UAT #1 & #2 Protection Relay Setting & Testing
February 3, 2017 | Author: Erwin Sambas | Category: N/A
Short Description
Download UAT #1 & #2 Protection Relay Setting & Testing...
Description
UAT No.1 & No.2 Protection Relay Setting & Testing Testing
Contents
1. Setting of UAT #1 Protection Relay
- - - - - - - - - - P. 3 – P13
2. UAT #1 Protection Relay Test Record Sheet 3. Setting of UAT #2 Protection Relay
- - - - - - - - - - - P. 22 – P.32
4. UAT #2 Protection Relay Test Record Sheet
-
2
-
- - - - - P.14 – P.21
- - - - - P. 33 – P.40
1.
Setting of UAT #1 Protection Relay
-
3
-
Setting of UAT-1 Protection Relay Type RET670 F87T - Unit Aux. Transformer Differential Protection 1. Terminal identification Station Name :
KERAMASAN
Bay Name:
UAT-1
Relay Name
RET 670
Relay serial No Frequency
50 Hz
Aux voltage
110 VDC
2. General Data Transformer:
GSUT-1, two winding
Rated data :
Rated power
6 MVA
Voltage ratio
11 kV / 6.3 kV
W1 rated current - Ir1
315 A
W2 rated current - Ir2
550 A
Connection
Dyn11 (resistive grounding at Y winding)
p.u. Impedance
0.08
at Base
6
CT ratio W1 (11kV)
750 / 1 A
CT ratio W2 (6.3kV)
1250 / 1 A
VT ratio W1
11 / 0.11 kV
VT ratio W2/W3
6.3 / 0.11 kV
Short circuit data : Three-phase short circuit current at 6.3kV busbar
9300 A
Phase to Ground short circuit current at 6.3kV busbar
11 A
Phase current contribution of UAT for 3-Ph fault at 6.3kV busbar
6580 A
measured at 6.3kV side Phase current contribution of UAT for 3-Ph fault at 6.3kV busbar
3768.5 A
measured at 11kV side
3. Setting Considerations Protection Scheme - Transformer 2 winding differential protection (87T) is applied as main protection to mostly protect the transformer from internal phase to phase fault. Very small earth fault current due to resistive grounding makes REF protection will not be effective and sensitive enough to protect the transformer from internal earth fault. Therefore, sensitive earth fault protection relay shall then be provided in the backup protection relay. Differential current setting (Idmin)
UAT1 F87T
1/4
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4
Keramasan
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The usual practice for transformer protection is to set the bias characteristic to a value of at least twice the value of the expected spill current under through faults conditions. Spill current may arise from several conditions such as : - transformer phase shift and ratio error - current transformer ratio error - different CTs characteristic Idmin of 0.3 x Ibase is normally recommended to be applied. Zero-sequence current substraction A differential protection may operate unwanted due to external earth faults in cases where the zero sequence current can flow only on one side of the power transformer but not on the other side. This is the situation when the zero sequence current can not be properly transformed to the other side of the power transformer having a combined Y and D connection group. In such case, the zero sequence substraction function shall be set ON for Y winding and OFF for D winding.
4. Setting of analogue input Configure analogue inputs for TRM1 (-X401) : Set analogue current channels AI1
AI2
AI3
AI4
AI5
Ctprim
=
750
750
750
1250
1250
Ctsec
=
1A
1A
1A
1A
1A
CTStarPoint
=
AI6
AI7
AI8
AI9
Ctprim
=
1250
not used
not used
not used
Ctsec
=
1A
not used
not used
not used
CTStarPoint
=
To Object
not used
not used
not used
To Object To Object To Object
To Object To Object
Set analogue voltage channels AI10
AI11
AI12
Vtprim
=
not used
not used
not used
Vtsec
=
not used
not used
not used
5. Protection Settings 5.1. Setting of the Differential function data under T2WPDIF General settings. Winding 1 (W1)
Winding 2 (W2)
RatedVoltageW1
11 kV
RatedVoltageW2
6.3 kV
RatedCurrentW1
315 A
RatedCurrentW2
550 A
ConnectTypeW1
D
ConnectTypeW2
Y
TconfigForW1
No
TconfigForW2
No
CT1ratingW1
750 A
CT1ratingW2
1250 A
ZSCurrSubtrW1
Off
UAT1 F87T
ZSCurrSubtrW2
On
ClockNumberW2
11
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5
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Note : All other setting parameters under general setting are not relevant. Use default values.
5.2. Differential Protection Setting (87T) under T2WPDIF Setting group: Operation
=
On
=
Off
=
0.2 *Ibase
Operation of SOTF feature SOTFMode Setting of differential current alarm IDiffAlarm
Setting of time delay of differential current alarm tAlarmDelay
=
10 s
Setting of minimum differential operating current IdMin
=
0.3 *Ibase
Setting of cross-over point between slope 1 and slope 2 EndSection1
=
1.25 Ibase
Setting of slope 2 stabilisation, Slope 1 has fixed stabilization SlopeSection2
=
40% *Ibias
Setting of cross-over point between slope 2 and slope 3 EndSection2
=
3.00 Ibase
=
80% *Ibias
Setting of slope 2 stabilisation SlopeSection3
Setting of minimum differential operating current for unrestraint step Idunre
=
20.00 *Ibase
Set the operation of Cross Blocking logic On-Off OpCrossBlock
=
On
Set the second and fifth harmonic stabilizing level when transformers are inside the zone I2/I1Ratio
=
15%
I5/I1Ratio
=
25%
Set the operation of Negative sequence differential protection NegSeqDiffEn
=
No
Setting of minimum negative sequence differential current level IMinNegSeq
=
0.04
=
60 deg
=
No
Setting of the Relay operating angles NegSeqROA Set the operation of Open CT detection OpenCTEnable
Note : All other setting parameters under this setting group are not relevant.
5.3. All other protection functions Operation
=
Off
6. Assignment of Binary Input BIM_3
UAT1 F87T
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6
Keramasan
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BIM_3.BI01
: Bucholz Trip
BIM_3.BI02
: Rapid Pressure Relay Trip
BIM_3.BI03
: Oil Level Low Low Trip
BIM_3.BI04
: Protective Relay Trip
BIM_3.BI05
: Oil Temperature Trip
BIM_3.BI06
: HV Winding Temperature Trip
BIM_3.BI07
: Not used
BIM_3.BI08
: Trip from Generator Protection (59BG)
BIM_3.BI09
: Trip from Generator Protection (52G Mech Fail)
BIM_3.BI10
: Trip from GSUT Protection
BIM_3.BI11
: Reset Lockout
BIM_3.BI12
: Not used
BIM_3.BI13
: Not used
BIM_3.BI14
: Not used
BIM_3.BI15
: Not used
BIM_3.BI16
: Not used
7. Assignment of Binary Output BOM_4 BOM_4.BO01
: Transformer Differential Trip (T2WPDIF)
BOM_4.BO02
: Not used
BOM_4.BO03
: Trip from Generator Protection
BOM_4.BO04
: Trip from UAT Transformer's Protection (Bucholz etc)
BOM_4.BO05
: Not used
BOM_4.BO06
: Not used
BOM_4.BO07
: Not used
BOM_4.BO08
: Not used
BOM_4.BO09
: Transformer Differential Trip (T2WPDIF)
BOM_4.BO10
: Not used
BOM_4.BO11
: Trip from Generator Protection
BOM_4.BO12
: Not used
BOM_4.BO13
: Trip from UAT Transformer's Protection (Bucholz etc)
BOM_4.BO14
: Trip from GSUT Protection
BOM_4.BO15
: Transformer Differential Trip (T2WPDIF)
BOM_4.BO16
: Not used
BOM_4.BO17
: Trip from GSUT Protection
BOM_4.BO18
: Trip from Generator Protection
BOM_4.BO19
: Not used
BOM_4.BO20
: Not used
BOM_4.BO21
: Not used
BOM_4.BO22
: Not used
BOM_4.BO23
: Not used
BOM_4.BO24
: Not used
UAT1 F87T
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7
Keramasan
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Setting of UAT-1 Protection Relay Type REF615 F5051 - Backup OC & EF Protection 1. Terminal identification Station Name
KERAMASAN
Bay Name:
UAT-1
Relay Name
REF615
Relay serial No Frequency
50 Hz
Aux voltage
110 VDC
2. General Data Transformer:
UAT-1, two winding
Rated data :
Rated power
6 MVA
Voltage ratio
11 kV / 6.3 kV
W1 rated current - Ir1
315 A
W2 rated current - Ir2
550 A
Connection
Dyn11 (resistive grounding at Y winding)
p.u. Impedance
0.08
at Base
6
CT ratio W1 (11kV)
750 / 1 A
CT ratio W2 (6.3kV)
1250 / 1 A
Short circuit data : Three-phase short circuit current at 6.3kV busbar
9300 A
Phase to Ground short circuit current at 6.3kV busbar
11 A
Phase current contribution of UAT for 3-Ph fault at 6.3kV busbar
6580 A
measured at 6.3kV side Phase current contribution of UAT for 3-Ph fault at 6.3kV busbar
3768.5 A
measured at 11kV side Maximum tripping time for 6.3kV outgoing feeders
Instantaneous
3. Setting Considerations Protection Scheme - Low-set phase overcurrent (51) protection at 11kV side are used as backup protection for differential (87T) and REF (87REF) protection. To maintain selectivity against downstream protection relays, a time delay of 0.5s on top of the downstream (6.3kV outgoing feeders) protection relays maximum operating time shall be introduced. - Instantaneous-set overcurrent (50) at 11kV side is applied to protect the transformer during short circuit condition. Time delay shall be introduced to maintain selectivity from the fault which occur at the other parts of the system. UAT1 F5051
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- Sensitive earth fault/SEF (50S) of this relay will be applied at 6.3kV to detect earth fault condition at 6.3kV system. To maintain selectivity against earth fault protection relay at 6.3kV outgoing feeders, a time delay of 0.5s on top of the outgoing feeders tripping time is introduced. As the fault current is considerably small, a longer operating time is somehow still acceptable as long as not exceeding the rated time of NGR (10s). - To avoid unwanted operation of the overcurrent and earth fault protection due to inrush current during transformer startup, the inrush detection element INRPHAR is activated to give a blocking signal to the overcurrent & earth fault element when inrush current is detected.
4. Setting of analogue input Analog input settings, phase currents Secondary current
=
1A
Primary current
=
750 A
Amplitude corr. A
=
1
Amplitude corr. B
=
1
Amplitude corr. C
=
1
Nominal current
=
315 A
Rated secondary value
=
3 mV/Hz
Reverse polarity
=
0
Secondary current
=
1A
Primary current
=
1250 A
Amplitude corr.
=
1
Reverse polarity
=
0
{In} {False}
Analog input settings, residual currents
{False}
5. General System Setting Rated frequency
=
50 Hz
Phase rotation
=
Blocking mode
=
Bay Name
=
UAT2
IDMT saturation point
=
50
ABC Freeze timer
6. Setting of Three Phase Overcurrent Function (PHxPTOC) on 11 kV side 6.1. PHIPTOC (Instantaneous) Non group settings: Activation of the PHIPTOC function Operation
=
1
{ 1=On }
1
{ 1=1-out-of-3 }
Number of phases required for operate activation Num of start phase
=
Reset delay time
=
Reset delay time 20 ms
UAT1 F5051
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{ instantaneous }
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6.2. PHIPTOC (Instantaneous) Group settings: Start values is set at 130% of transformer short circuit current to get selectivity with faults at 6.3kV. Start Value PHHPTOC Start Value PHHPTOC
=
130% x 3768.5 A
=
4899.1 A
=
15.6 x In
Operate delay time Operate delay time
=
20 ms
{ instantaneous }
Note : All other setting parameters are not relevant. Default values can be used. 6.3. PHHPTOC (high-set) Non group settings: Activation of the PHHPTOC function Operation
=
5
{ 5=Off }
Note : All other setting parameters are not relevant. Default values can be used. 6.4. Setting of parameters for PHLPTOC (low-set) Non-group Setting Activation of the PHLPTOC function Operation
=
1
{ 1=On }
Number of phases required for activation Num of start phase
=
1 out of 3
Minimum operate time for IDMT curve Min. oper. Time
=
40 ms
Reset delay time
=
20 ms
Reset delay time Curve parameter for programmable curve Curve parameter A, B, C, D, E
=
default
{NA}
6.5. PHLPTOC (low-set) Group settings: Start values is set at 110% of transformer rated current. Start Value PHLPTOC
=
120% x 315 A
=
378 A
=
1.2 x In
=
1
Time multiplier
=
1
Time delay PHLPTOC
=
400
=
IEC Extremely Inverse
=
1
Start Value PHLPTOC Multiplier for scalng the start value Start value Mult Time multiplier setting (TMS)
{See note below}
Operate delay time ms
{Not relevant for inverse type}
Operating curve type Curve PHLPTOC Selection of reset curve type Type of reset curve
{Immediate}
Note : Time delayed PHLPTOC shall be set to operate in about 0.8 s at short circuit UAT1 F5051
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current to give safe margin to the transformer main protection and other unit protection at the other part of the system. Short circuit current
=
3768.5 A
=
12 x In
with start value
=
1.2 x In
and set time multiplier
=
1
for extremely inverse curve, the operating time t is : t
=
0.814 s
--> OK
7. Setting of Earth Fault Protection Function (EFxPTOC) on 6.3 kV side 7.1. EFIPTOC (Instantaneous) Non group settings: Activation of the EFIPTOC function Operation
=
5
{ 5=Off }
Note : All other setting parameters are not relevant. Default values can be used. 7.2. EFHPTOC (high-set) Non group settings: Activation of the EFHPTOC function Operation
=
5
{ 5=Off }
Note : All other setting parameters are not relevant. Default values can be used. 7.3. EFLPTOC (low-set) Non group settings: Activation of the EFLPTOC function Operation
=
1
{ 1=On }
Minimum operate time for IDMT curve Min. oper. Time
=
40 ms
Reset delay time
=
20 ms
Reset delay time Curve parameter for programmable curve Curve parameter A, B, C, D, E
=
default
{NA}
Selection for used Io signal Io signal Sel
=
1
{Measured Io)
7.3. EFLPTOC (low-set) Group settings: Start value for earth fault is set at 50% of maximum earth fault current. Start Value EFLPTOC Start Value EFLPTOC
=
50% x
=
6A
=
0.02 x In
=
1
=
0.1
11 A
{See note below}
Multiplier for scalng the start value Start value Mult Time multiplier setting (TMS) Time multiplier
{See note below}
Operate delay time UAT1 F5051
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Time delay EFLPTOC
=
0.9
s
=
Definite time
=
1
Operating curve type Curve EFLPTOC Selection of reset curve type Type of reset curve
{Immediate}
8. Setting of Inrush Detector INRPHAR 8.1. Inrush Detector INRPHAR Group Setting Ratio of the 2nd to the 1st harmonic leading to restraint Start value
=
Operate delay time
=
0.15 %
Operate delay time 20 ms
8.2. Inrush Detector INRPHAR Non Group Setting Activation of the INRPHAR function Operation
=
Reset delay time
=
1
{ 1=On }
Reset delay time 20 ms
9. All other protection functions Operation
=
5
{ 5=Off }
10. Assignment of Binary Input Binary Input Terminal -X110_ BI1
: Not used
BI2
: Not used
BI3
: Not used
BI4
: Not used
BI5
: Not used
BI6
: Not used
BI7
: Not used
BI8
: Not used
BI9
: Not used
BI10
: Not used
Binary Input Terminal -X120_ BI1 BI2 BI3 BI4
: Reset lockout
11. Assignment of Binary Output
UAT1 F5051
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Binary Output Terminal -X100_ PO1
: Overcurrent Trip (Operation of PHHPTOC, PHLPTOC)
PO2
: SEF Trip
SO1
: Overcurrent Trip
SO2
: SEF Trip
(Operation of EFLPTOC)
PO3 PO4 Binary Output Terminal -X110_ SO1
: Overcurrent Trip
SO2
: SEF Trip
SO3 SO4
UAT1 F5051
6 of 6
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13
Keramasan
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2.
UAT #1 Protection Relay Test Record Sheet
-
14
-
Protection Relay Test Equipment
:
Unit Aux. Transformer Differential Protection Relay RET670
Feeder
:
UAT #1
1.
2.
Reference Drawing Schematic Diagram
:
KPP-00-TPS-W-141
Transformer Bay
:
11kV 6.3kV UAT #1
General Data ABB
Manufacture : Type
3.
RET670
:
F87T
Designation : Sereal No.
:
Commissioning Tests 3.1 Visual Check a)
Physically Good ?
:
b)
Relay Healthy ?
:
c)
Mounting and wiring completed ?
:
3.2 Verifying the connections and the analog inputs Apply input signals as needed and verify that signals are measured correctly Injected Values Measured Secondary Values Primary
No.
Procedure
1
Inject current phase R → A101
A
A
2
Inject current phase S → A102
A
A
3
Inject current phase T → A103
A
A
4
Inject current phase R → A104
A
A
5
Inject current phase S → A105
A
A
6
Inject current phase T → A106
A
A
7
Inject current Neutral → A107
A
A
Contractor
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15
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Remarks
3.3 Deferential Protection Test (1) Check on HV side No.
Secondary Injection
Procedure
Items to be verified.
Remarks
1 Make sure that REF and OC / EF function are set to off. 2 Connect the test set for injection of 3 phase current to the current terminals of RET670 which are connected to the CT's on HV side of transformer
3 Increase the current in phase L1 until the protection operates and check
L1
a) the operating current (Iop)
a) Iop :
A
b) Trip contacts operation
b) Trip contact : Operate / Not operate
c) Alarm contact operation
c) Alarm contact : Operate / Not operate
4 Increase the current in phase L2 until the protection operates and check
L2
For stable condition, Trip not operated
a) the operating current (Iop)
a) Iop :
b) Trip contacts operation
b) Trip contact :
A
Operate / Not operate c) Alarm contact operation
c) Alarm contact : Operate / Not operate
5 Increase the current in phase L3 until the protection operates and check
For stable condition, Trip not operated
L3
a) the operating current (Iop)
a) Iop :
A
b) Trip contacts operation
b) Trip contact : Operate / Not operate
c) Alarm contact operation
c) Alarm contact : Operate / Not operate
Contractor
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16
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(2) Check on LV side
Secondary Injection
No.
Procedure
Items to be verified.
1
Connect the test set for injection of 3 phase current to the current terminals of RET670 which are connected to the CT's on LV side of transformer
2 Increase the current in phase L1 until the protection operates and check
L1
a) the operating current (Iop)
a) Iop :
A
b) Trip contacts operation
b) Trip contact : Operate / Not operate
c) Alarm contact operation
c) Alarm contact : Operate / Not operate
3 Increase the current in phase L2 until the protection operates and check
L2
a) the operating current (Iop)
a) Iop :
A
b) Trip contacts operation
b) Trip contact : Operate / Not operate
c) Alarm contact operation
c) Alarm contact : Operate / Not operate
4 Increase the current in phase L3 until the protection operates and check
L3
a) the operating current (Iop)
a) Iop :
A
b) Trip contacts operation
b) Trip contact : Operate / Not operate
c) Alarm contact operation
c) Alarm contact : Operate / Not operate
Contractor
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17
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Remarks
3.4 6.3kV Restricted EF Protection Test (1) Secondary Injection Procedure
No.
Items to be verified.
1 Make sure that Differential protection and OC/EF function are set to off. 2 Connect the test set for injection of neutral current to the current terminals of RET670 to which the NCT 20kV is connected
3 Increase the current in until the protection operates and check
L1
a) the operating current (Iop)
a) Iop :
A
b) Trip contacts operation
b) Trip contact : Operate / Not operate
c) Alarm contact operation
c) Alarm contact : Operate / Not operate
4.
Remarks :
Contractor
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18
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Remarks
Protection Relay Test Equipment
:
Backup OC & EF Protection Relay REF615
Feeder
:
UAT #1
1.
2.
Reference Drawing Schematic Diagram
:
KPP-00-TPS-W-141
Transformer Bay
:
11kV 6.3kV UAT
General Data ABB
Manufacture : Type
3.
RET615
:
F5051
Designation : Sereal No.
:
1VHR91059397
Commissioning Tests 3.1 Visual Check a)
Physically Good ?
:
b)
Relay Healthy ?
:
c)
Mounting and wiring completed ?
:
3.2 Verifying the connections and the analog inputs Apply input signals as needed and verify that signals are measured correctly Injected Values Measured Secondary Values Primary
No.
Procedure
1
Inject current phase R
A
A
2
Inject current phase S
A
A
3
Inject current phase T
A
A
4
Inject current phase N
A
A
Contractor
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19
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Remarks
3.3 Testing of the phase overcurrent protection The test is performed as a secondary test, by injecting current to the current energizing inputs with the setting values used during normal operation Procedure
No. 1
Items to be verified.
Inject the current (Ii) in phase L1 Ii = 2.5 * I > * rated current input I > setting :
2
Start of stage I > : . Trip of stage I > : . Operation time : s
* In
t > setting : s Inject the current (Ii) in phase L2 Ii = 2.5 * I > * rated current input I > setting :
3
Start of stage I > : . Trip of stage I > : . Operation time : s
* In
t > setting : s Inject the current (Ii) in phase L3 Ii = 2.5 * I > * rated current input I > setting :
4
Start of stage I > : . Trip of stage I > : . Operation time : s
* In
t > setting : s Inject the current (Ii) in phase L1 Ii = 8 * I >>> * rated current input I >>> setting :
5
Start of stage I >>> : . Trip of stage I >>> : . Operation time : s
* In
t >>> setting : s Inject the current (Ii) in phase L2 Ii = 8 * I >>> * rated current input I >>> setting :
6
Start of stage I >>> : . Trip of stage I >>> : . Operation time : s
* In
t >>> setting : s Inject the current (Ii) in phase L3 Ii = 8 * I >>> * rated current input I >>> setting :
Start of stage I >>> : . Trip of stage I >>> : . Operation time : s
* In
t >>> setting : s
Contractor
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20
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Remarks
3.4 Testing of the earth fault protection The test is performed as a secondary test, by injecting current to the current energizing inputs with the setting values used during normal operation Procedure
No. 1
Items to be verified.
Inject the current (Ii) in the earth fault energizing input : Ii = 2.5 * I0 > * rated current input
2
I0 > setting :
* In
t0 > setting :
s
Start of stage I > : . Trip of stage I > : . Operation time : s
Inject the current (Ii) in the earth fault energizing input : Ii = 2.5 * I0 >> * rated current input
4.
I0 >> setting :
* In
t0 >> setting :
s
Start of stage I >> : . Trip of stage I >> : . Operation time : s
Remarks :
Contractor
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Remarks
3.
Setting of UAT #2 Protection Relay
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22
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Setting of UAT-2 Protection Relay Type RET670 F87T - Unit Aux. Transformer Differential Protection 1. Terminal identification Station Name :
KERAMASAN
Bay Name:
UAT-2
Relay Name
RET 670
Relay serial No Frequency
50 Hz
Aux voltage
110 VDC
2. General Data Transformer:
GSUT-2, two winding
Rated data :
Rated power
6 MVA
Voltage ratio
11 kV / 6.3 kV
W1 rated current - Ir1
315 A
W2 rated current - Ir2
550 A
Connection
Dyn11 (resistive grounding at Y winding)
p.u. Impedance
0.08
at Base
6
CT ratio W1 (11kV)
750 / 1 A
CT ratio W2 (6.3kV)
1250 / 1 A
VT ratio W1
11 / 0.11 kV
VT ratio W2/W3
6.3 / 0.11 kV
Short circuit data : Three-phase short circuit current at 6.3kV busbar
9300 A
Phase to Ground short circuit current at 6.3kV busbar
11 A
Phase current contribution of UAT for 3-Ph fault at 6.3kV busbar
6580 A
measured at 6.3kV side Phase current contribution of UAT for 3-Ph fault at 6.3kV busbar
3768.5 A
measured at 11kV side
3. Setting Considerations Protection Scheme - Transformer 2 winding differential protection (87T) is applied as main protection to mostly protect the transformer from internal phase to phase fault. Very small earth fault current due to resistive grounding makes REF protection will not be effective and sensitive enough to protect the transformer from internal earth fault. Therefore, sensitive earth fault protection relay shall then be provided in the backup protection relay. Differential current setting (Idmin)
UAT2 F87T
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The usual practice for transformer protection is to set the bias characteristic to a value of at least twice the value of the expected spill current under through faults conditions. Spill current may arise from several conditions such as : - transformer phase shift and ratio error - current transformer ratio error - different CTs characteristic Idmin of 0.3 x Ibase is normally recommended to be applied. Zero-sequence current substraction A differential protection may operate unwanted due to external earth faults in cases where the zero sequence current can flow only on one side of the power transformer but not on the other side. This is the situation when the zero sequence current can not be properly transformed to the other side of the power transformer having a combined Y and D connection group. In such case, the zero sequence substraction function shall be set ON for Y winding and OFF for D winding.
4. Setting of analogue input Configure analogue inputs for TRM1 (-X401) : Set analogue current channels AI1
AI2
AI3
AI4
AI5
Ctprim
=
750
750
750
1250
1250
Ctsec
=
1A
1A
1A
1A
1A
CTStarPoint
=
AI6
AI7
AI8
AI9
Ctprim
=
1250
not used
not used
not used
Ctsec
=
1A
not used
not used
not used
CTStarPoint
=
To Object
not used
not used
not used
To Object To Object To Object
To Object To Object
Set analogue voltage channels AI10
AI11
AI12
Vtprim
=
not used
not used
not used
Vtsec
=
not used
not used
not used
5. Protection Settings 5.1. Setting of the Differential function data under T2WPDIF General settings. Winding 1 (W1)
Winding 2 (W2)
RatedVoltageW1
11 kV
RatedVoltageW2
6.3 kV
RatedCurrentW1
315 A
RatedCurrentW2
550 A
ConnectTypeW1
D
ConnectTypeW2
Y
TconfigForW1
No
TconfigForW2
No
CT1ratingW1
750 A
CT1ratingW2
1250 A
ZSCurrSubtrW1
Off
UAT2 F87T
ZSCurrSubtrW2
On
ClockNumberW2
11
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Note : All other setting parameters under general setting are not relevant. Use default values.
5.2. Differential Protection Setting (87T) under T2WPDIF Setting group: Operation
=
On
=
Off
=
0.2 *Ibase
Operation of SOTF feature SOTFMode Setting of differential current alarm IDiffAlarm
Setting of time delay of differential current alarm tAlarmDelay
=
10 s
Setting of minimum differential operating current IdMin
=
0.3 *Ibase
Setting of cross-over point between slope 1 and slope 2 EndSection1
=
1.25 Ibase
Setting of slope 2 stabilisation, Slope 1 has fixed stabilization SlopeSection2
=
40% *Ibias
Setting of cross-over point between slope 2 and slope 3 EndSection2
=
3.00 Ibase
=
80% *Ibias
Setting of slope 2 stabilisation SlopeSection3
Setting of minimum differential operating current for unrestraint step Idunre
=
20.00 *Ibase
Set the operation of Cross Blocking logic On-Off OpCrossBlock
=
On
Set the second and fifth harmonic stabilizing level when transformers are inside the zone I2/I1Ratio
=
15%
I5/I1Ratio
=
25%
Set the operation of Negative sequence differential protection NegSeqDiffEn
=
No
Setting of minimum negative sequence differential current level IMinNegSeq
=
0.04
=
60 deg
=
No
Setting of the Relay operating angles NegSeqROA Set the operation of Open CT detection OpenCTEnable
Note : All other setting parameters under this setting group are not relevant.
5.3. All other protection functions Operation
=
Off
6. Assignment of Binary Input BIM_3
UAT2 F87T
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BIM_3.BI01
: Bucholz Trip
BIM_3.BI02
: Rapid Pressure Relay Trip
BIM_3.BI03
: Oil Level Low Low Trip
BIM_3.BI04
: Protective Relay Trip
BIM_3.BI05
: Oil Temperature Trip
BIM_3.BI06
: HV Winding Temperature Trip
BIM_3.BI07
: Not used
BIM_3.BI08
: Trip from Generator Protection (59BG)
BIM_3.BI09
: Trip from Generator Protection (52G Mech Fail)
BIM_3.BI10
: Trip from GSUT Protection
BIM_3.BI11
: Reset Lockout
BIM_3.BI12
: Not used
BIM_3.BI13
: Not used
BIM_3.BI14
: Not used
BIM_3.BI15
: Not used
BIM_3.BI16
: Not used
7. Assignment of Binary Output BOM_4 BOM_4.BO01
: Transformer Differential Trip (T2WPDIF)
BOM_4.BO02
: Not used
BOM_4.BO03
: Trip from Generator Protection
BOM_4.BO04
: Trip from UAT Transformer's Protection (Bucholz etc)
BOM_4.BO05
: Not used
BOM_4.BO06
: Not used
BOM_4.BO07
: Not used
BOM_4.BO08
: Not used
BOM_4.BO09
: Transformer Differential Trip (T2WPDIF)
BOM_4.BO10
: Not used
BOM_4.BO11
: Trip from Generator Protection
BOM_4.BO12
: Not used
BOM_4.BO13
: Trip from UAT Transformer's Protection (Bucholz etc)
BOM_4.BO14
: Trip from GSUT Protection
BOM_4.BO15
: Transformer Differential Trip (T2WPDIF)
BOM_4.BO16
: Not used
BOM_4.BO17
: Trip from GSUT Protection
BOM_4.BO18
: Trip from Generator Protection
BOM_4.BO19
: Not used
BOM_4.BO20
: Not used
BOM_4.BO21
: Not used
BOM_4.BO22
: Not used
BOM_4.BO23
: Not used
BOM_4.BO24
: Not used
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Setting of UAT-2 Protection Relay Type REF615 F5051 - Backup OC & EF Protection 1. Terminal identification Station Name
KERAMASAN
Bay Name:
UAT-2
Relay Name
REF615
Relay serial No Frequency
50 Hz
Aux voltage
110 VDC
2. General Data Transformer:
UAT-2, two winding
Rated data :
Rated power
6 MVA
Voltage ratio
11 kV / 6.3 kV
W1 rated current - Ir1
315 A
W2 rated current - Ir2
550 A
Connection
Dyn11 (resistive grounding at Y winding)
p.u. Impedance
0.08
at Base
6
CT ratio W1 (11kV)
750 / 1 A
CT ratio W2 (6.3kV)
1250 / 1 A
Short circuit data : Three-phase short circuit current at 6.3kV busbar
9300 A
Phase to Ground short circuit current at 6.3kV busbar
11 A
Phase current contribution of UAT for 3-Ph fault at 6.3kV busbar
6580 A
measured at 6.3kV side Phase current contribution of UAT for 3-Ph fault at 6.3kV busbar
3768.5 A
measured at 11kV side Maximum tripping time for 6.3kV outgoing feeders
Instataneous
3. Setting Considerations Protection Scheme - Low-set phase overcurrent (51) protection at 11kV side are used as backup protection for differential (87T) and REF (87REF) protection. To maintain selectivity against downstream protection relays, a time delay of 0.5s on top of the downstream (6.3kV outgoing feeders) protection relays maximum operating time shall be introduced. - High-set overcurrent (50) at 11kV side is applied to protect the transformer during short circuit condition. Time delay shall be introduced to maintain selectivity from the fault which occur at the other parts of the system. UAT2 F5051
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- Sensitive earth fault/SEF (50S) of this relay will be applied at 6.3kV to detect earth fault condition at 6.3kV system. To maintain selectivity against earth fault protection relay at 6.3kV outgoing feeders, a time delay of 0.5s on top of the outgoing feeders tripping time is introduced. As the fault current is considerably small, a longer operating time is somehow still acceptable as long as not exceeding the rated time of NGR (10s). - To avoid unwanted operation of the overcurrent and earth fault protection due to inrush current during transformer startup, the inrush detection element INRPHAR is activated to give a blocking signal to the overcurrent & earth fault element when inrush current is detected.
4. Setting of analogue input Analog input settings, phase currents Secondary current
=
1A
Primary current
=
750 A
Amplitude corr. A
=
1
Amplitude corr. B
=
1
Amplitude corr. C
=
1
Nominal current
=
315 A
Rated secondary value
=
3 mV/Hz
Reverse polarity
=
0
Secondary current
=
1A
Primary current
=
1250 A
Amplitude corr.
=
1
Reverse polarity
=
0
{In} {False}
Analog input settings, residual currents
{False}
5. General System Setting Rated frequency
=
50 Hz
Phase rotation
=
Blocking mode
=
Bay Name
=
UAT2
IDMT saturation point
=
50
ABC Freeze timer
6. Setting of Three Phase Overcurrent Function (PHxPTOC) on 11 kV side 6.1. PHIPTOC (Instantaneous) Non group settings: Activation of the PHIPTOC function Operation
=
1
{ 1=On }
1
{ 1=1-out-of-3 }
Number of phases required for operate activation Num of start phase
=
Reset delay time
=
Reset delay time 20 ms
UAT2 F5051
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{ instantaneous }
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6.2. PHIPTOC (Instantaneous) Group settings: Start values is set at 130% of transformer short circuit current to get selectivity with faults at 6.3kV. Start Value PHHPTOC Start Value PHHPTOC
=
130% x 3768.5 A
=
4899.1 A
=
15.6 x In
Operate delay time Operate delay time
=
20 ms
{ instantaneous }
Note : All other setting parameters are not relevant. Default values can be used. 6.3. PHHPTOC (high-set) Non group settings: Activation of the PHHPTOC function Operation
=
5
{ 5=Off }
6.4. Setting of parameters for PHLPTOC (low-set) Non-group Setting Activation of the PHLPTOC function Operation
=
1
{ 1=On }
Number of phases required for activation Num of start phase
=
1 out of 3
Minimum operate time for IDMT curve Min. oper. Time
=
40 ms
Reset delay time
=
20 ms
Reset delay time Curve parameter for programmable curve Curve parameter A, B, C, D, E
=
default
{NA}
6.5. PHLPTOC (low-set) Group settings: Start values is set at 110% of transformer rated current. Start Value PHLPTOC
=
120% x 315 A
=
378 A
=
1.2 x In
=
1
Time multiplier
=
1
Time delay PHLPTOC
=
400
=
IEC Extremely Inverse
=
1
Start Value PHLPTOC Multiplier for scalng the start value Start value Mult Time multiplier setting (TMS)
{See note below}
Operate delay time ms
{Not relevant for inverse type}
Operating curve type Curve PHLPTOC Selection of reset curve type Type of reset curve
{Immediate}
Note : Time delayed PHLPTOC shall be set to operate in about 0.8 s at short circuit current to give safe margin to the transformer main protection and other UAT2 F5051
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unit protection at the other part of the system. Short circuit current
=
3768.5 A
=
12 x In
with start value
=
1.2 x In
and set time multiplier
=
1
for extremely inverse curve, the operating time t is : t
=
0.814 s
--> OK
7. Setting of Earth Fault Protection Function (EFxPTOC) on 6.3 kV side 7.1. EFIPTOC (Instantaneous) Non group settings: Activation of the EFIPTOC function Operation
=
5
{ 5=Off }
Note : All other setting parameters are not relevant. Default values can be used. 7.2. EFHPTOC (high-set) Non group settings: Activation of the EFHPTOC function Operation
=
5
{ 5=Off }
Note : All other setting parameters are not relevant. Default values can be used. 7.3. EFLPTOC (low-set) Non group settings: Activation of the EFLPTOC function Operation
=
1
{ 1=On }
Minimum operate time for IDMT curve Min. oper. Time
=
40 ms
Reset delay time
=
20 ms
Reset delay time Curve parameter for programmable curve Curve parameter A, B, C, D, E
=
default
{NA}
Selection for used Io signal Io signal Sel
=
1
{Measured Io)
7.3. EFLPTOC (low-set) Group settings: Start value for earth fault is set at 50% of maximum earth fault current. Start Value EFLPTOC
=
50% x
=
6A
=
0.02 x In
=
1
Time multiplier
=
0.1
Time delay EFLPTOC
=
0.9
Start Value EFLPTOC
11 A
{See note below}
Multiplier for scalng the start value Start value Mult Time multiplier setting (TMS) {See note below}
Operate delay time
UAT2 F5051
s
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Operating curve type Curve EFHPTOC
=
Definite time
=
1
Selection of reset curve type Type of reset curve
{Immediate}
8. Setting of Inrush Detector INRPHAR 8.1. Inrush Detector INRPHAR Group Setting Ratio of the 2nd to the 1st harmonic leading to restraint Start value
=
Operate delay time
=
0.15 %
Operate delay time 20 ms
8.2. Inrush Detector INRPHAR Non Group Setting Activation of the INRPHAR function Operation
=
Reset delay time
=
1
{ 1=On }
Reset delay time 20 ms
9. All other protection functions Operation
=
5
{ 5=Off }
10. Assignment of Binary Input Binary Input Terminal -X110_ BI1
: Not used
BI2
: Not used
BI3
: Not used
BI4
: Not used
BI5
: Not used
BI6
: Not used
BI7
: Not used
BI8
: Not used
BI9
: Not used
BI10
: Not used
Binary Input Terminal -X120_ BI1 BI2 BI3 BI4
: Reset lockout
11. Assignment of Binary Output
UAT2 F5051
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Binary Output Terminal -X100_ PO1
: Overcurrent Trip (Operation of PHHPTOC, PHLPTOC)
PO2
: SEF Trip
SO1
: Overcurrent Trip
SO2
: SEF Trip
(Operation of EFLPTOC)
PO3 PO4 Binary Output Terminal -X110_ SO1
: Overcurrent Trip
SO2
: SEF Trip
SO3 SO4
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4.
UAT #2 Protection Relay Test Record Sheet
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33
-
Protection Relay Test Equipment
:
Unit Aux. Transformer Differential Protection Relay RET670
Feeder
:
UAT #2
1.
2.
Reference Drawing Schematic Diagram
:
KPP-00-TPS-W-141
Transformer Bay
:
11kV 6.3kV UAT #2
General Data ABB
Manufacture : Type
3.
RET670
:
F87T
Designation : Sereal No.
:
Commissioning Tests 3.1 Visual Check a)
Physically Good ?
:
b)
Relay Healthy ?
:
c)
Mounting and wiring completed ?
:
3.2 Verifying the connections and the analog inputs Apply input signals as needed and verify that signals are measured correctly Injected Values Measured Secondary Values Primary
No.
Procedure
1
Inject current phase R → A101
A
A
2
Inject current phase S → A102
A
A
3
Inject current phase T → A103
A
A
4
Inject current phase R → A104
A
A
5
Inject current phase S → A105
A
A
6
Inject current phase T → A106
A
A
7
Inject current Neutral → A107
A
A
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Remarks
3.3 Deferential Protection Test (1) Check on HV side No.
Secondary Injection
Procedure
Items to be verified.
Remarks
1 Make sure that REF and OC / EF function are set to off. 2 Connect the test set for injection of 3 phase current to the current terminals of RET670 which are connected to the CT's on HV side of transformer
3 Increase the current in phase L1 until the protection operates and check
L1
a) the operating current (Iop)
a) Iop :
A
b) Trip contacts operation
b) Trip contact : Operate / Not operate
c) Alarm contact operation
c) Alarm contact : Operate / Not operate
4 Increase the current in phase L2 until the protection operates and check
L2
For stable condition, Trip not operated
a) the operating current (Iop)
a) Iop :
A
b) Trip contacts operation
b) Trip contact : Operate / Not operate
c) Alarm contact operation
c) Alarm contact : Operate / Not operate
5 Increase the current in phase L3 until the protection operates and check
L3
For stable condition, Trip not operated
a) the operating current (Iop)
a) Iop :
A
b) Trip contacts operation
b) Trip contact : Operate / Not operate
c) Alarm contact operation
c) Alarm contact : Operate / Not operate
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(2) Check on LV side
Secondary Injection
No.
Procedure
Items to be verified.
1
Connect the test set for injection of 3 phase current to the current terminals of RET670 which are connected to the CT's on LV side of transformer
2 Increase the current in phase L1 until the protection operates and check
L1
a) the operating current (Iop)
a) Iop :
A
b) Trip contacts operation
b) Trip contact : Operate / Not operate
c) Alarm contact operation
c) Alarm contact : Operate / Not operate
3 Increase the current in phase L2 until the protection operates and check
L2
a) the operating current (Iop)
a) Iop :
A
b) Trip contacts operation
b) Trip contact : Operate / Not operate
c) Alarm contact operation
c) Alarm contact : Operate / Not operate
4 Increase the current in phase L3 until the protection operates and check
L3
a) the operating current (Iop)
a) Iop :
A
b) Trip contacts operation
b) Trip contact : Operate / Not operate
c) Alarm contact operation
c) Alarm contact : Operate / Not operate
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Remarks
3.4 6.3kV Restricted EF Protection Test (1) Secondary Injection Procedure
No.
Items to be verified.
1 Make sure that Differential protection and OC/EF function are set to off. 2 Connect the test set for injection of neutral current to the current terminals of RET670 to which the NCT 20kV is connected
3 Increase the current in until the protection operates and check
L1
a) the operating current (Iop)
a) Iop :
A
b) Trip contacts operation
b) Trip contact : Operate / Not operate
c) Alarm contact operation
c) Alarm contact : Operate / Not operate
4.
Remarks :
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Remarks
Protection Relay Test Equipment
:
Backup OC & EF Protection Relay REF615
Feeder
:
UAT #2
1.
2.
Reference Drawing Schematic Diagram
:
KPP-00-TPS-W-141
Transformer Bay
:
11kV 6.3kV UAT
General Data ABB
Manufacture : Type
3.
RET615
:
F5051
Designation : Sereal No.
:
Commissioning Tests 3.1 Visual Check a)
Physically Good ?
:
b)
Relay Healthy ?
:
c)
Mounting and wiring completed ?
:
3.2 Verifying the connections and the analog inputs Apply input signals as needed and verify that signals are measured correctly Injected Values Measured Secondary Values Primary
No.
Procedure
1
Inject current phase R
A
A
2
Inject current phase S
A
A
3
Inject current phase T
A
A
4
Inject current phase N
A
A
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Remarks
3.3 Testing of the phase overcurrent protection The test is performed as a secondary test, by injecting current to the current energizing inputs with the setting values used during normal operation Procedure
No. 1
Items to be verified.
Inject the current (Ii) in phase L1 Ii = 2.5 * I > * rated current input I > setting :
2
Start of stage I > : . Trip of stage I > : . Operation time : s
* In
t > setting : s Inject the current (Ii) in phase L2 Ii = 2.5 * I > * rated current input I > setting :
3
Start of stage I > : . Trip of stage I > : . Operation time : s
* In
t > setting : s Inject the current (Ii) in phase L3 Ii = 2.5 * I > * rated current input I > setting :
4
Start of stage I > : . Trip of stage I > : . Operation time : s
* In
t > setting : s Inject the current (Ii) in phase L1 Ii = 8 * I >>> * rated current input I >>> setting :
5
Start of stage I >>> : . Trip of stage I >>> : . Operation time : s
* In
t >>> setting : s Inject the current (Ii) in phase L2 Ii = 8 * I >>> * rated current input I >>> setting :
6
Start of stage I >>> : . Trip of stage I >>> : . Operation time : s
* In
t >>> setting : s Inject the current (Ii) in phase L3 Ii = 8 * I >>> * rated current input I >>> setting :
Start of stage I >>> : . Trip of stage I >>> : . Operation time : s
* In
t >>> setting : s
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Remarks
3.4 Testing of the earth fault protection The test is performed as a secondary test, by injecting current to the current energizing inputs with the setting values used during normal operation Procedure
No. 1
Items to be verified.
Inject the current (Ii) in the earth fault energizing input : Ii = 2.5 * I0 > * rated current input
2
I0 > setting :
* In
t0 > setting :
s
Inject the current (Ii) in the earth fault
Start of stage I > : . Trip of stage I > : . Operation time : s
energizing input : Ii = 2.5 * I0 >> * rated current input
4.
I0 >> setting :
* In
t0 >> setting :
s
Start of stage I >> : . Trip of stage I >> : . Operation time : s
Remarks :
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Remarks
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