Hydrogen Production and Uses

(Updated October 2020)

  • Hydrogen is increasingly seen as a key component of future energy systems if it can be made without carbon dioxide emissions. 
  • It is starting to be used as a transport fuel, despite the need for high-pressure containment.   
  • The use of hydrogen in the production of liquid transport fuels from crude oil is increasing rapidly, and is vital where tar sands are the oil source. 
  • Hydrogen can be combined with carbon dioxide to make methanol or dimethyl ether (DME) which are important transport fuels. 
  • Hydrogen also has future application as industrial-scale replacement for coke in steelmaking and other metallurgical processes. 
  • Nuclear energy can be used to make hydrogen electrolytically, and in the future high-temperature reactors are likely to be used to make it thermochemically. 
  • The energy demand for hydrogen production could exceed that for electricity production today. 

Hydrogen is not found in free form (H2) but must be liberated from molecules such as water or methane. It is already a significant chemical product, about half of annual pure hydrogen production being used in making nitrogen fertilisers via the Haber process and about one-quarter to convert low-grade crude oils (especially those from tar sands) into liquid transport fuels. There is a lot of experience handling hydrogen on a large scale, though it is not as straightforward as natural gas.  

Most hydrogen today is made by steam reforming of natural gas or coal gasification, both with carbon dioxide (CO2) emissions. Future demand will be mainly for zero-carbon hydrogen. Plans for increased hydrogen production are essentially based on electrolysis using electricity from intermittent renewable sources. Off-peak capacity of conventional nuclear reactors or other power plants can also be used. 

The rapidly-growing demand for hydrogen by oil refineries and chemical plants favours technologies with low costs. Limited hydrogen pipeline networks already exist, allowing production facilities to be some way from users. 

In future, a major possibility for zero-carbon hydrogen production is decomposition of water by direct use of heat from nuclear energy, using a thermochemical process enabled by high-temperature reactors.  

If hydrogen is produced by electricity from intermittent renewables then this is called 'green hydrogen'. 'Grey hydrogen' is that produced from methane with corresponding CO2 emissions, 'blue hydrogen' is grey hydrogen but with CCS (typically 50-70% efficient), and ‘yellow hydrogen’ uses nuclear electricity for electrolysis. ‘Turquoise hydrogen’ is produced from methane by molten metal pyrolysis, with solid carbon byproduct. Only green and yellow hydrogen are reliably zero-carbon. Future thermochemical production from nuclear power does not yet have a name. 

Like electricity, hydrogen is an energy carrier (but not a primary energy source). Hydrogen has some potential to replace oil as a transport fuel and in other applications. It is the preferred fuel for fuel cell electric vehicles (FCEVs), though portable storage at vehicle scale is a challenge. Hydrogen can also be used in internal combustion engines.

While hydrogen can replace liquid hydrocarbons, it is never as energy-dense or convenient to store and transport. However, it does compare well with batteries, which is why it and hydrogen-based liquid fuels have a lot of potential.

Electricity and hydrogen are convertible one to the other as energy carriers. However, the overall efficiency of electricity-hydrogen-fuel cell-electricity is no more than 40%. One approach to mitigate intermittency of wind and solar electricity is to make hydrogen by electrolysis and feed this into the gas grid, the power-to-gas strategy. It has been suggested that most electricity from wind might be used thus, greatly simplifying electrical grid management. 

In future some hydrogen produced for fuel may be converted into ammonia as a more energy-dense carrier medium volumetrically for trade or long-term energy storage. The mass energy density of hydrogen is 120 or 142 MJ/kg*, compared with methane 50 MJ/kg, propane 46 MJ/kg and ammonia 19 MJ/kg. Volumetrically, the energy density of hydrogen is low – 10.8 or 12.75 MJ/Nm3 (or liquid: 8.5 or 10.0 MJ/L)**.

* Lower (net heat of combustion) and higher (gross heat of combustion) heating values, respectively. Thus 33.3 or 39.4 kWh/kg. The higher heating value includes the latent heat in the vapourised water, the lower heating value (or net calorific value) excludes this.
** Nm3 = normal cubic metre (0 °C temperature and 1.01325 bar (i.e. 1 atmosphere) pressure.

All this points to the fact that while a growing hydrogen economy already exists, linked to the worldwide chemical and refining industry, and potentially for steelmaking, a much greater one is in sight. With new uses for hydrogen as a fuel, the primary energy demand for its production may exceed that for electricity production. 

Transport is expected to constitute the largest demand for hydrogen in both the EU and South Korea by 2050, reflecting the conversion of the heavy vehicle and large passenger car fleet from diesel to hydrogen FCEVs. Heating for buildings is expected to be the next largest demand, replacing natural gas. Railways can replace diesel fuel with hydrogen. 

If hydrogen is to fuel shipping or aviation, refuelling needs to be available worldwide, so Europe’s ambitious plans will need much wider take-up.

A September 2020 report by LucidCatalyst said that in addition to deployment of renewables for power generation: “The only known way to address the ‘difficult-to-decarbonize’ economic sectors is with the large-scale use of hydrogen as a clean energy carrier and as a feedstock for synthetic fuels such as ammonia.” But clean hydrogen needs to come from non-fossil sources, at a lower price – under $1/kg – than is prospective today.

An abundant supply of low-cost hydrogen would greatly boost world agricultural productivity through increased availability of nitrogen fertilizers, as well as fuelling transport.

National and regional plans 

The Institute for Energy Economics and Financial Analysis (IEEFA) estimates a global zero-carbon hydrogen demand of 8.7 million tonnes (Mt) per year by 2030. Forecasts of world hydrogen demand by 2050 vary from very little through 67 Mt (compared with about 70 Mt today) to 490 Mt, plus 158 Mt as industrial feedstock.

The International Energy Agency's (IEA's) Energy Technology Perspectives 2020 in its Sustainable Development Scenario projects global hydrogen production growing rapidly to about 445 Mt for energy use plus 75 Mt for process use by 2070. The 520 Mt hydrogen would be produced 58% by electrolysis and 40% from fossil fuels with carbon capture and storage (CCS). Of the energy demand, 60% is for transport, and of the process used, 60% is chemical and 40% steel production.

In Europe, EU energy ministers signed the Hydrogen Initiative, a non-binding political declaration of support for hydrogen development, in September 2018. The EU has launched a massive ‘green hydrogen’ programme based on surplus power from intermittent renewables sources to decarbonise industry and aviation and to develop export opportunities. Green hydrogen is seen as key to reaching 'net-zero' emissions targets, but as yet, costs are high due to expensive equipment and the amount of electricity required.

The EC’s hydrogen strategy for the EU published in July 2020 calls for the installation of at least 6 GWe of electrolysers powered by renewable energy by 2024 (compared with 1 GWe in 2020), producing up to one million tonnes per year of green hydrogen by 2024. From 2025 EU member states should treat hydrogen as an intrinsic part of their energy system, “with a strategic objective to install at least 40 GWe of renewable hydrogen electrolysers by 2030 and the production of up to ten million tonnes of renewable hydrogen in the EU.” Hydrogen use will be expanded to transport and steelmaking. From 2030 to 2050 “renewable hydrogen technologies should reach maturity and be deployed at large scale.” The EC expects “cumulative investments in renewable hydrogen in Europe [to] be up to €180-470 billion by 2050, and in the range of €3-18 billion for low-carbon fossil-based hydrogen” (i.e. with CCS). 

In June 2020 the trade body Hydrogen Europe said that EU hydrogen demand by 2030 would be about 16.9 Mt, of which 7.4 Mt would be green hydrogen produced from renewables, some imported from Ukraine and North Africa. Clean hydrogen from electrolysis using other low-carbon electricity such as nuclear, and natural gas with CCS, would provide 8.2 Mt, and 1.3 Mt would come from coal gasification with CCS. The report envisaged 20 Mt of green steel production using 1 Mt hydrogen by 2030. Other uses would be blending with natural gas, power generation and transport fuel.  

Germany’s national hydrogen strategy approved in June 2020 offers about €7 billion to bring electrolyser capacity to 5 GW by 2030 for green hydrogen. The strategy also provided €2 billion for projects abroad, as hydrogen imports will be needed – only a small proportion of estimated 2030 demand will be produced domestically. While the objective is to use green hydrogen, both blue and turquoise hydrogen will play a part.

France is providing €7 billion for green hydrogen to 2030, with €2 billion of this over the two years to 2022, in support of its 2018 hydrogen strategy. Some 40% of this will be funded from the EU’s €750 billion coronavirus recovery programme. 

China has not set such aggressive targets for green hydrogen as Europe, but the China Hydrogen Alliance, composed of companies, universities and research institutes, predicted in 2019 that the majority of hydrogen production would shift from fossil fuels to renewable energy by mid-century. Most of China’s hydrogen production of 22 million tonnes per year (one-third of world total of clean hydrogen) is from coal, and only 3% from renewables. It has almost 1000 coal gasifiers in operation accounting for 5% of its coal use, according to Cleantech Group. China plans to have one million FCEVs and 1000 hydrogen refuelling stations by 2030. Its target for 2050 is for hydrogen, mostly grey hydrogen, to comprise 10% of total energy, requiring about 60 Mt per year. 

Japan’s Ministry of Economy, Technology and Industry (METI) produced a comprehensive hydrogen strategy roadmap in 2016 and updated it in 2019. This is to replace fossil fuel use in Japan with mainly blue and grey hydrogen. Rapid expansion of hydrogen fuel cell use is anticipated in both buildings and mobility applications such as trucks and cars by 2030. It aims to reduce the cost to JPY 30/Nm3 by then, and to ¥20 later. Japan plans to import zero-carbon hydrogen and ammonia.

South Korea has plans for increasing use of FCEVs, especially buses and trucks fuelled by zero-carbon hydrogen, and expects hydrogen demand to double by 2030. Its national hydrogen roadmap says: “The total potential of hydrogen in Korea amounts to 17 Mt (equivalent to 564 TWh) in 2050, accounting for more than 20% of total national energy demand.” This is mainly blue hydrogen.

Russia is planning a new hydrogen industry by 2024. Gazprom is to test a new hydrogen turbine in 2021, and a partnership between Gazprom Energieholding and Siemens is reported to be pending. Gazprom aims to produce turquoise hydrogen by pyrolysis of methane (rather than steam reforming) to leave solid carbon rather than CO2. Rosatom produces hydrogen by electrolysis and is planning to test hydrogen-powered trains on the island of Sakhalin. 

In the USA, the Department of Energy’s H2@Scale initiative supports innovations to produce, store, transport, and utilize hydrogen across multiple sectors. The 11 Mt/yr of US hydrogen production has thermal potential of 1.3 EJ, and consumes nearly 5% of US natural gas usage by steam reforming, releasing 77 Mt CO2 annually. The use of hydrogen for all US transport would require some 200 Mt/yr of hydrogen, though this scenario is some way off.

In Australia, gasification of lignite in Victoria’s Latrobe Valley is planned in the National Hydrogen Roadmap, with CCS in the nearby Gippsland Basin. Costs of about US$2/kg are envisaged with commercial-scale production by the 2030s. In the meantime alkaline electrolysis may be used at under US$4/kg. Export markets for liquefied hydrogen are anticipated. 

Hydrogen Europe notes that the EU plans will have considerable manufacturing implications, including expansion of electrolyser manufacturing from 1 GW/yr to 25 GW/yr, increasing fuel cell manufacturing to 10 to 100 GW/yr, plus much ancillary equipment.

Hydrogen production 

Almost all hydrogen today is made from carbon-based materials, with significant CO2 emissions. World production is about 70 million tonnes* of pure hydrogen, plus 45 Mt mixed with other gases and used in industries such as steel and methanol production, both growing steadily.** A small amount is made by electrolysis of water.

* In thermal terms: 8400 PJ/yr, about the same as the thermal equivalent of US nuclear electricity.
** International Energy Agency, The Future of Hydrogen – Seizing today’s opportunities, Report prepared by the IEA for the G20, Japan (June 2019)

Cost estimates in 2019 (without costing CO2 emissions):  

  • ING: about €1.50/kg for grey hydrogen, €2.50/kg for blue hydrogen and €5-6/kg for green hydrogen.
  • Bloomberg New Energy Finance: green hydrogen ranging from $2.50/kg to $6.80/kg, but potentially reducing to $1.40/kg by 2030.
  • Aurora Energy Research in 2020 put levelized costs of production (higher heating value, real, 2018) at around €40/MWh (€1.6/kg) for conventional grey hydrogen, €50/MWh (€2/kg) for blue hydrogen and €80/MWh (€3.2/kg) for green hydrogen.
  • S&P Global Platts in August 2020: conventional grey hydrogen at €1.24/kg, blue hydrogen at €1.31/kg and green hydrogen (polymer electrolyte membrane electrolysis including capex) at €3.43/kg.
  • International Atomic Energy Agency (IAEA) figures in 2019 were: $4.15/kg for normal electrolysis, $3.23/kg for dedicated nuclear high-temperature steam electrolysis (HTSE), and $2.50/kg for off-peak HTSE, competitive with large-scale steam reforming of methane (grey hydrogen).
  • LucidCatalyst in 2020: $2/kg yellow hydrogen from conventional nuclear power, potentially dropping to half that by 2030. In basic energy terms, $2/kg is $16.7/GJ (lower heating value) – well above most natural gas prices. LucidCatalyst suggests that $1.50/kg for clean hydrogen would be competitive generally with high oil prices, but under $1/kg would be needed with cheap oil.

In mid-2020, 14 new hydrogen production projects mostly based on renewable energy were under construction, some with a view to international trade. The Institute for Energy Economics and Financial Analysis (IEEFA) conservatively estimates that 2.9 million tonnes per year from such sources is likely to be online in 2030. The International Energy Agency (IEA) estimates that global hydrogen production in 2019 released 830 million tonnes of carbon dioxide, equivalent to 2.2% of energy-related emissions.

Steam methane reforming, coal gasification

Most hydrogen today is made by steam reforming of natural gas (methane, hence ‘SMR’). About one-quarter of supply is from coal, by reacting it with steam and oxygen under high temperature and pressure to form synthesis gas comprising hydrogen with carbon monoxide. These produce so-called grey hydrogen, unless the CO2 emissions are substantially mitigated by carbon capture and storage (CCS) in which case it is blue hydrogen. 

In steam-methane reforming, methane reacts with steam under 3-25 bar pressure in the presence of a catalyst to produce hydrogen and carbon monoxide (with a small amount of carbon dioxide). Steam reforming is endothermic and uses steam at 700 °C to 1000 °C.

2CH4 + 2H2O ⇌ 2CO + 3H2   ∆H +206 kJ/mol
CO + H2O ⇌ CO2 + H2   ∆H -41 kJ/mol – water-gas shift reaction (exothermic)

Coal gasification is similar, reacting carbon in coal with oxygen and steam under high temperature and pressure:

3C + O2 + H2O ⇌ 3CO + H2
CO + H2O ⇌ CO2 + H2   ∆H -41 kJ/mol – water-gas shift reaction (exothermic)

With about 76% of pure hydrogen being made from natural gas and 23% from coal gasification, this gives rise to 830 Mt of CO2 emissions annually – each tonne of hydrogen produced by SMR gives rise to at least 11 tonnes of CO2.  

The Great Plains Synfuel plant in the USA produces 1300 tonnes of hydrogen per day in the form of hydrogen-rich syngas from brown coal gasification, with CCS. About half of the CO2 is captured and sold to two oilfields for enhanced oil recovery.

Air Products at Port Arthur, Texas, employs SMR using vacuum-swing adsorption gas separation technology (rather than amine absorption) for carbon capture from 2013. It captures about 90% of the CO2 and sells about 1 Mt/yr for enhanced oil recovery nearby. The US Department of Energy (DOE) funded two-thirds of the cost of the project.

At the Quest project in Alberta, Canada, hydrogen is produced by SMR and an unknown proportion of the CO2 – up to 1 Mt/yr – is stored 2 km underground.

Australian plans for gasification of lignite envisage plants of over 500 t/day to be economical, hence relying on exports to achieve scale.

Pyrolysis

So-called turquoise hydrogen can be made by pyrolysis decomposition of methane, using a molten metal reactor with a catalytic active Ni-Bi alloy, leaving a solid carbon residue. The process heat can be from burning hydrogen product or methane, or electric arc. Alternatively a plasma reactor may be used. 

CH4 -> C + 2H2   (endothermic)

Electroylsis

Electrolysis of water at ambient temperatures requires about 55 kWh per kilogram of hydrogen produced.* It is undertaken on a fairly small scale today, producing only about 2% of world supply (IEA, 2019). It requires high-purity water, so electrolysers need an integrated deioniser allowing them to use fairly low-grade potable water.

Recent plans in several countries have focused on green hydrogen production by electrolysis. The plans for massively increased electrolyser deployment, fed by surplus electricity from renewables, are based on this. It would mean that increased deployment of intermittent renewables would result in less curtailment, and thus justify such overcapacity with low utilisation (due to wind and solar intermittency). However, low capacity factors for the electrolysers result in high costs for the hydrogen.

* The thermodynamic efficiency limit is 40 kWh/kg, and 45 kWh/kg is considered the likely best achievable. 

High-temperature steam electrolysis based on solid oxide electrolysis cells (SOECs) requires about one-third less energy but is not yet commercial. SOECs operate at over 600 °C (and are essentially solid oxide fuel cells run in regenerative mode). The solid oxide electrolyte is typically zirconia (zirconium dioxide, ZrO2). A source of heat such as nuclear would bring it into contention. 

Since the hydrogen is able to be stored much more readily than electricity, this is an important potential application of surplus power from intermittent renewable sources, as well as for nuclear power especially off-peak. Two US nuclear plants are installing small electrolysers to pilot hydrogen production off-peak, with a view to possibly moving to high-temperatrue steam electrolysis. However, production from electrolysers is expensive. 

Most large-scale hydrogen production is using alkaline electrolysers (AE), but polymer electrolyte membrane also known as proton exchange membrane (PEM) types are more suitable than alkaline electrolysers for small- and medium-scale hydrogen plants because they are compact and handle variable power supply from renewable sources more efficiently.* They also operate at lower temperatures and produce pure hydrogen. Electrolyser costs are difficult to verify but $850/kW has been reported for PEM type and the IEA quotes $500/kW for lowest-cost alkaline electrolysers with $200/kW being reported for Chinese alkaline electrolysers. LucidCatalyst uses a median figure of $500/kW. On a different basis, PEM electrolysers are quoted at producing hydrogen at $4.9/kg, AE ones at $3.8/kg. 

*AE units use potassium hydroxide to form H2 and O2 at the electrodes, PEM units catalytically split water. 

The IEA's Energy Technology Perspectives 2020 in its Sustainable Development scenario projects global electrolyser capacity increasing from about 170 MW in 2019 to about 500 GW by 2040, about 1400 GW by 2040 and over 3300 GW by 2070 running at 46% capacity factor – about 4000 full-load hours per year. 

Germany aims for 5 GW of installed electrolyser capacity by 2030. 

BP is leading a study into producing up to 45,000 tonnes of hydrogen per year in a 250 MW electrolysis plant at Rotterdam connected to offshore wind farms. If two-thirds of this production replaced hydrogen from steam reforming natural gas it would eliminate 350,000 tonnes of CO2 emissions per year from the BP refinery.

In Germany, Ørsted and EdF Germany plan a 30 MW electrolyser at Heide on the North Sea coast, where a number of wind farms connect. The €89 million project has €30 million in government subsidy. Germany's biggest PEM electrolyser – 10 MW – is being commissioned in late 2020 at the Shell Rhineland refinery.

Siemens Smart Infrastructure and WUN H2 have been contracted to build a hydrogen production plant at Wunsiedel in northern Bavaria by the end of 2021, next to an existing 8 MW battery unit. The plant will use a 'Silyzer 300' PEM electroyser from Siemens Energy, powered by 6 MW solely from renewable energy, producing 900 t/yr in the first phase, expandable to 2000 t/yr. Siemens sees it as a demonstration plant.

At Eemshaven in Netherlands the NorthH2 project is planned to produce 800,000 tonnes of green hydrogen per year from 10 GWe of offshore wind capacity, using about 750 MW of electrolysers. Phase 1 would be built by 2030, phase 2 by 2040. 

In Belgium, the Hyport Ostend project aims to use curtailed power from the country’s wind generation, initially from 2.26 GWe and increasing to 4 GWe. It will start with a 50 MW electrolyser to produce 100,000 t green hydrogen per year. 

In Provence, France, the HyGreen project plans 12,000 tonnes per year of green hydrogen production from 900 MWe of solar power, using 760 MW of electrolysers, with storage in salt caverns. Phase 1 is planned for 2022, and the full project in 2027. 

Also in France the H2V59 project plans to produce 28,000 t hydrogen per year using about 100 MW electrolyser for injection into the natural gas grid. 

In UK, Equinor’s H2H Saltend project is planning to produce 125,000 tonnes of blue hydrogen per year for an industrial park from a 600 MW auto thermal reformer with CCS. 

In Japan a 10 MW electrolyser paired with 20 MWe of solar PV started operation in 2020. 

A $5 billion project near Neom in Saudi Arabia is planned to employ 4 GWe of renewables to produce 237,000 tonnes per year of green hydrogen using Thyssenkrupp electrolysers and then green ammonia, by 2025. Production of 1.2 Mt of ammonia per year for export would be from Haldor Topsoe technology (essentially Haber-Bosch). The ammonia would be dissociated to make hydrogen for FCEV trucks and buses in Europe or elsewhere. It could be online in 2025. 

In northwestern Australia the planned Asian Renewable Energy Hub plans 15 GWe of renewable energy occupying 6500 sq km of land, with 12 GWe of output producing 500,000 tonnes per year of green hydrogen, largely for export, using about 1 GW of electrolysers. A final investment decision on the US$15 billion project is due in 2025. 

At Dongara in Western Australia Infinite Blue Energy aims to have its A$300 million Arrowsmith project operational in 2022. It will use 160 MWe of wind and solar capacity and produce about 900 tonnes of green hydrogen per year. 

At Eqianqi, Inner Mongolia, Chinese state-owned utility Jingneng Power plans to spend RMB23bn ($3 billion) on a 5 GWe hybrid solar, wind, hydrogen and storage facility, to be online in 2021. Green hydrogen production will be over 400,000 tonnes per year. 

S&P Global Platts Analytics’ hydrogen global production database in 2020 identified 1 GW of announced electrolyser production capacity set to come online across the next five years, half of which is expected by the end of 2022. Germany has about a 20% share in the world electrolyser market, followed by Japan and China. 

The IEA's Energy Technology Perspectives 2020 in its Sustainable Development scenario projects electrolyser manufacturing to increase from about 1.5 GW/yr in 2019 to about 60 GW/yr by 2070, and the cost (apparently for PEM) to fall from $850-1100/kWe today to below $300/kWe about 2070.

The role of nuclear power

Nuclear power already produces electricity as a major energy carrier. Operating at very high capacity factors, it is well placed to produce zero-carbon hydrogen. The evolution of nuclear energy's role in hydrogen production over perhaps two decades is seen to be: 

  • Cold electrolysis of water, using off-peak capacity (needs 55 kWh/kg). 
  • Use of nuclear heat to assist steam reforming of natural gas. 
  • High-temperature steam electrolysis, using heat and electricity from nuclear reactors. 
  • High-temperature thermochemical production using nuclear heat. 

Steam reforming of methane (SMR) requires temperatures of over 700 °C to combine methane and steam to produce hydrogen and carbon monoxide. A nuclear heat source would reduce natural gas consumption by about 30% (i.e. that portion of feed which would simply be for heat), and eliminate flue gas CO2 emissions. Apart from this, the efficiency of the whole process (primary heat to hydrogen) moves from about 25% with today's reactors driving electrolysis (33% for reactor x 75% for cell) to 36% with more efficient reactors doing so, to 45% for high-temperature electrolysis of steam, to about 50% or more with direct thermochemical production. 

High-temperature steam electrolysis (HTSE, at 600 °C or more) in solid oxide electroloysis (SOEC) to use both heat and electricity has been demonstrated, and shows considerable promise. It is a reverse reaction of the solid oxide fuel cell technology. It requires about one-third less energy than low-temperature electrolysis but has never been commercialised due to the poor durability of the ceramic components in a hot hydrogen environment. US research is at Idaho National Laboratory in conjunction with Ceramatec and FuelCell Energy in a $12.5 million project part-funded by the US Department of Energy. LucidCatalyst shows it producing hydrogen at two-thirds the cost of low-temperature electrolysis across a range of capacity factors.

The IAEA has developed the Hydrogen Economic Evaluation Program (HEEP) to assess the economics of large-scale hydrogen production using nuclear energy. 

Hydrogen directly from nuclear heat

Several direct thermochemical processes are being developed for producing hydrogen from water. For economic production, high temperatures are required to ensure rapid throughput and high conversion efficiencies. They essentially do not use electricity. 

In each of the leading thermochemical processes the high-temperature (800-1000°C), low-pressure endothermic (heat absorbing) decomposition of sulfuric acid produces oxygen and sulfur dioxide:

2H2SO4 ⇒ 2H2O + 2SO2 + O2

There are then several possibilities. In the iodine-sulfur (IS) process invented by General Atomics in the 1970s, iodine combines with the SO2 and water to produce hydrogen iodide. This is the Bunsen reaction and is exothermic, occurring at low temperature (120 °C): 

I2 + SO2 + 2H2O ⇌ 2HI + H2SO4

The HI then dissasociates to hydrogen and iodine at about 350-450°C, endothermically:

2HI ⇌ H2 + I2

This can deliver hydrogen at high pressure.

Combining all this, the net reaction is then:

2H2O ⇒ 2H2 + O2

All the reagents other than water are recycled, there are no effluents, hence it may be called the sulfur-iodine cycle, with zero-carbon hydrogen and oxygen byproducts. 

In February 2010 the Japan Atomic Energy Agency (JAEA) set up the HTGR Hydrogen and Heat Application Research Centre at Oarai to progress operational technology for an IS plant to make hydrogen thermochemically. It has demonstrated laboratory-scale and bench-scale hydrogen production with the IS process, up to 30 litres/h. In parallel with JAEA’s HTTR developments a pilot plant test project producing hydrogen at 30 m3/h from helium heated with 400 kW tested the engineering feasibility of the IS process. An IS plant producing 1000 m3/h (90 kg/h, 2t/day) of hydrogen was to be linked to the HTTR to confirm the performance of an integrated production system, envisaged for the 2020s. In 2014 hydrogen production at up to 20 L/h was demonstrated. In January 2019 it used the HTTR to produce hydrogen using the iodine-sulfur process over 150 hours of continuous operation. JAEA aims to produce hydrogen at less than $3/kg by about 2030 with very high temperature reactors.

The US Nuclear Energy Research Initiative (NERI) launched in 1999 was refocused in 2004 to include the Nuclear Hydrogen Initiative (NHI), allied to the Next Generation Nuclear Plant (NGNP) programme established in 2005. NGNP envisaged construction and operation of a prototype high-temperature gas-cooled reactor (HTR) and associated electricity or hydrogen production facilities by 2021, but funding was cut back under the Obama administration and prelicensing activities were suspended in 2013.

Under an International NERI agreement, Sandia National Laboratories in the USA and the French CEA with General Atomics in the USA were also developing the IS process with a view to using high-temperature reactors for it. They had built and operated a laboratory-scale loop for thermochemical water-splitting.

South Korea has also demonstrated thermochemical water-splitting at laboratory scale, supported by General Atomics. In December 2008, the ROK Atomic Energy Commission officially approved nuclear hydrogen development as a national programme, with the development of key and basic technologies through 2017 and the goal of demonstrating nuclear hydrogen production using the S-I process and a very high-temperature reactor (VHTR) by 2026.

The economics of hydrogen production depend on the efficiency of the method used. The IS cycle coupled to a modular high temperature reactor is expected to produce hydrogen at about $2.00/kg. The oxygen byproduct also has value. General Atomics earlier projected $1.53/kg based on a 2400 MWt HTR operating at 850°C with 42% overall efficiency, and $1.42/kg at 950°C and 52% efficiency (both 10.5% discount rate). Such a plant could produce 800 tonnes of hydrogen per day.  

For thermochemical processes an overall efficiency of greater than 50% is projected.

Production reactor requirements for process heat

For hydrogen production, high temperature – 750-1000 °C, is required, and at 1000 °C the conversion efficiency is three times that at 750 °C. The chemical plant needs to be isolated from the nearby reactor, for safety reasons, possibly using an intermediate helium or molten fluoride loop. 

Three potentially-suitable nuclear reactor concepts have been identified, though only the first is sufficiently well-developed to move forward with: 

  • High-temperature gas-cooled reactor (HTR), either the pebble bed or hexagonal fuel block type. Modules of up to 285 MWe will operate at 950°C but can be hotter. 
  • Advanced high-temperature reactor (AHTR), a modular reactor using a coated-particle graphite-matrix fuel and with molten fluoride salt as primary coolant. This is similar to the HTR but operates at low pressure (less than 1 atmosphere) and higher temperature, and gives better heat transfer. Sizes of 1000 MWe/2000 MWt are envisaged. 
  • Lead-cooled fast reactor, though these operate at lower temperatures than the HTRs – the most developed is the Russian BREST reactor which runs at only 540 °C. A US project is the STAR-H2 which would deliver 780 °C for hydrogen production and lower temperatures for desalination. 

These are described more fully in the Small Nuclear Power Reactors information page (with coolant characteristics) and the Advanced Nuclear Power Reactors page. 

For temperatures beyond 750ºC, molten fluoride salts are a preferred interface fluid between the nuclear heat source and the chemical plant. The aluminium smelting industry provides substantial experience in managing them safely. The hot molten salt can also be used with secondary helium coolant generating power via the Brayton cycle, with thermal efficiencies of 48% at 750°C to 59% at 1000°C. There remain significant challenges in achieving sustained temperatures for commercial hydrogen production in a plant built for the chemical and thermal conditions.

Hydrogen uses

Supplement in reticulated natural gas

In most pipelines, 15-20% hydrogen can be added to natural gas, but with new trunk pipelines like Nord Stream in Europe the proportion could be up to 70% to convey hydrogen to international markets. 

In the USA, the Gas Technology Institute is currently testing all US natural gas transport and distribution infrastructure components for various hydrogen fraction blends with natural gas to determine how much hydrogen can be blended into existing natural gas systems.

With the power-to-gas strategy, Uniper has a 2 MW pilot plant to produce up to 360 m3/h of hydrogen at Falkenhagen, Germany, to feed into the Ontras gas grid, which can function with 5% hydrogen. Vattenfall at Prenzlau in Germany is also experimenting with hydrogen production and storage from wind power via electrolysis. Also in Germany, near Neubrandenburg in the northeast, WIND-projekt is using surplus electricity from a 140 MWe wind farm to make hydrogen, storing it, and then burning it in a combined heat and power (CHP) unit to make electricity when demand is high. However, there is an 84% loss in this RH2-WKA (renewable hydrogen - Werder, Kessin, Altentreptow) demonstration process.  

Germany’s biggest operating power-to-gas plant is a 6 MW unit at Energiepark Mainz. RWE and Siemens plan a 105 MW power-to-gas pilot project, GET H2, at Lingen, using wind power, and two other similar projects are planned: Element Eins and Hybridge. In the Netherlands, Gasunie plans a 20 MW unit. BNetzA forecasts a 3 GW potential for power-to-gas by 2030. 

Oil refining

Hydrogen is a key processing agent in petroleum refining, for desulfurizing and catalytic cracking of long-chain hydrocarbons.* About one-quarter of world production is used to convert low-grade crude oils (especially those from tar sands) into liquid and energy-dense transport fuels such as gasoline and diesel fuel.  Heavy aromatic feedstock is converted into lighter alkane hydrocarbon products under a wide range of very high pressures (7000-14,000 kPa) and high temperatures (400-800°C), utilising hydrogen and special catalysts. It is also important for removing contaminants such as sulfur from these fuels. 

* e.g. (CH)n tar sands or (CH1.5)n heavy crude to (CH2)n transport fuel about 42-45 MJ/kg (32-39 MJ/L). Upgrading heavy crude oil and tar sands requires 3 to 4 kilograms of hydrogen per barrel (159 litres) of product.

Production of ammonia

Synthesis of hydrogen and nitrogen to produce ammonia – about 180 Mt/yr or 1 PWh* – accounts for over half of the world's pure hydrogen demand. This uses the Haber-Bosch process. 

* On the basis of 5.18 kWh/kg ammonia, quantities may be quoted in GWh, PWh, etc. 

Most ammonia today is used for agricultural fertilisers. Some is used (as ammonium nitrate, with diesel fuel) for mining explosives. 

According to Norman Borlaug, 1970 Nobel laureate and 'grandfather of the green revolution', organic nitrogen in the world's soils is only sufficient to feed one-third of today's population. The rest must come from inorganic additions. Most of the world's nitrogen fertilizers are made using the Haber process (see below), combining hydrogen with abundant atmospheric nitrogen. The resulting ammonia is then oxidised to nitrates.

The Haber process 

The Haber Process (Haber-Bosch Process) combines nitrogen from the air with hydrogen derived mainly from natural gas (methane) into ammonia. The reaction is reversible and the production of ammonia is exothermic. 

German scientist Fritz Haber invented the process to combine atmospheric nitrogen with hydrogen in 1909 and received the Nobel Prize for chemistry in 1918 for creating "an exceedingly important means of improving the standards of agriculture and the well-being of mankind," which now looks like a considerable understatement. It was scaled up by the chemical engineer Karl Bosch, so is often known as the Haber-Bosch process. Bosch received a Nobel Prize in 1931.

N2 + 3H2 ⇌ 2NH3   ∆H -92 kJ/mol   (exothermic, using a metal catalyst at high temperature and pressure)

The Haber process produces about 180 million tonnes of anhydrous ammonia per year for nitrogen fertilizers and consumes about 3-5% of the world's natural gas production to make the hydrogen for it. The nitrogen is obtained cryogenically from air. 

Looking to the future, ammonia could have a key role in the storage and transport of hydrogen – see later section. It may also be used as a fuel. In Japan projects are exploring co-firing ammonia with coal in boilers, and ammonia with natural gas in combustion turbines. Ammonia also has potential use as a maritime fuel, since it can be used in ship engines with only minor modification. Also it can be used in some fuel cells.

Production of methanol and DME fuels

Considering the storage and portability challenges of hydrogen itself, as well as the radical change to fuel cell cars, there is some use of methanol as an additive to petrol/gasoline. Any future liquid fuel for cars needs to compete with petrol at 32 MJ/L or diesel fuel at 39 MJ/L and be no more difficult to store and refuel than LPG. Methanol (CH3OH) has 16 MJ/L. It may be used in fuel cells. 

LNG has similar problem to hydrogen, ethanol generally comes from biomass, but methanol can be made from CO2 and hydrogen. Using zero-carbon hydrogen, and with abundant CO2, automotive fuel can be provided forever, using present engine technology.  

For diesel engines, dimethyl ether (CH3-O-CH3, DME) is better, and this is made by dehydrating a couple of methanol molecules. It is a gas but can be stored under low pressure as a liquid, like LPG. DME has an energy density of 18-19 MJ/L, so less than oil-based fuels, but usable and easily stored. Any post-oil future may be methanol-based. 

Methanol today is produced in a variety of ways, but ideally it will be produced from atmospheric CO2 with hydrogen produced by nuclear energy, and using more nuclear energy in the conversion process.

CO2 + 3H2 ⇒ CH3OH + H2O   ∆H -49.5 kJ/mol at 25°C, -58 at 225°C, exothermic

(The endothermic reverse water shift reaction CO2 + H2 ⇒ CO + H2O will occur at same time, along with: CO + 2H2 ⇒ CH3OH    ∆H -91 to -98 kJ/mol, exothermic)

Dimethyl ether is made in a dehydration reaction: 

2CH3OH ⇒ CH3OCH3 + H2O   ∆H -23 kJ/mol

Methanol and DME production is at relatively low temperature (compared with thermochemical hydrogen production) – 230-350°C. 

DME is already used as propane replacement, and world production capacity is over 10 million tonnes per year. China alone was aiming for 20 million tonnes per year DME capacity by 2020. Sweden is producing BioDME from black liquor. Ford has produced a DME-powered car – a 1.6 litre Mondeo, as part of the three-year xME project led by Ford with members of the FVV, Germany's international combustion engine technology research network. 

Most methanol production today is from synthesis gas (carbon monoxide and hydrogen) derived from biomass or fossil fuels, or from hydrogen by steam reforming of natural gas. Most methanol use is for making plastics. About 14% of it is used as a petrol additive and 7% to make DME. Methanol production accounts for about 13% of the word's hydrogen demand. 

Ethanol production is covered in the Process Heat information page. 

Methanol, together with derived DME, can be used as:  

  • A convenient energy storage medium.
  • A readily transportable and dispensable fuel for internal combustion engines and diesel (compression ignition) engines with little engineering change.
  • A fuel for fuel cells.
  • A feedstock for synthetic hydrocarbons and their products, including fuels, polymers and even single-cell proteins (for animal feed and/or human consumption). 

In Iceland, methanol production is already occurring using CO2 captured from flue gas and hydrogen from electrolysis using renewable energy. The company Carbon Recycling International was set up in 2006 to produce renewable methanol for automotive use and also biodiesel. 

In China, the Shanghai Advanced Research Institute has developed a process to convert CO2 and hydrogen into long-chain hydrocarbons such as in gasoline. A multifunctional catalyst containing indium oxide mixed with a zeolite initially produces methanol, which then interacts with the zeolite to produce long-chain hydrocarbons. Another research group at the Dalian Institute for Chemical Physics uses a magnetite and zeolite catalyst to also produce long-chain hydrocarbons from CO2 and hydrogen, but with different intermediate products. While there are a number of processes that can convert CO2 to single-carbon hydrocarbons such as methanol, the synthesis of longer-chain hydrocarbons has previously been elusive. 

In 2018 global methanol capacity reached about 140 million tonnes and is expected to reach 280 Mt by 2030, according to Statista. The Methanol Institute quotes 110 Mt world capacity (undated, on its website) but publishes figures indicating about 150 Mt capacity and 100 Mt demand in 2020.

Hydrogen can also be reacted with carbon dioxide at 300-400°C to give methane, using the exothermic Sabatier process.*  

* CO2 + 4H2 ⇒ CH4 + 2H2O.  This seems of more relevance to space travel than transport on Earth, though on a small scale it will scrub CO2 and CO from hydrogen streams for fuel cells. 

Use directly as fuel for transport – fuel cells

Burning hydrogen produces only water vapour, with no carbon dioxide or carbon monoxide.  However, it is far from being an energy-dense fuel volumetrically, and this limits its potential use, especially for motor vehicles. Ammonia is more energy-dense, and burns to water vapour and NOx or nitrogen. 

Hydrogen can be burned in a normal internal combustion engine, and some test cars were thus equipped.  Trials in aircraft have also been carried out. Until about 2010 the internal combustion engine was the main affordable technology available for using hydrogen.*   

*One hundred BMW Hydrogen 7s were built, and the cars covered more than 2 million kilometres in test programmes around the globe. BMW is the only car manufacturer to have used hydrogen stored in its liquid state. BMW has abandoned this development and is collaborating with Toyota on fuel cell vehicles. 

For transport, hydrogen’s main use is in fuel cells. A fuel cell is conceptually a refuellable battery, making electricity as a direct product of a chemical reaction. But where the normal battery has all the active ingredients built in at the factory, fuel cells are supplied with fuel from an external source and oxygen from the air. They catalyse the oxidation of hydrogen directly to electricity at relatively low temperatures. Proton exchange membrane (PEM) fuel cells are the main type used in cars and heavy vehicles. These operate at around 80-90°C and have about 60% efficiency in converting chemical to electrical energy to drive the wheels of an electric vehicle. However, in practice about half that has been achieved, except for the higher-temperature solid oxide fuel cells – 46%.   

At present fuel cells are much more expensive to make than internal combustion engines (burning petrol/gasoline or natural gas). In the early 2000s, PEM units cost over $1000 per kilowatt, compared with $100/kW for conventional internal combustion engine. The target cost for a PEM fuel cell stack for FCEV is below €100/kW, which will require reducing the amount of palladium catalyst.  

The direct methanol fuel cell (DMFC) technology is practical for portable electronic uses but not favoured for automotive use at present. Other fuel cell technologies include: the high-temperature proton exchange membrane fuel cell (PEMFC) operating up to 200°C, which is less vulnerable to catalyst poisoning by CO; the phosphoric acid fuel cell (PAFC) – well developed but high-temperature and used only for stationary power generation; the solid oxide fuel cell (SOFC) – operating over 800°C, hence mainly used for stationary power generation; and the molten carbonate fuel cell (MCFC) – high-temperature (about 650°C) and accepting a variety of fuels, for stationary power generation. 

For long-haul buses and trucks, FCEV powertrains have more promise than EV battery-based systems. The initial use of hydrogen for transport is municipal bus and truck fleets, already on the road in many parts of the world. These are centrally-fuelled, so avoid the need for a retail network, and onboard storage of hydrogen is less of a problem than in cars. Buses typically use two fuel cell stacks of about 100 kW plus a small traction battery topped up by regenerative braking. They carry 30 to 50 kg of compressed hydrogen, stored in polymer-lined, fiber-wound pressure tanks at 350 bar (35 MPa). Newer fuel cell buses use only 8 to 9 kg of hydrogen per 100 km, which compares well in energy efficiency with diesel buses. 

Smaller FCEVs are further from widespread commercial use than EVs and PHEVs, though Japan had 3400 FCEV on the road in 2019. A significant ramp up in numbers is expected in the 2020s. China was aiming for 5000 FCEV by 2020 and one million by 2030. The EV30@30 campaign envisages 30% of new car sales being EVs by 2030. 

Fuel cell hybrid vehicles (FCHV), with an electric motor driven by the battery and the fuel cell keeping the battery topped up and giving it greater life (by being kept more fully charged) are being marketed. Battery capacity is smaller than normal battery EVs and PHEVs, but the whole fuel cell stack plus hydrogen tank is much lighter than comparable EV battery packs. Plug-in FCEVs are possible, with greater battery capacity. The main FCEV problem apart from cost is the very few refuelling stations as yet. 

The fuel cell powertrain is a modular assembly. It comprises fuel cell stack, system module, hydrogen tanks, battery and electric motor. To August 2020 Ballard in USA had supplied over 670 MW of PEM fuel cell units, which – in medium and heavy vehicles, buses and trucks – had clocked up more than 50 million kilometres. About 70% of this was in China. 

Proton Motor Power Systems in 2020 has a production line near Munich being expanded to 10,000 fuel cell stack modules per year. The single stack modular designs cover power ranges from 2 up to 16 kW in the lower power class (PM200) and from 15 to 75 kW in the upper power class (PM400). It has also designed a multi-stack system for power demands over 100 kW for larger trucks, trains, ships and stationary back-up power applications. Its first fuel cell train order for a 180 kW system is to be delivered early in 2021. It envisages its fuel cell stacks being used in combination with batteries for hybrid electric-driven light duty vehicles, inner city buses, or for industrial power supply. It is providing 37 kW and 67 kW fuel cell systems for China. 

In 2019 Arizona-based Nikola Corporation embarked on a joint venture with IVECO in Europe to develop and market both EV trucks and fuel cell heavy trucks. Nikola’s main aim is to market FCEV trucks, and the Nikola One FCEV truck is expected on the market in 2023, with 800-1200 km range, up to 750 kW power from an 800 volt AC motor, up to 2700 Nm peak torque, through a single-speed transmission, and a 250 kWh lithium-ion battery.  

Nikola also plans to market a 4x4 FCHV pick-up truck, the Badger, with 120 kW fuel cell stack and 960 km range (half each from fuel cell and battery). In 2020 GM bought 11% of the company and will make the Badger in BEV (battery electric vehicle) and FCEV versions. The company has ordered 85 MW of alkaline electrolysers to support hydrogen refuelling stations. 

In April 2020 Daimler Truck and Volvo Group signed a non-binding agreement to develop, produce and commercialize hydrogen fuel cell systems for heavy-duty and especially long-haul vehicles. Daimler is to consolidate its fuel cell and hydrogen storage system activities in the joint venture.  

The fuel cell stacks in cars have an output of about 100 kW or more. As compared with battery electric cars they usually have a better range than EVs – around 400 to 500 km – with a lower vehicle weight and much shorter refuelling times of three to five minutes. They usually carry 4 to 7 kg of hydrogen, stored in carbon fibre pressure tanks at 700 bar (70 MPa). 

Honda, Toyota and Hyundai are the main car manufacturers developing FCEVs. Ford, Nissan, Renault and Mercedes have pulled back from FCEV development. See Electric Vehicles information page. 

An issue with using hydrogen in fuel cells is overall energy efficiency. If a nuclear reactor generates electricity which is used for electrolysis of water and the hydrogen is compressed and used in fuel cell powered vehicle (assuming 60% efficient fuel cell), the efficiency is much lower than if the electricity is used directly in EVs and PHEVs.* However, if the hydrogen can be made by thermochemical means the efficiency doubles, and they are comparable with EV/PHEV. 

* Say: 35% x 75% x 60% x 90% = 14% optimistically (reactor, electrolysis, fuel cell, motor) to:
50% x 60% x 90% = 27% for future thermochemical hydrogen 
cf 35% x 90% = 31% for EV. 

Apart from carbon-free production and then distribution to users, on-board storage is the principal problem for hydrogen as an automotive fuel – it is impossible to store it as simply and compactly as gasoline or LNG fuel. The options are to store it at very low temperature (cryogenically), at high pressure, or chemically as hydrides. The last is seen to have considerable potential, though refuelling a vehicle is less straightforward.   

Pressurised storage is the main technology available now and this means that at 700 times atmospheric pressure (70 MPa), five times the volume is required than for an equivalent amount of petrol/gasoline. The weight penalty of a steel tank is reduced by use of carbon fibre. Earlier, the tank had been about 50 times heavier than the hydrogen it stored, now it is about 20 times as heavy, and the new target is ten times as heavy. Storage for buses can be at 35 MPa, but for cars needs to be twice that. 

One promising hydride storage system utilises sodium borohydride as the energy carrier, with high energy density. The NaBH4 is catalysed to yield its hydrogen, leaving a borate (NaBO2) to be reprocessed. 

Fuel cells are currently being used in electric forklift trucks and this use is expected to increase steadily. They apparently cost a lot more than batteries but last twice as long (10,000 hours) and have less downtime.   

The Hydrogen Mobility Europe (H2ME) project announced in 2015 extends over six years supported by the Fuel Cells and Hydrogen Joint Undertaking (FCH JU) with funding from the EU’s Horizon 2020 research programme. The initiative is aimed to significantly expand the European hydrogen vehicles fleet and in so doing, to confirm the technical and commercial readiness of vehicles, fuelling stations and hydrogen production techniques. It involves deploying FCEVs and hydrogen refuelling stations (HRS), initially mostly in Germany, as well as testing the ability of electrolyser-hydrogen refuelling stations to help balance the electrical grid. The hydrogen refuelling stations are designed so that vehicles can be refuelled in under five minutes. 

In 2019 there were about 370 hydrogen refuelling stations (HRS) worldwide, 270 of these publicly accessible  There were 152 in Europe, 136 in Asia and 78 in North America (most in California).

Maritime use 

In April 2020 the Swiss electrical engineering company ABB signed an agreement with Hydrogène de France (HDF) to optimize fuel cell manufacturing to produce a megawatt-scale power plant for marine vessels to be built at HDF’s factory in Bordeaux, France. The arrangement will draw upon Ballard Power Systems proton exchange membrane (PEM) fuel cell technology. ABB said that hydrogen was not the sole energy carrier under consideration. “Although hydrogen is generally preferred because of its greater efficiency, ammonia and methanol with higher volumetric energy density makes it a good choice for deep-sea shipping. [It’s likely] we will see companies using a mix of energy carriers depending on their needs.”  

In September 2019, Japan Engine Corporation announced a partnership with the National Maritime Research Institute (NMRI) to begin developing engines fuelled by hydrogen and ammonia. Ballard has developed the FCwave fuel cell module for marine applications. This builds on NMRI development of engines fuelled by ammonia. 

The IEA's Energy Technology Perspectives 2020 in its Sustainable Development scenario projects about 12% of marine transport being fuelled by hydrogen and 55% by ammonia by 2070, mostly in internal combustion engines rather than fuel cells, with these fuels increasing slowly from 2030 and more rapidly from 2050. Fuel cells with hydrogen are likely to be confined to short-range shipping due to storage costs. (Nuclear power for propulsion is not considered at all.)

The International Maritime Organization (IMO) aims to reduce the carbon intensity of emissions from shipping by at least 40% by 2030, and 70% by 2050, compared with 2008 levels. The annual energy demand for shipping is about 12 EJ (3300 TWh). Based on wide consultation, a Shell report showed that cryogenic hydrogen and ammonia were the two most prospective fuels for shipping, with internal combustion being the main technology available in the short-term but fuel cells being more attractive in the longer-term.

Stationary energy applications

Fuel cells may be used for heat or electricity, or combined heat and power.  

Fuel cells using hydrogen can also be used for stand-alone small-scale stationary generating plants for remote area power supply in off-grid areas. This is particularly where higher temperature operation (e.g. of solid oxide fuel cells) and hydrogen storage may be less of a problem than in vehicles, or where hydrogen is reticulated like natural gas. Cogeneration fuel cell units for domestic power and heat were deployed in Japan under a subsidy scheme to 2012.   

The market for backup power applications is increasingly important. Backup applications include both emergency power supply and also uninterruptible power supply (UPS), as well as backup for electricity from intermittent renewables. 

Coal and biomass to liquid hydrocarbon fuels 

Coal and biomass can be a basis for liquid hydrocarbon fuels, and has been so for nearly a century, with some dependence on hydrogen.  

The Fischer-Tropsch process was originally developed in Germany in the 1920s, and based on coal provided much of the fuel for Germany during the Second World War. It then became the basis for much oil production in South Africa by Sasol, which now supplies about 30% of that country's gasoline and diesel fuel from coal and natural gas. However, it is a significant user of hydrogen, catalyzing a reaction with carbon monoxide to produce liquid hydrocarbons. The hydrogen is now produced with the carbon monoxide by coal gasification, with part of the gas stream undergoing the water shift reaction (CO + H2O ⇌ CO2 + H2). Using simply black coal, 14,600 tonnes of coal produces 25,000 barrels of synfuel 'oil' (along with 25,000 tonnes of CO2).

Overall: (2n+1)H2 + nCO ⇒ CnH2n+2 + nH2O    (where n is typically 10-20)

Nuclear power can be brought to bear on this in two ways. A nuclear source of hydrogen coupled with nuclear process heat would more than double the amount of liquid hydrocarbons from the coal and eliminate most CO2 emissions from the process.  

Alternatively, a hybrid system uses nuclear electricity to electrolyse water for the hydrogen and the oxygen. In this case, some 4400 tonnes of coal is gasified using oxygen from the electrolysis to produce carbon monoxide which is fed to the Fischer-Tropsch plant with the hydrogen to produce 25,000 barrels of synfuel 'oil'.  Very little CO2 results, and this is recycled to the gasifier.

Similarly from biomass, liquid biofuels may be produced by reacting the material with hydrogen under elevated temperatures and pressures in the presence of a catalyst. This hydrotreating technology is used by some commercial plants. Similarly the Fischer-Tropsch process may be employed in hydroprocessing wood residues for liquid fuels. 

Reductant for metallurgy, especially steelmaking 

A major use for metallurgical coke – essentially carbon – is in metallurgy, notably steelmaking as reductant. Natural gas is now well established in this role also, leading to consideration of hydrogen filling this role, and avoiding CO2 emissions. The world steel industry accounts for 7-9% of direct CO2 emissions.

Green steel is a major area of development planned in the 2020s. Hydrogen Europe envisages 20 Mt of green steel production using 1 Mt hydrogen by 2030. In South Australia at Whyalla, Infrabuild plans green steel production using hydrogen from a 280 MWe solar farm. This could conceivably produce about 9000 t steel per year (of the total 1.2 million tonnes per year).

Chemical feedstock 

Beyond ammonia synthesis and methanol production, hydrogen is used in some chemical processes. 

Storing and transporting hydrogen  

As hydrogen gas 

The low volumetric energy density of hydrogen poses a problem for transport and storage – 90g hydrogen occupies one cubic metre at standard temperature and pressure (STP), so one tonne of hydrogen occupies 11,126 m3 at STP. Also, due to its small molecular size, it leaks more readily than natural gas. It is also readily flammable.

For stationary storage or portable storage in vehicles hydrogen is compressed, which adds little to its cost. Compression to 35 MPa requires about 4.4 kWh/kgH2 and gives 23 kg/m3H2. Large-scale storage needs to be cryogenic.

In Europe, with 1.7 million kilometres of gas transmission and reticulation, Hydrogen Europe estimates that 50,000 km of natural gas pipelines can be converted to hydrogen pipelines at a cost of €25 billion. In Germany, gas transport grid operators have proposed to realise a 5900 km hydrogen pipeline backbone by retrofitting existing gas pipelines and connecting hydrogen production to industrial demand with salt cavern storage. In the Netherlands, a similar programme has been proposed that would cost €5-6 billion, one-quarter of the cost of building a new dedicated hydrogen pipeline.  

For storage or long-distance transport, hydrogen can be liquefied cryogenically, but the boiling point is very low: minus 253°C. This compares with LNG at minus 163°C, so requires better insulation. The density of liquid hydrogen is about 71 kg/m3 and up to 13 kWh/kgH2 is required. The extra cost is likely to be over $2/kg. 

For import and export, sea ports are considering necessary facilities for hydrogen, and Rotterdam with distributor Gasunie plan to jointly construct and operate a hydrogen pipeline linking Rotterdam port as a hydrogen hub to the national hydrogen network being developed by Gasunie.  

Japan has built a liquid hydrogen tanker for sea trade.

As ammonia

Ammonia (NH3) makes a good carrier of hydrogen, or means of long-term storage. It is a key part of the hydrogen picture, for storing it or moving it long distance.

Ammonia will be made by some refinement of the Haber Bosch process, requiring 2-3 kWh/kgH2 or 14 kWh/kg ammonia, then dissociated to release the hydrogen, requiring about 8 kWh/kgH2. Conversion to and from ammonia is likely to add about $1/kg to the hydrogen production cost.

Ammonia has thermal properties similar to propane, is easy to cool and compress into liquid form for transport and storage (boiling point minus 33°C), and has an energy density that is competitive with carbon-based fossil fuels. It contains 17.7% hydrogen by weight. Ammonia’s energy density of 18.6 MJ/kg* is comparable to that of compressed natural gas and methanol, but about half that of petrol/gasoline, diesel fuel and liquefied petroleum gas (LPG).

* 4.32 kWh/L or 5.18 kWh/kg. On this basis ammonia quantities may be quoted in GWh, PWh, etc. as with hydrogen.

Ammonia is seen as a large-scale solution to the problems in storage and movement of hydrogen beyond pipelines. According to the source of hydrogen, the ammonia may be ‘green’, ‘blue’ or ‘grey’. Already, over 100 million tonnes of ammonia is transported each year, so handling is well-established. It can be stored and moved at pressures of 800-1000 kPa, similar to propane, or in refrigerated tanks.  

After storage or transport, the ammonia can be dissociated or ‘cracked’ back into hydrogen and nitrogen by thermal catalytic decomposition or electro-oxidation, though recovery of high-purity hydrogen is unproven at scale. Ammonia may also be used directly in fuel cells, or blended with petrol/gasoline.


Notes & references

General sources

Alternative Fuels Data Center, US Department of Energy, webpage on Renewable Hydrocarbon Biofuels
Ammonia Energy Association website
US Department of Energy's Hydrogen and Fuel Cell Technologies Office (HFTO) website
Tom Koppel and Jay Reynolds, A Fuel Cell Primer: The Promise and the Pitfalls (2000)
Benjamin Russ and Bob Buckingham, Sulfur Iodine Process Summary for the Hydrogen Technology Down-Selection: Process Performance Package, General Atomics (June 2009)
International Atomic Energy Agency, Hydrogen Production Using Nuclear Energy, IAEA Nuclear Energy Series No. NP-T-4.2 (March 2013)
Hydrogen mobility gets a boost in Europe, Engerati (July 2016)
Grigorii Soloveichik, Advanced Research Projects Agency - Energy (ARPA-E), US Department of Energy, Ammonia as Virtual Hydrogen Carrier, presented at the H2@Scale Workshop held on 16-17 November 2016 in Golden, Colorado, USA
National Hydrogen Roadmap – Pathways to an economically sustainable hydrogen industry in Australia, Commonwealth Scientific and Industrial Research Organisation (2018)
International Energy Agency, The Future of Hydrogen: Seizing today’s opportunities, Report prepared by the IEA for the G20, Japan (June 2019)
Zero-Carbon Hydrogen: An Essential Climate Mitigation Option – Nuclear Energy’s Potential Role, Energy Options Network (July 2020)
Yong-Liang Por, Great Expectations – Asia, Australia and Europe Leading Emerging Green Hydrogen Economy, but Project Delays Likely, Institute for Energy Economics and Financial Analysis (August 2020)
Sebastian Timmerberg et al., Hydrogen and hydrogen-derived fuels through methane decomposition of natural gas – GHG emissions and costs, Energy Conversion and Management: X, Volume 7, 100043 (September 2020)
International Energy Agency, Energy Technology Perspectives 2020
Eric Ingersoll and Kirsty Gogan, Missing Link to a Livable Climate – how hydrogen-enabled synthetic fuels can help deliver the Paris goals, LucidCatalyst (September 2020)


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