Fuels, Combustion, and Flue Gas Analysis PDF

Fuels, Combustion, and Flue Gas Analysis • Chapter 3 7® OBJECTIVE 12 Explain the formation, monitoring, and control of nitrogen oxides (NOy), sulfur dioxide (SO^, and particulates. NITROGEN OXIDES When fuels burn, nitrogen may combine with oxygen to produce nitrogen oxides (N0^) as products of co...

Fuels, Combustion, and Flue Gas Analysis • Chapter 3 7® OBJECTIVE 12 Explain the formation, monitoring, and control of nitrogen oxides (NOy), sulfur dioxide (SO^, and particulates. NITROGEN OXIDES When fuels burn, nitrogen may combine with oxygen to produce nitrogen oxides (N0^) as products of combustion. These oxides are composed primarily of nitrogen monoxide (NO) and nitrogen dioxide (N02). More than 90% of the N0^; is nitrogen monoxide (NO). However, calculated concentrations of N0^ are normally expressed as nitrogen dioxide (N02). Nitrogen oxides (N0^;) are considered a pollutant and a greenhouse gas. These oxides are becoming increasingly regulated as a stack emission. The concentration of nitrogen oxides are also relevant to the operation of burners, particularly where the burners are specially designed for N0^; control (low-NO^ burners). In that respect, the measurement of N0^: may be included in the flue gas analysis program. NOx Formation The nitrogen in N0^ may originate from atmospheric air, in which case the combustion products are known as prompt N0^;. The nitrogen may also be a chemically bound component of fuels, such as oils and coals, in which case the products are known as fuel N0^. Nitrogen oxides that are a result of very high combustion temperatures are called thermal N0^. The amount of N0^ that forms is dependent on the following factors: • Temperature • Time for reaction • Mmng • Amounts of nitrogen and oxygen available Thermal N0^ is rapidly formed when the combustion temperatures exceed 1500°C. Tliermal N0^; is the predominant form of N0^ when natural gas or other fuels with low nitrogen content are burned. Fuel N0^; is dependent on the nitrogen content and volatility of the fuel. Fuel N0^: is the predominant form (up to 85%) of N0^; when the fuels burned are high in organically-bound nitrogen. 3rd Class Edition 3 • Part A2 169 r®- Chapter 3 • Fuels, Combustion, and Flue Gas Analysis NOx Control When the N0^ measurement falls outside the allowable limits, the burner operation is impacted. The operator must adjust the N0^ control components of the burner, such as the amount of injection steam, the flue gas recirculation, or both. These adjustments may also affect the combustion efficiency and other gas readings of the flue gas analysis. N0^ can be controlled in the following two locations: • In the combustion zone • After the combustion zone The former reduces the production of N0^, while the latter removes N0^ that has already been produced. The amount of N0^: produced in the combustion zone can be controlled by the following methods: • Restricting the amount of excess air used in combustion • Reducing the temperature in the combustion zone Two-stage combustion supplies less air to the burners than the air that is theoretically required for complete combustion. Additional overfire air is supplied above the main combustion area to complete the combustion process. Reburning is a NO^-reducing strategy that involves the staging of both the air and the fuel in the combustion process. Reburning reduces both the combustion temperature and the amount of oxygen present in the combustion zone. Flue gas recirculation for the reduction of thermal N0^ involves the recirculation of a percentage of the flue gas back to the burner. The control of N0^ in the combustion process requires specific designs of burners and furnaces. NOjc control after the combustion zone may be accomplished using either a non-catalytic or a catalytic process. Non-Catalytic Control ofNOx The non-catalytic control of nitrogen oxides (N0^) uses a process called selective non-catalytic reduction (SNCR) in which the chemicals select the NOjc to react with, rather than selecting other impurities. SNCR units are used in many industries and applications across a wide range of boiler designs and burning of a variety of fuels. These boiler designs include process incinerators and heaters, municipal solid waste burners, and glass furnaces. SNCR is most effective in applications where furnace residence time exceeds one second, combustion N0^ levels are relatively high, and furnace exit temperatures are in a specific temperature range. Selective non-catalytic reduction involves the injection of a N0^ reducing agent, such as ammonia or urea, into the upper furnace or convective pass of a boiler. This is done within a specific temperature range of about 870°C-HOO°C (1600°F-2000°F). This method avoids the use of an expensive catalyst. The ammonia or urea breaks down the N0^ in the exhaust gases to water and atmospheric nitrogen. Selective non-catalytic reduction can reduce N0^; up to 70%. However, non-catalytic reduction must be applied within a specified temperature range. This method of N0^ control is not as effective in industrial boilers that modulate or cycle frequently since the location of the exhaust gases at the specified temperature range is constantly changing. Therefore, selective non-catalytic reduction is not generally used in boilers that have high turndown capabilities and modulate or cycle frequently. 170 3rd Class Edition 3 • Part A2 Fuels, Combustion, and Flue Gas Analysis • Chapter 3 T® Figure 14 shows a system for the catalytic and non-catalytic removal of N0^;. This system includes a compressed-air carrier system, ammonia or urea storage, and injection system. The liquid ammonia is fed to a vaporizer where it is vaporized and then mixed with the carrier before entering the injectors. The system shown in the schematic injects the ammonia into the upper part of the furnace for the non-catalytic reduction, and into the exhaust gas stream near the stack for the catalytic reduction. For both systems, the reduction reactions are as follows: Nitrogen oxide + Ammonia + Oxygen -> Nitrogen + 4NO 4NH. 0, -> 4N, Water 6H20 Nitrogen dioxide + Ammonia + Oxygen -^ Nitrogen + Water 2N02 + 4NH3 + 02 ^ 3N2 + 6H20 Figure 14 - Catalytic and Non-Catalytic NOy Removal Superheater Superheater| Stack Non-catalytic NO. removal Injectors uuuuu Boiler Economizer Air preheater Catalytic NO. removal Electrostatic precipitators Furnace Burners Ammonia or urea Compressed air supply < —) b Catalytic Control ofNOx Selective catalytic reduction (SCR) is a highly efficient method to remove NO;? and is achieved through a reaction with ammonia in the presence of a catalyst. Selective catalytic reduction can be used where exhaust gases are between 260°C and 650°C (500°F and 1200°F) depending on the catalyst. As shown in Figure 14, the SCR unit is in the exhaust gas stream just before the electrostatic precipitators and the exhaust stack. Reduction of N0^. occurs as the flue gas passes through the catalyst chamber. The catalyst enhances the chemical reactions between N0^; and ammonia (NN3), which causes N0^ to be reduced to nitrogen and water. The catalyst may be a base metal such as titanium oxide, a zeolite such as aluminosilicate, or even a precious metal such as platinum. The use of a catalyst allows the ammonia to reduce N0^ levels at lower exhaust temperatures than is possible in the selective non-catalytic reduction. Selective catalytic reduction can result in N0^ reductions up to 90%. However, a catalyst is expensive, and the cost can rarely be justified on boilers with inputs less than 30 megawatts (MW). 3rd Class Edition 3 • Part A2 171 Chapter 3 • Fuels, Combustion, and Flue Gas Analysis SULFUR DIOXIDE Sulfur dioxide (S02) is an effluent that forms a corrosive weak acid when it dissolves in water. This acid may enter the ecosystems near the plants where sulfur emissions occur, causing acid rain and damage to buildings and infrastructure. Usually, provincial government regulations are in place to limit the amount of sulfur emissions. Formation of 802 Sulfur dioxide is formed when fuels that contain sulfur are burned. Sulfur + Oxygen ^ Sulfur dioxide S + 02 ^ S02 When the gaseous SO^ combines with free water, it forms a dilute, aqueous solution ofsulfurous acid (N2803). Sulfur dioxide + Water ^ Sulfurous acid S02 + HzO -> H2S03 Sulfurous acid can easily oxidize in the atmosphere to form sulfuric acid (H2S04). Dilute sulfuric acid is the major component of acid rain. Oxygen + Sulfurous acid -> Sulfuric acid 02 + 2H2S03 -> H2S04 Control of S02 The best control of sulfur dioxide is achieved by burning fuels with no sulfur content, such as natural gas, certain oils, and select coals. Choosing a fuel with zero or low sulfur content in the design stage, or retrofitting a plant to burn these fuels, may be a practical consideration. However, economically, this alternative may be too expensive. Certain combustion modifications, such as the use of a fluidized bed of limestone, significantly reduce sulfur dioxide emissions. In this modification, the sulfur dioxide is reduced because of the reaction between the sulfur dioxide and the limestone. Another strategy for sulfur dioxide control is the injection of a calcium sorbent material into the flue gas stream at an optimum temperature. The sorbent material reacts with the sulfur dioxide to reduce or eliminate the SO^. Examples ofcalcium sorbents include lime (CaO) and hydrated lime (Ca(OH)2). The following is a typical reaction and shows how the SO^ is eliminated: Ca(OH)2(s) + S02 ^ CaS03xH20(l) Wet and dry scrubbing are forms of SO^ control that involve the injection of a slurry, made of water and a sorbent material, into the flue gas. Depending on the type of reactor vessel used, the waste products that are formed are either wet or dry. The wet products may be removed for the recovery of usable products. The dry products must be removed by particulate control equipment. 172 3rd Class Edition 3 • Part A2 Fuels, Combustion, and Flue Gas Analysis • Chapter 3 PARTICULATES Particulate matter, particularly fly ash, has a deleterious effect on the ecosystem in the vicinity of the plant where it originates. The particulate creates an abrasive, dusty film on buildings, vehicles, and infrastructure in the area, and contributes to their deterioration. The abrasive particles may enter air intakes for boiler and machinery rooms and cause mechanical wear to equipment. When particulate enters air conditioning units, it also causes wear and damage to filters, screens, and equipment. Particulates may also cause health issues, particularly respiratory problems, for residents living in the vicinity of the plant where the particulate originates. For these reasons, limits are placed on particulate emissions. Formation of Particulates Besides natural gas, all fossil fuels and most biomass fuels contain quantities of ash. Since ash does not burn, it remains as a solid after combustion. Some of the ash drops to the bottom of the furnace and can be removed from there, and the remaining ash is called/^ ash. Fly ash is a particulate matter that is carried out of the furnace with the flue gas. The amount of particulate matter produced depends on the fuel and the firing method. Coals can have an ash content ranging from 5% to 30%. The percentage of ash in the original fuel that becomes fly ash and leaves with the flue gases also varies depending on the firing method. This is shown as follows: • Pulverized coal: up to 90% of the ash content • Cyclone furnace: up to 40% of the ash content • Stoker firing: up to 40% of the ash content • Fluidized bed furnaces: all of the ash leaves the furnace The composition of the fly ash includes, but is not limited to, oxides of silicon, titanium, iron, aluminum, magnesium, calcium, potassium, sodium, and sulfur. Control of Particulates There are three main methods used to control particulates: cyclone separators, fabric filters or baghouses, and electrostatic precipitators. Cyclone separators produce a centrifugal force on the particulate matter to effectively remove larger particles from the flue gas. For fine particulate matter, the efficiency of a cyclone separator may drop to 90%. Fabric filters or baghouses allow the flue gas to pass through but collect the particulate matter. A disadvantage ofbaghouse filters is that they require high fan power. However, baghouse filters can be greater than 99% efficient in the removal ofparticulate matter. Electrostatic precipitators negatively charge the particles using high voltage direct current (DC) charging plates. The particles collect on grounded plates and are then removed. Electrostatic precipitators have an efficiency that is greater than 95%. 3rd Class Edition 3 • Part A2 173 Chapter 3 • Fuels, Combustion, and Flue Gas Analysis EMISSIONS MONITORING A continuous emissions monitoring system (GEMS) is typically used for monitoring pollutant gas emissions as required by government regulations. A CEMS can use both extractive and in situ sampling methods and employ a variety of electronic sensor technologies for gas detection. A CEMS is most often used on larger installations, especially when required by regulatory agencies. The following are the three different types of continuous monitoring analyzers: 1. Extractive analyzers are used where the monitoring equipment is close to the sample point. 2. Dilution analyzers use a carrier, such as instrument air, to distribute a diluted sample to an analyzer. This analyzer is a long distance from the flue gas sample. 3. In situ analyzers are located directly within the flue gas path. Recall that in situ refers to sensors in the stack. Generally, the analyzers consist of a measuring cell and a reference cell. The instruments are zeroed, and the span adjusted using air or a standard calibration gas. The voltages across the measuring and reference cells are measured and compared to determine the composition of the flue gas. Specific cells are used to analyze each substance that is measured. One method of measuring nitrogen oxides is by injecting ozone into the sample. The ozone reacts with the N0^ and generates a light that is measured by a photocell. The intensity of the light is directly related to the amount of NOjc present. A second method uses a light detector to measure the concentration of a specific constituent after infrared light is passed through a measurement filter. Particulate matter can be measured using an in situ transmissometer analyzer, as shown in Figure 15. A transmissometer measures the transmission of light through a fluid. In this method, a light is passed through the flue gas and a mirror is used to reflect the light back to a measuring instrument. The quantity of light reflected to the measuring instrument is proportional to the particulate matter in the flue gas. Figure 15 - In Situ Transmissometer Analyzer Light beam Reflector Light source Air purge unit 174 Exhaust stack 3rd Class Edition 3 - Part A2 Fuels, Combustion, and Flue Gas Analysis • Chapter 3 7® SELF-TEST SOLUTIONS a) 5 b) 10.81 c) 10.81 g/mol d) 10.81 g e) 16 f) g) h) 32.07 32.07 g/mol 32.07 g a) 2, 7, 4, 6 b) 4, 7, 4, 6 c) 2,13,8,10 3rd Class Edition 3 • Part A2 181 Chapter 3 • Fuels, Combustion, and Flue Gas Analysis 182 3rd Class Edition 3 • Part A2 Fuels, Combustion, and Flue Gas Analysis • Chapter 3 ^ SUMMARY OF FUELS, COMBUSTION, AND FLUE GAS ANALYSIS Fuels and combustion are at the heart of the industrial economy. For Power Engineers, control of the combustion process is essential for safe and economical boiler operation. Combustion chemistry is the basis for understanding all aspects of boiler combustion control. The concepts of air-fuel ratio, stack temperature, and flue gas readings of oxygen (02), carbon monoxide (CO), and carbon dioxide (C02) are critical to measure combustion efficiency and operate safely. As this chapter indicates, there are also active issues concerning fossil fuels and renewable energy that affect the Power Engineering profession. Power Engineers have a responsibility to learn about new technologies and adapt to changes. If the Power Engineer is informed and knowledgeable, this will help on the job and in engaging with the public. An open mind and a willingness to hear all points of view will help the Power Engineer approach conversations about fossil fuel usage, industrial technology, and environmental concerns. 3rd Class Edition 3 • Part A2 175 Chapter 3 • Fuels, Combustion, and Flue Gas Analysis CHAPTER QUESTIONS Objective 1 1. Given 2 kg of 0^ at a temperature of 273 K and a volume of 0.30 m3, determine the pressure of the gas ifi^o = 8.314 kJ/kmol-K. 2. What is the formula mass for sulfur dioxide (802)? a) 32 b) 64 c) 96 d) 72 3. What is the mass of 5 kmol of carbon dioxide (C02)? a) 220 b) 60 c) 140 d) 176 4. Write balanced equations for the complete combustion of carbon, hydrogen, methane, and ethane. Objective 2 5. For complete combustion of 24 kg of carbon (C), what mass of 0^ is required? a) 88kg b) 32kg c) 24kg d) 64kg Objective 3 6. A burner takes 20 kg/min excess air. If the theoretical air is 60 kg/min, what is the percent of excess air? a) 50% b) 33% c) 30% d) 300% 176 3rd Class Edition 3 • Part A2 Fuels, Combustion, and Flue Gas Analysis • Chapter 3 7. Given the following ultimate analysis, calculate the theoretical air required to burn 1 kg of this fuel. Carbon 65.8% Sulfur 2.9% Nitrogen 8.8% Hydrogen 4.5% Oxygen 7.4% Ash 10.6% Objective 4 8. Which type of analysis gives exact percentages of each substance that makes up a sample of coal? a) Proximate analysis b) Zackleys analysis c) Ultimate analysis d) Boyle s analysis 9. Describe the procedure used to complete a proximate analysis of a fuel. 10. The composition of coal can be determined by proximate and ultimate analysis. a) What information is obtained from: i. The proximate analysis of coal? ii. The ultimate analysis of coal? b) What is the practical value of each analysis to the Power Engineer? 11. Describe the difference between higher and lower heating values. Objective 5 12. According to Dulongs formula, how much heat is produced by the combustion of 1 k^ of carbon? a) 33.7 MJ b) 33.7 kj c) 9.3 BTU d) 144kJ/m3 3rd Class Edition 3 • Part A2 177 Chapter 3 • Fuels, Combustion, and Flue Gas Analysis 13. With the following ultimate analysis of a fuel, calculate its calorific value using Dulongs formula. Carbon 65.8% Sulfur 2.9% Nitrogen 8.8% Hydrogen 4.5% Oxygen 7.4% Ash 10.6% Objective 6 14. Which statement applies to bituminous coals? a) The moisture content ofbituminous coal may be as high as 30% b) Bituminous coals are well suited to stoker firing c) Bituminous coals are difficult to ignite d) Bituminous coals burn easily Objective 7 15. Which of these are methods for atomizing fuel oil? a) Mechanical, steam, air b) Air, water, steam c) Chemical, mechanical, electrical d) Atomic, molecular, covalent Objective 8 16. Which component has the highest percentage in natural gas? a) Ethanol b) Methanol c) Water vapour d) Methane Objective 9 17. Ethyl alcohol is another name for which of the following substances? a) Methyl alcohol b) Ethanol c) Ethylene d) Acetylene 178 3rd Class Edition 3 • Part A2 Fuels, Combustion, and Flue Gas Analysis • Chapter 3 18. What are the main advantages of burning biomass fuels? Objective 10 19. A gaseous fuel has a heating value of 55 MJ/kg fuel. Flue gas measurements determine that 10 MJ/kg fuel are lost up the stack. Calculate the combustion efficiency. a) 60% b) 82% c) 18% d) 55% 20. In flue gas analysis, what are the individual significances ofC02, CO, and 02? Objective 11 21. Which type of device measures the decrease in light intensity due to absorption and scattering? a) Opacity meter b) Orsat analyzer c) Mass spectrometer d) Infrared spectroscopy Objective 12 22. N0^; emissions consist primarily of which compounds? a) NCOandNH3 b) N20andCN02 c) Ammonia and urea d) NO and N02 23. Explain one method used to control sulfur dioxide and nitrogen oxides emissions. 3rd Class Edition 3 • Part A2 179 ^ Chapter 3 • Fuels, Combustion, and Flue Gas Analysis NUMERICAL ANSWERS TO CHAPTER QUESTIONS 1. 473 kPa 7. 8.9986 kg air/kg fuel or 9.0 kg air/kg fuel 13. 27.6MJ/kg 180 3rd Class Edition 3 • Part A2