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The Future of Hydrogen Chapter 3: Storage, transmission and distribution of hydrogen challenging for them to implement. Blending hydrogen into the natural gas infrastructure that already exists would, however, avoid the significant capital costs involved in developing new transmission and distribution infrastructure. Further, if blending were to be carried out at low levels, while it might increase the cost of natural gas delivery to consumers, it would also provide reductions in CO2 emissions. Blending would be considerably easier to implement if steps were taken to clarify existing national regulations on hydrogen in natural gas and to harmonise regulations across borders. There are almost 3 million kilometres (km) of natural gas transmission pipelines around the world and almost 400 billion cubic metres (bcm) of underground storage capacity; there is also an established infrastructure for international liquefied natural gas (LNG) shipping (Snam, IGU and BCG, 2018; Speirs et al., 2017). If some of this infrastructure could be used to transport and use hydrogen, it could provide a major boost to the development of hydrogen. For example, a blend of 3% hydrogen 18 in natural gas demand globally (around 3 900 bcm in 2018) would require close to 12 MtH2. If the majority of this hydrogen came from electrolysers, then this by itself would require around 100 gigawatts (GW) of installed electrolyser capacity (at a 50% load factor), a level that could deliver around a 50% reduction in the capital cost of electrolysers. However, hydrogen blending faces a number of challenges: The energy density of hydrogen is around a third of that of natural gas and so a blend reduces the energy content of the delivered gas: a 3% hydrogen blend in a natural gas transmission pipeline would reduce the energy that the pipeline transports by around 2% (Haeseldonckx and D’haeseleer, 2007). End users would need to use greater gas volumes to meet a given energy need. Similarly, industrial sectors that rely on the carbon contained in natural gas (e.g. for treating metal) would have to use greater volumes of gas. Hydrogen burns much faster than methane. This increases the risk of flames spreading. A hydrogen flame is also not very bright when burning. New flame detectors would probably be needed for high-blending ratios. Variability in the volume of hydrogen blended into the natural gas stream would have an adverse impact on the operation of equipment designed to accommodate only a narrow range of gas mixtures (Abbott, Bowers and James, 2013). It could also affect the product quality of some industrial processes. The upper limit for hydrogen blending in the grid depends on the equipment connected to it, and this would need to be evaluated on a case-by-case basis. The component with the lowest tolerance will define the tolerance of the overall network. Some existing components along the natural gas value chain have a high tolerance for hydrogen blending (Figure 25). For example, polyethylene distribution pipelines can handle up to 100% hydrogen, and the H21 Leeds City Gate project in the United Kingdom aims to demonstrate the feasibility of delivering hydrogen through the gas distribution network to provide heat for households and businesses. Similarly, salt caverns can store pure hydrogen instead of natural gas without any need for upgrades. Many gas heating and cooking appliances in Europe are certified for up to 23% hydrogen, although the effects of such levels over many years of use are still unclear (Altfeld and Pinchbeck, 2013). However, there are other parts of the existing natural gas value chain that cannot tolerate high levels of blended hydrogen. The biggest constraint is likely to be in the industrial sector, where many industrial applications have not been certified or assessed in detail for hydrogen blending. 18 All blending percentages in this section are on a volume basis. PAGE | 71 IEA. All rights reserved.PDF Image | The Future of Hydrogen 2019
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