Energy Fuels 2010, 24, 4510–4517 Published on Web 07/13/2010
: DOI:10.1021/ef1005379
Process Evaluation of Biomass Cofiring and Reburning in Utility Boilers Wei Zhou,* Larry Swanson, David Moyeda, and Guang Xu General Electric Energy, 1831 E. Carnegie Avenue, Santa Ana, California 92705 Received April 28, 2010. Revised Manuscript Received June 23, 2010
Biomass has been considered as an alternative fuel to firing coal in utility boilers because of its vast availability and renewable nature. However, the use of biomass as a full or partial replacement for coal needs a careful evaluation of its impact on the boiler performance and the best approach for implementation. In the past, biomass has been implemented in a cofiring mode and is injected into the coal pipe providing a portion of the heat input. Another approach of utilizing biomass is through reburning. In this application, biomass can be directly injected above the burner zone as a reburn fuel, which utilizes the renewable energy and can lead to reduced NOX emissions. In addition, this approach reduces the requirements for mill and/or burner modifications. This paper reviews (1) the process conditions and burner flame structures for biomass cofiring as a function of the heat input and (2) the process requirements and impacts of biomass reburning on the boiler combustion performance. The study indicates that a successful implementation of biomass as an alternative fuel requires a case-by-case examination of the biomass properties such as its fuel factor, F, defined as the ratio of the air-to-fuel demand to the heating value, and its combustion moisture factor, MC, defined as the ratio of the fuel hydrogen content to the fuel carbon content.
various forms.8-10 However, compared to bituminous and sub-bituminous coals, which are widely used for power generation, biomass typically has a lower heating value, lower carbon content, and higher oxygen content. Hence, applications of biomass as an alternative fuel in utility boilers need careful evaluation of its feasibility and process impacts. Maciejewska et al.11 provided a comprehensive review on the biomass/coal-cofiring process and the biomass pretreatment. The study summarized three cofiring configurations and listed a few technical challenges of biomass cofiring, which included (1) the impact on the boiler capacity and performance, (2) slagging and fouling increased due to the alkali contents of some biomass fuels, (3) agglomeration, (4) potential increases of erosion and corrosion, and (5) ash utilization. Their study also indicated that some pretreatment of the biomass can help to reduce these side impacts. Dayton12 briefly summarized some of the biomass/coalcofiring demonstrations conducted in the United States in the late 1990s to early 2000s. The benefits of cofiring biomass were found to be the reduction of CO2, NOX and SO2 emissions. The issues for biomass cofiring were also acknowledged including the potential impact on the boiler efficiency, fuel handling, ash salability, increased slagging and fouling, etc. Xu et al.13 discussed the application of using low-calorific fuel as a reburning fuel for a coal-fired boiler. The work studied
1.0. Introduction Fossil fuels are the main energy resource used in utility and industrial boilers worldwide. Petroleum, coal, and natural gas accounted for about 86% of energy resources in 2007.1,2 However, fossil fuel combustion and utilization contribute significantly to the increased greenhouse gas [carbon dioxide (CO2) gas] emissions, which was over 7000 million metric tons in the United States alone in 2007,3,4 and only half of that amount can be absorbed by natural processes. In addition, fossil fuels are nonrenewable resources and take millions of years to form. The above concerns have forced people to look for alternative and renewable energy resources.5,6 Biomass has been considered as an alternative fuel because of its vast availability7 and renewable nature. Biomass has *To whom correspondence should be addressed. E-mail: wei.zhou@ ge.com. (1) http://www.eia.doe.gov/. (2) http://en.wikipedia.org/wiki/Fossil_fuel. (3) National Oceanic and Atmospheric Adminstration (Apr 24, 2008). Greenhouse Gases, Carbon Dioxide and Methane, Rise Sharply in 2007. ScienceDaily. Retrieved May 12, 2009, http://www.sciencedaily. com-/releases/2008/04/080423181652.htm. (4) U.S. Department of Energy (Dec 5, 2008). U.S. Greenhouse Gas Emissions Still Increasing. ScienceDaily. Retrieved May 12, 2009, from http://www.sciencedaily.com-/releases/2008/12/081204093041.htm. (5) Kumar, A.; Ergas, S.; Yuan, X.; Sahu, A.; Zhang, Q.; Dewulf, J.; Malcata, F. X.; van Langenhove, H. Enhanced CO2 Fixation and Biofuel Production Via Microalage: Recent Developments and Future Directions. Trends Biotechnol., 2010, in press. (6) Xu, X.; Wang, D. Use of Renewable Energy Presents Great Potential for Mitigating CO2 Emissions in East China. Energy Sources, Part A: Recov., Utiliz., Environ. Effects 2001, 23 (1), 19–26. (7) Milbrandt, A. A Geographic Perspective on the Current Biomass Resource Availability in the United States. Technical Report NREL/ TP-560-39181, Dec 2005, http://www.nrel.gov/docs/fy06osti/39181.pdf. (8) Steam, Its Generation and Use, 41st, ed.; Kitto, J. B., Stultz, S. C., Eds.; The Babcock & Wilcox Company: Lynchburg, VA, 2005. (9) Pooly, C. Analysis of the Effect of Co-firing Biomass with Fossil Fuels on the Renewables Obligation. A report prepared for British Wind Energy Association and Friends of the Earth, Nov 2003. r 2010 American Chemical Society
(10) Woodgas Energy Website, http://www.woodgas.com/proximat. htm. (11) Maciejewska, J.; Veringa, H.; Sanders, S.; Peteves, S. D. Cofiring of Biomass with Coal Constraints and Role of Biomass Pretreatment. http://ie.jrc.ec.europa.eu/publications/scientific_publications/ 2006/EUR22461EN.pdf. (12) Dayton, D. A Summary of NOx Emissions Reduction from Biomass Co-firing, NREL/TP-510-32260, May 2002, http://www.nrel. gov/docs/fy02osti/32260.pdf\. (13) Xu, G.; Zhou, W.; Swanson, L.; Moyeda, D. K.; Nguyen, Q. Evaluation of Applying Low Calorific Fuel as Reburn Fuel in an Opposed Wall Fired Boiler. J. Therm. Sci. Eng. Appl. 2010, 1 (3), 031007.
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: DOI:10.1021/ef1005379
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the feasibility of utilizing alternative low-calorific fuels, such as biomass, municipal wastes, and underground coal gasification gas, as the reburn fuel. The evaluation indicated that through an upgrade of the auxiliary systems, a low-calorific fuel can be used to provide heat input while reducing NOX emissions. This paper provides an evaluation of the impact of biomass firing on the process conditions in a coal-fired boiler. The work presents both a study and a review of the application of biomass as a cofiring fuel as well as a reburn fuel. The focus of the biomass-cofiring analysis is on burner flame structures at different biomass heat inputs. The focus of the biomass reburning analysis is on its application and impacts on the boiler thermal performance.
Table 1. Typical Fuel Analysis subbituminous bituminous lignite biomass
units HHV oxygen volatile carbon hydrogen
MJ/kg wt% as received wt% as received wt% as received wt% as received
25 7 35 75 5
20 15 40 70 5
15 15 45 60 5
15 35 70 50 5
Table 2. Air-to-Fuel Demand subbituminous bituminous lignite biomass
unit oxygen carbon hydrogen Φ
2.0. Biomass Fuel
wt% as received wt% as received wt% as received kg/kg
7 75 5 10
15 70 5 9
15 60 5 8
35 50 5 6
Fuel Properties. A vast amount of information8-10 can be found on the fuel analysis for various coals and biomass sources. Understanding the differences in the heating value and compositions between coal and its potential replacement, biomass, is a key to the implementation of biomass as an alternative fuel. Even though for each type of fuel, the higher heating value, fuel oxygen content as received, volatile content as received, and total fixed carbon vary in range, the overall observations are that (1) biomass has substantially higher oxygen and volatile contents than coals, (2) its heating value is significantly lower than those of bituminous and subbituminous coals and is close to that of lignite coals, and (3) the total fixed carbon in biomass is significantly less than that found in coals. These property differences need to be evaluated for specific process applications and are discussed in the following sections. For ease of discussions, the typical values of the fuel properties are listed in Table 1 and are used in the analysis. The fuel hydrogen content is typically around 5% on a wet basis for various coals and biomass. In this study, a boiler operating at 100% coal firing, 100% biomass firing, or cofiring conditions is assumed to have the same boiler heat input and boiler excess oxygen level. Under these two assumptions, the fuel, air, and flue gas flow rates and the furnace heat absorption distributions can be evaluated. Air-to-Fuel Demand. The air-to-fuel theoretical demand can be calculated based on the fuel analysis. For example, when the fuel ultimate analysis includes XC, % of total carbon (C), XH, % of hydrogen, and XO, % of oxygen (O) on a mass basis, the air-to-fuel theoretical demand, Φ, can be calculated approximately by XC XH XO MWair ð1Þ þ Φ ¼ MWC 4MWH 2MWO 0:21
ments, as shown in Table 3. It is found that the fuel carbon content contributes more than 98% of the total fuel heating value for both coals and biomass considered here. If the majority of the heating value is contributed by carbon, the CO2 emissions per unit of heat input would remain relatively constant during fuel switching. Flue Gas Flow Rate. In order to maintain the same boiler total heat input, the fuel flow rate for biomass firing should be increased to compensate for the reduction of the fuel heating value. The following equation exists and can be used to derive the biomass flow rate for a 100% biomass-firing case:
where MW represents the molecular weight. Using eq 1, the air-to-fuel demand for the fuels listed in Table 1 can be calculated and are shown in Table 2. It can be seen that the air-to-fuel demand of biomass is typically much lower than that of coal. Fuel Heating Value. The Dulong formula can be used to estimate the fuel heating value. The Dulong formula is written as
the flue gas flow rate can remain relatively unchanged when switching coal to biomass while maintaining the boiler O2. In this study, Φ/HHV is defined as the fuel factor, F. The fuel factor can be easily used according to the following equation to evaluate the flue gas flow rate change and auxiliary system upgrade needs during fuel switching,
HHV ¼ 338000XC % þ 144000ðXH % - XO %=8Þ
mFG, bio Fbio mFG, coal Fcoal
þ 2778XS % J=kg
mcoal HHVcoal ¼ mbio HHVbio
ð3Þ
According to Zhou et al.,14 the ratio of the flue gas flow rates between the two firing conditions can be expressed as mFG, bio HHVcoal 1 - ash%bio þ Φbio mFG, coal HHVbio 1 - ash%coal þ Φcoal
HHVcoal Φbio HHVbio Φcoal
ð4Þ
assuming that the flue gas molecular weights are similar for both firing conditions and the fuel composition is negligible in the calculations. HHV denotes the fuel higher heating value. Equation 3 is plotted in Figure 1. The plots indicate that when the biomass heating value is less than half of that of coal, its flue gas flow rate will likely be greater than the flue gas flow rate at a coal-firing condition. The increase of the flue gas flow rate will require a closer examination of the auxiliary system capacity, such as the induced-fan capacity, and impacts on the ESP, air preheater, and boiler heat-transfer performance. When Φbio Φcoal HHVbio HHVcoal
ð2Þ
ð5Þ
ð6Þ
(14) Zhou, W.; Moyeda, D. K. Process Evaluation of Oxy-fuel Combustion with Flue Gas Recycle in a Conventional Utility Boiler. Energy Fuels 2010, 24, 2162–2169.
When using the fuel analysis shown in Table 1, the formula estimates the heating value contributions from the main ele4511
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Table 3. Heating Value Contributions
HHV contribution from C HHV contribution from H HHV contribution from O % carbon contribution to HHV
unit
bituminous
sub-bituminous
lignite
biomass
J/kg J/kg J/kg %
253 500 7200 -1260 98
236 600 7200 -2700 98
202 800 7200 -2700 98
169 000 7200 -6300 99
Table 4. Fuel Analysis in the Burner Study U.S. bituminous proximate analysis, wt % moisture ash volatiles fixed C total ultimate analysis, wt % H2O C H N S ash O total heating value, HHV, kJ/kg air-to-fuel demand, Φ, kg/kg F, Φ/HHV, kg/kJ MC
Figure 1. Flue gas flow rates.
Adiabatic Flame Temperature. To further understand the biomass firing impact on burner flame stability and furnace heat transfer, the adiabatic flame temperature is examined. Because the study assumes that the two firing conditions have the same total heat input, the following equations can be derived roughly from the adiabatic flame calculation:15 P fmFG CP, AF ðTAF - T0 Þ - ½mair, i CP, air, i ðTin, air, i - T0 Þgcoal X
fmFG CP, AF ðTAF - T0 Þ ½mair, i CP, air, i ðTin, air, i - T0 Þgbiomass
ð7Þ
i
where
P ½mair, i CP, air, i ðTin, air, i - T0 Þ i
¼ CP, air
X
P mair, i
i
i
3.50 8.20 30.94 57.36 100.00
8.19 3.39 71.27 17.15 100.00
3.50 75.18 4.63 1.05 1.54 8.20 5.90 100.00 29 263 10 3.4 10-4 0.37
8.19 44.11 5.40 3.37 0 3.39 35.55 100.00 15 230 5.36 3.52 10-4 0.73
Because the hydrogen to carbon content ratio of biomass is usually much higher than that of coal, the combustion moisture concentration in the flue gas from biomass firing is higher than that in the coal firing. As a result, the specific heat of the biomass-firing flue gas will be higher even when the fuel moisture contents are similar for coal and biomass. The increased flue gas moisture usually results in a reduced flame temperature.14 In this study, we define a combustion moisture factor, MC, as
i
-
U.K. wood dust
XH YH MWH2 MC ¼ ¼ XC YC MWC
½mair, i ðTin, air, i - T0 Þ P mair, i
ð11Þ
i
¼ CP, air mair ðTin, air - T0 Þ
where Y is the mole fraction of hydrogen or carbon in the fuel. The larger the combustion moisture factor of a fuel, the higher the combustion moisture concentration found in its flue gas. Equation 10 can be rewritten as
ð8Þ
in which Tin,air is the mixing cup temperature of the inlet air streams and CP,in,air is the average specific heat of the inlet air streams. If T0 is allowed to be Tin,air and assuming that the mixing cup temperatures of the air inlet streams are the same for the coal- and biomass-firing conditions, eq 6 becomes mFG, coal CP, coal, AF ðTAF, coal - Tin, air Þ mFG, bio CP, bio, AF ðTAF, bio - Tin, air Þ
TAF, bio - Tin, air Fcoal f ðMC, coal , Mf , coal Þ Fbio f ðMC, bio , Mf , bio Þ TAF, coal - Tin, air
where Mf denotes the fuel moisture content. Equation 12 indicates that, even when the fuel moisture content of biomass is similar to that of coal, the increased combustion moisture due to firing biomass will still lower the flame temperature. When the flame temperature is reduced, the boiler heat absorption will shift to upper elevations and may result in reduced steam flow rates and increased steam flow temperature when the attemperation rate remains relatively unchanged.13
ð9Þ
i.e., TAF, bio - Tin, air mFG, coal CP, coal, AF mFG, bio CP, bio, AF TAF, coal - Tin, air
Fcoal CP, coal, AF Fbio CP, bio, AF
ð12Þ
ð10Þ
3.0. Biomass Cofiring
Therefore, the biomass adiabatic flame temperature is determined by its fuel factors and the flue gas specific heat.
Several approaches can be applied for biomass/coal cofiring. One approach is the direct injection of biomass into the primary coal and air streams at the upstream of the burner coal nozzle exit or the coprocessing of biomass and coal
(15) Glassman, I. Combustion, 2nd ed.; Academic Press, Inc.: New York, ISBN 0-12-285851-1, 1987.
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Table 5. Burner Model Flow Inputs case no.
load (MW)
coal type
1 2 3
27.9 27.9 27.9
U.S. bituminous biomass U.S. bituminous/biomass, 50/50 heat input
a
fuel flow (kg/s)
primary air flow (kg/s)
secondary air flow (kg/s)
tertiary air flow (kg/s)
total air flow (kg/s)a
total flue gasb (kg/s)
0.98 1.88 0.49 coal/0.94 bio
2.27 2.27 2.27
1.40 1.47 1.43
7.94 8.31 8.13
11.61 12.05 11.83
12.59 13.93 13.26
Exit 3.4% O2. b Sum of the coal and air flows.
Figure 2. Burner temperature distributions predicted by CFD.
Figure 4. Burner volatile distributions predicted by CFD.
design principles: 1 The primary air velocity for flame stabilization consideration is maintained. 2 The same burner stoichiometric ratio is maintained. 3 The same flow split between the secondary air and tertiary air flow rates is maintained. 4 The biomass particle size distribution is similar to that of coal. In another words, the biomass has been milled. The computational fluid dynamics (CFD) simulationpredicted temperature, moisture, and volatile distributions for 100% coal, 50% coal and 50% biomass, and 100% biomass firing configurations are shown in Figures 2-4, respectively. The simulation was conducted using FLUENT 6.17 The predicted flame temperature is the highest for the 100% coal-firing condition. The flame temperature drops when the biomass heat input is increased. The reduction of the flame temperature is primarily due to the higher combustion moisture factor of the biomass and therefore the combustion moisture concentration in the flue gas, as shown in Figure 3. The burner combustion intensity and performance can be quite different from coal- to biomass-firing conditions and are complicated by the fuel property differences including the heating value, air-to-fuel demand, and fuel hydrogen to carbon content ratio. Hence, when biomass is implemented as a cofiring fuel, case-by-case evaluations are warranted and different fuel process requirements may be needed to meet the required boiler combustion performance. Figure 4 illustrates the volatile distributions. As expected, more volatiles are released in the biomass-firing case. A summary of the model outputs for CO2, H2O, and CO concentrations at the modeling domain exit is shown in Table 6. The results indicate that the total CO2 emissions remain the same while flue gas water concentration doubles from 100% coal firing to 100% biomass firing. When biomass particle size
Figure 3. Burner water concentration distributions predicted by CFD.
through the same mill. In this approach, the primary fuel stream is a mixture of coal, biomass, and primary air. Another approach is to dedicate one or two mills for biomass and, therefore, some burners would solely fire biomass. Immediate questions are, how stable would the flame be when a burner designed for coal fires biomass and what are the operational constraints for fuel switching? To address the question, the low NOX burner model developed by Zhou et al.16 is used here to study the biomass-firing and cofiring flames. Table 4 lists the fuel analysis for a sample of U.S. bituminous coal and a sample of wood dust, both of which are used in this simulation. The fuel factors, F, of the two fuels are close to each other and differ by less than 4%. The combustion moisture factor, MC, of the biomass, on the other hand, is as twice high as that of the coal. The flow inputs for the modeling study are shown in Table 5. The flow distributions are derived based on the following (16) Zhou, W.; Moyeda, D. K.; Payne, R.; Berg, M. Application of Numerical Simulation and Full Scale Testing for Understanding Low NOX Burner Emissions. Combust. Theory Modell. 2009, 13 (6), 1053– 1070.
(17) FLUENT 6 User’s Guide; Ansys Inc.: Canonsburg, PA, 2003. (www.ansys.com).
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Table 6. Summary of CFD Predictions at the Model Outlet
parameter
unit
100% coal
50% biomass/ 50% coal
CO2 H2O CO
% vol % vol ppm
14.5 5.8 15
14.6 9.4 24
100% biomass
100% biomass w/double particle size
14.6 12.5 9.6
14.6 12.5 180
increases, the unburned combustibles will need more residence time to complete combustion. 4.0. Biomass Reburning A schematic of the reburn process is shown in Figure 5. In the reburn zone, NOX generated in the combustion zone reacts with fuel fragments injected into the reburn zone, reducing it to the molecular nitrogen,18 i.e., reburn fuel f CH
ðIÞ
CH þ NO f HCN
ðIIÞ
HCN þ OH f NH2
ðIIIÞ
NH2 þ NO f N2
ðIVÞ
Figure 5. Schematic of reburn technology.
In a reburn retrofit, both fuel and air staging are applied to achieve the maximum NOX reduction in a combustion modification while maintaining the boiler thermal performance.18 Biomass reburn is a technology that uses biomass as the reburn fuel. Its application utilizes clean and renewable energy and also leads to a significant NOX reduction. Biomass Reburning Performance. Studies were conducted recently to evaluate the potential for applying biomass as a reburn fuel.19-21 Applying biomass as a reburn fuel has the potential of using up to 30% biomass as the heat input in a pulverized fuel boiler. In addition to the heat content of biomass, reburn makes effective use of its chemical properties. Because of its high volatile content, biomass can be a very effective reburn fuel. Several series of pilot-scale tests performed by GE demonstrated that the NOX reduction efficiency of woody biomasses could be as high as that of natural gas.22,23 The key process design parameters of reburning are the stoichiometric ratio (SR) and residence time (τ). The stoichiometric ratio is defined as the actual air provided divided
Figure 6. NOX emissions vs reburn zone SR in pilot-scale tests.
by the theoretical air demand. In a reburn application, the combustion region can be divided into multiple zones, i.e., (1) burner zone (SRB), (2) reburn zone (SR1), and (3) burnout zone (SR2). Figure 6 shows the exhaust NOX emission as a function of the reburn zone SR1 derived from a pilot-scale test facility.18 For various coals and propane as a reburn fuel, the best deNOX performance was found to be at around SR1 of 0.9 for a SRB of 1.1. Higher SR1, i.e., less reburn heat input, reduces the reburning performance. On the other hand, further reduction of SR1 results in no significant improvement of the reburn performance. Recent studies24,25 show that the optimal reburn zone SR1 in biomass reburn applications is also close to 0.9. In a reburn design, the burnout zone SR2 typically remains unchanged from the baseline level to control the unburned combustible emission within the existing boiler auxiliary system capacity. The zonal residence time is defined as the flue gas residence time in different combustion zones in the furnace, i.e., Qi ð13Þ τi ¼ Ai vflue, avg
(18) Moyeda, D. K. Reburn Technology Application Guidelines. DOE NETL Conference on Reburning for NOX Control, Morgantown, WV, May 18, 2004, http://www.netl.doe.gov/publications/proceedings/04/ NOx/e10.35moyeda2-presentation.pdf. (19) Harding, N. S.; Adams, B. R. Biomass as a Reburning Fuel, a Specialized Co-firing Application. Biomass Bioenergy 2000, 19 (6), 429– 445. (20) Vilas, E.; Skifter, U.; Jensen, A. D.; L opez, C.; Maier, J.; Glarborg, P. Experimental and Modeling Study of Biomass Reburning. Energy Fuels 2004, 18 (5), 1442–1450. (21) Lissianski, V. V.; Zamansky, V. M. Biomass Reburning;Modeling /Engineering Studies. DOE Contract No. DE-FC26-97FT97270, http://www.osti.gov/bridge/purl.cover.jsp;jsessionid=CB83BEF4B39F60BD2A271ADDF9D0C1A0?purl=/781801-QwvGWs/webviewable/. (22) Xu, G.; Zhou, W.; Swanson, L. W. Fuel Flexible Biomass Reburn Technology. Proceedings of HT2009, 2009 ASME Summer Heat Transfer Conference, San Francisco, CA, July 19-23, 2009; ASME: New York, 2009. (23) Zamansky, V. M.; Maly, P. M.; Ho, L.; Lissianski, V. V.; Rusli, D.; Gardiner, W. C. Promotion of NO Selective Non-Catalytic Reduction by Sodium Carbonate. 27th International Symposium on Combustion; The Combustion Institute: Pittsburgh, PA, 1998.
where Qi is the flow volume of zone i, Ai is the cross-sectional area of zone i, and vflue,avg is the flue gas average velocity in zone i. The desired minimum length of the residence time is determined by how fast a uniform distribution of the desired (24) Luan, J.; Sun, R.; Wu, S.; Lu, J. F.; Yao, N. Experimental Studies on Reburning of Biomasses for Reducing NOx in a Drop Tube Furnace. EnergyFuels 2009, 23 (2), 1412–1421. (25) Sheldon, M.; Marquez, A.; Zamansky, V. Biomass Reburning; Modeling/Engineering Studies. DOE Contract No. DE-FC26-97FT97270, 2000, http://www.osti.gov/bridge/servlets/purl/781804-rfHUHY/webviewable/ 781804.pdf.
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Figure 8. Predicted impact of the OFA velocity on UBC and CO.
discussions indicate that when biomass is applied as a reburn fuel, it may require some fuel processing to result in finer and dryer particles. In the burnout zone, the OFA injection system design is also critical for maintaining the boiler thermal efficiency and slagging and fouling tendency. Because the fuel combustion zone is extended to a higher elevation in a reburn mode, more unburned combustibles may escape from the burnout zone, particularly when the burnout zone residence time is short. To reduce the unburned combustibles and maintain the boiler efficiency, a boosted OFA (BOFA) technology can be used in biomass reburning application. BOFA technology26 has been applied in the past to increase the OFA velocity to higher than 80 m/s. At this velocity, the high-momentum OFA flow increases the turbulence intensity of the bulk flue gas flow and, therefore, enhances unburned combustible combustion. Figure 8 shows the impact of the OFA velocity on unburned carbon (UBC) and CO predicted by a CFD model for an OFA system in an opposed wall-fired unit. The chart indicates that as the OFA velocity is increased, the lower the UBC and CO emissions are decreased. At about 80 m/s, an appropriate OFA system can control the UBC at the baseline level. Further increases in the OFA velocity will continue to reduce UBC at a lesser degree. BOFA technology has been applied commercially27 and is especially of interest in Europe, where power companies often resell the ash. Case Study. A three-dimensional full-scale CFD model developed elsewhere22 was used in this study to illustrate the temperature and species profiles in an opposed wall-fired boiler rated at 250 MWe gross. The modeling approach is similar to the one shown in work by Zhou et al.28 The model inputs and outputs for the baseline coal firing and the 30% biomass reburning cases are summarized in Table 7. As shown in the table, the biomass consists of a higher oxygen content and a lower carbon content compared to the baseline coal. The model predicts a significant increase of CO and UBC emissions because of the large biomass particle size specified in the model and the delayed combustion in the reburn mode. A comparison of the coal and biomass fineness used in the study is shown in Figure 9. The model also
Figure 7. Reburn NOX reduction vs reburn zone residence time.
stoichiometric ratio can be achieved. Figure 7 shows pilotscale test data for the reburn deNOX efficiency as a function of the reburn zone residence time.18 The longer residence time is beneficial to the reburning deNOX performance. Usually, the achievable reburn zone residence time is limited by the boiler geometric design and the residence time required for the burnout zone. A typical residence time can be achieved in a full-scale application from 300 to 600 ms. Therefore, to improve the deNOX efficiency within a limited residence time, a careful design of both the reburn injection and the overfire air (OFA) injection system is required. Reburn and OFA Injection Specifications. As discussed in the previous section, good mixing is required in both the reburn and burnout zones to achieve a high reburn deNOX rate and low unburned combustible emissions. A well-designed injection system should yield both good lateral mixing and deep far-field penetration. The lateral mixing can be achieved by good planning of the number and locations of the injectors. The penetrations, however, are determined by the injection velocity. Assuming that injection is required to reach a penetration distance of D within a residence time of τ, the minimum injection velocity (vinj) can be estimated by vinj
Dmflue Fflue τminj Finj
ð14Þ
where m denotes the flow rate and F is the density. Using eq 14, with D = 10 m, τ = 400 ms, minj/mflue = 0.2, and Finj/ Fflue = 3 (due to the temperature difference), the calculated vinj, min will be about 42 m/s. As the quantity of the injection flow is reduced, a higher injection velocity is required. Usually, the reburn injection flow rate is lower than that of the OFA flow rate; hence, the reburn injection speed should be higher than that of the OFA. Another factor impacting the reburn performance within a limited reburn zone residence time is how fast the reburn fuel can be released and be in contact with the flue gas. From the pilot-scale data, natural gas has a better deNOX efficiency than that of coal because of its readiness to react with flue gas. Therefore, when biomass is applied as a reburn fuel, a higher volatile content and smaller particle size would be beneficial to the reburn performance. In addition, a general trend is that the higher the temperature in the reburn zone, the faster the reburning reactions that occur, which calls for a reduction of the water concentration, XH2O %, and a lower combustion moisture factor, MC, in biomass. The above
(26) Marion, J. L. Advanced overfire air system for NOx control. U.S. Patent 5,343,820, Sept 6, 1994. (27) Storm, S. K.; Storm, D. S.; McClellan, A. C.; Storm, R. F.; Mulligan, J. Apply the fundamentals to improve emissions performance. Power Mag. 2006 (Oct 15), http://www.powermag.com/coal/Apply-thefundamentals-to-improve-emissions-performance_574_p3.html. (28) Zhou, W.; Moyeda, D. K.; Payne, R.; Nguyen, Q. Comprehensive Process Design of Layered-NOX Control in a Tangentially Coal Fired Boiler. AIChE J. 2010, 5 (3), 825–832.
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Table 7. Summary of Furnace CFD Model Inputs and Outputs units
baseline 100% coal
30% biomass reburn
burner coal flow rate reburn biomass flow rate burner zone SR reburn zone SR burnout zone SR
Model Inputs kg/s 29.8 kg/s 0 1.18 1.18 1.18
21.9 11 1.1 0.88 1.18
C H N S O H2O ash HHV φ F MC
Fuel Analysis % wt 64.59 % wt 3.92 % wt 1.25 % wt 4.15 % wt 4.57 % wt 10.63 % wt 10.9 kJ/kg 26 540 kg/kg 7.24 kg/kJ 2.72 10-4 0.36
46.9 5.20 0.10 0.04 37.86 7.30 2.60 19 061 3.76 1.97 10-4 0.67
O2 CO CO2 H2O UBC
Model Outputs % 2.8 ppm 87 % 14.2 % 8.0 % 2.1
Figure 11. Flue gas temperature distribution in the center plane of the furnace.
2.8 242 14.1 13.5 19.5
Figure 9. Coal and biomass fineness used in the model study shown in Table 7.
Figure 12. Oxygen concentration distribution in the center plane of the furnace.
Figure 10. UBC as a function of the mean biomass particle size.
suggests that in this study, by reduction of the biomass particle size, the CO emissions can be controlled and the UBC emission can be reduced (Figure 10). To further reduce the emissions of the combustibles to the baseline level, a BOFA design can be used. Figures 11-14 illustrate the flue gas temperature and oxygen, CO2, and H2O concentrations of the two firing conditions. In general, the overall boiler temperature and
Figure 13. CO2 concentration distribution in the center plane of the furnace.
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Energy Fuels 2010, 24, 4510–4517
: DOI:10.1021/ef1005379
Zhou et al.
Biomass can be applied either as a cofiring fuel or a reburn fuel. In both cases, a review of the need for biomass processing for finer particles to control the emission of combustibles is required. Nomenclature A = cross-sectional area AF = adiabatic flame temperature bio = biomass avg = average CP = specific heat D = penetration distance flue = flue gas F = fuel factor FG = flue gas HHV = high heating value in = inlet inj = injection m = mass flow rate MC = combustion moisture factor Mf = fuel moisture content MW = molecular weight Q = flow volume SR = stoichiometric ratio T = temperature V = velocity XC = carbon mass fraction XH = hydrogen mass fraction XH2O = water mass fraction XO = oxygen mass fraction Xs = sulfur mass fraction φ = air-to-fuel demand F = density τ = residence time
Figure 14. H2O concentration distribution in the center plane of the furnace.
species concentration profiles are typical for the baseline and reburn retrofit conditions, except that the moisture concentration in the flue gas is significantly increased because of reburn fuel switching from coal to biomass. 5.0. Conclusions Process analysis is performed in this paper to evaluate the application of biomass cofiring and reburning in utility boilers. It is found that a successful application of biomass as an alternative fuel in utility boilers needs careful review of its properties including its fuel and combustion moisture factors. If the biomass fuel factor is similar to that of baseline coal, the total flue gas flow rate can remain relatively unchanged. If the biomass moisture factor is similar to that of baseline coal, the flue gas water concentration is relatively unchanged. When both factors are similar between biomass and coal, the flame temperature will remain relatively constant.
Note Added after ASAP Publication. The sixth paragraph of the Biomass Fuel section was modified in the version of this paper published ASAP July 13, 2010. The correct version published on July 15, 2010.
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