THE ELECTRIC DISTRIBUTION SYSTEM IS undergoing an evolutionary change thanks to the implementation of smart grid technology.
With the addition of millions of points of new data on the grid, it's even more imperative that utility operations be able to monitor and control, in near real time, what's happening on the distribution network.
Enter the distribution management system (DMS), which Robert Uluski, a technical executive with the Electric Power Research Institute (EPRI), defines in this way: "DMS is a decision support system to assist the control room and field operating personnel with the monitoring and control of the electric distribution system in an optimal manner while improving safety and asset protection."
Uluski, who leads EPRI's research and development activities in advanced distribution applications and engineering planning for smart grid distribution systems, also serves as secretary for the IEEE/PES Working Group in Smart Distribution, its task force on Volt-VAR control, and its new task force on distribution management systems. I asked him about the DMS of today, its most important components, the most important reasons for utilities to implement DMS and, finally, what the DMS of the future will look like.
High level of growth occurring
"We are already seeing high growth in the level of DMS deployment," Uluski told me. "Three years ago, there were fewer than five major DMS projects under way in North America. Now, there are dozens of DMS projects that are currently being planned or implemented by small and large utilities alike. Some of these newer projects are using a phased approach in which basic functionality (monitor, display, alarm) are implemented first, followed in a few years by more advanced functionality."
There are many reasons for electric utilities to consider implementing DMS. The most important reason is improved operator awareness and decision-making for a distribution system that is rapidly becoming more complex to operate.
"Complexity is due to heavier loading, frequent reconfiguration and the presence of high penetrations of distributed energy resources," he said. "Operators are taking on new responsibilities, such as optimizing the efficiency and reliability of the distribution system, and asset protection.
"The DMS provides an effective mechanism to manage the wealth of new distribution system data from AMI (advanced metering infrastructure) meters and sensors, perform tedious and often complex calculations using the acquired data, and assist in operator decision-making in a timely manner," Uluski explained. "The DMS helps collect information from the growing array of distribution system information sources and then applies suitable analytics on the acquired information to improve distribution system efficiency, reliability and performance."
Making better informed decisions
Real-time or near-real-time information (from a few seconds old to a few minutes old), as well as archived information (collected in the past) is all used in DMS applications. This enables distribution system operators to make informed operating decisions based on actual conditions as they exist at the time of the decision.
Where is this information collected? Most of it comes from distribution SCADA, an essential component to the DMS system. "Without SCADA and the associated analytics, decisions are based on assumptions and judgement calls, which is becoming increasingly difficult given the frequently changing and often unpredictable nature of the modern distribution system," Uluski said.
DMS analytics, he says, help make the complex control decisions that are needed to optimize distribution system performance, efficiency and reliability: "It is not practical to perform some performance improvement calculations manually in a timely manner without DMS-driven models and algorithms."
As many utility executives have noted, it's more than technology that drives the smart grid. Today's grid is also all about people and processes, and those processes, more and more, have to cross the traditional utility silos to inform all the necessary parts of the business, and quickly.
"The interfaces to external enterprise business systems are essential for effective communication between the multitudes of business processes that exist in the electric utility corporation," Uluski said. "It is no longer practical to handle interactions between important business systems via manual, paper-driven processes."
Marrying OMS and DMS
For some utilities, marrying its outage management system (OMS) to its DMS is an obvious slam-dunk. In fact, many are looking at it both for economies of scale, and because the combination of the two just simply makes sense. "While some electric utilities have separate distribution control rooms and outage response centers, the outage management and operations management functions at most utilities are handled by a single organization," Uluski explained. "So a combined OMS/DMS, with a single user interface, makes sense."
Another strong reason for a combined OMS/DMS is that the two systems share a distribution system model that must be maintained and kept up to date at all times: "This is a challenging and resource-consuming activity, so there is significant benefit if there is only one instance of the model to build and maintain," Uluski added.
Many system vendors that have traditionally supplied OMS to utilities have either already developed or are planning to develop a complementary DMS/SCADA system. "Similarly," he said, "most DMS/SCADA vendors are adding OMS functionality."
Choosing the applications
Other DMS applications vary from utility to utility, depending upon their specific needs. The most popular applications right now are Volt-VAR optimization and fault detection isolation and restoration, or FDIR. "Many utilities have implemented these two systems as separated, standalone distribution automation systems for proof of concept, and are seeking to use DMS for a more flexible, systemwide implementation," he said.
Looking to the near future, DMS applications for managing two imperative additions to the operational mix (managing demand response and distributed energy resources including distributed generation, renewables and energy storage) for volt-VAR control, microgrid management and more will increase in importance for utilities. Likewise, applications that manage electric vehicle charging strategies and vehicle-to-grid strategies will also become more important in regions where high EV penetration exists.
"Seeing" the distribution system
The massive amount of data now available on the distribution system means having effective and efficient data visualization techniques is essential on the DMS. "The number of distribution data points has grown exponentially in recent years, so displaying all DMS data points as individual numeric text data is not practical," Uluski said.
"For example, a DMS on-line power flow program generates well over 10,000 quantifies per feeder, and DMS with more than a million available quantities is the norm," he added. "The data visualization techniques must draw operator attention to high-priority, actionable parameters." Colors and various highlighting techniques on graphical displays have been used on distribution SCADA systems for many years. More recently, DMS visualization techniques have included high-resolution geographical displays showing street maps and physical landmarks with dynamic power system geographical display information superimposed.
"Photograph-quality displays and satellite images (Google Earth displays, for example) are common on recent DMS systems. Near-future systems will be able to view photographic and streaming video images from handheld devices and airborne drone-mounted cameras for improved damage assessment and interaction with the field workforce," he said.
On the path to the future, there are some important needs to be considered. Although a massive amount of data is now being collected on the distribution system, not all of it has practical applications as yet. "We are still looking for world-class ways to use the new data," Uluski said. "This includes using AMI data, which has great potential but few real applications. We also need new applications for data mining, and new analytics for improved distribution performance."
And, as with so many other aspects of the evolving intelligent grid, there comes the need for standards. Although integration standards such as CIM (Common Information Model) are under way, they are not yet fully realized. As well, Uluski said, "Standards for the DMS applications do not exist at all, so there is a lot of customization work, which increases cost and risk to utilities."
Looking to the future
I asked Uluski what he saw in the future for DMS as it evolves.
"The basic DMS building blocks will always be there: a nearly real-time interface to field devices for continuous monitoring and control, analytics to support improved decision-making and automatic control, and enterprise integration that will enable the DMS to interoperate seamlessly with other essential corporate business systems such as GIS, asset management, workforce management systems, etc.," he said.
Currently, there is considerable variation in how these basic DMS building blocks are configured: "The design varies between a `centralized' approach, where all analytics physically reside in a distribution control center or remote data center, and a `decentralized' or `distributed' approach, in which the analytics reside in a processor (or multiple processors) that are located in distribution substations or out on the feeders themselves (mounted on poles, pad mounted, or installed in underground vaults)," he said.
Which design, centralized or decentralized, will ultimately win the day?
Both, Uluski said. "Most of today's distribution automation (DA) and distribution management systems include a mix of centralized and decentralized components (a `hybrid' arrangement), and this is most likely a trend that will continue," he noted.
"DA/DMS applications that require fairly high-speed automatic control actions (responding in a few seconds)-for example, fault detection isolation and restoration-may be handled by decentralized components," he said. "Applications that primarily support operator decision-making and do not require high-speed control of field equipment (such as switch order management) will most likely be centralized."
The final key? "Regardless of the approach used, it is essential that the analytics use the latest (as operated) state of the distribution system and that the operators are always kept informed of any automatic control action," Uluski stressed.