• Energy Research

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. © 2014 Elsevier Ltd.

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 0.02 μm. 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.

In this study a systematic approach was chosen to test and characterize amine systems for CO2 capture. Vapour-liquid-equilibrium measurements were performed on a homologue series of amines, with ethylene amine as base structure. Various functional groups were used that ranged in chemical and physical properties. The effect of the addition of the following functional groups was investigated: -NH2 (ethylene diamine), -COOH (ß-alanine), -SH (cysteamine), SO3H (taurine) and -OH (monoethanolamine). Of these amine systems, MEA and taurine showed comparable behaviour in CO2 absorption and desorption. ß-alanine formed relatively more (bi)carbonate. As expected, no direct correlation in absorption behaviour with pKa was found, whereas there was a linear correlation between desorption behaviour at a fixed partial pressure with pKa. © 2011 Published by Elsevier Ltd.

AbstractAmine based solvent used for CO2 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 CO2 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.

Aqueous electrolytes are most commonly used for the CO2 reduction reaction (CO2RR), but suffer from a low CO2 solubility that limits the reaction. Electrochemical CO2 reduction in nonaqueous electrolytes can provide a solution, due to the higher CO2 solubility of organic solvent‐based electrolytes. Herein, the product distribution of the electrochemical CO2 reduction on polycrystalline Cu in 0.7 m tetraethylammonium chloride in propylene carbonate with different water additions (0, 10, and 90 v%), and for different operating conditions (10, 25, 40, and 60 °C), is investigated. It is found that CO2 reduction on Cu in a propylene carbonate solution results in H2, CO, and formic acid formation only, even though Cu is known to produce C2+ products such as ethylene and ethanol in aqueous electrolytes. Increasing the operating temperature increases the CO2RR kinetics and shows an improvement in CO formation and decrease in H2 formation. However, increasing the operating temperature also increases water transport through the membrane, resulting in an increase of H2 formation over time when operating at 60 °C.

Nowadays, nearly 50% of the hydrogen produced worldwide comes from Steam Methane Reforming (SMR) at an environmental burden of 10.5 tCO2,eq/tH2, accelerating the conse- quences of global warming. One way to produce clean hydrogen is via methane pyrolysis using melts of metals and salts. Compared to SMR, significant less CO2 is produced due to conversion of methane into hydrogen and carbon, making this route more sustainable to generatehydrogen.Hydrogenisproducedwithhighpurity,andsolidcarbonissegregatedand deposited on the molten bath. Carbon may be sold as valuable co-product, making industrial scale promising. In this work, methane pyrolysis was performed in a quartz bubble column using moltengallium as heat transfer agent and catalyst. Amaximumconversion of91%was achieved at 1119 ?Candambient pressure, witharesidence timeofthe bubbles in the liquid of 0.5 s. Based on in-depth analysis of the carbon, it can be characterized as carbon black. Techno-economic and sensitivity analyses of the industrial concept were done for different scenarios.Theresultsshowedthat, ifco-productcarbonissaleableandaCO2taxof50europer tonne is imposedtotheprocesses, themoltenmetaltechnologycanbecompetitivewithSMR.

One of the major issues encountered in the Post Combustion CO2 Capture processes is the degradation of the solvent which can be in great part attributed to the presence of oxygen in the solution. The present report focuses on the demonstration of DORA (Dissolved Oxygen Removal Apparatus), a technology developed by TNO as a counter-measure of oxidative degradation. The DORA was first operated in combination with TNO’s mobile bench-scale CO2 capture pilot (5 Nm3/h flue gas capacity) with artificial flue gas, showing an instant drop of 15% and an overall reduction of approximately 70% in the ammonia emissions from the absorber, which is an indication of reduced degradation. The technology was also demonstrated using the same pilot in an industrial environment in collaboration with the facility PlantOne bringing DORA from TRL5 to TRL6. This campaign proved that DORA contributed to the deacceleration of solvent degradation. The tests were executed with a porous membrane, and it was observed that exposure to degraded solvents led to solvent leakage through this membrane. Therefore, the use of a coated membrane was proposed to optimize the operation and increase oxygen removal. The use of this membrane is demonstrated at TRL3. Along with that, a model was developed to determine mass transfer resistances and the membrane area required to remove different levels of dissolved oxygen.

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.