Solar Energy Perspectives - IEA

Chapter 11: Testing the limits
The average capacity demand in regions not suitable for CSP, both hot and humid, and
cold regions, would be at most 65 000 TWh divided by the numbers of hours in a year,
or about 7 400 GW. This suggests that total demand would vary between 5 000 GW and
10 000 GW. Avoiding curtailment from wind during winter nights could thus require
about 5 000 GW of storage capacities (assuming, somewhat implausibly, that all wind
power capacities are in these regions). As is shown below, however, batteries of electric
vehicles and plug-in hybrids can considerably reduce this need, so the extent of largescale
electricity storage is in fact determined by the requirements to respond to demand
peaks.
It is assumed that the overall global demand could reach 10 000 GW at peak time after
sunset, giving no capacity credit to PV and only 10%, (i.e. 1 000 GW), to wind power (in
summer). A mix of base-load plants (geothermal, nuclear, fossil fuels and solid biomass
with CCS), would represent a total capacity of 1 200 GW. Flexible hydropower capacities
would add 1 600 GW. Imports from CSP-suitable areas could represent an additional firm
capacity of 400 GW. Therefore, the total balancing requirement – i.e. the additional
capacity needed to offset variability of renewables – would be up to about 5 800 GW.
Effective demand-side management (DSM) can reduce balancing needs. It would take
advantage of the thermal inertia of many uses of electricity, i.e. the fact that heat exchange
can be relatively slow, so devices that produce or transfer heat or cold can be stopped for
a while without any serious consequence. This inertia will have sharply increased in
50 years by comparison to today, with many heat pumps in buildings and industry, and
better insulated equipment (e.g. fridges or ovens) and buildings. DSM would also take
advantage of the fact that not all electric vehicles need be charged during peak demand.
A cautious assessment of 5% reduction from DSM brings the balancing needs down
to 5 500 GW.
Only a detailed assessment by continent could identify an optimal breakdown between
the two remaining options: gas-fired balancing plants, and storage. Storage capacities are
significant investments, and need to be used on a daily basis. Balancing plants cost less in
investment but more in fuels – and even if run on a mix of solar hydrogen and natural gas,
they would entail CO 2 emissions. They should be used only as extreme peak plants, and
in case of contingencies. The optimal mix depends on the amount of electricity needs to
be time-shifted on a daily basis to better match the demand. For example, 3 000 GW
capacities of balancing plants, running on average 1 000 hours per year, would produce
3 000 TWh per year, of which 2 000 TWh would come from solar hydrogen. The remaining
capacity required to respond to demand peaks would be 2 500 GW (Figure 11.5).
The volume of electricity storage necessary to make the electricity available when needed
would likely be somewhere between 25 TWh and 150 TWh – i.e. from 10 to 60 hours of
storage. If 20 TWh are transferred from one hour to another every day, then the yearly
amount of variable renewable electricity shifted daily would be roughly 7 300 TWh.
Allowing for 20% losses, one may consider 9 125 TWh in and 7 300 TWh out per year.
The same capacities would probably be ample to avoid most PV curtailment during the
sunniest hours, usually peak or mid-peak demand hours, assuming low wind speeds at
those times. In summertime, when PV production is maximum, a significant part of the
storage capacities installed to support wind power will remain unused to store power from
wind generation, and thus available to store PV-generated electricity.
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© OECD/IEA, 2011