by Stephen Kishewitsch
The smart grid is perhaps the hot button topic in the energy sector (aside from the ongoing need for new lines), and bids to remain a matter of great interest for a while. Representing the integration of computers, communications and the power system, its implications are extensive. In practical terms of course, it means several things: heightened awareness of and increased control over power use, more precise real-time knowledge of grid conditions, improved response time to problems, better use of grid infrastructure, and of increasing importance as renewables gain market share, increased ability to integrate variable and distributed resources.
It seems every utility above a certain size has some activity underway under the heading of the smart grid. In Ontario, there’s Hydro One, Toronto Hydro, Veridian, Powerstream, Burlington Hydro, and London Hydro. The Ontario Energy Board has a working group on the subject, and the Ontario Power Authority as well as the Ontario Centres of Excellence have funding to assist technical development. As noted in the previous article, Jon Norman, Director of Transmission and Distribution Policy at the Ontario Ministry of Energy, said at a recent workshop that the Ministry expects to see an investment in the province of some $390 million over the next five years in smart grid technologies.
But what does the growth of smart grid technology mean in practical terms? A wide spectrum of developments fall under the heading of the smart grid. Each of the utilities listed above is doing something different, though the technologies overlap. Herewith, an attempt to categorize the broad range of capabilities subsumed under the general heading of the smart grid. And while some activity is happening under all the headings below, this list could also be seen as a very rough progression, from the most readily implemented technologies, such as smart meters, already underway in many areas, to more difficult advances like automatically controlled integration of distributed renewables.
• Smart meters, together with the time of use pricing they enable. Just about everyone is changing their old electromechanical meters, or at least adding new capacity to them, to allow them to handle more information, frequently in both directions. Ontario has just about completed the largest rollout of smart meters in North America, with all residential and small business customers as the target, and the conversion of those customers from daily average to the time of use (TOU) rates is not far behind. Meters can support in-home displays and control centres, tools that allow customers greater awareness of, and control over, their energy use.
In addition to promoting demand shifting, the good old home electricity meter is being asked to do a great deal more: in a number of utility projects it will immediately notify operators of an outage, including where on the line it has taken place. Landis+Gyr and others make residential, commercial and industrial meters that also serve as voltage monitors, additionally storing voltage data for a period of time, allowing it to be retrieved for later analysis if desired. Alternatively, meters can be retrofitted with third-party communications equipment to send whatever data the utility is interested in to its operations centre.
Smart meters also allow utilities to understand consumer behaviour in much greater detail, allowing improved modeling and predictability.
Closely related to the meters is automated control of large loads, such as residential washers, dryers and air conditioning. Signals from the utility, by radio frequency or some other channel, can turn high-demand appliances off according to a broadcast price signal, frequently according to a preference that the customer can set on a personalized web page.
A study by Platts and Cap Gemini of over 100 senior utility executives found that nearly three quarters (72%) are or have been involved in rolling out smart meters to customers.
Smart meters and TOU rates seem to be where everyone begins, but it doesn’t stop there.
• System awareness. Depending on the particular utility project, this can cover a wide range of particulars:
» Faults on lines – over- and under-voltage or current, frequency out of range, frequency out of synchronization, line temperature. The Midwest Independent System Operator (MISO) issued a news release May 6 that it is partway through the installation of 165 synchrophasors that, as the company describes it, provide time-synchronized measurements for voltage and current as well as frequency – the “pulse” of the grid. This will provide grid operators with a powerful visualization tool to anticipate and analyze potential disturbances. Synchrophasors also provide data essential for post-mortem analysis of stressful situations on the grid, MISO explains.
» Transformers or line breakers operating out of range, substation equipment temperature out of standard operating range.
» Line load exceeding specifications.
There is a large number of third-party suppliers developing technologies – physical equipment and software – to provide these capabilities. Various suppliers provide various components under this heading:
» Sensors on distribution lines, detecting voltage, current and temperature
» Communication technology, frequently provided by a separate company and offered as a bundle with the sensing device. Manufacturers of such technology generally use cell phone communications networks where available, and bundle the data to be transmitted according to internet protocol.
“Anywhere you have cellular signal reception you can drop a node in and you have network presence at that location,” explains Ramdas Rao, Senior Vice President and Chief Technology Officer at Ambient Corp. “There’s no real preplanning required to build a network, and no separate networks for each communication need.” Ambient’s applications then provide the ability to process data in the field and store it locally, or pass notice of conditions that exceed some threshold back to central control. Once the operations centre does get an alarm, operators can access the last several days of data stored at the local node, such as a transformer that has gone out of range, and can see what’s been happening for the previous week.
» A number of providers include life cycle management, allowing the utility to remain aware of equipment condition across its system, allowing it to optimize the maintenance, repair or replacement of transformers, etc. and keep the system reliable while minimizing cost.
• Grid self-healing / automatic rerouting of feeders. Several utilities, for example London Hydro, are developing this technology. Distribution lines have utility-determined limits on the amount of distributed generation that can be connected, based on steady state voltage changes, temporary over-voltages during short circuit faults, and also on the level of short circuit currents generated by renewable and other sources. If due to an emergency – short circuits or other disturbances – power may need to be rerouted to other lines, without also violating the limits on that other line. Research is underway to develop techniques to do this automatically.
• Improved utilization of the grid infrastructure, as by improving reliability or allowing more power to be sent over existing lines. IPPSO FACTO touched on this capability in its February 2010 issue (see, for example, “The Static VAR compensator,” page 26). SVCs and related technologies allow improved regulation of line voltage, oscillations or other conditions, thereby also allowing delivering more power over existing lines. As John Bear, President and CEO of the Midwest ISO says of a project MISO has initiated (see above), “We build in a buffer zone to ensure that variations in energy delivery do not impact the stability of the system and overload our transmission wires. Now, we’ll be able to decrease the size of that buffer zone, and use more of the available transmission to deliver more power more efficiently. And, we will be able to do this without increasing risk or decreasing reliability.” The Smart Grid approach takes devices like SVCs and FACTS and integrates them into an increased awareness and automated system control.
» For example, Alternative Energy Solutions group of Dominion Resources, Inc. has a voltage management application that takes near real-time monitoring and feedback from every advanced meter on a distribution system and uses it to adjust voltage levels automatically from the substation load tap changer controller or line voltage regulator.
“Immediate feedback from customer locations allows us to keep customers in the lower band of acceptable voltage continuously, thereby promoting energy conservation without sacrificing power quality,” said Mark Murray, who is responsible for alternative energy business opportunities at Dominion. “We have successfully demonstrated that a 1 percent reduction in voltage equates to a 1 percent reduction in energy.” Additional testing has confirmed annualized savings of $300,000 from a single circuit by implementing this solution on a single substation transformer, the company says.
» For a different kind of example, GE offers predictive analytics, forecasting how loads will behave throughout the day and allowing the utility to know when, where and how much to turn off remotely controllable loads to adapt to optimally manage peak demand.
• Automated management of resources like curtailable loads, storage, and the rapidly spreading, variable, distributed, renewable energy sources like wind and solar. To some extent this is underway, while full automated integration of renewables is still in development. EnerNOC, for example, has announced that it will be providing the Bonneville Power Administration in the US northwest with automated demand response capacity (see “Who’s offering what,” page 28). Utility Integration Solutions, Inc. (UISOL) has implemented a similar system at PJM Interconnections.
• Spreading across this spectrum is the system needed to manage the information pouring from all these devices into the utility’s operations centre at an unprecedented rate, to combine it into a picture comprehensible to the operators, to filter out developing problems from the daily noise, to send out such control signals as are deemed safe to automate, and to facilitate long-term management decisions. A number of vendors offer systems to provide a single management platform for all inputs, and to cover some of or the entire range of operations, from data integration to complete system overview and control. Ability to work with equipment from multiple vendors is necessary, and the language used often uses terms like “open architecture” and the use of internet protocol for all data transmission, so that components from different manufacturers can talk to each other. GE offers several management packages, such as a Data Management Dashboard. UISOL offers DRBizNet for demand response management.
• Data security is a further consideration. With the smart grid so heavily dependent on the flow of reliable information on secure communication channels, there is a great need for cyber- security, so that this data does not get misused or contaminated (intentionally or otherwise).
Ontario utilities prepare for the smart grid
With the opportunities created by smart grid technology attracting increasing levels of interest, and becoming an increasingly important means of getting the most out of existing grid infrastructure, Ontario’s largest distribution utilities are among the province’s agencies with initiatives underway.
First and largest among them, Hydro One is in the process of refreshing its decades-old system with new standards to bring visibility and automation to what has traditionally been a “relatively dumb” electrical distribution network. Focused on a test area in Owen Sound, north of Toronto, the utility is developing what it calls its Advanced Distribution System (ADS) project. Rick Stevens, Director of Development Strategy, explained the objectives in a phone interview:
Automated control of the distribution system to reduce the duration of power outages. To take an example particularly relevant to Hydro One’s vast rural network, in the existing system an outage some distance out on a feeder could trip a re-closure all the way back at the substation – affecting many upstream customers unnecessarily. With distribution automation the utility can install automated switches, allowing it to section off the line section with the fault, thereby maintaining power to as many customers as possible, while line workers restore the rest. With smart meters on every customer along each line, monitoring line power in real time, equipped with telecommunications and backed up with battery power if the line goes dead, the operations centre would know of an outage within minutes, along with its exact location. The smart system is then able to automatically signal the right breaker – again, with the same telecommunications links – to deactivate just the necessary part of the line, identify the nearest repair crew, and inform the crew where to go. The meters themselves let control know when they have power again. And in fact, if there are more problems further down the line, the crew is informed of them before they leave the area.
Hydro One has selected Trilliant Inc. (See “Who’s offering what,” page 28) to supply the telecommunications equipment to be added to each meter.
In the first phase of the initiative, Hydro One wants to be able to plan for, enable and control, if required, distributed generation, again, primarily on the distribution system. It comes down to economics, Stevens said. First comes modeling of the output from all the windfarms on the feeders to ensure safety and reliability, then dispatch, if required.
The project is now in design phase with the focus on the safe and reliable operation of DG, explains Bob Singh, Manager of T&D Development. Go live for this “DG centric” phase is Q3 2012.
Hydro One has selected three prime vendors for the various needed components, Stevens said: IBM for the overall systems integrator; GE Canada for the power systems integrator, covering all the devices in the field; and Telvent, which makes a distribution management system that allows visualization of the system, modeling of scenarios, distributed generation coming on and off, and moving DG from one feeder to another.
Another major distribution utility, PowerStream, has a plan that covers investment in smart grid technologies out to 2015, with a total budget of $14.7 million. Technologies centre around advanced protection and asset utilization in its distribution system, under such headings as automated fault detection, isolation and restoration (FDIR, collectively) hardware and control programs; online monitoring of line and transformer conditions; and a grid optimization and management pilot.
Moreover, with the provincial government anticipating that one out of every 20 cars in Ontario will in some way be powered by electricity by 2020, Powerstream, Veridian, and Burlington, distribution companies in southern Ontario, have all announced projects to incorporate electric vehicles into their grid operations. Electric vehicles present both a potentially large new source of demand, and a new option for stabilizing the grid. California-based Better Place, which has been promoting its vision of an electric vehicle revolution, announced the projects with Powerstream and Veridian distributors March 3. Burlington Hydro announced a comparable project in April 2010.
Better Place explained that the initial project with Powerstream and Veridian involves smart charging of EVs via a network of charge spots managed by a network operations centre. This smart network will optimize charging, increase electric grid efficiency by avoiding peak-demand periods, and increase grid stability by taking advantage of the storage EV batteries can provide. The project also includes a demonstration centre featuring interactive displays to educate the public about the benefits of EVs and the Better Place model to enable mass-market adoption of electric cars.
The smart-charging facet of the project focuses on the network’s energy-management capabilities to optimize charge timing, reduce demand during peak hours, and limit impact on the electric grid. Relative to other devices that plug in, EVs offer the unique ability to store energy and, combined with intelligent network software, EV batteries can serve as distributed storage to absorb under-utilized, off-peak electricity and help balance daily load for utilities. This storage capability makes EVs a perfect match for intermittent sources of renewable energy, such as wind, Better Place says.
The project will involve various EVs that Better Place and its partners will recharge via a standards-based network of eight charge spots, each of which can support two EVs. Charge spots are already up and running at locations including: PowerStream sites in Barrie, Markham and Vaughan; Veridian sites in Ajax and Bowmanville; and the Evergreen Brick Works, a well-known showcase for sustainability and green design in Toronto. The project’s interactive EV education and demonstration centre also is located at the Evergreen Brick Works, 550 Bayview Avenue, in Toronto.
Burlington Hydro’s demonstration project entails a one-year study conducted by the University of Waterloo with funding from Transport Canada. It is designed to increase understanding of the operating characteristics of an all-electric fleet vehicle in practical, working applications, including its recharging patterns and requirements, how to optimize the usage and recharging cycle in a “real life” setting, overall performance, drive-cycle, battery state-of-health and electricity grid impacts.
The motor and drive system technology of the vehicle was developed specifically for fleet applications by Rapid Electric Vehicle Technologies Inc., in Vancouver. REV is a market-leading international private company that offers the REV PACK, used to convert light-duty Ford trucks into advanced battery powered highway-capable electric vehicles. REV will also provide on-board smart-grid and wireless telemetry capabilities, integrated data management and charging infrastructure.
The Ontario Ministry of Energy expects to see an investment in Ontario of some $390 million over the next 5 years in smart grid technologies, said Jon Norman, Director of Transmission and Distribution Policy, at a workshop on the smart grid in April.
Ontario’s two leading agencies also have working groups on the subject. The Ontario Energy Board, acting under Ministerial Directive, has held stakeholder meetings and released a guidance document, “Developing Guidance for the Implementation of Smart Grid in Ontario” – see “Ontario seeks to move smart grid plans forward,” in the April issue of this magazine. The IESO has been chairing the Ontario Smart Grid Forum as well, beginning in March 2008, and which released its second report on May 3 of this year. See “Smart Grid Forum releases second recommendations” page 27.
Ontario is leading the smart grid curve in North America, said Jon Norman. Ontario’s rollout of smart meters is well ahead of any other jurisdiction. And to a large extent it’s driven by the Green Energy Act, with the huge investment it has spawned of small, distribution-connected renewables that will need smart grid capability to manage.
Hydro-Québec announced in late May that it had signed a contract with Landis+Gyr for the acquisition of an advanced metering infrastructure (AMI) and 3 million next-generation meters. Hydro-Québec will be running three pilot projects over the next year, from June 2011 until May 2012, before rolling out the new meters throughout the province. The pilot projects will run in Boucherville (6,000 meters), Montréal (19,000 meters) and the regional county municipality of Memphremagog (2,000 meters). The company plans to install meters throughout the province as of 2012, starting in the greater Montréal area. The rollout in the rest of the province will continue until 2017.
See related feature story, “A smarter grid is coming,” IPPSO FACTO, February 2009.
Smart grid forum releases second set of recommendations
Observing that “[t]he electrical system in Ontario is going through a profound transition,” with, among other things, more than 25,000 homeowners, farmers, schools, and businesses signing on to develop renewable energy projects in less than two years, the Ontario Smart Grid Forum, chaired by the Independent Electricity System Operator, released its second report May 3. The report groups its recommendations under several headings:
Smart Homes
• Smart meters, [now almost completely deployed across the province, and with time-of-use rates following close behind,] are only a first step. The Forum’s Smart Home Roadmap (www.ieso.ca/smarthomeroadmap) shows how in-home technologies could evolve over the next 20 years. In only a few years, smart home technologies will be embedded in many household appliances, allowing consumers to collect real-time information about their energy use and respond to price signals.
• The Forum has called on the Ontario government to conduct annual surveys to gauge consumer interest in smart technologies in the home.
Electric Vehicles
• The provincial government anticipates that one out of every 20 cars in Ontario will in some way be powered by electricity by 2020. … There could be considerable stress on distribution networks if too many car owners charge their vehicles during peak periods. The Ontario Smart Grid Forum recommends that the Ontario Ministry of Transportation track electric vehicle registration, to help local distribution companies identify potential areas where distribution networks may be stressed, so they can plan appropriate upgrades.
Storage
• The Forum recommends that the Ontario Power Authority, the Independent Electricity System Operator, in consultation with industry and the OEB, develop a framework to promote the integration of distributed energy storage where it is cost-effective.
Standards
• The Forum is calling on the industry to follow recommendations on standards forthcoming from the Canadian National Committee of the International Electrotechnical Commission (IEC). Various members of the Forum are actively involved in the IEC’s Canadian National Committee through its Task Force on Smart Grid Technology and Standards. By coordinating on standards adoption, Ontario’s utilities and private sector interests will be better positioned to ensure an effective and interoperable smart grid, as well as offer Ontario-made products and services in the international marketplace.
Privacy
• The flow of customer information through the electricity system will increase exponentially with the advent of smart grid technologies. While this information is designed to promote more efficient and cost-effective electricity use, there are risks if this information were used without the consent of the customer. The Forum is recommending to the broader industry that they adopt the “Privacy by Design” principles set out by Ontario’s Information and Privacy Commissioner – which call for privacy principles to be embedded in the core design of all smart grid applications.
• The report also recommends that the Commissioner track all smart-grid related complaints with respect to how utilities and third parties use personal electricity consumption information.
Information Management
• The sheer volume of information flowing from the smart grid will pose a challenge for local utilities. With equipment monitoring system status, power quality and flows, or even temperatures every second of the day, some estimate the amount of data collected by utilities will increase nine-fold. This data holds tremendous value if it is properly analyzed and used for infrastructure planning and system optimization. As a result, the Forum is calling for common standards for information sharing that will enable the secure exchange and processing of data.
Access to Consumer Data
• The Forum is calling for the development of a test bed environment that would allow utilities and third-parties to test new applications against LDC systems to ensure they are interoperable.
The OEB has indicated that it will soon consider the practical issues surrounding the opening up of access to hourly smart metering and real-time data for licensed retailers, who can already access their customers’ total consumption data for billing purposes. The Forum and its corporate partners will explore barriers to facilitating third-party access to electricity consumers and their consumption information and provisions needed to ensure customer privacy.
See the Forum’s vision of the smart home, in the graphic above.
— Excerpted from “Modernizing Ontario’s Electricity System: Next Steps”
Who's offering what: Examples of smart grid products and services
The following list is taken from various product announcements. IPPSO FACTO includes commercial claims in this summary without implying endorsement. No attempt has been made at comprehensiveness.
• Alternative Energy Solutions group of Dominion Resources, Inc. has an application that takes advantage of emerging smart grid technologies that provide near real-time monitoring and feedback from every energy user on a distribution system. Using information provided by advanced meters, the voltage management application relies on up-to-date information from the customer site to adjust voltage levels automatically from the substation load tap changer controller or line voltage regulator.
“Immediate feedback from customer locations allows us to keep customers in the lower band of acceptable voltage continuously, thereby promoting energy conservation without sacrificing power quality,” said Mark Murray, who is responsible for alternative energy business opportunities at Dominion. “We have successfully demonstrated that a 1 percent reduction in voltage equates to a 1 percent reduction in energy. Additional testing has confirmed annualized savings of $300,000 from a single circuit by implementing this solution on a single substation transformer, the company says.
Dominion Resources will be working with Landis+Gyr to market the application. Landis+Gyr makes residential and commercial and industrial meters that also serve as voltage monitors, while both real-time and stored voltage profile information is managed through Landis+Gyr’s Gridstream™ solution software. This information is then paired with Supervisory Control and Data Acquisition (SCADA) data from the substation, as well as data from other distribution monitoring equipment to make accurate and timely voltage adjustments.
• Ambient Corp. based in Newton, MA provides a communications and an applications platform. The communications is all done through standard IP addresses, either using the cell phone network, or the communication possibilities on the line itself.
“Anywhere you have cellular signal reception you can drop a node in and you have network presence at that location,” explains Ramdas Rao, Senior Vice President and Chief Technology Officer. “There’s no real preplanning required to build a network, and no separate networks for each communication need.”
The applications then provide the ability to process data in the field and store it locally, or pass back to central control notice of conditions that exceed some threshold. Once the operations centre does get an alarm, people can access the last several days of data stored at the local node, such as a transformer that has gone out of range, and can see what’s been happening for the previous week.
Mr. Rao says the company has begun discussions with utilities in British Columbia and Quebec.
• Bit Stew Systems Inc. in Vancouver has released version 2 of its Grid Director platform that provides “management and visualization of the grid including live, realtime, and interactive mapping technology; realtime dashboards, and realtime calendar of events all within an intuitive web-based application. Grid Director provides a dynamic view into the grid by aggregating, analyzing and correlating information across the many disparate technologies that are embedded in operations and the enterprise. Grid Director’s modules include:
» AMI (Advanced Metering Infrastructure) Deployment & Management: streamlined handling of work orders, AMI registration events, monitoring, realtime map visualization, lifecycle management, notifications, rich dashboards, KPIs, and reporting.
» Demand Response 3.0. The next generation of demand response focuses on coordination and control across all the grid resources and providing the ability to perform load shaping.
» Home Energy Management. Tracks, analyzes and displays information to consumers to help with conservation and reducing demand during peak periods
• New York-based EnergyHub provides its Home Base, an in-home display and control center. It supports demand response programs, including customer segmentation, appliance-level control, and real-time monitoring, measurement, and verification. At the core of the system is the EnergyHub Data Exchange (EDX) – a robust, cloud-based control center that transmits and tracks data between the Home Base, the smart meter, and in-home devices to give consumers and utilities live, actionable information.
The EDX can operate independently to get up-and-running quickly or can integrate with utilities’ existing meter data management and operational systems. It also supports the EnergyHub Utility Web Portal, which is used to identify available loads and call events in real time enabling better returns on demand response programs.
• EnerNOC, with offices in the US, the UK, and Oakville, Ontario will provide the Bonneville Power Administration with demand response capacity managed by EnerNOC’s DemandSMART™ application to facilitate grid stability as BPA integrates wind-powered generation into its transmission system. The project, led by renewable energy consultancy Ecofys US, Inc., will demonstrate the ability of EnerNOC’s fully automated demand response capacity to act as a balancing resource, responding if necessary in fewer than 10 minutes to changing system needs. This is the first project of its kind to draw upon demand response capacity from commercial and industrial sites to balance both increases and decreases in supply from renewable resources, as well as traditional generation.
• Most notably from Ontario’s perspective, GE will be opening its Grid IQ Centre in Markham in July 2012. See “ GE to open Smart Grid centre,” page 30.
• Siemens offers its Smart-Substation™ controller, which enables intelligent substations, and the Siemens Spectrum Power™ Distribution Management System (DMS), which facilitates operations information management and security. It includes four major components: distribution network management, distribution network automation, distributed energy resource and demand response management.
The Siemens Smart-Substation™ controller provides an intelligent substation information technology platform to enable real-time substation and feeder automation, Volt/VAr control and demand management. The Siemens Spectrum Power™ Distribution Management System (DMS) will facilitate operations information management and security, in real-time, coordinating control center supervision with smart substation and feeder automation.
The system has been implemented at Kansas City Power & Light.
• Trilliant Incorporated adds communications equipment to existing solid-state meters and communicates with the utility’s operations centre using two-way IP based communications over digital cellular networks. This is part of a test system that Hydro One is installing in its Owen Sound region.
• Utility Integration Solutions (UISOL) in Lafayette, California provides its Open Automated Demand Response (OpenADR) protocol, developed by Lawrence Berkeley National Laboratory and implemented at PJM, to allow the utility to integrate distributed resources, including demand response, synchronous reserve and frequency regulation, with its existing automatic five-minute generation dispatch. UISOL’s automated demand response management system, DRBizNetTM, will serve as the integration platform creating fully automated end-to-end solutions for demand response.
See also:
Ontario launches Smart Grid Fund