Author: BSEE Hugo E Reyes (Universidad del Zulia - Venezuela)
ABSTRACT
This paper describes the most
important principles of Non-directional Overcurrent Protective Relays (50/51),
this type of protective device is generally used to protect radial power lines. An Overcurrent Relay (OCR) needs current information coming from current transformers
(CTs) to detect short-circuit currents (faults) or intolerable current
conditions in the protected element, once the fault has been detected the
overcurrent relay makes the decision of tripping (to open) the circuit breaker
(52) associated in order to clear the fault.
Key words: Non-directional Overcurrent Relay, Instantaneous
Overcurrent Element, Inverse Time Overcurrent Element, Definite-Time
Overcurrent Element, Pickup Current, Dial Time.
INTRODUCTION
The overcurrent relay (OCR) is
the most used protective device in industrial and utility distribution system,
it is the simplest relay in concept to use, the OCR was developed to some
extent emulate the characteristic of fuse.
The OCR must not to trip during
normal conditions but must to trip when it detect short-circuits in the
protected element.
There are operating conditions related to the
operation of the power system which are abnormal, but these are not faults
either so the OCR must not to trip under these conditions.
Examples of abnormal conditions are:
- Starting
currents of induction motors,
- Inrush
currents of transformers,
- Cold load
restoration (i.e. reenergizing circuits after an outage),
- Maximum
short-time overloads, and
- Conditions
of power swing.
There is an intolerable condition
as a sudden unbalance current such as open phases that can damage the rotor of
motors and generators, under this abnormal condition the overcurrent relay must
to trip as fast as possible. Other intolerable conditions are: reversed phase
rotation, abnormal frequency, overvoltage, undervoltage, etc.
THUS, THE OVERCURRENT RELAY AND IN FACT ALL
TYPE OF PROTECTIVE RELAYS MUST BE ABLE TO DISCRIMINATE BETWEEN NORMAL OPERATING
CONDITIONS, ABNORMAL CONDITIONS, INTOLERABLE CURRENT CONDITIONS AND SHORT-CIRCUIT
FAULTS.
RELAY IEEE
C37.2 DEVICE NUMBERS
The IEEE
C37.2 defines the function numbers and acronyms for devices and functions that
are used in electrical substations, generating stations and every power system.
Applied to protective relays some device
numbers are:
21: Distance Relay
24: Volts per Hertz Relay
27: Undervoltage Relay
32: Directional Power Relay
46: Reverse-Phase or Phase Balance Current
Relay
50: Instantaneous Overcurrent Relays
51: AC Inverse Time Overcurrent Relay
52: AC Circuit Breaker
59: Overvoltage Relay
67: AC Directional Overcurrent Relay
86: lockout Relay
87: Differential Protective Relay
OVERCURRENT PROTECTION SCHEME
A typical non-directional
overcurrent protection scheme is shown in figure 1.
Fig. 1 Typical Non-directional OCR Protection Scheme.
This protection scheme consists
of a set of current transformers (CTs), an overcurrent relay and its associated
circuit breaker and DC power supply (commonly 125 VDC). Overcurrent relays
receive a current magnitude from CTs and when that current is above a
predefined threshold they issue a trip signal to open an associated circuit
breaker
In the figure 2 is shown a typical DC tripping
circuit.
Fig. 2 Simplified DC Tripping Scheme of an OCR.
The contacts are shown in their
de-energized position. The normally open (NO) 52a circuit breaker (CB) contact is closed when the CB is closed. Relay
operation for a fault implies a closing of any Normally Open (NO) relay
contacts (51-1/2/3/N). This operation stablishes a current through CB Trip Coil
(52-TC) disconnecting the protected element. When the CB trips, the 52a contact
open to interrupt the tripping current.
We can see in the figure 2 that
each overcurrent phase element (51-1/51-2/51-3) measures only one phase current
and also we have a residual overcurrent element (51-N), this residual
connection allow the neutral element to measure the sum of the phase currents,
which is equivalent to the residual current 3.I0 (where I0 is the zero sequence current), so
this scheme need four electromechanical relays. Nowadays, numerical relays
allow the implementation of this scheme in one relay.
SYSTEM PROTECTION OBJECTIVES
Protection systems should have
several protection objectives or properties, the most important objectives are:
- Sensitivity
- Selectivity
- Speed of operation
- Reliability and Dependability
- Security
- Simplicity
- Economy
Sensitivity: is the
ability of the protective system to detect and operate under the presence of the
smallest faults within the protected elements.
Selectivity: is also known as relay coordination or
protection coordination, is the ability of the protective system to clear a
fault as fast as possible within the protected element by tripping only those
circuit breakers whose operation is required in order to isolate the fault.
Protection coordination means that primary protection eliminates faults
as fast as possible while the backup protection operates only if primary
protection fails.
Fig. 3 Example of
Selectivity
Speed of operation: is
the ability of the protective system to operate in a short time after any fault
inception. Relaying system operation time includes relay and circuit breaker
operation time. Typically, the operation time is given in cycles according to
the power system frequency (50 or 60 Hertz).
Example: one (1) cycle is equal to 16.67 milliseconds (ms) at 60 Hz
and 20 ms at 50 Hz. An instantaneous relay (ANSI 50) is a relay with no
intentional time delay while a high speed relay operates is less than 3 cycles
(50 ms) at 60 Hz. Nowadays, the instantaneous element of the numerical relays
can operates in about 1 cycle. On the other hand, typical circuit breaker
operation time are from 2 cycles to 8 cycles.
Example: if an instantaneous relay operates a 1 cycle (16.67 ms)
and its associated circuit breaker at 3 cycles (50 ms) the fault clearing time
would be 4 cycles (66.67 ms).
Reliability: is a measure
of the degree of certainty that a relay system will perform correctly. A
reliable relay system is one that trips when required (dependability) but does
not trip when no required. Reliability is dependent on incorrect
design/settings, incorrect installation/testing and deterioration in service. However,
it is found that simple relay systems are more reliable. System which depend on
local information tend to be more reliable and dependable than those than
depend upon the information at the remote end.
Dependability: is the
certainty of correct operation in response to system troubles. Dependability
includes the reliable operation of the relay system operating when it is
supposed to and selectively of the relay system operating to isolate the
minimum amount of the system necessary to provide continuity of service.
Security: is the ability
to avoid misoperations between faults. Every relay system has to be designed to
either operate or not operate selectively with other systems.
Simplicity: is very
important to keep a relay system as simple as possible. Therefore, it is
important to make sure that the protection system is only as complex as
required to meet the power system protection requirements.
Economy: a low-cost relaying system is not
necessarily the most economical solution, is important to define the level of
protection versus the protection cost according to the economic loss that the
protection system may prevent.
ZONES OF PROTECTION
Various zones of protection are
shown in Figure 4. It can be seen that the adjacent zone overlap. The
protection in each zone should overlap that in the adjacent zone. The location
of the current transformers (CTs) supplying the relay system defines the edge
of the protective zone.
Fig. 4 Typical System
and Its Zones of Protection.
The power system is divided into
protective zones for:
- Generators
- Transformers
- Buses
- Transmission
y sub-transmission power lines
- Motors
Protection zones are classified
as primary
and/or backup. The primary protective relays are the first line of
defense against system faults and operate first to isolate the fault.
Typically, primary protection operation should be as fast as possible,
preferably instantaneous (1 cycle to 3 cycles), if the fault is not isolated
after some time delay, backup protection clears the faulted equipment by
re-tripping the primary circuit breakers or by tripping circuit breakers in
adjacent zones. When adjacent zones are tripped by backup protection, more of the
power system is removed from service. The Backup protection should also
preferably be located at a place different from where the primary protection is
located.
NON-DIRECTIONAL OVERCURRENT RELAY BASIS
A non-directional overcurrent
relay (OCR) has a single input in the form of AC current coming from a CT’s
set. The output of the OCR is a normally open (NO) contact, which changes over
to closed state when the relay trips due to a short-circuit fault. In Figure 5
is shown a block diagram of a simple OCR.
Fig. 5 Typical Block
Diagram of an Overcurrent Relay
As we can see in Figure 5, the non-directional overcurrent
relay has two setting:
- Time Dial
Setting (TD)
- Pickup
Setting (TAP or 51P1P)
The Time
Dial setting (TD) decides the operating times of the overcurrent relay while
the Pickup Current ( TAP or 51P1P) decides the current required for the relay to pick-up
(and trip).
The name “TAP”
comes from the electromechanical overcurrent relays. In these relays we have to
insert a Tap Screw in a Tap Block
Bridge (see Figure 6), also the Main Coil of the OCR has Taps that allow adjusting of the Numbers
of Turns. We can adjust the Pickup Current (51P1P) electrically by changing Coil Taps. The same terminology continues to be used in the modern
relays.
Fig. 6 Operating Coil of an
Electromechanical Relay.
The multiple of
pick-up or multiplier (M) is defined as follows:
M = Isecondary/Ipickup (Eq. 1)
M =
(Iprimary/CTR) / Ipickup
Where:
CTR: is the CT Ratio
The value of Multiple of Pickup (M) tells us
about the severity of the current as seen by the relay. If M < 1 means that
normal current is flowing. At M > 1, the relay is supposed to Pick Up (Trip).
Higher values of M indicate how serious the short-circuit fault is.
Example:
Let us consider
a primary fault of 2.5 kA, a CTR equal to 40 (200/5 A), and a relay pickup
current of 3.5 A (Tap), then the multiple of pickup would be:
M = (2 500/40)/ 3.5 = 17.85
When a fault
clears and the relay current drops below the pickup current then the
overcurrent relay resets to a normal state. The time for the relay to
completely reset is called Reset Time.
Most
of the electromechanical overcurrent relays will not start to reset until the
current drops below about 60% of the pickup current but in digital overcurrent
relays is typically 95%.
OPERATING TIME
CHARACTERISTIC OF OVERCURRENT RELAYS
According to
operating time characteristic the OCRs are classified into:
- INSTANTANEOUS OVERCURRENT RELAYS ( 50)
- TIME-DELAYED OVERCURRENT RELAYS (51) (Define Time and Inverse Time)
INSTANTANEOUS OVERCURRENT RELAYS (50)
These relay have
no intentional time delay, the terms instantaneous and high-speed are
frequently used interchangeable. The operating time of an instantaneous relay
is of the order of one cycle or less. Such a relay has only the pickup current
setting and does not have time setting. These relays are typically used in
high-set primary overcurrent protection schemes.
Fig. 7 Instantaneous Time-Current Curve
TIME-DELAYED OVERCURRENT RELAYS (51)
These relays are classified into:
-
DEFINITE TIME OVERCURRENT RELAY
-
INVERSE TIME OVERCURRENT RELAY
DEFINITE TIME OVERCURRENT RELAY
These relays can be adjusted to
trip at a definite amount of time, after it pickups. Thus, it has a
time-setting adjustment and also a pickup current adjustment. These relays are
typically used for short power lines application and when coordination is not a
problem.
Fig. 8 Definite Time Current Curve
INVERSE TIME OVERCURRENT RELAY
(51)
The characteristic is inverse in
the initial part, which tends to a definite minimum operating time as the
current becomes very high. The reason for the operating time becoming definite
minimum at high values of current, is that in the electromechanical relays the
magnetic flux saturates at high values of current and the relay operating
torque, which is proportional to the square of the flux, does not increase
substantially after the saturation sets in. The resulting time-current
characteristic is inverse: the operating time diminishes when current
increases. Inverse Time Overcurrent Relays have a Pickup Current Setting and a
Time Dial Setting (TD).
Time-current characteristics of
inverse time overcurrent relays are usually divided into families. Thus, each
family contains a number of curves with a certain degree of inverseness. Per
each curve of family, there are different pickup currents and curves to satisfy
a variety of coordination requirements.
Inverse Time Overcurrent
Characteristic are divided in:
- DEFINITE
TIME (DT CO-6)
- MODERATELY
INVERSE (MI CO-7)
- INVERSE (I
CO-8)
- VERY
INVERSE (VI CO-9)
- EXTREMELY
INVERSE (EI CO-11)
These time-current
characteristics are shown in Figure 9.
Fig. 9 Time-Current
Curve Shape Comparison
Note: these curves belong to a conventional
Westinghouse type CO relays (electromechanical).
These time-current characteristic in Figure 9 are selected so
that all relays operate in 0.2 seconds at 20 times the Tap setting (M).
There
is no a unique way of selecting the ideal curve shape for a specific
application, except to make preliminary setting calculations. However, some
general comments can be made:
- Use
a comparable shape within a system segment for easier coordination.
- Use
a Define Time element (CO-6) when coordination is not a problem and for short
line application.
- Use
an Extremely Inverse Time element (CO-11) when fuses are involved.
- The
Inverse Time Element (CO-8) provides faster clearing time than the Very Inverse
Time Element (CO-9) for low current faults, so is suitable in long lines where
the available fault current is much less at the end of the line than at the
local end. It does not provide much margin for cold load pickup.
Also,
the flatter curves DT (CO-6) and VI (CO-7) are suitable when:
-
There are no
coordination requirements with other types of protection devices farther out in
the system.
-
The variation in
current for faults at the near and far ends of the protected circuit is too
small.
-
Instantaneous
trip units give good coverage.
The Figure 10 shows a families of
curves for a Moderately Inverse (MI
CO-7) Relay. The number on the curves are the corresponding Time Dial
Setting (TD) values. By increasing the time dial setting (TD) the relay
increase the operating time.
Fig. 10 Typical Time
Curves of The Type CO-7 Relay (51).
These Time current curves are plotted in terms of the
multiple of pickup (M) and Time Dial Setting (TD). For M equal or greater than
1 the elements picks up, and for M< 1 it resets.
INVERSE
TIME CHARACTERISTIC EQUATIONS FOR OVERCURRENT RELAYS (51)
The US STD IEEE C37.112 provides equations that define
Time-Current Characteristics for both the Operating Time (To) and the Reset
Time (Tr) of Inverse Time Overcurrent Elements.
The Operating Time Equation defines a family of Time-Current
Curves, with each curve determined by the TD Setting.
To = TD .{ A / (M^p -1)+B} , M ≥ 1 (Eq. 2)
Where:
To:
is the operating time in seconds (s).
TD:
is the time dial.
M: is the Multiple of
Tap (M = (Iprimary/CTR) / Ipickup)
Constants
A, B and P: they define different families of time-current
characteristics.
In Table 1 are shown the constants values
according to the IEEE curve shapes.
|
IEEE
CURVE SHAPE
|
A
|
B
|
P
|
|
Extremely Inverse
|
28.20
|
0.1217
|
2.00
|
|
Very Inverse
|
19.61
|
0.4910
|
2.00
|
|
Moderately Inverse
|
0.0515
|
0.1140
|
0.02
|
|
US Inverse
|
5.95
|
0.1800
|
2.00
|
Table 1 Constants for IEEE Standard Characteristics in Equation 2The Reset Time (Tr)
in Equation 3 describes a family of
reset time characteristics. The time dial setting (TD) determines the curve,
and constant C is the reset time (Tr) for M = 0 and TD = 1.
Tr =TD. { C/(1-M^2 )} ,
M < 1 (Eq. 3)
On the other hand, for European applications the Std IEC 60255-151
provides an equation (Eq. 4) for the
operating time of Inverse-Time Overcurrent Element, the equation does not
include parameter B, which provides
definite time behavior to the curve for large currents.
To=TD.( A/(M^p-1)) , M
≥ 1 (Eq. 4)
In Table 2 are shown the constants values
according to the IEC curve shapes.
|
IEC
CURVE SHAPE
|
A
|
P
|
|
Extremely Inverse
|
80.00
|
2.00
|
|
Very Inverse
|
13.50
|
1.00
|
|
Standard Inverse
|
0.14
|
0.02
|
|
Long Time Inverse
|
120.00
|
1.00
|
Table 2 Constants for IEC Standard Characteristics in Equation 4
SELECTING
PICKUP CURRENT OF INVERSE TIME OVERCURRENT RELAYS (51)
The overcurrent relay (OCR)
should allow normal load and also a certain degree of overload to be supplied. Also,
is important to determine the maximum possible load or Short Time Maximum Load
(STML) for each circuit, this STML is the reference value that should be used
for setting the pickup current. At the same time the OCR should be sensitive
enough to respond to the smallest fault.
The pickup value (Tap)
of the Phase OCR should be at least 2 times the normal maximum load and never
less than 1.5 times. If the STML is greater than the normal maximum load, then
the Tap can be selected greater than 1.25 the STML.
The Figure 11 shows a single line
diagram (SLD) of a radial system,
there is an overcurrent device 2 (OCR-2)
providing primary protection to the power
line, between Bus 1 and Bus 2, and also a backup protection to an
overcurrent device 1 (OCR-1). The
OCR-2 must detects short-circuit faults beyond the downstream OCR-1, the backup
protection is executed if the OCR-1 fails to operate in its primary zone. Hence,
the goal is to select the pickup current of the OCR-2.
Fig. 11 Single Line
Diagram (SLD) of a Radial Power System.
The pickup current for a phase overcurrent relay OCR-2 must
to be set at a value greater than the maximum load current (IML) and lower than
the minimum fault current in its circuit (IFMIN), so:
IML < IPICKUP-51P1P-2
< IFMIN-2
Where,
IFMIN-2 = IFMAX-1
Usually, the Pickup Current
Element (51P1P) can be selected as:
IPICKUP-51P1P-2
= 125% * IML
Note:
For default, some overcurrent relays have
an increased pickup current value. For example: 1.1 times greater than the
pickup current.
On the other hand, knowing the Relay’s Time Dial, the Inverse Time
Curve, and also the maximum short-circuit current available we can calculate the
operating time (To) by using the specific equation.
SELECTING
PICKUP CURRENT OF INSTANTANEOUS OVERCURRENT RELAYS (50)
The Figure 12 shows a single line diagram (SLD) of a radial system, there is an
overcurrent device 2 (OCR-2)
providing primary protection to the power
line between Bus 1 and Bus 2, and also a backup protection to an
overcurrent device 1 (OCR-1).
Figure 12 SLD and
Coordination Curves of OCR-1 and OCR-2. When inverse time overcurrent
relays are being used and In order to make a correct coordination between
relays OCR-1 and OCR-2 shown in Figure 12, it is
important to consider that the OCR-2
element must have enough time delay to serve as the backup protection of the downstream
device OCR-1. Also, this time delay
would be present for faults between both overcurrent relays, where the device OCR-2 is the primary protection in its
zone. It can be seen from Figure 12 that as the fault location moves toward the
source, the fault currents become larger.
Thus,
the instantaneous current pickup of the OCR-2 (IPK-2) have to be greater than the maximum current fault at
the next downstream device zone (OCR-1). Typically, an instantaneous pickup
current setting for the backup protection device OCR-2, is 125% the maximum
current fault (IF1_MAX)
of the next downstream overcurrent relay (OCR-1).
Then, the
instantaneous pickup current for relay 2 is:
IPK-50P1P-2 = 1.25 * IF1_MAX
DIGITAL OVERCURRENT
RELAYS
Digital overcurrent relays are microprocessor-based relays,
they have the same settings as electromechanical relays, but digital relays can
do a lot of things that traditional relays cannot do, such as:
a) Allow selection of different standard inverse-time curves;
b) Includes
instantaneous, definite-time, and inverse-time overcurrent elements in a single
relay;
c) Includes phase, negative-sequence, and zero-sequence
overcurrent elements in a single device;
d) Beside of protection functions they also provides metering,
logic control and monitoring functions.
e) IEC 61850
communications.
COORDINATION
OF INVERSE TIME OVERCURRENT RELAYS (51)
The Figure 13 shows a single radial
system with two overcurrent relays (51) that we called OCR-1 and OCR-2. The
Figure 13 as well shows the relationship between the operating time curve of
the primary relay (OCR-1), and that of the backup relay (OCR-2).
In order to ensure selectivity the primary
relay curve (OCR-1) is located to the left and below of the backup relay curve
(OCR-2) with enough time margin that is essential for maintaining selectively
between both relays. Hence this time margin is referred to as the coordinating
time interval (CTI).
Figure 13 Coordination Process of Two Pair of OCR (51)
According with Time-Current
Curve in Figure 13, we have:
T2 = T1 + CTI
The CTI must considerer the circuit breaker (CB) time operation, the primary time over-travel time (just for electromechanical relays), relay tolerances and a safety factor.
Typical CTI that are commonly used are:
- For Relay to Relay application should be in the range of 0.20 to 0.50 seconds.
- For electromechanical relays, the minimum time margin for a 5 cycle (0.083s) circuit breaker is typically 0.30 seconds.
- For digital relays the CTI margin for a 5 cycle circuit breaker is typically 0.25 seconds.
- Electromechanical relay and fuse coordination requires a minimum time margin of 0.22 seconds between curves.
- Fuse and fuse coordination requires that the total clearing time of the downline fuse curve be less than 75% of the minimum melt time of the up-line fuse curve.
- Fuse and relay coordination requires a minimum time margin of 0.30 seconds between curves.
The coordination process has to
be started from the relay which is at the tail end of the radial system
(OCR-1), this is because this relay is not constrained by selectivity problems.
These coordination criterion is applied for all short-circuit faults at the
zone of relay OCR-1
Furthermore, the operating time
of an overcurrent relay must be faster than the equipment damage time (example:
damage curve of a power transformer: I2.t
curve) and slower than any normal transient behavior than may occur on the
system (starting currents of induction motors, Inrush currents of transformers,
Cold load restorations, etc.).
When the primary and backup
relays has the same type of inverse-time curves, the minimum separation between
them occurs at the maximum short circuit fault. On the other hand, if the
curves are of different types, the minimum separation between curves may occurs
at any short circuit current value. Then we need to check coordination for
every fault current interval.
SUMMARY
-
The Non-directional Overcurrent Relay (50/51) is
the most simple, cheap, and used protective device in radial systems, it was
developed to some extent emulate the characteristic of fuses.
-
An Overcurrent relay and in fact all kind of
protective relay must be able to discriminate between normal operating conditions,
abnormal conditions, intolerable current conditions and short-circuit faults.
-
Power systems protection must consider primary
and backup protection.
-
Non-directional overcurrent relays has two
setting:
o
Time Dial
Setting (TD):
o
Pickup
Setting (TAP or 51P1P)
The Time Dial setting (TD) decides the operating times of the overcurrent relay while the Pickup Current ( TAP or 51P1P) decides the current required for the relay to pick-up (trip).
The
multiple of pickup (M) is also called Multiple of Tap. The name
“Tap”
comes from the electromechanical overcurrent relays.
The value of Multiple of Pickup (M) tells us about the severity of the current as seen by the relay. If M < 1 means that normal current is flowing. At M > 1, the relay is supposed to Pick Up (Trip). Higher values of M indicate how serious the short-circuit fault is.
-
According to operating time characteristic the
OCRs are classified into:
o
INSTANTANEOUS OVERCURRENT RELAYS ( 50)
o TIME-DELAYED OVERCURRENT RELAYS (51) (Define
Time and Inverse Time OCRs)
-
Inverse Time Overcurrent Characteristic are
divided in:
o
DEFINITE TIME (DT CO-6)
o
MODERATELY INVERSE (MI CO-7)
o
INVERSE (I CO-8)
o
VERY INVERSE (VI CO-9)
o
EXTREMELY INVERSE (EI CO-11)
-
There is no a unique way of selecting the
ideal curve shape for a specific application. However, some general comments
can be made:
o
Use a
comparable shape within a system segment for easier coordination.
o
Use a Define Time element (CO-6) when
coordination is not a problem and for short line application.
o
Use an
Extremely Inverse Time element (CO-11) when fuses are involved.
o
The Inverse Time Element (CO-8) provides faster
clearing time than the Very Inverse Time Element (CO-9) for low current faults,
so is suitable in long lines where the available fault current is much less at
the end of the line than at the local end. It does not provide much margin for
cold load pickup.
-
The pickup current for an overcurrent relay must
to be set at a value greater than the maximum load current (IML) and lower than the
minimum fault current in its circuit (IFMIN), so:
IML < IPICKUP < IFMIN
-
The instantaneous current pickup of a backup
overcurrent relay (IPK-2) has to be greater than the maximum current
fault at the next downstream overcurrent relay. Typically, an instantaneous
pickup current setting for the backup protection device, is 125% the maximum
current fault (IF1_MAX) of the next downstream overcurrent relay.
o
Then, the instantaneous pickup current setting
are:
IPK-1 = IF1_MAX
IPK-2 = 1.25 * IPK-1
-
The coordination of a pair inverse time
overcurrent relays has to be started from the relay which is at the tail end of
the radial system, this is because this relay is not constrained by selectivity
problems.
REFERENCES
1. - IEEE STD C37.2-2008. IEEE STANDARD FOR
ELECTRICAL POWER SYSTEM DEVICE FUNCTION NUMBERS, ACRONYMS, AND CONTACT
DESIGNATIONS.
2. FUNDAMENTALS OF POWER SYSTEM PROTECTION –
SECOND EDITION, Y.G. PAITHANKAR, S.R. BHIDE
3. PROTECTIVE RELAYING PRINCIPLES AND
APPLICATIONS - THIRD EDITION. J. LEWIS BLACKBURN, THOMAS J. DOMIN.
4. PROTECTIVE RELAYING THEORY AND APPLICATIONS
– SECOND EDITION. WALTER A. ELMORE
