United Kingdom

The geological storage of hydrogen is necessary to enable the successful transition to a hydrogen economy and achieve net-zero emissions targets. Comprehensive investigations must be undertaken for each storage site to ensure their long-term suitability and functionality. As such the systematic infrastructure and potential risks of large-scale hydrogen storage must be established. Herein we conducted over 250 batch reaction experiments with different types of reservoir sandstones under conditions representative of the subsurface reflecting expected time scales for geological hydrogen storage to investigate potential reactions involving hydrogen. Each hydrogen experiment was paired with a hydrogen-free control under otherwise identical conditions to ensure that any observed reactions were due to the presence of hydrogen. The results conclusively reveal that there is no risk of hydrogen loss or reservoir integrity degradation due to abiotic geochemical reactions in sandstone reservoirs.

The UK’s first-ever Hydrogen Strategy drives forward the commitments laid out in the Prime Minister’s ambitious 10 Point Plan for a green industrial revolution by setting the foundation for how the UK government will work with industry to meet its ambition for 5GW of low carbon hydrogen production capacity by 2030 – the equivalent of replacing natural gas in powering around 3 million UK homes each year as well as powering transport and businesses particularly heavy industry.<br/>A booming UK-wide hydrogen economy could be worth £900 million and create over 9000 high-quality jobs by 2030 potentially rising to 100000 jobs and worth up to £13 billion by 2050. By 2030 hydrogen could play an important role in decarbonising polluting energy-intensive industries like chemicals oil refineries power and heavy transport like shipping HGV lorries and trains by helping these sectors move away from fossil fuels. Low-carbon hydrogen provides opportunities for UK companies and workers across our industrial heartlands.<br/>With government analysis suggesting that 20-35% of the UK’s energy consumption by 2050 could be hydrogen-based this new energy source could be critical to meet our targets of net zero emissions by 2050 and cutting emissions by 78% by 2035 – a view shared by the UK’s independent Climate Change Committee. In the UK a low-carbon hydrogen economy could deliver emissions savings equivalent to the carbon captured by 700 million trees by 2032 and is a key pillar of capitalising on cleaner energy sources as the UK moves away from fossil fuels.

In this study a green hydrogen system was studied to provide electricity for an office building in the Sharjah emirate in the United Arab Emirates. Using a solar PV a fuel cell a diesel generator and battery energy storage; a hybrid green hydrogen energy system was compared to a standard hybrid system (Solar PV a diesel generator and battery energy storage). The results show that both systems adequately provided the power needed for the load of the office building. The cost of the energy for both the basic and green hydrogen energy systems was 0.305 USD/kWh and 0.313 USD/kWh respectively. The cost of the energy for both systems is very similar even though the capital cost of the green hydrogen energy system was the highest value; however the replacement and operational costs of the basic system were higher in comparison to the green hydrogen energy system. Moreover the impact of the basic system in terms of the carbon footprint was more significant when compared with the green hydrogen system. The reduction in carbon dioxide was a 4.6 ratio when compared with the basic system.

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.

Fuel transition can decarbonize shipping and help meet IMO 2050 goals. In this paper HFO with CCS LNG with CCS bio-methanol biodiesel hydrogen ammonia and electricity were studied using empirical ship design models from a fleet-level perspective and at the Tank-ToWake level to assist operators technology developers and policy makers. The cargo attainment rate CAR (i.e. cargo that must be displaced due to the low-C propulsion system) the ES (i.e. TTW energy needed per ton*n.m.) the CS (economic cost per ton*n.m.) and the carbon intensity index CII (gCO2 per ton*n.m.) were calculated so that the potential of the various alternatives can be compared quantitatively as a function of different criteria. The sensitivity of CAR towards ship type fuel type cargo type and voyage distance were investigated. All ship types had similar CAR estimates which implies that considerations concerning fuel transition apply equally to all ships (cargo containership tankers). Cargo type was the most sensitive factor that made a ship either weight or volume critical indirectly impacting on the CAR of different fuels; for example a hydrogen ship is weight-critical and has 2.3% higher CAR than the reference HFO ship at 20000 nm. Voyage distance and fuel type could result in up to 48.51% and 11.75% of CAR reduction. In addition to CAR the ES CS and CII for a typical mission were calculated and it was found that HFO and LNG with CCS gave about 20% higher ES and CS than HFO and biodiesel had twice the cost while ammonia methanol and hydrogen had 3–4 times the CS of HFO and electricity about 20 times suggesting that decarbonisation of the world’s fleet will come at a large cost. As an example of including all factors in an effort to create a normalized scoring system an equal weight was allocated to each index (CAR ES CS and CII). Biodiesel achieved the highest score (80%) and was identified as the alternative with the highest potential for a deep-seagoing containership followed by ammonia hydrogen bio-methanol and CCS. Electricity has the lowest normalized score of 33%. A total of 100% CAR is achievable by all alternative fuels but with compromises in voyage distance or with refuelling. For example a battery containership carrying an equal amount of cargo as an HFO-fuelled containership can only complete 13% of the voyage distance or needs refuelling seven times to complete 10000 n.m. The results can guide decarbonization strategies at the fleet level and can help optimise emissions as a function of specific missions.

Operating energy storage alongside onshore wind can improve its economics whilst providing a pathway for otherwise curtailed generation. In this work we present a framework to evaluate the economic potential of onshore wind co-located with battery storage (BS) and a hydrogen electrolyser (HE). This model is applied to a case study in Great Britain using historic data and considering local network charges and the cost of using curtailed power capturing an often neglected element of competition. We use a Markov Chain to model wind curtailment and determine the optimised scheduling of the storage as we vary price parameters and storage sizing. Finally by considering storage CAPEX and comparing against the case with no storage we can determine the value added (or lost) by different sized BS and HE for an onshore wind owner as a function of power purchase agreement (PPA) and green hydrogen market price. Results show that value added increases when HE is increased and when BS is decreased. Additionally a 10 MW electrolysers uses 27% more curtailed wind than 10 MW BS.

Delivering low-carbon heat will require the substitution of natural gas with low-carbon alternatives such as electricity and hydrogen. The objective of this paper is to develop a method to soft-link two advanced investment-optimising energy system models RTN (Resource-Technology Network) and WeSIM (Whole-electricity System Investment Model) in order to assess cost-efficient heat decarbonisation pathways for the UK while utilising the respective strengths of the two models. The linking procedure included passing on hourly electricity prices from WeSIM as input to RTN and returning capacities and locations of hydrogen generation and shares of electricity and hydrogen in heat supply from RTN to WeSIM. The outputs demonstrate that soft-linking can improve the quality of the solution while providing useful insights into the cost-efficient pathways for zero-carbon heating. Quantitative results point to the cost-effectiveness of using a mix of electricity and hydrogen technologies for delivering zero-carbon heat also demonstrating a high level of interaction between electricity and hydrogen infrastructure in a zero-carbon system. Hydrogen from gas reforming with carbon capture and storage can play a significant role in the medium term while remaining a cost-efficient option for supplying peak heat demand in the longer term with the bulk of heat demand being supplied by electric heat pumps.

Hydrogen produced without carbon emissions could be a useful fuel as nations look to decarbonize their electricity transport and industry sectors. Using the iodine–sulfur (IS) cycle coupled with a nuclear heat source is one method for producing hydrogen without the use of fossil fuels. An economic dispatch model was developed for a nuclear-driven IS system to determine hydrogen sale prices that would make such a system profitable. The system studied is the HTTR GT/H2 a design for power and hydrogen cogeneration at the Japan Atomic Energy Agency’s High Temperature Engineering Test Reactor. This study focuses on the development of the economic model and the role that input data plays in the final calculated values. Using a historical price duration curve shows that the levelized cost of hydrogen (LCOH) or breakeven sale price of hydrogen would need to be 98.1 JPY/m3 or greater. Synthetic time histories were also used and found the LCOH to be 67.5 JPY/m3 . The price duration input was found to have a significant effect on the LCOH. As such great care should be used in these economic dispatch analyses to select reasonable input assumptions.

The H21 National Innovation Competition project is examining the feasibility of repurposing the existing GB natural gas distribution network for transporting 100% hydrogen. It aims to undertake an experimental testing programme that will provide the necessary data to quantify the comparative risk between a 100% hydrogen network and the natural gas network. The first phase of the project focuses on leakage testing of a strategic set of assets that have been removed from service which provide a representative sample of assets across the network. This paper presents the work undertaken for Phase 1A (background testing) where HSE and industry partners have tested a range of natural gas pipework assets of varying size material age and pressure-rating in a new bespoke open-air testing facility at the HSE Science and Research Centre Buxton. The assets have been pressurised with hydrogen and then methane and the leakage rate from the assets measured in both cases. The main finding of this work is that the assets tested which leak hydrogen also leak methane. None of the assets were found to leak hydrogen but not methane. In addition repair techniques that were effective at stopping methane leaks were also effective at stopping hydrogen leaks. The data from the experiments have been interpreted to obtain a range of leakage ratios between the two gases for releases under different conditions. This has been compared to the predicted ratio of hydrogen to methane volumetric leak rates for laminar (1.2:1) and turbulent (2.9:1) releases and good agreement was observed.

Many countries have assigned an indispensable role for carbon capture and storage (CCS) in their national climate change mitigation pathways. However CCS deployment has stalled in most countries with only limited commercial projects realised mainly in hydrocarbon-rich countries for enhanced oil recovery. If the Paris Agreement is to be met then this progress must be replicated widely including hydrocarbon-limited countries. In this study we present a novel source-to-sink assessment methodology based on a hubs and clusters approach to identify favourable regions for CCS deployment and attract renewed public and political interest in viable deployment pathways. Here we apply this methodology to Spain where fifteen emission hubs from both the power and the hard-to-abate industrial sectors are identified as potential CO2 sources. A priority storage structure and two reserves for each hub are selected based on screening and ranking processes using a multi-criteria decision-making method. The priority source-to-sink clusters are identified indicating four potential development regions with the North-Western and North-Eastern Spain recognised as priority regions due to resilience provided by different types of CO2 sources and geological structures. Up to 68.7 Mt CO2 per year comprising around 21% of Spanish emissions can be connected to clusters linked to feasible storage. CCS especially in the hard-to-abate sector and in combination with other low-carbon energies (e.g. blue hydrogen and bioenergy) remains a significant and unavoidable contributor to the Paris Agreement’s mid-century net-zero target. This study shows that the hubs and clusters approach can facilitate CCS deployment in Spain and other hydrocarbon-limited countries.

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

There is worldwide interest in transporting hydrogen using both new pipelines and pipelines converted from natural gas service. Laboratory tests investigating the effect of hydrogen on the mechanical properties of pipeline steels have shown that even low partial pressures of hydrogen can substantially reduce properties such as reduction in area and fracture toughness and increase fatigue crack growth rates. However qualitative arguments suggest that the effects on pipelines may not be as severe as predicted from the small scale tests. If the trends seen in laboratory tests do occur in service there are implications for the assessment of damage such as volumetric corrosion dents and mechanical interference. Most pipeline damage assessment methods are semi-empirical and have been calibrated with data from full scale tests that did not involve hydrogen. Hence the European Pipeline Research Group (EPRG) commissioned a study to investigate damage assessment methods in the presence of hydrogen. Two example pipeline designs were considered both were assessed assuming a modern high performance material and an older material. From these analyses the numerical results show that the high toughness material will tolerate damage even if the properties are degraded by hydrogen exposure. However low toughness materials may not be able to tolerate some types of severe damage. If the predictions are realistic operators may have to repair more damage or reduce operating pressures. Furthermore damage involving cracking may not Page 2 of 22 satisfy the ASME B31.12 requirements for preventing time dependent crack growth. Further work is required to determine if the effects predicted using small scale laboratory test data will occur in practice.

As Europe moves towards decarbonising its energy infrastructure new measurement needs will arise that require collaborative efforts between European National Metrology Institutes and Designated Institutes to tackle. Such measurement needs include flow metering of hydrogen or hydrogen enriched natural gas in the gas grid for billing quality assurance of hydrogen at refuelling stations and equations of state for carbon dioxide in carbon capture and storage facilities. The European metrology network for energy gases for the first time provides a platform where metrology institutes can work together to develop a harmonised strategy prioritise new challenges and share expertise and capabilities to support the European energy gas industry to meet stringent EU targets for climate change and emissions reductions

Of all the alternatives to hydrocarbon fuels hydrogen offers the greatest long-term potential to radically reduce the many problems inherent in fuel used for transportation. Hydrogen vehicles have zero tailpipe emissions and are very efficient. If the hydrogen is made from renewable sources such as nuclear power or fossil sources with carbon emissions captured and sequestered hydrogen use on a global scale would produce almost zero greenhouse gas emissions and greatly reduce air pollutant emissions. The aim of this work is to realise a traceability chain for hydrogen flow metering in the range typical for fuelling applications in a wide pressure range with pressures up to 875 bar (for Hydrogen Refuelling Station - HRS with Nominal Working Pressure of 700 bar) and temperature changes from −40 °C (pre-cooling) to 85 °C (maximum allowed vehicle tank temperature) in accordance with the worldwide accepted standard SAE J2601. Several HRS have been tested in Europe (France Netherlands and Germany) and the results show a good repeatability for all tests. This demonstrates that the testing equipment works well in real conditions. Depending on the installation configuration some systematic errors have been detected and explained. Errors observed for Configuration 1 stations can be explained by pressure differences at the beginning and end of fueling in the piping between the Coriolis Flow Meter (CFM) and the dispenser: the longer the distance the bigger the errors. For Configuration 2 where this distance is very short the error is negligible.

In the framework of the ongoing EMPIR JRP 16ENG01 ‘‘Metrology for Hydrogen Vehicles’’ a main task is to investigate the influence of pressure on the measurement accuracy of Coriolis Mass Flow Meters (CFM) used at Hydrogen Refueling Stations (HRS). At a HRS hydrogen is transferred at very high and changing pressures with simultaneously varying flow rates and temperatures. It is clearly very difficult for CFMs to achieve the current legal requirements with respect to mass flow measurement accuracy at these measurement conditions. As a result of the very dynamic filling process it was observed that the accuracy of mass flow measurement at different pressure ranges is not sufficient. At higher pressures it was found that particularly short refueling times cause significant measurement deviations. On this background it may be concluded that pressure has a great impact on the accuracy of mass flow measurement. To gain a deeper understanding of this matter RISE has built a unique high-pressure test facility. With the aid of this newly developed test rig it is possible to calibrate CFMs over a wide pressure and flow range with water or base oils as test medium. The test rig allows calibration measurements under the conditions prevailing at a 70 MPa HRS regarding mass flows (up to 3.6 kg min−1) and pressures (up to 87.5 MPa).

This report evaluates the main options to provide required hydrogen storage capacity including the relevant system-level considerations and provides recommendations for further actions including low-regrets actions that are needed in a range of scenarios.

Many simplified methods for estimating blast loads from a hydrogen or vapor cloud explosion are unable to take into account the accurate geometry of confining spaces obstacles or landscape that may significantly interact with the blast wave and influence the strength of blast loads. Computation fluid dynamics (CFD) software Viper::Blast which was originally developed for the simulation of the detonation of high explosives is able to quickly and easily model geometry for blast analyses however its use for vapor cloud explosions and deflagrations is not well established. This paper describes the results of an investigation into the suitability of Viper::Blast for use in modeling hydrogen deflagration and detonation events from various experiments in literature. Detonation events have been captured with a high degree of detail and relatively little uncertainty in inputs while deflagration events are significantly more complex. An approach is proposed that may allow for a reasonable bounding of uncertainty potentially leading to an approach to CFD-based Monte Carlo analyses that are able to address a problem’s true geometry while remaining reasonably pragmatic in terms of run-time and computational investment. This will allow further exploration of practical CFD application to inform hydrogen safety in the engineering design assessment and management of energy mobility and transport systems infrastructure and operations.

The PRHYDE project (PRotocol for heavy duty HYDrogEn refueling) funded by the Clean Hydrogen partnership aims at developing recommendations for heavy-duty refueling protocols used for future standardization activities for trucks and other heavy duty transport systems applying hydrogen technologies. Development of a protocol requires a validated approach. Due to the limited time and budget the experimental data cannot cover the whole possible ranges of protocol parameters such as initial vehicle pressure and temperature ambient and precooling temperatures pressure ramp refueling time hardware specifications etc. Hence a validated numerical tool is essential for a safe and efficient protocol development. For this purpose engineering tools are used. They give good results in a very reasonable computation time of several seconds or minutes. These tools provide the heat parameters estimation in the gas (volume average temperature) and 1D temperature distribution in the tank wall. The following models were used SOFIL (Air Liquide tool) HyFill (by ENGIE) and H2Fills (open access code by NREL). The comparison of modelling results and experimental data demonstrated a good capability of codes to predict the evolution of average gas temperature in function of time. Some recommendations on model validation for the future protocol development are given.

In this seventh episode Steffan Eldred Hydrogen Innovation Network Knowledge Transfer Manager and Jenni McDonnell MBE Heating and Cooling Knowledge Transfer Manager from Innovate UK KTN discuss why using hydrogen to generate heat is so important and explore the hydrogen economy opportunities and challenges within this sector alongside their special guest Jeff House Head of External Affairs Baxi Boilers.

The podcast can be found on their website.

The present day energy supply scenario is unsustainable and the transition towards a more environmentally friendly energy supply system of the future is inevitable. Hydrogen is a potential fuel that is capable of assisting with this transition. Certain technological advancements and design challenges associated with hydrogen generation and fuel cell technologies are discussed in this review. The commercialization of hydrogen-based technologies is closely associated with the development of the fuel cell industry. The evolution of fuel cell electric vehicles and fuel cell-based stationary power generation products in the market are discussed. Furthermore the opportunities and threats associated with the market diffusion of these products certain policy implications and roadmaps of major economies associated with this hydrogen transition are discussed in this review.

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

Shifting from fossil fuels to clean alternative fuel options such as hydrogen is an essential step in decarbonising the road freight transport sector and facilitating an efficient transition towards zero-emissions goods distribution of the future. Designing an economically viable and competitive Hydrogen Supply Chain (HSC) to support and accelerate the widespread adoption of hydrogen powered Heavy Goods Vehicles (H2-HGVs) is however significantly hindered by the lack of the infrastructure required for producing storing transporting and distributing the required hydrogen. This paper focuses on a bespoke design of a hydrogen supply chain and distribution network for the long-haul road freight transportation in the UK and develops an improved end-to-end and spatially-explicit optimisation tool to perform scenario analysis and provide important first-hand managerial and policy making insights. The proposed methodology improves over existing grid-based methodologies by incorporating spatially-explicit locations of Hydrogen Refuelling Stations (HRSs) and allowing further flexibility and accuracy. Another distinctive feature of the method and the analyses carried out in the paper pertains to the inclusion of bulk geographically agnostic as well as geological underground hydrogen storage options and reporting on significant cost saving opportunities. Finally the curve for H2-HGVs penetration levels safety stock period decisions and the transport mode capacity against hydrogen levelized cost at pump have been generated as important policy making tools to provide decision support and insights into cost resilience and reliability of the HSC.

Low carbon hydrogen can be produced by a variety of processes that require substantial quantities of water. Several major hydrogen projects are proposed in Scotland; as an energy storage medium allowing new renewable power capacity to operate and as a direct alternative to displace natural gas as a primary fuel source. The additional water consumption associated with these hydrogen projects presents an infrastructure challenge.

The aims of the study are to evaluate the water requirements of new hydrogen production facilities and the associated implications for water infrastructure and to develop a strategic framework for assessing these aspects of hydrogen projects throughout the UK. The initial focus of the study is on Scotland; however the methodology developed in the project will be used throughout the UK

Benefits

Low carbon hydrogen can be produced by a variety of processes all of which require substantial quantities of water. Several major hydrogen projects are proposed in Scotland; both as an energy storage medium allowing new renewable power capacity (particularly wind) to operate and as a direct alternative to displace natural gas as a primary fuel source. The additional water consumption associated with these hydrogen projects presents an infrastructure challenge e.g. the Scottish Environment Protection Agency (SEPA) recently highlighted Scotland’s vulnerability to dry weather and climate-induced changes in the availability and functioning of water resources.

The project in partnership with Ramboll will look to deliver a technical assessment and feasibility study into water requirements for hydrogen production in Scotland. The aims of the study are to evaluate the water requirements of new hydrogen production facilities and the associated implications for water infrastructure and to develop a strategic framework for assessing these aspects of hydrogen projects throughout the UK. The initial focus of the study is on Scotland; however the methodology developed in the project will be used throughout the UK.

The research paper can be found on their website.

The UK government’s plans to decarbonise residential heating will mean major changes to the energy system whatever the specific technology pathway chosen driving a range of impacts on users and suppliers. We use an energy system model (UK TIMES) to identify the potential energy system impacts of alternative pathways to low or zero carbon heating. We find that the speed of transitioning can affect the network investment requirements the overall energy use and emissions generated while the primary heating fuel shift will determine which sectors and networks require most investment. Crucially we identify that retail price differences between heating fuels in the UK particularly gas and electricity could erode or eliminate bill savings from switching to more efficient heating systems.