Denis Chartrand
Chief-Distribution Network Strategies
Hydro-Québec Distribution

Matt Wakefield
Sr. Program Manager-Smart Grid
EPRI
 

  EET&D:   Matt, since EPRI is the principal architect of the Utility Host Site Demonstration Project Plan it seems appropriate that you kick off this interview by laying out the foundation for this program and its various goals and objectives.

  Wakefield:   I’ll be happy to do that, Mike. Let me start by saying that we’re very proud of what we’ve already been able to accomplish over the past three years in conjunction with what are now – with the recent addition of Hydro-Québec – 21 partners in this global program. The EPRI Smart Grid Demonstration Initiative is a seven-year collaborative research effort focused on design, implementation, and assessment of field demonstrations to address prevalent challenges with integrating distributed energy resources in grid and market operations to create a “Virtual Power Plant.”

  EET&D:   How often is the Smart Grid Demonstration Program being updated?

  Wakefield:  EPRI provides periodic updates on these projects and relevant industry news and events in the form of a newsletter, plus three face-to-face meetings per year at different project sites as well as through an annual update.

  EET&D:   And what is the make up and constituency of the overall Smart Grid initiative as it stands today?

  Wakefield:   Utility Host-Site Demonstrations provide the core foundation of Smart Grid initiatives everywhere. As of now, we have a total of thirteen Hosts collaborating with the 21 utility members, including utilities in France, Ireland and now Canada with Hydro-Québec. The demonstrations are supported by EPRI in design and analysis of key integration technologies and research goals in alignment with project objectives to resolve the information and technology gaps.

  EET&D:   I think it would be helpful to our readers if you could explain a little more about the difference between a Host Site and a Collaborator and the similarities or differences between them.

  Wakefield:   All utilities join the initiative as Collaborators. As a utility Collaborator, each has the opportunity to propose a project to be a Host Site that has research goals aligned with the initiative. Although the research we primarily conduct is for Host Site projects, the detailed research results are shared with all the Collaborators. Non-Host Site members benefit from the knowledge gained without the cost of deploying capital intensive projects, Host Sites benefit from research performed specifically for their projects. All of the Collaborators have committed to sharing high-level results with the public to help advance Smart Grid efforts in the industry.

  EET&D:   I know that EPRI originally created the IntelliGrid architecture to provide a roadmap for utilities to use in their own Smart Grid implementations. Is that being used here, and if so, how?

  Wakefield:   The EPRI IntelliGrid architecture is being applied to develop use cases and specify the highest priority requirements for communication and control of distributed resources. For each demonstration project implemented, a combination of performance, security, benefits, and/or interoperability assessments are conducted based on data collected through the deployments. The key to this is to use the demonstrations to increase knowledge and define the overall industry needs for integration into the overall system, and to build a consensus on the approaches that work best for integration and industry standards, based on these approaches.

  EET&D:   Let’s move on to the Hydro-Québec Distribution program. Denis, can you give our readers a quick synopsis of how Hydro-Québec fits into the master plan for the demonstration project in Québec?

  Chartrand:   Sure. Hydro-Québec Distribution’s Smart Grid Demonstration project completed the review process and was presented to the EPRI Board of Directors this past April as the 12th large-scale demonstration project. The project includes technologies to improve distribution system reliability and power quality, optimize power flow and distribution system energy efficiency and integrate active customer participation on the distribution system. Distribution automation equipment and Volt and VAR control are already available in the demonstration project. Automatic restoration, automatic fault location and advanced Volt and VAR control will be tested over the next few years.

An advanced metering infrastructure (AMI) and meter data management system (MDMS) will be implemented in the zone to evaluate demand response. The AMI infrastructure also provides a potential source of voltage measurement for advanced distribution applications. A charging infrastructure for electric vehicles is being installed, and vehicle-to-grid technology could potentially be tested as well. To support these distribution system technologies, a WiMax telecommunication system will be added to the existing telephone lines in order to facilitate the required exchange of information.

  EET&D:   That’s quite a broad agenda. How did you decide on the elements of the program?

  Chartrand:   Hydro-Québec’s CEO set out the priorities at the World Energy Congress held in Montréal on September 12-16, 2010. The main elements of that declaration were the support and promotion of renewable energy, the advancement of electric mobility, and creation of truly interactive transmission and distribution systems. These priorities are complementary to the more specific Hydro- Québec Distribution business objectives, such as improving the distribution system performance and efficiency for our customers. Smart Grid technologies are enabling these objectives.

This is why Hydro-Québec’s Distribution Smart grid roadmap integrates distribution systems advanced technologies including VVO, advanced distribution automation, fault location, etc., electric vehicle charging stations deployment and trials and, in a longer term, active customer participation in Distributed Energy Resources and Demand Response. All of these Smart Grid technologies can help us better understand the system behavior. This, in turn, allows us to optimize operational actions and decisions by reducing the traditional safety margins without compromising customer services and workplace safety standards. Optimizing the voltage within the Canadian voltage standard on the distribution system is a good example of a reduced safety margin that directly contributes by supplying 2 TWh of our overall goal to save 11 TWh in 2015 without compromising customer service or reliability. The remaining energy savings derived from this objective will be accomplished by promoting the efficient, sustainable use of electricity by our customers.

  EET&D:   What do you see as the major challenges that lie ahead in Smart Grid implementation?

  Chartrand:   There are four main areas where most of the key challenges lie. Those are telecommunications infrastructure, information technology, field standardization and the overall management of equipment-grid interaction. The approach to validating Smart Grid technology at Hydro-Québec Distribution involves the creation of a Smart Grid Zone.

  EET&D:   So what exactly does this Smart Grid Zone entail in terms of facilities and equipment?

  Chartrand:   As we’ve already discussed, it includes one substation (Pierre Boucher) and a total of 12 feeders with most sections overhead averaging 10 km. Peak consumption is pegged at about 110 MW with 450 gigawatt hours, annually. There are approximately 13,500 mixed load customers across residential, commercial and industrial accounts. It’s also important to remember that this is a permanent installation – not just a preliminary test lab – so we have great expectations for its long-term value as well.

  EET&D:   Why did you choose the Pierre Boucher substation in Boucherville as the principal site for your project?

  Chartrand:   There were actually several reasons. First of all, it is a fairly typical substation so it serves as a great location for staging and testing fault location, automatic restoration and advanced protection. It is also a suitable location for our electric vehicle charging stations and quick charge vehicle charging stations. We also have plans for the integration of distributed generation in the form of concentrated solar, all of which will be supported by WiMax wireless communications.

And the fact that IREQ – Hydro- Québec’s advanced research and development lab – is nearby is also beneficial on all fronts. Technical innovation on electricity systems is a trademark of Hydro-Québec, and IREQ is participating in the distribution Smart grid demonstration project. This is an example of leveraging the knowledge of all the participants to optimize the use of the available research resources.

Therefore, it afforded us a lot of diversity and flexibility in terms of what we can do in a relatively localized geographical area. However, there are also other aspects of the project elsewhere in our service territory.

  EET&D:   Can you give us a few examples of what those other dimensions might be?

  Chartrand:   Well, another major part of the demonstration environment is the large-scale fiber-optic network that we have in downtown Montréal, which connects underground chambers in this high-density commercial zone. This provides the backdrop for remote monitoring of the grid, remote maintenance and telecommunications with the intelligent underground chambers.

  EET&D:   Matt, perhaps you could jump in here and describe some of the anticipated benefits of the Smart Grid Demonstration Model and how those benefits manifest themselves.

  Wakefield:   There are four primary areas where we think tangible benefits can be derived. The first of these is expertise. That is, it serves as a real-world opportunity to gain experience and a feel for how Smart Grid technologies can be applied to monitoring, information and control with telecom and centralized control and integration with various existing systems. It also provides an opportunity to test the characteristics of multiple Smart Grid applications operating in parallel. Second, it delves into risk management, providing invaluable lessons learned from the testing of new applications and the ability to identify potential problems before large-scale deployment. Third, the energy conservation component gives us the ability to quantify actual reductions in energy consumption, providing the ability to analyze actual greenhouse gas reduction as an integral part of the model. And lastly, this knowledge is shared with the industry as a means of identifying gaps where future research is needed.

  EET&D:   What is the approximate time line for all of this to take place?

  Chartrand:   It’s essentially a 5-year plan, although some activities have been under way to various extents over much longer periods of time.

For example, the remote control distribution automation program was authorized in July 2005, and the underground automation program was initiated even earlier. This year we’re moving on to CATVAR (Distribution System Voltage Regulation and Reactive Power Control), remote meter reading and the beginnings of our electric vehicle plug-in stations. Then, between 2012 and 2015, we’ll be adding several more features including, automatic restoration, Volt-VAR optimization, advanced load control, and ultimately, concentrated solar by the end of the cycle.

  Wakefield:   It’s also important to note that as this project goes forward there are also other implications for the various internal departments and technological disciplines as well as customer engagement. In general, as the plan progresses, customer involvement escalates fairly substantially and more strain is placed on the transmission system – which in turn has an impact on system performance. Moreover, the subsequent stress placed on the utility’s telecommunications and information technology infrastructures will make those resources increasingly important to monitor closely too. Denis, perhaps you’d like to comment on that as well?

  Chartrand:   Yes, let me just add that because our end goal is to have a fully optimized real-time grid configuration in place by 2020, there will clearly be a need for changes and adjustments as the learning curve builds over time. Virtually every department will be affected to some degree.

  EET&D:   Before we close, I’d like to briefly touch on what else is happening with respect to the remaining areas you talked about earlier; namely the telecommunications piece, the CATVAR/ VVO applications, your electric vehicle recharging plan, AMI and related metering initiatives, renewable energy integration and some of the more advanced future plans for the Smart Grid Zone.

  Chartrand:   As mentioned before, our roadmap focus on distribution system applications such as advanced distribution automation combined with fault location, which is something we expect will improve our SAIDI numbers. And, with improved VVO we can further enhance distribution system efficiency. We are also deploying the EV recharging station infrastructure. As you know, we just announced our selection of Landis+Gyr for metering, so now things will start moving along rather quickly in that area. This year we will implement those smart meters in several areas of the province, including in our Smart Grid Zone, to test the technology. And, the WiMax telecommunication infrastructure required to support the information exchange will begin initial testing and evaluation this year at our IREQ lab.

  EET&D:   Any other plans for the future?

  Chartrand:   Over the next few years, demand response will be tried out in the Smart Grid demonstration project to evaluate the opportunity and benefits for our customers as well as for Hydro- Québec. Likewise, the new meters will create opportunities to provide information for advanced distribution applications such as VVO, which will be tested as we go forward. Our renewable energy initiative involves distributed generation and renewables integration through calls for tenders for power to be installed all over the Province of Québec.

We are also planning to enhance our monitoring with smart meters for profiling and forecasting loads (including the new EV loads) and vastly improved Smart Grid based protection and control strategies, eventually integrating DG into DMS for participation in those applications. We are also planning for utility-scale energy storage at one or more yet-to-be-determined substation locations and at EV plug-in terminals. Various other V2G initiatives to help support a viable electric vehicle rollout are also under consideration.

  EET&D:   Denis, I’ll leave the last word to you to sum all up. It certainly sounds like your Smart Grid deployments will be both diverse and comprehensive, making for a very interesting period of learning over the next several years.

  Chartrand:   Yes, that’s absolutely correct. It includes elements of smart distribution systems – initially as individual applications and later as integrated systems, including transmission – and charging station infrastructure for EVs, as well as AMI and telecommunications infrastructure. In particular, the Distribution Smart Grid Zone is a key element to meeting many of the Smart Grid challenges that lie ahead, not only on the power engineering side, but also regarding telecommunications, IT integration, Smart Grid standards, and the validation and integration of Smart Grid technologies and applications. With so much happening – not just with our project but for the entire global initiative – the future should be quite exciting and interesting indeed!