Australia

Hydrogen has been long known to provide a solution toward clean energy systems. With this notion many efforts have been made to find new ways of storing hydrogen. As a result decades of studies has led to a wide range of hydrides that can store hydrogen in a solid form. Applications of these solid-state hydrides are well-suited to stationary applications. However the main challenge arises in making the selection of the Metal Hydrides (MH) that are best suited to meet application requirements. Herein we discuss the current state-of-art in controlling the properties of room temperature (RT) hydrides suitable for stationary application and their long term behavior in addition to initial activation their limitations and emerging trends to design better storage materials. The hydrogen storage properties and synthesis methods to alter the properties of these MH are discussed including the emerging approach of high-entropy alloys. In addition the integration of intermetallic hydrides in vessels their operation with fuel cells and their use as thermal storage is reviewed.

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.

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.

Hydrogen gas can provide baseload energy as society decarbonizes through the energy transition. Underground Hydrogen Storage (UHS) will be secure convenient and scalable to accommodate excess hydrogen production or compensate temporary shortfalls in energy supply. Hydrogen is a gas under all viable subsurface conditions so is invasive mobile and low-density. Methane and CO2 are also stored underground but storage parameters differ for each affecting the balance of geological storage risks. UHS in Australia is most likely to utilise conventional sedimentary reservoir rocks bound by conventional trapping closures. Hydrogen energy density will affect the competitiveness of UHS against purpose-built surface storage or solution-mined salt cavities. This study presents an overview of key considerations when screening for UHS opportunities and evaluates them for five Australian sedimentary basins. A threshold storage depth mapped across them reveals that the most prospective UHS basins will have to function as integrated energy fluid resource systems.

This study examines the structural chemical and hydrogen storage properties of graphitic carbon nitride (gC3N4) nanotubes synthesized via a novel grinding-solution-synthesis (GSS) method which involve two consecutive precursor mixing processes: grinding and solution mixing. The impact of grinding duration on morphology surface area and hydrogen storage capacity was analyzed. X-ray diffraction (XRD) confirmed characteristic (100) and (002) peaks at ~13.1◦ and 28.0◦ respectively. Fourier-transform infrared (FTIR) spectroscopy identified tri-s-triazine heterocycles and hydrogen-bonded amino groups with a new peak at 1650 cm− 1 suggesting structural modifications. X-ray photoelectron spectroscopy (XPS) confirmed elemental composition with minor bonding variations. Nitrogen adsorption/desorption analyses showed that the 30-min ground sample (B1G30) had the highest specific surface area (321 m2 g-1) and pore volume (1.07 cm3 /g) while prolonged grinding (60–90 min) caused nanotube degradation reducing these properties. Scanning and transmission electron microscopy (SEM/TEM) confirmed nanotubular morphology with decreasing diameters and increasing structural collapse at longer grinding durations. Hydrogen storage tests revealed B1G30 exhibited the highest capacity (0.81 wt% at 3.7 MPa) decreasing with extended grinding (B1G60: 0.79 wt% B1G90: 0.75 wt%) due to structural collapse. Extrapolated data suggested B1G30 could reach ~4.0 wt% at 10 MPa. These findings underscore the importance of nanotube integrity in optimizing hydrogen adsorption and highlight g-C3N4 nanotubes’ potential for hydrogen storage applications. This GSS technique presents a cost-effective method for industrial-scale fabrication of high-surface-area g-C3N4 nanotubes enabling their large-scale use in energy storage carbon capture photocatalysis and other applications.

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.

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.

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.

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.

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.