Posted By David Clements,
Wednesday, May 01, 2013
Updated: Thursday, April 25, 2013
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In its simplest terms, branding is who we are, how others feel about us, and how industry and the public view us as an organization. Every time a prospective member, a potential customer or the general public contacts us, by whatever means, they formulate an opinion of us which creates our brand.
For example, one of the most successful brands was Tiger Woods, the first "billion dollar athlete.” Tiger, the golfer, was known and loved worldwide; a family man, he was known equally well for his work with underprivileged children and for his foundation. Corporations avidly sought his endorsements. Then an exposure of infidelity dramatically shattered his brand and, to some degree, the brand of those who endorsed him. With his recent wins re-positioning him as one of the world’s top golfers, will it also be a factor in recreating his brand?
Lance Armstrong, the cyclist, won the Tour de France for seven consecutive years, fought cancer, and returned to win again and again. He introduced the collaboration of sponsors, and corporations jockeyed to become sponsors. He also founded charities. Again, the public fervently supported him; he had over four million followers on Twitter. Then the deep dark secret of performance-enhancing drug use crashed his brand and changed the public’s perception of and attitude towards him. Of course, his brand is damaged right now.
Who we are and how others feel about us may also be called character, credibility, and reputation. Character is the combination of moral and other traits which makes one the kind of person one actually is. Credibility is the quality of being believable or worthy of trust. Reputation is the regard in which a person or group is held, especially by the community or the general public.
These elements of branding apply not only to individuals but to governments, businesses, and associations. In order to influence the world, a government must be true to its character and must maintain its credibility. When senators, politicians, and other government officials, acting from self-interest, depart from the country’s character and standards of government, the government loses credibility both at home and abroad.
You may recall that in 1982, Johnson & Johnson faced a major crisis due to someone’s tampering with extra-strength Tylenol capsules once they reached the market shelves; an unknown suspect(s) put cyanide into the Tylenol capsules, which resulted in the death of seven people in Chicago. This event was a potential major blow to the Johnson & Johnson brand. Although Johnson & Johnson knew they were not responsible for the tampering of the product, they assumed responsibility of ensuring public safety first and recalled all of their capsules from the market. The way Johnson & Johnson handled this crisis not only saved lives, but it saved their brand from damage. The public relations industry played an important role in managing the risk that could have damaged Johnson & Johnson’s reputation. Afterward, many companies followed their lead in dealing with major crises. However, others didn’t learn the lesson, such as in the case of Exxon Oil spill.
Starbucks and Apple customers generally develop a powerful and visceral emotional attachment to their brands. Could it be that these companies are exactly who they claim to be, and that they deliver what their customers want? It is certainly true that each of these companies jealously guard their reputations and the consistency of their brands. They obviously have learned that every little thing matters.
Has IAEI learned that? Let’s look at ourselves and ask two simple questions: Who are we? and What do others think of us? Confusing taglines and multiple logos do not make IAEI; character, credibility and reputation do. These elements are important:
Who are we really? IAEI is a group people who have chosen to work together toward the common goal of safe and compliant electrical installations. Do we understand that "we” means "all of us,” not just our officers or staff? Do we stand firmly on our moral and ethical beliefs? Are we joyful, excited, and forward-looking? Passion is contagious; therefore, it is essential that we truly enjoy and believe in what we do and stand for. If we do, others with the same passion will want to be part of our association and will talk about IAEI in a positive manner.
What are our skills and expertise? We must clearly and specifically identify what we do best and what are our core strengths. The more we focus on what we do best, the more efficiently we do it and the more likely we are to succeed.
What are our vision, goals, and strengths? We should not pattern our goals after those of other associations or groups. The goals must be our own and must be supported by our strengths. We must have our own identity, unique from others.
Over the next several months the International Office will be identifying ways to increase our brand recognition. In the meantime, every little thing matters! Never underestimate the affect that you, as an individual, have on the overall brand of IAEI.
Read more by David Clements
Posted By Underwriters Laboratories,
Wednesday, May 01, 2013
Updated: Friday, April 26, 2013
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Can I use any UL Listed grounding lug evaluated to UL 467 for grounding a photovoltaic (PV) panel or supporting rack system? What devices are evaluated for grounding and bonding PV modules and mounting racks to comply with 2011 NEC Section 690.43(C), (D), and (E)?
No, UL certified (Listed) grounding and bonding devices are not automatically evaluated for grounding or bonding PV modules unless the Listed PV module or panel’s installation instructions identify that device as suitable for grounding or bonding its modules. Grounding and bonding lugs are evaluated for compliance with the Standard for Safety for Grounding and Bonding Equipment, UL 467, and are certified (Listed) under the product category Grounding and Bonding Equipment (KDER) located on page 224 in the 2013 UL White Book and online at www.ul.com/database by entering KDER at the category code search field.
The Guide Information for this product category indicates that grounding and bonding equipment intended for use in PV systems is additionally investigated in combination with the PV module/panel (see QIGU) to the applicable requirements for such products. Installation instructions provided with the PV system identify the specific grounding and bonding device that has been investigated and intended for use with that system. PV panels are certified (Listed) under the product category Photovoltaic Modules and Panels (QIGU) located on page 339 in the 2013 UL White Book and also online at www.ul.com/database and enter QIGU at the category code search.
Each PV panel or module and its frame and mounting systems is different, made of different materials and configurations so that a grounding or bonding device that has only been evaluated for compliance with UL 467 alone has not been evaluated for use in PV systems and doesn’t address the special conditions of grounding and bonding each uniquely constructed PV module frame to the wiring system and the module supporting racking systems. UL 467 alone doesn’t address the different weather conditions and conditions of mechanical loading such as the panels themselves and snow and wind loads that can affect the integrity and reliability of the grounding and bonding systems of PV systems over time.
Grounding and bonding devices as well as mounting and racking systems specifically evaluated for PV systems are UL certified (Listed) under the product category Mounting Systems, Mounting Devices, Clamping Devices and Ground Lugs for use with Photovoltaic Modules and Panels (QIMS) located on page 343 in the 2013 UL White Book and also online at www.ul.com/database and enter QIMS at the category code search field.
Products certified under the QIMS product category are evaluated for compliance with the Outline of Investigation for Rack Mounting Systems and Clamping Devices for Flat-Plate Photovoltaic Modules and Panels, UL Subject 2703. This category covers photovoltaic (PV) mounting systems, mounting devices, clamping devices (which may be for bonding and/or mechanical loading) and ground lugs intended for use with specific PV modules and panels and specified module frames and mounting structures as identified in the individual Listings. Both mounting systems and clamping devices may be investigated for mechanical mounting alone, or mechanical mounting and ground bonding as identified in the individual Listings. Ground lugs may be investigated for use with specific PV modules, specific PV module frames, or specific mounting-system rails.
The installation of these mounting systems, clamping devices or bonding devices is intended to be in accordance with ANSI/NFPA 70, National Electrical Code, in addition to any applicable building codes. Authorities having jurisdiction should be consulted as to conformance with applicable building codes, including the class of roof covering.
The devices certified under this category can be identified by the UL Listing Mark on the product that identifies it as one of the following product names: "Photovoltaic Mounting System,” "Photovoltaic Module Clamping Device,” "Photovoltaic Mounting Device,” "Photovoltaic Bonding Device,” "Photovoltaic Mounting and Bonding Device” or "Photovoltaic Ground Lug.” The word "photovoltaic” may be abbreviated "PV.”
The installation instructions will identify the panels, modules and racking systems as appropriate for which they have been certified. That information can also be found on UL’s Online Certification Directory at www.ul.com/database and enter QIMS at the category search field, then click on the specific manufacturer. The certification information will detail the specific installation criteria of what the devices are certified (Listed) for, as well as the products they are certified for use with.
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UL Question Corner
Posted By Joseph Wages, Jr.,
Wednesday, May 01, 2013
Updated: Friday, April 26, 2013
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My First Tunnel
Remember your first tunnel? I do; but now, it not only involves me but also my wife and children. Driving through the tunnel has become an event my family and I look forward to when we travel to the state of Alabama. The tunnel I speak of runs beneath Mobile Bay. My first encounter came at age sixteen, while I was on vacation with the Rankin Family to the white beaches of Gulf Shores, Alabama. Even though I will never forget that vacation and the fun I had on the beach and while fishing in the gulf, the tunnel really got my attention.
At first, it was alarming that we would be traveling in an automobile through a small shaft under a large body of water; I was concerned that if something happened and all that water came rushing in, we would all die. But an interesting distraction happened while we were in the tunnel: happy-go-lucky kids, in numerous vehicles, were all honking their horns while inside the tunnel. This small act relieved a lot of the tension in me, and before I knew it we were out of the tunnel on the other side of the bay.
I still encounter tunnels on a daily basis. In the Dallas area, I have passed through roadway tunnels as well as through tunnels associated with the public transit system (DART). In the Northeast, I have experienced the Big Dig tunnel in the Boston, Massachusetts area. Driving back to Northwest Arkansas to visit family and friends I pass through the Bobby Hopper Tunnel, the first tunnel in Arkansas to go through a mountain and the connection to the River Valley with the enchanted area of the state known as Northwest Arkansas.
From the roadway tunnels that pass under interstate highways to smaller tunnels that allow for pedestrian and bike flow under a busy intersection, tunnels are everywhere. These locations serve a purpose that allows for safer and easier travel to millions of people around the world. They are also examples of great engineering and architectural achievements that span throughout world history.
Photo 1. Tunnel under a major intersection for pedestrian/ bike traffic. Notice signage above the entrance stating, "Keep Right Through Tunnel.”
Tunnels and the NEC
So, with tunnels comes a need for lighting and, in some cases, ventilation; but where does one go to find guidance toward the installation requirements for these areas? How do we decide which type of wiring method, device or luminaire to install in these locations? Are these areas subject to physical damage? What does the NEC have to say about these locations? Does the terminology that the NEC and the public use even have the same meaning?
Defining a Tunnel
When dealing with this subject one must know what defines a tunnel. In the NEC we typically find definitions in Article 100, but this is not the only place a definition can be found. Definitions that relate to a particular article are found in the .2 locations within the article. Upon searching, we find that there is no definition of tunnels within the NEC. This leads me to Webster’s Dictionary for their help.
When used as a noun, a tunnel is defined as a passageway through or under something, usually underground (especially one for trains or cars); example, "The tunnel reduced congestion at that intersection.” This definition seems to be addressing the two topics I mentioned in this story: we have passed under a large body of water and then under a busy city intersection. But what can we find within the NECtowards installation guidance and practices when there is no definition of these locations? More searching and a word search of the NEC finds the word "tunnel”; but in reading that section in Article 110, it appears that this applies to installations of "over 600 volts.” This code language does not help me apply the requirements to the pedestrian tunnels I want to discuss.Additionally, what guidance can we find toward what types of conductors and conduit methods are acceptable in these locations? Are these areas considered as dry, damp or wet locations? This is something that must be addressed now before we purchase materials, install the electrical devices, call for an inspection, and then face an inspector who ultimately has the final say. His or her decision might not be the same as ours, and could cause additional work, expense, and unnecessary hard feelings.
A tunnel can mean different things to different individuals. I recently passed a drainage culvert under a highway. A smaller culvert is not a tunnel to me, but to a beaver it becomes a great and safe passageway from one side of the road to the other. Based on the above definition, the culvert could be defined as a tunnel. It is noteworthy for the reader to be aware that there have been electrical conduits installed in what one might consider a culvert.
Photo 2. View of trails converging at the tunnel entrance.
A word search for the word "tunnel” was conducted for the 2011 NEC. The majority of the hits occurred in Article 110, Part IV, Tunnel Installations over 600 Volts, Nominal, but the installations I am interested in are applications under 600 volts. I had one other hit for tunnels in Section 210.6, Branch Circuit Voltage Limitations. This was for 600 volts between conductors and dealt with permanently installed auxiliary equipment for electric discharge lamps for luminaires. This is still not helpful for my installation. However, this information would be beneficial for the installation of a "utility” tunnel and would be very much applicable. This sort of tunnel would be installed between two buildings and used in conjunction with other utilities for the routing of their systems.
Wet, Damp or Dry Location?
How do we determine if a tunnel is a wet, damp or dry location? It is highly advisable to schedule a meeting with the local authority having jurisdiction (AHJ) for his/her viewpoint before you begin your project. While visiting various pedestrian tunnels I have observed several wiring methods. I have encountered set screw and compression EMT connectors and fitting. I have seen EMT conduit installed with one-hole straps to the wall of the tunnel. I have also seen installations of EMT conduit supported by unistrut with unistrut straps.
It appears to me that there are many interpretations of the tunnel area as it pertains to a wet, damp or dry location. We must also remember that changes in environmental conditions may change the condition of our tunnel. Heavy rains may change a typically dry condition to a wet or damp location. This must be considered when you choose the wiring method for these locations.
So who are these individuals that fill the role of an AHJ? The AHJ has final approval for your electrical project and is burdened with a tremendous responsibility for the safety of the public. This involves both property and personnel associated with various locations. These individuals are typically experts within their fields and highly respected. Let’s refresh ourselves on the NEC definition of the AHJ:
Authority Having Jurisdiction (AHJ). An organization, office, or individual responsible for enforcing the requirements of a code or standard, or for approving equipment, materials, an installation, or a procedure.
Informational Note: The phrase "authority having jurisdiction,” or its acronym AHJ, is used in NFPA documents in a broad manner, since jurisdictions and approval agencies vary, as do their responsibilities. Where public safety is primary, the authority having jurisdiction may be a federal, state, local, or other regional department or individual such as a fire chief; fire marshal; chief of a fire prevention bureau, labor department, or health department; building official; electrical inspector; or others having statutory authority. For insurance purposes, an insurance inspection department, rating bureau, or other insurance company representative may be the authority having jurisdiction. In many circumstances, the property owner or his or her designated agent assumes the role of the authority having jurisdiction; at government installations, the commanding officer or departmental official may be the authority having jurisdiction.
As we can see from the definition, an AHJ can be made up of different individuals. Who wears that hat depends on the location you are working in. Become familiar with the local AHJ, as this person can become your greatest asset towards installing a compliant electrical installation. The AHJ will use his/her experience and expertise to make a determination of what is best for that particular situation. But the AHJ will also take into consideration three definitions within the NEC to help mold that decision.
Photo 3. An access point to an underground utility tunnel
Proper Interpretation and Enforcement Starts with Understanding Definitions
Let’s look at the definitions we are to consider when making decisions about these locations. To begin, let’s go to Article 100 in the 2011 NEC. We need to review the definitions that are going to help us make this decision.
Location, Damp. Locations protected from weather and not subject to saturation with water or other liquids but subject to moderate degrees of moisture. Examples of such locations include partially protected locations under canopies, marquees, roofed open porches, and like locations, and interior locations subject to moderate degrees of moisture, such as some basements, some barns, and some cold-storage warehouses.
Location, Dry. A location not normally subject to dampness or wetness. A location classified as dry may be temporarily subject to dampness or wetness, as in the case of a building under construction.
Location, Wet. Installations underground or in concrete slabs or masonry in direct contact with the earth; in locations subject to saturation with water or other liquids, such as vehicle washing areas; and in unprotected locations exposed to weather.
Again, it must be stressed that these locations within tunnels are subject to the interpretation of the AHJ. Let’s revisit photo four; it could be argued that this is a damp location. It could also be considered a wet location. According to the definitions, this area could be subject to moderate degrees of moisture or, in some instances, saturation with water or other liquids. In this installation, the AHJ determined that this area meets the requirements of a dry location and allowed the wiring method shown in the picture. Right or wrong, it is the judgment of the AHJ and has been approved.
Photo 4. A "4 by 4 Combo Box” at the entrance (interior) of a tunnel. Notice corrosion on screws (inset photo).
Photo 5. Electrical installation on the exterior of the tunnel is considered a "wet” location.
In photo five, we see an installation on the exterior of the tunnel location. This area has been deemed a wet location from the definition stated above. It is noteworthy that an area does not have to be located outside to be considered a wet location. An example of an interior location that could be considered a wet location would be a poultry processing facility, which is subject to saturation from high pressure washdowns at the end of various shifts. This environment requires the electrical contractor to install the correct electrical devices and components that will "survive” as well as function properly under such conditions.
Luminaire Types within Tunnels
Luminaire types within fixtures must also follow the guideline of the above definitions as well as their manufacturer’s installation instructions. Protection of the lamp must also be considered due to the environment and also due to vandalism that sometimes occurs. Lighting is extremely important for the safety of the user of the trail/sidewalk system. Unsavory individuals with malicious and/or dishonorable intentions sometimes lurk in dimly lit areas. Properly lit areas help to deter the would-be unsavory individual from unleashing his devious intentions.
Lighting also allows for people to see in the tunnels. Walkers, joggers and bicyclists need lighting in these locations to avoid possible injuries due to collisions. It goes without saying that these requirements are also necessary for tunnels that allow for vehicular movements as well. One could only image the calamity that would result from improperly lighted tunnels.
Photo 6. Types of luminaries used in tunnels
Ventilation is an important consideration for life safety and for dissipation of heat from various electrical devices. Heat produced by transformers or lighting ballasts could accumulate and contribute to unfavorable conditions within these locations. Again, each tunnel is different. A small tunnel, as pictured above, top right, would not have many items that would produce a lot of heat. Being relatively short allows for the air to move freely through the tunnel. The absence of motor vehicle use does not allow for the entrapment of dangerous vapors. In larger tunnel installations, there exist many heat producing devices and ventilation would need to be considered. Ventilation will also allow for air exchanges that are necessary to remove moisture and to allow for air exchanges within these areas. Because these areas are subject to repair and alteration by qualified persons, their safety must be considered.
Roadway Tunnels Are Another Animal Altogether
Roadway tunnels are governed by another important document, which addresses lighting, ventilation and other electrical concerns that are not addressed within the NEC. These locations are still referred to as "tunnels” and deserve mention in this article.
NFPA 502 is a safety standard that covers roadway tunnels as well as other highway structures. Within this document, Chapter 12 is dedicated to the electrical systems found in these locations.
NFPA 90 lists several items that shall be connected to the emergency power system. Emergency lighting is one of these items, as one might think. Total darkness for emergency response personnel in the likelihood of an emergency would not be acceptable. Signaling features such as tunnel closure and traffic control and exit signs are to be on the system too. The other remaining items include: emergency communication, tunnel drainage equipment, emergency ventilation, fire alarm and detection, closed-circuit television, and video and firefighting equipment.
Emergency power for road tunnels is required to conform to Article 700 of NFPA 70 for certain categories of tunnels as described in Table 7.2 in NFPA 502. This part deals with fire protection and fire life safety requirements in these locations.
NFPA 502 is an interesting document. It reinforces that not all electrical requirements can be found in the NEC. Other documents must be consulted regarding specific installation practices. Please consult the NFPA website at www.nfpa.org for more useful information concerning this and other publications.
My journey through tunnels has addressed many issues, and has been a brief overview or things to consider. There are many terms that one must be familiar with before conducting an electrical installation or inspection for a tunnel. The types of locations and who makes these determinations are crucial in the success of your installation. A decision must be made as to what type of tunnel one is dealing with before you can begin the work. The three discussed have specific requirements based on their location.
I hope you take a few moments to observe the workings of the common tunnel. I think you will be surprised at some of the electrical requirements that must be considered. Think about some of the decisions that need to be addressed for these locations. Good communication between the installer and the AHJ will help with an understanding of the requirements of the NEC and of other documents. Tunnels can provide years of enjoyment and safety for individuals within your community. Together we can make sure they will be functioning correctly for years to come.
Read more by Joseph Wages, Jr.
Posted By Howard Herndon,
Wednesday, May 01, 2013
Updated: Friday, April 26, 2013
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The rooftop temperature adders in NEC310.15(B)(3)(c) were first included in the 2008 NEC. The proposal to include this requirement was based on a study that showed increased temperatures in conduits on rooftops in direct sunlight. However, there remained unanswered questions for the Southern Nevada Chapter of IAEI; they live with extreme temperatures, and yet installers and inspectors have not seen evidence of failure related to rooftop installations. Since the impact on conductor sizing due to this requirement is significant in the Southern Nevada area, the Chapter funded an experiment to gather more information about rooftop electrical installations exposed to direct sunlight.
In conjunction with SouthWest Electritech Services, a third party independent electrical testing firm, Chapter members designed a test setup to determine if actual electrical installations on rooftops experienced the damage to conductors reported to Code-Making Panel 6 in the 2008 NECdevelopment process. The conductor sizes used were based on NECrequirements, but without the temperature correction factors required by 310.15(B)(3)(c).
Test Setup Installation and Data
In order to capture data during the hottest part of the year, the test setup was installed July 7, 2012; data was collected and analyzed for a two-month period. The test period captured data during the hottest days of 2012, which was reported to be the hottest summer on record for Las Vegas. Licensed electricians installed the electrical conductors and thermocouples. Southwest Electritech Services employees installed the data loggers, current meters and recording software.
The test installation was located on a facility that is a two-story warehouse with office area on the first floor (occupying about 25% of the first floor). The construction is concrete tilt up with a wood truss built up roof, using asphalt rolled roofing. The second story was not in use throughout the duration of the testing, and therefore was not conditioned.
Photo 1. Rooftop installation for temperature experiment in Las Vegas
Temperature data was collected in three conduit locations. Since the electrical equipment was already in place, an additional 20 feet of EMT was added to each circuit (photo 1) to allow for the installation of the monitored conductors and thermocouples. The runs were installed running east to the west in a location chosen to get maximum sunlight exposure during the hottest portion of the day.
Two thermocouples were installed in conduits with wire that was unloaded and attached to an evaporative (swamp) cooler in two different conduit sizes. Another thermocouple was installed in a conduit with wire that was loaded and attached to an air conditioner. The thermocouples were carefully installed in such a way as to contact the conductor installation and in no way be in contact with the EMT itself (photo 2).
Photo 2. Thermocouple installation
The first setup had five 12 AWG conductors with THHN/THWN-2 insulation. These were installed in 10 feet of 1/2″ EMT and the return run in 3/4″ EMT. A thermocouple was installed in each of these runs. Also, a thermocouple was installed inside the disconnect of the evaporative cooler these conductors fed, and then one thermocouple was installed to measure outside ambient temperature at approximately 48″ above the roof surface, near the top of the cooler. The conduits were supported on industry manufactured roof support block approximately 6″ above the roof surface (photo 3).
Photo 3. Height above rooftop
The second installation was connected to a 5-ton rooftop mounted all-in-one A/C unit that was in use for the duration of the test (photo 4). This unit supplies cooling to the first floor offices of the facility. It was found that this unit frequently ran for over 3 hours at a time, giving us good data on the conductors feeding it. Measuring temperature readings on the insulation of the loaded conductors provided a real world application (photo 5). Since the A/C was the only load on these conductors and ran for more than three hours at a time, it was a good test of an installation with continuous loading and without diversity.
Table 1. Highest recorded temperatures for each thermocouple in conduit
Table 2. Highest recorded temperatures for thermocouple in disconnect and junction box
Photo 4. AC label
This installation consisted of two 6 AWG THHN/THWN-2 conductors with a 10 AWG equipment grounding conductor, installed in 1″ EMT, again on the same type of roof supports as the first installation. For this installation, a thermocouple was installed in one of the runs of the 1″ EMT, one was installed in the junction box about 18″ above the rooftop and the outside thermocouple was installed about 6″ above the rooftop so that it would have a western exposure.
Intellirent, a company specializing in electrical test equipment, provided certified, calibrated data loggers and current meters, as well as the computers and software used to download and analyze the data. Data was collected every 60 seconds by each of the data loggers for each of the measurement points (photo 6). This produced a great deal of data. In order to report meaningful information, the highest temperatures recorded each day were compared to nationally reported ambient temperature values obtained from the NOAA database. This comparison resulted in a maximum daily differential temperature.
Photo 5. Current meters
Photo 6. Data logger and software
Ambient temperature data was also collected with the thermocouples installed in two locations on the roof. In general, these ambient thermocouples recorded temperatures higher than that reported by NOAA. Since installers and inspectors will typically depend on nationally reported data, we chose to use the NOAA data to calculate the differentials. This resulted in a worse case differential than if the measurements from the ambient thermocouple installed on the rooftop were used.
During the experiment, it was found that on an actual rooftop in Las Vegas in an actual installation of conduits with wires (both loaded and unloaded), the temperatures measured did not approach the temperatures predicted by the adjustment requirements in Section 310.15(B)(3)(c). On the contrary, the average temperature differential recorded was 15°F for unloaded conductors in conduit. Since the conduits were installed approximately 6″ above the rooftop, the adjustment factors required by the values in the 2011 NEC Table 310.15(B)(3)(c) would require an adder of 30°F, twice the actual measured values.
Additionally, it was observed during this real world rooftop test that the loaded conductors never exceeded the operating temperature of the conductors or terminations during the testing. Since the originally stated reason that the additional temperature correction was added to the code was the premise that conductors would exceed their rated temperature, this testing shows that the premise was false. The highest recorded temperature was 148°F for fully loaded conductors. The maximum ambient temperature on that day was 114°F according to NOAA, resulting in a differential of 34°F for loaded conductors in conduit operating at the maximum load recorded on the air conditioning circuit (37 amps). Much of this differential was due to the heat generated by the current flowing through the conductor, not the heating of the conduit by sunlight exposure.
The conductors are rated at 194⁰ F and the connections are limited to 167⁰ F. Comparing these limitations to the measured temperatures indicates that even should the temperature be more extreme or if there was additional load placed on the circuit, the conductors and connections are unlikely to exceed their rated temperature.
2014 NEC Proposal 6-29 requested even higher values for temperature correction - for this installation, 50⁰ F would have been required. CMP-6 decided in the Comment phase to reject Proposal 6-29 in Panel Comment 6-14a. This decision was based in part on the information gathered during the experiment described in this article, which was presented to CMP-6 at the ROC meeting in December 2012.
The test results indicate that the added temperature correction values in 310.15(B)(3)(c) are unnecessary for rooftop electrical installations in the Las Vegas area. Since Las Vegas is one of the hotter areas in the country, it is likely that the correction factors are unnecessary for other areas, as well. These findings support the statement submitted by IAEI CMP-6 principal John Stacey with his negative vote to 2014 NEC Comment 6-16, which stated that "The requirement in Section 310.15(B)(3)(c) increases cost with no benefit to the safety of people or the protection of equipment, and this requirement should be removed in its entirety.”
Read more by Howard Herndon
Posted By Leslie Stoch,
Wednesday, May 01, 2013
Updated: Friday, April 26, 2013
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The Canadian Electrical Code’s long-winded definition of grounding is shown as: "a permanent and conductive path to the earth with sufficient ampacity to carry any fault current liable to be imposed on it, and of sufficiently low impedance to limit the voltage rise above ground and to facilitate the operation of the protective devices in the circuit.” This article discusses a number of permissible grounding requirements and methods covered by the Canadian Electrical Code.
As you no doubt noticed, the definition covers a lot of ground (excuse the pun), as it includes all of the electrical code requirements, including that grounding must:
- be permanent and continuous;
- carry available fault currents without failure;
- have sufficiently low impedance to ensure
- that voltage rise during a ground fault will
- not cause damage to components such as sensitive electronic devices; and
- ensure that fuses and circuit-breakers react
- quickly enough to prevent electrical failures,
- fires and shock hazards.
In some cases, the Canadian Electrical Code does not require that all electrical circuits be solidly grounded. In others, the CEC prohibits it. Rule 10-108 specifies that circuits supplying electrical arc furnaces (such as a scrap metal melting furnace) need not be grounded. Rule 10-110 specifies that circuits supplying cranes operating above highly flammable fibres in Class III hazardous locations must not be grounded. This provision reduces the probability of arcs and sparks along the crane rails and the current collector, thereby limiting the risk of a flash fire. Rule 10-112 permits ungrounded circuits supplied by a transformer incorporating a grounded faraday shield between the primary and secondary windings when permitted by other rules or in special cases to prevent electrical accidents (underwater swimming pool speakers, for example).
We are all at ease with solidly grounded electrical systems. They provide the benefit of limiting system voltages to ground and minimizing voltage stress on wiring and electrical equipment insulation. Solidly grounded systems may experience high ground fault currents, but when correctly arranged, faults are quickly detected and removed by fuses or circuit-breakers before there is damage. In an industrial environment, shutting down during a ground fault may be impracticable, and therefore other grounding methods are recognized in the Canadian Electrical Code. Rule 10-106(1) requires that except where otherwise specified, 120/240-volt and 120/208-volt AC systems or circuits that include a neutral conductor must be grounded.
Ungrounded delta systems don’t require shutting down during a single-phase ground fault since they have no reference to earth. However, they come with risk of equipment damage as well as personal safety risks when a second phase becomes inadvertently grounded. In addition, overvoltages tend to shorten the lives of electrical equipment. Rule10-106(2) requires that ungrounded delta systems must be equipped with ground fault detection devices such as ground indicating lights to ensure that inadvertent grounds are removed as quickly as possible. But you know what happens to those — the indicating lights burn out and are not promptly replaced, leaving people and equipment at risk.
A nice compromise is resistance grounding which permits operation during a single-phase ground fault. Resistance grounding offers a number of important advantages. It limits ground fault currents by connecting a grounding resistor between the electrical system neutral and the system ground electrode and thereby:
- minimizing damage to electrical wiring and equipment;
- reducing mechanical stresses;
- reducing arc flash and arc blast hazards ;
- controlling overvoltages; and
- no shutdown required during a ground fault.
Finally, effective grounding helps ensure that faults are quickly removed. Rule 10-500 defines effective grounding. Sound familiar? But what’s this about "impedance sufficiently low”? Appendix B provides an answer: impedance of the ground fault path should be sufficiently low so as to permit at least five times the setting of the circuit overcurrent devices to flow during a ground fault. For example, for a 400-ampere circuit, at least 5 times 400 amperes or 2000 amperes must be allowed to flow during a ground fault.
As with earlier articles, you should always check with the electrical inspection authority in each Province or Territory as applicable for a more concise interpretation of any of the above.
Read more by Leslie Stoch
Posted By Randy Hunter,
Wednesday, May 01, 2013
Updated: Friday, April 26, 2013
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Article 250 is the largest article in the National Electrical Code. It is often the most dreaded by those new to the code, and sometimes even by those who have dealt with the code for years. Some of the terminology is confusing and conceptually difficult to follow. In keeping with the Combination Inspector emphasis of this series of articles, we will cover those items which I have previously taught to inspectors who weren’t electrical by trade. In doing so, we will not cover every section of Article 250, but concentrate on those that are used most commonly by multi-trade inspectors.
Photo 1. Here is a very small sampling of some of the devices designed for grounding connections. Please note the bottom right device will bond the grounding electrode conductor to an enclosure or raceway.
Photo 2. This shows a sampling of bonding jumpers that are provided by the factory for main bonding jumpers in panels.
The scope of this article covers general requirements for grounding and bonding of electrical installations. First, we have two definitions that we need to consider in order to help us understand the principles of grounding. Effective grounded-fault current path is an intentionally constructed, low-impedance electrically conductive path designed and intended to carry current under ground-fault from the point of a ground fault on a wiring system to the electrical supply source and that facilitates the operation of the overcurrent protective device or ground-fault detectors on high impedance grounded systems. Ground-fault current path is an electrically conductive path from the point of a ground fault on a wiring system through normally non-current-carrying conductors, equipment, or the earth to the electrical supply source. Both of these are best understood as the emergency path the current takes in the event of a ground fault (which is a short from an ungrounded conductor to ground). If we have a good path, then the high current flow back to the source should operate the overcurrent device and shut down the system.
As you probably noticed, the main difference is that one is an intentionally constructed path, which is what we hope to have, and the second is any path in which the current may flow. To give a real life example of this, I remember getting a service call to a house which had smoke coming out of the walls. As luck would have it, I was very close and beat the fire department to the site. The first thing I did was shut off the main at the service and the smoke started to lessen. By the time the fire department got to the house, there was hardly any visible smoke coming out of the walls, just the smell of burning wood. The fire department broke open a hole in the wall and the plaster reinforcing wire lath had been burning its way into the wood studs, just like one of the old wood burning kits we used to have as kids. The only electrical device near this part of the dwelling was an air conditioner compressor unit. I opened the junction box of the unit and the grounding wire wasn’t connected. If it had been connected, there would have been a low impedance path that carried the current back to the breaker and caused it to open. However, one ungrounded conductor had shorted out and the only path for the fault current was through the copper refrigeration lines to the wall where they contacted the metal lath wire and energized it, causing it to heat up to the point of burning the wood framing. Without a good fault-current path back to the overcurrent device, the device just sees an additional load, but not enough to make it trip in a timely fashion.
Photo 3. The bare copper conductor here is the grounding electrode conductor that has been connected to the concrete- encased electrode (rebar) stubbed up from the building footing.
Where grounding starts
Now that we understand why we need good grounding paths, let’s start back at Part III Grounding Electrode System and Grounding Electrode Conductor, since this is where grounding starts, with a good connection made to the earth. The connections to the earth are called electrodes, and the code describes eight different types of electrodes. We will only cover the concrete-encased electrodes and ground rods, since they are the ones most commonly used in construction today. Details are found in 250.52(A)(3) for the concrete-encased electrode. This is the preferred electrode for any new construction, and it performs very well due to the fact that the concrete continues to extract moisture from its surrounding soil and has great contact with the earth simply due to its weight.
The second most common is rod or pipe electrodes, which are covered in 250.52(A)(5). Ground rods are very common and make a good connection to the earth due to the fact they are required to be 8′ in length and reach deep enough into the earth. This is the best option when adding a grounding electrode system to a facility where you can’t incorporate a concrete-encased electrode.
There are other electrodes covered in 250.52 (which you should take time to read), but I will mention one that is fading from use, and that is metal underground water pipe. For decades, it was the most common source of grounding electrode; however, with the advances made in water system products, it was found that if a facility had a metal water line that failed, it was being replaced by a non-metallic system. When that occurred, we lost our grounding electrode. Even in new housing construction, I haven’t seen a metallic water pipe feeding a residence in two decades. If you review 250.53, you will find the installation methods for each of the grounding electrodes mentioned above.
One item to note is a change made in the 2011 edition of the NEC for 250.53(A)(1) related to rod electrode installations. In the 2008 NEC 250.56, it stated that a rod, pipe or plate electrode that didn’t measure 25 ohms or less would have to be supplemented by an additional electrode. In the field, this meant an inspector had to have some assurance that one device would measure 25 ohms or less, but how do you do that? Does the inspector test it? Generally no, so it was up to the contractor to prove it met this code requirement. In practice it saved time and multiple trips to the site if the contractor simply installed two rods and then didn’t have to worry about the measurement at all. So in the 2011 NEC 250.53(A)(2), it states you will install two rod electrodes, and then there is an exception which allows one rod if you prove it meets the 25 ohms or less requirement. This is a good example of how the code is often modified to match what is actually the general practice in the field.
Photo 4. This is an example of 250.104, bonding of other systems. This is gas piping which goes throughout the house and may have the possibility of becoming energized and therefore shall be bonded.
Connecting to items to be grounded
So now that we have our actual connection to the earth, we have to connect it to those items we are trying to ground. To do this we use a conductor called the grounding electrode conductor. The grounding electrode conductor is covered in 250.62 through 250.68. First, this conductor must be made of a material resistant to any corrosive conditions to which it may be exposed. This could be various things, such as a corrosive soil, fumes within a building, or any other conditions that may damage it. Again, if we lose this connection to the electrode, we have totally lost our grounding system.
Article 250.64 is where we find the details on the installation of the grounding electrode conductor. Covered is how to secure and protect it, and depending on the size, it may need some physical protection such as a raceway. Please note that if protected by a metallic raceway, and the raceway isn’t continuous from the equipment to the grounding electrode, then the raceway must be bonded at each end to the grounding electrode, see 250.64(E). The reason for this is really pretty simple: the impedance of the conductor and the raceway are different and the current will travel at different speeds from one end to the other, so if they are not bonded and there is an air gap at one end or the other, it will arc. Repeated arcing will cause damage to the electrode conductor. It must be securely fastened to the surface on which it is carried and can be run through framing members. It shall be installed in one continuous length without a splice or joint; however, if it absolutely has to be spliced, there are four very specific ways to do it in 250.64(C). Remember this is a crucial element to the safety of the electrical system, and anytime we have a splice or connection we have created a possible failure point, so we try to avoid any conditions which may create a weak point.
Photo 5. In both of these photos, the grounding electrode conductor is the bare copper. It is being terminated on the grounded terminal location in these residential main services. Note the aluminum bussing that continues into the meter section in each of these photos to connect directly to the utility-grounded service conductor, which meets the main bonding jumper requirement.
Also please note 250.64(D), which has allowances for a single electrode and conductor to be tapped to serve several service-entrance enclosures located in close proximity to one another. Now for one of the key elements of the grounding electrode conductor — how do we size it? In Article 250.64(D)(2) we find that each electrode conductor is to be sized according to 250.66, and there we find that generally it is sized according to Table 250.66, which lists the size of the service conductors on the line side of a service and then shows us the size of the grounding electrode conductor. The sizing is based on the size of the conductors feeding the service, since we don’t have an overcurrent device on the service conductors. Refer to Table 250.66 and also review the notes, which cover the methods for multiple sets of conductors.
Now for three applications where we don’t need to use the table and that are covered in 250.66(A), (B) and (C): these deal with conditions where we have a single conductor which is the sole connection to the grounding electrode for rod, pipe, plate, concrete-encased and ground-ring electrodes. In these sections we find a new maximum size conductor requirement for each of these types of electrodes. For example, on a concrete-encased electrode you are not required to use a conductor larger than a 4 AWG copper conductor, no matter what the size of the service. I must caution you that if the design professional has designated a larger conductor, you would be obligated to follow his requirements. Remember that the code is a minimum and can always be exceeded.
Connecting to the grounded service conductor
So now that we have the electrode and the electrode conductor, what do we do with it? In 250.24 Grounding Service-Supplied Alternating-Current Systems, we find the answer. First, in 250.24(A) System Grounding Connections, we discover that the grounding electrode conductor shall be connected to the grounded service conductor. As simple as it sounds, this is one of the most critical requirements of the code. The connection can be done in various ways as outlined in 250.24, so please follow along in the code as we go.
This should be the only point where we connect together the grounded conductor, the grounding electrode conductor and the equipment grounding conductors. This is generally done at the main service disconnecting means of a service, utilizing what is called a main bonding jumper [see 250.24(B) and 250.28]. Failure to make this connection can lead to various issues, the least of which will be voltage fluctuations that may damage connected equipment.
Once we move past the service main location, we are not to connect the grounded conductor (remember this is generally referred to as a neutral) to any grounding conductors; this is covered in 250.24(A)(5). If you do, you will create parallel ground fault return paths that may not push the overcurrent device to react in a timely fashion. Or, if you are downstream of a ground fault sensor in either a GFCI or GFP device, it will cause the device to trip.
Connecting to equipment grounding conductor
From the service, the path continues in Part VI Equipment Grounding and Equipment Grounding Conductors. In 250.110 we learn that exposed, normally non-current-carrying metal parts of fixed equipment supplied by or enclosing conductors or components that are likely to become energized shall be connected to an equipment grounding conductor. In the remainder of 250.110 and in 250.112, 114 and 116, we see some specific requirements for various types of equipment. The types of equipment grounding conductors are outlined in 250.118, and the most common would naturally be a wire-type conductor. However, you will also notice within the article that various types of raceway also meet the grounding requirements. I will not go into details of any one of these specific methods, please review for yourselves.
We need to cover 250.119 Identification of Equipment Grounding Conductors, and here we find that these conductors can be bare, covered or insulated. If covered or insulated, they shall be identified with a continuous outer finish that is either green or green with one or more yellow stripes, except as permitted elsewhere in 250.119. Those exceptions make an allowance for conductors larger than 6 AWG, which normally doesn’t come in green from the factory. We are allowed to re-identify using three options: stripping the insulation or covering, coloring or marking at the termination points. Also covered in (B) and (C) are allowances for multiconductor cablesand flexible cords.
Our next concern with equipment grounding conductors is how to properly size them. In 250.122, it states that we shall size them according to Table 250.122. This table is based on the overcurrent device that is protecting the circuit. Basically, the larger the circuit ampacity size the larger the conductor that is required to handle the fault current back to the source and to cause the overcurrent device to operate. A couple of items need to be mentioned here; one is that if the ungrounded circuit conductors are increased in size for any reason, then the related equipment grounding conductor shall be proportionally increased. This might happen if voltage drop requires a larger phase conductor, since the larger conductors will have a higher fault current capacity and we have to compensate for that with a larger equipment grounding conductor.
The other item is found in 250.122(F) Conductors in Parallel, which states that in each raceway where an equipment grounding conductor is used it must be sized in accordance with the other rules in 250.122. So if you have six PVC conduits for a parallel run, you will have to install an equipment grounding conductor in each conduit, and each must be sized according to Table 250.122. However, in the body of 250.122 we find language which states that it will never have to be larger than the ungrounded conductors.
Photo 6. This is another example of bonding piping systems. On the left the water main is bonded, and in the upper left insert we have a poor example of bonding as the connection isn’t making direct contact due to the tape. On the right, I found a fire sprinkler riser at a gas station canopy and was wondering where they made the bonding connection.
Now that we have the equipment grounding conductors run where needed, what do we do with them? The purpose of the equipment grounding conductor is again to connect any normally non-current-carrying metallic parts that may become energized in order to provide what I call the emergency electrical relief system, which is needed to open the protective devices. In Part VII Methods of Equipment Grounding, you will find the details for such things as receptacles, certain boxes, ranges and dryers to name a few; again, please review these more completely on your own.
Connecting metallic items
Bonding is covered in Part V, starting at 250.90. Bonding is simply the connection of metallic items to ensure that we have a connection to the earth. Earlier we mentioned the main bonding jumper within the service, but now we are connecting other parts of the system for the purpose of ensuring electrical continuity to safely conduct any fault current that may be imposed. In 250.96, 97, and 98, we cover the most common bonding items we need to check for on our inspections.
Bonding of enclosures, raceways, cable trays and various other items (including around loosely jointed fittings) need to be addressed. One of the most common points is at factory knock-outs where we just don’t have a good ground path. So how do we size these jumpers? It depends on if you are working on the supply side of a system or on the load side. If you are on the supply side, then you use 250.66, based on the ungrounded conductor size. On the load side, we would use 250.122, which is based on the overcurrent device size. This distinction points out a very good general rule of thumb, which is that if you have an overcurrent device upstream, go to Table 250.122; if there is no overcurrent device, go to Table 250.66.
The last bonding items are in 250.104 and 106, which cover the bonding of piping systems, exposed structural steel and lightning protections systems. Review these requirements and make sure you are getting these items properly bonded in your areas. Often this is overlooked or not properly done as we sometimes tend to get casual about these items.
Connecting to separate buildings
One item which seems to be most overlooked (in housing construction especially) is 250.32 Buildings or Structures Supplied by a Feeder(s) or Branch Circuit(s). At each separate building or structure you should make sure you have a grounding electrode installed. I know this may sound bold, but let me explain. Often these types of projects start small, and you think you are going to have a single circuit, so you use the exception. Then the plan changes and now there are multiple circuits, and it is difficult to later install an electrode. In my local area, the home builders just decided to automatically install a concrete-encased electrode no matter what the original intended use of the separate structure. At times they would only intend them as a workout room, but then they could be converted to a casita (a small house) with a bathroom and cooking equipment, so it was just easier to stub up a rebar as a grounding electrode whether we needed it or not. A little planning ahead sometimes saves a lot of headaches later on.
Insuring reliable connections
The last items to cover are found in 250.8, 10 and 12. Notice that we started at the electrode and worked our way up, and these last requirements cover methods to insure good reliable grounding and bonding connections. This includes such things as the type of components to be used, even down to the types of screws. Ground clamps, which are devices for connecting conductors to various types of building materials, shall be approved for the use and may require protection, so you will have to review the listing and installation instructions on these. Through the years, probably one area of the most creative invention has been in the grounding and bonding process. There are so many products out there and electricians don’t always have access to the proper devices and therefore try to become designers, manufacturers and installers of some of the most unique methods. If it looks a little weird, ask for the literature that should have come with the components. Lastly, we must make these connections to clean surfaces, and that may require the removal of paint or other surface coating to ensure a good metal to metal connection.
This concludes the high level coverage of Article 250. I tried to do it in a logical inspection process from the bottom up, literally. Just remember to open the code book and review it with this article, and remember that grounding is the emergency safety line. Everything electrical will generally work just fine if the ground isn’t done right, but when we have some type of abnormal issue, it is the grounding installation that saves us. This is one of the most important portions of any inspection.
Read more by Randy Hunter
Posted By Ark Tsisserev,
Wednesday, May 01, 2013
Updated: Friday, April 26, 2013
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Apparently, there is some confusion on this subject. Let’s tackle it step-by-step.
Consumer’s service, a feeder and a branch circuit are defined by the Canadian Electrical Code as follows:
"Service, consumer’s — all that portion of the consumer’s installation from the service box or its equivalent upto and including the point at which the supply authority makes connection.
Feeder — any portion of an electrical circuit between the service box or other source of supply and the branchcircuit overcurrent devices.
Branch circuit — that portion of the wiring installation between the final overcurrent device protecting the circuit and the outlet(s)."
Although each of these defined portions of an electrical installation has a different purpose, Rule 8-104 of the CE Code offers absolutely similar fundamental requirements for a selection of a minimum rating of a consumer’s service, feeder or branch circuit.
This Rule also describes ampere rating as follows:
"8-104(1) The ampere rating of a consumer’s service, feeder, or branch circuit shall be the ampere rating of the overcurrent device protecting the circuitor the ampacity of the conductors, whichever is less.”
It means that if the selected ampacity of conductors (based on a particular ampacity table) is, for example, 225 A but the selected rating of the overcurrent device is 200 A, then the ampere rating of such circuit (feeder or consumer’s service) is 200 A.
So far, so good. But what are the main criteria for selecting a rating of a circuit at a specific value? What is the most important reference point? Similarly to a selection of the shoe size, which should be based on the size of the feet (if we want some level of performance and safety), selection of a circuit rating should be based on the calculated load.
Rule 8-104 provides following clarity on this condition as well:
"8-104(2) The calculated load in a circuit shall not exceed the ampere rating of the circuit.”
It means that under no condition selected conductors of a circuit should have ampacity value less than the calculated load, or under no condition the selected O/C device protecting conductors of that circuit should have a rating or setting at the value less than the calculated load in the circuit.
This Rule also provides criteria for determination of whether a calculated load should be considered continuous or not.
"8-104(3) The calculated load in a consumer’s service, feeder, or branch circuit shall be considered a continuous load unless it can be shown that innormal operation it will not persist for
(a) a total of more than 1 h in any two-hour period if the load does not exceed 225 A; or
(b) a total of more than 3 h in any six-hour period if the load exceeds 225 A.”
Therefore, only if it could be demonstrated that a load does not persist for more than half of the time period described in a condition (a) or (b) above, such calculated load is permitted by the Code to be considered as non-continuous load.
In fact, the CE Code only considers total load as non-continuous when such load is calculated for a purpose of selecting service conductors for a single dwelling or service/feeder conductors for a dwelling unit in an apartment building. All other loads are considered by the Code to be continuous, and appropriate demand factors should be applied to those continuous loads.
Although Rule 8-104(2) mandates a general criteria for selection of a circuit rating (i.e., that the calculated load in a circuit cannot exceed ampere rating of that circuit), this general criteria is additionally supplemented by Subrules 8-104(4) and 8-104(5), and the Code users should clearly understand which particular Subrule should applyin each specific case.
Subrule 8-104(4) states the following:
"8-104(4) Where a fused switch or circuit breaker is marked for continuous operation at 100% of the ampere rating of its overcurrent devices, thecontinuous load as determined from the calculated load shall not exceed
(a) 100% of the rating of the circuit where the ampacity of the conductors is based on Column 2, 3, or 4 of Table 2 or 4; or
(b) 85% of the rating ofthe circuit where the ampacity of the conductors is based on Column 2, 3, or 4 of Table 1 or 3.”
This means that if a fused switch or a circuit breakerspecifically marked for continuous operation at 100% ampere rating of its O/C device is selected for the installation, then the size of conductors indicated in Tables 2 or 4 could be selected for that calculated loadbased on criteria outlined in Subrule 8-104(2) shown above,(i.e.,provided that the continuous load does not exceed the selected ampacity of the circuit conductors). This also means that if free air conductors are intended to be selected for such installation in accordance with Table 1or 3, then the continuous load under no condition is allowed to exceed 85% of the selected ampacity of conductors.
When a traditional (80% rated, readily available off the shelf) fused switch or a circuit breaker is specified for installation in a circuit, then provisions of Rule 8-104(5) must apply as follows:
"8-104(5) Where a fused switch or circuit breaker is marked for continuous operation at 80% of the ampere rating of its overcurrent devices, thecontinuous load as determined from the calculated load shall not exceed
(a) 80% of the rating of the circuit where the ampacity of the conductors is based on Column 2, 3, or 4 of Table 2 or 4; or
(b) 70% of the rating of the circuit where the ampacity of the conductors is based on Column 2, 3, or 4 of Table 1 or 3.”
In this case, the continuous calculated load under no condition is allowed to exceed 80% of the selected ampacity of conductors, if Table 2 or Table 4 is used (i.e., when a multi-conductor cable, or conductors in raceways are intended to be installed), or the continuous calculated load under no condition is allowed to exceed 70% of the selected ampacity of conductors – if Table 1 or 3 is used.
Subrule 8-104(6) warns the Code users of additional conditions that may exist in installation (i.e., high ambient temperature or more than 3 conductors are installed in a raceway), andthat in these cases specific derating factors must be applied.
"8-104(6) If other derating factors are applied to reduce the conductor ampacity, the conductor size shall be the greater of that so determined or thatdetermined by Subrule (4) or (5).”
So, based on the discussion above, the following conclusions could be made:
1. Rating of the circuit overcurrent devices and ampacity of the circuit conductors shall not have values smaller than the calculated load of that circuit; and
2. If the calculated load in the circuit is continuous, this load cannot exceed 70%, or 80% or 85% of the rating of that circuit, depending on the applicable requirements of Rule 8-104(4) or 8-104(5).
But what about a correlation between the ampacity of circuit conductors and the overcurrent devices protecting these conductors? Does any requirement exist in the Code for such correlation?
Theanswer to this question could found in Rule 14-104(1) of the Code as follows:
"14-104 Rating of overcurrent devices
(1) The rating or setting of overcurrent devices shall not exceed the allowable ampacity of the conductors that they protect, except
(a) where a fuse or circuit breaker having a rating or setting of the same value as the ampacity of the conductor is not available, the ratings or settings given in Table 13 shall be permitted to be used within the maximum value of 600 A;
(b) in the case of equipment wire, flexible cord in sizes Nos. 16, 18, and 20 AWG copper, and tinsel cord, which are considered protected by 15 A overcurrent devices; or
(c) as provided for by other Rules of this Code.”
This requirement indicates to the Code users that in general (except as it may be permitted in other Rules of the Code), the rating or setting of the circuit overcurrent devices are not allowed to exceed ampacity of the circuit conductors protected by such overcurrent devices. This Rule also advises the Code users that such general correlation requirementmay be disregarded under provisions of Table 13, but only in those situations where the standard rating or setting of the overcurrent device of the same (or smaller) value than the ampacity of the selected conductors is not available.
Let’s illustrate the above requirements of Rule 8-104 and Rule 14-104 by a couple of examples.
Example 1:A calculated load of a stand-alone building occupied by a restaurant is 300 A at 120/208 V. The power to the building is supplied by a buried 4 conductorcopper armoured cable installed by an electrical contractorfrom the utility PMTto the electrical service boxcontaining a standard 80% rated circuit breaker. The circuit breaker is marked for the maximum allowable termination temperature at 75 Deg. C.
In this case, Rule 8-104(5(a) would have to apply for selection of the ampacity of the service conductors. Based on the calculated load of 300 A the next standard value of the conductors ampacity should be selected fromthe 75 Deg. C column of Table 2, and this value should be equal or more to the result of multiplication of 300 A by 1.25, which is 375 A. From Table 2, the next standard conductor ampacity meeting this requirementis 380 A, and this ampacity will allow us to select a cable sized at 500 MCM. This ampacity (and this cable size) will workfor the intended continuouscalculated load if there are no additional needs to de-rate the assigned ampacity (i.e., due to the voltage drop or high ambient temperature requirements).
Now, we can select the trip setting of the service circuit breaker based on the provision of Rule 8-104(5)(a). As the trip setting cannot be less than 375 A, then the next standard setting allowed by Rule 14-104(1) should be 400 A, provided that such setting meets the criteria mandated by Table 13. Review of Table 13 will allow the Code users to ascertain that the conductors with ampacity values from 351 A to 400 A could be protected by the overcurrent device set or rated at 400 A. Thus, a circuit breaker with a 400 A frame and 400 A trip set will work in this case.
Therefore, the rating of the serviceis selected successfully for the continuous load of the restaurant in our example 1.
Example 2: A calculated load of a single dwelling (of a detached two storey house) is 178 A. An electrical contractor has lots of 4/0 aluminum 3 conductor armoured cable in stock and wants to use it as the consumer’s service conductors, to supply the loads of the house.
As the load of a single dwelling is not considered to be continuous for the purpose of selection of the ampacity of service conductors supplying the singledwelling [see Rule 8-200(3) of the CE Code], the ampacity of conductors selected from 75 Deg. C column of Table 4 should not be smaller than the calculated load of 178 A. 4/0 aluminum cable intended to be used by the contractor will do the trick, as the ampacity of this cable is 180 A. This means that the condition of Rule 8-104(2) is met. What about the selection of the service overcurrent device? Can thecontractorinstall a 225 A combination panelboard with the circuit breaker trip set at 200 A? Table 13 will allow such setting, as a 200 A overcurrent device will be able to protect conductors with ampacities between 176 A and 200 A.
This means that the rating of this service is also adequately selected for the non-continuous load of the single dwelling.
Let’s spend a few moments of interesting relaxation allowed by Rule 14-104, as shown below:
"14-104 Rating of overcurrent devices
The rating or setting of overcurrent devices shall not exceed the allowable ampacity of the conductors that they protect, except.......
(c) as provided for by other Rules of this Code.”
This relaxation is intended for specific needs to correlate the overcurrent devices with ampacities of conductors for such loads as motors and capacitors where inrush currents (in case of motors) or charging currents (in case of capacitors) could be quite large, and the O/C devices should be selected so as to allow a successful start of this type of connected loads.
Relaxation allowed by Rule 62-116(7) for the correlation between the overcurrent protection of the service, feeder or branch circuit conductors and the ampacity of these conductors is another example of such provision of Rule 14-104(c).
It appears that the fundamentals of the circuit loading have been sufficiently addressed.
But what about an additionalrelaxation allowed by Rule 8-106(1) shown below:
"8-106 Use of demand factors
(1) The size of conductors and switches computed in accordance with this Section shall be the minimum used except that, if the next smaller standard size in common use has an ampacity not more than 5% less than this minimum, the smaller size conductor shall be permitted.”
This relaxation creates lots of confusion to the Code users, as itflagrantly conflicts with fundamental requirements of Rule 8-104 (it should be noted that Rule 8-104 has no notwithstanding provisions for such relaxation). In addition, use of this relaxation could reduce electrical safety, as it may lead to a selection of the conductors with ampacities smaller than the connected load. A case in point is when the load is not determined by a calculation but bymeasuring a demand in accordance with Rule 8-106(8) of the Code.
Despite the fact that this relaxation exists in the Code, there are many electrical safety regulators who are reluctant to accept use of this relaxation for the reasons expressed above.
It should be noted that the proposal has been submitted to Section 8 S/C to delete this 5% relaxation permission from Rule 8-106 and to introduce it as a notwithstanding Clause to Rules 8-104(4) and 8-104(5)under a control of a special permission by the AHJ.
Thus, as usual, when any specific issues arise in respect to load calculations, the authorities having jurisdiction should be consulted by the designers and contractors.
Read more by Ark Tsisserev
Posted By Thomas A. Domitrovich,
Wednesday, May 01, 2013
Updated: Friday, April 26, 2013
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Arc flash has and continues to be an issue for our industry. All you need to do is speak with someone who has survived an arc flash event or look at the statistics to understand the magnitude of impact these events have on not only that person who may have survived but also on everyone else either directly or indirectly involved; at work and at home. This is a problem in our industry that happens all too often but I firmly believe that these events can and should be things of the past. We have the technology and work practice knowledge to take a bite out of the statistics of arc flash, and NEC 2014 is making great strides in the right direction.
Surprisingly, after a search for a definition of the term arc flash, I could not find a formal definition in IEEE, NFPA or other similar publications. These documents define arc flash boundary, arc flash incident energy, arc flash hazard and other similar terms but not arc flash. So I am taking a liberty here to provide a definition that I have put together based on reading many different documents relating to arc flash and arc flash energy. "An arc flash is the light, heat, sound and gases produced as a result of a rapid release of energy due to an arcing fault sustained by the establishment of highly conductive plasma.” The severity of the event is not in the definition above as that aspect of an arc flash event is addressed by some of the other definitions above which address boundaries and incident energy.
Figure 1. Arc Flash Statistics
Arc flash incidents occur all too often and impact many lives; the remnants of the event may last forever. Figure 1 is a small peek into the problem. It illustrates statistics around a survey of 120,000 workers. These events can be violent, yielding temperatures as high as 20,000°C and forces in excess of 100kPa (Kilopascal). In addition to temperatures and pressures, there may be flying debris that also can do an extensive amount of damage.
The plasma mentioned in our definition of arc flash, amongst other things, introduces impedances that work to reduce the three phase fault current to a lower value of arcing current: "A fault current flowing through electrical arc plasma, also called arc-fault current and arc current.” 1
Figure 2. Breaker response time for a bolted fault current. Note the very fast clearing time removes the fault reducing arc-flash energy.
Figure 3. Breaker response time for an arcing fault current which is of a magnitude less than the calculated bolted fault current. Notice you are in the overload region of the trip curve and your clearing times are much longer resulting in a lot more energy.
Arcing current can be significantly lower than the calculated three-phase bolted fault. This lower value may be lower than the instantaneous pickup of the overcurrent protective device which would mean that the arcing current could be permitted to flow for a long period of time. To illustrate this, figures 2 and 3 include the time current characteristic (TCC) curve of a standard thermal magnetic circuit breaker. Figure 2 shows a calculated bolted fault value that falls above the instantaneous pickup and in the instantaneous region of the overcurrent protective device. Figure 3 illustrates that the arcing current is a percentage of the bolted fault current that in this case falls below the instantaneous pickup of the overcurrent protective device.
This response time results in an arcing current that is permitted to flow from approximately 0.5 second to 3 seconds which happens to be a very long time when you consider energy is time multiplied by the square of current. This illustrates why an arcing current downstream of an overcurrent protective device can do a lot of damage before a device trips. For an example such as that shown in Figure 2, some other means would have to be put in place to address the arcing fault and clear it in a shorter amount of time.
Arc flash events can be caused by metallic tools, test probes, loose equipment parts, or similar items coming in contact with energized bare parts creating a short circuit. Other sources have been known to include the misapplication of test instruments as test instruments applied beyond their listing. To address the problem in the industry we turn to codes and standards. A peek into the activity in this area illustrates the type of attention arc flash is getting by the electrical industry.
Electrical Codes / Standards
When I think about arc flash and codes and standards, two key documents come to mind; NFPA 70 National Electrical Codeand NPFA 70E Standard for Electrical Safety in the Workplace. These documents work together to help reduce the incidents of arc flash, in addition to many other hazards.
The key thing that separates these two documents is how they are enforced. NFPA 70 is familiar to many, enforced by electrical inspectors across the country, used as an installation requirement by many electrical contractors across the country and in the design process by many professional engineers across the country. It is an installation requirement that is adhered to and enforced at the early stages of the development of a structure. This document includes such requirements as GFCI, AFCI, equipment ground fault and grounding/equipment bonding which all act to prevent a problem from occurring or work to mitigate the effects of events should they occur. The systems installed per the NEC are later maintained by many in the industry.
NFPA 70E, on the other hand, is not enforced in the same manner. This document is primarily enforced by OSHA and usually after an event occurs. Recently though, OSHA has been enforcing workplace safety practices during routine inspections. In my mind, when it comes to stopping the problem before it occurs, NFPA 70 is the document that has the most impact.
With respect to arc flash, the NEC has not historically been very active until just recently. Section 110.16, Arc-Flash Hazard Warning, was the first introduction of the term arc-flash to the NEC. It was introduced in the 2002 version of the Code and is a requirement for a sign that raises awareness of the hazard. Signs are great ways to raise awareness of hazards but implementing technologies that act to mitigate the problem is a more direct way to address the issue.
NEC 2012 took a more direct approach in the fight against arc flash. This document introduced a new section 240.87, Noninstantaneous Trip, intended to specifically target the arc flash issue. Controversial as any other big change, this new section came in with one proposal (Proposal 10-82) and many comments (Comments 10-36, 10-37, 10-38, 10-39, 10-40, 10-41, 10-42, 10-43, and 10-44). Figure 5 illustrates the language that was decided upon for 240.87 and which can be found in NEC2011. This language was met with many questions. For example, the phrase "utilized without an instantaneous” came under fire by some in the industry as it was debated whether or not simply having instantaneous trip capabilities on the breaker, even when turned off, was enough to meet the intent of the code. But as with many sections of the NEC, time will help this section get better.
The 2014 cycle of the NEC offered another opportunity for public input. The Proposal phase of NEC 2014 saw 7 proposals on section 240.87 of the Code (10-53a, 10-54, 10-55, 10-56, 10-57, 10-58, and 10-59). The Comment phase brought out 10 comments (10-20, 10-21, 10-22, 10-23, 10-24, 10-25, 10-26, 10-27, 10-28, and 10-29). The panel settled on a language that is not only crystal clear for the inspector but will also have a considerable impact on the arc flash problem. The 2014 language, as gathered from ROP and ROC documents, is shown in figure 6. Note that the final published version of the NEC may have some minor changes but this should get you in the ballpark. The new language has removed any ambiguity of where this section applies. I will add that the technologies outlined in this section can be applied below 1200 amps as well.
The code panel utilized language from section 230.95 of the NEC when creating what we will soon see as the new Section 240.87. Section 230.95 states ". . . The rating of the service disconnect shall be considered to be the rating of the largest fuse that can be installed or the highest continuous current trip setting for which the actual overcurrent device installed in a circuit breaker is rated or can be adjusted.” With minor modifications, this language served the panel well in that the language is familiar to the inspector and installer. Good code is clear, concise and familiar. This new section is just that.
Arc Reduction Technologies
There are four technologies included in this section plus a provision that permits the application of an approved equivalent. Let’s talk briefly about each of these technologies and we’ll focus a little more on the approved equivalent later.
Figure 4. Section 110.16
Zone Selective Interlocking (ZSI)
A circuit breaker equipped with zone selective interlocking provides a method to reduce fault clearing times should a fault occur while working on energized circuits within the zone of protection (between the upstream and downstream pair of circuit breakers). The reduced clearing times greatly reduce arc flash energy.
Zone selective interlocking utilizes a communication signal between two or more trip units applied on upstream and downstream pairs of breakers that have already been selectively coordinated. During fault conditions, each trip unit that senses the fault sends a restraining signal to all upstream trip units. When the upstream trip unit sees this restraining signal, it will remain closed while the downstream breaker clears the fault. In the absence of a restraining signal, when the fault is between the two trip units, the upstream trip unit ignores its programmed settings and trips with no intentional time delay, reducing the clearing time, minimizing damage at the fault point and reducing the arc flash energy.
Differential relaying is very similar to zone selective interlocking in that it is able to determine if a fault occurs within a particular zone of protection, reduces the clearing time, minimizes damage at the fault point and reduces the arc flash energy. It is different in that it monitors the amount of current going into and out of a zone of protection. If the amount of current going into the zone is greater than the amount of current flowing out of the zone, then the device knows that the fault is within the zone and acts to open the circuit with no intentional delay. If the current going into the zone and the current going out of the zone are equal there is no fault within the zone, so the circuit breaker does not trip.
Energy Reducing Maintenance Switch
A circuit breaker equipped with an arc flash reduction maintenance system provides a simple and reliable method to reduce fault clearing times should a fault occur while working on energized circuits downstream. The reduced clearing times greatly reduce arc flash energy.
An arc reduction maintenance system can be turned on and off automatically or manually to reduce arc flash energy. In the "on” position, it reduces the clearing time of a circuit breaker that has been intentionally delayed for selective coordination purposes. In the "off” position the system responds in the manner in which it has been programmed to meet selective coordination requirements.
This technology is based on the realization that when working on energized electrical equipment, a fault that occurs within that gear needs to be cleared as quickly as possible. While this seems obvious, in actual installations, intentional delays are included in upstream devices to ensure selective coordination with downstream devices. This means that if a fault were to occur inside the equipment, the downstream breaker might never clear the fault regardless of how much delay is or isn’t programmed in the upstream breaker. This maintenance switch technology permits removing this delay while energized work is being conducted.
Figure 5. NEC-2011 language for Section 240-87, Noninstantaneous Trip
Energy Reducing Active Arc-Flash Mitigation Systems
A circuit breaker equipped with an energy reducing active arc-flash mitigation system provides a simple and reliable method to reduce fault clearing times. Work locations downstream of a circuit breaker with this technology can have a significantly lower incident energy level. When activated, this system monitors system parameters and acts to identify an arc flash. If an arc flash event occurs, the arc is diverted via various types of technology while opening an upstream circuit breaker, eliminating the faulted condition and de-energizing the system.
Approved Equivalent Means
Section 90.4 of the NEC has a provision for the authority having jurisdiction for enforcing the Code, to permit alternative methods to a requirement where it is assured that equivalent objectives can be achieved by establishing and maintaining effective safety. The phrase "or equivalent” is used 77 times in NEC 2011 with some instances being much more clear cut than others. The phrases "approved equivalent means” and "or equivalent” can be quite controversial in some instances when the inspector is being presented with a design that doesn’t meet the letter of the code but is being asked to be considered as equivalent. Inspectors across the country probably have those top two or three examples that they see all the time and have their dialog down pat when presented with the "equivalent” design. Section 240.87 offers another example of this but the answer can be quite clear.
Figure 6. NEC 2014 Section 240.87
Before an inspector evaluates a proposed equivalent means, we must first understand the intent of this section of the Code. The new title change helps considerably with this as it clearly states that it is there for "Arc Energy Reduction.” The inspector can make his/her job very transparent when approving an equivalent means. The first step is to request the results of an arc flash study for one of the four listed options and the results of an arc flash study with the proposed equivalent means. This yields two arc flash numbers that can be compared. The proposed equivalent means shall be considered "approved” when the arc flash value for the proposed equivalent means is equal to or less than the arc flash value calculated for one of the four listed technologies.
The inspector does not have to perform a calculation, read a TCC curve or any of the literature for a breaker or other type of system being offered as an equivalent means. Keep it simple. Ask for two arc flash values as described above and compare the numbers. It’s that simple.
NEC 2014 Section 240.87 is a historical code change and one of the most important leaps in arc flash safety for the electrical industry. This new language, through my eyes, will take a bite out of the arc flash issue and save lives. As we come closer to the annual meeting in Chicago for the final stages of NEC 2014, stay tuned for the final agreed upon language. Together we can make a difference.
As always, keep safety at the top of your list and ensure you and those around you live to see another day.
1IEEE Std. 1584-2002 "IEEE Guide for Performing Arc-Flash Hazard Calculations”
Read more by Thomas A. Domitrovich
Safety in Our States
Posted By Jesse Abercrombie,
Wednesday, May 01, 2013
Updated: Friday, April 26, 2013
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Have you recently received a pension buyout offer? If so, you need to decide if you should take the buyout, which could provide you with a potentially large lump sum, or continue accepting your regular pension payments for the rest of your life. It’s a big decision.
Clearly, there’s no "one size fits all” answer — your choice needs to be based on your individual circumstances. So, as you weigh your options,you’ll need to consider a variety of key issues, including the following:
Estate considerations — Your pension payments generally end when you and/or your spouse dies, which means your children will get none of the money. But if you were to roll the lump sum into an Individual Retirement Account (IRA), and youdon’t exhaust it in your lifetime, you could still have something to leave to your family members.
Taxes — If you take the lump sum and roll the funds into your IRA, you control how muchyou’ll be taxed and when, based on the amounts you choose to withdraw and the date you begin taking withdrawals. (Keep in mind, though, that you must start taking a designated minimum amount of withdrawals from a traditional IRA when you reach age 70½. Withdrawals taken before age 59½ are subject to taxes and penalties.) But if you take a pension, you may have less control over your income taxes, which will be based on your monthly payments.
Inflation — You could easily spend two or three decades in retirement, and during that time, inflation can really add up. To cite just one example, the average cost of a new car was $7,983 in 1982; 30 years later, that figure is $30,748, according to TrueCar.com. If your pension checksaren’t indexed for inflation, they will lose purchasing power over time. If you rolled over your lump sum into an IRA, however, you could put the money into investments offering growth potential, keeping in mind, of course, that there are no guarantees.
Cash flow— Ifyou’re already receiving a monthly pension, andyou’re spending every dollar you receive just to meet your living expenses, you may be better off by keeping your pension payments intact. If you took the lump sum and converted it into an IRA, you can withdraw whatever amount you want (as long as you meet the required minimum distributions), butyou’ll have to avoid withdrawing so much thatyou’ll eventually run out of money.
Confidence in future pension payments — From time to time, companies are forced to reduce their pension obligations due to unforeseen circumstances. You may want to take this into account as you decide whether to continue taking your monthly pension payments, but it’s an issue over which you have no control. On the other hand, once your lump sum is in an IRA, you have control over both the quality and diversification of your investment dollars. However, the trade-off is that investing is subject to various risks, including loss of principal.
Before selecting either the lump sum or the monthly pension payments, weigh all the factors carefully to make sure your decision fits into your overall financial strategy. With a choice of this importance, you will probably want to consult with your financial and tax advisors. Ultimately, you may find that this type of offer presents you with a great opportunity — so take the time to consider your options.
Read more by Jesse Abercrombie
Posted By Steve Foran,
Wednesday, May 01, 2013
Updated: Friday, April 26, 2013
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In the early 90s, utilities were in the midst of
massive change as downsizing, right-sizing—or whatever you called it — swept
the continent. Driven by technology, fewer people were needed to get the same
work done and from this emerged an industry called Process Re-engineering.
Our utility was engulfed in change. Our new business
processes resulted in many changes in responsibilities for many people, but one
affected our department very significantly. At the time we were responsible for
technical training associated with revenue metering.
The proposed change would reduce both travel and the
number of people needed to deliver metering services to residential customers
by combining two separate job functions together into a single job. I cannot recall
the exact numbers, but for illustrative purposes it was projected that we could
combine the work of 15 meter installers and 95 meter readers into, say, 100
multi-disciplined metering workers, resulting in a net reduction of 10 people.
The challenge was that the technical competence
required in the newly created position was higher than that of the 95 meter
To safely perform their duties, meter installers must
understand the meter nameplate, know how to identify the proper device for a
service and be competent to work around energized equipment. Quite simply, the
meter readers were not competent to do this work.
A comprehensive training program was developed and
delivered. It covered many aspects of the residential service which included
both theoretical and practical components where employees had to demonstrate
From the training, participants learned about the
risks associated with metering and energized equipment. Most importantly, they
obtained the knowledge and skills needed to safely manage the risks.
Of the many risks at the electrical service entrance,
there is one that stands out above all others. This risk came as a surprise to
every single participant in our training. In fact, none of the meter readers
were aware that this risk even existed.
Most meter readers thought the greatest risk was
electrical shock. Contact with 120 V is a risk; however, a far greater risk is
the fault level available at the service entrance in the event of a ground
fault. The potential physical harm to people and property as a result of a
short circuit in a meter base can be catastrophic.
For our system, we calculated the maximum possible
fault level at a 200 A 120/240 Volt service (close to a large substation, short
service run, large distribution transformer, etc.). Here’s what we found: the power delivered in the event of a short
circuit (even though only momentarily) is comparable to the power delivered by
a typical jet engine that you see on the wings of a large airplane.
In our training, we explained this to our
participants and asked them, "Would you stick a screw driver into a jet engine
while it’s running? What kind of
precautions would you take around a jet engine?”
A fault at a meter
base has the ability to instantaneously produce the same power delivered by a
jet engine. But unlike the jet engine, which makes all kinds of noise and
produces so much wind that you wouldn’t dare get too close, a meter base just
sits there — you can’t even tell if it is energized by looking at it.
Trainees told us that their biggest take-away was
their newfound appreciation of something which they were previously unaware.
As for me, I learned that we must be open to looking
at situations in new ways so we can see what was once invisible. Secondly, use
appreciation (appreciation of the risk, work methods, design, etc.) to replace
feelings of fear and lack of understanding.
The new service model was safely
implemented and I hear from colleagues who still work at the utility that they
continue to re-engineer their metering and customer services processes.