Rapid Shutdown for PV Systems
Inside this Article
The 2014 edition of the National Electrical Code added rapid-shutdown requirements for PV systems on buildings with the goal of allowing first responders to quickly and easily control the PV system circuits leaving a roof-mounted array.
According to market data that the Solar Energy Industries Association (SEIA) and GTM Research published in September 2014, there are more than 500,000 rooftop PV systems installed in the US. Bloomberg estimates that integrators installed roughly 3 GW of rooftop PV capacity on some 200,000 homes and businesses in the last 2 years alone. Due to the proliferation of rooftop solar installations, the regulatory agencies and entities responsible for developing codes and standards have increasingly scrutinized the potential hazards associated with PV systems mounted on buildings, especially with regard to firefighter safety. This scrutiny has resulted in new fire and electrical code requirements pertaining to roof-mounted PV systems. While the solar industry may not welcome the additional regulation, collaborating with the fire service to establish a positive long-term working relationship is critical.
In this article, I attempt to demystify one of the most controversial of these new code requirements—namely, NEC 2014 690.12, “Rapid Shutdown of PV Systems on Buildings.” To explain the historical context that led to these rapid-shutdown requirements, I begin with a brief background on the jurisdictional efforts to enforce fire regulations specific to roof-mounted PV systems. I then explore the technical difficulties associated with protecting firefighters from energized conductors on the dc side of a PV power system, as this establishes the need for rapid-shutdown requirements. Finally, I deconstruct the language in 690.12 and consider its intent and implications. In the process, I provide examples of some equipment configurations that meet these requirements in a variety of real-world applications.
History of Fire Regulations
Fire service concerns about PV systems are not new, but they have increased significantly over the last 6 or 7 years. Los Angeles was the first large jurisdiction in the US to enforce PV system fire regulations. In early 2007, the Los Angeles Fire Department published a set of restrictions for commercial and residential PV systems. These guidelines limited the size of array sections to 50 feet in any dimension and required 4-foot setbacks on all four sides of each array section. Further, the guidelines required “quick-release type” module-mounting hardware, which was subject to fire department approval but otherwise undefined.
Responding to this regulation by a major municipality, in July 2007 the California Solar Energy Industries Association (CALSEIA) began working with the California Department of Forestry and Fire Protection (CAL FIRE) to develop consensus on PV installation guidelines. Together, CALSEIA and CAL FIRE’s Office of the State Fire Marshal put together a task force consisting of fire service and solar industry stakeholders, building code officials, and codes and standards experts. This task force developed installation guidelines for roof-mounted PV systems that CAL FIRE published in April 2008 as recommendations for framing local ordinances (see Resources).
While the CAL FIRE Solar Photovoltaic Installation Guideline does not have the force of law, the 2012 editions of the International Fire Code (IFC) and NFPA 1 Fire Code subsequently codified its major provisions related to array layout restrictions. (See these SolarPro articles for more information: “Commercial Rooftop PV Arrays: Designing for Fire Code Compliance,” August/September 2014; “Pitched Roof Array Layout for Fire Code Compliance,” November/December 2014.) The CAL FIRE Guideline also includes circuit routing and system marking recommendations codified in NEC 2011 690.4(F) and 690.31(E), respectively.
Since the National Fire Protection Association (NFPA) publishes NFPA 70, National Electrical Code, it should come as no surprise that the association emphasizes minimizing the risks and effects of fire and takes a particular interest in firefighter safety. For example, Code Making Panel 4 (CMP4) also added NEC 690.11, “Arc-Fault Circuit Protection (Direct Current),” to Article 690 during the 2011 revision cycle. While arc-fault protection requirements mitigate fire initiation hazards associated with arcing faults, they do nothing to eliminate the shock hazard that PV power circuits present to first responders. Similarly, while the circuit routing and labeling requirements in NEC 2011 help first responders to identify energized PV power circuits, they do not mitigate the associated shock hazards.
Controlling PV System Circuits
Firefighters are accustomed to encountering roof-mounted electrical equipment, particularly on low-slope commercial roofs. However, PV systems are unlike conventional ac electrical equipment in terms of size, electrical characteristics and prevalence on residential roofs. As rooftop PV systems have become increasingly common in the built environment—especially in California, Hawaii, Massachusetts, New Jersey and other major US solar markets—demand has increased for firefighter training resources, such as CAL FIRE’s Fire Operations for Photovoltaic Emergencies (see Resources), to educate first responders about PV power systems.
One of the first questions asked at firefighter trainings is: “How can we shut the PV system down so that we won’t get shocked when responding to an emergency?” Unfortunately, there is no simple answer to this question, given the way most PV systems are designed and deployed today. Using rooftop dc disconnects to control PV power circuits is inherently problematic. The rapid-shutdown requirements for PV power systems on buildings address this problem.
Problem with dc disconnects. One of the first activities that firefighters perform when responding to a fire in a structure is to control the energy utilities. Often this involves closing a gas shut-off valve and opening an ac service disconnect. Many fire departments have sought to address the shock hazard associated with PV system circuits in an analogous manner by requiring rooftop dc disconnects in an attempt to eliminate that source of power. However, dc PV power circuits and conventional ac circuits are not analogous, and the differences can be life threatening. Though rooftop dc disconnects are important to the process of shutting down and isolating a PV array, they generally stop the flow of current only and do not provide voltage isolation as they would in a utility-supplied ac power system.
Requiring a rooftop dc disconnect seems like a simple and logical approach to shutting off a PV system. However, opening this disconnect does little, if anything, to reduce shock hazard. In fact, you could argue that opening a rooftop dc disconnect provides firefighters with a false sense of security that could increase the likelihood of an electrical shock. Since turning off a rooftop dc disconnect in a PV system does not de-energize the conductors on either side of the switch, NEC 690.17 requires the following warning label on dc disconnects:
WARNING: ELECTRIC SHOCK HAZARD.
DO NOT TOUCH TERMINALS.
TERMINALS ON BOTH THE LINE AND LOAD SIDES
MAY BE ENERGIZED IN THE OPEN POSITION.
Many PV systems are still dangerous even after you open a rooftop disconnect because there are typically power sources on both sides of the switch. On the one hand, the PV power source energizes the conductors on the PV array side of the switch during daylight hours, typically at voltages greater than 300 Vdc and up to 1,000 Vdc in nonresidential applications. On the other hand, the PV output side of the switch is often connected to the dc input bus of an inverter, which is another potential source of power. This side of the switch remains energized as long as PV output circuits are connected in parallel at a subarray or inverter-input combiner. For example, in a scenario where 15 dc disconnects are installed on a commercial rooftop—one at the location of each source-circuit combiner box—if an emergency response team leaves only one of these 15 in the on position, that could leave all array wiring fully energized and potentially lethal. Even where there are no parallel-connected PV power circuits, large dc input capacitors at the inverter may keep this side of the switch energized long after responders open the rooftop disconnect.
Though the fire service stakeholders who developed the CAL FIRE Guideline discussed rooftop dc disconnects at great length, representatives from the solar industry clarified that these would have little impact on improving safety for first responders. As a result, the published Guideline does not include requirements related to rooftop dc disconnects. However, the rationale for this intentional omission was not published in the Guideline, which has led some jurisdictional authorities and fire departments to adopt additional local requirements for rooftop dc disconnects.
In fact, while stakeholders were revising content from the CAL FIRE Guideline for inclusion in the 2012 IFC, a consultant for the fire service developed language requiring dc disconnects as a means of de-energizing PV power circuits. This proposal was withdrawn only after the Solar America Board for Codes and Standards (Solar ABCs) sent the consultant an 11th-hour communication—subsequently published as Appendix A to the report “Understanding the CAL FIRE Solar Photovoltaic Installation Guideline” (see Resources)—pointing out that PV power systems could shock or electrocute first responders if firefighters did not properly coordinate the operation of these disconnects. Clearly, a more comprehensive shutdown system is necessary to truly address firefighter safety.
Need for rapid shutdown. Fire service representatives are justifiably concerned about the inherent shock hazard that most PV power systems present first responders. Therefore, the NFPA established a Firefighter Safety Task Group within CMP4 to specifically address this issue for NEC 2014. This task group’s primary contribution to the National Electrical Code Committee Report on Proposals was Proposal 4-253, which recommended the creation of a new code section, 690.12, that would apply to roof-mounted systems and address the de-energization of PV power circuits.
The task group originally proposed that NEC 690.12 require module-level shutdown for roof-mounted PV systems. This would have left only the module wiring and the internal conductors energized in the event of a utility outage or manual PV array shutdown. While this language provided first responders with a way to quickly and easily control PV power circuits on a building in the event of an emergency, solar industry representatives objected to the requirements, arguing that module-level technologies were not mature enough for widespread adoption.
Three stakeholder groups subsequently worked together to rewrite NEC 690.12. This process included the PV Industry Forum, SEIA’s Codes and Standards Working Group, and the CMP4 Firefighter Safety Task Group. The resulting proposal is the language published in NEC 2014:
690.12 Rapid Shutdown of PV Systems on Buildings
PV system circuits installed on or in buildings shall include a rapid shutdown function that controls specific conductors in accordance with 690.12(1) through (5) as follows.
(1) Requirements for controlled conductors shall apply only to PV system conductors of more than 1.5 m (5 ft) in length inside a building, or more than 3 m (10 ft) from a PV array.
(2) Controlled conductors shall be limited to not more than 30 volts and 240 volt-amperes within 10 seconds of rapid-shutdown initiation.
(3) Voltage and power shall be measured between any two conductors and between any conductor and ground.
(4) The rapid-shutdown initiation methods shall be labeled in accordance with 690.56(B).
(5) Equipment that performs the rapid shutdown shall be listed and identified.
Note that this language originally appears in Proposal 4-110 of The National Electrical Code Committee Report on Comments (ROC) along with a lengthy substantiation. The substantiating comments are well worth a read if you are looking for a point-by-point breakdown of the deliberations and research that led to the published rapid-shutdown requirements. As with any new Code requirement, understanding the intent of the language in NEC 690.12 will not only help system integrators deploy compliant solutions, but also assist enforcement entities with permitting and inspection.
Understanding Rapid Shutdown
The primary objective of NEC 690.12 is to provide emergency response personnel with a comprehensive and effective means of controlling PV power circuits installed on or in buildings in a manner that eliminates the false sense of security associated with using rooftop dc disconnects. While the Fire Safety Task Group initially proposed module-level shutdown as a solution, the revised language essentially requires combiner-level shutdown near the array.
NEC 690.12 clarifies the types of PV systems that must comply with rapid shutdown, the circuits that the shutdown process must control, the maximum allowable voltage on these circuits, the maximum allowable time frame to accomplish shutdown, the system labeling requirements and the product listing requirements. The language intentionally does not specify what type of device you should use to initiate rapid shutdown or where you should locate it. Since the Code language is an installation requirement and not an instruction manual, here I address some of the frequently asked questions regarding rapid shutdown.
Which systems must comply? As stated in the section title, rapid-shutdown requirements apply to PV systems on buildings. If you are installing a roof-mounted PV system subject to NEC 2014, the rapid-shutdown requirements clearly apply to your project. If you are installing a ground-mounted or similar system where none of the PV system components or circuits contacts a building, the rapid-shutdown requirements do not apply.
This does not mean that all ground-mounted PV systems are exempt from rapid-shutdown requirements. Where PV system circuits from a ground-mounted PV system are physically attached to or penetrate a building, you should apply NEC 690.12. However, in this case, the conductors on or entering the building are subject to rapid shutdown, but the conductors off the building are not. Note that underground conductors that travel under buildings are not considered to be “on or in buildings.” Where buried conductors come up into a building, you are allowed to run them a distance of 5 feet from the point of penetration through the floor before installing a disconnecting means.
Which circuits must the shutdown system control? The rapid-shutdown requirements apply to “PV system circuits,” which includes both dc and ac circuit conductors. In utility-interactive PV systems, the primary rapid-shutdown objective is to control the dc PV power circuits, as you control the ac circuits associated with the PV system by opening the connection to the utility-supplied service, which is a standard emergency response tactic. In a stand-alone system or an interactive system with battery backup, the rapid-shutdown system must also control any ac circuits that remain energized in the absence of utility power.
As stated in 690.12(A), you must control the PV circuit conductors within 5 feet of entering a building or 10 feet of the array. If you install PV source-circuit conductors in metal conduit that directly enters the attic of a building, you must control those conductors within 5 feet. If you route your conduit across the roof instead, the maximum uncontrolled conductor length is 10 feet. No scenario permits you to add these allowable conductor lengths together; the maximum uncontrolled conductor length is 10 feet.
What is the maximum allowable controlled circuit voltage? During rapid shutdown, you must limit voltage on controlled conductors to no more than 30 volts. Per the ROC substantiation, the stakeholders who developed NEC 690.12 chose a 30-volt limit for two reasons. First, this is the touch-safe voltage limit for wet locations, established by various national and international standards. Second, this voltage level allows for the use of 24-volt control circuits, such as those used to control contactors in combiner boxes.
What is the allowable time frame? You must achieve safe voltage levels in control circuits within 10 seconds of rapid-shutdown initiation. Per the ROC substantiation, the 10-second requirement is intended to allow dc-side capacitor banks to discharge by means other than contactors and shunt-trip breakers. Verifying compliance with this time limit requires some diligence on the part of the designer, plan checker or inspector. The good news is that some inverters—typically transformerless string inverters—can meet this 10-second limit without further mitigation. The bad news is that other inverters—typically transformer-isolated string inverters and larger central inverters—cannot meet this 10-second limit without some method of controlling voltage from the capacitor banks.
To complicate matters further, some vendors already have a capacitor-bank control method integrated into their inverters, while others do not. For example, Solectria’s central inverters have a contactor in series with each of the fused inputs in its inverter-integrated subcombiners; when these contactors open, the subarray inputs are isolated from the capacitor bank. Some other inverters have large capacitor banks that take several minutes to de-energize to a safe voltage level and do not have any internal contactors. If an inverter cannot meet the 30-volt and 10-second limits and does not have an integrated isolation device, system designers need to add a control method external to the inverter to comply with NEC 690.12. If you are not sure whether you need to disable a particular inverter’s capacitor bank, contact the manufacturer’s applications engineering department.
What labeling must you apply? NEC 690.56(C) specifies the identification requirements for facilities with rapid shutdown. A permanent plaque or directory must include the following wording and capitalization:
PHOTOVOLTAIC SYSTEM EQUIPPED
WITH RAPID SHUTDOWN
The plaque or directory must be reflective, with white letters at least 3/8 inch in height against a red background. Ideally, you should locate the rapid-shutdown labeling where it is most beneficial to firefighters, and it should include simple instructions about how to perform the shutdown.
What are the product listing requirements? Per NEC 690.12(5), rapid-shutdown equipment must be “listed and identified.” This language allows for the use of off-the-shelf products listed for PV applications, including inverters, microinverters, ac modules, dc-to-dc converters, contactor combiner boxes, rapid-shutdown systems and so forth. It also permits other off-the-shelf electrical products—such as contactors, motorized switches and shunt-trip breakers—as long as you use these in accordance with their listings and the manufacturer’s instructions.
Some solar industry stakeholders have argued that AHJs should not enforce rapid-shutdown requirements, basing their argument on language in Article 90: “This Code may require new products…that may not yet be available at the time the Code is adopted. In such event, the authority having jurisdiction may permit the use of the products, constructions or materials that comply with the most recent previous edition of this Code adopted by the jurisdiction.” This is an incorrect application of 90.4. NEC 690.12(5) does not require the use of products listed and identified specifically for rapid shutdown—in which case 90.4 would apply—or even listed and identified specifically for PV systems. You can deploy many listed products in ways clearly “suitable for the specific purpose, function, use, environment, application”—per the definition of “identified” in Article 100—to enable rapid shutdown.
What about the rapid-shutdown initiator? NEC 690.12 does not specify where you should locate the initiating device or what type of device you must install. This lack of detail is intended to provide system integrators and AHJs with the flexibility to adapt rapid-shutdown solutions to the complexities of the built environment. While the best location for a rapid-shutdown device and the required label is typically at or near the service equipment, the fire service may have preplanned emergency response tactics for some large commercial or industrial buildings that favor a different location.
One of the simplest ways to initiate rapid shutdown is to set it up to occur automatically upon loss of ac power. This is why NEC 2014 does not require a specific type of rapid-shutdown initiation device. If you install a roof-mounted residential microinverter system or a commercial PV system using roof-mounted string inverters located within 10 feet of the array, you do not need any special equipment to initiate rapid shutdown; you can accomplish this function simply by interrupting utility-supplied power to the inverters. Some companies have developed various rapid-shutdown switches, and claim that rapid shutdown requires these extra switches. However, you have to install an extra rapid-shutdown switch only when you need to turn the array off by some means other than loss of utility power, as with battery-backup systems or inverters equipped with a daytime backup-power outlet.
NEC 690.12 does not specify how many buttons, switches or movements of the hand are allowed to complete rapid shutdown. Ideally, the process should only require one action. As written today, however, the language in 690.12 provides system integrators and AHJs with the flexibility to consider alternatives. Note that if the system design requires more than one action to initiate rapid shutdown, the 10-second time limit still applies. Therefore, where systems are deployed with more than one initiation device or switch, they should all be in close proximity so that emergency personnel can de-energize all of the PV system circuits on the building within 10 seconds. Further, labeling must clearly identify all of the initiation devices and all of the steps required to complete rapid shutdown.
Compliance in Real-World Scenarios
There are many ways to meet the intent of NEC 690.12 and improve firefighter safety in emergency response situations. I intend the following examples not as an exhaustive list of all possible 690.12-compliant solutions, but rather as a representative list of how to use existing PV products for rapid shutdown. I have organized these examples according to application: residential, commercial and battery backup. However, these are general rather than absolute distinctions. While solutions involving module-level power electronics are more likely to appear in residential applications in the short term, there is no reason you could not deploy them in commercial applications as well—or even in an ac-coupled battery-backup application.
Most residential PV systems use microinverters or ac modules, dc-to-dc converters or string inverters. You can deploy any of these options in a manner that complies with NEC 690.12. In addition, one residential string inverter scenario does not require additional equipment to meet 690.12.
Microinverters and ac modules. PV systems installed using microinverters or ac modules inherently comply with 690.12. Loss of ac power immediately de-energizes all PV system circuits outside the array area(s); only circuits internal to the module and conductors between modules and external microinverters remain energized. At present, Enphase Energy leads the microinverter market, which includes vendors such as ABB (Power-One), APS America, Darfon, ReneSola and SMA America. While ac modules currently have a smaller market share than microinverters, they are available from LG Electronics (Mono X ACe module) and SolarBridge’s TrueAC module vendor partners.
For load-side–connected microinverter or ac module systems without battery backup, the simplest way to initiate rapid shutdown is to turn off utility-supplied power to the building. This not only is cost effective, but also coordinates well with standard emergency response practices. First responders can initiate rapid shutdown by opening the main service disconnect or opening the PV system disconnecting means. In the former case, you could install the plaque or directory used to fulfill NEC 690.56(C) at the main service. Additional wording could direct emergency personnel to open the service disconnect to initiate rapid shutdown.
DC-to-dc converters. Because dc-to-dc converters can control voltage at the array, these systems are well suited to accomplish rapid shutdown. However, they are compliant only if they meet the 10-second time limit, which is largely a result of inverter selection. For example, SolarEdge offers complete power conversion systems combining module-level dc-to-dc converters with proprietary transformerless string inverters that a nationally recognized testing laboratory (NRTL) has verified can provide rapid shutdown. Not only is rapid shutdown available in all SolarEdge inverters, but installers can also upgrade existing installations to add this functionality. Other vendors, such as Tigo Energy, supply dc-to-dc converter solutions that are inverter agnostic. If you select one of these solutions, you must verify compliance with NEC 690.12.
For example, Trina Solar’s Trinasmart modules integrate dc-to-dc converters from Tigo Energy into the module junction box. Trinasmart modules can therefore control voltage within the array so that only circuits internal to the module remain energized in the event of an emergency. If you install Trinasmart modules with an inverter that meets the 30-volt and 10-second time limits, then the installed system is 690.12 compliant. However, if you install Trinasmart modules with an inverter that does not bleed down under 30 volts or otherwise isolate the capacitor bank within 10 seconds, then the installation is not compliant—unless you also install an external contactor or similar device to control the voltage source at the inverter.
String inverter systems. You need additional hardware to bring conventional string inverter systems into compliance with NEC 690.12. At a minimum you must install a contactor combiner or similar device in a manner that controls dc circuits in accordance with 690.12(1)—within 10 feet of the array or within 5 feet of entering a building—along with control circuits to actuate the contactor. Further, if the inverter’s capacitor-bank voltage does not drop below 30 volts within 10 seconds, you must add a contactor or switch to isolate the capacitor bank.
Emergency responders can initiate rapid shutdown in string inverter systems manually using a dc disconnect or a rapid-shutdown controller; alternatively, the systems can shut down automatically upon loss of ac power. If a dc disconnecting means at the inverter initiates rapid shutdown, this switch must also activate a switch or contactor within 10 feet of the array or 5 feet of entering the building. Where loss of ac power remotely activates both of these switches, the service disconnecting means can serve as the rapid-shutdown initiator for the PV system if labeled per 690.56(C). Where a dc disconnect initiates rapid shutdown, you should locate this device and the inverter it controls near the service equipment, and you must label it per 690.56(C).
The relative cost and complexity required to facilitate rapid shutdown in string inverter systems varies based on inverter selection. For example, Bentek has developed a rapid-shutdown system, consisting of a ground-level Rapid Shutdown Controller and a roof-mounted 2- or 3-string Rapid Shutdown Module that works with transformer-isolated or transformerless inverters. It is relatively cost effective to use this rapid-shutdown system with an inverter that meets the 30-volt and 10-second limits, such as ABB (Power-One) UNO series inverters or SMA America TL-US series inverters. However, costs increase if the system requires two Rapid Shutdown Modules, one at the roof-mounted array and another at a ground-level inverter. MidNite Solar and SolarBOS also provide rapid-shutdown solutions for residential string inverter applications. SMA America is working on a proprietary rapid-shutdown system that is compatible with its TL-US series inverters equipped with Secure Power Supply outlets.
No additional equipment required. NEC 690.12 allows installers to run uncontrolled PV system circuits a maximum of 10 feet beyond the array area. Therefore, if it is possible to install a PV system so that the conductor length between the array and the inverter is less than 10 feet, the system is compliant with NEC 690.12. For example, imagine a roof-mounted array installed on a single-story ranch home with a wall-mounted inverter directly below the array area. If the conduit run between the array and the inverter is less than 10 feet, this residential string inverter system does not require any remote switches or contactors to comply with 690.12.
Most commercial systems use a centralized architecture with large central inverters or a distributed architecture with multiple 3-phase string inverters. System designers can adapt either of these basic design options to comply with NEC 690.12.
Central inverter systems. Designers typically position high-capacity central inverters at ground level because of their large size and weight. This results in long uncontrolled PV output-circuit conductor runs off the roof. In this scenario, designers can comply with NEC 2014 requirements by specifying contactor combiner boxes that provide arc-fault protection per 690.11, rapid-shutdown capabilities per 690.12 and the dc combiner disconnect requirement per 690.15(C). Bentek, SolarBOS and Solectria Renewables are a few of the vendors offering listed source-circuit combiners with these capabilities.
Where you use roof-mounted contactor combiner boxes to comply with 690.12, you also have to install control circuits for these devices. The normally open contactor in the combiner will remain closed as long as you apply a 24 V signal to the device; if you interrupt the 24 V control circuit, the contactor will open. Pay special attention to verify that shutdown disables the large capacitor banks at the ground-level inverters in less than 10 seconds. Firefighters can initiate rapid shutdown manually using a dc disconnect or a rapid-shutdown controller, or it can occur automatically upon loss of ac power. In the latter case, firefighters can use the main service disconnecting means to initiate rapid shutdown for load-side–connected PV systems, or the PV system disconnecting means to initiate rapid shutdown for supply-side–connected systems.
3-phase string inverter systems. Due to the cost and complexity of designing NEC 2014–compliant central inverter systems—a combiner capable of providing dc arc-fault protection and rapid-shutdown functionality can cost twice as much as a standard disconnecting combiner—system integrators are increasingly installing 1,000 Vdc-rated, 3-phase string inverters, which range in capacity from 15 kW to 60 kW, on low-slope commercial rooftops in place of dc combiners. As long as you install these 3-phase string inverters within 10 feet of the array, the system complies with 690.12. Once firefighters interrupt utility-supplied power, which they can accomplish without any remotely activated switches, no uncontrolled conductors remain further than 10 feet from the array. However, all of the dc circuits within the array remain energized. For load-side–connected systems, firefighters can initiate rapid shutdown by opening the main service’s disconnecting means; for supply-side– connected systems, they must open the PV system’s disconnecting means.
Many inverter vendors—including ABB, Advanced Energy (via its REFUsol acquisition), Chint, Fronius, SMA America and Solectria Renewables—offer 3-phase string inverters with integrated arc-fault protection that you can install directly on low-slope commercial roofs. Increasingly, integrators are installing these 3-phase string inverters at a moderate tilt angle (5°–30°) on low-profile inverter racks and distributing them throughout the array in lieu of dc combiners. Many inverter and BOS vendors—including Advanced Energy, AET, Bentek, Shoals Technologies Group and SMA America—now offer string inverter mounting kits for low-slope roofs, attesting to the popularity of this design strategy.
Systems With Battery Storage
Battery storage adds a layer of complexity to the rapid-shutdown process. Most battery storage systems are designed to power selected loads during a utility power outage. Since standby power is the battery’s primary function, actuating rapid shutdown on loss of utility power defeats the battery’s purpose. Therefore, battery-based systems need a rapid-shutdown initiator that does not depend on loss of ac power. This independent shutdown initiator could be a simple on/off or control switch, such as a push button that controls remotely actuated switches. While the location for this initiation device ultimately depends on the project, the building and the PV system design, the best location is typically in close proximity to the main service equipment.
Wherever you locate the rapid-shutdown device, it must control the battery-backup circuits as well as the PV array circuits. The technical solution used to control the battery-backup circuits may vary depending on the distance between the batteries and the inverter.
Batteries more than 5 feet from inverter. Where integrators install batteries more than 5 feet from the connected inverter, a new requirement in NEC 2014 690.71(H) calls for a battery-bank disconnecting means “at the energy storage device end of the circuit.” In this scenario, you can install a remotely actuated switch at the battery bank to meet the requirements of both 690.12 and 690.71(H). During the rapid-shutdown process, both the roof-mounted switch for the array and the battery-bank disconnecting means open to de-energize all of the PV system circuits, including the backup power circuits. Since battery-based inverters do not have input capacitance, the voltage of the inverter–input circuit will drop below 30 volts as soon as you disconnect the battery and turn off the utility ac power. As with utility-interactive PV systems without battery storage, the ac circuit between the utility service and the inverter automatically shuts down upon loss of utility power.
Batteries within 5 feet of inverter. Where integrators install batteries within 5 feet of the inverter, NEC 690.71(H) does not require a disconnecting means at the battery bank. In this scenario, designers have two options for controlling the backup-power circuits to meet 690.12. They can install a remotely activated switch in the battery circuit, or they can install a remotely activated ac switch in the stand-alone inverter-output circuit. Either of these options will power down the PV system circuits that would otherwise remain energized upon loss of utility-supplied power.
The NEC 2014 rapid-shutdown requirements represent a substantial change in PV system design and deployment—and a significant step forward in PV system safety. As with all new NEC requirements, it will take some time for system designers and installers to learn how to meet rapid-shutdown requirements in a range of applications; it will also take time for plan checkers and inspectors to learn how to enforce 690.12. The first step is to determine which conductors you need to control. Once you have established this, you can evaluate the means of control. As I have illustrated, some PV system design strategies inherently comply with 690.12, while others require additional equipment.
Dozens of stakeholders participated in the process that culminated in the NEC 2014 rapid-shutdown requirements, and many stakeholders are similarly engaged in the process of improving 690.12 as part of the 2017 revision cycle. While it is far too early in the Code-making process to predict what the revised section will ultimately look like, two proposals have broad stakeholder support. The International Association of Firefighters has proposed revising 690.12 to require module-level control, which may provide the highest level of safety for its members. SEIA has proposed a more detailed and restrictive version of the existing combiner-level control provisions.
Bill Brooks / Brooks Engineering / Vacaville, CA / brooksolar.com
Fire Operations for Photovoltaic Emergencies, California Department of Forestry and Fire Protection (CAL FIRE), November 2010
Solar Photovoltaic Installation Guideline, California Department of Forestry and Fire Protection (CAL FIRE), April 2008
“Understanding the CAL FIRE Solar Photovoltaic Installation Guideline, ” Solar America Board for Codes and Standards, March 2011