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Abstract: The use of aqueous ammonia is a promising option to capture carbon dioxide from the flue gas of coal-fired power plants. Compared to a capture process using monoethanolamine (MEA), the use of ammonia can reduce the heat requirement of the CO2 desorption significantly, although an additional effort is necessary to provide the cooling of the process. To allow for a fair evaluation of the integration of this CO2 capture process into a power plant process, an overall process evaluation is carried out. The use of detailed models of the power plant, of the compressor and of the CO2 capture process enables the calculation of the power loss due to the steam extraction as well as due to the required auxiliary power for CO2 compression, solvent and cooling pumps and mechanical chillers. To study the influence of the cold end of the process, two power plants with different cooling water temperatures are analysed. Additionally, two different process configurations of the capture plant, with either one single absorber or two absorbers connected in series where the first absorber captures the majority of the CO2 and the second limits the NH3 slip, are evaluated. The influence of the main process parameters (desorber pressure, solvent circulation rate, solvent recycling rate and chilling temperature) are evaluated and the optimal configuration with respect to the overall net efficiency penalty is determined. The study shows that the configuration of the process with absorption at low temperature (approximately 10°C) with or without precipitation of ammonium carbonate compounds leads to a lower net efficiency penalty than an MEA-based process, assuming that low temperature cooling water is available. An estimate of the size of the absorber shows that the absorber columns of an ammonia-based process are significantly higher than the ones required for an MEA-based process. [Copyright &y& Elsevier]

Abstract: When integrating a post-combustion CO2 capture process and CO2 compression into a steam power plant, the three interface quantities heat, electricity and cooling duty must be satisfied by the power plant, leading to a loss in net efficiency. The heat duty shows to be the largest contributor to the overall net efficiency penalty of the power plant. Additional energy penalty results from the cooling and electric power duty of the capture and compression units. In this work, the dependency of the energy penalty on the quantity and quality of the heat duty is analyzed and quantified for a state-of-the-art hard coal fired power plant. Furthermore, the energy penalty attributed to the additional cooling and power duty is quantified. As a result correlations are provided which enable to predict the impact of the heat, cooling and electricity duty of post-combustion CO2 capture processes on the net output of a steam power plant in a holistic approach. [Copyright &y& Elsevier]

Abstract: An ideal solvent for CO2 capture by chemical absorption has to meet a number of requirements, such as high CO2 capacity, high rate of reaction, low costs, low corrosive behaviour, low degradation and low vapour pressure; above all, it has to show a low regeneration heat duty. This heat can be approximated as the sum of three terms: the sensible heat to raise the solvent from absorber to desorber temperature, the heat of evaporation required to produce the stripping steam in the reboiler, and the heat necessary to desorb the CO2 from the solution (heat of absorption). Many solvent screening studies focus almost exclusively on solvents that show a low heat of absorption. In these studies, the strong dependence of the three contributors to the overall regeneration heat duty on the chosen process parameters and on one another are often neglected. This work explains why the focus on solvents with a low heat of absorption, without considering the overall process, is not sufficient in quantifying the energy performance of alternative solvents. By using thermodynamic interrelations and underpinned by process simulations it is shown that operating parameters of the process, in particular the desorber pressure, must be taken into consideration in the evaluation of new solvents. [Copyright &y& Elsevier]

Abstract: The simulation tool ASPEN Plus® is used to model the full CO2-capture process for chemical absorption of CO2 by piperazine-promoted potassium carbonate (K2CO3/PZ) and the subsequent CO2-compression train. Sensitivity analysis of lean loading, desorber pressure and CO2-capture rate are performed for various solvent compositions to evaluate the optimal process parameters. EbsilonProfessional® is used to model a 600MWel (gross) hard coal-fired power plant. Numerical equations for power losses due to steam extraction for solvent regeneration are derived from simulation runs. The results of the simulation campaigns are used to find the process parameters that show the lowest specific power loss. Subsequently, absorber and desorber columns are dimensioned to evaluate investment costs for these main components of the CO2-capture process. Regeneration heat duty, net efficiency losses and column investment costs are then compared to the reference case of CO2-capture by monoethanolamine (MEA). CO2-capture by piperazine-promoted potassium carbonate with subsequent CO2-compression to 110bar shows energetic advantages over the reference process which uses MEA. Additionally, investment costs for the main components in the CO2-capture process (absorber and desorber columns) are lower due to the enhanced reaction kinetics of the investigated K2CO3/PZ solvent which leads to smaller component sizes. [Copyright &y& Elsevier]

Abstract: The oxyfuel process is one of the most promising options to capture CO2 from coal fired power plants. The combustion takes place in an atmosphere of almost pure oxygen, delivered from an air separation unit (ASU), and recirculated flue gas. This provides a flue gas containing 80–90vol% CO2 on a dry basis. Impurities are caused by the purity of the oxygen from the ASU, the combustion process and air ingress. Via liquefaction a CO2 stream with purity in the range from 85 to 99.5vol% can be separated and stored geologically. Impurities like O2, NOX, SOX, and CO may negatively influence the transport infrastructure or the geological storage site by causing geochemical reactions. Therefore the maximum acceptable concentrations of the impurities in the separated CO2 stream must be defined regarding the requirements from transportation and storage. The main objective of the research project COORAL therefore is to define the required CO2 purity for capture and storage. [Copyright &y& Elsevier]