ECE 4310-Power System Protection-1

8/4/2019 ECE 4310-Power System Protection-1

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ECE 4310: Energy Systems II

Power System Protection

Rama Gokaraju (Visiting Professor)Department of Electrical & Computer Engineering

University of ManitobaEmail:[email protected], Phone: (204) 474-7199

1 Introduction

The purpose of power system protection is to continuously monitor the system to ensure

maximum continuity of electrical supply with minimum damage to life, equipment andproperty. The general requirements for protective systems are 1) Reliability, 2) Speed, 3)Selectivity, 4) Simplicity.

A protective system is based on detecting fault conditions by continuously monitoring

power system variables such as current, voltage, power, frequency and impedance.Measurement of currents and voltages is performed by instrument transformers of current

type (current transformersCTs) and voltage type (voltage transformersVTs).

The instrument transformers feed measured variables to a relay system, which in turn,upon detecting a fault, commands a circuit interrupting device known as circuit breaker

(CB) to disconnect the faulted section of the system.

Ideally the circuit breaker must operate immediately to isolate the fault. The interruptionof a large current causes an arc across the contacts of the breaker. The arc in a circuit

breaker is a column of hot, ionized gas. The breaking of the circuit by the extinction ofthis arc occurs in two successive stages. In the first stage, the resistance of the arc

increases to a value so high that the current is negligible, and in the second stage, thedielectric strength of the arc space increases to a value so high that the arc will not be

reignited by the circuit voltage.

The power system relays can be classified into three types based on the principle of

operation. These are electromechanical (moving parts), static (no moving parts and dataprocessing is analog) and numerical (no moving parts and data processing is digital).

2 Zones of Protection

It is essential to provide each major element of a power system with a protection asshown in Figure 1. The first point to be noted in this figure is that each system element is

given adequate protection while keeping service interruption to a minimum. The second
mailto:[email protected]:[email protected]:[email protected]:[email protected]


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point to be noted is that each zone is overlapped to avoid unprotected (blind) areas. Theconnection of current transformers achieves the overlapping as shown in Figure 2. A fault

in the area of two CTs will trip all the breakers in both zones.

Gen

Motor

Generator

relay zoneGeneratortransformer

relay zone

Busbar

relay zone

Busbar

relay zone

Busbar

relay zone

Line relay

zone

Transformer relay zone

Motor relayzone

Figure 1 Zones of protection for a simple power system.


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CircuitBreaker

Zone 1 Zone 2

C. T. for

Zone 2

C. T. for

Zone 1

Circuit

BreakerZone 1 Zone 2

C. T. for

Zone 2

C. T. for

Zone 1

(a)

(b)

Figure 2 CT connections overlapping around a circuit breaker.

3 Primary and Backup Protection

Primary relaying is the first line of defense. Back-up relaying functions only when

primary relaying fails. Possible causes of primary relaying failure could be due to any ofthe following failures: 1. Current or voltage supply failures to the relays 2. Protective

relay failure 3. Tripping circuit or breaker mechanism failure etc. It is highly desirablethat back-up relaying be arranged so that anything that might cause primary relaying to

fail will not also cause failure of back-up relaying. The practice is to locate the back-uprelays at a different station. Consider for example the backup relaying for thetransmission line section EF of Fig. 3. The back-up relays for this line section are

normally arranged to trip breakers A, B, I and J. Should breaker E fail to trip for a faulton the line section EF, breakers A and B are tripped. Breakers A and B and their

associated back-up equipment, being physically apart from the equipment that has failed,are not likely to be simultaneously affected as might be the case if breakers C and D were

chosen instead.


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A C

B D

G I

H J

E F

Station K

Figure 3 Illustration of back-up protection of transmission line section EF.

4 Types of Protective Relays

Relays can be classified according to their function: current relays, voltage relays, power

relays, frequency relays, directional relays, distance relays, differential relays, etc.

5 Current Transformers (CTs)

It is necessary that a current transformer reproduce in its secondary winding a current

which duplicates the primary current waveform as faithfully as possible (similarconsideration holds good for a voltage transformer as well). The load on CTs (andvoltage transformers VTs) is commonly known as their burden. The burden is usually

specified in terms of the impedance or VA delivered to the load.

The schematic representation for current transformers is shown Figure 4. The primary

winding of a CT is a single turn, and is represented by a straight line marked a and b.This single turn is obtained by threading the primary conductor through one or more

toroidal coils steel cores. The secondary windings, the terminals of which are marked asa and b in Figure 4, are multiple-turn windings wound on the toroidal cores.

CTs have ratio errors and can be quite high if the impedance burden is too large, but withproper selection of the CT with respect to the burden the error can be maintained at anacceptable value.

The normal current rating of CT secondaries has been standardized at 5A, with a second

standard of 1 A being used in Europe. For short periods (for example during faults) thisrating of the CT secondary windings can be exceeded without damaging the windings.

Standard CT current ratios have been established, and some of these are given in Table 1.


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a

a

b

b

Figure 4 Schematic Representation of a CT.

Table I: Standard CT ratios

Current ratio Current ratio Current ratio

50:5 300:5 800:5

100:5 400:5 900:5

150:5 450:5 1000:5200:5 500:5 1200:5

250:5 600:5

6 Voltage Transformers (VTs)

Two types are commonly found in utility applications. For low-voltage applications(system voltages about 12kV or lower), secondary windings at 67 V (line-to-neutral

voltage) are an industry standard. For voltages at HV and EHV levels, a capacitancepotential-divider circuit is used as shown in Figure 5. Capacitors C1 and C2 are so

adjusted that a voltage of a few kilovolts is obtained across C2when terminal A is atsystem potential. In such a coupling-capacitor voltage transformer (CCVT), the tapped

voltage is further reduced to relaying voltage level by a transformer as shown in Figure 5.The CCVT is a free standing device housed in its own supporting insulator structure.

The Thevenin impedance looking toward the system across the terminals of C2 is

)C+C(

1

21

Adjusting L so that L equal the Thevenin impedance results in series resonance. Under

this condition, the output of the CCVT is in phase with the line potential with no phase-angle error introduced in the CCVT output.

VTs are generally far more accurate than the CTs and their ratio and phase angle errors

are generally neglected. However, it is often necessary to pay attention to the transient


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response of the CCVTs under fault conditions, as errors under these conditions arepossible.

C1

A

C2

TL

Figure 5 Circuit diagram of a capacitor-coupled voltage transformer (CCVT).

7 Logical Design of Relays

The main purpose of a relay is to discriminate between a fault within its zone of

protection, and do not trip for faults outside its zone of protection. The logicalperformance can be defined in terms of the inputs and outputs of the relay. The logical

design of the most common relays is described next.

7.1 Magnitude Relays (Example - Overcurrent Relays)

Most common form are the overcurrent relays. The simplest form of the overcurrent isdescribed below:

|pI|>|fI| : TRIP

|pI||fI|

where T is the relay operating time and is a function which describes its dependence

upon the fault current level. The functional dependence can be illustrated by adding timecircles such as T1 and T2 to the phasor diagram as shown in Figure 6. The length of


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phasor |fI| then falls on a time line (or between two time lines) which represents the

operating time of the relay for that fault current.

Im (I)

Re (I)

|IP|

Block

If

T1 T2Trip

Figure 6 Operating & blocking regions of a time over-current relay. Time T2 is earlier

that T1.

The characteristic curves of type IFC-53 (General Electric Company) electromechanicaltime ovecurrent relay are shown Figure 7. In these characteristics, the pickup setting

|pI| is adjustable through taps on its input winding. The relay IFC-53 is available with

tap settings of 1.0, 1.2, 1.5, 2.0, 3.0, 4.0, 5.0, 6.0, 7.0, 8.0, 10.0 and 12.0 A. Thecharacteristics are asymptotic to pickup values of current and decreases as inverse power

of current magnitude for |pI|>|fI| . The characteristic curves are presented with

multiples of pickup amperes on x-axis and operating time as ordinate. Multiples ofpickup amperes here means ratio of relay current to pickup current. The inverse-time

characteristics can be shifted up or down by an adjustment known as time-dial setting ortime multiplier setting. In the IFC-53, a time-dial setting of produces the fastest

operation of relay whereas a setting of 10 produces the slowest operation for a givencurrent.


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of about 90 degrees. The operation of relay is described by dividing complex plane ofphasor diagram such that current phasors lying in shaded region (voltage at bus 2 is used

as reference) would trip. The operating principle can be described by the followingequation:

max>op>min

TRIP

max


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|rZ||Z| BLOCK

The above relay is referred to as an impedance or a distance relay (see Figure 9(b)).When Z is plotted in a complex plane under normal conditions it will lie outside circle

of radius |rZ| and consequently the relay will not trip. Under faulted conditions Z will

be inside the circle. Angle associated with Z is or + depending upon whether the

fault is to the right or left of bus 1 in the circuit.

Modification to an Impedance Relay (Mho Relay)

An impedance relay can be made directional by offsetting it by an amount 'Z :

| ' | | |r Z Z Z TRIP

| ' | | |r Z Z Z BLOCK

The above gives a mho relay characteristics as shown in Figure 9(c).

Fault to the left of relay at bus 1 will result in no trip decision i.e.12I1V=Z will lie in the

third quadrant.


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T

TripBlock

B12

R12

1

Block

2

R

Trip

Z

|Zr|

R

X

Block

Trip

Z

|Zr|

R

X

Block

Z`

(a)

(b) (c)

Figure 9: Impedance relay characteristics (a) Zone of protection for R12 (b)

Nondirectional impedance relay (c) Mho relay. In (b) & (c) the Z is indicated for a fault

to the left of R12.

7.4 Differential Relays (Example Generator or TransformerInternal Fault Protection)

When entire zone of protection of a relay occupies a small physical space near relay we

can devise a very simple and effective relay using the current differential principle. Two

current transformers having same turns are placed at boundaries of zone of protection asshown in Figure 10.


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I1 I2

I1 I2

I1 I2

I1-I2

1 2

3

Block Block Trip

Generator phase

winding

If

Figure 10: Differential protection for a generator phase winding.

For normal faults outside the zone of protection,

1 2 0I I

For a fault inside protected zone

1 2 f I I I

The above two equations are strictly not true due to the errors of the CTs. Therefore to

account for these inaccuracies, a low value of |pI| is chosen such that

1 2| | | |p I I I for normal faults external to zone of protection.

1 2| | | |p I I I for internal faults.

Therefore the operating principle is:

1 2| | | |p I I I TRIP

1 2| | | |p I I I BLOCK


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If we connect an overcurrent relay so that its operating coil is 3 in the figure, then the

current through coil is 1 2I I and relay will protect generator by tripping a breaker

according to principle of differential relaying.

Often CT errors increase with increasing values of 1I and 2I and in such cases one can

make pI dependent upon average of 1I and 2I .

1 2 1 2| | k | ( ) | /2 I I I I TRIP

1 2 1 2| | k | ( ) | /2 I I I I BLOCK

The above equation represents the equation for a percentage differential relay.

)2I+1I( /2 is called the restraining current. 1 2( )I I is called the tripping current. If

currents in coils 1 and 2 oppose effect of current through 3 then relay will exhibit

percentage differential characteristics expressed in the above equation. Relativeeffectiveness of coils 1 and 2 compared to coil 3 determines k.

In an electromechanical relay, percentage differential relay coils 1, 2 and 3 are wound on

a common magnetic core such that direction of currents through 1 and 2 produce a MMFthat is in opposition to that produced by current in 3.

In modern electronic relays the desired characteristics can be obtained by amplification

factors in appropriate signal paths.

Similar differential protection schemes are used to protect a bus, transformer or a motor.

7.5 Protection of Subtransmission Lines and Radial DistributionNetworks

Consider the power system shown in Figure 11. A simplest form of protection system canbe devised when the system is radial in nature (generator connected to a load through a

transmission line). Since the source is only on one side, it is sufficient to provide only onecircuit breaker for each line at the source end (breakers at the other end of a line are not

necessary).


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1

2 3 4 5

j5.0

j5.0

j9.6

B1

j6.4

B2

j8.0

B3

j12.8

B4

Figure 11: Protection of a radial system. Line and transformer reactance values are

marked in ohms.

Overcurrent relays can be used to protect the lines of this kind of a system. The fault

current magnitude depends upon the type of fault and the amount of generation connectedat bus 1. Maximum fault currents are seen for maximum generation and a three-phase

fault. The minimum fault currents are seen for minimum generation and line-to-line orline-to-ground fault.

The relays at each of the three buses 1, 2 and 3 are provided to protect their respective

lines as primary protection and to provide remote backup protection to one linedownstream from the relay location. For example when relay at 1 provides backup

protection for line 2-3, it must be adjusted such that relay at bus 2 expected to operate forfaults on line 2-3.

Example 1 (Fault Current Calculations)

A portion of a 13.8 kV radial system is shown in Figure 11. The system may be operated

with one rather than two source transformers under certain operating conditions. Assumehigh voltage bus of transformer is an infinite bus. Protection system for line-to-line and

three-phase faults has to be designed. Transmission line reactances in ohms referred tothe 13.8 kV side are shown in the figure. Neglect resistance and first calculate the

minimum and maximum fault currents at bus 5.

Solution Hints:

1. Maximum fault current will occur for a three-phase with both transformers inservice.

2. Minimum fault in this case is assumed for a line-to-line fault. A line-to-line faultproduces a fault current equal to 2/3 times the three-phase fault. Also the

minimum fault current happens for line-to-line faults with one transformer inservice.


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The maximum and minimum fault currents are given below for faults at bus 1-5:

Table II: Maximum and Minimum Fault Currents

Fault at bus 1 2 3 4 5

Max faultcurrent, A

3187 659 431 301 203

Min fault

current, A

1380 473 329 238 165

Example 2 (Designing an Overcurrent Relay)

Consider again the portion of the 13.8 kV radial system shown in Figure 11.

For the above system, an over-current protection system has to be designed for line-to-

line and three-phase faults (CT ratios, relay tap (pickup) settings, and the relay time dialsettings).

The standard CT ratios are listed in Table I. Use at all locations the IFC-53 relay whose

characteristic curves are given in Figure 7 and whose mechanical tap settings are asfollows: 1.0, 1.2, 1.5, 2.0, 3.0, 4.0, 5.0, 6.0, 7.0, 8.0, 12.0 A. The relays at each bus 1, 2, 3,

and 4 are designated by R1, R2, R3, and R4, respectively. The breaker at each bus willopen all three phases when tripped by any of the three associated relays.

Determine the relay settings (CT ratios, relay tap (pickup) settings, and the relay time dial

settings) for R1-R4.

We will use the following design principles for calculations

1. Start you solution first with the calculations for R4. R4 must operate for allcurrents above 165. A, but for reliability purpose choose a relay which will

operate with a current in the line which is 30% of the minimum.2. Backup protection: Over-current relay for X, backing up the next downstream

relay Y, is that X must pick upa. For 30% of the minimum current seen by Y andb. For the maximum current seen by Y but no sooner than 0.3 s after Y

should have picked up for that current.

Solution

Settings for relay R4:

Select a relay which will operate when the current in the line is one-third of the minimum.


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A55=3

165='pI

Use a CT ratio of 50/5. Therefore,

A5.5=50

5x55=pI

Let us use a relay tap setting of 5.0 A. Relay is at end of radial system and therefore no

coordination is necessary. Time-dial setting therefore will be chosen to be .2

1


R3 has to provide primary protection for line 3-4 and provide remote backup protectionfor relay R4. Therefore, it must pick up reliably for smallest fault current seen by R4,

which is 165 A.

So just as for R4, we will use a CT ratio of 50/5 and a relay tap of 5A for R3 also.

The highest fault current seen by R4 is 301 A. The relay current of R3 and R4 is then

.A1.30=50

5x301

Therefore 6=5

1.30=

pIfI for both R3 and R4.

IFC-53 tells us the operating time for R4 is 0.135 s.

Therefore for R3 backing-up R4, the back-up time is:

0.135 + 0.3 = 0.435 s.


Smallest fault current for which R2 must pick up is 238 A. Therefore from backupprotection rule it is:

3.79=238x3

1. Use a CT ratio of100

5. Therefore we have:

.A4100

5x3.79 Therefore we specify a 4.0 tap for R2.

Maximum fault current at bus 3 is 431 A.


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Therefore thepIfI for R3 is going to be equal to 6.8=

5

1x)

50

5x431( . The

time-dial setting of R3 is 2. Relay R3 will operate for this fault current in 0.31s.

Therefore R2 must operate while backing up R3 in 0.31+0.3=0.61 s.

pIfI for R2 while backing up R3 is:

4.5=4

1x

100

5x431

Therefore the time-dial setting of R2 is 2.6 (for modern numerical relays intermediatetime-dial settings can be obtained easily and is drawn in the figure).

The relay R1 can be set similarly.

7.6 Protection of Loop Systems

Figure 12 shows the one-line diagram of a loop system.

1 2 3 4

A C EB D F

1 2

3

A

C

E

B

DF

(a) (b)

Figure 12: One-line diagram of a loop system. Arrows beside each circuit breaker show

the direction to the fault for which relay will respond. Relays having all arrows pointing

in the same direction around the loop coordinate with each other.

Overcurrent relay is made directional by using an additional directional relay at each

location and arranging outputs of directional and overcurrent units in such a manner thata logical and operation between their outputs is performed.


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7.7 Protection of HV and EHV Transmission Lines

In bulk power networks there are no radial or single-loop systems. Generating station and

subtransmission feed points are interconnected to form a network so that no simple loopscan be identified.

In such cases it becomes impossible to coordinate directional overcurrent relays toprovide protection for transmission lines. Impedance relays provide a method for

protecting transmission lines connected in a network. Impedance is proportional todistance to fault (therefore called as distance relays) and does not depend upon the fault

current levels.

Consider application of directional distance relays for protection of line 1-2 in Figure13(a).

For relay R12 faults at P2, P3 and P4 all appear to be at same distance from bus 1; yetfaults at P3 and P4 are clearly outside zone of protection of R12. To avoid this basic

problem zone of distance relay is modified as shown for R12 by dashed lines. The singlezone of protection shown by solid line is replaced by two zones (zone 1 and zone 2).

Zone 1 extends a shorter distance than zone shown by solid line and is usually about 80%of the line length. For faults within this zone, distance relay at bus 1 operates normally

(i.e. as quickly as possible). The shortened zone 1 is commonly known as anunderreaching zone. Zone 2 on the other hand extends beyond line terminal well into

lines connected to remote bus and is said to be an overreaching zone. Relay R12responds to a zone 2 fault with a time delay so that it may coordinate with R23 and R24.

Similarly zone 1 and zone 2 settings are available for relay R21 at bus 2.

For a fault at P1 both relays R12 and R21 operate at highest possible speed since this fault

is in zone 1 of both relays. A fault at P2 is in zone 1 of R21 and consequently breaker B21will be tripped at high speed. Relay R12 however will not clear fault at high speed since

this fault lies in zone 2 of R12.

After its zone 2 time delay has expired, relay R12 will operate and trip circuit breakerB12. There is thus a delayed fault clearing from bus 1 while bus2 end is cleared at high

speeds for faults such as P2.

Faults at P3:

Faults lying in zone 1 of relay R23 will be cleared by B23 at high speed. Relay R12 willtrip breaker B12 at bus 1 to isolate fault in zone-2 time of relay R12 if B23 fails to

operate. The zone-2 clearing time is slower than zone 1 clearing time of relay R23. Thezone-1 operating time is order of 1 cycle. Zone-2 operating time is in the order of 15 and


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30 cycles. The response time of relays R12, R23 and R24 to their respective zone-1 andzone-2 faults is shown in Figure 13(b).

Distance relays are also provided with another zone of protection known as their zone 3

to provide remote backup for neighboring lines.

Third zone of a relay must reach beyond longest line emanating from bus at remote endof its protected line. Third zone of relay R12 must coordinate with zone 2 of relays at bus

2 (R23 and R24).

The co-ordination is by time and distance: zone-2 reach of relay R12 is shorter than zone-1 reach of relay R23 or R24. Similarly zone-3 reach of relay R12 is shorter than zone-2

reach of R23 and R24. Zone-3 co-ordination order is of 1 s.

1 2

B12 B21

3

4

B23

B24

B32

B42

P1

P2

P3

P4

Zone 1

Zone 2

Zone 3

1 2 3 4

R12

R12

R12

R23

R24T2

T3

Operatingtim

e

(a)

(b)

Figure 13: Distance (or impedance) relays. (a) Zone of protection of protection shown by

solid line is replaced by zones 1 and 2 identified by dashed lines. Zone 3 provides backupprotection for neighboring protection systems. (b) Time delay and operating time for R12,

R23 and R24.

Figure 14(a) shows the characteristics of a directional impedance relay in the complex R-X plane.


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A straight line called the line impedance locus is shown in the figure. Along this line thepositive sequence impedances of the protected line as seen by the relay between its

location and different points along the protected line can be plotted.

Directional unit of the relay causes separation of the trip and block regions of the relay

characteristics by a line drawn perpendicular to the line impedance locus.

During emergency load-flow conditions when the load is quite high, the impedance seen

by the relay is low and must be checked to make sure that it does not fall within one ofthe zone circles of the relay characteristics. To avoid this kind of a problem mho

characteristics as shown in Figure 14(b) can be used.

The centers of zone circles lie on line impedance locus for mho relay.

Note: Radii of zone circles are half of radii of corresponding zone circles of directionaldistance relay for same impedances since intersection of a zone circle with the line

impedance locus must still be the impedance of line seen by relay between its locationand the end of zone.

R

X

1

2

3

2

4

Line impedance locus

Line impedance

locus

X

R

1

2

3

2

4

(a) (b)

Figure 14: Characteristics of (a) Directional impedance relay (b) Mho relay for the

power system configuration shown in figure 13.

This kind of protection is used almost universally to protect transmission lines of a

modern power network. Ground faults are covered by directional time overcurrent relays.Three-phase and line-to-line faults are covered by distance relays.


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Example 3 (Designing Impedance Relays)

Consider again portion of a 138 kV transmission system shown in Figure 13(a). Lines 1-2,

2-3 and 2-4 are respectively 64, 64 and 96 km long. Positive-sequence impedance oftransmission lines is 0.05+j0.5/km. Maximum load carried by line 1-2 under emergencyconditions is 50 MVA. Design a three zone distance relaying system to determine for

R12 zone settings which are impedance values in terms of CT and CCVT secondaryquantities.

Note: Zone settings give points on R-X plane through which zone circles of relay

characteristics must pass.

Solution

Positive sequence impedances of the three lines are:

Line 1-2 3.2+j32Line 2-3 3.2+j32

Line 2-4 4.8+j48

Maximum load current:

A2.209=310x138x3

610x50

Select a CT ratio of 200/5 so that it produces 5 A in the secondary winding under

maximum loading conditions.

System voltage to neutral:

V310x67.79=3

310x138

Industry standard for CCVT secondary voltage = 67 V.

CCVT ratio: 1/1.1189=67

310x67.79

Impedance measured by the relay:

0336.0xlineZ=40/pI

1.1189/pV


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ECE 4310-Power System Protection-1

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