EE 256 Notes 4 - Line Protection

Prof. Rowaldo R. del MundoDepartment of Electrical & Electronics Engineering

University of the Philippines

EE 256 - POWER SYSTEM PROTECTION

Line ProtectionLine Protection


Department of Electrical & Electronics Engineering2

EE 256 Power System ProtectionProf. Rowaldo R. del Mundo

TRANSMISSION AND DISTRIBUTIONLINE PROTECTION

4.1 Overcurrent Protection andCoordination

4.2 Distance Relaying

4.3 Pilot Relaying




GENERAL PROCEDURE ON COORDINATION OF OVERCURRENT PROTECTION

1. Gather data required for coordination.

a. Updated Single Line Diagram of the system

- show the type & ratings of protective devices (CB, recloser, relay, fuse, CT, PT and other related information)

b. Line currents that goes through the protective devices (normal, max. and emergency)




c. Short circuit currents (min. & max.)

- all types of faults (symm.& asymm)

d. Time-current characteristic curves of protective device.

2. Select current & voltage reference to be used in the log-log paper & scale all quantities to this reference (base)

a. Log-log paper has 4.5 decades

b. Current scale must show lowest normal current & max. short circuit current




c. Voltage scale: use one reference voltage (voltage of distribution)

*refer the current values to the chosen reference voltage

3. Plot current characteristics of equipment to be protected (inrush, starting, damage curves & points)

4. Plot the TCCs of devices being coordinated

-select settings or ratings based on principles of coordination

5. Draw the line diagram of the portion that you are coordinating & label the devices




Overcurrent Protection andCoordination

Overcurrent protection is directed primarily to the clearance of faults. The settings are usually adopted to obtain some measure of overload protection.

Coordination is the selection of ratings, settings and characteristics of overcurrent protective devices to ensure that the minimum unfaulted load is interrupted when protective devices isolate a fault or overload.





WHEN DO YOU CONDUCT COORDINATION?

New electrical system is being designed

Significant loads are added to the system

Existing equipment are replaced with higher rated equipment

Available short circuit current is increased

A fault on the periphery of the system shuts down a major portion of the system





DATA REQUIREMENTS

Single line diagram

Impedances

Short circuit currents

Starting and Inrush currents

Peak/Full load currents

Decrement curves of generators

Time-current characteristics (TCC) curves

Performance curves of CTs





COORDINATION PROCEDURE

Update and/or develop the single line diagram

Calculate fault currents (maximum and minimum)

Determine protection requirements of various elements of the system (motors, transformers, generators, feeders, etc.)

Prepare load analysis (maximum load and characteristics of load)

Obtain TCC of protective devices

Select proper scale (voltage and current) using a log-log paper

Select rating or setting which provide coordination margin





COORDINATION MARGIN

The time interval between the operation of two adjacent relays depends on the following factors:

circuit breaker interrupting time

Overshoot time of the relay

Errors

Final margin

Recommended Time: 0.3 0.5 seconds





A B C D E

MAX 7850AMIN 3920A

120A 170A 80A 50A

R4 R3 R2 R1

4500A2860A

2690A2003A

1395A1182A

500/5 400/5 200/5 100/5

Determine settings of R1 to R4 using the following relay data:

Normal Inverse Curve (see manufacturers TCC) Current Tap Setting: 0.5 2.5 x In (multiples of 0.5) Time Multiplier: 0.05 1.0 (multiples of 0.05) Instantaneous: 2.5 20 x In (multiples of 0.5)




Distance Relaying

Distance relaying provides discriminating zones of protection, provided that fault distance is a simple function of impedance

Distance Relay Types

Impedance Relay

Reactance Relay

Mho Relay




Distance Relaying

ZONES OF PROTECTION

Zone 1 (instantaneous zone)

- Choose relay ohmic setting of 80% of the protected line impedance (to provide an ample margin against over-reach)

Zone 2

- 100% of the protected line

- Plus 50% of the next shortest line (to deal with possible under-reach)

Zone 3

- 100% of the protected line

- Plus 100% of longest second line

- Plus 25% of longest third line (to provide back-up)




Distance Relaying

Transmission LinesZ1 = 2.5 + j5Zo = 7.5 + j20.5

Radial FeedersZ1 = 3.5 + j7Zo = 10.5 +j28.7

34.5 kV

34.5 kV

500 MVA fault @ 115 kV

R

Determine the settings of the distance relay using:

a. Impedance relayb. 45 Mho relay

36kV/ 120V

400/5Assignment:Compute minimum voltage at relay for a fault at Zone 1 reach

a. Phase faultb. Ground fault

Transformers50MVA, 115/34.5kVZ = 10%




Pilot Relaying

Pilot Relaying is an adaptation of the principles of differential relaying that avoids the use of control cable between terminals for fast clearing of faults of transmission lines

Communication Channels

Power Line Carrier (PLC)

Microwave

Fiber Optics

Pilot Wire




Pilot Relaying

Directional Comparison

Blocking Scheme

Unblocking Scheme

Tripping Scheme

Underreaching Transfer Trip

Overreaching Transfer Trip

Phase Comparison




Lateral Tap Fusing

Fuse must clear a Bolted SLGF in 3

seconds; or

Bolted SLGF = 6 X Fuse rating; or

Fuse must clear a SLGF with a 30-

ohm fault resistance in 5 seconds




Expulsion Fuse Expulsion Fuse Coordination

Downstream Fuse (referred to as the Protecting Fuse)

should operate before the Upstream Fuse (the

Protected Fuse)

Total Clearing Time of the Protecting Fuse should be less

than the Damage Time of the Protected Fuse [Note: Damage Time is 75% of the Minimum Melting Time]

Fuse-Fuse Coordination Table provides maximum fault currents that the protecting and protected fuse are

coordinated




Backup Current Limiting Fuse Coordination

CLF protecting Expulsion Fuse

Select a Backup CLF that have a maximum melting I2t below the

maximum clearing I2t of the expulsion element (Matched-Melt

Coordination Principle)

Check the TCC The expulsion link should always clear fault

currents in the low current operating region, especially below the

minimum interrupting current of the CLF

Estimating maximum melting I2t of expulsion links Take the

minimum calculated from the minimum melting TCC at 0.0125

sec. and multiply by 1.2 for Tin or 1.1 for Silver links




Recloser Expulsion Fuse Coordination

Adjust Fast Curve (A) of the recloser

For one fast operation: A curve time x 1.25

For two fast operation with a reclosing time greater or equal to 1 sec.: A curve time x

1.25

For two fast operation with a reclosing time

from 25 to 30 cycles: A curve time x 1.8

Smallest fuse must coordinate with the fast operation (A

curve) of the recloser.

Largest fuse must coordinate with the delayed operation (B

or C curve) of the recloser. Choose C curve if largest fuse

cannot coordinate with B curve




Recloser Recloser Coordination

Hydraulically-controlled Reclosers (Cooper)

Series-Coil Operated: Need more than 12 cycles

Solenoid Closing: Need 8 cycles separation

Coordinating Instantaneous Elements

Find a setting where the instantaneous relay will not operate for faults downstream of the

second protective device. The upstream relay will not operate if its pickup is above the

available fault current at the location of the downstream element. The instantaneous pickup

on the element must be higher than its time-overcurrent pickup.

[Note: This rules out hydraulic reclosers which have the same pickup for the fast (A) curve &

delayed curves (A&B)]

Use a time delay on the upstream instantaneous element. Choose enough time delay (6 to

10 cycles), to allow downstream device to clear before the station device operates.

Sequence Coordination If the device senses current above some minimum trip setting and

the current does not last long enough to trip based on the devices fast curve, the device

advances its control-sequence counter as if the unit had operated on its fast curve. So when

the downstream device moves to its delayed curve, the upstream device with sequence

coordination also is operating on its delayed curve.

Station device detects and counts faults (but does not open) for a fault cleared by a

downstream protection on the fast trip

If the fault current occurs again (usually because the fault is permanent), the station device

switches to the time-overcurrent element because it counted the first as an operation.




Station Relay and Recloser Settings

Phase Time-Overcurrent (TOC) Relay

Pickup at 2X the normal designed peak load on the circuit

Pickup < 75% of the bolted LTLF

Ground Time-Overcurrent (TOC) Relay

Pickup at 0.75X the normal designed peak load on the

circuit

Pickup < 75% of the SLGF current at the end of the line or

the next protective device

Must coordinate with the largest lateral fuse

Instantaneous Phase and Ground Relays

2X the TOC relay pickup




Sequence Coordination

Even with coordinated Fast Curves, nuisance momentary interruptions occur for faults cleared by downstream recloser

Sequence:

R2 operates on its A curve. (R1 will not operate)

After a delay, R2 recloses. The fault is still there, so R2 operates on its delayed B curve

R1 operates too on its a curve which operates before R2s curve

After R1 recloses, R2 should then clear the fault on its B curve, which should operate before R1s B curve

The fault is still cleared properly, but customers upstream of R2 have extra momentary interruptions

Documents

EE 256 Notes 4 - Line Protection