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.@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

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

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.@en

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 developed a method to assess the techno-economic performance and spatial footprint of CO2 capture infrastructure configurations in industrial zones. The method has been successfully applied to a cluster of sixteen industrial plants in the Dutch industrial Botlek area (7.1MtCO2/y) for 2020-2030. The configurations differ inter alia regarding capture technology (post-, pre-, oxyfuel combustion) and location of capture components (centralized vs. plant site). Results indicate that oxyfuel combustion with centralized oxygen production and decentralized CO2 compression is the most cost effective and realistic configuration when applying CO2 capture to all industrial plants (61€/tCO2; 5.8MtCO2/y avoided), mainly due to relatively low energy costs compared to post- and pre-combustion. However, oxyfuel combustion at plant level is economically preferable when capturing CO2 from only the three largest industrial plants. For post-combustion, a separated absorber-stripper configuration (73€/tCO2; 7.1MtCO2/y avoided) is preferable from a cost perspective, due to economic scale effects of capture equipment. The optimal pre-combustion configuration shows a slightly less favorable performance (81€/tCO2; 4.4MtCO2/y avoided). Whereas many industrial plants have insufficient space available for capture equipment, centralized/hybrid configurations show no insurmountable space issues. The deployment of the most favorable configurations is addressed in Part B.@en

This article identifies and quantifies the 10 most important benchmarks for climate action to be taken by 2020–2025 to keep the window open for a 1.5°C-consistent GHG emission pathway. We conducted a comprehensive review of existing emissions scenarios, scanned all sectors and the respective necessary transitions, and distilled the most important short-term benchmarks for action in line with the long-term perspective of the required global low-carbon transition. Owing to the limited carbon budget, combined with the inertia of existing systems, global energy economic models find only limited pathways to stay on track for a 1.5°C world consistent with the long-term temperature goal of the Paris Agreement. The identified benchmarks include: Sustain the current growth rate of renewables and other zero and low-carbon power generation until 2025 to reach 100% share by 2050; No new coal power plants, reduce emissions from existing coal fleet by 30% by 2025; Last fossil fuel passenger car sold by 2035–2050; Develop and agree on a 1.5°C-consistent vision for aviation and shipping; All new buildings fossil-free and near-zero energy by 2020; Increase building renovation rates from less than 1% in 2015 to 5% by 2020; All new installations in emissions-intensive sectors low-carbon after 2020, maximize material efficiency; Reduce emissions from forestry and other land use to 95% below 2010 levels by 2030, stop net deforestation by 2025; Keep agriculture emissions at or below current levels, establish and disseminate regional best practice, ramp up research; Accelerate research and planning for negative emission technology deployment. Key policy insights These benchmarks can be used when designing policy options that are 1.5°C, Paris Agreement consistent. They require technology diffusion and sector transformations at a large scale and high speed, in many cases immediate introduction of zero-carbon technologies, not marginal efficiency improvements. For most benchmarks we show that there are signs that the identified needed transitions are possible: in some specific cases it is already happening.@en

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 MWLHV. 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 MWLHV 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 MWLHV 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.@en

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).@en

This paper evaluated the techno economic performance of several CO 2 capture-network configurations for a cluster of sixteen industrial plants in the Netherlands using bottom up analysis. Preliminary findings indicate that centralizing capture equipment instead of capture equipment at plant sites shows lower average CO2 avoidance costs for both post-combustion (central: 70€ ; decentral: 86€ ) and oxyfuel combustion (central: 63€ ; decentral: 80€ ) technology, because of economic scale effects, use of large-scale CHP plants and revenues from electricity sale to the grid. Centralizing capture equipment is particularly interesting for small point sources, since these plants benefit most from economies of scale.@en