUSE DATA ............................................................................................................................ - 3 -
A.2 APPENDIX II ........................................................................................................................ - 4 -
A.2-1 LIST OF THE PROBLEM – GRID-CONNECTED MODE ........................................................................ - 4 - A.2-2 LIST OF THE PROBLEM – ISLANDED MODE .................................................................................... - 5 -
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List of Figures
Figure 3.1 Blinding Protection (left) & Sympathetic Tripping (right) ................................................. 6 Figure 3.2 Notation for active and reactive power at a typical bus i in power flow studies ................ 9 Figure 3.3 Pi-equivalent circuit .......................................................................................................... 10 Figure 3.4 The Symmetrical Component of Unsymmetrical Phasor ................................................. 11 Figure 3.5 Connection diagram for Various Faults ............................................................................ 12 Figure 3.6 The Sequence Network of the System .............................................................................. 12 Figure 3.7 Thévenin Equivalent of Sequence Network for SLG fault .............................................. 13 Figure 3.8 Thévenin Equivalent of Sequence Network for LL fault ................................................. 13 Figure 3.9 Thévenin Equivalent of Sequence Network for LLG fault ............................................... 14 Figure 3.10 Transformer Zero Phase Sequence Network .................................................................. 14 Figure 3.11 FRT Requirement [25, 26] .............................................................................................. 15 Figure 3.12 Fuse Coordination - Time Current Characteristic (TCC) ............................................... 16 Figure 4.1 Microgrid Topology ......................................................................................................... 18 Figure 4.2 Inverter Internal Impedance .............................................................................................. 20 Figure 5.1 FRT Capability for Wind Power Plant according to Nordic Grid Code ........................... 22 Figure 6.1 Pick-up Values for Negative and Zero Sequence Protection ............................................ 29 Figure 6.2 Base Protected Zone ......................................................................................................... 29 Figure 6.3 Maximum Coverage Protected Zone by the IED.............................................................. 31 Figure 7.1 Phase OC TCC.................................................................................................................. 32 Figure 7.2 Microgrid Solution with 2 IEDs ....................................................................................... 34 Figure 7.3 Negative Sequence TCC ................................................................................................... 35 Figure 7.4 Microgrid Solution with 3 IEDs ....................................................................................... 36 Figure 7.5 Phase OC TCC.................................................................................................................. 37 Figure 7.6 Microgrid Expansion: Higher Penetration of PVs ............................................................ 42 Figure 7.7 Microgrid Expansion: Additional Connection within Microgrid ..................................... 43
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List of Tables
Table 3.1 Quality of Protection ............................................................................................................ 7 Table 3.2 IEEE 1547 (Table 1) Interconnection system response to abnormal voltages ................... 15 Table 3.3 Definitions of Standard Relay Characteristic ..................................................................... 16 Table 4.1 Bus Types .......................................................................................................................... 19 Table 5.1 Relay Protection Setting according to SS-EN 50438 supplemented by SEK TK 8 ........... 21 Table 6.1 Unbalanced Load Flow Analysis - Case 1 ......................................................................... 25 Table 6.2 Unbalanced Load Flow Analysis - Case 2 ......................................................................... 26 Table 6.3 Unbalanced Load Flow Analysis - Case 3 ......................................................................... 27 Table 6.4 Unbalanced Load Flow Analysis - Case 4 ......................................................................... 28 Table 6.5 Flow at Bus B-T125-04 and B-T125-Y21 (IED Reference) for Different Fault ............... 30 Table 7.1 Phase OC Setting ............................................................................................................... 33 Table 7.2 Symmetrical Sequence Current Protection – Relay 1 Setting ............................................ 33 Table 7.3 Solution 1 – Qualities of Protection ................................................................................... 33 Table 7.4 Solution 2 – Qualities of Protection ................................................................................... 36 Table 7.5 Phase OC Setting ............................................................................................................... 37 Table 7.6 Symmetrical Sequence Current Protection – Relay 3 Settings .......................................... 38 Table 7.7 Solution 3 – Qualities of Protection ................................................................................... 38 Table 7.8 Islanded Mode -Protection Coordination Matrix ............................................................... 40 Table 7.9 Grid-Connected Mode - Protection Coordination Matrix .................................................. 41 Table 7.10 Microgrid Expansion: Symmetrical Sequence Protection ............................................... 43 Table 7.11 Final Grading Margin ...................................................................................................... 44 Table A.1 Customer Load Data ...................................................................................................... - 2 - Table A.2 Inverter Data .................................................................................................................. - 2 - Table A.3 Transformer Data ........................................................................................................... - 2 - Table A.4 Utility Grid Data ............................................................................................................ - 2 - Table A.5 Cable Impedance Data ................................................................................................... - 3 - Table A.6 Fuse Data ....................................................................................................................... - 3 - Table A.7 List of Problem - Grid-connected Mode ........................................................................ - 4 - Table A.8 List of Problem - Islanded Mode ................................................................................... - 5 -
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1 Chapter 1: Introduction
1.1 Background
The increasing concern about reducing the effect of global warming or as referred to de-
carbonisation caused by greenhouse gases which are generated by conventional energy
sources, i.e. fossil fuels, has made the research and development of renewable energy sources
(RES) take place in the recent years. The challenging issue about these renewable energies
such as wind power and photovoltaic (PV) is that these sources fluctuate over time so that it
is needed to be stored or controlled even further. In this degree project, wind power and PV
are mentioned as inverter based-renewable energy sources (IB-RES).
In the past, Microgrid served a different purpose which is to provide electricity in the
isolated grid[1]. By having loads in the isolated grid, the IB-RES is expected to improve the
reliability of supply by providing the islanded generation. Moreover, by providing high
reliability and quality power to the customer who requires more priority is also beneficial for
the grid in term of business model hence the concept of Microgrid is expanded to serve the
load while being connected to the utility grid. It is an important concept that a Microgrid
should have the capability to operate in both grid-connected and islanded mode. For instance,
when an unintentional outage occurs, it is expected that the Microgrid should disconnect the
connection from the utility grid by opening the breaker at the point of common coupling
(PCC) and then remain operational in the islanded mode.
The main focus of this thesis work was to analyse the technical challenges of protection
in Microgrid and propose protection strategies that could be used. It is known that the existing
distribution system is designed as a radial grid. With the presence of the distributed
generation (DG) in the grid, the grading protection is disrupted. The DG can be either
synchronous or asynchronous generator (i.e. IB-RES). The DG provides the bidirectional
power flow. Furthermore the inverter in the IB-RES limits the total of the fault current due
to its thermal capability. It can provide limited to 2-3 times of the rated current[2]. This
limitation is a problem when the Microgrid is in islanded mode, so the protection strategy is
needed to overcome these issues. Furthermore, the next challenge is to keep the healthy grid
operated after the fault within the Microgrid.
The IB-RES has anti-islanding protection so that if there is a disturbance outside the grid,
the PV can be disconnected from the grid. It means that IB-RES is not allowed to be operated
in the islanded mode. However, that is not the case with the Microgrid concept in which one
of the requirement is able to be operated in both grid-connected and islanded mode. Then the
anti-islanding protection in the IB-RES should be blocked when the islanded mode is
formed[3]. There is also a regulatory requirement for each IB-RES, known as fault ride
through (FRT) capability which is defined as the capability of the inverter to withstand the
fault. It means that the inverter is not allowed to be disconnected from the grid under the fault
for a particular time. Hence The FRT capability on each IB-RES was assessed in the proposed
Microgrid protection in this degree project. To be noted that FRT in each country can be
regulated differently[4].
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1.2 Research Objectives
The general objective of this study is to propose a protection strategy for the low voltage
(LV) Microgrid. To achieve the general objective, the sub-objectives are structured as
follows:
1. Investigate the existing protection and deliver short circuit study within the Microgrid
on both grid-connected and islanded mode
2. Analyze the different scheme for the Microgrid protection solution such as adaptive
overcurrent (OC), symmetrical component of unsymmetrical phasor,
voltage/frequency protection, and deployment of external devices (batteries)
3. Investigate the Microgrid expansion with more PV production and customer load.
This analysis is done after the proposed Microgrid protection is applied
4. Analyze the legal aspect of the corresponding proposed Microgrid protection strategy,
i.e. FRT regulation
1.3 Thesis Outlines
This thesis is divided into eight chapters that are listed below
Chapter 1 introduces the thesis and briefly explains Microgrid protection challenge in the
background followed by the research objectives and thesis outlines.
Chapter 2 explains the methodology that is used in the thesis. The methodology is explained
step by step to achieve the research objectives.
Chapter 3 presents the theory that is related to the work done in the thesis. This includes
Microgrid protection challenges, qualities of protection, available solutions for the
Microgrid protection, power flow studies, short circuit principle, FRT capability, fuse-relay
coordination and grading margin.
Chapter 4 describes the models that are used in the thesis. These include the Microgrid
topology and the components related to the topology.
Chapter 5 provides and discusses the result of the short circuit and sequence-of-operation
study.
Chapter 6 provides and discusses the result of fault detection method using the directional
zero and negative sequence current protection.
Chapter 7 delivers and discusses a complete protection strategy in the Microgrid.
Chapter 8 gives the thesis conclusions and provides recommendations for the future
research.
3
2 Methodology
The methodology is structured as presented below.
2.1 Short Circuit and Sequence-of-Operation Study
The first step is to do the steady state analysis: short circuit and sequence-of-operation study.
The steady state analysis is done by using the software called electrical transient analysis
program (ETAP). The short circuit study is used to provide the information of the fault
current between each of the modes. The information of the fault current is used to show the
different fault level in each of the modes. The fault in the short circuit study includes single-
line-to-ground (SLG), line-to-line (LL) fault, and line-line-to-ground (LLG) fault. The fault
is applied to each of the locations/buses.
Sequence-of-operation study is the sequence of each of the protective devices react to a
fault. The tripping time of each of the protective devices is the focus of this study. Thus the
problem in term of reliability, selectivity, and sensitivity of each of the protective devices is
presented in grid-connected and islanded mode.
2.2 Choose a Protection Scheme to Detect a Fault within the Microgrid
The fault limitation in the IB-RES is expected to provide a low fault current to the grid,
especially in the islanded mode. This implies that the current existing protective devices,
fuses, are not enough to detect a fault. Thus a method is chosen to detect a fault within the
Microgrid for both grid-connected and islanded mode. The symmetrical component of the
unsymmetrical phasor is used to determine the fault within the Microgrid. The protection is
called zero and negative sequence current protection. Thus the intelligent electrical device
(IED) that has this type of protection is expected to replace some of the fuses in the existing
grid.
2.3 Unbalanced Load Flow Analysis
In the distribution grid, it is common that the load is not exactly balanced in normal operation
which means the load is unbalanced for each of the phases thus providing zero and negative
current flowing in the grid. Because the protection scheme that is used to detect a fault is the
zero and negative sequence current protection, thus there must be an analysis to distinguish
normal operation and the fault condition.
The unbalanced load flow analysis is used to distinguish the normal operation under
unbalanced load with the fault condition. By doing the short circuit study and unbalanced
load flow analysis, the permissible pick-up value for the IED to trigger the fault can be
determined.
2.4 Adding the Directional Element to the Proposed Protection Scheme
After a method to detect a fault is proposed, the next step is to ensure that the protective
devices are selective. The directional element is used in addition to the proposed protection.
Thus the protection is called directional zero and negative sequence current protection. The
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selectivity is important to be applied to isolate the fault and make the remaining healthy phase
in operational.
2.5 Simulating Fault Ride-Through Capability
The fault ride-through capability is simulated in MATLAB Simulink by applying the voltage
protection in the inverter. If the fault still presents after a certain time, the inverter is expected
to disconnect from the main grid.
2.6 Assessing the Complete Protection Strategy
The strategy includes protection coordination between existing fuses, the IEDs, and the FRT
in each of the inverters. The steady state analysis is simulated after a whole strategy is
proposed. The sequence-of-operation simulation is done by ETAP to confirm the solution.
The reliability, selectivity, and sensitivity is assessed to quantify the strategy.
2.7 Simulating the adaptability of the Microgrid Protection
After the complete protection strategy is assessed, the next step is to expand the Microgrid
and assess the adaptability of the Microgrid protection.
The term expand in this thesis is defined as having more PV production in each of the
customers and adding an additional connection to the main bus which consists of additional
PVs production and customer loads. It is common that the customer is requesting the new
connection on continuous basis so that the adaptability of the proposed Microgrid protection
strategy needs to be analysed.
2.8 Concluding the Thesis
The conclusion is divided into general conclusion and future recommendation. The general
conclusion summarises the study that has been done in this thesis related to the research
objective. The recommendation provides author suggestion for the Microgrid protection
strategy study in the future.
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3 Theory
3.1 Microgrid Protection Challenges
This subsection presents the Microgrid protection challenges which consist of fault level
modification, blinding protection, and sympathetic tripping.
3.1.1 Fault Level Modification
In grid-connected mode, the fault current is provided by the utility grid and the DG. Since
utility grid represents a huge number of synchronous generator compared to IB-RES, it can
provide high magnitudes of fault current about 10-50 times of the rated current, and for low
voltage (LV) side fault resulting in 10-20 times of rated current[3]. By having this
contribution level, the protective device can be coordinated properly based on the fault level.
However, the problem is the presence of DG within Microgrid which modify the fault current
and affect the existing protection coordination.
In the islanded mode, assuming Microgrid only consists of IB-RES, the fault contribution
level is only 2-3 times of the rated current[2]. Since the fault contribution is low, it will not
trigger the protective device to pick-up. Another possibility is the protective device will pick-
up in a longer delay. In the low voltage, this protective device can be a fuse or IED.
Specifically for low voltage breaker, assuming the Microgrid also have molded case circuit
breaker (MCCB), depending on the product, the magnetic setting in MCCB can only be set
for a minimum of 5 times rated current[5]. However, the IED has a more flexible setting for
the instantaneous function[6]. So there is a need to have a proper coordination grading for
both grid-connected and islanded mode.
The current limitation on the fault level is due to the effect of power electronic protection
of inverter[7]. The desaturation detection technique for identifying a fault condition and a
short circuit in an insulated gate bipolar transistor (IGBT) is used in the protection of inverter.
The thermal protection of IGBT is also responsible for the limited fault contribution within
the Microgrid.
3.1.2 Blinding Protection
Due to the contribution of the DG within the Microgrid, the fault current measured by the
overcurrent (OC) relays is reduced, i.e. if the DG is connected between the feeding substation
and the fault location, then the feeder relay will sense decreased fault level[8, 9]. It can result
in the longer time for the breaker to be tripped caused by the presence of DG within the
Microgrid. Reference [10] provides the result for this case. It is clear from the result that there
is a delayed tripping of the feeder delay. Moreover, in the worst case scenario, there might
be no tripping at all. Blinding Protection is illustrated in Figure 3.1 left side.
3.1.3 Sympathetic/False Tripping
DG can contribute to a fault on a feeder fed from the same substation resulting in the
unnecessary isolation of a healthy phase or a DG unit. This condition is undesirable
considering that Microgrid should isolate the fault and make the remaining healthy grid
operate. Unnecessary isolation of a healthy phase or DG unit is shown in references[8, 10,
6
11]. The impacts of the sympathetic tripping within the Microgrid mean significant exposure
to the reliability of the system. Sympathetic tripping is illustrated in Figure 3.1 right side.
DG
Feeder 1
Fault
Utility Grid
PD 1 (not working)
PD 2
Blinding Protection
PD = Protective Device
DG
Feeder 1
Fault
Utility Grid
PD 1
PD 2 (open)
Sympathetic Tripping
PD = Protective Device
Feeder 2
PD 3
Figure 3.1 Blinding Protection (left) & Sympathetic Tripping (right)
3.2 Qualities of a Protection
Qualities of protection that are discussed in this degree project are reliability, selectivity, and
sensitivity.
3.2.1 Reliability
Reliability can be divided into two categories[12]: dependability and security. Dependability
is how the Microgrid relies on the protection, i.e. when there is a fault, the circuit breaker
should trip. For instance, dependability is presented in the condition that the circuit breaker
should trip at fault condition thus showing the protection is working properly. The next
category is security which is defined as the protection against unwanted tripping, i.e. when
there is no fault occurrence, the breaker should not trip.
Despite the protection reliability, it is important to mention the system reliability. If a
fault occurs within the Microgrid, it is expected that the protection will work so that it can
isolate the fault and make the rest of the grid remains operational. It means that the protection
enhances the system reliability. Two parameters of the system reliability are system average
interruption frequency index (SAIFI) and system average interruption duration index
(SAIDI)[13]. By implementing the Microgrid protection strategy, the frequency and duration
interruption can be reduced.
3.2.2 Selectivity
When a fault occurs, the protection scheme is required only for breaker whose operation is
required to isolate the fault. This property of selective tripping is called discrimination. There
is a need for Microgrid to remain operational after isolating the fault and some of the sensitive
7
loads may need uninterruptible connection. The criteria to keep the healthy grid remains
operated is referred as stability. This term is applied in protection and different to the power
networks as it refers to the ability to remain inert to all load condition and fault to the relevant
zone. For this reason, selectivity criteria need to be considered to achieve stability in
Microgrid protection.
3.2.3 Sensitivity
Sensitivity is a term frequently used when referring to the minimum operating level of relays
such as current, voltage, power or complete protection scheme. The choice of the protection
device can affect the sensitivity, for instance, the option to choose the MCCB or a high-speed
solid state switch at PCC. Sensitivity needs to be considered as there might be a potential loss
of Microgrid stability due to a fault. Sensitivity can also be defined as speed or protective
relays respond to an abnormal condition in the least possible time to avoid damage to
equipment and maintain stability[14]. Between the selectivity and sensitivity, there should
be an acceptable technical compromise[15].
To summarise, the quality of protection is defined in Table 3.1.
Table 3.1 Quality of Protection
3.3 Available Solutions for the Microgrid Protection
This subsection presents the available solutions for the Microgrid protection. By defining the
Microgrid protection issues and protection technical requirement, a protection strategy can
be proposed depending on the needs in the low voltage Microgrid.
3.3.1 Adaptive Protection
A protective device or relay has the capability to change its setting online, and it is suitable
for the Microgrid application whether the Microgrid is in grid-connected or islanded mode.
In the past, some papers discussed the adaptive protection implementation in the
Microgrid[11, 16-18]. Based on these references, the protection coordination is the key for
the Microgrid configuration. To be noted that this coordination might be set based on the
Microgrid topology, type of the fault, and the protective devices that are used in the grid, so
there are some technical challenges to be mentioned to improve the quality of the protection
coordination[16]. This practical solution needs to replace all the electromechanical and the
Definition
- Protective devices (fuse, IED, breaker, and etc) do not give dependability and security
• Depends on the inverter protection to isolate the grid
•• Both system and inverter protection are reliable
- -
• Relatively long delay
•• Fast
- Not selective
• Selective in some parts
•• Fully coordinated
Quality of Protection
Reliability
Sensitivity
Selectivity
8
solid state relay or possibly fuse in the low voltage typical grid by the IED. These IEDs have
the flexibility and capability to change the tripping characteristic[6].
Another solution for the adaptive protection is the use of fuses, recloser, and IED within
the Microgrid. For the low voltage Microgrid, the presence of fuses is expected. Hence it
might not be economical to change the fuse with IED as it comes at an additional cost. This
fuse-relay scheme provides cost-efficient solution compared to relay-relay adaptive OC
protection. IEDs are more reliable but costly as the application of the IED requires circuit
breaker, current transformer, a control circuit, and possibly communication. Reference [19]
provides a test using fuses, recloser, and relay resulting in high level of speed, compromised
reliability, and selectivity. Noted that this study regarding the fuse-relay is an interesting
solution with a few literature among Microgrid protection strategies.
3.3.2 Differential and Symmetrical Component Protection
If fault contribution within the Microgrid is low when the Microgrid is operated in an islanded
mode, one of the alternative solutions is to deploy the differential and symmetrical
component protection as presented in[20]. However, the topology in that reference was not
presented in detail, i.e. the earthing system was not provided as it is important for the
Microgrid protection analysis and decision. It was mentioned that differential protection is to
tackle the downstream earth fault protection, negative sequence protection for the line to line
fault, and zero sequence protection for the upstream earth fault. While the result was valid
and had a proper knowledge of protection, the explanation was given more deeply in another
reference[21] as the earthing system was presented. It is important that the result or
conclusion should not be generalised because the protection strategy depends on topology,
type of the fault, the protective devices that are used in the grid, and furthermore the
apparatus/part of the system that should be protected.
The differential protection mostly uses a communication structure as it needs two inputs
or even more in the case of the block differential with several (more than two) inputs. If the
communication fails, there is a need to have a backup protection. A transfer trip using
hardwire might be necessary to handle the communication fail. While phase OC has some
problems issue within Microgrid as a backup protection, an under voltage protection may be
taken into consideration. Another option is to have the symmetrical sequence protection as a
back-up even though this degree project will consider the symmetrical sequence protection
as the main protection. The demerits for the differential scheme is that this scheme requires
proper communication structure which might be considered as an economic issue or
constraint in the residential low voltage grid.
3.3.3 Voltage-based Protection
According to[22], the voltage based protection is proposed using the IB-RES inverter. When
this autonomous scheme is implemented, whether the Microgrid is operated in grid-
connected or islanded mode, the communication from the IB-RES to PCC should be
connected. The next sequence of operation is to decide which breaker should be opened.
However, it implies that even though it is a proper option to protect individual IB-RES, there
is a vulnerability in term of system protection. It is safe to say that this scheme is dependent
on Microgrid topology, so it is not a plug and play concept which means not preferable to the
9
Microgrid protection strategy. This scheme also has another noticeable demerit such as any
voltage deviation within the Microgrid may lead to dis-operation of the protection.
It is also important to mention individual IB-RES protection because it is related to anti-
islanding protection. Even though in Microgrid this anti-islanding signal will be blocked, it
is also important to have individual protection such as under/over voltage or frequency.
3.4 Power Flow Studies
Equation ((3.1) and (3.2) describes the form of the power flow equations; these equations
provide calculated values for the net real and reactive power entering the network at typical
bus i as shown in Figure 3.2.
𝑃𝑖 = ∑|𝑌𝑖𝑛𝑉𝑖𝑉𝑛|𝑐𝑜𝑠(𝜃𝑖𝑛 + 𝛿𝑛 − 𝛿𝑖)
𝑁
𝑛=1
(3.1)
𝑄𝑖 = − ∑|𝑌𝑖𝑛𝑉𝑖𝑉𝑛|𝑠𝑖𝑛(𝜃𝑖𝑛 + 𝛿𝑛 − 𝛿𝑖)
𝑁
𝑛=1
(3.2)
Mismatches occur from solving a power flow problem when calculated values of 𝑃𝑖 and
𝑄𝑖 do not match with the scheduled values 𝑃𝑖,𝑠𝑐ℎ and 𝑄𝑖,𝑠𝑐ℎ as shown in Figure 3.2. If the
calculated values 𝑃𝑖,𝑐𝑎𝑙𝑐 and 𝑄𝑖,𝑐𝑎𝑙𝑐 match the scheduled values 𝑃𝑖,𝑠𝑐ℎ and 𝑄𝑖,𝑠𝑐ℎ perfectly,
then the mismatches ∆𝑃𝑖 and ∆𝑄𝑖 are zero at bus i. The power balance equations then is
written as in Equation (3.3).
𝑔𝑖′ = 𝑃𝑖 − 𝑃𝑖,𝑠𝑐ℎ = 𝑃𝑖 − (𝑃𝑔𝑖 − 𝑃𝑑𝑖) = 0 (3.3)
𝑔𝑖′′ = 𝑄𝑖 − 𝑄𝑖,𝑠𝑐ℎ = 𝑄𝑖 − (𝑄𝑔𝑖 − 𝑄𝑑𝑖) = 0
Figure 3.2 Notation for active and reactive power at a typical bus i in power flow studies
At most, there are two equations such as Equation (3.3) available for each node, and so
there is a need to consider how the number of unknown quantities can be reduced to agree
with the number of available equations before solving the power flow problem. The general
practice of power flow is to identify three types of buses in the network. Two of the four
quantities 𝛿𝑖 , |𝑉𝑖|, 𝑃𝑖 , and 𝑄𝑖 are specified. These are the types of the bus:
1. PQ Bus. Both active and reactive power are specified
2. PV Bus. The active power is specified; the voltage magnitude is kept constant
3. Swing/slack Bus. The voltage and phase angle are specified. There is no requirement
to include (3.3) for the slack bus means that the mismatches are not defined for the
slack bus
10
3.4.1 Representation of Cables
Some of the cables that have shunt admittance values in this thesis are represented as a pi-
equivalence circuit as shown in Figure 3.3.
Z
+ +
- -
Y/2 Y/2
Figure 3.3 Pi-equivalent circuit
The current in the capacitance at the receiving end and the current in the series circuit are
needed to obtain an expression for 𝑉𝑠 as shown in Equation (3.4).
𝑉𝑠 = (𝑉𝑅
𝑌
2+ 𝐼𝑅) 𝑍 + 𝑉𝑅 (3.4)
3.4.2 Unbalanced Load Flow Analysis
The unbalanced load flow (ULF) analysis is done to distinguish normal operation (under
unbalanced load) and a fault condition. In case of SLG and LLG fault, the negative and zero
sequence component will present whereas in case of LL fault only negative sequence
component will present. Typically, in distribution grid, the three-phase load flow will not be
ideally balanced. Even the amount of unbalanced load may not be significant for each phase,
the ULF analysis needs to be done in order to set the lowest permissible pick-up value for the
IED. The ULF analysis is done by a software called electrical transient analysis program
(ETAP).
ETAP solves the ULF analysis with a technique called Newton-Raphson power flow
calculation using current injection method (CIM) as presented in[23, 24]. Equations (3.5)
presents three-phase current mismatches for a given bus k.
∆𝐼𝑘2 =
(𝑃𝑘𝑠𝑝
)𝑠
− 𝑗(𝑄𝑘𝑠𝑝
)𝑠
(𝐸𝑘𝑠)∗
− ∑ ∑ 𝑌𝑘𝑖𝑠𝑡𝐸𝑖
𝑡
𝑡𝜖𝛼𝑝𝑖∈Ω𝑘
(3.5)
Where,
𝑠, 𝑡 ∈ 𝛼𝑝
𝛼𝑝 = 𝑎, 𝑏, 𝑐
𝑘 = 1, … , 𝑛, n is the total number of buses
Ω𝑘 is set of buses directly connected to bus 𝑘
𝑌𝑘𝑖𝑠𝑡 = 𝐺𝑘𝑖
𝑠𝑡 + 𝑗𝐵𝑘𝑖𝑠𝑡, the nodal admittance bus matrix element
11
3.5 Short Circuit Principle
In order to detect a fault in both grid-connected and islanded mode, a different method is
approached compared to the OC protection. The purpose of symmetrical component study is
to extract the sequence component (negative and zero sequence) from unsymmetrical phasor.
By doing this, this component can be assessed to detect the fault i.e. single-line-to-ground
(SLG), line-to-line (LL) fault, and line-line-to-ground (LLG) fault. However, by doing this
study, the three-phase (3-P) fault cannot be detected by this method since this type of fault is
symmetrical.
3.5.1 The Symmetrical Components of Unsymmetrical Phasor
Each of the unbalanced components is the sum of its components; the phasor is defined in
term of its components as presented in Equation (3.6).
𝐼𝑎 = 𝐼𝑎(0)
+ 𝐼𝑎(1)
+ 𝐼𝑎(2)
(3.6) 𝐼𝑏 = 𝐼𝑏(0)
+ 𝐼𝑏(1)
+ 𝐼𝑏(2)
𝐼𝑐 = 𝐼𝑐(0)
+ 𝐼𝑐(1)
+ 𝐼𝑐(2)
The three sets of symmetrical component are defined by the additional superscript 1 for
the positive sequence component, 2 for the negative sequence components, and 0 for the zero
sequence component as presented in Figure 3.4.
Figure 3.4 The Symmetrical Component of Unsymmetrical Phasor
Let 𝑎 = 1∠120∘, then the final matrix of the sequence component can be deducted by its
phasor as presented in Equation (3.7).
[
𝐼𝑎(0)
𝐼𝑎(1)
𝐼𝑎(2)
] =1
3[1 1 11 𝑎 𝑎2
1 𝑎2 𝑎] [
𝐼𝑎
𝐼𝑏
𝐼𝑐
] = 𝐴−1 [
𝐼𝑎
𝐼𝑏
𝐼𝑐
] (3.7)
Equation (3.7) is important to the fault analysis since the main idea is to use this sequence
element in order the IED to pick up under fault condition.
12
3.5.2 Unsymmetrical Faults
The fault that is discussed in this subsection could involve fault impedance 𝑍𝑓. This degree
project neglects the fault impedance which means the fault is a bolted fault means direct short
circuit. Figure 3.5 represents the connection diagram of the hypothetical stubs for various
faults through impedance.
Single-line-to-ground fault line-to-line fault line-line-to-ground fault
k
k
k
k
k
k
k
k
k
Figure 3.5 Connection diagram for Various Faults
After the fault connection diagram is briefly explained, Figure 3.6 shows the Thévenin
equivalent circuit between the faulty point k and the reference node in each sequence
network. There are no negative or zero sequence currents flows before the fault occurs, and
that is why the pre-fault voltages are zero on all buses if the negative and zero sequence
network.
k+
-
k+
-
k+
-
Thevenin Equivalent of the Positive Sequence Network
Thevenin Equivalent of the Negative Sequence Network
Thevenin Equivalent of the Zero Sequence Network
Figure 3.6 The Sequence Network of the System
The terminal voltage equation for the Thévenin equivalent of the sequence network
shown in Figure 3.6 is presented in Equation (3.8).
𝑉𝑘𝑎(0)
= −𝑍𝑘𝑘(0)
𝐼𝑓𝑎(0)
(3.8) 𝑉𝑘𝑎(1)
= 𝑉𝑓 − 𝑍𝑘𝑘(1)
𝐼𝑓𝑎(1)
𝑉𝑘𝑎(2)
= −𝑍𝑘𝑘(2)
𝐼𝑓𝑎(2)
3.5.3 Single-Line-to-Ground Fault
The SLG fault in this thesis simulation will consider the phase a as a faulty phase. This type
of fault is the most common type caused by lightning or conductor making contact with a
grounded structures, i.e. the branch of the tree making contact with the conductor. As shown
in Figure 3.5, the fault is at the bus k and defined by Equation (3.9).
𝐼𝑓𝑏 = 0 𝐼𝑓𝑐 = 0 𝑉𝑘𝑎 = 𝑍𝑓𝐼𝑓𝑎 (3.9)
13
The final result for the sequence current for SLG fault then is given as
𝐼𝑓𝑎(0)
= 𝐼𝑓𝑎(1)
= 𝐼𝑓𝑎(2)
=𝑉𝑓
𝑍𝑘𝑘(0)
+ 𝑍𝑘𝑘(1)
+ 𝑍𝑘𝑘(2)
+ 3𝑍𝑓
(3.10)
Equation (3.10) confirms the Thévenin equivalent of the sequence network as in Figure
3.7 for the SLG fault. It is shown that the sequence component is connected in series in
addition to the fault impedance 𝑍𝑓 as well.
k+
-
k+
-
k+
-
Figure 3.7 Thévenin Equivalent of Sequence Network for SLG fault
3.5.4 Line-to-line Fault
Phase b and phase c are chosen as faulty phase for the LL fault. The voltages for the zero
sequence network must be zero since there are no zero sequence sources. Hence the LL fault
calculation does not involve the zero sequence network. However in this thesis Microgrid,
one of the proposed strategies is using negative or zero sequence component method. Since
the LL fault still has the negative sequence, it is also possible to detect the fault theoretically.
By defining the faulty phase, these are the requirement presented in Equation (3.11)
𝐼𝑓𝑎 = 0 𝐼𝑓𝑏 = −𝐼𝑓𝑐 𝑉𝑘𝑏 − 𝑉𝑘𝑐 = 𝐼𝑓𝑏𝑍𝑓 (3.11)
k+
-
k
+
-
Figure 3.8 Thévenin Equivalent of Sequence Network for LL fault
By confirming Figure 3.8 the current sequence for LL can be determined as presented in
Equation (3.12).
14
𝐼𝑓𝑎(1)
= −𝐼𝑓𝑎(2)
=𝑉𝑓
𝑍𝑘𝑘(1)
+ 𝑍𝑘𝑘(2)
+ 𝑍𝑓
(3.12)
3.5.5 Line-line-to-Ground Fault
Phase b and phase c are chosen as the faulty phase with the addition of making contact with
the grounding structure or earthing. As in Figure 3.5, the requirement for LLG fault is
presented in Equation (3.13).
𝐼𝑓𝑎 = 0 𝑉𝑘𝑏 = 𝑉𝑘𝑐 = (𝐼𝑓𝑏 + 𝑖𝑓𝑐)𝑍𝑓 (3.13)
k+
-
k+
-
k+
-
Figure 3.9 Thévenin Equivalent of Sequence Network for LLG fault
By confirming Figure 3.9 the positive current sequence for LLG can be determined as in
Equation (3.14). Then the negative and zero sequence current can be determined by doing a
current division.
𝐼𝑓𝑎(1)
=𝑉𝑓
𝑍𝑘𝑘(1)
+ [𝑍𝑘𝑘
(2)(𝑍𝑘𝑘
(0)+ 3𝑍𝑓)
𝑍𝑘𝑘(2)
+ 𝑍𝑘𝑘(0)
+ 3𝑍𝑓
]
(3.14)
3.5.6 Transformer Zero Sequence Equivalent Circuit
The representation of the zero sequence equivalent circuit that is used in this thesis is
presented as in Figure 3.10.
The transformer that is used in this thesis has star solidly grounded earthing and delta
connection. If zero sequence current can flow into and out of a winding, link a is closed. If
zero sequence current can circulate in the winding without flowing in the external circuit,
link b is closed.
a a
b b
Figure 3.10 Transformer Zero Phase Sequence Network
15
3.6 Fault Ride-Through Capability
To have a general sight, the IEEE 1547 for interconnecting distributed resources on the
distribution system is presented in Table 3.2. IEEE 1547 includes interconnection of all types
of DG up to 10MVA at the PCC with the utility. In Table 3.2, it is shown that despite having
LVRT, high voltage ride through (HVRT) is also presented. Focusing more on LVRT which
is referred as fault ride-through (FRT) in this thesis, it can be seen from Figure 3.11 (left side)
that the typical FRT characteristic is presented. If the IB-RES is still above the slope
characteristic, means it could remain connected to the grid. However, as long as it reaches
the slope then it should be disconnected. It can be seen that every country has different
regulation of FRT presented in Figure 3.11 (right side). One of the interesting characteristics
is from Japan grid. The data represented in Japan is actually from the residential zone and
applied in 2016. It may be a reference as well for this thesis because the Microgrid project is
within a residential area which has a voltage level of 0.42kV.
Table 3.2 IEEE 1547 (Table 1) Interconnection system response to abnormal voltages
Voltage Range (% of base voltagea) Clearing time (s)b
V<50 0.16
50≤V<88 2.00
110<V<120 1.00
V>120 0.16 aBase voltages are the normal system voltages stated in ANSI C84.1-1995
bDG≤30kW, maximum clearing time; DG>30kW, default clearing time
`
Italy US-FERC Germany Denmark Spain JapanVoltage (pu)
time (s)
Remain Connected
Voltage (pu)
time (s)
Figure 3.11 FRT Requirement [25, 26]
3.7 Fuse – Relay Coordination
The basic approach is, whenever possible, to ensure the relay back up the fuse and not the
way around, since it is challenging to maintain correct discrimination at high values of fault
current because of the fast operation of the fuse[12]. The relay characteristic to coordinate
with the fuse is expected to be extremely inverse standard which follows 𝐼2𝑡 characteristic.
16
The example of fuse coordination in time current characteristic (TCC) curve is shown in
Figure 3.12.
Figure 3.12 Fuse Coordination - Time Current Characteristic (TCC)
Typically, the coordination of the fuses in distribution grid is not a problem; means is not
intersected with each other because it is already defined in a standard for low voltage fuses.
However, once the fuse is replaced with an IED, the TCC should be similar to what fuses
have. Table 3.3 represents the equations for the extremely inverse (EI) characteristic.
Table 3.3 Definitions of Standard Relay Characteristic
Relay Characteristic Equation Standard
IEC Extremely
Inverse 𝑡 = 𝑇𝑀𝑆 ∙
80
𝐼𝑟2 − 1
IEC 60255
IEEE Extremely
Inverse 𝑡 =
𝑇𝐷
7∙ (
28.2
𝐼𝑟2 − 1
) + 0.1217 Northern American
IDMT Relay
Where,
𝐼𝑟 = (𝐼
𝐼𝑠) , 𝐼𝑠 𝑖𝑠 𝑡ℎ𝑒 𝑟𝑒𝑙𝑎𝑦 𝑠𝑒𝑡𝑡𝑖𝑛𝑔 𝑐𝑢𝑟𝑟𝑒𝑛𝑡
𝑇𝑀𝑆 = 𝑇𝑖𝑚𝑒 𝑀𝑢𝑙𝑡𝑖𝑝𝑙𝑖𝑒𝑟 𝑆𝑒𝑡𝑡𝑖𝑛𝑔
𝑇𝐷 = 𝑇𝑖𝑚𝑒 𝐷𝑖𝑎𝑙 𝑆𝑒𝑡𝑡𝑖𝑛𝑔
17
3.8 Grading Margin
The minimum coordination time between each of the IEDs is chosen based on the grading
margin requirement.
The grading margin depends on some factors such as circuit breaker interrupting time,
relay timing error, overshoot, CT error, and safety margin. For the digital and numerical
relay, the relay timing error should not be more than 5%[12]. Also, the total of overshoot and
safety margin is 0.05s. For the breaker interrupting time, the low voltage breaker is expected
to open at half cycle. However, the relay timing error does not apply to instantaneous time
delay function so it can be neglected. It is recommended to set the margin between each of
the IEDs based on this final grading margin which is 60ms.
Based on the final grading margin, in order to have acceptable delay time for
coordination, these are some considerations:
1. Islanding Detection Transition
Based on the information from the supplier, the whole transition from grid-connected
mode to an islanded mode is 60ms including islanding detection, signal sending time,
and breaker interrupting time.
2. Fault Ride-Through Capability
According to SS-EN 50438, the FRT is set to 200ms. However, if the grading margin
is applied, the FRT can be re-adjusted.
3. Directional Sequence Protection
Equation (3.15) provides the directional tripping time requirement and should follow
the grading margin standard means that the difference between each tripping time
should be at least 60ms. i represent the number of layer in the Microgrid. The layer
in the Microgrid is referred to the actual bus which has the IED connected to the each
of the lines. The first layer is the bus that closest to the utility grid while the last layer
is the bus in the end feeder.
𝑡𝑓𝑜𝑟𝑤𝑎𝑟𝑑𝑙𝑎𝑦𝑒𝑟 𝑖
< 𝑡𝑟𝑒𝑣𝑒𝑟𝑠𝑒𝑙𝑎𝑦𝑒𝑟 𝑖
, 𝑖 = 1, … , 𝑛 − 1
(3.15) 𝑡𝑓𝑜𝑟𝑤𝑎𝑟𝑑𝑙𝑎𝑦𝑒𝑟 (𝑖+1)
< 𝑡𝑓𝑜𝑟𝑤𝑎𝑟𝑑𝑙𝑎𝑦𝑒𝑟 𝑖
, 𝑖 = 1, … , 𝑛 − 1
𝑡𝑟𝑒𝑣𝑒𝑟𝑠𝑒𝑙𝑎𝑦𝑒𝑟 (𝑖+1)
> 𝑡𝑟𝑒𝑣𝑒𝑟𝑠𝑒𝑙𝑎𝑦𝑒𝑟 𝑖
, 𝑖 = 1, … , 𝑛 − 1
18
4 Chapter 4: Modelling
The modelling is divided into the studies that are done in this thesis such as unbalanced load
flow and short circuit study
The topology is provided by Vattenfall and presented as in Figure 4.1. The low voltage
Microgrid is divided into two networks and composed of:
Six energy consumers (spread into seven loads)
2 PV generations
1 energy storage system (ESS) unit
~=
~=
~=
F-T125-MV
B-T125-11
B-T125-04
F-T125
T1 – 11/0.42kV160kVA
F-LV
F-L1-1
KA-L1-1
B-T125-Y11
B-T125-X6
F-L1-2 F-L1-3
B-C1-80 B-C2-26
L-C110.5kVA
L-C214.2kVA
Battery
KA-R-1
F-L2-1
KA-L2-1
B-T125-Y21
B-T126-Y11
KA-L2-2
KA-L2-3
F-L2-2
PV-1818kVA
L-C3-112.9kVA
PV-2525kVA
L-C3-211.9kVA
F-L2-3
KA-L2-5
KA-L2-4
B-C3-94
B-C3-39
B-C3-87
F-L2-4 KA-L2-6
F-L2-5
KA-L2-7
B-T125-Y12
B-T125-J15
B-T125-A18F-L2-6
KA-L2-8
B-C4-00
L-C414.9kVA
B-R-1
B-R-2
F-L2-8
L-C614.2kVA
F-L2-7
B-C5-A19
L-C516.3kVA
HK-L1-1
HK-L1-2 HK-L1-3
HK-L2-1
HK-L2-2
HK-L2-3
HK-L2-4
Network 1
Network 2
B-T125-K6
B-C3-99
Figure 4.1 Microgrid Topology
4.1 Power Flow Study
4.1.1 Bus Types
In balanced load flow, the list of the bus types can be seen as shown in Table 3.2.
The utility grid is modelled as a swing bus. The customer loads are modelled as PQ bus.
The apparent power and the power factor of the customer loads are presented in Appendix-I.
The PV inverter is not controllable. This approach is based on IEE 1547 which states that
the inverter does not actively participate in any voltage regulation. It means that the inverter
will not respond to change in voltage by changing the reactive power production. In this
19
thesis, only the real power generation by the inverter is considered, the reactive power is set
to zero. Thus the inverter is modelled as PQ bus.
Table 4.1 Bus Types
4.1.2 Unbalanced Load Flow
The unbalanced load flow study is simulated in islanded mode. The unbalanced load study is
divided into 4 cases:
1. 20% unbalance of each phase according to [21] with the maximum aggregated load.
The balanced 3-phase data is provided by Vattenfall
2. 20% unbalance of each phase according to [21] with maximum load and minimum
PVs production
3. The unbalance of one phase is increased until the simulation does not converge
(considering each customer could have connected their load in 1 phase only)
4. Assuming each customer connect only 1 of their phase with the capacity of a third of
its maximum 3-phase load. This case is simulated because there is the probability that
when the load is at minimum/no load, several customers plug in their significant load
at one phase at the same time
In each of the cases, the direction of the load flow is also analyzed. Bus B-T125-04 and
B-T125-Y21 is the reference whether the flow is going forward or reverse. Forward direction
refers to the flow that goes to Network 2 (B-T125-04 to B-T125-Y21), while reverse direction
refers to the flow that goes to Network 1 (B-T125-Y21 to B-T125-04).
1. In forward direction, these conditions are applied: Battery is set as a swing/slack
bus, PVs are removed from the analysis. The reason that PVs are removed in this case
is to overestimate the result of detecting a fault. It means the higher the zero and
negative sequence current under unbalanced normal operation, the higher reliability
of the protection that is about to be applied
2. In reverse direction, these conditions are applied: Battery is removed from the grid,
one of the PV-18 is set to swing/slack bus. These conditions applied to overestimate
the result of detecting a fault. Even though it is known that the PVs are not allowed
to be controlled, to improve the protection study, these condition is applied
Connected Utility Bus Type
Utility Grid Swing
L-C1 PQ
L-C2 PQ
L-C3-1 PQ
L-C3-2 PQ
L-C4 PQ
L-C5 PQ
L-C6 PQ
PV18 PQ
PV25 PQ
Battery PQ
20
4.1.3 Cables
The cables data are presented in Appendix-I. The cables consist of underground cables and
hanging cable. If there is no admittance data, the cable is treated as a simple impedance. If
there is an admittance data, the circuit element is treated as a pi-equivalent, with one-half of
the charging susceptance connected to neutral at each end of the circuit. The first two letters
in the cable ID represent the type of the cables. KA is referred to underground cable and HK
is referred to hanging cable.
4.1.4 Transformer
The transformer that connects the medium (11kV) and low voltage (0.42) side have the power
rating of 160kVA. The positive sequence impedance data is provided in Appendix-I.
4.2 Short Circuit and Sequence-of-Operation Study
4.2.1 Utility Grid
The short circuit rating is presented in Appendix-I. The X/R ratio is assumed to be 1.
4.2.2 Loads
The loads connection is star with solidly grounded earthing for the short circuit analysis.
4.2.3 Transformer
The medium voltage side connection is delta; the low voltage connection is star with solidly
to ground earthing. The positive and zero sequence impedance data is provided in Appendix-
I.
4.2.4 Inverter
The inverter is modelled as a voltage source to the AC system. When its terminal bus is
faulted, the maximum possible contribution from the inverter is assumed to be 1.2 times rated
current in this thesis. If the fault location is further than the inverter terminal, the fault
contribution from the inverter is decreased. The inverter connection to the AC system is star
with solidly grounded earthing. The negative and zero sequence impedance of the inverter
units are the same as the positive sequence 𝑍2 = 𝑍0 = 𝑍1. The impedance value is
determined using the rated output voltage and maximum short circuit current as shown in
Figure 4.2. The complete data for the PV and battery inverter is provided in Appendix-I.
Short Circu
it
Figure 4.2 Inverter Internal Impedance
21
5 Chapter 5: Short Circuit and Sequence of Operation Analysis of
the Existing Protection
5.1 Grid-Connected Mode
47 problems were found in the steady-state analysis of short circuit and sequence-of-
operation study in grid-connected mode. The lists of the problem are presented in Appendix-
II. The typical problem is presented in this chapter by showing the result of short circuit study
and sequence-of-operation at bus B-T125-Y21 and B-T125-04; the single line diagram was
presented in Figure 4.1. The fault that is presented in this chapter is SLG fault.
In this context, the problems are related to the reliability of the fuses and FRT capability
in each of the PV/battery inverters.
5.1.1 Bus: B-T125-Y21 – SLG Fault
The result for simulating the SLG fault at bus B-T125-Y21 is that the upstream fuse prior to
the faulty bus, F-L2-1, melted in an instant less than 10ms while the downstream fuses did
not melt. The result for the upstream fuse was expected because there was a large contribution
fault current from the utility grid. Since the inverter of the PVs provided low fault current,
the result for the downstream fuse was also expected which is one of the problems.
The downstream fuses that did not melt were F-L2-2, F-L2-3, and F-L2-4. Since the fuses
did not melt, and the Microgrid does not have any protective device to clear and isolate the
fault, the disconnection of the PV was expected. As a consequence, Network 2 was collapsed.
It means that the fault clearance relies on the internal PV protection. If in any case that the
PV protection does not work, the fault poses a safety issue depending on how long the
inverter of the PV is able to feed the fault. As long as the DC part of the inverter can produce
electricity during the fault, then an accident might happen such as electrical shock.
Regarding the PV internal protection, In Sweden, distribution system operator (DSO) has
a requirement to the customer who wants to connect their PV to the grid. Table 5.1 provides
the information in an application form which is used to request the PV connection (generally
for micro production). The application form is in Swedish and translated into English. This
table is according to SS-EN 50438 and supplemented by SEK TK 8[27].
Table 5.1 Relay Protection Setting according to SS-EN 50438 supplemented by SEK TK 8
Protection Function
Set Value Enl. SEK TK 8
Time Level Time Level
Overvoltage (stage 2) 60s 255.3V Overvoltage (stage 1) 0.2s 264.5V
Undervoltage 0.2s 195.5V Overfrequency 0.5s 51Hz
Underfrequency 0.5s 47Hz
However, in addition to the fact that the disconnection of the PV is important to clear the
fault, the smarter protective device is needed to isolate only at the faulty bus and make the
remaining healthy grid in operation.
22
5.1.2 Bus: B-T125-04 – SLG Fault
The result for simulating the SLG fault at bus B-T125-04 is that the upstream fuse prior to
faulty bus, F-LV melted in an instant, less than 10ms while the downstream fuses did not
melt. The downstream fuses that did not melt were F-L2-1, F-L2-2, F-L2-3, and F-L2-4. This
causes the disconnection of PV in order to isolate the fault and leads to the complete
shutdown of a Microgrid.
Since the faulty bus is a main bus that is connected to the secondary side of the
transformer, any protective device should be able to isolate the faulty bus from the closest
point. The result shows that the fuses does not integrate with the presence of PV; this case
gives the similar problem as presented in the previous simulation – SLG fault at bus B-T125-
Y21. Because the fault current was low, the downstream fuses did not melt which leads to
disconnection of the PV from the grid. It also poses the safety issue as long as the PV keep
feeding the fault.
The inverter of the battery was expected to disconnect from the grid during the fault. In
the simulation, the internal protection of the battery was chosen to be undervoltage protection
to represent the FRT capability of the inverter. Since the battery is considered as the micro
production, the data in Table 5.1 was applied in the simulation. Since the aim of the FRT is
to withstand the fault for a certain of time, in this particular example is 200ms, thus if the
fault still persist after 200ms then the disconnection of the battery is expected from the grid.
It means if there is a coordination between the protective devices, it should be under 200ms
otherwise a complete shutdown of the Microgrid is expected. If there is a condition to change
the requirement to implement the selectivity in the protective devices, thus DSO is suggested
to discuss with the section that regulates the standard as presented in Table 5.1. The condition
is described in chapter 7 as it is related to the Microgrid protection strategy.
To compare the FRT that was simulated in this thesis, Figure 5.1 shows that the FRT
capability has a slope setting instead of a fixed setting provided in Table 5.1. This
characteristic is used for wind power plant in high voltage connection according to Nordic
Grid Code[28]. However, since the Microgrid is in the low voltage level, it might not be
related to the current project, but it can be a reference to define the FRT capability in the
Microgrid.
Figure 5.1 FRT Capability for Wind Power Plant according to Nordic Grid Code
23
5.2 Islanded Mode
47 problems were found in the steady-state analysis of short circuit and sequence-of-
operation study in islanded mode. The lists of the problem are presented in Appendix-II. The
typical problem is presented in this chapter by showing the result of short circuit study and
sequence-of-operation at bus B-T125-Y21 and B-T125-Y11. The fault that is presented in
this chapter is SLG fault.
5.2.1 Bus: B-T125-Y21 – SLG Fault
In this simulation, the different of the battery inverter capacity is applied. The first case
applied the 30kVA battery inverter capacity and the second case applied the 90kVA battery
inverter capacity according to the inverter data in Appendix-I.
The result for the first case is that both upstream (F-L2-1) and downstream fuses (F-L2-
2, F-L2-3, and F-L2-4) did not melt while the result for the second case is that the upstream
fuse melted in a long time, 59 second, and the downstream fuses did not melt. It shows that
a different battery inverter capacity affects the fuse melting time. Even though in the second
case the result shows that the fuse melted in 59 seconds but the isolation depends on the FRT
capability in the battery inverter. When the data in Table 5.1 were applied in simulation, the
result showed that the battery and the PVs disconnected from the grid after the fault was
applied and lead to the collapsing Microgrid.
Even in any case that the inverter is able to feed the fault in 59 seconds, there is a
requirement from the DSO that the fuse should melt under 5 second during a fault. It means
that even the battery has a bigger capacity and a longer FRT, the fuse still does not integrate
with the IB-RES.
5.2.2 Bus: B-T125-Y11 – SLG Fault
This simulation provides two cases of the different battery inverter capacity as explained in
the previous simulation. The result showed that fuse F-L1-1 melted in 29.2 seconds if the
battery inverter capacity is 90kVA otherwise fuse F-L1-1 did not melt for the other case.
It leads to the same conclusion from the previous simulation which is the fuse did not
integrate with the IB-RES thus the battery and the PVs disconnected from the grid after the
fault was applied and lead to the collapsing Microgrid. In general result, any fault in islanded
mode lead to the collapsing Microgrid assuming that the internal protection of battery and
PVs can be relied. Thus if the Microgrid is expected to be able to isolate the fault and make
the remaining healthy grid in operation, there is a need to replace the fuses with the smarter
protective device such as IED.
5.3 Conclusion for the Short Circuit and Sequence-of-Operation Study of the
Existing Protection
Based on the previous analysis that is presented in section 5.1 and 5.2, the conclusions are
provided in the following points:
Grid-Connected Mode
1. When a fault was applied within the Microgrid, the fuses downstream prior to
fault condition that is related to the IB-RES did not melt. The fuse that is upstream
24
prior to the fault condition melted in an instant due to large contribution fault
current from the utility grid
2. If there is a fault and the disconnection of the IB-RES is needed, then the
disconnection is relied on the inverter (battery and PVs) internal protection
3. Because of the fuse did not integrate with the presence of the IB-RES when there
was a fault, it posed a personal safety issue that should be taken into consideration
Islanded Mode
1. The larger capacity of the battery inverter provided more fault current which made
the fuse melted in a relatively long delay compared to the smaller inverter which
did not make the fuse melted
2. Despite the fact that the fuse melted in a relatively long delay, the battery and PVs
inverter were disconnected from the grid due to its FRT capability
3. It can be concluded that if a fault occurs in islanded mode, the whole Microgrid
will collapse. In order to have more reliability, a protection strategy needs to be
addressed
25
6 Chapter 6: Fault Detection Method using Directional Zero and
Negative Sequence Current Protection
This chapter presents the result of unbalanced load flow analysis followed by protection zone
analysis.
6.1 Unbalanced Load Flow Analysis
This section presents the result of unbalanced load flow analysis which is divided into four
cases as presented below.
6.1.1 Case – 1: 20% Unbalance with Maximum Aggregated Load
After the ULF was analysed, the result is summarized in Table 6.1. It can be seen the flow
from each of the buses to another bus is presented by Unbalanced Load Flow (A) column.
This column means that this value is applied as the lowest permissible value for the IED to
pick-up under negative and zero sequence component protection. 𝐼2 represents the negative
sequence current and 𝐼0 represents the zero sequence current. It can also be seen the
minimum fault current for the specific bus flow.
Table 6.1 Unbalanced Load Flow Analysis - Case 1
Bus Unbalanced Load Flow (A) Minimum Fault Flow (A)
Forward Reverse Forward Reverse
From To |I2| |I0| |I2| |I0| |I2| |I0| |I2| |I0|
B-T125-04* B-T125-Y11 2.7 2.6 2.7 2.4 69 68 - -
B-T125-Y11 B-T125-X6 2.7 2.6 2.7 2.4 55 50 - -
B-T125-X6 B-C1-80 1.1 1 1 0.963 50 45 - -
B-C1-80 L-C1 1.06 1.01 1.04 0.963 - - - -
B-T125-X6 B-C2-26 1.6 1.6 1.6 1.5 51 46 - -
B-C2-26 L-C2 1.64 1.56 1.62 1.49 - - - -
B-T125-04* B-T125-Y21 5.1 4.5 2.7 2.4 48 49 21 20
B-T125-Y21 B-T126-Y11 5.1 4.5 2.7 2.4 47 46 21 20
B-T126-Y11 B-T125-K6 5.1 4.5 2.7 2.4 39 38 21 21
B-T125-K6 B-C3-94** 1 0.973 6.8 6.3 55 51 9 10
B-C3-94** B-C3-39 1 0.973 1.1 1.1 64 61 - -
B-C3-39 L-C3-1 1.04 0.973 1.07 1.07 - - - -
B-T125-K6 B-C3-87 0.58 0.542 0.595 0.597 51 47 13 14
B-C3-87 B-C3-99 0.58 0.542 0.599 0.599 64 61 - -
B-C3-99 L-C3-2 0.58 0.542 0.599 0.599 - - - -
B-T125-K6 B-T125-Y12 3.5 3 3.6 3 55 50 - -
B-T125-Y12 B-T125-J15 3.5 3 3.6 3 49 44 - -
B-T125-J15 B-T125-A18 3.5 3 3.6 3 45 39 - -
B-T125-A18 B-C4-00 0.674 0.584 0.691 0.638 42 36 - -
B-C4-00 L-C4 0.674 0.584 0.691 0.638 - - - -
B-T125-A18 B-R-1 2.8 2.4 2.9 2.6 43 37 - -
B-R-1 B-R-2 1.6 1.3 1.6 1.5 43 37 - -
B-R-1 B-C5-A19 1.2 1 1.3 1.2 43 37 - -
B-C5-A19 LC-5 1.24 1.04 1.27 1.15 - - - -
* Connected to Battery Bus=Slack for Forward Analysis
** Connected to PV18 Bus=Slack for Reverse Analysis
26
It can be seen that by doing this analysis, the zero and negative sequence current can be
used to distinguish the fault and normal operation under unbalanced load condition. By doing
the forward and reverse analysis, it is expected that the normal and fault condition can be
distinguished for both direction, means that the IED will have two settings: forward or/and
reverse requirement depending on where the relay is installed.
6.1.2 Case – 2: 20% Unbalance with Maximum Load Capacity
The result is presented in Table 6.2 and implied that the unbalanced load flow analysis can
be used to distinguish normal operation and fault condition even with the maximum load
capacity and 20% unbalanced condition. To be noted that the ULF from Bus B-T125-K6 to
B-C3-94 for the reverse analysis is more than the minimum fault flow current because PV18
is set as a slack source/bus. Case 2 can also be used as a reference to set the pick-up values
of the directional zero and negative sequence current protection.
Table 6.2 Unbalanced Load Flow Analysis - Case 2
6.1.3 Case – 3: Maximum Negative and Zero Sequence Current
As it can be seen from Table 6.3, the normal operation and fault condition cannot be
distinguished in case 3 as presented in the rows that are marked in brown colour. However,
this case used an assumption if a significant 1 phase load can be connected into the Microgrid
until its limit defined by the software (did not converge). By default, this case actually will
Bus Unbalanced Load Flow (A) Minimum Fault Flow (A)
Forward Reverse Forward Reverse
From To |I2| |I0| |I2| |I0| |I2| |I0| |I2| |I0|
B-T125-04* B-T125-Y11 3.8 3.6 3.8 3.4 69 68 - -
B-T125-Y11 B-T125-X6 3.8 3.6 3.8 3.4 55 50 - -
B-T125-X6 B-C1-80 1.6 1.5 1.6 1.4 50 45 - -
B-C1-80 L-C1 1.63 1.52 1.59 1.42 - - - -
B-T125-X6 B-C2-26 2.2 2.1 2.2 1.9 51 46 - -
B-C2-26 L-C2 2.21 2.07 2.16 1.93 - - - -
B-T125-04* B-T125-Y21 10.2 8.1 3.8 3.4 48 49 21 20
B-T125-Y21 B-T126-Y11 10.2 8.1 3.8 3.4 47 46 21 20
B-T126-Y11 B-T125-K6 10.2 8.1 3.8 3.4 39 38 21 21
B-T125-K6 B-C3-94** 1.9 1.7 12.5 11 55 51 9 10
B-C3-94** B-C3-39 1.9 1.7 2 2 64 61 - -
B-C3-39 L-C3-1 1.93 1.7 2.05 2.05 - - - -
B-T125-K6 B-C3-87 1.8 1.6 1.9 1.9 51 47 13 14
B-C3-87 B-C3-99 1.8 1.6 1.9 1.9 64 61 - -
B-C3-99 L-C3-2 1.79 1.58 1.9 1.9 - - - -
B-T125-K6 B-T125-Y12 6.5 4.9 6.8 5.8 55 50 - -
B-T125-Y12 B-T125-J15 6.5 4.9 6.8 5.8 49 44 - -
B-T125-J15 B-T125-A18 6.5 4.9 6.8 5.8 45 39 - -
B-T125-A18 B-C4-00 2.1 1.6 2.2 1.9 42 36 - -
B-C4-00 L-C4 2.13 1.58 2.23 1.89 - - - -
B-T125-A18 B-R-1 4.4 3.3 4.6 3.9 43 37 - -
B-R-1 B-R-2 2 1.5 2.1 1.8 43 37 - -
B-R-1 B-C5-A19 2.3 1.8 2.5 2.1 43 37 - -
B-C5-A19 LC-5 2.35 1.76 2.46 2.08 - - - -
* Connected to Battery Bus=Slack for Forward Analysis
** Connected to PV18 Bus=Slack for Reverse Analysis
27
not be happening because as it can be seen from the load flow in Table 6.3, the phase current
is high and exceeding the fuse constraint (fuse data is presented in appendix II). One can also
think that it is not possible to connect all the load in 1 phase only.
Table 6.3 Unbalanced Load Flow Analysis - Case 3
6.1.4 Case – 4: Connecting 1 Phase Load with a Third of the Maximum Load
Capacity
It can be implied from Table 6.4 that in this case, the method can be used to distinguish
normal operation and fault condition. The unbalanced load flow in case 4 is higher than case
1 and 2. It means that the minimum current requirement for the IED to pick-up is higher
which means increasing the reliability of the protection. These facts are the reason why the
result in the first 2 cases are not going to be used in the upcoming application. Furthermore,
the result in case 4 is going to be used to determine the range for the IED to have a directional
zero and negative sequence current protection.
Bus Unbalanced Load Flow (A) Minimum Fault Flow (A)
Forward Reverse Forward Reverse
From To |I2| |I0| |I2| |I0| |I2| |I0| |I2| |I0|
B-T125-04* B-T125-Y11 0.022 0.06 29.3 29.3 69 68 - -
B-T125-Y11 B-T125-X6 0.022 0.06 29.3 29.3 55 50 - -
B-T125-X6 B-C1-80 0.009 0.025 12.4 12.4 50 45 - -
B-C1-80 L-C1 0.009 0.025 12.44 12.43 - - - -
B-T125-X6 B-C2-26 0.013 0.034 16.8 16.8 51 46 - -
B-C2-26 L-C2 0.013 0.034 16.83 16.83 - - - -
B-T125-04* B-T125-Y21 68 65.8 29.3 29.3 48 49 21 20
B-T125-Y21 B-T126-Y11 68 65.8 29.3 29.3 47 46 21 20
B-T126-Y11 B-T125-K6 68 65.8 29.3 29.3 39 38 21 21
B-T125-K6 B-C3-94** 1.3 3.8 29.2 29.2 55 51 9 10
B-C3-94** B-C3-39 1.3 3.8 0 0 64 61 - -
B-C3-39 L-C3-1 1.31 3.82 0 0 - - - -
B-T125-K6 B-C3-87 11.9 11.9 0.025 0.019 51 47 13 14
B-C3-87 B-C3-99 11.9 11.9 0.005 0.014 64 61 - -
B-C3-99 L-C3-2 11.88 11.88 0.005 0.014 - - - -
B-T125-K6 B-T125-Y12 57.3 57.2 0.016 0.041 55 50 - -
B-T125-Y12 B-T125-J15 57.3 57.2 0.016 0.041 49 44 - -
B-T125-J15 B-T125-A18 57.3 57.2 0.016 0.041 45 39 - -
B-T125-A18 B-C4-00 18.7 18.7 0.005 0.014 42 36 - -
B-C4-00 L-C4 18.72 18.71 0.005 0.014 - - - -
B-T125-A18 B-R-1 38.5 38.5 0.011 0.028 43 37 - -
B-R-1 B-R-2 17.9 17.9 0.005 0.013 43 37 - -
B-R-1 B-C5-A19 20.6 20.6 0.006 0.015 43 37 - -
B-C5-A19 LC-5 20.6 20.59 0.006 0.015 - - - -
* Connected to Battery Bus=Slack for Forward Analysis
** Connected to PV18 Bus=Slack for Reverse Analysis
28
Table 6.4 Unbalanced Load Flow Analysis - Case 4
6.2 Protection Zone Analysis
This section considers a minimum number set of IED to showcase the negative and zero
sequence protection application. In order to have a protective device to separate Network 1
and Network 2 in case of a fault, an IED with directional zero and negative sequence current
protection is chosen to be installed between bus B-T125-04 and B-T125-K6, more specific
to replace F-L2-1 with an MCCB. The location is chosen close to bus B-T125-04 which is
on the secondary side of transformer substation because the installation is more accessible in
this particular location. After the location of the IED is chosen, the setting range is proposed
from the ULF case 4 result as presented in Figure 6.1.
If the maximum current in the proposed setting range is chosen as the pick-up value for
the directional zero and negative sequence current protection, the zone of protection is
presented in Figure 6.2. It means that if a fault is applied outside the protection zone, the
protective device is not going to pick-up. Thus it is important to reduce the pick-up values in
order to have maximum coverage protection zone provided by the IED. Based on the short
circuit study result presented in Table 6.5, the maximum protected zone can be seen. If the
minimum current in the proposed setting range is chosen as the pick-up value, then the
protection zone is improved as presented in Figure 6.3.
Bus Unbalanced Load Flow (A) Minimum Fault Flow (A)
Forward Reverse Forward Reverse
From To |I2| |I0| |I2| |I0| |I2| |I0| |I2| |I0|
B-T125-04* B-T125-Y11 10.9 10.9 10.6 10.6 69 68 - -
B-T125-Y11 B-T125-X6 10.9 10.9 10.6 10.6 55 50 - -
B-T125-X6 B-C1-80 4.6 4.6 4.5 4.5 50 45 - -
B-C1-80 L-C1 4.65 4.65 4.5 4.5 - - - -
B-T125-X6 B-C2-26 6.2 6.2 6.1 6.1 51 46 - -
B-C2-26 L-C2 6.25 6.25 6.1 6.1 - - - -
B-T125-04* B-T125-Y21 28.6 28.6 10.6 10.6 48 49 21 20
B-T125-Y21 B-T126-Y11 28.6 28.6 10.6 10.6 47 46 21 20
B-T126-Y11 B-T125-K6 28.6 28.6 10.6 10.6 39 38 21 21
B-T125-K6 B-C3-94** 5.5 5.49 35.2 35.2 55 51 9 10
B-C3-94** B-C3-39 5.5 5.49 5.9 5.9 64 61 - -
B-C3-39 L-C3-1 5.5 5.49 5.9 5.9 - - - -
B-T125-K6 B-C3-87 5.11 5.11 5.5 5.5 51 47 13 14
B-C3-87 B-C3-99 5.11 5.11 5.5 5.5 64 61 - -
B-C3-99 L-C3-2 5.11 5.11 5.48 5.48 - - - -
B-T125-K6 B-T125-Y12 18 18 19.1 19.1 55 50 - -
B-T125-Y12 B-T125-J15 18 18 19.1 19.1 49 44 - -
B-T125-J15 B-T125-A18 18 18 19.1 19.1 45 39 - -
B-T125-A18 B-C4-00 5.95 5.95 6.3 6.3 42 36 - -
B-C4-00 L-C4 5.95 5.95 6.32 6.32 - - - -
B-T125-A18 B-R-1 12 12 12.8 12.8 43 37 - -
B-R-1 B-R-2 5.6 5.6 5.9 5.9 43 37 - -
B-R-1 B-C5-A19 6.43 6.42 6.82 6.82 43 37 - -
B-C5-A19 LC-5 6.43 6.42 6.82 6.82 - - - -
* Connected to Battery Bus=Slack for Forward Analysis
** Connected to PV18 Bus=Slack for Reverse Analysis
29
Normal Operation
Forw
ard - N
egative
Sequ
ence
Pick-
up
Va
lue
Fault
No
rma
l Op
eration
Reverse
- Nega
tive Seq
uen
ce P
ick-u
p V
alu
e
Fault
Normal Operation
Forw
ard - Ze
ro Se
qu
en
ce Pick-u
p
Valu
e Fault
No
rma
l Op
eration
Reverse
- Zero
Seq
ue
nce P
ick-up
V
alue Fault
Figure 6.1 Pick-up Values for Negative and Zero Sequence Protection
~=
~=
~=
F-T125-MV
B-T125-11
B-T125-04
F-T125
T1 – 11/0.42kV160kVA
F-LV
F-L1-1
KA-L1-1
B-T125-Y11
B-T125-X6
F-L1-2 F-L1-3
B-C1-80 B-C2-26
L-C110.5kVA
L-C214.2kVA
Battery
KA-R-1
KA-L2-1
B-T125-Y21
B-T126-Y11
KA-L2-2
KA-L2-3
F-L2-2
PV-1818kVA
L-C3-112.9kVA
PV-2525kVA
L-C3-211.9kVA
F-L2-3
KA-L2-5
KA-L2-4
B-C3-94
B-C3-39
B-C3-87
F-L2-4 KA-L2-6
F-L2-5
KA-L2-7
B-T125-Y12
B-T125-J15
B-T125-A18F-L2-6
KA-L2-8
B-C4-00
L-C414.9kVA
B-R-1
B-R-2
F-L2-8
L-C614.2kVA
F-L2-7
B-C5-A19
L-C516.3kVA
HK-L1-1
HK-L1-2 HK-L1-3HK-L2-1
HK-L2-2
HK-L2-3
HK-L2-4
Network 1
Network 2
Relay
MCCB
CT
B-T125-K6
VT
Protected Zone
B-C3-99
B-C3-99
Figure 6.2 Base Protected Zone
30
It can be seen from Table 6.5 that for reverse analysis, the IED setting can fully protect
Network 1 while for the forward analysis, the setting can only cover up until Bus B-T125-
Y12. By adjusting the setting to the lowest permissible value, then the protection coverage
area is presented in Figure 6.3. Still, by neglecting the protection coordination at the moment,
to completely cover Network 2, it can be said that there must be another additional protective
device to be installed. One option is to replace fuse F-L2-5 with an IED so the whole
Microgrid can be protected.
Table 6.5 Flow at Bus B-T125-04 and B-T125-Y21 (IED Reference) for Different Fault
|I2| |I0| |I2| |I0| |I2| |I0| |I2| |I0|
B-T125-04 - - 21 20
B-T125-Y11 - - 21 19
B-T125-X6 - - 16 14
B-C1-80 - - 15 13
B-C2-26 - - 16 13
B-T125-Y21 48 49 - -
B-T126-Y11 47 46 - -
B-T125-K6 42 38 - -
B-C3-94 42 38 - -
B-C3-39 42 38 - -
B-C3-87 42 38 - -
B-C3-99 42 38 - -
B-T125-Y12 36 31 - -
B-T125-J15 33 27 - -
B-T125-A18 30 24 - -
B-C4-00 28 22 - -
B-R-1 28 23 - -
B-R-2 28 23 - -
B-C5-A19 28 23 - -
Fault at Bus
Flow at Bus B-T125-04 and B-T125-
Y21 - IED Reference (A)
Forward Reverse
Lowest Permissible Value for IED -
between Bus B-T125-04 and B-
T125-Y21 (A)
Forward Reverse
Unprotected Zone
28.6 28.6
10.6 10.6- -
- -
31
~=
~=
~=
F-T125-MV
B-T125-11
B-T125-04
F-T125
T1 – 11/0.42kV160kVA
F-LV
F-L1-1
KA-L1-1
B-T125-Y11
B-T125-X6
F-L1-2 F-L1-3
B-C1-80 B-C2-26
L-C110.5kVA
L-C214.2kVA
Battery
KA-R-1
KA-L2-1
B-T125-Y21
B-T126-Y11
KA-L2-2
KA-L2-3
F-L2-2
PV-1818kVA
L-C3-112.9kVA
PV-2525kVA
L-C3-211.9kVA
F-L2-3
KA-L2-5
KA-L2-4
B-C3-94
B-C3-39
B-C3-87
F-L2-4 KA-L2-6
F-L2-5
KA-L2-7
B-T125-Y12
B-T125-J15
B-T125-A18F-L2-6
KA-L2-8
B-C4-00
L-C414.9kVA
B-R-1
B-R-2
F-L2-8
L-C614.2kVA
F-L2-7
B-C5-A19
L-C516.3kVA
HK-L1-1
HK-L1-2 HK-L1-3HK-L2-1
HK-L2-2
HK-L2-3
HK-L2-4
Network 1
Network 2
Relay
MCCB
CT
B-T125-K6
VT
Protected Zone
B-C3-99
Figure 6.3 Maximum Coverage Protected Zone by the IED
32
7 Chapter 7: Microgrid Protection Strategy
7.1 Solution – 1: Applying 1 IED to Replace Fuse F-L2-1
As presented in Figure 6.3, fuse F-L2-1 was replaced by an IED that have directional zero
and negative sequence current protection.
7.1.1 Phase OC
The first step is to ensure that the characteristic of the fuse is replaced by a function that is
available in the IED. EI characteristic is used to replace phase OC that is provided by the
fuse. The setting is shown in Table 7.1, and the TCC is presented in Figure 7.1.
Figure 7.1 Phase OC TCC
33
Table 7.1 Phase OC Setting
Phase Overcurrent (50/51)
Inverse Definite Minimum Time (IDMT) Instantaneous
Curve Type IEC - Extremely Inverse Curve Type Instant Pick-up (A) 105 Pick-up (A) 1050 Time Dial 0.1 Delay (Sec) 0.01
7.1.2 Directional Zero and Negative Sequence Current Protection
The negative and zero sequence component protection should have its discrimination if there
is any. However, since this protection is set to instantaneous delay, it can be coordinated
separately depending on the needs. A user could define more sensitive setting to these
function, means if a fault occurs within Microgrid, it will ignore the fuses characteristic and
make the IED pick-up as soon as there is a fault.
The setting for the symmetrical component is shown in Table 7.2 based on the ULF study.
However, to be noted that the instantaneous time is just an example; as long as the tripping
time is faster than the FRT and Inverter internal protection, then it can be applied.
Table 7.2 Symmetrical Sequence Current Protection – Relay 1 Setting
7.1.3 Qualities of Protection
It can be seen from Table 7.3 that by replacing fuse F-L2-1 to IED, the selectivity is reduced.
Even it is not selective, this IED provides a separation of the Network if a fault occurs on
each of the zones.
Table 7.3 Solution 1 – Qualities of Protection
7.1.4 Discussion
The coordination can be divided into phase coordination (phase OC of the IED, fuse rating,
FRT/inverter internal protection), negative sequence coordination, and zero sequence
coordination.
Symmetrical Sequence Protection
Forward Negative Sequence |I2|
Forward Zero Sequence 3·|I0|
Reverse Negative Sequence |I2|
Reverse Zero Sequence 3·|I0|
Curve type Instant Curve type Instant Curve type Instant Curve type Instant
Pick-up (A) 28.6 Pick-up (A) 85.8 Pick-up (A) 10.6 Pick-up (A) 31.8
Delay (Sec) 0.2 Delay (Sec) 0.2 Delay (Sec) 0.2 Delay (Sec) 0.2
Additional Device
Fault Reliability Sensitivity Selectivity
With 1 additional IED
Within Network 2 •• •• -
Within Network 1 •• •• -
Without additional IED
Within Network 2 • • -
Within Network 1 • • •
34
In Table 7.2, it can be seen that the zero sequence protection is multiplied by three. The
reason behind this condition is to utilise the zero sequence element into earth fault function
in an IED. However, the negative sequence element remains the same.
In this solution, however, the setting reverse can be disabled because the impact is the
same. When a fault is applied within Network 1 in islanded mode, it brings the whole
Microgrid to collapse at this point (since there is currently no protective device here other
than fuse). By enabling the reverse setting (or directional setting), the sensitivity is improved,
but still, the selectivity is still a challenging subject.
1 IED installation is enough to isolate Network 1 and Network 2 from each other if a fault
occurs within the Microgrid. If a fault is in Network 2, then the IED will send a signal to trip
the breaker and avoid the battery to be disconnected from Microgrid in islanded mode. By
doing this, the Network 1 can still be supplied by the battery. This also states that the zero
and negative sequence protection tripping time should be less than the FRT/inverter internal
protection. By making the priority of dependability and sensitivity over selectivity, the
healthy grid can remain in operation.
7.2 Solution – 2: Applying 2 IEDs within the Microgrid
In addition to the relay that is mentioned in solution 1, to increase the selectivity, another
relay is introduced to replace F-L1-1 as presented in Figure 7.2.
~=
~=
~=
F-T125-MV
B-T125-11
B-T125-04
F-T125
T1 – 11/0.42kV160kVA
F-LV
KA-L1-1
B-T125-Y11
B-T125-X6
F-L1-2 F-L1-3
B-C1-80 B-C2-26
L-C110.5kVA
L-C214.2kVA
Battery
KA-R-1
KA-L2-1
B-T125-Y21
B-T126-Y11
KA-L2-2
KA-L2-3
F-L2-2
PV-1818kVA
L-C3-112.9kVA
PV-2525kVA
L-C3-211.9kVA
F-L2-3
KA-L2-5
KA-L2-4
B-C3-94
B-C3-39
B-C3-87
F-L2-4 KA-L2-6
F-L2-5
KA-L2-7
B-T125-Y12
B-T125-J15
B-T125-A18F-L2-6
KA-L2-8
B-C4-00
L-C414.9kVA
B-R-1
B-R-2
F-L2-8
L-C614.2kVA
F-L2-7
B-C5-A19
L-C516.3kVA
HK-L1-1
HK-L1-2 HK-L1-3
HK-L2-1
HK-L2-2
HK-L2-3
HK-L2-4
Network 1
Network 2
Relay 2
MCCB
CT
B-T125-K6
VT
Protected ZoneRelay 1
MCCB
CT
VT
B-C3-99
Figure 7.2 Microgrid Solution with 2 IEDs
35
7.2.1 Phase OC
In this solution, the phase OC coordination is similar to Figure 7.1 because the downstream
and upstream fuses prior to relay 1 are the same rating as studied before. The phase OC
setting is presented as in Table 7.1.
7.2.2 Directional Zero and Negative Sequence Current Protection
The thing that needs to be considered is the coordination between forward sequence setting
of relay 1 and reverse sequence setting of relay 2. Since Network 1 does not have micro
production at the moment, so the reverse setting in relay 1 can be disabled. To ensure that
Microgrid protection has better selectivity than what is given in solution 1, the forward time
tripping in relay 1 must be less than the reverse time tripping in relay 2. The reverse negative
and zero protection in relay 2 can be stated as a backup protection. However, if a fault occurs
at the main bus B-T125-04, the reverse setting in relay 2 can detect the fault and isolate
Network 2 (at the moment Network 2 does not have any controllable sources). The example
of the negative sequence TCC coordination is shown in Figure 7.3.
Figure 7.3 Negative Sequence TCC
7.2.3 Qualities of Protection
Even though the selectivity is increased compared to by only having 1 IED, this second
solution still does not provide full protection within the Microgrid. The qualities of protection
is presented in Table 7.4
36
Table 7.4 Solution 2 – Qualities of Protection
7.2.4 Discussion
When a fault is applied in Network 1, the faulty area can be isolated and have Network 2
keep in operation which means there is selectivity in this case compared to solution 1. Since
Network 1 does not have IB-RES inside the connection, means the selectivity is improved.
Noted that there is still unprotected zone inside Network 2 as presented in Figure 7.2 which
means there is still selectivity issue in the solution.
7.3 Solution – 3: Applying 3 IEDs within the Microgrid
In addition to the relay that is mentioned in solution 1, to increase the selectivity, another
relay is introduced to replace F-L2-5 as presented in Figure 7.4.
~=
~=
~=
F-T125-MV
B-T125-11
B-T125-04
F-T125
T1 – 11/0.42kV160kVA
F-LV
KA-L1-1
B-T125-Y11
B-T125-X6
F-L1-2 F-L1-3
B-C1-80 B-C2-26
L-C110.5kVA
L-C214.2kVA
Battery
KA-R-1
KA-L2-1
B-T125-Y21
B-T126-Y11
KA-L2-2
KA-L2-3
F-L2-2
PV-1818kVA
L-C3-112.9kVA
PV-2525kVA
L-C3-211.9kVA
F-L2-3
KA-L2-5
KA-L2-4
B-C3-94
B-C3-39
B-C3-87
F-L2-4 KA-L2-6 KA-L2-7
B-T125-Y12
B-T125-J15
B-T125-A18F-L2-6
KA-L2-8
B-C4-00
L-C414.9kVA
B-R-1
B-R-2
F-L2-8
L-C614.2kVA
F-L2-7
B-C5-A19
L-C516.3kVA
HK-L1-1
HK-L1-2 HK-L1-3
HK-L2-1
HK-L2-2
HK-L2-3
HK-L2-4
Network 1
Network 2
Relay 2
MCCB
CT
B-T125-K6
VT
Protected ZoneRelay 1
MCCB
CT
VT
Relay 3
MCCB
CT
VT
Network 3
B-C3-99
Figure 7.4 Microgrid Solution with 3 IEDs
Additional Device Fault Reliability Sensitivity Selectivity
With two additional IEDs Within Network 2 •• •• •
Within Network 1 •• •• ••
37
7.3.1 Phase OC
The phase OC coordination can be seen in Figure 7.5. Noted that fuse F-L2-6 and relay
3 characteristic have a similar setting which may disrupt the coordination due to the error
margin. However, since relay 3 is originally based on fuse F-L2-5; and fuse F-L2-5 has the
same rating as F-L2-6, it means that the TCC characteristic should be overlapped. One way
to improve the selectivity is to reduce the rating of fuse F-L2-6. However, Figure 7.5 is an
example of how to make coordination for both fuse and relay.
Figure 7.5 Phase OC TCC
Relay 3 phase OC setting is provided in Table 7.5. The phase OC setting replaces the fuse F-
L2-5 characteristic.
Table 7.5 Phase OC Setting
Relay 3 - Phase Overcurrent (50/51)
Inverse Definite Minimum Time (IDMT) Instantaneous
Curve Type IEC - Extremely Inverse Curve Type Instant Pick-up (A) 82.5 Pick-up (A) 663 Time Dial 0.1 Delay (Sec) 0.01
38
7.3.2 Directional Zero and Negative Sequence Current Protection
For the negative and zero sequence coordination, the TCC is similar to Figure 7.3. To be
noted that relay 3 tripping time is faster than relay 2 for forward negative and zero sequence
protection.
The coordination that has to be considered is the forward negative and zero sequence
protection on relay 2 and relay 3. The ULF study can also be done to see the flow that goes
through Network 3. In order to avoid overlapping function with relay 2, it is a better approach
to set the tripping time in relay 3 less than relay 2. The example of the setting of relay 3 are
provided in Table 7.6. By default,
Table 7.6 Symmetrical Sequence Current Protection – Relay 3 Settings
Relay 3 - Symmetrical Sequence Protection
Forward Negative Sequence |I2| Forward Zero Sequence 3·|I0|
Curve type Instant Curve type Instant Pick-up (A) 18 Pick-up (A) 56 Delay (Sec) 0.1 Delay (Sec) 0.1
7.3.3 Qualities of Protection
By applying the three IEDs, all of the networks can be protected as shown in Figure 7.4.
Compared to solution 1 and 2 which still have an unprotected zone, this solution provides
optimum selectivity.
By Introducing another IED, it is expected that this solution has better selectivity than the
other two scenarios. It depends on what degree that the Microgrid should be protected. In the
end, it is a matter of priority. To sum up the 3 solutions, the quality of protection is given in
Table 7.7.
Table 7.7 Solution 3 – Qualities of Protection
7.3.4 Discussion
By applying three additional IEDs with a complete protection strategy that has been discussed
so far, the qualities of protection is improved. However, to make a complete selectivity by
using a fuse-relay configuration is hard to achieve in addition to the presence of IB-RES
inside Microgrid.
Additional Device Fault Reliability Sensitivity Selectivity
With 3 (three) additional IEDs Within Network 2 or Network 3 •• •• ••
Within Network 1 •• •• ••
With 2 (two) additional IEDs Within Network 2 •• •• •
Within Network 1 •• •• ••
With 1 (one) additional IED Within Network 2 •• •• -
Within Network 1 •• •• -
Without additional IED Within Network 2 • • -
Within Network 1 • • •
39
In order to see that a complete selectivity is hard to achieve within the Microgrid, the
FRT is included in this discussion. Despite that the FRT was modelled in an instantaneous
time of 200ms if the voltage dip is 15% or more, to highlight the example, the FRT is
represented by undervoltage protection with 201ms tripping time instead. Since the
coordination for the IED is based on time delay for negative and zero sequence function, the
FRT assumption does not affect the coordination.
Since the tripping time is flexible for the IED as long as it is under FRT capability, then
it is best to set the relay after the main breaker operates in the transformer substation in term
of islanding detection. It might take 60ms for a breaker to open if a fault occurs in the utility
grid which includes the islanding detection for the full transition. This statement is based on
the grading margin requirement.
By introducing additional 3 IEDs to the system. It still does not meet a full coordination
with all of the systems but is improved compared to the case with no additional IED. Since
the aim is to detect a fault and isolate it, the matrix protection shown in Table 7.8 and Table
7.9 show the possible tripping time by the sequence-of-operation study. The first level
detection is shown in green boxes, the second level protection is shown in orange boxes, the
unselective coordination is shown in yellow boxes, and the FRT is shown in red boxes. Based
on the grid-connected matrix, the recommended action is to replace fuse F-L1-3, F-L2-6, F-
L2-7, and F-L2-8 to lower rating fuses in order to achieve full selectivity. Based on the
islanded matrix, the best action to have full selectivity is adding more IEDs. In this thesis, it
is enough to introduce 3 IEDs to make an example how to detect and discriminate the fault.
A drawback that is seen from the result by using the symmetrical sequence protection is
the fast disconnection from the IEDs when a solid fault occurs at the customer side. However,
it can be made less sensitive by adding more time delay, but the FRT is the constraint here.
In another word, when the inverter does not have enough FRT capability after the adjustment
time delay in the IED, a collapsing Microgrid is the result. Once again, the IEDs are needed
in order to isolate the fault and make the healthy grid remains in operation.
40
Table 7.8 Islanded Mode -Protection Coordination Matrix
Faulty Bus (SLG Fault) F-T125 F-LV Relay 1 Function F-L1-2 F-L1-3 Relay 2 Function F-L2-2 F-L2-3 F-L2-4 Relay 3 Function F-L2-6 F-L2-7 F-L2-8
Battery
Protection -
UV
PVs
Protection -
UV
Selectivity Notes
100ms Forward EF 200ms Reverse EF •
100ms Forward Negative Sequence 200ms Reverse Negative Sequence
7630ms Phase OC
100ms Forward EF 200ms Reverse EF •
100ms Forward Negative Sequence 200ms Reverse Negative Sequence
6914ms Phase OC
100ms Forward EF 200ms Reverse EF ••
100ms Forward Negative Sequence 200ms Reverse Negative Sequence
5592ms Phase OC
100ms Forward EF 200ms Reverse EF ••
100ms Forward Negative Sequence 200ms Reverse Negative Sequence
2775ms Phase OC
200ms Reverse EF ••
200ms Reverse Negative Sequence
200ms Forward EF ••
200ms Forward Negative Sequence
14883ms Phase OC
200ms Forward EF ••
200ms Forward Negative Sequence
17771ms Phase OC
200ms Forward EF ••
200ms Forward Negative Sequence
>31818ms Phase OC
200ms Forward EF ••
200ms Forward Negative Sequence
>31818ms Phase OC
200ms Forward EF ••
200ms Forward Negative Sequence
>31818ms Phase OC
200ms Forward EF •
200ms Forward Negative Sequence
>31818ms Phase OC
200ms Forward EF •
200ms Forward Negative Sequence
>31818ms Phase OC
200ms Forward EF 100ms Forward EF ••
200ms Forward Negative Sequence 100ms Forward Negative Sequence
>31818ms Phase OC 2653ms Phase OC
200ms Forward EF 100ms Forward EF ••
200ms Forward Negative Sequence 100ms Forward Negative Sequence
3628ms Phase OC
200ms Forward Negative Sequence 100ms Forward EF ••
100ms Forward Negative Sequence
4896ms Phase OC
100ms Forward EF •
100ms Forward Negative Sequence
6152ms Phase OC
100ms Forward EF ••
100ms Forward Negative Sequence
5536ms Phase OC
100ms Forward EF •
100ms Forward Negative Sequence
5536ms Phase OC
100ms Forward EF •
100ms Forward Negative Sequence
5536ms Phase OC
F-L2-3 takes longer time than relay
2 to pick-up
F-L2-3 takes longer time than relay
2 to pick-up
F-L2-6 takes longer time than relay
3 to pick-up
F-L2-8 takes longer time than relay
3 to pick-up
F-L2-7 takes longer time than relay
3 to pick-up
B-T125-Y21
Since there is no fuses connected
to the bus B-T125-K6, then it is
considered selective
F-L1-2 takes longer time than relay
1 to pick-up
F-L1-3 takes longer time than relay
1 to pick-up
Since there is no fuses connected
to the bus B-T125-K6, then it is
considered selective
4345ms
3807ms
3810ms
B-T125-Y12
B-T125-J15
B-T125-A18
B-C4-00
B-R-1
B-R-2
B-C5-A19
2011ms
76205ms
1956ms
1956ms
B-T126-Y11
B-T125-K6
B-C3-94
B-C3-39
B-C3-87
B-C3-99
B-C1-80
B-C2-26
B-T125-X6
B-T125-Y11
B-T125-04
201ms 201ms
201ms 201ms
201ms 201ms
201ms 201ms
201ms 201ms
201ms 201ms
201ms 201ms
201ms 201ms
201ms 201ms
201ms 201ms
201ms 201ms
201ms 201ms
201ms 201ms
201ms 201ms
201ms 201ms
201ms 201ms
201ms 201ms
201ms 201ms
201ms 201ms
41
Table 7.9 Grid-Connected Mode - Protection Coordination Matrix
Faulty Bus (SLG Fault) F-T125 F-LV Relay 1 Function F-L1-2 F-L1-3 Relay 2 Function F-L2-2 F-L2-3 F-L2-4 Relay 3 Function F-L2-6 F-L2-7 F-L2-8
Battery
Protection -
UV
PVs
Protection -
UV
Selectivity Notes
100ms Forward EF ••
100ms Forward Negative Sequence
385ms Phase OC
100ms Forward EF 200ms •
100ms Forward Negative Sequence 200ms
322ms Phase OC
100ms Forward EF ••
100ms Forward Negative Sequence
203ms Phase OC
100ms Forward EF ••
100ms Forward Negative Sequence
10ms Phase OC
200ms Reverse EF ••
200ms Reverse Negative Sequence
200ms Forward EF ••
200ms Forward Negative Sequence
10ms Phase OC
200ms Forward EF ••
200ms Forward Negative Sequence
10ms Phase OC
200ms Forward EF ••
200ms Forward Negative Sequence
345ms Phase OC
200ms Forward EF ••
200ms Forward Negative Sequence
351ms Phase OC
200ms Forward EF ••
200ms Forward Negative Sequence
352ms Phase OC
200ms Forward EF ••
200ms Forward Negative Sequence
351ms Phase OC
200ms Forward EF ••
200ms Forward Negative Sequence
352ms Phase OC
200ms Forward EF 100ms Forward EF ••
200ms Forward Negative Sequence 100ms Forward Negative Sequence
926ms Phase OC 262ms Phase OC
200ms Forward EF 100ms Forward EF ••
200ms Forward Negative Sequence 100ms Forward Negative Sequence
1742ms Phase OC 480ms Phase OC
200ms Forward EF 100ms Forward EF ••
200ms Forward Negative Sequence 100ms Forward Negative Sequence
2888ms Phase OC 767ms Phase OC
200ms Forward EF 100ms Forward EF •
200ms Forward Negative Sequence 100ms Forward Negative Sequence
4057ms Phase OC 1039ms Phase OC
200ms Forward EF 100ms Forward EF ••
200ms Forward Negative Sequence 100ms Forward Negative Sequence
3481ms Phase OC 908ms Phase OC
200ms Forward EF 100ms Forward EF •
200ms Forward Negative Sequence 100ms Forward Negative Sequence
3481ms Phase OC 908ms Phase OC
200ms Forward EF 100ms Forward EF •
200ms Forward Negative Sequence 100ms Forward Negative Sequence
3481ms Phase OC 908ms Phase OC
6321531ms
6321531ms
13892ms
F-L1-3 takes longer time than relay 1
to pick-up, Suggestion: lower the
rating of fuse F-L1-3 to 35A
F-L2-6 takes longer time than relay 3
to pick-up, Suggestion: lower the
rating of fuse F-L2-6 to 25A
F-L2-7 takes longer time than relay 3
to pick-up, Suggestion: lower the
rating of fuse F-L2-7 to 25A
F-L2-8 takes longer time than relay 3
to pick-up, Suggestion: lower the
rating of fuse F-L2-8 to 25A
Since phase OC of relay 1 has similar
instant tripping time with fuse F-LV, it
still considered as selective
103ms <10ms
599ms <10ms
176ms79346ms
B-C5-A19 232ms 201ms
53154ms
36744ms
<10ms
14640ms
475ms
13404ms
B-R-1 201ms
B-R-2 232ms 201ms
6321531ms
B-T125-A18 201ms
B-C4-00 292ms 201ms
3419142ms
>9460681ms
B-T125-Y12 201ms
B-T125-J15 201ms
108026ms
878012ms
B-C3-87 <10ms 201ms
B-C3-99 <10ms 201ms
13875ms
B-C3-94 201ms
B-C3-39 201ms
13887ms
13905ms
B-T126-Y11 201ms 201ms
B-T125-K6 201ms
B-T125-04 201ms 201ms
B-T125-Y21 201ms 201ms
B-T125-X6
B-T125-Y11 201ms 201ms
B-C1-80 25.9ms
B-C2-26 213ms
42
7.4 Microgrid Expansion and the Protection Adaptability
7.4.1 High Penetration PVs in each of the Customer
Higher penetration of PVs in this thesis is defined as the presence of the PVs in each of the
customers. According to Figure 7.6, the presence of additional PVs can be seen in Network
1 and Network 3.
~=
~=
~=
F-T125-MV
B-T125-11
B-T125-04
F-T125
T1 – 11/0.42kV160kVA
F-LV
KA-L1-1
B-T125-Y11
B-T125-X6
F-L1-2 F-L1-3
B-C1-80 B-C2-26
L-C110.5kVA
L-C214.2kVA
Battery
KA-R-1
KA-L2-1
B-T125-Y21
B-T126-Y11
KA-L2-2
KA-L2-3
F-L2-2
PV-1818kVA
L-C3-112.9kVA
PV-2525kVA
L-C3-211.9kVA
F-L2-3
KA-L2-5
KA-L2-4
B-C3-94
B-C3-39
B-C3-87
F-L2-4 KA-L2-6 KA-L2-7
B-T125-Y12
B-T125-J15
B-T125-A18F-L2-6
KA-L2-8
B-C4-00
L-C414.9kVA
B-R-1
B-R-2F-L2-8
L-C614.2kVA
F-L2-7B-C5-A19
L-C516.3kVA
HK-L1-1
HK-L1-2 HK-L1-3
HK-L2-1
HK-L2-2
HK-L2-3
HK-L2-4
Network 1
Network 2
Relay 2
MCCB
CT
B-T125-K6
VT
Protected ZoneRelay 1
MCCB
CT
VT
Relay 3
MCCB
CT
VT
Network 3
B-C3-99
~=
F-AD-1
PV-4-14kVA
~=
F-AD-2
PV-4-24kVA
~=
F-AD-3
PV-4-34kVA
~=
F-AD-4
PV-4-44kVA
KA-R-2
~=
F-AD-5
PV-4-54kVA
KA-R-3
1st Layer - Protection
2nd Layer - Protection
Figure 7.6 Microgrid Expansion: Higher Penetration of PVs
In order to have a correct selectivity, the layer of the protection is defined in this section.
The 1st layer is defined as the bus on the low voltage side of the substation transformer (Bus
B-T125-04). The 2nd layer is defined as Bus B-T125-K6. The setting from chapter 7 is used
with some modification which is related to grading margin requirement.
The setting that is provided in Table 7.10 is chosen based on grading margin requirement.
Since the focus is on the symmetrical protection time delay with the respected protection
layer, it is best to consider this coordination. It does not matter how many additional
connection or relay in the Microgrid, as long as the IEDs follow Equation 3.15 then it should
provide correct selectivity.
43
Table 7.10 Microgrid Expansion: Symmetrical Sequence Protection
7.4.2 Adding Connection to the Main Bus (B-T125-04)
Another case is simulated which has an additional connection to the main bus B-T125-
04. The additional connection has the same model with Network 2 and Network 3 as shown
in Figure 7.7. By expanding the Microgrid, the directional zero and negative sequence
protection is adaptable. It means that the setting can be set the same before it is expanded as
long as it follows grading margin requirement. Not forget to mention that this scheme is
working for both grid-connected and islanded mode of a Microgrid.
~=
~=
~=
F-T125-MV
B-T125-11
B-T125-04
F-T125
T1 – 11/0.42kV160kVA
F-LV
KA-L1-1
B-T125-Y11
B-T125-X6
F-L1-2 F-L1-3
B-C1-80 B-C2-26
L-C110.5kVA
L-C214.2kVA
Battery
KA-R-1
KA-L2-1
B-T125-Y21
B-T126-Y11
KA-L2-2
KA-L2-3
F-L2-2
PV-1818kVA
L-C3-112.9kVA
PV-2525kVA
L-C3-211.9kVA
F-L2-3
KA-L2-5
KA-L2-4
B-C3-94
B-C3-39
B-C3-87
F-L2-4 KA-L2-6 KA-L2-7
B-T125-Y12
B-T125-J15
B-T125-A18F-L2-6
KA-L2-8
B-C4-00
L-C414.9kVA
B-R-1
B-R-2F-L2-8
L-C614.2kVA
F-L2-7B-C5-A19
L-C516.3kVA
HK-L1-1
HK-L1-2 HK-L1-3
HK-L2-1
HK-L2-2
HK-L2-3
HK-L2-4
Network 1
Network 2
Relay 2
MCCB
CT
B-T125-K6
VT
Protected ZoneRelay 1
MCCB
CT
VT
Relay 3
MCCB
CT
VT
Network 3
B-C3-99
~=
F-AD-1
PV-4-14kVA
~=
F-AD-2
PV-4-24kVA
~=
F-AD-3
PV-4-34kVA
~=
F-AD-4
PV-4-44kVA
KA-R-2
~=
F-AD-5
PV-4-54kVA
KA-R-3
1st Layer - Protection
2nd Layer - Protection
KA-L2-1-R
B-T125-Y21-R
B-T126-Y11-R
KA-L2-2-R
HK-L2-1-R
Relay 4
MCCB
CT
VT
~=
~=
KA-L2-3-R
F-L2-2-R
PV-18-R18kVA
L-C3-1-R12.9kVA
PV-25-R25kVA
L-C3-2-R11.9kVA
F-L2-3-R
KA-L2-5-R
KA-L2-4-R
B-C3-94-R
B-C3-39-R
B-C3-87-R
F-L2-4-RKA-L2-6-R KA-L2-7-R
B-T125-Y12-R
B-T125-J15-R
B-T125-A18-RF-L2-6-R
KA-L2-8-R
B-C4-00-R
L-C4-R14.9kVA
B-R-1-R
B-R-2-R
F-L2-8-R
L-C6-R14.2kVA
F-L2-7-RB-C5-A19-R
L-C5-R16.3kVA
HK-L2-2-R
HK-L2-3-R
HK-L2-4-RNetwork 4
B-T125-K6-R
Relay 5
MCCB
CT
VT
Network 5
B-C3-99-R
~=
F-AD-3-R
PV-4-3-R4kVA
~=
F-AD-4-R
PV-4-4-R4kVA
KA-R-2-R
~=
F-AD-5-R
PV-4-5-R4kVA
KA-R-3-R
Figure 7.7 Microgrid Expansion: Additional Connection within Microgrid
Instant Instant Instant Instant
10.6 31.8 4 12
0.14 0.14 0.16 0.16
Instant Instant Instant Instant
28.6 85.8 10.6 31.8
0.14 0.14 0.16 0.16
Instant Instant Instant Instant
18 56 5 18
0.1 0.1 0.2 0.2
Delay (Sec) Delay (Sec) Delay (Sec) Delay (Sec)
Symmetrical Sequence Protection
Forward Negative Sequence |I2| Forward Zero Sequence 3·|I0| Reverse Negative Sequence |I2| Reverse Zero Sequence 3·|I0|
Curve type Curve type Curve type Curve type
Pick-up (A) Pick-up (A) Pick-up (A) Pick-up (A)
Curve type Curve type Curve type Curve type
Pick-up (A) Pick-up (A) Pick-up (A) Pick-up (A)
Delay (Sec)
Curve type Curve type Curve type Curve type
IEDs
Relay 1 1
Relay 2
Relay 3
1
2
Protection
Layer
Pick-up (A) Pick-up (A) Pick-up (A) Pick-up (A)
Delay (Sec) Delay (Sec) Delay (Sec) Delay (Sec)
Delay (Sec) Delay (Sec) Delay (Sec)
44
The recommended tripping time is presented in Table 7.11 to follow the grading margin
requirement. Based on the final grading margin, the FRT can be adjusted to, i.e. 300ms if the
sequence protection scheme is to be applied as one of the main solutions within the
Microgrid.
Table 7.11 Final Grading Margin
7.4.3 Discussion
It is common that the new customer is registered on a continuous basis; also the customer
might also have their own PV means more production in the Microgrid. From the protection
point of view, the increasing PV means the minimum short circuit is increased. It also means
that the more customer registered in a Microgrid, the more the possible unbalanced power
flow in the grid.
If the directional zero and negative sequence current protection are to be applied, as long
as the protection coordination fulfil the grading margin requirement, the fixed setting can be
used means that the setting does not have to be modified once the grid is expanded.
To summarise the discussion, a complete Microgrid strategy consists of protection
characteristic in the fuses, IEDs, and FRT in each of the PVs/battery inverter. By having the
grid expanded, the setting provided in the expansion study implies that the qualities of
protection are similar to the coordination matrix before the grid is expanded which means the
directional zero and negative sequence current protection is adaptable.
Instant Instant Instant Instant
10.6 31.8 4 12
0.12 0.12 0.18 0.18
Instant Instant Instant Instant
28.6 85.8 25 75
0.12 0.12 0.18 0.18
Instant Instant Instant Instant
18 56 5 18
0.06 0.06 0.24 0.24
Instant Instant Instant Instant
28.6 85.8 25 75
0.12 0.12 0.18 0.18
Instant Instant Instant Instant
18 56 5 18
0.06 0.06 0.24 0.24
Relay 5 2
Curve type Curve type Curve type Curve type
Pick-up (A) Pick-up (A) Pick-up (A) Pick-up (A)
Delay (Sec) Delay (Sec) Delay (Sec) Delay (Sec)
Relay 4 1
Curve type Curve type Curve type Curve type
Pick-up (A) Pick-up (A) Pick-up (A) Pick-up (A)
Delay (Sec) Delay (Sec) Delay (Sec) Delay (Sec)
Relay 3 2
Curve type Curve type Curve type Curve type
Pick-up (A) Pick-up (A) Pick-up (A) Pick-up (A)
Delay (Sec) Delay (Sec) Delay (Sec) Delay (Sec)
Relay 2 1
Curve type Curve type Curve type Curve type
Pick-up (A) Pick-up (A) Pick-up (A) Pick-up (A)
Delay (Sec) Delay (Sec) Delay (Sec) Delay (Sec)
Relay 1 1
Curve type Curve type Curve type Curve type
Pick-up (A) Pick-up (A) Pick-up (A) Pick-up (A)
Delay (Sec) Delay (Sec) Delay (Sec) Delay (Sec)
IEDsProtection
Layer
Symmetrical Sequence Protection
Forward Negative Sequence |I2| Forward Zero Sequence 3·|I0| Reverse Negative Sequence |I2| Reverse Zero Sequence 3·|I0|
45
8 Chapter 8: Conclusions
8.1 General Conclusions
Based on the objectives that have been pointed out in this master thesis, the general
conclusions of this project is outlined as follows:
1. Investigation of the existing protection by short circuit and sequence-of-operation study
1.1. The existing protection (fuses) does not integrate with the PVs. The challenging
issue mainly focuses on fault isolation; means that the Microgrid needs IED to
isolate the fault and make the remaining healthy grid in operation
1.2. The Microgrid protection relies on the PVs inverter protection if the disconnection
of the PVs are required after a fault occurs which leads to the shutdown of the
Microgrid
1.3. Safety issue should be considered as one of the priorities and cannot be neglected
completely. This means the discussion with the inverter manufacturer and PV
owner should be conducted
1.4. For islanded mode, any fault occurs within the Microgrid makes the whole grid
collapse
1.5. In order to have more reliability, a protection strategy needs to be applied
2. Analysis of the proposed scheme: directional zero and negative sequence current
protection
2.1. The unbalanced load flow (ULF) study can be used to distinguish the normal
operation (under unbalanced load) and fault condition
2.2. There is a limited coverage protected zone provided by an IED with directional
zero and negative sequence current protection. It is necessary to add more IEDs
to have an optimum coverage protection zone within the Microgrid.
3. Microgrid Expansion
3.1. As long as the IEDs follow the grading margin requirement that has generally
been formulated in this thesis, the Microgrid expansion (i.e. by having more
residential PV in the grid and adding more connection) does not disrupt the
proposed protection coordination
4. Fault Ride-Through regulation
4.1. The FRT can be re-adjusted depending on the component presented in the grading
margin requirement. The FRT is expected to have the longest coordinated tripping
time within the Microgrid compared to the IEDs tripping time
8.2 Future Research and Recommendation
These are the potential research and recommendation that can be investigated in the future:
1. When the Microgrid is expanded, the instantaneous time delay coordination is not a
problem since it has generally been formulated. However, the pick-up value is
something that can be studied in depth in the future
2. The proposed protection is in a current basis; to rely on current protection alone is not
completely suggested. Coordinating current-based protection with voltage or
impedance could be an option
46
3. The problem in the low voltage grid is that the protective device or breaker is different
from medium voltage. The proposed protection is referred to the MV protection;
however, it is also possible to send the tripping signal to the LV MCCB. It can be a
good option if MCCB manufacturer can incorporate the sequence protection in the
MCCB (aside from phase OC)
4. The inverter is an important component in a Microgrid; modelling the inverter is still
a challenging issue to the short circuit study. It is best to compare with the
manufacturer since different manufacturer give different model
5. Research for the protection coordination topics related to the FRT should be taken
into consideration in the future
47
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- 2 -
A.1 Appendix I
A.1-1 Customer Load Data
The customer load that is used in the simulation are presented in Table A.1.
Table A.1 Customer Load Data
A.1-2 Inverter Data
The inverter data in each of the PVs and battery inverter are presented in Table A.2.
Table A.2 Inverter Data
A.1-3 Transformer Data
The transformer rating and impedance are presented in Table A.3.
Table A.3 Transformer Data
A.1-4 Utility Grid
The utility short circuit rating is presented in Table A.4.
Table A.4 Utility Grid Data
Customer/Load Busbar Apparent Power (kVA) Cosphi
L-C1 B-C1-80 10.51 0.97
L-C2 B-C2-26 14.2 0.97
L-C3-1 B-C3-39 12.85 0.97
L-C3-2 B-C3-99 11.9 0.97
L-C4 B-C4-00 14.9 0.97
L-C5 B-C5-A19 16.2 0.97
L-C6 B-R-1 14.18 0.97
PV Busbar Active Power (kW) Mode Short Circuit Contribution AC Grounding
PV-18 B-C3-94 17 PQ, Q=0 1.2xrated current Solidly Grounded
PV-25 B-C3-87 24 PQ, Q=0 1.2xrated current Solidly Grounded
Grid-connected: PQ, Q=0
Islanded: Swing/SlackBattery B-T125-04 57 Solidly Grounded
1.2xInverter capacity,
Inverter Capacity=90kVA
Power Rating (kVA) Primary Side (kV) Primary Grounding Secondary Side (kV) Secondary Grounding Vector
160 11 Delta 0.42 Y solidly earthed Dyn11, angle=-30
Impedance %Z X/R R/X %X %R
Positive 4 1.5 0.667 3.328 2.219
Zero 4 1.5 0.667 3.328 2.219
Short Circuit Rating MVAsc X/R kAsc
3-Phase 24.902 1 1.307
1-Phase 14.941 1 0.784
- 3 -
A.1-5 Cable Data
The underground and hanging cable data are presented in Table A.5.
Table A.5 Cable Impedance Data
A.1-6 Fuse Data
Fuse data is taken from ABB residential type fuse. The rating is presented in Table A.6.
Table A.6 Fuse Data
Cable IDFrom
BusbarTo Busbar
Resistance
(Ω)
Reactance
(Ω)
Capacitance to
Ground (ɥF)
KA-L1-1 B-T125-04 B-T125-Y11 0.0109 0.0013 0.0036
KA-L2-1 B-T125-04 B-T125-Y21 0.0128 0.0016 0.0042
KA-L2-2 B-T126-Y11 B-T125-K6 0.1449 0.0106 0.0466
KA-L2-3 B-T125-K6 B-C3-94 0.00183 0.00008 0
KA-L2-4 B-C3-94 B-C3-39 0.000054 0.000067 0.0006
KA-L2-5 B-T125-K6 B-C3-87 0.00183 0.00008 0
KA-L2-6 B-C3-87 B-C3-99 0.000054 0.000067 0.0006
KA-L2-7 B-T125-K6 B-T125-Y12 0.11895 0.005915 0.0208
KA-L2-8 B-T125-A18 B-C4-00 0.0756 0.0092 0.0248
HK-L1-1 B-T125-Y11 B-T125-X6 0.185249 0.021675 0
HK-L1-2 B-T125-X6 B-C1-80 0.0792 0.005412 0
HK-L1-3 B-T125-X6 B-C2-26 0.054485 0.006375 0
HK-L2-1 B-T125-Y21 B-T126-Y11 0.041665 0.004875 0
HK-L2-2 B-T125-Y12 B-T125-J15 0.104483 0.012225 0
HK-L2-3 B-T125-J15 B-T125-A18 0.101278 0.01185 0
HK-L2-4 B-T125-A18 B-R-1 0.041024 0.0048 0
Fuse ID From Busbar To Busbar Model Rating (A)
F-T125 B-T125-11 ABB CEF 16
F-LV B-T125-04 ABB NH1 160
F-L1-1 B-T125-04 B-T125-Y11 ABB NH0 80
F-L1-2 B-T125-X6 B-C1-80 ABB NH0 35
F-L1-3 B-T125-X6 B-C2-26 ABB NH0 63
F-L2-1 B-T125-04 B-T125-Y21 ABB NH0 63
F-L2-2 B-C3-94 ABB NH0 25
F-L2-3 B-T125-K6 B-C3-87 ABB NH0 35
F-L2-4 B-C3-87 ABB NH0 35
F-L2-5 B-T125-K6 B-T125-Y12 ABB NH0 55
F-L2-6 B-T125-A18 B-C4-00 ABB NH0 35
F-L2-7 B-R-1 B-C5-A19 ABB NH0 35
F-L2-8 B-R-1 ABB NH0 35
- 4 -
A.2 Appendix II
A.2-1 List of the Problem – Grid-connected Mode
The result of short circuit and sequence-of-operation study in grid-connected mode of the
existing grid is presented in Table A.7.
Table A.7 List of Problem - Grid-connected Mode
Number Fault at Bus Type of Fault Problem Notes
1 B-T125-04 all type of fault Battery Protection was not set
2 B-T125-04 all type of fault F-L2-2 did not blow/melt
3 B-T125-04 all type of fault PV18 protection was not set
4 B-T125-04 all type of fault F-L2-4 did not blow/melt
5 B-T125-04 all type of fault PV25 protection was not set
6 B-T125-04 all type of fault F-L2-3 did not blow/melt upstream fuse of F-L2-4
7 B-T125-04 all type of fault F-L2-1 did not blow/melt
9 B-T125-Y21 all type of fault F-L2-2 did not blow/melt
10 B-T125-Y21 all type of fault PV18 protection was not set
11 B-T125-Y21 all type of fault F-L2-4 did not blow/melt
12 B-T125-Y21 all type of fault PV25 protection was not set
13 B-T125-Y21 all type of fault F-L2-3 did not blow/melt upstream fuse of F-L2-4
15 B-T126-Y11 all type of fault F-L2-2 did not blow/melt
16 B-T126-Y11 all type of fault PV18 protection was not set
17 B-T126-Y11 all type of fault F-L2-4 did not blow/melt
18 B-T126-Y11 all type of fault PV25 protection was not set
19 B-T126-Y11 all type of fault F-L2-3 did not blow/melt upstream fuse of F-L2-4
21 B-T125-K6 all type of fault F-L2-2 did not blow/melt
22 B-T125-K6 all type of fault PV18 protection was not set
23 B-T125-K6 all type of fault F-L2-4 did not blow/melt
24 B-T125-K6 all type of fault PV25 protection was not set
25 B-T125-K6 all type of fault F-L2-3 did not blow/melt upstream fuse of F-L2-4
27 B-C3-94 all type of fault F-L2-2 did not blow/melt
28 B-C3-94 all type of fault PV18 protection was not set
29 B-C3-94 all type of fault F-L2-4 did not blow/melt
30 B-C3-94 all type of fault PV25 protection was not set
31 B-C3-94 all type of fault F-L2-3 did not blow/melt upstream fuse of F-L2-4
33 B-C3-39 all type of fault F-L2-2 did not blow/melt
34 B-C3-39 all type of fault PV18 protection was not set
35 B-C3-39 all type of fault F-L2-4 did not blow/melt
36 B-C3-39 all type of fault PV25 protection was not set
37 B-C3-39 all type of fault F-L2-3 did not blow/melt upstream fuse of F-L2-4
41 B-C3-87 all type of fault F-L2-4 did not blow/melt
42 B-C3-87 all type of fault PV25 protection was not set
46 B-C3-99 all type of fault F-L2-4 did not blow/melt
47 B-C3-99 all type of fault PV25 protection was not set
- 5 -
A.2-2 List of the Problem – Islanded Mode
The result of short circuit and sequence-of-operation study in islanded mode of the existing
grid is presented in Table A.8.
Table A.8 List of Problem - Islanded Mode
Number Fault at Bus Type of Fault Problem Notes
1 B-T125-04 all type of fault Battery Protection was not set
2 B-T125-04 all type of fault F-L2-2 did not blow/melt
3 B-T125-04 all type of fault PV18 protection was not set
4 B-T125-04 all type of fault F-L2-4 did not blow/melt
5 B-T125-04 all type of fault PV25 protection was not set
6 B-T125-04 all type of fault F-L2-3 did not blow/melt upstream fuse of F-L2-4
7 B-T125-04 all type of fault F-L2-1 did not blow/melt
9 B-T125-Y21 all type of fault F-L2-2 did not blow/melt
10 B-T125-Y21 all type of fault PV18 protection was not set
11 B-T125-Y21 all type of fault F-L2-4 did not blow/melt
12 B-T125-Y21 all type of fault PV25 protection was not set
13 B-T125-Y21 all type of fault F-L2-3 did not blow/melt upstream fuse of F-L2-4
15 B-T126-Y11 all type of fault F-L2-2 did not blow/melt
16 B-T126-Y11 all type of fault PV18 protection was not set
17 B-T126-Y11 all type of fault F-L2-4 did not blow/melt
18 B-T126-Y11 all type of fault PV25 protection was not set
19 B-T126-Y11 all type of fault F-L2-3 did not blow/melt upstream fuse of F-L2-4
21 B-T125-K6 all type of fault F-L2-2 did not blow/melt
22 B-T125-K6 all type of fault PV18 protection was not set
23 B-T125-K6 all type of fault F-L2-4 did not blow/melt
24 B-T125-K6 all type of fault PV25 protection was not set
25 B-T125-K6 all type of fault F-L2-3 did not blow/melt upstream fuse of F-L2-4
27 B-C3-94 all type of fault F-L2-2 did not blow/melt
28 B-C3-94 all type of fault PV18 protection was not set
29 B-C3-94 all type of fault F-L2-4 did not blow/melt
30 B-C3-94 all type of fault PV25 protection was not set
31 B-C3-94 all type of fault F-L2-3 did not blow/melt upstream fuse of F-L2-4
33 B-C3-39 all type of fault F-L2-2 did not blow/melt
34 B-C3-39 all type of fault PV18 protection was not set
35 B-C3-39 all type of fault F-L2-4 did not blow/melt
36 B-C3-39 all type of fault PV25 protection was not set
37 B-C3-39 all type of fault F-L2-3 did not blow/melt upstream fuse of F-L2-4
41 B-C3-87 all type of fault F-L2-4 did not blow/melt
42 B-C3-87 all type of fault PV25 protection was not set
46 B-C3-99 all type of fault F-L2-4 did not blow/melt
47 B-C3-99 all type of fault PV25 protection was not set
TRITA TRITA-EE 2017:164
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