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• The impact of delivery pressure on the design and cost of CO 2 liquefaction is investigated. • Different impurity and purity requirement scenarios are considered. • The CO 2 liquefaction cost decreases significantly with pressure for the range 7–40 bar. • Impurities have a strong impact on design, cost and comparison of the different pressures. • Purity requirements can have a strong impact on the pressure level comparison. As a first step towards identifying the optimal transport conditions for shipping CO 2 , this study investigates the impact of post-liquefaction delivery pressure on the design and cost of CO 2 liquefaction for (a) pure CO 2 (b) three impurity scenarios (c) two purity requirements. For pure CO 2 , the highest liquefaction cost is obtained at 7 bar amongst the range considered (7 to 70 bar), while a minimum lies around 40–50 bar. When different potential impurity scenarios are considered, impurities need to be purged for the low-pressure cases as these are not necessarily soluble in the liquefied CO 2 stream. As a consequence, the liquefaction cost increases significantly for low-pressure cases (up to 34% compared to the pure CO 2), and wider differences between the pressure levels are obtained. Purity requirements also have a significant impact on comparisons of delivery pressures, although this impact depends on both the impurities present and the purity requirement considered. [ABSTRACT FROM AUTHOR]

This work discusses methods for calculating the CO2 avoidance cost for Carbon Capture and Storage from the non-power generation industry. Unlike the power generation sector, three calculation methods are often used to evaluate the CO2 avoidance cost in the case of CCS from industrial sources. However, each of these methods relies on different assumptions of which potential users are not always aware. The links between these three methods are here presented and verified over an illustrative case to highlight the conditions that are required to ensure their reliable use, as well as their associated shortcomings. Finally, the basis to ensure the selection of the CO2 avoidance cost calculation method that is both valid and most efficient for cases considered by potential users are presented. Abbreviations: CCS, carbon capture and storage; CAPEX, capital expenditure; FCC, fluid catalytic cracker; OPEX, operating costs; TCR, total capital requirement. [ABSTRACT FROM AUTHOR]

This paper investigates the cost reduction opportunity of lower CO 2 capture ratios (CCR) on membrane-based CO 2 capture. A numerical model based on the attainable region approach is used to optimise and assess the cost of membrane-based processes for CO 2 capture from post-combustion flue gases containing 10–35% CO 2 , analysing five membranes and CO 2 capture ratios from 50 to 90%. Overall, these cost evaluations demonstrate that membrane-based post-combustion CO 2 capture can significantly benefit from lower CCRs (up to 55% reduction in CO 2 avoidance cost for a flue gas containing 35% CO 2 ). Considering lower CCRs could therefore enable early deployment of CCS despite low carbon emission cost, however the evaluations show that the optimal CCR and corresponding cost reduction potential shall be assessed considering the whole chain characteristics (CO 2 content in the flue gas, impurities, membrane module properties, CO 2 transport system, etc.). [ABSTRACT FROM AUTHOR]

This paper investigates various alternatives for the application of CCS at a cement plant which is one of the focus site for CCS deployment in Norway. A matrix consisting of nine CCS alternative chains is analysed in order to quantify cost reduction potentials across the CCS value chain based on an in-house techno-economic assessment methodology and tool called iCCS. In particular, the paper quantifies the strong cost reduction potential of second generation capture technologies and transport technology selection. CO 2 EOR is also identified to have a strong potential to reduce the overall CCS cost, however the cost benefits are strongly dependent on the oil value and the considered EOR injection period. The impact of the inclusion of CO 2 capture and conditioning in the cost of cement shows that public financial support will be required to ensure that the plant remain competitive under current cement market price. Finally, comparison of the full-scale capture versus part-scale capture shows, in this case, that the economies of scale are nearly compensated by the additional steam cost, therefore limiting the interest for full-scale implementation. However, joint deployment with the two other CCS potential sites in Norway (Yara and Klemenstrud) may bring more synergies. [ABSTRACT FROM AUTHOR]

This paper focuses on the identification of membrane properties required to enable cost-competitive post-combustion CO 2 capture from a coal power plant using membrane-based processes. In order to identify such properties, a numerical version of the attainable region approach proposed by Lindqvist et al., built as part of the of the iCCS tool developed by SINTEF Energy Research, is used to identify and assess the technical and cost performances of the optimal membrane process for a given set of membrane properties (selectivity and permeance). This numerical model is used to assess the cost performances of 1600 sets of membrane properties (selectivity and permeance) for post-combustion CO 2 capture from a coal power plant as defined by the European Benchmarking Task Force and compare it with the reference commercial solvent concept (MEA) to identify the membrane properties required in a base case that treats both membrane- and MEA-based processes as mature and developed. The results show that to reach this competiveness with simple process configurations requires a permeance of at least 3 m 3 (STP)/(m 2 ·h·bar) with high selectivity, or alternatively a selectivity of at least 65 with high permeances . These limits can be reduced to permeances as low as 1 m 3 (STP)/(m 2 ·h·bar) with high selectivity, or selectivities as low as 30 with high permeances, when advanced membrane process configurations are being considered. The assessments of five additional cases quantify how additional costs associated with demonstration projects and higher membrane module costs can significantly increase the selectivities and permeances required to compete with MEA based capture. In order to link the membrane development works to the results presented in this paper, the constraint introduced by Robeson's upper bound limitation, as well as data available in the literature on membrane modules and polymeric materials, are compared with the results obtained. The inclusion of the upper bound shows that the capacity to generate thin membrane film layers is important in order to avoid reducing the range of membrane properties, in which diffusion governed membrane can be interesting in term of cost performances, especially in cases that take demonstration and/or higher module costs into consideration. The comparison with literature data shows that while several membranes and polymeric materials have the potential to be cost-competitive with further properties improvements, and once membrane-based CO 2 capture becomes mature and demonstrated, financial support will be required to demonstrate and help mature the technology. Finally, ways to use the results presented here for membrane development by membrane development experts, for membrane selection by industrial users, and for technology development and demonstration support by decision-makers are discussed. [ABSTRACT FROM AUTHOR]

This paper focuses on identifying the cost limits of two single-stage pressure–vacuum swing adsorption (PVSA) cycles for post-combustion CO 2 capture if the "ideal" zero-cost adsorbent can be discovered. Through an integrated techno-economic optimisation, we simultaneously optimise the adsorbent properties (adsorption isotherms and particle morphology) and process design variables to determine the lowest possible cost of CO 2 avoided (excluding the CO 2 conditioning, transport and storage) for different industrial flue gas CO 2 compositions and flow rates. The CO 2 avoided cost for PVSA ranges from 87.1 to 10.4 € per tonne of CO 2 avoided, corresponding to CO 2 feed compositions of 3.5 mol% to 30 mol %, respectively. The corresponding costs for a monoethanolamine based absorption process, using heat from a natural gas plant, are 76.8 to 54.8 € per tonne of CO 2 avoided, respectively showing that PVSA can be attractive for flue gas streams with high CO 2 compositions. The "ideal" adsorbents needed to attain the lowest possible CO 2 avoided costs have a range of CO 2 affinities with close to zero N 2 adsorption, demonstrating promise for adsorbent discovery and development. The need for simultaneously optimising the particle morphology and the process conditions are emphasised. • Minimum cost of capture for the ideal "zero-cost" adsorbent calculated. • Process inversion optimises adsorbent properties and process simultaneously. • Minimum CO 2 avoided cost: 10.4 €/t (30% CO 2 in feed) to 87.1 €/t (3.5% CO 2 in feed). • PVSA attractive for high CO 2 concentration streams (steel, cement). • Ideal adsorbent: Wide range of CO 2 affinity and negligible N 2 affinity. [ABSTRACT FROM AUTHOR]

The pipeline has historically been the preferred means to transport CO2 due to its low cost for short distances and opportunities for economies of scale. However, interest in vessel-based transport of CO2 is growing. While most of the literature has assumed that CO2 shipping would take place at low pressure (at 7 barg and −46 °C), the issue of identifying best transport conditions, in terms of pressure, temperature, and gas composition, is becoming more relevant as ship-based carbon capture and storage chains move towards implementation. This study focuses on an in-depth comparison of the two primary and relevant transport pressures, 7 and 15 barg, for annual volumes up to 20 MtCO2/year and transport distances up to 2000 km. We also address the impact of a number of key factors on optimal transport conditions, including (a) transport between harbours versus transport to an offshore site, (b) CO2 pressure prior to conditioning, (c) the presence of impurities and of purity constraints, and (d) maximum feasible ship capacities for the 7 and 15 barg options. Overall, we have found that 7 barg shipping is the most cost-efficient option for the combinations of distance and annual volume where transport by ship is the cost-optimal means of transport. Furthermore, 7 barg shipping can enable significant cost reductions (beyond 30%) compared to 15 barg shipping for a wide range of annual volume capacities. [ABSTRACT FROM AUTHOR]

This study focuses on the techno-economic assessment integrated with detailed optimisation of a four step vacuum swing adsorption (VSA) process for post-combustion CO 2 capture and storage (CCS) from steam-methane reformer dried flue gas containing 20 mol% CO 2. The comprehensive techno-economic optimisation model developed herein takes into account VSA process model, peripheral component models, vacuum pump performance, scale-up, process scheduling and a thorough cost model. Three adsorbents, namely, Zeolite 13X (current benchmark material for CO 2 capture) and two metal–organic frameworks, UTSA-16 (widely studied metal–organic framework for CO 2 capture) and IISERP MOF2 (good performer in recent findings) are optimised to minimise the CO 2 capture cost. Monoethanolamine (MEA)-based absorption technology serves as a baseline case to assess and compare optimal techno-economic performances of VSA technology for three adsorbents. The results show that the four step VSA process with IISERP MOF2 outperforms other two adsorbents with a lowest CO 2 capture cost (including flue gas pre-treatment) of 33.6 € per tonne of CO 2 avoided and an associated CO 2 avoided cost of 73.0 € per tonne of CO 2 avoided. Zeolite 13X and UTSA-16 resulted in CO 2 avoided costs of 90.9 and 104.9 € per tonne of CO 2 avoided, respectively. The CO 2 avoided costs obtained for the VSA technology remain higher than that of the baseline MEA-based absorption process which was found to be 66.6 € per tonne of CO 2 avoided. The study also demonstrates the importance of using cost as means of evaluating the separation technique compared to the use of process performance indicators. Accounting for the efficiency of vacuum pumps and the cost of novel materials such as metal–organic frameworks is highlighted. • Techno-economic study of CO 2 capture from steam-methane reformer flue gas (20 mol% CO 2). • Capture costs (€/tonne CO 2 avoided): IISERP-MOF2=33.6; Zeolite 13X=51.4; MEA=30.1. • Cost, instead of energy/productivity, should be used to compare capture technologies. • Effect of Vacuum pump efficiency, L/D ratio and cost of Zeolite and MOF explored. • Complexity of adsorption process is high: multiple columns & multiple trains. [ABSTRACT FROM AUTHOR]

• A CO 2 absorption system is developed for marine engines with varying loads. • The operational limit and off-design performance are analyzed for the capture system. • The cost-optimal capacity and CO 2 avoided rate are identified for an actual sailing profile. • The capture unit costs less than equivalent biofuel usage for an intermediate CO 2 avoided rate. The International Maritime Organization has adopted a strategy aiming for net-zero greenhouse gas emissions from international shipping, prompting various mitigation technologies to comply with this strengthened strategy. Carbon capture technologies are increasingly being considered to satisfy the IMO strategy. In particular, amine-based carbon capture technologies, which are emerging as the most mature option, have been proposed for onboard application. However, the conventional design approach for onboard carbon capture systems, which assumes a fixed high engine load (75–100 %), does not reflect ship operations in a low engine load range, consequently leading to oversizing and unnecessary capital investment. This study designs five MEA-based onboard carbon capture systems with different capacities (sizes) based on the exhaust gas conditions. The study investigates the off-design performance over the entire engine load range while maintaining the capacity of the capture systems at their design values. To identify the optimal capacity of the onboard carbon capture system, the off-design performance is applied to an actual sailing profile in order to quantify the energy requirement, potential CO 2 reduction rate, and capture cost. The results show that smaller systems can reach a similar level of CO 2 reduction as other larger systems while reducing capture costs. This means that it is possible to reduce capture costs by decreasing the capture capacity while maintaining the carbon reduction potential. The small capacity capture system also achieves a more competitive CO 2 avoidance cost (236 € per tonne) compared to biofuel (304 € per tonne) for a similar CO 2 avoidance rate (59 %). Thus, this study demonstrates a new approach to the design of amine-based onboard carbon capture systems under variable engine loads and presents the potential of the decarbonization technology for shipping industry. [ABSTRACT FROM AUTHOR]

Transport is a key element of carbon dioxide (CO 2) capture, transport, and storage (CCTS) supply chains. Early movers, particularly inland emitters (e.g., in continental Europe), do not yet have access to a fully developed CO 2 network infrastructure connecting them with the offshore storage hubs (e.g., in the European northern seas, as these belong to the first wave of storage infrastructure that will be developed in Europe). Therefore, specific source-to-sink CCTS supply chains combining and integrating different transport options must be developed and deployed first. In this work we analyse such transport options, which include (i) tank containers that can be transported by trucks, trains, barges, or ships, (ii) dedicated tanks permanently integrated into trucks, trains, barges, or ships, and (iii) pipelines. We develop general and portable methods, criteria, and correlations to determine the cost of transport through any given connection between two nodes in a CO 2 network infrastructure, using any of the modes of transport above, as a function of distance and capacity. In particular, the correlations are based on real data collected through interviews with service providers and stakeholders. Based on the associated techno-economic assessment and the consideration of additional performance indicators of a more holistic nature, we carry out a multi-criteria assessment of the different transport options. Such multi-criteria approach allows for a holistic and transparent comparative assessment of the different alternatives for a whole CCTS supply chain, as illustrated with reference to a very specific connection. • Identification of CO 2 transport solutions at different technology readiness levels. • Solutions to transport CO 2 from inland emitters to storage sites already exist today. • Techno-economic analysis based on data from current industrial providers. • Multi-criteria comparative assessment of the CO 2 transport options. [ABSTRACT FROM AUTHOR]

• Techno-economic study of heat supply for partial carbon capture in process industry. • New method to estimate heat supply cost to enhances abatement cost curves. • Method includes multi-period optimization of heat sources; provides cost functions. • Result: Temporal variations in residual heat impact capture cost significantly. • Result: Site energy system of a refinery can supply heat to mitigate > 75% emissions. Carbon capture and storage (CCS) activities need to be ramped up to address the climate crisis. Abatement cost curves can help to identify low-cost starting points and formulate roadmaps for the implementation of CCS at industrial sites. In this work, we introduce the concept of energy supply cost curves to enhance the usefulness and accuracy of abatement cost curves. We use a multi-period mixed-integer linear programming (MILP) approach to find an optimal mix of heat sources considering the existing site energy system. For a Swedish refinery, we found that residual heat and existing boiler capacities can provide the heat necessary for CCS that avoids >75% of the site's CO 2 emissions. Disregarding the existing site energy system and relying on new heat supply capacities instead, would lead to capture costs that are 40–57% higher per tonne of CO 2 -avoided (excl. CO 2 liquefaction, transport, and final storage). Furthermore, we estimated that temporal variations of heat sources (intermittent residual heat) increases the heat supply cost and emissions by 7–26% and 9–66%, respectively. The proposed method for optimization of the energy supply mix considering temporal variations of heat sources enables detailed estimates of energy supply costs for CO 2 capture rates ranging from partial to full capture, and thus, improve abatement cost curves. [ABSTRACT FROM AUTHOR]

International shipping is crucial for freight transport, but it relies primarily on fossil fuels, contributing 3% of global greenhouse gas emissions. This calls for urgent action to decarbonize the shipping industry. While renewable-based e-fuels are a strong candidate for decarbonization of this sector in the long run, deploying these to the required scale will take significant time, considering technical modifications onboard the vessels, as well as the changes in fuel production and infrastructure for distribution. Carbon capture from ships is another route to emission reduction that can be implemented faster due to the relatively high maturity of the technology. Tankers, dry bulk carriers, and container vessels contribute a majority of global shipping emissions and are therefore prime candidates for carbon capture and storage. Solvent-based post-combustion capture is chosen for this study as it is mature and suitable for marine applications, though technical, economic, environmental, and practical challenges remain. This paper assesses the technical feasibility of the capture system for ships; both retrofit and newbuild vessels. While achieving zero-emissions presents a significant challenge, it is feasible to attain 70%–90% CO 2 reduction through carbon capture in the near term. This reduction is crucial for transforming the industry into a more sustainable and environmentally friendly state. The limitation of space onboard is identified as a key factor in determining the viability, and the 70%–100% increase in energy consumption between existing ships and newbuild will be a substantial operational challenge. However, the high fuel consumption of the capture system could be economically acceptable if the price of alternative fuels remains high. [ABSTRACT FROM AUTHOR]

In the literature, different energy carriers are proposed in future long-distance hydrogen value chains. Hydrogen can be stored and transported in different forms, e.g. as compressed dense-phase hydrogen, liquefied hydrogen and in chemically bound forms as different chemical hydrides. Recently, different high-level value chain studies have made extrapolative investigations and compared such options with respect to energy efficiency and cost. Three recent journal papers overlap as the liquid hydrogen option has been considered in all three studies. The studies are not fully aligned in terms of underlying assumptions and battery limits. A comparison reveals partly vast differences in results for chain energy efficiency for long-distance liquid hydrogen transport, which are attributable to distinct differences in the set of assumptions. Our comparison pinpoints the boiloff ratio, i.e. evaporation losses due to heat ingress, in liquid hydrogen storage tanks as the main cause of the differences, and this assumption is further discussed. A review of spherical tank size and attributed boiloff ratios is presented, for existing tanks of different vintage as well as for recently proposed designs. Furthermore, the prospect for further extension of tanks size and reduction of boiloff ratio is discussed, with a complementary discussion about the use of economic assumptions in extrapolative and predictive studies. Finally, we discuss the impact of battery limits in hydrogen value chain studies and pinpoint knowledge needs and the need for a detailed bottom-up approach as a prerequisite for improving the understanding for pros and cons of the different hydrogen energy carriers. • Liquid hydrogen (LH 2) is a prospective hydrogen energy carrier among other options. • A review of recent value chain studies reveals highly differing estimates for overall energy efficiency, which are attributable to differences in underlying assumptions. • Assumptions pertaining boiloff ratio in LH 2 storage tanks are discussed on the background of proven technology as well as expectations for capacity and performance extrapolations. • Differences in techno-economic assumptions and battery limits are discussed. The presumptive main assumptions in different studies and their potential impacts on overall results are reviewed, compared and discussed. [ABSTRACT FROM AUTHOR]

This paper investigates the deployment over time of a shipping infrastructure to enable carbon capture and storage from Norwegian industries. In particular, optimal transport investments, routing, shipping portfolio, and transport conditions required cost-efficiently connect nine Norwegian and Swedish industrial facilities to the Northern Light Initiative are identified based on a multi-period mixed-integer model. Optimization of the shipping portfolio allows us to analyze the potential benefits of economics of scale and how sailing multi-stop routes can utilize the potential benefits. Analyses show that the transport cost can be reduced by 12% when the optimal shipping portfolio is implemented instead of operating an independent transport chain for each emission source. Shipping at 7-bar is expected to result in lower costs compared 15-bar shipping, but a significant drawback is the technological maturity of the 7-bar transport technology. The model proposes two transport chains run in parallel as cost optimal, the average transport cost of the 15-bar chain is 32.4 €/ton, and the 7-bar has an average cost of 25.4 €/ton. A net present value criterion is used to identify the conditions for when retrofitting of the 15-bar transport chain is economically sound. Break-even is achieved when the ship's re-sale price is 60% of the purchase price, and the cost of retrofitting a 15-bar conditioning plant to a 7-bar is 40% of the investment cost. While retrofitting may be an attractive solution, the decisions lead to a less robust shipping portfolio, and the retrofitting of a fully operating carbon capture and storage value chain is regarded as unlikely. [ABSTRACT FROM AUTHOR]

Capture conditions for CO2 vary substantially between industrial point sources. Depending on CO2 fraction and pressure level, different capture technologies will be required for cost- and energy-efficient decarbonisation. For decarbonisation of shifted synthesis gas from coal gasification, several studies have identified low-temperature CO2 capture by condensation and phase separation as an energy- and cost-efficient option. In the present work, a process design is proposed for low-temperature CO2 capture from an Integrated Gasification Combined Cycle (IGCC) power plant. Steady-state simulations were carried out and the performance of the overall process, as well as major process components, were investigated. For the baseline capture unit layout, delivering high-pressure CO2 at 150 bar, the net specific power requirement was estimated to 273 kJe/kgCO2, and an 85% CO2 capture ratio was obtained. The impact of 12 different process parameters was studied in a sensitivity analysis, the results of which show that compressor and expander efficiencies, as well as synthesis gas separation temperature, have the highest impact on power requirements. Modifying the process to producing cold liquid CO2 for ship transport resulted in 16% increase in net power requirements and is well suited for capturing CO2 for ship transport. [ABSTRACT FROM AUTHOR]

Abstract: A carbon chain analysis is applied to assess a complex energy conversion system with CO2 capture and storage (CCS). A coal integrated gasification combined cycle, with CCS, which co-produces electricity and liquid fuels (IGCC–LF–CCS) is taken as a case study. A process simulation method is used to estimate the technological data, and balance the heat and electricity for the whole system. Carbon and energy flows are calculated to evaluate the mass conversion efficiency and the energy efficiency. The results show that in the case in which one third of the coal is allotted to synthesize liquid fuels, globally 60% carbon is captured for storage, 19% transferred to liquid fuels, 19% emitted to the atmosphere, while the remaining carbon is discharged as waste. For the energy flow, 28.1% of total higher heating value of coal is converted into the liquid fuels. The net electricity efficiency is 20.7% accounting for the power demands by air separation, CO2 capture and compression. Three scenarios with different ratio of resource to produce electricity and liquid fuels with or without CCS have been studied. This work will provide useful information for the coal utilization with CCS in a carbon-constrained world. [Copyright &y& Elsevier]

Low-carbon hydrogen is considered as one of the key measures to decarbonise continental Europe and Japan. Northern Norway has abundant renewable energy and natural gas resources which can be converted to low-carbon hydrogen. However, Norway is located relatively far away from these markets and finding efficient ways to transport this hydrogen to the end-user is critical. In this study, liquefied hydrogen (LH 2) and ammonia (NH 3), as H 2 -based energy carriers, are analysed and compared with respect to energy efficiency, CO 2 footprint and cost. It is shown that the LH 2 chain is more energy efficient and has a smaller CO 2 footprint (20 and 23 kg-CO 2 /MWh th for Europe and Japan, respectively) than the NH 3 chain (76 and 122 kg-CO 2 /MWh th). Furthermore, the study finds the levelized cost of hydrogen delivered to Rotterdam to be lower for LH 2 (5.0 EUR/kg-H 2) compared to NH 3 (5.9 EUR/kg-H 2), while the hydrogen costs of the two chains for transport to Japan are in a similar range (about 7 EUR/kg-H 2). It is also shown that under optimistic assumptions, the costs associated with the LH 2 chain (3.2 EUR/kg-H 2) are close to meeting the 2030 hydrogen cost target of Japan (2.5 EUR/kg-H 2). • LH 2 and NH 3 are analysed and compared regarding efficiency, CO 2 footprint and cost. • The LH 2 chain is associated with less CO 2 emissions than the NH 3 chain. • The hydrogen cost delivered to Rotterdam is lower for LH 2 compared to NH 3. • Two chains have similar costs delivered to Japan under conservative assumptions. • The LH 2 chain costs almost meet the target of Japan under optimistic assumptions. [ABSTRACT FROM AUTHOR]

Industry is responsible for one-quarter of the global CO 2 emissions. In this study, four different climate pathways are analyzed with a cost minimizing multihorizon stochastic optimization model, in order to analyze possible realizations of carbon capture and storage (CCS) in the power sector and main industrial sectors in Europe. In particular, we aim to achieve a deeper understanding of the distribution of capture by country and key sector (power, steel, cement and refinery), as well as the associated transport and storage infrastructure for CCS. Results point to the synergy effect of sharing common CCS infrastructres among power and major industrial sectors. The contribution of CCS is mainly found in three industrial sectors, particularly steel, cement and refineries) but also in the power sector to a lesser extent. It is worth noting that retrofitting of CCS in the power sector was not considered in this study. The geographical location for capture and storage, as well as timing and capacity needs are presented for different socio-economic pathways and corresponding emission targets. It has been shown that contributions of the three industry sectors in emissions reductions are neither geographically nor sector-wise homogeneous across the pathways. • Study of potential synergies between shared CCS infrastructure in the power sector and industry. • Study of the interplay between CCS and renewables in the power sector. • CCS strategies for the steel, cement and refinery sectors of Europe. • Timing and investment volumes needed to capture, transport and store CO 2. • Guided by climate targets of socio-economic pathways of IPCC. [ABSTRACT FROM AUTHOR]

A technical evaluation of CO2 capture technologies when retrofitted to a cement plant is performed. The investigated technologies are the oxyfuel process, the chilled ammonia process, membrane-assisted CO2 liquefaction, and the calcium looping process with tail-end and integrated configurations. For comparison, absorption with monoethanolamine (MEA) is used as reference technology. The focus of the evaluation is on emission abatement, energy performance, and retrofitability. All the investigated technologies perform better than the reference both in terms of emission abatement and energy consumption. The equivalent CO2 avoided are 73–90%, while it is 64% for MEA, considering the average EU-28 electricity mix. The specific primary energy consumption for CO2 avoided is 1.63–4.07 MJ/kg CO2, compared to 7.08 MJ/kg CO2 for MEA. The calcium looping technologies have the highest emission abatement potential, while the oxyfuel process has the best energy performance. When it comes to retrofitability, the post-combustion technologies show significant advantages compared to the oxyfuel and to the integrated calcium looping technologies. Furthermore, the performance of the individual technologies shows strong dependencies on site-specific and plant-specific factors. Therefore, rather than identifying one single best technology, it is emphasized that CO2 capture in the cement industry should be performed with a portfolio of capture technologies, where the preferred choice for each specific plant depends on local factors. [ABSTRACT FROM AUTHOR]

This paper presents an assessment of the cost performance of CO2 capture technologies when retrofitted to a cement plant: MEA-based absorption, oxyfuel, chilled ammonia-based absorption (Chilled Ammonia Process), membrane-assisted CO2 liquefaction, and calcium looping. While the technical basis for this study is presented in Part 1 of this paper series, this work presents a comprehensive techno-economic analysis of these CO2 capture technologies based on a capital and operating costs evaluation for retrofit in a cement plant. The cost of the cement plant product, clinker, is shown to increase with 49 to 92% compared to the cost of clinker without capture. The cost of CO2 avoided is between 42 €/tCO2 (for the oxyfuel-based capture process) and 84 €/tCO2 (for the membrane-based assisted liquefaction capture process), while the reference MEA-based absorption capture technology has a cost of 80 €/tCO2. Notably, the cost figures depend strongly on factors such as steam source, electricity mix, electricity price, fuel price and plant-specific characteristics. Hence, this confirms the conclusion of the technical evaluation in Part 1 that for final selection of CO2 capture technology at a specific plant, a plant-specific techno-economic evaluation should be performed, also considering more practical considerations. [ABSTRACT FROM AUTHOR]