Good morning. I have a 2.5mw, 12.5kv/480-277v transformer with a %Z of 6.10. My understanding is the that maximum available fault on the secondary would be The transformers full load current divided by %z (Ifla/%z). The utility has provided a secondary symmetrical fault current of 56398amps which is greater than the transformer max fault current of 49378amps (3120amps/.061). Is this possible?. I am assuming they mean asymmetrical? Thank-you.
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Transformer Maximum Secondary Available Fault current 2
- Thread starter tlona
- Start date
davidbeach
Electrical
Or that 6.1% is +/- 7.5% so they might have used 5.64% and then thrown in a factor for the voltage being at the higher end of its band.
I’ll see your silver lining and raise you two black clouds. - Protection Operations
I’ll see your silver lining and raise you two black clouds. - Protection Operations
bacon4life
Electrical
David's suggestion seems possible since using an overvoltage of 106% gets really close to the provided value.
Alternately, instead of providing the fault current for that specific transformer, the utility may have provided the maximum fault current based on the transformer impedance range that they will accept from a manufacturer. For reference, IEEE 24.12.34 shows 5.75% as the preferred nominal impedance of a 2500 kVA transformer.
Alternately, instead of providing the fault current for that specific transformer, the utility may have provided the maximum fault current based on the transformer impedance range that they will accept from a manufacturer. For reference, IEEE 24.12.34 shows 5.75% as the preferred nominal impedance of a 2500 kVA transformer.
It is more likely the case that they are providing you the fault current with the minimum impedance in the range for the size and type of distribution transformer. It is very doubtful that the utility keeps that good of records on each transformer and it exact tested impedance.
That is what I have seen our company do.
That is what I have seen our company do.
No, asymmetrical current will be more than twice the symmetrical current.
Maybe a finger fumble on the keyboard (5.1% rather than 6.1%) and possibly rounding errors.
They may have introduced a factor to reflect the ASCC of a cold transformer.
This is something that I have not seen in literature but have encountered in the lab:
ASCC is tested and rated with the transformer at operating temperature.
The actual fault current of a cold transformer may be higher.
What to do:
The Cover Your ASSets approach is to accept and work with the higher figure.
If you have any equipment rated at 50kA, this may be a problem.
Been there, done that; The few times that I have been faced with a transformer ASCC rating higher than the equipment ASCC rating, I have included the current limiting effects of the impedance of the conductors from the transformer to the equipment.
That has always reduced the ASCC at the equipment enough to justified the use of said equipment.
Good luck.
--------------------
Ohm's law
Not just a good idea;
It's the LAW!
Maybe a finger fumble on the keyboard (5.1% rather than 6.1%) and possibly rounding errors.
They may have introduced a factor to reflect the ASCC of a cold transformer.
This is something that I have not seen in literature but have encountered in the lab:
ASCC is tested and rated with the transformer at operating temperature.
The actual fault current of a cold transformer may be higher.
What to do:
The Cover Your ASSets approach is to accept and work with the higher figure.
If you have any equipment rated at 50kA, this may be a problem.
Been there, done that; The few times that I have been faced with a transformer ASCC rating higher than the equipment ASCC rating, I have included the current limiting effects of the impedance of the conductors from the transformer to the equipment.
That has always reduced the ASCC at the equipment enough to justified the use of said equipment.
Good luck.
--------------------
Ohm's law
Not just a good idea;
It's the LAW!
- Thread starter
- #6
davidbeach
Electrical
Utilities lose nothing by somewhat overstating the available fault current. The source impedance can vary for many reasons, substation transformers get replaced with newer larger units, substations get built closer, switching ties two feeders together, etc., etc. The last thing anybody wants is for the utility to come back later and say that the fault current has gone up.
I’ll see your silver lining and raise you two black clouds. - Protection Operations
I’ll see your silver lining and raise you two black clouds. - Protection Operations
davidbeach, sorry my wording above, i meant fault through transformer gets reduced by grid impedance plus self impedance. 3120/(0.061+(480/56398))= 44892 which is less than transformer through fault capacity.
So why to match with utility SC value?
So why to match with utility SC value?
OP said:
The utility has given the fault current, not for the grid but for the 480 Volt secondary.
For utilization planning, it is often not safe to include grid impedance in fault current calculations.
You have no control over grid impedance and it may change.
The figure supplied by the utility is 14% high.
That is only serious if the designer planned to use equipment rated for an ASCC of 50kA.
Grid impedance was mentioned.
You may justify using the impedance of the secondary conductors from the transformer to the switch gear to reduce the ASCC at the equipment.
I have seen this done.
We had a central switch room with a lineup of 13 kV breaker cabinets.
Stretching for several hundreds of feet unit subs and power distribution centers.
Each unit sub was fed 13 kV by cable from the central switchgear.
The ASCC at the main switch gear was above the ASCC rating of the unit subs.
The specs called for a MINIMUM of 100 feet of cable to each unit sub to reduce the ASCC to below the rating of the unit subs.
The cables were run past the near subs and then doubled back.
--------------------
Ohm's law
Not just a good idea;
It's the LAW!
-
2
- #11
bacon4life
Electrical
Jay08-Depending on which kind of study being being performed, there are different fault values to ask the utility for:
-Equipment withstand rating: ignoring system impedance and using the smallest likely replacement transformer impedance gives conservative results. Addressing high fault currents is much cheaper during the design phase rather than after the utility changes something on the grid size that increases fault currents.
-Arc flash studies: These should use the actual fault current, as best as it can be determined. For arc flash studies, it may be more appropriate to use the transformer nameplate and include the typical system impedance.
Including the grid impedance is more impactful for larger transformers, whereas for small transformers grid impedance may have negligible impact on fault currents.
Although the utility cannot predict fault current under all possible grid reconfigurations, it is fairly simple for me to provide fault values for three configurations when customers want to check a range of fault currents for an arc flash study:
1)Normal configuration
2)Circuits tied together- Most utility switching is make-before-break, so there will be periods lasting from seconds to tens of minutes while there could be two different substations simultaneously feeding a location.
3)Default substation outage-I have records for the typical reconfiguration used to take each substation offline for maintenance. This configuration typically has much higher system impedance. It may not represent the absolute maximum possible system impedance, but it seems like a reasonable compromise for checking whether reduced fault current will have a step change in arc flash risk.
-Equipment withstand rating: ignoring system impedance and using the smallest likely replacement transformer impedance gives conservative results. Addressing high fault currents is much cheaper during the design phase rather than after the utility changes something on the grid size that increases fault currents.
-Arc flash studies: These should use the actual fault current, as best as it can be determined. For arc flash studies, it may be more appropriate to use the transformer nameplate and include the typical system impedance.
Including the grid impedance is more impactful for larger transformers, whereas for small transformers grid impedance may have negligible impact on fault currents.
Although the utility cannot predict fault current under all possible grid reconfigurations, it is fairly simple for me to provide fault values for three configurations when customers want to check a range of fault currents for an arc flash study:
1)Normal configuration
2)Circuits tied together- Most utility switching is make-before-break, so there will be periods lasting from seconds to tens of minutes while there could be two different substations simultaneously feeding a location.
3)Default substation outage-I have records for the typical reconfiguration used to take each substation offline for maintenance. This configuration typically has much higher system impedance. It may not represent the absolute maximum possible system impedance, but it seems like a reasonable compromise for checking whether reduced fault current will have a step change in arc flash risk.
davidbeach
Electrical
And that's based on the assumption that switches don't accidentally get left closed when they should be open...bacon4life said:
I’ll see your silver lining and raise you two black clouds. - Protection Operations
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