By Robert W. Uluski & Dr. John H. Spare
Service reliability has become one of the hottest issues facing today’s electric utilities. Customers are particularly sensitive to outages and disturbances on the electric distribution system, which are usually due to permanent or momentary faults on distribution feeders. Some particular distribution automation applications can improve distribution system reliability, but these applications can sometimes be hard for utilities to cost justify.
Motivating Factors for Automation
The driving forces for improving distribution system reliability include maintaining or improving customer satisfaction, avoiding unfavorable actions of the state regulatory commissions and obtaining the monetary incentives imposed by the commissions. Maintaining customer satisfaction is key to customer loyalty and retention. Most electric utility customers are primarily interested in two main issues: How much is my bill? And, why aren’t my lights on? Satisfied customers are more likely to do business with the unregulated businesses (energy suppliers) that are affiliated with their local regulated utility. Furthermore, satisfied customers are unlikely to complain to regulatory agencies when the performance of their electric utility is less than satisfactory for a particular incident.
Regulatory issues play a big role in distribution reliability improvements. During the past two years, more than half of the state commissions have undertaken some type of rulemaking or proceeding focused on distribution system reliability. The activity has ranged from formal standard setting for reliability metrics to informal acknowledgement that the issue warrants attention. Regulators’ major concerns are outage frequency and interruption durations.
A utility’s performance does not necessarily have an associated monetary penalty or reward. In many cases, however, reliability may be based, in part, on established reliability metrics (Table 1). Metric performance may be considered in rate-of-return and performance-based rate (PBR) proceedings (where applicable). Some states have established PBRs that include reliability performance metrics. Service quality incentives include reliability (outage duration and/or frequency-system wide or class specific) and customer satisfaction (call center response, customer surveys, number of complaints). PBRs tied to service reliability are often established for utilities participating in merger or takeover activities to ensure that system reliability does not suffer following the merger. The possible rewards and penalties may be substantial, as illustrated by the examples in Table 2.
Potential Impact of Automation on Distribution Reliability
Many utilities have focused their reliability improvement efforts on feeder design improvements, vegetation control, animal guards, alternative conductor arrangements (spacer cable), use of underground vs. overhead lines, and other traditional methods which primarily are intended to reduce the number of outages and disturbances. Studies and actual implementation experience have shown, however, that distribution automation can also provide additional reliability improvements, especially in outage duration and frequency. Some of the most beneficial applications are substation automation, equipment condition monitoring, feeder automation and intelligent load restoration schemes.
For many years, electric utilities have applied SCADA systems for remote monitoring and control of substation equipment. The findings of KEMA Consulting’s recent studies indicate that SCADA systems, when used to monitor and control the distribution feeder breakers, can provide a 15 percent to 20 percent reduction in average customer outage duration (SAIDI) when compared with a similar feeder that is not equipped with SCADA facilities. This reduction in outage time results primarily from the dispatcher being informed immediately of a switch operation and taking action before customers call to report the outage. SCADA systems can also provide the dispatcher with fault location clues that can help reduce feeder patrol time. In addition, substation SCADA systems provide system operators with immediate notification when an interruption occurs, so that service restoration activities can start immediately. Substation intelligent electronic devices (IEDs) can also provide an estimated fault location, which can cut feeder patrol time in half.
While many electric utilities have already implemented SCADA systems in most of their substations, pockets of non-SCADA substations still exist, primarily in smaller substations and particularly in remote locations where communications have been difficult. Some utilities have been reluctant to install SCADA at these sites due to the expense of installing remote terminal units (RTUs) in such remote locations. However, the evolution of substation IEDs as a form of “mini-RTU” and the widespread availability of wireless communications and utility-owned fiber optic communication facilities has made SCADA capability economically feasible even at small remote stations. Electric utilities can exploit these new capabilities to achieve significant reliability improvements, even in remote parts of their service territory.
Equipment Condition Monitoring
A different type of automation is used in equipment condition monitoring to maintain electric equipment in top operating condition while minimizing the number of interruptions. Operating parameters are automatically tracked and trended to detect the emergence of various abnormal operating conditions, allowing maintenance personnel to take timely action when needed. This approach is applied most frequently to substation transformers and breakers to minimize their maintenance costs as well as improve their availability.
Reducing the amount of off-line maintenance and testing increases equipment availability and reliability, and reduces the number of equipment failures. To be truly effective, equipment condition monitoring should be part of a properly designed overall condition-based maintenance strategy, and should be integrated into the regular maintenance program (Ref. 2).
Feeder automation involves the use of automatic and/or remote-controlled switchgear out on the feeder. In many cases, automatic and remote controlled switchgear enables the utility to automatically locate and isolate faulted portions of the distribution circuit, restore power to the unfaulted feeder sections, and then return the feeder to its normal configuration after repairs are completed. Such schemes are able to reduce outage times from one hour or more down to five minutes or less for customers on unfaulted feeder sections. A recent study performed by KEMA Consulting for Luz y Fuerza de Central-the electric utility of Mexico City-determined that distribution system reliability could be improved 30 percent to 40 percent by implementing remote controlled switching on its worst performing feeders.
Feeder automation results in reduced outage time because restoration activities can begin before customers call in and before field crews arrive at the scene. This can be especially beneficial during storm emergencies when multiple outages are in progress and crew response must be prioritized. Feeder automation systems may permit power to be restored to many customers without crew intervention.
Utilities that have implemented line reclosers on their feeders can achieve some of the benefits of feeder automation by adding communication facilities to their reclosers. Communication facilities will enable distribution system operators to monitor the reclosers’ operation, so that system restoration activities can begin immediately rather than waiting for customers to call in.
While reliability improvement benefits are potentially large from feeder automation, there are several important design considerations:
- Diminishing Returns: Adding a single automated switch to a feeder usually produces sizable reliability improvement benefits, however, adding two or more switches usually produces relatively small incremental benefits.
- Load Transfer Capability: The capability to transfer significant portions of a faulted feeder to an adjacent feeder from the same or different substation is key. At many utilities, transfer capability may be limited, especially during peak load periods.
- Placement of Controllable Switches: The choice of switch placement locations can have a sizable impact on the reliability improvement benefit. Recent studies have shown that SAIDI improvements can vary by 20 percent to 25 percent depending on the switch location. Switch placement to achieve the maximum reliability improvement benefit depends on many factors, such as feeder topology, location of key customers (hospitals, government buildings, etc.), fault distribution and availability of normally-open feeder tie switches.
Intelligent Load Restoration Schemes
Some electric utilities are unable to carry the entire substation load when one of two transformers that normally share the load fails during peak load conditions. Remote controlled feeder switching will enable the electric utility to transfer portions of feeders to an adjacent substation so that automatic bus transfers can occur in the substation with the failed transformer. Intelligent load transfer schemes can help an electric utility avoid temporary load shedding actions during an emergency, such as substation transformer failure.
An important side benefit of the remote controlled switching is the ability to acquire information on the equipment conditions out on the distribution feeder, such as voltage level and loading. These facilities will also enable electric utility personnel to acquire disturbance and power quality information from out on the feeder, close to the customer.
Outage Detection Units
Even the most sophisticated feeder automation systems may have difficulty detecting outages on feeder branches and lateral taps that are protected by fuses. Blown fuses typically go undetected until customers served by the fuse call in to report the outage, which can add minutes or even hours (for overnight faults in residential neighborhoods) to the outage duration. Typically, branch fuses protect more than 75 percent of residential feeders’ load, and outages that cause the fuses to blow may go undetected by the feeder automation system.
To detect outages on branch lines, many electric utilities have employed outage detection units that are able to detect voltage loss and automatically initiate a telephone call to inform the dispatcher about the problem. The outage detection units can also provide outage notification to the utility’s outage management system. These relatively low cost devices are plugged into the wall socket at selected residences and connected to the customer’s telephone. When power is lost, the outage detection unit automatically dials the dispatcher or outage management system to indicate that the power is off at the site.
Outage detection units can also be valuable to small firms that have refrigeration units or other equipment that must run even during off-hours.
Justification of Distribution Reliability Improvement Measures
Economic justification of reliability improvement measures by traditional means represents a difficult challenge for electric utilities. This situation is primarily due to the lack of documented, tangible, “hard” benefits (actual dollar savings) in the industry. In many cases, the monetary benefits are limited to the reduction in unserved energy, which is the additional revenue that is achieved by having fewer and/or shorter service interruptions. In most cases, the additional revenue is quite small compared to the cost of achieving the reliability improvement.
Reliability improvement benefits include:
- Improvement in system or feeder reliability indices-reduced SAIDI and SAIFI;
- Sizable reward or reduced penalty under performance based ratemaking (where applicable);
- Reduction in “unserved energy”-lost opportunity to sell kilowatt-hours when the power is off;
- Labor savings-fewer manual switching activities or service restoration jobs required;
- Reduction in customer outage costs (traditionally a “soft” benefit).
Generally, there is no consensus in the industry about how to justify reliability improvement measures. One approach used in quantifying reliability’s worth or benefit is to estimate the customer costs (monetary losses) associated with power interruptions. Customer outage costs can be substantial. One study (Ref 3) indicated that the average one hour interruption cost for commercial and small industrial customers was approximately $10/kW and $4.30/kW, respectively. Typically, electric utilities use customer outage cost savings only as “soft” (non-monetary) benefits and do not use the savings as a monetary benefit in a benefit-cost analysis.
A number of utilities have performed customer satisfaction surveys to help determine the relationship between service reliability and customer satisfaction when trying to justify costs. Some have taken the study one step further to establish a relation between customer satisfaction and revenue-related issues such as customer retention. This approach appears to have merit, but as yet, there is not widespread acceptance of these values and technique.
Another cost justification method that appears to have merit in some circumstances is to compare the costs of various reliability improvement measures and determine which measures offer the highest payback. This approach is suitable for use in states, such as Idaho, where the utility is required to improve SAIDI and SAIFI performance by 10 percent and MAIFI by 5 percent. The approach is also valid in cases where the electric utility has decided to spend a fixed amount on reliability improvement and is seeking to prioritize the possible reliability improvement measures.
If customer interruption costs are considered together with other reliability benefits, it is possible to do an overall evaluation of the most cost-effective reliability level. All areas that affect reliability should be considered, including equipment upgrades, automation, maintenance, operations and system design.
Very significant distribution system reliability improvements can be achieved by employing distribution automation on all or selected portions of the distribution system. The most significant improvement that can be achieved using automation is in the area of outage duration reduction, where improvements of 25 percent to 30 percent are readily achievable. Such improvements can help achieve reliability thresholds and targets established by regulators, and greatly improve customer satisfaction in an area that has historically experienced reliability problems.
Robert W. Uluski, P.E. and Dr. John H. Spare, P.E. are members of KEMA Consulting’s Power Delivery Services business area, specializing in distribution automation, reliability engineering, and reliability centered maintenance consulting services. Mr. Joseph Bucciero and Mr. Doug Bowman of KEMA Consulting, and Mr. Bruce Humphreys of XENERGY Inc. also provided input to this article.
- “Performance-Based Regulation (PBR) Companion Study”; Henry Y. Yoshimura, XENERGY, Inc.; from the proceedings of the Performance-Based Ratemaking Conference sponsored by KEMA Consulting, November 9-10, 2000.
- “PEPCO’s Integrated Substation Equipment Condition Assessment Program”, T. Pierpoint, J. Spare, EPRI Substation Equipment Diagnostics Conference IX, 2001.
- “A Canadian Customer Survey to Assess Power System Reliability Worth”; G. Tollefson, R. Billinton, G, Wacker, E, Chan, J. Aweya; IEEE Transactions on Power Systems; February 1991
- “Electric Distribution System Reliability Target Based on Total Cost of Service Analysis”, InterRAM Power Industry Reliability Conference, J.H. Spare, 1992.