1540-7977/11/$26.002011 IEEE112 IEEE power & energy magazine september/october 2011
PPOWER 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 world-wide is 40% of the total investment in power systems. Of the remaining 60%, generation accounts for 40% and trans-mission accounts for 20%. Customers experience the direct impact of events occurring in distribution systems be-cause they are directly connected to it. According to some reports, 80% of the interruptions experienced by custom-ers are due to outages in distribution systems. Although power distribution systems are a large part of power sys-tems 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 ex-tremely large number of components. Now, with the infusion of smart grid technology, new challenges and op-portunities are emerging. Smart grid initiatives and funding by the federal government for utilities implementing smart grid technologies has acceler-ated 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 ve-
hicles is gradually increasing. The high penetration of such devices creates new dynamics for which the current equip-ment in distribution systems is inad-equate. Rapid fl uctuations of power output from distributed renewable re-sources causes severe voltage control problems. Further, current standards do not permit the operation of distri-bution systems in islanded mode with distributed generation. New standards to permit the operation of a distribu-tion system as a microgrid will be of extreme value to maintain the avail-ability 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 in-formation 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 substa-tion. As a result, most of the operation and planning of distribution systems has relied on heuristics and archived information. For example, every util-ity records load demand at a select group of customers representing dif-ferent load classes. This activity is called load research. These statisti-cal sample data provide information for operation and planning. Due to the lack of automation, most of the distribution systems operate in non-optimum mode and have diffi culties in recovering from abnormal events. Attempts to automate electricity dis-tribution to improve system operation
have been ongoing since the introduc-tion of the concept of DA in the 1970s. Advances in computer and commu-nication technology have made DA possible. Automation allows utilities to implement fl exible control, which would result in enhanced effi ciency, reliability, and quality of electric ser-vice. Flexible control also results in more effective utilization and life-extension of the existing distribution system infrastructure. Several utili-ties have run pilot projects and some have implemented automation based on their needs. However, there are no cases where we fi nd comprehensive automation of distribution systems. In parallel with DA, signifi cant activ-ity 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 automa-tion is not suffi cient. Until now, the ma-jor 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, todays customers are more willing to partici-pate in activities that result in energy conservation and generation of electric-ity from renewable resources. We see many people opting to install rooftop so-lar generators as well as energy storage
past, present, futureimpact of distribution management systems
(continued on page 109)Digital Object Identifi er 10.1109/MPE.2011.941703 Date of publication: 18 August 2011
september/october 2011 IEEE power & energy magazine 109
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. Distri-bution systems of the fu-ture will have homes with smart meters to moni-tor energy consumption, on-site grid-connected solar or wind generation, battery storage, and plug-in vehicles. The feed-ers will have advanced power electronic switch-ing devices to control the system, and sensors at strategic locations to measure the fl ow of real and reactive power, voltage, and
current. Similarly, the substation will have power electronic controls, mea-surements, and protection to operate the system more effi ciently and reliably. The system will have a seamless commu-nication layer from the utilitys 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 dis-tribution systems, the dis-tribution management
sys tem (DMS), which, in general, can be defi ned as a computer- and commu-
nication-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 fi nd different systems within the same utility addressing different system man-agement issues. These systems employ application interfaces between dissimilar applications and frequently these appli-cations run on separate noncompatible databases. The synchronization of data-bases is a constant concern and mainte-nance issue for the existing DMS.
Integrated Distribution Management SystemIn the future, various management ac-tivities in distribution systems will be
in my view (continued from page 112)
Advances in computer and communication technology have made DA possible.
110 IEEE power & energy magazine september/october 2011
integrated, which will be managed by the next generation integrated distri-bution management system (IDMS). The IDMS will use a connected mod-el based on the GIS, and it will utilize interconnected relationship and con-nectivity of various distribution system components including the substation and its associated control and intelli-gent 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 navi-gation are being developed to assist the operators in responding to the dynam-ics of the distribution system and to system disturbances. Further, real-time applications for automated manage-ment of the smart distribution systems are being explored.
The management of distribution sys-tems 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 res-toration following emergencies. Since most of the equipment is expected to op-erate near capacity, long duration outag-es can lead to problems due to enduring component of cold load pickup associ-ated with thermostatically controlled de-vices, such as air conditioners. In such cases, step-by-step restoration would be needed to avoid stressing the transform-ers beyond their capability. Real-time monitoring and analysis not only pro-
vide 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 se-lection, restoration can be accomplished in little time; thus improving the reliabil-ity of electricity supply to the customers. Some applications expected to be inte-grated in the next generation of IDMS include the following:
optimal volt/volt-ampere reac-tive control
real-time analysis adaptive protection contingency evaluation advanced fault location and ser-vice restoration
dynamic loading of power equip-ment
operation with large penetration of customer-owned renewable generation
operation of the system as a mi-crogrid
real-time pricing and demand response.
CostAs we have clearly seen, there is a real need to deploy a new generation of DMS in the distribution system to op-erate with a higher reliability and effi -ciency. However, cost has been and will be a big impediment to the widespread deployment of the IDMS. The distribu-tion 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 reluc-tant to make large investments. Smart grid funding initiatives by the U.S. De-
partment 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 seri-ously. The collective experience gained by such projects can show the benefi ts 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 mod-ernize 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 renew-able generation is not known. Some parts of the country will see more of these activities than other parts. The cost of electricity and equipment, incen-tives 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 antic-ipation of change in customer-level ac-tivities, or should they wait for changes to take place fi rst? There is no clear answer to this question. What is defi -nitely clear, however, is that the DMS of the future will be different from to-days system. They will integrate many new functions while utilizing common databases. p&e
In the History column by Gerhard Neidhofer in , due to a production error, the number 1p25 is incor-rect in the following sentence: The Thomson-Houston Company [later the General Electric Company (Gen-eral Electric) after its merger with the Edison General
Electric Company] preferred 15,000 alternations/min, corresponding to 1p25 cycles/s. The correct number is 125 cycles/s. We apologize for this error.
For Further Reading G. Neidhofer, 50-Hz frequency, IEEE Power Energy Mag., vol. 9, no. 4, pp. 6681, 2011.
Digital Object Identifi er 10.1109/MPE.2011.942238
Date of publication: 18 August 2011