Two electrolysis technologies fed with renewable energy sources are promising for the production of CO₂-free hydrogen and enabling the transition to a hydrogen society: Alkaline Electrolyte (AE) and Polymer Electrolyte Membrane (PEM). However, limited information exists on the potential environmental impacts of these promising sustainable innovations when operating on a large-scale. To fill this gap, the performance of AE and PEM systems is compared, using ex-ante Life Cycle Assessment (LCA), technology analysis and exploratory scenarios for which a refined methodology has been developed to study the effects of implementing large-scale sustainable hydrogen production systems. Ex-ante LCA allows modelling the environmental impacts of hydrogen production, exploratory scenario analysis allows modelling possible upscaling effects at potential future states of hydrogen production and use in vehicles in the Netherlands in 2050. A bridging tool for mapping the technological field has been created enabling the combination of quantitative LCAs with qualitative scenarios. This tool also enables diversity for exploring multiple sets of visions. The main results from the paper show, with an exception for the “ozone depletion” impact category, (1) that large-scale AE and PEM systems have similar environmental impacts with variations lower than 7% in all impact categories, (2) that the contribution of the electrolyser is limited to 10% of all impact categories results, and (3) that the origin of the electricity is the largest contributor to the environmental impact contributing to more than 90% in all impact categories, even when renewable energy sources are used. It is concluded that the methodology was applied successfully and provides a solid basis for an ex-ante assessment framework that can be applied to emerging technological systems.

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.

Oxidative degradation is a serious concern for upscaling of amine-based carbon capture technology. Different kinetic models have been proposed based on laboratory experiments, however the kinetic parameters included are limited to those relevant for a lab-scale system and not a capture plant. Besides, most of the models fail to recognize the catalytic effect of metals. The objective of this work is to develop a representative kinetic model based on an apparent auto-catalytic reaction mechanism between solvent degradation, corrosion and ammonia emissions. Measurements from four different pilot plants: (i) EnBW's plant at Heilbronn, Germany (ii) TNO's plant at Maasvlakte, The Netherlands; (iii) CSIRO's plants at Loy Yang and Tarong, Australia and (iv) DONG Energy's plant at Esbjerg, Denmark are utilized to propose a degradation kinetic model for 30 wt % ethanolamine (MEA) as the capture solvent. The kinetic parameters of the model were regressed based on the pilot plant campaign at EnBW. The kinetic model was validated by comparing it with the measurements at the remaining pilot campaigns. The model predicted the trends of ammonia emissions and metal concentration within the same order of magnitude. This study provides a methodology to establish a quantitative approach for predicting the onset of unacceptable degradation levels which can be further used to devise counter-measure strategies such as reclaiming and metal removal.

Over the past several years, there has been a significant effort to bring corrosion monitoring into the realm of online, real-time management with plant process control technology. As part of this new direction in corrosion monitoring, corrosion data (e.g. information on corrosion rate, measured Stern Geary constant (or B value), and parameters for pitting and corrosion filming tendencies) are directed to the plant process control system. Availability of such online corrosion data in real-time by process and corrosion engineers along with key process variables facilitates optimal management of process/plant safety and reliability. This paper reviews this new corrosion monitoring approach and experience gained from two monitoring campaigns in a post combustion CO₂ capture plant and identification of corrosion upsets and correlations with plant operating modes. It provides an indication of how real-time corrosion data can more specifically identify periods and causes of corrosion upsets that were previously "invisible" to process engineers facilitating quicker resolution and deployment of corrosion solutions with greater value than what was available with offline, reactive older corrosion monitoring approaches.

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.

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.

Amine based solvent used for SO₄ capture can be lost during the process due to: degradation, vaporization, mechanical losses and aerosol (mist) formation. Only recently, studies have appeared pointing out that aerosols can dominate the total amine emission at pilot plant scale behind coal fired power plants. Future full scale amine scrubber installations will be imposed emission limit values (ELV) for a number of components including NH3 and the amine itself. Most likely these ELV will be expressed as maximum concentrations tolerated in the SO₄ poor flue gas leaving the stack so it is important to prevent or cure amine aerosol emission. The study presents a novel combination of two existing measurement techniques, that measure: (i) amine emissions from the top of the absorber using FTIR and (ii) PSD of the incoming flue gas using the ELPI+. The study is the first to show how combining these two measurement techniques allows to predict the presence or absence of mist formation. This hypothesis is based on information obtained during several measurement campaigns on different pilot plants.

This study is to our knowledge the first to evaluate the potential of a wet electrostatic precipitator (WESP) to prevent aerosol formation issues inside amine based carbon capture installations. A WESP is a suitable option since this study proves that it is very efficient for the removal of the mist precursors inside the flue gas to be treated. Although a significant capital investment cost may be involved, energy requirements (i.e. low pressure drop), maintenance and therefore operational costs are expected to be very low. However, it is shown here that the WESP must be installed at the right location, i.e. the flue gas to be treated must contain no or very low levels of SO₂. The reason is that the WESP's aerosol removal efficiency decreases strongly in the presence of SO₂ gas and in a certain range also with increasing voltages. This limits the positive effect that the WESP has on reducing the MEA emissions from the absorber since a large number of mist formation precursors remain in the flue gas. In the presence of SO₂, a WESP can actually produce H₂SO₄ aerosols. It is shown that these newly created aerosols are very small (low nanometre range). This information is very important for future pilot and demo amine carbon capture installations thinking of implementing a WESP as countermeasure to aerosol formation issues. It implies that no or very low levels of SO₂ should still be present in the flue gas before 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 leaving the power plant's FGD) in front of their amine absorber, the WESP must be installed behind this pre-scrubber and not in front of it.