This study presents the results of two field tests that aimed at evaluating two countermeasures (WESP and GGH) to avoid acid mist formation. A WESP is shown to be very efficient for the removal of nuclei from the flue gas (100% efficient) and thus can prevent aerosol formation inside an amine based absorber. This is however only valid in the absence of SO₂ in the flue gas entering the WESP. A decreasing WESP efficiency is noted in the presence of SO₂ with increasing voltages as a result of newly formed aerosols inside the WESP. This implies that no or very low levels of SO₂ should be present in the flue gas entering the WESP. Since most of the amine carbon capture installations have a pre-scrubber (usually using NaOH to remove residual SO₂ in the flue gas leaving the power plant's Flue Gas Desulphurisation) in front of their amine absorber, the WESP must be installed behind this pre-scrubber and not in front of it. Having a Gas-Gas Heater (or any type of flue gas cooling such as a Low Temperature Heat Exchanger) installed upstream of the wet scrubbing may prevent homogenous nucleation and thus prevent the conversion of H₂SO₄ into sulfuric acid aerosols and consequently mist formation issues in the amine based carbon capture installation. Which option to choose amongst the two countermeasures presented in this study will depend on whether a new built installation is being considered or whether a carbon capture is planned as a retrofit into an existing installation. Published by Elsevier Ltd.

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HiPerCap aims to develop high-potential novel and environmentally benign technologies and processes for post-combustion CO₂ capture leading to real breakthroughs. The project includes all the main separation categories for post-combustion CO₂ capture, absorption, adsorption and membranes. Each technology category is focused on several promising concepts and a key focus in the project is to demonstrate the potential of these various capture technologies. A methodology has been developed for assessment and fair comparison of the various technologies and benchmarking against a state-of-the art capture technology demonstrated in the CESAR project. In the present paper, this methodology is demonstrated for two of the absorption-based concepts involving precipitating solvent systems. Here, the assessment is based on energy efficiency penalty for the total integrated power plant and capture plant process. Though there is a slight improvement compared to the reference plant (0.5 and 7%, respectively) neither of the two precipitating solvent systems assessed here meet the project target of 25% improvement. However, the uncertainty level in the numbers is higher for these two systems compared to the reference case and the models used for the capture process should be improved before a conclusion can be made. The HiPerCap project is just starting the assessment phase and it must be emphasized that additional assessment criteria will be used and other types of technologies will be assessed before completion at the end of 2017.

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This chapter gives an overview on the issue of aerosol-based emissions observed in post-combustion CO2 capture. Firstly, the evidence of aerosol-based emissions obtained from different pilot plant tests is presented. Unlike vapor-based emissions, which can be quantified and predicted based on the vapor pressure of the component, aerosol-based emissions are difficult to predict as it depends on several parameters. The key elements identified to explain the observation of aerosol-based amine emissions in PCC are discussed here. As the issue is being better understood, several countermeasures have been tested. Their efficiency in reducing aerosol-based emissions and possible disadvantages are summarized. The remaining knowledge gaps both from an understanding point of view as well as from a countermeasures point of view are outlined, and can serve as a basis for future research on this topic.@en

A novel type of separating heat exchanger, called a heat-integrated liquid-desorption exchanger (HILDE), applied to a typical CO₂ desorption process, has been investigated both numerically and experimentally. Process simulations, hydrodynamic and mass transfer experiments, and a preliminary cost evaluation have been used to compare HILDE to the conventionally used combination of a separate heat exchanger and desorber equipped with structured packing. The comparison revealed that the operational costs of the HILDE are 15% lower compared to the conventional desorption configuration, while the equipment costs are 45% lower. The reduction in operational costs is mainly caused by a reduced reboiler duty. The absence of a separate desorber column and a large decrease in the condenser size are the main reasons for the reduced equipment costs. Additionally, the system volume, mass hold-up, and total contact area are also expected to be significantly lower for HILDE.

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Flexibility in power plants with amine based carbon dioxide (CO₂) capture is widely recognised as a way of improving power plant revenues. Despite the prior art, its value as a way to improve power plant revenues is still unclear. Most studies are based on simplifying assumptions about the capabilities of power plants to operate at part load and to regenerate additional solvent after interim storage of solvent. This work addresses this gap by examining the operational flexibility of supercritical coal power plants with amine based CO₂ capture, using a rigorous fully integrated model. The part-load performance with capture and with additional solvent regeneration, of two coal-fired supercritical power plant configurations designed for base load operation with capture, and with the ability to fully bypass capture, is reported. With advanced integration options configuration, including boiler sliding pressure control, uncontrolled steam extraction with a floating crossover pressure, constant stripper pressure operation and compressor inlet guide vanes, a significant reduction of the electricity output penalty at part load is observed. For instance at 50% fuel input and 90% capture, the electricity output penalty reduces from 458 kWh/tCO₂ (with conventional integration options) to 345 kWh/tCO₂ (with advanced integration options), compared to a reduction from 361 kWh/tCO₂ to 342 kWh/tCO₂ at 100% fuel input and 90% capture. However, advanced integration options allow for additional solvent regeneration to a lower magnitude than conventional integration options. The latter can maintain CO₂ flow export within 10% of maximum flow across 30-78% of MCR (maximum continuous rating). For this configuration, one hour of interim solvent storage at 100% MCR is evaluated to be optimally regenerated in 4 h at 55% MCR, and 3 h at 30% MCR, providing rigorously validated useful guidelines for the increasing number of techno-economic studies on power plant flexibility, and CO₂ flow profiles for further studies on integrated CO₂ networks.

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This study is to our knowledge the first to describe the effect of a Gas-Gas Heater (GGH) of a coal fired power plant's has on (i) the H₂SO₄ concentration and (ii) the particle/aerosol number concentration and particle size distribution present in the flue gas. In the absence of a GGH, homogenous nucleation takes places inside the Wet Flue Gas Desulphurisation (WFGD) converting the gaseous H₂SO₄ into aerosol H₂SO₄. This leads to a high aerosol number concentration behind the WFGD with 80% of the aerosols being smaller than 0.02μm. This implies that an amine based carbon capture (CC) installation treating this flue gas can suffer from amine mist formation due to the high amount of available nuclei (i.e., H₂SO₄ aerosols) resulting in high amine emissions. In contrast, in the presence of a GGH not only 70% of the H₂SO₄ is removed from the flue gas (measured at the Nijmegen powerplant), but also homogenous nucleation in the WFGD is prevented resulting in low particle number concentrations. The flue gas leaving the GGH will not create any mist formation issues in an amine based CC installation due to the low amount of nuclei present in the flue gas. It is not the reduction in H₂SO₄ concentration by 70% inside the GGH as such that prevents mist formation but absence of H₂SO₄ in its aerosol form. These results are most likely quite widely transformable to other power plants that burn low sulfur coal i.e., around 0.7 weight%. This information will serve future pilot and demo CC installation around the world; in particular when retrofitted on power plants that have a GGH.

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Recently, studies have appeared pointing out that aerosols can dominate the total amine emission from amine based PCCC pilot plant scale installations. For the design of countermeasure types (upstream or downstream of the PCCC installation), it is crucial to have an idea of the aerosol size distribution and numbers entering or leaving the absorber. This study is the first to present this kind of data and should serve future installations when designing aerosol emission countermeasures. H₂SO₄ aerosols entering the absorber are observed to be extremely small (i.e. <0.2μm) with number concentrations exceeding 1E8cm^-3. The aerosols grow in size as they travel through the absorber through the taking up of water and amine to sizes close to but staying below 1μm. However, despite the fact that most of the aerosols (expressed in number concentrations) are well below 1μm, most of the water (and thus amine) is found in the aerosol sizes between 0.5 and 2μm. Therefore, if one aims at designing efficient countermeasures, eliminating this size fraction is crucial. This amine emission stream is therefore very difficult to remove using water washes as aerosols are known to travel through water wash sections. Moreover, also classical demisters show very little efficiency for these small aerosol sizes and are therefore believed not to be suitable for the removal of aerosols. This information will therefore serve future installations when designing aerosol emission countermeasures.

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A clear understanding of the dynamic behavior of the whole chain of conventional power generation to CO₂ storage is necessary. The rapidly increasing share of renewable energy makes the energy delivered to the grid more fluctuating leading to an impact on the CCS chain as well. A 250 MW scale carbon capture plant with CO₂ compression has been modelled with Dymola (dynamic) and with Aspen Plus (steady-state). It is evident that large perturbations in flue gas flow rate will make it difficult to control the water balance. Moreover, parallel compression trains may be necessary to prevent compressors to run in spill back mode.

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