United Kingdom

The decarbonisation of waterborne transport is arguably the biggest challenge faced by the maritime industry presently. By 2050 the International Maritime Organization (IMO) aims to reduce greenhouse gas emissions from the shipping industry by 50% compared to 2008 with a vision to phase out fossil fuels by the end of the century as a matter of urgency. To meet such targets action must be taken immediately to address the barriers to adopt the various clean shipping options currently at different technological maturity levels. Green hydrogen as an alternative fuel presents an attractive solution to meet future targets from international bodies and is seen as a viable contributor within a future clean shipping vision. The cost of hydrogen fuel—in the shortterm at least—is higher compared to conventional fuel; therefore energy-saving devices (ESDs) for ships are more important than ever as implementation of rules and regulations restrict the use of fossil fuels while promoting zero-emission technology. However existing and emerging ESDs in standalone/combination for traditional fossil fuel driven vessels have not been researched to assess their compatibility for hydrogen-powered ships which present new challenges and considerations within their design and operation. Therefore this review aims to bridge that gap by firstly identifying the new challenges that a hydrogen-powered propulsion system brings forth and then reviewing the quantitative energy saving capability and qualitive additional benefits of individual existing and emerging ESDs in standalone and combination with recommendations for the most applicable ESD combinations with hydrogen-powered waterborne transport presented to maximise energy saving and minimise the negative impact on the propulsion system components. In summary the most compatible combination ESDs for hydrogen will depend largely on factors such as vessel types routes propulsion operation etc. However the mitigation of load fluctuations commonly encountered during a vessels operation was viewed to be a primary area of interest as it can have a negative impact on hydrogen propulsion system components such as the fuel cell; therefore the ESD combination that can maximise energy savings as well as minimise the fluctuating loads experienced would be viewed as the most compatible with hydrogen-powered waterborne transport.

The APPG on Hydrogen has published its report urging the Government to deliver beyond its existing net zero commitments and set ambitious hydrogen targets in forthcoming strategies to reach net zero by 2050.

The All-Party Parliamentary Group (APPG) on Hydrogen’s report on the role of ‘Hydrogen in powering industry’ sets out 10 recommendations to support and accelerate the growth of the UK’s hydrogen sector and enable a sustainable energy transition.

• The Government must continue to expand beyond its existing commitments of 5GW production in the forthcoming Hydrogen Strategy.
• Any forthcoming Government and devolved policies must be complementary of the wider UK low-carbon commitments.
• Industrial clusters should be prioritised for hydrogen use and will be the key catalyst for driving forward the UK’s decarbonisation of industry.
• The Government must commit to incentivising hydrogen production within the UK as opposed to importing this.
• The Government must align hydrogen production pathways with nuclear technology to enhance hydrogen production.
• The Government must develop a UK wide hydrogen network to support the transport sector including a larger-scale implementation of hydrogen refuelling stations.
• Regulators must act quickly to update energy regulations and guidance to support hydrogen’s role in powering industry.
• For hydrogen to expand in the UK a technology neutral approach is required for all types of energy systems.
• Significant and long-term financial support is required for the development deployment and operation of hydrogen technologies.
• Ofgem must ensure the hydrogen market is subject to effective competition to drive down prices for consumers.

In 2020 the Department for Business Enterprise and Industrial Strategy (BEIS) commissioned Energy & Utility Skills to develop and deliver a Hydrogen Competency Framework as part of the Hy4Heat programme. The successful completion of this work is detailed in a new report published today.

The work done by Energy & Utility Skills was underpinned by three key pillars:

Collaboration

• Driving growth in engagement levels across the industry

Scalability

• Designing the framework for both initial trials and any future rollout

Safety

• The framework ensures engineers will have all the skills knowledge and understanding they need

The Hydrogen Competency Framework establishes a series of sequential components designed to ensure any future work done to install and maintain new hydrogen appliances will be completed safely to the highest standards and will only be carried out by hydrogen competent Gas Safe Registered engineers.

The resulting outputs of the design development stages are:

• A Comparative Analysis of Hydrogen and existing hydrocarbon gases
• A Skills Matrix that translates the analysis into skills knowledge and understanding
• An Interim Hydrogen Technical Standard that defines acceptable parameters and requirements for hydrogen installation work
• A Hydrogen Training Specification that will enable training course consistency and facilitate industry recognition
• An independent Hydrogen Assessment Module that will facilitate the addition of a hydrogen competence category on the Gas Safe Register

The Hydrogen Competency Framework is a significant success for the UK Gas Sector. This scalable framework will evolve and expand as the roll out of hydrogen into larger commercial applications occurs ahead of Hydrogen Apprenticeships becoming a reality. In the meantime it delivers the means to ensure the competence of engineers who will pioneer the transition to a hydrogen-fuelled gas industry.

More details about this report can be found on the Energy & Utility Skills website.

In the debate on the decarbonisation of heat renewable electricity tends to play a much more dominant role than green gases despite the potential advantages of gas in terms of utilising existing transportation networks and end-use appliances. Informed comparisons are hampered by information asymmetry; the renewable electricity has seen a huge grid level deployment whereas low-carbon hydrogen or bio-methane have been limited to some small stand-alone trials. This paper explores the regulatory and commercial challenges of implementing the first UK neighbourhood level 100% low-carbon hydrogen demonstration project. We draw on existing literature and action research to identify the key practical barriers currently hindering the ability of strategically important actors to accelerate the substitution of natural gas with low carbon hydrogen in local gas networks. This paper adds much needed contextual depth to existing generic and theoretical understandings of low-carbon hydrogen for heat transition feasibility. The learnings from pilot projects about the exclusion of hydrogen calorific value from the Local Distribution Zone calorific value calculation Special Purpose Vehicle companies holding of liability and future costs to consumers need to be quickly transferred into resilient operational practice or gas repurposing projects will continue to be less desirable than electrification using existing regulations and with more rapid delivery

Hydrogen is increasingly being viewed as a significant fuel for future industrial processes as it offers pathways to zero emission. The UK sees hydrogen as one of a handful of low-carbon solutions for transition to net zero. Currently most hydrogen production is from steam reforming of natural gas or coal gasification both of which involve the release of carbon dioxide. Hydrogen production from mini decentralised grids via a thermochemical process coupled with electricity production could offer favourable economics for small modular reactors (SMRs) whereby demand or grid management as a solution would include redirecting the power for hydrogen production when electricity demand is low. It also offers a clean-energy alternative to the aforementioned means. SMRs could offer favourable economics due to their flexible power system as part of the dual-output function. This study objective is to investigate the critical performance parameters associated with the nuclear power plant (NPP) the cycle working fluids and control-system design for switching between electricity and hydrogen demand to support delivery as part of a mini grid system for a reactor power delivering up to approximately 600 MWth power. The novelty of the work is in the holistic parametric analysis undertaken using a novel in-house tool which analyses the NPP using different working fluids with a control function bolt-on at the offtake for hydrogen production. The results indicate that the flow conditions at the offtake can be maintained. The choice of working fluids affects the pressure component. However the recuperator and heat-exchanger effectiveness are considered as efficiency-limiting factors for hydrogen production and electricity generation. As such the benefit of high-technology heat exchangers cannot be underestimated. This is also true when deciding on the thermochemical process to bolt onto the plant. The temperature of the gas at the end of the pipeline should also be considered to ensure that the minimum temperature-requirement status for hydrogen production is me

Commercialization of proton exchange membrane fuel cells can only materials provided its performance is closely related to existing technologies useful in commercial application. Other critical parameters like the utilization of cheaper materials should be taken into account during the manufacturing of the cell. A key component in the cell that has direct correlation to the cell perfor‐ mance is the flow plate. The weight coupled with cost of the cell revolves around the flow plate used in the manufacturing of the cell. This study explores materials ideal for the manufacturing of fuel cells in order to improve the overall cell performance. The investigation highlights the critical impact of varying materials used in the manufacturing of flow plates for PEM fuel cells. Stainless steel (SS) aluminium (Al) and copper (Cu) were the materials considered. The flow plate designs considered were serpentine and open pore cellular foam channel. Machine learning using python for the validation of the results with Linear regression Ridge regression and Polynomial regression algorithm was carried out. The performance of both flow field channels was compared using dif‐ ferent bipolar plate materials. The results show that metal foam flow channels overall performance was better than serpentine flow channels with all the various bipolar plate material used and Al material outperformed Cu and SS material. There is a direct correlation in terms of the outcome of the study and literature based on the data generated experimentally. It can however be concluded that molecules of hydrogen are stable on aluminium plates compared to copper and stainless steel

The independent cross-party report highlights a ‘sensible middle ground’ in the renewables debate and calls for more effort in building cross-party consensus. It finds that the UK has only just begun to harness low carbon renewable resources bigger than North Sea oil and gas and argues that the Government could do more to narrow the scope of debate about the technology mix beyond 2020. It argues that it should work with industry and academia first to establish ‘low regrets’ levels of technology deployment and second to ensure that policies are in place to incentivise investments such as supply chain investment needed to deliver these low regrets actions.

This approach would help provide the longer term clarity that could secure supply chain investments giving the UK a head-start in the global race. The report finds that these investments could be missed delayed or more expensive if there is insufficient confidence about long term demand for key technologies such as offshore wind. Work by Government to help incentivise these investments would increase the likelihood that technology cost reductions are achieved and help mitigate against high costs if new nuclear or carbon capture and storage development fail or are delayed.

On affordability the report finds that there are ‘hidden’ benefits that the UK could see from investing more in renewables through electricity bills between now and 2020. These include: avoiding bill increases driven by fossil fuels; making electricity bills more predictable; and providing an economic boost. The extra money paid to support renewables and other low carbon generation such as nuclear power could be more than offset by energy efficiency savings although Government needs to do more to show how these savings will arise.

On sustainability the report tackles myths about the carbon emitted in manufacturing renewable technologies or in backing up varying technologies such as wind solar wave and tidal. It finds that even when considering these factors renewables are still amongst the most low carbon options. The report also looks at the sustainability of electricity from biomass. Bioenergy overall could provide up to ten per cent of energy and reduce the cost of cutting carbon by £44 billion per year in 2050. The Government’s new biomass policies are a pragmatic response to concerns about the sustainability of biomass power which balances protecting the environment building public confidence and enabling the sector to grow.

On security of supply the inquiry argues that debate should focus on the whole electricity system and that individual technologies should be considered in the context of how they add to or reduce system risks. Considered like this renewables reduce some risks such as fuel supply risks which caused concern last winter and add to others such as system balancing risks. System balancing risks from varying renewables (wind solar wave and tidal technologies) are manageable using a number of existing and developing technologies.

The independent report chaired by former Energy Minister Charles Hendry MP and Shadow Energy Minister Baroness Worthington was compiled between May and September 2013 and was sponsored by Siemens and DONG Energy. It is part of a year-long independent and cross party inquiry into the UK power sector the Future Electricity Series sponsored by the Institution of Gas Engineers and Managers.

Link to Launch Video

DNV has carried out an investigation into potential uses for smart gas meter data as part of Phase 1 of the Modernising Energy Data Applications competition as funded by UK Research & Innovation. In particular a series of calculations have been carried out to investigate the possibility of differentiating accidental gas leaks from normal appliance use in domestic properties. This is primarily with the aim of preventing explosions but the detection of leaks also has environmental and financial benefits.

Three gases have been considered in this study:

• A representative UK natural gas composition.
• A blend of 80% natural gas and 20% hydrogen.
• Pure hydrogen.

An established method was used to calculate the gas outflow rate from leaks into buildings downstream of the meter regulator. These gas leak rates were compared with the gas use by typical domestic appliances and these leaks were considered in the context of the smart gas meter data that is currently available in 30-minute periods. A representative set of gas accumulation calculations was performed. It was found that the following three general cases apply to all three gases:

• Small holes of up to 1 mm rarely reach flammable gas/air concentrations for any gas except under the most unfavourable conditions such as small volumes combined with low ventilation rates. These releases would likely be detected within 6 to 12 hours.
• Medium holes between 1 mm and 6 mm give outflow rates equivalent to a moderate to high level of gas use by appliances. The ability to detect these leaks is highly dependent on the hole size the time at which the leak begins and the normal gas use profile in the building. The larger leaks in this category would be detected within 30 to 60 minutes while the smaller leaks could take several hours to be clearly differentiated from appliance use. This is quick enough to prevent some explosions.
• Large holes of over 6 mm give leak rates greater than any gas use by appliances. These releases rapidly reach a flammable gas/air mixture in most cases but would typically be detected within the first 30-minute meter output period. Again some explosions could be prevented in this timescale.

An event tree has been used to quantify the approximate success rate of detecting and preventing explosion events. Using the currently available 30-minute smart meter data and functionality it is estimated that around 7% of explosions could be prevented with a slight variation depending on the gas type in use. Additional functionality could be included in the meter to improve this performance. Typically one of the risk mitigation measures in isolation increases the explosion prevention rate to around 15%. If multiple improvements are made then the detection rate is predicted to increase to around 30%.

An examination of detailed historical incident information suggests that the explosions that lead to fatalities or significant damage to houses are typically of the type that would be more likely to be detected and prevented. It is estimated that between 25% and 75% of the more severe explosions could be prevented depending on which potential improvements are implemented.

Based on the conservative estimates of explosion prevention a cost benefit analysis suggests that it is justifiable to spend between around £1 and £10 per meter installed to implement the proposed technology. This is based purely on lives saved and does not take account of other benefits.

The injection of pure hydrogen at a T-junction into a horizontal pipe carrying natural gas is analysed computationally to understand the influence of blending and pipe geometry (diameter ratio various 90 orientations) on mixing for a target of 4.8e20% volume fraction hydrogen blend. The strongly inhomogeneous distribution of hydrogen within the pipe flow and on the pipe walls could indicate the location of potential pipe material degradation including embrittlement effects. The low molecular mass of hydrogen reduces the penetration of a side-branch flow and increases the buoyancy forces leading to stratification with high hydrogen concentrations on the upper pipe surface downstream of the branch. Top-side injection leads to the hydrogen concentration remaining >40% for up to 8 pipe diameters from the injection point for volumetric dilutions ( D) less than 30%. Under-side injection promotes mixing within the flow interior and reduces wall concentration at the lower surface compared to top-side injection. The practical implications for these results in terms of mixing requirements and the contrasting constraint of codes of practice and energy demands are discussed.

Collectively the UK investment in transport decarbonisation is greater than £27B from government for incentivising zero-emission vehicles as part of an urgent response to decarbonise the transport sector. The investments made must facilitate a transition to a long-term solution. The success relies on coordinating and testing the evolution of both the energy and transport systems this avoids the risk of unforeseen consequences in both systems and therefore de-risks investment Here we present a semiquantitative energy and transport system analysis for UK road freight focusing on two primary investment areas for nation-wide decarbonisation namely electrification and hydrogen propulsion. Our study assembles and assesses the potential roadblocks of these energy systems into a concise record and considers the infrastructure in relation to all other components within the energy system. It highlights that for system-wide success and resilience a hydrogen system must overcome hydrogen production and distribution barriers whereas an electric system needs to optimise storage solutions and charging facilities. Without cohesive co-evolving energy networks the planning and operational modelling of transport decarbonisation may fall short of meaningful real-world results. A developed understanding of the dependencies between the energy and transport systems is a necessary step in the development of meaningful operational transport models that could de-risk investment in both the energy and transport systems.

Combined heat and power (CHP) systems offer high energy efficiencies as they utilise both the electricity generated and any excess heat by co-suppling to local consumers. This work presents the potential of a combined heat and hydrogen (CHH) system a solution where Proton exchange membrane (PEM) electrolysis systems producing hydrogen at 60–70% efficiency also co-supply the excess heat to local heat networks. This work investigates the method of capture and utilisation of the excess heat from electrolysis. The analysed system was able to capture 312 kW of thermal energy per MW of electricity and can deliver it as heated water at either 75 ◦C or 45 ◦C this appropriate for existing district heat networks and lower temperature heat networks respectively. This yields an overall CHH system efficiency of 94.6%. An economic analysis was conducted based on income generated through revenue sales of both hydrogen and heat which resulted in a significant reduction in the Levelized Cost of Hydrogen.

High-strength aluminum alloys are widely used in industry. Hydrogen embrittlement greatly reduces the performance and service safety of aluminum alloys. The hydrogen traps in aluminum profoundly affect the hydrogen embrittlement of aluminum. Here we took a coincidence-site lattice (CSL) symmetrically tilted grain boundary (STGB) Σ5(120)[001] as an example to carry out molecular dynamics (MD) simulations of hydrogen diffusion in aluminum at different temperatures and to obtain results and rules consistent with the experiment. At 700 K three groups of MD simulations with concentrations of 0.5 2.5 and 5 atomic % hydrogen (at. % H) were carried out for STGB models at different angles. By analyzing the simulation results and the MSD curves of hydrogen atoms we found that in the low hydrogen concentration of STGB models the grain boundaries captured hydrogen atoms and hindered their movement. In high-hydrogen-concentration models the diffusion rate of hydrogen atoms was not affected by the grain boundaries. The analysis of the simulation results showed that the diffusion of hydro-gen atoms at the grain boundary is anisotropic.

Green Print -  Future Heat for Everyone draws together technical consumer and economic considerations to create a pioneering plan to transition 22 million UK homes to low carbon heat by 2050.<br/>Our Green Print underlines the scale of the challenge ahead acknowledging that a mosaic of low carbon heating solutions will be required to meet the needs of individual communities and setting out 12 key steps that can be taken now in order to get us there<br/>The Climate Change Committee (CCC) estimates an investment spend of £250bn to upgrade insulation and heating in homes as well as provide the infrastructure to deliver the energy.<br/>This is a task of unprecedented scale the equivalent of retro-fitting 67000 homes every month from now until 2050. In this Report Cadent takes the industry lead in addressing the challenge.

There is an increasing body of evidence that leakage of hydrogen to the atmosphere will have an indirect warming effect on the climate and so should be minimised.<br/>This study investigates and quantifies the current understanding of potential hydrogen emissions in the different sectors across a future hydrogen value-chain. It shows that there are some key areas in production distribution and end-use where there could potentially be significant leaks of hydrogen to the atmosphere. In some of these areas there are clear mitigation options while with others the options are less clear due to uncertainty in either data or future technology development.<br/>The report recommends further research and development to reduce the main leak pathways and additional evidence gathering in key areas where there is currently inadequate data to make accurate predictions.<br/>The study was commissioned by BEIS and conducted by the Frazer-Nash consultancy.

Pipelines have been installed and operated around the globe to transport oil and gas for decades. They are considered to be an effective economic and safe means of transportation. The major concern in their operation is corrosion. Among the different forms of corrosion stress corrosion cracking (SCC) which is caused by stresses induced by internal fluid flow or other external forces during the pipeline’s operation in combined action with the presence of a corrosive medium can lead to pipeline failure. In this paper an extensive review of different factors affecting SCC of pipeline steels in various environmental conditions is carried out to understand their impact. Several factors such as temperature presence of oxidizers (O2 CO2 H2S etc.) composition and concentration of medium pH applied stress and microstructure of the metal/alloy have been established to affect the SCC of pipeline steels. SCC susceptibility of a steel at a particular temperature strongly depends on the type and composition of the corrosive medium and microstructure. It was observed that pipeline steels with water quenched and quenched and tempered heat treatments such as those that consist of acicular ferrite or bainitic ferrite grains are more susceptible to SCC irrespective of solution type and composition. Applied stress stress concentration and fluctuating stress facilitates SCC initiation and propagation. In general the mechanisms for crack initiation and propagation in near-neutral solutions are anodic dissolution and hydrogen embrittlement.

The urgency to achieve net-zero carbon dioxide (CO2) emissions by 2050 as first presented by the IPCC special report on 1.5°C Global Warming has spurred renewed interest in hydrogen to complement electrification for widespread decarbonization of the economy. We present reflections on estimates of future hydrogen demand optimization of infrastructure for hydrogen production transport and storage development of viable business cases and environmental impact evaluations using life cycle assessments. We highlight challenges and opportunities that are common across studies of the business cases for hydrogen in Germany the UK the Netherlands Switzerland and Norway. The use of hydrogen in the industrial sector is an important driver and could incentivise large-scale hydrogen value chains. In the long-term hydrogen becomes important also for the transport sector. Hydrogen production from natural gas with capture and permanent storage of the produced CO2 (CCS) enables large-scale hydrogen production in the intermediate future and is complementary to hydrogen from renewable power. Furthermore timely establishment of hydrogen and CO2 infrastructures serves as an anchor to support the deployment of carbon dioxide removal technologies such as direct air carbon capture and storage (DACCS) and biohydrogen production with CCS. Significant public support is needed to ensure coordinated planning governance and the establishment of supportive regulatory frameworks which foster the growth of hydrogen markets.

This is the tenth annual Progress Report to the Scottish Parliament as required by the Climate Change (Scotland) Act 2009. This year’s report shows that in 2019 Scotland’s greenhouse emissions fell by 2% compared to 2018 and are now 44% below 1990 levels. The reductions were largely driven by the manufacturing and construction and fuel supply sectors with electricity generation remaining the biggest driver of emissions cuts over the past decade (2009-2019). The potential for further emissions savings from electricity generation has however largely run out.

The focus must now shift to ensuring that rapid emissions reductions are delivered with no further delay to allow Scotland to meet its legislated 2030 target.

This report and other reports by the Climate Change Committee can be downloaded on their website.

Hypothesis.<br/>The large-scale implementation of hydrogen economy requires immense storage spaces to facilitate the periodic storage/production cycles. Extensive modelling of hydrogen transport in porous media is required to comprehend the hydrogen-induced complexities prior to storage to avoid energy loss. Wettability of hydrogen-brine-rock systems influence flow properties (e.g. capillary pressure and relative permeability curves) and the residual saturations which are all essential for subsurface hydrogen systems.<br/>Model.<br/>This study aims to understand which parameters critically control the contact angle for hydrogen-brine-rock systems using the surface force analysis following the DLVO theory and sensitivity analysis. Furthermore the effect of roughness is studied using the Cassie-Baxter model.<br/>Findings.<br/>Our results reveal no considerable difference between H2 and other gases such as N2. Besides the inclusion of roughness highly affects the observed apparent contact angles and even lead to water-repelling features. It was observed that contact angle does not vary significantly with variations of surface charge and density at high salinity which is representative for reservoir conditions. Based on the analysis it is speculated that the influence of roughness on contact angle becomes significant at low water saturation (i.e. high capillary pressure).

This study has been commissioned by the gas transporters as part of the Gas Goes Green (GGG)2 work programme to develop and report a ‘gas transporter view’ on how to facilitate hydrogen blending from industrial clusters which are likely to form the initial source for hydrogen blending in the gas network. This view has been developed through engagement carried out with industrial clusters and other stakeholders as well as drawing on learnings from a previous hydrogen blending study.3 The key takeaways of this study are that: l Enabling hydrogen blending from industrial clusters can be done in a pragmatic way with limited need for change to existing gas frameworks. l Where frameworks do need to change the changes are incremental rather than involving overhaul of existing frameworks and are highly workable. l While there remain uncertainties as to the nature of blending at each cluster (e.g. the volume and profile of hydrogen injections) in general the changes required to commercial and regulatory frameworks are the same implying that they are low regret. Below we summarise gas transporters’ preferred approach to facilitating hydrogen blending from industrial clusters including both the policy decisions needed and the changes required to commercial and regulatory frameworks. We note that this work has not involved a legal review and that one will be required as part of the process of implementing the framework changes described below.

With the rising threat of climate change green hydrogen is increasingly seen as the high-capacity energy storage and transport medium of the future. This creates an opportunity for low- and middle-income countries to leverage their high renewable energy potential to produce use and export low-cost green hydrogen creating environmental and economic development benefits. While identifying ideal locations for green hydrogen production is critical for countries when defining their green hydrogen strategies there has been a paucity of adequate geospatial planning approaches suitable to low- and middle-income countries. It is essential for these countries to identify green hydrogen production sites which match demand to expected use cases such that their strategies are economically sustainable. This paper therefore develops a novel geospatial cost modelling method to optimize the location of green hydrogen production across different use cases with a focus on suitability to low- and middle-income countries. This method is applied in Kenya to investigate the potential hydrogen supply chain for three use cases: ammonia-based fertilizer freight transport and export. We find hydrogen production costs of e3.7–9.9/kgH2 are currently achievable across Kenya depending on the production location chosen. The cheapest production locations are identified to the south and south-east of Lake Turkana. We show that ammonia produced in Kenya can be cost-competitive given the current energy crisis and that Kenya could export hydrogen to Rotterdam with costs of e7/kgH2 undercutting current market prices regardless of the carrier medium. With expected techno-economic improvements hydrogen production costs across Kenya could drop to e1.8–3.0/kgH2 by 2030.

This episode examines how we are tackling a sustainable future – with Net Zero hurtling towards us at great pace. We’re around a year on from the pledges made at COP26 the UK’s Green Recovery initiative is well under way and by next year Britain is aiming to blend up to 20 per cent hydrogen into its gas networks. So now is the time to continue to unlock new insight and understand further the realities of both the challenges and opportunities ahead.

The podcast can be found here.

The existing literature on the hydrogen supply chains has knowledge gaps. Most studies focus on hydrogen production storage transport and utilisation but neglect ports which are nexuses in the supply chains. To fill the gap this paper focuses on ports' readiness for the upcoming hydrogen international trade. Potential hydrogen exporting and importing ports are screened. Ports' readiness for hydrogen export and import are reviewed from perspectives of infrastructure risk management public acceptance regulations and standards and education and training. The main findings are: (1) liquid hydrogen ammonia methanol and LOHCs are suitable forms for hydrogen international trade; (2) twenty ports are identified that could be first movers; among them twelve are exporting ports and eight are importing ports; (3) ports’ readiness for hydrogen international trade is still in its infancy and the infrastructure construction or renovation risk management measures establishment of regulations and standards education and training all require further efforts.

Britain’s Hydrogen Blending Delivery Plan which sets out how all five of Britain’s gas grid companies will meet the Government’s target for Britain’s network of gas pipes to be ready to deliver 20% hydrogen to homes and businesses from 2023 as a replacement for natural gas.

Decarbonisation of the energy sector is becoming increasingly more important to the reduction in climate change. Renewable energy is an effective means of reducing CO2 emissions but the fluctuation in demand and production of energy is a limiting factor. Liquid hydrogen allows for long-term storage of energy. Hydrogen quality is important for the safety and efficiency of the end user. Furthermore the quality of the hydrogen gas after liquefaction has not yet been reported. The purity of hydrogen after liquefaction was assessed against the specification of Hydrogen grade D in the ISO-14687:2019 by analysing samples taken at different locations throughout production. Sampling was carried out directly in gas cylinders and purity was assessed using multiple analytical methods. The results indicate that the hydrogen gas produced from liquefaction is of a higher purity than the starting gas with all impurities below the threshold values set in ISO-14687:2019. The amount fraction of water measured in the hydrogen sample increased with repeated sampling from the liquid hydrogen tank suggesting that the sampling system used was affected by low temperatures (−253 ◦C). These data demonstrate for the first time the impact of liquefaction on hydrogen purity assessed against ISO-14687:2019 showing that liquified hydrogen is a viable option for long-term energy storage whilst also improving quality.

An under-expanded hydrogen jet from high-pressure equipment or storage tank is a potential incident scenario. Experiments demonstrated that the delayed ignition of a highly turbulent under-expanded hydrogen jet generates a blast wave able to harm people and damage property. There is a need for engineering tools to predict the pressure effects during such incidents to define hazard distances. The similitude analysis is applied to build a correlation using available experimental data. The dimensionless blast wave overpressure generated by delayed ignition and the follow-up deflagration or detonation of hydrogen jets at an any location from the jet ∆Pexp/P0 is correlated to the original dimensionless parameter composed of the product of the dimensionless ratio of storage pressure to atmospheric pressure Ps/P0 and the ratio of the jet release nozzle diameter to the distance from the centre of location of the fast-burning near-stoichiometric mixture on the jet axis (30% of hydrogen in the air by volume) to the location of a target (personnel or property) d/Rw. The correlation is built using the analysis of 78 experiments regarding this phenomenon in the wide range of hydrogen storage pressure of 0.5–65.0 MPa and release diameter of 0.5–52.5 mm. The correlation is applicable to hydrogen free jets at ambient and cryogenic temperatures. It is found that the generated blast wave decays inversely proportional to the square of the distance from the fast-burning portion of the jet. The correlation is used to calculate the hazard distances by harm thresholds for five typical hydrogen applications. It is observed that in the case of a vehicle with onboard storage tank at pressure 70 MPa the “no-harm” distance for humans reduces from 10.5 m to 2.6 m when a thermally activated pressure relief device (TPRD) diameter decreases from 2 mm to a diameter of 0.5 mm.

The ability to remotely monitor hydrogen and map its concentration is a pressing challenge in large scale production and distribution as well as other sectors such as nuclear storage. We present a photonicsbased approach for the stand-off sensing and mapping of hydrogen concentration capable of detecting and locating <0.1% concentrations at 100m distance. The technique identifies the wavelength of light resulting from interaction with laser pulses via Raman scattering and can identify a range of other gas species e.g. hydrocarbons ammonia by the spectroscopic analysis of the wavelengths present in the return signal. LIDAR Light Detection and Ranging – analogous to Radar is used for ranging. Laserbased techniques for the stand-off detection of hydrocarbons frequently employ absorption of light at specific wavelengths which are characteristic of the gas species. Unfortunately Hydrogen does not exhibit strong absorption however it does exhibit strong Raman scattering when excited in the UV wavelength range. Raman scattering is a comparatively weak effect. However the use of solid-state detectors capable of detecting single photons known as SPADS (Single Photon Avalanche Photodiode) enables the detection of low concentrations at range while making use of precise time-of-flight range location correlation. The initial safety case which necessitated our development of stand-off hydrogen sensing was the condition monitoring of stored nuclear waste supported and funded by Sellafield and the National Nuclear Laboratory in the UK. A deployable version of the device has been developed and hydrogen characterisation has been carried out in an active nuclear store. Prior to deployment a full ignition risk assessment was carried out. To the best of our knowledge this technique is the strongest candidate for the remote stand-off sensing of hydrogen.

Autoignition risk in initially non-premixed flowing systems such as premixing ducts must be assessed to help the development of low-NOx systems and hydrogen combustors. Such situations may involve randomly fluctuating inlet conditions that are challenging to model in conventional mixture-fraction-based approaches. A Computational Fluid Dynamics (CFD)-based surrogate modelling strategy is presented here for fast and accurate predictions of the stochastic autoignition behaviour of a hydrogen flow in a hot air turbulent co-flow. The variability of three input parameters i.e. inlet fuel and air temperatures and average wall temperature is first sampled via a space-filling design. For each sampled set of conditions the CFD modelling of the flame is performed via the Incompletely Stirred Reactor Network (ISRN) approach which solves the reacting flow governing equations in post-processing on top of a Large Eddy Simulation (LES) of the inert hydrogen plume. An accurate surrogate model namely a Gaussian Process is then trained on the ISRN simulations of the burner and the final quantification of the variability of autoignition locations is achieved by querying the surrogate model via Monte Carlo sampling of the random input quantities. The results are in agreement with the observed statistics of the autoignition locations. The methodology adopted in this work can be used effectively to quantify the impact of fluctuations and assist the design of practical combustion systems. © 2022 The Authors. Published by Elsevier Inc. on behalf of The Combustion Institute.

The installed capacity electricity generation from wind and the curtailment of wind power in the UK between 2011 and 2021 showed that penetration levels of wind energy and the amount of energy that is curtailed in future would continue to rise whereas the curtailed energy could be utilised to produce green hydrogen. In this study data were collected technologies were chosen systems were designed and simulation models were developed to determine technical requirements and levelised costs of hydrogen produced and transported through different pathways. The analysis of capital and operating costs of the main components used for onshore and offshore green hydrogen production using offshore wind including alternative strategies for hydrogen storage and transport and hydrogen carriers showed that a significant reduction in cost could be achieved by 2030 enabling the production of green hydrogen from offshore wind at a competitive cost compared to grey and blue hydrogen. Among all scenarios investigated in this study compressed hydrogen produced offshore is the most cost-effective scenario for projects starting in 2025 although the economic feasibility of this scenario is strongly affected by the storage period and the distance to the shore of the offshore wind farm. Alternative scenarios for hydrogen storage and transport such as liquefied hydrogen and methylcyclohexane could become more cost-effective for projects starting in 2050 when the levelised cost of hydrogen could reach values of about £2 per kilogram of hydrogen or lower.

The feasibility of the global energy transition may rest on the ability of nations to harness hydrogen's potential for cross-sectoral decarbonization. In countries historically reliant on natural gas for domestic heating and cooking such as the UK hydrogen may prove critical to meeting net-zero targets and strengthening energy security. In response the UK government is targeting industrial decarbonization via hydrogen with parallel interest in deploying hydrogen-fueled appliances for businesses and homes. However prospective hydrogen futures and especially the domestic hydrogen transition face multiple barriers which reflect the cross-sectoral dynamics of achieving economies of scale and social acceptance. Addressing these challenges calls for a deep understanding of socio-technical factors across different scales of the hydrogen economy. In response this paper develops a socio-technical systems framework for overcoming barriers to the domestic transition which is applied to the UK context. The paper demonstrates that future strategies should account for interactions between political techno-economic technical market and social dimensions of the hydrogen transition. In parallel to techno-economic feasibility the right policies will be needed to create an even playing field for green hydrogen technologies while also supporting stakeholder symbiosis and consumer buy-in. Future studies should grapple with how an effective repurposing of pipelines policies and public perceptions can be aligned to accelerate the development of the hydrogen economy with maximum net benefits for society and the environment.

IGEM/TD/13 Standard applies to the safe design construction inspection testing operation and maintenance of pressure regulating installations (PRIs) in accordance with current knowledge and operational experience.

This Supplement provides additional requirements for new PRIs to be used for the transmission of Hydrogen including Natural Gas/Hydrogen blended mixtures (subsequently referred to as NG/H blends) and for the repurposing of Natural Gas (NG) PRIs for Hydrogen service.

NG/H blends are considered to be equivalent to 100 mol % Hydrogen with respect to limits on design stresses the potential effect on the material properties and damage and defect categories and acceptance levels unless an additional technical evaluation is carried out to qualify the materials.

NG/H blends containing in excess of 10 mol % Hydrogen are considered to be equivalent to 100 mol.% Hydrogen with respect to all other requirements except for hazardous areas.

This Supplement gives additional recommendations for PRIs and installations:

• with an upstream maximum operating pressure (MOP) not greater than 100 bar
• with an outlet pressure greater than or equal to 7 bar
• for use with Hydrogen or NG/H blends with a Hydrogen content greater than 10 %
• operating with a temperature range between -20°C and 120°C.

The supplement can be purchased on the IGEM website

Uncertainty surrounding the total cost of ownership system costs and life cycle environmental impacts means that stakeholders may lack the required information to evaluate the risks of transitioning to low-carbon fuels and powertrains. This paper assesses the life cycle costs and well-to-wheel environmental impacts of using electricity and electrofuels in Heavy Good Vehicles (HGVs) whilst considering input parameter uncertainty. The complex relationship between electricity cost electrolyser capacity factor CO2 capture cost and electricity emissions intensity is assessed within a Monte Carlo based framework to identify scenarios where use of electricity or electrofuels in heavy goods vehicles makes economic and environmental sense. For vehicles with a range of less than 450 km battery electric vehicles achieve the lowest total cost of ownership for an electricity cost less than 100 €/MWh. For vehicles that require a range of up to 900 km hydrogen fuel cell vehicles represent the lowest long-term cost of abatement. Power-to-methane and power-to-liquid scenarios become economically competitive when low-cost electricity is available at high-capacity factors and CO2 capture costs for fuel synthesis are below 100 €/tCO2; these fuels may be more applicable to decarbonise shipping and aviation. Battery electric HGVs reduce greenhouse gas emissions by 50% compared to the diesel baseline with electricity emissions of 350 gCO2e/kWh. Electricity emissions less than 35 gCO2e/kWh are required for the power-to-methane and power-to-liquid scenarios to meet EU emissions savings criteria. High vehicle capital costs and a lack of widespread refuelling infrastructure may hinder initial uptake of low-carbon fuels and powertrains for HGVs.

Approximately 20% of emissions from air travel are attributed to the auxiliary power units (APUs) carried in commercial aircraft. This paper proposes to reduce greenhouse gas emissions in international air transport by adopting proton-exchange membrane (PEM) fuel cells to replace APUs in commercial aircraft: we consider the design of three compressed hydrogen storage vessels made of 304 stainless steel 6061-T6 aluminium and Grade 5 (Ti-6Al-4V) titanium and capable of delivering 440 kW—enough for a PEM fuel cell for a Boeing 777. Complete structural analyses for pressures from 35 MPa to 70 MPa and wall thicknesses of 25 50 100 and 150 mm are used to determine the optimal material for aviation applications. Key factors such as deformation safety factors and Von Mises equivalent stress are evaluated to ensure structural integrity under a range of operating conditions. In addition CO2 emissions from a conventional 440 kW gas turbine APU and an equivalent PEM fuel cell are compared. This study provides insights into optimal material selection for compressed hydrogen storage vessels emphasising safety reliability cost and weight reduction. Ultimately this research aims to facilitate the adoption of fuel cell technology in aviation contributing to greenhouse emissions reduction and hence sustainable air transport.

Ammonia has been identified as a sustainable fuel for transport and power applications. Similar to hydrogen ammonia is a synthetic product that can be obtained either from fossil fuels biomass or other renewable sources. Since the 1960’s considerable research has taken place to develop systems capable of burning the material in gas turbines. However it is not until recently that interest in ammonia has regained some momentum in the energy agenda as it is a carbon free carrier and offers an energy density higher than compressed hydrogen. . Therefore this work examines combustion stability and emissions from gaseous ammonia blended with methane or hydrogen in gas turbines. Experiments were carried out in a High Pressure Combustion Rig under atmospheric conditions employing a bespoke generic swirl burner. OH* Chemiluminescense was used for all trials to determine reactivity of the radical. Emissions were measured and correlated to equilibrium calculations using GASEQ. Results show that efficient combustion can be achieved with high power but at very narrow equivalence ratios using both hydrogen and methane blends. Moreover low concentrations of OH radicals are observed at high hydrogen content probably as a consequence of the high NH2 production.

The envisioned role of hydrogen in the energy transition – or the concept of a hydrogen economy – has varied through the years. In the past hydrogen was mainly considered a clean fuel for cars and/or electricity production; but the current renewed interest stems from the versatility of hydrogen in aiding the transition to CO2 neutrality where the capability to tackle emissions from distributed applications and complex industrial processes is of paramount importance. However the hydrogen economy will not materialise without strong political support and robust infrastructure design. Hydrogen deployment needs to address multiple barriers at once including technology development for hydrogen production and conversion infrastructure co-creation policy market design and business model development. In light of these challenges we have brought together a group of hydrogen researchers who study the multiple interconnected disciplines to offer a perspective on what is needed to deploy the hydrogen economy as part of the drive towards net-zero-CO2 societies. We do this by analysing (i) hydrogen end-use technologies and applications (ii) hydrogen production methods (iii) hydrogen transport and storage networks (iv) legal and regulatory aspects and (v) business models. For each of these we provide key take home messages ranging from the current status to the outlook and needs for further research. Overall we provide the reader with a thorough understanding of the elements in the hydrogen economy state of play and gaps to be filled.

The geological storage of hydrogen is a seasonal energy storage solution and the storage capacity of saline aquifers is most appropriately defined by quantifying the amount of hydrogen that can be injected and reproduced over a relevant time period. Cushion gas stored in the reservoir to support the production of the working gas is a CAPEX which should be reduced to decrease implementation cost for gas storage. The cushion gas to working gas ratio provides a sufficiently accurate reflection of the storage efficiency with higher ratios equating to larger initial investments. This paper investigates how technical measures such as well configurations and adjustments to the operational size and schedule can reduce this ratio and the outcomes can inform optimisation strategies for hydrogen storage operations. Using a simplified open saline aquifer reservoir model hydrogen storage is simulated with a single injection and production well. The results show that the injection process is more sensitive to technical measures than the production process; a shorter perforation and a smaller well diameter increases the required cushion gas for the injection process but has little impact on the production. If the storage operation capacity is expanded and the working gas volume increased the required cushion gas to working gas ratio increases for injection reducing the efficiency of the injection process. When the reservoir pressure has more time to equilibrate less cushion gas is required. It is shown that cushion gas plays an important role in storage operations and that the tested optimisation strategies impart only minor effects on the production process however there is significant need for careful optimisation of the injection process. It is suggested that the recoverable part of the cushion gas could be seen as a strategic gas reserve which can be produced during an energy crisis. In this scenario the recoverable cushion gas could be owned by the state and the upfront costs for gas storage to the operator would be reduced making the implementation of more gas storage and the onset of hydrogen storage more attractive to investors.

With rising temperatures extreme weather events and environmental challenges there is a strong push towards decarbonization and an emphasis on renewable energy with wind energy emerging as a key player. The concept of multi-energy systems offers an innovative approach to decarbonization with the potential to produce hydrogen as one of the output streams creating another avenue for clean energy production. Hydrogen has significant potential for decarbonizing multiple sectors across buildings transport and industries. This paper explores the integration of wind energy and hydrogen production particularly in areas where clean energy solutions are crucial such as impoverished villages in Africa. It models three systems: distinct configurations of micro-multi-energy systems that generate electricity space cooling hot water and hydrogen using the thermodynamics and cost approach. System 1 combines a wind turbine a hydrogen-producing electrolyzer and a heat pump for cooling and hot water. System 2 integrates this with a biomass-fired reheat-regenerative power cycle to balance out the intermittency of wind power. System 3 incorporates hydrogen production a solid oxide fuel cell for continuous electricity production an absorption cooling system for refrigeration and a heat exchanger for hot water production. These systems are modeled with Engineering Equation Solver and analyzed based on energy and exergy efficiencies and on economic metrics like levelized cost of electricity (LCOE) cooling (LCOC) refrigeration (LCOR) and hydrogen (LCOH) under steady-state conditions. A sensitivity analysis of various parameters is presented to assess the change in performance. Systems were optimized using a multiobjective method with maximizing exergy efficiency and minimizing total product unit cost used as objective functions. The results show that System 1 achieves 79.78 % energy efficiency and 53.94 % exergy efficiency. System 2 achieves efficiencies of 55.26 % and 27.05 % respectively while System 3 attains 78.73 % and 58.51 % respectively. The levelized costs for micro-multi-energy System 1 are LCOE = 0.04993 $/kWh LCOC = 0.004722 $/kWh and LCOH = 0.03328 $/kWh. For System 2 these values are 0.03653 $/kWh 0.003743 $/kWh and 0.03328 $/kWh. In the case of System 3 they are 0.03736 $/kWh 0.004726 $/kWh and 0.03335 $/kWh and LCOR = 0.03309 $/kWh. The results show that the systems modeled here have competitive performance with existing multi-energy systems powered by other renewables. Integrating these systems will further the sustainable and net zero energy system transition especially in rural communities.

Consumption of fossil fuels especially in transport and energy-dependent sectors has led to large greenhouse gas production. Hydrogen is an exciting energy source that can serve our energy purposes and decrease toxic waste production. Decomposition of methane yields hydrogen devoid of COx components thereby aiding as an eco-friendly approach towards large-scale hydrogen production. This review article is focused on hydrogen production through thermocatalytic methane decomposition (TMD) for hydrogen production. The thermodynamics of this approach has been highlighted. Various methods of hydrogen production from fossil fuels and renewable resources were discussed. Methods including steam methane reforming partial oxidation of methane auto thermal reforming direct biomass gasification thermal water splitting methane pyrolysis aqueous reforming and coal gasification have been reported in this article. A detailed overview of the different types of catalysts available the reasons behind their deactivation and their possible regeneration methods were discussed. Finally we presented the challenges and future perspectives for hydrogen production via TMD. This review concluded that among all catalysts nickel ruthenium and platinum-based catalysts show the highest activity and catalytic efficiency and gave carbon-free hydrogen products during the TMD process. However their rapid deactivation at high temperatures still needs the attention of the scientific community.

Although hydrogen has been used in industry for many years as a chemical commodity its use as a fuel or energy carrier is relatively new and expert knowledge about its associated risks is neither complete nor consensual. Public awareness of hydrogen energy and attitudes towards a future hydrogen economy are yet to be systematically investigated. This paper opens by discussing alternative conceptualisations of risk then focuses on issues surrounding the use of emerging technologies based on hydrogen energy. It summarises expert assessments of risks associated with hydrogen. It goes on to review debates about public perceptions of risk and in doing so makes comparisons with public perceptions of other emergent technologies—Carbon Capture and Storage (CCS) Genetically Modified Organisms and Food (GM) and Nanotechnology (NT)—for which there is considerable scientific uncertainty and relatively little public awareness. The paper finally examines arguments about public engagement and "upstream" consultation in the development of new technologies. It is argued that scientific and technological uncertainties are perceived in varying ways and different stakeholders and different publics focus on different aspects or types of risk. Attempting to move public consultation further "upstream" may not avoid this because the framing of risks and benefits is necessarily embedded in a cultural and ideological context and is subject to change as experience of the emergent technology unfolds.

This study presents a novel design and development of a 280000 m3 liquefied hydrogen tanker ship by implementing a set of 6 Flettner rotors as an assistance propulsion system in conjunction with a combined-cycle gas turbine fuelled by hydrogen as a prime mover. The study includes assessment of the technical and environmental aspects of the developed design. Furthermore an established method was applied to simulate the LH2 tanker in different voyages and conditions to investigate the benefits of harnessing wind energy to assist combined-cycle gas turbine in terms of performance and emission reduction based on engine behaviour for different voyages under loaded and unloaded normal as well as 6 % degraded engine and varying ambient conditions. The results indicate that implementing a set of 6 Flettner rotors for the LH2 tanker ship has the potential to positively impact the performance and lead to environmental benefits. A maximum contribution power of around 1.8 MW was achieved in the winter season owing to high wind speed and favourable wind direction. This power could save approximately 3.6 % of the combined-cycle gas turbine total output power (50 MW) and cause a 3.5 % reduction in NOx emissions.

Energy networks are the systems of pipes and wires by which different energy vectors are transported from where they are produced to where they are needed. As such these networks are central to facilitating countries’ moves away from a reliance on fossil fuels to a system based around the efficient use of renewable and other low carbon forms of energy. In this review we highlight the challenges facing energy networks from this transition in a sample of key high income countries. We identify the technical and other innovations being implemented to meet these challenges and describe some of the new policy and regulatory developments that are incentivising the required changes. We then review evidence from the literature about the benefits of moving to a more integrated approach based on the concept of a Multi-Vector Energy Network (MVEN). Under this approach the different networks are planned and operated together to achieve greater functionality and performance than simply the sum of the individual networks. We find that most studies identify a range of benefits from an MVEN approach but that these findings are based on model simulations. Further work is therefore needed to verify whether the benefits can be realised in practice and to identify how any risks can be mitigated.

The successful and fast start-up of proton exchange membrane fuel cells (PEMFCs) at subfreezing temperatures (cold start) is very important for the use of PEMFCs as energy sources for automotive applications. The effective thermal management of PEMFCs is of major importance. When hydrogen is stored in hydride-forming intermetallics significant amounts of heat are released due to the exothermic nature of the reaction. This excess of heat can potentially be used for PEMFC thermal management and to accelerate the cold start. In the current work this possibility is extensively studied. Three hydride-forming intermetallics are introduced and their hydrogenation behavior is evaluated. In addition five thermal management scenarios of the metal hydride beds are studied in order to enhance the kinetics of the hydrogenation. The optimum combination of the intermetallic hydrogenation behavior weight and complexity of the thermal management system was chosen for the study of thermal coupling with the PEMFCs. A 1D GT-SUITE model was built to stimulate the thermal coupling of a 100 kW fuel cell stack with the metal hydride. The results show that the use of the heat from the metal hydride system was able to reduce the cold start by up to 8.2%.

Hydrogen is expected to play a key role in the decarbonised future of energy. For hydrogen distribution pipelines are seen as the main method for mass transport of hydrogen gas. To support the evaluation of risk related to hydrogen pipelines a revised QRA methodology is presented based on currently available and industry accepted guidance related to natural gas. The QRA approach is primarily taken from HSE UK’s MISHAP methodology [1]. The base methodology is reviewed and modifications suggested to adapt it for use with hydrogen gas transport. Compared to natural gas it was found that the escape distances for hydrogen (based on the degree of heat flux) were lower. However as for the overall risk for both individual and societal the case with hydrogen was more severe close to the pipeline. This was driven by the increased ignition probability of hydrogen. The approach may be used as part of the review and appraisal process of hydrogen projects

The Government is committed to developing the UK’s low carbon hydrogen economy: hydrogen is considered critical to delivering energy security and our decarbonisation targets and presents a significant growth opportunity. It can play a pivotal role in our transition to a future based on renewable and nuclear energy while ensuring that natural gas used during this transition is from reliable sources including our own North Sea production and can provide clean energy for use in industry power transport and potentially home heating. In the UK Hydrogen Strategy we included the commitment to regularly summarise our policy development to keep industry apprised. Since publication of the Hydrogen Strategy we have doubled our low carbon hydrogen production capacity ambition to up to 10GW by 2030 (with at least half from electrolytic hydrogen) in the British Energy Security Strategy provided greater clarity to investors through the Hydrogen Investment Package and made substantial policy and funding strides across the hydrogen value chain. We summarised these ambitions commitments and actions in the first Hydrogen Strategy update to the market in July 2022. This was published alongside other key elements of our policy support which also included the launch of the first Electrolytic Hydrogen Allocation Round – offering joint Net Zero Hydrogen Fund (NZHF) and Hydrogen Production Business Model (HPBM) support – and our Hydrogen Sector Development Action Plan and the appointment of a UK Hydrogen Champion. Hydrogen is closely integrated into Government’s wider policy development on energy security and the energy transition both domestically and internationally with hydrogen policy previously announced through the Net Zero Strategy and the Breakthrough Agenda at COP26. This December 2022 Hydrogen Strategy update to the market summarises the extensive activity across Government since July to develop new hydrogen policy at pace and to design and deliver funding support. This includes announcements on shortlisted hydrogen projects in the Cluster Sequencing Process the launch of a consultation on hydrogen transport and storage (T&S) infrastructure the publication of the HPBM Heads of Terms and an update on the ongoing first Electrolytic Hydrogen Allocation Round. The hydrogen policy development presented here underlines the Government’s approach to promote every aspect of the UK hydrogen economy in collaboration with industry investors and international partners to create a strong globally competitive UK hydrogen sector.

In this paper we implement a long-term multi-sectoral energy planning model to evaluate the role of green hydrogen in the energy mix of Chile a country with a high renewable potential under stringent emission reduction objectives in 2050. Our results show that green hydrogen is a cost-effective and environmentally friendly route especially for hard-to-abate sectors such as interprovincial and freight transport. They also suggest a strong synergy of hydrogen with electricity generation from renewable sources. Our numerical simulations show that Chile should (i) start immediately to develop hydrogen production through electrolyzers all along the country (ii) keep investing in wind and solar generation capacities ensuring a low cost hydrogen production and reinforce the power transmission grid to allow nodal hydrogen production (iii) foster the use of electric mobility for cars and local buses and of hydrogen for long-haul trucks and interprovincial buses and (iv) develop seasonal hydrogen storage and hydrogen cells to be exploited for electricity supply especially for the most stringent emission reduction objectives.

Hydrogen is an emerging technology changing the context of heating with cleaner combustion than traditional fossil fuels. Studies indicate the potential to repurpose the existing natural gas infrastructure offering consumers a sustainable economically viable option in the future. The integration of hydrogen in combined heat and power systems could provide residential energy demand and reduce environmental emissions. However the widespread adoption of hydrogen will face several challenges such as carbon dioxide emissions from the current production methods and the need for infrastructure modification for transport and safety. Researchers indicated the viability of hydrogen in decarbonizing heat while some studies also challenged its long-term role in the future of heating. In this paper a comprehensive literature review is carried out by identifying the following key aspects which could impact the conclusion on the overall role of hydrogen in heat decarbonization: (i) a holistic view of the energy system considering factors such as renewable integration and system balancing; (ii) consumer-oriented approaches often overlook the broader benefits of hydrogen in emission reduction and grid stability; (iii) carbon capture and storage scalability is a key factor for large-scale production of low-emission blue hydrogen; (iv) technological improvements could increase the cost-effectiveness of hydrogen; (v) the role of hydrogen in enhancing resilience especially during extreme weather conditions raises the potential of hydrogen as a flexible asset in the energy infrastructure for future energy supply; and finally when considering the UK as a basis case (vi) incorporating factors such as the extensive gas network and unique climate conditions necessitates specific strategies.

Hydrogen can be recognized as the most plausible fuel for promoting a green environment. Worldwide developed and developing countries have established their hydrogen research investment and policy frameworks. This analysis of 610 peer-reviewed journal articles from the last 50 years provides quantitative and impartial insight into the hydrogen economy. By 2030 academics and business professionals believe that hydrogen will complement other renewable energy (RE) sources in the energy revolution. This study conducts an integrative review by employing software such as Bibliometrix R-tool and VOSviewer on socio-economic consequences of hydrogen energy literature derived from the Scopus database. We observed that most research focuses on multidisciplinary concerns such as generation storage transportation application feasibility and policy development. We also present the conceptual framework derived from in-depth literature analysis as well as the interlinkage of concepts themes and aggregate dimensions to highlight research hotspots and emerging patterns. In the future factors such as green hydrogen generation hydrogen permeation and leakage management efficient storage risk assessment studies blending and techno-economic feasibility shall play a critical role in the socio-economic aspects of hydrogen energy research.  

The transition to energy systems with a high share of renewable energy depends on the availability of technologies that can connect the physical distances or bridge the time differences between the energy supply and demand points. This study focuses on energy storage technologies due to their expected role in liberating the energy sector from fossil fuels and facilitating the penetration of intermittent renewable sources. The performance of 27 energy storage alternatives is compared considering sustainability aspects by means of data envelopment analysis. To this end storage alternatives are first classified into two clusters: fast-response and long-term. The levelized cost of energy energy and water consumption global warming potential and employment are common indicators considered for both clusters while energy density is used only for fast-response technologies where it plays a key role in technology selection. Flywheel reveals the highest efficiency between all the fast-response technologies while green ammonia powered with solar energy ranks first for long-term energy storage. An uncertainty analysis is incorporated to discuss the reliability of the results. Overall results obtained and guidelines provided can be helpful for both decision-making and research and development purposes. For the former we identify the most appealing energy storage options to be promoted while for the latter we report quantitative improvement targets that would make inefficient technologies competitive if attained. This contribution paves the way for more comprehensive studies in the context of energy storage by presenting a powerful framework for comparing options according to multiple sustainability indicators.

Current technological improvements are yet to put the world on track to net-zero which will require the uptake of transformative low-carbon innovations to supplement mitigation efforts. However the role of such innovations is not yet fully understood; some of these ‘miracles’ are considered indispensable to Paris Agreement-compliant mitigation but their limitations availability and potential remain a source of debate. We evaluate such potentially game-changing innovations from the experts’ perspective aiming to support the design of realistic decarbonisation scenarios and better-informed net-zero policy strategies. In a worldwide survey 260 climate and energy experts assessed transformative innovations against their mitigation potential at-scale availability and/or widescale adoption and risk of delayed diffusion. Hierarchical clustering and multi-criteria decision-making revealed differences in perceptions of core technological innovations with next generation energy storage alternative building materials iron-ore electrolysis and hydrogen in steelmaking emerging as top priorities. Instead technologies highly represented in well-below-2◦C scenarios seemingly feature considerable and impactful delays hinting at the need to re-evaluate their role in future pathways. Experts’ assessments appear to converge more on the potential role of other disruptive innovations including lifestyle shifts and alternative economic models indicating the importance of scenarios including non-technological and demand-side innovations. To provide insights for expert elicitation processes we finally note caveats related to the level of representativeness among the 260 engaged experts the level of their expertise that may have varied across the examined innovations and the potential for subjective interpretation to which the employed linguistic scales may be prone to.

Jet flames originated by cryo-compressed ignited hydrogen releases can cause life-threatening conditions in their surroundings. Validated models are needed to accurately predict thermal hazards from a jet fire. Numerical simulations of cryogenic hydrogen flow in the release pipe are performed to assess the effect of heat transfer through the pipe walls on jet parameters. Notional nozzle exit diameter is calculated based on the simulated real nozzle parameters and used in CFD simulations as a boundary condition to model jet fires. The CFD model was previously validated against experiments with vertical cryogenic hydrogen jet fires with release pressures up to 0.5 MPa (abs) release diameter 1.25 mm and temperatures as low as 50 K. This study validates the CFD model in a wider domain of experimental release conditions - horizontal cryogenic jets at exhaust pipe temperature 80 K pressure up to 2 MPa abs and release diameters up to 4 mm. Simulation results are compared against experimentally measured parameters as hydrogen mass flow rate flame length and radiative heat flux at several locations from the jet fire. The CFD model reproduces well experiments with reasonable engineering accuracy. Jet fire hazard distances established using three different criteria - temperature thermal radiation and thermal dose - are compared and discussed based on CFD simulation results.

The future of a carbon-free society relies on the alignment of the intermittent production of renewable energy with our continuous and increasing energy demands. Long-term energy storage in molecules with high energy content and density such as ammonia can act as a buffer versus short-term storage (e.g. batteries). In this paper we demonstrate that the Haber–Bosch ammonia synthesis loop can indeed enable a second ammonia revolution as energy vector by replacing the CO2 intensive methane-fed process with hydrogen produced by water splitting using renewable electricity. These modifications demand a redefinition of the conventional Haber–Bosch process with a new optimisation beyond the current one which was driven by cheap and abundant natural gas and relaxed environmental concerns during the last century. Indeed the switch to electrical energy as fuel and feedstock to replace fossil fuels (e.g. methane) will lead to dramatic energy efficiency improvements through the use of high efficiency electrical motors and complete elimination of direct CO2 emissions. Despite the technical feasibility of the electrically-driven Haber–Bosch ammonia the question still remains whether such revolution will take place. We reveal that its success relies on two factors: increased energy efficiency and the development of small-scale distributed and agile processes that can align to the geographically isolated and intermittent renewable energy sources. The former requires not only higher electrolyser efficiencies for hydrogen production but also a holistic approach to the ammonia synthesis loop with the replacement of the condensation separation step by alternative technologies such as absorption and catalysis development. Such innovations will open the door to moderate pressure systems the development and deployment of novel ammonia synthesis catalysts and even more importantly the opportunity for integration of reaction and separation steps to overcome equilibrium limitations. When realised green ammonia will reshape the current energy landscape by directly replacing fossil fuels in transportation heating electricity etc. and as done in the last century food.