UNIVERSITY OF CALGARY
Effect of STATCOM Location on Distance Protection Relay Operation
by
Peng (Philip) Sun
A THESIS
SUBMITTED TO THE FACULTY OF GRADUATE STUDIES
IN PARTIAL FULFILMENT OF THE REQUIREMENTS FOR THE
DEGREE OF MASTER OF SCIENCE
GRADUATE PROGRAM IN ELECTRICAL ENGINEERING
CALGARY, ALBERTA
JUNE, 2015
© Peng (Philip) Sun 2015
Abstract
Flexible AC Transmission System (FACTS) devices are playing an increasingly important role
in electrical power systems to satisfy the function of achieving better power transferability and
enhancing power system controllability. The presence of FACTS devices in power systems has
brought up some challenges to the protection schemes in the grid. Distance protection, as a major
transmission line protective scheme, is facing such a challenge to meet the basic requirements for
its accuracy, selectivity, reliability and security. This dissertation reviews FACTS concepts, and
studies the shunt connected STATCOM and its modeling. Based on the dynamic behaviour of a
shunt connected STATCOM in a two-machine system, where a distance protection scheme is
applied to protect the transmission line connecting the two machines, performance of the two
zone distance protection scheme has been evaluated in EMTDC/PSCAD simulation environment
for various contingent conditions. This includes different STATCOM installation locations,
various STATCOM voltage settings, various fault locations & types. To overcome the misoperation of the distance relay and make the distance scheme operational and reliable when the
transmission line is shunt compensated with STATCOM, studies on some communication-aided
protection schemes, including PUTT, POTT and DCB, are conducted. These pilot protection
schemes have proven to be effective for fast clearance of the faults on the transmission line and
meet the requirements for protections, regardless of STATCOM installation locations.
ii
Acknowledgements
The dissertation is with great support and patience from my family in the past 4 years during
which we suffered the deep sorrow of losing an important family member and overcame the
unpredictable challenges of life together. The spiritual motivation from family is the power
encouraging me to move towards the completion of this project.
I wish to solemnly express my sincere gratitude and deep appreciation to my supervisors Dr. Ed
P. Nowicki and Dr. O. P. Malik at this time for their constant guidance, encouragement and
support throughout the whole program. A new window is open for me in Electrical Engineering
with their direction, from which I greatly broadened my horizon in the application of power
electronics and hence my professional career has benefited tremendously from the exciting
learning procedure. My foremost thanks go to them and I also wish to extend my appreciation to
other professors and support staff in the Department of Electrical and Computer Engineering in
University of Calgary for their help during my study here.
I also wish to thank some of my friends for their continuous support and constructive suggestions
that inspired and motivated me to complete the part time study, without whom I would be unable
to finish my project successfully.
iii
Table of Contents
Abstract ............................................................................................................................... ii
Acknowledgements ............................................................................................................ iii
Table of Contents ............................................................................................................... iv
List of Tables ..................................................................................................................... vi
List of Figures and Illustrations ........................................................................................ vii
List of Symbols, Abbreviations and Nomenclature .............................................................x
CHAPTER ONE: INTRODUCTION ..................................................................................1
1.1 Protection of transmission lines .................................................................................2
1.1.1 Non-Pilot Schemes ............................................................................................3
Distance relay ......................................................................................................3
Step Distance Schemes.........................................................................................5
1.1.2 Pilot Schemes ....................................................................................................6
1.2 Introduction to FACTS ..............................................................................................6
1.3 Type of converters ...................................................................................................11
1.4 Summary ..................................................................................................................13
1.5 Thesis Outline ..........................................................................................................13
CHAPTER TWO: STATCOM PRINCIPLE AND LITERATURE REVIEW .................16
2.1 Introduction to FACTS ............................................................................................16
2.2 STATCOM ..............................................................................................................17
2.2.1 Introduction to STATCOM .............................................................................17
2.2.2 Basic Principle of a STATCOM......................................................................19
2.2.3 STATCOM Control .........................................................................................23
Introduction to STATCOM Topologies ..............................................................23
Basic Control Approaches of a STATCOM .......................................................25
Indirect Control .................................................................................................26
Direct Control ....................................................................................................28
2.2.4 Steady State and Transient Characteristics of a STATCOM ..........................29
V-I characteristic ...............................................................................................29
Transient Stability ..............................................................................................31
2.2.5 Harmonic profile of STATCOM .....................................................................33
2.2.6 Detailed Mathematical Model of STATCOM .................................................36
Static Module of STATCOM ..............................................................................37
Dynamic Module of STATCOM .........................................................................38
2.2.7 STATCOM applications ..................................................................................41
CHAPTER THREE: MODELING OF DISTANCE PROTECTION IMPEDANCE .......46
3.1 STATCOM installed at mid-point of the transmission line.....................................46
3.1.1 Single phase fault after the STATCOM ..........................................................48
3.1.2 Single phase fault before the STATCOM .......................................................51
3.2 Phase to phase fault..................................................................................................54
3.2.1 Phase to phase fault after the STATCOM .......................................................54
3.2.2 Phase to phase fault before the STATCOM ....................................................56
iv
CHAPTER FOUR: SIMULATION ...................................................................................59
4.1 System Simulation ...................................................................................................59
4.1.1 Transmission System Module .........................................................................59
System configuration..........................................................................................59
Transmission line ...............................................................................................60
Generator and load ............................................................................................61
4.1.2 STATCOM modelling and its Control Circuit ................................................63
STATCOM model ...............................................................................................63
Voltage Control Loop ........................................................................................65
PWM Control Module ........................................................................................65
4.1.3 Distance Protection Module ............................................................................68
Voltage & Current Signal Processing ...............................................................70
Distance Mho Characteristic .............................................................................71
Distance Relay Output .......................................................................................73
4.2 Fault Simulations .....................................................................................................74
4.2.1 Midpoint connected STATCOM simulation ...................................................75
Fault resistance is 0 Ω .......................................................................................76
Fault resistance is 50 Ω .....................................................................................78
4.2.2 Near-end bus connected STATCOM simulation ............................................82
4.2.3 Far-end bus connected STATCOM simulation ...............................................84
4.2.4 Effect of Voltage Setting of STATCOM.........................................................87
4.3 Concluding Remarks................................................................................................90
CHAPTER FIVE: COMMUNICATION-AIDED DISTANCE PROTECTION SCHEMES
...................................................................................................................................91
5.1 Directional Comparison Scheme ...........................................................................91
5.1.1 Permissive Transfer Trip .................................................................................92
5.1.2 Directional Comparison Blocking (DCB) .....................................................102
5.2 Line Current Differential .....................................................................................108
5.3 Concluding Remarks ............................................................................................109
CHAPTER SIX: CONCLUSIONS ..................................................................................110
6.1 Thesis Summary ....................................................................................................110
6.2 Discussion ..............................................................................................................111
6.3 Future work ............................................................................................................112
REFERENCES ................................................................................................................114
v
List of Tables
Table 1.1 Control Attributes of Various Controllers .................................................................... 10
vi
List of Figures and Illustrations
Figure 1.1 Mho Characteristic ........................................................................................................ 4
Figure 1.2 Normal Selectivity Adjustment of Step Distance Scheme ............................................ 5
Figure 1.3 Valve for a voltage-sourced converter ........................................................................ 12
Figure 1.4 Voltage-Sourced Converter ......................................................................................... 12
Figure 2.1 VSC-based STATCOM interface diagram in a power system .................................... 19
Figure 2.2 STATCOM and associated phasor diagrams (capacitive) for Rg=0 and Rg≠0 ........... 20
Figure 2.3 Topology of a three-phase, two-level, six-pulse voltage-sourced converter ............... 23
Figure 2.4 Topology of a three-phase, three-level, twelve-pulse voltage-sourced converter ....... 24
Figure 2.5 Block Diagram of the basic control structure of a STATCOM................................... 25
Figure 2.6 Indirect control diagram of a STATCOM ................................................................... 27
Figure 2.7 Direct control diagram of a STATCOM ..................................................................... 28
Figure 2.8 V-I characteristic of a STATCOM .............................................................................. 30
Figure 2.9 Two-machine, two-line power system with a STATCOM ......................................... 31
Figure 2.10 Illustration of equal area criterion for transient Stability .......................................... 33
Figure 2.11Typical Harmonics in 6-pulse STATCOM voltage output ........................................ 35
Figure 2.12 STATCOM Equivalent Circuit.................................................................................. 36
Figure 3.1 Transmission Line with a STATCOM at mid-point.................................................... 47
Figure 3.2 Circuit with a fault after the STATCOM .................................................................... 48
Figure 3.3 Sequence Circuit with a single phase to ground fault after mid-point STATCOM .... 49
Figure 3.4 Single phase fault before mid-point STATCOM ....................................................... 51
Figure 3.5 Sequence Circuit with a single phase to ground fault before mid-point STATCOM . 53
Figure 3.6 Sequence circuit with a phase to phase fault after mid-point STATCOM .................. 54
Figure 3.7 Sequence circuit with a phase to phase fault before mid-point STATCOM ............... 56
Figure 4.1 Single line Diagram of Simulated Power System ....................................................... 59
vii
Figure 4.2 Transmission Line Module .......................................................................................... 61
Figure 4.3 VSC-based STATCOM module .................................................................................. 63
Figure 4.4 Voltage Control Loop of STATCOM Control Module ............................................... 65
Figure 4.5 PMW Control Module part 1 ....................................................................................... 66
Figure 4.6 PMW Control Module part 2....................................................................................... 67
Figure 4.7 Distance Relay Module ............................................................................................... 69
Figure 4.8 Voltage Signal Processing ........................................................................................... 70
Figure 4.9 Line-to-Ground Impedance and Mho Component ...................................................... 71
Figure 4.10 Line-to-Line Impedance and Mho Component ......................................................... 72
Figure 4.11 Distance Relay Output ............................................................................................... 73
Figure 4.12 Measured Impedance for Single phase ground (A-G) fault ...................................... 76
Figure 4.13 Measured Impedance for Phase-Phase-ground (BC-G) fault .................................... 77
Figure 4.14 Measured Impedance for Three Phase (A-B-C) fault................................................ 77
Figure 4.15 Measured Impedance for Single Phase Ground (A-G) fault ..................................... 78
Figure 4.16 Measured Impedance for Phase-Phase-ground (BC-G) fault .................................... 79
Figure 4.17 Measured Impedance for Three Phase (A-B-C) fault................................................ 80
Figure 4.18 Reactive Power from STATCOM for Single Phase Ground (A-G) fault ................. 81
Figure 4.19 Reactive Power from STATCOM for Phase-Phase-Ground (BC-G) fault ............... 81
Figure 4.20 Reactive Power from STATCOM for Three Phase (A-B-C) fault ............................ 81
Figure 4.21 Measured Impedance for Single phase ground (A-G) fault ...................................... 82
Figure 4.22 Measured Impedance for Phase-Phase-ground (BC-G) fault .................................... 83
Figure 4.23 Measured Impedance for Three Phase (A-B-C) fault................................................ 83
Figure 4.24 Measured Impedance for Single phase ground (A-G) fault ...................................... 84
Figure 4.25 Measured Impedance for Phase-Phase-ground (BC-G) fault .................................... 85
Figure 4.26 Measured Impedance for Three Phase (A-B-C) fault................................................ 86
viii
Figure 4.27 Measured Impedance for A-G fault Vref = 1.0 p.u, 0.9 p.u and 1.1 p.u ................... 87
Figure 4.28 Measured Impedance for BC-G fault Vref = 1.0 p.u, 0.9 p.u and 1.1 p.u ................. 87
Figure 4.29 Phase to Phase Seen impedance for ABC-G fault Vref = 1.0 p.u, 0.9 p.u and 1.1
p.u.......................................................................................................................................... 88
Figure 4.30 Measured Impedance for ABC fault Vref = 1.0 p.u, 0.9 p.u and 1.1 p.u .................. 88
Figure 4.31 Reactive Power Vref = 1.1 p.u .................................................................................. 89
Figure 4.32 Reactive Power Vref = 0.9 p.u ................................................................................. 89
Figure 5.1 Permissive Overreach Protection Scheme and Logic diagram.................................... 93
Figure 5.2 Impedance measured at the sending end for an A-G fault without STATCOM ......... 94
Figure 5.3 Measured impedance at the sending end for an A-G fault with STATCOM .............. 95
Figure 5.4 Impedance measured by the receiving end relay for an A-G fault with STATCOM.. 95
Figure 5.5 Timing for POTT scheme ............................................................................................ 96
Figure 5.6 Permissive Under-reach Protection Scheme and Logic diagram ................................ 98
Figure 5.7 Measured impedance at the sending end for an ABC-G fault without STATCOM ... 99
Figure 5.8 Measured impedance at the sending end for an ABC-G fault with STATCOM....... 100
Figure 5.9 Impedance measured by the receiving end relay for an ABC-G fault with
STATCOM ......................................................................................................................... 100
Figure 5.10 Timing for PUTT scheme ........................................................................................ 101
Figure 5.11 Directional Comparison Blocking Protection Scheme and Logic diagram............. 103
Figure 5.12 Measured impedance for an ABC-G fault with STATCOM................................... 105
Figure 5.13 Trip timing for DCB scheme ................................................................................... 106
Figure 5.14 Block timing for DCB scheme ................................................................................ 107
Figure 5.15 Line Differential Current Protection Scheme and Logic diagram........................... 108
ix
List of Symbols, Abbreviations and Nomenclature
Symbol
Definition
FACTS
STATCOM
SC
TCPST
UPFC
P
Flexible AC Transmission System
Static Synchronous Compensator
Series Capacitor
Thyristor Controlled Phase Shifting Transformer
Unified Power Flow Controller
Real Power transferred
Reactive Power transferred
Sending end voltage
Receiving end voltage
Power system angle
Transmission line reactance
STATCOM voltage output
AC System voltage
Current between AC system and STATCOM
Leakage impedance of coupling transformer
STATCOM voltage output in control simulation
Capacitor voltage output in control simulation
Phase angle between STATCOM and system
Sending generator terminal voltage
Receiving generator terminal voltage
Bus voltage at sending end
Bus voltage at receiving end
Impedance from generator to STATCOM
Impedance of transmission line
System angle of power system
Per unit distance from fault location to relay
location
Fundamental frequency of STATCOM output
Park’ transformation operator
Positive, negative and zero sequence impedance
Positive, negative and zero sequence voltage
Positive, negative and zero sequence current
Ground fault current
Teleprotection
Permissive Underreaching Transfer Trip
Permissive Overreaching Transfer Trip
Source to Line impedance Ratio
Current- Sourced Converter
Voltage-Sourced Converter
Gate Turn-Off Thyristor
θ
δ
ω
TPR
PUTT
POTT
SIR
CSC
VSC
GTO
x
IGBT
DCB
PLL
PLC
PSCAD
SCADA
Insulated-Gate Bipolar Transistor
Directional Comparison Blocking
Gating firing pulse 1- 6
Overhead ground wire 1,2
Transmission line phase conductor
Pulse Width Modulation
Phase Lock Loop
Fast Fourier Transform
Power Line Carrier
Power System CAD
Supervisory Control And Data Acquisition
xi
Chapter One: Introduction
Transmission lines, as a major component of an electrical power system, play the most important
role in the transmission of power from generation to load and to interconnect regional power
systems into a grid network.
Hence, protection of transmission lines is critical in system
contingencies to isolate faults and to ensure the safety and integrity of a power grid.
A large variety of protection schemes are applied on transmission lines based on different
protection theories and communication technologies, among which the most commonly used is
the distance scheme. Despite the economic reasons, distance protection is widely employed
because the basic requirements for a protection scheme, which are selectivity, reliability and
sensitivity with satisfactory fault clearing time, can be easily met with proper scheme setup and
coordination study. By measuring the ratio of voltage to current at relay location, distance
protection can detect different types of faults and initiate related tripping schemes to isolate the
fault from the system with a desired time delay [1]. Distance protection is a reliable and selective
form of protection for transmission lines especially where line terminals are relatively far apart.
With the development and application of power electronics technology and maturity of
manufacturing, more and more power semi-conductor based devices, called FACTS [2], with
ratings from tens to hundreds of giga watts, have been utilized in the power systems to satisfy the
function of achieving better power transferability and enhancing power system controllability.
FACTS actually is the application of power electronic equipment, with one or multiple functions,
to regulate and control the electrical parameters that govern the operation of transmission
systems including voltage, current, impedance, phase angle and damping of oscillations [2].
1
FACTS controllers can cause rapid changes of the important system parameters mentioned
above. Their presence, therefore, can significantly affect the operation of traditional distance
schemes when either series or shunt connected FACTS devices introduce new dynamic controls
into the power systems. They would inevitably affect the characteristics of a protective relay in a
transmission line to some extent. This work presents STATCOM, a shunt connected FACTS
device, and its modeling technology. Based on the dynamic behaviour of a STATCOM in a twomachine transmission system, performance of a distance relay protecting the transmission line in
the system during various contingency conditions has been evaluated in EMTDC/PSCAD
(commercial software) simulation environment. Further studies on the impedance seen by a
distance relay are given. Improved performance of different distance schemes with
communication aid in the same system is also shown in the analysis and system simulation.
Recommendations and conclusions on the distance relay performance are made according to the
simulation results and some future work is also discussed.
1.1 Protection of transmission lines
A brief description of major schemes that are commonly used for the protection of transmission
lines is presented here. As a widely accepted standard for a protective scheme, the following four
basic requirements have to be met in order to make the scheme fully functional [3]. All schemes
introduced work on the following criteria even though in some cases the standard cannot be
reached completely at the same time due to some limits in applications:

Reliability (Dependability, Security)

Selectivity/Coordination
2

Sensitivity

Fault clearing time
Based on the availability of communication channels between substations, relay schemes on
transmission lines can be listed into two categories: Non-pilot and pilot schemes.
1.1.1 Non-Pilot Schemes
A variety of protection schemes belong to this category to protect transmission lines [4], such as
over-current relay, directional over-current relay and distance relay. The following is a brief
introduction to distance relay and the protection schemes based on it.
Distance relay
Distance relay, also called impedance relay [5], operates on the principle that measures the ratio
of voltage to current phasors at a relay location to determine if a fault is within the relay’s
protection boundary. Numerous characteristics in distance relay family are built up according to
the positive and zero sequence impedance of the protected transmission line. According to
different shapes of the protective operating boundaries [3], the major characteristics of distance
relay can be recognized as Impedance, Mho, Reactance, Quadrilateral and Lenticular. More
complex shapes can be obtained by using one or more of the above relay types in a logical
combination to provide a composite tripping zone boundary [4]. Based on transmission line
impedance, setting coordination with adjacent lines and other regulations, distance protection
with specific characteristic can be selected to apply on the protected transmission line.
3
Figure 1.1 Mho Characteristic
It is common to use an R–X diagram to both analyze and visualize the response of a distance
relay. Impedance characteristic is plotted as a circle with its center at the origin of the
coordinates and radius equal to its setting in ohms [6]. Relay operation occurs for all impedance
values less than the setting, that is, for all the points within the circle.
In this work, the Mho characteristic is chosen to build up the simulation models and is used to
conduct analysis for a distance relay’s behavior under various system conditions with a
STATCOM installed on the transmission line. As shown in Figure 1.1, the characteristic of a
Mho impedance relay, when plotted on R-X diagram, is a circle whose circumference passes
through the origin. It will operate only on faults in forward direction (quadrant one) along the
transmission line. The Mho Characteristic of a distance relay is inherently directional to protect
the faults in one direction on the protected line [7]. The relay operates when the measured
impedance falls within the circle.
4
Step Distance Schemes
As a non-pilot application, distance relaying is called step distance protection when several zones
are employed to protect a transmission line [3]. A conventional step distance scheme installed at
terminal 1 protecting transmission lines is shown in Figure 1.2. The first zone, designated as Z1,
is set to trip without any intentional time delay and its protection boundary is set as
approximately 80%-90% of transmission line impedance in order to avoid overreach operation
for faults. The second zone, Z2, is set to protect the remaining 10%-20% of the transmission line
plus an adequate margin, and it has to be time delayed (TA2) to coordinate with the relays
installed at remote terminal 2. The third zone with time delay (TA3), Z3, is applied as backup for
zone 2 and can be applied as backup for relay failure or breaker failure at remote terminal 2.
With proper coordination, Z1 & Z2 at terminal 1, Z1 & Z2 at remote terminal 2, and Z3 at
terminal 1 relay will detect all faults on the transmission lines A and B plus some part of the
lines fed from the remote terminal 3 (Line C).
.
Figure 1.2 Normal Selectivity Adjustment of Step Distance Scheme
5
1.1.2 Pilot Schemes
Pilot schemes utilize communication paths to send signals from the relaying system at one end to
that at the other end [1], which allows high-speed tripping to occur for all the faults occurring on
100% of the protected transmission line. Current comparison schemes are commonly applied on
a shorter transmission line when source to line impedance ratio (SIR) > 4 [3], in which a true
differential measurement is made since the magnitudes and phase angles of currents between two
relay locations are compared to operate the relay for internal faults. Because of its principle of
responding only to current, it is more sensitive than the distance type schemes that always need
voltage input.
Some other pilot schemes, such as directional comparison schemes, AC pilot-wire relays, phase
comparison schemes and directional comparison schemes, etc, are seldom used in applications
[3]. However, with the assistance of pilot signals and the operation of distance relay, some new
schemes, such as Direct Underreaching Transfer Trip (DUTT), Permissive Underreaching
Transfer Trip (PUTT), Permissive Overreaching Transfer Trip (POTT) and Zone Acceleration,
can be built up to enhance reliability and acceptable fault clearing time significantly [1].
1.2 Introduction to FACTS
IEEE PES Task Force of the FACTS Working Group defined terms and definitions for FACTS
and FACTS Controllers in 1997 as follows [8]:
Flexible AC Transmission System (FACTS)
Alternating current transmission systems
incorporating power electronic-based and other static controllers to enhance controllability and
increase power transfer capability.
6
FACTS Controller
A power electronic-based system and other static equipment that
provides control of one or more AC transmission system parameters.
From the above definitions it is easy to understand that the power electronic-based controllers are
the key devices in the application. Also, it includes some other static controllers that are not
based on power electronics, such as MSC/MSR (Multiphase Switched Capacitor/Reactor).
In general, FACTS Controllers can be divided into four categories according to the way they are
connected to the power system [2]:
• Series Controllers
• Shunt Controllers
• Combined series-series Controllers
• Combined series-shunt Controllers.
Characteristics of these four FACTS Controllers in applications are listed below:
Series Controllers:
The series controllers could be variable impedance, such as capacitor, reactor, etc... They also
could be power electronics-based variable source of main frequency, sub-synchronous and
harmonic frequencies (or a combination) to serve the desired engineering need. In principle, all
series controllers should inject voltage in series with the connected transmission line [2]. For
easy understanding, a Series Controller works as a variable impedance multiplied by the current
flowing through it, so it can represent an injected series voltage in the line.
Shunt Controllers:
7
Same as series controllers, the shunt controllers may be variable impedance, variable source, or a
combination of these [2]. All shunt controllers inject current into the system at the point of
connection and work as a variable shunt impedance source connected to the line voltage. As long
as the injected current is in phase quadrature with the system line voltage, the shunt controller
only supplies or consumes variable reactive power. Any other phase relationships will involve
real power exchange.
Combined series-series Controllers:
These could be either a combination of separate series controllers or a unified controller [2]. A
combination of separate series controllers is controlled in a multiline transmission system in a
coordinated manner. While as a part of a unified controller, series controllers can provide
independent reactive power compensation for each line, and transfer real power among the lines
via the power link.
Combined series-shunt Controllers:
This type of controller could be a combination of separate shunt and series controllers, which are
controlled in a coordinated manner, or a Unified Power Flow Controller with series and shunt
elements [2]. Combined shunt and series controllers will inject current into the system with the
shunt part of the controller, and voltage in series in the line with the series part of the controller.
When the shunt and series Controllers are unified, there can be a real power exchange between
the series and shunt Controllers via the power link.
The major functions and attributes of the four mentioned types of FACTS controllers are shown
separately in Table 1.1 [9], based on the connections and structures of the controllers. The
control of a series connected controller is achieved by adjusting the injected voltage [2]. As long
8
as the voltage is in phase quadrature with the line current, the series controller only has the
control on reactive power. Otherwise, both real and reactive powers have to be affected by the
adjustment of the controller. Similar to series connected controller, the control of a shunt
connected controller is achieved by adjusting the injected current. The real power and reactive
power also can be controlled in the case that the injected current is not in phase quadrature with
the system voltage. Combined series-shunt controllers include independent and coordinated
shunt and series controllers. Hence, injection of voltage and current to the compensated system
can be established. More flexible control on the system parameters and functional goals for
damping oscillations, transient and dynamic stability, voltage stability, fault current limiting can
be accomplished [2].
As one of the most important shunt connected FACTS controllers, STATCOM is the focus of
this thesis. Its principles and applications will be discussed in Chapter 2.
9
Table 1.1 Control Attributes of Various Controllers
Facts Controller
Shunt
Connected
Controller
Control Attributes
Static Synchronous
Compensator (STATCOM
without storage)
Static Synchronous
Compensator (STATCOM with
storage, large capacitor)
Static VAR Compensator
(SVC,TCR, TCS, TRS)
Thyristor-Controlled Braking
Resistor (TCBR)
Static Synchronous Series
Compensator (SSSC without
storage)
Series
Connected
Controller
Thyristor-Controlled Series
Capacitor (TCSC, TSSC)
Thyristor-Controlled Series
Reactor (TCSR, TSSR)
Thyristor-Controlled PhaseShifting Transformer (TCPST)
Unified Power Flow
Controller (UPFC)
Combined
Shunt Series
Thyristor-Controlled Voltage
Limiter (TCVL)
Thyristor-Controlled Voltage
Regulator (TCVR)
Voltage control, VAR compensation,
damping oscillations, voltage stability
Voltage control, VAR compensation,
damping oscillations, transient and
dynamic stability, voltage stability
Voltage control, VAR compensation,
damping oscillations, transient and
dynamic stability, voltage stability
Damping oscillations, transient and
dynamic stability
Current control, damping oscillations,
transient and dynamic stability,
voltage stability, fault current limiting
Current control, damping oscillations,
transient and dynamic stability, voltage
stability, fault current limiting
Current control, damping oscillations,
transient and dynamic stability, voltage
stability, fault current limiting
Active power control, damping
oscillations, transient and dynamic
stability, voltage stability
Active and reactive power control,
voltage control, VAR compensation,
damping oscillations, transient and
dynamic stability, voltage stability, fault
current limiting
Transient and dynamic voltage limit
Reactive power control, voltage control,
damping oscillations, transient and
dynamic stability, voltage stability
Reactive power control, voltage control,
damping oscillations, transient and
dynamic stability, voltage stability
Interline Power Flow
Controller (IPFC)
10
1.3 Type of converters
In general, FACTS Controllers are based on an assembly of AC/DC or DC/AC converters or
high power AC switches [2]. A converter is an assembly of valves in which each valve is an
assembly of solid state power devices comprising of turn-on/turn-off gate drive circuits with
snubber circuits for damping purpose. Similarly, each AC switch is an assembly of back-to-back
connected solid state power devices along with their snubber circuits and turn-on/turn-off gate
drive circuits.
Compared to the self-commutating converter, the line-commutating converter must have an AC
source connected and will consume reactive power and suffer from occasional commutation
failures in the inverter mode of operation. Hence converters applicable to FACTS Controllers
often employ the self-commutating type [2]. There are two basic categories of self-commutating
converters:
Current-sourced converter
In Current-sourced converter (CSC), direct current always has one polarity, and the power
reversal takes place through reversal of DC voltage polarity.
Voltage-sourced converter
In Voltage-sourced converter (VSC), the direct voltage always has one polarity, and the power
reversal takes place through reversal of DC current polarity.
For the reasons of economy and performance, voltage-source converter is often preferred for
FACTS applications and it will be presented in the following.
11
Figure 1.3 Valve for a voltage-sourced converter
A voltage-sourced converter valve that is made up of an asymmetric turn-off device such as a
GTO, with a parallel diode connected in reverse is shown in Figure 1.3.
Figure 1.4 Voltage-Sourced Converter
The basic function of a voltage-sourced converter is shown in Figure 1.4. In this figure the
converter valve is schematically represented by a box that has a valve and a diode inside it. On
the DC side, the voltage is supported by a capacitor that is large enough to handle a sustained
charge/discharge current that accompanies the switching sequence of the converter valves. The
capacitor is also able to satisfy the current shifts in the phase angle of the switching valve
12
without significant changes in the DC voltage. The DC current can flow in either direction
hence it can exchange power with the connected DC system in either direction. On the AC side,
the generated AC voltage from the converter, Ua, is connected to the AC system via an
inductor. To the AC system, the converter output is a voltage source with low internal
impedance. Therefore, an inductive interface between the converter and the AC system is
important to ensure that the DC capacitor will not discharge rapidly into a capacitive AC load,
such as a transmission line, when there is a short circuit. In application, an interface transformer
can be utilized to achieve multi-functions including inductive interface, voltage regulation and
harmonic cancellation.
1.4 Summary
A brief description of the major protection on power transmission lines, distance relay, and other
protection schemes based on it is given above. Further, four basic types of FACTS controllers
are introduced and different attributes of the controllers are briefly discussed. Self-commuting
converters, the basic power electronic unit in FACTS Controllers, are also introduced. The
operation of voltage-sourced converter that is most applicable to FACTS Controllers is discussed
in the last section. The topic of how the traditional protection schemes are affected by the new
emerging FACTS devices is raised.
1.5 Thesis Outline
The thesis is organized as follows:
In Chapter 2, description of shunt connected STATCOM with its operating principles is
introduced first. Then different topologies of STATCOM based on GTOs are discussed along
13
with control methods of STATCOM. Both external and internal control approaches are presented
by providing different control logistics. Afterwards, discussion of the stable and transient
characteristic of STATCOM is given. The Equal criterion method is applied to analyze the
improvement of system stability with a STATCOM installed. Harmonics in a 6 pulse voltage
sourced converter are analyzed as well. Mathematical models for static and dynamic behaviour
of a STATCOM are presented, from which the current and voltage of a STATCOM can be
obtained with equations provided. Introduction to some worldwide STATCOM applications is
given in the last section.
In Chapter 3, mathematical model of distance protection impedance is built up so as to have a
clear analysis of the measured impedance of a distance relay when a STATCOM is installed at
mid-point of a transmission line. In the discussion for single phase to ground fault and phase to
phase fault, the method of symmetrical components is utilized to obtain the equations for the
measured impedance of the distance relay under different conditions. Conclusion of typical misoperations of distance relays can be made based on the new impedance equations.
Simulation studies for a transmission line with a source at each end and with STATCOM
installed are given in Chapter 4. Various control modules including transmission line module,
VSC-based STATCOM module, voltage control loop module, PWM (Pulse Width Modulation)
control module, distance relay voltage processing module, distance relay Mho module and
Distance relay output module are described. Simulations are run for midpoint connected
STATCOM, near-end bus connected STATCOM and far-end bus connected STATCOM with
different fault conditions. Comparison of the performance with different simulation studies is
14
presented along with an analysis of the behaviour of the distance relay. The effect of output
voltage setting of STATCOM is also considered. Results of all simulation studies should be
consistent with the conclusions made in Chapter 3.
Possible solutions to overcome the mis-operation of the distance scheme when a STATCOM is
installed on a transmission line are given in Chapter 5. Some communication-aided schemes,
including Permissive Overreach Transfer Trip, Permissive Underreach Transfer Trip, Directional
Comparison Blocking and Line Differential scheme, are analyzed and tested in the simulation
system. As a conclusion, Permissive Overreach Transfer Trip is found to be the most suitable
scheme to improve the performance of a traditional distance relay when STATCOM is installed
on the transmission line.
Summary of this work is given in Chapter 6. Further discussion of the distance protection with
installed STATCOM is provided.
Also, future work is considered and possible research
approaches, such as pilot schemes and adaptive setting, are discussed for better improvement of
distance relay in similar applications.
Results of research on the distance protection of a transmission line with the shunt compensation
device, STATCOM, are reported in this thesis. By conducting mathematical modeling for
distance protection and by building power system simulation model for STATCOM and step
distance scheme, this work provides a solid solution to overcome the mis-operation of a distance
relay protection, i.e. Underreach and Overreach, on a transmission line where STATCOM is
installed.
15
Chapter Two: STATCOM Principle and Literature Review
2.1 Introduction to FACTS
From power system equation, real power and reactive power transferred between two power
sources are [10]:
(2.1)
(2.2)
where:
U1 is the RMS voltage at power source 1
U2 is the RMS voltage at power source 2
θ1 is the power angle at power source 1
θ2 is the power angle at power source 2
XL is the transmission line reactance connecting the two sources
From equations 2.1 and 2.2, the power flow can be controlled in either direction in theory by
adjusting the variables of the equations on the right side, such as transmission line reactance XL,
system voltages U1 & U2 and system power angles θ1 & θ2. In practical applications, various
FACTS controllers can be used to achieve the different functions of adjusting specific system
parameters in the system they connect. The shunt connected SVC or STATCOM can provide the
supporting voltage to the compensated system. Other FACTS controllers can change the phase
angles between the two systems, such as TCPST. TCSC can be series connected in a long
transmission line to change the line reactance [2]. All the FACTS controllers mentioned above
16
can rapidly change the power flow within one cycle and even increase the power transfer limit at
normal operating conditions. When the power system is in abnormal or faulty conditions,
FACTS controllers can enhance the system stability with the inherent capability to change the
system parameters continuously. Especially in a ring connected power system, by applying SC
and TCPST, it is possible to meet the requirement of satisfying power demand, reducing
transmission line loss and increasing power transmission capacity [2].
The dynamic control of FACTS devices is based on the real time adjustment of power electronic
switching devices (turn on/off is within one millisecond). Therefore, a FACTS controller can
respond more quickly than a traditional circuit breaker when the FACTS controller is functioning
as an interrupting device (the fastest interrupting time of a circuit breaker is 2 cycles [11]).
Moreover, it is impossible for the mechanical apparatus to conduct the same functions that a
FACTS controller has. As common sense, mechanical device such as circuit breakers and
disconnect switches, cannot be operated so continuously at such high operating speeds without
any safety concerns and any power losses due to their inherent attributes. A circuit breaker can
be used to connect a fixed valued capacitor bank into the system; however, continuous
adjustment of compensation current from the capacitor bank is not possible.
2.2 STATCOM
2.2.1 Introduction to STATCOM
The IEEE defines the STATCOM as [8]:
17
“Static Synchronous Compensator (STATCOM):
A
Static
synchronous
generator
operated as a shunt-connected static VAR compensator whose capacitive or inductive output
current can be controlled independent of the AC system voltage.”
From this definition, a STATCOM is a shunt-connected reactive power compensation device that
is capable of independently generating/absorbing reactive power at its output terminals. In
addition, the compensating reactive power of a STATCOM device can be varied to control the
specific parameters of the electric power system to which it is connected [12].
In summary, a STATCOM can improve power system performance in the following areas:
1) Independent dynamic voltage control of transmission and distribution systems
2) Power-oscillation damping in power transmission systems
3) System transient stability enhancement
4) Voltage flicker control
5) Control of both reactive and active power on the connected line with an energy storage
source.
Furthermore, in practical engineering a STATCOM has some other application benefits due to its
small physical size and modular constructive characteristic compared to other shunt connected
FACTS devices such as SVC. This makes STATCOM have a minimum environmental impact
and more economic efficiency [12].
However, as new FACTS based technology, the
STATCOM is less commonly employed than the SVC in the conservative market. Nevertheless,
18
more projects with STATCOM applications have been commissioned worldwide recently. Some
examples of STATCOM projects are introduced later in this chapter.
2.2.2 Basic Principle of a STATCOM
A STATCOM is analogous to an ideal synchronous machine [12] that generates a balanced set of
sinusoidal voltages at the fundamental frequency with controllable amplitude and phase angle,
and also generates either capacitive or inductive VARs for the system.
Figure 2.1 VSC-based STATCOM interface diagram in a power system
A voltage-sourced converter based STATCOM interface diagram in a power system is shown in
Figure 2.1. The shunt connected compensation system, STATCOM, consists of three major
components, a capacitor, converter and a coupling transformer. The capacitor C, functions as a
DC input voltage source. As output voltages of the STATCOM, the three phase voltages
19
produced by the converters are connected to the AC system through the coupling transformer.
The leakage impedance Xg of the coupling transformer normally is rated at 0.1 p.u to 0.15 p.u.
[2]. Hence it can also functions as a tie inductance between the STATCOM and the AC system.
Then the reactive power exchange can be controlled in a manner similar to that of the
synchronous machine by adjusting the amplitude of the converter output voltages.
Figure 2.2 STATCOM and associated phasor diagrams (capacitive) for Rg=0 and Rg≠0
20
The basic schematic connection of a VSC-based STATCOM for reactive power generation is
shown in Figure 2.2 with phasor diagrams for the cases of Rg= 0 and Rg≠ 0, where Rg represents
the total resistance of the STATCOM. The phasor diagrams are for the cases where the
STATCOM provides capacitive VARs. The Rg = 0 case is the ideal case where power loss in the
circuit is neglected and the STATCOM output voltages are in phase with system voltages.
Referring to Figure 2.2, the equations for the voltages are given below:
Us=Ug+ j IgXg+ IgRg
(2.3)
Where
Us is the AC system voltage
Ug is the Converter output voltage
Xg is the reactance summation of the transformer leakage
Rg is the total resistance summation in STATCOM
For the Rg=0 case, the STATCOM current and reactive power exchanged is given by:
Ig =
(2.4)
Q=
(2.5)
For the sake of better understanding, the operation of a STATCOM is sometimes considered
analogous with the operation of a synchronous machine. Both equations 2.4 and 2.5 also apply
for a synchronous machine as well. For a synchronous machine, reactive power flow can be
controlled by adjusting the excitation of the machine, which in turn adjusts the magnitude of the
output voltage |Ug|. When the machine is over-excited, then it is |Ug| > |Us|. This will result in a
21
leading current, as shown in Figure 2.2. In this case the machine is sending VARs to the system;
consequently the machine can be seen by the system as a capacitor. Likewise, the machine can
function as a reactor in the under-excitation condition with |Ug| < |Us| (not shown in Figure 2.2).
A STATCOM functions in a similar way. This means if the amplitude of the converter output
voltage |Ug| is greater than system voltage |Us|, |Ug| > |Us|，the converter provides capacitive
reactive power to the system, i.e., the STATCOM behaves like a capacitor. On the other hand,
reactive power is absorbed from the system by controlling the converter output voltage to be
smaller than the system voltage, that is |Ug| < |Us|. In this case, the STATCOM behaves like an
inductor.
The resistance Rg in the circuit represents the total power loss of the STATCOM if the power
loss of the switching devices and coupling transformer are considered. In normal operation,
when the STATCOM is used for reactive power generation, the converter can keep the DC
capacitor charged at a desired voltage by making the output voltage of the converter Ug lag
behind the AC system voltages Us by a small angle, which is usually set between 0.1° and 0.2°
[2]. In this way, a small amount of real power from the AC system will be absorbed by the
converter to compensate for its internal real power loss and to meet the capacitor voltage
requirement. This approach can be applied to increase or decrease the capacitor voltage. Hence
VAR generation or absorption of the STATCOM can be controlled.
STATCOM control approaches are now discussed, to be followed by a discussion of
STATCOM’s applications and effects on distance protection.
22
2.2.3 STATCOM Control
Introduction to STATCOM Topologies
The topology of a STATCOM is related to the VAR capacity and to the harmonics profiles of the
STATCOM. Regardless the number of pulses, the voltage-sourced converter, is composed of
several high power switching devices such as GTO or IGBT devices, with a parallel diode
connected in reverse for each device [2].
A six-pulse STATCOM topology is shown in Figure 2.3. If a higher VAR capacity is needed,
then the 12-pulse topology of Figure 2.4 may be used. Other topologies exist, for example a 48pulse converter may be constructed using the multi-level converter approaches [2].
Figure 2.3 Topology of a three-phase, two-level, six-pulse voltage-sourced converter
23
Figure 2.4 Topology of a three-phase, three-level, twelve-pulse voltage-sourced converter
Referring to Figures 2.3 and 2.4, a switching device usually is comprised of a number of
(normally 3 to 10) series connected GTOs or IGBTs to increase the overall voltage peak
capability. Each of the three legs of the converter is controlled to produce a quasi-square wave
output voltage, or sometimes a pulse width modulated (PWM) output voltage waveform. The leg
waveforms are 120° phase shifted from each other in a three phase system.
A coupling transformer connection to the AC system is used to produce a stepped approximation
of a sine wave current waveform, in which a significant number of low order harmonics are
eliminated [2].
24
Basic Control Approaches of a STATCOM
A block diagram of the basic control functions of a STATCOM is shown in Figure 2.5.
Figure 2.5 Block Diagram of the basic control structure of a STATCOM
The control [2] of a STATCOM includes two main parts, external control and internal control.
External control provides the reference signals to determine the functional operation of the
STATCOM. The internal control provides the gating signals for the semiconductor power
switches of the voltage-sourced converter. Some reference signals for external control are
normally from operator instructions or system variables, such as system voltage fluctuation ΔUs
and reactive current IQref. With the support of the STATCOM, the system voltage at the
compensation point can be kept at a preset level. In applications, ΔUs is the voltage difference
between system voltage Us and reference voltage Uref and it has to be kept within a limit for
25
internal power loss. The STATCOM is able to increase the adjustment range with a fixed MVAR
capacity and to provide the flexible compensation to the system by following its V-I
characteristic slope, as discussed in section 2.2.4.
By computing the magnitude and phase angle of the STATCOM current Ig from external control
and the pre-set reference voltage, the internal control of the STATCOM can be achieved to
generate a set of coordinated timing waveforms, that can operate the converter power switches to
produce output voltage waveforms Ug, and provide the real/reactive power exchange requested
for the compensation. These timing waveforms have a gating pattern that determines the TurnON and Turn-OFF periods of each individual switch of the converter. The pre-defined phase
relationship between the waveforms is determined by different factors, such as the converter
pulse number, the method used for constructing the output voltage waveforms and the required
angular phase relationship between outputs in each phase (normally 120 degree).
There are two methods to achieve the function of internal control: Indirect Control and Direct
Control.
Indirect Control
A simple block diagram of the indirect control of a STATCOM for pure reactive compensation is
shown in Figure 2.6.
26
Figure 2.6 Indirect control diagram of a STATCOM
In this approach, magnitude of the output voltage from the converter is proportional to DC
capacitor voltage [2]. By varying the DC capacitor voltage through the temporary phase shift δ
between the STATCOM output voltage Ug and the AC system voltage Us, reactive current from
the converter can be controlled indirectly. The inputs from external control to the indirect control
are AC system bus voltage Us, converter output current Ig and the reactive current IQref. Voltage
Us operates a Phase Lock Loop circuit that provides the basic synchronizing signal angle θ.
Current IgQ is the reactive component of the converter output current Ig. It is compared with the
reference current IQref. The resulting error obtained provides an angle Δδ after suitable
amplification. The angle Δδ defines the necessary phase shift between converter output voltage
and the AC system voltage. Accordingly, Δδ is added to θ to provide Δδ+θ, which represents the
desired synchronizing signal for the converter and is processed by the Gate Pattern Logic circuit.
27
The Gate Pattern Logic circuit generates the gate drive signals for individual power switches.
When the control procedure is complete, there should be only reactive power exchange between
the STATCOM and the system, and the final δ is zero (if Rg=0).
Direct Control
A simple block diagram of the direct control approach of a STATCOM is shown in Figure 2.7.
Figure 2.7 Direct control diagram of a STATCOM
In this approach [2] the reactive output current can be controlled directly by the internal voltage
control mechanism of the converter while the DC voltage of capacitor is kept constant. To make
this possible real power exchange is needed and Pulse Width Modulation (PWM) is applied to
28
control the output real power and output voltage. Inputs from the external control circuit to the
indirect control are AC system bus voltage Us, converter output current Ig and the reactive
current IQref, plus the DC voltage reference Udcref. The DC reference voltage determines the real
power that the converter absorbs from the AC system in order to compensate its internal power
loss. As illustrated in Figure 2.7, the reactive component of the STATCOM output current is
compared with reference current IQref from external control. The real part is compared with IPref
from DC voltage regulation loop. After suitable amplification, the real and reactive current
error signals are processed to calculate the magnitude and phase angle Δδ. As in the case of
indirect internal control, Δδ is added to the basic synchronizing signal angle θ that is from the
Phase Locked Loop. As a result, the angle summation (Δδ + θ) together with the desired
converter output voltage, Ug, operates the Gate Pattern Logic circuit to provide the individual
gate drive logic signals to the switches. The internal control scheme operates the converters
with a DC power supply, the internal real current reference, IPref, can be summed to an
externally provided real current reference. This current, IgP, can indicate the desired real power
exchange with the AC system.
2.2.4 Steady State and Transient Characteristics of a STATCOM
V-I characteristic
The V-I characteristic of a STATCOM [13] is shown in Figure 2.8.
29
Figure 2.8 V-I characteristic of a STATCOM
On the Y axis in Figure 2.8, Vt is the per unit system voltage. The intersection of a given
characteristic sloped line with Y-axis provides the STATCOM operating voltage, i.e. the Y
intercept is the STATCOM voltage. It can be observed from the figure that the STATCOM can
be operated as either a capacitive or an inductive compensator. It is also depicted in Figure 2.8
that the STATCOM is able to control its output current. As shown in the figure, the STATCOM
can provide full rated steady-state reactive current even in the case that the system voltage is as
low as 0.15 p.u rated. This outstanding capability, compared to other shunt connected FACTS
devices, is particularly useful for the situations in which the STATCOM is needed to support
the system voltage during or after fault conditions.
30
Transient Stability
To examine the concept of transient stability, consider Figure 2.9, that shows a two-machine,
two-line power system with a STATCOM installed in the middle of one line.
Figure 2.9 Two-machine, two-line power system with a STATCOM
In Figure 2.9, Ui is the generator terminal voltage; Uj is the voltage at the receiving end. Ub1 and
Ub2 are voltages at the sending bus and the receiving bus while U1 represents the system voltage
at the STATCOM connection point. ZS1 is the impedance between the generator and the
STATCOM; Zr1 is the impedance between STATCOM and the receiving generator. P, Q and I
represent, respectively, real power, reactive power and current at various locations of the system.
The effectiveness of a STATCOM on transmission line stability improvement can be
conveniently explained with the equal area criterion [10] for the system in Figure 2.9.
31
In normal practice voltage amplitudes on both ends of the transmission lines are equal. From
equation 2.1, it means:
|Ub1| =|Ub2| = U
Defining:
δ = θ1 - θ2
(2.6)
equation 2.1 can be re-written as:
(2.7)
With the STATCOM installed at the mid-point of the transmission line system, the real power
transferred through the line is:
(2.8)
Based on equations 2.7 and 2.8, the curves in Figure 2.10 show the power transmitted in the
system without STATCOM and with STATCOM installed, respectively. The system is
represented by the P versus δ curve ‘a’ and it is operating at angle δ1 to transmit power when a
fatal fault occurs on line 2 [14]. During the fault, the system is characterized by the P versus δ
curve ‘b’. During the fault transient, the transmitted power drops significantly but at the same
time the mechanical input power to the sending generator remains substantially constant
corresponding to P1. As a result, the generator accelerates and the system angle increases from δ1
to δ2, at which time the protective breakers disconnect the fault line 2 and the generator still
accelerates. The additional energy absorbed by the generator during this transient corresponds to
the area ‘A1’. After the fault is cleared, the system without line 2 is represented by P versus δ
curve ‘c’. At angle δ2 on curve ‘c’ the transmitted power exceeds the mechanical input power P1
and the generator starts to decelerate. However the angle keeps increasing up to δ3 due to the
32
kinetic energy stored in the machine. δ3 is the maximum angle where the decelerating energy
(area A1) is equal to accelerating energy (area A2). The limit of transient stability is reached at
δ4, beyond which the decelerating energy would not balance the accelerating energy and system
synchronism would be lost. The area ‘Amargin’ between δ3 and δ4 represents the transient stability
margin of the system. From both curves it can be observed that the Amargin in the case with a
STATCOM installed is significantly bigger than that in the case without the STATCOM. The
above illustrates that the system stability has been improved by the STATCOM installation.
Without STATCOM
With STATCOM
Figure 2.10 Illustration of equal area criterion for transient Stability
2.2.5 Harmonic profile of STATCOM
As mentioned before, converters in STATCOM always have an inductive impedance interface
with the AC system (usually through a coupling transformer). The function of the inductance in
the circuit is to ensure that the DC capacitor does not discharge rapidly into a capacitive load
such as a transmission line [2]. The inductance also reduces the resultant harmonic current flow.
It is preferable if the STATCOM converter generates lower amplitude harmonics. Following is
an analysis of a simple six-pulse VSC-based STATCOM to illustrate harmonics generation.
33
As shown in Figure 2.3, the elementary 6-pulse VSC-based STATCOM consists of six selfcommunicating semiconductor high power switches, such as IGBT or GTO, with anti-parallel
diodes. The converter can produce a balanced set of three quasi-square voltage waveforms at a
given frequency. The output voltage of the STATCOM is a staircase type synthesized waveform.
It has substantial harmonics in addition to the fundamental. The following analysis is for a 180°
conduction sequence, a sequence where three switches in different legs conduct for equal time
intervals and conduct at a time [12].
Using Fourier-series equation, the STATCOM output voltage may be expressed as
(2.9)
where coefficients a0, an and bn can be determined by considering one fundamental period of Vab.
If Vab has no dc component, then a0=0. With odd wave symmetry, an=0. The coefficient bn can be
determined as:
(2.10)
Then
=
Therefore
34
(2.11)
(2.12)
For a 180° conduction sequence, α = 30°, where α is half of a step interval. The triplen
harmonics are zero in the output line voltage as per equation 2.13, because when n=3k, if
k=1,3,5,…, then cos (nα) =0 and if k=2,4,6… then cos(nα) =
n=5k, cos(nα)=
. It also can be noted that when
. Hence the STATCOM output voltage only includes the harmonic
components of (6k
) f0 in its output voltage, where f0 is the fundamental output frequency and
k=1,2,3…
The magnitudes of various harmonics in the converted voltage from the 6 pulse STATCOM are
shown in Figure 2.11.
Figure 2.11Typical Harmonics in 6-pulse STATCOM voltage output
35
To reduce the harmonic generation in the system, various converter configurations and converter
switching techniques are utilized in practice. This could involve transformer configurations,
different topologies of the STATCOM with multiple-level, multiple-pulse converter controls,
etc. [12].
2.2.6 Detailed Mathematical Model of STATCOM
Since a STATCOM produces a synchronous voltage with the AC system, it can be considered as
a synchronous voltage source. The real power and the reactive power can be solved with the
Park’s Transformation.
The equivalent circuit of a 6-pulse VSC-based STATCOM including a coupling transformer is
shown in Figure 2.12.
Figure 2.12 STATCOM Equivalent Circuit
36
The inductance L is primarily from the reactance of the coupling transformer; Rs represents the
total loss from the converters and transformer; Udc is the DC voltage on the capacitor and idc is
the DC current. For analysis, the following assumptions are made:
1) All the switches are ideal.
2) Only three phase sinusoidal voltages with 120 degrees phase displacement are generated
from STATCOM, and the AC system voltage is symmetrical.
3) All harmonics are neglected.
Static Module of STATCOM
As discussed before, a STATCOM can be taken as a synchronous voltage source with
controllable output voltage magnitude and phase angle. Refer to phasor diagram in Figure 2.2 for
the following discussion.
The reactive current Ig of the STATCOM and the corresponding reactive power Q exchanged is
determined by equations 2.4 and 2.5, repeated here for convenience:
Ig =
(2.4)
Q=
(2.5)
Ug =
(2.13)
It can be shown that:
Therefore, the real power and active power from the STATCOM to the AC system are:
P=
(2.14)
37
Q=
(2.15)
Recall the Ratio of Modulation M defined as:
M=
(2.6)
Then:
Udc =
=
(2.16)
It can be observed from the above equations that when the real power loss of the STATCOM,
which is represented by Rg in the phasor diagram and equations, is included, the phase angle δ
can be used to determine,
1) The STATCOM output voltage
2) DC voltage of capacitor bank
3) The magnitude and direction of real power and reactive power.
Also, because of the angle δ, the current of STATCOM is not completely orthogonal to the AC
system voltage.
Dynamic Module of STATCOM
For the AC voltage, if ω is the system frequency:
(2.17)
38
where Usa, Usb and Usc are the system voltages.
The voltage generated by the STATCOM is a three phase symmetrical voltage that has a phase
angle, δ, with the AC system. Then:
(2.18)
From the circuit of Figure 2.13 and using the principle of conservation of energy:
(2.19)
Using the Park’s Transformation, neglecting zero sequence components:
= Pk
(2.20)
= Pk ·
(2.21)
in which Pk is the a-b-c to d-q-0 transformation operator:
39
Pk
(2.22)
Then the mathematical model in the d-q-0 frame of reference is:
(2.23)
Pk
(2.24)
When the system is in asymmetrical operation there are still no zero sequence components
because of the delta connection of the STATCOM converters. The system voltage then can be
decomposed into positive and negative sequence components according to the symmetrical
component method. Taking phase A as the reference, the angle for positive voltage is zero and
that for negative voltage is
, then in the time domain:
=
(2.25)
40
Using Park’s transformation, the following can be obtained:
(2.26)
Then from equations 2.21 and 2.26 the current and voltage of a STATCOM can be resolved in
the case of asymmetrical conditions.
2.2.7 STATCOM applications
Over the past few decades Voltage Sourced Converter based technology has been successfully
applied in a number of FACTS projects. In 1980, Kansai Electric Power Co. Inc. (KEPCO) and
Mitsubishi Motors developed the first STATCOM in the world, a 20 MVAR STATCOM using
forced-commuted thyristor inverters [15]. Recent STATCOM projects in North America have
demonstrated the advantages of the application of the FACTS in power systems. In 1994
Tennessee Valley Authority (TVA), USA, developed a ±100 MVAR static condenser at the
Sullivan substation for voltage control of transmission systems [16]. This installation was the
first demonstration of a STATCOM under the EPRI flexible AC transmission systems program,
and at that time was the largest installation of its type in the world with the availability of high
power GTO thyristors for the development of controllable reactive power in transmission
systems. In 1997, American Electric Power (AEP) installed the world's first Unified Power Flow
Controller (UPFC) at the Inez substation in eastern Kentucky. In phase I of the project two ±160
MVAR voltage-sourced GTO-thyristor-based STATCOM were installed. This was the first
practical demonstration of the UPFC concept with the highest power GTO-based STATCOM
equipment ever installed [17]. On May 1st, 2001, the Vermont Electric Power Company, Inc.
41
(VELCO) placed a +133/-41 MVAR, 115 kV STATCOM system on line at the Essex Substation
located near Burlington, VT, USA. The STATCOM was installed to provide dynamic voltage
support and reactive compensation on the VELCO transmission system [18] [19]. In October
2002, San Diego Gas & Electric (SDG&E) initiated the installation of a 138 kV STATCOMbased dynamic reactive compensation system with capacity rating of
100MVAR in a major
transmission system enhancement project involving a key 230/138 kV substation [20]. In a
Northeast Utility project, a 150MVAR rated STATCOM at Glenbrook 115kV substation located
in Hartford Connecticut is split into two halves, each rated at
75MVAR. The STATCOM is to
provide fast acting dynamic reactive compensation for voltage support during contingency
events [21]. In November of 2002, BC Hydro installed a small STATCOM, an 8 MVA D-VAR
device, in their system at the Fort St. James substation to prevent voltage collapse in the 66 kV
long radial system and as a means to defer costly transmission reinforcement. It has shown that
utilizing small size STATCOMs distributed in multiple locations in a power grid is quite
effective in addressing issues such as: voltage support in contingencies; power transfer
limitations on interconnected systems; and integration of wind farms to grids [22].
As illustrated by the above projects, when a STATCOM is shunt connected in the system with
the FACTS using power semiconductor switching technology, several benefits may result:
dynamic voltage support; system stabilization; system transfer capacity increase and enhanced
power quality for both transmission and distribution systems. In normal practice, when a
STATCOM is used for voltage support, improving system stability or improving HVDC link
performance, the device is often installed at the end of a transmission line or on a bus in a power
42
substation [18] [20] [21]. For controlling power flow or increasing the power transfer limit of a
transmission line, the mid-point of the line is the best location for a STATCOM [2].
With the presence of a STATCOM in a system, there are concerns to be considered such as
harmonics caused by switching converters and potential effects on various protective schemes. In
this thesis, the focus is on the distance relay performance when a STATCOM is installed in a
transmission system. The following are some references focusing on this topic.
A general survey of the FACTS devices and a review of the effect of a STATCOM connected at
the midpoint of a transmission line on the performance of distance protection relays are
presented in Ref. [23].
The effect of the STATCOM installation locations on the measured impedance is considered in
Ref. [24]. Three locations were investigated, i.e. at the relaying point, mid-point and the remote
end of the transmission line.
Analytical and simulation results based on steady operation for modelling the STATCOM are
presented and the effect of STATCOM on a distance relay in both normal and faulty conditions
under different load levels were studied in Ref.[25].
The effect of the balanced fault in distribution system with STATCOM was analyzed and
simulated in Ref. [26]. The operating behaviour of the instantaneous over-current protection,
time-delayed instantaneous over-current protection, and definite time over-current were also
studied.
The impact of STATCOM employed in a transmission system on the performance of distance
relay was analyzed in Ref. [27]. The simulation cases include different fault conditions, influence
43
of location of STATCOM, settings of STATCOM control parameters, and the operation mode of
STATCOM.
The effect of mid-point STATCOM compensation on the performance of an impedance distance
relay under normal load and fault conditions was investigated in Ref. [28]. The adaptive distance
relaying scheme for transmission line protection was proposed and implemented in a DSP
system. In Ref. [29], detail study on a quadrilateral characteristic distance relay in presence of
STATCOM in a transmission line was given; adaptive distance relay protection was proposed
based on the control parameters from SCADA information.
The effect of mid-point FACTS compensation on the distance relay was studied in Ref. [30]. In
this study, the errors introduced in the relay due to the presence of FACTS devices were
analyzed first. Then various situations with different fault conditions and system conditions were
simulated in EMTDC. Finally the results were confirmed by testing a commercial relay through
RTDS. Mitigation methods to improve the performance of distance relays, when transmission
lines are midpoint compensated by shunt-FACTS devices, are proposed in Ref. [31].
Some references in this chapter analyzed the impact of a STATCOM on the performance of
distance relays. All studies have shown that when a STATCOM is installed in fault loops in a
transmission system, the apparent impedance seen by a conventional distance relay is different
from the one in a system without STATCOM due to the VAR injection of STATCOM and the
steady and transient component changes in the fault. In order to give an overall analysis this
work is supposed to consider the following issues in detail with different system variables and
contingencies.

Normal conditions and fault conditions;
44

STATCOM installation positions, mid-point and end receiving side;

Setting voltage of STATCOM, 1.1pu, 1.0pu, and 0.90pu;

Fault types, signal phase to ground, phase to phase, phase to phase to ground, three-phase
to ground;

Fault locations, from sending terminal to receiving terminal;

Faulty resistances, from small to relatively large;

Comparison with the situations without STATCOM.
45
Chapter Three: Modeling of Distance Protection Impedance
As discussed in Chapter 2, the best location for the installation of a STATCOM to improve
system stability in a two-power source transmission system is the mid-point of the transmission
line. In this chapter, the impedance measured by a distance relay is analysed when a STATCOM
is installed in this way. The scenarios discussed in this chapter are investigated further by
simulations in Chapter four.
Fault impedance calculation by a distance relay relies on the voltage and current of each phase
measured at the relay location. How the transmission line impedance seen by a distance relay on
the incidence of a fault is modified, when a STATCOM is installed at the middle of the line, is
discussed in this chapter. Combination of the single phase to ground fault and phase to phase
fault schemes can cover all types of faults in the forward direction of the transmission line.
3.1 STATCOM installed at mid-point of the transmission line
The system shown in Figure 3.1 is utilized to perform an analysis of the distance relay protecting
a transmission line with a STATCOM installed at the mid-point. In the circuit, two generators,
G1 and G2, are connected with a transmission line. The distance relay is installed next to Bus 1
to protect the transmission line on which a STATCOM is installed at the mid-point (n=0.5 in
Figure 3.1). In this case, only the distance relay close to Bus 1 is analysed. Another distance
relay installed at the Bus 2 end to protect the transmission line should behave in a similar manner
when the same types of faults occur on the transmission line.
46
Figure 3.1 Transmission Line with a STATCOM at mid-point
In order to analyze the operation of the distance relay when a STATCOM is installed at the midpoint of the line, a sequence network for a single phase fault is utilized. The apparent impedance
seen by the distance relay can be calculated with the symmetrical components of the voltage and
the current measured at the relay location.
The basic equation to calculate the apparent impedance seen by a distance relay for a single
phase to ground is [4]:
Z=
(3.1)
where:
VR, IR are the phase voltage and current at relay point
IR0 is zero sequence phase current
Z0, Z1 are zero and positive sequence impedance, respectively, of the
transmission line
47
For a distance relay on this transmission line, there are two possible fault locations to consider
relative to the STATCOM in the circuit: before and after the STATCOM point of installation.
3.1.1 Single phase fault after the STATCOM
A transmission line with a STATCOM installed at the mid-point and a single phase to ground
fault in the second half of the transmission line, i.e. after the STATCOM, is shown in Figure 3.2.
In the circuit, the distance relay is installed next to the sending Bus 1 and protects the
transmission line. The parameter ‘n’ is defined as the per unit distance from the fault location to
the relay location. Iline is the current in the transmission line after the STATCOＭ installation
point, Vs and Is are the voltage and current at bus 1, respectively, If is the ground fault current, Ist
is the shunt current injected from the STATCOM, Z is the combined impedance of the whole
transmission line.
Figure 3.2 Circuit with a fault after the STATCOM
48
Figure 3.3 Sequence Circuit with a single phase to ground fault after mid-point STATCOM
The sequence circuit for the case of a single phase to ground fault (A-G) in the transmission line
when the STATCOM is included in the fault loop is shown in Figure 3.3.
From Figure 3.3 it can be written that:
V1s= V1f + 0.5Z1I1s + (n-0.5)Z1(I1s + I1st)
(3.2)
V2s= V2f + 0.5Z2I2s + (n-0.5)Z2(I2s + I2st)
(3.3)
49
V0s= V0f + 0.5Z0I0s + (n-0.5)Z0(I0s + I0st)
(3.4)
Z1=Z2 (for a transmission line)
(3.5)
Vs= V1s + V2s + V0s,
(3.6)
V1f + V2f + V0f = 0 (for a direct short-circuit to ground)
(3.7)
As:
then:
Vs = nZ1I1s + (n-0.5)Z1(I1s + I1st) + nZ2I2s + (n-0.5)Z2(I2s + I2st)+ nZ0I0s + (n-0.5)Z0(I0s + I0st)
(3.8)
Also for a single phase to ground fault (e.g. A-G):
I1s = I2s = I0s
(3.9)
Ia= I1s + I2s + I0s
(3.10)
The current from the STATCOM:
Ist= I1st + I2st + I0st
(3.11)
I0st =0
(3.12)
Zero sequence current I0st from the STATCOM is zero. This is due to the Y/∆ configuration of
the coupling transformer of the STATCOM.
Then:
Vs = nZ1 (Ia -I0s) + (n-0.5)Z1Ist + nZ0I0s
(3.13)
Vs = nZ1 [(Ia -I0s) +
I0s]
(3.14)
) Ist]
(3.15)
Vs = nZ1 [(Ia +
Ist+
I0s+ (
The measured impedance of the distance relay is
Zrelay = nZ1 =
(3.16)
50
where:
n>0.5
Comparing equation (3.16) with the equation (3.1) of a distance relay without STATCOM, it can
be observed that the impedance seen by the relay is changed by the additional term (
) Ist
in the denominator. With the shunt current input from the STATCOM, Ist > 0, the reactive power
can be injected to the AC system. From equation (3.16), the apparent impedance seen by the
distance relay is bigger than the actual transmission line impedance. As one of the typical misoperations of a distance relay, this phenomenon is called under-reaching of a distance relay.
Similarly, on the other hand, when the STATCOM consumes reactive power from the AC
system and the current flow is from the AC system to the STATCOM, the Ist is negative (Ist < 0).
In this case the apparent impedance measured by the distance relay is smaller than the real
transmission line distance. Then another typical mis-operation of the distance relay, overreaching of a distance protection, occurs.
3.1.2 Single phase fault before the STATCOM
There is another scenario when the same single phase fault occurs before the STATCOM
installation point, i.e., in the first half on the transmission line.
Figure 3.4 Single phase fault before mid-point STATCOM
51
The transmission line circuit with a single phase fault before the STATCOM is shown in Figure
3.4. This is the same circuit as discussed previously; the only difference is the single phase to
ground location. In this circuit, the distance relay is installed next to the sending Bus 1 and
protects the transmission line. The per unit distance from the fault location to the relay location is
defined as n. Iline is the current in the transmission line after the STATCOM installation point, Vs
and Is are voltage and current at bus 1, respectively, If is the ground fault current, Ist is the shunt
current injected from the STATCOM, Z is the combined impedance of the whole transmission
line.
52
Figure 3.5 Sequence Circuit with a single phase to ground fault before mid-point STATCOM
The sequence circuit for the single phase to ground fault is shown in Figure 3.5. From the circuit:
V1s= V1f + nZ1I1s
(3.17)
V2s= V2f + nZ2I2s
(3.18)
V0s= V0f + nZ0I0s
(3.19)
Z1=Z2
(3.4)
Vs= V1s + V2s + V0s
(3.5)
V1f + V2f + V0f = 0
(3.6)
Now:
Also for a single phase to ground fault (e.g. A-G):
I1s = I2s = I0s
(3.8)
Ia= I1s + I2s + I0s
(3.9)
Then:
Vs = nZ1 [(Ia -I0s) + nZ0I0s
(3.10)
The measured impedance of the distance relay is
Zrelay = nZ1 =
(3.11)
Equation (3.11) is the same as standard equation (3.1) for a distance relay used to calculate the
measured impedance of the transmission line it protects. This clearly indicates that in the case
that the STATCOM is not in the fault loop, the distance relay functions as normal and the
STATCOM has no effect on the distance protection.
53
3.2 Phase to phase fault
3.2.1 Phase to phase fault after the STATCOM
The basic equation to calculate the apparent impedance seen by a distance relay for a fault
between phases B and C in a three phase transmission is [4]:
Z=
Vb  Vc
Ib  Ic
(3.12)
Figure 3.6 Sequence circuit with a phase to phase fault after mid-point STATCOM
The sequence circuit for the case of a phase to phase fault (B-C) in the transmission line when
the mid-point STATCOM is included in the fault loop is shown in Figure 3.6. The positive and
negative sequence voltage equations can be written as:
54
V1s= V1f + 0.5Z1I1s + (n-0.5)Z1(I1s + I1st)
(3.13)
V2s= V2f + 0.5Z2I2s + (n-0.5)Z2(I2s + I2st)
(3.14)
Z1=Z2
(3.15)
V1f = V2f
(3.16)
V1s -V2s =0.5Z1 (I1s - I2s) + (n-0.5) Z1 (I1s + I1st -I2s -I1st)
(3.17)
As:
Then:
From the sequence components:
Vb = V0
+
Vc = V0
+
Ib = I0
+
Ic = I0
+
V1 + α V2
α V1 +
(3.18)
V2
(3.19)
I1 + α I2
α I1 +
(3.20)
I2
(3.21)
Then:
V1s -V2s =
I1s -I2s =
I1st -I2st =
(Vb- Vc)
(3.22)
(Ib- Ic)
(3.23)
(Ib-st- Ic-st)
(3.24)
The impedance seen by the distance relay is calculated as:
Zrelay =
I  I c  st
Vb  Vc
= nZ1 + b  st
(n-0.5) Z1
Ib  Ic
Ib  Ic
where n>0.5
55
(3.25)
Compared to the standard equation 3.2 that a distance relay is used for phase to phase fault
determination, equation 3.25 has an extra term
I b st  I c  st
(n-0.5) Z1. It shows the effect of the
Ib  Ic
STATCOM on the measured impedance of a distance relay and the distance relay may not
operate properly. As the currents of the STATCOM, Ib-st and Ic-st are smaller than the system
current Ib&Ic in a phase to phase fault, the error of the seen impedance of the distance relay is
within a small range.
3.2.2 Phase to phase fault before the STATCOM
Figure 3.7 Sequence circuit with a phase to phase fault before mid-point STATCOM
56
The sequence circuit for a phase to phase fault before the STATCOM is shown in Figure 3.7. In
this case:
V1s= V1f + nZ1I1s
(3.26)
V2s= V2f + nZ2I2s
(3.27)
Z1=Z2
(3.28)
V1f = V2f
(3.29)
V1s -V2s =nZ1 (I1s - I2s)
(3.30)
As:
Then:
From the sequence components:
Vb = V0
+
Vc = V0
+
Ib = I0
+
Ic = I0
+
V1 + α V2
α V1 +
(3.18)
V2
(3.19)
I1 + α I2
α I1 +
(3.20)
I2
(3.21)
The impedance seen the distance relay is calculated as:
Zrelay =
Vb  Vc
= nZ1
Ib  Ic
(3.31)
Equation 3.31 is the same as standard equation 3.12 that a distance relay is used to calculate the
measured impedance of the transmission line for a phase to phase fault. This clearly indicates
57
that in the case that the STATCOM is not in the fault loop, the distance relay functions as normal
and the STATCOM has no effect on the distance protection.
58
Chapter Four: Simulation
4.1 System Simulation
EMTDC/PSCAD (Power System CAD) is utilized in this Chapter to build a simulation model for
a 230 kV, 360 km long transmission system with a shunt-connected STATCOM. The
transmission line in the simulated system is protected by a two-zone step distance protection
scheme. Various system configurations and contingent conditions are considered in order to
perform an analysis of how the shunt-connected STATCOM would affect the distance protection
in the transmission system. This includes different fault types/fault resistance, different
STATCOM installation locations, and various voltage settings of the STATCOM.
Some FACTS and protection components in the PSCAD library are referenced to compose the
major sections of the STATCOM, transmission line, as well as the distance protective scheme.
4.1.1 Transmission System Module
System configuration
Configuration of the simulated AC single line diagram is shown in Figure 4.1
Figure 4.1 Single line Diagram of Simulated Power System
59
In this system, the generator and the load are connected through a 360 km, 230 kV transmission
line. A distance relay with two protective zones is installed next to Bus 1 that is close to power
source Gen1 to react under various fault conditions. These include single phase to ground fault,
phase to phase fault, and three-phase to ground fault at different locations on the transmission
line. Another distance relay installed next to Bus 2 has the same function but protects the
transmission line from the reverse direction. A STATCOM with 70 MVA rating is shunt
connected into the system for analysis.
The EMTDC/PSCAD model includes several modules to achieve the complete functionality.
Among these modules, The Voltage Control and PWM Control modules are selected for
STATCOM control; Signal Processing module and Protection Scheme module compose a twozone distance relay detecting phase to ground fault and phase to phase fault. Several display
modules, such as System Display, STATCOM Display and Relay Display, are also built in for
better presentation of different analog/digital variables and relay protective zones with measured
impedance in the simulated system.
Transmission line
The 360 km long transmission line is simulated according to a Bergeron model [32], a model that
is based on a distributed LC parameter travelling wave line with lumped resistance and
reactance. Four 90 m long transmission line sections with transmission line interfaces are used in
the simulation. The line module with two overhead ground wires, as shown in Figure 4.2, is used
and the ACSR 477 is chosen for each single phase conductor.
60
GND1
10 [m]
GND2
C2
10 [m]
5 [m]
C1
C3
10 [m]
30 [m]
Tower: 3H5
Conductors: 3M (ACSR 477)
Ground_Wires: 1/2"HighStrengthSteel
0 [m]
Figure 4.2 Transmission Line Module
In Figure 4.2, one of the transmission towers, named 3H5, is shown. In this figure, GND1 and
GND2 represent overhead ground wires, and C1, C2 and C3 are the three phase conductors. The
conductors, and the clearance between them and ground determine transmission line parameters.
Parameters of the transmission line for this model are as follows:
Positive sequence impedance
0.0115 +j*0.572 ohms/km,
Negative sequence impedance
0.0115 +j*0.572 ohms/km,
Zero sequence impedance
0.4428 +j*1.3907 ohms/km
Conductor DC resistance:
0.1138 ohm/km
Conductor Geometric Mean Radius: 0.008758 m
Number of sub-conductors in a bundle: 1
Generator and load
There is a generator and a load in the simulated system. Both are based on Three-Phase Voltage
Source Model 3 in the PSCAD library and both of them are set with a capacity of 100 MVA at
230 kV. The load at the end of the transmission line is presented as a generator, which is chosen
61
to have the reference system angle for the transmission system. The generator in the system at
the sending end (Bus1) has a phase angle θ =10° input in order to create power flow on the
transmission line from Gen to Load in the simulation.
Parameters of the generator and the load are:
Generator and unit transformer
Power rating: 100 MVA;
Voltage at HV terminal of unit transformer: 230 kV;
System frequency: 60 Hz;
Phase angle: 10°;
Positive sequence impedance: 14.1588.04  ;
Zero sequence impedance: 20.8488.17   ;
Load
Power rating: 100 MVA;
System voltage: 230 kV;
System frequency: 60 Hz;
Phase angle: 0°;
Positive sequence impedance: 26.4580  ;
Zero sequence impedance: 32.7084.68  ;
62
4.1.2 STATCOM modelling and its Control Circuit
The STATCOM considered in this work is based on a Voltage-Source Converter. As discussed
before, from a given DC input voltage the STATCOM produces a set of three-phase AC output
voltages to compensate the AC system. Each output voltage is in phase with the AC system and
is coupled to the corresponding AC system voltage through a small reactance, provided by the
leakage inductance of a coupling transformer. An energy-storage capacitor is utilized for the DC
voltage input.
STATCOM model
The two level six-pulse STATCOM model, comprised of six Power Electronic Switches and a
Y/D transformer from PSCAD example Lib, is chosen in this work. The core component of the
STATCOM is based on Voltage-Sourced Converter, in which GTOs are utilized as the switching
valves.
1
g1
2
3
g3
2
5
g5
2
300.0 [uF]
#1
#2
4
g4
2
6
g6
2
2
g2
2
Figure 4.3 VSC-based STATCOM module
63
A VSC-based STATCOM module is shown in Figure 4.3. In this figure, the ratio of the Y/D-11
coupling transformer is 220 kV/25 kV. The transformer is rated at 300 MVA and its positive
sequence leakage reactance is 0.1p.u. G1 to G6 are GTO-based power electronic switches
whose gate firing pulses (g1 to g6) are generated by the STATCOM PWM control module.
Each GTO has a reversed paralleled connected diode with 10 000 V reverse withstand voltage.
A snubber circuit comprising resistance and capacitance is included in the GTO module as well.
The capacitance of the capacitor in the DC circuit is 300 μF.
The STATCOM control employed in this work is the Direct Control approach (discussed in
Chapter 2) and is based on PWM to generate the sequence firing gate signals so as to turn
on/off the GTO switches in the STATCOM to satisfy the desired VAR compensation and
voltage stability. Essentially the control of the VAR compensator is by computing the voltage
difference between STATCOM AC output and AC system from which the STATCOM takes its
reference. It can control the DC voltage of the capacitor through a defined algorithm and hence
achieve the goal of controlling the output voltage as well as the VAR output of the STATCOM
at a pre-set level. The phase shift angle caused by the installed coupling transformer is also
considered to generate gating signals for corresponding GTOs’ on/off operation.
The major components in control include two parts: Voltage Control Loop Module and PWM
Control Module.
64
Voltage Control Loop
Voltage
RMS (p.u.)
B
Low Pass
90Hz Notch
120Hz Notch
Vref
+
1  sT1
1  sT2
3%
Droop
+
PI
Controller
A
B
A
Reactive
Power (p.u.)
Angle
Shift
Figure 4.4 Voltage Control Loop of STATCOM Control Module
The voltage control module of the STATCOM is shown in Figure 4.4. Reference signals are the
per unit values of voltage that STATCOM is connecting to the system and the RMS value of the
reactive power that the STATCOM exchanges with the system. The per-unit value of the reactive
current is calculated first. Then after going through the low pass filters employed by the 2nd
order transfer function, the voltage error is obtained to generate the phase shift angle for
STATCOM through a Lead-Lag controller and PI controller. The output of the PI controller is
the angle order, which represents the required angle shift between the voltage generated by the
STATCOM and the system voltage based on the voltage error. The angle shift will determine the
direction and amount of real power and reactive flow between STATCOM and the AC system.
PWM Control Module
In PWM control module, firing pulses for each GTO are generated by using comparison of
reference signals to triangular signals. There are two parts in the module to generate triangular
65
signals and reference signals, respectively. The final firing pulses are obtained from an
Interpolated Firing Pulses function.
Figure 4.5 PMW Control Module part 1
The first part of a PMW Control Module is shown in Figure 4.5. The function of part one of the
PWM control module is to generate triangular waveforms that are synchronized with the system
AC voltage. A three phase PI-Controlled Phase Locked Loop (PLL) is utilized to produce a
ramp slope signal θ that varies between 0 and 360° at the carrier frequency and is locked in
phase with system voltage Va. Its frequency is multiplied by the PWM switching frequency
(1980Hz which is 33 times the power frequency, hence the use of IGBT devices are more
appropriate than GTO devices) and converted to a triangular signal whose amplitude is fixed
between -1 and +1. Carrier signals are converted by two Non-Linear Transfer Characteristic
components. The outputs of each component are saved in the format of a one-dimensional
scalar array. They are the triangular signals that will be used to generate firing pulses in PMW
Control Module part 2. There are two arrays in the application, one is for saving the turn-on
triangular signals and the other is for saving turn-off triangular signals. PWM frequency (1980
66
Hz) in this work is chosen to be divisible by three. Hence it can be applied to each GTO valve
in this 6-pulse Voltage Source Converter.
(a)
(b)
Figure 4.6 PMW Control Module part 2
Part two of the PMW Control Module is shown in Fig. 4.6. The function of this second part of
PWM control module, including section (a) and section (b), is to obtain a firing pulse and the
67
time tag required for each GTO switch in order to do the interpolated switching. In section (a),
another three Phase Locked Loop component (PLL) is utilized to generate a ramp reference
signal θ in a six-dimension format. The ramp signal is the input of the trigonometric function
(Sin) after it is shifted a phase angle (30 degree) that is determined by the connected coupling
transformer with Y-Delta configuration. It generates the signals, RSgnOn and RSgnOff, which
are used as reference signals in section (b) of this module. In section (b), an Interpolated Firing
Pulses function is employed to generate turn-on and turn-off signals for each GTO. The inputs
of the function are two sets of arrays, triangular signals (TrgOn & TrgOff) created in PMW
Control Module part 1 and reference signals created in section (a). One set of signals is for
turning on and the second one (a negation of the first set of signals) is for turning off. In this
Interpolated Firing Pulses function, the comparison from PWM triangular carrier signals to
reference sinusoidal wave signals is achieved and gating pulses are generated at cross-over
points of both signals. As a result, two pulse signals are being sent to each GTO switch in the
form of a two-element array: The first output element is binary 0/1 and represents the actual
gate control pulse to control the switch; the second one determines the exact moment of
switching and is used by a interpolation procedure which allows for switching between time
steps.
4.1.3 Distance Protection Module
Modelling for protection is comprised of the following sub-modules to achieve the basic function
of a Mho characteristic, two zone distance relay.
For phase to ground distance protection:
68
Z=
V
Z 0  Z1
I
I0
Z1
(4.1)
For phase to phase distance protection:
Z=
Vm  Vn
Im  In
m  a, n  b;
m  b, n  c;
Where
(4.2)
m  c; n  a.
Three-phase
Voltages
Three-phase
Currents
FFT
Sequence
Filter
Vi
Z  Z1
Ii  0
I0
Z1
Sequence
Filter
i  a, b, c
FFT
Vm  V n
Im  In
m  a, n  b;
m  b, n  c;
m  c; n  a.
Single
Phase
Seen
Impedance
Phase to
Phase
Seen
Impedance
Figure 4.7 Distance Relay Module
A distance relay module is shown in Figure 4.7. In this module, both Line to Ground Impedance
component and Line to Line impedance component are built up. They can compute the line-to69
ground impedance and the line-to-line impedance seen by an impedance relay. The Mho
characteristic is chosen to determine whether the measured impedance is within the protective
zone. Inputs of the distance relay module are the current and voltage at the distance relay
installation point. The output of the distance relay is the tripping signal to the circuit breaker to
isolate the fault. It is logic 1 if the measured impedance is within the setting circle boundary,
otherwise the output is 0. The assigned breaker (Bs) in the simulation system is controlled to
open the circuit by the output logic 1 after a time delay. In the distance relay module, there are
two major sections to achieve the basic functions for Voltage & Current Signal Processing and
Distance Mho Characteristic.
Voltage & Current Signal Processing
v
1
2
3
vam vbm vcm
1
1
1
X1
X2
X3
vam
Mag1 Mag2 Mag3
(7)
(7)
(7)
Ph1
(7) 1
FFT
Ph2 vap
(7) 1
Ph3 vbp
F = 60.0 [Hz]
(7) 1
dc1 dc2 dc3
vcp
|A|
|P|
/_A
/_P
vap
vbm
vpp
|B|
/_B
vbp
vcm
vpm
A
B
C
+
0
|N|
vnp
|C|
|Z|
/_C
/_Z
vcp
vnm
/_N
vzm
vzp
Figure 4.8 Voltage Signal Processing
The Voltage Signal Processing procedure to get accurate sequence components of measured
voltage at the distance relay for impedance calculation is shown in Figure 4.8. An online Fast
Fourier Transform (FFT), a component that can determine the harmonic magnitude and phase
angle of the input signal as a function of time, is utilized to filter out the harmonics (including
70
the DC component) of the input voltage and to extract fundamental magnitudes and phases. This
component is meant for processing signals consisting of power frequencies (typically 50 Hz and
60 Hz) and its harmonics. As the distance protection is not designed to respond to high frequency
harmonics, maximum 7th harmonics in the component is chosen to satisfy the accuracy
requirement of the relay. From the FFT function, the magnitude and phase angle of the input
voltage at fundamental frequency in each phase can be obtained. In Figure 4.8 for example, for
phase A voltage, the output is vam (magnitude) and vap (phase angle). Afterwards, in a
Sequence Filter function, the three phase voltages filtered from FFT are decomposed into their
sequence component formats and are saved in arrays. Exactly the same functions and logics are
used for Current Signal processing. Then some other arrays to install the sequence component
formats of three phase currents can be created for the next steps of calculation.
Distance Mho Characteristic
VM
VP
IM
IP
I0M
R
Va
X
I + kI
a
21
R
X
0
I0P
Figure 4.9 Line-to-Ground Impedance and Mho Component
A component that computes the line-to-ground impedance as seen by a ground impedance relay
and a Mho component in PSCAD library are shown in Figure 4.9. The inputs of the function are
voltage magnitude & phase of the positive and zero sequence of current, and phase to ground
voltage on the faulty phase. The line-to-ground impedance component produces the resistance
71
and reactance of the calculated impedance, which work as inputs of the Mho component. In the
Mho component, the comparison is made between calculated impedance and the pre-set Mho
circle. Depending on whether the calculated impedance is within the Mho circle or not, the
output of the Mho component is given as 1 or 0.
VM1
VP1
IM1
IP1
VM2
VP2
Va - Vb
Ia - Ib
R
X
R
21
X
IM2
IP2
Figure 4.10 Line-to-Line Impedance and Mho Component
A line-to-line impedance component that computes the phase to phase impedance as measured
by a relay and a Mho component are shown in Figure 4.10. The structure of the function is
similar to the Line-to-Ground Impedance and Mho component just discussed. The inputs of the
line-to-line impedance component are voltages and currents from two different phases. The
output function is either 1 or 0 depending on the comparison between pre-set Mho circle and the
calculated impedance.
In the simulation, two distance protection zones have been applied with the following settings.
The complete impedance of the transmission line as per the modulation is:
|Z1|=215.04 Ω
θ=78.59°
|Z0|=577.74 Ω
θ= 72.34°
Hence
K=
= 1.50
(4.3)
72
Zone 1:
The setting of zone 1 is set to cover 85% of the transmission line
Hence the setting of Zone 1 is
|Z1|= 178.55Ω
θ=78.52°
Instantaneous Trip
Zone 2
The setting of Zone 2 is set to cover 120% of the transmission line with the time delay of 0.35s
|Z2|=252.07 Ω
θ=78.52°
T=0.35s
The protective zones based on the setting are programmed to be of a typical two-zone directional
Mho characteristic through origin in PSCAD system as follows.
Distance Relay Output
TIME
Ta0Z1
6
Tb0Z1
Tc0Z1
4
1
TabZ1
2
TbcZ1
3
TcaZ1
5
Z1_Trip
Delay
Trip
TIME
Ta0Z2
6
Tb0Z2
Tc0Z2
4
1
TabZ2
TbcZ2
2
3
TcaZ2
5
Z2_Trip
Delay
Figure 4.11 Distance Relay Output
73
The output of a two zone distance relay is shown in Figure 4.11. When the calculated impedance
value from voltage and current is within the preset Mho boundaries of the Zone1 or Zone 2 of the
relay, the output of the zone will be asserted to logic 1. In this distance protection module, there
are six phase-to-ground Mho components and six phase-to-phase Mho components, to achieve
the complete coverage of Zone1 and Zone2 for various fault detections. Outputs from both
Zone1 and Zone2, after adequate time delay respectively, have an ‘OR” operation and the
outcome is sent to trip the main breaker (Bs) to isolate the fault from the system.
4.2 Fault Simulations
The installation position of the STATCOM in the transmission system has a significant influence
on distance tripping performance. In this work, three installation locations are considered as
follows: midpoint of transmission line, near end bus (Bus 1) and far end bus (Bus2). The desired
voltage level of STATCOM output is set to be 1.0 p.u. In this simulation, in order to have a
better illustration of the impedance trajectories that the relay detects, the main breaker (Bs) is
always kept close even though the tripping signal is received. All the faults are set to apply to the
system at 0.2s from the start of the simulation and last 0.5s only, and all the faults are set to
occur at 75% length of the line from near end bus (Bus 1).
The behaviour of the distance relay that is installed next to Bus 1 is to be studied. As per the
setting of Zone 1 of the distance relay, the reach of the zone is to cover 85% length of the
transmission line. While for Zone 2, the reach boundary is up to 120% of the transmission line.
In each of the following figures (Figure 4.12 through Figure 4.17), the Mho circles for Zone1
and Zone2 are presented. For phase to ground fault (A-G), the trajectory of the measured
impedance on faulty phase is shown. For Phase to Phase fault (BC-G and A-B), the trajectories
74
of the measured impedances on two faulty phases are shown. It is the same presentation in Three
Phase fault (A-B-C) as the trajectories of the measured impedance on three fault phases are
shown. With various faults, in the case there is no STATCOM installed, the distance relay should
pick up with Zone 1. However, with the installation of STATCOM, the apparent impedance the
relay detects is off the Mho circle when it should be within. This represents mis-operation of the
distance relay.
4.2.1 Midpoint connected STATCOM simulation
For a midpoint connected STATCOM transmission system, three different types of faults are
considered with two different fault resistance values 0 Ω and 50 Ω. Comparative results are
shown in Figs. 4.12 through 4.14. For an easy illustration, all the diagrams are shown in a pattern
that the measured impedance trajectory without STATCOM in the simulation is on left and the
one with STATCOM is on right. It also needs to be noted that in the simulations the 0 Ω of
ground fault resistance is set to be 0.01 Ω due to the constraint of the PSCAD software. From the
analysis made in chapter 3 and the previous work in referenced papers, STATCOM connecting
at the midpoint of the transmission line has a significant influence on the tripping characteristic
of a Mho distance relay. From all simulations, both overreaching and under-reaching of the
distance relay has occurred in different fault conditions.
75
Fault resistance is 0 Ω
X Coordinate
Y Coordinate
X Coordinate
Y Coordinate
Ra
Xa
Ra
Xa
Rcircle2
Xcircle2
Rcircle2
Xcircle2
Rcircle1
Xcircle1
Rcircle1
Xcircle1
+y
+y
300
300
200
200
100
100
0
-x
+x
0
-x
+x
-y
-y
-100
0
100
200
-100
300
0
100
200
300
Figure 4.12 Measured Impedance for Single phase ground (A-G) fault
X Coordinate
Y Coordinate
X Coordinate
Y Coordinate
Rcircle1
Xcircle1
Rcircle1
Xcircle1
Rbc
Xbc
Rbc
Xbc
Rca
Xca
Rca
Xca
+y
+y
300
300
200
200
100
100
0
-x
+x
0
-x
+x
-y
-y
-200
-100
0
100
200
-200
300
-100
(a) Phase to Phase impedance
76
0
100
200
300
X Coordinate
Y Coordinate
X Coordinate
Y Coordinate
Rcircle1
Xcircle1
Rcircle1
Xcircle1
Rb
Xb
Rb
Rc
Xc
Rc
Xb
Xc
+y
+y
300
300
200
200
100
100
0
-x
+x
0
-x
+x
-y
-100
-y
0
100
200
300
-100
0
100
200
300
(b) Phase to ground impedance
Figure 4.13 Measured Impedance for Phase-Phase-ground (BC-G) fault
X Coordinate
Y Coordinate
Rcircle2
Xcircle2
Rcircle1
Xcircle1
Rbc
X Coordinate
Y Coordinate
Rcircle2
Xcircle2
Rcircle1
Xcircle1
Rbc
Xbc
Xbc
+y
+y
300
300
200
200
100
100
0
-x
+x
0
-x
+x
-y
-200
-100
0
-y
100
200
300
-200
-100
0
100
200
300
Figure 4.14 Measured Impedance for Three Phase (A-B-C) fault
It can be observed from Figures 4.12 through 4.14 that the resistance and reactance of the
apparent impedance of the transmission line with installed STATCOM is changed and thus the
77
trajectories of impedance curve are out of Zone 1 Mho boundary in every single case. This
causes under-reaching of the distance relay because the actual reach of the distance protective
Zone 1 decreases due to the presence of STATCOM in the system. It is shown that in the single
phase to ground fault case, both resistance and reactance measured by the relay increase with the
connection of the STATCOM. It is worth mentioning, however, that in the case of a phase to
phase fault, the measured reactance of the relay decreases while resistance still increases when
the STATCOM is connected.
Fault resistance is 50 Ω
By keeping the rest of the settings of the simulation unchanged, some tests following the same
testing procedures were run and the results were recorded in Figures 4.15 through 4.17. The
results show that, due to the high resistance of the fault, over-reaching of distance relay is present
in the some simulations.
X Coordinate
Y Coordinate
X Coordinate
Y Coordinate
Ra
Xa
Ra
Xa
Rcircle2
Xcircle2
Rcircle2
Xcircle2
Rcircle1
Xcircle1
Rcircle1
Xcircle1
+y
+y
300
300
200
200
100
100
0
-x
+x
0
-x
+x
-y
-100
0
-y
100
200
300
-100
0
100
200
Figure 4.15 Measured Impedance for Single Phase Ground (A-G) fault
78
300
In Figure 4.15, single phase to ground fault shot shows that Zone 2 of the distance relay has an
over-reach when the STATCOM is present in the fault loop. When the fault resistance is big, in
normal conditions without STATCOM in the circuit, either Zone1 or Zone 2 of the distance relay
cannot detect the fault. This is shown in the left figure. In comparison, when a STATCOM is
present in the fault circuit, Zone 2 of the distance relay mistakenly detects the fault.
X Coordinate
X Coordinate
Y Coordinate
Ra
Y Coordinate
Ra
Xa
Rcircle2
Xcircle2
Rcircle1
Xcircle1
Xa
Rcircle2
Xcircle2
Rcircle1
Xcircle1
+y
+y
300
300
200
200
100
100
0
-x
+x
0
-x
+x
-y
-y
-100
0
100
200
300
-100
0
100
200
300
(a) Phase to ground impedance
X Coordinate
Y Coordinate
X Coordinate
Y Coordinate
Rcircle2
Xcircle2
Rcircle2
Xcircle2
Rcircle1
Xcircle1
Rcircle1
Xcircle1
Rbc
Xbc
Rbc
Xbc
+y
+y
300
300
200
200
100
100
0
-x
+x
0
-x
+x
-y
-y
-200
-100
0
100
200
300
-200
-100
0
100
200
300
(b) Phase to Phase impedance
Figure 4.16 Measured Impedance for Phase-Phase-ground (BC-G) fault
79
X Coordinate
Y Coordinate
X Coordinate
Y Coordinate
Rcircle2
Xcircle2
Rcircle2
Xcircle2
Rcircle1
Xcircle1
Rcircle1
Rbc
Xbc
Rbc
Xcircle1
Xbc
+y
+y
300
300
200
200
100
100
0
-x
+x
0
-x
+x
-y
-y
-200
-100
0
100
200
300
-200
-100
0
100
200
300
Figure 4.17 Measured Impedance for Three Phase (A-B-C) fault
Figures 4.16 and 4.17 show the same test results that a distance relay is over-reaching at phasephase to ground fault and three-phase to ground fault conditions.
The reason of Over-reaching of distance relay is as follows:
The over-reach phenomenon to Zone 2 of the distance relay is caused by the fact that the
reactive power the STATCOM injected to AC power system turned negative during the fault
period. The reactive powers sent from STATCOM to AC system in different simulations are
shown in Figures 4.18 through 4.20, respectively. The analysis on the reactive current/power
direction was made in Chapter 3, which is validated with the tests here.
80
1.50
st Reactive Pow er
Sending Reactive Pow er
1.00
y (MVAR)
0.50
0.00
-0.50
-1.00
-1.50
-2.00
Figure 4.18 Reactive Power from STATCOM for Single Phase Ground (A-G) fault
2.00
st Reactive Pow er
Sending Reactive Pow er
1.50
1.00
y (MVAR)
0.50
0.00
-0.50
-1.00
-1.50
-2.00
-2.50
Figure 4.19 Reactive Power from STATCOM for Phase-Phase-Ground (BC-G) fault
12.0
st Reactive Pow er
Sending Reactive Pow er
10.0
8.0
y (MVAR)
6.0
4.0
2.0
0.0
-2.0
-4.0
Figure 4.20 Reactive Power from STATCOM for Three Phase (A-B-C) fault
81
4.2.2 Near-end bus connected STATCOM simulation
For a near end bus (Sending Bus1) connected STATCOM transmission system, by following the
same test procedures with three different types of faults and fault resistance value 0 Ω, the
comparisons are shown in Figures 4.21 through 4.23.
X Coordinate
Y Coordinate
Rcircle1
Xcircle1
Rb
Xb
Rc
Xc
X Coordinate
Y Coordinate
Rcircle1
Xcircle1
Rb
Xb
Rc
Xc
+y
+y
300
300
200
200
100
100
0
-x
+x
0
-y
-100
-200
-100
0
-x
+x
-y
-100
100
200
-200
300
-100
0
100
200
300
Figure 4.21 Measured Impedance for Single phase ground (A-G) fault
X Coordinate
Y Coordinate
X Coordinate
Y Coordinate
Rcircle1
Xcircle1
Rcircle1
Xcircle1
Rb
Xb
Rb
Rc
Xc
Rc
Xb
Xc
+y
+y
300
300
200
200
100
100
0
-x
+x
-y
-100
-200
-100
0
0
-x
+x
-y
-100
100
200
-200
300
(a) Phase to ground impedance
82
-100
0
100
200
300
X Coordinate
Y Coordinate
X Coordinate
Y Coordinate
Rcircle1
Xcircle1
Rcircle1
Xcircle1
Rbc
Xbc
Rbc
Rca
Xca
Rca
Xbc
Xca
+y
+y
300
300
200
200
100
100
0
-x
+x
0
-x
+x
-y
-200
-100
-y
0
100
200
300
-200
-100
0
100
200
300
(b) Phase to Phase impedance
Figure 4.22 Measured Impedance for Phase-Phase-ground (BC-G) fault
X Coordinate
Y Coordinate
X Coordinate
Y Coordinate
Rcircle1
Xcircle1
Rcircle1
Xcircle1
Rbc
Xbc
Rbc
Rca
Xca
Rca
Xbc
Xca
+y
+y
300
300
200
200
100
100
0
-x
+x
0
-x
+x
-y
-y
-200
-100
0
100
200
-200
300
-100
0
100
200
300
Figure 4.23 Measured Impedance for Three Phase (A-B-C) fault
In the simulations shown in Figures 4.21 through 4.23, since the STATCOM is installed on Bus
1 and the relay measuring CTs are installed at the starting point of the transmission line after the
STATCOM, when there is a fault located at 75% length of the transmission line, the STATCOM
83
actually is not in the circuit that the distance relay protects due to its directional characteristic.
Hence the apparent impedance measured by the relay is equal to the actual impedance of the
transmission line section from relay point to fault point and is rarely affected by the reactive
power injection from the STATCOM. It can be observed from the distance relay measured
impedance trajectories in all cases and it is consistent with the analysis in Chapter 3.
4.2.3 Far-end bus connected STATCOM simulation
For a far end bus (Bus2) connected STATCOM transmission system, by following the same test
procedures with three different types of faults and fault resistance value 0 Ω, the comparisons
are shown in Figures 4.24 through 4.26.
X Coordinate
Y Coordinate
X Coordinate
Y Coordinate
Rcircle1
Xcircle1
Rcircle1
Xcircle1
Rb
Xb
Rb
Xb
Rc
Xc
Rc
Xc
+y
+y
300
300
200
200
100
100
0
-x
+x
0
-y
-100
-200
-100
0
-x
+x
-y
-100
100
200
-200
300
-100
0
100
200
Figure 4.24 Measured Impedance for Single phase ground (A-G) fault
84
300
X Coordinate
Y Coordinate
X Coordinate
Y Coordinate
Rcircle1
Xcircle1
Rcircle1
Xcircle1
Rb
Xb
Rb
Xb
Rc
Xc
Rc
Xc
+y
+y
300
300
200
200
100
100
0
-x
+x
0
-y
-100
-200
-100
-x
+x
-y
-100
0
100
200
-200
300
-100
0
100
200
300
(a) Phase to ground impedance
X Coordinate
Y Coordinate
X Coordinate
Y Coordinate
Rcircle1
Xcircle1
Rcircle1
Xcircle1
Rbc
Xbc
Rbc
Xbc
Rca
Xca
Rca
Xca
+y
+y
300
300
200
200
100
100
0
-x
+x
0
-x
+x
-y
-200
-100
0
-y
100
200
300
-200
-100
0
100
200
(b) Phase to Phase impedance
Figure 4.25 Measured Impedance for Phase-Phase-ground (BC-G) fault
85
300
X Coordinate
Y Coordinate
X Coordinate
Y Coordinate
Rcircle1
Xcircle1
Rcircle1
Xcircle1
Rbc
Xbc
Rbc
Xbc
Rca
Xca
Rca
Xca
+y
+y
300
300
200
200
100
100
0
-x
+x
0
-x
+x
-y
-200
-100
0
-y
100
200
300
-200
-100
0
100
200
300
Figure 4.26 Measured Impedance for Three Phase (A-B-C) fault
In the simulations shown in Figures 4.24 through 4.26, the STATCOM is installed at the far end
bus (Bus 2) of the system, where it is out of the reach of Zone 1 but still within Zone 2 of the
distance relay. When there is a fault located at 75% length of the transmission line, the
STATCOM actually is in the circuit that the distance relay protects and hence the apparent
impedance measured by the relay should deviate from the actual impedance of the transmission
line section that is from relay point to fault point. In this case, the STATCOM actually is out of
the Zone 1 coverage. As per the analysis and equation 3.21 in Chapter 3, Zone 1 protection in
this case should function normally. Zone 2 protection should have under-reaching per analysis in
section 4.21. Simulation studies in Figures 4.24 through 4.26 show that zone 1 protections does
not change at all in these tests and there is small offset on the trajectories of measured impedance
by zone 2 protection in all cases. Thus as a conclusion, when a STATCOM is installed at
transmission line receiving end, the impedance measured by Zone 2 of distance relay is with
errors, but Zone 1 protection is still reliable. The distance scheme still functions well to protect
86
the transmission line under all fault conditions but additional backup protection is needed to
cover 100% of the line.
4.2.4 Effect of Voltage Setting of STATCOM
All the above tests are run with the STATCOM voltage setting at 1.0 p.u. The maximum reactive
power injected from STATCOM to AC system is less than 12 MVAR in order to maintain the
pre-set 1.0 p.u. voltage in various fault conditions. Behaviour of a distance relay when the
STATCOM compensation voltage is set at different levels at a midpoint connected system for
various fault conditions (A-G, BC-G and ABC) is discussed in this section. The tests results are
recorded as follows in a pattern from left to right where the reference voltage of STATCOM (Vref
) is set at 1.0 p.u., 0.9 p.u. and 1.1 p.u., respectively.
X Coordinate
Y Coordinate
X Coordinate
Ra
Xa
Rcircle1
Xcircle1
Rcircle1
Rcircle2
Xcircle2
Rb
Xb
Rb
Rcircle1
Xcircle1
Rc
Xc
Rc
X Coordinate
Y Coordinate
Y Coordinate
Xcircle1
Xb
Xc
+y
+y
+y
300
200
200
100
100
200
100
0
0
-x
-x
+x
-x
0
+x
+x
-y
-y
-y
-100
0
100
200
-200
300
-100
0
100
-200
200
-100
0
100
200
Figure 4.27 Measured Impedance for A-G fault Vref = 1.0 p.u, 0.9 p.u and 1.1 p.u
X Coordinate
Y Coordinate
X Coordinate
Y Coordinate
X Coordinate
Y Coordinate
Rcircle1
Xcircle1
Rcircle1
Xcircle1
Rcircle1
Xcircle1
Rbc
Xbc
Rbc
Xbc
Rbc
Rca
Xca
Rca
Xca
Rca
Xbc
Xca
+y
+y
+y
300
200
200
200
100
100
100
0
0
-x
-y
-200
-x
+x
+x
-100
0
0
-100
100
200
-x
+x
-y
-200
-100
0
-y
100
200
300
-200
-100
0
100
200
Figure 4.28 Measured Impedance for BC-G fault Vref = 1.0 p.u, 0.9 p.u and 1.1 p.u
87
X Coordinate
Y Coordinate
X Coordinate
Y Coordinate
X Coordinate
Y Coordinate
Rcircle1
Xcircle1
Rcircle1
Xcircle1
Rcircle1
Xcircle1
Rbc
Xbc
Rbc
Xbc
Rbc
Rca
Xca
Rca
Xca
Rca
300
300
200
200
200
100
100
100
-x
+x
0
-y
-100
-200
-100
Xca
+y
300
0
Xbc
+y
+y
-x
+x
-y
-100
0
100
200
0
-200
300
-100
-x
+x
-y
-100
0
100
200
300
-200
-100
0
100
200
300
Figure 4.29 Phase to Phase Seen impedance for ABC-G fault Vref = 1.0 p.u, 0.9 p.u and 1.1 p.u
X Coordinate
Y Coordinate
X Coordinate
Rcircle1
Xcircle1
Rcircle1
Rbc
Xbc
Rbc
Rca
Xca
Rca
Y Coordinate
Xcircle1
200
100
100
100
-x
+x
-y
0
Xca
+y
200
-100
Xbc
Rca
200
-200
Xcircle1
Rbc
300
-100
Y Coordinate
Rcircle1
Xca
+y
300
0
X Coordinate
Xbc
+y
0
300
-x
+x
-y
-100
100
200
300
-200
-100
0
0
-x
+x
-y
-100
100
200
300
-200
-100
0
100
200
300
Figure 4.30 Measured Impedance for ABC fault Vref = 1.0 p.u, 0.9 p.u and 1.1 p.u
As described before in Chapter 3, when reactive power is injected into the system (the shunt
current from STATCOM to the system), the apparent impedance seen by a distance relay is
bigger. This will lead to the under-reaching of a distance relay. Likewise, when the STATCOM
consumes reactive power from the AC system, over-reaching of a distance protection occurs.
However, it is easy to conclude from the comparison of the trajectories of the measured
impedance of the distance relay in Figures 4.27 through 4.30 that the voltage settings of
STATCOM have less effect on the measured impedance of a distance relay. This happens
because in the application the different reference settings of STATCOM are in a regular range,
88
which causes the exchange of the reactive power between the system and STATCOM to be
small (less than 3.8 MVAR from tests) and thus the shunt current Ist
is relatively small
compared to Irelay. Hence the setting of reference voltage of a STATCOM is not sensitive to a
distance relay in application and has no significant effect on the distance relay behaviour.
Reactive Power from STATCOM
System : Reactive Pow er
4.0
st Reactive Pow er
Sending Reactive Pow er
3.0
y (MVAR)
2.0
1.0
0.0
-1.0
-2.0
0.00
0.10
0.20
0.30
0.40
0.50
0.60
0.70
0.80
0.90
1.00
...
...
...
0.90
1.00
...
...
...
Figure 4.31 Reactive Power Vref = 1.1 p.u
System : Reactive Pow er
4.0
st Reactive Pow er
Sending Reactive Pow er
3.0
y (MVAR)
2.0
1.0
0.0
-1.0
-2.0
0.00
0.10
0.20
0.30
0.40
0.50
0.60
0.70
0.80
Figure 4.32 Reactive Power Vref = 0.9 p.u
89
Reactive power exchange between STATCOM and the AC system is shown in Figures 4.31 and
4.32 for the case of a three-phase to ground fault condition. If the STATCOM is set at 1.1 p.u,
during the fault time between 02s to 0.7s, the STATCOM is sending the reactive power to the
system to support the voltage. In contrary, when the STATCOM is set at 0.9p.u, the
STATCOM is sending capacitive power to the system during the fault period.
4.3 Concluding Remarks
In this chapter, a simulation system for a two-terminal power transmission line is built up along
with a STATCOM shunt connected to the transmission line.
Various system components
utilized in the work and their basic functions in different modules are introduced first.
Simulations of different types of faults and STATCOM installation locations on the system are
conducted, based on which analysis and comparison of the behaviour of a distance relay in
different fault conditions are made. The test results are consistent with the analysis made in
Chapter 3. Also, a study on how the voltage setting of a STATCOM affects a distance relay is
conducted and from the tests, no significant influence is observed.
The built-up system simulation module is also ready for future analysis in order to study
adequate solutions to conquer the mis-operation of a distance relay on a transmission line when it
is shunt-compensated by a STATCOM.
90
Chapter Five: Communication-aided Distance Protection Schemes
As discussed, in the case of STATCOM installed at midpoint of a transmission line, the
protection zone of a traditional distance relay will either under-reach or over-reach when faults
occur between the midpoint and remote terminal. A pilot protection relay scheme can be utilized
to help the distance relay keep its tripping accuracy and reliability.
A pilot scheme [3], also known as Teleprotection (TPR), relies on relay communication channels
sending information of a local relay to the remote end relay so as to protect 100% length of the
transmission line. It will allow high speed tripping on faults occurring on the transmission line.
The information exchange between two terminals can be currents, permissive signals and
blocking signals. PLC (Power Line Carrier), microwave and fiber optic can be applied as the
communication media. In the application where a STATCOM is installed on a transmission line,
either current comparison schemes or directional schemes can be used to eliminate the misoperation of the distance relay. Directional comparison schemes send fault current directional
information between the terminals. Current comparison systems send information related to
current phase angle or magnitude of the current between the two replay locations.
5.1 Directional Comparison Scheme
Various types of directional comparison schemes that use the inherent directional characteristic
of a distance relay to make up complex and secure protection of the transmission line have been
proposed [1][3]. In the case with a STATCOM installed on the transmission line, the distance
91
protection still can function well with proper logic setup and the transferring of permissive
signals or blocking signals.
5.1.1 Permissive Transfer Trip
A distance relay with permissive signal can be used to provide a reliable protection scheme for a
two-terminal transmission line in applications with security and selectivity. The communicationaided distance protection scheme can initiate fast clearing for faults that occur at any point on the
transmission line and reduce either the under-reaching or over-reaching of the distance
measurement [1]. The schemes require permissive transfer signals from one terminal to the other.
Based on this principle, the distance protection schemes can make Permissive Overreach
Transfer Trip (POTT) and Permissive Underreach Transfer Trip (PUTT).
Permissive Overreach Transfer Trip (POTT)
(a) Permissive overreach scheme
92
(b) Logic diagram
Figure 5.1 Permissive Overreach Protection Scheme and Logic diagram
The logic of a permissive overreach distance protection scheme is shown in Figure 5.1. In this
scheme, it is expected that both ends of the transmission line have matching distance relays
installed. Zone 2 of the distance relay is utilized to initiate the permissive signals through
communication channel to the remote substation when a fault occurs in the protection zone.
Upon receiving the permissive signal, distance relay at the remote end will open the breaker in
the substation when its zone 2 protection picks up in conjunction with the received signal. If a
fault is between the STATCOM and the remote end, Sub 3, as shown in the Figure 5.1(a), per
previous discussion, the under-reaching of a distance relay will happen with a STATCOM
installed at the mid-point of the transmission line. Zone 1 of the distance relay at Sub 3 will open
the local breaker; at the same time zone 2 of the distance relay at Sub 3 will pick up and send a
permissive signal to the distance relay at Sub 2. At Sub 2, zone 1 of the distance relay is not
reliable to pick up for the faults, but zone 2 will trip the local breaker after the “AND” operation
on receipt of the transmitted signal. Time delay for normal zone 2 protection is bypassed. The
fault then is cleared in the system from both ends and the mis-operation of the distance
93
protection can be avoided for the fault. As zone 2 of the distance relay is utilized in this POTT
scheme to send transfer signals and it is set further than remote terminal, it may cause
coordination problems for zone 2 and zone 3, especially on a short transmission line. For a
transmission line with a STATCOM installed at mid-point, a POTT scheme helps but is not the
most suitable when the overall factors are considered.
The following is the outcome of a POTT scheme in the simulation to verify the proper
functionality of the protection scheme in the power transmission system with a STATCOM
installed.
X Coordinate
Y Coordinate
Rcircle1
Xcircle1
Rb
Xb
Rc
Xc
+y
300
200
100
0
-x
+x
-100
-y
-200
-100
0
100
200
300
Figure 5.2 Impedance measured at the sending end for an A-G fault without STATCOM
94
X Coordinate
Y Coordinate
Rcircle1
Xcircle1
Rbc
Xbc
Rca
Xca
+y
300
200
100
-x
0
+x
-y
-100
-200
-100
0
100
200
300
Figure 5.3 Measured impedance at the sending end for an A-G fault with STATCOM
X Coordinate
Y Coordinate
Ra2
Xa2
Rb2
Xb2
Rc2
Xc2
+y
300
200
100
0
-x
+x
-y
-300
-200
-100
0
100
200
300
Figure 5.4 Impedance measured by the receiving end relay for an A-G fault with STATCOM
95
Tripping trajectories for the two distance relays in the STATCOM-installed transmission line
system when a single phase fault (A-G) occurs at 75% of the line from the sending end, power
source 1, are shown in Figure 5.2 through 5.4. The relay correctly detects the fault in zone 1 and
zone 2 when there is no STATCOM installed in the system as shown in Figure. 5.2. Figure 5.3
shows the under-reaching of the relay when the same fault occurs but a STATCOM is connected
at the mid-point. In this case, zone 1 does not detect the fault due to the impedance of the
STATCOM and the tripping curve falling into zone 2 only. The tripping trajectory of the
distance relay at the receiving end in the transmission line system for the same fault is shown in
Figure 5.4. Both zone 1 and zone 2 of the relay can detect the fault when the STATCOM is
installed
Figure 5.5 Timing for POTT scheme
96
Figure 5.5 is also from system simulation to show distance zone element pickup and tripping
intervals of two distance relays at both ends of a transmission line in the POTT scheme. It shows
how the POTT scheme works fast to clear the fault at the sending end when under-reaching
occurs. In the simulation, the fault begins at 0.2s and lasts for 0.5s. When the fault occurs, zone 1
at the sending end relay does not detect the fault; hence the Z1_PU is not picked up. The zone 2
of the same relay will trip the breaker with a pre-set time delay 0.35s. In the POTT scheme, zone
2 of the receiving end relay detects the fault instantly (R_Z2_PU is picked up) and sends the
permissive transfer trip to the sending end relay, then Z1_Trip picks up and the relay operates to
clear the fault in a very short time 0.05s. The time delay 0.05s shown between the dotted lines X
and O on the diagram is caused by the communication channel and telecom equipment response
time. The tripping of the distance relay, Z2_Trip, is obviously accelerated compared to the time
delay of 0.35s from zone 2.
Permissive Underreach Transfer Trip (PUTT)
(a) Permissive underreach scheme
97
(b) Logic diagram
Figure 5.6 Permissive Under-reach Protection Scheme and Logic diagram
A PUTT scheme and its logic are shown in Figure 5.6. Similar to a POTT scheme, both ends of
the transmission line should have the matching distance relays installed. In this scheme, zone 1,
instead of zone 2, of the distance relay is utilized to initiate the permissive signals through
communication channel to the remote substation when there is a fault detected in the protection
zone. The distance relay at the remote end will open the breaker in the substation with the pickup
of its zone 2 protection and the received signal. For a fault shown in Fig. 5.6(a), zone 1 of the
distance relay at Sub 3 will pick up to trip the local breaker and at the same time to send a
permissive signal to the distance relay at Sub 2. At Sub 2, zone 2 of the distance relay trips the
local breaker after the “AND” operation on receipt of the transmitted signal. Zone 1 is normally
set to protect 85% of the transmission line (L23) and in this scheme it is chosen to send transfer
signals. For faults between one terminal (Sub 3) and the mid-point installed STATCOM, the
distance relay at this end (Sub 3) performs normally. At the remote end (Sub 2), zone 1 of the
distance relay will mis-operate as per the previous discussion. Zone 2 protection will pick up for
the fault as the setting of zone 2 is set to protect 120% of the transmission line. Then the fault
98
will be cleared out in the system from both terminals. The PUTT scheme is suitable for long
transmission lines, but setting coordination is needed for zone 2 and zone 3 without any major
conflicts. The scheme can provide fast fault clearing for the full length of the protected line with
the STATCOM installed and make a reliable protection scheme in this application.
The outcome of a PUTT scheme in the simulation to verify the proper functionality of the
protection scheme in the power transmission system with a STATCOM installed at mid-point is
shown in Figures 5.7 through 5.9.
X Coordinate
Y Coordinate
Rcircle2
Xcircle2
Rcircle1
Xcircle1
Rbc
Xbc
+y
300
200
100
0
-x
+x
-y
-200
-100
0
100
200
300
400
Figure 5.7 Measured impedance at the sending end for an ABC-G fault without STATCOM
99
X Coordinate
Y Coordinate
Rcircle2
Xcircle2
Rcircle1
Xcircle1
Rbc
Xbc
+y
300
200
100
0
-x
+x
-y
-200
-100
0
100
200
300
400
Figure 5.8 Measured impedance at the sending end for an ABC-G fault with STATCOM
X Coordinate
Y Coordinate
Ra2
Xa2
Rb2
Xb2
Rc2
Xc2
+y
300
200
100
0
-x
+x
-y
-300
-200
-100
0
100
200
300
Figure 5.9 Impedance measured by the receiving end relay for an ABC-G fault with STATCOM
100
The tripping trajectories for the distance relay at the sending end in the STATCOM-installed
transmission line system when a three-phase to ground fault (ABC-G) occurs at 75% of the line
from the power source 1 are shown in Figures 5.7 and 5.8. Figure 5.7 shows the relay correctly
detects the fault in zone 1 and zone 2 when there is no STATCOM installed in the system. The
under-reaching of the relay when the same fault occurs but with STATCOM connected at the
mid-point is shown in Figure 5.8. In this case, the detection of zone 1 on the fault is not reliable
due to the impedance of the STATCOM and most of the tripping curve falls into zone 2. Figure
5.9 shows the tripping trajectory of the distance relay at the receiving end with the STATCOMinstalled transmission line system when the same fault occurs. Both zone 1 and zone 2 of the
relay detect the fault correctly.
Z1_PU
0: 0.000
Z2_PU
0: 0.000
Z2_Trip
0: 0.000
R_Z1_PU
0: 1.000
Figure 5.10 Timing for PUTT scheme
The distance zone elements pickup and tripping intervals of the two distance relays at both ends
of a transmission line in the PUTT scheme as obtained from the system simulation studies are
shown in Fig. 5.10. It shows how the PUTT scheme works fast to clear the fault at the sending
101
end when overreach occurs. In the simulation system, the fault begins at 0.2s of the timing and
lasts for 0.5s. When the fault occurs, the detections of both zone 1 and zone 2 at the sending end
relay is not reliable as the Z1_PU and Z2_PU picks up and drops off rapidly. In the PUTT
scheme, zone 1 of the receiving end relay detects the fault instantly (R_Z1_PU is picked up) and
sends the permissive transfer trip to the sending end relay, where Z2_Trip picks up and relay
operates to clear the fault in a very short time 0.05s. The time delay of 0.05s shown between the
dotted lines X and O on the diagram presents response time of the communication channel and
telecom equipment. As shown in the figure, the tripping of the distance relay at the sending end,
Z2_trip, is fast and reliable enough to clear the fault in the system.
5.1.2 Directional Comparison Blocking (DCB)
(a) DCB scheme
102
(b) Logic diagram
Figure 5.11 Directional Comparison Blocking Protection Scheme and Logic diagram
DCB scheme and its logic are shown in Figure 5.11. The basic operation logic of the scheme is
that upon the receipt of a block signal from reverse zone protection at the remote end, the output
of the accelerated zone 2 protection of the local distance relay is blocked with proper setting to
prevent tripping of the local breaker [3].
For a fault shown in Figure 5.11, both zone 1 and zone 2 of the distance relay at Sub 3 will pick
up, and zone 1 will trip the local breaker instantaneously. There is an additional protection
covering reverse direction (towards Sub 4). This additional protection can be either directional
ground fault or normal distance protection. A status of the reverse zone protection is sent to the
remote terminal, Sub 2, as a blocking signal. At Sub 2, as discussed before, zone 1 is not reliable
for this fault but zone 2 can pick up and initiate a normal trip to the local breaker through a timer
T2. Meanwhile, the pickup of zone 2 also initiates a different timer T4, which is set much shorter
than T2. The output of T4 has an “AND” operation with the NOT receipt of the reserve zone
protection from terminal Sub3. If reverse zone protection at Sub 3 is not initiated, the output of
103
distance zone 2 at Sub 2 is able to open the local breaker through T4. On the other hand, if the
reverse zone protection is initiated at Sub 3, it means that the fault is not on the protected line
(L23), and then the transfer signal will be sent to Sub 2 to block the distance zone 2 accelerated
outputs.
Coordination of settings for distance zone 2, zone 3 and reverse zone is needed in this scheme
[33]. The coverage of Zone 2 of a distance relay is set to reach beyond the remote terminal,
normally 120% of the protected transmission line (L23). The blocking functions in the scheme
are initiated to detect faults that are not on the protected line but the remote end (Sub 2) zone 2
can detect. Therefore, the reverse zone at local substation (Sub 3) has to be set to reach further
than the zone 2 of the remote end (Sub 2) distance relay in the same direction.
The DCB scheme can provide fast and reliable fault clearance for the full length of the protected
transmission line, including a line with a STATCOM installed at mid-point. The deficiencies of a
distance relay in the application, either underreach or overreach, can be overcome with this
scheme.
The outcome of a DCB scheme in the simulation studies carried out to verify the proper
functionality of the protection scheme in the power transmission system with a STATCOM
installed at mid-point is shown in Figure 5.12.
104
X Coordinate
Y Coordinate
Rcircle1
Xcircle1
Rbc
Xbc
Rca
Xca
+y
300
200
100
0
-x
+x
-100
-y
-200
-100
0
100
200
300
400
Figure 5.12 Measured impedance for an ABC-G fault with STATCOM
The tripping trajectory for the distance relay at the sending end for a STATCOM-installed
transmission line system when a two-phase to ground fault (BC-G) occurs at 75% of the line
from the sending end, Sub 2, is shown in Figure 5.12. It can be observed from this figure that
zone 2 element of the distance relay is reliable while zone 1 protection is totally malfunctioned.
105
Figure 5.13 Trip timing for DCB scheme
Simulation results given in Figure 5.13 show how the DCB scheme on L23 works to clear the
fault at the sending end (Sub 2) and to eliminate the mis-operation of the distance relay when the
two-phase to ground fault (BC-G) occurs at 75% of the line from Sub 2. In the simulation system,
the fault begins at 0.2s and lasts for 0.5s. The diagram presents distance zone elements
pickup/tripping intervals of the distance relay at the sending end, Sub 2, of the transmission line.
When the fault occurs, the zone 2 element is very reliable and picks up instantly. In the DCB
scheme, reverse distance protection at the receiving end does not detect the fault (REV_PU is 0)
and sends the permissive transfer to the sending end relay, where Z2_T4 is asserted after a short
time delay (0.15s) to initiate the output of the relay, Trip, to clear the fault. The time delay
caused by the communication channel and telecom equipment response time is covered by the
time delay on Z2_T4. As shown in the figure, the accelerated tripping (Trip) of zone 2 of the
106
distance relay at the sending end is fast and reliable enough to clear the system fault in this DCB
scheme.
Figure 5.14 Block timing for DCB scheme
A case when the same fault (BC-G) is on the transmission line between Sub 3 and Sub 4, the
distance relay at Sub 2, is shown in Figure 5.14. The reverse direction protection at Sub 3 is
picked up (REV_PU=1) and transferred to Sub 2 to block the output of timer Z2_T4 at this
sending end. The zone 2 of the relay at Sub 2 can detect the fault and will clear the fault with the
normal time delay 0.35s. This time is shown between X and O in the diagram. Normally, there is
a distance relay installed at Sub 3 to protect the transmission line L34, the zone 1 of this relay
will open the breaker instantaneously to clear the fault. DCB scheme installed on L23 in this case
provides a solid backup protection for a fault out of its zone.
107
5.2 Line Current Differential
(a) Line differential current scheme
(b) Logic diagram
Figure 5.15 Line Differential Current Protection Scheme and Logic diagram
A line current differential scheme and its logic are shown in Figure 5.15. In the pilot scheme,
matching relays are needed at both ends for a true current differential measurement [3][4]. The
information compared can be either the phase angle or the magnitude of the currents from both
terminals of the transmission line. The internal faults are determined by the current differential
scheme when the current difference between the terminals is bigger than the set value. On a two-
108
terminal transmission line with a STATCOM installed, the scheme can operate on all the internal
faults between the two terminals and protect 100% of the transmission line. The scheme only
relies on currents to operate and does not need voltage inputs. Therefore, it is not affected by any
power system contingencies that cause the system voltage problems. Normally it is only used on
a short line with a big cost on telecommunication equipment [34]. A transmission line with a
STATCOM installed should be a long line that needs compensation, so the line current
differential scheme can work in this case but it is not the best choice to replace the distance
scheme.
5.3 Concluding Remarks
Different communication-aided protection schemes to improve the performance of the traditional
step distance relays in the case where a two-terminal transmission line is midpoint-compensated
using a STATCOM are discussed in this chapter. From the analysis and the system simulations,
it can be concluded that PUTT, with transfer permissive signals, is the best scheme for
application. DCB works well with the transferred block logic on zone 2 to clear the faults on the
line with which the distance zone1 has problems. A line current differential scheme is able to
protect all the internal faults on the line where there is a STATCOM. It is possible to replace the
distance relay but with a large communication equipment cost.
109
Chapter Six: Conclusions
6.1 Thesis Summary
The impact of a shunt connected FACTS device, the STATCOM, in a power transmission
system is investigated in terms of impedance protection. In particular, the impedance measured
by the distance relay protecting a transmission line compensated by a STATCOM is studied. A
model for a transmission line including a STATCOM and a distance protection scheme is built in
the PSCAD environment, in which various system fault conditions together with three
STATCOM installation locations are simulated. The Mho tripping characteristic of the distance
relay is analyzed in various contingent conditions. Both analysis and simulation results show that
the STATCOM installation location has a significant influence on the performance of the
distance relay. If the STATCOM is connected at the mid-point of the line, presence of the
STATCOM in the transmission line can cause malfunction of the distance relay. If the
STATCOM is installed at the sending end of the transmission line, the measured impedance of
the distance relay is not affected. In the cases when the STATCOM is installed at the receiving
end, the distance relay functions well with minimum errors. Voltage settings of the STATCOM
also are considered in the studies. However, no effect on the measured impedance of the distance
relay is detected when the voltage settings of the STATCOM are changed.
In order to overcome the mis-operation of the distance relay in the transmission line system, and
make the distance scheme operational and reliable when the transmission line is shunt
compensated using STATCOM, some communication-aided protection schemes are discussed.
Studies with different proposed schemes, including PUTT, POTT and DCB, are also conducted.
These pilot protection schemes are proved to be effective for fast clearance of the faults on the
110
transmission line and satisfy the basic requirement for protection speed and accuracy, regardless
of STATCOM installation location.
6.2 Discussion
A summary of the performance of a distance relay on a transmission line, where a shunt
STATCOM is connected at various installation points and the transmission system is exposed to
various fault conditions is presented in Section 6.1. In most applications the STATCOM is
installed at the mid-point of the transmission line and this configuration is discussed in more
detail.
It can be concluded from the results of simulation studies and analysis in this thesis that the
conventional distance relay cannot work well for a mid-point shunt STATCOM compensated
transmission line. Further details are given below:
1) The shunt connected STATCOM affect the protection zones, not only zone 1 on
compensated line, but also zone 2 or zone 3 of a distance relay on the nearby
transmission line.
2) When a distance relay acts as the main protection device for a high voltage transmission
line, communication-aided pilot protection schemes should be applied to eliminate the
malfunction of the distance relay.
3) In the communication-aided protection schemes, PUTT, POTT and DCB, can be utilized
to make fast and accurate protection of the transmission line compensated with a
STATCOM.
4) The voltage settings of the STATCOM, the fault type and fault resistance have little
influence on the impedance measurement of distance relay.
111
5) The distance relay is functional when a STATCOM is installed at the receiving end of the
transmission line, even though the relay tripping characteristics have minor errors (but
they are acceptable errors).
6) No detrimental effects are observed for the distance relay tripping characteristics when
the STATCOM is installed at transmission line sending end.
7) A transmission line current differential protection scheme can also ensure reliable
protection of the line compensated by a STATCOM but at a high cost. However, it is not
the best option to replace a distance scheme in the application considered in the thesis.
6.3 Future work
In the future, two approaches, i.e. pilot scheme and adaptive setting, should be investigated to
improve the performance of distance protection scheme for application to a transmission line
shunt compensated with a STATCOM, as briefly outlined below.
1. Communication-aided Distance Protection Schemes
a. These schemes rely on telecom technology and equipment to achieve protective
function, reliability and tripping latency.
b. With the development of telecom technology and new communication media,
other forms of pilot scheme depending on the Transfer Trip or Transfer Block
logic could be developed. Distance protection in the new scheme even could be
investigated with solid state logic and reliable equipment.
c. The transmission line differential scheme can be further improved if current
readings can be made available in the STATCOM switching yard.
112
2. Adaptive Distance Setting
Adaptive protection setting zones in the distance scheme could be utilized to mitigate the
miss-operation of a distance relay. Some adaptive distance settings in the conventional
relay are proposed to change the protective zones so as to cover the over-reach/underreach effect of the measured impedance caused by the STATCOM. New distance
protection can combine the information of the currents and breaker/switch status from the
STATCOM switching yard to make a setting group change or update algorithm for
accurate fault detection.
113
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