How to setting Relay Coordination
1. Standard and Code
- NEC Article 430-32 (Continuos - Duty Motors)
- NEC Article 430-126 (Rating of Motor Control Apparatus)
- IEEE Std 141-1976, IEEE Recommended Practice for Electrical Power Distribution for Industrial Plants
- IEEE Std 242-1986, IEEE Recommended Practice for Protection and Coordination of Industrial and Commercial Power System
- IEEE C37.101-1993, IEEE Guide for AC Generator Ground Protection
- IEEE C37.102-1987, IEEE Guide for AC Generator Protection
2. Principles of Protective Relay Application
Fault protection relaying can be classified into two groups, primary relaying which should function first in removing faulted equipment from the system, and backup relaying which functions only when primary relaying fails. For complete explanation, see IEEE Std 141-1976 (IEEE Recommended Practice for Electric Power Distribution for Industrial Plants).
3. Methodology / Calculation Criteria
The study is based on the data
and parameter as defined below:
- The study is performed by Power Plot version 2.5. The Power Plot v.2.5 has provided some fixtures which used as parameter in this project as follow:
- Transformer thermal damage and inrush currentcurve
- Cable thermal damage curve
- Motor Starting Curve
- MCP & MCCB curve
- User curve
- Available 3 phase short circuit current at all relevant buses
3.1 Generator Protection
3.1.1 Generator
Data
Gas Turbine
Generator
”A/B”
|
Diesel Engine
Generator
|
|
Engine Manufacturer
|
||
Generator manufacturer
|
||
kW rating
|
1100
|
650
|
kV rating
|
0.4
|
0.4
|
PF rating
|
0.8
|
0.8
|
Frequency Rating
|
50
|
50
|
FLA Rating (A)
|
1985
|
1173
|
Reactance (unsat)
|
||
Synchronous, Xd (%)
|
103.6
|
303.42
|
Transient, X’d (%)
|
13.8
|
22.1
|
Subtransient, X”d (%)
|
11
|
15.51
|
Motoring Power (kW)
|
120
|
|
Unbalanced Capability
|
see attachment #2
|
see attachment #2
|
3.1.2 Generator
Protection
Generator protection is using
GE - Multilin SR 489. The 489 Generator Management Relay is a
microprocessor-based relay designed for the protection and management of
synchronous and induction generator.
Refer to below paragraph for
the SR489 relay setting.
3.1.3 Setpoint /
System Setup
Current
Sensing
Gas Turbine
Generator
”A/B”
|
Diesel Engine
Generator
|
|
Phase Current
|
||
Primary CT
|
2500 Amps
|
1200 Amps
|
Ground Current
|
||
Ground CT Type
|
5 A Secondary
|
5 A Secondary
|
Ground CT Ratio
|
50/5
|
50/5
|
Voltage
Sensing
Gas Turbine
Generator
”A/B”
|
Diesel Engine
Generator
|
|
Voltage Transformer
|
||
VT Connection Type
|
Open Delta
|
Open Delta
|
Transformer Ratio
|
33.3
|
33.3
|
Generator
Parameters
Gas Turbine
Generator
”A/B”
|
Diesel Engine
Generator
|
|
Generator
Rated MVA
|
1.375 MVA
|
0.812 MVA
|
Generator
Rated Power Factor
|
0.8
|
0.8
|
Generator
Voltage Phase-Phase
|
400 V
|
400 V
|
Generator
Nominal Frequency
|
50 Hz
|
50 Hz
|
Generator
Phase Sequence
|
ABC
|
ABC
|
Serial
Start/Stop Initiation
None
3.1.4 Setpoint /
Digital Input
Breaker
Status
Gas Turbine
Generator
”A/B”
|
Diesel Engine
Generator
|
|
Breaker
Status
|
Breaker Auxiliary A
|
Breaker Auxiliary A
|
General
Purpose
None
Predefined
None
Generator
Switch Status
None
3.1.5 Setpoint / Output Relay
Gas Turbine
Generator
”A/B”
|
Diesel Engine
Generator
|
|
Relay Reset Mode
|
||
R1
Trip
|
All Resets
|
All Resets
|
R2
Auxiliary
|
All Resets
|
All Resets
|
R3
Auxiliary
|
All Resets
|
All Resets
|
R4
Auxiliary
|
All Resets
|
All Resets
|
R5
Alarm
|
All Resets
|
All Resets
|
R6
Service
|
All Resets
|
All Resets
|
3.1.6 Setpoint /
Protection
3.1.6.1 Current
Element
Overcurrent Alarm
·
Consideration/formula
This feature is intended to
give the time for operator to analyze and asses the situation when
overload of generator occurred.
·
Setting
GPR for GTG
”A/B”
|
GPR for DEG
|
|
Overcurent
Alarm
|
Unlatched
|
Unlatched
|
Assign
Alarm Relay (2-5)
|
5
|
5
|
Overcurent
Alarm Level
|
1.01 x
|
1.1 x
|
Overcurent
Alarm Delay
|
3 s
|
3 s
|
Overcurent
Alarm Event
|
On
|
On
|
Offline O/C
·
Consideration/formula
This feature is active only
when generator is OFFLINE and uses the neutral measurements end CT. It is set
more sensitive than differential relay to detect high impedance phase faults.
Since the breaker auxiliary
contacts wired to the 489 Breaker Status Input may not operate at exactly the
same time as the main breaker contact, the time delay should be coordinate with
the difference of the operation times.
·
Setting
GPR for GTG
”A/B”
|
GPR for DEG
|
|
Offline
Overcurrent Trip
|
Unlatched
|
Unlatched
|
Assign
Trip Relay (1-4)
|
1, 3
|
1, 3
|
Offline
Overcurrent Pickup
|
0.05 x CT
|
0.8 x CT
|
Offline
Overcurrent Delay
|
10 Cycles
|
10 Cycles
|
Inadvertent Energize
·
Consideration/formula
This relay is intended to
protect a poor synchronizing by “U/V or Offline”.
·
Setting
GPR for GTG
”A/B”
|
GPR for DEG
|
|
Inadvertent
Energize Trip
|
Unlatched
|
Unlatched
|
Assign
Trip Relay (1-4)
|
1, 3
|
1, 3
|
Arming
Signal
|
UV and Offline
|
UV and Offline
|
Inadvertent
Energize O/C Pickup
|
0.15 x CT
|
0.15 x CT
|
Inadvertent
Energize Pickup
|
0.95 x
Rated Volt
|
0.95 x
Rated Volt
|
Phase Overcurrent
·
Consideration/formula
This relay is as backup
protection and shall be coordinated with downstream “relay” to avoid
overlapping protection. (see relay coordination case #5 & #6 on the
paragraph 4.7 & 4.8 )
·
Setting
GPR for GTG
”A/B”
|
GPR for DEG
|
|
Phase
Overcurrent Trip
|
Latched
|
Latched
|
Assign
Trip Relay (1-4)
|
1, 3
|
1, 3
|
Enable
Voltage Restraint
|
No
|
No
|
Phase
Overcurrent Pickup
|
2 x CT
|
1.4 x CT
|
Curve
Shape
|
Definite Time
|
Definite Time
|
Overcurrent
Curve Multiplier
|
2
|
2
|
Overcurrent
Curve Reset
|
Instantaneous
|
Instantaneous
|
Negative Sequence
·
Consideration/formula
The relay should be set to
lower than I22t limit of the generator being protected.
The actual generator unbalance current capability shall be plotted in the
common scale (Log-Log) and then the relay (constant K) can be adjusted to get optimum setting of this relay
·
Setting
GPR for GTG
”A/B”
|
GPR for DEG
|
|
Negative Sequence Alarm
|
Latched
|
Latched
|
Assign Alarm Relay (2-5)
|
5
|
5
|
Neg. Sequence Alarm
Pick-up
|
5%
|
5%
|
Negative Sequence
Alarm Delay
|
5 s
|
5 s
|
Negative Sequence
Alarm Event
|
On
|
On
|
Negative Sequence O/C
Trip
|
Latched
|
Latched
|
Assign Trip Relay
(1-4)
|
1, 3
|
1, 3
|
Neg. Sequence Trip
Pick-up
|
20%
|
20%
|
Neg. Sequence O/C
Constant K
|
5
|
5
|
Neg. Sequence O/C
Max. Time
|
125 s
|
125 s
|
Neg. Sequence O/C
Reset Rate
|
150 s
|
150 s
|
Ground O/C
The ground O/C protection is
not used since generator is grounded through a ground fault neutralizer (HRG
device) to operate alarm and to give the time for operator to analyze and asses
the situation and tripping will be delayed as long as an hour or two to permit
fault insulation.
Phase Differential
·
Consideration/formula
·
Setting
GPR for GTG
”A/B”
|
GPR for DEG
|
|
Phase
Differential Trip
|
Unlatched
|
Unlatched
|
Assign
Trip (1-4)
|
1, 2, 3
|
1, 2, 3
|
Differential
Trip Min Pick-up
|
0.1 x CT
|
0.1 x CT
|
Differential
Trip Slope 1
|
10%
|
10%
|
Differential
Trip Slope 2
|
20%
|
20%
|
Differential
Trip Delay
|
10 cycles
|
10 cycles
|
Ground Directional
Not applicable since the 59N
is not used in this project.
High-set Phase O/C
·
Consideration/formula
This element
can be used as back-up feature to overcurrent. It is set above the maximum current
contribution from generator when parallel operation.
The maximum
current contribution from GTG and DEG to the fault are 18.7kA &
10.8kA.
·
Setting
GPR for GTG
”A/B”
|
GPR for DEG
|
|
High-Set
Phase O/C Trip
|
Unlatched
|
Unlatched
|
Assign
Trip (1-4)
|
1, 3
|
1, 3
|
High-Set
Phase O/C Pickup
|
2.2 x CT
|
1.6 x CT
|
High-Set
Phase O/C Delay
|
0.6s
|
0.6s
|
3.1.6.2 Voltage
Element
Undervoltage
·
Consideration/formula
Refer to General Electrical
Design Specification PS-1100-ELE-001 voltage drop on the bus max. drop 6% at steady state condition and 15% at transient
condition.
·
Setting
GPR for GTG
1147-GTG-600”A/B”
|
GPR for DEG
1147-DEG-620
|
|
Undervoltage
Alarm
|
Unlatched
|
Unlatched
|
Assign
Alarm Relays (2-5)
|
5
|
5
|
Undervoltage
Alarm Pickup
|
0.87 x Rated
|
0.87 x Rated
|
Undervoltage
Alarm Delay
|
2.3 s
|
2.3 s
|
Undervoltage
Trip
|
Latched
|
Latched
|
Assign
Trip Relays (1-4)
|
1,3
|
1,3
|
Undervoltage
Trip Pickup
|
0.85 x Rated
|
0.85 x Rated
|
Undervoltage
Trip Delay
|
2 s
|
2 s
|
Undervoltage
Curve Reset Rate
|
3 s
|
3 s
|
Undervoltage
Curve Element
|
Curve
|
Curve
|
Overvoltage
·
Consideration/formula
Generator overvoltage may
occur without necessarily exceeding the volts/Hz limits of the machine. In
general, this not problem with steam and gas turbine generators because of the
rapid response of the speed-control system and voltage regulator.
The instantaneous unit is
generally set to pickup at about 130% - 150% of nominal voltage (see IEE
C17.102-1987).
·
Setting
GPR for GTG
1147-GTG-600”A/B”
|
GPR for DEG
1147-DEG-620
|
|
Overvoltage
Alarm
|
Unlatched
|
Unlatched
|
Assign
Alarm Relays (2-5)
|
5
|
5
|
Overvoltage
Alarm Pickup
|
1.05 x rated
|
1.05 x rated
|
Overvoltage
Alarm Delay
|
2 s
|
2 s
|
Overvoltage
Trip
|
Latched
|
Latched
|
Assign
Trip Relays (1-4)
|
1,3
|
1,3
|
Overvoltage
Trip Pickup
|
1.1 x rated
|
1.1 x rated
|
Overvoltage
Trip Delay
|
1 s
|
1 s
|
Overvoltage
Curve Reset Rate
|
3 s
|
3 s
|
Overvoltage
Curve Element
|
Curve
|
Curve
|
Volt / Hertz
Not applicable since it is used for protection integral generator and
transformer
Phase Reversal
·
Consideration/formula
This feature is intended to
protect phase rotation.
·
Setting
GPR for GTG
1147-GTG-600”A/B”
|
GPR for DEG
1147-DEG-620
|
|
Phase
Reversal Trip
|
Latched
|
Latched
|
Assign
Trip Relays (1-4)
|
1, 3
|
1, 3
|
Underfrequency
Not applicable since using individual Relay 81 for underfrequency detection
Overfrequency
None
Neutral O/V (Fund.)
Not applicable since no detection device
Neutral U/V (3rd)
Not applicable since no detection device
Loss of Excitation
·
Consideration/formula
A. Loss
of excitation setting for Gas Turbine Generator (GTG)
= 16.02 W
X’d (sec) = Zbase x X’dpu
= 16.02
x 0.138 = 2.21 secondary ohms
Xd (sec) = Zbase x Xdpu
= 16.02
x 1.036 = 16.59 secondary ohms
\
Diameter = 
= 16.59 W
= 16.59 W
B. Loss of excitation
setting for Diesel Engine Generator (DEG)
·
Setting
GPR for GTG
1147-GTG-600”A/B”
|
GPR for DEG
1147-DEG-620
|
|
Enable
Voltage Supervision
|
Yes
|
Yes
|
Voltage
Level
|
0.70 x Rated
|
0.70 x Rated
|
Circle
1 Trip
|
Latched
|
Latched
|
Assign
Circle 1 Trip Relays (1-4)
|
1, 2, 3
|
1, 2, 3
|
Circle
1 Diameter
|
15.5 Wsec
|
29 Wsec
|
Circle
1 Offset
|
3.7 Wsec
|
7 Wsec
|
Circle
1 Trip Delay
|
3s
|
3s
|
Circle
2 Trip
|
Latched
|
Latched
|
Assign
Circle 2 Trip Relays (1-4)
|
1, 2, 3
|
1, 2, 3
|
Circle
2 Diameter
|
22.2 Wsec
|
42 Wsec
|
Circle
2 Offset
|
3.7 Wsec
|
7 Wsec
|
Circle
2 Trip Delay
|
4 s
|
4 s
|
Distance
Not applicable since it is intended for transmission line
3.1.6.3 Power
Element
Reactive Power
Not necessary
Low Forward Power
Not necessary
Reverse Power Trip
·
Consideration/formula
According to ANSI Std
C37-102-1987, the gas turbine prime mover usually have capability maximum
motoring power up to 50% of rating and a diesel engine with no cylinder firing
represented a load of up to 25% of rating, so the sensitivity is not critical.
In this project, there are
two types of generator, gas turbine generator and diesel engine generator. The
sensitivity of reverse power relay is not critical problem due to large power
required to motor.
·
Setting
GPR for GTG
1147-GTG-600”A/B”
|
GPR for DEG
1147-DEG-620
|
|
Block Reverse Power From
Online
|
2 s
|
2 s
|
Reverse
Power Alarm
|
Unlatched
|
Unlatched
|
Assign
Alarm Relays (2-5)
|
5
|
5
|
Reverse
Power Alarm Level
|
0.04 x Rated MW
|
0.04 x Rated MW
|
Reverse
Power Alarm Delay
|
25 s
|
20 s
|
Reverse
Power Trip
|
Latched
|
Latched
|
Assign
Trip Relays (1-4)
|
1,3
|
1,3
|
Reverse
Power Trip Level
|
0.06 x Rated MW
|
0.06 x Rated MW
|
Reverse
Power Trip Delay
|
5 s
|
12 s
|
3.1.6.4 RTD
Element
Disable
3.1.6.5 Thermal
Mode.
Disable
3.1.7 Setpoint /
Monitoring
Trip Counter
·
Setting for All Generators
GPR for GTG
1147-GTG-600”A/B”
|
GPR for DEG
1147-DEG-620
|
|
Trip Counter Alarm
|
Latched
|
Latched
|
Assign
Alarm Relay (2-5)
|
5
|
5
|
Trip
Counter Alarm Level
|
10 trips
|
10 trips
|
Trip
Counter Alarm Event
|
ON
|
ON
|
Breaker Failure
·
Setting for All Generators
GPR for GTG
1147-GTG-600”A/B”
|
GPR for DEG
1147-DEG-620
|
|
Breaker Failure Alarm
|
Unlatched
|
Unlatched
|
Assign
Alarm Relay (2-5)
|
5
|
5
|
Breaker
Failure Level
|
1.1 x CT
|
1.1 x CT
|
Breaker
Failure Delay
|
80 ms
|
80 ms
|
Breaker
Failure Alarm Event
|
ON
|
ON
|
Trip Coil Monitor
·
Setting for All Generators
GPR for GTG
1147-GTG-600”A/B”
|
GPR for DEG
1147-DEG-620
|
|
Trip Coil Monitor Alarm
|
Unlatched
|
Unlatched
|
Assign
Alarm Relay (2-5)
|
5
|
5
|
Supervision
of Trip coil
|
52 Closed
|
52 Closed
|
Trip
Coil Monitor Alarm Event
|
ON
|
ON
|
VT Fuse Failure
·
Setting for All Generators
GPR for GTG
1147-GTG-600”A/B”
|
GPR for DEG
1147-DEG-620
|
|
VT Fuse Alarm
|
Unlatched
|
Unlatched
|
Assign
Alarm Relay (2-5)
|
5
|
5
|
VT
Fuse Alarm Event
|
ON
|
ON
|
Current Demand
·
Setting for All Generators
GPR for GTG
1147-GTG-600”A/B”
|
GPR for DEG
1147-DEG-620
|
|
Current Demand Period
|
15 min
|
15 min
|
Current
Demand Alarm
|
Unlatched
|
Unlatched
|
Assign
Alarm Relay (2-5)
|
5
|
5
|
Current
Demand Limit
|
1.01 x
|
1.01 x
|
Current
Demand Alarm Event
|
ON
|
ON
|
MW Demand
·
Setting for All Generators
GPR for GTG
1147-GTG-600”A/B”
|
GPR for DEG
1147-DEG-620
|
|
MW Demand Period
|
15 min
|
15 min
|
MW
Demand Alarm
|
Unlatched
|
Unlatched
|
Assign
Alarm Relay (2-5)
|
5
|
5
|
MW
Demand Limit
|
1.01 x Rated
|
1.01 x Rated
|
MW
Demand Alarm Event
|
ON
|
ON
|
MVAR Demand
·
Setting for All Generators
GPR for GTG
1147-GTG-600”A/B”
|
GPR for DEG
1147-DEG-620
|
|
MVAR Demand Period
|
15 min
|
15 min
|
MVAR
Demand Alarm
|
Unlatched
|
Unlatched
|
Assign
Alarm Relay (2-5)
|
5
|
5
|
MVAR
Demand Limit
|
1.11 x Rated
|
1.11 x Rated
|
MVAR
Demand Alarm Event
|
ON
|
ON
|
MVA Demand
·
Setting for All Generators
GPR for GTG
1147-GTG-600”A/B”
|
GPR for DEG
1147-DEG-620
|
|
MVA Demand Period
|
15 min
|
15 min
|
MVA
Demand Alarm
|
Unlatched
|
Unlatched
|
Assign
Alarm Relay (2-5)
|
5
|
5
|
MVA
Demand Limit
|
1.1 x Rated
|
1.1 x Rated
|
MVA
Demand Alarm Event
|
ON
|
ON
|
Pulse Output
Disable
Generator Running Hour Setup
·
Setting for All Generators
GPR for GTG
1147-GTG-600”A/B”
|
GPR for DEG
1147-DEG-620
|
|
Initial Gen. Running Hours
|
0 h
|
0 h
|
Gen.
Running Hours Alarm
|
Unlatched
|
Unlatched
|
Assign
Alarm Relay (2-5)
|
5
|
5
|
Gen.
Running Hour Limit
|
1000 h
|
1000 h
|
3.2 Motor Protection
3.2.1 Largest motor at MCC “A & B”
§
Protective Scheme One Line Diagram
§
Protected Equipment:
The
protection is intended to protect motor against overload, short-circuit and
locked rotor.
·
Tag Number :
1130-KM-310A/B – Propane Compressor
·
Model, Manufacturer : Squirrel cage induction motor / Toshiba
·
Rating :
300 HP
·
Full load CURRENT (FLA) : 378.1Amps
·
Locked Rotor :
6 x FLA
·
Starting Device :
Soft Starter (manufacturer: ABB)
·
Service factor :
1.15
§
Protective device:
·
The Overload (OL) device
o
Model, Manufacturer : CEFB1-52-120VAC, Allen Bradley
o
Rating Trip Range : 160 – 630A
·
The motor circuit protection (MCP)
o Manufacturer : Merlin Gerin
o Model : NS630H, MA500 # 32950
o Type : MCCB 3P
o Frame : 500 Amps
o Nominal
Current, In : 500 A
o Trip
setting, Im : 9 – 14 x In
o Trip
Rating : 3150 - 6250 Amps
o Trip
setting : > locked rotor current
§
Consideration
Soft starter is equipped with
MCP to against locked rotor and short circuit. Due to operation of soft starter
only for starting motor and after that it will be bypassed when steady state
(normal running) is achieved. Therefore, it need to added other MCP on the
upstream to protect running motor.
The MCP(motor) trip setting is
set 600% FLA by manufacturer and can not/forbidden be change. To prevent
overlap protection, the MCP is set more than 600% FLA.
§
Setting
1. Thermal
O/L
Trip setting : 125% of FLA (according ANSI/NFPA 70 – 2002,
article 430.32(1))
Þ
Trip setting = 1.25 x 378.1 Amps = 472.63 Amps,
so trip setting = 480 Amps.
2. The
motor circuit protection (MCP)
Þ
Im = 9 x In or equal to 4500A
§
Time Current Curves of Protection Coordination.
See attachment #1
3.2.2 Largest motor at MCC “U”
§
Protective Scheme One Line Diagram
§
Protected Equipment:
The
protection is intended to protect motor against overload, short-circuit and
locked rotor.
·
Tag Number :
1155-PM-702 – Elec. Fire Water Pump
·
Model, Manufacturer : Squirrel cage induction motor / US Motor
·
Rating :
125 HP
·
Full load Current (FLA) : 179.4 Amps
·
Locked Rotor :
6 x FLA
·
Starting device :
Soft starter (manufacturer: Cutler-Hammer)
·
Service factor :
1.15
§
Protective device:
·
MCCB 3P (Thermal-Magnetic Breaker)
o
Manufacturer :
Merlin Gerin
o
Model :
NS250H + MA220
o Type : MCCB 3P
o Frame : 250 Amps
o Nominal
Current, In : 220 A
o Trip
setting, Im : 9 – 14 x In
§
Consideration
See above paragraph.
§
Setting
1. Thermal
O/L
Trip setting : 125% of FLA (according ANSI/NFPA 70 – 2002,
article 430.32(1))
Þ
Trip setting = 1.25 x 179.4 Amps = 224.3 Amps,
so trip setting = 250 Amps.
2. The
motor circuit protection (MCP)
Þ
Im = 9 x In or equal to 1980A
§
Time Current Curves of Protection Coordination,
see attachment #2
3.3 Coordination Relay – Case #1
Overcurrent Protection
Coordination for Largest Motor at MCC
“A” & Main Switchgear
o
o Protective device & others data:
§ Motor
Protection (see paragrap 4.2.1)
§ Protective
device at main switchgear outgoing feeder to MCC “A”:
¨
Feeder Name: 52-F3
¨
Manufacturer/type: Merlin Gerin/ ACB 3P –
NW20H1+Microlgic 6.0A
¨
Rating: 2000AT/2000AF
¨
Nominal Current, In = 2000A
¨
Breaking Capacity (Icu) = 100 kA
§ Equipment
cable:
¨
Size: 3 x 3/C # 2/0 AWG,
¨
Insulation: XLPE
§ Max.
3 phase fault at MCC “A” & Main Switchgear = 52.7 kA rms-sym, see
short-circuit calculation C-1100-ELE-004.
§ Max.
current flows to MCC “A” is 688A, see load flow calculation C-1100-ELE-002.
o Setting
Feeder 52-F3, ACB 4P (NT08H1) + Micrologic
6.0A
Þ
So setting of Ir is 0.7 x In or equal to 1400A
This “Relay” is backup
protection of downstream breaker (motor breakers) and to protect MCC “A” bus
bar. Largest motors is considered due to highest current flow during starting.
Referring to coordination
curve on attachment #1, setting of micrologic 6.0A is determined as
follow:
Þ
Setting of tr = 6s @ 6 x Ir (8400 A)
Þ
Setting of Isd = 5 x Ir (7000 A at 3 s)
Þ
Setting of I2t(OFF at 10 Ir) = 0.2s
(at 14000A)
Þ
Setting of Ii = 15 x In (30000A at 0.05s)
Value
|
|
Ir (x In)
|
0.7
|
ts
(@6Ir)
|
4
|
Isd
(x Ir)
|
5
|
tsd
(i2t)
|
0.2 OFF
|
Ii
(In)
|
15
|
Ig
|
A
|
tg
(i2t)
|
0.1 OFF
|
Þ
In =
2000A
Note: The above
setting is also applied for Feeder 52-F3
(MCC “B”)
3.4 Coordination Relay – Case #2
Overcurrent Protection
Coordination for Largest Motor at MCC
“U” & Main Switchgear
o
Protective Scheme One Line Diagram
o Protective device & others data:
§ Motor
Protection (see paragraph 4.2.2)
§ Protective
device at main switchgear outgoing feeder to MCC “U”:
¨
Feeder Name: 52-F9
¨
Manufacturer/type: Merlin Gerin/ ACB 3P –
NW12H1+Microlgic 6.0A
¨
Rating: 1250AT/1250AF
¨
Nominal Current, In = 1250A
¨
Breaking Capacity (Icu) = 100 kA
§ Equipment
cable:
¨
Size: 2 x 3/C # 1/0 AWG,
¨
Insulation: XLPE
§ Max.
3 phase fault at MCC “U” & Main Switchgear = 52.7 kA rms-sym, see
short-circuit calculation C-1100-ELE-004.
§ Max.
current flows to MCC “U” is 413A, see load flow calculation C-1100-ELE-002.
o Setting
Feeder 52-F9, ACB 4P (NT08H1) + Micrologic
6.0A
Þ
So setting of Ir is 0.7 x In or equal to 875A
This “Relay” is backup
protection of downstream breaker (motor breakers) and to protect MCC “A” bus
bar. Largest motors is considered due to highest current flow during starting.
Referring to coordination
curve on attachment #2, setting of micrologic 6.0A is determined as
follow:
Þ
Setting of tr = 16s @ 6 x Ir (5250 A)
Þ
Setting of Isd = 4 x Ir (3500 A at 3 s)
Þ
Setting of I2t(OFF at 10 Ir) = 0.1s
(at 8750A)
Þ
Setting of Ii = 10 x In (18750A at 0.05s)
Value
|
|
Ir (x In)
|
0.7
|
ts
(@6Ir)
|
8
|
Isd
(x Ir)
|
4
|
tsd
(i2t)
|
0.2 OFF
|
Ii
(In)
|
15
|
Ig
|
A
|
tg
(i2t)
|
0.1 OFF
|
In
= 1250A
3.5 Coordination Relay – Case #3
Overcurrent
Protection Coordination for MCC “Camp” and Main Switchgear 1147-PSW2-01
o
Protective Scheme One Line Diagram
o Protective device & others data:
§ Largest
outgoing feeder MCC “Camp”
·
Manufacturer :
Merlin Gerin
·
Type/model :
MCCB / NS100H + TM100D (80-100)
·
Rating :
In = 100A
·
Breaking Capacity (Icu) = 70 kA
§ Protective
device at incoming side of MCC “Camp”: ACB 4P (NT08H1) + Micrologic 6.0A.
¨
Manufacturer/type: Merlin Gerin/ ACB 4P –
NT08H1+Microlgic 6.0A
¨
Rating: 800AT/800AF
¨
Nominal Current, In = 800A
¨
Breaking Capacity (Icu) = 65 kA
§ Protective
device at outgoing feeder of Main Switchgear:
¨
Manufacturer/type: Merlin Gerin/ ACB 3P –
NT08H1+Microlgic 6.0A
¨
Rating: 1250AT/1250AF
¨
Nominal Current, In = 1250A
¨
Breaking Capacity (Icu) = 100 kA
§ 3
phase fault, see short-circuit calculation C-1100-ELE-004:
¨
MCC “Camp” = 6.8 kA rms-sym
¨
Main switchgear 1147-PSW2-01A = 52.7 kA rms-sym
§ Maximum
current flows to MCC “Camp” is equal to full load current transformer
1163-PTR2-01 “A or B”
§ Transformer
1163-PTR2-01
¨
Manufacturer/type: Unindo/Oil Immersed
¨
Rating: 400 kVA, 400/400V, D-Y
solid grounded
¨
Thermal capability curve : IEC curve
¨
Inrush Current = 5 x Inominal or
2887A, 1 second (see datasheet DS-1163-PTR2-01)
o Setting
1.
Setting of MCCB (NS100H + TM100D)
Þ
Setting of Ir = 1 x In or equal 100A
Þ
Setting of Ii = 800A (fixed)
2. Camp Incoming Feeder 52-1A, ACB 4P (NT08H1)
+ Micrologic 6.0A
Maximum current flows to MCC
“Camp” :
then,
Þ
So setting of Ir is 0.8 x In (640A)
This “Relay” is backup
protection of downstream breaker and to protect MCC bus bar. The maximum 3
phase fault is same with downstream. Referring to coordination curve on
attachment #3, setting of micrologic 6.0A is determined as follow:
Value
|
|
Ir (x In)
|
0.8
|
ts
(@6Ir)
|
4
|
Isd
(x Ir)
|
2
|
tsd
(i2t)
|
0.2 OFF
|
Ii
(In)
|
10
|
Ig
|
A
|
tg
(i2t)
|
0.1 ON
|
In
= 800A
Note: The above settings are also
applied for Incoming Feeder 52-1B
3. Main Switchgear Outgoing Feeder 52-F5, ACB
4P (NW12H1) + Micrologic 6.0A
This “Relay” is backup
protection of downstream breaker and also protect cable feeder and transformer
if fault occur between both breakers. Referring to coordination curve on
attachment #3, setting of micrologic 6.0A is determined as follow:
\
Setting of Ir
Þ
So setting of Ir is 0.7 x In (875A)
Þ
Setting of tr = 8s @ 6 x Ir (4320A)
Þ
Setting of Isd = 4 x Ir (3500 A at 3)
Þ
Setting of I2t(OFF at 10 Ir) = 0.1s
(at 7200A)
Þ
Setting of Ii = 9 x In (7200 A at 0.05s)
Value
|
|
Ir (x In)
|
0.7
|
ts
(@6Ir)
|
10
|
Isd
(x Ir)
|
4
|
tsd
(i2t)
|
0.4 OFF
|
Ii
(In)
|
15
|
Ig
|
A
|
tg
(i2t)
|
0.1 OFF
|
In
= 1250A
Þ
Note: The above
settings are also applied for Outgoing
Feeder 52-F8
3.6 Coordination Relay – Case #4
Overcurrent
Protection Coordination for PDB-Operation Bldg, Switchgear 1162-PSW2-01, and
Main Switchgear 1147-PSW2-01
o
Protective Scheme One Line Diagram
o Protective device & others data:
§ Largest
outgoing feeder PDB “Operation Building”
·
Manufacturer :
Merlin Gerin
·
Type/model :
MCCB / NS100H + TM100D (80-100)
·
Rating :
In = 100A
·
Breaking Capacity (Icu) = 70 kA
§ Protective
device at incoming of PDB “Operation Building”:
¨
Manufacturer/type: Merlin Gerin/ MCCB 4P –
NS400N+STR23SE
¨
Rating: 400AT/400AF
¨
Nominal Current, In = 400A
¨
Breaking Capacity (Icu) = 45 kA
§ Protective
device at outgoing feeder of switchgear 1162-PSW2-01A:
¨
Manufacturer/type: Merlin Gerin/ ACB 4P –
NT06H1+Microlgic 6.0A
¨
Rating: 400AT/400AF
¨
Nominal Current, In = 400A
¨
Breaking Capacity (Icu) = 42 kA
§ Protective
device at outgoing feeder of Main Switchgear:
¨
Manufacturer/type: Merlin Gerin/ ACB 3P –
NW12H1+Microlgic 6.0A
¨
Rating: 1250AT/1250AF
¨
Nominal Current, In = 1250A
¨
Breaking Capacity (Icu) = 100 kA
§ 3
Phase Fault, see short-circuit calculation C-1100-ELE-004:
¨
PDB “Op. Bldg.” = 6.3 kA rms-sym
¨
Switchgear 1162-PSW2-01 = 6.7 kA rms-sym
¨
Main switchgear 1147-PSW2-01A = 52.7 kA rms-sym
§ Maximum
current flows to MCC “Camp” is equal to full load current transformer
1162-PTR2-01 “A or B”
§ Transformer
1162-PTR2-01
¨
Manufacturer/type: Unindo/Oil Immersed
¨
Rating: 250 kVA, 400/400V, D-Y
solid grounded
¨
Thermal capability curve : IEC curve
¨
Inrush Current = 5 x Inominal or
1805A, 1 second (see datasheet DS-1162-PTR2-01)
o Setting
1.
Setting of MCCB (NS100H + TM100D)
Þ
Setting Ir = 1 x In or equal 100A
Þ
Setting Ii = 800A (fixed)
2.
Setting of MCCB (NS400N+STR23SE)
From load flow study
C-1100-ELE-002, operating current flows to 1162-PDB2-01A is 81 ampere
Ir = 2*81 = 162A
Þ
Setting of long time delay,
§
Io = 0.9 x
In or equal 360A
§
Ir = 0.8 x Io or equal to 288A
Þ
Setting of short time delay, Im = 5 x Ir or equal 1440A
Þ
Setting of instantaneous, Ii = 11 x In (fixed)
or equal to 4400A
3. Op. Building Incoming Feeder 52-1A, ACB 4P
(NT06H1) + Micrologic 6.0A
Maximum current flows to
switchgear “Op. Bldg” :
Þ
So setting of Ir is 0.95 x In or equal to 380A
This “Relay” is backup
protection of downstream breaker and also to protect switchgear bus bar.
Referring to coordination curve on attachment #4, setting of micrologic 6.0A is
determined as follow:
Value
|
|
Ir (x In)
|
0.6
|
ts
(@6Ir)
|
8
|
Isd
(x Ir)
|
6
|
tsd
(i2t)
|
0.2 OFF
|
Ii
(In)
|
10
|
Ig
|
A
|
tg
(i2t)
|
0.2 OFF
|
In = 630A
Note: The above settings are
also applied for Incoming Feeder 52-1B
4. Main Switchgear Outgoing Feeder 52-F2, ACB
3P (NW12H1) + Micrologic 6.0A
This “Relay” is backup
protection of downstream breaker and also protect cable feeder and transformer
if fault occur between both breakers. Referring to coordination curve on
attachment #4, setting of micrologic 6.0A is determined as follow:
Value
|
|
Ir (x In)
|
0.6
|
ts
(@6Ir)
|
12
|
Isd
(x Ir)
|
5
|
tsd
(i2t)
|
0.4 OFF
|
Ii
(In)
|
15
|
Ig
|
A
|
tg
(i2t)
|
0.1 OFF
|
In = 1000A
Note: The above settings are
also applied for Outgoing Feeder 52-7
3.7 Coordination Relay – Case #5
Overcurrent
Protection Coordination for Largest Outgoing (Main Switchgear) and GTG’s
Breaker (Normal Operation)
o
Protective Scheme One Line Diagram
o Protective device, others data and
setting:
§ In
normal operation, largest outgoing feeder of Main Switchgear is to MCC “A/B”.
Setting of the ACB, refer to paragraph 4.3 (Normal Condition – GTG’s ON)
§ Protective
device at incoming of Main Switchgear: Multilin SR 489 – Over current with
Voltage Restraint, see paragraph 5.1.6
§ 3
Phase Fault, see short-circuit calculation C-1100-ELE-004:
¨
Main switchgear 1147-PSW2-01A = 52.7 kA rms-sym
¨
Max. fault current is supplied by GTG = 18.9 kA
o Consideration/formula
Relay time dial setting.
Refer to ANSI extremely Inverse Curve for characteristic of the inverse
time relay. Since GTG’s breaker is as backup relay, it must be coordinated with
outgoing breaker(micrologic) of main switchgear. By adding a coordination time
interval (CTI) 0.3s to them, the setting of Multilin O/C relay is more than
0.5s for Max. Fault Current supplied by GTG.
then from ANSI curve; it is
found TMD = 4 & operating time of
relay is about 1.2s at 18.9kA.
o Setting:
See paragraph 4.1.6.1, section
phase O/C (A)
3.8 Coordination Relay – Case #6
Overcurrent
Protection Coordination for Largest Outgoing (Main Switchgear) and DEg’s
Breaker (Emergency Operation)
o
o Protective device, others data and
setting:
§ In
emergency operation, Largest outgoing feeder of Main Switchgear is to MCC “U”.
Setting of this ACB, refer to paragraph 4.4 (Normal Condition – GTG’s ON)
§ Protective
device at incoming of Main Switchgear: Multilin SR 489 – Over current with
Voltage Restraint, see paragraph 5.1.6
§ Max.
Fault, see short-circuit calculation C-1100-ELE-004:
¨
Main switchgear 1147-PSW2-01”B” = 52.7 kA
rms-sym
¨
Max. fault Current is supplied by DEG = 10.8 kA
o Consideration/formula
Relay time dial setting.
Refer to ANSI extremely Inverse Curve for characteristic of the inverse
time relay. Since DEG’s breaker is as backup relay, it must be coordinated with
outgoing breaker(micrologic) of main switchgear. By adding a coordination time
interval (CTI) 0.3s to them, the setting of Multilin O/C relay is more than
0.5s for Max. Fault Current supplied by DEG.
then from ANSI curve; it is
found TMD = 10 & operating time of
relay is about 3s at 10.8kA.
o Setting:
See paragraph 4.1.6.1, section Phase
O/C (B).
3.9 Ground Fault
Relay
o Protective device & others data:
A. at MCC “Camp”
¨
Manufacturer/type: Merlin Gerin/ ACB 4P –
NT08H1+Microlgic 6.0A
¨
Rating: 800AT/800AF
¨
Nominal Current, In = 800A
B. at Switchgear “Op. Bldg”
¨
Manufacturer/type: Merlin Gerin/ ACB 4P –
NT06H1+Microlgic 6.0A
¨
Rating: 400AT/400AF
¨
Nominal Current, In = 400A
o Consideration
The purpose of this relay is not
to limit fault damage of equipment but to protect human life, so that it need
high sensitivity to detect ground fault.
o Setting
A. Ground Fault Relay
(Micrologic 6.0A) at MCC “Camp”
Þ
Ground Fault Pickup, Ig = In x A (minimum setting A= 0.2, see attachment #3)
Þ
Time delay (ms) at In, I2t Off = 0.2
B. Ground Fault Relay
(Micrologic 6.0A) at Switchgear ”Op. Bldg”
Þ Ground
Fault Pickup, Ig = In x A (minimum
setting A= 0.3, see attachment #3)
Þ Time
delay (ms) at In, I2t Off = 0.2
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