ISSN 2167-3594 NETISSN 2167-3594 NETA WORLD JOURNAL PRINTA WORLD JOURNAL PRINTISSN 2167-3586 NETISSN 2167-3586 NETA WORLD JOURNAL ONLINEA WORLD JOURNAL ONLINE

WIN

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2016

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RREEGGISTISTEER TR TOODDAY

INSIDE!INSIDE!INSIDE!INSIDE!INSIDE!INSIDE!INSIDE!PPRREEVVIEIEWW G GUUIDIDEE

CELEBRATE NETA’S 45TH ANNIVERSARY

THE FUTURE OF

AND PROCESS AUTOMATIONINTEGRATED POWER

PROTECTIVE RELAY MISOPERATIONS AND ANALYSISPROTECTIVE RELAY MISOPERATIONS AND ANALYSIS

RELAY COLUMNRELAY COLUMN

Original Protection SettingsFigure 3 shows the original relay settings

for this breaker failure scheme.

Fault Current SignalsFigure 4 shows the oscillography captured by

the relay at the time of the trip.

Figure 5 shows the current phasors measured

by the protective relay when the breaker failure

occurred.

Figure 4:Figure 4: Fault Event OscillographyFault Event Oscillography

Figure 3: Breaker Failure Settings

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Figure 5:Figure 5: Fault Current PhasorsFault Current Phasors

PROTECTIVE RELAY MISOPERATIONS AND ANALYSISPROTECTIVE RELAY MISOPERATIONS AND ANALYSIS

RELAY COLUMNRELAY COLUMN

Case 1 ConclusionCase 1 ConclusionThe breaker failure trip occurred because I

C was

above the current detector pickup setting and

input 4 (BFI) was asserted.

The breaker failure function may be used for a

unit breaker rather than a generator breaker. It is

limited in that no fault detector is associated with

the unit breaker. Output contact operation would

occur if any of the initiate contacts close, and the

52b contact indicated a closed breaker after the

set time delay. The corresponding logic is shown

in Figure 6.

CASE 2: TRANSFORMERDIFFERENTIAL TRIP DUE TO SYMPATHETIC INRUSHThe transformer differential relay protecting

the step-up transformer at a processing plant

tripped when a nearby large GSU at a power

plant was energized from the high side. The trip

was due to sympathetic inrush current flowing

through the step-up transformer (Figure 7).

Original Protection SettingsOriginal Protection SettingsFigure 8 shows the original settings for the

transformer differential protection.

Fault Current SignalsFigure 9 shows the oscillography captured by the

relay at the time of the trip. Note that current

input IAW1 is almost completely offset, and there

is some distortion in other current inputs as well.

Figure 6: Fault Current Phasors

Figure 7: System Operating Conditions (Arrows Indicate Direction of Inrush Current)

Figure 8: 87T Settings

Figure 9:Figure 9: Fault Event Oscillography (Raw Waveforms)Fault Event Oscillography (Raw Waveforms)

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PROTECTIVE RELAY MISOPERATIONS AND ANALYSIS4646 • WINTER 2016WINTER 2016

RELAY COLUMNRELAY COLUMN

Harmonic Restraint CalculationsFigure 10 shows the second harmonic content

of the current inputs at the time of the trip. The

second harmonic differential current present

when the trip occurred was as follows:

A-Phase = 17 percent

B-Phase = 13 percent

C-Phase = 13 percent

The ratio of harmonic to fundamental differential

current used to restrain the transformer differential

protection is calculated as follows (Figure 11):

If the ratio is greater than the restraint setting,

then the transformer differential protection is

blocked (Figure 12).

The original second harmonic restraint setting was

20 percent for the electro-mechanical transformer

differential relay. The customer used the same

setting for the multi-function numerical relay that

replaced the original electro-mechanical relay.

Figure 10 showed that a setting of 20 percent was

not sensitive enough to detect the sympathetic

inrush current flowing through the step-up

transformer.

Case 2 ConclusionFor several decades, electro-mechanical relays

had a fixed harmonic inhibit level of 20 percent.

This worked well for a period of time until

transformer manufacturers began making better

transformers that used less material and were

designed with smaller tolerances. Therefore,

modern laminated-steel-core transformers will

not reliably produce 20 percent second harmonic

current during inrush.

Based upon this particular event, an 11 percent

setting for the second harmonic restraint would

be the most reliable. Note that the multi-function

numerical relay in this application actually uses

the root mean square (RMS) of the second and

fourth harmonic differential current, but that

still was not enough to restrain the protection.

Figure 10:Figure 10: Fault Event Oscillography (Second Harmonic Content)Fault Event Oscillography (Second Harmonic Content)

Figure 11: Even Harmonic Restraint Equation

Figure 12: Even Harmonic Restraint Logic

RELAY COLUMN

FINAL CONCLUSIONThe technical analysis of these two relay

misoperations, along with examples of how to use

the data recorded by a relay during these types of

conditions, should help you understand why each

misoperation occurred and how to implement

best practices for each particular application.

Knowing that the first misoperation was due to

an incorrect relay setting, while the second was

due to an incorrect application, should clarify the

need for careful attention during the design andneed for careful attention during the design and

initial work stages.initial work stages.

Steve Turner, an IEEE Senior Member, is

a Senior Applications Engineer at Beckwith

Electric Company. His previous experience

includes work as an application engineer with

GEC Alstom and as an application engineer

in the international market for SEL, focusing

on transmission line protection applications.

Steve worked for Duke Energy (formerly Progress Energy), where

he developed a patent for double-ended fault location on overhead

transmission lines. He has a BSEE and MSEE from Virginia Tech.

Steve has presented at numerous conferences, including Georgia Tech

Protective Relay Conference, Western Protective Relay Conference,Protective Relay Conference, Western Protective Relay Conference,

Energy Council of the Northeast, and Doble User Groups, as well asEnergy Council of the Northeast, and Doble User Groups, as well as

various international conferences.various international conferences.