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POWER PLANT PROTECTION
Power Management Institute
Noida
CONTENTS
S.No. DESCRIPTION PAGE NO
PART I BASIC ASPECTES OF PROTECTION
1. - Principals of Relays 1
2. - Maintenance Testing and Commissioning aspects 14
3. - Static replaying Concepts 21
4. -Grounding 33
PART II - PROTECTION OF BOILER & ITS AUXILIARIES,
5. - Main Boiler 45
6. - Boiler Auxiliaries 52
7. - Boiler side Protection causing Unit Tripping 54
PART III PROTECTION OFTURBINE AND ITS AUXILIARIES
8. - Main Turbine 57
9. - Turbine Auxiliaries 71
10. - Turbine side Protections causing Unit shut down 72
PART IV PROTECTION FOR ELECTRICAL SYSTEMS& EQUIPMENTS
11. - Motor 75
12. - Generator 82
13. - Transformer 98
14. - Bus –Bar 105
15. - Feeder 109
PART V PROTECTION & INTERLOCK TEST
16. -General 127
17. -Boiler 129
18. -Turbine 134
19. -Generator 135
PART VI SUMMARY OF INDIVIDAL RELAYS 136
21. Model Session Plan 155
© PMI, NTPC 1
1. Basic Aspects Of Protection
PRINCIPLES OF RELAYS
Every electrical equipment is designed to work under specified normal conditions. In
case of short Circuits, earth faults etc., an excessive current will flow through the
windings of the connected equipment and cause abnormal temperature rise, which will
damage the winding. In a power station, nonavailability of on auxiliary, at times,
may cause total shut down of the unit, which will result in heavy loss of revenue.
So, in a modern power system, to minimise damage to equipment two alternatives are
open to the designer, one is to design the system so that the faults cannot occur and
other is to accept the possibility of faulty and take steps to guard against the effect of
these faults. Although it is possible to eliminate faults to a large degree, by careful
system design, careful insulation coordination, efficient operation and maintenance, it
is obviously not possible to ensure cent percent reliability and theretofore possibility of
faults must be accepted; and the equipment are to be protected against the faults. To
protect the equipment, it is necessary to detect the fault condition, so that the
equipment can be isolated from the fault without any damage. This function is
performed by a relay. In other words, protective relays are devices that detect
abnormal conditions in electrical circuits by constantly measuring the electrical
quantities, which are different under normal and faulty conditions. The basic
quantities, which may change during faulty conditions, are voltage, current, frequency,
phase angle etc. Having detected the fault relay operates to complete the trip circuit
which results in the opening of the circuit breaker there by isolating the equipment
from the fault. The basic relay circuit can be seen in fig.No.1.
© PMI, NTPC 2
SOME TEMS ASSOCIATED WITH PROTECTIVE RELAYING
Circuit breaker
It is an ON-load switch, used to make or break an electrical circuit when it is carrying
current.
Current transformer
These are used for measuring purpose since it is not possible to measure very high
currents directly, it will be stepped down by means of 8 currant transformer to about
5A or 1A and the secondary current will be measured and monitored.
Voltage transformer
These are also used for measuring purpose and protective relaying purpose. Since it
is not practicable to measure and monitor high and extra high voltages they are
stepped down to 110V and the secondary voltage is measured and monitored.
Relay time
It is the interval between the occurrence of the fault and closure of relay contact.
© PMI, NTPC 3
Pick up
The operation of relay is called relay pick up. Pick up value or the level is the value of
operating quantity at which the relay operates.
Back up protection
A protective system intended to supplement the main protection in case the latter
should be ineffective, or to deal with faults in those parts of the power system that are
not readily included in the operating zones of the main protection.
Protected Zone
The portion of a power system protected by a given protective system or a part of that
protective system.
Protective Gear
The apparatus, including protective relays, transformers and ancillary equipment for
use in a protective system.
Protective relay
A relay designed to initiate disconnection of a part of an electrical installation or to
operate a warning signal, stet in the case of a fault or other abnormal condition in the
installation. A protective relay may include more than one unit electrical relay &
accessories.
Rating
The nominal value of an energizing quantity which appears in the designation of a
relay. The nominal value usually corresponds to the CT & VT secondary rating.
© PMI, NTPC 4
Resetting Value
The limiting value of the characteristic quantity at which the relay returns to its
initial position.
unrestricted protection
A protection system which has no clearly defined zone of operation and which
achieves selective operation only by time grading.
SI. No. Symbol Equipments Function
1. Circuit Breaker Switching during normal and abnormal conditions, interrupt the fault currents.
2. Isolator Disconnecting a part of the system from live parts under no load conditions.
3. Earth Switch Discharging the voltage on the lines to the earth after disconnection.
4. Lighting Arrestor Diverting the high voltage surges to earth and maintaining continuity during over voltages.
5. Current Transformer
Stepping down the current for measurement, protection, and control.
6. Voltage Transformer
Stopping down the voltage for the purpose of protection, measurement, and control,
Functions of protective relaying
- To sound an alarm, so that the operator may take some corrective action
and/or to close the trip circuit of circuit breaker so as to disconnect a
© PMI, NTPC 5
component during an abnormal fault condition such as overload, under voltage,
temperature rise etc.
- To disconnect the faulty parts as quickly as possible so as to minimise the
damage to the faulty part. Ex: If a generator is disconnected immediately after
a winding fault only a few coils need replacement. If the fault is sustained, it
may be in beyond repairable condition.
- To localise the effect of fault by disconnecting the faulty part from the healthy
part, causing least disturbance to the healthy system,
- To disconnect the faulty part as quickly as possible to improve the system
stability & service continuity. The requirements of protective relaying can be
summarised as follow:
- Speed: Protective relaying should disconnect a faulty element as quickly as
possible, in order to improve power system stability, decrease the amount of
damage and to increase the possibility of development of one type of fault into
other type. Modern high speed protective relaying has an operating time of
about I cycle.
- Selectivity: It is the ability of the protective system to determine the point at
which the fault occurred and select the nearest of the circuit breakers, tripping
of which leads to clearing of fault with minimum or no damage to the system.
- Sensitivity: It is capability of the relaying to operate reliably under the actual
minimum fault condition. It is desirable to have the protection as sensitive as
possible in order that it shall operate for low value of actuating quantity.
- Reliability; Protective relaying should function correctly at all times under any
kind of fault and abnormal conditions of the power system for which it has been
designed. It should also not operate on healthy conditions of system.
© PMI, NTPC 6
- Simplicity: The relay should be as simple in construction as possible. As a rule,
the simple the protective scheme, less the no, of relays, and contacts it
contains, the greater will be the reliability.
- Economy:; Cost of the protective system will increase directly with the degree
of protection required. Too much protection may give rise to tripping of
equipment even for an incipient fault. Depending on the situation a designer
should compromise with the degree of protection required & economy.
Classification of Relays
Depending upon their principle of operation they are classified as:
Electromagnetic attraction type relays: These relays operate by virtue of a plunger
being drawn into a solenoid or an armature being attracted towards the poles of an
electromagnet.
Induction type relays: In this type of relay a metal is allowed to relate between two
electro-magnets. The fields produced by the two magnets are displaced in space &
phase. The torque is developed by interaction of the fl»\ of one of the magnets and the
eddy current induced with disc by the other.
Thermal relays: They operate due to the action of heat generated by the passage of
current through the relay element. The strip consists of two metals having different
coefficients of expansions and firmly Fixer) together throughout the length so that
different rates of thermal expansion of two layers of metal cause the strip to bend
when current is passed through it. This principle is used in these relays.
Static relays; Employ integrated circuits, transistors, comparators etc. too obtain the
operating characteristic.
Moving coil relays: In this relay a coil is free to rotate with magnetic field of a
permanent magnet. The actuating current flows through the coil. The torque is
produced by the interaction between the field of the permanent magnet and the field of
© PMI, NTPC 7
the coil.
Relays can be classified depending upon their application also:
- Overvoltage, over current and overpower relays, in which operation takes place
when the voltage, current or power rises above a specified value.
- Under voltage, under current under frequencies low power relays, in which
operation takes place when the voltage, current frequency or power fall below a
specified value.
- Directional or reverse current relays: In which operation occurs when the
directional of the applied current changes.
- Distance relays: In this type, the relay operates when the ratio of the voltage & current change beyond a specified Limit.
- Differential relays: Operation takes place at some specific phase or magnitude difference between two or more electrical quantities.
Relays can also be classified according to their time of operation.
- Instantaneous relay: In which operation takes place after negligibly small interval of time from the incidence of the current or other quantity causing operation.
- Definite time lag relay: This operator after a set time lag, during which the threshold quantity of the parameter maintained.
- Inverse time lag relays: In which the- time of operation is approximately inversely proportional to the magnitude of the parameter causing operation; the philosophy behind it is when more fault current flows the protection should operate faster and vice-versa.
© PMI, NTPC 8
Operating principles of different types of relays
Induction over current and earth leakage relays
These are quite commonly used in all power stations. Schematic diagram of induction disc type relay is shown in fig.No.2.
The output of the current transformer is fed to a winding (1) on the centre limb of the E.-shaped core, the second winding (2) On the limb is connected to two windings on the poles of the E - and Li-shaped cores, operates contacts and is free to rotate against a mechanical restraining torque. The magnetic flux across the air gap induces currents in the disc, which in conjunction with the flux produced by the lower magnet, produces a rotational torque. A broke magnet (5), is used to control the speed of the disc. The time of operation of the relay varies inversely with the current fed into it by the current transformer of the protected circuit. The permanent magnet used for breaking has a tendency to attract iron filings, which can prevent operation. So care has to be taken while manufacturing this type of relays.
Time-current characteristics induction type relays has been given in fig.3
© PMI, NTPC 9
Balanced-beam relays
It consists of a horizontal beam pivoted centrally, with one armature attached to either
side. There are*two coils one on each side. The beam remains in horizontal position
till the operation force is more than the restraining force. The current in one coil gives
operating torque. The beam is given a slight mechanical bias by means of a spring so
that under normal conditions trip contacts will not make and the beam remains in
horizontal position. When the operating torque increases then the beam tilts and
closes the trip contacts. In current balance system both coils are energised by current
derived from CT's. In impedance relays, one coil is emerged by current and other by
voltage. In these relays the force is proportional to the square of the current, so it is
very difficult to design the relay. This type of relay is fast and instantaneous. In
modern relays electromagnetic are used in place of coils. See fig.No.4.
© PMI, NTPC 10
Permanent - Magnet moving - coil relays
There are two general types of moving coil relays. One type is similar to that of a
moving coil indicating instrument, employing a coil rotating between the poles of a
permanent magnet. The other is, employing a coil moving at right angles to the plane
of the poles of a permanent magnet. Only direct current measurement is possible with
both the types.
The action of a rotating coil type is shown in the fig.5. A light rectangular coil is pivoted
so that its' sides lie in the two air gaps between the two poles of a permanent magnet
and a soft Iron core. The passage of current through the coil produces a deflecting
torque by the reaction between the permanent magnetic field & the field of the coil.
See Fig.5.
The moving contact is carried on an arm, which is attached to the moving coil
assembly. A phosper bronze spiral spring provides the resetting' torque.
Increasing the contact gap and thus increasing the tension of the spring permits
variation in the quantity required to close the contacts.
Time -Current characteristic of a typical moving coil perma-magnetic relays is as
shown in fig.6.
© PMI, NTPC 11
Attracted armature relays
It is required to clear the faults in power system as early as possible. Hence, high-speed relay operation is essential. Attracted armature relays have a coil or an electromagnet energized by a coil. The coil is energised by operating quantity which may be proportional to circuit current or voltage. A plunger or a rotating vane is subjected to the action of magnetic field produced by the operating quantity. It is basically single actuatinq quantity relay.
Attracted armature relays respond to both AC & DC quantities. They are very fast in operation. Their operating time will not vary much with the amount of current. Operating time relay is as low as 12 sec. and resulting time relay is as low as 30 sec can be obtained in these relays. The relays are not having directional features are having the above characteristics. These are simple type of relays.
© PMI, NTPC 12
Examples of attracted armature type relays are given in fig.7
Time lag relays
These are commonly used in protection schemes as a means of lime discrimination. They are also frequently used in control, delayed auto-reclosing and alarm schemes to allow time for the required sequence of operations to take place, and to measure flip duration of (ho initial condition to ensure that 11 is not merely transient.
Various methods are used to obtain a time lag between the initiation of the relay and
the operation of its contact mechanism. These include gearing, permanent magnet
damping, friction or thermal means. In some cases the time lag in operation of tlie
contact a is achieved by a separate mechanism released by a voltage operated
elements. The release mechanism may be an attracted armature or solenoid &
plunger. The operating time of such relay is independent of the voltage applied to
© PMI, NTPC 13
the relay coil. One of the simplest forms of time lag relay is provided by a mercury
switch in which the flow of mercury is impeded by a constriction in the mercury bulb.
The switch is tilted by a simple attracted armature mechanism. The time setting of
such a relay is fixed by the design of the tube. Another method of obtaining short
timedelays is to delay operation of a normally instantaneous relay by means of a
device which delays the build up of the flux in the operating magnet. The device
consists of a copper ring around the magnet.
The operation of gas relays (Buchholz relay) is explained in transformers chapter.
© PMI, NTPC 14
2. Maintenance, Testing & Commissioning Aspects
Testing and maintenance of protective relays
Unlike other equipment, the protective relays remain without any operation until a fault
develops. However for a reliable service and to ensure that the relay is always
vigelant, proper maintenance is a must. Lack of proper maintenance may lead to
failure to operate.
It is possible for dirt and dust created by operating conditions in the ' plant to become
accumulated around the moving parts of the relay and prevent it from operating. To
avoid this, relays are to be cleaned periodically.
In general, overload relays sense overload by means of thermal element. Loose
electrical connections can cause extra heat and may result in false operation of the
relay. To avoid this, all the relay connections are to be tightened every now and then.
To confirm that the relay operation at the particular setting under particular
conditions for which the relay is meant for operating, we should perform no. of tests
on the relays. Quality control is given foremost consideration in manufacturing of
relay. Tests can be grouped into following five classes:
1) Acceptance tests
2) Commissioning tests
3) Maintenance tests
4) Repair tests
5) Manufacturers tests
© PMI, NTPC 15
Acceptance tests are generally performed in presence of the customer in the
laboratory or customer himself. These tests fall into two categories:
1) On new relays which are to be used for the first time.
2) On relay types, which were used earlier and only minimum necessary
checks are to be made.
After receiving the relays package, it should be visually examined for the damage in
the transit. The following precautions are to be taken while removing the relay-
- Care to be taken not to bend the light parts
- Avoid handling contact surface
- Armature is to be checked for free movement manually after removing the
packing pieces
Do not take steel screwdrivers near the permanent magnet.
Commissioning tests
These are the field tests to prove the performance of the relay circuit in actual
service. These are repeated till correct operations are obtained. These are performed
by simulated tests with the secondary circuits energised from a portable test source;
or simulated tests using primary load current or operating tests with primary energised
at reduced voltage.
The following steps are involved in commissioning tests:
Checking wiring on the basis of the circuit diagram.
Checking C.T. polarity connections
© PMI, NTPC 16
Measuring insulation resistance of circuits
Checking C.T. ratios
Checking P.T. for ratio, polarity and phasing
Conducting Secondary Injection Test On Relays
Conducting primary injection test
Checking tripping and alarm circuits.
Maintenance Tests
Maintenance tests are done in field periodically. The performance of a relay is
ensured by better maintenance. Basic requirements of sensitivity, selectivity,
reliability and stability can be satisfied only if the maintenance is proper.
The relay does not deteriorate by normal use; but other adverse conditions cause the
deterioration. Continuous vibrations can damage the pivots or bearings. Insulation
strength is reduced because of absorption of moisture; polluted atmosphere affects
the relay contacts, rotating systemic etc., Relays room, therefore, be maintained dust
proof. Insects may cause maloperation of the relay. Relay maintenance generally
consists of:
a) Inspection of contacts
b) Foreign matter removal
c) Checking adjustments
d) Checking of breaker operations by manual contact closing of relays
e) Tightness of the screen is to be checked
© PMI, NTPC 17
f) Cleaning of covers etc.,
Maintenance Schedule
1) Continuous supervision:
Trip circuit supervision, Pilot supervision Relay voltage supervision, Battery E/F
supervision, and C T circuit supervision.
© PMI, NTPC 18
2) Relay flags are to be' checked and reset, in every shift.
3) Carrier current protection testing is to be carried out once in a week.
4) Six monthly Inspect ions: tripping tests, Insulation resistance thesis etc.,
Secondary injection tests are to be carried out at least once in a year.
The following tents are to be performed during routine maintenance-
Inspection: Before the relay cover is removed, a visual check of (be cover is
necessary. Excessive dust, dirt, metallic material deposited on the cover should be
removed. Removing such material will prevent it from entering the relay when the
cover is removed. Logging of the cover glass should be noted and removed when
the cover has been removed. Such fogging is due to volatile material being driven
out of coils and insulating materials. However, if the fogging is excessive, cause is to
be investigated. Since most of the relay; are designed at 40oC, a check of the
ambient temperature is advisable. The voltage and current curried out by the relay
are to be checked with that of the nameplate details.
Mechanical adjustments and inspection
The relay connections are to be tight: Otherwise it may cause overheating at the
connections. It will cause relay vibrations also. All gaskets should be free from
foreign matter. If any foreign matter. If any foreign matter is found gaskets are to be
checked for proper operation.
Contact gaps are to be measured and compared with the previous readings. Large
variation in these measurement ", will indicate excessive wear, in which case worn
contacts are to be replaced. Contacts alignment is to; be checked for proper
operation.
© PMI, NTPC 19
Electrical tests and adjustments
Contact function: Manually close or open the contacts and observe that. They
perform their required function.
Pick up: Gradually apply current or voltage to see that pickup is within limits.
Drop out or reset: Reduce the current until the relay drops nut or fully resets. This
test will indicate excess friction.
Repair tests involve recalibration, and are performed after major repairs.
Manufacturers tests include development tests and type and routine tests.
Test equipment
Primary current injection test sets: Generally protective gear is fed from a current
transformer on the bus bars; and primary current injection testing checks all part of
the protection system by injecting the test current throughout the primary circuit. HIP
primary injection tests can be carried out by means of primary injection test sets. The
seta are comprising current supply unit. Control unit und other accessories. The test
set can give variable output current, the output current can be varied by means of
built-in-auto transformer. The primary injection test set i s connected to A.C. single-
phase supply. The output is connected to primary circuit of CT. The primary current
of C.I. can be varied by means of the test set. By using this test we can find ;)l what
value of current the relay is picking up and dropping out.
Secondary current injection lest set: It checks the operation of the protective gear but
dues not check the overall system including the current transformer. Since it is a rare
occasion to occur a fault in Cl, the secondary test is sufficient for most routine
maintenance. The primary test is essential when commissioning a new installation.
As it checks I hi entire system, we can be sure of the C T polarities etc., a simple
circuit is given in Fig. 8
© PMI, NTPC 20
Test Benches
Test benches comprise calibrated variable and voltage supplies and timing devices.
These benches can be conveniently used for testing relays and obtaining their
characteristics.
© PMI, NTPC 21
3. Static Relaying Concepts
Introduction
Static Relay is a relay in which the comparison or measurement of electrical
quantities is done by stationary network, which gives a tripping signal when the
threshold condition is passed. In simple language static relay is one in which there
are no moving parts except in the slave device. The static relay included devices,
the output circuits of which may be electric, semiconductor or even electro magnetic.
But the output device does not perform relay measurement; it is essentially a tripping
device. The slave relay in output circuits may be electromagnetic type. Static relays
employee electronic circuits for the purpose of relaying. The entity voltage, current,
etc, is rectified and measured. When the output device is triggered, thereby current
flows in the trip circuit of the circuit breaker.
With the intentions of semiconductors devices like diodes transistors, thyristors,
zener diodes etc., there has been a tremendous leap in the field of static relays.
The development of integrated circuits has made an impact in static relays. The
static relays and static protection has grown into a special branch in its own right. In
this section, however, the subject matter is very brief and compact.
Advantages of Static Relays
The static relays compared to the electromagnetic relays have many advantages
and a few limitations.
Low power consumption
Static relays provide fewer burdens on C.T.s and P.T.s as compared to conventional
relays. In other words, the power consumption in the measuring circuits of static
© PMI, NTPC 22
relays is generally much lower than for their electromechanical equivalents. The
consumption of one milliwatt is quite common in static over current relay whereas an
equivalent electromechanical relay can have consumption of about two watts.
Reduced consumption has the following merits.
a) C.T.s and P.T.s of lens ratings are sufficient
b)'The accuracy or CTs and Pls is increased
c) Air gaped CTs can be used (linear couplers)
d) Problems arising out of CT saturation art' avoided
e) Overall reduction in cost
Operating times: The static relays do not have moving parts in their measuring
circuits, hence relay times of low value's can be achieved. Such low relay times are
impossible with conventional electromagnetic relays.
By using special circuits the resetting times; and the overshoot time can be improved
and also high value of drop off to pick up ration can also be achieved.
Static relays assisted by power line carrier can be used for remote backup and
network monitoring.
Static relays are compact. Further more with use of integrated circuits, complex
schemes can be installed on a single pannel.
Complex protection schemes may be obtained by using logic circuits. Static relays
can be designed for repeated operations
No. of characteristics obtained by single static relays unit are much more than
electromagnetic relays.
© PMI, NTPC 23
Most of the components in static relays including the auxiliary relays in the output
stage are relatively indifferent to vibrations and shocks. The risk of unwanted
tripping is therefore less with static relays as compared to electromagnetic relays.
So, these can be applied in earthquake prone areas, ships, vehicles, aeroplanes
etc.,
Transducers
Several non-electrical quantities can be converted into electrical quantities and
then fed to static relays. Amplifiers are used wherever necessary.
Limitations
Auxiliary Voltage Requirement: This disadvantage is not of any importance as
auxiliary voltage can be obtained from station battery supply and conveniently
stepped down to suit load requirements.
Static relay are sensitive to voltage spikes or voltage transients. Special measures
are taken to overcome this difficulty. These include use of filter circuits in relays,
screening the cable connected to the relays.
Temperature Dependence of Static Relays
Trip characteristic of semiconductors are influenced by ambient temperatures. For
example, the apolitical factor of a transistor, the forward voltage drop of a diode etc.,
change with temperature variation. This was a serious limitation of static relays, in
the beginning. Accurate measurement of relay should not be affected by temperature
variation. Relay should be accurate over a wide range of temperature. (-10 + 50oC)
this difficulty is overcome by
a) Individual components in circuits are used in such a way that change in
characteristic of component dues not affect the characteristic of the complete
relay.
© PMI, NTPC 24
b) Temporal lire compensation in provided by thermistor circuit. Component
failure rate is quite high and it reduces the reliabilities of the relay. Extra
precaution for quality control test of the components has to be taken. As the
failure rate in highest in early period of components life, Artificial ageing of the
components is normally done, by heat soaking.
Level Detectors
A relay operates when the measured quantity changes, either from its normal value
or in relation to another quantity. The operating quantity in most protective relays is
the current entering the protected circuit. The relay may operate on current level
against a standard bias or restrained, or 'it may compare the torrent with another
quantity of the circuit such as the bus voltage or the current leaving the protected
circuit. (Fig.-9)
In a simple electromagnetic relay used as level detector gravity or a spring can
provide the fixed bias or reference quantity, opposing the force produced by the
operating current in electromagnet. In static relays the equivalent is a D.C. voltage
bias.
In the semiconductor circuit (See fig.10) the transistor is reverse biased in normal
conditions. No current flows through the relay coil. Under fault conditions capacitor
will be charged to +ive potential at the base side. If this potential exceeds that of the
emitter the B-E junction will be forward biased and transistor will conduct there by
tripping the relay. Thus the comparison is made against the D.C. fixed bias.
© PMI, NTPC 25
Comparators
In order to detect a fault or abnormal conditions of the power system, electrical
quantities or a group of electric quantities are compared in magnitude or phase angle
and the relay operates in response to an abnormal relation of these quantities. The
quantities to be compared are fed into a comparator as two or more inputs; in
complex relays each input is the vectorial sum or difference of two currents or
voltages of the protected ed circuit, which may be shifted in phase or changed in
magnitude before.' being compared.
Types of Comparators: Basically there are two types of comparators, vis.
a) Amplitude comparator, and
b) Phase comparator
The amplitude comparator compares the magnitudes of two inputs by rectifying
them and opposing them. If the inputs are A and B, the output of the Comparator is
A-B and this is positive if A is greater than B i.e. if the ratio of A/B is greater than
one. Theoretically the comparison should be purely scalar, i.e. the phase relation of
the inputs should have no effect on the output, but this is usually so if at least one
input is completely smoothened as well as rectified.
The phase comparator achieves a similar operation with phase angle; its output is
positive if arg A- arg B is positive i.e. if arg A/B is less than λ where λ is angle
determining the shape of the characteristic;
λ = 90 for a circular characteristic.
© PMI, NTPC 26
Both types of comparators can be arranged either for direct, comparison
(instantaneous) or to integrate their output over each half cycle.
Amplitude Comparators: Fig-11 shows how two currents can be compared in
magnitude only, using rectifiers and, in Fig. 16 two voltages are compared). The
current comparator is practical (usually more), because the rectifiers providing a
limiting action so that the relay can be made more sensitive, the voltage across the
rectifier bridge remain substantially constant and hence the rectifiers and the
sensitive relay are protected at high currents. In the voltage comparator the limiting
action is the wrong way, i.e. the increase of resistance at low voltage makes the
relay less sensitive at low voltages and the rectifiers are not protected at high
currents. Current versus voltage comparator is a compromise using a moving coil
relay as the comparator as well as the output device. It is not as efficient as the
circulating current comparator because the volt-ampere consumption relay coils are
added but their pulls are subtracted.
Circulating current comparator
Operation: Normally the restraining currents flow in the winding of the polarised relay
in the blocking direction. If the restraining current is small and operating current is
zero the flow of resultant current will be as shown in fig.12.
© PMI, NTPC 27
© PMI, NTPC 28
The voltage across the restraining coil is -V, across the relay serves as a bias in the
forward direction of bridge 1. If the restraining current ir is further increased, the
voltage drop across the relay will rise to a value Vt., the threshold or toe voltage of
bridge 1 and it will then conduct, then the current paths will be shown in fig 13. The
current through the relay consists of fairly flat-topped half waves as shown in Fig.14.
The reverse is true if 1° flows alone; the voltage drop across relay will now be V and
this will bias the restraint rectifier in its forward direction. When the voltage drop
across the relay attains a value V., corresponding to the threshold voltage of two
rectifiers in the series, the surplus current from bridge 1 is spilled through bridge 2.
This corresponds to the case of ir.is greater than ir in the fig.14.
When both bridges are energised simultaneously the relay is responsive to small
differences between i and i without, requiring a sensitive output relay. The composite
characteristic (ideal) for the relay is shown in Fig.15.
© PMI, NTPC 29
So, it can be seen that the current in the relay is a function of the difference between
io and ir. Owing to the nonlinear resistance of the rectifiers, the current through the
relay is limited to a fixed maximum value and the rest of the surplus flows through the
rectifier bridge with smaller current. The voltage across the comparator cannot
exceed the twice the forward drop in one of the rectifiers, which is about 0.6 for Si.
The linearity of the characteristic can be improved by the use of different
semiconductors in the two bridges, such as Germanium in the operating bridge and
Silicon in the restraining bridge.
Opposed Voltage Comparator: In this voltage comparator the voltage drop in the
resistances connected externally in the bridge circuits will be compared. The current
directions are shown in Fig.16. The voltage drop in the restraining coil bridges. If
these two drops are equal no current will flow through the relay coil and the relay will
be on the verge of operation. If the two voltages are not equal then unequal currents
will flow through the resistances and the voltage drops will not be same. So a current
will flow through the relay coil in a direction determined by the largest voltage drop in
the resistor. That is if the drop in the resistance of the operating bridge is more than
that of the restraining bridge then a current will flow in the operating direction through
the relay. The reverse is true if the drop across the restraining resistance is more than
the operating resistance.
© PMI, NTPC 30
Phase Comparators; There are two main types of static phase comparators}
a) those whose output is a d.c. Voltage proportional to the vector product of the
two a.c. input quantities,
b) those which give an output whose polarity depends upon the phase
relation of the inputs. The later are sometimes called concidence type and can
be direct acting or integrating.
Operating Principles of Static Time Current Relays/-,
Fig.17 shows the block diagram of a static time current relay. The auxiliary c.t. has
tops on the primary for selecting the desire pickup and current range and its rectifier
output is supplied to a fault detector and an RC timing circuit. When the voltage of
the timing capacitor has reached the value for triggering the level detector, tripping
occurs.
Operation of a Typical Static time current relay: The current from the main c.t. is first
rectified and partially smoothed by the capacitor Cs and then passed through the
tapped resistor Rs that the voltage across it is proportional to the t.e. Secondary
current. The spike filter RC protects the rectifier bridge against transient over
voltages in the incoming current signal, fig.18.
© PMI, NTPC 31
Timing Circuit
The rectified voltage across the Rs charges the capacitor Ct through resistor Rt and
when the capacitor voltage exceeds the base emitter voltage Vt the transistor T2 in
the fig 10 becomes conductive, triggering T3 and operating the tripping relay.
Vc = E [1-exp ( t/RC)] where F. is the voltage
Across Rs the charging time t = RC = log (E/E-Vt)
where Vi is the value of Vp required to make To Conduct.
For a given setting of Vt it will be seen that at high values of E, the time will tend to be
constant but at low values of E they will bear increasingly inverse relation; in other
words since E is proportional to is the auxiliary c.t. secondary current, the relay has
an inverse definite time characteristic.
Resetting circuit: ln order that the relay shall have an instantaneous reset, the
capacitor Ct must be discharged as quickly as possible, This is achieved by the fault
detector as follows (Fig.19).
The base of the transistor T1 is normally kept sufficiently positive relative to emitter
to keep it conductive and hence short circuiting the timing capacity Ct at YY' in
fig.20. when a fault occurs the over current through the resistor Rs makes the base
of Tl negative and cuts it off leaving Ct free to be charged. When the fault is cleared
the current falls to zero and the negative bias on T1 disappears so that Ct is again
© PMI, NTPC 32
short-circuited and discharged immediately. The circuitry for instantaneous never
current unit is similar to that of the time current unit except that Ct is omitted and the
voltage is applied directly to the transistor T2. This voltage is obtained from the tap
PQ on the same resistor Rs.
A weakness of very fast instantaneous units is the tendency to over sensitivity on
offset current waves. The instantaneous unit can be made insensitive to the d.c. off
set component by making the auxiliary c.t saturate just above the pickup current
value and connecting the capacitor and a resistor across the rectified input to the
level detector. This prevents tripping until both halves of the current, wave are above
pickup valve. That is until the off set has gone. The short delay this entails is
acceptable with time current relaying.
principles of static relays used for differencial protection, Distance protection etc.,
however, are not discussed in this book.
© PMI, NTPC 33
4. Grounding
Netural Grounding
All power systems, now-a-days operate with grounded Neutral. The Neutral point of
generator, transformer system etc., connected to earth either directly or through a
resistance or reactance. The neutral earthing is one of the most important features
of system design. Neutral grounding offers several advantages. The importance of
neutral earthing can be felt from the following points:
1) The earth fault protection is based on the method of neutral ea'rthing
2) The system voltage during earth fault depends on neutral earthing
3) Neutral earthing is to be provided basically for the purpose of discrimination of
protection, against arcing grounds, unbalanced voltage with respect to earth,
protection from lightning etc.,
Equipment earthing is different from neutral point earthing. Equipment earthing
means connecting non-current carrying metallic parts to earth in the neighborhood of
electrical circuits. A simple ungrounded neutral system is shown in Fig.21. The
capacitance between line conductor conductors and earth are shown by CRR, CY,
CB, in starform. In a perfectly transposed line, each conductor will have the same
capacitance to ground.
© PMI, NTPC 34
Therefore, under normal conditions, the line to neutral charging currents ICR, ICY,
ICB will form a balanced set of currents as shown in tiq.22. VRN, VYN, VBN
represent the phase to neutral voltages of each phase. The charging currents ICR,
ICY, ICB, lead their respective phase voltages by 90°.
In magnitude each of these current is = Vph/X C, where XC is the capacitive,
reactance of the line to ground. These phase currents balance and so no resultant
current flow to earth. Now, let us considered a phase to earth fault at F in line B as
shown in fig 23. The current through B phase i.e. fault current is vectorial sum of IBR
& IBR. The voltage driving these currents are VBR & VBR Since these currents are
predominantly capacitive they will lead their respective voltages by 90°. (Refer the
vector diagram Fig.24.
© PMI, NTPC 35
© PMI, NTPC 36
It can be seen from the above equations that,
1) In an ungrounded neutral system, under a single line to ground fault the
voltage to earth of the two healthy phases rises from their normal phase to
neutral voltage to full line voltage. This may result in insulation breakdown.
2) The capacitive current through the two healthy phases increases to 5 times the
normal value.
3) A capacitive fault current Ir- flows to the earth. A capacitive current in excess of
4 A will cause arcing grounds.
So it is not in practice now to operate systems with ungrounded neutral as:
a) Such systems can't be adequately protected for fault to earth.
b) The insulation of such system is likely to be over stressed by the over voltages.
c) Insulation overstress may give rise to insulation failure on their parts of the
system which may lead to heavy phase-to-phase fault conditions.
The Advantages of neutral grounding are:
a) Persistent arcing grounds are eliminated.
b) System can be protected against E/F. The system neutral can be grounded by
any one of the following methods:
a) Solid grounding
b) Resistance grounding
c) Reactance grounding
© PMI, NTPC 37
d) Resenant grounding
Solid Grounding
In solid grounding a direct metallic connection is made as shown in the fig.25 from
the system neutral to one or more earth electrodes consisting of plates, rode or pipes
driven into the earth. Now, let us consider, that an E/F, occurred in phase - 8 (Refer
Fig.26)
The phasor diagram for this condition is shown in Fig.27 above
It can be provided that IF =
Since Ip is predominantly inductive, it less behind the phase to neutral voltage of the
faulty phase by 90°.
The voltages driving the currents INR and INR are VNR and VNY respectively and lead
their respective voltages by 90° as shown in the phasor diagram ICF, the resultant of
INR and INY, is in phase opposition to IP.
3 Vph Z1 + Z2 + Z0
© PMI, NTPC 38
The following conclusions can be drawn from the above:
a) When a fault to earth occurs on any phase of the system, the voltage to earth of
the faulty phase become zero, but the healthy phase in general, remain at
their normal value. As such lightning arresters rated for phase voltage can be
insulated for phase voltage. Thus saving in cost.
b) The flow of heavy fault current. Ir will completely nullify the effect of the
capacitive current ICF and so no arcing ground phenomena will occur.
© PMI, NTPC 39
c) The flow of heavy fault current permits the use of discriminative gear. Now-a-
days the term "Solidly grounded" has been replaced by the term "effectively
grounded". The use of solid grounding is limited to systems where the normal
circuit impedance is sufficient to prevent very high value of fault currents.
Resistance Grounding
When it becomes necessary to limit the E/F current a current limiting-device, a
resistance or reactance is introduced between neutral and earth. It is more common
to use liquid resistors if the voltage is 6.6 KV or more. Metallic resistors do not alter
with time and no maintenance is required. In the example under discussion (Refer
fig.28). Current IF lags behind the phase voltage of the faulty phase by a certain
angle depending upon the resistance and the reactance of the system up to the point
of fault. IBR and IBY and VBY respectively by 90°. IP may be resolved into two
components, one reactive component and another resistive component. ICCF will be
in phase opposition to ICF By reducing the value of R, it is possible to nullify IRea. By
reducing the value of R, it is possible to nullify ICF thereby eliminating arcing grounds.
If the value of earthing resistance is made sufficiently high, then the system
conditions approach to that of ungrounded neutral system. (Ref.Fig.29).
An important consideration in resistance grounded system is the power loss in the
resistor during line to the ground faults. In general, it is a common practice to fix a
value which will limit the earth fault current to the full rating of the largest
generator or transformer. Based on the practice, the value of resistance to be
inserted in the neutral to earth connection is decided using the following formula:
VL R = ---------
3 I.
Where I Earth fault current to be allowed to flow, Resistance grounding is normally
employed on systems operating at voltages between 2.2 KV & 33 KV. Neutral
earthing resistors are designed to carry their rated maximum current for a short
period, usually 10 sec.
© PMI, NTPC 40
The salient features of the resistance grounding can be summarised as follows:
1. It minimises the hazard of arcing grounds.
2. It permits to use discriminative protective gear.
3. A resistance grounded system will have low E/F current when compared to solid grounding system and hence will have less influence on neighboring communication circuits.
4. This system is costlier solid grounded system.
© PMI, NTPC 41
Reactance grounding
Reactance grounding means grounding through impedance, the principal element of
which is reactance. The reactance connected in neutral provide a logging current
which neutralises the In. The reactance grounding provides additional reactance to
the system reactance. Thereby the capacitive currents are neutralised. Hence for
circuits where high charging currents are involved reactance grounding is preferred.
Arc - Suppression Coil Grounding
An arc-suppression coil is an iron cored reactor mounted in the neutral earthing
circuit and capable of being turned to resonate with the capacitance of the system
when on line becomes earthed. The function of the arc suppression coil is to make
arcing earth faults self-extinguishing and in the case of sustained faults to reduce the
earth current to low value so that the system can be kept in operation with one line
earthed. The arc suppression coif is sometimes referred to as a peterson coil or
ground fault neutralizer while the grounding so achieved is referred to as
Resonant grounding.
Fig.30 shows the B-phase earthed by a single line to earth fault on an arc
suppression coil wutral qroundrd system. The phasor diagram in figure 31. The
resultant capacity current is 3 times the normal line to neutral charging current of one
phase as derived below:
© PMI, NTPC 42
Under the conditions the voltage of the faulty phase is impressed across the arc
suppression coil and a current if lagging by approximately 90° (and in phase
opposition to Icf) flows. By adjusting the tapping on the coil, IF can be made to
neutralise Ipp so that the resultant current in the fault is limited to practically zero. As
such an arc at the fault cannot be maintained and neither power current nor
capacitive current can flow through the fault. The system can also operate with a
sustained earth fault on phase without harmful results and no arcing phenomena can
occur. In practice there will be a small resultant current present in the fault since
absolute tuning between the inductance of the-coil and the capacitance of the system
may not be possible. Experience shows that the small resultant currents due to
deviations of the order of 20% for system voltage upto 66 KV and 10% for higher
voltage from resonance cannot maintain the arc.
© PMI, NTPC 43
The inductance of coil can be determined as follows:
This leads to some difficulty when due to varying operational conditions
the capacitance of the network varies from time to time. It can be overcome, however,
by using a taped coil, the appropriate tapping being used for each change in network
condition.
The current rating of the coil is given by
3 Vph IF = -------------
Xc
© PMI, NTPC 44
1'he neutral point (Star point) is usually available at every voltage level from generator
or transformer neutral. However if no such point is available due to delta connections of
neutral points is desired on bus bars, the most common method is using a zig-zag
transformer. Such a transformer has no secondary. Each phase of primary has two
equal parts. There are three limbs and each limb has two windings providing opposite
flux during normal conditions. The two stars (1) and (2) are connected together as
shown in Fig.32. Since the fluxes oppose, the transformer takes very small magnetizing
currents during normal condition. During earth faults on the circuit in primary side, the
zero sequence currents which have the some phase for three components IRO, IYO ZYO,
flow in the transformer winding through earth connection. The earth fault current finds
little impedance.
© PMI, NTPC 45
5. Protection Of Boiler & Its Auxiliaries
MAIN BOILER
To ensure continuous power supply the availability of boilers is to be taken into account.
Eventhough this is an important consideration, the stress on safety of the personnel and
safety of the equipment can’t be ignored. Today s trend is to CJU for higher capacity
units. As the unit size and capacity increase the effect of a forced outage takes on
greater significance, particularly that from a furnace explosion. Not only is there a loss in
revenue but, the possibilities of personnel casualties and plant danger are very much.
Further, the length of the outage and the cost of repairs are almost proportional to the
size of the unit. Explosions resulting in extensive damage to equipment and personnel,
and in some instances fatalities have occurred in the history of steam generation. Refer
every effort must he made to prevent furnace explosions.
Majority of explosions are found to occur during light up after shutdown on a Boiler.
Also it is found, as per statistical data available that a majority of the causes for furnace
explosions is human error. A number of explosions have also occurred due to lack of
proper protection systems. Explosions have occurred through -
a) Ignition of an accumulated combustible gas in a boiler, which in out- of service for
quite some Lime.
b) Operating for a long period of time with a deficiency of air and then suddenly
bringing about proper fuel air ratio. The three basic operating reasons causing a
accumulation explosive mixture are:
1) Improper sequence of operation.
2) Insufficient ignition energy supplied, when compared to actual requirement.
© PMI, NTPC 46
3) Firing with improper fuel air ratio.
To prevent explosions from the above causes, every effort should he made by the
operators prevent putting an ignition source into a furnace full of gas, the sequence of
lighting the’ burner should be programmed, to adequately purge the furnace for several
minutes at a good airflow. There are several aids that can prevent explosions from rich
air mixture or less air mixture aids are called automatic combustion control equipment.
The one, supplied by BITFL is called F 555 or furnace safe guard supervisory system.
Almost all the interlocks and protections for boiler are generally covered under
combustion control system, through which the master fuel trip relay is actuated. It
utilises monitoring of the flame condition in the furnace and takes the appropriate action
to ensure safe condition. It also provides the operator with a method for starting and
stopping the admission of fuel to the furnace, including the related equipment.
Protection
The boiler receives a trip command when any one of the following conditions arise-:
1) tripping of both F.D. fans.
2) tripping of both I.D. fans.
3) furnace pressure high.
4) furnace pressure low.
5) when turbine trips.
6) when generator trips.
7) drum level high.
© PMI, NTPC 47
8) drum level low
9 air flow is less than 30%
10) total flame failure
11) less of 22U V.D.C. supply of F.S.S.S.
12) Both P.3.5. on I .S.S.S. pressed
13) Reheater protection. This protection will act when there in no flow in the R.H. &
furnish outlet temperature is more than 580°C.
The above protections are discussed in, brief in the following paragraph.
1. Tripping of both ID fans/FD fans: Causes for tripping of the one or both ID fans may
be due to:
1) Actuation of motor protection (over load, earth fault etc.)
2) Supply failure to feeding bus.
3) Low lub oil pressure.
4) High bearing temperatures.
5) Failure of cooling water to bearings.
Tripping of both ID fans causes unit tripping. That is turbine and generator will also
be tripped.
The Operator should prepare for hot rolling of the turbine, after ascertaining the
causes and taking proper action.
© PMI, NTPC 48
2. High Furnace Pressures Furnace pressure may go high because of the following
reasons:
a) Tripping of one out of the two ID fans or maloperation of regulating vanes of
fans or closing of dampers on the flue gas side.
b) Unstable coal flame due to improper air distribution in furnace, too much or too
low fuel air, sudden starting of mills, loss of ignition energy.
c) Unequal burner tilts (if provided)
d) Tripping of Air preheaters.
e) Furnace water seal failure.
f) Opening of manholes in E.P. etc.
High furnace pressure causes instable combustion, flue gases escape thro man hole,
peep holes etc. If allowed it may cause explosions. That is the reason why this
protection is provided. If furnace pressure touches -i- 200 mm. of water column, unit will
trip.
Operator should carefully check the draft readings and position of the 'dampers, vane
control mechanism of fans, motor currents etc., If the reason is tripping of one ID fan.
Combustion regime opening of auxiliary air, fuel air dampers is to be checked. Marginal
high furnace pressures can be handled by slightly reducing the primary and secondary
air input. Furnace seal is to be checked. Seal may get broken by sudden slag fall. Seal
may also be broken by low or interrupted water supply. Water flow is to be ensured. All
auto controls are to be watched for any maloperation. Choked impulse lines may cause
fault operation. Local operator should check all the man hole and peep holes. Dampers
in flue gas side should be ensured open. ID fan vane mechanism is to be checked for
© PMI, NTPC 49
proper operation. As a general rule protection should not be cut off during
emergencies.
Low furnace pressure
It may be due to I.D. fan auto control failure or I.D. fan vane control mechanism failure
causing vanes to open wide. Sudden load throw off also causes low furnace pressures.
Sudden tripping of FD fan also causes low pressures.
.Low pressure causes unstable flame conditions. It may cause even implosion of
furnace. That is the reason why this protection is provided to trip the boiler unit at - 200
mm of water column.
Operator should put the ID fan switch in manual and bring the normal parameters. ID
fan vane control mechanism is to be checked. Airflow is to be checked. FD fan is to be
restarted if it had tripped.
Drum level low
It may be caused by,
a) Tripping of one of the working feed pumps.
b) Maloperation of feed auto or scoop auto.
c) Sudden reduction of load.
d) Sudden tripping of one or more mills, oil burners etc.,
e) Sudden tube failure in the water wall system.
f) Inadvertant opening of Drum emergency drains/low point drain valves etc.
© PMI, NTPC 50
Initially water level low annunciation appears. Operator should take corrective action.
Even then if the level falls below - 150 mm, boiler will trip. When water level falls well
below the limits, it leads to water wall tubes failures. During this condition -
1) Operator should check whether the reserve feed pumps has started on auto or not
in case of tripping of one of the working feed pumps. If it has not started, it is to be
started.
2) Switch over feed/scoop Auto to manual and make up water level.
3) Water flow recorder is to be checked, excessive water flow for a particular steam
flow indicates failure of water wall tubes.
Drum Level High; the causes can be enlisted as follows:
a) Maloperation of feed water controls.
b) Over feeding.
c) Sudden increase in firing rate.
Initially "Water level high" annunciation appears in control room. Emergency blow down
valves will open to normalise the drum level. When drum level reaches normal position,
these valves will close on auto. In spite of the opening of emergency blow down valves,
and operators' action, if the level goes high then the unit will trip at +175 mm.
High drum level, beyond the visible range of gauge glass, is a source of water carry
over and can cause serious and instantaneous damage to Turbines, super heaters etc.
The effect of high drum level la more on Turbine side. So some power Engineers
consider this protection as a Turbine protection.
© PMI, NTPC 51
In case of high drum level condition also, the operator should change over the feed
controls to manual and reduce the water level. If emergency blow down valves did not
open on auto they were to be opened.
If high water level is due to upward load surge, try to reduce the load. Main steam lines
are to be watched for any hammering. If protection does not act then the unit is to be
tripped by the operator.
Airflow less than 30% for combination fuel air ratio plays a very vital part. During start
up and when boiler load is less than 30°o, airflow to the furnace should be more than
30% of MCR. Unit will trip whenever the air supply is less than 30% which can occur
due to a) FD fan discharge or air pre-heater inlet/outlet dampers get closed b) discharge
dampers of non running FD Fan get opened. Whenever the air flow is less than 30%,
the primary sensing element will be RF 01 & FF02 & relay CR 153 (recording to project
will. cut and boiler lockout as well as unit lock out relay will act causing the unit
shutdown.
Loss, of 200 Volts D.C. Supply to F.S.5.5; In case of 200 Volts D.C. supply failure to
F.S.S.S. the boiler lockout relay and unit lockout relay will act causing unit shutdown.
In tins case CR-52 and CR-53 relays will act and unit will trip instantaneously in the
above case of supply failure, if there is no tripping it can cause boiler explosion as the
auto control system will become nonoperational.
Flame failure: This protection will act when there is no fire ball condition at all elevation
in case there .is no flame in the furnace and fuel is continuously going in the furnace
there is every chance of pressurising the furnace and hence explosion can take
place of water carry over from super healer to turbine Hence in case of flame
failure, boiler lock out relay and unit lockout relay (CR-205) will act causing unit shut
down.
© PMI, NTPC 52
6. Boiler Auxiliaries
SI. No Description Protection
1.
ID Fans
Bering temp. Too high Motor bearing temp. Too high Lub-oil pressure for motor bearing low with Time Delay of 0-3 minutes. Both A.P.H. A&B off (provided deinterlocking switch is in lock position.
2.
F D Fans a) Bearing temp. Too high b) Motor bearing temp. Too high c) Both I. D. fan trips. d) If lub oil pressure continues to be low a preset low value for 30 minutes. e) If fan A or B trips and FD fan is selected in combination with I. D. fan.
3. Air Heater a) Temp. of support & guide bearing goes high as per setting b) Air motor also trips if temp. of support guide bearings goes high (as per setting).
4. Scanner Fan a) Scanner fan arranging damper opens automatically when F. D. fans are off.
5. Primary air fan a) P. A. fan bearing temp. too high. b) P.A. fan motor bearing temp. to high. c) Lub oil motor bearing low after a time delay of 0-5 minutes.
© PMI, NTPC 53
SI. No Description Protection
d) P. A. fan shall trip when one of the two F.D fans Trip and this fan is selected.
6. Seal air fan a) Running seal air fan will trip automatically after 60 Sec. Time delay when both P. A. fan trip.
7. Pulveriser a) Boiler trip condition is present. b) Discharge valves are closed. c) Loss of elevation A.C. supply for more than 2 sec. d) Loss of elevation A for more than 2 Sec. e) Support ignition energy is removed within 3 minutes of feeder starting. f) P.A. fan tripping g) Low primary air pressure for more than 5 sec. h) Motor protection operates. j) P.A. Pressure very low all mills will trip instantaneously.
8. Raw Coal Feeders a) If boiler trips. b) Elevation D.C. supplies fails after 2 sec. Delay. c) Elevation A.C. supply fails d) Ignition energy disappears before 3 minutes from the starting of feeder. e) Pelvises trips. f) Loss of coal flow and pelvises amperage low after 5 sec. From feeder start.
9. Furnace temp. Probe a) If furnace temperature probe is inside the furnace and temperature exceeds 540oC it will be retracted back automatically.
© PMI, NTPC 54
7. Boiler Side Protection Causing Unit Tripping SI.No.
Protection Description
Cause Tripping value
Relay to Act. Remarks
1. Loss of voltage 6.6 KV busbar
6.6 KV unit auxiliary busbar voltage drops below 50% of the rated value for a duration of about 5-10 Sec.
A. Boiler lockout relay
B. Turbine lockout relay.
C. To energies turbine trips solenoid.
D. To energies generator transformer lockout relay.
A. To stop all fuel input by tripping feeder/ Mills in service, closing the igniter oil, warm up oil and heavy oil trip valves and to trip PA fans.
B. To close super heater, re-heater spray isolating valve with a time delay of 0-3 minutes.
C. To disconnect the regulator impulse on burner tilt mechanism
2. Loss of 200 Volt D.C. supply of F.S.S.S
200 D.C supply to FSSS fails.
A. Boiler lock out relay
B. Unit lock out relay.
Unit shutdown
3. Loss of all fuel trip
Loss of all fuel to the furnace
A. Boiler lock out relay
B. Unit lock out relay
A. To disconnect the regulator impulse on burner till mechanism and to bring the mechanism in the horizontal position.
B. To close super heater, reheater spray isolating valve with the time delayed 03 minutes.
© PMI, NTPC 55
SI.No.
Protection Description Cause Tripping value Relay to Act. Remarks
4. Flame failure
This protection shall act when there is no fire valve condition at all elevations
A. Boiler lockout relay
B. Unit lock out relay
A. To disconnects the regulator impulse on burner tilt mechanism and to bring the mechanism in the horizontal position.
B. To close super heater, re-heater spray isolating valve with a time delay of 0-3 minutes.
5. Drum Level low
This protection will act when drum level is at –175 mm from the normal level.
A. Boiler lock out relay
B. Unit lock out relay.
A. Unit shutdown
6. Drum Level high
This protection will act when drum level is at + 175 mm from the normal level.
A. Boiler lock out relay
B. Unit lock out relay
A. Unit shutdown
7. Both ID fans trip.
Both the running ID fans trips.
A. Boiler lock out relay
B. Unit lock out relay
A. Both FD fans trips.
B. Both PA fans trips
C. Unit shutdown.
8. Both ID fans trip.
Both the running ID fans trips.
A. Boiler lock out relay
B. Unit lock out relay
A. Both PA fans trips.
B. Unit shutdown.
9. Furnace pressure very high.
This protection will act when furnace pressure is + 175 mm of w.c. I.
A. Boiler lock out relay.
B. Unit lock out relay.
Both PA fans trips.
Unit shutdown.
© PMI, NTPC 56
SI.No. Protection Description Cause Tripping value Relay to Act. Remarks
10. Furnace vacuum very high.
This protection will act when furnace vacuum is –175 mm of w.c .1.
A.Boiler lockout relay
B. Unit lock out relay
A. Both PA fans Trips.
B. Unit shutdown.
11. Air flow less than 30%
This protection will act when air flow in the furnace is less than 30%
A. Boiler lock out relay
B. Unit locks out relay.
A. Both PA fans Trips.
B. Unit shutdown.
12. Repeater Protection 30%
This protection will act when there is no flow through reheated and furnace of the temperature is more than 530oc.
A. Boiler lock out relay
B. Unit lock out relay
A. Both PA fans trips.
B. Unit shutdown
© PMI, NTPC 57
8. Protection Of Turbine & Its Auxiliaries
MAIN TURBINE
Now-a-days, steam turbine stands as a most important prime mover for large scale
energy production in thermal and nuclear power stations. A steam turbine consists of
regulated quantity of steam flowing over an alternate series of fixed and moving blades.
In a turbine, the heat energy of steam is converted into mechanical energy in terms of
torque at a certain rpm and thin in turn is converted into electrical energy in generator.
When a generating unit is in operation, equipment or operation error can result in
dangerous conditions effecting equipment and/or operator safety. In a small generating
unit with few auxiliary equipment, the operator can take action in time to any failures
and can ensure safe conditions. However, with large units, the no. of auxiliary
equipment has increased and the operation has to be remote from centrally located
control room. So in order to provide safety the remote control system is equipped with
protection and interlocks.
An interlock can be stated to be a condition or state that is a prerequisite to a
subsequent stage in operation or control. A motor with a journal bearing should be
started only after ensuring that the bearings have an established film of lubricating oil
and an assured supply of lub oil is established. Thus the starting of the motor is
interlocked with lub oil pressure or flow. This starting interlock is introduced in the motor
starting circuit in such a way that the motor .can be started only if the tub oil pressure is
adequate and the condition is called a permissive.
In this example continued running of the motor with the absence of lub oil flow is
harmful to the bearings and consequently to the motor. This is a failure and the motor is
required to be provided with protection against such a failure. Thus the protection of
protective interlock in this case is to automatically disconnect the motor when the lub oil
© PMI, NTPC 58
system drops below a certain value. In both the above operations the permissive and
protection interlock are set to operate at a particular set value.
There will be a number of such interlocks and protections that are required with the
large number of auxiliary equipment of both boiler and turbine generator units. In this
chapter we restrict ourselves to the various protections provided for a steam turbine.
The modern steam turbines are generally provided with the following protections to trip
the turbines:
1. Lubrication oil pressure dropping to impermissible value.
2. Vacuum in condenser dropping to impermissible value.
3. Speed rise upto 111 to 112%.
4. Speed rise upto 114 & 115%.
5. Impermissible axial shift.
6. Main steam and reheat steam temperature dropping to impermissible values.
7. Condensate level in H.P. heater rising to impermissible level.
8. Operation of generator protection
9. Manual tripping
10. Governing oil pr. falling to inadmissible value.
© PMI, NTPC 59
Lub Oil protection:
Generally- 200 MW units are provided with one AC tub oil pump called stand by oil
pump and a DC lub oil pump called Emergency oil pump, in addition to the shaft driven
main oil pump. The rotors are supported by journal 'bearings at both ends generally
consisting of horizontally split cast iron shell lined with white metal and aligned very
accurately. Ample oil supply to the bearings is given for cooling and hydrodynamic
lubrication. The normal lub oil pressure will be 1 Kg/cm2. The purpose of AC lub oil
pump is to supply lub oil when the T-G set is on barring gear operation or when
emergency condition prevails. The AC lub oil pump starts when the lub oil system pr.
falls to 0.6 kg/cm2. Emergency oil pump is set to start when the lub oil pr. falls to 0.5
kg/cm2. Even after starting of Emergency lub oil pump, if the pressure is still dropping,
tripping of turbine will take place at 0.3 kg/cm2.
Possible causes of falling of lub oil pressure is:
1) Oil cooler choking in the oil, side.
2) Failure of MOP
3) Leakage in lub oil lines, flanges, bearings etc.
4) Excessive consumption of seal oil.
If we run the turbine with low lub oil pressure, bearing temperature will increase finally
resulting in bearing failure, vibrations, axial shift, thrust bearing failure. To avoid
running of turbine with low lub oil pr. the protection at 0.-5 kg/cm2 is provided.
So the operator in the shiFt should often check the lub oil pressures, check for any
oil leakages. At least once in a week lub oil interlock test is to be carried out.
Electrical logic diagram for lub oil protection has been given in fig.33.
© PMI, NTPC 60
If the lub oil pr. falls to 0.6 kg/cm2 contact (1) of oil pr. relay will close and relay 'A' will
energise then contact 'A' will close and relay Al will energise.
Contact of Al is utilised in the starting ckt. of AC oil pump. Similarly when pr. drops
below 0.5 contact (2) of opr. will energise which in turn energise relay 'B' contact B will
close and relay B1l energises. Contact of relay B1 is utilised in the starting of DC lub oil
pump. If pr. falls to 0.3 contact (3) of Opr closes and relay 'C' energises, then relay
'D' energise. Contacts of '0' are utiised in tripping of turbine and STG.
Overspeed Protection
The turbine is prevented from overspeeding by provision of emergency governing which
trip the turbine and cut off the steam supply, if the over speed exceeds 11 to 12%. This
protection is backed up by an additional protection in the follow pilot valve, which trips
the turbine and cuts off the steam supply if over speed exceeds 14 to 15°o. If turbine
over speeds, turbine is likely to get destroyed causing serious damage to men and
machinery in the vicinity. In case any explosion takes place, the tip of the turbine
blades at 3000-rpm travel with the velocity of sound. Possible causes are:
1) failure to stop valve and control valves in case of turbine trip.
© PMI, NTPC 61
2) failure of emergency governor
3) failure of FC NRV in case of turbine trip.
4) high grid frequency
5) failure of governing system
It is advisable to check the overspeed protection and closing of FC NRV at least once
a month.
In the unlikely event of speed increasing to 111 to 112% of nominal value, emergency
governor strikers fly out of the emergency governor body to trip the set through level
and other hydraulic circuit by closing stop valves, interceptor valves and control valves.
It is recommended that the emergency governor striker should be tested periodically
during normal service by disengaging emergency governor levers. Strikers return to
its normal position on 1U1 to 102% of normal speed. But to restart the set, emergency
governor pilot valves are to be charged. EGPV is an intermediate element to convert
mechanical, signal received from emergency governor thro' lever into a hydraulic signal.
It also receives signal from follow pilot valve and turbine shutdown switch. Hydraulic
signal is transmitted to emergency stop valves servometers, ICV servometer-and
control valve servometers to trip the set. After tripping EGPV does not come to their
normal values. It is brought to the normal position with the help of load speed control
gear. Two emergency stop valves servometers have been provided to totally cut off
steam supply to HP turbine in case of emergency condition. The emergency stop
valves will remain in fully open condition when 'the set is in service. Similarly, two ICV
servometers are provided to totally cut off the steam supply to IP turbine.
Main steam and Reheat steam temperature dropping to impermissible values:
© PMI, NTPC 62
If the mainsteam and reheat steam temperature drop below 45u°C the turbine will trip
on protection. Rated main and reheat steam temperature for a 200/210 MW unit is
535°C. The causes for this condition may be;
1) Unclean superheaters & reheaters
2) Inadequate air flow
3) High attemperation spray
4) Low burner tilt
5) Tripping of higher elevation mills.
If the temperature falls well below 450°C turbine expansion may become negative. Low
steam temperature causes erosion of last stage blades. If the steam temperature is
falling, all the above causes are to be examined; it is advisable to do soot blowing.
High Level In HP Heaters
High pressures heaters are meant for heating boiler feed water by bled steam from
turbine. These are a part of the regenerative cycle, which is provided for improving the
thermal efficiency of power plant. There are three higher-pressure heaters for a 200
MW unit. Heaters will be passed on feed waterside, when drip level in any of the H.P.
heaters reaches a certain pre set value. Even then, if the level does not become normal,
unit will trip at the pre set value.
Axial Shift Protection
Purpose
The equipment is meant for:
© PMI, NTPC 63
a) Protection of the turbine in case of excessive axial rotor shift towards the
generator or towards the front bearing caused by melting of babbit of the thrust
bearings;
b) Remote observation of the rotor position in the thrust bearing when changing the
operating conditions of the turbine;
c) Continuous record of thp rotor position in the thrust bearing. (Ref. Fig 34).
Main Components
1) Axial Shift Transmitter
2) Axial Shift relay pack no.1
3) Axial shift relay pack no.2
4) Single phase step-down transformer
5) Indicator with a specially calibrated scale;
Axial Shift Transmitter
The transmitter action is based on the principle of a differential transformer. The
transmitted' core Fig. 35 is made out of E-shaped stampings of transformers grade
© PMI, NTPC 64
sheet steel and primary winding (1) is wound round the middle limb. The distance
between the outer limbs is 46 mm. In the open part of the E-shaped core enters a 40
mm wide collar on the rotor. Hence, the total air gap between the collar and the outer
limbs of the transmitter core is 6 mm.
The transmitter is mounted on a special bracket. The rotor shift is simulated by
turning the position indicator and thereby displacing the transmitter with respect lo the
rotor collar. Apointer 2 fixed to the bearing indicates the amount of shift on the scale
of the position indicator.
Special screws 5 and 6 restrict the shift of the transmitter eliminating any possibility of
transmitter brushing against the rotor collar, when the device is being tested on a
running turbine.
© PMI, NTPC 65
Principle of operation
The alternating magnetic flux generated by the primary winding passes through the air
gap 'C' between the middle limb and the collar and divides into two loops: the R.H.
loop and the L.H. loop. The intensity of magnetic flux in each loop depends on the
reluctance of magnetic circuits. These reluctances are mainly determined by the
dimensions of air gaps in the magnetic circuits.
E.m.fs induced by the magnetic flux linkage with it secondary windings are
proportional to the amount of displacement i.e. induced voltage in the winding with a
reduced air gap in the magnetic circuit induced voltage is reduced.
The upper secondary circuit feeds the axial shift relay pack No.2 whereas the axial
shift relay pack no.l is fed by lower secondary circuit.
Axial shift relay pack no.2
The Axial shift relay pack no.2 consists of the following items;
1) Rectifier bridge Rc-2
2) Axial shift relay no.2 (ASR-2)
3) A variable resistor R6 for setting ASR-2.
Axial shift relay pack no.1
The axial shift relay pack no.1 is composed of the following:
1) Rectifier bridge Rc-1
2) Axial shift relay no.1 (ASR-1)
3) Three variable resistor R-3, R-4 and R-5 respectively.
© PMI, NTPC 66
Description of the circuit
The circuit Fig.36 is fed with 230V 50 c/s alternating current through a voltage
stabilizer common for all the turbine control instruments' and"1'^ through the
intermediate step-down transformer T-2. The stabilized voltage of 20 to 22 V is
brought to the primary winding of the transmitter.
When alternating current flows through the primary winding, the distribution of the
magnetic flux linking the secondary windings depends on the position of the rotor
collar between the transmitter. The resultant of voltage induced in the secondary
windings is rectified and is supplied to the axial shift relay no.1 (ASR-1) and to the
axial shift indicator in series with the latter.
© PMI, NTPC 67
Vacuum Protection
Purpose
The Vacuum relay is meant for resending audio and light signals whenever vacuum in
the condenser drops to 650 mm Hg. C and for tripping the turbine when vacuum
drops to 540 mm Hg. C.
Construction
The operating element of the relay (fig.37) comprises two metallic bellow 1, one and
face of such is soldered to plate 2 and the other to rod 3.
© PMI, NTPC 68
Inside the bellows there are springs 4, which rest against the rods and are
compressed by sockets 5. The spring tension is restricted by bush 6 and nut 7
resting against the adjusting plate 8. The bush 6 restricts the travel of bellows caused
by expansion or compression of the latter as a result of variation in vacuum.
Special pins 10 carry the adjusting plates 8 fixed by nuts 9. The adjusting plates carry
two micro switches and their leads are connected to a terminal block Fig.38.
Inner chambers of bellows communicate with the vacuum line through orifices in
sockets 5, a groove milled in base 11 and the nipple joint. Supply cables pass
through a special hole at the top and are connected to the terminal block.
© PMI, NTPC 69
Principle" of Operation
When the device is connected to a vacuum line, the bellows together with springs
fitted in them get compressed and the rods move away from the micro switches,
thereby breaking the normally open contacts.
When vacuum drops, the bellows expand under the force of the springs shifting rods
3 upwards through a distance proportional to the drop in vacuum.
At deep vacuum the rods are in their lowest positions and do not touch the
microswitches.
When vacuum drops to 650 mm Hg.C. the first stage microswitches trips and thus
closes the signalling circuit. If vacuum continuous to drop, the rod 3 rests against the
first stage microswitch while the other rod keeps on moving upwards and at a
vacuum of 540 mm Hg.C, presses against the second stage microswitch closing
© PMI, NTPC 70
the auxiliary relay circuit which trips the turbine and simultaneously gives an
emergency signal.
Maximum current rating for the microswitch contacts is 5A at 580 Volts A.C.
Final adjustment for microswitch tripping is done by altering microswitch positions
with the help of nuts 9. Nut positions, after final adjustment, should not be tempered.
Check that contacts 3,4(Fig.58) of first stage microswitch close when vacuum drops
to 650 mm Hg.C. whereas contacts 1,2 of second stage microswitch close when
vacuum drops to 540 mm Hg.C.
© PMI, NTPC 71
9. Turbine Auxiliaries SL. No. Description Protection
1. Boiler feed pump a) Main BFP will trio if lube oil pressure is below 0.5 Kg/cm2.
b) Pump will trip if its motor bearing temp.
is more than 80oC. c) Pump will trip if discharge flow is more
than 500 tonnes/ hr.
d) Pump will trip if discharge pressure of main BFP is below 6 kg/ cm2 for 20 seconds
e) Pump will trip if suction pressure of
main BFP is below 6Kg/cm2 for 20 seconds.
f) On turbine trip one BFP will trip if two are in operation.
2. Circulate water pump a) On closing of discharge valve CW 1&2 pump will trip.
b) CW pump will trip if motor bearing
temperature exceeds 80oC.
c) When both C.W. pumps trip, booster pump trips.
3. Condensate Pump a) Working pump will trip if discharge assure before its NRV becomes low (10 Kg/cm2) after 30 seconds of pump starting.
4. Barring gear a) B/G will trip if labroid pressure goes to 0.3 Kg/cm2.
5. Drip Pump a) Working drip pump will trip if drip level falls to 200 mm for 20 seconds.
6. H.P. Heaters a) H.P. heater will be bypassed through group bypass protection valve at 750 mm drip value.
b) Turbine trip at HPH level 4250mm.
© PMI, NTPC 72
10. Turbine Side Protections Causing Unit Shutdown
Sl. No. Description Cause/ Tripping Values
Relay to Act Remarks
1. 2. 3. 4. 5.
1.
Loss of voltage on unit aux. Bus Bar
6.6 KV unit auxiliary bus bar voltage drops below 50% of the rated value for 5-10 Sec.
Unit Lock out relay will act.
1. Unit shut down.ID/fan/fans and CW pump/ pumps breaker will remain closed.
2. Vacuum drop in condenser.
Condenser vacuum drops below 540 mm of Hg.
Turbine lock out relay will act. Unit lockout relay will act.
1. Unit shut down 2. Pre – trip alarm comes at 650mm of Hg. 3. To close ESVs. And Ivs of the Turbine.
3. Pressure drop of lubricating oil to the Turbo-generator.
Pressure drops down to 0.3 Kg/cm2
Annunciation & follow-up under a. Turbine lock out relay b. Unit Lock out relay
1. Unit shutdown 2. To close the ESVs IVs & CVs. 3. To trip barring gear if already running and to prohibit to start of already not in operation. 4. To open the shut off valve to break the vacuum in the condenser and also close MSVs.
© PMI, NTPC 73
1. 2. 3. 4. 5.
4.
Excessive axial shift of Turbine.
Axial shift of Turbine rotor corres- ponds to +1.2 mm and –1.7 mm.
1. Turbine lock out relay will act. 2. Unit locks out relay.
1. Unit shut down. 2. To open the shut off valve to break the vacuum in the condenser. 3. To close regulating valves on steam supply to ejectors. 4. To close ESVs, IVs & CVs. 5. To cut off steam to ejectors.
5. Boiler feed pump
Stepping of all boiler feed pump.
Unit lockout relay will act.
Unit Will trip after a time delay of 15 sec.
6. Very low main steam temp.
Main steam temp. drops to 450oc before emergency stop valve.
1. Turbine lock out relay will act. 2. Unit lock out relay will act.
1. Unit trips. 2. Heater will
be by-passed from feed water side, drip level in any one of the HP heaters reaches to 750 mm.
7. Operation of
electrical protection of Generator Transformer unit
All the electrical protections of generator and transformer will energies, unit lock out relay causing unit tripping.
Unit lock out relay will act.
1. Unit shut down.
© PMI, NTPC 74
1. 2. 3. 4. 5.
8.
ESV and IV closes. Gov. oil pressure 10 Kg/cm2
Due to over speed of turbine of operation of turbine trip sole noid.
Unit lock out relay will act
1. Unit will trip
9. Manual tripping Unit can be tripped manually from UCB by pressing a push button & then operating the switch.
Unit lockout relay will act.
1.Unit will trip
10. Emergency Governor over speed tripping.
11% & 12% over speed.
a. ESV & IV clocks. b. Turbine trip solenoid will act.
Unit will trip
7. H.P. heater level very high.
When drip level in the heater is 4250 mm.
Unit lock out relay will act.
1. Unit will trip.
© PMI, NTPC 75
11. Protections For Electrical Systems And Equipment
MOTOR
There is a wide range of motors and motor characteristics in existence, because of
numerous duties for which they are used and all of them need protection. Motor
characteristics must be carefully considered when applying protection. It is
emphasized because it applies more to motors than to other items of power system
plant, for example, the starting and stalling currents and times must of necessity
be known when applying overload protection and furthermore the thermal withstand
of machine under balance and unbalanced loading must be clearly defined.
The conditions for which motor protection is required can be divided into two broad
categories, imposed external conditions and internal faults. The former category
includes unbalanced supply voltages, under voltage, single phasing and reverse
phase sequence starting and in case of synchronous machines only, loss of
synchronism. The latter category includes bearing failures, internal shut faults which
are most commonly earth faults and overloads.
The protection applied to a particular machine depends on its size and the nature of
the load to which it is connected. However, all motors should be provided with
overload and unbalanced voltage protection. Basically A.C. motors are of two types:
a) Asynchronous or induction motors
b) Synchronous motors.
Induction motors, which are more versatile with respect to their use for various
applications are of two types, viz.
© PMI, NTPC 76
1) Squirrel cage induction motors
2) Slipring induction motors
Squirrel cage induction motors are used for general applications like fans, pumps,
and mills etc. where no change in speed is required. Wherever aped regulation is
required, slipping induction motors are used. Now-a-days, even squirrel cage
induction motors are used in conjunction with hydraulic couplings for variable speed
applications. Squirrel cage induction motors in thermal stations are generally started
direction line.
In a Thermal power station absence of a single auxiliary may result in shut- down of
the unit for many a days, and at the same time a faulty equipment is to be isolated
from the system as early as possible to safeguard the other equipment and to protect
the equipment from further damage so that the equipment will not turn to be
unrepairable one. Taking the above philosophy into consideration, adequate
protection is provided by means of contractors & fuses. For large motors various
protections are provided to trip the circuit breaker of the motor on’ detecting a fault.
Abnormal conditions
Abnormal motor operation may be duo to internal causers (short circuit in the stator,
over heating of bearing etc.) or due to external conditions such as,
1) Mechanical overload
2) Supply voltage changes
3) Single phasing
4) Frequency changes
© PMI, NTPC 77
According to international standards a motor can operate successfully on any voltage
within +/- 10% variation from the nominal voltage, in case of over loading or faults.
Line voltage changes
The most important consequence of a line voltage change is its effect on the torque
speed curve of the motor. In fact, the torque at any speed is proportiona-1 to the
square of the applied voltage. Thus if the stator voltage decreases then torque also
decreases. Line voltage drop can be observed due to heavy starting currents at the
time of starting.
On the other hand, if the line voltage is too high the flux per pole will be too high.
This increases both the iron losses and the magnetizing current, with the result the
temperature increases and power factor drops down. If the voltage and frequency,
both vary, the sum of the two percentage changes must not exceed 10%.
Mechanical Overload
Although standard induction motors can develop twice their rated power for short
periods, they should not be allowed to run continuously beyond their rated capacities.
Overloading causes over heating, which deteriorates the insulation and reduces its
life. As soon as the apearage of the motor increases beyond its normal value, then
action is to be taken to reduce the mechanical loading. To avoid overheating of the
windings and to save the motor, over-current protection is provided.
Unbalanced Loading
Unbalanced loading cause negative sequence currents to flow through the windings.
A slight unbalance of 3 phase voltages produces a serious unbalance of the three
line currents. This condition increases the rotor and stator loses, yielding a high
temperature. A voltage unbalance of as little as 3.5% can cause the temperature to
increase by 15c.
© PMI, NTPC 78
Single phasing
If one line of a 3-phase line is accidentally opened or if a fuse blows while the motor
is running, the machine will continue to run on a single-phase motor. The current
drawn from the remaining two lines will almost double, and the motor will begin to
overheat. The thermal relays, if provided, will protect the motor from overheating.
The torque speed characteristic is seriously affected when a 3-phase motor operates
on a single phase. The breakdown torque decreases to about 40% of its original
value, and the motor develops no starting torque at all.
Frequency variation
Adverse frequency changes never take place on a large distribution system, except
during a major disturbance. The most important consequence of a frequency change
is the resulting change in the speed of the motor. IF the frequency drops by 20%
speed of the machine will also drop by 20%. A 50 HZ motor operates well on a 60
Hz line, but its terminal voltage should be raised to 65 of the nameplate rating. The
new break down torque then equal to the original breakdown torque and the starting
torque is slightly reduced. Power factor efficiency and temperature rise remain
satisfactory.
Protection
All 6.6 motors used in Power Plants would be squirrel cage type and would be direct
on line started through circuit breakers. Following protections are generally provided
for each motor:
a) Short circuit protection
b) Overload protection
c) Stalling protection
© PMI, NTPC 79
d) Overload Alarm
e) E/F protection
f) Under voltage protection.
The above protections are explained with respect to the scheme shown (Ref. fig 39)
Short circuit protection
High set instantaneous over current relays (50) will be connected in all the three
phases to trip the motor. The relays would be set such that they do not operate due
to inrush of starting current, the pick up setting being about twice the motor locked
rotor current. For the motors above 2000Kw differential protection is normally
provided for short circuit protection.
Overload protection
Long inverse time 0/C relays (51) are connected in two phases to trip the motor. The
relays should be .set to pick up at about 125% of the rated full load current of the
motor. The time setting would be selected such that the relays do not operate during
the motor starting process.
© PMI, NTPC 80
Stalling protection
It is provided only for those motors, which have a comparatively less starting time,
which is too close to or lesser, than the hot locked rotor withstands time. The
protection would comprise an instantaneous over current relay (50: LR) on one
phase, set to pick up at about 50U% of the motor rated current and D.C. timer (2 LR).
The motor would also have a speed switch to detect stalling. If the current relays
remains picked up and speed switch continuous to indicate stalling/low speed for the
permissible stalling time of the motor, the protection would trip the circuit breaker.
Overload protection (Alarm)
Overload alarm would be arranged for each motor with an instantaneous over relay
(50A), on one phase and D.C. timer (2A). The relay would have a high reset ratio
© PMI, NTPC 81
and would be set to pick up at about 105% of the motor rated full load current. The
time setting is more than the normal starting time of the motor so that the alarm is not
initiated during a normal starting. The alarm provision would ensure that in case of
overload the operator has adequate time to take corrective measures, before motor
tripping is initiated by inverse time relays.
E/F protection
E/F Protection with a core balance C.T on the outgoing cables and an over current
relays (64)
For large motors having more than one cable (where core balance C.T. is not
feasible) the E/F relay would be connected in the residual circuit of the phase C.T’s
used for other protections. If the relay is put in the residual circuit it should be
ensured that it does not operate during starting for which a series resistance is used
with the relay.
Under voltage protection
Under voltage protection is provided to trip the motors in stages according to their
importance when a supply failure or a persistent severe voltage dip takes place. This
will be linked up to the auto-change over scheme.
All 415V motors connected through the circuit breaker are generally provided with
instantaneous over current protection for short circuits and inverse time over current
relay for overload protection. For 415V motors provided with contractor control, the
5.C. protection is provided by means of HRC fuse and bimetallic 'thermal overload
protection for overload.
© PMI, NTPC 82
12. Generator
The core of an electrical power system is the generator. The range of size of
generator extends from a few hundred KVA (or even less) to sets exceeding 500
MVA in rating.
A modern generating unit is a complex system comprising the generator stator
winding and associated transformer and unit transformer, the rotor with its field
winding and exciters, along with the turbine end its auxiliaries and boiler and
auxiliaries. Faults of many kinds can occur within the system for which diverse
protective means are needed. The amount of protection applied will be governed by
economic considerations, taking into account the value of the machine and its,
importance to the power system as a whole.
Of the various faults, which may occur on the generator, stator faults and unbalanced
loading are the moat dangerous in nature, the faults which may occur on stator
windings may be listed as follows:
a) Phase to phase faults
b) Phase to earth faults
c) Short circuits between turns
d) Open circuits in winding, and
e) Over heating.
Sustained unbalanced loading on the generator arises from earth faults or faults
between phases on the external circuit of the generator. Unbalanced currents, even
of a value much less than the rated current of the machine, may give rise to
© PMI, NTPC 83
dangerous overheating in the rotor, which may result in mechanical weakening or
even failure.
As soon as a stator fault develops, the generator must be disconnected from the
system to avoid the faulty machine from being fed by other. The main circuit breaker
between’ the machine and the busbar must therefore be opened. At the same time it
is necessary to suppress the rotor field to prevent the machine from feeding into the
fault itself.
Protection against stator (Phase to Phase faults)
The most common form of protection adopted for this purpose is the differential
protection. In the figure, "A" represents the stator windings of a 3-phase alternator;
current transformers CTi are mounted in the neutral connection and CT2 are mounted
in the switchgear equipment. Each set of CTa are connected in star the two star
points being joined by neutral pilot* Relay coils are connected in star and the star
point being connected to the star point of the CTs. It is essential that the relay coil in
the path of each point of current transformers and the neutral pilot should be
connected at equipotential points. The. Relays are usually of electromagnetic type.
The CTs selected should be identical in characteristics.
Let us consider a short circuit between the phases (Y & B) the path of the circuit
current shall be as indicated in the figure 40. This current will be reflected in
secondary winding of both corresponding CT's. The fault component of the
secondary current will flow through the two relays, and operates the relays and main
breaker is tripped out. More important point to be checked here is that the relay
should not operate on through fault, which is ensured by pulling a resistance in series
of relay coils to make the relay stable under through fault condition.
© PMI, NTPC 84
Protection against earth faults
Normally the generators have high resistance grounding through a grounding
transformer and a resistance connected across it. The earth fault current is normally
restricted to few ampere to have an economical design of stator core. This value of
fault current would not be able to operate generator differential protection and
hence the head of separate earthfault protection.
© PMI, NTPC 85
There are three ways of providing this protection;
1) A voltage relay connected across the grounding resistors, as there is an
earthfault. The voltage will appear across the resistance and relay shall
operate. This relay protects nearly 95-96% of the stator winding.
2) A current relay connected to the CT provided in grounding transformer
secondary circuit. As there is an earthfault there would be voltage across the
resistance, which will drive a current, and relay would operate.
3) A voltage relay connected to the open delta in generator voltage transformer
as the earth fault across in the stator winding the voltage balance disturbs and
operate the relay
Stator Inter-turn protection
In case of large generators stator windings are sometimes duplicated owing' to the
very high currents which they have to carry. The circuits are connected into the
equal parallel groups with a current transformer for each group. S1 and So are the
stator windings of one phase only. The CTs, are connected on the circulating current
principle. As long as there is no turn to turn fault both the currents will be equal and
no resultant current will flow through relay. If a turn-to-turn fault develops, then the
© PMI, NTPC 86
stator currents will no longer be equal and a current proportional to the difference in
two currents will flow through the relay R (Ref.fig.42)
Figure No- 42
Negative sequence current protection
It was mentioned earlier that sustained flow of unbalanced current will cause rotor
overheating and it is necessary to provide protection against them. In cases of
unbalanced loads, negative sequence components of currents will flow through the
windings. If we detect the negative sequence currents and provide protection against
these currents, it is equivalent to providing protection against unbalanced loading.
Principle of negative sequence current detection is explained below in brief:
In the circuit of fig.43 the resistance and inductance Z Z1 are such that the current
through the impedance lags the voltage across it by an angle of 60o, Z2 is a pure
© PMI, NTPC 87
resistance and the ohmic value of which is equivalent to Z1 from the below vector
diagram 44 it can be seen that the above circuit detect negative phase sequence of
currents and not positive phase sequence component, since the relay R measures
the vector sum of E1 & E2. By suitably interchanging Z1 & Z2, it can be proved that
the above circuit will detect PRS component of currents.
The detection of pps can be used in over load protection and the detection of nPS
currents can be used to limit the degree of unbalance. The later is particularly
important with reference to the currents in the stator windings of three phase
alternators. If the stator currents contains ups currents, the field due to the ups
components rotates at synchronous speed in the opposite direction to that of the
stator, since ups is equivalent to a symmetrical system of vectors rotating in a clock
wise direction. Thus in the case of 50 HZ two pole alternator the field due to ups
currents cuts the rotor at 100 HZ or 6000 rmp. If the nps field exceeds limits set by
the design of the machine, extensive rotor damage may result from over heating
caused mainly due to eddy currents induced in the rotor iron.
The modern generators are generally provided with the following protections;
a) Single phase to earth fault protection
b) Over load protection
c) Negative sequence current protection
d) Earth fault protection on the HV side of transformer
e) Generator differential protection
f) Unit differential protection
g) Generator transformer differential protection
© PMI, NTPC 88
h) Gas protection (from transformer side)
i) Protection against Inter turn faults
j) Loss of excitation protection
k) Rotor over current protection
l) Rotor E/F protection.
m) Protection through B8P
n) Pole slipping protection.
o) Over voltage and over fluxing protection
p) Backup impedance protection
The above protections are explained with the help of the following schemes (Fig.45)
© PMI, NTPC 89
© PMI, NTPC 90
CT Connections
SI No Protection Self of CIS used
1. Unit differential protection CT 1, CT9, CT14 & 15
2. Generator differential CT 7 and C T 8
3. Bus- Bar protection CT 2
4. Generator Earth fault C T 10
5. Generator transverse differential protection. CT 12
6. Summary E/F porten C T 11
7. Metering CT 3 and CT 5
8. A V R CT 4
9. Overloaded, Loss, of excitation, pole
Shipping, Negative, sequence, Backup,
Impedance. CT 9
10. Stator E/F C T 16
Generator differential protection, protection against inter turn faults and principle of
negative phase sequence currents protection were discussed already.
Unit differential protection
This protection is intended to safeguard the generator against phase to phase fault or
three phase short circuits in the windings; or inter connected bus ducts between the
© PMI, NTPC 91
generator and generator transformer; or the transformer against phase to phase fault
in primary, or phase to earth fault in the secondary side up to the protected zone.
The principle operation is same as in the case of generator differential protection. CT
CT-10 & I provide protection through suitable relay connection (Ref. Fig.46).
Figure-46
Overload protection
This protection is provided to safeguard the generator from rise in temperature in the
stator winding due to overload. This protection initiates an alarm to guide the
operator for reducing the load. If overload is accompanied by under voltage, tripping
will occur. Two relays OL-1 & OL-2 are connected in series on the generator
differential protection circuit between the CTs CT-4 & CT-8, setting of OL1 is lower
than that of OL-2. When the overload on generator reaches to the set value of OL-1,
the annunciation "overload" will appear in UCB. Then action should be taken in
reduce the load on the generator (Ref. Fig.47)
© PMI, NTPC 92
Negative sequence protection
Negative phase sequence currents will flow through the generator for phase-to-phase
faults, during asymmetrical loading, due to open circuit on any one phase or during
single phase to earth faults.
Negative phase sequence relay has one element, which sounds an alarm in UCB
when Z1 reaches the permissible Neg. sequence current. There is one element,
which trips the generator when it reaches beyond permissible value.
Generator stator earth fault protection
Neutral of the stator winding in the generator shown in fig.48 is earthed via high
resistance. Therefore, a single earth fault in the winding is not that harmful. In the
generator under consideration, the two neutral points of the double star winding of
the stator are inter-connected through a transverse differential CT and earthed
through grounding transformer.
© PMI, NTPC 93
Earth fault protection on the HV side of the transformer
When a single phase to earth fault occurs on the HV side of the generator
transformer i.e. on the bushing itself, busbars, outgoing lines or transformer etc.,
current will flow through neutral point of the star connected HV winding to the
earth since the neutral earthing isolator is kept closed in the generator transformer.
CT 10 & CT 11 are in the neutral to earth circuit. A current relay (3) is connected in
the secondary of the CT 11 and will pick up at its set value. In the event of a single
phase to earth fault on the HV side and when current exceeds the set value, relay no.
(3) will pick up and trips the circuit breaker (Ref. fig 49).
© PMI, NTPC 94
Generator transverse differential protection
The double star winding of the generator stator has its two neutral points connected
through a CT 13. During normal balanced condition both the neutrals will be at zero
potential. At the occurrence of an interterm fault in one of the parallel windings of a
phase or between the turns of the two parallel windings in the same phase, a
potential difference will exist between the two neutral points and current will circulate
between them. A differential relay connected through secondary of CT 3 will pick up
at its' set value and energise the Generator master relay, which in turn trips the unit.
An inturn fault in the generator stator winding falls within the zone of both the
generator and unit differential protections. Whenever an unit trips on differential
protection, voltage should not be developed on the machine, unless through check up
was carried out.
Loss of excitation protections
Sudden loss of excitation in an alternator makes the generator to run as an induction
generator. Generally all the generators shall be designed to run as induction
generator with a reduced load for a short period but the rotor will get over-heated
from the induced current flowing in the rotor iron particularly at the retaining rings of
the rotor. "Continuous operation of the generator as induction-generator is prohibited.
Further when generator runs as an induction generator it draws the reactive power
from the grid and there may be a voltage dips in the system, which is not desirable
from system point of view. So there is a loss of excitation accompanied by under
voltage there is instantaneous tripping of Unit, but if loss of excitation is there without
undervoltage there tripping may be delayed.
Pole slipping protection
Pole slipping may occur in the generator due to un-stability in the comparatively
weak, long distance 900/220 KV system associated with' the generator, such a
© PMI, NTPC 95
situation may not be covered by loss of excitation if generator excitation is healthy,
hence there is a need of separate protection.
Point A is the normal operating point. If the pt. A shifts towards the fourth quardent
as shown in Fig.50 then Blinder B1 and B2 will sense it and if B1 and B2 operates
within a set time then relay operates and trips the generator.
Overvoltage and overfluxing protection
The generator can develop dangerously high voltages in the event of mal-operation of
AVR or a load throw off while generator excitation is under manual control. An
overvoltage relay should be provided to detect this and give an alarm in UCB.
Overfluxing of the generator transformer and LJAT’s can occur due to overvoltages
on generator terminals or due to excitation application while generator is at lower
speed. Its persistence can cause gradual overheating and damage to the
transformers and generators. An overfluxing protection should be provided to detect
this and trip the generator.
Reverse overvoltage shall also be covered by this protection.
Backup impedance protections
A three phase zone impedance relay (216) is to be provided for the backup protection
of generator against external three phase and phase to phase faults in the 400/220
1<V system which may be hanging on due to failure of this own system primary
© PMI, NTPC 96
protection. The zone of 216 should be extended beyond 400 KV/220 KV switchyard
as far as possible and it should be connected to trip the generator after a time delay
of 1 to 1.5 seconds so that the generator is tripped only when 400 KV/220 KV
protections has not cleared the faults even in the second zone.
Reverse power protection
When the input to the prime mover suddenly goes off and the generator is in service
delivering power to the system, the machine will not cease to function, but would
continue to rotate at the same speed; now as motor deriving the requisite energy from
the system to keep the frictional and windage losses Both the direction and
magnitude of the active power between the system and the machine therefore
changes, while the reactive or wattless power controlled by the field excitation
remains unaltered. Although this abnormal condition would not harm the generator, it
could, however damage the prime mover. It has been the general practice to provide
protection against any such contigencies, by thermal or mechanical devices in the
form of temperature detectors and hydraulic flow indicators. The adoption of a single
reverse power relay at the generator terminals, although attractive from the point of
added safety and backup protection, was not considered till recently, apparently
an account of certain difficulties and limitations in its application. The relay while
capable enough to distinguish motoring from transient power reversals that occur
when paralleling or during system disturbances, had to be at the same time
sufficiently sensitive to pick up for motoring currents as low as 0.5% of the machine
rating.
Low Forward power interlock
If the main circuit breaker of a very large steam or hydrogenerator set trips open
before the prime mover inlet value is closed, then there is a tendency for the rotor to
accelerate and overspeed, since the governor mechanism would be incapable of
controlling the speed quickly. The introduction of a low forward power relay has been
considered favourable under such circumstances to exercise a check and permit the
main circuit breakers to operate under fault conditions; only after the prime mover
© PMI, NTPC 97
inlet valve is closed. The low tampered power relay in conjunction with an adjustable
time lag unit could also then function for sustained motoring conditions. Provision of
the time lag unit is for preventing undesired operation from transient power reversals.
What will happen if generator protection acts?
When the generator protection acts,
1) The circuit breaker connecting the unit to the Bus bars will trip.
2) Field breaker will trip.
3) 6.6 KV Reserve supply comes into service on interlock and working supply
breakers will trip.
4) Impulse will be given from the Generator master relay or generator trip relay to
the unit master relay Lu rip boiler and Turbine.
Generator will trip on protection for any faults on unit Transformers also.
© PMI, NTPC 98
13. Transformer
Transformers play vital role in power systems. It is relatively simple and reliable
equipment when compared to generator. The faults generally occurring on power
transformers are earth faults, phase to phase faults, inter turn faults, and over-heating
from overloading or coreheating. Of these the most common are earth fault and
interturn faults rapidly develop into E/Fs; and therefore only earth fault protection is
generally provided. The choice of protection for any given power transformer depends
upon a number of factors, such as its size, its importance, cost etc.,
The following information is necessary while selecting the protection scheme for a
power transformer.
1) Particulars of transformer viz. KVA, voltage ratio, connections of windings,
percentage reactance, whether neutral is earthed or not whether indoor or
outdoor, with or without conservator etc.,
2) Fault level at power transformer terminal
3) Network diagram showing position of transformer
4) Requirements of protection
5) Length and cross-section of connection leading between CT loads & relay panels
etc.
Protective equipment for transformers include gas relays, Merz price of protection etc.
Buchholz Relays
This is meant for protecting transformer against incipient faults. The Buchholz
system is applicable to oil-immersed transformers, the great majority, and depends
© PMI, NTPC 99
on the fact that transformer breakdowns always preceded-by more or less violent
generation of gas. An earth fault has the' same result. Sudden short circuits rapidly
increase the temperature of the windings, particularly the inner layers, and results in
vaporisation of the oil, will also cause oil dissociation accompanied by the generation
of the GAS Core faults, such as short circuits due to faulty core-clamp .insulation,
produce local heating and generate gas.
This generation of oil vapour or gas is utilised to actuate a relay. The relay is
hydraulic devices, arranged in the pipeline between the transformer tank and the
separate oil conservator. In fig.5-1 the relay is shown in greater detail. The vessel is
normally full of oil. It contains two floats b1 & b2, which are to be hinged and to be
pressed by their buoyancy against two stops. If gas bubbles are generated in the
transformer due to a fault, they will rise and will be trapped in the upper part of the
relay chamber, thereby displacing the oil and lowering the float bi. This sinks and
eventually closes an external contact, which operates an alarm.
© PMI, NTPC 100
A small window in the wall of the vessel shows the amount of gas trapped and its
colour.. From the rate of increase of gas an estimate can be made of the severity and
continuance of the fault, while from the colour a diagnosis of the type of fault is
possible.
If the rate of generation of gas is small, the lower float by is unaffected. When the
fault becomes dangerous and the gas production violent the sudden displacement of
oil along the pipeline tips the float b2 and causes a second contact to be closed
making the trip-coil circuit and operating the main switches on both h.v. and l.v. sides.
Gas is not produced until the local temperature exceeds about -l50°C. Thus
momentary overloads do not affect the relay unless the transformer is already hot.
The normal to-and-fro movement of the oil produced by the cycles of heating and
cooling in service is insufficient to cause relay operation.
Differential Protection
This type of protection is meant for protecting transformer against phase-to-phase
faults & E/Fs. The differential protection responds to vector difference between two
similar quantities. CTs are connected to each end of the line connected to the
transformers. CT secondaries are connected to the transformers. CT secondaries
are connected either in star or in delta and pilot wires connected between CTs of
each end. The CT connections and CT ratios are such that the currents fad into the
pilot from both the ends are equal under normal circumstances and for the external
faults. During internal faults such as phase to phase or phase to ground the balance
is disturbed and the out of balance current flow thro' relay coils and operate the
protection. To avoid unwanted operation for thru' faults restraining or bias coils are
provided in series with pilot wires.
In designing differential protection of transformers care should be taken to connect
CT secondaries so that it will not operate for ext-prnal faults. For example, if
transformer is connected in star-star & if the Cl secondaries are also connected in
star-star then protection will operate for even external faults as shown in fig. whereas
© PMI, NTPC 101
if we connect the CT secondaries in delta then this problem can be eliminated.
(Refer Fig.52).
Similarly for a A - Y transformer, since there is a. phase displacement between
primary and secondary line currents and to compensate for them, CTs on the delta
side of the transformer are connected in delta. Not only this, due to different voltages
on the input and output sides of the transformer the magnitudes of the line currents
will also be different and unless suitable ratios for the CTs on the input and output are
selected there may be unwanted relay operation. A general rule is that the CTs cm
any star winding of a power transformer should be connected in delta & that the CTs
on any delta winding should be in star. The table I given below shows the type of
connection employed for the CTs on the input and the output sides for different
connections of the primary & secondary windings of power transformers.
© PMI, NTPC 102
Sl.No Power Transformer Current Transformers
Primary Secondary On the Primary side
On the Secon-ary side
1. Star Star with neutral earthed. Delta Delta
2. Delta Star with neutral earthed Star
Delta
3. Star with neutral earthed Delta Delta Star
4. Delta
Delta with earthing transformer on secondary.
Star Delta
5. Star Star with a tertiary winding. Delta Delta
Problems arising in Merz. price, protection system applied to transformers.
Simple differential protection system is not enough for protecting transformers due
to following reasons:
Difference in lengths of pilot wires on either sides of the relays. This difficulty is
overcome by connecting adjustable resistors in pilot wires. These are adjusted on site
to set equipotential point on pilot wires.
Difference in CT ratios - due to ratio error difference at high values of short circuit
currents. Because of this difference the relay operates for through fault. This
difficulty is overcome by utilising based or percentage differential relay. In such a
relay a restraining coil is connected in the pilot ires.
© PMI, NTPC 103
Magnetisinq current in rush
When the transformer is energised, initially there is no induced e.m.f. the condition is
similar to switching of an inductive circuit. The resistance bring low, a large in-
rush of magnetising current takes place. The magnitude of this current in-rush can be
several times that of load current. Maximum peak values equal to 6 to 8 times the
rate current can occur.
The inrush of magnetising current will certainly cause the operation of Merz price
protection system unless some special modification is done. Formerly, the relay was
provided with time lag of 0.2 second. By this time inrush will vanish and relay does
not trip unnecessarily.
While commissioning, one does not know whether there is a fault or not. Providing a
time lag is therefore risky. There are several reported incidents in which the
transformer tripped due to internal fault during switching on for the first time. The
engineers thought that the transformer has tripped due to magnetising current inrush.
They made the relay inoperative and switched on the transformer. Since there was a
fault and relay was inoperative, the transformer was damaged.
Next development was desensitizing the relay for a short period of 0.1 second during
switching. After this time the shunt across the relay is removed. This method also
leads to the same danger mentioned above. The latest method adopted in
transformer protection is "Harmonic current restraint".
Tap changing alters the ratio of voltages (and currents) between H.V. sides and L.V.
sides.
Harmonic Restraint
The initial inrush of magnetising currents have a high component of even and odd
harmonics. Table 2 gives a typical analysis.
© PMI, NTPC 104
Harmonic component of snort circuit currents is negligible. This principle is used for
restraining the relay from operation during initial current inrush. The harmonic restrain
differential relay remains sensitive to fault currents but does not operate due to
magnetizing currents.
TABLE-2
The operating coil of the relay receives fundamental component of current only. The
restraining coil receives rectified sum of fundamental and harmonic component.
Harmonic component in magnetizing current
Amplitude as a % of fundamental
2nd
63.0
3rd
26.8
4th
5.1
5th
4.1
6th
3.1
7th
2.1
© PMI, NTPC 105
14. Bus Bars
The majority of bus bar faults involve one phase and earth, but faults arise from many
causes and a significant number are interphase clear of earth. A large proportion of
bus bar faults result from human error rather than the Failure of switchgear
components.
The protection of bus bars in a power system plays a vital role and if a fault develops
in the bus bars considerable damage and disruption of supply will occur. The bus bar
protection covers every Feeder connected to that particular bus. Bus bar protection
will be designed so as to trip all the elements connected to that particular bus, needs
particular attention due to the Facts that:
a) Fault level in bus bars is very high.
b) Stability of the system is affected.
c) Fault on bus bars causes interruption of supply.
d) Fault in bus bars should be cleared as quickly as possible to avoid any damage to equipments.
It is essential that bus bar protection installations should be so designed to have the
highest possible standard of reliability since the failure of the later to operate on fault
or alternatively their unnecessary operation under healthy conditions will generally
have very much more serious consequence than with any other protection system. To
achieve this it is general practice to design the protection system in such a manner
that two independent fault-detecting devices must operate before tripping takes place.
Requirements of bus bar protection
1) Shortest possible tripping time. The bus bars now-a-days have developed into
focal points, to which numerous incoming and outgoing ines are connected,
© PMI, NTPC 106
handling enormous energy. Short circuit currents attain a value as high as 100
KA. Since bus bar Faults arc accompanied by arcing in most of the cases, 'hey
can cause considerable damage due to Faults, it is necessary to design the
protection system to clear the Fault within shortest possible tidie (Opn. time of
relay).
Reliability
A protection scheme provided for bus bars must be reliable and selective i.e. it should
not respond to faults outside the protected zone, and secondly it shall only disconnect
those bus bars or sectional area affected by the fault. Secondly the system must
have a maximum flexibility. It must not be complicated in design. The design of the
protection system must be such, as to allow modifications and extensions at any time.
Since the bus bar protection equipment operates quite rarely in practice there must
be suitable arrangements to test the system frequently.
Frame Leakage Protection
© PMI, NTPC 107
Figure 53 shows application of the frame leakage protection to a single bus bar
substation with a switchgear unit comprising an incoming transformer and two
outgoing feeder equipment. The switchgear is of the metal dad-type, All the metal
frameworks are bonded together and lightly insulated from earth. The switchgear
framework should also be insulated from the lead cable seat, so that when a leakage
to the framework occurs, the only path for the leakage current is through the
connection from the framework to earth.
The contacts of the check relay, which is energized by a current transformer mounted
in the transformer neutral earth connection, are connected in series with the contacts
of the frame leakage relay which is energized by a current transformer mounted in the
earth connection of the switchgear frame. We can see from the figure that two
independent relays must operate before the tripping relays can be energised, to trip
the circuit breakers of the equipment connected to the faulty section of the busbars.
Let us assume that a fault to earth develop on feeder C outside the protected area.
Current will then pass through the primary of the neutral check current transformer to
power transformer and the check relay contacts will close but the frame leakage relay
contacts will remain open.
© PMI, NTPC 108
If, however, an earth fault takes place within the protected area, current will appear in
both the earth connections and both relays will close to energize the tripping relay,
which will trip the circuit-breaker of all sections i.e. A, B, C.
Circulating current protection
The Merz price circulation current system of protection is one of the most widely used
system in the field of protective gear engineering.
Its principle of operation was explained in previous chapters.
The application of the current balanced principles as applied to busbar protection as
shown in the fig. in single line diagram for the sake of simplicity. There balanced
C.T. groups are employed, one for each of the two bus bar sections (discriminative
group) and the third covering the complete bus bar installation (check group). The
discriminative groups are thus fully discriminative.
While the check group is fully discriminative in sofar as the complete busbar
installation is concerned since it is unable to distinguish between faults on the
different sections. As shown in the fig. both the check relay and the appropriate
discriminating relay must operate before tripping of the fault section can occur.
© PMI, NTPC 109
15. Feeder
The transmission lines form important links between generating stations and load
points. With the steady growth of power system, the length of transmission lines, the
amount of power transmitted, short circuit levels and stability requirements have
become quite significant. The system voltages, above 660V are called high voltages,
22D KV and above called extra high voltages and above 775 KV are called ultra high
voltage. For continuous and reliable power supply a proper protection scheme for
transmission lines and feeders is very much essential.
The various protection schemes as applied to feeder protection are as follows:
a) Time graded protection,
b) Differential protection,
c) Distance protection, and
d) Carrier current protection.
Non-directional time graded over current protection
Figure 55 two sections of radical feeders between AB & BC. Protection is provided at
all the stations. 'X' mark represents a CB; mark indicates that CB operates for faults
on sides, t1, t2 & t3 indicates the time lag. For a fault beyond station 'C1 the circuit
breaker at C operates first after t1 time meanwhile other relays at station B & A start
operating but after 0.3 seconds the fault is cleared and the relays at A&B get reset.
Therefore for faults between B&C only C.B. at 'B' .operates and likewise. Thus
unnecessary tripping is avoided. If the relay at 'B' fails to operate, the relay at A
provides backup protection. Inverse definite minimum time delay relays are
extensively used for obtaining current and time gradings.
The main disadvantage of this system is that a time lag is to be provided. Secondly,
this method is not suitable for ring mains or parallel feeder. The settings of the relays
© PMI, NTPC 110
are to be changed with new connections. And also it is not suitable for such systems
where rapid fault clearing is necessary.
Parallel feeder protection
To obtain discrimination, where power can flow to the fault from both the directions,
the circuit breakers on both the sides should trip, so as to disconnect the faulty line.
Example: parallel feeders, ring mains, T feeders, interconnected lines etc. In such
cases directional relays can operate for fault current flowing in a particular direction
shown by arrow:
X Circuit Breaker
—> Directional Relay
<—> Non Directional Relay.
© PMI, NTPC 111
Fig.56 shows system where three feeders are connected in parallel between a power
station and remote supply point.
Let an earth fault develop on feeder 2 as shown in the fig. It will be seen that this fault
is fed via three routes, (a) directly along feeder 2 from the power source, (b) From
feeder 1'via the receiving and busbars, (c) from feeder 3 via the receiving and
busbars.
Now.to clear this fault, only circuit breakers 3 and 4 should open. This is achieved by
employing non-directional relays on the supply end and directional relays operating
only when fault power is feeding in the direction of the arrow on the receiving end.
With such an arrangement, it is clear that with a fault at E all the three relays at the
receiving end, only the relay on feeder 2 (i.e. relay number 4) will start and operate to
isolate the fault from the receiving end. But it is also desired that the circuit breakers
on feeder 1 and 3 at the source do not open. This is ensured by the fact that the time
of operation for relays 1 and 5 will be longer than that of 3. This is because the fault
current in feeders 1 and 3 will be much smaller than that in feeder 2 on account of
their greater impedance and so the inverse time characteristics of the relays will
provide greater time of operation for relay 3, so that relay 3 will have isolated its
feeder before relays 1 and 5 have completed their travel.
Distance Protection
Distance relay is considered for protection of transmission lines where the time lag
can’t be permitted and selectivity can't be obtained by over current relaying. A
distance relay measures the ratio V/I at location, which give the measure of distance
between the relay and fault location. The impedance of a fault loop is proportional to
the distance between the relay and the fault point. For a given setting, the distance
relay picks up, when impedance measured by it is less than the set value. Hence it
protects a certain length of the line. That is why it is called a distance protection.
Distance relays differ in principle from other forms of relays in that their performance
is not governed by magnitude of the current or the voltage in the protected circuit but
© PMI, NTPC 112
rather on the ratio of these two quantities. In distance relays, there is balance
between voltage and current ratio, which can be expressed in terms of impedance.
Impedance is an electrical measure of distance along a transmission line.
Impedance Relay
In an impedance relay, the torque produced by a current balanced against the
torque produced by a voltage element. Element produces position (pick-up) torque
proportional to voltage element produces negative (Reset) torque proportional torque
equation is
T = K' I2 K"V2 K"
where K and K" are torque constants and k" is spring constant-. At the balance point,
when the relay is on the voltage of operating, the net torque is zero so that
K” = V 2 - K’ I2 - K” ‘
Dividing by K” I 2 we get
V 2 K ‘ K” ‘ ----------- = ---------- - ------------- I2 K” K” I2
V K’ K” ‘ Or -------- = Z = ------ -- -------- I K” K” I2
It is customary to neglect the effect of the control spring, since its effect is
noticeable only at current magnitudes well below those normally encountered.
Therefore with K" ' = 0,
k’ Z = ------------ = Constant k”
In other words an impedance relay is on the verge of operation at a given constant
value of the ratio V to I which may be expressed as impedance.
© PMI, NTPC 113
Theoretically, the V/I ratio as measured will be constant for any particular fault
position and will only vary if the position of the fault with respect to the relaying point
varies. Thus nearer the fault is to the relay, the lower would be the ratio of voltage to
current and conversely, further the fault is from the relay the higher will be this ratio.
If a relay capable of measuring this ratio is now installed at the supply and of a line,
its V/I setting can be adjusted so that the relay operates for faults anywhere within
a given section of line and remains in operative for any fault beyond this section.
The usual way of expressing the operating characteristics of an impedance relay
is on R-X diagram as shown in fig.57 the numerical value of the ratio V to I is
shown as the length of a radious vector such as Z and phase angle 0 between
the voltage and current fixes the position of the vector as s hown
since the operation of the impedance relay is independent of the phase angle ø
between V and I, the operating characteristic is a circle with its centre as origin.
Any value of Z less than the radius of the circle will cause the relay to operate,
whereas any value greater than this will cause the relay to restrain irrespective of the
phase angle between V and I; the impedance relay is this non-directional (Refer
Fig.53). If such an impedance relay is applied to a transmission line where the
voltage element is fed from a voltage transformer and the current element from a
current transformer as shown in fig. The two quantities supplied to the relay will be
proportional to the line current I and the system voltage V. Consider a fault as
© PMI, NTPC 114
shown the relay will be supplied with a voltage equal to 'If. Thus the ratio of the
voltage and the current supplied to the relay will be equal to 'Zf the impedance
between the relaying point and the point of fault. As above, the impedance relay
being non-directional 'If' would also operate for all fault positions within section AC of
the line in the figure for which the impedance presented to the relay is less than 'Zf.
To avoid this unwanted operation it is necessary to use a directional relay in
conjunction with the impedance relay, the combined characteristic then being the
shaded part of fig: in which AB represents the impedance of the line in front of the
relay and AC the impedance of the line behind the relaying point since the directional
unit permits tripping only in the +ve torque region. The active portion of the
impedance unit characteristic is shown in fig.59 (shaded). The net result is that
tripping will occur only for points that are both within the circle and above directional
unit characteristic.
© PMI, NTPC 115
Admittance Relay (MKO Relay)
The impedance relay so far discussed is not normally used mainly because of the need
of separate directional relay and relays of the Mho type are normally used. The Mho
relay is similar in principle to an impedance relay ‘but is made inherently directional by
the addition of a voltage winding kpo.wn as the polarising winding. With potential
polarizing winding, the torque is the product of the potential polarising flux times the
fluxes from the opposed I and V poles as shown in fig.60. Hence the torque equation of
such a unit is
© PMI, NTPC 116
T = K VI cos (ø – ά ) – K”V2 – K” ‘.
Where ø and x are defined positive when I lags V. At balance point T = 0
Therefore k” V2 = KVI cos (ø – ά ) – K” ‘
Dividing both sides by K” V I
V K K” ‘ --- = Z = ---- (ø – ά ) - ------ I K” K” VI
If we neglect the control spring effect, K” ‘ =0
K and Z = ---- cos (ø – ά ) K” This is the equation of a circle of diameter K/K" which posses through the origin as
shown in fig.61 the impedance characteristic of a relay is therefore a circle passing
through the origin.
© PMI, NTPC 117
If we consider the two lines AB and AC with Mho relay located at A. It will be seen that
the relay is inherently directional and does not need separate directional element.
Principle of operation of distance protection can be understood by following illustration
(Fig.62). Considering zero fault impedance the voltage at fault point will be zero. The
voltage -it location 'o' will be equal to the voltage drop along the length OF: If a fault
had occurred near ‘O' the voltage at '0' would be very less, current would be more,
because of the reduction in line impedance.
In distance relays the ratio V/I is measured. The current give operating torque and
voltage gives restraining torque. Hence for values of Z above certain setting, the relay
© PMI, NTPC 118
does not operate. Hence it protects only a certain length equivalent to its impedance
setting.
DifferentiaI Protection
The rlirferentia.1 circulating current protection principle is used in protecting
transmission lines upto 16 KM. Two CT's of similar construction and ratios are
connected in each protected line, one at each end. Under healthy/external fault
conditions the secondary currents are equal and circulate in pilot wires. The relay is
connected in between equipotential points of pilot wires. For external fault and normal
condition the differential current of two CIs is zero and relay dues not operate. During
Internal faults this balance is disturbed and differential current flow thro the relay
operating coils. Ref. Fig. 63.
Pilot wire relaying using voltage balance
In this method the CT secondary currents are converted into an equivalent voltage
source. The equivalent voltages at two ends are compared as shown in the fig.
64. For healthy condition no current will be flowing thro' the relay coil since
© PMI, NTPC 119
both the voltages will be equal and opposite. During internal fault the
equilibrium is disturbed and one voltage will be more
than other voltage, so a current will flow thro' the relay coil. In Transley system,
telephone lines are used as pilot wires. In other systems pilot wires are to be erected
additionally and the pilot wires need supervision to check. Open circuits and short
circuits on pilot wires lead to relay failure.
Pilot wires are laid at the same time along with power conductors. In cable systems,
pilot cables are put in the same trench of power cable. Voltages are induced in pilot
wires due to the field of power conductors. This voltage should be limited to 5 to 15 V.
U/H pilot wires are exposed to lightening. So they are to be provided with lightening
arresters.
Carrier current protection
This type of protection is used for protection of transmission lines. Carrier currents of
the frequency range 31J to 500 k.c./s are transmitted and received thro' the
transmission lines for the purpose of protection. Each end of the line will be provided
© PMI, NTPC 120
with identical carrier current equipment. The carrier current equipments connected to
the transmission line thro coupling capacitor which is of such a capacitance that it offers
low reactance to carrier frequency and high reactance to power frequency.
The line trap unit is a parallel resonance circuit which offer negligible impedance to
power frequency currents, the line traps are provided to restrict the carrier signals in the
desired lines so as to avoid interference with other lines, the relay unit is connected to
the system by means of a C.T. & P.T.
The relaying acts at both the ends when a fault occurs in the transmission line. The
fault is sensed by the disturbance in the signal received from the other end. As the fault
occurs, both the circuit breakers at the ends trip simultaneously (Ref.Fiq.65).
There are two methods of carrier current pro Leo lions.
a) Directional comparison method, and
b) Phase comparison method.
In phase comparison method, the phase relation between the current entering
the zone of protection and current leaving the zone of protection are
compared. When there is no fault the signal is sent for alternate 1/2 cycle from
each and which result in continuous signal over the line. The
© PMI, NTPC 121
same conditions hold good for external fault. During internal fault the current in
one line reverses in phase or differs in phase and remains below the fault
detector setting, so that carrier is sent only for half the time. The relay is arranged
to detect the absence of signal in the line. When the difference between phase
readies a certain value, tripping will take place. In other words, in this system,
simultaneous measurement of phase displacement at both ends of protected line
is made possible by means of a high frequency current link. For external faults
the effect produced by the two signals is similar to that obtained when a
continuous high frequency line is available on the line. Sum of these two signals
for an internal fault produces an effect similar to the periodic suppression of such
a continuous carrier, the duration of each suppression being the primary current
at both ends. The protection is designed to operate for phase displacement
greater than a normal angle of 30°. The angle is usually referred to as the
stability angle.
Distance Protection of Feeders
Distance protection is meant for providing selective tripping of the circuit breaker
feeding the fault depending upon the zone where the fault occurs. This is
accomplished with the aid of directional impedance relays. For grid feeders, the
© PMI, NTPC 122
directional impedance relays will actuate for power flow from the bus to the line.
To guard against the mal operation of the impedance relays during power swings
a negative phase sequence filter relay is used. When power swing occurs, the
impedance relays might pick up, but the protection will not operate, as the filter
relay will not pick up. (Ref. Fig. 66&67).
In the scheme now under discussion, 'I zone' comprises 80% of the line and
second zone comprises 80 to 120, that is, the second zone will comprise
receiving end buses also.
As soon as the DC supply to the protection circuit is switched on,
relays ‘A’ and 'B' get energised. Relay 'A' will be energised through
normally closed contact A-l, and subsequently thro' it retaining contact
A-3 and the normally closed contact of ‘C' of the filter relay. Relay ‘B’ will be
© PMI, NTPC 123
energised thro’ normally closed contact A-5 and subsequently retains
through B-2. Relay B, which is energised will deenergise by its own contact B-3
shunting after one second. When B gets deenergised, the contact B-1 closes to
energise relay 'D'. When the relay A and D get energised, the contact A-8 & .D-5
close to energise 5 P &. 6 P relays. Now the circuit is ready for operation.
Inter phase faults
(Refer Fig.68 & Fig.69)
© PMI, NTPC 124
During inter phase faults the filter relay 'C' gets energised and any one of the
impedance relays ZA Zb Zc also gets energised. The normally closed
contact of C gets opened, deenergising A and the relay D also gets deenergised
(since contact A-4 shunts it). The contact A-8 opens to deenergise 5P
6P. The contact A-6 closes and one of the contacts ZA or ZB or ZC will also be
closed whereby energising the relay 8 p (contact 5 p will open after time lag only).
The contract of 8 p is used to trip the feeder breaker. Since relay 'D' is
deenergised, the contact D-l, closes to energise relay 'A1, Relay B gets energised
© PMI, NTPC 125
in the meantime since A-5 was closed and after ‘1’ gets deenergised and "D" gets
energised thro the contact B-1. The operation for a fault in I zone is
instantaneous.
Zone-II
On occurrence of a fault in zone-II, the relay A and D will get deenergised as also
relays 5 P & 6 P. Since this is beyond zone-I, the distance relays ZA ZB & ZC will
not pick immediately. After 5 seconds reduced voltage is applied to the relays ZA
ZB & ZC thro' contact of 5 p & 6 p i.e. the voltage to the restraining winding is
reduced.
For a fault in zone II, ZA, ZB & ZC will pickup with these reduced restraints voltage.
Now relay 8 p will get energised thro’ normally closed contact of 5 p and the
contact of the distance relay. The auxiliary contact of 8 P closes the trip circuit of
the feeder breaker.
Fault beyond zone-II
On occurrence of a fault beyond zone-II, the relays A, 5P, 6 P & D will get
deenergised, but the distance relays ZA ZB & ZC will not pick up even with the
reduced voltage applied to it restraining winding, 2 P B which gets energised at
the occurrence of fault in any zone or direction thro’ the normally open contact of
filter relay will trip feeder breaker after 2.'4" thro auxiliary relays 7 p.
A part from the distance protection, non-directional over current protection is also
provided as backup to the distance protection. The over current relays 1 T & 2 T
pick up to energise PB. The contact of PB, after 2.1" trips the feeder breaker thro’
auxiliary relay 7 P.
© PMI, NTPC 126
Directional Earth Fault Protection
This protection is provided in three steps. For a fault, if the direction of
power flow is from the bus to the line, the directional relays 1 PM pick up
and depending on the magnitude of the current, relays 3 T, 4 T or 5 T
(Ref.Fig.70)
will pickup. The directional relay contact in series with that of 3 T, 4 T or 5 T trips
the feeder breaker. If 3 T pickup, the feeder gets tripped instantaneous. If 4 T
alone pick up, relay 3 PB gets energised, v-hose aux. contact trips the feeder
breaker with a time lag of 0.6". If only 5T pickup, relay 4 PB gets energised and
the feeder breaker is tripped with a time lag of 2.1".
© PMI, NTPC 127
16. Protection And Interlock Tests
GENERAL
In previous chapters the importance of various protections and interlocks were
discussed in detail. It is not just enough to have the protection and interlocks, but it
is the responsibility of the Power Engineers to make it sure that these protections
act and protect the equipment in case of abnormalities. To ascertain that these
protections and interlocking systems are in healthy condition, it is necessary to
conduct protection and interlock tests of the boiler, turbine, generator and
associated auxiliaries at least once after every long shut down.
The conditions of the unit before conducting the test should be:
1) Unit is to be in tripped condition.
2) 6.6 KV unit-working supplies are in isolated condition and reserve supplies are
in service.
3) 415 V working supply is in service.
In order to conduct protection and interlock tests the following arrangements are to
be made:
1) Take 415 V reserve supply and switch off the 415 V working supply. Keep
interlock switch in 'off position'.
2) Trip the 6.6 KV reserve supply breakers keeping the interlock switch in 'off
position'.
© PMI, NTPC 128
3) Control and .power supplies to the breakers of individual equipment are to
available.
4) Rack out Bus PTs in 6.6 KV Switchgear.
5) Rack in the circuit breakers of all the individual equipment. Now the tests can be conducted.
The idea behind doing the above operation is:
1) During the protection and interlock test out interest is to check whether the
circuit breaker is tripping on protection or not.
2) And to check whether the reserve equipment's circuit breaker is closing on
interlock or not.
Since the equipment, for which protections and interlocks test is being carried out
should not run and we are switching off the power supply to the equipment.
Now the breakers of the individual equipment can be closed as per our requirement,
and simulate the fault conditions. Then check whether the expected result is
obtained or not. If expected result was not obtained then check for the fault in
protection circuits and they are to be rectified.
Method of conducting protection and interlock test for some of the equipment is
tabulated in the tables attached:
© PMI, NTPC 129
17. Boiler 1.
I.D. fan a (B fan ‘fan’)
1. Inlet damper
open. 2. Reg. Vane
in min position
3. Outlet damper closed.
4. Lub. Oil pres-ssure is adequate.
5. Fan and
motor bearing temps not high.
1. Make 6.6 kV
unit bus dead. 2. Take out low
voltage age protection
3. Make all the permissive.
4. Make
available L.T. Supply from Reserve
5. Close the break-er keeping it in service remote position.
Make any one of the permissive not satisfactory
1. Breaker shall close. 2. Out let damper shall
open after a time delay. 3. Connecting the
regulating vanes to the regulator.
4. Opening the interconnecting dampers.
5. Closing the inlet dampers
and the outlet damper of I.D. fan B and bringing its regulating its regulating vane to minimum position.
Breaker shall not close:
2. I.D. Fan B (A Fan ‘On’)
1. Outlet damper is closed.
2. Regulating
vane min. position
3. Inlet damper
closed. 4. Lub oil
pressure adequate.
Make the condition as in the previous case. Close the breaker.
1. Inlet damper shall open after a time delay.
2. Outlet damper shall open
after 8 time delay. 3. Compacting the
regulating vanes to the regular.
4. Closing the
interconnecting damper.
© PMI, NTPC 130
5. Fan & Motor brg. Temp. not high
Make any one of the permissive not satisfactory.
Breaker shall not close.
3.
F.D. Fan A (B fan off )
1. Either of the
I.D. fans ‘on’ 2. Control oil
pressure adequate.
3. Fan impeller
bleade to the minimum position
4. Out damper in closed position
Make all permissive satisfactory . Close the breaker Close the breaker Make any permissive not satisfactory. Close and the Breaker.
Breaker shall close. 1. Out let damper shall
open after a time delay. 2. Connecting the fan
impeller blade control drive to the regulator.
3. Opening the interconnecting dampers.
4. Closing the outlet dampers and the outlet damper of F.D. fan B to the minimum position
Breaker shall not close:
4.
Tripping of ID fan A (fan B is Off)
ID fan shall trip under tier following conditions: Fan bearing temperature temp. too high Motor bearing temp. too high Lub. Oil pr. Low with a time delay of 0-3 minutes. Air heater A &
Close ID-A breaker. Simulate the conditions one by one as per permissive and check that the breaker trips.
1. Opening the out ler
damper of ID fan B. 2. Opening the regulating
vane of ID fan B. 3. Disconnecting the
© PMI, NTPC 131
B off. Emergency push button is pressed.
regulating impales acting on regulating vane of I.D. fan opening the regulating impales acting on regulating vane of I.D. fan A.
4. Opening the regulating
vane of I.D. fan A. 5. Closing the inter-
connecting dampers. 6. Tripping the working F.D
fan and working P.A. fan.
6. F.D fan B
(A fan ‘ON’) Tripping conditions one of the ID fan trips and this fan is selected
Fan bearing too high
Fan motor bearing temp. too high.
Lub oil pressure low for more than 30 seconds
Unit trips Emergency push button is pressed
-do- 1. Tripping PA fan B if PA fan A is on and this fan is selected
2. disconnecting regulator impulse from acting on impeller blade control drive.
3. Bringing impeller blade contour derive to min. position
4. Closing the outlet damper.
5. Opening the interconnecting damper
6. Exercitation of partial load relay
© PMI, NTPC 132
7.
F.D. fan A (B fan off)
1. Tripping conditions:
fan bearing temp. too high
2. Motor bearing
temp. too high 3. Both I.D. trips and
FD-A is selected by the switch
4. Lib. Oil pr. Low for
30 seconds. 5. Emergency push
button is pressed.
Close ID-A breaker. Simulate the conditions one by one as per and see that the breaker trips.
1. Disconnecting the
impeller blade control drive from the regulator.
2. Bringing the impeller
blade control drive to the max. position
3. Bringing the impeller
of FD fan B to the max. position.
4. Opening the outlet
damper of FD fan B.
5. Open the emergency scanner air damper.
8. F.D.
fan B (A fan ‘on’)
1. Tripping conditions one of the ID fan trips and this fan is selected
2. Fan bearing too
high 3. Fan motor bearing
temp. too high. 4. Lub oil pressure
low for more than 30 seconds
5. Unit trips 6. Emergency push
button is pressed
-Do- 1. Tripping PA fan B if PA fan A is ON and this fan is selected.
2. Disconnecting regulator impulse from acting on impeller blade control drive.
3. Bringing impeller blade control drive to min. position.
4. Closing the outlet dampers.
5. Opening the inter-connect ing damper.
6. Energising of partial load relay .
© PMI, NTPC 133
1. 2. 3. 4. 5.
9. Drum Level High/Low
Condition: for Unit tripping
1. When drum level rises beyond + 200 mm
2. When drum level falls to –150 mm
Simulate the conditions by shorting the Tripping contact.
Unit trip annunciation appears.
10. Furnace draft High/Low
Conditions for unit tripping:
1. When furnace draft goes to+ 200 mm
2. When furnace vacuum goes to –200mm
Simulate the conditions shorting the contacts of Pr. Switches.
Unit trip annunciation shall appear.
© PMI, NTPC 134
18. Turbine
SL.No. Protection Causing
Operations be carried out RESULT
1.
Loss of voltage on unit Auxiliary Bus Bars.
1. Make 6.6 KV Bus dead after putting loss of voltage on unit auxiliary bus bars protection in “ON” position.
a) Boiler Lock-out relay will act. b) Turbine lock out relay acts. c) Generator lock out relay acts. d) Unit lock out relay acts.
2. Main steam temperature very low.
1. Bring the Main steam temperature indicator to 450oc.
2. Cut in the main steam temperature protection
Same as in the case of protection No.1
3. Axial shift protection
1. Cut in the axial shift protection
2. Simulate axial shift value to + 1.2 mm and –1.7 mm one by one from local.
Unit trip annunciation should appear along with the cause.
4. Low Lub oil pressure
a) Cut out links for A.C. and D.C. lub oil pumps not to start on inter lock. b) Drain the oil from oil pressure relay to read 0.3 Kg/cm2
a) Unit trip annunciation should appear along with the cause. b) BG will trip if in running condition.
5. Low vacuum in condenser
1) Put the vacuum protection in “on” position
2) Drop the vacuum in condenser vacuum relay to 540 mm.
“Unit tripped” annunciation should appear along with the cause
6. Manual tripping Operate the trip buttons from the turbine desk.
© PMI, NTPC 135
19. Generator
Testing of the boiler and turbine protection-causing unit tripping were tabulated in the
precious pages, Generator and Transformer protection can also be checked in the
similar way, AS a general rule, whenever we are testing a particular protection. all other
protection causing unit tripping should be cut off.
To test generator protection the following procedure is to be flowed.
Make the arrangements of the protection checking as explained earlier, keep the bus
and line insulators of the unit in open position. Keep the field breaker isolator in the
position, then close the field breakers, 6.6 KV working supply breaker, and generator
breakers, after satisfying the circuitry requirements, then cut in any generator protection,
on the generator, on generator transformer protection, and, make to the relay contacts
corresponding to the bottom float than working supply breaker, generator breaker and
field breakers will trip on protection, Boiler, turbine, unit lock out relay will get energized.
Cause of the unit is to be observed in the annunciation windows.
The method of the testing protection and interlocks was discussed only for the
academic interest, All the protection and interlocks should be checked only in the
pressure in the presence of the concerned Engineers.
© PMI, NTPC 136
20. Summary Of Individual Relays
This section gives a summary of the wide range of the standard protective relays and
signaling equipment that is available for the protection of the electrical plant and power
system network, the list of the relays is arranged in alphabetical order for ease of the
reference and includes all the basic designs armature, moving coil, disc, induction cup,
polarized and static.
AVB4 Automatic Voltage regulating relay.
AVC4 Automatic Voltage regulating relay with Under voltage blocking facility.
AVE4 Automatic Voltage regulating relay with under voltage blocking facility and an adjustment define time delay feature.
C10 High frequency communication system for the power line carrier.
CAA11 Series auxiliary relay with self reset contacts.
CAA12 Series auxiliary relay with self and hand reset contacts.
CAA13 Series auxiliary relay with relay with hand reset contacts.
CAD Line drop compensator for the electromagnetic voltage regulating relay.
© PMI, NTPC 137
CAEF12 Earth fault indicator with hand reset flag.
CAEF14 Earth fault indicator with the flag automatically reset on restoration of the line voltage.
CAF11 Series flag indicator relay.
CAG11 Instantaneous over current relay with fixed setting.
CAG12 Instantaneous over current relay with variable setting and low drop—off/ pick –up ratio.
CAG13 High set instantaneous over current relay with variable setting and high transient over – reach.
CAG14 High impedance differential relay with variable current setting.
CAG17 High set instantaneous over current relay with variable setting and high drop –off – pick –up ratio. Low transient over –reach.
CAG19 Instantaneous over current relay with variable setting and high drop –off /pick-up ratio low transient over –reach.
© PMI, NTPC 138
CAN Negative phase sequence relay with define time characteristic.
CATF Overhead line fault indicator.
CAU Define time over current relay.
CD4 Battery negative biasing relay.
CDAG over current relay with time delayed phase fault elements having any of the standard inverse characteristics, plus an instaneous earth fault element.
CDD21 Directional inverse time over current relay with a single contact on the disc.
CDD23 Directional very inverse time over current relay.
CDD24 Directional extremely inverse time over current relay.
CDD26 Directional externally inverse time over current relay with contacts on the disc.
© PMI, NTPC 139
CDG11 Directional time over current relay with basic inverse time operating characteristic and a single contact on the disc.
CDG12 Inverse time over current relay with long time operating characteristic.
CDG13 very inverse time over current relay.
CDG14 Extremely inverse time over current relay.
CDG16 Inverse time over current relay with basic inverse characteristic and two contacts on the disc.
CDN Negative phase sequence relay with inverse time characteristic for generator protection Electromagnetic.
CDV21 Voltage restrain inverse time over current relay.
CDV22 Voltage controlled inverse time over current relay.
C I JC Static line drop compensator time over current relay.
CMC Battery earth fault relay.
© PMI, NTPC 140
CMQ Current sensitive balanced armature relay.
CMU Sensitive earth fault relay, Define time characteristic.
CID Static directional relay.
CTG11 Static equivalent of CDC 11
CTG13 Static equivalent of CDG 13
CTG14 Static equivalent of CDG 14.
CTG 25 Silicon rectifier protection relay.
CTIG 39 Local breaker back-up with one instantaneous over current elements per – phase.
CTIG68 Local breaker back –up relay with two instantaneous over current elements per phase.
CTM Motor Protection relay.
© PMI, NTPC 141
CTN Negative phase sequence relay with inverse with time characteristic for generator protection, Static.
CTU12 Static define time over current relay.
CTU15 Static sensitive earth fault relay, Define time characteristic.
CWTG Industrial and marine generator protection.
D12 VF high speed signaling system, General purpose, frequency shift,
DBA4 Moving coil relay with variable setting and two adjustable setting.
DBB4 Moving coil relay with variable setting and two adjustable settings.
DBM4 surge –proof internship receiver relay shunt connection.
DBS4 Surge—proof inter ship receive relay with low impedance for the connection and higher surge withstand.
DDG31 Generator percentage biased differential relay.
© PMI, NTPC 142
DDGT31 Generator – transformer percentage biased differential relay.
DDT32 Transformer percentage biased differential relay.
DMH31 Two – winding transformer percentage biased differential relay with harmonic restraint.
DMV Plain feeder pilot wire circulating current relay.
DS7 Plain feeder with speed stability pilot wire relay. Private pilots
DSB7 Feeder high-speed pilot wire relay, private pilots.
DSC7 plain feeder high-speed pilot wire relay post office pilots.
DSD7 plain feeder higher speed pilot wire relay used when post office pilot are required for telephony as well.
DSE7 plain feeder higher speed moving coil pilot wire relay used on capable feeders.
DSF7 plain feeder higher speed moving coil pilot wire relay private pilots.
© PMI, NTPC 143
DTH31 Static two – winding transformer percentage biased differential relay with harmonic restraint.
DVM4 Voltage transformer supply supervision relay.
FAC14 High impedance Voltage calibrated differential relay with variable setting.
FMC11 Over frequency relay.
FMC12 Under frequency relay.
FOS24 Synchronous motor out –of –step relay.
FTG11 Static under frequency relay.
GIT Over fluxing relay.
HHTA4 Tran slay transformer feeder speed pilot wire relay.
HHTB4 Tran slay teed transformer feeder medium speed pilot wire relay.
© PMI, NTPC 144
HM4 Trans lay plain feeder medium speed pilot wire relay, without over current starting relays, post office pilots.
HMB4 Trans lay plain feeder medium speed pilot wire relay, with over current starting relay, post office pilots,
HO4 Trans lay plain feeder medium speed standard pilot wire relay.
HOA4 Trans lay plain feeder medium speed pilot wire relay with alternative setting.
HT4 trans lay pilot wire relay with adjustable time setting for use with fused tee.
K10 High frequency signaling system for the power line carrier.
MIV Mho single zone phase fault distance protection.
M3V Mho three zone phase fault distance protection.
MM3V Mho three-zone phase and earth fault distance protection.
M3T Static mho three zone phase and earth fault distance protection.
© PMI, NTPC 145
MMIT Static mho three zone phase and earth fault distance protection.
MM3T Static mho three zone phase and earth fault distance protection.
NDM Multi- stage power factor control relay.
NDO Single – stage power factor control relay.
NOP Multi Stage power factor relay with non – volt resetting feature.
NSS4 Supersensitive a.c. directional relay.
NSS5 D.C. pilots supervision relay.
OBC Gas actuated Bachholz relay.
PIO Phase comparison carrier protection.
PCD Poly phase directional relay
© PMI, NTPC 146
PDI Poly phase interlocked over current relay.
PERM programmable equipment for relaying and measurement.
R3V Reactance three zone phase fault distance protection.
RR3V Reactance three-zone phase and earth fault distance protection.
S25 Vf single channel high-speed high security frequency shift signaling system.
SS25 Vf dual channel high-speed high security high frequency shift signaling systems.
SDN Static feeder protection with optional auto – re closing.
SDA Static pilot supervision relay with capacitor.
SDB Static pilot supervision relay without capacitor.
SKA feeder check synchronizing relay.
© PMI, NTPC 147
SKB Generator check synchronizing relay.
SKC Auto –re close check synchronizing relay.
SKD Auto – re close check synchronizing relay voltage lock –out feature.
SKE Generator check synchronizing relay with phase and voltage difference adjustments.
SSM3V Switched mho three zone phase Ault protection
SSMM3V Static switched mho three zone phase and earth fault distance protection.
TTT10 Transformer oil temperature indicator with alarm and trip functions.
TTT11 Transformers winding temperature indicator with alarm and trip functions.
TTT12 transformers winding temperature indicator f with the alarm and trip functions and one cooler control.
TTT13 Transformers winding temperature indicator with alarm and trip functions, two cooler controls and with two –rate temperature differential,
© PMI, NTPC 148
VAA11 Shunt auxiliary relay self reset contacts.
VAA12 Shunt auxiliary relay with self and hand reset contacts.
VAA13 Shunt auxiliary relay with hand reset contacts.
VAA14 Shunt auxiliary relay with electrically reset contacts.
VAC Counting relay.
VAF Shunt flag indicator relay.
VAG11 A, C Under voltage or over voltage relay with a fixed setting.
VAG12 D.C. under voltage relay with variable settings.
VAG21 A.C. Under Voltage of over voltage relay with a fixed setting and high drop –off/ pick –up ratio.
VAG22 A.C. Under voltage of the over voltage relay with variable setting and high drop –off / pick—up ratio.
© PMI, NTPC 149
VADC11 A.C Control relay with electricity reset contacts.
VADS13 Low burden relay high speed tripping relay with hand reset contacts,
VAGS13 Low burden high speed tripping relay with self reset contacts.
VADX11 High speed tripping relay with electrical or hand and electrical reset contacts.
VAGY11 High speed tripping relay with electrical of hand reset contacts.
VAGZ11 High speed tripping relay with self reset contacts.
VAJZ14 Inter ship send for d.c. auxiliary supplies.
VAK13 Check alarm relay for d.c. auxiliary supplies.
VAK14 check alarm relay for a.c. auxiliary supplies.
VAK15 Check alarm relay for British Electrically Board recommended schemes.
© PMI, NTPC 150
VAM Semaphore indicator.
VAP22 Voltage selection relay.
VAP 31 Voltage selection relay.
VAR22 A Fuse failure relay.
VAR29 Auto relay National committee scheme RI.
VAR39 Auto – re close relay National Committee Scheme R2.
VAR4I M High Speed three –phase auto - re close relay.
VAR49 Auto - re close relay National Committee Scheme R3.
VAR55 A Multi relay National Committee Scheme R3.
VAR79 Auto –re close relay National Committee Scheme R4.
© PMI, NTPC 151
VAR82 Slow speed three-phase auto phase auto – re close relay, high-speed single-phase auto –re close relay.
VAR83 High speed single – phase auto –re close relay.
VAR84 High-speed single or three-phase auto – re close relay.
VAR85 High-speed single or three phase and single /three phase auto re close relay.
VAT11 Define time delay relay.
VAT14 Define time delay relay two-relay time.
VAT15 Define time relay with two –rate time.
VAT16 Define time under voltage of over voltage relay.
VAU21 Define time under voltage of over voltage relay.
VAWA Interposing relay.
© PMI, NTPC 152
VAWJ22 Low burden mult contact electricity reset relay.
VAWJ23 Inter ship send with controlled time irrespective of initiation time.
VAWJ34 Combined Send / receive non- surge proof inter ship relay with controlled send time.
VAX12 D.C. Supply failure relay.
VAX21 Trip circuit supervision relay. Monitors the trip circuit only when the circuit breaker is closed.
VAX31 Trip circuit supervision relay. Monitors the trip circuit with the circuit breaker either the open or closed positions.
VDG11 Inverse time over voltage relay.
VGD12 Inverse time neural displacement relay for the use in distribution systems.
VGD13 Inverse time voltage relay.
VGD14 Inverse time neural displacement relay for use in the generator circuits.
© PMI, NTPC 153
VDM Reverse phase and under voltage relay induction motors.
VME Rotors earth fault relay.
VTOC13 Static Voltage regulating relay with tap changer alarm supervision.
VTM Synchronous motor field application relay.
VTP Static high-speed fuse failure relay.
VTT Static high time delay relay.
VIU Static definite time delay relay.
VX Bushar supervision relay.
WCD 11 Reverse power relay.
WCD 12 Poly phase sensitive under power relay.
© PMI, NTPC 154
WCG Single –phase reverse power relay power relay with define time characteristic.
XTF32 Distance - to – fault locator.
XTFA12 Digital reader unit distance to the fault relay.
YCCF Generator asynchronous running detection relay.
YTG3 Static power zone phase or either fault distance relay.
YTO Static power swing blocking relay.
ZMC Impedance relay generator back-up protection.
ZTC High speed fault detector.
© PMI, NTPC 155
2211.. Model Session PlanModel Session Plan
Module No: IME- 01A MODULE: Power Plant Protection Duration: 1 WK
DAY Session – I Session – II Session – III Session – IV
1 Introduction to protectction philosophy
Principles of relays Maintenance, testing and commissioning aspects of relays.
Static relaying concepts and grounding
2 Main Boiler Protections Boiler Auxiliaries Protection
3 Main Turbine Protections Turbine Auxiliaries Protection
4 Protection & Interlock Testing on Boiler
Protection & Interlock Testing on turbine
Generator Protection & Interlock & their testing
5. HT/LT Motor Protection Transformer Protection Bus Bar and feeder Protection
6. Unit resetting procedure. Test and Evaluation
