Emissions of So 2, No X, Co 2, and HCL From Co-Firing of Coals With Raw and Torrefied Biomass Fuels [PDF]

Citation preview

See discussions, stats, and author profiles for this publication at: https://www.researchgate.net/publication/320383217



Emissions of SO 2, NO x, CO 2, and HCl from Co-firing of coals with raw and torrefied biomass fuels Article  in  Fuel · January 2018 DOI: 10.1016/j.fuel.2017.09.049



CITATIONS



READS



16



433



4 authors, including: Emad Rokni



Xiaohan Ren



Northeastern University



Shandong University



21 PUBLICATIONS   139 CITATIONS   



27 PUBLICATIONS   175 CITATIONS   



SEE PROFILE



Yiannis Levendis Northeastern University 220 PUBLICATIONS   3,569 CITATIONS    SEE PROFILE



Some of the authors of this publication are also working on these related projects:



Combustion View project



Assessment of blends of Hydrocarbon/CO2 as alternative natural refrigerants View project



All content following this page was uploaded by Aidin Panahi on 13 October 2017. The user has requested enhancement of the downloaded file.



SEE PROFILE



Fuel 211 (2018) 363–374



Contents lists available at ScienceDirect



Fuel journal homepage: www.elsevier.com/locate/fuel



Full Length Article



Emissions of SO2, NOx, CO2, and HCl from Co-firing of coals with raw and torrefied biomass fuels ⁎



Emad Roknia, Xiaohan Renb,c, , Aidin Panahia, Yiannis A. Levendisa, a b c



MARK



⁎



Mechanical and Industrial Engineering Department, Northeastern University, Boston, MA 02115, USA Institute of Thermal Science and Technology, Shandong University, Jinan 250061, China School of Energy Science and Engineering, Harbin Institute of Technology, Harbin 150001, China



A R T I C L E I N F O



A B S T R A C T



Keywords: Coal-biomass blends Raw and torrefied biomass Pollutant emissions SO2 NOx CO2 HCl



This work examined acid gas emissions of sulfur dioxide, nitrogen oxide, carbon dioxide, and hydrogen chloride from co-firing biomass (corn straw and rice husk) with either a high-sulfur bituminous coal or a low-sulfur subbituminous coal. Pulverized neat coals, neat biomass, either raw or torrefied, and 50–50 wt% blends thereof were introduced to a laboratory-scale electrically-heated drop-tube furnace (DTF), operated at a gas temperature of 1350 K, and experienced high heating rates. Emissions from the combustion of the fuels in air were measured at the furnace effluent. Coal particles were in the range of 75–90 µm and biomass particles in the range of 90–150 µm. Results revealed that blending of both coals with raw and torrefied biomass drastically reduced the coal’s SO2 and NOx emission yields to values that were below those predicted by linear interpolation of the corresponding emission yields of the two neat fuels. The SO2 emission yields from torrefied biomass were lower than those of their raw biomass precursors due to their lower sulfur contents. Similarly to the emission yields, the SO2 emission factors (based on the energy content of each sample) from the blends of coal with torrefied biomass were also lower than the blends of coal with raw biomass. NOx emission yields from neat torrefied biomass were mildly higher than those from raw biomass, as the latter had higher nitrogen content per unit mass. There was no discernible trend in NOx emissions from the blends based on their nitrogen contents. HCl emission from torrefied corn straw was lower than that from its raw precursor, as the former had a lower chlorine content. The HCl emission yields from the blends of corn straw with coal were much higher than those from neat coal combustion. Finally, the HCl emission yield from blends of the high-sulfur coal with corn straw were higher than those from the blends of the same biomass with the low-sulfur coal.



1. Introduction 1.1. Bioenergy harvested from co-firing biomass with coal Concerns about the environmental impact from using fossil fuels in electricity generation have promoted the use of alternative renewable sources of energy, such as solar, wind and biomass. Biomass is one of the oldest sources of energy; it is derived from organic matter such as agricultural crops, forest harvest residues, seaweed, herbaceous materials, and organic wastes. A reasonable option for biomass utilization is co-firing with coal in conventional coal-fired boilers’ as such infrastructure is already available and it only requires limited modifications [1]. In recent years, bioenergy accounted for 10% (51 EJ) of the total global energy supply which value was greater than any other renewable source of energy [2]. About 50% of the total bioenergy was derived from traditional use of biomass in wood stoves in developing countries,



⁎



and 12% was derived in biomass-based electricity generation systems [2]. Co-firing biomass with coal can be an economic option in power generation, and its overall cost depends on the availability and the proximity of the biomass feedstock to the power plant. Capital and operational costs of co-firing are significantly lower than the cost of neat biomass-fired power plants [3]. 1.2. Environmental aspects of co-firing biomass and coal 1.2.1. Greenhouse gases emissions Biomass may be considered as a nearly CO2-neutral fuel [4] as there are still emissions related to its harvesting, transportation, pre-treatment etc. Moreover, burning biomass prevents release of methane (CH4) from decaying residues, which is important given that CH4 has a 21 times higher global warming potential (GWP) than CO2 [5]. In addition, the alkaline ashes of biomass may capture some of the CO2 gases



Corresponding authors. E-mail addresses: [email protected] (X. Ren), [email protected] (Y.A. Levendis).



http://dx.doi.org/10.1016/j.fuel.2017.09.049 Received 7 June 2017; Received in revised form 1 September 2017; Accepted 13 September 2017 0016-2361/ © 2017 Elsevier Ltd. All rights reserved.



Fuel 211 (2018) 363–374



E. Rokni et al.



from the combustion event [5]. As storing biomass wastes also causes anaerobic release of NH3, H2S, volatile organic acids, and other chemicals, combusting the biomass helps prevent such emissions, which has been reported by other researchers [6–29].



firing high-sulfur fuels with biomass can curtail the amount of KCl produced [60,61]. It should be mentioned that decreasing the amount of KCl can increase the concentration of HCl, as it is the product of chlorine sulfation reactions [60,61].



1.2.2. SO2 and NOx Emissions Most biomass fuels contain little sulfur; therefore, their co-firing with coal typically results in lower SO2 emissions [30]. NOx emissions arise from atmospheric nitrogen and from fuel-bound nitrogen, which is released during both the devolatilization and the char oxidation phases. Volatile matter release from biomass combustion is higher than that from coal, and during this phase volatilized tars shuttle fuel nitrogen to the volatile matter flame [31]. Therein biomass-bound nitrogen forms mostly NH3, rather than HCN which is typically formed by coal-bound nitrogen, and this could help prevent the eventual formation of NOx in flames [27–29,32]. A previous study on co-firing coal and rice husk [33] reported that keeping the amount of coal the same and increasing the amount of biomass in the blends decreased the NO emissions but slightly increased the SO2 emissions. The reduction in NO was attributed to the lower terminal velocities of the rice husk particles than those of the coal particles, due to their density difference [34]. This caused the rice husk particles to burn earlier and to release volatile gases, which reduced the amount of NO from coal oxidation via the “reburning” mechanism [35,36]. Another study reported that co-firing a bituminous coal with 10–20% straw (on an energy basis) in a 250 MWe coal boiler resulted in a net decrease in SO2 and NOx emissions [37]. Therein, the lower sulfur content of the blended fuel and higher sulfur retention in the ash were the main causes of the lower SO2 emissions. Moreover, while the nitrogen content of that blended fuel was higher than the coal’s, a lower overall conversion of the fuel-N to NO was reported as the main reason for the lower NO emission [37]. Another study [7] of co-firing coal with 60 wt% bagasse, wood chips, sugarcane trash and coconut shell biomass also reported reductions of SO2, NOx and suspended particulate matter (SPM). Furthermore, cofiring a sub-bituminous coal with different types of biomass with variable nitrogen contents, such as wood chips, sugarcane bagasse, cotton stalk, and shea meal showed that their addition reduced the NOx emissions of the coal [38]. In these and other studies, co-firing was shown to have beneficial synergisms in reducing the emissions of SO2, NOx, and CO2 of coal [7,11,14,32,37,39–44]. Higher boiler efficiencies and fuel cost savings have also been reported [7,40,41]. However, comparative SO2 and NOx emissions from the combustion of coals blended both with raw biomass and with their torrefied biomass derivatives are hard to find in the literature, thus this investigation was undertaken to fill this gap.



1.3. Pre-treatment of biomass Biomass pre-treatments, such as pelletization and torrefaction, increase the energy density and improve transport and storage [62–65]. Torrefaction is a partial thermal decomposition of biomass that leaves a high-energy dense substance with smaller particle size and much less moisture [66]. Torrefaction improves the grindability of biomass and renders it suitable for co-firing with coal, as the torrefied biomass has similar properties to coal [67–70]. Torrefaction not only reduces SO2 and sometimes NOx emissions, but it also reduces the chlorine content of biomass [30,71]. For instance, it has been reported that torrefaction can reduce the chlorine content of biomass by 20–70% [71–76] and the sulfur content by 30–80% [30]. The release of chlorine inside low temperature torrefaction reactors is likely to be less problematic than inside high-temperature boilers. However, to implement torrefaction a significant investment is required, and to compensate for such investment large amounts of biomass feedstock need to be processed [1]. Whereas co-firing of coal and raw biomass has been studied extensively in the past and there have been reports on the gaseous emissions therefrom, little if any has been reported on the emissions from co-firing coal with torrefied biomass. This work aims to compare the gaseous emissions of carbon, sulfur and nitrogen oxides as well as hydrogen chloride acid gases from co-firing coal with biomass in both their raw and torrefied states. 2. Experimental procedure All solid fuels were burned in an electrically-heated, laminar-flow, alumina drop-tube furnace (DTF), manufactured by ATS. A schematic of the combustion setup is shown in Fig. 1. A water-cooled injector was used to introduce particles to the top of a 25 cm long and 3.5 cm in diameter heated zone section in the furnace. For combustion of streams of pulverized solid fuels, a bed of particles was placed in a vibrated glass vial (test-tube), which was advanced by a constant-velocity syringe-pump (Harvard Apparatus). Fuel particles were entrained in metered air, and entered a long capillary tubing (with 1.8 mm inner diameter), procured from McMaster. The tubing was vibrated to its natural frequency, by two vibrators (12 V 2000 RPM 0.05 A DC Mini Vibration Motor), to ensure an unimpeded flow of particles to the DTF through a water-cooled stainless steel furnace injector. Most experiments were conducted at a constant setting in the syringe pump - driven fuel feeder of this experimental setup, i.e., by feeding pulverized solid fuel beds at a constant volumetric flow rate. However, as the bulk bed densities of pulverized biomass and coal differed drastically, the mass flow rates also differed accordingly. Hence, additional experiments were performed where the mass feeding rates of the fuels were equalized. To achieve such analogy, the mass feeding rates of the blends were kept constant, while those of the coals were decreased mildly and those of biomass were increased significantly. Since corn straw performed erratically under such higher feeding rates, as it consists of needle-shape particles [30], results therefrom are not included in this manuscript, and only those of coals and rice husk, which consists of chunky particles [30] that fluidize well, are presented herein. Air was introduced to the hot zone of the DTF through both the particle injector and through a concentric annular space between the furnace injector and the alumina drop-tube. The furnace was sealed and the effluent gases and solids from the combustion of dilute clouds of particles in controlled atmospheres were monitored. Furnace wall temperatures, Twall, were continuously monitored by type-S thermocouples attached to the wall. The gas temperature along the centerline of the radiation zone of the furnace was measured to be ∼50 K lower than the tube wall temperature,



1.2.3. HCl emissions Like SO2 and NOx, hydrogen chloride (HCl) not only can contribute to corrosion inside a boiler, but it can also contribute to acid rain [45]. Fuel-bound chlorine can be released as HCl, Cl2, or alkali chlorides mainly potassium chloride (KCl), sodium chloride (NaCl), and calcium chloride (CaCl2) [46–48]. Previous studies [49–51] showed that HCl and particulate chlorine are the dominant products in the combustion effluents of biomass. To alleviate boiler deposition and corrosion, possible solutions include lowering the share of biomass in the fuel blend, using low chlorine and low alkali content biomass, injecting sorbents (such as limestone) in the furnace and pre-treating the fuel [52–59]. As will be shown later in the manuscript, this work demonstrated that cofiring coal with torrefied biomass is an additional (partial) solution to the aforementioned boiler issues. Aho and Ferrer [54] reported on the positive effects of alumino-silicates and sulfur in preventing chlorine deposition on boiler surfaces by blending coal with high chlorine biomass. Others [56,57] have reported that co-firing low-chlorine biomass (wood with < 0.01% Cl) with coals (0.09–0.17% Cl) can be favorable in reducing the HCl emissions from the coals. Alkali chlorides (mostly KCl) contribute to high-temperature corrosion inside the boilers, and co364



Fuel 211 (2018) 363–374



E. Rokni et al.



Fig. 1. Schematic of electrically heated DTF for solid fuel combustion and emission monitoring. The inserted photograph shows particles of 50–50 wt% blend of Illinois coal (the five particles with contrails in the upper left corner) and raw corn straw (the remaining five particles) during their volatile matter combustion phase.



3. Fuel properties



Twall. The full axial gas temperature profile has been given in Fig. 3 of Ref. [27]. The air flow rate was kept at 2 l/min through the flow straightener and 2 l/min through the furnace injector. The combined flow at furnace wall temperatures of 1400 K resulted in an average gas velocity of 30 cm/s and a nominal gas residence time of about 1s inside the furnace radiation cavity. The effluent of the furnace passed through a glass condenser, placed in an ice-bath, and it was then channeled to the following analyzers: (a) a Teledyne UV-based SO2 analyzer Model T100H, (b) a Teledyne chemiluminescent NOx analyzer Model T200H, O2, CO, and CO2 Horiba VIA-510 analyzers as well as a California CO, and CO2 analyzer. LabVIEW software running on a micro-computer recorded the analyzer signals through a Data Translation (PCI-6221) acquisition card. HCl emissions were monitored by Fourier Transform Infra-Red (FTIR) spectroscopy (using a GASMET DX4000 instrument) and sampling through a heated line, as described in our prior work [71]. All experiments were repeated three times and each point shown on each plot represents the mean of the three tests; the error bars represent the standard error of the mean. The schematic includes a selected image from high-speed and high-resolution cinematography in a drop tube furnace (DTF) of early stage combustion events of free-falling dilute particle clouds form a 50–50 wt% blend of pulverized bituminous coal (Illinois #6) with raw corn straw biomass. The bituminous coal particles formed bright elongated envelope flames of burning volatiles, topped with long contrails of luminous soot, see Fig. 1. Biomass particles formed spherical volatile matter flames around individual particles. Their luminosity was lower than the luminosity of bituminous coal particles [77]. Inside the volatile matter envelope flames, biomass particles were seen to rotate, and to consistently shrink. In addition, the envelope flame luminosity of torrefied biomasses particles was visibly higher than the flame luminosity of raw biomass particles, which has been documented in previous research in this laboratory [78,79].



A low sulfur, high alkali sub-bituminous coal (PRB, Wyodak, Wyoming) and a high sulfur, low alkali bituminous coal (Illinois #6) were procured from the Penn State Coal Sample Bank, and have been extensively characterized in prior work [80,81]. Corn straw and rice husk were obtained from farms at the vicinity of Harbin Institute of Technology in China and were pulverized by grinding. The Ultimate and Proximate analysis of all fuel samples are shown in Table 1. The entire Proximate and Ultimate analyses of the coal samples was performed by the Penn State Coal Sample Bank, whereas the Proximate and Ultimate analyses of the biomass samples were performed at Harbin Institute of Technology, based on the GB/T 212-2008 and GB/T 30733-2014 Chinese standards respectively. The sulfur analysis of the biomass samples was performed based on the GB/T 214-2007 standard and the heating values were measured according to GB/T 213-2008 standard. The Proximate Analysis numbers add up to 100%, whereas the Ultimate Analysis numbers do not add up to 100% because not all of the ash components are listed in Table 1. The coal particles were sieved and then collected in the range of 75–90 µm and the biomass particles (both the raw and the torrefied) were sieved and collected in the range of 90–150 µm. The aspect ratio of the biomass particles can be much higher than those of coal, particularly those of the corn straw which are needle-shaped. Hence, while their diameters were in the aforesaid range their lengths were much higher. The torrefaction process for the biomass samples was carried out in a laboratory-scale muffle furnace in a nitrogen flow, as described in Ref. [30]. The data presented in Table 1 show that upon torrefaction the volatile contents of both types of biomass decreased, while the amounts of fixed carbon and ash increased. In addition, upon torrefaction the mass fraction of nitrogen content increased by about 20% in both biomass samples while the mass 365



Fuel 211 (2018) 363–374



E. Rokni et al.



Table 1 Chemical compositions (wt%) and energy contents (MJ/kg) of the fuels.



fraction of sulfur decreased by about 60% in both cases. The mass fraction of alkali contents increased in the case of torrefied biomass as the concentration of the residual ash in the fuel increased, while the mass fraction of chlorine content in torrefied biomass decreased by 40–70%. All the fuel samples were dried out inside an oven at 100 °C overnight prior to the experiments to make sure the moisture contents of the samples are negligible. 4. Results and discussion Combustion of pulverized coal and biomass was first conducted at constant fuel bed volumetric flow rates. However, as the density of pulverized biomass was lower than that of the coals, additional experiments were also conducted at constant fuel mass flow rates. In all experiments, neat coals, neat raw and torrefied biomass, as well as 50–50 wt% blends thereof were burned in air, under fuel-lean conditions. In addition in all experiments the bulk (global) equivalence ratios, ϕ, were calculated based on Eq. (1) based on the input of fuel and air, are shown in Fig. 2.



Fig. 2. Bulk (global) equivalence ratios, ϕs, of neat coals, neat biomass, and 50–50 wt% blends thereof in experiments where the volumetric flow rate of pulverized fuel beds was kept constant.



mf



ϕ=



( m ) actual



feeder. The lower ϕ of the raw corn straw sample can be partly explained based on its low bulk density, as its particles are needle-shaped. The bulk bed densities of raw and torrefied corn straw were determined to be approximately 0.25 g/cm3 and 0.35 g/cm3, respectively; whereas those of raw and torrefied rice husk were determined to be about 0.35 g/cm3 and 0.45 g/cm3, respectively [30]. The torrefied biomass samples experienced higher ϕs in general, as their bulk densities are higher than those of the raw samples. The neat coal samples experienced the highest ϕs due to their higher bulk densities than those of the biomass samples. As expected, the equivalence ratios of the 50–50 wt% blends were in-between the values of their corresponding neat coal and biomass components. For those experiments where the mass flow rates of the pulverized fuel beds were kept constant, described in a



air



mf



( m ) stoichiometric air



(1)



4.1. Combustion experiments with constant fuel bed volumetric flow rate (variable mass flow rates and, thus, variable equivalence ratios) In these experiments the volumetric flow rates of the pulverized fuel beds were kept constant, while the attained bulk equivalence ratios differed due to variant bulk bed densities. In the cases of the two coals ϕ was approx. 0.55, whereas in the case of corn straw ϕs were around 0.13 and 0.20 for its raw and torrefied states, respectively. In the case of rice husk ϕs were around 0.24 and 0.27 for its raw and torrefied states respectively, at the same settings of the syringe pump – driven fuel 366



Fuel 211 (2018) 363–374



E. Rokni et al.



corn straw and the highest to rice husk samples, for the reasons mentioned before. In addition, the torrefied corn straw generated higher CO2 emissions in line with its higher carbon content. For the 50–50 wt % blends of coal and biomass the CO2 emissions were between 4.3% and 7%; rice husk (raw and torrefied) blends generated higher emissions than corn straw (raw and torrified) blends. Moreover, torrefied biomass in the 50–50 wt% blends generated higher CO2 emissions than raw biomass. These disparities can be attributed to the differences in the bulk equivalence ratios ϕ among the fuel samples and to differences in their carbon contents. Emission yields (mass based emissions), i.e. g/ (g dry fuel), were also calculated to normalize such discrepancies in the CO2 mole fractions. As shown in Fig. 4, the emission yields of neat corn straw(raw) and rice husk(raw) were around 1.5 and 1.6 g/(g dry fuel), which are lower than the 2.11 and 2.43 g/(g dry fuel) for bituminous and sub-bituminous coals respectively. Emission yields from combustion of the blends were between 1.8 and 2.15 g/(g dry fuel); those from corn straw – coal blends were slightly higher than those of rice husk blends. Subsequently, the CO2 emission yields were further normalized with the energy contents of the fuels listed in Table 1, i.e., kg/(GJ of fuel burned), and such emission factors are also shown in Fig. 4. As the energy contents of neat coals are higher than those of the 50–50 w% blends, and those of the blends are higher than those of the neat biomass, then in general the emission factors are inversely proportional to the fuel energy contents. The CO2 emission factors range from 75 to 108 kg/GJ. It is notable that all biomass samples have higher CO2 emission factors than those of coals burned herein because of their lower heating values. In agreement with the aforesaid observations, the O2 mole fractions in the effluents were inversely proportional to the emitted CO2, as shown in Fig. 4.



Fig. 3. Combustion efficiencies of neat coals, neat biomass, and 50–50 wt% blends thereof in experiments where the volumetric flow rate of pulverized fuel beds was kept constant.



subsequent sub-section, the equivalence ratio was kept at ϕ ≈ 0.4. 4.1.1. Combustion efficiencies Combustion efficiencies were calculated as shown in Eq. (2), based on the mass fraction of carbon in a fuel sample introduced to the furnace that was converted into the carbon in the emitted CO2; they are plotted in Fig. 3. Such efficiencies include any small losses of fuel powders that may have happened in the feeding tube.



Combustion Efficiency (%) =



mcarbon in CO2 × 100 mcarbon in fuel



4.1.3. SO2 emissions in the combustion effluents The measured mole (volume) fractions of SO2 in the combustion effluents of all samples are shown in Fig. 5, together with the mass emission yields, the emission factors and the mass fractions of sulfur converted to SO2. The SO2 emissions from the bituminous coal were the highest at 3180 ppm or 110 mg/g of dry coal, see also [80], followed by sub-bituminous coal at 188 ppm or 7.2 mg/g of dry coal. The SO2 emissions from burning biomass were much lower. The SO2 emissions of corn straw, raw and torrefied, were 17 and 9 ppm respectively, which correspond the mass emissions of 1.7 and 0.75 mg/g of dry fuel and to emission factors of 0.1 and 0.04 kg/GJ respectively. The SO2 emissions for the rice husk, raw and torrefied, were 10 and 5 ppm respectively, which correspond to mass emission yields of 0.5 and 0.24 mg/g of dry fuel, and to emission factors of 0.035 and 0.015 kg/GJ respectively. It was calculated that the coal samples emitted most of their sulfur as SO2, amounting to 83% and 100% for sub-bituminous and bituminous respectively. The biomass samples emitted much lower fractions of their sulfur content as SO2, ranging between 20% and 43% in all cases, including raw and torrefied, and was mainly attributed to higher sulfur retention in their alkali-rich ashes. For the all cases of the 50–50 wt% blends the SO2 mole fractions, mass emission yields, and emission factors were in-between those of neat coals and neat biomass. The fact that such values are much lower than those of coal constitutes a significant benefit of co-firing coal and biomass. In addition to replacing high sulfur coal with low sulfur biomass, a beneficial synergism is also evident which reduces the SO2 emissions to even lower values than those predicted based on linear interpolations between the values of neat coal and biomass. This can be attributed to the high alkali earth metal content of biomass that can capture gas-phase SO2 heterogeneously in the ash. Capturing sulfur by alkali metals available in the fuel structures was extensively studied in previous research in this laboratory [80–83]. To support this argument herein, sufficient amounts of ash were generated and analyzed for their sulfur contents, as described in Section 5. Upon further examination of Fig. 5, it becomes evident that the SO2 emissions from burning torrefied biomass were lower than those from raw biomass, as also shown in



(2)



In all cases, these efficiencies were determined to be between 87% and 100%. The neat bituminous and sub-bituminous coals experienced 90% and 95% combustion efficiencies, respectively. The torrefied biomass samples experienced higher combustion efficiencies than the raw samples. Similarly, the 50–50 wt% blends of coal with torrefied biomass experienced higher combustion efficiencies than those of coal with raw biomass. Discrepancies between the combustion efficiencies of torrefied and raw biomass can be, at least partially, attributed to the fact that torrefied biomass is less fibrous than raw biomass and its particles have lower aspect ratios [79]. Thus, it fluidizes better and, upon entering the furnace, it may achieve better dispersion and more effective mixing with air, aiding its burnout. As torrefied biomass is less fibrous the size distribution of its particles in a given size cut was visually observed to be more uniform, and long needle-shaped particles, which are present in raw biomass and are more difficult to burn, are thus avoided. Torrefied corn straw also contains more carbon than raw corn straw, which generated more carbon dioxide which, in turn, increased the combustion efficiency, as calculated from Eq. (2). An additional observation is that the rice husk biomass and its blends with coals experienced higher combustion efficiencies than the corn straw biomass and its blends with coals. The, higher combustion efficiencies in the case of rice husk and its blends with coal are also attributed to their lower aspect ratio than those of corn straw [30], which facilitates their fluidization, dispersion, mixing with air and burning in the furnace. 4.1.2. CO2 emissions in the combustion effluents The measured volume fractions of CO2 in the combustion effluents of all samples are shown in Fig. 4 (a- representing bituminous coalbiomass samples, and b- sub-bituminous coal-biomass samples). The mole fractions of CO2 in the neat coal effluents were about 9%, as also reported in the previous works under similar conditions [80,81]. For all neat raw and torrefied biomass samples the mole fractions of CO2 were between 2.2% and 5.5%, of which the lowest number corresponds to 367



Fuel 211 (2018) 363–374



E. Rokni et al.



Fig. 4. Carbon dioxide mole fractions (%), mass fractions based on the amount of fuel introduced to the furnace (g/g), and corresponding emission factors (kg/GJ), followed by mole fraction of oxygen(%) in combustion effluents. (a- represents bituminous coal – biomass samples, and b- represents sub-bituminous coal – biomass samples). In these experiments the volumetric flow rates of pulverized fuel beds were kept constant.



Fig. 5. Mole fractions of sulfur dioxide in the combustion effluents (ppm), mass fractions based on the amount of fuel burnt inside the furnace (mg/g), corresponding emission factors (kg/ GJ) and conversion amounts of the fuel sulfur to SO2, (a- represents bituminous coal – biomass samples, and b- represents sub-bituminous coal – biomass samples). In these experiments the volumetric flow rates of pulverized fuel beds were kept constant.



368



Fuel 211 (2018) 363–374



E. Rokni et al.



content of the fuels herein is in the range of 0.94–1.5 wt%, and all biomass samples have higher nitrogen contents than the coals, see Table 1. Monitored mole fractions (ppm) of NOx in the biomass effluents were lower than in those of the coals, see Fig. 6, because of the lower bulk equivalence ratios in these experiments, therefore, to allow direct comparison, mass emission yields were calculated based on the mass of fuel burnt (specific mass emissions) and then, again, emission factors were obtained based on the energy content of the fuels. The emissions from burning bituminous and sub-bituminous coals were 690 and 575 ppm respectively, which correspond to 11.2 and 10.3 mg/g of dry fuel, and 0.4 and 0.35 kg/GJ, respectively. NOx emissions from raw and torrefied rice husk were 185 and 230 ppm, respectively, which represent 3.2 and 3.6 mg/g of dry fuel, respectively, and 0.22 kg/GJ in both cases. Finally, NOx emissions from raw and torrefied corn straw were 144 and 288 ppm, respectively, resulting in 4.8 and 6.1 mg/g of dry fuel, and 0.29 and 0.32 kg/GJ respectively. The fact that corn straw generated higher specific emissions of NOx than rice husk may be attributed to its higher nitrogen content and to its higher volatile content, which facilitates release of fuel-bound nitrogen. The torrefaction process increased the mass fraction of nitrogen content of fuels, as shown in Table 1, therefore NOx emission yields from torrefied biomass were typically higher than those from raw biomass. Under the strongly fuellean conditions of this work, less than 40% of the fuel-nitrogen of the coals was converted to NOx, as it was also reported in previous research [27,88]. It is notable, that even if the biomass samples contained more nitrogen than coal, they emitted less NOx, which indicates different conversion pathways for the fuel-N (e.g., the heightened importance of the NH3 route in comparison to the HCN route, etc. [27–29,32]). In fact, in the cases of raw and torrefied rice husk the amount of fuel-nitrogen converted to NOx was less than 13%, while for the raw and torrefied corn straw raw the corresponding fractions of fuel-nitrogen converted to NOx were about 19% and 28%, respectively. Generally, as some raw



previous work [30] and reflects the lower sulfur content of the torrefied biomass, as shown in Table 1. During the process of torrefaction (lowtemperature pyrolysis) sulfur was released to the gas phase, as also documented in other studies where torrefaction at different temperatures resulted in reduction of the sulfur contents of different types of biomass [76,84]. Sulfur can be found in both organic and inorganic compounds in biomass. The organic sulfur can be released during biomass devolatilization at low temperatures (akin to the torrefaction temperatures used in this work). The inorganic sulfur can be released at high temperatures (above 900 °C) through interaction with the char matrix; or it can be retained in the ash [76]. A significant release of sulfur from six different biomass types has been reported to be up to 60%, when torrefaction occurred at 350 °C [76], whereas for herbaceous biomass it has been reported to be 35–50% when pyrolysis occurred at 400 °C [76,85,86]. Thus, in this study organic-bound sulfur must have been released during the torrefaction, which lowered the sulfur content of torrefied biomass, as shown in Table 1. Hence, it can be concluded that torrefaction reduced the amount of SO2 emissions in the effluent gases and, consequentially, torrefied biomass generated less SO2. Finally, by comparing the rice husk and corn straw biomass herein, the former samples contain less sulfur, therefore their mass emission yields and their emission factors were lower as expected. In addition, the emissions from blends of coals with torrefied biomass were lower than those of coal with raw biomass due to lower sulfur content of the coal-torrefied biomass blends. 4.1.4. NOx emissions in the combustion effluents Experimental results in Fig. 6 show the NOx emissions in the combustion effluents of the fuels, as mole fractions, as mass-based emission yields, as emission factors, and as percentages of fuel-nitrogen converted to NOx, respectively. Generally, the nitrogen content of coals varies less [87] than that of different types of biomass. The nitrogen



Fig. 6. Mole fractions of nitrogen oxide in the combustion effluents (ppm), mass fractions based on the amount of fuel burnt inside the furnace (mg/g), corresponding emission factors (kg/GJ) and conversion amounts of the fuel sulfur to NOx, (a- represents bituminous coal – biomass samples, and b- represents sub-bituminous coal – biomass samples). In these experiments the volumetric flow rates of pulverized fuel beds were kept constant.



369



Fuel 211 (2018) 363–374



E. Rokni et al.



respectively) than the predicted values from linear interpolations of the corresponding emissions of their constituents. The amounts of such additional HCl that appeared during combustion of the blends may be partly attributed to homogeneous reactions of alkali chlorides (mostly KCl) with SO2 gases released from the combustion of the coals, as explained in the ensuing paragraph. This hypothesis is supported by the fact that more HCl was found in the gas phase when corn straw was cofired with the high-sulfur Illinois coal than with the low-sulfur PRB coal. In the case of burning 50–50 wt% blends of both coals with the torrefied corn straw the HCl emissions were also higher than values expected from a linear interpolation of the corresponding emissions from burning their constituents, but by a lesser amount than in the case of coal blends with the raw corn straw (by about 5% and 9% for I-CS(T) and PRB-CS(T) samples, respectively). This may be explained based on the much lower chlorine content of the torrefied biomass – coal blends, as compared to the raw biomass – coal blends by factors of nearly 3. Sulfation reactions of alkali chlorides are important, as they have been reported to lessen the severity of corrosion and fouling problems inside the boilers [91]. Such a reaction with KCl is exemplified below:



corn straw particles may have a delayed and prolonged combustion due to their typically bigger particle masses and, if not fully dried, higher moisture content compared to coal, a lower fraction of their volatile nitrogen components may be converted into NO, due to encountering lower local oxygen concentrations [28,29]. The NOx emissions of all blends were between those of the corresponding neat coal and neat raw or torrefied biomass. In the case of coal-torrefied biomass co-firing, the mass emissions and emission factors were lower than those predicted by a linear interpolation of the emissions of the neat fuels, which is a result of possible different release mechanisms and/or the presence of beneficial NOx reduction synergisms during the combustion of these blends. For instance, as biomass has a high volatile content, it may serve as a de facto re-burn fuel for NOx reduction from the coal combustion, which gives a further potential to decrease the NOx emissions from the blend [14]. There may also be a temperature contribution to the fact that the NOx emissions from the blends of coal with torrefied biomass were lower than predicted, as ongoing research by the authors shows that torrefied biomass chars burn cooler than coal chars. Other researchers have also reported the positive influence of higher volatile content on NOx until the fuel volatility (defined as volatile matter/fixed carbon) reaches unity [38]. It has been also reported that the NOx emissions from combustion of raw and torrefied biomass decrease with the increase in volatility [30], which was also seen in the experiments of this work, as the raw biomass samples contain more volatile matter than the torrefied samples. In addition, it was reported that the NOx emissions decrease with the increase of calcium and magnesium over nitrogen, since the CaO and MgO in fuel structure can form active sites that would catalyze the reduction of NO [89,90].



2KCl (g,c) + SO2 +



1 O2 + H2 O(g) ⇆ K2SO4(g,c) + 2HCl (g) 2



(3)



The thermodynamic chemical equilibrium constant, Kp, can be calculated based on the Gibbs Free Energy (G) change as follows:



ln Kp =



−ΔGTo RT



(4)



where Gibbs free energy ΔGTo is defined as follows:



ΔGTo = ΔHTo−T ΔSTo



(5)



ΔHTo



ΔSTo



is the standard enthalpy change, is standard molar where entropy change, and T is the reaction temperature. The calculated Kp for Eq. (3) for KCl (in gaseous state) and KCl (in condensed state) are shown in Eqs. (6) and (7), respectively:



4.1.5. HCl emissions in the combustion effluents The specific mass-based emissions of HCl from the combustion of both coals (Illinois and PRB), corn straw (raw and torrefied), and 50–50 wt% blends of either coal with corn straw are shown in Fig. 7. The HCl emissions from corn straw were found to be much higher than those from either of the two coals, which is expected based on the much higher Cl content of corn straw than those of the coals (see Table 1). It is notable, however, that the HCl emissions from the 50–50 wt% blends of either of the two coals with the raw corn straw were higher (by about 39% and 22% for I-CS(R) and PRB-CS(R) samples,



Kp = 9.58 × 10−5e Kp = 1.045 ×



28880 T



78700 10−12e T



−1



atm 2



−5 atm 2



(6) (7)



Eqs. (6) and (7) are shown in Fig. 9(a), plotted versus reaction temperature. Whereas increasing temperature is not favorable for the sulfation of KCl, at the furnace gas temperature attained in this work, Tgas = 1350 K, the gas-phase reaction is more than likely to take place. In addition, published results by Lisa et al. [91] suggest that most of the KCl sulfation in a boiler can be expected to occur in gas phase. Their experiments [91] took place inside a laminar entrained-flow reactor operated at temperatures in the range of 1150–1350 K and residence times in the range of 0.24–1.22 s, both which are pertinent to the experimental conditions found herein. For the chemical reaction of Eq. (3), higher SO2 concentrations can increase the HCl emissions in the flue gases, as observed in the experimental results herein (Fig. 7). A prior investigation [91] reported that the sulfation rates in both molten and gas phases depend on the concentrations of SO2, and O2, but not H2O, based on experiments in an entrained flow reactor; and showed that SO3 is also available for sulfation of alkali chlorides. Yet, another investigation reported that homogeneous formation of SO3 from SO2 amounted to 1.8% of 1000 ppmv SO2 introduced in a flow reactor, heated to 1400 K [92]. In agreement with that work, for the case of the high-sulfur Illinois bituminous coal burned herein, previous experiments by the authors detected about 68 ppm of SO3 (corresponding to 2% of total sulfur of the coal) in the flue gases [81]. 4.2. Combustion experiments with constant mass flow rate and, thus, constant bulk (global) equivalence ratio



Fig. 7. Mass fraction of hydrogen chlorides (mg/g of fuel burned) in combustion effluents of Illinois (I), PRB, raw corn straw (CS(R)), torrefied corn straw (CS(T)), and their blends.



The results in the previous sections were obtained with nominally constant volumetric flowrate of the fuel powders in the furnace. This 370



Fuel 211 (2018) 363–374



E. Rokni et al.



Fig. 8. Mass fractions of CO2, SO2, and NOx based on the amount of fuel burnt inside the furnace (g/g & mg/g). All experiments have similar equivalence ratios (ϕ = 0.4). In these experiments the volumetric flow rates of pulverized fuel beds were kept constant.



5. Ash analysis Additional experiments to assess the chemical composition of the ashes and investigate the validity of the aforesaid explanations on the fate of the gaseous pollutants were performed by burning fixed-beds of fuel in a horizontal muffle furnace. This was done to collect sufficient amounts of ashes for reliable elemental analysis, which was performed by Ion Chromatography (IC). That furnace was operated under atmospheric conditions and combustion occurred in air. The furnace was preheated to 1400 K and a porcelain boat containing a known quantity of fuel was expediently inserted. Thereafter the fuel experienced a heating rate of 103 K/s. Upon combustion, the ashes were cooled and collected for analysis. Prior to characterization, the ashes were dried at 105 °C for 2 h. Then, they were placed into an ultra-high purity (metal impurity content is less than 1 ppb) solution (HNO3: 6 ml, H2O2: 2 ml) for two hours. Afterwards, a new solution (HNO3:H2O2:HF = 4:2:2) was added and the samples were heated to 120 °C at a heating rate of 20 °C /min and were kept at the maximum temperature for 5 min. Subsequently, the samples were heated to 200 °C with a rate of 16 °C /min and kept at that final temperature for one hour. Thereafter, the solutions were detected by IC with a Dionex ICS-900 instrument. The abbreviations used in Table 2 are for the following samples: corn straw raw (CS(R)), corn straw torrefied (CS(T)), rice hush raw (RH(R)), rice husk torrefied (RH(T)), Illinois coal (I), Powder River Basin coal (PRB). The results shown in Table 2 include the total alkali in the neat biomass fuels and their blends with coal, as well as the percentages of nitrogen, sulfur, and chlorine detected in the ashes of each sample upon combustion. Based on the amounts of these elements contained in the fuels and those contained in their combustion ashes, the fractions of the elements that were captured in the ashes were calculated. Then by dividing these fractions of N, S, and Cl captured in the ashes by the total initial alkali mass in each fuel sample, the retention effectiveness of the alkalis for these elements was assessed, and listed in Table 2. (i) For sulfur, such ratios are higher in the cases of blends of the biomass with the high-sulfur Illinois coal, as the biomass fuels have high alkali contents and this coal emits copious amounts SO2. Similar results were seen in prior work when this high-sulfur coal was blended with a low-sulfurhigh alkali lignite [80,81]. (ii) For chlorine, such ratio is the highest for raw corn straw and for its blends with the Illinois coal, as raw corn straw has high chlorine and high alkali contents. (iii) For nitrogen these ratios vary in a much narrower range than those for sulfur and chlorine, as all fuels contain similar amounts of nitrogen. Overall, the amounts of nitrogen captured in the ashes of the torrefied biomass samples and in their blends with coal were higher than the nitrogen captured in the ashes of the raw biomass samples and their blends with coal. This can be attributed to the higher amounts of ash, especially alkali metals, in the torrefied samples, as shown in Table 1. It has been reported that ash elements can inhibit the conversion of fuel-N to NO [93]. It has also been reported that Mg, Ca, and K can contribute to catalytic activity in



Fig. 9. Equilibrium constants for KCl (condensed or gas) sulfation reactions versus temperature.



caused notable differences in the mass flowrate and the resulting equivalence ratios, as seen in Fig. 2, depending on the bulk densities of the powders. Hence, a limited number of additional experiments were performed with comparable mass flow rates of the pulverized fuels to investigate the validity of the conclusions. The equivalence ratios in these experiments were kept constant at approx. ϕ = 0.4. The corn straw was not included in these experiments as some fluidization difficulty was encountered in maintaining the higher mass flow rate needed to attain ϕ = 0.4. To the contrary, rice husk fluidized equally well as the coals. Mass-based emissions of CO2, SO2 and NOx from the combustion of the bituminous coal (Illinois), raw and torrefied biomass (rice husk), and their 50–50 wt% blends are shown in Fig. 8. Therein, results obtained with constant powder volumetric flowrate, shown before, are also superimposed for comparison. The specific mass-based emissions of CO2 and SO2 were fairly similar in both types of experiments (constant mass flowrate and constant volumetric flowrate of the powders). However, the NOx emissions for the raw and torrefied rice husk samples almost doubled in the constant mass flow rate experiment which was conducted at a higher equivalence ratio, which itself almost doubled (from ϕ = 0.2 in the constant volumetric flowrate to ϕ = 0.4) in the constant mass flowrate experiments. It is likely, but it was not documented, that at the higher ϕ the mass flow rate fluidization of the pulverized biomass was steadier, resulting in better combustion and more NOx.



371



Fuel 211 (2018) 363–374



E. Rokni et al.



Table 2 Percentage of fuel-N, S, and Cl converted to NOx, SO2, and HCl as well as the amount of these elements retained the ash.



NO reduction from char combustion [93–96]. The NO reduction by the alkali metals could may partially explain the observed lower NOx emissions, shown in Fig. 6, from burning blends of coal with torrefied biomass which have higher concentrations of alkali metal elements than their raw biomass precursors.



•



6. Conclusions This research burned blends of two coals, a high-sulfur bituminous coal (Illinois #6) and a low-sulfur sub-bituminous coal (PRB), with two types of biomass, a herbaceous (corn straw) and a crop related (rice husk). The acid gas emissions (SO2, NOx, and HCl) of the neat coal, biomass, and their 50–50 wt% blend were monitored. The following quantitative observations were made:



•



• Specific CO •



•



•



•



2 mass emissions (normalized by fuel mass) from cofiring coals with torrefied biomass samples were typically higher than those from co-firing coals with raw biomass samples. These discrepancies can be attributed to the differences in their carbon contents of raw and torrefied biomass. Specific SO2 mass emissions (normalized by fuel mass) from cofiring a high-sulfur bituminous coal with raw and torrefied corn straw were reduced by 35% and 46%, respectively, from the expected values of a linear interpolation of the corresponding emissions of their constituents. Corresponding SO2 reductions from cofiring this coal with raw and torrefied rice husk were 37% and 50%, respectively. Specific SO2 mass emissions (normalized by fuel mass) from cofiring a low-sulfur sub-bituminous coal with raw and torrefied corn straw were reduced by 26% and 33%, respectively, from the expected values of a linear interpolation of the corresponding emissions of their constituents. Corresponding SO2 reductions from cofiring this coal with raw and torrefied rice husk were 19% and 36%, respectively. Specific NOx mass emissions (normalized by fuel mass) from cofiring a high-sulfur bituminous coal with raw and torrefied corn straw were reduced by 6% and 17%, respectively, from the expected values of a linear interpolation of the corresponding emissions of their constituents. Corresponding NOx reductions from co-firing this coal with raw and torrefied rice husk were 10% and 19%, respectively. Specific NOx mass emissions (normalized by fuel mass) from co-



firing a low-sulfur sub-bituminous coal with raw and torrefied corn straw were reduced by 5% and 15%, respectively, from the expected values of a linear interpolation of the corresponding emissions of their constituents. Corresponding NOx reductions from co-firing this coal with raw and torrefied rice husk were 9% and 27%, respectively. Specific HCl mass emissions (normalized by fuel mass) from cofiring a high-sulfur bituminous coal with raw and torrefied corn straw increased by 39% and 5%, respectively, from the expected values of a linear interpolation of the corresponding emissions of their constituents. Specific HCl mass emissions (normalized by fuel mass) from cofiring a low-sulfur sub-bituminous coal with raw and torrefied corn straw increased by 22% and 9%, respectively, from the expected values of a linear interpolation of the corresponding emissions of their constituents.



Acknowledgement This work has been partially supported by Northeastern University and partly by the Innovative Research Groups of the National Natural Science Foundation of China (Grant No. 51421063). Mr. Xiaohan Ren was supported by the China Scholarship Council. References [1] Agbor E, Zhang X, Kumar A. A review of biomass co-firing in North America. Renewable Sustainable Energy Rev 2014;40:930–43. [2] IRENA, Biomass for Heat and Power, http://www.irena.org/DocumentDownloads/ Publications/IRENA-ETSAP_Tech_Brief_E05_Biomass%20for%20Heat%20and %20Power.pdf Last accessed December 2016, (2015). [3] Sahu S, Chakraborty N, Sarkar P. Coal–biomass co-combustion: an overview. Renewable Sustainable Energy Rev 2014;39:575–86. [4] Hughes E. Biomass cofiring: economics, policy and opportunities. Biomass Bioenergy 2000;19:457–65. [5] Saidur R, Abdelaziz E, Demirbas A, Hossain M, Mekhilef S. A review on biomass as a fuel for boilers. Renewable Sustainable Energy Rev 2011;15:2262–89. [6] Tillman DA. Cofiring benefits for coal and biomass. Biomass Bioenergy 2000;19:363–4. [7] Narayanan K, Natarajan E. Experimental studies on cofiring of coal and biomass blends in India. Renewable Energy 2007;32:2548–58. [8] Williams A, Pourkashanian M, Jones J. Combustion of pulverised coal and biomass. Prog Energy Combust Sci 2001;27:587–610. [9] Lester E, Gong M, Thompson A. A method for source apportionment in biomass/coal blends using thermogravimetric analysis. J Anal Appl Pyrolysis 2007;80:111–7. [10] Mann MK, Spath PL, The environmental benefits of cofiring biomass and coal, in: Proceedings of the international technical conference on coal utilization and fuel



372



Fuel 211 (2018) 363–374



E. Rokni et al.



Fuels 2009;24:173–81. [48] Rahim MU, Gao X, Wu H. A method for the quantification of chlorine in low-rank solid fuels. Energy Fuels 2013;27:6992–9. [49] Echalar F, Gaudichet A, Cachier H, Artaxo P. Aerosol emissions by tropical forest and savanna biomass burning: characteristic trace elements and fluxes. Geophys Res Lett 1995;22:3039–42. [50] Gaudichet A, Echalar F, Chatenet B, Quisefit J, Malingre G, Cachier H, et al. Trace elements in tropical African savanna biomass burning aerosols. J Atmos Chem 1995;22:19–39. [51] Lobert JM, Keene WC, Logan JA, Yevich R. Global chlorine emissions from biomass burning: Reactive chlorine emissions inventory. J Geophys Res 1999;104:8373–89. [52] Obernberger I, Brunner T, Bärnthaler G. Chemical properties of solid biofuels—significance and impact. Biomass Bioenergy 2006;30:973–82. [53] Jensen PA, Sander B, Dam-Johansen K. Removal of K and Cl by leaching of straw char. Biomass Bioenergy 2001;20:447–57. [54] Aho M, Ferrer E. Importance of coal ash composition in protecting the boiler against chlorine deposition during combustion of chlorine-rich biomass. Fuel 2005;84:201–12. [55] Coda B, Aho M, Berger R, Hein KR. Behavior of chlorine and enrichment of risky elements in bubbling fluidized bed combustion of biomass and waste assisted by additives. Energy Fuels 2001;15:680–90. [56] McIlveen-Wright D, Huang Y, Rezvani S, Wang Y. A technical and environmental analysis of co-combustion of coal and biomass in fluidised bed technologies. Fuel 2007;86:2032–42. [57] Dayton DC, Belle-Oudry D, Nordin A. Effect of coal minerals on chlorine and alkali metals released during biomass/coal cofiring. Energy Fuels 1999;13:1203–11. [58] Shemwell B, Levendis YA, Simons GA. Laboratory study on the high-temperature capture of HCl gas by dry-injection of calcium-based sorbents. Chemosphere 2001;42:785–96. [59] Courtemanche B, Levendis YA. Control of the HCl emissions from the combustion of PVC by in-furnace injection of calcium-magnesium-based sorbents. Environ Eng Sci 1998;15:123–35. [60] Hupa M, Karlström O, Vainio E. Biomass combustion technology development–It is all about chemical details. Proc Combust Inst 2017;36:113–34. [61] Kassman H, Pettersson J, Steenari B-M, Åmand L-E. Two strategies to reduce gaseous KCl and chlorine in deposits during biomass combustion—injection of ammonium sulphate and co-combustion with peat. Fuel Process Technol 2013;105:170–80. [62] Koppejan J, Van Loo S. The handbook of biomass combustion and co-firing. Routledge; 2012. [63] IRENA, Biomass Co-firing, http://www.irena.org/DocumentDownloads/ Publications/IRENA-ETSAP%20Tech%20Brief%20E21%20Biomass%20Co-firing. pdf last accessed December 2016., (2013). [64] Moghtaderi B, Sheng C, Wall TF. An overview of the Australian biomass resources and utilization technologies. BioResources 2007;1:93–115. [65] Kiel J, Prospects of torrefaction to optimize bioenergy value chains, in: Proccedings of the Energy Delta Convention, 2011. [66] Tumuluru JS, Wright CT, Boardman RD, Yancey NA, Sokhansanj S. A review on biomass classification and composition, co-firing issues and pretreatment methods, in: 2011 Louisville, Kentucky, August 7-10, 2011. Am Soc Agric Biol Eng 2011:1. [67] Bergman P.C., Boersma A., Zwart R., Kiel J., Torrefaction for biomass co-firing in existing coal-fired power stations, Energy Centre of Netherlands, Report No. ECN-C05-013, (2005). [68] Uslu A, Faaij AP, Bergman PC. Pre-treatment technologies, and their effect on international bioenergy supply chain logistics. Techno-economic evaluation of torrefaction, fast pyrolysis and pelletisation. Energy 2008;33:1206–23. [69] Bergman P., Combined torrefaction and pelletisation, The TOP process, (2005). [70] Van der Stelt M, Gerhauser H, Kiel J, Ptasinski K. Biomass upgrading by torrefaction for the production of biofuels: A review. Biomass Bioenergy 2011;35:3748–62. [71] Ren X, Sun R, Chi H-H, Meng X, Li Y, Levendis YA. Hydrogen chloride emissions from combustion of raw and torrefied biomass. Fuel 2017;200:37–46. [72] Björkman E, Strömberg B. Release of chlorine from biomass at pyrolysis and gasification conditions1. Energy Fuels 1997;11:1026–32. [73] Keipi T, Tolvanen H, Kokko L, Raiko R. The effect of torrefaction on the chlorine content and heating value of eight woody biomass samples. Biomass Bioenergy 2014;66:232–9. [74] Toptas A, Yildirim Y, Duman G, Yanik J. Combustion behavior of different kinds of torrefied biomass and their blends with lignite. Bioresour Technol 2015;177:328–36. [75] Shang L, Ahrenfeldt J, Holm JK, Barsberg S, Zhang R-Z, Luo Y-H, et al. Intrinsic kinetics and devolatilization of wheat straw during torrefaction. J Anal Appl Pyrolysis 2013;100:145–52. [76] Saleh SB, Flensborg JP, Shoulaifar TK, Sárossy Z, Hansen BB, Egsgaard H, et al. Release of chlorine and sulfur during biomass torrefaction and pyrolysis. Energy Fuels 2014;28:3738–46. [77] Khatami R, Stivers C, Joshi K, Levendis YA, Sarofim AF. Combustion behavior of single particles from three different coal ranks and from sugar cane bagasse in O2/ N2 and O2/CO2 atmospheres. Combust Flame 2012;159:1253–71. [78] Levendis YA, Joshi K, Khatami R, Sarofim AF. Combustion behavior in air of single particles from three different coal ranks and from sugarcane bagasse. Combust Flame 2011;158:452–65. [79] Panahi A, Levendis YA, Vorobiev N, Schiemann M. Direct observation on the combustion characteristics of Miscanthus and Beechwood biomass including fusion and spherodization. Fuel Process Technol 2017;166:41–9. [80] Rokni E, Panahi A, Ren X, Levendis YA. Reduction of sulfur dioxide emissions by burning coal blends. J Energy Resour Technol 2016;138:032204.



systems, 2002, pp. 205–215. [11] Sami M, Annamalai K, Wooldridge M. Co-firing of coal and biomass fuel blends. Prog Energy Combust Sci 2001;27:171–214. [12] Sweeten JM, Annamalai K, Thien B, McDonald LA. Co-firing of coal and cattle feedlot biomass (FB) fuels. Part I. Feedlot biomass (cattle manure) fuel quality and characteristics. Fuel 2003;82:1167–82. [13] Tillman DA. Biomass cofiring: the technology, the experience, the combustion consequences. Biomass Bioenergy 2000;19:365–84. [14] Nussbaumer T. Combustion and co-combustion of biomass: fundamentals, technologies, and primary measures for emission reduction. Energy Fuels 2003;17:1510–21. [15] Baxter L. Biomass-coal cofiring: an overview of technical issues. Solid biofuels for energy. Springer; 2011. p. 43–73. [16] Baxter L. Biomass-coal co-combustion: opportunity for affordable renewable energy. Fuel 2005;84:1295–302. [17] Leckner B. Co-combustion: a summary of technology. Therm Sci 2007;11:5–40. [18] Sondreal EA, Benson SA, Hurley JP, Mann MD, Pavlish JH, Swanson ML, et al. Review of advances in combustion technology and biomass cofiring. Fuel Process Technol 2001;71:7–38. [19] Vamvuka D, Sfakiotakis S. Combustion behaviour of biomass fuels and their blends with lignite. Thermochim Acta 2011;526:192–9. [20] Hupa M. Interaction of fuels in co-firing in FBC. Fuel 2005;84:1312–9. [21] Li J, Yang W, Blasiak W, Ponzio A. Volumetric combustion of biomass for CO2 and NOx reduction in coal-fired boilers. Fuel 2012;102:624–33. [22] Hughes EE, Tillman DA. Biomass cofiring: status and prospects 1996. Fuel Process Technol 1998;54:127–42. [23] Easterly JL, Burnham M. Overview of biomass and waste fuel resources for power production. Biomass Bioenergy 1996;10:79–92. [24] Sarvaramini A, Assima GP, Beaudoin G, Larachi F. Biomass torrefaction and CO2 capture using mining wastes–A new approach for reducing greenhouse gas emissions of co-firing plants. Fuel 2014;115:749–57. [25] Bragato M, Joshi K, Carlson JB, Tenório JA, Levendis YA. Combustion of coal, bagasse and blends thereof: Part I: Emissions from batch combustion of fixed beds of fuels. Fuel 2012;96:43–50. [26] Bragato M, Joshi K, Carlson JB, Tenório JA, Levendis YA. Combustion of coal, bagasse and blends thereof: Part II: Speciation of PAH emissions. Fuel 2012;96:51–8. [27] Kazanc F, Khatami R, Manoel Crnkovic P, Levendis YA. Emissions of NOx and SO2 from Coals of Various Ranks, Bagasse, and Coal-Bagasse Blends Burning in O2/N2 and O2/CO2 Environments. Energy Fuels 2011;25:2850–61. [28] Hein K, Bemtgen J. EU clean coal technology—co-combustion of coal and biomass. Fuel Process Technol 1998;54:159–69. [29] Spliethoff H, Hein K. Effect of co-combustion of biomass on emissions in pulverized fuel furnaces. Fuel Process Technol 1998;54:189–205. [30] Ren X, Sun R, Meng X, Vorobiev N, Schiemann M, Levendis YA. Carbon, sulfur and nitrogen oxide emissions from combustion of pulverized raw and torrefied biomass. Fuel 2017;188:310–23. [31] Lau CW, Niksa S. The impact of soot on the combustion characteristics of coal particles of various types. Combust Flame 1993;95:1–21. [32] Hein K, Spliethoff H, Co-combustion of coal and biomass in pulverized fuel and fluidized bed systems–Activities and research in Europe, in, Univ. of Stuttgart (DE), 1999. [33] Xie J-J, Yang X-M, Zhang L, Ding T-L, Song W-L, Lin W-G. Emissions of SO2, NO and N2O in a circulating fluidized bed combustor during co-firing coal and biomass. J Environ Sci 2007;19:109–16. [34] Fang M, Yang L, Chen G, Shi Z, Luo Z, Cen K. Experimental study on rice husk combustion in a circulating fluidized bed. Fuel Process Technol 2004;85:1273–82. [35] Smoot LD, Hill S, Xu H. NOx control through reburning. Prog Energy Combust Sci 1998;24:385–408. [36] Spliethoff H, Greul U, Rüdiger H, Hein KR. Basic effects on NOx emissions in air staging and reburning at a bench-scale test facility. Fuel 1996;75:560–4. [37] Pedersen LS, Nielsen HP, Kiil S, Hansen LA, Dam-Johansen K, Kildsig F, et al. Fullscale co-firing of straw and coal. Fuel 1996;75:1584–90. [38] Munir S, Nimmo W, Gibbs B. The effect of air staged, co-combustion of pulverised coal and biomass blends on NOx emissions and combustion efficiency. Fuel 2011;90:126–35. [39] Savolainen K. Co-firing of biomass in coal-fired utility boilers. Appl Energy 2003;74:369–81. [40] Demirbaş A. Sustainable cofiring of biomass with coal. Energy Convers Manage 2003;44:1465–79. [41] Battista Jr JJ, Hughes EE, Tillman DA. Biomass cofiring at seward station. Biomass Bioenergy 2000;19:419–27. [42] Molcan P, Lu G, Le Bris T, Yan Y, Taupin B, Caillat S. Characterisation of biomass and coal co-firing on a 3MWth combustion test facility using flame imaging and gas/ash sampling techniques. Fuel 2009;88:2328–34. [43] Gold BA, Tillman DA. Wood cofiring evaluation at TVA power plants. Biomass Bioenergy 1996;10:71–8. [44] Fahlstedt I, Lindman E-K, Lindberg T, Anderson J, Co-firing of biomass and coal in a pressurized fluidized bed combined cycle. Results of pilot plant studies, in, American Society of Mechanical Engineers, New York, NY (United States), 1997. [45] Reichel HH, Schirmer U. Waste incineration plants in the FRG: Construction, materials, investigation on cases of corrosion. Mater Corros 1989;40:135–41. [46] Salmenoja K, Mäkelä K, Hupa M, Backman R. Superheater corrosion in environments containing potassium and chlorine. J Inst Energy 1996;69:155–62. [47] Yip K, Tian F, Hayashi J-I, Wu H. Effect of alkali and alkaline earth metallic species on biochar reactivity and syngas compositions during steam gasification. Energy



373



Fuel 211 (2018) 363–374



E. Rokni et al.



[89] Johnsson J., Dam-Johansen K., Formation and reduction of NOx in a fluidized bed combustor, in: Proceedings 11th International Conference on Fluidised Bed Combustion. Montreal: ASME, 1991, pp. 1389–1396. [90] Werther J, Saenger M, Hartge E-U, Ogada T, Siagi Z. Combustion of agricultural residues. Prog Energy Combust Sci 2000;26:1–27. [91] Iisa K, Lu Y, Salmenoja K. Sulfation of potassium chloride at combustion conditions. Energy Fuels 1999;13:1184–90. [92] Fleig D, Alzueta MU, Normann F, Abián M, Andersson K, Johnsson F. Measurement and modeling of sulfur trioxide formation in a flow reactor under post-flame conditions. Combust Flame 2013;160:1142–51. [93] Karlström O, Perander M, DeMartini N, Brink A, Hupa M. Role of ash on the NO formation during char oxidation of biomass. Fuel 2017;190:274–80. [94] Zevenhoven R, Hupa M. The reactivity of chars from coal, peat and wood towards NO, with and without CO. Fuel 1998;77:1169–76. [95] Illan-Gomez MJ, Linares-Solano A, Radovic LR, Salinas-Martinez de Lecea C. NO reduction by activated carbons. 2. Catalytic effect of potassium. Energy Fuels 1995;9:97–103. [96] Illan-Gomez MJ, Linares-Solano A, Radovic LR, Salinas-Martinez de Lecea C. NO reduction by activated carbons. 4. Catalysis by calcium. Energy Fuels 1995;9:112–8.



[81] Rokni E, Panahi A, Ren X, Levendis YA. Curtailing the generation of sulfur dioxide and nitrogen oxide emissions by blending and oxy-combustion of coals. Fuel 2016;181:772–84. [82] Rokni E, Chi HH, Levendis YA. In-furnace sulfur capture by cofiring coal with alkalibased sorbents. J Energy Resour Technol 2017;139:042204. [83] Rokni E, Levendis YA. Utilization of a high-alkali lignite coal ash for SO2 capture in power generation. J Energy Eng 2016:04016067. [84] Knudsen JN, Jensen PA, Lin W, Frandsen FJ, Dam-Johansen K. Sulfur transformations during thermal conversion of herbaceous biomass. Energy Fuels 2004;18:810–9. [85] Johansen JM, Jakobsen JG, Frandsen F, Glarborg P. Release of K, Cl, and S during pyrolysis and combustion of high-chlorine biomass. Energy Fuels 2011;25:4961–71. [86] Wolf KJ, Smeda A, Muller M, Hilpert K. Investigations on the influence of additives for SO2 reduction during high alkaline biomass combustion. Energy Fuels 2005;19:820–4. [87] Flagan RC, Seinfeld JH. Fundamentals of air pollution engineering. Courier Corporation; 2012. [88] Pohl JH, Sarofim AF. Devolatilization and oxidation of coal nitrogen. Symposium (International) on Combustion. Elsevier; 1977. p. 491–501.



374



View publication stats