Caution to the wind - storing wind power as hydrogen for the grid
Some of Germany’s leading power companies are making strides to effectively store wind power by turning it into hydrogen for the gas grid. Tim Probert asks, can this hydrogen be used to generate power, too?
Germans: known for their efficiency and dislike of waste, or so goes the cultural stereotype. So it follows that for many living under the Bundesflagge, the mismatch between supply and demand from intermittent sources of renewable is almost an affront to the national consciousness. Under German law, renewable energy power must be fed into the electricity grid and accrue subsidies, even if supply exceeds national demand. With an expected 111GW of renewables capacity by 2017, this problem is set to get much worse.
According to German engineering giant Siemens, up to 20% of wind power can go unused because of the lack of storage capacity. While surplus German power is frequently traded across European borders, to prevent much of this renewable energy going to waste Germany needs to install huge energy storage capacity.
It is estimated that if Germany hits its 2050 target of generating 85% of national electricity supply from renewables, it would require 30,000GWh of storage. Siemens believes the only storage option available that offers the required scale is using surplus power to produce hydrogen via electrolysis. The company says large quantities of hydrogen could be stored in the underground salt caverns used by natural gas suppliers as reservoirs, or directly injected into the national gas grid. With a 5% hydrogen component, Siemens says Germany’s national gas grid could effectively store 130TWh of electrical energy – almost a quarter of the country’s annual power consumption.
Several projects are under way in Germany to use renewable energy to produce hydrogen via electrolysis. One is by its biggest power generator E.ON, which is also, not coincidentally, Europe’s largest gas storage company.
The company is constructing a pilot plant at Falkenhagen, located 80km east of Berlin and a stone’s throw from the Polish border. Once operational (expected in the third quarter of 2013), it will produce up to 360Nm3/h of hydrogen – equivalent to around 30MWh of energy over a 24-hour period – from a containerised 2MW electrolyser and compression plant.
The hydrogen will be carried via a 1.6km pipeline to a connection point on the natural gas grid, where it will be injected into ONTRAS/VNG’s high-pressure transmission pipeline. The project is entirely funded by E.ON and is being built without partners, although Hydrogenics, a Canadian company, is supplying the electrolyser.
Power-to-gas technology is particularly attractive because of the large storage capacity offered by existing gas infrastructure, says E.ON’s project manager Rene Schoof. ‘We see a big change in the German power system and we believe this technology will help us overcome the challenge of very large volumes of wind power generation with almost no electricity storage capacity other than pumped hydropower. The main aim of Falkenhagen is to develop the process of connecting the power grid to the gas grid to store wind energy.’
The company expects to achieve a round-trip efficiency of more than 50%, but it will need some auxiliary power for the compressors and hydrogen measuring systems. The lifetime of the project, valued at around £4.37m, will be three years, during which E.ON will attempt to increase the efficiency of components that would need to respond secondby-second to variations in wind, and test their interaction.
Schoof says the hydrogen produced will be labelled as windgas and the company plans to receive payment for the production of this green gas. ‘At present there are no German policy measures to incentivise such wind-to-gas plants,’ he says. ‘We would expect the Erneuerbare-Energien-Gesetz (Germany’s Renewable Energy Act) to recognise windgas as similar to biogas.’
While the hydrogen produced could also be used in transport, for example at hydrogen refilling stations such as those located in Hamburg and Berlin, Schoof is keen to stress the goal of Falkenhagen is the storage of wind energy and not the sale of hydrogen. ‘The primary purpose is to store wind energy on a chemical basis, with the possibility of generating power in other locations when the wind isn’t blowing.’
The Falkenhagen project is one of several attempting to convert excess wind energy into hydrogen. German renewables project developer Enertrag’s pilot project in the state of Brandenburg, operational since October 2011, uses three wind turbines (totalling 6.9MW), connected to a 500kW electrolyser. The hydrogen can be used in three ways – as fuel for road vehicles, as fuel in a 70/30 blend with biogas for co-generation plants producing electricity and heat, or for feeding into the natural gas network.
Meanwhile Enbridge, Canada’s second-largest pipeline company and operator of 1GW of renewables capacity, has taken a CAN$5m stake in compatriot Hydrogenics. The two companies intend to install a 1MW windgas pilot project in 2013/14 and have identified several potential locations along Enbridge’s gas distribution network in the Canadian province of Ontario. Once that is accomplished, Enbridge could scale up to a 10MW project in 2016 and thereafter potentially large-scale installations in the 100–200MW range.
Siemens itself is developing windgas technology with the aim of giving wind farms an alternative revenue stream when the grid is fully charged. The company is working on two pilot systems and plans to have systems with a capacity of 2MW on the market by 2015, increasing to 250MW by 2018.
Unlike conventional industrial electrolysers, which need a steady supply of power to efficiently split water, the company’s football field-sized design is flexible enough to run on intermittent power from wind turbines. Based on proton-exchange membrane technology similar to that used in fuel cells for cars, the electrolysers can also temporarily operate at two to three times their rated power levels, which could be useful for accommodating surges in power on windy days.
Siemens says its electrolysers are about 60% efficient – 40% of the energy generated by a wind turbine would be lost making hydrogen gas. Then at least 40% of the energy in the hydrogen would be lost in generating electricity in gas-fired power plants or fuel cells. Therefore only around a third of the original renewable energy would be retained. The company puts the cost of hydrogen production via electrolysis at €10,000/kWh of installed load, although it is expected that costs will fall below €1,000/kWh by 2018. By then, the company claims electrolysers should be able to accommodate up to 100MW.
While Germany subsidises renewable energy, there is no reimbursement when supply exceeds demand. Prices on European power exchanges have, on occasion, turned negative, so electrolysers could appeal to utilities or financial investors seeking to profit from fluctuating electricity prices.
Hydrogen in gas turbines?
Due to Germany’s national gas regulations, only a small amount of hydrogen gas can be fed into existing natural gas infrastructure. The volume of hydrogen injected into the grid from E.ON’s Falkenhagen project will be limited to 2% by volume, explains Schoof. ‘There are no problems at 2% volume, but our power generation business may have technical problems if hydrogen is present in more than 3–4% of the natural gas,’ he says. ‘With a high concentration, the combustion flame temperature is too high and the speed of the flame in the burning process is too fast and so it is possible that the turbine could be damaged.’
Pure hydrogen holds nearly four times more energy per mass than natural gas and when burned with pure oxygen in a gas turbine, hydrogen would make the dream of zero-emission power plants a reality. However, flames resulting from the combustion of hydrogen gas would have a temperature of around 3,000°C. That would cause current gas turbine blades to melt.
Needless to say, this is far higher than the hottest gas turbines that run on natural gas. Even at lower temperatures, turbine blades need to be air-cooled, so new ceramic materials would be required. Despite this, Siemens hopes to one day build a prototype that can burn pure hydrogen. Dr Manfred Waidhas of Siemens’ Hydrogen Electrolyser Division says that at the moment the technical limit is a hydrogen component of 40–50% in a conventional natural gas mix. ‘You could then circulate part of the steam back into the combustion chamber to keep the temperature below the critical level,’ he says.
Higher temperatures also produce more nitrogen oxides. Another hurdle is flame stabilisation, since the smaller and more stable the flame, the lower the resulting emissions. Instead of a candle-shaped flame, a hydrogen flame in a conventional burner looks, on a temperature image, like footprints in snow – this is due to hydrogen’s high combustion speed. The flame front propagates at 10m/s, creating instabilities. By comparison, natural gas flame fronts propagate at just 0.4m/s, making the flames much more stable.
Siemens has managed to stabilise hydrogen flames using a vortex burner, developed in conjunction with researchers at Russia’s National Research Nuclear University (MEPhI) in Moscow. Here, hydrogen flows into a chamber tangentially via four ports, causing the gas to spin and its flame to shoot straight up like a candle. By stabilising the flame, the vortex burner also reduces nitrogen oxide emissions.
The company’s team in Russia has other suggestions for stabilising hydrogen flames. One patented idea involves a pipe with a square crosssection that improves the hydrogen-air mixture by giving the two gases more time to mix as they flow through the pipe. This makes the flame smaller and limits the volume within which high temperatures, and therefore nitrogen oxides, can form.
These concepts will help keep the flame away from the combustion chamber walls and turbine blades until materials researchers deliver new solutions for higher temperature flames. While commercial power generation from pure hydrogen appears some way off, the prospect of using surplus renewable energy to produce hydrogen windgas appears closer to commercial reality. Time will tell whether the cost can fall to a viable level.