Hydrogen is widely expected to be the energy carrier to replace fossil fuels as renewable energy becomes more prevalent. A good energy carrier needs to be easy and cheap to transport between producers and end-users. Unfortunately, hydrogen has a very low bulk density that makes it prohibitively expensive to transport over long distances, limiting its widespread adoption. Ammonia (NH3) provides a potential solution and could enable the worldwide trade of renewable energy.
The cheapest method of producing hydrogen is by chemically reacting natural gas (CH4) with water (steam) at high temperatures. This process, called steam methane reforming (SMR), is carried out in very large chemical plants and it accounts for approximately 95% of the 65 million tonnes of hydrogen produced per year. Unfortunately, carbon dioxide is a by-product of this method of hydrogen production, with about 9 tonnes of CO2 produced for every 1 tonne of H2.
To produce low-carbon hydrogen, it is possible to capture about 80% of the CO2 produced by SMR and inject it deep into the ground where it will remain trapped for thousands of years. Suitable locations include depleted oil and gas wells and deep saline aquifers. This process of ‘carbon capture and storage’ (CCS) requires the hydrogen to be produced in locations close to wells or aquifers which are suitable for CO2 storage.
CCS has been successfully demonstrated in several locations, but it has not yet been widely deployed to produce low-carbon hydrogen. Some technical challenges remain and it does pose some long-term liability and environmental concerns. The cost of CCS is an additional concern, but it is expected to provide an economically viable means of producing low-carbon hydrogen, provided it is operated at a large scale.
If widely available, it is anticipated that hydrogen from natural gas with CCS (so-called ‘blue hydrogen’) would have a production cost of approximately $2.30/kg, on average in Europe.
For use as a transport fuel in fuel cell vehicles, cost parity with diesel, fully taxed, in the UK would require a hydrogen price, at the pump, of approximately $7.30/kg ($2.60/kg excluding taxes). Consequently, it is apparent that blue hydrogen could be an economically viable alternative to diesel, providing access to suitable carbon storage is available.
Water electrolysis is an alternative means of producing low, and ultimately zero-carbon, hydrogen. In this process, an electric current is passed through water, breaking it down into its constituent components; hydrogen and oxygen. As with CCS, this technology has been widely demonstrated, but not yet at the scale required to make any significant impact on the demand for hydrogen.
Although electrolysis has relatively high capital costs at present, the main contributor to the cost of hydrogen produced by electrolysis is, by far, the cost of the electricity used.
Large-scale electrolysis, directly connected to renewables could potentially provide hydrogen at a low cost. In this case, the hydrogen would be zero-carbon or ‘green’. To achieve a comparable cost to blue hydrogen, a renewable electricity price of $40/MWh would be required with a high capacity factor. Such prices could be achieved in limited specific locations within Europe.
Small-scale grid and renewables-connected electrolysers are being installed at distributed end-user locations but they suffer from intrinsically high electricity prices and it is questionable whether these will be economically viable. The average price of grid electricity in the UK for ‘very large industrial consumers’ was approximately $140/MWh in Q3 2020. In the most favourable circumstances, this would equate to a hydrogen cost in excess of $7.00 per kg, excluding any taxes. In some situations, the cost could be reduced by private line connection to renewables but the benefit is partly offset by low capacity factors that could result in the expensive electrolyser asset standing idle for a significant amount of time.
Electricity prices of less than $20/MWh can be achieved by direct connection to renewables in locations such as the Middle East, North Africa, and Australia but, unfortunately, any hydrogen produced would need to be transported great distances to large centres of demand.
Low-cost, low or zero-carbon hydrogen can be produced but only in locations with a combination of low-cost natural gas and carbon storage or where there is low-cost renewable electricity. These locational requirements mean that hydrogen will need to be transported over long distances to reach end-users in many centres of population.
Fossil fuels do a great job of holding energy in a form that can be easily stored and transported at a low cost. For example, a 44-tonne truck can carry sufficient gasoline to refuel 900 cars. Unfortunately, a similar-sized truck of the type typically used to transport hydrogen, as a gas compressed at 180 bar (2,700psi), can only refuel 50 cars. This is because hydrogen is a very light gas indeed. At atmospheric pressure, it is about 8,000 times less dense than gasoline. This is improved when it is compressed, but then it must be held in very heavy, thick, steel-walled cylinders which take up most of the payload carrying capacity of the truck.
More hydrogen can be carried if it is turned into liquid form. This is still 10 times less dense than gasoline and now it has to be cooled to – 253oC, just 20o above absolute zero, and transported in super-insulated cryogenic vessels. A truck of liquid hydrogen can fill up to 600 cars but the costs associated with the liquefaction and transportation are still very high.
The cost of transporting hydrogen by road depends on the detail of specific routes but a cost of $1/kg hydrogen per 100km is typical for the compressed gas.
Shipping hydrogen by sea is also expensive. Kawasaki Heavy Industries has produced an 8,000-tonne ship to transport liquid hydrogen from Australia to Japan. It can carry 75 tonnes of hydrogen. Not a lot for such a big ship!
While the development of blue and green hydrogen production has progressed rapidly, much less attention has, so far, been paid to the infrastructure and supply chains necessary to deliver hydrogen fuel to end-users at low cost and in the quantities required. This is not a trivial issue. As we have seen, hydrogen can be produced cheaply, but only in certain favourable locations, and, because of its extremely low density, hydrogen is expensive to transport over any significant distance.
The use of ammonia (NH3) as a bulk hydrogen carrier has the potential to address these issues. Ammonia has a high hydrogen density and is readily transported and stored in liquid form. Surprisingly, there is 50% more hydrogen in 1 litre of liquid ammonia than there is in 1 litre of liquid hydrogen!
The ammonia industry is mature, with existing storage and distribution assets and a well-established safety record.
The key question is: Can low/zero carbon ammonia be produced, transported and converted back to hydrogen at a lower cost than transporting hydrogen in its elemental form?
Several players in the hydrogen industry believe that it can. An example is Air Products, which has announced a $5bn joint investment with renewables company ACWA and the Saudi city of NEOM to produce 1.2 million tonnes per year of green ammonia. A further $2bn will be invested to establish the infrastructure to ship this ammonia around the world and ‘crack’ it back to hydrogen close to the points of end-use. The ammonia will be made by the Haber-Bosch process which has been operated and developed since the 1920s. Hydrogen will be fed to this process from large electrolysers directly connected to both wind and solar electricity generation. Air products believes that the low cost of renewable electricity at NEOM, in north-west Saudi Arabia, combined with a high capacity factor on the electrolysers will produce very low-cost hydrogen which can then be supplied in the form of ammonia to other countries where the cost of producing green hydrogen will be much higher.
In this highly optimised situation, it is anticipated that an electricity cost of less than $20/MWh will be achieved which will enable hydrogen production of approximately $1/kg.
Liquid ammonia has physical properties similar to LPG and ships capable of transporting LPG can generally be used for ammonia. It is estimated that the cost of transporting liquid ammonia from the Middle East to the UK via the Suez Canal (6,266 nautical miles) in a typical dual purpose LPG/NH3 vessel containing 60,000 tonnes would be approximately $0.33/kg of hydrogen contained, including canal fees, port costs, insurance and return of the empty vessel.
Once landed, the ammonia can then be transferred to road tankers and trucked to the end-user for cracking, purification, and use as a transport fuel. The fact that the hydrogen is in the form of ammonia means that the road transport part of the distribution chain is very low in cost in comparison to transporting domestically produced compressed hydrogen. For an example journey of 240km, from the port to the end-user, the cost of transporting hydrogen as ammonia is $0.18/kg, compared with $2.18 for the same route for compressed hydrogen gas.
Once the ammonia is delivered to the end-user, it needs to be ‘cracked’ back to hydrogen and purified. This adds approximately $0.86/kg hydrogen to the overall cost.
A comparison of the costs for UK produced green hydrogen and hydrogen produced in the Middle East and transported as ammonia is given in Figure 4. The comparison assumes an electricity cost of $50/MWh in the UK and $20/MWh in the Middle East and in both cases, the end-user is 240km from either the UK production location or the UK port of arrival.
It can be seen that by using ammonia as a hydrogen carrier under these assumptions, Middle East produced hydrogen can be provided more cheaply to UK end-users than domestically produced hydrogen, where the end-users are located more than about 100km from the source of production. A large proportion of the demand base in Europe, North America, and Asia would also benefit from this supply method.
This has potentially significant implications for the future trade of renewable energy. Where historically, fossil fuels have been the energy carriers to connect production and demand, ammonia may take over. The Air Products green ammonia facility is due online in 2025 and many other companies are exploring ammonia as a future energy carrier. There are some challenges to be overcome, including the development of commercial-scale ‘cracking’ technology but overall, this concept is based on already proven and practiced, low-cost technologies and distribution methods.
In summary, the widespread adoption of hydrogen as a low/zero-carbon fuel is hindered not by its costs of production, but by its costs of distribution. Ammonia can potentially provide a means of distributing hydrogen around the world at a low cost. This has implications for global trade, enabling the supply of the world’s cheapest renewable energy to distant markets and accelerating the transition to net-zero.
Kevin Fothergill has 35 years of experience in the chemicals, hydrogen and fuel cells industries. He has a degree in Chemistry and an MBA and has operated in a range of technical, commercial and business management roles. Previously Commercial Director at Johnson Matthey Fuel Cells for 12 years, he is currently Chief Executive at EnAcumen, a boutique consultancy providing market and technical advice on all aspects of hydrogen and fuel cells. He is passionate about the adoption of hydrogen for decarbonisation but is realistic and pragmatic about the challenges that need to be overcome. Kevin has been involved in numerous committees and industry groups and has extensive contacts across the industry. He is widely regarded as an authority in this field with a deep understanding of the business drivers of hydrogen producers and end-users.
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