Renew your energy: May 2010 Archives
Offshore wind energy is booming, with for once the UK in the lead, having installed over 1000 Megawatts (MW) of offshore wind farm generation capacity. Denmark is second in the league table, with 640MW in place, followed by the Netherlands at 250MMW and Sweden at 164MW. But several other EU countries are moving ahead. Belgium, Finland and Ireland all have working offshore projects, while Germany has started up its first large offshore project – it wants 10,000 MW by 2020. France has announced 10 zones for offshore projects off its Atlantic and Mediterranean coasts – it wants to have 6,000MW in place by 2020. However the UK seems likely to stay in the lead – it aims to install up to 40,000MW by around 2020, maybe more.
That's not to say there have not been problems. Costs have risen, in part because of the increased cost of materials like steel, which in turns reflects the increased costs of conventional energy. And there have been teething problems with some of the designs. A minor fault in the design of the transitional piece which connects the tower to the monopile foundations of the newer machines has been detected, which has resulted in movement of a few centimetres in a number of turbines. Fortunately it is not thought that there is any safety risk or threat to service or output and it's evidently planned to deal with the as part of the usual rolling programmes of operation and maintenance, with any repairs that are necessary being carried out turbine by turbine, so that there should be no impact on the operation of the rest of the wind farm. The fault evidently does not effect earlier offshore designs.
Clearly issues like this will have to be taken into account in the design of new much larger 10MW machines now being developed. However, one of the newer designs, the 10MW SWAY floating turbine being developed in Norway, won't face quite the same problem – it's actually designed to tilt by 5–8 degrees in the wind.
Outside the EU, in 2009 China installed a 3MW offshore turbine, the first unit of a 100MW project. And, after nearly 10 years of sometimes heated debate, the Cape project off Nantucket Sound in New England has at last got the go ahead. It will be the USA's first offshore wind farm – with 130 turbines. But many others are being considered, including floating versions for use in deeper water. For example, researchers at the Worcester Polytechnic Institute (WPI) have a $300,000 grant from the US National Science Foundations for a three-year on floating wind turbine platforms.
The EU is of course well advanced in this field – with for example the Norwegian Sway device mentioned above, Statoil Hydro's Hywind and the UK's 10MW Nova project. There is also the novel floating Poseidon wave and wind platform system being developed in Denmark – a 10MW version is now planned.
But a report released by the US Dept of Energy in 2008, says the 28 US states that have coastlines consume about 80% of all the electricity the US produces, so maybe they'll have an incentive to push ahead too.
As in the EU, the idea of an offshore supergrid to link up offshore wind projects has also been mooted in the US. Researchers from the University of Delaware and Stony Brook University say that linking Atlantic Coast offshore wind parks with high-voltage direct current (HVDC) cables under the ocean would substantially smooth out the fluctuations. As a fix for intermittency, they say "transmission is far more economically effective than utility-scale electric storage".
Currently there are proposals for five offshore wind farms from Delaware to Massachusetts. As plans stand, each would have separate underwater transmission cables linked into the nearest state electric grid. But the report suggest a single, federal offshore Atlantic Transmission Grid would be a better bet. Co-author Brian Colle said: "A north-south transmission geometry fits nicely with the storm track that shifts northward or southward along the U.S. East Coast on a weekly or seasonal time scale. Because then at any one time a high or low pressure system is likely to be producing wind (and thus power) somewhere along the coast."
Offshore wind isn't the only offshore option. The use of wave energy and tidal streams is also moving ahead around the world, with once again the EU, and the UK especially, in the lead. For example 1,200 MW of wave and tidal current turbine project have just be given the go ahead in Scotland. But US company Ocean Power Technologies (OPT) has been making progress winning contracts for its Power Buoy wave device including one from the Australian government.
Tidal current turbine projects are also developing around the world, for example Ireland's Open Hydro has linked with Nova Scotia Power to deploy a 1MW tidal turbine in the Bay of Fundy. And the UK's Marie Current Turbine Ltd is to install a 1.2MW Seagen there too. Meanwhile, South Korea is pushing ahead with a range of ambitious tidal projects, over 2,000MW in all, while businessgreen.com has reported that Israeli marine renewables company SDE Energy recently completed construction of a 1MW wave power plant in China. The $700,000 plant consists of a floating buoy attached to a breakwater. It's been installed near the city of Dong Ping in Guangzhou province. SDE is also reportedly in the final stages of negotiations over other projects to be built near Zhanjiang City and in the province of Hainan. SDE has talked in terms of ultimately having 10GW of wave energy systems along the Chinese coastline.
It looks like offshore renewables could really become a significant new option. The big advantage of going offshore is that there is less visual impact. The energy potential is also large – wind speed are usually higher and less variable, and for tidal flow systems, there is a lot more energy in moving water than in moving air. But there may be some environmental impacts (e.g. on fish and sea mammals), something that the device developers are very keen to avoid by careful location and a sensitive design.
However, it is argued that relatively slowly rotating free-standing tidal rotors, or wave energy buoys or platforms, should not present many hazards, while it seems that offshore wind turbine foundations can provide a substrate for a range of sea-life to exploit. As with on-land wind turbines, birds can be at risk of collision with moving wind turbine blades, but observations have suggested that sea birds avoid offshore wind turbines.
Even so, environmental and wildlife impact issues need attention, for example in terms of influencing the choice of location and layout. Overall, a precautionary approach has been adopted: developers have to submit detailed Environmental Impact Statements and there is much research on specific impacts.
But most of the problems seem to be during the installation process (e.g. noise impacts when driving piles for wind-turbine foundations and disruption during cable laying). Once installed, there seem to be fewer problems, other than possibly sea-bed sediment movements, although navigation hazards have led to some debates.
* A new UK report co-ordinated by the Public Interest Research Group puts the total practical UK resource for offshore wind, wave and tidal power as 2131TWh p.a. (six times current UK electricity use: www.offshorevaluation.org). I'll be looking at that in a subsequent blog.
A study by consultants Poyry on behalf of the European Wind Energy Association claims that wind power generation can reduce electricity prices by between €3 and €23 (£2.60 and £19.90) per megawatt hour depending on the scale and location. Entitled Wind Energy and Electricity Prices, the report looks at a range of studies of prices and concluded that an increased penetration of wind power reduces wholesale spot prices. Overall it says that "due to market dynamics and the lower marginal costs of wind power compared to conventional power, the spot electricity prices decrease by 1.9 €/MWh per additional 1,000 MW wind capacity in the system".
That already seem to have been playing out in practice. Poyry reports studies that suggest that, for example, in Germany, increased wind power has reduced costs in the range of €1.3–5 bn per year. One result has it seems been that some power companies have begun to reduce charges to consumers, although this is mainly because of the need to avoid wind curtailment: at periods of low demand and when there is excess wind available, a price-rebate system has been used in Germany, to avoid wind curtailment (i.e. power dumping), and according to an article in Offshore Wind Magazine (OWM), "payments have risen as high as 500.02 euros a megawatt-hour" for some users. In effect it's negative pricing-selling power at below cost.
Anti-wind cynics might of course say that this just goes to show that we should not subsidise wind – then suppliers wouldn't have to pay people to use it when there was excess. However, the counter point is that, although the capital cost is high, so that subsidies may initially be needed to establish it in the market, once it is established the marginal operating costs are low (there is no fuel cost) making it very competitive, especially if curtailment can be limited.
Dropping the price locally can certainly help to avoid having to curtail the wind-turbine output, but of course, like curtailment, this does eat into profits. Since the spot-price volatility is unpredictable, it makes it hard to plan ahead. So arguably there have to be limits on how low prices can fall or else it becomes uneconomic to produce power, at least within a competitive market system.
To avoid this, and the risk of the market collapsing, OWM notes: "Nord Pool, the Nasdaq OMX Group Inc.-owned Scandinavian power bourse, last year took steps to encourage generators to limit production by implementing a minimum price. The most generators would pay users to take their power is 200 euros per megawatt hour if there is excess electricity from too much wind." It added, the measures are meant to "increase the effectiveness of the market, forcing power generators to consider reducing their electricity generation or having to pay for delivering electricity". Similar arrangements have evidently been made in Australia, where excess wind generation has also at times been forcing pool prices to go negative, leading the market regulator to set a minimum floor price. But that is a pretty crude approach – fixing the market. It's not a sustainable long-term solution.
Diversity is another way out. OWM noted that RWE, Germany's second-largest utility, minimizes the risks of having to pay consumers to use power by using a "broad" range of different-generation technologies in different markets. RWE said that rebates or negative prices didn't have a big effect on the company.
Longer term, what's needed is diversity plus better and wider-ranging grid links, which can allow excess power to be sold further afield, and also compensate for any shortfalls by drawing power from other areas (i.e. via regional and even inter-country power trading). OWM noted that this is already done among France, the Netherlands and Belgium, and Germany plans to join them soon – selling excess power to power-short areas. That's where the HVDC supergrid would come into play, allowing for EU-wide optimization of green energy.
Storing excess energy (e.g. using it to pump water up into hydro reservoirs) is another option, and this could be done on an EU-wide basis, using the supergrid. That's what Denmark already does with some of its surplus wind-derived electricity, selling excess to Norway and Sweden, who, if they don't need it immediately, may store in their hydro reservoirs. Denmark then, in effect, buys it back when there is a wind shortfall in Denmark. The only problem is that the Danes get less for the excess wind that they sell than they have to pay for the bought-back power.
Negative pricing and surpluses are not just an EU issue. OWM noted that, according to the Electricity Reliability Council of Texas, Texas had so-called negative power prices in the first half of 2008 because wind turbines in the western part of the state weren't adequately linked with more populated regions in the east. See my earlier blog on grid congestion and wind-curtailment issues in the US.
OWM quote Andrew Garrad, chief executive officer of GL Garrad Hassan, a wind-consulting company, that commented that in parts of Texas, some utilities are using wind power because it's the cheapest form of energy. But until there's more integration and better transmission grids, prices probably will continue to fluctuate, leading to negative prices, with payment to consumers being reflected as a discount on their monthly bills. Garrard conclude that "we do need to get the right market mechanisms in place" to better integrate wind power into energy grids.
That's clearly true. But rather than just leaving it up to the market or fixing floor prices, one idea might be to introduce a cross feed tariff on power transfers, to help balance cash and energy flows, so as to optimize carbon savings by avoiding curtailment. For example, it could raise money via a levy on the overall transfer or from sales to stimulate investment in grid upgrades and reward suppliers who can deal with excess generation, and then meet shortfalls, using energy-storage facilities.
A version of the OWM article originally appeared in Bloombergs Business Week, authored by Jeremy van Loon.
Renewable energy isn't cheap, but prices should fall as markets build and technology develops. Indeed the basis of 'learning curve' theory is that this is what happens, over time. So why are some renewables getting more expensive- off shore wind for example?
One reason is that materials, like steel and aluminium, have been getting more expensive, in part reflecting the increased costs of (conventional) energy – these are very energy intensive materials. Some of those price rises were just blips (e.g. linked to the oil crisis last year), but the long-term trend for fossil (and fissile) fuels must surely always be up, since they are finite reserves. So the old technology undermines the new. At some point in the future we will be using renewable energy to produce/process these and other materials, so the continual price escalation problem will be avoided. But that's some way off.
Certainly we will need an initial fossil fuel input to kick off a renewable energy future – so as to build the new renewable-energy technologies and produce the materials used in their construction. So some say that net emissions will increase if we try to expand renewables quickly. That ignores the fact that we will have to replace the existing fossil plants anyway in the years ahead, as they get old and are retired. Moreover, the energy (and carbon) debt from replacing the existing system with renewables should be less that either building more fossil plants, or even than going nuclear e.g. the embedded energy content of wind turbines is low – typically you get around 80 times more energy out over their lifetimes operation than is needed for their construction. By comparison, according a 2002 Hydro Quebec study, the output from nuclear plants over their lifetime is only around 16 times the energy needed for their construction and for the (energy intensive) production/processing of their fuel. Even more dramatically, the equivalent figure quoted for coal was 7 and gas CCGT 5. That for PV solar was initially about 9 – PV cell production is energy intensive – but it has been improving. Similarly for wind and other renewables – the energy/carbon debts are falling.
High energy (and therefore carbon) debts are only incurred when fossil, or to a lesser extent nuclear, fuels are used to build renewables: fossil fuels are obviously the worst, but the review by Ben Sovacool (Energy Policy 36 (2008) pp2940–2953) suggests that a nuclear system generates about seven times more CO2 over its lifetimes than wind turbines. However, after the high carbon input phase, the energy for building more renewables can come from these initial renewables. In effect we would then have renewable breeders. There are already some PV powered PV manufacturing plants – solar breeders.
That said, the rate of ramp up needs debate: what rate of new renewables growth could be sustained by the existing renewables – including providing the energy needed for producing basic materials?
Some say, rather bleakly, that we won't even be able to get to that point: with peak oil, peak gas, peak uranium and even peak coal, looming, we just won't have the energy to start ramping up renewables seriously – or for anything! Some add that this at least means that climate change will not be a problem! But others argue that, while Peak Oil and Gas now seem very likely soon, and Peak Uranium not far off (see the German Energy Watch Group's study), there is still plenty of coal, so that is what is likely to be used- and, tragically, can be, given slow progress on a global climate agreement.
While it might be possible to reduce the impacts by Carbon Capture and Storage, rather than just burning the remaining fossil fuels off carelessly, we really ought to use whatever is left to start to build the new renewable energy system. Using these fuels to build a nuclear system, which is the only other supply option on the table, seems to be very short-sighted – given the energy intensive nature of the nuclear fuel cycle and the relatively limited uranium reserves. Though, if all else fails, and in the worst case and there isn't enough fossil fuel, you could say that nuclear plants might, in the interim, provide some of the energy we need to start to build up the renewables system. More sensibly though, we should try to cut energy demand, so leaving more fossil energy to build the initial renewables.
Could it be done – will there be enough energy to support the development of a full renewable system? At the most obvious level if there is not enough energy to replace our existing plants with new plants of whatever type, then we are all doomed. But if we choose renewables for the future, it would be good not to incur massive emission debts. That rather depends in part on which renewables we choose – some are more energy intensive than others. It also depends on how quickly we need to ramp up renewables: if it could be done more slowly, then they can bootstrap themselves in energy terms, to some extent. But given the climate crisis, we may have to move faster than that. In which case, demand reduction and also possibly Carbon Capture and Storage, would become even more important, while we are still stuck in a mainly fossil-fuelled economy.
For the Hydro Quebec study see: L.Gagnon, C. Belanger and Y. Uchiyama ' Life Cycle assessment of electricity generation options: the status of research in the year 2001' Energy Policy 30 (2002) pp 1267–1278.
The UK Department of Energy and Climate Change has been developing a 2050 Road map. A report was expected in parallel with the recent pre-election Budget, but in the event all that emerged was an interim statement, in an appendix to a Treasury/DECC 'Energy Market Assessment' up to and beyond 2020. This concluded tentatively that:
* Based on the analysis to date, total UK energy demand in 2050 will need to fall significantly, potentially as much as 25% lower relative to 2007 levels.
*A substantial level of electrification of heating and surface transport will be needed.
* Electricity supply needs to be decarbonised, and may need to double. It says: 'The use of electricity for significant parts of industry, heating and transport means that demand for electricity is likely to rise, even as overall energy use declines.'
It says we might look to higher levels of interconnection with neighbouring countries to allow fluctuations in demand and supply to be smoothed across a number of countries; new storage technologies, such as large-scale batteries; smart or flexible demand, such as off-peak charging of electric vehicles; the distribution network would need to become bigger and smarter to enable a potential doubling of overall electricity demand and to cope with new sources of energy supply and demand.
Overall it says that: ''Low-carbon electricity will provide a very large proportion of the UK's future low-carbon energy. It can be used for a wide range of activities, often with high efficiency compared to other fuels, and can, to a large extent, be scaled up to meet demand' although it accepts that 'other technologies are also likely to be required. For example, in heating, the use of waste heat from power stations, solar thermal technologies and energy from waste may be important and could reduce the burden on the electricity system. In road transport, biofuels and fuel cells may also be long-term contributors, particularly for modes that are hard to electrify. Even so, a significant degree of electrification appears to be necessary.'
What the report doesn't say is which low carbon sources we might need, a key issue being the role of nuclear, something that the long term EU and US studies mentioned in my previous blog included only in some low renewables scenarios, tangentially, or not at all. Instead they all focused on renewables, with 100% by 2050 or even earlier being seen as viable.
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The UK governments recent National Policy Statement on Energy by contrast focuses mainly on nuclear, and asserted that 'by 2050 the UK may need to produce more electricity than today', as part of its justification for an expanded nuclear programme. But it had little to offer to back this up. And the new DECC statement above goes only a little further. Basically we don't yet have a 2050 UK scenario.
The Sustainable Energy Partnership (SEP) spotted this omission and also pointed to an apparent contradiction: SEP noted that the 2008 Nuclear White Paper said that, given attention to energy efficiency, by 2050, total electricity demand could 'remain at roughly today's levels despite the UK's GDP being three times larger than it is today'.
SEP brings together nearly all environmental and fuel poverty NGOs and relevant trade groups, including ACE, AECB, BWEA, CPRE, CHPA, FoE, Green Party, Greenpeace, Micropower Council, NEA, PV-UK, PRASEG, RSPB, REA, SERA, Solar Century and WWF-UK. In its submission to a Select Committee review of the NPS, SEP commented: 'It defies common sense to approve a massive [nuclear] building programme to achieve the long term objectives of energy policy without a proper assessment of the future long term need for electricity.'
In the absence of 2050 scenario, what the NPS does, says SEP, is to assert that 'under central assumptions there will be a need for approximately 60 GW of new capacity by 2025' – and then quotes a Redpoint study as the source for this. But Redpoint's study simply looked at how 'a goal of achieving around 28–29% of electricity from renewables by 2020' might be achieved, not at how or whether we could generate enough electricity without nuclear to meet demand. Or, one could add, what the 2050 situation might be.
The government was evidently aware that the longer term rationale for nuclear was a little weak (to put it mildly) which is no doubt why it commissioned a review of energy policy issues and options up to 2050. Hopefully the interim DECC statement will be followed by something more substantial in due course, which will take note of the very encouraging EU scenarios mentioned above.
Meanwhile in its reply to 'Energy Envoy' Malcolm Wicks' proposal for 30–40% of nuclear 'beyond 2030', the government indicated that, in addition to renewables, with around 35 GW expected by 2025, we might need 25 GW of new 'non-renewables' (presumably nuclear and CCS) by 2025. But a specific nuclear target was said not to be needed at this stage.
Maybe that's not surprising. Most of the large number of scenarios now available seem to agree that '100% from renewables by 2050' is possible, with the costs not being prohibitive – after all there would be no fuel costs.
Interestingly even the relatively conservative International Energy Agency, concluded in a recent report on the Projected Costs of Generating Electricity, produced with the Nuclear Energy Agency (NEA), that, in comparative cost terms, there was now not a lot in it, depending mainly on location: "Nuclear, coal, gas and, where local conditions are favourable, hydro and wind, are now fairly competitive generation technologies for baseload power generation."
Certainly, even under present economic framework, wind power is already competitive in some US states (it's the cheapest source on the grid in California), and it is moving ahead in the US rapidly, as it is in China, India and the EU. As costs for wind and other renewables fall further, while the cost of fossil and fissile fuels rise, we are likely to see a steady transition in most places around the world. And if more rational climate policies are adopted this transition could accelerate, so that 100% % by 2050 becomes a real possibility.
Most of the new scenarios focus on electricity, but accept that there are also other renewable heat supply and transport options which may be significant – solar and biomass in particular. Electricity is obviously important, but the best balance between large and small projects, local generation and supergrid feeds, heat and power production, as well as of course energy efficiency, remains to be determined.
Clearly the energy system of the future will look very different from the one that has grown up in the fossil fuel era. Demand and supply will be matched dynamically via interactive load management systems, with a wide range of renewables of varying scales and types linked up by supergrids and with energy storage becoming important. While some look to an almost all-electric future, others look to the use of hydrogen as a new more easily storable energy vector, while others again argue that heat is the best storage option. In the event a mixture of some or all of these is likely to emerge, differing in each geographical context.
Whether nuclear has a continuing long-term role in this remains to be seen.
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