Saturday, March 2, 2024

Reader Suggests Province Should Look to Batteries For Power Storage

Dear Editor,

In his November 30th letter, John Mikkelsen stated, “Ontario Pumped Storage will not create lakebed turbidity because its innovative design ensures water will flow through multiple, raised, deep water lakebed inlet and outlet ports at a very slow speed, similar to Georgian Bay’s natural currents.”

As a retiree with many years of experience working and instructing in the fields of instrumentation and control systems and electrical, I am quite skeptical of this claim when a 375-acre reservoir with a capacity of 23 million cubic meters of water, and 150 meters of head pressure will be filled and emptied on a daily basis.

Many years ago, I took a boat up the Bruce nuclear generating plant cooling water outlet channel. The current was so strong that I needed full engine power to make any headway against that current. The cooling water outlet flow at the Bruce nuclear plant is only a fraction of the flow that Ontario Pumped Storage (OPS) will have.

Does TC Energy have proof of this claim, evidence that the inlet and outlet ports will work, reference to where this “innovative design” is being used and experience data on this design? Does TCE actually have any real data, technical documentation and design specifications to support many of its claims related to this project?

As for battery storage, Mr. Mikkelsen is correct about the Moss Landing BESS facility. It does supply stored power for only 4 hours but as of August 2023, it has been expanded and now stores and supplies 750 MW for 4 hours (3,000 MWh). If eight of Ontario’s Oneida battery storage facilities were built, their MWh (megawatt-hour) capacity would match the Ontario PS project’s 8,000 MWh capacity. They could store and supply 1,000 MW for the 8 hours just as the proposed OPS. Combined, they would cost less, be constructed much faster, have no additional long transmission lines (if located at the electrical grid) and have a total footprint of about 80 acres vs. approximately 500 acres for the pumped storage project.

Battery energy storage technologies are constantly developing, improving and decreasing in cost. Batteries can also be recycled. Two examples are the recent emergence of lithium iron phosphate (LPF) and sodium solid-state battery technologies that have several advantages over current lithium-ion battery technology. They have greater energy density (more efficiency), are safer and can be produced at less cost.

Tesla is switching to LFP battery cells for its utility-scale Megapack energy storage product. Their 3 MWh per unit Megapack product is advertised as a sustainable alternative and Tesla says it could deploy a 250 MW, 1,000 MWh plant on a 3 acre footprint with the product.

The solid-state sodium-ion battery is regarded as the next generation battery to replace the current commercial lithium-ion battery, with the advantages of abundant sodium resources, low price, higher energy density, faster charging, longer lifespan and high-level safety. A Chinese EV company has currently started producing cars with this battery technology and in the near future it could also be used for utility electrical grid energy storage.

Worldwide, large hydroelectric and pumped storage project starts have declined significantly in recent years due to cost overruns and environmental damage. Pumped storage plants for hydroelectric power in the United States were built primarily between 1960 and 1990. Nearly half of the pumped storage capacity still in operation was built in the 1970s.

An Oxford University study concluded that large hydro capital projects (e.g. pumped storage) increase in cost an average of 92% from the original cost estimate to the actual cost on project completion.

One current example is the Snowy Hydro Snowy 2.0 Pumped Storage Project in Australia. I have included the following excerpts as a reference:

The Guardian – Aug. 30, 2023

The giant Snowy 2.0 pumped hydro project in the Kosciuszko national park, first touted by the Turnbull government in 2017 as costing $2bn, was later revised to a cost of $5.9bn. That tally, though, has escalated to $12bn, with that estimate contingent on completion by the end of 2028.”

The 2.0 project also excludes the $5bn HumeLink project that will connect it to the wider grid. That tab will be picked up by NSW (New South Wales) consumers.”

Another example is the BC Hydro BC Site C dam. The following is an excerpt from Narwhal reporter Sarah Cox:

Marc Eliesen was at the helm of BC Hydro in the early 1990s when its board of directors decided not to build the dam, in large part due to geotechnical risks. The Site C project’s original budget was ‘illusionary’, Eliesen told me, accurately predicting the dam would be beset by enormous cost overruns. He was a fierce critic of the BC government’s decision to push forward on construction amid mounting geotechnical problems that were kept secret from the public. A rational person would have said ‘Enough is enough, let’s stop now,’ he said in 2021.”

The Site C dam is the most expensive dam in Canadian history, and not nearly the largest. Approved as an $8.8 billion project in 2014, the dam’s price tag soared to $10.7 billion just three years later. The BC NDP government approved another increase in 2021, inflating the budget to $16 billion.

Speaking of “illusionary” (given many hydro project histories), the current $4.3 billion project cost projection for the proposed Ontario Pumped Storage project is years out of date and should be revised by extrapolating a more realistic cost projection for the expected completion date.

There isn’t any ‘warranty 100 years’ with this pumped storage project. Advances in newer energy storage technologies could make this Ontario Pumped Storage project obsolete within a few years. This would be at the expense of the Ontario taxpayers and electricity ratepayers.


Mike McTaggart, Meaford

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