Cofiring coal and dairy biomass in a 29 kWt furnace

Applied Energy 86 (2009) 2359–2372

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Applied Energy journal homepage: www.elsevier.com/locate/apenergy

Cofiring coal and dairy biomass in a 29 kWt furnace Ben Lawrence a, Kalyan Annamalai a,*, John M. Sweeten b, Kevin Heflin b a b

MS 3123 TAMU, Texas A&M University, College Station, TX 77843, United States Texas AgrLife Research, TAMU System, 6500 Amarillo Blvd. West, Amarillo, TX 79106, United States

a r t i c l e

i n f o

Article history: Received 17 October 2008 Received in revised form 2 February 2009 Accepted 3 February 2009 Available online 11 April 2009 Keywords: Cofiring Coal Dairy biomass Combustion Emissions

a b s t r a c t Cofiring biomass with fossil fuels is emerging as a viable option for promoting the use of low quality renewable biomass fuels including energy crops. In the current work, dairy biomass (DB) is evaluated as a cofiring fuel with coal in a small scale 29 kWt boiler burner facility. Two types of coal (Texas lignite, TXL and Wyoming Powder River Basin coal, WYO) and two forms of partially composted DB fuels were investigated (low ash separated solids LA-PC-SepSol-DB and high ash soil surface HA-PC-SoilSurf-DB). Proximate and ultimate analyses performed on both coals and both DBs reveal the following: higher heating value (HHV) of 28,460–29,590 kJ/kg for dry ash free (DAF) coals and 21,450 kJ/kg for DB; nitrogen loading of 0.36 and 0.48 kg/GJ for WYO and TXL, respectively and 1.50 and 2.67 kg/GJ for the LA-PC-SepSol-DB and the HA-PC-SoilSurf-DB respectively; sulfur loading of 0.15 and 0.42 kg/GJ WYO and TXL, respectively and 0.33 and 0.43 kg/GJ for the LA-PC-SepSol-DB and the HA-PC-SoilSurf-DB respectively; ash loading from 3.10 to 8.02 kg/GJ for the coals and from 11.57 to 139 kg/GJ for the DB fuels. The cofiring experiments were performed with 90:10 and 80:20 and 100:00 (mass%) coal:DB blend (96:4, 92:8, 100:00 – % on heat basis). The results revealed that the blend burns more completely in the boiler, due to the earlier release of biomass volatiles and higher amount of volatile matter. Results were obtained for burnt fraction, NOx and CO emission. Pure TXL produced 1505 ppm of CO at an equivalence ratio of 1.1. An 80:20 blend of TXL:LA-PC-SepSol-DB produced 4084 ppm of CO at the same equivalence ratio. The NOx emissions for equivalence ratio varying from 0.9 to 1.2 ranged from 0.4 to 0.13 kg/GJ for pure TXL coal. The corresponding NOx emissions are 0.8–0.10 kg/GJ for pure WYO coal. For 80:20 TXL:LA-SepS-DB blend they ranged from 0.375 to 0.05 kg/GJ over the same range. In general, the blends produced less NOx than pure coal under rich conditions even though the DB contained more nitrogen. This result is probably due to the fuel bound nitrogen in dairy biomass is mostly in the form of urea which reduces NOx to N2. Ó 2009 Elsevier Ltd. All rights reserved.

1. Introduction Large coal fired plants produce almost 310 GW of electricity requiring almost 930 GW of thermal energy input. Cofiring, a cost effective method in reducing fossil fuel costs and in promoting the use of alternate fuels, is defined as combustion of two dissimilar fuels. The cofiring which can provide up to 15% of heat input has been successfully demonstrated over 150 installations world wide [1]. Boiler efficiency has not suffered when the share of cofired fuel is of the order 5–10%. The biomass fuels can be fired by (i) premixing of the two solid fuels (such as done in these experiments) when biomass contributes <10% of the total heat input (ii) by firing coal in central fuel nozzle with biomass in the coaxial nozzle) and (iii) firing biomass separately (a single boiler when heat input is more

* Corresponding author. Tel.: +1 979 845 2562; fax: +1 979 845 3081. E-mail addresses: [email protected] (B. Lawrence), kannamalai@ tamu.edu (K. Annamalai), [email protected] (J.M. Sweeten), k-hefl[email protected] (K. Heflin). 0306-2619/$ - see front matter Ó 2009 Elsevier Ltd. All rights reserved. doi:10.1016/j.apenergy.2009.02.003

than 10% but less desirable because of complexities in tuning up the air) in a single boiler [2]. The biomass, a renewable fuel supplement to coal in boilers, can be classified as: agriculture based biomass (AgB) and animal waste based biomass fuels (AnB). Typically coal is milled to a fine powder and fired in a suspension fired boiler and hence there is expectation by the utilities that the biomass needs to be ground to similar size. It is noted that the use of biomass itself directly does not reduce CO2 per MJ as seen in Fig. 1 constructed with use of Boie equation (see Table 1 footnote) [1]; the direct emissions of CO2 in g/MJ (or kg/GJ) from coal and biomass are similar even though the H/C ratio is higher for biomass than that for coal. CO2 emissions are the same for coal and biomass because both have similar carbon loading on per unit heat basis. Higher H/C implies lower C and hence lower CO2 on a mass basis. However, it is seen that biomass has a higher O/C ratio which lowers the heat value. Hence, the emission of CO2 on a heat basis is normally similar. The advantages of cofiring with biomass are reduction of fuel and capital cost, CO2 reduction due to renewable nature of fuel and NOx reduction when low nitrogen AgB fuels

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200 180 160

CO2, g/MJ

140

O/C=1 0.8 0.6 0.4 Coal Biomass 0.2

120 100

CO2 released during fermentation

Corn grain

0

Methanol Methanol, actual

80 Carbon

60

Ethanol

40

Methane

20 0 0

0.5

1

1.5

2

2.5

3

3.5

4

4.5

H/C Fig. 1. Chart for estimation of CO2 in g/MJ (=kg/GJ) for C–H–O fuels (for lb/mmBTU multiply ordinate by 2.33).

which typically contain low nitrogen%. The issues are typically stated to be: nitrogen content, fouling potential, catalytic components if any of cofired fuel. Most of the early research has been concentrated in the area of AgB which contain low nitrogen (exception Alfalfa, rice hulls), and sulfur. The current paper deals with cofiring of high nitrogen AnB fuels. Intensive animal feeding operations (dairy and cattle farms) are the corner stones of the agricultural economy in Texas and neighboring states in the Southern Great Plains. These operations create large amounts of animal waste that must be safely disposed of in

order to avoid environmental degradation. Potentially harvestable biomass from cattle farms from all of the confined feeding operations in the US easily exceeds 100 million tons per year on a dry basis and 6–12 million dry tons in the Texas Panhandle alone. If cattle manure is not beneficially utilized as fertilizer or properly disposed of, these by-products may become sources of air, water, or soil pollution along with global warming CH4 gas emission in farm areas of United States, including the Southern Great Plains. When the cattle biomass gets very dry, the cattle’s feet grind the dry manure, creating a dust emission (particulate matter, PM: from 8.5 to 12 lm). Total suspended particles in feedlot dust can range from 150 lg/m3 to 400 lg/m3 [3]. The PM 10 regulation requires the concentration of particles from CAFOs less than 10 lm should be less than 150 lg/m3. Cattle manure, produced from undigested ration, could be used as a fuel by mixing it with coal and firing it in an existing coal suspension fired combustion systems. Thus cattle manure will be henceforth termed as cattle biomass (CB). The CB fuels are higher in ash, lower in heat content, higher in moisture, and higher in nitrogen and sulfur (which can cause air pollution) compared to coal. This work is focused on studying the effects of cofiring coal with dairy biomass (DB) containing high amount of nitrogen compared to coal and determine the comparative performance of burner when fired with coal and then with blend of coal:DB. 2. Background and literature review Dairy cattle, each animal, having a live weight between 544 kg (1200 lb) and 907 kg (2000 lb), produce between 27 kg (60 lb) and 54 kg (125 lb) of wet manure (7–15% of body weight) per day per animal (Fig. 2). This manure contains 85–90% moisture and 10– 15% solids (including volatile matter, nutrients, ash and combustibles) [4].

Table 1 Fuel properties (compare with natural gas: 55,000 kJ/kg).

Ash Dry loss (% moisture) FC VM Carbon, C Hydrogen, H Nitrogen, N Oxygen, O (diff) Sulfur, S Empirical formulae CO2 max, mol% HHV, kJ/kg as received (BTU/lb) HHV, kJ/kg dry (BTU/lb) HHV, kJ/kg DAF (BTUlb) HHV, kJ/kg of stoich air (BTU/lb) Boie HHV, kJ/kg (BTU/lb) VM, HHV, kJ/kg (BTU/lb) VM heat contr, % A:F AR A:F DAF FC DAF VM DAF Ash kg/GJ HV of VM Heat% by VM Nitrogen kg/GJ (lb/mmBTU) Sulfur kg/GJ (lb/mmBTU) SMD (lm) from sieve analysis SMD (lm) from Rosin-Rammler distribution

HA-PC-DB-SoilS

LA-PC-DB-SepS

TXL

WYO

59.89 12.21 3.92 23.99 18.04 1.45 1.15 7.07 0.19 CH0.96N0.055 O0.29S0.0039 19.36 4312(1854) 4911(2111) 15,452(6643) 1931(830) 7340(3156) 12,625(5429) 81.7 2.23 8.11 14.04 85.96 138.90 12,624 70 2.67(6.21) 0.43(1.00) 84.69 70.86

14.86 25.26 13.00 46.88 35.21 3.71 1.93 18.60 0.43 CH1.25N0.047 O0.40S0.0046 18.93 12,844(5522) 17,186(7389) 21,450(9222) 2886(1241) 14,799(6362) 18,312(7874) 66.8 4.45 7.44 21.72 78.28 11.57 18,310 67 1.50(3.49) 0.33(0.768) 88.84 98.80

11.46 38.34 25.41 24.79 37.18 2.12 0.68 9.61 0.61 CH0.68N0.016 O0.19S0.0061 19.66 14,287(6142) 23,169(9961) 28,460(12,236) 3156(1357) 14,582(6269) 24,046(10,340) 41.7 4.53 8.77 50.62 49.38 8.02 24,046 42 0.48(1.12) 0.42(0.977) 94.72 88.88

5.64 32.88 32.99 28.49 46.52 2.73 0.66 11.29 0.27 CH0.70N0.012 O0.18S0.0022 18,193(7822) 27,107(11,654) 29,593(12,723) 3192(1372) 18,348(7888) 25,916(11,144) 40.6 5.70 9.22 53.66 46.34 3.10 25,921 41 0.36(0.837) 0.15(0.349) 114.17 100.95

Computed using Boie equation (Annamalai et al. 1987): HHV(kJ  kg1) = 35,160  YC + 116,225  YH  11,090  YO + 6280  YN + 10,465  YS, where YC, mass fraction of element carbon in fuel.

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Fig. 2. Cattle feed life cycle (adapted from www.dpi.qld.gov.au/environment/5166.html).

The DB fuel properties (chiefly ash content) depend greatly on the collection technique used when the manure is gathered from the dairy. Most dairies have a soil base with an interfacial layer which consists of mixed soil and manure. If the manure is not harvested carefully some of the interfacial layer will be disturbed and collected with the manure as in the case of FB. This leads to higher ash content in the manure. Collection techniques for DB are similar to FB when one of the following methods is used: wheel loader alone, chisel-plow followed by wheel loader, or box scraper [4]. For dairy cattle (milking herd) housed on concrete-floored milking house, fresh manure is collected by flushing the milking house floor with water or scraping the manure or using a vacuuming technique. This manure does not contain soil. The flushed solids– water slurry (95% water, 5% solids containing combustibles ash) is then passed through a mechanical separator to separate the solids (called separated solids, SS) and liquids. This separated liquid containing approximately 3–6% solids can then be used as lagoon water. The SS, still containing 80% water, can be used as a fuel [5]. Tillman [6] cofired coal with low nitrogen AgB and showed that NOx can be reduced by cofiring; thus NOx was reduced simply by reducing the nitrogen loading to the furnace. However reported the amount of NOx reduction (measured trend line) was greater than expected based on theoretical data from the authors. The NOx reduction cannot be explained solely by reduced nitrogen loading (Fig. 3). It is hypothesized by the current authors that the increased volatile matter of AgB under cofiring conditions resulted in increased volatiles release and hence rapid reduction of O2 which reduces the rate of formation of NOx from fuel nitrogen. Lundgren [7] studied using horse manure from ranches for on site heat production. He found that the horse manure could be effectively disposed of through firing in a small stoker burner and the heat released could be used for on site applications. Lund-

gren reported 370 mg/m3 of NOx (approximately 324 ppm assuming that 370 mg refers to NO) at 10% excess O2. However no data was presented under slightly rich combustion conditions. Miller et al. [8] showed that dairy biomass had 14 times more moisture compared to coal on an as received basis. On a dry basis, the dairy biomass had 1.25 times more volatile matter and 4.25 times more ash than coal. The coal had 8 times more fixed carbon than the dairy biomass on an as received basis. Di Nola [9] used an FTIR instrument to measure the concentrations of HCN and NH3 in the early flame stages of coal and coal:litter biomass blends. His work showed that coal alone can produce upwards of 700 ppm of HCN and approximately 80 ppm of NH3. The results show that when 20% by mass litter biomass by mass was blended with the coal, HCN decreased to approximately 250 ppm and NH3 increased to approximately 200 ppm. However no data on HCN and NH3 were presented for pure litter biomass (LB). Using the linearity rule, the present authors estimate that the LB can produce no HCN and 680 ppm NH3. So, it is apparent that LB fuel contains more nitrogen in the form of NH3 (which is a good agent for reducing NOx) and less nitrogen in the form of HCN. The nitrogen in animal waste originates from urea. Thus, cofiring coal with DB has the potential to reduce the formation of NOx. A comprehensive literature review on cofiring of coal with agricultural and animal waste based biomass fuels was undertaken earlier and the review article was published in 2001 [10]; Previous work [11–17] was concerned with cofiring coal with feedlot biomass (FB). However information about cofiring coal with dairy biomass is relatively sparse in the current literature. The specific topic of cofiring coal with DB is relatively sparse in the current literature. The diet fed to dairy animals is different compared to feedlot animals to enhance the milk production over beef production.

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Fig. 3. Synergistic NOx reduction from cofiring biomass. Adapted from [6].

3. Objective It is apparent from literature review that there is no prior data on the effect of cofiring low quality and high nitrogen DB on the combustion and emission characteristics. Hence, the objective of the current work is to determine the combustion and emission performance of pure coal and coal:DB blends using a small scale boiler (29 kWt) burner facility. 4. Experiments 4.1. Experiment facility The current boiler burner facility (Texas A&M University, thermal rating of 29 kWt (100,000 Btu/h)) for firing either coal or coal:feedlot biomass fuel blends is shown in Fig. 4. The main furnace is 0.1524 m (6 in.) in diameter, and is made of a 0.0508 m (2 in.) silica ceramic shell surrounded by a 0.0508 m (2 in.) thick silica fiber blanket and a 6.35 mm (0.25 in.) steel shell. Along the walls of the furnace there were several gas sampling ports and temperature measurements ports located 15.24 cm (6 in.) apart. Dual water jets (8) injected water into the boiler to catch particulates and to cool hot gas stream and then the colder exhaust gases vented out through an exhaust system. The cooling water is drained off into a sump. The combustion air was supplied to the boiler burner by a secondary air compressor. The secondary air (80–90% of total air) was preheated to a minimum of 473.15 K (392 °F) with the use of a circulation heater (720 W (2456.7 Btu/h)) before it entered the boiler through a swirler. The pre-heat temperature was varied to better control the maximum furnace temperature. Secondary air is injected co-axially with the primary air and the fuel but with a swirl motion. The formula suggested by [16] was used to obtain a swirl number of 0.7 for this burner. In addition to the swirler, a ceramic diffuser, or quarl is used to stabilize the flame. The quarl is made of silica ceramic and has an l/d ratio of 1.8 and a half angle of 24°. The fuel feed system is a commercial volumetric feeding system, accurate to within 2% for samples taken over a 1-min interval. The primary air transports the fine fuel suspension injected

through a Venturi valve into the quarl of the boiler burner. The entire facility was operated from a central control panel. The burner was fitted with two propane torches, which serve to preheat the boiler and initiate combustion. Once the coal flow started, the torch was turned off. Primary air was provided from a compressed air line and was used to carry solid fuel to the burner nozzle. The amount of primary air was dictated by the feeder and was constant at 5.95 m3/ h (15–25% of total air). However, secondary air (75–85% of total air) was provider by a separate compressed air line and could be adjusted to change the equivalence ratio at constant fuel feed rate so that the thermal rating is kept constant. Combustion any leaner than equivalence ratio of 0.8 created a heavy strain on the compressor and hence lowest equivalence ratio was set at 0.8. 4.2. Procedure The secondary air heater was run for an hour before the experiment was started. Once the secondary air reached a steady temperature approximately 500 K (440.33 °F) the propane torches were ignited. Natural gas and propane were used to preheat the furnace to operating temperatures. Approximately 40 L/min of natural gas were fired for about 180 min in the furnace with the flame kept near stoichiometric. Once the furnace reached 1366 K (2000 °F), the natural gas was turned off and the natural gas line was closed. The solid feeder line was opened and the solid feeder was turned on and set to the desired fuel flow rate. The primary and secondary air lines were set to the appropriate flow rates to obtain the desired equivalence ratio. The furnace was allowed to run for 30 min before the first readings were taken. After 75 min of firing fuel, additional fuel was added to the hopper. The measurement was taken at the last sampling port just before the quenching water sprays and the wet flue gases were ducted to the atmosphere. After taking a measurement at this equivalence ratio, the secondary air could be adjusted to a different equivalence ratio. After taking measurements at all desired equivalence ratios, the furnace was turned off. To turn of the furnace, the fuel feeder was turned off and the primary air line was closed. The secondary air was cut back to 200 L/min and the view port windows were

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Fig. 4. Experimental facility.

opened to cool the furnace. Cooling the furnace required approximately 4 h. 4.3. Diagnostics Primary air flow measurements were made using volumetric flow meters. Two flow meters were used, one for motive air and one for eductor air. Each flow meter was calibrated to be accurate in the range of 20–200 SCFH of air with an accuracy of ±5 SCFH. Secondary air was measured using a digital gas mass flow controller. The flow meter was calibrated to be accurate in the range of 0– 1000 SLPM of air with an accuracy of ±1.5% FS of the flow. The temperature profile along the axial length of the furnace was measured by 12 type K (shielded, ungrounded) thermocouples in the boiler and type S thermocouples in the secondary air stream. Flue gas concentrations were measured using an portable flue gas analyzer capable of measuring CO, CO2, NOx, SO2, and O2 in a flue gas stream. The analyzer uses electrochemical cells to detect flue gases in low range applications and NDIR in middle range applications. The probe also contained a type K thermocouple mounted at the tip for temperature measurements. 5. Results and discussion 5.1. Fuels TXL was used as the base case fuel. TXL and WYO were fired alone and as blends with two DB fuels. Each coal was blended with each DB fuel in 100–0, 95–5, 90–10, and 80–20 blends on a mass basis. This created 14 different fuel blends. For each blended fuel, the equivalence ratio was varied from 0.8 to 1.2 in 0.1 increments.

The 80–20 blends were too rich in DB to be used in industrial applications, but were used in order to get more data points for the study. In the rich regime (equivalence ratio > 1.0) the high ash soil surface dairy biomass quickly clogged the sampling port due to high ash content. Thus, a full set of data points could not be generated. In order to compare the performance at same thermal output, the coal: biomass blends needed to be fired at higher feed rate due to lower heat value of DB. 5.1.1. Fuel preparation The cofiring approach in existing suspension fired burners requires grinding of high ash, high moisture, and heterogeneous biomass almost to the same fineness as coal. High moisture and fibrous nature of biomass created grinding difficulties. Thus the biomass fuels were composted for 90 days in a greenhouse [17] to provide more homogeneity and to reduce the moisture. Hence both of the biomass fuels had less moisture than either of the coals. 5.1.2. Fuel properties All fuel samples used in cofiring tests were analyzed by Hazen Laboratories in Colorado for ultimate, proximate, and heat analyses. Table 1 presents the results of fuel analyses and derived fuel properties. Note that the DB fuels are much higher in nitrogen than coal fuels. This is different from most AgB fuels (e.g. saw dust, corn stalks, switch grass, nut shells, rice hulls, etc.) which are lower in nitrogen than coal. Manure based biomass is the exception to this generality. The ash in high ash, partially composted, soil surface, dairy biomass (HA-PC-SoilSurf-DB) was more than 10 times that of Wyoming Powder River Basin coal. The heat values of HA-PCSoilSurf–DB are unreliable due to very high ash content. The experiments with coal (Texas lignite and Wyoming coal): high ash soil

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surface dairy biomass blends were mostly unsuccessful due to excessive amounts of particulate matter (mostly ash) clogging the flue gas analyzer. The SMD’s were calculated based on the sieve analyses as well as using a Rosin-Rammler plot and they are presented in Table 1. Low ash, partially composted, separated solids, dairy biomass (LA-PC-SepSol-DB) was almost three times richer in nitrogen than Wyoming Powder River Basin coal. Although, low ash separated solids dairy biomass was more than four times lower in ash than high ash soil surface dairy biomass, it was still higher in ash than either coal. On a dry ash free basis, the dairy biomass fuels contained almost twice the volatile matter of coal, and hence less fixed carbon. Since HHV of DAF fuel is approximately given as:

HHVDAF  VMDAF  HHVVM þ FCDAF  HVFC where HHV DAF is the dry ash free higher heating value, FCDAF = 1  VMDAF, HVFC = 32,806 kJ/kg of C, the HVVM can be estimated; the% heat contribution by VM is then computed using the relation:% heat by

VM ¼ HHVDAF ¼ fVMDAF  HHVVM g  100=HHVDAF It is seen from Table 1 that even though the VM% is higher by twice the amount of VM of coal, the heat% contribution is not twice that of coal due to lower HV of VM from DB. On a heat basis, the DB fuels had higher nitrogen contents than coal. The TGA experiments revealed that 10% mass loss rate for dry DB occurs at 553 K while it occurs at 685 K for WYC indicating that pyrolysis occurs at lower temperature compared to coal [18]. It is apparent that the DB released VM at lower temperature compared to TXL and WYO. 5.2. Exhaust O2 analysis The air fuel ratio (A:F), and hence the equivalence ratio (/), can _ A ) and the calibe estimated from measured flow rates of air (m _ F ). Equivalence ratio can also be computed brated fuel flow rate (m using the measured O2 or CO2% in the exhaust for lean mixtures. For any C–H–O fuel, the equivalence ratio based on flue gas analysis can be derived to be [19,20]

X O2 ðN2 =O2 ÞA X N2

ð1aÞ

1 Coal 0.9

A

2

uflue  1 

X O2 ; X O2 ;A

/ < 1:0

ð1bÞ

where X O2 is the measured mole fraction of oxygen in the flue gases (dry basis), and X O2 ;A is the mole fraction of oxygen in the ambient air (dry basis). X O2 ;A is typically 0.21. Eq. (1) states that when X O2 is maintained same when switching fuels, the equivalence ratio and hence excess air% remains the same. Similar derivation can be performed for any CHOS and shown that

XCO2 =XCO2 max ¼ ½1  XO2 f1 þ ðN2 =O2 ÞA g ¼ ½1  ð1  /ÞXN2 fðO2 =N2 ÞA þ 1g

Methane

y = -0.0084x + 1.0119 R2 = 0.9602

0.7 0.6 0.5 0.4 0.3 0.2 0.1 0

0

0.5

1

1.5

ð2Þ

where X CO2 max is maximum CO2 dry mole fraction under stoichiometric condition. Note that the use of Eq. (2) requires a knowledge of composition of fuel for calculating X CO2 ;max while O2% method does not. The above equations (Eqs. (1a) and (2)) are also applicable to CHNOS fuels when N is in trace amounts in the fuel (e.g. coal, DB, etc.). It is seen that use of (1b) reduces to (2). The above approximation has been checked C–H–O fuels for 0, 10%, 20% excess air and the fit for ½X CO2 =fX CO2  /g is almost independent of O/C and H/C and ½X CO2 =fX CO2  /g  1 for O/C ranging from 0 to 1 and H/C ranging from 0 to 4 (Fig. 5). Eq. (1b) is used to estimate /flue rather than Eq. (2) since it does not require a knowledge of fuel composition. When burnt fraction less than 1, the measured O2 percentage will increase which will cause the equivalence ratio based on flue gases to be artificially lean. Fig. 6 plots the /flue computed from flue gas analysis versus the /flow computed from measured air and fuel flow rates. For both TXL and WYC. Ideally, the data points would follow a 45 degree line (solid line in Fig. 6, indicating /flue and /flow were in perfect agreement. If data points fall below the indicated line, this will indicate burnt fraction <1; however, figure shows that data points fall on both sides. In all future plots, unless otherwise indicated, the subscript ‘‘flow” will be omitted and hence / represents the equivalence ra-

O/C=1,pi=0.8 O/C=0,pi=0.9 Biomass

0.8

CO2/(pi*CO2max)

/fuel ¼ 1 

where Xk, mole fraction of species k in dry products under complete combustion and (N2/O2)A the N2:O2 mole ratio in supplied gas. Eq. (1a) is also applicable to CHNOS fuels as long as N in fuel exists in trace amounts (ex. coal,  DB). If X N2  X N2 ;A , ambient air mole fracX O ;A tion and with X N2 ;A ¼ NO22

2

2.5

3

3.5

H/C atom Ratio Fig. 5. The CO2, CO2 max and / (inverse of stoichiometric ratio) relation for various fuels.

4

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A:F φ vs. Exhaust φ TXL 80-20 TXL:LA-PC-DB-SepS WYO 80-20 WYO:LA-PC-DB-SepS

5.3. Burnt fraction

90-10 TXL:LA-PC-DB-SepS Ideal Line 90-10 WYO:LA-PC-DB-SepS

1.1

Eq. (1a) assumes complete combustion or BF being equal to 1. If burnt fraction is less than 1, then /flue based on exhaust gas analysis will be lower than the true value since less O2 is used by lesser amount of fuel being burnt. When BF < 1 (ex: rich mixtures), then one can modify expression (1a) for any C–H–O–S fuel as

1

Oxygen stoich for burnt fuel Oxygen sup p Oxygen stoich for sup p fuel  BF ¼ ¼ /  BF Oxygen sup p X O2 ðN2 =O2 ÞGas sup p ¼1 X N2

φ Flue

/flue ¼

0.9

1

0.8

X  

0.7 0.7

0.8

0.9 φ Flow

1

1.1

Fig. 6. Equivalence ratio based on air flow rates and the calibrated fuel flow rate vs. equivalence ratio based on O2% in exhaust.

tio based on measured air flow rates and the calibrated fuel flow rate. Due to limitations of the feeder, only average flow rates could be measured. The next section computes the burnt fraction (BF) using flue gas analysis and supplied equivalence ratio.

O2

XN

2

/¼

N2 O2

Gas sup p

ð3aÞ

BF

where BF is the burnt fraction, / is the measured equivalence ratio from flow rates. The above equation is equally applicable for C–H– N–O–S fuels when nitrogen is in trace amounts. As before

1 BF   /

X O2 1 X O2;A

! ð3bÞ

When mixture is rich, there should be no oxygen left in products if fuel is burnt completely; but oxygen could be still present when the fuel is not burnt completely. Figs. 7 and 8 present the BF for TXL and DB blended fuels and WYO and DB blended fuels, respectively. Even in the very rich combustion (/ = 1.2), approximately 83% of the fuel was burnt. Even though DB is a low quality fuel, the VM is almost 80% on DAF (Table 1) and hence BF is comparable to pure coal. It is

Burnt/Gasification Fraction vs. Equivalence Ratio for TXL and TXL:DB Blended Fuels TXL

90-10 TXL:LA-PC-DB-SepS

80-20 TXL:LA-PC-DB-SepS

1.20

Burnt/Gasification Fraction

1.00

0.80

0.60

0.40

0.20

0.00 0.7

0.8

0.9

1

1.1

1.2

1.3

φ Fig. 7. Effect of fuel on BF for TXL and TXL:DB blended fuels. Note that in the rich regime, the BF overlaps for all fuels. This indicates that the same percentage of all fuels was burnt.

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Burnt/Gasification Fraction vs. Equivalence Ratio for WYO and WYO:DB Blended Fuels WYO

90-10 WYO:LA-PC-DB-SepS

80-20 WYO:LA-PC-DB-SepS

1.20

Burnt/Gasification Fraction

1.00

0.80

0.60

0.40

0.20

0.00 0.7

0.8

0.9

1

1.1

1.2

1.3

φ Fig. 8. Effect of fuel on BF for WYO and WYO:DB blended fuels. Note that the data points come close to overlapping for all equivalence ratios. Thus, BF was independent of fuel type.

seen that BF is larger than 1 for a few extremely lean experiments. These values demonstrate the limitations of Eq. (3) as well as experimental uncertainties including fuel compositions since / requires prior knowledge of stoichiometry of the burnt

fuel and hence on the average fuel composition. But the general trend shows decreasing burnt fraction with increase in equivalence ratio.

Effect of Fuel on NOx (ppm) for TXL and TXL:DB Blended Fuels TXL

95-5 TXL:LA-PC-DB-SepS

90-10 TXL:LA-PC-DB-SepS

80-20 TXL:LA-PC-DB-SepS

900

800

700

NO x (ppm)

600

500

400

300

200

100

0 0.7

0.8

0.9

1

1.1

1.2

1.3

φ Fig. 9. Effect of fuel on NOx for TXL and TXL:DB fuels. Note that blended fuels have lower NOx values at stoichiometric and in rich combustion.

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5.4. NOx emissions Figs. 9 and 10 present the NOx emissions for TXL and DB blended fuels in ppm and on a heat basis (kg of NO2/GJ). All of the blended fuels produced more NOx in the lean region than the pure TXL in kg/GJ. This is due to the higher amount of fuel

bound nitrogen present in the biomass binding with the excess oxygen to form NOx. But, in the slightly rich region, the blended fuels produced less NOx than the pure TXL. This is due to the fuel bound nitrogen being forced to form molecular nitrogen compounds due to the deficiency in oxygen and high amount of volatile matter in DB oxidizing rapidly in reducing

Effect of Fuel on NOx for TXL and TXL:DB Blended Fuels TXL

95-5 TXL:LA-PC-DB-SepS

90-10 TXL:LA-PC-DB-SepS

80-20 TXL:LA-PC-DB-SepS

0.5 0.5 0.4

NOx (kg/GJ)

0.4 0.3 0.3 0.2 0.2 0.1 0.1 0.0 0.7

0.8

0.9

1

1.1

1.2

1.3

φ Fig. 10. Effect of fuel on NOx for TXL and TXL:DB blended fuels in kg/GJ.

Effect of Fuel on NOx for WYO and WYO:DB Blended Fuels WYO

95-5 WYO:LA-PC-DB-SepS

90-10 WYO:LA-PC-DB-SepS

80-20 WYO:LA-PC-DB-SepS

1200

1000

NOx (ppm)

800

600

400

200

0 0.7

0.8

0.9

1

1.1

1.2

φ Fig. 11. Effect of fuel on NOx for WYO and WYO:DB fuels. Note how NOx decreases in the near lean region for blended fuels.

1.3

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Effect of Fuel on NOx for WYO and WYO:DB Blended Fuels WYO

95-5 WYO:LA-PC-DB-SepS

90-10 WYO:LA-PC-DB-SepS

80-20 WYO:LA-PC-DB-SepS

1.4

1.2

NOx (kg/GJ)

1.0

0.8

0.6

0.4

0.2

0.0 0.7

0.8

0.9

1

1.1

1.2

1.3

φ Fig. 12. Effect of fuel on NOx for WYO and WYO:DB blended fuels in kg/GJ.

available oxygen which otherwise the might bind with nitrogen to NOx. Figs. 11 and 12 present the NOx emissions from WYO coal and DB blended fuels in ppm and in kg/GJ based on the mass of NO2.

5.5. Fuel nitrogen conversion efficiency The nitrogen conversion efficiency is defined as the amount of fuel nitrogen that gets converted to NOx. Overall fuel nitrogen conversion efficiency can be approximated by [19]:

Fuel Nitrogen Conversion Efficiency for TXL and TXL:DB Blended Fuels TXL

95-5 TXL:LA-PC-DBSepS

90-10 TXL:LA-PC-DBSepS

80-20 TXL:LA-PC-DBSepS

25

Conversion Efficiency (%)

20

15

10

5

0 0.7

0.8

0.9

1

1.1

1.2

1.3

φ

Fig. 13. Effect of fuel on nitrogen conversion for TXL and TXL:DB blended fuels. Note that the conversion efficiency is less than coal for almost all TXL:DB blended fuels.

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Fuel Nitrogen Conversion Efficiency for WYO and WYO:DB Blended Fuels WYO

95-5 WYO:LA-PC-DBSepS

90-10 WYO:LA-PC-DBSepS

80-20 WYO:LA-PC-DBSepS

35

Conversion Efficiency (%)

30

25

20

15

10

5

0 0.7

0.8

0.9

1.0

1.1

1.2

1.3

φ Fig. 14. Effect of fuel on nitrogen conversion efficiency for WYO and WYO:DB blended fuels. Note that the conversion efficiency is less than coal for almost all WYO:DB blended fuels.

Effect of Fuel on CO2 for TXL and TXL:DB Blended Fuels TXL

90-10 TXL:LA-PC-DB-SepS

80-20 TXL:LA-PC-DB-SepS

23 22 21

CO2 (%)

20 19 18 17 16 15 0.7

0.8

0.9

1 φ

1.1

1.2

1.3

Fig. 15. Effect of fuel on CO2 for TXL and TXL:DB blended fuels.

NCONV 

ðc=nÞ  X NO X CO2 þ X CO

ð4Þ

where c/n is the atom ratio of the carbon to nitrogen (see Table 1), XNO is the mole fraction of NOx, X CO2 is the mole fraction of CO2, and XCO is the mole fraction of CO. Typically in coal fired boilers, fuel NOx forms more than 80% of NOx. Thus the Eq. (4) assumes that all NOx originates from fuel nitrogen and hence it presents an upper bound on fuel nitrogen conversion efficiency. This approximation is

justified in view of the fact that the furnace temperatures are less than the temperature (1500 K) above which thermal NOx becomes significant. Figs. 13 and 14 show the results for TXL:DB and WYO:DB blends. As equivalence ratio increased, less nitrogen was converted to NOx. Further the dairy biomass blended fuels converted less nitrogen to NOx compared to coal. It is noted that the nitrogen percentage increased from 0.66% for pure WYO to 0.91% for 80:20 WYO:DB blend. The NOx does not increase by same% as revealed by lower conversion efficiency; partic-

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ularly the conversion efficiency for the 80:20 blends is the lowest. There are two effects. The blend has higher amount of VM which reduces the local oxygen concentration and lowers the NOX while fuel N is increased in the blend. It is well known that the oxygen effect on fuel NOx is dominant and hence the nitrogen conversion efficiency is lowered.

In nitrogen containing solid fuel combustion, the majority of NOx comes from fuel bound nitrogen bonding with available oxygen to form NOx, called fuel NOx. The NOx reaction rate is reduced when carbon radicals bond with available oxygen to form CO and CO2. The largest decrease in conversion occurred when

Effect of Fuel on CO for TXL and TXL:DB Blended Fuels TXL

90-10 TXL:LA-PC-DB-SepS

80-20 TXL:LA-PC-DB-SepS

14000

12000

CO (ppm)

10000

8000

6000

4000

2000

0 0.7

0.8

0.9

1.0

1.1

1.2

1.3

φ Fig. 16. Effect of fuel on CO for TXL and TXL:DB fuels.

CO2 for WYO and WYO:DB Blended Fuels WYO

90-10 WYO:LA-PC-DB-SepS

80-20 WYO:LA-PC-DB-SepS

23

22

21

CO2 (%)

20

19

18

17

16

15 0.7

0.8

0.9

1.0

1.1

φ Fig. 17. Effect of fuel on CO2 for WYO and WYO:DB blended fuels.

1.2

1.3

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Effect of Fuel on CO for WYO and WYO:DB Blended Fuels WYO

90-10 WYO:LA-PC-DB-SepS

80-20 WYO:LA-PC-DB-SepS

14000

12000

CO (ppm)

10000

8000

6000

4000

2000

0 0.7

0.8

0.9

1.0

1.1

1.2

1.3

φ Fig. 18. Effect of fuel on CO for WYO and WYO:DB fuels.

the furnace operation went from stoichiometric to rich with conversion efficiency as low as 2%. 5.6. CO2 and CO emissions Recall that the BF relations presume that CO% is negligible compared to CO2% when computing the BF in the lean regime. Figs. 15 and 16 show the results for CO2 and CO% for pure TXL and TXL: DB blends while Figs. 17 and 18 show the results for pure WYO and WYO:DB blends. In general the WYO had higher CO compared to the TXL essentially due to the larger SMD for WYO (114 lm) compared to TXL (95 lm) and as such the CO from the TXL released much earlier and had time to oxidize. At almost identical sizes (TXL and LA-PC-DB), the blends of TXL:DB produced more CO compared to pure TXL. The CO is less than 5000 ppm (0.5%) while CO2 is of the order of 19.5–21.0%, and hence the assumption of negligible CO is justified. The trends for CO and CO2 are similar for both fuel blends. In lean combustion, there is sufficient oxygen for all the carbon to fully oxidize to CO2 and hence very little CO was formed in the lean regime. However, once combustion became oxygen deficient (rich) CO begins to be formed. In general, the blended fuels produced more CO because the dairy biomass fuels contained more oxygen (see Table 1). It is apparent that CO2 peaked at approximately the stoichiometric condition. As air flow was increased from the stoichiometric point, the excess air in the lean regime resulting in decreased the CO2%. On the other hand, if air flow was decreased below the stoichiometric air flow rate, less CO2 was formed due to insufficient O2 to fully oxidize fuel bound carbon and hence more CO was formed (Figs. 16 and 18). This explains why the peak in CO2 was at approximately stoichiometric. 6. Summary and conclusions 1. Dairy biomass had lower heat value due to less fixed carbon, more oxygen, more fuel bound nitrogen, and more ash. On DAF basis, the dairy biomass has 60% of the heat value of coal.

2. The dairy biomass contained higher VM (46.88%) compared to coal (28.49%), but the VM from dairy biomass contributes 65% of heat while coals contributes 40% heat. Hence dairy biomass can be successfully blended with coal and cofired in a furnace even though the heat value of fuel is lower. 3. Burnt fraction was independent of fuel type. Burnt fraction was almost unity when operating near stoichiometric. 4. Cofiring increased NOx in lean combustion, however; NOx was reduced to a very low value by blending coal with dairy biomass in rich combustion due to a lower percentage of fuel bound nitrogen to convert to NOx. 5. Blending of fuel by more than 90–10 was beyond practical limitations imposed by the high ash percentage in dairy biomass fuel since ash output per GJ becomes significant and as well as the higher Cl content in dairy biomass compared to coals. Acknowledgements This work was supported by Department of Energy (DOE) – Golden, CO, Grant Number: DE-FG36-05GO85003 and Texas Commission on Environmental Quality (TCEQ) Grant No.: NTRD 582-565591-0015. References [1] Baxter Larry. Biomass cofiring overview. Second world conference on biomass for energy, industry, and world climate protection, Rome, Italy, May 10–14; 2004. [2] Laux S, Grusha J, Tillman DA. Co-firing of biomass and opportunity fuels in low NOx burners. 25th Intl Tech conf on coal utilization and fuel Systems, Clearwater, FL, March 6–9; 2000. [3] Sweeten JM. Texas agricultural extension service publication L-1094. College Station, Texas: Texas Agricultural Extension Service, Texas A&M University; 1979. [4] Carlin N, Annamalai K, Sweeten J, Mukhtar S. Thermo-chemical conversion analysis on dairy manure-based biomass through direct combustion. Int J Green Energy 2007;4:133–59. [5] Sweeten JM. Texas agricultural extension service publication B-1671. College Station, Texas: Texas Agricultural Extension Service, Texas A&M University; 1990.

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[14] Annamalai K, Sweeten J, Priyadarsan S, Arumugam S. Energy conversion. In: Capehart B, editor. The encyclopedia of energy engineering and technology. Boca Raton, FL: Taylor and Francis Group; 2006. [15] Annamalai K, Sweeten J, Mukhtar S, Thien B, Wei G, Priyadarsan S, et al. Cofiring coal: feedlot and litter biomass (CFB and CLB) fuels in pulverized fuel and fixed bed burners. Final DOE report. DOE-Pittsburgh Contract # 40810; 2003. [16] Sweeten JM, Annamalai K, Thien B, McDonald L. Fuel 2003;10:1167–82. [17] Annamalai K, Thien B, Sweeten J. Co-firing of coal and cattle feedlot biomass (FB) fuels. Part II. Performance results from 30 kWt (100,000) BTU/h laboratory scale boiler burner. Fuel 2003;82(10):1183–93. [18] Heflin K, Sweeten J. Preliminary interpretation of data from proximate, ultimate and ash analysis, results of June 7, 2006 samples taken from feedlot and dairy biomass biofuel feedstocks at TAES/USDA-ARS, Bushland, TX Texas Agricultural Experiment Station, Texas A&M Agricultural Research & Extension Center Amarillo/Bushland/Etter; 2006. [19] Lawrence B. Cofiring coal and dairy biomass in a 100,000 BTU/h Burner boiler facility. Master Thesis, Texas A&M University, College Station, Texas; 2007. [20] Annamalai K, Puri IK. Combustion science and engineering. Boca Raton, FL: CRC Press, Taylor and Francis Group; 2007.