19-10-2012, 01:31 PM
Primary-Side Transformer Protection
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INTRODUCTION
There are many different protection schemes used today for
distribution substation transformers, covering a wide range
of expense and complexity—from high-end ring bus and
breaker-and-one-half schemes, to low-end flash bus and
grounding switch schemes. Given the pressure to increase
the continuity of service, more advanced protective devices
are called for than a motor-operated disconnect switch to
initiate a fault. Today, the best practice is to individually
protect each transformer with a local protective device.
Doing so eliminates the need to take off-line all transformers
connected to the transmission line, when only one
transformer has experienced a fault . . . unnecessary
interruptions to service are avoided.
Secondary-side bus faults are the most common type of
event that a primary-side protective device must interrupt.
But they may be difficult for some devices due the highfrequency
transient recovery voltage (TRV). One might
think that a device with a robust fault interrupting rating—
such as a 40-kA circuit breaker—would be able to handle a
relatively low-magnitude fault on the secondary-side of the
transformer. But the secondary-fault interrupting rating of a
device is dependant on the device’s ability to withstand a
fast-rise transient voltage—much faster than that seen
during high-current fault interrupting. Therefore, the device
must be specifically tested to determine its ability to
withstand and interrupt fast TRVs. A device with a 40-kA
primary-fault interrupting rating may not necessarily be able
to interrupt 4-kA secondary faults with a fast-rise transient
voltage.
LOCATIONS OF FAULTS AFFECTING THE
TRANSFORMER
Primary-side protective devices are widely applied at loadtap
transformers where the available primary fault current
exceeds the device’s primary-fault interrupting rating.
Overlapping protection from statistically rare high-current
primary faults is afforded by the line-terminal circuit
breakers and first-zone phase- and ground-fault lineprotective
relays. On systems using line-terminal circuit
breakers, circuit interruption following a high-current
primary fault is typically accomplished by the line breakers
in 3 cycles. A local primary-side transformer protective
device will respond to faults internal to the transformer and
to faults on the secondary bus that is included in its zone of
protection. It can also provide back-up protection for the
secondary-side protective device(s). A properly applied
transformer protective system will overlap some of the
protection provided by the line-terminal circuit breakers and
supplement the protection afforded by the secondary-side
protective device(s).
SECONDARY-SIDE FAULT INTERRUPTION
Secondary-side faults, found in Location 4 in Figure 1
(above), are difficult to interrupt. Special attention must
be paid to selecting a device that can interrupt these lowcurrent
transformer-limited faults. Such faults are limited
by the impedance of the transformer, so they have modest
magnitudes, but the transient recovery voltage (TRV)
frequency seen by the interrupting device after clearing
the current is high because of the small bushing and
winding capacitance of the transformer, compared to its
large inductance.
SELECTING TRANSFORMER PRIMARY-SIDE
PROTECTIVE DEVICES
Selecting a primary-side device for a new substation can be
just as much an economic decision as a technical one.
Smaller, less expensive transformers are often protected with
power fuses. In the past, these transformers have been
protected with remote protection schemes which rely on the
line-terminal breakers to protect the transformer, as well as
to provide back-up protection for the secondary-side
protective device. Larger transformers and transformers
serving critical loads are usually protected with devices that
use relaying schemes—from simple overcurrent relays to
sophisticated combinations of differential, sudden pressure,
overcurrent and instantaneous relays that fully coordinate
with upstream and downstream devices.
Once a device with the appropriate secondary-side
interrupting rating requirements has been identified, the
selection process largely becomes a matter of choosing the
features and configuration appropriate to the installation.
Factors such as available substation real estate, bus layout,
seismic requirements, structure height requirements,
equipment maintenance cycles, and system ratings are only a
few of the factors that must be considered . . . the suitability
of the device for a particular substation is usually a matter of
utility preference.
Circuit Breaker
Circuit breakers are also used for transformer protection, as
shown in Figure 7. Like circuit-switchers, circuit breakers
are relay-activated. Breakers offer higher interrupting ratings
than power fuses and circuit-switchers, are SCADAcompatible,
and work with the same protective relay
schemes as circuit-switchers. Breakers are generally used in
complex bus schemes, such as ring-bus or breaker-and-onehalf
schemes. In those situations, the breaker acts as both the
transformer protective device and the protective device for
the incoming lines—thus the need for high-speed reclosing,
short-line fault interrupting capability and, in many cases,
high primary-fault current capability. In the United States,
dead-tank breakers are typically used since current
transformers can be economically applied.
CONCLUSION
Providing a local primary-side protective device for each
distribution substation transformer affords the best
protection against secondary-side faults, and eliminates
unnecessary disturbances on the transmission line. When
selecting a primary-side protective device, careful
examination must be made of its secondary-side fault
interrupting capability. Other factors must be taken into
consideration, including the cost of the transformer, the
criticality of the load, and the available resources.