Distributed energy, thermal storage, and demand response score highest on the smart grid.
By Ed Ritchie
Utilities across the country are getting smarter by the minute, and as a result, we’re seeing high scoring projects that capitalize on a triple play that combines distributed energy, thermal storage, and demand response (DR)technologies. As proof of those high scores, we’ll visit some examples showing how generating and storing energy onsite can be good for the bottom line of most any enterprise, and more than welcome as a method of DR for utilities that need to address their peak demand problems.
To start on a high note, as in the high altitude of the Rocky Mountains, let’s drop in on a brewery where sustainable manufacturing is second only to the company’s pride in producing award-winning beers. We’re under the blue skies of Fort Collins, CO, at New Belgium Brewing, talking with plant engineer Craig Skinner, who’s equally proud of his company’s participation in a US Department of Energy (DOE) project called the Renewable and Distributed Systems Integration (RDSI) Program. The RDSI Program is composed of nine locations scattered across the US, and New Belgium is one of six DR sites at the Fort Collins location, where the project has been adopted as a stepping stone towards the ultimate goal of creating FortZED, a net-zero energy district within Fort Collins.
Photo: New Belgium Brewing
New Belgium Brewing facilities
Photo: Spirae Inc.
Electric vehicle-charging stations at Fort Collins City Hall
New Belgium played a special role because it has distributed energy assets, thermal storage, and the ability to reduce some of its manufacturing process load. But the pilot included a load reduction target of 85 kW, and aligning the various assets revealed some challenges and some opportunities. According to Skinner, “It was challenging for us in a way that we didn’t anticipate. Finding dispatchable load opportunities forced us to take a hard look at our processes and equipment.”
Some of those reductions involved air handling units in New Belgium’s packaging area, but just communicating with the HVAC control system proved difficult. Additionally, the plant’s packaging materials and equipment have specific humidity and temperature requirements that had to be maintained. But other load reduction efforts went smoothly, such as reducing the power consumption of cooling compressors with a 50,000-gallon coldwater tank. Ultimately, New Belgium met the reduction targets and had equal success with their distributed energy assets.
Easy Digestion for Cogenerator
For the task of sending energy onto the grid New Belgium used three resources, a 500-kW cogeneration system, a 262-kW generator, and a 200-kW photovoltaic (PV) array. Producing beer provides plenty of organic material for aerobic digestion, and the 500-kW Guascor generator uses the digester’s biogas.
“The facility consumes around 1,300 to 1,600 kilowatts,” explains Skinner. “But that’s dependent upon the time of year. With the generators and the PV producing almost one megawatt, there have been times when the plant runs totally off of our own resources.”
All told, technical partners within the RDSI orchestrated the dispatch of over 4,000 kW of distributed generation as well as 760 kW of dispatchable load reduction, and New Belgium’s contribution made it possible to exceed the program’s goals, says Bill Becker, director of business development at Spirae Inc., Fort Collins. As one of three lead technical partners (along with the Brendle Group and Woodward Inc.) of the Fort Collins’ RDSI project, Spirae was responsible for management and coordination of the distributed energy assets at the project’s five site partners; Spirae deployed its BlueFin active distribution management software platform.
Becker notes that the Fort Collins project was among the highest performing of all RDSI projects in complexity and outcomes. “The target was 15%, and we were shooting for a 20% reduction with distributed energy and energy efficiency,” says Becker. “It’s a substantial reduction and an ambitious goal, considering the fact that the last two summers were very hot. If a utility was at the point where growth required new feeders or substations, a 20% reduction could delay that expense for many years. And this means both infrastructure and substations, or having to build peaking plants to handle these loads or buying megawatts during peak times on the open market.”
Of course, not everything went perfectly. Becker notes that reliability is a key issue with energy assets, and in some cases there were hiccups with older generation units. “We did have an occasion where the demand drifted up and we had no more assets to call on,” he recalls. “So, if you’re shooting for 20%, it’s important to have more than that amount in generation or reducible load, because the assets may not always be available.” As for New Belgium’s issues with accessing the controls of the HVAC system, there’s a worldwide movement to solve that problem, and it will play a major role in another worldwide movement, the smart grid.
Standards Provide Invisible Transparency
Standardizing the connection of commercial buildings to the smart grid is the main focus of a new strategic relationship between LonMark International and OpenADR. LonMark is a nonprofit association for the certification, education, and promotion of interoperability standards for control networking, and the Open ADR (Open Automated Demand Response) Alliance is a nonprofit created to foster the development, adoption, and compliance of an open smart grid standard.
New Belgium could have benefitted from LonMark’s base of nearly 400 member companies that manufacture, distribute, develop, install, or use systems based on the ISO/IEC 14908 body of standards. The technology selection has exceeded 550 interoperable products, all certified and listed on the organization’s website, along with nearly 600 people trained and certified as LonMark Certified Professionals.
According to Barry Haaser, the Executive Director for both LonMark International and the OpenADR Alliance, the need is great to provide a standardized mechanism to communicate price changes for DR events in an automated fashion, rather than manual intervention. “Typically, demand response involves a phone call or e-mail from the service provider to the customer asking them to participate,” says Haaser. “LonMark provides the core technology automation that’s invisible and transparent to the building’s occupants using a low level methodology to control HVAC or appliances.”
Moreover, the automation can also control distributed energy assets. “We talk about the customer and integrator, and the open standard will usher in a whole new era of energy efficiency; this also provides an interesting incentive for distributed energy resources because utilities are looking to shift load effectively,” says Haaser. “The other area we’re watching is storage. What will storage systems look like, and can they make it to a price point that makes sense for the industry?”
High prices are often touted as the major roadblock to widespread adoption of energy storage. But is it accurate? That depends on the type of storage, according to Gary Connett, director of environmental stewardship and member services at Great River Energy, Elk River, MN. Great River has achieved widespread adoption of energy storage, though it’s electrical to thermal, as in hot water stored in grid connected residential water heaters.
The Perfect Storage System
“Everybody’s looking for the perfect battery for storing energy, and we think we already have that right here and now,” says Connett. “It’s spread out around 70,000 homes in our service territory as large capacity electric water heaters that we charge only from 11 p.m. to 7 a.m. So, every night, we can put around 15 kilowatt-hours in each of these water heaters, and we have a battery that is in total bigger than a gigawatt, and the largest battery in the Midwest.”
Great River started the thermal storage program 30 years ago, and has another 30,000 peak shaving water heaters that are curtailed during critical peak hours in the afternoon. “That kind of peak shaving strategy is typical for most utilities, but we’re different,” notes Connett. “As members of the wholesale electricity market, we see the hourly wholesale prices 24 hours ahead of time. For example, last night our prices off-peak were $17 a megawatt-hour, or $1.7 cents a kilowatt-hour. If we can buy this energy at a very low cost and charge hot water heaters at night, we have an arbitrage situation where we’re buying low and selling at much higher cost time periods through the use of hot water consumed during the day.”
Consumers that use the super-insulated water heaters with 85 or 105-gallon capacities get a price break; so in essence, the co-op has made it profitable for 70,000 customers to host a maintenance-free distributed energy resource, and Connett expects the arbitrage opportunity to grow at other utilities as they continue to buy more electricity from wind power resources. Such is the case at PJM, the world’s largest regional transmission organization (RTO). With more than 700 utilities in its membership, PJM is responsible for coordinating the movement of wholesale electricity in all or parts of 13 states and the District of Columbia.
Both PJM and Great River are using thermal storage technology supplied by Steffes Corporation, Dickinson, ND, but PJM has spent the last two years piloting a smart grid-enabled version of the Steffes system, and according to Scott Baker, senior business solutions analyst at PJM, the two-way communication of the smart grid makes it possible to take storage and demand response to a new level.
Maintaining the 60-Hz Speed Limit
“There are a number of companies that have demand response capability, but Steffes is special, because not only do they look at the price of heating the water, they also heat the water in a fashion that follows a control signal from PJM,” explains Baker. “We use this control signal to balance our system second by second. So it’s kind of like fine-tuning to make sure we’re constantly in balance. The electric system has to operate at 60-hertz frequency. In the past, if the frequency deviated above or below, we had to make fine-tuning adjustments by either increasing or decreasing our generation, and that’s how the system has been operated for hundreds of years. But what’s new is the trend to adjust load like water heaters, air conditioners, large pumps, or any kind of adjustable load.”
Photo: Wright Hennepin Cooperative Electric Association
For the smartest grid, energy storage is key.
Photo: Silent Power
A roof-mounted PV system charges the Silent Power battery system.
The ability to fine-tune the system during shoulder hours when spinning reserve is too high and can't be ramped down fast enough is critical, adds Baker. “The way Steffes acts like a generator is that it sends data to PJM that it’s going to heat water at two kilowatts, but if PJM sends an updated signal, it can adjust that two kilowatts around the baseline to meet our balancing requirements. This could also be any building, industrial, commercial, or residential, and certainly there are a lot of industrial buildings participating in the energy market today. But there are only so many steel plants in a wholesale market, and once you sign them up for demand response, you have to keep seeking new business. Yet, the residential space is largely untapped.”
Although Baker describes the Steffes pilot as being surprisingly effective, he notes that there are still challenges, and they are related more to the smart grid, rather than thermal storage. First, there’s the issue of cyber security (see the Cyber Security sidebar to the right), and Baker notes that as utilities add more Information Technology (IT) pathways to energy production, they add more exposure to cyber security attacks. Then, there are regulatory issues, and the investor-owned utilities have something of reputation for moving slowly. So slowly in fact, that FERC has been forced to intervene with regulations that remove impediments to progress in the adoption of smart grid and demand response technologies. And finally, there are many cases of a systemic opposition to demand response from utilities and peak shaving plants that see their investments threatened by new technologies that don’t require the same level of capital intensive generator hardware.
Yes, there are some challenges, but decentralized thermal storage will continue to grow, according to Paul Steffes, CEO of Steffes Corporation. “We’ve been doing electric thermal storage for 25 years and approaching 100,000 installations in the US and Canada,” says Steffes. “Then, five years ago, we started developing smart grid technology and our units have been in the field over two years.” Steffes’ technology isn’t limited to residential water heaters. More than 100 units are in place in schools throughout Montreal Canada. Moreover, the company also does electrical thermal storage for space heating.
Heating Brick by Brick
Steffes cites a large office building in downtown Montreal that’s heated exclusively with his company’s 500-kWh space heating unit. It’s roughly about the size of a refrigerator, and operates on the same night recharging principle as the water heaters, but stores the heat (up to 1,600°F) in ceramic bricks. At Prince Edward Island, Canada, the local utility has distributed space and water heaters to create a thermal energy storage system to maximize energy from four wind turbines. By connecting them in a grid interactive configuration, the utility can harvest more nighttime hours of the wind’s renewable energy, while reducing the consumption of oil for space and water heating during the day.
The price of heating oil and diesel fuel can create severe financial hardship upon remote villages. For example, the residents of Tuntutuliak, AK, a village about 450 miles from Anchorage, have relied solely on electricity from diesel generators, with costs at a staggering 60 cents per kilowatt-hour. The winter temperatures average -2°F to 19°F, and the village uses plenty of electricity for heating, so residents welcomed the chance to join three other villages in a project to bring wind turbines to the area. The project is a partnership between Alaska’s Emerging Energy Technology Grant Fund, the Chaninik Wind Group, and Steffes. Each village received 450 kW of wind turbine power and, so far, about 20–30 homes have Steffes space and water heating units that are storing the turbine’s energy when it peaks during evening hours. The ultimate goal is to hit a 40% fossil fuel reduction by 2015.
The cold temperatures and expensive oil prices in Alaska make it an ideal market for thermal storage with hot water and space heating, but if we travel down the West Coast to California, the use of ice for thermal storage offers the same advantage—low-priced nighttime electricity stored as thermal energy for use during peak daytime hours. For example, in Redding, CA, the Redding City Council recently approved an expansion of Redding Electric Utility’s Thermal Energy Storage Program with Ice Energy, Glendale, CA. The company’s Ice Bear system works in conjunction with commercial direct-expansion air conditioning systems, storing thermal energy in the form of ice, and using the ice to displace the operation of commercial air-conditioning condensing units during on-peak periods.
Bearing Up Under Hot Weather
Currently, 40 commercial buildings in Redding have Ice Bears, and those installations have exceeded 1 MW of peak demand reduction. The program to install Ice Bear units within the northern California territory aims to reduce peak electricity load demand by up to 6 MW over five years.
“The net impact is that we’ve taken about 95% of the peak demand of an HVAC unit off the grid during peak hours,” says Mike Hopkins, executive vice president and general counsel at Ice Energy. “I think that there’s been a lot of progress in smart grid performance, but when it comes to metering and the ability to read the load at the micro level of the grid, there hasn’t been as much. And that’s where the Ice Bear is having a major impact. It gives the utility the ability to meaningfully impact load and adjust to meet the actual conditions at that location on the grid. An example would be the ability in real time to use that six-hour storage resource in each Ice Bear and shift it around. So if there is a heat wave condition but it comes on earlier than was forecast or goes later than was forecast, the utility can bring that storage forward or move it back in real time.”
Ice Energy has a 53-MW program with the Southern California Public Power Authority, and Hopkins notes that such projects are evidence of a major shift in how utilities solve problems of grid congestion. “Often, an Ice Bear program is more effective than the traditional solutions that utilities used to deal with a congested feeder or a substation that needs an upgrade,” he explains. “The Southern California Public Power Authority deal went across multiple grids just to reduce overall peak demand, but the more common projects that we’re doing these days are focused on maybe two or three megawatts to serve particular substations or collections of feeders that are congested.”
In the case of companies that required cold temperatures in their manufacturing process, the thermal storage could is often available, yet untapped. In past issues we’ve covered the demand response savings at Oxnard, CA-based Mission Produce. After a survey from Powerit, Seattle, WA, Mission Produce found six areas for energy management and demand response automation, including: cold room evaporators with variable frequency drives (VFDs), condensers with VFDs, Freon refrigeration compressors (sequencing and staging), hydro-coolers, ripening rooms, battery chargers, and lights.
“Mission Produce combined demand response, demand control, and energy efficiency to drive down their average electricity bill by 33%,” says Kevin Klustner, CEO, Powerit Solutions. “That was at one site; they’ve also rolled out our system to other sites, and are now using it for benchmarking as well. With technologies like Powerit Solutions’ Spara system, you can monitor energy consumption in real time, load by load. You can also see the cost of consuming that energy in real time, load by load, and most importantly, do something about it in real time. Now you can curtail loads when there are spikes in energy rates, and earn payments by cutting back when your utility calls a real-time demand response event.”
Photo: Dairland Power Cooperative
Energy management is key.
Klustner notes that the opportunities will grow as the smart grid evolves. “Next-generation smart grid programs require more frequent responses—perhaps five to 10 times a week—with shorter durations. Businesses must have automated response capability to participate. And with the rise of alternative, onsite power generation, automated demand management systems will need to be able to take pricing and usage data in real time from the meter and the grid, and then provide intelligent analysis around the tradeoffs of paying peak demand pricing, participating in a DR event, or bringing that onsite energy into play.”
Data Points, Millions Today. Billions Tomorrow?
The rise of intelligent analysis of data has helped large-scale aggregators of demand response customers. For example, EnerNOC, Boston, MA, works with more than 100 utilities and grid operators worldwide, using energy management for commercial, institutional, and industrial customers that participate in demand response programs. The company recently won a $10 million contract with the Massachusetts Department of Energy Resources to help reduce electricity consumption at 480 state buildings. The project involves metering the buildings and analyzing data from more than 2 million data points as it’s streamed to EnerNOC’s network operations center.
According to Greg Dixon, senior vice president of marketing at
EnerNOC, using energy curtailment and data for demand response programs is growing, but making use of distributed energy assets has yet to match that progress. “New York and New England are hotspots, but very few developers and owners of CHP Systems are actually aware of this,” says Dixon. “Distributed generation is a form of demand response, and if you have an emergency generator onsite, you can in certain markets use it for demand response purposes because it’s relieving the grid of a strain. Even generation that’s running continuously has value to the grid. If it’s something like a one-megawatt system that could run in prime power mode for 12 hours, we could bid the power into the market for energy purposes of capacity or ancillary services.”
Thermal energy storage is getting a boost from both utilities and aggregators such as EnerNOC, but traditional electrical battery technologies are also seeing benefits. If we circle back to Great River, we’ll find that it is one of three co-ops currently involved in a $5 million demonstration project under the umbrella of a National Rural Electric Cooperative Association (NRECA) $34 million grant program. The project’s goals include the implementation of software systems to manage the large amounts of smart meters; pilot testing of in-home displays to signal homeowners when electricity prices spike; providing customer access of electricity usage data via the Web; enhanced demand response management tools; and the demonstration of energy storage devices, including residential battery storage systems and grid-interactive electric thermal storage water heaters.
“A company called Silent Power is contributing to our distributed energy storage system, and we have a fair number of members that are installing photovoltaic solar panels and some customers with small-scale wind turbines on their homes and farms,” explains Connett. “So, within our smart grid demonstration project we’re installing upwards of 20 Silent Power batteries at residential homes. If the wind blows all night or it’s an incredibly sunny day, that creates a lot of energy for storage in batteries, and they could be downloaded between four o’clock and eight o’clock tomorrow afternoon when the demand for energy is at its highest.”
A Battery of Technology Choices
According to John Frederick, CEO of Silent Power, Baker, MN, it’s worth noting that the word “downloaded” has important implications for grid control. “Our battery systems can add reactive or inductive load to the grid,” says Frederick. “And they are tied to the grid, so let’s say there’s a home and it’s only using a kilowatt of energy for the typical load. Our device is outputting 4.6 kilowatts, so with only one kilowatt consumed by the home, the other 3.6 kilowatts could go out to the grid, and the utility would see a total reduction of 4.6 kilowatts even though the home is only using one kilowatt.”
Silent Power is also supplying 15 of its systems for a distributed energy storage pilot with the Sacramento Municipal Utility District (SMUD) in California. The $5.9 million project aims to determine how battery storage can provide extra capacity during peak demand, such as the hottest hours during the summer. The project is funded by a $4.3 million grant from the Department of Energy, with the remainder coming from SMUD, the California Energy Commission, and SunPower Corp. In this case, the battery technology is lithium-ion, but Frederick notes that less expensive lead acid batteries are often used.
“We’ve used advanced sealed lead acid batteries with absorption glass mat designs that are relatively high cycling, and lithium-ion batteries,” says Frederick. “Lithium-ion are still pricey but amazing in their recycling and efficiency performance. The absorption glass mat sealed acid batteries are relatively inexpensive and work fine in many applications, such as the cooperatives pilot. So the fact is not one size fits all.”
Though one size doesn’t fit all, some technologies may fit better in larger power configurations. Zinc bromide flow batteries offer a technology that concentrates power in large manageable sizes. For example, ZBB Energy Corporation, Milwaukee, WI, manufactures modular, redundant, and scalable architecture from 50 kWh to 2 MWh or more from a single point of system connection. The company recently won a contract to provide its EnerSystem integrated power management product for a microgrid installation at the Joint Base Pearl Harbor Hickam US Military base in Honolulu, HI.
The ZBB EnerSystem will intelligently manage inputs of various energy sources on the base that include an existing photovoltaic solar power system and new wind turbine system. The deployment is part of the first phase of a three-phase, $30-million multi-government agency project known as Smart Power Infrastructure Demonstration for Energy Reliability and Security, or SPIDERS. The mission of SPIDERS is to reduce the risks associated with unreliable power by establishing the standards and technology for smarter, more secure and robust microgrids that incorporate renewable energy sources while decreasing vulnerability to cyber attacks.
The military’s need for security and stability is a key factor in moving technology forward for the smart grid, according to Dan Delurey, executive director of the Association for Demand Response & Smart Grid (ADS). “One of the biggest bright spots for the smart grid and distributed energy is the military,” says Delurey. “Their overall thrust towards sustainability and energy comes from the Congress or executive order, and they are very focused on microgrids and looking at distributed energy as part of that. In San Diego, they are very active and bullish on demand response and working on microgrids with the Navy. But they also see the regulatory waters required for demand response.”
The Department of Energy and Environmental Protection has a budget of $20 million to test microgrids at a number of municipalities, and the US Department of Energy has committed $55 million for eight microgrid projects. On a state level, Connecticut has launched a microgrid pilot. On a county level, the Santa Rita Jail in Dublin, CA, has a microgrid that has been featured in this magazine’s pages, and we’ve covered a 30-MW microgrid at the University of California, San Diego.
The growing interest in microgrids hasn’t escaped the attention of GE Digital Energy, Atlanta, GA. In October 2012, the company launched its Multilin Microgrid Control System, a product designed to help permanently islanded or grid-connected microgrid operators integrate renewable energy and fossil fuel-based resources. Benefits include efficient management of storage and dispatch of energy resources so that they are used when it’s most economical.
“With Multilin, you manage the assets that are generating power, as well as actually making sure that the various places where the power gets consumed are also managed,” says Bala Vinayagam, marketing director for GE Digital Energy. “So you know for sure that power is available for that particular load without any problems. And if you’re grid-connected and you have a smart system, you can respond to a utility’s need for demand response with an asset from your microgrid.”
Multilin can manage thermal storage and helps optimize the usage of any storage resource. “It could be wind, hydro, diesel, and storage,” says Vinayagam. “Each would have an associated cost, and the highest would probably be diesel, so the system looks at all the different resources and designates the most efficient use of those resources. For example, it might suggest a 30% power usage from hydro, 30% from when and 30% from storage.” Currently, the US Department of Defense is using GE’s Microgrid Control System at the Twenty-nine Palms Marine Base in California.
The Multibillion-dollar Market
The opportunities for products that manage microgrids are growing rapidly. According to Pike Research, there is a total of 3.2 GW of total microgrid capacity throughout the world, up from 2.6 GW in the second quarter of 2012. The total number of new project entries was 67, representing an increase of 571 MW. That amounts to an 82% increase in identified capacity within a six-month period, and several additional microgrids are in the planning stages. Pike credits the falling prices of PV for much of the growth, and predicts that the PV-based market could be worth almost $2 billion globally by 2018. But what about wind and fuel cells in the overall microgrid distributed generation mix? Pike reports that this segment of microgrid enabling technologies accounts for the largest target of new investment: 3,978 MW of new generation capacity valued at more than $12.7 billion.
As microgrids continue to grow and demonstrate the value of distributed energy, the opportunities for harnessing that energy in demand response and smart grid applications could grow at an equal pace. Consider that the RDSI project at Fort Collins achieved a 20% load reduction from a group of businesses and government buildings that used existing assets. That’s a significant amount of load curtailment, and leads us to the question: How much more is possible with the use of new generation and storage technology? The next step is to look at combining those high-scoring load curtailment results with power optimization products and smart grid tools. Clearly, the value of today’s triple play will result in a winning season for many of the industry’s players.
Author’s Bio: Writer Ed Ritchie specializes in energy, transportation, and communication technologies.