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Fundamentals of Microprocessor 
Based Protective Relays
Suhag Patel, P.E.
Industrial Electric Machinery
Carson, CA
IEEE In...
Objective
• Understand Commonly Used Protective 
Functions and Their ANSI Protective Device 
Numbers
• Understand Protecti...
ANSI Function Number
• Used to Easily Convey Information on 
Electrical Drawings
• Function Will Have a Number and Sometim...
ANSI Function Numbers – Partial 
Listing
Feeder Protection
• The Following ANSI Device Numbers Are 
Used for Feeder Protection:
– 50 – Instantaneous Overcurrent
– ...
Interrupting Methods
• Fuse
 Fusible element melts to disconnect faulty
zone/equipment
 I2T law
• Recloser
 Single or t...
50 – Instantaneous OC
OPERATE
CURRENT
TIME
FAULT
CURRENT
PICKUP
50 – Instantaneous OC
Instantaneous Overcurrent (function 50)
• The instantaneous overcurrent protective element operates ...
50 – Definite Time OC
OPERATE
CURRENT
TIME
FAULT
CURRENT
PICKUP
138 kV
52
M
R
52
1
R
52
2
R
52
3
R
R
52
U
F-1
12.5 kV
480v
• We Desire 
Selectivity, 
therefore 
Instantaneous 
Protection...
51 – Time Overcurrent
OPERATE
CURRENT
TIME
FAULT
CURRENT
PICKUP
OPERATING
TIME
51 – Time Overcurrent
• Where it is desired to have more time delay before the element operates for the purpose of 
coordi...
51 – Time Dial
51 – The Coordination Problem
138 kV
52
M
R
52
1
R
52
2
R
52
3
R
R
52
U
F-1
12.5 kV
480v
F1
F3
F2
F4
Fault magnitude
• F4 ...
51 – Coordinating Time 
CURRENT
TIME
F1 F2 F3 F4PICKUP PICKUP
TIME
COORDINATION
INTERVAL
Main Feeder
Relay
Feeder 3
Relay
51 ‐ Fuses
• The time verses current characteristics of a fuse
has two curves.
• The first curve is called the minimum mel...
51 – Coordinating Fuses
Load
Primary
Secondary
LoadSecondary
2I
1I 1I
Time
Current
• The operating time of a fuse is a fun...
51 – Coordinating Fuses & Relays
Current
Time
Minimum TCI time of
0.4s
Time Over Current Curve
Fuse curve
• The time overc...
51 – Coordinating Relays
• The following is recommended TCI to ensure proper coordination.
0 1000 2000 3000 4000
0
0.5
1
1...
51 – Reset Curves
• Reset of Time Overcurrent Element
• There are (2) different types of resets within Time Overcurrent Pr...
51 ‐ Custom                                 Curves
• Microprocessor 
Relays Allow You 
to Design Your 
Own Curves
67 – Directional Overcurrent
• In Loop‐Fed 
Systems, it is 
Desirable to 
Have Different 
Trip Times for 
Forward and 
Rev...
67 – How it Works
(a) To determine the direction of
current we need a reference
voltage or current that will not
change di...
67 – Transmission Line Angle
• Conductors (Trans. Line) mostly inductive.
• Load is heavily resistive.
Rload
Xline
Rload >...
67 – Transmission Line Angle
• Normal Current lags Voltage by small amount
• Fault Current lags Voltage by large amount.
V...
67 –V & I During 3Ø Forward 
Directional Fault
• Prefault, Balanced Voltages and Currents
• Fault, Balanced Voltages and C...
67 –V & I During 3Ø Reverse 
Directional Fault
• Prefault, Balanced Voltages and Currents
• Fault, Balanced Voltages and C...
67 – Electromechanical Directional 
Characteristic
Va
Vb
Vc
Ia
Ic
Ib
VabVca
Vbc
Va
3Ø forward fault at
60 degree line angl...
67 – Microprocessor Characteristic
79 – Reclosing Relay
• Not all Faults Are Permanent
– Most Industrial Facilities Use Insulated Cable, 
Which Results in Pe...
79 – Reclosing Relay
• Automatically reclose a circuit breaker or recloser which has been tripped by protective 
relaying ...
79 – Reclosing & Fuses
52
R
• Two methods:
• Fuse blowing
• Fuse blows for any fault, including temporary fault
• Fuse sav...
79 – Fuse Blowing
CURRENT
TIME
FAULT
TCI
> 0.4s typical
Fuse
Feeder
Relay
79 – Fuse Saving
CURRENT
TIME
FAULT
TCI
> 0.4s typical
Feeder
Relay
Inst active on
first reclose shot
only
Fuse
INST
PICKU...
81U – Frequency Protection
• Often Applied to Feeder for Load Shedding 
Purposes
– If system frequency is collapsing, this...
81O – Frequency Protection
• Often Applied to Feeder for Automatic Load 
Restoration after Load Shed Event
– Once Frequenc...
25 – Synchronism Check
• Synchronism check function is intended for 
supervising the paralleling or connection of 
two par...
• Phase instantaneous and
time-delayed overcurrent
is used.
• Ground instantaneous
overcurrent is used.
• Optionally, grou...
Typical Utility Feeder CB
• Phase and ground
overcurrent protection
with multi-shot
reclosing relay is used.
• Both instan...
Typical Medium Voltage Incoming 
Main Protection
Benefits of Microprocessor Relays
Motor Protection
• The Following ANSI Device Numbers Are 
Used for Motor Protection:
– 50 – Instantaneous Overcurrent
– 87...
50 – Short Circuit Protection
• The short circuit element provides
protection for excessively high overcurrent
faults
• Ph...
87 – Differential Protection
• If sufficient margin 
between starting 
current and short 
circuit value doesn’t 
exist, di...
87 – Differential Protection
• In cases where 
conductors are too 
large, or window 
CT can not be 
mounted core 
balance ...
50G – Ground Fault Protection
• Many Industrial 
Plants use High 
Resistance Ground 
Schemes
• Need sensitivity, 
should u...
50G – Ground Fault Protection
• Not always possible to 
use Zero Sequence CT
• Use Residual 
Connection
• Acceptable for S...
49 – Thermal Protection
• Different then typical overcurrent characteristic. 
• Takes into account cooling characteristics...
A motor can run overloaded without a fault in motor or supply
A primary motor protective element of the motor protection r...
49 - Motor Thermal Limit Curves
Thermal Limit Curves:
B. Hot Running Overload
B
A. Cold Running Overload
A
D. Hot Locked R...
49 - Thermal Overload Pickup
• Set to the maximum allowed by
the service factor of the motor.
• Set slightly above the mot...
• Thermal Capacity Used (TCU) is a criterion selected in thermal model
to evaluate thermal condition of the motor.
• TCU i...
Overload Curve
Set the overload curve below cold thermal limit and above hot thermal limit
If only hot curve is provided b...
If the motor starting
current begins to
infringe on the thermal
damage curves or if the
motor is called upon to
drive a hi...
49 - Overload Curve Selection
A custom overload curve
will allow the user to
tailor the relay’s thermal
damage curve to th...
49 - Current Unbalance Bias
Negative sequence currents (or unbalanced phase currents) will cause
additional rotor heating ...
49 - Current Unbalance Bias
• Equivalent heating motor current is employed to bias thermal model in
response to current un...
Thermal Model - Motor Cooling
• Motor cooling is characterized by separate cooling time constants
(CTC) for running and st...
46 - Unbalance Protection
• Indication of unbalance  negative sequence current / voltage
• Unbalance causes motor stress ...
27 – Undervoltage Protection
• The overall result of an undervoltage condition is an increase
in current and motor heating...
59 – Overvoltage Protection
• The overall result of an overvoltage condition is a
decrease in load current and poor power ...
37 – Undercurrent
• Many times, it is desirable to protect the 
equipment driven by a motor
• In the case of a pump, for e...
66 – Jogging Protection
• Starting a motor multiple times in rapid 
succession is bad for the motor
• Starts/Hour limits c...
Typical Low Value MV Motor 
Protection Package
Typical High Value MV Motor 
Protection Package
Transformer Protection
• The Following ANSI Device Numbers Are 
Used for Transformer Protection:
– 50 – Instantaneous Over...
Size Matters
• Small 500 to 10,000 kVA
• Medium 10,000 kVA to 100 MVA
• Large 100 MVA and above
• Less than 500kVA not con...
Transformer Zones of Protection
Phase
Fault
Ground
Fault
Breaker
Failure
Phase
Fault
Ground Fault
Breaker
Failure
Overexci...
50/51 Protection
• Characteristics Similar to What Was Discussed 
for Feeder Protection
• Instantaneous Protection Applied...
87T – Transformer Differential
• Similar to Machine Differential, but Special 
Considerations
• Need to Compensate for Pha...
Basic Transformer Connections
Transformer Phase Shifts
• H1 (A) leads X1 (a) by 30
• Currents on “H” bushings are
line-to-line quantities
• Subtract fro...
87 – EM Relays
87T – Microprocessor Relay
* *
* *
D/Y30
WYE connectionWYE connection
T60
Compensation Performed Internally By Relay
• Pick up set to 0.05 to 0.1 pu (based on phase CT primary)
• Slope 1 for “normal” errors:  10%
• Break 1 at IEEE calculat...
87T ‐ Through Current: Perfect Waves
0
-4
+4
4 pu
87
0 2 4 6 8 10
2
4
6
8
10
BA
A
IR
= Max [I1
or I2
]
ID = I1 + I2
B
TRIP...
87T ‐ Through Current: Imperfect Waves
0
-4
+4
4 pu
87
0 2 4 6 8 10
2
4
6
8
10
C
A
A
IR
= Max [I1
or I2
]
ID
= I1
+ I2
B
B...
87T ‐ Internal Fault: Perfect Waves
0
-4
+4
4 pu
87
0 2 4 6 8 10
2
4
6
8
10
BA
A
IR
= Max [I1
or I2
]
ID
= I1
+ I2
B
TRIP
...
87T ‐ Internal Fault: Imperfect Waves
0
-4
+4
4 pu
87
0 2 4 6 8 10
2
4
6
8
10
A B
A
IR
= Max [I1
or I2
]
ID = I1 + I2
B
TR...
87T ‐ Inrush Detection
• Inrush Detection and Restraint
– 2nd harmonic restraint has been employed 
for years
– “Gap” dete...
• When a transformer is energized, inrush current can be as high as 10 x FLC of 
the transformer
• Inrush lasts for only a...
Traditional 2nd Harmonic
> Responds to the RATIO of magnitudes of 2nd Harmonic and
Fundamental Frequency Components
> Typi...
CT Saturation & Inrush Restraint
CT Saturation & Inrush Restraint
Igd, pu
I= max( IR1, IR2,IR0 ), pu
Min. PKP
S lope
 Fast detection of winding ground faults
 Very secure performance on ...
87TG ‐ Improved Ground Fault Sensitivity
IG
IA
IB
IC
IG
IA
IB
IC
Internal External
63 – Pressure Devices
• Two Main Types:
– Sudden Pressure Relay – Applied to transformers 
without a Conservator Tank, use...
63 – Transformer with Conservator
63 – Transformer w/o Conservator
SUDDEN PRESSURE
RELAY
CHANGE PRESSURE RELIEF
DEVICE
63 - Sudden Pressure Relay (SPR)
•The SPR detects excessive rates of p...
63 - Buchholtz Relay
•Used on conservator type oil preservation systems
as a protective device that senses gas accumulatio...
59/81 – Volts/Hertz Protection
–Protects against overfluxing
• Excessive v/Hz
–Constant operational limits
• ANSI C37.106 ...
59/81 – Overexcitation Causes
• Transmission Systems that Supply Distribution Substations
– High voltage from Generating P...
59/81 – Example of Overexcitation
60 MVAR
30 MVAR
30 MVAR
Caps ON When They Should Be Off
Medium Power Transformer
87
T
50
51
51
G
High Side Low Side
ANSI / IEEEC37.91
“Guide for Protective Relay Applications
for...
Large Power Transformer
One Line Examples
M M
ST1
Other Loads
S1
SB1
MM M
S2
SB2
ST2
Tie Breaker
Microprocessor Benefits –
Redundancy/Reduction In Device Count
One Relay, 6 different independent CT input ratios
CB1
CB5C...
Microprocessor Benefits – Complete Small 
Sub Protection with Minimal Devices
87T
50/51
F3*
50/51
F4*
50/51
F1*
50/51
F2*
...
Microprocessor Benefits – Separate Control 
Not Required
Thank You
Suhag Patel
suhag.patel@ge.com
562‐233‐1371
Fundamentals of Microprocessor Based Relays
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Fundamentals of Microprocessor Based Relays

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Fundamentals of Microprocessor Based Relays

  1. 1. Fundamentals of Microprocessor  Based Protective Relays Suhag Patel, P.E. Industrial Electric Machinery Carson, CA IEEE Industrial & Commercial Power Systems Conference Newport Beach, CA May 5, 2011
  2. 2. Objective • Understand Commonly Used Protective  Functions and Their ANSI Protective Device  Numbers • Understand Protection is Based on Power  System Component • Advantages of Grouping Protective Relay  Functions in a Microprocessor Relay
  3. 3. ANSI Function Number • Used to Easily Convey Information on  Electrical Drawings • Function Will Have a Number and Sometimes  letter(s) • Examples: – 50N – 67P
  4. 4. ANSI Function Numbers – Partial  Listing
  5. 5. Feeder Protection • The Following ANSI Device Numbers Are  Used for Feeder Protection: – 50 – Instantaneous Overcurrent – 51 – Time Overcurrent – 67 – Directional Overcurrent – 79 – Reclosing Relay – 81O/U – Under/Over Frequency – 25 – Synchronism Check
  6. 6. Interrupting Methods • Fuse  Fusible element melts to disconnect faulty zone/equipment  I2T law • Recloser  Single or three-phase, 15 to 38kV  Line or substation • Circuit Breaker • Indoor switchgear • Outdoor breaker or switchgear • Air, Oil, SF6, Vacuum, Magnetic blast
  7. 7. 50 – Instantaneous OC OPERATE CURRENT TIME FAULT CURRENT PICKUP
  8. 8. 50 – Instantaneous OC Instantaneous Overcurrent (function 50) • The instantaneous overcurrent protective element operates with no intentional time delay when the current has exceeded the relay setting • There is a pickup setting. • 50P – phase inst. overcurrent. Pickup usually set at 25% higher than the maximum current seen by the relay for a three-phase fault at the end of the circuit. • 50N – neutral inst. overcurrent (The phasor summation of phase currents Ia, Ib, Ic equals In) • 50G – ground inst. overcurrent – low pickup setting (Uses separate or zero sequence CT)
  9. 9. 50 – Definite Time OC OPERATE CURRENT TIME FAULT CURRENT PICKUP
  10. 10. 138 kV 52 M R 52 1 R 52 2 R 52 3 R R 52 U F-1 12.5 kV 480v • We Desire  Selectivity,  therefore  Instantaneous  Protection Alone is  not Sufficient • Definite Time does  not Replicate Real  Equipment Damage  Curves 50 – Instantaneous OC
  11. 11. 51 – Time Overcurrent OPERATE CURRENT TIME FAULT CURRENT PICKUP OPERATING TIME
  12. 12. 51 – Time Overcurrent • Where it is desired to have more time delay before the element operates for the purpose of  coordinating with other protective relays or devices, the time overcurrent protective element is  used.  The trip time varies inversely with current magnitude.  • Characteristic curves most commonly used are called “inverse,””very inverse,” and “extremely  inverse.”  The user must select the curve type.  They are said to be a family of curves and selected  by the time dial.   • Curve type and time dial are separate settings. Time dial adjusts the time delay of the characteristic  to achieve coordination between downstream and upstream overcurrent devices. • There is a minimum pickup setting.  The pickup setting should be chosen such that the protective  device will be operating on the most inverse part of its time curve over the range of current for  which must operate.  • 51P – phase time overcurrent • 51N – neutral time overcurrent  (The phasor summation of phase currents Ia, Ib, Ic equals In)  • 51G – ground time overcurrent  ‐ low pickup setting  (uses separate or zero sequence CT)
  13. 13. 51 – Time Dial
  14. 14. 51 – The Coordination Problem 138 kV 52 M R 52 1 R 52 2 R 52 3 R R 52 U F-1 12.5 kV 480v F1 F3 F2 F4 Fault magnitude • F4 > F3 > F2 > F1 Why? • Impedance
  15. 15. 51 – Coordinating Time  CURRENT TIME F1 F2 F3 F4PICKUP PICKUP TIME COORDINATION INTERVAL Main Feeder Relay Feeder 3 Relay
  16. 16. 51 ‐ Fuses • The time verses current characteristics of a fuse has two curves. • The first curve is called the minimum melt curve • The minimum melt curve is the time between the initiation of a current large enough to cause the fusible element(s) to melt and the instant when arcing occurs. • The second curve is called the total clearing time. • The total clearing time is the total time elapsing from the beginning of an overcurrent to the final circuit interruption. • The time current characteristic curve of a fuse follows a I2T characteristic - that is to say as the current goes up, the time drops by the square of the current increase. Total clearing time curve Minimum melt Current Time
  17. 17. 51 – Coordinating Fuses Load Primary Secondary LoadSecondary 2I 1I 1I Time Current • The operating time of a fuse is a function of the pre-arcing (melting) and arcing time • For proper coordination, total I2T of secondary fuse shouldn’t exceed the pre-arcing (melting) of primary fuse. This is established if current ratio of primary vs. secondary fuse current rating is 2 or greater for fuses of the same type.
  18. 18. 51 – Coordinating Fuses & Relays Current Time Minimum TCI time of 0.4s Time Over Current Curve Fuse curve • The time overcurrent relay should back up the fuse over full current range. The time overcurrent relay characteristic curve best suited for coordination with fuses is the Extremely Inverse, which is similar to the I2t fuse curves. For Extremely Inverse relay curves, primary pickup current setting should be 3-times fuse rating. For other relay curves, up to 4- times fuse rating should be considered. Ensure no cross over of fuse or time overcurrent relay curves. • To account for CT saturation and errors, electro-mechanical relay overshoot, timing errors and fuse errors a minimum TCI of 0.4s should be used.
  19. 19. 51 – Coordinating Relays • The following is recommended TCI to ensure proper coordination. 0 1000 2000 3000 4000 0 0.5 1 1.5 2 2.5 3 Fault current at 11 kV Timetooperate(s) 0.4 s between relay and fuse 0.3 s between digital relays
  20. 20. 51 – Reset Curves • Reset of Time Overcurrent Element • There are (2) different types of resets within Time Overcurrent Protection: • EM or Timed Delay Reset – this mimics the disc travel of an electromechanical relay moving back to the reset position. • If the disc has not yet completely traveled back to the reset position and the time overcurrent element picks up again, the trip time will be shorter. • If the current picks up and then dropouts many times, the disc will “ratchet” itself to the operate position. • Be careful when coordinating with upstream or downstream devices. • Instantaneous Reset – once the time overcurrent element operates, it will reset immediately
  21. 21. 51 ‐ Custom                                 Curves • Microprocessor  Relays Allow You  to Design Your  Own Curves
  22. 22. 67 – Directional Overcurrent • In Loop‐Fed  Systems, it is  Desirable to  Have Different  Trip Times for  Forward and  Reverse Faults • 50/51 Is Not  Sufficient 1 5 2 4 3 A B E D C c e d a b L L L L Bus X Bus Y
  23. 23. 67 – How it Works (a) To determine the direction of current we need a reference voltage or current that will not change direction during the fault. To determine the direction of current in phase A we will use Vbc. Digital relays allow an offset from the reference voltage or current to provide better protection. (b) The protection engineer must look back into the system from the fault and determine the current fault angle (in this case a 600 lagging in current from phase Van is determined the typical fault angle).
  24. 24. 67 – Transmission Line Angle • Conductors (Trans. Line) mostly inductive. • Load is heavily resistive. Rload Xline Rload >> Xline
  25. 25. 67 – Transmission Line Angle • Normal Current lags Voltage by small amount • Fault Current lags Voltage by large amount. V I V I
  26. 26. 67 –V & I During 3Ø Forward  Directional Fault • Prefault, Balanced Voltages and Currents • Fault, Balanced Voltages and Currents, but magnitude is much different. Va Vb Vc Ia Ic Ib
  27. 27. 67 –V & I During 3Ø Reverse  Directional Fault • Prefault, Balanced Voltages and Currents • Fault, Balanced Voltages and Currents, but magnitude is much different. Va Vb Vc Ia Ic Ib Va Vb Vc Ia Ic Ib
  28. 28. 67 – Electromechanical Directional  Characteristic Va Vb Vc Ia Ic Ib VabVca Vbc Va 3Ø forward fault at 60 degree line angle Vbc Restraint Region Ia Maximum Torque Line Zero Torque Line
  29. 29. 67 – Microprocessor Characteristic
  30. 30. 79 – Reclosing Relay • Not all Faults Are Permanent – Most Industrial Facilities Use Insulated Cable,  Which Results in Permanent Faults – Utilities Often Use Non‐Insulated Overhead  Conductors, Resulting in Many Temporary Faults: • Wind Causing Conductors to Touch • Fires Temporarily Breaking Down Air
  31. 31. 79 – Reclosing Relay • Automatically reclose a circuit breaker or recloser which has been tripped by protective  relaying or recloser control • Multi‐shot reclosing for distribution circuits • Instantaneous shot (~0.25s) • Delayed reclosures (typically two delayed , for example 3s & 15s, or 15s & 30s) • Coordinate with branch fuses • After initial reclose block instantaneous overcurrent functions to allow fuse to blow • After successful reclose, the reclosing function will reset after some adjustable time delay  (typically 60s). • If the fault is permanent, the protective device will trip and reclose several times.  If  unsuccessful, the protective device will go to LOCKOUT and keep the breaker open.   Some devices have a separate reset time from lockout (for example 10s after the breaker  is manually closed).   
  32. 32. 79 – Reclosing & Fuses 52 R • Two methods: • Fuse blowing • Fuse blows for any fault, including temporary fault • Fuse saving • Use automatic reclosing to try and save fuses for temporary faults
  33. 33. 79 – Fuse Blowing CURRENT TIME FAULT TCI > 0.4s typical Fuse Feeder Relay
  34. 34. 79 – Fuse Saving CURRENT TIME FAULT TCI > 0.4s typical Feeder Relay Inst active on first reclose shot only Fuse INST PICKUP Inverse time only after first reclose shot
  35. 35. 81U – Frequency Protection • Often Applied to Feeder for Load Shedding  Purposes – If system frequency is collapsing, this indicates a  load‐generation imbalance.  – Some feeders are designed to trip offline after  frequency decays beyond a specific level, i.e. 59.8  Hz with 2S delay and 59.5 Hz no time delay
  36. 36. 81O – Frequency Protection • Often Applied to Feeder for Automatic Load  Restoration after Load Shed Event – Once Frequency is above nominal for some time,  feeder breaker is closed, restoring service back to  load • Frequency Elements typically work by  measuring Zero Crossings of Voltage/Current
  37. 37. 25 – Synchronism Check • Synchronism check function is intended for  supervising the paralleling or connection of  two parts of a system which are to be joined  by the closure of a circuit breaker.  • Synchrocheck verifies that voltages (V1 and  V2) on the two sides of the supervised circuit  breaker are within set limits of magnitude,  angle and frequency differences. • V1 is typically acquired using 2 or 3 potential  transformers • V2 is typically a signal phase potential  transformer measuring a phase‐to‐phase  voltage, such as Vab or Vbc G Industrial Utility
  38. 38. • Phase instantaneous and time-delayed overcurrent is used. • Ground instantaneous overcurrent is used. • Optionally, ground time- delayed overcurrent is used Typical Industrial Feeder CB
  39. 39. Typical Utility Feeder CB • Phase and ground overcurrent protection with multi-shot reclosing relay is used. • Both instantaneous and time-delayed overcurrent are used. • Reclosing is Often Included for Overhead Lines 79
  40. 40. Typical Medium Voltage Incoming  Main Protection
  41. 41. Benefits of Microprocessor Relays
  42. 42. Motor Protection • The Following ANSI Device Numbers Are  Used for Motor Protection: – 50 – Instantaneous Overcurrent – 87M – Machine Differential – 49 – Thermal Protection – 46 – Current Unbalance Protection – 27/59 – Under/Over Voltage – 37 – Undercurrent – 66 – Jogging
  43. 43. 50 – Short Circuit Protection • The short circuit element provides protection for excessively high overcurrent faults • Phase-to-phase and phase-to-ground faults are common types of short circuits • To avoid nuisance tripping during starting, set the the short circuit protection pick up to a value at least 1.7 times the maximum expected symmetrical starting current of motor. • The breaker or contactor must have an interrupting capacity equal to or greater then the maximum available fault current or let an upstream protective device interrupt fault current.
  44. 44. 87 – Differential Protection • If sufficient margin  between starting  current and short  circuit value doesn’t  exist, differential  protection is required. • Core Balance CT  Connection Is  Preferred
  45. 45. 87 – Differential Protection • In cases where  conductors are too  large, or window  CT can not be  mounted core  balance  connection can  not be used
  46. 46. 50G – Ground Fault Protection • Many Industrial  Plants use High  Resistance Ground  Schemes • Need sensitivity,  should use Zero  Sequence CT
  47. 47. 50G – Ground Fault Protection • Not always possible to  use Zero Sequence CT • Use Residual  Connection • Acceptable for Solidly  Grounded System,  requires delay for HRG  Scheme
  48. 48. 49 – Thermal Protection • Different then typical overcurrent characteristic.  • Takes into account cooling characteristics of the motor.  • Can also use physically measured temperatures (RTD) • Very sophisticated, primary element that makes a motor  relay a motor relay
  49. 49. A motor can run overloaded without a fault in motor or supply A primary motor protective element of the motor protection relay is the thermal overload element and this is accomplished through motor thermal image modeling. This model must account for thermal process in the motor while motor is starting, running at normal load, running overloaded and stopped. Algorithm of the thermal model integrates both stator and rotor heating into a single model. • Main Factors and Elements Comprising the Thermal Model are: • Overload Pickup Level • Overload Curve • Running & Stopped Cooling Time Constants • Hot/Cold Stall Time Ratio • RTD & Unbalance Biasing • Motor State Machine 49 – Overload Protection
  50. 50. 49 - Motor Thermal Limit Curves Thermal Limit Curves: B. Hot Running Overload B A. Cold Running Overload A D. Hot Locked Rotor CurveD C C. Cold Locked Rotor Curve F. Acceleration curve @100% voltage F E. Acceleration curve @ 80% rated voltageE • Thermal Limit of the model is dictated by overload curve constructed in the motor protection device in the reference to thermal damage curves normally supplied by motor manufacturer. • Motor protection device is equipped with set of standard curves and capable to construct customized curves for any motor application.
  51. 51. 49 - Thermal Overload Pickup • Set to the maximum allowed by the service factor of the motor. • Set slightly above the motor service factor by 8-10% to account for measuring errors • If RTD Biasing of Thermal Model is used, thermal overload setting can be set higher • Note: motor feeder cables are normally sized at 1.25 times motor’s full load current rating, which would limit the motor overload pickup setting to a maximum of 125%. SF Thermal Overload Pickup 1.0 1.1 1.15 1.25
  52. 52. • Thermal Capacity Used (TCU) is a criterion selected in thermal model to evaluate thermal condition of the motor. • TCU is defined as percentage of motor thermal limit utilized during motor operation. • A running motor will have some level of thermal capacity used due to Motor Losses. • Thermal Trip when Thermal Capacity Used equals 100% 49 – Thermal Capacity Used
  53. 53. Overload Curve Set the overload curve below cold thermal limit and above hot thermal limit If only hot curve is provided by mfgr, then must set below hot thermal limit 49 - Overload Curve Selection
  54. 54. If the motor starting current begins to infringe on the thermal damage curves or if the motor is called upon to drive a high inertia load such that the acceleration time exceeds the safe stall time, custom or voltage dependent overload curve may be required. 49 - Overload Curve Selection
  55. 55. 49 - Overload Curve Selection A custom overload curve will allow the user to tailor the relay’s thermal damage curve to the motor such that a successful start can occur without compromising protection while at the same time utilizing the motor to its full potential during the running condition.
  56. 56. 49 - Current Unbalance Bias Negative sequence currents (or unbalanced phase currents) will cause additional rotor heating that will be accounted for in Thermal Model. Positive Sequence Negative Sequence • Main causes of current unbalance • Blown fuses • Loose connections • Stator turn-to-turn faults • System voltage distortion and unbalance • Faults
  57. 57. 49 - Current Unbalance Bias • Equivalent heating motor current is employed to bias thermal model in response to current unbalance. • Im - real motor current; K - unbalance bias factor; I1 & I2 - positive and negative sequence components of motor current. • K factor reflects the degree of extra heating caused by the negative sequence component of the motor current. • IEEE guidelines for typical and conservative estimates of K.
  58. 58. Thermal Model - Motor Cooling • Motor cooling is characterized by separate cooling time constants (CTC) for running and stopped motor states. Typical ratio of the stopped to running CTC is 2/1 • It takes the motor typically 5 time constants to cool. Thermal Model Cooling100% load - Running Thermal Model Cooling Motor Tripped
  59. 59. 46 - Unbalance Protection • Indication of unbalance  negative sequence current / voltage • Unbalance causes motor stress and temperature rise • Current unbalance in a motor is result of unequal line voltages • Unbalanced supply, blown fuse, single-phasing • Current unbalance can also be present due to: • Loose or bad connections • Incorrect phase rotation connection • Stator turn-to-turn faults • For a typical three-phase induction motor: • 1% voltage unbalance (V2) relates to 6% current unbalance (I2) • For small and medium sized motors, only current transformers (CTs) are available and no voltage transformers (VTs). Measure current unbalance and protect motor. • The heating effect caused by current unbalance will be protected by enabling the unbalance input to the thermal model • For example, a setting of 10% x FLA for the current unbalance alarm with a delay of 10 seconds and a trip level setting of 25% x FLA for the current unbalance trip with a delay of 5 seconds would be appropriate. Motor Relay
  60. 60. 27 – Undervoltage Protection • The overall result of an undervoltage condition is an increase in current and motor heating and a reduction in overall motor performance. • The undervoltage protection element can be thought of as backup protection for the thermal overload element. In some cases, if an undervoltage condition exists it may be desirable to trip the motor faster than thermal overload element. • The undervoltage trip should be set to 90% of nameplate unless otherwise stated on the motor data sheets. • Motors that are connected to the same source/bus may experience a temporary undervoltage, when one of motors starts. To override this temporary voltage sags, a time delay setpoint should be set greater than the motor starting time.
  61. 61. 59 – Overvoltage Protection • The overall result of an overvoltage condition is a decrease in load current and poor power factor. • Although old motors had robust design, new motors are designed close to saturation point for better utilization of core materials and increasing the V/Hz ratio cause saturation of air gap flux leading to motor heating. • The overvoltage element should be set to 110% of the motors nameplate unless otherwise started in the data sheets.
  62. 62. 37 – Undercurrent • Many times, it is desirable to protect the  equipment driven by a motor • In the case of a pump, for example, a sudden  loss of load indicates a problem with the  pump • This condition won’t damage the motor but is  catastrophic to the pump
  63. 63. 66 – Jogging Protection • Starting a motor multiple times in rapid  succession is bad for the motor • Starts/Hour limits can be applied • Time Between Starts can also be applied
  64. 64. Typical Low Value MV Motor  Protection Package
  65. 65. Typical High Value MV Motor  Protection Package
  66. 66. Transformer Protection • The Following ANSI Device Numbers Are  Used for Transformer Protection: – 50 – Instantaneous Overcurrent – 51 – Time Overcurrent – 87T – Main Transformer Differential – 87RGF – Ground Differential  – 63 – Sudden Pressure – 59/81 – Volts Per Hertz
  67. 67. Size Matters • Small 500 to 10,000 kVA • Medium 10,000 kVA to 100 MVA • Large 100 MVA and above • Less than 500kVA not considered a power transformer • Our Discussion is mainly applicable to Medium and Large  Power Transformers
  68. 68. Transformer Zones of Protection Phase Fault Ground Fault Breaker Failure Phase Fault Ground Fault Breaker Failure Overexcitation Undervoltage Underfrequency Overload
  69. 69. 50/51 Protection • Characteristics Similar to What Was Discussed  for Feeder Protection • Instantaneous Protection Applied on the High  Side for Internal Fault Backup Protection • Time Overcurrent Protection Applied on the  High Side for Overload Protection • Low Side TOC Protection Applied for  Bus/Feeder Backup Protection
  70. 70. 87T – Transformer Differential • Similar to Machine Differential, but Special  Considerations • Need to Compensate for Phase & Magnitude  Shifts As Well as CT Ratio Differences • Need to Include Inrush Restraint Algorithm • Microprocessor Much Less Complicated then  EM Relays
  71. 71. Basic Transformer Connections
  72. 72. Transformer Phase Shifts • H1 (A) leads X1 (a) by 30 • Currents on “H” bushings are line-to-line quantities • Subtract from reference phase vector the connected non-polarity vector HV LV H1 H2 H3 X1 X3 X2 A B C a b c a b c A B C Assume 1:1 transformer
  73. 73. 87 – EM Relays
  74. 74. 87T – Microprocessor Relay * * * * D/Y30 WYE connectionWYE connection T60 Compensation Performed Internally By Relay
  75. 75. • Pick up set to 0.05 to 0.1 pu (based on phase CT primary) • Slope 1 for “normal” errors:  10% • Break 1 at IEEE calculated worse case remnance point (assume 80% flux) • Break 2 at 5X times Break 1 (assume no DC offset) • Slope 2 for large errors: 50‐80% ID = I1 + I2 IR = Max [I1 or I2 ] 87T ‐ Differential Characteristic
  76. 76. 87T ‐ Through Current: Perfect Waves 0 -4 +4 4 pu 87 0 2 4 6 8 10 2 4 6 8 10 BA A IR = Max [I1 or I2 ] ID = I1 + I2 B TRIP RESTRAIN
  77. 77. 87T ‐ Through Current: Imperfect Waves 0 -4 +4 4 pu 87 0 2 4 6 8 10 2 4 6 8 10 C A A IR = Max [I1 or I2 ] ID = I1 + I2 B B (2, -4) (0,0) (1, -3) C TRIP RESTRAIN
  78. 78. 87T ‐ Internal Fault: Perfect Waves 0 -4 +4 4 pu 87 0 2 4 6 8 10 2 4 6 8 10 BA A IR = Max [I1 or I2 ] ID = I1 + I2 B TRIP RESTRAIN 4 pu
  79. 79. 87T ‐ Internal Fault: Imperfect Waves 0 -4 +4 4 pu 87 0 2 4 6 8 10 2 4 6 8 10 A B A IR = Max [I1 or I2 ] ID = I1 + I2 B TRIP RESTRAIN 4 pu (4, 1.5)
  80. 80. 87T ‐ Inrush Detection • Inrush Detection and Restraint – 2nd harmonic restraint has been employed  for years – “Gap” detection has also been employed – As transformers are designed to closer  tolerances, the incidence of both 2nd harmonic and low current gaps in waveform  have decreased – If 2nd harmonic restraint level is set too low,  differential element may be blocked for  internal fault due to generated harmonics
  81. 81. • When a transformer is energized, inrush current can be as high as 10 x FLC of  the transformer • Inrush lasts for only a few cycles but can cause the differential element to  operate because it has the appearance of an internal fault (current flows into  but not out of the unloaded transformer  • Predominantly 2nd harmonic • 2nd harmonic restraint is used to prevent misoperation of differential  element during inrush. Transformer Magnetizing Inrush Current
  82. 82. Traditional 2nd Harmonic > Responds to the RATIO of magnitudes of 2nd Harmonic and Fundamental Frequency Components > Typical setting is 15-20% (dependent on transformer construction) Adaptive 2nd Harmonic > Responds to both Magnitudes and Phase Angles of 2nd Harmonic and Fundamental Frequency Component > Use on transformers experiencing lower than normal 2nd harmonic levels during magnetizing inrush conditions (say 5- 10%) 87T – Harmonic Restraint
  83. 83. CT Saturation & Inrush Restraint
  84. 84. CT Saturation & Inrush Restraint
  85. 85. Igd, pu I= max( IR1, IR2,IR0 ), pu Min. PKP S lope  Fast detection of winding ground faults  Very secure performance on external ground faults  Configurable pickup, slope, and time delay 87TG - Restricted Ground Fault Protection
  86. 86. 87TG ‐ Improved Ground Fault Sensitivity IG IA IB IC IG IA IB IC Internal External
  87. 87. 63 – Pressure Devices • Two Main Types: – Sudden Pressure Relay – Applied to transformers  without a Conservator Tank, uses pressure Rate of  Rise  – Bucholtz Relays – Applied to Transformers with a  Conservator Tank, uses accumulated gas pressure • When an Arc occurs in oil, a release of various  gasses occurs.  • Sudden Pressure Increase is Detected by Relay
  88. 88. 63 – Transformer with Conservator
  89. 89. 63 – Transformer w/o Conservator
  90. 90. SUDDEN PRESSURE RELAY CHANGE PRESSURE RELIEF DEVICE 63 - Sudden Pressure Relay (SPR) •The SPR detects excessive rates of pressure rise within the tank as result of internal arcing causing oil breakdown and subsequent gas evolution •They can operate on a change in oil or gas pressure •Using a bellows and orifice to respond to rapid differential pressure changes, they are an inverse-time characteristic •The SPR should be an input on the digital transformer relay for targeting, SOE and waveform capture
  91. 91. 63 - Buchholtz Relay •Used on conservator type oil preservation systems as a protective device that senses gas accumulation •If a low level fault results in arcing, the small amount of gas that is produced will accumulate in this relay resulting in an alarm •The SPR should be an input on the digital transformer relay for targeting, SOE and waveform capture
  92. 92. 59/81 – Volts/Hertz Protection –Protects against overfluxing • Excessive v/Hz –Constant operational limits • ANSI C37.106 & C57.12 –1.05 loaded, 1.10 unloaded • Inverse curves typically available for values over the  constant allowable maximum
  93. 93. 59/81 – Overexcitation Causes • Transmission Systems that Supply Distribution Substations – High voltage from Generating Plants – Voltage and Reactive Support Control Failures • Runaway LTCs • Capacitor banks in when they should be out • Shunt reactors out when they should be in • Near‐end breaker failures resulting in voltage rise on  line (Ferranti effect)
  94. 94. 59/81 – Example of Overexcitation 60 MVAR 30 MVAR 30 MVAR Caps ON When They Should Be Off
  95. 95. Medium Power Transformer 87 T 50 51 51 G High Side Low Side ANSI / IEEEC37.91 “Guide for Protective Relay Applications for Power Transformers”
  96. 96. Large Power Transformer
  97. 97. One Line Examples M M ST1 Other Loads S1 SB1 MM M S2 SB2 ST2 Tie Breaker
  98. 98. Microprocessor Benefits – Redundancy/Reduction In Device Count One Relay, 6 different independent CT input ratios CB1 CB5CB4CB3CB2 CB6 800:5 600:5 1000:5 1200:5 400:5 3000:5
  99. 99. Microprocessor Benefits – Complete Small  Sub Protection with Minimal Devices 87T 50/51 F3* 50/51 F4* 50/51 F1* 50/51 F2* 50/51 F3 50/51 F4 79 F3 79 F4 81 F1 W/ Var W/ Var 50/51P T 87B ** 50/51 F1 50/51 F2 79 F1 79 F2 W/ Var W/ Var 51G T LTC CTL 27B 81 F2 81 F3 81 F4 HVBUS LTC CS LVBUS F1 F2 F3 F4 3 1 T35 F35
  100. 100. Microprocessor Benefits – Separate Control  Not Required
  101. 101. Thank You Suhag Patel suhag.patel@ge.com 562‐233‐1371

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