Comparison of the Loss-on-Ignition and Thermogravimetric Analysis

Sep 19, 2001 - On the other hand, the correlation between LOI and UC is not as good as that between LOI and TL for most fly ashes, as illustrated in F...
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Energy & Fuels 2001, 15, 1414-1417

Comparison of the Loss-on-Ignition and Thermogravimetric Analysis Techniques in Measuring Unburned Carbon in Coal Fly Ash Maohong Fan* and Robert C. Brown† Center for Sustainable Environmental Technology, Iowa State University, Ames, Iowa 50011 Received February 27, 2001. Revised Manuscript Received August 1, 2001

We have determined, through thermogravimetric analyses (TGA) of seventy fly ash samples obtained from diverse coals and boilers, that loss-on-ignition (LOI) consistently overestimates unburned carbon in fly ash. Experimental results have shown that LOI overestimated unburned carbon by at least 20% in 44% of the fly ashes tested. Although some of these errors may be associated with previously identified thermal decomposition of minerals in fly ash, volatile organic compounds appear to play a role for some of the fly ashes evaluated in this study. This discovery has implications in the use of LOI to calculate combustion losses and monitor fly ash quality by power plant managers. We propose an alternative method to measure unburned carbon based on TGA.

Introduction Loss-on-ignition (LOI) has long served as a standard method1 to measure unburned carbon (char) in fly ash. However, Brown and Dykstra2 challenged this standard when they discovered minerals that dehydrate or decompose upon heating occur in sufficient concentrations to significantly overestimate the carbon content of fly ash upon LOI analysis. They suggested a wet chemical method for improving the accuracy of unburned carbon determination.3 In studies of unburned carbon in fly ash using a wider collection of samples, we have discovered another source of error in the LOI method. Using a methodology based on thermogravimetric analysis (TGA), we have found that some volatile material is not removed by the chemical method and can result in further overestimation of the carbon content in fly ash. We propose the use of TGA methods to replace LOI in the measurement of unburned carbon. Experimental Apparatus and Methods As-received fly ash is a heterogeneous mixture of mineral matter, char, and tar with particles ranging in diameter from 100 µm to submicron sizes. Representative sampling can be problematic under these circumstances. Grinding reduces the size of large particles of fly ash, makes the sample more homogeneous, and improves the chances of obtaining a representative sample. To this end, about 5 g of sample was placed in a mortar and hand-ground with a pestle for 2 min. LOI Methodology. The ASTM standard procedure was used to run all the LOI tests in this research.1 Tests were performed with 2.0 ( 0.5 g grams of fly ash as measured with * Corresponding author. Tel: (515) 294-3759. Fax (515) 294-3091. E-mail: [email protected]. † E-mail: [email protected]. (1) Annual Book of ASTM Standards Part 26; ASTM: Philadelphia, 1982; ASTM Standard No. d3174-82. (2) Brown, R. C.; Dykstra, J. Fuel 1995, 4, 570. (3) Waller, D. J.; Brown, R. C. Fuel 1996, 13, 1568.

an analytical balance. The sample was first placed in a clean crucible and dried at approximately 110 °C in an oven for about 2 h. The sample was removed from the oven and placed in a desiccator to cool for at least 60 min before being reweighed. The weight loss was recorded as the moisture content of the fly ash. Dried fly ash was then placed in an ashing furnace with an air atmosphere for 2 h at 750 °C. The fired sample was cooled to room temperature in a desiccator and then weighed. The weight loss associated with firing the sample is known as the loss-on-ignition (LOI), a quantity often assumed to be essentially the unburned carbon content of the original sample. TGA Methodology. Thermogravimetric evaluations were performed with a programmable Perkin-Elmer TGA-7. Fly ash samples were heated in an oven prior to TGA tests to remove moisture in the same manner as used in LOI tests. A 25 ( 5 mg sample of fly ash was loaded into the TGA and nitrogen admitted to the apparatus at a flow rate of 30 mL/min for approximately 30 min to purge the lines of oxygen and stabilize the apparatus. Heating of the sample in the nitrogen atmosphere commenced once the TGA readings were steady. The sample was heated from room temperature to 750 °C at a heating rate of 20 °C/min in this inert atmosphere to drive off volatile compounds (for example, water of hydration, carbon dioxide from calcination, or condensed hydrocarbons) present in the sample. Once 750 °C was reached, the temperature was held constant for about 30 min to make sure no further weight loss occurred. If necessary, the isothermal period was extended an additional 40 min to achieve steady weight readings before proceeding to the next stage. This extension was performed for fly ashes AM 40, AM 41, AM 51, AM 68, and AM 77). At this point, the flow of nitrogen was replaced by airflow of 30 mL/min, which oxidized solid carbon (char) in the fly ash to carbon dioxide. The test was terminated when the weight loss curve became level. A typical TGA weight loss curve for fly ash is shown in Figure 1. About 0.5% weight loss occurs as the sample is heated to 500 °C, which may be the result of reabsorbed moisture in the sample or instrument drift (which would only be about 0.02% per min). At 500 °C a more rapid drop produces a 2% loss in sample weight, which represents volatile matter released from the sample. When air is finally admitted to the

10.1021/ef0100496 CCC: $20.00 © 2001 American Chemical Society Published on Web 09/19/2001

Measuring Unburned Carbon in Coal Fly Ash

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Figure 1. TGA weight loss curve of a typical fly ash sample. sample, a precipitous drop occurs due to oxidation of solid carbon, which in this case amounts to 12% of the original sample weight. We define total loss (TL) as the total change in weight during the TGA test (14.5% in this instance). Unburned carbon (UC) is defined as the weight loss after air is admitted to the TGA (12% in this instance). Evaluation of Volatile Organic Compounds. We require a qualitative indicator of volatile organic compounds (VOC) in fly ash. Our experience suggests that, when present in fly ash, much of this material is aromatic in nature. Accordingly, we employed benzene as a solvent to extract VOCs from fly ash. For this test, 0.2 g of 22342AT, AM61, 22368AT, or AM41 as-received fly ash was mixed with 10 mL of benzene in a capped 25 mL flask and heated in an oven to 60 °C for about 10 min. The flask was allowed to cool for 30 min. Two phases were evident in the flask: a liquid phase at the top and a solid phase at the bottom. The liquid phase was a mixture of benzene and dissolved VOCs, which tinted the liquid black, while the solid phase was mineral matter and char from the fly ash. The contents of the flask were poured through filter paper and the color of the liquid phase compared to pure benzene as an indicator of VOC content. We also desired a more direct test of the hypothesis that volatile gases released during thermogravimetric analysis were organic compounds. To this end, we directed exhaust gases from the TGA to a beaker where it was bubbled through 100 mL of water. If the volatile gases released during heating of fly ash under an inert atmosphere were carbon dioxide from calcination of mineral matter or water from dehydration, then no appreciable change in color was expected in the beaker of water. However, if the released gases were aromatic hydrocarbons, then a black, oily residue might be expected to appear in the water. For each fly ash evaluated in this manner, exhaust gases from TGA tests were bubbled through the beaker for sixteen minutes until the flow of nitrogen was replaced by airflow at 750 °C during the TGA test to accumulate VOCs for visual inspection. It was expected that the color of the water would be proportional to the volatile content of the fly ash because equal quantities of fly ash and water were used in each TGA test.

Results and Discussion Seventy fly ash samples were collected from different boilers operating in the United States, Canada, China, and Australia. Loss-on-ignition (LOI) and TGA evaluations were performed on each fly ash. The results are given in Table 1. On the basis of the definitions presented, we expected the total loss of weight (TL) during a TGA test to correspond to LOI. Also, based on our previous work, we expected a poor correlation between LOI and unburned carbon (UC) obtained from the TGA tests.

Figure 2. Comparison of TL based on TGA methodology and LOI based on ASTM methodology.

Figure 2 plots LOI vs TL for all seventy fly ashes. The correlation is good, confirming that LOI and TL are equivalent measures. Total loss, in general, reads slightly higher than LOI. In some cases, disagreement between LOI and TL may result from absorption of moisture by hydroscopic fly ashes before the TGA evaluation could be performed. For example, Figure 1 probably represents such an instance, with a 3% error in TL arising from moisture released early during the heating process (at temperatures well below 400 °C). On the other hand, the correlation between LOI and UC is not as good as that between LOI and TL for most fly ashes, as illustrated in Figure 3. Loss-on-ignition consistently overestimates the actual quantity of unburned carbon in fly ash. The relative error of using LOI to estimate unburned carbon in fly ash was calculated with the following expression:

relative error )

LOI - UC × 100% UC

(1)

The results of these calculations are presented in Table 1. Only 30% of the 70 fly ash samples had LOI values within 10% of the unburned carbon values as measured by TGA. Furthermore, 17% of the samples had relative errors exceeding 100%. In a previous study,2 we found that such large errors were common for fly ashes obtained from coals with high intrinsic calcium carbonate or from fluidized bed boilers that used calcium carbonate as sulfur sorbent. In these cases, weight loss during heating in an inert atmosphere resulted from conversion of calcium carbonate to calcium oxide. However, the present collection of fly ashes did not include any obtained from fluidized beds and many of the errors were too large to be attributed to intrinsic calcium content of the parent coal. We hypothesized that large relative errors in LOI measurements were the result of volatile organic compounds in the fly ash. We formulated this hypothesis from visual inspection of fly ashes that had large relative errors: even fly ash of low carbon content was relatively dark in appearance and some of these fly ashes had a slightly oily consistency. Solvent extraction tests were performed on four fly ashes representing increasing volatile content (defined as the wt-% difference between LOI and UC measure-

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Fan and Brown

Table 1. Results of “Unburned Carbon” Determination by Various Measures indicators

sample number

sample source

LOI (%)

TL (%)

UC (%)

relative error of LOI (%)

GCA4 GCA5 GCA13 GCA26 GCA27 32AT AM36 AM37 AM38 AM39 AM40 AM41 AM43 AM44 AM45 AM46 AM47 AM48 AM49 AM50 AM51 AM52 AM53 AM55 AM56 AM57 AM58 AM59 AM61 AM62 AM63 AM64 AM65 AM66 AM67 AM68 AM70 AM71 AM72 AM73 AM75 AM77 AM78 21839AT 22001AT 21825AT 21832AT 21837AT 21846AT 21960AT 21964AT 21996AT 22368AT 22288AT 22343AT 22462AT 22473AT 22499AT 22332AT 22336AT 22339AT 22342AT 22345AT 22348AT 22352AT 22356AT 22360AT 22368AT 22372AT 22518AT

Yaomeng/Pingdingshan, China Yaomeng/Pingdingshan, China Yaomeng/Pingdingshan, China Stanwell/Queensland, Australia Stanwell/Queensland, Australia Scrubgrass/ Kennerdell, PA Titus Station /GPU Genco, PA Sikeston Power Station, MO Hennepin Station, IL Streeter/Cedar Falls Utilities, IA Pell-Electric Department, IA Pell-Electric Department, IA Fort Drum Cogeneration Fort Drum Cogeneration Fort Drum Cogeneration Fort Drum Cogeneration Fort Drum Cogeneration Wisconsin Public Service, WI Unit 1/Payette Power Plant, TX Unit1 &2/Chalk Point Units, MD Texas-New Mexico Power, TX Centralia Plant /Pacificorp, WA Centralia Plant/ Pacificorp Dunkirk Steam Station, NY Dunkirk Steam Station, NY Dunkirk Steam Station, NY Four Covners/Fruitland, NM Dunkirk Steam Station, NY Chamois Plant, MO Brandon Gen. Station, Canada Muscatine Power & Water, IA Elmer Smith Station, KY Sundonce Plant, Canada Sundonce Plant, Canada Unknown North Valmy Station, NV UNC-CH Cogen. Facility, NC UNC-CH Cogen. Facility, NC J. H. Campbell Unit #2, MI J. H. Campbell Unit #3, MI St. Joseph Light Plant, MO Lee Station/ Pelzer, SC Pht. Scherer, GA Duquesne/Elrama, 4B PA Duquesne/Elrama 3B, PA Duquesne/Elrama 2A, PA Duquesne/Elrama 3B, PA Duquesne/Elrama 3B, PA Duquesne/Elrama 4B, PA Duquesne/Elrama 3B, PA Duquesne/Elrama 3B, PA Duquesne/Elrama 3B, PA Duquesne/Elrama 3B PA Duquesne/Elrama 2A, PA Duquesne/Elrama 2A, PA Duquesne/Elrama 2A, PA Duquesne/Elrama 2A, PA Duquesne/Elrama 2A, PA Duquesne/Elrama 3B, PA Duquesne/Elrama 3B, PA Duquesne/Elrama 3B, PA Duquesne/Elrama 3B, PA Duquesne/Elrama 3B, PA Duquesne/Elrama 3B, PA Duquesne/Elrama 3B, PA Duquesne/Elrama 3B, PA Duquesne/Elrama 3B, PA Duquesne/Elrama 3B, PA Duquesne/Elrama 3B, PA Duquesne/Elrama 3B, PA

2.42 13.82 5.90 11.40 4.95 10.50 13.70 0.30 4.70 3.03 8.59 8.50 14.67 14.54 10.63 2.00 6.46 0.35 0.42 5.32 1.57 22.42 0.10 1.60 3.76 7.50 1.72 0.44 18.02 0.54 0.15 1.05 0.52 0.66 0.23 1.60 3.83 13.78 2.32 5.68 22.56 18.91 1.95 6.20 8.01 0.10 9.98 11.70 14.00 18.22 8.93 14.67 7.01 13.67 15.00 1.83 10.50 2.10 3.01 17.00 10.70 14.70 14.4 13.50 7.10 7.20 7.30 3.63 8.02 2.60

3.16 18.33 9.48 11.68 5.00 11.40 14.36 0.52 4.74 3.52 9.67 9.39 15.99 14.82 11.43 2.46 7.44 0.70 0.57 5.46 1.92 23.96 0.58 1.68 4.58 7.87 1.80 0.85 18.62 0.99 0.39 1.47 0.91 0.75 0.69 2.12 4.73 13.83 2.46 6.15 23.26 22.48 3.81 6.42 8.16 0.23 10.45 11.86 14.27 18.45 9.04 14.79 7.90 13.89 15.20 1.93 11.93 3.09 3.59 17.41 11.2 14.90 14.7 16.51 7.42 7.90 7.50 3.83 8.10 2.71

2.12 13.14 5.97 10.68 4.40 9.53 11.99 0.23 3.15 2.94 2.68 2.07 13.96 13.80 9.63 1.30 5.40 0.19 0.04 4.60 0.05 23.32 0.02 1.18 1.93 6.88 1.22 0.17 14.38 0.07 0.04 0.81 0.11 0.41 0.22 0.64 1.92 12.70 1.66 5.66 19.84 6.33 3.10 5.52 6.91 0.03 9.72 11.27 12.88 16.15 7.88 13.36 3.84 12.82 13.86 1.03 9.46 1.92 2.44 16.23 10.03 14.49 13.00 14.14 6.04 6.54 6.44 2.74 6.26 1.33

14.15 5.18 1.17 6.74 12.50 10.18 14.26 30.43 49.21 3.06 220.52 310.63 5.09 5.36 10.38 53.85 19.63 84.21 950.00 15.65 3040.00 -3.86 400.00 35.59 94.82 9.01 40.98 158.82 25.31 671.43 275.00 29.63 372.73 60.98 4.55 150.00 99.48 8.50 39.76 0.35 13.71 198.74 -37.10 12.32 15.92 233.33 2.67 3.82 8.7 12.82 13.32 9.81 82.55 6.63 8.23 77.67 10.99 9.38 23.36 4.74 6.68 1.45 10.77 -4.53 17.55 10.09 13.35 32.48 28.12 95.49

ments). The unburned carbon content ranged from 2.7 to 14.49 wt % while the volatile content (purported to be volatile organic compounds) ranged from 1.14 to 6.43

wt %. These four cases are detailed in Table 2. According to our hypothesis, solvent extraction should produce increasing coloration of the benzene solvent in going

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Energy & Fuels, Vol. 15, No. 6, 2001 1417

of aromatic hydrocarbons such as indene, coumarone, dicyclopentadiene, benzene, toluene, and xylene. Tar released during the pyrolysis stage of combustion is subsequently oxidized to carbon dioxide and water under conditions of excess oxygen, high temperature, and turbulent gas flow. However, a poorly operated boiler may contain regions that do not meet these conditions and tar vapors may escape the furnace section of the boiler. As the flue gas cools, the tar vapor may condense, with fly ash particles, especially porous char, serving as nucleation sites. Thus, a poorly operated boiler may produce fly ash containing large amounts of volatile organic compounds relative to the unburned carbon (char) and indicate high LOI and low UC. Conclusion Figure 3. Comparison of UC based on TGA methodology and LOI based on ASTM methodology. Table 2. Results of Solvent Washing of Selected Fly Ashes sample number

UC (wt %)

volatile content (wt %)

solvent color after washing

22343AT AM61 22368AT AM41

14.49 14.38 3.84 2.7

1.14 3.64 4.06 6.43

clear tinted black tinted black very dark

from the lowest volatile content fly ash (22343AT) to the highest volatile content fly ash (AM41). Indeed, this simple test yielded a virtually clear solvent for fly ash 22343AT, a darkly colored solvent for fly ash AM41, and an intermediate coloration for the two fly ashes of intermediate volatile content. These results support the hypothesis that VOCs can interfere with LOI evaluations. The four fly ashes described in the previous paragraph were further evaluated in TGA tests by bubbling exhaust gases through water. The test results were consistent with our hypothesis about volatiles in fly ash. The AM41 fly ash released the highest quantity of vapors upon heating in an inert atmosphere, which condensed in the beaker of water as a dark, sticky substance. On the other hand, the 22343AT fly ash released the smallest amount of gas, which did not visibly condense in the beaker of water. The presence of VOCs in fly ash, we suspect, is the result of incomplete combustion. The initial stage of combustion consists of pyrolysis, a process that yields carbonaceous residue (char), low molecular weight gases, chemically produced water, and tar, the latter being defined as all compounds other than water that are liquid at room temperature.4 The amount of tar released from pyrolyzing coal is known to be large, representing 38-80% of the total volatile yield. Tar yields at first increase with increasing temperature but decrease above 600 °C where thermal cracking converts tar to light gases and char.5 Tar is characterized as a dark brown to black, fairly mobile liquid, with characteristic unpleasant smell.6-8 It is composed of a variety (4) Howard, J. B. Chemistry of Coal Utilization, Second Supplementary Volume; Elliott, M. A., Ed.; John Wiley & Sons: New York, 1981; p 701. (5) Peters, W.; Bertling, H. Fuel 1965, 44, 317.

We discovered that a significant fraction of the 70 fly ashes evaluated in our tests contained volatile organic compounds. Volatile organic compounds contribute to the LOI for fly ashes containing them, but are not an accurate representation of the unburned carbon content. This discovery raises two questions relevant to operation of coal-fired power plants. The first question is related to combustion efficiency. Traditionally, LOI has been used as a proxy for unburned carbon in calculating mass balances and combustion losses for boilers. Clearly, VOCs contribute to combustion losses but they are not equivalent to unburned carbon losses. The second question is related to disposal of combustion residues at coal-fired power plants. Many utilities market fly ash as a concrete admixture. For this application, the maximum amount of unburned carbon in the fly ash must be carefully controlled to obtain a satisfactory concrete product. Again, LOI has served as proxy for unburned carbon in this determination. Our work shows that LOI grossly overestimates unburned carbon for fly ashes with significant quantities of VOC. Thus, some utilities may be inadvertently losing markets for their fly ash by relying on LOI measurements. However, our work does not address the effect VOCs may have on the suitability of fly ash as concrete admixtures. Since LOI overestimated unburned carbon by at least 20% in 44% of the fly ashes tested, we recommend an alternative to LOI be employed for the purpose of measuring unburned carbon. The TGA methodology presented here is suitable for this determination. Acknowledgment. Iowa State University Research Foundation funded this research. We appreciate the assistance of Mr. Mark Coppler, Dr. Bob Novack, Mr. Jeff Winter, and Mr. Dennis Hungerman at Ametek Corporation in obtaining many of the fly ash samples. Lee Girard performed some of the thermogravimetric analyses for us. EF0100496 (6) McNeil, D. Chemistry of Coal Utilization, Second Supplementary Volume; Elliott, M. A., Ed.; John Wiley & Sons: New York, 1981; p 1005. (7) Smith, K. L.; Smoot, L. D.; Fletcher, T. H.; Pugmire, R. J. Structure and Reaction Processes of Coal; Plenum Press: New York, 1994; pp 210-213. (8) Ma, J.; Fletcher, T. H.; Webb, B. W. Conversion of Coal Tar to Soot During Coal Pyrolysis in a Post-Flame Environment. Twentysixth Symposium (International) on Combustion, Pittsburgh, PA; The Combustion Institute: Pittsburgh, 1996; pp 3161-3167.