UNIVERSITY OF CINCINNATI

Transcription

1 UNIVERSITY OF CINCINNATI Date: I,, hereby submit this work as part of the requirements for the degree of: in: It is entitled: This work and its defense approved by: Chair:

2 Study of Trona ( Sodium Sesquicarbonate) Reactivity with Sulfur Dioxide in a Simulated Flue Gas A thesis submitted to the Division of Research and Advanced Studies of the University of Cincinnati in partial fulfillment of the requirements for the degree of MASTER OF SCIENCE In the Department of Civil and Environmental Engineering of the College of Engineering 2003 by Rangesh Srinivasan B.E. Anna University, Madras, India 2000 Committee Chair: Dr. Tim C. Keener 1

3 Abstract In the last few years, sulfur dioxide (SO 2 ) has been under heavy scrutiny for reduction and its emissions are being monitored very closely by both federal and state regulatory agencies. Most of the conventional flue gas desulfurization techniques are able to meet the standards but normally come with very high capital and maintenance costs and have other associated problems. Dry injection of sodium-based sorbents has gained a lot of attention in the last few years. With Dry injection, it is possible to achieve almost similar and in some cases even higher SO 2 removal efficiencies than with spray dry or wet scrubbing systems. It is proposed to study the reactivity of Trona (Na 2 CO 3.NaHCO 3.2H 2 O) with SO 2 in a simulated flue gas stream by means of an entrained flow reactor coupled with a fabric filter simulator. The objective of this study is to provide fundamental kinetic data on the effect of flue gas variables including temperature, particle size, SO 2 concentration and stoichiometric ratio on removal of SO 2. A drop tube reactor with a fabric filter simulator was developed to simulate sorbent injection and sorbent particle capture. Trona was found to remove SO 2 from flue gas at efficiencies that were comparable to those of sodium bicarbonate under certain conditions. It was found that the different variables like temperature, SO 2 concentration and especially trona particle size have a very critical effect on removal efficiency. 2

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5 ACKNOWLEDGEMENTS I express my sincere thanks to my advisor Professor Tim Keener for providing me with this wonderful research opportunity. Without his guidance and encouragement I wouldn t have been able to complete my work. I would also like to thank Dr. Soon Jai Khang and Dr. Mingming Lu for agreeing to serve on my thesis committee. I would like to thank Mr. John Mazuik at Solvay Minerals for funding this project and providing all the trona samples. Special thanks to all members of the air quality group for all their help in completing my thesis. Finally, thanks to every one of my friends who made my stay at UC a wonderful and unforgettable experience. 4

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7 TABLE OF CONTENTS LIST OF TABLES ii LIST OF FIGURES iii 1. INTRODUCTION Problem Statement SO 2 background information Advantages of dry sodium-based sorbent injection Project Objectives 8 2. LITERATURE REVIEW Literature Overview 9 3. EXPERIMENTAL SETUP Entrained Flow Reactor Sorbent Feeder Operating Conditions Experimental Procedure RESULTS Effect of Particle Size on SO 2 Removal Effect of Temperature on SO 2 Removal Effect of Inlet Gas SO 2 Concentration on Overall SO 2 Removal 36 i

8 4.4 Effect of Stoichiometric Ratio on SO 2 Removal Model CONCLUSIONS AND FUTURE WORK REFERENCES 51 APPENDIX 1 EXPERIMENTAL DATA 53 APPENDIX 2 MODEL CALCULATIONS 63 APPENDIX 3 MODEL CALCULATIONS 66 ii

9 LIST OF TABLES Table 1. Flue gas composition 22 Table 2. List of Equipment 23 Table 3. T-200 particle size distribution 27 Table 4. T-200 : Mean mass diameter of particles 28 iii

10 LIST OF FIGURES Fig. 1. Schematic of a dry sodium injection system in a coal fired power plant. 8 Fig. 2. Comparison of nahcolite and trona (200 mesh, A/C : 2.3). 10 Fig. 3. Effect of trona particle size on SO 2 removal (A/C : 2.3). 11 Fig. 4. Variation of conversion with time (Temperature : 150 C, SO 2 concentration : 3500 ppm). 12 Fig. 5. Variations of conversion of spray dried soda with time at lower temperatures. 12 Fig. 6. SO 2 removal with trona (O : Pittsburgh seam coal(1.6 % S, 59 µm sorbent) ; : West Virginia coal(3.1 % S, 32 µm sorbent)). 13 Fig. 7. Results of a pilot plant dry scrubbing demonstration study using NaHCO Fig. 8. Comparison of SO 2 removal using trona and sodium bicarbonate. 16 Fig. 9. Effect of stoichiometric ratio on SO 2 removal. 17 Fig. 10. Comparison of sorbent costs. 17 Fig. 11. Drop tube reactor schematic. 19 Fig. 12. Drop Tube Reactor. 19 Fig. 13. Fabric Filter Simulator. 20 Fig. 14. Sorbent Feeder System. 21 Fig. 15. Conversion at different stoichiometric ratios (Temperature = 300 F ; Inlet SO 2 concentration = 500 ppm ; Particle Size = <38µ). 29 Fig. 16. Effect of particle size on conversion at different stoichiometric ratios (Temperature = 300 F ; Inlet SO 2 concentration = 500 ppm). 29 iv

11 Fig. 17. Comparison of conversion at a higher stoichiometric ratio. 30 Fig. 18. Comparison of conversion at a lower stoichiometric ratio. 30 Fig. 19. Conversion at different temperatures (Inlet SO 2 concentration : 500 ppm; stoichiometric ratio : 2-4). 32 Fig. 20. Conversion at different temperatures (Inlet SO 2 concentration : 500 ppm; stoichiometric ratio : 4-6). 33 Fig. 21. Conversion at different temperatures (Inlet SO 2 concentration : 500 ppm; stoichiometric ratio : 8-10). 33 Fig. 22. Conversion at different temperatures (Inlet SO 2 concentration : 1000 ppm; stoichiometric ratio : 3-6). 34 Fig. 23. Conversion at different temperatures (Inlet SO 2 concentration : 1000 ppm; stoichiometric ratio : 2-4). 34 Fig. 24. Conversion at different temperatures (Inlet SO 2 concentration : 1500 ppm; stoichiometric ratio : 2-4). 35 Fig. 25. Conversion at different temperatures (Inlet SO 2 concentration : 1500 ppm; stoichiometric ratio = 0-3). 35 Fig. 26. Effect of S0 2 inlet concentration on conversion (T : 250F, SR : 2-4). 36 Fig. 27. Effect of S0 2 inlet concentration on conversion (T : 325F, SR : 2-4). 37 Fig. 28. Effect of S0 2 inlet concentration on conversion (T : 350F, SR : 2-4). 37 Fig. 29. Comparison of utilization at two different inlet SO 2 concentrations (SR : 2-4). 38 Fig. 30. Utilization versus Temperature (Inlet SO 2 concentration : 500 ppm). 39 Fig. 31. Utilization versus Temperature (Inlet SO 2 concentration : 1000 ppm). 39 Fig. 32. Utilization versus Temperature (Inlet SO 2 concentration : 1500 ppm). 40 v

12 Fig. 33. Effect of stoichiometry on conversion (Temperature : 275 F; Inlet SO 2 concentration : 500 ppm). 41 Fig. 34. Effect of stoichiometry on conversion (Temperature : 300 F; Inlet SO 2 concentration : 500 ppm) 41 Fig. 35. Effect of stoichiometry on conversion (Temperature : 250 F; Inlet SO 2 concentration : 1500 ppm). 42 Fig. 36. Shrinking core of NaHCO 3 and varying exposure times of Na 2 CO Fig. 37. Pore plugging model fit (Inlet SO 2 concentration : 500 ppm). 46 Fig. 38. Pore plugging model fit with actual data (Inlet SO 2 concentration : 500 ppm). 46 Fig. 39. X versus temperature at different stoichiometric ratios (Inlet SO 2 concentration = 500 ppm). 47 Fig. 40. X versus temperature at different stoichiometric ratios (Inlet SO 2 concentration = 1500 ppm). 48 vi

13 1. INTRODUCTION 1.1 Problem Statement Sulfur dioxide (SO 2 ) is arguably the most important pollutant on EPA s list of six criteria pollutants and reduction in SO 2 emissions remains the main focus of EPA s strategy for cleaner air. SO 2 has been associated with health effects ranging from respiratory illnesses to acute and chronic heart and lung disorders. It is also a primary contributor to the formation of particulate matter and acid rain. Ever since the 1990 amendments to the clean air act that revamped air quality management in the United States, there has been a constant effort to research and determine not only economical but more effective technologies for the control of the criteria pollutants, especially SO 2. With an emphasis to build new power generation facilities, a majority of which would use coal, this has become all the more pertinent. FGD systems can be classified into wet limestone processes, semi-dry processes that include spray dry lime/limestone injection and dry processes that use sodium or calcium based sorbents. In the last few decades, dry flue gas desulfurization using sodium sorbents like sodium carbonate, sodium bicarbonate and trona has been identified to be a highly efficient process. Dry injection is advantageous because of the simplicity of the process and ease of retrofit with power plants already equipped with bag house filters. At the same time, it also solves disposal problems that are normally associated with wet FGD systems. There has been a lot of research done on the removal of SO 2 using sodium bicarbonate (NaHCO 3 ). Studies have shown that more than 90 % SO 2 removal can be achieved with sodium bicarbonate even at low stoichiometric ratios. On the contrary, very little work has been done to study SO 2 removal using trona. Trona is naturally occurring sodium sesquicarbonate with a chemical compositon as shown. 1

14 Chemical Formula: (Na 2 CO 3 NaHCO 3 2H 2 O) Composition: Molecular Weight = gm Sodium (Na) : % Hydrogen (H) : 2.23 % Carbon (C) : % Oxygen (O) : 56.63% The largest pure deposit of trona in the United States lies underground near Green River, Wyoming. T-200, which is a natural form of sodium sesquicarbonate, costs less than sodium bicarbonate and has been found to have removal rates of upto 90% for SO 2 [1]. It is currently being used in a variety of industries including utilities, municipal waste, chemical and cement plants. Selective research done on trona- SO 2 reaction has shown that SO 2 removal efficiencies at slightly higher stoichiometric ratios for sodium bicarbonate and trona are very similar. This is a potentially innovative and cost-effective method for desulfurization of flue gas. The problem is the lack of consistent data on the kinetics of the trona- SO 2 reaction. Without this kind of data it would be very difficult to arrive at a model for this reaction and to compare it with the sodium bicarbonate SO 2 reaction. 1.2 SO 2 Background information Sulfur dioxide or SO 2, belongs to the family of sulfur oxide gases (SOx). All raw materials, including crude oil, coal, and ore that contain common metals like aluminum, copper, zinc, lead, and iron have sulfur in them. SO 2 is formed as a result of combustion of fuel containing sulfur, such as coal and oil, during distillation of crude oil, or metal during 2

15 extraction. SO 2 dissolves in water vapor to form acid, and interacts with other gases and particles in the air to form particulate matter that can result in serious health and environmental problems [2]. Electric utilities, especially the ones using coal for combustion, are the primary sources of SO 2 releasing as much as 13 million tons every year, which is about 65 % of the total SO 2 released into the air. Other sources of SO 2 include industrial facilities that derive their products from raw materials like metallic ore, coal, and crude oil, or that burn coal or oil to produce process heat [3]. Petroleum refineries, cement manufacturing, and metal processing facilities, locomotives, large ships, and other diesel equipment are known to burn high sulfur fuel and release SO 2 emissions to the air in large quantities. SO 2 has been associated with a wide variety of health and environmental effects because of the manner in which it reacts with other gases and particles in the atmosphere. Effects range from temporary breathing difficulties to severe heart and lung problems. SO 2 contributes to the formation of particulate matter, which in turn result in increased respiratory symptoms and also reduce visibility. It also causes damage to crops and forests and aesthetic damage by formation of acid rain. The methodologies for SO 2 control can be classified into pre-combustion and postcombustion control. Pre-combustion techniques would deal with either fuel switching or coal pre-cleaning. Fuel switching is switching to a fuel with low sulfur content, from coal or oil to natural gas or renewables like wind or solar. For power plants, this would correspond to using low sulfur coal for the boilers. However the economics of availability and transportation of low sulfur coal have to be considered. More recently, utilities have started focusing on coal cleaning to remove sulfur to reduce acid-rain-related emissions. Coal-cleaning methods may be classified into conventional physical cleaning and various advanced cleaning methods, including advanced physical cleaning, aqueous phase pretreatment, selective agglomeration, and organic phase 3

16 pretreatment [4]. The total sulfur removal ranges 10 to 40 percent depending upon the method used. However in order to make coal cleaning cost effective, the cost and energy requirements involved have to properly balanced. The post-combustion control would mainly deal with Flue Gas Desulfurization technologies (FGD) [4]. FGD systems can be mainly classified into six broad categories. 1. Wet Scrubbers Wet scrubbers are the most widely used FGD technology for SO 2 control throughout the world. Calcium, sodium and ammonium-based sorbents are used in a slurry mixture, which is injected into a specially designed vessel to react with the SO 2 in the flue gas. The reactions taking place in a wet scrubber are normally simple but the resulting corrosion, congestion and waste disposal make them hard to handle in practical situations. The preferred sorbent in the operation of wet scrubbers is limestone followed by lime. These are favored because of their availability and relatively low cost. The overall chemical reaction, which occurs with a limestone or lime sorbent, can be expressed in a simple form as: SO 2 + CaCO 3 CaSO 3 + CO 2 Ca(OH) 2 + SO 2 CaSO 4 + H 2 O In Ammonia scrubbing the major reactions are : NH 3 + H 2 O NH 4 OH NH 4 OH + SO 2 NH 4 HSO 3 NH 4 HSO 3 + 1/2O 2 (NH 4 ) 2 SO 2 + SO 3 + H 2 O In this case ammonia bisulfite, which is a byproduct, presents disposal problems because of its acidity and corrosiveness. 4

17 2. Spray dry scrubbers Spray dry scrubbers are the second most widely used FGD technology. However, their application is limited to small or medium sized coal-fired power plants. Spray dry scrubbers in commercial use have achieved removal efficiency in excess of 90% with some suppliers showing more than 95% SO 2 removal efficiency as achievable. Spray dry scrubbers require the use of an efficient particulate control device such as an ESP or fabric filter. The sorbent usually used is lime or calcium oxide and is atomized/sprayed into a reactor vessel in a cloud of fine droplets. The SO 2 reacts with the hydrated lime to form a dry mixture of calcium sulfate / sulfite. Wastewater treatment is not required in spray dry scrubbers because the water is completely evaporated in the spray dry absorber. 3. Sorbent Injection Dry sorbent injection involves direct injection of the sorbent into the upper part of the furnace or the flue gas stream to react with the SO 2 forming sulfates of calcium or sodium which are later captured in a fabric filter. Sodium based compounds or commercially available limestone (CaCO 3 ) or hydrated lime (Ca(OH) 2 ) are used as sorbents. It is important to have an even distribution of the sorbent in the flue gas for higher removal efficiencies. Also, fine sorbent particle size (<5 µm) has been found to significantly improve the process performance. Typical reactions taking place in a sodium bicarbonate based dry sorbent injection system are: 2 NaHCO 3 Na 2 CO 3 + CO 2 + H 2 O 2 NaHCO 3 + SO 2 Na 2 SO 3 + 2CO 2 + H 2 O Na 2 CO 3 + SO 2 Na 2 SO 3 + CO 2 Na 2 SO 3 + ½ O 2 Na 2 SO 4 5

18 4. Dry Scrubber In this technology, a dry sorbent, mostly hydrated lime is injected into a circulated fluid bed or a moving bed to react with the SO 2 in the flue gas. The process achieves SO2 removal efficiency of 93-97% at a Ca/S molar ratio of Regenerable processes In regenerable processes, the sorbent is regenerated chemically or thermally and re-used. Regenerable processes generally require no waste disposal, produce little waste water and have low sorbent make-up requirements. Although these processes can achieve high SO 2 removal efficiencies (>95%), they have in general high capital costs and power consumption. 6. Combined SO 2 /NOx removal Combined SO 2 /NO x removal processes are considered fairly complex and costly. However, emerging technologies have the potential to reduce SO 2 and NO x emissions for less than the combined cost of conventional FGD for SO 2 control and selective catalytic reduction (SCR) for NO x control. Most processes are in the development stage, although some processes are commercially used on low to medium-sulphur coal-fired plants. 1.3 Advantages of dry sodium-based sorbent injection Some of the advantages associated with the use of dry sodium-based sorbents for flue gas desulfurization are [5]: Significantly lower capital costs because of the removal of SO 2 and particulate matter in a single device. 6

19 Lesser maintenance due to the simplicity of the process and ease of retrofit for utilities already equipped with particulate control devices. In most cases the byproduct is dry. Hence, ease of disposal and minimal scaling and corrosion. Lower operating and maintenance costs because of high conversion of the sorbents resulting in a high-value byproduct. Reasonably high NOx removal can be achieved simultaneously by the reaction of NO with sodium bicarbonate to form solid products. Unlike calcium based sorbents, sodium sorbents exhibit high removal efficiencies over a wide range of temperatures (250 F- 900 F). These advantages make sodium injection for FGD very attractive and the utility industry is paying an increased attention to this technology. There are several small scale and a few fullscale commercial applications in practice. Among the various sodium-based sorbents, sodium bicarbonate has been associated with the highest SO 2 removal. Although the cost of sodium bicarbonate is much higher when compared to lime/limestone, higher utilization still makes it attractive. The only concern is the brown plume resulting from the formation of NO 2, which can be taken care of by addition of certain chemical additives. Fig. 1. shows a schematic of a typical sodium based dry sorbent injection system in a coal fired power plant. 7

20 Fig. 1. Schematic of a dry sodium injection system in a coal fired power plant [5]. 1.4 Project Objectives The objective of this project was to identify and study the process parameters that influence the SO 2 removal ability of trona. An entrained flow reactor coupled with a fabric filter simulator was used to study the effect of various variables like temperature, flue gas concentrations and stoichiometric ratio on this reaction. Additional consideration was given for future studies on the effect of moisture content, filter air-cloth ratio and trona particle size. Kinetic data based on these variables could be used to model the reactions taking place between trona and SO 2 in a dry sorbent injection system. 8

21 2. LITERATURE REVIEW 2.1 Literature Overview Studies performed over the last century have confirmed that materials containing sodium are bound to be much more effective in removing SO 2 from flue gas when used as sorbents in dry injection when compared to materials containing calcium and magnesium. Most of this research has been performed on sodium bicarbonate, and there is very little published information on the reactivity of trona with SO 2. This can be attributed to the thought that the behavior of trona is more or less similar to that of sodium bicarbonate stoichiometrically, because of the similarities in their chemical composition. In 1981, EPRI undertook an experimental study to characterize a process designed to remove SO 2 by injecting two dry sodium-based sorbents namely trona and nahcolite, which is naturally occurring sodium bicarbonate [6]. The reactions took place in pulverized coal-fired combustor that used a low-sulfur western coal at baghouse temperatures ranging from F, air to cloth ratio between 1 and 4, and inlet SO 2 concentration between ppm. They studied the effect of nahcolite net stoichiometric ratio (NSR) on SO 2 removal for both continuous injection and batch feeding. For continuous injection the SO 2 removal was 67% at a NSR of 1 and upto 90% when the NSR was increased above 1.5. Batch feeding also produced similar results but the injection system was much more complex. They also observed that there was a time lag between the injection of nahcolite and the drop in the outlet SO 2 concentration. It was also found that removal increased with decreasing particle size and was not influenced by increase in air to cloth ratio. They found the behavior of trona to be different than that of nahcolite. With trona, the SO 2 removal was almost immediate with essentially no time lag until the outlet SO 2 reached a steady state concentration. Trona removed SO 2 at an efficiency of 40% at an NSR of 1 and about 57% at an NSR of 2. On the contrary, nahcolite had almost 90% removal at an NSR of 2 as shown on Fig. 2. 9

22 Fig. 2. Comparison of nahcolite and trona (200 mesh, A/C : 2.3) [6]. Unlike nahcolite, the baghouse temperature did have an influence on SO 2 removal with trona. As with nahcolite, the variation in air to cloth ratio did not have any significant influence on the reaction. It was also found that particle size had a very significant effect on SO 2 removal using trona. Fig. 3. compares SO 2 removal efficiencies for three different trona particle sizes. 10

23 Fig. 3. Effect of trona particle size on SO 2 removal (A/C : 2.3) [6]. In 1982, Keener and Davis performed a study to compare the reactivities of trona and sodium bicarbonate in a differential fixed-bed reactor [7]. The results indicated that trona had better reactivity than sodium bicarbonate on average. It was concluded that gas temperature and particle size had a very significant impact on the utilization of the sorbent and the overall SO 2 removal, especially for trona. In 2000, Guldur and Dogu studied the reaction of activated soda, produced by decomposition of trona, with SO 2 [8]. The activated soda was generated by employing two different procedures - spray drying of trona solution and direct calcinations of trona particles, forming activated trona. A two-stage behavior was observed for both samples but was more significant for the activated trona. This two-stage behavior was also found to be more significant at lower temperatures as shown in Fig. 4. and 5. At low temperatures, adsorption of SO 2 followed by surface reaction becomes more significant than direct conversion of Na 2 CO 3 to Na 2 SO 3. This 11

24 along with textural variations of the solid are the two main reasons for the two-stage behavior. The authors developed a deactivation model that gave satisfactory results in the prediction of experimental results for this reaction. Fig. 4. Variation of conversion with time (Temperature : 150 C, SO 2 concentration : 3500 ppm) [8]. Fig. 5. Variations of conversion of spray dried soda with time at lower temperatures [8]. In , the department of utilities at the City of Colorado Springs, FMC corporation and EPRI conducted a full-scale demonstration of the injection of dry sodium sorbents, namely sodium sesquicarbonate and sodium bicarbonate [9]. Sodium sorbents were injected upstream of one of the fabric filters, side-by-side with an identical fabric filter operating without sorbent injection. The objective of the study was to run the plant boiler continuously for 55 days with sodium injection and to determine the SO 2 removal and sodium utilization. The results showed 12

25 that the system averaged almost 74% SO 2 removal with 56% sodium utilization over the entire period of operation as seen in Fig. 6. At the same time, a NO X removal of about 23% was achieved. The sodium sesquicarbonate injection also resulted in a significant reduction in the flue gas pressure drop across the fabric filter. It was concluded that the distribution of the sorbent in the flue gas stream was critical in achieving maximum sorbent utilization. Fig. 6. SO 2 removal with trona (O : Pittsburgh seam coal(1.6 % S, 59 mm sorbent) ; D : West Virginia coal(3.1 % S, 32 mm sorbent)) [9]. Thermal decomposition kinetics of sodium bicarbonate [16] is what governs the reaction of SO 2 with both trona and sodium bicarbonate. Keener and Khang developed a parallel reaction path model to explain the reaction between sodium bicarbonate particles and SO 2 [10]. They concluded that the bicarbonate reacts directly with SO 2 at temperatures below which thermal decomposition occurs but at higher temperatures, it decomposes to form sodium carbonate, which then reacts with SO 2 to form the final product. The following chemical reactions could be used to explain this parallel path reaction behavior in the trona SO 2 reaction as well. 13

26 Na 2 SO 3 + CO 2 +H 2 O --- path1 NaHCO 3 Na 2 CO 3 + CO 2 + H 2 O SO 2 {Na 2 CO 3 NaHCO 3 2H 2 O} Na 2 SO 3 + CO 2 +H 2 O --- path 2 (trona) Na 2 CO 3 CO 2 + H 2 O K d2 K d1 SO 2 SO 2 K d3 K 3 K 1 K 2 Na 2 SO3 + CO 2 + H 2 O --- path 3 The sodium carbonate micro-grains formed in this manner have very high specific surface area and result in high level of conversion. Hence the overall reaction can be described as a multipath reaction. For the development of the model, it was assumed that as the reaction progresses, a shrinking boundary of sodium bicarbonate exists, and at this boundary, micrograins of the reaction products, namely sodium sulfite and sodium carbonate are produced. The overall conversion is the summation of the conversions resulting from paths 1 and 2 and the reaction kinetics of these 2 paths are derived separately. The model is developed based on the assumption that the bicarbonate is almost non-porous, path 1 is a first order reaction and that a semi-empirical pore plugging model can be used for path 2 which is a zero order reaction. The model was found to be in agreement with kinetic data published earlier. The authors concluded that this model could be used to give a reasonably good prediction of the behavior of sodium bicarbonate particles during their reaction with SO 2 in flue gas. 14

27 Fig. 7. Results of a pilot plant dry scrubbing demonstration study using NaHCO 3 [10]. Wu, Keener and Khang proposed a mathematical model for simulation of dry sodium bicarbonate injection for SO 2 removal across a fabric filter [10]. They found out that SO 2 removal took place in two stages- within the duct section and across the fabric filter and developed a twostage model on these lines. In the duct section, its was assumed that the particles were in a monodisperse mode, axial diffusion was negligible when compared to the convective flow for the flue gas and the solid particles. With a plug flow for both gas and solid and a mass balance on the SO 2, a mathematical expression was arrived at for the duct section. For the fabric filter section, a pseudo steady-state assumption is used for the height of the particle buildup on the filter. By doing a mass balance on the sorbent, the height of the sorbent layer is calculated. A final mathematical expression is derived by performing a mass balance on the SO 2. It was found that SO 2 removal predominantly occurs across the filter (95%) and only a small fraction (5%) is 15

28 removed in the duct section. The model has also been used to discuss the effects of operating parameters like temperature, stoichiometric ratio, particle size and SO 2 concentrations on removal efficiency and these results were validated with published test data. Experiments performed by Solvay Minerals at their Central Study and Research Center [11] have shown that at temperatures over 250 F, trona is rapidly calcined to sodium carbonate by means of the following reaction, resulting in a popcorn like crystal structure change that creates a large and reactive surface for adsorption and neutralization of acidic gases like SO 2. 4{Na 2 CO 3 NaHCO 3 2H 2 O} 6 Na 2 CO CO H 2 O This increase in surface area has been found to be as high as 20 times the original surface area. At higher stoichiometries around 1.8-2, the behavior of trona and nahcolite is almost similar as shown in Fig. 9. Fig. 8. Comparison of SO 2 removal using trona and sodium bicarbonate [11] The effect of trona particle size on SO 2 removal is shown in Fig. 10. with almost 90% removal at a particle size of around 11 microns. 16

29 Fig. 9. Effect of stoichiometric ratio on SO 2 removal [1] The following figure shows how the economics of the various dry sorbents compare. Trona is found to be significantly cheaper when compared to sodium bicarbonate. Fig. 10. Comparison of sorbent costs [1] 17

30 3 EXPERIMENTAL SETUP 3.1 Entrained Flow Reactor A drop tube reactor system (Fig. 13 and 14) was developed for the purpose of studying the reaction between SO 2 and trona. The actual test concentrations of SO 2, CO 2, NO 2, NO and H 2 O to be used for the baseline tests were first determined. These concentrations were based on the combustion data for Colorado seam B coal. A known concentration of these gases was injected by means of individual cylinders into a manifold where these constituent gases mixed to simulate the flue/reactant gas. There are two streams of gases to the reactor system, the stream on the right-hand-side is the flow of carrier gas whereas the other contains reactant gases. Sorbent particles are fed into the carrier gas by means of a sorbent feeder system. The reactant gases traveled a 10.5 feet long duct, 0.5 inches diameter before entering the reaction chamber. The carrier gas duct was 6 feet long. All the ductwork was heated to simulate actual flue gas conditions by means of band heaters, the temperatures on which could be easily adjusted. Steam was fed at a known rate by injecting water by means of a calibrated syringe pump and by heating the feed line with a furnace heater, the rate of heating on which could be manually controlled. 18

31 Fig 11. Drop tube reactor schematic Fig. 12. Drop Tube Reactor 19

32 Fig. 13. Fabric Filter Simulator The reactant gas and the sorbent particles come into contact inside the venturi where by virtue of turbulence, they are well mixed with the gases before entering the reaction chamber. The entrained flow reaction chamber is a stainless steel tube 3 ft in height and 2 inches in diameter. A constant temperature can be maintained in this reaction chamber by means of a Lindberg 3 zone-heating furnace by manually adjusting the three individual heating zones. This first stage reaction chamber is used to simulate sorbent injection where the sorbent particles are in a dispersed mode. Immediately below the entrained chamber is the fabric filter simulator that is a cylindrical metallic container 1 ft high and 1 ft wide as shown in Fig. 15. A filter made of NOMEX fiber, 9 diameter was used for collecting the reaction byproducts. The fabric filter 20

33 simulator also consists of thermocouples, static pressure taps, flanges for disassembly and clamp heaters for maintaining the test temperatures. 3.2 Sorbent Feeder The sorbent feeding system as shown in Fig. 15., runs on a variable speed DC motor, a turning plate with three grooves, a hopper for loading the sorbent particles and an aspirator for delivering the particles into the reactor. The turntable feeder had three grooves of different sizes and had provisions for changing the speed of rotation. By setting the rotational speed and by selecting the appropriate groove, a wide range of sorbent feeding rates could be maintained over a long period of time Fig. 14. Sorbent Feeder System 21

34 3.3 Operating Conditions Once the desired temperature is reached inside the fabric filter simulator, known concentrations of the reactant and carrier gases (Table 1.) are injected through calibrated flowmeters. Sorbent injection takes place only after a steady state SO 2 concentration is achieved. Most of the SO 2 in the reactant gas is converted to solid sodium sulfate, which is retained on the filter. As a result, the flue gas coming out of the fabric filter simulator has a significantly lower SO 2 concentration. Table. 2. lists all the equipment utilized in this study. A gas conditioning unit was used downstream of the fabric filter to remove any moisture from the gas before the gas sample reaches the analyzers. A single component infrared gas analyzer was used to measure the SO 2 concentration coming out of the reactor. The analyzer was calibrated with appropriate span and zero gas before each experiment. A portable Nova gas analyzer was used to measure the percentage of CO 2 and O 2 in the outlet gas stream. All gas and temperature data was stored on a computer through the data acquisition system. The data was then transferred to an excel spreadsheet for plotting and comparison of results. Table 1. Flue gas composition Percentage Flow rate(scfh) N CO SO O H 2 O

35 3.4 Experimental Procedure A basic stepwise experimental procedure to run a test is shown below: 1. The data acquisition system is turned on in order to view the inlet gas concentrations and system temperatures at different points. 2. The reactor system is preheated to the required temperature by turning on the Lindberg 3- zone heating furnace and by adjusting the settings on the controller. 3. The flue gas duct is preheated by turning on the two furnace heaters and setting the controller to the required temperature. The controllers on the band heaters around the duct are also adjusted to the right temperature. 4. A fresh filter cut out to the right dimensions is placed inside the fabric filter simulator. 5. The fabric filter section is also heated to the right temperature by turning on the respective controller. 6. The SO 2 analyzer is now calibrated by following the procedure shown below. 7. The gas conditioning unit along with the pumps upstream and downstream of the unit are turned on. 8. The exhaust system is now turned on before injection of any gas takes place. 9. After approximately two hours of preheating, the different gases namely air, CO 2 and nitrogen are injected into the system at already determined flowrates. 10. Steam is injected into the system by turning on the syringe pump and adjusting to arrive at the right settings. 11. The overall system temperature is adjusted again to account for the temperature change because of the gas flow. 12. Pure SO 2 is now injected into the system at the predetermined rate. 23

36 13. The flow rate is adjusted on the flowmeter till the SO 2 concentration reaches the required test concentration. 14. The system temperature and SO 2 flowrate are fine tuned to be as close to the required test conditions as possible. 15. The data acquisition system is brought to the save mode thereby allowing the user to save all the data till the end of the experimental run. 16. The system conditions are maintained till steady state conditions are reached. 17. The sorbent feeder system is checked for calibration by measuring the turn table rotational speed. Trona is now injected through the sorbent feeder system by selecting the appropriate groove and corresponding rotational speed. 18. The dilution effect due to pulling in of atmospheric air is taken into account. 19. The different system parameters like temperature at various points, sorbent feed rate are monitored during the duration of the test and necessary adjustments made. 20. The pressure drop across the filter is monitored periodically. 21. The experimental run is continued until the outlet SO 2 concentration decreases to a constant value. 22. Once a steady state outlet concentration is achieved, logging of data on the system is discontinued. 23. The system is now shut down systematically and is allowed to cool. 24. The filter cloth is now removed from the system for analysis. Calibration of the Gas Analyzer The SO 2 analyzer that works on the non-destructive infra-red principle (NDIR), is calibrated by following the simple procedure given below: 1. Power the unit on and adjust the knob to the correct range setting. 24

37 2. Turn on the supply of the zero gas (NO) and adjust the zero knob till the display shows 0 ppm and is steady. 3. Cut the supply of the zero gas and open the regulator on the span gas. 4. Adjust the span knob till the display shows the right SO 2 concentration. 5. Turn off the supply of span gas and turn on the supply of zero gas. Check if it the display goes back to 0 ppm, otherwise adjust accordingly. 6. Repeat the above steps till the analyzer displays consistent concentration values. Table 2. List of Equipment. Instrument Manufacturer Model Number Serial Number 1. SO 2 gas analyzer California 100 1M12005 Analytical Instruments 2. Data Acquisition System Superlogics Inc. 8017, 8018 input modules 3. Gas Dryer IMR Inc. IMR 400 H Three zone heating furnace Lindberg Reactor temperature Lindberg controller 6. Furnace heaters Lindberg Turn table motor Marathon electric SJ92M68W manufacturing co. 8. Syringe pump Sage instruments Trolley jack Central Hydraulics 619S Inc. 10. Outlet gas pump Thomas Industries 2107CA18TFEL-A Inc. 11. Sorbent feeder vibrator Vibco Inc. SPR

38 4 RESULTS Based on the results obtained from carrying out the reaction between SO 2 and trona in the entrained flow reactor, the effects of various operating conditions on SO 2 removal are evaluated. The major parameters in any dry FGD process are temperature, inlet SO 2 concentration, stoichiometric ratio of the sorbent to SO 2 and sorbent particle size. For a better understanding of the comparison of results at different operating conditions, the results have been presented as a series of charts. According to Keener et al [15], removal of SO 2 takes place in two stages, one within the duct section and the other in the bag house filter. In the duct section, the residence time of the particles is very small and generally varies between 1 to 2 seconds. This does not give enough time for the particles to decompose and hence contribution of the duct section towards SO 2 removal is almost negligibly small when compared to the removal in the baghouse. Also within the duct, smaller particles show higher removal efficiency. It was found that at higher temperatures, the removal is increased for a short period of time. However, the final removal is a combined result of both temperature and particle size. It is the baghouse filter where the primary SO 2 removal occurs, where the particles accumulate on the surface of the bag filter and react with the SO 2 in the flue gas in a continuous manner. The SO 2 removal is considered to be a very dynamic process and the reaction between SO 2 and sorbent particles at different positions along the particle layer is considered. However after a certain period of operation, the SO 2 removal reaches a steady state. 4.1 Effect of Particle size on SO 2 removal Previous studies dealing with SO 2 removal using dry sorbent injection have demonstrated that removal of SO 2 increases with the decrease in particle size. This can be mainly attributed to 26

39 the fact that the active surface area for smaller particles is much larger in comparison to bigger particle sizes under the same stoichiometric conditions. Also the time for smaller particles to reach steady state is much shorter than for larger particles because the time required for particles to decompose decreases with size. The diffusion of SO 2 into the particles governs this reaction. According to Keener and Khang [10], the initial sodium bicarbonate is considered to be a nonporous solid particle and pores are formed as a result of removal of CO 2 and water vapor from the solid matrix. This decomposition process not only provides a path for further reactions but also results in a large amount of freshly formed active area. Hence, another possible reason for high reactivity is that the diffusion resistance for SO 2 is relatively smaller for particles with a smaller size when compared to larger particle sizes where the pore structure becomes more complex. To study the effect of particle size on the trona- SO 2 reaction, tests were run on two different types of trona - one with particles passing through 38 micron sieve and the other being the T-200 trona. Results of sieve analysis showed that the mean mass diameter for T-200 particles was around 41 microns as shown in Table 2 and 3. Table. 3. T-200 particle size distribution Sieve Opening Typical weight percent < 70 µm 75 < 28 µm 50 < 6 µm 10 On the smaller sized trona, tests were run at an inlet SO 2 concentration of 500 ppm and a temperature of 300F and at three different stoichiometric ratios. Fig. 15. shows the conversions for the finer trona at three different stoichiometric ratios. It can also be observed that the conversion is higher at higher stoichiometries. 27

40 From Fig. 16., it can be clearly seen that the conversion for the smaller particle size is higher when compared to the conversion for T-200 at all three stoichiometric ratios. Figures 17. and 18. compare conversions between T-200 and finer trona at a lower and a higher stoichiometry. When compared to T-200, the conversion for the finer particle size trona is significantly higher. Table. 4. T-200 : Mean mass diameter of particles Size range (µm) Weight % Mean Diameter(µm) Wt % * MD < ~ ~ > MMD (µm)

41 Fig. 15. Conversion at different stoichiometric ratios (Temperature = 300 F ; Inlet SO 2 concentration = 500 ppm ; Particle Size = <38µ) conversion SR time (s) Fig. 16. Effect of particle size on conversion at different stoichiometric ratios (Temperature = 300 F ; Inlet SO 2 concentration = 500 ppm) Conversion Particle Size <38µ T Stoichiometric Ratio 29

42 Fig. 17. Comparison of conversion at a higher stoichiometric ratio Conversion Particle Size <38 micron(sr:6.2) T-200(SR:5.2) time (s) Fig. 18. Comparison of conversion at a lower stoichiometric ratio Conversion Particle size <38 micron(sr : 2.9) T-200(SR : 2.36) time (s) 30

43 4.2 Effect of Temperature on SO 2 removal Temperature has a very crucial effect on the overall desulfurization process. Fig. 19 through 25 show some of the typical results at different temperatures. The plots show the variation in conversion with temperature within the first 600 seconds of trona injection. Tests have been conducted at five different temperatures to study the effect of temperature on SO 2 removal. The temperatures ranged from 250 F to 350 F. Generally, upto a certain temperature, the conversion increases with temperature and then drops back and finally increases again. However this trend is not true for all stoichiometric ratios and inlet gas concentrations as seen from the plots. It can be seen from the plots that in most cases the conversion drops as the temperature increases from 250 F to around 275 F and then starts to increase with temperature upto 300 F. Conversion drops as the temperature reaches around 325 F followed by another increase in most cases as the temperature reaches 350 F. At lower temperatures, the desulfurization reaction proceeds during and after the sodium bicarbonate decomposition. Since the reaction proceeds at a lower rate, there is more time for the reaction to occur and hence higher removal of SO 2 before pore closure occurs. Freshly formed sodium carbonate becomes available at the right rate for the reaction to proceed. At higher temperatures, the reaction reaches the final removal rate at a very short period of time due to the quick decomposition and quicker build up of decomposition byproduct resulting in pore plugging and closure at outside surface of the particle. As a result, it becomes very difficult for the SO 2 to penetrate the unreacted core of the decomposition product. The primary reason for pore plugging is the molar volume difference between the initial sodium carbonate (42.25 cm 3 /mol) and the final product sodium sulfate (53.16 cm 3 /mol). It can also be observed that the time to reach steady state reduces with increase in temperature. According to Chungfa wu [5], the time to reach steady state depends on particle size and system temperature instead of flue gas concentration. 31

44 It is observed that for this type of a system, which can be considered as a combined sytem of duct and filter house, there exists a temperature at which the SO 2 removal is the highest. This effect is interestingly different from that of sodium carbonate, which always displays a higher conversion with increasing temperature. According to Keener and Davis, there exists a temperature at which the release of CO 2 and water vapor from the decomposing particle is just at the right rate to allow maximum counter-diffusion of SO 2 into the inner particle for further reaction. However studies have shown this optimum temperature to be a function of the particle size and hence, the particle size has to be taken into consideration before making any conclusions. Fig. 19. Conversion at different temperatures (Inlet SO 2 concentration : 500 ppm; stoichiometric ratio : 2-4) Conversion 0.2 Temperature 250 F 275 F 300 F 325 F 350 F Time (s) 32

45 Fig. 20. Conversion at different temperatures (Inlet SO 2 concentration : 500 ppm; stoichiometric ratio : 4-6) Conversion Temperature 250 F 275 F 300 F 325 F 350 F Time Fig. 21. Conversion at different temperatures (Inlet SO 2 concentration : 500 ppm; stoichiometric ratio : 8-10) Conversion Temperature 250 F 275 F 300 F 325 F 325 F Time (s) 33

46 Fig. 22. Conversion at different temperatures (Inlet SO 2 concentration : 1000 ppm; stoichiometric ratio : 2-4) Conversion Temperature 250 F 275 F 300 F 325 F 350 F Time (s) Fig. 23. Conversion at different temperatures (Inlet SO 2 concentration : 1000 ppm; stoichiometric ratio : 3-6) Conversion Temperature 250 F 275 F 300 F 325 F 350 F Time (s) 34

47 Fig. 24. Conversion at different temperatures (Inlet SO 2 concentration : 1500 ppm; stoichiometric ratio : 0-3) Conversion 0.1 Temperature 250 F 300 F 325 F Time (s) Fig. 25. Conversion at different temperatures (Inlet SO 2 concentration : 1500 ppm; stoichiometric ratio : 2-4) Conversion 0.2 Temperature 250 F 275 F 300 F 325 F 350 F Time (s) 35

48 4.3 Effect of Inlet Gas SO 2 Concentration on overall SO 2 removal Apart from the temperature, SR and particle size, inlet SO 2 Concentration also has an influence on the overall SO 2 removal. From the results, it can be seen that increase in the inlet SO 2 concentration enhances the reaction and hence increases the overall SO 2 removal. Tests run at three inlet SO 2 Concentrations namely 500 ppm, 1000 ppm and 1500 ppm have shown that the conversion is highest for 1500 ppm at the same temperature and SR. Figures 26. through 28. show the effect of inlet SO 2 concentration on conversion at different temperatures. Studies have shown that the effect of inlet SO 2 concentration is more pronounced for trona / sodium sesquicarbonate than for sodium bicarbonate. According to Chungfa Wu [5], the concentration has a direct effect on the pore plugging time constant which inturn has a critical effect on conversion. Hence, inlet SO 2 Concentration has an indirect effect on the overall desulfurization process. Fig. 26. Effect of S0 2 inlet concentration on conversion (T : 250F, SR : 2-4) Conversion Inlet SO2 concentration 500 ppm 1000 ppm 1500 ppm Time (s) 36

49 Fig. 27. Effect of S0 2 inlet concentration on conversion (T : 325F, SR : 2-4) Conversion 0.2 Inlet SO2 concentration 500 ppm 1000 ppm 1500 ppm Time (s) Fig 29. compares the sorbent utilization for two different inlet SO 2 concentrations. It is very clear that the sorbent utilization at the higher inlet gas concentration is higher. Fig. 28. Effect of S0 2 inlet concentration on conversion (T : 350F, SR : 2-4) Conversion Inlet SO2 concentration 500 ppm 1000 ppm 1500 ppm Time (s) 37

50 Fig. 29.Comparison of utilization at two different inlet SO 2 concentrations (SR : 2-4) Utilization (%) Inlet SO 2 concentration 500 ppm 1500 ppm Temperature (F) Figures 30. through 32. show the variation in utilization with temperature and stoichiometry at three different inlet gas concentrations. It is very difficult to establish a trend for utilization versus temperature and inlet SO 2 concentration as it exhibits a sinusoidal behavior. However it can be said with certainty that the utilization of trona increases with increase in stoichiometry. 38

51 Fig. 30. Utilization versus Temperature (Inlet SO 2 concentration : 500 ppm) Utilization (%) 10 0 SR Temperature (F) Fig. 31. Utilization versus Temperature (Inlet SO 2 concentration : 1000 ppm) Utilization (%) SR Temperature (F) 39

52 Fig. 32. Utilization versus Temperature (Inlet SO 2 concentration : 1500 ppm) Utilization (%) SR Temperature (F) 4.4 Effect of Stoichiometric Ratio on SO 2 removal Stoichiometric ratio corresponds to the amount of trona injection at a certain inlet SO 2 concentration at a given flue gas flow rate. The following plots show the results from tests run at different stoichiometries for the same inlet SO 2 concentration and temperature. It is easy to conclude that as the stoichiometry increases, SO 2 removal also increases, irrespective of the other factors like temperature, particle size and inlet SO 2 concentration. From Figures 33. through 35., it can be seen that this trend holds for different temperatures and inlet SO 2 concentrations. Theoretically at a net stoichiometric ratio (NSR) of 1, the removal or conversion should be 100 %. However this is not practically possible because of the reaction efficiency, particle behavior and other factors. 40

53 Fig. 33. Effect of stoichiometry on conversion (Temperature : 275 F; Inlet SO 2 concentration : 500 ppm) Conversion SR Time (s) Fig. 34. Effect of stoichiometry on conversion (Temperature : 300 F; Inlet SO 2 concentration : 500 ppm) Conversion SR Time (s) 41

54 Fig. 35. Effect of stoichiometry on conversion (Temperature : 250 F; Inlet SO 2 concentration : 1500 ppm) SR Model While selecting a model for the progress of any gas-solid reaction, it is important to understand that every model comes with its own set of mathematical expressions and it should be able to closely predict and describe the actual kinetics of the reaction. The two main types of models used for prediction of gas-solid reactions are unreacted core and the pore plugging model [12] Unreacted core Model According to the unreacted core model, the reaction first occurs at the outer skin of the particle and the zone of reaction eventually moves into the solid leaving behind completely converted material and inert solid. The gas first diffuses through the film surrounding the particle to the surface of the solid which is followed by penetration through the blanket of ash to the surface of the unreacted core. 42

55 Fig 36. Shrinking core of NaHCO 3 and varying exposure times of Na 2 CO 3 [10] This is when the actual gas solid reaction takes place followed by diffusion of gaseous products through the ash back to the exterior surface of the solid and eventually through the gas film back into the main gas stream. There are three major types of resistances to this reaction and they have their own set of mathematical expressions. 1. Diffusion through gas film controls t τ rc = 1 R 3 = XB 2. Diffusion through ash layer controls t τ rc = 1 = 1 B R ( 1 X ) 1/ 3 3. Chemical reaction controls t = τ ( 1 X ) 2/ 3 1 B 43