2. From Lecture 1, We can say:
Generator hazards and problems are as follows:
A. Internal faults
1. Phase or ground faults in the stator and associated areas
(required primary and backup protection )
2. Ground faults in the rotor and loss-of-field excitation
(Mention the relay types according to generator rating)
B. System disturbances and operational hazards
1. Loss of prime-mover; generator motoring (32)
2. Overexcitation: volts or hertz protection (24)
3. Inadvertent energization: non synchronized connection (67)
4. Unbalanced currents: negative sequence (46); breaker pole
flashover (61)
5. Thermal overload (49)
Reverse Phase Relay
Thermal Relay
3. Continue
Generator hazards and problems are as follows:
6. Off-frequency operation for large steam turbines
7. Un cleared system faults: backup distance (21); voltage
controlled time over-current (50V)
8. Overvoltage (59)
9. Loss of synchronism: out of step
10. Sub-synchronous oscillations
11. Loss of voltage transformer signal to relaying or voltage
regulator
12. Generator breaker failure
Cut the fues of V.T
4. In the case of DG, additional protection is required at
the point of common coupling (PCC).
This protection also serves to protect the generator from
events that may originate on the utility power system.
Facilities at the PCC will typically consist of protection to
A- prevent islanded operation of the DG and part of the utility
system,
B- To assure that:
(1) the generator does not cause voltage and frequency on the
utility system to be outside the acceptable limits,
(2) the generator trips for required faults on the intertie line,
(3) faults on the distributed generator system are cleared by
the PCC breaker rather than by interrupting devices located on
the utility power system.
10. A- Differential protection for small generator units with flux
summation current transformers and an instantaneous over
current (50 relay). (Self-Balancing Differential)
11.
12.
13. ▪The limitation is the ability to pass the two conductors
through the window or opening of the CT. Typical opening
diameters are about 4–8 in. However, where this is possible,
high-sensitivity, high-speed protection is obtained, and CT
performance does not have to be matched, for there is only one
involved per phase.
➢ The flux summation CT ratio (commonly 50:5) is
independent of generator load current.
➢Typical sensitivities in the order of 5 A primary current can
be obtained.
➢This provides protection for both phase- and ground-fault
currents as long as the fault level for faults within the
differential zone is greater than the sensitivity.
14. Be Careful
This scheme does not provide protection to the connections
from the flux summation CT to the generator breaker, unless
the CT is on the bus side of the breaker and the generator
neutral side leads are carried to that point.
This is seldom practical, so other protection must be provided
for this area between the flux summation CT and the breaker.
In general, this scheme is more sensitive as long as the
generator CT ratio is greater than 150:5 to 200:5.
If the flux summation CT is not applicable and differential
protection is desired, the scheme of next Figure can be
used.
15. B- Typical differential (87) connections for the protection of
wye - and delta connected generators
19. ➢Usually, the differential CTs have the same ratio, and they
should preferably be of the same type and manufacture to
minimize mismatch errors for external faults. This is possible
for the unit generators
➢Generally, the impedance of the restraint winding of
differential relays is low. All this contributes to a totally low-
burden and increased performance margins for the CTs.
➢The application recommendations permit the use of sensitive
generator differential relays with low percentage
characteristics, typically 10%–25% for the fixed percentage
types and the equivalent or lower for the variable types.
Relay sensitivities (pickup current) are near 0.14–0.18 A for
the 10% and variable percentage types and about 0.50 A for
the 25% types.
The function of the restraining coil is to avoid
the malfunctioning of the main relay.
Restraining current is flowing through the
restraining coil is to prevent the external faults.
The increase the current increases the
restraining torque.
20. ➢The operating time should be fast to open the breaker(s),
remove the field, and initiate reduction of the prime-mover
input.
➢Unfortunately, the flux in the machine continues to supply
the fault for several seconds (about 8–16 sec), so instantaneous
de-energization of generator faults is not possible.
➢Problems with magnetizing inrush generally are not severe
because the voltage on the machine is developed gradually,
and the generator is carefully synchronized to the power
system.
21.
22. The Minimum Pickup region is used between zero and
approximately 0.5 per unit restraint current. It provides
security against CT remanence and accuracy errors and is
usually set between 0.3 and 0.5pu.
• The Slope 1 region is used between the minimum pickup
region and the slope 2 breakpoint. Slope 1 provides security
against false tripping due to CT accuracy. Class C CT
accuracy is +/‐10%, therefore 20% should be the absolute
minimum setting with greater than 30% preferred.
• The Slope 2 region is used above the slope 2 breakpoint,
which is normally set at 2pu. Slope 2 provides security
against false tripping during through fault events where CT
saturation is likely.
Above 2pu current, a significant DC current component will
be present and therefore saturation is likely. Slope 2 is
normally set at 60‐80%.
23. C- HIGH-IMPEDANCE VOLTAGE DIFFERENTIAL
PROTECTION FOR GENERATORS
The high-impedance voltage type of differential protection scheme can
be applied as an alternative to the current differential type described. The
relays are connected between phase and neutral leads of paralleled CTs.
For external faults, the voltage across the relay will be low, because the
current circulates between the two sets of CTs (see Figure 8.7).
For internal faults, the fault currents must pass through the exciting
branch and high impedance relay of each CT, so that the CTs are
saturated for most faults, producing a high voltage to operate the relay.
This protection scheme is widely used for bus protection and is described
further in Chapter 10. The CT requirements are more or less critical.
They should have identical characteristics, negligible leakage reactance,
and fully distributed secondary windings.
30. Split-winding generators, where the two winding
halves are available with CTs in one of the halves
(Figure 8.8), can be protected with two separate
differentials. By comparing one winding half against
the total, as shown, protection for shorted turns and
open-circuited windings is possible. This is difficult or
impossible for conventional relaying until the fault
develops into the other phases or the ground. Where a
2:1 CT ratio is not available, auxiliary CTs can be
used.
33. PHASE-FAULT BACKUP PROTECTION (51V) OR (21)
Backup protection for the generator and connected system
can be provided by a voltage-controlled or voltage-restraint
time-over current relay (51V) or by phase distance relays
(21). These two types are in wide use, with 51V generally
applied to medium and smaller generators, and 21V for
large-unit generators.
VOLTAGE-CONTROLLED OR VOLTAGE-RESTRAINT
TIME–OVERCURRENT (51V) BACKUP PROTECTION
This is a non directional relay; therefore, it can be connected
to CTs at the ground terminal or at the neutral end as in
Figure generator connection. Voltage is from the generator
voltage transformers (VTs) and is used to prevent the time
over current unit from operating, until a fault decreases the
voltage.
34.
35. PHASE-DISTANCE (21) BACKUP PROTECTION
On large generators, especially the unit types, phase-fault
backup is usually provided by phase-distance units (21). When
connected to CTs on the neutral side, backup is provided for
both the generator and the system. When using a three-phase
type 21 relay, the phase shift of the transformer does not affect
the reach, as it does for single-phase-type units. Voltage is
obtained from the VTs at the generator terminals.
For distance relays, the location of the CTs determines the
directional sensing, whereas distance is measured from the
location of the VTs. Thus, if CTs at the generator leads were
used, backup could be provided only for the system or for the
generator, but not both, depending on the connections. When
it is set such that it looks into the system, a fixed timer
provides the necessary time delay to coordinate with all the
relays its setting overreaches.
