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S.M.Abbas
2 GE Consumer & Industrial Multilin
3 GE Consumer & Industrial Multilin
4 GE Consumer & Industrial Multilin
5 GE Consumer & Industrial Multilin
7 GE Consumer & Industrial Multilin
8 GE Consumer & Industrial Multilin
9 GE Consumer & Industrial Multilin
11 GE Consumer & Industrial Multilin
13 GE Consumer & Industrial Multilin
14 GE Consumer & Industrial Multilin
17 GE Consumer & Industrial Multilin
19 GE Consumer & Industrial Multilin
20 GE Consumer & Industrial Multilin
21 GE Consumer & Industrial Multilin
Fault Data •Three phase faults have the highest fault current.
•Single phase faults have the lowest fault current. •The fault current is determined by the impedance of the fault path. •Fault paths closer to the source will have less impedance. •Faults caused by trees will have higher impedance.
Desirable Protection Attributes •Reliability: System operate properly – Security: Don’t trip when you shouldn’t – Dependability: Trip when you should
•Selectivity: Trip the minimal amount to clear the fault or abnormal operating condition
•Speed: Usually the faster the better in terms of minimizing equipment damage and maintaining system integrity •Simplicity: Less components simple wiring •Economics: Don’t break the bank
Art & Science of Protection Selection of protective relays requires compromises: •
Maximum and Reliable protection at minimum equipment cost
•
High Sensitivity to faults and insensitivity to maximum load currents
•
High-speed fault clearance with correct selectivity
•
Selectivity in isolating small faulty area
•
Ability to operate correctly under all predictable power system conditions
•
Primary objectives is to have faulted zone’s primary protection operate first, but if there are protective relays failures, some form of backup protection is provided.
25
GE Consumer & Industrial Multilin
Primary Equipment & Components • Transformers - to step up or step down voltage level • Breakers - to energize equipment and interrupt fault current to isolate faulted equipment • Insulators - to insulate equipment from ground and other phases • Isolators (switches) - to create a visible and permanent isolation of primary equipment for maintenance purposes and route power flow over certain buses. • Bus - to allow multiple connections (feeders) to the same source of power (transformer). 26 GE Consumer & Industrial Multilin
Primary Equipment & Components • Grounding - to operate and maintain equipment safely • Arrester - to protect primary equipment of sudden overvoltage (lightning strike). • Switchgear – integrated components to switch, protect, meter and control power flow
• Reactors - to limit fault current (series) or compensate for charge current (shunt) • VT and CT - to measure primary current and voltage and supply scaled down values to P&C, metering, SCADA, etc. • Regulators - voltage, current, VAR, phase angle, etc. 27 GE Consumer & Industrial Multilin
Types of Protection Overcurrent • Uses current to determine magnitude of fault – – – – – –
Simple May employ definite time or inverse time curves May be slow Selectivity at the cost of speed (coordination stacks) Inexpensive May use various polarizing voltages or ground current for directionality
Instantaneous Overcurrent Protection (IOC) & Definite Time Overcurrent (DTOC) • Relay closest to fault operates first • Relays closer to source operate slower • Time between operating for same current is called CTI (Clearing Time Interval)
CTI
t
I
CTI 50 +2
Distribution Substation
50 +2
29 GE Consumer & Industrial Multilin
(TOC) Coordination •Relay closest to fault operates first •Relays closer to source operate slower •Time between operating for same current is called CTI
t
I
CTI
Distribution Substation
Time Overcurrent Protection (TOC) • Selection of the curves uses what is termed as a “ time multiplier” or “time dial” to effectively shift the curve up or down on the time axis
• Operate region lies above selected curve, while no-operate region lies below it • Inverse curves can approximate fuse curve shapes
Types of Protection Differential – – – – – –
current in = current out Simple Very fast Very defined clearing area Expensive Practical distance limitations • Line differential systems overcome this using digital communications
1 pu IP
CT-X
IP
CT-Y
IS
IS
Relay IR-X
IR-Y
+1 Current, pu
1 + (-1) = 0 0
-1 DIFF CURRENT
Differential • Note CT polarity dots • This is a throughcurrent representation • Perfect waveforms, no saturation
2 pu
2 pu
Fault
IP
CT-X
IP
CT-Y
Differential
X IS
IS
Relay IR-X
IR-Y
+2 Current, pu
2 + (+2) = 4 0
-2 DIFF CURRENT
• Note CT polarity dots • This is an internal fault representatio n • Perfect waveforms, no saturation
Types of Protection Voltage • Uses voltage to infer fault or abnormal condition • May employ definite time or inverse time curves • May also be used for undervoltage load shedding – Simple – May be slow – Selectivity at the cost of speed (coordination stacks) – Inexpensive
Types of Protection Frequency • Uses frequency of voltage to detect power balance condition • May employ definite time or inverse time curves • Used for load shedding & machinery under/overspeed protection – Simple – May be slow – Selectivity at the cost of speed can be expensive
Types of Protection Power • Uses voltage and current to determine power flow magnitude and direction • Typically definite time – Complex – May be slow – Accuracy important for many applications – Can be expensive
Types of Protection Distance (Impedance) – Uses voltage and current to determine impedance of fault – Set on impedance [R-X] plane – Uses definite time – Impedance related to distance from relay – Complicated – Fast – Somewhat defined clearing area with reasonable accuracy – Expensive – Communication aided schemes make more selective
Protection Zones 1. Generator or Generator-Transformer Units 2. Transformers 3. Buses 4. Lines (transmission and distribution)
5. Utilization equipment (motors, static loads, etc.) 6. Capacitor or reactor (when separately protected) Bus zone Unit Generator-Tx zone
Bus zone Line zone
Bus zone Motor zone
Transformer zone
Transformer zone
~ Generator
XFMR
Bus
Line
Bus
XFMR
Bus
Motor
What Info is Required to Apply Protection 1. One-line diagram of the system or area involved 2. Impedances and connections of power equipment, system frequency, voltage level and phase sequence 3. Existing schemes 4. Operating procedures and practices affecting protection 5. Importance of protection required and maximum allowed clearance times 6. System fault studies 7. Maximum load and system swing limits 8. CTs and VTs locations, connections and ratios 9. Future expansion expectance 10. Any special considerations for application.
Abnormal Operating Conditions
ANSI / IEEE Standards
• Latest developments reflected in:
– Std. 242: Buff Book Latest developments reflected in: – C37.102: IEEE Guide for Generator Protection – Std. 242: Buff Book – C37.101: IEEE Guide for AC Generator Ground Protection – C37.102: IEEE Guide for Generator – C37.106: IEEE Guide for Abnormal Frequency Protection Protection for Power Generating Plants – C37.101: IEEE Guide for AC Generator Ground Protection – C37.106: IEEE Guide for Abnormal Frequency Protection for Power Generating These are created/maintained by the IEEE PSRC & IAS Plants They are updated every 5 years
Small Machine Protection IEEE Buff Book
32 Reverse Power 40 Loss of Excitation 51V voltage restraint 51G Ground O/C 87 Differential
• Small – up to 1 MW to 600V, 500 kVA if >600V
Small Machine Protection IEEE Buff Book
32 Reverse Power 40 Loss of Excitation
46 Negative Sequence 51V voltage restraint 51G Ground O/C 87 Differential
• Medium – up to 12.5 MW
Small Machine Protection IEEE Buff Book 32 Reverse Power 40 Loss of Excitation 46 Negative Sequence 49 Thermal Overload
51V voltage restraint 51G Ground overcurrent 64 Ground Relay 87 Differential
• Large – up to 50 MW
Large Machine Protection IEEE C37.102 • Unit Connected, High Z Grounded
32 Reverse Power 40 Loss of Excitation 46 Negative Sequence 49 Thermal Overload 51V voltage restraint 51G Ground overcurrent 64 Ground Relay 87 Differential
Under & Over Voltage Protection • Protects against a severe overload condition (27) • Initiates the starting of an emergency standby genset (27) • Load shed shut down in the event of AVR failure (27) • Protect against dangerous over-voltages (59) • Backup to internal V/Hz limiters • Commonly combined 27/59
Devices 27 / 59
Reverse Power Protection • Provides backup protection for the prime mover. • It detects reverse power flow (kW) should the prime mover lose it’s input energy without tripping its generator feeder breaker • Prevents motoring, drawing real power from the system
Device 32
Loss of Field Protection •Loss of excitation can occur:
Device 40
•Loss of field to the main exciter. •Accidental tripping of the field breaker. •Short circuits in the field circuits. •Poor brush contact in the exciter. •Field circuit-breaker latch failure. •Loss of ac supply to the excitation system. •Reduced-frequency operation when the regulator is out of service.
Phase Balance Current Protection • Unbalanced loads • Unbalanced system faults • Open conductors • Unbalanced I2 currents induce 2X system frequency currents in the rotor causing overheating
Device 46
Backup Overcurrent Protection
• The function of generator backup protection is to disconnect the generator if a system has not been cleared by the primary protective device • Time delays
Device 51V/21
Ground Overcurrent Protection • Provides backup protection for all ground relays in the system at the generator voltage level • Provides protection against internal generator ground faults • Commonly provided as GF alarm.
Device 51G
Voltage Balance Relay
Device 60 • Monitors the availability of PT voltage. • Blocks improper operation of protective relays and control devices in the event of a blown PT fuse
Out of Step Protection •High peak currents and off-frequency operation can occur when a generator losses synchronism.
Device 78
•Causes winding stress, high rotor iron currents, pulsating torques and mechanical resonances.
•Conventional relaying approach – analyzing variations in apparent impedance as viewed at generator terminals. •Variation in impedance can be detected by impedance relaying and generator separated before the completion of one slip cycle
Differential Protection • For rapid detection of generator Φ to Φ or Φ-G faults. • When NGR’s are used, 87G should be used. • Used for protection of larger generators • Zone protection
Device 87
Phase Fault Protection (87G)
Differential Protection (87) • A key point to remember is that differential relays don’t prevent damage, they LIMIT damage. • If a relay is properly operating it won’t trip until there is actually a line to ground fault somewhere in its zone of protection. • By limiting the duration of a fault, it is often possible to limit damage, but there is STILL damage. • Eventually, you will have to deal with it.
REF Protection (87GN / 64GN)
Frequency Protection Significant load addition Sudden reduction in mechanical input power Loss of generation / Loss of load Underfrequency can cause: Higher generator load currents Overexcitation Turbine blade fatigue
Device 81
Temperature Protection • Resistance temperature detectors are used to sense winding temperatures. • A long term monitoring philosophy that is not readily detected by other protective devices
RTD’s
FFBL GENERATOR PROTECTION LAYOUT
Digital Generator Protection System (DGP) • Microprocessor Based Protection, Control and Monitoring System • Waveform Sampling • User Friendly • GE/Hydro Quebec Joint Development
Tripping Methods Factors of selection includes severity of fault, probability of Fault spreading & overspeeding, time required to resynchronize, effect on power system etc. • SIMULTANEOUS TRIP
• MANUAL RUNBACK & TRIP
• GENERATOR TRIP
• AUTOMATIC RUNBACK
• BREAKER TRIP
• MANUAL RUNBACK
• SEQUENTIAL TRIP • MANUAL TRIP
Generator Faults (GE) • STATOR OVERCURRENT • STATOR GROUND FAULT • STATOR PHASE TO PHASE FAULT • OVER VOLTAGE • VOLT PER HERTZ • FIELD OVEREXCITATION • FIELD GROUND • LOSS OF EXCITATION • UNBALANCED ARMATURE CURRENT • STATOR OVERTEMPERATURE
• LOSS OF SYNCHRONISM • ABNORMAL FREQUENCY OPERATION • BREAKER FAILURE • HIGH SPEED RECLOSING • SUBSYNCHRONOUS RESONANCE • INADVERTENT ENERGIZATION • SYSTEM BACK UP • VOLTAGE SURGES • BEARING VIBRATION • SYNCHRONIZING ERRORS • MOTORING
Digital Generator Protection System (DGP)
DGP Digital Generator Protection The DGP is a digital system which provides a wide range of protection, monitoring, control and recording functions for AC generators.
•It can be used on generators driven by steam, gas and hydraulic turbine. •Any size of generator can be protected with the DGP.
• A high degree of dependability and security is achieved by extensive self diagnostic routines and an optional redundant power supply.
Generator Trip Scheme • BREAKER TRIP • 46 UNBALANACE • 32 REVERSE POWER • 51 V OVERCURRENT WITH VOLTAGE RESTRAINT • 81 U UNDER FREQUENCY • TURBINE TRIP • 87 G DIFFERENTIAL • 40 LOSS OF EXCITATION • 24 OVER EXCITATION • 59 OVERVOLTAGE • 51 GN GROUND OVERCURRENT • ALARM ONLY • 27 UNDER VOLTAGE • 81 O OVER FREQUENCY • EXT VTFF • BLK # 9 (81, 32, 27, VTFF)
Applications • For Small, Medium and Large Generator Protection • Suitable for Variety of Prime-Movers - Gas, Steam, Hydro Turbines • Most Commonly Used Protection Functions Packaged in a Standard Modular Case
TYPICAL INPUT WIRING DIAGRAM OF DGP
THE DGP SYSTEM TAKES EIGHT CURRENT AND FOUR VOLTAGE SENSING INPUTS.
THE DGP SYSTEM The input currents in terminals BH1,INPUTS BH3, and BH5 (IAS, IBS, and ICS) are used to process functions 46, 40, 32, and 51V. These currents can be derived from system side or neutral side CTs as desired. Either the system or neutral side CTs can be used for these functions if the Stator Differential (87G) function is enabled. Current inputs INS and INR are derived from the residual connections of the respective phase CTs.
The current inputs INS and INR are derived from the residual connections of the respective phase CTs and do not require dedicated neutral CTs. Zero-sequence current at system and/or neutral side of the generator stator windings is calculated and then compared with the measured INS and/or INR values by the DGP as a part of the background self-test. The INR current is used to process the 51GN function DGP .If desired, a dedicated neutral CT can be used for the input INR.
The DGP phase voltage inputs can be wye or delta and are derived from the generator terminal voltage. VN is derived from the generator neutral grounding
DGP Monitoring
Present Values GEN Simulator DGP
0000 PRESENT VALUES Station ID:MALVERN
Generator ID:MODEL GENERATOR 10/28/93 14:37:23:446 IAS: 5696.0 A -014 DEGS VAN: 008.5 KV 000 DEGS IBS: 5488.0 A -142 DEGS VBN: 008.1 KV -118 DEGS ICS: 4864.0 A 104 DEGS VCN: 008.2 KV 122 DEGS IAR: 5680.0 A -014 DEGS IBR: 5456.0 A -142 DEGS ICR: 4880.0 A 104 DEGS NEGATIVE SEQ CURRENT: 08.1 % 3RD HARM PH: 00.1 % 3RD HARM N: 03.7% WATTS:
+126.33 MWATT
GEN OFF-LIN: OPEN DIG IN 3: OPEN OSC TRIG: OPEN FREQ: 60.00
VARS: +041.95 MVAR INLET VLV: OPEN DIG IN 4: OPEN EXT VTFF: OPEN SAMPLING FREQ:
720.0
• • • • • •
Currents Voltages Watts Vars Frequency Negative Sequence Current • 3rd Harmonic Voltage • Status of Digital Inputs
Fault Report Gen Simulator DGP
0000 FAULT REPORT
Station ID:MALVERN Generator ID:MODEL GENERATOR
– Currents – Voltages – Watts – Vars – Frequency
FAULT#: 02 FAULT DATE: 08/09/93 TRIP TIME: 05:10:37:829 FAULT TYPE: ABC TRIP TYPE: 87G SYSTEM OPERATING TIME: 000008 PREFAULT -------------------------------------IAS: 0128.0 A IBS: 0208.0 A ICS: 0080.0 A
VBN: 010.2 KV VCN: 010.0 KV FREQ: 60.00
FAULT -----------------------------------------------------IAS: 014672 A IAR: 015664 A IBS: 015264 A IBR: 016704 A ICS: 013600 A ICR: 014960 A INS: 0048.0 A INR: 0384.0 A VAN: 010.2 KV VAN: 693.0 V VBN: 693.0 V VCN: 679.4 V VN: 047.0 V
WATTS: +1888.5 KWATT VARS: +3777.0 KVAR 05:10:37.834 87G PHASE A ON 05:10:37.834 87G PHASE B ON
Prefault
Post Fault – Currents – Voltages – Trip Targets – Operating Time
Selected Events Last 3 Faults Stored
TYPICAL WIRING DIAGRAM OF DGP
END
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Fault Data •Three phase faults have the highest fault current.
•Single phase faults have the lowest fault current. •The fault current is determined by the impedance of the fault path. •Fault paths closer to the source will have less impedance. •Faults caused by trees will have higher impedance.
Desirable Protection Attributes •Reliability: System operate properly – Security: Don’t trip when you shouldn’t – Dependability: Trip when you should
•Selectivity: Trip the minimal amount to clear the fault or abnormal operating condition
•Speed: Usually the faster the better in terms of minimizing equipment damage and maintaining system integrity •Simplicity: Less components simple wiring •Economics: Don’t break the bank
Art & Science of Protection Selection of protective relays requires compromises: •
Maximum and Reliable protection at minimum equipment cost
•
High Sensitivity to faults and insensitivity to maximum load currents
•
High-speed fault clearance with correct selectivity
•
Selectivity in isolating small faulty area
•
Ability to operate correctly under all predictable power system conditions
•
Primary objectives is to have faulted zone’s primary protection operate first, but if there are protective relays failures, some form of backup protection is provided.
25
GE Consumer & Industrial Multilin
Primary Equipment & Components • Transformers - to step up or step down voltage level • Breakers - to energize equipment and interrupt fault current to isolate faulted equipment • Insulators - to insulate equipment from ground and other phases • Isolators (switches) - to create a visible and permanent isolation of primary equipment for maintenance purposes and route power flow over certain buses. • Bus - to allow multiple connections (feeders) to the same source of power (transformer). 26 GE Consumer & Industrial Multilin
Primary Equipment & Components • Grounding - to operate and maintain equipment safely • Arrester - to protect primary equipment of sudden overvoltage (lightning strike). • Switchgear – integrated components to switch, protect, meter and control power flow
• Reactors - to limit fault current (series) or compensate for charge current (shunt) • VT and CT - to measure primary current and voltage and supply scaled down values to P&C, metering, SCADA, etc. • Regulators - voltage, current, VAR, phase angle, etc. 27 GE Consumer & Industrial Multilin
Types of Protection Overcurrent • Uses current to determine magnitude of fault – – – – – –
Simple May employ definite time or inverse time curves May be slow Selectivity at the cost of speed (coordination stacks) Inexpensive May use various polarizing voltages or ground current for directionality
Instantaneous Overcurrent Protection (IOC) & Definite Time Overcurrent (DTOC) • Relay closest to fault operates first • Relays closer to source operate slower • Time between operating for same current is called CTI (Clearing Time Interval)
CTI
t
I
CTI 50 +2
Distribution Substation
50 +2
29 GE Consumer & Industrial Multilin
(TOC) Coordination •Relay closest to fault operates first •Relays closer to source operate slower •Time between operating for same current is called CTI
t
I
CTI
Distribution Substation
Time Overcurrent Protection (TOC) • Selection of the curves uses what is termed as a “ time multiplier” or “time dial” to effectively shift the curve up or down on the time axis
• Operate region lies above selected curve, while no-operate region lies below it • Inverse curves can approximate fuse curve shapes
Types of Protection Differential – – – – – –
current in = current out Simple Very fast Very defined clearing area Expensive Practical distance limitations • Line differential systems overcome this using digital communications
1 pu IP
CT-X
IP
CT-Y
IS
IS
Relay IR-X
IR-Y
+1 Current, pu
1 + (-1) = 0 0
-1 DIFF CURRENT
Differential • Note CT polarity dots • This is a throughcurrent representation • Perfect waveforms, no saturation
2 pu
2 pu
Fault
IP
CT-X
IP
CT-Y
Differential
X IS
IS
Relay IR-X
IR-Y
+2 Current, pu
2 + (+2) = 4 0
-2 DIFF CURRENT
• Note CT polarity dots • This is an internal fault representatio n • Perfect waveforms, no saturation
Types of Protection Voltage • Uses voltage to infer fault or abnormal condition • May employ definite time or inverse time curves • May also be used for undervoltage load shedding – Simple – May be slow – Selectivity at the cost of speed (coordination stacks) – Inexpensive
Types of Protection Frequency • Uses frequency of voltage to detect power balance condition • May employ definite time or inverse time curves • Used for load shedding & machinery under/overspeed protection – Simple – May be slow – Selectivity at the cost of speed can be expensive
Types of Protection Power • Uses voltage and current to determine power flow magnitude and direction • Typically definite time – Complex – May be slow – Accuracy important for many applications – Can be expensive
Types of Protection Distance (Impedance) – Uses voltage and current to determine impedance of fault – Set on impedance [R-X] plane – Uses definite time – Impedance related to distance from relay – Complicated – Fast – Somewhat defined clearing area with reasonable accuracy – Expensive – Communication aided schemes make more selective
Protection Zones 1. Generator or Generator-Transformer Units 2. Transformers 3. Buses 4. Lines (transmission and distribution)
5. Utilization equipment (motors, static loads, etc.) 6. Capacitor or reactor (when separately protected) Bus zone Unit Generator-Tx zone
Bus zone Line zone
Bus zone Motor zone
Transformer zone
Transformer zone
~ Generator
XFMR
Bus
Line
Bus
XFMR
Bus
Motor
What Info is Required to Apply Protection 1. One-line diagram of the system or area involved 2. Impedances and connections of power equipment, system frequency, voltage level and phase sequence 3. Existing schemes 4. Operating procedures and practices affecting protection 5. Importance of protection required and maximum allowed clearance times 6. System fault studies 7. Maximum load and system swing limits 8. CTs and VTs locations, connections and ratios 9. Future expansion expectance 10. Any special considerations for application.
Abnormal Operating Conditions
ANSI / IEEE Standards
• Latest developments reflected in:
– Std. 242: Buff Book Latest developments reflected in: – C37.102: IEEE Guide for Generator Protection – Std. 242: Buff Book – C37.101: IEEE Guide for AC Generator Ground Protection – C37.102: IEEE Guide for Generator – C37.106: IEEE Guide for Abnormal Frequency Protection Protection for Power Generating Plants – C37.101: IEEE Guide for AC Generator Ground Protection – C37.106: IEEE Guide for Abnormal Frequency Protection for Power Generating These are created/maintained by the IEEE PSRC & IAS Plants They are updated every 5 years
Small Machine Protection IEEE Buff Book
32 Reverse Power 40 Loss of Excitation 51V voltage restraint 51G Ground O/C 87 Differential
• Small – up to 1 MW to 600V, 500 kVA if >600V
Small Machine Protection IEEE Buff Book
32 Reverse Power 40 Loss of Excitation
46 Negative Sequence 51V voltage restraint 51G Ground O/C 87 Differential
• Medium – up to 12.5 MW
Small Machine Protection IEEE Buff Book 32 Reverse Power 40 Loss of Excitation 46 Negative Sequence 49 Thermal Overload
51V voltage restraint 51G Ground overcurrent 64 Ground Relay 87 Differential
• Large – up to 50 MW
Large Machine Protection IEEE C37.102 • Unit Connected, High Z Grounded
32 Reverse Power 40 Loss of Excitation 46 Negative Sequence 49 Thermal Overload 51V voltage restraint 51G Ground overcurrent 64 Ground Relay 87 Differential
Under & Over Voltage Protection • Protects against a severe overload condition (27) • Initiates the starting of an emergency standby genset (27) • Load shed shut down in the event of AVR failure (27) • Protect against dangerous over-voltages (59) • Backup to internal V/Hz limiters • Commonly combined 27/59
Devices 27 / 59
Reverse Power Protection • Provides backup protection for the prime mover. • It detects reverse power flow (kW) should the prime mover lose it’s input energy without tripping its generator feeder breaker • Prevents motoring, drawing real power from the system
Device 32
Loss of Field Protection •Loss of excitation can occur:
Device 40
•Loss of field to the main exciter. •Accidental tripping of the field breaker. •Short circuits in the field circuits. •Poor brush contact in the exciter. •Field circuit-breaker latch failure. •Loss of ac supply to the excitation system. •Reduced-frequency operation when the regulator is out of service.
Phase Balance Current Protection • Unbalanced loads • Unbalanced system faults • Open conductors • Unbalanced I2 currents induce 2X system frequency currents in the rotor causing overheating
Device 46
Backup Overcurrent Protection
• The function of generator backup protection is to disconnect the generator if a system has not been cleared by the primary protective device • Time delays
Device 51V/21
Ground Overcurrent Protection • Provides backup protection for all ground relays in the system at the generator voltage level • Provides protection against internal generator ground faults • Commonly provided as GF alarm.
Device 51G
Voltage Balance Relay
Device 60 • Monitors the availability of PT voltage. • Blocks improper operation of protective relays and control devices in the event of a blown PT fuse
Out of Step Protection •High peak currents and off-frequency operation can occur when a generator losses synchronism.
Device 78
•Causes winding stress, high rotor iron currents, pulsating torques and mechanical resonances.
•Conventional relaying approach – analyzing variations in apparent impedance as viewed at generator terminals. •Variation in impedance can be detected by impedance relaying and generator separated before the completion of one slip cycle
Differential Protection • For rapid detection of generator Φ to Φ or Φ-G faults. • When NGR’s are used, 87G should be used. • Used for protection of larger generators • Zone protection
Device 87
Phase Fault Protection (87G)
Differential Protection (87) • A key point to remember is that differential relays don’t prevent damage, they LIMIT damage. • If a relay is properly operating it won’t trip until there is actually a line to ground fault somewhere in its zone of protection. • By limiting the duration of a fault, it is often possible to limit damage, but there is STILL damage. • Eventually, you will have to deal with it.
REF Protection (87GN / 64GN)
Frequency Protection Significant load addition Sudden reduction in mechanical input power Loss of generation / Loss of load Underfrequency can cause: Higher generator load currents Overexcitation Turbine blade fatigue
Device 81
Temperature Protection • Resistance temperature detectors are used to sense winding temperatures. • A long term monitoring philosophy that is not readily detected by other protective devices
RTD’s
FFBL GENERATOR PROTECTION LAYOUT
Digital Generator Protection System (DGP) • Microprocessor Based Protection, Control and Monitoring System • Waveform Sampling • User Friendly • GE/Hydro Quebec Joint Development
Tripping Methods Factors of selection includes severity of fault, probability of Fault spreading & overspeeding, time required to resynchronize, effect on power system etc. • SIMULTANEOUS TRIP
• MANUAL RUNBACK & TRIP
• GENERATOR TRIP
• AUTOMATIC RUNBACK
• BREAKER TRIP
• MANUAL RUNBACK
• SEQUENTIAL TRIP • MANUAL TRIP
Generator Faults (GE) • STATOR OVERCURRENT • STATOR GROUND FAULT • STATOR PHASE TO PHASE FAULT • OVER VOLTAGE • VOLT PER HERTZ • FIELD OVEREXCITATION • FIELD GROUND • LOSS OF EXCITATION • UNBALANCED ARMATURE CURRENT • STATOR OVERTEMPERATURE
• LOSS OF SYNCHRONISM • ABNORMAL FREQUENCY OPERATION • BREAKER FAILURE • HIGH SPEED RECLOSING • SUBSYNCHRONOUS RESONANCE • INADVERTENT ENERGIZATION • SYSTEM BACK UP • VOLTAGE SURGES • BEARING VIBRATION • SYNCHRONIZING ERRORS • MOTORING
Digital Generator Protection System (DGP)
DGP Digital Generator Protection The DGP is a digital system which provides a wide range of protection, monitoring, control and recording functions for AC generators.
•It can be used on generators driven by steam, gas and hydraulic turbine. •Any size of generator can be protected with the DGP.
• A high degree of dependability and security is achieved by extensive self diagnostic routines and an optional redundant power supply.
Generator Trip Scheme • BREAKER TRIP • 46 UNBALANACE • 32 REVERSE POWER • 51 V OVERCURRENT WITH VOLTAGE RESTRAINT • 81 U UNDER FREQUENCY • TURBINE TRIP • 87 G DIFFERENTIAL • 40 LOSS OF EXCITATION • 24 OVER EXCITATION • 59 OVERVOLTAGE • 51 GN GROUND OVERCURRENT • ALARM ONLY • 27 UNDER VOLTAGE • 81 O OVER FREQUENCY • EXT VTFF • BLK # 9 (81, 32, 27, VTFF)
Applications • For Small, Medium and Large Generator Protection • Suitable for Variety of Prime-Movers - Gas, Steam, Hydro Turbines • Most Commonly Used Protection Functions Packaged in a Standard Modular Case
TYPICAL INPUT WIRING DIAGRAM OF DGP
THE DGP SYSTEM TAKES EIGHT CURRENT AND FOUR VOLTAGE SENSING INPUTS.
THE DGP SYSTEM The input currents in terminals BH1,INPUTS BH3, and BH5 (IAS, IBS, and ICS) are used to process functions 46, 40, 32, and 51V. These currents can be derived from system side or neutral side CTs as desired. Either the system or neutral side CTs can be used for these functions if the Stator Differential (87G) function is enabled. Current inputs INS and INR are derived from the residual connections of the respective phase CTs.
The current inputs INS and INR are derived from the residual connections of the respective phase CTs and do not require dedicated neutral CTs. Zero-sequence current at system and/or neutral side of the generator stator windings is calculated and then compared with the measured INS and/or INR values by the DGP as a part of the background self-test. The INR current is used to process the 51GN function DGP .If desired, a dedicated neutral CT can be used for the input INR.
The DGP phase voltage inputs can be wye or delta and are derived from the generator terminal voltage. VN is derived from the generator neutral grounding
DGP Monitoring
Present Values GEN Simulator DGP
0000 PRESENT VALUES Station ID:MALVERN
Generator ID:MODEL GENERATOR 10/28/93 14:37:23:446 IAS: 5696.0 A -014 DEGS VAN: 008.5 KV 000 DEGS IBS: 5488.0 A -142 DEGS VBN: 008.1 KV -118 DEGS ICS: 4864.0 A 104 DEGS VCN: 008.2 KV 122 DEGS IAR: 5680.0 A -014 DEGS IBR: 5456.0 A -142 DEGS ICR: 4880.0 A 104 DEGS NEGATIVE SEQ CURRENT: 08.1 % 3RD HARM PH: 00.1 % 3RD HARM N: 03.7% WATTS:
+126.33 MWATT
GEN OFF-LIN: OPEN DIG IN 3: OPEN OSC TRIG: OPEN FREQ: 60.00
VARS: +041.95 MVAR INLET VLV: OPEN DIG IN 4: OPEN EXT VTFF: OPEN SAMPLING FREQ:
720.0
• • • • • •
Currents Voltages Watts Vars Frequency Negative Sequence Current • 3rd Harmonic Voltage • Status of Digital Inputs
Fault Report Gen Simulator DGP
0000 FAULT REPORT
Station ID:MALVERN Generator ID:MODEL GENERATOR
– Currents – Voltages – Watts – Vars – Frequency
FAULT#: 02 FAULT DATE: 08/09/93 TRIP TIME: 05:10:37:829 FAULT TYPE: ABC TRIP TYPE: 87G SYSTEM OPERATING TIME: 000008 PREFAULT -------------------------------------IAS: 0128.0 A IBS: 0208.0 A ICS: 0080.0 A
VBN: 010.2 KV VCN: 010.0 KV FREQ: 60.00
FAULT -----------------------------------------------------IAS: 014672 A IAR: 015664 A IBS: 015264 A IBR: 016704 A ICS: 013600 A ICR: 014960 A INS: 0048.0 A INR: 0384.0 A VAN: 010.2 KV VAN: 693.0 V VBN: 693.0 V VCN: 679.4 V VN: 047.0 V
WATTS: +1888.5 KWATT VARS: +3777.0 KVAR 05:10:37.834 87G PHASE A ON 05:10:37.834 87G PHASE B ON
Prefault
Post Fault – Currents – Voltages – Trip Targets – Operating Time
Selected Events Last 3 Faults Stored
TYPICAL WIRING DIAGRAM OF DGP
END
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