There’s a simple way to drought-proof a town – build more water storage



Inland towns need far more water storage.
Flickr/Mertie, CC BY-SA

Michael Roderick, Australian National University

The federal parliament has voted to funnel A$200 million to drought-stricken areas. What exactly this money will be spent on is still under consideration, but the majority will go to rural, inland communities.

But once there, what can the money usefully be spent on? Especially if there’s been a permanent decline in rainfall, as seen in Perth. How can we help inland communities?




Read more:
Recent Australian droughts may be the worst in 800 years


Let’s look at the small inland town of Guyra, NSW, which is close to running dry. Unlike our coastal cities, Guyra cannot simply build a billion-dollar desalination plant to supply its water. Towns like Guyra must look elsewhere for its solutions.

Running dry isn’t just about rainfall

“Running dry” means there is no water when the tap is turned on. It seems to make sense to blame the drought for Guyra’s lack of water. But the available water supply is not only determined by rainfall. It also depends on amount of water flowing into water storage (called streamflow), and the capacity and security of that storage.

While Perth has had a distinct downturn in its rainfall since the 1970s and has built desalination plants to respond to this challenge, no such downturn is evident at Guyra. Indeed, to date, the driest consecutive two years on record for Guyra were 100 years ago (1918 and 1919).

Long-term rainfall records for Perth (left) and Guyra (right). Dashed red line shows the trend and the full yellow line shows 600 mm annual rainfall.
Bureau of Meteorology

Despite the differences, there are some similarities between Perth and Guyra. As a rule of thumb, in Australia, significant streamflow into water storages does not occur until annual rainfall reaches around 600mm. This occurs as streamflow is generally supplied from “wet patches” when water can no longer soak into the soil. Thus, if annual rainfall is around 600mm or below, we generally anticipate very little streamflow.

While Guyra has seen some rain in 2019, it is not enough to prompt this crucial flow of water into the local water storage. The same is true for Perth, with annual rainfall in the past few decades now hovering close to the 600mm threshold.

Importantly, rainfall and streamflow do not have a linear relationship. Annual rainfall in Perth has declined by around 20%, but Perth’s streamflow has fallen by more than 90%.

With little streamflow filling its dams, Perth had little choice but to find other ways of increasing its water supply. They built desalination plants to make up the difference.

Let’s return to Guyra in NSW and the current drought. The rainfall records do not indicate there is a long-term downward trend in rainfall. But even without a rainfall trend, there are still dry years when there is little streamflow. Indeed, in Guyra, the rainfall record shows that, on average, the rainfall will be 600mm or less roughly one year out of every ten years.

Build more storage

So how do the residents of Guyra ensure a reliable water supply, given that they cannot build themselves a desalination plant?

Well, in this case, you can simply get water from somewhere else if it is available. A pipeline is currently under construction to supply Guyra from the nearby Malpas Dam, and is expected to be in operation very soon.

But that’s not always an option. A made-in-Guyra water solution means one thing: expanding storage capacity.

Guyra can generally store around 8 months of their normal water demand (although of course demand varies with the seasons, droughts, water restrictions and price per litre).

To give a point of comparison, Sydney can store up to five years of its normal water demand, and has a desalination plant besides. Despite these advantages, Sydney residents are now under stage one water restrictions which happens when its storages are only 50% full. Yet, even when Sydney’s glass is only half-full, that city still has at least another two years of water left to meet the expected water demand even without using desalination.

By comparison, when water storages in Guyra are 50% full, they have less than six months normal water supply.

It is astonishingly difficult to find accurate data on small-town water supplies but in my experience Guyra is not unique among rural towns. There is a big divide between the water security of those living in Australia’s big cities compared to smaller inland towns. Many rural communities simply do not have sufficient water storage to withstand multi-year droughts, and in some cases, cannot even withstand one year of drought.




Read more:
Droughts, extreme weather and empowered consumers mean tough choices for farmers


Nature, drought and climate change cannot be blamed for all of our water problems. In rural inland towns, inadequate planning and funding for household water can sometimes be the real culprit. Whether Australians live in rural communities or big cities, they should be treated fairly in terms of both the availability and the quality of the water they use.The Conversation

Michael Roderick, Professor, Research School of Earth Sciences and Chief Investigator in the ARC Centre of Excellence for Climate Extremes, Australian National University

This article is republished from The Conversation under a Creative Commons license. Read the original article.

How protons can power our future energy needs



File 20180312 30994 1en5r6j.jpg?ixlib=rb 1.1
The proton battery, connected to a voltmeter.
RMIT, Author provided

John Andrews, RMIT University

As the world embraces inherently variable renewable energy sources to tackle climate change, we will need a truly gargantuan amount of electrical energy storage.

With large electricity grids, microgrids, industrial installations and electric vehicles all running on renewables, we are likely to need a storage capacity of over 10% of annual electricity consumption – that is, more than 2,000 terawatt-hours of storage capacity worldwide as of 2014.

To put that in context, Australia’s planned Snowy 2.0 pumped hydro storage scheme would have a capacity of just 350 gigawatt-hours, or roughly 0.2% of Australia’s current electricity consumption.




Read more:
Tomorrow’s battery technologies that could power your home


Where will the batteries come from to meet this huge storage demand? Most likely from a range of different technologies, some of which are only at the research and development stage at present.

Our new research suggests that “proton batteries” – rechargeable batteries that store protons from water in a porous carbon material – could make a valuable contribution.

Not only is our new battery environmentally friendly, but it is also technically capable with further development of storing more energy for a given mass and size than currently available lithium-ion batteries – the technology used in South Australia’s giant new battery.

Potential applications for the proton battery include household storage of electricity from solar panels, as is currently done by the Tesla Powerwall.

With some modifications and scaling up, proton battery technology may also be used for medium-scale storage on electricity grids, and to power electric vehicles.

The team behind the new battery. L-R: Shahin Heidari, John Andrews, proton battery, Saeed Seif Mohammadi.
RMIT, Author provided

How it works

Our latest proton battery, details of which are published in the International Journal of Hydrogen Energy, is basically a hybrid between a conventional battery and a hydrogen fuel cell.

During charging, the water molecules in the battery are split, releasing protons (positively charged nuclei of hydrogen atoms). These protons then bond with the carbon in the electrode, with the help of electrons from the power supply.

In electricity supply mode, this process is reversed: the protons are released from the storage and travel back through the reversible fuel cell to generate power by reacting with oxygen from air and electrons from the external circuit, forming water once again.

Essentially, a proton battery is thus a reversible hydrogen fuel cell that stores hydrogen bonded to the carbon in its solid electrode, rather than as compressed hydrogen gas in a separate cylinder, as in a conventional hydrogen fuel cell system.

Unlike fossil fuels, the carbon used for storing hydrogen does not burn or cause emissions in the process. The carbon electrode, in effect, serves as a “rechargeable hydrocarbon” for storing energy.

What’s more, the battery can be charged and discharged at normal temperature and pressure, without any need for compressing and storing hydrogen gas. This makes it safer than other forms of hydrogen fuel.

Powering batteries with protons from water splitting also has the potential to be more economical than using lithium ions, which are made from globally scarce and geographically restricted resources. The carbon-based material in the storage electrode can be made from abundant and cheap primary resources – even forms of coal or biomass.




Read more:
A guide to deconstructing the battery hype cycle


Our latest advance is a crucial step towards cheap, sustainable proton batteries that can help meet our future energy needs without further damaging our already fragile environment.

The time scale to take this small-scale experimental device to commercialisation is likely to be in the order of five to ten years, depending on the level of research, development and demonstration effort expended.

Our research will now focus on further improving performance and energy density through use of atomically thin layered carbon-based materials such as graphene.

The ConversationThe target of a proton battery that is truly competitive with lithium-ion batteries is firmly in our sights.

John Andrews, Professor, School of Engineering, RMIT University

This article was originally published on The Conversation. Read the original article.

Yes, SA’s battery is a massive battery, but it can do much more besides


Dylan McConnell, University of Melbourne

Last Friday, the “world’s largest” lithium-ion battery was officially opened in South Australia. Tesla’s much anticipated “mega-battery” made the “100 days or it’s free” deadline, after a week of testing and commissioning.

Unsurprisingly, the project has attracted a lot of attention, both in Australia and abroad. This is largely courtesy of the high profile Tesla chief executive Elon Musk, not to mention the series of Twitter exchanges that sparked off the project in the first place.

Many are now watching on in anticipation to see what impact the battery has on the SA electricity market, and whether it could be a game-changer nationally.

The Hornsdale Power Reserve

The “mega battery” complex is officially called the Hornsdale Power Reserve. It sits alongside the Hornsdale Wind Farm and has been constructed in partnership with the SA government and Neoen, the French renewable energy company that owns the wind farm.

The battery has a total generation capacity of 100 megawatts, and 129 megawatt-hours of energy storage. This has been decribed as “capable of powering 50,000 homes”, providing 1 hour and 18 minutes of storage or, more controversially, 2.5 minutes of storage.

At first blush, some of these numbers might sound reasonable. But they don’t actually reflect a major role the battery will play, nor the physical capability of the battery itself.

What can the battery do?

The battery complex can be thought of as two systems. First there is a component with 70MW of output capacity that has been contracted to the SA government. This is reported to provide grid stability and system security, and designed only to have about 10 minutes of storage.

The second part could be thought of as having 30MW of output capacity, but 3-4 hours of storage. Even though this component has a smaller capacity (MW), it has much more storage (MWh) and can provide energy for much longer. This component will participate in the competitive part of the market, and should firm up the wind power produced by the wind farm.


Read more: Australia’s electricity market is not agile and innovative enough to keep up


In addition, the incredible flexibility of the battery means that it is well suited to participate in the Frequency Control Ancillary Service market. More on that below.

The figure below illustrates just how flexible the battery actually is. In the space of four seconds, the battery is capable of going from zero to 30MW (and vice versa). In fact it is likely much faster than that (at the millisecond scale), but the data available is only at 4-second resolution.

Hornsdale Power Reserve demonstrating its flexibility last week. The output increased from zero to 30MW (full output) in less than 4 seconds.
Author provided (data from AEMO)

Frequency Control and Ancillary Service Market

The Frequency Control and Ancillary Service (FCAS) market is less known and understood than the energy market. In fact it is wrong to talk of a single FCAS market – there are actually eight distinct markets.

The role of these markets is essentially twofold. First, they provide contingency reserves in case of a major disturbance, such as a large coal generation unit tripping off. The services provide a rapid response to a sudden fall (or rise) in grid frequency.

At the moment, these contingency services operate on three different timescales: 6 seconds, 60 seconds, and 5 minutes. Generators that offer these services must be able to raise (or reduce) their output to respond to an incident within these time frames.

The Hornsdale Power Reserve is more than capable of participating in these six markets (raising and lowering services for the three time intervals shown in the illustration above).

The final two markets are known as regulation services (again, as both a raise and lower). For this service, the Australian energy market operator (AEMO) issues dispatch instructions on a fine timescale (4 seconds) to “regulate” the frequency and keep supply and demand in balance.

The future: fast frequency response?

Large synchronous generators (such as coal plants) have traditionally provided frequency control, (through the FCAS markets), and another service, inertia – essentially for free. As these power plants leave the system, there maybe a need for another service to maintain power system security.

One such service is so-called “fast frequency response” (FFR). While not a a direct replacement, it can reduce the need for physical inertia. This is conceptually similar to the contingency services described above, but might occur at the timescale of tens to hundreds of milliseconds, rather than 6 seconds.


Read more: Baffled by baseload? Dumbfounded by dispatchables? Here’s a glossary of the energy debate


The Australian Energy Market Commission is currently going through the process of potentially introducing a fast frequency response market. In the meantime, obligations on transmission companies are expected to ensure a minimum amount of inertia or similar services (such as fast frequency response).

I suspect that the 70MW portion of the new Tesla battery is designed to provide exactly this fast frequency response.

Size matters but role matters more

The South Australian battery is truly a historic moment for both South Australia, and for Australia’s future energy security.

The ConversationWhile the size, of the battery might be decried as being small in the context of the National Energy Market, it is important to remember its capabilities and role. It may well be a game changer, by delivering services not previously provided by wind and solar PV.

Dylan McConnell, Researcher at the Australian German Climate and Energy College, University of Melbourne

This article was originally published on The Conversation. Read the original article.

With battery storage to the rescue, the Kodak moment for renewables has finally arrived



Image 20170319 6133 1xq9awd

AAP/Lukas Coch

David Holmes, Monash University

Who would have thought that, scarcely five weeks after Treasurer Scott Morrison, paraded a chunk of coal in parliament, planning for Australia’s energy needs would be dominated by renewables, batteries and hydro? The Conversation

For months now, the Coalition has been talking down renewables, blaming them for power failures, blackouts, and an unreliable energy network.

South Australia was bearing the brunt of this campaign. The state that couldn’t keep its lights on had Coalition politicians and mainstream journalists vexatiously attributing the blame to its high density of renewables.

But this sustained campaign, which would eventually hail “clean coal” as Australia’s salvation, all came unstuck when tech entrepreneur Elon Musk came out with a brilliant stunt: to install a massive battery storage system in South Australia “in 100 days, or it’s free”.

The genius of the stunt was not to win an instant contract to follow up on such a commitment, but to put an end to decades of dithering over energy policy that major political parties are so famous for in Australia and around the world, and which have intensified the climate crisis to dangerous levels.

Musk’s stunt was not without self-interest. It also aimed to position Tesla as a can-do company for future contracts. But where it was lethal was in completely neutering the campaign against renewables.

Anti-renewable politicians around the country, regardless of whether they are captive to the fossil-fuel lobby, could no longer argue for a dubious “clean-coal” powered station that would take between five and seven years to build when Tesla could fix a state’s energy crisis in 100 days – and not emit one gram of carbon at the end of the process.

Both the South Australian and Victorian governments have responded to Musk’s proposal by bidding for 100 megawatts of battery storage in their states. In South Australia’s case, a state-owned 250MW backup gas-fired fast-start aeroderivative power plant is also to be commissioned.

The state-owned gas power plant is, however, only a support to plans for a renewable-fed grid to be the main source of emergency dispatchable power. It is a plant that anticipates the way extreme weather can impact on energy infrastructure in much the same way desalination plants do for water infrastructure.

This is one reason it must be state-owned. But another is that a private operator would insist on full-time generation to maximise investment and profits. Thus, the South Australian gas plant is actually a critique of the privatisation of energy provision in Australia, which is the single greatest cause of why electricity prices have gone up.

As Giles Parkinson from RenewEconomy points out, within a framework in which privatisation dominates, the current market rules actually disadvantage the merits of non-domestic battery storage for consumers – because private power retailers can exploit arbitrage between low and high prices.

They can load up the batteries when excess wind and solar are cheap and sell it at peak demand for inflated prices. So, storage can actually enhance profits for power suppliers and create a bad deal for consumers.

However, the intrinsic value of storage is that the more you add, the less volatility there will be in a market. This creates a stable price for consumers and less profits for the corporations.

An example Parkinson uses is the Wivenhoe pumped storage facility in Queensland. This is:

… rarely used, because it would dampen the profits of its owners, which also own coal and gas generation.

Nevertheless, as a concept, the battery storage solution proposed by Musk, followed by South Australian Premier Jay Weatherill’s decisive action, really had constricted Malcolm Turnbull’s options. For a start, it makes redundant the longstanding fiction of “baseload power”, which was coined by the fossil-fuel industry to justify coal.

By last week, Turnbull would have already had the results of focus groups telling him that “clean” coal doesn’t wash with voters at all.

So, after reeling for most of last week over the humiliation that the Tesla and Weatherill challenge presented, and after scrambling for a counterpunch, Turnbull came up with Snowy Hydro 2.0. Here Musk’s stunt could only be really met with another stunt, but one in which Turnbull is only trying to salvage a very bad hand that he has played against battery-friendly renewables.

It is true that pumped hydro is currently cheaper than battery storage, but cannot be implemented nearly as quickly, and is not infinitely scalable as battery farms are.

Also, whereas the cost of battery storage continues to fall, the cost of the engineering needed for pumped hydro is not. And there are limited locations suitable for its operation.

But more important than all these considerations is that it while Snowy 2.0 will stabilise the national grid no matter whether clean or dirty energy is powering its pumps, it will only assist decarbonisation if the pumps are powered by wind and solar, which has all been glossed over in its PR sell.

With current energy market rules, there is still some incentive for dirty generators to feed the Snowy pumps. This helps energy security but does nothing for the climate crisis.

Yet, with his PR campaign, Turnbull thinks he is on a winner. The Snowy is also an icon of Australian nation-building and fable. And there is probably some political capital to be scored there. But the Snowy is a once-off, and not a part of the future as battery storage is.

But in having to play the part of the Man from Snowy River, Turnbull may have forestalled the inevitable onset of batteries, the price of which was that he was snookered into committing to an alternative substantial renewable-energy-friendly project.

So significant was the original stunt by Musk that set off a train of events cornering Turnbull into offering counter-storage that Giles Parkinson declared:

Turnbull drives stake through heart of fossil fuel industry.

But then, just when you thought coal had been cremated for the last time, it is revived over the weekend with the work of Chris Uhlmann, the ABC’s political editor, who gained notoriety for his anti-renewable stance on South Australia last year.

In his latest piece on the ABC, Uhlmann forewarns that the closure of the Hazlewood power station (5% of the nation’s energy output) will lead to east coast blackouts and crises in the manufacturing sector.

Uhlmann salutes the language of the coal companies in predicting that an energy crisis will result from no new investment in “baseload” power, even though this is precisely what renewables plus storage actually amounts to. He then quotes a Hazelwood unit controller as his source to raise the bogie of intermitancy once again:

Intermittent renewable energy could not be relied on during days of peak demand.

But the most misleading part of his piece was to point to the Australian Energy Market Operator’s prediction that shortfalls in supply next summer can be attributed to the closure of coal power stations, rather than the fact that climate-change-induced hotter temperatures are driving up demand during this period – as they did in the summer just gone, when Hazelwood was operating.

Perhaps Uhlmann’s piece would not look like such an advertorial for the coal industry had it not appeared on the same day as Resources Minister Matt Canavan’s speculation that a new coal-fired plant could be built in Queensland that will be subsidised by the A$5 billion Northern Australia Infrastructure fund.

On the ABC’s Insiders, Canavan lamented that Queensland did not have a:

… baseload power station north of Rockhampton … We’ve got a lot of coal up here, the new clean-coal technologies are at an affordable price, reliable power and lower emission.

It seems that while South Australia is leading the progress on a renewables Kodak moment, Queensland, with plans to build a coal-fired power stations and the Queensland Labor government going to great lengths to support the gigantic Adani coal mine, at least two states are moving in completely opposite directions.

David Holmes, Senior Lecturer, Communications and Media Studies, Monash University

This article was originally published on The Conversation. Read the original article.

Putting carbon back in the land is just a smokescreen for real climate action: Climate Council report


Martin Rice and Will Steffen, Australian National University

Just as people pump greenhouse gases into the atmosphere by burning fossil fuels, the land also absorbs some of those emissions. Plants, as they grow, use carbon dioxide and store it within their bodies.

However, as the Climate Council’s latest report shows, Australia’s fossil fuels (including those burned overseas) are pumping 6.5 times as much carbon into the atmosphere as the land can absorb. This means that, while storing carbon on land is useful for combating climate change, it is no replacement for reducing fossil fuel emissions.

Land carbon is the biggest source of emission reductions in Australia’s climate policy centrepiece – the Emissions Reduction Fund. This is smoke and mirrors: a distraction from the real challenge of cutting fossil fuel emissions.

Land carbon

Land carbon is part of the active carbon cycle at the Earth’s surface. Carbon is continually exchanging between the land, ocean and atmosphere, primarily as carbon dioxide.

In contrast, carbon in fossil fuels has been locked away from the active carbon cycle for millions of years.

Carbon stored on land is vulnerable to being returned to the atmosphere. Natural disturbances such as bushfires, droughts, insect attacks and heatwaves, many of which are being made worse by climate change, can trigger the release of significant amounts of land carbon back to the atmosphere.

Changes in land management, as we’ve seen in Queensland, for example, with the relaxation of land-clearing laws by the previous state government, can also affect the capability of land systems to store carbon.

Burning fossil fuels and releasing CO₂ to the atmosphere thus introduces new and additional carbon into the land-atmosphere-ocean cycle. It does not simply redistribute existing carbon in the cycle.

The ocean and the land absorb some of this extra carbon. In fact, just over half of this additional carbon is removed from the atmosphere, and split roughly equally between the land and the ocean. However, this leaves almost half of the CO₂ emitted from fossil fuel combustion in the atmosphere. It’s this remaining CO₂ that is driving global warming.

Figure 2. Changes in the global carbon cycle from 1850 to 2014. Positive changes (above the horizontal zero line) show carbon added to the atmosphere and negative changes (below the line) show how this carbon is then distributed among the ocean, land and atmosphere.
Adapted from Le Quéré et al. 2015, data from CDIAC/NOAA-ESRL/GCP/Joos et al. 2013/Khatiwala et al. 2013.

Although Australia’s land sector has absorbed more carbon than it has emitted over the past decade or two, this has been overshadowed by our domestic fossil fuel emissions and those from our exported fossil fuels. These are roughly 6.5 times greater than the uptake of carbon by Australian landscapes.

Under international carbon accounting protocols, emissions are assigned to the country that burns the fossil fuels. However, many Australians are becoming increasing concerned about the ethics associated with exploiting our fossil fuels, no matter where they are burned.

In short, we’ve got a big problem that requires a global response, which includes a strong commitment from Australia.

Falling short of our commitment

Last December, Australia joined the rest of the world in pledging to do everything possible to limit global warming to no more than 2°C above pre-industrial levels, and furthermore to pursue efforts to limit the increase to 1.5°C. Yet Australia lacks a robust, credible long-term plan to cut Australia’s CO₂ emissions from fossil fuel combustion.

Current climate change policies and practices in Australia allow for the use of land carbon “offsets” – that is, carbon taken up by land systems can be used to offset or subtract from fossil fuel emissions. For example, the government’s Emissions Reduction Fund (ERF) provides financial incentives for organisations or individuals to adopt new practices or technologies that reduce or sequester greenhouse gas emissions.

Currently, vegetation (land system) projects represent the majority of ERF-accepted projects (185 out of 348). And yet, while storing carbon on land can be useful, it must be additional to, and not instead of, reducing fossil fuel emissions. Moreover, numerous critiques have questioned the effectiveness of the ERF.

Problems of scale

We also have a problem of scale. Reducing emissions through land carbon methods could save up to 38 billion tonnes of carbon globally by 2050 if combined with sustainable land management practices. By comparison, global carbon emissions from fossil fuel combustion are currently around 10 billion tonnes per year.

If this rate is continued, total fossil fuel emissions from 2015 to 2050 will be about 360 billion tonnes – nearly 10 times larger than the maximum estimated biological carbon sequestration of 38 billion tonnes over the same period.

It is now virtually certain that the carbon budget (the amount of carbon that can be produced while keeping warming below a certain level) will be exceeded. To meet the Paris 1.5°C aspirational target (and probably to meet the 2°C target) will require the use of negative emission technologies throughout the second half of the century.

However, no proposed negative emission technology has yet been proven to be feasible technologically at large scale and at reasonable cost, so this approach remains an in-principle option only. For effective climate action, the emphasis must remain on reducing emissions from fossil fuel combustion.

Using land carbon to “offset” our fossil fuel emissions is ultimately a smokescreen for real climate action.

Our thanks to Jacqui Fenwick for co-authoring this article and the report.

The Conversation

Martin Rice, Head of Research, The Climate Council of Australia and Honorary Associate, Department of Environmental Sciences and Will Steffen, Adjunct Professor, Fenner School of Environment and Society, Australian National University

This article was originally published on The Conversation. Read the original article.

Carbon capture and storage is unlikely to save coal in the long run


Gary Ellem, University of Newcastle

As the world moves to combat climate change, it’s increasingly doubtful that coal will continue to be a viable energy source, because of its high greenhouse gas emissions. But coal played a vital role in the Industrial Revolution and continues to fuel some of the world’s largest economies. This series looks at coal’s past, present and uncertain future.

Coal is the greatest contributor to climate change of all our energy sources. This means that if the world acts to limit global warming to well below 2℃, coal will likely be constrained – unless its greenhouse gas emissions can be removed.

One of the great hopes of the industry is carbon capture and storage (CCS), a way to burn coal, remove the carbon dioxide (CO₂) emissions and store it safely away from the atmosphere. While there have been several breakthroughs, the technology remains expensive.

Advances in energy technologies mean that adding CCS doesn’t just need to work; it needs to work at a lower cost than its growing legion of competitors. And while the alternatives are good news for avoiding dangerous climate change, it’s a substantial challenge for the coal industry.

Capturing carbon

The current range of CCS technologies can be grouped into “pre-combustion” and “post-combustion” methods.

Pre-combustion methods typically react the carbon in the fuel with high-pressure steam to make hydrogen CO₂. The CO₂ is then separated (captured) from the hydrogen before the hydrogen is burned in the power station to make energy, with the only emissions being water vapour.

Post-combustion technologies try to capture the carbon after it has been burned and becomes CO₂. If the fuel is burned in air, then the CO₂ needs to be separated from the exhaust gas stream which, like air, is mostly composed of nitrogen gas. This is usually done by passing the gas stream through a liquid that dissolves the CO₂ but not the nitrogen.

Another technique, called “oxyfuelling”, separates oxygen out of the air and then uses it to burn the fuel in an atmosphere of oxygen and recycled CO₂. The exhaust gas stream from this process is close enough to pure CO₂ that it can be sent directly to the storage process.

Several options have been explored for storing the carbon. These include the deep ocean, depleted oil and gas wells, deep saline aquifers, as manufactured mineralised carbonate rock, or as naturally mineralised carbonate by injection into basalt reservoirs.

Regardless of the technique, the outcomes for coal combustion are similar. The amount of emissions is reduced by 80-100%, while the cost of coal-fired electricity generation increases by at least the same amount.

These costs come from building the capture plant, CO₂ transport pipelines and the sequestration plant. More than double the amount of coal must be burned to make up for the energy cost of the CCS process itself.

When CCS was first considered as an emissions solution, competition from renewables, such as solar and wind, was weak. Costs were high and production volumes were negligible.

How cheap?

In the 1990s, many believed that renewables (other than existing hydro, geothermal and biomass for heating) might never be able to replace coal cheaply. The future of energy was going to be a centralised grid, rather than the distributed power models being discussed today, and there were only two widely backed horses in the technology race: CCS and nuclear.

But the early part of this century has seen an energy revolution in both renewables and fossil fuels. Among renewables, solar and wind have both taken enormous strides in reducing production costs and building manufacturing scale.

For fossil fuels, the expansion in gas pipeline infrastructure, the development of liquefied natural gas (LNG) shipping and the growth of both conventional and unconventional gas production have encouraged fuel switching from coal in European and US markets in particular.

Trying to compare the costs of different types of electricity can be tricky. Power stations require capital to build and have heavy financing, operational and decommissioning costs. Nuclear and fossil fuel power stations also have to buy fuel.

Analysts use the term “levelised cost of electricity (LCOE)” to aggregate and describe this combination of factors for different methods of electricity generation.

A significant challenge for coal and CCS is that the LCOE for wind and solar at a comparable scale is already competitive with coal generation in many places. This is because the cost of manufacturing has fallen as production has increased.

While this seems not to bode well for coal and CCS, there’s a caveat: a coal with CCS power station makes power when the sun doesn’t shine and the wind doesn’t blow.

It’s easier for wind and solar to compete when traditional fossil fuel power stations are there to back them up, but not so easy when renewables become dominant generators and the cost of storage needs to be taken into account to ensure a consistent supply.

A game changer?

That was until batteries came along and offered the ability to store renewable energy for when the sun doesn’t shine. There is considerable hype around the entry of the Tesla Powerwall into the home electricity market.

But that is only one of numerous home battery solutions from the likes of Samsung, LG, Bosch, Panasonic, Enphase and others. All are designed to store excess solar power for use at night.

The emerging breakthrough of these products is the price, which is bringing batteries into the realm of competition with centralised electricity generation.

While a battery won’t take your family entirely off-grid at first, such batteries mean most suburban households can become largely energy-independent. They need only top up from the grid now and then when a run of cloudy days comes along during the shorter days of winter.

In the longer term, there’s a clear pathway for most homes to disconnect completely from the grid, should battery prices continue to fall.

Why are batteries a threat?

The reason that batteries can compete with centralised generation is because the cost of transmission and distribution from a coal-fired power station to your home is considerable.

These costs are not normally considered in the LCOE calculations, because it is assumed that all power generators have access to the same, centralised electricity grid.

But a battery in your home means that these costs are largely avoided. That makes home energy generation and storage much more competitive with traditional power generation in the longer term.

For developing nations without a strong centralised grid it also means that energy systems can be built incrementally, without large investments in infrastructure.

This is an ill wind for the competitive future of CCS, which depends on the centralised generation model and a lack of low-cost competitors to stay viable.

That doesn’t mean the coal industry should give up on CCS. Having a range of options for a low-emission future is a good thing. Affordable energy is at the heart of our modern civilisation and standards of living.

CCS may also lay the foundations for Bioenergy with Carbon Capture and Storage (BECCS), one of the few (albeit expensive) technologies with the potential to recoup significant amounts of CO₂ from the atmosphere. But this points to a renewable biomass future, not a coal future.

The odds that CCS will keep coal alive as an industry into the future are getting longer each year.

What we are seeing is the start of the great transition from fossil fuel mining to manufacturing as the basis for our energy systems. It’s not dominant yet, but you would be starting to get very nervous if you were betting against it.

The Conversation

Gary Ellem, Conjoint Academic in Sustainability, University of Newcastle

This article was originally published on The Conversation. Read the original article.

Storage can replace gas in our electricity networks and boost renewables


Dylan McConnell, University of Melbourne

Energy storage could replace peak gas in our electricity network. That’s the finding of a study that my colleagues and I recently published in the Journal of Applied Energy.

Energy storage is often considered the holy grail of the electricity sector. Tesla’s Powerwall home battery system, for instance, allows households to store energy from solar panels, to be used when the sun isn’t shining. It is seen as a vital piece of the puzzle in a future with more renewable energy.

Storage is great for households, but could also be as important in the wider electricity network. Here’s how it could work.

Volatile prices

Generators or power stations sell their electricity on a wholesale market (in eastern Australia this is the National Electricity Market or NEM). From there it is passed onto households and businesses by retailers at retail prices. The wholesale price is a significant factor in the cost of electricity (other factors include poles and wires).

The wholesale price varies throughout the day – sometimes quite considerably, as you can see in the chart below from Queensland. In times of peak demand, prices can skyrocket to 300-400 times the average price.

Half-hourly wholesale electricity prices in Queensland, at the beginning of this year. The average price for the full 2014-2015 financial year was about $50/MWh.
(Author provided, data from AEMO)

This volatility is largely a result of physics: generators have to match demand instantaneously, because electrical energy can’t directly be stored.

People don’t use electricity equally throughout the day. Usually electricity use is concentrated at the end of the day, or on the very hottest day of summer when people fire up their air conditioners.

Electricity networks are typically set up to meet the maximum possible peak demand. They meet this demand with flexible generators such as open cycle gas turbines (which are quick to fire up and shut down, unlike generators such as coal-fired power stations). Such “peak” gas generators are typically used less than 5% of the time.

Load duration curve for the National Electricity Market in the 2008-09 financial year. Curve illustrates the percentage of time that the system is at or above a particular demand level. A large amount of capacity is required for small time periods throughout the year.
Author provided, data from AEMO

These rapid variations in energy demand, along with outages of generators or transmission lines and generator bidding behaviour on the market, can result in highly volatile prices. This is where storage can play a role.

Energy can be stored as chemical energy (in the case of batteries), or in other ways such as gravitational potential energy (in the case of pumped hydro), to be used later to generate electricity when convenient.

These electricity storage technologies can also provide peak capacity. In our paper, we found that this was the main value of energy storage. In fact, peak capacity potential may turn out to offer greater value than other options for meeting peak demand.

Surprisingly, we found this value wasn’t affected by energy losses involved in storage (not all energy is recovered when released from storage).

Powering up with storage and renewables

Due to its high flexibility, gas is often considered to be an ideal partner for renewable energy, because it can pick up the slack when the sun isn’t shining or the wind isn’t blowing.

But as the share of renewable energy continues to expand, large-scale electricity storage offers a promising alternative to gas.

In fact, a study by the Australian Energy Market Operator suggested that significant energy storage was crucial to a 100% renewable energy system, in order to minimise costs while maintaining reliability and security standards.

Our research found that storage actually has a competitive advantage over gas when it comes to meeting peak demand. While both can provide peak capacity, storage can also gain extra revenue by taking advantage of smaller price differences that occur on a more frequent (such as daily) basis. When taking this into account, storage may already be cheaper than gas in meeting peak demand. New reports from the US estimate batteries could replace gas in 3-5 years.

Relative costs of providing capacity from an open cycle gas turbine (OCGT) and pumped hydro electric storage (PHES). The right most bar shows the cost of capacity when the revenue from daily arbitrage is taken into account.
(Author provided)

Australia’s electricity system is currently oversupplied with capacity to generate electricity – by around 37%. As such, there appears to be no need for new capacity for the foreseeable future.

However, there may be demand for new storage capacity if older generators are withdrawn from the electricity network. Alternatively, the outlook for storage may improve as renewable energy generation is increased to meet mandated targets.

Increasing penetration of variable renewable energy will increase revenues for storage. In times of high generation output there will be more opportunities for storage owners to shop around for lower prices. This fluctuation between prices is already happening in South Australia.

In this way, storage and renewables may prove mutually beneficial.

The Conversation

Dylan McConnell, Research Fellow, Melbourne Energy Institute, University of Melbourne

This article was originally published on The Conversation. Read the original article.