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Past, Present, Future

Impact of distribution management systems

Power distribution systems are the lowest end of power systems and thus are nearest to the customers. It is estimated that the capital invested in power distribution systems worldwide is 40% of the total investment in power systems. Of the remaining 60%, generation accounts for 40% and transmission accounts for 20%. Customers experience the direct impact of events occurring in distribution systems because they are directly connected to it. According to some reports, 80% of the interruptions experienced by customers are due to outages in distribution systems. Although power distribution systems are a large part of power systems and have a direct impact on the customers, integration of automation into their operation and control have lagged considerably behind those of generation and transmission systems. Progress in power distribution system automation has been relatively slow due to the large investment needed to automate these systems with an extremely large number of components. Now, with the infusion of smart grid technology, new challenges and opportunities are emerging. Smart grid initiatives and funding by the federal government for utilities implementing smart grid technologies has accelerated activities related to distribution automation (DA) and smart metering. Similarly, the number of customers installing rooftop solar generation or owning plug-in hybrid or electric vehicles is gradually increasing. The high penetration of such devices creates new dynamics for which the current equipment in distribution systems is inadequate. Rapid fluctuations of power output from distributed renewable resources causes severe voltage control problems. Further, current standards do not permit the operation of distribution systems in islanded mode with distributed generation. New standards to permit the operation of a distribution system as a microgrid will be of extreme value to maintain the availability of power supply to customers upon the loss of power from the grid and under natural disasters, such as hurricanes and earthquakes as well as terrorist acts.

Currently, very little real-time information is available to operators from the distribution system. Most often, the only real-time measurement available for distribution systems is from the feeder gateway at the substation. As a result, most of the operation and planning of distribution systems has relied on heuristics and archived information. For example, every utility records load demand at a select group of customers representing different load classes. This activity is called load research. These statistical sample data provide information for operation and planning. Due to the lack of automation, most of the distribution systems operate in nonoptimum mode and have difficulties in recovering from abnormal events. Attempts to automate electricity distribution to improve system operation have been ongoing since the introduction of the concept of DA in the 1970s. Advances in computer and communication technology have made DA possible. Automation allows utilities to implement flexible control, which would result in enhanced efficiency, reliability, and quality of electric service. Flexible control also results in more effective utilization and life-extension of the existing distribution system infrastructure. Several utilities have run pilot projects and some have implemented automation based on their needs. However, there are no cases where we find comprehensive automation of distribution systems. In parallel with DA, significant activity has taken place in the automated metering infrastructure (AMI), which deals mainly with the placement of smart meters in homes to measure and monitor electricity, gas, and water consumption. Information from AMI systems has also been used by utilities for outage management.

Now, with additional technological progress, the current level of automation is not sufficient. Until now, the major focus of the smart grid has been on advanced metering, but in the coming years, the utilities will be gearing up to focus more on DA. In addition, today's customers are more willing to participate in activities that result in energy conservation and generation of electricity from renewable resources. We see many people opting to install rooftop solar generators as well as energy storage devices in their homes. Similarly, we can expect people to gradually migrate toward plug-in hybrid and electric vehicles. The higher penetration of such devices in distribution systems poses new challenges as well as offers new opportunities. Distribution systems of the future will have homes with smart meters to monitor energy consumption, on-site grid-connected solar or wind generation, battery storage, and plug-in vehicles. The feeders will have advanced power electronic switching devices to control the system, and sensors at strategic locations to measure the flow of real and reactive power, voltage, and current. Similarly, the substation will have power electronic controls, measurements, and protection to operate the system more efficiently and reliably. The system will have a seamless communication layer from the utility's control room to customers, and it will be integrated with advanced cyber systems to enable its operation. Substantially more real-time information will be available to facilitate their operation and control.

Since there has been no comprehensive approach to the automation of distribution systems, the dis-tribution management sys-tem (DMS), which, in general, can be defined as a computer- and communication-based system to manage the distribution system, has had different meanings to different utilities. It could be a system for DA, outage management, or facilities and work order management utilizing the geographical information system (GIS). In many instances, we find different systems within the same utility addressing different system management issues. These systems employ application interfaces between dissimilar applications and frequently these applications run on separate noncompatible databases. The synchronization of databases is a constant concern and maintenance issue for the existing DMS.

Integrated Distribution Management System

In the future, various management activities in distribution systems will be integrated, which will be managed by the next generation integrated distribution management system (IDMS). The IDMS will use a connected model based on the GIS, and it will utilize interconnected relationship and connectivity of various distribution system components including the substation and its associated control and intelligent discrete sites along the distribution circuits. The operators will have a full view of the electric distribution system, including customer information system (CIS) as well as outage management system (OMS) data. Techniques for analysis, information display, and navigation are being developed to assist the operators in responding to the dynamics of the distribution system and to system disturbances. Further, real-time applications for automated management of the smart distribution systems are being explored.

The management of distribution systems of the future would require faster decisions and thus real-time analysis of distribution systems. Since more data can be measured, the analysis becomes more complex. The tools should be able to use these data effectively. As an example, real-time monitoring and analysis would lead to faster system restoration following emergencies. Since most of the equipment is expected to operate near capacity, long duration outages can lead to problems due to enduring component of cold load pickup associated with thermostatically controlled devices, such as air conditioners. In such cases, step-by-step restoration would be needed to avoid stressing the transformers beyond their capability. Real-time monitoring and analysis not only provide the status on loading of equipment but also allows determination of the next step, such as location and time of the next switch to be closed to restore a group of customers. With judicious selection, restoration can be accomplished in little time; thus improving the reliability of electricity supply to the customers. Some applications expected to be integrated in the next generation of IDMS include the following:

  • optimal volt/volt-ampere reactive control

  • real-time analysis

  • adaptive protection

  • contingency evaluation

  • advanced fault location and service restoration

  • dynamic loading of power equipment

  • operation with large penetration of customer-owned renewable generation

  • operation of the system as a microgrid

  • real-time pricing and demand response.


As we have clearly seen, there is a real need to deploy a new generation of DMS in the distribution system to operate with a higher reliability and efficiency. However, cost has been and will be a big impediment to the widespread deployment of the IDMS. The distribution systems in the United States have operated with very high reliability even without much automation. Therefore, unless the utilities see a real bottleneck in their operations, they would be reluctant to make large investments. Smart grid funding initiatives by the U.S. Department of Energy for implementing automation in utility operation is a step in the right direction. Such incentives allow utilities to invest in activities that they might not otherwise consider seriously. The collective experience gained by such projects can show the benefits to other utilities and thus speed up the process. Continuation of such funding in the future is very desirable but uncertain.

The Role of Customers

In the future, a lot will depend on the customers' actions. Their actions will make it necessary for utilities to modernize their systems. For example, the success of plug-in vehicles and their rate of acceptance by the customers is unclear at present. Similarly, the future penetration of customer-owned renewable generation is not known. Some parts of the country will see more of these activities than other parts. The cost of electricity and equipment, incentives by federal and state government, desire of customers to be green, and opportunities for the customers to sell power to the grid will be some of the factors that will determine this growth. Larger penetration of such devices will force utilities to modernize their system to manage it more effectively. So the question really is: “Should the utilities start modernizing their system in anticipation of change in customer-level activities, or should they wait for changes to take place first?” There is no clear answer to this question. What is definitely clear, however, is that the DMS of the future will be different from today's system. They will integrate many new functions while utilizing common databases.

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