Biogas is a gaseous compound mainly composed of CH₄, CO₂, and impurities in lower concentrations. Biogas can be produced from the anaerobic digestion of different types of waste biomass. According to the European Biogas Association (2020) and International Energy Agency (2020), three main biogas plant categories can be found:

- Biodigesters, where organic materials are decomposed thanks to bacteria (psychrophilic, mesophilic, or thermophilic depending on the fermentation temperature) in anaerobic tanks.

The as-produced biogas needs to undergo dehumidification and cleaning steps before exploitation, to remove condensation and harmful contaminants, with the purity level depending on the downstream technology chosen for biogas use.

Biogas from biodigester application can be further classified depending on the feedstock type (i.e., substrate) (European Biogas Association, 2020):

- Agricultural sub-products like animals’ manure, crops’ residues, straw, and similar biomasses.

Among such feedstocks, the most diffused at the EU level are the agricultural biogas plants (more than 60% of the installed electrical capacity comes from agriculture), running on a mix of residues and animal manure. This category has the highest share in the EU and most single countries, except particular cases like Switzerland, where sewage biogas (from WWTPs) is predominant, or Norway, where the highest share comes from landfill applications.

Landfill gas is the second largest group, together with industrial wastes and WWTPs.

Energy crops are still highly diffuse as feedstock type in Europe: these plants were usually installed in the first decade of the 2000s, when high incentives were not linked with the feedstock typology. In Germany, for example, around 50% of feedstocks used for biogas production are crops, according to the European Biogas Association (2020). Currently available incentives mainly focus on the use of biowaste material as a source for bioproducts from biogas (electricity or biomethane).

Shifting from the current scenario to production potential, manure and crops’ residuals are still the higher share even in the overall potential analysis (International Energy Agency, 2020), followed by MSW and woody biomass, which are currently not fully exploited. The most significant potential is found to be in the Asia Pacific and North America (between 150 and 200 Mtoe), followed by Central and South America and Europe.

Differences are also available among the different feedstocks in terms of biogas production yield (efficiency of the biodigesters) and cost of the biogas produced (Table 1). Industrial waste, for example, has one of the highest biogas conversion yields but is currently economically competitive only in medium and large scale. The lowest biogas yield is the one of manure and sewage biogas, which anyway has a strong potential and can be economically feasible in the same sizes as industrial plants.

Lastly, the International Energy Agency (IEA) pointed out that the sustainable potential for biogas in 2040 is 50% higher than available today, based on the increased availability of the various feedstocks in a larger global economy.

Within biogas applications, the separation of CO₂ from CH₄ using upgrading technologies is often employed for further injection of biomethane into the gas grid and carbon dioxide recovery. Table 2 lists the preferential capture technologies (and their mean capture efficiency (Teir et al., 2014; Huang et al., 2015; Riboldi and Bolland, 2015; Awe et al., 2017; Pellegrini et al., 2020)) utilized in the biomethane plants throughout Europe.

In this context, the total number of biomethane plants installed in Europe amounted to 742 at the end of 2019 (European Biogas Association, 2020). With respect to the share of capture technologies, membranes and water scrubbing represented the leading upgrading technologies, followed by chemical scrubbing, pressure swing adsorption, physical scrubbing, and cryogenic separation (Figure 1). Accounting for the different substrates, energy crops and agricultural wastes are the main ones utilized for the anaerobic digestion process (33 and 29% of the biomethane plants, respectively). Only 2% of the plants (i.e., 14 biomethane plants) utilize landfill as the preferential substrate.

Operating biogas plants in Europe were 6,227 in 2009, and the number increased to 18,966 in 2019 (Figure 2). Moreover, the installation of biogas-upgrading plants has constantly risen, from 187 in 2011 to 742 in 2019. Considering the different EU countries with operating plants as of 2019, Germany was the country with the highest number of biogas plants (11,084), followed by Italy (1,655), France (837), and the United Kingdom (715). Considering the existing biomethane plants (Figure 3), Germany was still the country with the highest number, followed by France, the United Kingdom, and Sweden. As seen from Figure 2, the installation of biogas plants is reaching a plateau condition. Contrariwise, there is a rising trend in the available ready-to-use carbon dioxide derived from upgrading the biogas streams into biomethane and CO₂.

Additionally, the data available regarding biomethane plants (i.e., biogas plants with an upgrading unit, connected to the gas grid) presented by the European Biomethane Map (European Biogas Association, 2020) provide details about the type of substrate utilized in the anaerobic digestion process, the employed technology for carbon dioxide recovery, and the amount of biomethane supplied by each plant.

For biogas plants, the open literature provided clustered information on the total number of operating plants, the total biogas installed capacity (expressed in MW_el), the total production of biomethane (GWh/y), and the average size of the plants (MW_el) for each of the assessed European countries (European Biogas Association, 2020; Association EB, 2018). Consequently, the total amount of captured CO₂ (ton/h) was evaluated for these plants according to Eqs 1, 2. The generated carbon dioxide from the eventual combustion of methane was omitted, assuming CH₄ injection into the gas grid: V ˙ b i o g [ m 3 h ] = 3600 · P b i o g η e l · L H V b i o g , (1) M ˙ C O 2 [ t o n h ] = V ˙ b i o g · y C O 2 b i o g · η c a p t · P M C O 2 · 0.00224 · 10 − 6 . (2)

Here, P _biog is the installed capacity of biogas in each country, η _el is the electric efficiency assumed to be 38% (EBA, 2020), the lower heating value of biogas was considered 20 MJ/m³ (International Energy Agency, 2020), and the mean concentration of CO₂ in the biogas was 40% (Marchese et al., 2020). The CO₂ capture efficiency (biogas-to-CO₂) η _capt was taken as 95%, evaluated as the mean value of capture efficiency for the different technologies engaged in biogas upgrading (Bauer et al., 2013).

Regarding biomethane plants, Data Availability provides details on the amount of CH₄ supplied by every plant to the gas grid. Accordingly, the amount of available carbon dioxide was estimated based on the technology employed for upgrading at each of the 742 sites. In this regard, the efficiencies presented in Table 2 were used, assuming a biogas composition of 60:40 of CH₄:CO₂.

Additionally, for both biogas and biomethane plants, the potential amount of digestate available was evaluated according to the methodology presented by Marchese et al. (2021b), starting from the amount of CO₂ derived from biogas and assuming a substrate-to-digestate mass conversion of 65% (Blank and Hoffmann, 2011). The landfill substrate was accounted for only in the production of CO₂. Digestate derived from landfill applications was excluded from evaluating the production potential, being considered a discharged material disposed of in dedicated disposal areas.

From the total amount of carbon dioxide and digestate streams from both biogas and biomethane plants, the evaluation of the potential production of Fischer–Tropsch fuels and chemicals was carried out taking into account results from techno-economic feasibility investigations (Marchese et al., 2020; Marchese et al., 2021b; Marchese, 2021). In a previous study, we analyzed the conversion of CO₂ captured from biogas via chemical scrubbing into FT hydrocarbons from an energy analysis point of view (Marchese et al., 2020). The syngas required by the FT reactor was produced in a reverse water–gas shift reactor coupled with an alkaline electrolyzer or in a solid oxide co-electrolyzer. Based on previous results, operating the RWGS or SOEC devices at low pressure is preferential for high FT product synthesis. Finally, using an SOEC solution is beneficial for energy integration purposes, better matching the thermal demands of the biogas-upgrading unit based on chemical scrubbing. The model exploited 1,000 kg/h of CO₂ as carbon feedstock. In a second investigation, we analyzed the gasification of digestate into FT compounds (Marchese et al., 2021b). The FT off-gas was either used as a fuel for electric generation or recycled into the gasifier for enhanced generation of synthetic FT waxes. A solution internally recirculating the FT off-gases was preferential for a higher production of FT compounds. The model employed 881 kg/h of dry digestate material (979 kg/h as received). For both biogas-derived CO₂ and digestate, economic considerations were accounted for the production of FT waxes (Marchese, 2021). For all the analyzed processes, the production of FT compounds is described by a mechanistic kinetic model validated with experimental results (Marchese et al., 2019). Figure 4 provides the schematics of the process models taken into consideration for the evaluation of the FT production potential throughout Europe. The electric input for both processes (i.e., 195 kWel and 6,005 kWel for the digestate and biogas routes, respectively) was assumed to be of renewable source, allowing for its storage into FT compounds for e-fuels and e-chemicals (naphtha and middle distillates and waxes). A detailed description of the process routes, as well as energy integration solutions, can be found in the studies of Marchese et al. (2020), Marchese et al. (2021b), and Marchese (2021).

In the process of evaluating the potential production of FT compounds, techno-economic considerations were takin into account considering the cost of production of paraffin FT waxes. Accordingly, results from techno-economic considerations for the baseline configurations were considered, including both CAPEX and OPEX costs, as well as revenues derived from the sale of FT naphtha and middle distillates, and by-products such as heat, oxygen, and biomethane (Marchese et al., 2021b; Marchese, 2021). Consequently, economy of scale was applied to each CCU plant accounted for as in Eq. 3: C p l a n t [ € ] = C p l a n t , r e f ∗ ( S p l a n t S p l a n t , r e f ) s . f . , (3) C p l a n t r e f = ∑ i = 1 n = p l a n t   c o m p o n e n t s C e q i . (4)

The reference cost (C_plant,ref) of each plant corresponded to the purchase cost of the reference plant evaluated by Marchese (2021), taking into account the sum of purchase cost of each plant component (C_eq,i). The plant size value corresponded to the amount of digestate entering the DIGESTATE plant, and CO₂ entering the BIOGAS plant. The reference size corresponded to 881 kg_dig/h and 1,000 kg_CO2/h, respectively. A scaling factor of 0.78 was assumed for the overall CCU plant. From the plant cost, the total investment cost was evaluated considering installation factors, contingency costs, engineering costs, and commissioning costs. OPEX and revenues were varied depending on the plant producibility without applying any scaling factor.

Given the higher availability of biogas plants, the assessment was performed for Germany and Italy. Consequently, state incentives for biomethane grid injection were assumed for both countries. Regarding German policies, these accounted for a biomethane sale price of 31.6 €/kWh with 20-year sale credits of 61.6 €/MWh (Regatrace (2020); Baena-Moreno et al., 2020; Daniel-Gromke et al., 2019). In the case of Italy, a sale price of CH₄ of 20.9 €/kWh was assumed, with credits of 62.7 €/MWh in the first 10 years and 0.305 €/m³ for each subsequent year of plant operations (Regatrace (2020); Barbera et al., 2019).

The cost of wax production was evaluated with the annuity method (Michailos et al., 2019), which included the cost of capital repayment for the borrowed capital. Specific component costs, operating costs, and revenues are provided in the Supplementary Material.

Figure 5 provides the potential out-take of carbon dioxide and digestate for each state. The total EU potential corresponds to 4.23 kton/h and 2.79 kton/h of pure CO₂ and dry digestate, respectively. As seen, Germany dominates the market for the installed capacity of biogas—with the highest total number of installed plants—providing the highest potential out-take for both carbon dioxide and biomass material. Remarkably, the UK is the second country in terms of potential material flow of CO₂, determined by the higher installed capacity than that in Italy (nevertheless, Italy has a higher number of operating biogas plants than the UK). However, the UK also presents a higher percentage of biogas produced from landfill applications (58% of biogas production from landfill, against 19% from Italy (EBA, 2020)), making Italy the second country in Europe with the availability of digestate material for further processing, followed by France, Czech Republic, and Estonia.

The total out-take potential of biomethane plants corresponds to 419 t/h and 357 t/h of CO₂ and (dry) digestate, respectively. The share of production depending on the location is provided in Figure 6. Among all the countries that currently present installed upgrading units, Germany is the one with the highest availability of useful non-fossil streams.

With reference to the accounted CCU plant configurations, utilizing the streams available from the biogas plants provides different amounts of FT feedstocks. The results are listed in Table 3. Such routes provide 831.6 kton/y and 2,948.4 kton/y of waxes utilizing digestate and biogas-derived CO₂, respectively. Hence, if we were to exploit the full potential of biogas and digestate, 78.8% of the wax demand could be covered by non-fossil sources.

Similarly, the production of Fischer–Tropsch material utilizing CO₂ streams and digestate available from the biomethane plants is provided in Table 4. The total wax production from the digestate route corresponds to 12.6 ton/h, and that from biogas is 34.7 ton/h. Accounting for both contributions, up to 8.3% (39.7 kton/y) of the global paraffin demand can be covered with non-fossil feedstock. However, it is important to point out that this wax production derives from ready-to-use streams of CO₂ and digestate that would otherwise be disposed of, especially for the carbon dioxide route where the waste stream would be vented toward the environment.