Australia

As nations around the world seek to reduce carbon dioxide emissions in order to mitigate climate change risks there has been a resurgence of interest in the use of hydrogen as a zero-emissions energy carrier. Hydrogen can be produced from diverse feedstocks via a range of low-emissions pathways and has broad potential in the process of decarbonization across the energy transport and industrial sectors.<br/>With an abundance of both renewable and fossil fuel energy resources a comparatively low national energy demand and excellent existing regional resource trading links Australia is well positioned to pursue industrial-scale hydrogen production for both domestic and export purposes. In this paper we present an overview of the progress at the government industry and research levels currently undertaken to enable a large-scale hydrogen industry for Australia.

The demand for fossil fuels is increasing because of globalization and rising energy demands. As a result many nations are exploring alternative energy sources and hydrogen is an efficient and practical alternative fuel. In the transportation industry the development of hydrogen-powered cars aims to maximize fuel efficiency and significantly reduce exhaust gas emission and concentration. The impact of using hydrogen as a supplementary fuel for spark ignition (SI) and compression ignition (CI) engines on engine performance and gas emissions was investigated in this study. By adding hydrogen as a fuel in internal combustion engines the torque power and brake thermal efficiency of the engines decrease while their brake-specific fuel consumption increase. This study suggests that using hydrogen will reduce the emissions of CO UHC CO2 and soot; however NOx emission is expected to increase. Due to the reduction of environmental pollutants for most engines and the related environmental benefits hydrogen fuel is a clean and sustainable energy source and its use should be expanded.

To ensure the UK’s net zero targets are met the transition from conventionally fueled transport to low emission alternatives is necessary. The impact from increased decarbonised electricity generation on ecosystem services (ES) and natural capital (NC) are not currently quantified with decarbonisation required to minimise impacts from climate change. This study aims to project the future electric and hydrogen energy demand between 2020 and 2050 for car bus and train to better understand the land/sea area that would be required to support energy generation. In this work predictions of the geospatial impact of renewable energy (onshore/offshore wind and solar) nuclear and fossil fuels on ES and NC were made considering generation mix number of generation installations and energy density. Results show that electric transport will require ~136599 GWh for all vehicle types analysed in 2050 much less than hydrogen transport at ~425532 GWh. We estimate that to power electric transport at least 1515 km2 will be required for solar 1672 km2 for wind and 5 km2 for nuclear. Hydrogen approximately doubles this requirement. Results provide an approximation of the future demands from the transport sector on land and sea area use indicating that a combined electric and hydrogen network will be needed to accommodate a range of socio-economic requirements. While robust assessments of ES and NC impacts are critical in future policies and planning significant reductions in energy demands through a modal shift to (low emission) public transport will be most effective in ensuring a sustainable transport future.

Green hydrogen (H2) is emerging as a future clean energy carrier. While there exists significant analysis on global renewable (and non-renewable) hydrogen generation costs analysis of its transportation costs irrespective of production method is still limited. Complexities include the different forms in which hydrogen can be transported the limited experience to date in shipping some of these carrier forms the trade routes potentially involved and the possible use of different shipping fuels. Herein we present an open-source model developed to assist stakeholders in assessing the costs of shipping various forms of hydrogen over different routes. It includes hydrogen transport in the forms of liquid hydrogen (LH2) ammonia liquified natural gas (LNG) methanol and liquid organic hydrogen carriers (LOHCs). It considers both fixed and variable costs including port fees possible canal usage charges fuel costs ship capital and operating costs boil-off losses and possible environmental taxes among many others. The model is applied to the Rotterdam-Australia route as a case study revealing ammonia ($0.56/kgH2) and methanol ($0.68/kgH2) as the least expensive hydrogen derivatives to transport followed by liquified natural gas ($1.07/kgH2) liquid organic hydrogen carriers ($1.37/kgH2) and liquid hydrogen ($2.09/kgH2). While reducing the transportation distance led to lower shipping costs we note that the merit order of assumed underlying shipping costs remain unchanged. We also explore the impact of using hydrogen (or the hydrogen carrier) as a low/zero carbon emission fuel for the ships which led to lowering of costs for liquified natural gas ($0.88/kgH2) a similar cost for liquid hydrogen ($2.19/kgH2) and significant increases for the remainder. Given our model is open-sourced it can be adapted globally and updated to match the changing cost dynamics of the emerging green hydrogen market.

Introducing CO2 electrochemical conversion technology to the iron-making blast furnace not only reduces CO2 emissions but also produces H2 as a byproduct that can be used as an auxiliary reductant to further decrease carbon consumption and emissions. With adequate H2 supply to the blast furnace the injection of H2 is limited because of the disadvantageous thermodynamic characteristics of the H2 reduction reaction in the blast furnace. This paper presents thermodynamic analysis of H2 behaviour at different stages with the thermal requirement consideration of an iron-making blast furnace. The effect of injecting CO2 lean top gas and CO2 conversion products H2–CO gas through the raceway and/or shaft tuyeres are investigated under different operating conditions. H2 utilisation efficiency and corresponding injection volume are studied by considering different reduction stages. The relationship between H2 injection and coke rate is established. Injecting 7.9–10.9 m3/tHM of H2 saved 1 kg/tHM coke rate depending on injection position. Compared with the traditional blast furnace injecting 80 m3/tHM of H2 with a medium oxygen enrichment rate (9%) and integrating CO2 capture and conversion reduces CO2 emissions from 534 to 278 m3/tHM. However increasing the hydrogen injection amount causes this iron-making process to consume more energy than a traditional blast furnace does.

This  paper  reports  on  the  results  of  interviews  conducted  with  21  representatives  from   emergency services organisations within Australia and New Zealand. With a relative emergent industry such as future fuels a chicken and egg situation does emerge with regards to how much training needs to be in place in advance of large-scale industry development or not. These respondents were employed in a variety of roles being directly involved in research and training of emerging technologies frontline operational  managers  and  other  senior  roles  across  the   emergency  services  sector.  Participants' responses to a series of questions were able to provide insights into the state of knowledge and training requirements within their organisations in relation to hydrogen and other future fuels. The findings suggest that formal and informal processes currently exist to support the knowledge development and transferal around the adoption of hydrogen and other future fuels. From the interviews it became clear that  there  are  a  number  of  processes  that  have  emerged  from  the  experiences  gained  through  the implementation   of  rooftop  solar  PV  and  battery  storage  that  provide  some  background  context  for advancing future fuels information across the sector. Because safety is a critical component for securing a social licence to operate engagement and knowledge sharing with any representatives from across this sector will only help to build confidence in the industry. Similarly because interviewees were very keen to access information they expressed a clear willingness to learn more through more formalised relationships rather than an ad hoc information seeking that has been employed to date. The presentation will  identify  key  recommendations  and  also  highlight  the   importance  of  QR  Codes in the emergency responder landscape. Implications for industry and policy makers are discussed.

This work reports on H2 fuel generation from sewage water using Cu/CuO nanoporous (NP) electrodes. This is a novel concept for converting contaminated water into H2 fuel. The preparation of Cu/CuO NP was achieved using a simple thermal combustion process of Cu metallic foil at 550 ◦C for 1 h. The Cu/CuO surface consists of island-like structures with an inter-distance of 100 nm. Each island has a highly porous surface with a pore diameter of about 250 nm. X-ray diffraction (XRD) confirmed the formation of monoclinic Cu/CuO NP material with a crystallite size of 89 nm. The prepared Cu/CuO photoelectrode was applied for H2 generation from sewage water achieving an incident to photon conversion efficiency (IPCE) of 14.6%. Further the effects of light intensity and wavelength on the photoelectrode performance were assessed. The current density (Jph) value increased from 2.17 to 4.7 mA·cm−2 upon raising the light power density from 50 to 100 mW·cm−2 . Moreover the enthalpy (∆H*) and entropy (∆S*) values of Cu/CuO electrode were determined as 9.519 KJ mol−1 and 180.4 JK−1 ·mol−1 respectively. The results obtained in the present study are very promising for solving the problem of energy in far regions by converting sewage water to H2 fuel.

As the global search for new methods to combat global warming and climate change continues renewable fuels and hydrogen have emerged as saviours for environmentally polluting industries such as aviation. Sustainable aviation is the goal of the aviation industry today. There is increasing interest in achieving carbon-neutral flight to combat global warming. Hydrogen has proven to be a suitable alternative fuel. It is abundant clean and produces no carbon emissions but only water after use which has the potential to cool the environment. This paper traces the historical growth and future of the aviation and aerospace industry. It examines how hydrogen can be used in the air and on the ground to lower the aviation industry’s impact on the environment. In addition while aircraft are an essential part of the aviation industry other support services add to the overall impact on the environment. Hydrogen can be used to fuel the energy needs of these services. However for hydrogen technology to be accepted and implemented other issues such as government policy education and employability must be addressed. Improvement in the performance and emissions of hydrogen as an alternative energy and fuel has grown in the last decade. However other issues such as the storage and cost and the entire value chain require significant work for hydrogen to be implemented. The international community’s alternative renewable energy and hydrogen roadmaps can provide a long-term blueprint for developing the alternative energy industry. This will inform the private and public sectors so that the industry can adjust its plan accordingly.

The recent detection of natural hydrogen seeps in sedimentary basin settings has triggered significant interest in the exploration of this promising resource. If large economical resources exist and can be extracted from the sub-surface this would provide an opportunity for natural hydrogen to contribute to the non-carbon-based energy mix. The detection and exploration of hydrogen gas in the sub-surface is a significant challenge that requires costly drilling sophisticated instrumentation and reliable analytical/sampling methods. Here we propose the application of a commercial-based sensor that can be used to detect and monitor low levels of hydrogen gas emissions from geological environments. The sensitivity selectivity (K > 1000) and stability (<1 ppm/day) of the sensor was evaluated under various conditions to determine its suitability for geological field monitoring. Calibration tests showed that the hydrogen readings from the sensor were within ±20% of the expected values. We propose that chemical sensing is a simple and feasible method for understanding natural hydrogen seeps that emanate from geological systems and formations. However we recommend using this sensor as part of a complete geological survey that incorporates an understanding of the geology along with complementary techniques that provide information on the rock properties.

Developing a thriving hydrogen industry will depend on public and community support. Past research mainly focusing on the acceptance of hydrogen fuelling stations and cars suggests that people generally support hydrogen energy technology (HET). Few studies have however considered how people think about other components of the hydrogen supply chain (i.e. technologies required to make store transport and use hydrogen). Moreover there has been limited research investigating how people interpret and develop beliefs about HET after being presented with technical information. This paper attempts to address these research gaps by presenting the findings from four face-to-face focus group discussions conducted in Australia. The findings suggest that people have differing views about HET which depends on the type of technology and these views influence levels of support. The study also revealed concerns about a range of other factors that have yet to be considered in hydrogen acceptance research (e.g. perceived water use efficiency and indirect benefits). The findings highlight the value of qualitative research for identifying salient beliefs that shape attitudes towards HET and provide recommendations for future research and how to effectively communicate with the public and communities about an emerging hydrogen industry.

In the last two years or so there has been increasing interest in hydrogen as an energy source in Australia and around the world. Notably this is not the first time that hydrogen has caught our collective interest. Most recently the 2000s saw a substantial investment in hydrogen research development and demonstration around the world. Prior to that the oil crises of the 1970s also stimulated significant investment in hydrogen and earlier still the literature on hydrogen was not lacking. And yet the hydrogen economy is still an idea only.<br/>So what if anything might be different this time?<br/>This is an important question that we all need to ask and for which the author can only give two potential answers. First our need to make dramatic reductions in greenhouse gas (GHG) emissions has become more pressing since these previous waves of interest. Second renewable energy is considerably more affordable now than it was before and it has consistently outperformed expectations in terms of cost reductions by even its strongest supporters.<br/>While this dramatic and ongoing reduction in the cost of renewables is very promising our need to achieve substantial GHG emission reductions is the crucial challenge. Moreover meeting this challenge needs to be achieved with as little adverse social and economic impact as possible.<br/>When considering what role hydrogen might play we should first think carefully about the massive scale and complexity of our global energy system and the typical prices of the major energy commodities. This provides insights into what opportunities hydrogen may have. Considering a temperate country with a small population like Australia we see that domestic natural gas and transport fuel markets are comparable to and even larger than the electricity market on an energy basis.

Non-catalytic thermal methane cracking (TMC) is an alternative for hydrogen manufacturing and traditional commercial processes in small-scale hydrogen generation. Supplying the high-level temperatures (850–1800°C) inside the reactors and reactor blockages are two fundamental challenges for developing this technology on an industrial scale (Mahdi Yousefi and Donne 2021). A regenerative reactor could be a part of a solution to overcome these obstacles. This study conducted an experimental study in a regenerative reactor environment between 850 and 1170°C to collect the conversion data and investigate the reactor efficiency for TMC processes. The results revealed that the storage medium was a bed for carbon deposition and successfully supplied the reaction’s heat with more than 99.7% hydrogen yield (at more than 1150°C). Results also indicated that the reaction rate at the beginning of the reactor is much higher and the temperature dependence in the early stages of the reaction is considerably higher. However after reaching a particular concentration of Hydrogen at each temperature the influence of temperature on the reaction rate decreases and is almost constant. The type of produced carbon in the storage medium and its auto-catalytic effect on the reactions were also investigated. Results showed that carbon black had been mostly formed but in different sizes from 100 to 2000 nm. Increasing the reactor temperature decreased the size of the generated carbon. Pre-produced carbon in the reactor did not affect the production rate and is almost negligible at more than 850°C.

Instead of storing the energy produced by photovoltaic panels in batteries for later use to power electric loads green hydrogen can also be produced and used in transportation heating and as a natural gas alternative. Green hydrogen is produced in a process called electrolysis. Generally the electrolyser can generate hydrogen from a fluctuating power supply such as renewables. However due to the startup time of the electrolyser and electrolyser degradation accelerated by multiple shutdowns an idle mode is required. When in idle mode the electrolyser uses 10% of the rated electrolyser load. An energy management system (EMS) shall be applied where a storage technology such as a lithium-ion capacitor or lithium-ion battery is used. This paper uses a state-machine EMS of PV microgrid for green hydrogen production and energy storage to manage the hydrogen production during the morning from solar power and in the night using the stored energy in the energy storage which is sized for different scenarios using a lithium-ion capacitor and lithium-ion battery. The mission profile and life expectancy of the lithium-ion capacitor and lithium-ion battery are evaluated considering the system’s local irradiance and temperature conditions in the Australian climate. A tradeoff between storage size and cutoffs of hydrogen production as variables of the cost function is evaluated for different scenarios. The lithium-ion capacitor and lithium-ion battery are compared for each tested scenario for an optimum lifetime. It was found that a lithium-ion battery on average is 140% oversized compared to a lithium-ion capacitor but a lithium-ion capacitor has a smaller remaining capacity of 80.2% after ten years of operation due to its higher calendar aging while LiB has 86%. It was also noticed that LiB is more affected by cycling aging while LiC is affected by calendar aging. However the average internal resistance after 10 years for the lithium-ion capacitor is 264% of the initial internal resistance while for lithium-ion battery is 346% making lithium-ion capacitor a better candidate for energy storage if it is used for grid regulation as it requires maintaining a lower internal resistance over the lifetime of the storage.

In order to achieve carbon neutrality in a few decades the clean energy proportion in power mix of China will significantly rise to over 90%. A consensus has been reached recently that it will be of great significance to promote hydrogen energy that is produced by variable renewable energy power generation as a mainstay energy form in view of its potential value on achieving carbon neutrality. This is because hydrogen energy is capable of complementing the power system and realizing further electrification especially in the section that cannot be easily replaced by electric energy. Power system related planning model is commonly used for mid-term and long-term planning implemented through power installation and interconnection capacity expansion optimization. In consideration of the high importance of hydrogen and its close relationship with electricity an inclusive perspective which contains both kinds of the foresaid energy is required to deal with planning problems. In this study a joint model is established by coupling hydrogen energy model in the chronological operation power planning model to realize coordinated optimization on energy production transportation and storage. By taking the carbon neutrality scenario of China as an example the author applies this joint model to deploy a scheme research on power generation and hydrogen production inter-regional energy transportation capacity and hydrogen storage among various regions. Next by taking the technology progress and cost decrease prediction uncertainty into account the main technical– economic parameters are employed as variables to carry out sensitivity analysis research with a hope that the quantitative calculation and results discussion could provide suggestion and reference to energy-related companies policy-makers and institute researchers in formulating strategies on related energy development.

Currently renewable energy-based generators are considered worldwide to achieve net zero targets. However the stochastic nature of renewable energy systems leads to regulation and control challenges for power system operators especially in remote and regional grids with smaller footprints. A hybrid system (i.e. solar wind biomass energy storage) could minimise this issue. Nevertheless the hybrid system is not possible to develop in many islands due to the limited land area geographical conditions and others. Hydrogen as a carrier of clean energy can be used in locations where the installation of extensive or medium-scale renewable energy facilities is not permissible due to population density geographical constraints government policies and regulatory issues. This paper presents a techno-economic assessment of designing a green hydrogen-based microgrid for a remote island in North-east Australia. This research work determines the optimal sizing of microgrid components using green hydrogen technology. Due to the abovementioned constraints the green hydrogen production system and the microgrid proposed in this paper are located on two separate islands. The paper demonstrates three cost-effective scenarios for green hydrogen production transportation and electricity generation. This work has been done using Hybrid Optimisation Model for Multiple Energy Resources or HOMER Pro simulation platform. Simulation results show that the Levelized Cost of Energy using hydrogen technology can vary from AU$0.37/kWh to AU$1.08/kWh depending on the scenarios and the variation of key parameters. This offers the potential to provide lower-cost electricity to the remote community. Furthermore the CO2 emission could be reduced by 1760777 kg/year if the renewable energy system meets 100% of the electricity demand. Additionally the sensitivity analysis in this paper shows that the size of solar PV and wind used for green hydrogen production can further be reduced by 50%. The sensitivity analysis shows that the system could experience AU$0.03/kWh lower levelized cost if the undersea cable is used to transfer the generated electricity between islands instead of hydrogen transportation. However it would require environmental approval and policy changes as the islands are located in the Great Barrier Reef.

Conventional fuels for vehicular applications generate hazardous pollutants which have an adverse effect on the environment. Therefore there is a high demand to shift towards environment-friendly vehicles for the present mobility sector. This paper highlights sustainable mobility and specifically sustainable transportation as a solution to reduce GHG emissions. Thus hydrogen fuel-based vehicular technologies have started blooming and have gained significance following the zero-emission policy focusing on various types of sustainable motilities and their limitations. Serving an incredible deliverance of energy by hydrogen fuel combustion engines hydrogen can revolution various transportation sectors. In this study the aspects of hydrogen as a fuel for sustainable mobility sectors have been investigated. In order to reduce the GHG (Green House Gas) emission from fossil fuel vehicles researchers have paid their focus for research and development on hydrogen fuel vehicles and proton exchange fuel cells. Also its development and progress in all mobility sectors in various countries have been scrutinized to measure the feasibility of sustainable mobility as a future. This paper is an inclusive review of hydrogen-based mobility in various sectors of transportation in particular fuel cell cars that provides information on various technologies adapted with time to add more towards perfection. When compared to electric vehicles with a 200-mile range fuel cell cars have a lower driving cost in all of the 2035 and 2050 scenarios. To stimulate the use of hydrogen as a passenger automobile fuel the cost of a hydrogen fuel cell vehicle (FCV) must be brought down to at least the same level as an electric vehicle. Compared to gasoline cars fuel cell vehicles use 43% less energy and generate 40% less CO2.

A paradigm shift towards the utilization of carbon-neutral and low emission fuels is necessary in the internal combustion engine industry to fulfil the carbon emission goals and future legislation requirements in many countries. Hydrogen as an energy carrier and main fuel is a promising option due to its carbon-free content wide flammability limits and fast flame speeds. For spark-ignited internal combustion engines utilizing hydrogen direct injection has been proven to achieve high engine power output and efficiency with low emissions. This review provides an overview of the current development and understanding of hydrogen use in internal combustion engines that are usually spark ignited under various engine operation modes and strategies. This paper then proceeds to outline the gaps in current knowledge along with better potential strategies and technologies that could be adopted for hydrogen direct injection in the context of compression-ignition engine applications—topics that have not yet been extensively explored to date with hydrogen but have shown advantages with compressed natural gas.

Hydrogen is one of the prospective clean energies that could potentially address two pressing areas of global concern namely energy crises and environmental issues. Nowadays fossil‐ based technologies are widely used to produce hydrogen and release higher greenhouse gas emis‐ sions during the process. Decarbonizing the planet has been one of the major goals in the recent decades. To achieve this goal it is necessary to find clean sustainable and reliable hydrogen pro‐ duction technologies with low costs and zero emissions. Therefore this study aims to analyse the hydrogen generation from solar and wind energy sources and observe broad prospects with hybrid renewable energy sources in producing green hydrogen. The study mainly focuses on the critical assessment of solar wind and hybrid‐powered electrolysis technologies in producing hydrogen. Furthermore the key challenges and opportunities associated with commercial‐scale deployment are addressed. Finally the potential applications and their scopes are discussed to analyse the important barriers to the overall commercial development of solar‐wind‐based hydrogen production systems. The study found that the production of hydrogen appears to be the best candidate to be employed for multiple purposes blending the roles of fuel energy carrier and energy storage modality. Further studies are recommended to find technical and sustainable solutions to overcome the current issues that are identified in this study.

Over the past three years there has been a rapid increase in discussions across the different levels of Australia's governments about the role that hydrogen might play in helping the world transition to a low carbon future. While those working in the energy industry are aware of the opportunities and challenges that lay ahead the general public is less engaged. However we know from the  introduction of previous technologies that public attitudes towards technologies including whether they view them to be safe can severely impact overall acceptance. Understanding how the public perceives hydrogen both for domestic and export use and the potential benefits it brings to Australia is critical for the industry to progress. In this paper we present the initial findings of a national survey of the Australian public conducted in March 2021 which builds on the results of a previous survey conducted in 2018. The 2021 respondents were drawn from all Australian states and territories (n=3020) and quotas were used to ensure adequate representation of age groups and gender. Overall the respondents have favorable views about using hydrogen for energy in Australia with caveats about production-related environmental impacts and issues such as safety. While there has been a slight increase in support for hydrogen as a possible solution for energy and environmental challenges since the 2018 survey the effect size is very small. This suggests that while hydrogen discussions have increased at a policy level little has been done to improve public understanding of hydrogen in communication strategies will be needed as the Australian hydrogen industry continues to develop and gain more widespread media attention.

Hydrogen vehicles encompassing fuel cell electric vehicles (FCEVs) are pivotal within the UK’s energy landscape as it pursues the goal of net-zero emissions by 2050. By markedly diminishing dependence on fossil fuels FCEVs including hydrogen vehicles wield substantial influence in shaping the circular economy (CE). Their impact extends to optimizing resource utilization enabling zero-emission mobility facilitating the integration of renewable energy sources supplying adaptable energy storage solutions and interconnecting diverse sectors. The widespread adoption of hydrogen vehicles accelerates the UK’s transformative journey towards a sustainable CE. However to fully harness the benefits of this transition a robust investigation and implementation of safety measures concerning hydrogen vehicle (HV) use are indispensable. Therefore this study takes a holistic approach integrating quantitative risk assessment (QRA) and an adaptive decision-making trial and evaluation laboratory (DEMATEL) framework as pragmatic instruments. These methodologies ensure both the secure deployment and operational excellence of HVs. The findings underscore that the root causes of HV failures encompass extreme environments material defects fuel cell damage delivery system impairment and storage system deterioration. Furthermore critical driving factors for effective safety intervention revolve around cultivating a safety culture robust education/training and sound maintenance scheduling. Addressing these factors is pivotal for creating an environment conducive to mitigating safety and risk concerns. Given the intricacies of conducting comprehensive hydrogen QRAs due to the absence of specific reliability data this study dedicates attention to rectifying this gap. A sensitivity analysis encompassing a range of values is meticulously conducted to affirm the strength and reliability of our approach. This robust analysis yields precise dependable outcomes. Consequently decision-makers are equipped to discern pivotal underlying factors precipitating potential HV failures. With this discernment they can tailor safety interventions that lay the groundwork for sustainable resilient and secure HV operations. Our study navigates the intersection of HVs safety and sustainability amplifying their importance within the CE paradigm. Using the careful amalgamation of QRA and DEMATEL methodologies we chart a course towards empowering decision-makers with the insights to steer the hydrogen vehicle domain to safer horizons while ushering in an era of transformative eco-conscious mobility.

Green hydrogen is a key element that has the potential to play a critical role in the global pursuit of a resilient and sustainable future. However like other energy production methods hydrogen comes with challenges including high costs and safety concerns across its entire value chain. To overcome these low-cost productions are required along with a promised market. Offshore renewables have an enormous potential to facilitate green hydrogen production on a large scale. Their plummeting cost technological advances and rising cost of carbon pave a pathway where green hydrogen can be cost-competitive against fossil-fuel-based hydrogen. Offshore industries including oil and gas aquaculture and shipping are looking for cleaner energy solutions to decarbonize their systems/operations and can serve as a substantial market. Offshore industrial nexus moreover can assist the production storage and transmission of green hydrogen through infrastructure sharing and logistical support. The development of offshore green hydrogen production facilities is in its infancy and requires a deeper insight into the key elements that govern decision-making during their life-cycle. This includes the parameters that reflect the performance of hydrogen technology with technical socio-political financial and environmental considerations. Therefore this study provides critical insight into the influential factors discovered through a comprehensive analysis that governs the development of an offshore green hydrogen system. Insights are also fed into the requirements for modelling and analysis of these factors considering the synergy of hydrogen production with the offshore industries coastal hydrogen hub and onshore energy demand. The results of this critical review will assist the researchers and developers in establishing and executing an effective framework for offshore site selection in largely uncertain and hazardous ocean environments. Overall the study will facilitate the stakeholders and researchers in developing decision-making tools to ensure sustainable and safe offshore green hydrogen facilities.

Transitioning to a sustainable energy future necessitates innovative storage solutions for renewable energies where hydrogen (H₂) emerges as a pivotal energy carrier for its low emission potential. This paper explores unlined rock caverns (URCs) as a promising alternative for underground hydrogen storage (UHS) overcoming the geographical and technical limitations of UHS methods like salt rock caverns and porous media. Drawing from the experiences of natural gas (NG) and compressed air energy storage (CAES) in URCs we explore the viability of URCs for storing hydrogen at gigawatt-hour scales (>100 GWh). Despite challenges such as potential uplift failures (at a depth of approximately less than 1000 m) and hydrogen reactivity with storage materials at typical conditions (below temperatures of 100◦C and pressures of 15 MPa) URCs present a flexible scalable option closely allied with green hydrogen production from renewable sources. Our comprehensive review identifies critical design considerations including hydraulic containment and the integrity of fracture sealing materials under UHS conditions. Addressing identified knowledge gaps particularly around the design of hydraulic containment systems and the interaction of hydrogen with cavern materials will be crucial for advancing URC technology. The paper underscores the need for further experimental and numerical studies to refine URC suitability for hydrogen storage highlighting the role of URCs in enhancing the compatibility of renewable energy sources with the grid.

We report a new techno-economic model to assess performance and capital costs for large-scale underground hydrogen storage in depleted gas reservoirs. A simulation toolbox is developed to model surface facilities and to simulate the hydrogen flow in geological formations in an integrated fashion.<br/>Integrated modelling revealed the following key insights: 1) A buffer system is highly desirable to absorb inherent variability in upstream hydrogen production; 2) hydrogen mixing with existing gases in the reservoir together with gravity segregation and diffusion results in a decline in hydrogen purity at the wellhead over time and can require increased purification; 3) the capital cost is dominated by the cost of cushion gas (hydrogen) and the compression system where about 9% of the total energy content of the hydrogen is consumed for compression. The scenarios modelled in our study result in a levelized cost of storage in Australia ranging from 2.3 to 4.29 A$/(kg).

This paper provides a comprehensive overview of the physical properties and applications of natural gas (NG) and hydrogen as fuels in internal combustion (IC) engines. The paper also meticulously examines the use of both NG and hydrogen as a fuel in vehicles their production physical characteristics and combustion properties. It reviews the current experimental studies in the literature and investigates the results of using both fuels. It further covers the challenges associated with injectors needle valves lubrication spark plugs and safety requirements for both fuels. Finally the challenges related to the storage production and safety of both fuels are also discussed. The literature review reveals that NG in spark ignition (SI) engines has a clear and direct positive impact on fuel economy and certain emissions notably reducing CO2 and non-methane hydrocarbons. However its effect on other emissions such as unburnt hydrocarbons (UHC) nitrogen oxides (NOx) and carbon monoxide (CO) is less clear. NG which is primarily methane has a lower carbon-to-hydrogen ratio than diesel fuel resulting in lower CO2 emissions per unit of energy released. In contrast hydrogen is particularly well-suited for use in gasoline engines due to its high self-ignition temperature. While increasing the hydrogen content of NG engines reduces torque and power output higher hydrogen input results in reduced fuel consumption and the mitigation of toxic exhaust emissions. Due to its high ignition temperature hydrogen is not inherently suitable for direct use in diesel engines necessitating the exploration of alternative methods for hydrogen introduction into the cylinder. The literature review suggests that hydrogen in diesel engines has shown a reduction in specific exhaust emissions and fuel consumption and an increase in NOx emissions. Overall the paper provides a valuable and informative overview of the challenges and opportunities associated with using hydrogen and NG as fuels in IC engines. It highlights the need for further research and development to address the remaining challenges such as the development of more efficient combustion chambers and the reduction of NOx emissions.

This research conducted a probabilistic life-cycle assessment (pLCA) into the greenhouse gas (GHG) emissions performance of nine combinations of truck size and powertrain technology for a recent past and a future (largely decarbonised) situation in Australia. This study finds that the relative and absolute life-cycle GHG emissions performance strongly depends on the vehicle class powertrain and year of assessment. Life-cycle emission factor distributions vary substantially in their magnitude range and shape. Diesel trucks had lower life-cycle GHG emissions in 2019 than electric trucks (battery hydrogen fuel cell) mainly due to the high carbon-emission intensity of the Australian electricity grid (mainly coal) and hydrogen production (mainly through steam–methane reforming). The picture is however very different for a more decarbonised situation where battery electric trucks in particular provide deep reductions (about 75–85%) in life-cycle GHG emissions. Fuel-cell electric (hydrogen) trucks also provide substantial reductions (about 50–70%) but not as deep as those for battery electric trucks. Moreover hydrogen trucks exhibit the largest uncertainty in emissions performance which reflects the uncertainty and general lack of information for this technology. They therefore carry an elevated risk of not achieving the expected emission reductions. Battery electric trucks show the smallest (absolute) uncertainty which suggests that these trucks are expected to deliver the deepest and most robust emission reductions. Operational emissions (on-road driving and vehicle maintenance combined) dominate life-cycle emissions for all vehicle classes. Vehicle manufacturing and upstream emissions make a relatively small contribution to life-cycle emissions from diesel trucks (

A significant contribution to the reduction of carbon emissions will be enabled through the transition from a centralised fossil fuel system to a decentralised renewable electricity system. However due to the intermittent nature of renewable energy storage is required to provide a suitable response to dynamic loads and manage the excess generated electricity with utilisation during periods of low generation. This paper investigates the use of stationary hydrogen-based energy storage systems for microgrids and distributed energy resource systems. An exploratory study was conducted in Australia based on a mixed methodology. Ten Australian industry experts were interviewed to determine use cases for hydrogen-based energy storage systems’ requirements barriers methods and recommendations. This study suggests that the current cost of the electrolyser fuel cell and storage medium and the current low round-trip efficiency are the main elements inhibiting hydrogen-based energy storage systems. Limited industry and practical experience are barriers to the implementation of hydrogen storage systems. Government support could help scale hydrogen-based energy storage systems among early adopters and enablers. Furthermore collaboration and knowledge sharing could reduce risks allowing the involvement of more stakeholders. Competition and innovation could ultimately reduce the costs increasing the uptake of hydrogen storage systems.

Hydrogen has received tremendous global attention as an energy carrier and an energy storage system. Hydrogen carrier introduces a power to hydrogen (P2H) and power to hydrogen to power (P2H2P) facility to store the excess energy in renewable energy storage systems with the facts of large-scale storage capacity transportability and multiple utilities. This work examines the techno-economic feasibility of hybrid solar photovoltaic (PV)/hydrogen/fuel cell-powered cellular base stations for developing green mobile communication to decrease environmental degradation and mitigate fossil-fuel crises. Extensive simulation is carried out using a hybrid optimization model for electric renewables (HOMER) optimization tool to evaluate the optimal size energy production total production cost per unit energy production cost and emission of carbon footprints subject to different relevant system parameters. In addition the throughput and energy efficiency performance of the wireless network is critically evaluated with the help of MATLAB-based Monte-Carlo simulations taking multipath fading system bandwidth transmission power and inter-cell interference (ICI) into consideration. Results show that a more stable and reliable green solution for the telecommunications sector will be the macro cellular basis stations driven by the recommended hybrid supply system. The hybrid supply system has around 17% surplus electricity and 48.1 h backup capacity that increases the system reliability by maintaining a better quality of service (QoS). To end the outcomes of the suggested system are compared with the other supply scheme and the previously published research work for justifying the validity of the proposed system.

An adaptive response renewable energy plant (AREP) that provides grid balancing services and XeV station fuelling services (where “X” is any type) using renewable energy located in urban centres is described. The AREP has its own primary renewable energy sources and adapts operation in the short term to changing levels of excess or deficient energy on LV and MV electricity grids. The AREP adaptively responds by (1) storing excess energy in batteries for the short term and in hydrogen tanks after energy conversion by electrolysers for the long term; (2) returning power to the grid from either the AREP’s own primary (electron-based) energy sources or batteries and/or from hydrogen via conversion in fuel cells; (3) providing electricity for fast charging BeVs and PHeVs and hydrogen for FCeVs; and (4) exporting excess stored energy as hydrogen to domestic markets. The AREP also adapts over the long term by predictive planning of charging capacity such that the type and capacity of renewable energy equipment is optimised for future operations. A key advantage of this AREP configuration is a flexible “plug and play” capability with modular extension of energy assets. If the AREP footprint is constrained interaction with neighbouring AREPs as a mini-VPP-AREP network can assist in balancing short-term operating requirements. The benefits of this grid balancing and XeV renewable energy filling station or AREP are environmental social and economic through efficient functionality of appropriately sized components. AREPs provide a net zero emissions electricity solution to an existing network with short and long-term storage options as well as a net zero emissions fuel alternative to the transport sector while leveraging existing infrastructure with minimal upfront CAPEX. AREPs can give the flexibility a grid needs to enable high levels of renewable installations while developing green hydrogen production.

One of the benefits of the direct use of hydrogen is its ability to be burned in a similar way to natural gas using appliances with which the community is already familiar. This is particularly true for applications where electrification is neither practicable nor desirable. One common example is domestic cooking stoves where the open flame offers numerous real and perceived benefits to the chef. Similarly many commercial and industrial appliances rely on the unique properties of combustion to achieve a desired purpose that cannot readily be replaced by an alternative to an open flame. Despite the enormous decarbonisation potential of the direct replacement of natural gas with hydrogen there are some operational constraints due to the different burning characteristics of hydrogen. One of the challenges is the low visible light emission from hydrogen flames. The change in visible radiation from the combustion of hydrogen compared with natural gas is a safety concern whereby visual observation of a flame may be difficult. This paper aims to provide clarity on the visual appearance of hydrogen flames via a series of measurements of flame visibility and emission spectra accompanied by the assessment of strategies to improve the safe use of hydrogen.

Growth in Australia’s demand for engineers is fast outpacing supply. A significant challenge for Australia to achieve high projected low emissions hydrogen export targets by 2030 will be finding engineers with suitable knowledge skills and attributes to deliver hydrogen engineering projects safely and sustainably. This systematic review investigates educational outcomes needed to develop a hydrogen engineering workforce. Sixteen relevant studies published between 2003 and 2023 were identified to explore “What key knowledge skills and attributes support the development of a hydrogen engineering workforce?”. While these studies advocated the need for training and prescribed areas of required knowledge for the low-emissions hydrogen sector there was limited empirical evidence that informed what knowledge skills and attributes are relevant for entry to practice. This finding represents a significant opportunity for researchers to engage with employers and engineering practitioners within emerging low-emissions hydrogen sector capture empirical evidence and inform the design of educational programs.

This paper explores the skills landscape of the emerging green hydrogen industry in Australia drawing on data collected from a study that gathered insights on training gaps from a range of hydrogen industry participants. A total of 41 industry participants completed a survey and 14 of those survey respondents participated in industry consultations. The findings revealed widespread perceptions of training and skilling as being very important to the industry but under-provisioned across the sector. Data were analysed to consider the problem of skilling the green hydrogen industry and the barriers and enablers as perceived by industry stakeholders. In this paper we argue that urgent cross-sector attention needs to be paid to hydrogen industry training and skill development systems in Australia if the promise of green hydrogen as a clean energy source is to be realised.

Hydrogen fuel cells power a range of vehicles including cars buses trucks forklifts and even trains. As fuel cell electric vehicles emit no carbon emissions and only produce water vapor as a by-product they present an attractive option for countries who are experiencing high pollution from transport. This paper presents the findings of ten focus groups and a subset of a national survey which focused specifically on use of hydrogen in the transport sector (N=948). When discussing hydrogen transport options Australian focus group participants felt that rolling out hydrogen fuel cell buses as a first step for fuel cell electric vehicle deployment would be a good way to increase familiarity with the technology. Deploying hydrogen public transport vehicles before personal vehicles was thought to be a positive way to demonstrate the safe use of hydrogen and build confidence in the technology. At the same time it was felt it would allow any issues to be ironed out before the roll out of large-scale infrastructure on a to support domestic use. Long haul trucks were also perceived to be a good idea however safety issues were raised in the focus groups when discussing these vehicles. Survey respondents also expressed positive support for the use of hydrogen fuel cell buses and long-haul trucks. They reported being happy to be a passenger in a fuel cell bus. Safety and environmental benefits remained paramount with cost considerations being the third most important issue. Respondents supportive of hydrogen technologies were most likely to report purchasing a hydrogen vehicle over other options

Low-carbon hydrogen can play a significant role in decarbonizing the world. Hydrogen is currently mainly produced from fossil sources requiring additional CO2 capture to decarbonize which energy intense and costly. In a recent Green Energy & Environment paper Cheng and Di et al. proposed a novel integration process referred to as SECLRHC to generate high-purity H2 by in-situ separation of H2 and CO without using any additional separation unit. Theoretically the proposed process can essentially achieve the separation of C and H in gaseous fuel via a reconfigured reaction process and thus attaining high-purity hydrogen of ∼99% as well as good carbon and hydrogen utilization rates and economic feasibility. It displays an optimistic prospect that industrial decarbonization is not necessarily expensive as long as a suitable CCS measure can be integrated into the industrial manufacturing process.

A dedicated grid-tied offshore hybrid energy system for hydrogen production is a promising solution to unlock the full benefit of offshore wind and solar energy and realize decarbonization and sustainable energy security targets in electricity and other sectors. Current knowledge of these offshore hybrid systems is limited particularly in the integration component control and allocation aspects. Therefore a grid-integrated analytical model with a power dispatch allocation strategy between the grid and electrolyzer for the co-production of hydrogen from the offshore hybrid energy system is developed in this paper. While producing hydrogen the proposed offshore hybrid energy system supplies a percentage of its capacity to the onshore grid facility and the amount of the electricity is quantified based on the electricity market price and available total offshore generation. The detailed controls of each component are discussed. A case study considers a hypothetical hybrid offshore energy system of 10 MW situated in a potential offshore off the NSW of Australia based on realistic metrological data. A grid-scale proton-exchange membrane electrolyzer stack is used and a model predictive power controller is implemented on the distributed hydrogen generation scheme. The model is helpful for the assessment or optimization of both the economics and feasibility of the dedicated offshore hybrid energy farm for hydrogen production systems.

Countries around the world are prioritising net zero emissions to meet their Paris Agreement goals. The demand for social impact assessment (SIA) is likely to grow as this transition will require investments in decarbonisation projects with speed and at scale. There will be winners and losers of these projects because not everyone benefits the same; and hence trade-offs are inevitable. SIAs therefore should focus on understanding how the risks and benefits will be distributed among and within stakeholders and sectors and enable the identification of trade-offs that are just and fair. In this study we used a hypothetical case of large-scale hydrogen production in regional Australia and engaged with multi-disciplinary experts to identify justice issues in transitioning to such an industry. Using Rawlsian theory of justice as fairness we identified several tensions between different groups (national regional local inter and intra-communities) and sectors (environmental and economic) concerning the establishment of a hydrogen industry. These stakeholders and sectors will be disproportionately affected by this establishment. We argue that Rawlsian principles of justice would enable the practice of SIA to identify justice trade-offs. Further we conceptualise that a systems approach will be critical to facilitate a wider participation and an agile process for achieving just trade-offs in SIA.

Green Hydrogen (H2 via renewable-driven electrolysis) is emerging as a vector to meet net-zero emission targets provided it is produced with a low life cycle impact. While certification schemes for green H2 have been introduced they mainly focus on the embodied emissions from energy supply during electrolyser operation. This narrow focus on just operation is an oversight considering that a complete green H2 value chain also includes the electrolyser’s manufacturing transport/installation and end-of-life. Each step of this chain involves materials and energy flows that impart impacts that undermine the clean and sustainable status of H2. Therefore holistic and harmonised assessments of the green H2 production chain are required to ensure both economic and environmental deployment of H2. Herein we conduct an overarching environmental assessment encompassing the production chain described above using Australia as a case study. Our results indicate that while the energy source has the most impact material and manufacturing inputs associated with electrolyser production are increasingly significant as the scale of H2 output expands. Moreover wind power electrolysis has a greater chance of achieving green H2 certification compared to solar powered while increasing the amount of localised manufactured content and investment in end-of-life recycling of electrolyser components can reduce the overall life cycle impact of green H2 production by 20%.

The commercialization of hydrogen as a fuel faces severe technological economic and environmental challenges. As a method to overcome these challenges microalgal biohydrogen production has become the subject of growing research interest. Microalgal biohydrogen can be produced through different metabolic routes the economic considerations of which are largely missing from recent reviews. Thus this review briefly explains the techniques and economics associated with enhancing microalgae-based biohydrogen production. The cost of producing biohydrogen has been estimated to be between $10 GJ-1 and $20 GJ−1 which is not competitive with gasoline ($0.33 GJ−1 ). Even though direct biophotolysis has a sunlight conversion efficiency of over 80% its productivity is sensitive to oxygen and sunlight availability. While the electrochemical processes produce the highest biohydrogen (>90%) fermentation and photobiological processes are more environmentally sustainable. Studies have revealed that the cost of producing biohydrogen is quite high ranging between $2.13 kg−1 and 7.24 kg−1 via direct biophotolysis $1.42kg−1 through indirect biophotolysis and between $7.54 kg−1 and 7.61 kg−1 via fermentation. Therefore low-cost hydrogen production technologies need to be developed to ensure long-term sustainability which requires the optimization of critical experimental parameters microalgal metabolic engineering and genetic modification.

Ammonia plays a vital role in feeding the world through fertilizer production as well as having other industrial uses. However current ammonia production processes rely heavily on fossil fuels mostly natural gas to generate hydrogen as a feedstock. There is an urgent need to re-design and decarbonise the production process to reduce greenhouse emissions and avoid dependence on volatile gas markets and a depleting resource base. Renewable energy driven electrolysis to generate hydrogen provides a viable pathway for producing carbon-free or green ammonia. However a key challenge associated with producing green ammonia is managing low cost but highly variable wind and solar renewable energy generation for hydrogen electrolysis while maintaining reliable operation of the less flexible ammonia synthesis unit. To date green ammonia production has only been demonstrated at pilot scale and optimising plant configurations and scaling up production facilities is an urgent task. Existing feasibility studies have demonstrated the ability to model and cost green ammonia production pathways that can overcome the technical and economic challenges. However these existing approaches are context specific demonstrating the ability to model and cost green ammonia production for defined locations with set configurations. In this paper we present a modelling framework that consolidates the array of configurations previously studied into a single framework that can be tailored to the location of interest. Our open-source green ammonia modelling and costing tool dynamically simulates the integration of renewable energy with a wide range of balancing power and storage options to meet the flexible demands of the green ammonia production process at hourly time resolution over a year or more. Unlike existing models the open-source implementation of our tool allows it to be used by a potentially wide range of stakeholders to explore their own projects and help guide the upscaling of green ammonia as a pathway for decarbonisation. Using Gladstone in Australia as a case study a 1 million tonne per annum (MMTPA) green ammonia plant is modelled and costed using price assumptions for major equipment in 2030 provided by the Australian Energy Market Operator (AEMO). Using a hybrid (solar PV and wind) renewable energy source and Battery Energy Storage System as balancing technology we estimate a levelized cost of ammonia (LCOA) between 0.69 and 0.92 USD kgNH3 -1 . While greater than historical ammonia production costs from natural gas falling renewables costs and emission reduction imperatives suggest a major future role for green ammonia.

Steam methane reforming (SMR) using natural gas is the most commonly used technology for hydrogen production. Industrial hydrogen production contributes to pollutant emissions which may differ from the theoretical estimates due to process conditions type and state of installed pollution control equipment. The aim of this study was to estimate the impacts of hydrogen production using facilitylevel real emissions data collected from multiple US EPA databases. The study applied the ReCiPe2016 impact assessment method and considered 12 midpoint and 14 endpoint impacts for 33 US SMR hydrogen production facilities. Global warming impacts were mostly driven by CO2 emissions and contributed to 94.6% of the endpoint impacts on human health while global warming impact on terrestrial ecosystems contributed to 98.3% of the total endpoint impacts on ecosystems. The impacts estimated by direct emissions from the 33 facilities were 9.35 kg CO2e/kg H2 which increased to 11.2 kg CO2e/kg H2 when the full life cycle of hydrogen production including upstream emissions was included. The average global warming impact could be reduced by 5.9% and 11.1% with increases in hydrogen production efficiency by 5% and 10% respectively. Potential impact reductions are also found when natural gas hydrogen production feedstock is replaced by renewable sources with the greatest reduction of 78.1% found in hydrogen production via biomass gasification followed by 68.2% reduction in landfill gas and 53.7% reduction in biomethane-derived hydrogen production.

Energy plays a crucial role in the sustainable development of modern nations. Today hydrogen is considered the most promising alternative fuel as it can be generated from clean and green sources. Moreover it is an efficient energy carrier because hydrogen burning only generates water as a byproduct. Currently it is generated from natural gas. However it can be produced using other methods i.e. physicochemical thermal and biological. The biological method is considered more environmentally friendly and pollution free. This paper aims to provide an updated review of biohydrogen production via photofermentation dark fermentation and microbial electrolysis cells using different waste materials as feedstocks. Besides the role of nanotechnology in enhancing biohydrogen production is examined. Under anaerobic conditions hydrogen is produced during the conversion of organic substrate into organic acids using fermentative bacteria and during the conversion of organic acids into hydrogen and carbon dioxide using photofermentative bacteria. Different factors that enhance the biohydrogen production of these organisms either combined or sequentially using dark and photofermentation processes are examined and the effect of each factor on biohydrogen production efficiency is reported. A comparison of hydrogen production efficiency between dark fermentation photofermentation and two-stage processes is also presented.

Political decarbonisation commitments and outcompeting renewable electricity costs are disrupting energy systems. This foresight study prepares stakeholders for this dynamic reactive change by examining visions that constitute a probable plausible and possible component of future energy systems. Visions were extrapolated through an expert review of energy technologies and Australian case studies. ‘Probable–Abundant’ envisages a high penetration of solar and wind with increased value of balancing services: batteries pumped hydro and transmission. This vision is exemplified by the South Australian grid where variable and distributed sources lead generation. ‘Plausible–Traded’ envisages power and power fuel exports given hydrogen and high-voltage direct-current transmission advances reflected by public and private sector plans to leverage rich natural resources for national and intercontinental exchanges. ‘Possible–Zero’ envisages the application of carbon removal and nuclear technologies in response to the escalating challenge of deep decarbonisation. The Australian critical minerals strategy signals adaptations of high-emission industries to shifting energy resource values. These visions contribute a flexible accessible framework for diverse stakeholders to discuss uncertain energy systems changes and consider issues from new perspectives. Appraisal of preferred futures allows stakeholders to recognise observed changes as positive or negative and may lead to new planning aspirations.

This study investigates the impact of including (or neglecting) the variable efficiency of hydrogen electrolyzers as a function of operating power in the modelling of green hydrogen produced from variable renewable energy sources. Results show that neglecting the variable electrolyzer efficiency as is commonly done in studies of green hydrogen leads to significant overestimation of hydrogen production in the range of 5–24%. The effects of the time resolution used in models are also investigated as well as the impact of including the option for the electrolyzer to switch to stand-by mode instead of powering down and electrolyzer ramp rate constraints. Results indicate that these have a minor effect on overall hydrogen production with the use of hour resolution data leading to overestimation in the range of 0.2–2% relative to using 5-min data. This study used data from three solar farms and three wind in Australia from which it is observed that wind farms produced 55% more hydrogen than the solar farms. The results in this study highlight the critical importance of including the variable efficiency of electrolyzers in the modelling of green hydrogen production. As this industry scales continuing to neglect this effect would lead to the overestimation of hydrogen production by tens of megatonnes.

This study evaluates the levelised cost of hydrogen (LCOH) dynamically produced using the two dominant electrolysis technologies directly connected to wind turbines or photovoltaic (PV) panels in regions of Australia designated as hydrogen hubs. Hourly data are utilised to size the components required to meet the hydrogen demand. The dynamic efficiency of each electrolysis technology as a function of input power along with its operating characteristics and overload capacity are employed to estimate flexible hydrogen production. A sensitivity analysis is then conducted to capture the behaviour of the LCOH in response to inherent uncertainty in critical financial and technical factors. Additionally the study investigates the trade-offs between carbon cost and lifecycle emissions of green hydrogen. This approach is applied to ascertain the impact of internalising environmental costs on the cost-competitiveness of green hydrogen compared to grey hydrogen. The economic modelling is developed based on the Association for the Advancement of Cost Engineering (AACE) guidelines. The findings indicate that scale-up is key to reducing the LCOH by a meaningful amount. However scale-up alone is insufficient to reach the target value of AUD 3 (USD 2) except for PV-based plant in the Pilbara region. Lowered financial costs from scale-up can make the target value achievable for PV-based plants in Gladstone and Townsville and for wind-based plants in the Eyre Peninsula and Pilbara regions. For other hubs a lower electricity cost is required as it accounts for the largest portion of the LCOH.

Industry is the biggest sector of energy consumption and greenhouse gas emissions whose decarbonisation is essential to achieve the Sustainable Development Goals. Carbon capture energy efficiency improvement and hydrogen are among the main strategies for industrial decarbonization. However novel approaches are needed to address the key requirements and differences between sectors to ensure they can work together to well integrate industrial decarbonisation with heat CO2 and hydrogen. The emerging Calcium Looping (CaL) is attracting interest in designing CO2-involved chemical processes for heat capture and storage. The reversibility relatively high-temperature (600 to 900 ◦C) and high energy capacity output as well as carbon capture function make CaL well-fit for CO2 capture and utilisation and waste heat recovery from industrial flue gases. Meanwhile methane dry reforming (MDR) is a promising technology to produce blue hydrogen via the consumption of two major greenhouse gases i.e. CO2 and CH4. It has great potential to combine the two technologies to achieve insitu CO2 utilization with multiple benefits. In this paper progresses on the reaction conditions and performance of CaL for CO2 capture and industrial waste heat recovery as well as MDR were screened. Secondly recent approaches to CaL-MDR synergy have been reviewed to identify the advantages. The major challenges in such a synergistic process include MDR catalyst deactivation CaL sorbents sintering and system integration. Thirdly the paper outlooks future work to explore a rational design of a multi-function system for the proposed synergistic process.

The reliability of renewable hydrogen supply for off-take applications is critical to the future sustainable energy economy. Integrated water electrolysis can be deployed at distributed municipal wastewater treatment plants (WWTP) creating opportunity for reduction in carbon emissions through direct and indirect use of the electrolysis output. A novel energy shifting process where the co-produced oxygen is compressed and stored to enhance the utilisation of intermittent renewable electricity is analysed. The hydrogen produced can be used in local fuel cell electric buses to replace incumbent diesel buses for public transport. However quantifying the extent of carbon emission reduction of this conceptual integrated system is key. In this study the integration of hydrogen production at a case study WWTP of 26000 EP capacity and using the hydrogen in buses was compared with two conventional systems: the base case of a WWTP with grid electricity consumption offset by solar PV and the community’s independent use of diesel buses for transport and the non-integrated configuration with hydrogen produced at the bus refuelling location operated independently of the WWTP. The system response was analysed using a Microsoft Excel simulation model with hourly time steps over a 12-month time frame. The model included a control scheme for the reliable supply of hydrogen for public transport and oxygen to the WWTP and considered expected reductions in carbon intensity of the national grid level of solar PV curtailment electrolyser efficiency and size of the solar PV system. Results showed that by 2031 when Australia’s national electricity is forecast to achieve a carbon intensity of less than 0.186 kg CO2-e/kWh integrating water electrolysis at a municipal WWTP for producing hydrogen for use in local hydrogen buses produced less carbon emissions than continuing to use diesel buses and offsetting emissions by exporting renewable electricity to the grid. By 2034 an annual reduction of 390 t–CO2–e is expected after changing to the integrated configuration. Considering electrolyser efficiency improvements and curtailment of renewable electricity the reduction increases to 872.8 t–CO2–e.

Hydrogen-diesel dual direct-injection (H2DDI) engines present a promising pathway towards cleaner and more efficient transportation. In this study hydrogen split injection strategies were explored in an automotive-size single-cylinder compression ignition (CI) engine with a focus on varying the injection timings and energy fractions. The engine was operated at an intermediate load with fixed combustion phasing through adjustments of pilot diesel injection timing. An energy substitution principle guided the variation in energy fraction between the two hydrogen injections and then diesel injection while keeping the total energy input constant. The findings demonstrate that early first hydrogen injection timings lead to characteristics indicative of premixed combustion reflecting a high homogeneity of the hydrogen-air mixture. In contrast hydrogen stratification levels were predominantly influenced by later second injection timings with mixing-controlled combustion behaviour apparent for very late injections near top dead centre or when the second hydrogen injection held high energy fractions which led to decreased nitrogen oxides (NOx: NO and NO2) emissions. The carbon dioxide (CO2) emissions did not show high sensitivity to the hydrogen split injection strategies exhibiting about 77 % reduction compared to the diesel baseline due primarily to increased hydrogen energy fraction of up to 90 %

Underground Hydrogen Storage (UHS) is an emerging large-scale energy storage technology. Researchers are investigating its feasibility and performance including its injectivity productivity and storage capacity through numerical simulations. However several ad-hoc relative permeability and capillary pressure functions have been used in the literature with no direct link to the underlying physics of the hydrogen storage and production process. Recent relative permeability measurements for the hydrogen-brine system show very low hydrogen relative permeability and strong liquid phase hysteresis very different to what has been observed for other fluid systems for the same rock type. This raises the concern as to what extend the existing studies in the literature are able to reliably quantify the feasibility of the potential storage projects. In this study we investigate how experimentally measured hydrogen-brine relative permeability hysteresis affects the performance of UHS projects through numerical reservoir simulations. Relative permeability data measured during a hydrogen-water core-flooding experiment within ADMIRE project is used to design a relative permeability hysteresis model. Next numerical simulation for a UHS project in a generic braided-fluvial water-gas reservoir is performed using this hysteresis model. A performance assessment is carried out for several UHS scenarios with different drainage relative permeability curves hysteresis model coefficients and injection/production rates. Our results show that both gas and liquid relative permeability hysteresis play an important role in UHS irrespective of injection/production rate. Ignoring gas hysteresis may cause up to 338% of uncertainty on cumulative hydrogen production as it has negative effects on injectivity and productivity due to the resulting limited variation range of gas saturation and pressure during cyclic operations. In contrast hysteresis in the liquid phase relative permeability resolves this issue to some extent by improving the displacement of the liquid phase. Finally implementing relative permeability curves from other fluid systems during UHS performance assessment will cause uncertainty in terms of gas saturation and up to 141% underestimation on cumulative hydrogen production. These observations illustrate the importance of using relative permeability curves characteristic of hydrogen-brine system for assessing the UHS performances.

This current article discusses the technoeconomics (TE) of hydrogen generation transportation compression and storage in the Australian context. The TE analysis is important and a prerequisite for investment decisions. This study selected the Australian context due to its huge potential in green hydrogen but the modelling is applicable to other parts of the world adjusting the price of electricity and other utilities. The hydrogen generation using the most mature alkaline electrolysis (AEL) technique was selected in the current study. The results show that increasing temperature from 50 to 90 ◦C and decreasing pressure from 13 to 5 bar help improve electrolyser performance though pressure has a minor effect. The selected range for performance parameters was based on the fundamental behaviour of water electrolysers supported with literature. The levelised cost of hydrogen (LCH2 ) was calculated for generation compression transportation and storage. However the majority of the LCH2 was for generation which was calculated based on CAPEX OPEX capital recovery factor hydrogen production rate and capacity factor. The LCH2 in 2023 was calculated to be 9.6 USD/kgH2 using a base-case solar electricity price of 65–38 USD/MWh. This LCH2 is expected to decrease to 6.5 and 3.4 USD/kgH2 by 2030 and 2040 respectively. The current LCH2 using wind energy was calculated to be 1.9 USD/kgH2 lower than that of solar-based electricity. The LCH2 using standalone wind electricity was calculated to be USD 5.3 and USD 2.9 in 2030 and 2040 respectively. The LCH2 predicted using a solar and wind mix (SWM) was estimated to be USD 3.2 compared to USD 9.6 and USD 7.7 using standalone solar and wind. The LCH2 under the best case was predicted to be USD 3.9 and USD 2.1 compared to USD 6.5 and USD 3.4 under base-case solar PV in 2030 and 2040 respectively. The best case SWM offers 33% lower LCH2 in 2023 which leads to 37% 39% and 42% lower LCH2 in 2030 2040 and 2050 respectively. The current results are overpredicted especially compared with CSIRO Australia due to the higher assumption of the renewable electricity price. Currently over two-thirds of the cost for the LCH2 is due to the price of electricity (i.e. wind and solar). Modelling suggests an overall reduction in the capital cost of AEL plants by about 50% in the 2030s. Due to the lower capacity factor (effective energy generation over maximum output) of renewable energy especially for solar plants a combined wind- and solar-based electrolysis plant was recommended which can increase the capacity factor by at least 33%. Results also suggest that besides generation at least an additional 1.5 USD/kgH2 for compression transportation and storage is required.

The necessity of energy solutions that are economically viable ecologically sustainable and environmentally friendly has become fundamental to economic and societal advancement of nations. In this context renewable energy sources emerge as the most vital component. Furthermore hydrogen generation systems based on renewable energies are increasingly recognized as the most crucial strategies to mitigate global warming. In the present study a comparative analysis is conducted from an exergy-economic perspective to find the most efficient configuration among three different systems for renewable-based power to hydrogen production. These renewable sources are wind turbine salinity gradient solar pond (SGSP) and ocean thermal energy conversion (OTEC). SGSP and OTEC are coupled with a hydrogen production unit by a trilateral cycle (TLC) to improve the temperature match of the heating process. The heat waste energy within these systems is recovered by a thermoelectric generator (TEG) and a proton exchange membrane electrolyzer (PEME) is used for hydrogen production. Under base case input conditions the net power input of PEME is estimated to be approximately 327.8 kW across all configurations. Additionally the 3E (energy exergy and exergy-economic) performance of the three systems is evaluated by a parametric study and design optimization. The results of the best performance analysis reveal that the best exergy efficiency is achievable with the wind-based system in the range of 5.8–10.47% and for average wind speed of 8–12 m/s. Correspondingly the most favorable total cost rate is attributed to the wind-based system at a wind speed of 8 m/s equating to 66.08 USD/h. Subsequently the unit cost of hydrogen for the SGSP-based system is estimated to be the most economical ranging from 42.78 to 44.31 USD/GJ.

A range of existing and newly developed hydrogen standards certification and labelling (SCL) schemes aim to promote the role of ‘renewable’ ‘clean’ or ‘green’ hydrogen in decarbonising energy transitions. This paper analyses a sample of these SCLs to assess their role in the scaling up of renewable hydrogen and its derivatives. To analyse these hydrogen SCLs we embellish a novel conceptual framework that brings together Sustainability Systems Thinking and Governance (SSG) literatures. The results reveal noteworthy scheme differences in motivation approach criteria and governance; highlighting the complex interconnected and dynamic reality within which energy systems are embedded. We consider whether the sustainable utilisation of renewable hydrogen is well-served by the proliferation of SCLs and recommend an SSG-informed approach. An SSG approach will better promote collaboration towards an authoritative global multistakeholder compromise on hydrogen certification that balances economic considerations with social and environmental dimensions.