So in previous threads, we've discussed times when we model installed utility feeds instead of utility-provided "worst case" information.

That said, when a Utility's provided "worst case" AFC scenario is based off the transformer actually installed, how do you all generally go about matching that supplied AFC data?

Local utilities generally provide a form showing the KVA and impedance of the installed transformer (as well as the "worst case" transformer they might possibly install at that location), and conductor size, quantity, and length to the service. They also provide their calculated 3LL and 2LL max fault current, voltage drop, and flicker.

In the past, I've created my models with a generic utility and input the installed utility transformer. By fiddling with the utility info, I've been able to match the Utility's supplied AFC calculations at the meter base. However, on a current study, I've only been able to match AFC by tweaking the Utility transformer's impedance, and I still can't get both the 2LL and 3LL to match Utility at the same time.

So would you say tweaking the Utility transformer to match AFC is an acceptable solution, or are there problems with that? Is there a better method to match AFC that doesn't involve changing impedance? How important is it that both 2LL and 3LL AFC match under the same model? Is it more important to match one over the other, and if both are necessary to be accurate, does that mean modelling them separately all the way through the reporting process?

The follow-up to this is that manipulating Utility transformer impedance to get a matching AFC at the meter base means that the 25kAIC rating of some breakers downstream is not enough to pass minimum standards. Modelling the actual transformer values provided puts those downstream devices well within the available limits but doesn't match the Utility's provided AFC at the meter base.

I used to do what you are prescribing when I had POCO transformer data but only the secondary fault current info.. I decided it would be better just to not model the primary or POCO transformer and just use the secondary data at the secondary voltage as the utility rather than guess at primary available to get as close as I could to the supplied secondary data.

Thanks! Just so I know I'm tracking, are you saying you set up the supplied voltage and available fault current from the secondary side of the Utility transformer as the Utility Service?

Yes. I have almost this exact situation on a current project, except the POCO gave me even less information so I have to run with what they are willing to provide. I know the primary voltage and the pad mount nameplate but they won't provide the primary fault current data. Only secondary 3 phase data. No SLG or X/R data. See below.

NOTE: THIS IS NOT ADVICE OR A GUARANTEED TO BE ACCURATE OR APPROPRIATE WAY OF HANDLING A SITUATION LIKE THIS. IT IS ONLY ONE EXAMPLE OF HOW I AM CHOOSING TO HANDLE IT IN ONE PARTICULAR INSTANCE.

Very interesting! I never receive X/R data from the utility. It's also interesting that they're giving you info from the load side of the utility transformer...the local utilities I deal with tend to give fault information at the meters, which are always on or near the main service gear, and 25'-300' from the utility transformer. They also give service conductors, which since we can usually see where they terminate on the service equipment, is not always correct.

I see that you mention using 8.0 as a default X/R. Is that a generic default number you're pulling from somewhere, or something based on a standard you see from Utilities you deal with?