Advanced Generator Ground Fault Protectionsprorelay.tamu.edu/wp-content/uploads/sites/3/2019/... ·...

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

[email protected]

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


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


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


• 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


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


43

Observations:Real Ω = 118kΩTotal Ω = 23kΩ


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


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


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


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


• 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?

Advanced Generator Ground Fault Protectionsprorelay.tamu.edu/wp-content/uploads/sites/3/2019/... ·...

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