environmentalresearchweb blog
March 13, 2010
Selling Green Power
Under Ofgem’s new ‘Green Energy Supply’ Guidelines, launched in February, suppliers offering ‘green electricity’ to consumers under the voluntary tariff system must demonstrate that their green tariff involves a commitment above and beyond what is required from existing Government targets for sourcing renewable electricity and reducing emissions. In most cases that will involve some sort of fund to support additional projects, which might include community-scaled renewables or energy saving projects, or even carbon offsetting projects.
The rules for domestic tariffs in the new scheme require that offsetting projects save or avoid the emission of at least 1 tonne of carbon a dioxide equivalent annually, and 50kg of CO2 equivalent emissions p.a. for all other environmental activities, such as community-scaled renewable electricity projects, these all having to be additional to that saved from any existing programmes e.g. as counted within the Renewable Obligation (RO). Basically they can’t just use power already credited under the RO. To meet the new rules they must do more, and the new scheme provides specifications, which will be accredited by an independent panel, overseen by the National Energy Foundation. See: www.greenenergyscheme.org
The voluntary green power market has always sat uneasily on the margins of the UK Renewables market- which is driven by the Renewable Obligation. All electricity consumers already pay their suppliers extra for that, so the voluntary green power schemes have to offer something else to give extra value - they just can’t charge extra twice for the same electricity used to meet the suppliers RO requirements. Most suppliers have already been offering additional green benefits to justify premium prices- some have set up funds to support green projects. But not all have charged more. For example, npower set up a self -financed fund for its Juice scheme to support new marine renewables projects- it’s reached over £2m so far.
Quite a range of schemes have emerged, with there being some confusion and indeed scepticism about the validity of some of the claims to ‘green-ness’ being made. The new rules puts these schemes, and the additional elements, on a more formal basis.
All the large main suppliers- British Gas, E.On, EDF Energy, RWE Npower, Scottish and Southern Energy and Scottish Power, and linked groups, have signed up to the new scheme, as well as independent supplier Good Energy.
Unlike the ‘big six’ suppliers, who also sell non-green power, Good Energy buys in and sells 100% green power from mostly local independent sources- and retires any Renewable Obligation Certificates (ROCs) it gets, rather than selling them on. So it claims that it will help renewables to expand, since the value of ROCs will rise proportionately. The other main independent, Ecotricity, sells a roughly 50/50 mix of green/conventional power, which it sees as being reasonable since it is still four times as much green power than currently required by the RO targets. It also charges a premium green tariff rate, but says the income helps it to invest in new renewable energy projects- and it certainly has been pushing ahead with major wind projects.
However Ecotricity has been very critical of the new OFGEM scheme and has not joined. It argues that the renewable energy used under the new tariffs will still all come from Britain’s same pool of RO linked renewable electricity, which meant that the big energy companies would not be required to build any extra major source of renewable energy. They will simply provide added-on schemes such as carbon offsetting, help with micro-generation or energy efficiency schemes.
When the guidelines were first proposed last year, Ecotricity’s CEO Dale Vince said: ‘In these guidelines Ofgem are accrediting everything you can imagine except the thing that really counts- green electricity. Of course we believe in planting trees, protecting wildlife and cutting carbon, all of these things have an important role to play- but not in green tariffs. Green tariffs and consumer choice of green-tariffs- people power- could play a crucial role helping us to reach government renewable energy targets. But Ofgem have sidelined the consumer in one fell swoop by excluding real green electricity from their definition of so-called green-tariffs.’
After the launch earlier this year he reaffirmed his view: ‘Green electricity tariffs should be about more than feel-good charity schemes. If suppliers want to plant trees or even help old ladies across the road, I’m all for that but not under the guise of green electricity. Ofgem’s new ‘rules’ set an artificial standard of what green electricity really is. This can only result in them becoming an expensive niche product in a charity ghetto, doing more harm than good. Consumers will get poorer, but Britain won’t get any greener as a result of this’.
That may be overstated, after all the new scheme does require real carbon emission reductions, but he may be right in principle- while some small community project may get some support, it won’t lead to extra capacity in the mainstream renewables sector. Basically the problem is that the government wants the Renwables Obligation to be the main vehicle for supporting renewables and sees the green consumer tariff as additional and voluntary. Certainly, so far, the uptake has been marginal- only about 2% of UK consumers have signed up to such schemes. What’s not clear is what will happen when the new Feed-In Tariffs (FiTs) for small projects come on line from April onwards . Since it’s outside the RO, will that power, including some from community projects, be available for ‘voluntary’ tariff schemes? That might change things, even though the FiT is also only seen as a small, marginal exercise, leading to at most to 2% contribution to UK electricity by 2020.
Elsewhere in the EU, Feed In Tariffs and green energy certificates schemes used by consumers are taken seriously, and have had major impacts. I the UK though they are still seen as marginal- the focus remains on the competitive market orientated RO, despite the fact that, so far, this has been poor at delivering much renewable energy capacity.
For more on renewable energy developments and policies see Renew: www.natta-renew.org
March 9, 2010
The smallprint of the RFS2 renewable fuel standard
As by volume the most relevant renewable fuel standard world wide, a closer look at the details of this regulation is worthwhile - to understand the issues behind decarbonization policies in transport. The RFS2 details that
“EPA is making threshold determinations based on a methodology that includes an analysis of the full lifecycle of various fuels, including emissions from international land-use changes resulting from increased biofuel demand. EPA has used the best available models for this purpose, and has incorporated many modifications to its proposed approach based on comments from the public, a formal peer review, and developing science. EPA has also quantified the uncertainty associated with significant components of its analyses, including important factors affecting GHG emissions associated with international land use change.”
Specific lifecycle GHG emission thresholds for each of four types of renewable fuels were established, requiring a percentage improvement compared to lifecycle GHG emissions for gasoline or diesel. One of these fuels, ethanol produced from corn starch produced at a new natural gas facility using advanced efficient technologies will meet the 20% reduction threshold compared to the 2005 gasoline baseline (says EPA). Other fuels meet the 50% or 60% benchmark.
While the life cycle methodology of the EPA if fairly comprehensive, a few important caveats were noted in a review of the RFS2 by Richard Plevin:
- EPA performs its analysis in a projected 2022 world, assuming a variety of technology changes. This is similar to accounting for today’s emissions from coal power plants as if they had implemented anticipated CCS technology. In 2012 all and in 2017 most corn ethanol pathways analyzed by the EPA do not meet the 20% GHG reduction requirement, or even produce greater GHG emissions than the gasoline baseline.
- In the EPA model corn ethanol achieves productivity gains without additional use of fertilizer. The peak of corn ethanol production is achieved in 2016 - inducing most ILUC - while productivity assumptions refer to 2022 with additional 9.4% crop yield. Hence, ILUC are systematically underestimated.
- EPA attributes large soil carbon sequestration to biodiesel, most likely for increased used of no-till. However, no-till may increase N2O emissions (Six et. al). There is uncertainty on this issue, but EPA treats net soil carbon sequestration as a fact.
- Cellulosic ethanol obtains a low GHG rating by co-product credits generated by electricity from biochemical cellulosic refineries that displaces the average US grid electricity. Taking the average US grid as benchmark is a courageous assumption. More detailed analysis could significantly change the life cycle emissions.
- An additional supply of biofuels reduces the world market price of petroleum, by this increasing its demand. In one study, the global petroleum effect is estimated to be around 27% implying that each MJ of biofuel replaces 0.73 MJ of petroleum (Stoft, 2009). Hence, biofuels that are less then 27% below gasoline baseline could have a net positive global warming effect. This effect is acknowledged but not modeled by EPA.
In summary, EPAs carbon accounting should be taken with some care. In particular, today’s corn ethanol may have higher than baseline gasoline GHG emissions (e.g., Hertel et al., 2010). By focussing on potential 2022 technologies, this emission disbenefit is insufficiently reflected. Some policy maker pressure the EPA with respect to corn ethanol, arguing that corn ethanol production decreases energy independence and produces jobs. However, from this perspective, pro-corn ethanol policies should be designed from the perspective of jobs and energy independence, rather than using the RSF2 as camouflage.
References
Hertel, T. W., A. Golub, et al. (2010). “Global Land Use and Greenhouse Gas Emissions Impacts of U.S. Maize Ethanol: Estimating Market-Mediated Responses.” BioScience 60(3): 223-231.
Plevin, R. J., M. O’Hare, et al. (forthcoming). The greenhouse gas emissions from market-mediated land use change are uncertain, but potentially much greater than previously estimated, UC Berkeley.
Six, J., S. M. Ogle, et al. (2004). “The potential to mitigate global warming with no-tillage management is only realized when practised in the long term.” Global Change Biology 10(2): 155-160.
Stoft, S. (2009). “The Global Rebound Effect Versus California’s Low-Carbon Fuel Standard”
March 8, 2010
Ice arches and positive feedback
The shrinking extent of sea ice in the Arctic has been a cause of concern for some decades, and the record low extent measured with passive-microwave radiometers in September 2007 gathered a good deal of publicity. The September minimum was 7.11 million km2 on average during 1979-1998. In 2007 it was 4.30 million km2. The two minima since then have each been greater. 2008 saw the second lowest and 2009 the third lowest extent.
You can check out the state of Arctic sea ice at the National Snow and Ice Data Center in Boulder, Colorado. Thus far during the present winter, 2009-2010, the extent has been tracking pretty closely the course followed in 2007, so two successive years of increased minimum annual extent do not justify us in concluding that the ice pack might be recovering. Equally, there is no sign of an impending catastrophe at the top of the world, but we would still like to understand why 2007 was a record-breaker. There have been several interesting attempts to explain it.
A particularly interesting attempt by Ron Kwok and colleagues appeared last month. They focus on a detail of the bigger picture, the outflow of sea ice through Nares Strait, the narrow gap between northwest Greenland and Ellesmere Island. To put this study in context, we need to step up from thinking about sea-ice extent to thinking about sea-ice mass.
Very roughly, the ice is 3 m thick on average, for a total mass each average September of about 19 million gigatonnes (but only 12 million Gt in 2007). The mass of the ice pack is the result of a balance between freezing, melting and export. The exported bergs and floes eventually melt, but not within the Arctic Ocean.
Most of the export, about 2000 Gt/yr, is through Fram Strait, between Greenland and Svalbard. Of the other possible outlets, the channels between the islands of the Canadian arctic archipelago contribute little. Apart from being narrow, they are most often blocked at their northward ends by plugs or “arches” of immobile ice. The arches form during the winter and persist until the end of summer, so that for much of the year there is effectively no southward ice export.
Kwok and colleagues found that no arch formed in 2007 at Nares Strait, which was therefore an open passageway for the full 365 days. Between 1998 and 2006, the open-channel state prevailed for only 140 to 230 days per year. From 2004 to 2006, when ice thickness measurements are available from the ICESat laser altimeter, the mass export was about 80-85 Gt/yr, but in 2007 it was 230 Gt/yr.
Why worry about such tiny amounts? The export through Nares Strait in 2007 was only 10% of that through Fram Strait, and insignificant in comparison with the total mass of the pack. The answer is that the ice in the Lincoln Sea, just north of Nares Strait, is some of the thickest, at about 5 m on average, in the whole Arctic Ocean.
The decline of Arctic sea ice is usually discussed in terms of its extent, but that is mainly because we have lots of information about extent. Measurements of thickness are harder to come by, and therefore so are estimates of total mass (area times thickness, multiplied by 900 kg m-3, the density of ice). But one of our main concerns about Arctic sea ice is that apart from shrinking in extent it is also getting thinner.
The impact on ice extent of the free evacuation of thick Lincoln Sea ice in 2007 was small, but it depleted the thick end of the frequency distribution of ice thickness. An ice pack with relatively more thin ice is less likely to survive the summer melt season, so the non-formation of ice arches in Nares Strait constitutes a positive feedback, magnifying the vulnerability of the ice pack as a whole. And it may be a positive feedback in another sense. Presumably arching, that is, blockage, is more likely when the supply of thick chunks of ice is greater. If an episode of free outflow decreases that supply, future episodes of free outflow become more probable.
March 6, 2010
FiT for purpose?
The debate on the UK’s new Feed-In Tariff (FiT) has been quite lively, with the Guardian’s George Monbiot arguing that, with solar PV being still very expensive, the way the FiT provided the support needed was economically regressive.
It does look that way at first glance – those that could afford to invest say £10,000 in PV might get £1000 p.a. back for the electricity they generated and used, paid for by all the other consumers, who would be charged extra via their electricity bills. It’s been suggested that this would lead to a £11 p.a. surcharge on bills by 2020.
However, in a rebuttal to Monbiot’s analysis, Jeremy Leggett from Solar Century said “the average household levy in 2013, when tariff rates are all up for review, is likely to be less than £3” and he added “this is far less than the average saving from the government’s various domestic energy efficiency measures over the same period. So there is no net subsidy. The levy is not ‘regressive’ at all”.
The extra cost is certainly small, since the expected size of the FiT scheme is small, only maybe leading to 2% of UK electricity by 2020, so maybe this is not a major issue. But it is good to see that the government has now announced a “green-energy loan” scheme (part of its new “Warm Homes, Green Homes” strategy) under which energy-supply companies and others (e.g. the Co-op) may offer consumers zero or low interest loans for installing new energy systems, to be paid back out of the resultant energy savings. Details have yet to be agreed, but up to £7 bn may be made available over the next decade in this way – although it seems it will start off slowly, from 2012 onwards.
This scheme could help the less well-off to invest in new energy technologies like PV, and join in the FiT. Providing up-front loans via a “pay-and-you-save” system certainly seems likely to be more effective at ensuring wide uptake than just using revenue over time from a FiT. And there would be no extra charges on the taxpayer or the other consumers. So it could be popular.
There does seem to be a lot of support for self-generation. A YouGov survey for Friends of the Earth, the Renewable Energy Association and the Cooperative Group found that 71% of homeowners who were asked said that they would consider installing green-energy systems if they were paid enough cash. So perhaps, one way or another, uptake will be significant.
However, there are still some uncertainties. I argued in an earlier blog, before the UK FiT details emerged, that, while it worked very well for wind in Germany, using a FiT to push PV down its learning curve, to lower prices, might not be the most effective approach for PV.
Now we have the details of the tariff, which has set the price for PV so that those who install it get the same rate of return as those using other cheaper options. This may be fine if you are desperate to get PV accelerated. That’s a matter of judgment. For electricity, in the UK context, large-scale on-land and off-shore wind is clearly a better bet for the moment in terms of price, and also the scale of the resource. But PV prices are falling, and it could well be next in line for expansion, helped by the FiT, plus the loan scheme. Certainly there are benefits: localized generation using micro-power units like PV do avoid long-distance transmission losses, which can amount to up to 10% across the whole UK, and that is important.
However, domestic micro-generation has it limits – it’s arguably the wrong scale. PV is one of the better ones – there are no real technical economies of scale, except via bulk buying and sharing installation costs for larger projects. But micro wind is only relevant in a very few urban UK locations – larger grid-linked machines in windy places are so much more efficient and cost effective. Solar heating (to be supported under the forthcoming Renewable Heat Incentive) maybe be the best domestic option, but even then there are economies of scale (e.g. for grouped-solar schemes sharing a large heat store or even solar-fed district heating). Micro Combined Heat and Power (CHP) similarly: larger-scale mini or macro CHP, linked to district heating networks, are arguably more sensible.
Fortunately the 5 MW UK FiT ceiling, though low, gives us a chance to operate at slightly larger community scale, which may redeem the whole thing. See the excellent Energy Saving Trust report Power in Numbers, which states that “the economics of all distributed energy technologies improve with increasing scale, leading to lower cost energy and lower cost carbon savings and justifying efforts for community energy projects”. And for some smaller-scale renewables, it adds that “it is only when action occurs at scales above 50 households, and ideally at or above the 500 household level, that significant carbon savings become available”.
March 1, 2010
The first ice in Antarctica
Palaeogeography is a seductive subject. The appeal of conjuring a vanished landscape out of a few strands of evidence and a good deal of restrained conjecture is irresistible. We know that the reconstructed world is imaginary, but with right treatment of the evidence, under the right constraints, we also know that it must represent a realistic approximation to the way things were.
That is what Douglas Wilson and Bruce Luyendyk appear to have done for West Antarctica at the end of the Eocene, about 34 Ma (million years ago). Records of oxygen isotope ratios in the microfossils preserved in deep-sea sediment suggest that glacier ice began to accumulate in Antarctica at about that time. But models of the palaeoclimate have trouble simulating as much ice on East Antarctica as the isotopes suggest. East Antarctica, palaeoclimatically interesting in itself but not our focus here, is the larger, higher part of the continent.
West Antarctica is not big enough to house the missing ice. Most of it is below sea level. The prevailing wisdom is that you can’t grow a marine ice sheet — that is, one with its bed below sea level — from scratch, at least not quickly. So, assuming we are reading the isotopes aright, where was the missing ice?
Enter Wilson and Luyendyk . Their geography of West Antarctica as it may have been at 34 Ma offers a persuasive answer: most of it wasn’t below sea level back then.
The first step in the palaeogeographic reconstruction, starting from a map of the modern ice thickness, is to remove the ice and allow the underlying lithosphere to recover from the removed load, rebounding and flexing. You have to juggle with the calculated new surface elevations because in some parts, where the new surface is below sea level, the place of the ice load is taken by a new load of ocean water. This requires care, but it is not a deep problem. On the other hand the result isn’t much help. Most of West Antarctica remains under water.
The second step is to account for thermal contraction of the lithosphere. As constrained by palaeomagnetic and other measurements, the main feature of the tectonic-plate system around here until about 28 Ma, the West Antarctic Rift System, was the surface expression of the rising limb of a convection cell in the Earth’s mantle. The convection stretched the overlying lithosphere while causing the two sides of the rift to spread apart. Now too high for the fluid mantle rock supporting it, the lithosphere subsided gradually. Wilson and Luyendyk estimate that the subsidence since 34 Ma has varied from 200 to 500 m across West Antarctica.
Apart from correcting for the subsidence, you also have to undo the stretching, moving the Pacific side of the rift some tens of kilometres back towards the East Antarctic side.
A lot of erosion can happen in 34 million years. How do you restore a landscape that has ceased to exist? The answer is that we know, first of all, that the erosive products go downhill, and second that they have to end up somewhere. Most of them end up as sediment offshore, and not too far away. Wilson and Luyendyk rely on sediment thickness estimates for this, their third step. Not all of the sediment is due to erosion, a good deal of it being the fossils of marine microorganisms, and the eroded rock would have been more dense than the deposited sediment. Nevertheless, their approach is very conservative. The volume they restore is only 13% of the volume of offshore sediment.
This step also requires corrections for rebound and subsidence. Shifting loads of sediment are just like shifting loads of water and ice when it comes to the response of the underlying lithosphere.
In the end, Wilson and Luyendyk found another 1.5 million km2 of land, turning the West Antarctica of 34 Ma from an archipelago into a landmass. This plausible landmass, imaginary as it is, is consistent with all the evidence and is constrained by basic principles of physics. In turn it makes what the isotope records imply, that there was quite a lot of ice at 34 Ma, more plausible.
Getting beyond plausibility is a challenge, but one that would be worth rising to because it would allow us to move on to the next questions. Why so much ice? And why then and not earlier or later?
February 27, 2010
Water-footprint measure can be locally and temporally specific, but isn’t used that way
I just attended the conference Understanding, Measuring, and Managing Water Scarcity Risks and Footprints in the Supply Chain this past week. This conference was primarily attended by sustainability managers of corporations along with a few academics and non-governmental organizations. There was much discussion of how to measure water impacts of industry as well as how to act on measured or calculated information. Many of the speakers and attendees were familiar with several methods for measuring water “usage” such as the Water Footprint (www.waterfootprint.org) and the Global Water Tool of the World Business Council on Sustainable Development (www.wbcsd.org/web/watertool.htm). The former presents information on the green water (soil moisture for the most part provided by precipitation) and blue water (stored water in rivers, lakes, and aquifers) consumed in the supply chain of a product. The latter is a mapping program that allows businesses to understand if they have operations in regions of the globe that have water scarcity.
There was general agreement within the community that the Water Footprint is not properly used as Jason Morrison of the Pacific Institute summarized by saying “different interests use the term ‘water’ footprint’ to mean different things” for their own purposes. Technically speaking, the water footprint is in units of water volume per time. By multiplying by the time per product manufactured, one can obtain the water footprint in units of water per product. This last term is the one most commonly presented in such examples as the quantity of water needed for a pair of jeans or a cup of coffee. This water volume per product is a handy unit of measure that consumers and business people can easily grasp. The problem is that it doesn’t seem to be helping either water resource management practitioners or sustainability managers at companies.
The issue stems from culminating into one term the water consumed over a supply chain that occurs in time and in space. If your supply chain for a product occurs in more than one location and/or at more than one time, then by definition you cannot capture all of that information into a single number. Mathematically this is like taking the derivative of a number. Each time you take the derivative, you lose one degree of freedom or information. For example, the volume of a sphere is described as V = 4/3*pi*r^3 and is in units of cubic meters (m^3) to describes a three-dimensional space. Taking the derivative of volume with respect to its radius results in the surface area of the sphere at A = 4*pi*r^2 in units of square meters (m^2) to describe a two-dimensional space. Hence we went from three dimensions to two dimensions. If I show only the final value for the surface area of the sphere, say 1 m^3, I do not know that a sphere is being described. However, if tell you the equation for the sphere’s surface area and tell you it is equal to 1 m^2, then you know how to calculate the volume (or radius) because I have just provided more information that told you about the third dimension.
What does this have to do with water footprinting? Well, similarly to needing to know more than one piece of information about the surface area being described (need two of either equation, radius, and surface area) to know it is for a sphere, you need more than a single value for the water footprint of a product to understand the environmental impact caused by its production. For example, if a shirt requires water during farming of cotton and dyeing of the fibers, then one could present the information in two numbers on a bar chart (among many other means for presenting information). Part of the bar chart would represent the cotton farming, and the other part would represent the dyeing step. By telling people where you source your cotton and where you perform your dyeing, you have now presented more information – information again that cannot be understood using a single value. I have just described four pieces of information: water for cotton, water for dyeing, location for cotton, and location for dyeing. A map with the water consumption value in each location the water is consumed could present all four pieces of this information. I could go on for temporal components. The World Water Tool exists to take the information described in this paragraph to relate to water scarcity around the globe. They of course use a map for this.
This thought exercise is meant to show that people understand that describing environmental impacts is somewhat complex. In describing water flows for human appropriated needs, from a basic standpoint we should focus on avoiding the word “use” to describe water flows. Instead, use “consumption” to describe water that enters the system as a liquid and exits as water vapor or in another chemical form. Use “withdrawal” to describe water entering and exiting the system in a liquid form, and note that consumption is a subset of withdrawal. The water footprint is a consumptive descriptor that for the most part includes evapotranspiration (green water) on top of what the term consumption (the blue water component) takes into account. If we stick to some of these basic rules, we can better understand how human and ecosystem services are subjected risks in water availability.
Tides come in
The use of tidal energy for generating electricity is moving ahead rapidly around the world, and the potential for expansion is significant, with the emphasis being on tidal current turbines, although some tidal barrages are also being developed or planned – for example, various barrage and lagoon scheme are still under consideration for the Severn estuary. A decision on which to go for should emerge later this year.
The global potential is quite large. Trade network Tidal Today’s second annual ‘Tidal Summit’, held in London last November, heard from a speaker from the Fraunhofer Institute for Wind Energy and Energy System Technology (IWES) who relayed some estimates of tidal energy potentials: China: 50 TWh p.a; Ireland: 10 TWh; UK: 31 TWh; France: 10 TWh; Norway: 3 TWh; US: 115 TWh. The big ones, in terms of capacity, included Canada: >40 GW and South Korea: 1000 GW.
In terms of tidal turbine development and deployment, the UK still leads the pack, with Marine Current Turbines’ 1.2 MW Seagen in Strangford Narrows to be followed soon by a 10MW tidal farm off Anglesey – MCT has just got £4.8 m from Siemens, EDF Energy, HighTide and others for the next stage. Meanwhile, the European Marine Energy Centre (EMEC) on Orkney is providing key test facilities for UK devices and systems from overseas. It has the world’s only grid linked tidal test facilities – five open sea births, with 11 kv, 5 MW subsea cables. And, as the Crown Estate noted at the Summit, Scotland has 25% of the available European tidal potential – Pentland Firth and Orkney Waters contain six of the top-10 UK tidal sites. Crown Estates seem to have been taking their time assessing these, but are about to announce site licenses for selected projects. So prospects for the future look good.
One of the leaders of the new projects is Open Hydro’s novel ‘open centre’ rim generator turbine, which was tested at EMEC. There are plans for deployment off Alderney and in the bay of Fundy. Next up, Atlantis Resources Corp, the international marine energy company, is to test its AK-1000™ tidal turbine at EMEC this summer. Tidal Today reported that the AK-1000™ has been designed specifically for harsh marine environments. It features what are claimed to be the world’s most efficient blades – 18 meters rotor diameter – and has minimal moving parts. It should be capable of generating 1 MW of power in a 2.6 m/s tidal current. The company says that it will award contracts associated with the deployment supporting over 100 UK jobs. The AK-1000™ will be its second grid-linked turbine. Its Nereus turbine in San Remo, Australia, first deployed in 2006, still continues to generate power for the grid.
The US is also active in the field. The summit heard updates on Verdant powers seven turbine projects in New York’s East River, and there are several other North American projects, including the Canadian ‘Clean Current’ ducted rotor, which is now being developed in conjunction with Alstom. At the summit it was reported that ‘in September 2006, clean current installed a 3.5 m diameter, 65 kW demonstration unit at race rocks, BC, Canada,’ and that ‘performance met or exceeded expectations’. On-going testing is now being carried out, with a view to installation in the Bay of Fundy.
There’s also a lot happening in South Korea – who seem likely to become the world leader. Developer Voith Hydro noted that tidal range (barrage) projects in planning/execution included Shiwa: 254 MW; Garorim Bay 520 MW; Incheon Bay: 1320 MW, and that the Korean Ministry of Knowledge Economy estimates tidal current potential at 470 MW. Voith are installing 100 MW of its 500–1000 kW propeller type turbine at Jindo, Jeollanamdo Province and there’s also a project involving the UK’s Lunar Energy ducted-rotor system.
But not everyone was quite so positive. RWE npower told the summit that costs and financing were still issues. There was an ‘immature market so commercial costs are not yet apparent’ and ‘utilities won’t loss lead demo projects for uncertain future market – demo projects must promise stand alone economic returns’. There were also ‘inadequate support mechanisms’. And there was a ‘massive offshore wind potential’, whereas tidal ‘has a fair way to go’. Consultants Douglas Westwood evidently felt similarly: they told the summit that it cost about ‘£60 m to take a device through to commercialization’ and felt that the ‘forecast of 41 MW installed capacity by 2013 may be missed’, and that without proper support, tidal might only provide ‘1% of UK power generation capacity by 2030’.
Fortunately, in February the UK government finally got its support system working and has allocated £22 m from its new Marine Renewable Proving Fund (MRPF), to six projects, two wave systems (Osprey and Pelamis) and four tidal current projects – using new turbines from Atlantis, Voith, MCT and Hammerfest Strom UK.
The MRPF is managed by the Carbon Trust, which notes that all of the devices receiving MRPF funding will be deployed in UK waters, and will stimulate supply chain opportunities associated with construction and deployment of these technologies, with over 75% of the funding released through the MRPF going to the UK supply chain.
The MRPF aims to accelerate the development of marine energy devices to the stage when they can qualify for the Government’s existing, but so far unused, £42 m Marine Renewables Deployment Fund (MRDF) support scheme and, ultimately, be deployed on a commercial scale, with support from the Renewables Obligation. MCT’s Seagen has in fact managed to jumped straight to that, after several years of grant aided and independent development, and is now getting 2 ROCs/MWh for its 1.2 MW unit in Strangford Narrows. The new MRPF money means that it, and the other developers, can now get moving on new projects.
In addition to those already mentioned, there is quite a range of projects at the starting gate, or at least under development, with some novel UK designs emerging. Scottish projects are well represented, with for example the Scotrnewables’ floating device and TidalStream Ltd.’s unique tidal turbine platform design – Triton. But Wales is also in the race, with Swanturbines’ Cygnet, developed at Swansea University, and Tidal Energy DeltaStream device, which is to be put through trials at Ramsey Sound, near St Davids.
Humberside is also figuring strongly. For example, following tests on models at the University of Hull, a full-scale prototype of Neptune’s ducted vertical-axis turbine ‘Proteus’ device is being tested in the Humber Estuary at Hull. Pulse Tidal’s hydrofoil device is also under test in the Humber. Its 100 kW test rig currently feeds power to a chemicals company on the banks of the river. Tidal Today reported that it is to receive a grant of €8 m from the EU’s technology research and development fund (Framework Programme 7) to enable the company to begin work immediately on developing its first fully commercial tidal energy generator – a 1 MW unit, to be commissioned in 2012.
Not all of the many new tidal current devices emerging will succeed or get sufficient funding to prove themselves. But there is a mood of pioneering enthusiasm, with developers like Pulse Tidal’s chief executive Bob Smith, being very positive about the future: ‘We have developed an economic way to recover predictable, renewable energy from the tides and are entering a young market predicted to be worth at least £6 bn annually in electricity sales’. He added: ‘The Pulse system is expected to match the cost of offshore wind after only 100 MW has been installed. In the future tidal energy is set to surpass wind as the most economic and predictable source of offshore power.’
* For more information, visit www.tidaltoday.com.
February 22, 2010
Can volcanoes trigger ice ages?
The idea that a super-enormous volcanic eruption — or hypereruption — would alter the climate dramatically has been around for a long time. It fits the facts about the biggest historical eruptions we know of, and also our understanding both of how volcanoes work and how the atmosphere works. But could the drama extend to tipping the climate from an interglacial state to a full-blown ice age?
The answer, as has long been believed, is still No, according to Alan Robock and colleagues in a paper published last year. They added several new kinds of potential cooling mechanism to two climate models, and were unable to trigger an ice age.
When a volcano goes off, it is always unpleasant for those in the immediate neighbourhood. The climatologist’s concern, however, is with the broader consequences. A violent enough eruption can loft its products into the stratosphere, where they can persist long enough to spread around the world.
The main culprit is sulphur dioxide, SO2. It reacts with water vapour to form a haze of sulphuric acid droplets. The droplets increase the scattering of incoming solar radiation, making the atmosphere more reflective and cooling the Earth slightly. The more SO2, the more cooling.
The snag is that the haze doesn’t last. The atmospheric effects of Pinatubo in 1991, the largest eruption of recent times, were detectable for a few years at most.
Krakatau in 1883 was bigger than Pinatubo. Tambora in 1815 was even bigger, and still stands as the largest eruption in the historical record. If we turn to the geological record, the largest eruption we know of is that of Toba in Sumatra, in about 72,000 BC. Toba yielded a quantity of stratospheric SO2 hundreds of times that of Pinatubo, which was about 20 megatonnes.
Robock and colleagues injected 300 “Pinatubos” of SO2 into the baseline run of their models, but also tried amounts as great as 900 Pinatubos. With a dynamic vegetation module, they explored the feedback on global temperatures of widespread death of vegetation due to the volcanic cooling. The feedback was not very impressive. Precipitation dropped markedly, but cooling reached about 10 degrees at most, and recovery was nearly complete after about a decade. Coupling the climate model to an interactive model of atmospheric chemistry, they found that the SO2 reaction products persist for longer and produce greater total cooling — as much as 18 degrees — but still no permanent, ice-age-like change in the climatic state. The cooling was partly offset by warming influences, such as more water vapour and ozone in the stratosphere, and more methane in the troposphere. All of these are greenhouse gases.
One thing that bothers me about the Robock study, which is a step forward, is that it still may not cover all the bases. For example the model runs may not have been long enough to pick up delayed responses of the ocean to reduced inputs of heat during the cooling episode. And the climate models were unable to follow the behaviour of the other sluggish players in the drama, the glaciers themselves.
On the other hand, look at what actually happened. In an older paper, Zielinski and co-authors found a signal from Toba in an ice core drilled in Greenland: about six years of strongly enhanced deposition of sulphate, followed by a 1,000-year long “stadial”. Stadials, identified by looking at ratios of the isotopes of oxygen, are relatively short cool episodes within ice ages. However Toba was preceded by 2,000 years of more moderate cooling, which suggests that the stadial proper might have happened anyway. What is more, the oxygen isotopes repeat a very similar pattern in the 2-3,000 years after the end of the “Toba stadial”: rapid warming, moderate cooling, rapid cooling, with no evidence for volcanism at all. In fact, these two excursions look rather like Dansgaard-Oeschger events.
So we have a plausible but not compelling link between our only known hypereruption and a limited amount of long-term cooling. If a Toba happened tomorrow, it might presage a short stadial, but not a long one, and anyway stadials ought not to be at the top of your list of things to worry about. But on the purely intellectual side, the effort to understand Toba nevertheless bears on an important question. How hard do we have to hit the climate system before it really gets upset, or, putting it another way, what does “tipping point” mean?
February 20, 2010
Radiative-forcing analysis: more mitigation effort in road transport
Carbon dioxide is not the only greenhouse gas. Coemitted air pollutants also significantly affect global climate. By various interactions, their absolute effect can be complicated to evaluate. In principle, however, most air pollutants have a relatively short time span in the atmosphere, and hence, can be classified as short lived species. Many air pollutants, including organic aerosols have a global cooling effect, whereas black carbon and ozone contribute to global warming. The effect of the short lived species is not marginal. In fact, their combined radiative forcing may outweight that of carbon dioxide (Forster et al., 2007). In view of this observation, there is increased attention on the mitigation potential of some air pollutations, such as ozone and black carbon, short lived species with high radiative forcing. On the other hand, there are other aerosols, excluding black carbon, which exert a cooling effect that may have masked about 50% of the global warming by GHG. The fight against air pollution and for public health can, hence, have an unwanted impact by inducing accelerated global warming. Starting with this background, Unger et al. from NASA ask in PNAS in their article Attribution of climate forcing to economic sectors the following question: How is the total radiative forcing effect organized according to economic sector, the drivers of emissions?
The authors point out that emissions of black carbon (positive RF) and organic aerosols (negative RF) are often coupled. Hence, the ratio between both emittants is important to evaluate the total radiative forcing in a specific sector. An analysis of sectors according to this ratio reveals significant differences across sectors:
- There are sector such as the power industry that have high emissions of species with both positive and negative radiative forcing.
- Other sectors, such as road transport, are dominated by species with positive radiative forcing. More specifically, the ratio between black carbon and organic carbon aerosols is relatively high in road transport.
The accumulated climate impact over all sectors is visualized in the figure below (Source: Unger et al., 2010). In fact, in the short term (2020), road transport dominates the accumulated climate impact. In the long run (2100), the power sector dominates as greenhouse gases persists significantly longer in the atmosphere than short lived species.
Climate impact of economic sectors in 2020 and 2100.
From this technical analysis, effective climate change mitigation can most easily be obtained in on-road transportation - with significant co-benefits as air pollutants from transport are more harmful than from other sectors. This is for example due to a higher intake fraction (fraction of pollutants that is inhaled, e.g. Marshall et al., 2005), but can have more general benefits for public health and overall mobility (Creutzig and He, 2009). However, from a climate perspective road transportation is underregulated. For example, in Europe road transport is not part of the emission trading scheme, and, by this, is positively discriminated against electrified rail transport. A clever mix of instruments that prices the harmful parts of mobility while increasing its beneficial aspects (e.g. accessibility, thence, could have a near and long term positive impact).
Thanks to Jan Minx for pointing out the PNAS article.
References
Forster P, et al. (2007) Changes in Atmospheric Constituents and in Radiative Forcing, in Climate Change 2007: The Physical Science Basis, Contribution of Working Group I to the Fourth Assessment Report of the Intergovernmental Panel on Climate Change, eds Solomon S, et al. (Cambridge Univ Press, New York)
Unger, N., Bond, T. C., Wang, J. S., Koch, D. M., Menon, S., Shindell, D.T., Bauer, S. (2010) Attribution of climate forcing to economic sectors PNAS 2010 : 0906548107v1-6
Marshall, J.D., Teoh, S.K., and Nazaroff, W.W. (2005) Intake fraction of nonreactive vehicle emissions in US urban areas. Atmospheric Environment 39 (7), 1363
Creutzig, F. and He, D. (2009) Climate change mitigation and co-benefits of feasible transport demand policies in Beijing Transportation Research D 14: 120-131
Green energy for China
What happens in China, in terms energy use, is widely seen as a key to whether serious global climate impacts can be avoided or limited. China is relying heavily on coal but is also turning increasingly to non-fossil energy sources. Its nuclear programme often gets the headlines but in 2008 China had as much wind capacity in place as it had nuclear capacity – 8.9 GW. Of course, the relatively low load factor for wind (under 20%) meant that nuclear produced more energy – 68 TWh as against 13 TWh for wind. Moreover, new nuclear plants are planned, including fast neutron reactors to be supplied by Russia. In all, plans announced in recent years call for nuclear stations to supply 4% of China’s power needs by 2020, up from about 2% now, although of course its energy use is expanding rapidly, so that is more than a doubling in capacity. But wind has now more than doubled – installed capacity reached 25 GW in 2009, and a 2020 wind target of 150 GW has been mentioned. China’s wind programme is also moving offshore: it recently installed its first 3 MW 90-metre diameter “Sinovel” offshore turbine, the first unit of a 100 MW Shanghai Donghai Bridge demonstration project.
Certainly renewable energy, along with clean coal (i.e. with carbon capture) seems to be seen as a key way ahead. Chen Mingde, vice-chair of the National Development and Reform Commission, in comments quoted by the China Daily newspaper last year, claimed that “nuclear power cannot save us because the world’s supply of uranium and other radioactive minerals needed to generate nuclear power are very limited”. He saw the expansion of China’s nuclear power capacity a “transitional replacement” of the country’s heavy reliance on coal and oil, with the future for China being in more efficient use of fossil fuels and expanded use of renewable energy sources like wind, solar, and hydro.
China’s current target is to get 15% of its energy (not just electricity) from renewables by 2020, although this is likely to be raised to 20%. In addition to wind, it’s pushing ahead with solar as well as hydro and biomass. China’s hydro capacity is expected to nearly double to 300 GW by 2020. And a recent REEEP study suggested that 30% of China’s rural energy demand could be met through bioenergy. China already has 65 GW of installed solar thermal power, and the potential for expansion is significant (e.g. for large scale, concentrating solar power units in desert areas, feeding power by HVDC links to the cities). A 1GW prototype plant is planned.
PV solar is also set to expand rapidly. China is already the largest producer of solar cells globally and, although until recently most of them were exported (around 1 GW in 2007), the emphasis has now changed, so that the current national target of having 3 GW of capacity in place by 2020 could be exceeded by perhaps a factor of three. Looking further ahead, work in also underway on tidal and wave energy projects.
Some major integrated projects are also emerging. For example, Reuters reports that China is currently developing a demonstration zone in Hangjin Banner, with a planned 11,950 MW renewable-energy park, which, when completed, should have 6,950 MW of wind generation, 3,900 MW of photovoltaics, 720 MW of concentrating solar power, 310 MW of biomass plants and 70 MW of hydro/storage.
Some innovative new grid links are also being established, designed to deal with the problem that much of the renewable electricity resource is remote from mostly coastal centres of population. The new extended grid system could also help with balancing the variable output from some renewables. Modern Power Systems reports that Siemens Energy and China Southern Power Grid has started commissioning part of a High Voltage Direct Current (HVDC) transmission line, with a capacity of 5000 MW, covering a distance of more than 1400 km. It’s claimed to be the first HVDC link in the world operating at a transmission voltage of 800 kV. Commissioning of the second phase, and startup of the full system, is scheduled soon.
The Yunnan–Guangdong interconnector will transmit power generated by several hydro power plants in central China to the rapidly growing industrial region in the Pearl River delta in Guangdong Province with its megacities Guangzhou and Shenzhen. This system can, it us claimed, reduce the annual CO2 emissions that would otherwise have been produced by fossil-fuelled power plant by over 30 megatonnes. In addition Modern Power Systems reports that there is the 800 kV Xiangjiaba–Shanghai link, on which ABB has been working with the State Grid Corporation of China (SGCC). It will be capable of transmitting 6400 MW of power from the Xiangjiaba hydropower plant, located in the southwest of China, to Shanghai – a distance of over 2000 km. It is claimed that transmission losses on the line will be less than 7%.
China is now the world’s largest carbon dioxide emitter and its energy demand is still rising rapidly, despite the global economic recession. However, in the run up to the COP 15 climate negotiations in Copenhagen last December, while not willing to commit to reductions in net emissions, China said it would cut its energy intensity (emissions/GNP) dramatically – by 40–45% by 2020. That’s not the same as reducing net emissions of course, but it would be a start. And if that is acted on, renewables would clearly play a major part.
China’s role at COP 15 has been much debated – essentially it seemed to want to protect its continued growth, and avoid imposed emission targets targets – much like the US. But, like the US, it also seems keen to be a leader in the move to green energy technology – perhaps becoming the “green workshop of the world” feeding the expanding markets for renewable energy systems around the world. In addition to exporting solar PV cells, it was even planning to build wind turbines for and in the US – although a US senator’s objections may have scotched that.
How rapidly China can and will green itself though is less clear. Certainly China has massive renewable resources: for example the wind resource is put at around 2 TW. And a new study by Michael McElroy and colleagues at Harvard and Tsinghua University in Beijing, published in the journal Science, has claimed that, in theory, wind power could meet all of China’s electricity demand by 2030.
That is very unlikely happen by then of course, but China is likely to become a major player in the green-energy revolution.
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