Overcurrent protection

Power System Protection

Abdul Basit
Types of overcurrent relay

• Overcurrent relays are classified on the basis of operating

characteristics as:
• definite current relay

• definite time relay

• inverse time relay

Definite Current Relay
• Relay operates instantaneously when current reaches a
predetermined value.
• Settings:
• Relay will operate for a low current value for substation furthest
away.
• Operating currents are progressively increased at each substation,
moving towards the source
• Relay with lower settings operates first
• Disadvantage:
• Little selectivity at high values of short circuit current
• Poor discrimination: difficulty in distinguishing fault current at near
points location
 Definite Current Relay
• Figure (a): impact of impedance on the short-circuit current.
• Figure (b): Fault current are same for faults at point F1 and F2 –
difficult to obtain correct settings for Relay
• Impedance of Transformer will produce difference between F2 and
F3 – discrimination for fault current
• Relay settings based on maximum fault level conditions may
not be appropriate during lower fault level.
• Relay settings based on lower value of fault could result in
some breakers operating unnecessarily if the fault level
increases.
• Consequence, definite-current relays are not used as the only
overcurrent protection, but their use as an instantaneous unit
is common where other types of protection are in use.
Definite-time/current or definite-time relays
• Relay used to cope with different levels of current by using different
operating times.
• Discrimination margin is achieved by keeping the breaker nearest to
the fault to trip in the shortest time, and then the remaining breakers
are tripped in succession
• Time discrimination in fixed steps makes the protection more selective
• Disadvantage: Faults near to the source, which result in bigger
currents, may be cleared in a relatively long time.
• Relay settings: Current tap settings and Time Dial Settings
Inverse-time relays
• Relays operate in a time that is inversely proportional to the fault
current
• Advantage over definite-time relays:
• for very high currents, much shorter tripping times can be obtained without
risk to the protection selectivity.
• Inverse-time relays are classified in accordance with their
characteristic curve that indicates the speed of operation
• inverse, very inverse or extremely inverse.
• Inverse-time relays are also referred to as inverse definite minimum
time (IDMT) overcurrent relays
Setting overcurrent relays
• Overcurrent relays are normally supplied with an instantaneous
element and a time delay element within the same unit
• Setting: define the required time/current characteristic of both
the time-delay and instantaneous units for phase relays and
over current relays
• three-phase short-circuit are used for setting phase relays
• phase-to-earth fault current are used for earth-fault relays
• Fault current calculated at normal power system operating state
Setting instantaneous units
• For power system elements with high impedance,
Instantaneous units are more effective
• criteria for setting instantaneous units vary depending on the
location and the type of system element being protected
• Advantages:
• Reduce operating time of the relays for severe system faults.
• avoid loss of selectivity in a protection system consisting of relays
with different characteristics; this is obtained by setting the
instantaneous units so that they operate before the relay
characteristics cross
Setting instantaneous units
• Lines between substations
• Take at least 125% of the symmetrical r.m.s. current for the maximum fault level at
the next substation
• If two relays at particular fault level fails to coordinate the relay furthest from the
source shall operate at lower level of current, 25% margin avoids overlapping the
downstream instantaneous unit if a considerable DC component is present
• Distribution lines: fifty percent of the maximum short-circuit current at the
point of connection of the CT supplying the relay OR between six and ten
times the maximum circuit rating.
• Instantaneous units of the overcurrent relays installed on the primary side
of the transformers should be set at a value between 125% and 150% of
the shortcircuit current
Coverage of instantaneous units protecting lines
between substations
• Percentage of coverage of an instantaneous unit that
protects a line, X, can be illustrated by considering the
system

From figure:

If Ki = 1.25 & Ks = 1, then X = 0.6

60% of the line is protected
 Setting the parameters of time-delay overcurrent
relays
• Operating time of an overcurrent relay has to be
delayed to ensure that the relay does not trip
before any other protection situated closer to the
fault.
• Figure illustrate the difference in the operating
time of two relays at the same fault levels in order
to satisfy the discrimination margin requirements.
• Definite-time relays and inverse-time relays can be
adjusted by selecting two parameters
• time dial or time multiplier setting
• Pick Up (PU) or Plug setting (tap setting).
The pick-up setting
• PU/plug setting, refer as plug setting multiplier (PSM), is used to
define the PU current of the relay
• ratio of the fault current in secondary amps to the relay PU or plug setting.
• For phase relays, the PU setting is determined by allowing a margin
for overload above the nominal current, as in the following
expression:
The pick-up setting
• For earth-fault relays, the PU setting is determined taking account of
the maximum unbalance that would exist in the system under normal
operating conditions. A typical unbalance allowance is 20% so that
the expression
Time dial settings
• Adjusts time delay before the relay operates whenever the fault
current reaches a value equal to, or greater than, the relay current
setting.
• Electromechanical relays: time delay is usually achieved by adjusting
the physical distance between the moving and fixed contacts
• smaller time dial value results in shorter operating times.
• Time dial setting is also referred to as the time multiplier setting.
Time dial settings – criteria
1. Determine the required operating time of the relay furthest away from
the source by using the lowest time dial setting and considering the fault
level for which the instantaneous unit of this relay picks up.
2. Determine the operating time of the relay associated with the breaker in
the next substation towards the source,
• t2a is the operating time for back up relay and tmargin is the discrimination margin for
the same fault as 1
3. With the same fault current as in 1 and 2 above, and knowing t2a and the
PU value for relay 2, calculate the time dial setting for relay 2.
• Use the closest available relay time dial setting whose characteristic is above the
calculated value.
4. Determine the operating time (t2b) of relay 2, but now using the fault
level just before the operation of its instantaneous unit.
5. Continue with the sequence, starting from the second stage
 Time discrimination margin
• time discrimination margin between two successive time/current
characteristics of the order of 0.25–0.4 s should be typically used for
selectivity:
• breaker opening time
• relay overrun time after the fault has been cleared
• variations in fault levels.
• Single-phase faults on the star side of a DY transformer are not seen on
the delta side.
• setting earth-fault relays, the lowest available time dial setting can be applied to
the relays on the delta side, which makes it possible to considerably reduce the
settings and thus the operating times of earth-fault relays nearer the source
infeed.
Mathematical expression for relay
Relay R1 does not have any coordination responsibility and hence it can trip without any
intentional time delay. Relay R2 has to coordinate with relay R1 and hence its time of
operation is delayed by time equal to Coordination Time Interval (CTI). Relay R3 has to back
up R2. Hence its time of operation is delayed by another CTI. Thus, we see that as we move
along towards source, the relaying action slows down.
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Pick up current for phase fault protection
• Guidelines
• Pickup current should be above maximum load current seen by the feeder.
This ensures that relay does not trip on load. Iref > 1.25 ILmax
• Pick up current should be below the minimum fault current i.e; Iref < Ifmin.
This ensure that protection system operates for low as well as high fault
current.
• During this condition, in the utility least number of generators are in service. Hence, this
coordination occurs at light load condition and at the remote end of the feeder

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Pick up current for phase fault protection
• Guidelines
• Pick up current should also be below the minimum fault current of the feeder
that it has to backup. Otherwise, a relay's backup protection responsibility will
not be fulfilled.
• For a fault on the feeder being backed up, the relay should provide sufficient
time for the corresponding primary relay to act before it issues tripping
command. This interval is called CTI (co-ordination time interval). Typically,
CTI is about 0.3 sec. It consists of CB operating time+ Relay operating time +
Factor of safety
If above measures can not be satisfied simultaneously, then
overcurrent relays cannot be used for protection. Alternatives are
distance or directional protection.

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Back up protection by time discrimination
• Relay setting and coordination involves primarily following steps:
• Identify all possible Primary-Back-up relay pairs.
• Decide the correct sequence for coordination of relays.
• Decide the pickup value and hence PSM for relays.
• Compute the TMS/TDS to meet the coordination.
• Validation of the results.

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Identification of primary backup relay pairs

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Identification of primary backup relay pairs

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Identification of primary backup relay pairs

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Identification of primary backup relay pairs

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Identification of primary backup relay pairs

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Setting and Coordination of Overcurrent
Relays
• Relay settings and coordination activity has to be determined after
identifying the primary and backup relay pairs
• At leaf node, the relay is not providing the back up so the TSM/TDS is set to
minimal level
• The PSM is set for the primary and the back up relay
• TMS of the back-up relays is computed so that they maintain at least a time
delay equal to CTI with all primary relays
• Then, we delete the leaf nodes, update the coordination tree and this
process is repeated until we hit the source node

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Setting and Coordination of Overcurrent
Relays
Step 1 Initialize the coordination tree.
Step 2 Are there any leaf nodes except the root? If yes, go to step - 3, else to
step - 7.
Step 3 Identify the leaf nodes in coordination tree.
Step 4 If the PSM and/or TMS of these relays have not been set so far, set
them.
Step 5 Identify the backup relay of leaf-nodes in step - 3. Compute their PSM
and TMS for backup protection and co-ordination.
Step 6 Delete the leaf nodes. Update the co-ordination tree and go back to
step - 2.
Step 7 The co-ordination activity is now complete.
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Example

3 ϕ fault under consideration; Relays used have Normal Inverse, IEC standard
characteristics. Coordination time interval CTI is 0.3sec.
Required primary protection should fulfill its responsibility within 1.0 sec

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Example
• Pick up current settings for the relays should be above the feeder load
currents and not the bus load currents
• Rule of thumb: set the pick-up current at 1.25 times maximum load current
or limit to 2/3rd of the minimum fault current

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Example
• Pick-up current of relay R2, not adequate to just look at the minimum
fault current of section CB.
• Because, relay R2 has to back up the relay R1. Hence, minimum fault current
to be protected by relay R2 is also 250 A.
• However, if we use same TMS/TDS setting for R2 as R1 then it leads to a
serious conflict of interest between relays R1 and R2 with both of them
competing to clear the fault.
• If R1 clears the fault F1 first, then there is absolutely no problem. But if R2
clears the fault first then, there is an unwanted loss of service to load at node
B.

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Example
• Step 1
• Choose for relay R1
TMS = 0.025. No intentional time delay is provided because R1 does not have
backup responsibility.
Relay 1 (R1), pickup current = 160A.
For fault on section AB (Ifmax = 500 A):
PSM = Fault Current / Actual Pick up = 500/160 = 3.125
Operating time using IEC SI TCC

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Example
• Step 2
Relay 2 (R2)
Let, Actual Pick up = 167 A. R2 co-ordinate with R1 for close in fault for
relay R1 leading to large PSM. If relays co-ordinate at large PSM, then co-
ordination at lower values is automatically ascertained.
PSM = Max Fault Current / Actual Pick up = 500/167 = 2.99
Expected operating time for relay 2 = Operating time of relay 1+ CTI = 0.15
+ 0.3 = 0.45sec.

TMS = 0.07

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Example
• Now for maximum fault current on section BC (1200A)
PSM = Fault Current / Actual Pick up = 1200/167 = 7.185 with TMS =
0.07 operating time of relay 2

• Operating time of relay 2 = 0.24sec.

In the similar way all relays can be coordinated.

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Fault Type and CT burden
Consider a three phase fault in WYE
connected CT. The current does not require
an explicit return path. Therefore, only single
lead wire resistance RL is taken into account.
Then effective impedance seen by CT, Z = RS
+ RL + ZR.
phase to ground fault: fault current requires
an explicit return path and hence the lead
wire resistance RL has to be doubled.
Effective impedance: Z = RS + 2RL + ZR

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Fault Type and CT burden

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 Example 2

1. A 8 MVA, 138/13.8 KV transformer is connected to an infinite bus. If a bolted three

phase fault occurs at F, find out the fault current. The impedance of the transformer is
10% and location of the fault is close to the bus
2. If the distribution feeder has 600/5 C 200 CT with a knee point 100 Volt, calculate the
voltage developed across CT and comment on its performance. CT secondary resistance
is 0.414 Ω.
Assume that (1) CTs are star connected (2) Lead wire resistance is 0.411Ω and relay
impedance is 0.259 Ω .
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 Example 2

3. If the existing 8 MVA transformer is replaced with a new 28 MVA transformer with
10% leakage impedance, find out the new fault current. Will this new fault current
lead to CT saturation?
4. In case CT saturates, comment on the performance of
(a) Primary relay (b) back up relay (c) co-ordination between primary and back up
relay pair.

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Earth Fault Relays
Overcurrent Protection
Earth-fault Relays
• Used to protect feeder against faults involving ground.
• Typically, earth faults are single line to ground and double line to ground
faults.
• For the purpose of setting and coordination, only single line to ground faults
are considered.
• Maximum fault current line to ground is given by:
3E
IF 
Z s1  Z s 2  Z s 0
• For identical sequence impedance:
E
IF 
Z s1
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Earth-fault Relays
• The IF is identical to the bolted three phase fault current.
• If however, ZS0 < ZS1 then the bolted single line to ground fault current can be higher
than the three phase fault current.
• As we move away from the source, for a bolted fault, fault current reduces due to
larger impedance. Since, for a feeder, zero sequence impedance can be much higher
than the positive or negative sequence impedance, it is apparent that fault current
for bolted fault reduces significantly as we go away from source.
• If single line to ground fault has an impedance ZF, then the fault current can fall even
below the bolted line to ground fault value.
3E
IF 
Z1,eq  Z 2,eq  Z 0,eq  3Z F
In contrast, for a balanced system, three phase fault current is independent of the
value of ZF.
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Earth fault relays
• Important
• Significant variation in earth fault current values and can be even
below the load current due to large impedance to ground.
• To provide sensitive protection, earth fault relays use zero
sequence current rather than phase current for fault detection.
• Note that the zero sequence component is absent in normal load current
or phase faults. Hence, pickup with zero sequence current can be much
below the load current value, thereby providing sensitive earth fault
protection.

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 Earth fault relays
• Distribution systems are inherently unbalanced
and therefore load current would also have a
small percentage of zero sequence.
• mandatory to keep the pick up current above the
maximum unbalance expected under normal
conditions.
• Rule of thumb assume maximum unbalance factor to
be between 5 to 10%.
• Earth fault relays will not respond to the three
phase or line to line faults.
• One earth fault relay is adequate to provide protection
for all types of earth fault
• Three phase relays are required to provide protection
against phase faults
• Thus with four relays complete overcurrent protection
can be provided
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Adaptive Relaying
• Protection scheme in which settings can adapt to the system
conditions automatically, so that relaying is tuned to the prevailing
power system conditions.
• Traditionally, in overcurrent fault protection, one would like to choose pick-up
current to be above the maximum possible load current and below minimum
possible fault current. Sometimes, it may be quite difficult to obtain such
'comfort zones'. for relay settings.
• Load currents vary significantly from 'light loads' to 'peak load'
conditions, one can increase 'sensitivity' of a overcurrent relay under
light load conditions by safely reducing corresponding overcurrent
pick up value. Such, adjustments makes relaying' adaptive'.
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Adaptive Relaying
• In the present era, generation is being added to the distributed system
directly. This also changes the fault level in the system directly.
• Presence or absence of grid and/or distributed generator will alter fault
current levels drastically, and it would be impossible to achieve a single
acceptable setting for distributed generators.
• However, if overcurrent relay could be made aware through
communication that grid and/or DG is connected, it could choose the
settings from a set of a present values and 'adaptive' to new load
condition.
• Adaptive protection has not yet realized its full potential, and hence
provides new opportunities for bright and innovative research in relaying.

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Automatic Reclosing
• Faults (80-90%) in the overhead distribution system like flash over of
insulators, temporary tree contacts , etc are temporary in nature
taking a feeder or line permanent outage
• lead to unnecessary long loss of service to customers.
• Many utilities use fast automatic re-closers for an overhead radial
feeder without synchronous machines or with minimum induction
motor load.
• Presence of synchronous machines will require additional problem of
synchro-check to be addressed.
• The almost universal practice is to use three and occasionally four attempts to
restore service before lock out

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Automatic Reclosing
• The initial re-closure can be high speed (0.2 - 0.5 sec) or delayed for 3
- 5 seconds - allowing for de-ionization time for fault arc.
• If the temporary fault is cleared, then the service is restored.
Otherwise, the relay again trips the feeder.
• Then one or two additional time delayed re-closures are programmed on the
reclosing relay.
• Re-closers use three phase and single phase oil or vacuum circuit breakers for
overhead distribution lines.
• With underground network, faults tend to be more often permanent
and re-closers are not recommended.

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Automatic Reclosing

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