This pathway combines two thermo-chemical technologies, gasification and methanation, to produce bio-based synthetic natural gas (bio-SNG) and CO₂ from woody biomass. Equation (1) represents the overall chemical reaction stoechiometry. A drying step is needed before the gasification process for decreasing the humidity below 20%, in order to ensure the proper functioning of the gasification. The gasification process, which takes place at 800–900°C in an oxygen restrained environment (Gassner and Maréchal, 2009; Gassner et al., 2009), decomposes the biomass into syngas, a mixture of CH₄, H₂, CO, CO₂, and H₂O. The syngas is then cleansed before being converted to CH₄ (SNG) and CO₂ by the methanation process in a catalytic reactor (using nickel catalysts) at 300–400°C. Depending on the biomass composition and the specific gasification technology, the output of the reactor will contain between 40 and 50% volume of methane (CH₄), which has to be separated from the CO₂ and the remaining H₂ if one wish to inject it in the natural gas grid (Gassner and Maréchal, 2009; Gassner et al., 2009). The complete process is depicted in Figure 1. The fuel efficiency of the complete process (EnergyOutput_SNG/EnergyInput_Biomass) is expected to range from 39 to 75% (Gassner and Maréchal, 2012), depending on the biomass composition and moisture content.

The critical part of this pathway is the methanation step. Although the 2-stage process feasibility has been demonstrated in pilot plant scale, like the one in Guessing (Austria) producing 1 MW_SNG, the technology has not yet reached commercial status (Iskov, 2013). The Swedish project GOBIGAS in Göteborg expects commissioning of the world’s first large-scale commercial methanation plant supplying 100 MW_SNG by 2020.²

Hydrothermal gasification (HTG) is a promising technology for the production of bio-SNG from wet woody biomass or any biomass with moisture content between 50 and 80% (Gassner et al., 2011). As for the gasification/methanation process, HTG fully converts the energy content of the biomass into gas, electricity, and heat. Its main advantage over other conversion processes lies in the fact that the biomass is treated in supercritical water, thus avoiding the energy consuming drying step. Under supercritical conditions, the biomass macromolecules are hydrolyzed and become accessible to the catalyst for the conversion into CH₄ and CO₂. In addition, the supercritical conditions require less energy for heating up the water to the operating conditions.

Up to date, only lab-scale HTG facilities have been built (Waldner et al., 2007; Kruse, 2009). The performances in Table 1 are based on models, which have been calibrated with data from laboratory experiments, in order to be able to calculate the efficiencies of an integrated industrial process.

As shown in Table 1, the performance of the HTG process highly depends on the properties of the feedstock. In addition, the process heat demand is fairly sensitive to the level of dilution of the organic matter in the water. In this respect, hydrothermal gasification is in direct competition with bio-methanation (anaerobic digestion). In some cases these two technologies can actually complement each other as HTG can treat in a post-process the non-digested output from the bio-methanation reactor.

The biomass to liquids (BTL) conversion pathway considered in this study consists in the synthesis of Fischer-Tropsch fuels from lignocellulosic biomass. The first step of the process is the pretreatment by which raw biomass (35% moisture content) is dried, torrefied, and ground into fine particles. The biomass particles are then gasified in a pressurized (30 bar) steam-oxygen blown entrained flow gasifier. The synthesis gas produced, consisting mainly of H₂, CO, and CO₂, is cooled by a water quench and cleaned in a scrubber. A water gas shift (WGS) reactor is used to adjust the H₂ to CO ratio and CO₂ is removed by amine scrubbing in order to satisfy the requirements of the FT synthesis by which the liquid hydrocarbon fuels are produced. This process is described in detail in Emanuela (2015), as a reference process using entrained flow gasification with “most conventional technologies” and converting 200 MW_th (on a LHV daf basis) of lignocellulosic biomass.

FT fuels can be blended to diesel fuel. Methanol production is an alternative BTL conversion pathway with similar conversion to the FT fuel pathway. Methanol can be blended with gasoline (Peduzzi et al., 2013).

A biomass integrated gasification combined cycle (BIGCC) uses a pressurized gasifier to convert woody biomass into synthesis gas (syngas), which consists mainly of H₂, CO, and CO₂. The syngas is then cleansed from impurities prior to entering a gas turbine to generate electricity. In order to maximize the electrical efficiency, the heat content of the flue gas is then used in a boiler for producing steam, which subsequently expands in a bottoming steam turbine to further produce electricity. A BIGCC is identical to a natural gas combined cycle, in which gasified biomass substitutes natural gas as input to the gas turbine.

This integrated system converts woody biomass to electricity with a maximum efficiency of 71% (Caliandro et al., 2014). The biomass is first dried to 10–25% moisture content. The dry wood then enters a directly heated fluidized bed gasifier (CFB) to produce syngas, which fuels a solid oxide fuel cell (SOFC)–gas turbine (GT) hybrid cycle. Prior to injection into the hybrid cycle the syngas produced in the gasifier is sent to the hot cleansing unit to remove particulates, sulfur and tar, in order to reach the required syngas purity specifications required by the SOFC. The SOFC outlet stream is at high temperature and still contains some syngas. Thus it has a high exergy content, which is exploited in a gas turbine to produce additional electricity (Facchinetti et al., 2011). If the combustion in the gas turbine is made with pure oxygen, the flue gases only contain CO₂ and water vapor. The water vapor can be condensed to separate the CO₂ which can be compressed for its transport and storage (carbon capture and storage). A detailed description of the system is available in Caliandro et al. (2014).

Torrefaction is a thermo-chemical process carried out at 200–300°C, with low heat-up rates (less than 50°C of temperature increase per minute), and long reaction time (about 1 h). It may be used as pretreatment process to upgrade woody biomass or other kinds of lignocellulosic biomass. It completely dries and reduces the hygroscopic nature of biomass, meaning that only 1–6% moisture content may be regained during storage. In comparison to raw woody biomass, torrefied biomass has a higher heating value and energy density. In addition, torrefied biomass has better grindability and better properties for injection when used in boilers or gasifier, as it is a more homogeneous fuel than raw biomass. These characteristics make torrefied woody biomass a suitable substitute of coal in co-firing or gasification facilities, with a minimal efficiency penalty even in equipments designed for coal. Furthermore, because of the low hygroscopic nature and higher energy density transportation costs can be reduced (Peduzzi et al., 2014).

This section analyses the fossil CO₂ abatement obtained when replacing a fossil-fueled technology by a woody biomass pathway to supply space heating only, or space heating and electricity (cogeneration).

The different pathways that deliver space heating are made of 1, 2 or 3 consecutive conversion technologies. The first one is the “Biomass to Fuel” technology, by which woody biomass is transformed into a gaseous or liquid biofuel, and possibly electricity as a by-product. The second technology “Fuel to X” converts the biofuel into heat and/or electricity. It is worth noting that some technologies, such as the Biomass Integrated Gas Combined Cycle (BIGCC), combine both steps as they directly convert the woody biomass into electricity and/or heat. The third possible technology is heat pump which converts the electricity produced along the pathway (if any) into space heating. The fossil pathways which are substituted also integrate heat pumps if electricity production along the pathway, so that the comparison is fair. Figure 3 contains an example for such as “HEAT pathway.”

Results are shown in Table 4. The fossil CO₂ emissions reduction obtained when 1 kWh of woody biomass is used for space heating in different bioenergy pathways as a substitution for natural gas (NG) pathways. Values in the same row represent the CO₂ abatement potentials of a given bioenergy pathway depending on the displaced natural gas pathways.

The values in Table 4 are normalized considering the emission reduction obtained if the biomass was used in a wood boiler that substitutes heat from a natural gas boiler (see reference pathway in Figure 3). A value of 1 in Table 4 corresponds to a reduction of 0.211 kgCO2/kWhWoodyBiomass. The higher the values, the higher the CO₂ abatement potential of the biomass pathway. Negative values reflect situations where the biomass pathway actually generates more lifecycle CO₂ emissions than the fossil pathway that is substituted.

The results in Table 4 indicate that the mitigation potential depends greatly both on the biomass pathway considered and on the fossil pathway it substitutes. For instance, the first line in Table 4 shows that the CO₂ mitigation of a wood boiler ranges from 1, when the substituted technology is a natural gas boiler (reference pathway), to −0.01, if the substituted fossil pathway is a heat pump driven by electricity produced by a combined cycle gas turbine (CCGT) with carbon capture and storage (CCS).

The worst case scenario (negative values of −0.49 in Table 4) corresponds to the following case: a “Bio-SNG and Electrolysis–Boiler” biomass pathway substitutes a heat pump driven by electricity that is generated by a CCGT plant with CCS (see Figure 4). The biomass pathway produces 12.3 kg CO₂-eq. (on a life cycle basis), while the emissions from the fossil pathway are only 2.0 kg CO₂-eq, thanks to the use of a heat pump and because the CO₂ emitted by the CCGT plant is captured and sequestrated.

The biomass pathway offering the highest emission reduction potential is the “Bio-SNG and Electrolysis–SOFC, GT and CCS–HP” pathway, which could lead to 8.48 times the emissions savings of the reference pathway (only biomass boiler). In this pathway, the bio-SNG and electrolysis system produces bio-SNG from woody biomass and hydrogen produced from renewable electricity. The bio-SNG is then used in a solid oxide fuel cell (SOFC) with bottoming gas turbine (GT), combined with carbon capture and storage (CCS) and where the electricity produced by the fuel cell is used to drive a heat pump. Given the CO₂ sequestrated by the CCS is of biogenic origin, the system acts as a carbon sink, removing CO₂ from the atmosphere.

The pathways that deliver heat and electricity are composed of two technologies: “Biomass to Fuel” and “Fuel to X.” Figure 5 contains an example for such “HEAT and ELECTRICITY” pathway.

Results are shown in Table 5 which gives the CO₂ emissions reduction obtained when 1 kWh of woody biomass is used for supplying space heating and electricity, in replacement for fossil pathways offering the same energy services. The reference value for normalization is the same as in Table 4 (0.211 kgCO2/kWhWoodyBiomass).

The woody biomass pathway in the first row of Table 5 is composed by only a boiler for heat-only production, and serves as a reference pathway. Its abatement potential is thus constant along the row, as the different fossil-based electricity supply technologies are not used, since the woody biomass pathway only supplies space heating.

The highest CO₂ abatement potentials are obtained when supercritical coal power plants for electricity generation are substituted, due to the low efficiency of the coal technology and the high emission factor of coal in comparison to the natural gas based CCGT technology (see Tables 2 and 3). Actually the combination of CCGT and CCS technologies is the most efficient fossil pathway and, thus, presents the lowest abatement potential for biomass pathways (Table 5). The worst case is obtained when the “Bio-SNG and Electrolysis → CCGT” pathway replaces the “CCGT and CCS + Boiler (Natural gas)” fossil pathway. In this case, the fossil CO₂ abatement is even negative (−0.34), which reflects the fact that the fossil pathway emits less fossil CO₂ on a life cycle basis than the woody biomass pathway thanks to the use of the CCS technology.

As for space heating only (Table 4), the highest abatement potential (7.87) is given by the biomass pathway in which the bio-SNG and electrolysis and SOFC, GT, and CCS technologies are combined together (Table 5). In addition, comparing the results in these two tables indicates that substituting fossil fuels for space heating brings slightly higher mitigation impact than displacing fossil electricity.

If biomass is converted into a fuel, it can be used to substitute the corresponding conventional fossil fuel used in transportation. When considering a 2035 horizon, it is, however, critical to consider both the possible fuel substitution but also the expected fuel efficiency increase of vehicles. It is in particular necessary to take into account the full electrification and hybridization of power trains. Table 2 defines the efficiencies of different power trains in cars that are used in this study.

The pathway transforming the energy content of woody biomass into mobility service can be formed by up to three technologies: “Biomlass to Fuel,” “Fuel to X,” and “Elec. to Transport.” “Biomass to Fuel,” and “Fuel to X” play the same role as in the pathways analyzed above for space heating and electricity production (Tables 4 and 5), with the added possibility for “Fuel to X” to be a private passenger vehicle. The “Elec. to Transport” technology is a battery electric car using all electricity production of the pathway for mobility.

Table 6 shows the fossil CO₂ emissions reduction obtained if the primary energy source for mobility and space heating is biomass instead of fossil fuels. The biomass pathways that produce heat are used to replace the use of natural gas boilers for space heating, see the “HEAT and MOBILITY” pathway example in Figure 6. As in the previous Tables 4 and 5, the reference value for normalization is 0.211 kgCO2/kWhWoodyBiomass.

The highest fossil CO₂ emissions reduction (9.55) is achieved when woody biomass is used in the “Bio-SNG and Electrolysis → SOFC, GT, and CCS → Car-Elec” pathway to replace cars fueled by compressed natural gas (CNG) (see Figure 7). In this pathway, there is also a small amount of heat production (16% thermal efficiency) from SOFC, GT, and CCS, which substitutes natural gas boilers for space heating.

Interestingly, there are no negative values in Table 6, which indicate that all substitution pathways do bring CO₂ emissions reductions. The reason for this lies in the fact that battery electric vehicles are about 3 times more energy efficient than diesel cars (see Table 2). Hence, using electric cars that run on renewable electricity instead of diesel cars will bring higher abatement potential than substituting fossil-based heaters of power plants by biomass-based technologies. Comparing the results from Tables 4–6 shows that the “space heating and mobility” pathways offer the highest mitigation potentials.

The difference on efficiencies between fossil fuel cars and battery electric cars is such as that it brings a higher CO₂ mitigation to replace a diesel or CNG car by an electric car running on biomass electricity than a battery electric car running on electricity from supercritical coal power plant. A diesel car emits 0.122 kg CO₂-eq./pkm, while a battery electric car using electricity generated from coal has an impact of 0.100 CO₂-eq./pkm (based on emission factors and efficiencies reported in Tables 3 and 2).

Biomass potential in Switzerland has been evaluated by Steubing et al. (2010) later updated by Thees et al. (2014). Table 7 presents the sustainable potential for woody biomass by type of resource with the corresponding LHV per ton of dry matter (t_dw). The sustainable potential represents the total potential, including the present use of biomass, which amounts to about 51%. The total sustainable potential is 53.3 PJ. Today, biomass covers a mere 5% of the primary energy demand of Switzerland. By comparison, Austria which has a similar topography and forestry surface to Switzerland, supplies 17% of its primary energy demand with biomass (Vuille et al., 2015b). When considering the “New Energy Policies” (NEP) transition scenario for 2050 of the Swiss confederation (Prognos, 2012), the woody biomass potential of Switzerland corresponds to 9.7% of the overall energy needs.

Thinking of the carbon capture effect of photosynthesis, the woody biomass potential corresponds to a biogenic source of carbon that has captured up to 5,353 ktCO2 corresponding to 12% of the actual emissions of Switzerland (Codina Gironès et al., 2015).

The characterization of the future Swiss energy system is based on the New Energy Policy (NEP) scenario in 2050 (Prognos, 2012) that the Swiss government uses as a basis to its Energy Strategy 2050. Figure 8 presents the monthly profiles of the electricity production for the NEP scenario in 2050. The per capita electricity production and demand are 811 and 750 Wyear/inhab., respectively. This NEP scenario is based on a relatively high penetration of renewable electricity sources. The annual photovoltaic electricity production is increased to 140 Wyear/inhab. The monthly profiles show the contributions of cogeneration in the winter months and the excess electricity produced in summer. It also takes into account an increase of the height of certain dams which allows shifting around 30 Wyear/inhab. from summer to winter months (Schleiss, 2012). In this scenario, around 4.9 TWh (62.3 Wyear/inhab.) corresponding to 7.7% of the annual production has to be stored or curtailed, as it cannot a priori be exported as neighboring countries will experience the same excess production. It also represents 44.5% of the electricity produced by photovoltaic panels considered in the scenario.

This future summer excess corresponds to the current winter deficit that Switzerland covers with imports. Hence, seasonal storage would enable substituting the winter imports and increase significantly the energy independence of Switzerland while reducing the carbon footprint of its electricity. However, in the NEP scenario, it is planned that cogeneration is used to bridge the winter deficit, thanks to its capacity to jointly produce power and heat when both products are actually needed. In the NEP scenario, there is no more electricity deficit, and hence no need for seasonal storage.

Given that seasonal storage of electricity will a priori not be needed in Switzerland in 2050, an alternative use of its future excess electricity produced in the summer has to be found. In this context, biomass chemical conversion technologies combined with electrolysis are a good option for transforming the excess summer electricity into biofuels. This is the case for the wood-based bio-SNG and electrolysis pathway (see section 2.1), as well as the Fischer-Tropsch (FT) and electrolysis pathway (see sections 2.3).

The electricity-to-fuel efficiency of the FT and electrolysis pathway is higher than that of the bio-SNG and electrolysis process, 78% against 68%. However, the later process is able to store more electricity per unit of biomass energy input (1.44 kWh_e/kWh_Biomass) than the FT and electrolyisis (0.54 kWh_e/kWh_Biomass). Therefore, the bio-SNG and electrolysis process is the best option as the amount of available biomass is limited. In addition, it is the chemical conversion pathway, included in the pathways described in section 4, with the highest fossil CO₂ abatement potential. The bio-SNG and electrolysis pathway as a system for electricity storage is analyzed in detail in the following paragraphs as well as in section 5.4.

Based on the results presented in Gassner and Maréchal (2008), absorbing 4.9 TWh of excess electricity in the Swiss NEP energy transition scenario requires a 1.21 GW_WoodInput (0.13 kW/inhab.) bio-SNG and electrolysis facility with a 1.76 GW_e (0.20 kW/inhab.) electrolyzer. The annual woody biomass consumption of such a facility is 10.6 TWh (134 Wyear/inhab.), while its bio-SNG production is 10.1 TWh (127 Wyear/inhab.).

For calculating the values in the previous paragraph, the bio-SNG and electrolysis system is sized by considering the month with the highest surplus of electricity with the objective to use the entire surplus electricity in the electrolyzer. The ratio between the electricity input in the electrolyzer (Elec_in) and the wood input in the gasifier (Wood_in) takes the maximum value presented in Gassner and Maréchal (2008) for the directly heated gasification system: Elec_in/Wood_in = 1.445. The wood input power is assumed to be constant along the year, thus the Elec_in/Wood_in is lower for the other months. The gas output for month i (Gas_out,i) is calculated using Eq. 5. The necessary data for defining Eq. 5 are available in Gassner and Maréchal (2008) (directly heated gasification system case). Figure 9 shows the behavior of the system for 1 MJ of wood being gasified in 1 year. The Swiss electricity production and consumption profiles in the NEP scenario for 2050 are used to determine the electricity surplus profile.

As discussed in section 5.3, the bio-SNG and electrolysis pathway is a priori the preferred one for Switzerland. However, the implementation of this pathway in the Swiss NEP scenario is constrained by the fact that almost 90% of the woody biomass resources are already used by other existing pathways, mainly wood boilers and cogeneration units for heat and electricity production (Prognos, 2012). The untapped biomass potential is only about 6 PJ, which is significantly below the amount required for storing all the excess electricity during summer: 38 PJ of woody biomass. Therefore, it is necessary to define alternative scenarios to the NEP scenario in order to assess the impact of the implementation of this biomass pathway in the Swiss energy system in 2050.

Two alternative scenarios are proposed: the “gasification scenario” and the “photovoltaic scenario.” These two scenarios, which are presented in sections 5.4.1 and 5.4.2, have been designed using the Energyscope energy model (Codina Gironès et al., 2015). The Energyscope model has seven input variable categories: socio-economics, efficiency, transport, heating and combined heat and power, renewable electricity, non-renewable electricity, and cost (Codina Gironès et al., 2015). In the two alternative scenarios, all the inputs are kept identical to those in the NEP scenario, except for the technology mix for distributed heating (heating and combined heat and power category), and the composition of the vehicle fleet (transport category). These are the decision variables of the optimization problem to generating these alternative scenarios. The technology mix for distributed heating is composed of seven different technologies (see Table 8). Their role is to supply space heating and sanitary hot water to the households, industry, and service sectors. The weight of each technology within the mix is expressed as a percentage of the total installed power for distributed heating.

In the two alternative scenarios, the possibility of storing the CO₂ in the output of the methanation process is evaluated. The use of hydrogen for increasing the bio-SNG yield decreases the amount of CO₂ that can be captured, as the hydrogen uses the carbon from the CO₂ for the production of methane (see 2.1). The CO₂ stored can represent up to 30% of the equivalent CO₂ emissions of the Swiss energy system (point F1P4 in Table 8).

Table 8 contains the decision variables and output values of the highlighted points in Figure 10. From Figure 10, it can be directly concluded that the higher the PV penetration, the lower the CO₂ emissions. The electricity supplied by the additional installed capacity is used both to drive decentralized heat pumps and to feed electrolysers for increasing the production of bio-SNG. This use is compatible with the fact that Switzerland is expected to have no electricity deficit in 2050 (according to the NEP scenario), and that electricity export is not possible as neighboring countries will experience the same production peaks such as Switzerland. To meet these constraints, it is necessary to invest 0.3 Swiss Francs (CHF) in decentralized heat pumps and 0.6 CHF in the bio-SNG and electrolysis technologies for every CHF invested in PV capacity. The linear relation between investments is extracted from Figure 10.

The previously described strategy rises the consumption of woody biomass of the bio-SNG production facility, so the amount of woody biomass consumed by direct combustion technologies is decreased, under the assumption that no wood is imported. The extra amount of bio-SNG injected into the system replaces the fossil natural gas until the PV installed capacity reaches approximately 16.3 GW (point 3 in Figure 10). At this deployment level the decentralized heat pumps reach their maximum weight in the distributed heating mix. At this point, decentralized heat pumps cannot be the electricity sink for additional photovoltaic electricity. As there is no other technology being able to consume electricity whose capacity can be modified by the optimizer, the only option is to decrease the electricity production from other sources in order to accommodate the additional photovoltaic electricity. For this reason, the installed capacity of advanced cogeneration decreases (from 1% in point 3 to 0% in point 4). When reducing the installed capacity of advanced cogeneration, the optimizer then reacts by increasing the amount of CNG vehicles (from 0.2% in point 3 to 1.6% in point 4) and decentralized boilers (from 4.1% in point 3 to 5.2% in point 4) in order to consume all the bio-SNG produced by the biomass pathway, since we have set the constraint that no natural gas export is allowed. This explains the change on the slopes of the investment curves in Figure 10.

The annual total cost of the energy system (capital and operational cost) is calculated under the assumption that the complete energy system is rebuilt in 2050 with the efficiencies and the specific investment cost of the technologies in 2050. All the information and sources regarding efficiencies and cost can be found in footnote.³ For this analysis, the cost of the private passenger vehicles has been added into the model. The number of cars in Switzerland is assumed to grow linearly with population. As the number of cars per inhabitant has remained almost constant for the last 10 years (0.51 in 2005 vs. 0.53 in 2015), so the expected number of cars in 2050 is 4.79 millions for a 9.04 million inhabitants (0.53 car/inhabitant) (Section Mobil, 2015). Table 9 contains the considered investment cost for the types of cars. The cost taken into account into the model is the difference between the chosen vehicle fleet and 100% gasoline/diesel vehicle fleet.

Figure 11 shows the annual equivalent CO₂ emissions against the total cost of the energy system. The colors of the points indicate the level of installed PV capacity. The decision variables and output values for the marked points are given in Table 8.

It can be concluded that the vehicle fleet composition has a significant impact on both the CO₂ emissions and total cost of the Swiss energy system. F2P3 (point 3 in Figure 11) corresponds to an energy scenario in which the vehicle fleet is only composed by hybrid vehicles (70% plug-in hybrid and 30% hybrid vehicles). The scenarios with lower CO₂ emissions than F2P3 have a vehicle fleet with a high percentage of battery electric vehicles. F2P3 is the inflection point where the slope of the graph is modified due to the increasing penetration of battery electric vehicles.

Figure 12 shows the cost composition of the pareto front points of Figure 11. In the pareto front the increase in installed PV panels is linked to an increase in the investment in the vehicle fleet, which corresponds to an increased penetration of plug-in hybrid and battery electric vehicles. The consumption of biofuels and fossil fuels decreases with increasing penetration of PV panels, which reflects the electrification of the vehicle fleet. The other of the cost categories do not show any strong relationship with the installed capacity of PV panels.

The points F2P4–F2P7 (points 4–7 in Figure 11) represent energy scenarios with similar CO₂ emissions but different costs. The difference in total cost of the energy system can be explained by the level of deployment of PV. The higher the PV penetration, the lower the total cost of the energy system. The excess electricity from PV is used to produce bio-SNG according to the bio-SNG and electrolysis pathway (see section 2.1.1), which results in lower cost of natural gas imports. Therefore, the deployment of PV panels in this scenario allows to reduce the CO₂ emissions and the dependency over imports, while maintaining the total energy system cost constant. This is a conclusion with far reaching implications for energy policy making.