Vitality economics of the zero-carbon grid


Can renewables be a major player in the energy supply? E&T looks at how to make the plans add up.

With some notable exceptions, governments around the world are moving to support the idea of clamping down on greenhouse gas emissions by making major changes to the biggest single source: the energy grid. The main question is whether it is feasible to move to a net-zero-emission grid in three decades – a target proposed by the Intergovernmental Panel on Climate Change to bring warming under the 2°C threshold seen as key to preventing the worst outcomes.

One part of that analysis is how much the use of generation technologies that avoid the use of fossil fuels will clamp down on greenhouse gas emissions over their entire lifecycle. A solar panel may produce little to no carbon dioxide when mounted on a rooftop, but its manufacture will likely produce a significant amount. And its use may rely on other technologies that themselves produce greenhouse gases during their operation, sometimes in ways that seem at first to be counterintuitive.

It is a similar issue to the one we encounter when looking at the lifetime emissions of different motor vehicles, where the reliance of electric vehicles (EVs) on large batteries, which are expensive to produce both in terms of money and emissions, narrows the gap between them and efficient, lighter designs based on internal-combustion engines.

The high temperatures needed to purify silicon for solar photovoltaic (PVs) panels, for example, increase the emissions from production relative to a technology such as wind. However, there are potentially cheaper technologies that do not need such high temperatures or as much silicon area. An example is the concentrator solar cell, which trades active area for large glass lenses while delivering the ability to absorb more of the Sun’s photons. Another lies in the novel organic thin-film chemistries that need less heat and raw-materials refinement to produce.

The big differences in PV technologies, as well as whether fossil fuels were consumed in their production, leads to a wide range of greenhouse-gas estimations. For example, in a 2013 study by Roberto Turconi and colleagues working at the Technical University of Denmark, carbon-dioxide emissions ranged from 20kgCO2/kWh to 200kgCO2/kWh. The relative efficiency of PV technologies complicates the calculations as to how effective they are in reducing emissions overall. Concentrator plants are more complex to build but use less active PV area than flat panels and can use more of the Sun’s output over a typical day.

According to estimates from groups such as the World Energy Council, even in the high-cost scenarios when measured on a kilogram of carbon dioxide per tonne basis, PVs are not much more expensive to build and install than a modern gas-fired power station based on technologies such as selective catalytic reduction that filter out nitric oxide and other secondary pollutants. Though the gas-fired power station has better overall emissions than coal, this difference is nowhere near as dramatic as that between gas and any of the renewables, even PVs at the top end of the production scale. Whereas a PV plant could lead to total production of 200kgCO2/kWh from its manufacture and installation amortised across its projected 30-year lifetime, the very low emissions from the generation phase means the total is dwarfed by the emissions from a fossil-fuel plant. Gas winds up in a range of 400kgCO2/kWh to 1,000kgCO2/kWh.  

Biomass presents a more complex picture for lifecycle emissions. Proponents use the argument that it is in effect, like biofuel for vehicles, a net-zero technology because the trees that act as its feedstock are renewable and absorb carbon dioxide while they grow. Burning the feedstock simply releases that temporarily stored carbon. UK operator Drax even claims it will be a carbon-negative business by 2030 through the use of carbon capture and storage. Although it releases carbon dioxide during generation, the chief advantage that biomass has over the other renewables is that it is, like natural gas, a ‘dispatchable’ generation technology that can be used to ride out spikes in demand that renewables and nuclear generation cannot meet directly. This is a consideration that is likely to mean biomass remains in the energy mix into the future.

Before zero-carbon became a desirable target, nations such as Australia considered a ‘clean energy’ option for 2040 to have about half of generating capacity coming from gas and biomass, 40 per cent from wind and other renewables, with the balance made up by coal as those plants were gradually wound down. A 2008 report for the Australian parliament described gas as a “change agent”: a source that would provide the capacity to ride out peaks as the country built up its renewables capacity. As biomass usage expands, it may take over that role from gas for some countries as a way of preserving dispatchable generation, and use carbon-credit accounting to justify the decision.

Renewables such as solar and wind, by contrast, frequently hit situations where they produce far too much power for the grid to absorb in real-time before paring back output in the face of demand spikes. In California, where solar has made strong progress but still accounts for less than 20 per cent of generating capacity overall, its output is already being curtailed in the summer months in a pattern that has been repeated across the sunnier states of the US.

The California Independent System Operator, which oversees the state’s electricity grid, coined the term ‘duck curve’ to describe the effect. The increasingly fat stomach of the duck’s outline that appears on the chart of power demand through the average day represents the number of megawatts that the grid cannot use in a period of a few hours after midday, when output is at its peak, versus the early evening peak as people return home. In April 2018, solar operators in California had to divert some 95GWh of electricity from making it onto the grid. It would have been enough to power 1.5 million homes for a day.

Renewables suffer from another issue. Being highly distributed and supplying power through independently controlled electronic inverters, without careful management, they make grids more unstable. Because coal and gas-fired power stations use speed-controlled turbines with a high degree of inertia, they are pretty reliable at providing AC with a voltage and frequency that stays within a tight range. Coordinated frequency control over the inverters can help deal with the problem.

In practice, both issues are likely to pass to another alternative to dispatchable biomass and gas generation: energy storage.

One storage technology is already in place and proven to be effective around the world because of another energy source that does not cope well with peak demand: nuclear. Lurking inside a Snowdonia mountain, the Dinorwig pumped-storage reservoir is the UK’s most famous example of what was to have been a larger group built to support a transition to nuclear in the 1970s and 1980s. In the event, few facilities were built in the UK though other countries invested far more. In the period when it favoured nuclear generation, Japan pushed ahead, installing 28GW of available power output, slightly behind China’s 32GW. According to the International Renewable Energy Agency, pumped hydro represented 96 per cent of electricity storage available worldwide in 2017, with an estimated 4.5TWh of capacity, though it is difficult to obtain hard numbers as many projects have not published their effective capacity, just their peak output capability.

As with renewables, the direct lifecycle emissions penalty of storage is, for the most part, loaded into the production and installation phases, with the possible exception of the various forms of battery storage where the need to replace materials once cells have exhausted their useful life represents part of the ongoing cost.

However, the picture for lifecycle emissions from a grid that uses storage is far more complex than for the generation technologies. How they are used has turned out in models to be as important as how much carbon dioxide their manufacture and operation produce directly.

Privatised national energy markets that have sprung up in the place of direct state control in many countries, but which employ sometimes arcane rules of engagement, complicate the development and management of grids as the share of low-carbon sources increases. Traditionally, storage operators faced a problem in that they could not take part in energy trading directly, which tends to force the technology into being part of generating capacity, though this problem has been resolving in various countries around the world.

For example, since 2017, a lithium-ion battery installation in South Australia has been able to bid as much as 90 per cent of its capacity, now close to 200MWh, directly into the energy market. This lets it perform load shifting over three hours at up to 30MW. The rest of its power output is reserved for maintaining grid stability – 70MW for up to 10 minutes – a capability that was used shortly after it was completed: the Hornsdale Power Reserve injected several megawatts into the grid when a coal plant tripped off, maintaining grid frequency while a backup gas plant moved to respond with more substantial backup.

Although its name implies a focus on grid stability, National Grid’s Enhanced Frequency Response programme also lets operators perform energy trading.

Even with trading in place, the financial incentives that drive energy markets can lead to seemingly perverse outcomes when it comes to estimating the value of storage. A model published by Eric Hittinger of the Rochester Institute of Technology and Inês Azevedo of Carnegie Mellon University in 2017, showed how arbitrage for higher profitability combined with storage in a grid that has not fully transitioned to carbon-free sources can lead to unanticipated carbon dioxide emissions.

The researchers used simulations based on recorded usage data across the 48 contiguous states of the USA to determine how storage operators might maximise revenues to charge and then sell electricity at different times. Cheap coal-fired power stations could wind up charging the storage facilities over long periods before the storage discharges during peaks, displacing slightly cleaner technologies that are often used for peaking capacity, such as gas or biomass. Governments could address the problem by restricting the ability to charge from the grid and only use, for example, co-located renewables or apply a penalty to grid charging if renewable sources are not available.

A second issue outlined by Hittinger and Azevedo, among others, was the effect of round-trip efficiency on profitability, which could lead to operators making less environmentally beneficial choices. It is more profitable, for example, for an operator to sell electricity immediately because they will collect 100 per cent of the joules supplied. If the energy is stored for later, they may command a higher spot price but will only realise maybe 75 per cent of the plant’s original output. A second set of simulations performed by Hittinger with Rochester colleague Laura Arciniegas showed that this can happen even in relatively solar-rich California.

Degradation plays a role in controlling the decisions made by operators. Studies in Germany and Italy demonstrated how battery-backup operators may hold back from entering the market because the degradation their installations suffer cuts too far into predicted profitability. A key issue is the waiting time between submitting a bid for a predicted peak and discharge if the bid is accepted. However, frequency-only operation can cause issues with cell lifetime because they are constantly on standby that may encourage operators to switch portions between different applications in order to perform maintenance and rebalancing.

Though it is possible for storage to lead to higher than expected emissions in a transition to net-zero, there are arguments for operators to see storage as a path to higher profits. Generated electricity only has a value if you can sell it in the first place. That cannot happen during the periods when curtailment is being applied. If curtailment is in place, the inability to sell a large chunk of their output makes it harder for new operators to enter the market because their payback time stretches out too far for investors and, in turn, financing fizzles out.

Work by Maryam Arbabzadeh of the Center for Sustainable Systems at the University of Michigan at Ann Arbor and colleagues showed it is possible to use storage to cut overall emissions by as much as 90 per cent compared to a zero-renewables grid. Without storage, the reduction would be 72 per cent with one-third of the generation from the simulated 60GW of installed renewables being curtailed. Curtailment still occurred but this fell to less than 10 per cent. In Texas, however, the gains were lower because curtailment is less likely there and the emissions reductions came from moving generation from coal to gas.

The simulations performed so far imply some level of tax or charge needs to be levied on any carbon-intensive technology, though the level of that charge might be hard to set. Though there are clear advantages in terms of emissions control in moving away from fossil fuels and moving to generation technologies that lack their dispatchability, the need to include storage in the equation greatly complicates the calculations. Even after producing numerous models, researchers remain uncertain as to which market and incentive structures will deliver the greatest overall benefit.

Governments have signalled they are willing to make the changes that will help drive fossil fuels out of generation but it remains unclear how well the laws they write will encourage a move to zero-carbon energy within 30 years and whether unanticipated flaws will slow the process down.


Storage choices

If we assume that storage and renewables go together, the question is which storage technologies show the best prospect of delivering a net-zero future.

Pumped hydro has the strongest argument for large-scale storage. It is well understood, the installations are long-lived, with an estimated operational lifetime of more than half a century, and require few exotic materials. On a financial cost basis, even though battery prices will likely fall in the future and construction will not get much cheaper for hydro if at all, industry group IRENA projects an order of magnitude advantage over batteries beyond 2030.

There is a catch with pumped hydro. With an energy density three orders of magnitude lower than lithium-ion batteries and a conversion efficiency that is about 10 per cent behind the batteries, it is a storage technology that needs a lot of space as well as a helping hand from geography: mainly a height difference between two potential lakebeds. Despite that, work by a team led by Professor Andrew Blakers at the Australian National University claimed there are half a million locations around the world that would be suitable candidates for pumped-hydro installations of various sizes. However, the need to flood lakebeds to get enough water into the system and the effects on wildlife will lead to pushback.

With an energy density around three times better than pumped hydro, compressed air may provide a more socially acceptable choice. It is a natural fit for dry underground spaces such as salt caverns and it can use the same kind of turbines as those used in gas-fired generators. One option for countries concerned about effects on the landscape is a more experimental design that lets the compressed-air balloons sink into the sea as they store more of the energy. One downside is that the most mature technology relies on gas to help drive the turbines as the air is released for generation.

For storage that needs to be close to the point of use and for quick reactions, batteries currently have the lowest requirement for space and may ultimately become a leading contender because of countless ‘behind the meter’ installations in homes and offices as well as utility-scale facilities built for both frequency control and time-shifting.

Private-equity funds such as Gore Street have invested more heavily in battery operations in the short term – largely in response to a greater focus on frequency control rather than time-shifting energy from renewables. But the high costs of materials and construction mean building battery storage at the scale needed for widespread time-shifting seems unlikely. Cheaper and potentially less flammable solid-state battery chemistries and flow batteries may yet tip the balance, though all these technologies have bigger problems of materials degradation with use that the kinetic technologies like hydro and compressed air do not.

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