In this paper we show the effects of expanding the system when evaluating well-to-wheel (WTW) CO₂ emissions for biomass-based transportation, to include the systems surrounding the biomass conversion system. Four different cases are considered: DME via black liquor gasification (BLG), methanol via gasification of solid biomass, lignocellulosic ethanol and electricity from a biomass integrated gasification combined cycle (BIGCC) used in a battery-powered electric vehicle (BPEV). All four cases are considered with as well as without carbon capture and storage (CCS). System expansion is used consistently for all flows. The results are compared with results from a conventional WTW study that only uses system expansion for certain co-product flows.

It is shown that when expanding the system, biomass-based transportation does not necessarily contribute to decreased CO₂ emissions and the results from this study in general indicate considerably lower CO₂ mitigation potential than do the results from the conventional study used for comparison. It is shown that of particular importance are assumptions regarding future biomass use, as by expanding the system, future competition for biomass feedstock can be taken into account by assuming an alternative biomass usage. Assumptions regarding other surrounding systems, such as the transportation and the electricity systems are also shown to be of significance.

Of the four studied cases without CCS, BIGCC with the electricity used in a BPEV is the only case that consistently shows a potential for CO₂ reduction when alternative use of biomass is considered. Inclusion of CCS is not a guarantee for achieving CO₂ reduction, and in general the system effects are equivalent or larger than the effects of CCS. DME from BLG generally shows the highest CO₂ emission reduction potential for the biofuel cases. However, neither of these options for biomass-based transportation can alone meet the needs of the transport sector. Therefore, a broader palette of solutions, including different production routes, different fuels and possibly also CCS, will be needed.

This paper evaluates the economic effects and the potential for reduced CO2 emissions when biomass gasification applications are introduced in a Swedish district heating (DH) system. The gasification applications included in the study deliver heat to the DH network while producing renewable electricity or biofuels. Gasification applications included are: external superheater for steam from waste incineration (waste boost, WE), gas engine CHP (BIGGE), combined cycle CHP (BIGCC) and production of synthetic natural gas (SNG) for use as transportation fuel. Six scenarios are used, employing two time perspectives - short-term and medium-term - and differing in economic input data, investment options and technical system. To evaluate the economic performance an optimisation model is used to identify the most profitable alternatives regarding investments and plant operation while meeting the DH demand. This study shows that introducing biomass gasification in the DH system will lead to economic benefits for the DH supplier as well as reduce global CO2 emissions. Biomass gasification significantly increases the potential for production of high value products (electricity or SNG) in the DH system. However, which form of investment that is most profitable is shown to be highly dependent on the level of policy instruments for biofuels and renewable electricity. Biomass gasification applications can thus be interesting for DH suppliers in the future, and may be a vital measure to reach the 2020 targets for greenhouse gases and renewable energy, given continued technology development and long-term policy instruments.

Biomass gasification is considered a key technology in reaching targets for renewable energy and CO2 emissions reduction. This study evaluates policy instruments affecting the profitability of biomass gasification applications integrated in a Swedish district heating (DH) system for the medium-term future (around year 2025). Two polygeneration applications based on gasification technology are considered in this paper: (1) a biorefinery plant co-producing synthetic natural gas (SNG) and district heat; (2) a combined heat and power (CHP) plant using integrated gasification combined cycle technology. Using an optimisation model we identify the levels of policy support, here assumed to be in the form of tradable certificates, required to make biofuel production competitive to biomass based electricity generation under various energy market conditions. Similarly, the tradable green electricity certificate levels necessary to make gasification based electricity generation competitive to conventional steam cycle technology, are identified. The results show that in order for investment in the SNG biorefinery to be competitive to investment in electricity production in the DH system, biofuel certificates in the range of 24-42 EUR/MWh are needed. Electricity certificates are not a prerequisite for investment in gasification based CHP to be competitive to investment in conventional steam cycle CHP, given sufficiently high electricity prices. While the required biofuel policy support is relatively insensitive to variations in capital cost, the required electricity certificates show high sensitivity to variations in investment costs. It is concluded that the large capital commitment and strong dependency on policy instruments makes it necessary that DH suppliers believe in the long-sightedness of future support policies, in order for investments in large-scale biomass gasification in DH systems to be realised.

This paper evaluates system aspects of biorefineries based on biomass gasification integrated with pulp and paper production. As a case the Billerud Karlsborg mill is used. Two biomass gasification concepts are considered: BIGDME (biomass integrated gasification dimethyl ether production) and BIGCC (biomass integrated gasification combined cycle). The systems analysis is made with respect to economic performance, global CO2 emissions and primary energy use. As reference cases. BIGDME and BIGCC integrated with district heating are considered. Biomass gasification is shown to be potentially profitable for the mill. The results are highly dependent on assumed energy market parameters, particularly policy support. With strong policies promoting biofuels or renewable electricity, the calculated opportunity to invest in a gasification-based biorefinery exceeds investment cost estimates from the literature. When integrated with district heating the BIGDME case performs better than the BIGCC case, which shows high sensitivity to heat price and annual operating time. The BIGCC cases show potential to contribute to decreased global CO2 emissions and energy use, which the BIGDME cases do not, mainly due to high biomass demand. As biomass is a limited resource, increased biomass use due to investments in gasification plants will lead to increased use of fossil fuels elsewhere in the system.

In this study we analyse economic policy support for biofuels, with the aim to determine the amount of support necessary to make investments in a gasification based biorefinery producing DME (dimethyl ether) profitable for a pulp and paper mill. As a case the integrated Swedish pulp and paper mill of Billerud Karlsborg is studied, using mixed integer linear programming and different future energy market scenarios. The results show that the required support is strongly connected to the price ratio of oil to biomass, with the support ranging from 10 EUR/MWh biofuel (lower than the present tax exemption of 14 EUR/MWh) to 61 EUR/MWh. The required support is shown to be sensitive to changes of the capital cost, but not to the pulp and paper production rate of the host mill. It is concluded that strong policy instruments will be required for forest industry based biorefineries to be desirable for the future.

This paper presents the development and use of an optimisation model suitable for analysis of biofuel production scenarios in the EU, with the aim of examining second generation biofuel production. Two policy instruments are considered – targeted biofuel support and a CO₂ cost. The results show that over 3% of the total transport fuel demand can be met by second generation biofuels at a cost of approximately 65-73 EUR/MWh. With current energy prices, this demands biofuel support comparable to existing tax exemptions (around 30 EUR/MWh), or a CO₂ cost of around 60 EUR/t_CO2. Parameters having large effect on biofuel production include feedstock availability, fossil fuel price and capital costs. It is concluded that in order to avoid suboptimal energy systems, heat and electricity applications should also be included when evaluating optimal bioenergy use. It is also concluded that while forceful policies promoting biofuels may lead to a high biofuel share at reasonable costs, this is not a certain path towards maximised CO₂ emission mitigation. Policies aiming to promote the use of bioenergy thus need to be carefully designed in order to avoid conflicts between different parts of the EU targets for renewable energy and CO₂ emission mitigation.

The European Union has set a 10 % target for the share of renewable energy in the transportation sector for 2020. To reach this target, second generation biofuels from, for example, forest residues are expected to replace around 3 % of the transport fossil fuel consumption. However, forest residues could also be utilised in the heat and electricity sectors where large amounts of fossil fuels can be replaced, thus reducing global fossil CO₂ emissions. This study investigates the use of forest residues for second generation biofuel (ethanol or methanol) or combined heat and power (CHP) production at the European level, with focus on the influence of different economic policy instruments, such as carbon cost or biofuel policy support. A techno-economic, geographically explicit optimisation model is used. The model determines the optimal locations of bioenergy conversion plants by minimising the cost of the entire supply chain. The results show that in order to reach a 3 % second generation biofuel share, a biofuel support comparable to today’s tax exemptions would be needed. With a carbon cost applied, most available forest residues would be allocated to CHP production, with a substantial resulting CO₂ emission reduction potential. The major potential for woody biomass and biofuel production is found in the region around the Baltic Sea, with Italy as one of the main biofuel importers.