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Johnson Matthey Technol. Rev., 2020, 64, (3), 357

doi:10.1595/205651320x15910225395383

The Role of Zero and Low Carbon Hydrogen in Enabling the Energy Transition and the Path to Net Zero Greenhouse Gas Emissions

With global policies and demonstration projects hydrogen can play a role in a net zero future

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Article Synopsis

As public pressure to limit global warming continues to rise, governments, policy makers and regulators are looking for the most effective ways to achieve the target set by the Intergovernmental Panel on Climate Change (IPCC) to keep the global temperature increase to below 1.5°C above pre‐industrial levels. This will require the world to move to net zero greenhouse gas (GHG) emissions by 2050, and numerous governments have committed to reach net zero by this date, or even earlier. It is widely recognised that achieving net zero at the state, country and regional levels will necessitate a systems-wide approach across all the major sources of GHG emissions, which include power generation, transport, industrial processes and heating. Land use is also critical with billions of trees needing to be planted and a change in the amount of meat eaten. There is a growing realisation that hydrogen has a vital role to play, particularly to decarbonise sectors and applications that are otherwise extremely difficult to abate, such as industrial processes, heavy duty freight movement, dispatchable power generation and heating applications. Hydrogen will also provide long-term (for instance seasonal) energy storage, enabling much greater uptake of renewable power generation, which itself is a key prerequisite of the clean energy transition. Hydrogen can play a role in the decarbonisation of all major segments, and this means it can facilitate cross-sector coupling, enabling the exploitation of synergies between different key parts of the economy. This article discusses the different production routes to low and zero carbon hydrogen, and its uses across numerous applications to minimise and eliminate carbon dioxide and GHG emissions, building a picture of the key role that hydrogen will play in the energy transition and the broader global move towards decarbonisation and climate stabilisation. An overview of some of the ongoing and planned demonstration projects will be presented, outlining the importance of such activities in providing confidence that the hydrogen approach is the right one for multiple geographies around the world and that there are technologies that are ready to be deployed today.

1. Introduction

The use of hydrogen is not new. Fuel cells were invented over 150 years ago and have been providing on-board power to space missions for over 50 years. Industry makes millions of tonnes of hydrogen every year, with its main uses (in pure and mixed forms) being: oil refining (33%), ammonia production (27%), methanol production (11%) and steel production via the direct reduction of iron ore (3%). Hydrogen is manufactured primarily from the conversion of natural gas (~75%) and coal (~20%), with 2% from electrolysis. The associated CO2 emissions are of the same magnitude as those of the UK and Indonesia combined (1).

The urgent need to minimise and then eliminate CO2 and other GHG emissions to avoid a climate catastrophe is driving new dialogue around ways to achieve this, and hydrogen is moving to the centre in many of these discussions. For example, the Committee on Climate Change (CCC), the UK Government’s independent advisor on climate change, said in its net zero policy document that moving from the previous target of 80% GHG emissions reduction to the net zero target “changes hydrogen from being an option to an integral part of the strategy” (2).

This article will present an overview of some ongoing and planned demonstration projects, outlining the importance of such activities in providing confidence that the hydrogen approach is the right one for multiple geographies around the world and that there are technologies that are ready to be deployed today.

2. Net Zero Policies and Their Implications

The IPCC reported in November 2018 that global warming should be limited to 1.5°C (3), and they showed that this requires net CO2 and GHG emissions to become zero by 2050. Achieving net zero by 2050 is going to be very challenging, both at the country and the worldwide level. While CO2 emissions in the developed economies have generally either stabilised or started to drop, those in rapidly developing countries such as China and India are increasing significantly, as shown in Figure 1.

Fig. 1

Historical and projected annual CO2 emissions from major countries and regions. Reprinted from (4) under a Creative Commons Attribution 4.0 International license

Historical and projected annual CO2 emissions from major countries and regions. Reprinted from (4) under a Creative Commons Attribution 4.0 International license

The global requirement for energy to drive industry, transportation, heating and cooking is also rising, placing further stress on efforts to limit global warming (5). Nevertheless, several national governments have set net zero targets, and some have already enshrined them in legislation (6, 7, 8). In the UK, the Department of Business, Energy and Industrial Strategy (BEIS) responded to the IPCC report by commissioning the CCC to review the implications of a net zero target, and to assess whether there was a credible pathway to achieve zero GHG emissions. The CCC’s ground-breaking work outlined a bottom up approach to a total energy system decarbonisation, achieving net zero. On the back of this, the UK was the first of the G20 major global economies to legislate a net zero emissions target by 2050 when it updated the Climate Change Act early in 2020 (6). 15 other countries have now set net zero targets, including Sweden (2045), Denmark, France and New Zealand (all 2050) and several others (including Chile, Spain and the EU27, through the European Commission) are discussing the target and its timeline (9).

The implications of net zero are marked. In the past, those emissions most costly and difficult to abate could be left. However, net zero means that most sectors will have to become completely emission free. Furthermore, processes which offer negative emissions will become extremely important to offset areas such as aviation where a zero emission pathway will be extremely challenging for the foreseeable future. For example, the combustion of biomass with the capture and storage of the CO2 generated is one route to negative emissions, as is the more well-known example of planting trees.

3. The Role of Hydrogen in Enabling Global Decarbonisation and Net Zero

Hydrogen is regarded as a flexible energy vector, and this section discusses its potential application in a number of key sectors: power generation (including energy storage), transportation, industrial and chemical processes and heating buildings (10). There are many divergent forecasts, as the appreciation of the role that hydrogen could play in reducing global emissions develops (2, 10, 11). However, many proposals require at least a tenfold increase in production of low carbon hydrogen over the fossil fuelled production today. As an example in 2017 the Hydrogen Council produced a report which described the scaling up of hydrogen out to 2050. The analysis showed a requirement for 78 exajoules (EJ) of low carbon hydrogen versus 10 EJ of fossil derived hydrogen today. The split proposed between different sectors was 9 EJ for power generation, 22 EJ for surface transport, 16 EJ for industrial energy, 11 EJ for building heat and power, 9 EJ of new process feedstocks and 10 EJ to convert existing feedstocks (10) to low carbon hydrogen.

3.1 Power Generation

One reason that hydrogen did not take off previously as part of global decarbonisation efforts was that there were other sectors with high CO2 emissions that could be reduced more cost effectively. From a policy perspective it was easier and cheaper to focus on the power sector where large reductions in emissions have been achieved. For example, in the UK the carbon intensity of electricity generation was almost halved between 2013 and 2017 (12) by the removal of coal from the system and the deployment of high levels of renewables such as solar and wind as well as conversion of some coal to biomass. The relative return has been high as there was an existing infrastructure to plug these new generation sources into, which to date has been largely able to cope with the move from large centralised generation facilities to more distributed power generation (such as wind and solar). However, the existing system may struggle to run stably as the proportion of renewables increases further. For example, there was a major loss of power across several regions in the UK in August 2019 when the system lost stability, partially caused by loss of a large off-shore wind farm (13).

Increasing the renewable content in the power generation sector is a key lever in moves towards net zero across many sectors, and renewable energy now accounts for a third of global power capacity (2). In the UK, up to 40% of electricity generation comes from renewables today, including 20% from wind, 12% from biomass and 6% from solar (14, 15). This increasing trend will clearly continue, driven both by the needs to decarbonise the power generation sector, and by the continued reductions in the cost of wind and solar power installations. Figure 2 shows the dramatic drop in the cost of utility scale solar, on-shore and off-shore wind power between 2012 and 2023 (17), showing how competitive renewables have become with fossil fuel power generation. A recent report from Bloomberg New Energy Finance (BNEF), USA, (18) states that from 2010 to the present day, there has been an 85% reduction in the cost of solar power and a 49% reduction in the cost of wind power. Indeed, the BNEF report goes on to say that more than two thirds of the global population today live in countries where solar or wind, if not both, are the cheapest form of new electricity generation. By 2030, new wind and solar are forecast to get cheaper than running existing coal and gas plants almost everywhere, if the transmission system costs are ignored.

Fig. 2

Cost of generation for utility scale renewables and fossil fuels from 2012 to 2022 (16)

Cost of generation for utility scale renewables and fossil fuels from 2012 to 2022 (16)

As well as the system stability challenges mentioned above, another concern with increased future reliance on renewables is how to maintain supply when the sun isn’t shining and the wind isn’t blowing. This introduces the need for large scale energy storage, with different storage and release timescales depending on location. For example, California and the UK have economies of comparable sizes, and have a similar total electricity demand, but the seasonal variation in energy demand is lower in California than in the UK, due to its more stable climate. In California, therefore, the main requirement is for short-term energy storage, storing excess solar energy during the day for use in the evening and overnight, so battery-based solutions make sense here. In the UK (and in large parts of Europe) there are massive seasonal demand fluctuations, so very large amounts of excess energy must be stored for much longer periods of time. In fact, as the proportion of renewables increases there will be a need for even more seasonal energy storage as the fossil fuel baseload has been reduced, which lends itself to a gas-based solution. Hydrogen will play a key role here since it can be generated from water through electrolysis using excess renewable energy (to make zero carbon hydrogen), as well as by advanced gas reforming with carbon capture utilisation and storage (CCUS) (to make low carbon hydrogen), as discussed later. Crucially, hydrogen is able to provide underground storage of a zero‐carbon fuel at the multi-Terawatt hour (TWh) scale required for inter-seasonal energy storage. This underground hydrogen storage can be in depleted gas fields or salt caverns, depending on local geological conditions (19).

Turbine manufacturers are already turning their attention to hydrogen gas turbines. Most have a turbine capable of taking a blend of hydrogen and natural gas today and are working on 100% hydrogen turbines. In this way, hydrogen provides the required flexible, dispatchable power to compliment the growth in variable renewable generation.

3.2 Transportation

There is no doubt that many countries have made significant steps to decarbonise the power sector, but this is not the case for other sectors such as transport where emissions have increased over the past 10 years (20, 21). Even in Europe, where tailpipe CO2 levels are regulated and where there is a strong drive to improve fuel efficiency (and reduce CO2) to minimise fuel and vehicle taxation costs, the last two years have seen an increase in the average CO2 emissions of new cars in the European fleet (see Figure 3). This has been partly driven by the reduction in sales of diesel vehicles (which are more fuel efficient than comparable gasoline vehicles) and by the increase in sales of larger cars, such as sport utility vehicles (SUVs). Nevertheless, this trend is going in the wrong direction and needs to be reversed rapidly.

Fig. 3

Average CO2 emission of new cars sold in Europe (22)

Average CO2 emission of new cars sold in Europe (22)

The two main routes towards net zero ground transportation are based on uptake of battery electric vehicles (BEVs) and fuel cell electric vehicles (FCEVs). BEVs are already being sold in significant numbers and in the passenger car sector these will make up a large proportion of sales in a future, decarbonised world (22). However, there are transport applications where hydrogen fuel cells constitute a more suitable zero emission powertrain, such as in long haul trucking. Hydrogen (when pressurised in storage tanks) can have a much higher energy density than batteries and refuelling with hydrogen can be carried out in a similar timeframe to filling current fuel tanks, while the batteries required to meet the needs of long haul trucks would need to be very large, and therefore expensive and heavy, and require a long time to charge (23). Fuel cells also match the needs of cars covering large annual distances, where the long range and fast refuelling advantages make a compelling combination. In addition, fuel cell powered locomotives are starting to be introduced, and these could provide a cheaper route than electrification to decarbonise rail transport for branch lines (24).

Many governments (25) have developed strategies around the future use of hydrogen in transportation and have set targets on the uptake of FCEVs and the number of installed hydrogen refuelling stations (HRS) to provide their fuel. For example, the uptake of FCEVs is projected to increase massively in China, on the back of strong government policy and incentives. The government is planning to have over one million FCEVs in the vehicle fleet by 2030. Japan and South Korea are also strongly focused on developing into hydrogen economies, and part of this involves increased uptake of FCEVs in the transport sector, with concomitant HRS infrastructure development. As well as being driven by energy security considerations, this government focus on hydrogen also provides support and stimulus for large domestic original equipment manufacturers who are the leaders in global FCEV introduction: Toyota, Japan, and Hyundai, South Korea.

So fuel cells will work alongside batteries to play an important role in reducing the CO2 footprint of ground transportation. Furthermore, FCEVs also have a battery, so there are some very direct synergies between the two technology approaches.

3.3 Industrial Heat and Feedstock for Chemical Processes

The main historical use of hydrogen has been in refineries to process crude fuels into refined fuels, to remove sulfur and as a feedstock for ammonia and methanol production (26). In future, these processes will need to be decarbonised further by moving to a low carbon hydrogen feedstock, but it is not a simple process as plant sizes are large and are heavily integrated. Retrofit opportunities are available, but they will often not decarbonise the processes in line with net zero targets.

New processes are being considered such as the use of electrolysis to provide hydrogen for ammonia production. Currently these are small prototypes and it is unclear at what point the economics of such a route could be considered competitive. Among others, ENGIE, France, and Yara International ASA, Norway, have announced a project in Western Australia (27) based on using solar power, however there are challenges in storing electricity or hydrogen to buffer for night‐time as chemical plants do not like to be started up and shut down repeatedly.

With the move to net zero there has been a focus on heavy industry. Under the previous GHG reduction targets of 80%, it was recognised that heavy industry is hard to decarbonise and it would be likely that residual emissions would be left in certain sectors. However, net zero means that nearly all emissions need to be removed from the industrial sector as there are other areas that are even harder to decarbonise, such as aviation. The challenge for industry is it has few routes to decarbonisation since high temperature processes have historically used fossil fuels and conversion to electrification is not deemed technically or commercially feasible in many cases. Hydrogen is viewed as the most viable technical alternative and given the correct support to value the low carbon product could be the most economical solution.

The other major issue with industrial processes is the scale. Today a world scale methanol plant can produce 5000 tonnes per day (tpd) from fossil fuels, primarily natural gas and coal. To convert a single plant of this scale to using hydrogen produced by electrolysis would require power from more than 500 of the world’s largest wind turbines (28). There are examples of plants (29) that can use renewable energy to generate hydrogen for production of methanol when combined with captured CO2, but these are currently at much smaller scale than required for a world market of greater than 75 million tonnes per annum (30).

3.4 Heating Buildings

Recently heating is an area in focus particularly in the UK where currently 85% of domestic houses use natural gas. With a net zero ambition all heating must be fully decarbonised. Whilst electric heat pumps can be an efficient route and will play a part to low carbon heating (particularly in new housing stock), the uptake of this technology is low, so alternative solutions will be required and again hydrogen offers a number of advantages as it can be retrofitted into existing systems in the home (31).

The challenge posed by heating in the UK (and a number of countries worldwide) is that there is a marked seasonal variation in energy requirement through the year. An often-cited graph (Figure 4) demonstrates this well, showing the energy demand in the UK between 2015 and 2018 split between the different fuels. What is clear is that the UK relies heavily on gas to provide a secure and resilient energy system. Gas provides on average around three times more energy than electricity and at peak demand this can increase to more than five times more energy. The other stark feature of the graph is how constant the demand for electricity and transportation fuel are, whilst the demand for gas is very seasonal. The ability to store gas in large volumes and the infrastructure in place to deliver gas to the end user allows for the rapid response to changes in demand profile.

Fig. 4

Annual trends in the UK’s daily use of energy for electricity, transport and gas. Data are from the National Grid, Elexon and BEIS. Charts are licensed under an Attribution-No Derivatives 4.0 International license. By Grant Wilson, University of Sheffield, UK

Annual trends in the UK’s daily use of energy for electricity, transport and gas. Data are from the National Grid, Elexon and BEIS. Charts are licensed under an Attribution-No Derivatives 4.0 International license. By Grant Wilson, University of Sheffield, UK

The proposal from the CCC for net zero requires the capacity of the electricity grid to double, both in terms of generation and transmission, to accommodate the large increase in BEVs. To date the UK has made great strides in decarbonising power, but realistically three to four times more renewable generating capacity is needed and network infrastructure to meet the new requirement before considering using large amounts of renewable electricity for heat or to make hydrogen to be used for heating. Therefore, it has widely been proposed to use low carbon hydrogen, manufactured from natural gas at large scale, to provide decarbonised heating. Initially this would be by blending hydrogen into the grid. In the future when the safety case has been proven there could be the move to 100% hydrogen in the UK’s gas transmission and distribution system.

Again in the UK, the H21 report (32) has been instrumental in setting out a clear, rational plan to cover all requirements for a transition from natural gas to hydrogen, using Leeds as a test case. The proposal had four steam methane reformers produce hydrogen coupled with CCUS. The hydrogen is then distributed through the polyethylene piping that is rolling out across the gas distribution network. The domestic side would require burners to be changed (for example gas boilers, cooking hobs and ovens), but this was done in the 1960s when the UK transitioned from town gas (which contained around 50% hydrogen) to natural gas (which contains essentially no hydrogen) (33). A lot of attention has been paid to the H21 work as it gave a fully costed route using existing technology blocks with a scheme to roll it out across a real network by domain. The work was recently extended to cover the North East of England.

Trials are taking place in the UK at Keele University where an ITM Power electrolyser (ITM Power, UK) is blending hydrogen into the private university gas network. The project (34) is led by Cadent, UK, and it is funded by the Office of Gas and Electricity Markets (Ofgem) (£6.8 million). To cover the domestic use case BEIS has awarded (35) £25 million to a project managed by Arup, UK, called Hy4Heat. The UK is well placed as an iron gas main replacement programme (36) has been running for a number of years converting piping to polyethylene, which is a much better material for transporting hydrogen. Iron piping has issues with embrittlement when in contact with hydrogen, which would lead to safety issues. Other trials looking at 100% hydrogen in the gas grid under the H21 programme are being led by Northern Gas Networks, UK, which include research and development (R&D) as well as operational and maintenance considerations of conversion.

As mentioned above, one of the key considerations for heating is to be able to store large volumes of energy and distribute it across the country. In the next section we will consider how hydrogen can be made, stored and distributed.

4. Low and Zero Carbon Hydrogen Production, Storage and Distribution

While hydrogen can be produced through the electrolysis of water, most of the hydrogen produced today is manufactured by steam methane reforming (SMR), in which, at high temperatures, natural gas is converted to hydrogen and CO2. As identified by the CCC, production of bulk low-cost, low carbon hydrogen from fossil resources is an integral part of meeting the UK’s net zero obligations (and net zero targets around the world). It can also make a significant and important contribution to the UK’s pressing 4th and 5th carbon budget shortfalls. The low cost aspect is important: at present the cost of manufacturing hydrogen by advanced gas reforming incorporating downstream CCUS (to ensure the hydrogen has a low carbon footprint) is around US$1.50–2.80 kg−1, while the cost of hydrogen from renewables is much higher, falling between US$3.00–7.50 kg−1 (1). Hydrogen made from electrolysis using renewable electricity is regarded as zero carbon and is referred to as ‘green’ hydrogen, while that made via methane reforming with CCUS is regarded as low carbon and referred to as ‘blue’ hydrogen. While the end-point in a fully decarbonised ecosystem will be green hydrogen, the most cost effective way to integrate hydrogen broadly into a wide range of applications today (and for the foreseeable future in many parts of the world) is to use blue hydrogen. For example, the CCC’s Net Zero report and roadmap predicts that the UK will require approximately 270 TWh of hydrogen in 2050 (up from around 15 TWh today), and they estimate that around 80% of this will be blue hydrogen, with the remaining 20% being green, as shown in Figure 5 (2).

Fig. 5

Projected net zero UK demand for hydrogen in 2050, and the proportion generated by electrolysis (green hydrogen) and advanced gas reforming (blue hydrogen). Copyright (2019) Committee on Climate Change (2)

Projected net zero UK demand for hydrogen in 2050, and the proportion generated by electrolysis (green hydrogen) and advanced gas reforming (blue hydrogen). Copyright (2019) Committee on Climate Change (2)

Before we discuss the routes to blue hydrogen, electrolysis will be outlined. Electrolysis uses electricity to split water into hydrogen and oxygen. This reaction takes place in an electrolyser, which like fuel cells consists of an anode and a cathode separated by an electrolyte. There are two commercially available technologies:

  • Alkaline technology has been commercially available for many years. The electrolyte is a liquid alkaline solution of potassium hydroxide and materials like nickel, carbon-platinum, cobalt and iron are used for the electrodes. Alkaline is considered a well-known, lower risk technology, and generally has a lower capital cost than proton exchange membrane (PEM) but a higher operating cost (37)

  • PEM technology is more recently commercialised. The electrolyte is a PEM, which allows diffusion of H+ from one electrode to the other. One electrode is Pt and the other is iridium/iridium oxide. Ir/IrOx is necessary because it can withstand the acidic conditions of the cell (many metals dissolve under these conditions) (38).

There are two other types of electrolyser at earlier technology readiness levels:

  • Anion exchange membrane (AEM) is similar to PEM but anions diffuse through the electrolyte. AEM is expected to be as efficient and dynamic as PEM but membrane development is required for it to withstand the alkaline conditions (39)

  • Solid oxide electrolysers run at high temperature (600–800°C) and could make use of waste heat or steam in industrial processes. Currently there are issues relating to the durability of the ceramic materials at high temperatures.

The topic of electrolysis will be revisited in the future as there are important advances required to enable large scale deployment. In the near term, as mentioned above, the consensus is that blue hydrogen will be key. Johnson Matthey, UK, has developed a process known as Low Carbon Hydrogen (LCHTM), which has a gas heated reformer and autothermal reformer at its core to generate blue hydrogen from natural gas, shown in Figure 6 (40). This approach gives a higher hydrogen yield and is more energy efficient than existing SMR technologies. And, crucially, this process is easier and cheaper to decarbonise through CCUS than an SMR. The process delivers a high CO2 capture rate, high efficiency and low-cost solution, providing significant benefits compared with SMR and alternative autothermal reforming (ATR) technologies. The approach is based on established chemical process engineering, designed to operate at scale, enabling carbon reduction for industry, dispatchable power, domestic heating and transport.

Fig. 6

The LCHTM flowsheet

The LCHTM flowsheet

The main benefits of the LCHTM technology compared to the current SMR technology with >95% CO2 capture rates are:

  • a cost-effective way of producing low carbon hydrogen with a CO2 stream that is suitable for transport and geological storage

  • the hydrogen product is of suitable quality and quantity to be used for a range of applications including domestic, industrial and, in the future, power generation and fuel cell vehicles

  • high reliability and robustness in terms of the ramp rates and turndown capability which can match demand

  • eliminates the cost issues associated with the SMR post-combustion CO2 removal unit

  • small plot plan allowing efficient utilisation of existing available area and option for installation of larger plants in case of increasing hydrogen demand.

A comparison of the process performance for LCHTM versus an SMR is shown in Table I, where the hydrogen production rate has been fixed and a minimum CO2 capture rate of 95% has been required.

Table I

Comparison of Process Performance and Total Capital Cost for a Steam Methane Reforming versus an LCHTM plant.

Parameter Units SMR flowsheet LCH flowsheet
Natural gas as feed kNm3 h−1 39.74 38.31
Natural gas as fuel kNm3 h−1 5.36 0
Total natural gas kNm3 h−1 45.10 38.31
Natural gas energya MW 439 400
Hydrogen production kNm3h−1 107.4 107.4
Hydrogen energya MW 322 322
Natural gas efficiency % 73.3 80.6
CO2 captured tonne h−1 83.7 76.3
CO2 emitted tonne h−1 4.4 3.7
CO2 captured % 95.0 95.4
ISBL + OSBLb CAPEX £, millions 261 159

aEnergy is stated on a lower heating value basis

bInside battery limits (ISBL), outside battery limits (OSBL), capital expenditure (CAPEX)

Overall, the LCHTM technology offers the UK and other countries a ‘low regrets’ way of moving towards a net zero scenario as all of the unit operations have been deployed at scale in other areas, such as in production of methanol and ammonia. Design work has confirmed that a single train is capable of producing 300 MW (lower heating value) of high purity hydrogen. Furthermore, work has been conducted that indicates that a 1.5 GW hydrogen plant could be built in a single train with a number of equipment items in parallel.

One of the major barriers to hydrogen deployment versus other renewable technologies has been the requirement to build new infrastructure immediately, particularly for generation and distribution to the various customers. Today much of the hydrogen market is dominated by captive supply where generation is next to use, for example hydrogen production for use at a refinery for upgrading transport fuels.

The view that hydrogen can be crucial to decarbonise multiple market sectors means that hydrogen production at scale will be required. It is envisaged that a hub and spoke model will work best, with centralised production facilities bearing the brunt of the load, supplemented by smaller production facilities operating away from large emissions centres. The clustering of existing industry, gas facilities (liquified natural gas, gas turbines), ports, major pipelines and intersections with hydrogen production and CCUS facilities represents the lowest cost route to net zero. The additional ability to reuse existing gas distribution networks in some countries will play a large role in reducing transport costs.

Before returning to examples of key UK projects it is worth discussing how energy is moved as this is one of the key infrastructure challenges to make a dramatic energy transition. Transportation and storage are costly elements of the value chain. At small scale distributed production will rely on local storage and distribution, for example tube trailers. At large scale the reuse of gas pipelines will allow hydrogen to be moved around cost effectively and there are known and available solutions for storing hydrogen such as salt caverns. More capacity will be required to deal with the volumes of gas required, but this is not seen as a barrier for deployment.

There is another opportunity that hydrogen offers, which is to move renewable energy from where it can be generated at very low cost to where it can be monetised. There are areas of the world which have very good utilisation factors for renewables, but they are not near demand centres and the cost and practicality of a transmission system would not be viable. The focus has been on using hydrogen to transport the energy in a chemical bond. Different strategies are being considered, such as liquefication of hydrogen, synthesis of a hydrogen containing molecule (ammonia or methanol) that can be converted back to hydrogen or use of a carrier (liquid organic hydrogen carriers) where an organic molecule is hydrogenated and dehydrogenated. The main considerations are process efficiency, energy density, safety and whether there is existing infrastructure (41).

Extensive studies have been carried out and large-scale projects are now being initiated to demonstrate how low and zero carbon hydrogen can be manufactured at scale and integrated at a city-wide and regional level (4245). In the UK, BEIS are currently engaged in supporting a number of studies covering the whole value chain to understand the current technology options and potential lowest cost solutions. The strategy is being developed as part of the Clean Growth Plan. In addition, since the announcement of the UK’s Net Zero legislation there have been further funding streams announced, which are either live (Industrial Strategy Challenge Fund), under consultation (Industrial Energy Transformation Fund) or will be consulted on in 2020 (Low Carbon Hydrogen). However, this should only be considered as the tip of the iceberg. Of critical importance to the sustained roll out of low carbon hydrogen will be the business models that allow private investment, which improves the supply chain and increases scale ultimately driving down costs to the consumer.

Whilst no definitive policy changes have been made to date in the UK there has been much more focus on how the UK can lead in low carbon technologies and embed this at the heart of plans for clean growth. BEIS has responsibility for both the Clean Growth Plan and Industrial Strategy. It has recently been much more active in the hydrogen and CCUS space, considering production, transport and use. Another £33 million has been made available under the Hydrogen Supply Competition (HSC) focused on production (46).

5. Case Study: HyNet

The HyNet project comprises the development and deployment of a 100 kNm3 h−1 (equivalent to 300 MW of hydrogen, lower heating value) hydrogen production and supply facility to be sited at Essar Oil’s Stanlow refinery utilising Johnson Matthey’s LCHTM technology. It could represent one of the first deployments of a technology proven in other sectors to the production of clean hydrogen and will achieve this at scale, at higher efficiency than other reforming technologies and with a very high carbon capture rate. It therefore will deliver low cost, low carbon bulk hydrogen.

This plant is core to the North West HyNet project. It is not a theoretical plant design but one that meets the specific regional demands, delivered on a specific project site. It will provide a foundation reference design for replication through multiple lines in the North West, elsewhere in the UK and internationally. When associated with the HyNet CO2 transport and storage infrastructure, this delivers low cost, low carbon hydrogen for key industrials alongside non-disruptive blending to over two million households as part of delivering a net zero industrial cluster in the region. A schematic of the concept is shown in Figure 7.

Fig. 7

A schematic of the HyNet project. Provided courtesy of HyNet

A schematic of the HyNet project. Provided courtesy of HyNet

Having completed prefeasibility work under Phase 1 (47) of the BEIS HSC, the full front-end engineering design and wider operational, delivery, contracting and consenting programme is underway as part of Phase 2 of the HSC, which will deliver a shovel-ready project, providing the basis for a final investment decision. The project is being developed by a consortium of Johnson Matthey, as technology provider, SNC-Lavalin, Canada, as project delivery specialists, Essar Oil which owns the land, and led by project developer Progressive Energy, UK.

6. Case Study: Acorn

The Acorn Hydrogen Project, in North East Scotland (Figure 8) places advanced reforming technology at its core. The project will deliver a replicable process for cost-efficient hydrogen production based around natural gas, whilst capturing and sequestering climate changing CO2 emissions.

Fig. 8

A schematic of the Acorn project to be located in Scotland at St Fergus. Provided courtesy of Pale Blue Dot

A schematic of the Acorn project to be located in Scotland at St Fergus. Provided courtesy of Pale Blue Dot

By 2025, the plant could be the first operational clean hydrogen plant in Europe, enabled for early development by the Acorn CCUS Project which is under development at the same location. North East Scotland is home to the oil, gas and renewables supply chain, which has the capability, capacity, technology and assets to diversify into a future hydrogen supply chain, creating economic value and jobs for the region and supporting a just transition to a low carbon economy. Clean hydrogen can be blended into the National Transmission System (NTS) and used in the region for decarbonising heat, industry and transport.

Phase 1 of the HSC delivered a feasibility study for an advanced reforming process at St Fergus (48). The basis of the study was export of hydrogen at a 2% by volume blend into the NTS. No technical issues were identified. Crucially, the work has also strengthened the partnering and route to market aspects of the Acorn Hydrogen Project.

The Acorn Hydrogen Project is led by Pale Blue Dot Energy, UK, and benefits from strong industry study partners in Shell, The Netherlands, Chrysaor, UK and Total, France, while Johnson Matthey will play a significant role in providing a hydrogen technology option for the project. Acorn Hydrogen offers Scotland and the UK the opportunity to capture up to 19 million tonnes CO2 equivalents of CO2 per year through the build-out, enabling the UK to reach its net zero obligations by 2050 and Scotland by 2045.

These are not the only projects that are being discussed in the UK. Recently announced, the Zero Carbon Humber (49) project brings together Equinor, Norway, Drax, UK and National Grid, UK with a vision to cut the emissions from the largest UK hotspot and again has hydrogen at the core. Johnson Matthey is also involved in a project called Cavendish (50) looking to produce low carbon hydrogen at the Isle of Grain, which would provide decarbonised dispatchable power to service London as well as providing a decarbonised gas for domestic heating.

It should be noted that this is not purely a UK opportunity as shown by the projects being discussed in The Netherlands, H-Vision project (51) at the Port of Rotterdam as well as Magnum (52), which is the conversion of a natural gas combined cycle gas turbine (CCGT) to hydrogen. The recently published US Hydrogen Roadmap (53) also discusses routes to hydrogen and sees a role for low carbon hydrogen production from natural gas.

7. Conclusions and Recommendation

Low carbon hydrogen has the potential to play a large role in supporting the journey to net zero. Projects should be deployed in the next 10 years to learn the real costs of operation and stimulate the supply chain. It will take time to build the volume of hydrogen production and the infrastructure for hydrogen use in all the sectors discussed above. There is always the question of balancing supply and demand, but with the many potential use cases building capacity will be a key starting point. Hydrogen produced by electrolysis powered by renewables is the ultimate answer and efforts need to be developed and scaled up, but it will struggle to deploy at the scale required in many locations in the near term. Both routes to low carbon hydrogen will be needed and they should be seen as complimentary with a transition happening over time.

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Acknowledgements and Declaration of Interests

The author declares the following interests. Johnson Matthey is a consortium member in the HyNet project; an industry partner in Acorn Hydrogen Project; and a supporter of Cavendish project. The author represents Johnson Matthey on the Hydrogen Council Working Board, the Decarbonised Gas Alliance, the CCUS Advisory Group and is on the Advisory Board of the new cross sector publication H2 View.

Supplementary Information

H2 View LINK https://www.h2-view.com/

The Author


Sam French currently works in Business Development at Johnson Matthey, leading the development of the strategy and the programme for Low Carbon Hydrogen. Previous roles at Johnson Matthey include Technology Manager for the steam reforming catalyst and technology research and development (R&D) team. After moving from R&D into Business Development, he was tasked with developing a portfolio of new opportunities for processes from new feedstocks, such as biomass, waste and renewable energy. Sam represents Johnson Matthey on the Hydrogen Council Working Board, the Decarbonised Gas Alliance, the CCUS Advisory Group and is on the Advisory Board of the new cross sector publication H2 View.

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