Hydrogen Blending

In light of the Paris Agreement road-freight represents a critically difficult-to-abate sector. In order to meet the ambitious European transport sector emissions reduction targets a rapid transition to zero-carbon road-freight is necessary. However limited policy assessments indicate where and how to appropriately intervene in this sector. To support policy-makers in accelerating the zero-carbon road-freight transition this paper examines the relative cost competitiveness between commercial vehicles of varying alternative drive-technologies through a total cost of ownership (TCO) assessment. We identify key parameters that when targeted enable the uptake of these more sustainable niche technologies. The assessment is based on a newly compiled database of cost parameters which were triangulated through expert interviews. The results show that cost competitiveness for low- or zero-emission niche technologies in certain application segments and European countries is exhibited already today. In particular we find battery electric vehicles to show great promise in the light- and medium-duty segments but also in the heavy-duty long-haul segments in countries that have enacted targeted policy measures. Three TCO parameters drive this competitiveness: tolls fuel costs and CAPEX subsidies. Based on our analysis we propose that policy-makers target OPEX before CAPEX parameters as well utilize a mix of policy interventions to ensure greater reach increased efficiency and increased policy flexibility.

Lean premixed swirl combustion is widely used in gas turbines and many other combustion Processes due to the benefits of good flame stability and blow off limits coupled with low NO_x emissions. Although flashback is not generally a problem with natural gas combustion there are some reports of flashback damage with existing gas turbines whilst hydrogen enriched fuel blends especially those derived from gasification of coal and/or biomass/industrial processes such as steel making cause concerns in this area. Thus this paper describes a practical experimental approach to study and reduce the effect of flashback in a compact design of generic swirl burner representative of many systems. A range of different fuel blends are investigated for flashback and blow off limits; these fuel mixes include methane methane/hydrogen blends pure hydrogen and coke oven gas. Swirl number effects are investigated by varying the number of inlets or the configuration of the inlets. The well known Lewis and von Elbe critical boundary velocity gradient expression is used to characterise flashback and enable comparison to be made with other available data. Two flashback phenomena are encountered here. The first one at lower swirl numbers involves flashback through the outer wall boundary layer where the crucial parameter is the critical boundary velocity gradient Gf. Values of Gf are of similar magnitude to those reported by Lewis and von Elbe for laminar flow conditions and it is recognised that under the turbulent flow conditions pertaining here actual gradients in the thin swirl flow boundary layer are much higher than occur under laminar flow conditions. At higher swirl numbers the central recirculation zone (CRZ) becomes enlarged and extends backwards over the fuel injector to the burner baseplate and causes flashback to occur earlier at higher velocities. This extension of the CRZ is complex being governed by swirl number equivalence ratio and Reynolds Number. Under these conditions flashback occurs when the cylindrical flame front surrounding the CRZ rapidly accelerates outwards to the tangential inlets and beyond especially with hydrogen containing fuel mixes. Conversely at lower swirl numbers with a modified exhaust geometry hence restricted CRZ flashback occurs through the outer thin boundary layer at much lower flow rates when the hydrogen content of the fuel mix does not exceed 30%. The work demonstrates that it is possible to run premixed swirl burners with a wide range of hydrogen fuel blends so as to substantially minimise flashback behaviour thus permitting wider used of the technology to reduce NOx emissions.

Following the international trend of using hydrogen as combustible in many industry branches this paper investigates the impact of mixing methane gas with 23% hydrogen (G222) on condensing boilers’ operation. After modeling and testing several boilers with heat exchange surface different designs the authors gathered enough information to introduce a new concept namely High-Performance Condensing Boiler (HPCB). All the boilers that fit into this approach have the same operational parameters at nominal heat load including the CO2 concentrations in flue gases. After testing a flattened pipes condensing boiler a CO2 emission reduction coefficient of 1.1 was determined when converting from methane gas to G222 as combustible. Thus by inserting into the national grid a G222 mixture an important reduction in greenhouse gases can be achieved. For a 28 kW condensing boiler the annual reduction in CO2 emissions averages 1.26 tons value which was experimentally obtained and is consistent with the theoretical evaluation.

Britain's gas networks are ready for hydrogen blending. Learn more about Britain's hydrogen blending capacity in the National Transmission System and Distribution Networks.

A steady state analysis method was developed for gas networks with distributed injection of alternative gas. A low pressure gas network was used to validate the method. Case studies were carried out with centralized and decentralized injection of hydrogen and upgraded biogas. Results show the impact of utilizing a diversity of gas supply sources on pressure distribution and gas quality in the network. It is shown that appropriate management of using a diversity of gas supply sources can support network management while reducing carbon emissions.

With increasing shares of variable and uncertain renewable generation in many power systems there is an associated increase in the importance of energy storage to help balance supply and demand. Gas networks currently store and transport energy and they have the potential to play a vital role in longer-term renewable energy storage. Gas and electricity networks are becoming more integrated with quick-responding gas-fired power plants providing a significant backup source for renewable electricity in many systems. This study investigates Ireland’s gas network and operation when a variable green hydrogen input from excess wind power is blended with natural gas. How blended hydrogen impacts a gas network’s operational variables is also assessed by modelling a quasi-transient gas flow. The modelling approach incorporates gas density and a compressibility factor in addition to the gas network’s main pressure and flow rate characteristics. With an increasing concentration of green hydrogen up to 20% in the gas network the pipeline flow rate must be increased to compensate for reduced energy quality due to the lower energy density of the blended gas. Pressure drops across the gas pipeline have been investigated using different capacities of P2H from 18 MW to 124 MW. The results show significant potential for the gas network to store and transport renewable energy as hydrogen and improve renewable energy utilisation without upgrading the gas network infrastructure.

The deployment of low-carbon hydrogen in gas grids comes with strategic benefits in terms of energy system integration and decarbonization. However hydrogen thermophysical properties substantially differ from natural gas and pose concerns of technical and regulatory nature. The present study investigates the blending of hydrogen into distribution gas networks focusing on the steady-state fluid dynamic response of the grids and gas quality compliance issues at increasing hydrogen admixture levels. Two blending strategies are analyzed the first of which involves the supply of NG–H2 blends at the city gate while the latter addresses the injection of pure hydrogen in internal grid locations. In contrast with traditional case-specific analyses results are derived from simulations executed over a large number (i.e. one thousand) of synthetic models of gas networks. The responses of the grids are therefore analyzed in a statistical fashion. The results highlight that lower probabilities of violating fluid dynamic and quality restrictions are obtained when hydrogen injection occurs close to or in correspondence with the system city gate. When pure hydrogen is injected in internal grid locations even very low volumes (1% vol of the total) may determine gas quality violations while fluid dynamic issues arise only in rare cases of significant hydrogen injection volumes (30% vol of the total).

Blending hydrogen into the natural gas infrastructure is becoming a very promising practice to increase the exploitation of renewable energy sources which can be used to produce “green” hydrogen. Several research projects and field experiments are currently aimed at evaluating the risks associated with utilization of the gas blend in end-use devices such as the gas meters. In this paper the authors present the results of experiments aimed at assessing the effect of hydrogen injection in terms of the durability of domestic gas meters. To this end 105 gas meters of different measurement capabilities and manufacturers both brand-new and withdrawn from service were investigated in terms of accuracy drift after durability cycles of 5000 and 10000 h with H2NG mixtures and H2 concentrations of 10% and 15%. The obtained results show that there is no metrologically significant or statistically significant influence of hydrogen content on changes in gas meter indication errors after subjecting the meters to durability testing with a maximum of 15% H2 content over 10000 h. A metrologically significant influence of the long-term operation of the gas meters was confirmed but it should not be made dependent on the hydrogen content in the gas. No safety problems related to the loss of external tightness were observed for either the new or 10-year-old gas meters.

The aim of the article is to determine what amount of hydrogen in %mol can be transferred/stored in the Estonian Latvian and Lithuanian grid gas networks based on the limitations of chemical and physical requirements technical requirements of the gas network and quality requirements. The main characteristics for the analysis of mixtures of hydrogen and natural gas are the Wobbe Index relative density methane number and calorific value. The calculation of the effects of hydrogen blending on the above main characteristics of a real grid gas is based on the principles described in ISO 6976:2016 and the distribution of the grid gas mole fraction components from the grid gas quality reports. The Wärtsila methane number calculator was used to illustrate the effects of hydrogen blending on the methane number of the grid gas. The calculation results show that the maximum hydrogen content in the grid gas (hydrogen and natural gas mix) depending on the grid gas quality parameters (methane number gross heat of combustion specific gravity and the Wobbe Index) is in the range of 5–23 %mol H2. The minimum hydrogen content (5 %mol H2) is limited by specific gravity (>0.55). The next limitation is at 12 %mol H2 and is related to the gross heat of combustion (>9.69 kWh/m3). It is advisable to explore the readiness of gas grids and consumers in Estonia Latvia and Lithuania before switching to higher hydrogen blend levels. If the applicability and safety of hydrogen blends above 5 %mol is approved then it is necessary to analyse the possible reduction of the minimum requirements for the quality of the grid gas and evaluate the associated risks (primarily related to specific gravity).

Hydrogen has emerged as a promising option for promoting decarbonization in various sectors by serving as a replacement for natural gas while retaining the combustion-based conversion system. However its higher reactivity compared to natural gas introduces a significant risk of flashback. This study investigates the impact of operating and geometry parameters on flashback phenomena in multi-slit burners fed with hydrogenmethane-air mixtures. For this purpose transient numerical simulations which take into account conjugate heat transfer between the fluid and the solid walls are coupled with stochastic sensitivity analysis based on Generalized Polynomial Chaos. This allows deriving comprehensive maps of flashback velocities and burner temperatures within the parameter space of hydrogen content equivalence ratio and slit width using a limited number of numerical simulations. Moreover we assess the influence of different parameters and their interactions on flashback propensity. The ranges we investigate encompass highly H2 -enriched lean mixtures ranging from 80% to 100% H2 by volume with equivalence ratios ranging from 0.5 to 1.0. We also consider slit widths that are typically encountered in burners for end-user devices ranging from 0.5 mm to 1.2 mm. The study highlights the dominant role of preferential diffusion in affecting flashback physics and propensity as parameters vary including significant enrichment close to the burner plate due to the Soret effect. These findings hold promise for driving the design and optimization of perforated burners enabling their safe and efficient operation in practical end-user applications.

Various research and development activities are being conducted to use hydrogen an environmentally friendly fuel to achieve carbon neutrality. Using natural gas–hydrogen blends has advantages such as the usage of traditional combined cycle power plant (CCPP) technology and existing natural gas piping infrastructure. Therefore we conducted CCPP process modeling and economic analysis based on natural gas–hydrogen blends. For process analysis we developed a process model for a 400 MW natural gas CCPP using ASPEN HYSYS and confirmed an error within the 1% range through operation data validation. For economic analysis we comparatively reviewed the levelized cost of electricity (LCOE) of CCPPs using hydrogen blended up to 0.5 mole fraction. For LCOE sensitivity analysis we used fuel cost capital expenditures capacity factor and power generation as variables. LCOE is 109.15 KRW/kWh when the hydrogen fuel price is 2000 KRW/kg and the hydrogen mole fraction is increased to 0.5 a 5% increase from the 103.9 KRW/kWh of CCPPs that use only natural gas. Economic feasibility at the level of 100% natural gas CCPPs is possible by reducing capital expenditures (CAPEX) by at least 20% but net output should be increased by at least 5% (20.47 MW) when considering only performance improvement.

Hydrogen is of great significance for replacing fossil fuels and reducing carbon dioxide emissions. The application of hydrogen mixing with natural gas in gas network transportation not only improves the utilization rate of hydrogen energy but also reduces the cost of large-scale updating household or commercial appliance. This paper investigates the necessity of a gas mixing device for adding hydrogen to existing natural gas pipelines in the industrial gas network. A three-dimensional helical static mixer model is developed to simulate the mixing behavior of the gas mixture. In addition the model is validated with experimental results. Parametric studies are performed to investigate the effect of mixer on the mixing performance including the coefficient of variation (COV) and pressure loss. The research results show that based on the the optimum number of mixing units is three. The arrangement of the torsion angle of the mixing unit has a greater impact on the COV. When the torsion angle θ = 120◦ the COV has a minimum value of 0.66% and when the torsion angle θ = 60◦ the COV has a maximum value of 8.54%. The distance of the mixing unit has little effect on the pressure loss of the mixed gas but has a greater impact on the COV. Consecutive arrangement of the mixing units (Case A) is the best solution. Increasing the distance of the mixing unit is not effective for the gas mixing effect. Last but not least the gas mixer is optimized to improve the mixing performance.

Replacing fossil fuels with non-carbon fuels is an important step towards reaching the ultimate goal of carbon neutrality. Instead of moving directly from the current natural gas energy systems to pure hydrogen an incremental blending of hydrogen with natural gas could provide a seamless transition and minimize disruptions in power and heating source distribution to the public. Academic institutions industry and governments globally are supporting research development and deployment of hydrogen blending projects such as HyDeploy GRHYD THyGA HyBlend and others which are all seeking to develop efficient pathways to meet the carbon reduction goal in coming decades. There is an understanding that successful commercialization of hydrogen blending requires both scientific advances and favorable techno-economic analysis. Ongoing studies are focused on understanding how the properties of methane-hydrogen mixtures such as density viscosity phase interactions and energy densities impact large-scale transportation via pipeline networks and enduse applications such as in modified engines oven burners boilers stoves and fuel cells. The advantages of hydrogen as a non-carbon energy carrier need to be balanced with safety concerns of blended gas during transport such as overpressure and leakage in pipelines. While studies on the short-term hydrogen embrittlement effect have shown essentially no degradation in the metal tensile strength of pipelines the long-term hydrogen embrittlement effect on pipelines is still the focus of research in other studies. Furthermore pressure reduction is one of the drawbacks that hydrogen blending brings to the cost dynamics of blended gas transport. Hence techno-economic models are also being developed to understand the energy transportation efficiency and to estimate the true cost of delivery of hydrogen blended natural gas as we move to decarbonize our energy systems. This review captures key large-scale efforts around the world that are designed to increase the confidence for a global transition to methane-hydrogen gas blends as a precursor to the adoption of a hydrogen economy by 2050.

The blending of hydrogen gas into natural gas pipelines is an effective way of achieving the goal of carbon neutrality. Due to the large differences in the calorific values of natural gas from different sources the calorific value of natural gas after mixing with hydrogen may not meet the quality requirements of natural gas and the quality of natural gas entering long-distance natural gas and urban gas pipelines also has different requirements. Therefore it is necessary to study the effect of multiple gas sources and different pipe network types on the differences in the calorific values of natural gas following hydrogen admixing. In this regard this study aimed to determine the quality requirements and proportions of hydrogen-mixed gas in natural gas pipelines at home and abroad and systematically determined the quality requirements for natural gas entering both long-distance natural gas and urban gas pipelines in combination with national standards. Taking the real calorific values of the gas supply cycle of seven atmospheric sources as an example the calorific and Wobbe Index values for different hydrogen admixture ratios in a one-year cycle were calculated. The results showed that under the requirement of natural gas interchangeability there were great differences in the proportions of natural gas mixed with hydrogen from different gas sources. When determining the proportion of hydrogen mixed with natural gas both the factors of different gas sources and the factors of the gas supply cycle should be considered.

As smart grid develops and renewables advance challenges caused by uncertainties of renewables have been seriously threatening the energy system’s safe operation. Nowadays the integrated electric-gas system (IEGS) plays a significant role in promoting the flexibility of modern grid owing to its great characteristic in accommodating renewable energy and coping with fluctuation and uncertainty of the system. And hydrogen as an emerging and clean energy carrier can further enhance the energy coupling of the IEGS and promote carbon neutralization with the development of power-to-hydrogen (P2H) technology and technology of blending hydrogen in the natural gas system. Dealing with the uncertainty of renewables a robust schedule optimization model for the integrated electric and gas systems with blending hydrogen (IEGSH) considering the dynamics of gas is proposed and the iterative solving method based on column-and-constraint generation (C&CG) algorithm is implemented to solve the problem. Case studies on the IEGSH consisting of IEEE 39-bus power system and 27-node natural gas system validate the effectiveness of the dynamic energy flow model in depicting the transient process of gas transmission. The effectiveness of the proposed robust day-ahead scheduling model in dealing with the intra-day uncertainty of wind power is also verified. Additionally the carbon emission reduction resulting from the blending of hydrogen is evaluated.

The article reviews gas turbine combustion technologies focusing on their current ability to operate with hydrogen enriched natural gas up to 100% H2. The aim is to provide a picture of the most promising fuel-flexible and clean combustion technologies the object of current research and development. The use of hydrogen in the gas turbine power generation sector is initially motivated highlighting both its decarbonisation and electric grid stability objectives; moreover the state-of-the-art of hydrogen-blend gas turbines and their 2024 and 2030 targets are reported in terms of some key performance indicators. Then the changes in combustion characteristics due to the hydrogen enrichment of natural gas blends are briefly described from their enhanced reactivity to their pollutant emissions. Finally gas turbine combustion strategies both already commercially available (mostly based on aerodynamic flame stabilisation self-ignition and staging) or still under development (like the micro-mixing and the exhaust gas recirculation concepts) are described.

A numerical study of the energy conversion process occurring in a lean-charge cogenerative engine designed to be powered by natural gas is here conducted to analyze its performances when fueled with mixtures of natural gas and several percentages of hydrogen. The suitability of these blends to ensure engine operations is proven through a zero–one-dimensional engine schematization where an original combustion model is employed to account for the different laminar propagation speeds deriving from the hydrogen addition. Guidelines for engine recalibration are traced thanks to the achieved numerical results. Increasing hydrogen fractions in the blend speeds up the combustion propagation achieving the highest brake power when a 20% of hydrogen fraction is considered. Further increase of this last would reduce the volumetric efficiency by virtue of the lower mixture density. The formation of the NOx pollutants also grows exponentially with the hydrogen fraction. Oppositely the efficiency related to the exploitation of the exhaust gases’ enthalpy reduces with the hydrogen fraction as shorter combustion durations lead to lower temperatures at the exhaust. If the operative conditions are shifted towards leaner air-to-fuel ratios the in-cylinder flame propagation speed decreases because of the lower amount of fuel trapped in the mixture reducing the conversion efficiencies and the emitted nitrogen oxides at the exhaust. The link between brake power and spark timing is also highlighted: a maximum is reached at an ignition timing of 21° before top dead center for hydrogen fractions between 10 and 20%. However the exhaust gases’ temperature also diminishes for retarded spark timings. Lastly an optimization algorithm is implemented to individuate the optimal condition in which the engine is characterized by the highest power production with the minimum fuel consumption and related environmental impact. As a main result hydrogen addition up to 15% in volume to natural gas in real cogeneration systems is proven as a viable route only if engine operations are shifted towards leaner air-to-fuel ratios to avoid rapid pressure rise and excessive production of pollutant emissions.

The lack of hydrogen (H2) transportation infrastructure restricts the development of the H2 industry. Owing to the high investment of building specific facilities using existing natural gas (NG) pipelines to transport a blend of H2 and NG (H2NG) is a viable means of transportation and approach for large-scale long-time storage. However variation in the thermo-physical properties of an H2NG blend will impact the performance of pipeline appliances. To address the gaps in H2 transmission via an NG system in the context of energy consumption in the present paper a one-dimensional pipeline model is proposed to predict the blended flow in a real existing pipeline (Shan–Jing I China). The data of NG components were derived from real gas fields. Furthermore the influence of H2 fractions on pipeline energy coefficient and the layout of pressurization stations are comprehensively analyzed. In addition the case of intermediate gas injection is investigated and the effects of injection positions are studied. This study serves as a useful reference for the design of an H2NG pipeline system. The present study reveals that with the increasing in H2 fraction the distance between pressure stations increases. Furthermore when the arrangement of original pressure stations is maintained overpressure occur. Intermediate gas injection results in the inlet pressure of subsequent pressurization stations reducing. Using existing pipeline network to transport H2NG it is necessary to make appropriate adjustment.

Operators of public electricity grids today are faced with the challenge of integrating increasing numbers of renewable and decentralized energy sources such as wind turbines and photovoltaic power plants into their grids. These sources produce electricity in a very inconstant manner due to the volatility of wind and solar power which further complicates power grid control and management. One key component that is required for modern energy infrastructures is the capacity to store large amounts of energy in an economically feasible way.<br/>One solution that is being discussed in this context is “power-to-gas” i.e. the use of surplus electricity to produce hydrogen (or even methane with an additional methanation process) which is then injected into the public natural gas grid. The huge storage capacity of the gas grid would serve as a buffer offering benefits with regards to sustainability and climate protection while also being cost-effective since the required infrastructure is already in place.<br/>One consequence would be however that the distributed natural gas could contain larger and fluctuating amounts of hydrogen. There is some uncertainty how different gas-fired applications and processes react to these changes. While there have already been several investigations for domestic appliances (generally finding that moderate amounts of H2 do not pose any safety risks which is the primary focus of domestic gas utilization) there are still open questions concerning large-scale industrial gas utilization. Here in addition to operational safety factors like efficiency pollutant emissions (NOX) process stability and of course product quality have to be taken into account.<br/>In a German research project Gas- und Wärme-Institut Essen e. V. (GWI) investigated the impact of higher and fluctuating hydrogen contents (up to 50 vol.-% much higher than what is currently envisioned) on a variety of industrial combustion systems using both numerical and experimental methods. The effects on operational aspects such as combustion behavior flame monitoring and pollutant emissions were analyzed.<br/>Some results of these investigations will be presented in this contribution.

The development of hydrogen-blended natural gas (HBNG) increases the risk of gas transportation and presents challenges for pipeline security in utility tunnels. The objective of this study is to investigate the diffusion properties of HBNG in utility tunnels and evaluate the effectiveness of various ventilation mechanisms. The numerical simulation software Fluent 2023 R1 is applied to simulate and analyze the leakage of small holes in a HBNG pipeline in the natural gas compartment. By examining the leaking behavior of HBNG through small holes in different circumstances we aimed to identify the most unfavorable operational situation for leakage. Subsequently we analyzed the ventilation strategy for sub-high-pressure pipes at various pressure levels in this unfavorable condition. This study’s findings demonstrate that blending hydrogen improves the gas diffusion capacity and increases the likelihood of explosion. The primary factors that influence the pattern of leakage are the size of the leaking holes and the pressure of the pipeline. The gas compartment experiences the most unfavorable working conditions for natural gas pipeline leaks when there are higher pressures wider leak openings higher hydrogen blending ratios (HBRs) and leaks in close proximity to an air inlet. When the HBR is 20% the minimum accident ventilation rates for pressures of 0.4 MPa and 0.8 MPa are 15 air changes per hour and 21 air changes per hour respectively. The maximum allowable wind speed for accident ventilation is 5 m/s as regulated by China’s national standard GB 50838-2015. This regulation makes it difficult to minimize the risk of leakage in a 1.6 MPa gas pipeline. It is recommended to install a safety interlock device to quickly shut off the pipeline in the event of a leak in order to facilitate the dispersion of the substance.

Hydrogen blending into natural gas has attracted significant attention in domestic applications. The paper studied the effects of natural gas mixed with hydrogen at 0% (vol) 5% 10% 15% 20% and 25% on the performance of typical round-port gas stove (TRPGS) swirling strip-port gas stove (SSPGS) and radiant porous media gas stove (RPMGS). The experimental results show that flame length shortens with the increase of hydrogen proportion and the combustion remains stable when the hydrogen proportion is equal to or less than 25%. With increasing hydrogen proportion the measured heat inputs of the three types of domestic gas stoves decrease gradually and the average thermal efficiency of TRPGS and SSPGS increase by 0.82% and 1.18% respectively. In addition the average efficiency of the RPMGS first increases by 1.35% under a hydrogen proportion of 15% and then decreases by 1.36% under a hydrogen proportion of 25%. In terms of flue gas emission CO emission reduces significantly with increasing hydrogen proportion while NOX emissions remain almost unchanged.

DNV has carried out an investigation into potential uses for smart gas meter data as part of Phase 1 of the Modernising Energy Data Applications competition as funded by UK Research & Innovation. In particular a series of calculations have been carried out to investigate the possibility of differentiating accidental gas leaks from normal appliance use in domestic properties. This is primarily with the aim of preventing explosions but the detection of leaks also has environmental and financial benefits.

Three gases have been considered in this study:

• A representative UK natural gas composition.
• A blend of 80% natural gas and 20% hydrogen.
• Pure hydrogen.

An established method was used to calculate the gas outflow rate from leaks into buildings downstream of the meter regulator. These gas leak rates were compared with the gas use by typical domestic appliances and these leaks were considered in the context of the smart gas meter data that is currently available in 30-minute periods. A representative set of gas accumulation calculations was performed. It was found that the following three general cases apply to all three gases:

• Small holes of up to 1 mm rarely reach flammable gas/air concentrations for any gas except under the most unfavourable conditions such as small volumes combined with low ventilation rates. These releases would likely be detected within 6 to 12 hours.
• Medium holes between 1 mm and 6 mm give outflow rates equivalent to a moderate to high level of gas use by appliances. The ability to detect these leaks is highly dependent on the hole size the time at which the leak begins and the normal gas use profile in the building. The larger leaks in this category would be detected within 30 to 60 minutes while the smaller leaks could take several hours to be clearly differentiated from appliance use. This is quick enough to prevent some explosions.
• Large holes of over 6 mm give leak rates greater than any gas use by appliances. These releases rapidly reach a flammable gas/air mixture in most cases but would typically be detected within the first 30-minute meter output period. Again some explosions could be prevented in this timescale.

An event tree has been used to quantify the approximate success rate of detecting and preventing explosion events. Using the currently available 30-minute smart meter data and functionality it is estimated that around 7% of explosions could be prevented with a slight variation depending on the gas type in use. Additional functionality could be included in the meter to improve this performance. Typically one of the risk mitigation measures in isolation increases the explosion prevention rate to around 15%. If multiple improvements are made then the detection rate is predicted to increase to around 30%.

An examination of detailed historical incident information suggests that the explosions that lead to fatalities or significant damage to houses are typically of the type that would be more likely to be detected and prevented. It is estimated that between 25% and 75% of the more severe explosions could be prevented depending on which potential improvements are implemented.

Based on the conservative estimates of explosion prevention a cost benefit analysis suggests that it is justifiable to spend between around £1 and £10 per meter installed to implement the proposed technology. This is based purely on lives saved and does not take account of other benefits.

As global efforts intensify to transition toward cleaner and more sustainable energy sources the blending of hydrogen with natural gas emerges as a promising strategy to reduce carbon emissions and enhance energy security. This study employs a systematic approach to assess the economic viability of hydrogen blending considering factors such as gas costs and heat values. Various hydrogen blending scenarios are analyzed to determine the optimal blend ratios taking into account both technical feasibility and economic considerations. The study discusses potential economic benefits challenges and regulatory implications associated with the widespread adoption of hydrogen–natural gas mixtures. Furthermore the study explores the impact of this integration on existing natural gas infrastructure exploring the potential for enhanced energy storage and delivery. The findings of this research contribute valuable insights to policymakers industry stakeholders and researchers engaged in the ongoing energy transition by providing a nuanced understanding of the economic dimensions of hydrogen blending within the natural gas sector.

The increase in demand and thus the need to lower its price has kept C-based fuels as the main source. In this context the use of oil and gas has led to increased climate change resulting in greenhouse gases. The high percentage of emissions over 40% is due to the production of electricity heat or/and energy transport. This is the main reason for global warming and the extreme and increasingly common climate change occurrences with all of nature being affected. Due to this reason in more and more countries there is an increased interest in renewable energies from sustainable sources with a particular emphasis on decarbonisation. One of the energies analysed for decarbonisation that will play a role in future energy systems is hydrogen. The development of hydrogen–natural gas mixtures is a major challenge in the field of energy and fuel technology. This article aims to highlight the major challenges associated with researching hydrogen–natural gas blends. Meeting this challenge requires a comprehensive research and development effort including exploring appropriate blending techniques optimising performance addressing infrastructure requirements and considering regulatory considerations. Overcoming this challenge will enable the full potential of hydrogen–natural gas blends to be realised as a clean and sustainable energy source. This will contribute to the global transition to a greener and more sustainable future. Several international European and Romanian studies projects and legislative problems are being analysed. The mix between H2 and natural gas decreases fugitive emissions. In contrast using hydrogen increases the risk of fire more than using natural gas because hydrogen is a light gas that easily escapes and ignites at almost any concentration in the air.

The forthcoming implementation of national policies towards hydrogen blending into the natural gas grid will affect the technical and economic parameters that must be taken into account in the design of building heating systems. This study evaluates the implications of using hydrogenenriched natural gas (H2NG) blends in condensing boilers and Gas Adsorption Heat Pumps (GAHPs) in a residential building in Rome Italy. The analysis considers several parameters including nonrenewable primary energy consumption CO2 emissions Levelized Cost of Heat (LCOH) and Carbon Abatement Cost (CAC). The results show that a 30% hydrogen blend achieves a primary energy consumption reduction of 12.05% and 11.19% in boilers and GAHPs respectively. The presence of hydrogen in the mixture exerts a more pronounced influence on the reduction in fossil primary energy and CO2 emissions in condensing boilers as it enhances combustion efficiency. The GAHP system turns out to be more cost-effective due to its higher efficiency. At current hydrogen costs the LCOH of both technologies increases as the volume fraction of hydrogen increases. The forthcoming cost reduction in hydrogen will reduce the LCOH and the decarbonization cost for both technologies. At low hydrogen prices the CAC for boilers is lower than for GAHPs; therefore replacing boilers with other gas technologies rather than electric heat pumps increases the risk of creating stranded assets. In conclusion blending hydrogen into the gas grid can be a useful policy to reduce emissions from the overall natural gas consumption during the process of end-use electrification while stimulating the development of a hydrogen economy.