Publications

This paper presents a method for refining the forecast schedule of renewable energy sources (RES) generation by its intraday adjustment and investigates the measures for reserving RES with unstable generation in electric power systems (EPSs). Owing to the dependence of electricity generation by solar and wind power plants (PV and WPPs respectively) on natural conditions problems arise with their contribution to the process of balancing the power system. Therefore the EPS is obliged to keep a power reserve to compensate for deviations in RES from the planned generation amount. A system-wide reserve (mainly the shunting capacity of thermal and hydroelectric power plants) is used first followed by other means of power reserve: electrochemical hydrogen or biogas plants. To analyze the technical and economic efficiency of certain backup means mathematical models based on the theory of similarity and the criterion method were developed. This method is preferred because it provides the ability to compare different methods of backing up RES generation with each other assess their proportionality and determine the sensitivity of costs to the capacity of backup methods with minimal available initial information. Criterion models have been formed that allow us to build dependencies of the costs of backup means for unstable RES generation on the capacity of the backup means. It is shown that according to the results of the analysis of various methods and means of RES backup hydrogen technologies are relatively the most effective. The results of the analysis in relative units can be clarified if the current and near-term price indicators are known.

Hydrogen is known to be the carbon-neutral alternative energy carrier with the highest energy density. Currently more than 95% of hydrogen production technologies rely on fossil fuels resulting in greenhouse gas emissions. Water electrolysis is one of the most widely used technologies for hydrogen generation. Nuclear power a renewable energy source can provide the heat needed for the process of steam electrolysis for clean hydrogen production. This review paper analyses the recent progress in hydrogen generation via high-temperature steam electrolysis through solid oxide electrolysis cells using nuclear thermal energy. Protons and oxygen-ions conducting solid oxide electrolysis processes are discussed in this paper. The scope of this review report covers a broad range including the recent advances in material development for each component (i.e. hydrogen electrode oxygen electrode electrolyte interconnect and sealant) degradation mechanisms and countermeasures to mitigate them.

The increasing demand for hydrogen has made it a promising alternative for decarbonizing industries and reducing CO2 emissions. Although mainly produced through the gray pathway the integration of carbon capture and storage (CCS) reduces the CO2 emissions. This study presents a sustainability method that uses flare gas for hydrogen production through steam methane reforming (SMR) with CCS supported by a techno-economic analysis. Data Envelopment Analysis (DEA) was used to evaluate the oil company’s efficiency and inverse DEA/sensitivity analysis identified maximum flare gas reduction which was modeled in Aspen HYSYS V14. Subsequently an economic evaluation was performed to determine the levelized cost of hydrogen (LCOH) and the cost–benefit ratio (CBR) for Nigeria. The CBR results were 2.15 (payback of 4.11 years with carbon credit) and 1.96 (payback of 4.55 years without carbon credit) indicating strong economic feasibility. These findings promote a practical approach for waste reduction aiding Nigeria’s transition to a circular low-carbon economy and demonstrate a positive relationship between lean and green strategies in the petroleum sector.

Hydrogen is a clean substitute for hydrocarbon fuels in the marine sector. Liquid hydrogen (2 ) can be used to move and store large amounts of hydrogen. This novel application needs further study to assess the potential risk and safety operation. A recent study of 2 large-scale release tests was conducted to replicate spills of 2 inside the ship’s tank connection space and during bunkering operations. The tests were performed in a closed and outdoor facility. The 2 spills can lead to detonation representing a safety concern. This study analyzed the aforementioned 2 experiments and proposed a novel application of the random forests algorithm to predict the oxygen phase change and to estimate whether the hydrogen concentration is above the lower flammability limit (LFL). The models show accurate predictions in different experimental conditions. The findings can be used to select reliable safety barriers and effective risk reduction measures in 2 spills.

The present review focuses on the current progress on harnessing the potential of hydrogen production by Methane Steam Reforming (MSR). First based on the prominent literature in last few years the overall research efforts of hydrogen production using different feed stocks like ethanol ammonia glycerol methanol and methane is presented. The presented data is based on reactor type reactor operating conditions catalyst used and yield of hydrogen to provide a general overview. Then the most widely used process [steam methane reforming (SMR)/ methane steam reforming (MSR)] are discussed. Major advanced reactors the membrane reactors Sorption Enhanced methane steam reforming reactors and micro-reactors are evaluated. The evaluation has been done based on parameters like residence time surface area scale-up coke formation conversion space velocity and yield of hydrogen. The kinetic models available in recently published literature for each of these reactors have been presented with the rate constants and other parameters. The mechanism of coke formation and the rate expressions for the same have also been presented. While membrane reactors and sorption enhanced reactors have lot of advantages in terms of process intensification scale-up to industrial scale is still a challenge due to factors like membrane stability and fouling (in membrane reactors) decrease in yield with increasing WHSV (in case of Sorption Enhanced Reactors). Micro-reactors pose a higher potential in terms of higher yield and very low residence time in seconds though the volumes might be substantially lower than present industrial scale conventional reactors.

Hydrogen is indispensable to decarbonise European industry and reach the EU’s 2030 climate targets and 2050 climate neutrality. It is one of the key technologies of Europe’s Net Zero Industry Act. By scaling up its production we will reduce the use of fossil fuels in European industries and serve the needs of hard-to-electrify sectors.

At present hydrogen is considered as one of the most promising motor fuels capable of replacing traditional hydrocarbons. This article presents the results of a comprehensive experimental study of the effect of hydrogen additives on the main parameters of a gasoline spark-ignition ICE. The thermophysical parameters of the processes of ignition and combustion inside the cylinder with the addition of hydrogen in the amount of 0%–20% of the air volume as well as the fuel and energy characteristics of the engine and its impact on the environment were studied. It has been established that hydrogen leads to significant changes in the engine operation. It increases some parameters and reduces others improving or worsening them compared to running on pure gasoline. So with a 20% H2 addition at an average engine load the following parameters increase: the maximum pressure in the cylinder by almost 20%; the rate of pressure increase in the combustion chamber by 2.8 times; the highest combustion temperature by 140 K. At the same time the following parameters decrease: average indicator pressure by 18%; ignition timing by 82% (6◦ to TDC versus 34◦ for gasoline); crank angle corresponding to the maximum pressure by 32% (9.4◦ versus 13.9◦ for gasoline); crank angle corresponding to maximum temperature by 54% (17.7◦ after TDC versus 38.3◦ for clean gasoline); ignition delay time (τind = 0.32 ms) and visible combustion time (τvis = 1.58 ms) by 4 and 2.3 times respectively.

The green hydrogen industry highly efficient and safe is endowed with flexible production and low carbon emissions. It is conducive to building a low-carbon efficient and clean energy structure optimizing the energy industry system and promoting the strategic transformation of energy development and enhancing energy security. In order to achieve carbon emission peaking by 2030 and neutrality by 2060 (dual carbon goals) China is vigorously promoting the green hydrogen industry. Based on an analysis of the green hydrogen industry policies of the U.S. the EU and Japan this paper explores supporting policies issued by Chinese central and local authorities and examines the inherent advantages of China’s green hydrogen industry. After investigating and analyzing the basis for the development of the green hydrogen industry in China we conclude that China has enormous potential including abundant renewable energy resources as well as commercialization experience with renewable energy robust infrastructure and technological innovation capacity demand for large-scale applications of green hydrogen in traditional industries etc. Despite this China’s green hydrogen industry is still in its early stage and has encountered bottlenecks in its development including a lack of clarity on the strategic role and position of the green hydrogen industry low competitiveness of green hydrogen production heavy reliance on imports of PEMs perfluorosulfonic acid resins (PFSR) and other core components the development dilemma of the industry chain lack of installed capacity for green hydrogen production and complicated administrative permission etc. This article therefore proposes that an appropriate development road-map and integrated administration supervision systems including safety supervision will systematically promote the green hydrogen industry. Enhancing the core technology and equipment of green hydrogen and improving the green hydrogen industry chain will be an adequate way to reduce dependence on foreign technologies lowering the price of green hydrogen products through the scale effect and thus expanding the scope of application of green hydrogen. Financial support mechanisms such as providing tax breaks and project subsidies will encourage enterprises to carry out innovative technological research on and invest in the green hydrogen industry.

This review focuses on the reduction of iron oxides using hydrogen as a reducing agent. Due to increasing requirements from environmental issues a change of process concepts in the iron and steel industry is necessary within the next few years. Currently crude steel production is mainly based on fossil fuels and emitting of the climate-relevant gas carbon dioxide is integral. One opportunity to avoid or reduce greenhouse gas emissions is substituting hydrogen for carbon as an energy source and reducing agent. Hydrogen produced via renewable energies allows carbon-free reduction and avoids forming harmful greenhouse gases during the reduction process. The thermodynamic and kinetic behaviors of reduction with hydrogen are summarized and discussed in this review. The effects of influencing parameters such as temperature type of iron oxide grain size etc. are shown and compared with the reduction behavior of iron oxides with carbon monoxide. Different methods to describe the kinetics of the reduction progress and the role of the apparent activation energy are shown and proofed regarding their plausibility.

Although energy-intensive industries are often seen as ‘hard-to-decarbonise’ net-zero megaprojects for industrial clusters promise to improve the technical and economic feasibility of hydrogen fuel switching and carbon capture and storage (CCS). Mobilising insights from the megaproject literature this paper analyses the dynamics of an ambitious first-of-kind net-zero megaproject in the Humber industrial cluster in the United Kingdom which includes CCS and hydrogen infrastructure systems industrial fuel switching CO2 capture green and blue hydrogen production and hydrogen storage. To analyse the dynamics of this emerging megaproject the article uses a socio-technical system lens to focus on developments in technology actors and institutions. Synthesising multiple megaproject literature insights the paper develops a comprehensive framework that addresses both aggregate (‘outside-in’) developments and the endogenous (‘inside-out’) experiences and activities regarding three specific challenges: technical system integration actor coordination and institutional alignment. Drawing on an original dataset involving expert interviews (N = 46) site visits (N = 7) and document analysis the ‘outside-in’ analysis finds that the Humber megaproject has progressed rapidly from outline visions to specific technical designs enacted by new coalitions and driven by strengthening policy targets and financial support schemes. The complementary ‘inside-out’ analysis however also finds 12 alignment challenges that can delay or derail materialisation of the plans. While policies are essential aggregate drivers institutional misalignments presently also prevent project-actors from finalising design and investment decisions. Our analysis also finds important tensions between the project's high-pace delivery focus (to meet government targets) and allowing sufficient time for pilot projects learning-by-doing and design iterations.

The reduction of harmful emissions from the international shipping sector is necessary. On-board energy demand can be categorised as either: propulsion or auxiliary services. Auxiliary services contribute a significant proportion of energy demand with major loads including: compressors pumps and HVAC (heating ventilation and air-conditioning). Typically this demand is met using the same fuel source as the main propulsion (i.e. fossil fuels). This study has analysed whether emissions from large scale ships could feasibly be reduced by meeting auxiliary demand by installing a hydrogen fuel cell using data from an LNG tanker to develop a case study. Simulations have shown that for a capacity of 10 x 40ft containers of compressed hydrogen the optimal fuel cell size would be 3 MW and this could save 10600 MWh of fossil fuel use equivalent to 2343 t of CO2. Hence this could potentially decarbonise a significant proportion of shipping energy demand. Although there are some notable technical and commercial considerations such as fuel cell lifetime and capital expenditure requirements. Results imply that if auxiliary loads could be managed to avoid peaks in demand this could further increase the effectiveness of this concept.

The deployment of hydrogen fuel cell electric vehicles (FCEVs) is critical to achieve zero emissions. A key parameter influencing FCEV performance and durability is hydrogen fuel quality. The real impact of contaminants on FCEV performance is not well understood and requires reliable measurements from real-life events (e.g. hydrogen fuel in poor-performing FCEVs) and controlled studies on the impact of synthetic hydrogen fuel on FCEV performance. This paper presents a novel methodology to flow traceable hydrogen synthetic fuel directly into the FCEV tank. Four different synthetic fuels containing N2 (90–200 µmol/mol) CO (0.14–5 µmol/mol) and H2S (4–11 nmol/mol) were supplied to an FCEV and subsequently sampled and analyzed. The synthetic fuels containing known contaminants powered the FCEV and provided real-life performance testing of the fuel cell system. The results showed for the first time that synthetic hydrogen fuel can be used in FCEVs without the requirement of a large infrastructure. In addition this study carried out a traceable H2 contamination impact study with an FCEV. The impact of CO and H2S at ISO 14687:2019 threshold levels on FCEV performance showed that small exceedances of the threshold levels had a significant impact even for short exposures. The methodology proposed can be deployed to evaluate the composition of any hydrogen fuel.

Alternative fuels are crucial to decarbonize the European maritime transport but their net climate benefits vary with the type of fuel and production country. In this study we assess the energy potential and climate change mitigation benefits of using agricultural and forest residues in different European countries for drop-in (Fast Pyrolysis Hydrothermal Liquefaction and Gasification to Fischer-Tropsch fuels or Bio-Synthetic Natural Gas) and hydrogen-based biofuels (hydrogen ammonia and methanol) with or without carbon capture and storage (CCS). Our results show the combinations of countries and biofuel options that successfully achieve the decarbonization targets set by the FuelEU Maritime initiative for the next years including a prospective analysis that include technological changes projected for the biofuel supply chains until 2050. With the current technologies the largest greenhouse gas (GHG) mitigation potential per year at a European scale is obtained with bio-synthetic natural gas and hydrothermal liquefaction. Among carbon-free biofuels ammonia currently has higher mitigation but hydrogen can achieve a lower GHG intensity per unit of energy with the projected decarbonization of the electricity mixes until 2050. The full deployment of CCS can further accelerate the decarbonization of the maritime sector. Choosing the most suitable renewable fuels requires a regional perspective and a transition roadmap where countries coordinate actions to meet ambitious climate targets.

Synthetic fuels or e-fuels produced from captured CO2 and renewable hydrogen are envisaged as a feasible path towards a climate-neutral transportation in medium/heavy-duty and maritime sectors. EU is presently debating energy targets by 2030 for these fuels. As their production involves chemical processing of hydrogen it must be evaluated if the extra cost is worthy at least in applications where hydrogen use is possible. This manuscript focuses on the performance and environmental impact when hydrogen and methanol are fed to a heavy-duty compression-ignition engine working under dual-fuel combustion. The trade-off thermal efficiency-NOx emissions is primary considered in the assessment by combining both variables in an own defined function. During the work engine operating settings were adjusted to exploit the potential of methanol and hydrogen. Compared to conventional combustion methanol required centering the combustion towards TDC and doubling the EGR rate resulting in a low temperature highly premixed combustion almost soot-free and with extremely low NOx emissions. The best settings for hydrogen were in the middle of those for methanol and conventional combustion. Results showed great dependance with the engine load but methanol proved superior to hydrogen for all conditions. At high load 20–60 % methanol even improved the efficiency and reduced the NOx emissions obtained by conventional combustion. However at low load hydrogen could substitute 90 % of the diesel fuel while methanol failed at substitutions higher than 55 %.

The presented work concerns experimental research of a spark-ignition engine with variable compression ratio (VCR) adapted to dual-fuel operation in which co-combustion of ammonia with hydrogen was conducted and the energy share of hydrogen varied from 0% to 70%. The research was aimed at assessing the impact of the energy share of hydrogen co-combusted with ammonia on the performance stability and emissions of an engine operating at a compression ratio of 8 (CR 8) and 10 (CR 10). The operation of the engine powered by ammonia alone for both CR 8 and CR 10 is associated with either a complete lack of ignition in a significant number of cycles or with significantly delayed ignition and the related low value of the maximum pressure pmax. Increasing the energy share of hydrogen in the fuel to 12% allows to completely eliminate the instability of the ignition process in the combustible mixture which is confirmed by a decrease in the IMEP uniqueness and a much lower pmax dispersion. For 12% of the energy share of hydrogen co-combusted with ammonia the most favorable course of the combustion process was obtained the highest engine efficiency and the highest IMEP value were recorded. The conducted research shows that increasing the H2 share causes an increase in NO emissions for both analyzed compression ratios

Under the requirements of China's strategic goal of "carbon peaking and carbon neutrality" as a renewable clean and efficient secondary energy source hydrogen benefits from abundant resources a wide variety of sources a high combustion calorific value clean and non-polluting various forms of utilization energy storage mediums and good security etc. It will become a realistic way to help energy transportation petrochemical and other fields to achieve deep decarbonization and will turn into an important replacement energy source for China to build a modern clean energy system. It is clear that accelerating the development of hydrogen energy has become a global consensus. In order to provide a theoretical support for the accelerated transformation of hydrogen-related industries and energy companies and provide a basis and reference for the construction of "Hydrogen Energy China" this paper describes main key technological progresses in the hydrogen industry chain such as hydrogen production storage transportation and application. The status and development trends of hydrogen industrialization are analyzed and then the challenges faced by the development of the hydrogen industry are discussed. At last the development and future of the hydrogen industry are prospected. The following conclusions are achieved. (1) Hydrogen technologies of our country will become mature and enter the road of industrialization. The whole industry chain system of the hydrogen industry is gradually being formed and will realize the leap-forward development from gray hydrogen blue hydrogen to green hydrogen. (2) The overall development of the entire hydrogen industry chain such as hydrogen production storage and transportation fuel cells hydrogen refueling stations and other scenarios should be accelerated. Besides in-depth integration and coordination with the oil and gas industry needs more attention which will rapidly promote the high-quality development of the hydrogen industry system. (3) The promotion and implementation of major projects such as "north-east hydrogen transmission" "west-east hydrogen transmission" "sea hydrogen landing" and utilization of infrastructures such as gas filling stations can give full play to the innate advantages of oil and gas companies in industrial chain nodes such as hydrogen production and refueling etc. which can help to achieve the application of "oil gas hydrogen and electricity" four-station joint construction form a nationwide hydrogen resource guarantee system and accelerate the planning and promotion of the "Hydrogen Energy China" strategy.

Fluctuations in renewable energy production especially from solar and wind plants can be solved by large‐scale energy storage. One of the possibilities is storing energy in the form of hydrogen or methane–hydrogen blends. A viable alternative for storing hydrogen in salt caverns is Lined Rock Cavern (LRC) underground energy storage. One of the most significant challenges in LRC for hydrogen storage is sealing liners which need to have satisfactory sealing and mechanical properties. An experimental study of hydrogen permeability of different kinds of polymers was conducted followed by modeling of hydrogen permeability of these materials with different additives (graphite halloysite and fly ash). Fillers in polymers can have an impact on the hydrogen permeability ratio and reduce the amount of polymer required to make a sealing liner in the reservoir. Results of this study show that hydrogen permeability coefficients of polymers and estimated hydrogen leakage through these materials are similar to the results of salt rock after the salt creep process. During 60 days of hydrogen storage in a tank of 1000 m2 inner surface 1 cm thick sealing liner and gas pressure of 1.0 MPa only approx. 1 m3STP of hydrogen will diffuse from the reservoir. The study also carries out the modeling of the hydrogen permeability of materials using the Max‐ well model. The difference between experimental and model results is up to 17% compared to the differences exceeding 30% in some other studies.

Fuel Cells are a promising technology in the context of clean power sustainability and alternative fuels for shipping. Different specific developments on Fuel Cells are available today with research and pilot projects under evaluation that have revealed strong potential for further scaled up implementation. The EMSA Study on the use of Fuel Cells in Shipping has been the result of this Agency’s initiative under the agreement of the Commission and in support of EU Member States an important instrument developed in close partnership with DNV-GL.

Notwithstanding the close dependency of Fuel Cell technology and the development of hydrogen fuel solutions different solutions are today in place making use of LNG methanol and other low flashpoint fuels. EMSA participates in support of the Commission in the 2nd phase development of the IGF Code where provisions for Fuel Cells are to be included as a new part of the text.

The EMSA Study on the use of Fuel Cells in Shipping includes a technology and regulatory review identifying gaps to be further explored the selection of the most promising Fuel Cell technologies for shipping and finally a generic Safety Assessment where the selected technologies are evaluated according to Risk & Safety aspects in generic ship design applications.

This paper presents a theoretical analysis of the selected properties of HCNG fuel calculations and a literature review of the other fuels that allow the storage of ecologically produced hydrogen. Hydrogen has the most significant CO2 reduction potential of all known fuels. However its transmission in pure form is still problematic and its use as a component of fuels modified by it has now become an issue of interest for researchers. Many types of hydrogen-enriched fuels have been invented. However this article will describe the reasons why HCNG may be the hydrogen-enriched fuel of the future and why internal combustion (IC) piston engines working on two types of fuel could be the future method of using it. CO2 emissions are currently a serious problem in protecting the Earth’s natural climate. However secondarily power grid stabilization with a large share of electricity production from renewable energy sources must be stabilized with very flexible sources—as flexible as multi-fuel IC engines. Their use is becoming an essential element of the electricity power systems of Western countries and there is a chance to use fuels with zero or close to zero CO2 emissions like e-fuels and HCNG. Dual-fuel engines have become an effective way of using these types of fuels efficiently; therefore in this article the parameters of hydrogen-enriched fuel selected in terms of relevance to the use of IC engines are considered. Inaccuracies found in the literature analysis are discussed and the essential properties of HCNG and its advantages over other hydrogen-rich fuels are summarized in terms of its use in dual-fuel (DF) IC engines.

Underground Hydrogen Storage (UHS) has received significant attention over the past few years as hydrogen seems well-suited for adjusting seasonal energy gaps. We present an integrated reservoir-well model for “Viking A00 the depleted gas field in the North Sea as a potential site for UHS. Our findings show that utilizing the integrated model results in more reasonable predictions as the gas composition changes over time. Sensitivity analyses show that the lighter the cushion gas the more production can be obtained. However the purity of the produced hydrogen will be affected to some extent which can be enhanced by increasing the fill-up period and the injection rate. The results also show that even though hydrogen diffuses into the reservoir and mixes up with the native fluids (mainly methane) the impact of hydrogen diffusion is marginal. All these factors will potentially influence the project's economics.

The usage of fossil fuels to generate energy and the lack of wastewater treatment in Mexico are two issues that can be addressed at the same time while developing wastewater treatment technologies that incorporate energy recovery in their process train. We carried out a systematic review based on the PRISMA methodology to identify and review studies regarding energy recovery using wastewater as a substrate in Mexico. Peer-reviewed papers were identified through Scopus Web of Knowledge and Google Scholar using a timeframe of 22 years that represented from 2000 to 2022. After applying the selection criteria we identified 31 studies to be included in the final review starting from 2007. The kind of energy product type of technology used substrate wastewater amount of energy produced and main parameters for the operation of the technology were extracted from the papers. The results show that methane is the most researched energy recovery product from wastewater followed by hydrogen and electricity and the technology used to archive it is an up-flow anaerobic sludge bed (UASB) reactor to produce methane and hydrogen. In addition microbial fuel cells (MFCs) were preferred to produce electricity. According to our data more energy per kgCOD removed could be obtained with methane-recovering technologies in the Mexican peer-reviewed studies compared with hydrogen recovery and electricity production.

In this Podcast David Ledesma discusses with Stephen Craen Visiting Research Fellow OIES the challenges facing the financing of future hydrogen projects as it is expected that a substantial amount of capital will need to be invested in green hydrogen production to meet the 2050 net zero targets. Based around an ‘Archetype’ world scale hydrogen export project where 1 GW solar power is used to make green hydrogen which is converted to 250000 tpa green ammonia for export with a capital cost in the region of USD 2 billion the podcast discusses how ‘efficient financing’ can make an important contribution to minimising cost and making projects cost competitive. Stephen Craen argues that lenders and investors will look to precedents when assessing the nascent green hydrogen sector and the foremost will be LNG and offshore wind which both represent large-scale technically complex projects. Commercial structures of the green hydrogen business are expected to borrow concepts from offshore wind projects particularly in relation to price but also from LNG where this is relevant such as take-or-pay contracts. In this podcast we discuss the key issues that will need to be addressed to make a green hydrogen export project bankable concluding that commercial debt from either commercial banks or project bonds can help create competition.

The podcast can be found on their website.

In this study we present a pre-feasibility analysis that examines the viability of implementing autonomous green hydrogen production plants in two strategic regions of Chile. With abundant renewable energy resources and growing interest in decarbonization in Chile this study aims to provide a comprehensive financial analysis from the perspective of project initiators. The assessment includes determining the optimal sizing of an alkaline electrolyzer stack seawater desalination system and solar and wind renewable energy farms and the focus is on conducting a comprehensive financial analysis from the perspective of project initiators to assess project profitability using key economic indicators such as net present value (NPV). The analyses involve determining appropriate sizing of an alkaline electrolyzer stack a seawater desalination system and solar and wind renewable energy farms. Assuming a base case production of 1 kiloton per year of hydrogen the capital expenditures (CAPEX) and operating expenses (OPEX) are determined. Then the manufacturing and production costs per kilogram of green hydrogen are calculated resulting in values of USD 3.53 kg−1 (utilizing wind energy) and USD 5.29 kg−1 (utilizing photovoltaic solar energy). Cash flows are established by adjusting the sale price of hydrogen to achieve a minimum expected return on investment of 4% per year yielding minimum prices of USD 7.84 kg−1 (with wind energy) and USD 11.10 kg−1 (with photovoltaic solar energy). Additionally a sensitivity analysis is conducted to assess the impact of variations in investment and operational costs. This research provides valuable insights into the financial feasibility of green hydrogen production in Chile contributing to understanding renewable energy-based hydrogen projects and their potential economic benefits. These results can provide a reference for future investment decisions and the global development of green hydrogen production plants.

The National Hydrogen Strategy sets out the strategic vision on the role that hydrogen will play in Ireland’s energy system looking to its long-term role as a key component of a zero-carbon economy and the short-term actions that need to be delivered over the coming years to enable the development of the hydrogen sector in Ireland.<br/>The Strategy is being developed for three primary reasons:<br/>1. Decarbonising our economy providing a solution to hard to decarbonise sectors where electrification is not feasible or cost-effective<br/>2. Enhancing our energy security through the development of an indigenous zero carbon renewable fuel which can act as an alternative to the 77% of our energy system which today relies on fossil fuel imports<br/>3. Developing industrial opportunities through the potential development of export markets for renewable hydrogen and other areas such as Sustainable Aviation Fuels<br/>The Strategy considers the needs of the entire hydrogen value chain including production end-uses transportation and storage safety regulation markets innovation and skills.<br/>It also sets out that Ireland will focus its efforts on the scale up and production of renewable ""green"" hydrogen as it supports both our decarbonisation needs and energy security needs given our vast indigenous renewable resources. Renewable hydrogen is a renewable and zero-carbon fuel that can play a key role in the ""difficult-to-decarbonise"" sectors of our economy where other solutions such as direct electrification are not feasible or cost effective.<br/>In the coming years renewable hydrogen is envisioned to play an important role as a zero-emission source of dispatchable flexible electricity as a long duration store of renewable energy in decarbonising industrial processes and as a transport fuel in sectors such as heavy goods transport maritime and aviation. The Strategy will provide clarity for stakeholders on how we expect the hydrogen economy to develop and scale up over the coming decades across the entire value chain.

In this paper by using a large eddy simulation we study the combustion process in the HyShot II scramjet combustor. By conducting a detailed analysis of the mass-fraction distributions of the main species such as H2 H2O and the radicals OH and HO2 of the mass source terms of these main species and of the chemical source term of the energy equation we detect the regions where chemical reactions occur through a diffusion process and the regions where auto-ignition and premixed combustion may develop. The analysis indicates that the combustion process is mainly of diffusive type along a thin shear layer enveloping the hydrogen plume whereas there could be some auto-ignition and/or premixed combustion cores inside the plume.

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.

The glass industry is part of the energy-intensive industry with most of the energy needed to melt the raw materials. To produce glass temperatures between 1000 and 1600 °C are necessary. Presently mostly fossil natural gas is the dominant energy source. As direct electrification is not always possible in this paper a Life Cycle Assessment (LCA) for specialty glass production is conducted where the conventional fossil-based reference process is compared to a hydrogen-fired furnace. This hydrogen can be produced on-site in an water electrolyzer using not only the hydrogen for the combustion but also the produced oxygen. Hydrogen can be produced alternatively off-site in a large scale electrolyzer to facilitate economy of scale. For the transport and distribution of this hydrogen different options are available. A rather new option are liquid organic hydrogen carriers (LOHC) which bind the hydrogen in a chemical substance. However temperatures around 300 °C are necessary to separate the hydrogen from the LOHC after transport. At the glass trough waste heat is available at the required temperature level to facilitate the dehydrogenation. The comparison is completed by the production of off-site hydrogen transported to the glass trough as conventional liquefied hydrogen in cooling tanks by truck or in hydrogen pipelines. In this assessment to power the electrolyzers the national grid mix of Germany is used. A time frame from 2020 till 2050 and its changing energy system towards defossilisation is analyzed. Regarding climate change on-site hydrogen production causes the least impact for specialty glass production in 2050. However negative trade-offs for other environmental impact categories e.g. Metal depletion are recorded.

Green hydrogen is a key element that has the potential to play a critical role in the global pursuit of a resilient and sustainable future. However like other energy production methods hydrogen comes with challenges including high costs and safety concerns across its entire value chain. To overcome these low-cost productions are required along with a promised market. Offshore renewables have an enormous potential to facilitate green hydrogen production on a large scale. Their plummeting cost technological advances and rising cost of carbon pave a pathway where green hydrogen can be cost-competitive against fossil-fuel-based hydrogen. Offshore industries including oil and gas aquaculture and shipping are looking for cleaner energy solutions to decarbonize their systems/operations and can serve as a substantial market. Offshore industrial nexus moreover can assist the production storage and transmission of green hydrogen through infrastructure sharing and logistical support. The development of offshore green hydrogen production facilities is in its infancy and requires a deeper insight into the key elements that govern decision-making during their life-cycle. This includes the parameters that reflect the performance of hydrogen technology with technical socio-political financial and environmental considerations. Therefore this study provides critical insight into the influential factors discovered through a comprehensive analysis that governs the development of an offshore green hydrogen system. Insights are also fed into the requirements for modelling and analysis of these factors considering the synergy of hydrogen production with the offshore industries coastal hydrogen hub and onshore energy demand. The results of this critical review will assist the researchers and developers in establishing and executing an effective framework for offshore site selection in largely uncertain and hazardous ocean environments. Overall the study will facilitate the stakeholders and researchers in developing decision-making tools to ensure sustainable and safe offshore green hydrogen facilities.

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.

The steel sector currently accounts for 7% of global energy-related CO2 emissions and requires deep reform to disconnect from fossil fuels. Here we investigate the market competitiveness of one of the widely considered decarbonisation routes for primary steel production: green hydrogen-based direct reduction of iron ore followed by electric arc furnace steelmaking. Through analysing over 300 locations by combined use of optimisation and machine learning we show that competitive renewables-based steel production is located nearby the tropic of Capricorn and Cancer characterised by superior solar with supplementary onshore wind in addition to high-quality iron ore and low steelworker wages. If coking coal prices remain high fossil-free steel could attain competitiveness in favourable locations from 2030 further improving towards 2050. Large-scale implementation requires attention to the abundance of suitable iron ore and other resources such as land and water technical challenges associated with direct reduction and future supply chain configuration.

To meet the climate targets set forth in the International Maritime Organization’s Initial GHG Strategy the maritime transport sector needs to abandon the use of fossil-based bunker fuels and turn toward zero-carbon alternatives which emit zero or at most very low greenhouse gas (GHG) emissions throughout their lifecycles. This report “The Potential of Zero-Carbon Bunker Fuels in Developing Countries” examines a range of zero-carbon bunker fuel options that are considered to be major contributors to shipping’s decarbonized future: biofuels hydrogen and ammonia and synthetic carbon-based fuels. The comparison shows that green ammonia and green hydrogen strike the most advantageous balance of favorable features due to their lifecycle GHG emissions broader environmental factors scalability economics and technical and safety implications. Furthermore the report finds that many countries including developing countries are very well positioned to become future suppliers of zero-carbon bunker fuels—namely ammonia and hydrogen. By embracing their potential these countries would be able to tap into an estimated $1+ trillion future fuel market while modernizing their own domestic energy and industrial infrastructure. However strategic policy interventions are needed to unlock these potentials.

This report illustrates what a reliable resilient decarbonised electricity supply system could look like in 2035 and the steps required to achieve it. It provides new insights and new advice on how such a system can be achieved by 2035 using real weather data and hourly analysis of Great Britain’s power system (Northern Ireland is part of the all-Ireland system). It also looks at the implications for hydrogen.

China is the world’s largest producer and consumer of hydrogen. The country has adopted a domestic strategy that targets significant growth in hydrogen consumption and production. Given the importance of hydrogen in the low-carbon energy transition it is critical to understand China’s hydrogen policies and their implementation as well as the extent to which these contribute to the country’s low-carbon goals.<br/>Existing research has focused on understanding policies and regulations in China and their implications for the country’s hydrogen prospects. This study aims to improve our understanding of central-government initiatives and look at how China’s hydrogen policies are implemented at the local level. The paper examines the three cities of Zhangjiakou (in China’s renewable-rich Hebei province) Datong (in the country’s coal-heartland of Shanxi province) and Chengdu which is rich in hydropower and natural gas. To be sure the three cities analysed in this paper do not cover all regional plans and initiatives but they offer a useful window into local hydrogen policy implementation. They also illustrate the major challenges facing green hydrogen as it moves beyond the narrow highly subsidized field of fuel cell vehicles (FCVs). Indeed costs as well as water land availability and technology continue to be constraints.<br/>The hydrogen policies and road maps reviewed in this paper offer numerous targets—often setting quantitative goals for FCVs hydrogen refuelling stations hydrogen supply chain revenue and new hydrogen technology companies—aligning with the view that hydrogen development is currently more of an industrial policy than a decarbonisation strategy. Indeed hydrogen’s potential to decarbonise sectors such as manufacturing and chemicals is of secondary importance if mentioned at all. But as the cities analysed here view hydrogen as part of their industrial programmes economic development and climate strategies support is likely to remain significant even as the specific incentive schemes will likely evolve.<br/>Given this local hydrogen development model rising demand for hydrogen in China could ultimately increase rather than decrease CO₂ emissions from fossil fuels in the short run. At the same time even though the central government’s hydrogen targets (as laid out in its 2022 policy documents) seem relatively conservative Chinese cities’ appetite for new sources of growth and the ability to fund various business models are worth watching.

In recent years growing interest has emerged in investigating the integration of energy storage and green hydrogen production systems with renewable energy generators. These integrated systems address uncertainties related to renewable resource availability and electricity prices mitigating profit loss caused by forecasting errors. This paper focuses on the operation of a hybrid farm (HF) combining an alkaline electrolyzer (AEL) and a battery energy storage system (BESS) with a wind turbine to form a comprehensive HF. The HF operates in both hydrogen and day-ahead electricity markets. A linear mathematical model is proposed to optimize energy management considering electrolyzer operation at partial loads and accounting for degradation costs while maintaining a straightforward formulation for power system optimization. Day-ahead market scheduling and real-time operation are formulated as a progressive mixed-integer linear program (MILP) extended to address uncertainties in wind speed and electricity prices through a two-stage stochastic optimization model. A bootstrap sampling strategy is introduced to enhance the stochastic model’s performance using the same sampled data. Results demonstrate how the strategies outperform traditional Monte Carlo and deterministic approaches in handling uncertainties increasing profits up to 4% per year. Additionally a simulation framework has been developed for validating this approach and conducting different case studies.

Molecular hydrogen (H2 ) is a low-molecular-weight non-polar and electrochemically neutral substance that acts as an effective antioxidant and cytoprotective agent with research into the effects of H2 incorporation into the food chain at various stages rapidly gaining momentum. H2 can be delivered throughout the food growth production delivery and storage systems in numerous ways including as a gas as hydrogen-rich water (HRW) or with hydrogen-donating food supplements such as calcium (Ca) or magnesium (Mg). In plants H2 can be exploited as a seedpriming agent during seed germination and planting during the latter stages of plant development and reproduction as a post-harvest treatment and as a food additive. Adding H2 during plant growth and developmental stages is noted to improve the yield and quality of plant produce through modulating antioxidant pathways and stimulating tolerance to such environmental stress factors as drought stress enhanced tolerance to herbicides (paraquat) and increased salinity and metal toxicity. The benefits of pre- and post-harvest application of H2 include reductions in natural senescence and microbial spoilage which contribute to extending the shelf-life of animal products fruits grains and vegetables. This review collates empirical findings pertaining to the use of H2 in the agri-food industry and evaluates the potential impact of this emerging technology.

One of the challenges associated with the use of hydrogen is its storage and transportation. Hydrogen pipelines are an essential infrastructure for transporting hydrogen from offshore production sites to onshore distribution centers. This paper presents an innovative analysis of the pressure drops velocity profile and levelized cost of hydrogen (LCOH) in various hydrogen transportation scenarios examining the influence of pipeline type (steel vs. composite) diameter and outlet pressure. The role of the compressor and the pipeline individually and together was assessed for 1000 and 100 tons of hydrogen. Notably the LCOH was highly sensitive to these parameters with the compressor contribution ranging between 21.52% and 85.11% and the pipeline’s share varying from 14.89% to 78.48%. The outflow pressure and diameter of the pipeline have a significant impact on the performance: when 1000 tons of hydrogen is transported the internal pressure drop ranges from 2 to 30 bar and the flow velocity can vary between 2 and 25 m/s. For equivalent hydrogen quantities the composite pipeline exhibits the same trends but with minor variations in the specific values.

With the growing demand for green technologies hydrogen energy devices such as Proton Exchange Membrane (PEM) fuel cells and water electrolysers have received accelerated developments. However the materials and manufacturing cost of these technologies are still relatively expensive which impedes their widespread commercialization. Additive Manufacturing (AM) commonly termed 3D Printing (3DP) with its advanced capabilities could be a potential pathway to solve the fabrication challenges of PEM parts. Herein in this paper the research studies on the novel AM fabrication methods of PEM components are thoroughly reviewed and analysed. The key performance properties such as corrosion and hydrogen embrittlement resistance of the additively manufactured materials in the PEM working environment are discussed to emphasise their reliability for the PEM systems. Additionally the major challenges and required future developments of AM technologies to unlock their full potential for PEM fabrication are identified. This paper provides insights from the latest research developments on the significance of advanced manufacturing technologies in developing sustainable energy systems to address the global energy challenges and climate change effects.

This comparative study examines the potential for green hydrogen production in Europe and the Middle East leveraging 3MWp solar and wind power plants. Experimental weather data from 2022 inform the selection of two representative cities namely Krakow Poland (Europe) and Diyala Iraq (Middle East). These cities are chosen as industrial–residential zones representing the respective regions’ characteristics. The research optimizes an alkaline water electrolyzer capacity in juxtaposition with the aforementioned power plants to maximize the green hydrogen output. Economic and environmental factors integral to green hydrogen production are assessed to identify the region offering the most advantageous conditions. The analysis reveals that the Middle East holds superior potential for green hydrogen production compared to Europe attributed to a higher prevalence of solar and wind resources coupled with reduced land and labor costs. Hydrogen production costs in Europe are found to range between USD 9.88 and USD 14.31 per kilogram in contrast to the Middle East where costs span from USD 6.54 to USD 12.66 per kilogram. Consequently the Middle East emerges as a more feasible region for green hydrogen production with the potential to curtail emissions enhance air quality and bolster energy security. The research findings highlight the advantages of the Middle East industrial–residential zone ‘Diyala’ and Europe industrial–residential zone ‘Krakow’ in terms of their potential for green hydrogen production.

This report from the WP5 “Mitigation” provides information and test results regarding perturbations that hydrogen could cause to gas appliances when blended to natural gas especially on anatural draught for exhaust fumes or acidity for the condensates. The important topic of on-site adjustment is also studied with test results on alternative technologies and proposals of mitigation approaches.

The cross-regional renewable hydrogen supply is significant for China to resolve the uneven distribution of renewable energy and decarbonize the transportation sector. Yet the economic comparison of various hydrogen supply routes remains obscure. This paper conducts a techno-economic analysis on six hydrogen supply routes for hydrogen refueling stations including gas-hydrogen tube-trailer gas-hydrogen pipeline liquid-hydrogen truck natural gas pipeline MeOH truck and NH3 truck. Furthermore the impacts of three critical factors are examined including electrolyzer selection transportation distance and electricity price. The results indicate that with a transport distance of 2000 km the natural gas pipeline route offers the lowest cost while the gas-hydrogen tube-trailer route is not economically feasible. The gas-hydrogen pipeline route shows outstanding cost competitiveness between 200 and 2000 km while it is greatly influenced by the utilization rate. The liquid-hydrogen truck route demonstrates great potential with the electricity price decreasing. This study may provide guidance for the development of the cross-regional renewable hydrogen supply for hydrogen refueling stations in China.

Several countries have revised their targets in recent years to reach net-zero CO2 emissions across all sectors by 2050 and the transport sector is responsible for a significant share of these emissions. This study compares possible pathways to decarbonise the transport sector through electrification including passenger cars light commercial vehicles and heavy commercial vehicles. To do so we explore 125 scenarios by varying the share of battery and hydrogen-based fuel cell electric vehicles in each of the three categories above independently. We further model the decarbonisation of the industrial hydrogen demand using electrolysers with hydrogen storage. To explore the potential role of electric and hydrogen transport as well as their trade-offs we use GRIMSEL an open-source sector coupling energy system model of Switzerland which includes the residential commercial industrial and transport sectors with four energy carriers namely electricity heat hot water and hydrogen. The total costs are minimised from a social planner perspective. We find that the full electrification of the transport sector could lead on average to a 12% increase in costs by 2050 and 1.3 MtCO2/year which represents a 90% CO2 emissions reduction for the whole sector. Second the transport energy self-sufficiency (i.e. the share of domestic electricity generation in final transport demand) may reach up to 50% for the scenarios with the largest share of battery electric vehicles mainly due to a smaller energy demand than with hydrogen vehicles. Third more than three quarters of the industrial hydrogen production is met by local photovoltaic electricity coupled with battery at minimum costs i.e. green hydrogen. Finally the use of hydrogen as an energy carrier to store electricity over a long period is not cost-optimal.

As a reformist approach to low-carbon transitions green hydrogen is often promoted as an easy replacement for fossil fuels. This substitution narrative makes this technology compelling as it offers to reduce emissions while continuing the contemporary energy system. Using ‘sociotechnical imaginaries’ this paper explores the underlying political processes on what appears to be a mostly technical vision of green hydrogen. Analysis through expert interviews in Aotearoa New Zealand revealed two contrasting energy visions one emphasizing the technical role of green hydrogen in New Zealand's transition—the green hydrogen imaginary and the other which advocated for a future motivated by social change—the alternative energy imaginary. Comparing the tensions through a lens of hydrogen justice exposed the assumptions and exclusions present in the emerging green hydrogen imaginary. This paper argues that the technocratic business as usual approach of green hydrogen depoliticizes the social nature of energy and thus risks perpetuating inequalities and harms present in the current energy system. However these critiques also suggest that there is hope for green hydrogen to be reimagined in more ethical and just ways.

Green hydrogen is likely to play an important role in meeting the net-zero targets of countries around the globe. One potential option for green hydrogen production is to run electrolysers directly from offshore wind turbines with no grid connection and hence no expensive cabling to shore. In this work an innovative proof of concept of a wind farm control methodology designed to reduce variability in wind farm active power output is presented. Smoothing the power supplied by the wind farm to the battery reduces the size and number of battery charge cycles and helps to increase battery lifetime. This work quantifies the impact of the wind farm control method on battery lifetime for wind farms of 1 4 9 and 16 wind turbines using suitable wind farm battery and electrolyser models. The work presented shows that wind farm control for smoothing wind farm power output could play a critical role in reducing the levelised cost of green hydrogen produced from wind farms with no grid connection by reducing the damaging load cycles on batteries in the system. Hence this work paves the way for the design and testing of a full implementation of the wind farm controller.

In this podcast David Ledesma engages in a conversation with Alex Patonia and Rahmat Poudineh on their recent paper focusing on hydrogen storage for a net-zero carbon future. The podcast delves into the various types of hydrogen storage options highlighting their relative strengths and drawbacks.

In order for a hydrogen economy to be established several key factors must be addressed including efficient and decarbonized production adequate transportation infrastructure and the deployment of suitable hydrogen storage facilities. However hydrogen presents unique challenges when it comes to storage and handling. Due to its extremely low volumetric energy density under ambient conditions hydrogen cannot be efficiently or economically stored without undergoing compression liquefaction or conversion into other more manageable substances.

At present there exist several hydrogen storage solutions at different levels of technology market and commercial readiness each with varying applications depending on specific circumstances.

Additionally the podcast explores the primary barriers that hinder investment in hydrogen storage and the essential components of a viable business model that can address the primary risks to which potential hydrogen storage investors are exposed.

The podcast can be found on their website.

A simulation tool called HYDRA to optimize individual hydrogen infrastructure layouts is presented. The different electrolyzer technologies namely proton exchange membrane electrolysis anion exchange membrane electrolysis alkaline electrolysis and solid oxide electrolysis as well as hydrogen storage possibilities are described in more detail and evaluated. To illustrate the application opportunities of HYDRA three project examples are discussed. The examples include central and decentral applications while taking the usage of hydrogen into account.

The need to reduce the dependency of chemicals on fossil fuels has recently motivated the adoption of renewable energies in those sectors. In addition due to a growing population the treatment and disposition of residual biomass from agricultural processes such as sugar cane and orange bagasse or even from human waste such as sewage sludge will be a challenge for the next generation. These residual biomasses can be an attractive alternative for the production of environmentally friendly fuels and make the economy more circular and efficient. However these raw materials have been hitherto widely used as fuel for boilers or disposed of in sanitary landfills losing their capacity to generate other by-products in addition to contributing to the emissions of gases that promote global warming. For this reason this work analyzes and optimizes the biomass-based routes of biochemical production (namely hydrogen and ammonia) using the gasification of residual biomasses. Moreover the capture of biogenic CO2 aims to reduce the environmental burden leading to negative emissions in the overall energy system. In this context the chemical plants were designed modeled and simulated using Aspen plus™ software. The energy integration and optimization were performed using the OSMOSE Lua Platform. The exergy destruction exergy efficiency and general balance of the CO2 emissions were evaluated. As a result the irreversibility generated by the gasification unit has a relevant influence on the exergy efficiency of the entire plant. On the other hand an overall negative emission balance of −5.95 kgCO2/kgH2 in the hydrogen production route and −1.615 kgCO2/kgNH3 in the ammonia production route can be achieved thus removing from the atmosphere 0.901 tCO2/tbiomass and 1.096 tCO2/tbiomass respectively.

In recent years sustainable development has become a challenge for many societies due to natural or other disruptive events which have disrupted economic environmental and energy infrastructure growth. Developing hydrogen energy infrastructure is crucial for sustainable development because of its numerous benefits over conventional energy sources. However the complexity of hydrogen energy infrastructure including production utilization and storage stages requires accounting for potential vulnerabilities. Therefore resilience needs to be considered along with sustainable development. This paper proposes a decision-making framework to evaluate the resilience of hydrogen energy infrastructure by integrating resilience indicators and sustainability contributing factors. A holistic taxonomy of resilience performance is first developed followed by a qualitative resilience assessment framework using a novel Intuitionistic fuzzy Weighted Influence Nonlinear Gauge System (IFWINGS). The results highlighted that Regulation and legislation Government preparation and Crisis response budget are the most critical resilience indicators in the understudy hydrogen energy infrastructure. A comparative case study demonstrates the practicality capability and effectiveness of the proposed approach. The results suggest that the proposed model can be used for resilience assessment in other areas.

The importance of hydrogen in the effort to decarbonize the power sector has grown immensely in recent years. Previous studies have investigated the effects of mixing hydrogen into natural gas for gas turbine combustors but limited studies have examined the resulting effects hydrogen addition has on the entire system. In this work a thermodynamic model of a gas turbine with combustion chemical kinetics integrated is created and the effects hydrogen addition (0-100 volume percent addition) has on the system performance emissions and combustion kinetics are analyzed. The maximum system performance is achieved when the maximum turbine inlet temperature is reached and the resulting optimal fuel/air equivalence ratio is determined. As hydrogen is added to the fuel mixture the optimal equivalence ratio shifts leaner causing non-linearity in emissions and system performance at optimal conditions. An analysis of variance is conducted and it is shown that isentropic efficiencies of the turbine and compressor influences the system performance the most out of any system parameter. While isentropic efficiencies of the turbine and compressor increase towards 100% an operating regime where the optimal system efficiency cannot be achieved is discovered due to the lower flammability limit of the fuel being reached. This can be overcome by mixing hydrogen into the fuel.

This paper introduces a Techno-Economic Assessment (TEA) on present and future scenarios of different energy storage technologies comprising hydrogen and batteries: Battery Energy Storage System (BESS) Hydrogen Energy Storage System (H2ESS) and Hybrid Energy Storage System (HESS). These three configurations were assessed for different time horizons: 2019 2022 and 2030 under both on-grid and off-grid conditions. For 2030 a sensitivity analysis under different energy scenarios was performed covering other trends in on-grid electric consumption and prices CO2 taxation and the evolution of hydrogen technology prices from 2019 until 2030. The selected case study is the Research Park Zellik (RPZ) a CO2- neutral sustainable Local Energy Community (LEC) in Zellik Belgium. The software HOMER (Hybrid Optimisation Model for Electric Renewable) has been selected to design model and optimise the defined case study. The results showed that BESS was the most competitive when the electric grid was available among the three possible storage options. Additionally HESS was overall more competitive than H2ESS-only regardless of the grid connection mode. Finally as per HESS hydrogen was proved to play a complementary role when combined with batteries enhancing the flexibility of the microgrid and enabling deeper decarbonisation by reducing the electricity bought from the grid increasing renewable energy production and balancing toward an island operating mode.

The abundant hydro resources in Nepal have resulted in the generation of electricity almost exclusively from hydropower plants. Several hydropower plants are also currently under construction. There is no doubt that the surplus electricity will be significantly high in the coming years. Given the previous trend in electricity consumption it will be a challenge to maximize the use of surplus electricity. In this work the potential solutions to maximize the use of this surplus electricity have been analysed. Three approached are proposed: (i) increasing domestic electricity consumption by shifting the other energy use sectors to electricity (ii) cross-border export of electricity and (iii) conversion of electricity to hydrogen via electrolysis. The current state of energy demand and supply patterns in the country are presented. Future monthly demand forecasts and surplus electricity projections have been made. The hydrogen that can be produced with the surplus electricity via electrolysis is determined and an economic assessment is carried out for the produced hydrogen. The analysis of levelized cost of hydrogen (LCOH) under different scenarios resulted values ranging from 3.8 €/kg to 4.5 €/kg.