United Kingdom

CFD modelling of liquified hydrogen boiling and evaporation during the pressurised tank venting is presented. The model is based on the volume-of-fluid method for tracking liquid and gas phases and Lee’s model for phase change. The simulation results are compared against the liquid hydrogen evaporation experiment performed by Tani et al. (2021) in a large-scale pressurised storage tank using experimental pressure dynamics and temperatures measured in gas and liquid phases. The study focuses on tank pressure decrease and recovery phenomena during the first 15 s of the venting process. The model sensitivity have been studied applying different Lee’s model evaporisation-condensation coefficients. The CFD model provided reasonable agreement with the observed pressure and gas phase temperature dynamics during the liquid hydrogen storage depressurisation using Lee’s model coefficient =0.05 s-1. Experimentalists’ hypothesis about particularly intensive boiling in the proximity of thermocouples was supported by close agreement between simulated and experimental saturation temperatures obtained from pressure dynamics.

With a limited global carbon budget it is imperative that decarbonisation decisions are based on accurate holistic accounts of all greenhouse gas (GHG) emissions produced to assess their validity. Here the upstream GHG emissions of potential UK offshore Green and Blue hydrogen production are compared to GHG emissions from hydrogen produced through electrolysis using UK national grid electricity and the ‘business-as-usual’ case of continuing to combust methane. Based on an operational life of 25 years and producing 0.5MtH2 per year for each hydrogen process the results show that Blue hydrogen will emit between 200-262MtCO2e of GHG emissions depending on the carbon capture rates achieved (39%–90%) Green hydrogen produced via electrolysis using 100% renewable electricity from offshore wind will emit 20MtCO2e and hydrogen produced via electrolysis powered by the National Grid will emit between 103-168MtCO2e depending of the success of its NetZero strategy. The ‘business-as-usual’ case of continuing to combust methane releases 250MtCO2e over the same lifetime. This study finds that Blue hydrogen at scale is not compatible with the Paris Agreement reduces energy security and will require a substantial GHG emissions investment which excludes it from being a ‘low carbon technology’ and should not be considered for any decarbonisation strategies going forward.

This paper presents a comprehensive review of existing explosion mitigation techniques for tunnels and evaluates their applicability in scenarios of hydrogen tank rupture in a fire. The study provides an overview of the current state of the art in tunnel explosion mitigation and discusses the challenges associated with hydrogen explosions in the context of fire incidents. The review shows that there are several approaches available to decrease the effects of explosions including wrapping the tunnel with a flexible and compressible barrier and introducing energy-absorbing flexible honeycomb elements. However these methods are limited to the mitigation of the action and do not consider either the mitigation of the structural response or the effects on the occupants. The study highlights how the structural response is affected by the duration of the action and the natural period of the structural elements and how an accurate design of the element stiffness can be used in order to mitigate the structural vulnerability to the explosion. The review also presents various passive and active mitigation techniques aimed at mitigating the explosion effects on the occupants. Such techniques include tunnel branching ventilation openings evacuation lanes right-angled bends drop-down perforated plates or high-performance fibre-reinforced cementitious composite (HPFRCC) panels for blast shielding. While some of these techniques can be introduced during the tunnel's construction phase others require changes to the already working tunnels. To simulate the effect of blast wave propagation and evaluate the effectiveness of these mitigation techniques a CFD-FEM study is proposed for future analysis. The study also highlights the importance of considering these mitigation techniques to ensure the safety of the public and first responders. Finally the study identifies the need for more research to understand blast wave mitigation by existing structural elements in the application for potential accidents associated with hydrogen tank rupture in a tunnel.

The report considers the full end-to-end nature of the hydrogen economy to ensure there is a common understanding of the economic opportunity it could represent by 2050. Insights from across industry have brought clarity to both market and technology requirements identifying four focus areas that represent the greatest potential benefit for the UK. It highlights the steps needed to build the UK industrial capability and capacity to position the UK as a market leader. The UK Hydrogen Innovation Opportunity has been developed with and for industry with the first phase of industrial engagement involving over 250 businesses and 12 sector bodies. A second phase of industrial engagement will expand to a broader set of consulted stakeholder groups concluding with a report entitled Hydrogen Innovation: The Case for Action in summer 2024. This will seek to validate the proposed focus areas provide more detailed scope definition the size of the opportunity and outline the steps required to secure them for the UK.

This report can also be downloaded for free on the Hydrogen Innovation Initiative website.

As one of the most promising renewable energy sources hydrogen has the excellent environmental benefit of producing zero emissions. A key technical challenge in using hydrogen across sectors is placed on its storage technology. The storage temperature of liquid hydrogen (20 K or 253 C) is close to absolute zero so the storage materials and the insulation layers are subjected to extremely stringent requirements against the cryogenic behaviour of the medium. In this context this research proposed to design a large liquid hydrogen type-C tank with AISI (American Iron and Steel Institution) type 316 L stainless steel as the metal barrier using Vapor-Cooled Shield (VCS) and Rigid Polyurethane Foams (RPF) as the insulation layer. A parametric study on the design of the insulation layer was carried out by establishing a thermodynamic model. The effects of VCS location on heat ingress to the liquid hydrogen transport tank and insulation temperature distribution were investigated and the optimal location of the VCS in the insulation was identified. Research outcomes finally suggest two optimal design schemes: (1) when the thickness of the insulation layer is determined Self-evaporation Vapor-Cooled Shield (SVCS) and Forcedevaporation Vapor-Cooled Shield (FVCS) can reduce heat transfer by 47.84% and 85.86% respectively; (2) when the liquid hydrogen evaporation capacity is determined SVCS and FVCS can reduce the thickness of the insulation layer by 50% and 67.93% respectively.

Multi-energy microgrids (MEMGs) with green hydrogen have attracted significant research attention for their benefits such as energy efficiency improvement carbon emission reduction as well as line congestion alleviation. However the complexities of multi-energy networks coupled with diverse uncertainties may threaten MEMG’s operation. In this paper a data-driven methodology is proposed to achieve effective MEMG operation considering the green hydrogen technique and congestion management. First a detailed MEMG modelling approach is developed coupling with electricity green hydrogen natural gas and thermal flows. Different from conventional MEMG models hydrogen-enriched compressed natural gas (HCNG) models and weatherdependent power flow are thoroughly considered in the modelling. Meanwhile the power flow congestion problem is also formulated in the MEMG operation which could be mitigated through HCNG integration. Based on the proposed MEMG model a reinforcement learning-based method is designed to obtain the optimal solution of MEMG operation. To ensure the solution’s safety a soft actor-critic (SAC) algorithm is applied and modified by leveraging the Lagrangian relaxation and safety layer scheme. In the end case studies are conducted and presented to validate the effectiveness of the proposed method.

This paper proposes and assesses three different control approaches for the hydrocarbon natural gas (HCNG) penetrated integrated energy system (IES). The three control approaches adopt mixed integer linear programing conditional value at risk (CVaR) and robust optimization (RO) respectively aiming to mitigate the renewable generation uncertainties. By comparing the performance and efficiency the most appropriate control approach for the HCNG penetrated IES is identified. The numerical analysis is conducted to evaluate the three control approaches in different scenarios where the uncertainty level of renewable energy (within the HCNG penetrated IES) varies. The numerical results show that the CVaR-based approach outperforms the other two approaches when renewable uncertainty is high (approximately 30%). In terms of the cost to satisfy the energy demand the operational cost of the CVaR-based method is 8.29% lower than the RO one while the RO-based approach has a better performance when the renewable uncertainty is medium (approximately 5%) and it is operational is 0.62% lower than that of the CVaR model. In both evaluation cases mixed integer linear programing approach cannot meet the energy demand. This paper also compares the operational performance of the IES with and without HCNG. It is shown that the IES with HCNG can significantly improve the capability to accommodate renewable energy with low upgrading cost.

The supplement to the standard IGEM/TD/1 gives the additional requirements and qualifications for pipelines transporting hydrogen and hydrogen/natural gas blends (NG/H blends) at pressures at MOP exceeding 7 barg.<br/>Where there is no numbered section in the supplement corresponding to a section in the main document the requirements of the main document apply in full. Where there is a corresponding numbered section in the main document the numbered section in the supplement is either in addition to or replaces the section in the main document.<br/>Repurposing in accordance with the recommendations of this supplement should only be considered for pipelines which have been operated in accordance with the recommendations of the main document for at least 5 years and which have been audited in accordance with the recommendations of clause 12.4.2.1. This requirement is specified so that compliance with the operational and maintenance requirements specified in the main standard is confirmed through records. With respect to pipelines this includes the requirements for MOP affirmation. This requirement is more onerous than the requirement is ASME B31.12 Clause GR-5.2.1[1] which requires that assessment for conversion to hydrogen service shall be assessed at the time of conversion and reassessment of integrity shall be done within 5 years of conversion.<br/>NG/H blends containing more than 10% mol hydrogen are considered to be equivalent to 100 mol.% hydrogen with respect to limits on design stresses and 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 (see clause S5.8). It is noted that there is no evidence to confirm that blends containing up to 10 mol.% hydrogen do not cause material degradation but it is considered that the risk is low.<br/>With respect to industry experience with towns gas this product contained 10-20 % carbon monoxide which has been identified as inhibiting the effect of hydrogen on fracture toughness and fatigue crack growth. Therefore the historical experience with town gas is not relevant.

A pivotal ambition to aid global decarbonisation efforts is green electrolytic hydrogen produced with renewable energy. Prolonged operation of water electrolysers induces cell degradation decreasing production efficiency and gas yield over the lifespan of the electrolyser stack. Considerations for degradation modelling is seen to a varying extent in previous literature. This work shows the effects of including degradation modelling within existing system scenarios and new ones to demonstrate the impact of inclusion on key techno-economic parameters. A fundamental Anion Exchange Membrane electrolyser model is constructed validated and utilised into a broader hydrogen and oxygen co-production system powered by solar-PV. A second scenario tests the compatibility of the no-degradation trend with reference material and then investigates the effects of including degradation modelling showing only a 1.47% increase in levelised cost of hydrogen (LCOH). Subsequent scenarios include determining that byproduct oxygen utilisation becomes beneficial for a scenario with rated electrolyser power of above 35 MW and the observations related to stack replacement strategies are discussed. Under hypothetically higher degradation rates detriment to gas yield and LCOH is around 5% for average operational degradation rates of 15–20 μV/hr and around 10% for 30–40 μV/hr compared to around 2% for the model baseline average rate of 5.23–5.26 μV/hr.

This paper presents the results of the H2SAREA project which focuses on integrating hydrogen (H2) into the existing natural gas (NG) distribution network with blends of up to 20%. A key component of the project was the H2Loop testing platform built using ex-service materials and components to realistically assess the impact of hydrogen on current systems and components. The investigation covered several critical areas including gas injection and blending network capacity leak detection gas pressure regulation station (GPRS) performance valve and meter functionality materials compatibility permeation testing and gas deblending. Results show the feasibility of safely injecting up to 20% hydrogen into the existing system offering valuable insights to guide the transition of gas distribution networks toward a hydrogen-based energy future.