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.     

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.     

Mercury mass balances: a case study of two North Dakota power plants

The Energy & Environmental Research Center (EERC) conducted a mercury-sampling program to provide data on the quantity and forms of Hg emitted and on the Hg removal efficiency of the existing air pollution control devices at two North Dakota power plants--Milton R. Young Station and Coal Creek Station. Minnkota Power Cooperative, Great River Energy, the North Dakota Industrial Commission, and EPRI funded the project. The primary objective was to obtain accurate measurements of Hg released from each plant, as verified by a material balance. A secondary objective was to evaluate the ability of a mercury continuous emission monitor (CEM) to measure total Hg at the stack. At both plants, speciated Hg measurements were made at the inlets and outlets of both the electrostatic precipitators (ESPs) and the flue gas desulfurization (FGD) systems. A Semtech Hg 2000 (Semtech Metallurgy AB) mercury CEM was used to measure the total Hg emissions at the stack in real time. Using these measurements and plant data, the measured Hg concentrations in the coal, FGD slurries, and ESP ash, a Hg mass flow rate was calculated at each sampling location. Excellent Hg mass balances were obtained (+/- 15%). It was also found that the Hg was mostly in the elemental phase (approximately 90%), and the small amount of oxidized Hg that was generated was removed by the FGD systems. Insignificant amounts of particulate-bound Hg were measured at both plants. However, 10-20% of the elemental Hg measured prior to the ESP was converted to oxidized Hg across the ESP. The data show that, at these facilities, almost all of the Hg generated is being emitted into the atmosphere as elemental Hg. Local or regional deposition of the Hg emitted from these plants is not a concern. However, the Hg does become part of the global Hg burden in the atmosphere. Also, the evidence appears to indicate that elemental Hg is more difficult to remove from flue gas than oxidized Hg is.     

Mercury Mass Balances: A Case Study of Two North Dakota Power Plants

ABSTRACT

The Energy & Environmental Research Center (EERC) conducted a mercury-sampling program to provide data on the quantity and forms of Hg emitted and on the Hg removal efficiency of the existing air pollution control devices at two North Dakota power plants—Milton R. Young Station and Coal Creek Station. Minnkota Power Cooperative, Great River Energy, the North Dakota Industrial Commission, and EPRI funded the project. The primary objective was to obtain accurate measurements of Hg released from each plant, as verified by a material balance. A secondary objective was to evaluate the ability of a mercury continuous emission monitor (CEM) to measure total Hg at the stack.

At both plants, speciated Hg measurements were made at the inlets and outlets of both the electrostatic precipi-tators (ESPs) and the flue gas desulfurization (FGD) systems. A Semtech Hg 2000 (Semtech Metallurgy AB) mercury CEM was used to measure the total Hg emissions at the stack in real time. Using these measurements and plant data, the measured Hg concentrations in the coal, FGD slurries, and ESP ash, a Hg mass flow rate was calculated at each sampling location. Excellent Hg mass balances were obtained (±15%). It was also found that the Hg was mostly in the elemental phase (~90%), and the small amount of oxidized Hg that was generated was removed by the FGD systems.

Insignificant amounts of particulate-bound Hg were measured at both plants. However, 10-20% of the elemental Hg measured prior to the ESP was converted to oxidized Hg across the ESP. The data show that, at these facilities, almost all of the Hg generated is being emitted into the atmosphere as elemental Hg. Local or regional deposition of the Hg emitted from these plants is not a concern. However, the Hg does become part of the global Hg burden in the atmosphere. Also, the evidence appears to indicate that elemental Hg is more difficult to remove from flue gas than oxidized Hg is.     

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.     

Differential partitioning and speciation of Hg in wet FGD facilities of two Spanish PCC power plants

This paper evaluates the speciation and partitioning of mercury in two Spanish pulverised coal combustion power plants (PP1 and PP2), equipped with wet limestone-based flue gas desulphurisation facilities (FGD) operating with forced oxidation and re-circulation of FGD water streams. These plants are fed with coal (PP1) and coal/pet-coke blends (PP2) with different mercury contents. The behaviour, partitioning and speciation of Hg were found to be similar during the combustion processes but different in the FGD systems of the two power plants. A high proportion (86-88%) of Hg escaped the electrostatic precipitator in gaseous form, Hg²⁺ being the predominant mercury species (68-86%) to enter the FGD. At this point, a relatively high total Hg retention (72% and 65%) was achieved in the PP1 and PP2 (2007) FGD facilities respectively. However, during the second sampling campaign for PP2 (2008), the mercury removal achieved by the FGD was much lower (26%). Lab-scale tests point to liquid/gas ratio as the main parameter affecting oxidised mercury capture in the scrubber. The partitioning of the gaseous mercury reaching the FGD system in the wastes and by-products differed. In the low mercury input power plant (PP1) most of the mercury (67%) was associated with the FGD gypsum. Moreover in PP2 a significant proportion of the gaseous mercury reaching the FGD system remained in the aqueous phase (45%) in the 2007 sampling campaign while most of it escaped in 2008 (74%). This may be attributed to the scrubber operating conditions and the different composition and chemistry of the scrubber solution probably due to the use of an additive.     

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.     

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.     

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).     

The emissions of heavy metals and persistent organic pollutants from modern coal-fired power stations

Extensive research for establishing the emissions of heavy metals from coal-fired power stations is performed in the Netherlands for the past 25 years. In the Netherlands coal is fired from all over the world. This means that the emissions are established for coal of various origins. In the eighties, the emissions of installations equipped with ESPs (electrostatic precipitators) were measured. In the nineties, the influence of wet FGD (flue gas desulphurisation) on the emissions was studied. The effect of co-combustion of biomass and other secondary fuels is the main item for the last 10 years.Fifty-five elements were measured in the solid state and eight elements in the gaseous phase. It appeared that at low particulate concentration the influence of calcium containing evaporated water droplets downstream the wet FGD on the emissions of heavy metals is bigger than the composition of the coal. Also it appeared that at modern coal-fired power stations the emissions are hardly influenced by co-combustion of biomass. All the results are used for modelling, resulting in the KEMA TRACE MODEL^®, by which the emissions can be predicted. The established emission factors are for most elements in good agreement with literature values for comparable modern installations.Persistence organic pollutants (POPs) that were detected in the flue gases of coal-fired power stations are polycyclic aromatic hydrocarbons (PAH) and dioxins/furans. Measurements during full coal-firing and during co-firing of biomass have indicated that these emissions are negligible.     

Amelioration of alkali soil using flue gas desulfurization byproducts: productivity and environmental quality

In this study, flue gas desulfurization (FGD) byproducts are used to ameliorate alkali soil. The average application rates for soils with low exchangeable sodium percentage (ESP), mid ESP, and high ESP are 20.9, 30.6, and 59.3 Mg ha(-1), respectively. The experimental results obtained for 3 consecutive years reveal that the emergence ratios and yields of the crops were 1.1-7.6 times and 1.1-13.9 times those of the untreated control, respectively. The concentrations of Cr, Pb, Cd, As, and Hg in the treated soils are far below the background values stipulated by the Environmental Quality Standard for Soils (GB15618-1995). Their concentrations in the seeds of corn and alfalfa grown in the treated soils are far below the tolerance limits regulated by National Food Standards of China. The results of this research demonstrate that the amelioration of alkali soils using FGD byproducts is promising.     

Trace metal distribution and control in the pilot-scale bubbling fluidized bed combustor equipped with the pulse-jet fabric filter,limestone injection,and the humidification reactor

This work focused on trace metal behavior and removal in a fabric filter or in a humidification reactor during the cofiring of sawdust and refuse-derived fuels (RDFs) in a pilot-scale bubbling fluidized bed (BFB) boiler. Trace metal emissions measurements before and after the fabric filter revealed that removal efficiency in the fabric filter was in the range of 80-100%, and that the European Union (EU) Directive on Incineration of Waste restrictions for trace metal emissions are easily achieved even if addition of RDFs substantially increases the concentration of trace metals in fuel blends. Limestone injection enhanced the removal of As and Se but had no noticeable effect on the removal of other trace metals. Extensive formation of HgCl2 and condensation on fly ash particles during sawdust plus 40% RDF cofiring resulted in a 92% Hg removal efficiency in the fabric filter. Limestone injection had no effect on the Hg removal in the fabric filter but decreased the Hg removal in a humidification reactor from 40 to 28%. Results of the bed material and fly ash analysis suggested capture of Cu, Pb, Mn, Ni, and Zn in the bed material but also suggested that these metals may be released from the bed if the fuel characteristics or process conditions are changed.     

The impact of wet flue gas desulfurization scrubbing on mercury emissions from coal-fired power stations

This article introduces a predictive capability for Hg retention in any Ca-based wet flue gas desulfurization (FGD) scrubber, given mercury (Hg) speciation at the FGD inlet, the flue gas composition, and the sulphur dioxide (SO2) capture efficiency. A preliminary statistical analysis of data from 17 full-scale wet FGDs connects flue gas compositions, the extents of Hg oxidation at FGD inlets, and Hg retention efficiencies. These connections clearly signal that solution chemistry within the FGD determines Hg retention. A more thorough analysis based on thermochemical equilibrium yields highly accurate predictions for total Hg retention with no parameter adjustments. For the most reliable data, the predictions were within measurement uncertainties for both limestone and Mg/lime systems operating in both forced and natural oxidation mode. With the U.S. Environmental Protection Agency's (EPA) Information Collection Request (ICR) database, the quantitative performance was almost as good for the most modern FGDs, which probably conform to the very high SO2 absorption efficiencies assumed in the calculations. The large discrepancies for older FGDs are tentatively attributed to the unspecified SO2 capture efficiencies and operating temperatures and to the possible elimination of HCl in prescrubbers. The equilibrium calculations suggest that Hg retention is most sensitive to inlet HCl and O2 levels and the FGD temperature; weakly dependent on SO2 capture efficiency; and insensitive to HgCl2, NO, CA:S ratio, slurry dilution level in limestone FGDs, and MgSO3 levels in Mg/lime systems. Consequently, systems with prescrubbers to eliminate HCl probably retain less Hg than fully integrated FGDs. The analysis also predicts re-emission of Hg(O) but only for inlet O2 levels that are much lower than those in full-scale FGDs.     

Sulfur Gas Emissions from Flue Gas Desulfurization Sludge Ponds

This paper presents initial measurement data on the emission of volatile, reduced sulfur-containing gases from flue gas desulfurization (FGD) storage ponds. Several different types of FGD stored sludges were studied including lime, limestone, and mixtures of fly ash and lime or limestone residues, some of which had been chemically stabilized. The volatile sulfur gas emissions were cryogenically concentrated and determined by wall-coated, open-tubular capillary column gas chromatography using a flame photometric detector. Hydrogen sulfide, carbonyl sulfide, dimethyl sulfide, carbon disulfide, and an unusual, unidentified sulfur-containing compound were found in the gaseous pond flux. Benzene, toluene, and α-pinene were also identified by gas chromatography-single ion monitoring mass spectrometry. The total reduced sulfur gas emission from a 100 acre pond approximated 2.0 kg day^?1 (as sulfur).     

Mercury emission trend influenced by stringent air pollutants regulation for coal-fired power plants in Korea

Regulatory control of mercury emission from anthropogenic sources has become a global concern in the recent past. Coal-fired power plants are one of the largest sources of anthropogenic mercury emission into the atmosphere. This paper summarizes the current reducing trend of mercury emission as co-beneficial effect by more stringent regulation changes to control primary air pollutants with introducing test results from the commercial coal-fired facilities and suggesting a guideline for future regulatory development in Korea. On average, mercury emission concentrations ranged 16.3–2.7 μg Sm^?3, 2.4–1.1 μg Sm^?3, 3.1–0.7 μg Sm^?3 from anthracite coal-fired power plants equipped with electrostatic precipitator (ESP), bituminous coal-fired power plants with ESP + flue gas desulphurization (FGD) and bituminous coal-fired power plants with selective catalytic reactor (SCR) + cold side (CS) ? ESP + wet FGD, respectively. Among the existing air pollution control devices, the best configuration for mercury removal in coal-fired power plants was SCR + CS ? ESP + wet FGD, which were installed due to the stringent regulation changes to control primary air pollutants emission such as SO₂, NOx and dust. It was estimated that uncontrolled and controlled mercury emission from coal-fired power plants as 10.3 ton yr^?1 and 3.2 ton yr^?1 respectively. After the installation of ESP, FGD and SCR system, following the enforcement of the stringent regulation, 7.1 ton yr^?1 of mercury emission has been reduced (nearly 69%) from coal-fired power plants as a co-benefit control. Based on the overall study, a sample guideline including emission limits were suggested which will be applied to develop a countermeasure for controlling mercury emission from coal-fired power plants.     

Investigation of aerosol and gas emissions from a coal-fired power plant under various operating conditions

The concentrations of fine particles and selected gas pollutants in the flue gas entering the stack were measured under several common operation modes in an operating coal power plant producing electricity. Particle size distributions in a diameter range from 10 nm to 20 μm were measured by a scanning mobility particle sizer (SMPS), and the flue gas temperature and concentrations of CO₂ and SO₂ were monitored by a continuous emission monitoring system (CEMS). During the test campaign, five plant operating modes were studied: soot blowing, bypass of flue-gas desulfurization (FGD), reheat burner operating at 0% (turned off), 27%, and 42% (normal condition) of its full capacity. For wet and dry aerosols, the measured mode sizes were both around 40 nm, but remarkable differences were observed in the number concentrations (#/cm³, count per square centimeter). A prototype photoionizer enhanced electrostatic precipitator (ESP) showed improved removal efficiency of wet particles at voltages above +11.0 kV. Soot blowing and FGD bypass both increased the total particle number concentration in the flue gas. The temperature was slightly increased by the FGD bypass mode and varied significantly as the rating of reheat burner changed. The variations of CO₂ and SO₂ emissions showed correlations with the trend of total particle number concentration possibly due to the transitions between gas and particle phases. The results are useful in developing coal-fired power plant operation strategies to control fine particle emissions and developing amine-based CO₂ capture technologies without operating and environmental concerns associated with volatile amine emissions.

Implications: The measurement of the fine particle size distributions in the exhaust gas under several common operating conditions of a coal-fired power plant revealed different response relations between aerosol number concentration and the operating condition. A photo-ionizer enhanced ESP was demonstrated to capture fine particles with higher efficiency compared to conventional ESPs, and the removal efficiency increased with the applied voltage. The characteristic information of aerosols and main gaseous pollutants in the exhaust gas is extremely important for developing and deploying CO₂ scrubbers, whose amine emissions and operating effectiveness depends greatly on the upstream concentrations of fine particles, SO₂, from the power plant.     

Application of the Lime/Limestone Flue Gas Desulfurization Process to Smelter Gases

In this presentation, adaptation of the lime/limestone process for flue gas desulfurization (FGD) is discussed and how this process can be adapted to applications in the nonferrous smelting industry such as fugitive gases, copper reverberatory furnace gases, lead sintering gases, molybdenum roasting plant tail gases, and other weak SO₂ smelter gases. Different methods for particulate removal are also discussed with emphasis on how the particulate removal process can be integrated with the desulfurization process.     

Simulation of stack plume opacity

The visual impact of primary particles emitted from stacks is regulated according to stack opacity criteria. In-stack monitoring of the flue gas opacity allows plant operators to ensure that the plant meets U.S. Environmental Protection Agency opacity regulations. However, the emission of condensable gases such as SO3 (that hydrolyzes to H2SO4), HCl, and NH3, which may lead to particle formation after their release from the stack, makes the prediction of stack plume opacity more difficult. We present here a computer simulation model that calculates the opacity due to both primary particles emitted from the stack and secondary particles formed in the atmosphere after the release of condensable gases from the stack. A comprehensive treatment of the plume rise due to buoyancy and momentum is used to calculate the location at which the condensed water plume has evaporated (i.e., where opacity regulations apply). Conversion of H2SO4 to particulate sulfate occurs through nucleation and condensation on primary particles. A thermodynamic aerosol equilibrium model is used to calculate the amount of ammonium, chloride, and water present in the particulate phase with the condensed sulfate. The model calculates the stack plume opacity due to both primary and secondary particles. Examples of model simulations are presented for three scenarios that differ by the emission control equipment installed at the power plant: (1) electrostatic precipitators (ESP), (2) ESP and flue gas desulfurization, and (3) ESP and selective catalytic reduction. The calculated opacity is most sensitive to the primary particulate emissions. For the conditions considered here, SO3 emissions showed only a small effect, except if one assumes that most H2SO4 condenses on primary particles. Condensation of NH4Cl occurs only at high NH3 emission rates (about 25 ppm stack concentration).     

The Use of Nahcolite Ore and Bag Filters For Sulfur Dioxide Emission Control

This paper describes some technical and economic aspects of the nahcolite ore injection process for the simultaneous removal of fly ash and sulfur oxides from stack gases. The process is capable of removing greater than 99% of the particulate matter and greater than 70% of the sulfur oxides present in such gases. In the process, nahcolite ore, a naturally occurring material containing 70 to 90% sodium bicarbonate, is ground to 90% passing through —200 mesh screens. Approximately 20% of the ground ore is used to precoat the filter bags in a baghouse filter while the remainder of the material is fed into the flue gas Just ahead of the baghouse. The flue gas is drawn through the baghouse by induced draft fans and sent up the stack. Most of the SO₂ and practically all of the fly ash in the flue gas can be removed as the gas passes through the filter bags. The spent nahcolite ore and fly ash are collected and conveyed to waste disposal as landfill, or alternatively processed for insolubilization by coprecipitation prior to landfilling. The technical feasibility of the process has been demonstrated in both bench scale and pilot scale engineering studies. Economic analyses performed for the cases of plants located in the midwest and southwest indicate lower capital costs for the nahcolite injection process when compared to wet scrubbing. On an annual cost basis, the nahcolite ore Injection process is comparable in cost to wet scrubbing for the case of the southwestern power plant, and somewhat more expensive for the case of the midwestern plant.