The future of DMS
EPRI's Robert Uluski puts the equation together
Not long ago, I reached out to Robert Uluski, a technical executive with the Electric Power Research Institute (EPRI), to talk about what the distribution management system (DMS) of the future would look like, and some of the most important reasons for utilities to implement it.
Uluski, who leads EPRI's research and development activities in advanced distribution applications and engineering planning for smart grid distribution systems, defines DMS as "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."
One obvious use for DMS is to marry it to the outage management system (OMS), which provides economies of scale with a single user interface. And because OMS and DMS share a distribution system model that must be maintained and kept up to date at all times (which is both a challenging and a time-consuming activity), there is significant benefit to the utility if there is only one instance of the model to build and maintain.
Other DMS applications vary from utility to utility, depending upon their specific needs. Uluski said 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, stand-alone distribution automation systems for proof of concept, and are seeking to use DMS for a more flexible, system-wide 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, he told me, applications that manage electric vehicle charging strategies and vehicle-to-grid strategies will also become more important in regions where high EV penetration exists.
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 hand-held devices and airborne drone-mounted cameras for improved damage assessment and interaction with the field workforce," he said.
Looking to the future, there are some important needs to be considered. While 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," he told me. "This includes using AMI data, which has great potential that electric utilities are just beginning to exploit. 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. While integration standards such as CIM (Common Information Model) are underway, they are not yet fully realized. As well, Uluski noted, "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."
What is in the future for DMS as it evolves?
Uluski told me 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, and more.
Currently, there is considerably 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, according to Uluski: "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.
"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. 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.
Kate Rowland Editor-in-Chief, Intelligent Utility magazine