Overview and some issues related to co-firing biomass and coal.

Dai, Jianjun ; Sokhansanj, Shahab ; Grace, John R. 等

INTRODUCTION

Partial substitution of coal by biomass feedstocks or other materials (e.g. waste) in coal-fired power plants requires cofiring (Fernando, 2005). Co-firing also occurs when biomass feedstocks (or other materials) are partially replaced by coal (Leckner, 2006). In most instances, co-firing of biomass in existing coal-fired boilers provides an attractive approach to nearly every aspect of the development of biomass-to-energy capacity, especially in the presence of economic incentives to replace coal.

Low heating values (LHV), varying chemical compositions (Table 1), peculiar physical properties (e.g. wide range of particle size, high moisture content (MC), irregular shapes, low bulk densities), as well as high investment costs and insecurity of feedstock supply, are major concerns when stand-alone biomass plants are built. Large biomass units (>300 MWe) may be economically impractical based on present economic criteria (Fernando, 2005). Coal can mitigate the effects of variations in biomass feedstock quality and buffer the system when there is insufficient biomass feedstock (Rickets, 2002; Viewls, 2005), whereas biomass brings environmental and social benefits to coal plants. When co-firing occurs in large units with high thermal efficiency, specific operation costs are likely to be lower than in small-scale systems (Rickets, 2002; Viewls, 2005), and the costs of adapting existing coal power plants should be lower than building new dedicated biomass systems (Fernando, 2005). Recent reviews of co-firing identified over 100 successful field demonstrations in 16 countries, utilizing many types of biomass in combination with various types of coals and boilers (Baxter, 2005) (Table 2). There have also been extensive studies concerning the co-firing of coal and biomass for energy generation (Leckner and Karlsson, 1993; Armesto et al., 1997, 2003; Desroches-Ducarne et al., 1998; Hein and Bemtgen, 1998; Dayton et al., 1999; Amand et al., 2001; Sami et al., 2001; Laursen and Grace, 2002; Ross et al., 2002; Skodras et al., 2002; Gayan et al., 2004; Hupa, 2005; Huang et al., 2006; Zulfigar et al., 2006; Nevalainen et al., 2007).

Three basic types of technological configurations can be identified for biomass co-firing in power plants (Zuwala and Sciazko, 2005): direct co-firing (Figures 1 to 4), parallel co-firing and indirect co-firing (Figure 5). Currently the most common option is direct co-firing, where biomass and coal are utilized together in the same boiler, mainly due to relatively low capital cost required to convert an existing coal-fired power plant into a co-firing operation. For direct co-firing of biomass, two methods have been developed: (a) blending the biomass and coal in the fuel handling system, with the blended fuel then being fed; and (b) separate fuel handling and separate burners for the biomass, thereby avoiding impact on the conventional coal delivery system (Brem, 2005). Parallel co-firing units (where biomass and coal are fed into separate boilers, jointly producing steam for power generation) are also popular, especially in the pulp and paper industry. The indirect option is expensive and involves a separate biomass gasifier. Hence this option is rarely adopted (Maciejewska et al., 2006). However, some researchers regard indirect co-firing as the most effective method of introducing large quantities of biomass with coal (BDC, 2007).

There are many successful co-firing systems with different reactors (fixed bed, fluidized bed and entrained flow). Several different types of biomass can be co-fired with coal, including wood, residues from forestry and related industries, agricultural residues, and biomass in refined form, such as pellets. Energy crops are also potential candidates for co-firing (IEA, 2005; Maciejewska et al., 2006). Clean wood waste, especially when pelletized, is an excellent fuel with low ash and alkali concentrations, and several commercial-scale co-firing demonstration tests have been completed without deposition problems with up to 10% biomass on an energy basis (Tillman, 2000; Savolainen, 2003; Baxter, 2005). Danish tests with up to 20% on an energy basis indicate that straw can be co-fired with coal without severe deposition or corrosion problems (Frandsez, 2005). There is also one large coal-burning CHP plant in Sweden which successfully converted to 100% wood pellets (Melin, 2007).

In recent years, some groups (Sjostrum et al., 1994; Kurkela et al., 1994; Madsen and Christensen, 1994; Reinoso et al., 1994; Brage et al., 1995; Chen et al., 1995; de Jong et al., 1998; Collot et al., 1999; Sjostrum et al., 1999; Brown et al., 2000; Pan et al., 2000; Xie et al., 2001; Chmielniak and Sciazko, 2003; McLendon et al., 2004) have reported co-gasification of biomass and coal. Co-gasification brings environmental benefits (e.g. reduced C[O.sub.2] emissions, decreased sulphur and nitrogen oxide emissions), while also reducing problems that occur in biomass operations associated with the production of tar. Air-steam gasification facilitates high conversion of solid feedstocks such as biomass and coal into gas (Hanaoka et al., 2005). However, there have been few reports on co-gasification of woody biomass and coal with air and steam from the viewpoint of the supply of syngas for synthesis of liquid fuels (de Jong and Hein, 1999; Pinto et al., 2003). There have also been few reports on co-gasification where the relative proportions of biomass and coal have varied over wide ranges (Kumabe et al., 2007). Research is needed on pre-treating biomass to facilitate co-feeding and dosing to the gasifier. The ash, slagging, fouling and corrosion behaviour of typical biomass minerals have to be assessed (Boerrigter et al., 2006).

This paper highlights the technical difficulties related to co-firing of biomass and coal based on previous experience. Calculation and analysis are also provided to deepen understanding of co-firing issues and problems, especially for direct co-firing.

COAL AND/OR BIOMASS COMBUSTION/GASIFICATION TECHNOLOGY AND EQUIPMENT

Coal/Biomass Combustion

Information on biomass co-combustion with coal can be found in several articles that have summarized the state-of-the-art in this field (Sami et al., 2002; Demirbas, 2005). In general, three types of combustion systems can be identified (Table 3):

(1) Packed bed combustion systems use grate-fired furnaces and underfeed stokers. Different types of grate furnaces (up to 20 MWa,) are available: fixed, moving, travelling, rotating, and vibrating (van Loo and Koppejan, 2004). Underfeed stokers are used in small- and medium-scale systems up to a nominal boiler capacity of 6 MWa, (van Loo and Koppejan, 2004). Packed bed boilers are generally not good candidates for direct co-firing compared to fluidized beds, although they can be a component of more advanced modes, for example for parallel or in-direct co-firing (Maciejewska et al., 2006). Some studies of packed bed direct co-firing of biomass and coal have also been conducted (Sampson et al., 1991; Brouwer et al., 1995).

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(2) Flnidized bed combustion (FBC) (Figure 6) has been reported to be most efficient and suitable for converting agricultural and wood residues into energy, as well as for co-firing (Elanchezian and Antonio, 1993; van den Broek et al., 1996; Philippek and Werther, 1997; Bhattacharya, 1998; Werther et al., 2000; Tsai et al., 2002; Backreedy et al., 2005). There are two major types of FBC systems: bubbling fluidized beds (BFB) and circulating fluidized beds (CFB). Hupa (2005) reviewed interactions of various fuels in various FBCs and found that factors such as flue gas emissions, fouling, and bed-sintering seldom depend in a simple linear manner on the composition of the fuel mixture; instead, non-linear relationships tend to be the norm (Wan et al., 2007). Hot, inert, and granular material (usually silica sand and limestone or dolomite) provide thermal inertia and can stabilize the combustion process (also capturing sulphur), constituting 90-98 % of the total in-bed mixture by mass, the balance being fuel particles (van Loo and Koppejan, 2004).

Given their good mixing, fluidized beds can accept various fuels (e.g. wood and straw), but require close control of fuel particle size (BFB < 80 mm, CFB < 40 mm) (van Loo and Koppejan, 2004). Particle segregation in bubbling fluidized beds is primarily caused by differences in particle density of the two species, so this can be a problem when coal and biomass are present. The combustion temperature has to be kept below about 900[degrees]C to prevent ash sintering, which could cause de-fluidization (van Loo and Koppejan, 2004). Hence, fluidized bed combustion is better suited for woody biomass (ash melting point > 1000[degrees]C) than for herbaceous biomaterial (e.g. straw, ash melting point <700[degrees]C) (Maciejewska et al., 2006). The potential significant drawback, especially in CFB, is incomplete combustion of fuels in the bed. This occurs because the unburned carbon, often appearing as soot, is very light and may not be captured by cyclones (Maciejewska et al., 2006). Among the three basic types of combustion systems, fluidized bed combustion seems to have the highest fuel flexibility with respect to MC, heating value and ash content, enabling the use of fuel mixes and increasing the range of fuels which can be fed or co-fed in existing power plants (van den Broek et al., 1996; Bhattacharya, 1998; Werther et al., 2000).

(3) Pulverized fuel or dust combustion systems (Figure 7) are fed pneumatically. Fuels include coal, sawdust, and fine shavings (van Loo and Koppejan, 2004). Fuel quality in dust combus tion needs to be maintained, with a maximum fuel particle size of 10-20 mm and MC of no more than 20 wt% (wb) (van Loo and Koppejan, 2004).

Coal/Biomass Gasification

Gasification is an important process related to indirect co-firing (Maciejewska et al., 2006). Gasifiers are used in various applications (Hotchkiss et al., 2002). There are two major types of gasification: direct and indirect gasification.

Fixed bed, fluidized bed and entrained flow gasifiers constitute the three basic types of gasifiers. Fixed bed gasifiers can be subdivided into updraft and downdraft gasifiers. Both require mechanically stable fuel particles of limited size (e.g. [less than or equal to] 10-30 mm) to facilitate passage of gas through the bed. Therefore the biomass can be preferred as pellets or briquettes. The scaling-up of fixed bed gasifiers, tar generation and NO, emissions are major concerns affecting the relative merits of different configurations (Maciejewska et al., 2006).

Two types of fluidized bed gasifiers can again be identified (Figure 6): BFB and CFB. Both have favourable fuel flexibility, being able to treat fuels of different origins (Belgiorno et al., 2003). Ash sintering and bed agglomeration are of concern when biomass is the fuel (Heinrich and Weirich, 2002). The efficient performance of fluidized bed gasifiers requires relatively small fuel particles to ensure good contact with bed material, as in fluidized bed combustion.

Entrained flow gasifiers (EFG) convert mixtures of fuel and oxygen into a syngas at high temperatures (significantly >1200[degrees]C, even as high as 2000[degrees]C) in very short periods of time (a few seconds) and at high pressures (~50 bar). The typical oxidizing agent is oxygen, in order to reduce the nitrogen content in the gas and resulting NO, emissions. The production of pure oxygen and the high pressure result in high costs (Heinrich and Weirich, 2002). In order to achieve reliable feeding and high conversion of the feedstock, particles should be smaller than 1 mm, or liquid (e.g. pyrolysis oil) feedstock can be used (Maciejewska et al., 2006). Producing sufficiently fine powders from biomass for entrained flow gasifiers is also expensive. Slurry feeding can reduce the overall cost of solid fuel feeding at high-pressures, but it cannot

be applied to biomass because of the low energy density and the high moisture capacity of biomass (Maciejewska et al., 2006). There are several commercial pneumatic feeding designs available for coal (GE/ChevTex, Conoco E-gas, Shell), but these do not work with more than 10-15 % biomass on an energy basis in a coal blend (Maciejewska et al., 2006). Entrained-flow gasification is a mature/commercial technology for petroleum residues and coal. However, experience is (very) limited with biomass. Not every biomass type is appropriate in any case due to difficulties with ash melting (Maciejewska et al., 2006). Emery Energy hinted at using an entrained flow concept for biomass, but details are not publicly available (Maciejewska et al., 2006). Supercritical water gasification operates at temperatures of 500-700[degrees]C and pressures of 200-400 bar. The process is suitable for wet feedstocks, but, as it is a relatively new concept, experience is restricted to laboratory and pilot scale experiments (Tuurna, 2003). Commercialization of supercritical water gasification also faces challenges in both economic and technical aspects, depending on specific conditions.

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MECHANISM AND PHENOMENA RELATED TO CO-FIRING

Combustion of biomass differs from coal combustion due to differences in chemical compositions and physical properties (Figures 8 and 9). Chao et al. (2008) conducted thermogravimetric analysis (TGA) and differential thermal analysis (DTA) of coal, rice husk, and bamboo at a heating rate of 5[degrees]C/min in air. High volatile matter (VM) contents and low activation energies of rice husk and bamboo made the pyrolysis and subsequent volatile oxidation start earlier than for coal. The higher VM content of biomass led to two distinct stages of weight losses, with gas phase oxidation at the beginning and char oxidation in the second stage, whereas the latter dominated the entire process for coal. The TG/DTA results indicated that a substantial fraction of the energy from the biomass combustion came from VM reaction, whereas almost all of the energy for coal came from char oxidation (Table 4). The time scales of the VM gas-phase reactions are much less than that of the char oxidation reaction of the residual carbon in the solid phase. The latter depends on the diffusion of oxygen to the surface of the carbon residues, followed by surface chemistry. This difference in time scale is crucial in explaining combustion performance and pollutant emissions (Chao et al., 2008) (Figure 9). Hence, the mechanisms of biomass and coal combustion differ somewhat, although biomass follows the same sequence of pyrolysis, devolatilization and combustion as for combustion of low-rank coal (Sami et al., 2001). Biomass can burn more intensively and may give rise to higher local peak temperatures due to its higher reactivity than coal. The combustion rate of biomass char is slightly higher because of a more disordered carbon structure (Backreedy et al., 2005), while biomass char burning rates are comparable to burning rates of high-VM bituminous coal chars (Sami et al., 2001). In fact, the reactions of the major components of wood, hemicellulose, cellulose, and lignin, are interconnected at high temperatures, with the wood reacting at one composite rate. Wood containing a high proportion of lignin, for example in knots, reacts more slowly (Backreedy et al., 2005). Lignin does not burn completely, especially if >0.5 mm in diameter.

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Biomass particles are large and physically complex, influencing heat and mass transfer. Particle shape and size affect char burnout because biomass does not melt, and irregular shapes are maintained during combustion. Larger particles of a given mass burn faster when they are non-spherical. Kinetics of the major steps in biomass combustion are not fully understood (Backreedy et al., 2005). Pyrolysis, ignition, and combustion of coal and biomass particles (Sami et al., 2001; Backreedy et al., 2005) are compared in Table 4.

Combustion modelling for coal/biomass blends is complex due to gas and two particulate phases, as well as chemical reactions. Two chemically different fuels are involved, with biomass much more reactive and having higher VM and MC than coal. Most reactor models contain sub-models for fluid-mechanics, particle dispersion, fuel devolatilization, gaseous combustion, heterogeneous char reaction and pollutant formation. Combustion models based on coal need to be modified to account for the effects of biomass co-firing on the overall combustion behaviour (Gayan et al., 2004). The suitability of the sub-models for biomass combustion is a key factor in selecting an appropriate code, including CFD models (Backreedy et al., 2005). Similarity between the coal and biomass sub-models can be assumed, despite differences in mechanisms and kinetics (Backreedy et al., 2005). Sami et al. (2001) revised the modelling of co-firing based on models for pulverized or swirls burners. Saastamoinen et al. (2005) presented a burning regimes model covering the combustion of coal, wood chips and their mixtures. The model assumes that a burning fuel particle initially loses mass due to drying and devolatilization, causing its average density to decrease, while its diameter remains approximately constant. In practice, wood particles may shrink in size, whereas some coals swell (Nevalainen et al., 2007). CFB models for burning coal (Adanez et al., 1995) and biomass (de Diego et al., 2002; Adanez et al., 2003) and blended biomass and coal (Gayan et al., 2004) have been developed in the past decade with a focus on predicting combustion efficiency, fouling, and emission of pollutants for different fuels and their mixtures in commercial-scale fluidized bed combustors.

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When a small amount of biomass is added to a coal flame, the reaction environment is primarily determined by the combustion of the coal rather than by the biomass kinetics. Biomass additions have led to a slight delay in the ignition of the blended fuels, although biomass has a lower ignition temperature (Demirbas, 2004; Goh, 2005; Lu et al., 2007). This is attributed to the larger particle sizes and higher MC of the biomass. Premixing biomass and coal can enhance the combustion of the two fuels, whereas poorly mixed biomass and coal tend to burn independently at different rates (Lu et al., 2007). Test results have suggested that, due to the varying physical and chemical properties of the biomass fuels, their additions have a significant impact on the characteristics of the flame, particularly the flame front and brightness. However, flame stability has been found to be little affected by the amount of biomass added in all cases studied, provided that the addition is less than 20% by mass (Lu et al., 2007).

McIlveen-Wright et al. (2007) analyzed 25 biomass processes in CFBC systems based on actual power plants. It was shown that CFBC power plants of different sizes could operate effectively and efficiently with a range of biomass types and loadings in co-firing applications, with lower net COZ emissions (compared to cases where coal is the sole fuel), and improved compliance with NO, and S[O.sub.x], emission limits.

HYDRODYNAMIC CHARACTERISTICS OF CFBC

CFB hydrodynamic characteristics have been analyzed and modelled (e.g. Johnsson et al., 1992; Johnsson and Leckner, 1995; Pallares and Johnsson, 2000; Gayan et al., 2004). The riser was divided into three zones: a bottom zone, characterized by a dense bed, similar to a bubbling bed; a splash zone with predominantly homogeneous particle clustering flow; and a transport zone with a core-annulus structure. In the splash and transport zones, the vertical distribution of solids was characterized by an exponential decay model, with the solid concentration assumed to be the sum of contributions from a cluster phase and a dispersed phase. The hydrodynamic model can predict mean voidage, annulus and core voidages, core radius, upward solids flow in the core, downward solids flow in the annulus and external circulation solid flux, all as functions of height (Gayan et al., 2004). For more information about fluidized bed hydrodynamics and reactor modelling, see Grace et al. (2003).

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Hydrodynamic analysis is also important for both blended feeding and separate feeding in order to estimate the hydrodynamic regimes for different particles and to optimize their physical properties (e.g. size, MC, density) for blended fuels. Mixtures of biomass and coal can be well fluidized only when the biomass constitutes less than 50 % by volume. Minimum fluidization velocity of particle blends can be calculated by the Ergun equation with reasonable accuracy (Bi, 2005). A sample calculation is given in Table 5 for different fuels, including coal and various biomass feedstocks. It is commonly assumed that the density and shape of biomass particles do not change and that no fragmentation occurs (Nevalainen et al., 2007). Non-spherical shapes may affect the drag coefficients and require the use of shape factors (Clift et al., 1978; Backreedy et al., 2005). Biomass particles differ in density, size and shape from coal particles, and this can cause different trajectories and reaction locations in the furnace.

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Ganser (1993) introduced two shape factors [K.sup.1] and [K.sup.2] applicable in the Stokes and Newton's regimes for the estimation of the

drag coefficient, [C.sub.d]:

[C.sub.d]=/[K.sub.2]24/Re[K.sub.1][K.sub.2][1+0.1118 (Re[K.sub.1][K.sub.2])sup.0.6567] + 0.4305/1+3305/Re[K.sub.1][K.sub.2] (1)

where Re is the particle Reynolds number based on the volume equivalent diameter, [d.sub.v]; [K.sub.1] = [([d.sub.n]/3[d.sub.v] + (2/3) [[psi].sup.0.5].sup.-1]; [K.sub.2] = [10.sup.1.8148 (-log [psi]).sup.0.5743]; [d.sub.n] is the projected-area-equivalent J diameter; and [psi] is the sphericity.

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The terminal velocity, [u.sub.t], can then be estimated from: ~ 4gdv (pp - pf)

[u.sub.t] =[square root of (4g[d.sub.v]([rho].sub.P]-[[rho].sub.f)]/3[[rho].sub.i][C.sub.d] (2)

where [[rho].sub.P] is the particle density, and pt is the fluid density. The Ergun equation (Ergun, 1952):

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can be used to estimate the minimum fluidization velocity (Nemec and Levec, 2005; Keyser et al., 2006). Here [[DELTA].sub.P] is the pressure drop, A is the Blake-Kozeny-Carman constant, B is the Burke-Plummer constant, [H.sub.b] is the bed height, [U.sub.mf] is the minimum fluidization velocity, [[micro].sub.f] is the dynamic viscosity of fluid, and [[epsilon].sub.mf] is the void fraction at minimum fluidization. For spherical particles, A = 150 and B = 1.75. For cylindrical particles (including disks), Nemec and Levec (2005) recommend:

A=150/[[psi]sub.3/2], B= 1.75/[[psi]sub.4/3]

Since cylinders are reasonably similar in shape to cuboids, these relations are also give reasonable predictions for cuboidal particles (e.g. ground wood pellets in Table 5). Calculated minimum fluidization velocities calculations for different types of particles, including 50:50 blends of biomass and coal, are shown in Table 5. Biomass particles are not easy to fluidize due to their large size and irregular shapes. Wood pellets can be better suited to fluidization after grinding.

TECHNICAL CONSTRAINTS RELATED TO CO-FIRING COAL AND BIOMASS

Constraints related to co-firing can include fuel preparation, handling, storage, milling and feeding problems (e.g. high MC, low bulk density, hydrophilic, non-friable character, biodegradability), different combustion behaviour, possible decreases in overall efficiency (e.g. relatively low calorific value, high MC), deposit formation (slagging and fouling), agglomeration, corrosion and/or erosion (e.g. low ash melting point, chemical composition with potentially high alkaline metals and chlorine content) and ash utilization (e.g. high alkaline metals and chlorine content). Most of these issues are related to fuel properties (Figures 8 to 11, and Tables 1 and 6). With proper combinations of these elements, a number of power plants practice co-firing without major problems (Figure 11) (Tillman, 2000; Aho and Ferrer, 2005; Aho et al., 2005; Baxter, 2005; Ferrer et al., 2005).

Ash, Slagging, Fouling, and Corrosion Problems

In indirect co-firing, as well as parallel co-firing, the ash produced in the process is kept separate. In direct co-firing, coal and biomass ash are mixed together. Mixed ash is not easy to utilize in the same applications as coal ash (e.g. in the construction industry). The degree of difficulty depends on the quality and percentage of biomass in the fuel blend, type of combustion and/or gasification, co-firing configuration, and coal properties. Therefore, when analyzing the environmental impacts of cofiring, the options for ash utilization must be assessed, especially for high biomass/coal ratios.

The major mechanisms and rates of ash deposition are related to the inorganic material (e.g. chlorine, sulphur, aluminium, and alkaline) in the fuel and to the combustion conditions (EUBION, 2003). Deposits may be caused by light sintering, or complete fusion due to the lower ash melting-point of biomass ash. The degree of fouling and slagging varies throughout the boiler, depending on local gas and tube temperatures, tube orientation, gas velocity and fuel composition (EC, 2000; Jensen et al., 2001; EUBION, 2003; Benetto et al., 2004). Deposits tend to cause deterioration in the heat transfer to tubes, reducing combustion efficiency (EUBION, 2003). Although slagging and fouling may occur quickly, corrosion may progress slowly over a long period, with or without associated slagging or fouling (EUBION, 2003). Chlorine-rich deposits (NaCl and KCI) induce hot corrosion of heat transfer surfaces, but high-risk chlorine compounds can react with sulphur and aluminum silicate compounds, releasing HCI, which is less harmful (EUBION, 2003). CORIDS (2005) reported that suitable materials and additives can reduce corrosion in boilers burning biomass, even at temperatures as high as 550[degrees]C. Ammonium sulphate may be injected into the flue gas after combustion to convert gaseous potassium chloride into potassium sulphate (a much less corrosive compound), resulting in reductions in corrosion and deposition rates by 50%. The corrosion issues in co-firing or biomass systems can also be addressed by pretreatment of biomass by leaching with water, thereby reducing the content of alkalis, sulphur, and chlorine in the feedstock (Jenkins et al., 1996; Jensen et al., 2001; Davidsson et al., 2002). More information on biomass pre-treatment through washing (both biomass washing and char washing) and its benefits for co-firing systems was provided by Maciejewska et al. (2006). Biomass-related deposit formation and corrosion are linked (EUBION, 2003); erosion and corrosion also interact (Stack and Jana, 2004). Therefore it is difficult to address these issues separately.

Baxter (1993) concluded that the ash deposition rate in biomass combustion peaks at early times and then decreases monotonically. The tenacity and strength of biomass combustion deposits tend to be higher than for deposits from coal combustion, with smooth deposit surfaces and low porosity. This means that the deposits from biomass combustion tend to be difficult to remove, requiring additional cleaning effort.

Pollutant Emissions

Blending coal and biomass can lead to reductions in pollutant emissions (Leckner and Karlsson, 1993; Nordin, 1995; Armesto et al., 1997, 2003; Gulyurtu et al., 1997; Desroches-Ducarne et al., 1998; Hein and Bemtgen, 1998; Dayton et al., 1999; Werther et al., 2000; Amand et al., 2001; Laursen and Grace, 2002; Ross et al., 2002), with the levels of pollutants decreasing as the proportion of biomass increases. Dayton et al. (1999) investigated the interactions between co-fed biomass and coal during combustion. The results revealed the synergetic effects of co-firing for HCI, KCI, and NaCl. The amounts of NO, and S[O.sub.2] detected suggested that any decrease resulted from dilution of N and S in the fuel blend, although alkaline ash from biomass may capture some S[O.sub.2] generated during combustion. The fuel nitrogen content of biomass is mainly converted to ammonia during combustion, contributing to reduced NO, for co-firing (Gayan et al., 2004). Hydrocarbons from biomass can also react with NO., producing molecular [N.sub.2] Hence, biomass has the potential to be an effective additional fuel when coal is the primary fuel. In addition, NH3 found in the biomass (e.g. animal wastes) or formed during combustion of biomass may contribute to the catalytic reduction of N[O.sub.x], (Sami et al., 2001).

Circulating fluidized bed (CFB) technology has been used to burn coal and biomass because of its ability to handle low-quality, high-sulphur fuels. Leckner and Karlsson (1993) measured experimental emissions of NO, [N.sub.2]O, S[O.sub.2], and CO from combustion of mixtures of bituminous coal and wood in a CFB. They concluded that emissions from the combustion of mixtures are related to the mass fractions of the fuels and to their properties. Nordin (1995) optimized sulphur retention during co-combustion of coal and biomass fuels in a fluidized bed using statistical experimental designs for operating variables. When Van Doorn et al. (1996) and Sami et al. (2001) fired blended coal, wood, straw, and municipal sewage sludge into a fluidized bed combustor, they found wood to be the most favourable co-firing fuel in terms of ease of combustion and reduced emissions of N[O.sub.x], and S[O.sub.2]. No particle agglomeration was observed. Emissions of S[O.sub.2], CO and N[O.sub.x], decreased with increasing wood-to-coal ratio. Similar effects were observed when co-firing straw, but the HCI concentration increased with larger straw-to-coal ratios due to its relatively high chlorine content. Huang et al. (2006) reported that co-firing wood chips resulted in lower N[O.sub.x] emissions, whereas co-firing straw or sewage sludge slightly increased N[O.sub.x] in pressurized fluidized bed combustors (PFBC). N[O.sub.x] may decrease or increase when co-firing coal and straw (or other biomass feedstocks) depending on the blending ratio, fuel properties, and combustion conditions.

Hein and Bemtgen (1998) studied the co-combustion of different biomass materials with coal in a range of pilot plants and large-scale power stations. They found that CFBs could be designed to handle the size of wood chips and that biomass addition suppressed SOZ emissions significantly for all FB facilities. Higher excess air for co-combustion of biomass and coal relative to pure coal combustion in a CFB was recommended by Werther et al. (2000) and Amand et al. (2001). Armesto et al. (2003) combusted a blend of coal and olive-oil-industry residue in a bubbling fluidized bed pilot plant to study the effect of operating conditions on the emissions and combustion efficiencies. They found that the share of residue in the mixture (10-25% on a mass basis) did not affect the combustion efficiency, although there was a significant influence on SOZ emissions due to the calcium and potassium content of the biomass. Generally the flue gas passes to an electrostatic precipitator or bag filter to have particulate matter removed. Sulphur can be removed using flue gas desulphurization, whereas oxides of nitrogen can be controlled by modifications to the burners. Clean-up systems for N[O.sub.x] such as selective catalytic reduction (SCR) and selective non-catalytic reduction (SNCR) can also be adopted. Each of these technologies can be used in co-firing systems with little or no modification.

Large portions of Cl-rich biomass (meat and bone meal (MBM) and refuse-derived fuel (RDF)) have been co-fired with selected coals without operational problems (Aho et al., 2008). As mentioned above, the sulphur and aluminosilicates present in coal can capture alkalis from alkali chlorides and release HCI, preventing Cl from condensing on superheaters as alkali chlorides. HCI does not bring chlorine to the deposits. The key reactions are sulphation and alkali aluminum silicate formation (Aho et al., 2008). Increased kaolinite (A[1.sub.2][Si.sub.2][O.sub.5] [(OH).sub.4]) and decreased alkali contents in the coals improved alkali capture, allowing larger contents of Cl-rich biomass in co-firing without Cl deposition (Ferrer et al., 2005). Ca/S ratios >3 can provide effective S[O.sub.2] capture. High S/Cl ratios (>4) can facilitate sulphation (Salmenoja et al., 1996; Fernandez, 1998). High Al/Cl ratios can lead to effective alkali aluminum silicate formation if a significant portion of the aluminum is present as active kaolinite (Fernandez and Curt, 2004; Aho and Ferrer, 2005; Ferrer and Aho, 2005). (Na + K)/Cl > 1 indicates an excess of alkalis for formation of alkali chlorides (Aho et al., 2008). Chlorine concentration in some fuels, such as straw, can be reduced by fuel pre-treatment with water. This can also have a beneficial effect on ash fusion temperatures (Jenkins et al., 1998).

Dioxins that might be expected appear to be destroyed within the furnace when temperatures are >1000[degrees]C, but may be formed in the cooling region downstream by de novo synthesis. The fate of certain trace elements in biomass and wastes has not been fully established. Most heavy metals appear to be trapped within the ash. Although further tests are needed in this area, co-firing appears to be advantageous in many respects.

Handling and Feeding of Biomass

Different chemical compositions and peculiar physical properties (e.g. low bulk density and high MC) can significantly influence the design and operation of handling and feeding systems. A separate feeding system is frequently provided for the biomass component of the fuel. Drying, size reduction, storage, transportation, feeding, and handling of biomass fuels present problems in achieving stable conditions. Large particle size, high MC, irregular shapes and low bulk density tend to promote feed rate irregularities. Co-feeding of blended fuels, for example coal and biomass, presents more problems than separate feeding.

Although direct co-firing affects combustion behaviour and ash handling, if the proportion of biomass in the coal is small (e.g. <10% on an energy basis), the effect of biomass addition has been found to be insignificant (Table 2) for packed bed, fluidized bed, and entrained flow reactors, with significant economic and environmental benefits (Sami et al., 2001). Feeding of blend fuels is not straightforward. For example, pre-mixing of some biomass feedstocks (e.g. straw) and coal was not feasible due to segregation of the two materials. In addition, slightly higher MC of the biomass can cause feeding of blend fuels to be unstable or to fluctuate (Dai, 2007). Separate feeding mitigates the feeding and ash problems for co-firing of biomass and coal at the expense of higher investment costs. In many co-firing plants, biofuels are pre-mixed with coal (or other materials) before feeding into the boiler (Granada et al., 2006). If the limestone is fed with the coal for capture of sulphur, the limestone may also be pre-mixed with the coal and biomass.

Various measures can be applied to avoid or reduce problems in biomass or blend feeding. Densified biomass (pellets and briquettes) is one option. Pellets are appropriate for coalfired plants (Bergman et al., 2005; Maciejewska et al., 2006) because modification of biomass properties addresses the source of the problems, rather than their consequences. The high costs of pelletization can be justified by better operability of the fuel (handling, transportation, storage, and feeding), resulting in improved boiler and combustion performance. The importance of pre-treatment is likely to increase with the tendency to utilize low-quality biomass. Another interesting option, especially for herbaceous biomass (currently rarely considered for co-firing) might be a pre-treatment process combining torrefaction and pelletization to allow co-utilization of high ratios of low-quality biomass with coal in existing coal systems without major modifications. This pre-treatment option has not yet been commercialized, so that environmental impacts, large-scale performance and economics are currently unknown (Maciejewska et al., 2006).

Bulk material handling and feeding are widely described in the literature. Various options such as hoppers or lock hoppers, screw feeders (Dai, 2007), conveyor belts (Abbas et al., 1994), and pneumatic feeding systems (Tmej and Haselbacher, 2000; Sami et al., 2001; Dai, 2007), have proved to be suitable for different kinds of biomass. The feeding system should be designed to handle the specific fuel flow properties. The most common feeding system for pellet stoves is a screw auger driven by a slow-moving high-torque motor fed from a hopper (Granada et al., 2006). Screw feeders may cause fuel flow fluctuations and segregation of pellet and forest residues when fed by the same screw. Because of segregation during storage and different feeding behaviour of pellet and forest residue, different chambers are needed in a hopper to obtain steady flow and to control mixing (Granada et al., 2006). Pelletized biomass (dried during processing to a low MC) can be successfully processed by coal mills, but this route is expensive (Segrest et al., 1997). More research is required for blend feeding.

CONCLUDING REMARKS

(1) Both biomass and coal can benefit from co-firing. Co-firing in coal plants can strongly increase biomass use and reduce the emissions of greenhouse gases and other pollutants at low capital and operational cost (compared to dedicated biomass plants).

(2) Direct co-firing is the most popular current option for biomass and coal co-firing, with modest investment cost to turn existing coal power plants into co-firing plants. Direct co-firing of biomass and coal takes advantage of the high efficiencies obtainable in large coal-fired power plants and improves combustion due to the higher volatile content of the biomass. The cost of parallel co-firing is significantly higher than the direct option, but may assist in optimizing the combustion process and in utilizing difficult fuels with high alkali and chlorine contents. Indirect co-firing can keep the biomass ashes separate from the coal ashes, while allowing very high co-firing ratios. However, indirect co-firing requires relatively high unit investment costs.

(3) Although more research is needed, there is already a wealth of practical experience for different conditions. For direct cofiring, the physical characteristics and chemical composition of the fuel entering the combustors or gasifiers are critical to their operation. Any biomass mixed with coal needs to have acceptable physical properties. For low co-firing ratios (< 10 thermal), there appears to be no irresolvable issues. Higher capital costs of advanced co-firing configurations may be justifiable due to better operability and flexibility of the system. For higher co-firing ratios, additional research is needed. The trend in co-firing is to increase the ratio of biomass/coal, and to utilize a wider range of biomass fuels.

(4) Combining torrefaction and pelletization, with leaching biomass, and combining biomass pyrolysis with char washing are interesting options for pre-treatment processes, especially for herbaceous biomass (which currently is not often considered for co-firing).

(5) Chemical composition and particle physical properties affect reactor performance (e.g. fouling, agglomeration, and quality of fluidization). Trouble-free feeding is crucial for the success of co-firing.

(6) More research is needed on co-firing biomass and coal including work on: preparation, handling, storage, and feeding of biomass feedstocks (e.g. drying, torrefaction, pelletization); co-firing mechanisms; hydrodynamic analysis of co-firing combustors and gasifiers; boiler/gasifier capacity, slagging, fouling, corrosion, efficiency, reliability, fuel flexibility; lower emissions and gas cleaning; catalyst poisoning; investment and operating costs.

(7) In all the co-utilization technologies considered, there are technical problems and limitations that have not yet been fully resolved. However, none of the perceived technical issues appears to be unsolvable.

NOMENCLATURE

A Blake-Kozeny-Carman constant
B Burke-Plummer constant
[C.sub.d] drag coefficient
[d.sub.n] projected area diameter (m)
[d.sub.v] volume-equivalent diameter (m)
[H.sub.b] bed height (m)
[K.sub.1] = [(dn/3[d.sub.v]) + (2/3)[[psi]sup.-o.s].sup.-1]
[K.sup.2] = [10.sup.1.8148(-log[psi])sup.O.5743]
Re particle Reynolds number
[U.sub.mf] minimum fluidization velocity (m/s)
[u.sub.t] terminal settling velocity (m/s)

Greek Symbols

[DELTA]P pressure drop (Pa)
[[epsilon].sub.mf] void fraction at minimum fluidization
[[micro].sup.f] dynamic viscosity of fluid (Pa s)
[rho] density (kg/m3)
[[rho].sub.f] fluid density (kg/m3)
[[rho].sub.P] particle density (kg/m3)
[psi] sphericity

Abbreviations

ar as received
b-dRDF binder-enhanced densified refuse-derived fuel
BFBC bubbling fluidized bed combustion
CFBC circulating fluidized bed combustion
daf dry ash-free
db dry basis
DTA differential thermal analysis
EFG entrained flow gasification
FBC fluidized bed combustion
HC hydrocarbons
HHV higher heating value
LHV lower heating value
MBM meat and bone meal
MC moisture content
PFBC pressurized fluidized bed combustion
SCR selective catalytic reduction
SNCR selective non-catalytic reduction
TGA thermogravimetric analysis
VM volatile matter
wb wet basis
wt weight

Subscripts

ave average

b bulk density
mf minimum fluidization velocity
p particle
v volume

Mannscript received December 24, 2007; revised Mannscript received February 15, 2008; accepted for publication February 21, 2008.

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Jianjun Dai, * Shahab Sokhansanj, John R. Grace, Xiaotao Bi, C. Jim Lim and Staffan Melin

Department of Chemical and Biological Engineering, University of British Columbia, 2360 East Mall, Vancouver, BC, Canada V6T I Z3

* Author to whom correspondence may be addressed.

E-mail address: djianjan0a chml.abc.ca Can. J. Chem. Eng. 86:367-386, 2008 [c] 2008 Canadian Society for Chemical Engineering DOI 10.1002/cjce.20052

Table 1. Properties of different biomass fuels compared with coal (a)

Fuel LHV Volatile Ash Ultimate analysis
 (daf) matter content % w/w (daf)
 MJ/kg % w/w % w/w
 (daf) (dry) C H O N S

Straw 18.2 81.3 6.6 49 6 44 0.8 0.2
Wood 18.7 83 1.8 50.5 6.1 43 0.3 0.1
Bark 16.2 76 7 50.5 5.8 43.2 0.4 0.1
Rape oil 35.8 100 0 77 12 10.9 0.1 0
Peat 19 74.2 2.7 52.6 5.8 40.6 0.9 0.1
Bituminous 31.8 34.7 8.3 82.4 5.1 10.3 1.4 0.8
coal

(a) Chmielniak and Sciazko (2003).

Table 2. Examples of co-firing projects

System description Fuel type and heating Blend parameters and
 value HHV (kJ/kg) feeding methods

Grate-fired boiler Coal/wood chips blends. 10-20% (energy basis)
(electricity or Wood: birch, aspen, wood; blend feeding,
steam generation) spruce. spreader stokers with
 HH[V.sub.coal] = 22 605; travelling grates; fly
 HH[V.sub.wood] = 17 742 ash re-injection
 system; 35-41% moisture
 for blend fuel

Spreader Coal and refuse-derived Blend feeding and
stoker-fired fuel (softwood waste) separate feeding; for
boiler (140-300 kW the pulverized coal
(fuel)) and a facility, blend
pulverized coal feeding, and separate
boiler (38 kW feeding with biomass as
(fuel)) a reburn fuel after the
 recirculation zone

Multi-circulating Coal/straw/wood chips 18-49% biomass (mass
fluidized bed blends; heating values basis); blend feeding
combustor (MCFBC) not available and separate feeding
(power generation,
20 MWe)

Pressurized FBC Blend of straw with coal Blend feeding
(1.6 M[W.sub.th])

Fluidized bed Coal and wood, straw, Blend feeding;
combustor and municipal sewage emissions of
 sludge S[O.sub.2], CO, and
 N[O.sub.x] decreased
 with increasing
 wood/coal ratio

CFBC combustion Federal coal, straw, and
systems (250 MWe sewage sludge
CFBC at Gardanne)

CFB boiler Milled peat, wood fuels Blend feeding and
(295 M[W.sub.th]) (sawdust, bark, cutter separate feeding
(Rauhalahti chips, forest chips)
Municipal CHP (20%, heat basis) and
Plant, Finland) coal. MC (wt%, wb): 45%
 (peat); 45-50% (wood
 fuels); LHV (daf,
 MJ/kg): 10 (peat); 7-9
 (wood fuels)

BFB boiler Wood waste (35%), coal Blend feeding; the fuel
(42 MWe) (Steam (50%) and RDF (15%, heat mix is fed to the FBCs
plant #2, Tacoma, basis) overbed, while
Washington) limestone is added
 directly to the beds
 for S[O.sub.2]
 absorption

CFB boiler Coal (59%, energy Direct co-firing, not
(132 M[W.sub.th]) basis), recycled pulping available for blend or
 chemicals (35%), bark separate feeding
 and wood waste (5%), and
 oil (1%)

CFBC boiler (35 Coal (60%, heat basis) Direct co-firing, not
MWe) (Slough Heat and a densified RDF available for blend or
and Power Ltd.) material (40%). HHV separate feeding
 (daf, MJ/kg): 18 (RDF)

CFBC boiler Wood chips, bark, Direct co-firing, not
(55 M[W.sub.th]) sawdust and rejects from available for blend or
 cardboard production. separate feeding
 MC(wt%, wb): 10% (coal)
 and 46% (biofuels). LHV
 (daf, MJ/kg): 24.5
 (coal) and 8.2
 (biofuels)

CFBC Coal and straw (50% Separate feeding. The
(88 M[W.sub.th]) energy basis) shredded straw was fed
(Elsam, Denmark) pneumatically through
 air locks to the boiler
 injection loop seals

CFBC boiler Coal, RDF, wood waste, Blend and separate
(110 M[W.sub.th]) sewage sludge, and a feeding; fuels of lower
(Austria Energy range of specific bulk density that are
and LLB Lurgi, industrial wastes RDF, wood waste, and
Lenzing, Austria) specific industrial
 wastes are injected
 pneumatically into the
 combustion chamber.
 Coal and sewage sludge
 were fed into the
 return leg from the
 seal pot

Front wall-fired, Bituminous coal and Direct co-firing, blend
pulverized coal sawdust (5% mass basis); feeding
boilers (182 MWe) about 95% of the
 screened material was
 <1/8" and 67% was <1/16"
 in size

Wall--fired Coal and sawdust (<12% Separate injection
pulverized coal heat basis)
boiler (32 MWe)
(Seward Station)

Wall-fired boiler Coal/switchgrass blends. 15% co-firing (mass
Burners HH[V.sub.coal] = 25 500; basis); blend feeding;
(50 MW (fuel)) HH[V.sub.switchgrassl] = 12 wt% (wb) moisture
 15 997 in biomass

Wall-fired boiler Coal/straw/cereal 0-100% biomass firing
Burners blends. Heating values (heat basis); fuel with
(500 kW (fuel)) not available higher nitrogen content
 should be injected in
 fuel rich zone to
 reduce N[O.sub.x];
 Optimum co-firing ratio
 60%; blend and separate
 feeding

Wall-fired dual Coal/sawdust blends. Coal and sawdust fed
fuel burner HH[V.sub.coal] = 32 260; separately. Coal: 74%
(500 kW (fuel)) HH[V.sub.sawdust] = <90 [micro]m, sawdust:
 18 140 75% <1.4 mm

Tangentially fired 5% wood derived biofuel Blend feeding
and wall-fired PC (heat basis) was
boilers (Kingston co-fired
and Colbert power
plants)

Laboratory-scale Pulverized coal, rice Fuel mixture supplied
pulverized fuel husk, and bamboo; by a variable speed
combustion testing Coal size: 75-106; screw conveyor from
facility Biomass: 100-300 storage bin; pulverized
 [micro]m, coal and biomass were
 MC: 8-16 wt% (wb); transported by primary
 HH[V.sub.coal] = 27 463. air. Biomass blending
 HH[V.sub.rice husk] = ratio 0%, 20%, 30%,
 16 054. 40%, 50%, and 100% on
 HH[V.sub.bamboo] = mass basis
 17 296

Cyclone coal Coal and crossties (<25 Blend feeding, wood
boiler (175 MWe) wt%). Crossties size: blended with coal by a
(manufactured by <1 mm coal yard scraper and
Babcock & Wilcox) dozer to measure and
 mix the materials in
 the coal yard prior to
 pushing the blend to
 the reclaim hoppers.
 Blend was then loaded
 on conveyor belt prior
 to crusher house

Cyclone coal Bituminous coal and Blend of coal and paper
boiler (165 MWe) paper pellets (5 wt%) pellets was bunkered on
(Gannon Generating a 24-h basis during the
Station) 21 d. No control over
 the blend once it was
 introduced to the
 bunker

Cyclone-fired Coal/b-dRDF blends. 12% co-firing (mass
Combustor (440 MWe HH[V.sub.coal] = 14 388; basis), blend feeding;
Power generation) HH[V.sub.RDFl] = 12 955 19 wt% (wb) moisture in
 biomass

Down-fired Coal/manure blends 100 g/min blend feed
concentric swirl HH[V.sub.coal] = 26 535; rate; 20% manure (mass
burner HH[V.sub.manure] = 8650 basis)
(35.4 kW (fuel))

Supercritical PF Coal and straw (20% on Separate burners
coal-fired power energy basis); coal and
station (600 MWe sewage sludge (20% on
Amer 9 power energy basis)
station)

System description Technical difficulties Reference

Grate-fired boiler Difficult blend mixing; Sampson
(electricity or Stoker capacity problems et al. (1991)
steam generation)

Spreader Brouwer
stoker-fired et al. (1995)
boiler (140-300 kW
(fuel)) and a
pulverized coal
boiler (38 kW
(fuel))

Multi-circulating Coal and wood injected Hansen et al.
fluidized bed at bottom, straw (1995)
combustor (MCFBC) injected with secondary
(power generation, air; no steady output of
20 MWe) gaseous alkali metals

Pressurized FBC Co-firing reduced the Andries et al.
(1.6 M[W.sub.th]) CO, N[O.sub.x], and (1997)
 S[O.sub.2]
 concentrations in the
 freeboard

Fluidized bed Wood is the most Van Doorn
combustor favourable co-firing et al. (1996)
 fuel in terms of ease of
 combustion and reduced
 emissions of N[O.sub.x]
 and S[O.sub.2]. For
 co-firing straw, HCl
 concentration increased
 with larger straw/coal
 ratios; co-firing sewage
 sludge with coal caused
 agglomeration

CFBC combustion Jacquet et al.
systems (250 MWe (1994),
CFBC at Gardanne) Rajaram (1999),
 McIlveen-Wright
 et al. (2007)

CFB boiler Melting of ash did not Rauhalahti
(295 M[W.sub.th]) occur. However, deposits (2005)
(Rauhalahti formed on superheaters
Municipal CHP when the combustion of
Plant, Finland) fresh forest chips
 started

BFB boiler Bed temperatures are Tacoma
(42 MWe) (Steam maintained at (2005)
plant #2, Tacoma, ~840[degrees]C to
Washington) minimize ash
 agglomeration and
 maximize sulphur capture

CFB boiler Spring
(132 M[W.sub.th]) (2005)

CFBC boiler (35 Slough
MWe) (Slough Heat (2005)
and Power Ltd.)

CFBC boiler Stora (2005)
(55 M[W.sub.th])

CFBC Several short-duration Grena (2005)
(88 M[W.sub.th]) failures occurred due to
(Elsam, Denmark) excessive cutter wear
 and compacted bales with
 wet intrusions. Dry
 comminuted and/or
 pelletized biomass fuels
 were used with separate
 storage and supply
 systems

CFBC boiler Lenzing
(110 M[W.sub.th]) (2005)
(Austria Energy
and LLB Lurgi,
Lenzing, Austria)

Front wall-fired, Mixing and handling Colbert
pulverized coal problems; moisture (2005)
boilers (182 MWe) content variation (the
 blends were mixed by the
 natural path through the
 transfer points and the
 bunker and pulverizers)

Wall--fired Boiler efficiency loss Seward
pulverized coal was ~0.5%; slight impact (2005)
boiler (32 MWe) on unburnt carbon; CO
(Seward Station) emissions always were
 <20 ppmv, indicating no
 problem with combustion
 completeness. Favourable
 impact on S[O.sub.2],
 NO, and C[O.sub.2]
 emissions

Wall-fired boiler No slagging, normal unit Aerts et al.
Burners operation, N[O.sub.x] (1997)
(50 MW (fuel)) decreased by 20%; some
 traces of partially
 burned switchgrass in
 ash

Wall-fired boiler Three different burner Siegel et al.
Burners configurations studied (1996)
(500 kW (fuel)) (burner efficiency and
 optimization)

Wall-fired dual 81-90% burnout; Abbas et al.
fuel burner N[O.sub.x] reduced, (1994)
(500 kW (fuel)) optimum co-firing ratio:
 30% (mass basis) for
 maximum burnout and
 minimum N[O.sub.x]; fuel
 injection mode depends
 on reactivity and
 [N.sub.2] in biomass

Tangentially fired Due to pulverizer Sami et al.
and wall-fired PC performance and fuel (2001)
boilers (Kingston particle size, 5% (heat
and Colbert power basis) co-firing was
plants) found to be the
 limiting case

Laboratory-scale VM and MC very Chao et al.
pulverized fuel important in affecting (2008)
combustion testing combustion time,
facility particle, and PAH
 emissions. Particle size
 did not significantly
 affect combustion
 performance

Cyclone coal Blending wood with coal Thomas
boiler (175 MWe) with further reduction (2005)
(manufactured by of wood particle size
Babcock & Wilcox) worked well; S[O.sub.2]
 emissions decreased by
 7%; particulate
 emissions decreased by
 12%; N[O.sub.x]
 emissions increased 8%.
 No significant handling
 problems during testing

Cyclone coal Biggest problem in Gannon
boiler (165 MWe) co-firing was pluggage (2005)
(Gannon Generating in the conveyor feeder;
Station) there was no impact on
 unburned carbon in the
 flyash; problem
 experienced for low and
 high feed rates was
 variability in the
 steaming rate of the
 boiler due to the
 variations in heat input
 from the varying blend
 going to the boiler

Cyclone-fired N[O.sub.x] reduction of Ohlsson
Combustor (440 MWe 2-3%, S[O.sub.2] (1994)
Power generation) reduction 17%,
 particulate
 concentration (heat
 basis) increased by
 about 50%

Down-fired Crushing manure to same Frazzitta
concentric swirl size as coal difficult; et al. (1999)
burner S[O.sub.x] and
(35.4 kW (fuel)) N[O.sub.x] decreased
 with blend combustion,
 easy ignition with blend

Supercritical PF Flue gas Breihofer
coal-fired power desulphurization (FGD) et al. (1991),
station (600 MWe Gramelt (1994),
Amer 9 power McIlveen-Wright
station) et al. (2007)

Table 3. Comparison of different combustion technologies (a)

Reactor Advantages Disadvantages
type

Packed bed Low investment costs for Mixtures of wood fuels
combustion plants <20 [MW.sub.th] and can be used, but mixtures
(grate low operating costs (van combustion behaviour and
furnaces) Loo and Koppejan, 2004); of fuels with different
 can use almost any type ash melting points (e.g.
 of wood (Veijonen et al., blends of wood with straw
 2003); appropriate for or grass) are not
 biomass fuels with possible (van Loo
 high moisture content (10-60 and Koppejan, 2004);
 wt% wb) (Tuurna, 2003; van increase of temperature
 Loo and Koppejan, 2004). may cause ash melting
 Suitable for fuels with high and corrosion (Tuurna,
 ash content and varying 2003)
 particle sizes (with a
 limitation regarding the
 amount of fine particles)
 (van Loo and Koppejan, 2004)

Fluidized Large fuel flexibility in Despite the flexibility
bed calorific value, moisture with regard to fuel
combustion content, and ash content, specifications, it is not
 enabling fuel always possible to use the
 diversification and existing feeding system
 increasing the scope of for biomass by premixing
 fuels in existing power the fuels (the cheapest
 plants; combustion option). In cases where
 temperature in bed is low, the feeding characteristics
 resulting in low [NO.sub.x] of the co-fired fuels vary
 emissions (EC, 2000; van too much from the primary
 Loo and Koppejan, 2004); fuel, a separate feeder
 provides an option to needs to be installed;
 directly inject limestone slagging and fouling on
 to remove sulphur boiler walls and tubes
 cost-effectively (instead when burning fuels with
 of FGD equipment), high alkali content; Bed
 maximized combustion agglomeration when burning
 efficiency even with fuels of high alkaline and/
 low-grade fuels; or aluminum content;
 environmental performance of Cl-corrosion on heat
 FBC installations is good, transfer surfaces (e.g.
 with low emissions of superheater tubes) (EC,
 CO (<50 mg/[Nm.sup.3]), 2000); high investment
 [NO.sub.x] (<70 mg/MJ, after costs, interesting only
 the boiler, eventually for plants >20 [MW.sub.th]
 reduced to less than 10 mg/ for BFB and >39
 MJ when using SCR) and high [MW.sub.th] for CFB, low
 boiler efficiencies (about flexibility in particle
 90%) (EC, 2000); Fluidized size, high dust load in
 bed technology can be the flue gas, loss of bed
 converted from coal to material with the ash
 biomass/coal co-combustion (van Loo and Koppejan,
 with relatively little 2004); incomplete
 investment (Veijonen et combustion of fuels and
 al., 2003) high unburned carbon
 content in the ash,
 especially in CFB
 (Maciejewska et al.,
 2006)

Pulverized Increased efficiency due to Particle size of biomass
fuel or low excess oxygen, high is limited to <10-20 mm
dust [NO.sub.x] reduction (van Loo and Koppejan,
combustion possible when appropriate 2004). Low moisture content
 burners used (van Loo and required (typically <15
 Koppejan, 2004) wt%, wb) for pneumatic
 feeding and decreased
 efficiency for
 high-moisture fuels

(a) Maciejewska et al. (2006).

Table 4. Comparison of coal and biomass combustion (a)

Items Biomass Coal

Particle size Relatively large and Relatively small
 wide range and narrow range

Particle size Wide Narrow
distribution
Particle shape Irregular Relatively regular
Moisture content High Low
Reactivity Higher Lower
Volatile matter Higher Lower
content
Devolatilization Lower temperature Higher temperature
Pyrolysis (b) Earlier Later
Specific heating Lower Higher
value of volatiles
(MJ/kg)
Fractional heat ~50-70% (Chao et ~30%
contribution by al., 2008)
volatiles
Char More oxygen Less oxygen
Combustion rate Slightly higher Slightly lower
of char
Ash More alkaline, Less alkaline
 chlorine

(a) Sami et al. (2002) and Demirbas (2005).

(b) Temperature at which pyrolysis occurs depends on fuel type
and heating rate.

Table 5. Sample calculations for coal and some biomass feedstocks

 Ground
 American Wood wood
 Federal pellets pellets-1
Fuel types Coal (a) (a,b) (a,b)

Proximate
analysis

 Water (wt%, ar) 6.3 5.43 5.43
 Ash (wt%, ar) 6.22 2.55 2.55
 Volatiles 87.48 79.16 79.16
 (wt%, ar) (daf) (daf)
 Fixed carbon 47.91 47.91
 (wt%, ar) (daf) (daf)

Ultimate analysis
(wt%, daf)

 Carbon 84 51 51
 Hydrogen 5.7 6 6
 Oxygen 6.06 42.9 42.9
 Nitrogen 1.5 0.05 0.05
 Sulphur 2.6 0.05 0.05
 Chlorine 0.14 0 0
 HHV (MJ/kg daf) 35.64 18.71 18.71
 LHV (MJ/kg daf)

Physical
properties

 Average size 0.5 9.8 4
 (mm) (d)
 Shape (e) Spheroid Cylinder Cuboid
 ([PHI] ([PHI]
 6.5 x 15) 3.2 x 3.2
 x 3.2)
 Sphericity 1 0.82 0.81
 Particle 1500 1200 1200
 density
 (kg/[m.sup.3])
 Bulk density 810 630 485
 (kg/[m.sup.3])
 Voidage 0.46 0.48 0.6

Calculations (f)

 (1) Sole coal
 or biomass
 Power (HHV, 60 60 60
 MW)
 Fuel flow rate 1.68 3.21 3.21
 (kg/s, daf)
 Fuel flow rate 1.92 3.48 3.48
 (kg/s, wb)
 Oxygen molar 130 150 150
 flow rate
 (mol/s)
 Air mass flow 17.8 20.59 20.59
 rate (kg/s)
 Air volumetric 43.88 50.75 50.75
 flow rate
 ([m.sup.3]/s)
 Bed radius 0.9 0.9 0.9
 (or side
 dimension)
 (m)
 Superficial 17.24 19.94 19.94
 gas velocity
 in reactor
 (m/s)
 Min. 0.12 3.4 2.76
 fluidization
 velocity-1,
 [U.sub.mf]-1
 (m/s) (g)
 Min. 0.09 2.98 2.32
 fluidization
 velocity-2,
 [U.sub.mf]-2
 (m/s) (h)
 Drag 2.93 1.13 1.08
 coefficient,
 [C.sub.d] (i)
 Terminal 2.8 17.86 11.71
 velocity,
 [U.sub.t],
 (m/s) (j)

 (2) 50 wt%
 biomass in
 coal/biomass
 blend
 Average 709 607
 blend bulk
 density (kg/
 [m.sup.3])
 (k)
 Average 1333 1333
 blend
 particle
 density (kg/
 [m.sup.3])
 (l)
 Average 0.47 0.54
 voidage of
 blend fuel
 (m)
 Average 0.9 0.89
 sphericity
 (n)
 Average 5.67 2.44
 particle
 size (mm)
 (o)
 Average 2.41 1.52
 minimum
 fluidization
 velocity
 (m/s) (p)

 Wheat Switch-
 straw grass
Fuel types (a,c) (a)

Proximate
analysis

 Water (wt%, ar) 10.6 7.17
 Ash (wt%, ar) 4.07 4.62
 Volatiles 85.33 88.21
 (wt%, ar)
 Fixed carbon
 (wt%, ar)

Ultimate analysis
(wt%, daf)

 Carbon 48.84 43.58
 Hydrogen 7.08 5.83
 Oxygen 42.36 5.02
 Nitrogen 1.28 4.00
 Sulphur 0.16 0.00
 Chlorine 0.28 0
 HHV (MJ/kg daf) 19.9 21.61
 LHV (MJ/kg daf) 18.2

Physical
properties

 Average size 0.91 0.91
 (mm) (d)
 Shape (e) Disk Disk
 ([PHI] ([PHI]
 1 x 0.5) 1 x 0.5)

 Sphericity 0.83 0.83
 Particle 500 500
 density
 (kg/[m.sup.3])
 Bulk density 160 160
 (kg/[m.sup.3])
 Voidage 0.68 0.68

Calculations (f)

 (1) Sole coal
 or biomass
 Power (HHV, 60 60
 MW)
 Fuel flow rate 3.02 2.78
 (kg/s, daf)
 Fuel flow rate 3.53 3.15
 (kg/s, wb)
 Oxygen molar 135 111
 flow rate
 (mol/s)
 Air mass flow 18.54 15.23
 rate (kg/s)
 Air volumetric 45.69 37.54
 flow rate
 ([m.sup.3]/s)
 Bed radius 0.9 0.9
 (or side
 dimension)
 (m)
 Superficial 19.59 16.09
 gas velocity
 in reactor
 (m/s)
 Min. 0.37 0.37
 fluidization
 velocity-1,
 [U.sub.mf]-1
 (m/s) (g)
 Min. 0.27 0.27
 fluidization
 velocity-2,
 [U.sub.mf]-2
 (m/s) (h)
 Drag 3.62 3.62
 coefficient,
 [C.sub.d] (i)
 Terminal 1.96 1.96
 velocity,
 [U.sub.t],
 (m/s) (j)

 (2) 50 wt%
 biomass in
 coal/biomass
 blend
 Average 267 267
 blend bulk
 density (kg/
 [m.sup.3])
 (k)
 Average 750 750
 blend
 particle
 density (kg/
 [m.sup.3])
 (l)
 Average 0.64 0.64
 voidage of
 blend fuel
 (m)
 Average 0.87 0.87
 sphericity
 (n)
 Average 0.81 0.81
 particle
 size (mm)
 (o)
 Average 0.29 0.29
 minimum
 fluidization
 velocity
 (m/s) (p)

(a) Huang et al. (2006).

(b) Lu et al. (2007).

(c) McIlveen-Wright et al. (2007).

(d) Equivalent volume diameter.

(e) Assumed particle shape.

(f) Based on 830[degrees]C, 1 atm and 10% excess air, bed materials
(e.g. silica sand and dolomite) are not considered.

(g) Based on [Re.sub.mf] = [square root of ([C.sup.2.sub.1] +
[C.sub.2][A.sub.[tau]] - [C.sub.1])] with consideration of sphericity
and voidage of particles.

(h) Based on modified Ergun equation.

(i) Based on modified drag coefficient for irregular single
particle without wall effects.

(j) Based on [u.sub.t] = [square root of ([4gd.sub.v] ([[rho].sub.p] -
[[rho].sub.f])/(3[[rho].sub.f][C.sub.D]) for single particle without
wall effects.

(k) [[rho].suub.b,ave] = ([m.sub.coal] + [m.sub.biomass])/
([m.sub.coal]/[[rho].sub.b,coal] + [m.sub.biomass]/
[[rho].sub.b,biomass]).

(l) [[rho].sub.p,ave] = ([m.sub.coal] + [m.sub.biomass])/
([m.sub.coal]/[[rho].sub.p,coal] + [m.sub.biomass]/
[[rho].sub.p,biomass]).

(m) [[epsilon].sub.ave] = (1 - [[rho].sub.b,ave]/[[rho].sub.p,ave]).

(n) Calculated and averaged according to particle volume fraction
of each type of particle in the blend.

(o) Calculated and averaged according to particle volume fraction
of each type of particle in the blend.

(p) Based on modified Ergun equation.

Table 6. Physical and chemical characteristics of biomass feedstocks
and their effects on co-firing (a)

 Properties Effects

Physical Moisture content Storage durability
properties Dry-matter losses
 Low LHV
 Self ignition
 Bulk density Fuel logistics (storage,
 transport, handling) costs;
 storage and feeding problems
 (e.g. bridging and
 stoppage)
 Ash content Dust, particulate emissions,
 ash utilization problems,
 disposal costs
 Particle size, size determines fuel feeding
 distribution, and shape system, Determines combustion
 technology, drying properties,
 dust formation, operational
 safety during fuel conveying

Chemical Carbon (C) HHV (position)
composition Hydrogen (H) HHV (positive)
 Oxygen (O) HHV (negative)
 Chlorine (Cl) Corrosion
 Nitrogen (N) [NO.sub.x], [N.sub.2]O, HCN
 emissions
 Sulphur (S) [SO.sub.x] emission, corrosion
 Fluorine (F) HF emissions, corrosions
 Potassium (K) Corrosion (heat exchangers,
 superheaters), lowering of
 ash melting temperatures,
 aerosol formation, ash
 utilization
 Sodium (Na) Corrosion (heat exchangers,
 superheaters), lowering ash
 melting temperature, aerosol
 formation
 Magnesium (Mg) Increase of ash melting
 temperature, ash utilization
 Calcium (Ca) Increase of ash melting
 temperature, ash utilization
 Phosphorus (P) Increase of ash melting
 point, ash utilization
 Heavy metals Emissions of pollutants, ash
 utilization and disposal
 issues, aerosol formation

(a) EBA (2000), van Loo and Koppejan (2004) and Maciejewska
et al. (2006).