Northern Territory Low Emissions Carbon Capture Storage and Utilisation Hub
Sector Coupling Opportunities ? Task 5 Report
Jason Czapla, Matthew Josh, Ben Clennell, Andrew Ross, Indiana Squiers

December 2024



CSIRO Energy
Citation
Czapla, J., Josh, M., Clennell, B., Ross, A., Squiers, I. (2024) Northern Territory Low Emissions Carbon Capture Storage and Utilisation Hub: Sector Coupling Opportunities Ð Task 5 Report. CSIRO report number EP2024-6156, pp 94. CSIRO, Australia.

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Foreword
Transitioning the global energy system while rapidly reducing emissions to net zero by 2050 is a vast and complex global challenge. 
Modelling of a range of emissions pathways and decarbonisation scenarios from the Intergovernmental Panel on Climate Change (IPCC, 2023a), International Energy Agency (IEA, 2024) and Net Zero Australia (NZA, 2024) shows that to meet net zero 2050 greenhouse gas emissions targets, a wide range of emissions reduction technologies will be required to decarbonise existing and future industries globally (IPCC, 2023b).
These organisations identify that emissions elimination from hard-to-abate and high-emissions industries will require using carbon capture and storage (CCS) alongside other abatement strategies, such as electrification, underpinned by power generation from renewable energy sources such as photovoltaics and wind. 
Globally, there is considerable effort being undertaken to identify industrial hubs and clusters where common user infrastructure and efficient linkages between energy end users, manufacturing and supply chains (sector coupling) can enable rapid decarbonisation of existing industries and enable future low-emissions industrial development. 
Australia has an opportunity to create new low-carbon growth industries and jobs in these areas, but lacks the infrastructure, skills base and business models to realise this. The transition to net zero will have greater impact on regional communities, particularly those reliant on industries in transition, but it may also create economic opportunities through a wide range of new industries and jobs suited to regional areas.
The Commonwealth Scientific and Industrial Research Organisation (CSIRO) is working to identify decarbonisation and transition pathways for existing and potential future industries that may be established in the Northern Territory by developing a Low Emissions Hub concept in the Darwin region. 
CSIRO has established a portfolio of projects to explore and evaluate a range of emissions reduction and emerging transition technologies and approaches. This includes research into Northern Territory renewable energy potential, hydrogen demand generation and storage, and carbon capture utilisation and storage (CCUS). CSIRO is working collaboratively with industry and government to understand their needs, drivers and strategic directions so that our research is informed and relevant. This includes establishing appropriate pathways and partnerships to understand and incorporate the perspectives of First Nations peoples.
A key activity is the research into a business case project (CSIRO, 2024a; Ross et al., 2022) that aims to enhance understanding of the viability of a CCUS hub centred on the Middle Arm of the Darwin Harbour. 
The work has three elements comprising 15 tasks:
1. analysing macroeconomic drivers, Northern Territory and regional emissions, low-emissions product markets (Ross et al., 2023), identifying key learnings from other low emissions hubs being developed globally, and cross-sector coupling opportunities (Tasks 0?5) 
2. completing CCUS hub technical definition and technical risk reduction studies, including detailed studies on the infrastructure requirements for a CCUS hub, renewable power requirements for existing and potential future industries and road-mapping for carbon dioxide (CO2) utilisation industries that could be established to produce low or net zero products (e.g. zero-emission chemical feedstocks) (CSIRO, 2023c) (Tasks 6?9) 
3. creating a business case to appreciate the scale of investment required to develop a Low Emissions Hub and the economic returns from doing so; this will lead to suggested business models and routes of execution (Tasks 10?14). 
The CCUS business case project will involve research that is based on possible industrial development scenarios, models of future potential emissions, market demand, technologies and costs. The project is intended to provide an understanding of possible future outcomes. Industry development will be determined by individual industry proponent investment decisions, government policies and regulations, and the development trajectories of technologies essential to the energy and emissions transition. 
On completion of this research, outcomes of the CCUS business case project will be made publicly available. 
The work summarised in this report comprises Task 5 of the Northern Territory CCUS business case project. It provides an understanding of possible sector coupling options that could be contemplated as part of the Middle Arm Sustainable Development Precinct (MASDP). Sector coupling could increase process efficiencies and provide future options for industrial transition as new lower emissions technologies become commercially available at scale. This report provides only an initial assessment of these options, with further investigation required to fully understand the benefits and disadvantages of sector coupling.



Contents
Acknowledgements	viii
Abbreviations		ix
Summary		xii
1	Introduction	1
1.1	Sector coupling and industrial symbiosis in the energy transition	1
1.2	Sector coupling for a Northern Territory Low Emissions Hub	3
1.3	Sector coupling examples chosen for analysis	5
2	Hydrogen production	7
2.1	Introduction to hydrogen production	7
2.2	Thermochemical methods of hydrogen production from methane	7
2.3	Biohydrogen production	19
2.4	Electrolytic hydrogen production	20
2.5	Water usage for hydrogen production	24
2.6	Sector coupling opportunities	25
3	Cryogenic air separation	27
3.1	Introduction	27
3.2	Inputs and outputs	27
3.3	Process	27
3.4	Opportunities for industrial symbiosis, sector coupling and decarbonisation	29
4	Ammonia and urea production	31
4.1	Ammonia production	31
4.2	Urea production	32
4.3	Alternative low-emissions ammonia synthesis pathways	32
4.4	Opportunities for industrial symbiosis, sector coupling and decarbonisation	33
5	Methanol	35
5.1	Introduction	35
5.2	Production	35
5.3	Potential for lower emissions methanol via biosynthetic and electrochemical pathways	37
5.4	Discussion	38
6	Direct air carbon capture	40
6.1	Introduction	40
6.2	Process	40
6.3	Energy consumption	45
6.4	Key companies	46
6.5	Main challenges	47
6.6	Opportunities for sector coupling and industrial symbiosis	48
7	Liquid air energy storage	50
7.1	Introduction	50
7.2	Benefits and limitations of LAES	53
7.3	Sector coupling opportunities for LAES	53
8	Spodumene refining for lithium	54
8.1	Introduction	54
8.2	Process	55
8.3	Inputs and outputs	57
9	Block diagrams of possible configurations for the Northern Territory Low Emissions Hub			60
10	Summary and conclusions	64
10.1	Managing energy efficiency: reutilisation, storage and electrification	64
10.2	Barriers and opportunities for sector coupling	64
References		66



Figures
Figure 1: A map of the Middle Arm Sustainable Development Precinct	4
Figure 2: The Balanced Scenario showing the wide range of potential industries that could be located in the MASDP, and their input needs, outputs and output uses Source: NTG (2024)	4
Figure 3: Highly simplified block diagram of synthesis routes for ammonia, urea and methanol using methane reforming	5
Figure 4: Block flow diagram of steam-methane reforming	9
Figure 5: Block flow diagram of autothermal reforming with carbon capture	11
Figure 6: Summary of inputs and outputs for reforming-based process for hydrogen production. Categories with question marks are dependent on process/technology used	13
Figure 7: Block flow diagram of a simplified methane pyrolysis system with carbon capture	14
Figure 8: Levelised total methane consumption per tonne of hydrogen produced	17
Figure 9: Levelised onsite CO2 emissions per tonne of hydrogen produced using thermochemical methods	17
Figure 10: Levelised cost of hydrogen converted to 2023 US$	18
Figure 11: Schematic of an electrolyser cell of proton exchange membrane type with a selectively permeable membrane for hydrogen ions separating the two half-cells	20
Figure 12: General block diagram of an air separation unit	28
Figure 13: Conventional flow of the Haber-Bosch process	31
Figure 14: Methanol synthesis flowsheet based on a quench reactor	36
Figure 15: Methanol synthesis via direct CO2 hydrogenation	37
Figure 16: Schematic representation of the DAC process	41
Figure 17: Schematic of a liquid DAC system.	43
Figure 18: S-DAC, based on a system used by Climeworks	44
Figure 19: Energy requirements, in GJ/tonne CO2.	46
Figure 20: Schematic of a liquid DAC system.	48
Figure 21: Representation of sector coupling between energy, climate and water for DAC systems driven by renewable energy. Heat pumps, thermal energy storage (TES) and electrical energy storage (here represented by batteries) are key enablers	49
Figure 22: Generalised block flow diagram of LAES	51
Figure 23: Plot of published LAES RTE rates versus charge pressure	52
Figure 24: A flow diagram of the major treatment processes for spodumene (chlorination, sulfation and alkaline processes)	56
Figure 25: A block flow diagram illustrating the production of lithium hydroxide and lithium carbonate products from spodumene	57
Figure 26: Simplified block diagrams of the processing of spodumene to lithium hydroxide monohydrate or lithium carbonate to illustrate the major input and output streams amenable for integration with other industrial processes	59
Figure 27: Illustrative diagram of the integrated process blocks that can be developed in the hub in the near term	60
Figure 28: Illustrative diagram of an integrated process block that can be developed once lower cost hydrogen and DAC are demonstrated	62
Figure 29: MASDP Balanced Scenario potential industry locations	62

Tables
Table 1: Benefits of and barriers to sector coupling and symbiosis between industry partners	1
Table 2: Levelised inputs per tonne of hydrogen produced for various production methods (52% and 85% denote the percentage of CO2 captured)	16
Table 3: Levelised CO2 emissions generated for various thermochemical hydrogen production methods	17
Table 4: Cost breakdown of natural gas-based technologies at an illustrative plant capacity of 607 tonnes hydrogen/day (in 2023 US$) (Source: Oni et al. (2022))	18
Table 5: Raw water demand depending on water quality and assuming evaporative cooling	24
Table 6: Production range of air separation processes as described by Tesch et. al. (2019)	28
Table 7: Levelised inputs and outputs for ASU	29
Table 8: Levelised inputs and outputs for the production of 1 tonne of methanol via direct CO2 hydrogenation Source: Schorn et al. (2021)	37
Table 9: Principles, advantages and disadvantages of different DAC technologies	41
Table 10: Key features of S-DAC and L-DAC systems	44
Table 11: LAES development history	50
Table 12: Chemical composition and percentage of lithium in minerals	54
Table 13: Comparison of leaching processes for lithium extraction from minerals	55
Table 14: Material, energy and water inputs per tonne of concentrated spodumene produced, based on Western Australian mining	57
Table 15: Material, energy and water inputs per tonne of lithium hydroxide monohydrate and lithium carbonate produced in China from Australian spodumene concentrate	58
Table 16. Classes of energy storage technology for cross-sectoral use	64

Acknowledgements
CSIRO acknowledges the Traditional Owners of the land, sea and waters, of the area that we live and work on across Australia. We acknowledge their continuing connection to their culture, and we pay our respects to their Elders past and present.
The authors of this report acknowledge the support and funding provided by CSIRO to undertake this work. We thank the internal CSIRO independent peer reviewers for their review of the report and valuable comments and suggestions.
While this report is an output from a CSIRO-funded initiative, we thank our industry and government collaborators for their insights, contributions and suggestions, which have improved the report outcomes.
Although CSIRO has sought feedback from government and industry on the technical content of the report, CSIRO has sole discretion on including such feedback.

Abbreviations
¡C
Degrees Celsius 
Al2O3
Aluminium oxide
ARENA
Australian Renewable Energy Agency
ASU
Air separation units
ATR
Autothermal reforming of methane
AUD
Australian dollar 
CAES
Compressed- air energy storage
CaO
Calcium oxide
CCS
Carbon capture and storage
CCUS
Carbon capture utilisation and storage
CH4
Methane 
CO
Carbon monoxide 
CO2
Carbon dioxide
CO2e
Carbon dioxide equivalent 
CSIRO
Commonwealth Scientific and Industrial Research Organisation
DAC
Direct air capture 
DC
Direct current 
DCCEEW
Department of Climate Change, Energy, the Environment and Water
DIPL
Department of Infrastructure, Planning and Logistics
GHG
Greenhouse gases 
GJ
Gigajoule 
GL
Gigalitres 
Gt
Gigaton
GTGW
Gigawatt
H2
Hydrogen 
H2O
Water
HP
High pressure 
HT
High temperatures 
IEA
International Energy AgencyÊ
IPCC
Intergovernmental Panel on Climate ChangeÊ
IrO2
Iridium dioxide
IRR
Internal rate of return 
K2O
Potassium oxide
kg
Kilogram
KJ
Kilojoule 
kL
Kilolitre
KtÊ
Kilotonne
KWh
Kilowatts hour 
L
Litres 
LAES
Liquid air energy storage 
L-DAC
Liquid direct air capture
Li
Lithium 
LNG
Liquified Liquefied natural gas
MASDP
Middle Arm Sustainable Development Precinct
MECS
Microbial electrolysis cells
MJ/L
Megajoules per liter 
Molmol
Unit of measurement 
MP
Methane pyrolysis
Mt
Million tonnes
Mtpa
Million tonnes per annum
NGD
Natural gas decomposition
Nh2conh2NH2CONH2
Urea 
Nm3
Normal cubic meter
NT
Northern Territory
NT-DIPL
Northern Territory Department of Infrastructure, Planning and Logistics
O2g
Oxygen gas
Pd
Palladium
PemPEM
Proton exchange membrane 
PJ
Petajoule
ppm
Parts per million 
PSA
Pressure-swing adsorption
Pt
Platinum
PV
Photovoltaics
R&D
Research and development
RTE
Round trip efficiency 
RuO2
Ruthenium oxide
SAF
Sustainable aviation fuels
S-DAC
Solid direct air capture 
SiO2
Silicon dioxide
SMR
Steam methane reforming
SOx
Sulfur oxides
t
Metric tonne
TES
Thermal energy storage
tpa
Tonnes per annum
TRL
Technology readiness level 
TWh
Terawatt-hour
US
United States 
V
Volts
WGS
Water?gas shift
WGS-HT
WGS at high temperature
WGS-LT
WGS at low temperature
X2P
X to power (using something else to create power, e.g., hydrogen)

Summary
Realising net zero ambition within industrial sectors will require large-scale deployment of renewable energy, low-emissions substitution of fossil fuels and significant increases in process efficiency (IEA, 2023b). Substantial efficiencies can, in principle, be gained through the coupling of industrial processes across different sectors.
As such, this Task 5 report of the Northern Territory CCUS business case project focuses on a high-level technical review of technologies and approaches that could be employed to realise cross-sector coupling. 
While there is no single definition of sector coupling (Ramsebner et al., 2021), the term is most commonly used to describe the uptake of excess renewable electricity to power homes, transportation and industry. For this report, sector coupling is considered broadly to include, alongside electrification, beneficial use of process heat, repurposing of existing facilities and the creation of new products from waste streams. These concepts, associated with industrial symbiosis or industrial ecology, fall within the paradigm of sustainable development and the growth of a circular economy where waste is ultimately eliminated (Kusch-Brandt, 2020).
While sector coupling seems like a win?win for everyone, there are inevitably trade-offs whenever projects increase in complexity and the number of stakeholders and regulators grows. At a minimum, an increase in the time taken for approvals and key business decisions can be expected. Where different commercial entities are sharing new infrastructure or investing in equipment and processes that are not fully tested, differences in risk appetite, access to capital or legal and contractual issues may prevent what would otherwise be a profitable venture. Critically, to realise the benefits of cross-sector coupling there is a requirement for a common vision, a willingness to collaborate and to share risk.
The concept of sharing common infrastructure and using industrial symbiosis to realise a circular economy and cross-sector coupling has a long history, with much written about the success or failure of landmark enterprises, such as the Kalundborg Eco-Industrial Park in Denmark. This is cited as a model of good practice where water, energy and raw materials are shared (Engie Impact, 2021), but where success has been hard won (Perrucci et al., 2022). The World Bank points to eco-industrial parks as a way forward for sustainable development (Aggeri, 2021), but successful examples are more likely to be found in prosperous Scandinavia or the centrally planned economy of China than in G7 countries or the Global South. In industrial hubs, research centres and training facilities can also become part of the energy ecosystem, sharing infrastructure, using waste heat and trialling new technologies to reduce risks before they are adopted at scale by heavy industry.
Methodology
This report focuses on sector coupling and industrial symbiosis opportunities in existing and future potential industries that could be located within the MASDP. It uses the Balanced Scenario (this scenario uses the widest range of industries that are envisaged to be established in the MASDP) developed by the Northern Territory Department of Infrastructure Planning and Logistics (NT-DIPL). The actual industrial mix that is established in the MASDP may not match the exact composition used here, but the Balanced Scenario offers a way to align with other modelling and design activities that the Northern Territory Government is pursuing.
The technologies reviewed in this report were selected for how they could be implemented in chemical synthesis routes and include the production of ammonia, urea and methanol (and derivatives). Synthesis routes were considered as an integrated system (i.e. not separate processes) and process technologies were considered for both their utility for sector coupling in the near term and also their adaptability for changing feedstock and sector coupling benefits over the long term. In selecting the technologies, a sequential approach was used to first screen and then identify those for more detailed investigation.
As a result of the screening and identification process, the technologies discussed in detail in this report are:
* hydrogen 
o methane reforming combined with CCS
o electrolytic water splitting to produce hydrogen from renewably sourced electricity, as an example of sector coupling
* cryogenic air separation, including liquid air energy storage (LAES)
* ammonia and urea synthesis
* methanol synthesis
* direct air capture (DAC) of carbon dioxide
* mineral processing of critical energy metals.
These technologies have only been reviewed at a high level and further process modelling is required to gain a more detailed understanding of the viability of their implementation within the MASDP and the Northern Territory Low Emissions Hub.
Hydrogen
There are several sector coupling opportunities across hydrogen-generation technologies. These include the use of ÔwasteÕ oxygen from electrolysis as an input feedstock for autothermal reforming (ATR) of methane. In addition, there are opportunities to use waste heat to drive endothermic reactions and in carbon dioxide (CO2) capture material regeneration. In the case of methane reforming, waste CO2 can also be used to synthesise downstream products of urea and methanol. There are also potential opportunities for the recycling of waste heat in the generation of power through both methane reforming and electrolysis pathways. 
Cryogenic air separation 
Cryogenic air separation is important in several processes: oxygen can be used in ATR and other chemical processes, while nitrogen is required in combination with hydrogen for ammonia and urea production. In addition, atmospheric CO2, water and noble gases produced can be sequestered or used for other processes or to generate additional revenue streams. 
Cryogenic air separation is a significant industrial process that can been scaled up to process thousands of tonnes of air per day and accordingly involves the use of large amounts of electrical power and the transfer of large amounts of heat. There are clear synergies between the compression trains and chiller systems used for air separation units (ASU) and other processes requiring cooling. For example, when liquefying hydrogen for storage or transportation, the type of cooling used in an ASU may be used in a preliminary stage. On the other hand, if lower grade cooling is needed for refrigeration (e.g. for meat packing, or for transportation of goods), Ôwaste coldÕ could be used, which would mean that much of the energy requirement for chillers may be reduced. 
The most obvious sector coupling opportunities that LAES can enable is variable renewable energy firming by the storage process. Oversized ASUs required for gas separation for other processes can provide the appropriate volumes of cryogenic gases for expansion to generate power. Various cases have been discussed in the literature, a recent example being the combination of air separation, argon concentration and waste heat recycling into LAES, proposed by Liu et al. (2024). According to their analysis, the system payback time could be as short as 6 years, with much of the uplift derived from an efficient waste heat recovery system.
Ammonia and urea synthesis
In the production of ammonia and urea, aside from sector coupling opportunities for power to hydrogen, and efficiency improvements in the nitrogen production chain by more integrated process cooling systems, sector coupling opportunities can also be achieved through incorporation of biowaste to generate nitrogen compounds such as urea and nitric acid derived from black liquor gasification of waste wood pulp (Ribeiro Domingos et al., 2024).
Methanol synthesis
In methanol synthesis, the relatively low heat process requirements potentially allow waste heat from other processes to be used or heat to be generated from renewable electricity or solar thermal sources. 
Direct air capture 
Thermal energy for desorption of capture materials represents 80% of energy requirements for DAC. Therefore, waste heat could dramatically reduce the operational costs for DAC technologies where heating requirements are low. At the same time, the processes supplying the waste heat may benefit from reduced cooling requirements. The energy to drive fans is another major cost component of DAC. There is an opportunity to leverage air flows from other industrial processes such as cooling towers. Alternatively, the coupling could be focused on the power generation side of a major hub development close to renewable infrastructure combined with electrical energy storage (e.g. batteries).
Mineral processing of critical energy metals 
In the review of mineral (lithium ore) processing pathways, there are limited sector coupling opportunities beyond the use of electricity and hydrogen for high heating requirements associated with the processing of lithium ores.
Results
The review of industrial processes has identified technologies that can be used to create a low-emissions production hub for the synthesis of ammonia, urea, methanol and derivatives. Two possible integrated processes are presented, the first representing near-term integrated industrial development and the second medium-to-long term process adapting the first integrated process to take advantage of future technology developments and reductions in costs. The core of an integrated process is the production of hydrogen, which is the key building block for downstream products.
The near-term integrated industrial development envisages an ATR hydrogen generation plant fed by oxygen (from the ASU), methane and steam feedstocks, with resultant CO2 captured for storage or further downstream use. Hydrogen would then be used for the synthesis of ammonia (using nitrogen from the ASU) and methanol, also using CO2 from hydrogen generation. Methanol could be used in the manufacture of further derivatives. The ammonia plant could use some of the generated CO2 for synthesis of urea. Assumed in the integrated industrial development would be the reuse of heat and cold energy across the system, as identified in the report. 
The medium-to-long term integrated process envisages adaptions to incorporate the production of hydrogen through electrolysis and DAC for CO2 capture exchanging the prior ATR. All other components of the system would be retained, with the ASU continuing to supply nitrogen to the ammonia plant but now also using nitrogen as a liquid air energy storage medium.
Conclusions
It should be noted that more detailed investigation is required to assess the viability of such a system, and that there might be intermediate stages to development where methane reforming, electrolysis and DAC operate simultaneously to reduce net emissions and obtain greater sector coupling efficiencies. The technical key to sector coupling success is efficient energy management. Storage is at the nexus of sector coupling between electricity, industry and transport (Sterner and Stadler, 2019) and for the industries discussed in this report, reuse and storage of heat are important, as well as transferring and exchanging heat efficiently.
To be able to realise sector coupling in the Northern Territory Low Emissions Hub through either the processes and technologies discussed here, or alternative approaches, it is important that technological and financial risks can be managed and shared. In other jurisdictions mechanisms have been implemented that allow greater investment certainty and so enable industries to invest in higher risk technologies. In Australia, the Australian Renewable Energy Agency (ARENA) funding for projects is one example of how government investment can enable the uptake of new technologies, although this funding is often constrained to a single sector. 
To enable cross-sector coupling and the operation of shared systems requires significant technical expertise and ongoing maintenance and upgrades by a skilled workforce. Plans should not be overcomplex or overambitious in their goals, and common standards and language should be adopted among industries. In addition, existing regulations may not fully support and may even hinder industrial symbiosis, requiring adjustments or new policies to facilitate better integration. There may also be legal and contractual issues, or disputes over information sharing and intellectual property. Careful consideration is required to understand how to remove unnecessary barriers to sector coupling.
Aligning the interests of multiple stakeholders and managing complex agreements can be time-consuming and difficult. A central body with proper governance could be established to plan for success and to operate efficiently and responsibly once launched. The foundation industry participants, together with their commercial partners (for finance and material supply), energy and service providers and the state or territory government, would typically be the key stakeholders whose vision must be aligned. Other key stakeholders include the traditional owners, residents of neighbouring areas, primary producers (farming, pastoral, forestry, fishing), unions and trade associations and other statutory interested parties. The workers at all levels within the participating companies are the final set of critical stakeholders. Informing and giving agency to all of these stakeholders is a key to success.




1 
1 Introduction
1.1 Sector coupling and industrial symbiosis in the energy transition
To realise net zero ambition within industrial sectors will require large-scale deployment of renewable energy, low-emissions substitution of fossil fuels and significant increases in process efficiency (IEA, 2023b). Substantial efficiencies can be gained through the coupling of industrial processes from different sectors. There is no single definition of sector coupling (Ramsebner et al., 2021), with the term most commonly used to describe the uptake of excess renewable electricity to power homes, transportation and industry. For this report, sector coupling is considered broadly to include, alongside electrification, beneficial use of process heat, repurposing of existing facilities and the creation of new products from waste streams. These concepts, associated with industrial symbiosis or industrial ecology, fall within the paradigm of sustainable development and the growth of a circular economy where waste is ultimately eliminated (Kusch-Brandt, 2020).
Sector coupling might seem like a win?win for everyone, but inevitably there are trade-offs whenever projects increase in complexity and the number of stakeholders and regulators grows. At a minimum, the time taken for approvals and key business decisions can be expected to increase. Where different commercial entities are sharing new infrastructure or investing in equipment and processes that are not fully tested, differences in risk appetite, access to capital, and legal and contractual issues may prevent what would otherwise be a profitable venture. Table 1 summarises some of the pros and cons of sector coupling and industrial symbiosis in a hub or cluster.
Table 1: Benefits of and barriers to sector coupling and symbiosis between industry partners
Benefits
Barriers
Reduction in capital cost of shared facilities and access to major infrastructure
Technical risks from more complex and/or novel and untested interconnected systems and plant
Reduced energy costs from more efficient processes and reuse of waste heat
Project management complexity from more stakeholders and multiple decision makers
Reduced raw materials costs using waste or by-products in novel synthesis
Risk of dependency and flow-on problems from one process, or from one entity across to others
Reduced overall environmental impact from CO2 emissions, water use and waste streams
Regulatory and legal issues navigating multiple sectors with different laws and/or jurisdictions 
Access to new markets and premium price for low-emissions products
Long-term commitment to finance and maintain common infrastructure, supply chains and markets
Emergence of new, high-growth industries providing wealth and employment
Disputes arising from ownership, facility management, intellectual property or institutional culture

The concept of sharing common infrastructure and using industrial symbiosis to realise a circular economy has a long history, and much has been written about the success or failure of landmark enterprises such as the Kalundborg Eco-Industrial Park in Denmark. This is cited as a model of good practice where water, energy and raw materials are shared (Engie Impact, 2021), but where success has been hard won (Perrucci et al., 2022). The World Bank points to eco-industrial parks as a way forward for sustainable development (Aggeri, 2021), but successful examples are more likely to be found in prosperous Scandinavia or the centrally planned economy of China than in G7 countries or the Global South. Helpful definitions, reviews and recommendations for industrial symbiosis involving sector coupling between clean energy provision, material production, supply chains and waste heat utilisation can be found in (Fraccascia and Giannoccaro, 2020; Fraccascia et al., 2021; Henriques et al., 2021; Neves et al., 2020; Trianni et al., 2017; Turken and Geda, 2020; Walsh and Thornley, 2012).
Industrial symbiosis and more recently sector coupling in Australian industry clusters have been addressed widely, with the example of Kwinana in Western Australia being notable for its evolution and adaptation to changed circumstances and global trends over several decades. The Kwinana precinct, focusing on chemical industries and mineral processing, currently generates $15Êbillion of economic activity and employs approximately 40,000 people (Development WA, 2024). It has been declared a Strategic Industrial Area, earning special provisions from the Western Australian Government (Development WA, 2024). The impacts of closing the Kwinana oil refinery in 2021 and the Alcoa Alumina refinery scheduled to shut down in late 2025 have in part been offset by incentives from government, investments in new energy infrastructure and greening initiatives by private sector industries including BP (BP Australia, 2024). Key to capturing the promise of lower cost, variable renewable energy to revitalise Kwinana are upgrades to electricity transmission and investments in energy storage that are of GW scale. As such, SynergyÕs two Big Battery projects at Kwinana have attracted global attention (Synergy, 2024).
To accelerate successful CCUS hub developments in Australia, there are overseas examples where industry, backed by international capital markets, has driven the decision making and where financial support from the government is in the form of genuine investments that can expect future returns (see the Task 4 report; Stalker et al. (2024)). The Rotterdam Harbour and Industry Complex in the Netherlands is a well-established example. In addition to major investments in energy supply infrastructure and expanded transport connections, sector coupling is achieved by steam generation and waste heat being used Ôacross the fenceÕ between companies and the local community. Cogeneration supplies industry partners with power and process heat, and waste heat is used to support a fish farming industry and for residential heating in winter. The Port of Rotterdam is now at the centre of new activity around a CCS hub, Porthos, set up by GasUni and EBN, the national energy agency and backed by multinationals such as Shell and Air Liquide (The CCUS Hub, 2024). (See the detailed discussion in the Task 4 report; Stalker et al. (2024)) The CCUS hub has broadened to encompass hard-to-abate industries nearby (chemicals, manufacturing, steel and cement) and imported CO2 from around north-west Europe, involving the CO2Next and Aramis in partnerships.


The role of education, research and development
In additional to infrastructure and regulatory support from governments, research partners and education and training providers including universities, government R&D agencies, TAFEs and specialist companies can co-locate with industry to provide technical support and troubleshooting and to grow skilled employment. The research centres and training facilities can also become part of the energy ecosystem, sharing infrastructure, using waste heat and trialling new technologies before they are adopted at scale by heavy industry. 
Away from population centres, there is less opportunity to develop this classic Ôtechnology parkÕ model. Large industrial developments in rural and remote areas should aim to upskill local workers, provide apprenticeships for school leavers and grow Indigenous participation in high-value employment. In any setting, participation of the new and established workforce through information sharing and consultation can remove a hidden barrier to the success of complex projects, by giving a sense of common purpose and rewards for innovating thinking, inclusivity and a safety culture.
1.2 Sector coupling for a Northern Territory Low Emissions Hub
A full analysis of all sector coupling and industrial symbiosis opportunities across the Northern Territory or Greater Darwin is beyond the scope of this work. This report focuses on existing and future potential industries that could be located within the MASDP (Figure 1) that would comprise part of the Low Emissions Hub. A number of key industry activities and processes have been identified as examples of how efficiencies can be realised through closer integration to support synergistic growth of the hub.
The Northern Territory Department of Infrastructure Planning and Logistics has defined the possible makeup of future industries that could be situated in the MASDP in its Balanced Scenario (this scenario uses the widest range of industries that are envisaged to be established in the MASDP). The actual industrial mix that is established in the MASDP may not match the exact composition used here, but the Balanced Scenario offers a way to align with other modelling and design activities that the Northern Territory Government is pursuing, and therefore this scenario has been chosen for the whole of the CCUS business case project. The industries included in this scenario are shown in Figure 2 and include the production of liquefied natural gas (LNG), hydrogen (both from steam methane reforming [SMR] and electrolysis based), methanol, ammonia (one based on hydrogen from SMR, and another on that from electrolysis), urea, ethylene, CCUS and critical minerals processing (e.g. lithium, vanadium).


Figure 1: A map of the Middle Arm Sustainable Development Precinct 
Source: NTG (2024)

Figure 2: The Balanced Scenario showing the wide range of potential industries that could be located in the MASDP, and their input needs, outputs and output uses
Source: NTG (2024) 
Technologies considered within this report were selected for how they could be implemented into industrial chemical synthesis routes and include the production of ammonia, urea and methanol (and derivatives) (Figure 3). Synthesis routes were considered as an integrated system (i.e. not separate processes) and process technologies were considered for both their utility for sector coupling in the near term and also their adaptability for changing feedstock and sector coupling benefits over the long term. In considering technologies a sequential approach was used to first screen and then identify technologies for further investigation.

Figure 3: Highly simplified block diagram of synthesis routes for ammonia, urea and methanol using methane reforming

1.3 Sector coupling examples chosen for analysis
As a result of the screening and identification of process technologies in the block models, the technologies considered and discussed in detail in this report are as follows:
* Hydrogen: This is a key chemical feedstock and a zero-emissions fuel, hence the unprecedented investments worldwide in a future Ôhydrogen economyÕ. Two main branches are examined:
o methane reforming combined with CCS
o electrolytic water splitting to produce hydrogen from renewably sourced electricity, as an example of sector coupling.
* Cryogenic air separation: This could be used to produce industrial oxygen and liquid nitrogen, as well higher value trace gases. Sector coupling opportunities arise using LAES. Since it uses common components and processes to the chemical industry and is an extension to air separation, LAES could be a natural drop-in to smooth the supply and demand of renewable energy and intensive industrial processes requiring power, heat and active cooling.
* Ammonia and urea: These are key components of fertiliser production and are also used for explosives. Ammonia has potential as an exportable, low-emissions fuel, to partly abate fossil fuel stationary power generation when blended, and as a substitute for diesel, particularly in marine applications where both CO2 and sulfur oxide emissions are avoided. 
* Methanol: This is among the simplest derivative molecules used as a fuel and a versatile chemical feedstock for aldehydes, formic acid and plastics, and is a staple of the petrochemical industry. It can be produced by a range of established and novel synthesis processes and has high potential for industrial symbiosis. Methanol can directly substitute for fuels in internal combustion engines, is the base molecule for sustainable aviation fuel (SAF) and has applications in fuel cells, so that it can play a role in power to X (using power to create something else) and energy-transport sector coupling.
* DAC of carbon: Zero-emission products require a negative-emissions source of CO2, ideally captured from the atmosphere rather than from a stream of fossil-based CO2. DAC requires a large amount of heat energy and a smaller amount of electrical power for fans and pumps, and therefore is a key consideration of power to X and heat to X sector (where power is used to generate a product directly) coupling processes that aim towards net zero or negative-emissions products.
* Mineral processing of critical energy metals: Refining of spodumene (a refractory silicate ore of lithium, which requires large amounts of energy for its processing) is investigated as a final case example for potential sector coupling opportunities.
The technologies described in the following sections have only been reviewed at a high level. Further detailed process modelling is required to gain a deeper understanding of the viability of their implementation.


2 Hydrogen production 
2.1 Introduction to hydrogen production 
A range of synthesis methods have been developed where hydrogen is the primary product (EIA, 2023) or a by-product of other industrial process. Crucially, the main synthesis pathway to produce hydrogen at industrial scale today (methane reforming of various types) consumes natural gas and produces CO2. Decarbonisation of methane-derived hydrogen therefore requires that the stream of CO2 is captured and stored, or that the CO2 is used in further chemical synthesis. 
Hydrogen from electrolytic water splitting only produces oxygen as a by-product but requires very large amounts of electricity. For the product to be termed green hydrogen, the electricity must come from renewable sources. Electrolytic hydrogen production is a straightforward example of sector coupling known as power to hydrogen. Most other low-emissions pathways to produce hydrogen are not capable of being scaled to produce large quantities, but they may still play a role in closing energy cycles, product cycles or, in the case of biosynthesis, nutrient cycles, in a symbiotic industrial system. 
Globally 95 million tonnes (Mt) hydrogen were produced in 2022 (IEA, 2023b), of which 79.6 Mt were produced from fossil fuels without carbon capture and storage, 14.8 Mt were the by-products of other processes, 0.5 Mt were derived from natural gas and coal using CCS and 0.1 Mt was generated through electrolysis (IEA, 2023b). Thus, only a tiny fraction of the hydrogen produced today has low emissions. Here in Australia, different synthesis pathways for hydrogen production and their prospects for decarbonisation through sector coupling and/or industrial symbiosis, provide opportunity to save energy and use waste streams to generate new products, assuming some technical innovations are adopted. (Further discussion of hydrogen and derivative demand is included in the Task 3 report (Joodi et al., 2024)).
2.2 Thermochemical methods of hydrogen production from methane
Currently, global production of hydrogen is dominated by thermochemical methods, operating at high temperatures and pressures, and based on coal and natural gas. Natural gas from onshore and offshore is in scope for use in the Northern Territory today, and in the future could be supplemented by biogas (i.e. methane derived from organic matter). In this section SMR, ATR and methane pyrolysis (thermal decomposition) are reviewed. Partial oxidation is not specifically reviewed but is included in variants of SMR and ATR.
2.2.1 Steam methane reforming
SMR of natural gas is a two-step synthesis process whereby methane and water (steam) are reacted with a catalyst at high temperature first to produce hydrogen and carbon monoxide, and then the carbon monoxide is oxidised further by steam in a second, lower temperature catalytic process to produce CO2 and additional hydrogen. SMR accounts for more than 40% of global hydrogen production (IEA, 2019). Due to its widespread deployment over many decades, the process is very well understood and has high technical maturity (technology readiness level [TRL] = 9). However, there is continued research to find improvements, such as the development of new catalysts used in the process, which can lower the operating temperature and pressure, improve conversion rates, minimise coke formation and optimise yield (Ighalo and Amama, 2024).
Inputs and outputs
The inputs to SMR are water and natural gas together with high-grade heat. Methane is consumed inside the reactor and more gas is combusted to generate the heat to drive the process, but this methane stream is not involved in the reaction. The by-product of SMR is CO2 (resulting from the purification step to increase hydrogen production). The waste stream also includes nitrogen and sulfur compounds. Some carbonaceous material termed coke is also deposited on the catalyst surfaces: the coke can build up over time and affect the efficiency and economics of the process.
Process
The major steps within SMR are listed below and shown in Figure 4:
* Steam and natural gas, free of impurities, are mixed and heated. 
* Reactions in the reformers occur between 500¡C and 1,200¡C and 30 bar (Barbera et al., 2022). Reactions take place in the presence of a nickel-based reactor (Oni et al., 2022). The steam methane reformation reaction is:
      CH4 + H2O --> CO + 3H2
Steam reforming of methane over supported nickel catalysts is performed with steam-to-carbon molar ratio in the range of 2?5, to preserve a stable catalyst activity (Nawfal et al., 2015).
* Hydrogen yield is increased by water?gas shift (WGS) reactors. The WGS at high temperature (WGS-HT) takes place between 380¡C and 460¡C and is followed by WGS at low temperature (WGS-LT) occurring between 210¡C and 270¡C (Barbera et al., 2022). The WGS-HT and WGS-LT reactors are arranged in series with Fe2O3-Cr2O3 and CuO/ZnO/Al2O3 catalysts, respectively (Oni et al., 2022). The WGS reaction is:
      CO + H2O --> CO2 + H2
* The hydrogen is purified in a pressure-swing adsorption (PSA) unit (Barbera et al., 2022; Oni et al., 2022).
An alternative reforming approach is to use CO2 and methane in a reactor at 975oC over a nickel catalyst to create both carbon monoxide and hydrogen (Halmann, 1993), both of which can be used in other chemical processes: 
      CH4 + CO2 --> 2CO + 2H2
While this Ôdry reformingÕ has the potential to reduce water use and consume CO2, back reactions (where water is produced) reduce efficiencies and further technology development is required to increase its TRL. 
Natural gas in SMR is both a fuel and a feedstock (together with water). Typically, 30Ð40% of the methane is combusted to fuel the process, giving rise to a low-concentration CO2 stream, while the rest of it is split by the process into hydrogen and a concentrated process CO2 stream.


Figure 4: Block flow diagram of steam-methane reforming

Overall, SMR can achieve energy efficiency of 74?85% ( (US DoE, 2024b)) and SMR plant capacities are reported to range from 130,000 to 300,000 tonnes of hydrogen per year (Oni et al., 2022). SMR is the most widespread technology for hydrogen production from natural gas at large scale and the International Energy Agency (IEA, 2019) has reported that SMR is likely to remain the dominant technology for large-scale hydrogen production in the near term because of its favourable economics and the large number of SMR units in operation today.
Benefits and limitations 
The benefits of SMR when compared with other methods are:
* high selectivity to hydrogen in syngas product ? higher hydrogen/carbon monoxide ratio for hydrogen production than ATR or partial oxidation
* less clean-up required than pyrolysis options
* CO2 reforming ? makes use of CO2 as a reagent.
The limitations are:
* high CO2 emissions (requires CCS or further downstream synthesis)
* in the case of steam reforming, high water usage per kilogram of hydrogen producedÊ
* in the case of CO2 reforming, greater energy demand and lower quantities of hydrogen produced per unit of natural gas.

2.2.2 Autothermal reforming of methane 
ATR is a combination of SMR and combustion of the fuel (methane), where steam is added to the oxidation process. The heat from the oxidation step within the reaction vessel itself supplies the energy required for the steam reforming process, so heat external to the reactor is removed or reduced. ATR has previously been considered as less cost-effective than traditional SMR in producing hydrogen directly from methane at large scale owing to its greater complexity, but modern designs may reverse this trend (see discussion below). 
Inputs and outputs
The inputs to classical ATR are natural gas, oxygen, steam and heat. The requirement for oxygen to attain high enough temperatures for the complete autothermal hydrogen synthesis means that an air separation unit is required. As with SMR, CO2 may be used as an input to increase the yield of carbon monoxide. The main by-product is again CO2, plus a stream of nitrogen and other separated gases, such as argon.
Process
ATR is generally operated between temperatures of 950¡C and 1,050¡C, a pressure of 30Ð50 bar, a steam-to-carbon molar ratio of 0.5Ð1.5 and an oxygen-to-carbon molar ratio of 0.6Ð1.0 and with a nickel-based catalyst (Lamb et al., 2020). The ATR reaction of methane can be summarised (Jordan, 2022) as:
      2CH4 + 2H2O + O2 --> 2CO2 + 6H2 
ATR is the preferred reforming technology on a small to medium scale, where air may be used instead of oxygen. This reduces the system complexity ? (Jordan, 2022)?. According ? (Oni et al., 2022), the reactions considered in the autothermal reactor are partial combustion of methane, steam reforming, reverse WGS, methane cracking, reverse Boudouard reaction and combustion of carbon: 
      CH4 + 0.5O2 ? CO + 2H2		(partial combustion of methane)
      CH4 + 2H2O ? CO2 + 4H2		(steam reforming)
      CO2 + H2 ? CO + H2O			(reverse WGS)Ê
      CH4 ? C + 2H2				(methane cracking)Ê
      C + CO2? 2CO				(reverse Boudouard reaction)Ê
      C + O2? CO2				(carbon combustion)Ê
The block flow diagram in Figure 5 shows a representation of the ATR process combined with carbon capture. The process begins with an ASU to supply the oxygen for the partial oxidation reaction in the autothermal reactor. The partial oxidation reaction provides heat for the endothermal reforming reaction. However, external energy is required to provide the required operating temperatures. Natural gas is combusted to heat the natural gas and steam reactant feedstocks in the reactor. The product of ATR is syngas containing hydrogen, CO2, steam and some trace gases (Oni et al., 2022). Subsequent WGS reactors increase overall hydrogen yield. 


Figure 5: Block flow diagram of autothermal reforming with carbon capture
The WGS operates at lower temperatures than the ATR so heat is rejected from the process stream entering the WGS reactors. To enable carbon capture, after the WGS the process steam is used in a syngas purification unit (amine unit) to separate CO2 from the process steam. The CO2-depleted stream is further purified in a PSA unit to produce high-purity hydrogen. In PSA, 90% of the hydrogen is assumed to be recovered at a purity of 99.9%, while the remaining gases (fuel gases) are used as fuel in the boiler/furnace. For the case without CCS, the effluents from the WGS reactors are sent directly to the PSA unit after cooling and water separation. The CO2 produced is released directly into the atmosphere (Oni et al., 2022).
Benefits and limitations 
The benefits of ATR are:
Ð high selectivity to syngas
Ð flexible hydrogen/carbon monoxide ratio for syngas production, for subsequent production of synthetic fuels
Ð less clean-up required than pyrolysis options
Ð can use CO2 as a reagent
Ð lower process temperature than partial oxidation
Ð heat from fuel combustion is used to supplement the SMR component ? lower parasitic heat load as a result
Ð the SMR and combustion components are integrated into a single unit
Ð low carbon/soot formation, which minimises pressure drop and reduces operating expenses
Ð compact design and small footprint relative to other fossil fuel conversion methods (although can be scaled up with modern reactor fabrication methods)
Ð rapid startup time.
Its limitations include: 
Ð extensive control system required 
Ð requires air or oxygen 
Ð requires CCUS or downstream synthesis to achieve low carbon emissions.
Discussion 
ATR is a combination of steam reforming and partial oxidation (Lamb et al., 2020), resulting in an overall reaction enthalpy close to zero (Voitic et al., 2018) that can achieve energy efficiencies of 60?75%. The partial oxidation supplies process heat for the subsequent endothermic steam reforming process. ATR has a higher hydrogen yield than partial oxidation alone and provides more flexibility in terms of process conditions, startup time and complex feedstock utilisation than steam reforming (Voitic et al., 2018). I
In oxygen-blown units, the hydrogen is often passed immediately to synthesise methanol (see section 4). In air-blown ATR (i.e. without an ASU), the most common pathway is to synthesise ammonia (see section 3) by combining hydrogen and nitrogen in the Haber?Bosch process (Oni et al., 2022).
Consulting firm ICF has compared some of the issues of ATR with SMR, and options for optimisation and scale-up of ATR for lower cost production of hydrogen (ICF, 2023). ICF provides some recommendations on how to achieve a lower emissions footprint and suggests that modern technology enables ATR to outperform SMR in both costs and overall emissions. ATR integrates directly into pathways to synthesise methanol and ammonia, and so provides more options than traditional SMR to lower overall carbon emissions when producing hydrogen and derivative products, particularly for ammonia, urea, methanol and other synthetic fuels. Various process steps can use recycled energy or undergo electrification to reduce overall fuel consumption, notwithstanding the fact that CO2 will always be a major by-product if hydrogen is the primary target of the synthesis.
2.2.3 SMR/ATR plus CCS
Hydrogen production from natural gas via SMR (or ATR) can be combined with CCS to produce low-emissions hydrogen. The most common technology for carbon capture from concentrated CO2 streams is chemical absorption with amines (Òamine unitÓ in Figure 7). The CO2 is then dehydrated, compressed for transport and stored permanently underground. 
In Figure 7, the amine capture unit would be inserted into the Òout gasÓ stream. Typically up to 85% of the emissions of CO2 can be abated if both the process gas and the reaction heatersÕ flue gas are captured (Oni et al., 2022). Amine units are reported to achieve CO2 streams with purities as high as 99% (Barbera et al., 2022). If it is not all destined for underground storage, the CO2 can be partly recycled in the hydrogen production processes described above, or used for other chemical synthesis. 
There are further opportunities for decarbonisation, and efficiency improvements for SMR and ATR present a pathway for emissions reduction. Waste heat from the reactors could be recycled as part of the carbon capture process. Sorption-enhanced steam methane reforming involves the use of sorbents to enhance the reactions and realise CO2 separation, and if optimised would be more efficient than current practice (Aniruddha et al., 2023). Other pollutants such as sulfur oxides, when scrubbed out of the out gas and flue gas streams, could themselves be transformed into useful products such as sulfuric acid (Figure 6).

Figure 6: Summary of inputs and outputs for reforming-based process for hydrogen production. Categories with question marks are dependent on process/technology used
2.2.4 Methane pyrolysis/natural gas decomposition (MP/NGD)
Methane will thermally decompose into hydrogen and carbon if heated to high temperature (600?1,200¡C) in the absence of oxygen, in a process termed pyrolysis (or sometimes cracking). By avoiding the oxidation reaction in the transformation of methane to hydrogen, the requirement for CO2 capture and storage can be avoided entirely, leading to a lower emissions process, even when natural gas is the feedstock. 
The net energy requirements should be similar to SMR or ATR in principle, but the primary energy input needs to exceed 1,700 kJ/mol to split the methane into ionised hydrogen and carbon atoms (i.e. a plasma state). Considerable effort has been invested in R&D to produce systems that can split methane directly, even though this requires focused energy input under controlled conditions. Importantly, the formation of a stable plasma may be hard to scale up to produce large enough quantities of hydrogen. 
Today, pyrolysis is used to produce carbon black (used in a range of industrial products, notably tyres and inks) from methane or other hydrocarbons (Kvaerner process) (Harrison, 2021), with the hydrogen considered the less valuable product, since complete pyrolysis of methane yields 3 kg of carbon for every kg of hydrogen. The TRL for industrial-scale hydrogen production from pyrolysis ranges from 6 to 9 (Chen et al., 2022; Keitz, 2021), with further development occurring on variants of the technology that have a TRL ranging from 2 to 5.
Inputs and outputs 
Methane and heat are the inputs, and the output is hydrogen gas and solid carbon. The form of the carbon, and so the value of any solid products, varies depending on the exact process and conditions.
Process
Numerous variants have been devised for a methane pyrolysis process. The detailed reaction mechanism has many intermediate products including alkanes and aromatics (S‡nchez-Bastardo et al., 2021), but the basic reaction for the overall transformation is always the same:
      CH4 ?C(s) +2H2 
Natural gas and a catalyst are supplied to a reactor. The thermal decomposition reaction is endothermic (?H = 75 kJmol-1) and without catalysis, the reaction requires a high temperature (~1,200¡C) to achieve reasonable reaction rates (Oni et al., 2022). In some variants, a plasma burner may operate at temperatures up to 1,600¡C, but in many practical systems, catalysts reduce the operating temperature to ~800¡C, thereby decreasing the metallurgical requirements of the reactors and capital costs. 
Below and in Figure 7, a high TRL simplified process is described:
1. Natural gas and a catalyst are supplied to a reactor. The catalyst helps to reduce the operating temperature of the reactor vessel to ~800¡C (Oni et al., 2022).
2. Hydrogen and unconverted natural gas and solid carbon exit the reactor. A fluidised bed reactor with an internal cyclone may be used to separate the solid carbon from the gases (Oni et al., 2022).
3. The hydrogen and unconverted natural gas are separated in a PSA unit.
4. The separated natural gas is recycled into the process.
5. The hydrogen can be compressed for storage or transport.
6. The CO2 produced from the combustion of natural gas to provide heat for the reactor is captured in an amine plant.


Figure 7: Block flow diagram of a simplified methane pyrolysis system with carbon capture

Improvements to methane pyrolysis/natural gas decomposition can be sought and there are a number of opportunities for R&D, such as:
* continued development into new catalysts 
* methods for mitigating coke formation 
* improving appliance and plant design for greater flexibility in ramping up and ramping down
* developing and demonstrating effective means of integrating CCUS to achieve zero-to-low carbon emissions
* integrating renewable energy sources (e.g. concentrated solar power can act as a thermal energy source for the process) 
* developing burner designs for optimal mixing and catalysts to cope with severe operating conditions
* developing and scaling up direct heating methods (e.g. using microwaves or radiofrequency energy).
Benefits and limitations
Benefits of methane pyrolysis include:
* no CO2 is emitted in the process, as the carbon is in solid form, not a greenhouse gas 
* the solid carbon has value as a product to generate secondary revenue streams, such as carbon black, graphene or even carbon nanotubes (see (Lott et al., 2023) for insights on the complexity of product formation), reinforcement filler in rubber products, inks, and high-performance coatings and plastics
* lower net energy requirement compared with electrolysis of water.
Limitations include:
* highly concentrated energy input required to form plasma
* catalytic methods have not yet been perfected (Raza et al., 2022)
* process may be hard to control while generating a high yield of hydrogen
* low TRL and not commercially available at scale
* in 2022 14.5 Mt of carbon black were produced (carbon black market size, growth and forecast 2035, ChemAnalyst (2023)). 
Discussion
Associated greenhouse gas emissions from methane pyrolysis plant operations are estimated to be around 1 kg/kg of hydrogen (Fromm, 2021; Timmerberg et al., 2020) and this would be less with renewably derived electricity. This makes methane pyrolysis 4?6 times less intensive for carbon emissions compared with other methane reforming methods, but plant efficiencies following optimisation and scale-up are hard to estimate so these numbers, just like the costs, have high uncertainty. Whether carbon produced by methane pyrolysis has any intrinsic value depends on what form the carbon takes, and if there are pathways to beneficiate the carbon to produce saleable products. Even if the solid carbon was turned into a high-value product, large-scale production would likely saturate current markets. 
Other molecular-level decomposition methods such as electrocatalytic or photocatalytic splitting of methane have also been researched, but these are at a low TRL and suffer from larger barriers for upscaling compared with using thermal energy. Plasma formation can be achieved with an arc furnace, and the heat to perform methane cracking could also be provided directly to the molecules by using directed radiofrequency energy or microwaves (Fromm, 2021; Harrison, 2021). These variants can be powered by renewable electricity and avoid losing heat to a large reaction vessel and containment structures. Another potential source of high-grade heat is solar thermal energy directly focused on the reaction vessel or carried via dark particles or molten salt. For these more unusual technologies, cost and scaling are poorly determined, though there is potential for methane pyrolysis to be cost-competitive in the future (Chen et al., 2022; Timmerberg et al., 2020). 
2.2.5 Comparison of thermochemical methods (SMR-ATR-MP/NGD)
Oni et al. (2022) have presented a comparison of the required inputs for various hydrogen generation methods, as listed in Table 2 and Figure 8, and the associated CO2 generation emissions, listed in Table 3 and Figure 9. The average steam to natural gas molar ratio for SMR and ATR (with and without CCS), is 5 and 1.7 respectively and reported ratios range from 3 to 6 for SMR and 1.1 to 3 for ATR (Oni et al., 2022). Natural gas consumption increases per tonne of hydrogen produced when incorporating CCS for SMR but does not impact ATR and natural gas decomposition (Oni et al., 2022). 
Table 2: Levelised inputs per tonne of hydrogen produced for various production methods (52% and 85% denote the percentage of CO2 captured) 
Source: Adapted from Oni et al. (2022)
Ê
Ê
Unabated hydrogen generation 
Abated hydrogen generationÊ
ItemÊ
Unit of measure
SMRÊ
ATRÊ
NGDÊ
SMR-52% CCSÊ
SMR-85% CCSÊ
ATR-CCS1
NGD*
Natural gas feedstockÊ
CH4 tonne/tonne H2Ê
2.26Ê
2.83Ê
3.40Ê
2.26Ê
2.26Ê
2.83Ê
3.40Ê
Natural gas fuelÊ
CH4 tonne/tonne H2Ê
1.13Ê
0.00Ê
0.57Ê
1.89Ê
2.45Ê
0.00Ê
0.57Ê
SteamÊ
H2O tonne/tonne H2Ê
13.79Ê
5.98Ê
0.00Ê
13.79Ê
13.79Ê
5.98Ê
0.00Ê
O2Ê
O2 tonne/tonne H2Ê
0.00Ê
3.78Ê
0.00Ê
0.00Ê
0.00Ê
3.78Ê
0.00Ê
ElectricityÊ
kWh/kg H2Ê
0.96Ê
2.35Ê
2.23Ê
1.32Ê
4.42Ê
3.59Ê
3.07Ê
*Noting that natural gas decomposition does not require CCS for process emissions as none are created. 1CO2 capture is embedded within the ATR process.
Table 3: Levelised CO2 emissions generated for various thermochemical hydrogen production methods 
Source: Adapted from Oni et al. (2022)
Ê
Ê
Unabated H2 GenerationÊ
Ê
Abated H2ÊGeneration
Ê
ItemÊ
Unit of measure
SMRÊ
ATRÊ
NGDÊ
SMR-52% CCSÊ
SMR-85% CCSÊ
ATR-CCSÊ
NGD-CCSÊ
CO2 (process)Ê
Tonne/tonne H2Ê
9.17Ê
8.39Ê
1.84Ê
5.52Ê
1.98Ê
0.62Ê
0.90Ê

ATR is the most efficient method in terms of levelised natural gas consumption with and without CCS, as can be seen in Figure 8. The heat generated in the autothermal reactor significantly lowers fuel consumption. The SMR-85% case consumes the most natural gas because natural gas is needed to generate low-pressure steam for the amine regenerators. If an alternative source of heat was available, such as solar thermal, it is conceivable that SMR would have the lowest natural gas consumption.

Figure 8: Levelised total methane consumption per tonne of hydrogen produced
Source: Adapted from Oni et al. (2022)

Figure 9: Levelised onsite CO2 emissions per tonne of hydrogen produced using thermochemical methods
Source: Adapted from Oni et al. (2022)

 (Oni et al., 2022) have presented illustrative comparative costs for various technologies and an estimated production cost of hydrogen for a 10% internal rate of return (IRR) as listed in Table 4 and Figure 10: Levelised cost of hydrogen converted to 2023 US$Ê
Source: Oni et al. (2022). The actual cost of thermochemical hydrogen generation is highly specific to the particular circumstance. 
Table 4: Cost breakdown of natural gas-based technologies at an illustrative plant capacity of 607 tonnes hydrogen/day (in 2023 US$) (Source: Oni et al. (2022))
Ê

SMR
ATR
NGD
SMR-52%
SMR-85%
ATR-CCS
NGD-CCS
Capital costsÊ
$MÊ
$695
$991Ê
$1,040Ê
$967Ê
$1,226
$1,397Ê
$1,240
Operating costsÊ
$M/yearÊ
$110Ê
$68Ê
$150Ê
$152Ê
$231
$83
$183Ê
Hydrogen costs @ 10% IRRÊ
$/kg H2Ê
$1.11Ê
$1.12Ê
$1.93Ê
$1.54Ê
$2.15Ê
$1.51Ê
$2.32Ê

Without CCS, the cost difference between SMR and ATR is negligible, but with CCS ATR presents a more compelling unit cost of hydrogen. For ATR, a major contributing capital and operating cost is the ASU. In a standalone ATR operation, only the oxygen is used and the remaining gases are assumed to be released. However, there is an opportunity to share use of the ASU with other industrial processes (such as ammonia production) that consume nitrogen.


Figure 10: Levelised cost of hydrogen converted to 2023 US$Ê
Source: Oni et al. (2022)
Many variables and assumptions are used to derive illustrative hydrogen costs. For example, (Barbera et al., 2022) have presented a comparison of hydrogen costs from SMR with and without CCS at US$2.65 and US$3.98, respectively. This estimate is over double what was presented by Oni et al (2022). Oni et al.Õs analysis was based on a large 607 tonnes per day plant in Canada, whereas Barbera et al.Õs was based on a small 24 tonnes per day plant in Europe. As one would expect, input costs, location and scale play a critical role in the production costs. According to (Bruce et al., 2018) thermochemical plants such as ATR and SMR should be built at scales larger than 500 tonnes per day to offset the large capital costs. They also suggest that the costs of hydrogen produced from SMR in Australia could range from A$2.27 to A$2.77 (2023 US$1.51?US$1.84), more aligned with Oni et al.Õs assessment.
2.3 Biohydrogen production
Biohydrogen offers a lower emissions route to hydrogen production, and numerous processes have been suggested. Hydrogen (and protons) is fundamental to biochemical reactions and hydrogen is often exchanged in intra- and extra-cellular processes critical to life. Hydrogen gas is typically released as a waste product of anaerobic digestion or fermentation, but is easily recombined with CO2 to form acetate and methane. Lee et al. (2010) have outlined the prospects and challenges of biological hydrogen production, while Happe and Marx (2024) provide a recent review of biological and biotechnical processes (i.e. industrialised biological synthesis integrated into scalable chemical engineering systems).
2.3.1 Use of biomethane in existing unabated or abated hydrogen plants
Using biomethane from the anaerobic decomposition of organic matter, rather than natural gas, will produce a lower emissions hydrogen end product. Sources of biogas include landfill gas, bio-digestors that dispose of agricultural or forestry waste, and bioreactors that produce organic compounds of high value (e.g. methanol, lipids) and have methane as a subsidiary product stream. Existing SMR- or ATR-based production facilities can be used in the generation of hydrogen where biomethane can be blended, and in conjunction with CCUS, this can potentially offer zero or even negative emissions hydrogen (a type of bioenergy with carbon capture and storage).
2.3.2 Direct biosynthesis of hydrogen
Certain microorganisms and microbial consortia can be harnessed to produce hydrogen directly without the use of any high-temperature/high-pressure process. In some photosynthetic algae and cyanobacteria, hydrogen is produced directly, catalysed by the hydrogenase enzyme, in a process termed biophotolysis (Teke et al., 2023). The second main pathway, which does not require exposure to light, is anaerobic fermentation of organic matter (Kothari et al., 2017). While these two methods can be isolated at the laboratory scale, most biohydrogen is less likely to be the main product of biosynthesis and would more typically be a by-product or breakdown compound from food processing, waste disposal, animal feed or fertiliser production. 
2.3.3 Discussion
Yields of hydrogen production from biological processes such as fermentation are typically low as they transform only certain compounds such as starches and sugars, whereas cellulosic and refractory organic matter must be broken down first with a series of pre-processing steps (Ahmed et al., 2021; Dzulkarnain et al., 2022). TRLs for most proposed biohydrogen processes are also low, typically 2?4. Costs and lifecycle emissions need to be properly analysed, and the barriers to scale-up need to be addressed before a profitable industry can develop (Teke et al., 2023). 
The likely scale of biohydrogen production would therefore be limited to hundreds or thousands of tonnes per year, unless there was a very large supply of waste organic matter available. This seems unlikely in the Northern Territory unless existing timber crops were used for the production of biomethane. A more foreseeable scenario would be supplementing natural gas with ancillary streams of biogas to capture by-products from biofuel production and intercept fugitive methane emissions from waste streams or landfill.
2.4 Electrolytic hydrogen production
Water can be split into its constituentsÑhydrogen and oxygenÑelectrolytically by the passage of DC electric current. Since water is tightly held together by covalent bonds, the energy requirement is high, but it can come directly from renewable sources of electricity and so there is significant interest in Australia addressing the question of whether it can become a renewable energy and hydrogen ÔsuperpowerÕ. 
Electrolysis can occur in several forms, which are briefly reviewed here. Electrolysis is a mature technology that is commercially available at a scale of 1?2 MW units, which can be joined together to make larger systems. However, there are still barriers to electrolysis-derived hydrogen becoming competitive with methane-derived hydrogen on a cost basis, despite the latterÕs overhead CCS costs. The many technology variants in electrolysers offer scope for innovation but can only take cost savings so far. The operating conditions of proton exchange membrane (Figure 11), alkaline electrolyser and solid oxide electrode systems vary from near ambient to high pressure and high temperature, and therefore they offer different opportunities for efficient sector coupling in power to hydrogen and industrial symbiosis through recycling of waste heat and co-located power to X synthesis. 

Figure 11: Schematic of an electrolyser cell of proton exchange membrane type with a selectively permeable membrane for hydrogen ions separating the two half-cells 
Source: US DoE (2024a)

2.4.1 Inputs and outputs 
The only inputs are water-based electrolyte (water and some dissolved ionic compounds to increase electrical conductivity) and the electric current. The outputs are hydrogen at the cathode and oxygen at the anode. In some variants, the heat supplied reduces the amount of electrical energy required.
2.4.2 Process
In acidic conditions, the cathodic reaction has a reference value of zero volts, while the anode reaction has a positive potential of 1.23 V: 
      Cathode 	4H+ + 4e- = 2H2			Ec? = 0.0 V		
      Anode		2H2O = 4H+ + O2 + 4e- 	Ea? = 1.23 V 
In actual operation, the current supplied to the electrolyser has to overcome resistance at the electrodes in series with the potential through the electrolyte due to processes such as gas bubble formation, meaning that some energy is wasted supplying a so-called overvoltage to the cell. The most efficient electrolyser designs reduce overvoltage to a minimum by, for example, flowing the gas bubbles away from the electrodes as soon as they are generated.
Proton exchange membrane electrolysis operates at a low temperature of 20?80oC, and at low pressure. Currently these electrolysers require noble metals Pt/Pd at the cathode and IrO2/RuO2 at the anode to act as electrocatalysts. This makes them expensive and means that water has to be deionised before acidification to avoid poisoning the surfaces within the cell.
Modifying the pH to an alkaline, the solution shifts the cathodic reaction to negative values and produces hydroxide ions, where the hydroxide is consumed at the anode, but the net potential between the electrodes in open circuit conditions is still 1.23 V at room temperature. As temperature increases, the voltage needed to split water decreases somewhat. Alkaline electrolysers using potassium hydroxide (KOH) solution do not require expensive electrocatalyst metals and operate effectively in the temperature range 80?160oC (most modern designs <100oC) and at a pressure of 3?30 bars.
Solid oxide electrolysis operates at high pressure and at significantly elevated temperature of 500?850oC, meaning that water is provided in the form of steam. Expensive electrocatalysts are not required but specialised metal oxide ceramics are needed. Older forms of solid oxide electrode technology used zirconia-based oxygen ion conducting ceramics, whereas new designs incorporate proton-conducting ceramics that operate at lower temperatures. Solid oxide electrolysis can achieve high efficiency and needs less electrical energy than either proton exchange membrane or alkaline electrolysers, but cell lifetimes can be short owing to the harsh conditions. 
2.4.3 Benefits and limitations 
Benefits of electrolytic hydrogen generation include: 
* electrolysis is a direct sector coupling pathway of renewable electrical energy to fuel and chemical product; it uses low-voltage, high-current DC power directly supplied by photovoltaics and batteries
* electrolysis can achieve high-process efficiency; the most advanced electrolytic cells can split water with 95% efficiency, while commercially available systems can operate at 75?80% efficiency
* proton exchange membrane systems operate at low temperatures and pressures
* some higher temperature electrolysis systems can use thermal energy supplied by industrial processes to avoid wastage.
Limitations include:
* electrolysis is hard to scale up to produce tonnes or millions of tonnes of product, since many individual cells need to operate in parallel ? capital cost is therefore high
* basic thermodynamics dictates that water splitting takes more energy than splitting methane; as this comes from electricity, the amount of electrical power needed is very large (power is the main cost element) ? therefore, unless that power is extremely cheap, reforming methods are more economical since the capital costs are lower and operating costs are much lower
* proton exchange membrane systems typically use expensive noble metals and/or rare earth metals as electrocatalysts.
2.4.4 Discussion 
Production of electrolytic hydrogen requires a prodigious amount of electrical energy. Currently, to produce 1 kg of hydrogen in a proton exchange membrane electrolyser, with process and parasitic losses takes about 50 kWh. Scaling up to 1 Mtpa of electrolyser-derived hydrogen requires about 50 TWh of electricity. This converts to 180 PJ or about 1.4 times the total energy used annually in the Northern Territory in 2022?023 (DCCEEW, 2024a). The efficiency of electrolysis is projected to increase until it reaches 43 kWh/kg hydrogen by the year 2035, according to CSIRO analysis of learning curves (DCCEEW, 2024b). The capital cost of electrolysers could decrease through innovations in the short- to medium-term. 
Technologies using alternative membrane systems to the proton exchange membrane that alleviate the need for high cost/critical metals have been proposed, including anion membrane electrolysis, but they are still at TRL 2?4. However, neither capital expenditure nor process efficiency makes a significant impact on the levelised cost of hydrogen from electrolysis. It is the unit cost of renewable power that must decline to less than $30 per MWh to produce hydrogen at $1.5?$2 per kg. To obtain sufficiently low-cost renewable power requires large new developments in solar and wind at GW scale, connected by high-capacity transmission and firmed by storage.
Cost estimate of electrolyser-based hydrogen production and need for subsidies
Lazard (2024) included hydrogen in its annual techno-economic comparison of levelised energy costs for the US marketplace. Electrolysis-derived hydrogen costs are US$4.5?6.0 per kg (A$6.54?8.72) for proton exchange membrane technology, and similar but slightly lower for alkaline electrolyser technology at US$4.3?5.4/kg (A$6.2?7.85). Subsidies in the form of tax offsets under the US Inflation Reduction Act can bring this down to US$2.4?3.0/kg (A$3.49?4.36). This cost is substantially higher than the A$2 per kg target for a viable green hydrogen industry in Australia (Menezes, 2023). 
Longden et al. (2020) estimate that electrolysis-derived hydrogen from wind-sourced renewable electricity in Australia could be produced at less than A$2.7?3.2 per kg by 2030, whereas hydrogen produced in Australia from SMR without CCS is now costing US$2.2?2.7/kg (A$3.20?3.92). Lazard (2024) does note that with a suitable subsidy (foreseeable in the US, but not in Australia), blending of up to 25% electrolysis-derived hydrogen into natural gas for peaking power plants would make firmed renewable energy more competitive, reduce peaking plant emissions and could be justified economically under some of the scenarios that it explored. 
The amount of subsidy needed in Australia, owing to cheaper renewable energy and more expensive gas, is likely to be less than in the US (or Europe), but the cost of electrolysis-derived hydrogen is unlikely to be competitive with abated methane reforming, which has a cost range of US$2.0?3.0/kg (A$2.9?4.36). However, as shown in Table 4, these costs are still 50% more than unabated methane-derived hydrogen generation. Plans for several low-emissions hydrogen ÔmegaprojectsÕ that were reliant on very large-scale renewable power and electrolyser infrastructure were scaled back during Q1?Q2 2024, most notably by Fortescue Future Industries (Verrender, 2024). Subsidies or targets are being pursued both internationally and within Australia to promote the growth of the hydrogen industry (see the Task 3 report; Joodi et al. (2024)).
Photocatalytic electrolysis, electrocatalysis and bioelectrical synthesis: emerging technologies
Variants of electrolysis of interest for renewable energy integration include photocatalytic electrolysis (or photoelectrolysis), which uses high-energy photons from the sun in parallel with renewable electricity (Jia et al., 2016; Osman et al., 2023). However, such technology has very poor scaling owing to a requirement that the electrodes are directly exposed to sunlight. Both this technology and electrolysis directly from photovoltaics can only operate in daylight hours, so the true cost of firmed, 24-hour renewable energy needs to be factored into the unit costs of electrolytically produced hydrogen.
Just as electrolysis can be used to produce hydrogen from water, microbial electrolysis cells can generate hydrogen from acetate substrates mediated by electroactive bacteria. In a microbial electrolysis cell, an external electric current supplies energy directly to the biological system, whereas in nature the electrical potential is generated by coupled redox reactions (e.g. involving iron and sulfur species in solution and/or on mineral surfaces). The topic and prospects are reviewed by (Noori et al., 2024) , while (Osman et al., 2023) compare photocatalysis, biocatalysis and electrocatalysis for the production of hydrogen and biofuels.
The key promise of bioelectrochemical synthesis of hydrogen is a reduction in the energy requirement for conventional electrolysis used to produce low-emissions hydrogen, and high efficiency because of a much lower voltage requirement (~0.118 V in an acetate microbial electrolysis cell as opposed to 1.23 V in a room-temperature proton exchange membrane cell; Noori et al., 2024). For example, for each molecule of acetate consumed in a microbial electrolysis cell, 8 electrons are generated at the anode; the reaction at the anode then produces 4 molecules of hydrogen. While production of hydrogen at large scale is not feasible with bioelectrosynthetic methods, the opportunity to produce a zero-emissions fuel (hydrogen) that is more valuable and saleable than methane from wastewater treatment makes the technology of considerable interest (Dange et al., 2021; Osman et al., 2023).

2.5 Water usage for hydrogen production
Water use required for hydrogen production and its implications has been reviewed by Arup for the Australian Hydrogen Council (DCCEEW, 2022). GHD Consulting also reviewed water impacts of the hydrogen industry more generally in 2023, building on data gathered comparing water uses for different hydrogen production methods (summarised in (Naylor et al., 2022), and it is from this that most of the data for this section are drawn.
The stoichiometric water consumption in steam methane reforming is 4.5 L water/kg hydrogen. As demineralised water is required in the steam feed, and other losses need to be accounted for, the overall amount consumed is estimated to be 15?40 L/kg hydrogen. In ATR and partial oxidation methods, the overall water consumption is similar. However, water demand increases with the inclusion of carbon capture processes, so that the range in estimated consumption increases to 18?44 L/kg hydrogen.
The practical water usage estimate from GHD is significantly higher than the theoretical usage estimated by Oni et al. (2022). Naylor et al. (2022) presented a table of water usage by hydrogen generation source for both good-quality raw water supply and for seawater, and this is shown in Table 5. 
Water electrolysis uses larger amounts of water than thermochemical methods, although coal gasification uses much more water than SMR or ATR of natural gas. Biofuel-derived hydrogen uses slightly less water than electrolysis. Electrolytic water splitting itself consumes 9?11 L demineralised water/kg hydrogen, with the other cooling and purification processes again consuming far more than the theoretical stoichiometric minima.
Table 5: Raw water demand depending on water quality and assuming evaporative cooling 
Source: Naylor et al. (2022)
Hydrogen?production pathway
Total demand (L/kg hydrogen), good-quality raw water
Total demand (L/kg hydrogen), seawater as raw water
Coal gasification without carbon capture
70
175?350
Natural gas reforming without carbon capture
15?40
38?100 and up to 200
Natural gas reforming with carbon capture
18?44
45?110 an up to 220
Biogas reforming 
20?45
50?113 and up to 225
Biomass gasification
60
150?300
Water electrolysis
60?95
150?238 and up to 475

Using desalination increases the amount of water used: this is assumed to be seawater, in which case no potable water is being displaced. Naylor et al. (2022) also note that the electrical energy consumption for desalination would be less than 0.5 kWh/kg hydrogen produced (for a reverse osmosis plant), compared with around 50 kWh/kg hydrogen for the electrolyser.
Given the very large amounts of water needed for cooling, Arup focused on this aspect in its detailed report for the DCCEEW (2022). Once-through cooling requires more water than evaporative cooling, and the latter requires more water in hotter, drier climates. This is a key reason for the ranges given for water consumption in Australia. Darwin would be at the higher end of the range, as it is hot year-round and humid for half the year. Air cooling is an alternative that could be considered in some climate zones but requires much more energy than evaporative cooling and could be impractical in hotter conditions. The Arup report also considers seawater cooling, although this is expensive, requires special plant and has high maintenance costs (DCCEEW, 2022).
2.5.1 Implications of water and energy requirements for electrolyser-based hydrogen production
Based on the numbers from GHD and Arup, a large-scale hydrogen industry producing 1 million tonnes of hydrogen per year would use 18?40 GL per year for methane reforming with carbon capture and 60?90 GL for electrolyser production, without desalination.
To put these numbers in context, the city of Darwin uses 44 GL of water per year, with the 40% consumed by residential users relating to about 600 kL per year per household (1 kL = 1 tonne; (PowerWater, 2024) . The Darwin LNG plant uses about 300 kL of treated (potable) water per day (URS, 2002), and Ichthys LNG around 2,000 kL per day (Environment and Heritage Division NRETAS, 2011) also supplied by the NT Power and Water Corporation. This totals around 0.84 GL per year, and while significant this represents less than 2,000 householdsÕ worth of demand. To supply a hydrogen industry that is one-quarter of the energy equivalent of the current LNG industry would require a doubling or tripling of the potable water supply to the Darwin area. For desalination, a very large capacity plant would be required. The large desalination plant near Kwinana in Perth has a capacity of 50 GL per year (Water Corporation, 2024). To limit water use to practical levels, hybrid cooling systems with substantial water recirculation are likely to be needed for hydrogen production at scale in the Northern Territory.
To summarise, 9?11 L deionised water/kg hydrogen plus 5?10 times that amount of cooling/process water would be needed for electrolyser-based hydrogen production using proton exchange membrane electrolysers. For methane reforming with carbon capture, 5.2 L purified water/kg hydrogen would be needed to supply the reformer (assume SMR), and around five times more cooling water is required, almost all of which is consumed in the condensation recovery cycle, assuming liquid amine capture. These numbers apply before any derivative products, or compression/export matters, are considered. 
2.6 Sector coupling opportunities
Hydrogen feeds into the production of ammonia and its derivatives, which are discussed in section 4. Waste heat can be used to drive endothermic reactions and consumption of CO2 by-products to synthesise urea.
Hydrogen and CO2 together are also the basis of methanol production, discussed in section 5. Aside from methanol, other fuels and chemical products could be synthesised, often adding more CO2 to produce products such as solvents, paints and plastics. Ultimately, the demand could swing from net emissions of CO2 to net consumption, in which case the industrial precinct could incorporate DAC to remove CO2 directly from the atmosphere. Technologies for DAC are reviewed in section 6.
Biogas (which may also contain CO2 alongside methane) provides further scope for sector coupling and industrial symbiosis. Teke et al. (2023) examined the sector coupling and process integration aspects of biohydrogen generation from a techno-economic perspective. Hydrogen can also be consumed by, and produced in, a biorefinery used to synthesise low- or negative-emissions liquid fuels or other high-value products. A biorefinery combines bioreactors with traditional chemical processes for product synthesis, conversion, enrichment and separation. As hydrogen is so eagerly consumed by microorganisms, it is a natural fuel for process intensification in biorefineries.
Hydrogen transport could involve blending with natural gas in existing pipelines or using dedicated pipelines should demand be sufficient in the future. This could enable the transport of clean energy supplies to locations outside of an immediate hub or cluster. For exportation, hydrogen could be transported via a carrier such as ammonia or methanol using existing vessels, with minor modifications to existing loading and unloading infrastructure. On the other hand, if liquid hydrogen is to be exported, it would require investment in compression and multi-step cryogenic cooling infrastructure to reach the liquefaction point of -253oC (Al Ghafri et al., 2022). Initially, this could piggyback on existing LNG infrastructure, providing pre-cooling to -160¡C, but the facility would need to be modified. 
Innovations such as ortho-para hydrogen conversion, more effective refrigerants and improved heat exchangers can reduce the cooling load required, and enable scale up to operations on the order of hundreds of tonnes per day required for future export industries (Al Ghafri et al., 2022). To achieve efficient operation, the hydrogen liquefaction plant would become part of a Ôcryo-hubÕ where shared cooling capacity to different step temperatures could be used to make each of the participating industries more efficient. These industries could include cryogenic air separation (section 3) and incorporate LAES (section 7) as a means for firm variable renewable electricity. The large amount of waste heat generated by the cryo-services hub could potentially be pooled for common use, intensified using heat pumps for specific purposes or stored alongside the liquid air.
Combined systems with heat and power can increase overall efficiency and underpin sector coupling involving power-to-X implementation (Koumparakis et al., 2025). Opportunities for waste heat utilization in DarwinÕs climate zone are more limited than in hubs operating in higher latitudes and with local communities and small businesses nearby, and therefore the focus must be on capturing higher grade heat sources and designing pooled cooling services in a way that does not impact on system fragility. Electricity costs and load factor on the proton exchange membrane will remain the most important variables to control the levelised cost of hydrogen from electrolysis.
3 Cryogenic air separation
3.1 Introduction 
A cryogenic process involves sustained temperatures below -153¡C, i.e., at temperatures when many permanent gases start to liquify, and well below the temperatures attained by normal refrigeration process. Cryogenic air separation is a mature technology using refrigeration and compression to liquefy and separate oxygen, nitrogen and the rare gases that are present in the atmosphere (Hersh and Abrardo, 1977). Cryogenic air separation units (ASUs) use a simple air separation process; however, they are mechanically complicated and require large amounts of energy to drive the chillers and compressors to reach temperatures between -170¡ and -190¡C. Cryogenic air separation plants have been constructed globally to produce oxygen at rates from 160 nm3h-1 to 140,000 nm3h-1 with purities ranging from 90% to 99.6% (Hersh and Abrardo, 1977). 
Oxygen is often the main target for an ASU, for use in petrochemical or material processing. Nitrogen is frequently considered a by-product unless used nearby for ammonia production. Only cryogenic processes can produce rare gases such as argon, neon, krypton and xenon from air. These are valuable enough to be exported internationally, but large quantities of oxygen and nitrogen have to be used locally, meaning that ASUs are installed in many industrial clusters.
Cryogenic air separation is considered in this report for two reasons. Firstly, in the Northern Territory, expansion and optimisation of air separation units already used in the LNG industry provides economies of scale and opportunities for industrial symbiosis. Secondly, the products are in-demand for co-located industries. Oxygen can be used in ATR and other chemical processes, while nitrogen is required in combination with hydrogen for ammonia and urea production (considered in section 4).
3.2 Inputs and outputs 
The input for an ASU is air, but parallel operation of LNG or captured carbon for shipping in some scenarios could also be considered. As already mentioned, the bulk products are nitrogen (78%) and oxygen (21%) in liquid form, with nearly 1% argon, CO2 and trace amounts of the more valuable trace gases neon, krypton and xenon, all of which have mainstream industrial uses and niche applications and so are easily commercialised. 
3.3 Process
A simplified block diagram of a cryogenic air separation unit is shown in Figure 12. Air enters the compression block where it is filtered to remove dust. The air is then compressed in multiple stages with a series of intercoolers. The compressed air enters a purification process to remove all impurities that would freeze during the cryogenic liquefaction process, such as water (<0.1 ppm) and CO2 (<1 ppm) (Tesch et al., 2019). This is generally achieved using either thermal swing adsorption or PSA. To liquefy air it must be cooled to -172¡C and this is achieved using expansion and complex heat exchangers. 
The liquefaction process produces liquid oxygen and liquid nitrogen at high purity. Residual gases present after the liquefaction process, such as oxygen and argon, can be processed or used, or released to the atmosphere. As well as the production of argon, neon, krypton and xenon, CO2 and water purified from the air inlet stream could also be captured for use and can represent additional feedstocks, CO2 for storage or sources of revenue.


Figure 12: General block diagram of an air separation unit
Air separation is an energy-intensive process with high capital costs. Energy and maintenance account for more than 50% of the operating costs, and the capital cost is dominated by compression and heat exchange (Young et al., 2021). The specific electricity consumption has been reported as 0.16?0.58 kWh/kg of oxygen gas (kg O2g) (Young et al., 2021), with estimates and analysis indicating that the higher range electricity consumption figure is more realistic. 
Cryogenic air separation is a fully developed process with extensive industrial history, with global industrial plant suppliers providing turnkey solutions. Cryogenic units can be sized for a wide range of applications from small remote units to large industrial units. Tesch et al. (2019) described the production ranges for ASUs (Table 6, and Young et al. (2021) presented levelised inputs and outputs for an illustrative cryogenic ASU (Table 7).
Table 6: Production range of air separation processes as described by Tesch et. al. (2019)
ComponentÊ
Capacity (Nm3/h)Ê
Separation methodÊ
NitrogenÊ
1?1,000Ê
MembraneÊ

5?5,000Ê
Pressure swing adsorptionÊ

200?400,000Ê
Cryogenic air separationÊ

100?5,000Ê
Vacuum pressure swing adsorptionÊ
OxygenÊ
1,000?150,000Ê
Cryogenic air separationÊ
ArgonÊ
2?4,000
Cryogenic air separationÊ

Table 7: Levelised inputs and outputs for ASU 
Source: Young et. al. (2021)
ÊInput/output
Unit of measurement
ValueÊ
Gaseous oxygen
t/dayÊ
2,413Ê
Gaseous nitrogen
t/t of O2gÊ
0.98Ê
Liquid oxygenÊ
t/t of O2gÊ
0.18Ê
Liquid nitrogen
t/t of O2gÊ
0.10Ê
Liquid argon
t/t of O2gÊ
0.02Ê
ColdÊ
kWh/kg of O2gÊ
0.59Ê
HeatÊ
kWh/kg of O2gÊ
0.22Ê
ElectricityÊ
kWh/kg of O2gÊ
0.58Ê

3.4 Opportunities for industrial symbiosis, sector coupling and decarbonisation
Cryogenic air separation is a significant industrial process that can be scaled up to produce, or process, hundreds of tonnes of air per day and accordingly involves the use of large amounts of electrical power and the transfer of large amounts of heat. There are clear synergies between the compression trains and chiller systems used for air separation and other processes requiring cooling. For example, when liquefying hydrogen for storage or transportation (requiring temperatures below -253C), the type of cooling used in an ASU may be used in the preliminary stages, to reach around -180C. On the other hand, if lower grade cooling is needed for refrigeration (e.g. for meat packing or transportation of goods), then Ôwaste coldÕ from ASUs could be used that would mean much of the energy requirement for conventional chillers may be reduced.
In the operation of a cryogenic ASU, CO2 is typically removed at an early stage to prevent solid CO2 clogging parts of the system downstream or causing problems. The sub-system for CO2 capture can potentially be modified to treat enriched streams of CO2 gas; for example, as part of a methane reforming based hydrogen process (a market segment being targeted by some of the major industrial participants; see (Linde, 2023) or for cement production or in steel making. It could also be used to purify CO2 to a much higher level than is typical in carbon capture processes based on liquid amines or membranes, such that captured CO2 is a higher value product for use in food or pharmaceuticals industries (e.g. for information on another proprietary process; see Air Liquide (2022).
As mentioned in section 2, liquefaction of hydrogen requires compression and chilling to -253¡C: much of the heavy lifting in the overall energetics of the process is the pre-cooling using liquid nitrogen to reach -196¡C (e.g. from the ASU).
When considering the integration of variable renewable energy into industrial processes in a major plant, cluster or precinct, there is a technology for long-duration electrical energy storage that uses liquid air directly, and this is discussed in section 7.
4 Ammonia and urea production
4.1 Ammonia production 
Ammonia is the second most highly produced chemical commodity globally (235 million tonnes in 2019). Ammonia production is energy-intensive, accounting for 1?2% of global energy consumption, and creates 3% of global carbon emissions (IEA, 2021). Ammonia is primarily used in agriculture in the production of fertilisers, but has other uses as an energy carrier for energy storage and transport, and in the production of polyamides, nitric acid nylon, and pharmaceuticals. 
Ammonia is 17.6 wt% hydrogen so it is also an indirect hydrogen storage compound that has several advantages for transportation. Ammonia has an energy density of 4.32 kWh/L, which is the same as methanol and approximately double that of liquid hydrogen. It is much easier to liquefy than hydrogen since ammonia liquefies at -33.4¡C (compared with hydrogen at -253¡C). The energy density of liquid hydrous ammonia is 15.3 MJ/L compared with 10.1 MJ/L for liquid hydrogen. Unlike hydrogen, ammonia is not typically explosive (Ghavam et al., 2021), but can have negative environmental impacts.

Figure 13: Conventional flow of the Haber-Bosch process 
Source: Mitsushima and Hacker (2018)
Ammonia is produced by the Haber-Bosch process using direct catalytic conversion of gaseous hydrogen and nitrogen in a high-pressure, high-temperature reactor. (Mitsushima and Hacker, 2018) have illustrated the conventional flow of this process, as shown in Figure 13. Hydrogen reacts with nitrogen in a PSA process. The reaction vessel usually operates at 400?650oC and 20?40 MPa to increase the speed and completeness of the transformation, which is enabled by catalysts. The most common catalysts are based on finely divided iron supported by potassium oxide (K2O), calcium oxide (CaO), silicon dioxide (SiO2) and aluminium oxide (Al2O3). The reaction is:
      3H2 + N2 ? 2NH3
The energy requirement for ammonia production via this process from natural gas feedstock is 28 GJ/t (TunΠet al., 2013).
The inventor and key developer of the eponymous Haber-Bosch process jointly received the Nobel Prize for Chemistry in 1931, so it is fair to say that the technology behind ammonia production is mature, and indeed it has not changed much. The energy requirements are unlikely to change and so the opportunities are for process integration and use of process heat that would otherwise be wasted.
4.2 Urea production
Ammonia can be further processed into urea (CH4N2O), which is an organic, nitrogenous compound containing a carbonyl group attached to two amine groups (Jeenchay and Siemanond, 2018). Annually, about 130 Mt of CO2 are used to manufacture urea, salicylic acid, cyclic carbonates and polycarbonates, among which the urea process consumes most of the CO2 industrially (Shirmohammadi et al., 2020). The majority of CO2 recovery plants integrated into urea plants have been established by Mitsubishi Heavy Industries Engineering (Shirmohammadi et al., 2020). Urea is principally a result of the reaction between ammonia and CO2 (Jeenchay and Siemanond, 2018). The main urea synthesis reactions are:
      2NH3+ CO2  ? NH4CO2NH2 
      NH4CO2NH2 ? CH4N2O + H2O 
where the first reaction is exothermic and the second is endothermic, but overall the process is exothermic (PŽrez-Fortes et al., 2014).
4.3 Alternative low-emissions ammonia synthesis pathways
Ammonia and urea synthesis are well established but energy intensive, and therefore innovations have focused on reducing energy usage and emissions via low-emissions ammonia pathways. Emissions reduction is not restricted to production of ammonia by the Haber-Bosch (HB) process, simply by using electrolyser-derived hydrogen as the feedstock. This pathway applied on its own could be considered retrogressive, because of the large amount of heat and pressure required by the Haber-Bosch process, both of which are inherent to SMR/ATR but are not generated in many common types of electrolysis. Electrolyser variants that operate at higher temperatures and discharge the hydrogen at a few tens of bar are potentially compatible with a modified HB process employing novel catalysts, and this is an active area of research (CSIRO, 2024b)
Ammonia synthesis by low-temperature plasma catalysis (Wang et al., 2019) offers one method to produce hydrogen using low-energy-intensity methods end-to-end. The plasma catalysis process can be summarised by the following reactions from (Zhang et al., 2021), where dots indicate ionised atoms with unpaired electrons and stars indicate electronically excited species: 
Gas phase:
      H2O ? ?H + ?OH ? 2?H + ?O 		
      N2 ? N2* with ?O ? N2O 			
      N2 ? N2* ? 2N with free radical hydrogen ?H ? 2NH3			
Catalyst surface:	N2 ? N2* ? N2(s)* ? 2 N(s)* with ?H ? 2NH3	
Overall:		4N2 + 3H2O as plasma ? 2NH3 + 3N2O
Plasma catalysis overcomes the very large energy requirement of splitting the nitrogen bond responsible for the high-pressure/high-temperature conditions needed in the Haber-Bosch process. It has been demonstrated at the laboratory scale but remains at a low TRL of 3?4. It is also not without barriers to adoption, which include how to handle the waste products. 
Nitrous oxide, the principal by-product of ammonia synthesis via low-temperature plasma catalysis, is (like CO2) rather unreactive and a persistent greenhouse gas. It is also a potent ozone-depleting substance if it reaches the upper atmosphere. However, unlike CO2, nitrous oxide is a strong oxidising agent that has various industrial uses: it can be used to treat waste streams and is a nitrogen donor that can be used in further chemical synthesis, including at low temperatures as well as in the kind of high-pressure/high-temperature processes that plasma technology is designed to avoid (Severin, 2015). Other pathways that have been investigated include direct photoelectrochemical conversion using plasmon-enhanced black silicon (Ali et al., 2016) using high-energy solar photons to overcome the energy barrier in a photosynthesis process.
There is at present no simple solution to overcome the heat, energy and water requirements of the Haber-Bosch process to synthesise ammonia at scale (Ghavam et al., 2021). Lifecycle emissions of ammonia and urea production therefore remain high. The techno-economics and emissions intensity of conventional Haber-Bosch synthesis and some of the low-emissions alternatives have been reviewed by Lee et al. (2022).
4.4 Opportunities for industrial symbiosis, sector coupling and decarbonisation
Australia has a prodigious demand for fertiliser, approximately 5 million tonnes per year (equating to 1 million tonnes of nitrogen). Most of this demand is met by imports: 1.6 million out of 1.9 million tonnes of urea were imported during the period 2012?17 (Fertilizer Australia, 2019). Of the domestic production of ammonia, more than half is consumed by the explosives industry, where ammonium nitrate, a key derivative, and other more specialised products are used widely in the mining industry and for civil construction. 
Given that the extractive industries are concentrated in northern Australia, there is a role for expanded low-emissions production of mining chemicals and agricultural chemicals to serve regional markets. In the Gladstone precinct, one major manufacturer, Orica, is adopting new processes to abate more than 200,000 tpa of CO2e emissions through removal and conversion of nitrous oxide waste streams. This initiative is supported by integration of a nitric acid production plant and process heat recovery unit supporting industrial symbiosis with co-located aluminium products manufacture (Orica, 2024).
Aside from sector coupling opportunities for power to hydrogen, and efficiency improvements in the nitrogen production chain using more integrated process cooling systems, abatement can also be achieved by incorporating biowaste to generate nitrogen compounds such as urea and nitric acid derived from black liquor gasification of waste wood pulp (Ribeiro Domingos et al., 2024). 
5 Methanol 
5.1 Introduction 
Methanol is a simple and versatile liquid fuel and chemical feedstock that can be derived from multiple chemical, biochemical and electrochemical processes (World Economic Forum, 2023). Worldwide production of methanol is more than 170 Mt per year, and growing rapidly, especially in the Middle East and Asia (Bruce et al., 2018; IRENA and Methanol Institute, 2021; Statista, 2024). 
Methanol can be blended with gasoline at high ratios where the high-octane rating is beneficial, and with diesel at up to 20% for use in internal combustion engines. Methanol is toxic if ingested, so requires careful handling, but as a fuel it burns in internal combustion engines without producing particulates. However, only a few types of engines can run on pure methanol without being modified, so it is typically considered as a transition fuel for decarbonisation of transport and in back-up power applications that cannot immediately be electrified. 
Methanol can also be used in critical, hard-to-abate sectors by using modified engines for marine transportation, and it is an important precursor to safe, industry-compliant synthetic aviation fuel. In the future, methanol may be used as a hydrogen carrier to overcome some of the disadvantages of liquid hydrogen or it may be used in fuel cells to generate power without the thermodynamic energy penalties of combustion engines.
As an industrial chemical, methanol is used widely, including for water denitrification, as antifreeze/hydrate inhibitor and as a low-cost polar solvent for dyes and adhesives. Methanol is the basis for formaldehyde and acetic acid production, used in plastics, paints and various types of extractive and raw materials processing, and in higher value industries such as pharmaceuticals. 
5.2 Production
Methanol can be produced via the syngas pathway or from direct carbonation (see below). Both methods require heat, and as for several other industrial processes that have been examined in this report, this heat can come from waste heat, renewable electricity or solar thermal.
5.2.1 The syngas pathway
Conventionally, methanol is produced from syngas (carbon monoxide and hydrogen) processed from natural gas by way of SMR or ATR (Schorn et al., 2021). These methanol plants have a capacity of 5 million tonnes per year and production using this route has a TRL of 9. 
Carbon monoxide and hydrogen react over a catalyst, typically at a hydrogen/carbon monoxide ratio of 1.8 ~ 2.2, to produce methanol. Today, the most widely used catalyst is a mixture of copper and zinc oxides, supported on alumina at 3.5Ð10 MPa and 200?300¡C. Conventional methanol synthesis is an exothermic carbon monoxide hydrogenation reaction described by:
      CO + 2H2 ? CH3OH
Methanol synthesis has high selectivity with minor amounts of side products (de Klerk, 2020); however, it requires a looped reactor system to produce a substantial yield of product. Bell et al. (2011) have developed a methanol synthesis flowsheet (Figure 14). The synthesis reactor incorporates a recirculator because the reaction is substantially incomplete after a single cycle. The unreacted vapours re-enter the top of the vessel while the condensed product is cooled and purified.


Figure 14: Methanol synthesis flowsheet based on a quench reactor
Source: Bell et al. (2011)
5.2.2 Direct carbonation
Methanol can also be produced from CO2 and hydrogen in a direct carbonation process, shown in Figure 15 from Schorn et al. (2021). Carbon Recycling International has a plant converting CO2 and hydrogen to methanol at a demonstration scale of 4,000 tonnes per year (Schorn et al., 2021). The CO2 and hydrogen enter the system at 30 bar and 25¡C then a reactor operating at 80 bar and 230?250¡C, and water and methanol are discharged at atmospheric pressure and approximately 60¡C. Schorn et al. (2021) acknowledge that their modelling approach is optimistic, as perfect equilibrium cannot be achieved in real reactors, but for developing estimates of a mass and energy balance it will suffice. The resulting mass and energy balance from (Schorn et al., 2021) is shown in Table 8.



Figure 15: Methanol synthesis via direct CO2 hydrogenation 
Source: Schorn et al. (2021)

Table 8: Levelised inputs and outputs for the production of 1 tonne of methanol via direct CO2 hydrogenation Source: Schorn et al. (2021)
Ê
Unit of measure
ValueÊ
Hydrogen
TonneÊ
189Ê
CO2Ê
TonneÊ
1,373Ê
ElectricityÊ
MJÊ
556Ê
Water outÊ
TonneÊ
562Ê
Low-pressure steam outÊ
TonneÊ
1,665 @ 175¡CÊ
High-pressure steam outÊ
TonneÊ
93 @ 125¡CÊ

5.3 Potential for lower emissions methanol via biosynthetic and electrochemical pathways
To reduce the emissions intensity of using natural gas, methanol can be produced from biomethane-derived syngas and the CO2 used in a direct hydrogenation process can come from direct air capture to potentially produce a negative-emissions fuel. Yahyazadeh et al. (2024) have reviewed the potential for the sustainable production of methanol as a biofuel and for low-emissions chemical synthesis. Numerous feedstocks are suitable for generating methane, CO2 precursors or methanol directly by fermentation. With more complex feedstocks, a series of secondary products are produced alongside methanol and there are opportunities for using waste heat to speed the bioreactors.
Power to X has also been investigated as a future means to synthesise methanol using renewable electricity and not only to supply electrolysis-derived hydrogen to the process. Two main methods have been considered. In the first, co-electrolysis of CO2 and water inside a solid oxide fuel cell at elevated temperature produces syngas (Zhang et al., 2017): 
      Cathode:		?"CO" ?_2+"H" _2 "O"+4"e" ^-?"CO"+"H" _2+2"O" ^(2-)
      Anode:			2"O" ^(2-)?"O" _2+4"e" ^-
      Overall:		?"CO" ?_2+"H" _2 "O"?"CO"+"H" _2+"O" _2
The syngas is then used to produce methanol in a conventional thermochemical hydrogenation step. 
In the second, methanol is also produced by the direct reduction of CO2 in an electrochemical process, using a metallic catalyst, particularly copper (Ruiz Mart’nez and S‡nchez Herv‡s, 2020) with a cell voltage of around 1.3 V. The reactions can be written as:
      Cathode:		?"CO" ?_2+6"H" ^++6"e" ^-??"CH" ?_3 "OH"+"H" _2 "O" 
      Anode:			2"H" _2 "O"?"O" _2+4"H" ^++4"e" ^-
      Overall:		?"CO" ?_2+2"H" _2 "O"+6"e" ^-??"CH" ?_3 "OH"+?"1.5O" ?_2	
Li et al. (2022) have compared the techno-economics and lifecycle emissions of conventional hydrogenation of CO2 with electrolysis-derived hydrogen, electrochemical reduction and co-electrolysis. While research in the area is very active, as this is one of the key utilisation steps for CO2, Faraday efficiency and selectivity are too low for direct electrocatalytic conversion to be commercial and at present the TRL is 2?3. With future improvements, co-electrolysis may be competitive in terms of emissions and energy consumption if waste heat can be used, but again the development of an efficient conversion fuel cell is at a low TRL. This leaves a combination of electrolysis-derived hydrogen with thermochemical reduction and biosynthesis consuming waste organic matter and waste heat as two promising avenues for lower emissions methanol synthesis in the near future. 
5.4 Discussion
Methanol certainly has a role to play in the energy transition as a low-emissions transport fuel, a precursor to sustainable aviation fuels, and in low-, zero- or even negative-emissions products. It is a key chemical for sector coupling through power to X pathways, and also X to power, through its use in fuel cells. Methanol fuel cells based on proton exchange membrane type construction could potentially be used for transportation and stationary power generation, particularly if their efficiency can approach or exceed 50% (Methanol Institute, 2020; US DoE, 2020). Methanol has about four to five times the volumetric power density of compressed hydrogen. As for hydrogen-electric fuel cell systems, the niche applications may be for long-range and remote applications, heavy transport, passenger vehicles in urban low-emissions zones and marine transportation (Xing et al., 2021).
Being a liquid and a high-value chemical feedstock, the options for transporting and using methanol are arguably more diverse and economically attractive at a range of scales, serving local markets and potentially export industries, than for hydrogen.
6 Direct air carbon capture 
6.1 Introduction
Direct air capture (DAC) of carbon dioxide refers to technology that draws atmospheric CO2 directly from the air and concentrates it into a high-purity stream that can be stored or used. Linked directly to underground sequestration or to carbon mineralisation, DAC is a means to permanent carbon removal. DAC is also an enabling technology for low-emissions industries such as e-fuels, low-emissions methanol, ammonia, cement manufacturing and high-intensity agriculture.
CO2 is present in the lower atmosphere at a concentration of ~420 ppm, with a total mass of 3,237 Gt CO2 (Ozkan et al., 2022). This concentration is increasing at an accelerating rate, currently about 2.6 ppm/year (Rasmussen, 2024). At least 20 Gt CO2 capture and removal per year would be required by the end of the century to keep the temperature rise under 2¡C. Current global CO2 capture and removal capacity is 0.0385 Gt CO2 per year (Ozkan et al., 2022). 
Though it remains expensive (compared with emitting without capture) and requires significant energy input, the technology for capturing CO2 from concentrated (5?30% by volume) waste streams such as flue gas, cement manufacturing and natural gas processing is mature. Conventional CO2 capture from concentrated point sources of CO2 can be scaled up to hundreds of millions of tonnes per year, which can become economically viable with a carbon price of US$20?50/tonne (for the capture component only) (Ozkan et al., 2022). However, the direct capture of highly dilute CO2 in the atmosphere is a relatively new technology and DAC faces technical and economic challenges that must be addressed before it can be widely adopted at a scale sufficient to have a measurable impact on the trajectory of the global climate.
6.2 Process
There are two relatively mature categories of DAC technology: liquid direct air capture (L-DAC) and solid direct air capture (S-DAC; IEA, 2022). A third ÒemergingÓ category of lower TRL has been identified by Li and Yao (2024) (Figure 16 and Table 9). Electrochemical capture (or electro-swing adsorption ESA), moisture swing adsorption (MSA), membrane separation (m-DAC), plus cryogenic separation and mineral carbonation can all be considered emerging technologies within the DAC umbrella. KŸng et al. (2023) have compared all the main industrial methods including membrane and cryogenic separation (see also section 3), while Sharifian et al. (2021) have reviewed electrochemical capture and mineral carbonation is described by Sanna et al. (2014). Here the focus is mainly on L-DAC and S-DAC.


Figure 16: Schematic representation of the DAC process 
Source: Li and Yao (2024)

Table 9: Principles, advantages and disadvantages of different DAC technologies 
Source: Li and Yao (2024)
Technology
Principle
Common
material
Advantage
Disadvantage
L-DAC
The liquid solvent reacts with CO2Êto form carbonates for capture, and it releases CO2Êupon heating
Alkaline solutions
Large-scale operation
Continuous operation at steady state without interruption
Low-cost raw materials with good selectivity and capture capacity
High temperature requirement
High energy consumption
Requirement for corrosion-resistant equipment
S-DAC
The solid sorbent captures CO2Êfrom ambient air at room temperature and atmospheric pressure, and then releases CO2Êunder low pressure and moderate temperatures through a temperature-vacuum swing process
Amine-based sorbents
Modular and scalable operations

Lower energy consumption than L-DAC
Batch operations causing complex plant structures
Special construction required for cycling temperature and pressure conditions
High construction costs
Sorbents with low sustainability
Emerging DAC 
ESA
The electrochemical cell uses charge modulation to control the adsorption and desorption processes, capturing CO2Êwhen negatively charged and releasing it when positively charged
Electrochemical cell


Electrode materials
Space-efficient structure
Convenient operation with no additional equipment required
Low energy consumption
Effective capture capacity
Good durability
High investment costs

MSA
The moisture-sensitive sorbents rely on chemical reactions between carbonate ions and water molecules to alter energy states, facilitating CO2Êcapture in dry conditions and CO2Êrelease in wet conditions
Ion-exchange resins
Low energy consumption


Convenient integration with low-carbon energies
Consumption of a large amount of water

Sensitive to practical weather conditions

m-DAC
The membrane uses selective permeability properties to enable the separation and capture of CO2Êfrom air
Ultrathin-film composite 

Mixed-matrix 
Low energy consumption

Low carbon footprint
Low throughput

High material costs
6.2.1 Liquid DAC 
L-DAC uses a liquid absorbent ? an aqueous reactant solution such as potassium hydroxide (a strong base) in a vessel known as a contactor or an absorber ? to capture CO2 from air passing through. A series of metal vanes or a trickle-down process is used to increase the contact area between the liquid and the air stream. The CO2-charged liquid is then pumped to a second vessel called a regenerator to remove the CO2.
Alkaline liquids (potassium hydroxide solution ? or sodium hydroxide [NaOH]) work by reacting with dissolved CO2 in the contactor to produce carbonate ions. During regeneration the carbonate is reacted with lime (calcium hydroxide) to precipitate solid calcium carbonate, and the alkali is thereby regenerated. Looping of the liquid through the reactor a number of times may be required to extract all of the CO2. A pressure swing can be employed to make the process more efficient, with capture taking place at elevated pressure and reactant (or solvent) regeneration taking place at reduced pressure. 
According to IEA (2022), DAC plants can be built at a large scale using existing alkali liquid based technology and can remove in the order of 1 Mtpa CO2. Note that while simpler liquid amines, e.g., monoethanolamine (MEA), diethanolamine (DEA) and N-methyldiethanolamine (MDEA) are used widely for capturing CO2 from concentrated streams such as reservoir gas and combustion emissions, they do not work well at the low levels of CO2 found in the atmosphere, and hence, L-DAC based on traditional liquid amines is not being commercialised at the present time. Novel absorbents such as ionic liquids, quaternary ammonium compounds and amino acids (as well as more complex amine based molecules in aqueous and non-aqueous solutions,) can also be used in L-DAC, but these are much more expensive than alkali solutions or simple amines and/or have not been scaled up to date.
In the alkali process (Figure 17), the calcium carbonate produced can be treated as the end product and either disposed of or made into items such as building materials. Alternatively, the calcium carbonate can be thermally decomposed (calcined) to produce more lime (CaO), which is then recycled as calcium hydroxide solution. The calcining process requires a temperature of about 900oC and requires a large amount of thermal energy. Whether the calcining process occurs within the plant or is performed externally by the raw materials supplier has some effect on the lifecycle emissions of the DAC process, but the main factor is the fuel used in the process.
L-DAC function depends on the relative humidity of the air, with aqueous-based systems requiring additional water to compensate for evaporative loss from the solvent during regeneration. The IEA (2022) estimates that up to 4.7 tonnes of water per tonne of captured CO2 could be consumed in a L-DAC plant operating at 64% relative humidity and an ambient temperature of 20oC.



Figure 17: Schematic of a liquid DAC system. 
An alkali capture solution (KOH or NaOH) circulates through the contactor, with air driven through the contactor by fans past high surface area trickle beds. The charged capture solution is mixed with calcium oxide (lime) pellets in a reactor. The pellets are removed by gravity separation and regenerated in a high-temperature calciner operating at about 900oC. Pure CO2 is released in the calciner and the calcium oxide is returned to the pellet reactor 
Source: Wang et al. (2023)
6.2.2 Solid DAC 
S-DAC uses a solid adsorbent in the contactor in place of a liquid absorbent; the available capture capacity depends on the surface area and activity of the solid material, which typically needs to be finely divided and have a micro- or nano-porous microstructure to work effectively (Figure 18). Capture materials used in S-DAC may include solid amines (Hamdy et al., 2021), zeolites or high surface area functionalised materials such as metal organic frameworks or activated carbon.
The price of the raw materials, the lifetime use (number of cycles before degradation) and efficiency are key determinants of the economic viability of S-DAC (KŸng et al., 2023). One type of DAC, for example, uses low-cost calcium hydroxide as a solid reactant, which, being a strong base, captures CO2 directly from a moist air stream to form precipitate calcium carbonate. However, high-grade heat is required to regenerate the reagent, as in the liquid alkali process. 
The adsorption typically takes place at atmospheric pressure and temperature, while the desorption takes place in the same vessel subjected to moderately elevated temperatures (80?100oC) and vacuum (Deutz and Bardow (2021). Currently the largest S-DAC units capture a few thousand tonnes of CO2 per year, so are in orders of magnitude smaller than conventional L-DAC systems. Some systems employ moisture swing adsorption rather than a purely thermal cycle but the technology is still considered emerging.

Figure 18: S-DAC, based on a system used by Climeworks 
Source: Deutz and Bardow (2021)

S-DAC removes moisture from the air along with CO2 (in the order of 1 tonne H2O per tonne CO2) so many adsorbents therefore function more favourably in drier climates. Colder conditions can also improve CO2 uptake. Water can compete with CO2 for sites and increase the amount of energy needed for regeneration of the capture material.
The respective operating conditions and characteristics of S-DAC and L-DAC systems from the IEA report (2022) are shown in Table 10 (Bajamundi et al., 2019; IEA, 2022; Keith et al., 2018).

Table 10: Key features of S-DAC and L-DAC systems 
Source: IEA (2022)
S-DACÊ
Unit of measure
MinimumÊ
MaximumÊ
AverageÊ
Specific energy consumptionÊ
GJ/t CO2Ê
7.2Ê
9.5Ê
8.4Ê
Share as heat consumptionÊ
%Ê
0.8Ê
0.8Ê
0.8Ê
Share as electricity consumptionÊ
%Ê
0.2Ê
0.3Ê
0.2Ê
Regeneration temperatureÊ
¡CÊ
80.0Ê
100.0Ê
90.0Ê
Regeneration pressureÊ
Bar,aÊ
0.0Ê
1.0Ê
0.5Ê
Levelised cost of captureÊ
US$/t CO2Ê

up to 540Ê
?Ê
Capture efficiencyÊ
%Ê
0.3Ê
0.8Ê
0.6Ê
Average levelised electricityÊ
GJ/t CO2Ê
1.4Ê
2.4Ê
1.9Ê
Average levelised thermal energyÊ
GJ/t CO2Ê
5.4Ê
7.6Ê
6.5Ê
Average levelised waterÊ
t H2O/t CO2Ê
0.0Ê
0.0Ê
0.0Ê
Average levelised fuelÊ
GJ/TCO2Ê
0.0Ê
0.0Ê
0.0Ê
Average levelised airÊ
t air/t CO2Ê
5,050.5Ê
2,083.3Ê
3,566.9Ê
L-DACÊ
Unit of measureÊ
MinimumÊ
MaximumÊ
AverageÊ
Specific energy consumptionÊ
GJ/t CO2Ê
5.5Ê
8.8Ê
7.2Ê
Share as heat consumptionÊ
%Ê
0.8Ê
1.0Ê
0.9Ê
Share as electricity consumptionÊ
%Ê
0.0Ê
0.2Ê
0.1Ê
Regeneration temperatureÊ
¡CÊ
?Ê?
900.0Ê
900.0Ê
Regeneration pressureÊ
Bar,aÊ
?Ê?
1.0Ê
1.0Ê
Levelised cost of captureÊ
US$/t CO2Ê

up to 340Ê

Capture efficiencyÊ
%Ê
0.7Ê
0.7Ê
0.7Ê
Average levelised electricityÊ
GJ/t CO2Ê
0.0Ê
1.8Ê
0.9Ê
Average levelised thermal energyÊ
GJ/t CO2Ê
4.4Ê
8.8Ê
6.6Ê
Average levelised waterÊ
t H2O/t CO2Ê
3.2Ê
50.0Ê
26.6Ê
Average levelised fuelÊ
GJ/t CO2Ê
4.4Ê
8.8Ê
6.6Ê
Average levelised airÊ
t air/t CO2Ê
2,237.1Ê
2,487.6Ê
2,487.6Ê

6.3 Energy consumption
The energy consumption figures listed in the literature range from 5.5 to 9.5 GJ/t CO2 (~1,500?2,600 kWh/t CO2). For context, the average global electricity price for industry is ~US$100/MWh (A$145) and can range from US$20/MWh (A$29) to as high as US$216/MWh (A$314) according to the IEA global energy explorer (IEA, 2023a). For an average price of US$100/MWh (A$145) energy costs alone for capture would be greater than US$150/t CO2 (A$218). 
However, for S-DAC and L-DAC energy consumption is dominated by heat consumption (Figure 19; IEA, 2023), so there is an opportunity to lower energy costs if heat consumption can be sourced from waste heat rather than purchased as energy (either electrical or fuel). However, L-DAC technology requires higher regeneration temperatures (in the case of potassium hydroxide scrubbing, the calcining requires ~900¡C) and is less suitable for waste heat. On the other hand, S-DAC technology requires regeneration temperatures less than 100¡C, so is much more suitable for waste heat applications, thereby potentially reducing the purchased electricity requirements by as much as 80%. 
Wang et al. (2023) have investigated both the energy intensity and lifecycle emissions of DAC technologies, but pointing to the challenges of direct comparison, owing to the differences in heat sources (that can potentially be recycled or electrified), variations in climate and lack of demonstration at larger scale.



Figure 19: Energy requirements, in GJ/tonne CO2. 
In principle, L-DAC requires less energy per tonne of CO2 than S-DAC, but at a higher temperature (up to 900oC). Novel materials and processes can reduce S-DAC energy requirements considerably, whereas L-DAC is a more mature technology with less scope for improvements that reduce energy demand 
Source: (IEA, 2022)
6.4 Key companies
Globally, numerous parties are working on developing atmospheric carbon capture technologies. In this sector three companies are prominent (Li and Yao, 2024; Ozkan et al., 2022):
* Global Thermostat uses custom equipment and proprietary (dry) amine-based chemical ÔsorbentsÕ that are bonded to porous, honeycomb ceramic ÔmonolithsÕ which act together as CO2 sponges. The technology uses direct steam injection to regenerate CO2. Global Thermostat has licensed the technology from Georgia Institute of Technology and has already piloted a demonstration plant that has been operating since 2010 at SRI International in Menlo Park, California. A 2,000 tpa CO2 plant was set to be completed in 2021 in Oklahoma, but this is still not operating, with a plant being commissioned instead in Colorado. Engineering firm Black and Veatch were awarded the DOE funding to build a 100,000 tpa capacity DAC plant using Global Thermostat's technology. Global Thermostat was wholly acquired by Zero Carbon Systems in May 2024.
* Carbon Engineering is developing a capture mechanism based on aqueous potassium hydroxide coupled with a calcium caustic recovery loop. The process requires water, natural gas, electricity and a supply of calcium carbonate. The technology is likely TRL 8 with a demonstration of all components of the process in a relevant environment. Carbon Engineering has published cost estimates for its plants, with the levelised cost of production ranging from US$94 to US$232/tCO2 (A$137?232) (Keith et al., 2018). Carbon EngineeringÕs technology is designed to be deployed in 0.5 Mtpa CO2 modules (Mirza and Kearns, 2022). The company claims that it will capture 74.5% of CO2 from processed air (Keith et al., 2018).
* Climeworks uses an amine functionalised filter to capture CO2 which is then stripped using a temperature/vacuum swing. Gebald and Wurzbacher, the founders of Climeworks, developed a sorbent using nanofibrillated cellulose grafted with aminosilane to capture CO2 from air (Bajamundi et al., 2019). They have a pilot plant in Hinwil, Switzerland, which captures 900 tonnes/year and are building a 4,000 tonnes/year DAC plant in Iceland. The process is said to capture 80% of CO2 that passes through the system (Bhadola et al., 2020).
As of 2022, 19 DAC plants were in operation globally with a combined capacity of ~10,000 tpa CO2 and the largest facility capturing 4,000 tpa CO2 (Ozkan et al., 2022). Li and Yao (2024) have recently identified additional entrants in the North American and European markets.
6.5 Main challenges
Li and Yao (2024) have also discussed the recent advances and challenges for DAC. Improvements in materials and processes are highlighted for both S-DAC and L-DAC, together with a comparison of emerging DAC methods developed over the past decade. Wang et al. (2023) further point to issues with water and land use, but all analysis indicates that scale-up and energy intensity (of L-DAC, the primary technology used today) are the key issues to address. Above all, the high cost of the technology, which is capital- and energy-intensive has hindered uptake.
6.5.1 Scale-up
DAC technologies have yet to be demonstrated at an industrial scale (1 Mtpa CO2) where all relevant lifetime costs (including capital, construction, operations and finance) can be verified. There is still a large degree of uncertainty regarding the levelised lifetime cost of DAC, with estimates ranging from US$100 to US$1,000/t CO2 (A$145?1,450 ) (IEA, 2023a). DAC technologies need opportunities to demonstrate how they work at industrially relevant scales to reduce uncertainty in performance and costs and refine system designs. For DAC to be economically viable, the technologies need to achieve a lifetime levelised cost of carbon capture less than US$100/t CO2 (A$145) (Ozkan et al., 2022).
6.5.2 High operating temperature of L-DAC
While industrial carbon capture from concentrated waste streams can be achieved efficiently with amine liquids, which can be regenerated at around 100oC, typically the system does not work efficiently and cost-effectively for the very low CO2 concentrations targeted by DAC. Alkali liquids achieve very high capture efficiency, but the penalty is the very high temperature calcining process required (900oC) to regenerate the lime pellets used in the reactor. 
Using alternative compounds, such as aqueous amino acids (Abdellah et al., 2024) or ionic liquids (Figure 20) (Hospital-Benito et al., 2023) in the process may be a means to retain the efficiency of L-DAC but operate the system at lower temperatures. Different liquid?air contactor designs are also possible, including droplets and sprays, as are hybrid solid?liquid systems (CSIRO, 2023a; 2023b). In addition, direct thermal heating could potentially be used in calcining, although heat storage for nighttime/poor weather is an obvious issue.


Figure 20: Schematic of a liquid DAC system. 
The regeneration column and boiler system configuration and the temperature of operation depend on the chemistry of the system being used. Here an ionic liquid (IL), that is used to capture the CO2, is shown, which is a pre-commercial technology that enables much lower temperature of regeneration (~70?120oC) 
Source: Hospital-Benito et al. (2023)
6.6 Opportunities for sector coupling and industrial symbiosis
Capturing emissions directly from industrial sources is an obvious step to take in decarbonisation but may only achieve a partial reduction in lifecycle emissions, particularly in hard-to-abate industries. Therefore, negative-emissions technologies will need to be deployed alongside industrial hubs, the main reasons for co-location being infrastructure and workforce, and the potential to supply waste heat or steam for regeneration. With thermal energy for desorption representing 80% of energy requirements for S-DAC, waste heat could dramatically reduce the costs of DAC.
The temperature requirement, particularly for S-DAC thermal energy, is relatively low (<100¡C), lending itself to low-grade industrial waste heat. This low-grade heat is often rejected via cooling towers. DAC requires large volumes of air ranging from ~2,000 to 5,000 t air/t CO2 given the low concentrations of CO2 in the atmosphere. The energy needed to drive fans is another major cost component of DAC. There is an opportunity to leverage air flows from other industrial processes such as cooling towers. S-DAC could benefit from the waste heat while the processes supplying the waste heat may benefit from reduced cooling requirements. It is unlikely that L-DAC based on alkali looping would be amenable to using industrial waste heat because of the high temperature requirements (900¡C) of the calcining process used to generate lime.
Lower temperature liquids such as amines and amino acid solutions do not seem to have the capture efficiency required for DAC, and so have not been developed to the same degree as S-DAC or alkali liquids. In the future, emerging DAC technologies could be in scope for sector coupling; for example, electrochemical DAC could use common industrial infrastructure.
Alternatively, the coupling could be focused on the power generation side of a major hub development close to renewable infrastructure combined with electrical energy storage (e.g. batteries), as shown in Figure 21. 


Figure 21: Representation of sector coupling between energy, climate and water for DAC systems driven by renewable energy. Heat pumps, thermal energy storage (TES) and electrical energy storage (here represented by batteries) are key enablers 
Source: Breyer et al. (2020)


Breyer et al. (2020) modelled the development of large-scale DAC deployments in North Africa, a climate zone with many similarities to Northern Australia in terms of high-grade solar and wind resources. Also, in this location there is a premium on water provision and so S-DAC technologies that have a positive water balance (e.g. by using moisture swing) could be used to simultaneously remove CO2 from the atmosphere and harvest potable water from it. Key components of a renewable energy?DAC coupled system are electrical energy storage to firm variable renewable power (e.g. batteries, compressed or liquid air energy storage ? see section 7), the use of heat pumps to intensify heat and cooling used in thermal swing adsorption, and thermal energy storage to buffer the heat requirements, releasing heat as required to process vessels via heat exchangers.
7 Liquid air energy storage
7.1 Introduction
Long-duration energy storage is a critical requirement to firm renewable energy sources to provide clean power for the energy transition in Australia (ARENA, 2024; Clean Energy Council, 2024), especially in the context of the increased electrification of industries currently dependent on fossil fuels. Several candidate energy storage technologies have been reviewed in the Australian context by CSIRO (2023d), including compressed air energy storage (CAES) and liquid air energy storage (LAES). While CAES requires specific geological conditions, LAES is ideally co-located with heavy industry close to locations of power demand and with opportunities for further sector coupling.
The cryogenic air liquefaction process described in section 3 can be modified to provide energy storage in addition to the provision of oxygen and nitrogen. Compressed gas contains considerable potential energy, and as the liquefied air boils the expanding gas can be used to drive a generator. The idea of cryogenic energy storage was first proposed by EM Smith at the University of Newcastle in 1977, and tested by Mitsubishi in 1998 using liquid air as the cryogen (Damak et al., 2019). Summarising Damak et al. (2019) and Borri et al. (2021), a brief history of LAES is illustrated in Table 11.
Table 11: LAES development history 
Source: Borri et al. (2021); Damak et al. (2019); (Highview Power, 2024))
PartyÊ
YearÊ
MilestoneÊ
Smith et al.Ê
1977Ê
Proposed the concept of LAES
Mitsubishi/HitachiÊ
1998?2000Ê
Chino and Araki from Mitsubishi developed a 2.6 MW power recovery unit
Chen et al.Ê
2007Ê
Patented the LAES concept based on a Linde-Hampson air liquefier and direct expansion process for power recovery
University of Leeds and Highview PowerÊ
2011Ê
First complete pilot plant demonstration: 350 kW/2,500 kWh
Highview PowerÊ
2018Ê
First complete grid scale demonstration: 5,000 kW/15,000 kWh
Highview PowerÊ
2026Ê
Operation of grid-scale CRYOBattery in Carrington UK: 50,000 kW/300,000 kWh (under construction Oct 2024; plans for 2x 2.5GWh expansion by 2030*)
The energy stored in a cryogen is different from other thermal energy storage as it is obtained from decreasing its internal energy and increasing its exergy. So, exergy analysis is better at quantifying the potential of stored cryogen than energy analysis (Damak et al., 2019). The exergy of a stream, E, and the exergy efficiency, Eeff, of a process are defined, respectively, as (O'Callaghan and Donnellan, 2021):
E=Êm [(h?h0)?T0(s?s0)]

Eeff =Eout/Ein

where m is the mass of liquid air and h and h0 are the enthalpy of the stream and the reference enthalpy. Similarly, s and s0 are the entropy of the stream and the reference entropy.ÊT0 is the reference temperature. 

Figure 22 shows the basic processes involved in an LAES system:
* Liquefaction: Electricity drives an air compression system and liquefaction system to liquefy air.
* Storage: The liquefied air is stored in insulated tanks at -195¡C while the thermal energy streams generated from the various processes (both cold and hot) is stored in hot and cold storage systems. Storing and using these thermal energy streams increases overall system efficiency.
* Power generation: When electricity is required, the liquefied air is released from the storage tanks and allowed to heat and expand through a power generation system generally consisting of a turbine/generator set.
There are numerous variants for these processes, each with advantages and disadvantages.

Figure 22: Generalised block flow diagram of LAES 
Source: Based on a diagram presented by Brett and Barnett (2014)
Round trip efficiency (RTE) is the ratio of the energy consumed to produce liquid air to the energy generated during the expansion of the stored liquid air. In the literature a range of RTEs are presented, suggesting that there is a level of uncertainty in both the theoretical and demonstrated calculations. OÕCallaghan and Donnellan (2021) suggest that theoretically LAES RTE is ~70%, whereas Damak et al. (2019) suggest that with effective heat management >80% RTE can be achieved. 
To add to the uncertainty, Borri et al. (2021) have presented RTE ranges from several LAES studies with 49?62% for Linde-Hampson based systems and 50% for Claude-based systems (Borri et al., 2021). These numbers appear to be contradictory to the literature, as the Claude cycle is supposed to be a marked improvement over the Linde-Hampson. Furthering the uncertainty around RTE, the only complete demonstration of LAES to date, undertaken by Highview Power, achieved 8% RTE compared with the theoretical 49% (Damak et al., 2019) based on an improved Claude cycle. This was reportedly due to the small size of the plant and the poor quality of the cold recycle (Borri et al., 2021). 
She et al. (2019) presented results showing LAES RTE ranging from 45.1% to 53.7% depending on air charging pressure, showing that higher RTE is achieved at higher charge pressure. According to Sciacovelli et al. (2016), at commercial scale, LAES is expected to achieve an RTE of around 70%, rated power above 10 MW and rated capacity of the order of 100Õs of MWh. Note that the pilot plant at the University of Birmingham Ð a 350 kW/2.5M Wh storage installation Ð performed with a round trip efficiency <25% due to suboptimal charging/discharging pressure and because of the design of the liquefier. 
Figure 23 shows several published RTE rates versus charge pressure, which indicate that charge pressure has little impact on RTE (Borri et al., 2021; Kim and Chang, 2019; Krawczyk et al., 2018; She et al., 2019; Tafone et al., 2019). Most of the points mapped are for a Linde-Hampson liquefaction cycle and the highest efficiency point is for a Kapitza liquefaction cycle.


Figure 23: Plot of published LAES RTE rates versus charge pressure
Work by Tafone et al. (2019) has also suggested that charge pressure is less important than how the cycle is configured to maximise cold thermal energy storage. Tafone et al. (2019) presented parametric performance maps of LAES illustrating how critical it is to ensure high utilisation of cold energy storage (Tafone et al., 2019). The maps show that RTE can vary considerably depending on how well a system uses thermal energy storage, with RTE rates varying by a factor >2. It has been shown that using a cryoturbine instead of a throttling device in a conventional setup considerably improves the efficiency of the liquefaction unit. For example, in particular conditions, Li (2011) obtained an optimal RTE of 48% using a throttling valve, and this increased to about 82% using a cryoturbine (Damak et al., 2019; Li, 2011).


7.2 Benefits and limitations of LAES
The benefits of LAES are:
* geographically unconstrained
* indicative low levelised lifetime cost
* fast response time
* capable of providing ancillary services
* opportunities for integration into industrial processes such as LNG or hydrogen
* capable of long-duration storage and discharge
* relatively fast discharge response times (~1 min for discharge; Brett and Barnett, (2014)).
Its limitations include:
* complicated control systems
* need for specialised cryogenic equipment (i.e. heat exchangers, turbomachinery and storage tanks)
* to date, recommended cold thermal storage media are flammable, presenting health and safety considerations
* relatively slow charge response times (20?120 min for charging; (Brett and Barnett, 2014).
7.3 Sector coupling opportunities for LAES
The most obvious sector coupling opportunities that LAES can enable are variable renewable energy firming by the storage process and exploitation of higher value products from the gas separation sub-process. Various cases have been discussed in the literature, a recent example being the combination of air separation, argon concentration and waste heat recycling into LAES proposed by Liu et al. (2024). According to their analysis, the system payback time could be as short as 6 years, with much of the uplift derived from an efficient waste heat recovery system.
In the context of the Northern Territory Low Emissions Hub, any significant move into electrolyser-derived hydrogen production or electricity generation for export would require firming of variable renewable energy using long-duration energy storage. 
There are LAES and CAES projects in development or under investigation in Australia, involving international players Highview Power (UK) and Hydrostor (Canada) (Macdonald-Smith, 2024).

8 Spodumene refining for lithium
8.1 Introduction
Global lithium production is sourced from two primary resources: lithium-bearing brines and mineral ores. Brines comprise ~60% of production and mineral ore the remainder (Siekierka et al., 2022). Although the silicate ores spodumene, petalite, lepidolite, amblygonite, zinnwaldite and eucryptite offer theoretical lithium content between 3% and 5.53%, the achieved concentrations rarely exceed 2% (Siekierka et al., 2022) ? see Table 12. 
Spodumene has historically been the main ore of interest to produce lithium from minerals. It is a lithium aluminium silicate of the pyroxene group and is found in close association with quartz, feldspar and micas (Fosu et al., 2020). Spodumene is naturally present in a highly packed crystal structure and has the hardness of quartz, with high grindability and the mineral is difficult to leach without pre-treatment (Fosu et al., 2020).
The past decade has seen a fivefold increase in global demand for lithium from around 160 kt to around 800 kt annually, driven by the growth of electric vehicles and renewable energy storage. This has led to a significant increase in investment and development of spodumene resources in Australia, which is known to have significant reserves of the mineral. The spodumene is used as a primary source for lithium production along with smaller amounts of lepidolite (a variety of mica). These mineral deposits typically have average grades of 1?3% lithium oxide (Li2O) and are commonly associated with tin, and especially tantalum mineralisation.
Nearly all of AustraliaÕs resources are associated with granite pegmatites found within the Pilbara and Yilgarn cratons of Western Australia, including at Greenbushes and Mount Marion. However, the Northern Territory also has lithium resources, with several projects underway. While the region is not as well-known for its lithium resources as Western Australia, it has been identified as a potential area for significant lithium production. One notable development is the Finniss Lithium project, located near Darwin, which is being developed by ASX-listed Core Lithium to produce spodumene concentrate (5.5% lithium oxide concentrate at 70% lithia recovery, according to Core Lithium) for export. Core LithiumÕs investor presentations also mention potential expansion plans for onshore refinement of spodumene to higher value products such as lithium hydroxide (Core Lithium, 2020).
Table 12: Chemical composition and percentage of lithium in minerals
MineralÊ
Chemical formulaÊ
Percentage of lithium (wt%)Ê
SpodumeneÊ
LiAlS2O6Ê
3.73Ê
PetaliteÊ
LiAlSi4O10Ê
2.27Ê
LepidoliteÊ
LiKAl2F2Si3O9Ê
3.56Ê
AmblygoniteÊ
LiAlFPO4Ê
4.74Ê
EucryptiteÊ
LiAlSiO4Ê
5.53Ê

8.2 Process 
Processing spodumene to produce lithium hydroxide is energy-intensive and requires specialised equipment and facilities. However, it is a critical step in the production of lithium-ion batteries, which are widely used in a variety of applications, including electric vehicles and consumer electronics. There are three primary roasting methods for processing ?-spodumene (naturally occurring spodumene to ?-spodumene [?-spodumene that has undergone a phase transition decrepitation]; Qiu et al., 2022) ? the reagent used for roasting determines the name of the process: 
* acid roasting involves baking the ?-spodumene with an excess of concentrated sulfuric acid (H2SO4) at a temperature of ~250¡C 
* the alkaline process uses limestone (CaCO3) or lime (Ca(OH)2 or CaO) 
* the chloride route uses various chlorinating reagents (Fosu et al., 2020). 
Other approaches are being researched, such as carbonising (using sodium carbonate [NaCO3] in the presence of CO2 and other additives) and fluorination using sodium fluoride (NaF) (Fosu et al., 2020). Table 13 compares key criteria between the various leaching processes.
Table 13: Comparison of leaching processes for lithium extraction from minerals 
Source: Sierkierka et al. (2022)
Ê
Acid/SulfonationÊ
AlkaliÊ
ChlorinationÊ
Active reagentsÊ
Alkali metal sulfates, sulfuric acid, SO3 and water or oxygen
Lime or limestoneÊ
Hydrochloric acid, sodium chloride, calcium chloride or chlorine gas
TimeÊ
1?3 hÊ
1?2 h
<2.5h
pHÊ
2?3Ê
8?10Ê
<5Ê
TemperatureÊ
200?1,000¡CÊ
100?200¡C (lime)Ê
800?1,000¡C (limestone)Ê
800?1,100¡CÊ
DisadvantagesÊ
Non-selective methodÊ
A lot of leaching solution is requiredÊ
Impurities such as Al, Na, Mg, Fe and KÊ
Need to decompose lime and limestone to calcium oxideÊ
Toxic chloric reagentsÊ
Aggressive environment of leachingÊ
AdvantagesÊ
High rate of Li extractionÊ
High rate of Li extraction without corrosive agentsÊ
Selective for lithium chloride productionÊ
Both Fosu et al. (2020) and Wang et al. (2022) concur that sulfuric acid roasting is the most widely used method in industry and the most technologically mature. A generic block flow diagram of processing ?-spodumene to lithium carbonate by sulfonation is shown in Figure 24 (Dessemond et al., 2019; Fosu et al., 2020; Wang et al., 2022).


Figure 24: A flow diagram of the major treatment processes for spodumene (chlorination, sulfation and alkaline processes)
Lithium is made amenable to leaching by calcination at ~1,000¡C (calcination refers to thermal treatment of a solid chemical compound whereby the compound is raised to a high temperature without melting under restricted supply of ambient oxygen). By pulverising and roasting the ?-spodumene it is converted into ?-spodumene (Wang et al., 2022). Heating of crushed spodumene ore requires a temperature of at least 1,000¡C for 30 minutes and achieves 85?90% extraction efficiency of lithium content (Dessemond et al., 2019). The lithium carbonate product is obtained when sodium carbonate solution is added to trigger precipitation (Wang et al., 2022). The recovery rate of lithium in the extraction process using the sulfuric acid method can reach over 90% in general (Salakjani et al., 2019; Zeng-hu et al., 2008). However, producing 1 tonne of lithium carbonate using this process creates 8Ð10 tonnes of solid waste residue (Wang et al., 2022). One saleable by-product of this is analcime, a zeolite mineral that has niche industrial uses.
Fosu et al. (2020) have described the chemical process of converting spodumene to lithium carbonate. Lithium is leached by acidification using H+ from concentrated sulfuric acid to chemoselectively exchange with the univalent Li cations, forming solid lithium and aluminium sulfates, silica and water vapour. The lithium sulfate is then dissolved by water leaching, followed by neutralisation, purification, impurity removal, evaporation and concentration. The dissolved lithium sulfate is reacted with sodium carbonate at 90oC to remove any remaining impurities from the system and precipitate lithium carbonate, the sales product. The process reactions are:
?"2LiAlSi" ?_2 "O" _(6("s" ))+2"H" _2 ?"SO" ?_(4("l" ))??"Li" ?_2 ?"SO" ?_(4("s" ))+?"Al" ?_2 ?"(SO" ?_4 ")" _(3("s" ))+2?"SiO" ?_(2("s" ))+?2"H" _2 "O" ?_(("aq)" )
?"Li" ?_2 ?"SO" ?_(4("s" ))??2?"Li" ?^+?_(("aq)" )+??"SO" ?_(4 ("aq)" )^(2-)?_
?"Li" ?_2 ?"SO" ?_(4("aq" ))+?"Na" ?_2 ?"CO" ?_(3("aq" ))??"Li" ?_2 ?"CO" ?_(3("s" ))+?"Na" ?_2 ?"SO" ?_(4("aq" ))
A block flow diagram of lithium carbonate production from spodumene is shown in Figure 25.

Figure 25: A block flow diagram illustrating the production of lithium hydroxide and lithium carbonate products from spodumene 
Source: ChemAnalyst (2024); Pall Corporation (2024)
8.3 Inputs and outputs
Kelly et al. (2021) conducted a lifecycle analysis for the production of lithium carbonate and lithium hydroxide from brine and ore resources in which they provide insight into the mass and energy requirements for converting spodumene to the final product; see Table 14.
Table 14: Material, energy and water inputs per tonne of concentrated spodumene produced, based on Western Australian mining 
Source: Kelly et al. (2021)
Ê
Unit of measure
ValueÊ
Input spodumene ore lithium concentrationÊ
% Li2OÊ
0.8?0.9%Ê
Output spodumene concentrateÊ
% Li2OÊ
~5%Ê
Required spodumene oreÊ
tonneÊ
4.5Ê
Other (includes sodium carbonate and a dispersant)Ê
tonneÊ
0.015Ê
Fresh waterÊ
m3Ê
3Ê
Energy input (diesel)Ê
MJÊ
4,500Ê
Kelly et al. (2021) have also analysed the mass and energy requirements for converting the spodumene concentrate into lithium hydroxide monohydrate (LiOH-H2O) and lithium carbonate (Li2CO3), based on information made public by Tianqi Lithium Corporation ( (Kelly et al., 2021); see Table 15.

Table 15: Material, energy and water inputs per tonne of lithium hydroxide monohydrate and lithium carbonate produced in China from Australian spodumene concentrate 
Source: Kelly et al. (2021)
?Ê
Unit of measure
Input per tonne of LiOH-H2O
Input per tonne of Li2CO3
Input spodumene concentrate lithium concentrationÊ
% Li2OÊ
6%Ê
6%Ê
Spodumene concentrate (6% Li2O)Ê
tonneÊ
6.42Ê
7.3Ê
H2SO4 (98% concentrate)Ê
tonneÊ
1.52Ê
1.71Ê
Na2CO3 (98.8% concentrate)Ê
tonneÊ
0.025Ê
2.05Ê
NaOH (96% concentrate)Ê
tonneÊ
1.18Ê
0.05Ê
CaCO3 (>98% concentrate)Ê
tonneÊ
0.6Ê
0.7Ê
Fresh waterÊ
m3Ê
11.24Ê
40Ê
ElectricityÊ
MJÊ
12,600Ê
6,480Ê
Thermal energy for kiln and steam (in coal energy)Ê
MJÊ
71,343Ê
135,890Ê
Thermal energy for kiln and steam (in tonnes of steam)Ê
tonneÊ
12.00Ê
16.50Ê
By-product Na2SO4Ê
tonneÊ
1.72Ê
1.92Ê

Spodumene processing has numerous inputs and outputs, creating several opportunities for integration with other processes (Figure 26):
* Electricity: The production of lithium hydroxide monohydrate or lithium carbonate from spodumene is energy-intensive throughout the entire production process, from mining to refining. In conventional mining operations diesel is the primary fuel source. A competitive advantage could be realised by using electrically driven equipment and vehicles where possible if low-cost electricity were available, justifying the additional capital cost to electrify.
* Sulfuric acid: Sulfuric acid is a major reagent used in spodumene processing. For a Northern Territory-based spodumene refinery to be competitive, it will need to have access to low-cost sulfuric acid. None of the processes investigated in this report have sulfuric acid as a by-product. There are, however, new technologies on the horizon to be aware of. Directly converting aqueous lithium sulfate to lithium hydroxide by electrolysis will create sulfuric acid  as a by-product that can be reused in the process. Acids and bases can be produced from aqueous salt solutions using electrodialysis ? for instance, sulfuric acid and sodium hydroxide can be produced from a solution of sodium sulfate (Raucq et al., 1993). Conversion of an aqueous solution of sodium sulfate has been demonstrated at laboratory scale (Noureddine et al., 2013). This would allow the sodium sulfate produced in the conventional spodumene flow sheet to be converted to sulfuric acid. However, it would consume large quantities of electricity. This technology is in the early development stage and would need to progress through a scale-up program.
* Thermal energy: Many of the processes require large thermal energy inputs, and at high temperatures ? such as the roasting (900?1,100¡C) and sulfonation (~250¡C) ? so these processes would not be candidates for waste heat (normally <100¡C). An efficient spodumene refining facility would capture the high-grade heat following the energy-intensive roasting and sulfonation processes and use it in other downstream drying and evaporative processes. Potentially, high-temperature thermal energy storage systems could be integrated, but that would require a techno-economic assessment to determine benefits as well as technology demonstration.
* Chlorides: There is an opportunity to use chlorides produced from desalination (sodium chloride, potassium chloride, calcium chloride) to roast spodumene using the chlorination process. Most promising would be using calcium chloride as the roasting reagent and then using water as the lixiviant. This would be considered early-stage technology and would require progression to a demonstration plant before sufficient confidence could be gained for commercialisation.

Ê
Ê
Figure 26: Simplified block diagrams of the processing of spodumene to lithium hydroxide monohydrate or lithium carbonate to illustrate the major input and output streams amenable for integration with other industrial processes

9 Block diagrams of possible configurations for the Northern Territory Low Emissions Hub 
Current technology can be used to create a low-emissions production hub for the synthesis of ammonia, urea, methanol and derivatives. A low-cost supply of natural gas, fresh water and electricity and a low-cost CO2 sequestration plant for any unconsumed CO2 would be prerequisites for this type of configuration to be competitive. Beginning with the premise that the intent of the Northern Territory Low Emissions Hub is to maximise the value of the resources available to the precinct (i.e. natural gas, water, CO2 storage reservoirs and potentially low-cost renewable energy in the future), then it stands to reason that an integrated process would maximise the value of the natural gas and minimise the required consumption of water and electricity and the production of emissions.
Based on a review of the processes in this report, two possible integrated processes are presented, the first representing near-term integrated industrial development and the second medium-to-long term process adapting the first integrated process to take advantage of future technology developments and reductions in costs. 
The core of any integrated process will be the production of hydrogen. Some of the hydrogen could be sold and some could be converted into higher value products. For the conversion of natural gas to hydrogen, ATR is the most efficient method as it does not require external fuel for heat (the reaction is exothermic). It is likely that it will be more cost-effective to convert natural gas to hydrogen as opposed to hydrogen generated from electrolysis in the first instance. As such, a near-term hub might comprise the industrial composition shown in Figure 27.

Figure 27: Illustrative diagram of the integrated process blocks that can be developed in the hub in the near term
The integrated hub inputs begin with natural gas, water, air and electricity. ATR requires a source of oxygen, which could be supplied from an ASU. The nitrogen subsequently produced from the ASU could then be used to create ammonia. A portion of the hydrogen could also be used to create methanol. The CO2 produced from the ATR process will be captured and could be used for converting ammonia to urea and hydrogen to methanol. The production of methanol would also open opportunities for future higher value products. CO2 not consumed in these processes could be removed for storage through the hub CCUS infrastructure. 
The main processes (ASU, ammonia, urea and methanol) could be designed so that they can transition to a future scenario where hydrogen and CO2 are sourced via electrolysis and DAC, as shown in Figure 28. The electrolysis plant could supersede ATR and DAC could provide CO2 for urea and methanol production. The transition to this modified system could be gradual and incorporate a gradually increasing share of hydrogen sourced from electrolysis and CO2 sourced from DAC.
Note that for a low-emissions hub to exist, low-cost, baseload renewable energy is required, which would require energy storage. Since all of these processes are available to any developer/operator globally, for a hub to have a competitive advantage, it will need to focus on providing very low-cost electricity prices to the hub, efficient and low-cost shipping, and access to low-cost water.
It is worth considering a dedicated renewable energy generation and storage facility for the hub to achieve competitive electricity prices on a global scale. For processes at the hub to acquire power through a utility will impose added costs associated with the network. Across Australia, network costs are a significant component of the final cost of electricity.
There is an opportunity to create a combined use facility that performs the air separation function and energy storage using LAES technology. The ASU/LAES could store liquefied nitrogen in tanks. As required, the nitrogen could be diverted to power generation units, expanding the cryogenic nitrogen creating power, and the now gaseous nitrogen could be supplied to the ammonia process. All of the processes will need to operate continuously, so adequate storage quantities of nitrogen would be needed to account for intermittency of renewables (possibly weeksÕ worth of nitrogen), and the continuous demand of feedstock for the ammonia plant. Oxygen would be available for sale as a product from the ASU and the electrolysis processes. It could also be used in further value-added processes such as converting methanol to aldehydes and then to polymers, although other industries dependent on oxygen feedstock may be required to utilize a sizeable portion of the available supply.




Figure 28: Illustrative diagram of an integrated process block that can be developed once lower cost hydrogen and DAC are demonstrated

Another opportunity for integration is to use waste heat from the industrial processes to supply the thermal energy required for DAC. This could have a twofold impact by reducing the electricity required by DAC and reducing any cooling loads from the industrial processes. Currently the MASDP is proposed to be arranged as shown in Figure 29. Due to the waterways that exist in the proposed development site, the processes and facilities will need to be spread out where there is usable land.

Figure 29: MASDP Balanced Scenario potential industry locations

If either of the proposed integrated processes shown in Figure 27 or Figure 28 is considered as a viable development candidate, it would be advantageous to allocate land consistent with the process flow. For the near-term option shown in Figure 27, natural gas will be the foundation of the hub ? as such, reticulated natural gas supply throughout the precinct is a requirement. The energy-intensive ASU would benefit from being located nearest the substation, and the final higher value products (ammonia, urea and methanol) predominantly for export would locate nearest to the export terminal. 
In the case of the electrolysis and DAC-based scenario in Figure 28, the electrolysis plant and DAC would require access to electrical distribution and CO2 pipeline infrastructure. Even if CO2 is imported, DAC is probably still needed to support the ongoing production of urea and methanol, because the imported CO2 will likely be earmarked for sequestration to realise emission reduction credits. The location of the DAC plant(s) would be near sources of process heat but in non-hazardous areas of the precinct.  
Where processes are not co-located, to maximise opportunities for cross-sector coupling there would be a requirement for appropriate pipeline infrastructure within the precinct to enable products/wastes (including waste heat and cold) to be transported between industrial users.
10 Summary and conclusions
10.1 Managing energy efficiency: reutilisation, storage and electrification
The technical key to sector coupling success is efficient energy management: in a future based on variable renewable generation, energy storage is a critical enabler to firm power, and manage demand, taking advantage of the lowest cost options based on time-of-day pricing. Storage is at the nexus of sector coupling between electricity, industry and transport (Sterner and Stadler, 2019); see Table 16. For the industries discussed in this report, re-utilisation and storage of heat are important, as are transferring and exchanging heat efficiently. 
According to Thiel and Stark (2021), Ôto decarbonize industry we must decarbonize heatÕ. The prime pathway is electrification of fossil-fuel dependent process heating, with efficiency, process intensification and improved technologies for high-grade heat storage and exchange playing key roles. They estimate that developing new decarbonised process heating technologies could eliminate approximately one-fifth of global CO2 emissions.
Table 16. Classes of energy storage technology for cross-sectoral use 
Source: Modified from Sterner and Stadler (2019)

10.2 Barriers and opportunities for sector coupling
To summarise, four aspects should be addressed to realise a successful industrial symbiosis using sector coupling to decarbonise industry in a hub or cluster: 
1. Economic and financial constraints: Initial investments in shared infrastructure and technologies can be high, and companies may be reluctant to commit without clear financial benefits. They may not all be aligned with the timelines for investment, either to facilitate a quick startup or to stay the course over the multiple years or decades required to bring a full return on investment over the expected lifetime of the new infrastructure. A well-articulated business case, supported by risk analysis, is vital. In other jurisdictions, financial contributions from governments focus on building critical energy and transportation infrastructure and may consider well-reasoned tax incentives that support inwards investment (see the Task 4 report; Stalker et al. (2024)). Direct subsidies or poorly targeted grants that aim to buy jobs rarely bring long-term rewards, and can bring noise and uncertainty if they are seen as politically motivated.
2. Technical and operational issues: Ensuring the compatibility and efficient operation of shared systems requires significant technical expertise and ongoing maintenance and upgrades by a skilled workforce. Plans should not be overly complex or overambitious in their goals, and common standards and language should be adopted among industries.
3. Regulatory and policy challenges: Existing regulations may not fully support or may even hinder industrial symbiosis, requiring adjustments or new policies to facilitate better integration. There may also be legal and contractual issues, or disputes over information sharing and intellectual property. Careful consideration is required to understand how to remove unnecessary barriers that could permit sector coupling.
4. Stakeholder coordination: Aligning the interests of multiple stakeholders and managing complex agreements can be time-consuming and difficult. A central body with proper governance could be established to plan for success and to operate efficiently and responsibly once launched. The foundation industry participants, together with their commercial partners (for finance and material supply), the energy and service providers and the state or territory government, would typically be the key stakeholders whose vision must be aligned. Other key stakeholders include the traditional owners, residents of neighbouring areas, primary producers (farming, pastoral, forestry, fishing), unions and trade associations and other statutory interested parties. The workers at all levels within the participating companies as the final set of critical stakeholders. Informing and giving agency to all of these stakeholders is a key to success.
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