The British Wind Energy Association (BWEA) has welcomed, in particular, the findings of a recent report, Managing Variability, published in June 2009. The findings resonate with the conclusions of two other studies of wind power published earlier this year by National Grid, UK, and Helsinki-based Pöyry Energy Consulting. Maria McCaffery, CEO of the BWEA, sees the report as “the final nail in the coffin of intermittency”.
Managing Variability was prepared by energy consultant David Milborrow for four environmental bodies: Greenpeace UK, Friends of the Earth, the Royal Society for the Protection of Birds (RSPB) and WWF-UK.
Milborrow tackles assertions such as “when the wind stops, the lights will go out” and “every MW of wind needs a MW of back-up plant” head on, with a qualitative and quantitative rebuttal – referenced to the UK. There is, the report states, a growing understanding that wind power's variability can and must be managed. “Variability” is arguably a better term than “intermittency” since the latter suggests an on/off or stop/go nature while the wind power situation is more usually “on but varying”.
“There is now widespread agreement among utilities,” Milborrow told Renewable Energy Focus, “that there are no fundamental technical reasons why a high proportion of wind energy cannot be assimilated into the system. Steady growth of wind power worldwide shows that this renewable energy source is now seen as a robust choice for reducing greenhouse gas emissions.”
Focus on the aggregate
The variability of wind power should, in any case, be seen in perspective, Milborrow argues. Wind is almost always blowing in some part of the British Isles and aggregate wind variation over the whole region is much less than the variation evident at individual turbines or wind farms.
It is this aggregate that confronts the grid, not local wind power variation.
In fact, experience shows that aggregate variation in wind power is generally less than the fluctuations in consumer demand that the transmission network sees every day, and we should also remember that the grid has proven robust, even in the face of major shocks such as the loss of a power station. In comparison, the tripping out of a large conventional thermal or nuclear station would be a true and enormous intermittency, beside which wind power fluctuations could be regarded as benign.
Some tools for managing these threats to system stability are already available. In particular, existing provision within the system for short term “spinning” reserves and longer-term back-up currently amounts to about a fifth of peak demand level. Little addition is needed to this, the report contends, while the penetration of wind power into the system remains modest. Even for higher penetrations of wind power, reserves already in place would need boosting by only a few per cent of rated wind plant power, not 100%.
This assumes that system operators rely only on a realistic proportion of the full nominal capacity of available wind farms. In the UK, history suggests that this “capacity credit” should be about 30% at low wind penetrations. Improved estimates of capacity credit, based on growing operational experience, will help trim the need for reserves.
Nevertheless, some costs of rapid response and back-up generation assets must be allowed for, and these will be on a rising curve as wind power penetration progresses beyond about 20%. While periods of low or no wind accentuate this need, at the opposite end of the scale costs also rise at times of high wind, because the amount of the available wind power that can be accepted onto the grid is limited and the supply therefore has to be constrained. Such “constraint costs” are, however, thought unlikely to be substantial until wind is contributing about a quarter of total electricity requirement.
Various means of managing the variability of wind power are outlined in the report. The smoothing effects of aggregation and geographical spread can be dramatic. For example, a study has shown that fluctuations over the entire area of west Denmark are about a quarter of those evident at a single representative wind farm in the territory. Wider dispersion still can be achieved by adding more connections between the UK, France and Ireland, effectively leading to supergrids.
And smoothing can be further augmented by aggregating different types of energy source, including other renewable energy sources. Incorporating tidal energy, for instance, would add a source which, although variable, is highly predictable.
An important way to reduce the need for reserve and back-up capacity is to improve wind forecasting methods. Wind variability is not totally random. With knowledge of wind strength at a particular time, probability comes into play. That is, the wind strength at different times from that nominal time will lie within certain probability limits. These limits can be determined from wind strength statistics extending back several years. This allows forecasters to predict winds on an hour-to-hour basis, so reducing uncertainty for network system operators.
This is important because uncertainty about available wind energy compounds other uncertainties faced by operators, in particular over consumer demand and normal supply fluctuations. Operators must allow for “overall uncertainty” when calculating the required levels of reserve and back-up and their costs. Clearly, these levels rise as wind penetration rises. In the UK, National Grid estimates that, for 40% wind power penetration, its generating costs would rise by 10%.
Ultimately constraint costs will be cut or avoided by augmenting transmission capacity so that peak wind farm outputs can be accepted. The same pertains to the building of large nuclear or thermal plants. While, constraint costs, strictly speaking, are a function less of wind variability than of the location of renewable resources relative to major centres of consumption, they are still additional costs associated with the renewable source and must be allowed for.
Take the case in the UK: it seems likely that, because the best wind is to the north and west while the largest centres of population are in the south, additional north-to-south transmission lines will be needed. The report suggests that the cost for these could be some £4.7 billion.
At wind penetration levels exceeding 25%, the possibility arises that sometimes more wind will be generated than is needed and would be wasted. A small penalty cost will be associated with this “lost” electricity as the fixed costs of the wind plant are spread over fewer units of electricity. Of course, if markets can be found for the surplus, or if it can be stored in some way, perhaps as heat or pumped storage, this loss would be avoided. Further developments in technology and the market should facilitate this.
Storage, if deployed at a viable price, can help facilitate smoothing. Wind power can be stored as heat in space heating and water heating applications. Similarly, electric cars would smooth demand by drawing current at off-peak times during the night. If flow batteries are introduced on any significant scale, these could have a stronger role since power could be fed back to the grid at times of high demand. In principle, electric cars could do this too, thereby providing reserve service at modest cost.
Demand side management
Another mitigating tool for wind power variability will be demand side management (DSM), already widely practised. This can reduce both peak loads and reserve costs. Load management might involve, for instance, turning off interruptible appliances such as refrigerators and space heaters for limited periods at peak demand times. This could be done through local switching units triggered by smart meters, or by using teleswitching from a central control complex. Dynamic demand systems could automatically react to falls in supply frequency caused by high demand. DSM, the report argues, could be an effective tool, reducing extra costs at the 20% wind penetration level by upwards of 10%.
Comparing notes with other countries reveals broadly similar costs of additional reserve across all. In Britain, the costs at 20% wind power penetration are predicted to be below £3 /MWh. Even if domestic electricity prices need to rise to accommodate all the costs associated with variability, David Milborrow believes these increases will be small.
“Calculations for the UK suggest that if wind provides some 22% of electricity by 2020, as modelling for the Government suggests, the rise in domestic electricity prices needed to cover these costs would be just 2%. Increases needed at 40% penetration would still be modest and greater penetrations are still considered feasible.”
This is fortunate since wind appears poised to become a major contributor to the energy mix in Europe, for both environmental and supply security reasons. Denmark alone plans to increase its wind energy penetration to 50% by 2025, relying on electric vehicles and heat pumps to absorb surpluses, plus extensive use of demand side management.
This sort of wind power level, along with ambitious projections for Ireland, Germany, Portugal, Greece and other countries, suggests that assimilation of wind is not expected to be a serious problem. If growth in wind energy were to continue at 25% per annum despite the recession, this would signal that utilities and governments see wind as a viable source of carbon-free electricity. As Milborrow declares:
“Among utilities and other stakeholders, variability is no longer considered an insuperable barrier to large-scale wind exploitation, if it ever was. Wind can displace conventional plant, albeit not on a MW for MW basis.”
Pöyry Energy Consulting in Finland has taken a modelling approach to predicting what the wind energy landscape might look like by 2030 in two countries, the Republic of Ireland and the UK. Its findings included a market dimension, which was outside the scope of David Milborrow’s report mentioned above.
Researchers compiled a history of wind data gathered at 36 actual and potential wind farm locations between 2000 and 2007. More than 2.5 million data points were included in a statistical wind output model. Computerised results were extrapolated forward, allowing for certain anticipated changes until 2030, so that hour-to-hour wind strength projections could be made (National Grid are currently working on a similar model with hourly resolution, but for the year 2020).
The Finnish researchers paid special attention to the extremes of wind energy, arguing that policy makers often focus excessively on averages, so under-estimating the influence of the “tails of the curve”.
Using these wind energy projections and computer models of generating capacity in the British and Irish markets, the research team investigated how prices might evolve in the future. Simulations showed that at higher wind penetrations, hour-by-hour prices become more “spikey”, the greater price extremes increasing the risks of operating in the market. This effect is seen at its most extreme when a period of high wind follows a low-wind spell, as when a vigorous depression follows a prolonged anticyclone. Spot prices in this scenario would range from very low, even negative, at the time of high wind to extremely high during the anticyclonic period.
The study highlighted the fact that at high wind penetrations, wind variability forces some variability onto thermal plants as well, with implications for efficiency, maintenance and cost. When wind is allowed to contribute substantially to base load, wind peaks and troughs will have to be balanced by varying the contribution from conventional plants. Given that wind varies from year to year as well as hour to hour, there may be some years when thermal plants record unusually low running times.
Faced with consequent variable and uncertain revenues from conventional plants, investors may need extra inducement to implement the required reserve. One of the study’s conclusions was that Ireland’s Single Electricity Market (SEM) is better attuned to incentivising new generating capacity than UK’s BETTA (British Electricity Trading and Transmission Arrangements) model, which pays for energy delivered rather than capacity. The researchers concluded that BETTA copes less well with a future market which, at high wind penetrations, will be much more subject to the vagaries of weather than at present.
Using system interconnections between the British and Irish markets was found to be a useful means of combating wind variability, more especially for Ireland. Interconnections to Europe were envisaged too.
Overall, the research team seemed guardedly optimistic about the prospects for 2030. While emphasising that participants in the energy markets would have to learn to live with the uncertainty arising from wind variability, its report concluded that managing transmission networks with high wind penetration will require little additional fast-response standby generating plant, although more in Ireland than in Britain. Significant longer-term base reserve will, however, be needed, though the requirements would seem to be manageable. In fact, the team appears to have ended up more concerned about the future economic shape of the market than about the way the new dynamics will challenge system operators.
National Grid: consulting stakeholders
In the UK, National Grid (NG) has also reached some encouraging conclusions about a future, wind-rich power generation landscape. The tone of its recent publications suggests acceptance that it will have to learn to deal with the fluctuations inherent in renewable sources and a belief that the challenge can be met.
Currently engaged in a consultative exercise to test its assumptions and conclusions about the future, it has sought help from stakeholders and interested parties. In a consultation document published in June 2009, it asked questions about its vision for 2020, in a bid to stimulate informed debate.
The organisation’s vision, developed in collaboration with other energy companies, the government and Ofgem within the Electricity Networks Strategy Group, builds on its existing Gone Green scenario. Gone Green envisages that some 32 GW of wind capacity will be connected by 2020, of which about 20 GW would be offshore and 12 GW onshore. Domestic and small-scale electricity generation would contribute some 15 GW. This amounts to a radical change that will coincide with the phasing out of older coal and oil fired generating plants (under the Large Combustion Plant Directive), the retirement of much existing nuclear capacity, and the expected connection of 12 GW of new gas-fired generation.
Wind capacity is seen as increasing 12-fold by 2020, with gas-fired generation rising by about a quarter. Coal-fired capacity would fall by almost a third, as would nuclear capacity, because old stations would close faster than they can be replaced. Some 15 GW of embedded generation, such as on-site CHP, is envisaged.
NG anticipates that its task of balancing supply against demand minute by minute will become highly complex. An era of large-scale variable wind will require more active network management and smarter, more dynamic control solutions. Expansion of the transmission network with more interconnections will be necessary.
The consultative document asked how NG’s observations align with respondents’ own experiences – essentially, what they think of the vision. An assumption that UK electricity demand up to 2020 will not substantially differ from what it is now, about 60 GW, was supported by the argument that the effect of economic growth will be offset by improved energy efficiency, reduced losses and an increase in small-scale embedded generation not visible to the grid. One question was whether this assumption is justified.
What other questions did National Grid have?
NG also asked more specific questions, for example, whether wind generation is sufficiently controllable to assist in operating the networks – essentially can wind power be brought in and out of use as the need for balancing requires? The document mentioned some characteristics and relative flexibilities of available generator types – plain induction, double-fed induction, permanent magnet, superconducting, full converter, etc – and of power electronic conversion systems. There were also questions about future balancing and storage services, and what could be done to encourage the provision of reserve services without impacting wholesale energy markets too adversely.
Several questions were of particular interest to renewable energy specialists. In terms of wind, one topic was the extent to which low wind events across the country should be allowed for. National Grid clearly wanted views on how market participants expect periods of low/no wind operation, no matter how infrequent, to be managed and how operating margins can be maintained. The document posited that interconnections between networks, including trans-nationally, will be key, along with measures to reduce peak demand, enlist other reserve sources such as standby generators and, as a last resort, to impose demand side measures if necessary.
The organisation was keen to consider any suggestion that sufficient flexibility will be available for operating the system in 2020, and the role that control, communication and information systems will have in meeting future challenges.
NG also asked about the extent to which marine renewable technologies should be considered. In its discussion, the document barely skimmed this topic’s surface but did mention the potential of tidal streams and barrages. The predictability of tidal generation is considered a helpful factor but, just as with wind, balancing actions would become necessary as a result of large-scale developments, such as the Severn Barrage. The latter was not included as part of the Gone Green scenario for 2020, but National Grid is involved in early consultation processes on the various schemes.
Load balancing issues
Another area in which views were sought is the potential for renewable energy to flatten peak demand and provide balancing load. Embedded generation, including micro renewable energy and micro CHP, could play a substantial part, along with smart metering and electric vehicles. There were questions about the number of electric vehicles likely to be in use by 2020 and whether charging times can be mediated by smart grids and can react to price signals.
Demand side management
The role of demand side management prompted the query whether distribution companies, suppliers, aggregators and NG will all value and compete for the services that DSM can bring. These could include balancing services, active load management, implementation of “smart” homes and commercial premises, provision of timely data on energy prices and usage, etc.
Altogether, the tone of the National Grid document, Operation of the Electricity Transmission System in 2020, displays an aspiration to meet the undoubtedly severe challenge the organisation faces (see also Gone Green Scenario). But the debate is becoming intense and detailed, and the organisation will now be processing input from a wide range of interested parties. As David Milborrow comments, “This was a golden opportunity for anyone with an interest to comment. It was a chance for those so far without a voice to make themselves heard.”
Overall, BWEA, the wind constituency as a whole and readers of this magazine may be well pleased by the growing consensus that wind variability does not mean the lights will go out or that consumer prices will go through the roof. But there remain many James Lovelocks out there, and clearly there are many questions that need to be answered.
About the author:
George Marsh is a technology correspondent for Renewable Energy Focus magazine.