Southeast Alberta’s first large-scale power storage battery will installed at a solar field north of Medicine Hat this summer.
Invinity Energy Systems will add a “Vanadium Flow” battery to the Chappice Lake Solar project capable of holding about one-third of the production capacity of the 21-megawatt array.
That will allow the operator to “shift” its production forward, ease power more evenly onto the grid, capture higher prices and, essentially, allow solar power to be deployed at night.
That addresses several hurdles and longstanding criticisms of intermittent renewable power production, say company officials.
If you deliver the power at the time when it’s most needed, you can earn a lot more, said Matt Harper, chief commercial officer for Vancouver-based Invinity.
“The second part is that especially as we’re seeing more and more renewable power projects deployed, we’re starting to see limitations on how much power can be shunted into the grid at locations.”
The firm will assemble the unit in British Columbia then install it at the local site, 40 km northeast of Medicine Hat this summer as Elemental wraps up facility construction that could start in March.
Harper also said the particular product, a non-flammable, non-lithium battery which is mostly comprised of water, sidesteps safety concerns and other social or environmental concerns about mining heavy metal.
Vanadium can be extracted from petroleum production waste streams, from brine that results from drilling or from oilsands tailing ponds. There is currently limited commercial extraction, though the Alberta government is heavily promoting the potential.
The total Chappice Lake project budget is an estimated $40 million, with $10 million in grant funding coming from the provincial government and Emissions Reduction Alberta program.
Cold Lake First Nation also owns a portion of the project by Elemental Energy, which also owns and plans to expand the Brooks Solar facility this year.
Chappice Lake will feature 38 battery units each the size of a 20-foot shipping container and could cumulatively hold 8.4 megawatt hours of electricity, enough to power about 300 homes for one hour.
That would be built up in high production periods then dripped onto the grid when production drops or when prices are higher, allowing the company to hedge sales.
Alberta’s power market is only one of two in North America along with Texas that relies on a complete “energy only” bid-in system, where generators set the price at which they will deliver power. If that price is met in a clearinghouse format, the power is dispatched.
“As we prove out that these projects are profitable – they are a money-making proposition, after all – we could see tremendous uptake in Alberta,” said Harper, estimating that economics will make it profitable to build enough storage to accommodate 20 to 40 per cent of production at generation sites.
That could total 1,200-megawatts of capacity if industry projections on new green capacity hold.
Currently there are three battery-storage facilities operating on the Alberta grid, capable of holding up to 50 megawatts of power.
That’s compared to a total generating capacity of about 16,500 megawatts, including about 2,500 megawatts of renewable generating capacity that is poised to grow dramatically in the next three years.
Last month, TransAlta Utilities submitted its “WaterCharger” battery storage project for approval by the Alberta Utilities Commission. The 180-megawatt capacity battery would be joined to the Ghost River hydropower facility near Cochrane.
The provincial government has also launched a move to blend more battery storage onto the provincial grid as a way to increase investment. Industry consultation ended in January toward new legislation due this spring from the Energy Minister. This fall, Associate Minister of Electricity Dale Nally said another key benefit could be delaying the need for new line or line capacity upgrades to carry green power from largely rural production sites to high-demand urban centres.
Invinity has projects in service or development in the United Kingdom, Spain, France, the United States, South Africa and China. That includes smaller projects to help utilities or companies manage internal power needs or avoid higher time-of-use charges, as well as a solar-connect utility scale project in Australia.
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