Distribution Systems and Their Susceptibility to Severe Weather Events
The overhead distribution system is vulnerable to severe weather events such as hurricanes, wind, rain, lightning, ice, freezing rain, and snow. These events can challenge the electrical distribution grid’s resiliency and may result in power outages.
Because of this vulnerability, consideration is often given to moving circuits underground. Underground systems, however, are significantly more expensive than overhead systems and are not immune to the effects of weather. Flooding can quickly overwhelm vaults and related underground facilities leading to significant outages. Repairs with underground outages are typically more complex, more expensive, and result in longer restoration times.
Best Practices and Distribution Grid Maturity
Today, utility distribution grids are operated using a wide range of systems. The most common consist of a manually operated system from the substation breaker to the line disconnect switches. The most mature systems include advanced protection relays and controllers at the station and at strategically selected points controlled by advanced automation software and under remote dispatcher supervision.
To maximize the benefits and minimize the costs of distribution automation (DA) systems, utilities often prioritize them. They deploy varying automation levels depending on the criticality of the load, the number of customers served, and technical factors such as available communications infrastructure and existing levels of remote control. Most utilities also attempt to match the level of automation to the consumers’ willingness to pay for those higher levels.
The most troublesome circuits are measured in total customer outage minutes and in the frequency of sustained outages. These worst performing circuits are ranked to receive the highest level of automation. Outages associated with overhead circuits occur more frequently than with underground circuits, but are typically of a shorter duration. Figure 1 shows a common method of ordering circuits based on total customer outage minutes per year.
The data enables a utility to select a smaller number of circuits, 200 in this example, which represented 22 percent of the total number of circuits, but accounted for 70 percent of the total average annual outage minutes.
Figure 1 : Sample Prioritization Method
Distribution Grid Automation and System Benefits
The most advanced automation systems can reduce outage times by automatically detecting a fault, isolating the faulted section from the grid, and restoring service to unfaulted sections. The distribution operator then directs a crew to repair the problem, restore the service, and return the system to normal. This can reduce the time and frequency of outages and reduce the costs of locating the fault and manually operating switches. These systems can also improve safety for the public and utility workers since faults, such as downed wires, are cleared quickly and utility workers can efficiently manage their work since they can visualize and control much of the distribution grid.
Weather events such as hurricanes or winter storms can challenge a utility’s ability to restore power using DA. For instance, outages can be widespread and much of the grid infrastructure can be de-energized, reducing the options to restore unfaulted sections. However, remote supervision and control of the distribution system can significantly reduce the repair and restoration times.
NSTAR Distribution Grid Modernization Case Study1
NSTAR is an operating company of Northeast utilities that delivers safe and reliable electricity to 1.1 million electric customers in 81 communities in eastern, central, and southeastern Massachusetts. It makes grid modernization decisions by focusing investments on enhancing grid infrastructure to provide a safer, more reliable, and cost-effective service for customers.
NSTAR has made significant investments in DA and other grid-facing Smart Grid equipment. Its DA system utilizes sensors that communicate with remote operations and are managed by an auto-restoration system. The system consists of remote supervisory control of more than 2,000 overhead and underground switches and more than 5,000 voltage and current sensors. Nearly 80 percent of NSTAR customers benefit from its DA system.
NSTAR’s auto-restoration system has three operator modes:
- Mode 1 Supervisory—leverages remote control of switches and utilizes operator controlled sequences.
- Mode 2 Operational Acknowledgement—utilizes computer-simulated restoration sequences and operator validation and execution.
- Mode 3 Self-Healing—computer-determined and executed restoration sequences with little human intervention.
NSTAR Distribution Automation System Performance
Since the NSTAR DA system was first deployed in 2004, more than 600,000 customer outages have been avoided due to automated grid sectionalizing. In addition, NSTAR’s customers have experienced benefits resulting from fewer and shorter outages.
NSTAR’s operators have also been able to rapidly restore customers’ power using a combination of its DA system and transmission automation system. In 2011 during tropical storm Irene, NSTAR had 506,000 total customer interruptions and 232,000 customers were restored in less than one hour. For outages during the first nine months of 2012, 71,000 customers avoided a sustained outage and 163,000 customers were restored within five minutes or less. In 2012, Superstorm Sandy impacted 400,000 customers and 274,000 customers were restored in the first 24 hours.2
As with most mature systems, benefits can become increasingly difficult and expensive to achieve. The utility industry continues to look at ways to leverage advances that help reduce the cost of saving an additional outage or reducing an additional outage minute.
The most common advance is a further cost reduction in sensor and communication system costs. Many of these reductions come from leveraging additional functionality to realize additional benefits. It is common to leverage the communications network for additional uses including other automation functions such as VAR optimization and advanced metering infrastructure (AMI) backhaul. This helps reduce infrastructure costs of the communications network.
Some utilities leverage their AMI systems to detect or verify customer outages. This helps reduce the time to respond to an outage and improves the ability to detect a nested outage. Many utilities also use AMI systems to verify an outage when they receive a “no-light” call. This reduces costs of validating the outage manually.
Utilities are also using social media to better understand the location of a problem and to communicate with customers. This provides a significant amount of data that can be analyzed and visualized by the operators, maintenance, and field crews.
Severe weather challenges the electrical distribution grid resiliency; however, the commitment by utilities to further modernize the grid can reap the benefits of reducing outage times, improving customer service, and better managing costs. These efforts prepare the utility and its distribution grid for the next big challenge.
Next | Integrating a Fault Location Isolation, and Restoration System into an Outage Management System
Gelbien, Larry, Vice President of Engineering, NSTAR, and Schilling, Jennifer, Director of Asset Management, Western Massachusetts Electric Company. “Electric Grid Modernization Working Group Kick-Off Workshop,” Department of Public Utilities, State of Massachusetts, November 14, 2012