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Digital Energy
Multilin
Problems and Solutions of
Line Differential Application in
Cable Transformer Protection
Jorge Cardenas. GE Digital Energy
Mahesh Kumar. GE Digital Energy
Jesus Romero. RasGas
•CIGRE 7-10 September 2009, Moscow
Application problem in differential Cable+Transformer
Transformer Inrush phenomena affects the operation of the
differential protection in the same way as in case of a Power
Transformer. In the classical approach, an inhibition or blocking
action based on the harmonic (usually 2nd harmonic) content on the
differential algorithm, is normally used.
Because differential protection is practically disabled during some
time after the energization, a complementary protection is needed
to disconnect the circuit if a fault is produced during that time
Another problem is the Inrush phenomena after the voltage
recovery during external three-phase or phase-to-phase faults..
CIGRE 7-10 Sept 2009 Moscow
September, 2009
•2
On-line diagram and Line Differential Protection scheme
Karama (Utility)
SIMPLIFIED ON-LINE DIAGRAM
Short circuit current
contribution = 20 kA
33 kV
Network
composed by
other three
85L relays on
a second 33
kV Busbar.
The
arrangement
is similar to
RELAY B and
additionally
there are
other feeders
connected to
motor loads
SS-73
132 kV
X = 16%
3x60/75 MVA
132/34.5 kV
RELAY B
X = 11%
4x44/55 MVA
135/11 kV
X = 16%
60/75 MVA
138/33 kV
33 kV
33 kV
11.0 kV
1000/1A
87L
X = 10%
44/55 MVA
34.5/11 kV
47.6 Ohm
ZIG
ZAG
R = 0.132 Ohm.
XL = 0.2957 Ohm
XC = 861.5 Ohm
11.0 kV
X = 12%
4x45 MVA
35/11.5 kV
57.5 MVA
X’d = 29,5%
X’’d = 16.8%
11.0 kV
5.28 Km
f.o. link
f.o. link
4 x 57.5 MVA
X’d = 29,5%
X’’d = 16.8%
4 x 50.3 MVA
X’d = 29,5%
X’’d = 16.8%
TRAIN 1& 2
R = 0.0828 Ohm.
XL = 0.1266 Ohm
XC = 2602 Ohm
2.11 Km
TR-7341A
X = 8%
10/12.5 MVA
33/6.9 kV
TR-7241A
X = 10%
25/30 MVA
33/6.9 kV
400 A
400 A
f.o. link
3100/1A
87L
1200/1A
87L
6.6 kV
M
6.6 kV
M
CIGRE 7-10 Sept 2009 Moscow
September, 2009
•3
Initial Protection Scheme
As Current Differential Relays installed in the plant have not
specific functions to prevent Transformer Inrush phenomena,
initially a logic based on setting group change was implemented to
avoid a non-desirable trip when the Line is energized (there are no
CB´s on the 33 kV receiving end of the individual Power
Transformers) and interposing CT’s are used at LV side to correct
the vectors similar to conventional transformer differential
protection. At time zero, the relays work with a high pickup
differential settings (typically 2.0 p.u.) and with a time delay (800
ms) after the CB close, the pickup is changed to a lower value
(typically 0.3 p.u.).
CIGRE 7-10 Sept 2009 Moscow
September, 2009
•4
Initial Logic to prevent false trip during energization
TIMER 16
CB OFF ON (L5A)
0 msec
S
CB ON ON (L5C)
OR
30 msec
SET GR2 ACT (VO12)
Latch
(R-dominant)
TIMER 7
800 msec
0 msec
R
Relays (UR from GE) installed allows on-line logic change of
the differential pickup level. Setting Group is changed in less
than 2.5 ms. This is the maximum additional delay expected
to trip on internal faults.
CIGRE 7-10 Sept 2009 Moscow
September, 2009
•5
Problems with the Initial Protection Scheme
• Definition was correct, but incomplete. Logic only contemplates
Energization, but no Inrush after voltage recovery.
• Pickup setting were too low for Energization, particularly on 6.6
kV. Side
• No complementary protection was active to prevent faults during
the energization, only TOC as backup.
CIGRE 7-10 Sept 2009 Moscow
September, 2009
•6
Critical Irest vs Idiff in 6.6 kV with Actual Setting
Slope 2
Slope 1
p.u. Peak 33 kV
2
2,3
3
4
5
7
8
10
12
p.u. RMS 33 kV
0,707113562
0,813180597
1,060670344
1,414227125
1,767783906
2,474897469
2,82845425
3,535567812
4,242681375
p.u. RMS 6.6
2,814311979
3,236458775
4,221467968
5,628623957
7,035779946
9,850091925
11,25724791
14,07155989
16,88587187
Pickup
2
2
2
2
2
2
2
2
2
Slope
0,4
0,4
0,4
0,4
0,4
0,4
0,4
0,4
0,4
Irest^2
9,68967507
10,2345953
11,8017689
14,7587003
18,5604692
28,6985197
35,0348012
50,2418769
68,8283027
Idiff^2
7,92035191
10,4746654 Trip limit
17,8207918
31,6814076
49,5021995
97,0243109
126,725631
198,008798
285,132669
Break point = 6
CIGRE 7-10 Sept 2009 Moscow
September, 2009
•7
Changes Recommended
1. Switch on to fault and distance protections implemented in Setting Group 2 to
provide backup to current differential protection during transformer energizing or
when operation is blocked due to loss in communications. This new setting
effectively covered all 3 phase and phase to phase faults up to 120% of the line.
Ground TOCs in 33KV and 6.6KV provide the protection for phase to ground
fault as per existing settings. The current differential pickup is adjusted to avoid
unwanted trip due to inrush currents.
2. Setting Group 3 is introduced in the scheme to provide the correct setting for
inrush current produce during voltage recovery after the isolation of an external
fault. The new setting used distance protection to cover 3 phase and phase to phase
internal faults. Ground TOCs in 33KV and 6.6KV cover phase to ground faults as
the actual coverage is done with Setting Group 1.
3. Distance protection is implemented in Setting Group 1 to cover all faults up to
transformer HV windings, this also provided backup to current differential
protection when the operation is blocked due to loss of communications.
CIGRE 7-10 Sept 2009 Moscow
September, 2009
•8
Changes Recommended (cont.)
4. With the existing or proposed current differential settings in
Group 1, it was found out that for loads in 33KV of more than 200A
approximately, differential protection does not operate on phase to
ground faults. This is due to the increased in the restraint current
magnitudes with increased load currents. Enabling of distance Gnd
Z2 proved to address this problem plus the existing 33KV directional
Ground TOC.
It has also been noted that only trip on current differential is
programmed for circuit breaker inter trip. A new inter trip logic
based also in the other protection functions (Distance, SOFT and
Ground TOC) has been tested and it is recommended for
implementation.
The Solutions Proposed were validated initially with test on RTDS ans
later with tests in Field.
CIGRE 7-10 Sept 2009 Moscow
September, 2009
•9
Functions usage
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September, 2009
•10
ON-LINE DIAGRAM USED IN THE VALIDATION ON RTDS
230 MVA
X = 4.34%
X0= 3.53%
SIMPLIFIED ON-LINE DIAGRAM
132 kV
230 MVA
SS-73
X = 16%
3x60/75 MVA
132/34.5 kV
RELAY B
33 kV
=
X = 20.5%
33 kV
85L
1000/1A
2
2 uf
1
X = 29.8%
47.6 Ohm
ZIG
ZAG
R = 0.132 Ohm.
XL = 0.2957 Ohm
XC = 861.5 Ohm
Equivalent capacitance
from the other feeders 5.28 Km
f.o. link
f.o. link
57.5 MVA
R = 0.0828 Ohm.
XL = 0.1266 Ohm
XC = 2602 Ohm
2.11 Km
4
3
TR-7241A
X = 10%
25/30 MVA
33/6.9 kV
TR-7341A
X = 8%
10/12.5 MVA
33/6.9 kV
400 A
400 A
5
85L
1200/1A
6
6.6 kV
f.o. link
7
85L
3100/1A
6.6 kV
M
CIGRE 7-10 Sept 2009 Moscow
September, 2009
•11
Validation of the model for Inrush tests
a) Phase A
b) Phase B
CIGRE 7-10 Sept 2009 Moscow
c) Phase C
September, 2009
•12
Breaker Trip time estimation from a Real Event
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September, 2009
•13
New Setting Group Proposed for Inrush recovery after external faults
Modifications in Group 2 were as follows:
Relay at 33 kV: Change the slope 2 to 70% and the Breakpoint to 2
Relays at 6.6 kV: Raise the pickup to 4.0, slope 2 to 70% and Breakpoint to 2
p.u. Peak 33 kV
2
3
4
5
7
8
10
12
p.u. RMS 33 kV
0,707113562
1,060670344
1,414227125
1,767783906
2,474897469
2,82845425
3,535567812
4,242681375
p.u. RMS 6.6
2,814311979
4,221467968
5,628623957
7,035779946
9,850091925
11,25724791
14,07155989
16,88587187
Pickup
4
4
4
4
4
4
4
4
Slope
0,7
0,7
0,7
0,7
0,7
0,7
0,7
0,7
Irest^2
37,1746299
43,6429173
52,6985197
64,341437
95,3892165
114,794079
161,365748
218,286677
Idiff^2
7,92035191
17,8207918
31,6814076
49,5021995
97,0243109 Trip limit
126,725631
198,008798
285,132669
Break point = 2
Critical Irest vs Idiff in 6.6 kV modified Setting of Group 2
CIGRE 7-10 Sept 2009 Moscow
September, 2009
•14
New Setting Group Proposed for Inrush recovery after external faults
It was decided an intermediate setting, higher than the maximum peak estimated according to
table 1 (3,2 p.u.). Settings on relays at 33 kV and 6.6 kV were as follows:
p.u. Peak 33 kV
2
3
3,4
4
5
7
8
10
12
p.u. RMS 33 kV
0,707113562
1,060670344
1,202093056
1,414227125
1,767783906
2,474897469
2,82845425
3,535567812
4,242681375
p.u. RMS 6.6
2,814311979
4,221467968
4,784330363
5,628623957
7,035779946
9,850091925
11,25724791
14,07155989
16,88587187
Pickup
2
2
2
2
2
2
2
2
2
Slope
0,7
0,7
0,7
0,7
0,7
0,7
0,7
0,7
0,7
Irest^2
13,1746299
19,6429173
22,9546805
28,6985197
40,341437
71,3892165
90,7940787
137,365748
194,286677
Idiff^2
7,92035191
17,8207918
22,889817 Trip limit
31,6814076
49,5021995
97,0243109
126,725631
198,008798
285,132669
Break point = 2
CIGRE 7-10 Sept 2009 Moscow
September, 2009
•15
Logic Implemented to complement the Line Differential Algorithm
Logic to change to setting group 2 in 33 kV relay
DIRECT I/P 1-1 ON
Logic to change to setting group 2 in 6.6 kV relays
Logic to change to setting group 3 in 33 kV relay
Logic to change to setting group 3 in 6.6 kV relays
CIGRE 7-10 Sept 2009 Moscow
September, 2009
•16
Energization tests in the worst close angle condition after the new
logic implementation
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September, 2009
•17
Inrush voltage recovery tests after the new logic implementation
A = Relay + Output contact operation = 30 ms
B = Breaker Operation = 51 ms
C = Margin = 30 ms
Inrush after voltage recovery.
Operation considering load condition,
that is trip on external fault caused by an
instantaneous protective relay. 3PH fault on 1
CIGRE 7-10 Sept 2009 Moscow
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•18
Cable and Transformers Fault tests
PH_PH fault on pos 5.
3PH in pos 7.
PH-PH in Pos 7.
External 3PH fault on 6.
CIGRE 7-10 Sept 2009 Moscow
September, 2009
•19
Cable and Transformers Fault tests
Direct trip by Ground TOC and Distance during internal PH_G fault on 4.
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September, 2009
•20
Conclusions
• Proposed solution makes the energization of transformers without any
nuisance trips and proved several time for last 2 years. As these feeders
were crucial in LNG production of Rasgas, this solution helped them to
save time and money with an improved reliability.
• The solution implemented has been be extended to any other similar
substations w/o additional hardware, nor modifications on it.
• The numeric technology in the multifunction relays give us many tools
to implement new solutions to problems that in the past were only
possible to solve using another techniques as the second harmonic
restrain to prevent a false trip during transformer energization. We
have demonstrated that other possible schemes are also possible
maintaining a similar level of reliability and security as the traditional
ones.
• The use of the RTDS has allowed as a very good approach with the
problems encountered in field, helping in test new solution for Differential
Application on schemes composed by cables + transformers.
CIGRE 7-10 Sept 2009 Moscow
September, 2009
•21