1. ELEC 4302/7311
POWER SYSTEM PROTECTION:
PROTECTION SETTINGS
BY MOHD MOIZUDDIN
1

2. Contents
 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
 Overcurrent and Directional Protection Elements
 Distance Protection Function
2

3. PROTECTION 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. 3

4. Protection Settings: Introduction
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.
4
Fig. 1 Protection of power system sections

5. PROTECTION 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).
5

6. TABLE I: FAULT CLEARANCE
TIMES
Voltage CB operate correctly CB fail [ms]
level [kV] [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 -
6

7. FUNCTIONS 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. 7

8. FUNCTIONS 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. 8

9. …FUNCTIONS 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
9
deficiency inherent within the design of the relay.

10. …FUNCTIONS 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.
10

11. REQUIRED 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
11
consideration.

12. …REQUIRED 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.
12

13. …REQUIRED INFORMATION FOR
PROTECTIVE SETTING
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 13
load currents on site and comparing with a known
ratio.

14. …REQUIRED 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 14
correct unmatched ratios.

15. PROTECTION 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.
15

16. Fig. 2 Information flow during
protection settings preparation
Project leader of the Protection
Settings team determines scope IED manufacturers provide bay
of work and target dates specific IED details
Engineering team provides bay
specific proformas and drawings
Corrective actions and re-issue of
Summary and comparison of inputs drawings
OK Not OK
Study new protection and create
necessary setting templates in
liaison with engineering team and
IED manufactureres Interface with the Expansion Planing
team and IED manufacturers to obtain
Calculation and verification of settings relevant equipment parameters for
correct system modelling
Settings stored in central database Centralised Settings Management
and formal document issued System sends the action documents
to the field staff
Implementation date and responsible
field person stored in the central
database -> implementation action
Implementation sheet completed Corrective actions required to 16
by field staff and returned to ensure implementation
Protection Settings team

17. FUNCTIONAL ELEMENTS OF
PROTECTIVE RELAYS
 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 17
(action element) operates.

18. Sequence of protection operation initiated by a fault is
shown in Fig. 3.
Pickup of Operation of
Fault protection element protection element
Assertion of relay Action of relay
trip logic signal trip contact
Circuit breaker
Fault cleared
opening
Fig. 3 Sequence of operation. 18

19. OPERATING CHARACTERISTICS OF
PROTECTIVE 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 19
direction.

20. …OPERATING CHARACTERISTICS
OF PROTECTIVE RELAYS
 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. 20

21. OVERCURRENT AND DIRECTIONAL
PROTECTION ELEMENTS
 An overcurrent 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 21
of current flow.

22. CURRENT 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. 22

23. TIME 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 23
prove to be quite costly.

24. DIRECTIONAL 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.
24

25. DIRECTIONAL 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
Fig. 4: Use of direction element amount of circuitry that is
example isolated in order to clear a fault.
25

26. DIRECTION 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:
TA = VBC • I A • cos(∠VBC − ∠I A )
TB = VCA • I B • cos(∠VCA − ∠I B )
TC = V AB • I C • cos(∠V AB − ∠I C )
 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
26
inside directional element.

27. DISTANCE 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.
27

28. …DISTANCE PROTECTION FUNCTION
Fig. 5 Distance protection principle of operation.
 In Fig. 5 the impedance measured at the relay point A
is Z = ( R + jω L) x , where x is the distance to the fault (short
in
circuit), and R and L are transmission line parameters
in per unit length. The line length is l in the fig.. 28

29. …DISTANCE 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.
29

30. …DISTANCE PROTECTION FUNCTION
X
Region of
Line Q non-operation
120%
B outside the circle
80%
Zone 2
Line P
Z RS
Load
Region of region
operation
Zone 1
A R
Fig. 6 Mho positive-sequence R-X operating
characteristic of a distance element. 30

31. …DISTANCE 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 Z RS = hs Z L ,
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
31
impedance hsZL.

32. …DISTANCE PROTECTION FUNCTION
 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.
32

33. …DISTANCE 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.
33