Basics of Generator
Basics of Generator
Protection
2 2
Topic Outline
Topic Outline
I. I. GeGeneneraratotor ir in a n a viview ew of of an an PrPrototecectition on EnEngigineneerer II II.. TTypypicical al GeGeneneraratotor r PrPrototecectitiononTopic Outline
Topic Outline
I. I. GeGeneneraratotor ir in a n a viview ew of of an an PrPrototecectition on EnEngigineneerer II II.. TTypypicical al GeGeneneraratotor r PrPrototecectitionon3 3
Generator Configuration
5
Generator Configuration
7
Generator Connections
9
Generator Grounding
11
Generator Grounding
Generator Excitation Control and Generator
Capability
Excitation Control Basics
A generator excitation system provides the energy for the
magnetic field that keeps the generator in synchronism with the power system.
Two types: those using ac generators as power source and those using transformers.
13
Excitation Control Basics
Generator Excitation Control and Generator
Capability
Excitation Control Basics
Aside from maintaining synchronism of the generator, the generator also:
Affects the amount of reactive power that the generator may absorb or produce.
Increasing the excitation current results in increase reactive power output.
Decreasing the excitation current results in decrease
reactive power output, extreme case loss of synchronism will occur.
Generator Excitation Control and Generator
Capability
15
Generator Watt/VAR Capability
Generator Excitation Control and Generator
Capability
P-Q Curve
Generator Excitation Control and Generator
Capability
17
Protection Requirements
To detect faults on the generator
To protect generator from the effects of abnormal
power system operating conditions
To isolate generator from system faults not cleared
remotely
19
Sample Generator Protection
21
Stator Phase Protection
This is achieved by:
Differential Relaying (87)
Turn Fault Protection (for split-phase generators)
Overcurrent (thermal)
Differential Protection
High-Speed protection that can detect three-phase, phase to phase and double-phase to ground faults.
Single-line to ground faults are not normally detectable unless its neutral is solidly or low-impedance grounded.
Will not detect a turn-to-turn fault within the same phase
Both sides of the generator should be of the same ratio, rating, connected burden, and preferably have the same manufacturer. It could be high-impedance type, low-impedance type and
23
Differential Protection
25
Overcurrent Protection
For small generators this may be the only protection applied. With solid earthing, it will provide some protection against earth
faults
For a single generator, CTs must be connected to neutral end of stator winding.
~
Generator50/51
Overcurrent Protection
Some helpful points in setting overcurrent relays: From C37.102-2005:
Use IOC and TOC unit having an EI characteristic.
IOC is set to 115% FLC and is used to torque-control TOC unit TOC unit is set to 75%-100% FLC and a time settings operating
7sec @ 218% FLC or coordinate with downstream relay. From ABC’s of Overcurrent Protection:
Set protection above FLC and above decrement curve in the lowest decade.
Set protection below overload curve.
Set protection to intersect with the decrement curve in the second lowest decade.
27
Overcurrent Protection
29
Stator Ground Protection
This is achieved by (depends on the grounding method): Differential Relaying (87N)
100% Stator Ground Fault Protection using voltage relays
Stator Ground Fault Protection
Stator grounding determines the generator performance during fault conditions.
If solidly grounded, it will deliver very high current to a SLG fault at its terminals with no neutral voltage shift, therefore equipment damage is severe.
If ungrounded, it will deliver a negligible amount current during a SLG fault at its terminals with fill neutral voltage shift which could cause failure of generation equipment insulation.
31
Stator Ground Fault Protection
Because of this, stator windings on major generators are grounded in a manner that will reduce fault current and overvoltages and yet provide a means of detecting the ground fault condition quickly enough to prevent burning of core iron.
33
Low-Impedance Stator Grounding
Low-Impedance Grounding
The grounding resistor or reactor is selected to limit the generator contribution to an SLG fault to range of
currents between 200A and 150% of rated load current.
35
Low-Impedance Grounding
High-Impedance Grounding
High-resistance generator neutral grounding uses a
distribution transformer with a primary rating greater than or equal to the line-to-neutral voltage rating of the
generator and a secondary rating of 120 or 240V.
Power dissipated in the resistor is approximately equal to the reactive volt-amperes in the zero-sequence capacitive reactive of the generators, windings of any transformers connected to generator terminals.
37
High-Impedance Grounding
An SLG fault is generally limited to 3 to 25 primary amperes.
Others only uses resistor aside from transformers but the fault current is limited to 5A.
High-Impedance Grounding
39 39
Overvoltage/Overcurrent Schemes
Overvoltage/Overcurrent Schemes
59G works on fundamental59G works on fundamental
frequency (3V0)
frequency (3V0)
TTypically set at ypically set at 5V5V
Measures maximum atMeasures maximum at
terminal fault and decreases
terminal fault and decreases
at faults moves toward the
at faults moves toward the
neutral
neutral
Must be coordinated withMust be coordinated with
other protection that works
other protection that works
on ground faults
100% Stator Ground Fault Protection
100% Stator Ground Fault Protection
59G can provide protection for only about 80% to 95% of59G can provide protection for only about 80% to 95% of
the stator windings.
the stator windings.
This is due to generator construction imperfections andThis is due to generator construction imperfections and
subsequent small amounts of zero-sequence current that
subsequent small amounts of zero-sequence current that
will flow in the generator ground.
will flow in the generator ground.
This small amount of zero-sequence current makes itThis small amount of zero-sequence current makes it
impossible for conventional ground fault detection relays to
impossible for conventional ground fault detection relays to
remain selective when set too
remain selective when set too lowlow..
41
100% Stator Ground Fault Protection
Protection can be done using:
Third-harmonic voltage-based techniques
Neutral or residual subharmonic voltage injection
Third-harmonic voltages components are present at the terminals of nearly every machine to varying degrees; they arise due to the nonsinusoidal nature of rotor flux and vary based in machine design and manufacturer.
These voltages are used in detecting faults on the generator to provide protection.
100% Stator Ground Fault Protection
3rd-harmonic voltage is dependent
on operating conditions of the generator.
There is a point where the 3rd
-harmonic is zero.
For a ground fault at the neutral, 3rd
harmonic decreases as fault approaches to neutral
For a ground fault at the terminal, 3rd harmonic decreases as fault
approaches to the terminals.
The 3rd harmonic levels should be
measured with the generator
connected and disconnected from the transformer before enabling 3rd
43
100% Stator Ground Fault Protection
100% Stator Ground Fault Protection
Third-Harmonic Undervoltage
Since for a fault near the neutral, the level of third-harmonic voltage at the neutral decreases.
Therefore undervoltage relay at the neutral could be used.
It is tuned at 180Hertz to measure third harmonic.
Set to overlap with 59G settings.
Sometimes, it is supervised with OC relay, real or reactive power and breaker contact.
45
100% Stator Ground Fault Protection
100% Stator Ground Fault Protection
Third-Harmonic Overvoltage
Since for a fault near the neutral, the level of third-harmonic voltage at the terminal increases.
Therefore overvoltage relay (59T) at the terminal could be used.
It is tuned at 180Hertz to measure third harmonic.
47
100% Stator Ground Fault Protection
100% Stator Ground Fault Protection
49
Field Fault Protection
Field circuit is an isolated DC system.
Insulation failure at a single point:
No fault current, therefore no danger
Increase chance of second fault occurring
Insulation failure at a second point:
Shorts out part of field winding
Heating
Flux distortion causing violent vibration of rotor
51
Field Fault Protection
53
System Backup Protection
Backup protection is divided into:
Phase-fault protection
(21) Distance relays
(51V) Voltage controlled/restraint overcurrent relays
Earth fault protection
(51G) Ground OC Relays
55
System Backup Protection
System Backup Protection
51V
Use of simple OC relay is not recommended.
Voltage Restrained
Operating characteristics is continuously varied. depending on measured volts.
Voltage Controlled
Relay switches between fault characteristic and load characteristic depending on measured volts.
57
System Backup Protection
Distance Phase Backup Protection
Most common type of phase system backup protection.
Two zones are applied with mho characteristic.
If the generator is connected where there is no phase shift ( wye-wye transformer or directly connected), the relay will accurately measure the impedance
If the generator is connected to delta-wye transformer, where there is phase shift, auxiliary PT is required to compensate the phase shift.
System Backup Protection
Distance Phase Backup Protection Setting Guidelines
Set the impedance relay to the smallest of the three following criteria:
120 percent of longest line (with infeed). If the unit is connected to a breaker-and-a-half bus, this percent is calculated using the length of the adjacent line.
50 to 66.7 percent of load impedance (200 to 150 percent of the generator capability curve) at the machine-rated
power factor.
80 to 90 percent of load impedance (125 to 111 percent of the generator capability curve) at the relay maximum
59
System Backup Protection
System Backup Protection
Backup Ground Protection
Backup ground protection is set to pickup for ground faults at the end of all lines out of the station
Set to coordinate with the slowest ground fault protection on the system.
61
Abnormal Frequency
Protection (81)
Abnormal Frequency Protection
Stable system is when Power Input = Power of all loads + Losses in the system
When there is a change between the this relationship, abnormal system frequency arises.
Underfrequency condition occurs as a result of sudden reduction in input power
Overfrequency condition occurs as a results sudden loss of load or key interties exporting power.
63
Abnormal Frequency Protection
Major considerations associated with operating a generating plant at an abnormal frequency:
Protection of equipment from damage that could result from operation at an abnormal frequency.
Prevention of inadvertent tripping of the generating unit for a recoverable abnormal frequency condition that does not exceed the plant equipment design limits.
Abnormal Frequency Protection
Some turbine generators are designed to accommodate frequency voltage characteristics from IEC
60034-3:2007, Rotating Electrical Machines-Part 3.
This standard requires generators to deliver continuously rated output at the rated power factor over the range of
±5% in voltage and ±2% in frequency. (61.2 Hz and
58.8Hz)
65
Abnormal Frequency Protection
Abnormal Frequency Protection
Conformance to IEC 60034:2007
The standard recommends that operation outside the shaded are “be limited in extent, duration and frequency of occurrence.”
The manufacturer could therefore impose time
restrictions for example below 95% or above 103% of rated frequency.
Goal of frequency protection scheme is to return the frequency to the continuous IEC operating frequency
67
Abnormal Frequency Protection
Overexcitation and Overvoltage
Protection (24 / 59)
69
Overexcitation and Overvoltage
Overexcitation occurs whenever the ratio of the voltage to frequency (V/Hz) applied to the terminal exceeds
design limits. IEEE standards have established the ff. limits:
Generators, 1.05pu at the output terminals (generator base)
Transformers, 1.05pu at the terminals at rated load or 1.1pu at no load
Overexcitation and Overvoltage
Overexcitation and Overvoltage
When V/Hz ratios are exceeded, saturation of theWhen V/Hz ratios are exceeded, saturation of the
magnetic core of the generator or connected
magnetic core of the generator or connected
transformers can occur, and stray flux will be
transformers can occur, and stray flux will be induced intoinduced into
non laminated components.
non laminated components.
Note that overexcitation protection on a generator or itNote that overexcitation protection on a generator or itss
connected transformer is different from field
connected transformer is different from field
overexcitation.
overexcitation.
Excessive overvoltage of a generator will occur when theExcessive overvoltage of a generator will occur when the
level of dielectric field stress exceeds the insulation
71 71
Overexcitation and Overvoltage
Overexcitation and Overvoltage
Not all overvoltage condition will be detected by V/HzNot all overvoltage condition will be detected by V/Hz
relay.
relay.
It is general practice to provide overvoltage relaying toIt is general practice to provide overvoltage relaying to
alarm, or in some cases, trip t
alarm, or in some cases, trip the generators from thesehe generators from these
high dielectric stress levels.
Overexcitation and Overvoltage
73
Overexcitation and Overvoltage
75
Loss-of-Excitation
Protection (40)
Loss-of-Field Protection
Causes of loss-of-field:
Accidental trip of field breaker
Field open circuit
Field short circuit
Voltage regulator system failure
Loss of supply to excitation system
For most generators, the unit will overspeed and
77
Loss-of-Field Protection
On loss-of-field, apparent impedance of fully loaded machine travels from loaded value in the 1st quadrant to the 4th quadrant
close to –X axis at value just above the direct –axis transient reactance (about 2-7 seconds).
Final impedance point depends on initial load, varies between Xd’/2 at full load to direct-axis synchronous reactance Xd at no load.
79
Loss-of-Field Protection
For small and less important machines, a single-zone
offset mho is used to detect this condition. For larger
machines, two-zone offset mho is used.
Smaller Circle (#1)
Diameter of 1.0 pu impedance on machine base
“Small” “almost instantaneous” time delay
Offset equal to –X’d/2
Larger Circle (#2)
Diamter of Xd
Time delay of 30-60 cycles
Loss-of-Field Protection
81
Negative-Sequence
Current(46)
Negative-Sequence Protection
In the real world, I A does not necessarily equal to IB and IC
Unbalances are caused by:
System asymmetries
Unbalanced loads
Unbalanced system faults
Open phases
Produce negative-sequence currents-induce a double frequency current
83
Negative-Sequence Protection
I2 crosses the air gap, appears in rotor as double-frequency current
Flows in rotor surface, non magnetic wedges
Severe overheating, melting of wedges into air gap
Standards permits 5-10% of I2
Short-time limits expressed as
2
=
, where K is a design constant
85
Negative-Sequence Protection
Short-time
values apply for 120 seconds or less. Beyond 120 seconds, the continuous capability should be used.
87
Anti-motoring or Reverse
Power (32R)
Generator Motoring
Occurs when the energy supply to the prime mover is cut
off while the generator is still on the line. A primary
indication of motoring is the flow of real power into the
generator.
Estimated power required to motor the idling prime mover
is:
89
Out-of-Step Protection
When a fault occurs on the power system, the generator can begin to accelerate due to differences in the mechanical power into the generator and the electrical power at the generator
terminals.
If the fault is not cleared quickly, this acceleration will result in the generator rotor voltage advancing beyond 90 degrees with respect to the generator terminal voltage.
At this point, power flow into the generator and the rotor angle will continue to advance until is aligned with the next pole. This
91
Out-of-Step Protection
Out-of-Step Protection
Adverse Effects
High peak currents and off-frequency operation (slipping)
Winding stresses
Pulsating Torques
Mechanical resonances
Standard generator protection will not detect loss-of-sychronism
Standard transmission line protection will not detect loss-of-synchronism
out-of-93
Out-of-Step Protection
Determination of Electrical Center
Electrical center is the point in the system where the impedance between the sources is equal.
95
Out-of-Step Protection
97
Inadvertent Energization
When an offline generator is energized (w/o field) on turning gear or coasting to a stop, the generator behaves as an induction motor and can be damaged within a few seconds
Causes:
Operating Errors
Open Breaker Flashovers
99
Inadvertent Energization
When an offline generator is energized (w/o field) on turning gear or coasting to a stop, the generator behaves as an induction motor and can be damaged within a few seconds
Causes:
Operating Errors
Open Breaker Flashovers
Inadvertent Energization
The following protection elements may detect or can be set to detect inadvertent energizing:
Loss of Field Protection
Reverse Power
Negative-sequence overcurrent
Breaker Failure
101
Inadvertent Energization
Inadvertent energization protection needs to be in service when the generator is out of service.
Dedicated protection:
Directional Overcurrent
Frequency Supervised Overcurrent
Distance Relay
Voltage Supervised Overcurrent
Auxilliary Contact-Enabled Overcurrent
103
Loss-of-Potential
Loss of the voltage transformer (VT) signal can occur because of a number of cases, most commonly fuse failure.
It could be VT or wiring failure, an open circuit in the draw-out assembly, an open contact due to corrosion or blown fuse
Such loss can cause protective relay misoperation or failure or generator voltage regulator runaway, which can lead to
generator overexcitation
It is important to detect loss-of-potential condition, sometimes called, fuse loss (60FL)
105
Synchronism Check and
Auto Synchronizing (25)
Synchronism Check and Auto
Synchronizing
Synchronism Check
Checks the generator system frequency, voltage magnitude, and phase angle be in alignment
Typical parameters call for no more than 6RPM error, 2% voltage magnitude difference, and no more than 10 deg phase angle error before closing the breaker
107
Synchronism Check and Auto
Synchronizing
Auto Synchronizing (25A)
Checks the generator system frequency, voltage magnitude, and phase angle be in alignment
It involves sending voltage and speed raise and lower commands to the voltage regulator and prime governor.
When the system is in synchronism, the autosync relay is sometimes designed to send a close command in
advance of the zero phase angle error to compensate for breaker close
Synchronism Check and Auto
Synchronizing
109
Tripping Modes
Simultaneous Tripping
Provides the fastest means of isolating the generator
Used for all internal generator faults and severe abnormalities in the generator protection zone.
Generator Tripping
Does not shutdown the prime mover and is used where it may be possible to correct the abnormality quickly,
permitting a rapid reconnection of the machine to the system.
111
Tripping Modes
Unit Separation
Initiates only the opening of generator breakers
Recommended when maintaining the unit auxiliary loads connected to the generator is desirable.
Sequential Tripping
Used for prime mover problems where high-speed tripping is not a requirement.
1. turbine valves, 2. generator breakers 3. field breaker and load transfer of loads.
Tripping Modes
These tripping scheme must be review and applied according to the present generator application
Selection would depend on the ff:
Type of prime mover
Impact of the sudden loss of output power on the electrical system and prime mover
Safety to personnel
Operating experience
113
Tripping Modes
115
117
