The long term storage challenge – batteries not included

Print Friendly, PDF & Email

There is a lot of focus on the ability of battery storage to shift peaks and store energy for hours, or even days. But energy systems with high renewables penetration will need longer term solutions – hydrogen, compressed air, pumped hydro are three technologies being looked at in Australia and elsewhere.

Print Friendly, PDF & Email

Battery storage technologies seem to be the hot topic wherever you look in the energy industry. Germany is investing heavily into domestic storage, California has a huge mandate, and the market for peak shifting and storing production is gaining the interest of consumers, pro-sumers and network operators alike.

But can battery storage really solve some of the issues faced by the growing penetration of intermittent solar and wind technology? In the short term, it probably can, but as the penetration of renewables starts to grow in major economies, many think that battery storage will at such scale either simply be too expensive, or not have enough capacity to solve some of the long term issues.

Three new technologies are now emerging as potential long term solutions, and all argue that they will be cost competitive and even displace some of the gas generation that is normally assumed to fill the gaps.

Here’s a brief look at three of them:

Chemical Energy Storage

In Germany, there is a view that the only way to provide the amount of storage needed for a nearly fully renewable grid in the long term is through chemical means – and right now there are a bunch of projects that are looking how to apply electrolysis to turn excess output from wind and solar and other generation into hydrogen and methane.

At the Fraunhofer Institute for Solar Energy Systems in Frieburg, Dr Gunter Ebert says hydrogen and methane is the only option for large scale “season storage”. Battery can provide some short term storage capacity, maybe up to 50GWh – and so can pumped hydro  (60GWh) – but he says the options are limited in Germany.

“We need a tremendous amount of long term storage – up to 70TWh,” Ebert told RenewEconomy in Frieburg last month. “That can only be done with hydrogen and methane.”

Ebert’s plan is to use caverns to store hydrogen, which can then me used for vehicles, or in fuel cells, or it can be converted into methane for use in the gas grid. Or it can be used for direct heat and power generation, as this rather complicated graph shows.

energy storage

As Craig Morris reported on the Energiewende blog last week, the German company Thüga has exported the first hydrogen from electrolysis to the natural gas network.  The firm says it plans to go into official operation at the beginning of 2014 after a test run. The practical test under operating conditions will last for nearly 3 years until the end of 2016. The unit under investigation has a power capacity of 315 kilowatts and can produce 60 cubic meters of hydrogen per hour.

Ebert says there are  still many possibilities about how such a scheme could be put together – but some form of long term storage will be needed after 2020, when the share of renewables grows beyond 40 per cent, and more thermal generation is sidelined.

Compressed Air Energy Storage

compressed airThe second big technology that is being looked at is compressed air energy storage, known as CAES. The Boston-based firm General Compression last year opened a 2MW/500MWh pilot plant in Texas last year, and its representatives have made three trips to Australia this year to talk to utilities, renewable energy developers, and government representatives about their technology.

Development officer Peter Rood says CAES would work best at the utility-scale with 10MW to 100MW. It requires below ground storage – either natural or man-made – and could work with storing the output of wind energy, or even as a “storage bank” for thousands of rooftop and other distributed solar systems.

Rood told RenewEconomy during a visit to Australia last week that CAES will help wind energy act like a flexible gas-fired power station, providing base-load and peaking generation when needed – storing energy produced on some windy days for use later in the week – or even the month.

That means it would not only be able to mimic the services delivered by gas turbines, it would be able to compete with even combined cycle gas turbines as gas prices head above $10/mmbtu, where they are surely heading in Australia as the gas market heads towards export price parity.

“I think there will be a pretty compelling case to build wind plus storage,” he says, noting that a lot of thermal generation is ageing, and a renewables-focused energy system will need storage and other ancillary services, such as frequency, that such a system could provide.

General Compression is working on a rough formula of providing around 20-40 megawatt hours of storage for each MW of peak power production. Which means that for a 100MW wind project, the ideal would be to have a facility that could deliver between 200MWh and 400MWh of storage. CAES would be able to deliver this at a quarter of the price of battery technologies, says Rood.

General Compression also has a proposal for a “solar bank”, which would allow solar households to store excess energy, and either draw down that energy when needed, or sell it other users. (See more on that idea here).

General Compression has received some interesting funding to from the likes of oil giant ConocoPhillips and the largest utility in the US, Duke Energy.

Pumped Hydro 

Another option is pumped hydro – a technology that is being pursued by the Melbourne Energy Institute and separately by the Australian National University. Australia already has some pumped hydro – it’s a key element of the Snowy River Hydro Scheme – but the new approach looks at siting pumped hydro storage away from natural water-courses and using natural contours to situate two reservoirs at different elevation  that could be used to store energy – and negate the need to curtail output from wind farms.

japan pumped hydro storageAndrew Blakers from the ANU, says there are numerous sites along the eastern seaboard, and elsewhere, that could lend themselves to pumped storage – and he is proposing a survey could be done to identify those sites. A joint study by the engineering and consulting company Arup and the University of Melbourne Energy Institute suggested that best technology may be pumping seawater up to coastal cliff tops, as has been done in a pilot facility in Japan (pictured).

The irony is that pumped hydro was once built to support coal and nuclear, and their inability to ramp up quickly to meet changes in demand. Now they will be used to absorb and manage changes in supply. The MEI/Arup investigations found the benefits included  stabilising and reducing wholesale electricity prices
– increasing the spread of renewable energy – reducing the need to expand electricity transmission
– and improving grid operations.

A report by Blakers and colleague James Pittock found that pumped hydro could even by produced from pairs of oversized “farm dams” located close to each other at different elevations. They noted that the cost of these systems is much more heavily weighted to power production (pump/turbines, pipes & tunnels, interconnection to the grid) rather than energy storage (dams & lakes).

“Pumped hydro storage is efficient, flexible, economical and commercially available on a vast scale. Indeed, it is the only large scale storage technology currently available to the electricity industry,” they said – noting that competing storage techniques, such as compressed air, high temperature thermal storage in conjunction with concentrating solar thermal (CST), and advanced batteries, are considerably more costly or less developed.

Blakers says there are only around 200 large pumped hydro systems in the world, with a total capacity of around 130GW. Of this, about 2.5GW is located in Australia. But they note that storage of Australia’s entire electrical output for 24 hours using pumped hydro would require combined upper and lower lakes of about 100 km2 (or about 5 m2 per Australian citizen). This calculation assumes that the lakes are 15m deep, there is an elevation difference between the upper and lower lakes of 400m, and that the round trip efficiency is 80%.

Print Friendly, PDF & Email

  1. madankerr 5 years ago

    Blakers estimate that 100 sqkm of pumped hydro would cover 100% of Aust’s electricity demand for 24 hours. How big is 100 sqkm? For comparison, Warragamba Dam is 75sqkm. So, 100 sqkm of pumped hydro sounds eminently do-able.

    • Miles Harding 5 years ago

      Indeed it is!

      The 400m of height difference (head) in the story is a bit optimistic. There are many locations at 100m and many more at 50m, but more reservoir is needed.

      The round trip efficiency is currently around 75%, making it as good as lead-acid batteries and a lot better than hydrogen**.

      Also, there is an obvious pairing of aquaculture and seaside pumped hydro that may make the lake a lot more valuable.

      ** What is it with hydrogen??? This lousy option is like a good zombie!
      The tidy drawing needs a footnote on the three wind turbines:
      “Only one and a bit would be required for pumped hydro or batteries.”
      Why persist with an obvious loser?

      • JonathanMaddox 5 years ago

        Round-trip efficiency is not the most important thing, if the power being stored away is otherwise surplus to the instantaneous requirement. Some electricity spot-markets today allow for *negative* power prices in the off-peak times and prices of hundreds of dollars per MWh at peak daily demand (as opposed to a typical shoulder price around $50/MWh or less). With differentials like that, storage doesn’t need high round-trip efficiency. What matters far more is capital cost.

  2. juxx0r 5 years ago

    Isn’t it about time that we recognised hydro as storage. If we only used it when we needed it then Bob’s your uncle. The distinction that only pumped hydro is storage is false, if it has capacitance then it’s storage.

    • RobS 5 years ago

      You are confusing storage for despatchability. By your logic a gas turbine with a gas supply is also “storage” as it can be used when needed too. I agree that the despatchability of Hydro is a major strength that facilitates far higher levels of intermittent renewables in much the same way as storage does but at a far lower cost. However the two are different concepts.

      • juxx0r 5 years ago

        I see your point, but we can use hydro even when it’s not raining. We do this by storing the potential energy. It’s like where we waste energy pumping it up there except without pumping it up there and without wasting energy.

        It’s time to look at this like we look at efficiency, like it’s the best new supply.

        To not use it is to save it for later.

        • JonathanMaddox 5 years ago

          Don’t forget, however, that many hydro installations have limited storage capacity because of environmental and/or engineering concerns. Norway’s existing hydroelectric system was designed to provide seasonal storage of energy as there’s a clear annual snowmelt flood season each spring. Since its storage capacity is enormous by design, it serves very well as a “battery” for wind power. Existing hydro systems in Australia have not been designed with seasonal storage of energy in mind. In some locations (particularly the Snowy) it may be possible to adapt the existing reservoirs, but it’s not clear there would be sufficient storage space available to “hold back” much of our more unpredictable floods for later use.

      • JonathanMaddox 5 years ago

        Absolutely! Fossil fuels *are* stored energy. Our present-day energy infrastructure is designed to deplete that storage — with abysmal round-trip efficiency!

        Power-to-fuels technology such as that described above can, in effect, replenish that store using renewable electricity and achieving somewhat better efficiency.

  3. Dimitar Mirchev 5 years ago

    Dont forget second hand EV batteries. A typical EV Battery can be used two times longer as grid storage after it is no longer fit for electric transportation.

    EVs had around 20 kWh batteries, 1 million EV sales per year means that in 5-10 years theese 1 milion 20 kWh ( 20 GWh ) batteries will become grid storage. That’s 20 GWh/year.

    10 milion EV/year means 200 GWh/year. Thats not little.

  4. Nick Sharp 5 years ago

    Cryogenic storage may also be worth a look:

    Use surplus (at the time) electricity to liquefy air (as in liquid air/oxygen/nitrogen production). Store it in insulated vessels (atmospheric pressure). Use waste heat from some industrial process (or pebble-bed-stored heat generated by the liquefaction) to heat it up again in a pressure vessel, using the pressure to drive a turbine+generator.

    Could be combined with LA distillation to yield LOX and LN for the market, storing surplus LN for power. How environmental is that? The emissions consist of … nitrogen, returning to the air from whence it came!

  5. David Jago 5 years ago

    Then there’s “gravity power”. This seems a lot like pumped hydro, except that it’s underground.

  6. JonathanMaddox 5 years ago

    “The irony is that pumped hydro was once built to support coal and nuclear, and their inability to ramp up quickly to meet changes in demand.”

    This has turned out to be a bit of a myth as the costs of fuel, carbon emissions and maintenance for older coal-fired power stations have mounted. New South Wales’ and Queensland’s black-coal power stations have always reduced output at night when demand was reduced. Even older brown-coal power stations such as Yallourn and Hazelwood do so these days, though their operators swore it was impossible a few short years ago.

    In Germany the older power stations have been decommissioned en masse, and their more modern replacements (frequently called out by detractors of intermittent renewables as a renaissance of coal in the land of wind and solar) are not only much more efficient, but are also explicitly intended to be able to vary output more flexibly, precisely in order to accommodate ever-increasing penetration of intermittent renewables.

  7. Askgerbil Now 5 years ago

    A different perspective: If the poles and wires that are needed for fewer than 40 hours per year (in extreme peak conditions) are responsible for high network charges, can energy storage to replace that capacity for the same 40 hours per year make any appreciable difference to the fundamental economics of this problem.

    In other words, whether 40 hours a year of extreme peak demand is met from excess grid infrastructure, excess energy storage or excess distributed generation capacity – someone ends up “holding the bag”. That is: a substantial capital investment that is only useful for fewer than 40 hours each year.

    For something completely different…

    Suppose some people invest in assets that can profitably convert electricity into some other product – (aluminium, hydrogen, … ?) – and incur very little loss by turning that asset off during just 40 hours per year, then no-one is left “holding the bag”.

Comments are closed.