Publications

Hydrogen produced by renewable energy sources (green hydrogen) is at the centrepiece of European decarbonization strategies necessitating large imports from third countries. Egypt potentially stands out as major production hub. While technical and economic viability are broadly discussed in literature analyses of local acceptance are absent. This study closes this gap by surveying 505 locals in the Suez Canal Economic Zone (Port Said and Suez) regarding their attitudes towards renewable energy development and green hydrogen production. We find overall support for both national deployment and export to Europe. Respondents see a key benefit in rising income thereby strongly underlying the economic argument. Improved trade relationships or improved political relationships are seen as potential benefits of export but as less relevant for engaging in cooperation putting a spotlight on local benefits. Our study suggests that the local population is more positive than negative towards the development and scaling up of green hydrogen projects in Egypt.

With the continuous development of hydrogen storage systems power-to-gas (P2G) and combined heat and power (CHP) the coupling between electricity–heat–hydrogen–gas has been promoted and energy conversion equipment has been transformed from an independent operation with low energy utilization efficiency to a joint operation with high efficiency. This study proposes a low-carbon optimization strategy for a multi-energy coupled IES containing hydrogen energy storage operating jointly with a two-stage P2G adjustable thermoelectric ratio CHP. Firstly the hydrogen energy storage system is analyzed to enhance the wind power consumption ability of the system by dynamically absorbing and releasing energy at the right time through electricity–hydrogen coupling. Then the two-stage P2G operation process is refined and combined with the CHP operation with an adjustable thermoelectric ratio to further improve the low-carbon and economic performance of the system. Finally multiple scenarios are set up and the comparative analysis shows that the addition of a hydrogen storage system can increase the wind power consumption capacity of the system by 4.6%; considering the adjustable thermoelectric ratio CHP and the twostage P2G the system emissions reduction can be 5.97% and 23.07% respectively and the total cost of operation can be reduced by 7.5% and 14.5% respectively.

The decarbonization of industry heating and transportation is a major challenge for many countries’ energy transition. Hydrogen is a direct low-carbon fuel alternative to natural gas offering a higher flexibility in the range of possible applications yet currently most hydrogen is produced using carbonintensive steam methane reforming due to cost considerations. Therefore this study explores the economics of a prominent low-carbon method of hydrogen production comparing the cost of hydrogen generation from offshore wind farms with and without grid electricity imports to conventional hydrogen production methods. A novel techno-economic model for offshore electrolysis production costs is presented which makes hydrogen production fully dispatchable leveraging geological salt-cavern storage. This model determines the lifetime costs aportioned across the system components as well as the Levelized Cost of Hydrogen (LCOH). Using the United Kingdom as a case study LCOH from offshore wind power is calculated to be €8.68 /kgH2 using alkaline electrolysis (AEL) €10.49 /kgH2 using proton exchange membrane electrolysis (PEMEL) and €10.88 /kgH2 with grid electricity to backup the offshore wind power. A stochastic Monte-Carlo model is used to asses the uncertainty on costs and identify the cost of capital electrolyser and wind farm capital costs and cost of electricity as the most important drivers of LCOH across the different scenarios. Reducing the capital cost to comparative levels observed on today’s wind farms alone could see AEL LCOH fall to €5.32 /kgH2 near competitive with conventional generation methods.

Following the growing use of hydrogen in the industry gas explosions have become a critical safety issue. Computational Fluid Dynamic (CFD) and in particular the Large Eddy Simulation (LES) approach have already shown their great potential to reproduce such scenarios with high fidelity. However the computational cost of this approach is an obvious limiting factor since fine grid resolutions are often required in the whole computational domain to ensure a correct numerical resolution of the deflagration front all along its propagation. In this context Adaptive Mesh Refinement (AMR) is of great interest to reduce the computational cost as it allows to dynamically refine the mesh throughout the explosion scenario only in regions where Quantities of Interest (QoI) are detected. This study aims to demonstrate the strong potential of AMR for the LES of explosions. The target scenario is a hydrogen-air explosion in the GraVent explosion channel [1]. Using the massively parallel Navier- Stokes compressible solver AVBP a reference simulation is first obtained on a uniform and static unstructured mesh. The comparison with the experiments shows a good agreement in terms of absolute flame front speed overpressure and flow visualisation. Then an AMR simulation is performed targeting the same resolution as the reference simulation only in regions where QoI are detected i.e. inside the reaction zones and vortical structures. Results show that the accuracy of the reference simulation is recovered with AMR for only 12% of its computational cost.

The use of liquid hydrogen in maritime applications is expected to grow in the coming years in order to meet the decarbonisation goals that EU countries and countries worldwide have set for 2050. In this context The Norwegian Public Roads Administration commissioned large-scale LH2 dispersion and explosion experiments both indoors and outdoors which were conducted by DNG GL in 2019 to better understand safety aspects of LH2 in the maritime sector. In this work the DNV unignited outdoor and indoor tests have been simulated and compared with the experiments with the aim to validate the ADREA-HF Computational Fluid Dynamics (CFD) code in maritime applications. Three tests two outdoors and one indoors were chosen for the validation. The outdoor tests (test 5 and 6) involved liquid hydrogen release vertically downwards and horizontal to simulate an accidental leakage during bunkering. The indoor test (test 9) involved liquid hydrogen release inside a closed room to simulate an accident inside a tank connection space (TCS) connected to a ventilation mast.

This report of the High Level Group for Hydrogen and Fuel Cell Technologies sets out a vision for these technologies in future sustainable energy systems - improving energy security of supply and air quality whilst mitigating climate change. The report recommends actions for developing world-class European hydrogen technologies and fostering their commercial exploitation.

Hydrogen Economy and Cyclic Economy are advocated together with the use of perennial (solar wind hydro geo-power SWHG) and renewable (biomass) energy sources for defossilizing anthropic activities and mitigating climate change. Each option has intrinsic limits that prevent a stand-alone success in reaching the target. Humans have recycled goods (metals water paper and now plastics) to a different extent since very long time. Recycling carbon (which is already performed at the industrial level in the form of CO2 utilization and with recycling paper and plastics) is a key point for the future. The conversion of CO2 into chemicals and materials is carried out since the late 1800s (Solvay process) and is today performed at scale of 230 Mt/y. It is time to implement on a scale of several Gt/y the conversion of CO2 into energy products possibly mimicking Nature which does not use hydrogen. In the short term a few conditions must be met to make operative on a large scale the production of fuels from recycled-C namely the availability of low-cost: i. abundant pure concentrated streams of CO2 ii. non-fossil primary energy sources and iii. non-fossil-hydrogen. The large-scale production of hydrogen by Methane Steam Reforming with CO2 capture (Blue-H2) seems to be a realistic and sustainable solution. Green-H2 could in principle be produced on a large scale through the electrolysis of water powered by perennial primary sources but hurdles such as the availability of materials for the construction of long-living robust electrochemical cells (membranes electrodes) must be abated for a substantial scale-up with respect to existing capacity. The actual political situation makes difficult to rely on external supplies. Supposed that cheap hydrogen will be available its direct use in energy production can be confronted with the indirect use that implies the hydrogenation of CO2 into fuels (E-fuels) an almost ready technology. The two strategies have both pros and cons and can be integrated. E-Fuels can also represent an option for storing the energy of intermittent sources. In the medium-long term the direct co-processing of CO2 and water via co-electrolysis may avoid the production/transport/ use of hydrogen. In the long term coprocessing of CO2 and H2O to fuels via photochemical or photoelectrochemical processes can become a strategic technology.

Hydrogen as a primary carbon-free energy carrier is confronted by challenges in storage and transportation. However liquid organic hydrogen carriers (LOHCs) present a promising solution for storing and transporting hydrogen at ambient temperature and atmospheric pressure. Unlike circular energy carriers such as methanol ammonia and synthetic natural gas LOHCs do not produce by-products during hydrogen recovery. LOHCs only act as hydrogen carriers and the carriers can also be recycled for reuse. Although there are considerable advantages to LOHCs there are also some drawbacks especially relative to the energy consumption during the dehydrogenation step of the LOHC recycling. This review summarizes the recent progresses in LOHC technologies focusing on catalyst developments process and reactor designs applications and techno-economic assessments (TEA). LOHC technologies can potentially offer significant benefits to Australia especially in terms of hydrogen as an export commodity. LOHCs can help avoid capital costs associated with infrastructure such as transportation vessels while reducing hydrogen loss during transportation such as in the case of liquid hydrogen (LH2). Additionally it minimises CO2 emissions as observed in methane and methanol reforming. Thus it is essential to dedicate more efforts to explore and develop LOHC technologies in the Australian context.

Offshore electricity production mainly by wind turbines and eventually floating PV is expected to increase renewable energy generation and their dispatchability. In this sense a significant part of this offshore electricity would be directly used for hydrogen generation. The integration of offshore energy production into the hydrogen economy is of paramount importance for both the techno-economic viability of offshore energy generation and the hydrogen economy. An analysis of this integration is presented. The analysis includes a discussion about the current state of the art of hydrogen pipelines and subsea cables as well as the storage and bunkering system that is needed on shore to deliver hydrogen and derivatives. This analysis extends the scope of most of the previous works that consider port-to-port transport while we report offshore to port. Such storage and bunkering will allow access to local and continental energy networks as well as to integrate offshore facilities for the delivery of decarbonized fuel for the maritime sector. The results of such state of the art suggest that the main options for the transport of offshore energy for the production of hydrogen and hydrogenated vectors are through direct electricity transport by subsea cables to produce hydrogen onshore or hydrogen transport by subsea pipeline. A parametric analysis of both alternatives focused on cost estimates of each infrastructure (cable/pipeline) and shipping has been carried out versus the total amount of energy to transport and distance to shore. For low capacity (100 GWh/y) an electric subsea cable is the best option. For high-capacity renewable offshore plants (TWh/y) pipelines start to be competitive for distances above approx. 750 km. Cost is highly dependent on the distance to land ranging from 35 to 200 USD/MWh.

The aim of this paper is the design and implementation of an advanced model predictive control (MPC) strategy for the management of a wind–solar microgrid (MG) both in the islanded and grid-connected modes. The MG includes energy storage systems (ESSs) and interacts with external hydrogen and electricity consumers as an extra feature. The system participates in two different electricity markets i.e. the daily and real-time markets characterized by different time-scales. Thus a high-layer control (HLC) and a low-layer control (LLC) are developed for the daily market and the real-time market respectively. The sporadic characteristics of renewable energy sources and the variations in load demand are also briefly discussed by proposing a controller based on the stochastic MPC approach. Numerical simulations with real wind and solar generation profiles and spot prices show that the proposed controller optimally manages the ESSs even when there is a deviation between the predicted scenario determined at the HLC and the real-time one managed by the LLC. Finally the strategy is tested on a lab-scale MG set up at Khalifa University Abu Dhabi UAE.