Power distribution and transmission

8/12/2019 Power distribution and transmission

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1

Lecture-21

Dr. Tahir Izhar


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Overcurrent Uses 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 currentfor directionality

Communication aided schemes make more selective

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The operating characteristic of an overcurrent relay can be presented

as a plot of the operating time vs. the current.

Level detection. Over-current relays

This figure represents the operating

time for an independent delay time

overcurrent relay.

It will operate always at the same time

for currents over the pick up setting This relays are defined by the pick up

current, as number of times the normal

current, and the operating time

Coordination of different protections of

this type is achieved by time delayingand pick up setting

It must be a minimum of 0,3 sec. to

permit operating of the first breaker

t

iIn n*In

t 0

50 (ANSI)

3

Time Indepedent


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Relay closest to fault operatesfirst

Relays closer to sourceoperate slower

Time between operating forsame current is called CTI(Clearing Time Interval)

Distribution

Substation


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This type of relay will have an operating time depending on the value

of the current, generally with an inverse characteristic, that is to say,the bigger the current, the shorter the time.

Over-current relays. Dependent time delay

This characteristic permits a

reasonable coordination between

protections just changing the pick

up setting. These relays will be defined by the

pick up setting and the type of

tripping curve, which can be

adjusted

There are usually three types ofcurves, Normal (NI), Very inverse

(VI) and Extremely inverse (EI)

t

iIn n*In

Transfer

curve

Inverse t ime

t 0

Time Indep edent

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Relay closest to fault operates

firstRelays closer to source

operate slowerTime between operating for

same current is called CTI

Distribution

Substation


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Selection of the curvesuses what is termed as a

time multiplier or time

dial to effectively shift

the curve up or down on

the time axis

Operate region lies

above selected curve,

while no-operate region

lies below it

Inverse curves can

approximate fuse curve

shapes

Time Overcurrent Protection (TOC)

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Multiples of pick-up

Time Overcurrent Protection

(51, 51N, 51G)

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The working principle of an inverse time overcurrent relay is depicted in

this figure.

Overcurrent protection

The current to be controlled feeds

a coil with multiple taps which

allow the pick up current setting.

The generated magnetic field

makes the disc rotate with a

speed proportional to the current.

A timing dial allows the

adjustment between contacts and

hence sets the op. time.

The braking magnet lessens the

rotating speed and acts as anopposing force to the rotation.

Varying the magnetization,

different tripping curves can be

achieved.

Current

taps

Induction

disk

Laggingcoil

Timing

dial

Braking

2 4 6

1

2

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Differential current in = current out

Simple

Very fast Very defined clearing area

Expensive

Practical distance limitations

Line differential systems overcome this using digitalcommunications

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Note CT polarity

dots

This is a

through-current

representation

Perfect

waveforms, nosaturation

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Note CT

polarity dots

This is aninternal fault

representation

Perfectwaveforms, no

saturation

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It is triggered when the current exceeds the reference value and also

the energy or power flow has the determined direction. An overcurrent element controls the current magnitude

A directional element controls the direction of the power flow

Directional overcurrent protection

V

I

Cylinder

Magnetic

core

IV

IIII

IV

I

V

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87

With internal fault Id> 0 Trip

With external fault Id= 0 No trip

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

Protected

Equipment

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Internal

Fault

IDIF > ISETTING

CTR CTR

50

Relay Operates

Protected

Equipment

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False differential current can occur if a CT

saturates during a through-fault Use some measure of through-current to

desensitize the relay when high currents are

present

External

Fault

ProtectedEquipment

IDIF

0

CT CT

50

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Protected

Equipment

R

S

CTR CTR

Compares:

Relay

(87)

OP S RI I I

| | | |

2

S R

RT

I Ik I k

RPSP

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Communications

Channel

Exchange of logic information

on relay status

RL

Relays Relays

T

R

R

T

LI

RI


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Bus protection

Transformer protection

Generator protection

Line protection Large motor protection

Reactor protection

Capacitor bank protection

Compound equipment protection

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The overcurrent differential scheme is simpleand economical, but it does not respond well to

unequal current transformer performance

The percentage differential scheme responds

better to CT saturation Percentage differential protection can be

analyzed in the relay and the alpha plane

Differential protection is the best alternative

selectivity/speed with present technology

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Voltage Uses voltage to infer fault or abnormal

condition May employ definite time or inverse time

curves May also be used for under-voltage load

shedding Simple

May be slow Selectivity at the cost of speed

Inexpensive

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PowerUses voltage and current to determine

power flow magnitude and direction

Typically definite time Complex May be slow

Accuracy important for many applications

Can be expensive

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A B

IA IB

Internal fault = IAe IBare in phase reversal = Trip

External fault = IAe IBare in phase = No tr ip

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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, or

even an electrical failure if although open, is not capable of

breaking the current, which will keep on flowing as an arc.

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

itself.

In those applications which even though the mechanical

failure exist, the current could not be high enough to be

detected, the opening must also be verified by means of

breaker auxiliary contacts.

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87B+FI

21

I falta A tripping order for the

circuit breaker initiates

the time delay count

down for the protection.

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87B+FI

TELEDISPARO

21

I falta

T 250 ms

Once the time delay is over,if the breaker is not yet

open, the protection sends a

tripping order to all the

adjacent breakers, including

those at the end of the linesif necessary.

Sometimes two time

delays are used, the first

one to repeat the

tripping order for thebreaker itself, and the

second for the other

breakers.

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Generation-typically at 13kV

Transmission-typically at 230kV

Sub-transmission-typically at 132kV

Receives power from transmission

system and transforms into sub-

transmission level

Receives power from sub-

transmission system and transforms

into primary feeder voltageDistribution network-typically 11kV

Low voltage (service)-typically 230V 32


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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 zone

Bus zone

Line zone

Bus zone

Transformer zoneTransformer 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, which

means it can not be cleared until adjacent breakers (local or remote) are

opened.

Zone A Zone B

Relay Zone A

Relay Zone B

CTs are located at both sides of

CB-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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Partial listing

36GE Consumer & IndustrialMultilin


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Non-dimensioned diagram showing how

pieces of electrical equipment are

connected

Simplification of actual systemEquipment is shown as boxes, circles and

other simple graphic symbols

Symbols should follow ANSI or IECconventions

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41

C t T f


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Current transformers are used to step primary system currents to

values 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

42

St d d IEEE CT B d (5 A )


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

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V lt T f


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VP

VS

Relay

Voltage (potential) transformers are used to isolate and step down

and accurately reproduce the scaled voltage for the protective

device 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 safety

grounding

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1. Ungrounded: There is no intentional

ground applied to the system-however

its grounded through natural

capacitance. Found in 2.4-15kV

systems.

2. Reactance Grounded: Total system

capacitance is cancelled by equal

inductance. This decreases the currentat the fault and limits voltage across the

arc at the fault to decrease damage.

X0


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3. High Resistance Grounded: Limitsground fault current to 10A-20A. Used

to limit transient overvoltages due to

arcing ground faults.

R0= 2X0

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5. Solidly Grounded: There is a

connection of transformer or generatorneutral directly to station ground.

Effectively Grounded: R0


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Medium/High

Resistance Ground

Low/No

Resistance 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) incorrect

settings, (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 station

batteries.

Incorrect tripping of circuit breakers not associated with the trouble area is oftenas disastrous as a failure to trip. Hence, special care must be taken in both

application and installation to ensure against this.

Noconclusionis the last resort when no evidence is available for a correct or

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 be

immediately available to handle intolerable system

conditions 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 connected

in 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 an

infinite number of abnormalities that can possibly occur

within the power system.

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The first step in applying protective relays is to state the protection problemaccurately.

Although developing a clear, accurate statement of the problem can often

be the most difficult part, the time spent will pay dividends particularly

when assistance from others is desired.

Information on the following associated or supporting areas is necessary:

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 62


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System configuration is represented by a single-line diagram showing

the area of the system involved in the protection application.

This diagram should show in detail the location of the breakers, bus

arrangements, taps on lines and their capacity, location and size of the

generation, location, size, and connections of the power transformers

and capacitors, location and ratio of ct's and vt's, and system

frequency.

Transformer connections are particularly important. For ground

relaying, the location of all ground sourcesmust also be known

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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 should all

be included in the study.

Line-end fault (fault on the line-side of an open breaker) data are

important in cases where one breaker may operate before another. For ground-relaying, the fault study should include zero sequence

currents and voltages and negative sequence currents and voltages.

These quantities are easily obtained during the course of a fault study

and are often extremely useful in solving a difficult relaying problem.

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Multifunctional

Compatibility with

digital integrated

systems

Low maintenance

(self-supervision)

Highly sensitive,

secure, and

selective

AdaptiveHighly reliable

(self-supervision)

Reduced burden

on

CTs and VTs

Programmable

VersatileLow Cost


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THANK YOU

FOR YOUR ATTENTION

Power distribution and transmission

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