Publications

Hydrogen has become a key enabler for decarbonization as countries pledge to reach net zero carbon emissions by 2050. With hydrogen infrastructure expanding rapidly beyond its established applications there is a requirement for robust safety practices solutions and regulations. Since the 1980s considerable efforts have been undertaken by the nuclear community to address hydrogen safety issues because in severe accidents of water-cooled nuclear reactors a large amount of hydrogen can be produced from the oxidation of metallic components with steam. As evidenced in the Fukushima accident hydrogen combustion can cause severe damage to reactor building structures promoting the release of radioactive fission products to the environment. A number of large-scale experiments were conducted in the framework of national and international projects to understand the hydrogen dispersion and combustion behaviour under postulated accidental conditions. Empirical engineering models and numerical codes were developed and validated for safety analysis. Hydrogen recombiners known as Passive Autocatalytic Recombiner (PAR) were developed and have been widely installed in nuclear containments to mitigate hydrogen risk. Complementary actions and strategies were established as part of severe accident management guidelines to prevent or limit the consequences of hydrogen explosions. In addition hydrogen monitoring systems were developed and implemented in nuclear power plants. The experience and knowledge gained from the nuclear community on hydrogen safety is valuable and applicable for other industries involving hydrogen production transport storage and use.

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 (H2) production combined with carbon capture and storage (CCS) is anticipated to be an important technology contributing to reduce the carbon footprint of current fossil-based H2 production systems. This work addresses for the first time the techno-environmental assessment of a CCS process based on the ionic liquid [Bmim][Acetate] for H2 production by steam methane reforming (SMR) and the comparison to conventional amine-based systems. Two different SMR plants using MDEA or [Bmim][Acetate] for CO2 capture were rigorously modelled using Aspen Plus to compute material and energy needs and emissions. Literature and simulation results were then used to perform a life cycle impact assessment (LCIA) of these processes based on the ReCiPe model. Solvent synthesis CCS process and hydrogen production stages were considered for the cradle-to-gate analysis. Results showed that although [Bmim][Acetate] is a priori more harmful to the environment than amines (in a kg-to-kg comparison) LCIAs carried out for both CCS processes showed from 5 to 17 % lower environmental impacts values for all estimated categories when using [Bmim][Acetate] due to a 9.4 % more energy-efficient performance than MDEA which also reduced a 17.4 % the total utility cost. Indeed if a typical amine loss rate of 1.6 kg/tCO2 is assumed the values of the environmental impacts increase up to 14 % for the IL-based CCS plant but still maintaining its favorable results over MDEA. As consequence the SMR plant with the IL-based CCS system exhibited 3–20 % lower values for most of the studied impact categories. These results contribute to shed some light on evaluating the sustainability of ILs with respect to conventional solvents for CO2 capture and to guide the synthesis of new more sustainable ILs but also they would be used to compare the environmental burdens from the synthesis and process performance of other promising ILs for CO2 capture that are not environmentally assed yet.

Green energy is at the forefront of current policy research and engineering but some of the potential fuels require either a lot of deeper research or a lot of infrastructure before they can be implemented. In the case of hydrogen both are true. This report aims to analyse the potential of hydrogen as a future fuel source by performing a life-cycle assessment. Through this the well-to-tank phase of fuel production and the usage phase of the system have been analysed. Models have also been created for traditional fuel systems to best compare results. The results show that hydrogen has great potential to convert marine transport to operating off green fuels when powered through low-carbon energy sources which could reduce a huge percentage of the international community’s greenhouse gas emissions. Hydrogen produced through wind powered alkaline electrolysis produced emission data 5.25 g of CO2 equivalent per MJ compared to the 210 g per MJ produced by a medium efficiency diesel equivalent system a result 40 times larger. However with current infrastructure in most countries not utilising a great amount of green energy production the effects of hydrogen usage could be more dangerous than current fuel sources owing to the incredible energy requirements of hydrogen production with even grid (UK) powered electrolysis producing an emission level of 284 g per MJ which is an increase against standard diesel systems. From this the research concludes that without global infrastructure change hydrogen will remain as a potential fuel rather than a common one.

To contribute to a more diverse and efficient energy infrastructure large quantities of hydrogen are requested for industries (e.g. mining refining fertilizers…). These applications need large scale facilities such as dozens of electrolyzer stacks from atmospheric pressure to 30 bar with a total capacity ranging from 100 up to 400 MW and associated hydrogen storage from a few to 50 tons.

Local use can be fed by electrolyzer in 20 feet container and stored in bundles with small volumes. Nevertheless industrial applications can request much bigger capacity of production which are generally located in buildings. The different technologies available for the production of hydrogen at large scale are alkaline or PEM electrolyzer with for example 100 MW capacity in a building of 20000 m3 and hydrogen stored in tube trailers or other fixed hydrogen storage solution with large volumes.

These applications led to the use of hydrogen inside large but confined spaces with the risk of fire and explosion in case of loss of containment followed by ignition. This can lead to severe consequences on asset workers and public due to the large inventories of hydrogen handled.

This article aims to provide an overview of the strategy to safely design large scale hydrogen production facilities in buildings through benchmarks based on projects and literature reviews best practices & standards regulations. It is completed by a risk assessment taking into consideration hydrogen behavior and influence of different parameters in dispersion and explosion in large buildings.

This article provides recommendations for hydrogen project stakeholders to perform informed-based decisions for designing large scale production buildings. It includes safety measures as reducing hydrogen inventories inside building allocating clearance around electrolyzer stacks implementing early detection and isolation devices and building geometry to avoid hydrogen accumulation.

Hybrid renewable hydrogen energy systems could play a key role in delivering sustainable solutions for enabling the Net Zero ambition; however the lack of exact computational modelling tools for sizing the integrated system components and simulating their real-world dynamic behaviour remains a key technical challenge against their widespread adoption. This paper addresses this challenge by developing a precise dynamic model that allows sizing the rated capacity of the hybrid system components and accurately simulating their real-world dynamic behaviour while considering effective energy management between the grid-integrated system components to ensure that the maximum possible proportion of energy demand is supplied from clean sources rather than the grid. The proposed hybrid system components involve a solar PV system electrolyser pressurised hydrogen storage tank and fuel cell. The developed hybrid system model incorporates a set of mathematical models for the individual system components. The developed precise dynamic model allows identifying the electrolyser’s real-world hydrogen production levels in response to the input intermittent solar energy production while also simulating the electrochemical behaviour of the fuel cell and precisely quantifying its real-world output power and hydrogen consumption in response to load demand variations. Using a university campus case study building in Scotland the effectiveness of the developed model has been assessed by benchmarking comparison between its results versus those obtained from a generic model in which the electrochemical characteristics of the electrolyser and fuel cell systems were not taken into consideration. Results from this comparison have demonstrated the potential of the developed model in simulating the real-world dynamic operation of hybrid solar hydrogen energy systems for grid-connected buildings while sizing the exact capacity of system components avoiding oversizing associated with underutilisation costs and inaccurate simulation.

This document is phase 2 of the energy storage strategy study and it covers the storage challenges of the energy transition. We start in section 3 by covering historical and current natural gas imports into the UK and what these could look like in the future. In section 4 we explore what demand for hydrogen could look like – this has a high level of uncertainty and future policy decisions will have significant impacts on hydrogen volumes and annual variations. We generated two hydrogen storage scenarios based on National Grid’s Future Energy Scenarios and the Climate Change Committee’s Sixth Carbon Budget to assess the future need for hydrogen storage in the UK. We also looked at an extreme weather scenario resulting from an area of high-pressure settled over the British Isles resulting in very low ambient temperatures an unusually high demand for heating and almost no wind generation. In section 5 we investigate options for hydrogen storage and build on work previously carried out by SGN. We discuss the differences between the properties of hydrogen and natural gas and how this affects line pack and depletion of line pack. We discuss flexibility on the supply and demand side and how this can impact on hydrogen storage. We provide a summary table which compares the various options for storage. In section 5 we explore hydrogen trade and options for import and export. Using information from other innovation projects we also discuss production of hydrogen from nuclear power and the impact of hybrid appliances on gas demand for domestic heat. In section 7 we discuss the outputs from a stakeholder workshop with about 40 stakeholders across industry academia and government. The workshop covered UK gas storage strategy to date hydrogen demand and corresponding storage scenarios to 2050 including consideration of seasonal variation and storage options.

An accurate estimation of the effective thermal conductivity of various insulation materials is essential in the evaluation of heat leak and boil-off rate from liquid hydrogen storage tanks. In this work we review the existing experimental data and various proposed correlations for predicting the effective conductivity of insulation systems consisting of powders foams fibrous materials and multilayer systems. We also propose a first principles-based correlation that may be used to estimate the dependence of the effective conductivity as a function of temperature interstitial gas composition pressure and structural properties of the material. We validate the proposed correlation using available experimental data for some common insulation materials. Further improvements and testing of the proposed correlation using laboratory scale data obtained using potential LH2 tank insulation materials are also discussed.

Utilizing renewable energy sources (RESs) such as wind and solar to convert electrical energy into hydrogen energy can promote the accommodation of green electricity. This paper proposes an optimal capacity planning approach for an industrial electricity-hydrogen multi-energy system (EHMES) aimed to achieve the local utilization of RES and facilitate the transition to carbon reduction in industrial settings. The proposed approach models the EHMES equipment in detail and divides the system’s investment and operation into producer and consumer sides with energy trading for effective integration. Through this effort the specialized management for different operators and seamless incorporation of RES into industrial users can be achieved. In addition the variations in investment and operating costs of equipment across different installed capacities are considered to ensure a practical alignment with real-world scenarios. By conducting a detailed case study the influence of various factors on the capacity configuration outcomes within an EHMES is analyzed. The results demonstrate that the proposed method can effectively address the capacity configuration of equipment within EHMES based on the local accommodation of RES and variable unit cost sequence. Wind power serves as the primary source of green electricity in the system. Energy storage acts as crucial equipment for enhancing the utilization rate of RES.

Current hydrogen stations are using a constant dispenser pressure ramp rate method. When a flow rate increases for heavy duty vehicle a large pressure loss occurs and it slows down refueling. This study developed a new method (cTPR method) that has the constant pressure ramp rate in the tank by compensating for the tube pressure loss without any feedback from the vehicle. A refueling simulation confirmed that a refueling was shortened − 49s with a lower ending gas temperature. Testing confirmed that the cTPR method can be realized simply by changing the control without any hardware modification.