Over-current and Earth Fault
Protection
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v Introduction
As the fault impedance is less than load
impedance, the fault current is more than load current. If a short circuit
occurs the circuit impedance is reduced to a low value and therefore a fault
is accompanied by large current.
Over-current protection is that protection in which the relay picks up
when the magnitude of current exceeds the pickup level.
The basic element in Over-current protection is an Over-current relay.
The
Over-current relays are connected to the system, normally by means of CT's.
Over-current
relaying has following types:
1. High speed Over-current
protection.
2. Definite time Over-current
protection.
3. Inverse minimum time
Over-current protection.
4. Directional Over-current
protection (of above types).
Over-current
protection includes the protection from overloads. This is most widely used
protection. Overloading of a machine or equipment generally) means the
machine is taking more current than its rated current. Hence with
overloading, there is an associated temperature rise. The permissible
temperature rise has a limit based on insulation class and material problems.
Over-current protection of overloads is generally provided by thermal relays.
Over-current
protection includes short-circuit protection. Short circuits a be phase
faults, earth faults or winding faults. Short-circuit currents are generally
several times (5 to 20) full load current. Hence fast fault clearance is
always desirable on short-circuits.
When a
machine is protected by differential protection, the over-current is provided
in addition as a back-up and in some cases to protect the machine from
sustained through fault.
Several
protective devices are used for over-current protection these include:
1. Fuses
2. Circuit-breakers fitted with
overloaded coils or tripped by over-current relays.
3. Series connected trip coils
operating switching devices.
4. Over-current relays in
conjunction with current transformers.
The primary requirements of over-current protection are:
·
The protection should not operate for starting currents, permissible
over-current, and current surges. To achieve this, the time delay is provided
(in case of inverse relays). If time delay cannot be permitted, high-set
instantaneous relaying is used.
·
The protection should be coordinated with neighboring over-current
protections so as to discriminate.
v
Applications of Over-current Protection
Over-current
protection has a wide range of applications. It can be applied where there is
an abrupt difference between fault current within the protected section and
that outside the protected section and these magnitudes are almost constant.
The over-current protection is provided for the following:
v
Motor Protection
Over-current protection is the basic type of protection used against overloads and short-circuits in stator windings of motors. Inverse time and instantaneous phase and ground over-current relays can be employed for motors above 1200 H.P. For small/medium size motors where cost of CT's and protective relays is not economically justified, thermal relays and HRC fuses are employed, thermal relays used for overload protection and HRC fuses for short-circuit protection.
v
Transformer Protection
Transformers are provided with over-current protection against faults, only, when the cost of differential relaying cannot be justified. However, over-current relays are provided in addition to differential relays to take care of through faults. Temperature indicators and alarms are always provided for large transformers.
Small
transformers below 500 kVA installed in distribution system are generally
protected by drop-out fuses, as the cost of relays plus circuit-breakers is
not generally justified Line Protection.
The
lines (feeders) can be protected by
(1)
Instantaneous
over-current relays.
(2)
Inverse
time over-current relays.
(3)
Directional
over-current relay.
Lines
can be protected by impedance or carrier current protection also.
Protection of Utility Equipment
The
furnaces, industrial installations commercial, industrial and domestic
equipment are all provided with over-current protection.
v
Relays used in Over-current Protection
The
choice of relay for over-current protection depends upon the Time / current
characteristic and other features desired. The following relays are used.
1. For instantaneous over-current
protection. Attracted armature type, moving iron type,
permanent magnet moving coil type and static.
2. For inverse time
characteristic. Electromagnetic induction type, permanent magnet
moving coil type and static.
3. Directional over-current
protection. Double actuating quantity induction relay
with directional feature. 4. Static over-current relays. 5. HRC fuses, drop out fuses, etc. are used in low voltage medium voltage and high voltage distribution systems, generally up to 11 kV.
6. Thermal relays are used widely
for over-current protection.
Not: Now Digital Numerical Relay you can used for all types
v Characteristics of
relay units for over current protection
There
is a wide variety of relay-units. These are classified according to their
type and characteristics. The major characteristic includes:
1. Definite characteristic
2. Inverse characteristic
3. Extremely Inverse
4. Very Inverse
In
definite characteristic, the time of operation is almost definite i.e.
I 0 * T = K
Where:
I = Current in relay coil
T = Relay lime
K =
Constant.
In
inverse characteristic, time is inversely proportional to current i.e.
I 1 * T = K
In more
inverse characteristic
I n * T = K
Where n
can be between 2 to 8 the choice depends on discrimination desired.
Instantaneous
relays are those which have no intentional time lag sod which operate in less
than 0.1 second, usually less than 0.08 second. As suck they are not
instantaneous in real sense.
The
relays which are not instantaneous are called Time Delay Relay'. Such relays
are provided with delaying means such as drag magnet, dash poss. bellows,
escape mechanisms, back-stop arrangement, etc.
The
operating time of a relay for a particular setting and magnitude actuating
quantity can be known from the characteristics supplied by the manufacturer.
The typical characteristics are shown in (Fig. 1)
An
inverse curve is one in which the operating time; becomes less as the magnitude
of the actuating quantity is increased. However for higher magnitudes of
actuating quantity the time is constant. Definite time curve is one in which
operating time is little affected by magnitude of actuating current. However
even definite time relay has a characteristic which is slightly inverse
The
characteristic with definite minimum time and of inverse type is also called
Inverse Definite Minimum Time (IDMT) characteristics (Fig.1).
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Principle of trip circuit
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Referring
to (Fig. 2) the three current transformers and relay coils connected in star and
the star point is earthed. When short circuit occurs in the protected zone
the secondary current of CT's
increases.
These
current flows through relay coils and the relay picks-up, the relay contacts
close, thereby the trip circuit is closed and the circuit breaker-operates
The over-current protection scheme with three over-current relays (Fig. 2) responds to phase faults and earth faults
including single-phase to earth fault.
Therefore such schemes are used with solidly earthed systems where phase to phase and phase to earth faults are likely to occur.
For
proper functioning of over-current and
earth fault protection, the choice of CT's and polarity connections
should be correct.
Methods of CT Connections in
Over-current Protection of 3-Phase Circuits
v
Connection Scheme with Three Over-current Relays
Over-current protection can be achieved by means of three over-current
relays or by two over-current relays (See Table 1).
Table 1
v
Earth-Fault Protection
When the fault current flows
through earth return path, the fault is called Earth Fault. Other faults
which do not involve earth are
called phase faults. Since earth faults are relatively frequent, earth fault protection is
necessary in most cases. When
separate earth fault protection is not economical, the phase relays sense the
earth fault currents. However such protection lacks sensitivity. Hence
separate earth fault protection is generally provided. Earth fault protection
senses earth fault current. Following are the method of earth fault
protection.
v
Connections of CT's for Earth-fault Protection
1. Residually
connected Earth-fault Relay
Referring
to Fig. 3 In absence of earth-fault the vector sum of three line currents is
zero. Hence the vector sum of three
secondary currents is also zero.
IR+IY+IB=0
The sum
(IR+IY+IB) is called residual current
The
earth-fault relay is connected such that the residual current flows through
it (Figs.3 and Fig. 4), in the absence of
earth-fault,
Therefore, the residually connected earth-fault relay does not
operate. However, in presence of earth fault the conditions is disturbed and (IR+IY+IB) is no more zero. Hence flows
through the earth-fault relay. If the residual current is above the pick-up value,
the earth-fault relay operates.
In the scheme discussed here the earth-fault at any location near or
away from the location of CT's can cause the residual current flow. Hence
the protected
zone is not definite. Such protection is called unrestricted
earth-fault protection
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2.
Earth-fault Relay connected in Neutral to Earth Circuit (Fig. 5).
Another method of connecting an earth-fault relay is illustrated in
Fig 5. The relay is connected to secondary of a CT whose primary is
connected in neutral to earth connection. Such protection can be provided at
various voltage levels by connecting earth-fault relay in the
neutral-to-earth connection of that voltage level. The fault current finds
the return path through the earth and then flows through the neutral-to-earth
connected. The magnitude of earth fault current is dependent on type of earthing
(resistance, reactance or solid) and location of fault. In this type of
protection,
The
zone of protection cannot be accurately defined. The protected area is not
restricted to the transformer/generator winding alone. The relay senses the
earth faults
beyond the transformer/generator winding hence such protection is called unrestricted earth-fault protection. The earth-fault protection by relay in neutral to earth circuit depends upon the type of neutral Earthing. In case of large generators, voltage transformer is connected between neutral and earth
v
Combined Earth-fault and Phase-fault Protection
It is
convenient to incorporate phase-fault relays and earth-fault relay in a combined phase-fault and earth-fault
protection. (Fig. 4) The increase in current of phase causes corresponding
increase in respective secondary currents. The secondary current flows
through respective relay-units Very often
only two-phase relays are provided instead of three, because in case of phase faults current in any at
least two phases must increase. Hence two relay-units are enough.
v
Earth-fault Protection with Core Balance Current
Transformers. (Zero Sequence CT)
In this type of protection
(Fig. 6) a single ring shaped core of magnetic material, encircles the
conductors of all the three phases. A secondary coil is connected to a relay
unit. The cross-section of ring-core is
Ample,
so that saturation is not a problem. During no-earth-fault condition, the
components of fluxes due to the fields of three conductors are balanced and
the secondary current is negligible. During earth faults, such a balance is disturbed and current is induced in the
secondary. Core-balance protection can be conveniently used for
protection of low-voltage and medium voltage systems. The burden of relays and exciting current are deciding
factors. Very large cross-section of core is necessary for sensitivity
less than 10 A. This form of protection is likely to be more popular with
static relays due to the fewer burdens of the latter. Instantaneous relay
unit is generally used with core balance schemes.
v
Theory of Core Balance CT
. Let Ia, Ib and Ic, be the three line currents and Φa,
Φb
and Φc
be corresponding components of magnetic flux in the core. Assuming linearity, we get
resultant flux Φ as,
Φ=k (Ia
+ Ib + Ic)
where k is a
constant Φ = K * Ia. Referring to theory
of symmetrical components
(Ia + Ib
+ Ic)=3Ic=In
Where, Io is zero
sequence current and In, is current in neutral to ground circuit. During normal condition, when
earth fault is absent,
(Ia + Ib + Ic)
=0
Hence Φr = 0 and relay does not operate
During
earth fault the earth fault current flows through return neutral path.
For
example for single line ground fault,
If = 3Iao = In
Hence
the zero-sequence component of Io produces the resultant flux Φr in the core. Hence core balance
current transformer is also called as zero sequence current transformers (ZSCT).
v Application for Core
Balance CT's with Cable Termination Joints
The termination of a three core cable into three separate lines or
bus-bars is through cable terminal box. Ref. (Fig. 7),
the Core Balance Protection is used along with the cable box and
should be installed before making the cable joint.
The induced current flowing through cable sheath of normal
healthy cable needs particular attention with respect to the core balance
protection.
The sheath currents (Ish) flow
through the sheath to the cover of cable-box and then to earth through
the earthing connection between
cable-box. For eliminating the
error due to sheath current (Ish) the earthing lead between the cable-box
and the earth should be taken through the core of the core balance protection.
Thereby the error due to sheath
currents is eliminated. The cable box should be insulated from earth.
1.
Cable
terminal box
2. Sheath of 3 core cable
connection to (1)
3. Insulator support for 1
4. Earthing connection passing
through 5
5. Core balance CT
v
Frame-leakage Protection
The metal-clad switchgear can be provided with frame leakage protection. The
switchgear is lightly y insulated from the earth. The metal-frame-work or
enclosure of the switchgear is earthed with a primary of a CT in between (Fig. 8).
The concrete foundation of the switchgear and the cable-boxes and
other conduits are slightly insulated from earth, the resistance to earth
being about 12 ohms. In the event of an earth fault within the switchgear,
the earth-fault current finds the' path through the neutral connection. While
doing so, it is sensed by the earth fault relay.
Circulating
current differential protection also responds to earth-faults within its
protected zone.
v Earth-fault protection
can be achieved by following methods:
1. Residually connected relay.
2. Relay connected in
neutral-to-ground circuit.
3. Core-balance-scheme.
4. Frame leakage method.
5. Distance relays arranged for
detecting earth faults on lines.
6. Circulating current differential
protection.
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Directional Over-current Protection
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The
over-current protection can be given directional feature by adding
directional element in the protection system. Directional over-current
protection responds to over-currents for a particular direction
flow. If power flow is in the opposite direction, the directional
over-current protection remains un-operative.
Directional
over-current protection comprises over-current relay and power directional relay- in a single relay
casing. The power directional relay does not measure the power but is
arranged to respond to the direction of power flow.
Directional operation of relay is used where the
selectivity can be achieved by directional relaying. The directional relay
recognizes the direction in which fault occurs, relative to the location of
the relay. It is set such that it actuates
for faults occurring in one direction only. It does not act for faults
occurring in the other direction. Consider a feeder AC (Fig. 9) passing through sub-section B. The circuit
breaker CB3 is provided with a directional
Relay
`R' which will trip the breaker CB3 if
fault power flow in direction C alone.
Therefore for faults in feeder AB, the circuit breaker CB3 does
not trip unnecessarily. However for faults in feeder BC the
circuit-breaker CB3 trips
Because
it's protective relaying is set with a directional feature to act in
direction AC
Another
interesting example of directional protection is that of reverse power
protection of generator (Fig. 10). If the prime mover fails, the generator
continues to run as a motor and takes power from bus-bars.
Directional
power protection operates in accordance with the direction of power flow.
Reverse power protection operates when the power
direction is reversed in relation to the normal working
direction. Reverse power relay is different in construction than
directional over-current relay.
In directional over-current relay, the directional element does not
measure the magnitude of power. It senses only direction of power flow.
However, in Reverse Power Relays, the directional element measures magnitude
and direction of power flow.
v Relay connections
of Single Phase Directional Over-current Relay :
The current coils in the directional over-current relay are normally connected to a
secondary of line CT. The voltage coil of directional element is connected to
a line VT, having phase to phase output (of
110 V). There are four common methods of connecting the relay depending
upon phase angle between current in the current coil and voltage applied to
the voltage coil.
3-Phase Directional over current relays
When fault current can flow
in both directions through the relay location, it is necessary
to make the response of the relay directional by the introduction of directional
control elements. These are basically power measuring devices in
which the system voltage is used as a reference for
establishing the relative direction or phase of the fault current.
Although power measuring
devices in principle, they are not arranged to respond to the actual system
power for a number of reasons:
1.
The power system, apart from loads, is reactive so that the fault
power factor is usually low. A relay
Responding
purely to the active component would not develop a high torque and might be
much slower and less decisive than it could be.
1. The system voltage must
collapse at the point of short circuit. When the fault is single-phase, it is
the particular voltage across the short-circuited points which are reduced.
So a B—C phase fault will cause the B and C phase voltage vectors to move
together, the locus of their ends being the original line be for a
homogeneous system, as shown in (Fig.12)
At the point of
fault the vectors will coincide, leaving zero
voltage across the fault, but the
fault voltage to earth will be half the initial phase to
neutral voltage. At other points in the system the vector displacement will
be less, but relays located at such points will receive voltages which are
unbalanced in their value and phase position.
The effect
of the large unbalance in currents and voltages is to make the torques
developed by the different phase elements vary widely and even differ in sign
if the quantities applied to the relay are not chosen carefully. To this end,
each phase of the relay is polarized with a voltage which will not be reduced
excessively except by close three-phase faults, and which will remain in a
satisfactory relationship to the current under all conditions.
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Relay connections
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This is the
arrangement whereby suitable current and voltage
quantities are applied to the relay. The various
connections are dependent on the phase angle, at unity system power factor,
by which the current and voltage applied to the relay are displaced.
v
Relay maximum torque
The maximum
torque angle (MTA) is defined as the angle by which the current applied to
the relay must be displaced from the voltage applied to the relay to produce
maximum torque.
Although
the relay element may be inherently wattmetric, its
characteristic can be varied by the addition of phase shifting components to
give maximum torque at the required phase angle.
A number of
different connections have been used and these are discussed below.
Examination of the suitability of each arrangement involves determining the
limiting conditions of the voltage and current applied to each phase element
of the relay, for all fault conditions, taking into account the possible
range of source and line impedances.
v
30° relay connection (0° MTA)
The A phase
relay is supplied with current la
and voltage Vac. In this case, the flux due to the
voltage coil lags the applied Vac voltage by 90°, so the maximum
torque occurs when the current lags the system phase to neutral voltage by
30°. For unity power factor and 0.5 lagging power factor the
maximum torque available is 0.866 of maximum. Also, the potential
coil voltage lags the current in the current coil by 30° and gives a tripping
zone from 60° leading to 120° lagging currents, as shown in (Fig. 13a).
The most
satisfactory maximum torque angle for this connection, that ensures correct
operation when used for the protection of plain feeders, is 0°, and it can be
shown that a directional element having this connection and 0° MTA will
provide correct discrimination for all types of faults, when applied to
plain feeders
If applied
to transformer feeders, however, there is a danger
that at least one of the three phase relays will operate for faults in the
reverse direction; for this reason a directional element having this
connection should never be used to protect transformer feeders.
This
connection has been used widely in the past, and it is satisfactory under all
conditions for plain feeders provided that three phase elements are employed.
When only two phase elements and an earth fault element are used there is a
probability of failure to operate for one condition. An inter-phase short
circuit causes two elements to be energized but for low power factors one
will receive inputs which, although correct, will produce only a poor torque.
In particular a B—C fault will strongly energize the B element
with lb current and Vba voltage, but the C
element will receive Ic and the collapsed Vcb voltage, which quantities have a large relative
phase displacement, as shown in (Fig. 13b). This is satisfactory provided
that three phase elements are used, but in the case of a two phase and one
earth fault element relay, with the B
phase element omitted, operation
will depend upon the C element, which may fail to operate if the fault is
close to the relaying point.
v 60° No. 1 connection (0° MTA)
The A phase
relay is supplied with lab current and Vac voltage. In this case, the flux due to the
voltage coil lags the applied voltage to the relay by 90°, so maximum torque
is produced when the current lags the system phase to neutral voltage by 60°.
This connection, which uses Vac voltage with delta current
produced by adding phase A and phase B currents at unity power
factor, gives a current leading the voltage Vac by 60°, and
provides a correct directional tripping zone over a current range of 30°
leading to 150° lagging. The torque at unity power factor is 0.5
of maximum torque and at zero power factor lagging 0.866; see
(Fig.14).
It has been
proved that the most suitable maximum torque angle for this relay connection,
that is, one which ensures correct directional discrimination with the
minimum risk of mal-operation when applied to either plain or transformer
feeders, is 0°.
When used
for the protection of plain feeders there is a slight possibility of the
element associated with the A phase
mal-operating for a reversed B—C fault.
However,
although the directional element may mal-operation, it is unlikely that the
over current element which the directional element controls will receive
sufficient current to cause it to operate. For this reason the connection may
be safely recommended for the protection of plain feeders.
When
applied to transformer feeders there is a possibility of one of the
directional elements mal-operation for an earth fault on the star side of a
delta/star transformer, remote from the relay end. For mal-operation to
occur, the source impedance would have to be relatively small and have a very
low angle at the same time that the arc resistance of the fault was high. The
possibility of mal-operation with this connection is very remote, for two
reasons: first, in most systems the source impedance may be safely assumed to
be largely reactive, and secondly, if the arc resistance is high enough to
cause mal-operation of the directional element it is unlikely that the over
current element associated with the mal-operation directional element will
see sufficient current to operate.
The
connection, however, does suffer from the disadvantage that it is necessary
to connect the current transformers in delta, which usually precludes their
being used for any other protective function. For this reason, and also
because it offers no advantage over the 90° connection, it is rarely used.
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v
60° No. 2 connection (0° MTA)
The A phase
relay is supplied with current la
and voltage In this case, the flux of the
voltage coil lags the applied voltage by 90° so the maximum torque is
produced when the current lags the system phase to neutral voltage by 60°. This connection gives
a correct directional tripping zone over the current range of
30° leading to 150° lagging. The relay torque at unity
power factor is 0.5 of the relay maximum torque and at zero power
factor lagging 0.866; see (Fig.15).
The most
suitable maximum torque angle for a directional element using this connection
is 0°. However, even if this maximum torque angle is used, there is a risk of
incorrect operation for all types of faults with the exception of three-phase
faults. For this reason, the 60° No. 2 connection is now never recommended.
v
90° relay quadrature connection
This is the
standard connection for the type CDD relay; depending on the angle by which
the applied voltage is shifted to produce the relay maximum torque angle, two
types are available.
v
90°- 30° characteristic (30°
MTA)
The A phase relay is supplied with la current and Vbc
voltage displaced by 30° in an
anti-clockwise direction. In this case, the flux due to the voltage coil lags
the applied voltage Vbc by 60°, and the relay maximum torque is produced
when the current lags the system phase to neutral voltage by 60°. This connection
gives a correct directional tripping zone over the current range of 30°
leading to 150° lagging; see (Fig.16).
The relay torque at unity power factor is 0.5 of the relay maximum torque and at zero power factor
lagging 0.866. A relay designed .for quadrature connection and
having a maximum torque angle of 30° is recommended when the relay is used
for the protection of plain feeders with the zero sequence source behind the
relaying point.
v
90°- 45° characteristic (45°
MTA)
The A phase
relay is supplied with current la
and voltage Vbc displaced by 45°
in an anti-clockwise direction. In this case, the flux due to the voltage
coil lags the applied voltage Vbc by 45°, and the relay maximum
torque is produced when the current lags the system phase to neutral voltage
by 45°. This connection gives a correct directional tripping zone over the
current range of 45° leading to 135° lagging.
The relay
torque at unity power factor is 0.707 of the maximum torque and
the same at zero power factor lagging; see (Fig.17).
This connection is
recommended for the protection of transformer feeders or feeders which have a
zero sequence source in front of the relay. The 90°- 45° connection is
essential in the case of parallel trans-formers or transformer feeders, in
order to ensure correct relay operation for faults beyond the star/ delta
transformer. This connection should also be used whenever single-phase
directional relays are applied to a circuit
Theoretically, three fault
conditions can cause mal-operation of the directional element: a phase-phase
ground fault on a plain feeder, a phase-ground fault on a transformer feeder
with the zero sequence source in front of the relay and a phase-phase fault
on a power transformer with the relay looking into the delta winding of the transformer.
It should be remembered,
however, that the conditions assumed above to establish the maximum angular
displacement between the current and voltage quantities at the relay, are
such that, in practice, the magnitude of the current input to the relay would
be insufficient to cause the over current element to operate. It can be shown
analytically that the possibility of mal-operation with the 90°-
45° connection is, for all practical purposes, non-existent.
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Parallel feeders
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If
non-directional relays are applied to parallel feeders, any faults that might
occur on any one line will, regardless of the relay settings used,
isolate both lines and completely disconnect the power supply. With this type of
system configuration it is necessary to apply directional relays at the
receiving end and to grade them with the non-directional relays at the
sending end, to ensure correct discriminative operation of the relays during
line. faults. This is done by setting the directional relays R'1 and R'2 as shown in
(Fig.18) with their directional elements looking into the protected line, and
giving them lower time and current settings than relays R1 and R2. The usual
practice is to set relays R'1 and R'2 to 50% of
the normal full load of the protected circuit and 0.1 TMS, but care
must be taken to ensure that their continuous thermal
rating of twice rated current is not exceeded.
v
Ring mains
Directional relays are more commonly applied to ring mains. In the
case of a ring main fed at one point only, the relays at the supply end and
at the mid-point substation, where the setting of both relays are identical,
can be made non-directional, provided that in the latter case the relays are
located on the same feeder, that is, one at each end of the feeder.
It is interesting to note that when the number of feeders round the
ring is an even number, the two relays with the same operating time are at
the same substation and will have to be directional, whereas when the number
of feeders is an odd number, the two relays with the same operating time are
at different substations and therefore do not need to be directional.
It may also be noted that, at inter-mediate substations, whenever the
operating times of the relays at each substation are different, the
difference between their operating times is never less than the grading
margin, so the relay with the longer operating time can be non-directional.
v
Grading of ring mains
The usual procedure for grading relays in an inter-connected system is
to open the ring at the supply point and to grade the relays first clockwise
and then anti-clockwise; that is, the relays looking in a clock-wise
direction round the ring are arranged to operate in the
sequence 1—2—3—4—5—6 and the relays looking in the
anti-clockwise direction are arranged to operate
in the sequence 1'—2'—3'—4'—5'—6', as shown in
(Fig.19)
The arrows associated with the relaying points indicate the direction
of current flow that will cause the relays to operate.
A
double-headed arrow is used to indicate a
non-directional relay, such as those at the supply point where the power can
flow only in one direction, and a single-headed arrow a directional
relay, such as those at intermediate substations around the ring where the
power can flow in either direction. The directional
relays are set in accordance with the invariable rule,
applicable to all forms of directional protection that the current in the
system must flow from the substation bus-bars into the protected line in
order that the relays may operate.
Disconnection
of the faulty line is carried out according to time and fault current direction.
As in any parallel system, the fault current has two parallel paths and
divides itself in the inverse ratio of their impedances.
Thus, at
each substation in the ring, one set of relays will be made
inoperative because of the direction of current flow, and the other set
operative. It will also be found that the operating times of the relays
that are inoperative are faster than those of the operative
relays, with the exception of the mid-point substation,
where the operating times of relays 3 and 3' happen
to be the same.
The relays
which are operative are graded downwards towards the fault and the
last to be affected by the fault operates first. This applies to both paths
to the fault. Consequently, the faulty line is the only one to be disconnected
from the ring and the power supply is maintained to all the substations.
When two or
more power sources feed into a ring main, time graded over current protection
is difficult to apply and full discrimination may not be possible. With two
sources of supply, two solutions are possible. The first is to open the ring
at one of the supply points, whichever is more convenient, by means of a
suitable high set instantaneous over-current relay and then to proceed to
grade the ring as in the case of a single infeed, the second to treat the
section of the ring between the two supply points as a continuous bus
separate from the ring and to protect it with a unit system of protection,
such as pilot wire relays, and then proceed to grade the ring as in the case
of a single infeed.
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Directional Earth-Fault Protection
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In the directional over-current
protection the current coil of relay is actuated from secondary current of
line CT. whereas the current coil of directional earth fault relay is
actuated by residual current.
In directional over-current
relay, the voltage coil is actuated by secondary of line VT. In directional
earth fault relay, the voltage coil is actuated by the residual voltage. Directional earth fault relays
sense the direction in which earth fault occurs
with respect to the relay location and it operates for fault in a particular
direction. The directional earth fault relay (single phase unit)
has two coils. The polarizing quantity is obtained either from residual
current
IRS
= (Ia + Ib + Ic)
or residual voltage
VRs
= Va
+ Vb + Vc
Where Va,
Vb and Vc are phase voltages.
Referring to (Fig. 11) the
directional earth-fault relay has two coils. One to the coils is connected in residual current circuits (Ref. Fig.
5). This coil gets current during earth-faults. The other coil gets
residual voltage,
VRS= Va
+ Vb + Vc
Where Va, Vb and Vc are secondary voltages of the potential transformer
('Three
phase five limb potential transformer or three separate single phase potential transformers connected as shown in
Fig. 20). The coil connected in potential-transformer secondary
circuit gives a polarizing field.
The residual current IRS i.e. the out of
balance current is given to the current coil and the residual voltage VRs is given to the
voltage coil of the relay. The torque is proportional to
T = IRS * VRS
* cos (Φ - α)
Φ = angle between IRS and VRs
α = angle of maximum torque.
v Summary
Over-current protection responds to increase in current above the
pick-up value
over-currents are caused by overloads and short-circuits.
The
over-current relays are connected the secondary of current transformer. The
characteristic of over-current relays include inverse time characteristic,
definite time characteristic.
Earth fault protection responds to single line to ground faults and
double line to ground faults. The current coil of
earth-fault relay is connected either in neutral to ground circuit or
in residually connected secondary CT circuit.
Core
balance CTs are used for earth-fault protection.
Frame
leakage protection can be used for metal clad switchgear.
Directional over-current relay and Directional Earth fault relay
responds to
fault in which power flow is in the set direction from the CT and PT
locations. Such directional relays are used when power can flow from both
directions to the fault point.
v
Co-ordination
Correct
current relay application requires knowledge of the fault current that can
flow in each part of the network. Since
large scale tests are normally impracticable, system analysis must be used.
It is generally sufficient to use machine transient reactance X'd
and to work on the instantaneous symmetrical currents. The data required for
a relay setting study are:
1. A one-line
diagram of the power system involved, showing the type and rating of the
protective devices and their associated current transformers.
2. The impedances
in ohms, per cent or per unit, of all power transformers, rotating machines
and feeder circuits.
3. The maximum
and minimum values of short circuit currents that are expected to flow
through each protective device.
4. The
starting current requirements of motors and the starting and stalling times
of induction motors.
5. The maximum
peak load current through protective devices.
6. Decrement
curves showing the rate of decay of the fault current supplied by the
generators.
7. Performance
curves of the current transformers.
8. The relay
settings are first determined so as to give the shortest operating times at
maximum fault levels and then checked to see if operation will also be
satisfactory at the minimum fault current expected. It is always advisable to
plot the curves of relays and other protective devices, such as fuses, that
are to operate in series, on a common scale. It is usually more convenient to
use a scale corresponding to the current expected at the lowest voltage base
or to use the predominant voltage base. The alternatives are a common MVA
base or a separate current scale for each system voltage.
9. The basic
rules for correct relay co-ordination can generally be stated as follows:
10. Whenever
possible, use relays with the same operating characteristic in series with
each other.
11. Make sure
that the relay farthest from the source has current settings equal to or less
than the relays behind it, that is, that the primary current required
operating the relay in front is always equal to or less than the
primary current required operating the relay behind it.
v PRINCIPLES
OF TIME/CURRENT GRADING
Among the various possible methods used to achieve correct
relay co-ordination are those using either time or over
current or a combination of both time and over-current.
The common aim of all three methods is to give correct
discrimination. That is to say, each one must select and isolate only the
faulty section of the power system network, leaving the rest of the system
undisturbed.
1.
Discrimination by time
In this method an appropriate time interval is given by each of the
relays controlling the circuit breakers in a power system to ensure that the
breaker nearest to the fault opens first. A simple radial distribution
system is shown in (Fig. 21) to illustrate the
principle.
Circuit breaker protection is provided at B, C, D and E, that
is, at the infeed end of each section of the power system. Each protection
unit comprises a definite time delay over current relay in which the
operation of the current sensitive element simply initiates the time delay
element. Provided the setting of the current element is
below the fault current value this element plays no part
in the achievement of discrimination. For this reason, the relay
is sometimes described as an 'independent definite time delay relay'
since its operating time is for practical purposes
independent of the level of over current.
It is the time delay element, therefore, which provides the means
of discrimination. The relay at B is set at
the shortest time delay permissible to allow a
fuse to blow for a fault on the secondary side of trans-former A.
Typically, a time delay of 0.25s is
adequate.
If a fault occurs at F, the relay at B will
operate in 0.25s, and the subsequent operation of the circuit breaker at B will clear
the fault before the relays at C, D and E have time
to operate. The main disadvantage of this method of
discrimination is that the longest fault clearance time occurs for faults in
the section closest to the power source, where the fault level (MVA) is
highest.
1.
Discrimination by current
Discrimination by current relies on the fact that the fault current
varies with the position of the fault, because of the difference in impedance
values between the source and the fault. Hence, typically, the relays
controlling the various circuit breakers are set to operate at suitably tapered
values such that only the relay nearest to the fault trips its breaker. (Fig.
22) illustrates the method.
For a fault at F1, the system
short circuit current is given by:
I = 6350 /(Zs
+ ZL1)
A
Where Zs = source impedance = 112 / 250 = 0.485 ohms
ZL1= cable
impedance between C and B =
0.24 ohms
Hence I=6350/0.725
= 8800 A
So a relay controlling the circuit breaker at C and set to operate
at a fault current of 8800 A would in simple theory protect the
whole of the cable section between C and B. However,
there are two important practical points which affect this method of
co-ordination.
1. It is not
practical to distinguish between a fault at Fl and a fault
at F2, since the
distance between these points can be only a few meters,
corresponding to a change in fault current of approximately 0.1%.
2. In
practice, there would be variations in the source fault level, typically from
250 MVA to 130 MVA. At this lower fault level the fault current would not
exceed 6800 A even for a cable fault close to C, so a relay set at
8800 A would not protect any of the cable section
concerned.
Discrimination by current is therefore not a practical proposition for
correct grading between the circuit breakers at C and B. However,
the problem changes appreciably when there is significant
impedance between the two circuit breakers concerned. This can be seen by
considering the grading required between the circuit
breakers at B and A in (Fig. 22).
Assuming a fault at F4, the short-circuit current is given by:
I = 6350 /(Zs
+ ZL1 + ZL2
+ZT)
A
Where
ZS = source impedance
=112 / 250 = 0.485 ohms
ZL1
= cable impedance between C and B 0.24
ohms
ZL2 =
cable impedance between B and
4 MVA
transformer 0.04 ohms
ZT
= transformer impedance
=0.07(112/4) =2.12 ohms
Hence I = 6350/ 2.885 = 2200 A
For this reason, a relay controlling the circuit breaker at B and set to
operate at a current of 2200 A plus a safety margin would
not operate for a fault at F4 and would thus discriminate with the
relay at A. Assuming a safety margin of 20% to allow for relay errors and
a further 10% for variations in the system impedance
values, it is reasonable to choose a relay setting of
1.3 x 2200, that is, 2860 A for the relay at B. Now,
assuming a fault at F3,
that is, at the end of the 11 kV cable feeding the 4 MVA transformers,
the short-circuit current is given by:
I = 6350 /(Zs + ZL1 + ZL2 +ZT) I = 6350 /(0.485 + 0.24 + 0.04)=8300 Amp. Alternatively, assuming a source fault level of 130 MVA: I = 6350 /(0.93 + 0.24 + 0.004)=5250 Amp.
In other words, for either value of source level, the relay at B would
operate correctly for faults anywhere on the 11 kV cable feeding
the transformer.
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Discrimination
by both time and current
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3 Discrimination
by both time and current
Each of the two methods described so far has a fundamental
disadvantage. In the case of discrimination by time alone, the
disadvantage is due to the fact that the more severe faults are cleared in
the longest operating time. Discrimination by current can only be applied
where there is appreciable impedance between the two circuit breakers concerned.
It is because of the limitations imposed by the independent use of
either time or current co-ordination that the inverse time over current
relay characteristic has evolved. With this characteristic, the time of
operation is inversely proportional to the fault current
level and the actual characteristic is a function of both
'time' and 'current' settings.
The advantage of this method of relay
Co-ordination may be best illustrated by the system
shown in (Fig.23) which is identical to that shown
in (Fig.21) except that typical system parameters have been added.
In order to carry out a system analysis,
before a relay co-ordination study of the system shown in (Fig. 23), it is
necessary to refer all the system impedances to a
common base and thus, using 10 MVA as the reference base, we have:
4MVA transformer percentage impedance on 10MVA base=7X (10/4) =17.5%
11 kV cable between B and A percentage
impedance on10 MVA base
= (0.04 X 100 X
10) / 112= 0.33%
11 kV cable between C and B percentage impedance on 10 MVA base
= (0.24 X 100 X10)
/112 =1.98 %
30 MVA transformer percentage impedance on 10 MVA base
=22.5 X 10 / 30
=7.5 %
132 kV overhead line percentage impedance on10 MVA base
= (6.2x100x10)/ 1322 =0.36%
132 kV source percentage impedance on 10 MVA base
= (100 x 10)
/3500 =0.29%
The graph in (Fig.23) illustrates
the use of 'discrimination curves', which are an important aid to
satisfactory protection co-ordination. In this example, a voltage base of 3.3kV has been
chosen and the first curve plotted is that of the 200 A fuse, which is
assumed to protect the largest outgoing 3.3kV circuit. Once the operating
characteristic of the highest rated 3.3kV fuse has been plotted, the grading
of the over current relays at the various sub-stations of
the radial system is carried out as follows:
Substation B
CT ratio
250/5A Relay over current characteristic assumed to be extremely
inverse, as for the type CDG 14 relay. This relay must
discriminate with the 200A fuse at fault levels up to:
(10 x 100) /
(17.5+0.33+1.98+7.5+0.36+0.29) = 35.7 MVA
That is, 6260 A at 3.3kV or 1880 A at 11 kV. The operating
characteristics of the CDG 14 relay show that at a plug setting of 100%, that
is, 250 A and 4.76 MVA at 11 kV, and at a time multiplier setting of 0.2,
suitable discrimination with the 200 A fuse is achieved.
Substation C
CT ratio 500/5A Relay over current characteristic assumed to be extremely
inverse, as for the type CDG 14 relay. This relay must
discriminate with the relay in substation
B at fault levels up to:
(10 X 100) / (1.98
+7.5 +0.36 +0.29) = 98.7MVA
That is, 17,280 A at 3.3kV or 5180 A at 11 kV. The operating
characteristics of the CDG 14 relay show that at a plug setting of 100%, that
is, 500 A and 9.52 MVA at 11 kV, and at a time multiplier setting of 0.7,
suitable discrimination with the relay at substation B is achieved.
Substation D
CT ratio
150/1A Relay over current characteristic assumed to be extremely
inverse, as for the type CDG 14 relay. This relay must
discriminate with the relay in substation C at fault levels up to
(10 X 100) / (7.5
+ 0.36 + 0.29) = 123 MVA
That is, 21,500 A at 3.3kV or 538 A at 132 kV. The operating
characteristics of the CDG 14 relay show that at a plug setting of 100%, that
is, 150 A and 34.2 MVA at 132 kV and at a time multiplier setting of 0.25,
suitable discrimination with the relay at substation C is achieved.
Substation E
CT ratio 500/1 A Relay over current
characteristic assumed to be extremely inverse, as for the
type CDG 14 relay. This relay must discriminate with
the relay
in substation D at fault levels up to:
(10 x 100)
/ (0.36+0.29)
= 1540 MVA
That is, 270,000 A at 3.3kV or 6750
A at 132 kV. The operating characteristics of the CDG 14 relay show that at a plug
setting of 100%, that is, 500 A and 114 MVA at 132 kV, and at a time
multiplier setting of 0.9, suitable discrimination with the relay at
sub-station D is
achieved.
A comparison between the relay operating times shown in
(Fig. 21) and the times obtained from the
discrimination curves of (Fig. 23) at the
maximum fault level reveals significant differences. These differences can be
summarized as follows:
These figures show that for faults close to the relaying points the
inverse time characteristic can achieve appreciable reductions in fault
clearance times.
Even for faults at the remote ends of the protected sections,
reductions in fault clearance times are still obtained, as shown by the
following table:
To finalize the co-ordination study it is instructive to assess the
average operating time for each extremely inverse
over current relay at its maximum and minimum fault levels, and to compare
these with the operating time shown in (Fig.21) for the definite time over
current relay.
This comparison clearly shows that when there is a large variation in
fault level all along the system network the overall performance of the
inverse time over current relay is far superior to that of the definite over
current relay.
4 GRADING MARGIN
The time interval between the operations of two adjacent relays
depends upon a number of factors:
1. The fault current
interrupting time of the circuit breaker.
2. The
overshoot time of the relay.
3. Errors.
4. Final
margin on completion of operation.
A.
Circuit breaker interrupting time
The circuit breaker interrupting the fault must have completely
interrupted the current before the discriminating relay ceases to be
energized.
B.
Overshoot
When the relay is de-energized, operation may continue for a little
longer until any stored energy has been dissipated. For example, an induction
disc relay will have stored kinetic energy in the motion of the disc; static
relay circuits may have energy stored in capacitors. Relay design is directed
to minimizing and absorbing these energies, but some allowance is usually
necessary.
The overshoot time is not the actual time during which some forward
operation takes place, but the time which would have been required by the
relay if still energized to achieve the same amount of operational advance.
C.
Errors
All measuring devices such as relays and current transformers are
subject to some degree of error. The operating time characteristic of either
or both relays involved in the grading may have a positive or negative error,
as may the current transformers, which can have phase and ratio errors due to
the exciting current required to magnetize their core. This does not,
however, apply to independent definite time delay over current relays.
Relay grading and setting is carried out assuming the accuracy
of the calibration curves published by manufacturers, but since some
error is to be expected, some tolerance must be
allowed.
D.
Final margin
After the above allowances have been made, the discriminating relay
must just fail to complete its operation. Some extra allowance, or safety
margin, is required to ensure that a satisfactory contact gap (or equivalent)
remains.
E.
Recommended time
The total amount to be allowed to cover the above items depends on the
operating speed of the circuit breakers and the relay
performance. At one time 0.5s was a
normal grading margin. With faster modern circuit breakers and lower relay
overshoot times 0.4s is reasonable, while under the best possible conditions
0.35s may be feasible.
In some instances, however, rather than using a fixed grading margin,
it is better to adopt a fixed time value, to allow for the operating time of
the circuit breaker and relay overshoot, and to add to it a variable time
value that takes into account the relay errors, the CT errors and the safety
margin.
A value of 0.25s is chosen for the fixed time value, made up of 0.1 s
for the fault current interrupting time of the circuit breaker, 0.05s for the
relay over-shoot time and 0.1 s for the safety margin. Considering next the
variable time values required, it is first assumed that each
inverse time over current relay complies with Error Class E7.5
defined as normal British practice in BS 142:1966.
The normal limits of error for an E7.5 relay are ±7.5% but allowance
should also be made for the effects of temperature, frequency, and departure
from reference setting. A practical approximation is to
assume a total effective error of 2 x 7.5, that is,
15%, this to apply to the relay nearest to the fault, which shall be
considered to be slow.
To this total effective error for the relay a further
10% should be added for the overall current
transformer error. Hence, for the time interval t' required between inverse
time over current relays it is proposed to adopt the equation:
t' = 0.25t + 0.25
seconds
Where t = nominal operating time of relay nearer to the fault.
As far as the independent definite time delay over-current
relays are concerned, it is assumed that these comply
with Error Class El 0, defined as normal British practice in BS 142:1966. The
normal limits of error for an El 0 relay are ± 10%, but allowance should also
be made for the effects of temperature, voltage, frequency and departure from
reference setting. A practical approximation is to assume a total effective
error of 2 x 10, that is, 20%, this to apply to the relay, nearest to the
fault, which shall be considered to be slow. However, unlike the inverse time
over current relay, it is not necessary to add a further error for the
current transformers. Hence, for the time interval t' required between
independent definite time delay over current relays, it is proposed to adopt
the equation:
t' = 0.2t + 0.25
seconds
Where t = nominal operating time of relay nearest to the fault.
v
STANDARD I.D.M.T. OVER CURRENT RELAY
(TYPE CDG 11)
Limits of accuracy have been considered by various national committees
and (Fig.24) shows a typical example of the limits set by the British
Standards Institution specification BS 142:1966 for the standard inverse
definite minimum time over current relay.
The discriminating curves shown in (Fig.25) illustrate the application
of such a relay to a sectioned radial feeder; it will be seen that with the
assumed relay settings and the tolerances allowed in BS 142:1966 the
permissible grading margin between the over current relays at each section
breaker is approximately 0.5s. With the increase in system fault current it is
desirable to shorten the clearance time
for faults near the power source, in order to minimize damage. It is
therefore necessary to reduce the time errors, which are in this situation
disproportionately large when compared with the clearance time of modern
circuit breakers; this can only be achieved
by improving the limits of accuracy,
pick-up and overshoot
NOTE: The allowance error in operating time should not be less than 100ms
All this must be obtained without detriment to the general performance of the
relay; in other words, there must be no reduction in the operating torque or
weakening of the damper magnets or contact pressures, and the construction
must remain simple with the minimum number of moving parts. While these
requirements present considerable difficulties in manufacture, owing to
variations in materials and practical tolerances, the progress made in the
GEC Measurements relays has made it possible to discriminate more closely by
reducing the margin between both the current and the time setting of the
relays on adjacent breakers.
These relays will thus enable the time setting of the relay
nearest the power source to be reduced, or, alternatively, make it possible
to increase the number
of breakers in series without increasing the time setting of the relays at the power source. |
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