The gasification process requires the addition of an oxidizing or gasifying agent, such as air, oxygen, steam, carbon dioxide or combination of these. Depending on gasifying agent used, different calorific values of the product gas will be obtained (Wang, 2008). For example, if steam is used as the gasifying agent, the heating values of the product gas are typically 10-15 MJ/m3N and in case of air typically 3-6 MJ/m3N (Wang, 2008) for gasification of biomass. Typical gas compositions using air and oxygen/steam as gasifying agents in fluidized bed gasification are shown in Table 6.1.

Two parameters used to describe the measures of the air or oxygen flowrate is the equivalence ratio (ER) and the superficial velocity (SV). ER and SV are defined as the ratio of airflow to the airflow required for stoichiometric combustion of the biomass, which indicates the extent of partial combustion, and as the ratio of air flow to the cross-sectional area of the gasifier, which removes the influence of gasifier dimension by normalization, respectively (Yamazaki, 2005). Therefore, both the ER and the SV are directly proportional to the airflow. In case of using air as the gasifying agent, the air supplies with oxygen for the combustion process and by varying the air flow, in for example fluidized bed gasification; it will influence the degree of combustion, which also affects the gasification temperature. A higher airflow rate, results in a higher temperature, resulting in a higher biomass conversion. This is true as long as oxygen is not supplied in excess causing a too high degree of combustion of the biomass, resulting in decreased energy content of the product gas. If a too high air flow is used, the residence time will be shorter, which may reduce the extent of biomass conversion. Other factors of importance for the effect of ER on the product gas are e. g. temperature and steam to biomass ratio.

Steam as a gasifying agent increases the partial pressure of H2O in the gasifier. This favors the water gas reaction (eq. 6.4) as well as water gas shift (eq. 6.6) and methane reforming reactions (eq. 6.5), where the latter two occur at gasification temperatures above 750-800°C (Kumar, 2009; Turn, 2010; Lucas, 2004). The addition of steam results in an increased amount of H2 in the product gas. The temperature of steam is generally lower than the gasification temperature and therefore a large amount of heat is needed to elevate the steam temperature and thereby maybe lowering the temperature in the gasifier. This need more pronounced above a certain steam-to — biomass ratio where the product gas will be affected negatively. It is therefore recommended to preheat the steam or any gasifying agent before introducing it into the gasifier, to induce a higher gasification temperature.

3.2.1 Manure source

Managing the amount of manure produced from the hundreds, sometimes thousands, of animals on the farm which house dairy cows, beef cattle, hogs, chickens, and other traditional farm animals, is a significant undertaking (Centner, 2004). In the US, 33.7 million head of cattle were slaughtered in 2006. Kansas and Nebraska were the first and second largest producers of commercial cattle, respectively, with each producing over seven million cattle. Texas was the third largest producer of commercial cattle with 6.48 million head (NASS, 2007).

The potential manure production from cattle in feedlots is over 365 million wet tonnes per year for the US; 70.4 million wet tonnes per year for Texas. Most of these cattle are kept in highly concentrated feedlot operations during the weeks before they are slaughtered. Potentially harvestable manure biomass from all of the concentrated animal feeding operations (CAFOs) in the US easily exceeds 100 million dry tonnes per year and 6-12 million dry tonnes in the Texas Panhandle alone. Sometimes it is cheaper to store them and spread it over the land. Feedlots in the Texas and Oklahoma panhandle regions can range between 5000 and 75,000 head (Harman,

2004) . The Texas Panhandle is regarded as the “Cattle Feeding Capital of the World”, producing 42% of the fed beef cattle in the United States within a 200-mile radius of Amarillo. Manure produced from the 7.2 million head fed each year amounts to more than 5 million tonnes/year
on an as-collected basis. Hence, it has been used extensively for irrigated and dry land crop production, and in some cases on CRP lands being converted to rangelands. Declining water tables in the Ogallala Aquifer and increasing fuel costs have reduced irrigation water use per acre. As these trends continue, they will likely reduce demand for manure as fertilizer in a per-acre basis. Cattle feedlots will encounter longer hauling distances to achieve P — or N-based nutrient balances on irrigated crops or dry land situations. The amount of manure to be applied is usually determined by the amount of nitrogen contained in the solids. One hectare of grass requires about 250 kg of N. Sometimes this can lead to an overloading of phosphorus on the land. Only recently have farms begun to switch to P-based land application and composting (Osei et al, 2000).

Apart from cattle feedlots, the number of dairy operations with more than 500 head of cows increased from 29% of all dairies in 1997 to 39% of all dairies in 2001. Even though the overall number of dairy operations in the US has declined to 91,240 in 2002, 86,360 in 2003, and 81,440 in 2004, the expansion in milk output is well established and should continue with only modest deceleration (USDA, 2005). This is because the number of larger, more efficient dairies, with over 500 head of cows, has increased while smaller dairies have begun to disappear (Keplinger et al, 2004; NASS, 2002). Among dairy cattle, feeder steers or heifers, each animal (having a live weight between 544 to 907 kg/head or 1200 and 2000 lb/head) produces between 27 to 57 kg (approximately 5 to 6% of its body weight) of wet manure per day containing 85-90% moisture and 10-15% solids (including volatile matter, nutrients, ash and combustibles; Fig. 3.3) (DPI&F,

2003)

. About 110,000 dairy cattle in over 250 dairies in Erath County produce 1.8 million tonnes of manure biomass (excreted plus bedding) per year. The dairy cows in this region make up about 25% of the total number of dairy cows in Texas (TX PEER, 1998). Dairy manure termed as dairy biomass (DB) is used over 7% of the landscape in the Bosque River Watershed.

Figure 3.3. (a) Manure production and environmental effects, (b) soil surfaced feedlot manure or high ash

feedlot biomass or HAFB (Carlin, 2009), (c) paved surfaced feedlot manure or low ash (LA) feedlot biomass or LAFB; (Carlin, 2009).

Currently most dairies, as well as other CAFO’s, utilize large lagoon areas to store wet animal biomass. Water along with nutrients seeps into the soil (Fig. 3.3). This has been the case, for example, in the Bosque River Region and Erath County, just north of Waco, Texas. Water runoff from these lagoons has been held responsible for the increased concentration of phosphorus and other contaminates in the Bosque River, which drains into Lake Waco, the primary source of potable water for Waco’s 108,500 people. Thus the growth of cattle, dairy and swine industries will likely exacerbate the nutrient balance situation (Annamalai et al., 2012). Further, when the manure gets very dry, the cattle’s feet grind the dry manure, creating a dust problem. Particulate matter (PM) or dust from feedlot ranges from 8.5 to 12 microns. The total suspended particles (TSP) in feedlot dust normally range from 150 ^g/m3 to 400 ^g/m3 but there are also reports having average values exceeding 400 ^g/m3 (Sweeten etal., 1979). The PM 10 regulation requires concentration of particles less than 10 ^m should be less than 150 ^g/m3. Moreover, when wet and composting manure streams decompose or anaerobically digest in relatively uncontrolled settings, such as poorly maintained manure storage lagoons, methane (CH4) and malodorous odors can form, reducing the quality of life near the farm (Mukhtar, 1999). A video demonstration on biogas from a digester is available at the web site Climatetechwiki (2010). Methane is also a very strong (about 24 times more harmful than CO2) greenhouse gas.

The total energy usage ranged from as low as 464 kWh per year per head (kWh/y/hd) for a pasture dairy inNortheast Texas, to as high as 1637 kWh/y/hd for a hybrid facility in Central Texas. Where possible, the electricity usage at the dairies was allocated to four main energy sinks: the milking parlor, the animal housing areas, feeding, and manure management. Generally, milking and housing components dominated the electricity usage for hybrid dairies, with the milking parlor being the primary consumer of energy for the open-lot facilities (Sweeten et al., 2012).

The total amount of agricultural manure in the 15 EU countries was estimated to be 1124 x 106 tonnes in 1993 which includes 887 x 106 tonnes from cattle (Eurostat, Waste Statistics). The total energy consumption of the 27 EU member countries in 2009 was 1,113.6 million tonnes of oil equivalent, the biomass consumption made up 7.5% with 83.68 Mtoe. 43.9 Mtoe was input to power plants. Figure 3.4 summarizes the contribution every biomass category can make to the total EU biomass potential. Note that animal waste based biomass makes up only less than 5% while forest (41%) and waste (38%) sectors can contribute the greatest share of the potential (AEBIOM, 2011).

Similar to feedlot and dairy cattle, broiler chickens are raised in confinement buildings i. e. chicken houses on a bed of material that can be straw, sawdust, or rice hulls, upon which the

I Dry manure C:, Wet manure i: Stla’.’.

‘■$І Verge grass [ ■ Prunings a: Animal waste К Organic waste industry і:; Paper cardboard waste I Common sludges I Dedicated cropping [. .1 Additional harvestable roundwood

■ Primary forestry residues

■ Black liquor

broiler chicken manure is deposited on the bedding, along with spilled feed and feathers over the life of the birds. Hence the waste material is termed poultry litter or broiler litter or litter biomass (LB). At the end of one or more growing cycles, the broiler litter is harvested by scraping out the chicken houses typically using a small wheel loader and must be stored, disposed of, or utilized.

Though the focus of the present chapter is on thermal energy (non-biological) conversion, a brief overview is presented on biological conversion, typically a slow process but producing medium quality gas (with HHV of almost 50% of natural gas).

Changqing Dong & Xiaoying Hu

4.1 BIOMASS RESOURCES IN CHINA

In order to reduce the use of fossil fuel and the negative effects on climate, China has issued a Renewable Energy Law, which came into effect on 1st January 2006, to promote the development and utilization of renewable energy in China. In 2010, 76.8% of electricity generated in China was from coal (containing coal gangue): this corresponds to 3249 TWh, nearly 1100 million tonnes of coal burned and over 1800 million tonnes of CO2.

Along with the growing of social demand on energy, as the main energy source fossil fuels are decreasing rapidly. Therefore, looking for a renewable energy is being paid more and more attention by society, which becomes a focal point. Biomass is a source of renewable energy, which is considered one of the best forms of alternative energy. Biomass energy comes in many forms and the major sources of biomass are agriculture, food-processing residues, industrial wastes, municipal sewage and household garbage. Biomass accounts for 35% of primary energy con­sumption in developing countries, raising the world total to 14% of primary energy consumption. Biomass — the fourth largest energy source after coal, oil and natural gas — is the largest and most important renewable energy option at present and can be used to produce different forms of energy. It is reported that the annual yield of natural cellulosic biomass in China exceeds 0.7 billion tonnes, in which the amount of corn stalks are around 220 million tonnes. It was assumed about 50% of the agriculture waste can be used as energy, for power generation, heat supply and cooking. It is scheduled that biomass power generation capacity in China will reach 3000 MW in 2020.

This can be expressed as: total chlorine/fluorine, water soluble chlorine/fluorine and water insol­uble chlorine/fluorine. Dealing with total chlorine/fluorine the sample is burned in an oxygen atmosphere transforming chlorine into chlorides and fluorine into fluorides and with the succes­sive absorption in an alkaline solution. Chlorine and fluorine in solution are determined through potentiometric titration. Soluble chlorides/fluorides are measured by extracting a portion of the sample with water and then through potentiometric titration. Insoluble chorine/fluorine is cal­culated subtracting the soluble components from the total. The eventual content of chlorine and fluorine in biomass is responsible for the emission of acid gases (HCl and HF) and also dioxins and furans.

5.1.3.4 Chemical analysis (EN 15297, 2011 andEN 15290, 2011)

Other trace elements in the fuel have to be analyzed: As, Cd, Co, Cr, Cu, Hg, Mo, Mn, Ni, Pb, Sb, Se, Sn, V Zn, Al, Si, K, Na, Ca, Mg, Fe, P and Ti, using methodologies and instrumentations adequate for the specific element. The presence of these elements in the fuel influences the choice of the conversion process to be adopted. As an example Miles et al. (1996) showed that Ca and Mg increase the melting temperature of ashes, while K and Na decrease it; Si if combined with K and Na can form low-melting silicates.

The behavior of ashes and the technical standard used for the determination of ash melting behavior will be analyzed in a specific section.

Tars in the product gas can be tolerated if the gas is to be used as a fuel and closely coupled to the applications, such as boilers and kilns. For these applications, cooling and condensation of the tars can be avoided, and the energy content of the tars adds to the calorific value of the product gas. However, in more demanding applications tars in the raw product gases, even at low concentrations, can create major handling and disposal problems. Different systems for tar removal are shown in Figure 6.11. As soon as the temperature of the producer gas drops below the dew point, tars will either form aerosols or directly condense on the inner surfaces of the equipment, resulting in plugging and fouling of pipes, tubes, and other components downstream from the gasifier.

Aerosols are especially difficult to remove by filtration or scrubbing systems, causing deposits in the cooler parts. At temperatures above about 400°C, tars can also undergo subsequent dehy­dration reactions to form solid char and coke that further tend to plug up systems. The most important consideration is often to maintain the producer gas above the tar dew point (~400°C), thus avoiding condensation in the pipes. Internal combustion engines and methanol synthesis

applications require that the gas be cooled before final use. However, there are many techni­cal and economic reasons, such as thermal efficiency, environmental emissions compliance and tar-effluent treatment costs, to justify catalytic cracking and reforming of tars before cooling.

IC (internal combustion) applications require that particles and tars be lowered to about 30mg/m3N for particulates and 100mg/m3N for tars. Ideally, gas turbine applications require that the hot gas is completely cleaned and remains hot (and under pressure) before use. It is not practical, or thermodynamically efficient, to cool down the gas after gas generation in the gasifier. The range of the particulate concentration limit for gas turbines is 0.1 to 120mg/m3N, depending on the design and the operating conditions. Alkalis are also critical contaminants, and the reduction of these to acceptable levels (usually below 0.1 mg/m3N) remains a great challenge.

Hydrocarbons also possess potential problems for the methanol synthesis processes. To prevent catalyst poisoning (particularly the copper/zinc-based catalysts), total olefin content should be less than 6 mg/m3N and the ethene concentration should be below 4 mg/m3N. The catalysts are also very intolerant to the presence of sulfur and chlorine, as will be discussed.

Two basic approaches may be identified to remove tars from product gas streams:

• The physical methods are utilized for removing condensed tar aerosols, using technologies similar to those used for particulate removal such as wet scrubbers, electrostatic precipitators, or other technologies. These require that the product gas be cooled to ensure the tars are in a condensed form.

• The catalytic and thermal tar reduction methods have been studied to convert the tars to perma­nent gases. The catalytic approaches can potentially destroy tars in either the vaporized or the condensed state. These two approaches are discussed more in below, and special emphasis will be put on the catalytic tar cracking techniques as these possess the most promising techniques for tar removal.

In these techniques for physical tar removal, tars are removed from the gas stream by cooling the product gas, allowing tar condensation into aerosol droplets. Thereafter, the droplets are removed by systems similar to those used for particulate removal. The two most common techniques for this are wet scrubbing and electrostatic precipitation. As a result of the physical tar removal, a condensate contaminated with tars is generated and this condensate has to be treated.

In the wet scrubbers tars are collected by impinging the material on water droplets. Those tar — containing water droplets lead to a decanter where the bulk tars are separated from the aqueous phase. The use of water in these scrubbers needs the gas temperature at the exit to be in the range of 35-60°C (Stevens, 2001). Generally, particulates and other gas impurities, such as acidic or alkaline compounds, are removed simultaneously with tars by these techniques. It is possible that the condensation of tars on particulate surfaces can lead to plugging and fouling of gas conditioning equipment. Nevertheless, the use of wet scrubbers for small applications has proven to be a less reliable method for tar elimination because of their cost.

Tar removal in the electrostatic precipitators is based on the same principles as particulate removal. The collector surfaces of the electrostatic precipitators are washed continuously to remove the tar material. These collectors can operate up to about 150°C, but preferably at lower temperatures to avoid tar vaporization. The electrostatic precipitators are efficient removing tars and particulates from the product gas stream as they can remove up to 99% of particles less than ~0.1 ^m. However, the use of these systems in large-scale biomass gasifiers is rare because of their high operating and investment casts.

In the wet scrubbers and wet electrostatic precipitators, tars are collected as a tar-water mixture. The biomass tars include a wide variety of organic compounds, and most of them are at least to some extent water-soluble. This implies that, the wet waste cannot be clearly separated into organic and aqueous fractions. An incomplete separation of the effluent into two phases can be accomplished by settling though, but the resulting organic product still contains large amounts of water (typically 50%wt or more). The separated aqueous phase also contains lower molecular weight oxygenates including organic acids, aldehydes, and phenols. Plain wastewater cleanup and tar disposal is not feasible due to environmental concerns. Treatments for the aqueous wastewater are commercially available, but will increase costs. The most common techniques employed are: adsorption of dissolved organics by carbon, wet oxidation of wastewaters, and dilution and biological treatment of wastewaters. The operational costs of these wastewater treatments are, in principle, directly proportional to the contamination level of the condensate.

In this section, three different methods: Single Reaction Model, Conventional Arrhenius Method and parallel reaction model were employed to estimate the chemical kinetic parameters

of Biomass (Chen et al, 2012b) so that the rate of pyrolysis and time scale for pyrolysis can be determined.

3.7.1 Single reaction model: conventional Arrhenius method The single reaction model is given in the equation:

dmv

—- = k(T) ■ mv (3.17)

dt

where mv is the mass of volatiles remaining in the sample and k(T) is given by the Arrhenius expression (Annamalai and Puri, 2007):

Separating variables and integrating equation (3.17) yields the following result:

where mv is the mass of the volatiles at time t, mv 0 is the initial mass of volatiles at t = 0, B is the pre-exponential factor, E is the activation energy, R is the universal gas constant, and T is the absolute temperature.

Since the temperature change with time is constant in TGA tests, the integral on the right side of equation can be rewritten as:

ij= (E f e2X) e2(Xq)

mvo) V в) V r) l X Xq

where X = (E/RT), в is the rate of change for temperature with time (20K/min), E2, second exponential integral (Abaramovitz and Stegun, 1970) given as:

E2(X) = {exp(-X) — X ■ E1(X)},

where: a1 = 2.334733, a2 = 0.250621 bi = 3.330657, b2 = 1.681534

Using the expression for Ej(X), the E2(X) can also be expressed as:

Equation (3.20) presents the exact relation between mv, volatiles remaining at temperature T and heating rate for SRM. The conventional Arrhenius plot of ln(mv/mv0) vs. 1/T for extraction of E and B for the whole domain of pyrolysis is based on further approximations of equation (3.20). If T >> T0 (pyrolysis start temperature), then, X <<X0, and E2(X)/X >>>> E2(X0)/X0 and with equation (3.22), equation (3.20) becomes (Chen, 2012b):

(b — a1)X + b2 — a2 I X(X2 + b1X + b2) j

Here C(X) was introduced as a support vector. Taking the logarithm of equation (3.23):

l„|—1)| * .„j№/«>«№>>[_

equation (3.24) becomes:

E

ln{—ln(/)> * A — RT, (3.25)

where

/ = —

mvo

and C(X) is roughly constant. As a result, the activation energy E and pre-exponential factor B can be determined from the slope and intercept of the linear plot ln(—ln(mv/mvo). Figure 3.16 shows the Arrhenius plot for low ash partially composted separated solids dairy biomass.

1.2.1.2 Chuang Municipality Lutang Sugar Factory

Chuang Municipality Lutang Sugar Factory of Guangxi province improved the boiler by using a 35 t/h fluidized bed boiler for burning a mixture of coal and bagasse instead of 25 t/h pulverized — coal fired boiler. With a ratio of coal to bagasse of 60 to 40%, the project was successful (Liu et al., 2003).

Chuang Municipality Lutang Sugar Factory uses the fanlike coal pulverizer for milling in the 25 t/h pulverized coal fired boilers. The boilers are dual-drum transverse arrangement of convection bank boilers, the superheaters are arranged between slag screens with a convection bank, and economizers and air preheaters are arranged in the rear flue. Boiler design parameters: evaporation capacity of 25 t/h, vapor pressure of 2.4.5 MPa, vapor temperature of 400°C. The steam boilers produce is used to generate electricity and heating. The boilers need to burn high quality coal instead of bagasse, which is combustion by-product of virgin sugar. The boiler efficiency is not high, thus running a large consumption. Chuang Municipality Lutang Sugar Factory has an urgent requirement to transform the boilers, so that coal and bagasse can be mixed in the combustion to reduce the operating cost.

In order to expand the evaporation capacity (from 25 to 35 t/h) and mix coal with bagasse for combustion, the boilers use circulating fluid bed combustion, being a circulating fluid bed type of furnace with pipe laying. The boiler standards after transformation should be: (1) Fluidized bed boilers with coal mixed bagasse for fuel, the ratio of 60% for soft coal with 40% for bagasse. Net calorific power of soft coal is 16,747 kJ/kg, and volatile is 15.18%. (2) Boiler evaporation of 35 t/h. (3) Boiler steam with the same pressure and temperature. The detailed transformation of the boiler heating surface is shown in Table 4.6.

After the transformed boilers are put into operation, coal and bagasse are mixed to be burned (the ratio of 60% for soft coal with 40% for bagasse). Coal enters the combustion chamber through the belt feeder and bagasse enters the dilute-phase zone by pneumatic power. Coal main burns in the dense phase bed and bagasse main burns in the dilute phase bed. Evaporation capacity can

reach 30-32 t/h. Temperature under the bed is 930-980°C and at combustion chamber outlet is 680-720°. Boiler steam parameters can meet the design values and boilers run stable.

While in fixed bed combustion the solid fuel is either burnt on a pile or on a grate and there is minimal relative motion between the fuel bed and the surface on which it is laying, in moving bed combustors fuel particles are suspended in a turbulent flow of air therefore even the presence of a fuel bed may be questioned. In moving bed combustors small particle size becomes essential to guarantee the suspension, and therefore the functioning of the burner, while in fixed beds small particle size may lead to unburned particles in the flue gas and consequent fouling and particulate emissions. Moving bed combustors are divided in two categories: suspension burners, where only fuel particles are present in the air stream, and fluidized bed burners, where hot inert sand is also suspended in the air stream, to increase the heat transfer to the fuel particles.

5.3.3.1 Suspension burners

In suspension burners (Fig. 5.19) biomass fine and dry particles are blown inside the combustion chamber in a high turbulent motion by a stream of preheated primary air and are burnt before
the air stream leaves the furnace. To guarantee complete combustion a massive fuel pretreatment is necessary and particle size and humidity usually do not exceed respectively 15% and 0.6 cm, therefore for economic reasons usually they are limited to ready-to-use biomass by-products such as wood dust, rice husk etc. Some burners would require an auxiliary oil or gas pilot burner to maintain combustion, especially if the radiation from the refractory lining is not adequate to maintain the necessary temperature.

This section provides a brief overview of the thermochemical processes, namely, direct com­bustion, pyrolysis, and gasification, for converting biomass to useful energy, chemicals, and fuels.

2.1.1 Direct biomass combustion

Direct biomass combustion has traditionally been used to supply heat and power in the process industry. However, such systems for electricity generation have low overall efficiency and emit significant pollutants (Caputo et al., 2005). Systems utilizing direct combustion of agricultural waste include kilns and boilers for generating steam used for various industrial applications includ­ing electricity production. Werther et al. (2000) provide a review on direct biomass combustion. Figure 2.2 from their paper shows a schematic of processes associated with the combustion of wood or straw.

The sequence of events which a lump of solid fuel undergoes during combustion includes heat­ing up, drying, devolatilization, ignition and combustion of volatiles, and finally the combustion of char. As discussed by Werther et al. (2000), the fundamental information required to charac­terize the combustion of agricultural residues include temperatures at the start of devolatilization and char combustion, the influence of drying on the devolatilization process, the composition of devolatilization products, and the effect of volatile release and combustion on the overall combustion process.

There are many operational and environmental challenges associated with the biomass com­bustion technology. These include the low bulk density of agricultural waste (~5—10 times lower than coal), high moisture content, low melting point of the ash, and high content of volatile matter. The low density leads to problems such as high volume required for storage, low energy output on a volume basis, and high transportation costs. Densification is often used to address these problems. Similarly, the low melting temperature of the ash leads to problems such as bed agglomeration in a fluidized bed, and fouling, scaling and corrosion of heat transfer surfaces. The higher content of volatile matter implies significant differences between the combustion and emission characteristics of agriculture biomass and fossil fuels (Ogada et al., 1996). For instance, the presence of volatile matter enhances the biomass ignitability and reactivity, but the combus­tion process becomes difficult to control. This presents challenges in using agriculture biomass in the existing combustion devices. Moreover, due to the presence of sulfur, nitrogen, chlorine etc., the biomass combustion leads to the formation of gaseous pollutants such as SOX, NOX, N2O and HCl. Many of these issues can be addressed in biomass co-fired combustion systems (Backreedy,

2005) , but the amount of biomass is generally limited to 5-10% of the total feedstock due to concern about the plugging of existing feed systems (Yoshioka et al., 2005). Further discussion of these issues can be found in Werther el al. (2000).

Figure 2.2. A schematic of various processes associated with the combustion process of a lump of straw or wood chip (Werther et al., 2000).

There are few fundamental studies, experimental or theoretical, dealing with the biomass combustion and emission characteristics. This may partly be due to the lack of information about the physical and chemical properties of various biomass feed stocks. Consequently, there has not been as much work on the development of reliable kinetic and thermo-transport models for investigating biomass combustion and emissions. Such information is of critical importance for the design and efficient operation of biomass-based combustion systems. The lack of this information has also been a factor in low utilization of direct biomass combustion compared to biomass pyrolysis and gasification. Thus, there is a need for more fundamental research on biomass combustion, and the development of a database on the physical and chemical properties of biomass feed stocks. As such information becomes available, along with appropriate kinetic and thermo-transport models, the existing software, which has developed for the simulation of coal combustion (Smith et al., 1990), may be modified for predicting the biomass combustion and emission characteristics. Subsequently, these tools can be further refined for optimizing and improving the performance of direct biomass combustion systems.

During combustion, only a fraction of fuel N is converted into NOX (about 20% to 30% in sub­bituminous coal (Bowman, 1991, 2001)), while the remaining fuel N is released as N2 with the flue gases. The reaction of N with oxygen is inhibited by carbon radicals bonding with available oxygen to form CO and CO2. The nitrogen conversion efficiency is defined as the amount of fuel nitrogen that gets converted to NOX. Annamalai and Puri (2007) showed that overall fuel nitrogen conversion efficiency can be approximated by:

where c/n is the atom ratio of the empirical carbon and nitrogen respectively, XNO is the mole fraction of NOX, XCO2 is the mole fraction of CO2, and XCO is the mole fraction of CO. All gases were measured in the exhaust stream. Note that the equation assumes that all NOX originates from fuel nitrogen and hence it presents an upper bound on fuel nitrogen conversion efficiency. In addition, when fuel nitrogen conversion efficiency is very low, it means that most fuel-bound nitrogen is converted to something other than NOX.

Note that as the equivalence ratio increased, less nitrogen was converted to NOX. In the extremely rich region, the conversion efficiency was nearly 0%. The largest decrease in con­version occurred when the flame went from stoichiometric to rich. Figure 3.35 presents the fuel nitrogen conversion efficiency forTXL andTXL:DB blended fuels. Also note that in general, the

Effect of Fuel on NO, for WYO and WYO:OB Blended Fuels

4

Figure 3.35. Effect of fuel on nitrogen conversion efficiency for TXL and TXL:DB blended fuels. Note that the conversion efficiency is less than coal for almost all TXL:DB blended fuels (adopted from Lawrence, 2007).

DB blended fuels converted less nitrogen to NOX. The same trend was observed with WYO and WYO:DB blended fuels.

As with NOX reduction for AgB and coal blends, (section, 3.4.1), it is hypothesized that the increased volatile matter of AnB under co-firing conditions resulted in the increase of fuel N loading, greater depletion of O2 and sometimes even in reduction in NOX (Arumugam et al.,

2005) . However, the increased fuel N inAnB produces more NH3 due to urea type N in AnB. Thus, more NH3 type species are produced in blend coal:AnB fuels. Under appropriate temperature and oxygen concentration, the NOX reduction due to NH3 + NOX reactions may dominate the reduction process of NOX.