GENERATOR PROTECTION OVERVIEW 160118

GENERATOR PROTECTION OVERVIEW 160118 Presenter Contact Info Wayne Hartmann VP, Protection and Smart Grid Solutions Beckwith Electric Company [email protected] 904-238-3844 Wayne Hartmann is VP, Protection and Smart Grid Solutions for Beckwith Electric. He provides Customer and Industry linkage to n as contributing expertise for Beckwith Electric’s solutions, as well application engineering, training and product development. Before joining Beckwith Electric, Wayne performed in application, sales and marketing management capacities with PowerSecure, General Electric, Siemens Power T&D and Alstom T&D. During the course of Wayne's participation in the industry, his focus has been on the application of protection and control systems for electrical generation, transmission, distribution, and distributed energy resources. Wayne is very active in IEEE as a Senior Member serving as a Main Committee Member of the IEEE Power System Relaying Committee for 25 years. His IEEE tenure includes having chaired the Rotating Machinery Protection Subcommittee (’07-’10), contributing to numerous standards, guides, transactions, reports and tutorials, and teaching at the T&D Conference and various local PES and IAS chapters. He has authored and presented numerous technical papers and contributed to McGrawHill's “Standard Handbook of Power Plant Engineering, 2nd Ed.” 2 Generator Protection Generator Construction: Simple Bock Diagram Prime Mover (Mechanical Input) G DC Field Source ia ib ic Three-Phase Electrical Output 3 Generator Protection Applying Mechanical Input 3 4 2 1 1. 2. 3. 4. Reciprocating Engines Hydroelectric Gas Turbines (GTs, CGTs) Steam Turbines (STs) 4 Generator Protection Applying Field Static Exciter • • DC is induced in the rotor AC is induced in the stator 5 Generator Protection Rotor Styles Cylindrical (Round) Salient  Cylindrical rotor seen in Recips, GTs and STs  Salient pole rotor seen in Hydros  More poles to obtain nominal frequency at low RPM  Eq: f= [RPM/60] * [P/2] = [RPM * P] / 120 6 Generator Protection Cylindrical Rotor & Stator 7 Generator Protection Salient Pole Rotor & Stator 8 Generator Behavior During Short Circuits 9 Generator Protection Generator Short-Circuit Current Decay 10 Generator Protection Current Current Current Three-Phase Fault Effect of DC Offsets 11 Generator Protection Generator Protection Grounding Techniques  Why Ground? • Improved safety by allowing detection of faulted equipment • Stop transient overvoltages • Notorious in ungrounded systems • Ability to detect a ground fault before a multiphase to ground fault evolves • If impedance is introduced, limit ground fault current and associated damage faults • Provide ground source for other system protection (other zones supplied from generator) 12 Generator Protection System R Grounding Resistor Types of Generator Grounding  Low Impedance • Good ground source • The lower the R, the better the ground source • The lower the R, the more damage to the generator on internal ground fault • Can get expensive as resistor voltage rating goes up • Generator will be damaged on internal ground fault • Ground fault current typically 200400 A 13 Generator Protection Types of Generator Grounding  High Impedance System GSU Transformer RNGR RR R Neutral Grounding Transformer  With delta/wye GSU, creates “unit connection”  System ground source obtained from GSU  Uses principle of reflected impedance  Eq: RNGR = RR / [Vpri/Vsec]2  RNGR = Neutral Grounding Resistor Resistance  RR = Reflected Resistance  Ground fault current typically <=10A 14 Generator Protection Types of Generator Grounding  Hybrid Impedance Grounding • Has advantages of Low-Z and High-Z ground • Normal Operation • Low-Z grounded machine provides ground source for other zones under normal conditions • 51G acts as back up protection for uncleared system ground faults • 51G is too slow to protect generator for internal fault Hybrid Ground  Ground Fault in Machine Converts from low-Z • Detected by the 87GD elementto high-Z for • The Low-Z ground path is opened by a fault internal generator vacuum switch • Only High-Z ground path is then available • The High-Z ground path limits fault current to1 5 approximately 10A (stops generator damage) Generator Protection Types of Generator Grounding Hybrid Ground Converts from low-Z to high-Z for internal generator fault 16 Generator Protection Types of Generator Ground Fault Damage  Following pictures show stator damage after an internal ground fault  This generator was high impedance grounded, with the fault current less than 10A  Some iron burning occurred, but the damage was repairable  With low impedance grounded machines the damage is severe 17 Generator Protection Stator Ground Fault Damage 18 Generator Protection Stator Ground Fault Damage 19 Generator Protection Stator Ground Fault Damage 20 Generator Protection Stator Ground Fault Damage 21 Generator Protection Types of Generator Connections  Bus or Direct Connected (typically Low Z) - Directly connected to bus - Likely in industrial, commercial, and isolated systems - Simple, inexpensive 22 Generator Protection Types of Generator Connections  Multiple Direct or Bus Connected (No/Low Z/High Z) BUS - Directly connected to bus - Likely in industrial, commercial, and isolated systems - Simple - May have problems with circulating current Same type of grounding used on 1 or mutiple generators  Use of single grounded machine can help - Adds complexity to discriminate ground fault source 23 Bus (Direct) Connected 24 Generator Protection Generator Protection Types of Generator Connections  Unit Connected (High Z) - Generator has dedicated unit transformer - Generator has dedicated ground transformer - Likely in large industrial and utility systems - 100% stator ground fault protection available BUS 25 Generator Protection Types of Generator Connections  Multiple Bus (High Z), 1 or Multiple Generators - Connected through one unit xfmr - Likely in large industrial and utility systems - No circulating current issue - Adds complexity to discriminate ground fault source  Special CTs needed for sensitivity, and directional ground overcurrent elements 26 Generator Protection Unit Connected 27 Generator Protection Generator Protection Overview Stator Ground System Ground Exciter "Wild" Power System Stator Phase System Phase Internal and External Short Circuits 28 Generator Protection Generator Protection Overview Open Circuits Overexcitation Loss of Field Loss of Field Abnormal Frequency Overexcitation Exciter "Wild" Power System Inadvertent Energizing, Pole Flashover Abnormal Frequency Reverse Power Breaker Failure Overexcitation Loss of Synchronism Abnormal Operating Conditions 29 Unit Connected, High Z Grounded 30 Generator Protection Stator Ground Fault-High Z Grounded Machines  95% stator ground fault provided by 59G Tuned to the fundamental frequency • Must work properly from 10 to 80 Hz to provide protection during startup  Additional coverage near neutral (last 5%) provided by: • • 27TN: 3rd harmonic undervoltage 59D: Ratio of 3rd harmonic at terminal and neutral ends of winding  Full 100% stator coverage by 64S • • • Use of sub-harmonic injection May be used when generator is off-line Immune to changes in loading (MW, MVAR) 31 Generator Protection Stator Ground Fault (59G)  High impedance ground limits ground fault current to about 10A • Limits damage on internal ground fault  Conventional neutral overvoltage relay provides 90-95% stator coverage  Last 5-10% near neutral not covered  Undetected grounds in this region bypass grounding transformer, solidly grounding the machine! 59G 32 Generator Protection 59G Element Voltage at Neutral (60 Hz) 1.0 pu 0.5 pu 59 G 0 0% N 50% Fault Position 100% T  Neutral grounding transformer (NGT) ratio selected that provides 120 to 240V for ground fault at machine terminals  Max L-G volts =13.8kV / 1.73 = 7995V  Max NGT volts sec. = 7995V / 120V = 66.39 VTR 33 Generator Protection 59G System Ground Fault Issue  GSU provides capacitive coupling for system ground faults into generator zone  Use two levels of 59G with short and long time delays for selectivity  Cannot detect ground faults at/near the neutral (very important) 34 Generator Protection  59G-1, set in this example to 5%, may sense capacitance coupled out-ofzone ground fault Time (cycles) Multiple 59G Element Application  Long time delay • 59G-2, set in this example to 15%, is set above capacitance coupled out-of-zone ground fault – Short time delay 35 Generator Protection Use of Symmetrical Component Quantities to Supervise 59G Tripping Speed  Both V2 and I 2 implementation have been applied  A ground fault in the generator zone produces primarily zero sequence voltage  A fault in the VT secondary or system (GSU coupled ) generates negative sequence quantities in addition to zero sequence voltage 36 Generator Protection 59G Element 59G – Generator Neutral Overvoltage: Three setpoints  1st level set sensitive to cover down to 5% of stator • Long delay to coordinate with close-in system ground faults capacitively coupled across GSU  2nd level set higher than the capacitively coupled voltage so coordination from system ground faults is not necessary • • Allows higher speed tripping Only need to coordinate with PT fuses  3rd level may be set to initiate waveform capture and not trip, set as intermittent arcing fault protection 37 Generator Protection 59G/27TN Timing Logic Interval and Delay Timers used together to detect intermittent pickups of arcing ground fault 38 Generator Protection Intermittent Arcing Ground Fault Turned Multiphase 39 Generator Protection Why Do We Care About Faults Near Neutral?  A fault at or near the neutral shunts the high resistance that saves the stator from large currents with an internal ground fault  A generator operating with an undetected ground fault near the neutral is a accident waiting to happen  We can use 3rd Harmonic or Injection Techniques for complete (100%) coverage 40 Generator Protection Third-Harmonic Rotor Flux • Develops in stator due to imperfections in winding and system connections • Unpredictable amount requiring field observation at various operating conditions • Also dependent on pitch of the windings, which a method to define the way stator windings placed in the stator slots Rotor MMF 41 Generator Protection Using Third Harmonic in Generators I 3h A, B, C C Generator winding and terminal capacitances (C) provide path for the third-harmonic stator current via grounding resistor R 3I 3h This can be applied in protection schemes for enhanced ground fault protection coverage 42 Generator Protection Generator Capacitance and 3rd Harmonics  3rd harmonics are produced by some generators  Amount typically small • Lumped capacitance on each stator end is CS/2.  CT is added at terminal end due to surge caps and isophase bus  Effect is 3rd harmonic null point is shifted toward terminal end and not balanced 43 Generator Protection 3rd Harmonic in Generators  3rd harmonic may be present in terminal and neutral ends  Useful for ground fault detection near neutral • If 3rd harmonic goes away, conclude a ground fault near neutral  3rd harmonic varies with loading 44 Generator Protection 27TN – 3rd Harmonic Neutral Undervoltage  Provides 0-15% stator winding coverage (typ.)  Tuned to 3rd harmonic frequency  Provides two levels of setpoints  Supervisions for increased security under various loading conditions: Any or All May be Applied Simultaneously       Phase Overvoltage Supervision Underpower Block Forward & Reverse Under VAr Block; Lead & Lag Power Factor Block; Lead & Lag Definable Power Band Block       Undervoltage/No Voltage Block Varies with load May vary with power flow direction May vary with level May vary with lead and lag May be gaps in output Loading/operating variables may be Sync Condenser, VAr Sink, Pumped Storage, CT Starting, Power Output Reduction 45 Generator Protection 3rd Harmonic in Generators: Typical 3rd Harmonic Values   3rd harmonic values tend to increase with power and VAr loading Fault near neutral causes 3rd harmonic voltage at neutral to go to zero volts 46 Generator Protection Example 3rd Harmonic Plot: Effects of MW and MVAR Loading 47 Generator Protection 100% Stator Ground Fault (59G/27TN) 0-15% Coverage 59G 59 G 27 TN 59 27TN OR TRIP 59 Power Supervisions Satisfied Power Supervisions Satisfied AND 48 Third-Harmonic Undervoltage Ground-Fault Protection Scheme Generator Protection 100% Stator Ground Fault (59G/27TN) +10 1.0 3rd Harmonic Voltage profile in winding Vfund profile in winding 0 0.5 59N pickup 27TN pickup -10 0 59G 27TN 49 Overlap of Third Harmonic (27TN) with 59G Relay Generator Protection 59D – 3rd Harmonic Ratio Voltage  Examines 3rd harmonic at line and neutral ends of generator  Provides 0-15% and 85-100% stator winding coverage (typ.)  Does not have a security issue with loading, as can a 27TN - May be less reliable than 27TN (not enough difference to trip)  “Blind spot” at mid-winding protected by 59G  Needs wye PTs; cannot use delta PTs 50 Generator Protection 59D – 3rd Harmonic Ratio Voltage 0-15% Coverage 59 G 85-100% Coverage VN 59D 3V0  Employs comparison of 3rd harmonic voltages at terminal and neutral ends  These voltages are fairly close to each other  One goes very low if a ground fault occurs at either end of the winding 51 Generator Protection Stator Ground Faults: 59N, 27TN, 59D 52 Generator Protection Subharmonic Injection: 64S  20Hz injected into grounding transformer secondary circuit  Rise in real component of injected current suggests resistive ground fault  Ignores capacitive current due to isophase bus and surge caps  Uses it for self-diagnostic and system integrity Natural Capacitance Coupling Filter Voltage Injector V 20Hz I Notes: Subharmonic injection frequency = 20 Hz Coupling filter tuned for subharmonic frequency Measurement inputs tuned to respond to subharmonic frequency Measurements 53 Generator Protection 64S: Stator Ground Faults – Subharmonic Injection  Injects subharmonic frequency into generator neutral • Does not rely on third harmonic signature of generator  Provides full coverage protection  Provides on and offline protection, prevents serious damage upon application of excitation  Frequency independent 54 Generator Protection Stator Ground Faults: High Z Element Coverage 55 Generator Protection Brushed and “Brushless” Excitation Grounding Power Brush Commutation Brushes STATOR A DC B C ROTOR STATOR EXCITER AVR “Brushless” SET Brushed 56 Generator Protection Field/Rotor Ground Fault  Traditional field/rotor circuit ground fault protection schemes employ DC voltage detection  Schemes based on DC principles are subject to security issues during field forcing, other sudden shifts in field current and system transients 57 DC-Based 64F 58 Generator Protection Generator Protection Field/Rotor Ground Fault (64F)  To mitigate the security issues of traditional DC-based rotor ground fault protection schemes, AC injection based protection may be used  AC injection-based protection ignores the effects of sudden DC current changes in the field/rotor circuits and attendant DC scheme security issues 59 Generator Protection Advanced AC Injection Method Field Exciter Breaker + Square Wave Generator Exciter – Signal Measurement & Processing Protective Relay Coupling Network 60 Generator Protection Advanced AC Injection Method: Advantages  Scheme is secure against the effects of DC transients in the field/rotor circuit  DC systems are prone to false alarms and false trips, so they sometimes are ignored or rendered inoperative, placing the generator at risk  The AC system offers greater security so this important protection is not ignored or rendered inoperative  Scheme can detect a rise in impedance which is characteristic of grounding brush lift-off  In brushless systems, the measurement brush may be periodically connected for short time intervals  The brush lift-off function must be blocked during the time interval the measurement brush is disconnected 61 GeneratorProtection Protection Generator Rotor Ground Fault Measurement  Plan a shutdown to determine why impedance is lowering, versus an eventual unplanned trip!  When resistive fault develops, Vf goes down PROTECTION RELAY (M-3425A) VR VOUT Vf PROCESSOR Measurement Point FIELD GROUND DETECTION SQUAREWAVE GENERATOR VOUT M-3921 COUPLING NETWORK C 37 + R R C 35 SIGNAL MEASUREMENT CIRCUIT GEN. ROTOR - R Rf Cf Vf 36 Time Shaft Ground Brush , Machine Frame Ground 62 Generator Protection 64B: Brush Lift Off   Commutation brush lift-off will lead to: - Arcing - Tripping on loss-of-field Grounding brush lift-off can lead to: - Stray currents that cause bearing pitting Commutation Brush Grounding Brush 63 Generator Protection 64B: Brush Lift Off  As brushes lift-off, the sawtooth wave’s return signal slope gets less rounded, which is detected as a rise in voltage Commutation Brush Grounding Brush 64 Generator Protection Brush Lift-Off Measurement  When brush lifts off, Vf goes up Brush Lift-Off Voltage Vf Signal VALARM VNORMAL PROTECTION RELAY (M-3425A) Measurement Point VNORMAL = Normal Voltage for Healthy Brush Contact VALARM = PROCESSOR FIELD GROUND DETECTION SQUAREWAVE GENERATOR Time VOUT M-3921 COUPLING NETWORK C 37 C SIGNAL MEASUREMENT CIRCUIT GEN. ROTOR - R Rf Cf Vf 36 + R R 35 Alarm Voltage when Brush Resistance Increases due to poor contact Shaft Ground Brush , Machine Frame Ground 65 Generator Protection 64B: Brush Lift Off ALARM 66 Generator Protection Field/Rotor Ground Faults  64F/B Relay 1 Relay 2 (M-3425) (M-3425) - It is possible to apply two systems and have redundancy 3 3 Switch System Field Assembly Relay Panel - The switch system is initiated by manual means or by monitoring relay self diagnostic contacts 3 Exciter System Coupling Unit M-3921 Rotor Brush (Typ.) + R - Exciter System 67 Generator Protection Stator Phase Faults  87G – Phase Differential (primary for in-zone faults) • What goes into zone must come out • Challenges to Differential • CT replication issues: Remenant flux causing saturation • DC offset desensitization for energizing transformers and large load pick up • Must work properly from 10 Hz to 80Hz so it operates correctly at offnominal frequencies from internal faults during startup • May require multiple elements for CGT static start • Tactics: • Use variable percentage slope • Operate over wide frequency range • Uses RMS I /IFUND to adaptively desensitize element when challenged by DC offset for security  DC offset can occur from black starting and close-in faults 68 Generator Protection 87 Characteristic 40% 10% 0.6A 0.3A CTC = CT Correction Ratio = Line CTR/Neutral CTR Used when Line and Neutral CTs have different ratios 69 70 Generator Protection CT Remanence and Performance  Magnetization left behind in CT iron after an external magnetic field is removed  Caused by current interruption with DC offset  CT saturation is increased by other factors working alone or in combination:  High system X/ R ratio which increases time constant of the CT saturation period  CT secondary circuit burden which causes high CT secondary voltage  High primary fault or through-fault current which causes high secondary CT voltage 70 Generator Protection CT Saturation [1] Fig. 2: 400:5, C400, R=0.5, Offset = 0.5, 2000A 71 Generator Protection CT Saturation [5] CT Saturation [2] Fig. 6: 400:5, C400, R=0.75, Offset = 0.75, 8000A 72 Generator Protection 40% 10% 0.6A 0.3A CTC = CT Correction Ratio = Line CTR/Neutral CTR Used when Line and Neutral CTs have different ratios 73 Generator Protection 46: Negative Sequence Current  Typically caused by open circuits in system -Downed conductors -Stuck poles switches and breakers  Unbalanced phase currents create negative sequence current in generator stator and induces a double frequency current in the rotor  Induced current (120 Hz) into rotor causes surface heating of the rotor 74 Generator Protection Rotor End Winding Construction 75 Currents Flow in the Rotor Surface Generator Protection Negative Sequence Current: Constant Withstand Generator Limits  Salient Pole - With connected amortisseur - With non-connected amortisseur  Cylindrical - Indirectly - Directly cooled - to 960 MVA  961 to 1200 MVA  1200 to 1500 MVA 10% 5% 10% 8% 6% 5% 76 Generator Protection Negative Sequence Current: Constant Withstand Generator Limits  Nameplate - Negative Sequence Current (I2) Constant Withstand Rating - “K” Factor 77 Generator Protection Generator Ratings Typical K Values Salient Pole Generators 40 Cylindrical Generators 30 78 Generator Protection 46: Negative Sequence Electromechanical Relays  Sensitivity restricted and cannot detect I 2 levels less than 60% of generator rating  Fault backup provided  Generally insensitive to load unbalances or open conductors 79 Generator Protection 46: Negative Sequence Digital Relay  Protects generator down to its continuous negative sequence current (I 2) rating vs. electromechanical relays that don’t detect levels less than 60%  Fault backup provided  Can detect load unbalances  Can detect open conductor conditions 80 Generator Protection Overexcitation (24)  Measured  High Volts/Hertz ratio  Normal = 120V/60Hz = 1pu  Voltage up, and/or frequency low, make event  Issues  Overfluxing of metal causes localized heating  Heat destroys insulation  Affects generators and transformers 81 Generator Protection Overexcitation (24) Causes of V/HZ Problems  Generator voltage regulator problems • Operating error during off-line manual regulator operation • Control failure • VT fuse loss in voltage regulator (AVR) sensing voltage • Unit load rejection: full load, partial rejection • Power system islanding during major disturbances • Ferranti effect • Reactor out • Capacitors in  System problems • Runaway LTCs 82 Generator Protection Overexcitation (24) Modern Protection  Definite time elements • • Curve modify Alarm  Inverse curves • Select curve type for best coordination to manufacturers recommendations • Employ settable reset timer • Provides “thermal memory” for repeat events 83 Generator Protection Overexcitation (24) Example plot using definite time and inverse curve 84 Generator Protection Overexcitation (24) Modern Protection  V/Hz measurement operational range: 2-80 Hz - Necessary to avoid damage to steam turbine generators during rotor pre-warming at startup - Necessary to avoid damage to converter-start gas turbine generators at startup - In both instances, the generator frequency during startup and shut down can be as low as 2 Hz NOTE: An Overvoltage (59) function, designed to work properly up to 120 Hz, is important for Hydro Generators where the generators can experience high speed (high frequency) during full load rejection. Since the V/Hz during this condition is low, the 24 function will not operate, and the 59 function will provide proper protection from overvoltage. 85 Generator Protection 40: Loss of Field Can adversely effect the generator and the system!!  Generator effects  Synchronous generator becomes induction  Slip induced eddy currents heat rotor surface  High reactive current drawn by generator overloads stator  Power system effects  Loss of reactive support  Creates a reactive drain  Can trigger system/area voltage collapse 86 Generator Protection Protection Generator VAR OUT Normal WATT VAR IN TYPICAL GENERATOR CAPABILITY CURVE Loss of Field Generator capability curve viewed on the P-Q plane. This info must be converted to the R-X plane. 87 Generator Protection Increased Power Out P-Q Plane TRANSFORMATION FROM MW-MVAR TO R-X PLOT Increased Power Out R-X Plane TYPICAL GENERATOR CAPABILITY CURVE Excitation Limiters and Steady State Stability 88 Generator Protection  Limiting factors are rotor and stator thermal limits  Underexcited limiting factor is stator end iron heat  Excitation control setting control is coordinated with steady-state stability limit (SSSL)  Minimum excitation limiter (MEL) prevents exciter from reducing the field below SSSL Generator Capability Curve Reactive Power Into System Rotor Winding Limited MW G + MVAR System MVAR Overexcited Stator Winding Limited + MW Real Power Into System 0 MEL Underexcited – MVAR Reactive Power Into Generator MW SSSL Stator End Iron Limited G System MVAR 89 Generator Protection Loss of Field GE and Westinghouse Methods +X –R Diameter = 1.0 pu Offset = Xd 2 Machine Capability +R Xd 2 SSSL MEL Diameter = Xd –X Two Zone Offset Mho GE CEH Impedance w/Directional Unit Westinghouse KLF 90 Generator Protection Loss of Field Two Zone Offset Mho Xd 2 91 Generator Protection Loss of Field Impedance w/Direction Unit Xd 2 92 Generator Protection Loss of Field Event  Generator Lost Field, then went Out-of-Step!!! Generator Protection Phase Distance (21)  Phase distance backup protection may be prone to tripping on stable swings and load encroachment - Employ three zones  Z1 can be set to reach 80% of impedance of GSU for 87G back-up.  Z2 can be set to reach 120% of GSU for station bus backup, or to overreach remote bus for system fault back up protection. Load encroachment blinder provides security against high loads with long reach settings.  Z3 may be used in conjunction with Z2 to form out-of-step blocking logic for security on power swings or to overreach remote bus for system fault back up protection. Load encroachment blinder provides security against high loads with long reach settings. - Use minimum current supervision provides security against loss of potential (machine off line) 94 Generator Protection Fault Impendance 21: Distance Element Load (for Z1, Z2, Z3) Blinder +X L With Load Encroachment Blinder fro Z1, Z2, Z3 T Z3 Z2 Z1 -R +R -X or Z1, Z2 and Z3 used to trip Z1 set to 80% of GSU, Z2 set to 120% of GSU Z3 set to overreach remote bus 95 Stable Power Swing and Load Encroachment Blinding Generator Protection 21: Distance Element With: • Power Swing Blocking • Load Encroachment Blocking for Z1 and Z2 Power Swing or Load Encroachment 96 Generator Protection Generator Out-of-Step Protection (78)  Types of Instability • • • Steady State: Steady Voltage and Impedance (Load Flow) Transient: Fault, where voltage and impedance change rapidly Dynamic: Oscillations from AVR damping (usually low f) • • • Short circuits that are severe and close Loss of lines leaving power plant (raises impedance of loadflow path) Large losses or gains of load after system break up  Occurs with unbalance of load and generation  Generator accelerates or decelerates, changing the voltage angle between itself and the system • Designed to cover the situation where electrical center of power system disturbance passes through the GSU or the generator itself • More common with modern EHV systems where system impedance has decreased compared to generator and GSU impedance 97 Generator Protection Generator Out-of-Step Protection (78) • When a generator goes out-of-step (synchronism) with the power system, high levels of transient shaft torque are developed. • If the pole slip frequency approaches natural shaft resonant frequency, torque produced can break the shaft • High stator core end iron flux can overheat and short the generator stator core • GSU subjected to high transient currents and mechanical stresses 98 Generator Protection Stability Pmax  Eg Es Pe  X Eg Es X  sin g  s  Es - System Voltage Eg - Generator Voltage s - System Voltage Phase Angle g - Generator Voltage Phase Angle Pe - Electrical Power Egg Ess For maximum power transfer: • Voltage of GEN and SYSTEM should be nominal – Faults lower voltage • Impedance of lines should be low – lines out raise impedance 99 Generator Protection Out of Step: Generator and System Issue Pe  Eg Es X  sin g  s  100 Generator Protection Graphical Method: 78 X A B  One pair of blinders (vertical lines) System XS GSU XT P R M Swing Locus Mho Element Gen Xd 2X D + XT + XS A Element Pickup B Element Pickup Blinder Elements  Supervisory offset mho  Blinders limit reach to swings near the generator Generator Protection Graphical Method: 78 X A B System XS Unstable Swing Stable Swing GSU XT R Mho Element Gen Xd 2X D + XT + XS A Element Pickup B Element Pickup Blinder Elements Generator Protection Out-of-Step (Loss of Synchronism) Event Generator Protection Off-Nominal Frequency Impacts  Underfrequency may occur from system overloading  Loss of generation  Loss of tie lines importing power  Underfrequency is an issue for the generator  Ventilation is decreased  Flux density (V/Hz) increases 81-U  Underfrequency limit is typically dictated by the generator and turbine  Generator: V/Hz and loading  Turbine: Vibration Issues  Overfrequency may occur from load rejection  Overfrequency is typically not an issue with the generator  Ventilation is improved 81-O  Flux density (V/Hz) decreases  Overfrequency limit is typically dictated by the turbine (vibration) 104 Generator Protection Frequency (Hz) System Frequency Overview   For overfrequency events, the generator prime mover power is reduced to bring generation equal to load For underfrequency events, load shedding is implemented to bring load equal to generation  It is imperative that underfrequency tripping for a generator be coordinated 1 0 5 with system underfrequency load shedding Generator Protection Abnormal Operating Conditions  81 – Four Step Frequency - Any step may be applied over- or underfrequency - High accuracy – 1/100th Hz (0.01 Hz) - Coordination with System Load Shedding  81A – Underfrequency Accumulator - Time Accumulation in Six Underfrequency Bands - Limits Total Damage over Life of Machine  Typically used to Alarm  81R – Rate of Change of Frequency - Allows tripping on rapid frequency swing 106 Generator Protection Steam Turbine Underfrequency Operating Limitations Continuous Frequency (Hz) 60 59 Restricted 58 57 Prohibited 0.001 0.01 0.10 1.0 Time (Minutes) Typical, from C37.106 10.0 100.0 107 Generator Protection Turbine Over/Underfrequency Frequency (Hz) 62 61 Restricted Time Operating Frequency Limits 60 Continuous Operation Prohibited Operation 59 Restricted Time Operating Frequency Limits 58 57 Prohibited Operation 56 0.001 0.005 0.01 0.05 0.50 0.10 1.0 Time (Minutes) Typical, from C37.106 5.0 50.0 10.0 100.0 108 Generator Protection 81A – Underfrequency Accumulator  Turbine blades are designed and tuned to operate at rated frequencies  Operating at frequencies different than rated can result in blade resonance and fatigue damage  In 60 Hz machines, the typical operating frequency range:  18 to 25 inch blades = 58.5 to 61.5 Hz  25 to 44 inch blades = 59.5 and 60.5 Hz  Accumulated operation, for the life of the machine, not more than:  10 minutes for frequencies between 56 and 58.5 Hz  60 minutes for frequencies between 58.5 and 59.5 Hz Generator Protection Causes of Inadvertent Energizing  Operating errors  Breaker head flashovers  Control circuit malfunctions  Combination of above 110 Generator Protection Inadvertent Energizing: Protection Response  Typically, normal generator relaying is not adequate to detect inadvertent energizing • Too slow or not sensitive enough • Distance • Negative sequence • Reverse power • Some types are complicated and may have reliability issues • Ex., Distance relays in switchyard disabled for testing and inadvertent energizing event takes place 111 Generator Protection Inadvertent Energizing  When inadvertently energized from 3-phase source, the machine acts like an induction motor  Rotor heats rapidly (very high I 2 in the rotor )  Current drawn  Strong system: 3-4x rated  Weak system: 1-2x rated  From Auxiliary System: 0.1-0.2x rated  When inadvertently energized from 1-phase source (pole flashover), the machine does not accelerate  No rotating flux is developed  Rotor heats rapidly (very high I 2 in the rotor )  Protection system must be able to detect and clear both 3-phase and 1-phase inadvertent energizing events 112 Generator Protection Inadvertent Energizing Oscillograph Inadvertent Energizing 113 Generator Protection Inadvertent Energizing Scheme  Undervoltage (27) supervises low-set, instant overcurrent (50) – recommended 27 setting is 50% or lower of normal voltage  Pickup timer ensures generator is dead for fixed time to ride through three-phase system faults  Dropout timer ensures that overcurrent element gets a chance to trip just after synchronizing 114 Generator Protection Breaker Failure Timeline Margin Time Protective Relay Time Fault Cleared Breaker Interrupt Time Backup Breaker Interrupt Time BFI 62 -1 BF Timer Time Fault Occurs BF Trip Command Time Generator Protection Breaker Pole Flashover & Stuck Pole 116 Generator Protection Generator Breaker Failure and Pole Flashover Scheme: Simplified Conceptual View 52/a Breaker is closed by current detection or position OR 50 BF OR Protective Elements Breaker Failure AND T 0 TDOE Breaker Failure Trip 1= Protection BFI 52/b AND 50 N 1= Flashover detected Pole Flashover 117 Generator Protection Anti-Motoring: 32  Used to protect generator from motoring during loss of prime mover power  Motoring:  Wastes power from the system  May cause heating in steam turbines as ventilation is greatly reduced  Steam and dewatered hydro can motor with very little power; <=1% rated  CGT and Recip typically use 10-25% of rated power to motor  Generators are often taken off the system by backing off the power until importing slightly so not to trip with power export and go into overspeed (turbine issue)  This is known as sequential tripping  Two 32 elements may be applied:     Sequential trip (self reset, no lockout) Abnormal trip (lockout) Need great sensitivity, down to .002pu Usually applied as 32R, may be applied as 32F-U 118 Generator Protection Generator Tripping and Shutdown • Generat ors m ay be shut down for unplanned and planned reasons • • • Shut downs m ay be whole or part ial Shut downs m ay lock out ( 86- LOR) or be self reset t ing ( 94) Unplanned • • • Fault s Abnorm al operat ing condit ions Scheduled • Planned shut down 119 Generator Protection Generator Tripping F T G G T = Turbine Trip F = Field Trip G = Generator Breaker Trip 120 Generator Protection Tripping Philosophy & Sequential Tripping – Unit separat ion • Used when m achine is t o be isolat ed from syst em , but m achine is left operat ing so it can be synced back t o t he syst em aft er separat ing event is cleared ( syst em issue) • Only generat or breaker( s) are t ripped F T G G 121 Generator Protection Tripping Philosophy & Sequential Tripping – Generat or Trip • Used when m achine is isolat ed and overexcit at ion t rip occurs • Excit er breaker is t ripped ( LOR) wit h generat or breakers already opened F T G G 122 Generator Protection Tripping Philosophy & Sequential Tripping – Sim ult aneous Trip ( Com plet e Shut down) • • • • Used when int ernal ( in-zone) prot ect ion assert s Generat or and excit er breakers are t ripped ( LOR) Prim e m over shut down init iat ed ( LOR) Auxiliary t ransfer ( if used) is init iat ed F T G G 123 Generator Protection Tripping Philosophy & Sequential Tripping – Sequent ial Trip • Used for t aking m achine off- line ( unfault ed) – Generat or and excit er breakers are t ripped ( 94) – Prim e m over shut down init iat ed ( 94) – Auxiliary t ransfer ( if used) is init iat ed F T G G 124 Generator Protection Sequential Tripping Generator Protection Sequential Tripping Tripping Philosophy & Sequential Tripping • Back down t urbine and excit at ion – Backing down excit at ion t o allows easier bet t er m easurem ent of power • I nit iat e Sequent ial Trip – Use 32 elem ent t hat t rips G, F and T, but does not do t his t hrough a LOR – When a sm all am ount of reverse power is det ect ed, t rip G, F and T 126 Generator Protection Trip Logic LOR In-Zone Issues System Issues LOR In-Zone Issues Normal Shutdown Alarms 127 Generator Protection Typical Protection Functions for a Large or Important Generator 128 Generator Protection Mitigating Reliability Concerns  Integrating many protection functions into one package raises reliability concerns  Address these concerns by… 1. Providing two MGPRs, each with a portion or all of the protection functions (redundancy for some or all) 2. Providing backup for critical components, particularly the power supply 3. Using MGPR self-checking ability 129 Generator Protection Aug 2003, NE Blackout: Generator Trips 531 Generators at 261 Power Plants tripped!!!  IEEE PSRC Survey  Conducted in early ’90s, exposed many areas of protection lacking  Reluctance to upgrade: • • • • Lack of expertise To recognize problems To engineer the work The thought that “Generators don’t fault” • Operating procedures can prevent protection issues 130 Generator Protection Why Upgrade?  Existing generator and transformer protection may:  Require frequent and expensive maintenance  Cause coordination issues with plant control (excitation, turbine control)  Trip on through-faults (external faults), stable power swings, load encroachment and energizing  Not follow NERC PRC Standards (PRC = protection and control)  Exhibit insensitivity to certain abnormal operating conditions and fault types  Not be self-diagnostic  Lack comprehensive monitoring and communications capabilities  Not provide valuable event information that can lead to rapid restoration  Part of NERC Report comments on the August 03 Blackout  Not be in compliance with latest ANSI/IEEE Standards!  Asset Reliability, Insurance, Liability Issues  C37-102: Guide for the Protection of Synchronous Generators 131 Generator Protection Protection Upgrade Opportunities  Improved sensitivity • Loss of Field • 100% stator ground fault • Reverse power • Negative sequence • Overexcitation  Improved Security • Directionally supervised ground differential protection • Distance Element Enhancements • Load encroachment blinding • Power swing blocking (for stable swings) 132 Generator Protection Protection Upgrade Opportunities  New protections • Inadvertent energizing • VT fuse loss (integrated)  Special applications • Generator breaker failure • Pole flashover (prior to syncing) 133 Generator Protection Oscillography  Determine if relay and circuit breaker operated properly - Identify relay, control or breaker problem - Generators do experience faults / abnormal conditions  In the machine or the system?  Speed generator’s return to service - Identify type of testing needed - Provide data to generator manufacturer  Gives plant engineer data to force unit off-line for inspection  Uncovers unexpected problems - Synchronizing, shutdown 134 Generator Protection Long Records Let You See the Issue Voltage collapse on Ph-Ph Fault Ph-Gnd Fault Ph-Ph Fault 3-Ph Fault Gen feeding fault into low side of GSU, no low side breaker Example of Ph-Gnd fault evolving into 3-Ph Fault Insulation breakdown due to high voltage 135 21P backup element tripped Generator Protection Summary  Generators require special protection for faults and abnormal operations  These protections are for in-zone and out-of zone events  Modern element design matter for security and dependability  Complexity can be made simple with the correct user tools 136 Generator Protection References 1. I EEE Guide for Generat or Ground Prot ect ion, ANSI / I EEE C37.101- 2006. 2. I EEE Guide for AC Generat or Prot ect ion, ANSI / I EEE C37.102- 2006. 3. I EEE Tut orial on t he Prot ect ion of Synchronous Generat ors, Second Edit ion, 2010; Special Publicat ion of t he I EEE Power Syst em Relaying Com m it t ee. 4. I EEE Recom m ended Pract ice for Grounding of I ndust rial and Com m ercial Power Syst em s, I EEE St d. 142- 1991. 5. Prot ect ion Considerat ions for Com bust ion Gas Turbine St at ic St art ing; Working Group J- 2 of t he Rot at ing Machinery Subcom m it t ee, Power Syst em Relay Com m it t ee. 6. Prot ect ive Relaying for Power Generat ion Syst em s; Donald Reim ert , CRC Press 2006; I SBN# 0- 8247- 0700- 1. 7. Pract ical I m provem ent t o St at or Ground Fault Prot ect ion Using Negat ive Sequence Current ; Russell Pat t erson, Ahm ed Elt om ; I EEE Transact ions Paper present ed at t he Power and Energy Societ y General Meet ing ( PES) , 2013 I EEE. 8. Behavior Analysis of t he St at or Ground Fault ( 64G) Prot ect ion Schem e; Ram ón Sandoval, Fernando Morales, Eduardo Reyes, Sergio Meléndez and Jorge Félix, present ed t o t he Rot at ing Machinery Subcom m it t ee of t he I EEE Power Syst em Relaying Com m it t ee, January 2013. 9. Advanced Generat or Ground Fault Prot ect ions; Wayne Hart m ann, present ed at t he West ern Prot ect ive Relay Conference, Oct ober 2015.