Материал: The_Future_of_Hydrogen-IEA-2020

Near-term policy priorities

Targets and/or long-term policy signals. Governments at all levels should look seriously at industrial clusters as opportunities to scale up hydrogen in the 2030 timeframe. Developing cross-sectoral roadmaps and committing to deployment targets can be instrumental to bringing all stakeholders on board and to ensuring that visions for different industries are aligned in scale and timing.

Demand creation. Technology-neutral instruments like CO2 pricing would provide an overarching incentive for low-carbon hydrogen use, with a price of USD 50 tCO2 potentially enabling investment in CCUS retrofit at refineries or ammonia plants where CO2 storage is accessible. Other measures could also help, including legal or voluntary commitments to meet CO2 intensity goals at a sectoral level (similar to low-carbon fuel standards) or to provide a given share of output from low-carbon inputs (as with renewable transport fuel obligations), public procurement rules or auctions, tax credits, and schemes that allow consumers to differentiate between products so that they can buy low-carbon products if they wish to.

Investment risk mitigation. Supply chain risks and market uncertainty will persist for hydrogen use in most industrial applications over the next decade, especially where final product margins are tight. Specific risks also include cross-border variations in environmental regulations, and the risk of creating monopoly hydrogen suppliers of low-carbon hydrogen at high prices. To help manage these risks, governments might participate in project financing across borders, as in the EU Important Projects of Common European Interest (IPCEI), or organise competitive bidding for hydrogen supply contracts. In individual industrial clusters, or across a broader region, there may be an opportunity to spread risk for potential hydrogen buyers by establishing intermediaries that can sign multi-year contracts for future hydrogen supply, thus pooling their risk according to the scale and timing of their anticipated demand and providing more certainty for investors. Development of CCUS as a service business and special development zones could also help manage risks and therefore minimise costs

R&D, strategic demonstration projects and knowledge sharing. Hydrogen is already extensively used in industry today, so much of the research and cost reduction can be undertaken by the private sector as commercial competition increases, especially on the demand side. On the supply side, public support for the first major applications of CCUS technologies in a given region and large-scale integrated electrolyser demonstrations can help ensure that some of the resulting knowledge is widely shared to accelerate subsequent adoption. However, for novel applications (especially those at low technology readiness levels) and complex demonstrations, there might still be a case for public R&D support. Demonstration projects must be linked to overall energy policies and strategies, to avoid one-off projects that do not contribute to sustainable scale-up. In the steel sector, 100% hydrogen DRI needs further refinement and demonstration, and the emergent option of ammonia in DRI can be investigated. To facilitate large-scale demand for hydrogen and hydrogen-based products, proving and improving the (co-)firing of hydrogen in turbines and (co-)firing of ammonia in boilers/turbines/fuel cells are needed for de-risking. Improvements to the storage of hydrogen, including as liquid hydrogen, would also be valuable.

Harmonising standards, removing barriers. Areas that would benefit from international harmonisation and common standards include hydrogen purity and pipeline specifications for industry, comparable to ISO standards in the transport sector, safety protocols for the use of hydrogen and hydrogen-based fuels and feedstocks, and “guarantees of origin” (Table 12).

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2. Existing gas infrastructure: Tapping into dependable demand

Some 3 million km of natural gas transmission pipeline are in operation around the world today, and even greater lengths of distribution pipeline. These pipelines have near-term strategic value for hydrogen scale-up (Chapter 3). With only modest additional investment in infrastructure or end-use equipment, they would be able to transport the output of new hydrogen production facilities at low marginal costs, reducing the cost of supplying low-carbon hydrogen.

Before 2030 governments will need to take important strategic decisions about the long-term future of natural gas and gas pipelines in order to ensure a smooth transition towards full conversion or, potentially, away from gas grid utilisation altogether. These decisions will confront all gas networks at some point if they are to reduce emissions significantly (including fugitive emissions) because there is no attractive low-carbon alternative. They will have knockon implications for the investment needs of the electricity grid. Above a blended share of hydrogen of about 20%, the costs of modifying end-user equipment and the grid itself are only likely to be justified by a wholesale switch to 100% hydrogen. The two main ways to use hydrogen in the gas grid – blending hydrogen with natural gas, and converting the grid to 100% hydrogen – are distinct and treated independently in the following discussion.

Blending hydrogen

It is possible to blend small shares of hydrogen in existing natural gas systems with only minor changes to infrastructure, equipment and most end-user appliances, if changes are needed at all. Some new investment in hydrogen injection facilities would be needed, but in general blending at a safe level offers a relatively quick and easy way to transmit hydrogen supplies to end users, as long as hydrogen production is well-located near the gas transmission or distribution network.

As described in Chapter 5, several projects around the world are already demonstrating hydrogen blending in the gas grid for use in buildings, and more are planned on a larger scale. Among the larger proposed projects for coming years are electrolysers of 100 MW to 250 MW in Europe and North America that would run on wind or hydro power and inject tens of thousands of tonnes of hydrogen per year into the gas network. There are also proposed projects for blending hydrogen from natural gas with CCUS in Europe, including plans in North West England to inject around 0.6 MtH2/yr into the gas grid and to supply hydrogen to chemical plants by 2030, thus linking the gas grid and an industrial cluster. If these projects, and the H21 North of England project, go ahead, a sizeable and dependable hydrogen demand of over 2 MtH2/yr to could be created by 2030.

If hydrogen were blended into all natural gas use in the European Union at just 5% by volume, this would boost low-carbon hydrogen demand by 2.5 MtH2/yr. If this were supplied by electrolysers then it would require almost 25 GW of water electrolysis capacity. With cumulative installed capacity since 2000 standing at under 1 GW, this would amount to a significant scaleup, promoting efficiency improvements and capital cost reductions of up to one third. The capital investment for 25 GW of electrolyser capacity could be around USD 20 billion, plus an additional investment of over USD 3 billion for injection facilities (FCH JU, 2017). If the hydrogen were sourced from CCUS-equipped facilities instead, costs would likewise be expected to decline (not least because of the benefits that economies of scale bring to CO2 transport and storage), but less steeply.

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The costs and avoided emissions of blending depend on hydrogen costs, natural gas costs and the CO2 intensity of hydrogen production (Figure 67). At prevailing natural gas costs of USD 5/MBtu, a 5% blend (by volume) of hydrogen costing USD 4/kg would increase delivered gas costs by around 8%,55 but the impact in terms of larger-scale production and efficiencies should reduce the costs of hydrogen in the future. If the hydrogen and natural gas have no associated upstream greenhouse gas emissions, such a 5% volume blend would reduce the CO2 intensity of delivered gas by 2%.

Figure 67. Cost and emissions intensity of blending hydrogen into the gas network at different blend shares

Notes: Cost of delivered blended gas with assumed USD 4/kgH2, emissions intensity of “baseline SMR” = 91.0 kgCO2/GJ H2, “60% lower” = 36.4 kgCO2/GJ H2 and ”zero emission” = 0 kgCO2/GJ H2. Blend shares on a volumetric basis.

Source: IEA 2018. all rights reserved.

The cost and emissions reduction from hydrogen blending depend on the source of hydrogen and gas price. A 5% blend of low-carbon hydrogen could reduce CO2 emissions by 2%.

Conversion to 100% hydrogen

The conversion of existing gas grids to supply 100% hydrogen would lower distribution costs for hydrogen by facilitating much larger-scale supply; it would also enable sources of pure hydrogen demand (for example transport and industrial users) to connect to a common network.

The existing grid is not the only possible way to develop a future hydrogen transmission and distribution infrastructure, but it is likely to be the most cost-effective, especially at the distribution level.56 Some investment might be needed in key components of the grid, especially on the distribution network, but this should be technically and economically feasible

55Cost increases for end users could be lower, depending on tax treatment, pricing models and taxpayer support.

56Costs of repurposing plastic distribution pipelines to carry 100% hydrogen are uncertain, but estimated at USD 14 000/km (H21, 2018), whereas new hydrogen distribution pipelines costs range from USD 130 000/km to USD 2 700 000/km, depending on aspects such as labour costs and population density (SGI, 2017). The needs to oversize pipelines in anticipation of future demand growth would add to upfront costs.

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(NN, 2018; Dodds and Demoullin, 2013).57 Where distribution pipelines have been installed or upgraded recently they are likely to use polyethylene or nylon pipes that could carry 100% hydrogen. Existing pipelines do not require new permits, which can take years to acquire, further raising costs and risks and slowing the pace of change. There are also non-economic advantages to making use of existing infrastructure, including continuity of institutional arrangements and the avoidance of construction works, which could arouse opposition from local populations and owners of existing assets.

Converting to 100% hydrogen is a bigger change than blending. Conversion requires an overnight switch to 100% hydrogen supply for each part of the affected network, which means that new compressors and, in some cases, storage facilities, need to be available in advance.58 It also requires replacement of meters, compressors and monitoring equipment, thorough inspection of older parts of the pipeline, and replacement of current gas appliances. Furthermore, citizens’ reactions to such a programme are as yet untested. In the 2030 timeframe, full conversion is expected to be realised in fewer places than blending and only in limited parts of national grids, such as town distribution networks or specific underused transmission pipelines. The H21 project, currently at feasibility study level, proposes a conversion of the UK city of Leeds to 100% hydrogen from the late 2020s, with over 1 MtH2/yr from natural gas with CCUS from a North Sea industrial cluster (H21, 2018).

Near-term policy priorities

Targets and/or long-term policy signals. The timely development of clear roadmaps would decrease obstacles to grid conversion and help potential hydrogen suppliers estimate future market size. The timeframes for grid upgrade and conversion programmes are long, as are the timeframes for turnover of consumer appliances for gas use. Strategic decisions about future gas infrastructure and heating sources are particularly important in colder climates where heating accounts for a significant share of energy use and CO2 emissions. Timelines for the first large-scale projects might act as critical milestones in long-term plans.

Demand creation. At current cost levels, even low levels of hydrogen blending require policy support to stimulate demand from gas suppliers and to encourage hydrogen equipment production and infrastructure use. Few such policies are in place today (Dolci et al., 2019). To become a dependable source of low-carbon hydrogen demand, blending could be fostered by setting quotas, emission targets or blend levels for low-carbon gases, analogous to mechanisms for renewable electricity. Strategic consideration would need to be given to the sharing of additional costs if the effect on consumer prices could be counterproductive.

Investment risk mitigation. Governments could reduce the risks associated with investment in new hydrogen supplies for blending into the gas grid by clarifying market and technical conditions (Mulder, Perey and Moraga, 2019). The issues that need clarifying include conditions relating to third-party access, regulated returns for system operators, and consumer protection. Governments and system operators could further help investors to manage risks by taking steps to ensure that existing and future equipment on the grid is able to operate with blended hydrogen, including gas storage, compressors, turbines and home appliances.

57The existing low-calorific gas transmission network in the Netherlands, which is becoming underutilised, has steel pipeline grades that are suitable for hydrogen transport (DNV-GL, 2017). By 2030, demand for this gas is expected to have fallen sufficiently to potentially give rise to a unique opportunity to convert a transmission pipeline to 100% hydrogen.

58Where transmission pipeline corridors are made up of several pipelines in parallel, these could be converted one-by-one, and local distribution grids also exist that can be isolated from the wider distribution grid and connected to a dedicated hydrogen source.

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59 If some countries import or store low-carbon electricity in the form of hydrogen or hydrogen carriers it will be more efficient in all cases to use this hydrogen directly in vehicles rather than converting it back to electricity for BEVs.

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