National Hydrogen Strategy Issues Papers

There are ‘direct’ and ‘indirect’ measures for reducing emissions in steel manufacturing. These
measures can also apply to other manufacturing industries such as food (e.g. margarine/vegetable
oil from hydrogenation), glass production (e.g. surface treatment, tempering) and generator turbine
cooling.
Direct measures
Steel, more precisely steel alloy with minor alloying elements, requires extensive heating above the
steel alloys’ melting point and alloying/refining to form by means of direct combustion of fuel gas
and oxygen.
When using hydrocarbon or H2‐mix as fuel, the source of oxygen plays an important part in the
heating process. Purer oxygen is injected into the furnace/burner (with iron, lime, coke and alloying
elements). Better performance (conversion efficient) is expected when less energy is wasted into tail
components (stack gas).
Therefore, a reliable and consistent supply of oxygen to steel manufacturing can directly support
emissions reductions. Performance and efficiency are based on the economical availability of oxygen
injected into the furnace and quality of the fuel. The purer the oxygen and advancement of the
burner, the less energy that is wasted. The balanced stoichiometric ratio of pure oxygen and fuel
gases and the advance fuel gas blender and injectors also play a key role.
Improvement of heat recovery from the amount of energy leaving the furnace in tail components
and recycle of stack gas for other processes could also be encouraged. One waste stream from a
process can become a feedstock to other processes or energy sources.
Indirect measures
An indirect measure is the distance between the oxygen/hydrogen supply and steel manufacturing
plant, which can help reduce bulk oxygen/hydrogen deliveries and the amount of transport fuel
consumed. Strategic locations of steel manufacturing and oxygen/hydrogen supply could be
considered.
While heat recovery or conversion from process/waste stream and energy audits (conserving energy
in production) could also be considered.
Another indirect measure is to convert the emissions source (CO2) to an alternative usable product.
An example of this is methane and/or methanol, which can be converted by the pathways of photoelectrochemical
(PEC) and/or bio reactor using enzyme. CO2 can then be purified from the waste
stream into a useable product, such as beverages and other intermediate uses.
While these indirect measures do not exactly represent an emissions reduction, recycling via
repurposing or conversion of the carbon source (preferably with renewable energy), will reduce
reliance on carbon capture storage.
Investment in newer steel making technologies could also potentially drive a different economic
case in Australia that supports more higher‐value manufacturing. Incentives could be offered to
support growth of these industries through new technology.
Universities across Australia are also conducting different research projects in bio‐CO2 conversion. A
coordinated national approach between stakeholders, industry and universities is recommended to
support productivity and ensure appropriate funding to scale up and commercialise projects.
Key stakeholders need to work with steel manufacturers to explore options for reducing carbon
emissions – either using green electricity for furnaces or reducing carbon dioxide for hydrogen
production.

Industrial heat definitions can include (1) combustion for heat generation, (2) electrical process
heaters by thermal conversion, (3) boiler and steam generator by combustion of thermal conversion
and (4) heat and recovery/recycling system. Refer to attached diagram for an illustrated example.
Alternative energy sources (compared to the fuel currently used, such as carbon base gas/coal)
should consider renewables, such as solar, wind, hydro and ocean tidal waves to replace or
supplement the ‘Fuel’ and ‘Electricity’ on the left‐hand side of the diagram. Electricity generated
from a renewable source is a relatively simpler switch for achieving emission reductions. Gases and
liquids could also be considered, for example biofuels from a liquid perspective.
In finding a replacement or supplement fuel for heat generation, direct or indirect methods could be
considered. An indirect method could be adopting an electricity pathway for a possible transition to
H2, however this would require hardware change or major retrofitting. A direct method with
emissions reduction in mind, would be blending H2 with hydrocarbon fuel, thereby improving
combustion efficiency. The Standards Australia technical committee ME93 is looking at the Type B
appliance conversion from European standards (CEN) experience, while the Future Cell CRC is
conducting research and development into Type A and B appliances with H2 and H2 mix fuels.
Traditionally, the focus has not been on heat recovery from waste stream or flue/stack gas. This is
due to the additional investment required, with payback not always considered worthwhile when
cheaper energy (such as off‐peak rate) is made available and no government incentives.
While alternative energy sources are important to industrial users, a secure store of energy that is
readily available for use is equally important. Government incentives for energy providers and largescale
industrial users could be considered.

Hydrogen used as chemical feedstock needs to fulfil certain process specifications. Renewable
hydrogen from electrolysis, delivers purity levels at around 99%+. This purity is significantly more
than what is required in petrochemical refining processes, where a 90% purity level is satisfactory.
There are multiple challenges feeding hydrogen directly from a (fuel) gas network as feedstock to
industrial applications (other than fuel gas use) due to odourising reagents (whether sulphur base or
ester base) or unforeseen impurities including particulate matters.
However, it’s possible to feed hydrogen as feedstock to a chemical process if the network has a
dedicated supply of a specific grade of hydrogen. This type of localised and dedicated network can
be considered as a buffer storage too.
Location needs to be strategically considered. Hydrogen generation should come from the solar belt
rich region in central Australia as it can then be bulk transported via liquid H2. A localised generation
from a wind/solar source can then feed to a localised dedicated network for use.
Transporting large volumes of any fuel via trucking can be highly inefficient. For hydrogen,
challenges include its lightness and associated requirement for cryogenic trucks to transport it in
more dense, liquid form. While advances in the commercialisation of extracting hydrogen from
carriers such as ammonia may be available in the future, this is not expected to be commercially viable for some time. Bulk volumes of hydrogen would be most efficiently transported via fixed
infrastructure such as pipelines. However, for this to be commercially viable it is likely to be a
repurposed pipeline that has been assessed as fit for hydrogen service.
Given industrial operations are generally 24/7, the supply of hydrogen to any such operation would
have to be from a reliable, sustainable and continuous source.

This paper defines hydrogen as ‘clean H2’ produced using renewable energy or using fossil fuels with
carbon capture and storage. From an industrial user perspective, H2 is a raw material or
intermediate in an overall production process regardless of where or how it is sourced. The cost of
the raw material impacts the cost of production. While process changes are less likely if H2 meets
the raw material specification, it depends on each plant, how easy the integration will be, and what
equipment modifications would be required. However, if hydrogen was used as an electricity source,
the amount of modification required could be significantly less.
The timing of taking large‐scale clean H2 would be getting the cost base H2 from renewable source
closer to the current production cost, whether by Steam Methane Reforming (SMR) or electrolysis
from water. There are several sites that could be used to demonstrate the use of clean hydrogen.
However, a demonstration plant that integrates green hydrogen from an electrolyser, into a refinery
would have minimal material impact on the amount of hydrogen consumed. The largest electrolyser
being installed globally, at Rhineland, has a capacity of 10MW, which equates to approximately
1,300t/year of green hydrogen. This is approximately 0.7% of all hydrogen consumed there. In
Australia, while any reduction could be beneficial, having a secondary, stand‐alone electrolyser
would never be able to replace current SMR processes during an outage because electrolyser sizes
and hence volumes are still too small.
Odorising reagents containing sulphide can also impact the quality of the hydrogen for industrial use
and fuel cells. Sulphide is considered as a fuel cell degradation reagent or catalyst. Therefore,
odorant exemptions for industrial processes could also be considered to resolve these challenges
and protect equipment.
Quote from report 19184‐REP‐001‐rC
“Introduction of H2 has shown some benefits for engines (internal combustion) such as improving
the lean‐burn capability and flame burning velocity of natural gas engines under lean‐burn
conditions, as an increase in flow intensity is introduced in the cylinder which results in improved
engine efficiency but at the expenses of increased engine wear and increased NOx emission.”
At ambient temperatures, oxygen and nitrogen do not react. However, at high temperatures, they
undergo an endothermic reaction producing various species of oxides of nitrogen, some as
intermediate exist in relatively short time spend. NOx can be formed naturally from lightning or
bushfires.
Common NOx control strategies include flame characteristic optimisation (such as lowering the
flame temperature, tunning of oxygen injection) and hardware investment (catalytic low NOx
burner, flue gas recirculation). The former requires fine additional resources for tune and re‐tune on
a regular basis. The latter requires investment in major retrofitting. For Type A appliances, the
potential increases in NOx (when switching to H2 mix to 50% H2 blended) is negligible from
preliminary Australian Gas Association (AGA) testing observations. For Type B, due to the scale and
requirement of the fuel specification, some major upgrade/retrofits would likely be required. Timing
to revisit would be 50% blended H2 in gas network is ready.

Key challenges for the safe handling of H2 include flammability (4% to 75% limit), gas compatibility
and permeability. Due to its wide range of flammability, hydrogen is classified as Group IIC in
hazardous classification (Group IIC – hydrogen and acetylene). System design including electrical
components and installation would require more stringent specification which is more complex than
IIA and IIB groups such as LPG, petroleum. The IIC requirements poses additional challenges when
retrofitting into Group IIA and IIB existing installations.
Safe handling of hydrogen should be built on decades of developed worlds’ industrial experience and
knowledge. Many renowned references are available from Europe and North America, such as
European Industrial Gases Association (EIGA). Some of the sought codes when designing and
commissioning hydrogen plants/system are EIGA Doc 06/19, Doc 15/06, Doc 23.07/18, Doc 100/11,
as well as the yet to be adopted ISO publications.
It is important to stress that knowledge is not a substitution of ‘knowhows’ of safe handling of
hydrogen whether in high pressure gaseous form, cryogenic condition, storage in metal hydride or in
liquid‐solid slush form. A gas fitter qualification does not necessarily give the same levels of service
as an industrial gas technician competently handling 1000bar (100 MPa) and cryogenic installations.
Training and training providers will be in high demand, with industrial gas companies in Hydrogen
Mobility Australia playing an active role.
A cohesive interstate collaborative approach across government and industry is necessary to
streamline the development of a clean hydrogen industry. A situation where there are different
regulatory regimes in different states must be avoided.
The new Standards Australian technical committee established in April 2018, seeks to mirror the
ISO/TC197 publication on hydrogen technologies. ME93 will map the needs of further adoption (e.g.
TC105 fuel cell technologies, TC22 fuel cell vehicles) and the development of new standards in an
Australian context.

Organisations with established infrastructure and expertise in hydrogen can assist TAFE Colleges in
training and upskilling tradesmen to ensure correct certifications for maintaining hydrogen refueller
systems, and installation and commissioning of hydrogen gas system.
With the industry still in its infancy, cost remains a significant challenge in deploying proven
hydrogen technologies. As hydrogen research and development activities continue across Australia,
the key will be to ensure the right balance of investment and policy support to allow technologies to
be commercialised and deployed at a larger scale – therefore driving down costs across the
hydrogen value chain. Government incentives during the initial set‐up phase may help relieve costs.
Incentives are needed to help drive down the cost of electrolysers, which is one of the biggest
hurdles for the hydrogen market. Solar helps provide much lower costs for production, however
CAPEX is still high when considering an electrolyser. This applies to other infrastructure across the
hydrogen value chain, such as refuelling and hydrogen storage systems.
Close collaboration and partnerships with relevant industry associations, including Hydrogen
Mobility Australia, is required to build strong relationships with industry and to identify initiatives
that can be leveraged for overall sector growth. It is also important to consult with large industrial
players with a track record of delivering largescale projects with complicated supply chains.
Lastly, investment in shipping infrastructure should be considered as this requires less widespread
infrastructure and can take on bulk volumes. This would help position Australia for long‐term,
sustainable supply contracts.