Backup fault protection is recommended to protect generators from faults not cleared by the normal protection scheme due to failures. Voltage-dependent relays like distance relays and voltage-supervised overcurrent relays are well-suited for backup protection. They can detect low fault currents by using both current and voltage measurements to differentiate between load and fault conditions. The type of backup protection used depends on the phase protection scheme of the connected transmission system, with distance relays used if the system uses distance relays and overcurrent relays if the system uses overcurrent relays.

1. Backup fault protection for
generators in case of a
failure at the generation
station
By Edvard | December, 4th 2019 | 0 comments | Save to PDF
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The purpose of generator backup
protection
It is a common practice to use the differential relay as primary fault protection
for the generator. Backup fault protection is also highly recommended to protect
the generator from the effects of faults that are not cleared because of failures
within the normal protection scheme. The backup relaying is automatically
applied to provide protection in the event of a failure at the generation station,
on the transmission system, or both.

2. Backup fault protection for generators in case of a failure at the generation
station
Specific generating station failures would include the failure of the generator or
Generator Step Up (GSU) transformer differential scheme. On the transmission

3. system, failures would include the line protection relay scheme or the failure of
a line breaker to interrupt.
Table of contents:
1. Implementation of backup fault protection
2. Standard overcurrent relays
3. Voltage-dependent relays
4. Voltage supervised overcurrent relays
1. Voltage-controlled and voltage-restrained relays
2. Application options and fault sensitivity
5. Other distance relay applications
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1. Implementation of backup fault
protection
Figure 1 shows the sample system generator. Backup protection is provided by
distance relays (Device 21) or voltage supervised overcurrent relays (Device
51V). These relays can be connected to CTs at the neutral end of the generator
or they can be connected to CTs at the generator terminals.
The neutral end configuration is preferred because this connection will allow the
relaying to provide protection when the unit is off line. Terminal connected
relays will not see internal generator faults for this condition, because there is
no relay current.
If the scheme is intended to provide backup protection for both generating
station and system faults, the backup relays should initiate a unit shutdown.
This entails tripping the breaker on the high-voltage side of the GSU, the
generator field breaker, the auxiliary transformer breakers and initiating a prime
mover shutdown.
If the station configuration included a generator breaker it would be tripped
instead of the high-voltage breaker.
When relays are applied solely to backup transmission line relaying, only the
GSU transformer or generator breaker need be tripped. This would allow a
faster resynchronizing after the failure has been isolated. This assumes the unit

4. can withstand the effects of the full load rejection that will occur when the outlet
breaker opens.
If the unit cannot withstand this transient, a unit shutdown must be initiated.
Figure 1 – Generator online protection scheme

5. Go back to Contents Table ↑
2. Standard Overcurrent Relays
Standard overcurrent relays are not recommended for backup protection of a
generator. The backup relay must be capable of detecting the minimum
generator fault current. This minimum current is the sustained current
following a three-phase fault assuming no initial load on the generator and
assuming the manual voltage regulator in service.
If the automatic voltage regulator where service, it would respond to the fault-
induced low terminal voltage and boost the field current, thus increasing the
fault current. The assumption of no initial load on the generator defines the
minimum field current to drive the fault.
Typically, a generator’s synchronous reactance, which controls the value of the
sustained fault current, is greater than unity. If the generator is unloaded and
at rated terminal voltage (Et = 1.0) prior to the fault, the sustained short-circuit
current will be 1/Xd which will be less than full load current. In the case of the
sample system generator Xd = 1.48 and the resulting sustained three-phase
fault current would be 0.67 pu or 67% of full load current.
A standard overcurrent relay must be set above load and could not detect the
minimum sustained fault current. Tripping would be dependent on rapid relay
operation before the fault current decays below the relay’s pickup setting.
Figure 2 plots the decaying current for the minimum fault condition on the
sample system generator vs. an overcurrent relay set to carry full load. The
figure shows that the relay must be set with a very short time delay (Time Dial
= 1/4) to intersect the current plot to assure tripping.
This fast tripping is undesirable, because it would preclude coordination
with system relays and could cause misoperation during system
disturbances that do not require protective action.

6. Figure 2 – Fault clearing
with overcurrent relay
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3. Voltage-Dependent relays
The problems associated with standard overcurrent protection can be
overcome if fault detection is based on current and voltage. At full load, the
generator terminal voltage will be near rated voltage. Under sustained three-
phase fault conditions, the internal generator impedance will increase to the
synchronous value and the terminal voltage will decrease sharply.
Both distance relays and voltage supervised overcurrent relays use the voltage
degradation to differentiate between load current and a sustained fault

7. current condition. Because of this design, these backup relays are supervised
by a potential failure detection element, device 60. This element blocks tripping
in the event of an open phase or blown fuse in the potential circuit.
Without this blocking feature, these instrument circuit malfunctions would trip
the fully loaded unit.
The decision to use a 21 or a 51 V function as backup protection is normally
dependent on the type of phase protection applied on the transmission or
distribution system to which the generator is connected.
Distance backup protection is chosen if phase distance relaying is applied
on the transmission system. A 51 V function is chosen if overcurrent relays
are used for phase protection on the connected system. These choices are
made to facilitate relay coordination.
Go back to Contents Table ↑
4. Voltage Supervised Overcurrent
Relays
4.1 Voltage-controlled And Voltage-
restrained Relays
There are two kinds of voltage-supervised overcurrent relays used in generator
backup applications. The voltage-restrained overcurrent relay is normally set
125–175% of full load current. The relay uses voltage input from the
generator terminals to bias the overcurrent setpoint.
At rated voltage, a current equal to the setpoint is required to actuate the relay.
As input voltage decreases, presumably
due to a short circuit, the overcurrent setpoint also decreases. Typically a
current equal to 25% of the setpoint is require to operate the relay at zero volts
input.
Figure 3 is a typical pickup characteristic for a voltage-restrained relay.

8. The voltage-controlled relay is set below full load with sufficient margin to
detect the minimum fault current. The relay includes an undervoltage
element that senses generator terminal voltage. If the voltage is above the
undervoltage element setting, the overcurrent unit is not functional.
When voltage is depressed by a fault, the undervoltage element drops out,
allowing the relay to operate as a standard overcurrent relay in accordance with
its pickup and time delay settings.
Figure 3 –
Voltage-restrained overcurrent relay characteristic
The voltage-restrained relay is more difficult to apply because operating time is
a function of both current and voltage.
The voltage-restrained relay has two adjustable setpoints, a voltage-dependent
minimum pickup current, and a time delay setting. The voltage-controlled relay
has a voltage-independent current pickup setting, a time delay setting, and an
undervoltage drop out setting.
Go back to Contents Table ↑

9. 4.2 Application Options and Fault
Sensitivity
Voltage-supervised overcurrent relays allow many input options. The 51 V
function comprises three single-phase units. The current and voltage
connections are not standardized. Phase-to-neutral or phase-to-phase voltages
can be applied in conjunction with line or delta currents.
There is also the option of voltage-controlled or voltage-restrained relays.
Go back to Contents Table ↑
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5. Distance Relays
The term distance relays refers to a general class of relays that measure circuit
impedance. The relay distinguishes between fault current and load current in
a manner similar to the 51 V functions. The voltage applied to the distance
relay tends to restrain operation, while current promotes operation.
Both phase and ground distance relays are applied on the transmission system.
Unique relay designs are required for phase and ground fault protection.
There are many different algorithms used in these relays, but in all cases the
common goal is to measure the positive sequence impedance from the
relay to the fault. When full fault protection is provided by distance relaying, six
elements are required, phase elements A–B, B–C, C–A and ground elements
A–G, B–G, and C–G.
Phase distance relays are applied at generators for system backup
protection. Ground distance relays are not applied. Most generators are
grounded through impedance to limit the ground fault current. Specialized
ground fault protection schemes are required.
When a generator is solidly grounded and connected to a distribution system
directly or through a wye-wye transformer, overcurrent ground relays
provide superior fault sensitivity and economy when compared to ground

10. distance relays. Overcurrent ground relaying is applicable because generator
ground faults do not decay to values less than full load current and ground
overcurrent relays are not subject to setting limitations due to load current.
Likewise, when a generator is connected to a system through a delta-wye
grounded transformer, backup ground protection is usually provided by a time
overcurrent ground relay connected in the transformer neutral.
For example, SEL-700G protection relay offers three choices for system backup
protection. You can select one or more of the available elements:
 Distance (DC),
 Voltage Restraint (V), or
 Voltage Controlled (C) Overcurrent elements.
Modern protective relays provide four zones of phase step distance protection.
Functions are positive sequence voltage polarized mho characteristics. The
reach of the three forward looking zones can be compensated for a delta-wye
transformer.
Zone 4 is reversed and disregards any transformer between the relay and the
fault in the forward direction. Zones 1, 2, 3, and 4 each include independent
timers for phase step distance protection.
Out-of-step blocking monitors swing condition and blocks tripping. Out-of-step
tripping logic is provided with a choice of two or three mho type characteristics
with adjustable shapes.
Forward and reverse share a common maximum reach angle. Loss of
synchronism or a power swing between two areas of the power system is
detected by measuring the positive sequence impedance seen by the relay over
a period of time as the power swing develops.

11. Figure 4 – Generator
protection relay SEL-700 functionalscheme
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5.1 Other Distance Relay Applications
Other applications of the 21 function are also possible. Phase distance relaying
can be connected to CTs at the generator terminals with the 21 function
connected to look into the generator instead of the system. This relay can be
applied without a time delay to provide fast backup clearing for generator
faults when connected to the system.

12. Many generator protection microprocessor packages include two phase
distance relay functions. One zone can be implemented with a short reach and
a short time delay sufficient to coordinate with high-speed bus and line
relaying plus breaker failure time if applicable. The second zone is then set to
see into the transmission system with a delay sufficient to coordinate with zone
2 line relaying and applicable breaker failure time.
This scheme can provides 0.3 sec clearing for high current faults in the
vicinity of the generator as opposed to the single zone scheme that would
require a delay of about a second to coordinate with zone 2 and breaker failure
relaying.
Go back to Contents Table ↑
Sources:
1. Protective relaying for power generation systems by Donald Reimert
2. SEL-700G Generator Protection Relay by SEL
3. LPS-O System backup for generators and transmission lines by GE