T&D World Magazine

Q&A: Integrating Distribution Management Systems

As utilities move to join the smart grid bandwagon, they should first develop their own working, integrated distribution systems. T&D World's Online Editor Nikki Chandler asks industry expert Mehrdod Mohseni how U.S. utilities are doing in getting their business in order.

Mohseni, senior vice president and general manager, Smart Grid Practice at Enspiria Solutions, a Black & Veatch Co., tells us what makes up a sound, integrated distribution system, what the biggest hurdle we must overcome to achieve integration, and whether any utility in the United States has been successful in this regard.

Mohseni has more than 20 years of energy and utility industry experience with particular emphasis on T&D automation systems. He has assisted numerous clients with their vision, architecture, and implementation of various technology solutions with a focus on implementing enterprise-wide information and automation systems.

What components make up a sound integrated distribution management program?

There are probably too many to list them all, but I have provided a few in no particular order. Components that all play major roles in an integrated distribution management program include:

  • SCADA systems
  • Wireless communications for DA (AMI) or for DG (including transfer trip) then WiMAX (if we prove it works) or mesh grid technologies
  • AMI
  • MWM/mGiS for partial posting
  • MDMS
  • DMS
  • Operational Data
  • Historian
  • Smart Grid Data Repository
  • OMS
  • IEDs for both Substation Automation and Distribution Automation
  • Enterprise GIS
  • Graphic Job Design
  • Asset Management System
  • Weather Forecasting
  • Distributed Generation Forecasting, and dispatcher/scheduler applications
  • Load forecasting
  • Intelligent reclosers, switches, cap banks, voltage regulators
  • Spatially enabled Business Intelligence asset management tools

As you can see, both hardware and software components are on this list. If I had to narrow it down to key hardware components, however, I surmise we will start to see DA devices such as reclosers, automated feeder switches, capacitor banks and voltage regulators becoming the key “networked” devices for a distribution system. Cap banks and voltage regulators play an integral role in grid optimization, while reclosers and automated feeder switches, two key technologies for distribution automation, will offer the “self-healing” and reliability needs by allowing power distribution to be instantaneously re-routed around a fault.

We're seeing tons of interest in smart metering and its role in the new smart grid; What platforms do we need in place so that we can gain the best advantage from our metering investments?

Utilities need to consider a good load forecasting application in place to take advantage of the additional data that an AMI system will provide. Similarly, a Smart Grid Data Repository is needed to capture and store this information. A Planning Case Study Management system is also needed for obvious reasons. And lastly, OMS and DMS technologies are needed to tie it all together for a truly integrated distribution program to gain maximum value.

Are most utilities doing the hard work of defining the value in grid investments, or are we seeing a shotgun approach to investing?

My experience has shown that utilities are developing detailed Smart Grid business cases to justify the investments required. To a lesser degree, we are seeing utilities actually develop detailed Smart Grid Roadmaps that allow for better and more structured deployments (and associated investment) of the various technologies that make up a truly integrated smart infrastructure.

Are utilities really ready to handle the volumes of data that smart grid can generate?

I believe the recognition for the need is there – or certainly gaining more traction; however, our experience has been that most utilities today don't have an Enterprise-class Smart Grid data repository in place just yet.

Are our utilities investing in sufficient communications systems so they can securely transport data with the proper latency and bandwidth?

This is one of the BIGGEST hurdle for most utilities to overcome. As utilities move toward a smart grid, it is no longer about two-way communication, but rather about true networking communication systems that support sub latency needs of 17ms or less. This is in addition to <2 second work order status changes and <2 second SCADA communication requirements.

Add to that the tremendous amount of data from AMI and DA systems, and bandwidth can become an issue very quickly. So it will require some significant investment in systems that can provide both high-bandwidth coupled with very low latency. Today, not all vendors can meet these needs adequately; and even when they do, not all utilities are opting to pay for such an infrastructure initially.

How much stock are utilities putting on mobile field computing functions?

We are seeing more and more emphasis placed on this. We believe this is one of the 'key” requirements for supporting 'zero' latency of operating power network models that will be required for Distribution Management Systems. Similarly, it will greatly support the need to record manual switching steps as they occur.

How well are we faring with developing appropriate open architecture standards for smart grid?

There is a lot of discussion and planning going on in this front. DMS and AMI vendors are working hard to get there, but they have a little ways to go still. Standards are been defined at a high level by various working bodies but we are still not seeing all the smart grid technology providers (AMI, MDMS, DRMS, and CIS) adopting these interface standards very quickly yet.

Are you aware of utilities that today can boast of an up-and-running integrated distribution system or is everyone mostly a work-in-progress?

Yes, but mostly in Europe and even some in the Middle East. In the United States, this is not the case yet. There are several early adopters that are working at it currently (and a very few handful that are getting pretty close), but I'm not sure if there are any that can actually boast a fully up and running system just yet.

Mohseni goes on to give his recommendations to utilities on how to get started or, if they are in progress, how to advance toward the smart grid.

  • In addition to the topics discussed above (and ongoing investments in Smart Metering Infrastructure), consider investing in GIS, MWM, and DMS systems now. This would allow utilities to be in a better position to leverage their Smart Grid investments by being ready for advance applications such as: state estimation, VVO/IVVC, suggested switching, FLISR, and Load Management.
  • Consider and plan for a robust Smart Grid data repository
  • Consider a spatially enabled Business Intelligent tool as this will be key for asset management.
  • Spend some time and effort considering solutions, processes and strategies to engage end-consumers to support demand response, energy conservation and distribution energy resources.
  • There are many and varied applications in the smart grid and existing utility space that must be better integrated to take full advance of the investments in Smart Metering Infrastructure, DMS, GIS, WFM, etc.
  • And lastly, consider bringing in outside expertise with real hands-on experience with these issues.

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