Techno-Economic Assessment and Optimisation of Self-Sufficient Biomethane Systems for Regional Decarbonisation

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🔬研究者:Provides a nonlinear programming framework for optimizing biomethane island design, integrating technical, economic, and environmental constraints.

🏢実務担当者:Demonstrates feasible business models for gas network operators and biogas plant developers, highlighting the trade-offs between profitability and emissions.

🏛政策担当者:Offers evidence for reforming renewable gas subsidies (e.g., removing capacity caps, rewarding carbon intensity) to unlock cost-effective decarbonization.

Existing gas network infrastructure are important national energy assets, transporting mostly fossil-derived natural gas to end-users. Biomethane, methane derived from anaerobic digestion (AD) of organic matter, presents a potential route to replace fossil fuels with home-grown renewable gas. Combined with carbon capture and storage (CCS) of the CO2 in the biogas potentially results in carbon negative energy. This work seeks to understand the feasibility of operating a part of the gas network isolated from the main natural gas network fully on biomethane in Scotland. We present an integrated techno-economic optimisation framework for designing self-sufficient biomethane islands, applied to the Inverness network. The model, implemented as a nonlinear program (NLP), maximises annual net profit from biomethane sales and Green Gas Support Scheme (GGSS) tariffs subject to practical constraints such as GGSS-compliance of =50 % waste-derived biomethane, seasonal supply, land/scale, demand balancing with centralised liquefied natural gas (LNG) storage, and a life-cycle global warming potential (GWP) metric. Three archetypes are analysed: Type A (crop-dominated, manure co-digestion), Type B (food/industrial wastes, grass/manure support), and Type C (distillery residues + grass/manure). In Inverness, feasible solutions include: Type A (2 large ~92, 000 m³ digestion plants at ~23 ha/site producing 97.39 Mm³ y^-1 of gas; net revenue £13.4 M y^-1; GWP ~42.2 ktCO2e/y), Type B (1 ~97, 000 m³ plant at ~24 ha, producing 48.69 Mm³ y^-1 gas; net revenue £9.4 m y^-1; GWP ~48.0 ktCO2e/y), and Type C (2 large ~110, 000 m³ plants at ~27 ha, producing 97.4 Mm³ y^-1 of gas; net revenue £13.0 m y^-1; GWP ~47.2 ktCO2e/y). Type B is most profitable per unit capacity due to gate-fee feedstocks but carries higher GWP (mostly from grass-silage cultivation). The model balances a combination of dynamic feeding of different recipes with using a centralised LNG storage to buffers seasonal deficits and maximise asset utilisation; optional CO2 liquefaction (~87.7 kt y^-1 per large site at ~151 kWh t^-1) enables near/net-negative operation under low-carbon power. Our results find that the business model is feasible for Inverness and highlight the value of systems thinking and the need for policy reform (particularly lifting the 250 GWh y^-1 cap for GGSS and rewarding carbon intensity rather than just waste-derived methane) to unlock larger, efficient, low-emission regional systems.

• crossref https://doi.org/10.69997/sct.198589first seen 2026-06-20 06:42:50 · last seen 2026-06-21 05:31:52