Publications

As an important energy source to achieve carbon neutrality green hydrogen has always faced the problems of high use cost and unsatisfactory environmental benefits due to its remote production areas. Therefore a liquid-gaseous cascade green hydrogen delivery scheme is proposed in this article. In this scheme green hydrogen is liquefied into high-density and low-pressure liquid hydrogen to enable the transport of large quantities of green hydrogen over long distances. After longdistance transport the liquid hydrogen is stored and then gasified at transfer stations and converted into high-pressure hydrogen for distribution to the nearby hydrogen facilities in cities. In addition this study conducted a detailed model evaluation of the scheme around the actual case of hydrogen energy demand in Chengdu City in China and compared it with conventional hydrogen delivery methods. The results show that the unit hydrogen cost of the liquid-gaseous cascade green hydrogen delivery scheme is only 51.58 CNY/kgH2 and the dynamic payback periods of long- and short-distance transportation stages are 13.61 years and 7.02 years respectively. In terms of carbon emissions this scheme only generates indirect carbon emissions of 2.98 kgCO2/kgH2 without using utility electricity. In sum both the economic and carbon emission analyses demonstrate the advantages of the liquidgaseous cascade green hydrogen delivery scheme. With further reductions in electricity prices and liquefication costs this scheme has the potential to provide an economically/environmentally superior solution for future large-scale green hydrogen applications.

The Integrated Energy System (IES) that coordinates multiple energy sources can effectively improve energy utilization and is of great significance to achieving energy conservation and emission reduction goals. In this context a low-carbon and economic dispatch model for IES is proposed. Firstly a hydrogen energy-based IES (H2-IES) is constructed to refine the utilization process of hydrogen energy. Secondly the carbon emissions of different energy chains throughout their life cycle are analyzed using the life cycle assessment method (LCA) and the carbon emissions of the entire energy supply and demand chain are considered. Finally a staged carbon trading mechanism is adopted to promote energy conservation and emission reduction. Based on this an IES low-carbon and economic dispatch model is constructed with the optimization goal of minimizing the sum of carbon trading costs energy procurement costs and hydrogen sales revenue while considering network constraints and constraints on key equipment. By analyzing the model under different scenarios the introduction of life cycle assessment staged carbon trading and hydrogen energy utilization is shown to promote low-carbon and economic development of the comprehensive energy system.

This paper presents the results of increasing the hydrogen concentration in natural gas distributed within the territory of the Slovak Republic. The range of hydrogen concentrations in the mathematical model is considered to be from 0 to 100 vol.% for the resulting combustion products temperature and heating value and for the scientific assessment of the environmental and economic implications. From a technical perspective it is feasible to consider enriching natural gas with hydrogen up to a level of 20% within the Slovak Republic. CO2 emissions are estimated to be reduced by 3.76 tons for every 1 TJ of energy at an operational cost of EUR 10000 at current hydrogen prices.

Sustainable aviation fuel (SAF) production is one of the strategies to guarantee an environmental-friendly development of the aviation sector. This work evaluates the technical economic and environmental feasibility of obtaining SAFs by hydrogenation of vegetable oils thanks to in-situ hydrogen production via aqueous phase reforming (APR) of glycerol by-product. The novel implementation of APR would avoid the environmental burden of conventional fossil-derived hydrogen production as well as intermittency and storage issues related to the use of RES-based (renewable energy sources) electrolysers. The conceptual design of a conventional and advanced (APR-aided) biorefinery was performed considering a standard plant capacity equal to 180 ktonne/y of palm oil. For the advanced scenario the feed underwent hydrolysis into glycerol and fatty acids; hence the former was subjected to APR to provide hydrogen which was further used in the hydrotreatment reactor where the fatty acids were deoxygenated. The techno-economic results showed that APR implementation led to a slight increase of the fixed capital investment by 6.6% compared to the conventional one while direct manufacturing costs decreased by 22%. In order to get a 10% internal rate of return the minimum fuel selling price was found equal to 1.84 $/kg which is 17% lower than the one derived from conventional configurations (2.20 $/kg). The life-cycle GHG emission assessment showed that the carbon footprint of the advanced scenario was equal to ca. 12 g CO2/MJSAF i.e. 54% lower than the conventional one (considering an energy-based allocation). The sensitivity analysis pointed out that the cost of the feedstock SAF yield and the chosen plant size are keys parameters for the marketability of this biorefinery while the energy price has a negligible impact; moreover the source of hydrogen has significant consequences on the environmental footprint of the plant. Finally possible uncertainties for both scenarios were undertaken via Monte Carlo simulations.

Seasonal underground hydrogen storage (UHS) in porous media provides an as yet untested method for storing surplus renewable energy and balancing our energy demands. This study investigates the technical suitability for UHS in depleted hydrocarbon fields and one deep aquifer site in Taranaki Basin Aotearoa New Zealand. Prospective sites are assessed using a decision tree approach providing a “fast-track” method for identifying potential sites and a decision matrix approach for ranking optimal sites. Based on expert elicitation the most important factors to consider are storage capacity reservoir depth and parameters that affect hydrogen injectivity/withdrawal and containment. Results from both approaches suggest that Paleogene reservoirs from gas (or gas cap) fields provide the best option for demonstrating UHS in Aotearoa New Zealand and that the country’s projected 2050 hydrogen storage demand could be exceeded by developing one or two high ranking sites. Lower priority is assigned to heterolithic and typically finer grained labile and clay-rich Miocene oil reservoirs and to deep aquifers that have no proven hydrocarbon containment.

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.

This study proposes a country-based life-cycle assessment (LCA) of several conversion pathways related 10 to both on grid-connected Power-to-X (PtX) fuels and advanced biofuel production for maritime transport 11 in Europe. We estimate the biomass resource availability (both agricultural and forest residues and 12 second-generation energy crops from abandoned cropland) electricity mix and a future-oriented 13 prospective LCA to assess how future climate change mitigation policies influence the results. Our results 14 indicate that the potential of PtX fuels to achieve well-to-wake greenhouse gas intensities lower than 15 those of fossil fuels is limited to countries with a carbon intensity of the electricity mix below 100 gCO2eq kWh-1 16 . The more ambitious FuelEU Maritime goal could be achieved with PtX only if connected to electricity sources below ca. 17 gCO2eq kWh-1 17 which can become possible for most of the national 18 electricity mix in Europe by 2050 if renewable energy sources will become deployed at large scales. For 19 drop-in and hydrogen-based biofuels biomass residues have a higher potential to reduce emissions than 20 dedicated energy crops. In Europe the potentials of energy supply from all renewable and low-carbon 21 fuels (RLFs) range from 32-149% of the current annual fuel consumption in European maritime transport. 22 The full deployment of RLFs with carbon capture and storage technologies could mitigate up to 184% of 23 the current well-to-wake shipping emissions in Europe. Overall our study highlights how the strategic use 24 of both hydrogen-based biofuels and PtX fuels can contribute to the climate mitigation targetsfor present 25 and future scenarios of European maritime transport.

To combat climate change decarbonization measures are undertaken across the whole energy sector. Industry and transportation sectors are seen as difficult sectors to decarbonize with green hydrogen being proposed as a solution to achieve decarbonization in these sectors. While many methods of introducing hydrogen to these sectors are present in literature few systemlevel works study the specific impacts of large-scale introduction has on power and heat sectors in an energy system. This contribution examines the effects of introducing hydrogen into a Finnish energy system in 2040 by conducting scenario simulations in EnergyPLAN – software. Primary energy consumption and CO2 emissions of the base scenario and hydrogen scenarios are compared. Additionally the differences between a constant and flexible hydrogen production profile are studied. Introducing hydrogen increases electricity consumption by 31.9 % but reduces CO2 emissions by 71.5 % and fossil energy consumption by 72.6%. The flexible hydrogen profile lowers renewable curtailment and improves energy efficiency but requires economically unfeasible hydrogen storage. Biomass consumption remains high and is not impacted significantly by the introduction of hydrogen. Additional measures in other sectors are needed to ensure carbon neutrality.

The global issue of climate change caused by humans and its inextricable linkage to our present and future energy demand presents the biggest challenge facing our globe. Hydrogen has been introduced as a new renewable energy resource. It is envisaged to be a crucial vector in the vast low-carbon transition to mitigate climate change minimize oil reliance reinforce energy security solve the intermittency of renewable energy resources and ameliorate energy performance in the transportation sector by using it in energy storage energy generation and transport sectors. Many technologies have been developed to generate hydrogen. The current paper presents a review of the current and developing technologies to produce hydrogen from fossil fuels and alternative resources like water and biomass. The results showed that reformation and gasification are the most mature and used technologies. However the weaknesses of these technologies include high energy consumption and high carbon emissions. Thermochemical water splitting biohydrogen and photo-electrolysis are long-term and clean technologies but they require more technical development and cost reduction to implement reformation technologies efficiently and on a large scale. A combination of water electrolysis with renewable energy resources is an ecofriendly method. Since hydrogen is viewed as a considerable game-changer for future fuels this paper also highlights the challenges facing hydrogen generation. Moreover an economic analysis of the technologies used to generate hydrogen is carried out in this study.

Hydrogen production based on a combination of intermittent renewables and grid electricity is a promising approach for reducing emissions in hard-to-decarbonise sectors at lower costs. However for such a configuration to provide climate benefits it is crucial to ensure that the grid electricity consumed in the process is derived from low-carbon sources. This paper examined the use of hourly grid emission factors (EFs) to more accurately determine the short-term climate impact of dynamically operated electrolysers. A model of the interconnected northern European electricity system was developed and used to calculate average grid-mix and marginal EFs for the four bidding zones in Sweden. Operating a 10 MW electrolyser using a combination of onshore wind and grid electricity was found to decrease the levelised cost of hydrogen (LCOH) to 2.40–3.63 €/kgH2 compared with 4.68 €/kgH2 for wind-only operation. A trade-off between LCOH and short-term climate impact was revealed as specific marginal emissions could exceed 20 kgCO2eq/kgH2 at minimum LCOH. Both an emission-minimising operating strategy and an increased wind-to-electrolyser ratio was found to manage this trade-off by enabling simultaneous cost and emission reductions lowering the marginal carbon abatement cost (CAC) from 276.8 €/tCO2eq for wind-only operation to a minimum of 222.7 and 119.3 €/tCO2eq respectively. Both EF and LCOH variations were also identified between the bidding zones but with no notable impact on the marginal CAC. When using average grid-mix emission factors the climate impact was low and the CAC could be reduced to 71.3–200.0 €/tCO2eq. In relation to proposed EU policy it was demonstrated that abiding by hourly renewable temporal matching principles could ensure low marginal emissions at current levels of fossil fuels in the electricity mix.