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Australia’s pumped hydro storage potential worth thousands of Tesla big batteries

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Australia has enough untapped pumped hydro energy storage potential to support a 100 per cent renewable energy grid – 35 times over, a team of Australian National University researchers has found.

The ANU team – led by one of Australia’s key solar PV innovators, Professor Andrew Blakers – said this week it has so far mapped roughly 5,000 potential pumped hydro energy storage sites around the country, and hopes to identify hundreds more, as part of an ARENA funded study.

Potential PHES upper reservoir sites east of Port Augusta, South Australia. The lower reservoirs would be at the western foot of the hills (bottom of the image)

Potential PHES upper reservoir sites east of Port Augusta, South Australia. The lower reservoirs would be at the western foot of the hills (bottom of the image)

Professor Blakers said the energy storage potential of the sites already identified ranged from 0.9GWh to more than 100 gigawatt-hours (GWh); far eclipsing the capacity of the lithium-ion “Big Battery” Tesla is currently building in South Australia.

In total, the sites charted by the team – across Queensland, Tasmania, the Canberra district and in and around Alice Springs – are believed to have a combined energy storage potential of 15,000 gigawatt-hours, which Blakers says is 35 times larger the capacity required to support a 100 per cent renewable grid.

“Each site has seven to 1,000 times larger storage potential than the 0.13 GWh Tesla battery to be installed in South Australia,” said Blakers.

“Additionally, pumped hydro has a lifetime of 50 years compared with eight to 15 years for batteries.”

The ANU-led study, which has received $449,000 in funding from the Australian Renewable Energy Agency, aims to develop a nation-wide atlas of potential off-river pumped hydro storage sites, as part of the broader quest to accommodate higher and higher levels of variable solar and wind energy generation on the National Electricity Market.

Queensland has shown particular promise, with 2,213 potential sites identified, with a combined energy storage capacity of about 100 times more than would be required to support a 100 per cent renewable electricity system in the state, the report says.

ANUphes2

Map of potential PHES sites in Tasmania

Tasmania is similarly well endowed, with 2017 potential sites identified by the research.

“Tasmania already has large water storages, several of which are suitable for pumped hydro energy storage,” the report says. “The large number of upper storage sites identified in this
work provides confidence that there will be a sufficient number of feasible PHES for very large-scale storage.”

Off-river pumped hydro works by storing water in an upper reservoir and running it through a turbine to a lower reservoir when electricity is needed – such as when the sun is not shining or the wind is not blowing. The water can then be pumped back uphill when electricity from renewables and other sources is abundant and cheaper.

And while this well and truly mature technology currently accounts for a massive 97 per cent of energy storage capacity worldwide, it has fairly specific geographical requirements.

This includes pairs of reservoirs, typically ranging from 10 to 100 hectares, separated by an altitude difference of at least 300 metres, and joined by a pipe with a pump and turbine.

So far, there are not many large-scale pumped hydro energy storage systems operating in Australia – although NSW-based company, Genex Power, has been working away at its plans to convert the abandoned Queensland Kidston goldmine into one of Australia’s largest new examples, paired with a solar array.

Nonetheless, Blakers says his team’s work has revealed thousands of sites in Australia that “may be suitable” for establishing pumped hydro storage.

“All the potential sites we have found are outside national parks and urban areas, and like all hydro power can go from zero to full power very quickly,” he said.

“This assessment is based on very appealing physical characteristics. But the potential upper reservoir sites identified would require detailed due diligence involving land ownership, engineering, hydrological, environmental and other considerations.”

ANU co-researcher Matthew Stocks said the pumped hydro storage that could be built on the sites identified by the team could be capable of delivering maximum power from hours to more than a day.

“Our earlier work demonstrated the feasibility of 100 per cent renewable electricity for Australia supported by pumped hydro storage,” said Dr Stocks from the ANU Research School of Engineering.

“About 3,600 hectares of reservoir is required to support a 100 per cent renewable energy grid for Australia, which is five parts per million of Australia’s land mass. Annual water requirements would be less than one per cent of annual extraction from the Murray River.”

ARENA CEO Ivor Frischknecht said the project was part of ARENA’s focus on supporting flexible capacity solutions to ensure a smooth transition to a renewable energy future.

“Storage is becoming more important and valuable as we move towards higher levels of renewable energy in our grids,” he said.

“Pumped hydro is the most mature form of energy storage, and studies like these are helping to determine whether it could play an even greater role in increasing grid stability.”

ANU is partnering with ElectraNet and VTara Energy Group to conduct the Atlas of Pumped Hydro Energy Storage Study and develop a cost model for short-term off-river pumped hydro energy storage.

Further site searching is underway in NSW, Victoria, Western Australia and the Northern Territory, and is expected to “add greatly” to the total capacity already identified.  

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  • DJR96

    I can’t help but think that not many of these sites will actually be feasible, and the cost to construct won’t be trivial either. The round-trip efficiency isn’t all that good; Wivenhoe can generate for 10 hours but requires 14 to refill the same volume of water. And despite being able to ramp up/down relatively quickly, it is not instantaneous.

    Whereas batteries aren’t geographically constrained, can be installed pretty much anywhere and at any scale. And can respond instantly to supply/demand variations. And getting cheaper by the week.

    • Jay

      Agreed. I’m a fan of pumped hydro but the complexity and costs can’t be under played here. The biggest selling point of batteries is that they can be installed quite quickly and the environmental impact is very low.

      • Joe

        Yo…….is that you Premier Jay ?

    • Mike Westerman

      The 10/14 hours for Wivenhoe doesn’t represent roundtrip efficiency: Wivenhoe deliberately uses tandem machines, with separate turbines and pumps on the same shaft, so that changeover between modes is faster but also pumping power could be determined separately: each generator is rated at 260MW while the pumps are rated at 227MW (207m3/s at 103m head).

      • DJR96

        So 10 hours at 260MW = 2600MWh generation,
        vs. 14 hours at 227MW = 3178MWh to pump.

        That makes it 81.8% round-trip efficiency.

        Thank you for providing the numbers Mike.

        (Lithium battery storage is over 90%)

        • Mike Westerman

          Not quite linear in each direction but the 80% is about right. Each technology has it’s job to do! We just need lots of both, plus curtailment contracts, in a big hurry!

          • DJR96

            Totally agree. Storage is the future. Pity the powers that be still think 20th century tech and have zero vision for the future.

        • solarguy

          Yes it might be, but you won’t get the storage with batteries on a large scale as cheap!

          • DJR96

            PHES cost is very site specific and can vary wildly. Certainly the larger sizes could be hard to beat.
            It would be interesting to see comparison costs including projected decreasing costs of batteries. There would be a break-even point somewhere.

    • solarguy

      Although not quite instantaneous, vey bloody quick old son (still seconds) but good enough. Batteries can be used until the very short time it takes for the turbines to spool and naturally they won’t need to be very large for that purpose.

      Just keep in mind these PHES facilities can be in the GWhr scale and that will be needed!

      • Mike Westerman

        Their high inertia constant and capacity means instantaneously they contribute considerably to network frequency support as well as having high ramp rates as Solarguy says.

        • solarguy

          Thank you Mike! Great to hear from a fellow like minded thinker!

  • Mike Westerman

    Blaker’s study is a fairly coarse first pass, but it highlights the nonsense being sprouted that “all the hydro potential in Australia is already used”. Take a simple example: building a low 25m wall at about 41° 52.9’S 147° 4.800’E would create a 390ha pond which if coupled with Arthurs Lake >700m above it could provide 3GW for 12h. Coupled with a second Basslink and Tassies 2.6GW of existing hydro it would enormously underwrite RE for SE Australia.

    • Peter Williams

      Pumped Hydro makes sense to me particularly if it can be delivered cheaply. I wonder though Mike, if straight Hydro generation has been consistently rejected on environmental grounds why would pumped hydro be any different? Perhaps the individual systems are smaller but when you add them up it’s still a lot of hectares under water. Your thoughts?

      • Mike Westerman

        As I indicated in my post to Lin above, offstream schemes are very different from conventional hydro, and so avoid most of the typical issues. Many of the available high head sites will actually result in small reservoirs – these are not available to conventional hydro because their are no streams running between them to develop the energy.

    • solarguy

      And what Blaker’s is about is spreading these through out the country, so each region is accounted for and can dispatch as required, helping the local demand at times and then if needed helping other regions with short falls.

    • Ian

      Tasmania obviously has some of the best hydro resources already developed and could reasonably easily be extended by very fine wind resources but suffers from a lack of sufficient load. It needs a big chunky second Basslink. This has been discussed before and some say that the economics don’t stack up. Mike , you’re a hydro man, what is your take on this?

  • lin

    This is all very lovely, but green fields sites will be slow to build and connect to the grid.
    I would love to know what could be done with existing infrastructure.
    How much pumped hydro capacity could be created using exisiting hydro generators by addition of a small downstream dam and a pump?
    How much cheaper and quicker would it be to use existing sites, given they already have a power connection and generation capacity?

    • Mike Westerman

      Lin – the great things about off stream PHES are a) environmental impact is low b) risk due to flooding lower c) easier and quicker to work in the dry without having to divert a river first d) there is a net increase in water storage e) existing dams may be old and of unknown condition and f) nature doesn’t always plan ahead to make great sites on rivers – going elsewhere often produces much better results. So it can be cheaper to add another storage, usually above the existing storage, but not always as easily as you would think.

      • Malcolm M

        Some of the existing irrigation dams with small hydros could be converted to pumped storage hydro with the addition of a lower pool and a pump-generator, but the main advantage is that instead of 24/7 release during the irrigation release season at ~100% capacity factor, it is a peak period release at ~25% capacity factor into the lower pool. Burrinjuck Dam could be set up this way. Dartmouth and Eildon Dams are already set up this way, but without pump-generators. The extra cost of pump-generators over pure generators would be modest, and allow the hydro to bid during peaks outside the irrigation release season.

        The Derwent system in Tasmania could be enhanced with additional pump-generators so that rather than being a base load system with an 80% capacity factor, it is a peak load firming system with a ~25% capacity factor, with what would probably be a seldom-used pumping capacity.

        • Mike Westerman

          Possibly, but PHES is primarily a capacity play (high output, short duration to meet evening peak loads) whereas most mini-hydros on irrigation are small capacity high capacity factor (at least during the release periods) – they run flat out for the irrigation months, making money selling energy and RECs, rather than MW. I’m not sure the economics would work for adding small pumps, tho’ I wouldn’t be adamant on that.

          There is no doubt, any hydros that were built as baseload should be augmented to CF of around 30%.

        • lin

          yep, i was thinking particularly of Dartmouth. 250MW capacity on what is primarily a storage that is only released when the Hume is running low. it already has a small dam below the main wall which could be made bigger if needed, and a small dam-within-the-dam could be built to maintain the fall if needed too. It would allow the generator to be used a lot more than it currently is, and might be a nice little earner for its owner with very little environmental impact.

          • Mike Westerman

            Dartmouth is certainly the most interesting of the Vic existing dams because of its height. If Banimboola Dam was raised by about 20m to EL335, you would create a pond of about 300ha, and so could store 150MW for 6h, to match the 150MW of generation, with <1m fluctuation in that pond and negligible fluctuation in Dartmouth, which is important as an earth core dam doesn't like significant daily cycling of level!

            As Andrew Blakers has indicated, there are lots of sites waiting to be looked at!

          • lin

            You are correct My bad. Only 150MW capacity. But it does look like an easy way to create some useful storage.

        • Ian

          Now you’re thinking number 1. This is a worthwhile conversation if it reveals existing opportunities. Doug is right, what about those PHES that are already installed but sitting idle? I like the idea of better utilising once-through hydro such that it is conserved and used as a long term storage facility or as complimentary to other renewable resources. ie use wind when its blowing ,solar when its sunny and hydro when wind and sun is unavailable.

          I’d like to ask something, which may come across as rather abrasive, and in (maybe)poor taste. For the $449 000 of ‘my’ money given to them by ARENA, can Professor Blakers, say, of all the thousands of carefully documented sites, beautifully illustrated in stunning 3D, what is the estimated capital cost per installed KWH that he has calculated? The article does not seem to indicate this . Has he considered the storage function of the PHES in his study. Besides the frequency control, inertia , etc. The type of storage required is for long periods of renewables poor conditions. These are very difficult criteria: very cheap, very efficient, very large electricity storage. The piddly battery Tesla so proudly wants to install, may smooth over a very short blip in the energy supply we need massive , super cheap storage. If the storage is to last days and cover a failed solar and wind resource then it must be many multiples of generating capacity . ie 20 GW generating capacity silent for 3 days equals 1440 GWH of storage. The premise of the article is that there are so many sites available that this could easily be achieved. The problem of long term energy storage is that, by definition, it’s not used that often. To be economical storage needs to be cycled frequently. – an aeroplane not in the air is losing money- . If long term storage is utilised 1/10 as often as a daily cycling storage then it would need to be almost 10 x as cheap.

          • solarguy

            I think you hit the nail right on it’s head. It won’t be easy to work out the most economical scenario, but wer’e a clever species and we will find the best answer. However there is at this time no way of supplying power, country wide that won’t have to include some idle and expensive reserve power for times of max demand in shit weather periods.
            The way I see things panning out, is that if we can get the majority of homes and businesses, including light industrial to be self sufficient for 3-5 days it will lessen the problem. Even on some overcast, rainy shit days PV will produce between 5- 25% of max. Wind will be blowing some where. Hell I’m convinced we will find the solution. Oh and don’t forget Biogas, huge possibilities there.

          • John Christie

            Forgive me if I seem a bit naive, but the absence of an effective national grid appears to be at the heart of this matter. Solarguy, you you say that there is no way of supplying power country wide whereas across the whole of this continent there is never a time when the wind is not blowing somewhere or other. It would seem to me that with strategically located wind farms and an effective grid, we could generate continuous electricity. I don’t have the expertise to calculate the adequacy or cost of this supply, but I think that the ability to share energy from whatever source to whatever application is a pretty fundamental need.

          • solarguy

            Well John your right on one thing the wind will be blowing somewhere and sure we can share energy on the grid, but yesterday we had a fairly large proportion of NSW and SA cop a fair bit of cloud cover in the afternoon. Now there wasn’t a lot wind produced and solar was down a fair bit. So to fill the demand in a 100% RE scenario that power would need to come from another region. If that cloud cover is prolonged and enough can’t be supplied from say Queensland we will need to make the short fall from storage.

            Every region would have to have massive over sizing of PV and wind other wise.

          • If the storage is to last days and cover a failed solar and wind resource then it must be many multiples of generating capacity . ie 20 GW generating capacity silent for 3 days equals 1440 GWH of storage.

            A system needs only about 5 hours times the renewable (wind and solar) generating power capacity.

            As this “Wind Generation Capacity Focus Table” from my Wind, storage and back-up system designer at this link http://scottish.scienceontheweb.net/Wind%20power%20storage%20back-up%20calculator.htm?wind=20&units=gw shows, if you have 20GW of wind (+solar) capacity then 100 GWh of storage is all you need to build a working system for 100% renewable energy 24/7/52.
            https://uploads.disquscdn.com/images/dddfebd295e06c5feacf4ce7afa4882a4885ea00b7029579630c2341defee2b1.jpg

            If on the other hand, you are actually concerned about designing a system to supply customer peak demand of 20GW then the requirements for renewable generation and storage are different, as can be seen in this “Grid Watch Demand Focus Table” at this link – http://scottish.scienceontheweb.net/Wind%20power%20storage%20back-up%20calculator.htm?peak=20&units=gw

            https://uploads.disquscdn.com/images/d92e16a8592374969174ee1bb2f49269eca0caf04d119cd34a03d976ef726ed6.jpg

            So it is important to absolutely clear in your mind at all times whether the “20GW” or whatever GW or MW you are talking about is the generator capacity or the peak demand you need to supply because the capacity factor of the wind and solar means that in general you need multiple times the generating capacity to serve a particular peak demand.

            Wind, storage and back-up system designer

            http://scottish.scienceontheweb.net/Wind%20power%20storage%20back-up%20calculator.htm

            “Peak demand, wind and back-up power / energy usage and storage capacity calculator

            For the specification and design of renewable energy electricity generation systems which successfully smooth intermittent wind generation to serve customer demand, 24 hours a day, 7 days a week and 52 weeks a year.

            Adopting the recommendation derived from scientific computer modelling that the energy storage capacity be about 5 hours times the wind power capacity, the tables offer rows of previously successful modelled system configurations – row A, a configuration with no back-up power and rows B to G offering alternative ratios of wind power to back-up power. Columns consist of adjustable power and energy values in proportion to fixed multiplier factors.”

          • Ian

            Sorry Scottish I didn’t understand your accent for most of your reply but I do like your attempt to define the two types of storage modality 1. Short term which you call peak and 2. Long term which you call backup. Two different Clans and they need to wear two different kilts.

          • What I called “peak” was “peak demand”, for power, a demand made by the grid’s electricity customers, the “peak” means the maximum amount.
            “Peak demand” is not any kind of storage modality. It is the maximum amount of power that the grid must be able to supply, unless customers are to be disappointed when their demands for power are not met.

            What I call “back-up power” are the emergency generating capacity that the grid brings on line when the renewable generators cannot meet demand and neither can regenerated power from the energy store.

            So when it is dark and there is no solar power, when there is a flat calm and there is no wind power, when the pumped-hydro reservoir is running dry and when the battery is going flat – then the grid needs its emergency back-up power generators to kick in, to save the day and to guarantee that the customer demand for power will be met.

            In a 100% renewable energy system, the back-up power can be supplied from biomass-burning power stations, or by generating from hydrogen which has been previously created by power-to-gas.

            But when a renewable energy back-up is not available then needs must and the grid relies on fossil-fuel back-up power, like from a natural gas burning power station.

            “Back-up power” is assumed to be available come what may, in any eventuality, not limited by energy amount – not a “store” that should ever be allowed to run out.

            It would help you more if you could focus on the fact that I am a scientist, trying to help you with things you don’t understand, rather than focus on the Scottish aspect.

          • Ian

            If you can’t banter, then you can’t do science, it’s not allowed. Besides you Scots are too frigid under the kilt.

            I don’t think any generator or storage facility of any kind will be happy if their investment sits idle just in case the other generators go offline. You assume fossil fuelled generators can sit silent for extended periods and then fire up when the situation demands it. But consider a 99% renewables world where oil or gas is only used very occasionally and then in huge amounts to cover the failed renewables generation. Not gonna happen, oil and gas needs to flow continuously to be commercially viable. Renewables will just have to stand on its own feet. That is the question. Can it? No one really knows if 100% renewables with 100% reliability is possible. The chances are probably extremely good that it is possible, especially if all the generation types , storage types are interconnected over a wide area. The more diverse the system the more chance it will be reliable on a daily basis and on a more sustained basis. We probably don’t have to resort to too much heroic infrastructure to achieve this.

          • With the right contract suitable for profitability for a back-up generator or storage facility then they will be happy.

            Thermal power stations can burn renewable fuels mostly with an option to switch to burning fossil fuels if there is an emergency need.

            Therefore all that is needed for fossil fuels would be a storage facility by the renewable thermal power station, which storage capacity could be topped up in small amounts regularly after any emergency use of fossil fuels.

            It doesn’t cost much to keep a heap of coal or a tank of diesel sitting there, does it?

            How hard can it be?

          • $500k is a good price to pay someone to build an atlas of potential sites, we – the taxpayer – will get a return on that investment eventually.

      • solarguy

        Well said Mike.

  • Cooma Doug

    The thing we need to remember is the status quo. There are 5000 gwh of stored energy sitting there right now on the grid in hydro energy.
    It isnt used because of the market rules. The interesting thing is that when the rules are changed to encourage storage and stability response, the hydro will be a lot slower than battery storage.
    The rate of change of frequency will be very fast and render hydro response as a second preference.
    It will be interesting to see how these products line up in the battle including the huge load side possibilities. Again, hydro response will be behind battery and load shifting in the market price.
    I believe that pumped hydro will not compete at all with load shifting or battery storage as a security option but may be a gold mine in normal market function when the weather reduces renewables and during the transition.

    • solarguy

      Well Doug think of this possibility, we use a battery at each PHES facility to fix that problem…. Ah problem solved yeah!

      • Cooma Doug

        Not sure if you are putting that as a joke or not. But it is what will happen. Fast technology will be necessary to enable hydro pumps in a 100% renewable grid.
        Appropriate market rules will line up these things in a practical order of process.
        Battery system to provide support for 90 seconds enabling hydro to mode change or sync.
        200 MW/ 40MWh battery to enable a GW of hydro on 100% renewable grid.

    • Ian

      Sorry Doug, but is the figure of 5000GWH you quote PHES or once-through hydro or both?

      Tasmania’s dams produce about 9000GWH a year, which is nearly the total electricity consumption in that State, and have a generating capacity of 2600MW. Demand is maximum summer peak 1300MW , winter peak 1800MW minimum’s 500MW. Rather tricky to install wind power above 500 MW without risk of curtailment unless the extra is exported via bass link or used in PHES. Say you install 500MW wind with capacity factor of 45% you could extend the storage of existing hydro by 500 x .45 x 24x 365= 2000 GWH. This is very good but not exceptional. A 1 GW bass link could allow 1.5GW of wind or 5900GWH a year . The link working in a most base load fashion sending 1GW to Victoria constantly would drain 365 x 24= 8700GWH from Tasmania’s supply. Clearly Tasmania cannot supply this amount of energy. To fully occupy the link you would need a contribution from wind of more than 8700 GWH ie 2,2GW of wind. Juggling things more we now need to actively store wind energy in Tasmania to allow optimum use of the 2.2GW of wind. The storage required would be 8700-5900 = 2800 GWH a year or 7.7GWH a day . This is a horrendous amount of cyclical storage. In conclusion then Tasmania probably couldn’t supply the mainland with 1GW of baseload-type power and it couldn’t install more than 1.5 GW of wind capacity. Wind may not coincide with the daily minimum of Tassie’s Load so this analysis could be tweaked to give a better result. It does ,however illustrate the difficulty of making Tasmania the battery for Australia.

      I thought what about subsidising EV in Tasmania? The state is smallish, the number of vehicles required are few and these could contribute to using up excess wind energy production. Pushing up the minimum load by 100MW could allow 100MW of wind , say 300MWH of EV load. Each car would travel on average 40km a day and consume .2 KWH =8KWH a day that’s 37 000 EV. subsidise these by $7000 a vehicle: $260million. Considering each car would have 40 to 90 KWH of storage and the subsidised owners could be persuaded to share say 20 KWH each that would give 740 MWH of storage a day or 270GWH a year, this time shifting or load levelling effect of the battery storage could allow another 200MW of wind capacity to be installed. ie the ability to install an extra 300MW wind bringing in about $700million investment and exporting 1000GWH of electricity at say 10c/KWH= $100 million a year( not to mention the LGC’s which would double that.). To sweeten the deal further The subsidised EV could be given free electricity to charge their cars without changing the economics one little bit. From the EV owner’s point of view they would save about $2000/year on fuel costs. That’s $74 million not spent on petrol and thus retained in Tasmania’s economy. So for a subsidy investment of $260 million , $700million investment in wind infrastructure , and $200 million income a year to the economy of the state plus $74 million a year of revenue retained in the state.

  • Malcolm M

    How does the cost and capacity compare with storage through solar thermal, by using excess electricity to heat the molten salt ? There was a report on RenewEconomy that the proposed pumped storage hydro of Energy Australia near Port Augusta would need a daily difference between buy and sell prices of ~$80/MWh. Adding electric heaters to an existing solar thermal should get storage cheaper than this. Its main use would be in soaking up excess wind power between 2 am and 6 am, and to sell it into the next morning peak.

    • Mike Westerman

      Studies I did in 2014 of CSP with storage resulted in LCOE of around 30c/kWh for a mine site in WA, whereas the most recent Lazard (v10) suggests US$119-183 ie 14.3-22.9c/kWh. Still much higher than PH.

      The problem with thermal storage is the Carnot efficiency of sub-critical STs is only about 20%

      • Peter F

        1. You can use organic fluids and get much higher Carnot efficiency. However the Carnot limit is the real problem with all thermal storage, Excess wind and solar might be available for 3 to 4c or even less but at 30% efficiency that is 9-12c + capital and operating costs of 12-20c and so breakeven differential of 20c or $200 per MWhr

        • Mike Westerman

          Yeah I can’t see thermal storage being economical except for HVAC

    • solarguy

      Yes and yet another way, shows your thinking!

  • Ladies and Gentlemen,

    In recognition of the fabulous economic wealth of opportunity revealed for the people of Australia, thanks to the brilliant leadership of Professor Andrew Blakers and his colleagues,

    https://uploads.disquscdn.com/images/6ece1b8a355cab39f70105b7f7f2b0eb11f61e187860f18c6eb718d08f5542f9.jpg

    I would ask you to be upstanding for the Australian National Anthem
    https://www.youtube.com/watch?v=3CuMR6M8yIA

    Australians all let us rejoice
    For we are young and free
    We’ve golden soil and wealth for toil
    Our home is girt by sea
    Our land abounds in nature’s gifts
    Of beauty rich and rare
    In history’s page, let every stage
    Advance Australia Fair
    In joyful strains then let us sing
    Advance Australia Fair

    Beneath our radiant Southern Cross
    We’ll toil with hearts and hands
    To make this Commonwealth of ours
    renowned of all the lands
    For those who’ve come across the seas
    We’ve boundless plains to share
    With courage let us all combine
    To Advance Australia Fair
    In joyful strains then let us sing
    Advance Australia Fair

    • Mike Westerman

      Laddie – not all of us feel particularly proud of this gibberish: it is just one thing in a catalog of “Things that need to Change” in Australia in the next wee while IMHO. But I do affirm Andrew Blaker’s efforts in at least educating Australians that the Snowy didn’t end hydro here even if the last PHES was commissioned >30y ago.

    • Joe

      Please, no more Sen. Malcolm Roberts photos in these pages.

  • ChristopherABrown

    As long as there is no wildlife or vegetation at those reservoir sites, it’s okay. Except for the consideration of naturally charged aquifers that are down stream from the pumping sites. If hydrostatic pressure is decreased from lowered stream of river levels, aquifers won’t recharge. The study is myopic in this way maximizing the potential to gain investors. The fact is that a full array of renewables are needed.

    • Johnnydadda

      Rotting vegetation would produce methane which is 60 times more effective a greenhouse as than carbon, so creating these reservoirs could result in higher greenhouse gas production than if fossil fuels were used.

      http://regmorrison.edublogs.org/files/2013/02/METHANE-2-1sca3tx.pdf

      • Mike Westerman

        Note according to the IPCC, the effect of methane is 34x over 100y. Methane is only continuously produced if organic matter continuous to flow into the reservoir. Extremely unlikely the methane produced will go anywhere near the fugitive emissions of methane from FF extraction or the subsequent CO2 of combustion, let alone particulates.

    • Mike Westerman

      Christopher there will be two ponds for each scheme, and each will locally raise the water table slightly. Using off stream sites means by definition that the water table is below ground level so that there is no surface flow. There will be environmental impacts and these would be studied in the normal way to establish a baseline and manage impacts during construction and operations. Note that Blaker’s study is a preliminary sieving exercise – it would be followed by all the normal site specific studies.

  • Looking forward to seeing the sites in VIC and it’ll be interesting to see if any sites appear on this atlas above existing (and potential) ‘lower reservoirs’ at the Thompson, Lake Narracan, Moondarra Reservoir and Lake Glenmaggie. They’re all very close to the existing terminal stations & transmission infrastructure for the thermal generators in the La Trobe Valley.

    The Thompson’s western flank is the Baw Baw massif with elevation differences of ~440m at Lake Thompson up to 1000-1100 immediately west of the lake and further away the peak is around 1500m.

  • RobS

    Pumped hydro just massively increases the cost and complexity, hydro already acts as a big battery without adding the cost and efficiency losses of pumping, you simply allow water to accumulate in the reservoir when other sources are producing adequate energy and draw down from the reservoir when necessary.. Just build standard hydro at these sites and use them as rapid despatch spinning reserves. Down the track if we reach a point where renewables are regularly producing at over 100% of demand then we can begin retrofitting the sites with pumped storage.

    • Blakers’ pumped storage sites are “off river” and could not support standard hydroelectric power – not enough rainfall and / or not a large enough catchment area draining into those sites.

      It’s cost effective to add pumped-storage to existing hydro-schemes so do that first.

    • Mike Westerman

      Our total hydro is 7GW, with fairly low capacity factors already, so very little room to do much more with them. Offstream hydro is relatively cheap and low risk to develop, because you build in the dry with a low environmental footprint, the sites are more ideal than what nature dishes up and you can optimise for lowest cost of storage.

  • Alex Hromas

    Pumped storage has been around for a long time i.e. the Windy Creek to Jyndabine Reservoir hydro station has a pumped storage capacity of 70 MW and is about 30 years old. Compared to large scale batteries pumped storage has disadvantages of being site specific (and some suitable sites may not be feasible for environmental reasons) and low overall efficiency about 40% for the round trip. Modern batteries are not site specific thus limiting transmission losses and have a round trip efficiency of about 80%. This is typical of all engineering solutions there is no perfect solution only options. The mix of options that will form the grid over the next decade will depend on all of the above as well as the political will to do something about honouring our Paris agreement. The latter is totally missing

    • Not only “40%”? 75%+ round-trip efficiency for pumped storage with a suitable site and good design.

      Wikipedia – Pumped-storage hydroelectricity
      http://en.wikipedia.org/wiki/Pumped-storage_hydroelectricity

    • Mike Westerman

      Alex – I think someone has been giving you confusing information. Kosciusko and Windy Ck altho’ proposed, were never built – Guthega being the highest power station in that cascade. There is only 1 pumped hydro in the scheme, being the 3 units at Tumut with tandem pumps. The Jindabyne pump station is a diversion scheme rather than pumped storage, diverting Snowy R water into the Murray and exploiting the much higher head on the western side of the range. As Scottish Scientist indicates 75-80% round trip is quite typical for PHES.

  • Potential PHES upper reservoir sites east of Port Augusta, South Australia. The lower reservoirs would be at the western foot of the hills (bottom of the image)

    South Australia could build a stepped sea canal from Spencer Gulf to the foot of the hills with options for either
    * a small canal to top up the lower reservoirs at the foot of the hills
    * a big canal to use Spencer Gulf as the lower reservoir itself

    Moving water over gradual slopes for pumped-storage hydro schemes
    https://uploads.disquscdn.com/images/c77d5da8a7c65fa76431cdaaf2818c90d36a943045d3ace3b7e90d7160152225.jpg

    Map of potential PHES sites in Tasmania. Tasmania is similarly well endowed ..

    Oh the plentiful water and mountains makes Tasmania a much better place for new pumped-storage hydro.

    Scottish Scientist
    Independent Scientific Adviser for Scotland
    https://scottishscientist.wordpress.com/

    * Wind, storage and back-up system designer
    * Double Tidal Lagoon Baseload Scheme
    * Off-Shore Electricity from Wind, Solar and Hydrogen Power
    * World’s biggest-ever pumped-storage hydro-scheme, for Scotland?
    * Modelling of wind and pumped-storage power
    * Scotland Electricity Generation – my plan for 2020
    * South America – GREAT for Renewable Energy