Article pubs.acs.org/EF
Sulfur Capture by Fly Ash in Air and Oxy-fuel Pulverized Fuel Combustion Lawrence P. Belo,† Reinhold Spörl,‡ Kalpit V. Shah,† Liza K. Elliott,† Rohan J. Stanger,† Jörg Maier,‡ and Terry F. Wall*,† †
Chemical Engineering, University of Newcastle, Callaghan, New South Wales 2308, Australia Institute of Combustion and Power Plant Technology (IFK), University of Stuttgart, 70569 Stuttgart, Germany
‡
ABSTRACT: Ash produced during oxy-fuel combustion is expected to differ from ash produced during air combustion because of the higher CO2 and SO2 atmospheres in which it is generated. For a quantitative understanding of the sulfation behavior of fly ash in oxy-fuel combustion, fly ash from three commercial Australian sub-bituminous coals was tested and decomposed under an inert atmosphere. Thermal evolved gas analysis was completed for ash produced in both air and oxy-fuel environments. Pure salts were also tested under the same conditions to allow for identification of the species in the ash that capture sulfur, along with thermodynamic modeling using FactSage 6.3. Sulfur evolved during the decomposition of air and oxy-fuel fly ash was compared to the total sulfur in the ash to close the sulfur balance. Both total sulfur captured by the ash and sulfur evolved during decomposition were higher for oxy-fuel fly ash than their air counterparts. Correlations of capture with ash chemistry are presented.
1. INTRODUCTION In today’s world, fossil fuel continues to be the major source of energy, as reported by the International Energy Agency, with 82% of the world’s energy mix as of 2011.1 Coal, being the most abundant and cheapest source of energy compared to other fossil fuels (i.e., natural gas and oil), has always been the principal candidate for power plants. Apart from being mainly carbon, which contributes CO2 to the atmosphere, coal also consists of several impurities, such as nitrogen and sulfur, which when oxidized are partially released in the atmosphere as NOx and SOx. The SOx and NOx emissions cause health and environmental concerns.2,3 Because there is now a well-defined relationship between the world’s energy use and the increase of CO2 in the atmosphere, several strategies and technologies are being developed to reduce the emissions of this greenhouse gas. Oxy-fuel combustion is one of the CO2 capture and storage (CCS) technologies available for power plants2,4−8 to reduce CO2 emissions. During oxy-fuel combustion, coal is burned in a mixture of O2 and recirculated flue gas (RFG), as opposed to air. This minimizes N2 in the system, thus increasing the CO2 concentration to acceptable purity for compression, transport, and storage.9 However, the concentrations of impurities, such as SOx, NOx, and Hg in the raw wet flue gas from oxy-fuel combustion are at least 3−4 times higher than in conventional air combustion because of recycling of impurities back to the boiler.4,6,7,10,11 The higher concentration of such impurities creates several operational problems, as described elsewhere.12 The current paper focuses on understanding the sulfur transformations in a flue gas, followed by its capture in fly ash during air and oxy-fuel combustion. Figure 1 shows the reaction routes of sulfur in a combustion system as presented in the existing literature.5,12−14 It can be seen that sulfur undergoes several chemical transformations during combustion and along the flue gas path where initially high SOx, primarily SO2, is © 2014 American Chemical Society
formed from the decomposition and oxidation of pyrite (FeS2), sulfates, and other organic sulfur associated in the coal matrix. Furthermore, SO3 is formed from SO2 in a homogeneous gasphase reaction or a heterogeneous, solids catalytic reaction.15 SO3 formation during combustion generally depends upon numerous factors, such as sulfur content of coal (affecting the SO2 partial pressure), oxygen partial pressure, content of catalytically active compounds in the ash (e.g., Fe2O3), and temperature−residence time profile of the plant.12,15,16 The alkali and alkaline earth metal compounds in the ash are known to capture SO2 and SO3 by forming sulfates.6,17,18 Moreover, at temperatures below ∼400 °C, SO3 and water vapor starts to form H 2 SO 4 and reaches complete transformation at approximately 200 °C.16,19 The dew point of H2SO4 depends upon the concentrations of H2O and SO3/H2SO4. It is also reported in the literature that SO3/H2SO4 from flue gas can be adsorbed or condensed on fly ash surfaces at temperatures near or below the sulfuric acid dew point (ADP) temperature.19,20 The effect of SO2 in oxy-fuel has been reviewed by Stanger and Wall.11 Early SO2 capture work in oxy-fuel combustion by Liu et al.21 showed that high SO2 increased the temperature at which SO2 capture began. Furthermore, the higher CO2 concentration also provided potential ash carbonation and a direct sulfation from carbonate to sulfate. Work at the University of Stuttgart4 showed that the SO2 concentration changed over the convective section. It can be stated that, because of the considerable differences in the SO2 and O2 partial pressures in flue gas between air and oxy-fuel combustion, the formation of SO3 can be altered. This can also be supported from the literature, where SO2/SO3 conversion extents between 1 and 5%12 with SO3 concenReceived: April 17, 2014 Revised: July 14, 2014 Published: July 14, 2014 5472
dx.doi.org/10.1021/ef500855w | Energy Fuels 2014, 28, 5472−5479
Energy & Fuels
Article
Figure 1. Reaction routes of sulfur in a combustion system.
Table 1. Proximate and Elemental Analyses of the Coals Used To Obtain the Fly Ash Samples in the Experimenta coal
NCV (kJ/kg)
W (%, ad)
A (%, db)
V (%, daf)
FC (%, daf)
C (%, daf)
H (%, daf)
N (%, daf)
S (%, daf)
Ob (%, daf)
Hg (μg/kg, daf)
A B C
18026 24956 26748
3.9 1.5 3.7
32.5 23.0 9.8
35.9 50.6 35.9
64.1 49.4 64.1
73.8 78.3 77.2
4.3 6.7 5.2
1.1 1.1 2.0
0.3 0.7 0.7
20.5 13.2 15.0
66.4 41.5 22.2
NCV, net calorific value; W, water; A, ash; FC, fixed carbon; C, carbon; H, hydrogen; N, nitrogen; S, sulfur; O, oxygen; Hg, mercury; ad, air-dried; db, dry basis; and daf, dry and ash-free basis. bCalculated by difference.
a
trations up to about 40 ppm in air-fired facilities and over 180 ppm in oxy-fuel-fired facilities were observed.4,7,12 Moreover, reduction in the gas volume, change in the combustion environment, and increase in SO2 and SO3 concentrations in the case of oxy-fuel combustion are expected to alter the extent of sulfation of alkali and alkaline earth metals in fly ash as well as adsorption/condensation dynamics of SO3/H2SO4 by fly ash in the bag filter. Therefore, the objective of this study was to evaluate the difference in sulfur captured by fly ash (FA) obtained during air firing, termed as air in this study. Practical oxy-fuel combustion with partial flue gas cleaning was termed here as oxy.
2. EXPERIMENTAL SECTION The characteristics of the three Australian sub-bituminous coals4 used in the air combustion (air) and oxy-fuel (oxy) are presented in Table 1. 2.1. Fly Ash Samples. Ash samples were obtained from a joint Australian−German study evaluating coal behavior in oxy-fuel. The 20 kWth combustion rig located at the Institute of Combustion and Power Plant Technology (IFK), University of Stuttgart, Germany (Figure 2), is capable of combustion investigations with 0.5−3 kg of pulverized fuel/h and is highly flexible for feeding of oxidant gases, such as air or mixtures of O2, CO2, H2O, and trace gases (e.g., NO, SO2, and Hg), to evaluate air- and oxy-fuel-firing conditions.4 The rig was operated for this study at a wall temperature of 1350 °C, with a constant product rate of about 11.5 m3 [standard temperature and pressure (STP)]/h to maintain comparable gas residence times for the different modes of firing, i.e., air combustion and oxy-fuel combustion.4 During the air combustion mode, the burner was fed with cleaned air, with a mix of 28% O2 and balance CO2 corresponding to the pilot-scale tests performed in 2006 by Ishikawajima-Harima Heavy Industries (IHI)10,22 and based on the matched radiative heat transfer with air firing. Impurities NOx, SO2, Hg0, and H2O were introduced to simulate the practical oxy-fuel combustion with partial flue gas cleaning conditions (with simulated removal of nominal 20% H2O, 20% SO2, and 50% Hgtot from flue gas based on theoretical maximum conversion4), referred to in this paper as “oxy” for convenience (Table 2). The practical case was based on the need to cool the primary recycle lies to prevent condensation of H2O in the coal mill.
Figure 2. Schematic diagram of the 20 kWth experimental rig used for air and oxy-fuel investigations at IFK, University of Stuttgart, Germany.4
Table 2. SO2 Concentrations at the Oxidant and End of the Furnace Entering the Bag Filtera SO2 in the oxidant (ppm, dry)
SO2 in flue gas (ppm, dry)
coal sample
air
oxy
air
oxy
A B C
0 0 0
824 1569 1723
199 367 444
1235 2578 2802
SO2 concentrations in oxy flue gas are 4−5 times higher than those in air firing because of the simulated recycled SO2 in the oxidant. a
Flue gas O2 was maintained at 3% for all test runs. Fly ash was sampled from the bag filter (marked in Figure 2), which was maintained at an inlet temperature of 225 ± 30 °C and outlet temperature of 195 ± 15 °C. Table 2 shows the SO2 concentrations to 5473
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Table 3. XRF and Percent C Analysis of the Fly Ash Samples Used in the Experiments fly ash sample A
B
C
%, dry basis
air
oxy
air
oxy
air
oxy
SiO2 Al2O3 Fe2O3 CaO MgO Na2O K2O TiO2 MnO2 P2O5 SO3 BaO SrO total percent carbon (unburned)
55.2 33.3 6.55 0.95 0.741 0.144 0.512 2.06 0.097 0.178 0.132 0.042 0.049 100 Al2O3, followed by Fe2O3; however, it can be observed that, in comparison to fly ashes A and C, fly ash B has a relatively low Fe2O3 content. CaO, MgO, TiO2, and MnO2 are present in small fractions for fly ashes A and B; however, fly ash C has higher CaO. Panels a−c of Figure 5 show the AAEMs composition from the XRF of the bulk ash. Calcium and magnesium are known to be very active species that capture SO2 in power plants; they play a significant role in the sulfur capture and retention in the ash. Furthermore, it has been stated that, among other AAEMs, calcium is the most effective species at capturing sulfur after deposition onto heat5476
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transfer surfaces in the cooler regions of the combustion system, e.g., economizer.6,12,17 It can however be noted that the XRF results across all three fly ash samples are consistent between air and oxy runs and that no significant differences were observed. It could be seen that fly ash C has higher SO3, about 1.2 mol %, compared to both A and B, which have values of approximately 0.2 mol %. Then again, this may be justified by the fact that fly ash C contains higher amounts of alkaline oxides, i.e., CaO and MgO, which are essential in sulfur capture.12,28,31 In Figure 5c, fly ash C shows higher CaO and MgO contents, 8 and 4 mol %, respectively, while A and B similarly contain approximately 2 mol % CaO and 1.8 mol % MgO. 3.3. Sulfur Release from Heating Fly Ash. Fly ash decomposition experiments were performed to decompose the sulfur-containing species, which may evolve upon heating the fly ash and provide a measure of identification from ambient temperatures up to 1400 °C. In Figure 6, it can be noted that, for all fly ash samples used, changing from samples from air to oxy has increased the amount of sulfur species [as parts per million (ppm) of SO2 in N2] evolved during the decomposition. The light, dotted lines in panels a−c of Figure 6 show air-firing-derived fly ash, while the solid lines represent the fly ash derived from oxy-fuel firing (oxy). Five main points that are noteworthy can be deduced from this plot. (1) The evolution of sulfur species was found to be aligned when the plots were drawn against one another, indicating that similar sulfur species evolve at similar temperatures from different samples with only a slight shifting of the evolution temperature. (2) Oxy fly ash SO2 release is 2−3 times greater compared to air fly ash, upon integration of the area under the curve. This finding is significant because it follows claims of other researchers that, during oxy-fuel combustion with flue gas recycling, SO2 and other impurities were found to be 3−4 times greater than in air, resulting in more sulfur retention by ash.6 The difference between the areas of oxy and air is shaded in panels a−c of Figure 6. (3) Between 400 and 800 °C, a wide primary peak of sulfur release with a smaller shoulder peak is observed from all fly ash samples (enlarged image in Figure 6a). (4) Between 800 and 1100 °C, a strong secondary peak with a shoulder peak can be observed, especially in samples B and C. These peaks are quite significant in all oxy samples, indicating that, because of its higher flue gas concentrations, an improved sulfur capture mechanism might be involved. In the air fly ash samples, however, the secondary peaks was only strongly visible with sample C. (5) It can be noted that a third set of peaks, occurring roughly at temperatures higher than 1300 °C could be observed from all fly ash samples for both air and oxy-fuel and evolved roughly at the same concentration level. This may indicate that, during the sintering of the fly ash, some high-temperature sulfur species, possibly associated with slag particles, are still evolved. 3.3.1. Peak Identification. To be able to identify the active species capturing sulfur in the fly ash, pure salts of the AAEMs (i.e., CaSO4, MgSO4, Na2SO4, and K2SO4) and other metal sulfates [Al2(SO4)3 and Fe2(SO4)3] were thermally decomposed. These decomposition temperatures from experiments were then compared to FactSage 6.3 model (Table 5). In the pure salt decomposition, the same conditions to the fly ash decomposition tests were employed. For the FactSage 6.3 model, the conditions used were [SO2] = 100−500 ppm, N2 balance, and alkaline salts calculated from XRF data (Table 3). A sample decomposition of CaSO4 is presented in Figure 7,
Figure 7. Decomposition of CaSO4 under 1.5 L/min N2 and 5 °C/ min heating rate.
showing the actual thermal decomposition of the pure salt and the cumulative decomposition (as percent total sulfur released) versus the sample temperature used to obtain the decomposition temperatures in Table 4. Thermal decomposition values obtained from FactSage 6.3 model and SI Chemical Data32 were used to guide the pure salt decomposition experiments; the model shows the initial decomposition temperature of the metal sulfates. The values in Table 4 suggest that the initial peaks between 400 and 800 °C may be a combination of iron(III) sulfate [Fe2(SO4)3] and aluminum sulfate [Al2(SO4)3]. The secondary peaks between 800 and 1100 °C may be a combination of magnesium sulfate (MgSO4) and potassium sulfate (K2SO4). The third peak, which occurs at temperatures greater than 1300 °C, may well be a combination of calcium sulfate (CaSO4) and sodium sulfate (Na2SO4). Although in the pure salt decomposition and the thermodynamic modeling, all of the Na, Ca, and K salts are decomposed well before 1300 °C, it could be that, during fly ash experiments, these sulfur species may have been encapsulated in the sintered slag, needing a longer time period for release. Preliminary experiments using varying heating rates showed no difference in the decomposition temperatures; however, higher temperature shifts were observed at higher heating rates similar to the rates in the literature.33 Fly ash C was also observed to have a lower sintering/melting temperature based on the experiments performed (1300 °C). These peaks from ash decomposition were consistent with thermodynamic predictions. Oxy fly ash showed consistently higher amounts of SO2 capture in the second set of peaks. The Eschka method was used for total ash sulfur determination. The amount of decomposable sulfur evolved that was released upon heating was found to vary from 38 to 83% of the ash sulfur, whereas the Eschka sulfur for oxy fly ash is only 17−23% higher than the air fly ash.
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[email protected]. Notes
The authors declare no competing financial interest.
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ACKNOWLEDGMENTS The authors acknowledge Xstrata Coal for the funding of the research project and IFK, University of Stuttgart, Germany, for the collaborative research initiative. 5479
dx.doi.org/10.1021/ef500855w | Energy Fuels 2014, 28, 5472−5479
