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Metallurgical coal’s role in the blast furnace

The blast furnace is a great example of what is termed a ‘counter current reactor’. Hot air or ‘blast’ is blown into the furnace via the tuyeres at the base of the furnace and the iron ore or ‘ferrous burden’ added at the top. Hot gases rise heating the descending burden. Metallurgical coke is also added to the top of the furnace, in alternating layers with the ferrous burden to promote gas and liquids flow. Coke is a product of heating a blend of metallurgical coals to over 1000°C to fuse the particles together to form fist sized lumps.

Coke plays three important roles inside the furnace. It provides:

  • a source of heat, raising the temperature inside the furnace to over 2000°C;
  • a chemical reducing agent, carbon monoxide that strips away the oxygen from the iron ore leaving metallic iron; and
  • internal structural support to the furnace and the materials inside and provide permeability for gas and liquid flow.

The first two roles can be fulfilled by substitutes: pulverised coal, natural gas, biomass, industrial waste or even hydrogen. Only coke can provide the internal structural support and permeability the blast furnace requires to operate efficiently. For this reason, coke is essential for the blast furnace process and while steelmakers strive to reduce coke consumption to reduce costs and carbon emission, a ‘minimum coke rate’ in the order of 250 kg per tonne of hot metal will be required.

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The opportunities and challenges of carbon capture

The integrated steel making process has multiple sources of CO2 with varying concentrations. For this reason, the application of carbon capture technology within an integrated steelmaking facility is more complex than in some other emissions intensive sectors.

Within an integrated steelmaking facility, there are two main sources where carbon capture can be adopted covering three quarters of all carbon emissions:

  1. At the hot blast stoves where energy rich gases from the blast furnace or coke plant (or natural gas) are combusted to heat the blast air; and
  2. At the onsite power plant where any remaining waste gases are combusted to produce electricity.

Another factor that needs to be considering with carbon capture is the proximity of suitable storage basins to major the steel making regions. While there appears to be an abundance of storage globally, the proximity of individual plants to suitable storage sites might make carbon capture more difficult at many steelmaking facilities.

Notwithstanding these challenges, the opportunity remains considerable; CCUS remains one of the lowest cost and most impactful abatement levers available to steel plants in many regions. While, adoption of CCUS within the steelmaking industry has had limited uptake to date - there is only one commercial scale project operating globally - there are a number of new pilot- and commercial-scale plants that are either in planning or under construction that will play an important role in demonstrating the benefit of this technology within the steelmaking industry.

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On low carbon hydrogen

The availability of large amounts of zero or very low carbon hydrogen is a key building block of many plausible pathways to the achievement of the green end state. Today, almost all hydrogen is produced through the chemical reforming of natural gas or gasification of coal, both relatively cheap (~$1/kg or $7.50/MMBtu) and carbon-intensive (the unabated gas variety is twice as carbon intensive as just burning the natural gas itself). There are two viable alternatives to bring down emissions:

  1. Blue hydrogen: using coal or natural gas, but adding CCS to abate ~90% of emissions. Costs today are ~$2.3/kg.
  2. Green hydrogen: Producing hydrogen via electrolysis of water coupled with zero carbon electricity, which today can be produced at $2.5-6.8/kg depending on geography and electrolyser technology.

Both face an uphill battle. Option 1 must cope with the storage and infrastructure difficulties mentioned in the CCS section above, in addition to concerns around methane leakage and natural gas feedstock availability.

Option 2 has gained significant attention in the European Union and among deep decarbonisation proponents. There is some encouragement here in that electrolyser learning rates, or the cost reduction experienced for every doubling of capacity, have improved to just under 20%--roughly on par with onshore wind (but still below solar panels, which have sustained a > 20% learning rate since the 1970s. However, electrolyser capex is just one challenge. Electricity and water costs make up between 50% and 85% of the cost of producing hydrogen and therefore green hydrogen’s competitiveness will depend on the ability to produce massive amounts of low cost renewable power that enable high utilisation rates.1

Even if electrolyser costs were to fall by 50% from the cheapest available on the market today, and even if you can get your electrolyser running at 50% utilisation (keep in mind, the average capacity factor for a solar plant today is ~20%), you’d still need to see power prices fall to $10/MWh (~60% lower than today’s lowest cost wind and solar) to get below the $1/kg mark. And if that electrolyser is only taking advantage of excess solar or wind and therefore running at lower utilisation, your electricity costs will need to fall even lower. Adding to the costs will be the additional transport and storage needs, with many of the world’s most valuable solar and wind resources located in remote geographies far from steel demand centres. 

A combination of higher carbon levies, continued renewables power cost reductions, and improvements in renewables capacity factors from energy storage and demand response could all help to close the gap. However, on economics alone, it’s clear that the challenges are considerable and will take a considerable period of time to surmount.

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1 Based on utilisation of 50%. At 100% utilisation, OPEX makes up 80-97% of the levelised cost of hydrogen. Bloomberg New Energy Finance.
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