Download - RT3b – André Smit, Siemens USA

Diapositive 1U.S. Distribution Feeder Automation Pilot Project
We have developed a peer-to-peer feeder automation system using WiMAX and IEC61850
During the project we needed to develop new protection settings for the feeder
We found that conventional settings of coordinated overcurrent relays was not possible
The relay setting groups could not be adapted to all the different operating scenarios we faced
We needed to find a solution that was less complicated with better performance
Frankfurt (Germany), 6-9 June 2011
Overcurrent protection operate and trip
Utility receives a fault notification from a customer experiencing an outage
Trouble desk dispatches a line crew to locate and isolate the fault
Crew restores service to unaffected sections of line
Crew effects repairs and restores feeder to normal operation
Outage time could be measured in hours
André Smit – U.S. – RT3b
FLISR
Circuit Breaker
Feeder Automation Pilot Project
Automating the Distribution Feeder
Operational Features to Consider
Isolate line sections for maintenance
Transfer to healthy source
Different curve shapes to deal with
Relay protecting power transformer does not have same shape curve as fuse designed to protect small distribution feeder load
Affect when lowering the Isc
The effect of moving 50 setting to indicate what happens when Isc is low.
Little room to coordinate with 51 element. Cannot coordinate with 50 element
as a higher Isc will cross both lines and both relays will trip.
Affect without low Isc being a factor
If low Isc not a factor, more space to coordinate with 51 element and still stay above fuse.
3 Reclosers with Tolerance Affect
Typical TCC curve showing high and low tolerances. (Used ±5% on pickup & time.)
Not considering CT tolerance. Illustrates need for space between curves.
1 Recloser
Only one recloser easy to fit between max fuse and feeder main breaker.
Better coordination (more space) between all four devices.
One set of TCC curves of 16 sets
Using four total setting groups
51 pickup markers
Largest downstream fuse
50 active only during reclose
Match curves
to data
by color
One set of TCC curves of 16 sets
Using four total setting groups
51 pickup markers
Largest downstream fuse
50 active only during reclose
Match curves
to data
by color
Difficulties in Coordinating Feeder
Reclosers are in series on feeder and not located on branches
Segments have different types of loads
Curves for transformers are not as steep
Demand changes by time of day and season and differently for each segment
Melt/time characteristics for distribution fuses do not fit closely with substation transformer protection upstream
Original system designed without new switching points
Difficulties in Coordinating Feeder
High source impedance + long line = very low fault currents
Substations located at the ends of the line, so source impedance is usually high; a long feeder—the best candidate for automation—adds to the impedance
Severe limits caused by existing minimum current settings and low short circuit current (Isc)
Low available Isc limits use of 50, or 50 with definite time
Must include considerable allowance for high-impedance branch line faults causing Isc to be even lower
Inrush current could be five times nominal current, therefore precluding the use of 50 element when Isc is low
How do we deal with these difficulties to protect an Automated Feeder?
Setting Sheets
Siemens Energy, Inc.
Protection & Substation Automation
Equiva-
Ratio (to 1)
P1 Right Forward A 2.40 ANSI-EI 3.25 7.50 0.10 1.20 ANSI-EI 5.00 6.11 0.10 P2, P3, or P4 open 120
P1 Right Reverse B -- -- -- -- -- -- -- -- -- -- Not used --
P1 Right Forward C 3.00 ANSI-EI 2.58 7.92 0.10 1.25 ANSI-EI 4.48 6.11 0.10 P5 open, P2 thru P4 closed 120 P1 Right Reverse D -- -- -- -- -- -- -- -- -- -- Not used --
P2 Right Forward A 0.28 ANSI-EI 0.50 1.15 0.15 0.125 ANSI-EI 0.90 0.88 0.15 P3 or P4 open 800
P2 Right Reverse B 0.25 ANSI-EI 0.475 0.50 0.15 0.081 ANSI-EI 0.85 0.375 0.15 P1 open 800
P2 Right Forward C 0.39 ANSI-EI 0.475 1.15 0.15 0.14 ANSI-EI 0.925 0.88 0.15 P5 open, P3 and P4 closed 800 P2 Right Reverse D -- -- -- -- -- -- -- -- -- -- Not used --
P3 Right Forward A 0.23 ANSI-EI 0.50 0.78 0.15 0.088 ANSI-EI 0.80 0.56 0.15 P4 open 800
P3 Right Reverse B 0.32 ANSI-EI 0.45 0.59 0.15 0.11 ANSI-EI 0.90 0.48 0.15 P1 open, P2 closed 800
P3 Right Forward C 0.32 ANSI-EI 0.45 0.78 0.15 0.11 ANSI-EI 0.90 0.56 0.15 P5 open, P4 closed 800
P3 Right Reverse D 0.24 ANSI-EI 0.45 0.59 0.15 0.088 ANSI-EI 0.90 0.48 0.15 P2 open 800
P4 Left Forward A 0.39 ANSI-EI 0.475 0.60 0.15 0.14 ANSI-EI 0.925 0.49 0.15 P1 open, P2 and P3 closed 800
P4 Left Reverse B 0.25 ANSI-EI 0.475 0.50 0.15 0.081 ANSI-EI 0.85 0.37 0.15 P5 open 800
P4 Left Forward C 0.33 ANSI-EI 0.475 0.60 0.15 0.125 ANSI-EI 0.925 0.49 0.15 P2 or P3 open 800
P4 Left Reverse D -- -- -- -- -- -- -- -- -- -- Not used --
P5 Left Forward A 3.00 ANSI-EI 2.58 5.42 0.10 1.25 ANSI-EI 4.48 4.83 0.10 P3 and P4 closed 120
P5 Left Reverse B -- -- -- -- -- -- -- -- -- -- Not used --
P5 Left Forward C 2.65 ANSI-EI 2.90 5.40 0.10 1.20 ANSI-EI 4.48 4.83 0.10 P3 or P4 open 120
P5 Left Reverse D -- -- -- -- -- -- -- -- -- -- Not used --
NOTES:
1) Following 7SR224 settings are OFF: "DTL" function, Tres (Reset Setting), Td (Delay Setting -- a fixed time adder)
2) "Right" is towards a higher Device Number. Normal topology is with P3 open and all others closed.
3) 7SR224 "Group" designator is 1 to 8. For 7SJ64 and 7SJ80 it is A - D. In this document, 1 = A, etc.
4) Positions of devices not shown do not affect that group selection. It is assumed that at least one of the devices will always be open.
5) If substations are paralleled, which is not recommended with current protection, all devices revert to Group A.
6) 7SJ64 & 7SJ80 relays use designation "N" for ground fault detection functions. 7SR224 uses "G." The "-1" indicates TCC segment within that Group and function.
7) 50 functions in 7SJ64 & 7SR224 relays enabled only after first reclose. Disabled after (1) lockout or (2) timeout of reset delay following successful reclose. Other settings
on that same device are not affected by reclose unless system reconfigures topology. See Tables 2 & 3.
8) 7SJ80 relay overcurrent settings in Table 2. Those settings are used for logic control -- fault direction, trip inhibit, and SICAM operation.
Three-Phase and Single-Line-to-Ground Overcurrent Trip Settings
For 7SJ64 (P1 & P5) and 7SR224 (P2, P3, & P4) Relays - Table 1 See Table 2 for Inrush Restraint & Line Differential Settings
10.pdf
Siemens Energy, Inc.
Protection & Substation Automation
Equiva-
(Note 2) (Note 3) (Note 9) (Notes 4 & 5)
P1 Right Forward A 7.50 6.11 15% 9.00 Not used P2, P3, or P4 open 120
P1 Right Reverse B -- -- -- -- -- Not used -- P1 Right Forward C 7.92 6.11 15% 9.50 Not used P5 open, P2 thru P4 closed 120
P1 Right Reverse D -- -- -- -- -- Not used --
P2 Right Forward A 1.15 0.88 15% 1.38 0.28 P3 or P4 open 800
P2 Right Reverse B 0.50 0.375 15% 0.60 0.25 P1 open 800 P2 Right Forward C 1.15 0.88 15% 1.38 0.39 P5 open, P3 and P4 closed 800
P2 Right Reverse D -- -- -- -- -- Not used --
P3 Right Forward A 0.78 0.56 15% 0.94 0.23 P4 open 800
P3 Right Reverse B 0.59 0.48 15% 0.71 0.32 P1 open, P2 closed 800
P3 Right Forward C 0.78 0.56 15% 0.94 0.32 P5 open, P4 closed 800
P3 Right Reverse D 0.59 0.48 15% 0.71 0.24 P2 open 800
P4 Left Forward A 0.60 0.49 15% 0.72 0.39 P1 open, P2 and P3 closed 800
P4 Left Reverse B 0.50 0.37 15% 0.60 0.25 P5 open 800
P4 Left Forward C 0.60 0.49 15% 0.72 0.33 P2 or P3 open 800
P4 Left Reverse D -- -- -- -- -- Not used --
P5 Left Forward A 5.42 4.83 15% 6.50 Not used P3 and P4 closed 120
P5 Left Reverse B -- -- -- -- -- Not used --
P5 Left Forward C 5.40 4.83 15% 6.48 Not used P3 or P4 open 120
P5 Left Reverse D -- -- -- -- -- Not used --
NOTES:
Notes 1 through 6 - See Table 1.
7) 50P-1 and 50N-1 are used to trip breaker or recloser if current exceeds those set points when closing from SICAM control
(auto-reconfigure or manual), with Inrush Restraint in effect. For reclosers, these are same settings as in 7SJ224 but are in 7SR80.
8) Inrush Restraint settings -- 2nd Harmonic is percentage of total RMS value of inrush current through device, restraining all 50 & 51
tripping of that device. I Max is Maximum RMS Current for restraint action. This value is 1.2 x 50P-1 setting for that device and group.
Cross-block function is used so that 2nd harmonic in any line causes restraint of all lines. (Second harmonic content in current is
present when transformers energize. This function in relays is called "Inrush Detection.")
9) 50P-2 is used with jump detection / line differential to inhibit second device upstream from fault. Settings are same as 51P-1 for
7SJ224 relays in reclosers. There is no restraint upstream from Breakers P1 & P5.
Three-Phase and Single-Line-to-Ground Overcurrent Settings
For Inrush Restraint and Line Differential Protection for All Relays - Table 2
(Note 8)(Note 7)
Our Solution
Detect and isolate faults with a differential (87L) function
Activate a 50/51 overcurrent curve on one device end and reclose on fault
87
87
Performance
Automating the Distribution Feeder
Transformer
Questions
Settings Phase
ANSI Extremely Inv. 2.58
50-1 Delay (0-60 Sec) 0.1
ComponentName P2 50/51
Settings Phase
50-1 Delay (0-60 Sec) 0.15
Settings Phase
50-1 Delay (0-60 Sec) 0.15
Settings Phase
50-1 Delay (0-60 Sec) 0.15
MAX FU 1-2
KEL 69KV T1B-OC
Settings Phase
50-1 Delay (0-60 Sec) 0.1
Settings Phase
50-1 Delay (0-60 Sec) 0.15
Settings Phase
50-1 Delay (0-60 Sec) 0.15
Settings Phase
50-1 Delay (0-60 Sec) 0.15
MAX FU 1-2
TCC Name: BKR KEL 69KV THRU TO OPEN P5 Current Scale x 1 Reference Voltage: 25000
March 31, 2011 9:54 PM Siemens Energy Automation, Wendell, NC
Existing devices shown for reference. Instantaneous enabled only during reclose cycle.