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 Post subject: Utility Short Circuit CurrentPosted: Fri Jul 06, 2007 4:46 pm

Joined: Wed Jul 04, 2007 7:58 am
Posts: 3
Anther Question. What if the study is performed for a specific short circuit current from the utility and they do something that changes it either higher or lower? How can you account for this unknown? Do they tell you if the changed things?

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 Post subject: Posted: Sun Jul 08, 2007 9:38 am

Joined: Fri Jul 06, 2007 9:06 am
Posts: 4
A good way to handle this is use alternate what if scenarios with larger and smaller utility short circuit currents. If you make changes to the study using larger and smaller values and the PPE conclusions remain the same, then it is not likely to be an issue. However if changing the utility current has a big change on the study results, then you need to determine is it a realistic scenario and perhaps approach the utility to see if that condition could ever exist.

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 Post subject: Posted: Mon Aug 06, 2007 10:50 am

Joined: Mon Aug 06, 2007 10:21 am
Posts: 35
Location: Ellijay, GA
Short circuit values

My experience thusfar has been that the value given by the utility company will remain relatively accurate unless they make large scales changes in the distribution system upstream from a particular property. I know that some people use the infinite bus method, which is a mistake in my opinion. Infinite bus is exactly that, the highest that it would be under any circumstance, determined by the transformer characteristics. The trouble is, if for some reason the actual Bolted Fault Current is lower at the time of the incident, the clearing times assumed at infinite bus will be too fast, which means the calculated energies will be too low, and the PPE the end user has on will be insufficient for the energy to which the are exposed.

A decent idea is to calculate Infinite Bus, then use a percentage of it, say 85%, as your available fault current, bolted fault current. whatever your software calls it. Just an aside too, I recommend doing some of your calculations manually, just to check the accuracy of your software. I have been in more than one facility where someone obviously enter erroneous data into their software, based on labels that call out Level 0 PPE for a 480 distribution panel fed directly off of a 3000 amp disconnect in the main switchboard. Possible, yes. Likely, I think not.

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 Post subject: Posted: Tue Aug 07, 2007 3:49 am

Joined: Fri Jul 06, 2007 9:06 am
Posts: 4
I believe the 85% is from IEEE 1584a and refers to 85% of the calculated/estimated arcing current from the forumlas. It is used to cover "unknowns" in the calculations. We run multiple scenarios of "what if" for infinte, normal conditions (from utility) and then we try various percentages of fault current to see if any of these values significantly change the PPE or incident energy results via changing device clearing time.

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 Post subject: Posted: Thu Oct 18, 2007 7:28 pm
 Sparks Level

Joined: Thu Oct 18, 2007 7:10 pm
Posts: 263
Location: NW USA
Some utilities will quote fault current for one size larger than actual transformer, and assuming infinite bus on the primary; with the idea that is conservative.

Such overstating of fault current migh have an adverse effect on calculated arc flash exposure if the true available fault current won't trip the instantaneous element.

I have only done calculations for industrial plants with their own medium voltage distribution, but if I were to encounter a grocery store, it might be wise to check what transformer really exists and assume a reasonable primary fault current of 5-10KA.

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 Post subject: Posted: Sat Jan 12, 2008 8:08 pm
 Arc Level

Joined: Thu Jan 10, 2008 8:49 pm
Posts: 510
Location: New England
While I agree with all said above, one has to remember that the utility is free to make upstream changes at anytime without notifying users. So if you base your calculations on a finite bus, you may wind up later changing 100's of arc flash labels if that changes your calculated values. As a gross estimate, the difference between finite and infinite bus on the primary will only reduce secondary fault current by 10% or thereabouts. In most cases this will not be enough to shift the trip curve out of the instaneous range and into the short or long time range. I think using an infinite bus, but at the same time being cognitive of any fault value that is not clearly into the instaneous portion of the curve would allow you to have a more consistent and longterm approach inside the plant without worrying about what the utility does.

Another question, and or option, would be whether or not to include motor contribution into the fault equation. Live work would most likely be done in a running plant. So motor contribution would increase fault current. But at the same time, routine live work could be done when the motor load is low. So in addition to finite versus infinite primary bus, we also need to consider full motor contribution to no motor contribution.

This is more art than science.

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 Post subject: Posted: Wed Jan 23, 2008 12:12 pm
 Sparks Level

Joined: Fri Nov 09, 2007 3:27 pm
Posts: 54
Location: Texas
haze10 wrote:
While I agree with all said above, one has to remember that the utility is free to make upstream changes at anytime without notifying users. So if you base your calculations on a finite bus, you may wind up later changing 100's of arc flash labels if that changes your calculated values. As a gross estimate, the difference between finite and infinite bus on the primary will only reduce secondary fault current by 10% or thereabouts. In most cases this will not be enough to shift the trip curve out of the instaneous range and into the short or long time range. I think using an infinite bus, but at the same time being cognitive of any fault value that is not clearly into the instaneous portion of the curve would allow you to have a more consistent and longterm approach inside the plant without worrying about what the utility does.

Another question, and or option, would be whether or not to include motor contribution into the fault equation. Live work would most likely be done in a running plant. So motor contribution would increase fault current. But at the same time, routine live work could be done when the motor load is low. So in addition to finite versus infinite primary bus, we also need to consider full motor contribution to no motor contribution.

This is more art than science.

Large industrial users usually have a wrtitten Contract with the Utility Company for multiple year service. It is easy to incorporate into the Contract a section that deals with the delivered Short Circuit Duty at the POS, to obligate the POCO to notify the user in advance of drastic changes and/or restrict the limits of such change. It could put the onus back on the POCO to limit the delivered SCD with reactors, etc. so that you don't exceed your equipment rating and not forced to spend money on your side.

Smaller users, good luck, until some legistlator takes up the banner and writes the above into law.

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 Post subject: Posted: Wed Jan 23, 2008 9:56 pm
 Arc Level

Joined: Thu Jan 10, 2008 8:49 pm
Posts: 510
Location: New England
I'm not sure about that. Utilities are either Regulated or Deregulated. If they are Regulated, they are the only source in town by law and as a public utility most States won't let them write contracts. The PUC (public utility commision) tries to avoid situations where similar users pay different rates. You may have rate classes by demand, but these are NOt contracts. In deregulated states you may have multiple generators who can write individual and competitive contracts for energy kwhr, but the Utility under the PUC still retains sole rights to distribution. And again, you can't write contracts with public utilities for distribution either.

If you have a really good account rep, and you are a major steel mill or oil refinery, you May get notice of off site changes by the Utility. But NFPA70E applies to all. You really think the Utility tells the account reps for 4 to 10 towns to call every 500KW to 5MW factory, hospital, office complex, etc, when they increase the size of a transformer at a 69KV substation, and tell them they will shortly be calculating and emailing the new X/R ratios to all uses?

If yes, I want to live in your State.

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 Post subject: Posted: Tue Feb 12, 2008 6:54 pm
 Sparks Level

Joined: Thu Oct 18, 2007 7:10 pm
Posts: 263
Location: NW USA
A utility would not, and could not, enter a contract that prohibits switching on a transmission grid, which would affect available fault current.

Up until Arc Flash became a concern, maximum fault current was quoted, to be conservative, with no promise that much fault current would be available.

I've worked on both sides of such numbers (utility rep and consulting engineer) and that is the way it is done in the Pacific NW, whether there is a special tariff for one industrial customer or not.

Gary B

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