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Lecture-20Dr. Tahir Izhar

Partial listing

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Over-currentUses current to determine magnitude of fault Simple May employ definite time or inverse time curves May be slow Selectivity at the cost of speed (coordination

stacks) Inexpensive May use various polarizing voltages or ground

current for directionality Communication aided schemes make more

selective

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The operating characteristic of an over-current relay can bepresented as a plot of the operating time vs. the current.

Level detection. Over-current relays

This figure represents the operatingtime for an independent delay timeover-current relay.

It will operate always at the same timefor currents over the pick up setting

This relays are defined by the pick upcurrent, as number of times thenormal current, and the operatingtime

Coordination of different protectionsof this type is achieved by timedelaying and pick up setting

It must be a minimum of 0,3 sec. topermit operating of the first breaker

t

iIn n*In

t 0

50 (ANSI)

4

TimeIndependent

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t

I

CTI

50+2

50+2

CTI Relay closest to fault operates

first Relays closer to source

operate slower Time between operating for

same current is called CTI(Clearing Time Interval)

DistributionSubstation

This type of relay will have an operating time depending on thevalue of the current, generally with an inverse characteristic, that isto say, the bigger the current, the shorter the time.

Over-current relays:Dependent time delay

This characteristic permits areasonable coordination betweenprotections just changing the pickup setting.

These relays will be defined by thepick up setting and the type oftripping curve, which can beadjusted

There are usually three types ofcurves, Normal (NI), Very inverse (VI)and Extremely inverse (EI)

t

iIn n*In

Transfercurve

Inverse time

t 0

TimeIndependent

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t

I

CTI

Relay closest to fault operates firstRelays closer to source operate

slowerTime between operating for same

current is called CTI

DistributionSubstation

• Selection of the curvesuses what is termed as a“ time multiplier” or “timedial” to effectively shiftthe curve up or down onthe time axis

• Operate region liesabove selected curve,while no-operate regionlies below it

• Inverse curves canapproximate fuse curveshapes

Time Overcurrent Protection (TOC)

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Multiples of pick-up

Time Over-current Protection

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The working principle of an inverse time overcurrent relay is depictedin this figure.

Over-current protection

The current to be controlled feedsa coil with multiple taps whichallow the pick up current setting.

The generated magnetic fieldmakes the disc rotate with a speedproportional to the current.

A timing dial allows theadjustment between contacts andhence sets the op. time.

The braking magnet lessens therotating speed and acts as anopposing force to the rotation.Varying the magnetization,different tripping curves can beachieved.

Currenttaps

Induction

disk

Laggingcoil

Timingdial

Braking

2 4 6

1

2

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1 5

2 4

3

A

B

E

D

C

c

e

d

a

b

L L

L L

Bus X Bus Y

E D C B A a b c d et

I

Differential• current in = current out• Simple• Very fast• Very defined clearing area• Expensive• Practical distance limitations Line differential systems overcome this using digital

communications

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Note CT polaritydots

This is athrough-currentrepresentation

Perfectwaveforms, nosaturation

IP

IS

IR-X

IP

IS

IR-Y

Relay

CT-X CT-Y

1 + (-1) = 0

+1

-1

0

Cur

rent

, pu

DIFF CURRENT

1 pu

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Note CTpolarity dots

This is aninternal faultrepresentation

Perfectwaveforms, nosaturation

FaultIP

IS

IR-X

IP

IS

IR-Y

Relay

2 + (+2) = 4

+2

-2

0

Cur

rent

, pu

X

2 pu 2 pu

CT-X CT-Y

DIFF CURRENT14

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It is triggered when the current exceeds the reference value andalso the energy or power flow has the determined direction.

An over-current element controls the current magnitude

A directional element controls the direction of the power flow

Directional

V

I

Cylinder

Magneticcore

IV

IIII

IV

I

V

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87

With internal fault Id > 0 Trip

With external fault Id = 0 Notrip

It compares the current entering the transformer with the current leaving theelement. If they are equal there is no fault inside the zone of protection

If they are not equal it means that a fault occurs between the two ends

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No Relay Operation if CTs Are Considered Ideal

ExternalFault

IDIF = 0

CT CT

50

Balanced CT Ratio

ProtectedEquipment

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InternalFault

IDIF > ISETTING

CTR CTR

50

Relay Operates

ProtectedEquipment

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False differential current can occur if a CTsaturates during a through-fault

Use some measure of through-current todesensitize the relay when high currents arepresent

ExternalFault

ProtectedEquipment

IDIF 0

CT CT

50

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CommunicationsChannel

Exchange of logic informationon relay status

RL

Relays RelaysT

R

R

T

LI RI

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Bus protection Transformer protectionGenerator protection Line protection Large motor protection Reactor protectionCapacitor bank protectionCompound equipment protection

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The over-current differential scheme is simpleand economical, but it does not respond well tounequal current transformer performance

The percentage differential scheme respondsbetter to CT saturation

Percentage differential protection can beanalyzed in the relay and the alpha plane

Differential protection is the best alternativeselectivity/speed with present technology

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VoltageUses voltage to infer fault or abnormal

conditionMay employ definite time or inverse time

curvesMay also be used for under-voltage load

shedding• Simple• May be slow• Selectivity at the cost of speed• Inexpensive

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FrequencyUses frequency of voltage to detect power

balance conditionMay employ definite time or inverse time

curvesUsed for load shedding & machinery

under/over-speed protection• Simple• May be slow• Selectivity at the cost of speed can be expensive

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PowerUses voltage and current to determine

power flow magnitude and directionTypically definite time

• Complex• May be slow• Accuracy important for many applications• Can be expensive

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Distance (Impedance)• Uses voltage and current to determine impedance of

fault• Set on impedance [R-X] plane• Uses definite time• Impedance related to distance from relay• Complicated• Fast• Somewhat defined clearing area with reasonable

accuracy• Expensive• Communication aided schemes make more selective

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• Relay in Zone A operates first• Time between Zones is called

CTI (Clearing Time Interval)

Source

A B

21 21

T1

T2

ZA

ZB

R

X ZL

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A B

IA IB

Internal fault = IA e IB are in phase reversal = Trip

External fault = IA e IB are in phase = No trip

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The breaker may have a mechanical failure if it is not ableto open any of the poles when it is ordered to do so, oreven an electrical failure if although open, is not capableof breaking the current, which will keep on flowing as anarc.

This implies a current flow that keeps on feeding thefault which can be used to detect the breaker failureitself.

In those applications which even though the mechanicalfailure exist, the current could not be high enough to bedetected, the opening must also be verified by meansof breaker auxiliary contacts.

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87B+FI

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I falta A tripping order for thecircuit breaker initiatesthe time delay countdown for the protection.

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87B+FI

TELEDISPARO

21

I falta

T 250 ms

Once the time delay isover, if the breaker is notyet open, the protectionsends a tripping order toall the adjacent breakers,including those at the endof the lines if necessary.

Sometimes two timedelays are used, the firstone to repeat thetripping order for thebreaker itself, and thesecond for the otherbreakers.

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Generation-typically at 13kV

Transmission-typically at 230kV

Sub-transmission-typically at 132kV

Receives power from transmissionsystem and transforms into sub-transmission level

Receives power from sub-transmission system and transformsinto primary feeder voltage

Distribution network-typically 11kV

Low voltage (service)-typically 230V32

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1. Generator or Generator-Transformer Units

2. Transformers

3. Buses

4. Lines (transmission and distribution)

5. Utilization equipment (motors, static loads, etc.)

6. Capacitor or reactor (when separately protected)

Unit Generator-Tx zoneBus zone

Line zone

Bus zone

Transformer zone Transformer zone

Bus zone

Generator

~

XFMR Bus Line Bus XFMR Bus Motor

Motor zone

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1. Overlap is accomplished by the locations of CTs, the key source for protectiverelays.

2. In some cases a fault might involve a CT or a circuit breaker itself, whichmeans it can not be cleared until adjacent breakers (local or remote) areopened.

Zone A Zone B

Relay Zone A

Relay Zone B

CTs are located at both sides ofCB-fault between CTs is cleared from bothremote sides

Zone A Zone B

Relay Zone A

Relay Zone B

CTs are located at one side of CB-fault between CTs is sensed by both relays,remote right side operate only.

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1. One-line diagram of the system or area involved

2. Impedances and connections of power equipment, system frequency,voltage level and phase sequence

3. Existing schemes

4. Operating procedures and practices affecting protection

5. Importance of protection required and maximum allowed clearancetimes

6. System fault studies

7. Maximum load and system swing limits

8. CTs and VTs locations, connections and ratios

9. Future expansion expectance

10. Any special considerations for application.

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Non-dimensioned diagram showing howpieces of electrical equipment areconnected

Simplification of actual systemEquipment is shown as boxes, circles and

other simple graphic symbolsSymbols should follow ANSI or IEC

conventions

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• Current transformers are used to step primary system currents tovalues usable by relays, meters, SCADA, transducers, etc.

• CT ratios are expressed as primary to secondary; 2000:5, 1200:5,600:5, 300:5

• A 2000:5 CT has a “CTR” of 400

Current Transformers

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Excitation Curve

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Application BurdenDesignation

Impedance(Ohms)

VA @5 amps

PowerFactor

Metering B0.1 0.1 2.5 0.9B0.2 0.2 5 0.9B0.5 0.5 12.5 0.9B0.9 0.9 22.5 0.9B1.8 1.8 45 0.9

Relaying B1 1 25 0.5B2 2 50 0.5B4 4 100 0.5B8 8 200 0.5

Standard IEEE CT Burdens (5 Amp)(Per IEEE Std. C57.13-1993)

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Forward Power

IP

IS

IR

Relayor Meter

Forward Power

IP

IS

IR

Relayor Meter

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VVPP

VVSS

Relay

• Voltage (potential) transformers are used to isolate and step downand accurately reproduce the scaled voltage for the protectivedevice or relay

• VT ratios are typically expressed as primary to secondary;14400:120, 7200:120

• A 4160:120 VT has a “VTR” of 34.66

Voltage Transformers

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Case ground made at IT location Secondary circuit ground made at first point

of use

Case

Secondary Circuit

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• Prevents shock exposure of personnel• Provides current carrying capability for the

ground-fault current• Grounding includes design and construction of

substation ground mat and CT and VT safetygrounding

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• Limits overvoltages• Limits difference in electric potential through local

area conducting objects• Several methods Ungrounded Reactance Coil Grounded High Z Grounded Low Z Grounded Solidly Grounded

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1. Ungrounded: There is no intentionalground applied to the system-howeverit’s grounded through naturalcapacitance. Found in 2.4-15kVsystems.

2. Reactance Grounded: Total systemcapacitance is cancelled by equalinductance. This decreases the currentat the fault and limits voltage across thearc at the fault to decrease damage.

X0 <= 10 * X1

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3. High Resistance Grounded: Limitsground fault current to 10A-20A. Usedto limit transient overvoltages due toarcing ground faults.

R0 <= X0C/3, X0C is capacitive zerosequence reactance

4. Low Resistance Grounded: To limitcurrent to 25-400A

R0 >= 2X0

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5. Solidly Grounded: There is aconnection of transformer or generatorneutral directly to station ground.

Effectively Grounded: R0 <= X1, X0 <=3X1, where R is the system faultresistance

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• Solidly Grounded Much ground current (damage) No neutral voltage shift Line-ground insulation

Limits step potential issues Faulted area will clear Inexpensive relaying

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• “Somewhat” Grounded Manage ground current (manage damage) Some neutral voltage shift Faulted area will clear More expensive than solid, less expensive then

ungrounded

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• Ungrounded Very little ground current (less damage) Big neutral voltage shift Must insulate line-to-line voltage

May run system while trying to find ground fault Relay more difficult/costly to detect and locate ground

faults If you get a second ground fault on adjacent phase,

watch out!

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Source

5051

50N51N

50

51

50N

51N50

51

50N

51N

Low/No Z

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Source

50

51

50G

51G

50

51

50G

51G

50

51

50G

51G

Med/High Z

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Medium/HighResistance Ground

Low/NoResistance Ground

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Relay performance is generally classed as

(1) correct,

(2) no conclusion

(3) incorrect.

Incorrect operation may be either failure to trip or false tripping.

The cause of incorrect operation may be (1) poor application, (2) incorrectsettings, (3) personnel error, or (4) equipment malfunction.

Equipment that can cause an incorrect operation includes current transformers,voltage transformers, breakers, cable and wiring, relays, channels, or stationbatteries.

Incorrect tripping of circuit breakers not associated with the trouble area isoften as disastrous as a failure to trip. Hence, special care must be taken inboth application and installation to ensure against this.

“No conclusion” is the last resort when no evidence is available for a corrector incorrect operation. Quite often this is a personnel involvement.

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Protective relays or systems are not required to functionduring normal power system operation, but must beimmediately available to handle intolerable systemconditions and avoid serious outages and damage.

Thus, the true operating life of these relays can be on theorder of a few seconds, even though they are connectedin a system for many years. In practice, the relays operate far more during testing and

maintenance than in response to adverse service conditions.

In theory, a relay system should be able to respond to aninfinite number of abnormalities that can possibly occurwithin the power system.

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In practice, the relay engineer must arrive at a compromise basedon the four factors that influence any relay application:

Economics: initial, operating, and maintenance

Available measures of fault or troubles: fault magnitudes andlocation of current transformers and voltage transformers

Operating practices: conformity to standards and acceptedpractices, ensuring efficient system operation

Previous experience: history and anticipation of the types oftrouble likely to be encountered within the system

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The first step in applying protective relays is to state the protectionproblem accurately.

Although developing a clear, accurate statement of the problem canoften be the most difficult part, the time spent will pay dividendsparticularly when assistance from others is desired.

Information on the following associated or supporting areas isnecessary:

System configuration

Existing system protection and any known deficiencies

Existing operating procedures and practices, possible future expansions

Degree of protection required

Fault study

Maximum load, current transformer locations and ratios

Voltage transformer locations, connections, and ratios Impedance of lines,transformers, and generators 61

System configuration is represented by a single-line diagramshowing the area of the system involved in the protectionapplication.

This diagram should show in detail the location of the breakers, busarrangements, taps on lines and their capacity, location and size ofthe generation, location, size, and connections of the powertransformers and capacitors, location and ratio of ct's and vt's, andsystem frequency.

Transformer connections are particularly important. For groundrelaying, the location of all ground “sources” must also be known

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The existing protective equipment and reasons for the desiredchange(s) should be outlined.

Deficiencies in the present relaying system are a valuable guide toimprovements.

New installations should be so specified.

As new relay systems will often be required to operate with or utilize partsof the existing relaying, details on these existing systems are important.

Whenever possible, changes in system protection should conform withexisting operating procedures and practices.

Exceptions to standard procedures tend to increase the risk of personnelerror and may disrupt the efficient operation of the system.

Anticipated system expansions can also greatly influence the choice ofprotection.

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An adequate fault study is necessary in almost all relay applications.

Three-phase faults, line-to-ground faults, and line-end faults shouldall be included in the study.

Line-end fault (fault on the line-side of an open breaker) data areimportant in cases where one breaker may operate before another.

For ground-relaying, the fault study should include zero sequencecurrents and voltages and negative sequence currents and voltages.

These quantities are easily obtained during the course of a faultstudy and are often extremely useful in solving a difficult relayingproblem.

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MultifunctionalCompatibility withdigital integratedsystems

Low maintenance(self-supervision)

Highly sensitive,secure, andselective

AdaptiveHighly reliable(self-supervision)

Reduced burdenonCTs and VTs

ProgrammableVersatile

Low Cost

Improvements in computer-basedprotection

Highly reliable and viablecommunication systems (satellite, opticalfiber, etc.)

Integration of control, command,protection, and communication

Improvements to human-machineinterface

Much more

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THANK YOUTHANK YOU

FOR YOUR ATTENTIONFOR YOUR ATTENTION

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