feca presentation 2014 protection.pdf · ieee/ feca protection coordination june 2014 serge...

Protection Coordination

Serge BeauzileChair IEEE FWCS

Ch i P & E S i tChair Power & Energy [email protected]

June 10 2014June, 10, 20148:30 -12:30

Florida Electric Cooperatives AssociationFlorida Electric Cooperatives AssociationClearwater, Florida

Seminar Objective

• Distribution Circuit Protection– Fuse to Fuse Coordination– Recloser to Fuse Coordination– Breaker to Recloser Coordination

• Transmission Line ProtectionDistance Protection– Distance Protection

– Pilot Protection Schemes– Current Differential ProtectionCurrent Differential Protection

2IEEE/ FECA Protection Coordination June 2014 Serge Beauzile

Art & Science of System Protection

• Not an exact science, coordination schemes will vary based on:schemes will vary based on:

– Company PhilosophyCompany Philosophy– Protection engineer preference– System requirements


C di ti D iCoordinating Devices

Basic concept: All protective devices are able to Basic concept: All protective devices are able to detect a fault do so at the same instant.

If h d i th t d f lt t d If each device that sensed a fault operated simultaneously, large portions of the system would be de-energized every time a fault needed g yto be cleared. This is unacceptable.

A properly designed scheme will incorporate time A properly designed scheme will incorporate time delays into the protection system, allowing certain devices to operate before others.


C di ti D iCoordinating Devices

Timing of device operation is verified using timeTiming of device operation is verified using time-current characteristics or TCCs – device response curves plotted on log-log graph paper.

Devices have inverse TCCs. They operate quickly for large magnitude overcurrents, and more slowly g g , yfor lower-magnitude overcurrents.

Operating time is plotted on the vertical axis and Operating time is plotted on the vertical axis, and current magnitude is plotted on the horizontal scale.


C di ti D iCoordinating Devices100 Four different TCCs

h th 10

are shown on the left. Device “D” is the fastest to

1

Tim

e in

Sec

onds operate, and device

“A” is the slowest.25

0.1

A

B

C

D

For a given current value, the operating ti b f d

.25 sec10

,000

100010 10

0

0.01

100,

000

D time can be found.

3 kACurrent in Amperes


Coordinating Devicesg

In this example, A l l

100

Device A is clearly faster than Device B for low (400-700 A)

10

UncertainCoordination

( )fault currents.

Device B is clearly Tim

e in

Sec

onds

1

Device B is clearly faster for high (>1000 A) fault

t b t i th

0.1A

currents, but in the 700-1000 A region, timing is uncertain.10

010

0.01

100,

000

10,0

00

1000

B

g

1

Current in Amperes


Coordinating DevicesExpulsion Fuse to Expulsion FuseExpulsion Fuse to Expulsion Fuse

100

Minimum Melt

10Average Melt + tolerance

1

Tim

e in

Sec

onds

Total Clear

0.1

Average Melt + tolerance+ arcing time

Curves are developed at 25ºC

10010

1000

00,0

00

0,00

0

0.01

Curves are developed at 25ºCWith no preloading

101

Current in Amperes



100

In this example, the red

10

TCCs represent the downstream (protecting) fuse, and the blue TCCs

1

Tim

e in

Sec

onds represent the upstream

(protected) fuse.

0.1

The protected fuse should not be damaged by a fault in the

10010

1000

,000

,000

0.01

yprotecting fuse’s zone of protection.

1

100,10

,

Current in Amperes



100

Four factors need to be

10

considered:

1. Tolerances.

1

Tim

e in

Sec

onds

2. Ambient temperature.

0.1

p

3. Preloading effects.

10010

1000

0,00

0

0,00

0

0.01

4. Predamage effects.

1

10010

Current in Amperes



100

Consideration of these

10

four factors can be quite involved.

1

Tim

e in

Sec

onds Practically, the “75%

Method” can be used: the maximum clearing

0.1

gtime of the protecting link shall be no more than 75% of the

10010

1000

,000

,000

0.01

minimum melting time of the protected link.

1

10010

Current in Amperes11IEEE/ FECA Protection Coordination June 2014 Serge Beauzile


100

Minimum melting time of

10

protected link at 5 kA is 0.3 seconds.

1

Tim

e in

Sec

onds Total clearing time of the

protecting link at 5 kA is 0.22 seconds.

0.1 0.22 < 0.3 × 75% = 0.225, so coordination is

10010

1000

0,00

0

0,00

0

0.01

assured for current magnitudes ≤ 5 kA.

10010

Current in Amperes


Utility Distribution FeedersyMultiple Feeder Segments

Segments are defined as sectionalizable pieces of a feeder that can be automatically or manually separated from the rest of the feederseparated from the rest of the feeder.

Segments are delineated by reclosers, fuses, sectionalizers or switchessectionalizers or switches.

Two primary concerns: number of customers per d l segment and time to isolate segment.


Utility Distribution FeedersyNumber of Customers per Segment

The number of customers per segment has a major impact on reliability indices.

As the number of segments per feeder increases, reliability can also be adversely impacted, and y y pconstruction cost will increase.

A ti i t t b ht t d t i th An optimum point must be sought to determine the best segment size.


Utility Distribution FeedersUtility Distribution FeedersPresent and Future Load Requirements

Even the best load forecasts are full of errors.

You must continuously monitor your fuse coordination due changes in the load.coordination due changes in the load.

It is impossible to predict everything, so versatility is the key.


Coordination Goal

1. Maximum Sensitivity.

2. Maximum Speed.

3. Maximum Security.

4. Maximum Selectivity.


Basic Coordination Strategygy1. Establish a coordination

pairs.

2. Determine maximum load of each segment and the pickup of all delayed overcurrent devices.

3. Determine the pickup current of all instantaneous current of all instantaneous overcurrent devices, based on short-circuit studies.

4 D t i i i 4. Determine remaining overcurrent device characteristics starting from the load and moving to gthe source.


Fuse Peak Load Capability

IEEE/ FECA Protection Coordination June 2014 Serge Beauzile 23

Fuse Blow Vs. Fuse SaveFuse Blow Vs. Fuse Save• Fuse Blow

– Eliminates Instantaneous trip of the breaker or recloser Eliminates Instantaneous trip of the breaker or recloser (1st) by having the fuse blow for all permanent and temporary faults.

– Minimizes momentary interruptions and increases SAIDI Minimizes momentary interruptions and increases SAIDI. Improves power quality but decreases reliability.

• Fuse Save• Fuse Save– Minimizes customer interruption time by attempting to

open the breaker or recloser faster than it takes to melt the fuse fuse.

– This saves the fuse and allows a simple momentary

interruption.


Fuse Blow

FUSE is BLOWN

Lateral experiencesLateral experiences

sustained interruption 30

Fuse BlowFuse Blow– Used primarily to minimize momentary

interruptions (reduces MAIFI)– Increases interruption duration (SAIDI)– Very successful in high short circuit areas – More suitable for industrial type

customers having very sensitive loads


Fuse Save

Entire Feeder trips

Momentary occurs

FUSE is SAVEDFUSE is SAVED


Fuse SaveFuse Save– Minimize customer interruption time

Reduce SAIDI– Reduce SAIDI– Increase MAIFI– May not work in high short circuit areas– May not work in high short circuit areas– Work well in most areas – Not suitable for certain industrial Not suitable for certain industrial

customers that cannot tolerate immediate reclosing

– Works best for residential and small commercial customers


Both (Fuse Save & Fuse Blow)( )

• Many utilities use both schemes for a variety of reasons reasons – Fuse Blow for high short circuit current areas

and Fuse Save where it will work.– Fuse Save on overhead and Fuse Blow on

underground taps.– Fuse Save on rural and Fuse Blow on urbanFuse Save on rural and Fuse Blow on urban– Fuse Save on stormy days and Fuse Blow on nice

days.F S i it d F Bl – Fuse Save on some circuits and Fuse Blow on others depending on customer desires


Fast Bus Trip

IEEE/ FECA Protection Coordination June 2014 Serge Beauzile 35

SEL-351SSEL 351SProtection and Breaker Control

RelayRelay


Modern Microprocessor RelayProtection and Breaker Control Relay

Extremely versatile, many applications

Most commonly used on distribution feeders

Communicates with EMS system (DNP 3.0 Protocol)

Key element of “Substation Integration”

Provides many “traditional” features

Provides new capabilities


SEL-351SProtection and Breaker Control Relay

Protection Features:

P f t l t 18 diff t t ti f tiPerforms at least 18 different protection functions.

=



Protection Features:

B U d lt (27)Bus Undervoltage (27)

Phase Overvoltage (59P)

G d O lt (59G)Ground Overvoltage (59G)

Sequence Overvoltage (59Q)

O f (81O)Overfrequency (81O)

Underfrequency (81U)


Modern Microprocessor RelayProtection and Breaker Control Relay

Protection Features (continued):

Ph Di ti l O t (67P)Phase Directional Overcurrent (67P)

Ground Directional Overcurrent (67G)

S Di ti l O t (67Q)Sequence Directional Overcurrent (67Q)

Instantaneous Phase Overcurrent (50P)

I t t G d O t (50G)Instantaneous Ground Overcurrent (50G)

Instantaneous Sequence Overcurrent (50Q)(50Q)



Protection Features (continued):

Ti Ph O t (51P)Time Phase Overcurrent (51P)

Time Ground Overcurrent (51G)

Ti S O t (51Q)Time Sequence Overcurrent (51Q)

Directional Neutral Overcurrent (67N)

I t t N t l O t (50N)Instantaneous Neutral Overcurrent (50N)

Time Neutral Overcurrent (51N)



Breaker Control Features:

S h i Ch k (25)Synchronism Check (25)

Automatic Circuit Reclosing (79)

TRIP/CLOSE Pushbuttons

Enable/Disable ReclosingEnable/Disable Reclosing

Enable/Disable Supervisory Control



Other Features:

E t R ti d R diEvent Reporting and Recording

Breaker Wear Monitor

St ti B tt M itStation Battery Monitor

High-Accuracy Metering

F lt L tFault Locator


• Advantages of microprocessor relays • Advantages of microprocessor relays Extremely flexibleHave many different elements (UF, UV, Directionality, etc…)One relay can protect on zone of protectionOne relay can protect on zone of protectionInexpensive and require much less maintenanceAlarm if they fails and don’t need calibrationProvide fault informationProvide oscillography and SER dataCan provide analog data to SCADA

• Disadvantages of microprocessor relays Can be very complex to program due to given flexibilityR i t i i t R l T h i iRequire more training to Relay TechniciansRequire more training to Relay Engineers


RelaysRelays• Basic relay settings:

Phase overcurrent elements must be set above maximum Phase overcurrent elements must be set above maximum possible loadsGround overcurrent elements must be set above maximum anticipated unbalanced loadspMust be coordinated with downstream protective devicesUnder Frequency elements must be set according to the predetermined set point

• TAGGINGNORMAL mode – 2 reclosing attemptsg pWORK mode – HOT LINE TAG COLD mode


Relay CurvesRelay Curves100

10

1

Second

Moderately Inverse

Inverse

Very Inverse

0.1

ds

Very Inverse

Extremely Inverse

0.010.1 1 10 100

Multiple of Pick UpMultiple of Pick Up


Very Inverse Curve Time DialVery Inverse Curve Time Dial1000.29s

In this example

10

p

Multiple of Pickup = 3.

TD = 0 5 Time = 0 3s

1

SEC

ON

DS

TD=0.5

TD=2

TD=6

TD = 0.5 Time = 0.3sTD = 2 Time = 1.1sTD = 6 Time = 3.4sTD = 15 Time = 7.0s

0.1

TD 6

TD=15

0.010.1 1 10 100

Multiples Of Pick UpMultiples Of Pick Up


Very Inverse Curve Time DialVery Inverse Curve Time Dial1000.29s In this example,

Pi k 600 A

10

Pickup = 600 A.Fault Current = 1800 A.

TD = 0.5 Time = 0.29s

1

SEC

ON

DS

TD=0.5

TD=2

TD=6

T 0.5 Time 0. 9sTD = 2 Time = 1.16sTD = 6 Time = 3.48sTD = 15 Time = 8.72s

0.1

TD 6

TD=15Pickup = 900 A.

Fault Current = 1800 A.

0.010.1 1 10 100

Multiples Of Pick Up

TD = 0.5 Time = 0.69sTD = 2 Time = 2.78sTD = 6 Time = 8.33sTD = 15 Time = 20 8sMultiples Of Pick Up TD = 15 Time = 20.8s


Pickup Current of Delayed Ground OC Devicesp y

Source Side Load Side

Single Phase to Ground Fault

PrimaryBackup

IMU<IPU<I MIN Fault

g

IMU = Maximum Unbalance


Pickup Current of Delayed Phase OC Devicesp y

Source Side Load Side

IML<IPU<Imin Ø‐Ø Fault Phase to Phase Fault

IML = Maximum Load


Typical Pickup Setting

TB > TR + CTI CTI = Coordination Time Interval (Typically 0.2-0.5sec)

Recloser Ct ratio 600:1 Breaker Ct ratio 240:1IPU = 1 A IPU = 3.75 A

IPU Primary= 600 A IPU Primary= 900 A


Trip LogicTR OC + PB9 + 51P1T + 51G1T * (LT6 + LT7) + (50P3 + 50G3) * LT7 + (50P2 + 50G2) * SH1TR = OC + PB9 + 51P1T + 51G1T * (LT6 + LT7) + (50P3 + 50G3) * LT7 + (50P2 + 50G2) * SH1

OC: OPEN COMMAND (SCADA TRIP)PB9: FRONT PUSH BUTTON51P1T: PHASE TIME OC ELEMENT51G1T: GROUND TIME OC ELEMENTLT6: TAGGING IS IN NORMAL MODELT7: TAGGING IS IN WORK MODE50P2/50P3: PHASE INSTANTANEOUS OC ELEMENT50G2/50G3: GROUND INSTANTANEOUS OC ELEMENTSH1: RECLOSING SHOT #1 (FIRST RECLOSE ATTEMPT)

CTR = 600.0 INSTANTANEOUS ENABLED ONLY AFTER FIRST RECLOSE ATTEMPT50P2P = 2.5 (1500 AMPS PRIMARY)50G2P = 1 6 (960 AMPS PRIMARY)50G2P 1.6 (960 AMPS PRIMARY)

INSTANTANEOUS ENABLED ONLY DURING WORK/HOT LINE TAG50P3P = 1.35 (810 AMPS PRIMARY)50G3P = 0 50 (300 AMPS PRIMARY) NORMAL UNBALANCE GROUND CURRENT ~20 TO 30 AMPS50G3P = 0.50 (300 AMPS PRIMARY) – NORMAL UNBALANCE GROUND CURRENT ~20 TO 30 AMPS


SEL-351SHistory Summary (HIS Command)

Sample output:


SEL-351SSequence of Events Recording (SER)Sequence of Events Recording (SER)


SEL-351SMetering Data (MET Command)

Sample output - Metering Data (MET):



Sample output - Metering Demand (MET D):



Sample output - Metering Energy (MET E):



Sample output - Metering Max/Min (MET M):


Differential RelaysProtection of a Delta‐Wye Transformer

II II IA

B

a

b

Ia

5252Ib

Ia‐Ib IaIa

Ia‐Ib

Ib‐Ic

Ia‐Ib

Ib‐Ic IaB

C

b

c

5252Ic

Ib‐Ic

Ic‐Ia

Ib

Ic

Ib

Ic

Ic‐IaIc‐IaIb

Ic

Ia‐Ib

Ia‐Ib R ROP

OP

Ia‐Ib

I I

Ic‐Ia

Ib‐Ic

R

R

R

ROP

OP Ic‐Ia

Ib‐Ic Ib‐Ic

Ic‐Ia

Power System Protection -64- Ralph Fehr, Ph.D., P.E. – October 28, 2013

R R

Distance RelaysyProtection Features

– Four zones of distance protection– Pilot schemes

– Phase/Neutral/Ground TOCs

Phase/Neutral/Ground IOCs


– Phase/Neutral/Ground IOCs

Distance RelaysyProtection Features ‐ continued

– Negative sequence TOC

– Negative sequence IOC

– Phase directional OCs

– Neutral directional OC

– Negative sequence directional OC

– Phase under‐ and overvoltage

– Power swing blocking

– Out of step tripping


Distance RelaysControl FeaturesControl Features

B k F il ( h / t l )– Breaker Failure (phase/neutral amps)

– Synchrocheck

– Autoreclosing


Distance RelaysMetering FeaturesMetering Features

F lt L t− Fault Locator− Oscillography− Event Recorder− Data Logger− Phasors / true RMS / active, reactive and apparent power, power factorand apparent power, power factor


Distance RelaysZones of Protection Zone 2

X

Line Impedance (Line A)Zone 1

Zone 2

123Line Impedance (Line A)

Zone 2

Z 3

12

31

Line AA1 A2

Zone 1

Zone 3 341

2

Bus 1 Bus 2

Normal Load

Distance Relayat Bus 1

R

Zone 1 – fastest (80% of line)

2 Normal Load

to protect Line A

Zone 3

Zone 2 – slower (120% of line)Zone 3 –(backwards Use in Pilot

Protection for current

4

Reversal logic)


Zone 3Zone 2 Zone 2

Zone of Protection∆t

Zone 1 Zone 1

Zone 2

∆t∆t

∆t

1 2 43

Zone 1Zone 1 Zone 1

Zone 3

Zone 2Zone 2

Zone 3Zone 1: Under reaches the remote line end Typically 0.7 Z1L to 0.9 Z1L

With no intentional time delay.

Z 2 O h th t li d T i ll 1 2 ZZone 2: Over reaches the remote line end Typically 1.2 Z1L

with definite time delay.

Zone 3: Over reaches the longest adjacent linei h d fi i i d l h Z 2with definite time delay greater than Zone2.


Unconventional Zone 2 & Zone 3 Settings

Zone 2

Zone 1

Zone 2∆t

Long Line Short Line

Be Mindful when Applying General Rules


Step Distance Relay Coordination Exercise

Setting the relay at breaker 3 protecting Circuit 2.

Set the Zones of Protection.

The maximum expected load is about 600A.

CTR = 1200:5 or 240:1 PTR = 600:1CTR 1200:5 or 240:1 PTR 600:1


Distance Relay Coordination Exercise

Circuit 2 & Circuit 5 Impedances Circuit 3 & Circuit 6 Impedances

Z1 = 35.11 83.97˚ Ω primary

Z0 = 111.58 81.46˚ Ω primary

Z1 = 17.56 83.72˚ Ω primary

Z0 = 53.89 81.56˚ Ω primary

Circuit 1& Circuit 4 Impedances

Z1 = 35.21 83.72˚ Ω primary

Z0 = 187.80 81.56˚ Ω primary


Distance Relay Coordination Exercise

Zone 1 Reach = 0.8 * (35.11 83.97˚) Ω primary Zone 1 Reach = 28.09 83.97˚) Ω primary

Z 2 R h 1 2 * (35 11 83 97˚) Ω i Z 2 R h 42 13 83 97˚) Ω iZone 2 Reach = 1.2 * (35.11 83.97˚) Ω primary

Check Zone 2 reach does not overreach = Circuit 2 Impedance + (Zone 1 of Circuit 3) or (Zone 1of Circuit 6).

General rule = protected Circuit Impedance + Zone 1 of the Shortest Circuit past the protected circuit.

Zone 2 Reach = 42.13 83.97˚) Ω primary

p p p p

Check for Zone 2 Overreach = 35.11. + (0.8 * 17.56) = 49.16 Ω primary

Zone 2 Reach = 42.13 < 49.16 no overreach

Zone 4 Reach = 52.55 83.35˚) Ω primaryZone 4 Reach = (35.11 83.97˚) + (17.56 83.72˚) ( Ω primary)


Primary / Secondary ImpedanceRelay Input

75

Relay Input

Zone 1 Reach = 28.09 Ω x 240 = 11.24 Ω secondary600




Overcurrent Supervision Setting Criteria

1) Find the lowest Ø – Ø fault seen by relay 3for a remote end bus (4 10 5 11)

Set above (maximum load) and 60% of min fault.

Zone 1 Phase Fault detector:

for a remote end bus (4, 10, 5, 11).

Zone 2 Phase Fault detector:

Set above (maximum load) and 60% of min fault. 1) Find the lowest Ø – Ø fault seen by relay 3for a remote end bus (6, 12).( , )

Zone 4 Fault detector same as Zone 2

Repeat same process for Ground Fault detector.


Current InfeedIL =0.5 AZL =2 Ω

IR =1 AZR =1 Ω

IT =0.5 AZT =1 Ω Actual Impedance from L to the Fault is 3Ω

Apparent Impedance = EL

I L

Apparent Impedance = ( IL x ZL) + (IR x ZR)IL

Apparent Impedance = 4Ω


Thank YouThank You


feca presentation 2014 protection.pdf · ieee/ feca protection coordination june 2014 serge...

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