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1. Power SystemPower System
ProtectionProtection
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2. ContentsContents
Introduction
Functions of Equipment Protection
Functions of Protective Relays
Required Information for Protective Setting
Protection Settings Process
Functional Elements of Protective Relays
Operating Characteristics of Protective Relays
Over current and Directional Protection
Elements
Distance Protection Function
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3. Protection Settings: IntroductionProtection Settings: Introduction
A power system is composed of a number of
sections (equipment) such as generator,
transformer, bus bar and transmission line.
These sections are protected by protective
relaying systems comprising of instrument
transformers (ITs), protective relays, circuit
breakers (CBs) and communication equipment.
In case of a fault occurring on a section, its
associated protective relays should detect the
fault and issue trip signals to open their
associated CBs to isolate the faulted section
from the rest of the power system, in order to
avoid further damage to the power system.
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4. 4
Below Fig. 1 is an typical example of power system sections with their
protection systems. Where:
G1 is a generator. T1 is a transformer. B1,...,B5 are bus bars. L45 is
a transmission line (TL).
RG is a generator protective relay. RT is a transformer protective
relay. RB is a bus protective relay. RL-4,...,RL-9 are TL protective
relays. C1,..., C9 are CBs.
Protection Settings: Introduction

5. Protection Settings: IntroductionProtection Settings: Introduction
Maximum fault clearance times are usually
specified by the regulating bodies and
network service providers.
The clearing times are given for local and
remote CBs and depend on the voltage level
and are determined primarily to meet
stability requirements and minimize plant
damage.
The maximum clearance times of the backup
protection are also specified.
e.g. the clearing times for faults on the lines
specified by one network service provider in
Australia are presented in Table I (next
slide).
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6. Table I: Fault clearance timesTable I: Fault clearance times
Voltage
level [kV]
CB operate correctly
[ms]
CB fail [ms]
Local Remote Local Remote
500 80 100 175 175
330 100 120 250 250
275 100 120 250 250
220 120 140 430 430
132 120 160 430 430
110 120 160 430 430
66 120 160 430 430
≤ 33 1160 - 1500 -
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7. Functions of Equipment ProtectionFunctions of Equipment Protection
Protection schemes are generally divided into
equipment protection and system protection.
The main function of equipment protection is to
selectively and rapidly detect and disconnect a fault
on the protected circuit to:
◦ ensure optimal power quality to customers;
◦ minimize damage to the primary plant;
◦ prevent damage to healthy equipment that
conducts fault current during faults;
◦ restore supply over the remaining healthy
network;
◦ sustain stability and integrity of the power system;
◦ limit safety hazard to the power utility personnel
and the public.
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8. Functions of Protective RelaysFunctions of Protective Relays
 The protection functions are considered adequate when
the protection relays perform correctly in terms of:
 Dependability: The probability of not having a failure to
operate under given conditions for a given time interval.
 Security: The probability of not having an unwanted
operation under given conditions for a given time interval.
 Speed of Operation: The clearance of faults in the
shortest time is a fundamental requirement (transmission
system), but this must be seen in conjunction with the
associated cost implications and the performance
requirements for a specific application.
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9. ……Functions of Protective RelaysFunctions of Protective Relays
 Selectivity (Discrimination):
The ability to detect a fault within a specified zone of
a network and to trip the appropriate CB(s) to clear
this fault with a minimum disturbance to the rest of
that network.
 Single failure criterion:
A protection design criterion whereby a protection
system must not fail to operate even after one
component fails to operate.
With respect to the protection relay, the single
failure criterion caters primarily for a failed or
defective relay, and not a failure to operate as a
result of a performance deficiency inherent within
the design of the relay.
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10. ……Functions of Protective RelaysFunctions of Protective Relays
The setting of protection relays is not a
definite science.
Depending on local conditions and
requirements, setting of each protective
function has to be optimized to achieve
the best balance between reliability,
security and speed of operation.
Protection settings should therefore be
calculated by protection engineers with
vast experience in protective relaying,
power system operation and
performance and quality of supply.
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11. required information for Protective Settingrequired information for Protective Setting
Line Parameters:
 For a new line: final total line length as well as the
lengths, conductor sizes and tower types of each
section where different tower types or conductors
have been used.
 This information is used to calculate the parameters
(positive and zero sequence resistance, reactance and
susceptance) for each section.
 Maximum load current or apparent power (MVA)
corresponding to the emergency line which can be
obtained from the table of standard conductor rating
(available in each utility).
 The number of conductors in a bundle has to be taken
into consideration.
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12. ……required information for Protective Settingrequired information for Protective Setting
Transformer Parameters:
◦ The manufacturer's positive and zero sequence
impedance test values have to be obtained.
◦ The transformer nameplate normally provides the
manufacturer's positive sequence impedance values
only.
Terminal Equipment Rating:
◦ The rating of terminal equipment (CB, CT, line trap,
links) of the circuit may limit its transfer capability
therefore the rating of each device has to be
known.
◦ Data can be obtained from the single line diagrams.
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13. ……required information for Protectiverequired information for Protective
SettingSetting
Fault Studies
◦ Results of fault studies must be provided.
◦ The developed settings should be checked on future
cases modelled with the system changes that will
take place in the future (e.g. within 5 years).
◦ Use a maximum fault current case.
CT & VT Ratios:
◦ Obtain the CT ratios as indicated on the protection
diagrams.
◦ For existing circuits, it is possible to verify the ratios
indicated on the diagrams by measuring the load
currents on site and comparing with a known ratio.
•
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14. ……required information for Protective Settingrequired information for Protective Setting
Checking For CT Saturation:
◦ Protection systems are adversely affected by CT saturation.
It is the responsibility of protection engineers to establish for
which forms of protection and under what conditions the CT
should not saturate.
CTs for Transformer Differential
Protection:
◦ MV, HV and LV CTs must be matched as far as possible
taking into consideration the transformer vector group, tap
changer influence and the connection of CTs.
CTs for Transformer Restricted Earth
Fault (REF) Protection:
◦ All CT ratios must be the same (as with the bus
zone protection), except if the relay can internally
correct unmatched ratios.
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15. PROTECTION SETTINGS PROCESSPROTECTION SETTINGS PROCESS
 The Protection Settings team obtains all the
information necessary for correct setting calculations.
 The settings are then calculated according to the
latest philosophy, using sound engineering principles.
Pre-written programs may be used as a guide.
 After calculation of the settings, it is important that
another competent person checks them.
 The persons who calculate and who check the
settings both sign the formal settings document.
 The flowchart in Fig. 2 indicates information flow
during protection setting preparation for
commissioning of new Transmission plant.
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16. 16
Project leader of the Protection
Settings team determines scope
of work and target dates
Summary and comparison of inputs
IED manufacturers provide bay
specific IED details
Engineering team provides bay
specific proformas and drawings
Corrective actions and re-issue of
drawings
Study new protection and create
necessary setting templates in
liaison with engineering team and
IED manufactureres
OK Not OK
Calculation and verification of settings
Settings stored in central database
and formal document issued
Implementation date and responsible
field person stored in the central
database -> implementation action
Implementation sheet completed
by field staff and returned to
Protection Settings team
Interface with the Expansion Planing
team and IED manufacturers to obtain
relevant equipment parameters for
correct system modelling
Centralised Settings Management
System sends the action documents
to the field staff
Corrective actions required to
ensure implementation
Fig. 2 Information flow during
protection settings preparation

17. FUNCTIONAL ELEMENTS OF PROTECTIVEFUNCTIONAL ELEMENTS OF PROTECTIVE
RELAYSRELAYS
 To achieve maximum flexibility, relays is designed using the
concept of functional elements which include protection
elements, control elements, input and output contacts etc.
 The protection elements are arranged to detect the system
condition, make a decision if the observed variables are
over/under the acceptable limit, and take proper action if
acceptable limits are crossed.
 Protection element measures system quantities such as
voltages and currents, and compares these quantities or
their combination against a threshold setting (pickup
values).
 If this comparison indicates that the thresholds are crossed,
a decision element is triggered.
 This may involve a timing element, to determine if the
condition is permanent or temporary. If all checks are
satisfied, the relay (action element) operates.
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18. 18
Fault
Pickup of
protection element
Operation of
protection element
Assertion of relay
trip logic signal
Action of relay
trip contact
Circuit breaker
opening
Fault cleared
Sequence of protection operation initiated by a fault is
shown in Fig. 3.

19. OPERATING CHARACTERISTICS OFOPERATING CHARACTERISTICS OF
PROTECTIVE RELAYSPROTECTIVE RELAYS
 Protective relays respond and operate according to
defined operating characteristic and applied settings.
 Each type of protective relay has distinctive operating
characteristic to achieve implementation objective:
sensitivity, selectivity, reliability and adequate speed
of operation.
 Basic operating characteristics of protective elements
is as follows:
 Overcurrent protection function: the overcurrent
element operates or picks up when its input current
exceeds a predetermined value.
 Directional function: an element picks up for faults
in one direction, and remains stable for faults in the
other direction.
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20. ……OPERATING CHARACTERISTICS OF PROTECTIVEOPERATING CHARACTERISTICS OF PROTECTIVE
RELAYSRELAYS
Distance protection function: an element
used for protection of transmission lines whose
response is a function of the measured electrical
distance between the relay location and the fault
point.
Differential protection function: it senses a
difference between incoming and outgoing
currents flowing through the protected
apparatus.
Communications-Assisted Tripping
Schemes: a form of the transmission line
protection that uses a communication between
distance relays at opposite line ends resulting in
selective clearing of all line faults without time
delay.
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21. OVERCURRENT AND DIRECTIONALOVERCURRENT AND DIRECTIONAL
PROTECTION ELEMENTSPROTECTION ELEMENTS
 An over current condition occurs when the
maximum continuous load current permissible for a
particular piece of equipment is exceeded.
 A phase overcurrent protection element
continuously monitors the phase current being
conducted in the system and issue a trip command
to a CB when the measured current exceeds a
predefined setting.
 The biggest area of concern for over-current
protection is how to achieve selectivity.
 Some possible solutions have been developed,
including monitoring current levels (current
grading), introducing time delays (time grading) or
combining the two as well as including a directional
element to detect the direction of current flow.
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22. Current gradingCurrent grading
Current grading will achieve selectivity by
determine the location of a fault using purely
magnitude of current.
It is difficult to implement this in practice
unless feeder sections have sufficient
differences in impedance to cause noticeable
variations in fault current.
In a network where there are several
sections of line connected in series, without
significant impedances at their junctions
there will be little difference in currents, so
discrimination or selectivity cannot be
achieved using current grading.
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23. time delaystime delays
 An alternate means of grading is introducing time delays
between subsequent relays.
 Time delays are set so that the appropriate relay has
sufficient time to open its breaker and clear the fault on its
section of line before the relay associated with the adjacent
section acts.
 Hence, the relay at the remote end is set up to have the
shortest time delay and each successive relay back toward
the source has an increasingly longer time delay.
 This eliminates some of the problems with current grading
and achieves a system where the minimum amount of
equipment is isolated during a fault.
 However, there is one main problem which arises due to the
fact that timing is based solely on position, not fault current
level.
 So, faults nearer to the source, which carry the highest
current, will take longer to clear, which is very contradictory
and can prove to be quite costly.
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24. directional elementsdirectional elements
 Selectivity can be achieved by using directional elements
in conjunction with instantaneous or definite-time
overcurrent elements.
 Directional overcurrent protection schemes respond to
faults in only one direction which allows the relay to be
set in coordination with other relays downstream from the
relay location.
 This is explained using example in Fig. 4.
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25. directional elementsdirectional elements
 By providing directional
elements at the remote ends
of this system, which would
only operate for fault
currents flowing in one
direction we can maintain
redundancy during a fault.
 This is in line with one of the
main outcomes of ensuring
selectivity, which is to
minimize amount of circuitry
that is isolated in order to
clear a fault.
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Fig. 4: Use of direction element
example

26. direction of current flowdirection of current flow
 In AC systems, it is difficult to determine the direction of
current flow and the only way to achieve this is to perform
measurements with reference to another alternating
quantity, namely voltage. The main principle of how
directional elements operate is based on the following
equations for torque:
 If current is in the forward direction, then the sign of the
torque equation will be positive and as soon as the direction
of current flow reverses, the sign of the torque equation
becomes negative. These calculations are constantly being
performed internally inside directional element.
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)cos( ABCABCA IVIVT ∠−∠••=
)cos( BCABCAB IVIVT ∠−∠••=
)cos( CABCABC IVIVT ∠−∠••=

27. DISTANCE PROTECTION FUNCTIONDISTANCE PROTECTION FUNCTION
A distance protection element measures the
quotient V/I (impedance), considering the
phase angle between the voltage V and the
current I.
In the event of a fault, sudden changes
occur in measured voltage and current,
causing a variation in the measured
impedance.
The measured impedance is then compared
against the set value.
Distance element will trip the relay (a trip
command will be issued to the CB associated
with the relay) if the measured value of the
impedance is less then the value set.
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28. ……DISTANCE PROTECTION FUNCTIONDISTANCE PROTECTION FUNCTION
We can see that the impedance value of a
fault loop increases from zero for a short
circuit at the source end A, up to some finite
value at the remote end B. We can use this
principle to set up zones of distance
protection as well as to provide feedback
about where a fault occurred (distance to
fault).
Operating characteristics of distance
protection elements are usually represented
using R-X diagrams.
Fig. 6 shows an example of Mho R-X
operating characteristic. The relay is
considered to be at the origin.
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29. ……DISTANCE PROTECTION FUNCTIONDISTANCE PROTECTION FUNCTION
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Region of
operation
Zone 1
Region of
non-operation
outside the circle
Load
region
R
X
Zone 2
A
B
80%
120%
Line P
Line Q
Fig. 6 Mho positive-sequence R-X operating
characteristic of a distance element.

30. ……DISTANCE PROTECTION FUNCTIONDISTANCE PROTECTION FUNCTION
The need for zones shown in Fig. 6 arises
from the need of selective protection; i.e.
the distance element should only trip faulty
section.
We can set the distance element to only
trigger a trip signal for faults within a
certain distance from the relay, which is
called the distance element reach.
The setting impedance is represented by
, where ZL is the line impedance.
The distance element will only trip when
the measured impedance ZR is less than or
equal to the setting impedance hsZL.
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RS s LZ h Z=

31. ……DISTANCE PROTECTIONDISTANCE PROTECTION
FUNCTIONFUNCTION
 Typically hs is set to protect 80% of the line between
two buses and this forms protection Zone 1.
 Errors in the VTs and CTs, modeled transmission line
data, and fault study data do not permit setting Zone 1
for 100% of the transmission line.
 If we set Zone 1 for 100% of the transmission line,
unwanted tripping could occur for faults just beyond
the remote end of the line.
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32. ……DISTANCE PROTECTION FUNCTIONDISTANCE PROTECTION FUNCTION
Zone 2 is set to protect 120% of the line,
hence making it over-reaching, because it
extends into the section of line protected by
the relay at point B. To avoid nuisance
tripping, any fault occurring in Zone 1 is
cleared instantaneously, while faults which
occur in Zone 2 are cleared after a time delay
in order to allow relay B to clear that fault
first.
This provides redundancy in the protection
system (backup), whilst maintaining
selectivity.
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