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(updated June 2010)
Technology to utilise the forces of nature for doing work to supply human needs is as old as the first sailing ship. But attention swung away from renewable sources as the industrial revolution progressed on the basis of the concentrated energy locked up in fossil fuels. This was compounded by the increasing use of reticulated electricity based on fossil fuels and the importance of portable high-density energy sources for transport - the era of oil.
As electricity demand escalated, with supply depending largely on fossil fuels plus some hydro power and then nuclear energy, concerns arose about carbon dioxide emissions contributing to possible global warming. Attention again turned to the huge sources of energy surging around us in nature - sun, wind, and seas in particular. There was never any doubt about the magnitude of these, the challenge was always in harnessing them.
Today we are well advanced in meeting that challenge. Wind turbines have developed greatly in recent decades, solar photovoltaic technology is much more efficient, and there are improved prospects of harnessing tides and waves. Solar thermal technologies in particular (with some heat storage) have great potential in sunny climates. With government encouragement to utilise wind and solar technologies, their costs have come down and are now in the same league as the increased costs of fossil fuel technologies due to likely carbon emission charges on electricity generation from them.
There is a fundamental attractiveness about harnessing such forces in an age which is very conscious of the environmental effects of burning fossil fuels and sustainability is an ethical norm. So today the focus is on both adequacy of energy supply long-term and also the environmental implications of particular sources. In that regard the near certainty of costs being imposed on carbon dioxide emissions in developed countries at least has profoundly changed the economic outlook of clean energy sources.
A market-determined carbon price will create incentives for energy sources that are cleaner than current fossil fuel sources without distinguishing among different technologies. This puts the onus on the generating utility to employ technologies which efficiently supply power to the consumer at a competitive price.
Sun, wind, waves, rivers, tides and the heat from radioactive decay in the earth's mantle as well as biomass are all abundant and ongoing, hence the term "renewables". Only one, the power of falling water in rivers, has been significantly tapped for electricity for many years, though utilization of wind is increasing rapidly and it is now acknowledged as a mainstream energy source. Solar energy's main human application has been in agriculture and forestry, via photosynthesis, and increasingly it is harnessed for heat. Electricity remains a niche application for solar. Biomass (eg sugar cane residue) is burned where it can be utilised. The others are little used as yet.
Turning to the use of abundant renewable energy sources other than large-scale hydro for electricity, there are challenges in actually harnessing them. Apart from solar photovoltaic (PV) systems which produce electricity directly, the question is how to make them turn dynamos to generate the electricity. If it is heat which is harnessed, this is via a steam generating system.
If the fundamental opportunity of these renewables is their abundance and relatively widespread occurrence, the fundamental challenge, especially for electricity supply, is applying them to meet demand given their variable and diffuse nature*. This means either that there must be reliable duplicate sources of electricity beyond the normal system reserve, or some means of electricity storage. The largest utility-scale electricity storage so far is a 4 megawatt sodium-sulfur battery system to provide improved reliability and power quality for the city of Presidio in Texas.
Policies which favour renewables over other sources may also be required. Such policies, now in place in about 50 countries, include priority dispatch for electricity from renewable sources and special feed-in tariffs, quota obligations and energy tax exemptions.
* The main exception is geothermal, which is not widely accessible.
The prospects, opportunities and challenges for renewables are discussed below in this context.
This load curve diagram shows that much of the electricity demand is in fact for continuous 24/7 supply (base-load), while some is for a lesser amount of predictable supply for about three quarters of the day, and less still for variable peak demand up to half of the time. Some of the overnight demand is for domestic hot water systems on cheap tariff. With overnight charging of electric vehicles it is easy to see how the base-load proportion would grow, increasing the scope for nuclear and other plants which produce it. Source: Vencorp
Most electricity demand is for continuous, reliable supply that has traditionally been provided by base-load electricity generation. Some is for shorter-term (eg peak-load) requirements on a broadly predictable basis. Hence if renewable sources are linked to a grid, the question of back-up capacity arises, for a stand-alone system energy storage is the main issue. Apart from pumped-storage hydro systems (see below), no such means exist at present, at least on any large scale.
However, a distinct advantage of solar and to some extent other renewable systems is that they are distributed and may be near the points of demand, thereby reducing power transmission losses if traditional generating plants are distant. Of course, this same feature sometimes counts against wind in that the best sites for harnessing it are sometimes remote from population, and the main back-up for lack of wind in one place is wind blowing hard in another, hence requiring a wide network with flexible operation.
RIVERS & HYDRO ELECTRICITY
Hydro-electric power, using the potential energy of rivers, is by far the best-established means of electricity generation from renewable sources. It now supplies 16% of world electricity (99% in Norway, 58% in Canada, 55% in Switzerland, 45% in Sweden, 7% in USA, 6% in Australia). Apart from those four countries with an abundance of it, hydro capacity is normally applied to peak-load demand, because it is so readily stopped and started. This also means that it is an ideal complement to wind power in a grid system, and is used thus most effectively by Denmark (see case study below). World hydro capacity is 867 GWe, and in 2006 it supplied 3121 GWh (41% capacity factor), underlining its generally peak use.
Hydro is not a major option for the future in the developed countries because most major sites in these countries having potential for harnessing gravity in this way are either being exploited already or are unavailable for other reasons such as environmental considerations. Growth to 2030 is expected mostly in China and Latin America. China is commissioning the $26 billion Three Gorges dam, which will produce 18 GWe, but it has displaced over 1.2 million people.
The chief advantage of hydro systems is their capacity to handle seasonal (as well as daily) high peak loads. In practice the utilisation of stored water is sometimes complicated by demands for irrigation which may occur out of phase with peak electrical demands.
WIND ENERGY
Utilization of wind energy has increased spectacularly in recent years, with a 29% increase in installed capacity during 2008 capping similar rises in previous years. The 27 GWe increment represented an investment of EUR 36.5 billion (US$ 47.5 billion). This brought total world wind capacity to 121 GWe, with tens of thousands of turbines now operating.
Wind turbines of up to 5 MWe are now functioning in many countries, though most new ones are 1-2 MWe. The power output is a function of the cube of the wind speed, so doubling the wind speed gives eight times the energy potential. In operation such turbines require a wind in the range 4 to 25 metres per second (14 - 90 km/hr), with maximum output being at 12-25 m/s (the excess energy being spilled above 25 m/s). While relatively few areas have significant prevailing winds in this range, many have enough to be harnessed effectively and to give better than a 25% capacity utilisation. Alternative power sources allow the system to cope with calmer periods.
Where there is an economic back-up which can be called upon at very short notice (eg hydro), a significant proportion of electricity can be provided from wind. The most economical and practical size of commercial wind turbines is now up to 2 MWe, grouped into wind farms up to 200 MWe. Depending on site, most turbines operate at about 25% load factor over the course of a year (European average), but some reach 33%. The average size of new turbines in USA in 2007 was 1.6 GWe.
The USA leads the field with over 25 GWe installed, Germany has 24 GWe, Spain has almost 17 GWe and China over 12 GWe at the end of 2008.
With increased scale and numbers of units, generation costs have been diminishing. They are still greater than those for coal or nuclear, and allowing for backup capacity and grid connection complexities adds to them. Wind is intermittent, and when it does not blow, back-up capacity such s hydro or gas is needed. When it does blow, and displaces power from other sources, it may reduce the profitability of those sources and hence increase prices.
However, government policies in many countries ensure that power from wind turbines is able to be sold (see Appendix). The Global Wind Energy Council claims that world capacity of 121 GWe at the end of 2008 will produce 260 TWh per year (ie 24.6% capacity factor). Wind is projected to supply 3% of world electricity in 2030, and perhaps 10% in OECD Europe.
Wind turbines have a high steel tower to mount the generator nacelle, and have rotors with three blades up to 50m long. Foundations require a substantial mass of reinforced concrete. Hence the energy inputs to manufacture are not insignificant. Also siting is important in getting a net gain from them. In the UK the Carbon Trust found that small wind turbines on houses in urban areas often caused more carbon emissions in their construction and fitting than they saved in electrical output (CT 7/8/08).
SOLAR ENERGY
Solar energy is readily harnessed for low temperature heat, and in many places domestic hot water units (with storage) routinely utilise it. It is also used simply by sensible design of buildings and in many ways that are taken for granted. Industrially, probably the main use is in solar salt production - some 1000 PJ per year in Australia alone (equivalent to two thirds of the nation's oil use).
Three methods of converting the sun's radiant energy to electricity are the focus of attention. The best-known method utilises sunlight acting on photovoltaic cells to produce electricity. Flat plate versions of these can readily be mounted on buildings without any aesthetic intrusion or requiring special support structures. Solar photovoltaic (PV) has application for certain signaling and communication equipment, such as remote area telecommunications equipment in Australia or simply where mains connection is inconvenient. Sales of solar PV modules are increasing strongly as their efficiency increases and price falls. Even working on 1 kilowatt per square metre in the main part of a sunny day, intensity of incoming radiation and converting this to high-grade electricity is still relatively inefficient - typically 10% in commercial equipment or up to 20% in more expensive units. But the cost per unit of electricity - at least ten times that of conventional sources, limits its potential to supplementary applications on buildings where its maximum supply coincides with peak demand.
More efficiency can be gained using concentrating solar PV (CPV), where some kind of parabolic mirror tracks the sun and increases the intensity of the solar radiation up to 1000-fold. Modules are typically 35-50 kW and some 18 MWe of CPV capacity was installed in 2006. In Australia a 154 MWe dense-array CPV power station is planned for Mildura in Victoria, with A$ 125 million government support promised. In the USA Boeing has licensed its XR700 high-concentration PV (HCPV) technology to Stirling Energy Systems with a view to commercializing it for plants under 50 MWe from 2012. The HCPV cells in 2009 achieved a world record for terrestrial concentrator solar cell efficiency, at 41.6%.
For a stand-alone system some means must be employed to store the collected energy during hours of darkness or cloud - either as electricity in batteries, or in some other form such as hydrogen (produced by electrolysis of water). In either case, an extra stage of energy conversion is involved with consequent energy losses.
Many solar PV plants are connected to electricity grids in Europe and USA. Japan has 150 MWe installed. Several Spanish PV plants are over 20 MWe, and the Olmedilla one peaks at 60 MWe. A 600 MWe plant is planned for Rancho Cielo New Mexico, using thin film PV panels. In Australia a 154 MWe solar PV power station is planned for northwestern Victoria, costing A$ 420 million and expected to come into operation over 2010-13. It uses mirrors to concentrate the sun's energy on the PV collectors. Research continues into ways to make the actual solar collecting cells less expensive and more efficient. In some systems there is provision for feeding surplus PV power from domestic systems into the grid as contra to normal supply from it, which enhances the economics. A total of over 9 GWe of solar PV capacity is installed worldwide.
A solar thermal power plant has a system of mirrors to concentrate the sunlight on to an absorber, the energy then being used to drive turbines - concentrating solar thermal power (CSP). The concentrator may be a parabolic mirror trough oriented north-south, which tracks the sun's path through the day. The absorber is located at the focal point and converts the solar radiation to heat in a fluid such as synthetic oil, which may reach 700°C. The fluid transfers heat to a secondary circuit producing steam to drive a conventional turbine and generator. Several such installations in modules of 80 MW are now operating. Each module requires about 50 hectares of land and needs very precise engineering and control. These plants are supplemented by a gas-fired boiler which generates about a quarter of the overall power output and keeps them warm overnight.
In mid 2007 Nevada Solar One, a 64 MWe capacity solar thermal energy plant, started up. The $250 million plant is projected to produce 124 million kWh per year and covers about 160 hectares with 760 mirrored troughs that concentrate the heat from the desert sun on to pipes that contain a heat transfer fluid. This is heated to 390°C and then produces steam to drive turbines. Nine similar systems totaling 354 MWe have been operating in California. Andasol 1, Alvarado 1 and Energia Solar De Puertollano in Spain, each 50 MWe, commenced operation in 2008-09.
Another form of this CSP is the power tower, with a set of flat mirrors (heliostats) which track the sun and focus heat on the top of a tower, heating water to make steam, or molten salt to 1000°C and using this to produce steam for a turbine. California's Solar One/Two plant produced 10 MWe for a few years. Based on this, Spain's 17 MWe Solar Tres plant and has 2500 mirrors, each 115 m2 and 6250 tonnes of molten salt as the transfer fluid which also stores heat, enabling operation into the evening, thus approximating to much of the daily load demand profile. The salt used may be 60% sodium nitrite, 40% potassium nitrite. Another 11 MWe Spanish plant PS10 has 624 mirrors, each 120 m2 and produces steam directly in the tower. A 20 MWe version adjacent, PS20, is the largest CSP plant in the world, and by 2015 Spain expects to have 2000 MWe of CSP operating. Power production in the evening can be extended fairly readily using gas combustion for heat.
Another CSP set-up is the Solar Dish Stirling System which uses reflectors to concentrate energy to drive a stirling cycle engine. Two Tessera Solar plants, of 750 and 850 MWe, are planned to be built in 2010 at Imperial Valley and Calico in California. The system consists of a solar concentrator in a dish structure with an array of curved glass mirror facets which focus the energy on the power conversion unit's receiver tubes containing hydrogen gas which powers a Stirling engine. Solar heat pressurizes the hydrogen to power the four-cylinder reciprocating Solar Stirling Engine and drive a generator. The hydrogen working fluid is cooled in a closed cycle. Waste heat from the engine is transferred to the ambient air via a water-filled radiator system.
Over 600 MWe of CSP capacity worldwide has supplied about 80% of the total solar electricity so far. Another 1700 MWe of CSP was under construction as of mid 2009. The US Department of Energy has awarded a $1.37 billion loan guarantee to BrightSource Energy, Inc. to build the 400 MWe Ivanpah Solar Power complex in the Mojave Desert of California. This comprises three CSP Luz power towers which simply heat water to 550°C to make steam, using 500 mirrors each of 14 m2 per MWe. Construction starts late 2010 for operation from 2012. The company is seeking some A$ 450 million Australian government support for a similar 2-tower, 250 MWe plant with gas-fired evening function in Australia.
With solar input being both diffuse* and interrupted by night and by cloud cover, solar electric generation has a low capacity factor, typically less than 15%, though this is partly addressed by heat storage using molten salt. Power costs are two to three times that of conventional sources, which puts it within reach of being economically viable where carbon emissions from fossil fuels are priced.
* In low to middle latitudes on a sunny day up to 1 kW/m2 falls on a surface maintained at right angles to the sun's rays. In Europe much less than this is received through much of the year, for instance in winter most of Europe averages less than 1 kWh/m2 per day (on a horizontal surface).
Large CSP schemes in North Africa, supplemented by heat storage, are proposed for supplying Europe via high voltage DC links. One proposal is the Desertec Industrial Initiative with estimated cost of EUR 400 billion, networking the EU, Middle East and North Africa with 20 transmission lines of 5 GW each.
Another kind of solar thermal plant is the solar updraft tower, using a huge chimney surrounded at its base by a solar collector zone like an open greenhouse. The air under this skirt is heated and rises up the chimney, turning turbines as it does so. The 50 MWe Buronga plant planned in Australia was to be a prototype, but plans are now for two 200 MWe versions each using 32 turbines of 6.25 MWe with a 10 square kilometre collector zone under a 730 metre high tower in the Arizona desert. Thermal mass - possibly brine ponds - under the collector zone means that some operation will continue into the night. A 50 kWe prototype plant of this design operated in Spain 1982-89.
A significant role of solar energy is that of direct heating. Much of our energy need is for heat below 60oC - eg. in hot water systems. A lot more, particularly in industry, is for heat in the range 60 - 110oC. Together these may account for a significant proportion of primary energy use in industrialised nations. The first need can readily be supplied by solar power much of the time in some places, and the second application commercially is probably not far off. Such uses will diminish to some extent both the demand for electricity and the consumption of fossil fuels, particularly if coupled with energy conservation measures such as insulation.
With adequate insulation, heat pumps utilising the conventional refrigeration cycle can be used to warm and cool buildings, with very little energy input other than from the sun. Eventually, up to ten percent of total primary energy in industrialised countries may be supplied by direct solar thermal techniques, and to some extent this will substitute for base-load electrical energy.
GEOTHERMAL ENERGY
Where hot underground steam can be tapped and brought to the surface it may be used to generate electricity. Such geothermal sources have potential in certain parts of the world such as New Zealand, USA, Philippines and Italy. Some 10,000 MWe of capacity is operating, including 3000 MWe in the USA and 2000 MWe in Philippines, and in 2005 geothermal produced 57 GWh worldwide. In Japan 500 MWe of capacity produces 0.3% of the country's electricity. In New Zealand 420 MWe produces over 7% of the electricity, and Iceland gets most of its electricity from 200 MWe of geothermal plant. Lihir Gold mine in Papua New Guinea has 56 MWe installed, the last 20 MWe costing US$ 40 million - about the same as annual savings from the expanded plant. Geothermal electric output is expected to triple by 2030. The largest geothermal plant is The Geysers in California, producing about 1000 MWe, but diminishing.
There are also prospects in certain other areas for hot fractured rock geothermal, or hot dry rock geothermal - pumping water underground to regions of the Earth's crust which are very hot or using hot brine from these regions. The heat - up to about 250°C - is due to high levels of radioactivity in the granites and because they are insulated at 4-5 km depth. They typically have 15-40 ppm uranium and/or thorium, but may be ten times this. The heat from radiogenic decay* is used to make steam for electricity generation. South Australia has some very prospective areas. The main problem with this technology is producing and maintaining the artificially-fractured rock as the heat exchanger. Only one project is operational, the Geox 3 MWe plant at Landau, Germany, using hot water (160ºC) pumped up from 3.3 km down. It cost EUR 20 million. A 50 MWe Australian plant is envisaged as having 9 deep wells - 4 down and 5 up.
* For Geodynamics: 11 milliWatts per tonne (range 3-100 mW/t) in granite.
Ground source heat pump systems or engineered geothermal systems also come into this category, though the temperatures are much lower. The 1997 Geoscience Australia building in Canberra is heated and cooled thus, using a system of 210 pumps throughout the building which carry water through loops of pipe buried in 352 boreholes each 100 metres deep in the ground. Here the temperature is a steady 17°C, so that it is used as a heat sink or heat source at different times of the year. See 10-year report (pdf).
TIDAL ENERGY
Harnessing the tides with a barrage in a bay or estuary has been achieved in France (240 MWe in the Rance Estuary, since 1966), Canada (20 MWe at Annapolis in the Bay of Fundy, since 1984) and Russia (White Sea, 0.5 MWe), and could be achieved in certain other areas where there is a large tidal range. The trapped water can be used to turn turbines as it is released through the tidal barrage in either direction. Worldwide this technology appears to have little potential, largely due to environmental constraints.
However, placing free-standing turbines in major coastal tidal streams appears to have greater potential, and this is being explored. See news item
Currents are predictable and those with velocities of 2 to 3 metres per second are ideal and the kinetic energy involved is equivalent to a very high wind speed. This means that a 1 MWe tidal turbine rotor is less than 20 m diameter, compared with 60 m for a 1 MWe wind turbine. Units can be packed more densely than wind turbines in a wind farm, and positioned far enough below the surface to avoid storm damage. A 300 kW turbine with 11 m diameter rotor in the Bristol Channel can be jacked out of the water for maintenance. Early in 2008 a 1.2 MWe twin turbine was installed in Strangford Lough, Northern Ireland, billed as the first commercial unit of its kind and expected to produce power 18-20 hours per day. The next project is a 10.5 MWe nine-turbine array off the coast of Anglesey. Generally however ocean currents are too slow or too variable to exploit commercially.
Some tidal stream generators are designed to oscillate, using the tidal flow to move hydroplanes connected to hydraulic arms sideways or up and down. A prototype has been installed off the coast of Portugal.
Another experimental design is using a shroud to speed up the flow through a venturus in which the turbine is placed. This has been trialled in Australia and British Colombia.
A major pilot project using three kinds of tidal stream turbines is being installed in the Bay of Fundy's Minas Passage, about three kilometers from shore. Some 3 MWe will be fed to the grid from the pilot project. Eventually 100 MWe is envisaged. The three designs are a 10m diameter turbine from Ireland, a Canadian Clean Current turbine and an Underwater Electric Kite from USA.
Tidal power comes closest of all the intermittent renewable sources to being able to provide a continuous and predictable output, and is projected to increase from 1 billion kWh in 2002 to 35 billion in 2030 (including wave power).
WAVE ENERGY
Harnessing power from wave motion is a possibility which might yield significant electricity. The feasibility of this has been investigated, particularly in the UK. Generators either coupled to floating devices or turned by air displaced by waves in a hollow concrete structure (oscillating water column) are two concepts for producing electricity for delivery to shore. Other experimental devices are submerged and harness the changing pressure as waves pass over them. The first commercial wave power plant is in Portugal, with floating rigid segments which pump fluid through turbines as they flex at the joints. It can produce 2.25 MWe. Another - Oyster - is in UK and is designed to capture the energy found in nearshore waves in water depths of 12 to 16 metres. Each 200-tonne module consists of a large buoyant hinged flap anchored to the seabed. Movement of the flap with each passing wave drives a hydraulic piston to deliver high-pressure water to an onshore turbine which generates electricity. The 315 kW demonstration module being tested in the Orkney Islands is expected to have about a 42% capacity factor.
Numerous practical problems have frustrated progress with wave technology, not least storm damage.
OCEAN THERMAL ENERGY
Ocean thermal energy conversion (OTEC) has long been an attractive idea, but is unproven beyond small pilot plants up to 50 kWe. It works by utilising the temperature difference between equatorial surface waters and cool deep waters, the temperature difference needing to be about 20ºC top to bottom. In the open cycle OTEC the warm surface water is evaporated in a vacuum chamber to produce steam which drives a turbine. It is then condensed in a heat exchanger by the cold water. The main engineering challenge is in the huge cold water pipe which needs to be about 10 m diameter and extend a kilometre deep to enable a large water flow. A closed cycle variation of this uses an ammonia cycle. The ammonia is vapourised by the warm surface waters and drives a turbine before being condensed in a heat exchanger by the cold water. A 10ºC temperature difference is sufficient.
BIOFUELS
Growing crops of wood or other kinds to burn directly or to make fuels such as ethanol and biodiesel has a lot of support in several parts of the world, though mostly focused on transport fuel. The main issues here are land and water resources. The land usually must either be removed from agriculture for food or fibre, or it means encroaching upon forests or natural ecosystems. Available fresh water for growing biofuel crops such as maize and sugarcane and for processing them may be another constraint.
Burning biomass for generating electricity has some appeal as a means of utilising solar energy for power. However, the logistics and overall energy balance usually defeat it, in that a lot of energy is required to harvest and move the crops to the power station. This means that the energy inputs to growing, fertilising and harvesting the crops then processing them can easily be greater than the energy value in the final fuel, and the greenhouse gas emissions can be similar to those from equivalent fossil fuels. Also other environmental impacts can be considerable. For long term sustainability, the ash containing mineral nutrients needs to be returned to the land. In Australia and Latin America sugar cane pulp is burned as a valuable energy source, but this (bagasse) is a by-product of the sugar.
By 2030 biomass-fuelled electricity production was projected to triple and provide 2% of world total, 4% in OECD Europe, as a result of government policies to promote renewables. However, such projections are increasingly challenged as the cost of biofuels in water use and pushing up food prices is increasingly questioned. The cost in subsidies is also increasingly questioned: in the OECD US$ 13-15 billion is spent annually on biofules which provide only 3% of liquid transport fuel.
In 2008 about 100 million tonnes of grain (enough feed nearly 450 million people) was expected to be turned into fuel. This includes about 30% of the US corn crop, aided by heavy subsidies. Meanwhile basic food prices have risen sharply.
NUCLEAR ENERGY
In recent years there has been discussion as to whether nuclear power can be categorised as “renewable”. In the context of sustainable development it shares many of the benefits of many renewables, it is a low-carbon energy source, it has a very small environmental impact, similarities that are in sharp contrast to fossil fuels. But commonly, nuclear power is categorised separately from ‘renewables’. Nuclear fission power reactors do use a mineral fuel and demonstrably depletes the available resources of that fuel.
In the future nuclear power will make use of fast neutron reactors. As well as utilizing about 60 times the amount of energy from uranium, they will unlock the potential of using even more abundant thorium as a fuel. In addition, some 1.5 million tonnes of depleted uranium now seen by some people as little more than a waste, becomes a fuel resource. In effect, they will ‘renew’ their own fuel resource as they operate. The consequence of this is that the available resource of fuel for fast neutron reactors is so plentiful that under no practical terms would the fuel source be significantly depleted.
‘Renewables’, as currently defined, would offer no meaningful advantage over fast neutron reactors in terms of availability of fuel supplies. Most also tend to make very large demands on resources to construct the plant used for harnessing the natural energy - per kilowatt hour produced, much more than nuclear power.
DECENTRALISED ENERGY
Centralised state utilities focused on economies of scale can easily overlook an alternative model - of decentralized electricity generation, with that generation being on a smaller scale and close to demand. Here higher costs may be offset by reduced transmission losses (not to mention saving the capital costs of transmission lines) and possibly increased reliability. Generation may be on site or via local mini grids.
RENEWABLES in relation to BASE-LOAD ELECTRICITY DEMAND
It is clear that renewable energy sources have considerable potential to increase their contribution to meeting mainstream electricity needs. However, having solved to problems of harnessing them there is a further challenge: of integrating them into the supply system. Obviously sun, wind, tides and waves cannot be controlled to provide directly either continuous base-load power, or peak-load power when it is needed, so how can other, controllable sources be operated so as to complement them?
If there were some way that large amounts of electricity from intermittent producers such as solar and wind could be stored efficiently, the contribution of these technologies to supplying electicity demand would be much greater. Already in some places pumped storage is used to even out the daily generating load by pumping water to a high storage dam during off-peak hours and weekends, using the excess base-load capacity from low-cost coal or nuclear sources. During peak hours this water can be used for hydro-electric generation. Relatively few places have scope for pumped storage dams close to where the power is needed, and overall efficiency is less than 80%.* Means of storing large amounts of electricity as such in giant batteries or by other means have not been developed.
* Tumut 3 is Australia’s largest pumped storage system. It can store for re-use the equivalent of about 9 million kWh of electricity – the equivalent of a 1 GWe nuclear or coal power plant running for about 6 hours.
There is some scope for reversing the whole way we look at power supply, in its 24-hour, 7-day cycle, using peak load equipment simply to meet the daily peaks. Today's peak-load equipment could be used to some extent to provide infill capacity in a system relying heavily on renewables. The peak capacity would complement large-scale solar thermal and wind generation, providing power at short notice when they were unable to. This is essentially what happens with Denmark, whose wind capacity is complemented by a major link to Norwegian hydro (as well as Sweden and the north German grid).
Case study: West Denmark
West Denmark (the main peninsula part) is the most intensely wind-turbined part of the planet, with 1.74 per 1000 people - 4700 turbines totaling 2315 MWe, 1800 MWe of which has priority dispatch and power must be taken by the grid when it is producing. Total system capacity is 6850 MWe and maximum load during 2002 was 3700 MWe, hence a huge 81% margin. In 2002, 3.38 billion kWh were produced from the wind, a load factor of 16.8%. The peak wind output was 1813 MWe on 23 January, well short of the total capacity, and there were 54 days when the wind output supplied less than 1% of demand. On two occasions, in March and April, wind supplied more than total demand for a few hours. In February 2003 during a cold calm week there was virtually no wind output. Too much wind is also a problem - over 20 m/s output drops and over 25 m/s turbines are feathered. Generally, a one metre/second wind change causes a 320 MWe power change for the whole system.
However, all this can be and is managed due to the major interconnections with Norway, Sweden and Germany, of some 1000 MWe, 600 MWe and 1300 MWe respectively. Furthermore, especially in Norway, hydro resources can normally be called upon, which are ideal for meeting demand at short notice. (though not in 2002 after several dry years). So the Danish example is a very good one, but the circumstances are far from typical.
Case study: Germany
The 2006 report from a thorough study commissioned by the German Energy Agency (DENA) looked at regulating and reserve generation capacity and how it might be deployed as German wind generation doubled to 2015. The study found that only a very small proportion of the installed wind capacity could contribute to reliable supply. Depending on time of year, the gain in guaranteed capacity from wind as a proportion of its total capacity was between 6 and 8% for 14.5 GWe total, and between 5 and 6% for 36 GWe total projected in 2015. This all involves a major additional cost to consumers.
Case study: UK
The performance of every UK wind farm can be seen on the Renewable Energy Foundation web site. Note particularly the percentage of installed capacity which is actually delivering power averaged over each month.
However, if hydro is the back-up and is not abundant then it will be less available for peaking loads. If gas is the back-up it this may be the best compromise between cost and availability. If brown coal generating plant is the back-up and thus has to be run at lower output to accommodate the wind-generated input then the CO2 emissions per kWh increase, eroding or even eliminating any emission advantage from wind. In Germany brown coal plants need to be run inefficiently to back up wind capacity and this has both cost and CO2 implications (see below).
In practical terms non-hydro renewables are therefore able to supply up to some 15-20% of the capacity of an electricity grid, though they cannot directly be applied as economic substitutes for most coal or nuclear power, however significant they become in particular areas with favourable conditions. Nevertheless, they will make an important contribution to the world's energy future, even if they cannot carry the main burden of supply. The Global Wind Energy Council expects wind to be able to supply between 10.8 and 15.6% of global electricity by 2030.
A 2005 report on wind energy in Germany by E.On, the country's largest grid operator, pointed out that: "As wind power capacity rises, the lower availability of the wind farms determines the reliability of the system as a whole to an ever increasing extent. Consequently the greater reliability of traditional power stations becomes increasingly eclipsed. As a result, the relative contribution of wind power to the guaranteed capacity of our supply system up to the year 2020 will fall continuously to around 4%. In concrete terms, this means that in 2020, with a forecast wind power capacity of over 48,000 MW in Germany (Source: DENA grid study), 2,000 MW of traditional power production can be replaced by these wind farms." Hence "traditional power stations with capacities equal to 90% of the installed wind power capacity must be permanently online in order to guarantee power supply at all times." Wind energy cannot replace conventional power stations to any significant extent.
Intermittency and grid management
Grid management authorities faced with the need to be able to dispatch power at short notice treat wind-generated power not as an available source of supply which can be called upon when needed but as an unpredictable drop in demand. In any case wind needs about 90% back-up, whereas the level of back-up for other forms of power generation which can be called upon on demand is around 25%, simply allowing for maintenance downtime.
Improved ability to predict the intermittent availability of wind enables better use of this resource. In Germany it is claimed that wind generation output can be predicted with 90% certainty 24 hours ahead. This means that it is possible to deploy other plant more effectively so that the economic value of that wind contribution is greatly increased.
The high cost of wind power plus the need for substantial back-up gives rise to very high system generating costs by present standards, but in some places it may be the shape of the future.
Modeling done by the UK National Grid Corporation shows the effect of wind's unreliability on the required plant for achieving the 20% UK renewables target:
Thus, building 25 GWe of wind capacity - approximately equal to the present world total and equivalent to almost half of UK peak demand, will only reduce the need for conventional fossil and nuclear plant capacity by 6.7%. Also, some 30 GWe of spare capacity will need to be on immediate call continuously to provide a normal margin of reserve and to back up the wind plant's inability to produce power on demand - about two thirds of it being for the latter.
Ensuring both secure continuity of supply (reliably meeting peak power demands) and its quality (no voltage drops etc) means that the actual potential for wind and solar input to a system is severely limited. Doing so economically, as evident from the above UK figures, requires low-cost back-up such as hydro, or gas turbine with cheap fuel. For the UK, with little interconnection beyond its shores, a 20% renewables target is difficut.
In a March 2004 report Eurelectric and the Federation of Industrial Energy Consumers in Europe pointed out that "Introducing renewable energy unavoidably leads to higher electricity prices. Not only are production costs substantially higher than for conventional energy, but in the case of intermittent energy sources like wind energy, grid extensions and additional balancing and back-up capacity to ensure security of supply imply costs which add considerably to the end price for the final consumer." "Reducing CO2 by promoting renewable energy can thus become extremely expensive for consumers," though both organisations fully support renewables in principle. The economic disadvantage referred to will also be reduced as carbon emission costs become factored in to fossil fuel generation.
Because wind turbine output is so variable, for planning purposes its potential output is discounted to the level of power that can be relied upon for 90% of the time. In Australia that figure comes to 7% of installed wind capacity, in Germany it is 8%, which is all that can be included as securely available (ie 90% of the time).* On the 90% availability basis, other technologies can be counted on for much higher reliability, and hence the investment cost per kilowatt reliably available is much less.
* Figures from NEMMCO and E.ON respectively.
A 2006 report by the UK Energy Research Council looked at the system implications and costs of intermittent inputs from renewables whose variability was uncontrollable. It found that intermittent sources meeting up to 20% of electricity demand need not compromise reliability, but was likely to have a significant cost. The report looked at system balancing impacts, in managing fluctuations from system balancing reserves, and reliability impacts which affected ability to meet peak demand and also required a greater system margin (15-22% higher). It costed the former at £2-3/MWh and the latter at £3-5/ MWh - total £5-8 (0.5p to 0.8p/kWh) with 20% wind input.
If electricity cannot be stored on a large scale, the next logical step is to look at products of its use which can be stored, and hence where intermittent electricity supply is not a problem.
THE HYDROGEN ECONOMY
Hydrogen is widely seen as a possible fuel for transport, if certain problems can be overcome economically. It may be used in conventional internal combustion engines, or in fuel cells which convert chemical energy directly to electricity without normal burning.
Making hydrogen requires either reforming natural gas (methane) with steam, or the electrolysis of water. The former process has carbon dioxide as a by-product, which exacerbates (or at least does not improve) greenhouse gas emissions relative to present technology. With electrolysis, the greenhouse burden depends on the source of the power.
With intermittent renewables such as solar and wind, matching the output to grid demand is very difficult, and beyond about 20% of the total supply, apparently impossible. But if these sources are used for electricity to make hydrogen, then they can be utilised fully whenever they are available, opportunistically. Broadly speaking it does not matter when they cut in or out, the hydrogen is simply stored and used as required.
A quite different rationale applies to using nuclear energy (or any other emission-free base-load plant) for hydrogen. Here the plant would be run continuously at full capacity, with perhaps all the output being supplied to the grid in peak periods and any not needed to meet civil demand being used to make hydrogen at other times. This would mean maximum efficiency for the nuclear power plants, and that hydrogen was made opportunistically when it suited the grid manager.
About 50kWh is required to produce a kilogram of hydrogen by electrolysis, so the cost of the electricity clearly is crucial.
ENVIRONMENTAL ASPECTS
Renewable energy sources have a completely different set of environmental costs and benefits to fossil fuel or nuclear generating capacity.
On the positive side they emit no carbon dioxide or other air pollutants (beyond some decay products from new hydro-electric reservoirs), but because they are harnessing relatively low-intensity energy, their 'footprint' - the area taken up by them - is necessarily much larger.
Whether Australia could accept the environmental impact of another Snowy Mountains hydro scheme (providing some 3.5% of the country's electricity plus irrigation) is doubtful. Whether large areas near cities dedicated to solar collectors will be acceptable, if such proposals are ever made, remains to be seen. Beyond utilising roofs, 1000 MWe of solar capacity would require at least 20 square kilometres of collectors, shading a lot of country.
In Europe, wind turbines have not endeared themselves to neighbours on aesthetic, noise or nature conservation grounds, and this has arrested their deployment in UK. At the same time, European non-fossil fuel obligations have led the establishment of major offshore wind forms and the prospect of more.
However, much environmental impact can be reduced. Fixed solar collectors can double as noise barriers along highways, roof-tops are available already, and there are places where wind turbines would not obtrude unduly.
APPENDIX: Government Support for Renewables Deployment
In an open market, government policies to support particular generation options such as renewables normally give rise to explicit direct subsidies along with other instruments such as feed-in tariffs, quota obligations and energy tax exemptions. In the EU, feed-in tariffs are widespread.
Corresponding to these in the other direction are taxes on particular energy sources, justified by climate change or related policies. For instance Sweden taxes nuclear power at about EUR 0.6 cents/kWh.
European Environment Agency figures in 2004 gave indicative estimates of total energy subsidies in the EU-15 for 2001: solid fuel (coal) EUR 13.0, oil & gas EUR 8.7, nuclear EUR 2.2, renewables EUR 5.3 billion.
The Global Wind Energy Council (2008) reported that "In the pursuit of the overall target of 21% from renewable electricity by 2010, the Renewable Electricity Directive 2001 gives EU Member States freedom of choice regarding support mechanisms. Thus, various schemes are operating in Europe, mainly feed-in tariffs, fixed premiums, green certificate systems and tendering procedures. These schemes are generally complemented by tax incentives, environmental taxes, contribution programs or voluntary agreements."
France has a feed-in tariff of EUR 8.2 c/kWh to 2012, which then will decrease.
Germany's Renewable Energy Sources Act gives renewables priority for grid access and power dispatch. It is regularly amended to adapt feed-in tariffs to market conditions and technological developments. For wind energy an initial tariff applies for up to 20 years and this then reduces to a basic tariff of EUR 5.02 c/kWh. The initial tariff is EUR 9.2 c/kWh for onshore wind and 15 c/kWh for offshore wind from January 2009. The combined subsidy from consumers and government totals some EUR 5 billion per year - for 7.5% of its electricity.
Denmark has a wide range of incentives for renewables and particularly wind energy. It has a complex 'Green Certificate' scheme which transfers the subsidy cost to consumers. However, there is a further economic cost borne by power utilities and customers. When there is a drop in wind, back-up power is bought from the Nordic power pool at the going rate. Similarly, any surplus (subsidised) wind power is sold to the pool at the prevailing price, which is sometimes zero . The net effect of this is growing losses as wind capacity expands.
Italy in 2008 legislated to provide EUR 18 c/kWh on a quota system for wind power.
Spain has different levels of feed-in tariffs depending on the technology used. A fixed tariff of EUR 7.32 c/kWh is one option, or a fixed premium of 2.93 c/kWh on the market price (but with a floor of 7.13 cents) is the other, as of 2008. The tariffs for renewables are adjusted every four years.
Greece has a feed-in tariff of 6.1-7.5 c/kWh, whereas the Netherlands relies on exemption from energy taxes to encourage renewables.
The UK has not used any feed-in tariff arrangement, but is to do so from 2010. Meanwhile a specific indication of the cost increment over power generation from other sources is given by the 4.5 - 5.0 p/kWh market value for the Renewables Obligation, by which utilities can cover the shortfall in producing a certain proportion of their electricity from renewables by paying this amount and passing the cost on to the consumer. In addition there is a Climate Change Levy of 0.43 p/kWh on non-renewable sources (at present including nuclear energy, despite its lack of greenhouse gas emissions), which corresponds to a subsidy.
Sweden subsidises renewables (principally large-scale hydro) by a tax on nuclear capacity, which works out at about EUR 0.67 cents/kWh from 2008. For wind, there is a quota system requiring utilities to buy a certain amount of renewable energy by purchasing certificates.
In Norway the government subsidises wind energy with a 25% investment grant and then production support per kWh, the total coming to NOK 0.12/kWh, against a spot price of around NOK 0.18/kWh (US$ 1.3 cents & 2 cents respectively).
In the USA the wind energy production tax credit (PTC) of 1.5 c/kWh indexed to inflation (now about 2.1 c/kWh) has provided incentive, though this expires every two years before being renewed by Congress.
Canada provides a production incentive payment of 1c/kWh for wind power, plus feed-in tariffs.
In Australia energy retailers are required to source specified quantities of power from new (non hydro) renewables. The obligation is tradeable and there is a fallback tax of AUD 4 c/kWh for retailers failing to comply.
In India ten out of 29 states have feed-in tariffs, eg 2.75 times the tariff for coal-generated power in Karnataka, plus a federal incentive scheme paying one third of the coal-fired tariff.
Small-scale PV input is encouraged by high feed-in tariffs, eg 48 c/kWh in Germany and 50 c/kWh in Portugal.
Sources:Boyle, G (ed), 1996, Renewable Energy - Power for a Sustainable Future, Open University, UKOECD IEA (1987) Renewable Sources of EnergyEuropean Wind Energy Association + Greenpeace (2002), Wind Force 12.Duffey & Poehnell, 2001, Hydrogen production, nuclear energy & climate change, CNS Bulletin 22,3.Laughton, M.A. 2002, Renewables and the UK Electricity Grid Supply Infrastructure, Platts Power in Europe.Sharman, H. 2003, Danish Lessons, www.countryguardian.netEurelectric 25/3/04, www.eurelectric.orgOECD IEA 2008 World Energy OutlookUK Energy Research Centre, 2006, The Costs and Impacts of Intermittency.E.On Netz Wind report 2005 DENA 2006 Grid Study.Global Wind Energy Council, 2008 Annual Report