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. 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
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
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 deficiency
inherent within the design of the relay.
9
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
consideration.
11
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 load
currents on site and comparing with a known ratio.
13
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 correct
unmatched ratios.
14
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. 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
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 (action
element) operates.
17
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
Fig. 3 Sequence of operation.
Sequence of protection operation initiated by a fault is
shown in Fig. 3.
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 direction.
19
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 of
current flow.
21
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 prove to be
quite costly.
23
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
amount of circuitry that is isolated
in order to clear a fault.
25
Fig. 4: Use of direction element
example
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:
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. 26
)
cos( A
BC
A
BC
A I
V
I
V
T
)
cos( B
CA
B
CA
B I
V
I
V
T
)
cos( C
AB
C
AB
C I
V
I
V
T
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
In Fig. 5 the impedance measured at the relay point A is
, where x is the distance to the fault (short circuit), and R
and L are transmission line parameters in per unit length.
The line length is l in the fig.. 28
Fig. 5 Distance protection principle of operation.
in
Z R j L x
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
30
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
RS
Z
Fig. 6 Mho positive-sequence R-X operating
characteristic of a distance element.
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 ,
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.
31
RS s L
Z h Z
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
