By Stephen Kishewitsch
Energy storage technology is entering a new stage of evolution as a part of our power supply. Several storage technologies have proven themselves and are moving past the stage of installing pilot-scale technologies here and there. The next-level job is their integration in a way that optimizes their various values, in many cases within the distribution grid.
That was the main theme of a one-day conference on storage June 24, hosted by Ryerson University’s Centre for Urban Energy (CUE) and the National Sciences and Engineering Research Council (NSERC).
“Storage can now be considered a reliable component of the grid,” said the Independent Electricity System Operator’s CEO Bruce Campbell. “The IESO’s most recent Alternative Technologies for Regulation (ATR) procurement has demonstrated that. It’s now a matter of getting the right size in the right location.”
The ATR procurement, launched in 2012, sought to procure up to 10 MW of regulation from alternative sources, including storage. The IESO signed contracts with a flywheel and a battery service provider. The pilot allowed the IESO and its contractees to settle some “unexpected operational issues,” Mr. Campbell said, but the organization was satisfied that storage technologies can reliably meet rigorous performance requirements.
The IESO, along with a few utilities, has now had pilot projects in place for a few years (see sidebar). They have provided needed experience in how such technologies and their control systems interact with the larger grid. Those numbers will grow, along with the needed system experience. Toronto Hydro has the largest number of storage sites, in various stages of development, in the country – currently some 14, of various capacities and using various technologies, for a total of 17 megawatts. That has the potential to rise to 20 sites within a year, for a potential total of 41 MW, said Gary Thompson, Supervisor – Engineering, Generation Planning and System Studies at Toronto Hydro
PowerStream is not far behind. On page 31 is a story about the utility’s launch in July of a microgrid, with a storage unit at its core, in Penetanguishene, a community of a few hundred at the end of a feeder line subject to interruptions. In June 2014 the utility launched a microgrid at its headquarters, a pilot using three different battery technologies, plus solar panels, a wind turbine, a natural gas genset, an electric vehicle charger, and the management system to control them all.
Storage is about to grow out of its baby shoes. Neetika Sathe, PowerStream’s Vice President of Corporate Development, put it this way in a phone conversation: “Three years ago when PowerStream launched the microgrid at its head office, microgrids were a concept still mostly a matter of hype. Nobody knew how to put one together, much less commercialize it. Some of the technologies, like lithium ion batteries, were still not well understood. [Ms. Sathe was speaking in the context of microgrids, but the two are closely related, and even a single storage unit can function as a microgrid of sorts.]
“In those three years we’ve come a long way. Now we’re at somewhat the same stage when it comes to aggregation. We understand how a single microgrid works, or the bidirectional capabilities for Li-ion batteries. Standards are being discussed for the various technologies. But when it comes to managing multiple microgrids within a larger system, and the various values that can be harnessed, that discussion is still at a very early stage.
“If you want to use storage for voltage or frequency regulation or load diversion or to participate in a capacity market, you need to add intelligence to that unit. You need a robust energy management system. And if you have several such units scattered around your service territory, and you want to coordinate how they deal with system operator calls under varying grid conditions, you need another management layer on top of that. In its main service territory, for example, PowerStream has a pilot of twenty homes, each generating some of its own power from rooftop solar, and each with its own lithium ion battery storage unit. The utility can command all twenty at once, to take some of the load off the local line if needed.”
That top system layer – still at an early stage of development – would be the next stage in the evolution, not just of the storage field but another component in the evolution of the entire system.
In mid-May, CanSIA awarded the ‘Game Changer Award’ both to both Toronto Hydro, for Solar Enablement and PowerStream, for its work in smart energy management for that residential solar storage pilot program, named ‘POWER.HOUSE.’
The home for storage is in distribution
The reasons why the role for storage is growing are well-known. “The IESO is looking at having to integrate a non-hydro renewable fleet that’s expected to approach 10,700 MW in pretty short order,” Mr. Campbell said. Much of that is located at the distribution grid level. Hence the other part of the message: if the wind farms and solar fields are mostly in the distribution system, that’s where the storage needs to be too.
“We were a kind of just-in-time delivery service” Ms. Sathe observes. “Now with energy storage solutions we can buffer that energy delivery.”
In fact, they have to, Gary Thompson says. Among all the other system changes, “We’re moving from a heavily industrial economy to a kind of hybrid industrial/service economy, and customers are also changing. The load used to be fairly resistive and inductive in character. Now it consists of much more electronics, hence creating a different character. Loads are more variable, with more sophisticated equipment that are more sensitive to variations in power quality. Customers are more sensitive to intermittent system changes, for example, voltage reduction one of the techniques applied during times of high demand. That puts challenges to a grid that was designed essentially for one-way energy flow. Distribution utilities are challenged to keep supply resilient when we have distributed generation such as solar and wind flowing on what is now a two-way street. It increases the potential for instabilities. Energy storage, with an intelligent controller, allows you to inject energy onto the grid at the right time, to assist in the correction of system issues.
In addition it can provide short-term energy supply, during a fault that would normally create a local outage. There are residential areas, for example, with an increasing elder population, some who depend on medical equipment that require electricity. Toronto Hydro has a pilot “storage on a [distribution] pole,” developed with eCamion and Ryerson’s CUE, that can step in to keep a feeder line powered while an outage is dealt with. And storage can open up opportunities for more renewable-source power. There are already over 1,403 active PV sites in Toronto, Thompson says – 920 under the MicroFIT program, i.e. 10 kW and under; and 413 more under the FIT, from 10 to 500 kW, plus a few more under other programs. But there are potentially many more sites still, with potential capacity that customers don’t have the load to support. Storage would allow them to make use of it, and redirect it into the grid during peak demand.
How to pay for it all?
“LDCs have one revenue source, the meter,” says Gary Thompson. “We can’t spend money as we wish, we’re obligated to apply to the Ontario Energy Board via a rate submission mechanism. This process allows for an open transparent mechanism to review and approve our proposed plans and operations. With the changes in technology and the increasing cost of equipment and complexity of operations, it’s conceivable current revenue streams will become challenged. Hence the need for consideration of alternatives/additional sources. Such a mixed source of revenue will bring with it a flexibility to respond prudently to rapidly changing situations.
“Toronto Hydro, in its last rate filing, included a request for funding of Energy Storage, which the Ontario Energy Board approved. But the existing regulatory structure has different services in different silos – this much for ancillary services, this much for power quality, this much for voltage support, this much for black start, this much for standby power. Under the traditional system, a generator would be paid for and use a resource specifically and only for voltage support, for example. At the moment the IESO will procure 2 MW of voltage support from a flywheel, say, but just for voltage support, nothing else. Any given storage technologies can do several of those things.
“The challenge now is to bring all that together. Because of its cost, storage needs to be recognized as capable of all those. Toronto Hydro is working with the existing regulatory framework to properly fund the values that storage can bring. If we sign a demand response contract for 5 to 10 years, we know the projected revenue.”
Neetika Sathe makes the same point. “LDCs need to become energy providers, rather than just carriers,” she says. Under the Green Energy Act LDCs are allowed to own and operate “clean energy” generation, like solar and CHP, and storage. A Ministerial Directive two years ago allowed them to own behind-the-meter demand response equipment as long as it serves the demands of the grid. But the regulatory world is still trying to keep up with the disruption in the industry, she says.
There is some smart, high-tech equipment that would allow them to manage their part of the grid better if the equipment could be put in the rate base. If electric cars become popular, for example, and they all start charging at once as people get home from work, it will put a strain on the transformers serving the area and possibly cause an expensive failure. PowerStream would like to apply smart controls to that fleet of EV chargers. Of course nothing stops them from setting up a fleet of EV chargers. But it would greatly help to have part of the cost of that fleet covered by an addition to customer rates, and make it that much easier to enable deferral of an expensive upgrade to the existing transformer fleet. Instead, for now the old technologies win on [short-term] cost.
Along with Ryerson, PowerStream is studying storage versus traditional poles and wires.
“There will be a point in the future where these graph lines intersect, as the cost of electricity rises and the cost of new technologies declines,” she says. “Also as the market opens up the value of the new technologies – for example, a storage unit next to a transformer station will add value beyond saving power outages or peak management, in the form of voltage and frequency regulation. We would like to see demand response for the residential market. We would love for the customer to make some money by opting in for demand reduction to help reduce locational congestion.”
The IESO is no longer looking at pilot projects, Bruce Campbell said. It has scheduled 100 MW of regulation service, and expects that to rise to 200.
Referring to PowerStream’s pilot 20 homes with battery storage, Mr. Campbell asked, “Suppose they had 20,000 homes. At what point does this become the size of a Pickering nuclear unit?” he wondered.
Summary of recent IESO storage initiatives
The IESO completed a two-phase energy storage procurement in late 2015, contracting about 50 MW in total. Phase 1 obtained just under 35 MW from 12 individual installations in one of four technologies – thermal energy storage, stationary batteries, flywheels, and power-to-gas (hydrogen storage). The projects are located across the province in different electrical zones to facilitate evaluation of their effectiveness at alleviating local constraints or restrictions. Contracts are for three years. One of the expected benefits will be the learning experience that emerges, which will be shared with the rest of the industry.
Phase 2 resulted in five proponents being selected, representing nine more distinct projects totalling almost 17 MW.
Through the Conservation Fund the IESO recently invested $500,000 in a project led by PowerStream to develop and implement the POWER.HOUSE, an aggregated fleet of 20 residential solar and energy storage systems that PowerStream can control through intelligent software to simulate a single facility capable of meeting system needs. Reports on project outcomes, electricity system benefits and potential new LDC business models will be produced and shared publicly with all Ontario LDCs.