Protection System with FACTS Device Controllers to

Increase Power Transfer Capability

Achyar Maulana Pratama1, Erdi Nindito Rumono

2, Ginas Alvianingsih

3

1NPM: 1206201422,

2NPM: 1206201523,

3NPM: 1206201580

Departement of Electrical Engineering, Faculty of Engineering, University of Indonesia

Abstract—The aim of the paper is to study power flow control

through transmission lines and the protection system with

FACTS device. FACTS or flexible alternating current

transmission system is a system composed of static equipment

used for the AC transmission of electrical energy. It is meant to

enhance controllability and increase power transfer capability of

the network. It is generally a power electronics-based system.

Index Terms—digital relay; Flexible AC transmission systems

(FACTS) device controllers; power electronics; power flow control;

transient stability; transmission line.

I. INTRODUCTION

Flexibility of electric power transmission is the ability to

accommodate changes in the electric transmission system or

operating conditions while maintaining sufficient steady state

and transient margins. Then, flexible AC transmission system

is an alternating current transmission systems incorporating

power electronic-based and other static controllers to enhance

controllability and increase power transfer capability.

FACTS Controller is a power electronic-based system and

other static equipment that provide control of one or more AC

transmission system parameters [1]. FACTS device can be

used to control power flow, limit short-circuit currents,

mitigate subsynchronous resonance, damp out power

oscillations, and enhance transient stability [2]. In this paper,

FACTS device that will be discused are thyristor controlled

series capasitor (TCSC), thyristor switched series capasitor

(TSSC), distributed power flow controller (DPFC), and

voltage source converter.

There are several types of FACTS controllers. Example of

series connected controllers are Thyristor Controlled Series

Capasitor (TCSC) and Thyristor Switched Series Capasitor

(TSSC). Thyristor Controlled Series Capasitor (TCSC) is a

capasitive reactance compensator which consist of a series

capasitor bank shunted by thyristor controlled reactor in order

to provide a smoothly variable series capasitive reactance.

Thyristor Switched Series Capasitor (TSSC) is a capasitive

reactance compensator which consist of a series capasitor

bank shunted by a thyristor switched reactor to provide a step-

wise control of series capasitive reactance. [1]

One of the combined shunt and series connected

controllers in FACTS is Distributed Power Flow Controller

(DPFC). DPFC emerges from the UPFC (Unified Power Flow

Controller), where UPFC is a combination of a static

synchronous compensator (STATCOM) and a static

synchronous series compensator (S3C) which are coupled via

a common dc link, to allow bi-directional flow of real power

between the series output terminals of the S3C and the shunt

output terminals of the STATCOM, and are controlled to

provide concurrent real and reactive series line compensation

without an external electric energy source. [1]

The employment of series/shunt compensation of

transmission lines by above devices creates certain problems

for their protective relays and fault locators using conventional

techniques because of the rapid changes introduced by the

associated control actions in primary system parameters, such

as line impedances and load currents. There are some

multiline voltage-source (VSC)-based FACTS controllers are

introduced to control the power flows of multilines

simultaneously. [5]

II. DIRECTIONAL RELAYING IN THE PRESENCE OF A

THYRISTOR-CONTROLLED SERIES CAPASITOR

This section addresses the problems with directional

relaying in the presence of TCSC in a line and proposes a

solution. It is found that a single classifier using the phase

information of sequence components is inadequate to provide

direction of fault for all situations for a line with TCSC. More

reliable protection algorithms can be achieved by combining

several protection principles together.

A. TCSC’s four modes of operation

TCSC operates with four modes of operations depending

on the situation:

1. Blocking mode

2. Bypass mode

3. Capasitive boost mode

4. Inductive boost mode

B. Voltage and Current Inversion Condition

Voltage inversion at a relay bus occurs when the total

impedance between the voltage source and the fault is

inductive and simultaneously the impedance between the bus

and the fault point is capacitive. Voltage inversion results in

the relay seeing the forward fault in reverse direction.

For a fault at F and with TCSC in capacitive mode, the

fault current through the relay will be

(1)

Fig 1. Reactance diagram of the line with TCSC

Current lags or leads the voltage by 90 , depending on the

sign of the denominator. Further

(2)

Vm will be inverted when the following conditions are

satisfied:

(3)

For above situation, the directional relay will see the fault

in the reverse side.

For a forward fault in the line, if the current at the relay

location leads the relay voltage by 90 due to the large

capacitive reactance in the fault loop and simultaneously the

relay voltage is in phase with the source voltage, current

inversion occurs. The condition for current inversion becomes

(4)

At this situation also, the relay will see the fault in the reverse

direction.

C. Classifiers

1) Classifier-1: Phase Angle Between the Positive-

Sequence Component of Fault Current and Voltage: The angle

between the positive-sequence fault current and voltage (Φ1)

is a common technique for directional relaying. With

during a fault in the system, the rule of

decision with such a classifier in the normal line will be: a

positive angle corresponds to a fault in the upstream and

negative angle for the downstream fault. During capacitive

mode of operation, for the fault in the Fx side, Φ1x is positive

and provides the correct direction of fault. For a fault in the Fy

side, Φ1y is again positive, resulting in an incorrect direction

of fault due to the voltage inversion. During voltage inversion,

the angle between fault and prefault voltage at the relay

location is much higher as shown in Fig. 2(b) and is used as

the indicator of voltage inversion. During current inversion,

the fault voltage at the relay location is more than the prefault

voltage. The change in magnitude of positive-sequence fault

and prefault voltage and Φ1 are positive and are used as the

indicator of current inversion. For an inductive mode of

operation, for a fault in the Fx side, the positions of phasors

are the same as shown in Fig. 2(a). For fault in the Fy side

during the inductive mode of TCSC, the phasor positions are

shown in Fig. 2(c). Φ’1y in this situation is negative and

provides a correct direction of fault.

Fig. 2. Phasor diagrams for classifier-1. (a) For a fault in

the Fx side. (b) For a fault in the Fy side for capasitive mode

operation (voltage inversion). (c) For a fault in the Fy side for

inductive mode of operation.

2) Classifier-2: Phase Angle Between Positive-Sequence

Superimposed Voltage and Current: The second classifier

determines the direction of fault by considering the angle (Φ2)

between the superimposed relay voltage and current. The

superimposed components are obtained as

(5) (6)

And Φ2 = ∟∆VM - ∟∆IM, where VMF and Vmpre are the fault

and prefault voltages at the relay point, respectively, and IMF

and Impre are the fault and prefault currents at the relay point,

respectively. The decision rule with such a classifier will be: if

the angle difference is positive, then the fault is in the

upstream (Fx side) and if it is negative, then the fault is in the

downstream (Fy side). During capacitive mode of operation,

for a fault in the Fx side, the corresponding phasor positions

are shown in Fig. 3(a). The superimposed component IM lags

the superimposed component VM, providing proper fault

direction (the angle difference Φ2x being positive).

For a fault in the Fy side, the superimposed component IM

leads the superimposed component VM, providing proper fault

direction (the angle difference Φ2y being negative) as shown

in Fig. 3(b). For faults in the Fx and Fy sides during inductive

mode of operation, the phasor diagrams are the same

as for the capacitive mode of operation. The superimposed

component approach has limitations during the load change in

the system.

Fig. 3. Phasor diagrams for classifier-2 for the capasitive

and inductive mode of operation. (a) In the Fx side. (b) In the

Fy side.

3) Classifier-3: Phase Angle Between the Positive-

Sequence Component of Fault Current and Prefault Current:

The third classifier obtains the direction of fault by using the

angle between the fault current and prefault current. For a fault

in the Fx side, the corresponding phasor diagram is provided

in Fig. 4(a). The angle Φ3x between Impre and INF is positive

and the decision for fault direction would be correct. For the

fault in the Fy side during current inversion as shown in Fig.

4(b), the relay fault current ILF leads Ipre, which contradicts the

without inversion condition. This will result in an incorrect

decision by the classifier. During current inversion, the fault

voltage at the relay location is more than the prefault voltage

as shown in Fig. 4(b). At this situation, if Φ3 and ∆V are

positive, then current inversion is assumed.

With the classifier being current based, for voltage

inversion, this classifier will not be affected. For inductive

mode of operation, for a fault in the Fx side, the phasor

diagram is the same as shown in Fig. 4(a). For the Fy side

fault, the corresponding phasor diagram is shown in Fig. 4(c).

In this case, the classifier correctly identifies the fault

direction.

Fig. 4. Phasor diagrams for classifier-3. (a) For a fault in

the Fx side. (b) For a fault in the Fy side for capasitive mode

operation. (c) For a fault in the Fy side for inductive mode of

operation.

D. Voting Method

In case of a line with TCSC, the variation in line reactance

changes the power flow in the line. Due to the variation in

reactance, the fault path may become capacitive or inductive.

It is observed that the voltage and current inversions may

occur at certain situations. From the study, it is found that a

single classifier does not perform correctly for all of the fault

situations. Further, all three classifiers do not fail for a

particular case simultaneously. A voting method is proposed

to combine all three decisions of the classifiers to derive the

final fault direction. In the voting method, the final decision is

based on the maximum votes marked against a particular

decision. The majority voting technique is easy to implement

and is applied to the decision process that produces a unique

class label as output and requires no training.

In a voting technique, suppose are the outputs of each

classifier with C elements, where C is the number of output

decisions. The output of each classifier can be ―1‖ or ― 1‖ for a

two-class problem like directional relaying and in that case.

At time , the decision rule selects the output as the class

that carries the majority vote

(7)

X is derived from di, which is a vector of the same length as

the number of classifiers (N). The matrix D can be formulated

from the data of having different C classes. If the decision of

the classifier belongs to a class, it is assigned ―1‖ or else ―0‖

in the D matrix. y(j) is a vector of length C and each element

indicates the total number of votes for a particular class. The

least square technique using one-cycle data is used to estimate

the phasors. The three classifiers estimate the fault direction

and the majority voting technique provides the direction of

fault at a situation. [2]

III. AN ADAPTIVE CONTROLLER FOR POWER SYSTEM STABILITY

IMPROVEMENT AND POWER FLOW CONTROL BY MEANS OF A

THYRISTOR SWITCHED SERIES CAPASITOR (TSSC)

Thyristor switched series capacitor (TSSC) is a device

capable of changing the apparent reactance of a line in a

number of discrete steps. The controller is developed using a

continuous approach, making it suitable for use also with

devices like the thyristor controlled series capacitor (TCSC)

having continuous reactance control. The proposed controller

is a power-oscillation-damping (POD) controller, which

includes features for transient stability improvement and

power flow control. POD is traditionally performed by power

system stabilizers (PSS) connected to the automatic voltage

regulators (AVR) of the generators in the power system.

Properly tuned, these can effectively damp both local and

inter-area modes of power oscillation. Most approaches are

based on a power system model with full or reduced

complexity, which is linearized. In such a system, linear

control theory can be applied and the poles of the closed-loop

system can be placed such that the damping of the critical

oscillation modes is improved.

The nature of interarea oscillations is often such that there

is a dominant mode of oscillation, which is significantly less

damped than all other modes. With this in mind, a simple way

to reduce the total power grid is to view it as a system split

into two grid areas and the reactances of the lines

interconnecting the areas, as seen in Fig. 1. Here, each area is

represented by a single synchronous machine with a lumped

moment of inertia.

Fig. 5. Generic system model used for control of the TSSC.

Where,

Xi : Series Reactance

U1,2: Voltage phasors of constant magnitudes

Xeq : Paralel Reactance

θ1,2: Variable phase angles

X : Variable Reactance

Test System

Fig. 6. Four-matchine test system

The four-machine system is based on a commonly used

230 kV/60 Hz system for studies of interarea oscillations.

Some changes are made from the original system: one tie line

is added and the length of the lines interconnecting the two

grid areas is stretched to 300 km. Shunt compensation in node

8 is also inserted to maintain a good voltage profile. The

generators are equipped with fast exciters and PSS units with

an intentionally selected low gain in order to give a system

with a small positive damping ratio. The test system has two

local power oscillation modes with a frequency in the range of

1 Hz with a reasonable damping and one interarea mode of

oscillation with a frequency in the range of 0.6 Hz, which is

poorly damped. One important goal for the TSSC in this

system is to improve the damping of the interarea mode.

Principle of POD

If a three-phase to ground fault at node 8 is simulated at t =

1.0 s and cleared after 100 ms with no line disconnection and

no action of the CSC, a poorly damped inter area oscillation is

established, as shown in Fig. 7.Fig. 8 shows that this is indeed

possible. If the controller is limited to act only at times

coinciding with the high and low peaks of the oscillation, it is

theoretically possible to cancel out the oscillation at any given

peak. However, Fig. 8 also shows that a very large change in

the level of compensation is necessary to fulfill the

requirement resulting in a very high level of the power

transmitted on the CSC line. In order to find a practical use of

this principle, it is necessary to extend it to a two-step practice.

Fig. 9 shows this procedure. Here, the controller acts twice on

consecutive peaks in the power oscillation, which results in an

almost total cancellation of the inter area oscillation. With this

technique, it is possible to control the final power on the line

with the CSC since the first step in the sequence can be chosen

with an optional magnitude, whereas the second step can

always cancel the oscillation according to the single-step

argument mentioned earlier. Now, what remains is to find a

way to determine the necessary step magnitudes of the CSC

action to fulfill the requirements. This problem is solved

assuming that the grid can be accurately modeled by the

generic system model in Fig. 5. [4]

IV. DISTRIBUTED POWER FLOW CONTROLLER (DPFC)

The DPFC employs the distributed FACTS (D-FACTS)

concept, which is to use multiple small-size single-phase

converters instead of the one large-size three-phase series

converter in the UPFC. As the D-FACTS converters are

single-phase and floating with respect to the ground, there is

no high-voltage isolation required between the phases.

Fig. 10 Fig. 9

Fig. 8 Fig. 7

The UPFC is the combination of a static synchronous

compensator (STATCOM) and a static synchronous series

compensator (SSSC), which are coupled via a common dc

link, to allow bidirectional flow of active power between the

series output terminals of the SSSC and the shunt output

terminals of the STATCOM. The components of the UPFC

handle the voltages and currents with high rating; therefore,

the total cost of the system is high. Due to the common dc-link

interconnection, a failure that happens at one converter will

influence the whole system. To achieve the required reliability

for power systems, bypass circuits and redundant backups

(backup transformer, etc.) are needed, which on other hand,

increase the cost.

Fig 11. Simplified representation of a UPFC

The DPFC is able to control all system parameters: the line

impedance, the transmission angle, and bus voltage. The

DPFC eliminates the common dc link between the shunt and

series converters. The active power exchange between the

shunt and the series converter is through the transmission line

at the third-harmonic frequency. Comparing with the UPFC,

the DPFC have two major advantages: 1) low cost because of

the low-voltage isolation and the low component rating of the

series converter and 2) high reliability because of the

redundancy of the series converters.

Fig 12. Flowchart from UPFC to DPFC

Fig 13. DPFC configuration

A. DPFC Principle

Two approaches are applied to the UPFC to increase the

reliability and to reduce the cost; they are as follows. First,

eliminating the common dc link of the UPFC and second

distributing the series converter, as shown in Fig. 12. By

combining these two approaches, the new FACTS device—

DPFC is achieved.

The DPFC consists of one shunt and several series-

connected converters. The shunt converter is similar as a

STATCOM, while the series converter employs the D-FACTS

concept, which is to use multiple single-phase converters

instead of one large rated converter. Each converter within the

DPFC is independent and has its own dc capacitor to provide

the required dc voltage. The configuration of the DPFC is

shown in Fig. 13. The DPFC also requires a high-pass filter

that is shunt connected at the other side of the transmission

line, and two Y–Δ transformers at each side of the line.

1. Eliminate DC Link

(8)

Equation above describes that the active power at different

frequencies is isolated from each other and the voltage or

current in one frequency has no influence on the active power

at other frequencies. The independency of the active power at

different frequencies gives the possibility that a converter

without power source can generate active power at one

frequency and absorb this power from other frequencies.

Fig 14. Active power exchange between DPFC converters

By applying this method to the DPFC, the shunt converter

can absorb active power from the grid at the fundamental

frequency and inject the current back into the grid at a

harmonic frequency. According to the amount of required

active power at the fundamental frequency, the DPFC series

converters generate a voltage at the harmonic frequency,

thereby absorbing the active power from harmonic

components.

The high-pass filter within the DPFC blocks the fundament

frequency components and allows the harmonic components

to pass, thereby providing a return path for the harmonic

components. The shunt and series converters, the high-pass

filter, and the ground form the closed loop for the harmonic

current.

Fig 15. Utilize grounded Y-∆ transformer to provide the path

for the zero-sequence third harmonic

Due to the unique characters of third-harmonic frequency

components, the third harmonic is selected to exchange the

active power in the DPFC. In a three-phase system, the third

harmonic in each phase is identical, which is referred to as

―zero-sequence.‖ The zero-sequence harmonic can be

naturally blocked by Y–Δ transformers, which are widely used

in power system to change voltage level. Therefore, there is no

extra filter required to prevent the harmonic leakage to the rest

of the network. In addition, by using the third harmonic, the

costly high-pass filter, as shown in Fig. 14, can be replaced by

a cable that is connected between the neutral point of the Y–Δ

transformer on the right side in Fig. 13 and the ground.

Because the Δ winding appears open circuit to the third-

harmonic current, all harmonic current will flow through the

Y-winding and concentrate to the grounding cable, as shown

in Fig. 15. Therefore, the large-size high-pass filter is

eliminated.

2. Distributed Series Converter

Fig 16. D-FACTS unit configuration

The D-FACTS is a solution for the series-connected

FACTS, which can dramatically reduce the total cost and

increase the reliability of the series FACTS device. The idea

of the D-FACTS is to use a large number of controllers with

low rating instead of one large rated controller. The small

controller is a single-phase converter attached to transmission

lines by a single-turn transformer. The converters are hanging

on the line so that no costly high-voltage isolation is required.

The single-turn transformer uses the transmission line as the

secondary winding, inserting controllable impedance into the

line directly. Each D-FACTS module is self-powered from the

line and controlled remotely by wireless or power-line

communication (see Fig. 16).

The structure of the D-FACTS results in low cost and high

reliability. As D-FACTS units are single-phase devices

floating on lines, high-voltage isolations between phases are

avoided. The unit can easily be applied at any transmission-

voltage level, because it does not require supporting phase-

ground isolation. The power and voltage rating of each unit is

relatively small. Further, the units are clamped on

transmission lines, and therefore, no land is required. The

redundancy of the D-FACTS provides an uninterrupted

operation during a single module failure, thereby giving a

much higher reliability than other FACTS devices.

3. DPFC Advantages

High control capability

High reliability

Low cost

B. DPFC Control

Fig 17. DPFC control block diagram

To control the multiple converters, DPFC consists of three

types of controllers; they are central controller, shunt control,

and series control, as shown in Fig. 17. The shunt and series

control are local controllers and are responsible for

maintaining their own converters’ parameters.

1. Central Control

The central control generates the reference signals for

both the shunt and series converters of the DPFC. It is focused

on the DPFC tasks at the power-system level, such as power-

flow control, low-frequency power oscillation damping, and

balancing of asymmetrical components.

2. Series Control

Each series converter has its own series control. The

controller is used to maintain the capacitor dc voltage of its

own converter by using the third-harmonic frequency

components and to generate series voltage at the fundamental

frequency that is prescribed by the central control.

3. Shunt Control

The objective of the shunt control is to inject a constant

third harmonic current into the line to provide active power for

the series converters. The third-harmonic current is locked

with the bus voltage at the fundamental frequency. The shunt

converter’s fundamental frequency control aims to inject a

controllable reactive current to grid and to keep the capacitor

dc voltage at a constant level. [3]

V. A LARGE POWER, LOW-SWITCHING-FREQUENCY VOLTAGE

SOURCE FPR FACTS APPLICATIONS WITH LOW EFFECT ON THE

TRANSMISSION LINE

We are witnessing an increased interest in flexible ac

transmission systems (FACTS) within the so-called SmartGrid

revolution. These provide a fast control of some of the

transmission grid key parameters and are used, for instance, to

overcome the challenges arising from the massive integration

of renewable energy sources, intrinsically uncertain and highly

variable by nature.

The voltage source converter (VSC) topology, could be

used to form a large power FACTS device such as a static

synchronous series compensator (SSSC) or as a static

synchronous compensator (STATCOM), depending on the

series or parallel connection of the grid coupling transformer.

The former is mainly used to provide power flow control,

whereas the latter is generally used to provide voltage support,

reactive power compensation, or to help complying with grid

code requirements. Alternatively, two VSCs could be

combined to form a unified power flow controller (UPFC) to

provide both series and shunt reactive compensation. In doing

so, both the active and reactive power flow can be controlled.

In addition, the proposed converter could be used as a part of

any large power electronic system where the topology fits the

application requirements.

A. Description of the Converter

1. Parallel Combination of Two Inverter Poles

Fig 18. Parallel connection of two inverter poles using an IPT

The IPT (Inter Phase Transformers) is effectively a single

primary, single secondary transformer, where the two

windings are connected in series. The series connection point

is taken as the output and the remaining terminals are the two

inputs. The two windings, closely coupled, are arranged so

that the flux created by equal currents entering the input

terminals is canceled out, that is, their amp-turns are equal and

of a different sign, leaving in the core the flux created by the

voltage difference between the two input terminals.

2. Series Transformers Connection

Due to the inherent amp-turns balance created in each of

the transformer limbs, as Ampere’s law explains, the currents

iA5 and iA6 have the same shape, but are 30o

out of phase,

leading or lagging depending on the transformer connection.

Moreover, as explained shortly, provided that the converter

outputs are phase-shifted by 30o

to match the phase shift of the

transformer, the overall output voltage will be double to that

of each inverter. That is, the inverters can be considered as

two series-connected voltage sources, which, by virtue of the

galvanic isolation provided by the transformer, are allowed to

share a common and better optimized dc bus.

B. Modulation Strategies

There are 2 ways to made modulation for converter

connection to reduce harmonic. The first one with full-wave

48-pulse modulation and the second one with Selective

Harmonic Elimination of Three Angles (SHE-3).

1. Full-Wave 48-Pulse Modulation

In this strategy, each of the inverter poles produces a

voltage wave form with the lowest possible switching

frequency allowed for in a 3-L NPC inverter. This, which

has an average frequency of 100 Hz over a complete cycle,

consists in applying 0V, only during a short angle of θ,

centered on each of the zero crossings.

The harmonic content of that waveform, expressed in

Fourier coefficients, can be easily calculated as

(9)

This waveform has no even harmonics present.

Moreover, some of the harmonics can be greatly attenuated

by the right choice of the θ angle. For instance, if θ is made

equal to 15o, the 11th 13th, 35th, and 37th harmonics will

be attenuated by a value of 0.1305, whereas the

fundamental component will be merely reduced by a factor

of 0.9915.

2. SHE of Three Angles (SHE-3)

This implementation consists in generating an SHE wave

form where the three switching angles per quarter-cycle

α1, α2, and α3, are chosen such that the harmonics

eliminated at the inverter pole output vA1G is the 11th and

13th, while controlling the waveform amplitude.

Subsequently, the 23rd and 25th

harmonics are mitigated at

the IPT by choosing the γ angle equal to 7.5o. Repeat the

time control for switch to eliminate the others harmonic

distorsion orde until the output waveform like a normal

wave form.

VI. IMPACT OF VSC-BASED MULTILINE FACTS CONTROLLERS

ON DISTANCE PROTECTION OF TRANSMISSION LINES

The employment of series/shunt compensation of

transmission lines by above devices creates certain problems

for their protective relays and fault locators using conventional

techniques because of the rapid changes introduced by the

associated control actions in primary system parameters, such

as line impedances and load currents. There are some multiline

voltage-source (VSC)-based FACTS controllers, such as an

Interline Power-Flow Controller (IPFC), Generalized Interline

Power-Flow Controller (GIPFC), and Generalized Unified

Power-Flow Controller (GUPFC) are introduced to control the

power flows of multilines simultaneously. Multiline VSC

based FACTS controllers can control different variables of the

power system, such as the bus voltage and independent active

and reactive power flows of two lines by combining three or

more converters working together.

Fig 19. Simplified one-line diagram of multiline FACTS

controllers connected to the middle of the transmission lines

Fig. 19 shows the generic representation of a multiline

VSC based FACTS controller. Different controllers are

achieved by the status of the DC switches, as Table I.

According to this table,when all of the DC switches are

closed, it represents a GUPFC. SSSC1 and SSSC2 in Table I

indicate the static synchronous series compensators (SSSCs)

configured in Line 1 and Line 2, respectively.

A. Multiline VSC-Based FACTS Controllers Impact on

Apparent Impedance

To make FACTS controllers at GUPFC condition, all

switch must be closed so the one line diagram will be

Fig 20. Sample system with GUPFC

In this figure, the GUPFC is connected to the middle of the

line to include the series compensators in the fault loop. VSe1

and VSe2 are the series-injected voltages powered by the

shunt converter, represented by impedance Zsh and current

source Ish. If the converter losses are ignored, then the active

power drawn by the shunt leg is equal to the delivered power

to lines 1 and 2. The performance of relays R1 and R2 for

different fault types, fault locations, and fault resistances Rf is

analyzed to show the impact of different multiline VSC-based

FACTS controllers on distance protection. Faults on Line 1 at

point F between K and H with the per-unit distance x from the

relay location are considered. In this sense, x has a value

between 0.5 and 1.0 for faults between K and H in the sample

system. ZL is theimpedance of each line, and VG is the

voltage measured by R1 and R2 which is the same for both

relays.

B. GUPFC Control System

Although GUPFC has many possible operating modes, it is

anticipated that the shunt converter will generally operate in

automatic voltage-control mode and the series converter will

typically be in automatic power-flow control mode. The

control schemes assume that series and shunt converters

generate output voltage with controllable magnitude and

angle, and that the dc bus voltage will be held substantially

constant.The automatic power-flow control for the series

converter is achieved by means of a vector-control scheme

that regulates the transmission-line current, using a

synchronous reference frame in which the control quantities

appear as dc signals in the steadystate. The appropriate real

and reactive current components are determined for a desired

Prefand Qref, compared with the measured line currents, and

used to derive the magnitude and angleof the series converter

voltage.

C. Simulation result of GUPFC Control System

a. Relay Performance for a Single-Phase Fault (A-G)

Fig 21. Trip characteristics of relay R1 for a single-phase fault

A comparison of the characteristics ABCD with its

counterpart A’B’C’D’ (hatched area without GUPFC)

reveals that GUPFC has an impact on R1 to measure

higher apparent reactance/resistance. This means for a

single-phase fault at Zone I reach of the relay, higher

apparent impedance is seen by the relay, so the fault

falsely appears outside Zone I. In other words, GUPFC

causes the relay to under reach.

b. Relay Performance for a Two-Phase Fault (A-B)

Fig 22. Apparent impedance seen by R1 for a phase-to-phase

fault at 225 km

It can be seen that the trajectories of apparent

impedances do not enter the Zone I mho characteristics for

GUPFC/UPFC, while the trajectory does enter the circle

for IPFC. It can be deduced that GUPFC/UPFC caused the

relay to under reach (i.e., not to detect

the fault at Zone I), while the impact of IPFC is not

remarkable.

c. Relay Performance for a Two-Phase-to-Ground Faults

Fig 23. Apparent impedance seen by different measuring units

of the relay for an ABC fault at 225 km witk GUPFC

The impact of GUPFC for ABG faults is less severe

than the single-phase faults. Despite the fact that the A-B

unit does not cross the trip boundary, it is still less affected

than the single-phase measuring units (A-G and B-G).

d. Impact of Pref and Qref on the Apparent Impedance

Fig 24. Apparent impedance seen by distance relay R1 for

different values of active and reactive power-flow reference

values

As can be seen from this figure, for Pref = Qref = 0,

the power flows are 315.6 MW and ----58.1 MVAr. The

solid line in Fig. 24 shows the variation of the apparent

impedance versus the variation of Pref, while keeping Qref

constant. It can be deduced that Pref has an impact on the

apparent impedance for all of the values between 1.8 p.u.

and 1.2 p.u. with a constant Qref. In the next step, Qref is

varied while Pref is held constant. As Fig. 11 shows, Qref

also affects the apparent impedance such as Pref but to a

lesser extent. The impact of Qref is higher for its lower

values. [5]

VII. CONCLUSIONS

FACTS devices that are developed can be used to

increase the power transfer capability by means of

stabilizing the transient and detect any failures.

Directional relaying in the presence of TCSC is

addressed by three positive-sequence-based classifier

outputs and combined with the voting method to

obtain the direction of fault.

Thyristor switched series capacitor (TSSC) as

controller is developed using a continuous approach.

The proposed controller is a power-oscillation-

damping (POD) controller, which includes features

for transient stability improvement and power flow

control.

The DPFC emerges from the UPFC and inherits the

control capability of the UPFC, which is the

simultaneous adjustment of the line impedance, the

transmission angle, and the bus-voltage magnitude.

The voltage source converter (VSC) is mainly used to

provide power flow control, provide voltage support,

reactive power compensation, or to help complying

with grid code requirements.

Multiline VSC- based FACTS controllers, which are

used to simultaneously control the active and reactive

power flows of multilines, have a remarkable

impacton conventional distance protection of

transmission lines due to the rapid changes

introduced by the associated controlactions in

primary system parameters such as line impedances

and load currents.

Acknowledgment

We gratefully acknowledge to our teachers Mr. Faiz

Husnayain, S.T, M.T, and Mr. Ir. I Made Ardita, M.T, and all

of classmates of power engineering for discussing about the

power electronics in our six semester.

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