This study analyses the impacts of technological improvements and increased operating experience on the techno-economic performance of integrated gasification (IG) facilities. The facilities investigated produce electricity (IGCC) or FT-liquids with electricity as by-product (IG-FT). Results suggest that a state-of-the-art (SOTA) coal-fired IGCC without CO₂ capture has electricity production costs of 17€/GJ (60€/MWh) with the potential to decrease to 11€/GJ (40€/MWh) in the long term. Specific direct CO₂ emissions may drop from about 0.71kgCO₂/kWh to 0.59kgCO₂/kWh. If CO₂ is captured, production costs may increase to 23€/GJ (83€/MWh), with the potential to drop to 14€/GJ (51€/MWh) in the long term. As a result, CO₂ avoidance costs would decrease from 35€/t CO₂ to 18€/t CO₂. The efficiency penalty due to CCS may decrease from 8.8%_pt to 3.7%_pt.CO₂ emissions can also be reduced by using torrefied biomass (TOPS) instead of coal. Production costs of a SOTA TOPS-fired IGCC without CO₂ capture are 18-25€/GJ (64-92€/MWh). In the long term, this may drop to 12€/GJ (44€/MWh), resulting in CO₂ avoidance costs of 7€/t CO₂. The greatest reduction in anthropogenic CO₂ emissions is obtained by using biomass combined with carbon capture and storage (CCS). A SOTA TOPS-fired IGCC with CCS has, depending on the biomass price, production costs of 25-35€/GJ (91-126€/MWh) with CO₂ avoidance costs of 19-40€/t CO₂. These values may decrease to 15€/GJ (55€/MWh) and 12€/t CO₂ avoided in the long term. As carbon from biomass is captured, specific direct CO₂ emissions are negative and estimated at -0.93kgCO₂/kWh for SOTA and -0.59kgCO₂/kWh in the long term. Even though more carbon is sequested in the future concepts, specific emissions drop due to an increase in the energetic conversion efficiency of the future facilities. New technologies in IG-FT facilities have a slightly smaller impact on production costs. In the long term, production costs of FT-liquids from coal may drop from 13€/GJ to 9€/GJ if CO₂ is vented and from 15€/GJ to 10€/GJ if CCS is applied. The use of TOPS results in 15-23€/GJ (Vent) and 17-24€/GJ (CCS) for SOTA facilities. These production costs may drop to 11-18€/GJ (Vent) and 12-19€/GJ (CCS) in the long term. Contrary to the IGCC cases, the coal-fired IG-FT facility shows the lowest CO₂ avoidance costs. The CO₂ emission of coal to FT-liquids with CCS is, however, similar to gasoline/diesel production from crude oil.

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This study analyses the impact of technological improvements and increased operating experience on the techno-economic performance of integrated gasification facilities producing electricity and/or transportation fuels. Also, the impact of using torrefied biomass instead of coal and/or applying CCS is examined. Results indicate that current production costs of electricity and/or transportation fuels are above market prices. Future improvements, however, could reduce production costs sufficiently to make gasification facilities economical. Furthermore, although CCS can be used to reduce CO₂ emissions at relative low CO₂ avoidance costs, only the use of biomass allows the production of carbon neutral electricity and/or transportation fuels and in combination with CCS can even result in negative CO₂ emissions.

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CO₂ emissions from distributed energy systems are expected to become increasingly significant, accounting for about 20% for current global energy-related CO₂ emissions in 2030. This article reviews, assesses and compares the techno-economic performance of CO₂ capture from distributed energy systems taking into account differences in timeframe, fuel type and energy plant type. The analysis includes the energy plant, CO ₂ capture and compression, and distributed transport between the capture site and a trunk pipeline. Key parameters, e.g., capacity factor, energy prices and interest rate, were normalized for the performance comparison. The findings of this study indicate that in the short-mid term (around 2020-2025), the energy penalty for CO₂ capture ranges between 23% and 30% for coal-fired plants and 10-28% for natural gas-fired plants. Costs are between 30 and 140 €/tCO₂ avoided for plant scales larger than 100 MW _LHV (fuel input) and 50-150 €/tCO₂ avoided for 10-100 MW_LHV. In the long-term (2030 and beyond), the energy penalty for CO₂ capture might reduce to between 4% and 9% and the costs to around 10-90 €/tCO₂ avoided for plant scales larger than 100 MW _LHV, 25-100 €/tCO₂ avoided for 10-100 MW _LHV and 35-150 €/tCO₂ avoided for 10 MW_LHV or smaller. CO₂ compression and distributed transport costs are significant. For a distance of 30 km, 10 €/tCO₂ transported was calculated for scales below 500 tCO₂/day and more than 50 €/tCO₂ transported for scales below 5 tCO₂/day (equivalent to 1 MW_LHV natural gas). CO₂ compression is responsible for the largest share of these costs. CO₂ capture from distributed energy systems is not prohibitively expensive and has a significant cost reduction potential in the long term. Distributed CO₂ emission sources should also be considered for CCS, adding to the economies of scale of CO₂ transport and storage, and optimizing the deployment of CCS.

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This study assesses whether the deployment of CO 2 capture technologies in the European industrial sector would result in significant changes in the emissions of air pollutants (NO x, SO 2, PM, and NH 3) in the short term. The industrial sectors investigated were: cement, petroleum refineries, and iron and steel. The analysis included onsite emissions and changes associated with grid electricity consumption due to CO 2 capture. Post-combustion capture using monoethanolamine (MEA) was considered for the cement sector and petroleum refineries, and Top Gas Recycling Blast Furnace (TGRBF) with vacuum-pressure swing adsorption (VPSA) for the iron and steel sector. The results show that when all three industrial sectors in the EU-27 are fully equipped with CO 2 capture, industrial SO 2 emissions in the EU-27 may decrease by 40-70% whereas NH 3 emissions may increase by 120-520% (equivalent to 2-8% of total European emissions). The large increase in NH 3 emissions is due to the degradation of MEA. Cement and petroleum refineries account for nearly all these changes. The results also show limited impact (within ±10% of EU-27 industrial emissions) on NO x and PM emissions. Emission changes due to electricity import/export are found to be equally important as onsite emission changes. For the iron and steel sector, the changes in National Emissions Ceilings Directive (NECD) emissions are found to be limited for the selected CO 2 capture technique under conservative assumptions. However, the changes in the NECD emissions could vary largely depending on how the steel mill will adapt and operate their coke oven batteries that supply the coke to the blast furnace (BF).@en

This study aimed to identify the optimal techno-economic configuration of CO ₂ capture at steam methane reforming facilities using currently available technologies by means of process simulations. Results indicate that the optimal system is CO ₂ capture with ADIP-X located between the water-gas shift and pressure swing adsorption units. Process simulations of this system configuration showed a CO ₂ emission reduction of 60% at 41€/t CO ₂ avoidance. This is at the lower end of the range reported in open literature for CO ₂ capture at refineries (26-82€/t CO ₂) and below the avoidance costs for CO ₂ capture at natural gas-fired power plants (44-93€/t CO ₂). CO ₂ avoidance costs are dominated by the natural gas consumption, responsible for up to 66% of total costs. Using imported steam and electricity can reduce CO ₂ avoidance costs by 45%. Addition of small amounts of piperazine to aqueous MDEA solutions results in up to 70% smaller absorbers or 10% lower reboiler heat duty. Optimising the whole capture process instead of individual units resulted in lower piperazine concentrations than the common industrial practice (3mass% vs. 5mass%). Finally, keeping the solvent rate constant when operating the capture unit below its design load resulted in a lower specific energy for CO ₂ capture than when the solvent rate was downscaled with the syngas flow.

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In this study, we identify and characterize known and new environmental consequences associated with CO₂ capture from power plants, transport by pipeline and storage in geological formations. We have reviewed (analogous) environmental impact assessment procedures and scientific literature on carbon capture and storage (CCS) options. Analogues include the construction of new power plants, transport of natural gas by pipelines, underground natural gas storage (UGS), natural gas production and enhanced oil recovery (EOR) projects. It is investigated whether crucial knowledge on environmental impacts is lacking that may postpone the implementation of CCS projects. This review shows that the capture of CO₂ from power plants results in a change in the environmental profile of the power plant. This change encompasses both increase and reduction of key atmospheric emissions, being: NO_x, SO ₂, NH₃, particulate matter, Hg, HF and HCl. The largest trade-offs are found for the emission of NO_x and NH₃ when equipping power plants with post-combustion capture. Synergy is expected for SO₂ emissions, which are low for all power plants with CO₂ capture. An increase in water consumption ranging between 32% and 93% and an increase in waste and by-product creation with tens of kilotonnes annually is expected for a large-scale power plant (1 GW_e), but exact flows and composition are uncertain. The cross-media effects of CO₂ capture are found to be uncertain and to a large extent not quantified. For the assessment of the safety of CO₂ transport by pipeline at high pressure an important knowledge gap is the absence of validated release and dispersion models for CO₂ releases. We also highlight factors that result in some (not major) uncertainties when estimating the failure rates for CO ₂ pipelines. Furthermore, uniform CO₂ exposure thresholds, detailed dose-response models and specific CO₂ pipeline regulation are absent. Most gaps in environmental information regarding the CCS chain are identified and characterized for the risk assessment of the underground, non-engineered, part of the storage activity. This uncertainty is considered to be larger for aquifers than for hydrocarbon reservoirs. Failure rates are found to be heavily based on expert opinions and the dose-response models for ecosystems or target species are not yet developed. Integration and validation of various sub-models describing fate and transport of CO₂ in various compartments of the geosphere is at an infant stage. In conclusion, it is not possible to execute a quantitative risk assessment for the non-engineered part of the storage activity with high confidence.

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This article presents a consistent techno-economic assessment and comparison of CO₂ capture technologies for key industrial sectors (iron and steel, cement, petroleum refineries and petrochemicals). The assessment is based on an extensive literature review, covering studies from both industries and academia. Key parameters, e.g., capacity factor (91-97%), energy prices (natural gas: 8 €₂₀₀₇/GJ, coal: 2.5 €₂₀₀₇/GJ, grid electricity: 55 €/MWh), interest rate (10%), economic plant lifetime (20 years), CO₂ compression pressure (110 bar), and grid electricity CO₂ intensity (400 g/kWh), were standardized to enable a fair comparison of technologies. The analysis focuses on the changes in energy, CO₂ emissions and material flows, due to the deployment of CO₂ capture technologies. CO₂ capture technologies are categorized into short-mid term (ST/MT) and long term (LT) technologies. The findings of this study identified a large number of technologies under development, but it is too soon to identify which technologies would become dominant in the future. Moreover, a good integration of industrial plants and power plants is essential for cost-effective CO ₂ capture because CO₂ capture may increase the industrial onsite electricity production significantly. For the iron and steel sector, 40-65 €/tCO₂ avoided may be achieved in the ST/MT, depending on the ironmaking process and the CO₂ capture technique. Advanced LT CO₂ capture technologies for the blast furnace based process may not offer significant advantages over conventional ones (30-55 €/tCO ₂ avoided). Rather than the performance of CO₂ capture technique itself, low-cost CO₂ emissions reduction comes from good integration of CO₂ capture to the ironmaking process. Advanced smelting reduction with integrated CO₂ capture may enable lower steel production cost and lower CO₂ emissions than the blast furnace based process, i.e., negative CO₂ mitigation cost. For the cement sector, post-combustion capture appears to be the only commercial technology in the ST/MT and the costs are above 65 €/tCO₂ avoided. In the LT, a number of technologies may enable 25-55 €/tCO₂ avoided. The findings also indicate that, in some cases, partial CO₂ capture may have comparative advantages. For the refining and petrochemical sectors, oxyfuel capture was found to be more economical than others at 50-60 €/tCO ₂ avoided in ST/MT and about 30 €/tCO₂ avoided in the LT. However, oxyfuel retrofit of furnaces and heaters may be more complicated than that of boilers. Crude estimates of technical potentials for global CO ₂ emissions reduction for 2030 were made for the industrial processes investigated with the ST/MT technologies. They amount up to about 4 Gt/yr: 1 Gt/yr for the iron and steel sector, about 2 Gt/yr for the cement sector, and 1 Gt/yr for petroleum refineries. The actual deployment level would be much lower due to various constraints, about 0.8 Gt/yr, in a stringent emissions reduction scenario.

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This paper investigates the economics of integrated gasification polygeneration (IG-PG) facilities and assesses under which market conditions flexible facilities outperform static facilities. In this study, the facilities use Eucalyptus wood pellets (EP), torrefied wood pellets (TOPS) and Illinois #6 coal as feedstock to produce electricity, FT-liquids, methanol and urea. All facilities incorporate CCS. The findings show production costs from static IG-PG facilities ranging between 12 and 21 €/GJ using coal, 19-33 €/GJ using TOPS and 22-38 €/GJ using EP, which is above the average market prices. IG-PG facilities can become competitive if capital costs drop by 10%-27% for coal based facilities. Biomass based facilities will need lower biomass pellet prices or higher CO ₂ credit prices. Biomass becomes competitive with coal at a CO ₂ credit price of 50-55 €/t CO ₂. Variations in feedstock, CO ₂ credit and electricity prices can be offset by operating a feedstock flexible IG-PG facility, which can switch between coal and TOPS, thereby altering its electricity production. The additional investment is around 0.5% of the capital costs of a dedicated coal based IG-PG facility. At 30 €/t CO ₂, TOPS will be the preferred feedstock for 95% of the time at a feedstock price of 5.7 €/GJ. At these conditions, FT-liquids (gasoline/diesel) can be produced for 15.8 €/GJ (116 $/bbl). Historic records show price variations between 5.7 and 7.3 €/GJ for biomass pellet, 1.0-5.6 €/GJ for coal and 0-32 €/t CO ₂. Within these price ranges, coal is generally the preferred feedstock, but occasionally biomass is preferred. Lower biomass prices will increase the frequency of switching feedstock preference from coal to biomass, raising the desire for flexibility. Of the three investigated chemicals, an IG-PG facility producing FT-liquids benefits the most from flexibility. Our study suggests that if the uncertainty in commodity prices is high, a small additional investment can make flexible IG-PG facilities attractive.

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This article investigates technical possibilities and performances of flexible integrated gasification polygeneration (IG-PG) facilities equipped with CO₂ capture for the near future. These facilities can produce electricity during peak hours, while switching to the production of chemicals during off-peak hours. Several simulations were performed to investigate the influence of substituting feedstock and production on IG-PG facility output, load and efficiency. These simulations were done using a detailed AspenPlus simulation model of a Shell entrained flow gasifier combined with conversion facilities. In this model carbon-rich feedstocks (oil residues, coal and biomass) were converted to a variety of products (H₂, electricity, FT-liquids, methanol and urea) using state-of-the-art technology. The size of the gasifier was limited to the equivalent of 2000 MW_th Il #6 coal input. Overall efficiency of the simulated non-flexible configurations to convert pure coal or pure wood pellets to electricity (40%_HHV vs 38%_HHV), FT-liquids (60%_HHV vs 55%_HHV), methanol (53%_HHV vs 49%_HHV) or urea (51%_HHV vs 47%_HHV) are in good agreement with the literature. Using torrefied wood pellets instead of pure wood pellets reduces the penalty drop in efficiency compared to coal. Moreover, torrefied wood pellets have superior energetic density, handling and feeding compared to wood pellets. In this analysis, the H₂:CO ratio of the sweet syngas was fixed to match FT-liquids criterion. As a result, overall CO₂ capture rates are low, around 56-65%, depending on the feedstock used. Still, especially with FT-liquids and methanol production, CO₂ emissions at the facility are significantly reduced; less than 20% of the carbon feedstock entering the facility is emitted with the flue gas. Applying biomass and CO₂ capture shows great opportunities to produce CO₂-neutral electricity or chemicals. When the biomass fraction exceeds 40% on an energy basis, production is CO ₂-neutral, independent of what is produced. Biomass can be co-fed up till 50% on an energy basis. Higher fractions cause significant fouling on cooling equipment. A small part-load penalty is observed during the substitution of coal by biomass. When changing from pure coal to pure wood pellets, the power case suffers a 2.5% efficiency drop, while all three chemical cases have an efficiency drop of less than 1%. At the same time total output is reduced to 67-69%, mainly because of the lower energy density of biomass. By over-dimensioning the gasifier and gas cleanup and optimisation section this drop can be eliminated. The syngas can be tailored to the desired composition regardless of the used feedstock. Therefore, the chemical conversion sections only have to cope with a reduction in syngas flow and not with a change in syngas composition. Altering production between chemicals and electricity is possible, although the load of the conversion sections should remain between 40% and 100% to prevent operational problems. This gives a high degree of flexibility. Complete substitution between chemical and power production while using the same feedstock is possible for the methanol and urea cases. The FT-liquids case is restricted to 60-100% load of the chemical conversion section to prevent that the gas turbine load is reduced below 40%. The economic aspects of flexible IG-PG facilities are addressed in part B.

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This paper evaluated the economic effects of introducing flexibility to state-of-the-art integrated gasification co-generation (IGCG) facilities equipped with CO2 capture. In a previous paper the technical and energetic performances of these flexible IG-CG facilities were evaluated. This paper investigated how market conditions affect the economics of flexible IG-CG facilities by analyzing several case studies. The IG-CG facilities used Eucalyptus wood pellets, torrefied wood pellets and Illinois #6 coal as feedstock and produced electricity, FT-liquids, methanol and urea. Results indicated that currently biomass is, compared to coal, too expansive. Therefore, feedstock flexibility is not attractive. Production flexibility between chemical and electricity production under current economic conditions reduces the profitability of the IG-CG facility. Therefore, with state-of-the-art technology and the current economic climate, introducing flexibility to IG-CG facilities is not economically profitable.@en

This paper presents the methodology and the preliminary results of a techno-economic assessment of CCS implementation on the iron and steel sector. The results show that for the short-mid term, a CO₂ avoidance cost of less than 50 €/tonne at a CO₂ avoidance rate of around 50% are possible by converting the conventional blast furnace (BF) to Top Gas Recycling Blast Furnace (TGRBF). However, large additional power consumption for CO ₂ removal and oxygen generation, and reduction in BF gas export, makes the economic performance of the technology very sensitive to energy prices. Add-on CO₂ capture for conventional BF may achieve similar costs (40 - 50 €/tCO₂ avoided), but the CO₂ avoidance rate will be only about 15% of the specific CO₂ emissions. For the long term future, although there are large uncertainties, advanced CO ₂ capture technologies do not seem to have significant economic advantages over conventional technologies. The results also indicate that in a carbon-constrained society, when considering new plants, smelting reduction technologies such as the COREX process, may become a strong competitor to conventional blast furnace based steel making process when equipped with CO ₂ capture. Although conventional iron and steel making using BF is expected to dominate the market in the long term, strong need for drastic CO₂ emissions reduction may drive the sector towards large scale implementation of advanced smelting reduction technologies.

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In this paper we identify and characterize known and new environmental consequences associated with CO2 capture from power plants, transport by pipeline and storage in geological formations (CCS). The DPSIR framework, describing environmental Drivers, Pressures, States, Impacts and Responses, is used to systematically review environmental impact assessment procedures and scientific literature on CCS. Also, it is investigated whether crucial knowledge on environmental impacts is lacking that may postpone the implementation of CCS projects. The findings of this study are that the capture of CO2 from power plants results in a change in the environmental profile of the power plant. This change encompasses trade-offs and synergies in the reduction of key atmospheric emissions, being: NOx, SO2, NH3, particulate matter, Hg, HF and HCl. The largest trade-offs are found for the emission of NOx and NH3 when equipping power plants with post-combustion capture. Synergy is expected for SO2 emissions, which are low for all power plants with CO2 capture. An increase in water consumption ranging between 32% and 93% and an increase in waste and by-product creation with tens of kilotonnes annually is expected for a large-scale power plant (1 GWe), but exact flows and composition are uncertain. The cross-media effects of CO2 capture are found to be uncertain and not quantified. For the assessment of the safety of CO2 transport by pipeline at high pressure an important knowledge gap is the absence of validated release and dispersion models for CO2 releases due to pipeline failures. There is also uncertainty in estimating the failure rates for CO2 pipelines. Furthermore, uniform CO2 exposure thresholds, detailed dose-response models and specific CO2 pipeline regulation are absent. Most gaps in environmental information regarding the CCS chain are identified and characterized for the risk assessment of the underground, non-engineered, part of the storage activity. This uncertainty is considered to be larger for aquifers than for hydrocarbon reservoirs. Failure rates are found to be heavily based on expert opinions and the doseresponse models for ecosystems or target species are not yet developed. Integration and validation of various sub-models describing fate and transport of CO2 in various compartments of the geosphere is at an infant stage. Concluding, it is not possible to execute a quantitative risk assessment for the non-engineered part of the storage activity with high confidence. Finally, several recommendations have been formulated to deal with the knowledge gaps identified in this study.@en

A systematic assessment, based on an extensive literature review, of the impact of gaps and uncertainties on the results of quantitative risk assessments (QRAs) for CO₂ pipelines is presented. Sources of uncertainties that have been assessed are: failure rates, pipeline pressure, temperature, section length, diameter, orifice size, type and direction of release, meteorological conditions, jet diameter, vapour mass fraction in the release and the dose-effect relationship for CO₂. A sensitivity analysis with these parameters is performed using release, dispersion and impact models. The results show that the knowledge gaps and uncertainties have a large effect on the accuracy of the assessed risks of CO₂ pipelines. In this study it is found that the individual risk contour can vary between 0 and 204m from the pipeline depending on assumptions made. In existing studies this range is found to be between <1m and 7.2km. Mitigating the relevant risks is part of current practice, making them controllable. It is concluded that QRA for CO₂ pipelines can be improved by validation of release and dispersion models for high-pressure CO₂ releases, definition and adoption of a universal dose-effect relationship and development of a good practice guide for QRAs for CO₂ pipelines.

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Industrial Combined Heat and Power plants (CHPs) are often operated at partial load conditions. If CO₂ is captured from a CHP, additional energy requirements can be fully or partly met by increasing the load. Load increase improves plant efficiency and, consequently, part of the additional energy consumption would be offset. If this advantage is large enough, industrial CHPs may become an attractive option for CO₂ capture and storage CCS. We therefore investigated the techno-economic performance of post-combustion CO₂ capture from small-to-medium-scale (50-200 MWe maximum electrical capacity) industrial Natural Gas Combined Cycle- (NGCC-) CHPs in comparison with large-scale (400 MWe) NGCCs in the short term (2010) and the mid-term future (2020-2025). The analyzed system encompasses NGCC, CO₂ capture, compression, and branch CO₂ pipeline. The technical results showed that CO₂ capture energy requirement for industrial NGCC-CHPs is significantly lower than that for 400 MWe NGCCs: up to 16% in the short term and up to 12% in the mid-term future. The economic results showed that at low heat-to-power ratio operations, CO₂ capture from industrial NGCC-CHPs at 100 MWe in the short term (41-44 €/tCO₂ avoided) and 200 MWe in the mid-term future (33-36 €/tCO₂ avoided) may compete with 400 MWe NGCCs (46-50 €/tCO₂ avoided short term, 30-35 €/tCO₂ avoided mid-term).

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This study quantifies the trade-offs and synergies between climate and air quality policy objectives for the European power and heat (P&H) sector. An overview is presented of the expected performance data of CO2 capture systems implemented at P&H plants, and the expected emission of key air pollutants, being: SO2, NOX, NH3, volatile organic compounds (VOCs) and particulate matter (PM). The CO2 capture systems investigated include: post-combustion, oxyfuel combustion and pre-combustion capture. For all capture systems it was found that SO2, NOx and PM emissions are expected to be reduced or remain equal per unit of primary energy input compared to power plants without CO2 capture. Increase in primary energy input as a result of the energy penalty for CO2 capture may for some technologies and substances result in a net increase of emissions per kWh output. The emission of ammonia may increase by a factor of up to 45 per unit of primary energy input for post-combustion technologies. No data are available about the emission of VOCs from CO2 capture technologies. A simple model was developed and applied to analyse the impact of CO2 capture in the European P&H sector on the emission level of key air pollutants in 2030. Four scenarios were developed: one without CO2 capture and three with one dominantly implemented CO2 capture system, varying between: post-combustion, oxyfuel combustion and pre-combustion. The results showed a reduction in GHG emissions for the scenarios with CO2 capture compared to the baseline scenario between 12% and 20% in the EU 27 region in 2030. NOx emissions were 15% higher in the P&H sector in a scenario with predominantly post-combustion and lower when oxyfuel combustion (-16%) or pre-combustion (-20%) were implemented on a large scale. Large scale implementation of the post-combustion technology in 2030 may also result in significantly higher, i.e. increase by a factor of 28, NH3 emissions compared to scenarios with other CO2 capture options or without capture. SO2 emissions were very low for all scenarios that include large scale implementation of CO2 capture in 2030, i.e. a reduction varying between 27% and 41%. Particulate Matter emissions were found to be lower in the scenarios with CO2 capture. The scenario with implementation of the oxyfuel technology showed the lowest PM emissions followed by the scenario with a significant share allocated to pre-combustion, respectively -59% and -31%. The scenario with post-combustion capture resulted in PM emissions varying between 35% reduction and 26% increase.@en

This study provides insight into the feasibility of a CO₂ trunkline from the Netherlands to the Utsira formation in the Norwegian part of the North Sea, which is a large geological storage reservoir for CO₂. The feasibility is investigated in competition with CO₂ storage in onshore and near-offshore sinks in the Netherlands. Least-cost modelling with a MARKAL model in combination with ArcGIS was used to assess the cost-effectiveness of the trunkline as part of a Dutch greenhouse gas emission reduction strategy for the Dutch electricity sector and CO₂ intensive industry. The results show that under the condition that a CO₂ permit price increases from €25 per tCO₂ in 2010 to €60 per tCO₂ in 2030, and remains at this level up to 2050, CO₂ emissions in the Netherlands could reduce with 67% in 2050 compared to 1990, and investment in the Utsira trunkline may be cost-effective from 2020-2030 provided that Belgian and German CO₂ is transported and stored via the Netherlands as well. In this case, by 2050 more than 2.1 GtCO₂ would have been transported from the Netherlands to the Utsira formation. However, if the Utsira trunkline is not used for transportation of CO₂ from Belgium and Germany, it may become cost-effective 10 years later, and less than 1.3 GtCO₂ from the Netherlands would have been stored in the Utsira formation by 2050. On the short term, CO₂ storage in Dutch fields appears more cost-effective than in the Utsira formation, but as yet there are major uncertainties related to the timing and effective exploitation of the Dutch offshore storage opportunities.

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Large-scale deployment of carbon capture and storage needs a dedicated infrastructure. Planning and designing of this infrastructure require incorporation of both temporal and spatial aspects. In this study, a toolbox has been developed that integrates ArcGIS, a geographical information system with spatial and routing functions, and MARKAL, an energy bottom-up model based on linear optimization. Application of this toolbox led to blueprints of a CO₂ infrastructure in the Netherlands. The results show that in a scenario with 20% and 50% CO₂ emissions reduction targets compared to their 1990 level in respectively 2020 and 2050, an infrastructure of around 600 km of CO₂ trunklines may need to be built before 2020. Investment costs for the pipeline construction and the storage site development amount to around 720 m€ and 340 m€, respectively. The results also show the implication of policy choices such as allowing or prohibiting CO₂ storage onshore on CO₂ Capture and Storage (CCS) and infrastructure development. This paper illustrates how the ArcGIS/MARKAL-based toolbox can provide insights into a CCS infrastructure development, and support policy makers by giving concrete blueprints over time with respect to scale, pipeline trajectories, and deployment of individual storage sites.

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Large-scale implementation of carbon capture and storage needs a whole new infrastructure to transport and store CO₂. Tools that can support planning and designing of such infrastructure require incorporation of both temporal and spatial aspects. Therefore, a toolbox that integrates ArcGIS, a geographical information system with elaborate spatial and routing functions, and MARKAL, an energy bottom-up model based on linear opt imization has been developed. Application of this toolbox for devising blueprint s of a CO₂ infrastructure in the Netherlands, shows that early knowledge on the availability, potential, and suitability of sinks is of major importance for a cost-effective design of the infrastructure.

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Potentially low-cost CO2 capture may facilitate pre-commercial solid oxide fuel cell (SOFC) technology entering the energy market. The aim of this study was to compare and evaluate the techno-economic performance of CO2 capture from industrial SOFC-Combined Heat and Power plant (CHP). CO2 is captured by using oxyfuel afterburner and conventional air separation technologies. The results were compared to both SOFC-CHP plants without CO2 capture and conventional gas engines CHP without CO2 capture. The system modeling was performed using Cycle Tempo software. Our results show that while SOFC-CHP without CO2 capture requires a low SOFC stack production cost of about 310$ /kW to compete with conventional GE-CHP, SOFC-CHP with CO2 capture using large scale air separation unit can compete with GE-CHP at higher stack production costs when the CO2 price is above 37 $ /t CO2. CO2 avoidance cost of 50 $ /t CO2 can be achieved at a stack production cost of 410 $ /kWe. The results indicate that CO2 capture, even with commercially available technologies, can economically facilitate SOFC entering the energy market in a carbon-constrained society.@en

Techno-economic performance of post-combustion CO2 capture from industrial Natural Gas Combined Cycle (NGCC) Combined Heat and Power plants (CHPs) of scales from 50 MWe to 200 MWe were compared with large-scale (400 MWe) NGCC for short-term (2010) future. Four components were included in the system boundaries: NGCC, CO2 capture, compression, and branch CO2 pipeline. Effects of plant scale, operational conditions, part-load efficiency and costs of system components were investigated. The results show that CO2 capture energy requirement for industrial NGCC-CHPs may be up to 16%. lower than for 400 MWe NGCCs. Load increase to meet CO2 capture energy requirement also increases the plant efficiency and consequently offsets part of CO2 capture energy requirement. CO2 avoidance cost of below 45 €/t CO2 may be feasible.@en