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We study the role of solar heat in decarbonization of a Nordic district heating (DH) network, where most of the annual heat demand is satisfied with bioenergy. We use actual data from a Finnish municipality to create a dynamic model of the heating system with Apros® simulation software. With the help of modelling, we examine various decarbonization scenarios for the existing heating system, using different combinations solar thermal collectors, thermal energy storage (TES) and limitations on how and when solar heat can access the system. According to results, zero emissions during the summer can be achieved with annual solar share of 13.2% and at 44 €/MWh levelized cost of heat (LCoH), if the integration is supported by TES and a careful planning of solar heat integration. Our results show that a simple approach of pursuing for a maximal solar share does not necessarily lead to a reduction in carbon emission or in LCoH. In fact, aiming at higher solar shares of 15–25% in our case system, actually increase greenhouse gas emissions compared to the base case. This highlights the importance of focusing on emissions reductions instead of simple addition of renewable energy when DH utilities plan for solar heat investments.

We combine previously separate models of Northern European power markets, local district heating and cooling (DHC²2District Heating and Cooling (DHC).) systems, and biomass supply in a single modelling framework to study local and system level impacts of bioenergy technologies in phasing out fossil fuels from a DHC system of the Finnish capital. We model multiple future scenarios and assess the impacts on energy security, flexibility provision, economic performance, and emissions. In the case of Helsinki, heat only boiler is a robust solution from economic and climate perspective, but reduces local electricity self-sufficiency. Combined heat and power solution is more valuable investment for the system than for the city indicating a conflict of interest and biased results in system level models. Bringing a biorefinery near the city to utilize excess heat would reduce emissions and increase investment's profitability, but biomass availability might be a bigger limiting factor. Our results show that the availability of domestic biomass resources constrains bio-based technologies in Southern Finland and further highlights the importance of considering both local and system level impacts. Novel option to boost biorefinery's production with hydrogen from excess electricity is beneficial with increasing shares of wind power.

We develop a framework for comparing carbon-neutral synthetic fuels (CNSFs) with battery electric vehicles (BEVs) as alternatives to reducing CO2 emissions from light-duty vehicles. CNSFs can be divided into fuels produced from biomass via gasification and electrofuels produced from CO2 and water using electricity. We develop CNSF cost estimates for first-of-a-kind plants operating at commercial scale. Although already competitive over short distances, we find that longer-range BEVs are likely to remain more expensive than CNSFs even if low (∼$125/kWh) battery costs are achieved, and all three options would require carbon prices in excess of $130/tCO2 or oil prices in excess of $100/bbl to become commercially viable relative to petroleum. The viability of electrofuels ultimately depends on access to low-cost, ultra-low-carbon power systems or sources of zero-carbon electricity with high annual availability. Priorities should include deploying a portfolio of CNSF technologies to help appraise decarbonization pathways, economies of scale, and learning by doing.

The European Commission has proposed a minimum share of 3.6% for advanced biofuels in transport in 2030. Satisfying this target using synthetic biofuels would require 48–62 Mt/a of forest residue feedstock. If all biofuel plants were maximally enhanced with additional hydrogen input, the biomass demand would be reduced by 35 Mt to 16–24 Mt/a. As sustainable biomass is a limited resource, such drastic improvements in the efficiency of biomass use have a favourable impact on biomass availability. In this work we assume electrolysis of water as the source of hydrogen and investigate the GHG emission balances of hydrogen enhanced biofuels using the calculation method provided in the European Union’s sustainability criteria for biofuels. The required 70% emission saving compared to fossil fuels is achieved when the carbon intensity of electricity remains under 84–110 gCO2/kWh, depending on the process configuration. In addition, we study the possibility that an emission factor could be allocated to the wood biomass, referring to recent discussions on climate impacts of forest bioenergy. Without hydrogen enhancement, the emission factor needs to remain below 13 gCO2/MJwood to meet the 70% requirement, while for hydrogen-enhanced configurations it could increase to 36 gCO2/MJwood, under the assumption of zero emission electricity.

Potential to increase biofuels output from a gasification-based biorefinery using external hydrogen supply (enhancement) was investigated. Up to 2.6 or 3.1-fold increase in biofuel output could be attained for gasoline or methane production over reference plant configurations, respectively. Such enhanced process designs become economically attractive over non-enhanced designs when the average cost of low-carbon hydrogen falls below 2.2–2.8 €/kg, depending on the process configuration. If all sustainably available wastes and residues in the European Union (197 Mt/a) were collected and converted only to biofuels, using maximal hydrogen enhancement, the daily production would amount to 1.8–2.8 million oil equivalent barrels. This total supply of hydrogen enhanced biofuels could displace up to 41–63 per cent of the EU (European Union)'s road transport fuel demand in 2030, again depending on the choice of process design.

Large-scale systems suitable for the production of synthetic natural gas (SNG), methanol or gasoline (MTG) are examined using a self-consistent design, simulation and cost analysis framework. Three basic production routes are considered: (1) production from biomass via gasification; (2) from carbon dioxide and electricity via water electrolysis; (3) from biomass and electricity via hybrid process combining elements from routes (1) and (2). Process designs are developed based on technologies that are either commercially available or successfully demonstrated at precommercial scale. The prospective economics of future facilities coproducing fuels and district heat are evaluated from the perspective of a synthetic fuel producer. The levelised production costs range from 18-37 euros/GJ for natural gas, 21-40 euros/GJ for methanol and 23-48 euros/GJ for gasoline, depending on the production route. For a given end-product, the lowest costs are associated with thermochemical plant configurations, followed by hybrid and electrochemical plants.

The overall objective of this project was to quantify the energy, environmental, and economic performance of industrial facilities that would coproduce electricity and transportation fuels or chemicals from a mixture of coal and biomass via co-gasification in a single pressurized, oxygen-blown, entrained-flow gasifier, with capture and storage of CO{sub 2} (CCS). The work sought to identify plant designs with promising (Nth plant) economics, superior environmental footprints, and the potential to be deployed at scale as a means for simultaneously achieving enhanced energy security and deep reductions in U.S. GHG emissions in the coming decades. Designs included systems using primarily already-commercialized component technologies, which may have the potential for near-term deployment at scale, as well as systems incorporating some advanced technologies at various stages of R&D. All of the coproduction designs have the common attribute of producing some electricity and also of capturing CO{sub 2} for storage. For each of the co-product pairs detailed process mass and energy simulations (using Aspen Plus software) were developed for a set of alternative process configurations, on the basis of which lifecycle greenhouse gas emissions, Nth plant economic performance, and other characteristics were evaluated for each configuration. In developing each set of process configurations, focusedmore » attention was given to understanding the influence of biomass input fraction and electricity output fraction. Self-consistent evaluations were also carried out for gasification-based reference systems producing only electricity from coal, including integrated gasification combined cycle (IGCC) and integrated gasification solid-oxide fuel cell (IGFC) systems. The reason biomass is considered as a co-feed with coal in cases when gasoline or olefins are co-produced with electricity is to help reduce lifecycle greenhouse gas (GHG) emissions for these systems. Storing biomass-derived CO{sub 2} underground represents negative CO{sub 2} emissions if the biomass is grown sustainably (i.e., if one ton of new biomass growth replaces each ton consumed), and this offsets positive CO{sub 2} emissions associated with the coal used in these systems. Different coal:biomass input ratios will produce different net lifecycle greenhouse gas (GHG) emissions for these systems, which is the reason that attention in our analysis was given to the impact of the biomass input fraction. In the case of systems that produce only products with no carbon content, namely electricity, ammonia and hydrogen, only coal was considered as a feedstock because it is possible in theory to essentially fully decarbonize such products by capturing all of the coal-derived CO{sub 2} during the production process.« less

A process model for pressurised fluidised-bed gasification of biomass was developed using Aspen Plus simulation software. Eight main blocks were used to model the fluidised-bed gasifier, complemented with FORTRAN subroutines nested in the programme to simulate hydrocarbon and NH3 formation as well as carbon conversion. The model was validated with experimental data derived from a PDU-scale test rig operated with various types of biomass. The model was shown to be suitable for simulating the gasification of pine sawdust, pine and eucalyptus chips as well as forest residues, but not for pine bark or wheat straw.