The Heat Is On: Fault Detection and Fire Prevention
Inside this Article
Could PV-involved fires dampen a hot solar market?
On the evening of June 19, 2015, a KOB 4 Eyewitness News anchor in an Albuquerque, New Mexico, studio teased a developing story with a video montage running behind his back. “This video shows smoke pouring from the roof of a community center,” he explained, as the footage cross-faded from fire engines with flashing lights to firefighters hosing down the roof of a broad building from an aerial ladder. Before the video cut to helicopter footage showing a smoldering and blackened roof, the anchor intoned: “Tonight a fire there is blamed on solar panels.”
One bad news report like this can counterbalance a hundred positive stories. News of the Solyndra bankruptcy, after all, made more of an impression on the public than two decades’ worth of sustained solar market growth and job creation. For the solar industry to continue to enjoy broad public and political support, we must do everything in our power to eliminate fires in PV systems.
In this article, I provide a brief history of PV-involved fires, exploring both their causes and effects. I describe specific design and installation practices that can help prevent PV-initiated fires by minimizing ground faults and series arc faults. I summarize efforts to improve fault detection in fielded PV systems with new codes and standards, and provide troubleshooting tips for identifying and remedying detected faults. Lastly, I consider some actions integrators and asset managers can take to limit liability and financial exposure associated with possible future fires in legacy PV systems that are not built to the latest codes and standards.
Brief History of PV-Involved Fires
Though fires involving PV systems are very rare, they occur on a continual basis. In April 2009, for example, a fire began with a PV array on the roof of a big box store in Bakersfield, California. When I subsequently analyzed this fire in SolarPro, I foresaw that the same type of event could happen again unless the industry changed the ground-fault detectors used in these systems. (See “The Bakersfield Fire: A Lesson in Ground-Fault Protection,” February/March 2011.) Approximately 2 years later, in April 2011, a fire originating within an array on the roof of a manufacturing facility in Mount Holly, North Carolina, damaged 20 PV modules, two combiner boxes and portions of the roof.
In May 2013, a PV-involved fire occurred at the headquarters of a dairy co-op in La Forge, Wisconsin, causing roughly $12 million in damages. The local fire department classified the cause as undetermined. However, a fire investigator for the National Fire Protection Association (NFPA) wrote an article (see Resources) contending that the site’s green building technologies and construction materials—including the PV array on the roof and recycled cotton-based insulation in the wall cavities—contributed to the spread of the fire and presented safety issues for firefighters.
Perhaps the most publicized PV-involved fire occurred in September 2013 at a 300,000-square-foot food warehouse in Delanco, New Jersey. While the origin of this fire is still under investigation, the fire was linked closely with the PV system. Media outlets reported that firefighters did not fight the blaze more aggressively because they were afraid that the PV system would injure them.
While the community center in Albuquerque is perhaps the most recent PV-involved fire to make the news, a similar event occurred in May 2015 on the roof of a large industrial facility in Mesa, Arizona. Though investigators are still determining their causes, it is likely that both were PV-initiated fires. Further, both resulted in severe damage, with the Mesa fire creating millions of dollars of fire loss.
Causes. Until recently, the manner in which PV systems started fires was subject to speculation and hypothesis. Now, however, after dozens of examples of PV-initiated fires in fielded systems, there is general consensus regarding the primary causes. We can categorize the vast majority of fires originating within PV arrays as either ground-fault detection blind spot fires on the one hand or series arc-fault fires on the other.
The Bakersfield and Mount Holly fires, for instance, are examples of fires caused by a blind spot in a ground-fault detection system. While ground-fault detection blind spot fires are unique to certain PV systems, fires caused by arc faults are not. An arcing fault can cause a fire in a dc circuit even more easily than it can in an ac circuit. Common causes of series arc faults in PV circuits are loose or separated connections in modules, connectors or combiner boxes.
Effects. Both the Bakersfield and Mount Holly fires received a lot of attention from solar industry stakeholders. The Solar America Board for Codes and Standards (Solar ABCs), for example, launched an investigation to determine and mitigate the cause of these well-publicized fires. Between January 2012 and June 2013, the Solar ABCs published multiple reports based on its research and findings (see Resources). Recent changes to codes and standards, which I address in detail later, have closed the ground-fault detection blind spot and added series arc-fault protection requirements for PV systems. However, hundreds of thousands of PV systems are deployed in the US with older-style ground-fault detectors and no arc-fault detectors.
The Delanco fire, meanwhile, is infamous because the fire losses may exceed $100,000,000, making it the largest insured loss worldwide related to a building with a PV system. As a result of this fire, insurance companies have begun to more systematically scrutinize the underwriting of PV systems and the buildings on which they are mounted.
The fundamental basis for preventing fires within PV systems is basic attention to detail when terminating conductors and managing cables. However, these measures alone are not sufficient to prevent PV-initiated fires. To better understand what we should or should not do, it would be ideal if we could analyze specific fire incidents related to PV systems over the last decade. Unfortunately, the origins of most PV fires remain shrouded behind a curtain of nondisclosure agreements. Several themes, however, have emerged from fire investigations that we can use to help prevent PV fires.
REDUCING GROUND FAULTS
The following are some key design and installation tips—largely intended to minimize opportunities for conductor damage—that will reduce the occurrence of PV system ground faults.
Use shorter circuit lengths. Both copper and aluminum conductors expand and contract at different rates than steel raceways. Long-distance circuit runs magnify this difference and can cause significant problems at turns and terminations.
Avoid conduit bodies for 90° turns. Where possible, use alternatives to LB-, LL- or LR-type conduit bodies for making turns in conduit. When coupled with dissimilar expansion and contraction rates, the tight turns associated with these fittings are a common cause of conductor damage.
Avoid the need for expansion fittings. Whenever circuit runs exceed a distance of 100 feet, consider using cable tray rather than conduit to eliminate the need for expansion fittings.
Use aluminum for large circuits. To eliminate dissimilar expansion rates, use aluminum cable trays or raceways with aluminum conductors, which are also much lighter and cheaper than copper.
Terminate aluminum with care. Extra attention is warranted when terminating aluminum to ensure quality, long-lasting circuits. Verify that the terminals are rated for use with aluminum conductors and use antioxidant on all terminations.
REDUCING ARC FAULTS
The following are some key design and installation tips—largely intended to ensure high-quality electrical connections—that will reduce the occurrence of series arc faults in PV system circuits.
Engage both clips on connectors. Engaging only a single safety-locking clip on an MC4 or MC4-style connector dramatically increases the likelihood of the connection coming apart.
Assemble connectors per manufacturer’s instructions. Follow the connector manufacturer’s assembly instructions when preparing and assembling connectors in the field. Use the manufacturer-specified crimp tool and ensure that it is set appropriately for the conductor gauge and type.
Check the connector assembly. After assembling connectors, perform a pull test of about 30 pounds. The connectors should never yield to this amount of pull tension. This test can verify the mechanical integrity of both field- and factory-assembled crimp connections. Conductors slipping out of connector fittings are a common cause of arc faults.
Use connectors from the same manufacturer. There is no connector standard for interoperability. Though manufacturers of MC4-style connectors often claim that their connectors are compatible with Multi-Contact’s MC4 connectors, it is unclear whether these companies—even those that are quite large—will back up the contractor in the event of an arc-fault fire. The simple rule, therefore, is to never mate connectors from different manufacturers, as this eliminates connector mixing as a potential contributing cause to a fire.
Do not strain junction box conductors. Fires have resulted from strain at module terminations compromising the electrical connection to the module. Conductor thermal cycling can exacerbate the tension on the terminations and increase the stress at these connections. This is particularly problematic for homeruns to combiner boxes, as longer conductor lengths increase the probability of cable tensioning strain.
Torque, retorque and mark terminations. Terminations can loosen over time due to thermal cycling, vibrations and other strand movement. To minimize loose terminations in conductors smaller than 250-kcmil, torque the connection to the specified value and then move the conductor two or three inches side to side a few times. Moving the conductor in this manner while it is under stress can reposition the strands so that the conductor better fills the terminal cavity. Afterward, retorque the connection to the proper value and mark the terminal with a permanent marker.
Avoid using fine-stranded conductors. Whenever possible, use standard Class B rather than fine-stranded conductors and cables. Where fine-stranded conductors are required, never assume that a terminal is rated for these conductors without referring to supporting documentation. Few larger-diameter pressure terminals are listed and rated for use with fine-stranded conductors. The weight of a large, heavy conductor alone can cause an improper connection to work loose over time. Do not use flexible, fine-stranded cables with setscrew-type terminals or lugs.
No one ever builds a PV system expecting it to catch fire. However, PV-involved fires can and do occur, even when everyone involved observes the best design, installation and maintenance practices. Detecting faults before they have an opportunity to start a fire is therefore a top priority for the stakeholders involved in the process of developing codes and standards pertaining to PV systems. These efforts involve both electrical and building codes, as well as product safety standards.
Electrical code requirements. The National Electrical Code is the most logical place to address arc-fault and ground-fault detection, the two main causes of PV-originated fires. To this end, the Code-making panel responsible for Article 690 added dc arc-fault protection requirements in Section 690.11 as part of the 2011 cycle of revisions. As published in NEC 2011, 690.11 applies to PV systems with dc circuits “on or penetrating a building.” NEC 2014 effectively expands these requirements to all PV systems operating above 80 Vdc. As part of the 2014 revision cycle, the Code-making panel also added enhanced ground-fault detection requirements to Section 690.5. Specifically, 690.5(A)(1) requires ground-fault detectors capable of detecting a ground fault in “intentionally grounded conductors.”
Without dc arc-fault detectors, an event that might happen one time out of every 10,000—such as a module failure, a loose connector or an inadequate termination—can lead to an arcing fault. If that arc fault occurs in the presence of fuel, it has the potential to start a fire. If that fire becomes self-propagating, it will stop only when it is suppressed or runs out of fuel. In a worst-case scenario, “running out of fuel” may mean that the fire has completely destroyed the building.
Without highly sensitive ground-fault detectors, an overlooked pinched wire can become a latent ground fault that goes undetected. In the event that another ground fault occurs elsewhere in the system, current can now flow in the equipment-grounding system and grounded metal components. These inadvertent current-carrying connections can get extremely hot and often progress into an arcing fault to ground, as was the case with the Bakersfield and Mount Holly fires. Once again, fuel availability can dictate the extent of these fires in the absence of fire suppression.
Building code requirements. Managing or limiting fuel in proximity to a PV system is a key—and often overlooked—safety consideration. However, the results of 5 years of PV fire performance testing have shown that roof fire performance ratings are also extremely important.
A wood shake roof, for instance, presents many PV installation challenges: Installation activities easily damage the roofing system, the roof penetrations are difficult to waterproof, and the roofing material is highly flammable. This all adds up to a highly unfavorable roof condition for a PV installation. If an arc occurs within a PV array on a shake roof and that arc is cable of generating enough energy to start a fire, the results could be catastrophic. It would be ill advised, therefore, to install a PV system without advanced ground-fault and arc-fault protection on a shake roof. Given the other installation challenges, it is probably wise to avoid installing any PV system over a wood shake roof. Most large installation companies will install a PV system at a residence with a shake roof only if a roofing contractor removes and replaces the wood material in the vicinity of the array.
Many commercial roofs likewise have very poor fire ratings. It is the building owner’s responsibility to ensure that these roofs are properly rated in accordance with applicable building codes, which require a minimum Class C roof fire rating for most buildings. However, the codes require a Class B fire rating for roofs on all assembly occupancy buildings. California and other Western states, meanwhile, have Class A fire rating requirements for high fire severity areas, wildland-urban interface areas and other areas.
The 2012 editions of both the International Building Code and the International Residential Code require that PV systems meet the same fire classification rating as is required for the roof. Therefore, to put a PV system on the roof of a church or synagogue anywhere in the US, installers must ensure that the PV system has a Class B or better fire classification rating. Since Class A or B modules are not readily available, only PV systems evaluated to the new versions of the UL 1703 and UL 2703 product safety standards can meet these requirements. (See “Fire Classification for Roof-Mounted PV Systems,” SolarPro, November/December 2014.) This is a significant change as failure to meet these requirements could place a contractor at risk. In the event that a fire occurs within a roof-mounted PV array subject to the 2012 building codes, fire investigators will likely scrutinize the installation for fire classification compliance.
Product safety standards. Insofar as they define requirements for the evaluation and certification of PV system components, product safety standards are an essential part of fire prevention and fault detection. Without product safety standards, the codes would have to define not only practical safeguards but also specific verification test requirements. The intent of the codes is simply to dictate what safeguards are required in practice. The role of standards is to provide details about how to test and evaluate a product to prove that it meets the intent of the codes.
UL 1703 and UL 1741 are the primary PV industry product safety standards. The former governs the safety of flat-plate PV modules and includes fire performance test requirements. The latter governs the safety of inverters and other specialty electrical or electronic components used in PV systems. UL 1741 includes ground-fault detection test requirements and references UL 1699B for arc-fault detection test requirements.
While UL 1699B is still very much a work in progress, Nationally Recognized Testing Laboratories (NRTLs) are evaluating products to this standard. Nuisance tripping and nondetection remain an issue with dc arc-fault detectors, as was the case when ac arc-fault detectors first came to market (see “Troubleshooting Arc Faults and Ground Faults,” at left). However, these products are a great leap forward for the PV industry. They have already prevented several fires.
Of the remaining product safety standards relevant to the solar industry, the standard pertaining to mounting systems is perhaps most pertinent to fire prevention and fault detection. UL 2703 is the product safety standard that defines fire performance test requirements for PV modules in combination with mounting systems. This standard also contains test requirements for grounding and bonding devices, which are critical to ground-fault detection.
The above inventory of codes and standards is not simply interesting trivia. Product standards allow PV system designers and installers to select properly evaluated equipment that meet the required codes. Installing listed and labeled equipment in a code-compliant manner not only makes PV systems safer, but also limits contractor liability.
Imagine what happens if you install a PV system to the latest code requirements, and perform all the correct installation and maintenance procedures—and it still catches on fire. Since PV systems built to the latest codes are far less likely to start a fire than systems installed only a few years ago, the likelihood of this happening is extremely small. However, it is impossible to foresee or prevent every possible event that will befall fielded PV systems. In the unlikely event of a fire, an important benefit of the codes and standards process is that following these construction norms protects the contractor.
In the one in 100,000 chance that a PV system your company installed initiates a fire, codes and standards are the measure by which fire investigators and insurance companies will judge the installation. If the installation meets all the applicable requirements, then the fire must have been unpreventable given the available products and technologies. This legal concept is known as the standard of care. Contractors are not required to employ every available safeguard; rather, they must follow the safeguards that are standard to the industry.
Failure to follow these codes and standards leaves contractors exposed. If investigators find deficiencies in an electrical system that caused a fire, they could find the contractor at fault. If so, lawyers may try to pin a negligence charge on the contractor for not following the standard of care. This has implications for new installations as well as fielded systems.
New installations. The vast majority of properly installed PV systems should never need to use their arc-fault or ground-fault detectors throughout the life of the system. This is especially true if these systems are part of an effective O&M program implemented by a competent asset manager. However, stakeholders have adopted new ground- and arc-fault protection safeguards precisely because even the most careful and conscientious system installer, with the aid of a competent asset manager, cannot prevent all PV system fire events.
To limit liability, it is incumbent on integrators and installers to implement advanced ground-fault and dc arc-fault detectors in all new PV systems—regardless of the version of the NEC that the local AHJ is enforcing. Both of these safeguards are codified in NEC 2014. However, some jurisdictions are enforcing NEC 2011, which requires dc arc-fault detectors only, and others are still on NEC 2008, which requires neither. Though some jurisdictions do not yet mandate advanced ground-fault or dc arc-fault detectors, contractors should still install systems to this standard of care. The good news is that most PV systems designed to meet the requirements of NEC 2011—such as commercial roof-mounted PV systems using 20 kW–50 kW 3-phase string inverters—will meet industry best practices for fire prevention and fault detection within PV arrays.
Fielded systems. High-profile fires involving PV systems have captured the attention of the insurance industry. Greater scrutiny by insurance carriers is almost guaranteed to increase premiums or deductibles unless companies take measures to improve system safety. Providing or offering upgrades for fielded systems is one option available to PV system owners as a means of controlling insurance costs while improving safety.
Increased insurance costs are not the only issue these fires raise. Another issue to consider is whether ignorance is still a viable defense in the event of a PV-initiated fire. The 2009 Bakersfield fire, for example, initiated a well-documented multi-year investigation that eventually led to revised ground-fault protection requirements in NEC 2014. An effort is now under way to revise the product safety standard in light of these new Code requirements.
Prior to these developments, contractors could reasonably claim that ground-fault detection blind spot fires were unforeseeable and that no solutions to the problem were available. These days, it is increasingly difficult for installers or asset managers to claim ignorance—in part because of articles like this one. Further, non-isolated inverters with highly sensitive ground-fault detectors are readily available and widely used.
Today, ignorance is no longer a reasonable response to a PV-initiated fire, which leaves the door open for litigation. In the event of a fire, lawyers may have a viable legal case if they can reasonably prove that a contractor had knowledge of a potential safety problem—one for which a viable commercial solution was available—and did not inform the customer. The legal concepts behind such a case include situations such as failure to warn, withholding of information or concealment. If the contractor informs the customer of a potential safety problem and the customer chooses to take no action, the customer rather than the contractor bears responsibility in the event of a fire. Transfer of knowledge is the key.
So how can a contractor or asset manager inform customers of a potential safety issue without alarming them unduly or winding up in a situation where customers insist on free system upgrades? The crux of the matter is how companies communicate with their existing customers. The project permitting date determines the Code requirements at the time of construction. Prior to the 2014 edition, the NEC did not require ground-fault detection on grounded conductors. Prior to the 2011 edition, the NEC did not require dc arc-fault protection; further, these arc-fault detectors were not available commercially until 2013. Since the NEC is a construction document, not a maintenance document, contractors or asset managers are not required to update existing systems as new technologies come to market. However, they can certainly offer customers these upgrades as options.
The following is an example script a contractor or asset manager might use to notify past customers about new safety technologies that are now available for existing PV systems:
The safety track record of PV systems is among the best in the electrical industry. In recent years, electrical code revisions have further reduced PV system fire hazards. New technologies are now available that improve PV system safety. While these additional safeguards were not required or available when your PV system was installed, it is possible to upgrade your PV system to include these new safety technologies. Enclosed is information about safety upgrades and typical costs for installing these on PV systems like yours. If you would like to receive a detailed cost estimate to have these upgrades installed on your system, please contact us.
The benefit of notifying customers about PV system upgrade options is that it reduces exposure to lawsuits based on failure to warn, withholding of information, or misrepresentation and concealment. The larger the material loss in a fire, the more likely it is that lawyers will attempt to use every legal tool available to assign blame to the contractor. Notifying customers helps alleviate potential exposure to liabilities. Ultimately, a contractor’s best defense against these allegations is to detail that it completed the PV installation in accordance with the codes enforced at the time of the installation. The NEC is one of the most universally adopted codes throughout the US and represents an authoritative standard of care for electrical installations.
Companies that have experienced a PV-involved fire invariably take steps to ensure that fires will not recur on their projects. They become far more vigilant about O&M practices on existing systems as well as design and installation standards for future systems. This response emerges from a better understanding of the financial impacts of a fire. Good installation and asset management practices and implementation of new safety technologies based on improved codes and standards offer the cheapest insurance against these potential losses.
Bill Brooks / Brooks Engineering / Vacaville, CA / brooksolar.com
Ball, Greg, et al., “Inverter Ground-Fault Detection ‘Blind Spot’ and Mitigation Methods,” Solar America Board for Codes and Standards,June 2013
Brooks, Bill, “The Ground-Fault Detection Blind Spot: A Safety Concern for Larger Photovoltaic Systems in the United States,” Solar America Board for Codes and Standards, January 2012
Brooks, Bill, “Field Guide for Testing Existing Photovoltaic Systems for Ground Faults and Installing Equipment to Mitigate Fire Hazards,” NREL, Subcontractor Report NREL/SR-5D00-65050, September 2015
Duval, Robert, “Perfect Storm,” NFPA Journal, January/February 2014
Flicker, Jack, and Jay Johnson, “Analysis of Fuses for ‘Blind Spot’ Ground-Fault Detection in Photovoltaic Power Systems,” Solar America Board for Codes and Standards, June 2013