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October 2012 Archives

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Shale gas and CCS

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In the 2012 Budget, Chancellor George Osborne said 'Gas is cheap, has much less carbon than coal and will be the largest single source of our electricity in the coming years'.

DECC followed this up by saying that it saw gas as 'continuing to play an important part in the energy mix well into and beyond 2030, while meeting our carbon budgets. We do not expect the role of gas to be restricted to providing back-up to renewables, and in the longer term we see an important role for gas with CCS.'

However then the independent advisory Climate Change Committee (CCC) warned the government that 'Extensive use of unabated gas-fired capacity (i.e. without carbon capture & storage technology) in 2030 and beyond would be incompatible with meeting legislated carbon budgets'.

DECC backed off a bit, saying that 'after 2030 we expect that gas will only be used as back up [for variable renewables], or fitted with Carbon Capture and Storage technology.'

There are all sorts of problems with this plan. Firstly, it is far from clear whether, and if so when, CCS technology will be available and widely deployed. What is clear is that it will add substantially to the cost of power generation. Secondly, it is not clear to what extent shale gas will extend the UK's diminishing gas reserves- and at what price, in both economic and environmental terms, not least given the large amounts of water needed for fraking, the resultant ground water contamination and the risk of micro-quakes from fraking. Thirdly, pushing ahead with CCS and shale gas will deflect resources from the development of renewables, including sources of green gas (see my previous Blog), the only real long term sustainable energy options, unless you see fast breeders or fusion as viable, sustainable options.

All these issues are contentious. The industry say that shale gas fracking is fine, with minimal environmental impacts:

However, the European Commission has published a study on environmental impacts which says that extracting shale gas generally imposes a larger environmental footprint than conventional gas development. Risks of surface and ground water contamination, water resource depletion, air and noise emissions, land take, disturbance to biodiversity and impacts related to traffic are deemed to be high in the case of cumulative projects. On climate impacts, the EU has issued a report which says that shale gas produced in the EU causes more GHG emissions than conventional natural gas produced in the EU, although, if well managed, less than imported gas from outside the EU, whether via pipeline or by LNG, due to the impacts on emissions from long-distance gas transport.

Some see emissions from shale gas combustion being abated by CCS. However, some environmentalist worry about the impacts and safety of CCS (e.g. the risk of sudden major CO2 release) and about it providing a way for the continued use of fossil fuels at high extra cost, with, in practice, the net emission reductions not actually being as high (80-90%) as is claimed.

The European Environment Agency says that, depending on the CO2 capture technology used, there could be a net rise in some toxic emissions:

Some studies also suggest that CCS might trigger, and be susceptible to, micro-quakes, possibly releasing all the stored CO2 suddenly: and

However, CCS does offer the possibility of carbon negative energy production, if carbon neutral biomass is used as a fuel, so some greens see fossil CCS as an interim test bed for a very positive green CCS option.

Against that, there are the opportunity cost issues both for CCS and shale gas. They both keep fossil fuel going as major option. It does seem that shale gas has already undermined renewables in the USA:

Certainly there has been a boom in shale gas there. The U.S. used to generate about half its electricity from coal, and roughly 20 % from gas. But now coal's share is 32%, on a par with gas, with shale gas paying an increasing role. There are disputes about net emission from shale gas, but natural gas is about 40% less carbon intense/kWh than coal, and the overall result of the US 'dash for gas' is that emission have fallen by 14%, although the expansion of wind power will also have helped. But will shale gas boom continue? Some say the wells will become rapidly depleted:

In the UK, the optimists suggest that shale gas finds so far could be worth up to £50 bn and were equivalent to about a third of conventional UK natural gas reserves- and much more may be found to be available.

A much better option, some say, than importing LNG from Qatar, or expanding coal use. The later is more carbon intense, the former may be unreliable:

So the battle goes on, with a series of reports reviewing the prospects from a range of perspectives, e.g :

On (or rather under) the ground, some shale gas drilling looks set to go ahead in the UK, but although there are plans, as yet there are no major UK CCS projects. There was much vilification about the mess, following the collapse of the earlier CCS programme. Margaret Hodge, chair of the Public Accounts Committee, commented that the government 'must learn the lessons from this failure to avoid squandering any more time and money'. The National Audit Office published a review of the programme, which said the failed funding round was 'a high-risk and challenging undertaking launched with insufficient planning and recognition of the commercial risks'. A UKERC report talked of a long hard trek.

The government has launched a new funding programme, with a view to starting commercial operations in the 2020s, using the £1 bn from the shelved CCS programme. The original programme had been about CCS for coal-fired plants, but it has now been expanded to gas plants. That's maybe just as well. For, with OFGEMs concerns about power shortfalls hitting the headlines, 20GW of new gas-fired plant have been proposed for installation by 2030. Though whether any of this will have CCS remains unclear. As is also how much shale gas there will be to run them on- despite the Chancellors promise of a 'generous tax regime'.

While shale gas extraction is new in the UK and is being opposed in parts of the rest of the EU, the situation in the USA is somewhat different. As noted above, shale gas fraking is widespread and expanding. CCS is also now beginning to take off there, although in a more limited way. There have been some small CCS projects in Germany and France, but what has been claimed as the word's first integrated carbon capture system, a demonstration project in Alabama, has began underground injection of CO2 recovered from emissions from a coal-fired power plant.

For an overview of CCS technology and the evolving regulatory situation in the USA, see 'Carbon Capture and Storage' G. Morgan and S, Mccoy, Routledge.

Renewable methane

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There has been a lot of interest in developing national energy systems using renewable methane, rather than fossil methane, or even electricity, as a major energy carrier. Unlike electricity, methane can be stored and can also be transmitted with lower energy losses. In the UK the natural gas grid actually handles about four times more energy than the electricity grid. Moreover, if the methane is generated using green energy sources then it's carbon neutral, and if it's generated from bio-sources and also has CCS added, then its combustion can be carbon negative.

Biomethane produced from biomass/waste via AD is one option and this can be added to the gas grid. It's an idea that's spreading across the EU. See: 120529D22Overviewofbiomethanemarkets_rev1.pdf

However, there are also more advanced ideas. Germany has been pushing ahead with 'green gas' production, generating hydrogen via electrolysis, using excess wind-derived electricity. The hydrogen gas can be used as a fuel direct (e.g. in fuel cells or gas turbines) for electricity production, or added to the natural-gas grid, or used in vehicles. It can also be converted into other fuels. Audi will be launching their 'e-gas' vehicles in 2013, running on methane made from wind-derived hydrogen in combustion engines designed for gas use. E.ON has started work on a €5m wind-to-gas pilot project for gas-mains injection. But the hydrogen can also be converted to methane or other syn fuels, using CO2 captured from the air or from power plant exhausts, once again for use in vehicles, for heating or for power production. In effect it provides a way to store excess wind and also capture CO2. The later concept is central to the CO2RRECT project

There are several more complex versions of these ideas currently being promoted. In one variant explored by the Fraunhoffer institute, green hydrogen and captured CO2 is used to upgrade biomasss feed stock, the argument being that this will allow for the production of higher value fuels without having to use so much land area for biomass growing.

There are other possibilities. Enertrag AG is operating a 6MW wind-to-gas plant 120 kilometers north of Berlin, with the help of its partners, Vattenfall, Total and Deutsche Bahn. One option is to mix the hydrogen with biogas made from local corn waste to feed into CHP/ cogen plants, which produce electricity and heat. The power can be fed back into the grid at times when little or no wind is available, while the heat can be fed into district heating networks. During periods of low wind, the biogas plant can run on biomass alone. Enertrag is also feeding hydrogen gas direct into the natural gas grid and Greenpeace Energy is already buying some of this 'windgas' to sell to households. And of course it can also be used in vehicles:

It's not just Germany that is exploring these options. In Denmark, Haldore Topose have developed a highly efficient high-temperature electrolysis-methanisation system that can convert water and CO2 into a range of synfuels/syngases.

Finland is also looking at the idea, with the focus on transport. In January 2012, the Finnish Ministry of Transport and Communications set up a task force 'Future motive powers in transport ' to work out targets and plan paths for achieving them, for different motive powers in road, rail, water and air transport in 2020 and 2050. One of the motive powers considered was renewable methane, for which a sectoral report was prepared by Finnish Biogas Association and North Karelian Traffic Biogas Network Development Programme. An extended summary (31 pages) of the report 'Roadmap to renewable methane economy', in English, is available at

It outlines a goal of 40% share for renewable methane of transport energy consumption in 2050. Progress is already being made. Two large ships (300 GWh annual methane consumption) will be taken into use: Viking Grace (a large passenger ship for Turku-Stockholm route) and UVL 10 (Finnish border patrol boat). Both of them are currently under construction in Finland by STX and they both will be using Finnish Wärtsilä dualfuel methane-diesel engines. By 2020 at least 20 vessels are expected as a result of the UN/IMO sulfur emission restrictions in the Baltic Sea.

In road transport, their target is to have 2% of vehicles methane powered in 2020, i.e. 60,000 vehicles. Also, part of non-electrified rail transport is expected to move from diesel oil to methane by 2020, but in air transport, methane use is not yet expected to have begun by 2020.

In 2020 natural gas (NG) is expected to cover 60% of transport methane use of 2.5 TWh. Biogas (BG) and synthetic biogas (SBG) would contribute by 1 TWh (40%). After 2020 the share of renewable methane will continuously increase and by 2050 the use of natural gas and all other fossil fuels will end, on the basis of the groups scenario, in all transport sectors, although direct non-fossil electricity will provide some of the power.

Clearly then the renewable methane idea is moving ahead. And it's not just a European phenomena. Canadian multi-national Hydrogenics have also developed a wind-to-gas concept, for producing CNG for vehicles, as well as grid gas, heat and power:

In the UK, progress has been limited: as I will be reporting in my next blog, the emphasis has instead been on natural and shale gas. But AD biogas is now being taken more seriously and there are five new government-backed R&D projects aiming to speed up the adoption of energy systems using hydrogen and fuel cell technologies, funded by the Technology Strategy Board and the DECC with £9m, in a £19m programme focused mainly on hydrogen electrolysis.

So far the only UK 'air capture' project for synfuel production using COS from the atmosphere is that being developed by Air Fuel Synthesis. This has recently begun to receive press attention after have received backing from the IMechE: For more see

For more on wind to synfuel see:

Of course what matters in all of this is the energy-conversion efficiencies and costs. But good progress is being made. And the system-wide benefits of being able to store and then use otherwise wasted energy may offset the conversion costs. For more analysis see:

For an overview see the Macogaz 'Power to gas' fact sheet:

Waste not, want not

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We produce of lot of waste. Some is a potential source of energy. That may even include the carbon dioxide produced from combustion.

We usually treat carbon dioxide as a problem. But it can also be a solution. There are some interesting new ideas about using it to make fuels. One option is to use it to enhance algae growth. This can of course be done, in principle, with any bio-crop in large glass houses or other gas-tight enclosure: gas-engine exhaust is already used in commercial glasshouse horticulture for tomatoes etc, e.g. in Holland. But algae absorb CO2 more rapidly. MIT's carbon-capture and algae-bioreactor system is interesting. However there are evidently issues of maintaining efficient reactions, and the US company involved with this, GreenFuel Technologies, evidently has had financial problems. But trials by Sheffield University, using captured CO2 (from Tata steelworks near Scunthorpe) bubbled through algae tanks, are showing some promise:

Meanwhile Swedish utility Vattenfall has launched a pilot project using algae to absorb greenhouse-gas emissions from a coal-fired power plant in eastern Germany in a €2m trial run. Half the funding for the MiSSiON (Microalgae Supported CO2 Sequestration in Organic Chemicals and New Energy) project comes from Vattenfall, the other half from state and EU subsidies. The flue gas emitted at the Senftenberg brown-coal fired plant is being pumped through a broth using algae cultivated in 12 plastic tanks. The biomass produced can be used to produce biodiesel, to feed biogas power plants and as a nutritious supplement in fish food.

In a somewhat similar approach, Carbon Sciences Inc. says it's developing a technology to transform greenhouse gases into liquid portable fuels, such as gasoline, diesel and jet fuel. 'We are developing highly scalable clean-tech processes to produce liquid fuels from naturally occurring or human-made greenhouse gas emissions. From sources such as natural gas fields, refinery flare gas, landfill gas, municipal waste, algae and other biomass, there is an abundant supply of inexpensive feedstock available to produce large and sustainable quantities of liquid fuel to replace petroleum for global consumption, thereby eliminating our dependence on petroleum'.

Much more radical is the idea of reacting CO2 with hydrogen produced by electrolysis using electricity from wind turbines, to make methane and synfuels. See the UK 'Air Fuels' project and the various German/EU projects e.g CO2RRECT I'll be looking at this 'wind-to-green-gas' idea more in my next blog.


We also treat municipal and domestic solid waste as a problem, sometimes just letting it rot in landfill sites producing methane - a powerful greenhouse gas. Some of that gas can be and is captured, providing a cheap renewable fuel, but if it's burnt to generate power then you get carbon dioxide, although that could be captured and stored. Then the energy would be carbon neutral or even carbon negative, given that the production of food/farm waste has involved the absorption of carbon dioxide.

However, there are also other approaches, such as controlled anaerobic digestion of food/farm waste algae, with the emphasis on high-value food products rather than energy production. For example, start-up company Merlin Biodevelopments based in North Wales has devised a new way of growing protein-rich algae from waste food and cow slurry, which can be used in high-protein food products for human and animal consumption. An array of reactor tubes, in which the algae are cultivated, has been built in a polytunnel at the Moelyci Environmental Centre, Tregarth, near Bangor. So far Merlin has invested £500,000 in the project, including R&D grants worth £160,000 from the Welsh Assembly Government. It's designed its own low-cost micro AD plant, and its single 30m long polytunnel can produce 20 tonnes of algae a year. A second plant is due to open in south Wales soon and Merlin expects to be producing 1,000-2,000 tonnes by 2013. They say a 210 sq m polytunnel can produce as much protein in a year as 10 sq km of top-grade agricultural land. In a side project at Moelyci, Merlin is also investigating the value of processing AD residue into high value fertiliser using the algae system.

Using food waste for AD is clearly sensible. As I've noted before, Gwynedd Council are backing a new AD plant, which will process around 11,000 tonnes of food waste each year; converting it into renewable electricity and biofertiliser for use on nearby farmland. The food waste will be collected from local homes and businesses via a collection scheme run by Gwynedd Council. The new plant will replace the existing landfill site. It will be the second waste-fed anaerobic digestion plant built in Wales, following the construction of the Premier Foods plant last year near Newport.

In addition, food waste from homes in South Gloucestershire is now also being converted into renewable energy and organic fertiliser at a single site via AD. Food collected at the kerbside is being sent to an anaerobic digestion plant in Oxfordshire to be broken down by bacteria into useful gases and organic materials. The long-term arrangement with operator Agrivert, brokered by the council's waste collection contractor Sita UK, will see about 6,000 tonnes of food waste processed each year - equivalent to the weight of rubbish carried in 600 full refuse lorries. Agrivert manager Harry Waters said the company would expect to capture two million kilowatt hours of renewable energy from that amount of food waste every year. He said: "That is enough to power more than 400 family homes and produce organic fertiliser which will be used by farmers to grow food on more than 700 acres of land. Moreover, we capture a million cubic metres of methane that would otherwise be released to the atmosphere."

One way or another the AD biogas option looks likely to become increasingly important. The Anaerobic Digestion and Biogas Association recently said the Chancellor's efforts to give shale gas a helping hand with a 'generous tax regime', would be better spent on other forms of gas which are renewable, like biogas. The ADBA suggests biogas from anaerobic digestion (AD), 'which can provide energy security at a lower cost and, since it's renewable, with far lower carbon emissions and environmental impact than more experimental technologies like shale gas. AD can be scaled up fast and cheaply and with the right support could generate 40 TWh of biogas, equivalent to 10% of the UK's domestic gas demand, at the same time as boosting economic growth and creating 35,000 jobs.'

Storing energy

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The Energy Futures Lab at Imperial College London has produced a 'Strategic Assessment of the Role and Value of Energy Storage Systems in the UK Low Carbon Energy Future' for the Carbon Trust, using a holistic system-wide modeling approach. It concludes that storage would allow significant savings to be made in generation capacity, interconnection, transmission and distribution networks and operating costs. In all it says that storage could provide up to £10 billion of added value in a 2050 high renewables scenario.

However, the relative level and share of the savings changes over time and between different assumptions. In the high renewables 'Grassroots pathway' used by the research team, the value of storage increases markedly towards 2030 and further towards 2050, so that carbon constraints for 2030 and 2050 can be met at reduced costs when storage is available. For bulk storage cost of £50/kW per year, the optimal volume deployed grows from 2 GW in 2020 to 15 and 25 GW in 2030 and 2050 respectively. The equivalent system savings increase from modest £0.12bn per year in 2020 to £2bn in 2030, and can reach over £10bn per year in 2050.

The value of storage is the highest in pathways with a large share of renewables, where storage can deliver significant operational savings through reducing renewable generation curtailment i.e. when there is excess wind output available. In addition, storage could lessen the even larger wind curtailment requirement that would result if there was also significant amount of inflexible nuclear capacity on the grid. However CCS scenarios yield the lowest value for storage: 'adding storage increases the ability of the system to absorb intermittent sources and hence costly CCS plant can be displaced, which leads to very significant savings.'

Although it can be very useful in some situations, storage is not a magic solution for all our grid balancing problems: it is best used for specific purposes and durations. Crucially, Imperial say that 'A few hours of storage are sufficient to reduce peak demand and thereby capture significant value. The marginal value for storage durations beyond 6 hours reduces sharply to less than £10/kWh year.'

So it seems we are talking about short storage cycles, ready for the next demand peak- not long term grid balancing to deal with long lulls in wind availability. That makes sense: storage is expensive, so you want to use the hardware regularly to capture excess energy (when it's cheap) and sell it soon after to meet peaks, when energy prices are high.

This may be fine for short cycles. But how then do you deal with longer lulls? Especially in areas where there is a lot of wind capacity? Imperial say 'Bulk storage should predominantly be located in Scotland to integrate wind and reduce transmission costs, while distributed storage is best placed in England and Wales to reduce peak loads and support distribution network management.'

The report also offers some other valuable insight into the interactive nature of the overall system options and operation. For example, one option for balancing grids in the short term is the use of flexible demand - e.g. reducing peaks by time-shifting demand. Imperial say that 'Flexible demand is the most direct competitor to storage and it could reduce the market for storage by 50%.' So with that, you would not need so much storage.

Another option, which might also help with longer-term grid balancing, is the use of interconnectors. While pumped hydro is the cheapest large scale bulk electricity storage option, the UK does not have much potential for large amounts, and some have argued that it would be cheaper to get access to the large pumped hydro storage capacity on the continent, in Norway for example, using 'supergrid' interconnector links. That could also allow the UK to import power when there was a long lull in wind availability.

Interconnectors are expensive, but Imperial say that cross-channel links (maybe 12GW or more) could be 'beneficial for the system because it significantly reduces the amount of curtailed renewable electricity generation in the UK from 29.4 TWh to 15.1 TWh annually'. They add 'this also suggests there will be less scope for storage to be used to reduce the system operating cost through reductions in renewable curtailment. The operating cost savings component is indeed lower in cases with increased interconnection capacity, by about 50% compared to the baseline (Grassroots) case.' So we would not need so much storage.

Nevertheless, Imperial do see a need for perhaps 15GW of storage, given that 'in the Grassroots Pathway, storage has a consistently high value across a wide range of scenarios that include interconnection and flexible generation.'

While there is a good overview of some storage technologies, beyond the points as above about the relative merits of bulk and distributed storage, the report doesn't specify what sort of storage is best. Moreover, it is primarily about electricity storage. But how about rival modes of storage/ transmission e.g. heat or gas (including green gas). That would open up even more interactivity and may also improve the overall efficiency of the system and perhaps even reduce costs. After all, it is much easier to store heat or gas than electricity. Imperial admit that there are technical limits to conventional storage: the round-trip efficiency of storage can be low, and trying to increase it might not actually be worthwhile: 'higher storage efficiencies only add moderate value of storage' although 'with higher levels of deployment efficiency becomes more relevant'. They also warn that 'operation patterns and duty cycles imposed on the energy storage technology are found to vary considerably, and it is likely that a portfolio of different energy storage technologies will be required, suited to a range of applications.'

Fair enough: clearly more research is needed! Imperial do make a good job of promoting the benefits of storage and defending it against some critics. They say that 'by providing reserve capacity and the resulting improved scheduling of plant, storage enables more wind energy to be delivered at the time of generation. In such instances the round trip efficiency of storage does not directly affect the amount of avoided curtailed that displaces other plant.'

However they add that 'there remain a number of important unknowns with respect to the technologies involved in grid-scale energy storage, in particular relating to the cost and lifetime of storage technologies when applied to real duty cycles within the electricity network.' While it is useful to get some idea of the possible interactions and their impacts, these technological and operational uncertainties do make you wonder how useful high-level modeling is: we are some way from being able to optimize the design of the emergent new grid systems, especially given the advent of novel storage technologies. So perhaps its not surprising that, on policy, Imperial ends up saying, 'it is not clear whether government policies should incentivise the development and deployment of novel storage technologies, and if so, what sort of mechanisms should be considered, e.g. ranging from subsidies to direct procurement.'

Governments seek to mitigate climate change and make their countries energy independent. Biofuels seemed to achieve both: sequestering the carbon they emit, biofuels were considered carbon neutral; they also rely on intra-regional resources, notable land, and reduce oil imports.

But studiy after studiy points to unforeseen dangers. The current aggressive deployment of biofuels compromise food security; and perversely, biofuel production contributes to climate change by releasing carbon formerly stored in soil and forests (indirect land use change, ILUC).

The European Commission finally awakes to this challenge. The Guardian reports that the Commission aims to reduce the mandated quota of biofuels from 10% to 5% in 2020, a level that is already achieved now. Equally important, indirect land-use change will be part of the metric.

If policy makers reduce quotas, forests, peat lands, and food production gain maneuvering space. The EU would directly alleviate land-based ecosystem and communities from potentially harmful pressure. But what are the implications of the ILUC factor?

Chris Malins published his research on precisely this question in Global Change Biology last month. Malins is confident that "introducing iLUC factors will make the policies more effective and will greatly reduce the risks of doing more harm than good". In his model (given a required 50% thresholds on carbon savings), "there is a 94% chance that introducing iLUC factors would improve the carbon saving per unit of energy achieved by EU biofuels policy by at least 20 percentage points, with an expected benefit of 49 percentage points, i.e. iLUC factors would be expected to be a very effective policy intervention".

The implications for the European biodiesel industry are devastating; European biodiesel production seems currently unable to meet the requirements, biodiesel would be pushed out of business. Understandably, the biodiesel lobby is outraged.

But if a policy designed to mitigate climate change, instead aggravates climate change, it remains the right decision to change course. The ILUC policy in particular is suitable to navigate the climate-change Scylla of fossil-fuel dependency and the climate-change Charybdis of land-based emissions: the ILUC factors put pressure on markets to come up with low-emitting second-generation biofuels (long announced but hardly been seen so far). 

Is this the end of the line, or just a foot in the door? I would argue that a revised EU regulation of ILUC is just the entry point for something much bigger, allowing science and policies to grow to meet the tremendous challenges we are facing. The main issue is the interconnectedness of energy, food and climate dynamics and policies.

Scientifically, what is the counter-factual fossil fuel used for bio-refineries? Which combination of food, fuel, and forest policies leads to what kind of land use (emission) outcome? I am certainly not the only one to suggest that the true relevance of biofuel policies only reveals itself in the context of world agricultural politics, food demand, and forest protection efforts.

Politically, why should biofuels be carefully discriminated against their global warming potential (what I fully support), when food production is not? How does the effectiveness of ILUC regulation depend on the proper and stringent enforcement and continuation of carbon prices for fossil fuel, and caps?

The Scylla and Charybdis of biofuel policies is only one adventurous incidence of a much larger Odyssey.


Further reading:

F. Creutzig, A. Popp, R. Plevin, G. Luderer, J. Minx, O. Edenhofer (2012) 

Reconciling top-down and bottom-up modeling on future bioenergy deployment.

Nature Climate Change 2: 320-327