Power Plant Protection (npti)

IG/ For restricted Circulation Only

POWER PLANT PROTECTION

Power Management Institute Noida

CONTENTS S.No.

DESCRIPTION

PART I

BASIC ASPECTES OF PROTECTION

1.

- Principals of Relays

1

2.

- Maintenance Testing a nd 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 PROTECTION FOR ELECTRICAL SYSTEMS& EQUIPMENTS

72

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

PART IV

PAGE NO

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.

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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.

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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.

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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

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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.

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-

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

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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.

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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

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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.

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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.

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Attracted armature relays It is required to clear the faults in power system as early as possible. Hence, highspeed 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

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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

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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.

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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

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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

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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. ensured by better maintenance.

The performance of a relay is

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

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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.

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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 maintenanceInspection: 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.

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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. singlephase 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

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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.

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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 © PMI, NTPC

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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

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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.

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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

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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

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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.

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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.

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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.

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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.

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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

31

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.

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32

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.

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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.

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35

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

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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 =

3 Vph Z1 + Z2 + Z0

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.

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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.

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c)

The flow of heavy fault current permits the use of discriminative gear. Now-adays 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 generator or transformer.

to the

full

rating

of the largest

Based on the practice, the value of resistance to be

inserted in the neutral to earth connection is decided using the following formula: R=

VL --------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

39

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.

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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:

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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.

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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 IF

© PMI, NTPC

=

3 Vph ------------Xc

43

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.

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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.

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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.

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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.

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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 peep holes etc.

man hole,

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

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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.

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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.

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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.

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6. Boiler Auxiliaries Protection

SI. No

Description

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.

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52

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

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a) If furnace temperature probe is inside the furnace and temperature exceeds 540oC it will be retracted back automatically. 53

7. Boiler Side Protection Causing Unit Tripping SI.No. 1.

Protection Description

Cause Tripping value

Loss of 6.6 KV unit auxiliary voltage 6.6 busbar voltage drops KV busbar below 50% of the rated value for a duration of about 510 Sec.

Relay to Act.

Remarks

A. Boiler lockout A. To stop all fuel input relay by tripping feeder/ Mills in service, closing the B. Turbine lockout igniter oil, warm up oil and heavy oil trip valves relay. and to trip PA fans. C. To energies turbine trips B. To close super heater, re-heater spray isolating solenoid. valve with a time delay of 0-3 minutes. D. To energies generator C. To disconnect the transformer regulator impulse on lockout relay. burner tilt mechanism

2.

Loss of 200 200 D.C supply to A. Boiler lock out Unit shutdown Volt D.C. FSSS fails. relay supply of F.S.S.S B. Unit lock out relay.

3.

Loss of fuel trip

all Loss of all fuel to the A. Boiler lock out A. To disconnect the furnace relay regulator impulse on burner till mechanism to bring the B. Unit lock out and mechanism in the relay horizontal position. B. To close super heater, reheater spray isolating valve with the time delayed 03 minutes.

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SI.No. 4.

Protection Cause Tripping value Description Flame failure

Relay to Act.

Remarks

This protection shall act A. Boiler lockout A. To disconnects the when there is no fire valve relay regulator impulse on condition at all elevations burner tilt mechanism B. Unit lock out and to bring the relay 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 This protection will act A. Boiler lock out A. Unit shutdown relay low when drum level is at – 175 mm from the normal B. Unit lock out level. relay.

6.

Drum Level This protection will act A. Boiler lock out A. Unit shutdown high when drum level is at + relay 175 mm from the normal B. Unit lock out level. relay

7.

Both ID fans Both the running ID fans A. Boiler lock out A. Both FD fans trips. trip. trips. relay B. Both PA fans trips B. Unit lock out C. Unit shutdown. relay

8.

Both ID fans Both the running ID fans A. Boiler lock out A. Both PA fans trips. trip. trips. relay B. Unit shutdown. B. Unit lock out relay

9.

Furnace pressure very high.

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This protection will act A. Boiler lock out Both PA fans trips. when furnace pressure is relay. + 175 mm of w.c. I. B. Unit lock out Unit shutdown. relay.

55

SI.No.

Protection Cause Tripping value Description

Relay to Act.

Remarks

10.

Furnace vacuum very high.

11.

Air flow less This protection will act A. Boiler lock A. Both PA fans Trips. than 30% when air flow in the out relay furnace is less than B. Unit shutdown. 30% B. Unit locks out relay.

12.

Repeater Protection 30%

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This protection will act A.Boiler lockout A. Both PA fans Trips. when furnace vacuum relay is –175 mm of w.c .1. B. Unit shutdown. B. Unit lock out relay

This protection will act A. Boiler lock A. Both PA fans trips. when there is no flow out relay through reheated and B. Unit shutdown furnace of the B. Unit lock out temperature is more relay than 530oc.

56

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

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57

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.

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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.

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59

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.

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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:

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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:

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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

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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.

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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

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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.

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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.

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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.

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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

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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.

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9. Turbine Auxiliaries SL. No.

Description

1.

Boiler feed pump

Protection 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

2.

Circulate water pump

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. 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. a) Working pump will trip if discharge assure before its NRV becomes low (10 Kg/cm2) after 30 seconds of pump starting. a) B/G will trip if labroid pressure goes to 0.3 Kg/cm2.

3.

Condensate Pump

4.

Barring gear

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.

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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 6.6 KV unit Unit Lock out relay 1. Unit shut down. on unit aux. Bus auxiliary bus bar will act. ID/fan/fans and Bar voltage drops CW pump/ pumps below 50% of the breaker will rated value for 5remain closed. 10 Sec.

2.

Vacuum drop in Condenser condenser. vacuum drops below 540 mm of Hg.

3.

Pressure drop Pressure drops Annunciation & 1. Unit shutdown of lubricating oil down to 0.3 follow-up under 2. To close the to the Turbo- Kg/cm2 a. Turbine lock out ESVs IVs & CVs. generator. relay 3. To trip barring b. Unit Lock out gear if already relay 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.

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Turbine lock out 1. Unit shut down relay will act. 2. Pre – trip alarm Unit lockout relay comes at 650mm will act. of Hg. 3. To close ESVs. And Ivs of the Turbine.

72

1.

2.

4.

Excessive axial Axial shift of shift of Turbine. Turbine rotor corres- ponds to +1.2 mm and –1.7 mm.

5.

Boiler pump

6.

Very low main Main steam temp. 1. Turbine lock steam temp. drops to 450oc out relay will act. before emergency stop valve. 2. Unit lock out relay will act.

7.

Operation electrical protection Generator Transformer unit

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4.

5.

1. Turbine lock 1. Unit shut down. out relay will act. 2. To open the shut off valve to 2. Unit locks out break the vacuum relay. 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.

feed Stepping of all Unit lockout relay Unit Will trip after boiler feed pump. will act. a time delay of 15 sec. 1. Unit trips. 2. Heater will be bypassed from feed water side, drip level in any one of the HP heaters reaches to 750 mm.

of All the electrical Unit lock out relay 1. Unit shut down. protections of will act. of generator and transformer will energies, unit lock out relay causing unit tripping.

73

1.

2.

8.

ESV and closes. Gov. pressure Kg/cm2

9.

Manual tripping

10.

7.

3.

4.

5.

IV Due to over Unit lock out relay 1. Unit will trip speed of turbine will act oil of operation of 10 turbine trip sole noid.

Unit can be Unit lockout relay 1.Unit will trip tripped manually will act. from UCB by pressing a push button & then operating the switch. Emergency 11% & 12% over a. ESV & IV Unit will trip Governor over speed. clocks. speed tripping. b. Turbine trip solenoid will act.

H.P. heater When drip level in Unit lock out relay 1. Unit will trip. level very high. the heater is 4250 will act. mm.

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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.

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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

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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.

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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

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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.

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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. protection

The

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

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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.

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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

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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.

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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

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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

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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

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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

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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)

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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.

AVR

CT 4

9.

Overloaded, Loss, of excitation, pole Shipping, Negative, sequence, Backup,

10.

Impedance.

CT 9

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

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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)

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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.

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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).

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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

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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
95

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

96

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.

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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

98

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.

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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

100

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.

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101

Sl.No

Power Transformer

Current Transformers On the Primary On the Seconside ary side

Primary

Secondary

1.

Star

Star with neutral Delta earthed.

2.

Delta

Star with neutral Star earthed

Delta

3.

Star with neutral earthed

Delta

Star

4.

Delta

Delta with earthing Star transformer on secondary.

Delta

5.

Star

Star with a Delta tertiary winding.

Delta

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

102

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 inrush 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.

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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 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

The operating coil of the relay receives fundamental component of current only. The restraining coil receives rectified sum of fundamental and harmonic component.

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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,

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105

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

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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

107

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.

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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 109

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

110

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

111

rather on the ratio of these two quantities. between

In distance relays, there is balance

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 V2 ----------I2

Or

It

V -------I

=

Z

K‘ = ---------K” K’ -----K”

=

K” ‘ - ------------K” I2

--

K” ‘ -------K” I2

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, Z

=

k’ -----------k”

= Constant

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

112

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 the voltage and

current

fixes

vector such as Z and phase angle 0 between 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

113

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.

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114

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

115

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 --- = Z = I

K ---K”

(ø – ά ) -

K” ‘ -----K” VI

If we neglect the control spring effect, K” ‘ =0

K and Z = ---- cos K”

(ø – ά )

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.

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116

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

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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 64. For

healthy

© PMI, NTPC

voltages at two

condition

no current

ends are will be

compared

as shown in the fig.

flowing thro' the

relay coil since

118

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

119

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 the

zone

comparison of

and

© PMI, NTPC

phase

protection and current

compared. When each

method, the

which

there

leaving the

is no fault the signal

result

in

relation between the current entering

continuous

zone

is sent for signal

of

protection are

alternate 1/2 cycle from

over

the

line. The

120

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 121

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 relays ‘A’ and 'B'

get

to

the

energised.

protection Relay 'A'

circuit is

will be

switched

energised

on,

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

122

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)

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123

During inter phase faults the filter relay 'C' gets impedance relays

ZA Zb

Zc

also

gets

energised

energised.

and any one of the

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

124

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.

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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 and depending

directional

relays

1 PM

pick up

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".

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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'.

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3)

Control and .power supplies to the breakers of individual equipment are to available.

4) 5)

Rack out Bus PTs in 6.6 KV Switchgear. 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:

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17. Boiler 1.

I.D. fan a (B fan ‘fan’)

1. Inlet damper 1. Make 6.6 kV open. unit bus dead.

1. Breaker shall close.

2. Reg. Vane in min position 3. Outlet damper closed. 4. Lub. Oil pres-ssure is adequate.

2. Out let damper shall open after a time delay.

5. Fan and motor bearing temps not high.

2.

I.D. Fan B (A Fan ‘On’)

2. Take out low voltage age protection 3. Make all the permissive.

4. Make available L.T. Supply from Reserve 5. Closing the inlet dampers 5. Close the and the outlet damper of break-er I.D. fan B and bringing its keeping it in regulating its regulating service vane to minimum remote position. position. Make any one of the permissive not satisfactory Breaker shall not close:

1. Outlet damper is closed.

1. Inlet damper shall open after a time delay.

2. Regulating vane min. position

2. Outlet damper shall open after 8 time delay.

3. Inlet damper Make the closed. condition as in the previous case. 4. Lub oil pressure adequate.

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3. Connecting the regulating vanes to the regulator. 4. Opening the interconnecting dampers.

Close the breaker.

3. Compacting the regulating vanes to the regular.

4. Closing the interconnecting damper.

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5. Fan & Motor Make any one of Breaker shall not close. brg. Temp. not the permissive high not satisfactory.

3.

F.D. Fan A (B fan off )

1. Either of the I.D. fans ‘on’ 2. Control oil pressure adequate.

Make all permissive satisfactory . Close the breaker

3. Fan impeller Close the bleade to breaker the minimum position 4. Out damper in closed position Make any permissive not satisfactory. Close and the Breaker.

4.

Tripping of ID fan A (fan B is Off)

Fan bearing temperature temp. too high

Close ID-A breaker.

Motor bearing temp. too high

Simulate the conditions one by one as per permissive and check that the breaker trips.

Air heater A &

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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:

1. Opening the out ler damper of ID fan B.

ID fan shall trip under tier following conditions:

Lub. Oil pr. Low with a time delay of 0-3 minutes.

Breaker shall close.

2. Opening the regulating vane of ID fan B.

3. Disconnecting the

130

B off.

regulating impales acting on regulating vane of I.D. fan opening the regulating impales acting on regulating vane of I.D. fan A.

Emergency push button is pressed.

4. Opening the regulating vane of I.D. fan A. 5. Closing the interconnecting 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

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-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.

Unit trips

5. Opening the interconnecting damper

Emergency push button is pressed

6. Exercitation of partial load relay

131

7.

1. Tripping conditions: F.D. fan bearing temp. fan A too high (B fan off) 2. Motor bearing temp. too high

Close breaker.

ID-A

Simulate the conditions one by one as per and see that the 3. Both I.D. trips and breaker trips. FD-A is selected by the switch 4. Lib. Oil pr. Low for 30 seconds. 5. Emergency push button is pressed.

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. 1. Tripping conditions -Dofan B one of the ID fan (A fan trips and this fan is ‘on’) selected 2. Fan bearing high

too

3. Fan motor bearing temp. too high. 4. Lub oil pressure low for more than 30 seconds 5. Unit trips

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 interconnect ing damper. 6. Energising of partial load relay .

6. Emergency push button is pressed

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1. 9.

2.

3.

4.

5.

Drum Condition: for Unit Simulate the conditions by Unit Level tripping shorting the Tripping annunciation High/Low contact. appears. 1. When drum level rises beyond + 200 mm

trip

2. When drum level falls to –150 mm 10.

Furnace Conditions draft tripping: High/Low

for

unit Simulate the conditions shorting the contacts of Pr. Switches.

Unit trip annunciation shall appear.

1. When furnace draft goes to+ 200 mm 2. When furnace vacuum goes to – 200mm

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18. Turbine SL.No.

Protection Causing

1.

Loss of voltage 1. Make 6.6 KV Bus dead after on unit Auxiliary putting loss of voltage on unit Bus Bars. auxiliary bus bars protection in “ON” position.

2.

Main steam 1. Bring the Main steam temperature very temperature indicator to low. 450oc. 2. Cut in the main steam Same as in the case of temperature protection protection No.1

3.

Axial protection

4.

Low Lub pressure

5.

Low vacuum in 1) Put the vacuum protection in “Unit tripped” condenser “on” position annunciation should 2) Drop the vacuum in appear along with the condenser vacuum relay to cause 540 mm.

6.

Manual tripping

© PMI, NTPC

Operations be carried out

RESULT 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.

shift 1. Cut in the axial shift Unit trip annunciation protection should appear along with 2. Simulate axial shift value to + the cause. 1.2 mm and –1.7 mm one by one from local. oil 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.

Operate the trip buttons from the turbine desk.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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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

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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.

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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,

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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.

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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.

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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.

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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.

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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.

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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.

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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.

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21. Model Session Plan Module No: IME- 01A

MODULE: Power Plant Protection

DAY

Session – I

1

Introduction protectction philosophy

2

Main Boiler Protections

Boiler Auxiliaries Protection

3

Main Turbine Protections

Turbine Auxiliaries Protection

4

Protection & Interlock Protection & Testing on Boiler Interlock Generator Protection & Interlock & Testing on their testing turbine

5.

HT/LT Motor Protection

6.

Unit resetting procedure.

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Session – II

Duration: 1 WK

to Principles of relays

Session – III

Session – IV

Maintenance, Static relaying testing and concepts and commissioning grounding aspects of relays.

Transformer Bus Bar and feeder Protection Protection Test and Evaluation

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