Hydrogen-Enhanced Combustion of Hydrocarbons

Abstract

Strong policy momentum is supporting the adoption of hydrogen as a major energy carrier for a decarbonised global economy, especially for reducing emissions in hard-to-abate industrial sectors. Although achieving large-scale hydrogen deployment will require substantial long-term investment in dedicated infrastructure, blending hydrogen with conventional hydrocarbon fuels provides a practical near-term pathway to accelerate uptake by leveraging existing systems and fuel-supply networks. To inform future research and development in this field, this review summarises experimental and numerical findings on the combustion behaviour of hydrogen–hydrocarbon mixtures and highlights the main challenges and research gaps that must be addressed to ensure the safe and efficient use of hydrogen-enriched fuels in current combustion systems. It also examines the fundamental combustion characteristics of hydrogen and hydrogen-enriched fuels, the effects of hydrogen addition to gaseous, liquid, and solid fuels on combustion performance and emissions, and the contrasting policy approaches shaping hydrogen uptake across major global economies.

1. Introduction

In its The Future of Hydrogen report, the International Energy Agency (IEA) [1] notes that “hydrogen is currently enjoying unprecedented political and business momentum” as a means for decarbonising the global economy. Notably, it provides a pathway for storing renewable energy in a chemical form that can then be converted to electricity or thermal energy via fuel cells or carbon-free (or low-carbon) combustion. However, the same report also emphasises that hydrogen still faces critical challenges related to its cost-effectiveness as an energy carrier, the lack of dedicated infrastructure, various regulatory barriers and the fact that it is still almost entirely produced from fossil fuels through processes such as steam methane reforming [1]. (More precisely, of the total 97 Mt of hydrogen produced in 2023, less than 1% was via low-emission processes, such as electrolysis [2]. Nevertheless, the global installed capacity of electrolysers has increased almost nine-fold between 2021 and 2024, and—on the basis of announced projects—IEA also estimates that low-emission hydrogen production could reach 49 Mt per year by 2030 [2].)

The IEA identifies four near-term opportunities to accelerate hydrogen deployment as an energy carrier, one of which is leveraging existing infrastructure, particularly through the use of existing natural-gas (NG) networks [1]. Hence, blending hydrogen with conventional hydrocarbon fuels used in combustion-based energy-conversion system provides a practical near-term pathway to boost demand and achieve economies of scale. This has, in turn, stimulated a growing body of review articles examining various aspects of hydrogen use in combustion systems, usually focusing on specific technologies or application sectors.

For instance, Leicher et al. [3] and Sîrbu et al. [4] concentrated on hydrogen-enriched NG combustion in residential and commercial appliances, Ghazal et al. [5] reviewed hydrogen-enriched gaseous fuels in combustors and gas turbines, Honu et al. [6] focused on hydrogen utilization in industrial boilers, Peng et al. [7] analyzed numerical modelling approaches for hydrogen combustion, and Yu et al. [8] reviewed hydrogen-based CHP systems. Other studies [9,10,11,12,13] have addressed hydrogen production pathways, storage technologies, e-fuels, transportation infrastructure, and broader hydrogen economy concepts rather than combustion technologies and thermal energy applications.

Despite these contributions, several knowledge gaps remain. Existing reviews rarely provide an integrated assessment of hydrogen combustion fundamentals, hydrogen-enriched hydrocarbon combustion, residential and industrial thermal applications, hydrogen-assisted combustion of gaseous, liquid, and solid fuels, emissions formation mechanisms, combustion stability, safety considerations, and deployment challenges within a single framework. Therefore, the interactions between fuel type, combustion behaviour, emissions performance, and application-specific requirements remain fragmented across the literature. To address these gaps, the present review provides a comprehensive assessment of hydrogen-assisted combustion technologies in thermal energy systems across multiple fuel types and application sectors.

Table 1. Comparison of representative reviews on hydrogen combustion, hydrogen-enriched NG, and related applications.

Study	Main Focus	Combustion Fundamentals	Hydrogen-Enriched NG	HVAC Applications	Industrial Applications	Policy	Main Limitation
Leicher et al. (2022) [3]	Hydrogen admixture in residential and commercial gas appliances	Yes	Yes	Yes	No	No	Focused on end-use gas appliances
Ghazal et al. (2024) [5]	Hydrogen enrichment of gaseous fuels in combustors and gas turbines	Yes	Yes	No	Yes	No	Limited to gaseous fuels and combustors
Honu et al. (2024) [6]	Hydrogen utilization in industrial boilers	No	Yes	No	Yes	No	Focuses primarily on materials and degradation issues
Sîrbu et al. (2026) [4]	Hydrogen-enriched NG combustion in residential appliances	Yes	Yes	Yes	No	No	Limited to residential applications
Peng et al. (2026) [7]	CFD modelling of hydrogen and hydrogen-blended combustion	Yes	Yes	Partial	Partial	No	Numerical modelling focus
Yu et al. (2023) [8]	Hydrogen-based CHP systems	Partial	Partial	Partial	Yes	No	CHP systems rather than combustion technologies
Giacomazzi et al. (2023) [14]	Hydrogen combustion fundamentals and heavy-duty applications	Yes	Yes	No	Yes	No	Limited to power-generation and industrial systems
Present Review	Hydrogen-enriched combustion technologies across thermal systems	Yes	Yes	Yes	Yes	Yes

summarizes the scope of representative review articles and highlights the contribution of the present review relative to previous work. Whereas previous reviews typically focus on individual application sectors, specific fuel categories, or particular methodological approaches, the present review integrates combustion fundamentals with practical thermal energy applications and compares hydrogen-assisted combustion across gaseous, liquid, and solid fuels. By combining residential, commercial, and industrial perspectives within a single framework, the review provides a broader understanding of the opportunities, limitations, and future research directions associated with hydrogen-based combustion technologies.

The main contributions of this review are threefold: (i) to summarize the fundamental combustion characteristics of hydrogen and hydrogen-enriched fuels; (ii) to compare the effects of hydrogen addition to gaseous, liquid, and solid fuels on combustion performance and emissions; and (iii) to assess the opportunities, challenges, and future research needs associated with residential and industrial thermal energy applications. In addition, the review incorporates an assessment of the policies and strategies adopted by major global actors, with particular attention to the European Union, United States, and China, thereby linking technological developments with the policy momentum shaping hydrogen’s role in future energy systems.

First, the key property differences between hydrogen and hydrocarbon fuels—and their implications for the combustion processes—are examined. The focus is on how these differences influence flame characteristics and combustion products, although other relevant effects are also considered. This is followed by a discussion of the policy frameworks and strategic initiatives adopted by leading global economies, with emphasis on the EU, to promote green hydrogen deployment. The review then examines studies on the combustion behaviour of hydrogen-hydrocarbon mixtures (covering gaseous, liquid, and solid hydrocarbon fuels) and the required design and operational modifications for combustion equipment in both industrial and building-sector applications. In this context, the main research gaps identified in the literature are analysed.

2. Fundamental Property Differences Between Hydrogen and Hydrocarbon Fuels

To provide a clearer basis for the subsequent discussion, Table 2 summarises representative properties of hydrogen, methane/NG and propane. Methane is used as the main natural-gas reference fuel, while propane represents a higher gaseous alkane relevant to LPG-type and enriched natural-gas compositions [15,16].

Table 2. Representative properties of hydrogen, methane/NG and propane. Values are indicative for near-ambient initial conditions unless otherwise stated.

Property	Hydrogen	Methane/NG	Propane	Main Combustion Implication
Molecular weight, g ${\mathrm{mol}}^{-1}$	2.016	16.04	44.10	Density, diffusion, leakage and fuel delivery.
Density, ${\mathrm{kg·Nm}}^{-3}$	≈0.09	≈0.72	≈1.97	Storage volume, buoyancy and leakage behaviour.
Lower heating value, ${\mathrm{MJ kg}}^{-1}$	≈120	≈50	≈46.4	Mass-based energy content.
Volumetric heating value, ${\mathrm{MJ Nm}}^{-3}$	≈10.8	≈35.8	≈93	Volumetric fuel flow and fuel-system sizing.
Stoichiometric air requirement, ${\mathrm{Nm}}^3$ air per ${\mathrm{Nm}}^3$ fuel	≈2.38	≈9.52	≈23.8	Air–fuel ratio and burner air supply.
Stoichiometric fuel concentration in air, vol.%	≈29.6	≈9.5	≈4.0	Reference point for lean/rich operation.
Flammability limits in air, vol.%	4–75	5–15	2.1–9.6	Operating range and safety margin.
Minimum ignition energy, mJ	≈0.017	≈0.28	≈0.25	Ignition reliability and unintended ignition risk.
Autoignition temperature, °C	≈585	≈540	≈470	Hot-surface ignition and autoignition safety.
Adiabatic flame temperature in air, °C	≈2045	≈1950	≈1980	Thermal ${\mathrm{NO}}_x$ tendency and heat-release intensity.
Laminar burning velocity/flame speed, ${\mathrm{cm·s}}^{-1}$	≈200–300	≈35–40	≈40–45	Flashback, flame compactness and instability.
Diffusion coefficient in air, ${\mathrm{cm}}^2·{\mathrm{s}}^{-1}$	≈0.6	≈0.16	≈0.10	Mixing, leakage and preferential diffusion.
Quenching distance/gap, mm	≈0.6	≈2.0	≈1.8–2.0	Flame arresting and flashback resistance.
Main complete-combustion products	H2O	CO2 + H2O	CO2 + H2O	Direct carbon emissions at point of use.

Note: The values are representative and should be interpreted as indicative ranges rather than universal constants. Several parameters, especially adiabatic flame temperature, laminar burning velocity, diffusivity and quenching distance, depend on temperature, pressure, equivalence ratio, dilution, fuel composition and measurement method. Methane is used as the main natural-gas reference fuel, while propane represents a higher gaseous alkane relevant to LPG-type and enriched natural-gas compositions [13, 15, 16, 17, 18].

Table 2. Representative properties of hydrogen, methane/NG and propane. Values are indicative for near-ambient initial conditions unless otherwise stated.

Property	Hydrogen	Methane/NG	Propane	Main Combustion Implication
Molecular weight, g ${\mathrm{mol}}^{-1}$	2.016	16.04	44.10	Density, diffusion, leakage and fuel delivery.
Density, ${\mathrm{kg·Nm}}^{-3}$	≈0.09	≈0.72	≈1.97	Storage volume, buoyancy and leakage behaviour.
Lower heating value, ${\mathrm{MJ kg}}^{-1}$	≈120	≈50	≈46.4	Mass-based energy content.
Volumetric heating value, ${\mathrm{MJ Nm}}^{-3}$	≈10.8	≈35.8	≈93	Volumetric fuel flow and fuel-system sizing.
Stoichiometric air requirement, ${\mathrm{Nm}}^3$ air per ${\mathrm{Nm}}^3$ fuel	≈2.38	≈9.52	≈23.8	Air–fuel ratio and burner air supply.
Stoichiometric fuel concentration in air, vol.%	≈29.6	≈9.5	≈4.0	Reference point for lean/rich operation.
Flammability limits in air, vol.%	4–75	5–15	2.1–9.6	Operating range and safety margin.
Minimum ignition energy, mJ	≈0.017	≈0.28	≈0.25	Ignition reliability and unintended ignition risk.
Autoignition temperature, °C	≈585	≈540	≈470	Hot-surface ignition and autoignition safety.
Adiabatic flame temperature in air, °C	≈2045	≈1950	≈1980	Thermal ${\mathrm{NO}}_x$ tendency and heat-release intensity.
Laminar burning velocity/flame speed, ${\mathrm{cm·s}}^{-1}$	≈200–300	≈35–40	≈40–45	Flashback, flame compactness and instability.
Diffusion coefficient in air, ${\mathrm{cm}}^2·{\mathrm{s}}^{-1}$	≈0.6	≈0.16	≈0.10	Mixing, leakage and preferential diffusion.
Quenching distance/gap, mm	≈0.6	≈2.0	≈1.8–2.0	Flame arresting and flashback resistance.
Main complete-combustion products	H2O	CO2 + H2O	CO2 + H2O	Direct carbon emissions at point of use.

Note: The values are representative and should be interpreted as indicative ranges rather than universal constants. Several parameters, especially adiabatic flame temperature, laminar burning velocity, diffusivity and quenching distance, depend on temperature, pressure, equivalence ratio, dilution, fuel composition and measurement method. Methane is used as the main natural-gas reference fuel, while propane represents a higher gaseous alkane relevant to LPG-type and enriched natural-gas compositions [13, 15, 16, 17, 18].

The comparison shows that hydrogen differs from methane and propane in two particularly important ways. On a mass basis, hydrogen has a very high heating value, whereas on a volumetric basis its energy density is much lower because of its low density [13]. Consequently, substantially larger volumetric flow rates of fuel are required for hydrogen-fired equipment to deliver an energy input comparable with that of natural-gas systems. This volumetric-density limitation also manifests at the component level: for instance, fuel-injection nozzle diameters must be increased to admit sufficient amounts of hydrogen into the combustion chamber to achieve the same energy input [19].

Furthermore, the small molecular size and high diffusivity of hydrogen make containment more demanding and are also related to material-compatibility problems. One important example is hydrogen embrittlement, which occurs when hydrogen atoms diffuse into the crystal lattice of solid materials, reducing ductility and fracture toughness and potentially leading to material failure over time [13]. The same molecular properties also increase the relevance of hydrogen leakage during production, storage, transport and end use. Leaked hydrogen has an indirect greenhouse effect over near- and medium-term horizons because it affects the atmospheric lifetime of methane, tropospheric ozone and stratospheric water vapour [20,21].

2.1. Flame Properties

From a flame-dynamics perspective, the most important differences are the wider flammability range, lower ignition energy, higher diffusivity and higher laminar flame speed of hydrogen. These characteristics can extend lean operating limits and improve ignition, but they also increase the sensitivity of premixed systems to flashback, autoignition and combustion instability [15,16]. Therefore, the fuel properties listed in Table 2 are directly linked to the operational issues discussed in the following subsections. In addition, due to the different chemical composition, hydrogen flames are far less luminous than hydrocarbon flames, and a larger fraction of heat transfer occurs via convection rather than thermal radiation [14,22]. As a result of these differences, in combustion chambers hydrogen-rich flames are shorter, more compact, and more reactive than, for instance, methane flames; this affects residence time, flame stabilisation, and the interaction between heat transfer and the flow field [23,24].

Notably, hydrogen has a laminar flame speed approximately an order of magnitude higher than that of methane [18]. Even partial substitution—i.e., introducing hydrogen into a methane-dominated mixture—substantially increases burning velocity: mixtures containing up to 50% hydrogen can reach twice the laminar flame speed of pure methane [22], trigger earlier onset of laminar-flame instabilities, and reduce Markstein lengths [25]. Hydrogen flames also require much higher jet velocities to detach from the nozzle [26], and their higher turbulent flame speeds produce more compact reaction zones that shift upstream toward the burner outlet [27]. The elevated flame speeds increase the risk of flashback, which occurs when the local turbulent flame speed exceeds the flow velocity, allowing the flame to propagate upstream into the premixing or fuel-supply passages and potentially damage the combustion equipment [18,28].

Mechanistically, this behaviour is not only an empirical fuel-property difference, but a consequence of hydrogen’s intrinsic chemical kinetics and transport behaviour. Hydrogen oxidation is governed by fast radical chain-branching and chain-propagation reactions involving H, O and OH radicals, while the high mass diffusivity of ${\mathrm{H}}_2$ promotes preferential diffusion toward the reaction zone [27,29]. As a result, hydrogen flames are generally thinner, more compact and more reactive than methane- or propane-air flames. When hydrogen is blended into hydrocarbon fuels, the characteristic chemical time decreases and the flame can stabilise closer to the burner exit or even shift upstream [15,27]. This reduces the convective time delay between mixture perturbation and heat release, which is a key parameter for both flashback and thermoacoustic response [27].

Flashback occurs when the local flame propagation speed exceeds the local flow velocity in the burner or premixing passages. Hydrogen addition increases this risk because it increases the laminar and turbulent burning velocities, lowers the ignition energy and broadens the flammable range [18,29]. In premixed systems, flashback may occur through several coupled mechanisms, including core-flow propagation, boundary-layer flashback, combustion-induced vortex breakdown and instability-driven flashback [27]. Therefore, simply increasing the flow velocity is not always a sufficient solution, because it can increase pressure losses, reduce efficiency and move the system closer to blowoff. Mitigation requires combined control of mixture residence time, local equivalence ratio, velocity gradients, burner-wall cooling, flame anchoring position and the residence time of the premixed reactants [18,29].

The influence of hydrogen on blowoff is more nuanced. On the one hand, hydrogen can extend the lean blowout limit because its high reactivity, high diffusivity and high flame speed support stable combustion at lower equivalence ratios [18,27]. On the other hand, if the flow velocity is increased excessively to avoid flashback, the flame may be displaced downstream, weakened by excessive strain, or extinguished. Thus, hydrogen addition can simultaneously enlarge the lean operating window and narrow the safe design margin between flashback and blowoff. The final behaviour depends on burner geometry, swirl strength, residence time, local mixing quality, pressure, dilution level and the interaction between flow field and flame structure [16,18].

Hydrogen addition also modifies thermoacoustic instability because it changes the coupling between unsteady heat release and acoustic pressure oscillations. In lean premixed combustors, self-excited instabilities arise when heat-release fluctuations occur sufficiently in phase with pressure oscillations and the acoustic energy supplied by the flame exceeds acoustic damping [27]. Hydrogen-enriched flames are shorter and more compact, and their stabilisation position can move upstream, modifying the convective time delay, the flame transfer response and the phase relation between pressure and heat release [15,27]. Depending on burner design and operating point, hydrogen can therefore either suppress an existing instability or trigger a new one, shift instability regions toward lower equivalence ratios, promote mode switching and excite higher-frequency oscillations. Elevated pressure can further intensify flame-front wrinkling and reduce the hydrogen fraction required for instability onset [16,27].

2.2. Combustion Products and Emissions

Apart from trace contaminants that may remain in the hydrogen gas after its production and purification, the only notable emissions from the complete combustion of hydrogen are water vapour and ${\mathrm{NO}}_x$ [18]. The large quantities of water in the flue gases can increase the heat transfer coefficient between the hot gas and the surfaces exposed to it, while also creating a more corrosive environment for the solid materials [28].

Nevertheless, the most significant flue-gas-related problem associated with hydrogen combustion is usually ${\mathrm{NO}}_x$ formation. ${\mathrm{NO}}_x$ formation in hydrogen and hydrocarbon flames cannot be attributed to a single pathway, since combustion systems may involve fuel ${\mathrm{NO}}_x$, prompt ${\mathrm{NO}}_x$ and thermal ${\mathrm{NO}}_x$ depending on fuel composition, local equivalence ratio, temperature, oxygen availability and residence time [18]. Fuel ${\mathrm{NO}}_x$ originates from nitrogen chemically bound in the fuel and is therefore negligible for methane and propane under normal fuel-quality conditions, and non-existent for pure hydrogen. Prompt ${\mathrm{NO}}_x$ is formed in the early reaction zone, especially under locally fuel-rich conditions, through fast radical reactions involving hydrocarbon fragments. In pure hydrogen flames, hydrocarbon-radical prompt chemistry is absent, although NNH-related pathways may contribute to NO formation under some conditions [18].

Unlike prompt and fuel ${\mathrm{NO}}_x$ emissions, thermal ${\mathrm{NO}}_x$ emissions are strongly dependent on combustion temperature: they are practically not formed below 750 °C, but above 1500 °C become significant and increase exponentially with temperature. Hence, at the high temperatures typical of hydrogen and hydrogen-enriched flames, thermal ${\mathrm{NO}}_x$ is usually the dominant concern. It is strongly controlled by the peak flame temperature, oxygen availability and residence time in high-temperature zones, and is mainly described by the extended Zeldovich mechanism [18,30]:

$${\mathrm{N}}_2+\mathrm{O}\rightleftharpoons \mathrm{NO}+\mathrm{N},$$

$$\mathrm{N}+{\mathrm{O}}_2\rightleftharpoons \mathrm{NO}+\mathrm{O},$$

$$\mathrm{N}+\mathrm{OH}\rightleftharpoons \mathrm{NO}+\mathrm{H}.$$

Because hydrogen combustion can produce high local flame temperatures, short and compact reaction zones, and highly reactive radical pools, hydrogen and hydrogen-enriched flames may intensify thermal ${\mathrm{NO}}_x$ formation unless the combustion system is designed to limit temperature peaks and residence time [27,29]. Practical mitigation approaches therefore include lean premixed combustion, staged combustion, exhaust-gas or flue-gas recirculation, steam or water dilution, nitrogen dilution, micromix combustion concepts and, when required, post-combustion treatment such as selective catalytic reduction. Experimental studies also show that burner design measures promoting internal exhaust-gas recirculation can substantially reduce ${\mathrm{NO}}_x$ emissions during hydrogen combustion [18,31].

As the adiabatic flame temperature of hydrogen is roughly 300 K higher than that of methane, thermal ${\mathrm{NO}}_x$ emissions can increase drastically when hydrogen is substituted for NG, unless additional measures are undertaken. The combustion temperature can be managed by a number of mechanisms, most notably through changing the fuel-to-air ratio (the equivalence ratio) or by cooling the flame through the addition of other gases. An example of the latter is the exhaust gas recirculation technology, which is employed in internal combustion engines to reduce the flame temperature by feeding exhaust gases back into the cylinders [32].

The negative effects can also be mitigated through appropriate burner design and operation [31]. In particular, changing the diameter and number of air nozzles enhances the internal recirculation of the flue gases, lowers the flame temperature, and substantially reduces ${\mathrm{NO}}_x$ emissions. This conclusion is particularly important in the context of modernisation of existing combustion systems, as it shows that ${\mathrm{low-NO}}_x$ hydrogen combustion can be sought not only through entirely new combustion chamber concepts, but also through targeted adaptation of combustion systems already in use [31,33], as discussed in the following sections.

The environmental assessment of burners, boilers, furnaces, reciprocating engines and gas turbines operating with hydrogen should not be limited to accounting for carbon emissions at the place of use; it should also consider the other emissions from the combustion processes, the operational limitations of the combustion system itself, as well as the indirect effects and emissions along the whole supply chain [20,21,33,34,35,36,37]. When produced through electrolysis with renewable or nuclear energy, hydrogen can have a low greenhouse-gas footprint over its life cycle; however, the still dominant production from fossil fuels (e.g., via steam-methane reforming) remains very carbon-intensive, especially in the absence of effective carbon capture [38]. Even renewables-based electrolytic production of hydrogen can impose considerable environmental burdens due to geographic supply-demand imbalances and the predominance of hydrogen-production potential within water-stressed regions [39].

2.3. Implications for Numerical Studies

Computational fluid dynamics (CFD) has become an essential tool for analysing hydrogen-enriched combustion processes due to its ability to resolve complex interactions between fluid flow, chemical kinetics, and heat transfer. Modern CFD approaches allow detailed investigation of combustion characteristics, including flame structure, temperature distribution, and pollutant formation, across a wide range of operating conditions [40,41]. Despite its widespread use, conventional CFD modelling faces several challenges, particularly when applied to hydrogen combustion problems. The high reactivity and fast chemical kinetics of hydrogen require detailed reaction mechanisms and an accurate representation of turbulence–chemistry interactions, which significantly increase computational cost [40]. As a result, simplified models are often employed; however, these may introduce uncertainties in predicting ignition behaviour, flame propagation, and emissions.

Recent developments focus on improving model accuracy and efficiency through hybrid approaches that combine CFD with machine learning techniques. These methods can markedly reduce computational time while maintaining acceptable predictive capability, enabling more extensive parametric studies and real-time optimisation [40]. At the same time, advances in turbulence modelling, radiation modelling, and chemical kinetics continue to enhance the reliability of CFD simulations for hydrogen combustion applications [41].

Studies show that hydrogen enrichment strongly affects mixing processes, flame stabilisation, and heat release rates, requiring careful calibration and validation of numerical models against experimental data [42,43]. In particular, accurate prediction of ${\mathrm{NO}}_x$ emissions remains a key challenge due to the sensitivity of thermal ${\mathrm{NO}}_x$ formation to local temperature and residence time. In practical combustion systems, numerical simulations highlight the importance of boundary conditions, fuel injection strategies, and reactor geometry in determining overall performance. Variations in injection location, air–fuel ratio, and flow distribution can substantially alter temperature fields and emission characteristics, especially in systems with high hydrogen content [44,45].

Although significant progress has been made with respect to CFD modelling of laboratory-scale and industrial systems involving hydrogen combustion, including swirling flames, internal combustion engines, and furnace applications, several limitations remain. These include difficulties in modelling high-pressure combustion, multi-phase interactions, and detailed pollutant formation mechanisms, particularly in complex fuel mixtures [5,46]. Therefore, continued development of advanced CFD methodologies, supported by experimental validation, is essential for improving predictive capabilities and enabling the reliable design of hydrogen-based combustion systems.

3. Green Hydrogen and European Frameworks and Strategies

“Green” hydrogen is emerging as a key energy carrier in the global transition to a low-carbon economy, particularly in the context of decarbonizing hard-to-abate industrial sectors [47]. Unlike conventional hydrogen, produced through steam reforming of NG, green hydrogen is generated through the electrolysis of water using renewable energy, resulting in minimal greenhouse gas emissions [2].

Within the European Union, the development of the so called “hydrogen economy” is closely linked to the goal of climate neutrality by 2050, as set out in the European Green Deal [48]. In this context, hydrogen is not considered as a universal solution, but rather as a strategic tool for decarbonizing specific industrial processes where direct electrification is technologically or economically inefficient [49]. Despite the ambitious goals and significant investments, the development of green hydrogen is accompanied by a number of challenges, including high costs, regulatory complexity, and demand uncertainty [2]. One of the aims herein is to analyse the European regulatory framework, industrial practices, and technological aspects of hydrogen, while offering a critical comparative analysis with the approaches of the United States and China.

3.1. EU Policy, Strategic and Regulatory Framework

The European Union’s hydrogen policy is being developed within the broader strategy for energy transition and decarbonization [48]. A foundational document is the 2020 European Hydrogen Strategy, which lays the groundwork for the development of the market, infrastructure, and technologies [50]. Additionally, the REPowerEU initiative reinforces the role of hydrogen as a means of reducing dependence on fossil fuel imports, particularly in the context of geopolitical risks [48]. This strategy sets a specific target for the production and import of a total of 20 million tons of renewable hydrogen by 2030, representing a significant increase from current levels. In parallel, the EU is integrating hydrogen into legislative initiatives such as the “Fit for 55” package, which aims to reduce emissions by at least 55% by 2030 [51]. This multi-layered policy approach reflects the EU’s ambition to combine climate goals with industrial development, but at the same time leads to a high degree of regulatory complexity.

One of the key elements of European hydrogen policy is Directive (EU) 2023/2413 (RED III), which introduces mandatory targets for the use of renewable hydrogen in industry [47]. According to the directive, at least 42% of the hydrogen used in industry by 2030 must be renewable, with this share increasing to 60% by 2035. A key part of the regulatory framework consists of delegated acts that define the criteria for so-called RFNBO (renewable fuels of non-biological origin). These criteria include requirements for additionality, temporal correlation, and geographical connectivity between hydrogen production and renewable energy [47]. While these requirements ensure environmental sustainability, they significantly increase project costs and complexity [52]. The Hydrogen and Decarbonised Gas Market Package [53] complements the regulatory framework by establishing market mechanisms for trading, infrastructure access, and the development of competition. However, the lack of a fully integrated market remains a key challenge.

Although the European Union promotes a common hydrogen strategy, significant differences exist among member states regarding resources, industrial structures, and policy priorities. Germany has emerged as one of the leading hydrogen economies in Europe due to its large industrial base, particularly in steel, chemicals, and manufacturing. The German National Hydrogen Strategy emphasizes both domestic production and large-scale imports from partner countries. Spain and Portugal benefit from abundant solar resources, enabling relatively low-cost renewable electricity generation. These countries increasingly position themselves as future exporters of renewable hydrogen to northern European markets.

The Netherlands focuses on developing hydrogen infrastructure around major industrial clusters and ports, particularly Rotterdam, where hydrogen imports and distribution are expected to play a central role. France places greater emphasis on low-carbon hydrogen production linked to its nuclear electricity system. While EU policy primarily prioritizes renewable hydrogen, France argues that nuclear-powered electrolysis can also contribute significantly to decarbonization objectives. Central and Eastern European countries generally face additional challenges related to financing, infrastructure development, and industrial transformation. Consequently, hydrogen deployment across the EU is likely to remain heterogeneous during the coming decades.

3.2. Comparative Perspective on EU, U.S. and Chinese Hydrogen Policies

The development of the hydrogen economy is increasingly shaped by different policy approaches adopted by the European Union, the United States, and China. Although all three jurisdictions recognize hydrogen as a strategic component of future low-carbon energy systems, they differ substantially in regulatory philosophy, industrial policy instruments, and deployment strategies.

The European Union has adopted a regulatory and sustainability-oriented approach. The European Hydrogen Strategy, REPowerEU, RED III, and the Hydrogen and Decarbonised Gas Market Package collectively establish a comprehensive framework governing hydrogen production, certification, infrastructure development, and market integration. One of the major strengths of the EU model is the creation of clear sustainability criteria for renewable hydrogen through the Renewable Fuels of Non-Biological Origin (RFNBO) framework. Such criteria enhance environmental credibility, improve investor confidence in the long term, and support the development of a harmonized internal hydrogen market. At the same time, practical challenges have emerged. The requirements concerning additionality, temporal correlation, and geographical matching between renewable electricity generation and hydrogen production increase administrative complexity and project costs. Industry stakeholders have argued that compliance with these requirements may slow project implementation during the early stages of market development. Consequently, while the European framework provides regulatory certainty and strong environmental safeguards, it may create barriers to rapid deployment when compared with more flexible international approaches.

The United States has adopted a predominantly market-driven strategy centred on economic incentives. The Inflation Reduction Act (IRA) introduced production tax credits of up to USD 3 per kilogram of clean hydrogen, significantly reducing production costs and improving project economics. Rather than prescribing detailed sustainability requirements at the outset, the U.S. framework prioritizes rapid market creation and industrial scaling. This policy has stimulated numerous large-scale hydrogen projects across several states, particularly in regions with abundant renewable resources. An important element of the U.S. approach is the Regional Clean Hydrogen Hubs Program, funded through the Bipartisan Infrastructure Law. These demonstration hubs integrate hydrogen production, transportation, storage, and end-use applications across industrial clusters. Projects such as the Gulf Coast Hydrogen Hub and the Mid-Atlantic Clean Hydrogen Hub seek to demonstrate the commercial viability of hydrogen in refining, chemicals, power generation, and heavy transportation. The emphasis on demonstration projects allows technological learning and cost reductions through practical deployment. However, critics have noted that the U.S. approach may initially allow hydrogen production pathways with higher lifecycle emissions than those permitted under EU regulations.

China follows a third model based on state-industry coordination and long-term industrial planning. Hydrogen development has been incorporated into national industrial strategies and five-year plans. Chinese policy focuses on scaling domestic manufacturing capacity, reducing technology costs, and establishing leadership in key supply chains, particularly electrolysers and fuel-cell technologies. State-owned enterprises play a central role in project implementation, supported by provincial governments and public financing mechanisms. Several large-scale demonstration projects have been launched in industrial regions such as Inner Mongolia, Hebei, and Guangdong. These projects integrate renewable electricity generation with hydrogen production and industrial consumption. China has also become the world’s largest market for fuel-cell buses and heavy-duty vehicles, supported by dedicated subsidy schemes. The Chinese model demonstrates strong capability for rapid industrial deployment and cost reduction through economies of scale. Nevertheless, concerns remain regarding transparency, regional disparities, and the continued use of fossil-based hydrogen in some sectors.

These contrasting approaches are summarized in

Table 3. Comparison of hydrogen policies across the European Union, United States, and China.

Aspect	European Union	United States	China
Policy approach	Regulatory and sustainability-oriented	Market-driven	State–industry coordination
Main policy instrument	RED III, REPowerEU, Hydrogen Strategy	Inflation Reduction Act, Hydrogen Hubs	Five-Year Plans, industrial policy
Main strength	Regulatory certainty and sustainability	Strong economic incentives	Rapid industrial scaling
Main limitation	Higher compliance costs and complexity	Sustainability criteria still evolving	Transparency and market distortions
Demonstration projects	Industrial clusters and Hydrogen Valleys	Regional Clean Hydrogen Hubs	Large-scale provincial projects
Competitiveness impact	High environmental credibility	Lower production costs	Manufacturing and scale advantages

and illustrate different policy priorities. The EU emphasizes sustainability and regulatory harmonization; the United States prioritizes market creation through financial incentives; and China focuses on industrial scaling and strategic manufacturing leadership. Rather than representing mutually exclusive models, these approaches demonstrate alternative pathways toward hydrogen market development.

3.3. Industrial and Technological Aspects of the Green Hydrogen

Green hydrogen is primarily used in high-carbon-intensity industries, such as steel production, the chemical industry, and refineries [54]. In steel production, for example, hydrogen can replace coke as a reducing agent in the direct iron reduction process, leading to a significant reduction in the emissions [55]. In the chemical industry, hydrogen is a key component in the production of ammonia and methanol, and replacing grey with green hydrogen could have a substantial impact on emissions [49]. However, high production costs remain a major barrier to widespread adoption [2]. Furthermore, integrating hydrogen into industrial processes requires significant investments in new equipment and infrastructure, which further increases the financial risk for businesses [56].

Green hydrogen production relies primarily on electrolysers, which can be alkaline, proton-exchange membrane, or solid-oxide types [2]. Each technology has specific advantages and limitations related to efficiency, cost, and scalability. One of the key engineering challenges is hydrogen embrittlement, which leads to the degradation of metallic materials and poses risks to infrastructure [49]. This requires the development of new materials and safety standards. Additionally, hydrogen transport requires high pressure or liquefaction, which increases energy losses and costs [2]. In this context, the use of existing gas infrastructure by blending hydrogen with NG is viewed as a transitional solution, although one with technical limitations.

3.4. Economic and Investments Aspects of the Green Hydrogen

The cost of producing green hydrogen currently ranges between €3 and €8 per kilogram, depending on the price of electricity and the technology used [2]. These costs are expected to decrease with technological advancements and economies of scale, but uncertainty remains significant. The European Investment Bank estimates that the development of the hydrogen economy will require investments amounting to hundreds of billions of euros by 2050 [56]. However, the lack of stable demand and long-term contracts makes it difficult to finance projects [52]. This economic context underscores the need for coordinated policies that stimulate both the supply and demand for hydrogen.

The global development of the hydrogen economy is characterized by three distinct models: regulatory (EU), market-driven (U.S.), and state-industry collaboration (China) [57]. The EU emphasizes sustainability and regulation, which ensures environmental reliability but increases costs and slows down deployment [47]. The U.S., through the Inflation Reduction Act, provides significant subsidies that reduce the cost of hydrogen and stimulate rapid market development [2]. China, for its part, employs centralised planning and industrial policy, which enables rapid scaling of production and technological development [49]. These differences lead to significant variations in prices and competitiveness, with the U.S. and China holding a cost advantage.

The economic viability of green hydrogen remains one of the most important determinants of future market growth. Current estimates indicate production costs ranging from approximately €3–8/kg, depending on electricity prices, electrolyser technology, utilization rates, and regional conditions. Although substantial cost reductions are expected over the next decade, green hydrogen remains more expensive than conventional hydrogen production methods. Grey hydrogen, produced through steam methane reforming without carbon capture, generally costs between €1–2/kg under normal NG market conditions. Blue hydrogen, which incorporates carbon capture and storage technologies, typically ranges between €1.5–3/kg, depending on carbon capture efficiency and NG prices. Consequently, green hydrogen currently faces a significant cost disadvantage despite its superior environmental performance.

From an energy perspective, one kilogram of hydrogen contains approximately 33.3 kWh of lower heating value energy. At a production cost of €3–8/kg, the resulting energy cost corresponds roughly to €90–240/MWh. By comparison, wholesale NG prices in Europe have often ranged between €20–60/MWh, while industrial electricity prices vary considerably but frequently remain below the equivalent energy cost of green hydrogen. This comparison illustrates why direct electrification is generally preferred whenever technically feasible. For this reason, hydrogen is increasingly viewed as a complementary rather than universal decarbonization solution. Its primary role is expected in sectors where electrification remains technically challenging, including steel production, ammonia synthesis, chemical feedstocks, maritime transport, aviation fuels, and long-duration energy storage. In these sectors, the higher cost of hydrogen may be justified by the absence of viable low-carbon alternatives.

3.5. Discussion

As mentioned above, the European hydrogen incorporation model is characterized by a high degree of regulatory clarity and stability, but at the same time suffers from overregulation and high costs [52]. This creates a risk of falling behind other regions that offer more flexible and cost-effective conditions. Furthermore, the lack of coordination between supply and demand policies leads to uncertainty and project delays [2]. This problem is intensified by the global competition and geopolitical factors. In this context, the EU must rethink the balance between regulation and industrial policy to maintain its competitiveness.

Green hydrogen is a key element of the energy transition, but its development is accompanied by significant challenges. The EU is a leader in establishing a regulatory framework but lags behind the United States and China in industrial deployment. The future success of the hydrogen economy in the EU will depend on the ability to strike a balance between sustainability, economic efficiency, and technological development.

The comparison with the United States and China suggests that future European hydrogen policy may benefit from a balanced combination of regulatory rigor and industrial support mechanisms. The EU framework provides a strong foundation for environmental sustainability and market transparency. Nevertheless, accelerating project deployment may require additional measures that stimulate demand, reduce investment risk, and support first-of-a-kind industrial applications. The experiences of the United States demonstrate the effectiveness of substantial financial incentives and demonstration projects in creating early markets. China’s experience highlights the importance of industrial coordination, manufacturing scale, and long-term strategic planning. Integrating selected elements of these approaches while preserving the EU’s sustainability objectives could strengthen European competitiveness in the emerging global hydrogen economy.

Overall, green hydrogen remains an important component of long-term decarbonization strategies, particularly for sectors that are difficult to electrify. Its future success will depend not only on technological progress and cost reductions but also on the ability of policymakers to create stable, predictable, and economically viable market conditions.

4. Combustion Behaviour of Hydrogen-Enriched Hydrocarbon Fuels

4.1. Hydrogen Co-Combustion with Gaseous Fuels (Natural Gas)

Hydrogen enrichment of NG has been extensively investigated across a wide range of systems, including domestic boilers, industrial burners, and power plant applications. Experimental and numerical studies demonstrate that hydrogen addition in the range of approximately 5–30 vol.% can be implemented in existing combustion systems without major modifications, although higher fractions typically require redesign of burner geometry and operating conditions [9,58,59,60]. In particular, investigations on domestic-scale boilers show that stable combustion can be maintained up to 30% hydrogen content, with significant changes in flame structure and temperature distribution [58].

From a combustion physics perspective, hydrogen enrichment substantially modifies flame characteristics due to its high reactivity, low ignition energy, and fast diffusion rates. The interaction between multiple flame fronts, especially in perforated burner geometries, results in complex flame merging and localised high-intensity combustion regions, which strongly influence heat transfer and emission formation [59]. The impact of hydrogen addition on temperature fields remains strongly dependent on system configuration. Although some experimental studies report a reduction in peak combustion chamber temperature due to flame shortening and redistribution of heat release [58], other numerical investigations indicate localised temperature increases associated with intensified reaction rates and enhanced radical formation [60,61]. These differences highlight the importance of burner design, flow distribution, and mixing conditions in determining thermal behaviour.

Emission characteristics are similarly complex and often exhibit competing trends. Hydrogen addition inherently reduces carbon-based emissions such as ${\mathrm{CO}}_2$ due to fuel substitution effects; however, the behaviour of CO and ${\mathrm{NO}}_x$ emissions depends on local combustion conditions. For example, incomplete oxidation in low-temperature regions may lead to increased CO emissions, particularly when flame shortening reduces residence time [58]. At the same time, ${\mathrm{NO}}_x$ formation may increase due to elevated flame temperatures and enhanced radical pool formation, especially under near-stoichiometric conditions [60,61]. Conversely, under lean and well-mixed conditions, hydrogen enrichment can contribute to reduced ${\mathrm{NO}}_x$ emissions due to dilution effects and altered temperature profiles [59].

From an operational standpoint, hydrogen blending extends lean combustion limits, enabling more flexible operation and potentially higher efficiency. However, these benefits are accompanied by challenges related to flame control, burner durability, and emission trade-offs. Numerical and experimental studies emphasise the need for optimised combustion chamber design to accommodate changes in flame structure, temperature gradients, and pollutant formation mechanisms [62,63,64]. Overall, the existing literature suggests that moderate hydrogen fractions (typically 10–30%) provide a practical compromise between improved combustion performance and manageable emission behavior [9,59].

The studies reviewed in this section include experimental appliance tests, CFD and numerical modelling studies, combined experimental–modelling investigations, and review papers on hydrogen-enriched natural-gas combustion. To improve clarity, the representative sources are summarized according to their main methodological approach in

Table 4. Representative experimental studies on hydrogen-enriched natural-gas combustion.

System/Application	${\mathrm{H}}_2$ Range	Main Findings	Ref.
Domestic natural-gas-compatible boiler	5–30 vol.%	Stable combustion was maintained. Hydrogen addition shortened the flame, decreased peak combustion-chamber temperature, reduced NO, increased ${\mathrm{NO}}_2$, and caused a slight increase in CO.	[58]
Storage water heaters	low blends and higher blends	Low hydrogen contents caused no loss of efficiency and only minor emission changes; emission response depended on appliance type and operating conditions at higher blends.	[65]
Residential and commercial gas appliances	various blends	Most appliances remained operational with hydrogen-enriched natural gas, but appliance-specific differences were observed in emissions, safety margin and burner behaviour.	[3]
Partially premixed combustion equipment	0–30 vol.%	Moderate blends maintained acceptable operation; ${\mathrm{NO}}_x$ trends depended on burner type, adjustment strategy and emission-normalisation basis.	[66]
Condensing boiler	23 vol.%	Stable operation was reported with no significant efficiency penalty and no major adverse emission effect under the tested conditions.	[67]
Domestic condensing boilers	up to 50 vol.%	Hydrogen blending improved condensation-related heat recovery; ${\mathrm{NO}}_x$ and CO decreased in the reported tests and remained below regulatory limits.	[68]
Domestic boiler with staged combustion	0–45 vol.%	Hydrogen addition affected thermal behaviour and emissions non-linearly; optimisation of equivalence ratio and hydrogen fraction was required to balance efficiency and ${\mathrm{NO}}_x$.	[69]
Semi-industrial combustion system	up to 100 vol.%	Hydrogen enrichment reduced carbon-containing emissions, while ${\mathrm{NO}}_x$ control became more important due to changes in flame temperature and heat-release distribution.	[70]

(experimental studies),

Table 5. Representative CFD and numerical-modelling studies on hydrogen-enriched natural-gas combustion.

System/Application	${\mathrm{H}}_2$ Range	Main Findings	Ref.
Domestic back-pressure boiler with non-premixed burner	up to 75% mass fraction	Hydrogen enrichment reduced carbon emissions but increased thermal NO formation because of higher local flame temperatures.	[60]
Domestic condensing boiler combustion chamber	0–50 vol.%	Hydrogen addition modified flame interaction and pollutant formation; improved mixing and dilution could reduce CO and NO under suitable conditions.	[59]
Furnace/hydrogen-blended natural-gas flame	0–75 vol.%	Hydrogen addition altered the temperature field, radiative heat transfer and combustion-product distribution.	[61]
660 MW power-plant boiler	hydrogen co-firing	Temperature distribution and ${\mathrm{NO}}_x$ formation were strongly affected by hydrogen injection strategy and air distribution.	[71]
Low-swirl boiler burner	NG model study	Predicted flame structure and ${\mathrm{NO}}_x$ emissions were sensitive to the turbulence and combustion models; ${\mathrm{NO}}_x$ could be overpredicted depending on model choice.	[64]
Natural-gas combustion with hydrogen blending	various	Numerical simulation was shown to be useful for analysing flame structure, temperature fields, emission formation and system optimisation under hydrogen blending.	[44]

(numerical studies),

Table 6. Representative combined experimental–numerical studies on hydrogen-enriched natural-gas combustion.

System/Application	${\mathrm{H}}_2$ Range	Main Findings	Ref.
Industrial low-swirl burner	0–100 vol.%	CO and ${\mathrm{CO}}_2$ decreased with increasing hydrogen content, while ${\mathrm{NO}}_x$ generally increased, highlighting the need for burner optimisation.	[63]
Optimised wall-hung boiler combustion chamber	hydrogen blending	Burner and combustion-chamber optimisation reduced NO and CO despite hydrogen-induced changes in temperature distribution.	[62]
Gas-fired boiler with combustion-stabilising device	approximately 20 vol.%	Combustion stabilisation improved boiler performance and helped control pollutant emissions under hydrogen-enriched operation.	[72]
Industrial gas-fired boiler	0–25 vol.% numerically; about 10 vol.% in field tests	Hydrogen increased laminar flame speed, extinction strain rate and flammability range; field tests showed a trade-off between thermal efficiency and ${\mathrm{NO}}_x$ emissions.	[73]

(combined experimental-numerical studies) and

Table 7. Representative review studies on hydrogen-enriched natural-gas combustion.

System/Application	${\mathrm{H}}_2$ Range	Main Findings	Ref.
Hydrogen blending in natural-gas pipelines	various	Technical and regulatory limits for hydrogen blending were reviewed, including safety, material compatibility, fuel-property changes and infrastructure constraints.	[9]
${\mathrm{NO}}_x$ emissions from hydrogen/natural-gas space-heating boilers	5–20 vol.%	Reported ${\mathrm{NO}}_x$ changes were highly variable, indicating strong dependence on appliance type, operating conditions and emission-normalisation method.	[74]
CFD studies of hydrogen and blended homogeneous fuels	various	The review summarised CFD approaches for hydrogen-blended combustion and highlighted modelling limitations related to chemical kinetics, turbulence–chemistry interaction and pollutant prediction.	[7]
Residential and commercial appliance compatibility	various	The study reviewed appliance safety and performance gaps for hydrogen–natural-gas blends, emphasising the need for appliance-specific testing and updated standards.	[75]

(review studies), while

Table 8. Generalised effects of hydrogen fraction on combustion characteristics.

${\mathrm{H}}_2$ Fraction	Flame Behaviour	Temperature Field	CO Emissions	${\mathrm{NO}}_{\mathit{x}}$ Emissions	Stability/Design Implications
Low (≤10%)	Slight flame acceleration	Minor changes	Slight decrease	Minor increase or stable	Compatible with existing systems
Medium (10–30%)	Shorter, more reactive flame	Redistribution of heat release	May increase locally	Strongly configuration-dependent	Requires combustion tuning
High (30–50%)	Strong flame shortening	Non-uniform temperature fields	CO may increase	Often increases (thermal NO)	Stability and mixing issues emerge
Very high (>50%)	Highly reactive, unstable flame	High peak temperatures and gradients	Incomplete oxidation possible	Significant ${\mathrm{NO}}_x$ increase	Requires redesign of burner/chamber

summarises the general trends discussed above according to hydrogen fraction.

4.2. Hydrogen Co-Combustion with Liquid Fuels

Overall, hydrogen enrichment in liquid fuel systems cannot be treated as a straightforward fuel substitution but must be approached as an integrated combustion optimisation problem. The strong coupling between turbulence, chemical kinetics, and heat transfer necessitates the use of advanced modelling tools and carefully designed experimental validation to ensure stable, efficient, and low-emission operation.

Hydrogen co-combustion with liquid fuels has been investigated in large part in the context of transportation applications. For example, CFD simulations have been employed to study the effect of hydrogen addition at varying hydrogen volume fractions and ignition timings on the performance and emissions of a gasoline direct injection engine [76]. The study finds that blending hydrogen with gasoline increases the concentration of active hydroxyl radicals, which accelerates the combustion process. As hydrogen fraction increases, both peak heat release rate and cylinder pressure rise, indicating improved combustion dynamics. The study also registers an increase in ${\mathrm{NO}}_x$ emissions due to hydrogen blending, although another study reveals that CO emissions are reduced with the addition of hydrogen in a lean burn [77].

The former study also finds that the ignition delay period decreases with higher hydrogen volume fractions, particularly at late ignition timings [76]. This reduction in ignition delay is attributed to hydrogen’s favourable combustion properties, which enhance mixture vaporisation and reduce cold wall quenching. Hydrogen’s high octane rating also contributes to improved knock resistance in the engine. The findings suggest that blending hydrogen can shift the onset of autoignition to an earlier crank angle, thus enhancing overall engine stability.

Multiple studies [76,78,79] have used the SAGE model as appropriate for accurate simulation of gasoline burning in internal combustion engines. The SAGE model is a general combustion model [80] that can accurately evaluate the ignition and combustion mechanisms in detail. Based on the flow phenomena inside a cylinder, the renormalisation group k–$\epsilon$ turbulence model has been found preferable to describe the turbulence characteristics of the flow [81]. Regarding the hydrogen enrichment of traditional fuels, two approaches can be distinguished: hydrogen port injection and hydrogen direct injection, of which the latter is generally preferred due to several advantages [81].

The findings of multiple studies on hydrogen enrichment in liquid fuels and dual-fuel combustion systems are summarised in

Table 9. Representative experimental and combined experimental-numerical studies on hydrogen enrichment in liquid-fuel and dual-fuel combustion systems.

System/Application	${\mathrm{H}}_2$ Involvement	Main Findings	Ref.
Hydrogen–gasoline engine	Hydrogen–gasoline mixture	Hydrogen addition affected toxic-emission formation; CO emissions were reduced under lean-burn operation, while ${\mathrm{NO}}_x$ control remained important.	[77]
Hydrogen-enriched ethanol Wankel rotary engine	Hydrogen-enriched ethanol	Hydrogen enrichment improved lean-operation behaviour and combustion characteristics under ultra-lean and full-load conditions.	[82]
Hydrogen-enriched n-butanol rotary engine	Hydrogen enrichment	Hydrogen addition improved lean combustion performance, but operating conditions had to be controlled to avoid combustion and emission penalties.	[83]
Hydrogen-rich swirling non-premixed flame (combined experimental-numerical sttduy)	Hydrogen-rich mixtures	Stable hydrogen-rich combustion was achieved with moderate ${\mathrm{NO}}_x$ increase, and CFD results showed good agreement with experimental verification.	[42]

(experimental and combined experimental-numerical studies),

Table 10. Representative numerical-modelling studies on hydrogen enrichment in liquid-fuel and dual-fuel combustion systems.

System/Application	${\mathrm{H}}_2$ Involvement	Main Findings	Ref.
Gasoline direct-injection engine	Hydrogen blending	Hydrogen addition increased active radical concentration, accelerated combustion, increased peak heat-release rate and cylinder pressure, and could increase ${\mathrm{NO}}_x$.	[76]
Hydrogen–diesel dual-fuel CI engine	Hydrogen–diesel dual-fuel mode	Higher local in-cylinder temperatures under hydrogen–diesel dual-fuel operation promoted NO formation, demonstrating the importance of local temperature control.	[84]
Marine dual-fuel engine	20–60% energy fraction	Hydrogen premixed combustion improved efficiency, but increased ${\mathrm{NO}}_x$ formation and introduced knock and pressure-rise constraints at high load.	[85]
SI engine with premixed and direct-injection strategies	Hydrogen injection	Premixed and direct-injection strategies affected mixture formation, flame development and efficiency; direct injection was sensitive to injection timing.	[43]
PFI SI engine under lean combustion	Lean hydrogen combustion	The CFD model reproduced heat-release and ${\mathrm{NO}}_x$ trends under lean hydrogen combustion, showing strong dependence on equivalence ratio and operating conditions.	[86]
Pulse detonation combustor	Hydrogen vs. liquid fuels	Hydrogen showed higher exergetic efficiency and improved thermal performance compared with selected liquid-fuel cases.	[87]
Gas microturbine combustor	Hydrogen-enriched fuel	Hydrogen enrichment increased temperature and ${\mathrm{NO}}_x$ formation; internal flue-gas recirculation showed limited effectiveness under some operating conditions.	[45]
Hydrogen direct-injection stratified gasoline Wankel engine	Hydrogen direct injection	Ignition strategy and hydrogen injection affected mixture formation, combustion phasing and emissions in the rotary engine configuration.	[78]
PFI gasoline engine with hydrogen direct injection	Hydrogen direct injection	Hydrogen direct injection influenced combustion and emission characteristics, indicating the importance of injection strategy in gasoline engines.	[79]
Hydrogen direct-injection Wankel rotary engine	Hydrogen direct injection	Hydrogen injection strategy affected mixture formation and combustion development in partially premixed rotary-engine operation.	[81]

(numerical studies) and

Table 11. Representative review studies on hydrogen enrichment in liquid-fuel and dual-fuel combustion systems.

System/Application	${\mathrm{H}}_2$ Involvement	Main Findings	Ref.
Diesel/biodiesel CI engines	Dual-fuel/blending	Hydrogen addition to diesel and biodiesel blends generally improved combustion and reduced CO, ${\mathrm{CO}}_2$, HC and smoke emissions, although ${\mathrm{NO}}_x$ often increased without mitigation.	[46]
Multi-system combustion modelling	Various alternative fuels	Hybrid CFD–machine-learning approaches can reduce computational cost and support prediction and optimisation of combustion and emission behaviour.	[40]
Fuel systems and reactors	Gaseous and liquid fuels	CFD modelling was identified as a useful tool for design improvement, optimisation and scale-up of gaseous and liquid fuel systems.	[41]
MILD combustion of liquid fuels	Indirect relevance	MILD combustion provides more uniform temperature fields and low-emission potential, which is relevant to hydrogen-assisted and hydrogen-compatible combustion concepts.	[88]
Liquid ammonia spray and combustion	Hydrogen carrier	Ammonia combustion is relevant as a hydrogen-carrier pathway, but faces important ${\mathrm{NO}}_x$ and flame-stability challenges.	[89]
Alternative liquid fuels in marine engines	Includes hydrogen	Alternative marine fuels, including hydrogen-related pathways, require integrated assessment of safety, storage, combustion control and emissions.	[90]
Flameless combustion with liquid fuels	Indirect relevance	Flameless combustion can reduce emissions through more uniform temperature fields and is relevant to low-emission combustion-system design.	[91]
Hydrogen internal combustion engines	Hydrogen fuel	Hydrogen engines offer fuel-flexibility and low carbon emissions, but simultaneous optimisation of efficiency, power output, ${\mathrm{NO}}_x$ emissions and abnormal-combustion control remains challenging.	[92]

(review studies).

A comprehensive review of advancements in hydrogen-fuelled internal combustion engines in the transportation sector is provided in Ref. [92]. The study outlines the benefits of hydrogen internal combustion engines, such as their fuel flexibility, lower purity requirements, and compatibility with existing infrastructure, but also articulates that achieving high efficiency, low emissions, and adequate power output simultaneously remains a challenge. The authors conclude that although hydrogen engines present a promising alternative for reducing reliance on fossil fuels, significant research is still needed to overcome technical barriers and make them competitive in the broader market.

4.3. Hydrogen Co-Combustion with Solid Fuels

The co-combustion of hydrogen with solid fuels, such as coal and coke, involves complex multi-phase interactions between gas-phase reactions and heterogeneous processes, including devolatilisation, char oxidation, and gasification. These processes occur over different time and length scales, making the overall combustion behaviour highly dependent on both chemical kinetics and transport phenomena [93,94]. The addition of hydrogen considerably enhances ignition and promotes the formation of reactive radicals, accelerating gas-phase reactions and influencing the conversion of solid fuels [95,96]. Hydrogen-enriched environments increase the concentration of reducing species such as ${\mathrm{H}}_2$ and CO, which play a critical role in industrial applications, such as blast furnaces, by improving reduction efficiency and lowering overall carbon emissions [97,98].

However, hydrogen also introduces competing mechanisms that can negatively affect solid fuel conversion. One of the key challenges is the competition for oxygen between hydrogen and solid fuel particles. As hydrogen preferentially reacts with available oxygen, the oxidation rate of coal particles may decrease, leading to reduced burnout efficiency, particularly at higher hydrogen fractions [99,100]. This effect is especially important in pulverised coal systems, where residence time and mixing conditions are critical for complete combustion.

From a thermal perspective, hydrogen enrichment leads to higher local temperatures and modified temperature distributions within the combustion zone. Although increased temperatures enhance reaction rates and improve ignition, they also promote thermal ${\mathrm{NO}}_x$ formation, especially in regions with high oxygen availability [101]. The spatial distribution of temperature and species therefore plays a crucial role in determining overall emission behaviour.

CFD-based studies demonstrate that hydrogen significantly influences flow structure, mixing patterns, and flame stabilisation in solid fuel combustion systems. Accurate modelling of these effects requires advanced turbulence–chemistry interaction models and detailed treatment of multi-phase flows [101,102]. In industrial applications, such as blast furnaces, the effectiveness of hydrogen injection depends strongly on injection strategy, flow configuration, and operating conditions [97,99].

Overall, hydrogen integration into solid fuel combustion systems offers considerable potential for emission reduction and improved process efficiency. However, achieving these benefits requires careful optimisation of operating conditions to balance enhanced reactivity with stable combustion, efficient fuel conversion, and controlled emission formation.

Based on the solid-fuel co-combustion literature discussed above, Figure 1 presents a literature-based conceptual overview of the qualitative influence of hydrogen addition on selected coal-combustion characteristics, including temperature, ${\mathrm{NO}}_x$ formation, ${\mathrm{CO}}_2$ emissions and coal burnout [97,98,99,100,101]. The trends are intended to summarise the general direction of reported effects and should be interpreted as indicative tendencies rather than quantitative correlations.

5. Combustion Processes Involving Hydrogen in Industrial and Power-Generation Applications

The integration of hydrogen into industrial combustion systems introduces considerable modifications to combustion processes. Industrial applications such as gas turbines, industrial furnaces, boilers, and blast furnaces, operate under conditions of elevated temperature, pressure, and turbulence, where hydrogen enrichment affects not only chemical kinetics but also flow structure, heat transfer, and system stability [40,41].

5.1. Applications in Boilers, Furnaces and Kilns

In industrial boiler and furnace systems, hydrogen addition alters flame structure and heat release distribution, often resulting in shorter and more intense flames. These changes directly influence heat transfer mechanisms, including convective and radiative heat fluxes. Numerical studies indicate that hydrogen enrichment modifies the radiative properties of combustion gases due to changes in species composition, particularly the reduction of ${\mathrm{CO}}_2$ and the increase of H₂O, which affects overall thermal efficiency and temperature distribution within the combustion chamber [45,61,71]. As a result, conventional heat transfer assumptions used in NG systems may no longer be applicable without adjustment.

In blast furnace and metallurgical applications, hydrogen is increasingly considered as a reducing agent and supplementary fuel for decarbonisation. The injection of hydrogen-rich gases into the raceway region modifies the thermochemical environment, increasing the concentration of reducing species and influencing the combustion behaviour of pulverized coal and coke [97,98]. While hydrogen enhances reduction reactions and decreases ${\mathrm{CO}}_2$ emissions, it also affects the thermal balance and flow dynamics within the furnace. Studies show that hydrogen injection can alter the size and structure of the high-temperature reaction zone, as well as the distribution of gas species and particle behaviour [99,100].

A key challenge in industrial systems is the interaction between hydrogen combustion and heterogeneous processes. In solid fuel-based systems, hydrogen competes with solid fuels for oxygen, potentially reducing the burnout efficiency of coal particles and affecting overall system performance [99]. At the same time, hydrogen combustion increases local temperatures, which can enhance reaction rates but also promote thermal ${\mathrm{NO}}_x$ formation, particularly in oxygen-rich regions [101]. These competing effects require careful optimisation of operating conditions to balance efficiency and emissions.

From a modelling perspective, industrial hydrogen combustion systems require advanced CFD approaches capable of capturing multi-scale and multi-physics interactions, including turbulence, chemical kinetics, heat transfer, and multi-phase flows. However, accurately resolving these phenomena at an industrial scale remains computationally demanding, and model simplifications are often necessary [40,41]. The reliability of such models depends strongly on validation against experimental data, which remains limited for high-pressure and large-scale hydrogen combustion systems.

Overall, the implementation of hydrogen in industrial combustion systems offers considerable potential for reducing carbon emissions and improving process sustainability. However, it also introduces significant challenges related to flame control, heat transfer, emission formation, and fuel conversion efficiency. Achieving stable and efficient operation requires coordinated optimisation of fuel composition, injection strategy, and system design, supported by both experimental investigations and advanced numerical modelling.

5.2. Applications in Gas-Turbine Engines

Global electricity production from gas-fired power plants amounts to approximately 6805 TWh per year, corresponding to approximately 22% of the total power output [103]. Much of this output is from gas turbine-based technologies, including combined-cycle configurations. The degree of reliance on gas-fired power generation varies substantially across regions. Countries in the Middle East and North Africa rely heavily on gas turbines—approaching 100% of total electricity generation in some cases—and the share is also high in the United States (43%) and the United Kingdom (31%). At the other end of the spectrum are Brazil (7%), India and China (around 3% each), as well as South Africa (0%), while gas-fired generation accounts for approximately 17% of electricity production in each of the European Union, Canada, and Australia [104].

The prominence of gas turbines in the energy supply mix is attributable to several advantages: they offer a high power-to-weight ratio, rapid start-up and ramping capability, and modular scalability—from microturbines with outputs starting in the vicinity of 10 kW to large heavy-duty units with capacities approaching 600 MW [105]—as well as high operational reliability. However, currently deployed gas-turbine engines are predominantly designed for natural-gas combustion, and their existing architectures cannot be assumed to operate safely or effectively with hydrogen. The disparities in combustion-related properties between hydrogen and methane have significant implications for gas-turbine design and operation, influencing combustor geometry, fuel-delivery systems, and overall thermodynamic performance.

In large-scale power generation systems, such as utility boilers and gas turbines, hydrogen co-firing introduces additional complexity related to mixing, combustion stability, and emission control. The distribution of hydrogen within the combustion zone plays a critical role in determining temperature fields and pollutant formation. Numerical investigations demonstrate that injection strategy, including the position and staging of hydrogen supply, significantly influences ${\mathrm{NO}}_x$ formation and overall combustion performance [71]. Improper mixing or localised enrichment can lead to hot spots and increased thermal ${\mathrm{NO}}_x$ formation, whereas optimised distribution strategies can mitigate these effects.

The impact of hydrogen-enriched fuels on combustion stability in gas turbine combustors has been investigated in Ref. [106] through large eddy simulations. The authors utilise a multi-step chemical mechanism for hydrogen–methane combustion within a swirling flame context. The study finds that increasing hydrogen content or decreasing fuel flow rate stabilizes the flame structure, reducing combustion instability. This is attributed to changes in the flame’s interaction with the recirculation zone. The research emphasises that flame–vortex interactions are critical to understanding stability characteristics. Unstable pressure fluctuations are linked to vigorous vortex burning when unburnt mixtures are periodically supplied into the recirculation zone. Flame structure analysis shows that as hydrogen content increases, the flame length decreases due to hydrogen’s higher diffusivity and laminar burning velocity. The authors highlight the importance of fuel composition in managing combustion dynamics and suggest that optimising hydrogen content can lead to more stable operation in partially premixed swirl combustors. Future research could focus on further refining simulation techniques and exploring additional fuel compositions to enhance understanding of combustion instability mechanisms.

When compared with methane, the combustion of hydrogen involves an increased water content in the flue gases, which leads to increased convective heat transfer coefficients [107] and a more corrosive environment [108] in the hot sections of gas-turbine engines. These factors can accelerate material degradation and reduce the service life of the engines. Advanced combustor designs help mitigate these effects by employing various strategies, such as optimising air–fuel mixing and, controlling flame temperature to limit water formation in the combustion products and reduce flue gas temperatures. Material selection is also crucially important, with corrosion-resistant superalloys and other high-temperature alloys required to withstand the moisture-rich and chemically aggressive environment. Overall, to support the adoption of high-hydrogen gas turbines, further research is required to quantify how changes in convective and radiative heat transfer affect turbine component temperatures, material durability, and cooling strategies [107].

A summary of some recent studies involving design modifications related to the introduction of hydrogen as a fuel in gas-turbine engines is shown in Table 12.

5.3. Applications in Gas-Fired Spark Ignition Engines

The effect of blending hydrogen with NG in spark ignition engines has also been investigated. The study, presented in Ref. [109], employs both one-dimensional (1D) and three-dimensional (3D) simulation models to analyse flame propagation, emissions, and energy balance. The authors utilised GT-Power software for 1D simulations and detailed reaction kinetics for 3D modelling, allowing for comprehensive analysis of flame dynamics and emissions. Among the key findings of the study is that the addition of hydrogen increases the initial spark kernel volume, leading to faster flame propagation in NG-fired spark ignition engines. This effect is particularly pronounced under lean-burn conditions where traditional NG struggles with stability. Hydrogen enrichment results in higher nitrogen oxide emissions due to elevated peak combustion temperatures. However, it also facilitates more complete oxidation of CO and considerably reduces hydrocarbon and soot emissions.

Overall, hydrogen addition improves the energy efficiency and fuel economy of the engine, especially at lean mixtures. This enhancement is attributed to the increased radical pool and improved combustion characteristics. The findings suggest that integrating hydrogen into NG engines offers a promising pathway towards cleaner combustion technologies. Future research directions include further exploration of emission mechanisms and optimisation of fuel compositions to maximise benefits.

Table 12. Studies on design modification related to the combustion of hydrogen in gas turbines.

Gas Turbine/ Test Rig	Analysis	${\mathrm{H}}_2$ Content (% vol.)	Design Modifications (Actual or Suggested)	Findings	Ref
Microturbine (100 kW)	Experimental (test rig)	50–100%	New burner based on FLOX technology; fuel train replaced with a mixing unit; new fuel valves; additional controller to maintain required energy input	Stable operation with ${\mathrm{NO}}_x$ below allowed limits; electrical efficiency not impaired by ${\mathrm{H}}_2$ injection; GHG reduction with increasing ${\mathrm{H}}_2$ fraction	[110]
Supercritical (15–30 kW)	Numerical (CFD)	100%	Increased number of oxygen inlets; dilution of oxygen with argon	More uniform temperature profile with additional oxygen inlets; higher risk of localized material overheating near inlets; argon dilution reduces peak temperature and overheating risk for critical inlet components	[111]
Combustion chamber with thermal input up to 800 kW	Experimental (atmospheric test rig) + CFD	100%	New axial swirler; co-flow injection system	Higher flow velocity required to avoid flame positioning inside premixer when using ${\mathrm{H}}_2$; increased burner exit velocity raises burner pressure drop; limited effect of flame shape on ${\mathrm{NO}}_x$	[112]
Heavy duty (238 MW)	Numerical (Aspen HYSYS)	5–30%	Mixer added to facilitate blending of ${\mathrm{H}}_2$ and NG before the combustor	Higher thermal efficiency (0.32–0.37% per 5% increase in ${\mathrm{H}}_2$); ${\mathrm{CO}}_2$ emissions decreased by 2.16% for every 5% increase in ${\mathrm{H}}_2$ fraction	[113]
Gas-turbine auxiliary power unit (335 kW)	Experimental + CFD	100%	Cross-flow mixing of air and hydrogen generating multiple miniaturized diffusion flames	Low ${\mathrm{NO}}_x$ emissions due to a very short residence time of reactants in the flame region	[114]
Microturbine (40 kW)	Numerical (CFD)	0–50%	Autonomous internal flue gases recirculation (IFGR) system	Obtained recirculation ratios too low to significantly affect the combustion process	[45]
Microturbine (100 kW)	Experimental + CFD	0–100%	Novel burner geometry: two independent lean-premixed swirl burners with aerodynamic stabilization; central burner for low ${\mathrm{H}}_2$ and coaxial crown burner for high ${\mathrm{H}}_2$	${\mathrm{NO}}_x$ limited by adopting appropriate equivalence ratio; good performance within 30–70% ${\mathrm{H}}_2$ while meeting emission limits; some equivalence ${\mathrm{ratio/H}}_2$ combinations cause flame retreat and anchoring at the central bluff body, creating a localized ignition hotspot that accelerates material degradation	[115]

Table 12. Studies on design modification related to the combustion of hydrogen in gas turbines.

Gas Turbine/ Test Rig	Analysis	${\mathrm{H}}_2$ Content (% vol.)	Design Modifications (Actual or Suggested)	Findings	Ref
Microturbine (100 kW)	Experimental (test rig)	50–100%	New burner based on FLOX technology; fuel train replaced with a mixing unit; new fuel valves; additional controller to maintain required energy input	Stable operation with ${\mathrm{NO}}_x$ below allowed limits; electrical efficiency not impaired by ${\mathrm{H}}_2$ injection; GHG reduction with increasing ${\mathrm{H}}_2$ fraction	[110]
Supercritical (15–30 kW)	Numerical (CFD)	100%	Increased number of oxygen inlets; dilution of oxygen with argon	More uniform temperature profile with additional oxygen inlets; higher risk of localized material overheating near inlets; argon dilution reduces peak temperature and overheating risk for critical inlet components	[111]
Combustion chamber with thermal input up to 800 kW	Experimental (atmospheric test rig) + CFD	100%	New axial swirler; co-flow injection system	Higher flow velocity required to avoid flame positioning inside premixer when using ${\mathrm{H}}_2$; increased burner exit velocity raises burner pressure drop; limited effect of flame shape on ${\mathrm{NO}}_x$	[112]
Heavy duty (238 MW)	Numerical (Aspen HYSYS)	5–30%	Mixer added to facilitate blending of ${\mathrm{H}}_2$ and NG before the combustor	Higher thermal efficiency (0.32–0.37% per 5% increase in ${\mathrm{H}}_2$); ${\mathrm{CO}}_2$ emissions decreased by 2.16% for every 5% increase in ${\mathrm{H}}_2$ fraction	[113]
Gas-turbine auxiliary power unit (335 kW)	Experimental + CFD	100%	Cross-flow mixing of air and hydrogen generating multiple miniaturized diffusion flames	Low ${\mathrm{NO}}_x$ emissions due to a very short residence time of reactants in the flame region	[114]
Microturbine (40 kW)	Numerical (CFD)	0–50%	Autonomous internal flue gases recirculation (IFGR) system	Obtained recirculation ratios too low to significantly affect the combustion process	[45]
Microturbine (100 kW)	Experimental + CFD	0–100%	Novel burner geometry: two independent lean-premixed swirl burners with aerodynamic stabilization; central burner for low ${\mathrm{H}}_2$ and coaxial crown burner for high ${\mathrm{H}}_2$	${\mathrm{NO}}_x$ limited by adopting appropriate equivalence ratio; good performance within 30–70% ${\mathrm{H}}_2$ while meeting emission limits; some equivalence ${\mathrm{ratio/H}}_2$ combinations cause flame retreat and anchoring at the central bluff body, creating a localized ignition hotspot that accelerates material degradation	[115]

6. Combustion Processes Involving Hydrogen in Heating, Ventilation and Air-Conditioning Applications

Fossil fuels are still playing a leading role in the residential heating and domestic hot water sector in the EU, according to the official Eurostat data as of 2023 [116]. Approximately 42% of total EU household thermal energy consumption is derived from NG (29.5%), oil and petroleum products - including liquefied petroleum gas (LPG) (10.3%), and solid fossil fuels (2.2%). Including district heating systems (DHS), fossil fuels are providing more than 51% of the total thermal energy production in the EU, by using mainly NG and solid fuels [117]. This highlights the continued reliance on fossil fuels in European heating systems, despite the increasing implementation of different renewable energy sources and heat pumps. In this regard, one of the main goals of the EU Hydrogen Strategy, adopted in 2020, is to reduce this dependence by promoting renewable hydrogen as a clean alternative for heating as well as for other sectors that are difficult to electrify.

Hydrogen combustion has a high potential for heating, ventilation and air-conditioning systems, where it can be used directly in heating boilers or to power internal combustion engines that drive heat pumps’ compressors. European standards, such as EN 15502-1 [118] and EN 437 [119], currently permit the operation of boilers with hydrogen-enriched NG blends of up to 23 vol.% without necessitating significant modifications to boiler design or materials. Boiler prototypes that operate on 100% hydrogen have already been developed, tested, and validated by major manufacturers. In terms of technological readiness level, hydrogen boilers are therefore significantly further ahead than hydrogen internal combustion engines in terms of heating, as commercial deployment of 100% hydrogen boilers is already underway. Hydrogen engines are still limited to pilot and research projects and also in CHP applications.

Despite its strong potential, a realistic assessment of hydrogen’s role in the European heating sector suggests that its contribution is expected to remain limited in most decarbonisation scenarios. Recent multi-model analyses and policy-oriented studies, including those by the IEA [120], and Deloitte [121], consistently forecast that hydrogen will account for less than 1–5% of the total heat demand for buildings by 2050; some scenarios indicate figures even below 1%, limited primarily to specific applications, such as backup power in DHS or in buildings that are difficult to electrify. Even under more optimistic deployment pathways, such as those presented in the Hydrogen Roadmap Europe [122], hydrogen use in buildings will reach approximately 465 TWh by 2050. This corresponds to heating demand equivalent of approximately 52 million households, which represents only about 10–15% of the total final energy demand for buildings in the EU. In contrast, electrification—particularly through the large-scale adoption of electric heat pumps—is expected to dominate the decarbonisation of the heating sector, covering between 50% and 70% of heat demand over the same time horizon [120,123].

6.1. Hydrogen-Enriched Natural Gas

Hydrogen-enriched NG represents the first step towards decarbonising domestic heating by using the existing infrastructure. Nowadays, a number of real demonstrators confirm the safe implementation of hydrogen-enriched NG across Europe. The projects HyDeploy in the UK [124] and GRHYD in France [125] demonstrate the possibility of injecting 20 vol.% hydrogen into existing gas distribution networks serving hundreds of households. The results show no problems with the operation of the appliances, nor any significant safety concerns.

Hydrogen is generally mixed with NG or with pure methane (${\mathrm{CH}}_4$) for laboratory tests. Studies by Sami et al. [126] and Wright et al. [74] have shown that up to 20 vol.% ${\mathrm{H}}_2$, the existing gas-fired boilers are capable of working without modification in most cases. This compatibility enables near-term ${\mathrm{CO}}_2$ reductions with minimal cost. On the other hand, hydrogen addition increases flame speed and adiabatic flame temperature, potentially raising ${\mathrm{NO}}_x$ emissions, which have been observed to increase by an average of 8% at 5% ${\mathrm{H}}_2$ blends and up to 19% at higher concentrations [125]. The formation of ${\mathrm{NO}}_x$ in such systems is primarily governed by the thermal (Zeldovich) mechanism, which is highly sensitive to the peak flame temperature. An increase in hydrogen content generally promotes higher local flame temperatures and faster reaction kinetics under near-stoichiometric conditions, leading to enhanced ${\mathrm{NO}}_x$ formation. However, when combustion occurs under lean conditions (i.e., higher excess air ratio), the peak flame temperature is reduced, which can suppress thermal ${\mathrm{NO}}_x$ formation despite the presence of hydrogen. This explains the non-linear behaviour reported in the literature, where small hydrogen additions may increase ${\mathrm{NO}}_x$ emissions, whereas higher hydrogen fractions combined with optimised air–fuel ratios can lead to a reduction in ${\mathrm{NO}}_x$. Mixtures of hydrogen and NG containing up to 30 vol.% hydrogen show slight but inconsistent differences in combustion efficiency and emissions, as shown in Ref. [127], compared with a mixture of hydrogen and methane, attributed to the presence of additional impurities in NG, such as hydrocarbons and inert gases.

In terms of gas-fired boiler efficiency, enriching NG with hydrogen improves the latent heat recovery capability of condensing boilers due to the phase change. Bălănescu and Homutescu [128] observed an increase in boiler efficiency from approximately 91 to 92.8% when the hydrogen content in the mixture increased from 0 to 80%. This improvement was due to higher flue gas dew point temperatures and, consequently, increased condensation of water vapour in them. Lo Basso et al. [129] extended this study by presenting a detailed thermodynamic model and experimental data that confirmed that the specific heat of the flue gases decreases with increasing hydrogen concentration, leading to a reduction in stack losses. Their analysis shows that a 30% hydrogen content in the mixture reduces losses and contributes to an increase in boiler energy efficiency by approximately 0.9%. It should be emphasised that the observed increase in efficiency is primarily due to the increased potential for water vapour condensation in the flue gases, rather than an inherent improvement in the combustion process. Since hydrogen combustion produces a greater amount of water vapour than methane, the dew point of the flue gases rises, which facilitates the recovery of latent heat under suitable conditions. However, the realisation of this effect depends strongly on the operating temperatures of the heating system, particularly the return water temperature.

In heating systems where return water temperatures remain above the dew point; for example, in conventional high-temperature radiator systems—the condensation process may be limited or entirely impossible. As a result, the actual improvement in efficiency under real operating conditions may be considerably lower than the values reported under controlled experimental or optimised condensation conditions. Schiro et al. [130] confirmed, by simulating various scenarios, that standard condensing boilers can maintain stable combustion when operating with up to 23 vol.% ${\mathrm{H}}_2$ without the need for modification. This was the case when using the test gas G222 with a composition of 77% ${\mathrm{CH}}_4$ and 23% ${\mathrm{H}}_2$, according to Ref. [119].

At moderate hydrogen enrichment of 20 to 50%, ${\mathrm{NO}}_x$ release tends to decrease markedly. Coşkun et al. [131] conducted a study that showed a 37% reduction in ${\mathrm{NO}}_x$ with only 20% hydrogen in a 24kW boiler. A decrease in ${\mathrm{NO}}_x$ levels to 2.7 mg/m³ at 50% hydrogen was also observed by Jankowski et al. [68]. Another study by Schiro et al. [132] shows that this is due to the higher flame reactivity of hydrogen, which facilitates leaner and more uniform combustion, reduces flame peak temperatures, and suppresses thermal ${\mathrm{NO}}_x$ via the Zeldovich mechanism. Controlling the air-fuel ratio and consequently the flue gas properties can further reduce ${\mathrm{NO}}_x$ formation according to Ref. [129]. Antonescu et al. [133] confirm that up to 20% hydrogen can be added to NG without loss of efficiency or increase in emissions, with experiments demonstrating up to 7% reduction in ${\mathrm{CO}}_2$ emissions and stable combustion performance.

A study by Boulahlib et al. [69] examines the combined effects of hydrogen enrichment in the range of 0 to 45 vol.%, in a 15 kW boiler. The results confirm what has been established so far, namely that the addition of hydrogen (up to approximately 20%) improves flame propagation and combustion intensity, leading to higher flue gas temperatures and improved thermal characteristics. At higher hydrogen fractions and richer conditions of staged combustion, a decrease in combustion temperature is observed, leading to reduced heat recovery and a gradual decrease in overall efficiency. Nitrogen oxides emissions show non-linear behaviour, increasing slightly at low hydrogen content (0–10%) due to enhanced thermal NO formation, followed by a significant decrease at higher hydrogen fractions as a result of reduced oxygen availability and lower peak temperatures. Under optimised conditions ($\varphi \approx 2.0-3.0$ and $H_2\approx 20\%$), ${\mathrm{NO}}_x$ levels of 12–22 ppm, corresponding to approximately 23–41 mg/m³ (as ${\mathrm{NO}}_2$), were achieved while maintaining acceptable thermal efficiency. These findings highlight the importance of balancing hydrogen content and equivalence ratio to optimise efficiency and emissions in hydrogen-enriched domestic boilers.

The data regarding boiler efficiency and ${\mathrm{NO}}_x$ emissions from the reviewed studies is summarized and presented in Table 13 (experimental studies), Table 14 (numerical studies) and Table 15 (studies involving both experimental and numerical methods). It is important to note that when the hydrogen content exceeds 50% by volume, serious combustion and material challenges arise. The high flame speed and low ignition energy of hydrogen-rich mixtures markedly increase the risk of reverse flame in conventional burners, requiring the use of specialised combustion system designs and the application of active flame stabilisation methods [134].

From a materials perspective, hydrogen-rich mixtures can lead to hydrogen embrittlement. Hydrogen atoms diffuse into the metal components due to the higher concentration and pressure, thus leading to reduced ductility, strength, and impact resistance, and consequently to crack formation and growth, even under low mechanical loads [75,135].

Table 13. Thermal Efficiency and ${\mathrm{NO}}_x$ Emission Performance of Boilers and Gas-Fired Appliances Operated with Hydrogen-Enriched NG (Experimental Studies).

Application	${\mathrm{H}}_2$ Content (vol.%)	Efficiency Change	${\mathrm{NO}}_{\mathit{x}}$ Response	Key Findings	Ref.
Water heater	<10	Negligible	Minimal change	Stable operation at low ${\mathrm{H}}_2$ fractions	[65]
Domestic appliances	13.2	Minor variation	Stable combustion	Safe operation without major performance degradation	[136]
Domestic gas appliances	0–20	Minor variation	Potential increase depending on burner design	Acceptable performance within blending range	[3]
Standard water heater	0–30	−1.2%	Slight decrease	Limited impact on performance	[66]
${\mathrm{Ultra-low-NO}}_x$ water heater	0–30	+0.9%	Slight decrease	Maintained ${\mathrm{ultra-low-NO}}_x$ performance	[66]
Condensing boiler	0–20	Negligible	N/A	${\mathrm{CO}}_2$ emissions reduced by ∼7%	[133]
Condensing boiler	23	Negligible	N/A	Annual ${\mathrm{CO}}_2$ emissions reduced by ∼1.26 t for a 28 kW boiler	[67]
2.8 MW condensing boiler	0–100	+8.8%	N/A	Efficiency increased from 101.8% to 110.6%; ${\mathrm{CO}}_2$ intensity reduced by 55.4%	[137]
Domestic condensing boiler	0–50	+1.6%	Strong decrease	${\mathrm{NO}}_x$ reduced to 2.7 mg/m3; CO reduced six-fold	[68]
Natural-gas-compatible boiler	5–30	N/A	Decrease	Peak temperature reduced by 87 °C at 30% ${\mathrm{H}}_2$	[58]
Semi-industrial furnace	0–100	+5.5%	+167%	Improved thermal performance but large ${\mathrm{NO}}_x$ increase at high ${\mathrm{H}}_2$ fractions	[70]

Table 13. Thermal Efficiency and ${\mathrm{NO}}_x$ Emission Performance of Boilers and Gas-Fired Appliances Operated with Hydrogen-Enriched NG (Experimental Studies).

Application	${\mathrm{H}}_2$ Content (vol.%)	Efficiency Change	${\mathrm{NO}}_{\mathit{x}}$ Response	Key Findings	Ref.
Water heater	<10	Negligible	Minimal change	Stable operation at low ${\mathrm{H}}_2$ fractions	[65]
Domestic appliances	13.2	Minor variation	Stable combustion	Safe operation without major performance degradation	[136]
Domestic gas appliances	0–20	Minor variation	Potential increase depending on burner design	Acceptable performance within blending range	[3]
Standard water heater	0–30	−1.2%	Slight decrease	Limited impact on performance	[66]
${\mathrm{Ultra-low-NO}}_x$ water heater	0–30	+0.9%	Slight decrease	Maintained ${\mathrm{ultra-low-NO}}_x$ performance	[66]
Condensing boiler	0–20	Negligible	N/A	${\mathrm{CO}}_2$ emissions reduced by ∼7%	[133]
Condensing boiler	23	Negligible	N/A	Annual ${\mathrm{CO}}_2$ emissions reduced by ∼1.26 t for a 28 kW boiler	[67]
2.8 MW condensing boiler	0–100	+8.8%	N/A	Efficiency increased from 101.8% to 110.6%; ${\mathrm{CO}}_2$ intensity reduced by 55.4%	[137]
Domestic condensing boiler	0–50	+1.6%	Strong decrease	${\mathrm{NO}}_x$ reduced to 2.7 mg/m3; CO reduced six-fold	[68]
Natural-gas-compatible boiler	5–30	N/A	Decrease	Peak temperature reduced by 87 °C at 30% ${\mathrm{H}}_2$	[58]
Semi-industrial furnace	0–100	+5.5%	+167%	Improved thermal performance but large ${\mathrm{NO}}_x$ increase at high ${\mathrm{H}}_2$ fractions	[70]

Table 14. Thermal Efficiency and ${\mathrm{NO}}_x$ Emission Performance of Boilers and Gas-Fired Appliances Operated with Hydrogen-Enriched NG (Numerical Studies).

Application	${\mathrm{H}}_2$ Content (vol.%)	Efficiency Change	${\mathrm{NO}}_{\mathit{x}}$ Response	Key Findings	Ref.
Condensing boiler	0–30	+0.9 pp	N/A	Increased condensation energy recovery	[129]
Industrial gas-fired boiler	9.7–10.1	−0.3 to −1.7%	Decrease under optimized conditions	Efficiency–${\mathrm{NO}}_x$ trade-off observed	[73]
4.2 MW boiler with waste heat recovery	0–40	+0.4–0.7% (>5% with advanced recovery)	+19%	Waste heat recovery improved efficiency; FGR recommended for ${\mathrm{NO}}_x$ mitigation	[138]
Porous media water heater	20	N/A	−53.9%	CO reduced by 25.4%; ${\mathrm{CO}}_2$ reduced by 6.78%	[73]
Industrial boiler	0–100	N/A	Increase	Higher ${\mathrm{H}}_2$ increased flame temperature and ${\mathrm{NO}}_x$; CO decreased; flames shorter and wider	[139]
Domestic condensing boiler	0–35	N/A	Increased tendency	Stable up to 35% ${\mathrm{H}}_2$; CFD agreed; burner modifications needed for pure ${\mathrm{H}}_2$	[140]
Condensing boiler with porous burner	20	∼−5% thermal output	−36.8%	${\mathrm{NO}}_x$ reduced from 19 to 12 mg/kWh; stable operation maintained	[131]
8 MW fire-tube boiler	0–100	+1.26%	Limited discussion	Reduced exhaust losses; improved thermal efficiency	[141]

Table 14. Thermal Efficiency and ${\mathrm{NO}}_x$ Emission Performance of Boilers and Gas-Fired Appliances Operated with Hydrogen-Enriched NG (Numerical Studies).

Application	${\mathrm{H}}_2$ Content (vol.%)	Efficiency Change	${\mathrm{NO}}_{\mathit{x}}$ Response	Key Findings	Ref.
Condensing boiler	0–30	+0.9 pp	N/A	Increased condensation energy recovery	[129]
Industrial gas-fired boiler	9.7–10.1	−0.3 to −1.7%	Decrease under optimized conditions	Efficiency–${\mathrm{NO}}_x$ trade-off observed	[73]
4.2 MW boiler with waste heat recovery	0–40	+0.4–0.7% (>5% with advanced recovery)	+19%	Waste heat recovery improved efficiency; FGR recommended for ${\mathrm{NO}}_x$ mitigation	[138]
Porous media water heater	20	N/A	−53.9%	CO reduced by 25.4%; ${\mathrm{CO}}_2$ reduced by 6.78%	[73]
Industrial boiler	0–100	N/A	Increase	Higher ${\mathrm{H}}_2$ increased flame temperature and ${\mathrm{NO}}_x$; CO decreased; flames shorter and wider	[139]
Domestic condensing boiler	0–35	N/A	Increased tendency	Stable up to 35% ${\mathrm{H}}_2$; CFD agreed; burner modifications needed for pure ${\mathrm{H}}_2$	[140]
Condensing boiler with porous burner	20	∼−5% thermal output	−36.8%	${\mathrm{NO}}_x$ reduced from 19 to 12 mg/kWh; stable operation maintained	[131]
8 MW fire-tube boiler	0–100	+1.26%	Limited discussion	Reduced exhaust losses; improved thermal efficiency	[141]

The reviewed studies indicate that hydrogen enrichment generally has a limited impact on boiler efficiency, with most studies reporting variations of less than 2% and, in some cases, improvements of up to 8.8% are reported in condensing boilers. Significant reductions in ${\mathrm{CO}}_2$ emissions are consistently observed, ranging from about 7% for mixtures with 20–23 vol.% ${\mathrm{H}}_2$ to over 55% at high hydrogen fractions. Unlike ${\mathrm{CO}}_2$ emissions, the effect on ${\mathrm{NO}}_x$ emissions remains less consistent. Several studies report reductions of up to 53.9% or ${\mathrm{NO}}_x$ levels as low as 2.7 mg/m³ through optimized burner designs and operating conditions, while others observe increases of up to 167% due to increased flame temperatures. These inconsistencies indicate that emissions are strongly influenced by burner configuration, air excess ratio, and combustion control, rather than solely by hydrogen concentration. Furthermore, differences in boiler type, hydrogen fraction, operating conditions, and measurement methodology limit direct comparison between studies and emphasize the need for standardized experimental procedures and long-term performance assessments.

Table 15. Thermal Efficiency and ${\mathrm{NO}}_x$ Emission Performance of Boilers and Gas-Fired Appliances Operated with Hydrogen-Enriched NG (Hybrid Experimental–Numerical Studies).

Application	${\mathrm{H}}_2$ Content (vol.%)	Efficiency Change	${\mathrm{NO}}_{\mathit{x}}$ Response	Key Findings	Ref.
Domestic condensing boiler	0–35	N/A	Increased tendency	Stable up to 35% ${\mathrm{H}}_2$; CFD predictions agreed with experiments; burner modifications required for pure ${\mathrm{H}}_2$ operation	[140]
Condensing boiler with porous burner	20	∼−5% thermal output	−36.8%	${\mathrm{NO}}_x$ reduced from 19 to 12 mg/kWh while maintaining stable operation	[131]
8 MW fire-tube boiler	0–100	+1.26%	Limited discussion	Reduced exhaust losses and improved thermal efficiency; numerical model validated with experiments	[141]

Table 15. Thermal Efficiency and ${\mathrm{NO}}_x$ Emission Performance of Boilers and Gas-Fired Appliances Operated with Hydrogen-Enriched NG (Hybrid Experimental–Numerical Studies).

Application	${\mathrm{H}}_2$ Content (vol.%)	Efficiency Change	${\mathrm{NO}}_{\mathit{x}}$ Response	Key Findings	Ref.
Domestic condensing boiler	0–35	N/A	Increased tendency	Stable up to 35% ${\mathrm{H}}_2$; CFD predictions agreed with experiments; burner modifications required for pure ${\mathrm{H}}_2$ operation	[140]
Condensing boiler with porous burner	20	∼−5% thermal output	−36.8%	${\mathrm{NO}}_x$ reduced from 19 to 12 mg/kWh while maintaining stable operation	[131]
8 MW fire-tube boiler	0–100	+1.26%	Limited discussion	Reduced exhaust losses and improved thermal efficiency; numerical model validated with experiments	[141]

Beyond the reported benefits in terms of efficiency and emissions, the practical implementation of hydrogen boilers faces several technical challenges. Due to hydrogen’s higher flame speed and wider flammability range, conventional stainless steel natural gas burners may experience flame instability, backfire, and increased ${\mathrm{NO}}_x$ formation at elevated hydrogen concentrations. Furthermore, hydrogen combustion requires modifications to burner geometry, air-fuel mixture control strategies, ignition systems, and safety devices. Material compatibility and the long-term durability of components exposed to hydrogen-rich environments also remain important considerations for large-scale deployment. These challenges indicate that, although hydrogen boilers represent a promising path to decarbonization, further development and standardization are needed to ensure safe and reliable operation.

6.2. Hydrogen-Enriched Liquefied Petroleum Gas

Hydrogen-enriched LPG is mainly used in systems that are not connected to a city gas grid. Enrichment of LPG with hydrogen gives similar results to NG enrichment in terms of boiler efficiency and reduction of ${\mathrm{NO}}_x$ emissions. Demetriou et al. [142] demonstrate in their study that the combustion efficiency of a domestic boiler increases by up to 10%, and CO emissions and unburned hydrocarbon are reduced by 50% to 80%. Studies by Kahangamage et al. [143] and Dostiyarov et al. [144] offer a critical insight into the applicability of hydrogen-enriched LPG for domestic and industrial boilers. Experimentally, it was found that the addition of hydrogen to LPG leads to an increase in the lean burn limit over a wide range of Reynolds numbers, which in turn indicates increased flame stability [143]. This is an essential requirement for domestic gas appliances, as it directly affects safety, combustion efficiency, and operational reliability. Thus, the poor combustion limits are increased by 4% to 7.2% with the addition of 5% hydrogen; the results are due to the higher combustion resistance of the hydrogen and LPG mixtures. A vortex burner system was evaluated in Ref. [144] for the purpose of industrial boilers. The authors found that enriching LPG with hydrogen improved flame stability by 23%, provided that the fuel was injected in a centrally controlled manner. On the other hand, an increase in ${\mathrm{NO}}_x$ emissions was observed, underlining the need to optimise the burner design to achieve a balance between efficiency and environmental compliance.

6.3. Hydrogen Boilers

To achieve climate neutrality by 2050, boilers running on 100% green hydrogen are one of the most promising technologies for the complete decarbonisation of the domestic heating and industrial sectors. Their efficiency is comparable with that of NG boilers [145] in the range of 95% to 98%, based on the lower heating value, for domestic applications. For industrial scale boilers, studies have shown that without specific optimisation, burning 100% hydrogen results in an efficiency reduction of approximately 5% compared with NG. This is due to the difference in flame properties of the two fuels and the reduced radiative heat transfer compared with NG. These imperfections can be overcome by optimising the burner design and the heat exchanger [146].

The main advantage of burning hydrogen is the elimination of carbon emissions released on-site. A major problem with burning hydrogen is nitrogen oxides (${\mathrm{NO}}_x$) emissions due to the high flame temperature of hydrogen. Theoretical modelling shows that under identical conditions, hydrogen combustion produces many times more ${\mathrm{NO}}_x$ than NG boilers [147,148]. Despite these theoretical calculations, real experiments with optimised burner designs show that hydrogen boilers can meet modern ${\mathrm{NO}}_x$ emission standards. Field measurements of prototype hydrogen boilers show ${\mathrm{NO}}_x$ emissions of 10–25 mg/kWh [149], which is within the EU eco-design limit of 56 mg/kWh.

When working with pure ${\mathrm{H}}_2$, the same challenges are faced as when dealing with hydrogen-rich mixtures. Hydrogen embrittlement and high-temperature hydrogen attack compromise the overall structure of the boiler components. Honu et al. [6] performed a detailed analysis of the problem, mainly considering boilers for industrial applications. To mitigate these effects, they focus on the use of hydrogen-compatible materials, such as nickel-based superalloys (e.g., Inconel 625, Hastelloy X, single-crystal PWA 1480E), as well as protective coatings.

A study by Feng et al. [150] investigates how hydrogen affects the mechanical behaviour of Inconel 625, produced by additive manufacturing with arc-welding. Under increased mechanical stress induced by strain, hydrogen accumulates at the material interface via dislocation transport and diffusion, progressively weakening interfacial cohesion. This local hydrogen enrichment reduces the energy required for fracture initiation, delaying failure. These findings underscore the need for microstructural control, particularly in controlling the Laves phase distribution, to improve the hydrogen resistance of additively manufactured nickel-based superalloys. Inconel 625 is used mainly in industrial boilers and demonstration units.

The hydrogen embrittlement behaviour of single-crystal nickel-based superalloy PWA 1480E was studied in the 90s [151,152,153]. These studies confirm that the superalloy retains with excellent strength at high temperature while being highly sensitive to crystallographic orientation, stress concentration, and temperature. These findings underscore that this alloy is suitable for handling hydrogen under extreme conditions, with a pressure of 34 MPa and a temperature of 871 °C, making it highly suitable for turbine development.

Using Hastelloy X, Hasegawa et al. [154] reported that smooth surfaces retained their mechanical integrity at a pressure of 30 MPa ${\mathrm{H}}_2$ at 449.85 °C, whereas notched surfaces exhibited embrittlement due to local stresses from hydrogen retention. Ageing has also been found to increase sensitivity. Hastelloy X finds application in industry at moderate pressures, provided that microstructural ageing and stress concentration are carefully controlled. For domestic boilers working with 100% ${\mathrm{H}}_2$, stainless steel (304/316L) is mainly used as their application is limited to 100 °C and a working pressure of 3 barg. The cost of stainless steel is 5–20 times lower than nickel-based superalloys.

6.4. Hydrogen-Fuelled Internal Combustion Engine-Driven Heat Pumps

Gas engine-driven heat pumps (GEHPs) have been commercially available for over three decades, with widespread adoption in East Asia—particularly in Japan and South Korea—and increasing interest in parts of Europe, including Italy and Germany. These systems, traditionally powered by NG or LPG, are recognised for their ability to deliver high heating capacities, reduce peak electrical loads, and utilise waste heat from the internal combustion engine. Their performance advantages are especially evident in commercial and industrial sectors, where full electrification is not possible due to infrastructure or load characteristics. Studies such as those by Pawela et al. [155], Hepbasli et al. [156] and Zhao et al. [157] emphasise the high performance energy ratios (PER > 1.0) and economic viability of GEHPs under optimised operating conditions. Despite these advantages, GEHPs currently account for only a minor share—estimated at 2–5%—of the total heat pump market in Europe. This limited penetration is largely attributable to policy frameworks favouring full electrification and subsidies supporting electric heat pump deployment [158].

Despite growing interest in hydrogen as a clean energy vector, its direct application as a fuel in gas engine-driven heat pumps remains entirely theoretical in the current literature. Only Roselli et al. [159] explicitly address hydrogen, and even then only as a prospective component of future gas blends. No source offered experimental validation, technical specifications, or quantitative performance data for hydrogen-fuelled variants. Current discourse predominantly focuses on indirect integration pathways, such as Power-to-Gas (P2G) strategies and the Sabatier process, wherein hydrogen is converted to synthetic methane for use in conventional systems. Such approaches imply a near-term preference for hydrogen blending over the development of dedicated hydrogen-fuelled gas engine configurations [159].

Critical challenges include the redesign of internal combustion engines to handle hydrogen’s high flame speed and risk of pre-ignition, the integration of advanced safety systems for storage and handling, and the absence of a dedicated hydrogen distribution network. Notably, none of the sources reviewed provides a techno-economic assessment comparing hydrogen-fuelled GEHPs with conventional gas heat pumps, leaving questions of cost-competitiveness and deployment feasibility unresolved. Moreover, no systems were identified as commercially available, indicating a low technological readiness level for this configuration. Although projections from the EU anticipate that hydrogen will comprise approximately 27% of renewable gas by 2030, the current lack of demonstration projects and commercial momentum suggests that hydrogen-fuelled GEHPs are unlikely to be deployed at scale in the near term without substantial research and development investments and policy realignment [155,156,159].

Overall, the lack of experimental data, prototype development, and technical-economic assessments highlights a significant gap in scientific research. Future work should prioritise pilot demonstrations and comparative performance analyses to determine whether hydrogen-powered GEHPs can be a reliable addition to zero-emission on-site building technologies.

7. Critical Outlook and Research Gaps

Despite the considerable progress achieved in recent years, the application of hydrogen in combustion systems remains associated with several unresolved scientific and engineering challenges [40,41]. The reviewed literature shows that hydrogen combustion and hydrogen-enriched natural gas (HENG) should not be interpreted as fully compatible replacements for conventional hydrocarbon fuels. Instead, their feasibility is strongly dependent on the combustion device, burner architecture, air–fuel control strategy, hydrogen fraction, operating load, heat-transfer regime, and safety infrastructure [4,160,161,162]. This is particularly important for residential boilers, domestic water heaters, cookers, gas turbines, and industrial boilers, where existing systems were designed for natural gas and not for fuels with higher laminar burning velocity, wider flammability range, lower ignition energy, and higher diffusivity. In this context, the main research challenge is not only to determine whether hydrogen can be combusted but to define application-specific operating envelopes in which efficiency, emissions, flashback resistance, flame stability, material durability, metering accuracy, and user safety can be guaranteed simultaneously [4,68,131,160].

A first critical gap concerns the absence of universal hydrogen blending limits for existing residential and commercial combustion appliances. Several studies report satisfactory operation at moderate hydrogen fractions, but the acceptable limit varies significantly between devices. For example, partially premixed gas water heaters have been reported to require hydrogen fractions below 20% because hydrogen addition increases combustion temperature and can slightly increase ${\mathrm{NO}}_x$ emissions [161]. On the other hand, porous-media or specifically adapted domestic water heater and boiler configurations have shown improved pollutant performance at around 20% ${\mathrm{H}}_2$, including reductions in CO, ${\mathrm{NO}}_x$, and ${\mathrm{CO}}_2$ under certain operating conditions [131,162]. Recent condensing-boiler experiments further indicate that, when advanced combustion control is used, blends up to 50% ${\mathrm{H}}_2$ may be possible with improved efficiency and very low ${\mathrm{NO}}_x$ emissions in selected boiler configurations [68]. However, other studies on domestic boilers and appliances report ${\mathrm{NO}}_x$ increases, flashback concerns, or reduced thermal power at similar or lower hydrogen fractions [4,67,140]. Therefore, future research should not aim to establish a single “safe hydrogen percentage” for all appliances. Instead, it should classify hydrogen tolerance according to burner type, premixing mode, injector geometry, combustion-chamber heat transfer, excess-air ratio, load modulation range, ignition system, and flame-detection method.

The contradiction in ${\mathrm{NO}}_x$ trends is one of the most important unresolved scientific issues. In some studies, hydrogen enrichment increases flame temperature and promotes thermal ${\mathrm{NO}}_x$ formation, whereas in others, ${\mathrm{NO}}_x$ decreases because of shorter residence time, leaner operation, stronger heat transfer to walls, porous-media heat recirculation, or improved combustion control [68,73,131,139,161]. This means that the ${\mathrm{NO}}_x$ response cannot be predicted from the hydrogen fraction alone. Future studies should therefore isolate the effects of adiabatic flame temperature, local hot-spot formation, residence time, equivalence ratio, dilution, burner surface temperature, radiation losses, and heat-exchanger coupling. Particular attention should be given to the development of ${\mathrm{low-NO}}_x$ hydrogen-ready burners, including staged combustion, porous-media combustion, mixing concepts, MILD combustion, and adaptive air–fuel control strategies [68,139,163]. Without this distinction, the literature will continue to produce apparently conflicting results, making it difficult to formulate reliable design rules for hydrogen-ready boilers and burners.

Industrial heating applications introduce a second group of unresolved problems. Field and numerical studies on gas-fired industrial boilers show that hydrogen blending can increase flame speed and extend combustion limits, but the practical benefits remain strongly dependent on operating conditions [73,139]. In one real boiler field study, hydrogen fractions up to nearly 10% were associated with simultaneous decreases in thermal efficiency and ${\mathrm{NO}}_x$ emissions, indicating a direct trade-off between energy performance and pollutant reduction [73]. Other modelling work suggests that increasing hydrogen content can reduce CO while increasing flame temperature and ${\mathrm{NO}}_x$, with approximately 10% ${\mathrm{H}}_2$ identified as an optimal compromise under the investigated conditions [139]. Lean industrial combustor tests have also shown stable operation at hydrogen fractions of 23–35 vol%, but the tests were short in duration and therefore cannot be considered sufficient evidence for long-term industrial deployment [163]. These results show that industrial HENG operation must be evaluated under realistic duty cycles, including start-up, shutdown, load variation, fouling, maintenance conditions, air preheating, excess-air control, and seasonal operation.

The durability of industrial boiler components remains a major gap, the third one, that is often underestimated in combustion-focused studies. Hydrogen-rich combustion affects not only the flame but also the long-term integrity of pressure parts, heat exchangers, welds, fasteners, tubes, and auxiliary systems. Critical boiler components can operate at pressures of approximately 15.5–27.0 MPa and temperatures of 300–540 °C, while hydrogen-rich combustion may locally increase metal temperatures and hydrogen exposure [6]. Under such conditions, hydrogen embrittlement, high-temperature hydrogen attack, weld-zone degradation, coating failure, and time-dependent fracture risks become central issues. Current evidence indicates that material compatibility is not yet sufficiently established for retrofitting existing industrial boilers to high-H₂ operation [6]. Future work should therefore combine combustion testing with metallurgical assessment, including weld heat-affected zones, post-weld heat treatment, protective coatings, crack-growth behaviour, non-destructive inspection methods, and remaining-life assessment under realistic hydrogen partial pressures and thermal cycling.

The fourth research gap concerns the limited validation of numerical models for hydrogen-rich combustion. Computational fluid dynamics (CFD) is widely used to evaluate temperature fields, flame shape, heat transfer, combustion efficiency, and pollutant formation, but the reliability of CFD predictions remains constrained by turbulence–chemistry interaction models, radiation models, chemical kinetic mechanisms, wall heat-transfer treatment, and pollutant sub-models [7]. This is especially important for ${\mathrm{NO}}_x$ prediction, since thermal NO, prompt NO, N₂O-intermediate, and NNH pathways may contribute differently depending on hydrogen fraction, dilution level, equivalence ratio, pressure, temperature, and combustion regime [7]. Existing methane-based or simplified mechanisms may not be sufficiently accurate for high-hydrogen mixtures, particularly when differential diffusion and high flame speeds become important. Fundamental experimental data are also incomplete for ignition delay, laminar burning velocity, extinction limits, and pollutant formation over the combined pressure, temperature, and composition ranges relevant to appliances and boilers [164]. Future modelling work should therefore move from isolated CFD case studies toward open benchmark datasets, validated multi-physics simulations, uncertainty quantification, and model comparison across identical test cases.

Gas-grid integration represents the fifth major barrier. Hydrogen blending in existing natural gas networks is often presented as a transitional route for reducing carbon intensity, but the technical and regulatory evidence shows that grid readiness cannot be reduced to pipeline transport alone [9,165,166]. Hydrogen addition changes gas density, Wobbe Index, volumetric energy content, flow velocity, pressure losses, leakage behaviour, and end-use appliance performance. It also introduces concerns related to embrittlement, seals, valves, compressors, pressure regulators, and gas-quality control [9]. Fiscal and metrological issues are particularly important because existing natural gas meters were not necessarily designed for hydrogen–natural gas mixtures. Recent metrological studies show that evidence on the readiness of installed flow meters remains fragmented, despite analyses involving large numbers of meters in European gas networks [165,166]. Therefore, future HENG deployment requires coordinated research on gas composition monitoring, billing accuracy, meter recalibration, appliance certification, pipeline integrity, leakage detection, and harmonized regulatory limits.

Hydrogen safety remains the sixth critical engineering gap for combustion-based applications. In addition to flashback and flame instability, hydrogen-rich operation introduces risks related to leakage, accumulation in confined spaces, low ignition energy, wide flammability limits, and the compatibility of valves, seals, sensors, and safety shut-off devices [4,9,160,167]. Therefore, future research should not only evaluate burner performance but also validate complete safety chains, including leak detection, ventilation effectiveness, sensor response time, flame supervision, automatic shut-off logic, and emergency operating procedures under realistic appliance, boiler-room, and gas-grid conditions.

Taken together, the main research priority is to move from proof-of-concept demonstrations toward validated, durable, infrastructure-compatible, operationally reliable, and safely deployable hydrogen combustion systems. In the short term, priority should be given to standardized appliance and boiler test protocols, open CFD validation datasets, gas-meter readiness studies, realistic leak-dispersion tests, and long-duration field trials. In the medium term, research should focus on hydrogen-ready burner redesign, ${\mathrm{low-NO}}_x$ control strategies, material qualification, pressure-part integrity, and digital combustion supervision. In the long term, hydrogen combustion should be evaluated as part of integrated energy systems, where its role is compared with electrification, heat pumps, hybrid heating, seasonal storage, hydrogen-assisted solid-fuel combustion, and other low-carbon fuels. Only by addressing these combined scientific, engineering, infrastructural, safety, and regulatory gaps the hydrogen combustion can be assessed realistically as a component of future decarbonized heating and industrial energy systems.