The dissolution kinetics of industrial brine sludge wastes from a chlor-alkali industry as a sorbent for wet flue gas desulfurization (FGD)

The disposal of industrial brine sludge waste (IBSW) in chlor-alkali plants can be avoided by utilization of IBSW as a sorbent in wet flue gas desulfurization (FGD). The shrinking core model was used to determine the dissolution kinetics of IBSW, which is a vital step in wet FGD. The effects of solid-to-liquid ratio (m/v), temperature, pH, particle size, and stirring speed on the conversion and dissolution rate constant are determined. The conversion and dissolution rate constant decreases as the pH, particle size, and solid-to-liquid ratio are increased and increases as the temperature, concentration of acid, and stirring speed are increased. The sorbents before and after dissolution were characterized using x-ray fluorescence (XRF), x-ray diffraction (XRD), and scanning electron microscopy (SEM). An activation energy of 7.195 kJ/mol was obtained and the product layer diffusion model was found to be the rate-controlling step.

Implications: The use of industrial brine sludge waste as an alternative sorbent in wet flue gas desulfurization can reduce the amounts of industrial wastes disposed of in landfills. This study has proved that the sorbent can contain up to 91% calcium carbonate and trace amounts of sulfate, magnesium, and so on. This can be used as new sorbent to reduce the amount of sulfur dioxide in the atmosphere and the by-product gypsum can be used in construction, as a plaster ingredient, as a fertilizer, and for soil conditioning. Therefore, the sorbent has both economic and environmental benefits.     

半干法烟气脱硫新技术——粉末-颗粒喷动床技术

粉末 颗粒喷动床 (powder particlespoutedbed ,PPSB)是近几年来由日本研究人员开发的一种新的半干法烟气脱硫技术。本文介绍了PPSB的基本原理、优点以及在试验条件下所得到的影响因素和适宜的运行方式。PPSB在系统结构、废物处理、操作和费用方面比湿法有所提高 ,同时又比干法和其他半干法的去除率和吸收剂的利用率高。此外 ,对吸收剂研究结果表明 ,石灰石的脱硫效率虽然不及石灰 ,但是由于PPSB中吸收剂的停留时间长 ,气、固、液三相接触好的特点以及可以对石灰石进行研磨 ,因此 ,利用石灰石作吸收剂的PPSB完全可以达到理想的脱硫效率 ,同时也可以保持较好的经济性。但是 ,目前还没有大规模的试验和应用。所以PPSB是一项十分值得进一步开发和应用的烟气脱硫新技术。     

Technical Description of Parameters Influencing the pH Value of Suspension Absorbent Used in Flue Gas Desulfurization Systems

Abstract

As a result of the large limestone deposits available in Poland, the low cost of reagent acquisition for the large-scale technological use and relatively well-documented processes of flue gas desulfurization (FGD) technologies based on limestone sorbent slurry, wet scrubbing desulfurization is a method of choice in Poland for flue gas treatment in energy production facilities, including power plants and industrial systems. The efficiency of FGD using the above method depends on several technological and kinetic parameters, particularly on the pH value of the sorbent (i.e., ground limestone suspended in water). Consequently, many studies in Poland and abroad address the impact of various parameters on the pH value of the sorbent suspension, such as the average diameter of sorbent particles (related to the limestone pulverization degree), sorbent quality (in terms of pure calcium carbonate [CaCO₃] content of the sorbent material), stoichiometric surfeit of CaCO₃ in relation to sulfur dioxide (SO₂) absorbed from flue gas circulating in the absorption node, time of absorption slurry retention in the absorber tank, chlorine ion concentration in sorbent slurry, and concentration of dissolved metal salts (Na, K, Mg, Fe, Al, and others). This study discusses the results of laboratory-scale tests conducted to establish the effect of the above parameters on the pH value of limestone slurry circulating in the SO₂ absorption node. On the basis of the test results, a correlation equation was postulated to help maintain the desirable pH value at the design phase of the wet FGD process. The postulated equation displays good coincidence between calculated pH values and those obtained using laboratory measurements.     

A New Method to Assess Mercury Emissions: A Study of Three Coal-Fired Electric-Generating Power Station Configurations

Abstract

U.S. Environmental Protection Agency (EPA) Method 7473 for the analysis of mercury (Hg) by thermal decomposition, amalgamation, and atomic absorption spectroscopy has proved successful for use in Hg assessment at coal-fired power stations. In an analysis time of ～5 min per sample, this instrumental methodology can directly analyze total Hg—with no discrete sample preparation—in the solid matrices associated with a coal-fired power plant, including coal, fly ash, bottom ash, and flue gas desulfurization (FGD) material. This analysis technique was used to investigate Hg capture by coal combustion byproducts (CCBs) in three different coal-fired power plant configurations. Hg capture and associated emissions were estimated by partial mass balance. The station equipped with an FGD system demonstrated 68% capture on FGD material and an emissions estimate of 18% (11 kg/yr) of total Hg input. The power plant equipped with low oxides of nitrogen burners and an electrostatic precipitator (ESP) retained 43% on the fly ash and emitted 57% (51 kg/yr). The station equipped with conventional burners and an ESP retained less than 1% on the fly ash, emitting an estimated 99% (88 kg/yr) of Hg. Estimated Hg emissions demonstrate good agreement with EPA data for the power stations investigated.     

The fate and behavior of mercury in coal-fired power plants

For the past 22 years in the Netherlands, the behavior of Hg in coal-fired power plants has been studied extensively. Coal from all over the world is fired in Dutch power stations. First, the Hg concentrations in these coals were measured. Second, the fate of the Hg during combustion was established by performing mass balance studies. On average, 43 +/- 30% of the Hg was present in the flue gases downstream of the electrostatic precipitator (ESP; dust collector). In individual cases, this figure can vary between 1 and 100%. Important parameters are the Cl content of the fuel and the flue gas temperature in the ESP. On average, 54 +/- 24% of the gaseous Hg was removed in the wet flue-gas desulfurization (FGD) systems, which are present at all Dutch coal-power stations. In individual cases, this removal can vary between 8% (outlier) and 72%. On average, the fate of Hg entering the power station in the coal was as follows: <1% in the bottom ash, 49% in the pulverized fuel ash (ash collected in the ESP), 16.6% in the FGD gypsum, 9% in the sludge of the wastewater treatment plant, 0.04% in the effluent of the wastewater treatment plant, 0.07% in fly dust (leaving the stack), and 25% as gaseous Hg in the flue gases and emitted into the air. The distribution of Hg over the streams leaving the FGD depends strongly on the installation. On average, 75% of the Hg was removed, and the final concentration of Hg in the emitted flue gases of the Dutch power stations was only -3 microg/m3(STP) at 6% O2. During co-combustion with biomass, the removal of Hg was similar to that during 100% coal firing. Speciation of Hg is a very important factor. An oxidized form (HgCl2) favors a high degree of removal. The conversion from Hg0 to HgCl2 is positively correlated with the Cl content of the fuel. A catalytic DENOX (SCR) favors the formation of oxidized Hg, and, in combination with a wet FGD, the total removal can be as high as 90%.     

Study of the use of coal fly ash as an additive to minimise fluoride leaching from FGD gypsum for its disposal

The use of coal fly ash as a fluoride retention additive has been studied as a way of treating flue gas desulphurisation (FGD) gypsum for its disposal in landfills. With this end leaching studies following the standard EN-12457-4 [Characterization of waste- Leaching-Compliance test for leaching of granular waste materials and sludges - Part 4: One stage batch test at a liquid to solid ratio of 10l/kg for materials with particle size below 10mm (without or with size reduction)] have been performed on FGD gypsum samples treated with different proportions of fly ash (0.1-100%). It was found that the fluoride leachable content in FGD gypsum was reduced in the range 1-55%, depending on the fly ash proportion added to FGD gypsum. High levels of fluoride leaching reduction (close to 40%) were achieved even at relatively low fly ash additions (5%). So, low fly ash incorporations assure the characterization of this by-product as a waste acceptable at landfills for non-hazardous wastes according to the Council Decision 2003/33/EC [Council Decision 2003/33/EC of 19 December 2002 establishing criteria and procedures for the acceptance of waste at landfills pursuant to Article 16 of and Annex II to Directive 1999/31/EC] on waste disposal. Furthermore, the effectiveness of the proposed FGD gypsum stabilization method was also studied in column leaching systems, proving its good performance in simulated conditions of disposal. In such conditions a fluoride leaching reduction value slightly higher than 25% was displayed for a fly ash added amount of 5%.     

Environmental impact of a coal combustion-desulphurisation plant: abatement capacity of desulphurisation process and environmental characterisation of combustion by-products

The fate of trace elements in a combustion power plant equipped with a wet limestone flue gas desulphurisation (FGD) installation was studied in order to evaluate its emission abatement capacity. With this aim representative samples of feed coal, boiler slag, fly ash, limestone, FGD gypsum and FGD process water and wastewater were analysed for major and trace elements using the following techniques: inductively coupled plasma-mass spectrometry (ICP-MS), inductively coupled plasma-atomic emission spectrometry (ICP-AES), ion chromatography (IC), ion selective electrode (ISE) and atomic absorption spectroscopy (AAS). Mass balances were established allowing to determine the element partitioning behaviour. It was found that, together with S, Hg, Cl, F, Se and As were those elements entering in the FGD plant primarily as gaseous species. The abatement capacity of the FGD plant for such elements offered values ranged from 96% to 100% for As, Cl, F, S and Se, and about 60% for Hg. The environmental characterisation of combustion by-products (boiler slag, fly ash and FGD gypsum) were also established according to the Council Decision 2003/33/EC on waste disposal. To this end, water leaching tests (EN-12457-4) were performed, analysing the elements with environmental concern by means of the aforementioned techniques. According to the leaching behaviour of combustion by-products studied, these could be disposed of in landfills for non-hazardous wastes.     

The Fate and Behavior of Mercury in Coal-Fired Power Plants

Abstract

For the past 22 years in the Netherlands, the behavior of Hg in coal-fired power plants has been studied extensively. Coal from all over the world is fired in Dutch power stations. First, the Hg concentrations in these coals were measured. Second, the fate of the Hg during combustion was established by performing mass balance studies. On average, 43 ± 30% of the Hg was present in the flue gases downstream of the electrostatic precipitator (ESP; dust collector). In individual cases, this figure can vary between 1 and 100%. Important parameters are the Cl content of the fuel and the flue gas temperature in the ESP. On average, 54 ± 24% of the gaseous Hg was removed in the wet flue-gas desulfurization (FGD) systems, which are present at all Dutch coal-power stations. In individual cases, this removal can vary between 8% (outlier) and 72%.

On average, the fate of Hg entering the power station in the coal was as follows: <1% in the bottom ash, 49% in the pulverized fuel ash (ash collected in the ESP), 16.6% in the FGD gypsum, 9% in the sludge of the wastewater treatment plant, 0.04% in the effluent of the wastewater treatment plant, 0.07% in fly dust (leaving the stack), and 25% as gaseous Hg in the flue gases and emitted into the air. The distribution of Hg over the streams leaving the FGD depends strongly on the installation. On average, 75% of the Hg was removed, and the final concentration of Hg in the emitted flue gases of the Dutch power stations was only ~3 μg/m_STP ³ at 6% O₂. During co-combustion with biomass, the removal of Hg was similar to that during 100% coal firing.

Speciation of Hg is a very important factor. An oxidized form (HgCl₂) favors a high degree of removal. The conversion from Hg⁰ to HgCl₂ is positively correlated with the Cl content of the fuel. A catalytic DENOX (SCR) favors the formation of oxidized Hg, and, in combination with a wet FGD, the total removal can be as high as 90%.     

A new method to assess mercury emissions: a study of three coal-fired electric-generating power station configurations

U.S. Environmental Protection Agency (EPA) Method 7473 for the analysis of mercury (Hg) by thermal decomposition, amalgamation, and atomic absorption spectroscopy has proved successful for use in Hg assessment at coal-fired power stations. In an analysis time of approximately 5 min per sample, this instrumental methodology can directly analyze total Hg--with no discrete sample preparation--in the solid matrices associated with a coal-fired power plant, including coal, fly ash, bottom ash, and flue gas desulfurization (FGD) material. This analysis technique was used to investigate Hg capture by coal combustion byproducts (CCBs) in three different coal-fired power plant configurations. Hg capture and associated emissions were estimated by partial mass balance. The station equipped with an FGD system demonstrated 68% capture on FGD material and an emissions estimate of 18% (11 kg/yr) of total Hg input. The power plant equipped with low oxides of nitrogen burners and an electrostatic precipitator (ESP) retained 43% on the fly ash and emitted 57% (51 kg/yr). The station equipped with conventional burners and an ESP retained less than 1% on the fly ash, emitting an estimated 99% (88 kg/yr) of Hg. Estimated Hg emissions demonstrate good agreement with EPA data for the power stations investigated.     

Optimizing the specific surface area of fly ash-based sorbents for flue gas desulfurization

High performance sorbents for flue gas desulfurization can be synthesized by hydration of coal fly ash, calcium sulfate, and calcium oxide. In general, higher desulfurization activity correlates with higher sorbent surface area. Consequently, a major aim in sorbent synthesis is to maximize the sorbent surface area by optimizing the hydration conditions. This work presents an integrated modeling and optimization approach to sorbent synthesis based on statistical experimental design and two artificial intelligence techniques: neural network and genetic algorithm. In the first step of the approach, the main and interactive effects of three hydration variables on sorbent surface area were evaluated using a full factorial design. The hydration variables of interest to this study were hydration time, amount of coal fly ash, and amount of calcium sulfate and the levels investigated were 4-32 h, 5-15 g, and 0-12 g, respectively. In the second step, a neural network was used to model the relationship between the three hydration variables and the sorbent surface area. A genetic algorithm was used in the last step to optimize the input space of the resulting neural network model. According to this integrated modeling and optimization approach, an optimum sorbent surface area of 62.2m(2)g(-1) could be obtained by mixing 13.1g of coal fly ash and 5.5 g of calcium sulfate in a hydration process containing 100ml of water and 5 g of calcium oxide for a fixed hydration time of 10 h.     

Air-substrate mercury exchange associated with landfill disposal of coal combustion products

Previous laboratory studies have shown that lignite-derived fly ash emitted mercury (Hg) to the atmosphere, whereas bituminous- and subbituminous-derived fly ash samples adsorbed Hg from the air. In addition, wet flue gas desulfurization (FGD) materials were found to have higher Hg emission rates than fly ash. This study investigated in situ Hg emissions at a blended bituminous-subbituminous ash landfill in the Great Lakes area and a lignite-derived ash and FGD solids landfill in the Midwestern United States using a dynamic field chamber. Fly ash and saturated FGD materials emitted Hg to atmosphere at low rates (-0.1 to 1.2 ng/ m2hr), whereas FGD material mixed with fly ash and pyrite exhibited higher emission rates (approximately 10 ng/m2hr) but were still comparable with natural background soils (-0.3 to 13 ng/ m2hr). Air temperature, solar radiation, and relative humidity were important factors correlated with measured Hg fluxes. Field study results were not consistent with corresponding laboratory observations in that fluxes measured in the latter were higher and more variable. This is hypothesized to be partially an artifact of the flux measurement methods.     

Understanding selected trace elements behavior in a coal-fired power plant in Malaysia for assessment of abatement technologies

The Proposed New Environmental Quality (Clean Air) Regulation 201X (Draft), which replaces the Malaysia Environmental Quality (Clean Air) 1978, specifies limits to additional pollutants from power generation using fossil fuel. The new pollutants include Hg, HCl, and HF with limits of 0.03, 100, and 15 mg/N-m³ at 6% O₂, respectively. These pollutants are normally present in very small concentrations (known as trace elements [TEs]), and hence are often neglected in environmental air quality monitoring in Malaysia. Following the enactment of the new regulation, it is now imperative to understand the TEs behavior and to assess the capability of the existing abatement technologies to comply with the new emission limits. This paper presents the comparison of TEs behavior of the most volatile (Hg, Cl, F) and less volatile (As, Be, Cd, Cr, Ni, Se, Pb) elements in subbituminous and bituminous coal and coal combustion products (CCP) (i.e., fly ash and bottom ash) from separate firing of subbituminous and bituminous coal in a coal-fired power plant in Malaysia. The effect of air pollution control devices configuration in removal of TEs was also investigated to evaluate the effectiveness of abatement technologies used in the plant. This study showed that subbituminous and bituminous coals and their CCPs have different TEs behavior. It is speculated that ash content could be a factor for such diverse behavior. In addition, the type of coal and the concentrations of TEs in feed coal were to some extent influenced by the emission of TEs in flue gas. The electrostatic precipitator (ESP) and seawater flue gas desulfurization (FGD) used in the studied coal-fired power plant were found effective in removing TEs in particulate and vapor form, respectively, as well as complying with the new specified emission limits.

Implications:Coals used by power plants in Peninsular Malaysia come from the same supplier (Tenaga Nasional Berhad Fuel Services), which is a subsidiary of the Malaysia electricity provider (Tenaga Nasional Berhad). Therefore, this study on trace elements behavior in a coal-fired power plant in Malaysia could represent emission from other plants in Peninsular Malaysia. By adhering to the current coal specifications and installation of electrostatic precipitator (ESP) and flue gas desulfurization, the plants could comply with the limits specified in the Malaysian Department of Environment (DOE) Scheduled Waste Guideline for bottom ash and fly ash and the Proposed New Environmental Quality (Clean Air) Regulation 201X (Draft).     

Investigation of a Mercury Speciation Technique for Flue Gas Desulfurization Materials

Abstract

Most of the synthetic gypsum generated from wet flue gas desulfurization (FGD) scrubbers is currently being used for wallboard production. Because oxidized mercury is readily captured by the wet FGD scrubber, and coal-fired power plants equipped with wet scrubbers desire to benefit from the partial mercury control that these systems provide, some mercury is likely to be bound in with the FGD gypsum and wallboard. In this study, the feasibility of identifying mercury species in the FGD gypsum and wallboard samples was investigated using a large sample size thermal desorption method. Potential candidates of pure mercury standards including mercuric chloride (HgCl₂), mercurous chloride (Hg₂Cl₂), mercury oxide (HgO), mercury sulfide (HgS), and mercuric sulfate (HgSO₄) were analyzed to compare their results with those obtained from FGD gypsum and dry wallboard samples. Although any of the thermal evolutionary curves obtained from these pure mercury standards did not exactly match with those of the FGD gypsum and wallboard samples, it was identified that Hg₂Cl₂ and HgCl₂ could be candidates. An additional chlorine analysis from the gypsum and wallboard samples indicated that the chlorine concentrations were approximately 2 orders of magnitude higher than the mercury concentrations, suggesting possible chlorine association with mercury.     

Flue gas desulfurization: the state of the art

Coal-fired electricity-generating plants may use SO2 scrubbers to meet the requirements of Phase II of the Acid Rain SO2 Reduction Program. Additionally, the use of scrubbers can result in reduction of Hg and other emissions from combustion sources. It is timely, therefore, to examine the current status of SO2 scrubbing technologies. This paper presents a comprehensive review of the state of the art in flue gas desulfurization (FGD) technologies for coal-fired boilers. Data on worldwide FGD applications reveal that wet FGD technologies, and specifically wet limestone FGD, have been predominantly selected over other FGD technologies. However, lime spray drying (LSD) is being used at the majority of the plants employing dry FGD technologies. Additional review of the U.S. FGD technology applications that began operation in 1991 through 1995 reveals that FGD processes of choice recently in the United States have been wet limestone FGD, magnesium-enhanced lime (MEL), and LSD. Further, of the wet limestone processes, limestone forced oxidation (LSFO) has been used most often in recent applications. The SO2 removal performance of scrubbers has been reviewed. Data reflect that most wet limestone and LSD installations appear to be capable of approximately 90% SO2 removal. Advanced, state-of-the-art wet scrubbers can provide SO2 removal in excess of 95%. Costs associated with state-of-the-art applications of LSFO, MEL, and LSD technologies have been analyzed with appropriate cost models. Analyses indicate that the capital cost of an LSD system is lower than those of same capacity LSFO and MEL systems, reflective of the relatively less complex hardware used in LSD. Analyses also reflect that, based on total annualized cost and SO2 removal requirements: (1) plants up to approximately 250 MWe in size and firing low- to medium-sulfur coals (i.e., coals with a sulfur content of 2% or lower) may use LSD; and (2) plants larger than 250 MWe and firing medium- to high-sulfur coals (i.e., coals with a sulfur content of 2% or higher) may use either LSFO or MEL.     

湿法烟气脱硫系统的脱汞性能现场实验

分析湿法烟气脱硫系统的脱汞性能,对控制燃煤电厂的汞污染具有重要意义。利用安大略水法和吸附管法分别对某600 MW电厂湿法脱硫系统的进出口的烟气进行了采样,测量了烟气中各形态汞浓度,并分析了该系统对烟气总汞、气态氧化态汞的脱除效果以及对气态单质汞的影响。研究结果表明,安大略水法和吸附管法均能较为准确地测定湿法脱硫系统进出口烟气中的汞含量,测得入口和出口的氧化汞与平均值的相对误差的绝对值分别为3.5%和1.3%;入口和出口的单质汞与平均值相对误差的绝对值分别为16.6%和3.3%。其中吸附管法操作相对简单。通过湿法烟气脱硫系统后,烟气中氧化态汞的浓度可下降87.5%,其中约67.5%的氧化态汞被湿法脱硫系统脱除,约20%的氧化态汞在脱硫浆液的还原作用下被还原为单质汞,导致脱硫系统出口的单质汞浓度高于入口。     

石灰石湿法脱硫过程中SO2吸收数学模型

为揭示石灰石湿法脱硫体系中喷淋塔内SO2的浓度和脱硫效率的变化情况,针对喷淋塔内石灰石在气膜控制、气液膜控制和固体溶解控制的3个不同阶段,以双膜理论为基础,以单个石灰石颗粒为研究对象,通过石灰石在不同阶段的转化率和粒径变化,得到SO2在不同阶段脱硫效率随时间的变化规律,建立SO2吸收的数学模型.模型计算结果表明,在烟气行程上,脱硫效率受SO2气膜传质阻力和石灰石溶解速率限制.在吸收塔底部和上端SO2吸收速率较低,在SO2和石灰石摩尔比在适宜条件下,有效吸收段高度为2 m左右.理论模型揭示的规律对喷淋塔的设计和运行参数选取有一定借鉴意义.     

Distribution of mercury in the combustion products from coal-fired power plants in Guizhou,southwest China

Method 30B and the Ontario Hydro Method (OHM) were used to sample the mercury in the flue gas discharged from the seven power plants in Guizhou Province, southwest China. In order to investigate the mercury migration and transformation during coal combustion and pollution control process, the contents of mercury in coal samples, bottom ash, fly ash, and gypsum were measured. The mercury in the flue gas released into the atmosphere mainly existed in the form of Hg°. The precipitator shows a superior ability to remove Hg^p (particulate mercury) from flue gas. The removal efficiency of Hg²⁺ by wet flue gas desulfurization (WFGD) was significantly higher than that for the other two forms of mercury. The synergistic removal efficiency of mercury by the air pollution control devices (APCDs) installed in the studied power plants is 66.69–97.56%. The Hg mass balance for the tested seven coal-fired power plants varied from 72.87% to 109.67% during the sampling time. After flue gas flowing through APCDs, most of the mercury in coal was enriched in fly ash and gypsum, with only a small portion released into the atmosphere with the flue gas. The maximum discharge source of Hg for power plants was fly ash and gypsum instead of Hg emitted with flue gas through the chimney into the atmosphere. With the continuous upgrading of APCDs, more and more mercury will be enriched in fly ash and gypsum. Extra attention should be paid to the re-release of mercury from the reutilization of by-products from APCDs.

Implications: Method 30B and the Ontario Hydro Method (OHM) were used to test the mercury concentration in the flue gas discharged from seven power plants in Guizhou Province, China. The concentrations of mercury in coal samples, bottom ash, fly ash, and gypsum were also measured. By comparison of the mercury content of different products, we found that the maximum discharge source of Hg for power plants was fly ash and gypsum, instead of Hg emitted with flue gas through the chimney into the atmosphere. With the continuous upgrading of APCDs, more and more mercury will be enriched in fly ash and gypsum. Extra attention should be paid to the re-release of mercury from the reutilization of by-products from APCDs.     

Eliminating Reheat from Existing FGD Systems

The Clean Air Act Amendments of the early 1970_s required coal burning utilities to reduce their emissions of sulfur dioxide. Lime or limestone based wet systems were employed for flue gas desulfurization (FGD). These systems reduced flue gas temperatures to below acid dew point conditions. Concerned about the prospect of ductwork exposed to a saturated, acid-rich environment, most utilities turned to stack gas reheat (SGR) to increase flue gas temperatures. By 1980, 82 percent of all FGD facilities employed SGR. Today there are about 130 FGD systems of which 101 employ some form of stack gas reheat.     

Anion-Exchange Resin-Based Desulfurization and Dechlorination of Spent Sorbent Material

Abstract

Emissions of acid gases such as SO₂ and HCI/CI₂ from energy conversion or waste incineration facilities are unacceptable. Under the various regulations, the emissions of such acid gases are regulated by the U.S. Environmental Protection Agency (EPA). Alkali metal sorbents can remove these acid gases more efficiently than the lime/limestone type sorbents used in the conventional flue gas desulfurization (FGD) systems. However, the resulting alkali metal sulfate and chloride are unsuitable for landfill disposal because they are water-soluble and can potentially leach into groundwater, altering the soil pH. Replacing the (virgin) sorbent material is expensive. Hence, it is desirable that the spent sorbent materials obtained from such emissions control systems be converted to sulfur- and chlorine-free forms, so that they can be reused. The weak-base, anionexchange resin-based desulfurization concept, developed and tested at the University of Tennessee Space Institute (UTSI), can also simultaneously remove sulfur- and chlorine- containing species from such spent sorbent materials. Under the U.S. Department of Energy’s (DOE) sponsorship, bench scale studies have been carried out at UTSI to evaluate the feasibility of removing sulfur- and chlorine-containing species using this resin-based concept. Efforts have also been made to enhance the candidate resins’ performance by carrying out the resin exhaustion step under CO₂ static pressure and by using suitable pH buffering agents, such as low-molecular weight organic acids. Preliminary cost estimates for a regeneration scheme employing reactivated alkali metal-based spent sorbent material using the ion-exchange resin-based concept seem attractive and comparable to currently available options. After further development, this low-cost, simple process can be easily integrated into alkali metal sorbent-based flue gas desulfurization and acid gas emission control systems.     

Reduction of combustion by-products in WTE plants: O2 enrichment of underfire air in the MARTIN SYNCOM process

The SYNCOM process involves oxygen enrichment of underfire air, recirculation of flue gas and a combustion control system using infrared thermography of the waste layer on the grate. At the demonstration plant in Coburg, operational reliability and plant availability using SYNCOM could be proven under real disposal conditions with a waste throughput of 7 t/h. Oxygen enrichment of the underfire air promotes the destruction of pollutants due to the high oxygen partial pressures and temperatures. This is then reflected in very low residual amounts of organic combustion by-products in the bottom ash and flue gas from the SYNCOM unit. The flue gas concentrations of organic pollutants are reduced, as compared with conventional operation, by over 35% (for CO, total hydrocarbons and PCDD/F) at the boiler outlet. As the flue gas flow is reduced by oxygen enrichment and flue gas recirculation, the resulting reduction in terms of kg of pollutant per Mg of waste is even higher. In the bottom ash, the level of organic residues is reduced, by 45% in the case of loss on ignition and by 55% in the case of TOC and dioxins (I-TE of PCDD/F). This is due to the higher oxygen partial pressures and the fuel bed temperature which is increased by 135 to 1200 degrees C. Other important features of the process include more intense sintering and thus improved immobilization of the bottom ash, as well as reduced flue gas and fly ash flows.