Influence of SO3 on mercury removal with activated carbon: Full-scale results

Activated carbon injection is considered one of the most cost-effective options for mercury control at PRB-fired power plants. However, roughly 30% of sites firing PRB coal use SO₃ for flue gas conditioning. The presence of SO₃ in flue gas can decrease mercury capture by activated carbon, sometimes dramatically. Overcoming activated carbon performance limitations caused by SO₃ conditioning for units with this configuration is essential to enable these plants to cost-effectively meet pending mercury emission regulations. Ameren's Labadie Unit 2 fires PRB coal and uses SO₃ to enhance particulate capture in the electrostatic precipitator (ESP). Full-scale sorbent injection tests at Labadie were conducted from 2005–2007. Six sorbents were tested at SO₃ injection concentrations ranging from 0 to 10.7 ppm. Sorbent performance was evaluated at two injection locations (the air preheater (APH) inlet and outlet). Native mercury capture on fly ash was typically less than 15%. When the mercury sorbents were injected downstream of the air preheater, the SO₃ concentration resulted in a decrease in mercury capture from 85% (no SO₃ injection) to 17% (SO₃ injection set at 10.7 ppm). Mercury sorbents were more effective when injected upstream of the air preheater. With the SO₃ system off, mercury removal increased from 75% when injecting 5.1 lb/MMacf of brominated carbon at the APH outlet, compared to 95% when injecting at the inlet. With the SO₃ system on, test results indicated an increase from about 30% injecting at the outlet to 58% injecting at the inlet. Tests evaluating the ADA-ES patented onsite milling process showed that 85% mercury capture was achieved injecting 4 lb/MMacf of milled activated carbon compared to a requirement of 10 lb/MMacf to achieve the same removal using as-received carbon, representing a 60% reduction in activated carbon consumption. No changes in opacity, APH and ESP performance, or other balance-of-plant effects were observed in these tests.     

Gas-phase elemental mercury capture by a V2O5/AC catalyst

Gas-phase elemental mercury (Hg⁰) capture by an activated coke (AC) supported V₂O₅ (V₂O₅/AC) catalyst was studied in simulated flue gas and compared with that by the AC. The study on the influences of V₂O₅ loading, temperature, capture time and flue gas components (O₂, SO₂, H₂O and N₂) shows that the Hg⁰ capture capability of V₂O₅/AC is much higher than that of AC. It increases with an increase in V₂O₅ loading and is promoted by O₂, which indicates the important role of V₂O₅ in Hg⁰ oxidation and capture; it is promoted slightly by SO₂ but inhibited by H₂O; it increases with an increase in temperature up to 150 °C when Hg desorption starts. X-ray photoelectron spectroscopy analysis and sequential chemical extraction experiments indicate that the main states of Hg captured on V₂O₅/AC are HgO and HgSO₄. Temperature programmed desorption experiments were also made to understand the stability of the Hg captured.     

Investigation on elemental mercury oxidation mechanism by non-thermal plasma treatment

Converting elemental mercury into divalent compound is one of the most important steps for mercury abatement from coal fired flue gas. The oxidation of elemental mercury was investigated in this paper using dielectric barrier discharge (DBD) non-thermal plasma (NTP) technology at room temperature. Effects of different flue gas components like oxygen, moisture, HCl, NO and SO₂ were investigated. Results indicate that active radicals including O, O₃ and OH all contribute to the oxidation of elemental mercury. Under the conditions of 5% O₂ in the simulated flue gas, about 90.2% of Hg⁰ was observed to be oxidized at 3.68 kV discharge voltage. The increase of discharge voltage, O₂ level and H₂O content can all improve the oxidation rate, individually. With O₂ and H₂O both existed, there is an optimal moisture level for the mercury oxidation during the NTP treatment. In this test, the observed optimal moisture level was around 0.74% by volume. Hydrogen chloride can promote the oxidation of mercury due to chlorine atoms produced in the plasma process. Both NO and SO₂ have inhibitory effects on mercury oxidation, which can be attributed to their competitive consumption of O₃ and O.     

Removal of elemental mercury from simulated coal-combustion flue gas using a SiO2–TiO2 nanocomposite

A novel silica–titania (SiO₂–TiO₂) nanocomposite has been developed to effectively capture elemental mercury (Hg⁰) under UV irradiation. Previous studies under room conditions showed over 99% Hg⁰ removal efficiency using this nanocomposite. In this work, the performance of the nanocomposite on Hg⁰ removal was tested in simulated coal-fired power plant flue gas, where water vapor concentration is much higher and various acid gases, such as HCl, SO₂, and NO_x, are present. Experiments were carried out in a fix-bed reactor operated at 135 °C with a baseline gas mixture containing 4% O₂, 12% CO₂, and 8% H₂O balanced with N₂. Results of Hg speciation data at the reactor outlet demonstrated that Hg⁰ was photocatalytically oxidized and captured on the nanocomposite. The removal efficiency of Hg⁰ was found to be significantly affected by the flue gas components. Increased water vapor concentration inhibited Hg⁰ capture, due to the competitive adsorption of water vapor. Both HCl and SO₂ promoted the oxidation of Hg⁰ to Hg(II), resulting in higher removal efficiencies. NO was found to have a dramatic inhibitory effect on Hg⁰ removal, very likely due to the scavenging of hydroxyl radicals by NO. The effect of NO₂ was found to be insignificant. Hg removal in flue gases simulating low rank coal combustion products was found to be less than that from high rank coals, possibly due to the higher H₂O concentration and lower HCl and SO₂ concentrations of the low rank coals. It is essential, however, to minimize the adverse effect of NO to improve the overall performance of the SiO₂–TiO₂ nanocomposite.     

Impacts of acid gases on mercury oxidation across SCR catalyst

A series of bench-scale experiments were completed to evaluate acid gases of HCl, SO₂, and SO₃ on mercury oxidation across a commercial selective catalytic reduction (SCR) catalyst. The SCR catalyst was placed in a simulated flue gas stream containing O₂, CO₂, H₂O, NO, NO₂, and NH₃, and N₂. HCl, SO₂, and SO₃ were added to the gas stream either separately or in combination to investigate their interactions with mercury over the SCR catalyst. The compositions of the simulated flue gas represent a medium-sulfur and low- to medium-chlorine coal that could represent either bituminous or subbituminous. The experimental data indicated that 5–50 ppm HCl in flue gas enhanced mercury oxidation within the SCR catalyst, possibly because of the reactive chlorine species formed through catalytic reactions. An addition of 5 ppm HCl in the simulated flue gas resulted in mercury oxidation of 45% across the SCR compared to only 4% mercury oxidation when 1 ppm HCl is in the flue gas. As HCl concentration increased to 50 ppm, 63% of Hg oxidation was reached. SO₂ and SO₃ showed a mitigating effect on mercury chlorination to some degree, depending on the concentrations of SO₂ and SO₃, by competing against HCl for SCR adsorption sites. High levels of acid gases of HCl (50 ppm), SO₂ (2000 ppm), and SO₃ (50 ppm) in the flue gas deteriorate mercury adsorption on the SCR catalyst.     

Experimental study on mercury transformation and removal in coal-fired boiler flue gases

This paper reported mercury speciation and emissions from five coal-fired power stations in China. The standard Ontario Hydro Method (OHM) was used into the flue gas mercury sampling before and after fabric filter (FF)/electrostatic precipitator (ESP) locations in these coal-fired power stations, and then various mercury speciation such as Hg⁰, Hg²⁺ and Hg^P in flue gas, was analyzed by using EPA method. The solid samples such as coal, bottom ash and ESP ash, were analyzed by DMA 80 based on EPA Method 7473. Through analysis the mercury speciation varied greatly when flue gas went through FF/ESP. Of the total mercury in flue gas, the concentration of Hg²⁺ is in the range of 0.11–14.76 μg/N m³ before FF/ESP and 0.02–21.20 μg/N m³ after FF/ESP; the concentration of Hg⁰ ranges in 1.18–33.63 μg/N m³ before FF/ESP and 0.77–13.57 μg/N m³ after FF/ESP, and that of Hg^P is in the scope of 0–12.11 μg/N m³ before FF/ESP and 0–0.54 μg/N m³ after FF/ESP. The proportion of Hg²⁺ ranges from 4.87%–50.93% before FF/ESP and 2.02%–75.55% after FF/ESP, while that of Hg⁰ is between 13.81% – 94.79% before FF/ESP and 15.69%–98% after FF/ESP, with that of Hg^P is in the range of 0%–45.13% before FF/ESP and 0%–11.03% after FF/ESP. The mercury in flue gas mainly existed in the forms of Hg⁰ and Hg²⁺. The concentrations of chlorine and sulfur in coal and flue gas influence the species of Hg that are formed in the flue gas entering air pollution control devices. The concentrations of chlorine, sulfur and mercury in coal and the compositions of fly ash had significant effects on mercury emissions.     

Understanding the effects of sulfur on mercury capture from coal-fired utility flue gases

Coal combustion continues to be a major source of energy throughout the world and is the leading contributor to anthropogenic mercury emissions. Effective control of these emissions requires a good understanding of how other flue gas constituents such as sulfur dioxide (SO₂) and sulfur trioxide (SO₃) may interfere in the removal process. Most of the current literature suggests that SO₂ hinders elemental mercury (Hg⁰) oxidation by scavenging oxidizing species such as chlorine (Cl₂) and reduces the overall efficiency of mercury capture, while there is evidence to suggest that SO₂ with oxygen (O₂) enhances Hg⁰ oxidation by promoting Cl₂ formation below 100 °C. However, studies in which SO₂ was shown to have a positive correlation with Hg⁰ oxidation in full-scale utilities indicate that these interactions may be heavily dependent on operating conditions, particularly chlorine content of the coal and temperature. While bench-scale studies explicitly targeting SO₃ are scarce, the general consensus among full-scale coal-fired utilities is that its presence in flue gas has a strong negative correlation with mercury capture efficiency. The exact reason behind this observed correlation is not completely clear, however. While SO₃ is an inevitable product of SO₂ oxidation by O₂, a reaction that hinders Hg⁰ oxidation, it readily reacts with water vapor, forms sulfuric acid (H₂SO₄) at the surface of carbon, and physically blocks active sites of carbon. On the other hand, H₂SO₄ on carbon surfaces may increase mercury capacity either through the creation of oxidation sites on the carbon surface or through a direct reaction of mercury with the acid. However, neither of these beneficial impacts is expected to be of practical significance for an activated carbon injection system in a real coal-fired utility flue gas.     

Investigation of flue-gas treatment with O3 injection using NO and NO2 planar laser-induced fluorescence

Direct ozone (O₃) injection is a promising flue-gas treatment technology based on oxidation of NO and Hg into soluble species like NO₂, NO₃, N₂O₅, oxidized mercury, etc. These product gases are then effectively removed from the flue gases with the wet flue gas desulfurization system for SO₂. The kinetics and mixing behaviors of the oxidation process are important phenomena in development of practical applications. In this work, planar laser-induced fluorescence (PLIF) of NO and NO₂ was utilized to investigate the reaction structures between a turbulent O₃ jet (dry air with 2000 ppm O₃) and a laminar co-flow of simulated flue gas (containing 200 ppm NO), prepared in co-axial tubes. The shape of the reaction zone and the NO conversion rate along with the downstream length were determined from the NO-PLIF measurements. About 62% of NO was oxidized at 15d (d, jet orifice diameter) by a 30 m/s O₃ jet with an influence width of about 6d in radius. The NO₂ PLIF results support the conclusions deduced from the NO-PLIF measurements.     

A pilot-scale fireside deposit study of co-firing Cynara with two coals in a fluidised bed

Costs of biofuel production from energy crops can be reduced by applying the crop residues in heat and power production. Perennial herbaceous crops like Cynara cardunculus L. are challenging fuels because they tend to have high ash and chlorine contents. Coals, however, are often rich in aluminium silicates and sulphur, and co-firing of these biofuels with coal could be expected to reduce operational problems. In addition, CO₂ emissions are lower than during coal firing alone. Blends of Cynara and two coals, South African bituminous and Spanish sub-bituminous coal, were combusted in a 20 kW bubbling bed pilot reactor to ascertain the ability of the coals to reduce operational problems by alkali capture. The Cynara fuel sample contained almost 2 wt% chlorine. The South African coal was rich in kaolinite capable of capturing alkalies from chlorides to produce alkali aluminium silicate and HCl. The Spanish coal was rich in sulphur (mostly present as FeS₂), and produced high concentrations of SO₂ that partially oxidised to SO₃. The SO₃ can capture alkalies from chlorides by sulphation. Up to 30% Cynara, on energy basis, could be co-fired with Spanish coal without operational problems, whereas the same percentage of Cynara with South African coal led to strong Cl deposition. Co-firing of Cynara with both coals resulted in high HCl emissions (up to 1500 mg/Nm³ in 6% O₂). In addition, co-firing of the Spanish coal led to very high SO₂ emissions (up to about 16,000 mg/N m³ in 6% O₂). Thus, a power plant capable of firing such blends must be equipped with flue gas cleaning equipment for effective SO₂ and HCl capture in the flue gas channel after the superheaters, or else the quality of the Cynara must be markedly improved by changing the harvesting technology and fertilisers, which could be major sources of high ash and chlorine content in the fuel.     

Impact of calcium chloride addition on mercury transformations and control in coal flue gas

Pilot-scale experiments were conducted to investigate mercury transformations in coal flue gas when firing subbituminous coal with a CaCl₂ additive. Cofiring the CaCl₂ additive with the subbituminous coal resulted in approximately 50% oxidized mercury, as a result of reactive chlorine species formed in coal flue gas, compared to the dominance of elemental mercury in the baseline flue gas. The mercury data indicate that mercury-flue gas chemistry reactions may occur at fairly high temperatures (>400 °C) in chlorine-enriched flue gas. Field tests were conducted to further demonstrate the impact of cofiring CaCl₂ on the eventual fate of mercury. These tests were completed on a 650-MW subbituminous coal-fired power plant equipped with selective catalytic reduction (SCR), a fabric filter (FF), and a wet scrubber. Overall mercury removals across the SCR-FF-wet scrubber system ranged from 75% to 96% with 200-800 ppm (coal basis) chlorine addition compared to 18-32% during baseline operations. Field data indicate that the SCR enhanced mercury oxidation, possibly as a result of the supplemental formation of reactive chlorine species and the aid of the SCR catalyst. As a result, most of the mercury in the flue gas was in an oxidized state and was removed in the downstream wet scrubber, indicating that cofiring CaCl₂ is an effective mercury control approach for a subbituminous coal-fired plant equipped with an SCR and wet scrubber.     

Analysis of mercury species present during coal combustion by thermal desorption

Mercury in coal and its emissions from coal-fired boilers is a topic of primary environmental concern in the United States and Europe. The predominant forms of mercury in coal-fired flue gas are elemental (Hg⁰) and oxidized (Hg²⁺, primarily as HgCl₂). Because Hg²⁺ is more condensable and far more water soluble than Hg⁰, the wide variability in mercury speciation in coal-fired flue gases undermines the total mercury removal efficiency of most mercury emission control technologies. It is important therefore to have an understanding of the behaviour of mercury during coal combustion and the mechanisms of mercury oxidation along the flue gas path. In this study, a temperature programmed decomposition technique was applied in order to acquire an understanding of the mode of decomposition of mercury species during coal combustion. A series of mercury model compounds were used for qualitative calibration. The temperature appearance range of the main mercury species can be arranged in increasing order as HgCl₂ < HgS < HgO < HgSO₄. Different fly ashes with certified and reference values for mercury concentration were used to evaluate the method. This study has shown that the thermal decomposition test is a newly developed efficient method for identifying and quantifying mercury species from coal combustion products.     

Full-scale measurements of SO2 gas phase concentrations and slurry compositions in a wet flue gas desulphurisation spray absorber

Two measurement campaigns were carried out at ENERGI E2's Asnæs Power plant, unit 5. The unit has a capacity of 620 MW_e and is equipped with a wet flue gas desulphurisation (FGD) plant employing a counter-current spray absorber with five spray levels. In the first campaign, the power plant was firing Orimulsion^® with 2.85 wt% S resulting in a flue gas concentration of SO₂ exceeding 2000 ppmv. In the second campaign, the fuel applied was a low-S blended coal and the SO₂ concentration in the raw gas was around 400 ppmv. A novel probe for in situ sampling of gas phase concentrations in wet FGD spray absorbers was developed and applied for measuring axial profiles of the SO₂ gas phase concentrations in the absorber. The expected decrease in SO₂ concentrations along the height of the absorber was found in the spray section (from height 26.5 to 36.2 m) whereas the SO₂ concentration above the holding tank and below the gas inlet was quite low probably due to long local residence times in the region. Horizontal variations, due to somewhat different flow conditions near the column wall were investigated and the SO₂ concentrations were found to be higher near the wall. Measurements at different gross loads showed that the SO₂ gas phase concentration at a given position inside the absorber was roughly linearly related to the L/G ratio in the measuring interval. Turning off one of the lower spray levels, while burning coal with low S content, did not lower the overall removal efficiency of the absorber. However, the SO₂ gas phase concentration inside the lower part of the absorber was increased by a factor of 2-3. Measurements of slurry pH at different positions showed a decrease of approximately 0.5 units from the upper to the lower part of the absorber. The full-scale measurements provide a detailed set of experimental data for validation of mathematical models of a wet FGD spray absorber.     

Advanced experimental analysis of the reaction of Ca(OH)2 with HCl and SO2 during the spray dry scrubbing process

This work evaluates both the removal efficiencies of HCl and SO₂ at different points in a spray dryer using Ca(OH)₂ as the absorbent. The operating conditions were specified in terms of the temperature of the flue gas (200-300 °C), the HCl concentration (120-1000 ppm), the SO₂ concentration (150-500 ppm) and the amount of CaCl₂ added (10-30 wt.%).The experimental results showed that the SO₂ removal efficiencies were higher in the presence of HCl (120-500 ppm) than in the absence of HCl at 250 °C and 20% relative humidity (RH). However, the removal efficiency of SO₂ decreased as the HCl concentration increased. The removal efficiency of SO₂ also increased with the amount of CaCl₂ in the spray dryer.     

Mercury emissions from six coal-fired power plants in China

Mercury emission field measurements based on the Ontario Hydro Method (OHM) were conducted for six coal-fired power plants in China. The mercury mass balances for the six power plants varied from 100.3% to 139.5% of the input coal mercury for the whole system. About 0.02%–1.2% of the mercury remained in the bottom ash. In the first five power plants equipped with pulverized coal boiler, most of the mercury was emitted from the stack to the atmosphere. The plants with Electrostatic Precipitator (ESP) system emitted more Hg⁰ than Hg²⁺, while the plants with the Fabric Filter (FF) emitted less Hg⁰ than Hg²⁺. Virtually all of the Hg^P enter the ESP or the FF was removed. The FF systems had better Hg⁰ and Hg²⁺ removal efficiencies than the ESP systems. The flue gas desulfurization (FGD) system removed up to 78.0% of Hg²⁺ and only 3.14% of Hg⁰ in the flue gas, while 8.94% of the original mercury in the coal was removed by the FGD system. The average mercury removal efficiencies of the ESP systems was 11.5%, that of the FF systems was 52.3% and that of the combined ESP + FGD system was 13.7%, much lower than the average removal efficiencies of pollution control device systems in US plants which have been used in previous studies of Chinese mercury emission inventory. Hg⁰, rather than Hg²⁺ as assumed in previous estimates, has been found to be the dominant species emitted in the atmosphere. The average emission factor was found to be 4.70 g/TJ (10.92 bl/Tbtu), which is much higher than for US plants burning bituminous coals due to the high mercury content in the Chinese coal and the low mercury removal efficiency of air pollution control devices of power plants.     

Results from trialling aqueous NH3 based post-combustion capture in a pilot plant at Munmorah power station: Absorption

Australia's Commonwealth Scientific and Industrial Research Organization (CSIRO) and Delta Electricity have developed, commissioned and operated an A$7 million aqueous NH₃ based post-combustion capture (PCC) pilot plant at the Munmorah black coal fired power station in Australia. The results from the pilot plant trials will be used to address the gap in know-how on application of aqueous NH₃ for post-combustion capture of CO₂ and other pollutants in the flue gas and explore the potential of the NH₃ process for application in the Australia power sector. This paper is one of a series of publications to report and discuss the experimental results obtained from the pilot plant trials and primarily focuses on the absorption section.The pilot plant trials have confirmed the technical feasibility of the NH₃ based capture process. CO₂ removal efficiency of more than 85% can be achieved even with low NH₃ content of up to 6 wt%. The NH₃ process is effective for SO₂ but not for NO in the flue gas. More than 95% of SO₂ in the flue gas is removed in the pre-treatment column using NH₃. The mass transfer coefficients for CO₂ in the absorber as functions of CO₂ loading and NH₃ concentration have been obtained based on pilot plant data.     

Mercury speciation and its emissions from a 220 MW pulverized coal-fired boiler power plant in flue gas

Distributions of mercury speciation of Hg⁰, Hg²⁺ and Hg ^P in flue gas and fly ash were sampled by using the Ontario Hydro Method in a 220 MW pulverized coal-fired boiler power plant in China. The mercury speciation was varied greatly when flue gas going through the electrostatic precipitator (ESP). The mercury adsorbed on fly ashes was found strongly dependent on unburnt carbon content in fly ash and slightly on the particle sizes, which implies that the physical and chemical features of some elemental substances enriched to fly ash surface also have a non-ignored effect on the mercury adsorption. The concentration of chlorine in coal, oxyge nand NO _x in flue gas has a positive correlation with the formation of the oxidized mercury, but the sulfur in coal has a positive influence on the formation of elemental mercury. This work was presented at the 6 ^th Korea-China Workshop on Clean Energy Technology held at Busan, Korea, July 4–7, 2006.     

Flue gas desulfurization by citrate process and optimization of working parameters

In this study, model flue gas was bubbled into 0.25 L tribasic sodium citrate (TSC) solution being in 0.5 L glass absorber to remove its SO₂ content. Size of gas bubbles, absorption temperature, gas flow rate, solution concentration and stirring rate were taken as working parameters to investigate their effect on SO₂ removal from flue gas. The Taguchi's experimental design method was used to obtain optimum values of working parameters for SO₂ saturation time of the TSC solution selected as a quality characteristic. The optimum levels of parameters to maximize the SO₂ saturation time of TSC solution were coarse bubbles for gas delivery, 35 °C for absorption temperature, 1.5 slm for gas flow rate, 0.5 M for TSC solution concentration and 500 rpm for stirring rate. Under these conditions, the SO₂ saturation time of the TSC solution was achieved as 511 min in average. The most effective parameters on the absorption of SO₂ in TSC solutions were ranked to the least as solution concentration, gas flow rate, size of gas bubbles, absorption temperature and stirring rate.     

Mercury speciation and emission from the coal‐fired power plant filled with flue gas desulfurization equipment

Mercury speciation and emission from two Chinese coal‐fired power stations equipped with flue gas desulfurization device were investigated. Research results reveal that Hg⁰ is the main form in the flue gas in Plant 1; Hg²⁺ is the main form in the flue gas in Plant 2. Most of mercury was emitted to the atmosphere, which was about 77–98%, and the elemental mercury released to atmosphere ranged 73–94% approximately. A pot of mercury is adsorbed by bottom ash, electrostatic precipitator (ESP) ash, and gypsum in Plant 1. However, most mercury, the scale of which is 75–83.2%, is collected by ESP ash, and only 7.0–12.2% mercury is emitted to the atmosphere in Plant 2. The mercury removal by NID semi‐desulfurization system is higher than wet flue gas desulfurization (WFGD) desulfurization system.     

Low cost coal-based carbons for combined SO2 and NO removal from exhaust gas

The aim of this paper is to show how a cheap carbonaceous material such as low rank coal-based carbon (or char) can be used in the combined SO₂/NO removal from exhaust gas at the linear gas velocity used in commercial systems (0.12 m s⁻¹). Char is produced from carbonization and optionally activated with steam. This char is used in a first step to abate the SO₂ concentration at the following conditions: 100 °C, space velocity of 3600 h⁻¹, 6% O₂, 10% H₂O, 1000 ppmv SO₂, 1000 ppmv NO and N₂ as remainder. In a second step, when the SO₂ concentration in the flue gas is low, NO is reduced to N₂ and steam at the following experimental conditions: 150 °C, space velocity of 900 h⁻¹, 6% O₂, 10% H₂O, 0-500 ppmv SO₂, 1000 ppmv NO, 1000 ppmv NH₃ and N₂ as remainder.It has been shown that the presence of NO has no effect on SO₂ abatement during the first step of combined SO₂/NO removal system and that low SO₂ inlet concentration has a negligible effect on NO reduction in the second step. Moreover, this char can be thermally regenerated after use for various cycles without loss of activity. On the other hand, this regenerated char shows the highest NO removal activity (compared to parent chars, either carbonized or steam activated) which can be attributed to the activating effect of the sulfuric acid formed during the first step of the combined SO₂/NO removal system.     

SO2 retention on CaO/activated carbon sorbents. Part II: Effect of the activated carbon support

The present paper analyses the role of the activated carbon (AC) properties on the SO₂ uptake capacity of CaO/AC sorbents prepared by AC impregnation or ionic exchange with calcium acetate water solutions. Gas adsorption and mercury porosimetry have been used for textural characterization of the AC and surface oxygen groups have been characterized by temperature programmed desorption (TPD). Thermogravimetry has been used for SO₂ retention tests and CO₂ chemisorption at 300 °C for CaO dispersion (d) determinations. The results show that the surface calcium on CaO/AC samples, determined as “Ca loading · CaO dispersion” (parameter Ca(%) · d), governs the SO₂ uptake. The surface oxygen content is the AC property that mainly controls both the calcium loading and surface calcium on CaO/AC samples, which could be explained by the fact that the surface oxygen lowers the hydrophobic character of the AC supports therefore favouring the interaction with the calcium acetate water solutions. The combination of high calcium loading and dispersion leads to SO₂ uptakes up to 123 mg SO₂/g. The textural properties of the supports have some influence in the calcium loading. However, the effect is masked by the blockage of AC porosity by the calcium loaded.