United Kingdom

Recent targets have increased pressure for the maritime sector to accelerate the uptake of clean fuels. A potential future fuel for shipping is hydrogen however there is a common perception that the volume requirements for this fuel are too large for deep sea shipping. This study has developed a range of techniques to accurately simulate the fuel requirements of hydrogen for a case study vessel. Hydrogen can use fuel cells which achieve higher efficiencies than combustion methods but may require a battery hybrid system to meet changes in demand. A series of novel models for different fuel cell types and other technologies have been developed. The models have been used to run dynamic simulations for different energy system setups. Simulations tested against power profiles from real-world shipping data to establish the minimum viable setup capable of meeting all the power demand for the case study vessel to a higher degree of accuracy than previously achieved. Results showed that the minimum viable setup for hydrogen was with liquid storage a 105.6 MW PEM fuel cell stack and 6.9 MWh of batteries resulting in a total system size of 8934 m3 . Volume requirement results could then be compared to other concepts such as systems using ammonia and methanol 8970 m3 and 6033 m3 respectively.

Hydrogen is emerging as one of the most promising energy carriers for a decarbonised global energy system. Transportation and storage of hydrogen are critical to its large-scale adoption and to these ends liquid hydrogen is being widely considered. The liquefaction and storage processes must however be both safe and efficient for liquid hydrogen to be viable as an energy carrier. Identifying the most promising liquefaction processes and associated transport and storage technologies is therefore crucial; these need to be considered in terms of a range of interconnected parameters ranging from energy consumption and appropriate materials usage to considerations of unique liquid-hydrogen physics (in the form of ortho–para hydrogen conversion) and boil-off gas handling. This study presents the current state of liquid hydrogen technology across the entire value chain whilst detailing both the relevant underpinning science (e.g. the quantum behaviour of hydrogen at cryogenic temperatures) and current liquefaction process routes including relevant unit operation design and efficiency. Cognisant of the challenges associated with a projected hydrogen liquefaction plant capacity scale-up from the current 32 tonnes per day to greater than 100 tonnes per day to meet projected hydrogen demand this study also reflects on the next-generation of liquid-hydrogen technologies and the scientific research and development priorities needed to enable them.

Environmental concerns such as global warming and human health damage are intensifying and the transportation sector significantly contributes to carbon and harmful emissions. This review examines the life cycle assessment (LCA) of alternative fuels (AF) evaluating current research on fuel types LCA framework development life cycle inventory (LCI) and impact selection. The objectives of this paper are: (1) to compare various AF LCA frameworks and develop a comprehensive framework for the transportation sector; (2) to identify emission hotspots of different AFs through simulations and real-world cases; (3) to review AF LCA research; (4) to extract valuable information for potential future research directions. The analysis reveals that all stages except for hydrogen use have an environmental impact. LCA boundaries and LCIs vary considerably depending on the raw materials production processes and products involved leading to different emission hotspots. Due to knowledge or data limitations some stages remain uncalculated in the current study emphasizing the need for further refinement of the AF LCI. Future research should also explore the various impacts of widespread adoption of alternative fuels in transportation encompassing social economic and environmental aspects. Lastly the review provides structured recommendations for future research directions.

The integration of wind and solar energy with green hydrogen technologies represents an innovative approach toward achieving sustainable energy solutions. This review examines state-ofthe-art strategies for synthesizing renewable energy sources aimed at improving the efficiency of hydrogen (H2 ) generation storage and utilization. The complementary characteristics of solar and wind energy where solar power typically peaks during daylight hours while wind energy becomes more accessible at night or during overcast conditions facilitate more reliable and stable hydrogen production. Quantitatively hybrid systems can realize a reduction in the levelized cost of hydrogen (LCOH) ranging from EUR 3.5 to EUR 8.9 per kilogram thereby maximizing the use of renewable resources but also minimizing the overall H2 production and infrastructure costs. Furthermore advancements such as enhanced electrolysis technologies with overall efficiencies rising from 6% in 2008 to over 20% in the near future illustrate significant progress in this domain. The review also addresses operational challenges including intermittency and scalability and introduces system topologies that enhance both efficiency and performance. However it is essential to consider these challenges carefully because they can significantly impact the overall effectiveness of hydrogen production systems. By providing a comprehensive assessment of these hybrid systems (which are gaining traction) this study highlights their potential to address the increasing global energy demands. However it also aims to support the transition toward a carbon-neutral future. This potential is significant because it aligns with both environmental goals and energy requirements. Although challenges remain the promise of these systems is evident.

Using high-resolution micro-CT imaging at 2.98 μm/voxel we compared the percolation of hydrogen in gas injection with gas expansion for a hydrogen-brine system in Bentheimer sandstone at 1 MPa and 20 ◦C representing hydrogen storage in an aquifer. We introduced dimensionless numbers to quantify the contribution of advection and expansion to displacement. We analysed the 3D spatial distribution of gas and its displacement in both cases and demonstrated that in gas injection hydrogen can only advance from a connected cluster in an invasion-percolation type process while in gas expansion hydrogen can access more of the pore space even from disconnected clusters. The average gas saturation in the sample increased from 30% to 50% by gas expansion and we estimated that 10% of the expanded volume is attributed to hydrogen exsolution from the brine. This work emphasises the importance of studying the combined effects of pressure decline and gas withdrawal in hydrogen storage to assess the influence of gas expansion on remobilising trapped gases.

This paper aims at the development and validation of a computational fluid dynamic (CFD) model for simulations of the refuelling process through the entire equipment of the hydrogen refuelling station (HRS). The absence of such models hinders the design of inherently safer refuelling protocols for an arbitrary combination of HRS equipment hydrogen storage parameters and environmental conditions. The CFD model is validated against the complete process of refuelling lasting 195s in Test No.1 performed by the National Renewable Energy Laboratory (NREL). The test equipment includes high-pressure tanks of HRS pressure control valve (PCV) valves pipes breakaway hose and nozzle all the way up to three onboard tanks. The model accurately reproduced hydrogen temperature and pressure through the entire line of HRS equipment. A standout feature of the CFD model distinguishing it from simplified models is the capability to predict temperature non-uniformity in onboard tanks a crucial factor with significant safety implications.

Hydrogen plays an important role in the global transition towards Net-Zero emission. While pipelines are a viable option to transport large quantities of compressed hydrogen over long distances it is not always practical in many applications. In such situations a viable option is to transport and deliver large quantities of hydrogen as cryogenic liquid. The liquefaction process cools hydrogen to cryogenic temperatures below its boiling point of -259.2 0C. Such extreme low temperature implies specific hazards and risks which are different from those associated with the relatively well-known compressed gaseous hydrogen. Managing these specific issues brings new challenges for the stakeholders.<br/>Furthermore the transfer of liquid hydrogen (LH2) and its technical handling is relatively well known for industrial gas or space applications. Experience with LH2 in public and populated areas such as truck and aircraft refuelling stations or port bunkering stations for example is limited or non-existent. Safety requirements in these applications which involve or are in proximity of untrained public are different from rocket/aerospace industry.<br/>The manuscript reviews knowhow already gained by the international hydrogen safety community; and on such basis elucidate the gaps which are yet to be filled to meet industry needs to design and operate inherently safe LH2 operations including the implications for regulations codes and standards (RCS). Where relevant the associated gaps in some underpinning sciences will be mentioned; and the need to contextualise the information and safety practices from NASA1/ESA2/JAXA3 to inform risk adoption will be summarised.

The large deployment of hydrogen technologies for new applications such as heat power mobility and other emerging industrial utilizations is essential to meet targets for CO2 reduction. This will lead to an increase in the number of hydrogen installations nearby local populations that will handle hydrogen technologies. Local regulations differ and provide different safety and/or separation distances in different geographies. The purpose of this work is to give an insight on different methodologies and recommendations developed for hydrogen (mainly) risk management and consequences assessment of accidental scenarios. The first objective is to review available methodologies and to identify the divergent points on the methodology. For this purpose a survey has been launched to obtain the needed inputs from the subtask participants. The current work presents the outcomes of this survey highlighting the gaps and suggesting the prioritization of the actions to take to bridge these gaps.

This project an essential part of the National Gas HyNTS programme endeavours to align the NTS with GB’s net zero ambitions by demonstrating the operational viability of the system with varying hydrogen blends using decommissioned assets typical of the natural gas network today ultimately aiming for 100% hydrogen conveyance. Several desktop studies were undertaken within the HyNTS programme to confirm the theoretical potential of the NTS to transport hydrogen safely and reliably. Further to these studies practical demonstration was deemed necessary to bridge the knowledge gaps and ensure the system’s transition maintains the utmost safety and reliability standards. A range of tests on decommissioned assets were conducted offline in a controlled environment to ensure robust outcomes that will ultimately start to build the safety case for a hydrogen network. The key deliverables and testing achievements of FutureGrid included: • Operational testing with natural gas and 2% 5% 20% and 100% hydrogen to verify the network’s ability to transport hydrogen and varying blends. • Standalone offline testing modules complementing evidence gathered on the main test facility. These address specific areas of concern including material permeation flange integrity asset leakage and rupture consequence which are essential for risk mitigation and safety assurance. FutureGrid is a global first facility and a critical part of National Gas’ hydrogen programme providing physical evidence of the capability of our network to transport hydrogen. It provides key evidence for hydrogen blending alongside 100% hydrogen pipelines which are planned under Project Union our Hydrogen Backbone across GB. FutureGrid is pivotal in the journey to reaching Net Zero by 2050 and is a fully operational proven technical demonstrator. FutureGrid’s repurposed assets are representative of today’s live high pressure gas network and have been subjected to testing at different blends of natural gas with hydrogen and 100% hydrogen; this was achieved with no major findings in differences in terms of how the assets interact with hydrogen. The overall project completion date was delayed from November 2023 to February 2024 due to technical issues with the newly built hydrogen re‑compressor. There were no changes made to the project costs.

As countries work towards achieving net-zero emissions the need for cleaner fuels has become increasingly urgent. Hydrogen produced from fossil fuels with carbon capture and storage (blue hydrogen) has the potential to play a significant role in the transition to a low-carbon economy. This study examined the technical and economic potential of blue hydrogen produced at 600 MWth(LHV) and scaled up to 1000 MWth(LHV) by benchmarking sorption-enhanced steam reforming process against steam methane reforming (SMR) autothermal gasheated reforming (ATR-GHR) integrated with carbon capture and storage (CCS) and SMR with CCS. Aspen Plus® was used to develop the process model which was validated using literature data. Cost sensitivity analyses were also performed on two key indicators: levelised cost of hydrogen and CO2 avoidance cost by varying natural gas price electricity price CO2 transport and storage cost and carbon price. Results indicate that at a carbon price of 83 £/tCO2e the LCOH for SE-SR of methane is the lowest at 2.85 £/kgH2 which is 12.58% and 22.55% lower than that of ATR-GHR with CCS and SMR plant with CCS respectively. The LCOH of ATR-GHR with CCS and SMR plant with CCS was estimated to be 3.26 and 3.68 £/kgH2 respectively. The CO2 avoidance cost was also observed to be lowest for SE-SR followed by ATR-GHR with CCS then SMR plant with CCS and was observed to reduce as the plant scaled to 1000 MWth(LHV) for these technologies.