sami - co-ﬁring of coal and biomass fuel blends

Co-firing of coal and biomass fuel blends

M. Sami, K. Annamalai* , M. Wooldridge1

Department of Mechanical Engineering, Texas A & M University, College Station, TX 77843-3123, USA

Received 4 August 1999; accepted 6 June 2000

Abstract

This paper reviews literature on co-firing of coal with biomass fuels. Here, the term biomass includes organic matterproduced as a result of photosynthesis as well as municipal, industrial and animal waste material. Brief summaries of thebasic concepts involved in the combustion of coal and biomass fuels are presented. Different classes of co-firing methods areidentified. Experimental results for a large variety of fuel blends and conditions are presented. Numerical studies are alsodiscussed. Biomass and coal blend combustion is a promising combustion technology; however, significant development workis required before large-scale implementation can be realized. Issues related to successful implementation of coal biomass blendcombustion are identified.q 2001 Published by Elsevier Science Ltd.

Keywords: Co-firing; Coal; Biomass; Emissions; Renewable energy

Contents

1. Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1722. Fundamental combustion issues. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 178

2.1. Material and combustion characteristics of coal . . .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1782.2. Pyrolysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1792.3. Volatiles oxidation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1792.4. Char reactions. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1792.5. Homogeneous reactions. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1802.6. Ignition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1802.7. Char combustion. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1812.8. Pollutant emissions. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 182

3. Biomass fuel. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1833.1. Pyrolysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1863.2. Ignition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1873.3. Char combustion. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1873.4. Fouling issues in biomass combustion. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1893.5. Summary comparison of coal and biomass combustion. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 191

4. Co-firing of blends . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1914.1. Blend combustion efficiency. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1924.2. Classes of co-firing. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1924.3. Coal and agricultural residues. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1934.4. Coal and RDF. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 195

Progress in Energy and Combustion Science 27 (2001) 171–214PERGAMONwww.elsevier.com/locate/pecs

0360-1285/01/$ - see front matterq 2001 Published by Elsevier Science Ltd.PII: S0360-1285(00)00020-4

* Corresponding author. Tel.:11-979-845-2562; fax:11-979-862-2418.E-mail address:[email protected] (K. Annamalai).

1 Current address: Mechanical Engineering and Applied Mechanics Department, University of Michigan, Ann Arbor, MI 48109-2125, USA.

4.5. Coal and animal waste. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2004.6. Combustion modeling for coal biomass blends. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2034.7. Fouling issues in co-firing. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 208

5. Issues and opportunities. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2096. Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 211Acknowledgements. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 212References. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 212

1. Introduction

The combustion of fossil fuels provides almost 85% ofthe energy requirement in the United States [1]. In 1997,the US electrical power utilities consumed,87% of thenearly 1.1 billion tons of coal produced [1]. Due to thelarge coal reserves, the United States relies heavily oncoal for electricity generation. Coal was used to provide51% of the total power generation in the United States in1995 and is projected to provide 49% in 2020 [1]. Hence,coal will continue to be the dominant fuel for use inelectricity production in the United States for the foresee-able future. As such, the air pollution emissions accom-panying the coal combustion are significant. Among thesepollutants are oxides of sulfur (SOx) and nitrogen (NOx),which lead to acid rain and ozone depletion. In addition,greenhouse gas emissions (CO2, CH4, etc.) have become aglobal concern.

Due to concerns over public health and the environment,federal regulations regarding the emission of air pollutantshave become particularly demanding. The EPA New SourcePerformance Standards (NSPS) passed in 1990 require a50% reduction of emissions that lead to acid rain (i.e. NOx

and SO2). The previous standard was 520 g SO2/GJthermal

(1.2 lb/MBtu), where GJthermal is the thermal energy fromfuel combustion. The current standard is 260 g SO2/GJthermal

(0.6 lb/MBtu). In Sweden and in some portions of theUnited States, the standards are even more severe, limitingemissions to 50 g SO2/GJthermal (0.115 lb/MBtu). As a directresult of these regulations, almost 50% reduction in SO2

from utility boilers has been achieved during the time periodfrom 1980 to 1995 [1]. The current standard for NOx is260 g/GJthermal (0.6 lb/MBtu). However, little progress hasbeen made in reducing NOx or CO2 emissions [1].

A number of techniques and methods have been proposedfor reducing gaseous emissions of NOx, SO2 and CO2 fromfossil fuel combustion and for reducing costs associatedwith these mitigation techniques. Some of the controlmethods are expensive and therefore increase productioncosts. Among the less-expensive alternatives, co-firinghas gained popularity with the electric utilities producers.Co-firing, in this context, is defined as the firing of arenewable fuel (i.e. biomass) along with the primaryfuel (coal, natural gas, furnace oil, etc.). Recent studiesin Europe and the United States [2–5] have establishedthat burning biomass with fossil fuels has a positive

impact both on the environment and the economics ofpower generation. The emissions of SO2 and NOx werereduced in most co-firing tests (depending upon thebiomass fuel used). The CO2 net production was alsoinherently lower, because biomass is considered CO2-neutral. In addition, total fuel costs can be reduced insome cases if the biomass processing costs (transporta-tion, grinding, etc.) are lower, on energy basis, than theprimary fuel processing costs on an energy basis.

In general, any organic fuel can be considered a biomassfuel. For the context of this discussion, biomass is used todescribe waste products and dedicated energy crops. Wasteproducts include wood waste material (e.g. saw dust, woodchips, etc), crop residues (e.g. corn husks, wheat chaff, etc.),and municipal, animal and industrial wastes (e.g. sewagesludge, manure, etc.). Dedicated energy crops, includingshort-rotation woody crops like hard wood trees and her-baceous crops like switchgrass, are agricultural crops thatare solely grown for use as biomass fuels. These crops havevery fast growth rates and can therefore be used as a regularsupply of fuel.

Biomass fuels are considered environmentally friendlyfor several reasons. First, there is no net increase inCO2 as a result of burning a biomass fuel (i.e. fossilgenerated CO2). Biomass consumes the same amount ofCO2 from the atmosphere during growth as is releasedduring combustion. Therefore, blending coal withbiomass fuels can reduce fossil-based CO2 emissions[2,4]. Co-firing of biomass residues, rather than cropsgrown for energy, brings additional greenhouse gasmitigation by avoiding CH4 release from the otherwiselandfilled biomass. It is believed that CH4 is 21 timesmore potent than CO2 in terms of global warmingimpact. Most biomass fuels have very little or no sulfur,and therefore net SO2 emissions can also be reduced byco-firing coal and biomass. This attribute is particularlydesirable when co-firing with high sulfur coals. Thealkaline ash from biomass also captures some of theSO2 produced during combustion [2,6]. Typically,woody biomass contains very little nitrogen on massbasis as compared to coal. In addition, most of thefuel nitrogen in biomass is converted to NH radicals(mainly ammonia, NH3) during combustion [2,6]. Theammonia reduces NO to molecular nitrogen (essentiallyproviding an in situ thermal DeNOx source). Hence,biomass co-firing can also result in lower NOx levels.

M. Sami et al. / Progress in Energy and Combustion Science 27 (2001) 171–214172

Blending can also result in the utilization of less-expensivefuels with a possible reduction in fuel costs (depending uponthe biomass fuel processing costs). Lastly, soil and waterpollution can be mitigated depending upon the type of biomassfuel blended with coal. Stored biomass wastes anaerobically(i.e. in the presence of bacteria and moisture) release CH4,NH3, H2S, amides, volatile organic acids, mercaptans, estersand other chemicals. By combusting the biomass, ambientemissions of these pollutants are reduced. For example, ifcattle manure is used as an inexpensive alternative biomass

fuel then many of the advantages described above arerealized, in addition to avoiding contamination of soil,water and air due to otherwise stockpiled manure.

Some typical biomass fuels found in coal co-firing studiesare: cattle manure [7], sawdust and sewage sludge [8,9],switchgrass [10], wood chips [11,12], straw [9,13–16] andrefuse-derived fuels [8,17]. Table 1 provides a brief over-view of some selected studies on co-firing coal and biomassfuels. The material properties of a number of biomass fuelsused in co-firing are given in Tables 2–6.

M. Sami et al. / Progress in Energy and Combustion Science 27 (2001) 171–214 173

Nomenclature

d particle diameter at timet (m)d0 initial particle diameter (m)dp particle diameter (m)h convective heat transfer coefficient

(W/m2 K)hm mass transfer coefficient (kg/m2 s)hc Heat of combustion (kJ/kg)m mass flow rate (kg/s)_mc char consumption rate (kg/s)_mO2

oxygenconsumption rate (kg/s)

mv volatile matter in biomass (kg)t time (s)tpyr pyrolysis time (s)B transfer numberBO2

pre-exponential factor for oxygenconsumption (m/s)

Bv pre-exponential factor (m/s)Cp specific heat of air (kJ/kg K)D diffusion coefficient (m2/s)DIV,c fourth Damkohler number for carbon

oxidation� (BO2dpYO2;∞Ruhc)/(ShDwyO2

ECp)Dw diffusion coefficient at particle wall (m2/s)E activation energy (kJ/kmol)Ru universal gas constant (8.314 kJ/kmol K)Sh Sherwood number� hmdp/rDTad adiabatic flame temperature (K)Tg gas temperature (K)Tp particle temperature (K)Tp,I particle ignition temperature (K)YO2;w mass fraction of oxygen at particle wallYO2;∞ mass fraction of oxygen in ambient

Greek symbolsa combustion rate constant (m2/s)e emissivityyO2

stoichiometric coefficient for reactions (I) or(II)

h mixture fractionhblend blend combustion efficiencyh coal coal combustion efficiency

h ch,b burn-out fraction of coal or biomass charr mixture density (kg/m3)rch char density (kg/m3)r∞ ambient density (kg/m3)s Stefan–Boltzmann constant (W/K4)u∞,HI dimensionless temperature� Tp,I/(E/Ru)

AbbreviationsAPAS activite de promotion, d’accompagnement et

de SuiviAPF annular primary fuelBtu British thermal unitCFB circulating fluidized bedCFD computational fluid dynamicsCPF central primary fuelDAF dry ash freeEPA environmental protection agencyFBC fluidized bed combustionFC fixed carbonFCM finished composted manureGI gas ignitionHC hydrocarbonsHI heterogeneous ignitionHV heating valueHVc heating value of charHVcoal heating value of coalHVv heating value of volatile matterHHV higher heating valueMCFBC multi-circulating fluidized bed combustionMSW municipal solid wasteNSPS new source performance standardsPCGC2 pulverized coal gasification and combustion

code — two-dimensionalPC pulverized coalPCM partially composted manureRDF refuse-derived fuelSIT spontaneous ignition temperatureTGA thermogravimetric analysisTEM transmission electron microscopeVM volatile matterXN nitrogen containing volatile matter

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Selected coal:biomass co-firing studies

Systemdescription

Fuel type andheating valueHHV (kJ/kg)

Systemcapacity,blend parameters

Results Issues Application Reference Remarks

Grate-firedboiler burner

Coal/wood chipsblends.Coal: 22,605;wood: 17,742

35–41%moisture,10–20% wood

Only 10–20% co-firing feasible,0.04–0.09 grains/SCFopacity

Blend mixingdifficult.Stokercapacityproblems

Electricity orsteamgeneration

Sampsonet al. [11]

Wood: birch,aspen, spruce.Break-evenprice� $26(45% moisture)

Down-firedconcentric swirlburner

Coal/manureblends.Coal: 26,535;manure: 8,650

35.4 kW (fuel)100 g/minblend feed rate; 20%manure (mass basis)

SOx and NOx

decrease with blendcombustion, easyignition with blend

Crushingmanure to samesize as coaldifficult

Powergeneration

Frazzittaet al. [7]

Wall-fired dualfuel burner

Coal/sawdustblends.Coal: 32,260;pine sawdust:18,140

500 kW (fuel);two-fuel injectionmodes,secondary swirlof 1.0

81–90% burnout, NOxreduced, optimum co-firing ratio� 30% formaximum burnoutand minimum NOx

Fuel injectionmode dependson reactivity andN2 in biomass

Powergeneration

Abbaset al. [8]

Coal andsawdust fedseparately. Coal:74%,90mm,sawdust:75%,1.4 mm

Multi-circulatingfluidized bedcombustor(MCFBC)

Coal/straw/woodchips blends.Heating valuesnot available

20 MW18–49% biomass

No steady outputof gaseous alkalimetals

Powergeneration

Hansenet al. [77]

Coal and woodinjected atbottom, strawinjected withsecondary air

15.2 cm (dia)×1.57 m (height)swirl combustor

Coal/manureblends.Coal: 26,535;manure: 8650

90:10 blend,three-mixturefraction approach

Higher burnout withblend,differences in the nearburner region oftemperature andspecies concentration

Powergeneration

Dhanaplanet al. [79]

Comparison oftwo- and three-mixture fractionapproaches

Wall-fired boilerburners

Coal/switch-grass blends.Coal: 25,500;switchgrass:15,997

50 MW (fuel)15% co-firingmass basis,12% moisturein biomass

No slagging,normal unit operation,NOx decreased by20%, lower opacity

Some traces ofpartially burnedswitchgrass inash

Powergeneration

Aerts et al.[10]

Wall-fired boilerburners

Coal/straw/cerealblends.Heating valuesnot available

500 kW0–100%biomass firingheat basis

Fuel with highernitrogen contentshould be injected infuel rich zone toreduce NOx.Optimum co-firingratio� 60%

Powergeneration

Siegelet al. [15]

Three differentburnerconfigurationsstudied

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Table 1 (continued)

Systemdescription

Fuel type andheating valueHHV (kJ/kg)

Systemcapacity,blend parameters

Results Issues Application Reference Remarks

Spreader-stoker Coal/railroadties.Heating valuesnot available

0.5–1 Mbtu/h20% co-firingmass basis

NOx reduced by 25%due to low nitrogencontent of biomass.CO reducedconsiderably at lowexcess air ratios

Powergeneration

Brouweret al. [76]

Down-fired PCfurnace

Coal/hardwood/soft woodblends.Heating valuesnot available

38 kW15% co-firingmass basis,12% moisturein biomass

Co-firing:unstaged combustion,NOx decreased byabout 17% at 50% co-firing.Staged combustion,no reduction untilco-firing ratio.50%,60% NOx reductionachieved in reburn.optimal stoichiometryfor reburn� 0.85

Powergeneration

Brouweret al. [76]

Both co-firingand reburningtests wereconducted

Cyclone-firedcombustor

Coal/b-dRDFblends.Coal: 14,388;RDF: 12,955

440 MW12% co-firingmass basis, 19%moisture inbiomass

NOx reduction 2–3%SO2 reduction 17%,particulateconcentration (heatbasis) increased byabout 50% as theRDF contained moreash than coal

Powergeneration

Ohlsson[17]

Lower sulfurcontent of RDFandheterogeneousreaction of SO2with the binderlowered SO2

significantlyDown-firedcombustor

Coal/straw/sewagesludge blends.Coal: 30,140;straw: 17,090;sewage: 10,510

0.5 MW 20% co-firing of straw (massbasis), 11% moisturein straw

Max. particle size forcomplete burnout:6 mm for straw.Burner configurationimportant in NOx

reduction

Powergeneration

Spliethoffand Hein[6]

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Table 2Chemical analysis and properties of selected biomass fuels

Fuel type Corn stovera Cotton ginb Coconut shellc Rice huskd Olive huske Corn cobsa Mustard stalkf Barley strawf Wheat strawf

Agricultural residue 35 – –Moisture 35 11.5 25 (% wet) 9.96 33 15 3.25 10.3 8.9Ash 3.25 14.5 0.8 (% dry) 20.61 1.6 1.4 54.6 – –Volatiles 54.6 – 79 (% dry) 54.68 – 76.6 7.15 20.9 19.8Fixed carbon 7.15 – 20.2 15.02 – 7 – 39.92 43.2C 42.5 42 – 34.94 47.8 48.4 – 5.27 5.0H 5.04 5.4 – 5.46 5.1 5.6 – 43.81 39.4O 42.6 35 – 38.86 45.4 44.3 – 1.25 0.61N 0.75 1.4 – 0.11 0.1 .3 – – 0.11S 0.18 0.5 – – – – 10,730 17,310 17,510HHV (kJ/kg) 10,730 15,500 20,000 13,524 – 15,549 – 17,288 17,499HHV (kJ/kg)g 10,718 15,459 – 13,515 17,993 15,549 4.48 6.8A:Fh 3.24 4.58 3.7 5.28 4.72 – 2302 1981AFT (K) i 1895 2273 – 2315 2342 2179

a Paul and Buchele [24].b LePori [23].c Mendis [67].d Hartiniati et al. [68].e Maschio et al. [83].f Ebeling and Jenkins [29].g HHV based on Boie equation.h Air to fuel ratio (DAF mass basis).i Adiabatic flame temperature calculated from the ultimate analysis.

The primary objective of this review is to summarizethe state of knowledge on suspension burning of pulver-ized coal and biomass fuel blends. Some relevant materialon fluidized bed combustion is also included. However, anin-depth discussion of fluidized bed combustion offuel blends is beyond the scope of this review. Co-firingwith furnace oil or natural gas and pulverizer per-

formance are not included in this work. Previous workon the use of biomass as an energy source has primarilyaddressed direct combustion, pyrolysis, anaerobic diges-tion or fermentation for synthesis of ethyl alcohol[18–26]. Until recently, there have been few studiesconcerning the co-firing of coal/biomass blends forenergy generation.


Table 3Chemical analysis and properties of selected wood products

Fuel type Peata Fuelwoodb Sawdustc Hardwoodd Softwoodd Switchgrasse Redwoodf Tan oakf Black locustf

Moisture 28 10 7.3 – – 11.99 – – –Ash 2.2 2 2.6 – – 4.61 0.36 1.67 0.8Volatiles – 70 76.2 – – – – – –Fixed carbon – 18 13.9 – – – 19.92 17.4 18.26C 53.3 – 46.9 50.2 52.7 42.02 50.64 47.81 50.73H 5.9 – 5.2 6.2 6.3 4.97 5.98 5.93 5.71O 36.7 – 37.8 43.5 40.8 35.44 42.88 44.12 41.93N 1.7 – 0.1 0.1 0.2 0.77 0.05 0.12 0.57S 0.2 – 0.04 – – 0.18 0.03 0.01 0.01HHV (kJ/kg) 15,300 16,100 18,140 21,000 22,000 15,991 20,720 18,930 19,710HHV (kJ/kg)g 15,286 – 18,136 21,000 22,000 15,974 20,717 18,929 19,709A:Fh 4.69 5.55 6.02 6.46 5.01 6.02 5.64 6.0AFT (K) i 2115 – 2279 2438 2422 2168 2419 2339 2339

a Kurkela et al. [69].b Kandpal et al. [84].c Abbas et al. [8].d Ragland et al. [85].e Aerts et al. [10].f Ebeling and Jenkins [29].g HHV based on Boie equation.h Air to fuel ratio (DAF mass basis).i Adiabatic flame temperature calculated from the ultimate analysis.

Table 4Chemical analysis and properties of selected municipal residue

Fuel type MSWa Tiresb

Moisture 16–38 0.5Ash 11–20 6.1Volatiles 67–78 65.2Fixed carbon 6–12 28.7C – 81.5H – 7.1O – 3.4N – 0.5S – 1.4HHV (kJ/kg) 15,950–17,533 36,800HHV (kJ/kg)c – 36,671A:Fd 11.66AFT (K)e – 2492

a Saxena and Jotshi [86].b Christian and Unsworth [70].c HHV based on Boie equation.d Air to fuel ratio (DAF mass basis).e Adiabatic flame temperature calculated from the ultimate analysis.

Table 5Chemical analysis and properties of selected energy crops

Fuel type Poplara Eucalyptus (Grandis)a

Moisture – –Ash 1.33 0.52Volatiles – –Fixed carbon 16.35 16.93C 48.45 48.33H 5.85 5.89O 43.69 45.13N 0.47 0.15S 0.01 0.01HHV (kJ/kg) 19,380 19,350HHV (kJ/kg)b 19,379 19,349A:Fc 5.7 5.6AFT (K)d 2374 2388

a Ebeling and Jenkins [29].b HHV based on Boie equation.c Air to fuel ratio (DAF mass basis).d Adiabatic flame temperature calculated from the ultimate analysis.

The discussion is organized in the following format.Fundamental concepts relevant to coal combustion aresummarized in Section 2. In Section 3, a description ofbiomass fuels and their combustion behavior is presented.Studies related to direct combustion of coal/biomass blendsare discussed in Section 4. Issues regarding successfulimplementation of co-firing are discussed in Section 5 andconclusions are presented in Section 6.

2. Fundamental combustion issues

To facilitate a discussion on coal/biomass blends, a briefreview of the characteristics important to coal combustion ispresented. It will be seen later that biomass fuels behavesimilarly to low-rank coals.

2.1. Material and combustion characteristics of coal

Coal is a complex polymer consisting primarily ofcarbon, hydrogen, oxygen, nitrogen and sulfur. It is acompact, aged form of biomass containing combustibles,moisture, intrinsic mineral matter (originating fromdissolved salts in water) and extrinsic ash (due to mixingwith soil). Coal is formed by the following sequence:

Vegetation! peat! lignite �low rank coal�! anthracite�high rank coal�Plant materials have high cellulose (CH2O) content and

high molecular weights (on the order of 500,000 kg/kmol).After plants die and are exposed to high pressure and heatover a long period of time in dense swampy conditions,anaerobic micro-organisms assist in converting plant debris

into peat-like deposits. Overtime, peat bed becomes coveredin sediment, increasing the pressure. The temperature in thepeat bed also increases and chemical decomposition occurs,lowering the oxygen and hydrogen content. Hence, coal isformed first as lignite, then as sub-bituminous and finally asanthracite. The C/O and C/H ratio increase throughout theformation process. Anthracite is almost all carbon, with acorresponding increase in the heating value. It takesapproximately 200–300 million years to form coal. Thechemical properties of coal depend upon the relative pro-portions of the chemical constituents present in the parentplant debris, the nature and extent of the changes, which theconstituents have undergone since deposition, and the natureand quantity of the inorganic matter present. Coal rank indi-cates the relative proportions of volatile matter (VM) andfixed carbon (FC) present in the coal. Upon heating coal inan inert atmosphere, combustible gases are evolved from thecoal due to thermal decomposition of the solid. This processis called pyrolysis. The remaining skeletal matter in thesolid is called char, and is predominantly FC. Coal rankincreases with decreasing VM. Typically, a medium rankcoal consists of 40% VM and 60% FC while a high-rankcoal has about 10% VM. The older the coal, the higher therank. The highest ranked coal is graphite in structure.

The higher or gross heating value (HHV) for a particularcoal sample can be either measured or estimated using theultimate analysis of the fuel and the following relation [27]:

HHV �kJ=kg� � 35;160C1 116;225H2 11;090O

1 6280N1 10;465S �1�

where C, H, O, N and S are the elemental mass fractions inthe coal. The HHV can be determined on an as-received


Table 6Chemical analysis and properties of selected food processing residue

Fuel type Sugarcane baggassea Almond shellsa Olive pitsa Walnut shellsa Peach pitsa

Moisture – – – – –Ash 11.27 4.81 3.16 0.56 1.03Volatiles – – – – –Fixed carbon 14.95 21.74 18.19 21.16 19.85C 44.8 44.98 48.81 49.98 53.0H 5.35 5.97 6.23 5.71 5.9O 39.55 42.27 43.48 43.35 39.14N 0.38 1.16 0.36 0.21 0.32S 0.01 0.02 0.02 0.01 0.05HHV (kJ/kg) 17,330 19,380 21,390 20,180 20,820HHV (kJ/kg)b 17,329 19,378 21,388 20,179 20,815A:Fc 5.2 5.4 5.75 5.84 6.46AFT (K)d 2338 2445 2561 2424 2326

a Ebeling and Jenkins [29].b HHV based on Boie equation.c Air to fuel ratio (DAF mass basis).d Adiabatic flame temperature calculated from the ultimate analysis.

basis or dry-ash-free basis (DAF). Both VM and FC con-tribute to the heat released from coal. If the heat of pyrolysisis neglected, the heat of combustion of coal can be repre-sented as a combination of the contribution from the VM(HVv) and the contribution from the FC (HVc), where VMand FC content is on a per unit mass basis:

HVcoal� VM �HVv�1 FC�HVc� �2�

If FC � 1 2 VM as in the case of DAF coals, the heatingvalues of the volatiles, HVv, can be correlated to VM [31].Eq. (2) can be used to determine HVv if HV coal and VM areknown. The heating value of char (HVc) can be assumed as32,500 kJ/kg.

2.2. Pyrolysis

Fig. 1(a) and (b) is a schematic representation of thevarious physical mechanisms important in the pyrolysisand combustion of coal. The following sections brieflydescribe the significant characteristics of these mechanisms.When a coal particle is placed in a furnace, it is heated andpyrolysis ensues (thermal decomposition of coal). Pyrolysisis somewhat similar to vaporization; however, it is a rela-tively slow chemical process compared to vaporization. Thetemperature at which pyrolysis occurs depends on the fueltype and the heating rate. Typically, bituminous coal pyro-lyzes at about 700 K (1% mass loss) for heating rates,1008C/s [32]. This temperature is at or below the sponta-neous ignition temperature (SIT) for hydrocarbons (HC)[33]. At high heating rates (.10,0008C/s), pyrolysis ispresumed to start around 1500 K. The products of pyrolysisare volatile gases and the composition of these gases alsodepends on the fuel. Pyrolysis products range from lightervolatiles (CH4, C2H4, C2H6, CO, CO2, H2, H2O, etc.) toheavier tars. Typically the composition of the volatilesfrom lignite (low-rank) coals at 1300 K is 3% CH4 and38% CO and CO2 [34]. When experiments were conductedwith a few micrograms of 60mm coal particles sandwichedbetween an electrical wire mesh, pyrolysis started around350–4008C (1% mass loss) for very low heating rates of10248C/s. At moderate heating rates of 1008C/s, pyrolysisoccurred at 12008C [35].

Volatiles were found to issue as jets from 80 to 100mmdiameter particles, while forDp , 40mm; there was noevidence of volatiles jets [36]. Recent experiments on1 mm particles using digital imaging system confirmed thejetting behavior [37]. Pyrolysis time scales are on the orderof 10–100 ms for a particle diameter of 1 mm.

Apart from volatiles, nitrogen is also evolved from thefuel during pyrolysis in the form of NH3, HCN and other N2-containing species which are generally represented as “XN”.Nitrogen evolution normally occurs during the later part ofpyrolysis. Nitrogen evolved from fuel undergoes oxidationto NOx and is called fuel NOx to distinguish it from thermalNOx produced by oxidation of atmospheric nitrogen.

2.3. Volatiles oxidation

Once released, the volatiles undergo oxidation within thegas film surrounding the particle (see Fig. 1(a)). During thevolatiles combustion period, the gas phase temperature ismuch higher than the particle temperature [38,39]. Shadowphotography by McLean et al. [36] and holography bySeeker et al. [38] reveal that volatiles may burn in jets oras a flame envelope. An enveloping flame acts like a shroud,preventing oxygen from reaching the particle surface andtherefore preventing heterogeneous oxidation of char.

Some approaches used to analyze the oxidation of coalvolatiles are:

1. local equilibrium assumption [40,41] which assumesinstantaneous chemical reaction to the equilibriumcomposition as the volatiles are released;

2. methane oxidation kinetics [42];3. kinetics controlled by CO kinetics [43];4. cellulose kinetics [44];5. global oxidation kinetics [45];6. oxidation to CO and H2 followed by CO oxidation

kinetics [46,47].

Typically, one-step kinetics mechanisms over predictthe rate of release of chemical energy. Depending uponthe scheme, the rate of heat release changes, affecting thevolatile combustion time scale. Because the total time forvolatile combustion is on the order of a few ms, the par-ticular reaction scheme does not affect the overall coalcombustion time scale, which is on the order of seconds.However, the choice of approach does become important inobtaining accurate estimates of NOx and SOx emissions.

2.4. Char reactions

The skeletal char remaining after pyrolysis is essentiallyFC. The carbon undergoes heterogeneous reactions withgaseous species. Heterogeneous reactions are generallygoverned by the following processes [48]:

(i) diffusion of gas phase oxidizing reactant species to theparticle surface;(ii) adsorption of gas phase species�E � 32;000 kJ=kmol�;(iii) chemical reaction of the adsorbed species;(iv) desorption of the solid oxides�E � 170;000 kJ=kmol�;(v) diffusion of gas phase products through the boundarylayer to the free stream.

If boundary layer diffusion, (i) or (v), controls the overallreaction rate, the system can be readily analyzed using masstransfer and fluid mechanics relations.

Oxygen transfer to carbon/char can occur via O2, CO2

and/or H2O. The heterogeneous combustion of carbon/charoccurs primarily via one or more of the following reactions:

C 1 �1=2�O2 ! CO �I�


C 1 O2 ! CO2 �II �

C 1 CO2 ! 2CO �III �

C 1 H2O! CO1 H2 �IV �Assuming first-order reaction for scheme (I), the oxygenconsumption rate is given as,

_mO2< pd2

pBO2exp 2

ERuTp

!r∞YO2;w �3�

Similar expressions can be written using the other reactions.The dominant oxygen transfer mechanism at high

temperatures is via reaction (I) withE=Ru ù 26;200 K andBO2� 2:3 × 107 m=s: Reaction (II) has an activation energy

of E=Ru � 20; 000 K and BO2� 1:6 × 105 m=s: Reaction

(III), the Boudouard reduction reaction, proceeds with anE/Ru of about 40,000 K. In general, char reaction withsteam has been found to be 50 times faster than char reactionwith CO2 for temperatures up to 2073 K (Montana Rosebudchar, 75–100mm, 1 atm) [49]. While, at lower temperatures(1150 K), Matsui et al. [50] found that reactions (III) and(IV) proceed at approximately the same rate and that thereaction (I) proceeds 104–105 times faster than reaction(III) between 1100 and 1200 K. Reaction (II) is significantat low temperatures (e.g. ignition conditions) while reac-tion (I) is dominant under typical combustion conditions.For char particle combustion in pure dry air, the CO2 andH2O mass fractions in the ambient are negligible.

However, in boiler burners, the fuel particles are closelyspaced resulting in reduced oxygen availability to eachparticle. Combustion under such conditions is called cloudcombustion. Under these conditions, the reduction reactions(III) and (IV) may become significant, especially at hightemperatures.

2.5. Homogeneous reactions

Once CO and H2 are released via heterogeneous reactions(III) and (IV), they can undergo oxidation in the gas phase.The detailed CO reaction scheme is summarized by Mitchellet al. [51], Hottel et al. [43] and others [52,53].

2.6. Ignition

A brief discussion is presented on the ignition of anisolated coal particle and the relation of the ignitiontemperature to the reaction parameters for coal. The readeris referred to the review on ignition of coal by Essenhigh etal. [33] for a detailed discussion.

Oil droplets which fully vaporize or a plastic which fullypyrolyzes (e.g. polymethyl methacrylate) ignite homo-geneously (homogeneous ignition or gas ignition, GI). Carbonparticles, which are non-gasifying upon heating in an inertenvironment, ignite heterogeneously (heterogeneous igni-tion, HI). Coal, like many polymers, is partially gasifyingand is called a charring solid. Volatile matter, flammabilityof the volatiles and transport from the particle determine


coal coal

XNPyrolysisproducts(volatilematter)

(i) Pyrolysis (ii) Volatile oxidation (iii) Char

O2

CO2, H2O

NOx

coal

(b)

CO

CO

CO2

H2O

CO2

O2

CO

H2

(a)

Fig. 1. (a) Schematic of coal combustion mechanisms [87]. Pyrolysis produces volatile matter which is oxidized, leaving a char skeletal matrixas a solid product; and (b) schematic depicting heterogeneous coal reactions for carbon particle [87].

whether ignition of an isolated coal particle occurs eitherheterogeneously or homogeneously. If the volatiles evolveearly in the combustion sequence, they may remove oxygenfrom the internal pore surface area, thus preventing hetero-geneous ignition. If coal is ignited homogeneously, the vol-atiles burn in the gas phase (similar to droplet flames)preventing oxygen from reaching the particle surface. Ifcombustion is not complete or if volatile liberation occursas jets or intermittently from the pores [36,54], then oxygencan still reach the particle surface. In such a situation,heterogeneous combustion of FC and combustion of insitu VM can proceed in parallel with gas phase combustion.The thermal explosion theory is commonly used to definethe onset of heterogeneous ignition. According to thermalexplosion theory, ignition occurs if the rate of heat releasedue to chemical reaction is higher than the rate of heat lossdue to convection, radiation, etc., and if the process resultsin runaway conditions. A correlation for the heterogeneouschar ignition temperature can be determined using thermalexplosion theory [55]:

Tp;I � �E=Ru�ln

BO2dpYO2;∞hcE

ShDwnO2RuT2

p;ICp

" # �4�

For temperatures belowTp,I, heterogeneous ignition of thecoal particle will not occur. Note that Eq. (4) is an implicitrelation forTp,I. Eq. (4) was used to estimate the heteroge-neous ignition temperatures for three different types of coal.

Fig. 2 shows the variation in heterogeneous ignitiontemperature with particle diameter. For small particles(,30mm or less), no realistic values forTp,I could befound, which indicates that very small particles cannot beignited heterogeneously. The rate of heat loss is too highcompared to the rate of heat generation for smaller particlesdue to the high surface area to volume ratio. Fig. 3 shows acomparison of the experimentally measured non-dimen-sional minimum gas temperature (u∞,HI) required for hetero-geneous ignition [56] with those predicted by the steadystate and transient models of Du and Annamalai [55]. Theinverse of u∞,HI is plotted as a function of the fourthDamkohler number for carbon oxidation. The Damko¨hlernumber is proportional to particle diameter, andu∞,HI isproportional to particle temperature. It is clear that boththeoretical and experimental results predict a decrease inignition temperature as the particle size is increased. Inother words, larger particles need lower temperatures forheterogeneous ignition to occur. Recent literature suggeststhat there is also an upper limit to particle size for hetero-geneous ignition [57]. More details on the transient ignitionphase can be found in Ref. [55], while studies on laserignited particles are presented in Ref. [58].

2.7. Char combustion

Once ignited, the combustion of high volatile content coalproceeds in two stages: combustion of the VM and combus-tion of the FC. Combustion of the VM is similar to the


Fig. 2. Variation of heterogeneous ignition temperature with particle diameter for various coal and biomass fuels;Sh� 2; Dw � 1 cm2=s;

YO2;∞ � 0:23:

combustion of vapors from an oil droplet. However, thereare significant differences. Consider a single oil droplet ofradiusa placed in a hot furnace. Due to energy suppliedfrom the furnace to the droplet, the droplet is heated. Vaporsreleased by the droplet move radially into the ambient wherethey mix with oxygen and establish a diffusion flame at aradiusrf q a away from the droplet surface. The vaporiza-tion of the fuel drop is a non-chemically reacting process.The molecular composition of the vapor is the same as thedrop molecular composition. On the other hand, coal par-ticles partially pyrolyze releasing volatiles (a chemicaldecomposition process of the coal particles to gaseoushydrocarbon species) and leaving char particles (predomi-nantly carbon). The gasification rate is controlled by thekinetics of pyrolysis. The volatiles diffuse into the surround-ing atmosphere where they mix with oxygen and a flame isformed if the volatiles exist in sufficient proportion to theambient air. After the volatiles are exhausted, only char(carbon and small amounts of hydrogen) remains. Now,oxygen diffuses to the char surface and reacts to form carbonmonoxide and carbon dioxide (char oxidation). Unlike thecombustion of volatiles, which diffuse towards the oxygenrich atmosphere (resulting in a large reaction area), theoxygen in heterogeneous combustion must be transportedto the particle surface. Thus, the char combustion rate underdiffusion limited conditions is very slow. In droplet combus-tion, the flame is located far away from drop surface andthus the reaction surface area is 4prf

2 and the mass transfercoefficient for oxygen is on the order ofrD=rf (the diffusionrate of O2 per unit area is slower). The oxygen consumptionrate is on the order of 4prfrD and the burning rate is fast�rf � 30a for a quiescent flame). For a char/carbon particle

of radiusa, the mass transfer coefficient is of the order ofrD=a while the surface area is 4pa2

: The consumption rateof O2 is therefore on the order of 4parD:

Under diffusion limited combustion of solid char (i.e.carbon) particles, the diameter can be shown as follows:

d2 � d20 2 at �5�

where a � �4ShrD�=rch ln�1 1 B�; B� YO2;∞ =yO2and yO2

may correspond to reactions (I) or (II).Similarly, steady state char particle temperature under

diffusion limited combustion is given by:

_mchc � { h�Tp 2 Tg�1 es�T 4p 2 T4

j �}pd2p �6�

where,

_mc � prDShdp ln�1 1 B�For _mc . 0 and hc . 0; Tp . Tg and, for Tp # Tg; no

combustion occurs.The diffusion-controlled burning rate is about 30 times

slower for a carbon particle than an oil drop, mainly due tothe reduced reaction surface area.

The typical total combustion time for a 100mm solid coalparticle is on the order of 1s in boilers and is dominated bythe time required for the heterogeneous combustion of theresidual char particle. The pyrolysis time�tpyr �106 �s=m2�d2

p [32]) is on the order of 1–10% of the totalburning time.

2.8. Pollutant emissions

The nitrogen in coal, which mainly exists as XN (e.g.HCN, H3N, etc) readily oxidizes to form NOx (NO, NO2)


Fig. 3. Comparisons of experimental results for heterogeneous ignition with steady state and transient models,�u∞;HI � RuTp=E� (X: BO2�

35:6 m=s; E � 46:3 kJ=mol; W: BO2� 2388:1 m=s; E � 103:4 kJ=mol; B: BO2

� 390:2 m=s; E � 73:7 kJ=mol; A: BO2� 66:8 m=s, E �

56:0 kJ=mol; O: BO2� 1903:4 m=s; E � 82:8 kJ=mol [55].

at low temperatures (fuel NOx). The oxidation of atmosphericN2 to NOx (thermal NOx) occurs at higher temperatures(.1800 K). The majority of NOx emitted from coal-fired plants originates from fuel nitrogen. Some NOx

control technologies include:

1. Staged combustion, where oxidation near the burneroccurs in a fuel-rich regime. Oxygen concentrationsare lower in the high-temperature regions of theburner, therefore decreasing thermal NOx emissions.

2. Injection of NH3 at later stages of burning to reduceNOx to N2 (thermal DeNOx process).

3. Reburn combustion, where HC (or coal whichreleases HC during pyrolysis) are injected down-stream of the primary combustion zone to reduceNOx to N2.

Pollutant emissions are a growing concern as men-tioned earlier and emission regulations are driving con-tinuous development of new combustion technologies.

3. Biomass fuel

Biomass fuels follow the same sequence of pyrolysis,devolatilization and combustion as seen in low-rank coalcombustion mechanisms. However, there are some signifi-cant differences between coal and biomass combustion. Coaldensities typically range from 1100 kg/m3 for low-rank coalsto 2330 kg/m3 for high-density pyrolytic graphite [59].Biomass densities ranges from 100 kg/m3 for straw to

500 kg/m3 for forest wood [60]. Biomass usually consistof 70–80% VM whereas coal consists of 10–50% VM.The heating values of biomass fuels are appreciably lowerthan that of coals. Eq. (1) was recently used [28] to deter-mine the HHV for biomass fuels and resulted in good agree-ment with the experimental results of Ebeling and Jenkins[29] for 62 types of biomass. A maximum error of 12% forrice straw and 4% for wheat dust was found [29]. It isknown that the HHV per unit mass of stoichiometric oxygen�mO2;s� is approximately constant for most fuels (HHV/mO2;s , 12,500–20,000 kJ/kg,O2,s) [30]. Converting to aper unit volume of stoichiometric air basis (Vair;g) (usingthe density of air at 1 atm, 298 K) results in HHV/Vair,s, 3400–5400 kJ. Figs. 4 and 5 show the DAF HHVper cubic meter of stoichiometric air for several biomass andcoal fuels, respectively. It is apparent from the figures thatthe DAF HHV/Vair,s is almost constant for all types of fuel(within ^2%). Fig. 6 is a plot of the adiabatic flametemperature as a function of the HHV/mO2;s (on an as-received basis) for selected biomass fuels. Because theHHV/Vair,s are approximately the same value regardless offuel type, the adiabatic flame temperature should remainconstant when plotted on a DAF HHV/Vair,s basis, asshown in Fig. 7. The scatter observed in Fig. 6, in termsof the heating value, is less indicating that the flametemperature is approximately constant for all the fuelsprovided DAF fuels are used. Hence, the adiabatic flametemperature (Tad) can decrease if the ash and/or moisturecontent increases, or if the amount of stoichiometric airrequired for complete combustion increases. A parametricstudy of the effects of moisture and ash contents on theadiabatic flame temperature for sawdust is shown in Fig. 8.


2000

2500

3000

3500

4000

4500

almon

dsh

ells

barle

y straw

black

locus

t

corn

cobs

cotto

ngin

euca

lyptu

s

hard

wood

man

ure

olive

pits

peac

hpit

spe

at

popla

r

redw

ood

rice

husk

soft

wood

sawdu

st

suga

rcan

eba

ggas

se

switc

hgra

ss

tan

oak

wheat

straw

walnut

shell

s

Fuel

HH

V/m

3of

stoi

ch.a

ir

Fig. 4. DAF higher heating value per unit standard cubic meter of stoichiometric air for several biomass fuels.

An empirical curve fit �R2 � 0:99� for Tad is given asfollows:

Tad� a 1 bx1 cx2 1 dy1 ey2 1 fy3

1 1 gx1 hx2 1 iy 1 jy2 1 ky3 �7�

where,x is the moisture content (% mass basis, 0, x , 40�andy is the ash content (% mass basis, 0, y , 40� and the

coefficients are

a� 2336:7; b� 224:5; c� 20:0149; d � 216:616;

e� 20:3057; f � 0:0037;

g� 20:00727; h� 27:70× 1026; i � 20:0071;

j � 20:00012 andk � 1:44× 1026


2000

2200

2400

2600

2800

3000

3200

3400

metaanthracite

low vol. bitum.Coal

med. vol.bitum. coal

high vol. bitum.Coal

sub bitum.Coal

Fuel

HH

V/m

3of

stoi

ch.a

ir

Fig. 5. DAF higher heating value per standard cubic meter of stoichiometric air for coal fuels (coal analysis from Ref. [31]).

0

500

1000

1500

2000

2500

3000

0 5000 10000 15000 20000 25000

HHV (kJ/kg of stoichiometric oxygen)

Adi

abat

icF

lam

eTe

mpe

rat

ure

(K)

cotton gin

rice husk

corn cobs

saw dust

switchgrass

poplar

eucalyptus

sugarcane baggase

raw manure

Fig. 6. Adiabatic flame temperature as a function of higher heating value (HHV/kg of stoichiometric oxygen, as received basis) for severalbiomass fuels. The values are bracketed within 15,000–20,000 kJ/kg, except for RM and rice husk.

If the temperature decreases below 1600 K, flame stab-ility problems can occur in boilers and furnaces due to thereduced rates of chemical reaction. It is clear from Fig. 8that at 40% ash content, the maximum moisture level tomaintain the temperature at or above 1600 K is 34%. Simi-larly, at 30% ash, moisture should not be more than 40% inorder to avoid flame instability.

In order to illustrate further the differences in coal andbiomass properties, Table 7 shows the proximate and ulti-mate analyses of Wyoming coal and feedlot manure, abiomass fuel. Feedlot manure (raw, PCM or FCM) containsapproximately 82% VM on DAF basis as compared toWyoming coal which contains only 36% VM. With aging,the VM in manure decreases as a result of the gradual


Fig. 7. Adiabatic flame temperature as a function of DAF higher heating value per cubic meter of stoichiometric air for several biomass fuelsand coals. The values are bracketed within 3200–4300 kJ/m3.

1000

1200

1400

1600

1800

2000

2200

2400

2600

0 10 20 30 40 50

Moisture (%)

Adi

abat

icF

lam

eTe

mpe

rat

ure

(K)

0% ash

5%

10%

15%

20%

25%

30%

40%critical temperature for flame stability

Fig. 8. Adiabatic flame temperature for varying moisture and ash content for sawdust.

release of hydrocarbon gases or dehydrogenation. The DAFheating value of feedlot manure, on average, is 15,000 kJ/kg(5000 Btu/lb) versus coal, which has a DAF heating value of35,000 kJ/kg (14,000 Btu/lb). Even though the biomass hashigh VM contents, the heating values of biomass volatile areless than that of coal as shown in Table 8 (cf. Eq. (2)).

Feedlot manure also has higher moisture (,32%) and ash(,28%) contents on mass basis than coal, which typicallyhas 10–25% moisture and,5% ash. Ash can be classifiedas extrinsic and intrinsic. Intrinsic ash is contained in thematrix of the biomass, whereas extrinsic ash comes fromthe biomass collection process. The ash contents of woodybiomasses are much lower than for coal. However, theash content of non-woody biomass fuels can vary widely.For example, rice hulls have 18% ash while almond shellshave 5% ash. Most of the ash in high-ash biomasses areextrinsic in nature, consisting primarily of SiO2. Highermoisture and ash contents of biomass may cause flameinstability during combustion if used in higher proportions

in the blend. The potential impact on the burner temperatureprescribes the maximum allowable percentage of biomass inthe blend.

3.1. Pyrolysis

Pyrolysis of biomass is thermal decomposition of the fuel.As with coal, pyrolysis is a relatively slow chemical reactionoccurring at low temperatures. The reaction mechanisms arecomplex but can be defined in five stages for wood [60].Other biomass fuels with considerable woody matter wouldexhibit similar behavior.

1. Moisture and some volatile loss.2. Breakdown of hemicellulose; emission of CO and CO2.3. Exothermic reaction causing the wood temperature to

rise from 250 to 3598C; emission of methane and ethane.4. External energy is now required to continue the process.5. Complete dissociation occurs.


Table 7Chemical analysis and properties of coal and raw feedlot manure

Parameter Coal Raw manure Partially composted manure Fully composted manure

Moisture 10.8 36.61 30.02 35.35Ash 5.68 25.25 28.01 30.73Volatile matter 30.72 31.57 34.11 27.86Fixed carbon 52.80 6.57 7.86 6.06Heating value (as received),kJ/kg

26,535 7865 8305 6610

C 54.9 19.24 20.65 16.62H 4.33 2.22 2.30 1.72O 23.32 14.68 16.43 12.92N 0.76 1.47 1.86 1.82S 0.34 0.53 0.73 0.84

Empirical formulaa (DAF basis) CH0.94O0.32N0.012S0.0023 CH1.37O0.57N0.065S0.01 CH1.32O.597N.077S.0132 CH1.23O.585N.0937S.019

Molecular weightb 18.3 23.8 24.4 24.5A:FStoichiometric

b 6.9 2.5 2.6 1.9A:FStoichiometric

b (DAF basis) 8.2 6.2 5.9 5.8Adiabatic flame temperature (K)c 2505 1705 1790 1685

a Determined via ultimate analysis.b Determined via empirical formula for fuel.c Including ash and moisture in fuel. Stoichiometric condition; heating values confirmed with Boie equation.

Table 8Comparison of estimated heating contributions from volatiles

Fuel HV of volatiles (kJ/kg VM) VMa (%) Heat from VM (%) Heat from char (%)

Coal 31,375 36.8 36.3 63.6Sawdust 17,994 84.5 75.5 24.5Manure 18,256 82.8 73.3 26.7Rice husk 15,945 78.8 64.5 35.5Fuel wood 14,773 79.5 64.2 35.8Tires 42,360 69.8 75.0 25.0

a Mass basis.

The main products of biomass pyrolysis depend on thetemperature, heating rate, particle size and catalyst used.Typical gas composition of woody biomass pyrolysisincludes CO, CO2, CH4 and H2 as major products alongwith other organic compounds. Usually, fast pyrolysis yieldsmore gases than solids.

The VM loss can be determined using an overall massloss rate equation:

2dmv

dt� Bvmv exp

2ERT

� ��8�

Table 9 presents a comparison of kinetics data obtainedfor some coal and biomass fuels. Activation energies andpre-exponential constants vary considerably dependingupon the pyrolysis conditions and fuel type. In biomasspyrolysis, distinct temperature ranges with different kineticsare found. In addition, the activation energies of coals areconsiderably higher than those for biomass fuels.

Sweeten et al. [25] performed thermogravimetric analysis(TGA) of feedlot manure. The results for a heating rate of808C/min are shown in Fig. 9. Due to the high VM contentsof manure and lower activation energy, the pyrolysistemperature was much lower than in the case of coal. Drying(outgassing of water vapor) occurred between 50 and 1008C.Pyrolysis started (i.e 1% mass loss occurs) at 185–2008Cand the minimum ignition temperature was approximately5288C. Pan et al. [61] carried out TGA experiments to studythe pyrolytic behavior of pine char and blends of pine withlow-grade coals. Fig. 10 shows the results for pine chips.Most of the devolatilization (,82%) was achieved within225–350 s and in a temperature range of 360–5608C. Forcomparison purposes, Fig. 11 shows typical TGA results fora bituminous coal. When compared with coal, it is clear thatbiomass pyrolysis starts at lower temperatures, and thepercent weight loss is higher in biomass due to the higherVM content.

3.2. Ignition

The ignition process of biomass is similar to that for coalexcept there is more VM available for reaction in a biomassfuel. It is, therefore, more likely that homogeneous ignitionwill occur for biomass fuels. The heterogeneous ignitiontemperature of biomass chars can be predicted usingEq. (5). Fig. 2 shows the variation of ignition temperaturewith particle diameter for biomass chars (wood and sewagesludge).BO2

was calculated using the char kinetic data givenin Winter et al. [62]. For Ficus wood, the data given byDasappa et al. [63] was used. Note that the biomass fuelsexhibit a broader range of ignition temperature for a givenparticle size than coal does.

3.3. Char combustion

The physical and chemical transformations of biomassduring combustion have been studied by many researchers.Wornat et al. [64] investigated the combustion of switch-grass and pine char particles in a laminar flow reactor.Table 10 shows the fraction of each organic element as afunction of char conversion. Large amounts of oxygen andhydrogen are lost from the char early during conversion,indicating the release of VM. The absence of a visibleflame suggests that these volatiles are primarily CO, CO2

and H2O and not hydrocarbon gases. Unlike high-rankcoals, oxygen levels remain high (almost an order of magni-tude higher) in biomass char as also seen in low-rank coals.In addition, nitrogen is preferentially retained compared tocarbon in the chars of switchgrass and pine.

Table 11 gives the fraction of each inorganic element as afunction of char conversion. During devolatilization, allmetals are retained within the biomass char. After devol-atilization, potassium and sodium vaporize. Althoughsodium has higher boiling point than potassium, vaporiza-tion of sodium is more pronounced. This may be due to the


Table 9Pyrolysis kinetic data for selected biomass fuels and coals

Fuel Heat rate Temperature range (8C) A (1/s) E (kJ/g mol) References

Coal Lignitea – – 6.60× 104 105 [88]Bituminousa – – 4.30× 1014 229 [89]

Biomass Hazel nut 28C/s – 4.69× 1013 89.8–128.6 [90]Rice husk 1008C/min 225–350 1.30× 109 97.1 [91]Rice husk 1008C/min 350–600 1.31× 101 11.2Forest wood 28C/s 225–325 7.68× 107 124.8 [92]Forest wood 28C/s 700–900 6.32× 102 92.3Hardwood 0.838C/s 300–1123 2.15× 103 59.4 [93]Cellulose – 280–350 4.69× 105 82.7 [94]Lignin – 390–500 2.10× 105 70.7Hemicellulose – 320–400 8.70× 102 33.8

a Single coal devolatilization reaction assumed.

fact that potassium, being more electropositive than sodium,is capable of forming intercalation compounds with carbons.The intercalation can prevent vaporization. Reaction ofsodium with SiO2 to form sodium silicates is also likelybecause silica is abundant in biomass. This reaction is facili-tated at particle temperatures above 1900 K (melting pointof SiO2) and biomass particles can exceed this temperature.Compared to the alkali metals (K, Na), the di- and trivalentmetals (Mg, Ca and Al) are retained at higher levels.Conversion to silicates, coalescence, and sintering mayaccount for the fairly high percentage of these metals inbiomass char after devolatilization [64].

Fig. 12 shows the heterogeneous nature of biomass char.Particle size, shape and texture vary widely and uponcombustion the aspect ratio decreases and structures becomemore lace-like. Fig. 13 shows images of pine and switch-grass chars before and after combustion. Before combustion,there is no crystalline order (Fig. 13(a)). Short-range order

develops during devolatilization but after devolatilization,very little additional ordering (graphitization) takes place,even at the highest levels of conversion. Graphitizationdepends on the ability of carbon crystallites to align andcoalesce. Mobility is enhanced by hydrogen whereasoxygen hinders mobility by developing highly cross-linkedrigid carbon structures. The biomass chars contain highlevels of oxygen and low levels of hydrogen compared tocoal. Hence, graphitic structures do not develop in biomasschars as they do in bituminous coal chars, which containlower oxygen levels. The structural disorder may also leadto higher reactivities of biomass in the late stages ofcombustion since more edge carbon (which is more reac-tive) is available [64].

Experiments were conducted by Wornat et al. [65] toexamine biomass char reactivity. Fig. 14 shows the particletemperature as a function of particle diameter for pine char,lignite coal and bituminous coal. Compared with the coal


Fig. 9. TGA of feedlot manure at a heating rate of 108C/min [25].

particles, the pine particles burn over a wider range oftemperatures. This is an indication of the heterogeneity ofthe biomass particles. Also shown are the temperaturesunder chemical diffusion limited combustion (with chemicalheat contribution) and inert condition (without chemicalheat contribution). Note that the biomass char temperaturesspan the limits between diffusion-limited combustion andinert combustion.

Fig. 15 shows the particle temperatures and sizes for

switchgrass char as a function of residence time. As theresidence time increases from 47 to 95 ms, the meanparticle temperature decreases and particle distributionnarrows. The changes may be due to the preferentialdepletion of carbon and the physiochemical transforma-tions during combustion in biomass chars. As combus-tion proceeds, carbon is consumed from the biomass/char particles leaving non-combustible ash-rich particleswhich causes the mean temperature to decrease.Combustion is also accompanied by preferential lossof catalytic elements such as K and Ca. These transfor-mations would have a large impact on the reactivity ofbiomass chars at later times. Nevertheless, biomasschars are quite reactive in the early stages of charconversion and burn almost under diffusion control.Biomass char burning rates are comparable to burningrates of high-volatile matter bituminous coal chars.

3.4. Fouling issues in biomass combustion

Fouling of combustor surfaces is a major issue thathas played an important role in the design and operationof combustion equipment. Slagging and fouling reducesheat transfer and causes corrosion and erosion problems,which reduce the lifetime of the equipment. The maincontributions to fouling come from the inorganic ma-terial in the fuel. The behavior of these inorganics is lesswell understood than that of organic materials. Becausebiomass fuels contain a larger variety of inorganic materialscompared to coal, issues of fouling, corrosion and pollutantemissions need to be explored. This is particularly true forsome agricultural residues and new tree growth where the


Fig. 10. TGA of pine chips at a heating rate of 1008C/min [61].

Table 10Organic element retention in the biomass chars [64]

Charconversion(% DAF)

Massa Normalized fractional retention inthe char

C H O N

Southern pine0 1 1 1 1 152.8b 0.472 0.562 0.082 0.157 0.69473.0b 0.270 0.314 0.054 0.126 0.53286.4b 0.136 0.154 0.020 0.088 0.39494.6 0.054 0.053 0.010 0.049 0.172

Switchgrass0 1 1 1 1 148.0 0.520 0.626 0.146 0.237 0.58276.3 0.237 0.225 0.044 0.118 0.34990.7 0.093 0.104 0.019 0.066 0.22293.9 0.061 0.065 0.018 0.060 0.126

a Normalized char mass on a DAF basis.b These samples produced at 6% O2; all other samples produced at

12% O2.

Table 11Inorganic element retention in the biomass chars [64]

Charconversion(% DAF)

Normalized fractional retention in the char

Na Mg Ala K Ca

Southern pine0 1 1 1 1 152.8b 1 0.980 0.762 0.982 0.99773.0b 0.455 0.931 0.692 0.887 0.96286.4b 0.449 0.917 0.729 0.599 0.97394.6 0.313 0.827 0.878 0.468 0.789

Switchgrass0 1 1 1 1 148.0 0.853 1 1 0.946 176.3 0.591 0.911 0.978 0.721 0.92090.7 0.429 0.738 0.947 0.493 0.79293.9 0.058 0.697 0.751 0.441 0.678

a Al values more uncertain for pine char, due to low absolute Allevels.

b These samples produced at 6% O2; all other samples produced at12% O2.

ash can have relatively high alkaline metal contents, parti-cularly sodium and potassium [4]. Sodium and potassiumlower the melting point of ash and, hence can increase ashdeposition and fouling of boiler tubes.

Baxter [66] addressed ash deposition and corrosionproblems during coal and biomass combustion. He developeda mechanistic model to describe ash deposition in solid fuelcombustors and postulated characteristics of ash deposits inbiomasscombustion.The major mechanismsof ash depositionwere related to the types of inorganic material in the fuelblend and the combustion conditions. Ash deposition prop-erties such as tenacity, emissivity, thermal conductivity

and morphology were discussed in relation to fuel charac-teristics and operating conditions. The theoretical pre-dictions were validated by experiments carried out witha variety of coal types. Baxter concluded that the ashdeposition rate in biomass combustion would peak at earlytimes and then decrease monotonically. As compared todeposits from coal combustion, the tenacity and the strengthof the biomass combustion deposits will be higher,with smooth deposit surfaces and little deposit porosity.This means that the deposits from biomass combustionmay be hard to remove and may require additional cleaningeffort.


Fig. 11. TGA of bituminous coal at several temperature levels [95] Particle size: 460mm. A, B, C and D: temperature levels (250, 400, 450 and5008C).

3.5. Summary comparison of coal and biomass combustion

A comparison of pyrolysis, ignition and combustion ofcoal and biomass particles reveals the following:

1. Pyrolysis starts earlier for biomass fuels compared tocoal fuels.

2. The VM content of biomass is higher compared to thatof coal.

3. The specific heating value of volatiles in kJ per kg islower for biomass fuels compared to those from coalfuel.

4. The fractional heat contribution by volatiles in biomass isof the order of,70% compared to,36% for coal.

5. Biomass char has more oxygen compared to coal.6. Pyrolysis of biomass chars mostly releases CO, CO2

and H2O.7. Biomass fuels have ash that is more alkaline in nature,

which may aggravate the fouling problems.

4. Co-firing of blends

In the combustion applications, biomass has been fireddirectly either alone (as a sole source fuel) or along with aprimary fuel (co-firing). Various technologies that utilizeanimal-based biomass as an energy source are summar-ized in Sweeten et al. [25] and Annamalai et al. [26].These include on-site gasification [67–70], fluidized bedcombustion [23,25,26] and circulating fluidized bedcombustion [71,72]. Some of the biomass technologies

have met with limited technical success. The limitationswere primarily due to relying on biomass as the solesource of fuel, despite the highly variable properties ofbiomass. The high moisture and ash contents in biomassfuels can cause ignition and combustion problems (Fig.8). The melting point of the dissolved ash can also be lowwhich causes fouling and slagging problems. Because ofthe lower heating values of biomass accompanied byflame stability problems, the limited need for new elec-trical capacity in most of the US and the relatively lowcapital investment required for implementation, co-firingcurrently holds more appeal than any of the sole sourcetechnologies including more advanced conversion optionssuch as integrated gasification combined cycles [7,73]. Itis anticipated that blending biomass with higher-qualitycoal will reduce flame stability problems, as well as mini-mize corrosion effects. The co-firing approach will alsohave high potential for commercialization. The synergeticeffects of blending coal and biomass may also lead toreductions in other pollutant emissions. For example,HC are known to react with NOx and produce molecularN2. By injecting coal beyond the combustion zone as areburn fuel, the HC released from volatiles can be used toreduce NOx. The higher the VM content, the larger thereduction in NOx [74]. While coal contains 40–50% VM,biomass contain up to 80% VM on a DAF basis. Hence,biomass has the potential to be a very effective reburn fuelwhen coal is used as the primary fuel. Another possibleadvantage of biomass blend combustion stems from thepotential catalytic reduction of NOx by NH3 found in the


Fig. 12. Scanning electron micrographs (magnification× 100) of switchgrass chars: (a) uncombusted char; and (b) sample removed fromreactor after burning in 12% O2 (mole basis) for 95 ms (90.7% conversion DAF) [64].

biomass. For example, NH3 is naturally present in animalwaste.

4.1. Blend combustion efficiency

Since biomass fuels have higher VM compared to coal,the combustion efficiency is typically limited by the extentof char combustion. If it is assumed that similar fractions ofcoal and biomass char,h ch,b, are completely burnt (and sincevolatiles are completely burnt), then overall combustionefficiency of the blend can be given as:

where,Yb is the mass fraction of the biomass in the blendedfuel. Assuming VMb � 0:8; VMc � 0:4 andhch;b � 0:67;we get the following linear relationship.

h�blend�=h�coal� � 1 1 0:16458Yb �10�

Our recent detailed turbulent combustion modeling ofblends confirms such a relationship [75].

Although biomass fuels have lower heating value, rapidrelease of volatiles may locally increase temperature nearthe burner compared to coal-only case. Such an increase intemperature may increase production of thermal NOx.Hence, changes in NOx emissions from firing coal onlymay not be simply proportional to the decrease in totalnitrogen input in the blend [76].

4.2. Classes of co-firing

In order to present a discussion of coal biomass blend

combustion, three classes of co-firing are defined. Theclass of co-firing depends upon the feeding method usedfor the coal and biomass fuels.

(I) Separate feed lines and separate burners for coal andbiomass fuels (see Fig. 16) [10].(II) Separate feed lines and a common burner:

(a) two inlets — coal in the primary air and biomass inthe swirling secondary air (or vice versa) (see Fig. 20)[8].(b) three inlets — two for primary air (central andannular), one for swirling secondary air [15]. Coaland biomass flow arrangements are shown in Fig.18(a).

(III) Common feed lines and a common burner with pre-mixed coal biomass blends [7,11,77].

Class I co-firing has the advantage of better control overfuel flow rates. Thermal output similar to coal-only firingrequires higher biomass feed rates. Thus separate feedersfacilitate controlling the biomass feed rate independent ofthe coal feed rate. Using a single feed line for a blend fuelhas the risk of agglomeration occurring in the supply line,which may lead to a disconnection or blockage in the fuelsupply. On the other hand, separate feed lines and separateburners increase capital and maintenance costs. Firing lowheating value biomass independently of coal also has a riskof poor combustion efficiency.

Class II co-firing is relatively inexpensive in the sensethat a single swirl burner can be used to fire the blend.The coal and biomass are fed separately, as in Class I co-firing. At the burner entrance, the two fuel streams areunmixed. In the quarl region of the burner, the two streamsmix due to the swirling action of the secondary air. Whengood mixing is obtained, higher combustion efficiencies andlower emissions result. However, if a swirler is used, feed-ing one of the pulverized fuels in the swirling secondary airis likely to cause damage to swirler blades and this issueneeds to be addressed. The swirling fuel stream can beavoided using Class IIb firing (see Fig. 18) or introducingsecondary air at an angle to achieve the swirl (see Fig. 20).


Fig. 13. High-resolution transmission electron micrographs ofcarbon rich portions of biomass chars: (a) uncombusted pine char;(b) pine char sample at 53% conversion DAF; (c) uncombustedswitchgrass; and (d) switchgrass char at 48% conversion DAF [65].

hblend

hcoal� VMbYb 1 VMc�1 2 Yb�1 hch;b��1 2 VMb�Yb 1 �1 2 VMc��1 2 VMb��

VMc 1 hch;b�1 2 VMc� �9�

Damage to the swirl blades can also be avoided bypre-mixing the two fuels before they enter the burner(Class III firing). Class III firing is the least expensivemethod since no separate feed lines and burners are requiredand the existing fuel lines can be used. The Class III co-firing method provides good mixing, high combustion effi-ciencies and low emissions. However, the risk of burnerproblems associated with feeding difficulties and maintain-ing similar thermal input are obvious concerns for the boileroperators. In order to have the same heat throughput rateswhen co-firing, the following relationship is obtained.

mblend� mc�HHVc�=HHVblend �11�Typically, a 90:10 coal:sawdust blend will have a heating

value about 3% less compared to coal. Using Eq. (10), theblend feed rate should be increased by about 3% to have thesame heat throughput. The co-firing can be through suspen-sion or stoker boilers. In addition, fluidized bed combustionof coal/biomass blends falls under this category of co-firing.

In the following sections, specific results of various co-firing studies are presented. Due to the broad range ofbiomass fuels studied, the discussion has been grouped bythe type of biomass fuel.

4.3. Coal and agricultural residues

Sampson et al. [11] reported results for co-firing woodchips mixed with coal (Class III) at a stoker-fired steamplant. The boilers were mechanically fired by spreaderstokers with travelling grates and a fly ash reinjectionsystem. Three different types of wood chip were used

(higher heating values ranging from 19,350 to 19,690 kJ/kg (8320–8420 Btu/lb)). The higher heating value of thecoal was 25,080 kJ/kg (10,600 Btu/lb). However, the inves-tigators did not provide the size distribution of coal andwood chips used. They fired,10–22% by dry mass basisof wood chips in the fuel mixtures and found a negligibleeffect on particulate emissions. Table 12 shows that the fuelblend particulate emissions ranged from 0.06 to 0.1 grainsper SCF (0.0039–0.0065 gm/SCF). No data on NOx and SOx

emissions were provided. Due to bunker and stoker capacityproblems in the feeder system, they could not fire 30%biomass in the fuel blend. The capacity problems and theparticulate emissions can be reduced if the moisture contentof the wood chips is reduced. An economic study, conductedfor the 55,555 kg/h (125,000 lb/h) of steam power plant,concluded that energy derived from wood would be com-petitive with that from coal if more than 30 kton of woodchips were produced per year and hauling distances wereless than 60 mile.

Aerts et al. [10] carried out experiments on co-firingswitchgrass with coal (Class I firing) in a 50 MW, radiant,wall-fired, pulverized coal boiler with a capacity of 180 tonof steam at 85 bar and 5108C (see Fig. 16). Table 13 lists theultimate analysis of the coal and switchgrass used. Note thatswitchgrass contains 60% less nitrogen than coal on massbasis. However, on heat basis, nitrogen content in switch-grass is only about 13% less than coal. Five co-fired and fivecoal-only combustion tests at switchgrass feed rates up to3365 kg/h (10% heat input at 40 MW) were conducted for4 h durations. The cumulative particle size distributions forcoal and switchgrass are shown in Fig. 17. The switchgrass


Fig. 14. Optical measurements of temperatures and sizes of single particles burning at 72 ms in 12% O2 (mole basis) for: (a) southern pine char;(b) Beluah lignite coal; and (c) Pittsburgh #8 bituminous coal. Particle diameters were determined using the area-averaging technique.Tg

denotes mean gas temperature.D andI correspond to diffusion and inert ignition limits for spherical particles of equivalent diameter [65].

particles were significantly larger than the coal particles, yetthere were no adverse effects in co-firing with switchgrass.Unit operation was normal and slagging was not observedduring co-firing. Table 14 provides SO2 emissions for coaland coal:switchgrass blend combustion. The SO2 levels, ingeneral, did not change appreciably except at low load whenthe SO2 jumped to almost 1200 ppm. No explanation wasprovided. The NOx emissions decreased by about 20%,which most likely was due to low nitrogen content of theswitchgrass (see Table 15). Some partially burned switch-grass nodes were observed in the bottom ash. The amount ofunburned carbon in the cyclone and precipitator ash was

about 5% with co-firing, which was similar to coal-onlyoperation. Such observations seem to suggest that thelarge particle size and lower heating value of the biomassfuel did not adversely affect combustor performance, prob-ably due to the higher VM content of the biomass fuel. TheVM burns rapidly and the higher VM content of the biomasscan also result in a highly porous char, thus accelerating thechar combustion as well.

Fahlstedt et al. [12] carried out a series of tests on co-firing wood chips, olive pits and palm nut shells with coal atthe ABB carbon, 1 MW fluidized bed facility. Table 16shows the results of the tests in terms of combustion ef-ficiency, heat output and system temperatures. It is interestingto note that the blend combustion had a slightly higher


Table 13Analysis of coal and switchgrass [10]

Coal (Kindill) Switchgrass

As-received Dry As-received Dry

HHV (kJ/kg) 25,498 29,826 15,991 18,171

Ultimate analysis (percent by weight)Carbon 62.97 73.66 42.02 47.74Hydrogen 3.73 4.36 4.97 5.64Oxygen 7.26 8.49 35.44 40.26Nitrogen 1.36 1.59 0.77 0.87Sulfur 1.34 1.57 0.18 0.21Chlorine 0.02 0.02 0.03 0.04Ash 8.80 10.30 4.61 5.24Moisture 14.51 0.00 11.99 0.00

Table 14Sulfur dioxide emissions for coal switchgrass blends (corrected to3% excess O2) [10]

Load (MW) SO2 (ppm) SO2 (g/MJ)

Coal 40.2 853 1.04Coal 40.7 781 0.94Coal 48.8 912 1.07Coal 49.2 810 0.96Co-fire 39.9 1198 1.31Co-fire 40.1 910 0.98Co-fire 43.8 949 1.00Co-fire 46.4 896 0.98Co-fire 47.3 930 1.04

Table 12Wood chip characteristics, steam load and particulate emissions [11]

Date Fuel Chip MC(% wet basis)

Wood as percent of total Average steam load(1000 lb/h)

Particulateemissionsa

Weight (%) Btus

6/2/87 Coal – – – 125 0.07306/2/87 Coal – – – 123 0.08456/2/87 Coal – – – 130 0.04666/3/87 Aspen–spruceb 34.7 9.9 7.3 124 0.05936/3/87 Aspen–spruce 34.7 9.9 7.3 123 0.06656/3/87 Aspen–spruce 34.7 9.9 7.3 124 0.06376/4/87 Aspen–spruce 35.3 12.1 8.9 125 0.07816/4/87 Aspen–spruce 35.3 12.1 8.9 125 0.06786/4/87 Aspen–spruce 35.3 12.1 8.9 123 0.06046/5/87 Spruce–birchc 41.6 21.9 15.2 106 0.06306/5/87 Spruce–birch 41.6 21.9 15.2 120 0.09856/5/87 Spruce–birch 41.6 21.9 15.2 123 0.07436/8/87 Spruce–birch 40.4 12.1 8.3 120 0.07426/8/87 Spruce–birch 40.4 12.1 8.3 121 0.07486/8/87 Spruce–birch 40.4 12.1 8.3 125 0.0850

a Rate is in grains per dry standard cubic foot, corrected to 12% CO2.b Aspen–spruce was 75% aspen and 25% white spruce by volume and was chipped from green timber.c Spruce–birch was 75% white spruce and 25% paper birch by volume and was chipped from fire-killed timber that had been standing dead

for 3 years.

efficiency than coal-only combustion. The reason, asmentioned above, is likely due to the higher VM contentof the biomass fuels. Increasing the wood chips co-firingratio from 20 to 40% by mass resulted in a decrease inNOx of about 25%. The NOx levels were also low withother biomass fuels when compared with the coal-onlycase, probably again due to the lower nitrogen content inwoody biomass fuel. No fouling was observed in general butin the case of palm nut shells there was some indication ofan oxide layer on the bed surfaces which requires furtherinvestigation.

Similar results were presented by Siegel et al. [15] whoco-fired straw and cereal with hard coal in a 500 kW pulver-ized-fuel test unit (Classes III and IIb co-firing, seeFig. 18(a)). Fig. 18(b) shows the effects of the differentfuel injection schemes on NOx emissions. At higher biomassthermal loading (,60%), it is obvious that injecting coal inthe annular pipe results in a decrease in NOx, whereas usinga central coal jet causes an increase in the emissions as alsoreported by Abbas et al. [8]. However, at lower biomassthermal loading (,40%), injection of coal in the centraljet has lower emissions. The burnout was almost 99% fora co-firing ratio of up to 60% (by heating value) for a varietyof cereals and straw tested. However, above this co-firingratio, a substantial drop in the combustion efficiency occurs.The authors concluded that the fuel with higher nitrogen

content (coal in this example) should be injected into thefuel rich zone in order to reduce NOx emissions. This alsoexplains the low NOx emissions at lower biomass loadingand higher NOx at higher loading because the % primary airincreases with reduced coal loading.

Andries et al. [16] co-fired straw with coal in a1.6 MWthermal pressurized FBC test rig (Class III firing).Because of the high VM of the biomass, the temperaturedownstream of the free board (the surface of the fluidizedbed) was higher than the coal-only case by about 30 K. Thelocation of the high-temperature region corresponds to thelocation of volatile combustion. Co-firing reduced the CO,NOx and SO2 concentrations in the free board.

4.4. Coal and RDF

A dual fuel burner designed for the co-firing of waste-derived solid fuel with pulverized coal (Class IIa firing) wasevaluated by Abbas et al. [8]. Figs. 19 and 20 are schematicsof the burner facility and the burner, respectively. The influ-ence of fuel injection mode and co-firing ratio on combus-tion aerodynamics, flame stability and NOx emissions werestudied. The biomass fuel was predominantly sawdust,although some sewage sludge data were also reported. Theauthors found that combustion efficiency increased and NOx

emissions decreased when saw dust particles were injectedin the primary air with a swirling annular stream of coalparticles surrounding the biomass particles (swirlingprimary fuel, SPF mode). They reasoned that the centralsawdust stream pushed the coal volatiles into an oxygen-lean zone, thereby reducing the initial amount of NOformed. The opposite results were obtained when the coalwas injected through the center with an annular swirlingsawdust stream (central primary fuel, CPF mode). Theexperimental results suggested an optimum co-firing ratiothat resulted in maximum particle burnout and minimumNOx emissions. The optimum was achieved when sawdustprovided 30% of the total heat input and the injection modewas SPF. They also compared results on 15% co-firing ofsewage sludge in both the SPF and CPF modes and foundthe SPF mode most suitable for co-firing. The results on


Table 15Emissions of nitrogen oxide for coal and switchgrass blends(corrected to 3% excess O2) [10]

Load (MW) NO (ppm) NO (g/MJ)

Coal 40.2 385 0.22Coal 40.7 386 0.22Coal 48.8 450 0.24Coal 49.2 422 0.23Co-fire 39.9 395 0.20Co-fire 40.1 313 0.16Co-fire 43.8 355 0.18Co-fire 46.4 350 0.18Co-fire 47.3 377 0.20

Table 16Results of coal biomass fluidized bed pilot plant testing [12]

Wood chips 20% Wood chips 40% Olive pips 24% Palm nut shells 24% Polish coal 100%

Combustion efficiency (%) 97.6 97.2 97.9 98.1 97.1Bed density (kg/m3) 1186 1167 1244 1181 a

In-bed heat transfer, (kW) 443 418 439 420 a

NOx (mg/MJ) 77 57 90 101 141b

Bed temperature (8C) 839 840 843 840 840Freeboard temperature (8C) 785 779 794 794 784Cyclone temperature, (8C) 739 731 743 752 739

a Too short a test for stable value.b Too high excess air.

sawdust and sewage sludge emphasize the need to considerthe reactivity and the nitrogen content of all the fuels beforeselecting the fuel injection mode.

Van Doorn et al. [9] fired coal and wood, straw andmunicipal sewage sludge in a fluidized bed combustor(Class III firing). They found wood to be the most favorableco-firing fuel in terms of ease of combustion and reduced

emissions of NOx and SO2. No agglomeration of fuel par-ticles was observed. The emissions of SO2, CO and NOx

decreased with increasing wood to coal ratio. In the caseof co-firing straw, similar effects were observed. However,the HCl concentration increased with larger straw to coalratios due to the relatively higher chlorine content of straw.Co-firing sewage sludge with coal caused agglomeration of


Fig. 16. Alternate fuel handling facility for biomass fuel at Blount St. Generating Station [10].

Fig. 15. Optical measurements of temperatures and sizes of single particles of switchgrass char burning in 12% O2 (mole basis), initial particlesizeù75–106mm, particle residence times: (a) 47 ms; (b) 72 ms; and (c) 95 ms. Particle diameters were determined using the coded aperturetechnique.Tg denotes mean gas temperature [65].

fuel particles and high emissions. Similar tests on co-firingstraw with coal were conducted at two pulverized coal firedpower plants by Christensen and Jespersen [14]. They founda reduction of 20% in NOx with 22% (by mass) co-firingratio. The decrease is again attributed to the lower nitrogencontent of straw. The authors also estimated that the corro-sion rate with co-firing would be twice as high as that forcoal alone.

Ohlsson [17] carried out co-firing tests in a 440 MWcyclone fired combustor and measured emission levels of

SO2 and NOx, among other pollutants (Class III co-firing).The RDF used was binder-enhanced, densified municipalsolid waste (MSW). They fired a blend of 12% RDF and88% coal (mass basis) over a 10 h test period. The reductionin NOx emissions was 2–3% and was attributed to the lownitrogen content of the RDF. The sulfur dioxide emissionswere 17% lower than the coal-only case. The lower sulfurcontent of the RDF and more importantly the heterogeneousreaction of SO2 with the binder (calcium hydroxide) in RDFhelped in lowering the SO2 emissions. The particulateconcentration was higher with blend firing as the RDFcontained more ash than coal. On heat basis, the particulateconcentration was about 1.5 times more than the coal-onlycase.

Armesto et al. [71] investigated co-firing of coal and pinechips in a circulating fluidized bed (CFB) and a fluidizedbed combustor (FBC). Operation of the combustors wasnormal and they did not encounter difficulties. The CFBprocess had higher combustion efficiencies than the FBCprocess and consequently lower CO emissions. The NOx

and SOx emissions were also reduced in the two systems.In both cases, the author estimated an increase in combus-tion efficiency with an increase in co-firing ratio.

A sharp decrease in SOx emissions was reported byRasmussen and Clausen [72], who co-fired straw in an


Fig. 18. (a) Multi-fuel burner configuration for co-firing cereal and straw with coal [15]; and (b) NOx emissions for different burnerconfigurations [15].

Fig. 17. Particle size distribution for coal and switchgrass [10].

80 MWthermal CFB. SOx levels decreased substantially withincreasing straw input because straw has lower sulfurcontent compared to coal. Due to decreasing temperatureat higher co-firing ratios, the NOx emissions remainedalmost constant. Particulate emissions were below thedetection limit.

Brouwer et al. [76] carried out studies on emission reduc-tions while firing coal blended with refuse-derived fuel(Class III co-firing). The RDF used was hard and softwoodwaste from manufacturing and chipped railroad ties. Twofacilities were used: a spreader stoker-fired boiler and apulverized coal boiler. The stoker system was a pilot-scalefacility with a firing rate capacity of 500,000–1,000,000 Btu/h. The pulverized coal facility was a 38 kWresearch facility. Two methods of firing biomass with coal inthe pulverized coal facility were used. In the first method,the biomass was pre-mixed with coal and injected throughthe main line. In the second method, the biomass wasinjected after the recirculation zone as a reburn fuel.

In the stoker tests, railroad ties were fired at 20% massbasis in the blend. As shown in Fig. 21, the NOx emissionswere lowered by 25% with co-firing under clean conditions(excess air,50% and CO emissions,20 ppm). Theemissions reduction was ascribed to the lower nitrogencontent of the railroad ties (0.22% nitrogen). At low excessair levels, the CO emissions were considerably lower forblend combustion suggesting increased burnout with


Fig. 19. Experimental facility for co-firing studies of coal/waste derived fuels [8].

Fig. 20. Schematic of dual-fuel burner which can be operated in twomodes. APF mode is obtained when fuel 1 is sawdust and fuel 2 is coal;CPF mode is obtained when fuel 1 is coal and fuel 2 is sawdust [8].

blended fuels. Note that this reduced CO level correspondsto increased NOx. This is also evident by looking at Fig. 21.At lower excess air levels (,20%), there is almost no differ-ence in NOx between coal and the blend even though theblend has lower nitrogen content. The NOx emissions werefurther reduced with the injection of natural gas as a reburnfuel. With 28% excess air and 15% gas injection, the NOx

levels decreased from about 0.45 lb/MBtu to almost 0.25 lb/MBtu.

In the pulverized coal furnace, both co-firing and reburn-ing of wood waste was tested. In co-firing, wood waste(100% 24 mesh) was pre-mixed with coal (70% 200mesh) and fired at a constant heating rate of 38 kW. Externalstaging was used to study NOx emissions. The results areshown in Fig. 22. With unstaged combustion, the NOx

decreased as the co-firing ratio was increased, again dueto the lower nitrogen content of the biomass fuel. However,the decrease is not as much as expected from the equivalent

reductions in fuel nitrogen. For example, 600 ppm of NOx

was measured when coal, which contained 1.6% nitrogen(mass basis), was fired alone. With 50% co-firing (by heat-ing value) of wood waste (0.2% nitrogen by mass), themeasured NOx was 500 ppm. Had there been a proportionaldecrease in NOx with the reduction in fuel nitrogen (0.9%nitrogen), the NO levels would have been 340 ppm. On theother hand, with staged combustion (reduction in secondaryair at the burner and subsequent injection of air and fueldownstream of the burner), significant reduction in NOx

did not occur until the co-firing ratio was greater than50%. This indicates that co-firing wood waste with coalmay not lead to reductions in NOx emissions in a low-NOxconfiguration unless large co-firing ratios are used.

In reburning, wood waste was not co-fired but separatelyinjected after the recirculation zone to reduce NOx. Lowerreburn stoichiometric ratios led to increased wood reburningand NOx reduction. The wood waste reduced NOx just aseffectively as coal or natural gas at a temperature of 1721 K.All fuels performed poorly when the NOx levels in thereburn zone were low (500–200 ppm). For 200 ppm ofNOx, wood and natural gas performed much better thancoal as a reburn fuel, primarily due to the large amountsof VM provided by wood and natural gas.

It can be concluded that co-firing in stoker systemresulted in NOx reduction. Reburning with natural gasfurther decreases the emission level. In the pulverized coalbiomass blend firing, NOx reductions were observed but theywere not in proportion to the amount of wood combusted.Substantial reduction in NOx was achieved (,60%) whileinjecting the biomass as a reburn fuel. At high temperatures,biomass works even better than coal as a reburn fuel toreduce NOx emissions. Reburn stoichiometry is the mostimportant parameter that determines the effectiveness ofreburning with the waste biomass fuels with optimalstoichiometric ratios around 0.85.

Foster Wheeler Environmental and Reaction Engineering


0

0.1

0.2

0.3

0.4

0.5

0.6

0.7

0.8

0 20 40 60 80 100

Excess Air (%)

NO

x(l

bs/M

Btu

)

050100150200250300350400450500

CO

(ppm

)

NO (coal)

NO (coal+railroad ties)

CO (coal)

CO (coal+railroad ties)

Fig. 21. Effects of co-firing 20% (mass basis) railroad ties with coal on NOx and CO emissions [76].

Fig. 22. Nitrogen oxide emissions as a function of percentage ofwood in the blend (on heat basis) [76].

International co-fired wood-derived fuel with coal at exist-ing facilities within the Tennessee Valley Authority (TVA)power generation system [5]. Four types of plant were eval-uated: (1) a cyclone coal-fired power plant; (2) a wall-firedpulverized coal power plant; (3) a tangentially fired pulver-ized coal power plant; and (4) a gas or oil-fired power plant.Results of co-firing tests at the tangentially fired PC unitwere as follows:

1. The flame temperature decreases by about 40 K duringco-firing. This suggests that there will be a small reduc-tion in thermal NOx during co-firing.

2. 10–15% wood co-firing (heating value basis) results in adecrease in boiler efficiency of less than 1.5% relative tocoal-only firing.

3. There is a significant reduction in SO2 and NOx emissionsprimarily due to reducing the total amount of sulfur andnitrogen in the fuel blend.

The Electric Power Research Institute (EPRI) initiated aprogram in 1992 to commercialize co-firing in utilitystations. Hughes and Tillman [3] provided a detailedaccount of the co-firing tests carried out in full-scalepower plants, pilot plants and laboratory scale facilities.

At the Allen Fossil Plant of TVA, biomass/coal blends ofup to 20% wood have been burned in cyclone boilers. Tireshave also been burned in the fuel blend. The co-firing alsoconfirmed a reduction in CO2, SO2 and NOx. The study alsoestablished that there is a trade off between boiler efficiencyand fuel costs.

At the Kingston and Colbert power plants, 5% wood-derived biofuel was co-fired (Class III co-firing) in tangen-tially fired and wall-fired PC boilers, respectively. Due topulverizer performance and fuel particle size, 5% co-firingwas found to be the limiting case.

Other co-firing tests performed in utility boilers and pilotplants are summarized in Tables 17 and 18. The plant ca-pacity was maintained in all the co-firing tests. The results ofthese tests can be summarized as follows.

1. Co-firing can be performed at moderate and high percen-tages in cyclone boilers.

2. Co-firing can be performed at low percentages (by mass,0–5%) in PC boilers. The co-firing ratio depends on thepulverizer performance which in turn depends on thetype of biomass fuel used. Most biomass fuels havefibrous structure (e.g. wood, switchgrass) which are diffi-cult to ground to the same sizes as coal used in coalpulverizers. Grinding costs determine the extent towhich biomass can be economically pulverized.

3. Co-firing (5–10%, mass basis) in PC boilers may requireseparate fuel feed lines depending upon the capacity ofexisting pulverizers, type and condition of biomass fuelsand the type of pulverizers used.

4. The potential for successful application of co-firing issite-specific. It depends upon the characteristics of

power plant being considered, the availability and priceof biofuel within 50–100 mile of the plant and theeconomic value of environmental benefits.

In 1996, DOE’s Federal Energy Technology Center(FETC), became a co-funder of the overall biomass co-firingresearch program conducted by EPRI. After several success-ful parametric tests done at utility boilers [5], the DOE’sOffice of Energy Efficiency and Renewable Energy,Biomass Power Program joined as a co-funder in 1998 toparticipate in several long-term demonstration tests. Co-firing at the NIPSCO Bailly Station, the GPU SewardStation and the Allen Station will demonstrate the long-term impacts and benefits of biomass co-firing.

The European Commission launched a 2 year project(APAS) in 1993 on co-firing biomass in laboratory, pilotand full-scale units. Twenty-five partners from eightEuropean countries participated in the project. Hein andBemtgen [2] summarized the activities undertaken duringthis project. A description of participants and facilities isgiven as Table 19. Two general types of biomass fuelwere considered: woody (wood, straw, paper, Miscanthus)and sewage sludge. Table 19(a) describes the woodybiomass studies and Table 19(b) describes the sewagesludge studies. The combustion facilities were either PCor FBC. The results derived from these studies were:

1. Both modes of PC and FB are well suited for co-firingprovided a fuel dependent feed and preparation system isinstalled.

2. No major negative effects on fuel conversion were found.3. In order to avoid corrosion and slagging of the heat trans-

fer surfaces, biomass fuel rich in chlorine and alkalimetals should not be used in co-firing.

4. With respect to the emissions of hazardous gaseouscompounds, no increases in concentrations in the fluegases were observed. In many cases, substantial emissionreductions were found, which were a function of biomasscomposition and the fuel injection mode. The effect ofemission reduction due to injection mode was particu-larly apparent for NOx emissions.

4.5. Coal and animal waste

Frazzitta et al. [7] evaluated the performance of a small-scale boiler burner facility (see Fig. 23) while using coal andpre-mixed coal and manure blends (Class III firing). The co-firing ratio was 20% manure by mass. Three types of feedlotmanure were used: raw (RM), partially composted (PC) andfully composted (FC). RM is defined as fresh manure justcollected from the ground. When RM is stockpiled andturned in the outside air for about 30 days, it is consideredPC. If the drying and turning period is greater than 120 days,the manure is considered FC.

The authors measured the temperature distribution inthe burner, emissions and composition of flue gases and



Table 17Co-firing tests performed at full-scale utility boilers [3]

Descriptive title andapproximate date

Organizations Report reference

Performers Funders

Commercial operations co-firing sander dust with coal in acyclone boiler at NSP (1987–present)

Northern States Power Northern States Power Power (,1990). EPRIconference 1992 and 1993

Co-firing forest debris fromHurricane Hugo in a pulverizedcoal boiler at Santee Cooper(1990)

Santee Cooper Electric Coop.(South Carolina)

Santee Cooper Electric Coop.(South Carolina)

Power (1993), SERBEP (1992)

Commercial coal/biomassfluidized-bed combustion atTacoma (1991–present)

Tacoma Public Utilities Tacoma Public Utilities Power (,1993)

Waste wood co-firing tests atPlant Hammond, pulverizedcoal boiler of Georgia Power(1992)

Georgia Power and SouthernCompany Services (SCS)

SCS and Georgia Power EPRI Conference 1993 inWashington, DC (TR-103146,12/93)

Tire-derived fuel co-firing testin a wall-fired grate-equippedPC boiler (1992)

City of Ames, Iowa StateUniversity

South Carolina E&G, Penelec:Centerior

EPRI TR-103851, 12/94

Confiring of low percentage ofwood at the Colbert wall-firedPC boiler of TVA (1992)

TVA TVA EPRI Meeting 12/93

Co-firing of low percentage ofwood at the Kingstontangential-fired PC Boiler ofTVA (1993, 1994)

TVA, Foster Wheeler TVA EPRI Meetings 12/93 and 11/94

Plastic/fiber waste co-fired in aPC boiler (1993)

South Carolina E&G South Carolina E&G South Carolina E&G 1994

High-percentage wood co-firingin a pulverized coal boiler atSavannah Electric (1993)

Savannah Electric and SCS Savannah Electric and SCS Power (1995)

Wood co-firing up to 20% bymass in a Cyclone boiler at TVA(August 1994)

TVA, Foster Wheeler TVA/EPRI Foster Wheeler 12/94, EPRIGray Cover 7/96

Mid-percentage (10% by heat)co-firing in a pulverized coalboiler at NYSEG (1994)

NYSEG NYSERDA, NYSEG,ESEERCO

NYSERDA Report No. 96-01(January 1996)

Wood and tire trifiring with coalup to 15% by mass at Cycloneboiler at TVA (August 1995)

TVA, Foster Wheeler TVA/EPRI EPRI Gray Cover 5/96

Wood co-firing up to 20% bymass in a Cyclone boiler at TVA(December 1995)

TVA, Foster Wheeler TVA/EPR Foster Wheeler Report andPaper 5/96

Wood preparation (sawdust,right-of-way and poplar) andco-firing in a PC boiler (1995)

GPU/Penelec, Foster Wheeler State of PA, DOE/PETC,EPRI, GPU/Genco

EPRI Gray Cover 7/96

Switchgrass co-firing in a wall-fired, grate-equipped PC boilerin Madison, WI (1996)

Madison Gas and Electric,University of Wisconsin

EPRI, DOE’s Great Lakes Reg.Biomass Prog., MG&E, others

EPRI Meeting 6/96

Preliminary test of plastics, millresidues co-fired in a PC boiler(1996)

Duke Power Duke Power EPRI Meeting 6/96


Table 18Co-firing tests performed at pilot plants and laboratory scale facilities [3]



Performers Funders

RDF co-firing in utility boilersand performance calculationsvia ‘RDFCOAL’ (,1985)

MRI, Iowa State University,EPRI

EPRI, DOE/Argonne EPRI CS-5754.6/88

RDF co-firing update (1996) Iowa State University EPRI EPRI,9/96Strategic analysis of biomass/waste fuels for utilities, and‘BIOPOWER’ Calculations(1993)

Appel, SFA Pacific, EPRI EPRI, NYSERDA, DOE/SERBEP

EPRI TR-102773, 12/93;-774, 3/95

Wood fuel sources,transportation and cost/supplyfor co-firing at TVA plants(1992–1995)

University of Tennessee TVA, EPRI University of Tennessee 8/93,EPRI,8/96

Case studies of wood co-firingconcepts and costs for TVApower plants (1993)

Ebasco (now Foster Wheeler) EPRI, TVA, DOE/SERBEP EPRI Gray Cover 4/94

Conceptual designs and costsfor co-firing wood in systemsbased on natural-gas fired gasturbines (1993)

Ebasco (now Foster Wheeler) EPRI, TVA, DOE/SERBEP EPRI Gray Cover 7/96

Wood reburn for NO, control incoal-fired boilers: lab tests andrough economics (1994)

REI, Foster Wheeler,University of Utah

DOE/SERBEP, EPRI, NSF REI Paper 1995 EPRI,8/96

Wood reburn concept design/cost for NO, control in TVAcyclone-fired boiler (1995)

Foster Wheeler, REI TVA/EPRI EPRI Gray Cover 5/96

Wood/coal blends: storage andcold-flow tests simulating binfeed for cyclone boilers (1994)

REI, Foster Wheeler TVA/EPRI EPRI Gray Cover 7/96

Fuel characteristics of millresidues for TVA co-firing(1994)

Foster Wheeler, TVA TVA/EPRI EPRI Gray Cover 7/96

Biomass fuel resources forIndiana (1994)

NEOS DOE/GLRBEP GLRBEP Report

Designs, costs and COFIREIspreadsheet (1995)

Foster Wheeler TVA.EPRI.DOE EPRI,8/96

Biomass resources and powerplants for potential co-firing atUnion Electric (1995)

Foster Wheeler Union Electric, EPRI EPRI,9/96

Wood resources and powerplants for potential co-firingprojects at PennsylvaniaElectric (1995)

Foster Wheeler GPU/Penelec, EPRI EPRI Gray Cover 10/95

Willow energy crop and woodco-firing feasibility in NewYork State (1995)

Antares, NYSEG, NMPC,SUNY

DOE/NREL, EPRI, NYSEG,NMPC, others

EPRI TR.105250 11/95.NREL also

Grass crops and wood crops forco-firing in a coal-fired powerplant in Iowa (1995)

Iowa State University, IES,others

DOE/NREL, EPRI, IES, others NREL (also an EPRIsummary in TR-105854)

Bench-scale test of switchgrassco-firing (1995)

DOE/PETC DOE/PETC PETC soon (,8/96)

Lab ‘drop tube’ test andengineering study of wasteplastic co-firing for a PC boiler(1995)

ABB-CE, Duke Power Duke Power, EPRI, AmericanPlastics Council

EPRI Gray Cover 7/96

determined the combustion efficiencies. Fuel blends wereinjected in a pre-heated burner with a hot secondary airstream of about 2008C. As the firing started with a constantair feed rate, the burnt fraction gradually increased withincreasing gas temperatures. When the burnt fraction wasabout 95%, the temperature distribution with and withoutthe manure was approximately the same suggesting thatmanure did not adversely affect the flame stability. Theburnt fraction was determined using the exhaust gas analysisand was found to be 97% for both coal and coal/manureblends. The NOx levels decreased from 555 ppm for FCmanure, to 500 ppm for RM and to 480 ppm for PC manureat 95% burnt fraction. The decrease in NOx may be due tothe varying amounts of nitrogen and moisture in the threetypes of manure (see Table 7). On a DAF basis, FC manurehas more nitrogen than PC manure. Fig. 24(a) shows theamount of nitrogen in NO normalized with nitrogen infuel for coal and coal/manure fuel blends. The ratio is high-est for coal and lowest for RM and gradually increases fromraw to PC to FC manure blends. The same excess air wasused in all three experiments and O2 concentration inexhaust was 3%. Fig. 24(b) shows that the NOx evolutionstarts even at low burnt fractions that occur during thewarm-up period of the reactor. Most importantly, lowerSOx emissions were measured for blended fuel. This maybe due to SO2 capture by the alkaline ash of the feedlotmanure, however, these results on SO2 need to be rechecked.

4.6. Combustion modeling for coal biomass blends

Coal/biomass blend combustion modeling is a complexproblem that involves gas and particle phases along with theeffects of turbulence on the chemical reactions. For turbu-lence closure,k–e model has been used in many combustioncodes. It is relatively easy and simple to implementcompared with other turbulence models. Computationaltime is relatively small and the results obtained are reason-ably accurate. The standardk–e model is modified toinclude the effects of particles on gas phase turbulence.However, for flows with strong swirl, thek–e model doesnot yield good results. This is due to the assumption of

isotropic turbulence made in the model. Strong swirl flowsare known to be highly non-isotropic in nature and thereforeneed a more elaborate modeling thank–e model.

Most coal combustion codes (e.g. PCGC-2) are based onmixture fraction-equilibrium chemistry approach. Fastchemistry is assumed and thus mixing of fuel and oxidizerdetermines the combustion process. The mixture fractionsare defined as,

hi � miXi

k�0

mk

�12�

wherek � 0 refers to secondary air and the index i refers toprimary air�i � 1�; coal-off gas�i � 2� and biomass-off gas�i � 3�:

The predictions are obtained by numerical solution of thetime-averaged conservation equations for the gas and par-ticle phases. The basic idea is to de-couple the gas andparticle equations using the particle source terms as tearvariables. Tear variables are the terms in the gas phaseequations that contain the sources of mass, momentumand energy from the coal particles. These terms make itpossible to solve the gas and the particle phase equationsseparately. The gas phase is solved in the Eulerian domainwhile the particles are treated in a Lagrangian frame. Mostmathematical models consist of sub-models for turbulentfluid mechanics, gaseous combustion, particle dispersion,coal devolatilization, heterogeneous char reaction, pollutantformation and radiation.

Existing coal combustion models are modified to includethe effects of biomass co-firing on the overall combustionbehavior. The problem in blend combustion is that twochemically different fuels (coal and biomass) are involved.Therefore, the off-gases from each solid fuel must betracked separately to capture the interaction of coal andbiomass combustion. There are few modeling studies onblend combustion in the literature probably due to the factthat co-firing is a developing technology still in the testingphase.

Abbas et al. [8] developed a mathematical model for


Table 18 (continued)



Performers Funders

Biomass co-firing prospects forNorthern Indiana PublicService (1996)

Foster Wheeler NIPSCO, EPRI EPRI soon (,8/96)

Biomass co-firing and CO2options for NIPSCO

Moll Associates NIPSCO, EPRI EPRI soon (,8/96)

Wood fuel preparation atNYSEG: equipment selectionand equipment tests (1996)

NYSEG EPRI, NYSERDSA,ESEERCO, NYSEG

EPRI,11/96

blend combustion based on thek–e turbulence model [78], aturbulence decay model for volatile combustion and a diffu-sive radiation model. A single step model was used for thepulverized fuel devolatilization, and a kinetic and diffusion

model was used for the char reactions. In order to accountfor the variability in the properties of the volatiles from eachtype of fuel, they used two mixture fractions to track coal-and straw-off gases separately. The coal-off gas and straw-off


Table 19Description of participants and facilities involved in the European Union biomass utilization program [2]

Fluidized bed Pulverized fuel

Atm. bubbling Press. bubbling Atmospheric circulating Low-rank coal High-rank coal

Low-rank coal High-rank coal

(a) Woody biomassKTH 10 kW straw, wood, misc. 11008C pyrolysis, reactivity tests, N-releaseECN 0.3 MWpellet, biomass700–9008C0–30%

INETI 0.3 MWstraw, wood700–9508C0–50%

IVD 0.35 MWMiscanthus, straw900–12008C0–50%

IVD 0.35 MWMiscanthus,straw 900–12008C0–50%

CIEMAT 1MW wood, straw700–9008C0–30%

Tu Delft 1 MWstraw,Miscanthus,750–9508C0–30%

RWE 1 MW straw,Miscanthus,750–9508C0–30%

CIEMAT 1 MWwood, straw700–10008C0–30%

RWE 1 MW straw,Miscanthus,900–11008C0–30%

KEMA 1 MWwood1000–13008C0–30%

IFRF 2.5 MWw.paper, straw1000–13008C0–50%

ELSAM 80 MWstraw 700–9008C0–60%

VEAG 100 MWMiscanthus, wood900–11008C0–10%

ELSAM 131 MWstraw 13008C0.25%

(b) Sewage sludgePulverized fuel Fluidized bed Other systemsHigh-rank coal High-rank coal

DMT 0.3 MWpellet, sewagesludge 700–9508C0–30%

IVD 0.35 MWsewage sludge900–12008C0–50%

ECN 0.3 MWpellet, sewagesludge 700–9508C0–30%

Imp. Coll. 0.5 MWstraw. Wood700–9508C 0–50%

Stadtw.SB 2 MWsewage sludge700–9008C0–30%

Berzelius sewagesludge leadproduction

IFRF 2.5 MWsewage sludge1000–13008C0–50%NEI 88 MWsewage sludge1200–16008C0–30%

Fechner 11 MWsewage sludge700–9008C 0–20%

Saarbergwerke150 MW sewagesludge 15008C0–15%

gas fractions were calculated on a staggered Cartesian meshusing a hybrid differencing scheme. The gas phase equationswere based on Eulerian reference frame while the particlephase equations were modeled using Lagrangian referenceframe. The authors compared the results with their experi-ments on co-firing coal and sawdust and found good agree-ment between the experiments and the model results. Theypredicted an earlier devolatilization of coal particles due toearly ignition of sawdust volatiles in the near burner region.Similar predictions were obtained by Dhanaplan et al. [79].The increased devolatilization rate led to lower NO forma-tion (40% reduction) when the sawdust was introducedthrough the middle of the annular coal jet.

A full-scale coal and straw-fired utility boiler wasmodeled by Kaer et al. [13]. The authors used a commercialCFD code (CFX4.2) with an extended particle formulationmodel. The steady state three-dimensional Navier–Stokesequations and Lagrangian particle tracking equations weresolved in a cartesian mesh. The calculations were based onphysical data from a full-scale co-firing facility. The calcu-lations incorporated ak–e turbulence model, a two-step gas-phase combustion formulation including chemical kineticsand a kinetic-diffusion model for the coal and straw charparticles. The results showed a marked difference in the

combustion behavior (temperature, species concentration,etc.) due in part to the large volumetric concentration ofstraw near the burner mouth. Devolatilization and burnoutof the larger straw particles occurred further away from theburner mouth, which changed the combustion behavior. Inaddition, the trajectories of the chopped straw were quitedifferent from those of the coal particles.

Dhanaplan et al. [79] obtained similar results when theynumerically studied coal-only and coal/manure blendcombustion in a swirl burner using the combustion code,PCGC2 [80]. In the near burner region, there were signifi-cant differences in temperature and species concentrationsbetween coal-only and coal/manure blend combustion. Thisis due to the different chemical compositions of coal andmanure. For blend combustion, PCGC-2 was modified toincorporate a three-mixture fraction approach. The originalPCGC2 tracks two-mixture fractions (primary and coal-offgases) only. In the modified code, a third mixture fractionwas added. The third fraction, manure-off gas, was usedbecause the properties of manure and coal are very differentand consolidating fuel-off gases into one mixture fractionwould lead to erroneous results. The authors compared themodeling results for 90:10 coal/manure blend (mass basis)as predicted by the three-mixture fraction model with those


Fig. 23. Schematic of experimental facility used for coal/manure blend studies [7].

from the original two-mixture fraction model. Similar sizesof coal and manure particles were used (70%,60mm).They found that in the near burner regions there were signif-icant differences between the two models in predicting thetemperature distribution and species concentrations. Fig. 25shows the results for the centerline temperature profiles forthe two- and three-mixture fraction approaches. The three-mixture fraction model yields higher temperatures thanthose predicted by the two-mixture fraction model fordistances greater than,0.2 m. The maximum temperaturedifference is about 350 K, which can be significant, particu-larly when determining thermal NOx emissions. However,the ignition distance remained almost unaltered due to thesmall amounts of manure in the blend. Fig. 26 shows speciesconcentration results (CO, CO2 and O2) at the centerline ofthe burner. The NOx concentrations were not evaluated. The

three-mixture fraction model predicted lower levels ofoxygen and higher levels of CO and CO2, indicating slightlyhigher burnout. The results can be attributed to the carbonatom fraction, which was more accurately predicted in thethree-mixture fraction approach. Separate treatment of thecoal-off and manure-off gases avoids averaging coal- andmanure-off gas properties and thus leads to improvedresults.

Sami et al. [75] also modeled coal and manure blendcombustion in a swirl burner using the PCGC2 code modi-fied for three-mixture fractions. A 90:10 coal/manure blend(by mass) was studied. The burner dimensions are describedelsewhere [7,79]. Manure particle sizes were twice that ofcoal particles (coal: 70% ,60mm, manure: 70%,110mm). The effects of the primary and secondary airflowrates on burnout and temperature profiles were studied,


Fig. 24. (a) Ratio of nitrogen in NO to nitrogen in the fuel for four different fuels [7]; and (b) emission of NOx from coal and coal/manure blendstudies [7].

while maintaining the equivalence ratio at a constant value.Since, the stoichiometric air to fuel ratio for manure (5.2 kgair/kg manure) is much lower than that for coal (9.7 kg air/kg coal), the equivalence ratio (w ) decreases when coal isreplaced by a small percentage of manure. There are twoways to maintain the equivalence ratio at the base case(coal-only) value: (i) increasing the fuel loading in theprimary air (equivalent to decreasing the primary air); or(ii) decreasing the secondary air.

Fig. 27 shows a comparison of the burnout for threedifferent cases whenw was kept constant at 0.89. It is inter-esting to note that a higher burnout is obtained for the casewhere the secondary air flow was decreased (Case 3) ascompared to the case where the fuel flow rate was increased(Case 4). However, the associated temperature profile forCase 3 resulted in lower values, as seen in Fig. 28. In fact,the Case 3 temperature profile was almost identical to thatpredicted for the coal-only case. This is due to the fact thatthe net heat input in Case 3 is less than that for coal-onlycase. The reduction in secondary air compensates the reduc-tion in heat input such that the resulting temperatures aresimilar. There was also a shift in the location of the peaktemperature for Case 4. For axial distances greater than,0.14 m, the centerline temperature increased with anincrease in fuel flow rate. This was due to the fact that theheat capacity� _mf C� of the fuel increased with an increase in

fuel flow rate. It therefore took more time to heat the fuel tothe pyrolysis temperatures. Hence, ignition was delayed andthe peak temperature shifted downstream of the burner. Therelative changes may be interpreted as a change in the flamelocation. Unlike coal-only combustion, blend combustionproduced more combustibles in the near-burner region fora given amount of primary air. More combustibles meanmore energy in a given control volume. Thus, in Case 4,temperature decreased slowly when compared with the coal-only case for a given secondary airflow rate.

The conclusions of Sami et al. [75] are summarizedbelow:

1. Blend combustion resulted in improved combustion ef-ficiencies compared to coal-only combustion.

2. Increasing fuel loading resulted in higher temperaturescompared to the coal-only case. A downstream shift inthe location of the peak temperature was also observed.Higher temperatures may also increase thermal NOx

levels.3. Decreasing the secondary air resulted in almost the same

temperature profiles (hence same thermal NOx level) asthose of the coal-only case, however the burnout wasimproved significantly.

4. In order to maintain the same equivalence ratio, it isbetter to reduce the secondary air flow than to increase


Fig. 25. Predicted centerline temperature profiles for 90:10 coal/manure fuel blends using the two- and three-mixture fraction approach [79].

the fuel flow rate. However, it should be noted that theheat throughput will also decrease slightly.

Although some combustion models exist for fuel blendcombustion, they are limited in their scope and complexity.Most of these models incorporate simplified assumptions indescribing various aspects of combustion like kinetics,turbulence and particle dispersion, and thus the predictionsobtained are qualitative in nature. For better predictions,accurate experimental data determining the chemical reac-

tions kinetics and a set of minimum assumptions must beemployed. Fewer model assumptions can increase computa-tional time many folds, however, with the rapid advance-ment in computing technology, it will be possible in the nearfuture to run detailed combustion codes in a reasonableamount of time.

4.7. Fouling issues in co-firing

Hansen et al. [77] investigated ash deposition in a multi-circulating fluidized bed combustor (MCFBC) fired withfuel blends of coal, wood and straw. The flow rates were650 kg coal, 1640 kg straw, 2330 kg wood chips and 25.8metric ton of air per hour. Fig. 29 is a sketch of the combus-tor. Coal wood blend is injected in the bottom of theMCFBC above the primary air. Secondary air mixed withstraw is introduced above the dense bed. The average bedtemperature was 980 K. Concentrations of alkali metals,sodium and potassium, were measured at six different loca-tions inside the burner as shown in Figs. 30 and 31. Morepotassium than sodium was found at all locations. Morealkali vapors were measured just above the dense bed thanabove the riser section. The authors also developed a semi-empirical model based on thermodynamic equilibriumcalculations to predict stable forms of alkali metals sodiumand potassium. A code (MINGTSYS) was used, which is


Fig. 26. Predicted centerline species profile for 90:10 coal/manure fuel blends using the two- and three-mixture fraction approach [79].

0.40.450.5

0.550.6

0.650.7

0.750.8

0.05 0.1 0.15 0.2

Axial distance (m)

burn

out

coal

Blend_case4

Blend_case3

Fig. 27. Predicted burnout along burner centerline for coal and coal/manure blends [75]. A 90:10 blend was used (Case 3 — reduction insecondary air, Case 4 — increase in fuel flow rate).

based on the concept of Gibbs minimum free energy. In thecalculation, 120 different compounds of C, H, O, N, Cl, Na,K or Si were examined. They found good agreement, exceptin the riser section, where predicted potassium concentra-tions were higher than measured values.

Clearly more studies are needed to understand the foulingmechanism in coal biomass blend combustion. The success-ful implementation of co-firing technology depends uponfinding new ways to mitigate fouling and corrosion asso-ciated with the combustion of biomass fuels. This appar-ently is the most important issue that needs to be addressed.

5. Issues and opportunities

Some of the main issues in the co-firing of coal andbiomass fuel blends are availability, fuel price, high-temperature corrosion, slagging and fouling effects,flame location, size of the biomass particles for suspen-

sion burning in pulverized coal boilers and implementa-tion costs.

1. Fuel availability can be dealt with if ample sourcesare close to the power plant. For example, in Texas,large quantities of feedlot manure are available. InKansas, wheat and corn residues are readily avail-able. Moreover, dedicated energy crops have beengrown in some parts of the United States and Europefor the sole purpose of energy generation.

2. The price of biomass depends on the collection,transportation, drying and grinding processes. Thesecosts need be lower than the primary fuel cost, onenergy basis, in order to obtain a cost advantage.

3. Deposition and high-temperature corrosion are signif-icant concerns to boiler operators. High concentra-tions of potassium and chlorine in biomass cancause serious problems, such as slagging, foulingand corrosion. However, in pulverized fuel boilers,this phenomenon is not observed to the extent thatit is observed in fluidized beds and stoker firedboilers [81] where ash agglomeration is a seriousproblem. It should be noted, however, that thesephenomena require long test times to evaluate theimpact on the combustor performance. Short durationtests (i.e. less than a few hours) may not providemeaningful data on slagging, fouling and corrosionrates.

4. Flame stand-off distance can be altered when blendsare fired in coal burners. In order to have the sameheat throughput, more biomass fuel is fired due to thelower heating value of biomass fuels. This causes theflame to shift downstream in the combustion cham-ber. This shift in flame location may cause flameinstabilities and increase in NOx levels.

5. The maximum size of biomass particle for suspensionfiring varies depending upon the type of fuel. Splieth-off and Hein [6] recommend maximum particle sizes


1500

1600

1700

1800

1900

2000

2100

2200

0.05 0.1 0.15 0.2 0.25 0.3

Axial distance (m)

Tem

pe

ratu

re(K

)

Coal

90:10 Blend_case4

90:10 Blend_case3

Fig. 28. Predicted centerline temperature profiles along burner centerline for coal and coal/manure blends [75]. A 90:10 blend was used (Case 3— reduction in secondary air, Case 4 — increase in fuel flow rate).

Fig. 29. Schematic of MCFBC. R1–R3 and P1–P3 indicatemeasurement locations [77].

of 4 mm for straw and 6 mm for wood. This issueneeds to be addressed further in order to determinethe relationship between particle size, type ofbiomass and the economics of pulverizing the fuel.

6. The implementation costs depend on the class of co-firing desired, the biomass paticle size and the co-firing ratio. If the co-firing percentage is very small,then pre-blended coal and biomass fuels can be firedin existing facilities with very few modifications. Asthe size of biomass particles increases, non-premixed

blends should be used. The biomass can then be co-fired using separate feed lines to avoid clogging.Pulverizer performance is also a factor if more than5% biomass is fired [5]. In this case, a dedicatedbiomass feeding mechanism may be required increas-ing implementation cost.

Although there are still many important issues thatare yet unanswered regarding coal biomass blendcombustion, there are numerous attractive features to


Fig. 30. Measured concentrations of Na and K at locations R1–R3 in the riser section. Measurement locations are shown in Fig. 29.Measurements carried out simultaneously are connected by lines [77].

Fig. 31. Measured concentrations of Na and K at locations P1–P3 in the pre-separator. Measurement locations are shown in Fig. 29.Measurements carried out simultaneously are connected by lines [77].

blend combustion. These opportunities include ad-ditional incentives (such as tax cuts and allowances),reduction in emissions, disposal of waste, jobs in agri-cultural sector (with the cultivation of dedicated energycrops) and low implementation costs.

1. The EPA awards allowances and tax credits to utili-ties who comply with agreed emissions levels. Theallowances and credits offset costs incurred by theutilities in retrofitting and/or buying new equipment.Some states in the US have laws that favor the useof biomass in utilities. In addition to these programs,some states have implemented renewable energycredits requiring specific generation or capacity levelsor other “green power initiatives” [82].

2. A strong motivation for biomass fuel usage comesfrom the fact that gaseous emissions are reducedwhen biomass is fired with coal.

3. Waste disposal is a perennial problem with somebiomass sources, e.g. manure. Co-firing thesebiomass fuels also reduces waste accumulation andattendant soil, water and air pollution.

4. When dedicated energy crops are cultivated to ensurecontinuous supply of biomass fuels to utilities, morejobs will be created in the agriculture sector. Morepeople will be employed and economy may improvein the rural areas.

5. Finally, provided the blend ratio is small and the sizeof the biomass particles is suitable, co-firing im-plementation cost would be very low. If biomassfuel costs are also low, a net profit can be obtainedcompared to coal-only firing.

The future of coal and biomass blend combustion inutility boilers looks very bright. Based on the positiveresults of recent co-firing studies, coupled with morestrict environmental regulations and associated penalties,utilities are seriously considering co-firing locally avail-able biomass fuels with coal in their boilers. TVA, forexample, has a research and development program forco-firing wood residue with coal in utility boilers. DOEand EPRI are actively engaged in co-firing differentbiomass fuels in coal fired boilers. In addition, manysections of the United States have made using a percen-tage of biomass mandatory for electric utilities. Some ofthese states include Connecticut, Massachusetts, Nevada,Maine, California, Colorado, Iowa, Minnesota, NewYork and Wisconsin.

6. Conclusions

Coal and biomass fuels are quite different in composition.Co-firing biomass fuels with coal has the capability toreduce both NOx and SOx levels from existing pulverized-coal fired power plants. In addition, overall CO2 emissions

can be reduced because biomass is a CO2 neutral fuel. Theco-firing programs carried out in the United States (mainlyunder the auspices of DOE and EPRI) and Europe (under theEuropean Union) have demonstrated that co-firing biomasswith coal in large utility boilers can be beneficial to theutilities as well as to the environment. Co-firing may alsoreduce fuel costs, minimize waste and reduce soil and waterpollution depending upon the chemical composition of thebiomass used.

Co-firing technology, however, faces some technologicalproblems. First, the issue of combustor fouling and corro-sion due to the alkaline nature of the biomass ash needsattention. Ash deposits reduce the heat transfer and mayalso result in severe corrosion at high temperatures.Compared to deposits generated during coal combustion,deposits from biomass materials are denser and more diffi-cult to remove. Second, the maximum particle size of agiven biomass that can be fed to and burned in a given PCboiler through a given feeding mechanism requires ad-ditional studies. However, this issue is a combination ofeconomics, and combustion characteristics and more workneeds to be done in this area. Third, practical pulverizerperformance needs to be examined. Biomass fuels mayrequire separate pulverizers to achieve high blend ratiosand good combustion performance. Since biomass fuelshave lower heating value compared to coal, blend flowrate has to be increased in order to have a heat throughputsame as in coal-only case. This increased fuel flow rate maycause the flame to move away from the burner mouth,thereby creating flame stability problem. Lifted flames arealso known to cause higher NOx levels.

Fundamental combustion studies must be performed,particularly for pre-mixed coal and biomass fuel blends, inorder to determine combustion behavior characteristics incontrolled laboratory settings. Interaction between biomassand coal particles during combustion is an area in particularneed of study. The results of this basic research will aid inthe design and optimization of practical coal and biomassblend facilities. Despite all the issues and concerns, coal-biomass blend combustion appears to be a promisingcombustion technology for electric utilities. Co-firing hasmoved from engineering studies to parametric tests tolong-term demonstrations. Future long-term demonstrationswill address many of the issues mentioned above and willhelp in making the co-firing technology easily available tothe industry at an optimal cost.

Acknowledgements

This work was supported by the Advanced TechnologyResearch Program of the State of Texas and the WesternBiomass Regional Program (DOE) through the TexasEngineering Experiment Station at Texas A & MUniversity.


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