Nuclear Process Heat for Industry

(Updated April 2020)

  • Nuclear energy is an excellent source of process heat for various industrial applications including desalination, synthetic and unconventional oil production, oil refining, biomass-based ethanol production, and in the future: hydrogen production.
  • For most major industrial heat applications, nuclear energy is the only credible non-carbon option.
  • Light water reactors produce heat at relatively low temperatures in relation to many industrial needs, hence the technology focus has been on high-temperature gas-cooled reactors (HTR) and more recently on molten salt reactors (MSR) producing heat at over 700°C.
  • In 2019 there were 79 nuclear reactors used for desalination, district heating, or process heat, with 750 reactor-years of experience in these, mostly in Russia and Ukraine.

Two information papers in this series address the application of nuclear energy to desalination and hydrogen in transport. This paper covers other applications, but includes hydrogen and methanol production.

Note that the unit MWt (megawatts thermal) is frequently used, with 3 MWt corresponding to about 1 MWe when electricity is generated.

The potential application of nuclear heat depends mainly on the temperature required. With reactor output temperatures of up to 700°C there is a wide range of possible applications, at 900°C there are further possibilities, and at 950°C an important future application to hydrogen production opens up. About 20% of US energy consumption goes into process heat applications, compared with 35-40% into electricity. In this 20%, replacing fossil fuels with nuclear heat promises much in energy security, price stability and reduced regulatory risks, and it is the only option if carbon dioxide emissions are to be avoided.

High-temperature reactors for process heat

The most advanced high-temperature gas-cooled reactor (HTR) project is China's HTR-PM, based on its successful HTR-10 prototype. The demonstration unit being built in Shidaowan links twin 250 MWt units with 750°C outlet temperature to a 210 MWe steam turbine.

The Nuclear Cogeneration Industrial Initiative (NC2I), part of the Sustainable Nuclear Energy Technology Platform (SNETP) in the European Union (EU), is focused on HTRs producing 550°C steam for a variety of industrial applications. The Gemini+ project launched in September 2017 is an outcome of this, involving the EU and international partners (Japan, South Korea and the USA) and coordinated by the Polish National Centre for Nuclear Research (NCBJ). This project is funded under the Euratom programme and aims to provide a conceptual design of a high temperature nuclear cogeneration system that supplies process steam to industry, a licensing framework for this system and a business plan for a full-scale demonstration.

Poland has 13 large chemical plants which need 6500 MWt of heat at 400-550°C. It is considering the potential role of HTRs for this, and very high-temperature gas-cooled reactors (VHTR) for hydrogen production. Deployment of HTRs for industrial heat production was included in the government’s July 2016 draft strategy for development. An early target is building a cogeneration HTR of 200-350 MWt for heat, and before this a 10 MWt experimental HTR at Swierk.

In the USA the Department of Energy (DOE) since 2005 has had a programme (with diminishing funding) to develop a Next Generation Nuclear Plant (NGNP) which is to be an HTR capable of producing hydrogen, electricity or process heat. Initially this was focused on eventual hydrogen production, which requires very high temperatures with corresponding technological and cost challenges. Other process heat applications would broaden the end-user base for nuclear energy. The prospect of an operating prototype by 2021 receded. Industrial partners in the endeavour, with 11 member companies including reactor vendors Areva and Westinghouse, utility Entergy, and potential end-users of electricity and process heat such as Dow Chemical and ConocoPhillips, then set their sights on a more readily-achievable 750°C outlet temperature for process heat rather than hydrogen production particularly. The NGNP was to be built at Idaho National Laboratory (INL) with substantial cost share intended from industry.  

Early in 2012 the NGNP Industry Alliance announced that it had selected the 625 MWt Areva HTR design, known as Antares, for further development. This would be run with helium as primary coolant at 750°C and a two-loop secondary steam cycle.

More recently, the NGNP Industry Alliance has been collaborating with the NC2I on the design and regulatory framework for HTR technology September 2017 launched the GEMINI+ project together with an international consortium to demonstrate high temperature nuclear cogeneration with HTR technology (see above). The NGNP Industry Alliance has evaluated US sites for a demonstration plant including the Piketon site in Portsmouth, Ohio; Odessa/Midland, Texas; a former Georgia Power coal power plant site; and Idaho Falls. All were found to be suitable but Piketon was judged best for electricity, process heat and hydrogen.

A 2011 evaluation by INL for a typical HTR multi-module plant showed that high-temperature process heat and electric power for use by energy-intensive industries can be produced at an energy price that is equivalent to natural gas in the $6-$9/GJ range. Areva's estimates support this.

In October 2015 a DOE assessment said: “The HTR, with outlet temperature limited to less than 800°C, is suitable for near-term deployment as a demonstration reactor.” It noted US government and industry investment in HTRs since the 1960s, totalling over $3 billion.

In South Korea the Nuclear Hydrogen Development & Demonstration (NHDD) project is focused on HTR technology for both hydrogen production and liquid hydrocarbons. It was launched in 2006 as a key programme supported by the Ministry of Science and Technology (now the Ministry of Science and ICT). The Korean Atomic Energy Research Institute (KAERI) earlier submitted a Very High Temperature Reactor (VHTR) design to the Generation IV International Forum. The VHTR is to produce hydrogen on a large scale, with 300 MWt modules each producing 30,000 tonnes of hydrogen per year. KAERI had expected engineering design to be completed by 2014, construction start 2016 and operation of a demonstration reactor in 2020, with commercialisation about 2025. R&D focus is on development of corrosion-resistant high-temperature materials and components and refractory coated-particle fuel.

KAERI also has a research partnership with China's Tsinghua University focused on hydrogen production, based on China's HTR-10 reactor.

In Japan, JAEA has confirmed the safety of HTRs, and in April 2004 a coolant outlet temperature of 950°C was achieved in its High-Temperature Engineering Test Reactor (HTTR) – a world first; and in 2009 it ran at 950°C for 50 days, opening the way for direct thermochemical hydrogen production. In January 2019 it produced hydrogen using the iodine-sulfur process over 150 hours of continuous operation in its integrated process loop of 100 L/h design capacity, operating at 30 L/h. Meanwhile JAEA plans to make hydrogen by steam reforming natural gas, using HTTR’s high temperature.

Based on the HTTR, JAEA is developing the HTR50 nuclear steam supply system to operate at 750°C and produce steam at 538°C and 12.5 MPa. Thermal rating would be up to 200 MWt and it would have the same TRISO fuel as the HTTR. It involves Toshiba, Fuji Electric and KHI and a lead plant is planned for the 2020s.

Following this and moving to VHTR, JAEA plans the 600 MWt Gas Turbine High Temperature Reactor (GTHTR300) cogeneration system operating at 850-950°C to enable 300 MWe electricity generation using direct cycle gas turbine, with 370 MWt process heat for hydrogen production (120 t/day), steelmaking (650,000 t/yr) and other industrial applications including district heating and desalination (55,000 m3/day) using waste heat. The basic design has been completed, involving MHI, Fuji Electric, IHI, and NFI and the lead plant is expected in the 2030s. The IS hydrogen system beyond the intermediate heat exchanger would be non-nuclear grade, in line with other hydrogen production facilities.

In 2006 the South African PBMR board formalised the concept of a higher-temperature PBMR process heat plant (PHP) with reactor output temperature of 950°C. The first plants were envisaged for 2016 and the applications would have been oil sands production and petrochemical industry (process steam), steam methane reforming for hydrogen and eventually thermochemical hydrogen production. Each 600 MWt module would produce about 200 tonnes of hydrogen per day, which is well matched to the scale of current industrial demand for hydrogen. In 2011 the programme was aborted due to lack of funds.

Process heat applications

Process temperature Up to 700°C Up to 900°C Up to 950°C
Electricity production Rankine (steam) cycle Brayton (direct) cycle
Utility applications Desalination H2 via steam reforming of methane or high-temperature electrolysis Thermochemical H2 production
Oil and chemical industry Tar/oil sands and heavy oil recovery,
Refinery and petrochemical
Syngas for ammonia and methanol Thermochemical H2 production

Recovery of oil from tar sands

From about 2003 various proposals have been made to use nuclear power to produce steam for extraction of oil from Alberta's northern tar sands deposits, as well as electricity for the major infrastructure involved.

About 1.05 GJ (28 m3) of natural gas is typically required to produce a barrel of bitumen by in situ methods (according to the Canadian Energy Resource Institute). This bitumen must then be upgraded to oil – natural gas is the raw material for hydrogen (by steam reforming) to break down the long-chain hydrocarbons to yield synthetic crude oil. The extraction overall represents a total energy intensity of 1.37 GJ per barrel of oil (each embodying 6 GJ), and in 2014 it accounted for one-third of Alberta's primary energy demand.

With production of 2.4 million barrels per day of crude bitumen in 2016 (half mined and half in situ), a great deal of gas is used and the cost exposure is considerable. Production is expected to reach 3.6 million barrels per day in 2026. In fact, Canadian natural gas is inadequate to supply the anticipated expansion in oil sands output and its use has major CO2 implications which are creating public concern – over 80 kg of CO2 per barrel is released in its production. Oil sands production accounts for 8.5% of Canada’s greenhouse gas emissions.

An intrinsic problem is that the steam supply needs to be semi portable as tar sand extraction proceeds, so relatively small reactors which could be moved every decade or so may be needed. One problem related to the provision of steam for mining is that a nuclear plant is a long-life fixture, and mining of tar sands proceeds across the landscape, giving rise to very long steam transmission lines and consequent loss of efficiency.

One proposal from Energy Alberta Corp. suggested that a single CANDU 6 reactor (about 1800 MWt) configured to produce 75% steam and 25% electricity would replace 6 million cubic metres per day of natural gas and support production of 175-200,000 barrels per day of oil. It would also save the emission of 3.3 million tonnes of CO2 per year. Other figures from Pebble Bed Modular Reactor (PBMR) proponents confirm that each 100 MWt will enable production of 10,000 barrels per day.

The Canadian Energy Research Institute (CERI) published a report in February 2009 saying that employing nuclear energy with (so far untested) carbon capture and storage in tar sands extraction and processing could make oil from that source cleaner than conventional oil with respect to its greenhouse gas and other emissions. The CERI report looked at both very large (1600 MWe) and multiple very small (10 MWe) nuclear reactors.

A more recent proposal is from Canada’s Terrestrial Energy, putting forward its Integral Molten Salt Reactor (IMSR), which the company aims to commercialise by 2021. It is considering 300 MWt units, producing simply steam.

The main difference between natural gas and nuclear steam generation is that a fuel-intensive process is replaced by a capital-intensive one, with no carbon emissions.

Oil refining

As well as separating the different components of crude oil by two distillation processes, an oil refinery typically breaks down the residual heavy or long-chain hydrocarbons in a catalytic cracker by adding hydrogen. The hydrogen is produced from natural gas, and it breaks down the long-chain hydrocarbons to yield synthetic crude oil (about 5 kg is used per barrel). This hydrogenation of heavy crude oil is a major use of hydrogen today. Overall, about 15-20% of the energy value of the crude oil is used in producing refined products.

Hydrogen production is by steam reforming of the natural gas, and gives rise to a lot of carbon dioxide. Nuclear power could make steam and electricity and use some of the electricity for high-temperature electrolysis for hydrogen production. (Heavy water and oxygen could be valuable by-products of electrolysis). Oil refineries account for about one quarter of the world's hydrogen demand.

Coal to liquids (CTL)

Various processes are used. Indirect liquefaction accounts for most world production, about 260,000 barrels/41,000 m3 per day. Coal is gasified to syngas and the product synthesized either to diesel and jet fuel, or to gasoline (Mobil or methanol MTG process). Direct liquefaction processes miss the syngas step and are either hydrogenation or pyrolysis and carbonization.

The Fischer-Tropsch (F-T) process was originally developed in Germany in the 1920s, and 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 most of that country's diesel fuel. However, it is a significant user of hydrogen, catalyzing a reaction with carbon monoxide. The hydrogen is now produced with the CO by coal gasification, part of the gas stream undergoing the water shift reaction.

* Coal gasification produces both CO and H2 feed for F-T, and the water shift reaction turns some CO into CO2 and more H2, both stages using water. In F-T itself hydrogen plus CO converts to alkane hydrocarbons using a catalyst.

At Erdos, Inner Mongolia, China, Shenhua Coal Liquefaction Corp produces 20,000 barrels /3000 tonnes of oil per day from nearly 10,000 tonnes of coal from the Shenfu-Dongsheng coalfield, using US technology. The $2.06 billion Erdos CTL plant was commissioned in 2010 and in 2013 it produced 866,000 tonnes of oil products. It has total design capacity of 1.08 million tonnes, comprising diesel (621,000 t/yr), naptha (321,000 t/yr) and LPG (70,000 t/yr). Water supply is a constraint on operation, and it requires 7-12 tonnes of fresh water to produce one tonne of product, depending on whether direct liquefaction or indirect (based on F-T), along with 9 tonnes of CO2 and 4.8 tonnes of contaminated waste water according to critics. It uses coal hydrogenation at high temperature and pressure with a catalyst.

Shenhua proposes $7 billion plant in Ningdong, Ningxia, China – the Shenhua CTL plant to produce 80,000 barrels/ 13,000 m3/day, using Sasol’s indirect liquefaction technology, based on F-T. Sasol has withdrawn from the venture.

The hydrogenation (Bergius) process requires hydrogen to react directly with coal at high temperature and pressure. Pyrolysis and carbonization processes give less yield, and that usually needs refining. They are not commercial for CTL.

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.

Using simply black coal in the Sasol-type plant, 14,600 tonnes produces 25,000 barrels of synfuel 'oil' (with 25,000 tonnes of CO2).

A hybrid system uses nuclear electricity to electrolyse water for the hydrogen. 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.

Hydrogen for agricultural fertilisers

Nuclear power has potentially a major role in agriculture.

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 box), combining abundant atmospheric nitrogen with hydrogen. The resulting ammonia is then oxidised to nitrates. But the hydrogen has to be made from fossil fuels, mainly methane, i.e. natural gas. This is costly and it gives rise to substantial carbon dioxide emissions ( in several steps, but overall: CH4 + O2 ⇒ CO2 + 2H2, so each tonne of hydrogen gives rise to 11 tonnes of CO2). Ammonia production accounts for over half of the world's hydrogen demand.

The Haber process

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.

N2 + 3H2 ⇒ 2NH3

The Haber process produces about 100 million tonnes of nitrogen fertilizer per year and consumes about 3-5% of the world's natural gas production to make the hydrogen for it.

If the hydrogen can be made simply from water, the CO2 is avoided and a valuable organic chemistry feedstock is conserved. Nuclear power can produce hydrogen by electrolysis, particularly high-temperature electrolysis, and in the future it may be made thermochemically as described above. An abundant supply of low-cost hydrogen would greatly boost world agricultural productivity through increased availability of nitrogen fertilizers.

Biomass-based ethanol production

Commercial-scale ethanol production from cellulose in a biorefinery requires energy input. Two processes can be used: biochemical fermentation, or thermochemical conversion. Either way, the energy input needed to produce ethanol from cellulose materials (such as wood) is equivalent to 25 to 38% of the output, mostly as steam (though the thermochemical process also requires high temperatures).

As well as burning the lignin content of feedstock, some energy can readily be supplied by nuclear plants as cogeneration, on a carbon-free basis. In future, the lignin may be converted to liquid fuels, probably by hydrogenation. In this case, the yield of liquid fuels from biomass can be increased by about half, per unit of input. Much of the nuclear energy input is as low-temperature steam, essentially a by-product of electricity generation, and hence low-cost.

CO2-based methanol production

Avoiding the need to encroach on arable land for biomass such as corn, or clear woody growth elsewhere, methanol (CH3OH) production from famously-surplus CO2 can use nuclear heat as well as nuclear-produced hydrogen. See sections below.

In 2015 global methanol capacity reached 118 million tonnes and is expected to reach 184 Mt by 2020, according to GlobalData. Most production today is from synthesis gas (carbon monoxide and hydrogen) derived from biomass or fossil fuels, usually by steam reforming of natural gas. Most methanol use is for making plastics. About 14% of it is used as a petrol additive, with the amount increasing steadily, and 7% to make dimethyl ether (DME). Methanol production accounts for about 13% of the word's hydrogen demand.

Hydrogen production

Most hydrogen today is made by steam reforming of natural gas. Some is produced by electrolysis, with the hydrogen able to be stored. Hence this is an important potential application of surplus power from intermittent renewable sources, as well as for nuclear power especially off-peak.

World demand is about 70 million tonnes of pure hydrogen plus 45 million tonnes mixed with other gases and used in industries such as steel and methanol production, both kinds of demand growing steadily1. About half of annual production is used in making nitrogen fertilisers via the Haber process and about half to convert low-grade crude oils (including those from tar sands) into transport fuels. 

About 76% of pure hydrogen is made from natural gas and 23% from coal. This gives rise to 830 million tonnes of carbon dioxide emissions annually – each tonne produced gives rise to at least 11 tonnes of carbon dioxide. Electrolysis accounts for only 2%1.

Recent plans in several countries have focused on hydrogen production by electrolysis, which is undertaken on a fairly small scale today, and requires about 50 kWh per kilogram produced. If the electricity is from intermittent renewables then this is so-called 'green hydrogen'. ('Grey hydrogen' is that produced from methane with corresponding CO2 emissions, 'blue hydrogen' is grey hydrogen but with CCS.) In 2019 cost estimates by Dutch bank ING were about €1.50/kg for grey hydrogen, €2.50/kg for blue hydrogen and €5-6/kg for green hydrogen. Electrolyser cost is put at $850/kW. International Atomic Energy Agency (IAEA) figures in 2019 were $4.15/kg for conventional electrolysis, $3.23/kg for dedicated nuclear high-temperature steam electrolysis (HTSE), and $2.50/kg for off-peak HTSE, about the same as for large-scale steam reforming of methane.

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.

Nuclear power already produces electricity as a major energy carrier. It is well placed to produce hydrogen either for converting CO2 into methanol (CH3OH), or if hydrogen itself becomes a major energy carrier also, in addition to its roles in oil refining and fertiliser production.

The evolution of nuclear energy's role in hydrogen production over perhaps three decades is seen to be:

  • Electrolysis of water, using off-peak capacity (needs 286 kJ/mol).
  • 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 requires temperatures of over 800°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.*

* Due to the need to compress hydrogen, plus the inefficiency of the fuel cell, from hydrogen to electric drive is only 30-40% efficient at this stage, giving 15-20% overall primary heat to wheels, compared with 25-30% for PHEV.

High-temperature electrolysis (HTSE, at 800°C or more) has been demonstrated, and shows considerable promise. 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.

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

Hydrogen 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.

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:

H2SO4 ==> H2O + SO2 + ½O2

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

 I2 + SO2 + 2H2O ==> 2HI + H2SO4

The HI then dissociates to hydrogen and iodine at about 350°C, endothermically:

2HI ==> H2 + I2

This can deliver hydrogen at high pressure.

Combining all this, the net reaction is then:

H2O ==> H2 + ½O2

All the reagents other than water are recycled, there are no effluents.

The Japan Atomic Energy Agency (JAEA) has demonstrated laboratory-scale and bench-scale hydrogen production with the IS process, up to 30 litres/hr. In January 2019 it used the HTTR to produce hydrogen using the iodine-sulfur process over 150 hours of continuous operation.

Sandia National Laboratories in the USA and the French CEA are also developing the IS process with a view to using high-temperature reactors for it.

General Atomics' preliminary laboratory work on thermochemical production was to be complete by 2006. A 10 MW pilot hydrogen plant using fossil heat was then to be built, followed by nuclear thermochemical production by 2015.

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 $1.50 to $2.00 per kg. The oxygen by-product also has value.

For thermochemical processes an overall efficiency of greater than 50% is projected. Combined cycle plants producing both H2 and electricity may reach efficiencies of 60%.

Production reactor requirements for process heat

Three potentially-suitable 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 best 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 Reactors page.

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.

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 temperatures for commercial hydrogen production.

Moving forward on hydrogen

In February 2010 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. In parallel with JAEA’s HTTR developments a pilot plant test project producing hydrogen at 30 m3/hr from helium heated with 400 kW tested the engineering feasibility of the IS process. An IS plant producing 1000 m3/hr (90 kg/hr, 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/hr was demonstrated. In January 2019 it produced hydrogen using the iodine-sulfur process over 150 hours of continuous operation.

The economics of thermochemical hydrogen production look good. General Atomics earlier projected US$ 1.53/kg based on a 2400 MWt HTR operating at 850°C.with 42% overall efficiency, and $1.42/kg at 950°C and 52% efficiency (both 10.5% discount rate). At 2003 prices, steam reforming of natural gas yields hydrogen at US$ 1.40/kg, and sequestration of the CO2 would push this to $1.60/kg. Such a plant could produce 800 tonnes of hydrogen per day, "enough for 1.5 million fuel cell cars" (@1 t/day for 1800 cars). JAEA aims to produce hydrogen at less than $3/kg by about 2030 with VHTR.

In the meantime, hydrogen can be produced by electrolysis of water, using electricity from any source. Non-fossil sources, including intermittent ones such as wind and solar, are important possibilities (thereby solving a problem of not being able to store the electricity from those sources). However, the greater efficiency of electrolysis at high temperatures favours a nuclear source for both heat and electricity.

In 2013 an IAEA report said that “nuclear generated hydrogen has important potential advantages over other sources that will be considered for a growing hydrogen share in a future world energy economy. Still, there are technical uncertainties in nuclear hydrogen processes that need to be addressed through a vigorous research and development effort. Safety issues as well as hydrogen storage and distribution are important areas of research to be undertaken to support a successful hydrogen economy in the future.”

Production of methanol using hydrogen, DME

Following on from thermochemical hydrogen production, and considering the storage and portability challenges of hydrogen itself, as well as the radical change to fuel cell cars, attention has turned to methanol. As noted above: portable hydrogen storage is difficult, especially for automotive use. Any future 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.

LNG has similar problem to hydrogen, ethanol comes from biomass, but methanol can be made from CO2 and hydrogen. If the hydrogen is nuclear-produced, and CO2 is a problem due to its abundance, automotive fuel can be provided forever, using present engine technology. For diesel engines, dimethyl ether (CH3-O-CH3) 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. These two have an energy density of 18-19 MJ/L, so less than oil-based fuels, but usable and easily stored. The post-oil future may be methanol-based.

Also, methanol can be used in fuel cells, if these are preferred over internal combustion engines.

Methanol, and dimethyl ether (DME) derived from it, are good energy carriers, and DME in particular can substitute for diesel fuel. 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

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.

Dimethyl ether (DME) is already used as propane replacement, and world production capacity is over 10 million tonnes per year. China alone is 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 a three-year xME project led by Ford with members of the FVV, Germany's international combustion engine technology research network.

Methanol, together with derived DME, can be used as: (i) a convenient energy storage medium; (ii) a readily transportable and dispensable fuel for internal combustion engines and compression ignition (diesel) engines with little engineering change; (iii) a fuel for fuel cells; and (iv) a feedstock for synthetic hydrocarbons and their products, including fuels, polymers and even single-cell proteins (for animal feed and/or human consumption).

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

In China, the Shanghai Advanced Research Institute has developed a process to convert carbon dioxide 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 carbon dioxide and hydrogen, but with different intermediate products. While there are a number of processes that can convert carbon dioxide to single-carbon hydrocarbons such as methanol, the synthesis of longer-chain hydrocarbons has previously been elusive.

District heating

Many reactors in cold climates provide hot water for district heating, without significant penalty in electrical performance. This usually replaces fossil fuel sources, with significant reduction in CO2 emissions.

Notes & references


1. International Energy Agency, The Future of Hydrogen – Seizing today's opportunities, Report prepared by the IEA for the G20, Japan (June 2019) [Back]

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Roger Arnold, The lowdown on hydrogen – part 2: production, Energy Post (21 April 2017)
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Donald Hoffman, EXCEL Services, Nuclear High Temperature Heat for Industrial Processes – HTGRs, GEMINI, the PRIME Concept and the U.S. Advanced Reactor Effort, presented at a side event to the International Atomic Energy Agency 61st General Conference held in Vienna, Austria (18-22 September 2017)
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