Courtesy of PV expert Bill Brooks, here’s how a utility-interactive PV system with no battery storage might be equipped with a rapid-disconnect facility that meets NEC 690.12 requirements. In this example, the PV array sits on the roof. Its inverter is in the garage. Wiring between the roof installation and the inverter runs in metal conduit, through the attic and into the garage. Inside the attic resides a remotely activated switch within 5 ft of where the conduit enters. (The remotely activated disconnect could also sit outside the attic, closer to the array, if that is more practical.) Another shutdown switch must sit within 5 ft of the inverter, unless the inverter itself can internally reduce its voltage below 30V or isolate its capacitors within ten seconds. In the diagram, the dc switch at the inverter is shown as being remotely operated.
Rapid-shut down and other provisions in the 2014 NEC aimed at first responder safety are causing confusion among PV professionals. Here’s why.
By Leland Teschler, Executive Editor
A short section of the 2014 National Electrical code has caused a lot of head-scratching among solar installers and officials from local municipalities.
NEC Section 690.12 reads in part:,
…circuits installed on or in buildings shall include a rapid shutdown function that controls specific conductors…..Requirements for controlled conductors shall apply only to PV system conductors of more than 1.5m (5 ft) in length inside a building, or more than 3 m (10 ft) from a PV array…..Controlled conductors shall be limited to not more than 30V and 240 V-A within 10 seconds.
Most municipalities haven’t yet adopted the 2014 version of the code, but indications are that the few now following the new requirement don’t know how to interpret it. These interpretation problems have on occasion led to installations that are potentially dangerous and, to a practiced eye, look a little silly.
“There is one notorious photo now making the rounds,” says Bill Brooks, principal of Brooks Engineering. “It depicts a disconnect mounted 20-ft off the ground on the side of a house. The jurisdiction interpreted a disconnect as meaning within 10 ft of an array. But they failed to understand that the conductors on the load side of that switch, which go to the inverter, were not taken care of. That’s also a requirement.”
Brooks is a registered professional engineer in both North Carolina and California and chaired the task group authoring the NEC photovoltaics provisions.
“The code language is brief intentionally because it was the first version,” Brooks says. “We didn’t want to dictate how to do things. But it is clear people need more hand-holding.”
“We have run into situations where inspectors have enforced the code incorrectly,” he adds. “Some are fine, but others have misunderstood requirements in the direction of oversimplification and didn’t know what they were approving. Others have misread the requirements and demanded all kinds of ridiculous things.”
Moreover, the NEC rules assume some familiarity with solar technology on the part of authorities, Brooks says. “Many of them have no background in solar and that’s a problem.”
Complicating matters is that different municipalities begin using newer versions of the NEC at different times.
“One inspector may want a solar installation one way while the inspector working across the street in a different jurisdiction may want it done another way,” says Dr. Sean White, a PV educator and designer of PV systems in the San Francisco Bay area. “Every place is different because the rules are changing so quickly.”
Another point of confusion arises from the fact that microinverters inherently meet the standard but string inverters do not — unless they incorporate specific means of implementing a rapid disconnect. Systems using microinverters or ACPV modules meet the requirements because they have no power outside the array other than the AC input to the inverter. First responders can shut these down using conventional practices.
Most systems incorporating DC-to-DC converters will also output less than 30 Vdc when the AC input to the inverter is lost. But the inverter capacitors can keep the circuit energized above 30 Vdc for up to five minutes. String inverters must be disconnected at two different points because they have two sources of current: The solar array itself and the capacitors in the inverter. The rapid-disconnect shut-off device must act on both these sources.
Inverter manufacturers are using two different approaches to implement the disconnect. They can use a DC disconnect to isolate the DC-link capacitors in the inverter from the conductors going to the roof. That’s the only measure necessary if the inverter sits near the service entrance. If the inverter is remote from the service entrance, the usual technique is to use AC-activated contactors at the DC input to the inverter and within 10 ft of the array on the roof. Then the main service disconnect could initiate the shutdown – contactors will shut off the circuit in less than one second.
One complication is that local municipalities determine where the rapid-disconnect switch should reside. The location isn’t spelled out in the NEC 690.12.
“The intention was that the location of the disconnect would be discussed by the fire service, the solar contractor and the inspector,” Brooks says. “Normally it would be near the service entrance. But some service entrances are in basements and may not be the best location for a shut off because there’s no easy access in an emergency.”
Another point of confusion concerns the difference between a rapid-shutdown initiator and the shutdown mechanism itself. It is only the interrupting mechanism — usually a contactor — that must sit within 10 ft of the array. The initiator almost always resides near the service entrance.
“You want to put it in an area where firefighters would go to control utilities in an emergency,” Brooks says. “The initiation process should be at the service disconnect or nearby so firefighters don’t have to find two independent locations in an emergency.”
Fire Starters
The point of rapid-disconnect, of course, is to make the area near the array less risky for first responders. Two other measures recently entering the NEC are aimed at minimizing risks of fire originating in the solar array and the ancillary equipment. Arc-fault detection for solar equipment became part of the NEC in 2011. One problem: Arc-fault detection for solar systems hadn’t yet been commercialized in 2011.
“The technology hadn’t been invented so obviously municipalities couldn’t enforce it,” White says. “Enforcement had to wait for manufacturers to catch up.”
Today, manufacturers have indeed caught up. The majority of string inverters sold today have arc-fault detection built in. NEC arc-fault provisions cover systems operating at more than 80V, which include those employing string inverters.
Arc faults usually arise from problems that include loose connectors and abraded or damaged conductors that heat up and eventually melt. One problem is that arcs arising from benign conditions can trigger arc-fault circuits. Ordinary electric brush motors, as found in hand-held drills for example, generate arcing that can potentially be interpreted as a dangerous fault. So there is some engineering involved in creating circuitry not affected by false positives. “Millions of dollars have been spent on differentiating between good and bad arcs,” Brooks says.
Difficulties have arisen when inverters get connected with ancillary equipment such as DC optimizers. Inverter makers know the noise output of their own equipment and can compensate for it. But they don’t necessarily know the signature of noise emanating from the gear that other vendors supply. On occasion, conflicts arise that necessitate software patches or modifications of inverter hardware.
Ground Faults
For decades, the NEC has required that solar arrays incorporate ground-fault protection. A ground fault arises when the energized conductor carries an amount of electric current that differs from that flowing through the return neutral conductor. Usually, the difference in current flow arises because some current leaks through damage in the protective insulation of conductors that normally carry current.
But parasitic capacitances to ground can be another source of difficulties for ac current. Usual paths include noise-canceling capacitors, lightning-protection devices, module frames, racking and so forth. Such current imbalances may also indicate current leakage through the body of someone who is grounded and accidentally touches an energized part of the circuit. Ground-fault interrupters are primarily designed to address the fire hazards of ground faults. Some newer ground-fault detectors can even disconnect quickly enough to prevent a lethal shock that can result from these conditions.
Both NEC 690.5 and 690.35(C) require that grid-tied photovoltaic inverters shut down in the event of a ground fault. The code makes exceptions for a few situations that include small ground or pole-mounted PV arrays isolated from any buildings.
Ground-fault detection and interruption technology for solar is well established. Only problem is, no one really knows how much of a problem ground faults really constitute in solar arrays.
“Ground faults have tended to be the more likely reason for fires in solar installations that I have investigated,” Brooks says. “But I now think arc faults produce a similar number of fires.”
Brooks has to guess at the statistics because there is no authoritative database of fire incidents in solar arrays. Fire services do not break out solar as a separate category of incident. And many investigations of fires that arise in solar equipment come under the jurisdiction of nondisclosure agreements and their details are not made public.
Accurate fire statistics may become more important as new requirements for solar installations are folded into building codes. The International Building Code requires that roofs have fire ratings of Class A, B or C. The ratings depend on results of tests for fire spreading, intermittent flames and burning.
Currently, PV modules receive a fire classification rating that often differs from that of the roof on which they mount. But new building codes that begin to take effect in 2015 demand that PV arrays have the same fire rating as is required for the roof. That’s because tests have shown the fire rating of PV modules isn’t a good predictor of how the roof and PV array together will behave.
Along with embracing the new requirements, regulating bodies will implement new methods of conducting fire classification tests. The tests will be based on the spread of flames and burning for modules, racks and the roof as a system.
Authorities think the new test will likely require that a baffle or barrier go under the array to prevent flames from spreading, for systems that need a Class A rating. The impact on solar installations could be significant, particularly in California where Class A roofs are a requirement in many residential municipalities.
“Fire services want to see higher fire ratings on roofs because these higher ratings help them fight fires,” Brooks says. “California is first with Class A roofing requirements, but I see the trend spreading across the country.”
References:
Brooks Engineering, Vacaville, Calif., brooksolar.com
Dr. Sean White, www.pvstudent.com
“Solar Photovoltaic Basics: A Study Guide for the NABCEP Entry Level Exam,” by Dr. Sean White