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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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Load Side PV Connections

Posted By John Wiles, Wednesday, January 22, 2014

Through the exceptional efforts of the members of NFPA NEC Code-Making Panel 4 working with the proposals and comments that were submitted for the 2014 Code, significant changes have been made to Section 705.12(D), Load Side Connections for Utility-interactive PV Inverters. These changes will allow better understanding of the requirements for load-side connections of utility interactive inverters and will clarify requirements that were not fully described in previous editions of the code. Not only will AHJs and plan reviewers benefit from these changes, the PV installer will also have significantly improved guidance in this area.

All material in quotations below is taken from the 2014National Electrical Code (NEC), ANSI/NFPA 70. Bold italics text represents changes from the 2011 NEC.

Introductory Paragraph 705.12(D)

"705.12(D) Utility-Interactive Inverters. The output of a utility interactive inverter shall be permitted to be connected to the load side of the service disconnecting means of the other source(s) at any distribution equipment on the premises. Where distribution equipment, including switchgear, switchboards, or panelboards, is fed simultaneously by a primary source(s) of electricity and one or more utility-interactive inverters, and where this distribution equipment is capable of supplying multiple branch circuits or feeders, or both, the interconnecting provisions for the utility-interactive inverter(s) shall comply with 705.12(D)(1) through (D)(6).”

The word "switchgear” has been added to the list of distribution equipment. And as in past editions of the Code, distribution equipment is not specifically defined. Of course, we all know what it means and numerous examples are usually given. But, we must also consider that distribution equipment in the form of junction boxes for taps or new panelboards can be added to the premises wiring at almost any location that is allowed by the Code. So essentially, connections for utility-interactive inverters can be made at many points on the load side circuits that are not in existing distribution equipment.

705.12(D)(1) Dedicated Overcurrent and Disconnect

"The source interconnection of one or more inverters installed in one systemshall be made at a dedicated circuit breaker or fusible disconnecting means.”

This section has been revised to specifically require that multiple inverters in a single PV system shall be connected to the existing premises wiring system at a single dedicated circuit breaker or fusible disconnecting means. This section no longer allows multiple connections to a load center or panelboard where there are multiple inverters involved. Multiple inverters must first be combined in an AC combining panel and the output of that panelboard is then connected to the single point of connection in the distribution equipment through one circuit breaker or fusible disconnecting means. See diagram 1.

 

Diagram 1.  705.12(D)(1)  Single PV connection allowed.

Unfortunately, we do not have a definition of "PV system” in the Code. This will be a gray area that must be interpreted by the AHJ. What happens when there are ten widely distributed PV "systems” on a large structure such as a mall? What happens if each "system” must be individually metered and connected to separate load centers for net power flow to separate facilities? Is this one system or can each system be considered separately? What about a large residence, with an inverter and modules on the garage and another set of modules and inverter on the main house? What about the situation where one inverter is fed by an array on the east facing roof and a second inverter is fed by an array on the west facing roof and the inverters are not co-located? And then there is the apartment building or condo where one structure may have three of more separate systems, each requiring a separate connection to individual load centers for net power purposes. Are all of these examples of one system? Or are they multiple systems that might be connected to the premises wiring at multiple points? Again, the AHJs will have to make the call.

It would appear that where multiple inverters are co-located in a single structure or facility and there is only one "user/owner/customer” of those multiple systems, they must have their outputs combined before a connection is made to the existing premises wiring system. And, as PV modules get more efficient and costs come down, we may see increasing numbers of multiple inverter systems on single buildings.

705.12(D)(2) Bus or Conductor Ampere Rating

"One hundred twenty-five percent of the inverter output circuit current shall be used in ampacity calculations for the following:”

Note that the title of the section remains bus or conductor ratings and will apply to both as they are defined in the introductory paragraph. The first noteworthy change in this section is the use of a factor of 125% of the inverter rated output current in calculations for busbar ratings and conductor ampacity. In the previous code, the rating of the overcurrent device protecting the inverter output circuit was used in the calculations. This new allowance may slightly reduce the required busbar and conductor ratings required by the following calculations.

Feeders

Feeder Ampacity

"(1) Feeders. Where the inverter output connection is made to a feeder at a location other than the opposite end of the feeder from the primary source overcurrent device, that portion of the feeder on the load side of the inverter output connection shall be protected by one of the following:

(a) The feeder ampacity shall be not less than the sum of the primary source overcurrent device and 125 percent of the inverter output circuit current.

(b) An overcurrent device on the load side of the inverter connection shall be rated not greater than the ampacity of the feeder.”

This section represents a significant change from past code requirements. It presents requirements for feeder size and overcurrent protection when the utility interactive inverter connection is notat the opposite end of the feeder from the utility connection.

PV Opposite Utility On the Feeder (Not addressed by Code)

 Since, the situation where the PV connection is at the opposite end of the feeder is not addressed in the new requirements, we can assume (sometimes not a good thing to do) that there is no ampacity correction required on the feeder under that situation. The size of the existing feeder was determined by the existing overcurrent device protecting that circuit from utility currents. Consider the feeder carrying PV currents with fused disconnects in the feeder at various points.

Additionally, while locating the PV inverter output connection at the opposite end of the feeder from the utility source will prevent the feeder from being overloaded by additive currents, it is obvious that 125% of the rated inverter output current must not exceed either the rating of the utility-end overcurrent device or the ampacity of the existing feeder.

Existing Load Taps of the Feeder (Not addressed by Code)

However, if that existing feeder has been tapped for load(s), common sense would dictate a close look at the tap rules because now there are two sources of current that can feed the tap conductor, and the tap rules and tap conductor size used initially may no longer be appropriate.

In (a), a PV connection is made to the feeder somewhere along the feeder, but not at the end opposite the utility connection. The portion of the feeder, from the connection point to the load end of the feeder can be subjected to currents that are additive and can be as high as the rating of the existing utility end overcurrent device protecting the feeder plus the output of the PV inverter. Hence, the conductor from the connection point to the load end of the feeder must have an increased ampacity equal to the sum of the existing overcurrent device protecting the feeder and 125% of the inverter output rating as noted in this section. See diagram 2.

 

Diagram 2.  705.12(D)(2)(1)(a) Increased feeder ampacity required.

In (b), an allowance is made to protect the existing feeder by installing an overcurrent device on the feeder on the load side of the connection point at the connection point. This allowance, with the added overcurrent protection rated the same as the existing feeder, will allow the existing feeder to be retained and not be replaced as may be required in (a). The addition of this overcurrent device will prevent excess load currents or faults from exceeding the ampacity of the feeder. See diagram 3.

 

Diagram 3.  705.12(D)(2)(1)(b) Additional breaker required.

Inverter Output Circuit (the tap conductor) Size

"(2) Taps. In systems where inverter output connections are made at feeders, any taps shall be sized based on the sum of 125 percent of the inverter(s) output circuit current and the rating of the overcurrent device protecting the feeder conductors as calculated in 240.21(B).”

Significant engineering analysis by code-making panel members and others went into this change concerning the use of the tap rules in section 240.21(B). While an overcurrent device and a disconnect are still required at the output of each utility-interactive inverter, that overcurrent protective device does not have to be at the tap point on the feeder. The tap rules allow the overcurrent device to be on the tap conductor at various distances from the connection point to the feeder. The inverter output overcurrent protective device is still required to be 125% of the inverter output rating; and, of course, there may be rating round up involved in selecting an appropriate overcurrent device. However, when calculating the required ampacity of the tap conductor under the various tap rules, the actual factor of 125% of the inverter rated output current is used and not the overcurrent device rating. Again, this may yield slightly reduced conductor sizes. See diagram 4.

 

Diagram 4.  705.12(D)(2)(2) Tap rules used to locate PV breaker and determine conductor ampacity

Busbars

"(3) Busbars. One of the methods that follows shall be used to determine the ratings of busbars in panelboards.

Busbar Rule (a)

(a) The sum of 125 percent of the inverter(s) output circuit current and the rating of the overcurrent device protecting the busbar shall not exceed the ampacity of the busbar.

Informational Note: This general rule assumes no limitation in the number of the loads or sources applied to busbars or their locations.”

This worst-case requirement presented in (a) assumes that the utility current through the existing main breaker and the current from the output of the utility-interactive inverter may add and that current may create an overload on the busbar. There are no restrictions on the location of the main utility breaker or the PV backfed breaker. If the busbar has a rating equal to the sum of these two values, then no overload would be possible.

It should be noted that reductions in the size of the utility breaker are not prohibited in this section and could be accomplished if allowed by other sections of the Code, load calculations and equipment limitations.

Busbar Rule (b)

"(b) Where two sources, one a utility and the other an inverter, are located at opposite ends of a busbar that contains loads, the sum of 125 percent of the inverter(s) output circuit current and the rating of the overcurrent device protecting the busbar shall not exceed 120 percent of the ampacity of the busbar. The busbar shall be sized for the loads connected in accordance with Article 220. A permanent warning label shall be applied to the distribution equipment adjacent to the back-fed breaker from the inverter that displays the following or equivalent wording:

WARNING:

INVERTER OUTPUT CONNECTION;

DO NOT RELOCATE THIS OVERCURRENT DEVICE.

The warning sign(s) or label(s) shall comply with 110.21(B).”

Section (b) is similar to the requirement found in previous editions of the code. If the two sources (utility and PV) are at opposite ends of the busbar, then the sum of those two sources can be as high as 120% of the busbar rating. With this location of sources, it is not possible to overload the busbar. Note that the busbar must be sized for the loads that are connected. The reason for the value of 120% is lost in history, but may be related to potential thermal overloading of the panelboard. The warning label is self-explanatory and the new requirement referring to section 110.21(B) gives additional information on the specifics of the appearance and durability of the warning label.

Busbar Rule (c)

"(c) The sum of the ampere ratings of all overcurrent devices on panelboards, both load and supply devices, excluding the rating of the overcurrent device protecting the busbar, shall not exceed the ampacity of the busbar. The rating of the overcurrent device protecting the busbar shall not exceed the rating of the busbar. Permanent warning labels shall be applied to distribution equipment that displays the following or equivalent wording:

WARNING:

THIS EQUIPMENT FED BY MULTIPLE SOURCES.

TOTAL RATING OF ALL OVERCURRENT

DEVICES, EXCLUDING MAIN SUPPLY

OVERCURRENT DEVICE, SHALL NOT EXCEED AMPACITY OF BUSBAR.

The warning sign(s) or label(s) shall comply with 110.21(B).”

Section (c) provides an alternate method of sizing the PV backfed breaker, or determining the size of the required busbar if the PV backfed breaker rating is known. This section will most likely be used when connecting PV to a subpanel or when sizing inverter ac combining panelboards. After excluding the main breaker from the utility, the sum of all remaining breakers, both load breakers and the PV supply breaker may not exceed the rating of the busbar. There are several aspects to this requirement that need close inspection and consideration.

First, the main breaker before the addition of any PV has been sized to protect the busbar from possible overload from utility currents. The main breaker will always be equal to or smaller than the busbar rating. For example, many load centers have a 125-amp busbar, but only a 100-amp main breaker. In a normal panelboard or load center, the ratings of the load breakers will total more than the rating of the main breaker or the busbar in nearly all circumstances. If this situation exists, then no PV can be added because the requirement cannot be met because the sum of the load breakers already exceeds the rating of the busbar. However, if the sum of the load breakers were equal to the rating of the busbar, that busbar would still be protected both by the main breaker and by the fact that excess current over the busbar could not be drawn through the load breakers. And again, under this condition, no PV backfed breaker could be added. However, as the sum of the load breakers is reduced, there becomes an allowance for adding a backfed PV breaker with increasing ratings. In the extreme case, there could be a situation where there are no load breakers and only a single backfed PV breaker rated the same as the busbar. In any of these cases, no matter where the PV breaker is installed on the busbar, the supply and/or load currents cannot exceed the rating of the busbar.

But, it should be noted that in existing load centers, with the sum of the load breakers totaling more than the busbar rating, it is unlikely that load and load breakers can or will be removed.

And, of course, it would not be wise to install a backfed PV breaker that was larger than the main breaker in those instances where the busbar rating is larger than the main breaker. If this were done, the main breaker could trip from over currents through the larger PV breaker.

 

Photo 1.  Panelboards and load-side connections — many changes for plan reviewers and inspectors in 2014.

But, this section needs to be used with extreme caution because there is no restriction on the position of the backfed PV breaker. Suppose a 50-amp PV breaker were installed near the top of the 100-amp busbar in the load center near a 100-amp main breaker and there were 50 amps of load breakers. The code requirement is met with this configuration. However, what happens if someone disregards the warning label or the label simply falls off over time? I suspect that many jurisdictions are going to have to emphasize the permanent nature of that warning label to cover the materials that it is made of and the manner in which it is fixed to the panel board. Also, some consideration might be made to permanently covering unused panelboard breaker positions. It might be wise to adopt a local jurisdiction requirement that the backfed PV breaker always be installed as far as possible from the main utility breaker and an additional warning label as required in (b) be placed adjacent to this PV breaker, or other PV overcurrent device.

Center-fed Panelboards

"(d) Connections shall be permitted on multiple-ampacity busbars or center-fed panelboards where designed under engineering supervision that includes fault studies and busbar load calculations.”

There was no provision in earlier codes to address center-fed panel boards and it was not possible to install the PV breaker at the opposite end of the busbar from the main breaker because there were two busbars connected to the main breaker. Section (d) was specifically added to the 2014 Code to address the common situation where PV needs to be connected to a center-fed panelboard. Although not clearly stated, there was no intent to allow center-fed panelboards to be installed under sections (a) through (c) of 705.12(D)(3). PV connections are now allowed on center-fed panelboards under the conditions noted in this section. Engineering supervision typically indicates that the analysis of the center-fed panel board connection will be made and stamped by a professional engineer. The load calculations will look not only at the breakers installed on the busbars, but also the loads connected to those breakers, and the possibility of installing additional breakers and loads in unused spaces in the panelboard. Fault studies may involve looking at the electrical time versus current profiles for each of the circuit breakers involved to ensure that all portions of the busbars will be protected under various fault scenarios from currents sourced both from the utility through the main breaker and from the PV system through the backfed PV breaker.

Marking (3), Suitable for Backfeed (4), and Fastening (5)

These sections are unchanged from the 2011NEC.

Wire Harness and Exposed Cable Arc-Fault Protection

"(6) A utility-interactive inverter(s) that has a wire harness or cable output circuit rated 240 V, 30 amperes, or less, that is not installed within an enclosed raceway, shall be provided with listed ac AFCI protection.”

This requirement will apply mainly to microinverter systems that have inverter ac output cables and trunk cables that are not installed in conduit.

Summary

It is obvious that the new 705.12(D) requirements are significantly different from those in past years. While many of them make sense from an engineering point of view, the real world faced by inspectors and plan reviewers may be somewhat different where people typically ignore instructions, ignore the Code, and ignore warning labels. On the other hand, PV systems have not changed significantly from 2011 to 2014 and the electrical systems they are being connected to have not changed significantly, so these new requirements might also be applied in jurisdictions using earlier editions of the Code by accepting alternate methods and materials waivers based on the 2014 NEC clarifications.


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Tags:  Featured  January-February 2014  Perspectives on PV 

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Supply-Side PV Connections: A Closer Look

Posted By John Wiles, Tuesday, November 19, 2013

Plan reviewers and inspectors throughout the country are seeing increasing numbers of supply-side connected utility interactive photovoltaic (PV) power systems [705.12(A)]. This article will examine some of the reasons for those increasing numbers of supply-side or utility-side connected systems. It will address the code requirements applicable to these systems and it will look at some of the implementations of these systems and areas in the installation that should receive additional attention. The article references NEC-2011.

Costs Decreasing

The cost of installing a PV power system has come down substantially in the last year or two for several reasons. There is a surplus of PV modules on the market and the cost of those modules has dropped significantly. New installation materials and techniques have become available, reducing labor costs. And, financial incentives at the national, state, and local levels are still in effect in many areas.

Load-side Limitations

The size of the typical residential and small commercial PV system has been increasing because of the lower costs mentioned above, increasingly large PV modules, and inverters with higher outputs. This increased size of the PV system has made it more difficult to make a load-side utility connection [705.12 (D)] because of the limitations of the 120% allowance for back feeding load centers.

With no reduction in the size of the main breaker, a 100-amp load center with the 20-amp backfed PV breaker would allow only a PV system with an inverter output rated current of 16 amps. The circuit breaker protecting the inverter output circuit has to be at least 125% of the rated inverter output current or in other terms, the rated inverter current can be no larger than 80% of the breaker rating (690.8). At 240 volts, this allows a maximum inverter rating of 3840 watts (240 x 16). Similarly, a 200-amp load center, again with no change in the main breaker, can handle only up to an inverter rated at 7680 watts.

And, since PV inverters have ratings such as 3000 W, 3500 W, 4500 W and the like, the PV output will actually be somewhat below the numbers above. Hence, the inspector community is seeing increasing numbers of supply-side connections. See photos 1 and 2.

 

Photo 1. PV systems are getting larger and frequently will require supply-side connection to the utility. No, shaded modules are not good and will not get the maximum energy from the PV array.


 

Photo 2. Two inverters on a residential installation will generally indicate that a supply-side utility connection is required.

Code requirements

Section 705.12(A) establishes the allowance for supply-side PV connections. A supply-side connection is made on the supply or utility side of the service disconnecting means for the existing building or facility. Section 705.12(A) refers to Section 230.82(6).

Of course, this section is in Chapter 2 of the Code dealing with services, and this section allows solar photovoltaic systems or interconnected electric power production sources to be connected on the supply side of the service disconnecting means.

Also pertinent is section 230.2(A)(5) that permits additional services including parallel power production systems as a Special Condition.

The National Fire Protection Association (NFPA) has ruled informally decades ago and again more recently that a supply-side connected PV system is an additional service on an existing building or facility. As a service, most of the Chapter 2 service requirements should apply to the ac circuits between the connection to the existing service and the new, added PV service disconnect.

After the circuit passes through the PV service disconnect, the electrical requirements are now on the load side of the service disconnect and the Chapter 2 service entrance requirements no longer apply. AC circuits toward the inverter from the PV service disconnect should comply with 690.8 or 705.12(D).

Service Entrance Requirements

While not attempting to address all of the requirements in Chapter 2 dealing with services, there are some requirements that are frequently overlooked in installing a supply-side connected PV system. The types, sizes and routing of the added PV "service conductors” are covered in Article 230.

It would appear that the minimum size for the added service conductors and the PV service disconnect is 60 A [230.79(D)]. The size of the PV output circuit overcurrent protection is not specified and may be lower than the 60-amp minimum rating of the PV disconnect and PV service-entrance conductors.

While the PV service minimum size is 60 amps, this does not preclude the connection of, for example, a 15-amp inverter output circuit to the 60-amp added service with the appropriate sized overcurrent protection. On the other hand, the maximum size of the supply-side connected PV inverter output would be limited to the rating of the service.

From the perspective of the existing service-entrance panel and conductors, the PV supply-side connection looks just like the existing utility service supply. The existing main overcurrent protective device protects all load-side circuits in the same manner whether or not the PV supply-side connection is present. None of the load-side code requirements [705.12(D)] apply to the new circuits between the new added PV service disconnect, the utility supply or the conductors to the existing main disconnect.

And, of course, the interrupt rating of the added PV service disconnect/overcurrent protection must be equal to or greater than the available short-circuit current from the service (110.9). Since the utility service may have been upgraded with larger transformers since the original electrical installation, the interrupt rating of the existing service equipment should not be relied upon as a sizing indicator for the interrupt rating of the new PV service equipment.

When the new PV service disconnecting means is notin the same enclosure as the existing service disconnect means, the PV circuit neutral should be bonded to ground and a grounding electrode conductor originating from the PV service disconnect location must be routed to the grounding electrode (250.24).

Even where the PV inverter connection does not have a neutral connection, the utility neutral should be routed to at least the new PV service disconnect and any PV production meter. The meter may require the neutral for proper operation.

Location of the Connection

The exact location where the supply-side connection can be made is subject to many variables. While the code says that the connection is made on the supply side of the service disconnecting means, that location can vary depending on the configuration of the service and other factors.

Utility Property or Premises Wiring?

It is assumed that the connection must be made on the premises wiring which is on the premises side of the service point (Article 100), but that service point will vary from utility to utility. In some cases, the service point is at the power pole or the underground distribution transformer. In other jurisdictions, the service point is the input or utility side of the meter base (socket); and in still other locations, the service point is the utility side of the main service disconnect. Normally, the PV supply-side connection must be made on premises wiring and not on utility-controlled wiring. Further complicating the issue is the fact that no matter where the service point is, the utility may actually do the wiring past the service point. In some jurisdictions the service point may be the service disconnect and the utility does the actual wiring all the way to that service point. In other jurisdictions, the service point may be the utility side of the meter base but the utility will still make the electrical connections all the way to the service disconnect. Another complicating factor is that even when the service point is the service disconnect, the local electrician may be required to make the wiring between the meter base and that service disconnect.

Many utilities are very protective of service wiring that they consider under their control. They nearly always lock the meter base; and in the larger installations, the service entrance section (SES) of the switchgear cannot be accessed by anyone other than the utility. Utility permission and access to these supply-side locations must be granted in order to make PV connections in these areas.

Inside the Service Equipment

There may be sufficient space to do a connection on the service-entrance conductors as they come into the service-entrance panelboard (load center) and before they reach the main breaker. There must be sufficient space in the panelboard to make these connections and this may be a workmanship judgment call by the AHJ. Note: Connections ahead of main breakers in subpanels that are not the service-entrance panels are not considered supply-side connections.

In some parts of the country, a main-lug-only service-entrance load center is used. With no main breaker, each of the six allowable breakers in this panelboard can be considered a supply-side connection and is considered a service-entrance disconnect. If one of the six breaker positions is unused, the PV connection can be made using a breaker in that open position. The maximum circuit rating of the PV output would be limited to the lesser of the service rating, the bus bar rating in this panelboard, or the maximum size breaker that can be installed in the open position. With this type of supply-side PV connection, where the added PV disconnect is inside an existing panelboard, the existing neutral-to-ground bond for the entire panelboard accomplishes the neutral-to-ground bond for the PV service.

It should be noted that the rating of a service-entrance panelboard is not necessarily the same as the rating of the service, although they may be related. The utility determines the rating of the service and their conductor size requirements, for a given current rating, are generally not the same as those found in the NEC.

The Meter-Main Combo

On small residential systems, a meter-main combo panel will frequently be used. This is a single unit containing the meter base and the service disconnect (photo 3). Although there is a significant amount of room in this combo panel and the conductors are easily accessed between the meter base and the disconnect breaker, those conductors may not be used for connection points for the PV system. Such a connection would violate the listing on the enclosure and should never be made [110.3(B)].


Photo 3. Meter main combos may not have the internal conductors (or bus bars) tapped for a PV supply-side connection. Such a connection would violate the listing on the device and therefore violate NEC section 110.3(B).

Large System Switchgear

On the larger commercial electrical installations, switchgear assemblies rated at thousands of amps are used (photo 4). These switchgear assemblies are generally manufactured and installed by electrical equipment assemblers/manufacturers known as Underwriters Laboratories (UL) 508 Shops, where UL 508 is the standard governing the certification of these assembly shops and what they can and cannot do. Making a supply-side connection on bus bars that are readily accessible in these types of switchgear is a specialized task. Underwriters Laboratories has maintained for years that only the assembling/manufacturing UL 508 Shop may legally make these connections without violating the listing on the switchgear. Just because holes are available in the bus bars at the proper location, does not mean that these holes are designed for electrical connections. In all cases, for an electrical connection to be made while maintaining the listing, the holes in the bus bars must be marked as "tap points,” the electrical terminal devices must be specified, and the specific instructions for making the electrical connection must be provided and followed.

 

Photo 4. Large system electrical switchgear. Possible connection points must be identified and made by an approved organization and allowed by the utility.

A complicating factor is that even though a connection point can be identified in the switchgear and a connection can legally be made, the utility may not allow such a connection in the service entrance section (SES) of the switchgear that is under their control. Also, the location of current transformers (CTs) and potential transformers (PTs) used for metering may not allow net metering to be accomplished because the metering points are frequently connected on the load side of the main disconnect. A supply-side PV connection, even when allowed, would not allow the meters to measure the net energy flow—only the load energy.

Ahead of the Service Equipment

In general, the connection between a separated meter base and the service disconnect panelboard is a possible place to make a connection. Of course, conduit or other raceway must be broken, a junction box added, and the splice made inside the junction box. The difficulty in completing these actions depends on the physical installation.

The meter base is another potential location for the supply-side connection. Some meter bases have lugs that are listed for double connections. Several organizations and meter base manufacturers have listed meter base adapters that are installed between the meter and the base and allow the PV supply-side connection to be made at that location. However, some utilities and some jurisdictions will not allow supply-side connections to be made at the meter or in the meter base.

With a supply-side connection ahead of the service equipment, the rating of the PV circuit is essentially limited to the lesser of the rating of the service (established by the utility) or the ampacity of the conductors where premises wiring is involved.

Summary

Plan reviewers and inspectors need to be fully aware of the Code requirements for making the supply-side PV connections. These unprotected conductors from the connection point to the new PV service disconnect are to be treated as service conductors. Familiarity with utility practices and restrictions is also required to ensure that a legal connection is being made.


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Tags:  Featured  November-December 2013  Perspectives on PV 

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A Closer Look at Batteries

Posted By John Wiles, Monday, September 16, 2013
Energy storage systems, in the form of batteries, when included in a photovoltaic power system are a critical and important item that needs close scrutiny during the plan review and inspection process.

Battery systems are found in both off-grid stand-alone PV systems and in battery-backed up, utility-interactive PV systems. See the March-April 2013 IAEI magazine for an overview of the battery-backed up, utility-interactive PV system. The following information will focus on the dc circuits associated with the battery system.

Types of Batteries

There are two main types of battery systems being used in PV systems at this time. Both are based on a lead acid battery technology [older than the National Electrical Code (NEC)]. The oldest technology uses a flooded lead acid battery that has removable vent caps and requires the addition of water on a regular basis. See photo 1. A related technology known as the valve-regulated, lead-acid (VRLA) battery uses an internal chemical design to allow the battery case to be effectively sealed. See photo 2. No water can be added to these VRLA batteries.

 

Photo 1. Flooded Lead Acid batteries

The newer battery types of nickel cadmium and lithium ion have not found their way into PV systems in any substantial numbers yet, probably due to the higher cost of these technologies. Increasing use of these battery types in electrical vehicles (EVs) will probably lower the costs and they will become more frequently used in PV applications. Other advanced technology battery types such as the chemical "flow” batteries are generally found only in large, experimental installations in utility and industrial applications.

Mechanical Installation, Venting and Acid Containment

Batteries contain substantial amounts of lead that makes them very heavy. The floor that they rest on must be sufficiently strong, particularly for the larger battery banks, which may weigh several tons. Where battery banks are installed in racks that are more than a foot or so high, those racks must be secured to a substantial wall. Building codes, especially in earthquake zones, require substantial mechanical securing of the batteries.

During the normal charging process, flooded lead acid batteries will emit hydrogen gas and sulfuric acid fumes into the surrounding environment. The type and adjustment of the charge controller will determine the amount of outgassing. Although the VRLA batteries are sealed, if the charge controller is misadjusted, becomes defective, or fails, the VRLA battery will also outgas hydrogen and sulfuric acid fumes. Both of these battery types should be installed in a well-ventilated area and should normally not be installed in a living space. In normal operation, the amount of hydrogen gas and sulfuric acid fumes are very limited and are quickly and easily dispersed into the surrounding room without problems. However, if these gases are restricted from being diluted with the surrounding air, an explosive combination of gases and air is possible. Garages and outbuildings are ideal locations for these batteries if they are well ventilated, not sealed, not used as living spaces, and do not have living spaces over them.

No attempt should be made to construct a manifold or venting system for these batteries. Power venting systems have a tendency to fail and the high-vent, low-vent system used for combustion appliances like gas furnaces and water heaters is not applicable to batteries since there is no driving energy source equivalent to the heat energy source of a heating system. Power vented manifolds on the batteries should not be used, as they have been responsible for explosions and fires in the past. Batteries installed in well vented locations are acceptable. Catalytic battery vent caps employing a platinum catalyst are available for use on flooded lead acid batteries to reduce hydrogen outgassing and reduce the requirement to add water to the battery.

 

 Photo 2. Valve Regulated Lead Acid (VRLA) batteries

Flooded lead acid batteries contain liquid sulfuric acid, and VRLA batteries include a similar jelled electrolyte. These batteries should be installed in a manner that prevents them from being mechanically abused. Many local building codes require some sort of acid containment for these batteries should the cases become cracked. Installing the batteries in an acid resistant outer container may be sufficient. Note the acid containment system under the batteries in photo 1. There are no generally available, certified/listed battery containers or battery boxes. For the smaller systems, it has been found that heavy-duty polyethylene toolboxes provides sufficient acid containment and also, with lockable tops, meet code requirements to prevent unqualified people from accessing the electrically energized battery terminals [690.72(B)(2)]. See photo 3.

  

Photo 3.  Flooded lead acid batteries in polyethylene containers

Location, Location, Location

In small and medium sized PV systems, the batteries operate at a nominal 12, 24, or 48 volts. To minimize voltage drop in the cables at the typical high operating currents, batteries are generally installed as close as possible to the loads that they serve. In PV systems these loads are usually a utility interactive inverter or a stand-alone inverter. In many cases, particularly in stand-alone systems, a power center is used which provides a central location for overcurrent protection, disconnects, and charge control functions. Even in the best of circumstances, it is generally not possible to mount and connect an overcurrent device or a disconnect any closer to the battery terminals than three or four feet.

Battery disconnects and overcurrent protection (either fused disconnects or circuit breakers) should not be installed very close to the batteries or inside any battery enclosure due to the potential evolution of hydrogen gas, which, when mixed with air can become an explosive mixture. Also the sulfuric acid fumes released from flooded lead acid batteries will be corrosive in nature and electrical components, other than properly protected cables, should not be in close proximity to these batteries (110.11).

When the batteries are located more than 4 – 5 feet from the utilization equipment, in a different room from the utilization equipment, or the cables must pass through a wall, those cables should be in conduit. The conduit should originate as close to the battery terminals as possible or at the battery container and then be routed all the way to the power center or other utilization equipment.

Cable Types and Sizes

THHN, RHW, THW and other commonly available cables listed in Chapter 3 of the code are acceptable for battery installations. Most commonly available plastic (thermoplastic) or rubber insulated (thermoset) cables are considered acid and moisture resistant.

The use of cables manufactured with type AWM or MTW conductors may not be accepted by AHJs because they are not typically used in fixed, code-compliant wiring systems.

Normal Class B and C stranded conductors can be used with certified/listed equipment that has the correct wire bending spaces. See NEC Chapter 9, Table 10. Unfortunately, not all equipment used with battery systems has been certified/listed and that equipment may have inadequate wire bending space. This has caused many installers to use a fine stranded, flexible cable-like welding or automotive battery cable; and these cables do not comply with NEC requirements for fixed, non-mobile, battery installations. Code-compliant cable types such as THHN, RHW, and THW are available in fine stranded, flexible configurations. However, the use of fine stranded flexible cables may pose termination issues. See NEC 110.14, 690.74, photo 4 and "Perspectives on PV” in the January–February 2005 IAEI News.

  

Photo 4. Class B stranded cables, top;  fine stranded cables, bottom 

Note a slight problem in the Code in 690.74. Single-conductor flexible cables are generally not available certified/listed for hard service duty. To be corrected in 2017.

Some "manufactured” battery cables may not have the proper terminals where fine stranded flexible cables have been used and are questionable even when a code-complaint cable type has been used. Without the proper terminations, the cables may fail at the terminations at some later date.

The cables must be sized based on the continuous current requirements that will be based on charging currents from either the PV array or an inverter/charger or on discharging currents, usually to the inverter. Depending on the system design, there may be more than one circuit connected to the battery – one circuit for charging, and one circuit for discharging. Where there is a single circuit used for both charging and discharging, the cable must be sized on the largest continuous current in either mode. Although the Code typically requires that conductors be sized and protected based on continuous (3 hours or more) loads, battery based systems may require a slightly different approach. With stand-alone, off-grid inverters, the inverters have a substantial capability to surge currents above their steady-state rating for periods of minutes to an hour, and this may create voltage drop in the cables that poses operational problems. In this case, voltage drop calculations must also be made to ensure that the inverter will operate properly under all conditions of continuous use and surges.

Battery banks connected with sets of series-connected cells or batteries and parallel sets of cells or batteries should be wired so that the length of cables (and the resulting resistance) would be the same for each series connection to minimize charging and discharging current and voltage imbalances and premature cell/battery failure. See figure 1.

  

Figure 1.  Series-parallel battery connections. Note: Current travels through equal lengths of conductors in each of the series paths. Battery cables should be the same size and length in each path. All terminations should be identical. Credit Trojan Battery Co.

Overcurrent Protection

Batteries can source high fault currents. It is somewhat difficult to obtain specific short-circuit current data on batteries and even more difficult to determine what those short-circuit currents may be at the output of the battery bank which may consist of numerous series and parallel connected individual batteries. Tests and estimates made several decades ago indicate that for typical residential and small commercial battery banks, the inter-cell/inter-battery connectors, the battery cables, the contact resistances, and other factors will typically limit the available short-circuit current at the output of the battery bank to less than 15,000 A. Therefore, any overcurrent device protecting these cables should have an interrupt rating of at least 15,000 A. Both dc rated fuses and dc rated circuit breakers with that rating are available.

DC rated, current-limiting fuses are commonly available and will provide some protection for downstream components. DC rated circuit breakers, on the other hand, have little or no current limiting capabilities. Any equipment in the dc battery conductor path should have sufficient short-circuit interrupt capabilities where circuit breakers are used.

Normally, in small residential and small commercial battery banks, the individual strings (series connected cells/batteries) of batteries are not fused. Series and parallel connections are made within the battery bank and then the overall output is provided with overcurrent protection. This would generally indicate that the cables within the battery bank be able to handle the entire current of the battery bank (and not be sized to handle just a proportional part of the total battery current). In parallel connected sets of batteries or cells the individual cells and batteries may not age at the same rate and the currents may tend to be higher in some of the series connections than in others. For that reason, it is somewhat difficult to fuse individual strings of batteries because they may be required to carry more and more current as other strings of batteries age and carry less current. Also installing an overcurrent device inside the battery bank on a single string or several strings poses both maintenance and potentially explosion hazards.

In larger battery installations (where room size battery banks are involved) individual strings of batteries or cells may have a fused disconnect on each string. That fused disconnect must be located in an area that allows easy access and is not subject to hydrogen gas/sulfuric acid fumes. The size of the conductors for each battery string and the overcurrent device rating require careful consideration because of the potential for unequal currents in the battery series circuits as the battery bank ages.

Part VIII of NEC Article 690 has numerous requirements that are relatively clear that apply to battery installations.

Proper maintenance of the battery banks is the key to maintaining battery longevity and keeping the various currents balanced.

The batteries are able to generate more short-circuit current than the typical charging source and there should be an overcurrent protection device near the batteries. The overcurrent device has to be sized at least at 125% of the continuous current (either charge or discharge, whichever is greater) and if the charging currents are greater than the discharging currents, an overcurrent device may be required at the charging source.

A disconnect may be required at the battery to not only service the fuse (a circuit breaker includes the disconnect), but also to provide a method of disconnecting the battery circuit from other connected devices.

Fuses that bolt directly to the battery terminals are generally not acceptable in code-compliant installations because they are very difficult for unqualified people to service on the always-energized battery terminals.

Summary

Plan reviewers and inspectors should check battery installations for substantial mechanical installation, correct cable types and sizes, proper placement and rating of overcurrent devices and disconnects, good conduit installation techniques, and proper ventilation.

For More Information

The author has retired from the Southwest Technology Development Institute at New Mexico State University, but is devoting about 25% of his time to PV activities in order to keep involved in writing these Perspectives on PV articles in the IAEI News and to stay active in the NEC and UL Standards development. He can be reached, sometimes, at: e-mail: jwiles@nmsu.edu, Phone: 575-646-6105

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

It should be updated to the 2008 and 2011 NEC before the 2014 NEC arrives.


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PV and the 2014 National Electrical Code

Posted By John Wiles, Monday, July 01, 2013
Updated: Thursday, June 20, 2013
The 2014 National Electrical Code is just around the corner and many states will be automatically adopting it on January 1, 2014. There are numerous changes in Articles 690 and 705 that apply to photovoltaic (PV) power systems. Here is an advanced look at highlights of material that potentially will be in the code based on the 2014 NFPA/NEC Report on Comments (ROC).

Article 690

690.2 Definitions.

DC to DC Converters are defined but little information will be found on how they are to be installed. The AHJs and the installer will have to rely on the instruction manual for these listed devices and NEC Section 110.3 B.

Various types of combiners such as source circuit combiners and re-combiners and other types of dc combiners have been combined into one definition: Direct-Current (dc) Combiner.

A Multimode Inverter is defined and this device will be appearing in the ever-increasing numbers of battery-backed-up, utility-interactive systems.

 

690.4 General Requirements.

The identification and grouping requirements have been moved to section 690.31. DC-to-DC converters have been added to the listed equipment requirement. Bipolar PV systems are required to have a warning concerning overvoltage on equipment if the grounded conductors are disconnected.

 

690.5 Ground-Fault Protection.

These devices are now required to recognize ground faults in intentionally grounded conductors, and they are now required to be listed.

 

690.7 Maximum Voltage.

The 600-V limit in one- and two-family dwellings has been raised to 1000 V.

For energy storage devices, significant details of the requirements for disconnects and overcurrent protection have been added.

 

690.9 Overcurrent Protection.

Circuits connected to current-limited sources such as PV modules and utility-interactive inverters shall be protected from overcurrents at the source of those overcurrents, usually external sources. The rating of overcurrent devices now must consider terminal temperature requirements and operation in environments over 40° C. Overcurrent devices listed for PV applications shall be required in the dc PV circuits. In ungrounded PV arrays, overcurrent protection must be installed in each undergrounded conductor where circuit overcurrent protection is required.

Transformers connected to the output of utility interactive inverters with a rating the same as the utility interactive inverter are not required to have overcurrent protection from the inverter output.

 

690.12. Rapid Shutdown of PV Systems on Buildings.

This new section requires a shutdown system that is to be used by first responders/Fire Service personnel that can shut down all PV circuits on or in a building within 10 seconds of activation. The controlled conductors after the shutdown must not have any more than 30 V or 240 VA between any two conductors and any conductor and ground. Energized conductor lengths inside the building will be limited to 1.5 m (5 feet) and no more than 3 m (10 feet) from the PV array outside the building,

Specific implementation details are not included in the code. However, we can expect that the remote disconnect will be in a readily accessible location, clearly marked on the outside of the building and will probably be near the existing utility revenue meter. Circuits that will be impacted include module outputs, string outputs, combiner outputs, inverter outputs, and the dc input circuits on inverters which may be energized for up to five minutes. Energy storage devices, such as batteries, associated with the PV system will also have to be disconnected.

 

Section III. Disconnecting Means.

The contents of sections 690.13; 690.14; 690.15 and 690.17 have been revised and merged with 690.14 removed. Most requirements remain the same. DC combiners located on the roofs of buildings will have a load break rated disconnecting means in the combiner or within 1.8 m (6 feet). The disconnect may be controlled remotely but must have a manual operation function.

 

690.17 Disconnect Type.

PV disconnecting means can be power operable with a manual operation function. A number of specific disconnecting means are now shown in the code.

 

690.31 Methods Permitted.

Conductors and wiring that are part of a listed system are now acceptable.

Inverter outputs may no longer be grouped in the same raceway as the PV source or PV output circuits unless there is a partition in the raceway (photo 1).

 

 Photo 1. Those raceways must have an internal partition to separate dc PV source conductors from ac inverter output conductors..


Single conductor cables listed and labeled as PV cables or PV wire are permitted in cable trays even though they are not marked for cable tray use. They must be supported at intervals not to exceed 300 mm (12 inches) and must be secured at intervals not to exceed 1.4 m (55 inches).

Multi-conductor cables Type TC-ER or USE-2 may be permitted in outdoor locations connected to the output of PV inverters where the inverters are not mounted in readily accessible locations.

Additional requirements for markings on the dc PV circuits inside and outside of buildings has been added and specifications on the types of markings will be found in this section.

Significant portions of 690.4 regarding circuit routing and grouping have been transferred to this section.

 

690.35 Ungrounded Photovoltaic Power Systems. Ground-Fault Protection.

The ground-fault protection equipment must now be listed.

 

690.41 System Grounding.

The section has been revised to indicate grounding requirements for various types of systems.

 

690.45 Size of Equipment Grounding Conductors.

Shortened due to the fact that all systems must have ground-fault protection now.

 

690.47 Grounding Electrode System.

(B) Direct-Current Systems.

The AC equipment grounding system may now be used to provide equipment grounding for ungrounded dc systems.

 

690.47(D) Additional Auxiliary Electrodes for Array Grounding.

This section returns from the 2008 Code after being removed from the 2011 Code and now has slight modifications for clarity.

 

690.53 Direct Current Photovoltaic Power Source.

Systems with multiple dc outputs shall have the output currents marked for each of the outputs.

 

690 Part VIII. Storage Batteries.

690.71 Installation.

(H) Disconnection Overcurrent Protection.

This new section establishes a number of significant requirements for disconnecting means and overcurrent protection for battery circuit output conductors (photo 2).

Photo 2. Battery disconnect adjacent to battery enclosure

 

690 Part IX. Systems over 1000 V.

This section has been revised from 600 V to 1000 V and a section 690.81 has been added indicating that listed products should be installed in accordance with the listing.

 

690 Part X. Electric Vehicle Charging.

This section primarily refers to other sections of Code dealing with electric vehicle charging.

 

Article 705

Section705.12(D) has had numerous revisions that will clarify previous code requirements and change several relating to the point of connection for utility interactive inverters on the load side of the service disconnect. These revisions will require an entire article to cover completely and that article will be in a forthcoming IAEI News (photo 3).

It appears that multiple inverter systems will require a combining panel so that there is a single AC output of the PV system to meet the dedicated point of connection requirements in 705.12(D)(1). How this affects large physical plants where the buildings (and PV systems) are scattered out or a large single building like a shopping mall with multiple PV systems is unclear.

705.12(D)(3)(d) allows connections to multi-ampacity bus works and center tapped panel boards where designed under engineering supervision that includes fault studies and busbar load calculations.

 

705.12(D)(6) will require listed ac AFCI protection for utility-interactive inverter outputs using exposed wire harnesses or cable operating at 240 V, 30 A, or less.

 

705.31 Location of Overcurrent Protection.

This new section requires that the overcurrent protection for conductors for a supply-side utility interactive inverter connection be at the point of interconnection or within 3 m (10 feet) of that point.


 Photo 3. Clarifications coming for load-side connections.

705.100 Unbalanced Interconnections.

(A) Single Phase.

Single-phase inverters connected to three-phase power systems shall not result in unbalanced voltages exceeding 3%.


Summary

Remember, the above information is based on the ROC and is not the final Code. Changes may occur and the published Code is the final authority. In upcoming articles, various sections of the 2014 NEC will be addressed in greater detail.

For More Information

The author has retired from the Southwest Technology Development Institute at New Mexico State University, but is devoting about 25% of his time to PV activities in order to keep involved in writing these Perspectives on PV articles in the IAEI News and to stay active in the NEC and UL Standards development. He can be reached, sometimes, at: e-mail: jwiles@nmsu.edu, Phone: 575-646-6105

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

It should be updated to the 2008 and 2011 NEC before the 2014 NEC arrives.


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Tags:  Featured  July-August 2013  Perspectives on PV 

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Gray Areas in PV and the Code

Posted By John Wiles, Friday, April 26, 2013

Gray Areas, Yours and Mine

The National Electrical Code, even though it is now almost 900 pages long, cannot specifically define every particular piece of equipment and every installation requirement for that equipment. There are always going to be areas that are left to the interpretation of the local inspector (the AHJ). This article will cover four gray areas that I get calls on and, perhaps, generate some discussion that may lead to clarifications. Send me your comments and your feelings about how the Code is either grayer or less gray and perhaps we will cover them in a future article.

Gray Areas, Yours and Mine  The National Electrical Code, even though it is now almost 900 pages long, cannot specifically define every particular piece of equipment and every installation requirement for that equipment. There are always going to be areas that are left to the interpretation of the local inspector (the AHJ). This article will cover four gray areas that I get calls on and, perhaps, generate some discussion that may lead to clarifications. Send me your comments and your feelings about how the Code is either grayer or less gray and perhaps we will cover them in a future article.      Photo 1. Couldn’t find the dc PV disconnect. What do you mean, the sun has to set?  Service Disconnect and PV Disconnect  This has long been one of my favorite gray areas in the Code. Section 230.70(A)(1) has the following requirement for the service disconnecting means.    

 Photo 1. Couldn’t find the dc PV disconnect. What do you mean, the sun has to set?

Service Disconnect and PV Disconnect

This has long been one of my favorite gray areas in the Code. Section 230.70(A)(1) has the following requirement for the service disconnecting means.

"230.70(A)(1) Readily Accessible Location. The service disconnecting means shall be installed at a readily accessible location either outside of a building or structure or inside nearest the point of entrance of the service conductors.”

690.14(C)(1) has a similar requirement for the dc PV main disconnecting means.

"690.14(C)(1) Location. The photovoltaic disconnecting means shall be installed at a readily accessible location either on the outside of a building or structure or inside nearest the point of entrance of the system conductors.”

Now let’s go to the definitions in Article 100 and look up the definition of readily accessible.

"Accessible, Readily. Capable of being reached quickly for operation, renewal or inspection without requiring those to whom ready access is requisite to climb over or remove obstacles or to resort to portable ladders and so forth.”

AC Service Disconnect. Fire Service personnel responding to fire emergencies have a requirement to access the service disconnect to turn off the ac power to a building or structure to ensure safety where water and axes are being used.

One would assume that a locked door is an obstacle that must be removed to access a service disconnect located inside a building. I question whether or not the installation of the service disconnect inside a locked building meets the definition of readily accessible. With half of the residential service disconnects located inside the home and the other half located outside of the home, we seem to have a gray area.

An all too common situation occurs when a residence is on fire. The ac service disconnect is behind locked doors. The Fire Service maintains that they have master keys to many locks. And when confronted with high security locks, they bring out their universal master key, the fire axe. However, entering a burning building with power still in the building is not conducive to maximum safety.

Normally, the Fire Service will request the local utility to quickly respond and remove power from the building by opening a disconnect somewhere in the distribution system. However, when the power company cannot respond quickly enough in emergency situations, the Fire Service can and will remove the utility meter from the outside of the building thereby disconnecting the AC power to the structure. The Fire Service is usually reluctant to do this because of perceived hazards in this action and the fact that the meter socket and service conductors are still energized on or in the vicinity of the structure.

In many jurisdictions, the local codes and utility requirements dictate that all ac service disconnects on new construction be installed on the outside of the building near the meter location.

While there are ways to disconnect the ac power from a building or structure, it appears that this is a gray area in the Code. What about the dc PV disconnect?

DC PV Disconnect. The dc circuits from a PV array on the roof entering a building or structure do not have a meter that can be removed when the dc disconnect is located inside the structure. This gray area gets a little grayer when other sections in Article 690 are examined. The exception to 690.14(C)(1) of the Code makes things even a little more confusing. Where the dc PV conductors are installed in a metallic raceway, the dc PV disconnect does not have to be located near the point of entry and apparently can be located anywhere inside the building (except in a bathroom), but the disconnect must still be readily accessible. See photo 1.

DC Battery Disconnect. And there is an (increasing) number of battery-backed-up utility-interactive PV systems as well as many off-grid PV systems that have the ac circuits supplied by an inverter that is, in turn, supplied by a battery bank. What is the disconnect requirement for that battery disconnect and where is it to be located?

Help in 2014? For PV circuits, it would appear that the 2014 National Electrical Code might provide some clarification (or at least, other requirements) in this area. It is likely that a Fast Response disconnect will be required for these energized PV circuits on and in a building and the implication is that the Fire Service will have access to some sort of a remote controlled disconnecting means that will de-energize most of the PV circuits on or in a building or structure from an external location. However, for the time being it appears that these areas are still gray and have been for a very long time.

Placards and Directories. Although not directly addressing the accessibility issue, placards and directories help the first responders in locating all of the required disconnects. Sections 690.54, 690.55, 698.56, and 705.10 address these requirements. See photo 2.

 Photo 2.   Placard showing external ac PV disconnect and dc battery disconnect in garage.

Photo 2.   Placard showing external ac PV disconnect and dc battery disconnect in garage.

Grouping

Another gray area is the definition of grouping. In several sections of the Code, disconnecting means are required to be "grouped.” These requirements appear in 690.15; 690.14(C)(4); 230.71; 230.72 and other sections. Grouping is not specifically defined in the Code. Some inspectors maintain that the distance between the grouped disconnects is as far as you can reach with outstretched arms. Others consider grouping to mean within sight and, of course, within sight from is defined in Chapter 1 of the Code. A gray area: Should the dc PV disconnect be grouped with the ac service disconnect for the building? And, if so, how far apart can they be? See photo 3.

 Photo 3.  Nicely grouped ac and dc disconnects

Photo 3.  Nicely grouped ac and dc disconnects

The Fence. Here is an example that I hear about several times a year. The inverter does not have an internal ac disconnect or the local jurisdiction or utility requires an external disconnect. NEC Section 690.15 requires a maintenance disconnect grouped with the inverter for obvious reasons. In many cases, where the inverter is located adjacent to the load center for the building, the backfed breaker in the load center can be used as the required disconnect. They are within arms length and it is easy to verify that the breaker is off when the inverter needs maintenance. Unfortunately, for some reason, frequently the inverter is mounted on a wall with a fence separating the inverter location from the wall-mounted ac load center containing the backfed breaker. Usually, the fence has a gate in it and when the gate is open the breaker is visible from the inverter vocation. But, when the gate is closed, the breaker cannot be seen from the inverter.

In some cases the gate is always closed to keep a dog in the backyard. In another example, the gate would normally swing shut by itself. And in some cases, the gate could be latched in the open position. This is a gray area requiring an AHJ decision. See photo 4.

 Photo 4. Oops, ac disconnect on other side of the wall

Photo 4. Oops, ac disconnect on other side of the wall

Expected Lowest Temperature

The Problem. PV designers and installers face a dilemma when designing PV systems. PV module voltages and string (the series connection of modules) voltages increase as temperatures go down, and they decrease as temperatures go up. The PV inverter is able to accept only a certain range of voltages. In hot weather the string voltage must be high enough to operate the inverter properly and, of course, associated with the lower module voltage is less module/string/array power. The designer wants to put as many modules in series for each string as possible to maximize power output and to keep the inverter operating properly in hot weather. However, in cold weather voltages increase and if they increase too much they may exceed the upper limit of the inverter and the upper voltage limit of the modules, the wiring, and other equipment.

The Gray Area. NEC Section 690.7, Maximum Voltage, requires that the maximum photovoltaic system voltage be determined and the requirement is to determine that voltage at the lowest expected ambient temperature. The gray area of interest: What is meant by the term lowest expected ambient temperature?

It is possible that the temperature may drop to a point where the voltage of the modules and the string of modules rise above the voltage rating of the modules, the voltage rating of the cables, or the voltage rating of other connected equipment? The open-circuit voltage (Voc) of the string is the voltage of concern. That voltage may be higher than the normal rated maximum power point voltage of the module or the string (Vmp), and may exceed the maximum voltage rating of equipment in the system.

Operating Modes. In a properly functioning PV system, the dc electrical system is rarely subjected to open-circuit voltage (Voc). As the array voltage comes up in the morning when the sun rises, the inverter will sense the increasing voltage and when the voltage is high enough to energize the control circuits, the inverter will start power tracking and will hold the array dc voltage at the peak power point (Vmp), which will be substantially below the open-circuit voltage. In most cases in the morning the current will be very low and no significant amounts of energy will be generated.

The only time that the inverter and the wiring on the dc side will see open-circuit voltage is when the dc disconnect is opened and then closed or the inverter is turned off or the inverter loses ac power.

All listed equipment is tested at twice the rated voltage +1000 V as a high potential test. For a 600 V module and 600 V wiring the test is 2200 V. Modules and wiring will normally not be damaged if operated slightly above the maximum rated voltage, although this would be a code violation [110.3(B)].

However, inverters are not as robust, and I personally have damaged a 600 V rated inverter at 604 V. This is the area of concern: Will cold weather subject the dc input of the inverter to a voltage above its rated value (frequently 600 V)? Be advised, some inverters have a maximum voltage of only 500 V or 550 V. It always pays to read the manual.

Multiple Events. In the real world, the following conditions have to occur simultaneously in order for the inverter to see voltages above maximum rated voltage. The temperature has to be at or below the expected low temperature being used in the calculation of Voc; there has to be sufficient light on the PV array (and that does not require direct illumination by the sun); and the dc disconnect must be opened and closed, or the inverter turned off, or the ac power disconnected or not present.

The lowest temperatures occur in the early morning hours and since the PV array has cold soaked all night long, it will be at that temperature for some period of time after the minimum temperature occurs. Also, on clear nights you have night-sky radiation that will lower the temperature of the PV array a few degrees Celsius (2 or 3 degrees) below the measured low ambient temperature.

In these early morning hours, there will usually be very little if any module heating because the sun is not directly shining on the PV array. Indirect sky illumination and cloud-scattered illumination may be sufficient to bring the module voltage up to full rated Voc for that temperature.

Also, there can be very cold, windy days in bright sunshine where the wind removes all heat from the PV modules and if the circuit is interrupted and then restored, the inverter can be subjected to a high Voc.

So, there is a probability function involved with these occurrences that will be very difficult to estimate. Also the record low may not be ever seen again in the area or, on the other hand, future variations in temperature may exceed that number.

But the Unexpected Happens. In warm, sunny Las Cruces, NM, where I live, most PV systems are designed for an expected low of 14–15°F. However, in February 2011, the temperature went down to -2°F for several days with rolling power blackouts that kept turning the numerous installed PV inverters OFF and ON. Fortunately, the blackouts did not occur until late afternoon and the PV arrays had been heated by the sun to temperatures in the 40–60°F ranges, resulting in open circuit voltages significantly below the rated voltages of the equipment. See photo 5.

Pick a Source. In choosing an expected lowest temperature, several methods are available—none explicitly required by the NEC. Another gray area for the AHJ.

A conservative estimate would be to use the local weather data to get the record low. This information is available from various sources on the web as well as www.weather.com. The ASHRAE Handbook—Fundamentals has data low temperatures that gives the frequency of the temperature variations that occur in a given area (Informational Note: 690.7). Also, the local weather station can provide the last 10 years of weather data and this data can be used to determine the average low and the trend on those low temperatures.

AHJ Decision? Some AHJs and jurisdictions require that the record low be used. Maybe they are not sure that Global Warming exists. Other AHJs allow the systems installer/designer to pick the expected low temperature and justify it.

  Photo 5. Unexpected very cold weather

 Photo 5. Unexpected very cold weather

DC-to-DC Converters

Several dc-to-dc converters are already on the market and more will be coming in future months. Most of these are separate boxes that are attached to the module leads and the output conductors are connected in series to make a string of modules. However, at least one, and possibly more, of these dc-to-dc converters will be installed directly in or replace the module junction box on the back of the PV module. See photo 6.

 Photo 6. Smart Module by Tigo Energy.

Photo 6. Smart Module by Tigo Energy.

In most cases, these dc-to-dc converters decouple the output of the module from the circuit going to the inverter. And each of these dc-to-dc converters has different characteristics with respect to the ratings of input and output circuits and the amount of isolation or decoupling from the module output. The NEC, even in 2014, will have few details on how these dc-to-dc converters must be installed.

It will not be possible to use sections 690.7, 690.8 and 690.9 which are based on module output characteristics to determine how these devices are to be treated in a PV system. At this point it appears that the only way the inspector has to deal with them is to use NEC Section 110.3(B). Each of these certified/listed products must be installed in a manner consistent with the instructions provided with the products. And unfortunately, there are going to be gray areas in those instructions and in the lack of specific requirements in the Code—or possibly due to existing requirements in the Code.

As an example: a dc-to-dc converter may have a maximum output of 60 V, and up to 15 of these converters may be connected in series to make a string. However, the interaction between the converter and the required matching inverter in the system restricts the maximum string voltage to 500 V by restricting the output of each converter to 40 volts. But here is the gray area: 15 x 60 = 900 V. Applying normal code procedures and requirements would tend to require that 900 V or 1000 V conductors and equipment would be needed. However, the instruction manual accompanying this listed device says that the "smart” inverter has been evaluated as a system with the dc-to-dc converter to fully maintain the correct voltage on the system in a safe manner and that the system has fail safe features that will ensure that the string voltage is never higher than the equipment limit.

Now and more so in the future, inspectors will have to read and become totally familiar with the installation manuals of current and new equipment. Only in this way, can the inspection community ensure the safety of the public.

Summary. Gray areas: Keeping life interesting for the inspector.

For More Information

The author has retired from the Southwest Technology Development Institute at New Mexico State University, but is devoting about 25% of his time to PV activities in order to keep involved in writing these Perspectives on PV articles in IAEI News and to stay active in the NEC and UL Standards development. He can be reached, sometimes, at: e-mail: jwiles@nmsu.edu, Phone: 575-646-6105

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 It should be updated to the 2008 and 2011 NEC before the 2014 NEC arrives.

Tags:  May-June 2013  Perspectives on PV 

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Batteries in PV Systems

Posted By John Wiles, Friday, March 01, 2013
Updated: Wednesday, February 13, 2013

Electrical power outages are becoming more common in recent times with man-made and natural disasters, and the aging utility infrastructure. With natural disasters such as Hurricane Sandy, tornadoes, and other severe weather conditions, many people who are already using photovoltaic (PV) systems and many that do not have PV systems are going to be interested in utilizing PV systems in the event of electrical power outages. The electrical inspector can expect to see increasing numbers of battery-backed-up, utility-interactive photovoltaic power systems.

PV Plus Batteries Means Power When the Utility Goes Out

These backup systems allow the owners to operate some or all of the loads in the building using a specially designed and configured PV system with batteries in the absence of the utility service. These systems can be as small as a system that can power a radio or cell phone charger. They can also be as large as necessary to run all appliances and loads in a residence or commercial building. The size and number of electrical loads that can be operated and the period of time they can be operated depend on the size of the photovoltaic power system, the size of the battery bank, and the size of the specialized inverter.

Photo 1. Battery-backed-up, utility-interactive PV system during installation

There are characteristics of these PV systems with batteries that are different from those relating to the standard utility-interactive PV system. Obviously, the batteries pose some unique problems that the inspector must review and the connection of the inverters to not only the electrical system in the house but also to the utility requires looking at some different code sections than are normally used.

The multimode inverter that is used has characteristics of both the utility-interactive inverter and the standalone, off-grid inverter with features that are unique to the multimodal inverter. These inverters will be listed to UL Standard 1741. These inverters will have two sets of ac input/output terminals and a connection for the battery bank. Photo 1 shows the batteries and the multimode inverters in a system being installed.

Figure 1 shows the basic elements of a battery-backed-up, utility-interactive PV system. Green arrows represent dc power/energy flow and red arrows represent ac power/energy flow. Double-headed arrows represent bidirectional power/energy flow.

Figure 1. Components in a battery-backed-up, utility interactive PV system

DC-Coupled Battery Charging

There are two main types of battery-backed-up, utility-interactive PV systems. The first and oldest is what is called a dc-coupled charging system. As shown in figure 2, the PV array has a nominal voltage of 24 volts or 48 volts and normally operates through a charge controller to charge a battery bank. The battery bank is connected to a multimode, utility-interactive inverter and that multimode inverter is connected to the house loads and to the utility using two separate and distinct ac input/output circuits. When the utility is present, the PV system charges the batteries through the charge controller; and power is taken from the batteries (or directly from the PV system when the batteries are fully charged) through the multimode inverter where it is converted to ac power.

Figure 2. DC-coupled system interconnections and power flows

The designated protected (backed up) loads may be supplied by either the utility (when present) or the PV inverter output (supplied from the batteries when the utility is absent). Where the PV system power output exceeds the building loads, the excess energy is fed into the utility and renewable energy credits (REC) or net-metering benefits may be accrued. At night or at other times when the PV production is low, power for the loads is purchased from the utility and fed to the main loads through the main panel or through the multimode inverter to the protected loads. In general, the battery stays fully charged at all times but there are some systems in which the stored energy in the battery can be sent ("sold”) to the utility with proper programming of the equipment.

When the utility is not present, the PV array and battery combination and the multimode inverter continue to operate the loads connected to the protected loads subpanel to the extent that the size of the PV system and the capacity of the battery bank can supply the energy required by those protected loads. The multimode inverter will not send power to the main (unprotected) loads or to the utility connection but continues to monitor that utility connection for voltage and frequency. And, the main panel gets no power from any source. When the utility comes back online with the proper voltage and frequency characteristics, the multimode inverter will reconnect and the system becomes utility interactive once again. Photo 2 shows a dc-coupled battery charging system. The three charge controllers are on the right and the four inverters are in the center between the ac and dc distribution panels.

Photo 2. DC-coupled system

AC-Coupled Battery Charging

Figure 3 shows a more recent type of system, known as ac-coupled charging system, where the PV modules are usually configured in a high voltage string configuration (200–600 volts) and provide dc voltage to a standard utility interactive inverter. The output of the utility-interactive inverter(s) is connected to the protected load subpanel with a backfed breaker [705.12(D)] and that subpanel is connected to the load ac input/output terminals of the multimode inverter. The battery again is connected to the multimode inverter dc input/output. The utility is connected to its unique ac input/output on the multimode inverter and when the utility is present, it feeds through the multimode inverter generally keeping the batteries charged at all times and providing energy to the protected load subpanel. The utility interactive inverter sees the proper voltage and frequency supplied by the utility and continues to convert dc PV energy into ac energy that can be used by the loads (both protected and main) and also be fed to the utility. When the utility goes down or has a brown out (voltage and/or frequency variation), the multimode inverter senses this and stops sending power to the now unenergized utility lines (and the main load panel) but continues to monitor them for proper voltage and frequency, which would indicate that the utility is back online. At this time, on the load ac input/output of the multimode inverter, the battery supplies energy to the inverter and it will become the correct frequency and voltage reference source to supply not only the protected loads, but also to keep the utility interactive inverter connected to the PV system, operating and producing energy (in the daytime).

Figure 3. AC-coupled system interconnections and power flows

Again, the amount of loads that can be connected and operated for any short period or long period of time depends on the size of the PV array and the capacity of the battery bank. Typically the PV array may only supply energy for 4 to 6 hours per day. Loads obviously can operate 24 hours a day, so the total amount of PV array energy that can be stored in the battery and the capacity of the battery and size of the inverter determine how long the loads can be operated and how many loads can be connected at any one time.

Photo 3 shows an ac-coupled, battery-backed-up, utility-interactive system. The gray utility-interactive inverters are above the yellow multimode inverters and the batteries are in the rear of this very compact installation. There is normally a clear insulating service panel in front of the batteries; the panel was removed when the photo was taken.

Photo 3. AC-coupled system

In either case, with dc charging or ac-coupled charging of the batteries, the certified/listed multimode inverter ensures safety for the power line and utility personnel at anytime the utility is shutdown or operates abnormally.

Battery Considerations

Batteries, although not considered a source of energy, can store considerable amounts of energy. They should not be considered current-limited sources like PV modules are, but have the characteristics of a constant voltage output like an ac feeder with large amounts of available short-circuit current. Batteries must have overcurrent protection and disconnects on the output cables. The current between the battery and the multimode inverter is bidirectional. It flows to the batteries when the batteries are being charged by the multimode inverter or the charge controller, and it flows from the batteries when the multimode inverter is in the inverting mode supplying the protected loads with ac power.

In the dc coupled charging system, the cables between the charge controller and the battery are sized based on the rated output of the charge controller irrespective of the size of the PV system feeding it. These conductors should be sized at 125% of the rated output current of the charge controller. There should be an overcurrent device and a disconnect at the battery end of the circuit to protect these cables from high short-circuit currents originating at the battery. Depending on the location of the charge controller with respect to other components, there may be disconnects required on the input and output of the charge controller. A main PV dc disconnect located between the PV array and the charge controller will be required complying with 690.14.

Available short-circuit currents. The battery banks used in these types of systems typically will have an available short-circuit current at the output conductors from the battery bank less than 15,000 A. Cable lengths, connections, and cable resistances limit the available short-circuit current. Any overcurrent devices and/or disconnects must have ratings that can handle currents of this magnitude. Current-limiting fuses and dc rated circuit breakers are generally available with sufficient ratings and should be used.

Conductors. The conductors between the battery bank and the multimode inverter must carry bidirectional currents. The multimode inverter will use utility power or power from the utility interactive inverter in AC coupled systems to keep the battery charged and currents will flow from the inverter to the battery. When the multimode inverter is operating in the inverting mode and supplying protected loads with energy, the currents will flow from the battery to the multimode inverter. In general, the discharging currents flowing from the battery to the inverter will be larger than the charging currents flowing from the inverter to the battery. This is because the typical multimode inverter will be able to draw more current from the battery than it can provide to charge the battery. Therefore, the cables between the batteries and the inverter must be sized based on the maximum rated output of the multimode inverter in the inverting mode of operation. This continuous current should be specified in the inverter specification/installation manual and the cable sized at 125% of this continuous current. Of course, the battery cables should be in a raceway along with an equipment-grounding conductor, which would be used to ground any metallic battery rack and battery disconnect or overcurrent device enclosure. The size of the equipment-grounding conductor would be based on the rating of the overcurrent device protecting the circuit.

Many pre-manufactured battery cables are made with fine-stranded cables consisting of type AWM (appliance wire material) conductors. These cables are not suitable for use in battery PV systems since they are not mentioned directly in the National Electrical Code as one of the Chapter 3 wiring materials suitable for field installed wiring. The use of these manufactured cables is a gray area and could be considered an AHJ decision. And, in many cases automotive battery cables and welding cables have been used but these are typically fine stranded conductors which are very difficult to terminate properly at conventional disconnects and circuit breakers and they are not allowed in this application by the Code. See the find-stranded cable warning in Section 110.14 in the 2011 NEC. Also see the IAEI News article, "Do You Know Where Your Cables Are Tonight?” in the January–February 2005 issue.

Battery Circuit Overcurrent Protection and Disconnects. An overcurrent device should be located at the battery end of the circuit to protect this conductor from high available fault currents from the battery. This overcurrent device will be sized at 125% of the multimode inverter rated dc current in the inverting mode which is the same number used to size the cables. An overcurrent device at the inverter end of the circuit is normally not required because the inverter typically cannot source the same high fault currents that the battery can. A battery disconnect should be installed at the battery end of the circuit. Normally, if the inverter is within 4 to 5 feet of the battery bank, it is not practical or possible to put a disconnect any nearer to the battery than this distance. Therefore, the disconnect for this circuit can be near or at the inverter—usually in a power center. However, if the distance between the battery and the multimode inverter is more than 4 to 5 feet or the inverter is located in a different room than the battery bank, then there must be a disconnect at the battery end of the circuit in addition to the overcurrent protection required at that location. Photo 4 shows a battery disconnect/overcurrent protection enclosure using circuit breakers mounted just above a valve regulated (sealed) battery bank. These batteries release no hydrogen gas or acid fumes during normal operation.

Photo 4. Battery disconnect and overcurrent protection located near the batteries

Grounding. The nominal battery voltage in these systems is 48 V DC. The operating voltage may be as high as 62 to 65 V. Normally the multimode inverters do not ground one of the battery circuit conductors and the NEC requires that one of the battery circuit conductors be connected to earth with a grounding electrode conductor (690.41).

If the system uses DC coupled battery charging, the connection to Earth will be usually done through a distinct and separate ground fault detection/interruption system (GFDI) as required by NEC Section 690.5. In some cases the charge controller may have this GFDI built in.

On an AC coupled system the utility interactive inverters will have their normal GFDI internal circuitry, which will usually ground one of the PV array output conductors. But in the ac coupled systems, the dc battery circuit will still have to be grounded to keep costs down and to be compatible with available equipment that has been designed for use in grounded systems.

AC Circuit Considerations

Multi-wire branch circuits. Many houses today have several multi-wire branch circuits that have two branch circuits with a shared neutral conductor and are wired with a 14–3 AWG/with ground type NM cable. Multimode inverters come with either 120V AC outputs or 120/240V AC outputs. Neither of these multi-mode inverters should be connected to load circuits in the building that are part of a multi-wire branch circuit. See NEC 690.10(C). The inverters in the inverting mode, in some cases, may not be in synchronization with the utility power frequency waveform. This could cause overloading of the shared neutral that is associated with multi-wire branch circuits. If any of the circuits needing battery backup power protection are multi-wire branch circuits they should be segregated in their entirety (both circuits) in the special protected loads load center that is connected to the multimode inverter ac output.

Utility connections. One of the characteristics of most of the multimode inverters is that they can pass power from the utility through to the protected load circuits at a greater power level then they can supply power to the utility in the utility interactive mode. This indicates that the circuit and the overcurrent device, typically a breaker, between the utility connection and the multimode inverter must be rated at the full pass-through current capability of the inverter. A common value of this circuit breaker would be 60 or 70 amps. However, in the utility interactive mode, the inverter may only be able to source 33 amps from the PV system into the utility. In previous editions of the code, the 60 or 70 amp breaker would be used in the 705.12(D) calculations to determine panelboard/load center busbar ratings and conductor sizes. But, the danger to the circuit from overloading is related to the 33-amp output of the inverter when feeding the utility. Now, an exception to NEC Section 705.12(D)(2) allows the calculations for this requirement to be based on 125% of the rated utility interactive inverter output in the utility interactive mode. In this example, 41.25 amps (1.25 x 33) could be used in the calculations. And the circuit breaker connecting the inverter to the load center can still be rated at the higher 60 or 70 amps required to allow the protected loads to be operated in the pass-through mode of operation.

Summary

Aside from the battery circuits and the unique characteristics of the utility interconnection covered above, the multimode inverter in the battery backed up, utility-interactive PV system is connected to the utility in much the same manner as any normal utility interactive system. The dc PV circuits are connected in the same manner as those circuits in a standard utility interactive PV system for the ac coupled system. The dc-coupled systems require additional considerations for the low-voltage battery charging circuits.

For More Information

The author has retired from the Southwest Technology Development Institute at New Mexico State University, but is devoting about 25% of his time to PV activities in order to keep involved in writing these Perspectives on PV articles in the IAEI News and to stay active in the NEC and UL Standards development. He can be reached, sometimes, at: E-mail: jwiles@nmsu.edu Phone: 575-646-6105

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

It should be updated to the 2008 and 2011 NEC before the 2014 NEC arrives.


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Tags:  Featured  March-April 2013  Perspectives on PV 

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Unraveling the Mysterious 705.12(D) Load Side PV Connections

Posted By John Wiles, Tuesday, January 01, 2013
Updated: Wednesday, January 16, 2013

The requirements pertaining to the connection of utility-interactive photovoltaic (PV) power systems to the load side of the main service disconnecting means have been with us for years. In the earlier codes, the driver was 690.64(B) and now those requirements are found in 705.12(D).

Many AHJs are familiar with the 120% allowance on busbar and conductor size allowed by 705.12(D)(2). Less familiar is the 705.12(D)(7) requirement that must be met before the 120% can be applied.

We typically, but not always, apply these requirements to a load center (photo 1). And if the backfed PV connections do not meet NEC requirements in 705.12(D)(7), problems can arise. In this load center rated at 100 amps with a 100-amp busbar, four 15-amp backfed PV breakers have been added at the top of the load center adjacent to the main breaker. If the panel were filled with load breakers and the loads on the panel were increased (during daylight hours) to 160 amps (for example), the load center busbar could see 160 amps, somewhat in excess of its rating. No breakers would trip since the main breaker could supply 100 amps from the utility and the PV breakers could supply an additional 60 amps from the PV system for a total of 160 amps.

Photo 1. Load Center/Panelboard. Rated at 100 amps with 160 amps of supply breakers

Photo 1. Load Center/Panelboard. Rated at 100 amps with 160 amps of supply breakers

Before we look at the overall requirements. Let us focus on a few of the details and those details will need some explanation.

Many PV installers and a few AHJs do not understand the significance of the 705.12(D)(7) requirement. If this backfed PV breaker location requirement is not met, then the 120% allowance in 705.12(D) cannot be used and many PV systems could not be installed. But what is so important about the location of the backfed PV breaker in the panelboard/load center?

Look at the simplified one-line schematic of a 100-amp load center in diagram 1. For simplicity, only one busbar, ½ of a 2-pole main breaker and a set of 15- and 20-amp load breakers on that busbar is shown.

Diagram 1. Simplified load center diagram

Diagram 1. Simplified load center diagram

The busbar in this 100-amp load center is also rated at 100 amps. It should be noted that the total rating of the load breakers on this busbar will typically exceed the busbar and the main breaker rating in normal dwelling and commercial installations. In the example, the breaker ratings total 225 amps. Although there are both fixed loads and plug loads in a typical structure and the fixed loads are used in the NECChapter 2 load calculations, the plug loads are estimated, but are otherwise not constrained or restricted, at least until they reach the branch circuit breaker rating.

If the total load currents (45+35) on the panel stay below the 100-amp rating of the main breaker and the bus bar, they are "happy” (stay cool with no trips) as shown in diagram 2.

Diagram 2. Happy load center with total loads less than 100 amps

Diagram 2. Happy load center with total loads less than 100 amps

But as consumers, we must have that new 96″ wood lathe, that 130″ two-wall flat screen gaming system, two new color laser printers, the plug-in electric car and a few other toys. The loads on each branch circuit would typically stay below the breaker rating, but if one load does exceed the rating, that breaker will trip. See diagram 3.

Diagram 3. Circuit breakers protect branch circuits

Diagram 3. Circuit breakers protect branch circuits

While the individual loads may stay below 15 or 20 amps, the total could go to 120 amps when everything is running. In a short time, the 100-amp main breaker will trip and the busbar may get a little warm at the top, near the main breaker. But, the main breaker will protect the busbar and possibly the service conductors from over loading. See diagram 4.

Diagram 4. Total load currents exceed 100 amps and the main breaker trips, protecting the busbar.

Diagram 4. Total load currents exceed 100 amps and the main breaker trips, protecting the busbar.

Now in diagram 5, a 20-amp backfed PV breaker has been added to the first breaker position at the top of the load center adjacent to the main breaker. As shown, the loads may total 80 amps and 20 amps are supplied by the PV system and 60 amps from the utility. Nothing is overloaded and the components stay cool.

Diagram 5. No problems with this connection… yet.

Diagram 5. No problems with this connection… yet.

Now let’s assume that the total loads are 120 amps during the day when the sun is shining brightly, the PV breaker can supply 20 amps and the main breaker can supply 100 amps. Yes, I know that these breakers should only be handling 80% of rating, but bear with me for this example. None of the load breakers trip, the main breaker is happy, but the busbar is probably getting a little warm since it is carrying 120 amps just below that backfed PV breaker. I am assuming that the 15-amp breaker at the top right is not contributing to the load currents. See diagram 6.

Diagram 6. Loads increased, busbar overloaded

Diagram 6. Loads increased, busbar overloaded

Warm busbars that operate over their intended design temperature (40 degree Celsius(C) plus normal current heating) will not melt, but they may cause overheating and softening of the plastic insulators in the load center and those insulators may allow various current-carrying parts to touch each other or ground. The NEC requirements are intended to address this potential overheating issue.

Diagram 7. PV breaker located per 705.12(D)(7) so no current overloading of the busbar is possible.

Diagram 7. PV breaker located per 705.12(D)(7) so no current overloading of the busbar is possible.

In diagram 7, the backfed PV breaker is moved to the lower left position as far as possible from the main breaker. The PV breaker can supply 20 amps, the main breaker can supply 100 amps and the total loads can be as high as 120 amps. As before, no breakers will trip, but in this case, the currents from the PV breaker and the main breaker have nowhere to add together as they jointly supply the load currents. At most, any section of the bus bar will see only 100 amps, no matter where the loads are placed or occur on the busbar. Although not possible, visualize a 120-amp load could be placed in the first breaker position just below the main breaker. The busbar section between the 100-amp main breaker and the 120-amp load breaker circuit would carry 100 amps. The remaining 20 amps would come up the busbar from the 20-amp back fed PV breaker. If the 120-amp load were concentrated just above the PV breaker, the busbar would supply 100 amps from the main breaker and 20 amps from the PV breaker. In both cases, the busbar would see no more than 100 amps.

Diagram 8. Center-fed panel has no place for PV that will prevent busbar overloading.

Diagram 8. Center-fed panel has no place for PV that will prevent busbar overloading.

So this is the reason that 705.12(D)(7) requires that the backfed PV breaker be located as far away from the utility sourced breaker on the busbar or the conductor.

Center-Fed Panels Are a NO GO.

Unfortunately, center-fed load centers are common in many parts of the country.

In diagram 8, one busbar of a center-fed load center is shown. The 100-amp main breaker feeds the center of the 100-amp rated bus bar and the load breakers are arranged above and below (or sometimes horizontally to each side) of the main breaker. With this diagram, it is fairly easy to see that, there is no position on either the upper or lower busbar that will keep the currents from the PV breaker adding to the currents from the utility breaker on the portion of the busbar that is opposite the busbar where the main breaker is added. Of course loads on the half of the bus bar that has the PV breaker would normally absorb the current from the PV input before it could overload the other portion of the busbar. But, there will be times when the electrical loads are not evenly distributed and there is the possibility of busbar overloading when center-fed panels are involved. It is expected that the 2014 NEC will have a warning about the use of center-fed panelboards.

SUMMARY

The NEC language is sometimes difficult to read and understand. However, in many cases, like this one, the Code is based on sound engineering and establishes requirements that help to ensure the safety of the public. These PV connections can and must be done correctly. See Photo 2.

Photo 2. Panelboard with PV breakers in the correct location — opposite the main lugs.

 

Photo 2. Panelboard with PV breakers in the correct location — opposite the main lugs.

 

For More 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: 575-646-6105

See the web site below for a schedule of presentations on PV and the Code. Call the author if you would like to schedule a presentation.

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


Read more by John Wiles

This work was supported by the United States Department of Energy under Contract DE-FC 36-05-G015149

Tags:  Featured  January-February 2013  Perspectives on PV 

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PV Systems in Unusual Locations, To Inspect or Not?

Posted By John Wiles, Thursday, November 01, 2012
Updated: Wednesday, January 16, 2013

In the normal workday, inspectors may drive pass numerous PV systems that are not located on a dwelling or a commercial building and are in somewhat obscure, out-of-the-way locations. When these systems are noticed, the question arises, Should they be permitted and inspected?

Here are some examples of such systems.

Electric Gate Openers

PV-powered electric gate openers are becoming more common because they are reliable, easily installed, and do not require trenching a branch circuit from the nearest building to the possibly remote gate location. See photos 1, and 2. These openers have many different designs and may employ a battery to allow operation at night and during cloudy weather. Normally the products are sold as a kit and installed by the building owner, the fencing contractor or others. In some cases, an electrician is involved.

These systems, when powered by a PV module will involve field-installed wiring and connections. The voltages are usually 12 or 24 volts dc and the batteries are typically automotive-sized, deep-cycle batteries. The system components rarely comply with NEC requirements in terms of listed modules, listed charge controllers and code-compliant wiring, disconnect, overcurrent protection and grounding. The contents of the entire kit or the electrical components have not been certified/listed in most cases. The AHJ must make the call on whether time is available to inspect these systems and whether or not they should be permitted. Few, if any, would pass an inspection for compliance with the NEC.

Photo 1. PV-powered electric gate; no trenching required

Photo 1. PV-powered electric gate; no trenching required

Photo 2. PV-powered electric gate. Courtesy MightyMule/GTO

Photo 2. PV-powered electric gate. Courtesy MightyMule/GTO

Solar Hot Water Systems

Many solar hot water systems have been and are being installed throughout the country using a PV module to power the circulating pump. The combination of a PV-powered pump with a solar collector works well since bright sun results in more hot water and also causes the pump to run faster, transferring that hot water to the storage system. The PV module(s) can have a power of 10–30 watts and higher with voltages from 12 to 24 volts (nominal). See photo 3. Field-installed modules, pumps and controllers are used and, in most cases, the equipment is not listed or installed in compliance with NEC requirements. There are typically no considerations given to module grounding, proper disconnects and ground-fault protection. Conductors from the pump to the roof frequently do not meetNEC requirements for such circuits. Plumbing or combination inspectors should also examine the electrical circuits for compliance with NEC requirements.

Photo 3. Solar water collector and PV modules connected to the circulating pump

Photo 3. Solar water collector and PV modules connected to the circulating pump

Construction Signs and Crossing Lights

Long gone are the small diesel or gasoline engine-powered generators powering the warning signs at highway construction sites. PV modules and batteries have replaced those noisy, polluting power sources and these systems are used throughout the country. But the PV connection is not noticed since the PV modules are usually out-of-sight (photo 4). School crossing and speed signs are also being powered by a PV module or two because such a system is cheaper than running utility power feeders along the highways. And there are the red light cameras and radar speed traps that are PV-powered.

These systems are usually manufactured as a single device that is already assembled and is, in many cases, portable. There are no field connections to make and inspections are usually not justifiable.

Photo 4. PV-powered construction sign.

 

Photo 4. PV-powered construction sign.

 

PV-Powered Air Conditioning

While there have been a few dc PV-powered air conditioners on the market, Lennox Industries has been marketing their Dave Lennox Signature SunSource heat pump and air-conditioning systems for more than a year. These systems have a set of AC PV modules connected to the outdoor compressor unit and the AC PV modules act as a utility-interactive PV system supplying the outdoor unit and feeding power into the building wiring system. When the local loads are less than the PV ac modules output, the excess is sent to the utility. The systems are available for both residential applications (photos 5 and 6) and commercial applications (photo 7). The outdoor compressor units have a factory-installed PV power combiner panel installed that has the necessary overcurrent devices required byNEC Section 705.12(D) (photos 8 and 9).

Photo 5. Residential Lennox SunSource HVAC system. Courtesy Lennox Industries

Photo 5. Residential Lennox SunSource HVAC system. Courtesy Lennox Industries

Photo 6. Lennox XC-21 SunSource Air Conditioning Outdoor Unit

Photo 6. Lennox XC-21 SunSource Air Conditioning Outdoor Unit

Photo 7. Lennox commercial SunSource system. Courtesy Lennox Industries

 

Photo 7. Lennox commercial SunSource system. Courtesy Lennox Industries

 

The size of the AC PV module array will vary with the customer’s budget and desires. Usually, in the residential applications, a single string of modules on a 15- or 20-amp circuit will be connected to a circuit breaker of that rating in the PV panel on the outdoor unit. And within the limited available space, the number of modules can be expanded from 1 to 15–17 depending on rating of the circuit and the rating of the AC PV module (photo 10).

Yes, these systems involve electrical connections above and beyond electrical wiring of the installation for the HVAC unit, and they should be permitted and inspected. The ac wiring is usually routed from the modules though a utility-required, readily accessible lockable disconnect and then to the PV breaker on the HAVC outdoor unit. There is no dc wiring to contend with and the equipment grounding of the module frames and the attached microinverters is made at a single point of one of the modules since they are all electrically and mechanically bonded together.

Photo 8. Lennox XC 21 PV power input panel

Photo 8. Lennox XC 21 PV power input panel

Photo 9. Backfed PV breaker in power panel on outdoor unit

Photo 9. Backfed PV breaker in power panel on outdoor unit

Photo 10. Four AC PV modules installed with expansion room for more modules

Photo 10. Four AC PV modules installed with expansion room for more modules

Large Systems in Remote Areas

Numerous large (megawatt and up) PV systems are being installed in remote areas on otherwise unused land or even on the unused and available flat roofs of very large buildings (photo 11). These systems will use multiple inverters rated from 500 kW to two megawatts each. In the case of ground-mounted systems, a fence will usually surround the entire array and all equipment with locked access. Large arrays on a building will also have limited access.

Photo 11. One megawatt PV array on a single building

Photo 11. One megawatt PV array on a single building

At this point, the AHJ should review section 90.2 of the NEC to determine if this system comes under the requirements of the NEC. Large PV systems may be utility-owned, utility-operated and located on utility property and these systems are not required to comply with NEC requirements. A utility is defined and regulated by state law. However, many of these large systems are not owned or are not being operated by a utility on utility property. They are power purchase agreement (PPA) systems that are installed and operated by third parties. They must comply with the requirements of the NEC and any local codes. Although these systems are frequently referred to as being "behind the fence,” this term has no meaning in the NECand all NEC requirements should apply. Inspections of these larger systems may find numerous safety and code violations.

Summary

Time and funds in most jurisdictions are limited. The AHJ must evaluate the workload carefully and apply knowledge and inspection talents wisely to ensure the public safety. Not all PV systems can or should be inspected but those that can pose the most potential hazards should be high on the list.

For More 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: 575-646-6105

See the web site below for a schedule of presentations on PV and the Code. Call the author if you would like to schedule a presentation.

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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Inspectors Rejoice! At Last — Significant Progress in a PV Standard

Posted By John Wiles, Saturday, September 01, 2012
Updated: Wednesday, January 16, 2013

Most inspectors don’t have or have not read the UL Standards related to PV systems, because the standards are expensive and do not relate directly to the job of ensuring that listed PV modules and inverters are installed in a manner that meets the requirements of the National Electrical Code (NEC–NFPA 70). However, the requirements in the standards affect what the instruction manuals must say and those instructions guide the PV installer because NEC Section 110.3(B) requires that the instructions and labels on listed products must be followed. On May 8th of 2012, Underwriters Laboratories (UL) released a revised version of UL Standard 1703, the "Standard for Safety for Flat Plate Photovoltaic Modules and Panels.” This UL standard is also an American National Standard Institute (ANSI) approved as ANSI/UL 1703-2012.

The Standards Development Process

For each of the major standards that UL publishes, a Standards Technical Panel (STP) is established and the STP actually controls the content of the standard through a rigorous process known as the Collaborative Standards Development System (CSDS). The STP membership consists of a balanced selection of representatives from all areas of interest that are involved in the product that the standard addresses. The STP for UL 1703 has more than 50 members from PV module and material manufacturers, PV installers and systems designers, electrical inspectors and plan reviewers (including IAEI members), users, NFPA Code-Making Panel members, IBEW, laboratories, government agencies, universities, and a general interest area.

ll parts of the standard are continually reviewed, analyzed with respect to Code changes and new equipment developments and discussed. Anyone may make proposals for changing the standard. The proposals are circulated, revised, re-circulated and voted on by the STP members. Negative votes must be accompanied by suggested changes and all negative votes must be addressed. UL, as a member of the STP, has only one vote just like all other members.

Photo 1. Top of frame module mounting. Listing is valid only if the method is in the instruction manual.

Photo 1. Top of frame module mounting. Listing is valid only if the method is in the instruction manual.

The STP meets about once a year, but may be convened more frequently as the need arises.

Safe Installations

When equipment is manufactured according to the requirements in the standard and is evaluated by one of the National Recognized Testing Laboratories (NRTL), it can be then certified as complying with the standard and the product is put on a list showing that certification. This is the Certification/Listing process. In the NEC, PV modules, charge controllers, inverters, combiners and ac PV modules are required to be listed. Currently, the US Occupational Safety and Health Administration (OSHA) has recognized four of the numerous NRTLs as capable of certifying and listing PV equipment. They are UL, TUV Rheinland NA, Intertek (ETL), and CSA International.

Certified/listed equipment, when installed according to the requirements established by the NEC will generally result in a hazard free electrical installation.

What’s New for Inspectors and Plan Reviewers?

AHJs around the country have been aware for some time that consistency in the PV module instructions manuals has been lacking. These inconsistencies stem from a lack of preciseness in UL 1703 in the areas of module mounting, module grounding, and the way the rated short-circuit current and module open circuit voltage are to be used in the application of NEC requirements to the module installation. Module manufacturers have widely varying instruction manuals in terms of content and detail. They issue tech notes that address mounting and grounding the modules, but it is unclear whether or not these tech notes have been reviewed by the certifying/listing NRTL for compliance with the standard.

Photo 2. Improper module grounding has failed.

Photo 2. Improper module grounding has failed.

Modules are generally tested, labeled, and listed with four mounting holes that are to be used for bolting the modules to the mounting surface. However, many installers use mounting racks that use clips that fasten the modules to the racks by clamping the top of the module to the rack with these clips which generally are not located near the four mounting holes. See photo 1. A few module manufacturers have instruction manuals that specify that top clips may be applied at certain locations on the modules, but most do not have these instructions.

Grounding issues abound for plan reviewers and inspectors and many module grounding systems are failing around the country. See photo 2. Typically a module has four labeled grounding holes that have been tested to meet UL 1703 requirements for safe connection to earth through the equipment-grounding system. Again module instruction manuals and tech notes vary greatly in the level of detail associated with using the labeled grounding holes to ground the PV modules. A few manufacturers supply hardware that has gone through the UL 1703 testing and evaluation process with the modules. Some manufacturers specify locally procured hardware like star washers and nuts and bolts to ground modules. See photo 3. Others provide very sparse instructions on grounding. And the content of tech notes ranges from very good to very poor with respect to grounding.

Photo 3. Correct hardware?

Photo 3. Correct hardware?

Since the inception of UL 1703, the standard has required that each PV module instruction manual have statements requiring that the short-circuit current (Isc) and the open-circuit voltage (Voc) be multiplied by 125% before any NEC requirements were applied. The 125% on Isc was to address normal and expected high levels of irradiance up to 1250 watts per square meter that can occur in many areas of the country for three hours or more. The 125% factor applied to the rated Voc was to address the fact the module voltage decreases as temperature increases, and this factor accounts for modules exposed to temperatures as low as -40°C (-40°F). In 1996, during deliberations for the 1999 NEC, all parties including the PV Industry, UL, AHJs, and the Code-Making Panels at NFPA agreed that these 125 factors should be removed from UL 1703 and placed in the Code.

They were placed in the 1999 NEC in 690.7 (Voc) and 690.8 (Isc), but until this revision of UL 1703, they have remained in the standard. Of course, looking at NEC 110.3(B) that requires the instructions with the listed product to be followed that duplicated the requirements of NEC Sections 690.7 and 690.8 created a very poor situation for the AHJs and the installers. Do we duplicate those 125% factors, which have been required in both the instructions and in the Code?

Current Revisions to UL 1703 Have Clarified Several Areas

In general, it is evident that previous editions of UL 1703 have not provided sufficiently detailed requirements to the NRTLs to allow them or require them to properly evaluate the instruction manuals for the PV module in terms of NEC-compliance, mounting, grounding, and the specifications related to the electrical parameters.

Photo 4. Module fire rating valid for this mounting?

Photo 4. Module fire rating valid for this mounting?

The May 8, 2012 revision of UL 1703 has addressed several of these longstanding issues.

1. The NRTL must verify the contents of the manual and NEC-compliance.

These revisions now include a requirement that the certifying/listing organization verify that the contents of the instruction manual and any tech notes comply with the standard and do not violate any NEC requirements. Here are a few of the relevant revisions extracted from UL 1703:

48.1 "A module or panel shall be supplied with installation instructions describing the methods of electrical and mechanical installation. The instructions shall include the following in addition to any other information required by this standard:

c) "A list containing the date of the first edition of these instructions and the dates of any and all subsequent revisions, amendments, and tech notes related to these instructions.”

48.1.1 "The electrical installation instructions shall include a detailed description of the wiring method to be used in accordance with the National Electrical Code, ANSI/NFPA 70.”

48.7 "The contents of the instruction manual and subsequent revisions to the instruction manual shall be verified for compliance with this standard by inspection.”

2. The 125% factors have been removed from the module instruction manual.

48.5 "To allow for increased output of a module or panel resulting from certain conditions of use, the installation instructions for a module or panel shall include the following statement or the equivalent: "Under normal conditions, a photovoltaic module is likely to experience conditions that produce more current and/or voltage than reported at standard test conditions. The requirements of the National Electrical Code (NEC) in Article 690 shall be followed to address these increased outputs.”

3. A module not mounted in accordance with the instructions in the manual will no longer retain its UL 1703 listing. This emphasizes the NEC requirement in 110.3(B).

48.1(B) 2) "The module is considered to be in compliance with UL 1703 only when the module is mounted in the manner specified by the mounting instructions below.”

4. A module not mounted per the mounting instructions will invalidate the fire rating on the module. See photo 4.

48.1(B) 1) "The fire rating of this module is valid only when mounted in the manner specified in the mechanical mounting instructions.”

5. A module not grounded according to the grounding instructions in the manual and not in accordance with the labeled grounding points on the module will invalidate the listing on the module. See photos 5 and 6.

48.1(B) 3) "A module with exposed conductive parts is considered to be in compliance with UL 1703 only when it is electrically grounded in accordance with the instructions presented below and the requirements of the National Electrical Code.”

Photo 5. Right grounding point; wrong hardware and method.

Photo 5. Right grounding point; wrong hardware and method.

Those grounding instructions include the following:

48.1.1 a) "The grounding method to be used, and where a specific grounding device is supplied or suggested, the following statements:

1) "Where common grounding hardware (nuts, bolts, star washers, spilt-ring lock washers, flat washers and the like) is used to attach a listed grounding/bonding device, the attachment must be made in conformance with the grounding device manufacturer’s instructions.

2) "PV module manufacturers recommending such a method must either 1) thoroughly detail the attachment means in the module installation instructions or 2) refer the installer to readily available manufacturer’s instructions for the grounding/bonding device.

3) "Common hardware items such as nuts, bolts, star washers, lock washers and the like have not been evaluated for electrical conductivity or for use as grounding devices and should be used only for maintaining mechanical connections and holding electrical grounding devices in the proper position for electrical conductivity. Such devices, where supplied with the module and evaluated through the requirements in UL 1703, may be used for grounding connections in accordance with the instructions provided with the module.”

6. A PV laminate without a frame is not considered a listed module until it has been mounted with hardware that has been evaluated with the laminate under this standard or has been subject to a field evaluation by an NRTL.

4) "Any module without a frame (laminate) shall not be considered to comply with the requirements of UL 1703 unless the module is mounted with hardware that has been tested and evaluated with the module under this standard or by a field inspection certifying that the installed module complies with the requirements of UL 1703.”

7. The value of module series overcurrent device marked on the back of the module now has to be at least 1.56 times the Isc in order to comply with NEC 690.8.

47.10 "A module or panel shall be marked relative to the maximum electrical rating of an acceptable overcurrent protective device (for protection against backfeed). The statement on the module or panel shall include the following: ‘Maximum series overcurrent protective device, where required.’ ”

47.10.1 "The ampere rating of the maximum series overcurrent device shall be not less than 1.56 times the rated short-circuit current of the module and the rating shall be rounded up to the next higher available overcurrent device rating. The available ratings are 1–10 amps in one-amp increments, 1.5, 2.5, 3.5, 12 amps, 15 amps, and 20 amps. The rounded up rating of the series overcurrent protective device shall be used in the reverse current tests of 28.1.”

Photo 6. Modules being grounded correctly

Photo 6. Modules being grounded correctly

These revisions to UL 1703 should clarify the intent and requirements for installing PV modules in a PV system that is compliant with the requirements of the National Electrical Code. The revisions are dated 8 May 2012 and it may take a few months for the module manufacturers, the rack manufacturers and the grounding device manufacturers to work together to get the necessary testing done and to revise the instruction manuals.

Noncompliance with the requirements of UL 1703 or the requirements of the NEC will result in a system that cannot be legally installed in jurisdictions where the NEC is legislated into law. This includes the entire United States.

More Changes Coming

By the time you read this article, the UL 1703 STP will have approved more changes in the standard related to module grounding and module grounding devices. These changes and related changes in UL 2703 (PV Racking), UL 487 (Grounding Devices) and other standards will enhance PV module grounding, reduce the labor requirements, and also reduce the costs associated with grounding.

The PV installer and the inspector will be reasonably assured that a listed module can be installed according to the instructions provided with that module using the Code requirements to achieve a safe and durable electrical system.

For More 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: 575-646-6105

See the web site below for a schedule of presentations on PV and the Code. Call the author if you would like to schedule a presentation.

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.htm

This work was supported by the United States Department of Energy under Contract DE-FC 36-05-G015149


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Tags:  Featured  Perspectives on PV  September-October 2012 

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The Conductors, Getting Solar Energy to the Inverter for 40–50 Years

Posted By John Wiles, Sunday, July 01, 2012
Updated: Wednesday, January 16, 2013

Harsh Environment—No Maintenance

Getting Solar Energy to the Inverter for 40-50 YearsPV modules may be generating energy for 40–50 years after installation. While power production may not be what it was when the PV system was new, hazardous amounts of voltage and current will be still available from the PV array. The rooftop, outdoor environment is harsh. Unlike HVAC equipment, which requires periodic inspections and maintenance, PV modules and the rooftop wiring and equipment may not be examined for the life of the system.

Inspectors and plan reviewers need to be aware of the requirements for cables used in PV systems. They also need to know that the system longevity may impose stringent workmanship and materials requirements on the conductors in a PV system.

Conductors interconnect the modules to the PV direct current combiners (where used) and then to the disconnects, inverters, and eventually to the utility grid or other load. The outdoor environment the conductors are exposed to is one of the most strenuous for any electrical circuit found in premises wiring. In various parts of the country, module and source circuit conductors, both in and out of conduit are exposed to temperatures from -50°C (-58°F) to +80°C (176°F), continuous submersion in water (in some conduits), ice, wind, hail, snow, sand, and for conductors exposed to the sun, ultraviolet (UV) radiation.

For these conductors to survive in this environment for the module life of 40–50 years, the conductors must be properly selected and installed. Cables come in many types, sizes, and constructions and PV even has some unique cable types that are not available to other industries.

USE-2

For many years, USE-2 has been the conductor of choice (and metNECrequirements) for a durable cable that could be attached to the PV module and also field installed in the outdoor environment. It is suitable only for module and source circuit wiring on grounded PV arrays where one of the dc circuit conductors is connected to earth/ground. This direct burial cable is typically made with cross-linked polyethylene insulation. The cable has undergone a 350 hour accelerated UV test, but is not marked "Sun Light Resistant” even though it is considered suitable for the outdoor environment. USE-2 is rated for wet environments (it is a direct buried cable) and for temperatures up to 90°C. Without any other markings (such as a dual USE-2/RHW-2 marking), USE-2 has no flame or smoke retardants and may not be used indoors in conduit. The author has personally had USE-2 conductors made with cross-linked polyethylene insulation exposed in the harsh outdoor conditions of New Mexico for more 30 years without obvious signs of deterioration.

Photo 1. Lug is not suitable for fine-stranded cable.

Photo 1. Lug is not suitable for fine-stranded cable.

PV Cable/PV Wire

PV modules are made for international markets and have attached conductors that can be used in different countries. Most of the rest of the world (ROW) uses transformerless inverters (a.k.a. non-isolated inverters) and ungrounded PV arrays (no dc circuit conductor, either positive or negative connected to earth/ground). TheNational Electrical Code(NEC) allows ungrounded arrays to be installed in the U.S., and a "PV cable” or "PV wire” is required for the permanently attached modules conductor as well as for the field-installed exposed wiring. This specialized conductor is only mentioned in the NEC in Section 690.35 and is not found elsewhere in the Code. It has a nonstandard outer diameter, so the conduit fill tables may not be used. It may be used on modules in ungrounded PV arrays and also on modules intended for grounded PV arrays. PV wire/PV cable is tested, certified and listed to Underwriters Laboratories (UL) Outline of Investigation 4703.

UL 4703 establishes the materials that can be used in the conductor and the tests that the conductor must pass. The conductor insulation may be either thermoset (synthetic rubber-like cross-linked polyethylene) or thermoplastic (PVC).

The thickness is specified and there may be one or two layers of insulation. The insulation must pass an accelerated UV test of 720 hours and will be marked "Sunlight Resistant.” PV cable/PV wire also has smoke and flame-retardants and may be used inside conduit inside buildings. In the U.S., it should not be called a "double-insulated cable” as that is a purely European term.

All Insulations Are Not Equal

Photo 2. Improperly secured conductors can abrade and fault.

Photo 2. Improperly secured conductors can abrade and fault.

Both USE-2 and PV cable/PV wire are available with colored insulations (e.g., white, red, green), but care should be exercised when considering colored insulations. While these colored cables are marked "Sunlight Resistant” and have passed the 720-hour accelerated UV test, they do not have as much carbon black in them as do the black-insulated cables. Carbon black is one of the main insulation components that provides a conductor with UV radiation resistance. Cables with less carbon black may not fare as well over 40–50 years in the extreme PV environment as cables with high levels of carbon black.

And, in a similar manner, PVC insulated cables have passed the 720-hour accelerated UV tests, but PVC insulated electrical components like PVC jacketed UF cables and PVC liquid-tight non-metallic conduit (LFNC) have not survived well in the hot, sunny southwest outdoor environment.

In Conduits

Conductors in conduits are somewhat protected from the mechanical abuse that affects the exposed conductors. However, PV systems are experiencing ground faults in conductors in conduits indicating that more care must be exercised during the installation process. Not using the correct number of pull boxes and installing too many degrees of turn, as well as not installing bushings at the entry and exit points can lead to insulation damage. And, while the problems may not show up at system turn-on, they may show up in later years as the conduits are subject to thermal expansion and high temperatures from solar heating. Inspectors need to keep vigilant for signs of improper cable installation such as missing bushings, tight or stretched cables, and slivers of insulation.

Photo 3. Stainless steel/EDPM Loop Strap (available from McMaster-Carr)

Photo 3. Stainless steel/EDPM Loop Strap (available from McMaster-Carr)

Conductor Stranding

The UL 4703 specification allows both normal class B stranding (typically 7–19 strands) and it also allows finer stranding which can be hundreds of fine strands in a 10 AWG conductor. The European IEC Standard for PV cable (yes, unfortunately, the same name) requires that the European PV cables be fine-stranded. While fine-stranded, flexible cables pose no problems when installed on the modules in the factory, the use of fine-stranded flexible cables is problematic where field-installed cables are involved. This is due to the lack of suitable terminals for fine-stranded cables (see photo 1). See NEC 110.14, 690.31(F), 690.74 and the "Perspectives on PV” article in the January/February 2005 IAEI News.

Excellent Workmanship Required

Photo 4. ACME cable clip by Wiley Electronics

Photo 4. ACME cable clip by Wiley Electronics

TheNEC, in Section 110.12, requires that electrical equipment be installed in a neat and workmanlike manner. ANSI/NECA 1-2006 Standard Practices For Good Workmanship in Electrical Contracting provides details. However, both theNECand the NECA standard were developed for conventional electrical installations where the conductors are installed in either interior locations (modest temperature, low mechanical stresses) or in exterior conduits. The exposed PV conductors, as noted above, are subject to far less benign conditions, and those conditions will affect the cables for many decades. When it comes to the workmanship associated with these exposed PV source circuit conductors, that workmanship must be excellent, not just good. Winds blowing a slightly loose conductor against a PV racking member can cause the insulation to be abraded in a few short months, leaving a potential shock hazard or ground-fault hazard (see photo 2). Exposed module conductors that hang below the modules and touch the roof are also subject to abrasion on the roof surface. In colder climates, they are also subject to ice dams and frozen snow sliding down the roof separating the cables from the modules—not a desirable situation.

Photo 5. Torque screwdrivers

Photo 5. Torque screwdrivers

The use of the common black plastic wire ties that are rated as UV resistant do not survive the PV environment which exposes the plastic to high levels of UV radiation and high temperatures on a day-in, day-out basis for many years. The most common size of these wire ties is ⅛” to 3/16″ wide and these have failed in PV installations after only a few years. It is possible that the more robust units, ⅜”to ½” wide and thicker, would survive more years. My organization (Southwest Technology Development Institute) deals with the smaller size PV systems (3–18 kW) and we usually use EDPM rubber-cushioned stainless-steel loop clamps to secure the module wires (see photo 3). PV equipment suppliers also stock stainless steel ACME cable clips by Wiley and others (photo 4).

Terminations

In addition to securing the exposed conductors properly, these conductors and others in conduit must be terminated properly on the fuse holders, circuit breakers, combiners, disconnects, inverters and at other equipment. In most cases, screw terminals are used and on every piece of certified/listed equipment, there is a torque value that must be used. Section 110.3(B) of the NEC requires that all instructions and labels associated with a listed product be followed. A torque screwdriver or torque wrench must be used to make these connections (see photo 5). If these terminals are not properly tightened, they will fail (see photo 6). IAEI, IBEW, and NECA have demonstrated numerous times that the average electrician cannot accurately make a screwed electrical connection without the use of a calibrated torque device.

Inspectors: Maybe it is time for your chief to get some torque screwdrivers.

Summary

Photo 6. Improper torque results in failed connections

Photo 6. Improper torque results in failed connections

As the large number of PV systems being installed today age in the decades ahead, we will see the affects of "average” workmanship. Plan reviewers and inspectors rarely get to see a PV system that has been installed 5 or 10 years ago. Research and development people who test these aging systems see the signs of deterioration on nearly every system. Systems integrators who sell maintenance contracts with their systems are finding issues with the conductors as the systems age.

It might prove informative and educational for plan reviewers and inspectors to visit a few of these older systems and see how the conductors and other parts of the installation are holding up. Perhaps the workmanship standard needs to be moved from "Good” to "Excellent.”

For More 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: 575-646-6105.

See the web site below for a schedule of presentations on PV and the Code. Call the author if you would like to schedule a presentation.

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 2005National 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

This work was supported by the United States Department of Energy under Contract DE-FC 36-05-G015149


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Tags:  Featured  July-August 2012  Perspectives on PV 

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