Guest post by Dr Phillip Bratby who reviews the EDF R&D Paper ‘Technical and Economic Analysis of the European Electricity System with 60% RES, by Alain Burtin and Vera Silva, 17 June 2015’
Dr Phillip Bratby BSc, PhD, ARCS, MNucI has spent most of his career in the civil nuclear industry, working in the areas of the safety and operation of water reactors. Before retirement he was an in independent energy consultant.
Download the EDF report Technical and Economic Analysis of the European Electricity System with 60% RES from Energy Post.
The EU has a strategy to increase the amount of electricity that will be generated from renewable energy sources (RES) to 55% by 2050. About 57% of the RES in Europe is currently hydro and there is little opportunity to expand hydro. Thus most of the projected increase in RES, which constitutes about 10% of electricity generation in 2014, will be from wind and solar PV, reaching 20% in 2020 and 30% in 2030. The EDF paper examined the future impacts, challenges and changes to the power system of increased wind and solar PV renewable energy sources (variable RES) on the European electricity grid…..
The paper examined a High RES scenario taken from the EU Energy Roadmap 2011. Assumptions concerning low carbon generation (RES and nuclear) were taken from the Roadmap, with 60% of electricity coming from RES by 2030, of which 40% would be variable RES.
In this review I have not examined the financial implications of the high RES scenario.
Analysis and Results
The intermittent (variable and uncertain) and non-dispatchable output of wind and solar PV are well understood. Using 30 years of weather data across Europe, the EDF paper studied the impact of 60% RES (40% variable RES) generation across Europe at differing timescales, from hourly, to seasonal and to inter-annual.
As expected, this showed for wind power that the intermittency is greatest at a local level, but is reduced at regional, national and European level.
Seasonal variability is such that load factors average about 25% but vary from 15% in summer to 30% in winter. Even at a European level, wind regimes show a strong correlation and there remains considerable variability. For example, with 280GW installed wind capacity across Europe, the average daily wind generation in winter varies between about 40GW and 170GW (a range of about 130GW, incorrectly labelled 90GW in the graph below).
Similar results were obtained for solar PV, with less variability as the geographical area is increased from a solar farm to a county, to a region and to a country.
With a total European installed capacity of 220GW, the average load factor is 13%, the daily variability is less than for wind power, and the load factors are 5% in winter and 20% in summer.
It was concluded that the integration of wind and solar PV poses two challenges:
- managing intermittency at the local distribution network level (not part of the study);
- handling variability at a fully developed Europe-wide interconnected distribution and transmission system (the handling of variable RES within national distribution and transmission systems is not part of the study).
Currently, variable RES (wind and solar PV) have priority access to the system, and the volume of production has so far only had a marginal impact on the system. However, the large scale introduction of variable RES will have a marked impact on the structure and operation of the electricity system at all levels. The paper examined the infrastructure requirements (inter-connectors, reinforcements), on existing generators, on the flexibility (storage, stability and demand) and costs/profits in order to accommodate 40% variable RES (wind and solar PV).
For the study of the high RES EU scenario of 60% renewable electricity by 2030 it was assumed that 20% of the electricity would come from hydro and biomass and 40% of the electricity would come from variable RES (wind and solar PV). The remaining 40% would come from nuclear and fossil fuels, with a nuclear capacity of 90GW, as given by the EU Energy Roadmap 2011. The EDF paper examined the feasibility of integrating this level of variable RES into the system and what the impact on fossil fuel generators would be.
It was assumed that variable RES across Europe would be distributed to prioritise best usage of the resource, whilst accommodating land usage and other social constraints. Thus onshore wind is spread across the whole of Europe, with offshore wind mainly in the north and solar PV mainly in the south. Interconnector developments were assumed necessary to transfer production to demand centres and reduce back-up requirements.
The study recognised that because wind and solar PV are variable and difficult to forecast, because electricity cannot easily be stored and because generation has to be balanced with demand at all time, the integration of a high proportion of variable RES will pose a number of challenges across the entire electrical system. A variety of computation tools were used to perform system-wide studies.
In the study it was assumed that in 2030 total demand is 3600TWh/year with a peak demand of 600GW.
The 40% of electricity (1440TWh/year) from 700GW of variable RES is provided by:
220GW of solar PV with a load factor of 13%
280GW of onshore wind with a load factor of 22%
205GW of offshore wind with a load factor of 36%
20% of the electricity (720TWh/year) is from hydro, biomass and geothermal.
40% of the electricity (1440TWh/year) is from fossil fuels and nuclear.
The results of the study showed the following:
1. Variable RES contribute to providing electricity but make a minor contribution to capacity.
2. 700GW of variable RES displace 160GW of baseload but increase backup by 60GW. The 700GW of variable RES thus lead to reduction in conventional capacity of only 100GW. The reduction of 100GW is solely due to wind since solar PV displaces 20GW of baseload and requires 20GW of backup (the capacity credit of solar PV is zero). Thus the capacity credit of wind is 20%, a figure which falls as wind capacity increases.
3. Nuclear capacity is assumed to remain unchanged at 90GW, as given by the EU Energy Roadmap 2011. Coal capacity is reduced by 170GW from 250GW to 80GW. CCGT is increased by 15GW from 70GW to 85GW. OCGT is increased by 65GW from 35GW to 100GW.
4. There will be periods (unspecified) when variable RES exceeds demand and curtailment is required in order to maintain generation/demand balance and to allow the provision of reserves and ancillary services required to ensure the security of the system.
5. Operation of the electricity system will be challenging, with traditional flexible sources no longer available and limited providers of ancillary services.
6. CO2 emissions are significantly reduced (1Gt/year) compared to a scenario without variable RES. However this figure is derived simply from the net reduction in fossil fuel usage from 40% of generation to 20% of generation (a reduction in coal usage but an increase in gas usage) and does not take account of the carbon footprint of the variable RES and of the infrastructure developments. The impact on backup emissions is low because backup is mainly provided by dispatchable hydro. There is limited usage of the OCGT for peaking, with operation only being necessary for a few hours a year. Coal usage continues at a much reduced level, but is not eliminated because the price of CO2 is not high enough to remove all coal plants. Further reductions of emissions would occur if the coal usage were completely replaced by gas usage.
7. Variable RES increase the system variability that needs to be managed by conventional generators. The net demand (defined as the real demand less the variable RES generation) is much more variable than the real demand, consisting of more frequent large variations in net demand. Upward hourly variations larger than 20GW and downward variations larger than 10GW increase by 50% and extreme hourly variations of >70GW now occur. Real daily demand varies by between 100 to 200GW, whereas net demand varies by over 400GW.
8. The variable RES are dependent on weather conditions such that the electricity generated can vary by 5TWh between the same day in different years (equivalent to 200GW capacity). The demand variation due to temperature conditions is only 2TWh (equivalent to 80GW) in winter and 0.7TWH (equivalent to 30GW) in summer. Increased load balancing is necessary to cope with this increased sensitivity to weather conditions and there will need to be a significant increase in operating margins.
9. Improved weather forecasting would reduce the operating margins and reserves needed to cover the uncertainty in variable RES generation. An integrated system across Europe would reduce the uncertainty by a factor two.
10. An island grid, such as that of the UK, would benefit from the further interconnectors, the reduced uncertainty of an integrated grid and increased security margins. However, with HVDC interconnectors, the management of frequency control would pose particular difficulties for the UK at 40% variable RES. An operating reserve of about 6GW would be required in the UK at 40% variable RES.
11. The increase of asynchronous generation (an electronically controlled interface between the generator and grid) of variable RES will lead to a reduction in system inertia and thus reduce the robustness of the system to faults. This is of particular concern during periods of low demand.
12. Demand response mechanisms and storage increases only have a small impact on the need for backup capacity, but can contribute to management of the system in terms of frequency control and grid balancing.
1. Regardless of how much variable RES is installed, thermal generation remains necessary in order to ensure system stability and security of supply.
2. Nuclear power is a necessary part of the thermal generation if CO2 emissions reduction targets are to be met.
3. New (unspecified) mechanisms will be needed to manage a large amount (40%) of variable RES, to maintain stability and ensure security of supply.
4. To achieve 60% of Europe’s electricity generation from RES (20% from hydro and biomass and 40% from variable RES (wind and solar PV)), about 500GW capacity in total of thermal (350GW), hydro (120GW) and biomass (30GW) and about 700GW of variable RES capacity will be needed.
5. 700GW of variable RES will result in large variations in daily variable RES production, by up to 50% of European total demand. Extreme hourly variations in net demand (>70GW/hr) will occur, with frequent upward and downward variations of >20GW/hr and >10GW/hr respectively.
6. There will need to be an increase in network infrastructure at local (distribution) , national (transmission) and intra-national (inter-connectors) levels.
7. Demand response mechanisms will need to be developed.
8. The security of supplies will become a more important issue as synchronous generators are replaced by asynchronous generators.
9. Island grids (such as Ireland and the UK, connected to Europe by HVDC interconnectors) will have particular difficulties with frequency control.
10. In order to meet CO2 emissions targets, low carbon conventional generation is needed; increased usage of nuclear power is the best option.