Ontario has experienced extraordinary growth in renewable power production, with wind and solar leading the way. However, as these new sources are highly dependent on wind strength, cloud cover and sun position, renewable power production does not always match up well with predictable periods of customer demand. Lamentably, power authorities are occasionally forced to sell excess power production to neighbouring jurisdictions, often at less than desirable prices.   What is urgently needed is a way to effectively store excess renewable power to meet later customer demand.  Indeed, so important is the issue of energy storage that it is frequently called the “Holy Grail” of the renewable power sector. 

Fortunately, the future of reliable energy storage may not be all that far off. In fact, one report suggests that the global energy storage market is about to “explode”, predicting annual installations of energy storage of 7GW by 2017 and 40GW by 2022, up from an initial base of just 0.34GW in 2012 and 2013. Other reports suggest that even though governmental subsidies for solar are declining, cost decreases in photovoltaic panels, coupled with technological advances and cost reductions in small-scale energy storage, will make residential solar applications financially viable over the shorter term, especially in jurisdictions promoting individual self-generation and grid stability. Beyond the small-scale, technological advances in large-scale (or ‘grid’) energy storage also appear to be proceeding apace.

Today, most large-scale energy storage consists of ‘pumped-storage’. In fact, of the 24.6GW of grid energy storage currently in place in the United States, pumped-storage applications comprise a full 95% of that total. Pumped-storage works where there are significant elevation changes in the local topography. The technology makes use of elevated reservoirs to accumulate water for periodic release through downstream tunnels and sunken turbines, working to convert the gravitational potential energy of the stored water into kinetic energy, producing electric power in the process. Water is released (and power produced) during periods of peak customer demand when power prices are at their highest, and is then pumped back up into the reservoir when demand and power prices decline. This ‘time arbitrage’ enables a positive return on the investment. In Canada, Northland Power’s proposed 400MW facility at Marmora is an example of a pumped-storage application.

A mature, commercial-scale, technology in use in a variety of locations around the world, pumped-storage applications have discharge times measured in hours, can be sized to produce up to 1,000MW of power, typically operate at 76-85% efficiency, and have long operational lives of 50-60 years or more.   Importantly, pumped-storage installations can improve grid stability by increasing power production during lulls in renewable power production, thereby balancing out overall production levels, while at the same time reducing the operating costs of, and wear and tear associated with, traditional base-load generation. Still, and quite surprisingly, total grid energy storage in the US (including from pumped-storage) represents only a tiny fraction of the overall US electricity sector; indeed, just 2.3% of total US electricity production.    

Given this back drop, one may well ask:  what happens if the local topography is not so facilitative?  Furthermore, how can power authorities deal with excesses of renewable production, as opposed to lulls in production? Is there a large-scale storage solution for excess power produced on long sunny days or during periods of strongly prevailing winds? Not surprisingly, this a very real issue for island jurisdictions where excess renewable power production cannot simply be sold off to neighbouring jurisdictions. Here, the future of energy storage seems tied to advances in large-scale, battery-based, systems. 

Typical electrochemical batteries using lithium-ion, sodium-sulfur and lead-acid solutions are already in use in several commercial applications, including in distributed and centralized power applications, typically in installations up to 1MW.  While standard battery technology is continually improving, wider deployment of the technology remains hampered by ongoing concerns over battery energy density, discharge times, battery lifetime, power performance, charging issues, safety and cost. Furthermore, customary battery storage is not particularly well suited for day-to-day load-leveling or for seasonal energy storage. Happily, accelerating research in the field of flow-battery (FB) technology offers some prospect for relief from at least some of these concerns.

Unlike traditional battery systems, FB systems use large storage tanks of differentially-charged electrolytic solutions, typically composed of vanadium (metal) salts immersed in sulfuric acid or zinc bromide solutions. These separately stored solutions can be brought into contact with one another at high flow rates in an adjoining electrochemical reactor to release electrons and produce electricity. The key here is that the electrochemical reaction is entirely reversible, meaning that electricity can be added to reverse the process, thereby effectively storing electrons in solution for later use. The electricity required for the reverse process can be supplied by a nearby wind farm or solar array producing excess renewable power. By running the reaction forward and back, the electrolytic solutions can produce or absorb electricity, as and when needed. 

Pilot projects using FB systems are already underway in several US states and in Australia, China, the UK and in other locales around the world. Research suggests that FB systems can achieve deeper battery charges than traditional batteries, should tolerate a larger number of charge/discharge cycles, can operate at close to 100% efficiency, and should enjoy extremely long operational lives. Furthermore, FB systems may also be able to cycle quickly between charge and discharge states, possibly several times per minute, promising even better grid stability and power balancing over much shorter time scales.   No doubt, challenges with the technology persist, including challenges relating to low battery energy density, required operating temperatures, overall system complexity, and the high cost of the metal-based electrolytic solutions. But even here, potential metal-free electrolytic solutions using organic molecules called ‘quinones’ are currently being developed which may drastically reduce the future cost of FB systems.  

If perfected, one may someday envisage a phalanx of FB storage tanks sitting amongst a cluster of wind turbines or beside a nearby solar array. Completely scalable, simply by adding additional storage tanks, FB systems can even theoretically expand as the adjoining wind farm or solar array expands. The resulting economies of scale and time arbitrage would further improve the overall profit margin of existing renewable installations.

As indicated, there are a number of pilot projects currently testing FB systems, in addition to other innovative storage technologies including, for example, involving fly-wheels and compressed air applications. These projects are being funded in the US under the Recovery Act Smart Grid Program and in the UK by the Department for Energy and Climate Change. Here at home, the Ontario government has recently affirmed, in its Long-Term Energy Plan, its commitment to invest in innovative storage technologies, particularly in proposals that “integrate energy storage with renewable energy generation”. Pilots projects in Ontario such as those involving Temporal Power’s flywheel technology are already underway, and it is expected that further announcements on energy storage will be forthcoming shortly.  Overall, in 2014, the Ontario government expects to include storage technologies in its procurement process starting with 50MW of contemplated storage. 

In conclusion, the eventual deployment of commercial-scale, grid energy storage solutions will ultimately depend not just on continuing technological advances in the field, but also on finding effective ways to finance the deployment, construction and operation of multiple new storage installations. If power authorities can achieve the overall goal of properly integrating renewable power production with commercial-scale, grid energy storage, they will, no doubt and quite rightfully, have reason to believe that they have finally attained the Holy Grail of the renewable power sector.