Numerical Modeling of Victorian Brown Coal Combustion in a

Aug 23, 2010 - (2) One challenge in the use of Victorian brown coal for power ..... M.; Korytni , E.; Chudnovsky , B.; Talanker , A.; Bar-ziv , E. Fue...
0 downloads 0 Views 4MB Size
Download PDF
Energy Fuels 2010, 24, 4971–4979 Published on Web 08/23/2010

: DOI:10.1021/ef100514v

Numerical Modeling of Victorian Brown Coal Combustion in a Tangentially Fired Furnace Zhao F. Tian,* Peter J. Witt, M. Phillip Schwarz, and William Yang Mathematics, Informatics and Statistics, Commonwealth Scientific and Industrial Research Organisation (CSIRO), Post Office Box 312, Clayton South, Victoria 3169, Australia Received April 22, 2010. Revised Manuscript Received July 14, 2010

A computational fluid dynamics (CFD) model of a 375 MW brown-coal-fired furnace in the Latrobe Valley, Australia, has been developed using ANSYS CFX 12.0. To improve the model predictions, a coal combustion model that takes into consideration carbon monoxide reactions has been utilized in ANSYS CFX 12.0. A level of confidence in the current CFD model has been established by carrying out a mesh independence test and validation against the furnace gas exit temperature (FGET), concentration of flue gas components, total boiler heat supply, and the wall incident heat fluxes measured in the power plant. The validated CFD model is then applied to investigate the effects of several operating conditions at full load, such as different out-of-service firing groups and different combustion air distributions on the coal flame. It is found that the selection of out-of-service firing groups has a considerable effect on coal combustion in terms of high-temperature zone shape and location and distribution of incident radiation heat flux on furnace walls. Model results also indicate that redistributing and increasing the velocity of the combustion air can change the location of the high-temperature zone in the furnace, therefore reducing the peak incident heat flux on the furnace walls. A reduction in peak heat flux is likely to lead to a reduction in furnace wall slagging. This study provides a basis for further assessment of future operation of dried brown coal in the existing furnaces in the Latrobe Valley, which were designed and currently operate using raw brown coal.

coal without pre-drying) in the furnaces under different operating conditions and to assess future operation of predried brown coal in the existing furnaces. CFD has the capacity to provide detailed information about coal combustion in furnaces, such as flame shape, gas velocity field, gas composition, temperature profiles, particle trajectories, radiation heat flux, fouling and slagging, as well as flue gas emissions. CFD has been extensively used to model various pulverized coal-fired furnaces, including front-wallfired furnaces with swirl burners,5 opposite-wall furnaces,6 down-fired furnaces,7 and tangentially fired furnaces.6,8-27

Introduction Brown coal has been the main energy source for the steady economic development in the state of Victoria in Australia for many years.1 About 97% of this brown coal is consumed by power stations in the Latrobe Valley region, producing over 85% of the electricity supply of Victoria.2 One challenge in the use of Victorian brown coal for power generation is the high greenhouse gas emission partially caused by its high moisture content, up to 70% by weight. For example, the CO2 emission per unit of electricity produced by the brown coal-fired power plant of TRUenergy in the Latrobe Valley is 1.42 tons of CO2/ MWh,3 while that of a typical Australian black coal-fired power plant is about 0.9 ton of CO2/MWh.4 The authors have been carrying out a research project “Modeling and Experimental Study of Latrobe Valley Brown Coal Combustion” for the Department of Primary Industries of Victoria, Australia. The major objectives of this project are to develop and validate computational fluid dynamics (CFD) models of the brown coal-fired furnaces at Latrobe Valley, to simulate and analyze combustion of raw brown coal (as mined

(5) Stopford, P. J. Appl. Math. Modell. 2002, 26, 351–374. (6) Spitz, N.; Saveliev, R.; Perlman, M.; Korytni, E.; Chudnovsky, B.; Talanker, A.; Bar-ziv, E. Fuel 2008, 87, 1534–1542. (7) Sheng, C. D.; Moghtaderi, B.; Gupta, R.; Wall, T. F. Fuel 2004, 83, 1543–1552. (8) Boyd, R. K.; Kent, J. H. Proc. Combust. Inst. 1986, 21, 265–274. (9) Lockwood, F. C.; Salooja, A. P. Combust. Flame 1988, 54, 23–32. (10) Boyd, R. K.; Kent, J. H. Energy Fuels 1994, 8, 124–130. (11) Zhou, L. X.; Li, L.; Li, R. X.; Zhang, J. Powder Technol. 2002, 125, 226–233. (12) Zhou, Y.; Xu, T.; Hui, S.; Zhang, G. Appl. Therm. Eng. 2009, 29, 732–739. (13) Belosevic, S.; Sijercic, M.; Oka, S.; Tucakovic, D. Int. J. Heat Mass Transfer 2006, 49, 3371–3378. (14) Belosevic, S.; Sijercic, M.; Tucakovic, D.; Crnomarkovic, N. Fuel 2008, 87, 3331–3338. (15) Belosevic, S.; Sijercic, M.; Crnomarkovic, N.; Stankovic, B. Energy Fuels 2009, 23, 5401–5412. (16) Backreedy, R. I.; Jones, J. M.; Ma, L.; Pourkashanian, M.; Williams, A.; Areninllas, A.; Arias, B.; Pis, J. J.; Rubiera, F. Fuel 2005, 84, 2196–2203. (17) Kumar, M.; Sahu, S. G. Energy Fuels 2007, 21, 3189–3193. (18) Bris, T. L.; Cadavid, F.; Caillat, S.; Pietrzyk, S.; Blondin, J.; Baudoin, B. Fuel 2007, 86, 2213–2220. (19) Diez, L. I.; Cortes, C.; Pallares, J. Fuel 2008, 87, 1259–1269. (20) Choi, C. R.; Kim, C. N. Fuel 2009, 88, 1720–1731.

*To whom correspondence should be addressed. Telephone: þ61-395458855. Fax: þ61-3-95628919. E-mail: [email protected]. (1) Li, C. Z. Introduction. In Advances in the Science of Victorian Brown Coal; Li, C. Z., Eds.; Elsevier: Amsterdam, The Netherlands, 2004; Chapter 1, pp 1-8. (2) Allardice, D. Aust. Coal Rev. 2000, October, 40–46. (3) TRUenergy Yallourn Power Station. TRUenergy Social and Environmental Snapshot, 2009; http://www.truenergy.com.au/downloads/ TRU_SEsnapshot_web2009.pdf. (4) Cottrell, A. J.; McGregor, J. M.; Jansen, J.; Artanto, Y.; Dave, N.; Morgan, S.; Pearson, P.; Attalla, M. I.; Wardhaugh, L.; Wardhaugh, L.; Yu, H.; Allport, A.; Feron, P. H. M. Energy Procedia 2009, 1, 1003– 1010. Published 2010 by the American Chemical Society

4971

pubs.acs.org/EF

Energy Fuels 2010, 24, 4971–4979

: DOI:10.1021/ef100514v

Tian et al.

Several particular research topics about the CFD modeling of coal combustion in tangentially fired furnaces are briefly reviewed. CFD modeling work on coal combustion in the 1980s8,9 mainly addressed preliminary model validation and demonstrated the potential of CFD models for coal combustion applications.9 In these studies, mesh densities were relatively low because of the limit of computing power and simple combustion models were used. Nevertheless, the CFD results showed reasonable agreement with plant measurements of gas velocity, temperature profile, and wall heat transfer. With advances in computing power, numerical algorithms, and measurement techniques, more comprehensive validations of CFD results have been reported in the literature.10-12 More recently, CFD has been employed to study the performance of tangentially fired furnaces under different operating conditions, namely, out-of-service burners, coal blend and switch, particle size distribution, air and coal mass flow rates, burner tilt degree, and excess air ratio. Belosevic et al.13 carried out a numerical simulation of Serbian lignite combustion with different grinding fineness of coal and coal quality. The CFD results showed that fine particles burn rapidly, giving higher concentrations of CO2 than those of coarse particles. Belosevic et al.14 modeled coal combustion under different operating conditions in a 350 MW tangentially fired boiler. Their model successfully predicted the influence of outof-service burners, air/fuel ratio, and boiler load, on the furnace process and operation characteristics. Recently, Belosevic et al.15 presented a further investigation on the coal flame of the boiler14 under different operating conditions, including different coal and air flow arrangements, particle size distributions, and operation scheme of the coal mills. Spitz et al.6 simulated and analyzed the influence of a sub-bituminous coal with high moisture content on the performance of tangentially fired and opposite-wall utility boilers, which were designed for bituminous coals. Backreedy et al.16 investigated the unburned carbon and NOx emission in a tangentially fired furnace combusting single coals and coal blends. They validated their models by comparing the simulation results of a drop tube reactor with measurements, and good agreement was achieved. For the tangentially fired furnace, the temperature predictions and NOx concentrations compared well to measured values. Kumar and Sahu17 numerically studied the effect of burner tilt angles on coal combustion in a 210 MW boiler. It was found that the burner tilt angle had considerable influence on the fire ball, furnace gas exit temperature (FGET), and heat flux distribution. More applications of CFD to predict NOx and flue ash emissions from coal combustion have also been reported.18-20 Other reported CFD simulations also cover particle ignition,21 particle burnout,22 gas-phase aerodynamics,23 gas temperature deviation,24,25 the reheater panel overheating problem,26 and water-wall corrosion.27 Generally, these studies found CFD

Figure 1. Geometry of the CFD model for TRUenergy Yallourn unit number 3.

to be a feasible and powerful tool for studying pulverized coal combustion in tangentially fired furnaces. This paper reports on the current progress of the CFD research on the Victorian brown coal combustion. A CFD model of unit number 3 furnace at the TRUenergy Yallourn power plant has been developed using the commercial package, ANSYS Workbench/CFX 12.0.28 This 375 MW tangentially fired furnace is fueled by the raw brown coal from Latrobe Valley coal mines without any pre-drying. Plant data, such as coal feed rates, coal properties, coal particle size distribution, and air flow rates, are used as input conditions in the model. The hydrocarbon combustion models available in ANSYS CFX 12.0 are not able to predict some combustion products, such as CO; to improve the model predictions, a coal combustion model that takes into consideration CO reactions has been utilized in ANSYS CFX 12.0 and is described below. The CFD modeling results are validated against measured FGET, concentration of flue gas components, total boiler heat supply, and incident heat fluxes on furnace walls. The validated model is then applied to investigate the effect of different operating conditions, including cases with different out-of-service firing groups and different combustion air distributions, on the raw brown coal combustion in the furnaces. The key original scientific contribution of the paper is a thorough analysis and understanding of the effects that different out-of-service firing groups and different combustion air distributions have on brown coal flames in industrialscale furnaces. To the best of the authors’ knowledge, it is the first paper to perform in-depth numerical investigations on the effects of different out-of-service firing groups on locally high wall heat flux, which is one of the main causes of slagging problems in an industrial-scale furnace and to propose and

(21) Asotani, T.; Yamashita, T.; Tominaga, H.; Uesugi, Y.; Itaya, Y.; Mori, S. Fuel 2008, 87, 482–490. (22) Chen, J. Y.; Mann, A. P.; Kent, J. H. Proc. Combust. Inst. 1992, 24, 1381–1389. (23) Hart, J. T.; Naser, J. A.; Witt, P. J. Appl. Math. Modell. 2009, 33, 3756–3767. (24) Xu, M.; Yuan, J. W.; Ding, S. F.; Cao, H. D. Comput. Methods Appl. Mech. Eng. 1998, 155 (1998), 369–380. (25) Yin, C. G.; Rosendahl, L.; Condra, T. J. Fuel 2003, 82, 1127– 1137. (26) He, B. S.; Zhu, L. Y.; Wang, J. M.; Liu, S. M.; Liu, B. L.; Cui, Y. T.; Wang, L. L.; Wei, G. Q. Comput. Fluids 2007, 36, 435–444. (27) Valentine, J. R.; Shim, H. S.; Davis, K. A. Energy Fuels 2007, 21, 242–249.

(28) ANSYS, Inc. ANSYS Workbench/CFX 12.0; ANSYS, Inc., Canonsburg, PA, 2009.

4972

Energy Fuels 2010, 24, 4971–4979

: DOI:10.1021/ef100514v

Tian et al.

investigate possible remedies by changing combustion air distributions.

are used in the CFD model. Properties of the high moisture content raw brown coal are given in Table 1. The moisture content of the raw coal in the duct system is 66% by weight. At the full load operation, six firing groups are normally required to supply 156 kg/s of raw brown coal particles through corresponding primary nozzles in vapor and main burners to the furnace. Hence, in normal operation, two firing groups are out of service with no coal flows. In this work, six different firing or out-of-service burner patterns are modeled with the configuration of each case, given in Table 2. Model results for cases 1-6 are presented to identify the effect of different out-of-service firing groups on raw brown coal combustion in the furnace. The location of each firing group and the predicted velocity vectors for case 1 on plane 1 are shown in Figure 4. The location of plane 1 is shown in Figure 3. In addition to different firing patterns, three different distributions of combustion air flow through the burners at full load are tested with firing groups 2 and 6 and 5 and 6 out of service (cases 7-10 as specified in Table 2). Distribution 1, listed in Table 2, corresponds to the airflow distribution used at the TRUenergy Yallourn power plant. The combustion air flow of each in-operation firing group under the full-load operation is 55 kg/s, which is supplied through the secondary air nozzles. These secondary air nozzles are located in the main and vapor burners above and below the primary nozzles. About 20 kg/s air flows through each of the out-of-service firing groups, protecting the burners from a large amount of radiant heat from the flame in the furnace. The second combustion air distribution case is a uniform distribution, where 46.25 kg/s of combustion air flows through each of the eight firing groups. The total combustion airflow pertaining to distribution 2 is the same as that for distribution 1, i.e., 370 kg/s. Air distribution 3 feeds 55 kg/s combustion air through each of eight firing groups, making a total of 440 kg/s combustion air. In this study, the coal flow rates and furnace gas out-flow rates through the off-takes are assumed to be evenly distributed between the six in-service firing groups. The temperature of the fuel gas and coal particles at the inlet of the burners is 170 °C, and the inlet temperature of the secondary air is 310 °C based on power plant data.

Experimental Section Boiler Geometry and Operating Conditions. The commercial package, ANSYS Workbench 12,28 has been selected to generate the model geometry. The boiler of unit number 3 at the TRUenergy Yallourn power plant is 77.5 m high and has a 15.9 m square cross-section. The unit generates 319 kg/s of steam, at 16.8 MPa and 541 °C, when operating at full-load conditions. The geometry of the CFD model for the boiler is shown in Figure 1 and includes part of the upstream burner ducts and extends up to the exit of the economizer. This furnace is equipped with eight firing groups. Each firing group is comprised of two wall-mounted slot main burners (upper and lower main burners), two vapor burners (upper and lower vapor burners), mill and duct system, and a gas off-take that extracts hot furnace gas to heat and dries the raw brown coal in the mill and duct system. The raw brown coal is fed to the duct system without any pre-drying process and pulverized by the mills to produce fine particles. The pulverized coal particles are fed to the furnace through the vapor and main burners. Typical coal size distributions of the pulverized brown coal at vapor and main burners are shown in Figure 2, and these size distributions

Figure 2. Pulverized coal particle size distribution at main and vapor burners. Table 1. Raw Brown Coal Properties proximate analysis

(wt %, db)

fixed carbon volatile matter ash

47.2 51.3 1.5

ultimate analysis

(wt %, daf)

C H N S O moisture (as received, wt %) gross dry specific energy (MJ/kg)

66.44 4.5 0.57 0.19 28.3 66 26.2

Figure 3. Isometric view of the furnace, showing location of ports, line 1, and plane 1.

Table 2. CFD Simulated Cases at MCR Conditionsa case number out-of-service burners combustion air distribution

1 2 and 6

2 3 and 6

3 4 4 and 6 5 and 6 distribution 1

5 6 and 7

6 6 and 8

7 8 2 and 6 5 and 6 distribution 2

9 10 2 and 6 5 and 6 distribution 3

a Combustion air distribution: distribution 1, 55 kg/s for each in-service burner and 20 kg/s for each out-of-service burner; distribution 2, 46.25 kg/s for all burners; distribution 3, 55 kg/s for all burners.

4973

Energy Fuels 2010, 24, 4971–4979

: DOI:10.1021/ef100514v

Tian et al.

to mix at the molecular level, sharing the same mean velocity, pressure, temperature, and turbulence fields.28 The bulk motion of the gas mixture is modeled using single velocity, pressure, temperature, and turbulence fields. Turbulence is modeled by the most widely used standard k-ε model, which has been found to perform well in a preliminary study of a non-swirl coal flame.29The gas-phase reactions are represented by a single-step combustion model based on an eddy dissipation assumption,30 which is based on the concept that the chemical reaction is fast relative to the transport processes in the flow. When the volatile gases or CO and oxygen mix at the molecular level, they instantaneously react and form products. The temperature, composition, and velocity of coal particles along their trajectories are predicted using a Lagrangian particle tracking model. Turbulent dispersion of particles is handled by integrating the trajectory equations for representative particles using the local fluid velocity along the particle path during the integration process. A stochastic method is used, in which 7100 sample coal particles are injected through each in-service firing group, summing to a total of 42 600 sample coal particles tracked in the furnace. The single first-order reaction (SFOR) model is used to calculate the devolatilization rate of the coal particles. This model assumes that the coal particle behaves isothermally and uniformly, regardless of their size, porosity, specific surface area, surface/mass ratio, and other coal characteristics.31 The preexponential factor and activation temperature in this study are taken from the work of Duong.32 The global reaction model is used to calculate the coal char oxidation. The pre-exponential factor and activation temperature of the char oxidation model are 497 kg m-2 s-1 and 8540 K based on the work of Wall et al.,33 respectively. Thermal radiation through the gas phase is modeled using a discrete transfer model. The radiation of the particle phase is included by assuming the particle emissivity εp to be a function of unburned carbon in particle Uc, i.e., εp = 0.4Uc þ 0.6. A “no-slip” boundary condition is employed along the wall for the gas phase. Heat transfer on the wall boundary is calculated by setting the temperature outside the furnace wall and heat-transfer coefficient through the water tube wall. Herein, the temperature outside the furnace is assumed to be the water and steam temperature in the water wall tubes. The watersteam system of the TRUenergy Yallourn unit 3 has a separating vessel that ensures that the water and steam in the water tubes are at the saturation temperature, 360 °C. The emissivity of the wall is set to be 0.7. On the basis of plant estimate, a mass flow rate of 6.5% of the total furnace gas flow flows through each off-take, giving a total of 39% of the total furnace gas flowing out from six in-service off-takes. The mass, momentum, chemical species, and energy equations are discretized using the finite volume approach. The discretized gas continuity and momentum equations are solved in a fully coupled manner. The convergence criterion for gasphase properties is 1.010-5 for the root-mean-square (rms) residuals. Further details regarding the fluid flow, turbulence models, radiation models, heat-transfer models, and coal combustion models along with simulation for a pilot-scale furnace can be found in a previous paper.29

Figure 4. Location of burners and predicted gas velocity vector on plane 1, case 1. Table 3. Heat Sink Values of Heat Exchangers Used in the CFD Model heat exchanger

heat sink value (MW)

superheater 1 superheater 2 superheater 3 superheater 4 reheater 1a reheater 1b reheater 2 economizer

76.1 77.6 145.2 80.2 25.6 40.7 114.2 77.8

Geometric details of the tubes in the convective passes have not been included in the current CFD model, because the main focus of the current study is on coal combustion and heat transfer in the radiant pass of the furnace. However, sink terms are added to the momentum and energy equations in the regions, where convective tube banks are located. The sink terms account for the effect of the tubes by imposing a pressure drop as a function of the gas-phase velocity as a means of damping the streamwise velocity components. Heat absorption in the convective tube banks is also included via sink terms, as given in Table 3. These values are based on the plant data. Computational Models. The commercial CFD code, ANSYS CFX 12.0,28 has been applied to construct a boiler model taking into account pulverized coal combustion. The hydrocarbon combustion models available in ANSYS CFX 12.0 are not able to predict some combustion products, such as CO; to improve the model predictions, a coal combustion model that takes into consideration CO reactions has been utilized in ANSYS CFX 12.0. The main reactions of the coal combustion model are coal f volatiles þ H2 O ðvaporÞ þ C ðcharÞ ð1Þ volatiles ðHCÞ þ O2 f CO þ H2 O

ð2Þ

1 C ðcharÞ þ O2 f CO 2

ð3Þ

1 CO þ O2 ¼ CO2 2

ð4Þ

(29) Tian, Z. F.; Witt, P. J.; Schwarz, M. P.; Yang, W. Combust. Sci. Technol. 2009, 181, 954–983. (30) Magnussen, B. F.; Hjertager, B. H. Proceedings of the 16th International Symposium on Combustion; The Combustion Institute: Pittsburgh, PA, 1976; pp 719-729. (31) Tillman, D. A. The Combustion of Solid Fuels and Wastes; Academic Press: New York, 1991. (32) Duong, T. H. NERDDP Project 931, End of Grant Report ND/87/ 040; State Electricity Commission of Victoria: Victoria, Australia, 1987. (33) Wall, T. F.; Phelan, W. J.; Bartz, S. Doc. F388/a/3; International Flame Research Foundation: Livorno, Italy, 1976.

The gas phase flow in the furnace is taken as a gas mixture consisting of the key gaseous components, which are O2, H2O, CO2, CO, N2, NO, and volatiles. These components are assumed 4974

Energy Fuels 2010, 24, 4971–4979

: DOI:10.1021/ef100514v

Tian et al.

Figure 5. Mesh independence test based on (a) gas velocity w and (b) gas temperature along line 1.

Figure 6. Comparison of calculated and measured wall incident heat flux profiles: (a) case 3 and (b) case 6 (measurements from Barlow34).

and Figure 5b gives the comparison of temperature profiles for the four mesh densities. The fine mesh (1 130 000 nodes) and medium-density mesh (950 000 nodes) yield similar results. Therefore, the mesh density of 950 000 nodes was applied for further work reported in this study. A comparison of predicted incident heat flux profiles on furnace walls for cases 3 and 6 with measurements34 is shown in Figure 6. At the time of measurement,35 the operating conditions of the unit were the same as those of the CFD simulation; the unit was operating at full load and the same firing groups were out of service. Both measurement and prediction of wall heat fluxes in the figure were obtained using the same method where heat flux was measured through ports in the furnace walls. In case 3, incident heat flux at each boiler level was determined from averaging the incident heat fluxes on all ports along the four walls at the same level. Similarly, the heat flux at each level in case 6 was based on values at the west, south, and north walls, because the heat flux ports were not available on the east wall at the time of measurement. Locations of the ports for the CFD calculation are displayed in Figure 3. The CFD model performs well; the trend of the heat flux on the walls is successfully captured, and good agreement between the measurement and simulation is obtained for these two cases. In both measurements and predictions, high wall incident heat fluxes are found at levels 5 and 6, which correspond to the location of

Results and Discussion Grid Independence Test and Validation. Combustion of a pulverized coal particle in an industrial furnace is a complex phenomenon and is determined by the furnace type, coal properties, operating conditions, etc. Previously, the CFD modeling approach has been applied to a non-swirling coal flame in a pilot-scale furnace.29 The CFD approach provided predictions that were in good agreement with detailed measurements available in the literature. Nevertheless, because of complexities in both the physical process and combustion model, a three-step validation procedure is implemented to ensure the reliability of predictions of this CFD approach. This procedure includes (1) a mesh independence test, (2) comparison of predicted incident heat flux profiles on furnace walls to power plant measurements, and (3) comparison of predicted FGET, flue gas temperature before air heaters, gas component concentrations in flue gas, and total boiler heat supply against measurements taken in the boiler. A mesh independence test is conducted for a case with firing groups 2 and 6 out of service and combustion air distribution 1. The wall emissivity used in the grid independent test cases was assumed to be 0.6. An initial mesh with about 200 000 nodes was first created in the computational domain. The mesh was then refined progressively, resulting in finer meshes with 600 000, 950 000, and 1 130 000 nodes. Mesh independence was checked by comparing the gasphase horizontal velocity component w along the z axis and the gas temperature along line 1 (shown in Figure 3) in the furnace. Figure 5a shows the comparison of gas velocity w,

(34) Barlow, M. HRL Report HLC/2005/051; HRL Limited: Mulgrave, Victoria, Australia, 2005. (35) Murtagh, P.; Marshall, L.; Salter, S. HRL Report HLC/2004/ 026; HRL Limited: Mulgrave, Victoria, Australia, 2004.

4975

Energy Fuels 2010, 24, 4971–4979

: DOI:10.1021/ef100514v

Tian et al.

case 1. This large votex is an inherent feature of a tangentially fired furnace designed to enhance mixing in the furnace and ensure longer particle residence time. The high-temperature zone and the center votex of case 1 are symmetric. At inservice burners, the pulverized coal particles are carried by inert fuel gas from the mill going through the primary burners, while combustion air is separately supplied through secondary air nozzles. The low-temperature inert fuel gas (170 °C) from the mill and the separation of air from fuel delay the devolatilization and ignition of the coal particles. As shown in Figure 7a, the ignition starts downstream of the burner jets, where fuel from the primary nozzle mixes with air from the secondary nozzles. The high-temperature zone skews toward the out-ofservice burners in all other cases, as shown in panels b-f of Figure 7 and is especially apparent in cases 3-6, where burners 4 and 6, 5 and 6, 6 and 7, and 6 and 8 are out of service, respectively. It is shown in panels d and e of Figure 7 that the high-temperature zone is attached to the south wall of the furnace for cases 4 and 5. Figure 8 compares contour plots of the incident heat flux on furnace walls for cases 1-6. In Figure 8a, a symmetric distribution of incident heat flux on walls is evident mainly due to the symmetry of the high-temperature zone shown in Figure 7a. Most radiative heat transfer occurs in the furnace chamber below the superheaters. Low incident intensity is found on the ash hopper wall because of the poor view factors shown in Figure 7. A higher wall incident heat flux is found on the east wall than that on other walls for case 3 (Figure 8c), where burners 4 and 6 are out-of-service. When burners 5 and 6 and 6 and 7 are out-of-service, as seen in panels d and e of Figure 8, high incident radiation is found on the south wall, on which firing groups 6 and 7 are located. This is due to the distortion of the high-temperature zone, as discussed previously. Operators of the TRUenergy furnaces report that, when operating in conditions with two firing groups next to each other, they observe significantly higher temperatures in the area above the vapor burners, as predicted here by the CFD model. The locally high heat fluxes can result in severe local slagging problems if the boiler was operating in this configuration for an extended length of time. This scenario could happen in plant operation, because selection of the two out-of-service firing groups is normally determined by maintenance requirements. One possible cause of the locally high-temperature and high-incident heat flux close to the out-of-service firing groups is the relatively high oxygen content in the out-ofservice burners exit. This is due to the low cooling air inlet velocity or momentum at the current combustion air distribution (20 kg/s for each out-of-service firing group). This will be further discussed later. Another possible cause is that the cooling effect is much weaker in the out-of-service burners than the in-service burners. As expected, there is a strong similarity between the distribution patterns of wall incident heat flux of case 3 (firing groups 4 and 6 out of service) and case 6 (firing groups 6 and 8 out of service). Effects of Combustion Air Distribution. As mentioned previously, the low inlet velocity of cooling air through the out-of-service mills, in distribution 1, results in a relatively high oxygen concentration in the out-of-service burner exits. This leads to locally higher temperatures and incident heat fluxes close to the out-of-service firing groups. Panels a and d of Figure 9 show the streamlines of the cooling air from firing groups 6 for case 1 (firing groups 2 and 6 out of service) and

Table 4. Measured and Calculated FGET, Flue Gas Temperature before Air Heaters, Flue Gas Components, and Total Boiler Heat Supply for Case 2

FGET (°C) flue gas temperature before air heaters (°C) flue gas O2 (wt %) flue gas CO2 (wt %) flue gas H2O (wt %) total heat supply (MW)

measurement

prediction

1083 392

1074 380

3.7 18 20 899

3.93 19.5 18.8 929

Figure 7. Iso-surfaces at 1327 °C: (a) case 1, (b) case 2, (c) case 3, (d) case 4, (e) case 5, and (f) case 6.

the upper main and lower vapor burners. This indicates that most of the combustion occurs at the burner level and is consistent with the design concept. Predicted FGET, flue gas temperature before air heaters, gas component concentrations in flue gas, and total boiler heat supply have been compared against the boiler measurements for case 2, where firing groups 3 and 6 are out of service. Validation of the FGET and total boiler heat supply are carried out using power plant instrument measurements gathered at the TRUenergy Yallourn power plant during November 2006. Measurements of the flue gas components (O2, CO2, and H2O concentrations) and flue gas temperature before air heaters were obtained from Murtagh et al.35 As shown in Table 4, CFD predictions are in good agreement with the measured data. On the basis of the above mesh independence test and validation, a level of confidence in the current CFD model can be established. Effects of Different Out-of-Service Firing Groups. The effects of having two out-of-service firing groups operating at full load on the raw brown coal flame are investigated using the validated CFD model. The 1327 °C iso-surfaces, as shown in Figure 7, summarize the performance of different cases. These iso-surfaces indicate the location of the hightemperature zone in the coal flame. It is clearly evident that the high-temperature zone is at the center of the furnace for the case 1, with firing groups 2 and 6 out of service (Figure 7a). As shown in Figure 4, the injected gas and coal particles from the burners form a large swirl or votex at the furnace center in 4976

Energy Fuels 2010, 24, 4971–4979

: DOI:10.1021/ef100514v

Tian et al.

Figure 8. Predicted wall incident heat flux: (a) case 1, (b) case 2, (c) case 3, (d) case 4, (e) case 5, and (f) case 6.

Figure 9. Streamlines of the cooling air from firing group 6 for (a) case 1, (b) case 7, (c) case 9, (d) case 4, (e) case 8, and (f) case 10.

case 4 (firing groups 5 and 6 out of service), respectively. For these two cases, there is 20 kg/s of cooling air and no fuel flowing through the out-of-service burners. The cooling air velocity through the out-of-service burner ducts is about 37% of the combustion air velocity in the in-service burners. As shown by streamlines in panels a and d of Figure 9, the cooling air spills out of the burners and flows upward immediately, creating a relatively oxygen-rich zone. The large votex in the furnace transports the unburnt volatiles and coal particles into these oxygen-rich zones, where they combust. Two other combustion air distributions that produce higher cooling air inlet velocities are tested. In the case of distribution

2, combustion air flow is 46.25 kg/s for all eight firing groups. This case has a total combustion air flow of 370 kg/s, which is the same as that of distribution 1, the current combustion arrangement. However, the cooling air velocity through the out-of-service burners is 2.31 times that of distribution 1. In the third distribution of combustion air, 55 kg/s of air enters through all eight firing groups, making a total of 440 kg/s of combustion air. This makes the air/fuel ratio about 19% higher than distribution 1. The cooling air velocity of distribution 3 at out-of-service burners is 2.75 times that of distribution 1. Streamlines of cooling air entering from firing group 6 with combustion air distributions 2 and 3 for cases with firing 4977

Energy Fuels 2010, 24, 4971–4979

: DOI:10.1021/ef100514v

Tian et al.

Figure 10. Predicted gas temperature profiles (°C) of plane 1: (a) case 4, (b) case 8, and (c) case 10.

Figure 11. Predicted wall incident heat flux: (a) case 1, (b) case 7, (c) case 9, (d) case 4, (e) case 8, and (f) case 10.

groups 2 and 6 and 5 and 6 out of service are illustrated in panels b, d, e, and f of Figure 9, respectively. Three cases with firing groups 5 and 6 out of service are shown in panels d, e, and f of Figure 9, respectively, corresponding to cases 4, 8, and 10 with the difference between them the distribution of combustion air. These three plots show that, for distributions 2 and 3, where the cooling air enters with a higher inlet velocity, the air penetrates further in the furnace than that of combustion air distribution 1. The effect of greater combustion air penetration is to move the high-temperature zone slightly toward the furnace center. The relocation of the high-temperature zone is shown in Figure 10, which compares the gas temperature profiles on plane 1 for cases 4, 8, and 10. As shown in Figure 11, movement of the high-

temperature zone away from the furnace walls leads to a reduction in the peak heat flux on the south wall for cases with firing groups 5 and 6 out of service (cases 4, 8, and 10) and on the south and north walls for cases with firing groups 2 and 6 out of service (cases 1, 7, and 9). A reduction in peak heat flux is likely to lead to a reduction in furnace wall slagging. Conclusion and Future Work A CFD model of a 375 MW tangentially fired furnace at the TRUenergy Yallourn power plant has been developed. A level of confidence in the current CFD models has been established by a mesh independence test and validation against power plant data. 4978

Energy Fuels 2010, 24, 4971–4979

: DOI:10.1021/ef100514v

Tian et al.

The validated CFD model was then applied to predict the combustion behavior of raw Victorian brown coal combustion in the furnace while operating at full load with different out-of-service firing groups. Model results show that, for the TRUenergy Yallourn power plant operating with the current combustion air distribution, there is a considerable difference in the combustion behavior within the furnace depending upon which two firing groups are out of service (cases 1-6). The CFD model successfully predicted the attachment of a high-temperature zone to the furnace walls for cases 4 and 5. The attachment of flame on the furnace wall leads to locally high heat fluxes and is supported by power plant observations. The CFD model was further applied to investigate possible remedies by changing the combustion air distribution. The comparison of different combustion air distribution results clearly shows that different combustion behaviors in terms of high-temperature zone shape and location and incident heat flux on furnace walls can be achieved by changing

combustion air velocity, particularly the cooling air velocity at the out-of-service burners. Increasing the cooling air velocity (combustion air distributions 2 and 3) can help move the flame away from the out-of-service burners by reducing the peak incident heat flux on furnace walls. However, distribution 3 could slightly reduce the total boiler efficiency because it has more excess air used than the other cases. Therefore, combustion air distribution 2 is recommended for power plant operations, especially for the cases where two neighboring firing groups are out of service. In future work, the CFD model will be used to investigate the combustion behavior of dried brown coal in the furnace. Acknowledgment. The financial support provided by the Victorian Government Department of Primary Industries under the ETIS Program is gratefully acknowledged. The authors also thank Steve Pascoe and Yorrick Nicolson of the TRUenergy Yallourn power plant for providing plant data for the CFD simulation and discussion about the predicted results.

4979