United Kingdom

The consumption of hydrogen could increase by sixfold in 2050 compared to 2020 levels reaching about 530 Mt. Against this backdrop the proton exchange membrane fuel cell (PEMFC) has been a major research area in the field of energy engineering. Several reviews have been provided in the existing corpus of literature on PEMFC but questions related to their evolutionary nuances and research hotspots remain largely unanswered. To fill this gap the current review uses bibliometric analysis to analyze PEMFC articles indexed in the Scopus database that were published between 2000–2021. It has been revealed that the research field is growing at an annual average growth rate of 19.35% with publications from 2016 to 2012 alone making up 46% of the total articles available since 2000. As the two most energy-consuming economies in the world the contributions made towards the progress of PEMFC research have largely been from China and the US. From the research trend found in this investigation it is clear that the focus of the researchers in the field has largely been to improve the performance and efficiency of PEMFC and its components which is evident from dominating keywords or phrases such as ‘oxygen reduction reaction’ ‘electrocatalysis’ ‘proton exchange membrane’ ‘gas diffusion layer’ ‘water management’ ‘polybenzimidazole’ ‘durability’ and ‘bipolar plate’. We anticipate that the provision of the research themes that have emerged in the PEMFC field in the last two decades from the scientific mapping technique will guide existing and prospective researchers in the field going forward.

The UK Hydrogen Champion engaged with stakeholders across the hydrogen value chain between July and December 2022.<br/>This report summarises their findings and makes recommendations for government and industry to accelerate the growth of the hydrogen sector.

Decarbonising ammonia production is an environmental imperative given that it independently accounts for 1.8% of global carbon dioxide emissions and supports the feeding of over 48% of the global population. The recent decline of production costs and its potential as an energy vector warrant investigation of whether green ammonia production is commercially competitive. Considering 534 locations in 70 countries and designing and operating the islanded production process to minimise the levelised cost of ammonia (LCOA) at each we show the range of achievable LCOA the cost of process flexibility the components of LCOA and therein the scope of LCOA reduction achievable at present and in 2030. These results are benchmarked against ammonia spot prices cost per GJ of refined fuels and the LCOE of alternative energy storage methods. Currently a LCOA of $473 t1 is achievable at the best locations the required process flexibility increases the achievable LCOA by 56%; the electrolyser CAPEX and operation are the most significant costs. By 2030 $310 t1 is predicted to be achievable with multiple locations below $350 t1 . At $25.4 GJ11 ) that do not have the benefit of being carbon-free.

This policy briefing considers how the use of nuclear energy could be expanded to make the most of the energy produced and also to have the flexibility to complement an energy system with a growing input of intermittent renewable energy.<br/>What is nuclear cogeneration?<br/>Nuclear cogeneration is where the heat generated by a nuclear power station is used not only to generate electricity but to address some of the ‘difficult to decarbonise’ energy demands such as domestic heating and hydrogen production. It also enables a nuclear plant to be used more flexibly by switching between electricity generation and cogeneration applications.<br/>Applications for nuclear cogeneration<br/>Heat generated by civil nuclear reactors can be extracted at two different points for applications requiring either low-temperature or high-temperature heat. Each application differs in many aspects of operation and have different challenges.<br/>Low-temperature cogeneration<br/>Applications for the lower temperature ‘waste’ heat include:<br/>District heating<br/>Seawater desalination<br/>Low-temperature industrial process heating<br/>High-temperature cogeneration<br/>Higher temperature heat can be accessed earlier and used for:<br/>High-temperature industrial process heating<br/>Hydrogen production<br/>Sustainable synthetic fuel production<br/>Direct air capture<br/>Thermal energy storage<br/>Challenges of cogeneration systems<br/>Whilst some nuclear cogeneration applications have been employed in many countries the economic benefit of widescale nuclear cogeneration needs to be determined. However if the construction cost reductions for small modular reactors (SMRs) can be realised and the regulation and licencing processes streamlined then the additional revenue benefits of cogeneration could be material for SMRs and for the future of nuclear generation in the UK.<br/>Other outstanding issues include the ownership of reactors the future demand for hydrogen and other cogeneration products at a regional national and international level and the cost of carbon and dependable power.

Ammonia an important basic chemical is produced at a scale of 150 million tons per year. Half of hydrogen produced in chemical industry is used for ammonia production. Ammonia containing 17.5 wt% hydrogen is an ideal carbon-free fuel for fuel cells. Compared to hydrogen ammonia has many advantages. In this mini-review the suitability of ammonia as fuel for fuel cells the development of different types of fuel cells using ammonia as the fuel and the potential applications of ammonia fuel cells are briefly reviewed.

Replacing fossil fuels with energy sources and carriers that are sustainable environmentally benign and affordable is amongst the most pressing challenges for future socio-economic development. To that goal hydrogen is presumed to be the most promising energy carrier. Electrocatalytic water splitting if driven by green electricity would provide hydrogen with minimal CO2 footprint. The viability of water electrolysis still hinges on the availability of durable earth-abundant electrocatalyst materials and the overall process efficiency. This review spans from the fundamentals of electrocatalytically initiated water splitting to the very latest scientific findings from university and institutional research also covering specifications and special features of the current industrial processes and those processes currently being tested in large-scale applications. Recently developed strategies are described for the optimisation and discovery of active and durable materials for electrodes that ever-increasingly harness first principles calculations and machine learning. In addition a technoeconomic analysis of water electrolysis is included that allows an assessment of the extent to which a large-scale implementation of water splitting can help to combat climate change. This review article is intended to cross-pollinate and strengthen efforts from fundamental understanding to technical implementation and to improve the ‘junctions’ between the field’s physical chemists materials scientists and engineers as well as stimulate much-needed exchange among these groups on challenges encountered in the different domains.

In this podcast David Ledesma talks with Rahmat Poudineh Senior Research Fellow and Aliaksei Patonia Research Fellow on issues and options with respect to long distance transportation of the hydrogen.

Hydrogen currently is mainly a local or regional commodity. If hydrogen is to become a truly global-traded commodity it needs to be transported over long transoceanic distances in an economical way. However unlike natural gas shipping compressed or liquefied hydrogen over long distances is very inefficient and expensive. At the same time hydrogen can be converted into multiple carriers with a higher energy density and higher transport capacity such as liquid ammonia toluene/methylcyclohexane (MCH) or methanol. These chemicals have their own advantages and drawbacks and their techno-economic characteristics in terms of boil-off gas and thermodynamic and conversion losses play a key role in the efficiency of transoceanic transportation of the hydrogen.

On the other hand apart from techno-economic features there are other factors to consider for long distance transportation of the hydrogen via its careers. Here such issues as safety public acceptance as well as legal and regulatory constraints may come into play. Another factor is the availability of the industries and infrastructures already developed around any of possible hydrogen carriers as well as their potential industrial applicability beyond hydrogen. Finally technological progress in other decarbonization applications and most importantly full commercialization of CCUS solutions is likely to dramatically change the approach towards long distance hydrogen transportation.

The podcast can be found on their website. 

Renewable energies such as the wind energy and solar energy generate low-carbon electricity which can directly charge battery electric vehicles (BEVs). Meanwhile the surplus electricity can be used to produce the “green hydrogen” which provides zero-emission hydrogen fuels to those fuel cell electric vehicles (FCEVs). In order to charge/refuel multi-energy vehicles we propose a novel scheme of hybrid hydrogen/electricity supply using cryogenic and superconducting technologies. In this scheme the green hydrogen is further liquefied into the high-density and low-pressure liquid hydrogen (LH2) for bulk energy storage and transmission. Taking the advantage of the cryogenic environment of LH2 (20 K) it can also be used as the cryogen to cool down super conducting cables to realize the virtually zero-loss power transmission from 100 % renewable sources to vehicle charging stations. This hybrid LH2/electricity energy pipeline can realize long-distance large-capacity and high efficiency clean energy transmission to fulfil the hybrid energy supply demand for BEVs and FCEVs. For the case of a 100 MW-class hybrid hydrogen/electricity supply station the system principle and energy management strategy are analyzed through 9 different operating sub-modes. The corresponding static and dynamic economic modeling are performed and the economic feasibility of the hybrid hydrogen/electricity supply is verified using life-cycle analysis. Taking an example of wind power capacity 1898 MWh and solar power capacity 1619 MWh per day the dynamic payback period is 15.06 years the profitability index is 1.17 the internal rate of return is 7.956 % and the accumulative NPV is 187.92 M$. The system design and techno-economic analysis can potentially offer a technically/economically superior solution for future multi-energy vehicle charging/refueling systems.

The use of hydrogen storage tanks at 100% of nominal working pressure NWP is expected only after refuelling. Driving between refuellings is characterised by the state of charge SoC<100%. There is experimental evidence that Type IV tanks tested in a fire at initial pressures below one-third of its NWP depending on a fire source were leaking without rupture. This paper aims at understanding this phenomenon and the development of a predictive model. The numerical research has demonstrated that the heat transfer from fire through the composite overwrap is sufficient to melt the polymer liner. This initiates hydrogen microleaks through the composite wall before it loses the load-bearing ability when the resin degrades deep enough to cause the tank to rupture. The dependence of tank fire-resistance rating (FRR) on the SoC is presented for tanks of volume in the range 36-244 L. The tank wall thickness non-uniformity i.e. thinner composite at the dome area is identified as a serious issue for tank’s fire resistance that must be addressed by tank manufacturers and OEMs. The effect of the burst pressure ratio on FRR is investigated. It is concluded that thermal parameters of the composite wall i.e. decomposition heat and temperatures play a vital role in simulations of tank failure and thus FRR.

In this fifth episode  Steffan Eldred and Neelam Mughal from Innovate UK KTN discuss how the glass industry is driving new hydrogen developments and research and explore the hydrogen transition opportunities and challenges in this sector alongside their special guest Rob Ireson Innovation and Partnerships Manager at Glass Futures Ltd.

The podcast can be found on their website

The world-wide sustainability implications of transport technologies remain unclear because their assessment often relies on metrics that are hard to interpret from a global perspective. To contribute to filling this gap here we apply the concept of planetary boundaries (PBs) i.e. a set of biophysical limits critical for operating the planet safely to address the optimal design of sustainable fuel supply chains (SCs) focusing on hydrogen for vehicle use. By incorporating PBs into a mixed-integer linear programming model (MILP) we identify SC configurations that satisfy a given transport demand while minimising the PBs transgression level i.e. while reducing the risk of surpassing the ecological capacity of the Earth. On applying this methodology to the UK we find that the current fossil-based sector is unsustainable as it transgresses the energy imbalance CO2 concentration and ocean acidification PBs heavily i.e. five to 55-fold depending on the downscale principle. The move to hydrogen would help to reduce current transgression levels substantially i.e. reductions of 9–86% depending on the case. However it would be insufficient to operate entirely within all the PBs concurrently. The minimum impact SCs would produce hydrogen via water electrolysis powered by wind and nuclear energy and store it in compressed form followed by distribution via rail which would require as much as 37 TWh of electricity per year. Our work unfolds new avenues for the incorporation of PBs in the assessment and optimisation of energy systems to arrive at sustainable solutions that are entirely consistent with the carrying capacity of the planet.

Hydrogen storage is one of the energy storage methods that can help realization of an emission free future by saving surplus renewable energy for energy deficit periods. Utilization of depleted hydrocarbon reservoirs for large-scale hydrogen storage may be associated with the risk of chemical/biochemical reactions. In the specific case of chalk reservoirs the principal reactions are abiotic calcite dissolution acetogenesis methanogenesis and biological souring. Here we use PHREEQC to evaluate the dynamics and the extent of hydrogen loss by each of these reactions in hydrogen storage scenarios for various Danish North Sea chalk hydrocarbon reservoirs. We find that: (i) Abiotic calcite dissolution does not occur in the temperature range of 40-180◦ C. (ii) If methanogens and acetogens grow as slow as the slowest growing methanogens and acetogens reported in the literature methanogenesis and acetogenesis cannot cause a hydrogen loss more than 0.6% per year. However (iii) if they proceed as fast as the fastest growing methanogens and acetogens reported in the literature a complete loss of all injected hydrogen in less than five years is possible. (iv) Co-injection of CO2 can be employed to inhibit calcite dissolution and keep the produced methane due to methanogenesis carbon neutral. (v) Biological sulfate reduction does not cause significant hydrogen loss during 10 years but it can lead to high hydrogen sulfide concentrations (1015 ppm). Biological sulfate reduction is expected to impact hydrogen storage only in early stages if the only source of sulfur substrates are the dissolved species in the brine and not rock minerals. Considering these findings we suggest that depleted chalk reservoirs may not possess chemical/biochemical risks and be good candidates for large-scale underground hydrogen storage.

The Heads of Terms for the Low Carbon Hydrogen Agreement sets out the government’s proposal for the final hydrogen production business model design. It will form the basis of the Low Carbon Hydrogen Agreement the business model contract between the government appointed counterparty and a low carbon hydrogen producer.<br/>The business model will provide revenue support to hydrogen producers to overcome the operating cost gap between low carbon hydrogen and high carbon fuels. It has been designed to incentivise investment in low carbon hydrogen production and use and in doing so deliver the government’s ambition of up to 10GW of low carbon hydrogen production capacity by 2030.

Combined heat and power (CHP) in a single and integrated device is concurrent or synchronized production of many sources of usable power typically electric as well as thermal. Integrating combined heat and power systems in today’s energy market will address energy scarcity global warming as well as energy-saving problems. This review highlights the system design for fuel cell CHP technologies. Key among the components discussed was the type of fuel cell stack capable of generating the maximum performance of the entire system. The type of fuel processor used was also noted to influence the systemic performance coupled with its longevity. Other components equally discussed was the power electronics. The thermal and water management was also noted to have an effect on the overall efficiency of the system. Carbon dioxide emission reduction reduction of electricity cost and grid independence were some notable advantages associated with fueling cell combined heat and power systems. Despite these merits the high initial capital cost is a key factor impeding its commercialization. It is therefore imperative that future research activities are geared towards the development of novel and cheap materials for the development of the fuel cell which will transcend into a total reduction of the entire system. Similarly robust systemic designs should equally be an active research direction. Other types of fuel aside hydrogen should equally be explored. Proper risk assessment strategies and documentation will similarly expand and accelerate the commercialization of this novel technology. Finally public sensitization of the technology will also make its acceptance and possible competition with existing forms of energy generation feasible. The work in summary showed that proton exchange membrane fuel cell (PEM fuel cell) operated at a lower temperature-oriented cogeneration has good efficiency and is very reliable. The critical issue pertaining to these systems has to do with the complication associated with water treatment. This implies that the balance of the plant would be significantly affected; likewise the purity of the gas is crucial in the performance of the system. An alternative to these systems is the PEM fuel cell systems operated at higher temperatures.

This study aims to help the Department for Business Energy and Industrial Strategy (BEIS) determine whether the government should intervene to enable or require hydrogen-ready industrial boiler equipment. It will do this based on information from existing literature along with qualitative and quantitative information from stakeholder engagement. The study draws on evidence gathered through BEIS’ Call for Evidence (CfE) on hydrogen-ready industrial boilers. The assessment will advance the overall understanding of hydrogen-ready industrial boilers based on four outputs: definitions of hydrogen-readiness comparisons of the cost and resource requirement to install and convert hydrogen-ready industrial boiler equipment supply chain capacity for conversion to hydrogen and estimates of the UK industrial boiler population.

Increased consumption of low-carbon hydrogen is prominent in the decarbonisation strategies of many jurisdictions. Yet prior studies assessing the current most prevalent production method steam reformation of natural gas (SRNG) have not sufficiently evaluated how process design decisions affect life cycle greenhouse gas (GHG) emissions. This techno-economic case study assesses cradle-to-gate emissions of hydrogen produced from SRNG with CO2 capture and storage (CCS) in British Columbia Canada. Four process configurations with amine-based CCS using existing technology and novel process designs are evaluated. We find that cradle-to-gate GHG emission intensity ranges from 0.7 to 2.7 kgCO2e/kgH2 – significantly lower than previous studies of SRNG with CCS and similar to the range of published estimates for hydrogen produced from renewable-powered electrolysis. The levelized cost of hydrogen (LCOH) in this study (US$1.1–1.3/kgH2) is significantly lower than published estimates for renewable-powered electrolysis.

Morocco despite its heavy reliance on imported fossil fuels which made up 68% of electricity generation in 2020 has recognised its significant renewable energy potential. The Nationally Determined Contribution (NDC) commitment is to reduce emissions by 45.5% from baseline levels with international assistance and abstain from constructing new coal plants. Moreover the Green Hydrogen Roadmap aims to export 10 TWh of green hydrogen by 2030 as well as use it for local electricity storage. This paper critically analyses this Roadmap and Morocco’s readiness to reach its ambitious targets focusing specifically on an energy trilemma perspective and using OSeMOSYS (Open-Source energy Modelling System) for energy modelling. The results reveal that the NDC scenario is only marginally more expensive than the least-cost scenario at around 1.3% (approximately USD 375 million) and facilitates a 23.32% emission reduction by 2050. An important note is the continued reliance on existing coal power plants across all scenarios which challenges both energy security and emissions. The assessment of the Green Hydrogen Scenarios highlights that it could be too costly for the Moroccan government to fund the Green Hydrogen Roadmap at this scale which leads to increased imports of polluting fossil fuels for cost reduction. In fact the emission levels are 39% higher in the green hydrogen exports scenario than in the least-cost scenario. Given these findings it is recommended that the Green Hydrogen Roadmap be re-evaluated with a suggestion for a postponement and reduction in scope.

Reversible solid oxide fuel cell (RSOFC) is an energy device that flexibly interchanges between electrical and chemical energy according to people’s life and production needs. The development of cell materials affects the stability and cost of the cell but also restricts its market-oriented development. After decades of research by scientists a lot of achievements and progress have been made on RSOFC materials. According to the composition and requirements of each component of RSOFC this article summarizes the research progress based on materials and discusses the merits and demerits of current cell materials in electrochemical performance. According to the efficiency of different materials in solid oxide fuel cell (SOFC mode) and solid oxide electrolyzer (SOEC mode) the challenges encountered by RSOFC in the operation are evaluated and the future development of RSOFC materials is boldly prospected.

The emergence and design of hydrogen transport infrastructures are crucial steps towards the development of a hydrogen economy. However pipeline routing remains underdeveloped in hydrogen infrastructure design models despite its significant impact on the resultant cost and network configuration. Many previous studies assume uniform cost surfaces on which pipelines are designed. Studies that consider a variable cost surface focus on designing candidate networks rather than bespoke routes for a given infrastructure. This study proposes a novel multi-stage approach based on a graph-based Steiner tree with Obstacles Genetic Algorithm (StObGA) to route pipelines on a complex cost surface for multi-source multi-sink hydrogen networks. The application of StObGA results in cost savings of 20–40% compared to alternative graph-based methods that assume uniform cost surfaces. Furthermore this publication presents an in-depth methodological comparative analysis of different pipeline routing and sizing methods used in the literature and discusses their impact. Finally we demonstrate how this model can generate design variations and provide practical insights to inform industry and policymakers.

Hydrogen offers the UK a unique opportunity to deliver on our Net Zero ambitions enabling deep decarbonisation of the parts of the energy system that are challenging to electrify balancing the energy system by providing large scale long duration energy storage and reducing pressure on electricity infrastructure. The UK Government in recognition of the centrality of hydrogen to the future energy system has set a 10GW hydrogen production ambition to be achieved by 2030. This ambition and its supporting policies such as the Hydrogen Business Model the Low Carbon Hydrogen Standard and the Hydrogen Transport and Storage Business Models will unlock private sector investment and kick-start the UK’s hydrogen activity. Encouragingly the UK has a positive track record of deploying low carbon technologies. The  combination of the UK’s world leading policies and incentive schemes alongside a vibrant  Research Development and Innovation (RD&I)  and engineering environment has enabled rapid  deployment of technologies such as offshore wind  and electric vehicles. Yet despite being world leaders  in deployment early opportunities for regional  supply chain growth and job creation were not fully  realised and taken advantage of from inception. The  hydrogen sector is therefore at a tipping point. To  capitalise on the economic opportunity hydrogen  offers the UK must learn from prior technology  deployments and build a strong domestic hydrogen  supply chain in parallel to championing deployment.

Hydrogen is unique amongst low carbon  technologies. It represents a significant economic  opportunity with future hydrogen markets estimated  by the Hydrogen Innovation Initiative to be worth  $8tn and hydrogen technology markets estimated to reach $1tn by 20501 but crucially it is also still a nascent market. Unlike many other low carbon technologies where supply chains are already well established hydrogen supply chains are embryonic meaning that the UK has an opportunity to anchor these supply chains here and establish itself as a global leader.

The UK is well placed to capitalise on this opportunity with favourable geography and geology  that enables us to produce and store hydrogen cost effectively coupled with a strong pipeline of hydrogen projects a stable policy environment that is attractive to investors and a wealth of transferable skills and expertise from the oil and gas industry.

We must ensure that alongside our focus on deployment we are also investing in technology and supply chains. Not only will this deliver exponential economic benefits from the projects supported by Government but it will also enable us to tackle increasing global supply chain constraints. Hydrogen UK estimated in its Economic Impact Assessment that hydrogen could deliver 30000 jobs annually and £7bn of GVA by 2030

It is important to be targeted and strategic in our investment and activities and recognise that hydrogen represents a wide range of technologies and the UK should not expect to lead in every area. Hydrogen UK with the support of the Hydrogen Delivery Council has undertaken analysis of the hydrogen value chain building on UK strengths and identifying the high value items that can deliver significant impact and benefit to the UK. We have also conducted widespread engagement with project developers to identify the barriers to utilising UK technology in projects and with technology developers to identify the challenges and barriers to investing and siting development and manufacturing in the UK.

The report can be found on Hydrogen UK's website.

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

The signing of the Paris Agreement in 2016 established the goals of countries around the world for the transition from traditional fossil energy to sustainable energy in the 21st century. Reduce carbon emissions using new sustainable energy sources while safeguarding the energy needs of social development. The advantages of hydrogen fuel cell vehicles such as no carbon emissions long battery life and short hydrogenation time make them the development direction of new energy vehicles in many countries. Many countries such as the United Kingdom China and Japan have formulated hydrogen energy development plans. As the hub and supply station of the hydrogen energy transportation network the hydrogen refueling station is crucial to the development of the hydrogen economy. This paper summarizes the current main hydrogen storage methods and the existing risks analyzes the main security threats of hydrogen refueling stations and discusses the security system to prevent hydrogen embrittlement and hydrogen explosion. Finally the hydrogen refueling station is compared with the petrol station and the future security development and management pattern of the hydrogen refueling station is summarized. The security assessment of the hydrogen refueling station is carried out in this paper which provides theoretical support for the development of hydrogen refueling stations from the perspective of security.

Underground Hydrogen Storage (UHS) as an emerging large-scale energy storage technology has shown great promise to ensure energy security with minimized carbon emission. A set of comprehensive UHS site evaluation criteria based on important factors that affect UHS performances is needed for its potential commercialization. This study focuses on the UHS site evaluation of gas mixing. The economic implications of gas mixing between injected hydrogen gas and the residual or cushion gas in a porous storage reservoir is an emerging problem for Underground Hydrogen Storage (UHS). It is already clear that reservoir scale heterogeneity such as formation structure (e.g. formation dip angle) and facies heterogeneity of the sedimentary rock may considerably affect the reservoir-scale mechanical dispersion-induced gas mixing during UHS in high permeability braided-fluvial systems (a common depleted reservoir type for UHS). Following this finding the current study uses the processmimicking modeling software to build synthetic meandering-fluvial reservoir models. Channel dimensions and the presence of abandoned channel facies are set as testing parameters resulting in 4 simulation cases with 200 realizations. Numerical flow simulations are performed on these models to investigate and compare the effects of reservoir and metre-scale heterogeneity on UHS gas mixing. Through simulation channel dimensions (reservoir-scale heterogeneity) are found to affect the uncertainty of produced gas composition due to mixing (represented by the P10-P90 difference of hydrogen fraction in a produced stream) by up to 42%. The presence of abandoned channel facies (metre-scale heterogeneity) depending on their architectural relationship with meander belts could also influence the gas mixing process to a comparable extent (up to 40%). Moreover we show that there is no clear statistical correlation between gas mixing and typical reservoir characterization parameters such as original gas in place (OGIP) average reservoir permeability and the Dykstra-Parsons coefficient. Instead the average time of travel of all reservoir cells calculated from flow diagnostics shows a negative correlation with the level of gas mixing. These results reveal the importance of 3D reservoir architecture analysis (integration of multiple levels of heterogeneity) to UHS site evaluation on gas mixing in depleted gas reservoirs. This study herein provides valuable insights into UHS site evaluation regarding gas mixing.

Climate change and the unsustainability of fossil fuels are calling for cleaner energies such as methanol as a fuel. Methanol is one of the simplest molecules for energy storage and is utilized to generate a wide range of products. Since methanol can be produced from biomass numerous countries could produce and utilize biomethanol. Here we review methanol production processes techno-economy and environmental viability. Lignocellulosic biomass with a high cellulose and hemicellulose content is highly suitable for gasifcation-based biomethanol production. Compared to fossil fuels the combustion of biomethanol reduces nitrogen oxide emissions by up to 80% carbon dioxide emissions by up to 95% and eliminates sulphur oxide emission. The cost and yield of biomethanol largely depend on feedstock characteristics initial investment and plant location. The use of biomethanol as complementary fuel with diesel natural gas and dimethyl ether is benefcial in terms of fuel economy thermal efciency and reduction in greenhouse gas emissions.

In this latest OIES podcast James Henderson talks to Bill Farren-Price the new Head of the Gas Programme about some of Key Themes identified by OIES research fellows for 2024. After a review of the outcomes from 2023 we look at the oil and gas markets and discuss a common theme around the contrast between the fundamental tightness in both markets compared with the relative softness of prices. We then move onto a number of energy transition issues starting with some of the key actions from COP28 that need to be implemented in 2024 and following with a review of the outlook for carbon markets hydrogen developments and offshore wind. We also consider the impact of emerging competition between regions over green industrial policy. Finally we consider some of the key geopolitical drivers for 2024 with the influence of China being the most critical. However in an election year for so many countries it will be critical to follow the key policy announcements of the main candidates and of most critically the outcome of the US election in November.

The podcast can be found on their website