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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.

Several Nordic countries and the EU have adopted net-zero greenhouse gas emission targets. Achieving net-zero will necessitate CO2 removal from the atmosphere to offset residual emissions that are challenging to mitigate. Bioenergy with CO2 capture and storage (BECCS) is a technology that has the potential to generate large-scale CO2 removal and contribute to the attainment of net-zero targets. The report describes the status of BECCS in the Nordic countries and globally. Significant initiatives in the Nordic countries are mapped. Challenges on the market that inhibit BECCS development are analyzed and areas of cooperation and joint initiatives on the Nordic level that could promote the development and deployment of BECCS are proposed. The project has been carried out by IVL Swedish Environmental Research Institute in collaboration with CICERO (Norway) and VTT (Finland).

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 potential to increase biofuel output from a fast pyrolysis-based biorefinery through hydrogen enhancement is assessed for thermal fast pyrolysis (TFP) and catalytic pyrolysis (CAT) processes featuring bio-oil upgrade into gasoline, diesel and heavy hydrocarbon fractions. Results show that utilizing pyrolysis process off-gases to produce synthetic natural gas with an external hydrogen source could provide up to 48.2% (TFP) and 61.2% (CAT) reductions in biomass resource utilization. These savings are enabled by significantly improved carbon efficiency of the hydrogen enhanced designs, with efficiencies increasing from 40.5% to 66.3% for TFP and from 28.9% to 58.6% for CAT. Although the CAT process has a lower biofuel yield than the TFP process, it has a higher potential for hydrogen enhancement and achieves a higher biofuel output than TFP when fully enhanced with external hydrogen. The trade-off to the improved biofuel yield (higher carbon efficiency) is the substantial need for electricity to produce hydrogen via electrolysis, as for every megajoule (MJ) of biomass feedstock, 0.65–0.66 MJ of electricity is needed for the electrolyser.

The invention relates to a method and apparatus for producing carbon monoxide, wherein the carbon monoxide is formed from a gaseous feed (1) which comprises at least carbon dioxide. The method comprises supplying oxygen (2) to a carbon dioxide stream (3) for forming a carbon dioxide based mixture (4), supplying the carbon dioxide based mixture (4) to a hydrogen based stream (5) to form the gaseous feed (1), supplying a hydrocarbon containing stream (6) to the hydrogen based stream (5) before the supply of the carbon dioxide based mixture (4), feeding the gaseous feed (1) into a reactor (7) which comprises at least one catalyst, treating the gaseous feed (1) by means of a partial oxidation in the reactor (7) so that carbon dioxide reacts with hydrogen in the reactor in presence of oxygen and heat is formed during the reaction, and recovering a product composition (8) comprising at least carbon monoxide and hydrogen from the reactor (7). Further, the invention relates to the use of the method.Patent family as of 22.12.2021CA3093759 AA 20200911 CA20193093759 20190312 EP3765404 A1 20210120 EP20190767777 20190312 EP3765404 A4 20211208 EP20190767777 20190312 FI127925 B 20190531 FI20180005232 20180313 FI20185232 A 20190531 FI20180005232 20180313 US2021246034 AA 20210812 US20200980132 20190312 WO19175476 A1 20190919 WO2019FI50204 20190312Link to currentpatent family on right

FLEXCHX Workshop Prodeedings, 3 April 2019 Lithuania

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.

Reforming is a key enabling technology for the production of tar and hydrocarbon free synthesis gas from biomass. In this work, two different reforming concepts, steam and autothermal reforming, were studied for cleaning of biomass-derived gasification gas. Long-term laboratory scale experiments (around 500 h) were carried out with two model biomass gasification gas compositions with low and medium hydrocarbon loads. The experiments were made using nickel and precious metal catalysts at atmospheric pressure and at temperatures around 900–950 °C. The deactivation of the catalysts was followed. Gas with low hydrocarbon content could be steam reformed with nickel and precious metal catalyst. Both autothermal and steam reforming modes were studied for gas with medium hydrocarbon content. In steam reforming mode, the catalysts deactivated more than in autothermal mode. Based on the experiments H 2 O/C REF molar ratio above 4 and O/C REF molar ratio above 8 are recommended. A concept assessment was carried out to examine plant level impacts of the reforming approaches to synthesis gas production. The results showed that the choice of reforming concept has only limited impact to the overall efficiency of synthetic biofuel production.

The biomass gasification process is modelled by utilising constrained thermodynamic equilibrium. The formation of char, tar, ammonia and light hydrocarbons and related syngas composition were described by extending the conventional chemical system with additional immaterial constraints and by defining process-dependent values for these constraints. Six different model structures were evaluated from global thermodynamic equilibrium to fully constrained local equilibrium. When models were validated against gasification setups, it was not necessary to fully constrain the system, as sufficient results were obtained by implementing constraints for char, tar, ammonia, CH4 formation as well as for the amount of carbon in light hydrocarbons. The method was shown to be versatile when it was validated against other gasification setups: by altering the models defining the constraints a new gasification conditions could be simulated. A clear benefit of the proposed method is that the gasification process can be resolved as a restricted partial equilibrium with a single calculation step. Another benefit is that chemical reactions, gasification enthalpy and the states of the system are estimated concurrently.

This paper summarises the long development work done at VTT for gas clean-up for various synthesis applications. The development work has covered the most challenging and costly steps in biomass gasification based processes: high-temperature gas filtration and reforming of hydrocarbon gases and tars. The tar content of product gas is one of the main factors defining the temperature window in which the hot-gas filter can be operated, which in the case of fluidized-bed gasification is at 350–500 °C. Research is ongoing to achieve higher and thus more economical operation temperatures. Optimal operation of a catalytic reformer can be achieved by using a staged reformer where zirconia-based catalysts are used as a pre-reformer layer before nickel and/or precious metal-based catalyst stages. The temperature of the reformer is optimally increased in subsequent stages from 600 up to 1,000 °C. According to the techno-economic analysis, increasing the hot-gas filtration temperature by 300 °C or methane conversion in the reformer from 55 to 95 % both lead to about 5 % reduction the liquid fuel production cost.

This study examines the impact of biomass drying on the overall efficiency of a Biomass-to-Liquids (BTL) process co-producing Fischer-Tropsch (FT) syncrude and heat. The proposed BTL process is based on steam-blown dual fluidised-bed gasification of biomass, simplified gas clean-up and FT synthesis. Biomass drying was found to have a significant effect on both the FT product yield and the overall thermal efficiency of the BTL plant. In the considered concept, FT off-gases are used as supplementary feedstock in the oxidiser, alongside with char, to satisfy the heat demand in gasification. Drying of the biomass feedstock leads to reduced need of water evaporation during gasification. This in turn reduces the demand for off-gases in the oxidiser, and allows to produce more syncrude (and less off-gases) in the FT unit. The simulations indicated that more extensive drying could result in a significant increase in FT syncrude yield: the thermal efficiency of FT syncryde production increased from 47.7% to 54.6% as the moisture mass fraction of the biomass feed was reduced from 30% to 8%. The highest overall thermal efficiencies of 85–88% were obtained with a two-stage drying concept that combines a belt dryer and an indirectly-heated steam dryer.

A model for pressurised steam/O2-blown fluidised-bed gasification of biomass with catalytic reforming of hydrocarbons and tars was developed using Aspen Plus simulation software. Seven main blocks were used to model the fluidised-bed gasifier and two for the catalytic reformer. Modelling blocks were complemented with FORTRAN subroutines to simulate the observed non-equilibrium behaviour of the process. The model was fitted with experimental data derived from a 0.5 MW scale test rig operated with crushed wood pellets and forest residues and was shown to be capable of predicting product gas composition from gasification of clean wood. A parametric analysis indicated that a significant improvement in the syngas efficiency could be achieved by rising the filtration temperature and reformer conversions. Other improvement possibilities include fuel drying and lower reforming temperature.

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.

A thermochemical processing route from biomass residues to light olefins (ethylene and propylene) is assessed by means of process simulation and cost analysis. A two-step process chain is proposed where (1) biomass residues are first converted to synthetic methanol in a gasification plant situated close to feedstock resources and (2) the produced methanol is transported to a steam cracking site where it is further converted in a methanol to olefins (MTO) plant. Possibilities for heat and product integration as well as equipment sharing with a steam cracking plant are discussed. Overall mass yields from dry biomass to light olefins range from 169 to 203 kg/t. Based on cursory capital cost estimates, the maximum methanol purchase price for such integrated MTO plants is estimated to be in the range of 420–450 €/t.

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 share of gasification and gas clean-up equipment for a plant producing synthetic fuels from biomass is in the range of 50-55 % of the total capital investment cost. Due to the stringent purity requirements, set by the downstream synthesis island, the gas clean-up needs to be carried out in several steps. The most important of these are a) high-temperature gas filtration b) reforming of hydrocarbon gases and tars in order to increase the yield of CO and H2, c) shift conversion to adjust the H2-CO ratio of syngas to meet the stoichiometric requirements of the downstream synthesis and d) gas cooling with effective heat integration and waste heat utilisation. Gas filtration is a key step in product gas cleaning. Effective filtration can be achieved with ceramic or metallic filter elements or by lower cost fibrous ceramic elements. These high temperature filter materials and filtration systems have been studied by VTT for cleaning of medium/high tar loaded gasification gas in various process applications. Tar content of product gas defines the temperature window in which the filter can be operated. In practice, product gas derived from fluidised-bed gasification of biomass is filtered at 500 - 600 °C, but research is on-going to achieve higher and thus more economical operation temperatures. Catalytic treatment, or reforming, of the gas offers a simple and economical way to solve gas clean-up problems related to tars and light hydrocarbons . Nickel catalysts are active in decomposition of these impurities but they are easily poisoned by sulphur compounds at temperatures below 900 °C and are easily deactivated due to coke deposits. Alternative tar decomposition catalysts are zirconia based and precious metal catalysts. Both are less prone to coking than nickel and can be operated at lower temperatures. The suitability of these catalysts was studied in various alternative configurations. The main finding is that optimal operation can be achieved by using a staged reformer so that zirconia based catalysts are used as pre-reformer layer before the nickel catalyst stage. The performance of the reformer can further be improved by using precious metal catalysts as a one layer in the staged reformer. Optimal operation of the reformer can be achieved by gradually increasing temperature in subsequent stages from 600 up to 1000 °C. The most important limitations set by the catalysts has also been studied and identified. The techno-economic feasibility of plants producing SNG or hydrogen was studied using Aspen Plus simulation. The effect of different catalytic reforming options to the thermodynamic efficiencies and production costs was examined and results will be presented. Detailed techno-economic assessments have indicated that in the case of plant processing 100 MWth of biomass, on the assumption of mature technology: 1) Gasification based technology for the manufacture of SNG has a levelised production cost of around 60 -70 /MWh. 2) Gasification based technology for the manufacture of hydrogen has a levelised production cost of around 50-60 /MWh. 3) Around 5 - 8 /MWh improvement in the production cost of SNG or hydrogen can be achieved by tailoring the right reforming process for a given product. Highest overall efficiencies from biomass to saleable energy products (of the order of 75 - 80 %) can be achieved when SNG or hydrogen are co-produced with district heat or process steam.

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.

Shifting from fossil-fuel based energy system to renewable energy sources requires the adaptation of conventional technologies but also creation of new technologies. Both economic and technical aspects need to be considered in order to secure their successful introduction to markets. This article discusses two concepts: Power-to-Methanol and Methanol-to-Power that, combined, enable a closed energy cycle where methanol is used as energy carrier. The adaptation of conventional methanol synthesis technology using CO2-rich feed gases was successfully demonstrated under laboratory conditions, thus proving technical feasibility of this part of the Power-to-Methanol concept. However, techno-economic analysis revealed highly challenging process economics under present day cost assumptions. Portable Methanol-to-Power (MtP) generators were shown to achieve energy efficiencies that range from 36 % to 50 %. Despite the relatively high initial investment cost of these generators, they were shown to become more profitable in comparison to conventional portable power generators at long operational times due to their high energy efficiency.