Moisture Content in Electrical Cabinet



At one facility I find that the condensation gathers on the inside surface of an enclosure, which can cause the rusting, short circuits, and breakdowns in electric and electronic equipment that is housed in enclosures. And one short circuit is already happened in the same cabinet.
One more critical problem in the same panel, the cable insulation is fell apart in pieces near the cable lugs. Same cable connected in else panels but didn’t find any such problem there.
So what will be the reason for the cable insulation breaking and what will be the preventive measures for the condensations??



If you have mild overloading/overheating, especially if the overload protection isn’t set up correctly, the highest resistance connections are at the lugs/joints and damage from overheating will start there and then work progressively back up into the cable body. After this occurs the first couple feet or so of insulation will lose it’s flexibility and either crack on its own or if you so much as touch it, it will crack and fall apart in your hands. If you catch it in the act, it will be literally smoking but won’t actually burst into flames or anything like that. This can occur without seeing any ongoing temperature issues and without discoloration occurring at the lugs and the flaking insulation might be your one and only sign that overload protection isn’t set up right.

This doesn’t mean you have an ongoing problem. Although all standards and manufacturers specifications say that you need to change the cable and/or remove the obviously defective portions, the reality is that this usually takes a lot of labor to remove and replace cable so it doesn’t get done…after all, the insulation is clearly obviously still there. And many times it gets overlooked since it just looks like the black rubber/plastic stuff is on the cable like it always is and cracks on something black are hard to see unless you are looking for it. I don’t condone the practice of leaving it when it is obviously defective but I definitely understand the reasons that this becomes a problem that may take years to address even if maintenance departments know about it and are truly committed to trying to do something about it. As a field service engineer I’ll point it out and document it which often gives the maintenance department ammunition to try to justify replacement but often the fact is that it’s hard to convince someone that it is important. They don’t recognize how much cables will actually jump during a fault and that all that insulation will fling off as the cable suddenly flexes.

It’s also definitely possible to find corrosion or similar damage occurring from other sources but the difference is usually obvious because you’ll see a whole lot more than just damaged cable if it’s a corrosion issue due to corrosive atmospheres.

As to the moisture problem…first off the anti-condensate heater idea works well IF you have a reliable source of power and if you are going to PM the heaters once in a while. There are two versions of these. One is a strip heater that is literally exactly what it sounds like and constantly puts out heat. A local motor vendor should easily be able to put you onto a source because they use them for customers that request them in motors, especially medium voltage motors. Second type are the ones that have a small thermostat that turns on and off as required and might even have a small circulation fan depending on the power output. Pretty much any MCC or switchgear catalog will list these in the “accessories” section. Obviously the reliability of a device that has more than just a strip of metal will be less…so along with the strip heater you will be committing yourself to regular PM’s to check them. In today’s paranoid world of so much as opening a cabinet, you can see the obvious issue. Many plants get along just fine with a simple small DIN rail circuit breaker and the previously mentioned “dumb” strip heaters, turning them on in Autumn and turning them off again in the Spring. READ MORE

AF label on Service Disconnect and ATS in same Enclosure

With the awareness of arc flash, many giant manufacturers do not manufacture the Service Disconnect and the Automatic Transfer Switch located in the same section or enclosure. However, this practice can be seen in the field for switchboards rated as high as 600 Amps.
The dangerous part is the upstream of service disconnect is like a blind spot as the only protective device is the utility’s fuse on the primary side of the transformer and often result in high incident energy (greater than 40 Cal/cm2 in most of the cases) at the service disconnect. But because of service disconnect as protective device, in the downstream the incident energy on the ATS(normal-utility side) gets reduced to for instance less than 4 cal/cm2. The problem is although ATS has lower incident energy, it is located right below the Service Disconnect in the same section (enclosure). This is a arc flash hazard and I affix the conservative label (service disconnect) on the section that has service disconnect on the top and ATS at the bottom. So please share your thoughts on how you affix labels:
1. When the Service Disconnect & ATS is located in the same section (enclosure)
2. When there is a barrier between Service Disconnect and ATS located in the same section (enclosure).


IEEE 1584.1-2013


Hello, good afternoon.

Does the standard contain new information to consider for arc flash analysis?

Thank you



No because we’re still on the 2002 edition. The new edition won’t get released until probably next year at the earliest.

As to answering your question, sort of yes and no. Three areas I know will change somewhat:
1. The “lower cutoff” (the old 125 kVA comment/rule) will likely change, probably downward in terms of what is “covered” under this exception but also it sounds like the “1 transformer” part may change to something a little more flexible such as a simple bolted fault cutoff.
2. They have a lot more data to work with. It is my understanding that the 2002 equations are within about 10-15% of the new equations. I’ve seen 3 possible new equations. The first is that EPRI and others have expanded into other areas for “device specific” equations so even though that’s the section that sees little attention, it might change. Second there’s the Wilkins simplified as well as the Wilkins time-domain models. In the past IEEE 1584 kind of covered everything out there and I wouldn’t be surprised if this one does something similar so both get honorable mentions. Both models fit the data a little better. The time domain model is the best but computationally complex to use. Finally I’ve heard that they are getting away from the “jump” that occurs at 1 kV due to the implementation differences between the medium voltage and low voltage models in terms of having a single empirical calculation or at least one that passes through the same point at 1 kV.
3. There has been a lot of discussion and rumbling about a lot more conditons/situations such as having more than just the existing 3 box cases and including electrode orientation which accounts for very problematic situations such as some switchgear. I’d expect that this is where the data gathering is going to have to increase substantially. Everything else just revises the model a bit. READ MORE

Liability and Legal Action

It’s no secret that the United States is a very litigious country.

Sometimes the more “interesting” interpretations that people use regarding codes, standards, design etc. tend to be more influenced by fear of lawsuits. I have had this conversation with many people over the years.

There are many reasons that legal action may be taken but this week’s question is very specific. It refers to: Liability from accident, injury, death, equipment failure. It applies to both the Plaintiff and Defendant.

Since this can be a sensitive topic, one of the answers is “can not answer”
Here it is:

Have you or your company/client ever been involved in legal action involving liability?
Can not answer

Stories are welcome if you are able to comment. ANSWER

Evaluation of Onset to Second Degree Burn Energy in Arc Flash

Our interest in determining accurate onset to second degree burn energy and its significance in computing the arc flash boundary is focused on the prevention of injury to the skin of a human who might be exposed to an arc-flash. During the last two decades different formulas have been proposed to calculate incident energy at an assumed working distance, and the arc flash boundary in order to determine arc rated personal protective equipment for Qualified Electrical Workers. Among others, the IEEE Standard P1584 Guide for Performing Arc-Flash Hazard Calculations [1584 IEEE Guide for Performing Arc-Flash Hazard Calculations. IEEE Industry Applications Society. September 2002] and formulas provided in Annex D of NFPA 70E [NFPA 70E Standard for Electrical Safety in the Workplace. 2012.] and CSA Z462 [ CSA Z462 Workplace electrical safety Standards. 2012.] Workplace Electrical Safety Standard are the most often utilized in the industry to perform arc flash hazard analysis. The formulas are based on incident energy testing performed and calculations conducted for selected range of prospective fault currents, system voltages, physical configurations etc.

Use of Incident Energy as a Measure of Burn Severity in Arc Flash Boundary Calculations
The IEEE P1584 Standard was developed by having incident energy testing performed based on methodology described in the ASTM F1959-99 standard. The incident energy to which the worker’s face and chest could be exposed at working distance during an electrical arc event was selected as a measure for determining hazard risk category and calculating the arc flash boundary. The incident energy of 1.2 cal/cm2 ( 5.0 J/cm2 ) for bare skinwas selected in solving the equation for the arc flash boundary in IEEE P1584 [1584 IEEE Guide for Performing Arc-Flash Hazard Calculations. IEEE Industry Applications Society. September 2002. page 41]. Also, NFPA 70E [NFPA 70E Standard for Electrical Safety in the Workplace. 2012. page 10] states that “a second degree burn is possible by an exposure of unprotected skin to an electric arc flash above the incident energy level of 1.2 cal/cm2 ( 5.0 J/cm2 )” and assumes 1.2 cal/cm2 as a threshold incident energy level for a second degree burn for systems 50 Volts and greater [NFPA 70E Standard for Electrical Safety in the Workplace. 2012. page 26].The IEEE 1584 Guidestates that “the incident energy that will cause a just curable burn or a second degree burn is 1.2 cal/cm2 (5.0 J/cm2 )” [1584 IEEE Guide for Performing Arc-Flash Hazard Calculations. IEEE Industry Applications Society. September 2002. page 96]. To better understand these units, IEEE P1584 refers to an example of a butane lighter. Quote: “if a butane lighter is held 1 cm away from a person’s finger for one second and the finger is in the blue flame, a square centimeter area of the finger will be exposed to about 5.0 J/cm2 or 1.2 cal/cm2 “. However IEEE P1584 equations (5.8) and (5.9) for determining the arc flash boundary can also be solved with other incident energy levels as well such as the rating of proposed personal protective equipment (PPE). The important point to note here is that threshold incident energy level for a second degree burn or onset to second degree burn energy on a bare skin is considered constant value equal to 1.2 cal/cm2 (5.0 J/cm2) in IEEE P1584 Standard.

Flash Fire Burn Experimentations and Observations

Much of the research which led to equations to predict skin burns was started during or immediately after World War II. In order to protect people from fires, atomic bomb blasts and other thermal threats it was first necessary to understand the effects of thermal trauma on the skin. To name the few, are the works done by Alice M. Stoll, J.B.Perkins, H.E.Pease, H.D.Kingsley and Wordie H. Parr. Tests were performed on a large number of anaesthetized pigs and rats exposed directly to fire. Some tests were also performed on human volunteers on the fronts of the thorax and forearms. A variety of studies on thermal effects have been performed and thermal thresholds were identified for different degree burns. We will focus on second degree burn as this is the kind of burn used to determine the arc flash boundary in engineering arc flash analysis studies.

Alice Stoll pursued the basic concept that burn injury is ultimately related to skin tissue temperature elevation for a sufficient time. Stoll and associates performed experimental research to determine the time it takes for second degree burn damage to occur for a given heat flux exposure. Stoll showed that regardless of the mode of application of heat, the temperature rise and therefore the tolerance time is related to heat absorbed by the skin[Stoll, A.M., Chianta M.A, Heat Transfer Through Fabrics. Naval Air Development Center. Sept. 1970]. Results of this study are represented in Figure 1 line (A) along with other studies discussed below. READ MORE

Time To Second Degree Burn Graph

Include Date on Arc Flash Label?

According to the 2015 Edition of NFPA 70E 130.5(2), The arc flash risk assessment “…shall be reviewed periodically, at intervals not to exceed 5 years, to account for changes in the electrical distribution system that could affect the results of the arc flash risk assessment.”

According to 130.5(D) Equipment Labeling, the date is not listed as a requirement for including on the label. However, many believe the date is an important aspect of the label in order to keep track of the “5 years” time limit.

Here is this week’s question:

Do you feel the date should be included on the arc flash label?


Adjusted Pickup Method – Shift Factor

I have been looking into the adjusted pickup method and associated shift factors used when multiple source bus configurations are being coordinated [ex. parallel generator systems two or more] and was hoping someone could point me to an IEEE standard or some industry articles on this to better understand this on shifting TCC’s around a specific location or device. On one example where two different sized generators were modeled it shifted the smaller units beyond the TCC of the larger unit indicating a longer trip time for that device for a downstream fault condition. It looks that the shift factor calculation looks at the generator current to the fault / the fault current at the location specified, assuming that larger gen breaker sees more current and trips faster than the smaller unit, this is what I am seeing and was looking for some backup information but searching around it appeared the information was pretty scarce and was hoping someone could point me toward some. THANKS. READ MORE

Non-melting clothing

Our company in the past 2 years has implemented an electrical safety and control of hazardous energy program for employees world-wide. Our daily work-wear clothing minimum requirement is non-melting clothing, except in US and Canada for which our AFHA’s determine minimum PPE requirements. Unfortunately, many countries have yet to recognize arc flash is a real threat to people and arc flash isn’t isolated to just North America. (Good news is they are beginning to wake up!)

As the implementation project manager I have not been able to find non-melting clothing for our Chinese colleagues that can be sourced in China. We can get clothing items from other countries but at a higher costs, shipping delays, etc.

Anyone have any experience in this area or have any suggestions? READ MORE

Behavior of Apparel Fabrics During Convective and Radiant Heating

Personal protective equipment (PPE) recommended for arc flash is not always designed for arc flash exposure. The purpose of this paper is to warn of the dangers posed by using the improper materials in arc flash exposures until standards have caught up on this issue.

The table below shows a representative range of everyday textiles along with some of the measurements of importance in establishing their response towards convective and radiant heating[1]:

Properties of Fabric Table


Times to ignition or melting of the 20 fabrics in Table above were reported by Wulff[2], [3] for different incident heat fluxes. The Wulff’s data have been used to develop a methodology by which ignition and melting times may be forecast. A semi-empirical relationship between ignition/melting time and radiative heat flux has been derived[1]:

[NF0] = -1 / NBi * ln(1 – NBi / [qxrad]) + a * [qxrad]^b * (1 – NBi / [qxrad])^-1, Equation 1
where [NF0] is the non-dimensional destruction time of the fabric (that is, time to ignition or melting) and is given by:

[NF0] = (k/l) * t / (pl * c), Equation 2



(k/l) – average thermal conductance, W / (m^2 * C);
t – ignition/melting time, sec;
pl – mass/unit area, kg / m^2;
c – average specific heat, W * sec / (kg * C).

NBi is the Biot number which is defined as the ratio of the average convective heat transfer coefficient of the fabric to the average thermal conductance of the fabric. It is obtained experimentally for each fabric.

The non-dimensional radiative heat flux [qxrad] is given by:

[qxrad] = ads * W0 / (k/l) / (Tim – T0), Equation 3 READ MORE

Safe Return-to-Service Following a Maintenance Outage

Best Practices for a Safe Return-to-Service Following a Maintenance Outage
Charles M. McClung, MarTek Limited
Russell R. Safreed, PE, MarTek Limited


Returning electrical equipment to service after a planned maintenance outage creates a unique set of hazards. Facility managers are under stringent time constraints for taking the system out of service, performing necessary maintenance tasks (as well as making un-anticipated repairs) and returning the system to service by the appointed time. These common, real-world factors may create circumstances that place workers at great risk as the system is returned to service. This paper seeks to identify those initiating factors and develop logical and practical ways to lessen or eliminate risks.

It’s all a setup, with good intentions.

Most well-run, progressive-minded companies readily accept the fact that their electrical distribution system is fundamental to the operation of their facilities. Maintaining the electrical is not an option—it is a ‘must’, not merely from a continuity of operations perspective, but also from a loss prevention perspective. Delaying the restart of a manufacturing process after a planned maintenance outage because of ‘schedule creep’ or ‘scope creep’ can be costly. Extended outages caused by major equipment failure can be devastating.

As important as these economic factors are, the prevention of a life-altering injury or death trumps all economic incentives. However, few would disagree that protecting people is also another form of loss prevention. Aside from the moral responsibility that is incumbent on employers to protect their workers, the failure to adequately protect people will likely result in significant economic losses in the form of OSHA fines, medical payments, higher worker’s compensation premiums and litigation.

Electrical maintenance outages are high-stress for everyone concerned. The Plant Manager just wants it to be over so operations may be returned to normal as soon as possible. The Electrical Distribution Engineer wants the greatest amount of work possible to be done in the allotted time to help ensure he never has to answer to the Plant Manager for an unplanned outage. The Maintenance Crew wants to be thorough and do a good job, but they also know the criteria for deeming the job ‘well done’—returning the system to operation on-time and with just enough ‘bad news’ about the condition of the equipment to justify the expense of the outage, but with not so much ‘bad news’ that a re-start is delayed or that significant repairs would be necessary.

All of these real-world pressures and sometimes competing objectives can produce a high-risk condition when the time comes to re-energize the electrical system following a planned maintenance outage.

Three major categories of risk-creating scenarios will now be explored. READ MORE