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The Southwest Technology Development Institute web site maintains a PV Systems Inspector/Installer Checklist and all copies of the previous “Perspectives on PV” articles for easy downloading. A color copy of the latest version (1.93) of the 150-page, Photovoltaic Power Systems and the 2005 National Electrical Code: Suggested Practices, written by the author, may be downloaded from this web site: http://www.nmsu.edu/~tdi/Photovoltaics/Codes-Stds/Codes-Stds.html

 

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Continuous Currents through Curious Cables

Posted By John Wiles, Monday, January 01, 2007
Updated: Tuesday, January 22, 2013

When inspectors see a photovoltaic (PV) power system for the first time, they will usually be faced with a type of wiring method not normally seen in residential or commercial electrical systems. That wiring method is the use of single-conductor exposed cables to connect the individual PV modules together in the PV array and is permitted by NEC 690.31. Exposed, single-conductor wiring is usually seen only in older neighborhoods as aerial feeders between buildings and in obsolete (but still with us) knob-and-tube wiring systems.


Photo 1. Modern PV module with leads and connectors

A Little History

PV modules, for the most part, are currently manufactured (and listed) with attached leads with connectors attached [see photo 1/inset 1]. The leads are 3–4 feet long and have polarized connectors, one for the positive output and one for the negative output.


 

Inset 1. Sealed terminal box and MultiContact connectors

 


Photo 2. Early (1980s) PV module with exposed, widely spaced terminals

Historically, this exposed wiring method was allowed into the Code in 1984 because PV modules at that time had single, widely spaced output terminals diagonally opposed at opposite corners on the back of the modules [see photo 2/inset 2].


Inset 2. Exposed terminal minus the insulating cover

It was deemed too difficult (and wasteful) to use one of the conventional wiring methods to make connections to these single terminals when many of the connections were routed to another single terminal on an adjacent module only a few inches away. Subsequent to the early days, where exposed terminals and insulating caps were used, junction boxes were added at each end of the module, one for the positive and one for the negative contact [see photo 3/inset 3].

In the 1990s, both positive and negative contacts were placed in a conduit-ready junction box at one end of the modules [see photo 4/inset 4].

These types of modules with conduit-ready junction boxes are still available on special order from a few manufacturers for use where local codes require the use of conduit, particularly in commercial installations.

Workmanship Is Important

The length of the leads attached to PV modules is sufficiently long to allow the modules to be mounted side by side in either portrait or landscape orientation. In either orientation, but particularly in the portrait configuration, the excess length of the leads should be gathered and secured to the module frames or mounting racks to provide some degree of mechanical protection from wind, rain, snow and ice. In no case should the single conductor leads touch the roof or be allowed to move in the wind. This could cause the cable insulation to be abraded or place strain on the module terminal boxes where the cables attach.

Photo 3. Older (1990s) PV module with two junction boxes

Inset 3. Junction box - single polarity

Conductor Types

The conductors permanently attached to the PV module are part of the listed module assembly and, presumably, Underwriters Laboratories (UL) has verified that the cables meet the necessary safety requirements. In most cases, the cables will be marked USE-2 or USE-2/RHW-2, and some also will be marked "Sunlight Resistant” indicating better ultra-violet capability than the basic USE-2, which is tested for UV resistance but not marked as such.


Photo 4. Special order PV module with conduit-ready junction box

PV modules are connected in series (called strings) and, after making anywhere from 4 to 24 series connections, the positive and negative conductors at the ends of the string are some distance apart. In order to bring these two points to a common location, single conductor wiring is again used. Although USE, SE, and UF cables are allowed by Section 690.31, the installer typically uses a USE-2 or USE-2/RHW-2 cable to get both the negative and positive negative conductors to a common junction point in the PV array. At this point, the exposed conductors are transitioned, using a junction box to one of the common wiring methods found in chapter 3. Don’t be misled by extraneous markings like MSHA and DLO as shown on the cable in the lead-in picture. This sunlight-resistant RHW-2 cable is not allowed by Section 690.31 for exposed, field-installed, PV module interconnections.


Inset 4. Junction box, both polarities

Since the environment is hot and wet on exposed roofs, usually THHN/THWN-2 or RHW-2 conductors are installed in conduit. EMT is commonly used and, where allowed by local codes, RNC may be used. In some cases, LNFC has been used and when properly attached to the supporting structure may be acceptable. A discussion of the routing of this output circuit may be found in the "Perspectives on PV” in the May/June 2007 IAEI News.

In NEC-2008, cable types USE, UF, and SE are being removed from Section 690.31 due to temperature limitations and availability in the needed sizes (10, 12, and 14 AWG) for the module interconnections.

A new PV conductor will appear in NEC-2008 in Section 690.31. It is mentioned in the comment for Section 690.35 in the 2005 NEC Handbook. This is a single-conductor cable designated "PV Wire,” "Photovoltaic Wire,” "PV Cable,” or "Photovoltaic Cable.” This cable will have an insulation that is thicker than the insulation on USE-2 (conduit fill will have to be calculated), it will be marked "Sunlight Resistant,” and it will have the necessary flame retardant and smoke properties that will allow it to be used inside buildings in conduit. This cable will be one of the wiring methods required when the PV array is operated in an ungrounded manner in PV systems that use the new transformerless inverters. See Section 690.35 for the current requirements for such systems.

A Typical System

The three-wire diagram for a typical residential PV system is shown in figure 1. The modules are connected in series with the 12 AWG leads with polarized connectors that are permanently attached at the factory. A 12 AWG USE-2/RHW-2 conductor is used to get the negative end of the string back to a junction/pull box where it and the positive lead are transitioned to 10 AWG THHN/THWN-2 conductors in a ¾-inch EMT conduit.
 

Figure 1. Residential PV system, 3-wire schematic

Conductor Ampacity

The module short-circuit currents may range from 1 amp to about 17 amps (in unusual cases). The larger 300+ watt PV modules have short-circuit currents approaching 12 amps. The ampacity of the attached and any field-installed cables should be 1.56 times the module short-circuit current (Isc) after the conditions of use are applied. In most cases, the factory-attached cables have sufficient ampacity. However, in very hot climates, the ampacity calculations should be checked. The ampacity of these conductors in free air should be evaluated using Table 310.17.

Equipment Grounding Conductors

Equipment grounding conductors connected to the PV module frames should be sized at 1.25 times the module short-circuit current (Isc). On large PV arrays, where fuses are used to protect these conductors, Table 250.122 can be used. This will result in a smaller, but adequate, equipment-grounding conductor than will be calculated using the 1.25 Isc value.

INSPECTION AREAS REQUIRING ADDITIONAL ATTENTION

Inspectors have seen the following problems in non-code-compliant installations.

Common Sense and Durability
The exposed, single-conductor cables should only be used for module interconnections. They should not be run across the roof away from the PV array, but should be transitioned at or under the PV array to another wiring method found in chapter 3 that is appropriate for the conditions of use.

Cables Like It Hot
The modules may operate up to 80°C and wiring touching or near the backs of these hot modules should have 90°C-rated insulation. The outdoor environment is a wet environment so "-2” conductors should be used that have a 90°C, wet–rated insulation both in and out of conduit.

Conduits in sunlight on roofs are going to be hot. See fine print note 2 for Section 310.10 in NEC-2005, and also see proposals in this area for the 2008NEC. An added 17°C to the average high temperature will be the minimum addition to the ambient temperature inNEC-2008. In areas where average high ambient temperatures of 40°C (104°F) are experienced, then conduits are going to be operating at least at 57°C. Appropriate temperature deratings may dictate the use of larger conductors than have been used previously to accommodate the reduced ampacity at the higher temperatures.

Grounding—Critical
Module grounding deserves at least a book by itself. With PV modules serving as power sources that will be generating hazardous voltages for the next 40–50 years, individual module grounding is a critical issue. This is particularly important since the module frames are difficult-to-ground aluminum and should remain solidly grounded for the life of the module. A ground fault in a module could energize an ungrounded frame at dangerous voltages if the module were still connected to the rest of the PV array while the module is being removed or otherwise serviced. The old, old Code requirement of connecting the ground first and disconnecting it last must certainly apply to PV modules.

Module Protective Fuse
The backs of all listed PV modules are marked with a value of a "Maximum Series Fuse” or similar wording. The overcurrent device, where required and used, protects the internal module conductors from damage from overcurrents that could be forced through the module from external sources. While many residential PV systems do not require overcurrent protection in the dc circuits, the larger commercial systems usually do require dc overcurrent protection. This will be the subject of another "Perspectives on PV.” The Code requires that any overcurrent device installed in the output of a module be rated for 1.56 Isc. There are a few modules being made (for unknown reasons) that have a maximum series fuse value of less than 1.56 Isc. This poses a Code quandary. Section 690.8 says use a fuse rated at 1.56 Isc, but Section 110.3 says to follow the product labels. Any inspector seeing such a module should report the problem to UL through the AHJ channel on the UL web site.

Summary

PV module wiring can indeed pose questions. However, the basic requirements can be found in Article 690 and as soon as those curious currents travel away from the PV array, they are contained in wiring systems familiar to all inspectors. Don’t forget, it is a hot and wet environment.

For Additional Information

If this article has raised questions, do not hesitate to contact the author by phone or e-mail. E-mail: jwiles@nmsu.edu or phone: 505-646-6105

A color copy of the latest version (1.6) of the 150-page, Photovoltaic Power Systems and the 2005 National Electrical Code: Suggested Practices, published by Sandia National Laboratories and written by the author, may be downloaded from this web site: http://www.nmsu.edu/~tdi/Photovoltaics/Codes-Stds/PVnecSugPract.html

The Southwest Technology Development Institute web site maintains a PV Systems Inspector/Installer Checklist and all copies of the previous "Perspectives on PV” articles for easy downloading. Copies of "Code Corner” written by the author and published in Home Power Magazine over the last 10 years are also available on this web site: http://www.nmsu.edu/~tdi/Photovoltaics/Codes-Stds/Codes-Stds.html

The author makes 6–8 hour presentations on "PV Systems and the NEC” to groups of 40 or more inspectors, electricians, electrical contractors, and PV professionals for a very nominal cost on an as-requested basis. A schedule of future presentations can be found on the SWTDI web site.


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Tags:  Featured  July-August 2007  Perspectives on PV 

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Inspectors Demand More Answers

Posted By John Wiles, Monday, January 01, 2007
Updated: Tuesday, January 22, 2013

Electrical inspectors and other inspectors are curious people and when faced with reviewing plans for a PV system or inspecting such a system, there are many new features that are worth questioning. Here are some of the questions that inspectors have raised via e-mail, telephone calls, and during my PV/NEC presentations over the last four months.

Question: When are fuses required in the dc wiring of a PV system?

Answer: Fuses are generally required in the dc sections of a utility-interactive PV system for two reasons. First, all ungrounded conductors must be protected from over currents. Second, each PV module must be protected from reverse currents that exceed the value of the module protective fuse that is marked on the back of the module (fuses and circuit breakers are considered equivalent) [see photo 1]. Overcurrents may result from a short circuit in the wiring, and reverse currents may result from either a short circuit or a shaded module or modules. In most cases, a single overcurrent device will satisfy both of these requirements and, in many small residential PV systems, no overcurrent device at all is required.

These overcurrent devices are required only when there are sources of over currents that could damage either the wiring or the module during shading or fault conditions. In the utility-interactive PV system, with a listed inverter, the only source of currents or over currents in the dc part of the system originate in the modules themselves. The inverter is not able to provide any current into the dc PV array, so it is not a source of currents other than a short transient current as the input noise filtering capacitors discharge.


Photo 1. Label on back of PV module

In a single string of PV modules (a series connection of several modules from 2-20+), the only current in question is the current generated by the modules in the string. This current is, at a worst-case maximum, 125 percent of the rated module short-circuit current (Isc). This current is marked on the back of the module as shown in photo 1. Per NEC requirements (690.8 and 690.9), all circuit conductors will be sized at 156 percent of the same short-circuit current. Therefore, the conductors have no source of high overcurrents that would exceed their ampacity and they do not need overcurrent protection (690.9, Exception). Currents generated within a string of modules cannot produce reverse currents in that string and, since there are no external sources of currents, no overcurrent device is needed to protect the PV module. The result is that in a utility-interactive PV system with a single string of modules, no overcurrent device is needed in the dc circuit.


Photo 2. DC combiner box with circuit breakers operating up to 125 volts

When there are two strings of modules, it is possible for one string to attempt to force currents back into the other string when that string is shaded. The unshaded string can produce up to 125 percent of the rated short-circuit current. All wiring in each string is sized at 156 percent of that same current so no overcurrent devices are required to protect the module wiring. Most PV modules have a marked, module-protective fuse that is well in excess of 156 percent of the rated short-circuit current, so again, there is no requirement for an overcurrent device to protect the modules. With two strings of modules connected in parallel, no overcurrent device is needed in the dc wiring.

When three or more strings of modules are connected in parallel, the situation may be different and a calculation must be made. If we assume that one string of modules is shaded, then the two unshaded strings of modules may attempt to force reverse current into the shaded string. Each of the unshaded strings can source up to 125 percent of the rated short-circuit current, so two strings can source up to 2 x 1.25 x Isc = 2.50 Isc. If this current (2.50 Isc) is greater than the value of the maximum module protective fuse marked on the module, then an overcurrent device must be installed in the ungrounded conductor of each string, and the value will be typically be 1.56 Isc or larger, up to the value of the maximum protective fuse. A minimum value of 1.56 Isc will protect the module from reverse currents and will also protect the conductors that have also been sized at 1.56 Isc. If a larger value of series overcurrent protective device is used (up to the allowed maximum protective fuse value), the ampacity of the conductors connecting the modules must be adjusted accordingly.


Photo 3. DC combiner boxes with fuses operating up to 600 volts.

When there are more than three strings, the same calculation applies. Just take the number of strings in parallel and subtract one. Use this number times 1.25 x Isc to get a number that will be compared to the value of the module protective fuse. If the calculated number is larger than the protective fuse value, then one overcurrent device will be required on each of the series-connected strings of modules. The overcurrent devices are usually mounted in a dc combiner box as shown in photos 2 and 3.

In summary, one and two strings of modules on a utility-interactive inverter will require no overcurrent devices in the dc circuits. When three or more strings are used, a calculation must be completed to determine if overcurrent devices are required or not.

There are a few modules currently on the market that have a series fuse rating that is less than 1.56 Isc. This creates a quandary for the installer and the inspector. NEC 110.3(B) requires that the module label be followed, but 690.8 and 690.9 require that an overcurrent device rated at 1.56 Isc be used. When these cases come up, it is time to call UL or enter a complaint through their AHJ/regulatory web site and get this continuing issue resolved.

Question: On PV systems with batteries, how is the ampacity of the conductor for the charge controller output circuit determined?

Answer: The ampacity of the charge controller output circuit must be based on the rated maximum output of the charge controller. This information should be in technical specifications or the instruction manual for the controller. The circuit ampacity and the rating of any overcurrent device must be at least 125 percent of the rated steady-state output currents. In some cases, the rated output current is not stated.


Photo 4. Battery charge controller

Some controllers use a relay as the switching/controlling element. In this case, the rating of the relay becomes the rating for the controller.

In other cases, the charge controller does a voltage conversion and can take higher input voltages (such as 48-72 volts from the modules) and charge batteries at lower voltages such as a 24-volt or even a 12-volt battery. While the manuals for these charge controllers usually specify a rated output current, the installer (and the inspector) should verify that the PV system is not designed so that excessive currents are forced through the controller. If this happens, NEC 110.3(B) may be violated by using the listed controller in a manner that is not covered by the instructions. For example, a controller may be rated at 60 amps output when connected to a 24-volt battery. If this controller is connected to a 48-volt, 60-amp PV array, the controller will reduce the output voltage to 24 volts and, at the same time, try to increase the output current to almost 120 amps. While the controller will presumably protect the output circuit by limiting the output to 60 amps, the controller is not being used in accordance with the manufacturer’s instructions [110.3(B)]. Most of these controllers list the maximum PV input power levels or maximum currents at various voltage levels for each battery output voltage.

Question: What safety precautions should I observe when inspecting a PV system?


Photo 5. High voltage, high currents - exercise caution!

Answer:

Keep in mind that the PV dc circuits between the PV modules and the dc disconnect will be energized any time the modules have light on them (even at dawn and dusk). Connections, switchgear, and other devices can be at voltages up to 600 volts. On any system showing signs of poor workmanship at a distance (inspectors know poor workmanship when they see it), the proper grounding of all metal surfaces should be inspected first. After that, it should be safe to open boxes and switchgear and inspect further. For additional details, see the "Perspective on PV” in the May/June 2006 edition of IAEI News (PDF available on the author’s web site).

Question: What types of information should I be requesting on plans for PV systems being used to obtain a permit?

Answer: Since none of us have seen, installed, or inspected hundreds of PV systems and each one is different, we really need to get as many details as possible in the permitting package. It is far easier to verify Code compliance on paper in the comfort of the office and then check to see if it was installed per the permit. We need the following items in the permit package: 1) an overall description of the system and how it works, 2) specifications for each of the major components and manuals for the modules, inverters, and any charge controllers, 3) a two- or three-line diagram showing the equipment-grounding provisions and system-grounding provisions, 4) calculations showing Code compliance for conductor ampacity and conditions of use deratings. See "Perspectives on PV” in the March-April 2006 edition of IAEI News (PDF available on the author’s web site) for more details.

Question: What are the requirements for grounding a PV system that is installed on a metal roof.

Answer: The National Electrical Code (NEC) requires that any exposed non-current-carrying conductive surface that may be energized be grounded to minimize electrical shock hazards (Section 250.110).

Rooftop PV systems may operate at voltages approaching 600 volts. These voltages pose a significant shock hazard if they are allowed to energize conductive exposed surfaces that may be touched. Such exposed non-current-carrying conductive surfaces include the PV module frames, the metallic module mounting racks, and possibly the metal roof the racks are attached to. Effectively bonding these conductive surfaces together and grounding them will minimize shock hazards.

There are two primary wiring methods used for connecting PV modules together; single-conductor exposed cables and conduit. Each will dictate a different grounding method. In both situations, the PV module frames must always be grounded properly. See the "Perspectives on PV” article in the September-October 2004 issue of the IAEI News titled "PV System—Should They Be Grounded” for information on grounding PV modules. This article is also available on the author’s web site

PV systems using exposed, single-conductor cables

PV modules connected together with exposed single-conductor cables (the most common installation method) would almost invariably have those cables touching the module mounting racks, and those racks should be grounded. Movement of the cables from wind, rain, and ice could cause the conductor insulation to deteriorate, and the bare conductors could energize the racks. Aluminum racks can be as difficult to ground as aluminum-framed PV modules.
 

Photo 6. Grounding a metal roof, THHN questionable

In many cases, it would be difficult to keep these exposed cables from touching the metal roof. They could touch at initial installation, or they may come into contact with the roof at a later date as cable ties break or loosen. Wind, rain, and ice could cause the cable to rub against the metal roof, abrade the insulation, and allow the energized copper conductor to energize the roof.

Where these exposed single conductor cables are used for modules, the racks and the roof should be grounded. Instructions on how to properly ground a metal roof are not readily available, but photo 6 shows a possible method that might be used provided the non-UV rated THHN conductor were not used. A bare grounding conductor would be a better, code-compliant choice. Such connections should be made where water penetration would not be an issue.

PV systems using conduit between modules

When conduit is used between the individual modules (currently a rare situation) and there are no exposed, single-conductor cables, then it is unlikely that either the module racks or the roof would require grounding. The module frames should be grounded, and conduit should surround the conductors, protecting them from damage. The conduit may be insulating types like rigid nonmetallic conduit (RNC) and liquidtight flexible nonmetallic conduit (LFNC) or a metal type like electrical metallic tubing (EMT). The EMT would be grounded, the LFNC, RNC would not be grounded, and both would provide the desired physical protection. Even if the conductor insulation should fail, the conduit would prevent the rack or the roof from becoming energized. Neither the metal racks nor the metal roof would require grounding except in the event that significant and likely PV module damage could be expected. Such damage could cause the internal conductors of a shattered PV module to contact the rack or the roof. If such damage were expected, then grounding both the rack and the roof would be advised.

For Additional Information

If this article has raised questions, do not hesitate to contact the author by phone or e-mail. E-mail: jwiles@nmsu.edu or phone: 505-646-6105

A color copy of the 143-page, 2005 edition of the Photovoltaic Power Systems and the National Electrical Code: Suggested Practices, published by Sandia National Laboratories and written by the author, may be downloaded from this web site: (http://www.nmsu.edu/~tdi/roswell-8opt.pdf.) The Southwest Technology Development Institute web site (http://www.nmsu.edu/~tdi/Photovoltaics/Codes-Stds/Codes-Stds.html) maintains a PV Systems Inspector/Installer Checklist and all copies of the previous "Perspectives on PV” articles for easy downloading. Copies of "Code Corner ” written by the author and published in Home Power Magazine over the last 10 years are also available on this web site.

The author makes 6–8 hour presentations on "PV Systems and the NEC” to groups of 40 or more inspectors, electricians, electrical contractors, and PV professionals for a very nominal cost on an as-requested basis. A schedule of future presentations can be found on the SWTDI web site.


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Tags:  Featured  January-February 2007  Perspectives on PV 

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PV Systems and Workmanship

Posted By John Wiles, Wednesday, November 01, 2006
Updated: Tuesday, January 22, 2013

With electrical systems lifetimes exceeding forty years, PV systems must be installed using the best available workmanship to ensure public safety over the life of the system. Article 110, Requirements for Electrical Installations, and particularly Section 110.12, Mechanical Execution of Work, of theNational Electrical Code(NEC) establish some general requirements for the installation of electrical equipment. A fine print note (FPN) to Section 110.12 references the National Electrical Contractors Association standard ANSI/NECA 1-2000 (latest edition is 2006) as describing accepted industry practices for electrical installations. This article will illustrate some areas that need attention when the workmanship of PV installations is being inspected. Of course, the local authority having jurisdiction (AHJ) determines what is acceptable.

Photo 1

Modules

PV modules must be securely mounted to a supporting structure. Mounting holes are provided in the frames of PV modules, and the modules have been tested under simulated high wind loadings using only these holes to ensure that the module can withstand normal and expected environmental conditions. These holes must be used to secure the module to a mounting rack, which is secured, in turn, to the roof of a building or to the ground. The hardware used must be of the appropriate size and be resistant to the exposed outdoor conditions. Stainless steel hardware is most commonly used (see photo 1).


Photo 2. Module rack mounting bracket

The devices used to attach the PV array to the building must be robust and connect the mounting rack to the structural elements of the roof, such as the trusses or rafters. Attachment to only the roof sheathing generally does not provide adequate strength. All penetrations must be sealed against the environment. Photo 2 shows a PV array mounting bracket attached to a 2 x 6 under the shingles and sheathing with sealing to keep out the light rains found in New Mexico.

A few PV modules do not have frames but may have other mounting systems. Some have mounting attachment points bonded to the rear of the fameless modules (called laminates), and others are intended to be installed in a glazing system as part of a building integrated curtain wall or overhead transparent walkway covering. In all cases, the instructions furnished with the modules will show the mounting requirements. It should be noted that some PV modules without frames are not fully listed to UL Standard 1703. Modules in this category are marked with the UR (UL recognized component) mark and should be subject to a field inspection conducted by a nationally recognized testing laboratory (NRTL) that has field evaluation services (see photo 3).


Photo 3. Frameless PV modules in overhead canopy

Many PV modules now have exposed, single-conductor cables (one positive and one negative) attached to the backs of the modules. While these exposed conductors are allowed by Section 690.31, they are only to be used to make connections between the individual modules and should be terminated under or very near the PV array. At that point, the array output wiring should transition to one of the more common NEC Chapter 3 wiring methods, such as conductors in electrical metallic tubing (EMT). In general, these exposed single-conductor cables, with attached connectors, will be longer than necessary when the modules are mounted side by side (see photo 4). The excess length must be controlled by gathering and fastening the excess cable and the connectors to the module racks. It should not be allowed to droop down and be exposed to abrasion damage due to wind and ice.


Photo 4. Typical PV module with long interconnecting cables

The fastening means should be robust; however, some plastic cable ties (especially the white nylon variety) do not resist the heat and ultra violet exposure well. Stainless steel pipe clamps in various sizes with EDPM rubber inserts appear to withstand various environments quite well, but other options are available.

Some installers will cut off the connectors and excess cable lengths and then solder the two cables together minimizing the excess length. The soldered splice is insulated with outdoor rated heat shrink tubing with an internal sealant that yields a splice that has the same electrical, mechanical, and insulation properties as the unspliced conductor. While this meets the Code requirements and results in a neat, durable, workman-like installation as shown in photo 5, a few module manufacturers maintain that splicing may violate the listing and/or the warranty on the module. If the heat shrink tubing does not have the same or greater thickness as the conductor insulation or the heat shrink is not rated for UV exposure, then the splice must be enclosed.


Photo 5. Shortened, spliced, and secured module interconnections

Bare, equipment grounding conductors should also be afforded the same mechanical protection as the exposed, single-conductor, insulated circuit conductors. When these bare conductors are spliced, the proper device must be used—usually a copper split bolt. Photo 6 shows a crimp-on splicing connector that has been evaluated only for indoor applications (usually in a junction box) being used improperly outdoors.

Exposed Conduit Runs

Unless the provisions of 690.31(E) inNEC-2005 have been followed and the PV circuits are run in metallic raceways through the attic, the PV output circuits from the PV modules must remain outside the house until the readily accessible PV dc disconnect is reached. Conduits running across roofs and down the sides of houses and buildings must be appropriately supported and attached to the structure. Appropriate hardware must be used (again, stainless steel is popular) and any structural penetrations sealed to prevent weather intrusions. In most cases, theCodeestablishes the support requirements for the various wiring methods.
 

Photo 6. Dry location splicing device used improperly outdoors

Equipment Mounting

PV inverters, even in residential sized systems, can weigh over 100 pounds. These inverters as well as the various disconnects should be firmly attached to the walls with anchors that connect the equipment directly to the wall studs or other internal load-bearing members. Connections to just the drywall are not sufficient. Lag screw and conduit penetrations should avoid, of course, any electrical circuits or plumbing in the wall cavity.
 

Photo 7. Flooded, lead-acid batteries in containers

While the NEC (404.8) requires that the center of the grip on the disconnect handles be no higher than 6’ 7” in the upper position, there appears to be no minimum height requirement. Common sense dictates that equipment, including PV inverters, not be mounted so low that water or splashing rain or mud can get into it. Some PV inverters have minimum space requirements at the bottom for ventilation. Access panels and fittings must be accessible.

The distance between disconnects associated with the term grouping is left to the AHJ. Since inverters must have ac and dc disconnects to allow for safe service and removal, it would seem appropriate that these disconnects be located adjacent to the inverter. While some inverters have internal disconnects, the AHJ must determine whether or not the inverter can be safely removed for service using these internal disconnects or whether external disconnects must also be required. If the inverter is mounted on the other side of a wall from the main PV dc disconnect or not near the back fed breaker in the main ac load center, then additional "servicing” disconnects will generally be required adjacent to the inverter.


Photo 8. VRLA batteries with terminals covered

When all of the PV-related equipment is mounted outside (or inside) the building, including the PV dc disconnect, the inverter, any utility-required disconnect, and the main load center for the dwelling, a minimum number of disconnects can be used since all equipment is on one wall and is in close proximity. See "Perspectives on PV” in the July/August IAEI News for examples.

Batteries

A comparatively small number of PV systems, both off grid and utility-interactive, will employ batteries for energy storage. There are two general categories of batteries used in renewable energy systems. The older types are like car batteries and are called flooded, lead-acid batteries (see photo 7). They outgas water vapor, some sulfuric acid fumes, hydrogen, and oxygen gas when being charged vigorously. The other category of battery is known as a valve-regulated, lead-acid (VRLA) battery and, under proper charging, does not release gas or fumes (see photo 8). Both battery types will have terminals between the cells and connecting cables that must be checked periodically. Therefore, both types should be installed in a manner that does not allow inadvertent contact with any exposed, energized terminals. The flooded, lead-acid batteries will require weekly to monthly addition of water to the cells, and contact with the cell caps should be restricted due to the normal presence of battery acid in these areas. In general, the flooded batteries should be mounted in containers (battery boxes) that will allow for frequent servicing while still preventing unqualified people from coming into contact with the battery tops or the energized contacts. Lockable, heavy-duty plastic toolboxes work well in this application. Spilled-electrolyte containment is also a consideration due to the infrequent overcharging that may occur. Hydrogen gas from the batteries is not normally found in explosive concentrations unless contained in small volumes, and small ventilation holes in the top of any battery box will allow it to escape into the room, which should be a well vented area like a garage or utility shed. Venting manifolds are generally not required or desired.

VRLA batteries are more easily installed and generally only need the terminals protected from accidental contact. Containers are normally not needed.

Conduit penetrations in containers with flooded batteries should be made in the sides of the container below the tops of the batteries. This will minimize the possibility of any hydrogen gas (which rises) from getting into the conduits.

Clearance Spaces

NEC110.26 defines the clearances around electrical equipment that must be serviced when energized. Such equipment might include the PV dc disconnect, the inverter, and any batteries. The six-inch depth allowance in 110.26(A)(3) allows some leeway, but the AHJ will have to evaluate each installation. This is particularly true when the inverter has been placed above the batteries that have been mounted on the floor. The inverter requires clear space from floor to 6 1/2 ft and the batteries may stick out 6 in. in front of the inverter. Also, the batteries need the same clear space, but since the inverter usually has less depth than the batteries, it will not be an issue.

Some inverters have access requirements from the sides and this may pose additional space requirements. Also, the 90° opening requirements for doors and access panels may dictate additional space.

Summary

With the use of exterior or interior conduit runs and the use of surface mounted inverters and disconnects, it becomes obvious that the materials, techniques, and workmanship requirements for a PV installation are going to resemble more closely a commercial electrical installation than a residential one. With PV modules generating dangerous amounts of electrical energy for 40 years or more, it behooves every one working with PV systems, from the designer to the inspector, to do everything possible to achieve the highest standards of workmanship.

For Additional Information

If this article has raised questions, do not hesitate to contact the author by phone or e-mail. E-mail:jwiles@nmsu.eduPhone: 505-646-6105

Here is a link to the National Electrical Contractors Association web site. They sell ANSI/NECA 1-2006, Good Workmanship in Electrical Contracting:http://www.necanet.org/store/index.cfm?fuseaction=search_results&index_number=NECA1-06. A color copy of the 143-page, 2005 edition of the Photovoltaic Power Systems and the National Electrical Code: Suggested Practices, published by Sandia National Laboratories and written by the author, may be downloaded from this web site: http://www.nmsu.edu/~tdi/Photovoltaics/Codes-Stds/PVnecSugPact.html.

The Southwest Technology Development Institute web site maintains a PV Systems Inspector/Installer Checklist and all copies of the previous "Perspectives on PV” articles for easy downloading. Copies of "Code Corner ” written by the author and published in Home Power Magazine over the last 10 years are also available on this web site: http://www.nmsu.edu/~tdi/Photovoltaics/Codes-Stds/Codes-Stds.html.

Proposals for the 2008 NEC that were submitted by the PV Industry Forum may be downloaded from this web site:
http://www.nmsu.edu/~tdi/pdf-resources/2008NECproposals2.pdf.

The author makes 6–8 hour presentations on "PV Systems and the NEC” to groups of 40 or more inspectors, electricians, electrical contractors, and PV professionals for a very nominal cost on an as-requested basis. A schedule of future presentations can be found on the SWTDI web site.


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Penetrating PV Questions from Inspectors

Posted By John Wiles, Friday, September 01, 2006
Updated: Tuesday, January 22, 2013

Based on this series of articles and presentations that I make to groups of inspectors around the country, I get several calls and e-mails a week and sometimes several calls a day from inspectors looking at PV plans or inspecting PV systems. The questions that they pose are always challenging because most of the inspectors have done their homework and found the Code lacking in clear concise answers. I usually gain new insights on the Code from these calls. Here are some of the more common questions and the best answers that I have. I encourage these calls so that everyone involved can help to ensure that the numerous PV systems being installed are as safe as possible.

Location of main dc PV disconnect

Question: Where should the main dc PV disconnect be located? NEC Section 690.14 says either inside or outside at the point of first penetration of the PV source or output conductors in a readily accessible location. Is there a preference between inside and outside locations?

Answer: The dc PV disconnect resembles the ac service-entrance disconnect in function, although it is not required to be rated as service-entrance equipment. The location of this dc PV disconnect should take into account the local requirements for locating the ac service


Photo 1. DC PV disconnect grouped with ac service disconnect

disconnect since they more than likely take into account emergency response requirements. If the ac service disconnect for the house or structure is outside, it seems reasonable to put the dc PV disconnect outside in the same vicinity. In a similar manner, an inside ac service disconnect would seem to point to an inside location for the dc PV disconnect. Both ac and PV disconnects should be "grouped” (as defined by the AHJ) since they both shut off power to the building (see photo 1). In a few cases it has been argued that the PV system is a second supply to the house and may have the main dc PV disconnect remotely located from the ac service disconnect if all disconnects are properly placarded.

Many jurisdictions allow an inside ac service disconnect, although a locked house may not be readily accessible. If an inside disconnect is allowed, then many locations for the dc PV disconnect are possible including on the exterior wall of an upstairs bedroom for example. Some installers would like to put the disconnect in an attic to eliminate the wiring on the outside of the building, but an attic would not be considered readily accessible unless permanent, fixed stairs were available to the attic.

Location of ac PV disconnect

Question: Where should the ac PV disconnect be located?

Answer: In the smaller residential systems, the ac PV disconnect is usually a backfed breaker in the load ac center and, if the inverter is close to the load center containing the backfed breaker,


Photo 2. AC and dc disconnects grouped at the inverter

no additional ac disconnect is required. The ac circuit between the inverter and the load center is very similar to any ac branch circuit. If there is some distance between the inverter and the backfed breaker, then an additional disconnect should be located at the inverter to allow safe servicing of that product (see photo 2). The AHJ determines how far apart the inverter and the disconnect may be. Some require a spread-arms’ distance between the ac and dc disconnects at the inverter, and other AHJs allow the disconnect to be some distance apart as long as they are both visible from the inverter.

Inverters with internal ac and/or dc disconnects

Question: I am seeing inverters with ac and dc or just dc disconnects built into them. Do these inverters meet code requirements when installed without external ac and dc disconnects?

Answer: The NEC provides little guidance in this area. The inverters have been listed to UL


Photo 3. Internal ac and dc disconnects

Standard 1741 and are considered to be safe in operation. They do have the internal disconnects that allow the unqualified user to safely turn them on and off during normal operations (see photo 3). The AHJ or the jurisdiction should decide on the safety requirements for servicing these electronic devices. Section 690.18 suggests that the PV array be covered before servicing the system and that blocking the light from the modules would de-energize the output circuits if done properly. However, on large roof-mounted arrays, covering the entire array is not a common or easy practice. If the AHJ or jurisdiction judges that qualified people are going to be disconnecting those energized dc input conductors from the PV array in the inverter, then the internal disconnect is probably OK. However, if there is a possibility that the inverter will be removed for service by unqualified people, they probably should not be handling those energized PV input conductors, and at least an external dc disconnect should be required (see photo 4). Hopefully, anyone servicing one of these inverters would know enough to open the backfed ac breaker to remove ac power from the inverter before disconnecting the ac circuits.

Several older inverters (out of production) and some newer inverters have an electronics section that can be removed for service from a lower input/output circuit section. The AHJ should evaluate the difficulty of the removal process. Some units can require that energized conductors be pulled through conduit knockouts. The input/output power section remaining attached to the wall should be examined to ensure that it is safe for contact by unqualified people and that it is somewhat weather resistant if the inverter is mounted outside. If these conditions are not met, the AHJ might consider requiring external disconnects.

Location of manual disconnect

Question: The local utility requires a manual safety switch (disconnect) between the inverter and the utility point of connection. What are the Code requirements pertaining to the installation of this disconnect?

Answer: This safety switch is a common requirement imposed by many, but not all, utilities. The utility wants to ensure that there is no possibility of a PV system "islanding” and energizing a feeder that a lineman has disconnected from the utility. The listed, utility-interactive inverter will sense a turned off grid and shut down. This automatic action plus the lineman’s safety procedures of measuring, shorting, and grounding the line to be serviced plus wearing protective gear are sufficient to allow some utilities to not require the safety switch. Other utilities will require the safety switch and will dictate its location—usually near the utility meter. However, this safety switch is being installed on the premises wiring and must follow the general Code requirements as far as rating, conductors, wiring methods, grounding, height, and clearances. In this position on the dedicated branch circuit serving the PV inverter, the safety switch would not have to be rated as service-entrance equipment.

 


Photo 4. Internal and external dc disconnects

 

If the inverter is adjacent to the utility-required disconnect on the outside of the house, in many cases, it can also be used as the inverter ac disconnect. In a situation where the PV utility connection is made on the supply side of the service disconnect, this utility-required disconnect may also serve as the PV ac inverter disconnect if it were rated as service-entrance equipment.

Aluminum lay-in lugs

Question: I have a PV system where aluminum lay-in lugs have been attached to the narrow sides of the modules for equipment grounding. These modules are marked for grounding points only on the long side of the modules. Does this comply with the Code?

Answer: There will be a couple of things that the installer must verify. First, aluminum lay-in


Photo 5. Dry-location lug rusting outdoors

lugs are generally not listed for outdoor/wet applications because the setscrew is typically plated steel and will rust quickly (see photo 5). The correct lay-in lug for these applications is a tin-plated, solid-copper lug that has a stainless-steel screw (see photo 6). These lugs are listed for underground, direct-burial applications and have been found to be suitable for wet/outdoor applications. While they are not listed for use with aluminum conductors, the tin plating allows them to be bolted to aluminum surfaces (like aluminum bus bars and aluminum module frames). The aluminum module frame should be scraped to remove the invisible oxidation and an anti-oxidation compound like Burndy PENETROX A-13 should be applied between the lug and the aluminum module frame at the contact point. A solid-copper lug without the tin plating should not be used since copper should not come into contact with aluminum (see photo 7). Drilling the module on the short side away from the marked grounding points may violate both the listing and the warranty on the module. The module manufacturer should be contacted before any modification of the module is undertaken that deviates from the instructions supplied with the module or the markings on the module.


Photo 6. Direct burial lug with stainless-steel screw

Unbalanced PV array and inverter ratings

Question: I have a PV system where the PV array is rated at 3000 watts, but the inverter connected to the array is rated at only 2500 watts. Won’t this arrangement damage the inverter, make the system unsafe, and be non-code-compliant?

Answer: The rating (3000 watts in this case) of a PV array is normally expressed at a set of standard test conditions (STC) of 1000 watts per square meter of irradiance (sunlight intensity) and a module temperature of 25°C (77°F). These laboratory test conditions are infrequently met in the installed PV array. At an outdoor temperature of 35°C (95°F), the PV modules will be operating at a temperature of about 65°C (149°F) and the array will only be putting out about 2350 watts when the irradiance is 1000 watts per square meter. The lower power output is due to the fact that PV modules lose


Photo 7. Copper direct burial lug, not suited for aluminum contact

power at the rate of about 0.5 percent per degree Centigrade as the temperature increases. At lower temperatures, higher power levels from the array can be expected, but the inverter simply limits the input current from the array and/or the output power to the utility grid to keep the output from exceeding the inverter rated power. Sizing the array slightly larger than the inverter rating is normal and allows more energy to be delivered to the grid during hot sunny days and during cloudy periods. The inverter protects itself; there is no safety issue, and no Code violation.

For Additional Information

If this article has raised questions, do not hesitate to contact the author by phone or e-mail. E-mail: jwiles@nmsu.edu Phone: 505-646-6105

A color copy of the 143-page, 2005 edition of the Photovoltaic Power Systems and the National Electrical Code: Suggested Practices, published by Sandia National Laboratories and written by the author, may be downloaded from this web site: (http://www.nmsu.edu/~tdi/roswell-8opt.pdf.) The Southwest Technology Development Institute web site (http://www.nmsu.edu/~tdi/Photovoltaics/Codes-Stds/Codes-Stds.html) maintains a PV Systems Inspector/Installer Checklist and all copies of the previous "Perspectives on PV” articles for easy downloading. Copies of "Code Corner,” written by the author and published in Home Power Magazine over the last 10 years, are also available on this web site.

Proposals for the 2008 NEC that were submitted by the PV Industry Forum may be downloaded from this web site:
http://www.nmsu.edu/~tdi/pdf-resources/2008NECproposals2.pdf

The author makes 6–8 hour presentations on "PV Systems and the NEC” to groups of 40 or more inspectors, electricians, electrical contractors, and PV professionals for a very nominal cost on an as-requested basis. A schedule of future presentations can be found on the SWTDI web site.


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Tags:  Featured  Perspectives on PV  September-October 2006 

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Achieving The Art of The Possible

Posted By John Wiles, Saturday, July 01, 2006
Updated: Tuesday, January 22, 2013

Those who have been following this series of articles for the last year or so may wonder what is involved in designing and installing a code-compliant, durable, reliable, and cost-effective PV system. Utility-interactive photovoltaic (PV) power systems are a mature technology. PV modules have warranties to 25 years and are predicted to produce significant amounts of power for 30 years or more. Inverters have warranties to 10 years and estimated life spans of 15 years or more with even greater longevity predicted in the future. PV systems can be designed and installed following existing guidelines and codes that will achieve long life, durable service, excellent safety, and cost effective power production. However, it is evident that great numbers of systems being installed today will not achieve the art of the possible because of poor design and installation practices. This article will address some of the steps that the PV systems vendor/designer/installer must accomplish to achieve a safe, durable, reliable, and cost-effective system.


Photo 1

The Equipment and the Design

PV systems can be designed and installed in a manner that will yield high levels of performance over the life of the PV modules, which is expected to be more than 30 years. Yes, inverters will have to be repaired or replaced during that time, but advances in inverter designs are driving their lifetimes ever longer. As in other fields, the quality of the products may vary and nearly all manufacturers have production problems from time to time. In most cases, the defective products are repaired or replaced under warranty and the properly designed and installed system will have a long and productive life.


Photo 2

The design of a system involves some complicated steps and details, a few of which have been outlined in previous "Perspectives on PV” articles. A full understanding of how the PV modules respond to the environment is needed. See the "Single Conductor Exposed Cables! Not In My Jurisdiction!” article in the July-August 2004 issue of theIAEI News. The electrical characteristics of the inverter must be matched to the output of the PV array under a wide variety of environmental conditions. The site electrical service must be examined to determine how to best interface the inverter to the utility in a code-compliant manner. See the "Making The Utility Connection” article in the September-October 2005 issue of theIAEI News. A site visit is absolutely necessary before any design can be completed.

The Site Visit

It is imperative that each site be visited to determine a number of critical design parameters. The proposed PV array location must be examined for available space, shading (now and in the future as the trees grow), and orientation (see photo 1). Special tools are available to the PV installer for predicting the impact of shading during each month of the year. Restrictive covenants frequently prohibit the installation of PV arrays on roof planes facing the desired direction. In some extreme cases, these covenants may prohibit any PV system from being installed on the roof. No one wants to cut down the 200-year old oak tree just south of the proposed PV array location. For the common roof-mounted systems, the structure of the roof must be examined not only for attachment methods, but also for structural loading. The location of the existing utility service entrance and the existing load center coupled with the proposed array location will determine where the inverter can be located. All dimensions must be recorded, as they will affect both the mechanical and electrical design. Access to the area where the PV array is to be located must be mapped out.

The Mechanical Design

The geographical location of the PV array will determine the environmental conditions (wind, snow, ice) that will strongly affect the mounting of the PV array. Both the array-to-rack and rack-to-roof or rack-to-ground mounting systems must be addressed in all areas. Structural loading may be positive (dead weight) or negative (wind uplift). High winds, particularly in coastal areas, and earthquakes will significantly impact the mechanical design. Lowered PV output from non-optimum orientations or shading may necessitate larger arrays if a certain output is required. Roofing materials from asphalt shingles, to metal roofs, to tile roofs must be penetrated without damage and then the penetrations effectively sealed against wind and water for the life of the system (see photo 2). Provisions should be made to allow easy removal of the PV array if the roof needs repair at some future date.

Routing of conduits and electrical wiring must be planned in advance. Codes generally require that the power conduits from the PV array remain outside the building shell until a readily accessible disconnect is reached. In some cases, metal conduits are allowed to penetrate the shell before reaching that first disconnect.

Nearly all roof structures in recent yea rs have either been designed by professional engineers (via software used by truss manufacturers) or by the installer strictly complying with the applicable building codes. Attaching any structure to these roofs that would affect either the dead weight or the live load should be preceded by an analysis of the possible effects on the roof.

An iterative process between the mechanical and electrical design is usually required. This is especially true when the site assessment does not permit an optimally sized (smallest) PV array.

The Electrical Design

The desired ac output, the available solar resource, the efficiency of the PV modules, the efficiency of the PV inverter, and the array orientation as well as any shading should be included in designing the system. After the system is sized, application of the requirements in theNational Electrical Code(NEC) and any local codes will determine the balance of systems (BOS) components such as conductor types and sizes, disconnects, and overcurrent protection. To some extent, these items are driven by the installation location (ground or roof) and the design of the inverter (internal disconnects). However, the local electrical inspector may apply local preferences/codes to some of these items. For example, external (rather than internal) disconnects for the inverter and an outside main PV disconnect may be required. Because the rules established by the NEC are numerous and complex, a PV design should only be attempted by someone fully familiar with theCodein the areas of residential and commercial electrical systems.

Coordination and Permitting

After the code-compliant design is completed (both electrical and mechanical), the PV system designer should coordinate with the building officials responsible for permitting and inspecting the system. The PV system design, at this stage, should be presented to the inspectors including as much appropriate documentation as possible. See the "PV Plan Check” article in the March-April 2006 IAEI News. The documentation should include all calculations used to ensure code compliance as well as specifications/cut sheets for each product being used. The inspectors may have their own interpretations of the code requirements of a PV system. Their comments should be integrated into the design, where possible and appropriate, before any hardware is purchased or installed. Conflicts between the requirements of the inspector and the designed system should be resolved at this point. Permits, both electrical and mechanical, should be obtained. In some cases, professional engineering approval must be obtained. Such approvals usually apply to commercial installations and, in some cases, to residential installations where roof loading is questioned.

Installation and Workmanship

PV modules will be generating hazardous amounts of power (voltage and possibly current) for the next 30 years or more even when inverters fail and are not repaired or replaced. These hazardous voltages must be well contained for that time in the face of severe outdoor environmental conditions. Daily sunlight (ultra violet radiation) over long periods of time, coupled with high temperatures (80°C +), make the use of the best materials and installation techniques mandatory. Residential PV installations typically resemble commercial electrical installations (with substantial use of conduit) more than they resemble residential electrical installations. The details of properly installing a high-quality, safe, durable PV system at the nuts-and-bolts level is a task best left to the electrician who has years of practical experience installing (but possibly not designing) electrical power systems (see photo 3).


 

Photo 3


Photo 4

 

Education, Training, and Experience Are the Keys

There is no "cookbook” for PV system design and installation. While a number of helpful written guides have been developed, none of them are, or can ever be, all inclusive; none of them will be able to teach the hands-on skills required; and none of them can imbue the installer with the years of experience required to learn the tricks of the trade. The needed hands-on details are not usually found in written guides, although some of the do-it-yourself manuals on electrical wiring try to provide instruction in these areas. Hands-on training given by various organizations is important and everyone involved in PV design and installation should avail themselves of every training opportunity. Most PV equipment manufacturers offer short (1–3 day) training sessions for people using their equipment (see photos 4 and 5).


Photo 5


Photo 6

Anyone involved in PV system design and installation must have a personal library (well-read and absorbed). That library should include as a minimum, the latest versions of the following:

  • National Electrical Code Handbook
  • Local electrical codes
  • Factory manuals for all products being installed
  • Manuals for related products (each manual has a few unique tips and techniques),
  • Guides

– The author’s PV/NEC suggested practices manual
– The North American Board of Certified Energy Practitioners (NABCEP) Study Guide (www.NABCEP.org)
– A set of this IAEI News series of articles, "Perspectives on PV.”

Because most PV systems are more complex than the typical residential electrical system, and the environment is more extreme (roof tops), the experienced electrician has the best experience base for installing these systems. In all cases, no PV installations should be attempted without significant experience in the electrical trades.

The Team

A team consisting of a competent PV systems designer working with an electrician using the best available equipment from the component manufacturers and the best available guidance on PV installations can design and install a safe, durable, and cost-effective PV system. The views and comments of the electrical inspectors (and any other building inspector) should be solicited and followed at the design stage (see photo 6). The system should be installed using only the highest quality balance of systems components with the highest standards of workmanship—typically commercial electrical system levels of craftsmanship. Full compliance with the requirements of theNational Electrical Codeand any local codes is an absolute minimum. The electrical inspector is a key player as that person verifies the safety of the completed installation. Close coordination, even teamwork, among the PV systems designer, the PV installer, and the electrical inspector will be required on nearly every PV installation if the art of the possible is to be achieved.

For Additional Information

If this article has raised questions, do not hesitate to contact the author by phone or e-mail. E-mail: jwiles@nmsu.edu Phone: 505-646-6105

A color copy of the 143-page, 2005 edition of the Photovoltaic Power Systems and the National Electrical Code: Suggested Practices, published by Sandia National Laboratories and written by the author, may be downloaded from this web site: (http://www.nmsu.edu/~tdi/roswell-8opt.pdf.) The Southwest Technology Development Institute web site (http://www.nmsu.edu/~tdi) maintains a PV Systems Inspector/Installer Checklist and all copies of the previous "Perspectives on PV” articles for easy downloading. Copies of "Code Corner” written by the author and published in Home Power Magazine over the last 10 years are also available on this web site.

Proposals for the 2008 NEC that were submitted by the PV Industry Forum may be downloaded from this web site:
http://www.nmsu.edu/~tdi/pdf-resources/2008NECproposals2.pdf

The author makes 6–8 hour presentations on "PV Systems and the NEC” to groups of 40 or more inspectors, electricians, electrical contractors, and PV professionals for a very nominal cost on an as-requested basis. A schedule of future presentations can be found on the SWTDI web site.


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Tags:  Featured  July-August 2006  Perspectives on PV 

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The 15-minute PV System Inspection. Can You? Should You?

Posted By John Wiles, Monday, May 01, 2006
Updated: Tuesday, January 22, 2013

As I make presentations on photovoltaic power systems and the National Electrical Code around the country, I frequently talk to inspectors who have as little as 15 minutes to make a residential electrical inspection. A common question is, "Can I inspect a residential PV system in 15 minutes?” This article will examine that question and also take up the question, "Should only 15 minutes be allocated for inspecting a residential PV system?”

Photo 1. Improperly wired 240-volt inverter; neutral wired to PE terminal

Let’s start with an ideal situation. The inspector is familiar with PV systems in general and has inspected quite a few. He or she receives an application for a permit for a PV system, and that application is accompanied by all of the material outlined in the "PV Plan Check” article in IAEI News, March/April 2006. A review of the supplied material shows no major problems in code compliance, and the installer quickly rectifies the few minor problem areas found. A team consisting of a PV vendor with a history of good PV installations and an electrical contractor/electrician who has a commercial electrical license and some PV experience has done the design of the system and the installation.

Here are some of the items that an inspector should verify during the site visit. They are listed in order of importance and in order of safety for the inspector. For a more complete list, see "Perspectives on PV,” in IAEI News, May/June 2005.

Grounding and Bonding

Proper grounding of the PV system is extremely important because the PV modules will be generating hazardous amounts of energy for the next fifty years or more. Proper grounding is the first, the last, and most important area (in my mind) that requires code compliance in a PV system. Proper grounding of all exposed metal surfaces that may become energized as the system ages or as accidents happen will provide the highest levels of protection against shock and fires. Proper grounding will also facilitate the action of the ground-fault detection system that most of these systems will have. As the inspector moves through the PV system, grounding will be a critical inspection item in several locations.
 

Photo 2. Inverter with three DC inputs

Many residential PV systems (6 kW and below) have all of the PV equipment, both ac and dc, grounded by a single equipment grounding conductor connected from the modules to the grounding bus bar in the residential ac load center. The module frames, the PV array mounting rack, the dc disconnect, the inverter, and the one or more ac disconnects are all grounded by the single equipment grounding conductor routed to the ac load center. The first item a careful inspector should verify is that the equipment grounding conductor from the PV system inverter has been connected properly in the ac load center grounding bus bar and that the ac load center has a proper connection to ground (earthed). If this equipment grounding has not been done properly, a ground fault in the PV array or elsewhere in the system may put several hundred volts on the ungrounded exposed metal surfaces of any PV equipment.

As PV systems mature and UL standards and the Code evolve, it is hoped that the grounding of PV systems will become more robust. Even now, some systems will be installed with a dc grounding electrode conductor connected to a dc grounding electrode or to the ac grounding electrode.

If the backs of the PV modules can be closely observed, proper grounding of the modules should be checked. The use of the hardware and instructions supplied by the module manufacturer should have been followed as shown in the instruction manual that was delivered, hopefully, with the permit request. See "Perspectives on PV” in the September/October 2004 issue of the IAEI News for more details on grounding PV systems.

AC Point of Connection to the Utility

While the residential ac load center is open to check the grounding connection, the value of the backfed PV circuit breaker can be noted. It should match the value on the permit application and not be generally greater than 20% of the load center rating. This assumes that the main breaker and the load center have the same rating [see NEC 690.64]. This requirement limits the backfed PV breaker to a maximum of 20 amps on a 100-amp load center and to a maximum of 40 amps on a 200-amp panel. Breakers larger than this indicate that the utility connection should have been made on the supply side of the service disconnect. See "Perspectives on PV” in the January/February 2005 issue of the IAEI News for supply-side connection requirements.

Inverters

The inverter should be opened to check the field-installed connections. Some inverters will require metric hex socket drivers (or Allen wrenches) to open. One manufacturer makes a sealed inverter with permanently attached cables for connections to the adjacent ac and dc disconnects.

Inverters with a 120-volt output should have line, neutral (grounded), and equipment grounding conductors between the load center and the inverter. Inverters made outside the U.S. may have the equipment grounding terminals marked PE for "Protective Earth.” Some 240-volt inverters have only line 1, line 2, and equipment grounding conductors with no neutral (grounded) conductor, while others will have line 1, line 2, neutral, and equipment grounding conductors. The inverter manual (submitted with the permit request) will show the proper connections. Inverters requiring no neutral connection must not have the neutral conductor attached to anything, particularly an equipment grounding terminal, because such a connection would establish a connection between ground and the neutral conductor that is prohibited by NEC Section 250.6 and 250.24(A)(5).

The dc input connections to the inverter may include one or more sets of positive and negative conductors as well as at least one dc equipment grounding conductor routed to either an external dc disconnect or to the PV array (see photo 2).

AC and DC Disconnects

Each disconnect should be properly grounded. Following and verifying the equipment grounding conductors backwards from the ac load center through the system to the PV modules is important to ensure that each exposed metal surface that may be energized is grounded. Grounding using sheet metal screws is prohibited by the Code and the use of "tech screws” and aluminum lugs is questionable (photo 3). Most listed fused disconnects and circuit breaker enclosures have ground-bar kits with specific mounting instructions and locations that should be used to maintain the listings of the devices and to provide the highest quality grounding connection (photo 4).
 

Photo 3. Improperly grounded dc disconnect; violates 250.8, 110.3(3), 250.96(A), and 250.4(A)(5)
 

Photo 4. Properly installed, listed ground bar kit

While the dc PV disconnect enclosure is opened, the color coding of the conductors should be checked. Most current PV systems use a negative ground and the negative conductor should be colored white and should not be switched or fused by the disconnect. There are a few positive grounded PV systems being installed, and in this case, the positive conductor is now colored white and is not switched. Section 690.35 of NEC-2005 permits the use of ungrounded systems (neither of the circuit conductors is grounded) and these will be showing up. These ungrounded systems must meet several additional requirements including switching both of the ungrounded circuit conductors with neither conductor colored white [see NEC 690.35]. The inverter or the system should be clearly marked (not yet a Code requirement) showing the type of grounding (negative ground, positive ground, or ungrounded) to allow easy determination of the proper color codes.


Table 1. Typical DC Wiring Conductor Colors

There is no specified color code for the ungrounded conductors, and any color is permitted as long as gray white, green, and green and yellow are not used. Typical conductor insulations are shown in table 1.

Both circuit conductors (positive and negative) should be routed through the disconnect enclosure even though only the ungrounded conductor is switched. Avoiding a "switch loop” configuration ensures that both circuit conductors are always in close proximity for best functioning of overcurrent devices and to allow a bolted connection point for the grounded conductor on an isolated "neutral bus” in the enclosure, if required.

In the dc PV disconnect, the always "hot” conductors from the PV array wiring should be connected to the top (covered) "Line,” terminals on the switch while the lower, exposed, "Load” terminals should be connected to the inverter. On the ac disconnect, the upper "Line” terminals should be connected to the utility power conductors that come from the backfed ac load center. The lower "Load” terminals should be connected to the inverter.

Workmanship and the Roof

The equipment used and the workmanship on most residential PV systems will more closely resemble the equipment and workmanship on a commercial electrical installation than those items in a residential electrical system. There will usually be surface-mounted disconnects and much of the wiring will be in exposed, surface-mounted conduit.


Photo 5. Module wiring properly secured

The installer should have a ladder on site the day of the inspection to facilitate examining the installed PV array. A quick look at the PV array on the roof should verify that any exposed wiring is firmly secured to the PV modules or the mounting structure and is not dangling down where it would be subject to physical damage (photo 5).

If the backs of the PV modules can be closely observed, proper grounding of the modules should be checked. The hardware supplied by the module manufacturer should have been used as shown in the instruction manual delivered with the permit application. Each PV module must be grounded, and if exposed, single conductor cables touch the mounting racks or a metal roof, those objects should also be grounded. See "Perspectives on PV” in the September/October 2004 issue of the IAEI News for more details on grounding PV systems.

The conductors used for module interconnections should be as specified in the permit application with respect to size (AWG), insulation type, and temperature rating. Any PV combiners containing overcurrent devices exposed to sunlight should be noted and the plans and technical data reviewed to determine if adequate temperature deratings were applied. Conduits in sunlight will also be exposed to higher-than-ambient temperatures.

Inspect in 15 Minutes?

Yes, it might be possible to perform the above inspections in 15 minutes if the inspector has spent some time at the plan-check stage and is experienced in PV systems employing this inverter and the installer is there to answer questions, open the inverter and other equipment as necessary and to provide a ladder for roof access. However, any problems found in the above areas should warrant a closer look at the entire system; and when more details are examined, the inspection time can grow. A lack of familiarity with either PV in general, the equipment being installed, or the installer would normally dictate that the inspection take more time. How much? Some residential PV inspections for new inspectors are somewhat of a training session and with a knowledgeable installer, examining and discussing all of the details relating to a durable, safe (for 50 years) installation might take two or more hours.

Should We Do 15-Minute Inspections?

See the little girl in the lead-in photo? That PV system she is touching will still be producing power when her grandchildren are her age. It will take more than a 15-minute inspection to ensure that the PV system will be as safe then as it is now. Fifteen minutes is probably insufficient time to ensure the public safety over a 40–50 year period.

For Additional Information

If this article has raised questions, do not hesitate to contact the author by phone or e-mail. E-mail: jwiles@nmsu.edu Phone: 505-646-6105

A color copy of the 143-page, 2005 edition of the Photovoltaic Power Systems and the National Electrical Code: Suggested Practices, published by Sandia National Laboratories and written by the author, may be downloaded from this web site: (http://www.nmsu.edu/~tdi/roswell-8opt.pdf.) The Southwest Technology Development Institute web sitehttp://www.nmsu.edu/~tdimaintains a PV Systems Inspector/Installer Checklist and all copies of the previous "Perspectives on PV” articles for easy downloading. Copies of "Code Corner” written by the author and published in Home Power Magazine over the last 10 years are also available on this web site.

Proposals for the 2008 NEC that were submitted by the PV Industry Forum may be downloaded from this web site: http://www.nmsu.edu/~tdi/pdf-resources/2008NECproposals2.pdf

The author makes 6–8 hour presentations on "PV Systems and the NEC” to groups of 40 or more inspectors, electricians, electrical contractors, and PV professionals for a very nominal cost on an as-requested basis. A schedule of future presentations can be found on the SWTDI web site.


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PV Plan Check

Posted By John Wiles, Wednesday, March 01, 2006
Updated: Tuesday, January 22, 2013

Electrical inspectors and electrical permitting personnel are seeing increasing numbers of photovoltaic (PV) power systems, both at the permitting stage and at the initial inspection. Both processes go much more smoothly for all concerned when the electrical system is properly documented. Since the typical PV installer has not installed hundreds of the same PV system, and the inspector has not seen hundreds of these systems, the documentation for these systems must, by necessity, be somewhat more detailed than the documentation associated with a typical residential electrical system. This article will examine a typical residential, utility-interactive PV system in terms of a package that should be submitted by the installer when applying for a permit or discussing the system with the inspector prior to installation. Installers can use this material to develop the package.

The Single-Line Diagram

A one-line diagram such as shown in figure 1 should accompany the permit application. Actually, since the details of disconnects and grounding are not familiar to all involved, a three-line diagram would be even better as shown in figure 2. While a formal CAD-generated diagram on 24″ x 36″ paper is not generally required, something better than a back-of-the-envelope sketch should be presented. The circled letters in the figures will be referenced below to indicate information that should appear on or be attached to the plan.


Figure 1. One-line PV system diagram

 


Figure 2. Three-line PV system diagram

Equipment Lists and Specifications

A list of the equipment used and the specifications for that equipment should be included with the permit. This list would include the PV-specific equipment such as the PV modules, the inverter, the fuses, and circuit breakers. Listing/certification and rating information must be included. The specifications of this equipment are necessary to determine if the conductors have been properly sized and that the fuses and circuit breakers used in the dc portions of the system are properly rated. Factory cut sheets or pages from instruction manuals are the preferred way to present this information.

The System

On the one- and three-line diagrams, the following information should be indicated, or that information should be attached.

A. PV Array

A.1. The type and number of PV modules in each series string should be indicated. The open-circuit voltage (Voc) of each module, times the number of modules connected in series, times a cold temperature factor (690.7) equals the maximum systems voltage and must be less than the maximum direct current (dc) input voltage of the inverter and less than the voltage rating of connected equipment (wires, overcurrent devices, disconnects). A label on the back of each module as shown in photo 1 will give the electrical parameters needed for the code-required calculations.


Photo 1. PV module label showing electrical ratings

A.2. The ampacity of module interconnection cables, after corrections for conditions of use, must not be less than 1.56 times module short-circuit current (Isc) marked on the back of the module. Due to the exposed, outdoor location and high operating temperatures, all conductors should have insulation rated for 90°C and wet conditions (in conduit, THHN/THWN-2 or RHW-2). Exposed conductors (usually USE-2) must also be sunlight resistant.

B. Conduits
B.1. Conduits will typically be used throughout the system and specifically after the wiring leaves the PV array. They will be installed in various locations, some of which may be in sunlight. [See NEC-2005, 310.10 Exception No. 2]. Conduit fill and conductor ampacity calculations for conduit fill and temperature calculations should be included.

B.2. The PV source circuit or PV output conductors must remain outside the structure until they reach the readily accessible PV dc disconnect switch unless the conductors are installed in a metallic raceway [690.14, 690.31(E)].


Photo 2. DC PV disconnect with required marking

C. Module and String Overcurrent Protection and PV DC Disconnect
C.1. Overcurrent protective devices (OCPD) in dc circuits may not be required when there are only one or two strings of modules. Three or more strings of modules typically require an OCPD in each string. The current rating of the OCPD, when required, should be 1.56 Isc for that circuit [690.8, 690.9]. The voltage rating of the OCPD should be not less than the maximum PV systems voltage found in A.1. The strings may be combined in parallel in a combiner box ahead of an unfused dc PV disconnect or combined at the output of the dc PV disconnect (figure 1 and photo 2). Appendix J in PV Power Systems and the National Electrical Code: Suggested Practices by the author has detailed calculations on the requirements for OCPD in the dc PV array circuits [see Additional Information below]. Any OCPD connected in series with a module or string of modules should not have a value greater than the maximum series fuse value marked on the back of the module (photo 1).

C.2. The PV array output should be connected to the top or line side of the main dc PV disconnect. The circuit to the inverter dc input should be connected to the bottom or load side of the disconnect. The grounded PV output conductor (usually the negative conductor) must not be switched by the disconnect, and this grounded conductor must be color-coded white. Some recent PV systems have a positive conductor that is the grounded conductor; it will be color-coded white, it will not be switched, and in this case, the ungrounded negative conductor will be connected to the switch pole. Future PV systems may not have any grounded PV array circuit conductors and then both PV output conductors would be switched and neither would be color-coded white [690.35].

C.3. PV output conductors, after any combining of series strings, should have an ampacity, after corrections for conditions of use, of not less than 1.56 times the module Isc times the number of strings in parallel.

D. The Inverter
D.1. The inverter must be listed for utility-interactive (U-I) use [690.60].

D.2. The inverter maximum input voltage must not be exceeded in cold weather [110.3(B)]. See A.1.

D.3. For PV systems with the modules mounted on the roofs of dwellings, the inverter must have a 690.5 ground-fault protection device (GFPD). When a GFPD is built in to the inverter (most U-I inverters below 10 kW), there should be no external (to the inverter) bond between the grounded circuit conductor and the grounding system.

D.4. In addition to ac and dc equipment grounding conductors, the inverter must also have a provision for a dc grounding electrode conductor, and that conductor must be properly connected to the grounding system (690.47). This requirement is not clearly spelled out in the Code and many U-I inverters meet the dc grounding requirements by using the ac equipment grounding conductor. The dotted lines in figure 2 show alternate routing and bonding for the dc grounding electrode conductors. See the July-August 2005 IAEI News "Perspectives on PV” article for details.


Photo 3. Inverter with internal ac and dc disconnects

D.5. AC and/or dc disconnects internal to the inverter are acceptable if they are readily accessible and the AHJ judges that only qualified people will service the inverter (photo 3). Otherwise, external disconnects will be needed (photo 4). Internal disconnects, if circuit breakers, may not be suitably rated for the ampacity of PV output conductors (the rating may be too high) and external OCPD may be needed.

E. Inverter AC Output Overcurrent Device and Disconnect
E.1. Any OCPD located in the inverter ac output should be rated at 1.25 times the maximum continuous output current of the inverter. The maximum continuous current is specified in the inverter manual or is calculated by dividing the inverter rated output power by the nominal ac line voltage. This OCPD may be a backfed breaker located in the dwelling load center, the place where any possible fault currents for the inverter ac output conductor would originate. A backfed breaker in the dwelling load center could also be the inverter ac disconnect if the inverter were located near the load center.


Photo 4. Inverter with external ac and dc disconnects

E.2. The inverter ac disconnect should be "grouped” with the dc inverter disconnect and both should be "near” the inverter. The AHJ determines the meaning of "grouped” and "near.” Most systems use the PV disconnect (see B.2.) as the dc inverter disconnect, but if the PV dc disconnect is on the outside of the building and the inverter is on the inside, a second dc inverter disconnect may be required inside the building at the inverter location. The same thing would apply if the backfed circuit breaker in the building load center was on the outside wall and the inverter was on the inside. A disconnect (usually a circuit breaker) would be required inside the building near the inverter.

E.3. From the above, it becomes obvious that the system diagram should show the physical location of all components.

F. Utility-Required AC Disconnect


Photo 5. Inverter ac disconnect combined with the utility disconnect to the right of the inverter

F.1. Many utilities require a visible-blade, lockable-open disconnect in the ac output circuit of the inverter. This disconnect is usually located within sight of the service entrance meter so that emergency response people can easily find it. The top terminals (line side) of this disconnect should be connected to the circuit that comes from the ac load center since it will usually be energized by utility voltage. The bottom terminals (load side) should be connected to the circuit from the inverter. This disconnect may be fused or unfused depending on the specific requirements of the utility. Photo 5 shows an ac disconnect to the right of the inverter that serves as both the ac inverter disconnect and the utility-required ac PV system disconnect. The utility point of connection is inside the house through a backfed circuit breaker in the load center.

F.2. The utility disconnect must have a minimum current rating of 1.25 times the maximum continuous output current of the inverter [690.8].

G. Point of Connection-Load Center
G.1. Most of the smaller residential PV systems will make the point of connection with the utility through a backfed breaker in the dwelling. NEC Section 690.64(B) establishes the requirements. If the load center is rated at 100 amps and has a 100-amp main breaker, the maximum current from all backfed PV breakers would be 20 amps (either or both phases of the 120/240 panel). A 200-amp load center with a 200-amp main breaker would be limited to 40 amps of backfed breakers. However, many installations have PV systems that are larger than the 100-amp or 200-amp load centers can accommodate. Other combinations are possible as is a supply-side tap of the service entrance conductors. See 690.64 and "Perspectives on PV” in the IAEI News in the September-October 2005 and January-February 2006 issues for more details.

Summary

All of the above information should be included in plans submitted for obtaining a permit for the installation of a PV system. The more information submitted, the easier it will be for the PV system designer/installer to communicate to the inspector/permitting official that the system design and component selection meet the requirements of the NEC. It is far more cost effective to change the design on paper before any hardware is purchased and installed than it would be after the system has been installed. Ready for the inspection? See the checklist and more details in "Perspectives on PV” in the May-June 2005 issue of the IAEI News.

For Additional Information

If this article has raised questions, do not hesitate to contact the author by phone or e-mail. E-mail: jwiles@nmsu.edu Phone: 505-646-6105

A PV Systems Inspector/Installer Checklist will be sent via e-mail to those requesting it. A color copy of the 143-page, 2005 edition of the Photovoltaic Power Systems and the National Electrical Code: Suggested Practices, published by Sandia National Laboratories and written by the author, may be downloaded from this web site: (http://www.nmsu.edu/~tdi/roswell-8opt.pdf.) The Southwest Technology Development web site (http://www.nmsu.edu/~tdi) maintains all copies of the previous "Perspectives on PV” articles. Copies of "Code Corner” written by the author and published in Home Power Magazine over the last 10 years are also available on this web site.
Proposals for the 2008 NEC that were submitted by the PV Industry Forum may be downloaded from this web site: http://www.nmsu.edu/~tdi/pdf-resources/2008NECproposals2.pdf

The author makes 6–8 hour presentations on "PV Systems and the NEC” to groups of 40 or more inspectors, electricians, electrical contractors, and PV professionals for a very nominal cost on an as-requested basis. A schedule of future presentations can be found on the SWTDI web site.


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Back to the Grid, Designing PV Systems for Code Compliance

Posted By John Wiles, Sunday, January 01, 2006
Updated: Tuesday, January 22, 2013

In the September/October 2005 issue of IAEI News, the "Perspectives on PV” article discussed making the utility connection for utility-interactive PV systems. In some of the larger residential PV systems and in many commercial PV systems, the grid connection must be made on the supply side of the service disconnect to comply with the requirements of NEC 690.64. In designing PV systems for code compliance, knowledge of all of the various Code requirements is a must. This article will cover some of these requirements as they apply to a supply-side tap of the service-entrance conductors. PV systems employing supply-side connections should be inspected with these requirements in mind.

Photo 1. Utility-required AC PV system disconnect. Note improper grounding connections

Service-Entrance Conductor Taps for Utility-Interactive Inverter Systems

Section 690.64 of the NEC establishes how and where a utility-interactive PV system may be connected to the utility system. The point of connection may be either on the load side of the service disconnect or the utility (supply) side of the service disconnect. In many cases, the complex requirements for load-side connections established by 690.64(B)(2) make such a connection impractical and dictate that the utility-interactive inverter be connected on the supply side of the service disconnect. Figure 1 shows the basic one-line diagram of a supply-side tap. Here are some, but not all, of the major Code sections that address the requirements for such a connection.

Can a Service-Entrance Conductor be Tapped?

Section 690.64(A) allows a supply (utility) side connection as permitted in 230.82(6).

Section 230.82(6) lists solar photovoltaic equipment as permitted to be connected to the supply side of the service disconnect.

It is evident that the connection of a utility-interactive inverter to the supply side of a service disconnect is essentially connecting a second service-entrance disconnect to the existing service and many, if not all, of the rules for service-entrance equipment must be followed.

Section 240.21(D) allows the service conductors to be tapped and refers to 230.91.

Section 230.91 requires that the service overcurrent device be co-located with the service disconnect. A circuit breaker or a fused disconnect would meet these requirements.

A Frequent Utility Requirement May Also Be Met

When the new PV service disconnect consists of a utility-accessible, visible-break, lockable (open) fused disconnect (safety switch), it may also meet utility requirements for an external PV ac disconnect. While this utility-required switch is not a Code requirement, it is installed on the premises, and the NEC requirements for such an installation must be followed. Photo 1 shows a typical disconnect required by a utility for a 10 kW three-phase PV system. Note that it has been grounded improperly by using lugs and sheet metal screws rather than with the required ground-bar kit listed by the manufacturer.

Section 230.71 specifies that the service disconnecting means for each set of service-entrance conductors shall be a combination of no more than six switches and sets of circuit breakers mounted in a single enclosure or in a group of enclosures. The addition of the photovoltaic equipment disconnect would be one of the six.

Locations and Markings

Section 230.70(A) establishes the location requirements for the service disconnect. Whether the service disconnect is allowed to be inside the building or outside the building is usually governed by the local jurisdiction.
 

Photo 2. Label on ac PV disconnect

Section 705.10 requires that a directory be placed in a central location showing the location of all power sources for a building. Locating the PV service disconnect and the direct-current PV disconnect (690.14) adjacent to or near the existing service disconnect may facilitate the installation, inspection, and operation of the system. See photo 2 for a typical label that is applied to the ac PV Disconnect.

Size and Rating

Section 230.79(D) requires that the disconnect have a minimum rating of 60 amps. This would apply to a service-entrance rated circuit breaker or fused disconnect used to connect the output of the PV system to the utility grid.

Section 230.42 requires that the service-entrance conductors be sized at 125 percent of the continuous loads (all currents in a PV system are considered worst-case continuous currents). The actual rating should be based on 125 percent of the rated output current for the utility-interactive PV inverter as required by 690.8. The disconnect must have a 60-amp minimum rating. This 60-amp minimum requirement would apply even if the inverter rated continuous output current dictated only a 15-amp circuit. Conductor ampacity adjustment factors for temperature and conduit fill may have to be applied.

For a small PV system, say a 2500-watt 240-volt inverter requiring a 15-amp circuit and overcurrent protection, these requirements would require a minimum 60-amp rated disconnect, but 15-amp fuses could be used; fuse adapters would be required. While 15-amp conductors could be used between the inverter and the 15-amp fuses in the disconnect, 230.42(B) requires that the conductors between the service tap and the disconnect be rated not less than the rating of the disconnect; in this case 60 amps.

How we would deal with the minimum 60-amp disconnect requirement and a 15-amp inverter overcurrent requirement using circuit breakers is not straightforward. A circuit breaker rated at 60 amps could serve as a disconnect and it could be connected to a 15-amp circuit breaker to meet the inverter overcurrent device requirements. In this case, the requirements of 690.64(B)(2) should be applied to the ampacities of any conductors involved, because the 15-amp circuit breaker now becomes a load-side connection on the new 60-amp service disconnect.

Interrupt Capability

Section 110.9 requires that the interrupt capability of the equipment be equal to the available fault current. The interrupt rating of the new disconnect/overcurrent device should at least equal the interrupt rating of the existing service equipment. The utility service should be investigated to ensure that the available fault currents have not been increased above the rating of the existing equipment. Fused disconnects with RK-5 fuses are commonly available with interrupt ratings up to 200,000 amps (Photo 1).

Section 230.43 allows a number of different service-entrance wiring systems. However, considering that the tap conductors are unprotected from faults (except by the primary fuse on the utility distribution transformer), it is suggested that the conductors be as short as possible with the new PV service/disconnect mounted adjacent to the tap point. Conductors installed in rigid metal conduit would provide the highest level of fault protection.


Photo 3. Exothermic weld splice in grounding electrode conductor

All equipment must be properly grounded per Article 250 requirements. For example, photo 3, shows an exothermic weld irreversible splice in a grounding electrode conductor.

Additional service-entrance disconnect requirements in Article 230 and requirements in other articles of the NEC will apply to this connection.

Where to Connect?

The actual location of the tap will depend on the configuration and location of the existing service-entrance equipment. The following connection locations have been used on various systems throughout the country.

On the smaller residential and commercial systems, there is sometimes room in the main load center to tap the service conductors just before they are connected to the existing service disconnect. In other installations, the meter socket has lugs that are listed for two conductors per lug. Combined meter/service disconnects/load centers frequently have significant amounts of interior space where the tap can be made between the meter socket and the service disconnect. Of course, adding a new pull box between the meter socket and the service disconnect is always an option.


Figure 1. Supply-side interconnection diagram

In the larger commercial installations, the main service-entrance equipment will frequently have bus bars that have provisions for tap conductors.

In all cases, safe working practices dictate that the utility service be de-energized before any tap connections are made.

Summary

Utility-interactive PV systems can be designed to be safely connected to the supply side of an existing service disconnect. These connections are being made throughout the country on both residential and commercial PV systems.

Back to the Grid, The End of an Era?

There is one long-term downside of installing a PV system on the roof of a building. At some point the roof may have to be repaired.

The conventional wisdom in New Mexico, where the author lives, is that it is a pretty arid state. Average rainfall in the southern end of the state is about 9–10 inches per year, but most of this rain comes in the form of heavy thunderstorms during the July–October rainy season.

This year, the author was unfortunate enough to have downpours of 4.5 inches and 1.5 inches hit his home in two successive weeks. Two significant roof leaks occurred on his 18-year old "flat” roofed home and neither could be located nor fixed, even after significant patching. The house will have to be re-roofed after all of the solar equipment is removed. That solar equipment consists of a large solar hot water collector system and a 4 kW PV system covering most of the roof area. On Tuesday, October 4th, the local utility reinstalled the KWH meter and the house became grid powered after 16 years of off-grid PV operation. The end of an era? No, hopefully, just a temporary, 2–3 month interruption, until the roof is repaired.

For Additional Information

If this article has raised questions, do not hesitate to contact the author by phone or e-mail. E-mail: jwiles@nmsu.edu Phone: 505-646-6105

A PV Systems Inspector/Installer Checklist will be sent via e-mail to those requesting it. A color copy of the 143-page, 2005 edition of the Photovoltaic Power Systems and the National Electrical Code: Suggested Practices, published by Sandia National Laboratories and written by the author, may be downloaded from this web site: (http://www.nmsu.edu/~tdi/roswell-8opt.pdf.) A black and white printed copy will be mailed to those requesting a copy via e-mail if a shipping address is included. The Southwest Technology Development web site (http://www.nmsu.edu/~tdi) maintains all copies of the previous "Perspectives on PV” articles. Copies of "Code Corner” written by the author and published in Home Power Magazine over the last 10 years are also available on this web site.

Draft proposals for the 2008 NEC being developed by the PV Industry Forum may be downloaded from this web site:
http://www.nmsu.edu/~tdi/pdf-resources/2008NECproposals2.pdf

The author makes 6–8 hour presentations on "PV Systems and the NEC” to groups of 40 or more inspectors, electricians, electrical contractors, and PV professionals for a very nominal cost on an as-requested basis. A schedule of future presentations can be found on the SWTDI web site.


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Tags:  Featured  January-February 2006  Perspectives on PV 

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Neither Sleet nor Snow nor Rain nor the Dark of Night…

Posted By John Wiles, Tuesday, November 01, 2005
Updated: Tuesday, January 22, 2013

Well, not exactly. Yes, all of those things will usually keep a system uses sunlight for fuel. However, these and other weather conditions also affect how a PV system is designed and installed to comply with the requirements of the National Electrical Code. With a PV power system lifetime exceeding 40 years, Mother Nature is going to use every trick in the book to make that system fail before its time. PV designers, installers, and inspectors need to devote significant attention to the weather-related safety requirements for PV systems to help ensure long-lived, hazard-free electrical installations.


Photo 1. THHN conductors exposed to sunlight

Intense Solar Radiation and High Temperatures

Before we look at the dark side of PV, let’s examine hot and sunny. PV modules are designed to operate in sunlight and the more sunlight they get, the more power and energy they will produce. The "Perspectives on PV” article in the July-August 2004 IAEI News (available on the SWTDI web site) addressed how the PV module’s electrical output is affected by the intensity of the solar radiation. But what about the related issues of the effects of temperature and ultra-violet radiation on the other equipment? Any equipment exposed to the sunlit environment should be rated for the exposure. Exposed conductors and cables must be marked sunlight resistant (UF and TC cables) or be tested during the listing process for UV exposure (USE and SE, Table 310.13) cables. Using the wrong conductors can lead to failures (photo 1). Because of the normal operating environment, cables attached to PV modules must be listed for wet (the W designator) and hot environments (the HH designator) and a -2 after the cable type gets them both. We have tested PV installations that have been in hot, sunny, dry weather for two weeks or more, opened module j-boxes and conduit bodies and had hot water run out. -2 cables are a must.

Underwriters Laboratory is releasing a specification for a new "PV” cable. Cables meeting this specification will have to pass a 720-hour accelerated UV exposure test, be rated for wet locations, have at least a 90°C rated insulation, have a flame retardant compound, and have a physically tougher insulation than type USE cable. Although the intent of the specification was that compliant cables would now meet the requirements for use in ungrounded PV systems as permitted by Section 690.35 of the NEC, it has yet to be determined how the "PV” cable will be used, given the existing code language in 690.35(D). The issue will hopefully be clarified in the 2008 NEC and the PV industry is looking at ways to use this cable long before the 2008 Code is enacted. Enlightened electrical inspectors who may see the new cable as an acceptable alternative to USE-2 may be the key to early its adoption.


Photo 2. Pipe clamps with inserts holding cables securely

Cord grips and cable clamps used on outdoor junction boxes should be UV rated. In some cases, metal cord grips have been used, and while metal is resistant to UV, these generally have not been listed for outdoor use because they can corrode rapidly. Nylon cable ties are frequently used to tie conduits and exposed cables to module racks. The white cable ties have no UV resistance, and even some of those that are black fail in a few months. The use of listed cable ties specifically marked (at least on the package) for outdoor use and sunlight resistance should be encouraged. Even better is the use of stainless steel pipe clamps with neoprene rubber inserts to firmly secure exposed single conductor cables to racks and frames (photo 2).


Photo 3. PVC conduit and cement darkened with age

The Fine Print Note No. 2 in 310.10 of the 2005 NEC points out that conduits on buildings in sunlight operate at temperatures of 17°C above the ambient temperatures. Because conduits in PV systems are exposed to sunlight for decades, the raceways many times become discolored or darken with age (photo 3). Therefore, I suggest to the PV installers that 20°C be added to the highest ambient temperature when doing ampacity calculations, to account for the higher solar energy absorption of the aged materials. With PV module junction boxes operating in the 65–75°C (and hotter) ranges and conduits in sun in ambient temperatures of 40–50°C plus the added 20°C for solar heating, it becomes evident that 310.15 temperature corrections are critical in calculating ampacities of wiring for PV systems.


Photo 4. PV combiner in the sun

PV combiner boxes that combine the outputs of strings of PV modules are also mounted in the sun. These devices (photo 4) usually contain overcurrent devices, and most overcurrent devices are rated for operation in ambient temperatures up to 40°C. With ambient temperatures in many locations of 40°C (45–50°C in the Southwest), solar heating of these enclosures pushes the internal temperature well above 40°C. The overcurrent device manufacturer must be consulted for appropriate temperature corrections. After applying the corrections by increasing the rating of the overcurrent device, the installer must then go back and verify that conductors and modules are properly protected from fault currents.

We also have to deal with those often overlooked terminal temperature limitations in NEC 110.14(C) because the high PV module temperatures require the PV installer to use 90°C rated conductors. While the modules all have terminals rated for use with 90°C conductors, the combiner boxes and most of the other fused disconnects and overcurrent devices have terminals that are restricted to use with 60°C or 75°C rated conductors. Some of the combiner boxes do not have temperature markings, and since the overcurrent devices are usually below 100 amps, a conductor temperature limitation of 60°C must be assumed. Things get pretty


Photo 5. PV combiner in shade

complex when we deal with a fused combiner box, for example, with unmarked terminal temperature limitations. Consider one operating in the sun in Phoenix, Arizona, where the ambient temperature may be 45°C for weeks at a time. The box temperature could be 55–60°C (requiring 90°C insulated conductors), the fuse rating must be temperature corrected for the 55–60°C operating temperature, and then the operating temperature of the conductor/terminal at these elevated temperatures must be estimated to be less than 60°C. Obviously, if the internal temperature of the enclosure is near 60°C, it is going to be difficult to have fuse terminals operating below 60°C with any appreciable current in the terminals. In this case, the prudent path would be to replace this PV combiner with one that is marked for use with 75°C insulated conductors. At the very least, any enclosure containing overcurrent devices installed in the hot Southwest (and other hot locations) should be mounted in the shade where it will be subjected to no more than the high ambient temperatures (photo 5).

Wind, Sleet, Snow and Rain

Moving from the hot summer Southwest (and other parts of the country) to winter and the colder locations, we see other weather related issues. Equipment has to be able to withstand wind-driven rains. The use of appropriate types of NEMA enclosures will generally ensure that the internal equipment will not be subject to direct water spray. The use of listed devices will ensure that the internal connections are also generally immune to the effects of wind-driven rain. However, some custom, field-assembled enclosures may have been made with materials that are not well designed for even a little moisture. Rust may form when the internal components have not been properly specified for outdoor/damp areas (see photo 6).

 


Photo 6. Rust due to improper use or location of components

 

High winds are an issue in coastal areas where hurricanes are common as well as in many other areas of the country. Building codes in these areas generally specify how items on the roof and on the ground are to be fastened down to resist the lifting forces of the wind. The Study Guide for the North American Board of Certified Energy Practitioners (NABCEP) has some guidance for PV installers in this area that is based on information in the National Design Specification for wood construction and on roofing manuals. The Study Guide may be downloaded from the Resources section of the NABCEP web site (www.nabecp.org).

In areas of the country where there is snow buildup on roofs, attention must be directed to securely fastening all conductors and cables to the module racks or mounts and to the roof. Otherwise, sliding snow can rip wires loose and pull conduits loose. Similar attention to these workmanship details should be applied to windy areas and in all installations, a neat, workman-like installation will usually be safer that a messy installation (photo 2).

The PV designer/installer will usually be required to make a tradeoff between the best tilt angle for PV array performance and the angle that will best shed snow. Fortunately, as the installation location moves farther north (into snow country), the tilt angle for best performance gets greater and even assists in shedding snow. However, these higher tilt angles usually result in the PV modules being subjected to higher wind loading, so secure mounting is a must.


Photo 7. Too much snow means no juice (Photo courtesy of NREL)

At very low temperatures, snow, sleet and freezing rain may adhere to the PV modules and must be removed if full output from the PV system is desired (photo 7). Obviously rooftop installations may make this more difficult. On the other hand, ground-mounted arrays must be high enough to avoid deep snow and drifts.

Hail? Usually, hail doesn’t pose too much of a problem. The PV modules are made with tempered glass and the modules are tested with impacts simulating hailstones.

Summary

Yes, sleet, snow, rain, and the dark of night will prevent a PV system from producing energy. But when the snow melts and the sun comes up, that PV system will again be generating power for a very, very long time. The wide range of environmental conditions in which PV systems are installed impose significant design and installation requirements. The NEC has been addressing such requirements for many years. The long life of these systems points to the need for durable hardware and high levels of workmanship. The equipment is required to be up to the task. Installers and inspectors must also be up to the job.

For Additional Information

If this article has raised questions, do not hesitate to contact the author by phone or e-mail. E-mail: jwiles@nmsu.edu Phone: 505-646-6105

A PV Systems Inspector/Installer Checklist will be sent via e-mail to those requesting it. A color copy of the 143-page, 2005 edition of the Photovoltaic Power Systems and the National Electrical Code: Suggested Practices, published by Sandia National Laboratories and written by the author, may be downloaded from this web site: (http://www.nmsu.edu/~tdi/roswell-8opt.pdf. ) A black and white printed copy will be mailed to those requesting a copy via e-mail if a shipping address is included. The Southwest Technology Development web site (http://www.nmsu.edu/~tdi) maintains all copies of the previous "”Perspectives on PV”" articles. Copies of "”Code Corner "” written by the author and published in Home Power Magazine over the last 10 years are also available on this web site.

Draft proposals for the 2008 NEC being developed by the PV Industry Forum may be downloaded from this web site: http://www.nmsu.edu/~tdi/pdf-resources/2008NECproposals2.pdf

The author makes 6–8 hour presentations on "”PV Systems and the NEC”" to groups of 40 or more inspectors, electricians, electrical contractors, and PV professionals for a very nominal cost on an as-requested basis. A schedule of future presentations can be found on the SWTDI web site.


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Tags:  Featured  November-December 2005  Perspectives on PV 

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Making the Utility Connection

Posted By John Wiles, Thursday, September 01, 2005
Updated: Tuesday, January 22, 2013

More than 90 percent of the new PV systems being installed throughout the United States are connected to the local utility with utility-interactive inverters (figure 1). These inverters range in size from about 250 watts (rated ac output) to about 250 kW. Multiple inverters may be used at a single location to provide even higher outputs. The connection requirements to the utility are established in various sections of the Code. Unfortunately, in many cases, these requirements are not fully understood or complied with. This article will concentrate on the requirements of the 2005 National Electrical Code Section 690.64, Point of Connection.

Figure 1. Utility-interactive inverter

This section of the Code allows the output of the inverter to be connected either on the supply (utility) side of the service disconnect or on the load (inverter) side of the service disconnect. Supply-side and load-side connections will be addressed for non-dwelling (commercial) installations first, followed by the requirements for dwellings.

Supply-Side Connections—690.64(A)

Connecting to the supply side of the service disconnect usually implies that the output of the PV inverter is connected to the conductors between the service disconnect and the meter socket. This connection is made to allow the meter to sense utility-generated power flowing to the load (facility) and PV-generated power flowing back to the utility when local power production exceeds local loads. Using a single meter allows relatively easy implementation of net metering where the meter runs forward and backward (depending on power flow) and the customer eventually pays for only the net energy used or produced. Figure 2 shows a diagram of such a connection, and figure 3 shows the picture. In the picture, the disconnect shown is an existing feeder disconnect (1980s vintage) for the building and the connections for the PV conductors are at the bottom, which are on the supply side of the service disconnect for the building. The conductors leading into the building connect to the building load center that has a main circuit breaker serving as the service-entrance disconnect.
 

Figure 2. Supply-side interconnection diagram

Figure 3. PV inverter connected to service conductors

The inverter will normally be connected through a disconnect/overcurrent protection device before being connected to the service-entrance conductors between the meter and the service disconnect. This is equivalent to connecting a second service entrance to the building and the disconnect/overcurrent device (circuit breaker or fused disconnect) should be rated as service-entrance equipment. Elsewhere, Article 690 requires that the output circuit from the inverter be sized and protected at 125 percent of the rated continuous ac output of the inverter. Obviously, the existing service-entrance conductors must be at least this size in case they have to handle the full rated output of the PV system. Like other service conductors, the conductors between the disconnect/overcurrent device and the existing service-entrance conductors are not protected, and it is suggested that they be as large as the disconnect/overcurrent device terminals will accept. It is also suggested that these conductors be kept as short as possible and that they follow the general requirements for service-entrance conductors. Since the inverter output circuit is not a load or feeder circuit, I do not believe that the general tap rules are applicable.


Figure 4. Load-side interconnection diagrams

Of course, the connection could be made with the addition of a new meter, and this would be a complete second service entrance to the facility. Usually, this complicates the measuring and billing for energy used or produced where net metering is in effect and the system is associated with a building or structure. However, this complete separate service entrance is frequently used on the larger (100 kW and up) systems.

Since many utilities require a visible blade, lockable (open) disconnect between the output of the inverter and the utility point of connection, the disconnect described above and required by the NEC, may also serve as the utility-required disconnect. In some cases, the utility will not allow a fused disconnect, so a second, non-fused disconnect must be added.

Load-Side Connections—690.64(B)

Load-side connection requirements are more numerous than supply-side connection requirements. Section 690.64(B)(1) requires that a dedicated circuit breaker or fused disconnect be used for the interconnection. This essentially means that the output of each single inverter be connected to a disconnect/overcurrent device before that circuit is connected to any other sources or loads. See figure 4 for a circuit showing two inverters connected to a load center (panelboard) on dedicated circuits. Figure 5 shows a picture of a load center being used to connect two utility-interactive inverters to the grid. And, yes, those circuits are "dead.”

Figure 5. The author, right, and Albuquerque, NM, Electrical Inspection Supervisor Hal Kissinger inspecting a load-side connection.

The requirements of 690.64(B)(2) are complex. Here is what the section (without the exception) says with emphasis added by the author. "The sum of the ampere ratings of overcurrent devices in circuits supplying power to a busbar or conductor shall not exceed the rating of the busbar or conductor.”

The key word that many readers miss is the word "supplying.” In a load center or panelboard, the main circuit breaker supplies power to the internal busbars, as do any backfed circuit breakers supplying power from the PV inverters. The potential problem can be seen in figure 4. The load center is rated at 100 amps, the main circuit breaker can supply 100 amps to the busbars, and at the same time, the inverters may add another 30 amps to the busbars. If the loads were increased to 130 amps (for example, increased plug loads), no circuit breakers would trip, but the busbars in the center of the panel rated at 100 amps would be overloaded carrying 130 amps.

In the deliberations for the 2002 NEC, the determination was made that while placing the backfed PV circuit breakers at the bottom of the panel (as far away from the main circuit breaker as possible) would prevent overloading the panel busbars, it was not an acceptable long-term solution (even with placards). Placards get lost or damaged and people who may not be familiar with PV installations and interconnections move around circuit breakers in load centers after the initial installation.

In designing PV systems for commercial (non-dwelling) installations, an existing load center is usually considered. In many commercial installations, the size of the main circuit breaker in the load center has the same rating as the load center itself. Therefore no additional current may be supplied to the load center from backfed PV circuit breakers. In this case, one alternative is to go to a supply-side connection as outlined above. Another option is to remove the existing load center and replace it with a new, larger load center that has a main circuit breaker rated the same as the original main circuit breaker. The amount of PV current that can be backfed is the difference between the panel rating and the main circuit breaker.

In all cases the main circuit breaker, the load center, and any conductors (including feeders) carrying the output of a PV system must be sized for at least 1.25 x the rated output of the inverter (see 690.8 and 690.9). As will be seen below, the load center will usually be significantly larger than just the size required by the PV circuits.

In some installations, an oversized load center is being used with an adjustable main circuit breaker. Assuming that the main circuit breaker is set at a trip point below the rating of the panel, then the difference between the two ratings is the allowable current that can be backfed from the PV array.

It is usually not a good idea to replace an existing main circuit breaker with one that has a lower rating or to adjust an adjustable main to a lower trip point in an attempt to accommodate a PV system. The original installer of the system sized that main circuit breaker based on code-required load calculations, and if the circuit breaker rating were changed, it could result in nuisance trips or an overloaded circuit breaker, not to mention a Code violation.

Connecting PV Systems to a Commercial Feeder Panel or Subpanel

In many commercial installations, the PV system is installed on the roof of a multi-story building. The building usually has a feeder panel or subpanel on each floor of the building, and those panels are connected to a main panel on the ground floor. To minimize the PV installation cost, an attempt is made to connect the PV output to the feeder panel on the top floor. However, figure 6 reveals a problem. While the requirements of 690.64(B)(2) are easily met at the top floor feeder panel, they become increasingly more difficult to meet at intermediate feeder panels and at the main panel.
 

Figure 6. Multiple feeder panel connection diagram

For example, the backfed PV current at the top floor 100-amp feeder panel could require only a 15-amp circuit breaker. Section 690.64(B)(2) would normally require that the feeder panel be increased to 125 amps (next standard size) to accommodate the 15-amp backfed PV circuit breaker. However, when we get to the first 400-amp intermediate panel, the rating of the backfed circuit breaker carrying the PV currents is now 100 amps, not the 15-amp rating of the circuit breaker in the top floor panel. Meeting 690.64(B)(2) is more difficult with the larger backfed circuit breaker. Since this 100-amp circuit breaker is the only circuit breaker limiting backfed currents, its full 100-amp rating must be considered, not just the 15-amps that it is carrying at the present time. If only the 15 amps were considered, then at some future date the PV array might be expanded and the intermediate feeder panels could be overloaded since any backfed currents could reach 100 amps before a circuit breaker tripped in the intermediate 400-amp panel. At this point, the 400-amp panel would have to be increased to at least a 500-amp panel to accommodate the 100-amp backfed circuit breaker to meet 690.64(B)(2) requirements.

The same analysis applies to the main 1000-amp panel. The backfed circuit breaker is now rated at 400 amps and to meet Code, the main panel would have to be upgraded to at least a 1400-amp panel to keep the 1000-amp main circuit breaker. All of these difficulties could be avoided by doing a supply-side connection (at 15 amps). Of course, those 15-amp PV output circuit conductors would have to be routed from the roof to the main service panel, and the output voltage of the inverter would have to match the voltage of the service entrance. In some cases a transformer might be required to match the inverter output voltage to the service-entrance voltage.

In all cases, connecting a second service-entrance disconnect with a 15-amp rating (probably using a higher-rated disconnect) to an existing 1000-amp service must, of course, be accomplished in a safe, code-compliant manner using appropriate equipment.

Applying 690.64(B)(2) to the feeder conductors carrying backfed PV currents between the various panels indicates that they usually will not have to be enlarged in size when a PV system is added. There is no place on these circuits where the feeder can be overloaded (unless the PV output current exceeds the feeder rating) because there are no places between circuit breakers where loads can be connected that could be inadvertently increased as they could be inside a panel board as shown in figure 4.

Supply-Side Connections—690.64(B)(2) Dwelling Units

Now, let us examine the installation requirements for dwelling units. The exception for 690.64(B)(2) reads: "For a dwelling unit, the sum of the ampere ratings of the overcurrent devices shall not exceed 120 percent of the rating of the busbar or conductor.”

Now we can add PV backfed circuit breakers to the dwelling (residential) load center with some leeway before we have to start changing equipment. Normally, the main circuit breaker in a residential load center is rated the same as the residential load center. This exception allows the sum of the main circuit breaker plus the sum of any backfed PV circuit breakers to be 120 percent of the rating of the load center. This additional 20 percent allowance is made because, generally, residential circuits are more lightly loaded (due to demand factor calculations) than circuits in commercial buildings. Where the main circuit breakers and panels have the same rating, the exception to 690.64(B)(2) allows 20 amps of backfed PV circuit breakers to be added to a 100-amp panel and 40 amps to be added to a 200-amp panel. Although these numbers translate to a 3840-watt (ac inverter output) PV system on a 100-amp panel and a 7680-watt PV system on a 200-amp panel, some people want to install bigger PV systems and that means creative thinking must be used. These limits include the normal 80 percent maximum continuous operating-current limitations on the circuit breakers.

Many common PV inverters are rated at 2500 watts, 240 volts. The rated output current is 2500/240 = 10.4 amps. Using the code-required 1.25 multiplier (690.8) yields a circuit breaker requirement of 13 amps, which rounds up to 15 amps as the rating of the backfed circuit breaker. On a 100-amp panel, with a 100-amp main circuit breaker, only one of these inverters can be accommodated. On a 200-amp panel, only two of these inverters may be connected limiting the PV system to 5000 watts and not the maximum potential of 7680 watts.

However, figure 7 shows a code-compliant way to add three of these 2500-watt inverters to a 200-amp panel by using a subpanel. A subpanel is selected to accommodate the three 15-amp backfed circuit breakers, one from each of the 2500-watt inverters. The main circuit breaker on this dedicated (PV-only) subpanel has to have a minimum rating of the 3 x 10.4 x 1.25 = 39 amps (round up to a 40-amp circuit breaker). This would also be the rating of the backfed circuit breaker in the main panel and, at 40 amps, would meet the Code requirements for a 200-amp main panel. Of course, two 40-amp circuit breakers would not be needed, and only one at the main panel would suffice.

What should the size of the subpanel be? Using a formula derived from the Code requirements, we see that the minimum size of the panel would be about 75 amps, which would round up to a 100-amp, standard-sized panel.

3 * 15 + 40 <= 1.2 X, where X is the panel size required

Solving for X gives us

X >=(45 +40)/1.2 = 71 amps

For those desiring to install larger PV systems on residential services, the use of a supply-side connection as outlined above can meet the Code requirements.

Line Side of Ground Fault Equipment—690.64(B)(3)

The Code generally requires that all PV inverters be connected on the line side of any ground-fault protection equipment with an exception that allows backfed GFP equipment when the protected circuits have ground-fault protection from all sources.

However, tests (by SWTDI and Sandia National Laboratories) on the typical 5 milliamp GFCIs, 5 and 30 milliamp GFP circuit breakers have revealed that the internal sensing and trip circuits are destroyed when they are tripped while being backfed by a PV inverter. Conversations with manufacturers of the larger 100–800-amp ground-fault protection devices also indicate that these devices will be damaged when tripped while being backfed. Therefore, it is recommended that ground-fault protection equipment never be backfed. A proposal deleting the exception to 690.64(B)(3) is being developed for the 2008 NEC.

Markings Required—690.64(B)(4)

This section requires that all panelboards and fused disconnects supplying power to a busbar or conductor be marked showing all sources of power. This requirement is generally met by the installation of placards containing the required information installed by the system installer on all backfed panelboards and fused disconnects. The placard should show the rated output current of the inverter feeding the circuit and the nominal line voltage of the inverter.
 

Figure 7. Three 2500-watt inverters on a 200-amp residential panel

Backfed Circuit Breakers—690.64(B)(5)

Although another section of the Code [408.36(F)] requires that backfed circuit breakers be clamped, changes to 690.64(B)(5) in the 2005 NEC no longer require them to be clamped when connected to the output of utility-interactive inverters. Section 690.3 indicates that the 690 requirements override the 408 requirement. A fine print note explains that circuit breakers suitable for backfeeding are not marked with "Line” and "Load” designations.

Battery-Backed-Up, Utility-Interactive Systems—More Complexity

The specifications in Underwriters Laboratories Standard 1741 require all utility-interactive inverters cease exporting power to the utility grid when the utility grid voltage and frequency deviate from very narrowly defined values. In blackout situations, the PV system and the standard utility-interactive inverter cease to operate and will not even supply power to local loads. In areas where utility blackouts are common or are anticipated to be common, some systems are being installed that have a battery-based energy storage system installed to provide local power during utility outages. The batteries are connected to a specially designed and listed utility-interactive inverter that, in the event of a utility outage, will disconnect from the utility system and provide a set of designated circuits with power from the PV system and the battery. All of these actions are done automatically with transfer devices built into the inverter. Figure 8 shows a simplified block diagram of a typical system. Several variations are possible.


Figure 8. Utility-interactive PV system with battery backup

In normal operation, the utility is present and the inverter acts as any other utility-interactive inverter. Any power from the PV system in excess of local load requirements is fed into the utility grid. When insufficient power is available from the PV system, the system buys power from the utility. The batteries are kept at full charge (float charged) by the utility power and are generally not used. However, when there is a utility outage, the inverter automatically senses this outage, ceases to export power to the utility, and feeds the backup load subpanel with ac power derived from the PV array and the batteries. The backup loads will receive ac power from the batteries and PV array to the extent that the energy draw does not exceed the capacity of the supply and storage systems.

Interfacing these systems with the utility grid and meeting 690.64(B)(2) requirements presents challenges for the system designer, the installer, and the inspector. Many of these inverters have internal transfer relays that are rated for 60-amps continuous duty, and that information is presented in the specifications. This specification leads designers and installers to size the backup load subpanel for 60 amps and to use a 60-amp backfed circuit breaker to connect the inverter to the main load center where the utility connection is made. The use of 60-amp circuit breakers in both positions provides for best use of the internal 60-amp relay and appears to allow maximum loads to be connected to the backup subpanel. Unfortunately, the use of 60-amp circuit breakers poses two problems and Code violations.

First, even though the inverter may be rated (and can be adjusted) to carry 60 amps, the external wiring and circuit breakers require the normal 80 percent continuous current derating. For a 60-amp continuous current, an 80-amp circuit breaker and conductors rated for at least 75 amps would be required. Another option, that will allow the 60-amp circuit breakers to be retained, would be to adjust the inverter to not allow more than 48 amps of continuous current to be handled by these circuits. That adjustment is commonly available on most of these inverters, although there is some question about who has access to the adjustment (qualified or unqualified people).

A second issue is the 690.64(B)(2) requirements discussed above. In a residential installation, a 60-amp backfed PV circuit breaker would dictate that at least a 300-amp main panel be used (60 amp PV circuit breaker + 300 amp main circuit breaker = 360 amps = 1.2 x 300 = 360). Residential load centers rated at 300-amps and above, while not impossible, are not common. In a commercial installation, the existing load center would have to be replaced with one having at least a 60 amp greater rating. In either case, a supply-side interconnection [690.64(A)] might be the more practical alternative. If the full 60 amps of the inverter are to be used, then, of course, 80-amp circuit breakers and 75-amp conductors should be used.

To further complicate the system design, many of these systems have an external inverter-bypass switch that is used if the inverter fails. This bypass switch, usually consisting of a pair of interlocked circuit breakers, is used to connect the back up subpanel directly to the main panel when the inverter fails. These circuit breakers are typically also rated at 60 amps and installed in a small 60-amp, three-position (three-phase) load center. Obviously neither the circuit breakers nor the load center are rated to carry 60-amps continuously. The use of a larger load center and interlocked 80-amp circuit breakers would allow a full 60-amp rating for the inverter-bypass switch.

Summary

The requirements of NEC Section 690.64 can be met in nearly all installations. While the requirements, at first glance, are somewhat complex and sometimes overlooked, attention to these details in the design, installation, and inspection of these systems should help to ensure a safe, durable, and code-compliant installation.

For Additional Information

If this article has raised questions, do not hesitate to contact the author by phone or e-mail. E-mail: jwiles@nmsu.edu. Phone: 505-646-6105

A PV Systems Inspector/Installer Checklist will be sent via e-mail to those requesting it. A color copy of the 143-page, 2005 edition of the Photovoltaic Power Systems and the National Electrical Code: Suggested Practices, published by Sandia National Laboratories and written by the author, may be downloaded from this web site: (http://www.nmsu.edu/~tdi/roswell-8opt.pdf.) A black and white printed copy will be mailed to those requesting a copy via e-mail if a shipping address is included. The Southwest Technology Development web sitehttp://www.nmsu.edu/~tdimaintains all copies of the previous "Perspectives on PV” articles. Copies of "”Code Corner”" written by the author and published in Home Power Magazine over the last 10 years are also available on this web site.

Draft proposals for the 2008 NEC being developed by the PV Industry Forum may be downloaded from this web site: http://www.nmsu.edu/~tdi/pdf-resources/2008NECproposals2.pdf

The author makes 6–8 hour presentations on "”PV Systems and the NEC”" to groups of 40 or more inspectors, electricians, electrical contractors, and PV professionals for a very nominal cost on an as-requested basis. A schedule of future presentations can be found on the SWTDI web site.


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Tags:  Featured  Perspectives on PV  September-October 2005 

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