Institution of Gas Engineers & Managers

In light of increased international efforts to combat climate change sustainable infrastructure is shifting toward green hydrogen produced through renewable-powered electrolysis. Still it is challenging to forecast the production of green hydrogen because environmental and system factors are variable both in time and space. We introduce a new system that utilizes a Spatio-Temporal Graph Convolutional Network (STGCN) and a novel algorithm the Ninja Optimization Algorithm (NiOA) to address this issue. Using the framework binary NiOA performs feature selection while continuous NiOA optimizes both the model architecture and the number of variables in the data simultaneously. It is clear from the research that forecasting results have shown significant improvement. The STGCN model achieved an R2 of 0.8769 and an MSE of 0.00375 whereas the STGCN with NiOA reached an R2 of 0.9815 and an MSE of only 7.48 × 10−8. Due to these improvements adaptive metaheuristics show even greater promise in delivering more accurate forecasting and reduced computational requirements for addressing critical environmental issues. The suggested strategy can be followed repeatedly providing a solid framework for the effective modeling of renewable energy systems and making green hydrogen projects more dependable.

As hydrogen gains prominence in energy systems its adoption as an energy source for fuel cell electric vehicles (FCEVs) necessitates the establishment of hydrogen refueling stations (HRS). These stations contain critical compo-nents including nozzles storage tanks heat exchangers and compressors which must be certified by regulatory agen-cies to ensure safety and public trust. Current certification processes are fragmented and manually intensive creating inefficiencies and limiting transparency across the infrastructure lifecycle. In this paper we propose a blockchain-based solution that creates a secure and auditable network for certifying key HRS components. The system integrates an EVM-compatible blockchain decentralized storage and a modular suite of smart contracts (SCs) that formalize registration bidding accreditation certification and governance. Each contract encodes a distinct actor-driven work-flow enabling traceable and role-specific operations. A Decentralized Application (DApp) interface supports real-time and role-based interaction across the ecosystem. We present and evaluate the SCs and their underlying algorithms us-ing gas usage analysis load testing and security auditing. Load testing across the certification lifecycle shows stable transaction throughput and predictable cost profiles under increasing actor activity. A static security analysis con-firms resilience against common vulnerabilities. Our cost analysis indicates that while the framework is technically deployable on public blockchains the execution costs of certain functions make it more cost-effective for private blockchains or Layer 2 networks. We also compare our framework with existing systems to highlight its novelty and technical advantages. Our SCs DApp interface and load testing scripts are publicly available on GitHub.

Given the Kenyan challenges in energy availability accessibility and affordability exploring green hydrogen as a sustainable energy solution is supreme. This study aimed to assess the potential of green hydrogen production a transformative clean energy technology and its implications for Kenya's future energy. The specific objectives were to identify the drivers of change that could accelerate green hydrogen adoption and policy recommendations. The study employed a scenario planning approach focusing on four key steps: defining the scenario and time horizon identifying drivers of change and developing and applying scenarios. The diffusion of innovation theory guided the study. Twelve key critical drivers of change were identified with societal and industry acceptance of green hydrogen and compatibility with existing energy infrastructure being the strongest drivers of change from cross-impact analysis results. The study outlined four plausible future scenarios for adoption: Successful Production (best scenario) Low Production Chaotic Transition and Rejection of Green Hydrogen Production (worst scenario). Major opportunities include advancements in hydrogen production export potential and job creation. Cost competitiveness analysis is essential comparing Kenya's hydrogen with traditional fuels and African peers. Economic models suggest that Kenya's renewable energy can lower costs enhancing its position in clean energy innovation. However critical challenges involve regulatory uncertainty ethical concerns public misconceptions about green hydrogen safety and financial barriers due to high initial investment costs. The study recommended that the Kenyan government invest in renewable energy infrastructure formulate a comprehensive national hydrogen policy and establish an enabling environment to attract private investment. In conclusion green hydrogen production stands as a strategic pillar for Kenya’s sustainable energy transition and further research should focus on strengthening regulatory frameworks and enhancing public engagement to unlock its full potential.

Hydrogen will play a critical role in decarbonizing diverse economic sectors. However given limited sustainable resources and the energy-intensive nature of its production prioritizing its applications will be essential. Here we analyse approximately 2000 (low-carbon) hydrogen projects worldwide encompassing operational and planned initiatives until 2043 quantifying their greenhouse gas (GHG) emissions and mitigation potential from a life cycle perspective. Our results demonstrate the variability in GHG emissions of hydrogen applications depending on the geographical location and hydrogen source used. The most climate-effective hydrogen applications include steel-making biofuels and ammonia while hydrogen use for road transport power generation and domestic heating should be discouraged as more favourable alternatives exist. Planned low-carbon hydrogen projects could generate 110 MtH2 yr−1 emit approximately 0.4 GtCO2e yr−1 and potentially reduce net life cycle GHG emissions by 0.2–1.1 GtCO2e yr−1 by 2043 depending on the substituted product or service. Addressing the current hydrogen implementation gap and prioritizing climate-effective applications are crucial for meeting decarbonization goals.

Hydrogen-based fuels are potential candidates to help international shipping achieve net-zero greenhouse gas (GHG) emissions by around 2050. This paper quantifies the environmental impacts of liquid hydrogen liquid ammonia and methanol used in a Post-Panamax container ship from 2020 to 2050. It considers cargo capacity changes electricity decarbonization and hydrogen production transitions under two International Energy Agency scenarios: the Stated Policies Scenario (STEPS) and the Net Zero Emissions by 2050 Scenario (NZE). Results show that compared to the existing HFO ship hydrogen-based propulsion systems can decrease cargo weight capacity by 0.3 % to 25 %. In the NZE scenario hydrogen-based fuels can reduce GHG emissions per tonne-nautical mile by 48 %–65 % compared to heavy fuel oil by 2050. Even with fully renewable hydrogenbased fuels 18 %–31 % of GHG emissions would still remain. Using hydrogen-based fuels in internal combustion engines requires attention to minimize environmental trade-offs.

Global renewable hydrogen trade is expected to play a key role in decarbonizing future energy systems. Yet hydrogen exporters may deviate from perfectly competitive behaviour to influence prices similarly to the existing fossil fuel market with important implications for consumer welfare and the pace of the energy transition. This study develops a global renewable hydrogen trade model that captures potential strategic interactions among exporters using a Stackelberg game-theoretic framework. The model is formulated as an Equilibrium Problem with Equilibrium Constraints (EPEC) and solved under three alternative equilibria: a profitmaximizing Nash equilibrium a cost-minimizing Nash equilibrium and a welfare-maximizing benchmark representing perfect competition. Results indicate that producers may strategically reduce their export quantities by up to 40 % relative to perfect competition to maximize profits. Such behaviour raises prices to a minimum of 4.5 USD/kg in 2050 across major import markets thereby significantly eroding consumer surplus. Strategic behaviour of dominant exporters also shifts trade flows reshaping the global allocation of hydrogen supply. Sensitivity analysis further reveals that financing costs play a key role in shaping strategic producers’ behaviour with lower financing costs helping to reduce prices and stimulate demand. These findings highlight the implications of imperfect competition in global hydrogen trade and suggest that policy measures may be needed to mitigate potential negative consequences.

This study investigates the cost-optimal capacity and operation of water electrolyzers in global net-zero CO2 energy systems. The production costs of hydrogen are largely determined by the electrolyzer capacity factor (i.e. full-load hours); therefore a global energy system model with an hourly temporal resolution was employed to consider the intermittency of variable renewable energy (VRE) and the dynamics of power system operations. Proton exchange membrane electrolysis is assumed in this study. The optimization results suggest three main findings. First water electrolysis is estimated to be a cost-effective option for achieving net-zero CO2 emissions. Under default technology assumptions the global installed capacity is projected to reach 2719 GW by 2050 with the majority of hydrogen consumed in the industry sector. Scaling up the supply chain is essential to realize this pathway. Second hydrogen and hydrogen-based fuels are economically competitive with negative emission technologies (NETs). A modest deployment of CO2 storage and NETs provides favorable conditions for water electrolysis deployment—and vice versa. Third flexible operation is critical to the widespread deployment of water electrolysis. In the default case the global weighted average capacity factor of electrolyzers is estimated at 37 % in 2050 to follow VRE output fluctuations. The results also indicate that limited operational flexibility may significantly hinder the cost-competitiveness of electrolyzer deployment.

In 2023 global carbon dioxide emissions reached 40 billion tonnes 60 % more than in 1990 intensifying climate concerns. This study explores hydrogen-natural gas blending as a transitional strategy for decarbonization across several regions and energy sectors – residential commercial industrial and agricultural. A multi-regional analysis framework evaluates integration of 20 % by volume low-carbon hydrogen blending into natural gas systems by identifying hydrogen producers importers and exporters based on production and import costs. Applied to Canada 528 scenarios (2026–2050) assess inter-regional hydrogen trade within Canadian provinces. The lowest-cost scenario involves Alberta exporting hydrogen produced through autothermal reforming with 91 % carbon capture and storage and British Columbia producing its own. The grid electrolysis scenario achieves the highest GHG reductions with a 4.5 % GHG mitigation in Canada with full energy system representation. These findings provide insights for policymakers and stakeholders in advancing hydrogen infrastructure and decarbonization strategies.

Fluidized bed systems play a crucial role in industrial processes such as combustion and gasification. In the Iron Power Cycle fluidized bed systems are essential for enabling the reduction of combusted iron back to iron making them a critical component in the regeneration step of the cycle. This study investigates the impact of operating gas velocity on conversion by performing reduction experiments at three distinct fluidization numbers (us/umf): 16 (bubbling regime) 55 (transition region) and 100 (fully turbulent regime). Experiments were conducted to determine the appropriate velocities for each regime ensuring optimal fluidization conditions across reduction temperatures ranging from 500 to 700 ⚬C. The results reveal that conversion rates increase significantly with gas velocities. At 500 ⚬C operating at approximately six times higher velocity leads to a sixfold improvement in conversion when using iron-oxide particles with a Sauter mean diameter of 61 µm. However while enhanced velocities improve reaction efficiency challenges remain at elevated temperatures (T ≥ 500 ⚬C) where iron undergoes defluidization when exposed to hydrogen. Once defluidization occurs refluidization proves impossible with either hydrogen or nitrogen raising concerns about process stability. These insights highlight the potential for optimizing fluidized bed reduction through velocity control while also underscoring the need for additional measures to mitigate unstable fluidization during high-temperature iron oxide reduction.

Hydrogen blending in natural gas systems is a key transitional strategy for reducing carbon emissions. This study explores the influence of hydrogen on combustion properties including flame flashback risk quenching distance and energy efficiency. Experimental and computational analyses demonstrate that hydrogen addition increases flame speed but reduces calorific value and quenching distance thereby impacting combustion stability and safety. Findings suggest that optimizing burner design and combustion control strategies is essential for safely and efficiently using hydrogen-enriched natural gas. Experimental validation confirmed that a 1.50 mm channel dimension effectively prevented flame flashback for hydrogen concentrations up to 40% in natural gas. As energy systems evolve toward decarbonization this research provides critical insights into the feasibility and challenges of hydrogen integration in residential or industrial applications. The study investigated the combustion behavior of natural gas enriched with various concentrations of hydrogen (up to 25%). Dynamic or fluctuating mixing conditions were excluded as the implementation of such a system in energy sector applications would necessitate a stable and well-defined gas composition.

This project has investigated equipment used to carry out purging of gas networks with a view to providing tooling for commissioning SGN’s H100 Fife project.

It has built on work including the HyPurge NIA2_SGN0008 and Lot 1 of the Hydrogen Skills and Standards for Heat projects. The project has further advanced the body of purge theory founded and developed in those previous projects. The HyPurge project showed that direct purging was feasible with hydrogen; this project has investigated some of the hazards presented and recommended tooling to mitigate those hazards.

Flame arrestors are specified for certain network operations involving Natural Gas. It is recommended that the current procedures regarding flame arrestors are kept for hydrogen and a range of flame arrestors suited to hydrogen use has been identified.

Purge tables specify minimum speeds for purging related to pipe diameter. These minimum purge speeds are used to suppress the buoyancy driven effect of a less dense gas to preferentially flow over a denser gas. The lower buoyancy of hydrogen suggests an increase in purge speed of 1.7x those recommended for methane. This increase is not required in smaller diameters (100 mm and below) where it has been found that diffusion effects dominate purge performance resulting in greater flexibility for purging. Therefore purge tables have been produced giving recommended minimum purge speeds for methane and hydrogen according to the PE pipe diameters proposed in the H100 Fife project.

A purge stack with additional features to assist with hydrogen purging has been developed in this project. The features include a restriction at the end of the stack to mitigate burn-back in the event of a vent ignition. Specific restriction sizes are linked to the diameter of network pipes being purged and each individual restriction is tailored to achieve the correct purge speed for the given network pipe diameter. A pressure gauge on the stack indicates sufficient back pressure showing the correct purge flow is being achieved. The stack also includes a hydrogen wHystle (developed by Steer independently) to provide feedback on purge progress in real time.

A review of non-sparking tool requirements has been carried out. Purge operations are such that it is unlikely that non-sparking tools will provide a significant reduction in hazard. The conclusions from this are that the current recommendations from SGN’s mainlay procedures on non-sparking tools and ignition prevention will be suitable for hydrogen use.

A preliminary investigation into the consequences of in-pipe ignitions has been carried out. The investigation has shown that the overpressures generated are affected by several different factors. The proportion of the pipe that contains the flammable mixture affects the ability of the system to absorb the overpressure through non-flammable gas buffer zones. Once detonable zones increase in size then the absolute length of the detonable zone in relation to pipe diameter becomes a dominant factor. The most significant hazard to be prevented is an in-pipe detonation therefore the volume of detonable mixture is an important factor that may result in a limit to the permitted length for direct purging in a given pipe diameter.

The hazards presented during purging have been investigated and three specific hazards have been studied. These are ignition of the vent in-pipe ignition and burn back from a vent ignition into the pipe. Although none of these events are likely to occur ignition of the vent is the most likely and the consequence of this is similar with hydrogen and methane. In-pipe ignition is the event with the greatest consequence and although very unlikely this should be avoided.

Proposed further work includes: data mining from the body of purge studies to date identification of the growth of flammable and detonable zones vs. purge length a study into static electricity generation and consequence testing on ignitions in a variety of 90 mm and 125 mm PE pipes of different lengths.

This report was submitted to HSE for their assessment of the safety evidence for 100% hydrogen heating which can be found at Hydrogen heating: HSE assessment of the safety evidence - GOV.UK.

Queries should be directed to DESNZ: https://www.gov.uk/guidance/contact-desnz

This study conducted theoretical modelling and experimental work to investigate if there were differences in particle transportation behaviour in hydrogen compared to natural gas. It was found that both experimental data and predictions indicate that the majority of particles are currently mobile at the standard maximum natural gas velocity of 20m/s thus an increase in velocity to 70m/s with hydrogen should not result in an increase in particle transportation. The experimental observations are that natural gas can transport particles at lower velocities than hydrogen and this is thought to be due to the higher density of natural gas. The consequence is that at a velocity of 20m/s natural gas would transport all mobile particles as would hydrogen at higher velocities and this means that high velocity hydrogen cannot transport more particles already transported by natural gas.

Therefore this study indicates that the mitigations for example filtration requirements and engineering policies and procedures should be unaffected by changing to hydrogen as no change to particle loading is anticipated.

CONCLUSIONS

• Modelling has been undertaken to predict particle flight and rolling velocities in 100% hydrogen and 100% natural gas to support experiments.

    o Initial comparison between the CFD modelling and British Gas modelling indicates results are similar for both particle        rolling and flight velocities for 100% hydrogen at 2barg.

    o For 100% methane the British Gas model results are 32-38% lower than those predicted by CFD modelling.

• Initial particle transportation experiments have been conducted using a purpose built test facility at Spadeadam to investigate particle transportation in 100% hydrogen and 100% natural gas at 2barg and 40mbarg.

    o Initial experimental results indicate that particle transportation occurred at lower velocities in natural gas than for             hydrogen.

    o From experimental data rolling and flight of particles occurs over a range of velocities and there is not one specific velocity to instigate rolling or flight.

    o Tests were performed for services in hydrogen. However a limited amount of sand was observed to travel up the service compared to the mains.

• Both experimental data and predictions indicate that the majority of particles are currently mobile at the standard maximum natural gas velocity of 20m/s (for unfiltered gas) thus an increase in velocity to 70m/s with hydrogen should not result in an increase in particle transportation.

• This study indicates that the mitigations used for natural gas should still be effective for hydrogen service

This report was submitted to HSE for their assessment of the safety evidence for 100% hydrogen heating which can be found at Hydrogen heating: HSE assessment of the safety evidence - GOV.UK.

Queries should be directed to DESNZ: https://www.gov.uk/guidance/contact-desnz.

There is a requirement for gas distribution network (GDN) operators to understand the cost safety and practicality of converting network pipelines from Natural Gas to Hydrogen in multi-occupancy buildings (MOBs). Previous work undertaken during project ‘MOBs Work Pack 2 Asset Information Review’ [1] considered the requirements for pressure testing commissioning and decommissioning of MOBs following a conversion to Hydrogen and identified the following gaps in technical evidence.

“How does Hydrogen affect the requirements for ventilation and explosion relief?”

“Work is required to understand the ventilation requirements of meters installed inside dwellings whether existing ventilation in MOBs is adequate and the practicalities of increasing the ventilation should it be required. Work has already been undertaken under the NIA project ‘NIA_WWU_2_12 – Ventilation Within Buildings’[2]. It was proposed that ROSEN review the NIA_WWU_2_12 work and confirm its applicability to MOBs”.

"Further work is required including a study consisting of a review of relevant British Standards (BS 8313 [77] BS 6891 [75] and BS 5925 [78]) and validation through case studies to determine how duct dimensions and ventilation requirements are affected by Hydrogen. This work would also need to determine whether the size and positioning of existing vents are adequate with Hydrogen.

“Further work is required to determine whether the ventilation in dwellings is adequate for risers and laterals located within and passing through dwellings.”

SGN is leading a feasibility project with some applied testing to understand the steps needed to convert MOBs to Hydrogen including any testing required to address any evidence gaps. This report focuses on the ventilation requirements associated with the conversion of MOBs from Natural Gas to Hydrogen. The objectives of this task are to:

• Determine ventilation requirements for meters risers and laterals inside buildings.

• Determine ventilation requirements for typical meter banks and energy centres with Hydrogen and how they compare with ventilation requirements for Natural Gas and update Table 6 of IGEM/G/5 Edition 3 [2]

• Determine ventilation requirements for typical ducts with Hydrogen and how they compare with ventilation requirements for Natural Gas and update Table 8 of IGEM/G/5 Edition 3.

• Investigate the feasibility of adding ventilation to MOBs which will need to be positioned so as not to compromise fire safety if located in a fire compartment.

This report was submitted to HSE for their assessment of the safety evidence for 100% hydrogen heating which can be found at Hydrogen heating: HSE assessment of the safety evidence - GOV.UK.

Queries should be directed to DESNZ: https://www.gov.uk/guidance/contact-desnz.

This project has built on the Hazardous Area Impact Mitigation (HAIM) Phase 1 project (NIA2_SGN0041) results that identified a disparity between hazardous zones measured during initial testing and those specified in the IGEM/SR/25 Hydrogen supplement. The aim of the HAIM Phase 2 project is to scale up the measurements to confirm the behaviour of larger vents equivalent to the test cases presented in the ATEX Equipment & IGEM/SR/25 Modification Assessment (NGNG_NIA_346) project.

The formation of a technical review group has informed the project team of the parameters and some of the assumptions used for the modelling leading to the development of the SR/25 Hydrogen Supplement. The difference between the modelled and measured data seen in the HAIM Phase 1 project has been attributed to the modelled data being carried out under a minimum of 0.5 m/s cross winds. Completely still conditions are not expected to occur hence this 0.5 m/s minimum. The result of this wind on the model leads to a significant reduction of the height of the resulting plume and a corresponding increase in the radial displacement of the plume from the vent tip. This has shifted the focus of this project towards examining wind influenced vents.

Two sets of experiments are provided in this interim report: measurements of plumes from wind influenced vents and plumes from fixtures and fitting leaks. The report also includes early results from plume ignition studies which have shown that ignition is not instantaneous for high velocity plumes.

The wind influenced plume tests have measured 0.0005 kg/s hydrogen releases from 50 mm and 15 mm vent pipes. The largest hazardous zone for these releases stipulated in IGEM/SR/25 hydrogen supplement is Xr = 2.5 m and Xh = 1.5 m so these were used as the extent of measurement. With no wind the plume rises vertically from the vent tip with no radial deflection. Measured concentration peaks have exceeded the lower flammable limit (LFL) at the 1.5 m measurement height. The influence of wind radially displaces the plume the higher the wind the larger the displacement. Concentration peaks are reduced but a wind of 0.5 m/s still permitted levels above the 4 % LFL value. Wind levels of 1.0 m/s displaced the plume to the end of the 2.5 m measurement array. Wind levels of 1.5 m/s broke up the plumes potentially driving pockets of gas beyond the 2.5 m measurement array.

Partial ignition of both vent types was possible at 1.5 m above the vent tip but complete sustained ignition was only possible when closer than 1 m to the vent tip.

Plumes from higher pressure (above 0.1 barg) fixture and fitting leaks have shown a good correlation between the shapes of modelled and measured vents. Except for the lowest pressure leaks which are momentum-dominated jets the resulting plumes are long and thin unaffected by buoyancy. The concentration decay in measured plumes is observed to be faster with distance compared to modelled values. Typically the measured distance to reach 2 % volume from the leak position is about half of the specified zone distances.

Limited ignition tests have been conducted but ignition from a 2 barg adverse downward pointing leak was challenging beyond 30 cm from the leak. The hydrogen jet also repeatably extinguished the methane flame used as pilot light during tests.

The next steps for the project are to carry out more measurements and to scale up the magnitude of the gas releases. This will provide more evidence supporting specified magnitudes of hazardous zones. In addition it is proposed that mitigation measures are explored that could reduce the specified hazardous zones for given vents. This could include design guidelines for hydrogen vents.

Further ignition tests will also be conducted to assess required conditions such as flow direction and gas concentration required to achieve both partial and stable ignition of hydrogen vents.

This report was submitted to HSE for their assessment of the safety evidence for 100% hydrogen heating which can be found at Hydrogen heating: HSE assessment of the safety evidence - GOV.UK.

Queries should be directed to DESNZ: https://www.gov.uk/guidance/contact-desnz.

This feasibility study has investigated the potential of repurposing existing gas installations for hydrogen use in Multi-Occupancy Buildings (MOBs). MOBs is a broad term extending from a single floor of flats over a shop to large tower blocks. For this study a MOB is defined as a building having at least one meter point and which meets one of these two criteria:

• The building contains at least three domestic dwellings

• The building contains a mixture of domestic dwellings and commercial units with there being at least three dwellings and units in total.

Due to the diverse nature of MOBs and the assets meter positions and appliances used in them it is necessary to sub-divide the population into archetypes and separately assess the risk posed in each category. Customers should only be exposed to Broadly Acceptable risk as defined as an individual risk of fatality of no more than 1 in 1 million per year in the HSE guidance document Reducing Risk Protecting People [1]. Due to the potential for multiple fatalities in MOBs it is important to understand how each building might respond to an incident and reduce risk to As Low As Reasonably Practicable (ALARP).

It is also reasonable to suggest that a customer’s risk after conversion to hydrogen should be comparable to that which currently exists for natural gas. Therefore risk to individuals within a building once converted to hydrogen should be no worse than either the risk faced by them prior to conversion or the average risk for that building height prior to conversion.

Based on SGN’s data the analysis has shown that with universally applied risk mitigation measures and up to two additional mitigations where required around 99% of MOBs can converted to hydrogen using repurposed assets. Detail can be located in Table 7 on page 12 of this report.

There are around 1% of MOBs where it is likely that existing natural gas installations cannot be repurposed for hydrogen use at an economic cost. The following options are available for this small proportion of buildings:

1. Accept a small individual risk increase in a small minority of building types.

2. Implement additional risk mitigation measures that would reduce those individual risks but at a disproportionate cost.

3. Remove gas supplies to these buildings and install an alternative energy source.

Based on the results the following recommendations are given:

• All MOBs to be divided into archetypes and subdivided by installation type prior to a pre-conversion site survey to identify the most practicable and cost-effective energy solution

• The survey will assess all the existing equipment which includes gas pipelines meter locations installation pipes and appliance locations against Gas Industry Standards

• Non-compliant installations will require further analysis and risk assessment on a case-by-case basis to determine their suitability for conversion to hydrogen

• It is proposed that where significant work will be required to re-purpose the existing installation to the required level of safety an economic assessment will be undertaken to determine the optimum solution for customers

• Further work should continue to develop and refine the risk assessment of hydrogen in MOBs. This will support the development of strategic decisions related to conversion. The risks associated with decommissioning gas installations in MOBs could also be assessed in future iterations

• Further work is required to assess Great Britain’s populations of MOBs and gas installation configurations

• Further work is required to provide a detailed cost benefit analysis across the Great Britain distribution networks to ensure that any proposals appropriately address societal expectations of risk versus investment and legal obligations

• Further work is required to define duty holders’ roles responsibilities and interoperability to convert MOBs to hydrogen

• The project has demonstrated that in most cases it is feasible to convert MOBs to hydrogen. The next steps include scoping of resource and operational strategies for conversion

• The additional MOB safety evidence recommendations detailed in Work Pack 3 - Task 12 of Appendix D should also be addressed.

This report was submitted to HSE for their assessment of the safety evidence for 100% hydrogen heating which can be found at Hydrogen heating: HSE assessment of the safety evidence - GOV.UK.

Queries should be directed to DESNZ: https://www.gov.uk/guidance/contact-desnz.

The current UK natural gas networks operated by the Gas Distribution Networks have the potential to flow blended hydrogen and to be re-purposed to flow 100% hydrogen. The hydrogen networks would therefore have the potential to contribute to Ofgem’s strategic innovation fund (SIF) decarbonisation of heat challenge to help meet national 2030 and 2050 emissions targets.

To demonstrate how the current gas networks can be intelligently and efficiently transitioned to provide low carbon heating the gas velocity constraints for hydrogen applied at the design stage need to be identified. These constraints will directly impact the level of capital investment required in the transition of the system to accommodate blended and 100% hydrogen.

However hydrogen gas does not contain the same level of energy by volume as natural gas so the volume of hydrogen flowing to consumers would have to increase a little over 3 times for an 100% hydrogen network to deliver energy at an equivalent rate compared to natural gas. Without network reinforcement this increase in flow could require a significant increase to the pressure and/or velocity of gas.

Currently IGEM standards specify a nominal maximum velocity of 20 m/s mainly to avoid the risk of debris within the pipes being picked up by the gas stream and causing wear to pipe components possibly then resulting in early failure. A velocity limit of 40 m/s is assumed where the pipe assets are assumed to be clean.

Debris may be present in the system particularly in the lower pressure tiers in the form of dust mainly as a product of the historic manufacture of towns gas. Whilst many metallic mains particularly in the LP pressure tier have been replaced with PE (polyethylene) piping under the ongoing replacement scheme it is anticipated that debris will still be present in the pipes that have not been replaced and may have already been transported into the plastic pipes. Hydrogen has different properties to natural gas so it is not known if debris may be picked up to the same degree or if any other factor will limit velocity. Other factors such as noise and/or vibration may also constrain the design velocity of gas in the system.

Building on this initial work it was envisaged that validation of the pipe network behaviour would require full scale testing to investigate the erosion vibration and noise behaviour associated with transportation of hydrogen and hydrogen blends with natural gas to support the objective of validating and enhancing existing models. To develop the requirements for such testing the “Alpha phase” (this phase) of the SIF project was initiated with the intention of delivering conceptual designs of the full-scale test facilities a detailed test programme and to undertake any associated laboratory testing which would be required to support these activities.

This report summarises the SIF alpha phase conclusions and recommendations from work packages 1 to 5:

Work package 1 Conceptual design of test facilities

Work package 2 Detailed test plan

Work package 3 Laboratory testing

Work package 4 Network engagement

Work package 5 Cost-benefit analysis

This report was submitted to HSE for their assessment of the safety evidence for 100% hydrogen heating which can be found at Hydrogen heating: HSE assessment of the safety evidence - GOV.UK.

Queries should be directed to DESNZ: https://www.gov.uk/guidance/contact-desnz.

Multiple Occupancy Buildings (MOBs) account for 21% of the UK’s domestic heating demand and tackling the challenge to decarbonise these properties will be key to meeting Government net zero targets.1 There is therefore a requirement for gas distribution network operators (GDNOs) to understand the cost safety and practicality of converting gas supplies to hydrogen. This project aimed to address evidence gaps centred around commissioning and decommissioning of risers associated with MOBs in particular purging operations.

The project has carried out a review of processes procedures and tooling used for purging MOBs examined site surveys and discussed purging with operators. Riser systems in MOBs are branched systems often comprising many vertical and horizontal elements taking a single supply source and distributing it to multiple individual dwellings in the building. Purging this network of elements is caried out in a routine manner as dictated by standards and procedures. Routine purging of MOBs is not challenging and this will continue to be the same when using hydrogen. The greatest challenge identified to purging MOBs is when each individual dwelling needs to be accessed to complete the purge. If an individual dwelling is inaccessible and individual lateral isolation valves are not installed then unpurged branches can remain. A consequence of leaving branches unpurged is a mixing of the air and fuel into a flammable mixture in the riser.

An experimental programme of work has been developed to investigate dispersion in unpurged branches of risers using methane and hydrogen. The experiments started with single pipes and developed in complexity to a branched system with six laterals. The main conclusions are: • If an unpurged branch is left over time the flammable volume at the interface between purged and unpurged sections will increase. Pipe diameter is the dominant parameter that dictates the speed of mixing of the two gases. • Gas dispersion occurs through a combination of buoyancy and diffusion buoyancy effects are diameter dependent becoming more dominant in pipe diameters greater than 50 mm. Below 50 mm gas dispersion is slow being dominated by diffusion alone. • Diffusion driven dispersion acts in the direction of concentration gradient from high to low. This acts to reduce the driving concentration gradient and slows down subsequent diffusion. In vertical pipes concentration gradients have been seen to act upwards or downwards. • Buoyancy effects act preferentially upwards but also promote mixing of different density gases in horizontal pipes. • In tests hydrogen dispersion was up to twice as fast as methane dispersion.

This report was submitted to HSE for their assessment of the safety evidence for 100% hydrogen heating which can be found at Hydrogen heating: HSE assessment of the safety evidence - GOV.UK.

Queries should be directed to DESNZ: https://www.gov.uk/guidance/contact-desnz.

Concerns relating to the production of carbon dioxide (CO2) and its effects on global background temperatures have led to international efforts to reduce CO2 emissions. A contributor to CO2 emissions is the burning of natural gas in domestic and commercial fuel supplies. The H21 project endeavours to explore the use of hydrogen gas as an alternative to natural gas.

As part of the work associated with delivering H21’s 100% hydrogen gas network a requirement was identified to develop a method of assessing the suitability of gas distribution network assets (e.g. pipes valves regulators) for use with hydrogen up to 7 barg. This project has developed such a methodology and this report summarises the work conducted and signposts the main deliverables.

The methodology developed for hydrogen suitability is based on a component-level analysis components being the individual items that make up an asset. The methodology structure is shown below where first the risk of the asset failing when operating on natural gas is determined. Next the asset is broken down to the component level and the individual risk of the components failing when operating on 100% hydrogen is determined. If the combination of these two risks is greater than is considered acceptable by the methodology the asset is considered not suitable for use with hydrogen without further mitigation.

The methodology is supported by the following key inputs delivered through the project:

♦ A list of assets on the gas distrbution network.

♦ A database of materials with their suitabiltiy for use with hydrogen quantified.

The method has been demonstrated on eight case studies and the next step will be for the project stakeholders to apply it to the population of network assets the results of which will gauge the networks readiness for hydrogen.

This report was submitted to HSE for their assessment of the safety evidence for 100% hydrogen heating which can be found at Hydrogen heating: HSE assessment of the safety evidence - GOV.UK.

Queries should be directed to DESNZ: https://www.gov.uk/guidance/contact-desnz.

In order to utilise the existing gas transmission and distribution network to transport 100% hydrogen the effects of the changes in characteristics of hydrogen from natural gas need to be reviewed and the resultant effect on the network assessed. Hydrogen features a substantially larger range of flammable concentrations than natural gas which could potentially cause safety concerns if the existing network is not reviewed. Hazardous area zoning of equipment present on the gas transmission and distribution network is modelled in accordance with standard IGEM/SR/25 Ed. 2. A hazardous area is defined in this standard as “an area in which explosive gas/air mixtures are or may be expected to be in quantities as such as to require special precautions for the construction installation and use of electrical apparatus or other sources of ignition.” A supplement to this standard compatible with the use of hydrogen blends up to 20% in addition to pure hydrogen was published by IGEM in November 2022. This hydrogen supplement has been utilised to establish the hazardous area zoning of hydrogen gas in 13 sites across multiple networks.

Hydrogen possesses a lower molar mass than natural gas therefore the mass flow rate of gas escaping relief vent pipework during venting operations is expected to decrease during pressure-driven release. Due to the larger flammable concentration range of hydrogen-air mixtures the impact on the sizes of hazardous areas was not immediately present. Across all sites the size of hazardous areas was seen to increase upon calculating the hydrogen mass flow rate for a given vent. It was observed on several sites that the hazardous areas of relief vents extended beyond the site boundaries.

Additional consideration was paid to vent pipe geometry in relation to sections 7.8.3 and 7.8.4 of IGEM/TD/13 Ed. 2 Supplement 1 – Pressure Regulating Installations for Hydrogen at Pressures Exceeding 7 bar. These clauses require that the Length/Diameter ratio of a vent pipe be kept below 60:1 to reduce the chance of combustion or detonation due to depressurisation in the vent pipe. This is due to hydrogen experiencing an increase in temperature during depressurisation as opposed to natural gas which decreases in temperature. This affects all sites due to the prevalence of small-bore pipework (10-15mm) used in impulse and instrumentation pipework. This also has potential to affect smaller relief vent pipework such as that used on district governors (typically 1”/25NB) depending on specific pipe and valve placement.

This report was submitted to HSE for their assessment of the safety evidence for 100% hydrogen heating which can be found at Hydrogen heating: HSE assessment of the safety evidence - GOV.UK.

Queries should be directed to DESNZ: https://www.gov.uk/guidance/contact-desnz.

In order to utilise the existing gas transmission and distribution network to transport 100% hydrogen the effects of the changes in characteristics of hydrogen from natural gas need to be reviewed and the resultant effect on the network assessed. Hydrogen features a substantially larger range of flammable concentrations than natural gas which could cause safety concerns if the existing network is not reviewed.

By surveying the electrical and instrumentation assets on site it was identified that many of the existing instruments currently in operation are not certified for the hydrogen environment (minimum Gas Group IIC) and require replacement.

There are a large quantity of instruments not suitable for the hydrogen environment due to asset condition / age and the effect of corrosion overtime affecting instruments such as missing or illegible faceplates resulting in being unable to verify ATEX certifications. A smaller percentage of existing instrumentation are in good condition but not certified for the hydrogen environment.

Equipment without a faceplate have been considered as not suitable for Hydrogen pending a review of certification for validation within a hydrogen atmosphere a replacement may not be required.

This report was submitted to HSE for their assessment of the safety evidence for 100% hydrogen heating which can be found at Hydrogen heating: HSE assessment of the safety evidence - GOV.UK.

Queries should be directed to DESNZ: https://www.gov.uk/guidance/contact-desnz.

In line with the UK governments decarbonisation strategy gas networks within the UK are continuing to investigate the potential to convert the UK gas networks to hydrogen. Northern Gas Network's (NGN) H21 project aims to enable the conversion to 100% hydrogen.

The process of converting the existing UK gas infrastructure involves primarily purging operations. Therefore there is a requirement to understand in more detail how hydrogen affects the requirements to conduct a safe and efficient purge.

The increased buoyancy forces associated with hydrogen is expected to increase the minimum purge velocity required to avoid stratification. This can easily be calculated theoretically for 100% hydrogen and can be used as a starting point for experimental investigations.

NGN's H21 project has focused on converting natural gas pipelines to 100% hydrogen via indirect purging which involves purging the air out with inert nitrogen first before commissioning with hydrogen. This avoids the potential to form a flammable mixture in the pipe as inert nitrogen is used as a buffer. However a minimum purge velocity is still required for the commissioning procedure to ensure efficiency and no pockets of nitrogen are left within the pipeline that could reach customers appliances.

This report provides the results of 32 set of tests which investigate stratification and the extent of mixing zones formed during the purge of the gases in pipe in relation to the purge speed. The programme is concerned with determining the minimum speed for successful purge in light of difficulties in satisfying Froude and Reynolds number criteria traditionally used as a basis for ensuring that stratified mixtures do not result and failed purges do not occur.

This report was submitted to HSE for their assessment of the safety evidence for 100% hydrogen heating which can be found at Hydrogen heating: HSE assessment of the safety evidence - GOV.UK.

Queries should be directed to DESNZ: https://www.gov.uk/guidance/contact-desnz.

Hydrogen is being proposed as a suitable low carbon alternative to natural gas. It has the potential to reduce green-house gas emissions across Great Britain’s industrial landscape but also for heating buildings. The Department of Energy Security and Net Zero (DESNZ) statistics show domestic heating currently accounts for 37% of the country’s CO2 emissions.

Hydrogen and natural gas are very similar when compared with other fuel sources. They are both gaseous at distribution operating pressures they can both be burned to release energy and they are both non-corrosives. This means that a piped distribution system and combustion appliances can be used to exploit their captured energy. They also differ from one another in that hydrogen has a broader range of flammability and lower ignition energy but is also much more buoyant and has higher diffusivity. Hydrogen does not have the potential to produce carbon monoxide when burnt the Health & Safety Executive’s (HSEs) incident statistics suggest that by 2032 there will still be 1.5 fatalities per year attributed to carbon monoxide poisoning as a direct result of using methane based natural gas for heating and cooking.

A Clean Heat Policy Decision from the Government is due in 2025. Ahead of this DESNZ has commissioned the Health and Safety Executive to carry out a Comprehensive Formal Assessment (CFA) of all safety and technical evidence on hydrogen due in mid-2025. The National Hydrogen Safety Assessment (NHSA) is being submitted to HSE along with other evidence for assessment as part of the CFA.

The purpose of the NHSA is to describe the minimum general arrangements that will be required to demonstrate that a network and its connected properties can be converted to hydrogen and be operated safely with risks appropriately managed for those working on the system or whose safety may be impacted including the general public (section 3). The NHSA applies to the transmission distribution and end use of hydrogen but does not include production or storage. At this time no specific parts of a network are planned for conversion and the NHSA therefore sets out the general approach to be taken for conversion and operation rather than detailed plans.

Subject to a successful policy decision on hydrogen for heating supported by HSE’s Comprehensive Formal Assessment of safety evidence the approach will be to develop detailed plans and safety cases to allow progression to delivering hydrogen conversion. The differences between natural gas and hydrogen mean that to transition from one gas to the other with the intention of utilising the same piped distribution system and end-utilisation requires due diligence assessment and where necessary updates to the system both to the assets themselves or the way they are operated.

This report was submitted to HSE for their assessment of the safety evidence for 100% hydrogen heating which can be found at Hydrogen heating: HSE assessment of the safety evidence - GOV.UK.

Queries should be directed to DESNZ: https://www.gov.uk/guidance/contact-desnz.

The purpose of this study is to consider identify and mitigate risks associated with a conversion (repurposing) of a natural gas (NG) installation to a 100% hydrogen (H2) installation within the current UK gas network. The scope of this project focuses on domestic gas installations downstream of the ECV to the appliance inlet.

The report analyses accident and leak data to explore the types of leak that occur in current NG domestic pipework. The differences in the physical properties of hydrogen and methane are tabulated and the differing behaviour of hydrogen and methane leaks is analysed.

This report concentrates on spontaneous leaks in the gap between small and the large which will trip the EFV. The dispersion of gas from the different types of leak and available ventilation models are discussed in detail.

British Standard and IGEM guidance documents are discussed in detail along with previous studies of hydrogen and NG leak behaviour.

The review recommends modifications to the original project work programme. In particular WP3 will be modified to examine methods of testing internal pipework to ensure that it is suitable for repurposing to hydrogen. This is an essential output from this project. This will include consideration of a range of options:

• Visual inspection of visible pipework

• Low pressure tightness testing

• Higher pressure strength testing

• Novel techniques such as thermal imaging or visual inspection using borescopes

• The use of other gases (helium) to check pipework soundness.

This report was submitted to HSE for their assessment of the safety evidence for 100% hydrogen heating which can be found at Hydrogen heating: HSE assessment of the safety evidence - GOV.UK.

Queries should be directed to DESNZ: https://www.gov.uk/guidance/contact-desnz.

Hydrogen is being proposed as a suitable low carbon alternative to natural gas. It has the potential to reduce green-house gas emissions across Great Britain’s industrial landscape but also for heating buildings. The Department of Energy Security and Net Zero (DESNZ) statistics show domestic heating currently accounts for 37% of the country’s CO2 emissions. Hydrogen also helps reduce fatalities associated with carbon monoxide. Discussions with the Health & Safety Executive (HSE) on incident statistics suggest that by 2032 there will still be 1.5 fatalities per year attributed to carbon monoxide poisoning as a direct result of using methane based natural gas for heating and cooking.

Hydrogen and natural gas are very similar when compared with other fuel sources. They are both gaseous at distribution operating pressures they can both be burned to release energy and they are both non-corrosives. This means that a piped distribution system and combustion appliances can be used to exploit their captured energy. They also differ from one another in that hydrogen has a broader range of flammability and lower ignition energy but is also much more buoyant and has higher diffusivity than natural gas; hydrogen also releases no carbon when burnt. The differences mean that to transition from one gas to the other with the intention of utilising the same piped distribution system and end-utilisation requires due diligence assessment and where necessary updates to the system – be that to the assets themselves or the way they are operated.

A strategic Government decision on the role of hydrogen in decarbonising heat is due in 2025. Ahead of this DESNZ has commissioned the Health and Safety Executive to carry out a Comprehensive Formal Assessment (CFA) of all safety and technical evidence on hydrogen due in mid-2025. The deadline to have all evidence to be assessed with the HSE is September 2024 (albeit work will continue after this date but not be part of the CFA). One of the safety demonstration requirements is an assessment of the change in risk posed by a transition to hydrogen. Whilst other projects focus on the risks related to transmission assets the emphasis of this piece of work has been on below 7 bar distribution assets and its end-users excluding industrial users and storage who would require bespoke risk assessments for their processes.

Several projects have been undertaken or contributed to hydrogen distribution and end-use risk assessments. DESNZ’s Hy4Heat Programme included a safety assessment in 2021. NGN’s H21 project and concurrent development of the Hydrogen Village Trial submissions helped progress the risk assessments in 2022 and 2023. They included the development of quantitative risk assessments (QRA) being carried out using the DNV modelling tool CONIFER which was developed specifically to differentiate between natural gas and hydrogen distribution systems.

Recognising the influx of additional safety and technical evidence throughout 2023 and 2024 leading up to the CFA deadline of September 2024 a final risk assessment was commissioned to cover all of Great Britain. It is the most thorough risk assessment the gas industry has ever carried out. All the Gas Distribution Networks (GDNs) and some of the Independent Gas Transporters (IGTs) have contributed to the study.

This report was submitted to HSE for their assessment of the safety evidence for 100% hydrogen heating which can be found at Hydrogen heating: HSE assessment of the safety evidence - GOV.UK.

Queries should be directed to DESNZ: https://www.gov.uk/guidance/contact-desnz.

Air ingress is not a new phenomenon that is exclusive to hydrogen - it already occurs in natural gas installations today (but has not previously been recorded as a challenge). Subsequent ignition events are highly unlikely requiring a very specific combination of actions and conditions to occur. However the likelihood and potential consequences of an ignition event occurring are greater with hydrogen systems (if unmitigated) compared to natural gas. Therefore additional safeguards are recommended for hydrogen systems to appropriately manage these risks. This work has concluded that theoretically any ignition events in hydrogen installations in the future should be prevented by requiring additional assurances within the formal testing and certification process of hydrogen appliances. However as good-practice extra layers of protection are also being recommended as precautionary measures - to inhibit the mechanisms of air ingress and to minimise the consequences of any (now unforeseeable) flash-back events respectively. Air ingress can be successfully mitigated in the short-term using existing technology and methods. Opportunities exist for significant improvements on mitigation measures in the future by deploying evolving technologies and ‘smart’ systems.

This report was submitted to HSE for their assessment of the safety evidence for 100% hydrogen heating which can be found at Hydrogen heating: HSE assessment of the safety evidence - GOV.UK.

Queries should be directed to DESNZ: https://www.gov.uk/guidance/contact-desnz.