Every fire season brings new horrors and hardships for people living in dry or drought-prone areas. The summer of 2020, for example, bought apocalyptic fires raging in Oregon and California. Air quality in Portland, Ore. is now considered some of the world’s worst because of smoke pollution, while California cities are shrouded in an eerie red and orange haze that makes noon look like midnight.
Earlier this year, the world could only watch as Australia’s 2019-2020 awful fire season charred more than 12.4 million acres, killed more than 30 people, and leaving millions of animals either dead, injured, displaced, or struggling to survive in scorched habitats.
These tragic fires are among the most recent manifestations of an overall trend. Whether wildfires are the result of global climate change or poor forestry management, or a combination of both, they have become larger, more destructive, and more frequent. Utilities dealing with this reality must ensure that that utility infrastructure is not the source of the next deadly spark.
A core concern for utilities
For any utility manager thinking that wildfires are not a problem in their service areas, perhaps it is time to think again, according to an article in Utility Dive.
The article quoted Anthony Westerling, a professor of Environmental Engineering at the University of California, Merced, who teamed up with researchers from five other research universities and found that large wildfires – those that scorched 1,000 acres or more – increased 450% across federal lands in the Western U.S. during the decade ending with 2012. These blazes burned areas that were 930% larger than similar fires in the 1970s and 1980s.
Indeed, NASA’s Earth Observatory has noted that our planet’s average global temperatures have increased 1.4 degrees since 1880, and two-thirds of that change has occurred since 1975.
Even places we do not expect to be tinder dry now see remarkable fire events. A case in point is Australia’s Gondwana rainforests, of which more than half burned during this most recent fire season. Florida is another place we expect to see plenty of humidity and lush greenery. Still, moderate drought recently contributed to a fire that damaged or destroyed more than 3,500 rental cars in an overflow parking lot at the Fort Meyers airport.
Australian ecologist Mark Graham told a U.S. National Public Radio reporter, “We’re in the Pyrocene, the age of fire.” Fortunately, another trend can help utility managers mitigate fire risk and address wildfire events. Technology is helping utilities keep up with fire risks. Are you keeping up with technology?
If you looked at the wildfire mitigation plans filed by major utilities in California, you’ll see vegetation management surfaces as a priority in all of these documents. Utilities with advanced metering infrastructure (AMI) systems already have a leg up on smart tree-trimming practices because advanced meters report momentary outages, which may indicate vegetation contact. But, what about remote areas, where advanced meters aren’t out there on the lines reporting those transient events?
Distribution and sub-transmission lines do not always follow a road, and they frequently traverse large stretches or remote, unpopulated areas where no one is around to see trouble erupt. Out there in the wilderness, impending equipment failures, downed conductors and other issues that can spark a fire are rarely visible to utility engineers until flames begin. Fortunately, those same equipment problems are visible to sensors, a must-have wildfire management tool.
How utilities are using sensors
Grid monitoring with smart grid sensors, according to a Utility Dive piece, is filling an important niche in the fight against wildfires. This is one reason why Pacific Gas & Electric told California told regulators it would be using them to help manage its network. According to its updated 2020 wildfire mitigation plan, PG&E is targeting both smart meters and sensors to augment situational awareness, which the utility said would support “more accurate forecasting and identification of environmental events and operating conditions that pose a risk to the grid so that critical issues may be dealt with as quickly as possible to avoid the risk of catastrophic wildfires.”
During the years 2014 through 2016, more than 51% of fires reported by PG&E to California regulators were suspected to be triggered by vegetation contact with utility lines.
Smart grid sensors can help utilities identify areas where vegetation or other obstructions could cause sparks that could lead to fires. An investor-owned utility in the Midwest, for example, was using Aclara’s sensors and, over the course of six months, the Aclara grid monitoring platform identified and alerted utility staff to nine separate events that required attention.
The utility investigated these events and found six instances of vegetation in contact with the primary conductor. In one of these events, utility workers found a fishing line wrapped around the phase and neutral wires. In total, utility staff estimated that finding these problems avoided approximately 400,000 customer minutes lost. In areas where wildfires are common, finding this type of fault can reduce the risk of a fire.
Another utility in the Northeast recently deployed smart grid sensors as part of their capital program to increase monitoring on their circuits. Even though the sensors were installed just six months after the circuit had hotspot tree trimming performed, the sensors detected areas of the circuit that were still experiencing vegetation contacts. The utility used the fault location capability of the Aclara Grid Monitoring solution to dispatch tree crews to resolve the remaining problem areas quickly and efficiently.
Benefits of smart grid sensors
Smart grid sensors have two primary benefits for wildfire management:
- They are easy to install and can be hot-clamped onto a line three-at-a-time in 30 minutes.
- They provide the utility with three vital parameters – voltage, current, and a timestamp – which are used to identify fault location.
The three parameters allow utility engineers to calculate where on the feeder the problem occurred – particularly subtle transient fault disturbances that are not visible to SCADA.
For instance, sensors will pick up when an energized conductor has fallen to the ground. This is important because up to 30% of faults in which a single line of conductor breaks and winds up on the ground “draw too little electrical current to blow a fuse or trip a circuit breaker” according to researchers at the Texas Wildfire Management Project at Texas A&M University.
When the line hits the ground, it may contact a surface that conducts electricity poorly. When that happens, an energized line can remain on the ground until someone notices it and, all the while, it may be producing high-temperature arcing that could cause a fire.
Another hazard that may not trip the circuit is a loose guy wire used to hold a utility pole in place. When a guy wire is broken, it can contact an energized power line, particularly on a windy day. That is an intermittent hazard that probably will not trip a breaker, but it is still quite dangerous because it may produce arcing, which can spark fires. With the right sensors, utilities will see that something is up. Better yet, they will know where to send linemen to repair the broken guy wire.
Locating faults and failing equipment
Locating faults and failing equipment is one of the most valuable fire prevention and restoration tool sensors deliver.
Consider conductor slap, a potential fire-starter because when lines contact each other, they could arc and eject hot particles of metal onto the ground. Conductor slap occurs when a huge rush of fault current flows through one phase of conductor and makes the line jump. If there is too much slack in the primary conductors, there is a chance the bouncing line will hit a conductor carrying another phase of power. Now, what started out as a single-phase fault turns into a phase-to-phase fault that may be missed by linemen because they will find the fault on one phase and not the other.
Smart grid sensors can identify where to look for evidence of conductor slap. What is more, only smart grid sensors can affordably provide the line-disturbance information on distribution feeders that stems from failing devices, downed conductor and other fire risks.
Yes, there are other telemetry solutions to this problem. But traditional telemetry generally only lets engineers know a fault has occurred. Smart grid sensors monitor and report conditions continuously, which means they can prevent fires by alerting engineers to equipment failure that is imminent, not just failures that have already happened.
Smart grid sensors or traditional telemetry?
Traditional telemetry solutions, which are highly accurate, have a number of characteristics that make it a less than optimal for fire mitigation:
- It is permanently placed — bolted is also bolted onto power pole cross arms and other utility frameworks.
- It usually employs additional equipment like reclosers or relays, feeds automation technology, and it requires its own telecommunications backhaul.
- It requires its own backhaul.
These three characteristics mean that a typical telemetry solution is expensive, costing well over $100,000 including installation and project costs.
On the other hand, smart grid sensors deployed for as little as $10,000 for a three-phase installation provide enough accuracy and data granularity to handle:
- Fault and disturbance location
- Circuit reconfiguration
- Power quality analysis
- Distribution planning
In addition, smart grid sensors can be moved and only take a crew about half an hour to install. This makes them particularly valuable during emergency events when rapidly changing weather conditions require rapid response and enhanced visibility of conditions.
Engineers who are serious about fire mitigation should consider putting a few smart grid sensors at multiple locations on every feeder. They will deliver information that no other equipment is providing and reveal anomalies that could spark tragedy. Smart grid sensors detect line disturbances, which represent vegetation contact, animal contact, or equipment starting to fail, three leading causes of wildfire.
So, which would you rather have on your power lines? Ignition or insight? Smart grid sensors make the difference.
To learn more about addressing that risk, download Aclara’s wildfire mitigation application guide.