CONTENTS
Chapter No. Chapter 1
Topic BASIC ASPECTS OF PROTECTION
1.0
Principles of Relays
1.1
Some Some
1.2
Relaying
1.3
Functions of Protective Relaying
1.4
Terms erms
Asso Associ ciat ated ed
with with
Page No.
Prot Protec ecti tive ve
The Requirements of Protective Relaying
1.5
Classification of Relays
1.6
Oper Operat atin ing g Prin Princi cipl ples es of diff differ eren entt type types s of
1.7
Relays
1.8
Testing and Maintenance of Protective Relays Test Equipment
Chapter 2 2.1 2.2 Chapter 3
Static Relying Concepts PROTECTIVE RELAYS Introduction Characteristic Curve MOTOR PROTECTION
3.1
Overload Protection
3.2
Sing Single le
3.3
Protection
3.4
Short Circuit Protection
3.5
Stalling Protection (Lock Rotor Protection)
3.6
Differential Protection
3.7
Earth Protection
Chapter 4 4.1
Phas Ph asin ing g
Prot Protec ecti tion on
or
Unba Unbala lanc nce e
Undervoltage Protection TRANSFORMER PROTECTIONS Transformer Protections
4.2
Protection against Internal Faults
4.3
Principles of Protection System
4.4
Gas Detection
4.5
Over Heating Protection
4.6
Over Current & Earth Leakage Protection
4.7
Percentage Bias Differential Protection
4.8
Over Voltage Protection
4.9
Over Fluxing Protection
4.10
Over Differential Protection
CHAPTER 5
GENERATOR PROTECTION
5.1
Introduction
5.2
Stator Earth Faults
5.3
Rotor Earth Fault Protection
5.4
Generator Interturn Fault Protection
5.5
Gene Genera rato torr Nega Negati tive ve Phas Phase e Sequ Sequen ence ce Curr Curren entt
5.6
Protection
5.7
Generator Loss of Excitation Protection
5.8
Generator Minimum Impedance Protection
5.9
Generator Differential Protection
5.10
Generator Overall Differential Protection
5.11
Generator Reverse Power Protection
5.12
Generator Over Frequency Protection
5.13
Generator Under Frequency protection
5.14
Generator Thermal Overload Protection
Chapter 6
Generator Overvoltage Protection BUS ZONE-PROTECTION AND
LOCAL
BREAKER 6.1
BACKUP PROTECTION
6.2
Introduction
6.3
Bus Bar Protection – Requirements
6.4 6.5 Chapter 7
Types of Busbar Protection Low Impedance Scheme (Biased) Local Breaker Back-up (LBB) Protection DISTRIBUTION FEEDER PROTECTION
7.1
Introduction
7.2
Unit Protection
7.3 Chapter 8
IDMT Overcurrent & Earth Fault Protection LINE PROTECTION (DISTANCE SCHEMES)
8.1
Introduction
8.2
Measuring Characteristics
8.3
Zones of Protection
8.4
Phase
8.5
Characteristic
8.6
Additional features of Distance Relays
Chapter 9
Sequence
Comparator
for
Carrier Aided Schemes CURRENT AND VOLTAGE TRANSFORMER
9.1
Introduction
9.2
Current Transformers
9.3
Voltages Transformers
MHO
CHAPTER 5
GENERATOR PROTECTION
5.1
Introduction
5.2
Stator Earth Faults
5.3
Rotor Earth Fault Protection
5.4
Generator Interturn Fault Protection
5.5
Gene Genera rato torr Nega Negati tive ve Phas Phase e Sequ Sequen ence ce Curr Curren entt
5.6
Protection
5.7
Generator Loss of Excitation Protection
5.8
Generator Minimum Impedance Protection
5.9
Generator Differential Protection
5.10
Generator Overall Differential Protection
5.11
Generator Reverse Power Protection
5.12
Generator Over Frequency Protection
5.13
Generator Under Frequency protection
5.14
Generator Thermal Overload Protection
Chapter 6
Generator Overvoltage Protection BUS ZONE-PROTECTION AND
LOCAL
BREAKER 6.1
BACKUP PROTECTION
6.2
Introduction
6.3
Bus Bar Protection – Requirements
6.4 6.5 Chapter 7
Types of Busbar Protection Low Impedance Scheme (Biased) Local Breaker Back-up (LBB) Protection DISTRIBUTION FEEDER PROTECTION
7.1
Introduction
7.2
Unit Protection
7.3 Chapter 8
IDMT Overcurrent & Earth Fault Protection LINE PROTECTION (DISTANCE SCHEMES)
8.1
Introduction
8.2
Measuring Characteristics
8.3
Zones of Protection
8.4
Phase
8.5
Characteristic
8.6
Additional features of Distance Relays
Chapter 9
Sequence
Comparator
for
Carrier Aided Schemes CURRENT AND VOLTAGE TRANSFORMER
9.1
Introduction
9.2
Current Transformers
9.3
Voltages Transformers
MHO
Chapter 10
DIGITAL RELAYING
10.1
Introduction
10.2
PC Based Schemes for Testing Protective Relays
10.3
Testing of a Distance Relay
CHAPTER – 1
BASIC ASPECTS OF PROTECTION 1.0
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, non-availability of an auxiliary, at times, may cause total shut down of the unit, which will result in heavy loss of revenue.
So, in 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 faults and take steps to guard against the effect f these faults. Although it is possible to eliminate faults to a larger degree, by careful system design, careful insulation coordination, efficient operation and maintenance, it is obviously not possible to ensure cent percent reliability and therefore 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 thereby isolating the equipment from the fault. The basic relay circuit can be seen in Fig. No. 1.1
FIG. 1.1
1.1
Some Terms 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 protection purpose since it is not possible to measure very high currents directly, it will be
stepped down means of a current 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.
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: It is the portion of a power system protected by a given protective system.
Protective Gear: These are the apparatus, including protective relays, current/voltage transformers and ancillary equipment for use in a protective system.
Protective Relay: A relay is designed to initiate disconnection of a part of an electrical installation or to operate a warning signal, in case of a fault or other abnormal condition in the installation. A protective r3elay may include more than one unit electrical relay and accessories.
Rating: It is 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.
Resetting Value: It is value of the characteristic quantity at which the relay returns to its initial position.
Unrestricted Protection: It is a protection system which has no clearly defined zone of operation and which achieves selective operation only by time grading.
Basic Symbols: The equipments they represent are as given below: Sr. No. 1.
2.
Symbol
Equipment
Function
Circuit
Switching
Breaker
abnormal conditions, interrupt the
Isolator
fault currents. Disconnecting a part of the system from
3.
Earth switch
live
5.
under
no
and
lad
to
the
earth
after
Lighting
disconnection. Diverting the high voltage surges
Arrestor
to earth.
Current
Stepping down the current for
Transformer 6.
parts
normal
conditions. Discharging the voltage on the lines
4.
during
Voltage Transformer
measurement,
protection,
and
control. Stopping down the voltage for the purpose
of
protection,
measurement and control. 1.2
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 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 art. 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 beyond repairable condition.
• To localize 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 and service continuity.
1.3
The requirements of protective relaying
•
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 1 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.
•
Simplicity: The relay should be as simple in construction as possible. As a rule, the simple the protective scheme, less the number 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. Depending on the situation a designer should strike a balance between with the degree of protection required and economy.
1.4
Classification of Relays
1.4.1 Depending upon their principle of operation they are classified as: Electromagnetic attraction type relays: These relays operate by the virtue of a plunger being drawn into a solenoid or an armature being attracted towards the poles of an electromagnet.
Induction type Relays: In his type of relay, a metal disc or cup is allowed to rotate or move between two electro-magnets. The fields produced by the two magnets are displaced in space and phase. The torque is developed by interaction of the flux of one of the magnets and the eddy current induced into the disc/up by the other.
Thermal Relay: 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 fixed 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.
Static Relays: It employs discrete electronic components like diodes, transistors, zenners, resistors/capacitors or Integrated circuits and use electronic measuring circuits like level detectors, comparators, integraters etc. to obtain the required operating characteristics.
Moving Coil Relays: In this relay a coil is free to rotate in magnetic field of a permanent magnet. The actuating current flows through the
FIG. 1.3
coil. The torque is produced by the interaction between the field of the permanent magnet and the field of the coil.
1.4.2 Relays can be classified depending upon their application also.
•
Over voltage, over current and over over power 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 power relays: In which operation occurs when the direction of the applied power changes.
•
Distance Relays: In this type, the relay operates when the ratio of the voltage and current change beyond a specified limit.
•
Differential Relays: Operation takes place at some specific phase or magnitude difference between two or more electrical quantities.
1.4.3 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 operates after a set time lag, during which the threshold quantity of the parameter is maintained.
•
Inverse time lag Relay: This operates after a set time Lab, during which the operating quantity of the parameter is maintained above its operating threshold.
1.5
Operating Principles of different types of Relays:
1.5.1 Introduction over current and earth fault relays: These are quite commonly used relays. Schematic diagram of induction disc type relay is shown in Fig. No. 1.2
The output of the current transformer is fed to a winding (1) on the center limb of the E-shaped core, the second winding (2) on the limb
FIG. 1.4
FIG. 1.5
is connected to two windings on the poles of the E and U shaped cores. The magnetic flux across he air gap induce currents in the disc, which in conjunction with the flux produced by the lower magnet, produces a rotational torque. A magnet (3), 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. 1.3.
1.5.2 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 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 energized 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 electromagnets are used in place of coils (See Fig. 1.4.).
1.5.3 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.
FIG. 1.6
FIG. 1.7
The action of a rotating coil type is shown in the Fig. 1.5. A light rectangular coil is pivoted so that its sides lie in the gap 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 and the field of the coil (See Fig. 1.5)
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 permanent magnetic relays is shown in Fig. 1.6.
1.5.4 Attracted armature relays: It is required to clear the faults in power system as early as possible. Hence, high-speed relay operation is essential. Attracted armature relays heave a coil or an electromagnet energised by a coil. The coil is energised by the 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 actuating quantity relay.
Attracted armature relays respond to both AC and DC quantities. They are very fast in operation. Their operating time will not vary much with the amount of current. Operating time of the relay is as low as 10-15 m seconds and resetting time is as low as 30 m sec can be obtained in these relays. These relays are non-directional and are simple type of relays. Examples of attracted armature type relays are given in Fig. 1.7.
1.5.5 Time Lag Relays: These are commonly used in protection schemes as a means of time discrimination. They are also frequently used in control, delayed autoreclosing and alarm scheme to allow time for the required sequence of operations to take place, and to measure the duration of the initial condition to ensure that it 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 includes gearing, permanent magnet damping, friction, thermal means or R.C. circuits. In some cases the time lag in operation of the contacts is achieved by a separate mechanism released by a voltage operated elements. The release mechanism may be an attracted armature or solenoid and plunger. The operating time of such relay is independent of the voltage applied to 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 time delays is to delay operation
of a normally instantaneous relay by means of a device which delays the build up or decay of the flux in the operating magnet. The device consists of a copper ring (slug) around the magnet and can produce delay on pickup as well as delay on reset.
1.6
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 vigilant, 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 get 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 over load by means f 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 number 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 test 2. Commissioning test 3. Maintenance tests 4. Repair tests 5. Manufacturers tests
1.6.1 Acceptance test Acceptance tests are generally performed in presence of the customer in the laboratory or by the customer himself. These tests fall into two categories: 1.
Type tests such as High frequency disturbance, Impulse voltage test, Fast transient test etc. on new relays. These tests are carried out to
prove the design and are not recommended for normal production relays. 2.
Routine Tests like operating value check, operating characteristic on Relays which were used earlier and of proven design, requiring only minimum necessary checks.
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
•
Operating movement (disc, armature etc.) is to be checked for free movement after removing the packing pieces.
•
Do not take steel screw drivers near the permanent magnet.
1.6.2 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
Measuring insulation resistance of circuits.
Checking C.T. Ratios
Checking P.T. ratio, polarity and phasing
Conducting secondary injection test on relays.
Conducting primary injection test
Checking tripping and alarm circuits.
Stability check for balanced protections like differential/REF.
1.6.3 Maintenance Tests Maintenance tests are done in field periodically. The performance of a relay is ensured by better maintenance. Basic requirements of sensitivity, selectivity, reliability and stability can be satisfied only if the maintenance is proper.
The relay does not deteriorate by normal use; but other adverse conditions cause the deterioration. Continuous vibrations can damage the pivots or beatings. Insulation strength is reduced because of absorption of moisture; polluted atmosphere affects the relay contacts, rotating systems 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 operation by manual contact closing of relays. e) Cleaning of cover etc. 1.6.4 Maintenance Schedule: 1. Continuous Supervision: Trip circuit supervision, pilot supervision, relay, auxiliary voltage supervision, Battery supervision, CT circuit supervision. 2. Relay flags are to be checked and resetted in every shift. 3. Carrier current protection testing is to be carried out once in a week. 4. Six monthly inspections: Tripping tests, insulation resistance tests, etc. Secondary injection tests are to be carried out at least once in a year.
The following tests are to be performed during routine maintenance:
Inspection: Before the relay cover is removed, a visual check of he 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. Fogging 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 relays are designed to operate at 40 oC, a check of the ambient temperature is advisable. The voltage and current carried by the relay are to be checked with that of the name plate details.
1.6.5 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 is found gaskets are to be checked and replaced if required.
Contact gaps and pressure are to be measured and compared with the previous readings. Large variation in these measurements will indicate excessive wear, in which case worn contacts are to be replaced. Contacts alignment is to be checked for proper operation.
1.6.6 Electrical Tests and Adjustments Contact function: Manually close or open the contacts and observe that they perform their required function.
Pick up: Gradually apply actuating quantity (current or voltage) to see that pickup is within limits. Drop out or reset: Reduce the actuating quantity (current or voltage) until the relay drops out or fully resets. This test will indicate excess friction.
Repair tests involve recalibration, and are performed after major repairs. Manufacturers tests include development tests, type and routine tests.
1.7
Test Equipment
1.7.1 Primary current injection test sets: Generally protective gear is fed from a current transformer on the equipments to be protected and primary current injection testing checks all parts of the protection system by injecting the test current through the primary circuit. The primary injection tests can be carried out by means of primary injection test sets. The sets are comprising current supply unit, control unit and 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 is connected to AC single phase supply. The output is connected to primary circuit of CT. the primary current of CT can be varied by means of the test set. By using this test one can find at what value of current the relay is picking up and dropping out.
1.7.2 Secondary current injection test set: It checks the operation of the protective gear but does not check the overall system including the current transformer. Since it is a rare
FIG. 1.8
occasion for a fault to occur in CT, the secondary test is sufficient for most routine maintenance. The primary test is essential when commissioning a new installation, as it checks the entire system. A simple test circuit is given in Fig. 1.8.
1.7.3 Test Benches: Test benches comprise calibrated variable current and voltage supplies and timing devices. These benches can be conveniently used for testing relays and obtaining their characteristics.
1.8
Static Relaying Concepts
1.8.1 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 value is crossed. In simple language static relay is one in which there are no moving parts except in the output device. The static relay includes electronic devices, the output circuits of which may be electric, semiconductor or even electromagnetic. But the output device does not perform relay measurement, it is essentially a tripping device. Static relay employs electronic circuits for the purpose of relaying. The entity voltage, current etc. is rectified and measured. When the output device is triggered, the current flows in the trip circuit of the circuit breaker.
With the inventions 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.
1.8.2 Advantages of Static Relays: The static relays compared to the electromagnetic relays have many advantages and a few limitations.
1.8.3 Low Power Consumption Static relays provide less burden on CTs and PTs as compared to conventional relays. In other words, the power consumption in the measuring circuits of static relays is generally much lower than that for the electromechanical versions. The consumption of one milli-VA is quite common
in
static
over
current
relay
whereas
as
equivalent
electromechanical relay can have consumption of about 2-3 VA. Reduced consumption has the following merits. a)
CTs and PTs of less ratings are sufficient
b)
The accuracy of CTs and PTs are increased
c)
Air gaped CTs can be used
d)
Problems arising out of CT saturation are avoided
e)
Overall reduction in cost
1.8.4 Operating time The static relays do not have moving parts in their measuring circuits, hence relay times of low values 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 ratio can also be achieved.
1.8.5 Compact Static relays are compact. The use of integrated circuit have further reduced their size. Complex protection schemes may be obtained by using logic circuits or matrix. Static relays can be designed with good repeat accuracies. Number of characteristics can be obtained in a single execution, unlike in case of their Electro-mechanical counter parts.
Most of the components in static relays including the auxiliary relays in the output stage are relatively immune 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.
1.8.6 Transducers Several non-electrical quantities can be converted into electrical quantities and then fed to static relays. Amplifiers are used wherever necessary.
1.8.7 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 relays are sensitive to voltage spikes or voltage transients. Special measures are taken to overcome this difficulty. These include use of surge supressors and filter circuits in relays, use of screened cables in input circuits, use of galvanically isolated auxiliary power supplies like d.c./d.c. converters, use of isolating transformers with grounded screens for C.T./P.T. input circuits etc.
1.8.8 Temperature Dependence of Static Relays The
characteristic
of
semiconductors
are
influenced
by
ambient
temperatures. For example, the amplification factor o a transistor, the forward voltage drop of a diode etc., changes 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. (-20oC to +50oC) this difficulty is overcome by a) Individual components in circuits are used in such a way that change in characteristic of component does not affect the characteristic of the complete relay. b) Temperature compensation is provided by thermistor circuits. Extra precaution for quality control of the components has to be taken. As the failure rate is highest in early period of components life, artificial ageing of the components is normally done by heat soaking. FIG. 1.9
FIG. 1.10
1.8.9 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 restrain, or it may compare the current with another quantity of he circuit such as the bus voltage or the current leaving the protected circuit (Fig. 1.9).
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.
E.g. In the semiconductor circuit (See Fig. 1.10) the transistor is reverse biased in normal conditions. No current flows through the relay coil under fault conditions capacitor will be charged to +ve 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.
1.8.10Comparators In order to detect a fault or abnormal conditions of he 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 comparators as two or more inputs; in complex relays each input is the vectorial sum or difference of two currents or voltages of the protected circuit, which may be shifted in phase or changed in magnitude before being compared.
1.8.11Types of comparators; Basically there are two types of comparators, viz. FIG. 1.11
FIG. 1.12
FIG. 1.13
FIG. 1.14
a) Amplitude comparators, 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 the angle determining the shape of the characteristic; λ = 90 for a circular characteristic.
Both types of comparators can be arranged either for direct comparison (instantaneous) or to integrate their output over each half cycle.
Amplitude Comparators: Fig.1.11 shows how two currents can be compared in magnitude only, using rectifiers and, in fig. 1.16 two voltages are compared. In current comparator, the rectifiers providing a limiting action so that the relay can be made more sensitive, the voltage across the rectifier bridge remains substantially constant and hence the rectifiers and the sensitive relay are protected at high currents. In voltage comparator, the increase of resistance at low voltage makes the relay less sensitive at low voltage and the rectifiers are not protected at high currents.
1.8.12Circulating Current Comparator Operation: Normally the restraining current flow in the winding of the polarized 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. 1.12. FIG. 1.15
FIG. 1.16
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 the relay will rise to a value V t, the threshold voltage of bridge 1 and I will then conduct, then the current paths will be shown in Fig. 1.13. The current through the relay consists of fairly flat topped half waves as shown in Fig. 1.14.
The reverse is true if Io 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 t, 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 io is greater than ir in the Fig. 1.14.
When both bridges are energised simultaneously the relay is responsive to small differences between io and ir without requiring a sensitive output relay. The composite characteristic (ideal) for the relay is shown in Fig.1.15.
Opposed Voltage Comparator: In this voltage comparator the voltage drop in the resistance connected externally in the bridge circuits is compared. The current directions are shown in Fig. 1.16. If the two drops are equal no current will flow through the relay coil and the relay will not operate. If he two voltages are not equal then unequal currents will flow through the resistances and 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.
Phase Comparators: There are two main types of static phase comparators:
FIG. 1.17
FIG. 1.18
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 coincidence type and can be direct acting or integrating.
1.8.13Operating Principles of Static Time Current Relays: Fig. 1.17 shows the block diagram of a static time current relay. The auxiliary C.T. has taps on the primary for selecting the desire pickup and current range. Its rectified 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 smoothed by capacitor ‘Cs’ and then passed
through he tapped resistor ‘Rs’ so that the voltage across it is proportional to the secondary current. The spike filter RC protects the rectifier bridge against transient over voltages in the incoming current signal, Fig. 1.18.
1.8.14Timing Circuit The rectified voltage across the ‘Rs’ charges the capacitor ‘Ct’ through resistor ‘Rt’. When the capacitor voltage exceeds the base emitter voltage ‘Vt’ the transistor ‘T2’ in the Fig. 1.20 becomes conductive, triggering transistor ‘T3’ and operating the tripping relay.
Resetting circuit: In order that the relay shall have an instantaneous reset, the capacitor ‘Ct’ must be discharged as quickly as possible. This is achieved by the detector as follows (Fig. 1.19).
The base of the transistor ‘T1’ is normally kept sufficiently positive relative to emitter to keep it conductive and hence short circuiting the timing capacitor ‘Ct’ at YY in Fig. 1.20. When a fault occurs the over current through the resistor ‘Rs’ makes the base of ‘T1’ negative and cuts it off leaving ‘Ct’ free to be charged. When the fault is cleared the
FIG. 1.19
FIG. 1.20
current falls to zero and the negative bias on ‘T1’ disappears so that ‘Ct’ is again short circuited and discharged immediately.
A weakness of very fast instantaneous units is the tendency to over sensitivity on off-set current waves. The instantaneous unit can be made insensitive to the D.C. off set component by making the auxiliary C.T. saturate jus 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 thus entailed is acceptable with time current relaying.
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CHAPTER – 2 INDUCTION DISC TYPE IDMT OVER CURRENT RELAYS 2.1
Introduction Induction types are most widely used for protective relaying purposes involving A.C. quantities. Torque is produced in these relays when alternating flux reacts with eddy currents induced in a disc by another alternating flux of the same frequency but displaced in time and space. These relays are used as over current or earth fault relay. In its simplest form, such a relay consists of a metallic disc which is free to rotate between the poles of two electromagnets (Fig. 2.1).
The spindle of this disc carries a moving contact which bridges two fixed contacts when the disc rotates through an angle which is adjustable. By adjusting this angle the travel of the moving contact can be adjusted so that the relay can be given any desired time setting which is i ndicated by a pointer on a time setting dial. The dial is calibrated from 0 to 1. These figures do not represent the actual operating times but are multipliers to be used to convert the time known from he relay name plate curve into the actual operating time.
The upper electromagnet has a primary and a secondary winding. The primary is connected to the secondary of a C.T. in the line to be protected and is provided with tappings. These tappings are connected to a plug setting bridge which is usually arranged to give seven selections of tapping, the over current range being 50 per cent to 200 per cent in steps of 25% and the earth fault 10% to 40% or 20% to 80% in steps of 5% & 10% respectively. These values are percentages of the current rating of the relay. Thus a relay may have a current rating of 5A, indicating that it is suitable for use on CT having secondary current rating of 5A but with a setting of 50% the relay would start to operate at 2.5A. Similarly if set at 200% it would start to operate at 10A. Thus the relay can be set to pick-up at any
FIG. 2.1: NON DIRECTIONAL INDUCTION RELAY
FIG.2.2: TIME CURRENT CHRACTERISTIC OF A NON DIRECTIONAL INDUCTION DISC RELAY
Desired tapping and, therefore, current setting can be selected by inserting a pin spring-loaded jaws of the bridge type soccer at the appropriate tap value. When the pin is withdrawn for the purpose of changing the setting while the relay is in service, the relay automatically adopts a high setting, thus ensuring that the C.T. secondary is not open circuited and that the relay remains operative for faults during the process of changing the settings. The secondary winding surrounds the limbs of the lower electromagnet as well. The torque exerted on the disc is due to the interaction of eddy currents produced therein by means of the leakage flux from the upper electromagnet and the flux from the lower electromagnet: these two fluxed having a phase displacement between them.
2.2
Characteristic Curve A set of typical time current characteristic curves of his type of relay is shown in Fig. 2.2. The curve shows the relation between the operating current in terms of current setting multiplier along the x-axis and operating time in seconds along the y-axis. A current setting multiplier indicates the number of times the relay current is in excess of the current setting. The current setting multiplier is also referred to as plug setting multiplier (P.S.M.). Thus
P.S.M=
Primary Current Primary Primary Current Setting Current Primary Setting Current
Primary Current Primary Current Setting XC.T.Ratio Where, as is usually he case, the rated current of the relay is equal to the =
rated secondary current of C.T. From the figure the operating time, when current setting multiplier is 10 and he time multiplier is set at 1, is 3 seconds. This is sometimes called the basic 3/10 curve.
It is evident that at the same current setting but the time multiplier set at 0.8, the time of operation is 2.4 seconds. Thus o get the actual tie of operation against any particular time multiplier setting, multiply the time of operation of the basic curve by the multiplier
FIG. 2.3
setting. Thus in this example the time of operation is 3 x 0.8 = 2.4 secs.
The time current characteristics of Fig. 2.2 are the inverse definite minimum time (I.D.M.T.) type since the time of operation is approximately inversely proportional to smaller values of current and tends to a definite minimum time as the current increases above 10 times the setting current.
The D.M.T. characteristic is obtained by saturating the iron in the upper magnet so that there is practically no increase in flux after current has reached a certain value. This results in the flattening out of the current time curve.
Example:
An I.D.M.T. over current relay has a current setting of 150%
and had a time multiplier setting of 0.5. The relay is connected in the circuit through a C.T. having ratio 500:5 amps. Calculate the time of operation of the relay if the circuit carries a fault current of 6000 A. the relay characteristic is shown in Fig. 2.3.
5
Solution: Sec fault current 6000 500 x
= 60A
Actual Current in Relay
Plug Setting multiplier (P.S.M.) = Setting Current
Time from graph against this multiplier of 8 = 3.15 sec. Operating time = 3.15 x 0.5 = 1.575 sec.
-oOo-
60 5 x=1.5
=8
CHAPTER – 3 MOTOR PROTECTION Electrical Motor is an important component of an industry. Squirrel cage induction motor is most widely used in power stations and industries. To protect the motor from different faults condition various protection are provided, which are as listed below.
3.1
Overload Protection A motor may get overloaded during its operation because of excessive mechanical load; (b) Single phase; (c) Bearing fault. An overloaded motor draws overcurrent overcurrent resulting resulting in overheati overheating ng of the winding winding insulatio insulation. n. A reasonable degree of overload protection can be provided by Bi-metallic thermal overload relay with setting, 15% for continuously rated motor and 40% 40% for for larg large e moto motors rs.. Mode Modern rn Moto Motorr Prot Protec ecti tion on Rela Relays ys prov provid ide e a I2 sensit sensitive ive Therma Thermall overlo overload ad protec protectio tion n having having a range range of expone exponenti ntial al curr curren ent/ t/ti time me
char charac acte teri rist stic ics s
to
matc match h
with with
the the
ther therma mall
with withst stan and d
characteristic of motor.
3.2 3.2
Sing Single le Phas Phasin ing g Prot Protec ecti tion on or Unbal Unbalan ance ce Pro Protec tecti tion on When one of the supply fuse of a 3 phase motor blows off or a terminal connection comes out, single phasing at the motor may occur. In such case, motor may continue to rotate, but the two healthy phases may draw high current leading to thermal stress on the insulation.
Besides, the Negative Phase sequence (I2) component of the unbalanced current, produces a reverse reaction field which cuts the Rotor iron and windin winding g at approx approxima imatel tely y double double the speed, speed, thereb thereby y induci inducing ng double double frequency eddy currents, causing over heating of the rotor.
I2 based single phasing protection having Inverse or definite time delay is used to protect he motor against his eventuality. For small L.T. Motors, single phasing preventor (unbalanced voltage V2 or current I2 based) is used to detect single phasing and isolate the defaulting Motor.
3.3 3.3
Short Ci Circuit Pr Protect ection A short circuit in the winding or at the terminals of a motor, results in overcurrent and thus overheating/damage to the winding insulation.
An instantaneous high set over current relay with a setting sufficiently above the starting/locked Rotor current is used for this protection.
For contactor controlled motors (usually L.T.Motors of small ratings), the short short circui circuitt protec protectio tion n is provid provided ed by the backup backup fuse fuse in view view of the limited break rating of the contactor.
3.4 3.4
Stal Stalli ling ng Prot Protec ectio tion n (Loc (Lock k Ro Rotor tor Prote Protect ctio ion) n) A motor may stall during its operation because of excessive mechanical load resulting in overloading of the motor. A definite time over current relay, with a setting of 1.5–2 times the Motor rated current, is used to protect the Motor against stalling condition. The time delay set, is usually above the Acceleration time and below the stall withstand time.
For high high inerti inertia a motors motors,, having having safe safe stall stall withst withstand and time time less less than than the starting time, the stalling protection is required to be controlled by a speed switch, mounted on the Motor shaft. During normal acceleration, the speed switch switch opens opens to disable the stalling stalling protection, protection, whereas during a genuine genuine condition the speed switch remains closed, thereby enabling he stalling protec protectio tion n and discon disconnec nects ts the defaul defaultin ting g Motor Motor within within the safe safe stall stall withstand time.
3.5 3.5
Differen rential Pr Protec otecti tio on To protect the motor against internal faults, differential protection based on circul circulat ating ing curren currentt princi principle ple provid provided ed for large large critic critical al motors motors.. The differential protection requires C.Ts of identical ratio and ratings (Class PS) on both line and neutral side of the Motor for each phase (i.e. 6 C.Ts in total). The differential relay is usually of high impedance type.
3.6 3.6
Earth Fault Protec otecti tion on A motor motor may suffer suffer an earth fault because because of damage damage to the winding winding insulation. Earth fault may occur in the connecting cable also. Usually two types of earth fault protections are i n vogue. a) Residually Residually connec connected ted earth earth fault protec protection tion with with a setting setting of 10% or or above. above. No time delay is required except on contactor controlled motors where it is necessary to prevent earth fault element over riding the fuse, for infeeds above the break rating of the contactor. The relay is, however, required to
be used with a series stabilising resistor which impedes any unbalance curr curren entt prod produc uced ed due due to uneq unequa uall erro errors rs in he CTs CTs duri during ng star starti ting ng transients. b) C.B.C. C.B.C.T. T. operate operated d earth fault fault relay with with a settin setting g of typica typically lly 1%, where where low earth faults are expected, requiring very high sensitivity.
3.7 3.7
Underv ervoltage tage Protec otecti tio on A reduced supply to a motor will increase motor losses and overloading of he winding. An IDMT or definite time under voltage relay operated off Bus P.T. is used to protect the motor, the under voltage relay trips the motors connected to the Bus on upstream supply failure and eliminates possibility of co-i co-inc ncid iden entt star starti ting ng of all all moto motors rs toge togeth ther er,, when when the the supp supply ly is subsequently restored. Thus, prevents stressing of the supply source.
Composite Motors Protection Relays (Conventional analog types) provide following protection functions. a)
Therma rmal ov overload (A (Alar larm/Trip) ip) – I TH TH
b)
Short circuit (ISC)
c)
Single Phasing (I2)
d)
Earth Fault (Io)
e)
Stalling (IIt)
Numerical versions are now available which offer following additional protection functions, besides those given above. f)
Prolonged starting time
g)
Too many start
h)
Loss of load
The Numerical versions have data acquisition acquisition capabiliti capabilities es and provide provide useful service Data (such as load currents, I2/Io content in load current, thermal status etc.), historic data fault data on operation. These relays have programmable settings, programmable output relays and continuous self monitoring against any internal failures.
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CHAPTER – 4 TRANSFORMER PROTECTIONS 4.1
Transformer protections are provided a) Against effects of faults in the system to which the transformer is connected. b) Against effects of faults arising in the transformer itself.
4.1.2 Protections against faults in the System a) Short Circuits b) High Voltage, high frequency disturbance c) Pure Earth Faults.
4.1.3 System Short Circuits A short circuit may occur across any to phases (phase to phase) or between any one line and earth neutral (phase to earth). The effect is excessive over current and electro-magnetic stresses proportional to square of short circuit current. For these type of faults additional reactance and additional bracing of the transformer winding and end leads is resorted to. This reactance may be incorporated in the design itself or separate series reactance with primary of transformer is provided.
4.1.4 High Voltage High frequency surges: These surges may be due to arching grounds, switching operation surges or atmospheric disturbances. These surges have very high amplitudes, steep wave front currents and high frequencies. Because of this, the breakdowns of the transformer turns adjacent to line terminals occurs causing short circuit between the turns.
To take care of this, the transformer winding is to be designed to withstand the impulse surge voltages as specified below and then protect it by surge divertors.
System Voltage KV
Impulse voltage withstand level (Peak
(RMS)
value) 60 KV
7.2 KV 12.5 KV
75 KV
33 KV
170 KV
66 KV
250 KV
145 KV
550 KV
245 KV
900 KV
400 KV
1350 KV
Surge divertors are provided from each line to earth. These consist of several spark gaps in series with a non-linear resistance. This spark gap breakdown when surge reaches the divertor and disturbance is discharged to earth through nonlinear resistance since at high voltage divertors resistance is low. These surge divertors should have rapid response, nonlinear characteristics, high thermal capacity, high system flow current interrupting capacity and consistent characteristics under all conditions.
4.1.5 System Earth Faults a) When neutral of the system is earthed: - It represents short circuit across the phase. Hence, same protection as for short circuit can be provided. b) When neutral is not earthed: - Surge divertor gears in front of transformer is used.
4.2
Protection against Internal Faults a) Electrical faults which cause serious immediate damage but are detectable by unbalance of current or voltage. i)
Phase to Earth Fault or phase to phase faults on HV and LV external terminals
ii)
Phase to earth faults or phase to phase faults on HV & LV
winding. iii)
Short circuit between turns on HV & LV winding (inter turn faults)
iv)
Earth faults on tertiary winding or short circuit between turn of tertiary winding.
v)
Problem in tap changer gear.
b) Incipient faults: These are initially minor but subsequently develops itself resulting into damage to the transformer. These may be due to – i)
Poor electrical connection of conductors due to breakdown of insulation of
laminations, core bolt faults, clampings, rings etc.
ii)
Coolant failure
iii)
Blocked oil flow causing local hot spot on winding.
iv)
Continuous uneven load sharing between transformers in parallel causing
4.3
overheating due to circulating current.
Principles of Protection System Principles used are – i)
Overheating
ii)
Over current
iii)
Un-restricted earth faults
iv)
Restricted earth-faults
v)
Percentage bias differential protection
vi)
Gas detection due to incipient faults
vii)
Over fluxing
viii)
Tank earth current detection
ix)
Over voltage
x)
Tap changer problems.
4.4
Gas Detection a) Buchholz relay protection b) Pressure relief valves/switches (for heavy internal faults)
4.4.1 Buchholz Protection This is for two types of faults inside the transformer. a) For incipient faults because of – i)
Core bolt insulation failure
ii)
Short circuit in laminations
iii) Local over heating because of clogging of oil iv) Excess ingress of air in oil system v) Loss of oil due to heavy leakage vi) Uneven load sharing between two transformers in parallel causing overheating due to circulating current. These generate gases causing operation of upper float and energises the alarm circuits.
b) For serious faults inside the transformer due to – i)
Short circuit between phases
ii) Winding earth faults iii) Puncture on bushing iv) Tap changer problems
These types of faults are of serious nature and operate both the floats provided in the buchholz relay and trip out the transformer.
4.4.2 Principles of Buchholz Relay Operation (Fig. 4.1) This relay is provided in the connecting pipe from transformer tank to conservator. Two floats are provided inside the relay and are connected to mercury switches. Normally the relay is full of oil and in case of gas collection the floats due to their buyopancy rotate on their supports until they engage their respective stops. Initially fault develops slowly and heat is produced locally which begins to decompose solid or liquid insulating material and thus produce inflammable gases. Gas bubbles are collected in relay causing oil level to lower down. The upper float rotates as he oil level in the relay goes down and when sufficient oil id displaced the mercury switch contacts close and initiates alarm. For serious faults as described above, gas generation is more violent and the oil displaced by gas bubbles flows through connecting pipe to conservator. This abnormal flow of oil causes deflection of both float and trip out the transformer. Recently the dissolved gas analysis technique (gas chromatography) is in use for predetection of type of slowly developing faults inside the transformer which helps to decide whether the transformer maintenance/internal inspection is required to be
FIG. 4.1
CIRCUIT DIAGRAM OF BUCHHOLZ RELAY
carried out or otherwise, and thus helps to predict transformer damage in future.
4.4.3 Dissolved Gas Analysis The inflammable gases dissolved in the transformer oil are mainly hydrocarbon gases (methane CH4, Ethane C2H6, Ethylene C2H4. Acetylene C2H2, Propane, hydrogen, carbon monoxide and carbon dioxide). With the help of dissolved gas analysis equipment the concentration of these gases in PPM can be known and can be cross checked with the IS standard. Also with the help of Roger’s ratio method, the type of probable incipient fault can be judged and corrective action can be taken in advance to prevent failure of the transformer (Ref. Annex.1 &II).
4.5
Over Heating Protection Protection is mainly required for continuous over load of the transformer.
a) Protection is based on measurement of winding temperature which is measured by thermal image technique. b) Thermal sensing element is placed in small pocket located near the top transformer tank in the hot oil. A small heater fed fro a current transformer (winding temp. C.T.) in the lower voltage terminal of one phase, is also located in this pocket and produces a local temp. rise, similar to that of main winding and proportional to copper losses, above general temp. of oil. c) Winding temperature high alarm/rip is provided through mercury switches in the winding temp. indicators. d) By thermo-meters, mercury switches heat sensing silicon resistance are also used for sensing the temp. rise. e) Thermisters are provided manly in the dry type transformers for temperature sensing. Temperature of 55o above ambient of 50oC is generally provided for tripping.
4.6
Over Current & Earth leakage protection
4.6.1 Earth Leakage Protection In case of transformer earthed through resistance or earthed through impedance. Resistance Grounding: The earth fault current in faulty winding in resistance grounded transformer depends on voltage between neutral and fault point and is inversely proportional to neutral resistance.
Iy =
10kv x p Sq. root of 3.Rn
Where Iy is earth fault current; P= percentage of winding to be protected; KV – line to line voltage and Rn = Neutral Grounding resistance. Suitable earth fault relay can be provided across C.T. in the neutral of the transformer depending upon the minimum earth fault current to be detected.
Impedance Grounding; Transformer neutral is connected to the primary of neutral grounding transformer. The suitable resistance is connected in parallel with the secondary of this neutral grounding transformer. The earth fault relay (neutral displacement relay) is connected across this resistance. The earth fault relay can be set at about 2.5 percent of maximum neutral voltage. The relay is time delayed for transient free operation.
4.6.2 Over current protection i) HRC fuses are provided for small distribution transformer. ii) Over current relays are used for power transformers, considering the following: a) IDMT relays should be chosen b) Discrimination with circuit protection of secondary side should be provided; c) Instantaneous trip facility for high speed clearance of terminals short circuit should be provided. d) Setting
depends on transformer
reactance or percentage
impedance, faults MVA, type of relay used. e) Setting of over current relays can be slightly higher than rated – full
load
current
(say 120
percent
of
FL)
with
proper
discrimination.
4.6.3 Combined over current and un-restricted E/F Protection (Ref. Fig. 4.2) a) Typical over current/earth fault protection is shown for a Delta/ start transformer in Fig. 4.2. b) IDMT O/C elements on delta and star side, primarily serve as back up protection against downstream short circuits and are time co-ordinated with downstream O/C protections. c) The high set instantaneous O/C elements on Delta side (connected to source) are provided to detect severe terminal short circuits and quickly isolate the transformer. These are set over and above the maximum short circuit current infeeds of the transformer for star side faults. d) The start side earth fault protection (IDMT) serves as a backup against downstream earth faults and is required to be suitably time graded. This can either be residually connected across the phase C.Ts or operated off a C.T. in the Neutral Earth connection (standby earth fault relay). The latter is considered to be advantageous since it can detect star winding earth faults, beside providing backup for downstream earth faults. Since the neutral C.T. ratio is not tied up with the load current, a lower C.T. ratio consistent with the maximum E/F current limited by NGR can be provided. This renders good sensitivity for the standby E/F protection. e) The E/F protection on delta side is inherently restricted to delta winding earth faults and does not respond to earth faults on the star side, due
to zero sequence isolation provided by the delta connection. The delta side E/F protection, therefore, assumes the form of REF
FIG. 4.2: COMBINED 0/C AND E/F PROTECTION CKT
FIG. 4.3: RESTRICTED E/F PROTECTION CKT
protection, enabling sensitive setting and instantaneous operation. The relay is connected in high impedance mode with a series stabilizing resistor, as shown.
4.6.4 Restricted Earth Fault Protection: (Ref. Fig. 4.3) a)
REF protection is used to supplement the differential protection, particularly here star neutral of the transformer is grounded through a neutral rounding resistor to limit the earth fault current. REF protection provides increased coverage to the star winding against earth faults.
b) The REF protection operates on the principle of Kirchoff’s law and requires CTs of identical ratio and ratings as the phases and neutral earth
connection.
The
relay
is
connected
across
the
parallel
combination of the CTs in High Impedance mode.
c)
For external earth fault, the associated CTs have dissimilar polarities forming a series connection. Thus, the resulting current through the relay is negligible. For internal fault, however, the CTs have similar polarities, forming a parallel connection, thus adding up the current in the relay branch. This ensures positive operation of the relay.
4.7
Percentage Bias Differential Protection a) In this protection, operating current is a function of differential current. b) The value of restraining current depends on 2nd and 5th harmonic component of differential current during magnetic inrush and over excited operation. c) Bias current is a function of through current (external fault current) and stabilizes the relays against heavy external fault.
4.7.1 Basic Consideration for differential protection a) Transformer ratio: the current transformers should match to the rated currents of the primary windings.
b) Transformer Connection: In delta star connected transformer, the phase shift of 30oC between primary and secondary side current exist. Also zero sequence current flowing on the star side will not produce the reflected current in the delta on the other side. To eliminate zero sequence component on star side the current transformer must be connected in delta and the current transformer of delta side must be connected in start.
c) For star / star transformer CTs on both sides should be connected in delta.
d) In order that secondary currents from two groups of CTs may have the same magnitude (i.e. primary side CTs and secondary side CTs). The ratio of star connected CTs if 5 Amp, then those of delta connected group may be 5 / Sq. Root of 3 = 2.89 Amps. e) The operating current is a appropriate percentage of reflected through fault current in the restraining (bias) coils and the ratio is termed as percentage slope.
f)
Operating coil is provided with vectors sum of the currents in the transformer windings and the bias coil sees the average scaler sum of the reflected through fault current. Spill current required to operate the relay is expressed as percentage of through current.
g) The relay is also provided with an unrestrained differential high set, to protect against heavy faults which are enough to saturate the line current transformers. The setting of this high set unit is kept above the maximum in rush current magnitude. This will operate in typically one cycle for heavy internal faults.
4.7.2 Operating Principles for Internal fault & external faults During external fault condition (through fault) (Fig. 4.4): Current in pilot wires would pass through whole of bias coils and only out of balance current due to mis-match caused by OLTC and C.T. errors
FIG. 4.4
FIG. 4.5
Would flow through operating coil. Under this condition biasing effect predominates and prevents the relay operation.
During internal faults: (Fig. 4.5) In this case, the reflected current flows through only one half of bias coil and the operating coil and back to CT neutral connection. Here the operating quantity pre-dominates resulting into operation of the relay.
4.8
Over Voltage Protection a) Two stage protection is provided b) The delayed trip is set at 110 percent of the rated voltage with two second time delay (typical). c) Instantaneous setting is kept at 115 – 120 percent of the rated voltage d) During voltage fluctuations the AVR (Automatic Voltage Regulator) will take care to avoid over voltage condition if fluctuations are within its operating limits (for Generator step-up transformer).
4.9
Over Fluxing Protection a) This protection is commonly used for Generator Transformers and large inter connecting transformers in the Grid.
b) This condition arises during abnormal operating conditions i.e. heavy voltage fluctuations at lower frequency conditions. This condition is experienced by the transformer during heavy power swings, cascade tripping of the generator sets and HT line in the Grid, interstate system separation conditions and due to AVR malfunctioning during start-up or shutting down in case of Generator Transformers.
c)
The power frequency over voltage cause both stress on insulation and proportionate increase in the magnetizing flux inside the transformer due to which the iron losses area increased and the core bolts get maximum component of flux, thereby rapidly heating and damaging its own insulation and coil insulation. Reduction in frequency during high voltage fluctuation has the same effect.
FIG. NO. 4.6
d) Transformer should be isolated within one or two minutes or as recommended by the manufacturer.
e) The core flux φ α V/f where V – impressed voltage and f – frequency. He index of over fluxing is, therefore, V/f. Over fluxing relays having variable V/f setting and time delays are used for this protection.
4.10
Overall Differential Protection a)
This is provided for complete protection of generator and generator transformer and as such is a compound overall differential protection.
b)
In addition to normal differential protection of generator, overall biased differential protection relay is connected to protect the unit as shown in Fig. 4.6.
c)
20% pickup and 20% bias setting is provided. (The values are typical).
d)
This is a supplementary protection for individual differential protection of the generator.
e)
Unit auxiliary transformers are provided with separate differential protection
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ANNEXURE – I
PERMISSIBLE CONCENTRATIONS OF DISSOLVED GASES IN THE OIL OF HEALTHY TRANSFORMER (TRANSFORMERS UNION AG)
Gas
4-10 years in
More than 10
Hydrogen Methane Acetylene Ethylene Ethane Carbon
Year in service 100/150 ppm 50/70 ppm 20/30 ppm 100/150 ppm 30/40 ppm 200/300 ppm
service 200/300 ppm 100/150 ppm 30/50 ppm 150/200 ppm 100/150 ppm 400/500 ppm
Years in service 200/300 ppm 200/300 ppm 100/150 ppm 200/300 ppm 800/1000 ppm 600/700 ppm
monoxide Carbon
3000/3500 ppm
4000/5000 ppm
9000/12000
dioxide
Less than four
ppm
ANNEXURE – II CODE FOR EXAMINING ANALYSIS OF GAS DISSOLVED IN MINERAL OIL AS PER CBIP TECHNICAL REPORT 62.
Ratio of Characteristic gases 0.1
Case No. 0 1
Code of Range ratio C2H2 CH4 C2H4 C2H4 C2H6 H2 0 1 0
0.1-1
1
0
0
1-3
1
2
1
3
2
2
2
0 0
0 1
0 0
Characteristic fault No fault Partial discharge
Typical Example Normal ageing Discharge in gas-filled cavities
of low energy
but not
r esulting
fro m
incomplete
density
signify-
impregnation, or super-saturation
2
Partial discharge of
cant 1
1
0
or cavita-tion or high humidity. As above, but leading to cracking
3
high energy density Discharge of low
1-2
0
1-2
or perforation of solid insulation Continuous sparking in oil
energy
between
bad
connections
of
different potential. Breakdown of 4
Discharges of high
1
0
2
energy
oil between solid materials. Discharges with power
flow
through. Arcing-breakdown of oil between
winding
or
coils
or
between coils to earth. Selector 5
Thermal fault of low
0
0
1
temperature
breaking current. General insulated
conductor
overheating
o
6
(150 C) Thermal fault of low temperature range
0
2
0
Local overheating of the core due to
concentr ations
of
flux,
150o-300oC
increasing hot sot temperature varying from small spots in core,
7
Thermal fault of
0
2
1
medium
eddy
temperature range o
shorting links in core. Overheating of copper due to currents,
bad
contacts/
joints (pyrolitic carbon formation)
o
300 -700 C
upto core and tank circulating current.
8
Thermal fault of
0
2
2
- do -
high temperature 150o-300oC
CHAPTER – 5 GENERATOR PROTECTIONS 5.1
Introduction Generation are designed to run at a high load factor for a large number of years and permit certain incidences of abnormal working conditions. The machine and its auxiliaries are supervised by monitoring devices to keep the incidences of abnormal working conditions down to a minimum. Despite of this monitoring, electrical and mechanical faults may occur, and the generators must be provided with protective relays, which in case of a fault, quickly initiate a disconnection of the machine from the system and, if necessary, initiate a complete shut-down of the machine.
The following are the various types of protections provided for a 200/210 MW Generator. 1.
Stator ground (earth) fault protection a) 95% stator ground fault protection b) 100% stator ground fault protection
2.
Rotor earth fault protection a) First rotor earth fault protection b) Second rotor earth fault protection
3.
Generator Interturn fault protection
4.
Generator Negative phase sequence protection
5.
Generator Loss of excitation protection
6.
Generator Minimum Impedance (MHO backup) protection
7.
Generator Differential protection
8.
Generator Overall differential protection
9.
Generator Reverse power protection
10.
Generator Over frequency protection
11.
Generator Under frequency protection
12.
Generator Thermal overload protection
13.
Generator Over voltage protection
14.
Generator out of sep (Pole slipping) protection
FIG. 5.1
FIG. 5.2
FIG. 5.3 5.2
Stator Earth Faults: In most countries, it is a common practice to ground the generator neutral through a Grounding Transformer having a loading resistor across its secondary. This method of earthing is called High Impedance earthing where the earth fault current is limited to 5–10 Amps. Tuned reactor which limit the ground fault current to less than 1.0A are also used.
The generator grounding resistor normally limits the neutral voltage transmitted from the high voltage side of the unit transformer in case of a ground fault on the H.V. side to maximum 2-3% of rated generator phase voltage.
Short circuits between the stator winding in the slots and the stator core are the most common electrical fault in Generators. Interturn faults, which normally are difficult to detect, will quickly develop into a ground fault and will be tripped by the stator ground fault protection.
5.2.1
95% Stator Ground fault Relay for Generator (Fig.5.1) For generators with unit transformer and with high impedance grounding of the neutral, a neutral voltage relay with harmonic immunity and independent time delay is used. The relay is normally set to operate at 5% of maximum neutral voltage with a time delay of 0.3 – 0.5 second. With this voltage setting, it protects approximately 95% of he Stator winding.
It also covers the generator bus, the low voltage winding of the unit transformer and the high voltage winding of the unit aux. Transformer.
Relay details: 64 A / B - Neutral Displacement Relay having IDMT or definite time characteristic.
5.2.2 100% Stator Ground fault protection for Generator Ground faults caused by mechanical damage may occur close to the generator neutral. Today there is a distinct trend towards providing ground fault protection for the entire stator winding (100% stator ground fault protection).
The principle diagram of the relay is shown in Fig. 5.2. The 100% stator ground fault scheme includes a 95% unit (1), which covers the stator winding from 5% of the neutral and a 3rd harmonic voltage measuring unit (2) which protects the rest of the stator winding. For generators with 3rd harmonic voltage less than 1%, a filter is available with a damping factor of more than 100.
When the generator is running and here is no ground fault near the neutral, the third harmonic voltage unit (2) and the voltage check unit (4) are both activated and the relay contact used in alarm/trip circuit is open. If a round fault occurs close to the generator neutral, the third harmonic voltage unit will reset, operating relay contact will close and alarm or tripping is obtained.
The voltage check unit is included to prevent faulty operation of the relay at generator standstill or during the machine running up or running down period.
Generators which produce more than 1% third harmonic voltage under all service conditions, can have the entire stator winding up to and including the neutral point protected by the 100% stator ground fault relay.
5.3
Rotor Earth Fault Protection (64R1/64R2): The field circuit of generator (i.e. rotor winding) is a isolated D.C. circuit and not earthed anywhere. The field circuit can be exposed to abnormal mechanical or thermal stresses due to vibrations, excessive currents or choked cooling medium flow. This may result in a breakdown of the insulation between the field winding and the rotor iron at one point where the stress has been too high.
A single earth fault in the field winding or its associated circuits, therefore, gives rise to a negligible fault current and does not represent any immediate danger. If, however a second ground fault should occur, heavy fault current and severe mechanical unbalance may quickly arise and lead to serious damage. It is essential therefore that any occurrence of insulation failure is discovered and that the machine is taken out of service as soon as possible. Normally the machine is tripped instantly on occurrence of second rotor earth fault. Three methods are available to detect this type of faults – (First Rotor earth fault protection) 64R1. a) Potentiometer method b) A.C. injection method c) D.C. injection method
5.3.1
Potentiometer Method (Fig. 5.3) In this scheme, a center tapped resistor is connected in parallel with the main field winding as shown in Fig. 5.3. The center point of the resistor is connected to earth through a voltage relay. An earth fault on the field winding will produce a voltage across the relay. The maximum voltage occurring for faults at the ends of the winding.
A ‘blind spot’ exists at the center of the field winding, this point being at a potential equal to that of the tapping point on the potentiometer. To avoid a fault at this location remaining undetected, the tapping point on the potentiometer is varied by a push button or switch. It is essential that station instructions be issued to make certain that the blind spot is checked at least once per shift. The scheme is simple in that no auxiliary supply is needed. A relay with a setting 5% of the exciter voltage is adequate. The potentiometer will dissipate about 60 volts.
5.3.2 A.C. Injection Method (Fig. 5.4) This scheme is shown in Fig. 5.4. It comprises of an auxiliary supply transformer, the secondary of which is connected between earth and one side of he field circuit through an interposed capacitor and a relay coil.
The field circuit is subjected to an alternating potential at the same level through out, so that an earth fault anywhere in the field system will give rise to a current which is detected by the relay. The capacitor limits the magnitude of the current and blocks the normal field voltage, preventing the discharge of a large direct current through the transformer. FIG. 5.4
FIG. 5.5
This scheme has an advantage over the potentiometer method in that there is no blind spot in the supervision of the field system. It has the disadvantage that some current will flow to earth continuously through the capacitance of the field winding. This current may flow through the machine bearings, causing erosion of the bearing surface. It is a common practice to insulate the bearings and to provide an earthing brush for the shaft, and if this is done the capacitance current would be harmless.
5.3.3 D.C. Injection Method (Fig. 5.5) The capacitance current objection to the a.c. injection scheme is overcome by rectifying the injection voltage as shown in Fig. 5.5. The d.c. out put of a transformer rectifier power unit is arranged to bias the positive side of the field circuit to a negative voltage relative to earth. The negative side of the field system is at a greater negative voltage to earth, so an earth fault at any point in the field winding will cause current to flow through the power unit. The current is limited by including a high resistance in the circuit and a sensitive relay is used to detect the current.
The fault current varies with fault position, but this is not detrimental provided the relay can detect the minimum fault current and withstand the maximum.
The relay must have enough resistance to limit the fault current to a harmless value and be sufficiently sensitive to respond to a fault which at the low injection voltage may have a fairly high resistance. The relay must not be so sensitive as to operate with the normal insulation leakage current, taking into account of the high voltage to earth at the negative end of the winding and any over voltage due to field forcing and so on.
5.3.4 (a) Second Rotor Earth Fault Protection 64R2 (Fig. 5.5 a) In this test system is replaced by a replica field system in the form of potential divider, two 1K potentiometers in parallel with station D.C. is used as shown in Figure 5.5 (a) with SW1 at 1st rotor E/F position. Close switch S1 check that 1st rotor E/F relay VAEM (64R1) operated.
FIG. 5.5 a
FIG. 5.5 b
Shift SW1 to Balance. Obtain balance on the mA meter (Galvanometers) by coarse / fine adjustment of potentiometer. Shift SW1 on “Test” position, check check operat operation ion of relay relay 64R2 64R2 by closin closing g switch switch S2 thus thus creati creating ng an unbalance which simulates second E/F.
5.3. 5.3.4 4 (b) (b) Rotor Rotor Ear Earth th Faul Fault t (Fig. (Fig. 5.5.b) The Scheme to detect Rotor Earth Fault in case of Brushless excitation system is shown in Fig. 5.5.(b). 5.5.(b). In this case, Rotor Earth Fault relay forms the the thre three e arms arms of a brid bridge ge whos whose e four fourth th arm arm is the the fiel field d wind windin ing g capacitan capacitance ce o Rotor Rotor body. body. During Rotor earth fault, fault, this capacitance capacitance gets shorted shorted and the bridge bridge becomes becomes unbalanced unbalanced operating operating the relay. relay. Main exciter winding, rotating diodes and Generator field winding is protected by this relay.
5.4 5.4
Genera Generator tor Inter Intertur turn n Fau Fault lt Prote Protect ctio ion n (95 (95A, A,B, B, C) (Fig. 5.6) Interturn faults have commonly been disregarded on the basis that if they occur they will quickly develop into earth faults. This is probably true if the fault is in the slot portion but will take a little longer in the region of the end connection. An approach of this kind is never attractive and may be enti entire rely ly unju unjust stif ified ied.. Ther There e is a poss possib ibili ility ty of the the mach machin ine e bein being g very very seriou seriously sly damage damaged d before before the fault fault evolve evolves s to a condit condition ion that that can be detected by the longitudinal system.
Modern Modern medium medium size size and large large size size turbo turbo genera generator tors s have have the stator stator winding designed with only one turn per phase per slot. For these machine Interturn faults can only occur in case of double ground faults or as a result of severe severe mechan mechanica icall damage damage of the stator stator end windin winding. g. The latter latter is considered rather unlikely to occur.
It is generally considered difficult to obtain a reliable protection against short- circuiting of one turn if the stator winding has a large number of turn per phase.
For For gene genera rato tors rs with with spli splitt neut neutra rals ls,, the the conv conven enti tion onal al inte interr-tu turn rn faul faultt protective scheme comprises a time delayed low set over-current relay which senses the current flowing in the connection between the neutrals of
the stator winding. The fault current can be extensively large in case of Interturn fault, hence the time delay must be short,
FIG. 5.6
FIG. 5.7
0.2 to 0.4 sec and the over current relay must be set higher than the maximum unbalanced current in case of external faults and the minimum unbalanced current for single turn short circuit have to be obtained from the manufacturer of the machine.
Due Due to the the diff diffic icul ulti ties es in obta obtain inin ing g a relia reliabl ble e and and secu secure re inte intert rtur urn n protection, it is in most cases omitted. It is assumed that the Interturn fault will lead to a single phase ground fault at the faulty spot, and the machine will then be ripped by the ground fault relay within 0.3 – 0.4 secs.
Relay is show for one phase only. Similar connections are for other two phases. Time delay of 200 sec. is provided to avoid operation of relay in system disturbance condition. 5.5 5.5
Genera Generator tor Neg Negat ativ ive e Phas Phase e sequen sequence ce Cur Curren rentt Prote Protect ctio ion n (46) (46) (FIG.
5.7) When the generator is connected to a balanced load, the phase currents are equal in magnitude and displaced electrically by 120o. The ampere turn wave produced by the stator currents rotate synchronously with the rotor and no eddy currents are induced in the r otor parts.
Unbalanced loading gives rise to a negative sequence component in the stato statorr curren current. t. The negati negative ve sequen sequence ce curren currentt produc produces es an additi additiona onall ampere turn wave which rotates backwards, hence it moves relatively to the rotor rotor at twice twice the synchr synchrono onous us seed. seed. The double double freque frequency ncy eddy eddy currents induced in the rotor may cause excessive heating, primarily in the surfa surface ce of cylind cylindric rical al rotors rotors and in the damper damper windin winding g of rotors rotors with with salient poles.
The approximate heating effect on the rotor of a synchronous machine for vari variou ous s
unba unbala lanc nced ed
faul faultt
determined by the product 2 I2t =
K, where
or
seve severe re
load load
unba unbala lanc nce e
cond condit itio ions ns
is
I2
=
Negative Negative sequence current expressed per unit of stator stator current current
(PU) t
=
K =
Time in seconds a cons constan tantt depend depending ing on the the heat heating ing char charact acteris eristic tic of the the mach machine ine (rotor) i.e. type of machine and the method of cooling adopted for rotor.
The capability of machine to withstand continuously unbalanced currents is expres expressed sed as negati negative ve sequen sequence ce curren currentt in percen percentt of rated rated stato statorr current. Typical values for generators are given in table. Type of generator
A
B
Max. permitted
Max. permitted
2 I2.t
continuous I2
Indirectly cooled
30
10
Directly cooled
(5 – 10)
(5 – 8)
40
10
40
5
(%)
Cylindrical rotor
Salient pole rotor with Damper winding Without damper winding
Single Single phase phase and speciall specially y two phase short circui circuits ts give give rise rise to large large negati negative ve sequen sequence ce curren currents. ts. The fault faults s are howeve however, r, cleare cleared d by other other rela relays ys in a tie tie much much shor shorte terr than than the the oper operat ate e time time of the the nega negati tive ve sequence relay.
A two phase short circuit with fault current equal to 3.46 (2 Sq.rt of 3) time rated generator current implies a negative sequence current component equal to twice twice the rate current (2 p.u.). Hence a negative negative sequence relay with the setting. 2 I2t = 10s would trip with a time delay of 10 = 2.5 sec. 22 Exampl Example e on load load dissym dissymetr etries ies which which give give rise rise to negati negative ve sequen sequence ce currents in the generator are 1.
Unb Unbalan alance ced d sin singl gle e pha phase se load loadss-T Tract ractio ion n lo loads ads and and indu induct ctio ion n fur furna nace ces s. 2. Tran Transm smis issi sion on line line diss dissym ymet etri ries es due due to capa capaci cito tors rs,, nonnon-tr tran ansp spos osed ed phase wire or open conductors (C.B. pole failure)
An open conductor may give rise to a considerable negative sequence current, as a maximum of more than 50% of rated machine current. The combination of two or more of the above mentioned dissymetries case give rise to harmful negative phase sequence current, even if each of them gives rise to a relatively small unbalance. The Fig. 5.7 will illustrate the C.T. and circuit.
5.6
Generator Loss of Excitation Protection (40G) (Fig. 5.8) A complete loss of excitation may occur as a result of – a. Unintentional opening of the field breaker b. An open circuit or a short circuit of the main field c. A fault in the automatic voltage regulator (AVR) with the result that the field current is reduced to zero
When a generator with sufficient active load looses the field supply, it goes out of synchronization and starts to run a synchronously at a speed higher than the system, absorbing reactive power (VAR) for its excitation from the system, operates as an induction generator.
The maximum active power that can be generated without loss of synchronism when the generator losses its excitation depends on the difference between the direct axis and quadrature axis synchronous reactance. For generators with salient poles, the difference is normally sufficiently large to keep the machine running synchronously; even with an active load of 15=25% of rated load.
For cylindrical turbo generators, the direct ad quadrature axis reactance are practically equal, and the machine falls out of synchronism even with a very small active load. The slip speed increases with the active load. The stator end regions and parts of the rotor will be overheated, if the machine is permitted to run for a long time at higher slip seeds. The relay used to detect field failure is an offset MHO Relay with 90 o lead MTA (40G). on field failure, the terminal impedance locus moves within the Relay characteristics, causing operation. The relay is used with an external or built-in time delay for its transient free operation.
FIG. 5.8
FIG. 5.9
5.6.1 Out of Step Protection of Generator A generator may lose synchronism with the power system, without failure of the excitation system. Because of a severe system fault disturbance or operation at a high load with a leading power factor and hence a relatively weak field. In this condition, which is quite different from the failure of field system,. The machine is subject to violent oscillations of torque, with vide variations in current, power and power factor. Synchronism can be regained if the load is sufficiently reduced but if this does not occur within a few seconds it is necessary to isolate the generator and then resynchronize.
The impedance of the generator measured at the stator terminals changes mostly when synchronism is lost by the machine. The terminal voltage will begin to decrease and the current to increase, resulting in a decrease of impedance and also a change in power factor.
A pole slipping protection comprising of two ohm relays is used to detect out of step operation. The relay monitors the load impedance at the machine terminals and operates when the terminal impedance locus sequentially crosses both ohm relay characteristics which corresponds to one pole slip between the defaulting machine and the system.
5.7
Generator Minimum Impedance (MHO Back) Protection (21G1, G2, G3): The generator minimum impedance protection (or Impedance back-up protection)
is primarily provided to protect the Generator
against
uncleared external short circuits on the lines emanating from the station bus bars. The relay has an impedance or offset MHO characteristic and is set to cover he impedance of the longest line. The Generator transformer being delta/star, introduces a 30o phase shift on the HV side. To ensure correct impedance measurement of the lines, the machine voltage fed to the relay (via Generator V.Ts), is phase corrected by using Interposing voltage transformers (delta/star) connected in the same vector group as that of the Gen. Transformer.
The relay operation is delayed by using external or built-in timer so as to discriminate with line back-up protections.
Over current type of back-up protection is also used for Generator. This is usually of voltage restraint or voltage controlled type where the voltage
input from the Generator V.T. is used to sensitise the over current protection on fault. This ensures [positive operation even though the sustained fault current is less than the full load current of the machine due to the effect of armature reaction. The over current backup is also set with adequate time delay to coordinate with down stream backup protections.
5.8
Generator Differential Protection (87A,B,C) (fig. 5.10)
5.8.1 Principle of Operation Current transformers at each end of the protected zone are interconnected by an auxiliary pilot circuit as shown in Fig. 5.10. Current transmitted through the one causes secondary current to circulate round the pilot circuit without producing any current in the relay. A fault within the protected zone will cause secondary currents of opposite relative phase as compared with the thorough fault condition. The summated value of these currents will flow in the relay, thus energizes the relay. The relay voltage setting is decided from the secondary load drop buy the following formula. Vmax = I11 (RCT + RL) where I11 = Secondary subtransient short circuit current. RL
= resistance of pilot wire between current transformer (CT) and relay.
RCT = resistance of the secondary winding of the saturated current transformer.
The relay operating voltage is set higher than Vmax. The minimum operating current depends mainly on the current setting of the relay, the magnetizing characteristics current of the associated CTs and CT Ratio.
For internal faults, the fault current equal to or above the minimum operating value of the relay, the voltage across the relay goes upto the
FIG. 5.10
Full saturation voltage of the CTs and the relay operates in 10-15 msec.
Non-linear Resistor (metrosils) across the differential relay limits the voltage to a safe level. The primary operating current is normally between 1-5% of rated generator current. The rel ay requires separate CT cores.
The differential relay is usually high impedance relay. The current transformers on the generator neutral and the line side shall have identical turns ratio and similar magnetizing characteristics. Hence under normal
service
conditions
and
external
faults,
with
unsaturated
current
transformers, the voltage across the relay is negligible.
Biased
differential
relays
are
also used
for
generator
differential
protection. The operating principle is same as that for the biased differential protection of transformers. However, a moderate bias (10 to 20%) is adequate for Generator since the mismatch is primarily due to CT errors, unlike in case of transformers where OLTC produces maximum mismatch on end taps. Besides, inrush immunity is not required incase of Generator, unlike in case of transformers.
5.9
Generator Overall differential Protection (87GT) (Fig. 5.1) This protection is used to protect the complete bus of generator, generator transformer and high voltage bus side of unit auxiliary transformer. The special features of the relay are – 1) Through current restraint for external faults 2) Magnetizing inrush restraint 3) Over
excitation
restraint
to counteract
operation
at
abnormal
magnetizing currents caused by high voltage/low frequency.
The magnetizing restraint is required to keep the relay stable when a nearby fault on an adjacent feeder is cleared.
During the time of fault, the terminal voltage of the main transformer is practically zero and after fault clearance i.e. when the circuit breaker of he faulty feeder opens, the transformer terminal voltage quickly rises. This may cause severe recovery inrush currents. The FIG. 5.11
FIG. 5.12
inrush restraint is also required when the unit transformer is energized from the HV bus.
The over excitation restraint is important since there is a possibility of over voltage when load is suddenly disconnected in which the differential relay may trip the generator and the voltage remains high until the automatic voltage regulator (AVR) brought it back to the normal value.
The relay has an unrestrained differential high set unit. The unrestrained operation must be set higher than the maximum inrush current of the transformer. It gives fast tripping (10-20m sec.) The CT and relay connections are shown in Fig. 5.11.
5.10
Generator Reverse Power Protection (32) (Fig. 5.12) This is basically the protection provided for the prime mover i.e. turbine. If the driving torque becomes less such as closure of main steam valves in case of steam turbo generator, the generator starts to work as a synchronous compensator, taking the necessary active power from the network. The reduction of steam flow reduces the cooling effect on the turbine blades and overheating may occur. The work done by the entrapped steam in the turbine is then zero. As generator is not designed to run as a motor it should be immediately tripped when the steam flow to the turbine is stopped and to avoid damage to the turbine blades.
The generator currents remain balanced when the machine is working as a motor. For large turbo-generator, where the reverse power may be substantially less than 1%, reverse power protection is obtained by a minimum power relay, which normally is set to trip the machine when the active power out put is less than 1% of rated value.
The relay contains directional current relay which measures the product IX cos Ø , where Ø
is the angle between the polarizing voltage and the
current to the relay. The scale range used is 5-20mA for 1A and 30-120 mA for 5A rated CT secondary currents. Time delay of 2 seconds is provided. The detail connections of CT and relay are shown in Fig. 5.12.
5.11
Generator Over Frequency Protection
5.12
Generator Under Frequency Protection (14A/14T/81) The Generators are designed to give rated output at rated terminal voltage ad rated frequency. Hence an operation above certain limit i.e. +5% and – 5% of rated frequency is avoided to protect various apparatus in a network and also the generator and turbine. Operation at low frequency must be limited, in order to avoid damage to generators, generator transformers and turbines, (over fluxing may occur if frequency is less than rated).
In practice, prolonged generator operation at low frequency can only occur when a machine with its local load is separated from the rest of the network. The necessity of under frequency protection has to be evaluated
from knowledge of the network and characteristics of the turbine regulator. A time delay of about 2 seconds is introduced in the tripping circuit to avoid transient tripping.
5.13
Generator Thermal Overload Protection (51A/51B) (Fig. 5.13) A generator operating on a large system under continuous supervision is not in much danger of accidental overloading. The power that can be generated is limited by the steam production and hence can not rise unnoticed or maintained for any appreciable period above the programmed level. Overloads in terms of current or MVA as distinct from megawatts are possible. Depending on the voltage regulator setting and type of control relative to the rest of the system, a given generator may take a disproportionate share of the MVAR load on the system. Overloads upto 1.4 times the rated current are not normally detected by the impedance or overcurrent protection. Sustained overloads within this range are usually supervised by temperature monitors (RTD/or thermocouples).
As an additional check of the stator winding temperature, an accurate thermal overload relay may be used. With static relay it is possible to obtain the short relay time constants required for adequate thermal protection. The current overload relay are not expected to give exact measurement of the winding temperature under all conditions. FIG. 5.13
FIG. 5.14 5.14
Generator Overvoltage Protection (I/II (59A/59B) (Fig. 5.14) During the starting up of a generator, prior to synchronization, he Generator terminal voltage is obtained by the proper operation of the automatic voltage regulator (AVR). After synchronization, the terminal voltage of the machine will be dictated by its own AVR and also by the voltage level of the system and the AVRS of nearby machines. It is not possible for one machine to cause any appreciable rise in the terminal voltage as long as it is connected to the system. Increasing the field excitation, owing to a fault in the AVR, merely increases the reactive MVAR output, which ay ultimately lead to tripping o the impedance relay or the V/Hz. Relay. Maximum excitation limit prevents the rotor field current and he reactive output power from exceeding the design limits.
This protection is used for the insulation level of the generator stator windings. Severe over voltage will occur, if the generator circuit breaker is
tripped while the machine is running at fu load and rated power factor, the subsequent increase in terminal voltage will normally be limited by a quick acting AVR. However, if the AVR faulty or at this particular time switched over to manual control, over voltage will occur. This voltage rise will be further increased if simultaneous over speeding should occur, owing to a slow acting turbine governor.
Modern unit transformers with high magnetic qualities have a relatively sharp and well defined saturation level, with a knee point voltage between 1.2 and 1.25 times the rated voltage (Un). A suitable setting of the over voltage relay is, therefore, between 1.15 and 1.2 times Un and with a definite delay of 1 to 3 sec.
An instantaneous high set voltage relay can be included to trip the generator quickly in case of excessive over voltage following a sudden loss of load and generator over speeding.
GENERATOR PROTECTIONS AT A GLANCE Protection
Cause
Effect Insulation damage
Relay Voltage Relay
Setting
Stator Earth
Short circuit in slots between
2-5% of normal
Fault
core & winding.
neutral voltage
Interturn short circuit Mech. or
t.d. 0.3 – 0.5 sec.
thermal damage to corona Rotor Earth
preventive paint Abnormal mech. or thermal
Fault
stresses due to vibrations,
Interturn fault
Overcurrent, overheating. Interturn Short Circuit
Negative Phase
Unbalance loading
Sequence Gen. Loss of Exen.
1. Unintentional Opening of field breaker. 2. An o/c or s/c in field. Winding
- do -
- do -
1-5% of voltage injected.
-do -
Double Primary
0.5 to 1.5A
Excessive rotor
CT &O/C relay O/C Relay
200 ms. to 1 sec. 5-10% of full load current
heating
(I2 based)
or as recommended by
Induction Generator
Impedance
manufacturer. Dim = 0.5xXd pu
Asynchronous
Relay/Offset MHO
t.d. 2 sec.
Operation
Relay
Offset=0.75 Xd’pu
3. Fault in AVR
Overheating of rotor and stator end zone
Gen. Min.
Phase to phase short circuit in
impedance
stator winding on Gen. Bus
Load imp.
LV side for GTR
1/0.7=1.4 times rated
HV side of UAT and uncleared
current at rated voltage
Generator
MHO Relay
faults on the evacuation lines. Internal fault
Differential Relay
Differential
70% of rated Gen.
1-1.5 msec. 1-5% of rated Gen.Current 10-15 msec.
Protection Reverse Power
Failure of prime mover
Motoring damage to
Directional power
0.5% of rated power.
Protection Low Forward
turbine blades Over speeding
relay
t.d. 2 sec.
Upon an electrical tripping
Power Over Frequency
prime mover fails to trip Sudden loss of load.
Overspeed
Frequency Relay
Under
C.B. Opens with turbine ON Increase in load
(Mech. Device) Over fluxing (V/f)
Frequency Over fluxing
Malfunc tioning of AVR.
Aux. Speed falls Overheating of stator
Frequency
Load throw-off with Excitation.
iron and transformer
Dependent
On manual, under frequency
iron parts
Voltage relay
- do -
- do -
Over Loading
operation Overloading in-terms of current or
Protection
MVA, Failure of coolant flow or
winding
over load relay
Over Voltage
temp. Sudden loss of load at full load
Insulation damage
Voltage Relay
Protection
and rated p.f. and AVR fails or
Temp. rise in stator
Static thermal
- do +5% t.d. 2 sec. -5% t.d. 2 sec. V = 1 to 1.3 F T = 3-5 sec.
Set=Amb. Temp. + Temp. rise given on name plate 110%-2 sec. t.d. 115% - 120% Instt.
changeover to manual and Local Breaker Backup
generator Overspeed GCB fails to trip
External sources
LBB Protection in
5-8%. In Set at 5%
feeding fault
conjunction with
t.d. – 0-20 sec.
Bus Bar protection
CHAPTER – 6 BUS ZONE – PROTECTION AND LOCAL BREAKER BACKUP PROTECTION 6.1
Introduction With ever increasing short circuit levels and growing complexities of the supply system, Busbar protection is becoming increasingly relevant even at medium voltage level in Industrial Distribution system. Besides, major Industrial installations with high contract demand and growth potential, often get utility supply at Extra High Voltage (EHV) level i.e. 132 KV and above where high speed bus bar protection is considered essential from the point of view of system stability.
Local breaker backup protection (against stuck breaker condition) though more prevalent in utility systems can be applied in industrial distribution system at an advantage. This protection gets well with Bus Bar protection as it can share common tripping logic with bus bar protection.
6.2
Bus Bar Protection - Requirements
6.2.1 Stability It should be stable under maximum through fault condition with fault level approaching switchgear breaking capacity.
6.2.2 High Speed Operation Typical operating time range between 10-30 msecs. Fast clearance enables maintaining system stability, besides limiting equipment damage and also enables localised isolation of the faulted Busbar avoiding wide spread disruption in the system.
6.2.3 Selectivity It should be selective in isolating the faulted busbar, particularly in case of multi-bus installations.
6.2.4
The protection should operate positively for internal fault, despite long intervening quiescent periods, the bus faults being fewer and far apart.
6.2.5 Sensitivity
The protection should be adequately sensitive to clear low in feed faults, particularly during minimum generating conditions. 6.2.6 Suitable for use with moderate C.T. ratings This is necessary since the CTs have to handle high fault currents, worst case being faults approaching switchgear breaking capacity.
6.2.6 Configurable to different Busbar arrangements The busbar arrangement may undergo changes such as sectionalisation and additional circuits may be connected in future. The protection should be extendable to such configuration changes.
6.3
Types of Bus Bar Protection The most commonly used bus bar protection system are: 1) System Protection covering Busbar 2) Differential protection
6.3.1 System Protections Covering Busbar These are primarily local or remote backup protection such as over current/earth fault relay on feeders/transformers or distance protection provided on lines.
The distance protection for example, provides backup protection to remote busbars in time delayed zone 2 or backup to local busbars in time delayed zone 3 with a small reverse reach. The IDMT overcurrent. Earth fault relays also provide similar backup protection to the connected circuits against bus faults. However, these cannot be considered as primary protection for busbar, being time delayed and non-selective.
6.3.2 Differential Protection The differential protection is the primary protection for bus bar against both phase and earth faults. Practical bus differential schemes have all the ingredient as spelled out under 6.2 above.
6.3.2.1
Operating Principle of Differential Protection
The protection uses a circulating current arrangement, with CTs of identical ratio and ratings on all incoming and outgoing circuits having heir secondaries connected in parallel (phase by phase) to form a replica of the primary bus bar arrangement. The differential relay is connected across the CT secondary bus wires.
For external faults, the summated inflow from healthy circuits is equal to the outflowing current from faulted circuit and thus the currents are balanced, with no differential current through the relay. For internal fault, however, all CTs see inflow of current into the bus. The secondary currents, therefore, add up into the relay branch. Typical current distribution for external and internal fault is shown in Fig. 6.3.2.1.
The above illustration, considers ideal current transformers with no errors which is too simplistic an assumption. In practice, CTs have errors and may experience unequal saturation due to remnant flux in the core and dissimilarities in their magnetizing characteristics, particularly if the fault current is asymmetrical having a slowly decaying d.c. component. This may produce transient unbalance, causing operation of the high speed differential
relay.
The
practical
differential
protection
for
busbars,
circumvent this problem either by making the relay branch high impedance or providing a through current bias, thereby, automatically increasing he pickup threshold of the differential relay, above the expected unbalance current, on through faults. Two types of bus bar protection schemes are in vogue: 1. High Impedance 2. Low Impedance (Biased)
6.3.2.2 1.
High Impedance Scheme (Fig. 6.3.2.2) The relay branch is made high impedance either by using a voltage operated high impedance relay or by connecting an external series resistor (stabilizing resistor) in case of current operated differential relay.
FIG. 6.3.2.1: CURRENT DISTRIBUTION
FIG. 6.3.2.2: TYPICAL C.T. CONNECTION
FIG.6.3.2.3 : C.T. SUPERVISION
2.
This type of protection requires special class PS CTs (with low turns ratio errors) of identical ratio and ratings on al circuits. Exclusive CT cores are required for high impedance schemes which cannot share common CT cores with other protections.
3.
High impedance schemes are primarily fundamental frequency turned, over current or over voltage relays and hence simple in design and execution.
6.3.2.3
Supervision
The differential protection has a fail safe design. Consequently, the relay becomes potentially unstable for any open circuit or cross connection in the CT secondary of he associated feeders. The maloperation of the Busbar protection can be prevented on load under the above condition by setting the pick up threshold of the differential element over and above the maximum loaded circuit current. However, the relay may still maloperate on a through fault, if the CT secondary open circuit goes undetected. A maloperation of busbar protection could be catastrophic, particularly in interconnected system and hence continuous supervision of CT secondary is required as an additional safeguard.
The supervision relay is an AC voltage relay, connected across the differential relay branch, having a sensitive setting range (usually 2 – 14 volts) and a fixed time delay to prevent transient operation on internal faults. The relay is connected to sound an alarm and short CT secondary Bus wires, on operation. Typical circuit arrangement for CT supervision relay is shown in Fig. 6.3.2.3.
6.3.2.4
Check Feature
Since stability is a very critical parameter of busbar protection, additional check feature is usually provided in high impedance schemes to enhance security against possible maloperation.
The check feature is operated off a separate CT core on all incoming and outgoing circuits connected to the bus and is a virtual duplication of the main differential system. The contacts of the main and check
FIG. 6.3.2.4 (a): TWO ZONE CHECK FEATURE
differential relay are connected in series so that tripping is conditioned by simultaneous operation of both for an internal fault the check zone provides a two fold advantage.
1.
It enhances security in Multi-Bus Installations where CT switching becomes inevitable for zonal discrimination.
2.
It enables sensitive setting to be adopted on differential relay without the risk of maloperation with CT open circuiting under maximum load condition.
A typical 2 zone scheme for sectionalized busbars with check feature is illustrated in Fig. 6.3.2.4.
6.3.2.5
C.T. Switching
In case of multi bus arrangement (2 Bus/3 Bus arrangement), CT secondaries of incoming/outgoing circuits are required to be switched to form a secondary replica of the primary Bus arrangement to achieve zonal discrimination. This is done either by using the bus isolator Auxiliary contacts of individual circuits or by using separate contact multiplication relay of Electrical reset type as shown in the Fig. 6.3.2.5.
6.4
LOW IMPEDANCE SCHEME (BIASED) Typical CT connection for the scheme is shown in Fig. 6.4.0. Low impedance Bus differential relay is primarily a biased differential relay where the through current bias (restraint) increases the pickup threshold of differential relay on external fault to ensure stability. The low impedance relay is more tolerant to CT mismatch and can share common CT core with other protections. Practical low impedance schemes provide CT saturation detectors to enhance stability.
6.5
LOCAL BREAKER BACK-UP (LBB) PROTECTION
6.5.1 Introduction In EHV substations, reliability of fault detection is enhanced by providing duplicated protections (either Main 1/Main 2 or Main and Backup Protection). At the upper end of the EHV levels, the D.C. sources for protection are also duplicated for better redundancy.
FIG. 6.3.2.5(a): TYPICAL C.T. SWITCHIG ARRANGEMENT
FIG. 6.4.0: LOW IMPEDANCE SCHEME (BIASED) Besides, the control breakers are provided with duplicated trip coils. All these measures, undoubtedly improve the reliability of fault detection and
isolation. However, the possibility of mechanical failures of the switchgear or interrupter flash overs can not be covered by these means for obvious reasons. A failure of the breaker may therefore, result inspite of correct operation of the protection and envergisation of trip coils. This situation can be corrected by providing local breaker backup (LBB) or breaker fail protection.
6.5.2 Operating Principle LBB protection comes into operation, only if, the breaker fails to trip, following energisation of its trip coi8l, through the circuit trip relays. The main ingredient of LBB protection, is a current check relay initiated by the circuit trip relays and a follower timer. The current check relay, on initiation, check the presence of the current in the faulted circuit and if it persists beyond a preset time, proceeds to trip all other circuits connected to the Busbar to which the stuck breaker is connected, thereby, ensuring local isolation. Tripping of remote breaker is also initiated through a separate carrier channel, in case of line breakers to arrest infeeds from remote end. A typical simplified LBB scheme is shown in Fig. 6.5.2 to illustrate its operating principle.
The circuit protections (M1/M2/BU) on operation initiate CB tripping and simultaneously trigger LBB current check relay by extending DC. The LBB protection, therefore, gets initiated on operation of the circuit protection and hence does not require any time co-ordination with the circuit protections. Besides a much sensitive setting can be provided in the current check relay, independent of the circuit loadings. Typical setting range for the current check relay and follower timer and recommended settings are give below.
Application
Generator Circuit All other circuits (TFRs/Lines/Bu s Couplers etc.
Current check relay Range Recommend
Follower Timer Range Recommend
ed
ed
5 – 80%
Setting 5%
0.1 – 1 secs.
Setting 0.2 secs
20 – 320%
20%
0.1 – 1 secs.
0.2 secs.
FIG. 6.5.2(a): TYPICAL LBB SCHEM AC/DC CIRCUITS
FIG. 6.5.2(b):
FIG. 6.5.3: COMBAINED BUS BAR PROTECTION/LBB
A more sensitive setting is generally adopted for Generator application, in view of the fact that a stuck breaker situation for certain abnormal conditions like motoring, may involve very low current infeeds.
6.5.3 Combined Tripping Logic for LBB/Bus Bar Protection Where Busbar protection is contemplated, the LBB scheme can share common trip logic/tripping relays with Busbar protection. A typical combined Busbar protection/ LBB scheme is shown in Fig. 6.5.3 of 2 Bus Installation.
6.5.4 Setting Criteria for LBB Timer The LBB time delay is primarily influenced by the tripping time of the breaker and the reset time of the current check relay on correct tripping of the breaker. Besides, adequate safety margin is also to be allowed. The timing criteria is explained on a time scale below.
TLLB = TCB + TDO + TM - TPU Where
TLLB - LBB Follower timer setting TCB - Breaker Tripping time TDO - Drop off time of current check relay TPU - Pick up time of current check relay TM - Safety Margin
Usually a time delay of 200 msecs. Is adopted which allows sufficient time co-ordination with remote back up protection.
- oOo -
7. 7.1
DISTRIBUTION FEEDER PROTECTION
Introduction Industrial Power Distribution systems make extensive use of cable feeders for example, between captive generation Bus or ‘Grid Supply Bus’, to load centers/Power control centers. These feeders are often radial or some times form part of a ring main systems. While IDMT over current/earth fault protection is mostly used for radial distribution feeders particularly in the tail end unit type protections, such as pilot wire protection are also sometimes used on critical feeders.
The unit protections are highly selective, sensitive and fast in operation, but do not have any back up capabilities. The IDMT protection on the contrary, are simple and economical but slower in operation to necessitate time coordination between adjacent sections for selective trippings. IDMT relays, however, provide excellent backup protection to the down stream system.
7.2
Unit Protection The principle of unit systems was first established by Merz and Price. This fundamental differential system have formed the bases of may highly developed protective arrangements for feeders and many other plant equipments. Two forms of different schemes are available. a) Circulating Current System b) Balanced voltage system
7.2.1 Circulating Current System In this arrangement current transformers of identical ratio and ratings are provided at each end of the protected zone and are interconnected by secondary pilots as shown in Fig. 7.2.1(a).
For external faults, the two end CTs see equal inflow and outflow producing a circulating current between the C.T. secondary and pilots, with no differential current through the relay. For an in-zone fault, however, the secondary currents have a additive polarity and, hence the summated current flows through the relay, causing operation.
FIG. 7.2.1(a): CIRCULATING CURREN SYSTEM
FIG.7.2.2 (a): BALANCED VOLTAGE SYSTEM FIG. 7.2.3(a): TYPICAL SUMMATION C.T.
In practice, unequal saturation of the CTs can cause increased spill current through the relay on external faults, producing instability. The problem is normally overcome by making the relay branch “high impedance” by adding series stabilizing resistor.
7.2.2 Balanced Voltage System In balance voltage system, the CT secondary outputs are opposed for through fault so that no current flows in the series connected relay. An inzone fault however, produce a circulating current causing operation. The arrangement is shown in Fig. 7.2.2.(a).
In the above arrangement, external fault would ineffect cause a CT open circuit condition as no secondary current would flow. To avoid excessive saturation of the core, the core is provided with non-magnetic gaps to absorb the maximum primary m.m.f. The secondary winding therefore would produce an e.m.f. and can be regarded a voltage source. The inherent CT errors and pilot capacitance would produce substantial spill current through the relay on through fault, causing instability. The problem is overcome by providing a through current bias (restraint) which increases the differential pickup approximately proportional to the through fault current, thereby ensuring stability.
7.2.3 Summation Arrangement In 3 phase systems, independent protection can be provided for each phase, using phase comparison of the two end currents. This would however, require a minimum 4 core pilot adding up to the cost. An alternative is to combine the separate phase currents into a single quantity for comparison over a pair of pilots. This is achieved by using summation current transformers.
A typical summation C.T. is shown in Fig. 7.2.3 (a) The interphase section of the summation winding (i.e. A-B & B-C) usually have equal number of turns and the neutral end winding (C-N) having greater number of turns.
The above summation arrangement would produce output for both balanced as well as unbalanced faults. Moreover, the relay offers different
sensitivities for different types of faults depending upon the phases involved. In the summation arrangement illustrated, the associated relay will have highest sensitivity for A-C and A-N faults.
7.2.4 Supervision of Pilots The pilot circuits are subjected to various hazards which can cause open circuit or short circuit of the pilot cores. While overhead pilots are vulnerable to storms, buried pilots may be damaged during excavation. The pilot failure may lead to either mal-operation or non-operation of the protection and hence continuous supervision of the healthiness of he pilots become necessary.
This is achieved by injecting a small d.c. current though the pilot from one end and monitoring its presence at the other end by energizing an auxiliary relay. The auxiliary relay resets in the event of any discrepancy in the pilots and sounds an alarm. A small time delay is introduced to prevent transient operation due to primary system faults, causing momentary dip in the auxiliary supply.
Overcurrent check feature may also be incorporated to prevent tripping on load in the event of a pilot open circuit condition as it may lead to instability.
7.3
IDMT Overcurrent & Earth Fault Protection While at the lower end of the distribution system (particularly at low Voltage Levels), fuses or series connected trip coils operating on Switching devices, are used for short circuit protection. IDMT over current/earth fault relay find wide application at medium voltage levels.
As the
name implies, IDMT relays have an Inverse
time/current
characteristic (i.e. The operating time is inversely proportional to the current) and a Definite Minimum Time (DMT) for high multiples of setting current. The time/current characteristic is usually represented on a logarithmic scale and gives the operating time at different multiples of setting current for the maximum “Time Multiplier Setting” (TMS). The TMS is continuously adjustable giving a range of time/current characteristic.
7.3.1 IDMT Characteristic Variations and their Applications There are different variations of IDMT Characteristics. These are
i) Standard Inverse
t = 0.14/(10.02-1)
ii) Very inverse
t = 13.5/(I-1) t = 80/(I2-1)
iii) Extremely Inverse iv) Long inverse
t = 120/(I-1)
Where t = Relay operating time (seconds) And
I = Current (as multiple of Plug setting)
Fig. 7.3.1(a) shows the above characteristic at the max. time multiplier setting of I.O
While standard Inverse Characteristic covers majority of he applications, very invese characteristic is particularly useful here there is a substantial reduction in the fault current as the distance from the power source increases. Extremely Inverse characteristic is particularly suitable in grading with fuses (the operating time being inversely proportional to the square of the current, the characteristic eminently matches with the fuse characteristic). Long Inverse characteristic is primarily used for overload protection or earth fault protection in resistance grounded systems.
The IDMT relays provide both time and current grading to achieve discrimination between successive stages in the distribution system.
7.3.2 Grading Margin The time interval (grading margin) between adjacent relay for selective operation depends upon following factors. i)
Circuit Breaker tripping time
ii)
Over shoot time of the relay
iii)
Relay timing errors
iv)
Safety Margin
The table below gives typical allowance to be made for the above factors.
FIG. 7.3.1(a).:IDMT CHARACTERISTICS
FIG.7.3.3.1 (a)
Timing Error (%) Over Shoot (Sec) Safety Margin (Sec)
EM Relay 7.5 0.05 0.1
Static Relay 5.0 0.03 0.05
A suitable grading margin can be calculated as follows: T2 = (2ER/100) x t + TCB + To + TSM Where t2 = time interval between adjacent relays t = Relay nominal operating time ER = % Timing error as given by manufacturer TCB = Circuit Breaker tripping time (seconds) Te = Relay over shoot (seconds) TSM = Safety Margin (seconds) Typically a grading margin of 0.3 o 0.4 second is considered adequate.
7.3.3.1
IDMT relays supplemented by High set Instantaneous over current elements
Particularly on transformer feeders or long distribution feeders connected to strong sources here there is a substantial reduction in the fault infeed for faults beyond the protected section, high set instantaneous over current element is often incorporated with the IDMT over current relay. The high set element is set over and above the infeeds for fault beyond the protected equipment/section such that it remains stable for such faults, while at the same time, offers high speed clearance for close up faults within the section.
A typical example for High set over current application is given in Fig. 7.3.3.1(a).
H.S. o/c setting at A = 1.3 x 3000 = 3900 Amp (primary) = 6.5 Amp (secondary) The relay thus remains stable for faults beyond station, “B”, but would offer instantaneous clearance for close up faults in section A-B.
The initial fault current may be asymmetrical with slowly decaying d.c. offset. To enable close setting above the steady sate through fault current, the highest element should immune to the d.c offset. Such immunity is defined in terms of transient over reach which should be low. Relays with less than 5% transient over-reach are available.
The high set unit also improves overall grading as the IDMT relays are now required to be time coordinated up to highest setting current and not upto the maximum short circuit current close to relaying point.
7.3.3.2
Directional IDMT Relays
When fault current can flow in both direction at the relay location, directional IDMT over current/earth fault can be used at an advantage to ensure selective tripping. Usually a separate directional element is provided which controls the operation of the IDMT over current relay. The directional unit is basically a power measuring device in which the relative direction or phase of the fault current is checked with reference to the system voltage.
Typical CT/VT input connection and Vector diagram for directional over current and earth fault relay is shown in Fig. 7.3.3.2 a/b and Fig. 7.3.3.2 c/d.
Referring to A phase element, the voltage coil flux lags the input volts “Vac” by 45o, whereas the current coil flux is in phase with current IA. Since the torque is function of Øv x Ø1 sin a, where Øv = voltage coil flux, Ø 1 = current coil flux and a = Angle between the two interacting fluxes, maximum torque will be produced when a = 90o. The maximum torque will, therefore be realized when IA lags VA by 45o (IA’). The operational range of the directional element will be 45o lead to 135o lag as shown in he vector diagram.
7.3.3.3
Typical Applications of Directional IDMT Relay
Following are the typical application of directional IDMT Relays. 1)
Parallel Feeders: Directional relays are used at the receiving end
of he parallel
feeders to ensure selective tripping as shown in Fig.
7.3.3.3.1 (a).
FIG. 7.3.3.2(a): Directional O/C relay Quadrature Connection FIG. 7.3.3.2(b): VECTOR DIG. FOR 45 O LEAD MTA FOR QUADRATURE CONNECTION FOR “A” PHASE RELAY.
FIG. 7.3.3.2(c): DIRECTIONAL EARTH FAULT RELAY CONNECTION
FIG. 7.3.3.2(d): VECTOR DIG. FOR DIRECTIOAL E/F RELAY
FIG.7.3.3.3.1 (a): PARALLEL FEEDER PROTECTION.
FIG.7.3.3.3.2 (a)
Referring to the figure above, for a fault on CKT2, while the relay at Receiving End (B) on CKT2, sees an infeed in its looking direction and operates, the relay on CKT 1 sees a current flow inn the reverse direction and restrains. By time coordinating the relays at, A and B, a selective tripping can be obtained. Besides the directional relays at End “B” are non responsive to downstream faults and hence do not require any time coordination with downstream backup, thereby enabling a relatively faster clearance.
2)
Ring Main System: Directional relays are used for Ring Mains. A
typical example is shown in Fig. 7.3.3.2 (a). While the source end station (A), can have non-directional relays (in view of no possibility of infeed reversal), the intermediate stations should have directional relays looking into the feeders.
The time grading can be worked out by considering the rid open at one side of the supply point, reducing it to radial system and grade from the tail end. The same procedure can be repeated by opening the grid on the other side, at the supply point. Directional IDMT relays are also used on the feeders between Grid supply and captive supply Bus for selective tripping and improved coordination.
-oOo-
CHAPTER – 8 LINE PROTECTION (DISTANCE SCHEMES) 8.1
Introduction Distance Protection is one of the most extensively used form of protection for transmission and sub-transmission lines. Distance relay, primarily measures the impedance of the line between the relaying point and fault point and compares it with the setting impedance to ascertain whether the fault is within the zone or outside. Practical distance relays have normally 3 zones of operation – an instantaneous first zone and time delayed backup zone 2 and 3.
When applied in conjunction with a signaling channel, it provides selective, high speed protection for he line in question, and also a time delayed backup to the adjoining lines through its second and third zone, thereby combining the advantages of a unit as well as non-unit protection.
The heart of a distance protection is a comparator which carries out the impedance measurement. Several impedance measuring characteristics are available covering both short and long lines, which are discussed below.
8.2
Measuring Characteristics The various measuring characteristics and heir applications are described below:
8.2.1 Impedance Characteristic (Fig. 8.2.1) An impedance characteristic is represented by a circle with its center at the origin on the R-X diagram, and its radius equal to its reach setting.
The characteristic is produced by using an amplitude comparator and does not take into account the phase relationship between the voltage and current.
The impedance characteristic is non-directional and is highly susceptible to power swings and load encroachment because of its larger coverage on
FIG. 8.2.1: IMPEDANCE CHARACTERISTIC
FIG. 8.2.2.1(a): SELF POLARISED MHO CHARACTERISTIC
FIG. 8.2.2.2(a): CROSS POL MHO CHARACTERISTIC the R-X plane. This characteristic is normally used for fault detection or as a time delayed backup zone.
8.2.2. MHO Characteristic (Or Directional Impedance Characteristic) There are three principle variations of MHO characteristic. a) Self Polarised MHO b) Cross Polarised MHO c) Offset MHO
8.2.2.1
Self Polarised MHO (Fig. 8.2.2.1.a) The self Polarised Mho characteristic is a circle whose circumference
passes through the origin and diameter represents the setting impedance or Replica Impedance (ZR) at an angle θ.
MHO Characteristic has an angle dependant reach (being maximum along the setting Impedance angle) and is directional. It is less prone to power swings/load encroachment due to its restricted coverage on the R-X plane, particularly along the Resistive Axis.
8.2.2.2
Cross Polarised MHO (Fig. 8.2.2.2a)
The cross polarised Mho characteristic is produced by deriving the polarizing
voltage
reference
from
healthy
phase(s).
While
the
characteristic is directional and has an angle dependant reach, it provides increased tolerance to fault resistance since the characteristic expands along the resistive axis for forward, unbalanced faults. This happens due to the healthy phase polarization.
This characteristic is eminently suitable for short lines tied up to weak sources where the fault arc resistance may be comparable to line impedance. The degree of expansion depends upon the source to line Impedance (ZS/ZL) ratio, being more at higher ZS/ZL ratio. The relay, thus provides enhanced resistive coverage hen the source is weak or the source impedance is high.
8.2.2.3
Offset MHO Characteristic
The offset MHO characteristic encloses the origin providing a small coverage for faults behind the relaying point as shown in Fig. 8.2.2.2(a).
The relay is then said to be having a reverse offset. A forward offset, on the contrary sets the characteristic away from the origin. The offset MHO characteristic is used for zone 3 (when provided with reverse offset) primarily as a back up against Busbar faults. Forward offset is used for producing certain specially shaped characteristics as indicated in Fig. 8 described later.
8.2.3 Reactance Characteristic (Fig. 8.2.3.a) The reactance characteristic is represented by a line parallel to the Resistive Axis while ZLLØ represents the line impedance, XR represents the setting Reactance.
The reactance characteristic is ideally suitable for short lines because of its high resistive coverage. The characteristic is however, non-directional and requires to be monitored by some directional characteristic, as shown by he dotted MHO circle in Fig.8.2.3a) when used for distance protection.
Besides the above standard characteristics, there are some shaped characteristics to cover special applications. These are described below.
8.2.4 Lenticular Characteristic (Fig. 8.2.4a) The characteristic is called lenticular because of its lens shape. While it provides the required coverage along the line impedance angle, the resistive coverage is restricted.
The characteristic is suitable for long over loaded lines and is often used for Zone 3 where load encroachment problem may be encountered. The lenticular characteristic invariably has a small reverse coverage.
8.2.5 Figure 8 Characteristic (Fig. 8.2.5a) The characteristic is produced by two offset MHO circles, the lower one having a small reverse offset where as the upper circle having a forward offset. The composite characteristic looks like the figure of 8 and hence the name. Here again the characteristic limits coverage along the resistive axis. FIG. 8.2.2.3(a): OFFSET MHO CHARACTERISTIC
FIG. 8.2.3(a): REACTANCE CHARACTERISTIC
FIG. 8.2.4(a): LENTIC CHARACTERISITC
FIG. 8.2.5(a): FIG.8: CHARACTERISTIC
FIG. 8.2.6(a): QUADRILATERAL CHARACTERISTIC
FIG. 8.3.0(a): TIME DISTANCE CHARACTERISTIC OF A 3 ZONE DISTANCE SCHEME
The characteristic is thus less prone to load encroachment and hence applied for long lines, evacuating bulk power.
8.2.6 Quadrilateral characteristic (Fig. 8.2.6a) The characteristic is of the shape of a quadrilateral and fully directional. Both the resistive and reactive reaches are independently adjustable.
The characteristic is, therefore, ideally suitable for very short lines, requiring high fault resistance coverage.
8.3
Zones of Protection Conventional distance relays have normally 3 zones of protection – namely an instantaneous zone 1 and time delayed zone 2/zone 3. Correct coordination between distance relays on adjacent lines in a power system, is achieved by judiciously selecting the reach and time settings of the various zones. Typical reach and time settings for a 3 zone scheme is shown in Fig. 8.3.0(a).
Associated time delays Zt – Inst, Z2-t2, Z3-t3.
The settings criteria for various zones is given below: Zone 1
- 80 – 85% of the protected Section
Zone 2
- Protected section + 50% of shortest adjoining Section or 120% of the protected section w hichever is greater.
Zone 3
- Protected section + Longest adjoining section.
The zone 1, being instantaneous, is set under-reaching with a margin of about 15 – 20% to account for possible relay/CT/PT errors and inaccuracies in the line impedance parameters. The zone 2 is primarily intended to cover he last 15-20% of the protected section, and hence is set to over-
reach the remote busbars bars with similar margin, to account for possible under-reaching due to relay/CT/PT errors. The Zone 2 covers up to 50% of the shortest adjoining section and ensures that it does not overlap with the zone 2 of adjoining section, thus avoiding coordination problem. However, if the shortest adjoining section is too short, compared to the protected section, the margin against possible under-reaching may not be adequate. In such an eventuality, the zone 2 can be set to cover 120% of the protected section.
Zone 3 protection is intended as a backup against uncleared external faults and hence set to cover the longest adjoining line. The zone 3 setting should, however, be checked against possible load encroachment, particularly in case of long heavily loaded lines.
8.4
Phase Sequence comparator for MHO characteristic The MHO characteristic as shown in Fig. 8.2.2.1(a) can be produced by using a sequence comparator with inputs derived from the current and voltages from the transmission line. The input for the measuring circuit for a plain MHO characteristic are V (fault voltage) from the line V.T., and IZ, from the replica impedance “Z” fed with line current “I” through the current transformer. The above inputs referred to a single phase system are shown in Fig. 8.4.0(a).
The voltage IZ is a replica of voltage which would be resented to the relay for a fault at a location equivalent to its reach point. The reach of the relay is set by adjusting the relative magnitudes of V and I.Z. and the characteristic angle is set by adjusting the phase angle of the Replica Impedance “Z”. The measuring circuit operated by deriving the signals VIZ and V∠ -90 o and feeding these to the sequence comparator. If inputs VIZ lags V ∠ -90o, the fault lies inside the characteristic whereas if V-IZ leads V ∠ -90o the comparator restrains since the fault is external. Signal V ∠ 90o is known as the polarizing signal which provides a reference for comparing the lag or lead relationship of the other input V-IZ. The MHO characteristic with the input signals is illustrated in Fig.8.4.0 (b).
8.4.1 Principle of comparator The above inputs V-IZ and V∠ -90o are sinusoidal quantities of power frequency denomination. Since the sequence comparator compares only the lag or lead relationship of the input signals, only phase angle information and not amplitude of inputs is important. The inputs are,
FIG. 8.4.0(a)
FIG. 8.4.0(b): SEQUENCE COMPARATOR VOLTAGES FOR MHO CHARACTERISTIC Therefore, filtered to remove the unwanted frequency components and then squared, so that they retain the phase angle information of the original sinusoidal inputs.
To understand the operation of the comparator, the input square wave A and B, which have either a high or low value can be regarded as logic variables. If the high and low state of the input signals is represented as A B and A B respectively, there are four possible combinations of their state i.e. A B, A B, A B, and A B. if both signals have unity mark space ratio and equal time periods, the four combinations will occur in a cyclic manner, with only two possible variations.
If A leads B, the sequence would be A B, A B, A B, the sequence would be A B, A B,
A
B and A B and if ‘A’ lags
Band A B.
The comparator has a logic circuit which examines the input signals at every change of state to see which of the two sequence are being followed and determines whether the same is progressing in a tri or restraint condition. The circuit can identify a trip or restraint condition from a single change of state and from any starting point from the cycle. However, a single change of state may be deceptive, if the input signals are laden with noise, since noise signals may alter the zero crossings and reverse the sequence momentarily. Greater security is therefore obtained, if tripping is conditioned by a number of status changes corresponding to a trip sequence. The comparator has a counter to determine the number of status changes. Every acceptable change corresponding to a tri sequence increments the counter while a change corresponding to restraint condition decrements the counter to a minimum of zero. The criteria for operation is usually a count of 3 or 4.
Referring to the figure 8.4.2(a) and (b), the noise signals introduces an extra pair of zero crossing one adding to the total count and the other subtracting. After each such interference, the counter is in the same
FIG. 8.4.1: RESTRAI LOGIC SEQUENCES
(a)
FOR COMPARATOR
FIG. 8.4.1: OPERATE LOGIC (b) SEQUENCES FOR COMPARATOR
FIG. 8.4.2(a): BASIC NOISE IMMUNITY FIG 8.4.2(b) : BASIC NOISE IMMUNITY
Position as before. The comparator, therefore, renders inherent noise rejection.
8.4.2 Polarising input to the Comparator The polarising input provides a reference for comparison for the other input. It is, therefore, imperative that the polarising voltage is always available irrespective of the location of the fault (close up) and the number of phases involved.
This is achieved by supplementing the faulted phase input, with either the healthy phase voltage or memory voltage. While healthy phase voltage would maintain polarising reference for close up unbalanced faults, memory polarization caters for symmetrical (3 phase) faults.
The healthy phase or memory polarization eventually produced resistive expansion of the characteristic, thereby enhancing fault resistance coverage. The memory signal is usually extended for a substantial length of time to enable positive operation of the relay on close u three phase faults. 8.5.0 Additional Features of Distance Relays The practical distance protection has several standard/optional features, these are:i)
Power Swing Blocking
ii)
V.T. Supervision and
iii)
Switch on to fault.
8.5.1 Power Swing Blocking Power Swing characterized by cyclic changes in current, voltage and power, are produced when the induced voltage of generators at different locations in an interconnected system, slip relative to each other to adjust to the changes in power transfers (in magnitude and direction) following system faults. The tandem variations in voltage and current during a
swing, presents a changing impedance to a distance relay, with the impedance locus moving away from the load area towards the relay characteristic. The distance relay, is therefore, prone for operation
During a swing and is required to be blocked, to allow the power system, to return to stable conditions, during recoverable swings.
The principle of power swing blocking is illustrated in Fig. 8.5.1(a).
Considering a Generator (represented by EG, XG) connected to a system (represented by ES, XS) through a transmission line (Impedance ZL), when the angle of displacement between EG & E S widens, the impedance moves towards he relay characteristic. The impedance locus is a perpendicular bisector of the total impedance line (i.e. XG + ZL + ZS) when EG = ES or takes a curvilinear path when EG is either greater of less than ES and shown in Fig. 8.5.1(b).
The detection of power swing is achieved by monitoring the rate of change of impedance or conversely the time required for the impedance locus to traverse the impedance gap between the PSB characteristic and the outermost tripping zone i.e., zone 3. if the time measured is less than the set time on timer “T”, it is considered as a power swing and blocking is applied to the selected zones (Fig. 8.5.1c).
Since power swing is a balanced 3 phase phenomena there is no residual current during a power swing. However, if a residual current is detected, as would happen during earth faults, following a power swing, power swing blocking is inhibited, using a neutral current level detector (NCD) as shown in the logic diagram, (Fig. 8.5.1d). the blocking is effective as long as the impedance locus stays within the “PSB” characteristic or until a set time delay, as required.
8.5.2 Voltage Transformer Supervision Distance relays are primarily voltage restraint relays and would tend to operate in the event of loss of V.T. supply due to say a blown off secondary fuse. The condition is therefore, required to be guarded against, to prevent undesirable operation on load. The V.T. supervision logic used in practical distance schemes is explained below (Ref. Fig. 8.5.2).
FIG. 8.5.1(a)
FIG. 8.5.1(b)
FIG.8.5.1(c ) IMPEDANCE DIAG
FIG.8.5.1: PSB LOGIC
FIG.8.5.2: VOLTAGE TRANSFORMER SUPERVISION
The VTs logic monitors either Zero Sequence of Negative sequence current and voltage at the terminal of the relay. Discrimination between a primary system fault and a blown off P.T. fuse or secondary wiring discrepancy is obtained by blocking the distance protection only when zero or negative sequence voltage is detected without the appearance of zero or negative current, as shown in the logic diagram.
When MCBs are used for controlling the VT supply, an auxiliary contact of the same is used to block the protection on operation of the MCB. This is normally done by cutting off the scheme d.c. supply through a normally open contact of the MCB.
8.5.3 Switch on to fault (SOFT) Feature As explained before, the polarizing voltage signal is required for the distance relay under all fault conditions for correct measurement and directional measurement and directional discrimination. However, the polarizing voltage signal may completely vanish for a close-up 3 phase fault. The memory polarization where provided, will certainly help to maintain the polarizing signal provided he relay has seen a prefault voltage before. However, when a dead line is energized with its earthling clamps left inadvertently in position, after a maintenance shutdown and if the associated distance protection is fed from line voltage transformers, the memory polarization also will not help for obvious reasons. To guard against such eventuality, parallel switch-on to fault (SOFT) trip logic is provided in all distance relays as standard feature, using voltage and current level detectors, as illustrated in Fig.8.5.3 (a).
The SOFT logic is enabled only after the voltage and current level detectors of all the 3 phases are in a de-energized status for a preset time interval, signifying that the line is initially dead. When the line is energized
subsequently with a close-up 3 phase fault already existing the current level detectors picking up simultaneously. The SOFT trip is thus activated after a short time delay of about 20 msec. The time delay is provided to swamp possible difference in the response time of the current FIG. 8.5.3(a): SIMPLIFIED SOTF TRIP LOGIC
FIG. 8.6.0(a): 3 STEP DISTANCE CHARACTERISTIC
(c) SIMPLIFIED SOLID STATE LOGIC And voltage level detector (the formal being faster) to permit healthy switching. Besides, current/voltage level detector, any zone comparator operation during the initial period of charging, activates SOFT trip, bypassing time delays associated with the zone 2/zone 3 comparators. 8.6
Carrier Aided Schemes The
distance
protection
covers about 80-85%
of the line in its
instantaneous first zone, the faults in the last. 15-20% being referred to the delayed zone 2. Thus for end section faults, the clearance is delayed from
the
farthest
end.
This
situation
cannot
be tolerated
in an
interconnected system for two reasons.
1.
A delayed clearance from one end may cause instability in the system.
2.
When the lines are equipped with high speed auto reclosing, a nonsimultaneous tripping would defeat auto reclosing, since there is no effective dead time to ensure de-energisation of the fault arc.
The practical distance relays are therefore, interlocked with a signalizing channel transmit information about the system conditions from one end to other end to accelerate tripping. The information transmitted can either be arranged to initiate tripping (on internal fault) of the remote circuit breaker on block tripping on external fault. The former arrangement is called as ‘transfer trip’ scheme where as latter is termed as ‘blocking’ scheme.
A typical transfer trip (under-reach) scheme logic is illustrated in Fig. 8.6.0 (a & b).
Referring to Fig.8.6.0, for fault close to end ‘B’ the relay at end B will trip in zone 1 and simultaneously initiate an inter trip signal to end ‘A’. When the signal is received at end ‘A’ and if the over-reaching zone 2 measuring
element has also operated, end ‘A’ will trip in ‘Carrier Aided Trip’ mode, resulting a near simultaneous clearance of the fault from both ends.
The different variations of carrier schemes are:
Permissive under-reach transfer trip (PUR)
Permissive over-reach transfer trip (POR)
Acceleration
Blocking
While inter-trip schemes (PUR, POR, Acceleration) are fast in operation, blocking scheme has an international delay to allow for the blocking signal to be received for an external fault. However, blocking scheme does not suffer from signal attenuation since the signal is transmitted over a healthy line unlike in case of a transfer trip scheme where the signal is transmitted on a faulty line.
-000CHAPTER –9
CURRENT AND VOLTAGE TRANSFORMER 9.1
Introduction The magnitude of current and voltage in a power circuits are usually too high to be handled by the secondary equipments like measuring instruments and relays. The i nstrument transformers are therefore, used as input devices which produce a scaled down replica of the primary input quantities within the required accuracy, for connecting the secondary equipments.
While the instrument transformers used for measurement purpose handle steady state quantities close to the rated values, those used for protection, handle fault quantities which are affected by d.c. transients, harmonic distortions etc. the performance requirements of the instrument transformers are therefore at variance depending upon their applications.
9.2
Current Transformers
9.2.1 Equivalent Circuit and vector Diagram a)
Ratio Error It is defined as the difference in magnitude of the primary and secondary current expressed as percentage of the primary current.
b)
Knxls – Ip Thus % Ratio Error =
X 100
Ip
Phase Angle This is the phase angle difference between the primary current and the reversed secondary current vector.
c)
Composite Error This is defined as the R.M.S value of the difference (Kn Is-Ip) integrated over one cycle under steady state conditions expressed as a percentage of RMS primary current. Thus,
FIG. 9.2.1
100 Composite error Eo -= Ip
I T
√
: :’ ∫
(Kn Is – Ip)2 .dt
Where T = Duration of 1 cycle. Ip, Is – Instantaneous values of primary and sec. Currents. Kn – Rated transformation ratio Ip – Primary current 9RMS)
9.2.3 Magnetizing Characteristic of CT The magnetizing characteristic of a C.T. is a plot between the secondary applied voltage and the corresponding magnetizing current taken by the C.T. as shown in Fig. 9.2.3.
The excitation curve can be divided into 4 regions. Ankle point, Linear region, knee point and saturation. The knee point is defined as a point on the excitation curve where a 10% increase in secondary EMF would cause 50% increase in the exciting current.
9.2.4 Effect of Secondary Open Circuiting The primary current of a C.T. is independent of its secondary loading. With the secondary shorted (directly or through the connected burden) the counter flux produced by the secondary keeps the core flux below the saturation level. However, if the secondary gets open circuited with the primary carrying current, the entire primary m.m.f. (ampere turns) is spent
in magnetizing the core, producing high core flux. This results in increased secondary E.M.F. with the voltage shooting up to very high value depending upon the primary current level and the working/saturation flux levels.
9.2.5 Classification of CTs There are three basic types of CTs. 1)
Measuring CTs
2)
Protection CTs
3)
Protection CTs for special Applications.
FIG. 9.2.3: MAGNETISING CHARACTERISTIC
9.2.5.1
Measuring CTs (Governed by IS 2705- 1992 Part II)
Measuring CTs are specified in terns of – Accuracy class VA Rating ISF (Instrument Security Factor) Typical Illustration : Class 1.0, VA-15, ISF-3 Standard Error Class – 0.1, 0.2, 0.5, 1.0, 3 and 5 The errors are specified between 5-120% of rated current and 25-100% of Rated burden connected. Higher errors permitted at lower currents.
Typical Illustration: Class 1.0 CT will have a ratio error of + 1% for 100120% of rated current, + 1.5% ratio error at 20% of rated current and + 3% ratio error at 5% of rated current.
9.2.5.2
Protective CTs (Governed by IS2705- 1992 Part III)
Protection CT ratings are specified in terms of class, accuracy limit factory (ALF) and VA rating.
Typical Illustration: 5P10, 15 VA Standard Error Class/AlF/VA ratings are as follows:Error Class 5P, 10P, 15P ALF 5, 10, 15, 20, 30 VA rating 5, 10, 15, 30
Errors are specified at rated current and ALF times rated current with rated burden connected.
Typical Illustration: 5P10/ 15VA CT will have a composite Error of +5% at 10 times rated current and a ratio error of + 1% at rated current with rated connected burden of 15VA.
For a given CT, VA and ALF are inversely related. For example, if connected burden is less than rated, ALF would increase.
Co-relation between ALF/VA/Output Voltage and Knee Point Voltage. Output Voltage at ALF ALF X VA VALF = ALF X IS Voltage Developed by CT at ALF ALF x VA V – (IS X RCT) X ALF + IS
Knee Point Voltage VK = 75 –80% of VALF
When Is = CT secondary Rated Current VA = Rated Burden (Volt Amps) RCT = CT secondary Resistance
While selecting 5P/ 10P class CTs for IDMT over current/Earth fault relays, following should be borne in mind.
i)
The CTs should have optimum ALF/VA Rating, so that they do not saturate up to at leas 20 time current setting. This may be achieved by selecting low burden relays or by selecting a ratio of appropriate high value.
ii)
Overrated CTs having high VA rating and ALF, may produce high secondary currents during severe faults
(in excess of 20 times
setting) that my cause thermal stressing of the relay current coils and eventual failures.
9.2.5.3
Protection CTs for Special Applications
5P/ 10P class CTs are used for Non-balanced protections like IDMT overcurrent, Earth fault relays. However, for balanced protection like circulating current differential, where balance is required between the
associated CTs with close tolerance, the characteristic requirements cannot be conveniently expressed in terms of 5P/ 10P class CTs.
For such applications, current transformers of class PS are used. These are specified in terms of-
i)
Knee point voltage (VK)
ii)
Magnetizing current (Im) usually at knee point voltage or a parentage thereof
iii)
CT secondary resistance (RCt)
For class PS, CTs, the turns ratio errors are limited to 0.25% which helps in maintaining balance between the protection systems during maximum through fault condition. Incidentally, 5P/ 10P class CTs are sometimes provided with deliberate turns ratio correction to0 maintain accuracy specified limits at ALF and hence are unsuitable for such special applications. Typical Illustration of class PS CTs specifications Ratio 100 / 1A VK >u 100 Volts Im < 30 Milliamps at VK / 2 RCT < 1.0 ohm
9.2.6 Core Balance CT (CBCT) CBCT are used for sensitive earth protections where the required sensitivity cannot be obtained using residual CT connections or by the use of CT on neutral earth connection.
In case of residual connection, the phase CTs primary rating is based on the full load rating of the circuit. Besides, the unbalance produced due to unequal errors in the phase CTs prohibits the use of very sensitive setting n the earth fault relays.
The CBCT on the contrary, are excited by the primary residual current since the core encloses all the 3 phases and hence do not have a high primary rating. Thus sensitivities down to 0.5 Amps primary or better can be obtained. When used for 4 wire systems, the CBCT core encloses the neutral, besides the phases. Thus high earth fault sensitivity can be obtained irrespective of the single phase unbalance.
Typical CBCT arrangement is shown in Fig.9.2.6. FIG. 9.2.6: CBCT
Following parameters are required to design a CBCT
Minimum Primary Earth fault current required to be detected (e.g. IA, 2A etc)
Minimum Pickup setting of the sensitive earth fault relay (e.g. 10 m Amps)
Ohmic burden of the relay at minimum pickup current. To & Fro lead resistance between CBCT and Relay Outer Diameter of the Cable (to determine CBCT Window size).
Typical Applications
Sensitive Earth fault protection of motors
Sensitive earth fault protection of non-effectively grounded systems
Sensitive earth fault protections of ungrounded system (based on unbalanced capacitive current detection).
9.2.7 Typical CT Requirements for Various Protections Some typical CT requirements are given below for general guidelines A)
High impedance circulating current different schemes. VK > 2 IF (RCT + 2RL) Volts Where RCT = CT secondary winding resistance 2RL = Two way lead resistance of the farthest CT in the parallel group IF = Maximum through current up to which relay should remain stable (referred to CT secondary)
For Transformers IF
= Maximum through fault current limited by leakage impedance of
transformers.
For Busbar IF
= Maximum through fault current limited to switchgear breaking
capacity.
For Generators IF = Maximum through fault current limited by sub transient reactance (Xd”) of the generator.
For Motors IF
= Maximum starting current (about 6 X full load current for D.O.L
Motors).
For Shunt Reactors IF = Maximum charging current of the reactor.
For Short Feeders IF = Maximum through fault current for fault at remote end busbar.
B)
Biased Differential Relay VK > K I (RCT + 2RL) Where I = Relay Rated current K = Constant specified by the manufacturer usually based on conjunctive tests. (The constant is usually chosen to ensure positive operation of highest differential unit on severe internal fault with extreme CT saturation).
C)
Distance protection
X VK > (1 + R ) ) IF (Zr +RCT + nRL)
X R
Where
= Primary system reactance/resistance ratio (To account for the d.c component of the fault current)
IF
=
Maximum CT secondary current for fault at zone 1 reach
point. Zr = Relay ohmic burden RCT = CT secondary Resistance nRl
=
Lead Resistance (one way for phase fault Since n = 1)
(two way
for earth fault since n = 2)
9.2.8 Choice of CT Secondary Rating 5A secondary i)
Preferred where lead burden is insignificant (e.g. CTs used in Indoor switchgear cubicles with closely located relays OR where primary ratings are very high say 10,000/5A).
ii)
Comparatively low peak voltage when secondary gets open.
iii)
Fine turns ratio adjustment is not possible when primary ratings is low particularly for Bar primary CTs (e.g. 25/5A).
IA Secondary
9.3
i)
Preferred when CTs are out door and lead burdens are high.
ii)
Comparatively high peak voltage when secondary is open.
iii)
Fine turns ratio adjustment possible.
Voltage Transformers
9.3.1 Equivalent circuit and Vector Diagram The equivalent circuit and vector diagram of a voltage transformer are Shown in Fig. 9.3.1(a), (b).
9.3.2 V.T. Errors Ratio Error: Ratio error is defined as –
Kn.Vs-Vp Vp
% Ratio Error =
X 100
Where Kn = Nominal Ratio of V.T. Phase Angle Error: (θ ) Phase angle error is the phase difference between the reversed secondary output voltage (-Vs) and the primary applied voltage (Vp). 9.3.3 Voltage Transformer Classification There are 3 types of VTs i)
Metering VTs
ii)
Protection VTs
iii)
Residual VTs The VTs are usually specified in terms of -
Voltage Ratio
-
Accuracy Class
-
Rated VA Burden
-
Rated Voltage factor
Typical Illustration 11KV /√3 V, 110/ √3 V, class 1.0, VA 50 VF – 1.2 continuous / 1.5 for 30 seconds.
FIG. 9.3.1
9.3.3.1
Metering VTs (Governed by IS3156 Part II-1992) Control 0.1 0.2
% Ratio Error +0.1 +0.2
Phase Angle Error (Minutes) +5 +10
Reference Conditions Voltage 80 – 120% Burden 25 – 100%
+0.5 +1.0 +3.0
0.5 1.0 3.0
9.3.3.2
% Ratio Error +3% +6%
3P 6P
Phase Angle Error(Minutes) +120 +240
Reference Conditions Voltage 5% to Voltage Factor times rated voltage Burden 25 – 100% P.F.0.8 Lag Frequency -Rated
Protection VTs (Governed by IS3156 Part III-1992) Clas s
% Ratio Error + 5% + 10%
5 PR 10
3.4
P.F. 0.8 Lag Frequency - Rat
Protection VTs (Governed by IS3156 Part II-1992) Class
9.3.3.3
+20 +40 Not Specified
Phase Angle Error(Minutes ) + 200 --
Reference Conditions Voltage 5% to Voltage Factor times rated voltage Burden 25 –100% Frequency –Rated P.F. 0.8 lab.
Rated voltage Factor (Is3156 Part 1-1992) Sl.N o. 1
2.
System Earthling Effectively Earthed
Rated Voltage Factor 1.2 1.5
Rated Time Continuous 30 Seconds
1.2 1.9
Continuous 30 seconds
1.2 1.9
Continuous 8 Hours
Non-Effectively earthed system (with Automatic Earth fault tripping)
3. Isolated Neutral or Resonant Earthed system (without Automatic Earth fault tripping)
VTs used in no-effectively earthed systems have voltage factor since in the event of an earth fault in one of the phases, the healthy phase voltage may rise to phase to phase value (i.e. √3 times phase to neutral voltage) as shown in Fig. 9.3.4.
FIG. 9.3.4 FIG. 9.3.5.3: STAR/OPEN DELTA CONNECTION
9.3.4 V.T. Connections
There are 3 types of connections 1.
V-V
2.
Star/Star
3.
Star/ Open delta
9.3.5.1
V-V Connection
This connections is generally used for measurement and for those protections which do not require phase to neutral voltage input (2 V.Ts are used). Primary of the V.Ts is connected in V. (i.e. one V.T. primary across R-Y phases and the other across Y- B phases), with identical V. connection for the secondary. In this connection zero sequence voltage cannot be produced.
9.3.5.2
Star-Star connection
Either 3 separate single phase VTs or a single 3 phase, 3 limb VT is used. Both primary and secondaries are connected in star with both star neutrals solidity grounded. Each primary phase limb is thus connected between phase to earth of the supply circuit ad replicated similar phase to earth voltage on the secondary.
Star/Star connection enables both phase to phase as well as phase to neutral distribution of the connected burdens. 9.3.5.3
Star/Open Delta Connection
The primary windings, are connected in star with star neutral solidly grounded and the secondaries are connected in series to form an open delta connection as shown in Fig. 9.5.3. This type of connection is called residual connection and requires either 3x single phase VTs or a suitable 3 phase 5 limb VT.
The residual connection is used for polarizing directional earth fault relays or for earth fault detection I non-effectively grounded or isolated neutral system.
-000-
CHAPTER –10 DIGITAL RELAYING 10.0. Introduction Protection scheme basically consists of protective relay and circuit breaker (i.e. Switching Circuit). Out of these two, protection relay plays an important role and therefore, it is known as brain behind the above scheme. It is the relay which senses the fault, determines the location of the fault and then sends tripping command to the proper Circuit Breaker by closing its trip coil. There has been continuous development and improvement in the theory, design ad operating principle of the protection scheme. From electromechanical relay of induction type in the beginning now we have digital relaying scheme using on-line microprocessor / mini computer. The idea being to develop a relay having.
1. Less Burden : (If the burden of a C.T. is high, its magnetic core gets saturated, result being secondary O/P is not linearly proportional to primary quantity and relay may maloperate).
2. High Speed : (If the fault is cleared quickly, not only the transient stability limit of the system is improved but also permanent damage to the equipment is avoided. Risk of fire or risk to the personnel is avoided).
Hence, during 1960 with the advent of digital computer, digital relaying becomes a reality, by developing several algorithm to realize different protection function using digital computer. But because of large size and cost of the computer only software package to realize different protection scheme
were
microprocessor
developed. and
During
early
mini-computer,
1986, with
digital
relaying
the using
arrival on
of line
microprocessor/mini computers were developed. These relaying schemes have several merits like
Lower Burden
Much faster in operation
No contact problem
Much less maintenance
Data Acquisition capabilities
Multi-protection functions using standard hardware
These relays do not operate due to external causes.
These schemes are highly flexible (by simple software programme, relay setting and characteristic can be changed)
Possesses self-checking facilities.
Digital relaying scheme is being proposed for the entire components of electric power system and apparatus viz. synchronous machines, bus-bar, transformer, feeder, EHV/ UHV transmission lines (Fig. 10.1 (a).
10.1
Application along with basic circuit a)
Differential Protection for Generator In which current entering a phase winding is compared with current leaving the same phase winding at the other end either in phase or in magnitude.
I 1 + I 2 2
For tripping I1 – I2) > S
To
realize
differential
protection
using
microprocessor/mini
computer, a sample and hold circuit is used where a definite number of signal samples are chosen per cycle and fed to microprocessor or mini computer which has a programme to detect abnormal condition in the memory and issue a trip signal (Ref.Fig.10.1 (b).
For differential protection, In the memory of microprocessor, with the help of a software programme second harmonic content of the sample current is obtained. The presence of second harmonic content above a threshold value is an indication of an inrush condition. b)
Stator Earth Fault Stator Earth Fault can be determined in the same way. With the help of Current Transformers connected in each phase winding the armature current is monitored. In the microprocessor, these currents are transformed to the sequence currents and because of the different component current, type of fault can be determined.
FIG. 10.1(a): AN EXAMPLE OF DEGITAL RELAYING OF GENERATOR
FIG. 10.1(b): BLOCK DIAGRAM
FIG. 10.2: FLOW CHART
e.g.
1
If I1 = I2 =I0
→
G fault
2
If I1 = I2, I0 = 0
→
L.L.fault
3
If I1 = I2 + I0 =0
4
If only I1 > threshold & -> I2 =I0 = 0 → 3 phase fault
→
LLG fault
In conventional differential protection of a transformer having taps on the windings, biasing is provided to take care of CT mismatch, CT errors under dynamic conditions and at different tap position. Because of this biasing relay remains insensitive for low level winding fault.
In digital differential scheme, (Flow Chart of the programme stored in the memory of CPU) (Fig. 10.2), CT mismatch errors at each tap is precalculated and a correction factor is calculated to be applied to CT secondary currents to get true line currents. These correction factors for all the taps are stored in the digital relay memory and transformer tap position is also monitored so that relay sensitivity remains same on all tap position.
Id1
=
Power frequency component of differential current
It1
=
Power frequency component of the through current
I0
=
Pick up current
B
=
Bias
Relay operates, if Id1 > I0 and Id1 > B, It1 . To restrain relay from operation in case of magnetizing in rush (when primary is charged and secondary open circuit)
HRF (Harmonic Restraint
Factor) is calculated. If HRF is more than threshold, relay operation is restrained. Where
HRF
=
(II
harmonic component + V Harmonic component)/
Fundamental frequency Component).
In case magnetizing inrush II and V Harmonic Content is more (16%). Thus, digital differential relays has high speed and sensitivity for internal faults and stability on heavy through fault and magnetizing inrush.
FIG. 10.3: SCHEMATIC OF PC BASED RELAY TEST BENCH
10.2
PC based schemes for testing protective relays Digital relays an be tested with a personal computer. The benefits are: 1. Respective test sequences in less time 2. Signals simulation with any desired level of harmonic and d.c. distortions
accurately and
of different
frequencies
than supply
frequency. 3. Transient signals can be simulated easily. 4. Flexibility and ease of programming 5. Accurate and realistic testing of relays
The scheme is as shown in Fig. 10.3 A PC AT 386/486 computes, the sample corresponding to the instantaneous values of the test signals (Digital) which is supplied to Digital to Analog Converter (DAC) with interrupt occurring at the end of inter sample interval. The number of sample per cycle can be 12, 16, 24, 36, 60. The DAC output waveform is a stepped waveform with stepped waves with number of steps = number of sample selected per cycle. These waveforms are smoothened and undesired harmonics are filtered out. Then waveforms are amplified by power amplifiers to generate relay test signals with necessary test levels.
PC has Menu Driven Software; Viz. a) Calibration Menu b) Relay Selectio0n Menu c) Type of test selection Relay test programme is stored in CPU of PC and computer monitor the relay trip status. After the test CPU generate relay characteristic plots.
10.3
Testing of a Distance Relay a) Steady State Test The main objective of the test is to obtain the trip characteristic of the relay for different reach setting as well as for different types of faults like phase to ground fault and phase to phase fault.
The relay reach is set to desired value. Test starts by simulating voltage and current signals with phase difference equal to zero between V & I of selected phases for which fault is to be simulated. The current signals of the faulty phases and voltage signals of the healthy phases are maintained at rated value. Then voltage signals of the selected faulty phases are decreased in steps till relay operates. At this point, computer holds the present value of fault voltage, current signals and phase difference V between them and Z =
∠ ϕI is calculated and signals are again
applied to the relay and operating time is determined. Testing is repeated with different phase angles. All the values of R, X & ϕ are displayed on the monitor and also stored in the data file.
b) Dynamic Test The objective is to determine the accuracy of the relay under transient fault conditions. Transient data sample (voltage and current) are obtained from off-line analysis of power system model and stored in the memory (e.g. 16 sample/cycle). These transient data signals are applied to the relay and its accuracy is checked. Transient test data consists of voltage and current of steady state prefault sample, fault transient and few cycles of post fault steady state sample.
These PC based programmable relay test scheme is intended for off-line testing of various protection equipments.
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REFERENCES 1.
Modern Power Station Practice Vol.4
2.
Maharashtra State Electricity Board, Power System Protection.
3.
Protection System – NTPC Publication
