United Kingdom

The H21 Phase 2 research will provide vital evidence both towards the hydrogen village trial and potential town scale pilots and to the Government which is aiming to make a decision about the use of hydrogen for home heating by 2026.

The key objectives of the H21 Phase 2 NIC project were to further develop the evidence base supporting conversion of the natural gas distribution network to 100% hydrogen. The key principles of H21 NIC Phase 2 were to:

→ Confirm how we can manage and operate the network safely through an appraisal of existing network equipment procedures and network modelling tools.

→ Validate network operations on a purpose-built below 7 barg network as well as an existing unoccupied buried network and provide a platform to publicise and demonstrate a hydrogen network in action.

→ Develop a combined distribution network and downstream Quantitative Risk Assessment (QRA) for 100% hydrogen by further developing the work undertaken on the H21 Phase 1 QRA and the Hy4Heat ‘downstream of ECV’ QRA.

→ Continue to understand how consumers could be engaged with ahead of a conversion. This programme was split into four phases detailed below:

→ Phase 2a – Appraisal of Network 0-7 bar Operations

→ Phase 2b – Unoccupied Network Trials

→ Phase 2c – Combined QRA

→ Phase 2d – Social Sciences

The project with the support of the HSE’s Science & Research Centre (HSE S&RC) and DNV successfully undertook a programme of work to review the NGN below 7 barg network operating procedures. The project implemented testing and demonstrations on the Phase 2a Microgrid at DNV Spadeadam and Phase 2b Unoccupied Trial site in South Bank on a repurposed NGN network to provide and demonstrate the supporting evidence for the required changes to procedures. Details of the outputs of the HSE S&RC procedure review and the evidence collected by DNV from the testing and demonstration projects is provided in detail in this technical summary report.

Due to the differences in gas characteristics between hydrogen and natural gas changes will be required to some of the operational and maintenance procedures the evidence of which is provided in this report. The Gas Distribution Networks (GDNs) will need to review the findings from this project when implementing the required changes to their operational and maintenance procedures.

This paper uses a whole-system approach to examine different strategies related to the future role of the gas grid in a low-carbon heat system. A novel model of integrated gas electricity and heat systems HEGIT is used to investigate four key sets of scenarios for the future of the gas grid using the UK as a case study: (a) complete electrification of heating; (b) conversion of the existing gas grid to deliver hydrogen; (c) a hybrid heat pump system; and (d) a greener gas grid. Our results indicate that although the infrastructure requirements the fuel or resource mix and the breakdown of costs vary significantly over the complete electrification to complete conversion of the gas grid to hydrogen spectrum the total system transition cost is relatively similar. This reduces the significance of total system cost as a guiding factor in policy decisions on the future of the gas grid. Furthermore we show that determining the roles of low-carbon gases and electrification for decarbonising heating is better guided by the trade-offs between short- and long-term energy security risks in the system as well as trade-offs between consumer investment in fuel switching and infrastructure requirements for decarbonising heating. Our analysis of these trade-offs indicates that although electrification of heating using heat pumps is not the cheapest option to decarbonise heat it has clear co-benefits as it reduces fuel security risks and dependency on carbon capture and storage infrastructure. Combining different strategies such as grid integration of heat pumps with increased thermal storage capacity and installing hybrid heat pumps with gas boilers on the consumer side are demonstrated to effectively moderate the infrastructure requirements consumer costs and reliability risks of widespread electrification. Further reducing demand on the electricity grid can be accomplished by complementary options at the system level such as partial carbon offsetting using negative emission technologies and partially converting the gas grid to hydrogen.

This paper presents a mathematical model for a multi-period hydrogen supply chain design problem considering several design features not addressed in other studies. The model is formulated as a mixed-integer program allowing the production and storage facilities to be extended over time. Pipeline and tube trailer transport modes are considered for carrying hydrogen. The model also allows finding the optimal pipeline routes and the number of transport units. The objective is to obtain an efficient supply chain design within a given time frame in a way that the demand and carbon dioxide emissions constraints are satisfied and the total cost is minimized. A computer program is developed to ease the problem-solving process. The computer program extracts the geographical information from Google Maps and solves the problem using an optimization solver. Finally the applicability of the proposed model is demonstrated in a case study from Oman.

Underground hydrogen storage in depleted hydrocarbon reservoirs and aquifers has been proposed as a potential long-term solution to storing intermittently produced renewable electricity as the subsurface formations provide secure and large storage space. Various phenomena can lead to hydrogen loss in subsurface systems with the key cause being the trapping especially during the withdrawal cycle. Capillary trapping in particular is strongly related to the hysteresis phenomena observed in the capillary pressure/saturation and relative-permeability/saturation curves. This paper address two key points: (1) the sole impact of hysteresis in capillary pressure on hydrogen trapping during withdrawal cycles and (2) the dependency of optimal operational parameters (injection/withdrawal flow rate) and the reservoir characteristics such as permeability thickness and wettability of the porous medium on the remaining hydrogen saturation.<br/>Model<br/>To study the capillary hysteresis during underground hydrogen storage Killough [1] model was implemented in the MRST toolbox [2]. A comparative study was performed to quantify the impact of changes in capillary pressure behaviour by including and excluding the hysteresis and scanning curves. Additionally this study investigates the impact of injection/withdrawal rates and the aquifer permeability for various capillary and Bond numbers in a homogeneous system.<br/>Findings<br/>It was found that although the hydrogen storage efficiency is not considerably impacted by the inclusion of the capillary-pressure scanning curves the impact of capillary pressure on the well properties (withdrawal rate and pressure) can become significant. Higher injection and withdrawal rates does not necessarily lead to a better performance in terms of productivity. The productivity enhancement depends on the competition between gravitational capillary and viscous forces. The observed water upconing at relatively high capillary numbers resulted in low hydrogen productivity. highlighting the importance of well design and placement.

Hydrogen (H2) has rapidly become a topic of great attention when discussing routes to net-zero carbon emissions. About 14% of CO2 emissions globally are directly associated with domestic heating in buildings. Replacing natural gas (NG) with H2 for heating has been highlighted as a rapid alternative for mitigating these emissions. To realise this not only the production challenges but also potential obstacles in the transmission/distribution and combustion of H2 must be technically identified and discussed. This review in addition to delineating the challenges of H2 in NG grid pipelines and H2 combustion also collates the results of the state-of-the-art technologies in H2-based heating systems. We conclude that the sustainability of water and renewable electricity resources strongly depends on sizing siting service life of electrolysis plants and post-electrolysis water disposal plans. 100% H2 in pipelines requires major infrastructure upgrades including production transmission pressurereduction stations distribution and boiler rooms. H2 leakage instigates more environmental risks than economic ones. With optimised boilers burning H2 could reduce GHG emissions and obtain an appropriate heating efficiency; more data from boiler manufacturers must be provided. Overall green H2 is not the only solution to decarbonise heating in buildings and it should be pursued abreast of other heating technologies.

Future Energy Scenarios (FES) represent a range of different credible ways to decarbonise our energy system as we strive towards the 2050 target.<br/>We’re less than 30 years away from the Net Zero deadline which isn’t long when you consider investment cycles for gas networks electricity transmission lines and domestic heating systems.<br/>FES has an important role to play in stimulating debate and helping to shape the energy system of the future.

Our Future Energy Scenarios (FES) draw on hundreds of experts’ views to model four credible energy pathways for Britain over coming decades. Matthew Wright our head of strategy and regulation outlines what the 2021 outlook means for consumers society and the energy system itself.<br/>This year’s Future Energy Scenarios insight reveals a glimpse of a Britain that is powered with net zero carbon emissions.<br/>Our analysis shows that our country can achieve its legally-binding carbon reduction targets: in three out of four scenarios in the analysis the country reaches net zero carbon emissions by 2050 with Leading the Way – our most ambitious scenario – achieving it in 2047 and becoming net negative by 2050.

Billions of litres of wastewater are produced daily from domestic and industrial areas and whilst wastewater is often perceived as a problem it has the potential to be viewed as a rich source for resources and energy. Wastewater contains between four and five times more energy than is required to treat it and is a potential source of bio-hydrogen—a clean energy vector a feedstock chemical and a fuel widely recognised to have a role in the decarbonisation of the future energy system. This paper investigates sustainable low-energy intensive routes for hydrogen production from wastewater critically analysing five technologies namely photo-fermentation dark fermentation photocatalysis microbial photo electrochemical processes and microbial electrolysis cells (MECs). The paper compares key parameters influencing H2 production yield such as pH temperature and reactor design summarises the state of the art in each area and highlights the scale-up technical challenges. In addition to H2 production these processes can be used for partial wastewater remediation providing at least 45% reduction in chemical oxygen demand (COD) and are suitable for integration into existing wastewater treatment plants. Key advancements in lab-based research are included highlighting the potential for each technology to contribute to the development of clean energy. Whilst there have been efforts to scale dark fermentation electro and photo chemical technologies are still at the early stages of development (Technology Readiness Levels below 4); therefore pilot plants and demonstrators sited at wastewater treatment facilities are needed to assess commercial viability. As such a multidisciplinary approach is needed to overcome the current barriers to implementation integrating expertise in engineering chemistry and microbiology with the commercial experience of both water and energy sectors. The review concludes by highlighting MECs as a promising technology due to excellent system modularity good hydrogen yield (3.6–7.9 L/L/d from synthetic wastewater) and the potential to remove up to 80% COD from influent streams.

Hydrogen is gaining traction as a key energy carrier due to its clean combustion high energy content and versatility. As the world shifts towards sustainable energy hydrogen demand is rapidly increasing. This paper introduces a novel hybrid time series modeling approach designed and developed to accurately predict hydrogen demand by mixing linear and nonlinear models and accounting for the impact of non-recurring events and dynamic energy market changes over time. The model incorporates key economic variables like hydrogen price oil price natural gas price and gross domestic product (GDP) per capita. To address these challenges we propose a four-part framework comprising the Hodrick–Prescott (HP) filter the autoregressive fractionally integrated moving average (ARFIMA) model the enhanced empirical wavelet transform (EEWT) and high-order fuzzy cognitive maps (HFCM). The HP filter extracts recurring structural patterns around specific data points and resolves challenges in hybridizing linear and nonlinear models. The ARFIMA model equipped with statistical memory captures linear trends in the data. Meanwhile the EEWT handles non-stationary time series by adaptively decomposing data. HFCM integrates the outputs from these components with ridge regression fine-tuning the HFCM to handle complex time series dynamics. Validation using stochastic non-Gaussian synthetic data demonstrates that this model significantly enhances prediction performance. The methodology offers notable improvements in prediction accuracy and stability compared to existing models with implications for optimizing hydrogen production and storage systems. The proposed approach is also a valuable tool for policy formulation in renewable energy and smart energy transitions offering a robust solution for forecasting hydrogen demand

This study focuses on arguably the most contentious choice of energy supply option available for decarbonizing general-purpose long-haul road freight: hydrogen. For operators infrastructure providers energy providers and vehicle manufacturers to make the investments necessary to enable this transition it is essential to evaluate the feasibility of individual energy supply choices. A literature review is conducted identifying ten requirements for an energy supply choice to be feasible which are then translated into “what would need to be true” conditions for hydrogen to meet these requirements. Considering these evidence from literature is used to assess the likelihood of each condition becoming true within the lifespan of a vehicle bought today. It is concluded that it is unlikely that hydrogen will become feasible in this time frame meaning it can be disregarded as a current vehicle purchase consideration as it will not undermine the competitiveness or resale value of a vehicle using a different energy source bought today. There are two principal innovations in the study approach: the consideration of socio-technical and political as well as techno-economic factors; and the application of realist retroductive option assessment. While not necessary to address the research question regarding hydrogen a realist retroductive assessment is also presented for other prominent low carbon energy source options: battery electric electric road systems (ERS) and biofuels; and the conditions under which these options could be feasible are considered.

The hydrogen fuel quality is critical to the efficiency and longevity of fuel cell electric vehicles (FCEVs) with ISO 14687:2019 grade D establishing stringent impurity limits. This study compared two different sampling techniques for assessing the hydrogen fuel quality focusing on the National Physical Laboratory hydrogen direct sampling apparatus (NPL DirSAM) from a 35 MPa heavy-duty (HD) dispenser and qualitizer sampling from a 70 MPa light-duty (LD) nozzle both of which were deployed on the same day at a local hydrogen refuelling station (HRS). The collected samples were analysed as per the ISO 14687:2019 contaminants using the NPL H2-quality laboratory. The NPL DirSAM was able to sample an HD HRS demonstrating the ability to realise such sampling on an HD nozzle. The comparison of the LD (H2 Qualitizer sampling) and HD (NPL DirSAM) devices showed good agreement but significant variation especially for sulphur compounds non-methane hydrocarbons and carbon dioxide. These variations may be related to the HRS difference between the LD and HD devices (e.g. flow path refuelling conditions and precooling for light duty versus no precooling for heavy duty). Further study of HD and LD H2 fuel at HRSs is needed for a better understanding.

The turbocharging of hydrogen fuel cell systems (FCSs) has recently become a prominent research area aiming to improve FCS efficiency to help decarbonise the energy and transport sectors. This work compares the performance of an electrically assisted variable-geometry turbocharger (VGT) with a fixed-geometry turbocharger (FGT) by optimising both the sizing of the components and their operating points ensuring both designs are compared at their respective peak performance. A MATLAB-Simulink reducedorder model is used first to identify the most efficient components that match the fuel cell air path requirements. Maps representing the compressor and turbines are then evaluated in a 1D flow model to optimise cathode pressure and stoichiometry operating targets for net system efficiency using an accelerated genetic algorithm (A-GA). Good agreement was observed between the two models’ trends with a less than 10.5% difference between their normalised e-motor power across all operating points. Under optimised conditions the VGT showed a less than 0.25% increase in fuel cell system efficiency compared to the use of an FGT. However a sensitivity study demonstrates significantly lower sensitivity when operating at non-ideal flows and pressures for the VGT when compared to the FGT suggesting that VGTs may provide a higher level of tolerance under variable environmental conditions such as ambient temperature humidity and transient loading. Overall it is concluded that the efficiency benefits of VGT are marginal and therefore not necessarily significant enough to justify the additional cost and complexity that they introduce.

Demand for low-carbon sources of hydrogen and power is expected to rise dramatically in the coming years. Individually steam methane reformers (SMRs) and combined cycle gas power plants (CCGTs) when combined with carbon capture utilisation and storage (CCUS) can produce large quantities of ondemand decarbonised hydrogen and power respectively. The ongoing trend towards the development of CCUS clusters means that both processes may operate in close proximity taking advantage of a common infrastructure for natural gas supply electricity grid connection and the CO2 transport and storage network. This work improves on a previously described novel integration process which utilizes flue gas sequential combustion to incorporate the SMR process into the CCGT cycle in a single “combined fuel and power” (CFP) plant by increasing the level of thermodynamic integration through the merger of the steam cycles and a redesign of the heat recovery system. This increases the 2nd law thermal efficiency by 2.6% points over un-integrated processes and 1.9% points the previous integration design. Using a conventional 35% wt. monoethanolamine (MEA) CO2 capture process designed to achieve two distinct and previously unexplored CO2 capture fractions; 95% gross and 100% fossil (CO2 generated is equal to the quantity of CO2 captured). The CFP configuration reduces the overall quantity of flue gas to be processed by 36%–37% and increases the average CO2 concentration of the flue gas to be treated from 9.9% to 14.4% (wet). This decreases the absorber packing volume requirements by 41%–56% and decreases the specific reboiler duty by 5.5% from 3.46–3.67 GJ/tCO2 to 3.27–3.46 GJ/tCO2 further increasing the 2nd law thermal efficiency gains to 3.8%–4.4% points over the un-integrated case. A first of a kind techno economic analysis concludes that the improvements present in a CO2 abated CFP plant results in a 15.1%–17.3% and 7.6%–8.0% decrease in capital and operational expenditure respectively for the CO2 capture cases. This translates to an increase in the internal rate of return over the base hurdle rate of 7.5%–7.8% highlighting the potential for substantial cost reductions presented by the CFP configuration.

In a fully decarbonized global energy system hydrogen is likely to be one of few energy vectors that can facilitate long-distance export of renewable energy. However because of divergent literature findings consensus is yet to be reached on the total supply chain costs of shipping hydrogen either as a cryogenic liquid or ammonia. To this end this article presents a detailed process systems-based economic analysis of a typical hydrogen value chain in 2050 employing the method of elementary effects to quantify the effect of uncertainties. With expected landed costs for liquid hydrogen of $4.60 kg1 (H2) and ammonia of $3.30 kg1 (H2) the importance of uncertainty quantification is demonstrated given that specific parametric combinations can yield landed costs below $2.50 kg1 (H2). Given our delivered hydrogen cost of $4.70 kg1 (H2) these results demonstrate the stark difference between the aspirations of decarbonization policy (with some countries aiming for prices below $1 kg1 by 2050) and the present techno-economic reality.

As hydrogen emerges as a pivotal energy carrier in the global transition towards net-zero emissions addressing its technological and regulatory challenges is essential for large-scale deployment. The widespread adoption of hydrogen technologies requires extensive research technical advancements validation testing and certification to ensure their efficiency reliability and safety across various applications including industrial processes power generation and transportation. This study provides an overview of key enabling technologies for green hydrogen production and distribution highlighting the critical challenges that must be overcome to facilitate their widespread adoption. It examines key hydrogen use cases across multiple sectors analysing their associated technical and infrastructural challenges. The technological advancements required to improve hydrogen production storage transportation and end-use applications are discussed. The development of state-of-the-art testing and validation facilities is also assessed as these are vital for ensuring safety performance and regulatory compliance. This work also reviews some of the ongoing academic and industrial initiatives in the UK aimed at promoting technological innovation advancing hydrogen expertise and developing world-class testing infrastructures. This study emphasises the need for stronger more integrated collaboration between universities industries and certifying bodies for building a strong network that promotes knowledge sharing standardisation and innovation for expanding hydrogen solutions and creating a sustainable hydrogen economy.

: Hydrogen is a clean non-polluting fuel and a key player in decarbonizing the energy sector. Interest in hydrogen production has grown due to climate change concerns and the need for sustainable alternatives. Despite advancements in waste-to-hydrogen technologies the efficient conversion of mixed plastic waste via an integrated thermochemical process remains insufficiently explored. This study introduces a novel multi-stage pyrolysis-reforming framework to maximize hydrogen yield from mixed plastic waste including polyethylene (HDPE) polypropylene (PP) and polystyrene (PS). Hydrogen yield optimization is achieved through the integration of two water–gas shift reactors and a pressure swing adsorption unit enabling hydrogen production rates of up to 31.85 kmol/h (64.21 kg/h) from 300 kg/h of mixed plastic wastes consisting of 100 kg/h each of HDPE PP and PS. Key process parameters were evaluated revealing that increasing reforming temperature from 500 ◦C to 1000 ◦C boosts hydrogen yield by 83.53% although gains beyond 700 ◦C are minimal. Higher reforming pressures reduce hydrogen and carbon monoxide yields while a steam-to-plastic ratio of two enhances production efficiency. This work highlights a novel scalable and thermochemically efficient strategy for valorizing mixed plastic waste into hydrogen contributing to circular economy goals and sustainable energy transition.

This paper presents a comprehensive thermo-economic analysis of a novel Power-to-X (P2X) polygeneration system designed for the production of hydrogen ammonia and methanol with near-zero CO2 emissions. The system integrates an air separation unit (ASU) a direct oxy-combustor (DOC) powered by natural gas combined with a supercritical carbon dioxide (sCO2) power cycle water electrolyzer (WE) a Haber-Bosch process (HBP) and a methanol production unit (MPU). The system is investigated in four configurations: ASU + DOC-sCO2 (S1) ASU + DOC-sCO2 + WE (S2) ASU + DOC-sCO2 + WE + HBP (S3) and ASU + DOC-sCO2 + WE + HBP + MPU (S4) each contributing to improve energy efficiency and reduced emissions. Simulation results show that the overall system efficiency reaches 56 % improving from 45 % to 56 % across different configurations. The system’s levelized cost of hydrogen (LCOH) decreases significantly from $1.70/kg to $0.80/kg and the levelized cost of electricity (LCOE) decreases from 4.30 ¢/kWh to 3.30 ¢/kWh. CO2 emissions are reduced from 200 gCO2/ MWe to 145 gCO2/MWe with the CO2 reduction rate improving from 89 % to 94 %. These results demonstrate the economic viability and environmental sustainability of the proposed P2X system paving the way for industrial decarbonization and large-scale deployment in future energy infrastructures.

The UK has set an ambitious target of delivering clean power by 2030. Low carbon dispatchable power generation using hydrogen will play a key role in a clean power system by providing flexibility and other services for system operability and also by providing supply adequacy during extended periods of low renewable output decarbonising the role currently performed by an aging portfolio of unabated natural gas power generation. While some 100% hydrogen to power (H2P) commercial projects are already being deployed globally using multi megawatt fuel cells alongside blending hydrogen into existing gas turbines and new hydrogen ready turbines industrial scale 100% H2P projects face additional challenges of deploying new technology into a nascent system one which requires significant volumes of hydrogen storage with long lead times. To achieve the 2030 clean power system ambition and lay the foundations for a clean resilient and secure power system beyond 2030 it is critical that the new government takes resolute actions now to support H2P at scale. A clear strategic plan should be developed within the first 12 months of the new administration with clarity being given on policy business models and deployment rates for hydrogen to power (H2P) and its enabling infrastructure. This report produced by Hydrogen UK’s Power Generation Working Group explores the role that H2P will play in the decarbonised power system of the future the barriers to deployment and recommendations for overcoming them.

This paper can be found on their website.

Low carbon hydrogen has a fundamental role to play in not one but two of the UK Government’s core missions. First it can help grow the economy - with thousands of new jobs and opportunities breathing new life into our industrial heartlands. Second it can help the UK become a clean energy superpower by using clean secure energy that we control. Third it can future-proof the UK’s foundational industries delivering decarbonisation and energy security to the hard-to-abate sectors which underpin the UK economy. Hydrogen developers across our membership report growing interest from customers in a wide range of sectors. Whilst current government policy has helped start the hydrogen economy industry wants this to accelerate and become more holistic so that interest is translated into demand allowing the sector to fully develop and the UK to meet its decarbonisation targets. With growing international competition the UK Government should prioritise the growth of hydrogen technology implementation leveraging the nation’s natural geological and geographical advantages. Although £20 billion in private capital investment is estimated to be ready to support the UK Government’s hydrogen ambitions persistent delays and market uncertainty risk this funding being lost to other markets. This report outlines the importance of Driving Demand for offtakers complementing the strong market foundation built from Government’s early hydrogen production focus. For effective policy implementation industry stakeholders have highlighted the importance of finding balance: retaining low-carbon technology optionality alongside certainty and support for investment with the adoption of a clear ‘vision’ and ‘market creation’ supported by a tailored mix of ‘carrots and sticks’ to support the market. From the research conducted by HUK it is clear that the choice of decarbonisation options is not done on a sector-by-sector basis that even within companies the decision-making process is site-by-site. This reflects the sensitivity of numerous factors that will ultimately determine the best solution for their site and re-enforces the view that customers must be allowed the choice of decarbonisation options. Hydrogen will play a significant role in decarbonising some of the hardest to abate sectors of the UK economy complimenting the role of electrification CCUS and other decarbonisation technologies. These sectors represent the hardest and therefore most expensive to decarbonise. However hydrogen also provides an opportunity to deliver significant economic growth through a thriving domestic supply chain and so a holistic approach should be applied.

The paper can be found on their website.

The decarbonization of energy systems poses significant challenges to energy networks due to the introduction of new energy vectors and changes in the pattern of energy demand. However this is currently an under-researched area. This paper addresses a gap in the literature by drawing on the socio-technological transitions and multi-system interactions literature to explore the views of experts from industry academia and other sectors about the challenges facing UK energy networks and the possible solutions including taking a more wholistic approach to the planning and operation of dierent networks. Using these frameworks we have demonstrated that systems can be deliberately integrated to interact and solve particular system challenges and have identified the nature of these interactions. The empirical results identify areas of consensus and disagreement about the future development of network infrastructure and regulation. They also highlight how government policy responds to the challenges and opportunities presented by the UK climate targets. The findings show widespread agreement that the UK energy system will become more electrified and decentralized as it incorporates more renewable energy. However the role of gaseous fuels in the energy system is more uncertain with some experts seeing a move from natural gas to hydrogen as being key to maintaining the security of supply while others see little or no role for hydrogen. There is also widespread agreement that the regulatory structure should change to address the challenges facing energy networks with much less agreement on whether this could happen quickly enough. Recent developments indicate the UK Government recognizes the need for regulatory change but it is premature to foresee their success in helping networks be a driver of rather than a barrier to a net-zero energy system.

As the need for sustainable hydrogen storage solutions increases enhancing the bonding interface between polymer liners and carbon fiber-reinforced polymer (CFRP) in Type IV hydrogen tanks is essential to ensure tank integrity and safety. This study investigates the effect of plasma treatment on polyethylene (PE) and PE/graphene nanoplatelets (GNP) composites to optimize bonding with CFRP simulating the liner-CFRP interface in hydrogen tanks. Initially plasma treatment effects on PE surfaces were assessed focusing on plasma energy and exposure time with key surface modifications characterized and bonding performance being evaluated. Plasma treatment on PE/GNP composites with increasing GNP content was then examined comparing the bonding effectiveness of untreated and plasma-treated samples. Wedge peel tests revealed that plasma treatment significantly enhanced PE-CFRP bonding with optimal conditions at 510 W and 180 s resulting in 212 % and 165 % increases in the wedge peel strength and fracture energy respectively. Plasma-treated PE/GNP composites with 0.75 wt.% GNP achieved a notable bonding enhancement with CFRP showing 528 % and 269 % improvements in strength and fracture energy over untreated neat PE-CFRP samples. These findings offer practical implications for improving the mechanical performance of hydrogen storage tanks contributing to safer and more efficient hydrogen storage systems for a sustainable energy future.

Green hydrogen and ammonia are forecast to play key roles in the deep decarbonization of the global economy. Here we explore the potential of using green hydrogen and ammonia to couple the energy agriculture and industrial sectors with India’s nationalscale electricity grid. India is an ideal test case as it currently has one of the most ambitious hydrogen programs in the world with projected electricity demands for hydrogen and ammonia production accounting for over 1500 TWh/yr or nearly 25% of India’s total electricity demand by 2050. We model the ambitious deep decarbonization of India’s electricity grid and half of its steel and fertilizer industries by 2050. We uncover modest risks for India from such a strategy with many benefits and opportunities. Our analysis suggests that a renewables-based energy system coupled with ammonia off-take sectors has the potential to dramatically reduce India’s greenhouse emissions reduce requirements for expensive long-duration energy storage or firm generating capacity reduce the curtailment of renewable energy provide valuable short-duration and long-duration load-shifting and system resilience to inter-annual weather variations and replace tens of billions of USD in ammonia and fuel imports each year. All this while potentially powering new multi-billion USD green steel and maritime fuel export industries. The key risk for India in relation to such a strategy lies in the potential for higher costs and reduced benefits if the rest of the world does not match their ambitious investment in renewables electrolyzers and clean storage technologies. We show that such a pessimistic outcome could result in the costs of green hydrogen and ammonia staying high for India through 2050 although still within the range of their gray counterparts. If on the other hand renewable and storage costs continue to decline further with continued global deployment all the above benefits could be achieved with a reduced levelized cost of hydrogen and ammonia (10–25%) potentially with a modest reduction in total energy system costs (5%). Such an outcome would have profound global implications given India’s central role in the future global energy economy establishing India’s global leadership in green shipping fuel agriculture and steel while creating an affordable sustainable and secure domestic energy supply.

The power to weight ratio of power plants is an important consideration especially in the design of Unmanned Aircraft System (UAS). In this paper a UAS with an MTOW of 35.3 kg equipped with a fuel cell as a prime power supply to provide electrical power to the propulsion system is considered. A pressure vessel design that can estimate and determine the total size and weight of the combined power plant of a fuel cell stack with hydrogen and air/oxygen vessels and the propulsion system of the UAS for highaltitude operation is proposed. Two scenarios are adopted to determine the size and weight of the pressure vessels required to supply oxygen to the fuel cell stack. Different types of stainless-steel materials are used in the design of the pressure vessel in order to find an appropriate material that provides low size and weight advantages. Also the design of a hydrogen pressure vessel and mass estimation are also considered. The estimated sizes and weights of the hydrogen and oxygen vessels of the power plant and propulsion system in this research offer a maximum of four hours of flying time for the UAS mission; this is based on a Horizon (H-1000) Proton Exchange Membrane (PEM) stack.

Located in the Arabian Gulf Kuwait is a renewable-abundant country ideal for producing hydrogen via solar energy (green hydrogen). With a global transition away from fossil fuels underway due to their adverse environmental impacts hydrogen is gaining significant traction as a promising clean energy alternative for the transport sector. Despite this there are still various challenges associated with implementing a hydrogen supply chain particularly with regard to the conflicting objectives of minimising cost environmental impact and risk. This study determines the feasibility of implementing a green hydrogen supply chain in Kuwait based on a multiobjective design to determine which combination of production (electrolysis type) storage method and transportation method is the most optimal for Kuwait. Three objective functions were considered in this study: the hydrogen supply chain cost environmental impact and safety/risk. A mathematical formulation based on mixed integer linear programming (MILP) was used involving a multi-criteria approach where the three considered objectives must be optimised simultaneously i.e. cost global warming potential and safety/risk. The multiobjective optimisation approach via the weighted sum method was applied in this study and solved via GAMS. To account for the ranking of multi-objective criteria a hybrid AHP-TOPSIS approach was used. Results showed that medium and high demand scenarios better reflect the comparative advantages of each considered method in terms of their multi-objective trade-offs. In particular it was found that higher hydrogen demand amplifies the impact of higher efficiency and operational savings within several production storage and transportation methods and that despite higher initial capital investments these costs are at some point offset by superior operational efficiency as hydrogen production volumes increase. Conversely using highly efficient electrolysers or transportation methods at low demand was found to limit their performance.

The reliance on hydrogen as part of the transition towards a low-carbon economy will require developing dedicated pipeline infrastructure. This deployment will be shaped by regulatory frameworks governing investment and access conditions ultimately structuring how the commodity is traded. The paper assesses the market design for hydrogen infrastructure assuming the application of unbundling requirements. For this purpose it develops a general economic framework for regulating pipeline infrastructure focusing on asset specificity market power and access rules. The paper assesses the scope of application of infrastructure regulation which can be set to individual pipelines or to entire networks. When treated as entire networks the infrastructure can provide flexibility to enhance market liquidity. However this requires establishing network monopolies which rely on central planning and reduce the overall dynamic efficiency of the sector. The paper further compares the regulation applied to US and EU natural gas pipeline infrastructure. Based on the different challenges faced by the EU hydrogen sector including absence of wholesale concentration and large infrastructure needs the paper draws lessons for a regulatory framework establishing the main building blocks of a hydrogen target model. The paper recommends a review of the current EU regulatory framework in the Hydrogen and Decarbonised Gas Package to enable i) the application of regulation to individual pipelines rather than entire networks; ii) the use of negotiated third-party access light-touch regulation and possibly marketbased coordination mechanisms for the access to the infrastructure and iii) a more significant role for long-term capacity contracts to underpin infrastructure investments.