Hydrogen and Biogas Could Replace Nearly 40% of Natural Gas by Volume, but There’s a Trade-Off

The future of gas infrastructure may depend less on replacing natural gas with a single clean alternative than on finding combinations of fuels that existing networks can accommodate. Hydrogen and biogas, commonly pursued through separate decarbonization strategies, could become more useful when their contrasting physical properties are deliberately combined. Yet the opportunity comes with significant questions about gas quality, safety, transport capacity and economic viability.

A new study titled "Hydrogen–Biogas Co-Blending for Low-Carbon Gas Systems," published in the journal Gases, examines whether hydrogen and partially treated biogas can jointly reduce natural gas dependence without requiring complete biogas upgrading. Conducted by Michele Francesconi and Carlo Carcasci of the University of Florence, the research identifies a promising middle ground between conventional fossil gas networks and ambitious renewable gas substitution.

The findings reveal that combining hydrogen with biogas containing 75% methane could accommodate nearly 40% renewable gas by volume under moderately relaxed modeling constraints. However, the same analysis demonstrates why maximizing renewable content is not necessarily the most practical decarbonization strategy. Higher substitution creates substantial penalties involving energy content, pipeline throughput and costs, exposing the engineering limits of conventional gas infrastructure.

The Overlooked Advantage of Keeping Carbon Dioxide in Biogas

Biogas has traditionally occupied an awkward position in gas network decarbonization. Produced from agricultural, agro-industrial and municipal residues, it offers a locally available energy resource, but its carbon dioxide content makes direct injection into conventional gas networks difficult. Upgrading removes carbon dioxide and produces methane-rich biomethane, although the process requires specialized equipment, additional energy and considerable investment.

These requirements disproportionately affect smaller producers. European biogas and biomethane production reached approximately 22 billion cubic metres in 2024, according to figures cited in the research, but only 5.2 billion cubic metres underwent upgrading. The difference illustrates the potential relevance of technologies capable of accommodating biogas without complete methane enrichment.

The researchers challenge the conventional treatment of carbon dioxide as an exclusively undesirable component. Although it reduces biogas heating value, carbon dioxide also modifies combustion behaviour in ways that could complement hydrogen. Hydrogen has low density and high reactivity, whereas carbon dioxide increases mixture density while moderating certain ignition characteristics.

Combining the two creates an opportunity to balance their disadvantages. Hydrogen partly offsets the density increase associated with carbon dioxide-rich biogas, while carbon dioxide reduces some of the ignition sensitivity associated with hydrogen. Rather than requiring either fuel to satisfy conventional gas specifications independently, the approach evaluates whether their combined composition can produce more acceptable operating characteristics.

The study investigates mixtures containing natural gas, hydrogen and two representative biogas qualities: one with 75% methane and another with 55%. A nonlinear optimization framework evaluates heating value, gas interchangeability, density and combustion indicators while pursuing either minimum fossil gas content or maximum hydrogen incorporation.

The resulting trade-offs remain important. Carbon dioxide cannot eliminate hydrogen's wider flammability characteristics, and combining the gases reduces volumetric energy content. Nevertheless, their partially compensating properties create blending possibilities that conventional hydrogen-only strategies would overlook.

Nearly 40% Renewable Gas, but Only Within a Wider Operating Envelope

Under the study's conventional reference constraints, binary natural gas–hydrogen blending permits approximately 1.8% hydrogen by volume. Introducing biogas raises the renewable share to roughly 9.6% for methane-lean biogas and 16.9% for methane-rich biogas, demonstrating that three-component blending expands the modeled feasible composition range.

The largest improvement emerges when the researchers hypothetically relax selected admissibility bounds by 10%. With higher-quality biogas, the optimized mixture contains approximately 37% biogas, between 2.5% and 2.8% hydrogen, and about 60% natural gas. Renewable gas consequently approaches 40% by volume, representing approximately 32% of the mixture's energy content.

Methane-lean biogas delivers a smaller but meaningful substitution opportunity. Under the same relaxation scenario, renewable content reaches approximately 23.5% by volume, comprising around 20.8% biogas and 2.7% hydrogen. Its higher carbon dioxide concentration makes blending more restrictive, although hydrogen helps counterbalance the resulting density increase.

These findings demonstrate how biogas quality shapes decarbonization potential. Methane-rich feedstocks permit greater substitution, while methane-lean streams require more careful balancing between energy content, density and combustion characteristics. Neither outcome establishes unrestricted compatibility with existing gas networks.

The 10% relaxation represents a mathematical adjustment to the model's operating envelope, not an authorized relaxation of regulatory standards. The researchers deliberately exclude the conventional carbon dioxide concentration limit as a binding constraint, meaning the optimized mixtures cannot automatically qualify for injection under existing network specifications.

More aggressive scenarios expose another limitation. Complete natural gas displacement requires a 34% relaxation for methane-rich biogas and 56% for methane-lean biogas. Although mathematically achievable, these mixtures depart substantially from conventional gas-quality characteristics.

The findings distinguish maximum theoretical substitution from credible near-term operation. Moderate renewable penetration offers a comparatively balanced outcome, whereas eliminating natural gas entirely produces compositions that would demand substantially greater infrastructure adaptation.

Lower Emissions Come With Higher Costs and Transport Demands

Gas composition is only one determinant of feasibility. Networks must transport sufficient energy under changing demand, and fuels with lower volumetric heating values require larger quantities of gas to deliver equivalent energy.

The researchers examine this challenge through a 20-kilometre pipeline simulation operating under repeated demand fluctuations. At the moderately relaxed blending level, average gas velocity rises by approximately 12% compared with pure natural gas, while maximum mass throughput increases by around 24%–25%.

Pressure remains stable within the simplified pipeline configuration, suggesting manageable hydraulic behaviour under the modeled conditions. However, increased throughput is not negligible, particularly because real networks contain compressors, elevation changes, interconnected pipelines and variable operating requirements absent from the simulation.

The picture deteriorates under complete fossil gas substitution. In the most demanding methane-lean scenario, average velocity more than doubles, while maximum mass flow rises by approximately 166%. Such increases demonstrate how lower energy density can translate into substantial transport burdens even when the modeled pressure response remains acceptable.

Environmental performance introduces another trade-off. At the moderate relaxation level, methane-rich blending reduces modeled greenhouse gas intensity by approximately 7.8%, while methane-lean blending achieves a 3.6% reduction relative to the natural gas benchmark.

These reductions carry additional commodity costs. Methane-rich blending raises the modeled cost by approximately 8%, compared with roughly 4% for methane-lean blending. The corresponding carbon abatement costs are approximately €290 and €310 per tonne of carbon dioxide equivalent.

More extensive substitution delivers larger greenhouse gas reductions, but the additional benefits come alongside increasing economic and hydraulic penalties. Hydrogen production costs play an important role in these calculations, while results also depend on assumed emissions factors and production pathways.

The economic assessment excludes investment in blending equipment, injection facilities, monitoring systems and associated infrastructure. Consequently, its cost estimates cannot be interpreted as comprehensive project costs or definitive evidence of commercial competitiveness.

The distinction between renewable volume and renewable energy is equally important. Hydrogen's low volumetric heating value means that a large renewable share by volume does not translate into an equivalent share of delivered energy. Measuring decarbonization exclusively through gas volume would therefore overstate the energy contribution of certain mixtures.

The Real Opportunity Lies in Adaptable Networks, Not Maximum Substitution

The research introduces a different perspective on gas infrastructure development. Instead of treating hydrogen injection and biogas upgrading as separate technological pathways, it considers gas composition as an engineering variable that can be optimized according to network constraints.

This approach could be relevant to smaller biogas facilities whose production volumes make complete upgrading economically difficult. Pre-treated biogas may offer alternative opportunities if local networks can accommodate its composition and operators can reliably control blending conditions.

However, partial treatment remains essential. Hydrogen sulphide, moisture and other contaminants must be removed or controlled before network injection. Avoiding carbon dioxide separation does not eliminate gas conditioning requirements or infrastructure safety obligations.

For network operators, the findings support evaluating gas quality, combustion behaviour and hydraulic performance together. A composition that performs favourably against one indicator may introduce difficulties elsewhere, making isolated assessments insufficient for operational decisions.

Regulators face a related challenge. Greater compositional flexibility could support renewable gas integration, but altered standards would require rigorous technical evidence. The study's combustion calculations are screening indicators, not validated explosion-safety margins, and cannot establish safe operation across different appliances and network configurations.

Several unanswered questions therefore remain. Experimental combustion testing, real-network simulations and detailed assessments of pipeline materials, compressors and end-use equipment are necessary before broader deployment can be considered. Commercial evaluations must also incorporate project-specific costs and variations in hydrogen production and biogas feedstocks.

For regions with agricultural residues and distributed biogas production, the approach offers a possible direction for renewable gas planning. Its applicability, however, depends on local infrastructure, gas specifications, feedstock characteristics and the economics of alternative energy uses.