Biomethane Injection Research Articles

Substitution of Natural Gas by Biomethane: Operational Aspects in Industrial Equipment

Global gas markets are changing as natural gas (NG) is replaced by biomethane. Biomethane is produced by upgrading biogas, which can have a molar concentration of methane to over 98%. This renewable energy has been injected into the pipeline networks of NG, which offers the possibility to increase its usage in industrial and residential applications. However, the expectation of the increase in biomethane proportion on the NG grids could increase the fluctuations on the composition of the NG–biomethane mixture in amplitude and frequency. In this context, the injection of biomethane into the existing network of NG raises a discussion about the extent to which variations in gas quality will occur and what permissible limits should exist, as variations in combustion characteristics can affect the operation of the combustion processes, with consequences for consumers, distributors and gas producers. This study describes a gas quality analysis with regard to the use of biomethane in industrial equipment, mixed or not mixed with NG, taking into account the indicators for gas interchangeability and provides a discussion on the necessary gas quality level to be achieved or maintained for efficient combustion in equipment originally designed to operate with NG. NG and biomethane real data collected for 92 consecutive days in 2022 and provided by two different companies in Brazil were used for this study. It is shown that the maximum deviation of the Wobbe Index (WI) of 5%, which is allowed for industrial plants, does not work for the operation of furnaces at temperatures of 1200 °C or more. In addition, it is shown that the WI, as defined in relation to the calorific value of the fuel, may allow inappropriate substitution of fuel gases, which is likely to reduce the range of blending of biomethane in NG pipelines. The results can be assessed to analyze how the addition of biomethane to NG grids will impact the WI and the equipment operation parameters such as the air-to-gas ratio, products-to-gas ratio, adiabatic flame temperature and furnace temperature.

Smart Gas Network with Linepack Managing to Increase Biomethane Injection at the Distribution Level

The current situation in Europe calls for the need of urgent measures to find sustainable alternatives to its outer dependence on natural gas. Biomethane injection into the existing gas infrastructure is a fundamental opportunity to be promoted that, however, causes increasing complexities in the management of natural gas grids. At the gas distribution level, the lack of a monitoring system and suitable software for the simulation, management, and verification of gas networks may act as barriers to a widespread diffusion of a biomethane production and injection chain. A transient fluid-dynamic model of the gas network is developed to perform estimations of the natural gas grid capacity in situations of production-consumption mismatch, taking into account the linepack as a gas buffer stock. The model is applied to the gas distribution network of a small urban-rural area. The aim is to assess the role of the linepack in determining the gas network receiving capacity and to test smart management of pressure set-points and injection flow rate to minimize biomethane curtailment. Results show that biomethane unacceptability can be reduced to 10% instead of 27% (obtained when following the DSOs state-of-the-art current procedures), thus highlighting the importance of the implementation of transient simulation software but also underlining the need for smarter control systems, actuators, and data management platforms for a transition to smart digital gas grids.

Energy generation potentials from agricultural residues: The influence of techno-spatial restrictions on biomethane, electricity, and heat production

Agricultural biogas production is subject to various spatial restrictions including legislation, biomass availability, transport, and the distribution of final energy products. This study introduces a geographic information system (GIS)-based approach for a comprehensive techno-spatial assessment of the above-mentioned factors, which was tested for Switzerland. First, spatial criteria were identified based on an extensive literature review that was complemented by expert knowledge. Then, quantitative GIS-based methods were developed to identify suitable areas for biogas production. Finally, a location- allocation algorithm was used to estimate national production potentials of biogas, electricity, heat, and biomethane and to assess the relevance of greenhouse gas (GHG) emissions from biomass transport. Maximum production potentials for electricity, heat, and biomethane were found to be in the order of 6.3, 8.5, and 13.8 PJ per year, respectively. Heat utilization and biomethane injection are often limited to areas in proximity of settlements. Furthermore, biogas production potentials varied depending on legal, economic, and technological factors. Particularly the utilization of excess heat from combined heat and power (CHP) plants was found to react very sensitive to altering spatial constraints due to its dependency on local demand. Resulting emissions from biomass transport were in the order of 0.5–0.8 kgCO2-eq per gigajoule of produced biogas, which is negligible compared to benefits from agricultural biogas production. The modeling results therefore suggest that attention should rather be concentrated on biomass utilization, plant efficiency, and optimal energy utilization when aiming to optimize GHG efficiency. Overall, the findings support the strategic planning of practitioners and authorities for the future development of agricultural biogas production. Moreover, the presented methodology can be transferred to different spatial and technological contexts.

The gas grid as a vector for regional decarbonisation - a techno economic case study for biomethane injection and natural gas heavy goods vehicles

This paper presents a novel method for incorporating the seasonal variations in gas demand into an assessment of the economic viability of a biomethane production and injection facility. A simulation of a gas distribution (Dx) network was built to investigate the impact of limits imposed by the gas network operator on the quantity of biomethane that can be injected. The results calculated the grid’s capacity to accept biomethane on an hourly basis over the course of a year. Scenarios of maximum, minimum and no demand at a Dx-connected compressed natural gas (CNG) filling station were computed for the 3 potential locations being investigated for the biomethane production and injection facility. This data was then used to determine a range of possible plant sizes for each potential facility location and CNG demand scenario. Next, a spatially explicit geographical information systems (GIS) model was created to map the distribution of feedstock suitable for biomethane production in the surrounding area and determine transportation distances. These two submodels fed into a techno-economic model that calculates the net present value (NPV) and levelised cost of energy (LCOE) for each configuration. Notably, the profitability of the plant was seen to increase proportionally with an increase in demand at the CNG filling station. Location 2 was determined to be the most economically viable site for the biomethane production and injection facility. The most economically competitive configurations resulted in an LCOE of 81.63 €/MWh, 83.59 €/MWh, and 83.73 €/MWh, with corresponding NPVs of M€ 9.56, M€ 3.98 and M€ 0.94, for maximum, minimum and no demand at the CNG filling station respectively. The most competitive configurations are achieved at a plant size of 115 GWh/a for the maximum CNG demand, 82.2 GWh/a for the minimum CNG demand, and 81.8 GWh/a for no CNG demand replacing 40%, 34%, and 35% of annual natural gas demand in the Dx network respectively.

Optimisation of energy usage and carbon emissions monitoring using MILP for an advanced anaerobic digester plant

This paper proposes a realistic model for energy and carbon management of an advanced municipal wastewater treatment works. Through minimisation of total cost of operations, it provides operators with a visual daily operational schedule based on varying tariffs. This site is the first in the UK with a mixed operational strategy for biomethane produced on site: to burn in CHP (Combined Heat and Power) engines to create electricity, burn in Steam Boilers for onsite steam use or inject the biomethane into the gas distribution network - Natural Gas can be imported to make up shortfalls in biomethane if required. Implemented using a novel mixed integer linear programming (MILP) approach, results indicate that biomethane injection should be maximised for the highest financial gain - the driving force for optimising the remaining operations being the site electricity imports and whether the electricity imported ‘generates’ carbon emissions. Based on the source of electricity and the new carbon emissions performance criteria, under the current operational strategy importing electricity from carbon-based sources has no tangible impact on site revenues (but does impact CO2 emissions), however carbon free (renewable) electricity sources could see shift in operations leading a revenue increase of 12%

Assessing process effectiveness with specific environmental and economic impact of heat, power & chemicals (HPC) option as future perspective in biogas

In RED II, the overall EU target for renewable energy sources consumption by 2030 has been raised to 32%. Biogas is an important contributor to the future of bioenergy and its targets. The most used technology processes to exploit biogas are the production of heat and electricity in Combined Heat and Power (CHP) plants and Biomethane Injection Plant (BIP) where biogas is upgraded to biomethane through the removal of CO2 and impurities. Nowadays, however, with the new national and European directives lowering incentives for energy generation from biogas, these plants have the critical risk of dismissing. The chemical industry requires new innovative pathways to exploit this feedstock. A promising opportunity that offers economic profitability seems to be the conversion of biogas into chemicals such as biomethanol with a new process technology called Heat, Power & Chemicals (HPC). This work introduces the HPC methanol synthesis through process simulation and LCA assessment analysis comparison with the most consolidated processes. Cradle-to-gate LCA analysis results highlight a lower carbon footprint for HPC technology. CAPEX/OPEX analysis assesses the promising economic feasibility of the HPC process. The positive feedback from the two studies gives actual and future perspectives in the biogas sector with the production of cleaner fuel through a circular process.

Wood ash biomethane upgrading system: A case study

In this work, a biomethane fuel was obtained from biogas, using a solid matrix of ashes obtained from a central heating plant fed by wood. Biomethane composition was studied in an experimental pilot plant that treats organic waste through dry anaerobic digestion. European limits were considered and respected for the biomethane injection into the gas grid. The process was able to completely remove carbon dioxide (CO2) during its initial phase. After 50 h of test CO2 concentration started to appear in the outlet gas. This behaviour is related to the ash content, reactive phases (e.g., Ca hydroxides) and fine particle size (<0.2 mm). Coupled with the CO2 removal, European limits for the biomethane injection into the gas grid must consider also trace compounds (Limits for Sulphur 150 mg/Nm3 and CO2 3%vol.). After 95 h of the experimental test, the gas injection limits are still maintained both for total sulphur trace compounds and both for CO2 limits. Uptake of 0.7 g/kg for H2S and 115 gCO2/kgash were registered from the pilot plant.

Aspects of Hydrogen and Biomethane Introduction in Natural Gas Infrastructure and Equipment

The injection of green hydrogen and biomethane is currently seen as the next step towards the decarbonization of the gas sector in several countries. However, the introduction of these gases in existent infrastructure has energetic, material and operational implications that should be carefully looked at. With regard to a fully blown green gas grid, transport and distribution will require adaptations. Furthermore, the adequate performance of end-use equipment connected to the grid must be accounted for. In this paper, a technical analysis of the energetic, material and operational aspects of hydrogen and biomethane introduction in natural gas infrastructure is performed. Impacts on gas transmission and distribution are evaluated and an interchangeability analysis, supported by one-dimensional Cantera simulations, is conducted. Existing gas infrastructure seems to be generally fit for the introduction of hydrogen and biomethane. Hydrogen content up to 20% by volume appears to be possible to accommodate in current infrastructure with only minor technical modifications. However, at the Distribution System Operator (DSO) level, the introduction of gas quality tracking systems will be required due to the distributed injection nature of hydrogen and biomethane. The different tolerances for hydrogen blending of consumers, depending on end-use equipment, may be critical during the transition period to a 100% green gas grid as there is a risk of pushing consumers off the grid.

The Study of Economic and Environmental Viability of the Treatment of Organic Fraction of Municipal Solid Waste Using Monte Carlo Simulation

Valorization of municipal solid waste (MSW) plays a crucial role in a sustainable society and provides an opportunity to reduce carbon emissions. The economic and social viability of the treatment of the organic fraction of MSW (OFMSW) with a multi-scenario analysis (composting and anaerobic digestion for renewable electricity or for biomethane injection into natural gas networks) was studied using a Monte Carlo simulation. The cost of treating organic fraction of MSW to neutralize financial net present value (NPV) and social NPV through greenhouse gas emissions avoided was determined for each scenario. The costs considered were the investment and the operating and maintenance costs. The financial benefits from the revenue of subproducts depended on the scenario. The lowest average fee to neutralize the financial NPV was 6.38 €/tonne treated in anaerobic digestion for biomethane injection into natural gas networks, therefore, it was the most financially viable. The average social NPV calculated for biomethane injection into natural gas networks (16.60 €/tonne) was higher than that obtained for renewable electricity (13.59 €/tonne). According to the results, anaerobic digestion for biomethane injection into natural gas networks is the most socially and economically viable alternative for the treatment of OFMSW.

Solar Integrated Anaerobic Digester: Energy Savings and Economics

Industrial anaerobic digestion requires low temperature thermal energy to heat the feedstock and maintain temperature conditions inside the reactor. In some cases, the thermal requirements are satisfied by burning part of the produced biogas in devoted boilers. However, part of the biogas can be saved by integrating thermal solar energy into the anaerobic digestion plant. We study the possibility of integrating solar thermal energy in biowaste mesophilic/thermophilic anaerobic digestion, with the aim of reducing the amount of biogas burnt for internal heating and increasing the amount of biogas, further upgraded to biomethane and injected into the natural gas grid. With respect to previously available studies that evaluated the possibility of integrating solar thermal energy in anaerobic digestion, we introduce the topic of economic sustainability by performing a preliminary and simplified economic analysis of the solar system, based only on the additional costs/revenues. The case of Italian economic incentives for biomethane injection into the natural gas grid—that are particularly favourable—is considered as reference case. The amount of saved biogas/biomethane, on an annual basis, is about 4–55% of the heat required by the gas boiler in the base case, without solar integration, depending on the different considered variables (mesophilic/thermophilic, solar field area, storage time, latitude, type of collector). Results of the economic analysis show that the economic sustainability can be reached only for some of the analysed conditions, using the less expensive collector, even if its efficiency allows lower biomethane savings. Future reduction of solar collector costs might improve the economic feasibility. However, when the payback time is calculated, excluding the Italian incentives and considering selling the biomethane at the natural gas price, its value is always higher than 10 years. Therefore, incentives mechanism is of great importance to support the economic sustainability of solar integration in biowaste anaerobic digestion producing biomethane.

The Biomethane Injection into the Natural Gas Networks: The EU’s Gas Synergy Path

Abstract Biomethane is one of the most promising renewable gases (hereafter – RG) – a flexible and easily storable fuel, and, when used along with the natural gas in any mixing proportion, no adjustments on equipment designed to use natural gas are required. In regions where natural gas grids already exist, there is a system suitable for distribution of the biomethane as well. Moreover, improving energy efficiency and sustainability of the gas infrastructure, it can be used as total substitute for natural gas. Since it has the same chemical properties as natural gas, with methane content level greater than 96 %, biomethane is suitable both for heat and electricity generation, and the use in transport. Biomethane is injected into the natural gas networks of many Member States of the European Union (hereafter – the EU) on a regular basis for more than a decade, with the Netherlands, Germany, Austria, Sweden and France being among pioneers in this field. In most early cases, permission to inject biomethane into the natural gas grids came as part of a policy to decarbonize the road transport sector and was granted on a case-by-case basis. The intention to legally frame and standardise the EU’s biomethane injection into the natural gas networks came much later and was fulfilled in the second half of the present decade. This paper addresses the biomethane injection into the natural gas grids in some EU countries, highlights a few crucial aspects in this process, including but not limited to trends in standardisation and legal framework, injection conditions and pressure levels, as well as centralised biogas feedstock collection points and the biomethane injection facilities. In a wider context, the paper deals with the role of biomethane in the EU energy transition and further use of the existing natural gas networks.

Greening the Gas Grid—Evaluation of the Biomethane Injection Potential from Agricultural Residues in Austria

In order to implement the Paris Climate Agreement, the current Austrian coalition government has included trend-setting targets in its policy statement. “Green gas” plays a key role in this context, as the natural gas grid shall also gradually become renewable. This article analyses the technical biomethane injection potential for agricultural residues based on Integrated Administration and Control System (IACS) data on a municipal level. While a technical biogas potential of 16.2 TWhCH4 from catch crops, farm manure, straw and beet leaves is available, only about half of it can be fed into the gas grid because of technical and economic reasons. Austria’s biomethane injection potential of 7.4 TWhCH4 is mainly produced in arable farming regions. In order to further increase this potential, the investment costs of biogas upgrading plants must be reduced, the use of biogenic waste and energy crops must be further promoted and an investor-friendly legal framework must be created.

Biomethane injection into natural gas network vs composting and biogas production for electricity in Spain: An analysis of key decision factors

The challenge of sustainable cities involves rethinking some infrastructure systems and supply chains, including those for energy and waste. In this sense, the injection of green gas as biomethane into the natural gas network could contribute to the reduction of waste in landfills and to the decarbonisation of energy systems. Positive and negative aspects of this challenge have been identified and quantified in comparison with traditional composting and biogas production for electricity, in order to give guidelines to overcome the obstacles that its use shows nowadays. For this, an integrated analytic hierarchy process – strengths, weaknesses, opportunities and threats (AHP-SWOT) analysis, supported by a panel of experts, has been applied. Results have shown the strength derived from the environmental and economic benefits obtained from the by-products, as well as the opportunity of biogas for electricity and biomethane production to generate positive effects on climate change, although the investment and exploitation costs could threaten its implementation. It has been possible to conclude that the use of biomethane in gas networks shows a greater flexibility of use and avoided emissions, so it can become an alternative. Nevertheless, its implementation needs promotion from governments as well as a regulatory framework to support it.

Towards circular economy: Economic feasibility of waste to biomethane injection through proposed feed-in tariff

Lately International Energy Agency (IEA) highlighted the vital role the biogas and anaerobic digester (AD) in the advent of circular economy. Organic residues or waste will be converted into high-value products, power, heating and fuel in the future of bio-economy. This study look specifically into the institutional and market factor, of a Feed-in Tariff (FiT) mechanism as a policy instrument to promote integration of biomethane into existing gas grid. In the circumstance where market is not in the favour of bioenergy/biogas, with fossil fuels are subsidised under national economic policy of the case study in Malaysia; this study found that under the current piped natural gas price, the proposed FiT, 34.02–141.79 MYR/GJ (7.13–29.73 EUR/GJ) is economically incompetent for biomethane to be injected into the grid without other policy and mandate support. However, natural gas price rationalisation may close the price gap, this is especially for biomethane derived from palm oil mill effluent (POME) and food waste at 4 MW size. Through Net Present Value (NPV) approach, among the four locally available feedstock assessed in this study: POME, food waste, chicken manures and cattle manures; POME and food waste show lower levelised cost due to minimal competing utilisation value in addition to their higher biogas conversion rate. POME prevails as a feedstock choice for its uniform composition and on-site production advantage. Discussion and recommendations based on the current policy scenarios in Malaysia are provided in the section following results and findings.

Policy change, power and the development of Great Britain's Renewable Heat Incentive

The role of socio-political power is central to the development of policy, but systematic analyses of power associated with the development of energy policy are rare. Power is also an important yet somewhat under-researched aspect of socio-technical transitions research. The Renewable Heat Incentive (RHI) policy aims to increase deployment of low-carbon heat in Great Britain and begin a transformation to a low carbon GB heat system. This article analyses the socio-political power associated with the development of the RHI policy based on Lukes' ‘dimensions of power’ approach using a methodology based on triangulation. We identify a number of policy change episodes during the development of the RHI and describe the influence of key actors on the policy. Despite the common assumption of the power of incumbents, we show that those actors with niche technological expertise, close relationships with Government actors and actors within the administration have been the most powerful drivers of policy development and change. Niche actors sped up the introduction of the RHI scheme and have also had some success in increasing relative support for biomethane injection. The power of a civil servant to slow the introduction of the domestic element of the RHI has also been identified.

Spatial-economic optimisation of biomethane injection into natural gas grid: The case at southern Malaysia

Energy is widely used in industry for heating and cooling, with natural gas (NG) being the largest primary energy source in Malaysia, closely followed by coal. Renewable energy, such as biogas upgrading to biomethane, could cut the use of fossil fuels by supplementing NG usage due to their similar physicochemical and thermochemical characteristics. Biogas production plants in Malaysia are more commonly seen in waste-to-energy scenarios, with the technology anaerobic digestion, and their deployment is supported via feed-in tariffs (FiT) for power generation. Other potential applications such as the conversion of biogas into biomethane, injection into the natural gas grid or transportation through a virtual pipeline may still need further technical development. This paper presents spatial techno economic optimisation modelling using BeWhere to determine decentralised biomethane production plants using feedstock from multiple sources of biogas, including palm oil mill effluent (POME), food waste, cattle manure and chicken manure. This model considered potential configurations and sizes of the biomethane plants, the transportation of biomethane using a virtual pipeline (at 250 psig) and demand in one of the states in Malaysia, namely Johor. It was found that two to four biomethane plants with capacities ranging between 125 and 700 m3/h were located in densely populated areas or heavier industrial consumers when the carbon tax was implemented at 167.71 EUR/tCO2 (800 MYR/tCO2). Sensitivity analysis suggested that biomethane production increases with the increasing country renewable energy share target to beyond 2080 MW. It is recommended that specific policy regulations and Feed-in Tariff (FiT) mechanisms are used to expand the biomethane market share in the country.

BBI JU: Bridging the gap between research and market to develop a sustainable bio-based economy in Europe

A global bioeconomy requires adequate logistical infrastructure to support trade of biomass feedstock and intermediates. An integration of biomass trade streams with existing supply chain infrastructure, originally constructed for other goods, presents an opportunity to efficiently enable such growth. This chapter examines to what extent existing logistical infrastructure can be used and/or shared with biomass trade streams via specific case studies. It identifies how biomass trade is already or could be integrated into existing supply chains handling infrastructure, and for what kind of biomass specifications a dedicated infrastructure is needed. It finds that the existing solids handling infrastructure is well suited to integrate biomass intermediates such as conventional or torrefied pellets. Liquids with a higher energy density than solids, for example, pyrolysis oil, could potentially realize many opportunities to leverage infrastructure designed for the petroleum industry, and may even enable leveraging home heating infrastructure, for example, in the US northeast, preventing costly modifications. However, high oxygen levels render pyrolysis oil corrosive, requiring investments in stainless steel or other more durable handling equipment. Biomethane injection into natural gas grids is already a common technology in most of Europe, but major hurdles remain, including high production costs, pipeline access, and the lack of quality standards.

Economic feasibility of feed-in tariff (fit) for biomethane injection into natural gas distribution grid

Feed-in Tariff (FiT) is a policy mechanism designed to promote investment in renewable energy technologies. Despite the successful implementation of FiT mechanism for renewable electricity generation in Malaysia since 2011, FiT for renewable gas, biomethane injection into the natural gas grid remains unexplored. This study aims to identify the financial feasibility of biomethane injection into natural gas grid by proposing FiT rate. Net Present Value (NPV) approach is used to calculate the FiT rate for the first five years of biomethane injection into natural gas distribution grid (NGDG), under 8 % degression rate. Preliminary results identified that FiT rate of 40.81 to 227.85 MYR/GJ for biomethane production plants within 1,000 m from the injection point at 4 different sizes: 250 m3/h, 500 m3/h, 750 m3/h and 1,000 m3/h. Biggest plant size (1,000 m3/h) shows lowest FiT rate (40.81 MYR/GJ), although the FiT rate is almost double the piped gas price, 28.85 MYR/GJ. Judging from the trend of increasing piped gas price, along with government subsidy rationalisation plan, it is foreseen that biomethane, under proper policy regulations and FiT mechanism, can be a competitive renewable gas as natural gas. Recommendations are discussed and provided for successful implementation of biomethane injection into the grid.

A short-cut model for predicting biomethane availability after biogas upgrading

Biomethane increasingly grows in importance in the bioenergy sector, as it is a renewable energy source that promotes waste recovery and GHG (greenhouse gases) reduction. In Brazil, the legal framework for biogas and biomethane is being developed, especially in the State of São Paulo. However, many of the final uses to biomethane require an upgrading and cleaning process, to remove contaminants such as H2S and CO2. Facing the great number of technological options to promote biogas upgrading and cleaning so far, policymakers and energy planners might lack the tools to accurately and readily estimate biomethane potentials to comply with a given biomethane quality standard. Our main objective thus is to propose a short-cut, mass balance-based model to predict biomethane availability after promoting a biogas cleaning and upgrading process, regardless of the source of organic feedstock. The model development results in the ratio of biogas to biomethane production and other relevant parameters regarding biomethane use, such as its LHV. The correlation with data from the literature shows that the model has a satisfactory prediction, even when using upgrading technologies that have high methane losses. The model was applied to a case study of upgrading biogas from vinasse from ethanol production in the state of São Paulo; it aided in choosing the upgrading technology for biogas focusing on biomethane injection in the natural gas pipeline and in replacing diesel oil in trucks and heavy-duty machinery in the ethanol plant. Using the proposed model, it was estimated that 1.975x109 Nm3/y of biomethane could be produced, supplying 16.6% of the NG consumption in the State of São Paulo and making it possible to displace the entire diesel oil consumption in ethanol mills. The use of biomethane in the ethanol plants of São Paulo would avoid 3.965x106 tCO2eq of GHG emissions, which represents 5.48% of the GHG emissions of the state in 2016.

A profitability analysis of small-scale plants for biomethane injection into the gas grid

Abstract Biomethane is a promising renewable energy carrier with the potential to diversify and decarbonise natural gas. It is produced from a range of waste sources and can be distributed into the natural gas grid or used as a vehicle fuel or converted into in cogeneration units. The economic evaluation of small plants for biomethane injection into the gas grid is not well defined in literature. This paper proposes a mathematical and economic model useful to evaluate the profitability of these plants in according to Discounted Cash Flow (DCF) method. The indicators used are Net Present Value (NPV), Discounted Payback Time (DPBT), Internal Rate of Return (IRR) and Profitability Index (PI). The baseline case studies analyse three different small-scale sizes (50 m3/h, 100 m3/h and 150 m3/h) concerning two typologies of substrates (organic fraction of municipal solid waste (ofmsw) and a mixture of maize and manure residues). Results define that the profitability is verified only for 150 m3/h ofmsw plant in baseline case study (NPV is 615,694 €, DPBT is 3 y, IRR is 33% and PI is 0.18). Furthermore, alternative case studies are conducted on the main critical variables (subsidies, investment costs of biogas production, transport costs of substrates and percentage of maintenance and overhead costs in biogas production). The economic feasibility can be reached in the following case studies: 100 m3/h ofmsw plant in sensitivity analysis, 50 m3/h ofmsw plant in scenario analysis, 150 m3/h mixed plant in scenario analysis with a new incentive scheme and 100 m3/h manure residues plant in scenario analysis. The biomethane can contribute to develop the circular economy recovering a wide range of waste.