Posted By Thomas A. Domitrovich,
Monday, July 01, 2013
Updated: Thursday, June 20, 2013
| Comments (1)
The story of the arc-fault circuit interrupter is an interesting one as it is technical in nature, wrapped in controversy, fueled by passion, and delivers a positive electrical safety impact to the electrical industry. I have read many different articles on this topic and for some time have noted issues with technical details. This article will provide a technical review of the AFCI technology from a standards perspective. You will see how the attempt to simplify a technical message has actually lead us to take liberties that are not technically accurate but help to convey a basic understanding. I will attempt to illustrate what the UL standard requires for a few types of AFCIs to cut through the lingo that has been used to describe the functionality of an AFCI. I am hoping that this article will be your technical resource to ground any discussions around what an AFCI device can or cannot do. I will be referencing UL standards for most, if not all, of the discussion that follows.
Standards versus Outline of Investigations
I can’t begin without addressing a fundamental aspect of UL Listed products that directly pertains to this AFCI discussion. We must first understand what a UL Outline of Investigation (OOI) is before proceeding. Most products you install are supported by a product standard which, in the case of AFCIs, is UL 1699 Standard for Safety ofArc-Fault Circuit Interrupters. A product standard like UL 1699 is an ANSI-approved document that is created through an ANSI process. The ANSI process requires a balanced panel of individuals assuring that no single interest group dominates. UL uses their Standards Technical Panel (STP) to usher this UL standard through the ANSI process. These STPs are similar to the code-making panels that you and I are most familiar with in the NFPA process. Both processes are ANSI-accredited. This balanced panel reviews proposed changes, votes, and ultimately produces an updated consensus standard. The other document I mentioned above, the OOI, is different in that it is not a document that has gone through the same ANSI process described for a UL standard. UL defines the OOI as ". . . a document that contains the construction, performance, and marking criteria used by UL to investigate a product when the product is not covered by the scope of an existing UL Standard for Safety. Outlines are not consensus documents and do not require review by an STP or other external group.” This definition is relevant as you will see later in this article. It is a way that a new product which has no UL standard can quickly come on the market and yet still be evaluated to a predefined test specification. From my experience, the OOI is usually a document that has received industry input from various organizations and just may be the first draft of a future UL /ANSI standard, but has not yet gone through the sometimes lengthy ANSI process.
UL standards contain performance basedtestingthat verifies products will do what the standard intends the products to do and confirms that the product safely performs these duties under the conditions in which it is intended to be applied. Let me explain performance based through an example of a performance based test and a prescriptive requirement. One AFCI test requires cutting into a wire with a sharp blade, causing an arc that must be cleared before a wrap of cotton ignites. This is an example of a performance based test and not a prescriptive requirement. A requirement that all AFCIs must have 30 mA ground fault would be an example of a prescriptive requirement, and one that is not in the standard. UL Standards thrive on performance based test requirements.
UL 1699 Standard and Associated OOIs Background
The origins of UL 1699 can be traced back as far as 1997. The draft requirements of this standard were used as input to the certification of branch-circuit AFCI devices available on the market at that time. Those first devices were initially UL Listed under the Standard for Molded-Case Circuit Breakers, UL 489, and UL Classified for mitigating the effects of arcing faults. UL subsequently pulled together an industry advisory group in the Fall 1998 to develop the draft requirements for the first edition of UL 1699 which was ultimately released in February 1999. The performance based test standard used in the classification of the first AFCIs on the market in 1997 may not have been called an OOI by UL at the time, as they are today, but it indeed resembled the process as we know it.
Today, UL utilizes Standards Technical Panels, (STPs) to usher standards through the ANSI consensus process. The ANSI consensus process has a strict set of guidelines that include important aspects of: Openness, Lack of Dominance, Balance and Consensus Voting.
Products that can be listed to UL 1699 standard requirements include the following:
- Branch Feeder AFCI (Category AVZQ)
- Combination AFCI (Category AWAH)
- Portable AFCI (Category AWDO)
- Cord AFCI (Category AWAY)
- Outlet Circuit AFCI (Category AWCG)
The outlet type AFCI above is not the Outlet Branch Circuit (OBC) AFCI that we have seen mentioned recently. We’ll discuss the differences later. The OBC AFCI is listed to an OOI, "Outline of Investigation for Outlet Branch Circuit Arc-Fault Circuit-Interrupters” and not to the ANSI /UL 1699 standard. The UL White Book discusses all of the above types of AFCI Categories; the OBC AFCI is found in Category AWBZ. Another type of AFCI that is listed to an OOI is the Photovoltaic DC AFCI, Category QIDC, listed to "Outline of Investigation for Photovoltaic (PV) DC Arc-Fault Circuit Protection.” This too can be found in the UL White Book but will not be a focus of this article.
Figure 1. NMB Conductor used in UL 1699 testing.
Figure 2. SPT-2 Conductor used in UL 1699 testing.
UL 1699 Arc-Fault Testing
If you were to purchase a copy of UL 1699 and look through the table of contents, the following are the performance tests conducted on AFCIs:
- Drop and Impact Tests
- Humidity condition
- Leakage Current Measurement
- Voltage Surge Tests
- Environmental Test
- Arc Detection Tests
- Unwanted Tripping Tests
- Operation Inhibition Tests
- Dielectric Voltage Withstand Tests
- Resistance to Environmental Nose Tests
- Normal Temperature Tests
- Operating Voltage Test
- Endurance Test
- Abnormal Operation Test
- Surge current test
- Abnormal overvoltage test
- Short circuit current test
- Terminal lead strain-relief test
- Power-supply cord strain-relief test
- Mechanical tests
- Crushing tests
- Dust test
- Performance of markings
- Reverse line – load miswire test
- Supplemental voltage surge immunity test
As you can see, the performance testing for AFCIs is quite extensive. I will focus on arc detection tests, unwanted tripping tests, and operation inhibition tests. I will also discuss the requirements in the OOI for the OBC AFCI but will leave the PV AFCI for another day.
There are four arc detection tests described in UL 1699. These include the following:
- Carbonized path arc ignition test
- Carbonized path arc interruption test
- Carbonized path arc clearing time test
- Point contact arc test
Not every product listed to UL 1699 has to be tested to the above arc detection tests. Table 1 illustrates the arc detection tests that must be performed for each of the devices that can be listed to UL 1699.
You’ll note the references in the tests above to NM-B and SPT-2 conductors. Not every test is performed on both types of conductors but these are the only types of conductors that are used. They are depicted in figures 1 and 2 respectively. Tests conducted on NM-B are performance tests that verify the tested product can detect and mitigate the effects of arcing faults in the installed wiring of a home. Tests conducted on SPT-2 cords are performance tests that verify the tested product can detect and mitigate the effects of arcing faults in cords, like those connected to receptacles which are usually attached to appliances.
Now let’s take a look at these arc detection tests, one at a time.
1. Carbonized path arc ignition test (figure 3): This test is conducted on NM-B samples only. The outer jacket of the NM-B sample is removed, insulation is removed from one conductor, and this conductor is cut. This area is then covered with electrical tape and loosely wrapped with cotton. A test apparatus is used to create a carbonized arcing path that can be sustained at 120 volts at varying RMS load currents as low as 5 amps. The AFCI must interrupt the circuit before the cotton ignites. Many call this a "Series Test,” but I would much rather refer to this as a "low-current” arcing test since the current is restricted by the load, and is a minimum of 5 A.
Figure 3. Carbonized Path Arc Ignition test sample preparation performed on the Branch Circuit and Combination Type AFCI. This one line diagram illustrates the preparation of the sample to be tested.
2. Carbonized path arc interruption test (figure 4): This test is conducted on both NM-B and SPT-2 samples. To prepare the sample, a cut is made to penetrate the insulation across all conductors. This area is then covered with electrical tape. A test apparatus is used to create a carbonized arcing path that can be sustained at 120 volts. This test is conducted without a connected load, at 100 A and 75 A as delivered by the source. The AFCI must clear the arcing fault if 8 half-cycles of arcing occur within a period of 0.5 seconds. Many refer to this as a "parallel test,” but I would much rather refer to this as a "high-current” arcing test since the current is not restricted by any load and is at a minimum, 75 amps.
Figure 4. Carbonized Path Arc Interruption test sample preparation performed on the Branch Circuit and Combination Type AFCI. This one line illustrates the preparation of the sample to be tested..
3. Carbonized path arc clearing time test (figure 5): This is the sole additional arc detection test required for the combination-type AFCI, beyond that which is required for the branch/feeder type. It is conducted on SPT-2 samples only. The test sample ends are cut and separated. A cut is made to penetrate the insulation across the conductors, and this area is then covered with electrical tape. A test apparatus is used to create a carbonized arcing path that can be sustained at 120 V. As in the carbonized path arc ignition test above, which is only performed on NM-B, a load is used to adjust the RMS load current as low as 5 amps for this test. The AFCI must interrupt the circuit before the times specified in the standard (at 5 A = 1.0 seconds). As noted above, this test is commonly referred to as a "Series Test,” but I would rather refer to this as a "low-current” arcing test since the current is restricted by the load, and is a minimum of 5 A.
Figure 5. Carbonized path arc clearing time test sample preparation. This is the only extra test a combination type AFCI must pass. This one line illustrates the preparation of the sample to be tested.
4. Point contact arc test (figure 6): known as the "Guillotine Test,” here a utility knife blade is utilized to attach a hinged lever arm that is slowly closed onto a test sample such that the blade cuts through the wire insulation causing an arc. Many, at IAEI events saw this test as manufacturers would demonstrate it during meetings. The AFCI must trip if 8 half-cycles of arcing occur within a period of 0.5 seconds. The test is conducted without a connected load at several specified current levels between 500 A and 75 A, as delivered by the source. Both NM-B and SPT-2 samples must be tested. Many refer to this as a "parallel test,” but I would much rather refer to this as a "high-current” arcing test since the current is not restricted by any load and is at a minimum, 75 amps.
Figure 6. Point contact test sample preparation performed on the Branch Circuit and Combination Type AFCI. This diagram illustrates how the steel blade cuts the insulation and causes the arcs in this test.
Figure 7. Illustrates the tests performed and protection provided by the branch feeder and combination type AFCIs as per the UL 1699 Standard. Note that a Branch Feeder AFCI mitigates from high and low arcing currents in installed NMB but only high arcing currents in connected cords. The Combination type AFCI extends the low current arc detection to connected cords.
Table 1 illustrates the fact that the difference between a branch feeder and combination-type AFCI is NOT that one does "parallel” arc detection and the other does "parallel” and "series” arc detection, but rather that the combination-type AFCI extends low-current arc detection to connected cords.
The OBC AFCI
The outline of investigation for the OBC AFCI device, because it is intended to detect arcing and sparking, a basic function of a UL 1699 device, utilized the UL 1699 standard as the basis for its development, referencing it heavily and performing many of the same tests that the combination-type AFCI must perform. Table 2 illustrates the arc detection tests required to be performed by the OBC AFCI. As noted in this table, there is an additional twist to two of the tests listed that make the OBC AFCI unique. Other listed devices are only required to look downstream. A combination AFCI, UL category (AWAH) for example, in the loadcenter, must detect high and low current arcing in all connected downstream NM-B and SPT-2 conductors. It does not look back towards the utility or other branch circuits on the same bus and, in fact, has technology to ensure this does not occur. The outlet-type AFCI, UL category (AWBZ) again this is not the OBC AFCI, must detect high-current and low-current arcing in connected cords (SPT-2) and downstream NM-B conductors connected to its load terminals. This device does not have to detect arcing in the NM-B conductors connected to its line-side terminals, looking back towards the utility.
The OBC AFCI, on the other hand, must detect high-current and low-current arcing on connected cords (SPT-2) and downstream NM-B conductors connected to its load terminals as well as detect low-current arcing in the NM-B conductors connected to its line-side terminals. The line-side arc detection for this device does not include detecting high-current arcing. This additional test of low-current line-side arc detection is in essence looking back towards the source for low-current arcing. An arcing fault that trips an OBC AFCI circuit could be on the load side of the device, in a connected cord, in the downstream NM-B conductors connected to its load terminals or in the line-side NM-B conductors connected to the line terminals of the device anywhere upstream. Figure 8 illustrates the protection coverage of the OBC AFCI device.
Figure 8. Illustrates the tests performed and protection provided by the OBC AFCI device as per the Outline of Investigation for this device.
Figure 9. Point contact test sample preparation with NMB instead of SPT-2 cord as shown in Figure 6.
Unwanted Tripping Tests
In addition to arc detection, it is important that the AFCI device does not needlessly trip. The UL 1699 standard has a section of the document focused on taking a representative AFCI of each rating and ensuring that it does not trip after being tested under various loading conditions including inrush currents, normal operating arcing, non-sinusoidal waveforms, cross talk, multiple loads and even lamp burnout. Tests are performed with various types of appliances from a flat iron skillet to vacuum sweepers and air compressors. Not every manufacturer’s device or model types are tested in these standards.
This testing is quite extensive and, as noted above, includes using tools and appliances you would find in a home. But this is an area where manufacturers go above and beyond to ensure their products perform in the market without unwanted tripping. More than one model or manufacture of an appliance is tested, more combinations of loads, varying models from various brands. It is a fact that if you walk through the AFCI labs of any one AFCI manufacturer, you will find products with which tests are performed that are not in the UL 1699 standard. The answer to why a manufacturer would do this lies in the desire to be the best in the market, to reduce warranty claims, and to maintain customer loyalty to name a few. Each manufacturer strives to have a product that operates with any load on its circuit yet detects the dangerous arcs that may be the source for fires. Other examples of this can be found in efficiency type standards. There is a lot of evidence where manufacturers have gone above and beyond to be the best in their markets. Whether it is to boast better gas mileage than their competition, more efficient transformers or lamps, or even longer lasting batteries, the work that the manufacturer does to have the best product on the market can be viewed as a competitive advantage.
Operation Inhibition Tests
So far we have discussed performance based testing that ensures an AFCI detects arcs and unwanted tripping tests that ensure it detects the bad arc and not the good arcs causing a trip. However, we can’t forget the fact that an AFCI must detect dangerous arcs without being masked by other types of loads on the same circuit. These tests in the UL standard help to ensure dangerous arcs can be detected even in the presence of other loads that may act to mask the arc, preventing the AFCI from doing what it needs to do — open the circuit when an arc fault exists. Scenarios such as electromagnetic interference (EMI), masking loads such as vacuum sweepers, air compressors, switching power supplies, electronic lamp dimmers and more are tested with the AFCI device to ensure its robust arc detection methods operate correctly in these "dirty” environments. High-current and low-current arcs must still be detected when other loads are on the circuit.
Series versus Parallel
The terms series arcs and parallel arcs are used quite heavily in discussions pertaining to AFCIs to describe the types of arcs that are being detected and to describe the differences between types of AFCIs. While it would appear that using these terms helps simplify the complex, we know that from an electrical standpoint this is technically not a correct use of these terms and, depending upon what they are used to describe, may not describe the facts at all.
Let’s first look at the definition of the words "series” and "parallel.” Merriam-Websterdefines series as "a number of things or events of the same class coming one after another in spatial or temporal succession.” This resource defines parallel as "extending in the same direction, everywhere equidistant, and not meeting.” Both of these definitions utilize a relationship or a comparison between two or more objects as the basis for the definition. These two words, in our context, are intended to describe the relationship between two or more elements of an electrical circuit. These terms, when used by themselves, series arc or parallel arc do not identify which element(s) are in series/parallel with another. If you draw a circuit, the terms series and parallel will heavily depend upon how you draw your circuit and reference the components in the circuit. From a technical perspective, these words do not provide clarity.
These terms are also used when describing the difference between a branch-circuit AFCI and a combination-type AFCI. You’ll hear, "A branch-circuit AFCI detects parallel arcs and the combination-type AFCI detects parallel and series arcs.” Plain and simple, this is incorrect. The reason is due to the facts we discussed above. Look at the carbonized path arc ignition test, figure 3, that the branch-feeder and combination-type AFCI must pass. Ask yourself if that is what you envision when someone says series arc. Is that conductor cut and subsequent arc across that conductor cut in series with the load? In this test, the current is limited down to 5 amps by the load because it is performed for both the branch-feeder and the combination-type AFCI devices, saying that the branch-feeder does not detect series arc faults is not an accurate statement per the standard.
If instead of usingseries and parallel we use low-current and high-current, respectively, our explanation is technically accurate and should be understandable. A better way to describe the difference between a branch-feeder AFCI and a combination-type AFCI would be as follows:
"A branch-feeder AFCI offers high- and low-current arc detection for installed NM-B wire and high-current arc detection for connected cords. The combination-type AFCI offers the same level of protection afforded by the branch-feeder AFCI but extends the low-current arc detection to connected cords.”
AFCIs and Ground Fault
In the past, confusion around the definition of a combination-type AFCI left some thinking that the combination-type AFCI was a combination of AFCI and GFCI in the same device. The UL 1699 standard does not include a prescriptive requirement of any level of ground-fault protection. Some AFCI devices do indeed have a level of ground-fault protection which may vary from manufacturer to manufacturer. Ground fault added to an AFCI is there primarily as a means to pass the carbonized path arc ignition performance test included in UL 1699 and described above. (See figure 3). An AFCI device that carries an additional listing to either UL 943 or UL 1053 standards would be considered a dual purpose AFCI device which provides people protection or equipment protection respectively.
The arc-fault circuit interrupter is a device that is technical in nature, wrapped in controversy, fueled by passion, and delivers a positive electrical safety impact to the electrical industry. For examples of found electrical products, bookmark www.afcisafety.org and check it often as there is a document on that web site that provides examples of found electrical problems. 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.
Read more by Thomas A. Domitrovich
Safety in Our States
Posted By Ark Tsisserev,
Monday, July 01, 2013
Updated: Thursday, June 20, 2013
| Comments (1)
The subject of bonding and grounding is perhaps the mostconfusing to the users of the electrical installation codes.
In fact, I have written on this subject in this very publication, at least two such articles, in the past few years. Nevertheless, I routinely receive e-mails and phone calls with the questions about differences between bonding, grounding and neutral conductors, about differences in use of these conductors under the Rules of the Canadian Electrical Code and about differences in the Code requirements for sizing such conductors. So, let’s provide a bit of clarification again.
1. Bonding conductor
Bonding and bonding conductor are defined in the CE Code as follows:
"Bonding — a low impedance path obtained by permanently joining all non-current-carrying metal parts to ensure electrical continuity and having the capacity to conduct safely any current likely to be imposed on it.
Bonding conductor — a conductor that connects the non-current-carrying parts of electrical equipment, raceways, or enclosures to the service equipment or system grounding conductor.”
Based on these definitions, it is abundantly clear that bonding is a low-impedance path that is deliberately created between all non-current-carrying metal parts of electrical equipment in order to safely conduct any undesirable current (leakage or fault current) that could be inadvertently imposed on these metal parts during use of electrical equipment.
Bonding conductor is such conductor that actually connects these (normally non-current-carrying) metal parts of the electrical equipment (including cable armour and sheath, and metal raceways) with service equipment or with system grounding conductor. Let’s hold for a time being the explanation regarding connection of bonding conductor with the service equipment or with system grounding conductor, and let’s concentrate on a selection of size for a bonding conductor.
Photo 1. Does marking of this bonding conductor comply with the CE Code?
Bonding conductor is not considered to be a circuit conductor, as circuit conductors carry the circuit current under a normal operating condition, and ampacity of circuit conductors is selected in accordance with Rule 8-104 (or with other applicable rules of the Code depending on a type of connected loads such as motor, capacitor or heating loads). However,asa bonding conductor is intended to carry only a fault current, it must be sized so, as to have sufficient ampacity to carry the maximum fault current that could be accidentlyimposed on the non-current-carrying metal parts of a specific electrical equipment (of a specific connected load).
Selection of a bonding conductor size is governed by Rule 10-814(1).
This Rule states the following:
"10-814(1) The size of a bonding conductor shall be not less than that given in Table 16, but in no case does it need to be larger than the largest ungrounded conductor in the circuit.”
Table 16 offers the code users a criteria for selection of a bonding conductor size based on the ampacity of the largest ungrounded conductor in the circuit.
Appendix B Note on this Rule further clarifies this requirement by explaining that raceways permitted by the Code to be used as bonding conductors are deemed to be of adequate size to carry the fault current. This Appendix B Note also explains to the Code users that a bonding conductor provided as an integral component of a cable designed and constructed in accordance with an applicable safety standard (with one of the CSA Part II standards listed in Appendix A of the Code) is also deemed to be of adequate size for the purpose of Rule 10-814(1) to carry the maximum fault current that could be imposed on the non-current-carrying metal parts of electrical equipment connected by that particular cable.
Appendix B Note on Rule 10-814(1) "When a raceway or cable sheath enclosing the circuit conductors is permitted to be used as a bonding conductor for the equipment being supplied, it is deemed to be of adequate size for the purposes of this Rule. The bonding conductor incorporated into a cable assembly is sized in accordance with the relevant Part II Standard. Typically, the bonding conductor size in manufactured cables corresponds to the requirements of this Rule, but in some cases it may differ by one size, usually on the larger side. In any case, the bonding conductor incorporated into a cable assembly is deemed to be of adequate size for the purposes of this Rule.”
So, for example, if three 3/0 AWG copper conductors are selected from a 75 Deg. C column of Table 2 with ampacity of 200 A, and these conductors are installed in a PVC for a connection to,let’s say, a motor, then a copper bonding conductorsized at not less than 6 AWG must be selected from Table 16 based on ampacity ofsuch circuit conductors. If these three circuit conductors are installed in a rigid metal conduit, and this rigid metal conduit is used as a bonding conductor in accordance with Rule 10-618 of the CE Code, then the rigid metal conduit selected as per Table6 of the Code is deemed to be of adequate size to carry the maximumfault current that could be imposed on the metal enclosure of the motor connected to the circuit by these three 3/0 AWG copper conductors.
Photo 2. What should be the color of insulated grounding conductor?
Now is a good time to re-visit the Code definition of bonding conductor "Bonding conductor — a conductor that connects the non-current-carrying parts of electrical equipment, raceways, or enclosures to the service equipment or system grounding conductor,” and review the portion of this definition that describes connection of the bonding conductor to the service equipment or to the system grounding conductor.
Let’s start with connection of a bonding conductor to agrounding conductor. Before we’ll analyze the objective of this portion of definition, we need to clearly understand the meaning of agrounding conductor and grounding electrode.
2. Grounding conductor
The CE Code defines grounding conductor and grounding electrode as follows:
"Grounding conductor — the conductor used to connect the service equipment or system to the grounding electrode.
Grounding electrode — a buried metal water-piping system or metal object or device buried in, or driven into, the ground to which a grounding conductor is electrically and mechanically connected.”
Based on these two definitions, it should be clear that agrounding conductor at service equipment is such aconductor that connects aservice equipment enclosure to the grounding electrode and, via a grounding electrode, toground (toearth). This means that a service equipment enclosure (to which all other non-current-carrying metal parts of electrical equipment are connected by a bonding conductor) is reliably connected to ground (earth) by means of a grounding conductor and grounding electrode. Italso means that through this connection to ground/earth, all bonded non-current-carrying metal parts of electrical equipment are not only connected together (i.e., they are not only kept at the same potential), but they are actually bonded to ground (i.e., they are reliably kept at the potential of ground). It means that the purpose of a grounding conductor between the service enclosure and a grounding electrode is to always keep the equipotential plane established by the equipment bonding — at the potential of ground.
What about a system grounding conductor? In a typical solidly grounded system usually derived by a secondary of a utility or a customer-owned transformer or by a generator, a neutral point of the system is connected to ground via a system grounding conductor and a grounding electrode. This neutral point is also permitted to be connected to the enclosure of a transformer or a generator.
Photo 3. Does identification of the neutral conductor meet the CE
So, how should a grounding conductor be sized? The answer to this question depends on the answer to another question: doesa grounding conductor carry a fault current?
Let’s review this question. When a fault current is imposed on a non-current-carrying metal part of electrical equipment which is bonded by a bonding conductor, this fault current is brought back to the service equipment by the bonding conductor sized in accordance with Table 16. What will be the effective path of a fault current back to the electrical power supply source in order to facilitate operation of the overcurrent protective device? Will this path be provided by a grounded service conductor which connects the bonded enclosure of the service equipment with the grounded neutral point of the source (with the grounded neutral point of the transformer or generator), or will it be provided by a grounding conductor and earth back to the neutral point of the source?
Of course, the effective ground fault current path will be provided only via a grounded service conductor and, for the purpose of facilitating operation of the overcurrent protective device, the fault current will never reach the source via a grounding conductor. This means that a grounding conductor does not carry a fault current for the purpose of facilitating operation of the overcurrent protective device. Of course, it does not. This is the reason that Table 17 has been removed from the CE Code, and Rule 10-812 states the following requirement for a grounding conductor sizing:
10-812 Grounding conductor size for alternating-current systems and for service equipment (see Appendix B) "The size of the grounding conductor connected to a grounding electrode conforming to Rule 10-700 shall be not smaller than No. 6 AWG.”
Appendix B note on Rule 10-812 offers the following clarification of this requirement:
"Appendix B Note on Rule 10-812 "It is intended that the size of a grounding conductor for a solidly grounded alternating-current system connected to a grounding electrode need not be larger than No. 6 AWG. The majority of fault current will be taken by the service grounded conductor of the system back to the source, and a grounding conductor sized not less than No. 6 AWG would be sufficient to carry any portion of the fault current that will flow through it.”
Let’s now elaborate on a "grounded service conductor” which will carry the fault current back to the source from the bonded service equipment. Usually such grounded service conductor is a neutral conductor.
3. Neutral conductor
Neutral is defined in the CE Code as follows: "Neutral — the conductor (when one exists) of a polyphase circuit or single-phase, 3-wire circuit that is intended to have a voltage such that the voltage differences between it and each of the other conductors are approximately equal in magnitude and are equally spaced in phase (see Appendix B).”
Appendix B provides the following clarification on this definition:
"Neutral — By definition, a neutral conductor of a circuit requires at least three conductors in that circuit. However, in the trade, the term "neutral conductor” is commonly applied to the conductor of a 2-wire circuit that is connected to a conductor grounded at the supply end. Care should therefore be taken in the use of this term when applying the Code.”
Neutral is acircuit conductor. However, neutral is identified (i.e., grounded) circuit conductor. Ina 3-phase, 4-wire circuit, or in a single-phase, 3-wire circuit, neutral conductor carries only unbalanced current. In a typical 2-wire circuit, neutral (identified) conductor carriesa full load current.
In fact, Subrules (3) and (4) of Rule 4-004 of the CE Code help the Code users in understanding the function of a neutral conductor in a circuit as follows:
"Rule 4-004(3) A neutral conductor that carries only the unbalanced current from other conductors, as in the case of normally balanced circuits of three or more conductors, shall not be counted in determining ampacities as provided for in Subrules (1) and (2).
Rule 4-004(4) When a load is connected between a single-phase conductor and the neutral, or between each of two phase conductors and the neutral, of a three-phase, 4-wire system, the common conductor carries a current comparable to that in the phase conductors and shall be counted in determining the ampacities as provided for in Subrules (1) and (2).”
Rule 4-022 provides guidance to the Code users regarding the minimum allowable size selection of a neutral conductor:
"Rule 4-024 Size of neutral conductor(1) The neutral conductor shall have sufficient ampacity to carry the unbalanced load. (2) The maximum unbalanced load shall be the maximum connected load between the neutral and any one ungrounded conductor as determined by Section 8 but subject to the following: (a) there shall be no reduction in the size of the neutral for that portion of the load that consists of (i) electric-discharge lighting; or (ii) non-linear loads supplied from a 3-phase, 4-wire system; and (b) except as required otherwise by Item (a), a demand factor of 70% shall be permitted to be applied to that portion of the unbalanced load in excess of 200 A. (3) The size of a service neutral shall be not smaller than the size of a neutral selected in accordance with Subrule (1) and shall (a) be not smaller than No. 10 AWG copper or No. 8 AWG aluminum; and (b) be sized not smaller than a grounded conductor as required by Rule 10-204(2), except in service entrance cable or where the service conductors are No. 10 AWG copper or No. 8 AWG aluminum. (4) In determining the ampacity of an uninsulated neutral conductor run in a raceway, it shall be considered to be insulated with insulation having a temperature rating not higher than that of the adjacent circuit conductors.”
But which Code requirement recognizes neutral conductor as a bonding conductor when the neutral conductor is installed betweentheneutral point of a solidly grounded system at the power supply sourceand the grounded enclosure of the service equipment?
The answer could be found in Rule 10-204(2) of the CE Code. Rule 10-204(2) "Where the system is grounded at any point, the grounded conductor shall: (a) be run to each individual service; (b) have a minimum size as specified for bonding conductors in Table 16; (c) also comply with Rule 4-024 where it serves as the neutral”;
This Code rule clearly recognizes the fact that the grounded conductor installed between the source of a solidly grounded supply system and the service is actually a bonding conductor, as it will carry the fault current between the bonded service enclosureand the source [see paragraph (b) above]. This rule also states that in addition to being a bonding conductor (and being sized as per Table 16) this grounded service conductor must be sized as per Rule 4-024 when it serves as a neutral conductor. Rule 10-624(4) specifically recognizes the fact that a grounded service conductor (regardless whether it is used as a neutral or just as a bonding conductor between the source of the solidly grounded supply and the service equipment) is permitted to bond the service equipment, thus re-enforcing its purpose by the Code of carrying the fault current between the service equipment and the source. Rule 10-624(4) states:
"The grounded service conductor on the supply side of the service disconnecting means shall be permitted to be connected to the metal meter mounting devices and service equipment, and where the grounded service conductor passes through the meter mounting device it shall be bonded to the meter mounting device.”
Hopefully, this exercise of reviewing functions of bonding, grounding and neutral conductors and criteria for selecting appropriate sizes of these unique conductors will help to further clarify the subject of bonding and grounding. However, as usual, in each case of design and installation, the respective AHJ should be consulted in discussing specific issues related to this subject.
Read more by Ark Tsisserev
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 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 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.
Posted By Steve Douglas,
Wednesday, May 01, 2013
Updated: Friday, April 26, 2013
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Residential load calculations first appeared in
the Canadian Electrical Code Part I (CE Code) in
the second edition dated 1930. In the 1930 edition, the load calculation rules
were in Section 6 Conductors. The calculations were quite different from the
present day calculations. For residential installations, the calculations were
based on the number of branch circuits being installed instead of the dwelling
floor area. In the fourth edition, dated 1939, a demand factor table for
lighting load based on the floor area was added. In the sixth edition dated
1953, the Conductor Section including the load calculation requirements were
moved to Section 4 Conductors. This calculation format remained until the
seventh edition, dated 1958. A new section called Circuit Loading and Demand
Factors including the single dwelling load calculations was added as Section 8
to the eighth edition of the CE Code dated 1962.
Photo 1. Single dwelling units as defined in the CE Code Part I
In the 1958 edition, calculations were similar to the
calculations of today with the main difference in the calculations being the
basic load. The basic load covering lighting and convenience outlets was 3,500
W for a residence with a living area up to 500 ft² (46.5 m²). For a residence
with a living area over 500 ft² and up to 1500 ft² (139.4 m²), the basic load
was 4,500 W with an additional 1000 W for each 1000 ft² (93m²) or portion
thereof. The 1958 basic load requirements stayed the same until the twelfth
edition dated 1975 when the basic load was increased to the requirements of the
Rule 8-200 of the 2012 CE Code covers load
calculations used to determine the minimum feeder or service size for
single dwelling units. To start off, we should establish what a dwelling unit
is. Section 0 defines a single dwelling unit as "a dwelling unit
consisting of a detached house, one unit of row housing, or one unit of a
semi-detached, duplex, triplex, or quadruplex house,” and a dwelling unit
as "one or more rooms for the use of one or more persons as a
housekeeping unit with cooking, eating, living, and sleeping facilities.”
Subrule (1) of Rule 8-200 is divided into two items (a) and (b). Item (a)
details the specific criteria for calculations and Item (b) mandates the
absolute minimum allowable ampacity of the service or feeder size – based on
the floor area. 100 A is required by the Code where the floor area of the
single dwelling, exclusive of basement floor area, is 80 m² (861 ft²) or more,
and 60 A is the minimum permitted service/feeder ampacity – where the floor area
of the single dwelling, exclusive of basement floor area, is less than 80 m².
Item (a) is further divided into seven items (i) to (vii).
Items (i) and
(ii) detail a basic load for the dwelling unit. This basic load includes 120 V 15- and 20-amp
convenience outlets, lighting loads and motor loads rated up to 1500 W. The
basic load for the dwelling unit is 5000 W for the first 90 m² (968 ft²) of
living area plus an additional 1000 W for each 90 m² or portion thereof in
excess of 90 m². The living area is determined as 100% of the ground floor,
100% of any area used for living purposes on the upper floor, plus 75% of the
basement area of the dwelling unit.
The next step in Item (iii) is to add the electric
space-heating and air-conditioning loads. Where it is known that the
installed electric space-heating and air-conditioning loads will not be used
simultaneously, the larger of the electric space-heating load or the
air-conditioning load is added to the base load. For electric space-heating
systems consisting of electric thermal storage heating, duct heater, or an
electric furnace, the connected heating load is calculated at 100% of the
equipment ratings. Where the electric heating installation is provided with
automatic thermostatic control devices in each room or heated area, the
electric space-heating load is 100% of the first 10 kW of connected heating
load plus the balance of the connected heating load at a demand factor of 75%.
Photo 2. A 11 kW electric range used in the article example
The next loads to add are any electric ranges.
Item (iv) allows 6000 W for a single range to be added to the basic load
provided the range does not have a rating in excess of 12 kW. In the event the
electric range is rated more than 12kW, 40% of any amount exceeding 12 kW will
need to be added as well.
Now we add water heaters. Item (v) indicates
any electric tankless water heaters or electric water heaters for steamers,
swimming pools, hot tubs, or spas are added to the basic load at 100% of
Item (vi) is new for the 2012 CE Code and
requires that any electric vehicle charging equipment loads also be added to
the basic load at 100% of equipment ratings.
The final step in Item (vii) is to add any
additional loads at 25% of the rating of each load with a rating in excess
of 1500 W if an electric range has been provided for, or 100% of the rating of
each load with a rating in excess of 1500 W up to a total of 6000 W plus 25% of
the load in excess of 6000 W if an electric range has not been provided for.
Photo 3. The nameplate of a 1500 W microwave oven
Photo 4. A 1500 W microwave oven used in the article example
As an example we will look at a 269 m² (2900 square
foot) residence with the following loads:
- lighting load
- 4 small appliance branch circuits
- laundry circuit 1500 W
- natural gas heating
- air conditioner 6000 VA
- electric range 11,000 W
- hot tub 8000 W (2 hp motor)
- Level II electric vehicle charger 7200 W
- electric dryer 5000 W
- garbage disposal 800 W
- microwave 1500 W
- dishwasher 1200 W
- electric water heater 4500 W
The calculated load for the 2900 ft² (269 m²)
single dwelling in this example is 173.1 amps.
The basic load is calculated based on the floor area
of the single dwelling. The load for the first 90 m² is 5000 W, leaving 179
m² of floor area. The next 90 m² has a load of 1000 W, and an additional
1000 W for the remaining 89 m². The total basic load of 7000 W includes the
lighting, convenience receptacles, small appliance branch circuits, laundry
circuit, garbage disposal, and the dishwasher.
The heating of the single dwelling is a gas furnace
and no electric heat is installed, leaving the 6000 W air-conditioning load
added with a demand factor of 100%.
The electric range for this single dwelling is less
than 12 kW providing a load for the calculation of 6000 W.
The 8000 W hot tub and the 7200 W electric vehicle
charging equipment are now added with a demand factor of 100%.
Any additional loads with a rating in excess of 1500
W are now added with a demand factor of 25%. In this example, the additional
loads over 1500 W are the 5000 W dryer and the 4500 W storage type water
heater; 25% of the 9500 W gives us 2375 W to be added to the calculation.
Table 1. Summary of the single dwelling service load calculation
Now that we know the calculated load, we can
determine the minimum service and conductor size. The ampacity of the load is
173.1 amps (41550 / 240 = 173.1). In most installations, the continuous load on
a service is limited to the continuous load rating of the equipment being used.
Subrule (3) of Rule 8-104 considers all loads continuous unless it can be shown
that in normal operation the load will not persist for a total of more than one
hour in any two-hour period for loads not exceeding 225 amp, or a total of more
than three hours in any six-hour period for loads in excess of 225 amp. In the
case of single dwelling units Subrule (2) of Rule 8-200 allows these loads to
be considered as a non-continuous load for application of Rule 8-104. However,
although Section 86 considers the EV charging equipment to be a continuous
load, when this load is calculated for the purpose of defining the ampacity of
a service in a single dwelling, such EV charging equipment load is not
considered as continuous load, similarly to all other loads under this Rule.
This means 100% of the calculated load for a single dwelling can be used to
determine the service equipment ampere rating. For our 269 m² example a
standard rating of 175 amp overcurrent device could be selected in the service
box as the calculated load is 173.1 amp. Typically 175 amp rating of the
overcurrent device will necessitate installation of the 200 A rated service
box, as 175 A rating for the service fused disconnect or the service circuit
breaker for residential installations is not available. In most cases a 200-amp
service would be installed with a 175-A or 200-A trip setting or rating. Let’s
consider that the trip setting of the service overcurrent device was selected
at 200 A.
The size of the service conductors are now
established using Rules 4-004, 4-006, and 14-104. As all distribution equipment
presently available has a temperature limitation of 75⁰C, Rule 4-006 requires
the allowable ampacity to be based on the 75⁰C column of either Table 2 or 4
for conductors installed in a raceway. The smallest 75⁰C conductor allowable
ampacity from Tables 2 and 4 for the calculated load of 173.1 amp are 2/0
copper with an allowable ampacity of 175 amp, or 4/0 aluminum with an allowable
ampacity of 180 amp.
Photo 5. The nameplate for a 1200 W dishwasher used in the article example
The next step is to verify the conductor selected meets
the requirements of Rule 14-104. Rule 14-104 requires the overcurrent device to
have a setting not higher than the allowable ampacity of the conductors being
protected. Where the conductor allowable ampacity does not correspond with the
overcurrent protection commercially available, Table 13 provides details on
acceptable limits for over protection settings. Based on the fact that a
200-amp service will be installed with a main 200-amp trip setting for the
breaker, Table 13 limits the conductor allowable ampacity to be not less than
176 amps. In the case of the copper conductors, the 2/0 copper conductor with
the allowable ampacity of 175 amp is undersized. At this point some code users
will try to apply "the 5% rule” in Subrule (1) of Rule 8-106 to the 175
allowable ampacity of Table 2. Subrule (1) of Rule 8-106 allows loads
calculated in accordance with Section 8 to be within 5% of the allowable
ampacity of the conductors selected. This means the 5% allowance can be applied
to a calculated load. Applying the "5% rule to a conductor allowable ampacity
table is a misapplication of Subrule (1).
In summary, the minimum
conductor size allowed for the 200-amp service where the conductors are
installed in a raceway for the example in this article is either 3/0 copper or
4/0 aluminum. If the main breaker of this service was reduced to 175 amp the
minimum copper conductor size could be reduced either 2/0, and the aluminum conductor
would remain at 4/0.
Posted By Thomas A. Domitrovich,
Friday, March 01, 2013
Updated: Wednesday, February 13, 2013
| Comments (0)
Recognizing shock hazards can be difficult to the untrained or inexperienced eye on job sites and especially areas / facilities that have experienced storm damage. An electrocution is the result of coming in contact with a lethal amount current. Shock protection comes in many forms with ground-fault circuit interrupters (GFCIs) being that last line of defense of protection; as long as you are lucky enough that this type of protection has been installed and installed correctly. There are many ways to stay safe, we simply need to train our eyes and implement the correct procedures and tools to facilitate it.
Based on data from the National Institute for Occupational Safety and Health (NIOSH) National Traumatic Occupational Fatalities (NTOF) surveillance system, electrocutions were the fifth leading cause of death from 1980 through 1995. The 7,326 deaths caused by electrocutions during this period accounted for 7.8% of all fatalities in the workplace and averaged 488 deaths per year. Electrocutions were fifth as compared to motor vehicle incidents (#1), machine related deaths (#2), homicides (#3) and, finally, falls (#4). Yes, it is hard to protect from something you can’t see, but there are lines of defense that you can use to ensure you do not come in contact with energized conductors and/or equipment.
Based on data from the National Center for Health Statistics (NCHS), the total number of electrocutions in the United States has decreased from 670 in 1990 to 400 in 2000. This is a reduction of 40%. During this same period, an estimated number of electrocutions related to consumer products decreased from 270 to 150, a whopping 44%. The work we do in codes and standards is driving these numbers in the right direction. Product standards are making the necessary changes to ensure products are more robust with this regard, installation codes like the NEC are including changes that help to provide the protection needed in new structures being built and work practices standards like NFPA 70E help to address safety in the workplace. On top of all of this activity, we are more educated on the topic of shock protection through articles such as this and IAEI training events like those held across the country every day.
Figure 1. Electrical tape or similar methods are not a fix for these types of severe neglect.
Lines of Defense
There are many ways to avoid coming in contact with energized conductors and equipment and there are various documents that help us understand how to do just that. The primary document that comes to my mind on this topic is the National Fire Protection Association’s (NFPA) number two best seller, NFPA 70E, "Standard for Electrical Safety in the Workplace.” In addition to this document, the National Electrical Code, NFPA 70, also helps. Let’s review some important lines of defense.
Grounding and Bonding: NEC 2011’s Article 250 takes a total of 31 pages to help ensure the grounding and bonding of your system is such that equipment type ground faults have the lowest amount of impedance possible, resulting in them being high enough to be overcurrents that are cleared by the overcurrent protective devices in the circuit. Ground faults can be overcurrents if they are high enough to exceed the ratings of the conductors and other equipment. In fact, NEC 2011 Article 100’s definition of overcurrent includes ground faults; it states that an overcurrent is "any current in excess of the rated current of equipment or the ampacity of a conductor. It may result from overload, short circuit, or ground fault.” By ensuring an effective ground path, overcurrent protective devices can do their job in clearing these dangerous faults that if left unattended due to high impedances, could result in fires and even electrocutions should someone touch these energized parts. Acting to de-energize problem circuits before a person comes in contact with them or the equipment they energize helps avoid an electrocution from occurring.
Distance: Putting distance between yourself or others and a hazardous location is one sure way to prevent electrocutions. Barriers and guards can help ensure only qualified individuals are in work areas. NFPA 70E has provisions for limited approach boundaries and advises that physical mechanical barriers should be installed no closer than the restricted approach boundaries defined within that document. It’s advisable to use non-conductive barriers, especially where they may come in contact with energized parts. Tools also help to put some distance between you and the work you are performing that may present opportunities for you to come in contact with energized equipment. Tools such as communicating management systems will provide the ability to open or close protective devices or switches from the safety of an office well away from the equipment. Hot sticks and similar type devices also facilitate the separation needed. Your equipment, though, must be well maintained and inspected before every use.
Insulated Tools: Insulated hand tools, matting and other personal protection equipment (PPE) can help prevent electrocution should you or your tool come in contact with energized equipment. Ensure your tools have not fallen in to disrepair, as insulation that is there to protect you could be jeopardized. You may have hand tools with insulated handles worn through, creating safety concerns. Figure 1 is a severe case of neglect. Electrical tape or similar methods are not a fix for these types of problems. There comes a time when if your tools don’t pass basic visual inspections, they should be replaced. Some tools require more than just a visual inspection; specific testing to identified standards may be required. NFPA 70E’s Table 130.7(C)(14), "Standards on Protective Equipment,” provides reference documents for various PPE items you will use on projects.
Rubber protective products require visual inspection before every use. Table 130.7(C)(14) has the following with respect to these types of products. Rubber Protective Products — Visual Inspection Standard Guide for Visual Inspection of Electrical Protective Rubber Products ASTM F 1236 - 96(2007)
Figure 2. This drawing Illustrates that the ground-fault sensor must have both conductors passing through the device. This sensor senses an imbalance in current and sends the difference of current between that which is going to the load and that which is coming back from the load to the relaying equipment.
For even more detail on rubber insulating equipment, NFPA 70E has Table 130.7(C)(7)(c), "Rubber Insulating Equipment, Maximum Test Intervals,” yet another good example of testing frequency and reference test standards. This table advises that blankets should be tested before first issue and every 12 months thereafter. Gloves should be tested before first issue and every 6 months thereafter. Gloves are tested to ASTM F 496. This table addresses blankets, covers, gloves, line hose and sleeves.
Personal Protective Equipment: Your personal protective equipment is important on every job. You must not only maintain your PPE, but you must also ensure you are using the correct equipment for the job at hand. NFPA 70E 130.7(C)(15), "Selection of Personal Protective Equipment When Required for Various Tasks,” is the perfect reference for this line of defense. This section includes a wealth of information providing guidance on which PPE should be utilized for various types of projects. This section includes those tables illustrated above as well as hazard / risk category guidance to help convey which PPE is required when working on various types of equipment.
Working De-Energized / Lockout-Tagout: Yet one more way to ensure your team avoids electrocution is to work on de-energized equipment. We should always strive to work de-energized. Proper lock-out tag-out procedures should be followed, and effective testing techniques to ensure equipment is de-energized are important as well.
GFCI Protection: The acronym GFCI is used quite often and if I were to hazard a guess, I would say that very often it is used incorrectly. It is not only important to use terminology correctly but to also understand the limitations of the various ground-fault devices out there to facilitate in their proper application. GFCI protection is your last line of defense that is hopefully provided in your situation. The next few sections will take a high level look at a few different types of ground-fault devices.
Safety Plan: Last but not least is your safety plan. This is that document that pulls together all of your safety procedures and policies providing your plan to electrical safety. This document is your springboard for safety training and reporting. It is the glue to all that is safety for your organization.
Figure 3. This image demonstrates all of the conductors passing through the sensor, as it is the job of the sensor to ensure all current is accounted for. Only 2-pole devices are adequate for these types of applications.
UL 943 vs. UL 1053 Ground-Fault Protection Devices
We’re talking people protection versus equipment protection when we set these two UL standards side-by-side. A device tested to UL 943, "Ground-Fault Circuit Interrupters,” is one that is intended for the protection of personnel. The Scope of UL 943 reads as follows: "This Standard applies to Class A, single- and three-phase, ground-fault circuit-interrupters intended for protection of personnel, for use only in grounded neutral systems in accordance with the National Electrical Code (NEC), ANSI/NFPA 70, the Canadian Electrical Code, C22.1 (CEC), and Electrical Installations (Use), NOM-001-SEDE. These devices are intended for use on alternating current (AC) circuits of 120 V, 208Y/120 V, 120/240 V, 127 V, or 220Y/127 V, 60 Hz circuits.”
A UL 1053, "Ground-Fault Sensing and Relaying Equipment,” device on the other hand is one that is designed to protect from equipment damage due to ground fault. The scope of this standard reads as follows: "These requirements cover ground-fault current sensing devices, relaying equipment, or combinations of ground-fault current sensing devices and relaying equipment or equivalent protection equipment for use in ordinary locations that will operate to cause a disconnecting device to open all ungrounded conductors at predetermined values of ground-fault current, in accordance with the National Electrical Code, ANSI/NFPA 70.” These types of devices help to prevent burn downs and other types of electrical fires.
A ground-fault device is going to be present to serve one of two basic needs: provide people protection or provide equipment protection. We’ll discuss the applications of both of these types of devices after covering some of the basics of ground-fault protection to help us understand their goals and their proper application. Suffice it to say that a device listed to UL 943 is designed for personnel protection and a device listed to UL 1053 is designed for equipment level ground-fault protection. Let’s take a quick refresher on how a GFCI device works before addressing the differences between these two basic types of devices.
Ground-Fault Device Operation Basics
A ground-fault device operates off of the basic principle of differential current; that current which goes out to the load through the hot conductor has to come back from the load over the neutral conductor. (Reference figure 2). The conductors involved are the expected paths for current. This applies to 2-wire, 3-wire or even more conductors in the case of three-phase installations. A three-phase device may appear to get a little more complicated due to phase angles and more hardware that needs to be installed, but you are still working off the basic fundamental principal of what goes out must come back over the expected paths, the conductors for the circuit.
A ground-fault device will employ two key components that work together to determine if ground-fault current is flowing. The system is comprised of sensing equipment and relaying equipment. The sensing equipment will come in the form of a current transformer that can be placed at various locations within the circuit. Sensing equipment and relaying equipment do not have to all be in one self-contained device. Industrial power systems will employ separate sensing equipment in the form of current transformers around bus bars or large conductors that must be wired back to the equipment. In the case of smaller ground-fault type devices like those you will find in residential applications, both sensing equipment and relaying equipment are located in the same small enclosure. Just to keep things simple, we’ll address what you would find in a residential ground-fault device as both of these key components are typically located within one small compact device.
Your basic ground-fault breaker or receptacle-type devices include a current transformer that surrounds the hot and neutral conductors of the circuit and a small circuit board that receives the signal from this sensor and makes the decision of whether or not to open the circuit. The conductors that pass through the sensor window must include all hot and neutral conductors serving the load. This is why, for shared neutral applications, you cannot apply a handle tie to two single-pole breakers and share the neutral. Both breakers need their own neutral return path. A two-pole GFCI device ensures the integrity of current flow through the internal current transformer for proper operation. (Reference figures 2 and 3 for examples of this).
Ground- fault currents are seeking the path of least resistance back to the source. NEC 2011’s Article 250 takes the time in a total of 31 pages to help you ensure the grounding and bonding of your system is the best it can be. For equipment ground faults, you want a low impedance path to the source. Article 250 helps get you there. Every wire connector and connection point in the grounding system is important to achieve your goals. If you have a good low impedance path to ground, your equipment type ground faults will become overcurrents that are acted upon by your standard overcurrent protective devices up stream.
Personnel Protection – UL 943
Now that we have a basic understanding of how ground-fault devices work, let’s explore what makes a ground-fault device a GFCI, one that is intended to protect personnel. To get electrocuted, three things are important: (1) the amount of current, (2) the path it takes through the body and (3) the amount of time it flows. A GFCI device does not know the path that current takes through your body and can have no control over that, but it can detect the amount of current and identify when to open the circuit. UL 943 defines these two key parameters for these types of devices. A GFCI device is designed to not trip for currents less than 4 mA and to always trip for currents above 6 mA. The amount of time it takes is determined by a couple of equations. For low-resistance faults, the equation is as follows:
For high-resistance faults, the equation is as follows:
So as an example, for a high-impedance fault which would result in a small current flowing, say 6mA as an example, the GFCI device as per the above equation will take 5.59 seconds to trip.
In reality, all GFCI devices trip much faster than that required by UL 943 and a 6mA fault would normally take no more than 0.1 seconds, with some margin for error, to be cleared by an off-the-shelf GFCI device.
To understand what this means to a person, the following table is used by many documents to describe the effect of current.
A GFCI device is designed to open the circuit to avoid the problems identified in table 1.
Table 1. The effect of current on humans
Equipment Protection – UL 1053
A device designed to this standard for equipment level protection is not meant to protect a person from electrocution. The UL standard for this type of device does not specify the current level at which it will pick up; it merely defines, amongst many other requirements, the amount of time it can take to clear. A UL 1053 device establishes the time criteria for clearing a ground fault at the pick-up level defined by the manufacturer of the device.
This performance criterion is not based on when the heart goes into defibrillation or when it may stop. This is an important thing to remember as it would be a mistake to apply a UL 1053 device, thinking you are going to achieve personnel protection.
Table 2. A UL 1053 device establishes the following as the time criteria for clearing a ground fault at the pick-up level defined by the manufacturer of the device.
There are many ways to prevent electrocution. Leverage your various lines of defense to avoid coming in contact with energized conductors and/or equipment; and as your last line of defense, ensure you have employed the correct GFCI device for personnel protection. GFCI devices are not required on every circuit at every voltage and for every application. Do everything you can to keep your distance, use insulated equipment, take care of your tools, and think and observe before proceeding in and around hazardous areas.
As always, keep safety at the top of your list and ensure you and those around you live to see another day.
Read more by Thomas A. Domitrovich