Green hydrogen searches for industrial outlets

In a world trying to wean itself off fossil fuels, hydrogen looks to be the answer to so many problems. It is nowhere as easy to handle as coal or oil but as a transportable fuel, hydrogen can go to many places that the electricity supply cannot. If they turn to producing it, operators of renewables farms around the world can kiss goodbye to the spectre of curtailment by simply diverting energy to nearby electrolysers whenever the electricity grid is full. Like liquid fuels, hydrogen can store energy for months rather than merely a matter of hours.

Inevitably, there is a downside. Unlike many of the storage technologies such as batteries or pumped hydroelectric reservoirs, hydrogen has a poor round-trip efficiency that is unlikely to get much better over the coming few decades. As much as two-thirds of the energy used to produce hydrogen is lost. Though the Hydrogen Council predicts hydrogen will be used for seasonal energy storage even by 2050 this will probably account for less than 10 per cent of the world’s output of green hydrogen because batteries and pumped-hydro and air installations are far more efficient storage options.

This will focus the use of hydrogen on industries that can justify using it even after taking into account that round-trip loss. Heavy transport is one option: it may account for around 25 per cent of hydrogen consumption by 2050, with industrial and home heating responsible for another third, according to the same Hydrogen Council predictions. Industrial production where it can substitute other raw materials is where hydrogen is likely to yield the biggest bang per buck in the shorter term. Even then, it will not be an easy switch and some major markets that need hydrogen today may well be a lot smaller by the time green hydrogen makes significant inroads.

With a demand of just under 40Mtonne in 2019, the biggest single use for hydrogen in industry today, ironically, is to support the oil business: refiners use the gas to reduce the sulphur content of petrol and diesel. As the source of this hydrogen can come from natural gas as well as from heavy oil through a process called partial oxidation, refining looks to be a poor candidate for green hydrogen. If oil usage begins to drop as the result of electrification, refiners may simply choose to focus on oil that has lower sulphur content to begin with, though it is possible significantly higher carbon tax or pricing might push refiners to buy in green hydrogen rather than invest in carbon capture at their plants.

It is a tiny user of hydrogen today but steel production has arguably the strongest argument for moving to hydrogen as a fuel, particularly if you compare the carbon dioxide output per tonne of raw steel production to the emissions from conventional blast furnaces. Responsible for as much as 1.7 tonne of carbon dioxide per tonne of metal, steel production in the classic blast-furnace process accounts for around 7 per cent of global emissions.

One option for cutting carbon emissions in the short term is to replace coke, used to reduce iron ore to metallic iron in a blast furnace, with hydrogen. This is what Thyssenkrupp among others has been trialling at its Duisberg plant. Unfortunately, there seems to be only so far you can go with this although hydrogen provides a path to partially decarbonising steelmaking without demanding a wholesale change to the process or extensive use of carbon capture and storage. Modelling by Can Yilmaz and colleagues from the Energy Research Centre of Lower Saxony, found only pulverised coal, which is conventionally used to increase the heat of the furnace, can be substituted with hydrogen. Coke would have to remain a major component of the process. That in practice limits reductions in carbon dioxide emissions to less than a quarter. Thyssenkrupp is targeting reductions of around 20 per cent.

Where hydrogen could make a bigger impact on steelmaking is in a direct-reduction process coupled to electric arc furnaces that are gradually replacing their coal-fuelled cousins and which, even today, is the most common process used in the US. Even then, it is not necessarily a clean sweep for hydrogen at least in the early stages of the transition, though a spokesman for Thyssenkrupp said the ultimate aim is to move to 100 per cent hydrogen based on direct reduction.

Modelling work by researchers at the University of Stavanger in 2019 found an increase in the overall energy consumption: hydrogen needs higher temperatures to reduce iron ore compared to the traditional mixture of carbon dioxide and monoxide. If you assume electricity supplied at the EU’s average grid emission factor of 295kgCO2/MWh, emissions fall by a third. In countries such as Poland, where coal-fired power is far more common today, emissions increase overall.

The question is whether it is better to focus renewables on making electricity rather than green hydrogen. The Stavanger team estimated electrolyser energy is at least double that of the electricity used for the arc furnace. It may make sense simply to switch to electric heating and use conventional sources of hydrogen unless the green form of the gas becomes plentiful. Analysis by S&P Global Platts found that in arc furnaces powered by renewables, even grey hydrogen, which is made from natural gas, leads to a significant reduction in carbon intensity compared to conventional blast furnace production.

Because of these complicating factors, it may take decades for green hydrogen to become a major component of steelmaking. However, the work so far shows there are multiple paths for introducing the gas as the industry transitions away from blast furnaces.

Cement production is similar to steelmaking in how both heat and chemical change contribute to carbon dioxide emissions. Hydrogen is being trialled as an alternative to natural gas and has the advantage of delivering high temperatures more easily for the process of making the key component, clinker. As with steel, the round-trip efficiency of hydrogen may prove to be a weakness as plasma heating directly from electrical sources may prove to be more commercially viable. The advantage that hydrogen has here is that it involves fewer equipment changes, though its compatibility with conventional kilns is still being investigated by manufacturers.

Ammonia, used to make fertilisers, provides a more straightforward path for conversion. Only narrowly behind refining in terms of volumes of hydrogen used today, with an annual demand on the order of more than 30Mtonne per year, ammonia is as carbon intensive as steel if the feedstock is grey hydrogen. It easily emits more than double the carbon per kilogram produced if the source is black hydrogen, where coal gasification produces the source gas.

Yet, there are issues that may, at least for the next decade, force green hydrogen to take a back seat in ammonia production. One is the Haber-Bosch process used to make ammonia from atmospheric nitrogen and hydrogen. The good news is that the reaction is exothermic – generating more energy than it uses – but calls for high temperature and pressure to get going. Energy efficiency drops significantly if the plant has to be wound down frequently, making it a poor outlet for renewables operators who expect to use intermittent electrolysis as a way to avoid curtailment. Ammonia plants choose to switch between blue and green hydrogen to maintain throughput. However, if ammonia turns out to become the dominant form for shipping hydrogen in the absence of pipelines, operators may simply choose to absorb the cost of heating their converters for each burst of activity rather than undertake the potentially more expensive option of liquefying hydrogen.

A second reason for favouring blue hydrogen at least in the short term, depending on the carbon price, is that the unwanted emissions from steam reforming can potentially be diverted into the manufacture of another nitrogen-based fertiliser: urea. Because urea fertiliser releases carbon dioxide after spreading, it is far from ideal as a means of carbon capture and may gradually be phased out in favour of nitrates made using ammonia, which in turn pushes production towards green hydrogen.

Ammonia is just one chemical product. The German government in particular is keen on the concept of ‘power to X’ (PtX), which revolves around the use of hydrogen and carbon sources, converted to carbon monoxide ‘syngas’ to make the chemicals that are today mostly derived from oil. To be considered green, hydrogen derived from renewables is practically essential. Blue hydrogen simply adds the complication of sequestrating carbon in one step before another source is potentially found for the chemical synthesis operations. In this environment, carbon pricing will likely determine how quickly chemical producers will switch. They may be able to hit targets by taking advantage of green hydrogen during the oil refining step rather than trying to incorporate green hydrogen synthesis. As with the rest of the debate around hydrogen, so much depends on the pressure exerted by legislation and the pricing mechanisms that go with it.