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.

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.

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This paper is written in response to the paper "How green is blue hydrogen?" by R. W. Howarth and M. Z. Jacobson. It aims at highlighting and discussing the

The present work aims to study the transient performance of a commercial-scale natural gas combined cycle (NGCC) power plant with post-combustion CO2 capture (PCC) system via linked dynamic process simulation models. The simulations represent real-like operation of the integrated plant during load change transient events with closed-loop controllers. The focus of the study was the dynamic interaction between the power plant and the PCC unit, and the performance evaluation of decentralized control structures. A 613 MW three-pressure reheat NGCC with PCC using aqueous MEA was designed, including PCC process scale-up. Detailed dynamic process models of the power plant and the postcombustion unit were developed, and their validity was deemed sufficient for the purpose of application.Dynamic simulations of three gas turbine load-change ramp rates (2%/min, 5%/min and 10%/min) showed that the total stabilization times of the power plant's main process variables are shorter (10-30 min) than for the PCC unit (1-4 hours). A dynamic interaction between the NGCC and the PCC unit is found in the steam extraction to feed the reboiler duty of the PCC unit. The transient performance of five decentralized PCC plant control structures under load change was analyzed. When controlling the CO2 capture rate, the power plant performs in a more efficient manner at steady-state part load; however, the PCC unit experiences longer stabilization times of the main process variables during load changes, compared with control structures without CO2 capture rate being controlled. Control of L/G ratio of the absorber columns leads to similar part load steady-state performance and significantly faster stabilization times of the power plant and PCC unit's main process variables. It is concluded that adding the PCC unit to the NGCC does not significantly affect the practical load-following capability of the integrated plant in a day-ahead power market, but selection of a suitable control structure is required for efficient operation of the process under steady-state and transient conditions.

We present a comparison of three strategies for the introduction of new biorefineries: standalone and centralized drop‐in, which are placed within a cluster of chemical industries, and distributed drop‐in, which is connected to other plants by a pipeline. The aim was to quantify the efficiencies and the production ranges to support local transition to a circular economy based on biomass usage. The products considered are biomethane (standalone) and hydrogen/biomethane and sustainable town gas (centralized drop‐in and distributed drop‐in). The analysis is based on a flow‐sheet simulation of different process designs at the 100 MWbiomass scale and includes the following aspects: advanced drying systems, the coproduction of ethanol, and power‐to‐gas conversion by direct heating or water electrolysis. For the standalone plant, the chemical efficiency was in the range of 78–82.8 % LHVa.r.50 % (lower heating value of the as‐received biomass with 50 % wet basis moisture), with a maximum production of 72 MWCH4 , and for the centralized drop‐in and distributed drop‐in plants, the chemical efficiency was in the range of 82.8–98.5 % LHVa.r.50 % with maximum production levels of 85.6 MWSTG and 22.5 MWnormalH2 /51 MWCH4 , respectively. It is concluded that standalone plants offer no substantial advantages over distributed drop‐in or centralized drop‐in plants unless methane is the desired product.