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Pumped-hydro energy storage – cost estimates for a feasible system

Guest Post by Peter Lang. Peter is a retired geologist and engineer with 40 years experience on a wide range of energy projects throughout the world, including managing energy R&D and providing policy advice for government and opposition. His experience includes: coal, oil, gas, hydro, geothermal, nuclear power plants, nuclear waste disposal, and a wide range of energy end use management projects.

[Ed: Peter is seeking feedback. Some reviewers comments he has already received are given at the end of this document, for reference.]

Pumped-Hydro Energy Storage – Tantangara-Blowering Cost Estimate

Introduction

Energy storage is essential for intermittent renewable energy generation and is valuable with coal and nuclear generation too. Pumped-hydro is a mature technology and is generally the least cost option for large scale energy storage.

This paper provides a rough cost estimate for a pumped-hydro energy storage facility that would utilise existing dams and reservoirs in the Australian Snowy Mountains Hydro Electric Scheme.

The paper is in response to questions about the cost of pumped hydro energy storage, especially as a component of a fossil-fuel-free electricity generation scenario for Australia. The paper is the fourth in a series of articles (see here for a listing — search this page for articles authored by Peter Lang).

Figure 1: Conceptual diagram of a pumped-hydro energy storage facility.

Project Description

The proposal is to build a 9 GW pumped-hydro facility by connecting two existing reservoirs with tunnels, pipes, generators and pumps.

The two reservoirs are Tantangara (the upper reservoir) and Blowering (the lower reservoir). The difference in elevation between the water levels in the upper and lower reservoirs is 875m (see Appendix). The tunnels to join the two reservoirs would be 53km long (Figure 2).

Figure 2: Proposed Tunnel Line for Tantangara-Blowering Pumped Hydro Scheme

The facility would generate 9GW peak power, for 3 hours per day from 6 hours of pumping at full pumping rate. It could generate for longer at less than 9GW, or if pumping was for longer than 6 hours per day, or if the pumping rate is greater than assumed in this analysis.

The proposal is to bore three tunnels, each of 12.7m diameter, to link the two reservoirs. The reservoirs would be tapped near their down-stream ends to maximise the volume of water storage available. About 3km of the tunnel at the lower end would be steel lined to prevent leakage. There is just about sufficient ground cover along most of the remainder of the tunnel route to avoid the need for waterproof lining or grouting for most of the remaining 50 km of tunnel.

The rocks to be tunnelled through would be mostly granite and similar strong, hard igneous rocks. There may be some hard sedimentary rocks, possibly including minor amounts of limestone. The rock would be fractured and faulted.

The power station is assumed to be similar to Tumut 3 in that it would have six turbines in a power station of similar size to Tumut 3. The differences are that the power output will be six times that of Tumut 3 (because six time the hydraulic head). There would be six pumps rather than the three at Tumut 3. Another difference is that some 3km of steel lining will be required in the tunnels.

Issue – Francis turbines, which are best for pump storage, currently have a hydraulic head limit of about 600m. Tantangara-Blowering is 875m hydraulic head. The manufacturers are working on increasing the upper limit. I understand manyufacturers are working at the moment to double them up.

Cost Estimate

The table below provides a ball park cost estimate for the scheme. The tunnel costs, the main component, were calculated using costs for rock tunnel excavation from world wide experience. The power station, pumps, etc, were estimated by multiplying the original costs (from 1967) for Tumut 3 by 10 (that is approximately how much inflation between 1967 and 2009), and by doubling the cost of this equipment to allow for the six times greater water pressure and, therefore, power output. The greatest uncertainty is the cost of the steel pipes, tunnel lining, power station and ‘Allowance for Other’.

How realistic is this cost estimate?

World experience is that hydro projects cost about US$2,000/kW to US$4,000/kW. The Electricity Storage Association gives a range of costs for Pumped-Hydro of US$500/kW to US$1500/kW. This project is A$744/kW.

So the proposed Tantangara-Blowering facility is towards the low end of the range (if the figures are correct). The main reason for the lower than average cost is that the reservoirs do not have to be built; they already exist. However, this project requires more tunnelling than is normal for pumped-hydro facilities.

Conclusions

The Tantangara-Blowering pumped hydro scheme would be a high capital cost investment for just 3 hours of peak power generation per day.

This is the most economic of the four projects investigated.

Pumped hydro is often economically viable for providing peak power for a system comprising mostly fossil fuel and/or nuclear generation (France’s system is the ideal example). But pumped hydro is not well suited to intermittent, unscheduled generators.

Acknowledgements

I would like to acknowledge the help of some friends, all of whom have had a life time of experience working on hydro-electric projects around the world (all but two still are). Our work on hydro sites and our friendship go back 39, 33, 33, 29, and 19 years. I would like to thank Rich Humphries and Dr Derek Martin for their invaluable assistance (and for taking time off from catching neutrinos to help me: they are building a large underground cavern deep below Sudbury, Ontario to catch neutrinos that will be beamed through the rock from Chicago); Tim Little (Canada), Andreas Neumaier (currently in Asia) both of whom have a life-time of experience designing and constructing hydro-electric projects; and David Purcell who was the first boss I had who could influence me. He grew up in Cabramurra, the construction camp for the Tumut 1 and Tumut 2 projects in the Snowy Mountains Scheme. On weekends he would go with his father, a civil engineer, around the scaffolding and walk-ways as he checked out the construction work and instrumentation on the Tumut Pond concrete arch dam, Tumut 2 Dam and the Tumut 1 and Tumut 2 underground power stations. What a way to start a life. Certainly, today’s young can’t get that sort of early experience of the real world.

Pumped hydro is an excellent match for nuclear and for dirty brown coal fired power stations (because they run at full power all the time and produce very cheap power). Consider the 2007 NEM demand: Peak = 33GW, average = 25GW, base-load = 18GW. Option 1 - nuclear only. 33 GW @ $4b/GW = $132b. Option 2 - nuclear + pumped hydro. 25 GW nuclear @ $4b/GW = $100b + 8GW pumped hydro for $15b = $115b. Conclusion: Option 2 (nuclear + pumped hydro) is the lower cost option.

Reviewers’ Comments

Reviewer 1

I had a quick look at your idea of a pumped storage scheme between the Tantangara and Blowering resevoirs in the Snowys. I have only spent a couple of hours looking at your numbers for the assessment of the technical and economic viability of such a scheme. It is my personal view as an individual and not that of the company I am working for.

Ok, here comes the technical side:

1. One would have to assume that the available head is between the minimum operating level at Tangagara, MOL = 1,207 and the full supply level at Blowering, FSL = 380 because any operator would have to guarantee 95% reliability for his peaking power. Thus, the gross head for power generation is MOL – FSL = 827 m

2. Assuming 3 No.s tunnels of diameter D = 12.7 m gives a cross sectional area of Atot = 380 m2.

3. Assuming a maximum flow velocity of v = 3 m/s to keep friction losses within a reasonable range, the total discharge Q = v * Atot = 1,140 m3/s.

4. With that and assuming a local and friction loss factor of η = 0.85, the energy P computes to be P = 7,860 MW using the formula

P = (9.81*η*Q*H)/1000

5. Assuming an operating time of T = 3 hours/day the available energy is E = P * T//1000 = 8.6 GWh/year

6. The discharge volume V = Q * T * 3,600 = 12.3 106 m3.

7. With a reservoir area of Ares = 2,118 ha and assuming vertical reservoir walls, the drawdown over the 3 hour operating period will be Δh = V/Ares = 0.6 m which is acceptable from an environmental and safety point of view, I think.

8. Assuming that the operator can sell peaking power at 4 times the rate as he has to buy the power for pumping during off-peak times, say $0.60 generating vs $0.15 pumping costs, the annual revenue from the scheme would be R = ($0.60 – $0.15) * 8.6 106 = $3.87 billion per year.

9.I am not a mechanical engineer but I believe that at a head of H = 827 m you are pushing the envelope of what turbines can take. I also think that you may need more than 3 units, say 6 or 9 to keep the size of the turbines and pumps and the width of the underground cavern to a reasonable size.

Now comes the project cost sides:

1. The tunnel is by far the most expensive single item so I have focused on that. I do not have a price for a 53 km long, 12, 7 m diameter tunnel excavated by TBM so have used a 8 km long, 3.5 m diameter tunnel and scaled it up to give an approximate figure for the bigger tunnel. Assuming that the tunnel will be mostly unlined and constructed in essentially sound rock, the costs for excavation, support and care of water during construction is $ 7.56 109, which more than double your figure.

2. You have scaled up the 1967 costs of T3 to arrive at the other major cost items. If my tunnel cost figure is correct, I fear that the other cost items may also be higher than what you have estimated.

3. If this is the case, the construction costs may be closer to $15 billion than $7 billion as you have estimated, which will bring the cost per installed kW back into the range of $2,000/kW which is about what pumped storage schemes cost these days.

I do not mean to discourage you but the capital expenditure for a pumped storage scheme between Tantangara and Blowering seems prohibitive because of the scale of the investment, the high up-front costs and the long period for investors to recover their money. Unfortunately, politicians and banks take a much shorter view of life when it comes to political or financial gains and it seems to me that your idea, as much as I like hydro, seems to be condemned to the ‘not economical’ basket.

Reviewer 2

I took a quick look at your costs and determined that it would take more time than I have to review those adequately.  We have had a lot of challenges with cost escalation over the last several years (until the last year or so) and I would not want to give you a misleading opinion.  That said, I do have some quick comments on your proposal:

— The proposed capacity of 9GW (9000 MW) is huge.  Compare to Itaipu (12,600 MW), previously the world’s largest hydro plant and now Three Gorges (ultimately about 22,000 MW) or Revelstoke (2000 MW, soon to be 2500 MW when Unit 5 is completed).

The proposed number of turbines is 6, which translates to 1500 MW each.  I believe the world’s largest turbine capacity to date is about 750MW. (e.g. the turbines at the Sayano-Shushenskaya dam in Siberia which recently experienced the world’s worst hydro plant disaster to date – check it out on Google if you are not familiar already).

The head is very high as you note.  I believe Francis turbines have been built for heads as high as about 800m, but probably not for large capacity.

Your overall cost looks quite low at less than $800/kW; as you note, world experience is typically several times that today.

Your stated uncertainty of 25% is too optimistic.  When we do a conceptual level estimate by a qualified estimator, we state that the uncertainty on the upper end is as high as 100%. The uncertainty goes down as more design is done, and we would not claim 25% uncertainty until we were into final design.

Steel lining is one of the more critical cost factors.  For many high head projects, the cost of steel lining is the factor that determines whether the project is economic or not. You need to know in situ stresses etc to do a proper analysis.

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By Barry Brook

Barry Brook is an ARC Laureate Fellow and Chair of Environmental Sustainability at the University of Tasmania. He researches global change, ecology and energy.

238 replies on “Pumped-hydro energy storage – cost estimates for a feasible system”

The following is an extract from a comment posted by EL on the “100% renewable electricity for Australia – the cost” thread https://bravenewclimate.com/2012/02/09/100-renewable-electricity-for-australia-the-cost/ . I’d like to post the questions and an edited version of the answer here for ease of finding comments on pumped hydro in future.

EL asked:

I don’t see where the authors have widely missed the mark on hydro storage capacity and requirements. 2.2 GW capacity at 20 GWh DOES reflect an upper storage limit …

I’d like to expand on the comment here http://www.oz-energy-analysis.org/feed/show_me.php?comm=OzEA_DG0002 which addressed the question:

What is the total energy storage capacity (in GWh) of Australia’s existing Pumped-Hydro facilities?

The short answer is roughly 5 GWh can be stored per day and 20 GWh total.

EDM-2011 cited this comment on OzEA as the basis of their pumped hydro energy storage capacity, but they did not realise there is a constraint on the rate at which energy can be stored.

In reply to EL’s comment about the rate at which energy can be stored in the three existing pumped hydro plants:

20 GWh DOES reflect an upper storage limit”. This statement is correct.

2.2 GW capacity”. No. That is not correct. Wivenhoe is the only pure pumped hydro scheme in Australia. The other two PHES plants have some pumped hydro capacity within a plant that is mainly a hydro plant. EDM-2011 attributed the full generating capacity of these plants to pumped hydro.

Only 0.9 GW of generating capacity can be attributed to pumped hydro. The remainder of the 2.2 GW EDM-2011 assumed should be attributed to hydro. Furthermore, there are energy losses in pumping and generating, so only about 75% to 80% the energy can be recovered.

Wivenhoe pumped hydro energy storage facility:

All the water Wivenhoe PHES plant uses to generate power must be pumped up from Wivenhoe reservoir. It can store energy (that is energy that can be recovered, after losses) at the rate of about 328 MWh per hour. It pumps when demand is low and electricity is cheap – between about midnight and 6 am (longer on weekends). It is on standby (spinning and ready to go to full power within less than 1 minute) for about 12 h per day and generating to meet peak and intermediate demand for about 7 hours per day (at variable power output). It generates a little during standby to balance power and frequency fluctuations in the grid. It cannot pump while it is generating or on standby. Because it is needed to be generating and on standby during the day, and because power is cheap at night, the pumping is done at night when the plant is unlikely to be needed for generation.

It takes a lot of energy to start pumping the water. The weight (~23,000 tonnes) of water must be lifted up 100 m against gravity and accelerated from 0 to 3.6 m/s velocity each time pumping starts. Therefore, it is not economic to repeatedly stop and start the pumping. The pumps are not variable speed so once started they run at their constant pumping rate of 207 m3/s.

Therefore, the pumps should only be started if they can be assured they will pump for at least several hours (e.g. 5 hours, but I said let’s assume a minimum of 4 hours to be economically viable).

If we assume an average of 5 hours of pumping time per day and energy storage at the rate of 328 MWh per h, then Wivenhoe can store about 1,640 MWh per day.

Tumut 3 has 1,500 MW of generating capacity in six generating units but only three have pumps and the power of the pumps is only little more than half the power of the generators. So it is not appropriate to assign the 1,500 MW of Tumut 3 generating capacity to PHES.

Bendeela & Kangaroo Valley – similar comment to Tumut 3.

See more details here:
http://www.oz-energy-analysis.org/feed/show_me.php?comm=OzEA_DG0002”

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I’ve received questions recently about pumped hydro cost estimates. I’ll post the questions (edited) and my answers here for the benefit of others:

I am currently trying to better understand the economics of pumped storage, albeit I am at a very early stage of that process.

* I am trying get ‘ball park’ costs in $/MW for pumped storage projects (say in the 100-300 MW range), but just for the key generation kit (i.e. presumably using reversible Francis turbines/pumps and the generators). Do you know where I might be able to find such information or who I should talk to in relation to getting access to such information? I have found it surprisingly difficult to find any details. At this stage, I am interested in indicative costs only.

* I also noted that the commentary suggests that the cost of pumped storage would typically increase significantly with smaller capacity. I suppose the question I am really asking is: are the costs for the key generation kit broadly scalable?

My reply:

Thank you for your question. I do not have recent cost figures.

What I can tell you is the cost of pumped hydro is very site specific. By “very” I mean order of magnitude. So realistically, unless you are dealing with a specific site, any cost estimates would be next to useless.

You asked for ‘ball park’ cost in $/MW. That is one of the unit costs. But the other you would need, if your interested is in energy storage for renewable energy, is $/MWh of energy storage capacity. Because, with renewable energy, the important parameter is how much energy you can store, not how much power you can generate.

This site gives a broad range of costs (both $/kW and $/kWh) for pumped hydro in the USA:
http://www.electricitystorage.org/technology/storage_technologies/technology_comparison

Here are some tools that can help with cost estimating, but you would need an engineer with a great deal of experience in hydro to assist with the data input.
http://hydrohelp.ca/eng/home.htm

Lastly, in this paper posted on 10 February 2012
https://bravenewclimate.com/2012/02/09/100-renewable-electricity-for-australia-the-cost/, I made a crude cost estimate for the “100% renewable electric NEM” system analysed by Elliston et al. (2011). My critique of the Elliston et al. paper provides some comments on the Australian pumped hydro storage capacity and the rate that energy can be stored.

Few people realise that pumped hydro has its place when matched with low cost base load power supply, but is most unlikely to be economic for storing renewable energy.

I understand that the costs are going to vary substantially on site specific features, but I suppose I was trying to a handle on those that presumably do not (i.e. the turbines, pumps and generator, but I note you don’t have recent information in this regard). That way, you can work backwards and work out how low your site specific costs (storages, pipes, electricity connection etc.) would need to be in order to make it work, if indeed it can, which seems highly unlikely based on all the numbers I have seen.

I do not have recent costs for the mechanical and electrical equipment. However, I’d caution against the approach where you start by estimating the cost of items that are a small component of the total cost and then look at the sensitivity to the high cost items. Other than adding a small pumped hydro facility to an existing dam, the costs of the civil works will dominate the costs as Table 1 in the Tantangara-Blowring post shows (the pumps, turbines, generators and transformers comprise about 5% of the total cost in that estimate).

I’d tend to start with the item that is the highest cost as the first step. There is no “general” price for pumped hydro. The cost depends on the hydraulic head (the elevation difference between the minimum operating level in the upper reservoir and the full supply level in the lower reservoir), the distance between the outlet from the upper reservoir and the lower reservoir, the length of tunnels or surface pipes, the length and thickness of steel pipes ( a very high cost item), and the minimum amount of storage available in smaller reservoir.

By the way, please note that the Tantangara-Blowering reservoir was purely and exercise to reveal the costs, and what is involved in the costs. The capital cost figure I derived is too low by at least a factor of two, as the two reviewers’ comments at the end of the post show. I expect the cost would be in the order of $15 billion. However, there is no way that the Tantangara Blowering pumped hydro scheme could be viable. It is not viable physically nor financially. It is not viable physically because of the time and power that would be required to stop and start the flow of 20 million tonnes of water moving at 3 m/s in the tunnels each time pumping had to stop and start. Think about the power and energy needed to accelerate 20 million tonnes to 3 m/s. That would be equivalent of having one tug boat at the head of a line of 100 fully loaded 200,000 tonne ships and trying to accelerate them to 11 km/h

Presumably with the carbon tax, the case for pumped storage can only get harder in most Australian jurisdictions, as off-peak prices will increase by much more than on peak prices reducing the opportunity for arbitrage?

Yes. I suspect you are correct on that point.

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Think about the power and energy needed to accelerate 20 million tonnes to 3 m/s

OK, Energy = 1/2 * m * v^2

20 * 10^6 * 10^3 kg * (3 m/s)^2 = 10 * 9 * 10^9 J = 90 GW.s

Which is a lot, but is also only 10 s of full power output, or 20 s of charging input.
Another perspective, use energy = pressure * volume. If the pumps can manage ~5 bar/50m head/0.5 MPa above the hydrostatic 875 m head to accelerate the water, they need to pump 90 GJ / 0.5 MPa = 180,000 m^3 of water to supply the kinetic energy. At a total cross section of 380 m^2, that’s ~473 m of movement. Call it 0.5 km. If the acceleration is steady from standstill to 3 m/s, the average speed during that time will be 1.5 m/s, so it will take 500/1.5 = 333 s, ~5.5 minutes to start up. This seems unrealistic for something so large, so maybe it’s only 1 bar of overpressure available, for a 30 minute startup. Doesn’t look inherently unworkable on these grounds.

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Luke_UK,

This is an excellent reality check. Very elegant. Thank you.

= 90 GW.s

Which is a lot, but is also only 10 s of full power output, or 20 s of charging input.

i.e. 9 GW for 10 s or 4.5 GW for 20 s.

In terms of power I think it is more manageable than this because there are three tunnels. I expect they would be started one at a time. Therefore, we’d need 3 GW for 10 s or 1.5 GW for 20 s (if the pumps had the capability to accelerate the mass of water in that time).

However, as you imply, the pumps would not have the power to provide this acceleration in addition to lifting the water against 875 m of hydraulic head. Hence your second “perspective”.

I’ve redone your calculations for the situation with three tunnels. I calculate the time to accelerate the water in each tunnel would be the same as you calculated – say 30 minutes – but the three tunnels would probably not be started in parallel. So the start up time to full pumping rate would probably be longer, and perhaps up to 90 minutes.

This seems to me to be an excessively long duration for pumped hydro. As far as I know the big pumps that would be needed on a project like this have to run at constant speed. So, I suspect a long acceleration time is unlikely to be viable (however, this is outside my area of expertise). I’d note that most hydro plants boast they can go from zero to full power generation in less than a minute. I am not sure how long the pumps take to start. Perhaps someone else could comment.

My gut feeling remains that a pumped hydro scheme with 53 km of tunnel and 875 m of head is not viable. For comparison, Tumut 3 has 488 m of surface penstock (i.e. steel pipes) and 150 m of head. Wivenhoe has 420 m of tunnel and 100 m of head (from memory). Therefore, the Tantangara-Blowring tunnel is more than 100 times as long and the hydraulic head is about 6-10 times greater than Wivenhoe and Tumut 3.

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Peter Lang — I’m a bit unsure about what you are enquiring, however even big pumps can use induction motors and so run at variable speed. For highest electrical efficiency synchronous motors are used and those run at only one speed under load.

The synchronous generators in the dams around here are rescheduled every five minutes and I’m not sure how much less time than that the units could be started or stopped. The ones I’ve seen rotate quite slowly despite generating around 200 MW each. In any case BPA routinely ramps in excess of 400 MW each rescheduling interval (but of course has many individual generators to participate in this load following).

Grand Coulee dam has has six pump-generators to deliver irrigation water (and someday do some peaking power gneration). These are of a design similar to the generators although only about 50MW each.

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DBB, Your examples are not applicable at all. They are of a totally different scale – orders of magnitude difference. Could I urge you to reread the lead article and the particular comments you are responding to with a particluar aim of getting a feel for the scale of what we are talking about. Then you might want to look for examples of pumped hydro schemes with 53 km tunnel length, 12.7 m diameter, 900 m of hydralulic head, 8-9 GW generating capacity and see if you can find anything that might be relevant?

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The latest in large-scale engineering technology are variable speed machines for greater efficiency. These machines generate in synchronization with the network frequency, but operate asynchronously (independent of the network frequency) as motor-pumps. from
http://en.wikipedia.org/wiki/Pumped-storage_hydroelectricity
and which I take to refer to induction motor-generators connected to the switchyard via power electronics. The technology is quite similar to that used in wind turbines [but of course the wind turbines are just used as generators]. The critical element is the power electronics but these can be made arbitrarily large, being not much more than a form of highly efficient rectifier/inverter pair. One could even put an HVDC line between the two ends if desired.

From
http://en.wikipedia.org/wiki/Francis_turbine
the highest head utilized so far is around 700 meters; I have no way to estimate whether operating with a 900 meter head is even possible with currently available materials.

The remaining issue is the valves used to control flow rates while generating. Again that great head height may be a concern. For smaller projects it seems that starting in under a minute is possible [from the first wiki article]. So one possiblity is to provide several smaller pump-generators, each with its own tunnel; only a suggestion.

In any case, I don’t see (so far) any insuperable difficulty regarding the electrical aspects. But as earlier comments have discussed, inertia means that flow is not going to quickly reverse.

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DBB, You are mixing apples and rocks.

The latest in large-scale engineering technology are variable speed machines for greater efficiency.

This is meaningless. What does it mean in the context of the pumped hydro we are talking about. Can I urge you to put the bits and pieces you come up with together. Otherwise it a bit like saying “an Atlas rocket is really big, but a Holden car is one of our biggest cars”. It’s just meaningless bits and pieces of unrelated snippets.

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Peter Lang — I explained already following the link to the quoted wiki page: once again, this is an induction motor-generator with power electronics to allow for variable speed operation.

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I don’t see why the three tunnels should not be started at least partially in parallel. Even for a 5-minute start, the peak acceleration power is only 12% of the full-rate pumping power, and for 30-minute startup only 2%. The simplest option would seem to be to let the pumps run up until the total power is the designed 1.5 GW/tunnel, then leave the flow rate to asymptotically approach 3 m/s at constant power draw.

For the nuclear + hydro case, how fast would you want to ramp up? You start with all the reactors running at near capacity and demand falling in the late evening. From the demand graph above the load ramp rate is about 1250 MW/hr, so you start the pumps at 23:00 but have to wait until 02:30 for there to be enough spare power to run at full rate. Then you ramp back down more steeply from 06:00 to 07:30. This scheme is so big, 18% of the average grid load, that it is constrained to move slowly to avoid over-stressing the grid it is meant to serve.

A possible error – is the 3 m/s flow rate for the discharge or recharge step? Back-of-envelope calculation gives 4.5 GW recharge as only 1.5 m/s, so all the energy and power estimates drop by a factor of 4.

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Luke_UK,

Good point. The 3 m/s is for discharge not recharge. I haven’t calculated the rate for recharge, but I’ll take your figure as probably correct.

You make a good point about the additional power needed for acceleration (i.e. additional to the power needed for constant rate pumping) is only 2% for 30 minutes acceleration period or 12% for 5 minute acceleration period.

However, I am still not sure about the capability of pumps to accelerate 7 million tonnes of water (per tunnel). I understand the pump’s speed is synchronised to the grid then begins pumping and its speed stays constant throughout. So I am not sure if it is feasible to accelerate the flow over a long period. I know very little about this, but I still wonder about accelerating this mass of water given that existing pumped hydro schemes have only relatively short tunnels.

You’ll notice on the map in the lead article the dog leg in the tunnel alignment. That is a high point in the surface topography and the best location for the surge shaft. I wonder how high the surge shaft would have to be above ground level to accommodate the surge caused by the relatively long duration acceleration and decelerations we are considering. Calculating this would be beyond my capability. Of course, this is just an added cost so it is does not preclude the concept. Also, there may be other ways, such as an underground pressure chamber instead. Again, just an additional cost.

For DBB, variable speed pumps are not used in large pumped hydro faculties, although they may become viable in the future. I’ve commented on some pumped hydro plants in Japan and Europe in previous comments on this thread.

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Having a surge shaft near the low end will make startup a fair bit easier, as it is then unnecessary to accelerate the whole mass of water together. Some checking on Google maps finds several points in the region to the east of Tantangara where ground level is well above the level of Blowering, Assuming that tunnelling there is possible, there is plenty of scope to get the water level in the shaft several tens of metres above hydrostatic equilibrium, which is all the overpressure required for any reasonable startup time.

The major issue, though, is how to manage the necessary ‘slip’ between the turbine rotor moving at full speed as required for grid synchrony and the water which is initially not moving at all. At startup the impeller blades have to move through the near-stationary water, while nearly all their swept volume goes around their edges. During normal pumping, or generation, running at only slightly lower pressure than the startup pressure, there can be only a few percent of the swept volume leaking past the blades if acceptable efficiency is to be achieved. I can’t think how this could be done with a fixed geometry for the rotor and housing. There has to be some way of allowing more bypass during startup. This problem is not unique to this scheme, and must have been solved for other pumped storage sysyems

Too much speculation here, I don’t think we can get much further unless a turbine designer comes along to help.

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Just enjoying the great brainstorming here. Perhaps very high pressure compressed air could both cheaply jump start the impeller, and using a temporary seal, far up the pipeline, we could vastly increase the water pressure, and velocity, just temporarily, to get the system up to efficient speed, cheaply.

I don’t know if there has been any experimentation with a hybrid low head pumped hydro, along with CAES. But this may make sense, just to toy around with the idea. Since wind and wave generated compressed air could augment any pumped hydro system. In theory it may be a good marriage. Both the wind and water supply can be fickle, and each could hedge each other, again in theory.

Since the most efficient storage of compressed air, to me, is at depth at sea, then the problem of distance would need to be overcome with pipe diameter, which should not be a problem. At sea CAES means little to no wiring and all the distance issues with transmission. Pipe is cheap, but pipe dreams are cheaper. http://www.environmentalfisherman.com

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[…] That these scenarios rely fundamentally on fossil fuels does not feel right to someone seriously concerned about climate change. This dependency can be broken if wind power during periods of high production could be stored somewhere. How much storage would be needed? I will now assume that: (i) (only) 20% of the energy is lost during the transfer of wind-generated energy to and from the storage, (ii) storage doesn’t “leak”, (iii) there are no limits on the storage input-output powers, and (iv) that the storage is arbitrarily large. Only type of storage that might approach these conditions even to some extent, appears to be pumped-hydro storage. […]

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The right niche for wind energy is isolated/rural off-grid locations. The grid cost can be replaced by storage.
To cut costs and make it feasible, following further changes are desirable.
The storage should be compressed air instead of battery or water pumping. Compressed air can be used directly for
Forced ventilation, with or without heat pumps.
Run pneumatic tools for pumping water for local use or other equipment.
Other pneumatic powered tools.
For lighting, photovoltaic cells and battery storage should be used in a 12 volt system via a loe power lighting diodes. This could also be used for electronic systems like TV and computers.
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Hi Jagdish – just a friendly reminder that, although the comments for some older threads are still “open”, more discussion is taking place over at the new BNC Discussion Forum including threads on various renewable energy sources. It is now the case that more people would see your comment and reply if you commented over there. It is also possible to start your own topic thread if you wish.
A tab at the top of the BNC main page links to the Forum.

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[…] Peter Lang huomautti muuten Brave new Climate:ssa, että varastoinnissa voi olla enemmän järkeä silloin, kun sitä käytettään kulutushuippujen sähköntuotantoon tilanteessa missä perusvoimaa tuotetaan halvalla ydin- (tai hiili) voimalla. Mikäli esim. ydinvoima kapasiteetti mitoitetaan kattamaan keskimääräinen kulutus ja tuotettu sähkö varastoidaan kulutuksen ollessa tätä alempi, voi energianvarastointi olla halvempi vaihtoehto kuin “ylirakentaa” ydinvoimaloita kattamaan myös kulutushuiput. Tanskan tapauksessa tarvittaisiin siis noin 5GW ydinvoimaa ja 1GW vesivoimaa kulutushuippuja varten. Tällä voi säästää, koska 1GW vesivarastointia voi maksaa vähemmän kuin 1GW ydinvoimaa. Tähän tarvittava sähkönsiirtokapasiteetti Tanskan ja Norjan välillä on jo olemassa. […]

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A smaller cheaper option exists between Eucumbene and Jindabyne. Less distance, less head, 220metres drop. Could all be built on freehold land outside the Park . The water could be pumped back up through the existing pump system at Jindabyne pump station then flow back to Eucumbene to be used again. at off peak I’m no scientist just an old farmer who left school at 15.

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Tom Barry,

You are correct, that Jindabyne-Eucumbine would be cheaper capital cost, but probably not more economic. Generating capacity for the same tunnel diameter, would be ~1/3. Furthermore, the pumps and generators must be designed to handle large water-level changes in both reservoirs – because these reservoirs are storage reservoirs and thus have to utilise near their full storage capacity. So the tunnels would have to be constructed joining near the lowest levels of each reservoir. The distance would be nearly 40 km (including a significant dog-leg to avoid tunneling under the Jindabyne reservoir). That’s expensive.

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The proposed Snowy Hydro energy storage scheme is unlikely to get off the ground (‘Snowy fix for power crisis’, 16/3). Pumped-hydro systems are seldom viable nowadays. Gas is a cheaper alternative for providing rapid response to changes in demand and for meeting peak load requirements. Pumped hydro is closest to being viable when three conditions are met: their energy storage capacity is near-fully utilized most days of the year; power for pumping is supplied by reliable, cheap, power at night; they generate power at time of peak prices, and do so most days of the year.

Cheap reliable, constant, full power for pumping can be provided by baseload power stations (coal, gas and nuclear) every night of the year. Intermittent, weather-dependent renewables, like wind and solar, cannot meet these requirements. Continued operation of Hazelwood Power Station could make the scheme more viable.

This hydro thought-bubble is another distraction from what is needed to address the power crisis in Australia. Rational policy calls for ceasing all new incentives for renewables, keeping the coal plants running, and focus on developing a reliable, cheap gas supply (as the US has done).

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One question I have with this proposal is why you would not have multiple generating stations along the length of the tunnel. You don’t need an 800m drop to run the power station, a couple of hundred metre drop would be quite sufficient so the tunnel could have 4 generators instead of one along the length. With tunneling being more than 50% of the cost I would expect there would be economic benefits to adding multiple generators.

A govt levy of 1c per kwh levy on all generators, would raise $2bn a year and would easily pay for construction and operation of this project.

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Hi David,

Multiple pump and generating stations would require storage at each one. The topography does not allow this, and even if sites were available it would entail a large extra capital and operating cost, and provide more points of failure, thus making the system less reliable.

A potential site for storage dam is available between Tantangara and Talbingo reservoirs (the PM’s proposal) but that would require another dam, and I think it would be located on the limestone formation that has the Yarrongobilly Caves: http://www.nationalparks.nsw.gov.au/things-to-do/show-caves/yarrangobilly-caves . So there is potential for leakage.

Much was discussed on this thread. I’d urge you to read the comments.

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The land near the Great Australian Bite is cavernous limestone. reservoirs on it would leak like a sieve. Plus, many other issues making it not viable – not even close.

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Hi Peter, that’s why the author recommends them lining the ground with plastic. The author claims the total bill to take Australia to 90% renewables (45GW) with this massive pumped seawater hydro-dam ‘battery’ and HVDC wiring across the bottom of Australia and all the wind and solar to recharge the battery would cost $253 billion.

Click to access sub982_attach.pdf

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[…] — Steel lining is one of the more critical cost factors. For many high head projects, the cost of steel lining is the factor that determines whether the project is economic or not. You need to know in situ stresses etc to do a proper analysis. Brave New Climate […]

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Those interested in Snowy Hydro 2.0 and energy storage, and those who read my 2010 post “Pumped-Hydro Energy Storage – Tantangara-Blowering Cost Estimatehttps://bravenewclimate.com/2010/04/05/pumped-hydro-system-cost/,
might find the lead article on the Commentary page (p10) of today’s The Australian of interest. The title is “On every count, Snowy 2.0 is a disaster in the making</i?”. I strongly recommend it.

Some short experts from the article are available here: https://wentworthreport.com/2020/09/18/on-every-count-snowy-2-0-is-a-disaster-in-the-making/

I’ll try to post the full article in another comment, but it may fail.

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Source: The Australian Commentary, 18 Sep 2020, by Ted Woodley and 36 other industry experts

On every count, Snowy 2.0 is a disaster in the making

https://cdn.newsapi.com.au/image/v1/c453e751c94fa8802863c04d93ff9b8f?width=650
The Tumut 3 power station at the Snowy Hydro Scheme in Talbingo.

“Even more revelations have emerged since our correspondence of March 24 that identified many overstated and false claims for the Snowy 2.0 pumped hydro project.
Back then we urged a comprehensive review of Snowy 2.0. It is now even clearer that there are numerous alternatives that are lower cost, more efficient, quicker to construct, and incur fewer emissions and environmental impacts.
Regrettably, no review was undertaken, and the Snowy 2.0 main works phase has been approved. Yet substantial evidence continues to emerge that further refutes the core claims of the project.
Details confirm that the Snowy 2.0 business case, issued almost two years ago by Snowy Hydro, was based on grossly inflated revenues and understated costs. Put simply, the federal government was presented with a profoundly flawed justification.
On the revenue side, the output of Snowy 2.0 from 2025 to 2042 is now forecast to be less than half the business case estimate, according to the Australian Energy Market Operator. AEMO forecasts Snowy 2.0 to be largely idle before 2033, as the existing 1800 megawatt Tumut 3 pumped hydro station can provide most of the forecast output from both stations until then. Also, AEMO forecasts Snowy 2.0 would never attain the maximum annual output estimate in the business case.
Not only has output been over-estimated by 100 per cent, Snowy 2.0 is not urgent or critical for the transition to renewable energy, nor itself “renewable”.
On the cost side, the business case estimate of $3.8bn to $4.5bn is understated, also by about 100 per cent. It has been disclosed that the estimate does not include all project costs, and has already been exceeded by a $5.1bn contract for just a portion of the works. Once all costs are added, including the associated transmission lines, we predict the total to be in the vicinity of $10bn.
It is now clear that Snowy 2.0 will never pay for itself. Analysis by the Victoria Energy Policy Centre finds that even Snowy Hydro’s inflated revenue projection will cover only a quarter of the capital cost. The latest AEMO forecast means the gap between revenue and cost is even wider. The owners of Snowy Hydro (that is, all Australian taxpayers) will be liable for billions of dollars in losses, in addition to the $1.4bn already allocated from Treasury.
Further, the cost trajectory for pumped hydro is rapidly trending in the opposite direction to other energy storage technologies. AEMO recently revised its modelling costs, increasing pumped hydro costs by 50 per cent and decreasing battery costs by 30 to 40 per cent, with a further 50 per cent decrease in battery costs by the end of this decade.
Battery costs are plummeting and are likely to continue to do so into the 2030s, crowding out pumped hydro.
This emerging uncompetitiveness of pumped hydro is evidenced by last month’s shelving of the Shoalhaven pumped hydro extension after a two-year assessment concluded it was “not commercially feasible”. It is telling that only one other pumped hydro project has been committed this century.
In contrast, battery projects are being announced almost weekly, of ever-larger capacities, as are major advances with demand management, “virtual” interconnected power plants, hydrogen etc.
The contribution of distributed energy will continue to grow, consolidating the need for smaller, co-located storage, rather than large-scale storage, hundreds of kilometres from load centres.
The financial and technical flaws of Snowy 2.0 are reason enough to halt the project. An equally compelling reason is the recently revealed magnitude of damage to Kosciuszko National Park. The bulldozed moonscape scar along 5km of the Yarran¬gobilly River at the Lobs Hole construction site is already visible on satellite images. Much more is to be destroyed across 35km of the park. Most of the 20 million tonnes of excavated spoil is now to be dumped on parkland rather than in the reservoirs.
No amount of engineered restoration can replace the loss of pristine alpine landscape and wildlife habitat in this internationally renowned location.
Your governments have conceded the inevitability of pest fish and pathogens being transferred from Talbingo Reservoir to Tantangara Reservoir and then throughout the Snowy Mountains and downstream rivers (Murrumbidgee, Murray, Snowy, Tumut).
Native fish and recreational fishing will be devastated. A critically endangered species, stocky galaxias, will become extinct.
Here’s how the NSW Department of Primary Industries describes them: “Stocky galaxias is listed as a critically endangered species. There are heavy penalties for harming, possessing, buying or selling them, or for harming their habitat.” Yet it is now evident that the NSW government has no option but to grant exemptions to its own biosecurity protections to “legitimise” the spreading of declared noxious pests, throughout a national park no less, and beyond — this will be unprecedented.
It has been reported that $1bn has been spent on the project, even though environmental approval was granted only two months ago and the transmission line environmental impact statement has yet to be exhibited. It is well time to cut the losses — there is still $9bn or more to be saved on behalf of Australian taxpayers and electricity consumers.
We again urge your governments to undertake an independent expert review of Snowy 2.0.
Recent information confirms that Snowy 2.0 is not critical, not viable, uncompetitive, wasteful and will devastate vast areas of Kosciuszko National Park. There are far better alternatives.”

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