United Kingdom

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

Hydrogen trade is an emerging area of interest for hydrogen developers end-users traders and governments around the world. It can enhance system flexibility energy security and clean growth enabling decarbonisation at a lower cost and faster pace. Thanks to its competitive advantage in existing ports terminals and interconnectors the UK is well placed to be the European trade hub for hydrogen and its carriers. With its access to world leading offshore wind generation capacity and geological storage the UK will almost certainly be a net exporter of hydrogen in the future delivering economic value and creating jobs. However hydrogen trade will not be a one-way process. In order to best position the UK as a future hydrogen trade hub there could be value in investing in small scale hydrogen imports and exports to ‘wet the pipes’ and stimulate investment in infrastructure. Imports could also enhance our energy security as a part of a diverse energy mix and support demand whilst domestic production gets up to speed. Both imports and exports will be key to build supply chains and skills and enhance clean growth. With major European economies having established their hydrogen trade strategy there is growing uncertainty as to how the United Kingdom will capitalise on its competitive advantage and position itself in the global hydrogen market. This is the first qualitative report released by Hydrogen UK’s Import and Export Taskforce. This report aims to provide a high-level overview of Hydrogen UK’s vision and recommendations with subsequent reports exploring this topic in further detail.

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

Inspired by the announcement of the new Hydrogen Strategy for the UK in 2021 this study aimed to determine how the oil and gas industry responds and adapts to the changes. This paper analyses qualitative and quantitative data from the companies’ annual and energy reports. Four oil and gas companies involved in hydrogen projects in the UK were selected as case studies. The responses from the companies were collected using the content analysis research strategy in 2019–2021. A steady increase was observed based on the code frequency reflecting the increasing discussions and actions the companies took regarding this hydrogen pathway. Although only one company appears to be at the forefront of this transition progress with a score of almost 90% based on the strategy management analysis other companies continue to demonstrate their commitment to supporting the national target.

The UK government plans to phase out pure diesel trains by 2040 and fully decarbonize railways by 2050. Hydrogen fuel cell (HFC) trains electrified trains using pantographs (Electrified Trains) and battery electric multiple unit (BEMU) trains are considered the main solutions for decarbonizing railways. However the range of these decarbonization options’ line upgrade cost advantages is unclear. This paper analyzes the upgrade costs of three types of trains on different lines by constructing a cost model and using particle swarm optimization (PSO) including operating costs and fixed investment costs. For the case of decarbonization of the London St. Pancras to Leicester line the electrified train option is more cost-effective than the other two options under the condition that the service period is 30 years. Then the traffic density range in which three new energy trains have cost advantages on different line lengths is calculated. For route distances under 100 km and with a traffic density of less than 52 trips/day BEMU trains have the lowest average cost while electrified trains are the most costeffective in other ranges. For route distances over 100 km the average cost of HFC trains is lower than that of electrified trains at traffic densities below about 45 trips/day. In addition if hydrogen prices fall by 26 % the cost advantage range of HFC trains will increase to 70 trips per day. For route distances under 100 km BEMU trains still maintain their advantages in terms of lower traffic density.

Hydrogen plays an important role in the global transition towards Net-Zero emission. While pipelines are a viable option to transport large quantities of compressed hydrogen over long distances it is not always practical in many applications. In such situations a viable option is to transport and deliver large quantities of hydrogen as cryogenic liquid. The liquefaction process cools hydrogen to cryogenic temperatures below its boiling point of -259.2 0C. Such extreme low temperature implies specific hazards and risks which are different from those associated with the relatively well-known compressed gaseous hydrogen. Managing these specific issues brings new challenges for the stakeholders.<br/>Furthermore the transfer of liquid hydrogen (LH2) and its technical handling is relatively well known for industrial gas or space applications. Experience with LH2 in public and populated areas such as truck and aircraft refuelling stations or port bunkering stations for example is limited or non-existent. Safety requirements in these applications which involve or are in proximity of untrained public are different from rocket/aerospace industry.<br/>The manuscript reviews knowhow already gained by the international hydrogen safety community; and on such basis elucidate the gaps which are yet to be filled to meet industry needs to design and operate inherently safe LH2 operations including the implications for regulations codes and standards (RCS). Where relevant the associated gaps in some underpinning sciences will be mentioned; and the need to contextualise the information and safety practices from NASA1/ESA2/JAXA3 to inform risk adoption will be summarised.

The widespread use of hydrogen as an energy source relies on efficient large-scale storage techniques. Underground Hydrogen Storage (UHS) is a promising solution to balance the gap between renewable energy production and constant energy demand. UHS employs geological structures like salt caverns depleted reservoirs or aquifers for hydrogen storage enabling long-term and scalable storage capacity. Therefore robust and reliable predictive tools are essential to assess the risks associated with geological hydrogen storage. This paper presents a novel reactive transport model called “Underground Gas Flow simulAtions with Coupled bio-geochemical reacTions” or “UGFACT” designed for various gas injection processes accounting for geochemical and microbial reactions. The flow module and geochemical reactions in the UGFACT model were verified against two commercial reservoir simulators E300 and CMG-GEM showing excellent agreement in fluid flow variables and geochemical behaviour. A major step forward of this model is to integrate flow dynamics geochemical reactions and microbial activity. UGFACT was used to conduct a simple storage cycle in a 1D geometry across three different reservoirs each with different mineralogies and water compositions: Bentheimer sandstone Berea sandstone and Grey Berea sandstone under three microbial conditions (“No Reaction” “Moderate Rate” “High Rate”). The findings suggest that Bentheimer sandstone and Berea sandstone sites may experience severe effects from ongoing microbial and geochemical reactions whereas Grey Berea sandstone shows no significant H2 loss. Additionally the model predicts that under the high-rate microbial conditions the hydrogen consumption rate can reach to as much as 11 mmol of H2 per kilogram of water per day (mmol / kg⋅day) driven by methanogenesis and acetogenesis.