Posted By Steve Douglas,
Friday, March 01, 2013
Updated: Wednesday, February 13, 2013
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The fourth edition of the SPE-1000 Model Code for the Field Evaluation of Electrical Equipment (SPE-1000) is scheduled to be published by June of this year. The SPE-1000 was first published in 1994 providing requirements used by inspection bodies accredited by the Standards Council of Canada when field evaluating unapproved electrical equipment. Used in conjunction with the requirements of the Canadian Electrical Code (CE Code), Part I, the SPE-1000 document provides construction requirements for the equipment being evaluated along with testing criteria, and minimum marking for equipment nameplates, warning and caution notices. The SPE-1000 does not cover the field evaluation of equipment for use in hazardous locations, medical electrical equipment, equipment connected to line voltage in excess of 46 kV, and individual stand-alone components such as conductors, cable, wiring devices, switches, relays, and timers.
Photo 1. Testing of a photovoltaic module
The changes in the fourth edition focused on the addition of specific requirements for industrial control equipment, high-voltage equipment, solar photovoltaic modules, wind turbines, inverters, and additional requirements for instrument transformers, energy usage metering devices, and associated equipment. During these additions, the SPE-1000 Working Group identified the need for general requirements for transformers, motors, switches, receptacles, enclosures for outdoor use, conductor ampacities, and supplementary protectors. New clauses have been added for the allowable ampacity for wires and cables. These new clauses reference allowable ampacities in the CE Code Part I for conductors external to control panels and to a new table that matches Table 18 from CSA Standard C22.2 No 14 Industrial Control Equipment for conductors within control panels. In addition the temperature limitations of CE Code Part I Rule 4-006 have been added to align the SPE-1000 with the CE Code Part I and existing equipment testing in CE Code Part II standards. For supplementary protectors a new definition has been added to the definition section of the SPE-1000 in Clause 2.2, and a new clause has been added detailing the limited acceptability for supplementary protectors.
New clauses have been added for industrial control equipment. These clauses include details for wire bending space including new tables from C22.2 No 14, disconnection means for control panels, protective devices, control transformer protection, minimum allowable conductor size, permanent connection provisions, terminal size requirements, enclosure thermal insulation limitations, observation windows, intrinsically safe equipment requirements, and additional marking requirements for control panels.
Photo 2. 27.6kV Switchgear modified to metering specification of the supply authority then field evaluated to the requirements in the SPE-1000
The high-voltage equipment requirements added to the SPE-1000 are limited to certified deadfront indoor enclosed and an outdoor enclosed assembly of switchgear and components that have been modified, and then only where adequate testing and review is performed or where documentation is provided to demonstrate that all type testing and mechanical review have been conducted as detailed in CSA Standard C22.2 No. 31 or CSA TIL D-25, as applicable, on a similar design of equipment. These clauses for high voltage equipment are not intended to approve a new design of high-voltage equipment where all relevant sections of CSA C22.2 No. 31 or another recognized document (ORD) are deemed necessary. The requirements in the clauses for high voltage equipment include construction, grounding and bonding, conductor spacing, circuit breakers and switching devices, force-cooled equipment, pad-mounted switchgear, and requirements switchgear intended to be used for service entrance. Testing for high voltage equipment includes all tests from CSA Standard C22.2 No 31 Switchgear, and additional requirements for short-circuit withstand rating, and dielectric strength testing.
New clauses have been added for solar photovoltaic modules. These clauses provide separate direction regarding additional testing and markings required for modules that have been either certified to UL 1703 or tested in accordance with IEC 61730-1 and 61730-2. Modules without UL 1703 certification or appropriate IEC 61730-2 testing cannot be field evaluated using the SPE-1000.
Wind turbines clauses have also been added to the SPE-1000. These clauses include details for generators and motors, generator overcurrent protection, wind turbine components, overcurrent protection for all components of the wind turbine, emergency blade pitch control power supplies, capacitors, low and extra low voltage cables, high voltage cables, grounding and bonding, lightning protection, disconnection means, and safety controls. In addition, clear direction is given for the main nameplate, and warning and caution markings.
Specific requirements for inverters/converter have also been added to the SPE-1000 with separate details for inverter components, and utility interconnected inverters. These clauses tie closely with the requirements and testing in CSA Standard C22.2 No 107.1 General Use Power Supplies.
Photo 3. Modified distribution panel with CTs installed for non-utility metering; ready for a field evaluation inspection
Additional requirements for instrument transformers, energy usage metering devices, and associated equipment have been added to the SPE-1000. These clauses were added as a direct result of the addition of Subrule (4) for CE Code Part I Rule 12-3032 allowing enclosures for overcurrent devices, controllers, and externally operated switches to be used as a raceway for wiring associated with instrument transformers and energy usage metering devices. These new clauses address the wiring space, wire bending space, and additional marking requirements when current transformers CTs are added to a panelboard.
In addition to the changes detailed in this article, tables have been added for
- Wire bending space
- Wiring space
- Full-load motor-running currents in amperes corresponding to ac horsepower ratings
- Full-load motor-running currents in amperes corresponding to dc horsepower ratings
- Allowable ampacities of insulated copper conductors inside industrial control enclosures
- Maximum acceptable rating of primary overcurrent device for control transformers
- Maximum acceptable rating of secondary overcurrent device for control transformers
- Minimum spacings for high-voltage power circuits
- Impulse and corona-extinction test voltages for high-voltage switchgear assemblies
- Dielectric strength test voltages for high-voltage switchgear assemblies, and
- Voltage and frequency operation limits
Two new figures have also been added, one for an articulated finger probe, and one for the typical arrangement of intrinsic safety barriers.
One more major change is in the process and scheduling of future editions of the SPE-1000. Future changes for the SPE-1000 will use a similar approach as the CE Code Part I in that separate proposals will be addressed when submitted then sent for ballot. The existing process held proposals until a sufficient number were received, and then a working group would work on all the proposals at once. The new process will address proposals sooner in an effort to encourage more proposals. The cycle for the SPE-1000 will also change to a three year cycle with new editions being published following the publication of the CE Code Part I.
Read more by Steve Douglas
Posted By Barry O’Connell,
Friday, March 01, 2013
Updated: Wednesday, March 13, 2013
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In September 2012, both UL and ULC withdrew certification for Electrical Circuit Protective Systems (FHIT and FHITC) that employed fire resistive cables. This included UL Classified Fire Resistive Cable (FHJR), UL Listed cable with "-CI” suffix (Circuit Integrity), and ULC Listed Fire Resistant Cable (FHJRC). Certification was retained for systems that used protective materials like intumescent wraps, tapes, composite mats, etc.
Fire resistive cables are used for emergency circuits in many applications, including high-rise buildings and places of assembly. Emergency circuits include feeders for fire pumps, elevators, smoke control equipment, fire alarm systems and other similar circuits. These circuits are required by the National Electrical Code and the Canadian National Building Code to have a 2-hour fire rating. This added level of survivability is intended to allow sufficient time for building occupants to exit a building during an emergency and to provide uninterrupted power for fire fighting equipment and emergency communication systems.
There are two types of fire resistive power cable systems: polymer insulated cables that require conduit protection and armored cables that do not. Armored cable types include both mineral-insulated and metal-clad cable. The events that led to the certification withdrawal were based on systems employing polymer insulated cables, not armored cable.
In 2011, UL was informed of an issue with using polymer insulated fire-resistive cables in conduit systems coated with zinc. UL confirmed that a problem existed and issued a notice stating that fire-resistive cables should be used only with components free of zinc. UL expanded their research and conducted extensive additional testing that showed an unacceptable level of variability with all non-armored polymer insulated cables.
These findings led to the conservative decision to withdraw all certifications, including armored cable systems, even though there was no indication that similar issues existed with either metal-clad or mineral-insulated cables. Shortly thereafter, however, UL offered an interim test program to manufacturers of fire-resistive cable for possible re-certification of existing products.
After UL/ULC withdrew all fire resistive cable certifications, a joint meeting of the UL Standard Technical Panel on Fire Resistive Cables and the ULC Standards Committee on Fire Tests was arranged. The meeting took place on October 24, 2012, in Ottawa, Canada, where the committee reviewed available information and agreed to form task groups to evaluate and update the fire resistance test standards for cable systems. This process will include additional testing and review, and a revised standard is likely to take at least two years to complete.
Because mineral-insulated cable construction is completely different from the cable-in-conduit technology under investigation, UL/ULC worked with Pentair Thermal Management to reinstate Pyrotenax mineral-insulated cable as a 2-hour fire-rated cable system. The process included reviewing MI cable designs in detail, detailed technical explanations of the critical design factors related to mineral-insulated cable’s fire resistance, and extensive fire tests, in accordance with the interim test program performed at the UL facility in November and December of 2012.
On December 21, 2012, UL and ULC re-established certification of fire-resistive cables used in electrical circuit integrity systems. The first system to be included is Pyrotenax Mineral Insulated Cable, and it has been assigned a new identification: System No. 1850. Information can be found at www.ul.com in the Online Certifications Directory.
Read more by Barry O'Connell
Posted By Jim Dollard,
Wednesday, February 13, 2013
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There were 120 proposals submitted to raise the 600-volt threshold in the NEC to 1000-volts in the 2014 NEC cycle. These proposals were submitted by the High Voltage Task Group (HVTG), which was appointed by the NEC Correlating Committee. The HVTG was charged to review all NEC requirements and/or the lack of requirements for circuits and systems operating at over 600-volts.
FPN reference to NESC deleted
The origin of this task group began at the end of the 2008 NEC cycle when a fine print note (FPN) [now Informational Notes] referencing the National Electrical Safety Code (NESC) was deleted from 90.2(A)(2). The substantiation provided in the proposal to delete the FPN stated that "conductors on the load side of the service point are under the purview of the NEC, and the FPN sending NEC users to the NESC creates serious confusion for designers, installers and the authority having jurisdiction (AHJ) working on premises wiring at voltage levels over 600-volts”. The proposal was supported by comments that pointed out conflicts that place the AHJ in a very difficult position and the FPN was deleted in the 2008 NEC. The NEC Correlating Committee then appointed the High Voltage Task Group to address issues with installations over 600 volts”.
Article 399 created
In the 2011 NEC, a proposal submitted by the HVTG created a new Article 399, Outdoor Overhead Conductors over 600 Volts. This new article was developed to provide the AHJ with NEC requirements to address the outdoor installations referenced in 90.2(A)(2) without a broad reference to another standard. It is interesting to note that most of the requirements in Article 399 are performance based. The requirements for conductor support and structures outline the installation requirements to consider without being prescriptive. In each case there must be documentation of an engineered design submitted by a licensed professional engineer engaged primarily in the design of such systems. This new article permits an engineer to design the installation in accordance with NESC requirements provided the design is documented and available to the AHJ.
Photo 1. XHHW cable labeled 600 volts
Raising the voltage threshold
The work of the High Voltage Task Group continued into the 2014 NEC cycle with a primary focus on raising the voltage threshold in the NEC from 600 to 1000 volts. This is not the first coordinated attempt to raise the voltage threshold. In the 1990 NEC revision cycle, a Correlating Committee task group tried unsuccessfully to raise the voltage threshold. Finding substantiation on how the NEC settled at 600 volts is difficult. The threshold was raised from 550 to 600 volts in the 1920 NEC. In 1990 it was difficult to substantiate a need to raise the voltage threshold. Today, emerging technologies are operating at just over the 600-volt threshold. We need product standards and installation requirements to facilitate their safe installation. The electrical industry is changing rapidly and codes/standards must keep pace; otherwise, we will be forced to use the International Electrotechnical Commission (IEC*) products and installation standards other than the NEC.
Is going from 600 to 1000 volts the right number? Small wind electric systems often operate at 690 volts AC but solar photovoltaic (PV) systems are currently being installed at dc voltages over 600 volts up to and including 1000 volts, 1200 volts, 1500 volts, and 2000 volts dc. These dc systems are expanding and have become a more integral part of many structures. Small wind electric systems and solar photovoltaic (PV) systems are employed regularly in and on all types of structures from dwellings units to large retail and high rise construction.
Photo 2. Cube fuses labeled 600 VAC or less
The first direction that the Higher Voltage Task Group took was to simply suggest revisions in Chapter 6 of the NEC for Special Equipment. It was quickly understood that changes throughout the NEC were required. Chapter 6 requirements simply modify and/or supplement the rules in Chapters 1 through 4. A review of the UL White Book reveals that UL has many products that are utilized in these systems rated at and above 600 volts, including but not limited to, 1000-V dc PV switches, 1500-Vdc PV fuses, and 2000-V PV wiring. The HVTG realized that the NEC must recognize those products through installation requirements or we will continue to have problems installing and inspecting systems for PV and small wind. The HVTG proposals to raise the voltage threshold recognize emerging technologies that are in many cases operating at just over 600 volts. Everyone needs to play a role in this transition. The present NEC requirements would literally require that a PV system operating at 1000 volts dc utilize a disconnecting means rated at 5 kV. The manufacturers, research and testing laboratories, and the NEC must work together to develop installation requirements and product standards to support these emerging technologies.
Moving the NEC threshold from 600 volts to 1000 volts will not, by itself, allow the immediate installation of systems at 1000 volts. Equipment must first be tested and found acceptable for use at the higher voltage(s). The testing and listing of equipment will not, by itself, allow for the installation of 1000-volt systems. The NEC must include prescriptive requirements to permit the installation of systems that are over 600 but less than or equal to 1000 volts. It will take both tested/listed equipment and changes in our installation code, the NEC, to meet the needs of these emerging technologies that society demands.
Eighty-two percent of the proposals submitted to raise the voltage threshold were accepted in some form. Where a code-making panel felt there was a safety issue or where manufacturers did not want to pursue having their products evaluated at 1000 volts, the Higher Voltage Task Group agreed to reject.
Moving the NEC to 1000 volts is just the beginning. This is just the first step of many to recognize emerging technology with prescriptive requirements to ensure that these systems and products can be safely installed and inspected in accordance with the NEC.
*The IEC is a nonprofit, nongovernmental international standards organization that prepares and publishes international standards for electrical and electronic technologies.
Read more by Jim Dollard
Posted By Randy Hunter,
Friday, January 18, 2013
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Overcurrent protection is a subject on which we could write volumes; however, our objective here is to cover the basics in order to provide the information needed for the combination inspector. This is actually a fun portion of training, as we usually take apart devices and explore how they operate. Check out the included photos that illustrate some of the details that we usually look at in training classes, and don’t be hesitant about disassembling equipment (that you don’t plan to install later!) to see what is inside.
To make sure we understand our topic, we need to start with the scope of this article. It provides the general requirements for overcurrent protection and overcurrent protective devices not more than 600 volts, nominal. There are two parts to Article 240 that we will not address: Part VIII dealing with supervised industrial installations and Part IX dealing with over 600 volts. Combination inspectors are generally not involved with these installations, so we will leave those topics to articles and books specifically concerned with those subjects.
Photo 1. Overcurrent protection comes in many types, sizes and shapes
As with most NEC articles, we need to start with some unique definitions. Article 240 has only three definitions, and they are located in 240.2. First we have a definition of current-limiting overcurrent protective device, which is a device that when interrupting currents in its current-limiting range will reduce the current flowing downstream to a level much less than if there were just a solid conductor having comparable impedance. Current-limiting devices are very instrumental in reducing incident energy (arc flash, arc blast) in our electrical systems, making them safer for personnel and providing protection of equipment.
The second definition deals with a term that is also used in other parts of the code. Quite often we have a question as to what exactly is an "industrial installation”? In 240.2, we have a definition of supervised industrial installation with a list of conditions which must be met to fall under this definition. Note that this definition is specifically limited to use in Part VIII of Article 240; this means that these limitations do not apply to any other code provision where supervised industrial installation (or similar term) is used. You can’t use this definition when applying 392.10(B), for example, which allows certain cable tray wiring methods in industrial establishments. Since we are not covering Part VIII in depth, I simply point this out so that you know that this definition is very limited in application.
Photo 2. Here is a very good example of a neutral main bonding jumper that was never properly connected after the completion of the ground fault testing. This caused several problems within this facility, including voltage fluctuations and equipment failures.
The last definition is that of a tap conductor as used in this article. This definition is needed as we have various tap rules within Article 240 with very specific rules. Simply put, a tap conductor is a conductor other than a service conductor that has overcurrent protection ahead of it which is oversized compared to the normal requirements found in Article 240.
Basic minimum overcurrent protection
So, let’s get down to the most basic of rules for overcurrent protection. The go-to article here is 240.4. Other than flexible cords, flexible cables and fixture wire, we refer to the ampacities of the conductors as specified in Article 310.15, unless covered in specific applications as described in 240.4(A) through (G). In these subparagraphs, we cover basic minimum overcurrent protection device sizing according to conductor sizes and properties. These are very basic rules that will at times get overlooked when using ampacity tables, but you absolutely need to try to commit these to memory. Also, many code test questions will ask about sizing a certain type and size conductor, and you’ll get sidetracked into doing a calculation and don’t want to forget that you have limitations in 240.4. Please review these and remember some basic ones such as 14 AWG copper must have 15 amp protection, 12 AWG copper is limited to 20 amps and 10 AWG copper at 30 amps, just to name a few.
There are two very important rules in 240.4 that we have to examine more closely, as they deal with protection for 800 amps and lower and then over 800 amps. These general rules state that if you are sizing protection for 800 amps or lower, you are allowed to round up to the next largest device, as long as you don’t violate the specific conductors mentioned in 240.4(D). If you have a system over 800 amps, then the ampacity of the conductors has to equal or exceed the rating of the overcurrent device.
Photo 3. This is a photo showing the interior of a 600-amp fuse after the sand filler has been removed. This fuse opened during an overload condition. You can see how five of the six alloy contact points melted and released; when the last one interrupted the flow of current, it arced and caused the burned sixth contact. Please note in the left photo you can see the short-circuit elements which are still intact; these are the webs which melt out during a high fault current condition.
The next question that usually comes up here is: When allowed to round up to the next size device, what is the next size? The next size according to what is available from the manufacturer? No, you round up to the next standard size device according to 240.6. Please notice that in 240.5 you will find the specific overcurrent sizes for flexible cord, cables and fixture wire; again, the rules are very specific and in part mention exact size overcurrent protection according to the wire size. Please review, but know that generally speaking, we don’t see these wire types that often in combination inspections.
Standard ampere ratings
Let’s go back to Standard Ampere Ratings in 240.6. This is one section of your code book you will need to reference almost as often as conductor ampacities, so please remember it. Here you find what the code considers "standard sizes” when references are made to sizing overcurrent devices. I always make a big point of making sure everyone uses the sizes listed in this article when working on code questions or test questions. Another note here, remember when we had the rule that you round up when working at 800 amps and below? Well, you will notice the size differences below 800 amps are much closer, so when we round up it’s not much of a shift; however, when you get over 800 amps you will notice there are not as many options and the sizes start to jump in pretty large increments. This helps to explain the reasoning behind this code requirement, since rounding up in such large steps could lead to a large disparity between conductor ampacity and overcurrent protection levels.
Also in 240.6 are two paragraphs, (B) and (C), which work together to address adjustable trip circuit breakers. If you have an adjustable breaker which has the adjustment exposed with ready access, then the rating of that breaker will be the maximum possible setting. However, if these controls have a restricted access feature meeting the requirements as set forth in (C), then the rating of this device will be at the set value. The one gray area here is that some of the breakers have a field-fitted rating plug. It was my opinion as an inspector that if this plug type device could not be removed without the removal of sealable covers or special tooling of some sort, we applied 240.6(B). One such case had a plug which could easily be removed using a pair of needle nose pliers, so we opted for the conservative approach and applied (C).
Photo 4. This photo shows the inside of a breaker. You can see some of the mechanical parts that are required for proper operation.
Fuses or circuit breakers in parallel
Questions appearing on some tests ask if it is permissible to use fuses and circuit breakers in parallel. This is addressed in 240.8. The correct answer is: only where they are a part of a factory assembly and listed as a unit. I have seen this from time to time, but never outside a factory listed unit.
Electrical system coordination
Continuing on, 240.12 starts us on the path for an interesting concept that often isn’t considered in design. The subject is electrical system coordination, and it simply states that to minimize hazard(s) to personnel and equipment where an orderly shutdown is required, a system of coordination based on two conditions shall be permitted. The first condition is coordinated short-circuit protection and the second is overload indication based a monitoring system or devices. Notice that this language says "shall be permitted.” This means that is allowed, but not required. This language is generally applied to situations where it is more hazardous to shut down the electrical source than it is to shut down the process. This is not the same as selective coordination, which is required for many emergency systems and will be covered when we finally get to Chapter 7.
Ground-fault protection of equipment
In 240.13 we find requirements for Ground-Fault Protection of Equipment. Let’s first consider the difference between ground-fault circuit interruption (GFCI) and ground-fault protection. The easiest way to explain this is that GFCI protection is for people and the threshold levels are extremely low (around 5 ma), whereas the protection of equipment is meant to minimize the damage to equipment in the event of a fault condition to ground. This applies to only a very specific power configuration and that is a solid wye-connected system, where the voltage to ground is more than 150 volts and the phase-to-phase voltage does not exceed 600 volts. Commonly this will be our 277/480 volts wye-connected three-phase systems that are 1000 amperes or more in size. Ground-fault protection offers a level of protection in the event of a ground fault at a much lower level of current than what the breaker is equipped to handle under normal operation. I’ll tell you a personal experience related to this. We had a bank in our jurisdiction where the service was rated at 1000 amps, 277/480 and so the inspector made a note that this installation would require ground-fault protection. The engineer stated it didn’t need it because he had specified an 800-amp main breaker. A little gray area I guess, but we decided to stick with the rating of the manufacturer’s label which stated the service equipment was 1000 amps. The end result was that the factory sent out new equipment labels and had a field inspection done by a listing agency to change the equipment to an 800-amp service officially.
Ground-fault protection needs a little deeper look, first to understand how it works and then to understand some of the complexities to look for as you are doing your inspections. First, these devices have a sensing ability to verify that the amount of current being called for is balanced and all accounted for between the other phases or the grounded conductor. In the event that we have current going to ground or not following the normal paths, then the ground-fault protection will open the device (this could be a breaker or a bolt switch equipped with the ground-fault protection). When these devices are sent out, they are set at factory minimums. If the levels are not adjusted at the time of installation, this minimum setting may cause nuisance tripping. The setting should be evaluated and specified by the engineer of record, and then set in the field to match the engineer’s design.
Once I got a service call for a large grocery store that had lost power. The main at this store had ground-fault protection, and the original contractor didn’t set up the device as requested by the engineer of record. So, it was still set at the minimum value. On the evening I got the call, the manager had asked a box boy to paint the hallway going upstairs to the break room, and the young man had saturated his roller to the point it caused some large drips to start running down the wall. The paint flowed into a 277-volt switch box and shorted out the switch. Well before the individual circuit breaker which fed the lighting circuit could interrupt the fault, the ground-fault device saw the fault to ground, did its job, and shut down the entire store. Because the device was not properly set by the installer, the entire facility lost power.
Photo 5. This collage of photos shows a before-and-after for breakers. The top row shows a breaker which has not been in operation. The left and middle photos show both sides of the contacts, and the right photo shows the arc chutes. The bottom row shows an example of the same parts of another breaker which has been subjected to a high fault current condition and had to open, causing damage to its components.
Total separation of grounds and neutrals
Now one of the critical items we must look at during inspection is the total separation of grounds and neutrals downstream of the ground-fault device. This must be done all the way throughout the system down to each branch-circuit device and the equipment connected to the system. At the main service we have to pay special attention to have the grounds connected only to the grounding bar, and neutrals connected only to the neutral bar. Now this is different from our normal method, say in a residential main panel, where we can just mix the grounds and neutrals as we see fit. In these larger systems, there is a neutral bonding jumper (which could be a conductor but is generally a piece of busing) that comes from the factory and is not connected to the ground bar. As an inspector, you have to verify that the grounds terminate on the ground bar and the neutrals, to the neutral bar. If these are not done properly, the system will have issues.
Locally we always required third party verification and testing of the ground-fault system before we would approve it to be energized. This was our insurance that the unit had the grounds and neutrals separated throughout the entire facility and that the system wasn’t left at factory minimums. Once the system has been checked, then the neutral bonding jumper is connected between the neutral and the ground bar. So after we got this report, we would make sure the bonding jumper link was connected between the neutral and ground bar and then allow the contractor to have the system energized. This was our solution for enforcement of ground-fault protection of equipment.
In the next issue we will pick up with Part II of Article 240, but this is a good time to cover a related issue. While teaching classes on the code, I always tried to take the mystery out of the electrical system as much as possible. So I am going to spend a little time explaining how overcurrent and short-circuit protection works. In class this always led to a lot of show and tell, taking apart devices and physically seeing their operation. I will try to explain this here and supplement it with some good photos.
Basics of circuit protection
We need to explore some of the basics of circuit protection. First we’ll start with the most common circuit breaker in the industry today, that being an inverse time circuit breaker. These come in all sizes and ratings, from 15 amps and up. They are rated by amperage, voltage and interrupting rating. The first two items we should already be familiar with; however, the last is often overlooked. The interrupting rating is the amount of fault current the device is able to safely handle without catastrophic failure. Insuring the available fault current is less than the rating of the device is one of the inspection items we need to look for. Breakers are mechanical equipment; similar to any other mechanical device, they require a lot of pieces to work together with the proper timing to do their job. A car is a good comparison, as it is a mechanical device that has many pieces that have to operate in a certain sequence for proper operation. Also similar to cars, the need for exercise and maintenance for breakers should be considered. Inside a breaker we have two distinct methods which cause it to open, one being an overload which is normally up to about 6 times the handle rating, and the other being the short-circuit portion which reacts to shorts causing a high level of fault current to flow. The overload is normally handled by a bi-metallic element which when exposed to excessive current starts to heat up and it then deflects to contact the trip bar and release the trip mechanism. Breakers handle short circuits with a magnetic sensor which reacts to high current flow and opens a breaker as fast as it can. Remember these are mechanical, and as such they take a certain amount of time to react and then to complete the operation of shutting down the circuit. The photos illustrate the number of components inside a breaker and also show a close up of the contacts, the arc shields which control and manage the arcing when operating in high-fault conditions, and a bi-metallic strip.
The other most common method of circuit protection is fuses, which in many circles is considered old style due to the fact they’ve been used to protect electrical systems practically since the beginning. However, they still have a distinct use in today’s systems and provide some very unique methods of protection due partially to their simpler operation. The most commonly used fuse for construction is a dual element time-delay fuse. These have two distinct portions within each fuse; the first portion is a thermally reactive element which handles an overload situation. This element uses a melting alloy which has been specifically created for each size fuse. When it is exposed to an overload condition it will melt out and release, allowing the fuse to open. The short-circuit section of a fuse consists of a web-style design which is designed to react to high-current flows and very rapidly melt out; as these melt and break away, the amount of metal mass left is diminished which limits the amount of current which can continue to pass through the fuse. Therefore, they are considered current-limiting by design. In order to control this arcing within the fuse, it is filled with sand. When the sand comes into contact with the extreme heat and arcing of the webs, it turns into glass to quench the arcing event and extinguish it.
I know the operation of a fuse sounds basic compared to a device full of mechanical components which have to work in unison, but that’s just how simple they are. Once a fuse opens, you replace them with a new fuse which restores the system back to its original level of protection. When a breaker has been subjected to fault current near its operating limit, it should be taken out of service and tested before using again. There are companies that test breakers to insure they operate in the proper time and current levels required and then re-certify them. If the breaker is not tested and re-certified, it may not protect the system during a future fault.
In the next issue we will continue with Article 240. Continue to review the code as these articles only cover the highlights you need to know.
Read more by Randy Hunter
Posted By Joseph Wages, Jr.,
Tuesday, January 01, 2013
Updated: Friday, January 18, 2013
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Think you might know what lurks behind the meter cover? Chances are you will think twice after reading this article!
Electrical Metering Devices
Meter enclosures are part of every electrical system. But how often do you look inside the enclosure after it has been installed and energized? A utility provider provides electricity to a customer in order to make a profit. Typically, this is accomplished by metering the electrical system at the point of connection. Electronic receiver/transmitter (ERT) meters are becoming more of the norm in today’s electrical metering systems. They provide many benefits to the electric utility provider and to the customer. But, this could allow for many unforeseen problems as well.
Photo 1. A 400-ampere, single-phase meter enclosure located at the front entrance of a church and preschool. Men, women, and children visiting this location walk by this meter enclosure on a daily basis. What’s located behind the cover could prove deadly! And chances are it will not be discovered until there is a problem.
The Good Ole Days and the Standard Electrical Meter
For many years the measurement of electricity went relatively unchanged. These metering devices worked adequately for the utility provider to accomplish the goal of registering electrical usage so that a utility bill could be generated. The customer received the monthly statement and would pay his or her bill.
In the event the customer fell in arrears and did not pay the monthly bills, a customer service representative would visit the location and disconnect the power. To accomplish this, the meter seal would be cut, the electric meter removed and booted off, and then reinserted into the meter base. The cover is then reinstalled and re-sealed until a time in which the customer pays the outstanding bill and any reconnection charges. In the event of tampering, the meter would either be removed and a blank inserted or the service conductors cut and disconnected at the weatherhead or utility pole.
Photo 2. Within the meter enclosure unknown to daily passersby are several potential dangers as can be seen, such as corrosion, effects of overheating to busbars and conductors, insulation failure as well as conductor damage.
When the service is ready to be reconnected, the customer service representative then returns to the property, cuts the meter seal, removes the meter, removes the boots and reinserts the meter. The cover is then installed and another seal applied. This returns electricity to the customer and usage is recorded for the next monthly billing cycle.
During this entire process there were several opportunities for the utility representative to notice and report any problems developing within the meter enclosure. Upon discovery, action could be taken to alleviate potential problems before they happened. Technology has changed the way that utilities gather billing information and even the disconnection of delinquent accounts. This has in turn made it even more imperative that electrical work within the meter enclosure be installed in a code-compliant fashion.
A statement must be mentioned concerning safety regarding this issue. Unbelievably, some customers take it upon themselves to reconnect their electricity without the approval of the serving utility. This has resulted in additional fees being accessed by utility and the electrical meter being removed or the conductors disconnected at the weatherhead or utility pole. This illegal activity can result in electrical accidents up to and including death. Qualified personnel are necessary to reconnect these services to assure the safety of the electrical system. Never attempt to reconnect your electrical service! Contact your friendly utility provider for help with this situation.
Photo 3. The interior of this meter enclosure depicts damage due to overheating and corrosion. Remember, none of this damage is visible from the outside of the meter enclosure.
The ERT Meter
An electronic receiver/transmitter meter (ERT meter) is used in a network meter reading environment. It can be retrofitted into existing meter enclosures and is available in single- phase and three-phase models. The meter uses electronic modules to communicate power consumption and power quality to the utility provider. The meter also allows two-way communications from the utility provider to the customer. This allows the utility provider the opportunity to be aware of outages that occur and to respond much more quickly.
The use of ERT meters saves the utility provider from physically visiting the meter location on a monthly basis. The ERT meters have a low-powered radio device that permits them to be read from a distance. This allows meter readings to be collected electronically with a mobile data collector (usually a laptop computer) or with a handheld receiver. Technicians are able to download the readings for multiple meters at one time rather than walking from house to house to look at each individual meter.
In some cases, the utility can also disconnect and reconnect the customer remotely. This can be for nonpayment of their monthly bill or to head off high demand issues on the utility system. This can be handy during high usage periods where the provider needs to disconnect loads within structures to prevent brownouts or blackouts from affecting the system. Many household devices are being produced with communication features that communicate with the electronic meters. Utilities can disconnect AC units briefly to prevent issues on the system from occurring. Most generally the customer is unaware that this has even taken place. Some consumers have expressed concerns regarding this issue as it applies to privacy. Many customers enjoy the features of ERT meters. This technology allows the customer to monitor their electrical usage. This has also allowed the customer to change some of their usage patterns in order to save money on their electrical bills by using electricity in the off-peak periods.
As you can see, the use of this technology removes the "hands on, eyes in the field” that may have visited the enclosure and discovered a problem. This can result in minor situations arising that develop into major issues. These issues can be lessened by proper equipment installation and inspection.
Photo 4. Conductor damage due to insulation failure that is not detectable from the exterior of the meter enclosure.
Preventing These Problems Begins with You
The first line of defense in addressing this issue starts with the electrical contractor. The contractor must make sure that all material used for the installation is listed and labeled as per requirements found in NEC 110.3(B). Proper application of NEC requirements will help ensure a safe and compliant installation. NEC Article 110 covers the requirements for electrical installations. Requirements found within this article include working clearances, interrupting rating, mechanical execution of work, mounting and cooling of equipment, illumination, electrical connections, arc-flash, and field marking. There are other requirements that are useful and required throughout the NEC as well.
Care must be taken to follow the manufacturer’s installation instructions. Special care must be taken to use anti-oxidant compounds as required by the NEC and the manufacturer. These requirements are found in NEC 110.14. Conductors should be stripped and prepared properly so as to not damage the conductor. Specialized tools are necessary to assure that the specific torque requirements are followed for the lugs and conductors. Informative Annex I includes recommended tightening torque values to be used in the absence of the manufacturer’s recommended torque values. These values are taken from UL Standard 486A-B.
The next line of defense lies with the electrical inspector. The inspector needs to assure the customer and utility provider that the electrical contractor has followed the guidelines for properly installing the metering equipment. A good understanding of the NEC and any additional electrical requirements required by the utility provider are necessary. Some of these requirements have been previously discussed. Additionally, the inspector needs to make sure that proper grounding and bonding has been accomplished. Grounding and bonding requirements can be found in NEC Article 250. Also, remember that the insulated fitting required at NEC 300.4(G) is required due to conductor size, not conduit type. Bushings are required for various conduit types throughout the NEC such as at 344.46 for rigid metal conduit. There have been many instances where the electrical installation has been turned down by an inspector due to a missing conduit bushing or insulated fitting.
Photo 5. For years a standard 2s meter was adequate for the needs of the utility company. Today’s technological advances have spurred changes within the utility industry in order to compete and reduce operation costs. Electronic radio transmission (ERT) meters may be able to control some electrical devices within the structure through the electrical utility to prevent system problems. These include the refrigerator, the air conditioner or some other high usage item. Privacy issues have been expressed by some people.
Arc Flash and Available Fault Current, a Deadly Combination
New to the 2011 NEC are 110.16 and 110.24 which deal with arc-flash and available fault current markings and requirements. Section 110.16 states that the marking shall be located so as to be clearly visible to qualified persons before examination, adjustment, servicing, or maintenance of the equipment. This includes meter socket enclosures as well as switchboards, panelboards, industrial control panels and other motor control centers. These requirements do not apply to dwelling units.
Service equipment must be marked with the maximum available fault current per NEC 110.24. This Code requirement further states that the field marking shall be legible and include the date that the fault-current calculation was performed. It must also be sufficiently durable to withstand the environment in which it has been installed. Modifications require that this calculation be verified and recalculated as necessary to ensure the service ratings are sufficient for the maximum available fault current at the line terminals of the equipment. An exception exists for industrial installations where conditions of maintenance and supervision ensure that only qualified persons service the equipment. Again, as previously stated these requirements do not apply to dwelling units.
These requirements help to ensure that whoever works on this equipment in the future is aware of the potential available fault current. This also brings up an interesting question. Who is responsible to adjust the modification markings to the existing equipment as per the requirements found within 110.24? Suppose the providing utility changes out the transformer to the building. Suppose the impedance is different from the existing transformer to the newly installed transformer. Who makes the changes to the marking at the service equipment? Is the building owner aware that these changes have been made and what effect it has on the available fault current to his equipment? Does the utility provider even know that this requirement is found within the NEC? How does this information get upgraded on the electrical equipment?
Photo 6. This electrical service location has a meter blank installed and the meter retired or taken out of service. This could be due to non-payment for services, tampering or because the electrical equipment is no longer in service.
Most utilities work under the guidelines of the National Electrical Safety Code (NESC). During a power outage at 2:00 A.M. in the pouring rain and lightning, who will make these adjustments in the field? Is there communication between the utility provider and the customer concerning these changes? What happens when the utility changes the substation feeder to this area of town from one substation to another? There are different characteristics present in both substations that will affect the calculations towards what is marked on the service equipment. These are just a few questions and situations that could arise and affect the accuracy of the field markings for these installations.
Interestingly, during the 2011 NEC Report on Proposals (ROP) and Report on Comments (ROC) meetings these situations were vigorously debated and discussed. The inclusion of the date of when the calculation was conducted was agreed upon and included so that the future electrical contractor would be aware of when the calculation was conducted. Under no circumstances should the electrical contractor rely on a marking on the equipment to determine the level of personal protective equipment (PPE) required. Changes to the system may have taken place after the date the calculation was performed, changing the available fault current at the terminals of the equipment.
Technology Always Has its Ups and Downs
In conclusion, a properly installed and inspected electrical service should provide years of service to the customer. If the customer increases the electrical load by adding new electrical appliances, the service size may need to be re-evaluated. There are many existing older homes and commercial locations with electrical services that were acceptable at the time they were built. Over the years with the addition of new electrical appliances, these services may no longer be adequate for their situation. An electrical contractor should review these services and determine if modifications are needed.
Believe it or not, there are still several locations within utility territories that have only 120-volt services. Usually these are only 60-amp services. This service was all that was necessary to provide electricity to the few devices available at that time. Technology has brought us many new items to add comfort and convenience to our daily life. Many homeowners are shocked when they purchase a new air conditioner or electric dryer to find out that they will need to modify their electrical service to utilize the equipment. Many tend to be elderly and on a fixed income.
Field markings are crucial to the safety of the equipment, the electrician and the electrical inspector. All attempts should be made by the utility and the customer to maintain the accuracy of these markings. Doing so may mean the difference between life and death!
And remember to consult the utility provider and to secure the required permits from the authority having jurisdiction (AHJ) before beginning the electrical upgrade. The utility provider may need to re-evaluate transformer sizes and make adjustments to their system due to your planned modification. What worked for the utility years ago may need modification today.
Read more by Joseph Wages, Jr.
Posted By Steve Douglas,
Tuesday, January 01, 2013
Updated: Friday, January 18, 2013
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The new standard for cablebus C22.2 No 273 is scheduled for publication by September of this year. This new standard will be the first standard for cablebus in North America. The committee includes the six major cablebus manufacturers in North America, two switchgear manufacturers, CSA, and an IAEI representative.
Cablebus is an assembly
Cablebus is an assembly of insulated conductors with fittings and conductor terminations in a completely enclosed, ventilated, or non-ventilated protective metal housing. In most cases, cablebus will be approved by either certification or field evaluation and is typically assembled at the point of installation from the components furnished by the cablebus manufacturer. Accompanying the cablebus, the manufacturer will provide installation instructions and drawings for the specific installation to facilitate:
a) system design;
c) fire stop rating (where applicable);
d) weatherproof entrance fittings (where appli-cable);
e) bonding, conductor and shield terminations (where applicable);
f) grounding of shields (where applicable) and installation;
g) inclusion of electrical detail of the conductor configuration, together with enclosure dimensions;
h) specification of maximum allowable span support; and
i) vertical installations.
To assist the electrical contractor and electrical inspector the main nameplate will include:
a) The manufacturer’s name, trademark, or other descriptive marking by which the organization responsible for the product can be identified;
b) The electrical ratings:
– rated nominal voltage, (Vrms or Vdc)
– frequency in Hz
– allowable ampacity (Amps), based on ambient temperature* of XX*C, and based on a maximum operating temperature of XX*C- short circuit current rating
– number of phases (poles for dc);
– 3-wire or 4-wire; and
–Maximum continuous current rating _XX_A, when connected to a 100% continuous rated overcurrent device
– Maximum continuous current rating _XX_A, when connected to a 80% continuous rated overcurrent device
*Note: the temperature is the maximum ambient temperature that the equipment was designed to operate in.
c) The month and year of manufacture, at least, shall be marked on the cablebus system in a location accessible without the use of tools.
d) The number of conductors and size per phase.
e) As a minimum, the allowable ampacity (amps) based on a maximum operating temperature of 75°C shall be included on the nameplate.
f) Type of material, such as stainless steel (including the type), aluminum, etc., and, if carbon steel, Type 1 (hot-dip galvanized), Type 2 (mill galvanized), or Type 3 (electrodeposited zinc), as applicable. If the manufacturer’s catalogue number marked on the product would readily lead the user to the required information published by the manufacturer, this marking is not mandatory;
g) a warning label that reads, "WARNING! DO NOT USE AS A WALKWAY, LADDER, OR SUPPORT FOR PERSONNEL; and
h) the design drawing number for the specific installation.
Maximum continuous current rating
The maximum continuous current rating will assist in the application of CE Code Rules 12-2260 and 8-104 and help provide consistency with respect to conductor loading. In addition to these nameplate markings, cablebus will be one of two classes corresponding with the Items (a) and (b) in CE Code Rule 12-2252. CE Code Part I Rule 12-2252 states:
12-2252 Use of cablebus (see Appendix B)
Cablebus shall be permitted for use where
(a) protection from contact with conductors is provided by design and construction of the enclosure; or
(b) installation is intended in areas
(i) accessible only to authorized persons;
(ii) isolated by elevation or by barriers; and
(iii) where qualified electrical maintenance personnel service the installation.
Class A cablebus is designed with protection from conductors contact provided by the design and construction of the enclosure. Class B cablebus is intended to be installed in areas accessible to authorized persons, isolated by elevation or by barriers, and where qualified electrical maintenance personnel service the installation.
Read more by Steve Douglas