Analysis and Solutions to Unusual Differential Relay Misoperation During External Disturbance
Analysis and Solutions to Unusual Differential Relay Misoperation
During External Disturbance
Jiseong Kang †,
Sunghyun Byun *,
Jeongjae Yang **,
Jongman Cho ***
Abstract – In this paper, two relay misoperation events are introduced. Misoperated functions are “Unit
Overall Differential” function and “Transformer Ground Differential”, also known as “Restricted Ground
Fault” or “Restricted Earth Fault” function. Both relays operated when the operator tried to combine separated
buses by closing the CB. The reason why the relays misoperated can be found in the relay’s internal scheme,
which is reducing the bias current smaller than ordinary values. This method enhances the sensitivity and it is
a kind of the provider’s philosophy. But this paper outlines that the bias reduction is sometimes risky, because
the misoperation happened in normal operating condition. The operator’s corrective action to prevent the
misoperation will be described in this paper. Disturbance analyses based on the technical reference materials
are also included in the paper.
Keywords: Relay Misoperation, Unit Overall Differential, Transformer Ground Differential, Restricted Ground Fault,
Switching Transient
1. Introduction
Most numerical relays offer highly secured differential
protection functions to protect the generators and
transformers. The function is usually prevented from tripping
during external fault by automatically increased bias.
However, in Korea, generators became unexpectedly tripped
by switching disturbance.
Korea Power Exchange(KPX), who is responsible for
coordinating every bulk power plant protection as a public
organization, analyzed this event to prevent the wrong
tripping. The main cause was revealed to be a reduced bias.
And it was mainly because the installed relay’s internal
scheme inclined to have a sensitive operation under a specific
situation. According to the scheme, the restraint factor was
too small to inhibit the differential factor.
This paper is going to describe and explain about two
events regarding this issue. Each event is analyzed focusing
on each protective function’s behavior
2. Network Description
The tripped generator units are connected to the 345kV
† Korea Power Exchange, Protection Team (toasty@kpx.or.kr)
* Korea Power Exchange, Protection Team (shbyun@kpx.or.kr)
** Korea Power Exchange, Protection Team Leader (jjyang@kpx.or.kr)
*** Korea Power Exchange, Vice President (jongman@kpx.or.kr)
switch yard through step up transformers. The high voltage
side is composed of gas insulated switchgear, and configured
with double-busbar, one-and-half CB layout. 9 generators
with 6 step up transformers, and 2 tie transformers are
connected to the switch yard. And the switch yard is
connected to 4 neighboring substations through 6
transmission lines. There are 4 series current limiting reactors
within the transmission lines. All tie transformers are
grounded because they are autotransformers, and 2 step up
transformers are grounded in order to maintain effective
grounded system. Rest transformers are ungrounded,
mitigating the single line to ground fault current magnitude.
Also it is common to split buses to reduce the fault current
level in Korea. The switch yard bus in this example is also
separated for the same purpose, not to exceed the interrupting
duty of the CB, which is 50kA.
During normal operation, all generator bays are connected
to the bottom bus, and all transmission line bays are
connected to the upper bus. A lot of current flows from the
bottom bus to the upper bus when the operators close CB to
connect the buses.
Figure 1 shows the configuration of first trip case, “Case 1A” namely. Figure 2 shows the configuration of second trip
case, “Case 2-G” namely. Figure 3 shows neighboring
substations and installed series reactors limiting power flow.
Presented at 42nd Western Protective Relay Conference, October 19-22, 2015
Analysis and Solutions to Unusual Differential Relay Misoperation During External Disturbance
grounding. The magnitude was about twice much as the
transformer’s rated current.
Fig. 1 Case 1-A Network Configuration
Fig. 4 Transformer phase currents (Case 1-A)
Very high DC offset with long time constant is recorded
when closing the CB. This can be a kind of inrush[1][5], so
the transient magnitude itself would not be a problem to the
relays. But it is obvious that the measured DC offsets are not
symmetrical between high voltage side CTs, CT1 and CT2.
The waveforms of two CTs are shown in Figure 5.
Fig. 2 Case 2-G Network Configuration
Fig. 5 DC offset difference (Case 1-A)
Fig. 3 Neighboring Substations and CLRs
3. Case 1-A Event
In the first case, the trip is occurred at the grounded
transformer bay. The function picked up was “Unit Overall
Differential”(ANSI 87U). At the moment of closing the 7B71
CB, zero sequence current flowed through transformer
At the start of transient the offset is practically equal, but
around 50ms before the trip the offset in CT1 is starting to
reduce, while the offset in CT2 remains the same level. At the
same time, differential current is starting to increase until it
reaches the set level of trip.
Inside the relay, the first step is to extract the fundamental
frequency waveform by performing DFT[2]. Table 1
describes the fundamental portion of each phase, at the time
of making trip signal. It shows that the 60Hz fundamental
portion of CT2 is not much as that of CT1, meaning the DC
Presented at 42nd Western Protective Relay Conference, October 19-22, 2015
Analysis and Solutions to Unusual Differential Relay Misoperation During External Disturbance
offset was not decayed sufficiently.
Table 1 Fundamental Frequency Current Portion (Case 1-A)
A phase
B phase
C phase
High Voltage Side CT1
99%
88%
78%
High Voltage Side CT2
76%
77%
81%
And Figure 6 shows the Bias versus differential trajectory.
The differential current was just above the minimum pickup.
But the restraining factor was too small compared to the large
passing current through high voltage side CTs, as shown in
Figure 5.
Fig. 7 CT inputs configuration (Case 1-A)
However in this case 1-A, this separation can’t be
maintained until the trip decision made, because the relay
internally combines those two currents into a single winding
current. After conducting that procedure, the largest phase
current among the winding currents is used as bias current[2] .
Equation 1 well expresses the calculation.
87U BIAS = MAX(CT1+CT2,CT3,CT4,CT5)
Fig. 6 Differential VS. Bias Trajectory (Case 1-A)
The reason can be understood by its internal scheme. This
type of relay internally combines the one-and-half side CTs
feeding for bias calculation. Its purpose is to “prevent
unwanted desensitizing”, namely to make it more sensitive
against the passing through current[2]. Actually that kind of
sensitizing is not needed because normally there is always a
strong fault current far exceeding the ordinary bias in Korea
network.
Before the protection system construction, commissioning
engineers and system operators did not wanted any sensitive
operation of differential relays. So the two CT inputs are
separated not to externally sum up before going into the relay.
They believed that it would provide the secure restraint
current. Figure 7 expresses the original configurations of CT
inputs conducted by engineers.
(Eq.1)
And Table 2 describes each CT’s current and the relay’s
calculated current at the time of tripping.
Table 2 A phase CT currents at the time of tripping (Case 1-A)
F/R
CT1
CT2
Gen.
Aux.
IDIFF
IBIAS
1469A
1799A
4456A
96A
-
-
215A
5A
155A
334A
Relay
334A
Relay current values are compensated values including
voltage, phase shift, zero sequence elimination, fundamental
frequency extraction.
On the other hand, there is an interesting point in another
differential function, “Transformer Ground Differential”
(ANSI 87N). The high voltage CT inputs going into the relay
are same as the 87U function. But in this 87N function, high
voltage side currents are not combined internally. Unlike the
87U function, the largest current among all separated phase
currents is used as the bias current in this function. Therefore
the 87N function calculated the bias current about 1,800[A],
which is more than 5 times bigger than the bias current used
in 87U, 334[A]. Equation 2 expresses the difference of 87N
in bias calculation.
87N BIAS = MAX(CT1,CT2,IN)
Presented at 42nd Western Protective Relay Conference, October 19-22, 2015
(Eq.2)
Analysis and Solutions to Unusual Differential Relay Misoperation During External Disturbance
If the 87U function also used the same bias scheme as the
87N, then up to 1,350[A] of differential current would be
allowed. This gives us a good implication because the
function definitely would not misoperate. Figure 8 shows the
operating characteristic of the 87N function.
Fig. 10 DC offset difference (Case 2-G)
And zero sequence current also passed through high
voltage side CTs. In this case, 87N function uses terminal side
3I0 current as differential. Decaying difference between two
CTs is also happened like previous case.
Fig. 8 Operating Characteristic of 87N function (Case 1-A)
4. Case 2-G Event
In the second case, the trip is occurred at the ungrounded
transformer bay. The function picked up was 87N in this case.
The relay manufacturer is different from case 1-A. Most
relays provide secured 87N function and do not make a trip
signal without the current through grounding conductor. But
in this case the relay operated even if the transformer is not
grounded.
Fig. 11 Zero sequence current at the terminal side (Case 2-G)
Regarding the bias current, the relay uses a unique scheme.
If the positive sequence current is smaller than 150% of the
CT primary rating, then the relay cuts down the bias current
to 12.5% of the original bias current[3][5]. And in one-andhalf CB layout, the probability of this bias reduction increases.
This is because normally switch yard CT margin is larger than
that of the transformer terminal side CT, therefore more
positive sequence current will be required to overcome larger
CT margin and to escape the bias reduction zone.
Fig. 9 Transformer Ground Differential (Case 2-G)
The problem is similar to the previous case. Figure 10
shows that the two CT measurements started making
difference on its way to stabilize after switching. Extreme DC
offsets also took place at the time of switching.
Fig. 12 Differential VS. Bias Trajectory (Case 2-G)
Presented at 42nd Western Protective Relay Conference, October 19-22, 2015
Analysis and Solutions to Unusual Differential Relay Misoperation During External Disturbance
The purpose of using this scheme is to have a better
sensitivity against low level winding fault currents[3]. This
philosophy is same to the previous 1-A case. However, if the
transformer is not grounded, it is not desirable to make a trip
signal even if there is some level of 3I0 current through
transformer terminal. But in this case the relay does not have
any blocking factor for ungrounded transformers, so this can
be categorized as a lack of security.
On the other hand, there is also phase differential current in
this 2-G case. Unlike the first case, the relay decided not to
trip because the bias was remained strong. Compared to
having just 335[A] bias in case 1-A, case 2-G held bias of
1,950[A]. This means that the relay 2-G does not combine
high voltage CT currents.
The interesting point is that the same amount of differential
current worked totally different result among different relays.
The differential and bias position is compared graphically in
Figure 13. Relay 1-A decided to trip and Relay 2-G decided
not to trip.
winding for the high voltage side in order to match each CT at
one winding only. Because the maximum number of winding
which can be configured by user is limited to 3, all low
voltage side CTs except the generator CT should be joined
before going into the relay. Figure 14 and Table 4 show how
the wirings and setting parameters are changed based on the
solution.
Table 3 Event Summary and Comparison
*1pu = transformer rated current
** Possible maximum values (in case loss of 1 CT current)
Event Date
Case Id.
Transformer
Grounding
Idiff.
87U
87N
#3ST
27th. Mar. 2015
1-A
#2ST
2nd. Jan. 2015
2-G
Grounded
Ungrounded
0.47pu
0.38pu
Ibias
1.00pu
5.83pu
Idmin.
0.46pu
0.33pu
Slope
Pickup
Criteria
Trip
47%
7%
Idiff. > Idmin.
Slope > 50%
YES
NO
Idiff.
1.94pu**
0.40pu
Ibias
7.55pu
0.09pu
Idmin.
0.35pu
0.36pu
Slope
Pickup
Criteria
Trip
26%**
426%
Slope > 75%
Idiff. > Idmin.
NO
YES
Table 4 Configuration Table for Case 1-A
Parameter
Fig. 13 Differential VS. Bias Comparison
5. Solutions and User’s guide
After conducting analysis on two misoperation cases, KPX
needed to find a way to enhance restraining factor of
differential relays. Table 3 outlines the summary and
comparison of the two relays’ behaviors.
Though the relay manufacturers want to enhance their
relay’s sensitivity by using their own special schemes, system
operators may want to limit the sensitivity at a certain level to
prevent misoperation.
After the 1-A case event, KPX directed to change the CT
inputs and relay setting. Physically the 2 CTs are in the same
transformer winding section, but KPX allocated one more
Before
After
Winding1
CT1
①7B72
①7B72
Winding1
CT2
②7B00
-
Winding2
CT1
③Generator
②7B00
Winding2
CT2
④St. Tr.
-
Winding3
CT1
⑤Aux. Tr.
③Generator
Winding3
CT2
-
④St.+⑤Aux. Tr.
Presented at 42nd Western Protective Relay Conference, October 19-22, 2015
Analysis and Solutions to Unusual Differential Relay Misoperation During External Disturbance
Voltage Deg.
-11.4
-5.3
Source R1
0.1666 ohm
0.1071 ohm
Source X1
5.2371 ohm
5.1895 ohm
Source R0
0.2738 ohm
0.2738 ohm
Source X0
5.0348 ohm
7.0106 ohm
X/R Ratio
31.4
48.4
And Figure 16 represents the PSCAD simulation model
based on above values.
Fig. 14 Solution to Case 1-A
In the 2-G case, KPX added the grounding CT current as a
supervisory factor. So even if the 87N function operates
according to the internal calculation, it can’t make a real trip
signal without fulfilling the current level of the grounding CT.
Thus this function will not operate any more within the
ungrounded transformer, like other major manufacturers’
relay’s practice. Figure 15 shows how the trip logic changed
based on the solution. This additional feature can be achieved
without a big effort.
Fig. 16 PSCAD simulation model for Case 1-A
When closing the CB, the simulation also shows the
transient currents like Figure 17. Large current is passing
through the high voltage side switch yard CTs. Fig.17(a) is
the CT1 current and the Fig.17(b) is the CT2 current.
Fig. 15 Solution to Case 2-G
6. Event Simulation
The fault recordings installed on the switch yard and
disturbance recordings memorized in the relay definitely
shows us that there was a big switching transient waveform.
Table 5 describes the network impedance and related
values needed to set up a simulation. Values are from the
EMS snapshot, at the time of just before closing the CB.
Because the switch yard is connected to the series reactors
the X/R ratio is high which directly affected to the big
transient effect[4].
Fig. 17(a) Passing current by switching transient in CT1
Table 5 Network values used for the PSCAD Simulation
Voltage Mag.
Bus 1
Bus 2
355kV
356kV
Fig. 17(b) Passing current by switching transient in CT2
Presented at 42nd Western Protective Relay Conference, October 19-22, 2015
Analysis and Solutions to Unusual Differential Relay Misoperation During External Disturbance
The waveforms can be extracted to the fundamental,
second harmonic, 5th harmonic portion using DFT. Figure 18
illustrates the DFT result of high voltage side CT1 and CT2.
Fig. 18(e) 2nd Harmonic Current in CT2
Fig. 18(a) PSCAD DFT Module to analyze waveform in Case 1-A
Fig. 18(f) 60Hz, 120Hz, 300Hz Portion in CT1
Fig. 18(b) DC Component in CT1
Fig. 18(g) 60Hz, 120Hz, 300Hz Portion in CT2
Fig. 18(c) DC Component in CT2
Fig. 18(d) 2nd Harmonic Current in CT1
In Fig.18(f~g), the blue line represents the fundamental
frequency content, the green line represents the second
harmonic content, and the violet line represents the 5th
harmonic content in percentage unit.
The second harmonic current was dominant in the transient
waveform, and this explains that the transformer inrush
current passed through CTs when closing the CB. Inrush
current is consist of DC component and harmonics, and
decaying DC component is a non-periodic signal with a wide
spectrum band[8].
The fundamental content difference between the two high
voltage side CTs is up to about 14% in this simulation(Figure
19). But in the Table 1, we saw that the difference in the
recorded waveforrm was 23% at the time of tripping. So it is
supposed that there were additional factors like CT
inacuraccy or CT characterisic difference, wich made a bigger
difference. And at the time of tripping, second harmonic
portion did not exceed 15%, because the trip is blocked
Presented at 42nd Western Protective Relay Conference, October 19-22, 2015
Analysis and Solutions to Unusual Differential Relay Misoperation During External Disturbance
during the second harmonic content is more than 15%, or the
5th harmonic content is more that 20%.
Fig. 19 60Hz Portion % Difference between CT1 and CT2
7. Summary and Conclusion
So far this paper has discussed the reason why the relay
misoperated in both cases. Though it was neither the
commissioning nor the setting, users can not be free from
responsibilities of tripping. Therefore it is important for users
to be aware of the relay’s internal scheme. Usually the users
trust the manufacturer’s philosophy and believe that the relay
is secure and robust. Actually most of the time, the relays are
immune to the external disturbance, meeting the customer’s
expectation.
But the two events happened in Korea showed that the
relays were working under a particular network situation.
Facilities and switchgear configurations altogether made high
X/R ratios and big transients. So if a relay is prepared to
operate as sensitive as possible, it is pretty likely to make a
trip. The probability will increase if the additional error
factors like CT inaccuracies are applied.
When deciding whether “to trip” or“not to trip”, the
decision is normally up to the relay’s internal scheme
calculating the differential and bias current. In general, the
higher the bias current, the higher the differential current
required to produce a trip[2]. KPX found that the schemes can
be different among relay manufacturers, and even can be
different among functions within the same relay. The relay’s
trip decision is largely affected by its internal scheme.
The 1-A case shows that its 87U function weakens the bias
current when two or more CTs are configured within the same
winding section. In this case the function combines the 2 CT
currents, hence the bias current reduces and the relay is more
likely to operate. The reason why relay weakens the bias is to
prevent “Unwanted Desensitizing”.
Similarly, the 2-G case shows that its 87N function
weakens the bias current when the phase current is less that
two times of CT primary current. In this case the bias current
is divided by 8 times. Moreover the ground current is not
supervised. The reason why this relay weakens the bias is to
ensure “Maximum Sensitivity”.
From the relay’s behaviors described above, we can know
that intentionally increasing sensitivity can also increase the
probability of misoperation. It is the operator’s decision
whether to accept the manufacturer’s concept or not. If not, it
is also the operator’s task to do the corrective action. For the
Case 1-A, changing the CT inputs and relay setting can be the
solution. For Case 2-G, the solution is to supervise the ground
CT current before making a trip.
Finally, this paper conducted PSCAD simulation to analyze
the transient and to see harmonics contained in the waveform.
The result showed that the majority of the transient was
transformer inrush current caused by CB switching.
But the reason why the DC decaying times were different
between two high voltage CTs is still in question. The CT
inaccuracy or different CT characteristics might be the answer,
but it is not proved yet. Further research is needed to find out
the exact phenomena.
References
[1] Transformer Inrush, Open Electrical website. Available:
http://www.openelectrical.org/wiki/index.php?title=Tran
sformer_Inrush
[2] Technical Reference Manual of RET670, ABB
[3] T60 Transformer Protection System, GE
[4] John Merrell, “The Importance of the X/R Ratio in LowVoltage Short Circuit Studies”, pp.1~3, Nov. 1999
[5] Hanli Weng, “Studies on the Unusual Maloperation of
Transformer Differential Protection During the
Nonlinear Load Switch-In”, IEEE TRANSACTIONS
ON POWER DELIVERY, Vol. 24, No. 4, pp.
1824∼1831, Oct. 2009
[6] Bogdan Kasztenny, "Impact of Transformer Inrush
Currents on Sensitive Protection Functions", 32nd
Western Protective Relay Conference, Oct. 2005
[7] Fahrudin Mekic, “Power Transformer Characteristics
and Their Effect on Protective Relays", 33rd Western
Protective Relay Conference, Oct. 2006
[8] Shantanu Kumar, “Elimination of DC Component and
Identification of Inrush Current using Harmonic
Analysis for Power Transformer Protection”, IEEE
TENCON Spring Conference, pp.1~2, 2013
Presented at 42nd Western Protective Relay Conference, October 19-22, 2015
Analysis and Solutions to Unusual Differential Relay Misoperation During External Disturbance
Jiseong Kang received the B.S. and M.S.
degrees from Yonsei University, Seoul, Korea,
in 2008 and 2012, respectively. He is currently
Assistant Manager for Power Grid Protection
Team in Korea Power Exchange, Naju, Korea.
His job is coordinating protective relays in power plants and
transmission networks. His research interests include power
system protection and operation.
Sunghyun Byun received the B.S. and M.S.
degrees from Sungkyunkwan University, Seoul,
Korea, in 1996 and 1998, respectively. He is
currently Manager for Power Grid Protection
Team in Korea Power Exchange, Naju, Korea.
His research interests include power system protection and
operation.
Jeongjae Yang received the B.S. degrees from
Konkuk University, Seoul, Korea, in 1989. He
is currently the Leader of Power Grid
Protection Team in Korea Power Exchange,
Naju, Korea. His research interests include
power system protection and operation.
Jongman Cho received the B.S. degree from
Seoul National University of Science and
Technology, Seoul, Korea, in 1986, and the
M.S. degree from Gyeongsang National
University, Jinju, Korea, in 1998, and the Ph.D.
degree from Hanyang University, Seoul, Korea, in 2006. He
is currently the Vice President of Korea Power Exchange,
Naju, Korea. His research interests include power system
dynamics, economics, and operation.
Presented at 42nd Western Protective Relay Conference, October 19-22, 2015