Energy Fuels 2010, 24, 205–212 Published on Web 09/09/2009
: DOI:10.1021/ef900557p
Speciation of Mercury in Coal-Fired Power Station Flue Gas† Pushan Shah, Vladimir Strezov,* and Peter F. Nelson Graduate School of the Environment, Department of Environment and Geography, Faculty of Science, Macquarie University, Sydney, New South Wales 2109, Australia. Received May 31, 2009. Revised Manuscript Received July 14, 2009
Mercury is a potentially toxic trace metal. Mercury exists naturally in coal in very low concentrations, having been incorporated during the coalification process. Consequently, coal-fired power stations are a major anthropogenic source of mercury because of the large quantity of coal used for electricity generation. In the environment, mercury transforms into methylmercury, a potential neurotoxin, bioaccumulates in aquatic biota, and subsequently, enters the food chain. The subsequent environmental fate and ability to capture mercury prior to emission are dependent upon its different physicochemical forms and oxidation states, known as speciation. In this work, speciation of mercury was conducted at five different coal power stations across Australia (one in New South Wales, three in Western Australia, and one in Queensland) by the Ontario Hydro sampling and analysis method. The total Hg concentrations in the emissions of these plants were found to be in the range of 1.9-5.6 μg Nm-3. Particle-bound mercury HgP occurred in very low proportions of 0.3-3.7%, while variable proportions of Hg0 and HgII were observed. Kinetic calculations were performed assuming a homogeneous system to understand role of the chlorine/mercury ratio of feed coal in the oxidation of mercury during power station combustion. Results from this study are compared to previous work published in the literature and discussed with respect to operating parameters of the power station.
compounds such as HgS (cinnabar), HgSe (tiemannite), and native Hg have been reported.4 Upon combustion, mercury is vaporized from coal and released in the elemental form into the combustion zone. Unlike the nonvolatile or semi-volatile trace elements in coal, this “initial” combustion transformation mechanism of mercury is independent of its mode of occurrence in feed coals.4 Mercury speciation in flue gas is largely dependent upon the availability of certain gas species, which have affinity to react, oxidize, or reduce the flue gas Hg compounds. Galbreath and Zygrlicke5 discussed the chemistry of Hg in flue gas, where Hg0 emitted during coal combustion can react with flue gas components, such as O2, HCl, Cl2, SO2, NO2, N2O, NO, NH3, and H2S, over the temperature range of 20-900 °C. Transformation of Hg0 to HgII involves both gas-phase and gas-solid reactions. It has also been reported that the rate of the gas-phase oxidation reaction of Hg0 with Cl2 is approximately 3 times higher than that of Hg0 (g) with HCl (g). HgII compounds, i.e., HgO and HgCl2, formed through oxidation reactions can possibly be reduced to Hg0 by SO2 and CO present in flue gas and/or their contact with the available hot steel surfaces. Apart from chlorine content in feed coal and subsequent homogeneous reaction mechanisms, recent studies have reported that heterogeneous reactions are essential for the Hg0 oxidation mechanism, where the level of unburnt carbon particles present in the postcombustion environment would play a significant role.6-8
Introduction It has been well-documented that different physicochemical forms of mercury influence its environmental transport, fate, and in some cases, impacts.1 Mercury is released from combustion of coal in three different forms: (i) elemental Hg0, (ii) divalent HgII, and (iii) particulate-phase mercury HgP. The particulate and divalent forms of mercury are more readily captured through existing pollution control devices, such as flue gas desulfurization (FGD), and particle control devices, such as electrostatic precipitators and fabric filtration. Divalent or particulate forms of mercury are ∼105 times more soluble in water than Hg0.1 As a result, when compared to the other two forms of mercury, Hg0 has a longer residence time in the atmosphere. Elemental mercury is expected to remain longer in the environment and, as a result, has the potential to deposit further from the power station, where it was emitted. In the atmosphere, Hg0 has a residence time of approximately 1 year, which is significantly longer when compared to the other forms, which have atmospheric residence times of a few hours to several months.2 Consequently, particle-bound HgP and divalent HgII are expected to be deposited closer to power stations by dry or wet deposition. Mercury in bituminous coal is mainly found within Fesulfides (pyrite and marcasite), whereas lower rank coals, i.e., sub-bituminous and lignite, have a greater proportion of organically bound Hg.3 For high-Hg coals (i.e., Hg>5 mg/kg), † Presented at the 2009 Sino-Australian Symposium on Advanced Coal and Biomass Utilisation Technologies. *To whom correspondence should be addressed. Telephone: þ61-29850-6959. Fax: þ61-2-9850-7972. E-mail:
[email protected]. (1) Lindberg, S. E.; Stratton, W. J. Environ. Sci. Technol. 1998, 32, 49–57. (2) Lin, C. J.; Pehkonen, S. O. Atmos. Environ. 1999, 33, 2067–2079. (3) Kolker, A.; Constance, S. L.; Quick, J. C. Int. J. Coal Geol. 2006, 21, 1821–1836.
r 2009 American Chemical Society
(4) Brownfield, M. E.; Affolter, R. H.; Cathcart, J. D.; Johnson, S. Y.; Brownfield, I. K.; Rice, C. A. Int. J. Coal Geol. 2005, 63, 247–275. (5) Galbreath, K. C.; Zygarlicke, C. J. Fuel Process. Technol. 2000, 65-66, 289–310. (6) Sable, S. P.; Jong, W.; Spliethoff, H. Energy Fuels 2008, 22, 321–330. (7) Niksa, S.; Fujiwara, N. J. Air Waste Manage. Assoc. 2005, 55, 930–939. (8) Niksa, S.; Fujiwara, N.; Fujita, Y.; Tomura, K.; Moritomi, H.; Tuji, T.; Takasu, S. J. Air Waste Manage. Assoc. 2002, 52, 894–901.
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Table 1. Ultimate and Proximate Analyses of Coal Samples proximate analysis (%) (ad basis)a coal A B C D E a
ultimate analysis (%) (daf basis)b
air-dried moisture
ash
volatile matter
fixed carbon
C
H
N
Oc
S
Cl (mg/kg)
13.3 11.1 11.0 2.8 4.0
5.4 6.8 7.3 20.9 32.5
33.4 33.0 31.5 28.2 26.6
47.9 49.1 50.2 48.1 36.9
74.5 73.2 73.5 82.1 77.1
3.9 4.2 4.1 5.1 5.5
1.5 1.4 1.4 1.9 1.5
20.0 20.6 20.3 10.8 15.7
0.1 0.6 0.7 0.1 0.2
77 52 400 110 150
Air-dried basis. b Dried ash-free basis. c O was determined by difference.
power stations. Speciation results from this study are compared to results reported in the literature to both compare the concentrations of mercury observed in flue gas and understand the impact of different operating parameters.
Environmental regulators in many countries are concerned with the emission of mercury from coal-fired power stations. The United States Environmental Protection Agency (U.S. EPA) in March 2005 announced a “cap and trade” approach under the Clean Air Mercury Rule to reduce emissions from U.S.-based coal-fired power stations, which is currently being reviewed by the U.S. EPA after being vacated by the U.S. courts.9 The National Pollutant Inventory (NPI) in Australia has estimated mercury emissions from electricity generation as 1.3 tons of the total 28 tons per year from all anthropogenic sources.10 A recent study that incorporated better estimation techniques and improved emission factors has estimated that stationary energy sources from Australia contribute 2-8 tons/year of mercury to the atmosphere.11 There is a range of literature reports on the speciation of mercury in flue gas for international power stations.12-22 There is, however, limited understanding of the speciation of mercury in Australian power stations using Australian coals.23 Australia’s heavy reliance on coal combustion for electricity generation and its leading position as a coal exporter point to a need to study speciation of mercury in flue gas from Australian power stations using a range of feed coals. The speciation of mercury was determined at five different power stations across Australia using the U.S. EPA recommended Ontario Hydro sampling and analysis method.24 Mercury contents in feed coal and in coal combustion products were analyzed to confirm volatile behavior of mercury in
Experimental Section Sampling. Coal, bottom ash, fly ash, and flue gas samples were collected from five different power stations across Australia. Three power stations were located in Western Australia, one in Queensland, and one in New South Wales. All power stations use black coal for electricity generation, obtained from local mining areas. The power stations are designated with the names “A”, “B”, “C”, “D”, and “E”. Power station “C” is operated by a mixed fuel of coal and natural gas at the ratio of 0.8:0.2. Representative coal, bottom ash, and fly ash samples were obtained from these power stations during the sampling period. Sampling of natural gas was not performed at the power station “C”. Typically, in Australian power stations, fabric filters (FFs) or electrostatic precipitators (ESPs) are installed as particle-capture devices. Neither selective catalytic reduction (SCR) nor flue gas desulfurization (FGD) units are installed in Australian power stations because of the generally low sulfur content of Australian coals and low environmental impact of acid gases.25 In this study, coal samples were collected from the coal feed to the boiler, bottom ash samples were collected from the hopper located at the bottom of the boiler furnace, and fly ash samples were collected from designated sampling points located at the particle-capture devices. For flue gas sampling, the transition duct downstream of the ESP or FF was chosen as the sampling location. Ultimate and proximate analyses of coal samples collected from the power stations are given in Table 1. The chlorine content in feed coals is shown in Table 1. The ash content of coals varies from 5.4 to 32.5%. Feed coals in power stations “A”, “B”, and “C” are mined from the same region, which is reflected by the similarity in properties, such as ash content and air-dried moisture. Mercury Content in Coal and Ash Samples. Mercury content in coal, bottom ash, and fly ash was determined by U.S. EPA method 1631, which uses oxidation, purge and trap, desorption, and coldvapor atomic fluorescence spectrometry (CVAFS).26 Using this method, coal samples were digested in concentrated nitric acid using an Anton-Paar high-pressure asher (HPA), in which digestion occurred in pure quartz vessels at approximately 350 °C and 100 atm. The digest was diluted to 20 mL, and small liquid aliquots were quantified for Hg using SnCl2 reduction, dual Au amalgamation, and CVAFS detection. The ash samples were digested in the mixture of concentrated HNO3, HF, and HCl at 100 °C in a Teflon bomb for a period of 10-15 h. The digest was diluted to 50 mL, and then small aliquots were quantified for Hg using SnCl2 reduction, dual Au amalgamation, and CVAFS detection.
(9) United States Environmental Protection Agency (U.S. EPA). Clean Air Mercury Rule, http://www.epa.gov/oar/mercuryrule/ (accessed on May 13, 2009). (10) National Pollutant Inventory (NPI). Mercury and compounds; Sources. www.npi.gov.au (accessed on March 25, 2008). (11) Nelson, P. F. Atmos. Environ. 2007, 41, 1717–1724. (12) Senior, C. L. Power production in the 21st Century: Impacts of fuel quality and operations. Engineering Foundation Conference, Snowbird, UT, Oct 28-Nov 2, 2001. (13) Pavlish, J. H.; Sondreal, E. A.; Mann, M. D.; Olson, E. S.; Galbreath, K. C. Fuel Process. Technol. 2003, 82, 89–165. (14) Otero-Rey, J. R.; Lopez-Vilarino, J. M.; Moreda-Pineiro, J.; Alonso-Rodriguez, E.; Muniategui-Lorenzo, S.; Lopez-Mahia, P.; Prada-Rodriguez, D. Environ. Sci. Technol. 2003, 37, 5262–5267. (15) Goodarzi, F. J. Environ. Monit. 2004, 6, 792–798. (16) Lee, S. J.; Seo, Y.; Jurng, J.; Hong, J. H.; Park, J. W.; Hyun, J. E.; Lee, T. G. Sci. Total Environ. 2004, 325, 155–161. (17) Lee, S. J.; Seo, Y.; Jang, H.; Park, K.; Baek, J.; An, H.; Song, K Atmos. Environ. 2006, 40, 2215–2224. (18) Tan, Y.; Mortazavi, R.; Dureau, B.; Douglas, M. A. Fuel 2004, 83, 2229–2236. (19) Guo, X.; Zheng, C.; Xu, M. Energy Fuels 2007, 21, 898–902. (20) He, B.; Cao, Y.; Romero, C. E.; Bilirgen, H.; Sarunac, N.; Agarwal, H.; Pan, W. Chem. Eng. Commun. 2007, 194, 1596–1607. (21) Goodarzi, F.; Huggins, F. E.; Sanei, H. Int. J. Coal Geol. 2008, 74, 1–12. (22) Wang, Y.; Duan, Y.; Yang, L.; Zhao, C.; Shen, X.; Zhang, M.; Zhuo, Y.; Chen, C. Fuel Process. Technol. 2009, 90, 643–651. (23) Shah, P.; Strezov, V.; Prince, K.; Nelson, P. F. Fuel 2008, 87, 859– 1869. (24) American Society for Testing and Materials (ASTM). Standard test method for elemental, oxidized, particle-bound and total mercury in flue gas generated from coal-fired stationary sources (Ontario Hydro Method), D6784-02. Annual Book of ASTM Standards; ASTM: West Conshohocken, PA, 2002; Vol. 11.03.
(25) Environment Protection Authority (EPA). Acid rain, http:// www.epa.sa.gov.au/pdfs/info_acidrain.pdf (accessed on March 25, 2008). (26) United States Environmental Protection Agency (U.S. EPA). Method 1631, Revision E: Mercury in water by oxidation, purge and trap, and cold vapor atomic fluorescence spectrometry, www.epa.gov/ waterscience/methods/method/mercury/1631.pdf (accessed on May 29, 2009).
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Table 2. Mercury and UBC Content in Coal, Bottom Ash, and Fly Ash and the REFs for Mercury in the Ash Fractions Following Combustion Hg (ppb) power station A B C D E
REF
coal
bottom ash
fly ash
% UBC
bottom ash
fly ash
30.7 ( 5.5 41.5 ( 7.5 34.2 ( 6.2 113.7 ( 12.5 40.6 ( 7.3
0.84 ( 0.15 0.89 ( 0.16 0.67 ( 0.12 0.95 ( 0.17 7.6 ( 0.17
5.8 ( 1 153 ( 17 140 ( 15 122.3 ( 13.5 41.7 ( 4.5
0.6 2.1 2.1 1.6 1.6
0.001 0.001 0.001 0.001 0.061
0.01 0.25 0.30 0.22 0.33
measurements were taken using a calibrated Strausscheibe-tube (S-type pitot) and K-type thermocouple attached to the sampling probe. The velocity and static pressure heads were measured using a dual-column inclined manometer, in accordance with U.S. EPA method 2.27 Oxygen and carbon dioxide contents of the flue gas were measured using a calibrated online analyzer in accordance with U.S. EPA method 3A.28 The moisture content of the gas was determined by gravimetric methods, in accordance with U.S. EPA method 4,29 in conjunction with isokinetic particulate matter and gaseous emissions/Hg speciation sampling activities (U.S. EPA method 5).30
Unburnt Carbon (UBC) in Fly Ash. UBC in fly ash was determined by the thermogravimetric analysis technique using a TGA/DSC 1 Mettler Toledo instrument. Approximately 25 ( 5 mg of fly ash sample was heated to 1000 °C in the oxidizing atmosphere of air at the flow rate of 70 mL/min. The mass (%) lost by the fly ash sample from 200 to 1000 °C was recorded as UBC. Ontario Hydro Sampling and Analysis. Flue gas sampling was conducted in accordance with the ASTM method of Ontario Hydro sampling (ASTM D6784-02).24 This method comprised isokinetic sampling of the combustion flue gas while maintaining the exit temperature and forcing the flue gas through a series of eight impingers immersed in an ice bath preceded by a filter to separate fine particles from flue gas. The filters used were Pall Life Sciences A/E glass fiber filters with a typical 0.3 μm DOP aerosol retention of 99.98%. Mercury content in the particles captured by filter was reported as particle-bound mercury, i.e., HgP. The first three impingers had 100 mL of 1 mol/L KCl solution. These impingers capture the oxidized form of mercury, i.e., HgII from flue gas. The fourth impinger contained 100 mL of a mixture of 5% (v/v) HNO3 and 10% (v/v) H2O2. The fifth, sixth, and seventh impingers contained 100 mL of a mixture of 4% HNO3 and 10% H2SO4. These impingers captured the elemental form of mercury (Hg0) from flue gas. The last impinger contained silica gel to capture the remaining moisture from the flue gas. Isokinetic conditions were maintained during the flue gas sampling by ensuring that the flue gas velocity for sampling was within (10% of the flue gas velocity in the stack. The analysis of mercury content from individual impingers was conducted using cold-vapor atomic absorption (CVAAS) or fluorescence spectrometry (CVAFS) (ASTM D 6784-02).24 During the sampling campaign, all plant conditions, such as power generation, coal feed rate, air flow, temperature at the outlet of air preheater, etc., were maintained at stable levels for at least 2 h prior to the commencement of sampling and were then maintained until the flue gas sampling was completed. In the case of power stations A and B, flue gas sampling was conducted at a single-point location because of the complexity of the plant configuration; however, the accuracy and representativeness of the sample positions were already established by these power stations by measuring velocity profiles of flue gas at different locations inside the duct. At power station C, the sampling was conducted in a duct downstream of the ESP using a 12-point sampling grid for a total period of 100 min. In the case of the power station D, sampling was conducted in the duct downstream of the ESP using an 8 6 sampling grid (total 48 points). Each point was sampled for 5 min. In the case of power station E, a 12-point sampling grid was employed at 15 min per point for a total sampling period of 180 min. In this work, fresh chemical solutions were prepared prior to each sampling activity. Glassware including impingers were thoroughly cleaned using hot soapy water and overnight soaking in dilute nitric acid. Demineralized water was used for rinsing. All reagents and chemicals were of analytical grade, and Millipore Milli-Q water was used for final washing of the glassware, impingers, and during solution preparation/dilution. The analysis of mercury in digested solutions was performed using CVAFS.24 Apart from speciation of mercury, several other parameters, such as flue gas velocity, temperature, and oxygen, carbon dioxide, and moisture content of the flue gases, were measured and reported during the sampling period. Velocity and temperature
Results and Discussion Concentrations of mercury in analyzed coal, bottom ash, and fly ash samples are shown in Table 2. The results are presented in parts per billion (ppb) ( μg/kg). Overall, concentrations of mercury in most feed coals for Australian power stations are low when compared to many coals consumed internationally in power generation.31 Relative enrichment factors (REFs) are a useful way of expressing the volatility of trace elements in power station combustion products. Introduced by Meij,32 the REF in the context of trace elements in coal combustion products is defined as relative enrichment factor ðREFÞ ¼
TE content in ash % ash content in coal TE content in coal 100
The volatility of trace elements can be classified according to the REFs.32 Table 2 presents REFs for mercury in the power station bottom and fly ash. Mercury was mostly volatile, escaping with flue gas through the stack. Thus, to be able to understand emissions of mercury from coal-fired power stations, it is essential to conduct flue gas sampling. After the REFs of fly ash were compared (displayed in Table 2), it appears that mercury enrichment in fly ash from power station A is much lower in comparison to fly ash samples from power stations B, C, D, and E. Previous studies suggest that mercury is adsorbed on the unburnt carbon particles in the fly ash, which is measured as loss on (27) United States Environmental Protection Agency (U.S. EPA). Method 2: Determination of stack gas velocity and volumetric flow rate (type S pitot tube), http://www.epa.gov/ttn/emc/promgate/m-02.pdf (accessed on Feb 15, 2009). (28) United States Environmental Protection Agency (U.S. EPA). Method 3a: Determination of oxygen and carbon dioxide concentrations in emissions from stationary sources (instrumental analyzer procedure), http://www.epa.gov/ttn/emc/promgate/method3A.pdf (accessed on Feb 15, 2009). (29) United States Environmental Protection Agency (U.S. EPA). Method 4: Determination of moisture content in stack gases, http:// www.epa.gov/ttn/emc/promgate/m-04.pdf (accessed on Feb 15, 2009). (30) United States Environmental Protection Agency (U.S. EPA). Method 5: Determination of particulate matter emissions from stationary sources, http://www.epa.gov/ttn/emc/promgate/m-05.pdf (accessed on Feb 15, 2009). (31) Commonwealth Scientific and Industrial Research Organisation (CSIRO). Mercury in Australian export thermal coals, 2008, http:// www.csiro.au/resources/ps2ra.html (accessed on March 10, 2008). (32) Meij, R. Fuel Process. Technol. 1994, 39, 199–217.
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Results on different forms of mercury are expressed in μg Nm-3. These values for the studied power stations are shown in Table 4 and are corrected to a common 7% O2 basis for the purpose of comparison. It can be observed that the concentration of particle-bound mercury (HgP) is very low compared to the divalent or elemental forms. It can also be noted that emission from power station A predominantly contains Hg0 (84%). Lower rank coals were combusted in power stations A, B, and C in this study. When the concentrations of reactive mercury are compared among the studied power stations, it can be observed that power station B has the highest concentration of reactive mercury at 2.8 μg Nm-3 and, hence, is likely to have a more pronounced local/regional pollution impact. The concentration of Hg0 is the highest for power station A at 2.2 μg Nm-3 and B at 2.7 μg Nm-3, while it is the lowest in flue gas from power station C at 0.8 μg Nm-3. Furthermore, in the case of power stations B, both reactive and elemental mercury concentrations were higher; hence, Hg emissions from this power station would be a contributor to both global and regional Hg pollutions. Mass Balance of Mercury at Power Stations A and B. The solids sampling of coal and ash fractions at power stations A and B was more rigorous and aimed to attempt to achieve a mass balance closure for mercury. The mass balance study of mercury has always been a challenge given the volatile nature of mercury under combustion conditions of a power station and the difficulty of accurate solids and gas analyses, given its very low concentration in all input and output streams.15 In the case of coal, bottom ash, and fly ash samples, all samples were homogenized and combined and subsamples of these were analyzed for total mercury concentration. Flow rates of each stream, i.e., coal, ash, and flue gas, were used for calculating the mass balance. Table 5 shows the mass balance results for power stations A and B. For power station A, ∼68% mass balance closure was obtained, and for power station B, ∼142% mass balance closure was obtained. The inaccuracy in mass balance closures might be due to inaccuracy associated with the measurements of mercury content, flow rates of each stream, i.e., coal, bottom ash and fly ash, and flue gas, and loss or accumulation of mercury within the power station because mercury is a volatile trace element.15 Also, it could be because of normal fluctuations in operations of the unit and the inability to obtain representative coal and ash samples relative to the flue gas sampling. The lack of continuous measurements might have also lead to poor mass balance closures. From mass balance studies shown in Table 5, it can be observed that the majority of mercury in feed coal is emitted in gaseous or volatile form through the flue gas. Homogenous Kinetic Modeling of Mercury in Flue Gas. During combustion, mercury from coal is vaporized and released in the elemental form in the combustion zone. Hg0 emitted during coal combustion can react with flue gas components, such as O2, HCl, Cl2, SO2, NO2, N2O, NO, NH3, and H2S.5 Mercury oxidation under coal combustion proceeds by both homogeneous and heterogeneous reactions, resulting in the formation of HgP, HgII, and Hg0. It is also known that gas-phase HgII formation in coal combustion systems can be significantly influenced by the chlorine content of the coal.5 Attempts have been made in the past to understand mercury transformation and the effect of flue gas components and operating parameters of power stations.
Figure 1. REFs of fly ash versus UBC (%) in fly ash.
ignition (LOI).19,33 Carbon particles act as an adsorbent for mercury, which captures the volatile mercury during the postcombustion cooling zone.34 In this work, unburnt carbon (UBC) content was analyzed using thermogravimetric analysis (TGA) and was found in the range of 0.6-2.1% in all fly ash samples (Table 2). As shown in Figure 1, a fair correlation (r2 = 0.75) was obtained, suggesting the influence of UBC of fly ash on the REFs in fly ash samples. Although the feed coals are different, all of the selected power stations were installed with ESP as the particle-capture device. However, more power station studies are required to confirm this trend. It can be observed from Table 3 that time of sampling varied for all of the power stations because of the complexity of plant configuration. The sampling volume was also varied from as low as 1.0 to as high as 4.2 m3. The temperature of flue gas sampled was in the range of 388-425 K. The oxygen content in flue gas varied widely from 3.6% for power station B to 8.6% in the case of power station E. It can also be observed from Table 3 that the isokinetic ratio was maintained according to the requirement of the method. Sampling guidelines, as stipulated in the method, were strictly followed, and no biases were reported. After collecting samples, impinger solutions and filters were digested according to the method.24 All digestions were carried out in duplicates and analyzed for mercury content. Relative percent differences (RPDs) of less than 5% were obtained between the duplicates against the accepted QC value of 20%. Recovery of mercury in all fortified samples was within the accepted limit of 85-115%. For HgP determination, a standard reference material NIST-1633b, i.e., coal fly ash, was digested using the digestion procedure outlined in the Ontario Hydro method for particles collected in filter. Mercury was recovered in the accepted range of 90-110%. No biases were reported during the digestion and chemical analysis. The flue gas sample collected for mercury speciation was a composite of samples collected from a large number of grid sampling points spread across the duct, and therefore, they represent an integrated average sample. Further, an unbiased comparison of duplicate samples in a dynamic system, such as a power station duct, is really not possible because of variations in power station load, coal composition, UBC, etc. (33) Lu, Y.; Rostam-Abadi, M.; Chang, R.; Richardson, C.; Paradis, J. Energy Fuels 2007, 21, 2112–2120. (34) Sable, S. P.; Jong, W.; Meij, R.; Spliethoff, H. Energy Fuels 2007, 21, 1891–1894.
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Table 3. Sampling Parameters at Power Stations parameter volume sample at dry STP temperature oxygen carbon dioxide moisture volumetric flow rate at dry STP (7% O2 basis) sampling time isokinetic ratio average flue gas velocity plant capacity particulate concentrations, dry standard a
unit
A
B
C
D
E
m K % % % m3/s h:min % m/s MW mg Nm-3
2.3 425 6.2 10.7 9.8 316 2:01 101 17 340 16
1.0 416 3.6 12.6 11.3 123 2:00 100.9 26.2 850 19.9
1.2 412 5.7 10.5 11.9 46 1:40 96.5 10.8 120 2.3
4.2 396 5.2 13.6 9.2 161 4:00 98 16 660 NRa
2.5 388 8.6 10.6 6.2 330 3:00 98 22 254 243
3
NR= not reported.
Table 4. Speciation of Mercury in Flue Gas (Corrected to a 7% O2 Basis) Hg0 power station
-3
μg Nm
A B C D E
2.2 2.7 0.8 1.1 0.9
HgII %
-3
μg Nm
84.0 47.5 44.1 58.0 39.4
0.4 2.8 1.0 0.8 1.4
coal bottom ash fly ash flue gas
30.70 ( 5.5 μg/kg 0.84 ( 0.15 μg/kg 5.8 ( 1 μg/kg 2.6 μg Nm-3
A ∼41.0 kg/s ∼0.5 kg/s ∼2.0 kg/s 316 N m3 s-1
∼4.53 ∼0.002 ∼0.04 3.02
∼68
coal bottom ash fly ash flue gas
41.5 ( 7.5 μg/kg 0.89 ( 0.16 μg/kg 153 ( 17 μg/kg 5.6 μg Nm-3
B ∼13.42 kg/s ∼0.18 kg/s ∼0.70 kg/s 123 N m3 s-1
∼2.004 ∼0.001 ∼0.407 2.448
∼142
-3
total Hg
μg Nm
%
μg Nm-3
0.01 0.12 0.04 0.07 0.01
0.3 2.1 1.8 3.7 0.3
2.6 5.6 1.9 1.9 2.4
chlorine in a homogeneous system. Krishnakumar and Helble36 tested the homogeneous reaction mechanism with the help of reaction kinetics data previously proposed by Qiu et al.,37 Wilcox et al.,38 and Niksa et al.,7 on a benchscale system and found that results obtained from kinetic calculations were in agreement with the experimental results. Wilcox et al.38 theoretically calculated kinetic data using a quantum chemistry approach for three of total eight reactions, as shown in Table 6, which has largely improved the model predictions.36 In this work, an attempt was made to see whether the oxidation of mercury during combustion could be explained by chlorine content in the coals. The averaged values of the flue gas measurements conducted using the Ontario Hydro method at the five different power stations has been used as a data set for comparison. The 8-step homogeneous Hg oxidation mechanism by Widmer et al.35 with reaction rate constants by Wilcox et al.38 and Qiu et al.37 have been used in CHEMKIN 4.0.1 to perform the kinetic calculations using a mixed flow reactor model. The reaction mechanism from Xu et al.39 was used along with the mercury oxidation mechanism to allow for the kinetic calculations to be made. Figures 2 and 3 show the results of kinetic calculations for HgII and Hg0 and the actual power station measurements, as functions of the feed coal chlorine. The Cl/Hg molar ratio values have been used as variables in an attempt to understand whether chlorine is controlling mercury oxidation. With an increasing chlorine/mercury molar ratio, the model predicts that the level of mercury oxidation steadily increases. While, in some cases, there were increased levels of mercury oxidation with increasing chlorine/mercury molar ratios as predicted by the homogeneous model, the model was a poor predictor of power plant performance (Table 7). Because the measurements are taken in flue gas from
total Hg mass balance flow (g/h) closure (%)
flow rate
% 15.7 50.4 54.1 38.3 60.3
Table 5. Mass Balance of Mercury at Power Stations A and B Hg content
HgP
A simplified homogeneous kinetic model is a widely used method to predict mercury oxidation under coal combustion conditions. Widmer et al.35 proposed the following 8-step mechanism for homogeneous mercury oxidation by chlorine: ðiÞ Hg þ Cl þ M a HgCl þ M ðiiÞ Hg þ Cl2 a HgCl þ Cl ðiiiÞ Hg þ HCl a HgCl þ H ðivÞ Hg þ HOCl a HgCl þ OH ðvÞ HgCl þ Cl þ M a HgCl2 þ M ðviÞ HgCl þ Cl2 a HgCl2 þ Cl ðviiÞ HgCl þ HCl a HgCl2 þ H ðviiiÞ HgCl þ HOCl a HgCl2 þ OH This reaction mechanism simple kinetic model has been used in the literature to model mercury transformation by
(37) Qiu, J.; Helble, J. J.; Sterling, R. Proceedings of the 12th International Conference on Coal Science, Cairns, Queensland, Australia, 2003. (38) Wilcox, J.; Marsden, D. C.; Blowers, P. Fuel Process. Technol. 2004, 85, 391–400. (39) Xu, M.; Qiao, Y.; Zheng, C.; Li, L.; Liu, J. Combust. Flame 2003, 132, 208–218.
(35) Widmer, N. C.; West, J.; Cole, J. A. Proceedings of Air and Waste Management Associations 93rd Annual Conference and Exhibition, Pittsburgh, PA, 2004. (36) Krishnakumar, B.; Helble, J. J. Environ. Sci. Technol. 2007, 41 (22), 7870–7875.
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Table 6. Reaction Kinetics Data for Homogeneous Mercury Oxidation Reactions with Chlorine reaction number 1 2 3 4 5 6 7 8
reaction
A (cm3 mol-1 s-1)
E (cal/mol)
B
reference
Hg þ Cl þ M a HgCl þ M Hg þ Cl2 a HgCl þ Cl Hg þ HCl a HgCl þ H Hg þ HOCl a HgCl þ OH HgCl þ Cl þ M a HgCl2 þ M HgCl þ HCl a HgCl2 þ H HgCl þ HOCl a HgCl2 þ OH HgCl þ Cl2 a HgCl2 þ Cl
4.24 10 3.26 1010 4.94 1014 3.43 1012 2.09 1017 4.50 1013 4.27 1013 2.02 1014
8588 22800 79300 12790 37952 3049 1000 3280
0 0 0 0 0 0 0 0
38 37 37 37 38 38 37 37
13
Figure 3. Hg0 (%) in flue gas versus the Cl/Hg molar ratio of feed coal for power stations A-E.
Figure 2. HgII (%) in flue gas versus the Cl/Hg molar ratio of feed coal for power stations A-E.
Table 7. Comparison of Field-Based Measurements of Mercury Speciation Compared to Predicted Values Using a Homogeneous Kenetic Reaction Model of Mercury Oxidation by Chlorine
large-scale power stations, factors other than chlorine content might have significantly influenced the speciation of mercury in the flue gas. One such factor could be the bromine content in feed coals. Previous studies have reported the significant influence of bromine on mercury oxidation in the flue gas.40,41 It has been reported previously that bromine content in Australian coals are in the range of 6-37 mg/kg compared to 0.5-90 mg/kg in the most international coals.42 The difference between model predictions and real measurement values may possibly be attributed to the lack of heterogeneous reaction mechanisms in the kinetic model and also the experimental difficulties associated with precise and accurate measurements under power station conditions, as indicated earlier by the failure to obtain mass balance closure. Comparison to International Studies. A review of the database of mercury speciation and stack emissions measurements in coal-fired power plants compiled by Mercury Information Collection Request (ICR) was initiated by the U.S. EPA. This review examined over 80 coal-fired power stations based on several factors, which included boiler type, configuration of air pollution control equipment, and fuel type. It was recommended by the U.S. EPA that the Ontario Hydro method be used for measurement of mercury species at the inlet and outlet of the pollution control devices. It was noted that all mercury present in coal was vaporized at the combustion conditions of boiler furnace and mercury concentrations were in the range of 1-20 μg Nm-3.12 In the same
power station A B C D E
Hg0 in flue gas (%)
HgII in flue gas (%)
Hg0 as predicted by the model (%)
HgII as predicted by the model (%)
84 47.5 44.1 58 39.4
15.7 50.4 54.1 38.3 60.3
25 40 48 45 20
75 60 52 55 80
review, it was also observed that coals with less than about 100 ppm Cl had predominantly elemental mercury at the inlet to the particle-capture device, while coals with greater than about 500 ppm Cl had less than 20% elemental mercury.12 In another study of U.S. coals, chlorine content and the coal and coal rank were poorly correlated and variations in speciation of mercury in emissions was observed to be influenced by the range of operating conditions, APCD type, and type/rank of feed coal.3 A review of the US-ICR database reported that, for bituminous-ranked coals, APCDs produce an average decrease of 20% in elemental mercury, Hg0, while for low-rank coal, there was little change in Hg0 across an ESP and a large decrease across FFs (in the order of 50% average).12 In a review by Pavlish et al.,13 it has been reported that mercury removal across cold-side ESPs averages 27% compared to 4% for hot-side ESPs, that fabric filters removed on average 58% of the flue gas mercury, probably because of a longer gas-solid retention time for mercury oxidation, and that both wet and dry FGD remove 80-90% of HgII but failed to capture the Hg0 form. Lee et al.16 reported 50% of mercury removal with cold-side ESP. They also reported oxidation of mercury through ESP, which could be removed
(40) Cao, Y.; Gao, Z.; Zhu, J.; Wang, Q.; Huang, Y.; Chiu, C.; Parker, B.; Chu, P.; Pan, W. Environ. Sci. Technol. 2008, 42, 256–261. (41) Liu, S.; Yan, N.; Liu, Z.; Qu, Z.; Wang, P.; Chang, S.; Miller, C. Environ. Sci. Technol. 2007, 41, 1405–1412. (42) Vassilev, S. V.; Eskenazy, G. M.; Vassileva, C. G. Fuel 2000, 79, 903–921.
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reference
211
a
660 254
300 250 660 50 200 220 600 600 340 850 116
300-2158 (6 different power stations)
cold-side ESP and bituminous wet FGD US-ICR average for bituminous coal-fired power stations with cold-side ESP and wet FGD cold-side ESP equipped sub-bituminous with hot-side ESP, except one with hot-side ESP ESP þ FGD bituminous ESP NR ESP bituminous FF bituminous FF bituminous FF bituminous ESP bituminous ESP bituminous ESP þ wet FGD bituminous ESP bituminous ESP bituminous ESP bituminous þ natural gas ESP bituminous ESP bituminous
500
coal type blends
ESP
1400
installed pollution control devices
Not corrected to a common flue gas O2 basis. b NR = not reported. c SD = standard deviation.
current work
Lee et al.16 Guo et al.19 He et al.20 Shah et al.23 Wang et al.22
Goodarzi
15
Otero-Rey et al.14 Lee et al.17
power generation (MW)
110 150
381 37 305 288 154 198 510 77 52 400
NR
NR
8.3-18.2
41.1
chlorine in coal (mg/kg)
113.7 40.6
41 52.1 244 188 11 209 50 30.7 41.5 34.2
NR
51-74
40-80
160
Hg content in coal ( μg/kg)
58 39.4
84 47.5 44.1
38.3 60.3
15.7 50.4 54.1
15 55-69 4-75.22 34 2.02-75.55
15.2 (SD = 25.1) 5.0-28.93
84.4 (SDc = 25.1) 70.5-95 85 31-45 24.78-96 58 0.77-13.57
24.0
64
HgII (%)
74.2
36
Hg0 (%)
Table 8. Speciation of Mercury in Flue Gas: Comparison of the Current Work to International Studies
3.7 0.3
0.3 2.1 1.8
8 0-0.54
NR NR
0.4 (SD = 0.4) 0.07-2.5
1.8
NRb
HgP (%)
1.9 2.4
2.6 5.6 1.9
2.25 13-21 1.285 ( 0.808 0.5 0.02-21.20
2.57 (SD = 1.8) 4.047-6.6
1.7
20.5
total Hg emissiona ( μg Nm-3)
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emissions and this may have the potential for deposition of mercury in the vicinity of power stations.
by FGD downstream. The evidence of oxidation of Hg to HgII and adsorption of gaseous mercury across particlecapture devices suggest that these processes are not simply related to chlorine and that other mechanisms may play a significant role in the process. These mechanisms have been incorporated in attempts to develop a combined homo- and heterogeneous model for mercury speciation.6-8 Previous studies carried out at overseas power stations using the Ontario Hydro method are shown in Table 8. It should be noted that the flue gas mercury concentrations reported for some overseas power stations may not be corrected to a common flue gas oxygen concentration basis. He et al.20 compared measurements of mercury speciation using both a semicontinuous monitoring methods and Ontario Hydro in a 250 MW coal-fired power station equipped with ESP. In their 12 different tests for speciation of mercury in flue gas at the ESP outlet, they found that mercury concentrations were in the range of 1.285 ( 0.808 μg Nm-3. An approximately 30% variation in Hg0 and 20% variation in THg were observed using the two measurement methods, and this was attributed to the different configuration and sampling port used during the course of measurement. Wang et al.22 measured speciation of mercury using the Ontario Hydro method at five coal-fired power stations in China and found that mercury mainly exited as Hg0 and HgII in flue gas. Hg0 was in the range of 0.77-13.57 μg Nm-3 post-ESP/FF, and HgII was in the range of 0.0221.2 μg Nm-3 post-ESP/FF. HgP was measured in the low concentrations of 0-0.54 μg Nm-3, which was significantly removed because of the presence of particle-capture devices. In the current work, the total mercury concentration in flue gas was in the range of 1.9-5.6 μg Nm-3 on dry 7% O2 basis. Although chlorine may have an influence on the oxidation of Hg0, this influence is not reliably predicted by a homogeneous kinetic model. It can be observed that ESP or FF installed in power stations significantly removes the HgP form of mercury from the flue gas. A previous study by these authors reported a mercury concentration in power station flue gas as 0.5 or 0.4 μg Nm-3 (corrected to 7% O2 basis), of which 58% was in the Hg0 form.23 That result and the current study confirm that the total Hg concentrations in flue gases from Australian power stations are in the lower range when compared to those reported for overseas power stations (Table 8), presumably because of lower mercury coals being used for combustion. Variable proportions of Hg0 and HgII were observed and may be due to many factors, including coal type, chlorine content, and plant-operating conditions, such as boiler design, etc. Because Australian power stations are not equipped with wet scrubbing technology, a larger proportion of HgII is likely to be released into the atmosphere via stack
Conclusions Speciation of mercury in flue gas at different power stations in Australia was performed using the Ontario Hydro method of sampling and analysis. Coal and ash samples were collected, and mercury concentrations were determined and confirm the volatile behavior of mercury under power station combustion conditions. A fair correlation between the unburnt carbon content of fly ash and REFs of fly ash for mercury suggests the possibility of increased retention capacity of mercury in fly ash with an increase in UBC. Concentrations of mercury in stack emission were observed in the range of 1.9-5.6 μg Nm-3, and elemental mercury was the dominant form for three power stations, while for two power stations, it was the divalent mercury species. For all power stations, particle-bound mercury, HgP, was the lowest or negligible in concentration, which is probably due to the presence of particle-capture devices, such as ESP. A comparison to the literature for mercury concentration in flue gas from international power stations indicates that mercury concentrations in flue gas from Australian coal-fired power stations are in the lower range primarily because of lower concentrations of mercury in Australian feed coals. Inaccuracies were observed for the mass balance of mercury at two power stations, which may be attributed to the inaccuracies associated with the sampling and analytical methods. Homogeneous kinetic modeling of mercury oxidation by chlorine suggests that, with an increasing Cl/Hg molar ratio in feed coal, the proportion of HgII in flue gas should steadily increase. No consistent correlation between the model predictions and measured results was found, suggesting that speciation of mercury in the flue gas from the stack depends upon many factors, such as coal type, operating conditions of the power station, including existing air pollution control devices (APCDs), and not simply the chlorine content of the feed coal. Acknowledgment. The authors acknowledge the support of CRC for Coal in Sustainable Development (CCSD), which is funded in part by the Cooperative Research Centres Program of the Commonwealth Government of Australia. This program was also partly supported by the Australian Coal Association Research Program (ACARP Project C16046). The authors thank Mr. Andy Wearmouth of Verve Energy for additional financial support. The authors also thank Dr. Artur Ziolkowski of Macquarie University for his help in TGA experiments.
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