Turning Surplus Renewable Power into Bio-SNG: What Models Reveal About Efficiency

A sweeping new review published in Discover Biotechnology has mapped, for the first time in detail, how researchers around the world are modelling the marriage of two clean-energy technologies that could help solve one of the most stubborn problems of the renewable transition: what to do with all the surplus electricity that wind turbines, solar farms and hydropower plants generate when the grid cannot absorb it. The study, led by Mohadeseh Naderi of Dundalk Institute of Technology together with Anthony Reynolds of Technological University Dublin and Wayne Doherty of Dundalk, systematically examined decades of modelling studies that combine power-to-gas technology with biomass gasification to produce bio-synthetic natural gas, or Bio-SNG, a renewable substitute for fossil natural gas that can be injected directly into existing pipelines.

The core idea is elegantly simple in principle. When renewable electricity floods the grid and prices collapse, electrolysers can split water into hydrogen and oxygen. Rather than storing that hydrogen directly, which is hampered by hydrogen’s low volumetric energy density and its tendency to leak through even metal pipelines, the gas can be reacted with carbon monoxide and carbon dioxide contained in the producer gas generated by gasifying biomass. In the presence of a nickel-based catalyst, this methanation reaction yields methane, chemically identical to the natural gas already flowing through national grids. The result is a seasonal energy store of almost unlimited scale, using infrastructure that already exists, while simultaneously recycling biogenic carbon that would otherwise escape to the atmosphere.

The review found enormous variation in how efficiently this chain of conversions performs on paper. Reported Bio-SNG production efficiencies ranged from a disappointing 26 percent to a striking 86.4 percent on a lower heating value basis, reflecting stark differences in gasifier type, feedstock, and the sophistication of system integration. The standout performers were dual fluidised bed gasifiers, which indirectly heat the biomass with steam rather than burning it directly with air, operated in a thermal sweet spot of 750 to 850 degrees Celsius. At these moderate temperatures, exemplified by studies modelled on the landmark GoBiGas plant in Sweden and the Güssing facility in Austria, researchers consistently reported efficiencies above 80 percent. By contrast, oxygen-blown and entrained flow gasifiers operating at temperatures approaching 1,300 degrees Celsius often delivered substantially lower returns, sometimes falling below 40 percent.

Technological preferences across the literature were strikingly clear. Of the studies analysed, dual fluidised bed and circulating fluidised bed gasifiers dominated, largely because they produce nitrogen-free product gas of a quality suitable for methanation while achieving high efficiency at medium scale. On the methanation side, the TREMP process, a multi-stage fixed-bed catalytic design with interstage cooling, appeared in seven studies as the workhorse configuration. When it came to electrolysis, the solid oxide electrolysis cell, or SOEC, was the most frequently modelled technology, followed by mature alkaline electrolysers and the faster-responding polymer electrolyte membrane units. SOECs appeal to modellers because they can exploit high-temperature heat recovered elsewhere in the plant, boosting overall conversion efficiency and lowering operating costs compared with low-temperature alternatives.

One of the review’s most valuable contributions is its dissection of system integration strategies. The authors classified plant layouts by where electrolytic hydrogen is injected and how oxygen reaches the gasifier. The most popular arrangement, adopted in nine studies, adds electrolytic hydrogen into the main methanation stage after a pre-methanation step, while the co-produced oxygen supports gasification, often with buffering storage. This proved something of a design sweet spot: injecting hydrogen early shifts both carbon monoxide and carbon dioxide toward methane, raising carbon utilisation and reducing the burden of carbon dioxide removal, but it demands rigorous heat management because methanation is strongly exothermic. Adding hydrogen later simplifies thermal control yet pushes a larger carbon dioxide separation problem upstream. Roughly equal numbers of studies explored variants relying on air separation units or hybrid oxygen supplies.

The methodological landscape tells its own story. Equilibrium models based on Gibbs free energy minimisation, implemented overwhelmingly in the Aspen Plus simulation environment using the ubiquitous RGibbs reactor block, accounted for 17 of the 27 studies reviewed. These models compute the theoretical end-state of reactions and are computationally cheap, making them attractive for rapid screening of plant concepts. However, they ignore reaction kinetics, catalyst behaviour, and temperature gradients, which means they can flatter real-world performance. A minority of ten studies adopted hybrid kinetic-equilibrium frameworks, pairing equilibrium gasification with kinetic sub-models for methanation, and these delivered more realistic predictions in multi-stage systems where heat removal and reaction rates genuinely constrain methane yield. Only one study in the entire corpus, work by Di Salvo and Wei on industrial decarbonisation in California, went beyond zero-dimensional black-box modelling to include a one-dimensional spatial description.

Validation emerged as a recurring weakness that the review’s authors flag as a serious barrier to commercialisation. Only a minority of the modelled systems were benchmarked against pilot-scale or industrial data. Notable exceptions include the Menin and colleagues studies, which anchored their gasification models to experimental data from the Güssing plant, and the Al Zakwani work, which achieved deviations below 5.5 percent for major gas species against the historic ADAM I methanation project. Many other studies relied purely on literature comparisons or theoretical consistency checks, leaving real confidence in their absolute efficiency claims difficult to establish. Compounding the problem, system boundaries and efficiency definitions varied wildly between papers, with only one study explicitly clarifying whether reported figures were net of the plant’s own auxiliary power consumption for oxygen production and gas compression.

Perhaps the most glaring gap concerns the very reason power-to-gas exists in the first place. Nearly all reviewed models assumed steady-state operation, yet the input electricity from wind and solar is inherently volatile. Only the Rivarolo and Massardo study performed a year-long, time-dependent thermo-economic simulation, and only the Katla work explicitly analysed buffer storage of hydrogen and oxygen alongside three distinct operating states, from abundant renewable input to a fallback mode where gas is diverted to combined heat and power when the wind stops blowing. The review argues that dynamic simulation capturing start-up, shutdown and fluctuating hydrogen supply is central to assessing power-to-gas viability, and that flexible methanation reactors and appropriately sized hydrogen buffers must become standard elements of future models rather than afterthoughts.

The authors conclude that the modelling foundation for power-to-gas integrated with biomass gasification is strong but incomplete, and they set out a clear research agenda: validated kinetic models for both gasification and methanation, dynamic simulations reflecting genuine renewable input profiles, techno-economic assessments that incorporate carbon pricing and declining electrolyser costs, and operational strategies for managing variable hydrogen supply. Several megawatt-scale demonstration plants producing Bio-SNG have already operated in Denmark, Sweden, Germany and France, and European pilot projects have shown that the approach can balance coupled electricity and gas networks. If the modelling community can close the validation and dynamics gaps, the dream of storing a summer’s worth of surplus sunshine and wind as pipeline-grade renewable methane, closing the carbon cycle in the process, could move from simulation screens to commercial deployment in decarbonised energy networks.

Subject of Research: Modelling of power-to-gas energy storage systems integrated with biomass gasification for bio-synthetic natural gas production

Article Title: A review on modelling of power-to-gas energy storage integrated with biomass gasification

Article References: Naderi, M., Reynolds, A., & Doherty, W. (2025). A review on modelling of power-to-gas energy storage integrated with biomass gasification. Discover Biotechnology, 2(1), Article 36. https://doi.org/10.1007/s44340-025-00045-8

Image Credits: AI Generated

DOI: 10.1007/s44340-025-00045-8

Keywords: power-to-gas, biomass gasification, Bio-SNG, methanation, electrolysis, dual fluidised bed, renewable energy storage, SOEC, process modelling, synthetic natural gas, energy transition, Aspen Plus