Variable truths on wind
The debate over how to deal with the variable energy output from wind turbines continues to rumble on. Some say that, when wind availability is low, there will be a need for extensive back up from conventional plant to maintain grid reliability. However, this backup may already exist: we have a lot of gas-fired capacity, much of which is used regularly, on a daily basis, to balance variations in conventional supply and in demand. Balancing wind variations means this will just have to be used a few times more often each year, adding a small cost penalty and undermining the carbon savings from using wind very slightly. But some say we will need much more that that. A report from Parsons Brinckerhoff (PB) claims that “the current mix of generating plant will be unable to ensure reliable electricity supply with significantly more than 10 GW of wind capacity. For larger wind capacity to be managed successfully, up to 10 GW of fast response generating plant or controllable load will be needed to balance the electricity system”.
“Controllable load” includes the idea of having interactive smart grids which can switch off some devices when demand is high or renewable supplies are low.
However even if that option is available, some say that, with more wind on the grid, to meet peak demand, we will still need more backup plants than we have. By contrast, wind energy consultant David Milborrow claims we have enough, and that some fossil-fired plants can actually be retired when wind capacity is added. That depends on the “capacity credit” of wind – how much of the wind plant capacity can be relied on statistically to meet peak demand. Milborrow puts the capacity credit of wind at around 30% with low levels wind on the grid, falling to 15% at high levels (at say 40% wind on the grid). That indicates how much fossil plant can be replaced.
PB see it very differently: “A high penetration of intermittent renewable generation drastically reduces the baseload regime, undermining the economic case for more-efficient plant types with lower carbon emissions.”
Milborow admits that balancing wind variations has the effect of reducing the load factor for thermal plant, but says that this only costs ~£2.5/MWh at 20% wind, or ~ £6/MWh at 40%. PB will have none of this: “Very high early penetration of wind generation is likely to have adverse effects on the rest of the generating fleet, undermining the benefits of an increased contribution of renewable electricity.”
PB also seems to slam the door on a possible way out, importing power from continental Europe, the wider footprint then helping to balance variations across a much larger geographical area. It says: “Electricity interconnection with mainland Europe would offer some fast-response capability, but would be unlikely to offer predictable support. Without additional fast-response balancing facilities, significant numbers of UK electricity consumers could regularly experience interruptions or a drop in voltage.”
Addressing the interconnector issue, among others, TradeWind, a European project funded under the EU’s Intelligent Energy-Europe Programme, looked at the maximal and reliable integration of wind power in Trans European power markets. It used European wind power time series to calculate the effect of geographical aggregation on wind’s contribution to generation. And it looked ahead to a very large future programme, with its 2020 Medium scenario involving 200 GW – a 12% pan-EU wind power penetration. It found that aggregating wind energy production from multiple countries strongly increased the capacity credit.
It also noted that “load” and wind energy are positively correlated – improving the capacity factor – the degree to which energy output matches energy demand. For the 2020 Medium scenario the countries studied showed an average annual wind capacity factor of 23–25 %, rising to 30–40 %, when considering power production during the 100 highest peak load situations – in almost all the cases studied, it was found that wind generation produces more than average during peak load hours.
Given that “the effect of windpower aggregation is the strongest when wind power is shared between all European countries”, cross-EU grid links were seen as vital. If no wind energy is exchanged between European countries, the capacity credit in Europe is 8%, which corresponds to only 16 GW for the assumed 200 GW installed capacity. But since “the wider the countries are geographically distributed, the higher the resulting capacity credit” if Europe is calculated as one wind energy production system and wind energy is distributed across many countries according to individual load profiles, the capacity credit almost doubles to a level of 14%, which it says corresponds to approximately 27 GW of firm power in the system.
Clearly then, with very large wind programmes you do get diminishing returns and need more backup, but it seems that can be offset to some extent by wider interconnectivity – the supergrid idea, linking up renewables sources across the EU.
That is already underway. The UK’s National Grid has agreed with its Norwegian counterpart Statnett to draw up proposals for a £1 bn grid-interconnector grid link-up, to be funded on a 50:50 basis, which could help solve the problem of winds intermittency, given that Norwegian hydro could act as back-up for the UK, in return for electricity from the UK on windy days. As yet no UK landfall site has been indicated, but it could include connection nodes along the route with spurs taking power from offshore wind farms and become the backbone of a new North Sea “supergrid”: the UK and eight other North West EU countries have now agreed to explore interconnector links across the North sea and Irish sea. National Grid said: “Greater interconnection with Europe will be an important tool to help us balance the system with large quantities of variable wind generation in the UK.”
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