power grid protection - nebula.wsimg.com

Page | 0

October 22, 2013

Submitted by: Mihnathul Munthaha Neerulpan

Student ID# 999495810

Power Grid Protection

Index Page

1 Transformer Protection 1

2 Generator Protection 7

3 Motor Protection 12

4 Transmission Line Protection 15

5 Bus Protection 24

6 Appendix 27

7 References 30

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Here we are going to discuss the principles of basic protection schemes for main

components (equipment)-Transformer, Generator, Motor, Line and Bus bar- in the power

grid. (A.C system)

1. Transformer Protection

Condition Protection

Internal

Winding phase-phase

Phase-ground fault

87T(differential)

51,51N(overcurrent)

87RGF(restricted ground fault)

Winding inter-turn fault 87T,

Buchholz relay

Core insulation failure, shorted

lamination

87T ,

Buchholz relay,

Tan fault 87T,

Buchholz relay and tank ground

protection relay

Over fluxing 24(volt/Hz)

External

Overload 49(thermal)

Overvoltage 59(overvoltage)

External system short circuit 51,51G(time overcurrent

50,50G(Instantaneous overcurrent)

Major Protection Schemes for Transformers

Differential protection

o Modified/Percentage/Biased/ differential protection

Overcurrent protection

Zero sequence over current protection

Ground fault protection

Thermal protection

Over fluxing protection

1.1 Transformer Differential Protection Scheme

It is based on the fact that any fault within electrical equipment would cause the

current entering it to be different from the current leaving it. Hence it works for internal

faults only.

Simple representation of a differential protection scheme is sown in Fig.1.1. If there

is an internal fault, the CT secondary currents are not matched and hence the differential

current is not zero. This causes the overcurrent element to pick up and operate the

circuit breakers to isolate the transformer. If there is no internal fault in the transformer,

zero current flows through the differential overcurrent element.

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Fig.1.1Simple representation of differential protection scheme of transformers.

Let a transformer with turn ratio is to be protected, In order to compare the

measured primary and secondary currents of the transformer CT must have matched turn ratio.

Let’s find the relation between transformer and CT turn ratio. Considering Fig.1.1,

Transformer turns ratio given by

The corresponding CT ratio given by

Then, Current in CT- 1 primary

Current in CT- 1 secondary =

Current in CT- 2 primary =

Current in CT- 2 secondary

If there is no fault, then with proper connections account for the CT polarity, we should

obtain circulatory current through CT secondary (i.e. current measured at primary of first CT and

secondary of second CT must be same).

Hence

1.1.2. Percentage/Biased/Modified Differential Protection

Differential protection discussed above has the following challenges.

The primary of transformer will carry no load current even when the secondary is open

circuited. This will lead to differential current.

It is not possible to exactly match the CT’s, this will also lead to differential currents

under healthy conditions.

To prevent the differential protection for picking up under such conditions, a percentage

differential protection scheme is used, in which a second coil known as restraining coil is also

there. This restraining coil makes the relay restrain from the small currents such as no load

current, differential current due to CT mismatch etc. Fig. 1.2 (a) shows the fundamental armature

- coils arrangement of the differential relay. Now let’s find the operating condition for this relay.

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Fig.1.2. Percentage differential relay

Ampere-turns acting on the left-hand section of the restraining coil =

Ampere-turns acting on the right-hand section of the restraining coil =

Total ampere-turns acting on the restraining coil =

We have flux,

Noting that torque in an electromagnetic relay is proportional to the square of the flux, Torque

produced by the restraining coil = [

]

Where M is a constant of proportionality.

Restraining torque produced by control spring =

Total restraining torque, [

]

Similarly, operating torque is due to the current (or flux) through he operating coil and is given

by, [ ]

The relay trips if the operating torque is greater than the restraining torque.

i.e. when: [ ] [

]

(neglecting the restraining torque due to spring)

This can be written as

Where

Where accounts for the effect of spring.

i.e. The relay operates when:

Fig1.3 shows the percentage differential protection scheme for a three phase

transformer. Connect Δ side CT’s in Y and, the Y side CT’s in Δ. By doing so, the zero sequence

currents would be restricted within the CT Δ on the LV side and within the main winding Δ on

the HV side. Thus no zero sequence would flow through the restraint winding and the balance

maintained.

If the CT’s are connected as shown in fig.1.3, during normal operation , currents in the

restraint windings(R) are equal, such that there is no current in the operating winding(Op) of any

relay. Equating the current in the restraint windings we get the restraint on the various system

ratios as

√

√

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Fig.1.3Percenage Differential Protection of three phase

transformer

1.2 Transformer Overcurrent Protection

This scheme uses both magnitude and phase angle of current for decision making. They

are commonly used for protection from phase and ground faults. Figure 1.4 shows two numbers

of phase-fault over-current relays and one ground-fault over-current relay for providing over-

current protection to the star-delta transformer. Such a scheme may serve the purpose of

providing either the primary protection for smaller transformers or the back-up protection for

bigger transformers

The pick-up value of the phase-fault over-current units is set such that they do not pick up

on maximum permissible overload, but are sensitive enough to pick up on the smallest phase

fault. The pick-up of the earth fault relay, on the other hand, is independent of the loading of the

transformer. The neutral current under load conditions is quite small. The neutral current is

essentially because of load unbalance.

Fig.1.4 Over current protection

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1.3 Zero sequence over current protection

To obtain sensitive ground fault detection, use a relay that responds only to the zero-

sequence current of the system (since zero sequence current generates only during a fault related

to ground). A zero-sequence overcurrent relay simply measures the sum of the three phase

currents, as given in Equation 1.4. Unbalanced faults involving ground, such as phase-to-ground

(L-G) or phase-to-phase-to-ground (L-L-G) faults cause zero-sequence current, also referred to as

ground or residual current. CT connection configurations and the neutral current of a delta-

grounded wye transformer are additional sources of zero sequence current. Set zero-sequence

overcurrent elements at very sensitive levels (i.e. a low pickup setting) because the zero-sequence

current generated under load conditions is typically small compared to load currents.

Zero sequence current is given by,

1.4 Ground fault Protection of transformers

Ground fault protection of transformers can be archived either differential relays or

overcurrent relays. The exact relay selection and connection depends on the type of transformer

bank.

Fig.1.5 Over current (delta) and differential (wye) ground fault protection for a delta-wye transformer

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1.5 Thermal Protection

Fig. 1.6 Transformer Thermal Protections

1.6 Over fluxing protection

The flux and the applied voltage in a transformer are related through the following expression

Where

V is the r.m.s value of the voltage

f is the frequency

N is the number of turns in the winding.

Thus, we can write the flux as

Whenever there is an over-voltage (frequency remaining constant), the transformer core is

subjected to a higher value of flux in order to be able to support the higher applied voltage. By

design, transformers operate at the knee of the saturation curve at normal voltage. Hence, any

increase in applied voltage, and the consequent increase in flux density, drives the transformer

deeper into saturation. The transformer, therefore, draws an excessive magnetization current.

Hence, this condition is described as over excitation. This, considerably, increases the core losses

giving rise to overheating of the transformer. Further, saturation of the core causes the flux to

flow into adjacent structures, causing high eddy current losses in the core and adjacent

conducting materials. Such an operating condition cannot be allowed to continue for long and the

transformer should be tripped if there is a prolonged over-excitation. It can be easily seen that

over-excitation can also occur in case of low-frequency operation of the transformer at rated

voltage.

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Fig.1.7 Typical protection of a 750KVAtransformer

In fig.1.7, 87T differential, 86-Lockout auxillary,50/51 Overcurrent and short circuit,

50G ground fault, 67 Directional overcurrent, V,S Voltage and power metering

2. Generator Protection

Conditions Protection

Internal Fault

Stator Phase fault 87G( Generator Differential)

Stator ground fault

87N(ground differential)

51N(Neutral over current)

59N(ground overvoltage)

27-3N(third harmonic under voltage)

Ground faults in the rotor -field winding 64F( detection of generator field ground)

Abnormal operating


Over excitation Overvoltage 24(volts/Hz),

59( over voltage)

Loss of field

40Q (Protection for failure of the

excitation system -Reactance based)

40Z (Protection for failure of the

excitation system -Impedance based)

Unbalanced operation ( Single phasing)

(46)

46( unbalance current )

47 (unbalance voltage )

Under and over frequency (81O/81U) 81U(under frequency)

81O(over frequency)

Loss of synchronization-out of step 78(out of step or pole slip)

25(synchronism check when paralleling)

Motoring or loss of prime move 32R (Reverse power-anti-motoring)

Inadvertent energizing 50/27

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Generator Protection Schemes

Differential Protection Scheme

Modified Differential Protection/Percentage differential protection

High impedance differential protection

Self-balancing differential protection

Restricted or balanced earth fault

Negative phase sequence

High impedance Protection

Self-balancing Protection

Inadvertent energizing protection

2.1Differential Protection scheme

The differential protection principle is same as explained earlier for transformer

protection. Differential scheme protection to three phase alternator winding is shown in fig.2.1

Fig.2.1 Differential scheme Protection to three-phase alternator winding

2.2 High Impedance Protection

This is another type differential relay, here we keep high impedance coils and hence the

actuating quantity is voltage instead of current. The relay discriminated between internal and

external faults by the voltage that appear that across the relay. On external faults the voltage

across the relay will be low, while for internal faults the voltage across the relay is relatively

high.

This scheme has higher sensitivity than the percentage differential relay, and thus may be

more susceptible to disoperation caused by proximity effects.

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Fig.2.2 High impedance differential

2.3 Self balancing Protection scheme

The self-balancing differential scheme has been used for phase and ground faults on small

generators with low-resistance neutral grounding. As shown in fig.2.3, leads from both ends of

the phase winding are placed in the opening of a window-type CT. Any difference between the

currents entering and leaving the winding is detected by an instantaneous overcurrent (IOC)

relay.

Fig.2.3 Self balancing Protection

2.4 Restricted or balanced earth fault protection

In case of small size generator the neutral end of 3 phase winding is not available because

it is made inside the generator and grounded through some low resistance then percentage

differential relay for ground fault is provided and is known as restricted earth fault protection.

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Fig.2.4 Restricted earth fault protection

2.5 Negative phase sequence protection

Unbalance may cause due to single phase fault or unbalanced loading and it gives rise to

negative sequence current. This current in rotor causes rotor overheating and damage to the rotor.

This can be protected by negative sequence current filter- which will detect only negative

sequence current that creates during the unbalance condition- with over current relay.

Fig.2.5 Generator protection against unbalanced loading using negative sequence filter

2.6 Inadvertent Energizing Protection

Inadvertent energizing is the accidental energizing of generators when they are off-line.

Operating errors, breaker head flashovers, control circuit malfunctions, or a combination of these

causes’ results in generators being accidentally energized while off-line. Unlike conventional

protection systems that provide protection when equipment is in service, these schemes provide

protection when equipment is out of service. The most widely used dedicated protection systems

used to detect inadvertent energizing include:

a) Directional overcurrent relays

b) Frequency supervised overcurrent

c) Distance relay scheme

d) Voltage supervised overcurrent

e) Auxiliary contacts scheme with overcurrent relays

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2.7 Multi-function generator protection systems As of now we discussed about the basics of each protection scheme individually. While

implementation, generally we use multiple protection schemes together to form a multi-function

protection system.Fig.2.7 shows the typical protection of a large generator.

Fig.2.7 Typical protection for a large or important generator

In most cases, new generators are being protected with either dual multifunction generator

protection systems (MGPS) or a single multifunction generator protection, possibly backed up by

some single function relays.

Figure 2.7 shows the block diagram of a typical MGPS. The MGPS has analog inputs

(voltage and current signals), digital inputs, and digital outputs for sending trip and alarm signals.

The MGPS may also have bi directional communication ports, which may be RS-232, RS-485,

fiber optic, or some other hardware interface for communicating with the external world. Internal

hardware consists of an analog data acquisition system that includes signal scaling, isolation,

filtering (anti-aliasing) analog multiplexing, and analog-to-digital conversion. The digital

subsystem consists of a microprocessor, read only memory (ROM) for program storage, random-

access memory (RAM) for temporary storage of information, and electrically erasable

programmable memory (EEPROM) for storage of set points. The functional operation and

performance of the MGPS are determined by both hardware and software programs.

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Fig.2.7.diagram of a typical MGPS

3. Motor Protection

Conditions Protection

Internal Fault

Phase fault 87S( Stator Differential)

Ground fault

87N(ground differential)

51N(Neutral over current)

59N(ground overvoltage)

27-3N(third harmonic under voltage)

Abnormal operating


Over voltage 24(volts/Hz),

59P( Phase over voltage)

59X (Auxiliary Overvoltage)

Under voltage 27P Phase under voltage

Loss of Load or under current 37

Unbalanced operation ( Single phasing)

46( unbalance current )

47 (unbalance voltage )

Under and over frequency (81O/81U) 81U(under frequency)

81O(over frequency)

Extended start (accelerating time) 48 (incomplete sequence)

Loss of supply 56 (field application )

Stalling (mechanical Jamming/Jogging)

Motor protection schemes can be easily compared with that of generator.

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Major Protection scheme for motors are:

Differential protection

Extended start time protection

Ground fault

Unbalance

Reduction in supply voltage

Over voltage protection

Under voltage protection

3.1 Differential Protection

Principle is same as explained earlier for transformer protection. Differential protection

may be considered the first line of protection for internal phase-to-phase or phase-to-ground

faults.

Fig.3.1 Differential protection scheme for a 3 phase induction motor

3.2 Extended start time protection

The relay function protects the motor from overheating in case of abnormal loading during

motor starts. The motor can be tripped if the motor does no reach a running condition within the

programmable motor acceleration time.

3.3 Protection against Unbalance

Unbalanced currents give rise to a negative sequence component in the stator current. The

negative sequence current produces an additional flux which rotates at synchronous speed in the

opposite direction of the rotor. The eddy currents which are induced in the rotor parts will have

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the double network frequency. During such sustained conditions, the temperature of the rotor

may reach high levels which accelerate the ageing of the insulation and cause mechanical stress

on the rotating components. The relay calculates negative sequence current and compares it with

the set operate value for the trip function.

Fig.3.2 Negative sequence voltage relay for protection against unbalance in supply voltage.

3.4 Reduction in Supply Voltage

The torque developed by an induction motor is proportional to the square of the applied

voltage as given in Eq.3.1. Therefore, any small reduction in voltage has a marked effect on the

developed torque. The reduced torque may cause the motors to lose speed and draw more current.

Large motors should be disconnected when a severe low voltage condition persists for more than

a few seconds. Under-voltage relays are used for protection against reduced supply voltage.

Torque,

Where is the slip

is rotor resistance

is rotor reactance

rotor induced e.m.f

stator voltage/supply voltage

3.5 Overvoltage Protection

The overall result of an overvoltage condition is a decrease in load current and poor power

factor. Although old motors had robust design, new motors are designed close to saturation point

for better utilization of core materials and increasing the V/Hz ratio cause saturation of air gap

flux leading to motor heating.

3.6 Under voltage Protection

The overall result of an under voltage condition is an increase in current and motor heating

and a reduction in overall motor performance. The under voltage protection element can be

thought of as backup protection for the thermal overload element. In some cases, if an under

voltage condition exists it may be desirable to trip the motor faster than thermal overload

element. Motors that are connected to the same source/bus may experience a temporary under

voltage, when one of motors starts. To override this temporary voltage sags, a time delay set

point should be set greater than the motor starting time.

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4. Transmission Line Protection

Major Fault Types for transmission line:

Single line-to-ground (85%)

Line-to-line (8%)

Three Phase (2%)

Line-to-line-to-ground (5%)

Based on communication transmission line protection can be broadly divided into two

Pilot aided schemes : Communication between distance relay is needed

Non-pilot aided schemes(step distance): No communication between distance relays

General Protection Schemes for Transmission Lines:

Overcurrent

Directional overcurrent

Zero sequence over current protection

Distance

o Reactance

o Impedance

o Mho

o Quadrilateral

Line current differential

Phase comparison

Stepped time/distance protection scheme

Directional Comparison Blocking(DCB)

Permissive Overreach transfer trip(POTT)

4.1Overcurrent Protection

Overcurrent protection is the simplest and least expensive form of fault protection that can

be placed on transmission lines. This operates using magnitude of current. The ac connections for

three-phase and one ground time overcurrent (TOC) relays and instantaneous overcurrent (IOC)

relays are shown in fig.4.1.

Fig.4.1 Connections for overcurrent phase and ground relay

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Operating condition of torque can be derived from Universal torque Equation (Eq.4.3).Spring

torque is the restraining torque and current coil produces the operating torque. Solving to the

balance point (zero torque) in Eq.4.1, determines the trip current (pickup current)

√

The plug-setting multiplier, PSM

Where the current through the relay operating coil and is the plug-setting of the

relay. The value of PSM tells us about the severity of the current as seen by the relay. A PSM

less than 1 means that normal load current is flowing. At PSM > 1, the relay is supposed to pick

up. Higher values of PSM indicate how serious the fault is.

4.1.2Directional overcurrent Protection

Relay responds to overcurrent condition in the forward direction only (device 67, 67N,

67NT) will not respond to reverse faults.

Fig.4.2.Directional overcurrent protection

Fig.4.3 Directional overcurrent protection representation

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In fig.4.3, for the given fault relay 101A,102A and !04A operates. Relay 103A does not operate

as the direction of current is still the same for that relay.

4.2Distance Protection Scheme

The basic principle is that the apparent impedance seen by the relay reduces drastically in

case of line fault (or during fault on a line, the current rises significantly and the voltage collapses

significantly). If the ratio of apparent impedance to the positive sequence impedance is less than

unity, it indicates a fault.

There are three types of distance relays as given below which are applied to long lines, short lines

and medium lines respectively.

o Reactance

o Impedance

o Mho

Distance protection scheme is inherently directional

Fig.4.4 Distance relay

The Universal relay torque equation:

| | | |

| |

Where,

Operating characteristics of all relay can be explained using this.

4.2.1Impedance Relay

Operating torque is produced by current coil, | |

Restraining torque is produced by voltage coil, | |

In order to operate the relay,

Page | 20

Fig.4.7 Mho relay characteristics

4.2.4 Quadrilateral relay

Quadrilateral relay combines the advantage of reactance with directional relay and

resistive reach control. It is applied for earth fault protection of short and medium lines where

high fault resistance tolerance is required

Fig.4.8 Quadrilateral relay characteristics

4.3 Out-of-step Protection

Out-of-Step (OOS) (unstable power swing phenomena), causes uncontrolled tripping of

circuit, as the apparent impedance during power swings can enter into the reach of distance relays

If the apparent impedance stays longer than the time delay in a given zone, that distance element

will trip as for a fault. To prevent such tripping, out-of-step blocking schemes are employed. In

fig.4.9 If the timer expires between the two zones, out-of-step condition is declared and selected

distance elements are blocked.

As we know stable power swings are not dangerous and we need to differentiate stable from

unstable power swings. So this is also taken into account of out-of-step trip function by this.

Page | 21

Fig.4.9 out of step blocking distance scheme.

.

4.4 Differential and biased differential Protection of Transmission Lines

Biased-differential elements compare an operating current with a restraint current as

explained earlier.

Fig.4.10 Differential Relay Operating Characteristics

In fig. 3.8,

4.5 Phase comparison relaying

This relay compares the relative phase angles between two currents. It is used to determine

the current direction with respect to reference quantity. For Example In a normal/balanced power

flow, the phase angle between voltage and current (power factor angle) is 30⁰.When power flows

in opposite direction, then the angle will be 180⁰-30⁰.i.e.For fault in forward or reverse direction,

the phase angle of current with respect to voltage is –Φ or 180⁰-Φ.

Where Φ is the impedance/power factor angle.

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Fig.4.11Basic Phase comparison operation

Fig.4.11 shows the phase comparison operation, clearly for external/through fault the direction of

current flow reverses by 1800.

4.6 Time stepped distance protection(Non-pilot) scheme

Conventional time-stepped distance protection is illustrated in Figure 4.12. One of the

main disadvantages of this scheme is that the instantaneous Zone 1protection at each end of the

protected line cannot be set to cover the whole of the line length and is usually set to about 80%.

This leaves two 'end zones', each being about 20% of the protected line length. Faults in these

zones are cleared in Zone 1 time by the protection at one end of the line and in Zone 2 time (with

a time lag) by the protection at the other end of the line.

Each zone characteristics is listed below:

Zone 1: Trips with no intentional time delay.Underreaches to avoid unnecessary operation

for faults beyond remote terminal. Typical reach setting range 80-90% of ZL

Zone 2: Set to protect remainder of line. Overreaches into adjacent line/equipment.

Minimum reach setting 120% of ZL.Typically time delayed by 15-30 cycles

Zone 3: Remote backup for relay/station failures at remote terminal. Reaches beyond ZL

(reaches nearest line/ equipment)

Page | 23

Fig.4.12 Conventional stepped time distance scheme

4.7 Permissive Overreaching Transfer Trip (POTT)

POTT schemes implement the logic shown in Figure 4.13. Since the Zone 2 trip output

requires an enable from a receiver output (permissive signal), the scheme is considered a tripping

scheme. This improves performance speed for faults detected by Zone 2 elements because the

relay operates as soon as an enabling signal is received for the remote terminal.

Fig.4.13.POTT Tripping Logic

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5. Bus Protection

Major Bus Protection schemes

Differential

Bus bar blocking

Fault bus

5.1Differential Protection The principle is same as explained earlier. This requires sectionalizing the bus bars into different

zones

Fig.4.1 Differential protection for Bus bars

For fig.4.1, For External Fault

and For Internal Fault,

Fig.4.2 Differential Protection-Double bus double breaker

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5.2 Bus bar blocking scheme

It’s a very low cost and simple scheme. Blocking scheme covers phase and earth faults and gives

adequate sensitivity – independent of no. of circuits. No additional CTs required. But it is only

suitable for simple bus bars and sensitivity is limited by load current.

Fig.4.3 Simple blocking scheme for a single bus with a single source

5.3 Fault Bus relay scheme

This scheme requires isolating the bus support structure from ground and grounding this

structure through a single-point ground and CT.

Page | 26

Fig.4.4Fault bus relay scheme

Page | 27

Appendix

A.1 Sequence Voltages and currents [12]

Symmetrical components are used to simplify analysis of unbalanced three phase power

systems under both normal and abnormal conditions.

A system of three unbalanced phasors can be resolved in the following three symmetrical

components:

Positive Sequence: A balanced three-phase system with the same phase sequence as the

original sequence.(abc,bca,cab)

Negative sequence: A balanced three-phase system with the opposite phase sequence as

the original sequence.(acb,bac,cba)

Zero Sequence: Three phasors that are equal in magnitude and phase

Fig.A.1 representation of (a) an unbalanced network, its (b) positive sequence(c) negative sequence (d) zero

sequence

Define Then,

[

] [

] [

]

Similarly,

[

] [

] [

]

A.2 Transmission Line Classification

Various protection schemes are applied to transmission line based on its length, nominal

voltage etc. Transmission lines are classified as follows depending on their source to line

impedance (SIR) ratio:

1. Short line SIR>4

2. Medium line 0.5<SIR<4

3. Long line SIR<0.5

A.3 Directional comparison Scheme

The idea behind this scheme is to obtain the response of the distance relay element at other

end to speed decision making (i.e. it overcomes the disadvantages of stepped distance protection

scheme). This scheme requires additional communication signals and it can quickly clear the

Page | 28

fault anywhere on the primary line. In this underreaching function, overreaching function,

blocking functions etc. are implemented for different zones using logic gates and IC’s to ensure

full protection of the line as well as high speed tripping. The primary difference between the

various directional comparison schemes is the way in which the relays use the information from

the other terminal.

Commonly used directional comparison schemes are:

1. Permissive Overreaching Transfer Trip (POTT)

2. Permissive Underreaching Transfer Trip (PUTT)

3. Directional Comparison Blocking (DCB)

4. Directional Comparison Unblocking (DCUB)

5. Direct Underreaching Transfer Trip (DUTT)

6. Direct Transfer Trip (DTT)

A.4 Communication systems typically used for protective relaying include:

Fiber optic (FO)

Pilot-wire 50, 60 Hz (PW)

Pilot-wire audio tones (AT)

Power line carrier (PLC)

Microwave (MW)

Point-to-point radio (R)

A.5 Power swing

Power swing is caused by the large disturbances in the power system, which can cause the

change in load impedance within the relay’s operating characteristic, to induce unwanted relay

operations at different network locations. These undesirable measurements may aggravate the

power-system disturbance and cause major power outages, or even power blackout. Particularly,

distance relays should not trip unexpectedly during dynamic system conditions such as stable

unstable power swings, and allow the power system to return to a stable operating condition.

Thereby, a Power Swing Block (PSB) function is adopted in modern relays to prevent unwanted

distance relay element operation during power swing. The main purpose of the PSB function is to

differentiate between power faults and power swings, and block distance or other relay elements

from operations during a stable power swing.

Fig.A.5 shows the reactance (resistance is neglected) variation (more curves if there are

more number of parallel lines) during swing. If the area 1 and area 2 are equal which implies a

stable power swing, it can go back to normal operating condition after the opening of CB with

the old or new impedance.

Fig.A.5. One-line diagram of a two source transmission line and power angle curve

Page | 29

Electrical power transmitted from source to receiver is given by the power transfer equation,

Where:

is sending end voltage

is receiving end voltage

is the angle by which leads by

is the total reactance between the sending end and receiving end voltages ( )

With fixed values of , relationship between can be described in the power

angle curve as shown in fig.4.(b) ( more in ref.12)

A.5 Blinders

Blinders limit the operation of distance relays (quad or mho) to a narrow region that

parallels and encompasses the protected line. Applied to long transmission lines, where mho

settings are large enough to pick up on maximum load or minor system swings.

Page | 30

References 1. IEEE Std C37.2-2008, IEEE Standard for Electrical Power System Device Function

Numbers, Acronyms, and Contact Designations

2. IEEE Std C37.91-2008, IEEE Guide for Protecting Power Transformers.

3. IEEE Std C37.102-2006, IEEE Guide for AC Generator Protection

4. IEEE Std C37.113-1999, IEEE Guide for Protective Relay Applications to Transmission

Lines

5. IEEE Std C37.234-2009, IEEE Guide for Protective Relay Applications to Power System

Buses

6. Electric Power Distribution Systems Operations, NAVFAC MO-201,April 1990

7. Y.G.Paithankar,S.R.Bhide, ‘Fundamentals of Power System Protection’,(Prentice Hall of

India),2003.

8. C.L.Wadhwa, ‘Electrical Power systems’,Sixth ed.,New age international publishers, 2010

9. ‘Applied Protective Relaying’, Westing House Electric Corporation, Relay Instrument

Division, New Jersey

10. L.G.Hewiton, Mark Brown, Ramesh Balakrishnan, ‘Practical Power system Protection’

11. P.M.Anderson, ‘Power system Protection’, IEEE Power series on Power

Engineering,1999

12. D.P.Kothari,I.J Nagrath, Modern Power system Analysis, Fourth Ed.,2011

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