Kinetics of sulfur dioxide- and oxygen-induced degradation of aqueous monoethanolamine solution during CO2 absorption from power plant flue gas streams

Studies of the kinetics of sulfur dioxide (SO₂)- and oxygen (O₂)-induced degradation of aqueous monoethanolamine (MEA) during the absorption of carbon dioxide (CO₂) from flue gases derived from coal- or natural gas-fired power plants were conducted as a function of temperature and the liquid phase concentrations of MEA, O₂, SO₂ and CO₂. The kinetic data were based on the initial rate which shows the propensity for amine degradation and obtained under a range of conditions typical of the CO₂ absorption process (3–7 kmol/m³ MEA, 6% O₂, 0–196 ppm SO₂, 0–0.55 CO₂ loading, and 328–393 K temperature). The results showed that an increase in temperature and the concentrations of MEA, O₂ and SO₂ resulted in a higher MEA degradation rate. An increase in CO₂ concentration gave the opposite effect. A semi-empirical model based on the initial rate, ?r_MEA = {6.74 × 10⁹ e^?(29,403/RT)[MEA]^0.02([O]^2.91 + [SO₂]^3.52)}/{1 + 1.18[CO₂]^0.18} was developed to fit the experimental data. With the higher order of reaction, SO₂ has a higher propensity to cause MEA to degrade than O₂. Unlike previous models, this model shows an improvement in that any of the parameters (i.e. O₂, SO₂, and CO₂) can be removed without affecting the usability of the model.     

Rate modeling of CO2 stripping from potassium carbonate promoted by piperazine

This work presents results from a rate-based model of strippers at normal pressure (160 kPa) and vacuum (30 kPa) in Aspen Custom Modeler^® (ACM) for the desorption of CO₂ from 5 m K⁺/2.5 m piperazine (PZ). The model solves the material, equilibrium, summation and enthalpy (MESH) equations, the heat and mass transfer rate equations, and computes the reboiler duty and equivalent work for the stripping process. Simulations were performed with IMTP #40 random packing and a temperature approach on the hot side of the cross-exchanger of 5 °C and 10 °C. A “short and fat” stripper requires 7–15% less total equivalent work than a “tall and skinny” one because of the reduced pressure drop. The vacuum and normal pressure strippers require 230 s and 115 s of liquid retention time to get an equivalent work 4% greater than the minimum work. Stripping at 30 kPa was controlled by mass transfer with reaction in the boundary layer and diffusion of reactants and products (88% resistance at the rich end and 71% resistance at the lean end). Stripping at 160 kPa was controlled by mass transfer with equilibrium reactions (84% resistance at the rich end and 74% resistance at the lean end) at 80% flood. The typical predicted energy requirement for stripping and compression to 10 MPa to achieve 90% CO₂ removal was 37 kJ/gmol CO₂. This is about 25% of the net output of a 500 MW power plant with 90% CO₂ removal.     

Environmental impacts of different food waste resource technologies and the effects of energy mix

The environmental impacts of food waste management strategies and the effects of energy mix were evaluated using a life cycle assessment model, EASEWASTE. Three different strategies involving landfill, composting and combined digestion and composting as core technologies were investigated. The results indicate that the landfilling of food waste has an obvious impact on global warming, although the power recovery from landfill gas counteracts some of this. Food waste composting causes serious acidification (68.0 PE) and nutrient enrichment (76.9 PE) because of NH₃ and SO₂ emissions during decomposition. Using compost on farmland, which can marginally reduce global warming (−1.7 PE), acidification (−0.8 PE), and ecotoxicity and human toxicity through fertilizer substitution, also leads to nutrient enrichment as neutralization of emissions from N loss (27.6 PE) and substitution (−12.8 PE). A combined digestion and composting technology lessens the effects of acidification (−12.2 PE), nutrient enrichment (−5.7 PE), and global warming (−7.9 PE) mainly because energy is recovered efficiently, which decreases emissions including SO₂, Hg, NO_x, and fossil CO₂ during normal energy production. The change of energy mix by introducing more clean energy, which has marginal effects on the performance of composting strategy, results in apparently more loading to acidification and nutrient enrichment in the other two strategies. These are mainly because the recovered energy can avoid fewer emissions than before due to the lower background values in power generation. These results provide quantitative evidence for technical selection and pollution control in food waste management.     

Testing of hydrotalcite-based sorbents for CO2 and H2S capture for use in sorption enhanced water gas shift

The feasibility of the sorption enhanced water gas shift (SEWGS) process under sour conditions is shown. The sour-SEWGS process constitutes a second generation pre-combustion carbon capture technology for the application in an IGCC. As a first critical step, the suitability of a K₂CO₃ promoted hydrotalcite-based CO₂ sorbent is demonstrated by means of adsorption and regeneration experiments in the presence of 2000 ppm H₂S. In multiple cycle experiments at 400 °C and 5 bar, the sorbent displays reversible co-adsorption of CO₂ and H₂S. The CO₂ sorption capacity is not significantly affected compared to sulphur-free conditions. A mechanistic model assuming two different sites for H₂S interaction explains qualitatively the interactions of CO₂ and H₂S with the sorbent. On the type A sites, CO₂ and H₂S display competitive sorption where CO₂ is favoured. The type B sites only allow H₂S uptake and may involve the formation of metal sulphides. This material behaviour means that the sour-SEWGS process likely eliminates CO₂ and H₂S simultaneously from the syngas and that an almost CO₂ and H₂S-free H₂ stream and a CO₂ + H₂S stream can be produced.     

CO2 recycling by reaction with renewably-generated hydrogen

A laboratory-scale reactor system was built and operated to demonstrate the feasibility of catalytically reacting carbon dioxide (CO₂) with renewably-generated hydrogen (H₂) to produce methane (CH₄) according to the Sabatier reaction: CO₂ + 4H₂ → CH₄ + 2H₂O. A cylindrical reaction vessel packed with a commercial methanation catalyst (Haldor Topsøe PK-7R) was used. Renewable H₂ produced by electrolysis of water (from solar- and wind-generated electricity) was fed into the reactor along with a custom blend of 2% CO₂ in N₂, meant to represent a synthetic exhaust mixture. Reaction conditions of temperature, flow rates, and gas mixing ratios were varied to determine optimum performance. The extent of reaction was monitored by real-time measurement of CO₂ and CH₄. Maximum conversion of CO₂ occurred at 300–350 °C. Approximately 60% conversion of CO₂ was realized at a space velocity of about 10,000 h^?1 with a molar ratio of H₂/CO₂ of 4/1. Somewhat higher total CO₂ conversion was possible by increasing the H₂/CO₂ ratio, but the most efficient use of available H₂ occurs at a lower H₂/CO₂ ratio.     

The challenge in understanding the corrosion mechanisms under oxyfuel combustion conditions

Basic research on the corrosive effect of flue gases has been performed at the BAM Federal Institute for Materials Research and Testing (Germany). Conditions at both high and low temperatures were simulated in specially designed experiments. Carburization occured in flue gases with high CO₂ content and temperatures higher than 500 °C. In SO₂ containing flue gases sulphur was detected in the oxide scale. At lower temperatures no corrosion was observed when gases with low humidity were investigated. Humidity higher than 1500 ppm was corrosive and all steels with Cr contents lower than 12% revealed corroded surfaces. At low temperatures below 10 °C a mixture of sulphuric and nitric acid condensed on metal surfaces. Acid condensation caused severe corrosion. Humidity, CO₂, O₂, and SO₂ contents are the important factors determining corrosion. Below 300 °C acid condensation is the primary reason for corrosion. Low humidity and low temperatures are conditions which can be expected in the CO₂ separation and treatment process. This work includes major conditions of the flue gas and CO₂ stream in CCS plants and CCS technology.     

Assessment of the different parameters affecting the CO2 purity from coal fired oxyfuel process

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 80–90 vol% 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 99.5 vol% can be separated and stored geologically. Impurities like O₂, NO_X, SO_X, 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.     

CO2 removal using membrane gas absorption

The objective of this study is to investigate the potential process for the removal of carbon dioxide (CO₂) from flue gas using fundamental membrane contactor, which is a membrane gas absorption (MGA) system. The experiments consisted of microporous polyvinylidenefluoride (PVDF) flat sheet membrane with 0.1 μm (as module I) and 0.45 μm (as module II) pore size. 2-Amino-2-methyl-1-propanol (AMP) solution was employed as the liquid absorbent. The effect of AMP concentration was studied with variation in the range 1–5 M. In addition, the experiments were carried out with 10%, 20%, 30% and 40% gas ratio of CO₂ to N₂ and pure CO₂ as well. Through contact angle measurement, membranes for module I and module II were obtained with CA values of around 130.25° and 127.77°, respectively. The mass transfer coefficients for module II are lower than those of module I for 1–5 M of AMP. Furthermore, the increase in CO₂ concentration in the feed gas stream enhanced the CO₂ flux as the driving force of the system was increased in sequence from 1 M to 5 M of AMP. However, after the particular percentage (40%) of CO₂ inlet concentration, the CO₂ fluxes seem saturated. The combination of AMP as liquid absorbent and PVDF microporous membrane in MGA system has shown the potential to remove the CO₂ from flue gas. In addition, the higher AMP concentration gave higher mass transfer coefficient at low liquid flow rates.     

Effect of feeding strategy and COD/sulfate ratio on the removal of sulfate in an AnSBBR with recirculation of the liquid phase

The objective of this work was to analyze the effect of the interaction between feeding strategy and COD/sulfate ratio on the removal efficiency of sulfate and organic matter from a synthetic wastewater. An anaerobic sequencing batch reactor with recirculation of the liquid phase and containing immobilized biomass on polyurethane foam (AnSBBR) was used. The AnSBBR with a total volume of 3.7 L, treated 2.0 L synthetic wastewater in 8-h cycles at 30 ± 1 °C and was inoculated with anaerobic biomass from a UASB. Two feeding strategies were assessed: (a) batch and (b) batch followed by fed-batch. In strategy (a) the reactor was fed in 10 min with 2 L wastewater containing sulfate and carbon sources. In strategy (b) 1.2 L wastewater (containing only the sulfate source) was fed during the first 10 min of the cycle and the remaining 0.8 L (containing only the carbon source) in 240 min. The COD/sulfate ratios assessed were 1 and 3. Based on these values and on the concentrations of organic matter (0.5–11.25 gCOD/L) and sulfate (0.5 and 2.5 gSO₄^2?/L), the sulfate and organic matter loading rates applied equaled 1.5 and 4.5 gSO₄^2?/L d for sulfate and 1.5, 4.5 and 13.5 gCOD/L d for organic matter. After stabilization of the system time profiles were run of monitored parameters (COD, sulfate, sulfide and sulfite). In general, the reactor showed to be robust for use in the anaerobic treatment of wastewaters containing sulfate. Gradual feeding (strategy b) of the carbon source favored sulfate reduction, resulting in sulfate removal efficiencies of 84–98% and organic matter removal efficiencies of 48–95%. The best results were observed under COD/sulfate ratio equal to 1 (loading rates of 1.5 and 4.5 gSO₄^2?/L d for sulfate, and 1.5 and 4.5 gCOD/L d for organic matter). When COD/sulfate ratio was 3 (loading rates of 1.5 and 4.5 gSO₄^2?/L d for sulfate, and 4.5 and 13.5 gCOD/L d for organic matter) the effect of feed mode became less significant. These results show that the strategy batch followed by fed-batch is more advantageous for COD/sulfate ratios near the stoichiometric value (0.67) and higher organic matter and sulfate concentrations.     

Treatment of municipal wastewater using a contact oxidation filtration separation integrated bioreactor

A new contact oxidation filtration separation integrated bioreactor (CFBR) was used to treat municipal wastewater. The CFBR was made up of a biofilm reactor (the upper part of the CFBR) and a gravitational filtration bed (the lower part of the CFBR). Polyacrylonitrile balls (50 mm diameter, 237 m²/m³ specific surface, 90% porosity, and 50.2% packing rate) were filled into the biofilm reactor as biofilm attaching materials and anthracite coal (particle size 1–2 mm, packing density 0.947 g/cm³, non-uniform coefficient (K₈₀ = d₈₀/d₁₀) < 2.0) was placed into the gravitational filtration bed as filter media. At an organic volumetric loading rate of 2.4 kg COD/(m³ d) and an initial filtration velocity of 5 m/h in the CFBR, the average removal efficiencies of COD, ammonia nitrogen, total nitrogen and turbidity were 90.6%, 81.4%, 64.6% and 96.7% respectively, but the treatment process seemed not to be effective in phosphorus removal. The average removal efficiency of total phosphorus was 60.1%. Additionally, the power consumption of the CFBR was less than 0.15 kWh/m³ of wastewater treated, and less than 1.5 kWh/kg BOD₅ removal.     

Study of Hg and SO3 behavior in flue gas of oxy-fuel combustion system

Oxy-fuel combustion systems have been under development to reduce CO₂ emissions from coal-fired power plants. In oxy-fuel combustion system, Hg in the flue gas causes corrosion in CO₂ purification and compression units. Also, SO₃ in the flue gas corrodes the equipment and ducts of oxy-fuel combustion system. Therefore, Hg and SO₃ need to be removed.Babcock-Hitachi conducted tests using a 1.5 MWth Combustion & Air Quality Control System (AQCS) test facility which consists of oxygen supply unit, furnace, Selective Catalytic Reduction (SCR) catalyst, Clean Energy Recuperator (CER), Dry Electrostatic Precipitator (DESP), flue gas recirculation system, Wet Flue Gas Desulfurization (WFGD), and CO₂ Compression and Purification Unit (CPU). In both cases of air and oxy-fuel combustion, the Hg removal across the DESP could be improved, and SO₃ concentration at the DESP outlet could be reduced to less than 1 ppm by installing a CER upstream of the DESP and reducing the gas temperature at the DESP inlet. Hg was not dissolved in the drain recovered from CO₂ compressor, and may be adsorbed at an inner part of CO₂ compressor. This indicated that Hg needs to be removed at a location upstream of the CO₂ compressor to prevent corrosion of the compressor.     

CO2 capture from power plants: Part I. A parametric study of the technical performance based on monoethanolamine

Capture and storage of CO₂ from fossil fuel fired power plants is drawing increasing interest as a potential method for the control of greenhouse gas emissions. An optimization and technical parameter study for a CO₂ capture process from flue gas of a 600 MWe bituminous coal fired power plant, based on absorption/desorption process with MEA solutions, using ASPEN Plus with the RADFRAC subroutine, was performed. This optimization aimed to reduce the energy requirement for solvent regeneration, by investigating the effects of CO₂ removal percentage, MEA concentration, lean solvent loading, stripper operating pressure and lean solvent temperature.Major energy savings can be realized by optimizing the lean solvent loading, the amine solvent concentration as well as the stripper operating pressure. A minimum thermal energy requirement was found at a lean MEA loading of 0.3, using a 40 wt.% MEA solution and a stripper operating pressure of 210 kPa, resulting in a thermal energy requirement of 3.0 GJ/ton CO₂, which is 23% lower than the base case of 3.9 GJ/ton CO₂. Although the solvent process conditions might not be realisable for MEA due to constraints imposed by corrosion and solvent degradation, the results show that a parametric study will point towards possibilities for process optimisation.     

Ionic liquids for post-combustion CO2 absorption

The present work is a study to evaluate ionic liquids as a potential solvent for post-combustion CO₂ capture. In order to enhance the absorption performance of a CO₂ capture unit, different ionic liquids have been designed and tested. The main goal was to get a comparison between a reference liquid and selected ionic liquids. As the reference, a solution of 30 w% monoethanolamine (MEA) and water was used. A large range of different pure and diluted ionic liquids was tested with a special screening process to gain general information about the CO₂ absorption performance. Based on these results, a 60 w% ionic liquid solution in water was selected and the vapour–liquid equilibrium was measured experimentally between 40 °C and 110 °C. From these curves the enthalpy of absorption for capturing CO₂ into the ionic liquid was determined. With these important parameters one is able to calculate the total energy demand for stripping of CO₂ from the loaded solvent for comparison of the ionic liquid based solvent with the reference MEA solvent. The energy demand of this 60 w% ionic liquid is slightly lower than that of the reference solution, resulting in possible energy savings between 12 and 16%.     

Development and testing of AZEP reactor components

The advanced zero emissions power plant (AZEP) project addresses the development of a novel “zero emissions,” gas turbine-based, power generation process to reduce local and global CO₂ emissions in a cost-effective way.The key element in AZEP is an integrated MCM-reactor, in which (a) O₂ is separated from air by means of a mixed-conducting membrane (MCM), (b) combustion of natural gas occurs in an N₂-free environment and (c) the heat of combustion is transferred to air by heat exchange.This paper focuses on the development and testing of the ceramic components of the MCM-reactor (air separation membrane and heat exchangers). For compactness and manufacturability, a module design based on extruded square channel monoliths has been chosen. The manifold design enables gas distribution in a checkerboard pattern. Modules with contact area of >500 m²/m³ have been produced.Results from testing of the modules under close to realistic process conditions agree with model predictions. Extrapolation to AZEP process conditions gives an oxygen production rate of around 37 mol O₂/(m³ s), or 15 MW/m³ power density (per net MCM volume). These values correspond to project targets and confirm the feasibility of the AZEP concept.     

The value of post-combustion carbon dioxide capture and storage technologies in a world with uncertain greenhouse gas emissions constraints

By analyzing how the largest CO₂ emitting electricity-generating region in the United States, the East Central Area Reliability Coordination Agreement (ECAR), responds to hypothetical constraints on greenhouse gas emissions, the authors demonstrate that there is an enduring role for post-combustion CO₂ capture technologies. The utilization of pulverized coal generation with carbon dioxide capture and storage (PC + CCS) technologies is particularly significant in a world where there is uncertainty about the future evolution of climate policy and in particular uncertainty about the rate at which the climate policy will become more stringent. The paper's analysis shows that within this one large, heavily coal-dominated electricity-generating region, as much as 20–40 GW of PC + CCS could be operating before the middle of this century. Depending upon the state of PC + CCS technology development and the evolution of future climate policy, the analysis shows that these CCS systems could be mated to either pre-existing PC units or PC units that are currently under construction, announced and planned units, as well as PC units that could continue to be built for a number of decades even in the face of a climate policy. In nearly all the cases analyzed here, these PC + CCS generation units are in addition to a much larger deployment of CCS-enabled coal-fueled integrated gasification combined cycle (IGCC) power plants. The analysis presented here shows that the combined deployment of PC + CCS and IGCC + CCS units within this one region of the U.S. could result in the potential capture and storage of between 3.2 and 4.9 Gt of CO₂ before the middle of this century in the region's deep geologic storage formations.     

CO2 capture from hot stove gas in steel making process

The capture of CO₂ from a hot stove gas in steel making process containing 30 vol% CO₂ by chemical absorption in a rotating packed bed (RPB) was studied. The RPB had an inner diameter of 7.6 cm, an outer diameter of 16 cm, and a height of 2 cm. The aqueous solutions containing 30 wt% of single and mixed monoethanolamine (MEA), 2-(2-aminoethylamino)ethanol (AEEA), and piperazine (PZ) were used. The CO₂ capture efficiency was found to increase with increasing temperature in a range of 303–333 K. It was also found to be more dependent on gas and liquid flow rates but less dependent on rotating speed when the speed was higher than 700 rpm. The obtained results indicated that the mixed alkanolamine solutions containing PZ were more effective than the single alkanolamine solutions. This was attributed to the highest reaction rate of PZ with CO₂. A higher portion of PZ in the mixture was more favorable to CO₂ capture. The highest gas flow rates allowed to achieve a desired CO₂ capture efficiency and the correspondent height of transfer unit (HTU) were determined at different aqueous solution flow rates. Because all the 30 wt% single and mixed alkanolamine solutions could result in a HTU less than 5.0 cm at a liquid flow rate of 100 mL/min, chemical absorption in a RPB instead of a packed bed adsorber is therefore suggested to capture CO₂ from the flue gases in steel making processes.     

Mineralization of integrated gasification combined-cycle power-station wastewater effluent by a photo-fenton process

The aim of this work was to study the mineralization of wastewater effluent from an integrated-gasification combined-cycle (IGCC) power station sited in Spain to meet the requirements of future environmental legislation. This study was done in a pilot plant using a homogeneous photo-Fenton oxidation process with continuous addition of H₂O₂ and air to the system.The mineralization process was found to follow pseudo-first-order kinetics. Experimental kinetic constants were fitted using neural networks (NNs). The NNs model reproduced the experimental data to within a 90% confidence level and allowed the simulation of the process for any values of the parameters within the experimental range studied. At the optimum conditions (H₂O₂ flow rate = 120 mL/h, [Fe(II)] = 7.6 mg/L, pH = 3.75 and air flow rate = 1 m³/h), a 90% mineralization was achieved in 150 min.Determination of the hydrogen peroxide consumed and remaining in the water revealed that 1.2 mol of H₂O₂ was consumed per each mol of total organic carbon removed from solution. This result confirmed that an excess of dissolved H₂O₂ was needed to achieve high mineralization rates, so continuous addition of peroxide is recommended for industrial application of this process.Air flow slightly improved the mineralization rate due to the formation of peroxo-organic radicals which enhanced the oxidation process.     

Heat of absorption of CO2 in aqueous ammonia and ammonium carbonate/carbamate solutions

A reaction calorimeter was used to determine the enthalpies of absorption of CO₂ in aqueous ammonia and in aqueous solutions of ammonium carbonate at temperatures of 35–80 °C. The heat of absorption of CO₂ with 2.5 wt% aqueous ammonia solution was found to be about 70 kJ/mol CO₂, which is lower than that with MEA (around 85 kJ/mol) at 35 and 40 °C. The value decreases with increased loading, but not to as low a value as expected by the carbonate–bicarbonate reaction (26.88 kJ/mol). The enthalpy of absorption of CO₂ in aqueous ammonia at 60 and 80 °C decreases with loadings at first, then increases between 0.2 mol CO₂/mol NH₃ and 0.6 mol CO₂/mol NH₃, and then decreases again. The behavior of the heat of absorption of CO₂ in 10 wt% ammonium carbonate solution was found to be the same as that of aqueous ammonia at loadings above 0.6 mol CO₂/mol NH₃. The heat of absorption increases with increasing temperature. The heats of absorption are directly related to the extent of the various reactions with CO₂ and can be assessed from the species variation in the liquid phase.     

CO2 capture from power plants: Part II. A parametric study of the economical performance based on mono-ethanolamine

While the demand for reduction in CO₂ emission is increasing, the cost of the CO₂ capture processes remains a limiting factor for large-scale application. Reducing the cost of the capture system by improving the process and the solvent used must have a priority in order to apply this technology in the future. In this paper, a definition of the economic baseline for post-combustion CO₂ capture from 600 MW_e bituminous coal-fired power plant is described. The baseline capture process is based on 30% (by weight) aqueous solution of monoethanolamine (MEA). A process model has been developed previously using the Aspen Plus simulation programme where the baseline CO₂-removal has been chosen to be 90%. The results from the process modelling have provided the required input data to the economic modelling. Depending on the baseline technical and economical results, an economical parameter study for a CO₂ capture process based on absorption/desorption with MEA solutions was performed.Major capture cost reductions can be realized by optimizing the lean solvent loading, the amine solvent concentration, as well as the stripper operating pressure. A minimum CO₂ avoided cost of € 33 tonne⁻¹ CO₂ was found for a lean solvent loading of 0.3 mol CO₂/mol MEA, using a 40 wt.% MEA solution and a stripper operating pressure of 210 kPa. At these conditions 3.0 GJ/tonne CO₂ of thermal energy was used for the solvent regeneration. This translates to a € 22 MWh⁻¹ increase in the cost of electricity, compared to € 31.4 MWh⁻¹ for the power plant without capture.     

Flue gas desulphurization for hot recycle Oxyfuel combustion: Experiences from the 30 MWth Oxyfuel pilot plant in Schwarze Pumpe

Significant differences exist in the flue gas composition in hot recycle Oxyfuel conditions as e.g. the high CO₂ partial pressure (>90 vol%, dry), the very high SO₂ concentration and the high water content (approx. 30 vol%). Therefore certain design and operation criteria have to be observed for the flue gas desulphurization with forced oxidation under Oxyfuel combustion conditions. Several performance tests have been executed at the 30 MW_th Oxyfuel pilot plant in Schwarze Pumpe to evaluate the main performance parameters and to assess the influence of the major operation parameters. The results show that there are no fundamental problems for the operation of the flue gas desulphurization unit under Oxyfuel combustion conditions. High removal rates could be reached and no negative impact of the high CO₂ partial pressure was observed under the tested operating conditions. No major differences in the gypsum quality have been observed between air firing and Oxyfuel conditions.