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Tag Archives: hydrogen

Energy transitions in the UK

By Dave Elliott

The UK energy transition is progressing quite well on the electricity side, despite on-shore wind being constrained, but less progress has been made on green heat. A new Energy Research Partnership report on decarbonising heat, Transition to low-carbon heat’, looks at the technical, social, financial and governance aspects and highlights the key actions that need to be taken now and in the next few years. ERP says that ‘supplying natural gas or oil directly into homes will need to be replaced by a decarbonised gas or by electric heating or heat network. But it is not a simple choice: each option has challenges that could limit their deployment. A combination of options is likely to be required; no one option may not dominate, as natural gas currently does. Demand reduction will be an essential part of a cost-effective transition’.

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Labour’s green gas push

By Dave Elliott

‘Turning certain rubbish materials and farm and food waste into various types of biogas – ‘green gas’ – holds the potential to cut costs, radically reduce pollution, and decrease our reliance on imports. Crucially, using more green gas could make a real impact on the decarbonisation of heat without the need to overhaul our national gas pipeline and heat delivery infrastructure and without significant technical barriers’. So say Labour MPs Lisa Nandy and Caroline Flint in the Green Gas book published by the Parliamentary Labour Party Energy and Climate Change Committee.

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Why not nuclear and renewables?

By Dave Elliott

Nuclear plants do not generate carbon dioxide, so why can’t we have nuclear AND renewables, supporting each other, as a response to climate change? In evidence to the Energy and Climate Change Select Committee in July Amber Rudd MP, DECC Secretary of State, suggested that despite its high cost nuclear baseload ‘enables us to support more renewables’ and was needed since, ‘as we all know, until we get storage right, renewables are unreliable’. Can nuclear really support renewables, and is it really low carbon?

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A new UK green energy transmission and storage vector

By Dave Elliott

This helpful paper from a team at Sheffield University, UK, entitled ‘Great Britain’s Energy Vectors and Transmission Level Energy Storage’, suggests that ‘power to gas’ conversion systems could supply synthetic gas (syngas), made using renewable electricity, for storage in the gas pipe network, so as to balance variable renewables, this  being a substantially larger storage option for the UK than pumped hydro.

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Germany stays on course

 By Dave Elliott

Germany is sticking to its ambitious plan to get at least 80% of its electricity from renewables by 2050. As part of that, it aims to support the construction and operation of 20 offshore wind farms, 7 GW in all, and that plan recently received a boost, with the European Commission agreeing that it did not conflict with EU state aid rules. The 17 wind farms in the North Sea and three in the Baltic will further EU energy and environmental objectives without unduly distorting competition in the Single Market, the EC said.

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Wind-to-gas

by Dave Elliott

By their nature, wind and solar energy are variable and there is likely to be excess electricity generated from using these resources at times, and shortages at other times. It is hard to store electricity directly, but the energy can be converted into more easily storable forms.

One of the big hopes for the future is the ‘wind to gas’ idea- using excess wind-derived electricity to produce hydrogen gas by electrolysis for storage and then use, when there is a lull in the wind and high demand, to generate power in a fuel cell or gas turbine. Alternatively, the hydrogen, or methane derived from it (and from captured CO2), can be fed into the gas grid to replace fossil gas. For once the label ‘game changer’ might even be right- perhaps the key to a balanced energy future, compensating for variable inputs from renewables. It seems like an idea whose time has come: www.aspo2012.at/wp-content/uploads/2012/06/Pengg_aspo2012.pdf

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Energy storage technologies

by Dave Elliott

There are many energy storage options which can be used balance grid systems so as to compensate for the variable output from some renewables. They include existing and newly emerging electro-chemical and electro-mechanical systems (batteries, pumped storage and compressed air storage), as well as a range of thermal and hydrogen based systems www.electricitystorage.org/ 

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Energy storage – Part 1

Energy storage is often seen as a key to grid balancing- matching variable renewable inputs to variable energy demands.

So far pumped hydro storage is the only significant form of storage, except of course for stored fuels like coal, gas, oil or biomass. At present though, energy storage is still very expensive. So far it’s only been done- at least in the UK- when there is thought to be a serious need. For example, the giant Dinorwic underground pumped hydro project, located in a vast cavern in Wales, which at the time of its construction, was Europe’s largest infrastructure project. It was it seems initially conceived, financed and built in part to provide backup in case the Sizewell B nuclear plant went off line. It could go from zero to full generation within around 20 seconds and therefore could compensate for sudden loss of power on the grid, but also for sudden increases in demands for energy. Dinorwic could of course only hold the fort for a short while- 1-2 GW for perhaps 2 hours, while other backup came on line. And it was very expensive, so much so that when, following UK electricity privatisation, a lot of cheap and flexible Combined Cycle Gas turbines came on the grid, it became less attractive and has evidently had a harder time making money in the new market.

However, some see it as the sort of thing that will be needed in addition to more conventional pumped hydro projects, as we move to have more wind and other variable renewables on the grid. An EU wide supergrid link could also help, not least by linking into pumped hydro storage capacity around the EU – for example there is a lot in Norway. See www.theoildrum.com/node/7404

There are of course also other electricity storage options, including, for the short term, capacitors, flywheels, utility scale batteries, and flow cells; for the medium term, compressed air systems; and, for longer term storage, the conversion of electricity to hydrogen for storage and then for use in fuel cells or combustion engines to produce electricity again when needed. In parallel there’s the option of conversion to heat, which can be stored in molten salt stores.

These options all have their pros and cons- high capital costs and low energy conversion efficiency being key problems. On this basis, the hydrogen lobby has had a few years in the doldrums e.g. electrolysis is seen as inefficient and storing hydrogen as a cryogenic liquid is expensive, and there are energy losses when it’s cooled and then regassified. But recently it’s been reinvigorated by new production possibilities including a new ‘Green Hydrogen’ production cold-plasma technology, which could tilt the balance more in favour. www.gasplas.com/w3

There are also some novel storage ideas emerging, with.claims about the viability of large scale underground hydrogen gas storage in salt caverns. See: www.whec2010.com/fileadmin/html/78-4.html

On a smaller scale, Highview Power Storage has demonstrated a novel 300kW prototype cyrogenic storage system which stores excess energy at times of low demand by using it to cool air to around -190 °C. via refrigerators, with the resulting liquid air, or cryogen, then being stored in a tank at ambient pressure (1 bar). When electricity is needed, the cryogen is subjected to a pressure of 70 bars and warmed in a heat exchanger. This produces a high-pressure gas that drives a turbine to generate electricity. The cold air emerging from the turbine is captured and reused to make more cryogen. If waste heat from a nearby industrial or power plant is used to re-heat the cryogen, it’s claimed the efficiency rises to ~70%. http://www.highview-power.com

Do we really need storage?

However storage, by whatever means, is still going to be expensive. Fortunately there are alternative ways to deal with variable supplies . For example, working on the demand side of the equation, we can develop dynamic demand management techniques – delaying load peaks by a few hours or switching off some loads when wind power is low, using smart meter links. Though we don’t need it yet. At present, and for some way ahead, the variable inputs from wind generation can be easily balanced by running conventional gas fired plant up and down from full power. They already have to do this to balance the daily demand cycles, with more wind on the grid they just have to do this a few times more often, adding a small extra cost and undermining to carbon saving role of wind very slightly. As we have to accommodate more inputs from variable renewables, we may have to install more balancing capacity, but its relatively cheap and can increasingly be fuelled with biomass or geothermal heat-or perhaps even some solar heat, backed up by heat stores. As I pointed out in an earlier Blog, that could be linked to a system with Combined Heat and Power Plants feeding district heating networks and heat stores.

Moreover when wave and tidal energy are also being to fed into the grid, they can help balance varying wind (and solar) to a degree, since waves are in effect stored wind, and tidal cycles are unrelated to the weather.

Couldn’t nuclear plants also be used to balance the variable outputs from renewables like wind? The short answer is no- at least not much. Nuclear plants are usually run 24/7 to recoup their large capital costs and there are operational and safety reasons why they can’t be run up and down from high to low power regularly and rapidly. It’s not just thermal stresses in PWRs, but also the excess production of contaminating isoptopes which can interfere with proper and safe operation. Even so, it seems an EPR could ramp-up from 25% to 100% capacity, at 5% per minute, of its maximum output (i.e 80 MW per minute) e.g. from 400 to 1,600 MW in 15 minutes, but only100 times per year e.g. once every three days. Not much use for balancing regular wind variations, but maybe OK for long lulls in wind, if the nuclear operators will accept running at lower power (and loosing money) when there is wind available. Note also that nuclear plants, like all power plants, have to be backed up: for example a 300 MW light oil fired gas turbine plant is being built in Finland to back up the new, much delayed, Olkiluoto nuclear power plant.

The simple message though is that, basically inflexible nuclear is not very suited to balancing variable renewables. Moreover, if we try to have a lot of both on the grid there will be conflicts when demand for power is low- which then do you switch off? Storage might help reduce this conflict, but at extra cost. Really we don’t want to have large amounts of both nuclear and renewables on the grid system.

For more on nuclear balancing here’s an audio file : www.nuclearinst-ygn.com/ Docs/Vol5_Iss6_Track%202.mp3
And for a good overview: www.claverton -energy.com/is-nuclear-power-flexible-does-it-have-load-following-capability.html

It could be argued that, to some extent, we only need large amounts of storage if we are having problems with balancing the grid system more directly-and, if for example, we have a large inflexible nuclear component on the grid. But, even if that not an issue, it is true that if we could come up with a cheap storage system that would help grid balancing, and the hunt is on for new ideas. I will be looking at some in my next Blog.

For more ideas, there was an energy storage session at this years All-Energy Aberdeen conference: <a href="http://www.all-energy.co.uk/Power_storage_-the_holy_grail.htm”>www.all-energy.co.uk/Power_storage-_the_holy_grail.html

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Only connect: greener options for new grid links

As electricity generating renewable energy project spread, there will be an increasing need for new grid links, often across remote areas. But pylons are invasive and there have been objections to some new wind projects on that basis. For example, this issue has come to a head recently in mid Wales. See the consultation at:
http://www.spmidwalesconnections.info/english/pdf/Consultation%20Strategy-English.pdf

National Grid notes that the total generation capacity of the new wind farms proposed in Mid Wales is 874MW, with start up dates in 2015/16. It says that without ‘new significant transmission infrastructure’ it is ‘highly unlikely that the Welsh Assembly Government’s target of 2 GW of onshore wind farm capacity by 2015/2017 will be met’.

It goes on ‘Currently there is no electricity transmission system in the region of the proposed new wind farms in Mid Wales. The nearest points of connection to the existing system are in North Wales, South Wales and the West Midlands’. And it then looks at grid connection options, geographically and technically.

Basically, conventional overhead AC links are cheapest, but are very invasive. Underground AC costs a lot more and High Voltage Direct Current grids cost even more, over relatively short distances – the main cost with HVDC is in the AC-DC converters and their losses at each end; the cable link itself is much cheaper/km, and less lossy, than for AC.
www.nationalgrid.com/NR/rdonlyres/18E52B43-8AB5-4F0B-95F7 -0BECCA0647BE/46002/MidWalesSORIssue1_110319.pdf

However, Friends of the Earth Cymru has proposed an alternative, potentially significantly cheaper, approach, allowing for underground HVDC, with the capital costs of an under ground link possibly being reduced from around the £600m estimated by National Grid to £300- 390m, depending on revised wind farm capacity, link configuration and whether new energy storage technology was included.

How come? Energy adviser to FOE Cymru, Neil Crumpton, explains ‘The existing Grid regulations require two circuits in the link, each of which could carry the maximum output of all the wind farms, to avoid lost production if there is a fault in one or other of the circuits. Yet, load-duration data from a group of wind farms in southern Scotland indicates that the farms generate around 95 % of their annual electricity production at below 66% of their maximum output. So for the wind regime in that region a 66 MW circuit from a 100 MW wind farm would still transmit around 95 % of annual production. The wind profile in Mid Wales may well be similar. So the proposed 800 MW or so of wind farms may well be served by 2 x 500 MW links rather than 2 x 1,000 MW links with little loss of production during faults of several weeks a year on one or other circuit. If so, the HVDC hardware and undergrounding cost might be nearly halved.’

FOE Cymru says an energy storage facility at or near the upland sub-station could minimise production losses during a fault by delaying transmission until the wind eases and link capacity becomes available. Storage would also ‘bring wider system benefits in terms of routine demand-responsive supply to Grid and power quality improvements’. The group suggest using vanadium flow cell technology or ABB’s battery system which could scale to 50 MW for an hour or more.

Underground HVDC links have been used round the world e.g. in Australia, but usually in larger, longer distance transmission or subsea schemes.

However there may be another, much more radical, approach to energy transmission. Energy transmission by electricity pylon, let alone underground cable, is much more costly than by gas pipeline. Estimates vary, but the costs to transport energy by gas pipeline may be 10 – 100 times lower than electricity pylon and 100 – 150 times lower than underground AC or HVDC cabling. Importantly, as pipelines are underground, they are visually non-intrusive, so route planning is less likely to attract public opposition. Pipelines also have lower transmission losses as no wires are getting hot, and they also offer a degree of energy storage, be it within the pipeline (‘stacking’) or in purpose built stores, at potentially strategic scale.

But what sort of gas and where would it come from? Well a new 48 inch diameter pipeline across south Wales from the new Milford LNG terminals is now supplying the UK with around 200 TWh/y of natural gas from around the world. One idea closer to home is to progressively switch parts of the UK gas network to hydrogen, or a mix of hydrogen and natural gas, to supply decentralised systems.

The hydrogen could come from a number of sources, be it coal or biomass gasification, natural gas or bio-methane reformation. For example large CCS-fitted gasifiers could be located on brown-field sites near port or rail facilities and carbon dioxide pipelines to the sea. The gasifiers could supply hydrogen by new strategic pipelines to dedicated hydrogen distribution networks, or to the existing gas distribution network, to be used locally in fuel cell CHP schemes, domestic micro-CHP boilers, or in urban areas, in larger scale arguably more efficient CHP /District heating projects.

More radically still, some of the peaking output of offshore windfarms could be converted to hydrogen by electrolysers within the turbine or a dedicated electrolyser platform, and then piped long distance.

Much would depend on the relative cost of electrolysers and hydrogen pipelines compared to HVDC converters and cabling capacity. There would be significant energy losses in converting electricity to hydrogen (25 %), though electrolyser efficiencies are improving and sea water electrolysis is being developed. Re-conversion losses to electricity should be minimised (to 10% or less) by utilising the heat in CHP systems. So given the benefits of storage and lower cost transmission infrastructure, piping hydrogen may be worth while.

Piping pure hydrogen would present problems (e.g with pipe embrittlement for non plastic pipes), but modern gas piping has been designed for higher pressures than the old town gas, since the energy density of natural gas is lower, so running with a mix of hydrogen and methane could be viable. Indeed it is already done widely around the world -it’s called hydrane. Some or eventually perhaps all of the natural gas could be replaced by biomethane, produced by AD conversion using biomass wastes. Some biogas is already being added to the gas grid. That way we have a 100% green energy system fed by wind (and possibly also wave and tidal) and biomass. And no unsightly pylons across sensitive areas.

There are plenty of technical and economic details to be considered before this particular ‘pipe dream’ can be taken seriously, but National Grid is currently consulting on grid connection issues, and their web site has much useful information about he details: see http://www.nationalgrid.com/uk/Electricity/UndergroundingConsultation/

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Hydrogen futures: coal-fired fuel cells?

There has been a proposal from B9 Coal to use AFC Energy’s alkaline fuel cell technology with hydrogen produced from burning coal in situ underground in a 500 MW in Northumberland. Underground coal gasification (UCG) produces syngas, which is then passed through a clean-up process, resulting in separate streams of hydrogen and carbon dioxide. Upwards of 90% of the CO2 can then, it is claimed, be captured as a by-product at no extra cost. The pure H2 is passed through the fuel cell, converting to electricity at 60% efficiency at a projected cost as low as 4p per kWh.

UCG does avoid mining, with all its costs and risks. But UCG has some problems, as was found in early projects in the US and Russia. There have been accidental fires in coal seams underground which have been hard to control: one in Columbia County, Pensylvania, started 1962 and is still burning. The official response is that though relatively shallow coal seams can burn if an air flowpath exists, UCG cannot burn out of control. Combustion requires a source of oxygen, and this can in theory be controlled, so there is allegedly no possibility of oxygen reaching the coal which, for UCG, needs to be at a depth of 500 to 2000 metres and lying beneath impermeable rock strata. But even if that is true in practice, in situ coal does not burn cleanly or evenly – you get partial oxidation and a range of pollutants, including tars, phenols, ammonia. So there are clean-up costs.

More on UCG at: www.ucgp.com/.

Also the efficiency of making hydrogen from coal is usually said to be only about 65%. So with fuel-cell efficiency at best 60%, that gives and overall efficiency of under 40%, which may be low compared with direct use of mined coal in Integrated Gasification Combined Cycle plants, even with Carbon Capture and Storage (CCS).

However, why bother with complex and expensive IGCC plants? Why not just use the hydrogen direct as a heating fuel, sent to users via the gas main (piping gas is cheaper than power distribution by electricity grid). Or, if you really do need electricity, then use the hydrogen in homes in a CHP fuel cell – so recycling some of the otherwise wasted heat and raising the efficiency to maybe 70%.

Biomass as an alternative

Then again why use coal for the hydrogen source? What’s wrong with biomass? That’s more or less carbon neutral if it’s replaced by regrowing. There is a range of ways for producing hydrogen, methane or syngas from biomass including anaerobic digestion, pyrolysis, and gasification. In one approach, biomass is gasified to make carbon monoxide, and then using the standard shift reaction (CO+H2O = CO2 + H2) this is converted to hydrogen, and while the CO2 is captured and stored, so making it overall carbon negative.

See: www.claverton-energy.com/wp-content/uploads/2010/07/Tetzlaff_Birmingham2010.pdf.

There are land-use and biodiversity limits to how much we want to rely on biomass, but, intriguingly, the Sahara Forest Project includes the idea of growing algae in seawater-fed desert greenhouses, and there is plenty of desert and sea water.

Of course, there is also quite a lot of coal and in situ coal gasification may open up a new approach to using old part-worked coal seams. But if we want to avoid both coal and biomass, then what’s wrong with getting hydrogen using solar-, wind-, wave- or tidal-derived electricity, via electrolysis of water, or even by direct high-temperature dissociation of water via focused solar?

See www.hionsolar.com/n-hion96.htm.

The latter is still relatively inefficient (1–2%) and both approaches are still expensive compared with conventional approaches to hydrogen production. However, the technology is improving. One 2009 study suggested that, while hydrogen produced via steam reforming of natural gas costs around $6–8 per kilogram of hydrogen, H2 from solar (via electrolysis) costs $10–12 per kg, from wind (via electrolysis) $8–10 per kg, and from solar via thermo-chemical cycles (assuming the technology works on a large scale) $7.50–9.50 per kg.

www.h2carblog.com/?p=461

So we are getting there. For example, a 2002 study noted that PV costs of ˜$300/kWpk were needed to get H2 cost of $7-8/MMBtu via electrolysis, comparable with the cost of hydrogen production from coal, which, with current gasification technology, is $6.50-7.00 per MMBtu, or just over $8.00/MMBtu with CCS. www.netl.doe.gov/technologies/hydrogen_clean_fuels/refshelf/pubs/Mitretek%20Report.pdf.

But some PV modules are now claimed to cost below 76 cents/Wpk, and it’s claimed that in some locations PV can deliver energy at costs below that from new nuclear plants, as can wind power. See www.ncwarn.org/?p=2290 and www.sourcewatch.org/index.php?title=Comparative_electrical_generation_costs.

However, electrolysis is only about 60% efficient, unless the waste heat can be recovered, and there is still a way to go before it, and other novel renewable powered or biomass-fed approaches, can rival conventional steam reformation of fossil fuels for hydrogen production on a large scale. So, if we want hydrogen, maybe we could go for coal UCG/ CCS just as an interim step?

Some of the above is based on discussions in the www.claverton-energy.com/Claverton Energy Group.

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