This document provides an overview of commonly used protective relay functions and their ANSI device numbers. It discusses instantaneous overcurrent (50), time overcurrent (51), directional overcurrent (67), reclosing relay (79), and under/over frequency (81O/U) functions. It explains how these functions work, their settings, and considerations for coordination between devices to ensure selective tripping during faults. Microprocessor relays allow for customized curves and grouping of protective functions.

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. 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. ANSI Function Number
• Used to Easily Convey Information on
Electrical Drawings
• Function Will Have a Number and Sometimes
letter(s)
• Examples:
– 50N
– 67P

4. ANSI Function Numbers – Partial
Listing

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. 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. 50 – Instantaneous OC
OPERATE
CURRENT
TIME
FAULT
CURRENT
PICKUP

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. 50 – Definite Time OC
OPERATE
CURRENT
TIME
FAULT
CURRENT
PICKUP

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. 51 – Time Overcurrent
OPERATE
CURRENT
TIME
FAULT
CURRENT
PICKUP
OPERATING
TIME

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)

14. 51 – Time Dial

15. 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

16. 51 – Coordinating Time
CURRENT
TIME
F1 F2 F3 F4PICKUP PICKUP
TIME
COORDINATION
INTERVAL
Main Feeder
Relay
Feeder 3
Relay

17. 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

18. 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.

19. 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.

20. 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

21. 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

22. 51 ‐ Custom Curves
• Microprocessor
Relays Allow You
to Design Your
Own Curves

23. 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

24. 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).

25. 67 – Transmission Line Angle
• Conductors (Trans. Line) mostly inductive.
• Load is heavily resistive.
Rload
Xline
Rload >>
Xline

26. 67 – Transmission Line Angle
• Normal Current lags Voltage by small amount
• Fault Current lags Voltage by large amount.
V
I
V
I

27. 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

28. 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

29. 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

30. 67 – Microprocessor Characteristic

31. 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

32. 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).

33. 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

34. 79 – Fuse Blowing
CURRENT
TIME
FAULT
TCI
> 0.4s typical
Fuse
Feeder
Relay

35. 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

36. 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

37. 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

38. 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

39. • Phase instantaneous and
time-delayed overcurrent
is used.
• Ground instantaneous
overcurrent is used.
• Optionally, ground time-
delayed overcurrent is
used
Typical Industrial Feeder CB

40. 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

41. Typical Medium Voltage Incoming
Main Protection

42. Benefits of Microprocessor Relays

43. 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

44. 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.

45. 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

46. 87 – Differential Protection
• In cases where
conductors are too
large, or window
CT can not be
mounted core
balance
connection can
not be used

47. 50G – Ground Fault Protection
• Many Industrial
Plants use High
Resistance Ground
Schemes
• Need sensitivity,
should use Zero
Sequence CT

48. 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

49. 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

50. 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

51. 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.

52. 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

53. • 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

54. 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

55. 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

56. 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.

57. 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

58. 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.

59. 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

60. 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

61. 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.

62. 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.

63. 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

64. 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

65. Typical Low Value MV Motor
Protection Package

66. Typical High Value MV Motor
Protection Package

67. 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

68. 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

69. Transformer Zones of Protection
Phase
Fault
Ground
Fault
Breaker
Failure
Phase
Fault
Ground Fault
Breaker
Failure
Overexcitation
Undervoltage
Underfrequency
Overload

70. 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

71. 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

72. Basic Transformer Connections

73. 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

74. 87 – EM Relays

75. 87T – Microprocessor Relay
* *
* *
D/Y30
WYE connectionWYE connection
T60
Compensation Performed Internally By Relay

76. • 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

77. 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

78. 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

79. 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

80. 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)

81. 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

82. • 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

83. 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

84. CT Saturation & Inrush Restraint

85. CT Saturation & Inrush Restraint

86. 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

87. 87TG ‐ Improved Ground Fault Sensitivity
IG
IA
IB
IC
IG
IA
IB
IC
Internal External

88. 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

89. 63 – Transformer with Conservator

90. 63 – Transformer w/o Conservator

91. 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

92. 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

93. 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

94. 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)

95. 59/81 – Example of Overexcitation
60 MVAR
30 MVAR
30 MVAR
Caps ON When They Should Be Off

96. Medium Power Transformer
87
T
50
51
51
G
High Side Low Side
ANSI / IEEEC37.91
“Guide for Protective Relay Applications
for Power Transformers”

97. Large Power Transformer

98. One Line Examples
M M
ST1
Other Loads
S1
SB1
MM M
S2
SB2
ST2
Tie Breaker

99. 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

100. 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

101. Microprocessor Benefits – Separate Control
Not Required

102. Thank You
Suhag Patel
suhag.patel@ge.com
562‐233‐1371