Numerical Analysis of NOx Control by

Article pubs.acs.org/EF

Numerical Analysis of NOx Control by Combustion Modifications in Pulverized Coal Utility Boiler Srdjan Belosevic,*,† Vladimir Beljanski,† Ivan Tomanovic,† Nenad Crnomarkovic,† Dragan Tucakovic,‡ and Titoslav Zivanovic‡ †

Institute of Nuclear Sciences Vinca, University of Belgrade, Laboratory for Thermal Engineering and Energy, P.O. Box 522, 11001, Belgrade, Serbia ‡ Faculty of Mechanical Engineering, University of Belgrade, Kraljice Marije 16, 11120 Belgrade 35, Serbia ABSTRACT: Considerable research efforts focus on modeling NOx formation/destruction and predicting NOx emission so that it can be controlled. A motivation for this numerical study was to examine the efficiency of combustion modifications in the furnaces of Kostolac B 350 MWe boiler units, tangentially fired by pulverized lignite. Numerical analysis was done by an in-house developed NOx submodel, coupled with differential comprehensive combustion model, previously developed and validated. The NOx submodel focuses on homogeneous reactions of both the fuel and the thermal NO formation/destruction processes. The submodel was validated by comparison of predicted NOx emissions with available measurements at the boiler units. Selected predictions of the emission, the furnace exit gas temperature, NO concentration, gas temperature, and velocity field are given for the case-study furnace under different operating conditions. The individual or combined effects of coal and preheated air distribution over the individual burners and the burner tiers, the grinding fineness and quality of coal, and the cold air ingress were investigated. Reduced emissions of up to 20−30% can be achieved only by proper organization of the combustion process. Obtained results were verified by the boiler thermal calculations. An optimal range of the furnace exit gas temperatures was proposed, with respect to the safe operation of the steam superheater. Simulations by means of a computer code developed for the purpose, showed that the air staging using overfire air ports might provide the NOx emission reduction of up to 24% in the test-cases with relatively high emission and up to 7% of additional reduction in already optimized cases.

■

INTRODUCTION Reduction of pollutants emission plays an outstanding role in both the exploitation and the retrofitting of the pulverized coalfired power plants. At the same time, it is essential to provide increased combustion and heat transfer efficiency. Nowadays, computational methods and codes1−16 are essential tools applied to achieve these tasks. In previous numerical simulations done by other authors, different furnace shapes and sizes could be seen. Few of them simulated tangentially fired furnaces with burners placed in furnace corners.1,2,5,11 Others performed simulations of wall fired furnaces,3,4,6,7 or used one-dimensional models9 to determine NOx emission. In some papers, simulations were performed to obtain data that could be used in automated control10 or to make an effort to minimize unburned coal in fly ashes.14 In papers covering detailed 3D gas phase flow modeling, the most common turbulence model in use is standard k−ε model.2,7,11−13,15,16 For gas−solid phase coupling, the Eulerian−Lagrangian approach is mostly applied. Various models are used for prediction of thermal radiation, such as Monte Carlo,1 P1,3,16 discrete ordinates,5 and discrete transfer.8,14 Different combustion models are used, varying in detail and complexity, that is, the diffusion-kinetics model3,5,8 for char combustion and the combined kinetics and eddy dissipation model14 for reactions in gaseous phase. Our own code12,13 uses the k−ε turbulence closure model. Interaction between gas and solid phases is modeled using the Eulerian−Lagrangian approach, with the particle-source-in (PSI) cell method used to treat the influence of the combusting particle on fluid. Radiation is © 2011 American Chemical Society

solved by the six-flux method. Combustion of coal particles is modeled in the combined kinetic-diffusion regime, on the basis of experimentally obtained case-study coal kinetic parameters.12,13 Some authors included a NOx model in their simulations.1,3−7,9,11,14−16 Most of the authors take into account the production and destruction of NO only,3,7,9,11,14−16 because it is the most abundant NOx compound in flue gases from coal combustion. In most NO formation and destruction simulations, prompt NO is neglected, while thermal NO and fuel NO are considered.3,6,7,11,14−16 Some authors even simulated only fuel NO as the predominant compound.9 In their simulations, authors mostly tried to verify some of primary methods for NOx reduction. Their main goal was to optimize the combustion process. Multiple stage combustion showed good NOx reduction.2−7 Some authors examined new burners3,4,14 and their influence on NOx reduction. Additional NOx reduction through introduction of OFA was investigated by some authors.5 Among the most important pollutants are oxides of nitrogen, so considerable research efforts focus on modeling NOx formation/destruction and predicting NO x emission.1−7,9−11,17,18 Nitrogen oxides consist of nitric oxide (NO), nitrogen dioxide (NO2), nitrous oxide (N2O), and other oxides of less influence. N2O emissions are not typically Received: September 13, 2011 Revised: November 29, 2011 Published: November 30, 2011 425

dx.doi.org/10.1021/ef201380z | Energy Fuels 2012, 26, 425−442

Energy & Fuels

Article

validated by comparison with available measurements of NOx emission from the case-study boiler units during operation. The individual or combined effects on the NOx emission of various operation parameters, like pulverized coal and preheated air distribution over the individual burners and the burner tiers, cold air ingress, composition, heating value, and grinding fineness of coal, were numerically investigated. The application of overfire air (OFA) ports was also analyzed and optimized numerically with special care. In addition, attention was paid to the pulverized coal diffusion flame geometry and position, because of its impact on heat transfer in the furnace and thermal load of the water walls, as already demonstrated.13 Most of de-NOx measures of this kind may reduce the boiler and the plant efficiency and disturb the safe operation of the superheaters. Thus, the primary measures were also optimized with respect to their impact on the efficiency of the heat transfer surfaces and the boiler unit. According to the boiler thermal calculations, an optimal range of the furnace exit gas temperatures (FEGT) was proposed, with respect to the safe operation of the steam superheater. For the optimal range, the amount of water injected into the line of reheated steam was minimal, contributing to the boiler unit efficiency increase.

significant within pulverized coal combustion systems. NO and NO2 are collectively referred to as NOx. Oxides of nitrogen have been identified as direct precursors of photochemical smog and they contribute to acid rain. The total amount of nitrogen oxides, emitted from all thermal power plants of the Electric Power Industry of Serbia, was 58 030 tons per year in 2008. The European Union Directive 2010/75/EU requires an emission limit of 500 mg/Nm3 of NO, measured as NO2 (dry basis, 6% O2 in flue gases), for solid fuels and the boiler facility power output >500 MWth, while current domestic NOx emission limit is 450 mg/Nm3, measured as NO2 (dry basis, 6% O2 in flue gases). Although the emission of NOx from domestic thermal power plants firing mostly low-rank coalslignites, is not extremely high, it considerably exceeds new European emission limits of 200 mg/Nm3 (valid from 2016 on). The unit mg/Nm3 represents the amount of any (CO, CO2, NOx, etc.) compound given in milligrams per normal cubic meter of flue gases. Normal cubic meter is cubic meter at normal conditions, which are 0 °C, 1013 mbar. For pulverized coal-fired power plants, any measured or numerically obtained value given for temperature and pressure different from normal conditions must be recalculated and expressed for normal conditions, dry basis and 6% O2 in the flue gases. Primary measures for NO x control (tuning of the combustion/aerodynamics parameters) offer a simple and cost-effective means of NOx emission reduction (up to 60%),18 whereas secondary measures, based on the flue gas postcombustion cleanup, are considerably more expensive. Motivation for this numerical study was to examine the possibility of decreasing NOx emission by primary measures combustion modifications in tangentially fired furnace of Kostolac-B 350 MWe boiler units. At the same time, it was essential to provide proper characteristics of flame and safe operation of the heat transfer surfaces, as well as to avoid the boiler unit efficiency decrease. Numerical analysis was done by an in-house developed submodel of NOx formation/destruction (so-called “NO postprocessor”). Constraints of practicality dictated the use of simplified chemical models, in conjunction with detailed CFD calculations, the approach is referred to as comprehensive modeling.18 The NOx submodel was coupled with comprehensive differential model for prediction and analysis of furnace process parameters. The model was previously developed and validated against experimental data.12,13 It can be easily used by engineering staff dealing with the process analysis in boiler units. NO from combustion systems results from three main processes: thermal NO, fuel NO, and prompt NO. The nitrogen present in fossil fuels, such as coal and fuel oil, is typically the most significant source of NO. Referred to as fuel NO, it typically accounts for 75−95% of the total NO in coal combustors.18,19 The contribution of thermal NO (formed from oxidation of atmospheric nitrogen) does not become significant until temperatures in coal flames are greater than 1600−1800 K.18 For the reasons of the model completeness, thermal NO in the present model is not ignored. Prompt NO is defined as the NO compound formed from the attack by hydrocarbon fragments on molecular nitrogen in the flame zone. It is significant only in very fuel-rich flames, and its contribution is likely to be small in fuel-lean or close to stoichiometric ratios; therefore, it is neglected in this study. The NOx submodel, developed to describe the formation and destruction of thermal and fuel NOx in the furnace, was

■

MATHEMATICAL MODEL

For prediction of processes in two-phase turbulent reactive flow in large-scale pulverized coal-fired boiler furnaces at stationary conditions, a comprehensive 3D differential mathematical model and computer code were previously developed in-house and validated against the available results of large-scale measurements in the casestudy boiler furnace.12,13 The comprehensive combustion model offers such a composition of submodels and modeling approaches so as to balance submodel sophistication with computational efficiency. To predict NOx emission, a submodel of NOx formation/destruction has been developed and coupled with the comprehensive combustion code. The comprehensive model has been already described in detail.12,13 Here, general features of the model are given, and the NOx formation/destruction modeling is emphasized. The two-phase flow is treated by the Eulerian−Lagrangian approach. Gaseous phase is described by time-averaged Eulerian partial differential equations for mass, momentum, energy, gas mixture components concentrations, turbulence kinetic energy, and its rate of dissipation. In general index-notation, for general variable Φ:

⎛ ⎞ ∂ ⎜ ∂Φ ⎟ ∂ + SΦ + SpΦ ΓΦ (ρUjΦ) = ⎜ ∂xj ⎝ ∂xj ⎟⎠ ∂xj

(1)

SpΦ,

while ρ, Uj, ΓΦ, and SΦ with additional sources due to particles denote gas-phase density (kg/m3), velocity components (m/s), transport coefficient, and source term for Φ, respectively. To close the gas phase conservation equations, the k−ε turbulence model is used. The dispersed phase is described by differential equations of motion, energy, and mass change in a Lagrangian field. Particle velocity vector is a sum of convective and diffusion velocity. The effect of particles on gas phase is accounted for by PSI cell method. The continuity equation for particle number density (concentration) is given in the form of eq 1. A convection−radiation heat transfer is considered, and radiative heat exchange is modeled by the six-flux method, which solves total radiation fluxes in the directions of coordinate axes. Total radiation fluxes are used to find the radiative heat transfer rate to a single particle and the volumetric heat transfer rate to the gas, which is used as the radiative energy source term in the gas-phase enthalpy equation. Flue gas and wall total emissivities are assigned values of εg = 0.35 and εw = 0.85, respectively.20 The absorption coefficient of the gas phase Ka,g (1/m) was determined from the expression for the total gas emissivity, given by εg = 1 − exp(Ka,gL), where L is a mean beam length (m). Absorption and scattering coefficients of the dispersed 426


Energy & Fuels

Article

overall rate of thermal NO formation/destruction reactions can be expressed as

phase were determined for the cloud of monodispersed fly ash particles. Efficiency factors for absorption and scattering were Qa ≈ 0.8 and Qs = 1.3, respectively.20 Diameter of the fly ash particle is determined for the conditions of complete coal combustion assuming that one coal particle is transformed into one fly ash particle. There were experimental data for particle kinetics of Serbian lignites with respect to the entire coal particle, which influenced the modeling approach: individual phenomena in combustion were treated together on the basis of experimentally obtained case-study coal kinetic parameters. Coal particle combustion is modeled with respect to the char combustion, being by far a slower process than devolatilization and volatiles combustion. The “shrinking core” concept is used. Change of the coal particle mass mp (kg), equal to the reaction rate ℛp (m/s), is given in combined kinetic-diffusion regime: dm p A pM p χox mol = 9p = 1 1 dτ + kr kd

d[NO] = 2k[O][N2], k = 1.8 × 108 e−38 370/ T dt

k r = A e E / RT k d = Sh + / d p + = 9.8 × 10−10T1.75

(3)

The reaction rate constant is taken from the references, and eq 3 is coupled to the fuel oxidation process through competition for an oxygen atom, whose local concentration [O] must be estimated. In fuel-lean combustion zones, oxygen atoms are assumed to be in equilibrium with O2 and [O] can be estimated from partial equilibrium of oxygen dissociation,10 as done here: 0.5O2 ⇔ O. The NOx submodel also comprises the reactions of fuel NO formation and depletion, in the first place, through hydrogen cyanide (HCN), as an intermediate compound from volatilization. The atomic nitrogen content of volatiles evolves as an intermediate nitrogenous compound, which can be hydrogen cyanide, ammonia, etc. The intermediate compound is then either oxidized to form NO, or reduced with a further nitrogen-containing species to yield molecular nitrogen. We have adopted recommendations given in De Soete,22 (this model may not necessarily be appropriate for strongly fuel-rich conditions). The chosen model is in conjunction with De Soete globalreaction kinetics for the gas-phase NO formation.22,23 The fuel NO formation reaction rate is given as

(2)

dXNO α −33 732.5/ T e = r1 = A11010XHCNXO 2 dt

2

Molecular diffusivity + (m /s) is given by empirical expression for ox , high-temperature combustion products.21 In addition, τ, Ap, Mp, χmol A, E, R, Sh, dp, and T, are time (s), particle cross section area (m2), molar mass (kg/mol), oxidant molar concentrations (kmol/m3), preexponential factor in Arrhenius expression (m/s), activation energy of the coal in Arrhenius expression (J/kmol), universal gas constant [=8.314 kJ/(kmol·K)], Sherwood number (dimensionless), particle diameter (m), and gas temperature (K), respectively. Total particle mass change due to reactions is the sum of changes due to the individual processes. Reactions of complete oxidation of carbon and hydrogen are considered by corresponding reaction rates, and sulfur is taken into account through equivalent carbon content. Mass and heat addition due to combustion is considered by additional sources to be the result of particles in conservation equations, eq 1. The determination of kinetic parameters for six Serbian lignites, as described,12,13 was done on the basis of the coal combustion experiments in a vertical cylindrical 15 kW laboratory furnace, with estimated experimental error less than 5%. The kinetic parameters obtained for the case-study coal (lignite Kostolac-Drmno) were A = 5.5 × 103 m/s and E = 9.95 × 104 kJ/kmol.12 Initial and boundary conditions usual for elliptical partial differential equations are applied. Conditions near the walls are described by the “wall functions”. Discretization of partial differential equations is performed by control volume method and hybrid-differencing scheme. Discretized equations are solved by SIPSOL method (a derivative of SIP algorithm). Coupling of the equations of continuity and momentum is done by SIMPLE algorithm. Stabilization of iteration procedure is provided by under-relaxation. The comprehensive combustion code was carefully verified by grid-independence study with assessment of numerical error.12 3D staggered, structured numerical grids were used (with 200 000, 549 250, and 731 250 grid nodes), in conjunction with 50, 200, and 800 trajectories per each vertical tier of each burner. The numerical results suggested the mesh with 549 250 nodes and 800 trajectories per burner (5600 trajectories in total-with seven burners in operation) as a proper choice, providing computational efficiency, converged solutions, and accuracy. A submodel of NOx formation and destruction processes has been incorporated into the complex combustion model. The submodel is executed after the flame structure has been predicted, in a common “post-processor” way. This approach is justified because pollutant species do not affect considerably the flame structure. For prediction of thermal NO, a simplified Zeldovich expression is used, assuming initial concentrations of NO and OH are so low that only forward rates of Zeldovich mechanism are significant.18 The

(4)

For fuel-lean conditions, which prevail in the pulverized-coal-fired furnaces, the constant of eq 4, that is, the pre-exponential factor A1, as proposed by Lockwood and Romo-Millares,18 is increased by 3.5 compared with original value A1 = 1 (De Soete,22 more proper for fuelrich conditions). As explained,17 because the effects of the temperature fluctuations were not considered, an adjustment of one of the model parameters (pre-exponential factor in equation for the reaction between HCN and O2) was required. A sensitivity analysis was made, to determine the best value, while the values presented in the literature (De Soete22 and Smith, Hill, and Smoot,24) were found not to give the correct magnitude of NO concentrations. The best fit of this coefficient, based only on experimental NO emission values, was found to be 3.5 × 1010 1/s,17 for the data presented. In forthcoming years, this value will be extensively used for NOx predictions in utility scale boilers.6,7 In this work, calculations of the reaction rate have been performed by means of eq 4, with different values of pre-exponential factor A1, in dependence on the local fuel concentration. Coefficient 0 ≤ α ≤ 1, used in eq 4, depends on the local concentration of oxygen, according to De Soete,22 given as

XO2 ≤ 4.1 × 10−3

α=1

4.1 × 10−3 ≤ XO2 ≤ 1.11 × 10−2 α = − 3.95 − 0.9 ln XO2

(5)

1.11 × 10−2 ≤ XO2 ≤ 0.03 α = − 0.35 − 0.1 ln XO2 XO2 ≥ 0.03

α=0

For the NO depletion rate, the following expression has been selected according to the literature:21

dXNO = r2 = − 3.0 × 1012XHCNXNO e−30 208.2/ T dt

(6)

XHCN, XO2, XNO are corresponding mole fractions. Partial differential equations for NO and HCN are solved in the Eulerian field, eq 7. The source of NO in the corresponding transport equation is obtained in dependence on the total net formation/ destruction rate of NO, while the source of HCN comprises both the 427


Energy & Fuels

Article

Table 1. Comparison with Measurements on Boiler Units TE Kostolac B-1 and B-2 for 2007−2010 fuel distribution over the burner tiers lower-stage burners test-case B-12007 B-12008c B-12009 B-12010 B-22007 B-22008c B-22009

NOx emissiona (mg/Nm3)

upper-stage burners

lower (%)

upper (%)

lower (%)

upper (%)

air−coal dust mix. gas phase through the lowerstage burners (%)

secondary air through the lower-stage burnersb (%)

num. sim.

52

28

meas.

13

7

56

70

439

449

39

21

26

14

57

65

868

1051

45.5

24.5

19.5

10.5

56

65

490

506

39

21

26

14

57

65

549

557

39

21

26

14

56

65

473

440

39

21

26

14

57

65

881

893

45.5

24.5

19.5

10.5

55

65

477

460

a Normal conditions (0 °C, 1013 mbar), dry basis, 6% O2 in flue gases. bIncluding the core air-portion of preheated air supplied through the middle of the coal dust−air mixture ducts. c20% increase of secondary air and 2% instead of 1% of N in the coal, as received.

Table 2. Comparison with Measurements on Boiler Units TE Kostolac B-2 for 2011 and Numerical Parametric Study of TestCases fuel distribution over the burner tiers lower-stage burners

upper-stage burners

lower (%)

upper (%)

lower (%)

upper (%)

B-2-20118463c B-2-20118226c

39

21

26

39

21

B-2-20118463-1 B-2-20118226-1c B-2-20118226-2d B-2-20118226-3d B-2-20118226-4d B-2-20118226-5

39

test-case

FEGT (°C)

NOx emissiona (mg/Nm3)

air−coal dust mix. gas phase through lower-stage burners (%)

secondary air through the lowerstage burnersb (%)

num. sim.

meas.

num. sim.

meas.

14

59

65

1047

1045

564

565

26

14

59

65

1041

1039

541

558

21

26

14

65

1048

535

45.5

24.5

19.5

10.5

57

65

990

468

45.5

24.5

19.5

10.5

58

65

1050

504

45.5

24.5

19.5

10.5

58

50

1040

461

45.5

24.5

19.5

10.5

58

70

1036

564

52

28

13

7

54

65

950

375

Numerical Parametric Analysis 58

a Normal conditions (0 °C, 1013 mbar), dry basis, 6% O2 in flue gases. bIncluding the core air-portion of preheated air supplied through the middle of the coal dust−air mixture ducts. cSeven mills in operation (in all other cases six mills). dImproved sealing of the furnace walls.

devolatilization and depleted in the gas phase through the reactions given by eq 4 and eq 6. It is reasonable to presume that the release rate of the fuel nitrogen into the gas phase is proportional to the devolatilization rate, as done in Lockwood and Romo-Millares.17 The source of HCN as a result of its release from the pulverized coal is calculated within the subroutine for Lagrangian particle tracking, as a sum of sources from all particle trajectories passing through the considered control volume.

HCN release by devolatilization and HCN depletion in the gaseous phase.

⎛ ∂XNO ⎞ ∂ ⎜ ∂ ⎟ + SNO (ρUjXNO) = Γ NO ∂xj ⎟⎠ ∂xj ⎜⎝ ∂xj ⎛ ∂XHCN ⎞ ∂ ⎜ ∂ ⎟ + SHCN (ρUjXHCN) = Γ HCN ∂xj ⎟⎠ ∂xj ⎜⎝ ∂xj

■

(7)

RESULTS AND DISCUSSION The NOx submodel was incorporated into the finite volume numerical code. For reliable predictions of NOx emission from the case-study furnace in variable operating conditions, the grid-independence study (extremely important in industrial scale problems) and validation of numerical calculations were

Mass fractions of NO and HCN are given by XNO (kg/kg) and XHCN (kg/kg), respectively, while ΓNO and ΓHCN are corresponding transport coefficients. SNO and SHCN are source terms for NO and HCN. SNO is obtained with respect to the total net formation/ destruction rate of NO: eq 3 and eq 4/eq 6. HCN is released by 428


Energy & Fuels

Article

performed. 3D nonuniform, structural, staggered grids were used. The grid-independence study suggested the mesh with 130 × 65 × 65 = 549 250 grid nodes as a proper choice, in conjunction with 200 particle trajectories per burner tier (800 per each burner, and 5700 for seven burners in operation). The representative initial mean diameter of monodispersed pulverized coal particle was selected (dp = 150 μm), with respect to the sieve analysis (grinding fineness of R90 = 55.0%, R1000 = 2.0%, where R90 denotes percentage residue on sieve with grid spacing 90 μm), Rosin−Rammler−Sperling distribution of particle size classes, and a set of numerical experiments. Validation of NOx Formation/Destruction Submodel. Tables 1 and 2 present comparisons between predicted NOx emissions (for year 2011 also FEGT) and available experimental results from the Kostolac Power Plant B-1 and B-2 steam boiler units during operation. The measurements on both units were carried out during 2007−2010 (results provided by Electric Power Industry of Serbia), while investigations on B-2 unit were performed also in 2011, by Institute of Nuclear Sciences Vinca, after repairs done on the air preheaters. To evaluate the predictions, it was necessary to recalculate the predicted average NOx mass fractions at the furnace exit to the conditions required by corresponding standards, T = 0 °C, P = 1 atm, and to express the emission in corresponding unit, mg/Nm3. The measurement procedure, equipment, and inaccuracy for gas temperature were already given.12 Measured emission of nitrogen oxides was based on nitric oxide content in the flue gases, measured by a corresponding instrument, that is, a gas-analyzer. The accuracy of the instrument was 1% of the range. However, the overall experimental error is very complex and strongly influenced, not only by measuring instrument and acquisition system accuracy but also by operating conditions, fluctuations of individual parameters, sampling, and sealing in the whole measuring system. Repeated measurements of NO content at the same conditions showed good reproducibility: differences between measured values were never greater than 5%. The case-study utility boiler units (nominal steam capacity 1000 t/h and power output 350 MWe at full load, each) are of tower-type with natural circulation. The water-wall dry-bottom furnaces (dimensions: 15.1 m × 15.1 m × 43.0 m), with after combustion device-grate, are identical. The furnace, burning pulverized coal (Serbian lignite Drmno), is tangentially fired. Figure 1 shows the case-study boiler dimensions and the burner tier configuration. The air−coal dust mixture (in Figure 1 given as PA+COAL) is injected through the two lower-stage burners (often called the “main burners”, used for the combustion of larger particle size classes) and the two upper-stage burners (supplying smaller particle size classes). Around them, secondary air (SA) is introduced to ensure good combustion (the air necessary for complete combustion). Figure 2 shows the setup of eight jet-burners in horizontal cross-section. The air−coal dust mixture and the secondary air are introduced into the boiler furnace tangent to an imaginary circle, providing the tangential firing. Therefore, in the middle of the furnace, a vortex structure is formed. Centrifugal separators and combination with louver separators on the air−coal dust mixture ducts are used in B-1 and B-2 units, respectively. Unless otherwise specified, 6 mills operated (uniformly): 2 opposite ones turned-off. Residue on sieve: R90 = 55% and R1000 = 2%. air−coal dust mixture temperature: 200 °C. Secondary air temperature: 283 °C (in 2007−2010) and

Figure 1. Kostolac Power Plant B-1 and B-2 steam boilers furnace.

287 °C (in 2011). For measured test-cases and the parametric analysis, operating conditions are presented by Tables 1−5. As Tables 1 and 2 show, agreement of predictions with measurements is very good (percentage difference 0.2−7.4%), except for test-case B-1-2008. Only for year 2008, considerable discrepancies were obtained; repeated numerical experiments suggested that the cause could have been the increased amount of air (either preheated or cold) and/or more nitrogen in the fuel, during the very measurements. Around 20% increase of secondary air (i.e., excess air at the furnace exit λout = 1.46 vs 1.22 in standard operating conditions at full load), in combination with twice as much nitrogen as in the guarantee coal (0.9−1%, as received, used in other cases), gave a quite satisfactory approximation of the emission in test-case B-2-2008 and a reasonable approach to the measured value in test-case B1-2008. As expected, a considerable amount of fuel injected through the upper-stage burners (60%) in test-cases measured in 2011, provided relatively high position of the flame, as shown in Figure 3. As an additional validation of the model, a parametric analysis was performed; see Tables 2 and 3. The proximate and ultimate analyses of the fuel were used as for the corresponding situations measured in 2011, Tables 4 and 5. The model properly predicts the effect of different operating conditions on both the emission and FEGT. In test-case B-2-2011-8463-1, six burners were in operation (two opposite turned-off) instead of seven in the measured case B-2-2011-8463: aero-thermody429


Energy & Fuels

Article

Figure 2. Tangential configuration of Kostolac Power Plant B-1 and B-2 steam boiler units burners.

Figure 3. Temperature field and concentration of nitrogen oxides in the boiler furnace for test-case B-2-2011-8463. 430


Energy & Fuels

Article

Table 3. Mass Flow Rates of Coal and Air in Measured Test-Cases and for Related Parametric Analysis total coal feed rate (kg/s)

pulverized coal flow rate, per burner (kg/s)

air−coal dust mixture gas phase flow rate, per burner (kg/s)

secondary air flow rate, per burnera (kg/s)

preheated air flow rate through after combustion device (kg/s)

cold air ingress into the furnace (kg/s)

B-1-2007 B-1-2008 B-1-2009 B-1-2010 B-2-2007 B-2-2008 B-2-2009 B-2-20118463b B-2− 20118226b

90.6 75.0 92.2 92.8 93.8 74.0 92.9 100.0

9.9 8.1 10.0 10.2 9.7 7.9 9.8 9.1

53.0 49.7 52.2 50.6 52.9 52.8 54.0 44.0

33.4 35.7 32.5 32.1 28.9 35.2 33.2 29.7

12.3 12.3 11.9 11.8 10.9 11.2 11.7 10.4

56.3 48.3 54.8 54.3 64.3 59.0 55.9 71.7

104.4

9.7

43.3

31.1

10.6

73.1

B-2-20118463-1 B-2-201182261b B-2-20118226-2c B-2-20118226-3c B-2-20118226-4c B-2-20118226-5

100.0

10.7

Numerical Parametric Analysis 47.4 34.8

10.4

71.7

104.4

9.7

43.7

31.3

10.6

73.1

102.8

11.1

42.1

42.8

12.3

35.9

102.8

11.1

42.1

42.1

12.3

35.9

102.8

11.1

42.1

47.0

12.3

35.9

104.4

11.3

49.3

35.4

10.6

73.1

test-case

a

Including the core air−portion of preheated air supplied through the middle of the coal dust−air mixture ducts. bSeven mills in operation (in all other cases six mills in operation). cImproved sealing of the furnace walls.

through the lower-stage burners (70% and 80%, respectively, instead of 60%) caused the decrease of both the FEGT and the emission, presumably due to the descent of flame.13 Increase of the amount of controlled, preheated air and considerable decrease of the cold air ingress, provided the conditions for the emission reduction in both test-cases B-2-2011-8226-2 and B-22011-8226-3. However, test-case B-2-2011-8226-4 gave higher emission, probably because of an excessive amount of secondary air through the lower-stage burners (70% vs 65%, or 50%); see Table 2. In other words, some amount of secondary air was subtracted from the lower-stage and introduced to the upper stage burners (a kind of OFA ports), in test-cases 8226-2 and 8226-3, thus providing the emission reduction compared with the case 8226-4. Numerical Study on NOx Emission Reduction by Combustion Modifications in the Case-Study Furnace. After validation, the model was applied to study the possibilities of NOx emission reduction by a proper organization of combustion process in the case-study boiler furnace, consider-

Table 4. Case-Study Coals Proximate Analysis and LHV, AsReceived, for Measured Situations test-case

moisture (%)

ash (%)

LHV (kJ/kg)

B-1-2007 B-1-2008 B-1-2009 B-1-2010 B-2-2007 B-2-2008 B-2-2009 B-2-2011-8463 B-2-2011-8226

40.43 41.33 41.23 40.37 43.20 41.63 42.23 41.91 41.13

19.91 17.85 20.46 21.76 20.11 17.08 19.07 20.17 21.64

8812 9483 8837 8607 8646 9450 8703 8463 8226

namic symmetry in the former case provided the conditions for, to some extent (5%), lower emission. In relation to test-case B2-2011-8226, five additional test-cases were examined. In testcases B-2-2011-8226-1 (7 mills operating) and B-2-2011-82265 (6 mills operating), an increased fraction of coal injected

Table 5. Pulverized Coal Proximate and Ultimate Analysis for Measured Operating Situations test-cases

moisture (%)

ash (%)

LHV (kJ/kg)

C (%)

H (%)

O (%)

N (%)

Scmbst (%)

B-1-2007 B-1-2008 B-1-2009 B-1-2010 B-2-2007 B-2-2008 B-2-2009 B-2-2011-8463 B-2-2011-8226

9.547 9.367 9.387 9.559 8.983 9.306 9.184 9.249 9.407

30.23 27.57 31.55 33.00 32.22 26.54 29.98 31.51 33.30

14 573 15 902 14 871 14 243 15 240 15 957 14 997 14 514 13 898

40.72 43.22 39.27 37.96 38.22 44.20 40.65 39.18 37.53

3.52 3.58 3.58 3.52 3.72 3.60 3.65 3.62 3.57

13.61 13.84 13.81 13.59 14.36 13.92 14.09 14.00 13.79

1.52 1.54 1.54 1.52 1.60 1.55 1.57 1.56 1.54

0.85 0.87 0.86 0.85 0.90 0.87 0.88 0.87 0.86

431


Energy & Fuels

Article

Table 6. Distribution of the Fuel and the Combustion Air Mass Flow Rate over the Burner Tiers fuel distribution over the burner tiers (%) lower-stage burners

upper-stage burners

testcase

lower

upper

lower

upper

air−coal dust mix. gas phase through the lowerstage burners (%)

secondary air through the lowerstage burners (%)

FEGT (°C)

NOx emission,a (mg/Nm3)

1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17b 18c 19 20 21 22d 23e 24f 25g 26h 27I 28b 29b,e

45.5 52.4 30.4 0.0 34.9 35.2 43.2 28.6 36.8 27.6 40.0 35.0 24.5 28.0 27.0 26.0 45.5 35.2 34.9 50.0 50.0 45.5 45.5 45.5 45.5 45.5 45.5 40.0 40.0

24.5 0.0 25.8 31.6 49.1 44.8 43.2 52.7 38.4 43.6 50.0 35.0 45.5 48.0 43.0 38.0 24.5 44.8 49.1 50.0 50.0 24.5 24.5 24.5 24.5 24.5 24.5 50.0 50.0

19.5 32.7 30.7 32.0 6.2 8.0 7.9 8.3 9.4 13.9 4.5 15.0 10.5 11.0 13.0 15.0 19.5 8.0 6.2 0.0 0.0 19.5 19.5 19.5 19.5 19.5 19.5 4.5 4.5

10.5 14.9 13.1 36.4 9.8 12.0 5.7 10.4 15.4 14.9 5.5 15.0 19.5 13.0 17.0 21.0 10.5 12.0 9.8 0.0 0.0 10.5 10.5 10.5 10.5 10.5 10.5 5.5 5.5

57 37 49 24 58 60 57 56 51 53 64 57 57 55 51 48 57 60 58 100 100 57 57 57 57 57 57 64 64

68 69 74 68 74 68 68 74 74 74 74 68 68 71 71 71 68 68 60 90 70 68 68 68 68 68 68 74 60

1021 1017 1093 1072 1020 1033 983 1027 1046 1069 996 1057 1064 1047 1076 1101 1015 904 991 1027 988 994 1018 965 916 936 1115 993 984

415 407 468 349 344 338 362 380 428 345 427 438 361 423 477 428 340 320 375 326 426 396 348 237 408 445 308 290

Normal conditions (0 °C, 1013 mbar), dry basis, 6% O2 in flue gases. bSeven burners operating unevenly (Table 7). cThe share of cold air ingress in the total amount of air 30.0% (in other test-cases: 7.5%). dInitial coal particle size dp = 50 μm (in other test-cases: 150 μm). eInitial coal particle size dp = 100 μm. fInitial coal particle size dp = 300 μm. gLHV (lower heating value), as received: 6071 kJ/kg (in other cases: 7327 kJ/kg, except in 26 and 27). hLHV: 6490 kJ/kg. ILHV: 8374 kJ/kg a

Table 7. Different Operation Regimes of Individual Burners, at the Full Load of the Boiler Unit burner

1

2

3

4

Test-Cases 1−16 and 18−27: Seven Burners Operating Evenly flow rate of pulverized coal/gas phase of the coal dust−air 10.4/43.7 10.4/43.7 10.4/43.7 10.4/43.7 mix. (kg/s) flow rate of secondary aira (kg/s) 38.2 38.2 38.2 38.2 Test-Cases 17, 28, and 29: Seven Burners Operating Unevenly flow rate of pulverized coal/gas phase of the coal dust−air 11.4/47.8 10.4/43.7 10.4/43.7 8.4/35.5 mix. (kg/s) flow rate of secondary aira (kg/s) 41.8 38.2 38.2 31.0 a

5

6

7

8

10.4/43.7

10.4/43.7

10.4/43.7

0.0

38.2

38.2

38.2

9.8

10.4/43.7

10.4/43.7

11.4/47.8

0.0

38.2

38.2

41.8

9.8

Including the core air-portion of hot air supplied through the middle of the coal dust−air mixture ducts.

ing also FEGT and the pulverized coal flame position. Through a number of test-cases, the effects of many parameters, such as distribution of coal and preheated air over the burners and the burner tiers, cold air ingress, coal quality, and grinding fineness of coal, were analyzed individually or in combination. Standard Operating Conditions at Full Load. Uniform operation mode of 7 burners with total coal feed rate of 424.3 t/h and total air flow rate of 1050 × 103 Nm3/h. Pulverized coal mass flow rate is distributed at approximately 70% per lower-

stage and 30% per upper-stage burners. The air−coal dust mixture (T = 200 °C, pulverized coal and transport fluid flow rate per burner, 10.38 and 43.73 kg/s, respectively). Preheated air (T = 288 °C, secondary air flow rate per burner = 38.18 kg/ s, air flow rate through after-combustion device = 15.18 kg/s). The cold air ingress into the furnace was 27.86 kg/s. Case-study coal, Serbian lignite Kostolac-Drmno, before grinding and drying in the mills (air-dried): proximate analysis (%), as received, moisture 43.93, ash 22.25, volatile 21.39, fixed carbon 432


Energy & Fuels

Article

Figure 4. Gas temperature field and O2, HCN, and NOx concentration fields in test-case 1.

distributions are given according to the investigations of the coal mills. To provide the improvement of the combustion process, additional numerical analyses were done. Different distributions of the fuel and the preheated air over the burner tiers are analyzed in test-cases 11 to 16 and 19 to 21. Test-case 18 investigates the effect of the increase of the cold air ingress. Test-cases 22 and 23 examine the influence of the coal grinding fineness, through different initial particle diameter (dp= 50 μm and dp= 100 μm). The combined effect of pulverized coal distribution over the burner tiers (as for test-case 11) in conjunction with the coal distribution over the individual burners (as for test-case 17) is analyzed in test-case 28. Testcase 29 differs from 28 by distribution of secondary air over the burner tiers and grinding fineness of coal. Numerical Results for the Reference Test-Case. Testcase 1 is a nominal operation regime of the boiler, so it was selected as the reference and presented separately to closely

12.43; lower heating value (kJ/kg), as received, 7326.9; ultimate analysis (%), as received, C 22.46, H 2.12, O 7.7, N 0.9, S (combustible) 0.64. Case-study coal after grinding and drying in the mills (pulverized coal): proximate analysis (%), moisture 8.83 and ash 36.18; ultimate analysis (%), C 36.52, H 3.45, O 12.52, N 1.46, S (combustible) 1.04. Coal particle density is 1300 kg/m3. Test-cases, shown in Table 6, consider the same values of coal and preheated air flow rates, in total and per burner, with uniform operation of seven coal mills, as for the standard operating conditions at full load (the reference test-case 1), except in test-cases 17, 28, and 29, in which burners operate unevenly, Table 7). Distributions of fuel, air−coal dust mixture gaseous phase, and secondary air over the burner tiers are mutually dependent. The distributions in test-cases 1, 17, 22, and 23 are exactly the same as for the standard operating conditions at full load, while for test-cases 2−10 the 433


Energy & Fuels

Article

Figure 5. Influence of the fuel distribution over the burner tiers on the temperature field and the NOx content in test-cases 3 (a) and 11 (b): 56% and 90% of coal through the main burners, FEGT = 1093 and 996 °C, NOx emission = 468.0 mg/Nm3 and 344.6 mg/Nm3, respectively.

describe the NO formation/destruction process. The predictions, Figure 4, show the dependence of NO content on the gas temperature and the concentration of reactants, in this case HCN and O2, that produce fuel NO by homogeneous reactions, eq 4. Reactions of NO reduction with HCN are also taking place, eq 6. As expected, thermal NO originates in a narrow region of maximal local temperatures in the furnace (1650−1800 K). Because fuel NO is, by far, more important than thermal NO (within the expected range of gas temperatures), the dependence of fuel NO determines the character of the total NO concentration field. Simulations showed that the contribution of thermal NO was on the order of several percentage points of the total NO. Figure 4 suggests significant influence of HCN and thus also of the nitrogen

content in the coal, which is the source of HCN, on the NO content. A narrow zone of high NO concentrations in the region of the lowest-stage burners, into which the major part of the fuel is injected, corresponds to the maximum of HCN content. A wider zone of high NO concentrations can be seen and is related to the region of intensive chemical reactions of HCN depletion and NO formation. In contrast to thermal NO, the content of fuel NO (and the total NO) is less affected by temperature. In addition to the nitrogen content in the fuel, it is strongly influenced by air to fuel ratio (excess air), that is, oxygen concentration. NO concentration field does not follow only the temperature and HCN concentration field but even more O2 concentration field. In spite of high temperatures, there is no high NO concentration in the central region of the 434


Energy & Fuels

Article

Figure 6. Uneven distribution of fuel and air over the individual burners, temperature field and the NOx content in test-cases 17 (a) and 28 (b): FEGT = 1015 and 993 °C, NOx emission = 428.0 mg/Nm3 and 307.7 mg/Nm3, respectively.

and 4, FEGT is higher, while in the former NOx emission exceeds domestic emission limit (450 mg/Nm3, measured as NO2, dry basis, 6% O2 in flue gases). In test-case 7, in which 86.4% of pulverized coal is supplied to the lower-stage burners, NOx emission reduction of 18.6% was predicted. In test-case 5, where 84% of the fuel is supplied to the lower-stage burners, the emission reduction is 16%, with FEGT approaching the predicted value for standard conditions at full load and the flame positioned optimally, Figure 7. In test-case 11, 90% of pulverized coal is injected through the lower-stage burners and 16.9% emission reduction is achieved. A comparison between test-cases 1, 3, and 11, Figures 4 and 5, suggests that the increase of the pulverized coal fraction through the lower-stage burners provides a decrease of both FEGT and NOx emission, while the flame is descending. In test-cases 1, 12, and 13, there is the same distribution of coal between lower- and upper-stage

furnace, Figure 4, because of the oxygen depletion by intensive reactions of the fuel combustion. In the model, this strong dependence of NO content on oxygen is described by the eq 5, which gives the dependence of the coefficient α on the local oxygen concentration, where α is the exponent of the mole fraction XO2 in eq 4 for fuel NO formation reaction rate. Variations in Operating Conditions: Test-Cases. A summary of the test-cases is shown in Table 6, while selected ones are also presented in Figures 5−8. Test-cases 2−21 investigate the influence of pulverized coal and preheated air distribution over the burner tiers. In test-cases 2−4 (using the centrifugal separators) and test-cases 5−10 (using the louver separators), the coal distributions over the burner tiers were obtained by investigations of the coal mills at the facility. When compared with test-case 1, minor NOx emission reduction is obtained in test-case 2, with similar FEGT. In both test-cases 3 435


Energy & Fuels

Article

Figure 7. Influence of the preheated air distribution over the burner tiers on the temperature field and the NOx content in test-cases 5 (a) and 19 (b): 84% coal/74% secondary air and 84% coal/60% secondary air through the main burners, FEGT = 1020 and 991 °C, NOx emission = 348.7 mg/ Nm3 and 320.3 mg/Nm3, respectively.

burners, 70% and 30%, but different distribution between upper and lower tiers of the stages. Increase in the coal fraction through the upper tiers of the stages provided higher values of both the FEGT (due to the higher flame position) and the emission. In test-cases 14−16, moving segments of the louver separators are closed, opened 15°, and opened 30°, providing 76%, 70%, and 64% of coal through the lower-stage burners, respectively. Compared with the reference test-case, NOx emission is reduced only in test-case 14 (13%), but the FEGT is higher. Uneven distribution of fuel and air over the individual burners, studied in test-case 17 (see Table 7) provides, to some extent, lower FEGT and higher emission than in test-case 1 but not considerably so. However, the flame is nearly centered in the furnace cross-section, Figure 6a, which is to decrease the

water-walls thermal stresses and diminish the conditions for fouling and slagging. In test-case 18, there is significant increase of the cold air ingress. Compared with test-case 6, for the same distribution of pulverized coal and air over the burner tiers, the emission remained virtually unchanged. Although it is considerably lower than in the reference test-case 1, FEGT is decreased to such an extent that it is impossible to achieve guaranteed parameters of steam. A 20% difference in secondary air through the lower-stage burners between test-cases 19 and 5 (60% instead of 74.2%), provided decrease in FEGT and the emission reduction of 22.8%, i.e. 8.1%, with respect to test-cases 1 and 5, respectively, with the flame given in Figure 7. In test-cases 20 and 21, the entire amount of fuel is injected through the lower-stage burners evenly, while 10% and 30% of the secondary air comes 436


Energy & Fuels

Article

Figure 8. Influence of the case-study coals characteristics on the temperature field and the NOx content in test-cases 25 (a) and 27 (b): LHV (as received) = 6071 kJ/kg and 8374 kJ/kg, FEGT = 916 and 1115 °C, NOx emission = 237.2 mg/Nm3 and 445.3 mg/Nm3, respectively.

case 1 (guarantee coal), Figure 4. In general, there is a fluctuation of the coal quality during the boiler operation. As expected, the fuels with different lower heating value (LHV) provide different temperature and NOx concentration field in the case-study furnace. The effect on both the emission and FEGT is considerable. Thus, although the emission reduction in test-case 25 is 42.8%, predicted FEGT is excessively low. The combined effect of different operation parameters was examined in test-cases 28 and 29. Test-case 28 differs from testcase 11 by uneven operation mode of the burners (see Table 7), providing nearly centered flame position, Figure 6b. Significant emission reduction is achieved, 25.8%, compared with the reference test-case 1 (10.7%, compared with test-case 11). In contrast with test-case 28, there is finer grinding of coal (dp = 100 μm, instead of 150 μm) in test-case 29, while about 20% of secondary air is redirected from the lower- to the upperstage burners. Achieved emission reduction is 30%, compared

through the upper-stage burners (as if they were OFA ports). The emission reduction in test-case 21 is 21.5% and 13.2%, if compared with test-cases 1 and 20, respectively. Different values of grinding fineness of coal were studied through the variation in initial particle size of pulverized coal: dp = 50, 100, and 300 μm in test-cases 22−24, respectively, compared with dp = 150 μm in the reference test-case. Finer grinding of coal, but only to some extent, (dp = 100 μm) provided slightly lower NOx emission (about 5%), but dp = 50 μm gave a slight increase in the emission. Although for dp = 300 μm the emission reduction of 16.1% was predicted, obtained FEGT was excessively low. In addition, completely different geometry of the flame was predicted for different valuses of grinding fineness of coal.13 In test-cases 25−27, different coal qualities were investigated: guarantee coal for the mill, lower guarantee quality, and upper guarantee quality, respectively, Figure 8, compared with test437


Energy & Fuels

Article

Table 8. Case-Study Boiler Unit Operation Parameters in the Selected Test-Cases FEGT (°C) water injection into superheated steam pipeline (kg/s) superheated steam temp. (°C) water injection into reheated steam pipeline (kg/s) reheated steam temp. (°C) fuel consumption (kg/s) FEGT (°C) flue exit gas loss (%) boiler efficiency (%)

test-case 6

test-case 5

test-case 11

test-case 17

test-case 19

test-case 21

test-case 7

1033 18.82 540 5.49 540 120.8 159.3 11.69 85.02

1020 15.50 540 4.21 540 120.3 158.9 11.66 85.06

997 4.12 540 2.07 540 119.5 158.2 11.60 85.11

995 3.08 540 1.88 540 119.4 158.2 11.60 85.12

991 1.01 540 1.57 540 119.3 158.1 11.59 85.13

988 0.27 538 1.20 540 118.8 157.9 11.58 85.14

982 0.49 536 0.78 540 118.4 157.7 11.56 85.15

and combined CFD analyses and thermal calculations of the boiler units are rare. The amount of heat received by the third stage of the superheater (the final stage, with respect to the steam flow) is increased, as a result of higher FEGT and rise in logarithmic mean temperature difference between the two streams (heat supplier and heat receiver, hot and cold stream). To keep the superheated steam temperature at 540 °C, in the case of FEGT = 1033 °C, the water injection into the superheated steam pipeline should be 18.82 kg/s, Table 8. Lower FEGT results in the decreased amount of exchanged heat by the third stage of the superheater and reduced amount of the injected water as well. A problem arises at the FEGT below 990 °C, because it is impossible to achieve the required superheated steam temperature of 540 °C. The second stage of the reheater (the final stage with respect to the steam flow) is situated above the third stage of the superheater (referring to the gas flow). The second stage of the reheater also receives the increased amount of heat at the higher furnace exit gas temperature. This increase is slightly less in comparison with the increase of the third stage of the superheater. The amount of water injected into the reheated steam pipeline is reduced with the decrease in FEGT, Table 8. Nevertheless, in all considered test-cases the required temperature of the reheated steam of 540 °C at the outlet is attained. In the case of considered boiler type, temperature control of the reheated steam is accomplished only by water injection between two stages (biflux and triflux heat exchangers are not included in this arrangement). The additional effects of the increase in amount of the injected water (into reheated steam pipeline) are the reduced efficiency of the boiler and higher fuel consumption; see Table 8. Taking into account larger amount of exchanged heat in the third stage of the superheater and the second stage of the reheater at higher FEGT, the flue gas temperatures at the inlet and outlet of the other heat transfer surfaces approach the desired temperatures. Flue gas temperature at the boiler exit and, consequently, the boiler efficiency, do not change significantly in dependence on the FEGT, as can be seen from Table 8. On the basis of the boiler thermal calculation, it can be concluded that the optimal range of the FEGT is 995−1010 °C (i.e., 990−1010 °C), with respect to the safe operation of the third stage of the superheater and attainment of required superheated steam temperature of 540 °C. Within this temperature range, the water injection into the reheated steam pipeline is minimal. Regarding these recommendations, the optimal test-cases, among the selected ones shown in Table 8, would be test-cases 11 and 17, and, very close to them, 19.

with the reference test-case (5.6%, compared with test-case 28), but FEGT is somewhat decreased. It is important to note that the uneven operation mode of the burners (giving favorable centered flame position) did not provide negative effects on both the emission and FEGT, in the examined cases. Simulations for test-cases 2−27 were done to determine influence of individual modifications of the process, such as air and coal flow rates, coal grinding guage, and coal quality. Altering the distribution of air and coal over the burner tiers has significant influence on the combustion process. Finer pulverization of coal, to a certain extent, reduces emission, but the reduction of FEGT is also present. Coals with reduced LHV have lower emission and FEGT. After getting an insight into the advantages of certain combustion process modifications, two new test-cases were created, simulating the combined influence of several parameters. Test-cases 28 and 29 have proper distribution of both air and fuel over the burner tiers, uneven burner operation, and varied coal particle size. They show that, by combining multiple primary measures, good NOx emission reduction can be obtained. In addition, simulations show that temperatures of both the air−coal dust mixture gas phase and the preheated air, in the range expected in the case-study furnace, do not affect NOx emission substantially. Analysis of Combustion Modifications regarding Boiler Efficiency. The analysis of primary techniques for NOx reduction may have more components, since most deNOx measures based on combustion modifications reduce boiler and plant efficiency through increased burnout losses. The conflict between low NOx emission and high boiler thermal efficiency encounters, especially for existing coal-fired utility boilers retrofitted with air staging. The adjustment of boiler operating conditions, including excessive air ratio and secondary air distribution pattern, as well as OFA damper openings, have to be performed to avoid noticeable decrease of boiler thermal efficiency and to balance between boiler thermal efficiency and NOx emission.25 Even when combustion modifications applied to reduce the emission do not disturb the boiler unit efficiency, it is necessary to verify the measures with respect to the safe operation of the superheater and the attainment of required superheated steam temperature. With respect to predicted NOx emission, FEGT, and the pulverized coal flame, combustion modifications for several test-cases were selected. Analysis of the combustion modifications was performed by the boiler thermal calculations,26 enabling evaluation of the heat transfer surfaces operation efficiency. Global thermal calculation of the boiler was done for the guarantee coal, on the basis of predicted FEGT (Table 8) for selected test-cases. In the available literature, such complex 438


Energy & Fuels

Article

(10%, 20%, or 30% subtracted from the secondary air). Different air flow rate through the OFA ports and its dimensions affect the air speed, influencing the penetration of the air into the combustion chamber and level of mixing with flue gases and unburned fuel, which significantly impact the combustion process. Modified code was tested to provide the stability and convergence of solution. The new numerical grid consists of 140 × 65 × 65 = 591 500 nodes. For each configuration of OFA ports, a developed mesh generator distributes the grid nodes so that, in this area, the grid is properly refined in axial direction. Previously obtained results of simulations for the same boiler (Table 6) were used for selection of test-cases to be simulated with OFA ports. Test-cases 11, 17, 19, and 28 already had satisfying FEGT (990−1010 °C), and relatively low NOx emission. Simulations also considered some test-cases where FEGT was too high or/and the emission was relatively high. It was reported that, depending on the conditions after the application of OFA ports, FEGT could decrease,15 or increase.27 Thus, test-cases 1, 3, 10, 14, 16, and 23 were selected to test whether it was possible to reduce the NOx emission and FEGT to an acceptable value simultaneously, only by using OFA method. For each of the basic test-cases, 12 combinations of height−position−percentage of secondary air for OFA were examined, as in Tables 9 and 10. Here, only some characteristic test-cases giving the best effects are separately analyzed. Test-case 1, without OFA ports, achieves FEGT higher than optimal and NOx emission below both the current European (500 mg/Nm3, measured as NO2, dry basis, 6% O2 in flue gases) and domestic emission limit (450 mg/Nm3, measured as NO2, dry basis, 6% O2 in flue gases). By using the OFA method, FEGT is decreased to the required value and the emission is additionally reduced up to 5.4%. Preferred effects are achieved at both positions of OFA ports (3 and 6 m), for both heights (0.5 and 1 m). Test-case 3 is not optimized without OFA ports and achieves higher FEGT and NOx emission than allowed. By using the OFA method FEGT is lowered to the optimum range and NOx emission is reduced considerably (reduction up to 24.1%), Table 9. Parameters that achieve preferred effects are the OFA ports position at 6 m and height of 0.5 m. Flame position and NOx content in the furnace, velocity vector field through the level of OFA ports, as well as the penetration of OFA jet into the furnace, are illustrated in Figure 11. Test-case 10 without OFA achieves higher FEGT and NOx emission near the upper limit. By implementing OFA, the NOx emission is reduced up to 18.2% and FEGT is lowered to a suitable value; see Table 10. The optimal position of OFA ports is 3 m, for both heights, and 6 m (at a height of 1 m). Test-case 17 does not achieve desired FEGT without OFA ports but has satisfactory emission. OFA ports in certain conditions give reduction of FEGT. In those cases, the emission is additionally reduced up to 7.7%. The effects are achieved when OFA port position is 3 m for both heights and 6 m for the port height of 1 m. To determine OFA performance at partial loads, additional simulations were performed. The following test-cases at full load were selected as reference cases: test-cases 3 and 10 (without OFA) and test-cases 3−12 and 10−9 (with OFA). These test-cases were numerically simulated at partial loads (90% and 70%). In all examined test-cases, the application of OFA provided considerable NOx emission reduction, even in

Similar FEGT exist also in the cases 22 and 28, as shown in Table 6. Numerical Prediction of OFA Influence on NO x Emission and FEGT. One of the most common primary methods of NOx emission reduction is injection of 10−30% of secondary air outside the burners area, above the flame, through the OFA ports. 70−90% of secondary air is injected through the burners, so that fuel rich zone and lower flame temperature are achieved, allowing lower NOx content in this region, than for conventional systems. To achieve complete combustion, the remaining secondary air is injected through OFA ports. In this region, because of the local increase in excess air, temperatures and, consequently, the NOx emission are decreased. To predict the application of OFA ports, a special, modified code was developed and the user-oriented interface of the software,13 was improved to enable input of OFA system operating parameters, as shown in Figure 9. The ports are

Figure 9. Form for data input of OFA system operating parameters.

Figure 10. Burner tier before adding OFA ports, four simulated positions and shapes of OFA port.

placed above the burners, as shown in Figure 10. Each port has the same width as the burner below it. The air introduced through OFA ports tangents the same imaginary circle as the secondary air and air−coal dust mixture streams. To optimize the OFA ports, the following parameters were varied in simulations: height (0.5 or 1 m), vertical position (3 or 6 m above the burners), and the air injected through the OFA ports 439


Energy & Fuels

Article

Table 9. Results of Numerical Simulation of OFA Ports Application to Test-Case 3 testcase

3

a

OFA testcase

secondary air for OFA ports (%)

vertical position of portsa (m)

height of ports (m)

1 2 5 6 8 9 10 11 12

10 10 20 20 20 30 30 30 30

3 3 3 3 6 3 3 6 6

1 0.5 1 0.5 0.5 1 0.5 1 0.5

FEGT without ports (°C)

FEGT with ports (°C)

1093

1075 1063 1047 1034 1040 1022 1015 1027 1011

NOx emiss. without ports (mg/Nm3)

NOx emiss.with ports (mg/Nm3)

emiss. reduct. (%)

468.0

410.4 402.4 375.3 381.7 375.8 347.2 365.3 342.6 355.2

12.3 14.0 19.8 18.4 19.7 25.8 21.9 26.8 24.1

NOx emiss. with ports (mg/Nm3)

emiss. reduct. (%)

394.7 371.6 362.1 380.6 375.0 349.9 340.5 360.6 354.4

7.7 13.1 15.3 11.0 12.3 18.2 20.4 15.7 17.1

b

b

With respect to the top level of the burners. bNormal conditions (0 °C, 1013 mbar), dry basis, 6% O2 in flue gases

Table 10. Results of Numerical Simulation of OFA Ports Application to Test-Case 10 testcase

OFA testcase

secondary air for OFA ports (%)

vertical position of portsa (m)

height of ports (m)

10

1 5 6 7 8 9 10 11 12

10 20 20 20 20 30 30 30 30

3 3 3 6 6 3 3 6 6

1 1 0.5 1 0.5 1 0.5 1 0.5

a

FEGT without ports (°C)

FEGT with ports (°C)

1069

1052 1022 1009 1037 1015 996 983 1004 985

b

NOxemiss.without ports (mg/Nm3)

b

427.7

With respect to the top level of the burners. bNormal conditions (0 °C, 1013 mbar), dry basis, 6% O2 in flue gases

■

CONCLUSIONS A comprehensive numerical study was performed on the effects of primary de-NOx measures (i.e. combustion modifications) in the pulverized lignite tangentially fired furnaces of 350 MWe Kostolac B-1 and B-2 utility boiler units, on NOx emission, FEGT, and the pulverized coal flame. Predictions were done by an in-house developed submodel of fuel- and thermal-NO formation/destruction, using simplified chemical kinetics in conjunction with detailed CFD calculations performed by previously developed 3D combustion code. The NOx model was validated by comparisons between numerical results for NOx emission with the available results of measurements on the case-study boiler units performed during 2007−2011. A high degree of predictive ability was demonstrated. The results suggest that developed NOx model is capable of reproducing different trends in NO formation/destruction, associated with the dissimilar operating conditions. After validation, the model was applied to study the possibility of reducing NOx emission by combustion modification in the case-study furnace, only by tuning different operating parameters, without need for construction changes. With respect to predicted NOx emission and FEGT, the most promising test-cases, that is, combustion modifications, were selected and then verifiedoptimized by the boiler thermal calculations. The calculations were applied to examine whether the selected primary measures disturb operation of the boiler unit. The calculations proposed an optimal range of FEGT: 990 °C (995 °C)−1010 °C, which provided a safe operation of the superheater third stage and the required superheated steam temperature of 540 °C. The impact of OFA was also examined. To introduce OFA ports, the software was modified and graphical user interface was updated, so that the choice of various combinations of OFA parameters

the case of partial loads. However, at partial loads, the performance of OFA is decreased to some extent; see Table 11. By reviewing numerical results for all test-cases simulated with OFA ports, the following can be concluded: (a) Before applying the OFA method, test-cases 3 and 16 had too high FEGT and NOx emission above the limit. After applying OFA method, test-case 3 showed reduction in NOx emission below the emission limits and decrease of the FEGT to an acceptable range, while this was not achieved in test-case. (b) Before applying the OFA method, test-cases 1, 10, 14, 17, and 23 had too high FEGT and good NOx emission. After applying OFA method, test-cases 1, 10, 17, and 23 showed reduction of NOx emission and a decrease of the FEGT to an acceptable range, while this was not achieved in test-case 14. (c) Before applying the OFA method, test-cases 11, 19, and 31 had optimal FEGT and NOx emission. After applying OFA method test-case 11 showed reduction of NOx emission with acceptable FEGT. Test-cases 19 and 31 did not achieve simultaneously required FEGT and NOx emission reduction. From all the obtained data for the given test-cases, it can be concluded that it would be recommendable to place the OFA ports 6 m above the burners with the OFA port height of 1 m. It would also be desirable in some cases to enable reducing the ports cross-section (e.g., by closing the half of the port with the shutter mechanism). The predicted reduction of NOx emission is up to 24% in the basic test-cases with relatively high emissions and up to 7% of additional emission reduction for already optimized test-cases. 440


Energy & Fuels

Article

Figure 11. OFA test-case TS-3−12: (a) temperature field in the furnace; (b) NOx content; (c) velocity field at the level of OFA ports with the intensity of the V component; (d) velocity field at the level of OFA ports with the intensity of the gas temperature; (e) penetration of OFA, isometric view; (f) penetration of OFA, front view. 441


Energy & Fuels

Article

appreciate contribution of Dr. Miroslav Sijercic and Dr. Slobodan Djekic, as well as assistance of Dr. Predrag Radovanovic regarding the large-scale measurements used in the model validation.

Table 11. NOx Emission for Different Loads of the Boiler full load, 100%

test-case

NOx emiss. (mg/ Nm3)

3 3−12 10 10−9

468 355 428 350

a

reduction (%) 24.1 18.2

partial load, 90% NOx emiss. (mg/ Nm3) 485 397 435 377

reduction (%) 18.1 13.3

partial load, 70%a NOx emiss. (mg/ Nm3) 494 405 435 385

■

reduction (%) 18.0 11.5

Six burners in operation (burners 4 and 8 are turned off).

before simulation could be easily accomplished. The geometrical and operational characteristics of OFA ports were optimized. Repeated numerical experiments provide recommendations for NOx emission reduction and efficient operation of the casestudy boiler, as follows. The coal and preheated air flow rate distribution over the individual burners and the burner tiers (i.e., a proper tuning of the local air excess in the burners region), quality and grinding fineness of coal and cold air ingress have significant impact on NOx emission. Temperatures of both the air−coal dust mixture and the preheated air, over the ranges expected during the utility boiler exploitation, do not have significant influence on the emission. By a proper organization of combustion process only, without construction changes in the facility, NOx emission reduction of up to 20− 30% can be achieved, together with the improvement of the flame position and FEGT. Regarding numerical predictions, the following combustion modifications are proposed: about 85% of pulverized coal introduced through the lower-stage burners; local excess air control in the burners region by redirecting up to 20% of secondary air from the lower- to the upper-stage burners; finer grinding of coal (to some extent), alone, or in combination with less preheated air injected through the lowerstage burners. Application of OFA can provide NOx emission reduction of up to 24% in the test-cases with relatively high emission and up to 7% of additional reduction of the emission in already optimized cases. Regardless of decrease in performance when operating under the partial loads of the boiler, OFA still achieves good NOx emission reduction. The presented results demonstrate the improvement of operating conditions during the operation of the case-study boiler furnace, regarding both the emission and the boiler unit efficiency. They can provide conditions for reliable evaluation of future proposals for NOx emission reduction during combustion of the case-study coal and for decision-making in retrofitting of the case-study boiler units.

■

REFERENCES

(1) Fan, J.; Sun, P.; Zha, X.; Cen, K. Energy Fuels 1999, 13, 1051− 1057. (2) Karpenko, E. I.; Messerle, V. E.; Ustimenko, A. B. Proc. Combust. Inst. 2007, 31, 3353−3360. (3) Zeng, L.; Li, Zh.; Zhao, G.; Shen, Sh.; Zhang, F. Energy Fuels 2010, 24, 5349−5358. (4) Chen, Zh.; Li, Zh.; Zhu, Q.; Jing, J. Energy 2011, 36, 709−723. (5) Modlinski, N. Fuel Process. Technol. 2010, 91, 1601−1608. (6) Coelho, L. M. R.; Azevedo, J. L. T.; Carvalho, M. G. Application of a Global NOx Formation Model to a Pulverized Coal Fired Boiler with Gas Reburning. Proceedings of the Fourth International Conference on Technologies and Combustion for a Clean Environment, Lisbon, Portugal, July 7−10, 1997. (7) Xu, M.; Azevedo, J. L. T.; Carvalho, M. G. Fuel 2000, 79, 1611− 1619. (8) Zheng, Ch.; Liu, Zh.; Duan, X.; Mi, J. Proc. Combust. Inst. 2002, 29, 811−818. (9) He, R.; Suda, T.; Takafuji, M.; Hirata, T.; Sato, J. Fuel 2004, 83, 1133−1141. (10) Li, K.; Thompson, S.; Peng, J. Control Eng. Pract. 2004, 12, 707−723. (11) Diez, L. I.; Cortes, C.; Pallares, J. Fuel 2008, 87, 1259−1269. (12) Belosevic, S.; Sijercic, M.; Tucakovic, D.; Crnomarkovic, N. Fuel 2008, 87, 3331−3338. (13) Belosevic, S.; Sijercic, M.; Crnomarkovic, N.; Stankovic, B.; Tucakovic, D. Energy Fuels 2009, 23, 5401−5412. (14) Hashimoto, N.; Kurose, R.; Tsuji, H.; Shirai, H. Energy Fuels 2007, 21, 1950−1958. (15) Makovička, J. Mathematical Model of Pulverized Coal Combustion. Ph.D. Thesis, Czech Technical University in Prague, Faculty of Nuclear Sciences and Physical Engineering, 2008. (16) Straka, R.; Beneš, M. Open Thermodyn. J. 2010, 4, 27−35. (17) Lockwood, F. C.; Romo-Millares, C. A. J. Inst. Energy 1992, 65, 144−152. (18) Hill, S. C.; Smoot, L. D. Prog. Energy Combust. Sci. 2000, 26, 417−458. (19) Smoot, L. D.; Smith, P. J. Coal Combustion and Gasification; Plenum Press: New York, 1985. (20) Blokh, A. G. Thermal Radiation of a Pulverized-Coal Flame. InHeat Transfer in Steam Boiler Furnaces; Hemisphere Publishing: New York, 1988; pp 85−124. (21) Solomon, P. R.; Colket, M. B. Fuel 1978, 57, 749−755. (22) De Soete, G. G. Proc. Combust. Inst. 1975, 15, 1093−1102. (23) De Soete, G. G. Proc. Combust. Inst. 1990, 23, 1257−1264. (24) Smith, P. J.; Hill, S. C.; Smoot, L. D. Proc. Combust. Inst. 1982, 19, 1263−1270. (25) Li, S.; Xu, T.; Hui, Sh.; Wei, X. Appl. Energy 2009, 86, 1797− 1803. (26) Brkic, Lj.; Zivanovic, T.; Tucakovic, D. Thermal Calculation of Steam Boilers; Faculty of Mechanical Engineering: Belgrade, Serbia, 2002 (in Serbian). (27) Eaton, A. M.; Smoot, L. D.; Hill, S. C.; Eatough, C. N. Prog. Energy Combust. Sci. 1999, 25, 387−436.

AUTHOR INFORMATION

Corresponding Author *Phone: (+381-11) 3408-834. Fax: (+381-11) 2453-670. Email: [email protected].

■

ACKNOWLEDGMENTS This work has been supported by the Republic of Serbia Ministry of Education and Science (project: “Increase in energy and ecology efficiency of processes in pulverized coal-fired furnace and optimization of utility steam boiler air preheater by using in-house developed software tools”, No. TR-33018) and the Electric Power Industry of Serbia. The authors also greatly 442


Numerical Analysis of NOx Control by

Recommend Documents