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Omaha, NBOctober 12, 2017
Wayne HartmannBeckwith Electric
Senior VP, Customer ExcellenceSenior Member, IEEE
Advanced Generator Ground Fault Protections
A Revisit with New Information
72nd Annual Conference forProtective Relay Engineers
March 25-28, 2019
• Before joining Beckwith Electric, performed in application, sales and marketing management capacities at PowerSecure, General Electric, Siemens Power T&D and Alstom T&D.
• Provides strategies, training and mentoring to Beckwith Electric personnel in sales, marketing, creative technical solutions and engineering.
• Key contributor to product ideation and holds a leadership role in the development of course structure and presentation materials for annual and regional protection and control seminars.
• Senior Member of IEEE, serving as a Main Committee Member of the Power System Relaying and Control Committee for more than 25 years.
• Chair Emeritus of the IEEE PSRCC Rotating Machinery Protection subcommittee (’07-’10). • Contributed to numerous IEEE Standards, Guides, Reports, Tutorials and Transactions, delivered
Tutorials IEEE Conferences, and authored and presented numerous technical papers at key industry conferences.
• Contributed to McGraw-Hill's Standard Handbook of Power Plant Engineering.
Wayne HartmannSenior VP, Customer Excellence
Beckwith Electric’s top strategist for delivering innovative technology messages to the Electric Power Industry through technical forums and industry standard development.
Speaker Bio
2
Introduction• Ground faults in generator stator and
field/rotor circuits are serious events that can:– Lead to Damage– Cause Costly Repair– Result in Extended Outage– Cause Loss of Revenue
• We will examine traditional and advanced protection
3
Field/Rotor Ground Fault Damage• Initial field/rotor circuit ground establishes
ground reference– In the event of a second ground fault,
part of the field/rotor circuit is shorted out• Shorted portion of rotor causes unequal flux in air gap
between rotor and stator • Unequal flux in air gap causes torsional stress and vibration,
and can lead to considerable damage in rotor and bearings• In extreme cases, rotor contact with stator is possible
– Second rotor ground fault produces rotor iron heating from unbalanced currents
• Field/rotor ground faults should be detected and affected generators alarmed at high resistance levels and tripped at low resistance levels
4
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
5
Brushed and “Brushless” Excitation
Brushed
6
“Brushless”
Brushes and Collector Rings
HPC Technical & National Coil7
Field/Rotor Ground Fault (64F)
• To mitigate security issues of traditional DC-based rotor ground fault protection schemes, AC injection-based protection may be used– AC injection-based protection ignores
effects of sudden DC current changes in field/rotor circuits and attendant DC scheme security issues
8
DC-Based 64F
9
Advanced AC Injection Method
10
Exciter
Field
+
ExciterBreaker
–
CouplingNetwork
ProtectiveRelay
Signal Measurement& Processing
Square Wave Generator
Rotor Ground Fault Measurement
PROCESSOR
SQUAREWAVEGENERATOR
PROTECTIONRELAY(M-3425A)
FIELD GROUNDDETECTION
SIGNALMEASUREMENTCIRCUIT
37
VOUT
36
35
Measurement Point Time
Vf
VRVOUT
M-3921COUPLING NETWORK
GEN.ROTOR
MachineFrameGround
+
-RR
RC
C
Vf
ShaftGround BrushRf Cf,
Generator Protection
§ Plan a shutdown to determine why impedance is lowering, versus an eventual unplanned trip!
§ When resistive fault develops, Vf goes down
11
Brush Lift-Off Measurement
PROCESSOR
SQUAREWAVEGENERATOR
PROTECTIONRELAY(M-3425A)
FIELD GROUNDDETECTION
SIGNALMEASUREMENTCIRCUIT
37
VOUT
Vf SignalVALARM
VNORMAL
Brush Lift-Off Voltage
Measurement Point
VNORMAL = Normal Voltage forHealthy Brush Contact
VALARM = Alarm Voltage when BrushResistance Increases dueto poor contact
Time
36
35
M-3921COUPLING NETWORK
GEN.ROTOR
MachineFrameGround
+
-RR
RC
C
Vf
ShaftGround BrushRf Cf,
Generator Protection
12
§ When brush lifts off, Vf goes up
Advanced AC Injection Method: Advantages
• Scheme is secure against effects of DC transients in field/rotor circuit– DC systems are prone to false alarms and false trips,
so they sometimes are ignored or rendered inoperative, placing generator at risk
– AC system offers greater security so this important protection is not ignored or rendered inoperative
• Scheme can detect grounding brush lift-off based on change in rise time of the injected signal due to disconnection of the rotor capacitance– In brushless systems, measurement brush may be periodically
connected for short time intervals– Brush lift-off function must be blocked during time interval
measurement brush is disconnected13
Stator Ground Fault• Ground faults in stator winding can cause severe damage
as level of fault current increases– Depending on ground fault current available,
damage may be repairable or non-repairable
• Generators are subject to prolonged exposure to stator ground fault damage due to the fact that even if system connection and excitation are tripped, stored flux remains and contributes to arc as generator coasts down
• Due to exposure to this damage, several types of generator grounding are employed– Stator circuit of generator may be ungrounded,
low-impedance grounded, high-impedance grounded or hybrid-impedance grounded
14
G
IGen ISystem
Power SystemX
Current IGen Current Decay
TimeGenerator
Breaker Trips
ISystem
0
The Problem with Clearing Generator Ground Faults
Stator Ground Fault Damage
16
Overexcitation causing insulation damageand subsequent ground fault
Generator GroundingUngrounded
17
GSUTransformer
G System
NeutralGrounding
Transformer
Secondary Neutral
GroundingResistor
Resistance Grounded
High-Impedance Grounded
Generator Grounding
18
Hybrid Impedance Grounded
Stator Ground Fault• Traditional stator ground fault
protection schemes include:–Neutral overvoltage–Various third harmonic
voltage-dependent schemes
• These exhibit sensitivity, security and clearing speed issues that may subject generator to prolonged low level ground faults that may evolve into damaging faults
19
Neutral Overvoltage (59G)
• 59G provides 95% stator winding coverage20
59G
90-95% Coverage
NGT
NGR
System
GSU Transformer
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 neutral (very important) 21
59G-1
90-95% Coverage
NGT
NGR
System
Capacitive Coupling on System Ground Fault
59G-2
59G-1
GSU Transformer
Multiple 59G Element Application
• 59G-2 is blind to capacitive coupling by GSU – Short time delay (18V in work up)
22
• 59G-1 is set to 8V, which may include effects of capacitive coupling by GSU (12V in work up)– Long time delay
Tim
e (c
ycle
s)
Volts
0 5 10 15 20+
45
90
Trip 59G-1
Trip 59G-2
59G-18V, 80 cyc.
59G-215V, 10 cyc.
Why Do We Care About Faults Near Neutral?
• A fault at or near neutral shunts high resistance that saves stator from large currents with internal ground fault
• A generator operating with undetected ground fault near neutral is an accident waiting to happen
• Neutral undervoltage (3rd Harmonic) or Injection Techniques for complete (100%) coverage is used
23
GSUTransformer
System
NeutralGrounding
Transformer
NeutralGrounding
Resistor
3rd Harmonic Undervoltage (27TN)
• Fault near neutral shunts 3rd harmonic near neutral to ground• Result is third harmonic undervoltage• Security issues with generator operating mode and power
output (real and reactive)
25
59G
0-15% Coverage
27TN
59
NGT
NGR
GSU Transformer
3rd Harmonic Ratio or Difference (59R or 59D)
• Fault near neutral or terminal shunts 3rd harmonic– This upsets difference or ratio between neutral or terminal ends of stator
• Reliability may be issue with low levels of 3rd harmonic (element blocks with low values)
• Security issues with generator operating mode and power output (real and reactive) as that can change ratios in unpredictable ways
26
3rd Harmonics at Neutral Variations with Loading
Example Plot on Gas Turbine (Midsize, 180MVA)27
Use of Symmetrical Component Quantities to Supervise 59G Tripping Speed
• Both V2 and I2 implementation have been applied– A ground fault in generator zone produces primarily zero sequence voltage– A fault in VT secondary or system (GSU coupled) generates negative
sequence quantities in addition to zero sequence voltage
28
I2 > 0.05 pu
§ Setting§ Time
§ Setting§ Time
Trip59N-1
Trip59N-2
Block
Block
59N-1 [A]
59N-2 [B]
NOTES:[A] 59N-1 is set sensitive and fast, using I2 supervision to check for external ground faults and control (block) the element for external ground faults[B] 59N-2 is set less sensitive and slower, therefore it will not operate for external ground faults.
[C] V2 > 0.05 pu
[D] V0 < 0.07 pu
60FL Asserts 59N-1 [A]
§ Setting§ Time
§ Setting§ Time
NOTES:[A] 59N-1 is set sensitive and fast, using V2 and V0 supervision to check for external ground faults and control (block) the element for external ground faults[B] 59N-2 is set less sensitive and slower, therefore it will not operate for external ground faults.[C] V2 derived from 3Y phase VTs[D] V0 derived from 3Y phase VTs
Trip59N-1
Trip59N-2
Block
Block
59N-2 [B]
OR
AND
Stator Ground Fault Damage
Typical winding damage resulting from broken stator winding conductor
Typical core and winding damage resulting from a burned open bar in a slot
Typical winding damage resulting from broken stator winding conductor
Clyde V. Maughan; “Stator Winding Ground Protection Failures,” ASME Power 2013 29
Intermittent Arcing Ground Faults• Can be very destructive, especially at neutral• At neutral, even though AC current is very low, arcing fault
develops a high voltage DC transient• If enough arcs occur in a short time, destructive insulation damage
can occur• Conventional time delayed ground fault protection cannot protect
for these events
Burned away copper of a fractured connection ring
Premature Failure of Modern Generators, Clyde V. Maughan
Side of a bar deeply damagedby vibration sparking
30
Intermittent Arcing Ground Fault
VAB
VBC
VCA
VN
IN
31
Intermittent Arcing Fault Timer Logic
Stallable Trip Timer: Times Out to TripIntegrating Reset Time: Delays Reset for Interval
Arcing Detected
Trip Timer
ResetTime
Trip
STALL
32
Intermittent Arcing Ground Fault
0
2
4
6
8
10
Stalling Trip Timer
(cycles)
Arcing Fault Detected(cycles)
Master Reset Timer(cycles)
1 1 3 2 2 1
0 10 20
TRIP
Arcing and Trip 33
Intermittent Arcing Ground Fault
0
2
4
6
8
10
Stalling Trip Timer
(cycles)
Arcing Fault Detected(cycles)
Master Reset Timer(cycles)
1 1
0 10 20
Arcing and Reset (No Trip) 34
Intermittent Arcing Ground Fault Turned Multiphase
35
Arcing Ground Fault Detection59G/27TN Timing Logic
Interval and Delay Timers used together to detect intermittent pickups of
arcing ground fault
36
A
27TN pu < sp
V1 > 80%
59G pu > sp
O
Interval Timer
IN
5 cycles
Delay Timer
10 cyclesOUT
IN Pick Up
Drop Out
3 cycles
OUT
Trip59G/27TNArcing
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
37
Coupling Filter VoltageInjector
Measurements
I
Natural Capacitance
Notes:Ø Subharmonic injection frequency = 20 HzØ Coupling filter tuned for subharmonic frequencyØ Measurement inputs tuned to respond to subharmonic frequency
V
VoltageInjector
20Hz
Subharmonic Injection: 64S
• Functions on-line and off-line• Power and frequency independent
38
GSUTransformer
G System
NeutralGrounding
Transformer
NeutralGrounding
Resistor
52
Static Frequency Converter
V1
§ No V0, therefore no I0§ No current flow through neutral§ No interference with 20Hz injected signal
Arcing Ground Fault Detection59G/64S Timing Logic
Interval and Delay Timers used together to detect intermittent pickups of
arcing ground fault39
59G pu > sp
O
Interval Timer
IN
5 cycles
Delay Timer
10 cyclesOUT
IN Pick Up
Drop Out
3 cycles
OUT
Trip by59G/64STransientGround Fault Protection
64S pu > sp
40
Subharmonic Injection: 64SSecurity Assessment
• Real component: Used to detect and declare stator ground faults through entire stator winding (and isophase and GSU/UAT windings), except at the neutral or faults with very low (near zero) resistance.
• Total component: A fault at the neutral or with very low resistance results in very little/no voltage (VN) to measure, therefore current cannot be segregated into reactive and real components, so total current is used as it does not require voltage reference. • In addition, presence of total current provides diagnostic check
that system is functional and continuity exists in ground primary and secondary circuits.
41
Subharmonic Injection: 64SSecurity Assessment
• A typical stator resistance (not reactance) to ground is >100k ohm, and a resistive fault in the stator is typically declared in the order of <=5k ohm.
• The two areas of security concern are when the generator is being operated at frequencies of 20 Hz and 6.67 Hz. All other operating frequencies are of no concern due to the 20 Hz filter and tuning of the element response for 20 Hz values.
• For our analysis, we use data from a generator in the southeastern U.S.A. outfitted with a 64S, 20 Hz subharmonic injection system.
42
Subharmonic Injection: 64SSecurity Assessment
Case 1: Generator Operating at 20 Hz• If the generator is operating as a
generator at 20 Hz without an external source (e.g., drive, LCI, back-to-back hydro start), there is no concern as the 20 Hz at the terminals is at or very close to balanced; therefore, 20 Hz zero-sequence current will not flow through the neutral circuit.
• If the generator is being operated as a motor with an external source (e.g., drive, LCI, back-to-back hydro start), the phase voltages are balanced or very close to balanced.
Coupling Filter
Measurements
I
Natural Capacitance
Notes:Ø Subharmonic injection frequency = 20 HzØ Coupling filter tuned for subharmonic frequencyØ Measurement inputs tuned to respond to subharmonic frequency
V
Injector
20Hz0.2Ω
25V
20kV
20,000V:240V
400 :5 Relay
8Ω
343 MVA
Subharmonic Injection: 64SSecurity Assessment
43
Observations:Real Ω = 118kΩTotal Ω = 23kΩ
Subharmonic Injection: 64SSecurity Assessment
44
Calculate CT primary currents:
IN pri (total) = 14.1 A * 10-3 * CTRIN pri (total) = 14.1 A * 10-3 * 80IN pri (total)= 1.128A
IN pri (real) = 2.8 A * 10-3 * CTRIN pri (real) = 2.8 A * 10-3 * 80IN pri (real) =0.224 A
Currents and voltages at grounding transformer primary:
IN pri (total) =1.128 A / NGT ratioIN pri (total) =1.128 A / 83.33IN pri (total) =0.013536 A
IN pri (real) = 0.0224 A / NGT ratioIN pri (real) = 0.0224 A / 83.33IN pri (real) = 0.002688 A
VN pri = V sec * NGT ratioVN pri = V sec * NGT ratioVN pri = 25 V
3rd harmonic voltage measured at relay = 0.75 V
V pri = V sec * NGT ratioV pri = 0.75 V * 83.33V pri =62.5 V
Assuming a zero sequence unbalance of 0.1% of nominal at 60 Hz
V pri unbalance = % unbalance / 100 * V L-L rated / √3V pri unbalance = (0.1% / 100) * (20,000 V / 1.73)V pri unbalance = 11.5V
V sec unbalance = V pri unbalance / NGT ratioV sec unbalance = 11.5 V / 83.33V sec unbalance = 0.14 V
Assuming V/Hz is kept constant in LCI or back-to-back generator start. The voltage at 20 Hz frequency is 20 Hz voltage during the start. Assuming 1pu V/Hz 120/60 = 2 = 1pu• Frequency divisor: 60 Hz / 20 Hz = 3. • Voltage divisor is 3.
V sec unbalance (20 Hz) = V sec unbalance (60 Hz) / 3V sec unbalance (20 Hz) = 0.14 V / 3 = 0.0466 V
Subharmonic Injection: 64SSecurity Assessment
45
20 Hz current flowing through NGR:NGR I 20 Hz = V sec unbalance (20 Hz) * NGR ΩNGR I 20 Hz = 0.0466 / 0.2 = 0.223 A
Relay measured 20 Hz current:I 20Hz Relay = NGR I 20 Hz * CTRI 20Hz Relay = 0.223 A / 80I 20Hz Relay = 0.0029 A = 2.9 mA
Using pickup values are 20 mA total and 6 mA real, element remains secure.
• Total current calculated: 2.9 mA• Total current setting: 20 mA• Margin: 17.1 mA
Total current calculated: 2.9 mAReal current setting: 6.0 mAMargin: 3.1 mA
Note the margins:
Settings:Real Ω = 55kΩTotal Ω = 16kΩ
Subharmonic Injection: 64SSecurity Assessment
Case 2: 6.67 Hz voltage at the generator terminals, assume 3rd harmonic (20 Hz) created in the neutral
In this case, we are assuming the generator under study is being started with a drive, LCI or back-to-back hydro start. The generator is acting like a motor and the unbalance is originating from the source.
Using typical values from a generator operating under full load, 3rd harmonic can be expected to be approximately 5X no load value.
3rd V 60 Hz NGT pri = 5 * (no load 3rd harmonic) * NGT ratio3rd V 60 Hz NGT pri = 5 * 0.75 V * 83.333rd V 60 Hz NGT pri = 312.498 V
The frequency during the start is reduced to 6.67 Hz (3 * 6.67 Hz= 20 Hz).
Assuming the V/Hz is kept as constant, the 3rd harmonic voltage is reduced.3rd V 20 Hz NGT pri = 6.67 Hz / 60 Hz * 312.498 V (without reduction in capacitance)3rd V 20 Hz NGT pri = 34.74 V (without reduction in capacitance) 46
Subharmonic Injection: 64SSecurity Assessment
Since the frequency is 20 Hz and not 180 Hz, there is a further reduction in 3rd harmonic current due to the capacitance at 1/9th of 60 Hz value. (180/20=9)
The model is complex and the relationship is not straightforward, so we assume a reduction of 1/5th instead of 1/9th
3rd V 20 Hz NGT pri = 34.74 V / 5 = 6.9 V
Voltage at NGT secondary:NGT V sec = 3rd V 20 Hz NGT pri / NGT ratioNGT V sec = 6.9 V / 83.33 = 0.0828 V
Current through NGR:NGR I 20 Hz = NGT V sec / NGR ΩNGR I 20 Hz = 0.0828 / 0.2 = 0.414 A
Relay measured 20 Hz current:I 20Hz Relay = NGR I 20 Hz * CTRI 20Hz Relay = 0.414 A / 80I 20Hz Relay = 0.005175 A = 5.175 mA 47
Subharmonic Injection: 64SSecurity Assessment
• Total current calculated: 5.175 mA• Total current setting: 20 mA• Margin: 14.825 mA
• Total current calculated: 5.175 mA• Real current setting: 6.0 mA• Margin: 0.825 mA
Note the margins:
48
Higher Margin for Real Ω: 7.0mA = 47.2kΩ; 8.0mA = 41.3kΩ
Summary and Conclusions
• Field/Rotor Ground Fault– Use of AC injection offers greater security than traditional DC
measurement systems, and can also detect brush lift-off condition
• 95% Stator Ground Fault Protection– Use of 59G element is time-tested method of protecting 95% of
stator for generator ground faults• Traditional approach to cope with GSU capacitive coupling and
interference with 59G element is using two elements, one long with long time delay coordinated system ground protection, and other with short time delay for in-zone ground faults.
• An advanced method of using sequence component supervision allows determination of external ground faults, and allows 59G element to quickly clear ground faults in generator zone.
49
Summary and Conclusions• 100% Stator Ground Fault Protection
– 3rd harmonic protection implementations are available to complement 59N element to provide 100% stator ground fault protection.
• 3rd harmonic protections may not work with all generators, and may not work at all times on given generator.
• 3rd harmonic values available for protection vary with operational mode and power (real and reactive) output.
– Both security and dependability issues may develop.
– Intermittent arcing ground faults can be detected with use of interval timing scheme on 59G and 27TN protections.
• This enhancement provides the ability to detect intermittent ground faults before a permanent ground/multi phase fault develops.
50
Summary and Conclusions• 100% Stator Ground Fault Protection
– Use of subharmonic injection provides ability to detect ground faults anywhere in stator or in unit-connected zone regardless of generator operation and loading
– If element uses real component for fault declaration, it is very sensitive
– As long as external signals at or near the subharmonic injected frequency are balanced, element is highly secure
• Element only responds to zero sequence current in generator neutral, not positive sequence current from external balanced system such as:
– Another generator during back-to-back starting – Static converter employed in starting combustion
gas turbine generators
51
References1. IEEE Guide for Generator Ground Protection, ANSI/IEEE C37.101-2006.2. IEEE Guide for AC Generator Protection, ANSI/IEEE C37.102-2006.3. IEEE Tutorial on the Protection of Synchronous Generators, Second Edition,
2010; Special Publication of the IEEE Power System Relaying Committee.4. IEEE Recommended Practice for Grounding of Industrial and Commercial
Power Systems, IEEE Std. 142-1991.5. Protection Considerations for Combustion Gas Turbine Static Starting; Working
Group J-2 of the Rotating Machinery Subcommittee, Power System RelayingCommittee.
6. Protective Relaying for Power Generation Systems; Donald Reimert, CRC Press2006; ISBN#0-8247-0700-1.
7. Practical Improvement to Stator Ground Fault Protection Using NegativeSequence Current; Russell Patterson, Ahmed Eltom; IEEE Transactions Paperpresented at the Power and Energy Society General Meeting (PES), 2013 IEEE.
8. Behavior Analysis of the Stator Ground Fault (64G) Protection Scheme; RamónSandoval, Fernando Morales, Eduardo Reyes, Sergio Meléndez and Jorge Félix,presented to the Rotating Machinery Subcommittee of the IEEE Power SystemRelaying Committee, January 2013.
52
Omaha, NBOctober 12, 2017
Wayne HartmannBeckwith Electric
Senior VP, Customer ExcellenceSenior Member, IEEE
Advanced Generator Ground Fault Protections
A Revisit with New Information
Questions?