BY ROBERT ULUSKI, UTILITY INTEGRATION SOLUTIONS INC.
Many electric distribution utilities are considering deploying distribution automation as part of their grid modernization strategies to improve reliability, efficiency, asset utilization and performance of the power delivery system.
Most distribution automation applications require significant technical and financial investment.
Before embarking on a widespread distribution automation deployment, electric companies must know for the benefit of customers and shareholders if the expected benefits outweigh the expected costs.
This article focuses on the costs and benefits of the two main distribution automation functions, volt-VAR optimization (VVO) and fault location isolation and service restoration (FLISR), that are being implemented or considered by many electric distribution utilities.
VVO is a distribution automation application function used to improve the overall efficiency of the electric distribution system through optimal control of capacitor banks, voltage regulators and possibly in the future distributed energy resources.
FLISR, the self-healing grid, is a distribution automation application that automatically detects and isolates distribution feeder faults and then quickly restores service to customers connected to healthy portions of the feeder with little or no manual intervention.
Figure 1 contains a block diagram of a typical distribution automation system.
The Cost Side
Implementing a distribution automation system is expensive.
Initial costs include procuring, implementing, testing and commissioning various supervisory control and data acquisition (SCADA)-ready, medium-voltage (12-kV to 35-kV) power apparatus (line switches, switched capacitor banks, voltage regulators, etc.), installing new sensors and adding intelligent controls to manage the operation of these individual components.
Significant improvements to the electric distribution system infrastructure, such as connecting existing radial feeders to a backup source of supply and feeder reconductoring, also might be needed to avoid overloads and undervoltage after feeder reconfiguration.
The distribution automation devices must be able to exchange information and control commands on a nearly real-time basis; that is, the latency, or delay, associated with these information exchanges must be five to 10 minutes or less.
This requires a reliable, effective communication network that covers the utility’s entire service territory.
Lack of a suitable communication infrastructure poses a significant barrier to successful distribution automation implementation.
In addition to these initial costs, electric distribution utilities must develop and implement an effective commissioning strategy to enable system operators to transition to the new distribution automation system.
The expenditures don’t end when the system is running. Periodic system updates, ongoing maintenance and upgrades to components that are relatively short-lived from an electric utility perspective also must be considered.
Utilities have been able to minimize costs by leveraging existing equipment on the feeder. Examples of this include
- Adding motor operators to enable automatic control of existing gang-operated switches as shown in Figure 2;
- Adding two-way communication interfaces to existing line reclosers;
- Leveraging an existing two-way communication infrastructure, such as the advanced metering infrastructure backhaul communications network; and
- Using information supplied by existing power apparatus rather than installing separate standalone sensors.
Nonetheless, costs ranging from $200,000 to $300,000 per feeder and higher in some cases can be expected with ongoing annual maintenance costs of roughly 3 to 5 percent of the investment amount. The value of distribution automation benefits must exceed these costs to justify the investment.
The Benefit Side-VVO
The VVO application controls switched capacitor banks, voltage regulators and, in the future, distributed energy resources to achieve one or more utility-specified business objectives.
Figure 3 depicts a representative VVO solution. Potential VVO benefits include but are not limited to
- Lower electrical losses by improving the power factor on the feeder to near unity through power factor correction. It is possible to reduce electrical losses on the electric distribution system by 5 to 10 percent. If the electric losses to begin with are some 4 percent of total energy consumption, then the loss reduction would be 0.2 to 0.4 percent of total energy consumption. This might seem like a small percentage, but the resulting loss savings is many gigawatt-hours, which could result in significant cost savings.
- Lower electrical demand during peak-load conditions through power factor correction and voltage reduction. It might be possible to reduce demand 2 to 3 percent of peak load. This can result in a significant savings in capacity charges for purchased power or the elimination or deferment of capacity additions.
- Fewer device operations for electromechanical power apparatus (voltage regulators, capacitor banks, etc.). It is possible to select “minimize number of device operations” as a VVO business objective. In this case, the VVO algorithm will propose a switching plan that minimizes the number of device operations. This will reduce wear and tear on the power apparatus, lower maintenance costs and potentially extend the useful life of the equipment. Some VVO solutions increase the number of electromechanical operations; in such cases, changes in the number of device operations would be viewed as a negative expense or cost.
Some VVO benefits do not necessarily have a direct positive impact on a utility’s bottom line; however, these benefits will lower the cost of service to customers, which ratemakers often view favorably.
The Benefits Side-FLISR
FLISR allows a utility to detect and isolate feeder faults quickly and then rapidly restore power to customers who are connected to healthy portions of the feeder with little or no manual intervention.
Figures 4a and 4b show the configuration of a faulted feeder before and after FLISR operation.
As a result, when a permanent fault occurs, some customers who normally would be without power for an hour or longer during the repair or restoration process have their power restored in less than five minutes.
Figures 5a and 5b contain service restoration time lines with and without FLISR.
Potential FLISR benefits include 50 percent or more improvements in System Average Interruption Duration Index and System Average Interruption Frequency Index.
Some increase in momentary interruptions might occur as long outages-longer than five minutes-become Momentary Average Interruption Frequency Index incidents-interruptions less than five minutes.
Monetizing Benefits is Significant Challenge
To perform a distribution automation benefit-cost analysis, the benefits must be expressed in dollars to enable comparison with the costs (also expressed in dollars).
Many benefits provided by distribution automation (e.g., reliability and efficiency improvements) do not translate easily into monetary terms.
Consequently, plausible cost-benefit comparisons can be difficult to perform. For example, the application FLISR provides significant improvement in customer outage duration; however, there is no well-established procedure for converting improved reliability to direct monetary benefits to determine if these benefits outweigh the high implementation cost for this application.
Several mechanisms for monetizing the VVO and FLISR functional and physical benefits are shown in the VVO and FLISR benefit trees in Figures 6a and 6b.
Some expected benefits do not benefit the electric utility’s bottom line directly.
For example, the costs associated with electrical losses often are passed on to customers in the kilowatt-hour rates; however, although such improvements do not directly benefit the utility, investment recovery may be permitted for prudent investments that reduce losses (such as VVO) for the benefit of the customers.
Verifying the Benefits
One of the most significant challenges facing utilities that are conducting distribution automation projects and proof of concept demonstrations is determining the benefits that can be attributed to distribution automation.
Determining the benefits would be simple if feeder loading and operating conditions were consistent from day to day.
If loading and operating conditions were identical each day, it would be simple to apply distribution automation for a day and then compare the day’s results with the previous day’s.
Unfortunately, determining the benefits is not that simple.
The electrical conditions of every feeder can vary significantly from day to day because of changing weather, random customer behavior and other factors.
The most common approach for determining FLISR incremental benefits is to record the time sequence of each FLISR operation and then manually replay the event assuming that FLISR was not present.
During the manual replaying of the event, an electric utility can assume average travel, fault investigation and manual switching times that normally would occur if FLISR is not present.
This straightforward approach enables the utility to determine impacts on customer outage duration and frequency for each event with and without FLISR.
The difference between the with-FLISR and without-FLISR calculations is the incremental benefit.
The measurement and verification process for VVO is more complicated than FLISR measurement and verification described because it is difficult to distinguish between performance impacts that can be attributed to VVO and naturally occurring variations.
Utility companies often resort to day-on/day-off testing and robust statistical analysis over an extended period to determine what would have happened if VVO were not deployed.
The difference between measured values and the results of the what-would-have-happened analysis is the incremental VVO benefit.
Distribution automation has proved effective for improving the efficiency, reliability and overall performance of the electric distribution system; however, it also has proved costly.
Before embarking on a distribution automation project, an electric distribution utility should do a thorough financial analysis of all costs and expected benefits.
Small-scale demonstration projects might be needed to support this analysis.
Robert Uluski is vice president of distribution automation/DMS systems at UISOL, an Alstom company. He has more than 35 years of experience in electric utility transmission and distribution automation systems. His background includes tenures with the Electric Power Research Institute, Quanta Technology, EnerNex Corp. and KEMA. Reach him at ruluski email@example.com
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