Green Hydrogen: A Tale From Two Countries

Written by Pierluigi Mancarella

In the context of decarbonizing power and energy systems worldwide, what is the role of green hydrogen that is generated from renewable energy sources through electrolyzers? Is it an unrealizable chimera, a possible but far reality, a game-change opportunity, or the panacea to all our decarbonization issues? In this article, we discuss the different approaches that are being explored in the UK and Australia – two of the countries that are leading the discussions on hydrogen – along with relevant differences, similarities, challenges, and opportunities.

Hydrogen has been used to power the moon landing, and since then several discussions on a “hydrogen economy” have taken place in different countries at various points over the past decades. However, it is only very recently that technology maturity and scale of production are making it a serious candidate to play a role in future power and energy systems. In particular, several roadmaps worldwide are envisaging the use of hydrogen as an energy vector to support the decarbonization of the whole energy system. In this respect, one of the key options is green hydrogen from electrolysis powered by renewable electricity, which is more and more coming to the fore while renewables technology cost drops. However, the techno-economic challenges and opportunities that are emerging for green hydrogen may be very different for different countries.

The economics of green hydrogen production is closely associated with the cost of the technology itself. In this regard, while renewables technology cost, particularly for wind and even more for solar, has dropped dramatically in the past decade and keeps following the trend, electrolyzers are still relatively expensive. However, the economy of scale for different electrolyzer technologies is likely to play a huge role as it indeed happened for renewables, with costs that may go down significantly with increasing production volume. Further and substantial benefits might also arise from the economy of scope, with the possibility of using hydrogen to support multiple sectors, as being envisaged and trialed in “hydrogen hubs” in many countries. Location and sizing of such hubs, and more in general electrolyzer plants, would also be heavily driven by the existing energy infrastructure.

Green hydrogen produced from otherwise curtailed renewable energy in electricity network-constrained areas could be injected into the gas network to decarbonize the gas sector. The feasibility of this power-to-gas process depends on a number of factors, including, among others, the availability of the gas network in relatively close proximity and the availability of sufficient gas flows at the injection point. In fact, particularly at the transmission level, the risk of embrittlement and leakage in steel pipes might pose constraints to the percentage of hydrogen that could be blended with natural gas, while at the distribution level this could be less of or not at all an issue, owing to the use of plastic pipes. In general, in the long term, some retrofitting of gas network pipes and other equipment (e.g., compressor stations) would be needed; this is beside the adoption of devices that would be suitable to burn gas with high, in case variable, hydrogen content, for domestic and industrial customers and hydrogen-based power plant alike.

Another important infrastructure aspect to consider, particularly for large-scale and long-distance (including cross-country) transportation of green hydrogen, is the suitability and economics of transporting energy in the form of electrons (transport electricity and then turn it into hydrogen at the use point) or molecules (produce hydrogen at the renewables site and then transport it in pipelines). The author’s ongoing research suggests that an optimal portfolio of HVDC lines and hydrogen pipelines might be the best option, depending on transportation distance and amount of energy transfer. Water availability constraints would also impact the optimal solution. In general, the impact on the electricity infrastructure might be substantial and should be adequately considered in integrated system planning, although dedicated corridors that link renewables hubs to hydrogen hubs might be better options in specific circumstances.

Figure. Sketch of a renewables-hydrogen hybrid corridor

Two countries that are leading on the uptake of renewable energy and are also considering decarbonization pathways based on hydrogen, including green hydrogen, are the UK and Australia. However, their starting points in terms of incumbent energy system are quite different, which also suggests a breadth of potential applications for hydrogen:

• UK: very seasonal heat demand, mainly supplied by gas; winter peak demand for both electricity and heat, with very high gas utilization; significant energy demand for transport; renewable energy potential unlikely to be able to cover the whole energy demand; energy system flexibility (for both electricity and heat) essentially relying on gas; need for energy import.
• Australia: relatively low heat demand, mostly in Victoria; electricity peak demand in summer; overall high industrial energy demand and significant energy demand for transport; much of the system flexibility provided by gas; practically infinite renewable energy potential, able to cover many times the electricity and, in case, the overall energy demand; large energy export, including liquefied natural gas, and great potential for renewable energy export.

As an important common point, both the UK and Australia are embracing a vision whereby sector-coupling and development of multi-energy systems can foster whole-system decarbonization. It is in this context that they are exploring, through different projects and practical trials, a number of paths for hydrogen deployment: these range from injection of hydrogen in the gas network to supply domestic and commercial users, including testing the suitability of the network asset to carry a gas blend, to industrial hydrogen hubs for multiple products and services. In particular, as mentioned earlier, by exploiting the economy of scope and existing industrial “anchor” load hydrogen hubs are being seen as key to make the first steps towards hydrogen project developments in both Australia and the UK. However, overall the fundamental drivers to invest into hydrogen in general and green hydrogen in particular as part of a future energy portfolio are quite different for the two countries, which reflects their different energy systems and end-use requirements.

In the UK the main driver for the development of green hydrogen is the flexibility that electrolyzers could provide to integrate renewables. This flexibility refers to both short-term operation balancing purposes and long-term (seasonal) storage. Seasonal storage, in particular, becomes essential in a renewables-based future, particularly if nuclear was no longer considered a viable option. While doing this, green hydrogen could be deployed to different extents, as part of a broader portfolio centered around a more electrified energy system, to support, in particular, decarbonization of the gas and heating sectors besides some segments of transport. Given the ratio of scale of energy consumption and renewable resources availability, the production of low-carbon hydrogen from natural gas with adoption of carbon capture and storage is another important option under consideration. Several projects in the UK are testing the feasibility and exploring the boundaries of such strategies and requirements, including with the aim of deploying the huge storage capability of the gas network to store renewable energy.

Similar studies and trials on the deployment of the existing gas network asset are also ongoing in Australia. Furthermore, given its huge potential on wind and solar production and at a very low cost, Australia is exploring bolder visions to become a renewable energy super-power by developing zero-carbon “future fuels”, including and in particular green hydrogen. These could be exported to other countries with limited renewable energy potential, such as Korea and Japan, to support their decarbonization targets. In this regard, the author’s ongoing work suggests that widespread large-scale electrolyzers, that are extremely flexible loads, would not only facilitate the integration of renewables by providing both short-term flexibility and security services and long-term adequacy and resilience options (e.g., via seasonal storage coupled to fuel cells and hydrogen turbines), but could also be effectively “co-developed” together with a renewable electricity system. In the context of renewable energy export, the technology used for shipping of future fuels (e.g., based on green hydrogen or ammonia), and its cost, would play an important role, and this is something that is the subject of important research and tests. Future fuels could also support decarbonization of heavy industry, including the manufacturing of energy-intensive metals such as aluminum and steel, which again could be exported as products with low to zero embedded carbon. This would be key in a future of low-carbon commodity trading.

Notwithstanding the diversity of situations exemplified, there seems to be a consistent picture of the potential role that green hydrogen could play in future energy systems worldwide, as emerged from the discussion on two very different systems such as the UK and Australia. However, several challenges are still being faced, including the difficulty of resolving the complex techno-economic interactions that arise in a “multi-energy system” context when different energy vectors (electricity, hydrogen, gas), networked infrastructures, sectors (including heat, transport, and heavy industry), and markets come together.

In the short term, it will be essential to identify options that are available to boost the business case opportunities for green hydrogen, which might include the use of electrolyzers to participate in ancillary service markets. In the long term, the plan for the development of an integrated multi-energy infrastructure and its economics, as well as the availability of an international renewable hydrogen market (in which Australia could play a role as a major exporter and the UK as the importer) are the biggest unknown. Another game-changer in the long term would be the issue of energy resilience. For example, hydrogen-based demand flexibility and deep storage technology potential could be used to navigate through the dark doldrums so much feared in the UK and Europe, while it would enable renewables-rich countries such as Australia to become more energy-independent, with major security of supply benefits also from a geopolitical perspective.

Regardless of the specific type and scale of implementation in different regions, it is very likely that a clean, affordable, secure, and resilient energy future will include a hybrid technology and infrastructure portfolio mix where hydrogen and particularly green hydrogen might play a significant role.

This article edited by Geev Mokryani

For a downloadable copy of the February 2021 eNewsletter which includes this article, please visit the IEEE Smart Grid Resource Center.

Pierluigi Mancarella (M’08–SM’14) received the M.Sc. (2002) and Ph.D. (2006) degrees in electrical energy systems from the Politecnico di Torino, Turin, Italy. He is currently the Chair Professor of Electrical Power Systems at The University of Melbourne, Melbourne, Australia, and Professor of Smart Energy Systems at The University of Manchester, Manchester, U.K. His research interests include multi-energy systems, grid integration of renewables, energy infrastructure planning under uncertainty, and resilience of low-carbon networks. Dr. Mancarella is an Editor of the IEEE TRANSACTIONS ON POWER SYSTEMS and the IEEE TRANSACTIONS ON SMART GRID, an IEEE Power and Energy Society Distinguished Lecturer, and the Convenor of the Cigre Working Group C6/C2.34 “Flexibility provision from distributed energy resources”.