I am looking for opinions and looking for information.

First, let me preface this by saying it's been my experience that elevated Incident Energy (IE) levels are found on the line side of the main disconnect on a secondary service and there's very little we can do about that particular location as the Utility has control over that equipment and overcurrent protective devices that serve the building. That said, we have lots of control beyond that main disconnect enclosure.

I've been recently asked to respond to a customer that is insistent that the simple operation or even coming near to a brand new, 5000A main breaker with > 40 cal/cm^2 IE level is an unacceptable hazard to their staff who merely intend on operating the breaker, nothing else. I can surmise from their correspondence that they feel they can not operate that main breaker for fear of it exploding. I'd like to note that part of that fear comes from a Schneider commissioning rep that saw the AF tag on the gear and commented that this was dangerous and would not get near it, even to operate the main breaker.

By the by, for that very same main, we've provided remote operation, this customer has "value-engineered" out IR ports, and we've included remote operation (currently 6' away) and the balance of the building is rife with AF mitigation.

Pretend for a moment that I am ignorant on AF matters and you would have to explain the idea that it is safe to operated a properly installed, well maintained or even brand new main breaker to them - how would you do that?

How would you respond to "why is the IE level elevated at the main breaker enclosure"?

Finally, I'd like to ask if it is your experience as well if you have little control over the IE levels at the main breaker enclosure as there is little if any control over the equipment that feeds and protects the building.

NFPA 70E 130.2(A)(4) refers to this as Normal Operation. To be considered "Normal Operation" all conditions below must be satisfied. This is a clarification of the "interaction" language that was introduced in the 2009 Edition of NFPA 70E which began the confusion and triggered the question: Is operating a circuit breaker "interaction" requiring PPE?

(4) Normal Operating Condition. Normal operation of electric equipment shall be permitted where a normal operating condition exists. A normal operating condition exists when all of the following conditions are satisfied:
(1) The equipment is properly installed.
(2) The equipment is properly maintained.
(3) The equipment is used in accordance with instructions included in the listing and labeling and in accordance with manufacturer’s instructions.
(4) The equipment doors are closed and secured.
(5) All equipment covers are in place and secured.
(6) There is no evidence of impending failure.

Someone needs to make the judgement if operating the subject circuit breaker is "Normal Operation"



I'm not sure I would say "safe" It is a low "likelihood of occurrence" which is text taken from NFPA 70E Table 130.5(C). This table uses the same 6 criteria above and also lists if there is a Likelihood of Occurrence - Yes/No for specific equipment/tasks.

My personal view is it is always good to wear some form of arc rated protection even when there is low likelihood of occurrence. Remote operation is a great way to perform the task. However the absence of voltage must still be verified (perhaps downstream of the main) which itself is considered live working.

A simple analogy: You buy a new car. Is it reasonable to say you should drive 10 MPH because the tire may fall off? If it is performing "normal" of course the tire should not fall off. But is there a guarantee this would never happen? No. There is always some risk - even if minimal.

As indicated in the other responses, normal operation may be considered acceptable if the equipment is in good condition and there is no reason to suspect that it is "not" in good condition. However, assessing it is in good condition may not be an exact science and anything mechanical may operate incorrectly for a myriad of reasons... so what are the steps that can be taken to mitigate risk associated with the hazard and the operation when you have no access to the protection on the transformer primary? Some things to ponder from a PtD perspective.
Distance - Remote operation, I believe you indicated the operator can operate from 6 feet away, and I would I be correct to assume not directly in front?
Equipment enclosure - You made no mention of the equipment being arc resistant, but even if not, as long as the enclosure is properly latched it should offer some undefined level of thermal protection, specially if there are not lots of ventilation openings used to cool the equipment pointing at the worker!
AF calculation are probably made using HCB exposure, when the CB is in place that is not the actual exposure and the bulk of the CB would absorb some energy, again, unqualified and not guaranteed in any way.
Operator can still wear PPE and if the distance put him far enough away the thermal protection required may be more manageable.
AVT installation - So absence of voltage can be ascertain after the MCB is opened via fixed tester without opening panels. If doing this make sure it is a UL listed AVT not a UL listed voltage sensor!
Barriers around the line side of the MCB, to minimize the probability of an arc, or the probability of the expansion of an arc to the line side
As far as protection - A crowbar device can be used so that it clamps down the voltage and stops an AF event. The crowbar can be connected on the load side of the main CB. If the CB has instantaneous protection the CB will operate upon sensing the bolted fault current. Then it will remove the crowbar from the circuit. But for ~ 2 cycles or so the system will be shorted and the arc would have been extinguished. But it the arc was caused on the primary side of the MCB it may come back when the MCB opens and voltage is re-established. It is improbable primary fuses would have melted. Unluckily this solution has a "probability" of working but there would be no guarantees. Since crowbars have a defined limited withstand they cannot be allowed to handle fault current indefinitely.

So there are things that can be done but they tend to address behavior or provide an undefined degree of probabilistic protection, not an absolute reduction in AF energy... This seems inadequate, but at some point all AF protection has some degree of probability attached to it! Will an over-current device work properly, was the AF study done properly, was the data used for the study correct? Did the worker use proper PPE, did he follow proper procedures, etc.

The above posts seem to cover the standard's approach, but there are other questions...

Is the new CB a Schneider unit? If so, with the Schneider commissioning staff having reservations about operating the CB, I would have questions about why the reservations, and whether the CB is fit for purpose. If it isn't a Schneider unit, is the Schneider guy just being negative about someone else's gear because it "isn't Schneider"?

Is the new CB designed and type tested for the calculated incident energy? If not, was the incident energy considered as part of the purchase, and was there an alternative device available that would be more suited. If so, perhaps a copy of the nameplate (official manufacturer copy) with those type tested ratings on it installed next to the AF label may help.

If the incident energy is so high that there is no device suitable for containing the fault, can the utility be held accountable for not providing a suitable service? The installation of an upstream device (like high interrupting fast acting fuses) may help to reduce the incident energy at the new CB, thus providing a safer service.

If the issue is there is no visible break when remotely operating the CB, perhaps a visible-break isolator just upstream of the CB with remote operation may assist.

Finally, if you as a company/entity are satisfied (from safety/legal/engineering/etc standpoints) with the installation but your customer is not, the simplest solution could be that you as a company/entity operate the CB for the customer.

The circuit breaker is Schneider brand and the trainer was from Schneider.

The circuit breaker is rated for the calculated fault current as required by NEC. We don't specify breakers based on calculated Incident Energy (IE) as IE is a value determined with respect to a specific distance and for a calculated amount of time. The high incident energy levels at this location are calculated for a fault at 18" distance and over 2 seconds of time and I have no control over this as we are dependent on the upstream utility overcurrent protection.

As someone so eloquently mentioned somewhere else in this forum, 100 Cal/cm2 within1 second would cause severe burns whereas the same exposure over 500 seconds wouldn't require much more than sunscreen to protect.

[elevated Incident Energy (IE) levels are found on the line side of the main disconnect on a secondary service and there's very little we can do about that particular location as the Utility has control over that equipment and overcurrent protective devices that serve the building.]

Sorry to open up an old post but it touches on a subject that I'm particularly interested in right now. I operate out of the United Kingdom and I can report that some of the difficulties that are encountered here in respect of information or cooperation can also be less than straightforward. I have been interacting with the utilities for some years now so I have enjoyed improved levels of dialogue and cooperation principally because the utility has a duty of care to cooperate across an operational boundary. A few questions if I may.

1. 5000 amps is a big breaker. Is there a design requirement that prevents the load being split?
2. I take it that the utility owns the feeder transformer and their protective device is on the primary side of the transformer?
3. Does the Utility provide emergency tripping of their equipment say by the use of a break glass/push button?

Many thanks, Mike