Principles Of Protection: Generator Basics

OUTLINE:

PRINCIPLES OF GENERATOR PROTECTION BASICS by: russell ian c. paragoso, pee

Generator Fundamentals Generator Faults General Abnormal Conditions Typical Generator Protection Functions References

The material presented is for Educational purposes only. Neither the author, nor anyone on his behalf, makes any warranty or representation as to the accuracy or completeness of the information contained herein, nor assumes responsibility or liability for the use or consequences for the use of any of this information. The practical application of any of the information contain herein must be in accordance with legislative requirements and must be given due regard to the individual circumstances.

Seminar Objectives ▸ Provides an introduction of typical protection functions of a generator protection ▸ Provides comprehensive overview on principles on damage curves of stator damage on generators and system interactions

1. INTRODUCTION

ANSI/IEEE Standards

IEEE Std 242 – Buff Book IEEE C37.101: IEEE Guide for AC Generator Ground Protection IEEE C37.102: IEEE Guide for Generator Protection IEEE C37.106: IEEE Guide for Abnormal Frequency Protection for Generating Plants IEEE Tutorial on The Protection of Synchronous Generator (by PSRC)

Generator Configuration

Rotor Styles

Cylindrical rotor seen in Recips, GTs and STs Salient pole rotor seen in Hydros

Salient Rotor and Stator

Cylindrical Rotor and Stator

Generator Connections

Direct Connected

Unit Connected

Sample Nameplate

Generator Grounding

Generator Grounding

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.

Generator Excitation Control and Generator Capability Excitation Control Basics

Generator Excitation Control and Generator Capability Excitation Control Basics Aside from maintaining synchronism of the generator, the excitation control 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 Generator Watt/VAR Capability

Generator Excitation Control and Generator Capability

P-Q Curve

2. Faults and Abnormal Conditions

Faults and Abnormal Conditions

Generator Behaviour during Short Circuits

Generator Behaviour during Short Circuits

3. Generator Protection Functions

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

Sample Generator Protection

Sample Generator Protection

Sample Generator Protection

Stator Phase Protection

Stator Phase Protection This is achieved by: Differential Relaying (87) Turn Fault Protection (for split-phase generators) Overcurrent (thermal) RTDs

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

self-balancing differential schemes.

Differential Protection

Differential Protection

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.

Generator

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50/51

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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.

Overcurrent Protection

Stator Ground Protection

Stator Ground Protection This is achieved by (depends on the grounding method): Differential Relaying (87N) 100% Stator Ground Fault Protection using voltage relays Overcurrent

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.

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.

Low-Impedance Stator Grounding

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. Supplementary protection is provided by using 87N

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.

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

Overvoltage/Overcurrent Schemes 59G works on fundamental frequency (3V0) Typically set at 5V Measures maximum at terminal

fault and decreases at faults moves toward the neutral Must be coordinated with other protection that works on ground

faults

100% Stator Ground Fault Protection 59G can provide protection for only about 80% to 95% of

the stator windings. This is due to generator construction imperfections and subsequent small amounts of zero-sequence current that will flow in the generator ground. This small amount of zero-sequence current makes it

impossible for conventional ground fault detection relays to remain selective when set too low. Additional ground fault protection is required.

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 3rdharmonic 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 harmonic protection.

100% Stator Ground Fault Protection Third-Harmonic Undervoltage

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.

100% Stator Ground Fault Protection Third-Harmonic Overvoltage

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. Set to overlap with 59G settings.

100% Stator Ground Fault Protection Third-Harmonic Comparator Technique

100% Stator Ground Fault Protection Subharmonic Injection Schemes

Field Fault Protection

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 Desirable to detect presence of first earth fault and give an alarm.

Field Fault Protection

Field Fault Protection

System Backup Protection

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 Sometimes (46) is also used as backup which provides unbalanced fault protection backup.

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.

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 ( wyewye 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. If no aux. PT, use compensator distance relay.

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 machinerated power factor. 80 to 90 percent of load impedance (125 to 111 percent of the generator capability curve) at the relay maximum torque angle (MTA).

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.

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 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.

Abnormal Frequency Protection Conformance to IEC 60034:2007 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)

Abnormal Frequency Protection Conformance to IEC 60034:2007

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 range (98% to 102%).

Abnormal Frequency Protection

Overexcitation and Overvoltage Protection (24 / 59)

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

These limits apply unless manufacturers state otherwise.

Overexcitation and Overvoltage When V/Hz ratios are exceeded, saturation of the magnetic core of the generator or connected transformers can occur, and stray flux will be induced into

non laminated components. Note that overexcitation protection on a generator or its connected transformer is different from field overexcitation.

Excessive overvoltage of a generator will occur when the level of dielectric field stress exceeds the insulation capability.

Overexcitation and Overvoltage Not all overvoltage condition will be detected by V/Hz relay. It is general practice to provide overvoltage relaying to

alarm, or in some cases, trip the generators from these high dielectric stress levels.

Overexcitation and Overvoltage

Overexcitation and Overvoltage

Overexcitation and Overvoltage

Loss-ofExcitation 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 operate as an induction generator. It will supply real power but takes reactive power from the system.

Loss-of-Field Protection On loss-of-field, apparent impedance of fully loaded machine travels from loaded value in the 1 st 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. Locus of impedance trajectory depends on system impedance

Loss-of-Field Protection

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) Diameter of Xd

Time delay of 30-60 cycles Offset equal of –X’d/2

Loss-of-Field Protection Two-zone Offset Mho characteristic

Two-zone LOF protection using negative-offset elements.

Loss-of-Field Protection Two-zone Offset Mho characteristic

Two-zone LOF protection using negative offset mho element and a

positive-offset mho element with directional element supervision.

Loss-of-Field Protection Example response of LOF protection

NegativeSequence Current(46)

Negative-Sequence Protection In the real world, IA 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

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 𝐼22 𝑡 = 𝐾, where K is a design constant

Negative-Sequence Protection

Actual maximum I2 loading curve

Negative-Sequence Protection

Negative-Sequence Protection

Short-time values apply for 120 seconds or less. Beyond 120 seconds, the continuous capability should be used.

Negative-Sequence Protection

Negative-Sequence Protection

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:

Out-of-Step Protection (78)

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 is known as slipping a pole or loss of synchronism.

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-ofsynchronism If electrical center is between the GSU into the generator, out-ofstep protection should be applied at the machine terminals

Out-of-Step Protection Determination of Electrical Center

Electrical center is the point in the system where the impedance

between the sources is equal. Electrical center = (Xd’ + Xt + Xs) / 2

Out-of-Step Protection

Out-of-Step Protection

Out-of-Step Protection

Inadvertent Energization

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 Control Circuit Malfunctions

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 Control Circuit Malfunctions

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 System backup

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 Overcurrent Supervised by Multiple Elements

Loss-ofPotential (60)

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)

Loss-of-Potential

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

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

Tripping Modes

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.

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 Management of unit auxiliary loads during emergency shutdown.

Tripping Modes

Sample Tripping Modes

Sample Logic

Sample Logic

Sample Logic

Sample Logic

References: Protective Relaying: Principles and Applications by Blackburn

IEEE Tutorial on Synchronous Generators Basler BE1-11g manual IEEE Seminar on Protective Relaying by Russ Patterson C37.101-2006 C37.102-2006