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USING I USING I
OP
CHARACTERISTICS TO
TROUBLESHOOT TRANSFORMER
DIFFERENTIAL RELAY MISOPERATION
Michael Thompson
James R. Closson
Basler Electric
Presented to
International Electrical Testing Association
Technical Conference
Kansas City, Missouri
March 13 - 16, 2001 (Revised July 2005) USING I
OP
CHARACTERISTICS TO TROUBLESHOOT TRANSFORMER DIFFERENTIAL
RELAY MISOPERATION
Michael Thompson, James R. Closson
Basler Electric Company
Abstract When a transformer differential relay operates with no obvious transformer fault,
system operators have a serious decision to make. Is there a transformer fault, or did the relay
operate incorrectly? Testing the transformer requires significant time, with the associated direct
and indirect costs to do so. On the other hand, reenergizing a faulted transformer can lead to
catastrophic equipment failure. This scenario of a questionable transformer operate occurs more
often than we would like to think, particularly during the equipment commissioning process.
Several conditions can cause differential relay false tripping. These conditions can cause false
trips from external faults, or simply increased transformer loading. Some indication is needed
that the relay is not operating as desired before an incorrect operate happens. A potential problem
can be identified by monitoring the operating condition of the differential relay. Indications
provided by this monitoring can serve as a warning if the settings or connections are not correct.
This paper will explore the issues contributing to transformer differential false trips, and suggest
methods to alleviate this issue.
REVIEWING DIFFERENTIAL RELAYING PRINCIPLES
When assessing relay system operation, a basic understanding of differential relay operation is
necessary. A summary of the concepts follows:
Fig. 1 General Differential Principle
Page 2
Closson/Thompson 2
Closson/Thompson
Differential relaying offers the highest selectivity and, therefore, the highest speed and most
secure type of system protection. In theory, a differential relay compares the currents into and out
of the protected zone. If the sum of the currents is not zero, the relay will operate. This is shown
in the phasor diagram, Figure 2.
The sum of the currents is identified as the operate (I
op
) or unbalance current. The relay does not
acknowledge conditions external to the protected zone. Accordingly, coordination delay times
are not necessary, and sensitivity can be optimized.
Fig. 2 Phasors of Ideal Non-Fault Condition
Differential relaying relies on the quality of the incoming currents from current transformer
secondaries. Therefore, CT performance is of particular concern in this application. Although the
relay must be desensitized to ensure security for all non-fault conditions, it must remain highly
sensitive to faults within the zone of protection. To accomplish this, a fixed minimum pickup
setting is commonly used, as well as percentage restraint. Percentage restraint increases the
amount of unbalance, or operate current, needed to actuate the relay based on the current flowing
through the protected equipment. The restraint setting, or slope, defines the relationship between
restraint and operate currents (See Figure 3). Relays vary in the way they define the restraint
value in the calculation of I
op
/Irestraint percentage ratio. Two common methods are to take the
average of the two currents (current entering the zone and current exiting the zone) or to take the
maximum of the two currents to use in the percentage ratio.
Fig. 3 Percent Restraint Characteristic Page 4
Closson/Thompson
TRANSFORMER DIFFERENTIAL SPECIFICS
Transformer differential relaying does have some complications, which can be the source of
errors in connections and set-up. As noted, differential relaying is based on virtually balanced
current into and out of the protected zone. However, a transformer is not a balanced current
device. The currents into and out of a transformer will differ by the inverse of the transformer's
voltage ratio. Thus, the associated currents need to be adjusted to represent a balance during non-
fault conditions. To a great extent, this adjustment can be accomplished with the selection of the
system current transformers. The final balancing is accomplished in the relay's TAP settings. The
TAP settings scale the input currents, effectively defining per unit values. The success of this
balancing is measured by the mismatch, which is the percentage difference between the ratio of
the currents seen by the relay and ratio of the relay taps.
Fig. 4 Transformer Differential Relaying
There are also conditions on the power system that create unbalance currents in a transformer,
but do not represent transformer faults. When system voltage is applied to a transformer at a time
when normal steady-state flux should be at a different value from that existing in the transformer,
a current transient occurs, known as magnetizing inrush current. The differential relay must
detect energization inrush current and inhibit operation. Otherwise, the relay must be temporarily
taken out of service to permit placing the transformer in service. In most instances this is not an
option. The harmonics in faults are generally small. In contrast, the second harmonic is a major
component of the inrush current. Thus, the second harmonic provides an effective means to
distinguish between faults and inrush.
Almost every transformer differential relay available inhibits operation based on the 2
nd
harmonic
content of the energization current. A parallel 'high set' operate level is included to ensure that
larger faults will still be detected during energization. The high set, unrestrained element is also
provided to ensure operation for a heavy internal fault such as a high side bushing flashover.
This high grade fault may result in CT saturation, which can generate significant harmonics that
may restrain the sensitive harmonic restrained element. This is shown in Figure 5. 4
Closson/Thompson
External faults can also cause unbalanced currents in a power transformer, depending on the
transformer's connections. A Wye connected transformer winding can act as a power system
ground source, providing ground current to external faults. This unbalanced current must be
blocked from the differential circuit to ensure relay security. This blocking is usually achieved by
a Delta connection in the associated relay input transformer circuit, which traps the zero se-
quence (ground) current component. This delta connection can be achieved either with the
current transformers, or, if an option, within the transformer differential relay itself.
Fig. 5 Simplified Block Diagram
An important issue with transformer differential relaying is the phase shifts inherent in most
transformer connections. A delta connection in a power transformer affects a 30° phase shift in
the associated currents. Since the differential relay compares the currents on an instantaneous
basis, this phase shift will create an unbalance, which must be compensated. This compensation
is usually achieved with a corresponding delta connection in the CT secondary circuits and must
be coordinated with any zero sequence blocking connections required.
Many transformers are connected with delta windings on the high side and wye windings on the
low side. This provides isolation between the power system voltages and a ground source for
detecting faults on the low voltage side. The three-line drawing, Figure 6, shows a delta/wye Page 6
Closson/Thompson
transformer with the associated phase shifts. In this example, the phase shift is accomplished by
connecting the CT's on the wye side in a delta configuration. The required phase shift compensa-
tion can also be accomplished within the differential relay. This is desirable for several reasons.
Probably the most important of these is that it allows the CT's to be connected in wye, making
them easier to connect and verify during installation.
Fig. 6 Phase Shifts in Transformers
The presence of a Load Tap Changer (LTC) in transformers will also affect differential relay
operation. Usually, these taps provide the possibility of modifying the voltage ratio 10% for
voltage or Var control. This ratio variance, in turn, varies the current ratios. This variation is
usually within the security margin provided by the relay's restraint characteristic. For a given
LTC position, the ratio of operate current to restraint current will remain constant, as shown in
Figure 7. 6
Closson/Thompson
Fig. 7 Operate Characteristics with Proper Configuration (10% Mismatch)
CONNECTION CONCERNS
Almost all nuisance trips associated with transformer differential relay applications can be
attributed to incorrect relay settings or CT connections or mismatch. During a through-fault
condition, the differential operating current due to mismatch can approach the current rating of
the transformer. These typical mistakes will be discussed, along with their effects on relay perfor-
mance.
For each case discussed, the TAP settings are presumed to be set to the transformer's full load
current. This defines the 1 per unit value to be equal to full load. This is the easiest setting to
calculate, and simplifies analysis. The minimum pickup of the transformer differential relay is
taken as 0.