Distribution Automation - A General Business Case for Intelligent Switches for Electric Power Distribution System Reliability
- Jun 22, 2018 7:00 pm GMT
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Power distribution systems were designed to be simple and dependable because of the immense scale, circuit miles, and capital investment necessary to initially construct them. As the distribution system is modernized in conjunction with increased levels of Distributed Energy Resources (DERs), it is important to maintain safe and dependable operation while designing an inherently more complex system. With increasing electricity supply coming from the DERs, distribution circuits will have a larger role in overall system reliability. The present grid was not designed to rely on generation at the distribution side. Therefore, minimizing the effect of power supply interruption has dual effects in ensuring that the customers are served, and that the DERs continue to generate and support the system.
There are several elements of a grid modernization strategy (GMS) that can lead to a much better understanding of the state of the grid and associated distribution circuits in near real-time. Advanced distribution planning is necessary to achieve more efficient distribution operation. An example of advanced distribution planning process can be summarized as follows:
- Creating or actively updating a software model for each distribution circuit.
- Gathering historical data such as fault locations, outages, circuit performance, customer types, etc. This information could be used in predicting load growth and DER growth, as well as in providing a reference for circuit performance metrics.
- Run simulations on the model with “as is” condition. Several metrics can be calculated, such as loadings, losses, phase balance, overvoltage/undervoltage, and an evaluation of assets, such as capacitor banks, etc. can be performed.
- Run similar cases for future scenario models against current scenario models and compare the results. Future scenarios could include DER penetration levels, or various load growth patterns. Make a list of upgrades/rebuild plans, such as replacing lines, adding lines or maybe even building a new substation to meet the demand.
- Perform a distribution automation study to evaluate fault indicators, reclosers, protective relays, cap banks switching, regulator operations, reliability etc.a
- Monitor reliability metrics in all the simulations if possible. Plan to integrate modern microprocessor controlled devices for protection and automation. Modern Intelligent Switches, the ones whose impact is studied in this article, help in circuit automation providing benefits such as advanced monitoring, intelligent protection, and reliability improvement.
- Perform cost benefit studies for all new installation/upgrades possibilities. An example cost benefit study of implementing intelligent switches for reliability improvement is presented in this article.
- Execute the most appropriate circuit upgrade.
These steps describe just a general example of an advanced distribution planning process. This process may vary from utility to utility based on their grid modernization strategies. This study performed in this article is a subset of the works mentioned in step 6, 7 and 8.
Regardless of the planning strategy, safety should be the topmost priority. Key aspects of a safe power distribution system include detecting faults and taking actions to de-energize the power lines when faults occur. Devices that perform this function are referred to as overcurrent protective devices, or simply “protective devices”. For over 100 years, basic protective devices, like fuses, have been used to detect and interrupt faults. In many schemes, fuses blow and service is not restored until a crew can be dispatched to replace the fuse. In a high-DER environment, the traditional protective devices and schemes are not adequate to maintain dependable electrical power service. Modern distribution switches can be utilized to overcome these challenges by deploying microprocessor-controlled overcurrent protective devices on the distribution system that will interrupt and isolate faults faster, enable proper coordination of overcurrent protective devices, provide advanced protection features, and have the capability to utilize communications for remote supervisory control and automatic restoration.
In addition to the overcurrent protection, modern switching devices with reclosing capabilities can improve reliability. Reclosing is the ability to disengage from a central generation source to interrupt a fault, then after a short delay, close automatically to re-energize the power line. The power system faults such as tree branches contacting power lines, are temporary in nature, which means that the disturbance goes away after some time (i.e., the limb falls off the power lines). Devices with reclosing capability generally wait a designated period of time before closing, and it is this delay that allows the disturbance to be removed so that power can be restored to customers upon reclosing. In other instances, some types of advanced devices are intelligent enough to examine the line in advance to see if the problem still persists. In case the problem has not been resolved, such devices prevent the re-initiation of the problem, therefore, avoiding further equipment damage and mitigating issues that would otherwise impact the grid.
By addressing the challenges associated with DER and system reliability in general, customers and utilities will see benefits in reliability and operational flexibility. As the power system evolves to integrate more renewable energy generation, distribution system reliability becomes even more important as it is vital not only to provide customers with fewer power interruptions but also to keep an increasing portion of generation connected.
This article focuses on demonstrating the importance of the advance intelligent switches as an integral part of the future of distribution planning. The following sections will demonstrate the ability of these advance and intelligent distribution switching devices in maintaining the distribution system reliability through a simple example case study. The example test system considered here and the calculated reliability metrics and cost figures are just for the purpose of illustration while emphasizing the benefits of these intelligent devices in grid modernization initiatives, and are not specific to any one utility or the system under consideration.
Reliability Improvement Case Study
Let’s consider a test circuit as shown in Figure 1 below. This circuit is considered as an example case study to evaluate the effectiveness of the intelligent switches from the reliability point of view.
Figure 1: Test Feeder.
For this example circuit, we made the following assumptions to simplify the overall analysis:
- All the faults are assumed to be temporary. Similar analysis can be done with the permanent fault as well.
- For each of the temporary faults, reclosers opening and closing happens for 3 cycles before the temporary fault is cleared. Reclosers open duration for each reclosing cycle is assumed to be 0.3 seconds.
- Distributed Energy Resources (DERs) cannot operate in islanded mode.
- All the assumed faults occur 10 times per year.
- All lines are overhead and fault locations are uniformly distributed.
- The single-phase fault has 10% customers downstream.
- There are no tie-line connections serving the feeder from another substation.
The system reliability is calculated by utilizing the metrics such as System Average Interruption Frequency Index (SAIFI), and System Average Interruption Duration Index (SAIDI).
SAIFI is defined as the average number of times that a customer is interrupted during a specific time period. It is determined by dividing the total number of customers interrupted in a time period by the average number of customers served. The unit is number of interruptions per customer.
SAIDI is defined as the average interruption duration for customers served during a specified time period. It is calculated by summing the minutes customers are out of power for each interruption during specified time period and then, dividing the sum by the average number of customers served during that period. The unit is in minutes. This index provides the utility with the information on the total minutes customers would have been out of service if all the customers were out at one time.
Generally, the circuit has a single recloser (R1) at the substation. This recloser covers all the feeder area as its protection zone. When all the assumed faults (F-1, F-2 and F-3) occur, the recloser R1 operates creating momentary outages for all the customers in the feeder. With the present architecture, customer momentary outages on this circuit average 27 seconds per year.
Now, let us consider a case when the new recloser, R2 is installed in the mid-point of the feeder, and the lateral recloser, R3 is installed in the section as shown in Figure 1. When the fault F-1 occurs close to the substation as shown, recloser R1 operates causing momentary outages for all of the customers. If the fault F-2 occurs at the location shown, recloser R2 operates. Therefore, in this case, momentary outages are seen only by the customers downstream from the location of R2. In other words, during the fault F-2, only 50% of the customers see momentary outages. Now, if lateral fault F-3 occurs, the single phase recloser R3 operates. During this fault, only 10% of the customers see the momentary outages. Therefore, after the reclosers R2 and R3 are installed, considering the total reclosing time of 0.3 seconds, calculations of System Average Interruption Duration Index (SAIDI) show that average customers’ momentary outages are reduced to 14.4 seconds per year.
When a scenario with only two reclosers (R1 and R2) on the circuit is considered without considering the lateral fault F-3, the average customers’ momentary outage is reduced to 20.25 seconds per year. This 25% improvement is achieved with two reclosers (R1 and R2) as compared to the case with only one recloser at the substation (R1).
This example assumes that the recloser R1 that is already installed has the capability to communicate and coordinate with the newly installed intelligent recloser R2. However, the substation reclosers in the present distribution system could be approaching the limit of its operational span and it might need to be replaced. Moreover, these old reclosers do not have the capability to communicate and coordinate with the new intelligent reclosers. Therefore, it is recommended that two intelligent switches should be installed per circuit for the feeder upgrade.
These types of circuit upgrades are essential for grid modernization as these new smart devices provide more protection and control to the localized parts of the circuit and therefore, help in increasing the system reliability. This means that the existing recloser at the substation, R1 should be replaced with a new intelligent recloser and another new recloser, R2, should be installed at the circuit midpoint to achieve 25% improvement in feeder reliability. Lateral reclosers may be deployed depending upon the requirements to solve some specific reliability problems, or in order to help in routine maintenance of the lateral fuses.
Estimating Benefits and Costs across the Distribution Circuits
In order to estimate the benefits of future intelligent switch installations across the distribution system, we have considered a hypothetical area. The benefits are compared against the assumed cost of installation and a brief summary of economic analysis presented in this section.
A simple methodology adopted in this analysis is described below:
- Assess current system reliability metrics: (SAIDI), and (SAIFI)
- Develop estimates for SAIDI and SAIFI with the investment in a range of quantities of intelligent switches
- Utilize the Interruption Cost Estimate (ICE) Calculator developed by Lawrence Berkeley National Lab to determine the monetary value associated with the achieved improvement in the reliability metric
- Evaluate benefits against estimated cost of deployment
Each of the above steps will be described in detail in the following paragraphs. Similar to the case study presented earlier, following assumptions are made for the result analysis:
- One intelligent switch is placed at the mid-point of the feeder, and another one at the feeder substation. Two intelligent switches are needed to upgrade one circuit.
- The customers are distributed uniformly along the feeder
- There is an equal probability of the fault occurrence on the either side of the mid-point recloser.
- The causes and location of outages are not consistent year over year, but only temporary outages are consistent.
The SAIDI and SAIFI improvement numbers for the example area are assumed based on our experiences with the previous projects. In order to illustrate our idea, we assumed that our test area system serves 275,000 customers, of which 90%, or 250,000 are residential. That leaves 25,000 customers that are non-residential. This area is assumed to have 275 circuits (1,000 customers per circuit). Some circuits perform better than others. Out of the total 275 circuit, 50 of them are the worst performing circuits where the circuit upgrade is more meaningful and beneficial. These worst performing circuits can change as a result of the equipment upgrades, shifts in customer behavior, or vegetation management. The worst performing circuits can vary every year. The causes and location of outages are not consistent year over year.
Table 1 shows the system SAIDI and SAIFI improvements due to the upgrades in various number of test circuits assumed for the test area after the installation of intelligent switches. We assumed a 20 year life cycle for these advanced switches in the ICE calculator.
Table 1: Annual system SAIDI and SAIFI improvements for test circuits upgrade
System SAIDI (minutes)
SAIDI % Improvement
System SAIFI (occurrence)
SAIFI % Improvement
No. of Circuits Upgraded with 2 Intelligent Reclosers
Table 2: ICE Calculator Reliability Improvement Estimate Based on upgrade of 15 Circuits
Number of Circuits Upgraded
Benefit per Customer
Results of the economic analysis are shown in Table 2. We assumed a $50,000 installation cost per advanced switch, which includes engineering, labor, and hardware costs. With these assumptions, we expect the circuit upgrades cost payback of only a few months according to Table 3.
Table 3: Cost-Benefit Analysis for Advanced Switches with Reliability improvement
Number of switches
These payback values are illustrative in nature, and should not alone be considered as a justification for the investment, even while considering actual statistics from a specific utility. Instead, a detailed study, such as the one mentioned in the introduction section should be performed to identify the actual economic benefits.
Also, due to the nature of analysis that retroactively examines the impact of such switches on the worst performing circuits, and due to the fact that the worst performing circuits change every year, the cost figures obtained here may vary drastically from the ones obtained from the deployed switches in the real-world systems. Therefore, detailed analyses as mentioned earlier are absolutely necessary before reaching to any investment decisions.
In this article, we looked deeper into one of the many benefits from the installation of intelligent distribution switches, that is, system reliability improvement with the help of an example case study. The payback period of the cost involved in installing these switches is very short; only a few months. Such advanced intelligent distribution circuit switches have other several applications and benefits that can be leveraged in multiple ways. These switches can be utilized as monitoring devices that can provide near real time measurements of the system parameters. These monitored quantities can then be utilized by Distribution Management System (DMS) algorithms. Such monitored quantities provide better visibility to the distribution system. Improved visibility aids operators to perform control and stability actions more effectively. The applications of such switches support distribution system operational flexibility through distribution feeder reconfiguration, which in turn, has several other benefits such as system loss reduction, load balancing, voltage profile improvement, in addition to the reliability improvement that is presented here.
All of these benefits fit very well into the overall modern grid framework in obtaining advanced distribution system monitoring, protection, and control capabilities because of which the modern distribution grid will be well-equipped to handle the larger penetration of DERs that are required to fulfill the ever increasing electricity demand.