Our most recent Exploring North Carolina Smart Grid webinar examined the issues of grid reliability and resiliency. The session featured Dr. Robert Cox, associate director of UNC Charlotte’s Energy Production & Infrastructure Center (EPIC); Lee Ragsdale, senior vice president, energy delivery in the power supply division of North Carolina’s Electric Cooperatives (NCEC); and our own David Farmer, senior engineer at Advanced Energy.
Resiliency and Resiliency Planning Overview
Resiliency and resiliency planning are not new, but they have taken on a new level of importance with developments and advancements of the last decade. Life-threatening weather events — storms and hurricanes as well as extreme temperatures — are occurring more frequently and with greater intensity, stressing the grid in new ways. There’s also the growing threat of cyberattacks.
Just this year, Farmer noted, the U.S. has experienced Texas’s severe-weather grid failure in February, wildfires in the West, heat waves in the Pacific Northwest, hurricanes along the East and Southeast, and the Colonial Pipeline cyberattack.
In the electric utility industry, resiliency is often viewed in terms of the grid’s ability to maintain services during and recover from major events. Metrics for evaluating resiliency continue to evolve, though it’s complicated, because the topic centers on scenarios that occur with limited frequency but have outsized effects on the grid and communities.
A distinct but related concept is grid reliability. Reliability examines how the grid operates during normal, everyday conditions — major events are typically excluded from reliability calculations. To that end, the grid must be able to avoid disruptions from high-frequency, low-impact events that are known to utilities. Unlike with resiliency, there are several established and accepted metrics to evaluate grid reliability.
|High-frequency, low-impact events||High-impact, low-frequency events|
|Ability to provide service under normal operating conditions||Ability to operate in full or reduced form during abnormal operating conditions|
|Industry-accepted standards — IEEE 1366||No industry standards currently|
|Major events are excluded||Major events are the focus|
|Impact to system, customers||Impact to system, customers, society and communities|
Resiliency in North Carolina
Building on Farmer’s presentation, EPIC’s Dr. Cox noted that the number of disasters and billion-dollar events has been increasing in North Carolina, triggering a need to understand how to develop a more resilient grid.
Both reliability and resiliency are probabilistic in nature: They assess how likely it is that a particular event will occur. Day-to-day issues, because they’re so common, are easier to manage, but how do you plan for situations that are unlikely to happen?
In the U.S., there are two larger entities concerned with grid reliability: the North American Electric Reliability Corporation (NERC) and the Federal Energy Regulatory Commission (FERC).
NERC is a federally approved organization for developing reliability standards for the bulk power grid, which includes power generation and high-voltage transmission across North America. In addition to evaluating the operating reliability of the bulk grid, NERC also assesses resource adequacy, which ensures that there are sufficient resources to supply the necessary electricity load. At the distribution level, reliability is typically handled by state regulatory agencies.
IEEE Standard 1366 defines 12 reliability metrics that utilities must provide to these state agencies. One such metric, the System Average Interruption Duration Index, or SAIDI, measures the average outage duration experienced by a customer in a given year for a utility.
A distinction is made between days without major events and those with, known as Major Event Days, or MEDs. MEDs reflect situations that are beyond the operational normalcy of the grid, such as low-probability, high-consequence (or high-impact, low-frequency) events, that are critical to thinking about resiliency.
Echoing Farmer’s presentation, Dr. Cox noted that because these events have low probability, they can be difficult to plan for and respond to. With that in mind, Dr. Cox’s definition of resiliency encompassed how we prepare for and adapt to changing conditions as well as withstand and recover rapidly from any disruptions they cause.
To put it simply, there are two main goals of resiliency: increasing robustness to lower the overall number of people who experience an outage, and improving response time, so that those who do lose power aren’t without it for as long.
Unfortunately, in practice, resiliency metrics are often imprecise, and they tend to undervalue the impact of large-scale outages, which can have compounding effects over time. For that reason, it’s difficult for utilities to sell resiliency improvements to their public utilities commissions.
Further complicating the picture is that outages have such far-reaching consequences. Electric power is foundational to the way our society functions, so resiliency requires looking beyond the grid itself and to what it enables. Because the grid is essential for so many services, different groups — communities vs. governments vs. individuals vs. utilities — have different views of what resiliency should entail.
Additional key features of resiliency and resiliency analyses are that they are risk-based and contextual. They look forward and must attempt to anticipate how an event will affect electric infrastructure and power delivery, what the consequences of those effects might be (lost services, harm to the economy, etc.), and how different planning options could make a difference.
Vulnerability to outages, however, can change over time, even just based on recent weather patterns. Furthermore, there is not always a correlation between grid circuits that might be weak from a reliability perspective and those that might see longer disruptions during larger events.
Another consideration is that resistance to one type of threat does not guarantee resistance to another. For example, wildfires or cold snaps typically cause a loss of generation and transmission, such that the grid is unable to send power to the distribution network, which is what occurred in Texas earlier this year. Alternatively, there can be shorter-duration outages (less than 24 hours) associated with minimal damage to the distribution system or longer-duration outages (24+ hours) with heavy distribution-system damage. North Carolina experiences all three types of conditions.
The expansion of distributed energy resources (DERs) is improving grid resiliency, but utilities must continue to explore the best ways to utilize them. Just because they are new and exciting does not mean they are always the most cost-effective approach or the right solution for every situation.
Dr. Cox concluded by reiterating that resiliency and resiliency policy are critical but complex issues, and a challenge that remains is how we value them.
The Distribution Operator and Resilience
North Carolina’s electric cooperatives provide power in 93 of the state’s 100 counties and cover 45% of its land mass. Increasingly, NCEC’s Ragsdale said, they’re providing that power through DERs, such as renewable energy and other emerging grid technologies.
DERs are essential to North Carolina’s electric cooperatives’ work toward building a brighter energy future, and several factors, including regulatory and market signals, are driving up DER adoption in North Carolina and beyond. When coordinated effectively, this DER growth can greatly enhance local resiliency.
Today, you can find DERs throughout North Carolina electric cooperative territory. There are community solar projects, utility-scale solar farms, solar-plus-storage facilities and numerous demand response programs.
Another budding DER for North Carolina’s electric cooperatives is the microgrid. Microgrids are a collection of grid resources, including both generation and battery storage, that benefit the grid to which they are connected while also being able to act independently to provide backup services in times of need, such as during an outage.
With any microgrid project, North Carolina’s electric cooperatives look at three primary objectives: demand response, resiliency and sustainability. But microgrids have use cases beyond resiliency and reliability. They provide broader benefits to a utility’s portfolio and add member value, ancillary services and potentially asset deferral.
What makes a microgrid go — what helps integrate the disparate components — is the microgrid controller. The controller is divided into three levels. Each microgrid may consist of one or more DERs, for example, a wind turbine, solar array, battery bank, etc., each with its own primary control. Above that the site controller governs what the microgrid can do, such as when and how to connect to or disconnect (island) from the grid and how to dispatch the various resources to best serve the system in its desired configuration. The distribution operator coordinates the site controller, sending commands that are then passed on to the system’s components to make it all happen.
The distribution operator is essential for enabling DERs to function effectively. It is particularly focused on enhancing DER visibility and coordination, which produces operational confidence and, in turn, increased reliability and value to the grid and to members.
NCEC has four active microgrids and one more under development. Two of the microgrids are what are known as residential microgrids that involve entire communities. The Heron’s Nest microgrid, which came online in Shallote, North Carolina, in 2020, grew out of a desire from a builder to develop a sustainable neighborhood. The builder went on to partner with NCEC and the local distribution cooperative, Brunswick EMC.
Each house in Heron’s Nest has rooftop solar and a smart thermostat and water heater that can be controlled for demand response. There’s an additional solar-plus-storage system at the head of the neighborhood. The combination of power generation at individual homes and at the community level, with storage, can be used in the event of an outage but also during everyday operations.
NCEC’s second residential microgrid, Eagle Chase, launched in spring 2021 outside Wake Forest, North Carolina. A developer approached Wake EMC, the local electric cooperative, about adding backup generation to each home. The groups ultimately decided that a single generator for the entire neighborhood, plus battery storage, would be more practical. In all, the microgrid controller and its resources can provide 36 hours of backup power to the community, on top of daily support.
The grid is evolving. With the help of distribution operators, Ragsdale concluded, the continued growth of DERs can open up new opportunities for enhanced reliability and resiliency for North Carolina’s communities.
To learn more about grid reliability and resiliency and how North Carolina is modernizing power generation and distribution, visit www.ncsmartgrid.org, where you can find previous webinar recordings, case studies and additional resources.