Biomass gasification involves pyrolysis and partial oxidation in a well-controlled oxidizing envi­ronment. It leads to products, such as H2, CO, CO2, H2O, and hydrocarbon species. The heat required for biomass drying, heating and pyrolysis is provided by the partial oxidation of biomass. Gasification is deemed as the most promising technology for producing renewable and carbon — free energy, as it provides tremendous flexibility with regards to feedstock and the fuels produced. In general, the gasification process converts low value biomass to a gaseous mixture containing syngas (mixture of H2 and CO) and varying amounts of CH4, and CO2. It can also produce hydrocarbons, particularly in the lower temperature range. The oxidizing agents can be pure O2, air, steam, CO2 or their mixtures. The syngas composition can be varied by using air and steam as the gasification agent (Rapagna, 2000). Moreover, the presence of CO2 can be used to increase H2 and CO contents, as it transforms char, tar and CH4 into H2 and/or CO in the presence of a catalyst such as Ni/Al (Ollero, 2003). Table 2.1 from (Jones et al., 2003; Giles, 2003) lists the representative compositions and properties of syngas used in various Integrated Gasification Combined Cycle (IGCC) facilities. As indicated, syngas has a wide composition range due to a large variety of source materials and processing techniques.

Numerous studies have been reported in recent years, dealing with the type of reactors used for gasification, thermo-chemical processes involved, and various gaseous and liquid fuels produced during gasification. Wang et al. (2008) and Gill et al. (2000) provide reviews of work on biomass gasification. As discussed in these reviews, significant advances have been reported in biomass gasification technology and syngas utilization. The syngas can be used to generate heat and power, for example, in an IGCC facility (Rodrigues et al., 2003), produce H2 (Watanabe, 2002), and synthesize other chemicals and liquid fuels such as F-T fuels (Tijmensen, 2002). Gill etal. (2000) summarize the various routes for the utilization of syngas, including the production of F-T and other transportation fuels. As discussed by Gill et al. (2000), the global reactions associated with syngas formation from biomass (CH„) include:

Reaction (2.1) corresponds to syngas formation in the presence of O2, while reaction (2.2) is the well-known water-gas-shift-reaction and reaction (2.3) is associated with the steam reforming of methane. Reactions (2.2) and (2.3) are used to control the H2/CO ratio. The production of F-T fuels from syngas involves a series of reactions in the presence of a catalyst. The global reactions for this process can be written as:

nCO + (2n + 1)H2 ^ CnH2n+2 + nH2O (Paraffins) (2.4)

nCO + 2nH2 ^ CnH2n + nH2O (Olefins) (2.5)

The first step during F-T formation is the conversion of syngas into -CH2- alkyl radicals and H2O. The — CH2- alkyl radicals then combine in a catalyst reaction to produce synthetic paraffin and olefin hydrocarbon (HC) fuels of various chain lengths. The amount and type of fuels formed are determined by parameters such as temperature, pressure, H2/CO ratio, and the type of catalyst. In general, F-T fuels can be produced from a variety of solid, liquid, and gaseous sources, and further processed to yield clean transportation fuels with desired specifications. Gill et al. (2000) provide an overview of technologies, including Biomass-to-Liquid (BTL) and Coal-to-Liquid (CTL) Gas-to-Liquid (GTL) processes, for producing various fuels through gasification and F-T processes.

Regardless of feedstock or process, F-T fuels have a number of desirable properties. For example, F-T diesel fuels can be produced with a high cetane number, with ultra-low sulfur and aromatic content, with the consequence of improved engine performance, significantly lower particulate mass (PM) emissions and favorable NOX/PM trade-off. However, these fuels generally have poor lubricity and lower volumetric energy density. These shortcomings can be alleviated by blending these fuels with petro-fuels. Thus, the biomass gasification can be used to produce syngas and subsequently clean drop-in transportation fuels. The effects of F-T fuel properties on engine performance and emissions have been reported by a number of investigations (Abu-Jrai et al., 2006; Schaberg et al, 2005; Wu et al., 2007). Gill et al. (2000) illustrate the improved HC/NOX tradeoff achieved with advanced injection timing using the GTL fuel compared to petro-diesel and rapeseed methyl ester (RME) biodiesel fuels.

A better understanding of the NO emissions can be observed when the fuel nitrogen content and the NO emitted are compared as shown in Figure 3.37. It can be observed that as the blend ratio is increased the fuel nitrogen content increases. Thus one would expect the formation of fuel NO to increase as the blend ratio is increased. On the contrary, the NO generated decreases. In the situation where the NO formation is only through fuel nitrogen, it is remarkable to observe that increasing FB content in cofired fuel does not necessarily lead to higher NO emissions. The trend is observed at different excess air ratios. Thus, the use of FB not only serves as a means of waste disposal, but also reduces the emissions. The reduction of NOX with coal:FB blends is due to better grindability of FB compared to fibrous DB.

3.8 REBURN

Previous sections dealt with co-firing of FB and DB with coal in conventional boiler burners. In this approach, the high temperatures produced by the coal allow for the successful combustion of the FB. A 30 kW Boiler Burner Facility was built at Texas A&M and co-firing was performed which revealed better combustion of coal with FB and similar or less NOX when cofired with coal even though FB has 2 and 4 times the N content of coal on a mass and heat basis. Small — scale co-firing tests were followed by pilot plant tests at the 500 kW facility of National Energy Technology Laboratory of DOE-Pittsburgh with similar results (Annamalai et al., 2003b, 2003c). Further, the VM of CB on DAF basis was almost twice that of coal. The large amount of volatile content of the biomass in the blend consumes oxygen rapidly in the near-burner region, thereby creating more localized fuel-rich zones, and hence less NO is formed. In addition, it is believed that most of the N in FB exists as NH3, the volatile matter of FB is twice that of coal and hence NOX emission did not increase. If so, the CB can serve as effective reburn fuel forNOx reduction. A premixed propane and trace amounts of NH3 were burnt to simulate coal combustion gases and use NH3 to produce NO in the main burner, and then test coal and feedlot biomass as reburn fuel.

The experiments were conducted in the Texas A&M laboratory scale boiler burner that was modified for reburn experiments. The boiler is a 30 kW (100,000 Btu/h) downward-fired furnace

made up of a steel shell encasing ceramic insulation. A schematic of the entire setup is shown in Figure 3.38. A premixed propane burner is mounted at the top of the furnace to produce hot furnace gases to simulate the products of coal combustion. Ammonia is injected into the premixed propane fuel stream and burnt in the primary zone. The primary or main burner zone equivalence ratio (фм) is typically <1 indicating excess O2. The reburn fuel is fed from a dry solids feeder, through a venturi inductor value, and injected through the reburn ports. The reburn injection ports are located below the tip of the premixed propane flame, after all of the NO has been formed in the primary zone. The reburn zone below the main burner receives excess O2 left from the main burner and the O2 from the reburn injector operated at equivalence ratio ф^. Thus the reburn zone equivalence ratio (фкв, ъ) is adjusted both by фм, фкв and fraction of thermal output (x) released by reburn as shown below.

Consider a reburn facility operated with total thermal rating of P [kW]. The main fuel M is fired at an equivalence ratio фм (< 1) such that it has a rated thermal output of PM = (1 — x)P. The reburn fuel R is fired at fR (> 1) such that its rated power output is PR = x P. The fR is adjusted so that the reburn zone equivalence ratio is ф^^ Then a relation between фкв can be obtained in terms of фм, ф^^ HHVO2,M and HHVO2,RB of main fuel and return fuel, and x, fraction of heat by reburn fuel:

The 0KB was adjusted to obtain the desired equivalence ratio 0kbZ from 1 to 1.1 (Fig. 3.39). An Enerac 3000E gas analyzer is then used to measure the concentration of oxygen and NO in the final sampling port. After passing by the gas sampling port, the furnace gases are cooled by a water spray and exhausted out of the building. There is no burnout zone in the current boiler burner configuration. Figure 3.40 shows the results; it is seen that NOX reduction is highest for FB due to (i) increased VM of FM, which reduces local O2, (ii) release of N probably in the form of NH3.

Currently, experiments are in progress on coals, and CB to determine the percentage nitrogen distribution between HCN and NH3. However, we have recently analyzed data presented elsewhere (Di Nola, 2009), which demonstrated that adding animal waste to coal increased the ratio of NH3 relative to HCN. It is noted that the emissions of HCN and NH3 are not expected under combustion conditions.

The fuel N evolved as NH3 undergoes oxidation reaction with O2 and reduction reactions with HCN and NH3. The overall competing reactions for “thermal” (i. e. temperature dependent) De-NOx process is as follows:

2NO + 2NH3 + (1 /2)O2 ^ 2N2 + 3H2O, destruction of NO, 871-1204°C (1600-2200°F)

(3.40)

2NH3 + 2.5O2 ^ 2NO + 3H2O, oxidation of NH3, T > 1204°C (2200°F) (3.41)

The upper end of the temperature window is caused by the rapid growth of chain carriers which enhances reactions involving the oxidation of NH2 eventually producing NO instead of reducing it (Lyon et al, 1986). Sometimes the upper end could be as high as 1204°C (2200°F) (EPA). Exxon had empirically determined that NOx reduction is effective at T < 955°C (1750°F). Typically reactions are faster in the presence of O2 but not in excess amounts; these reactions suggest that the stoichiometric ratio of mole of NH3 to mole of NO is about 1; the actual amount of NH3 needed for the reaction is much greater than the theoretical amount because NH3 reacts with several other gases in the flue gases, not just NOx. The literature suggests that one needs about

0. 5-3 moles of NH3 per mole of NOx. The Selective Noncatalytic Reduction process (SNCR) temperature window is about 900°C to 1100°C. To facilitate quick and inexpensive predictions with the thermal De-NOx method, two competitive reaction formulations have been used for modeling purposes. One may use an empirically based model (Lyon, 1987), which includes the following forward direction only competitive reactions (Thien et al., 2012):

Reaction A: 4NH3 + 4NO + O2 ^ 4N2 + 6H2O (fast)

Reaction B: 4NH3 + 5O2 ^ 4NO + 6H2O (slow)

NH3 oxidation, >1480K

d(NO)/dt, NO production/reduction rate per unit volume, {kmol/(m3 s)} = kB (NH3) — kA (NH3) (NO)

d(NH3)/dt, NH3 consumption rate per unit volume, {kmol/(m3 s)} = — kB (NH3) — kA (NH3) (NO) where (NH3), (NO) concentrations in kmol/m3 and the specific reaction rate constants k’s are defined as

3 17 (— 29400

ka, {m3/(kmol s)} = 2.45 x 1017 exp(———- —— j, T inK

kB, {1/s} = 2.21 x 1014expl———- ——j, T inK

Since O2 is in excess typically and others are in trace amounts, reaction A depicts the second — order reduction of NO to N2 and the reaction B represents the first order oxidation of NH3 (Duo et al., 1992).

It can be seen from the values of the two activation energies and the overall rate constants how the simple model was able to predict the temperature window for NO reduction (1145 to 1480 K). Figure 3.41 shows typical model results for an initial NO of 600 ppm and assumed NH3/NO = 2 at 1100 K. The model results showed that when NH3/NO was set to 1, the rate of reduction slowed down and when NH3/NO = 0.5, the NOx reduction was only 50%. While pure FB produces a

Figure 3.41.

high amount of NH3, coal:FB blends result in lesser NH3 concentration; similarly lesser reburn heat input will result in lesser NOX (Oh, 2008).

It is apparent that coal and FB can both be successfully used a rebum fuel in order to reduce NO in a boiler burner. Feedlot Biomass is almost two times more effective as a reburn fuel than coal. The NO reduction is more effective at higher reburn equivalence ratios for coal; however, the NOX reduction is almost independent of equivalence ratio for feedlot biomass. The behavior of coal-biomass blends falls in between the behavior of coal and biomass. The greater effectiveness of feedlot biomass may be due to the release of fuel nitrogen in the form of NH3, and its high volatile content on a dry ash-free basis (Annamalai and Sweeten, 2005).

The key technology of biomass gasification research and development is usually based on the gov­ernment’s advanced investment, then the industry world and business world would follow-up and quickly realize the technology industrialization and commercialization. The Chinese government realized the issue “total risk, share results” by strengthening the public-sector research institutions and private sector cooperation and effectively led the development of the biomass gasification technology initiative. The Chinese Academy of Sciences Guangzhou Institute of Energy carried on the MW level biomass gasification power generation system research in the Ninth Five-Year Plan period, aiming at developing medium-size biomass gasification power generation technol­ogy for Chinese market demand and resource characteristics. Its power demonstration system was completed in October 1998 and put into use.

“Agricultural Biomass Industry Development Plan” introduced in 2007 submitted the recent focus on gasification technology: first, continue to expand the scope of straw gasification demon­stration and perfect the biogas technology of straw production. The second is to strengthen and standardize the operation and management of straw gasification stations. The third is to solve the problem of high tar content in the straw gasification fuel and improve the stability of the system. The planning also proposed that China would build 1000 straw gasification gas stations till 2015, and annual output gas straw would reach 365 million cubic meters.

The reactor types suitable for biomass gasification can be simply categorized into fixed beds and fluidized beds according to the relative motion between solid and gas and the bulk density of the solid-phase in the reactor. The principal types of gasifiers are: downdraft or co-current fixed beds, updraft or counter-current fixed beds, cross-draft fixed bed, bubbling fluidized beds and fast or circulating fluidized beds. Additional types include the entrained bed and the fluidized bed twin-reactor concept (Bridgwater, 1995). In general one gasifier technology is not appropriate for the full range of applications, i. e. there is a suitable range of applications for each gasifier technology. In the case of the fluidized bed technology and the entrained flow, the range is >10 MW and >100 MW, respectively.

6.4.1.1 Fixed bed

In a fixed bed gasifier, the fuel is supported on a grate where the fuel moves down in the reactor as a plug. This type of gasifier is generally suitable for small-scale operation in the range of 10kW-10MW In Table 6.2 the three main types of fixed bed technologies are compared.

6.4.1.1.1 Updraft gasifiers

The fixed bed updraft gasifier has been the principal gasifier of use for coal for about 150 years. A schematic of an updraft gasifier is shown in Figure 6.6a. In this gasification concept, the biomass is fed into the top of the reactor, and the air or oxygen into the lower zone. The fuel (and the resulting char) flows slowly down and passes sequentially through drying, pyrolysis, gasifica­tion and combustion zones by gravity. In parallel is the pyrolysis vapors carried upward by the up-flowing hot product gas. Ashes are removed by an ash discharge system at the bottom of the gasifier.

In the lower gasification zone, the solid char from pyrolysis and tar cracking is partially oxidized by the incoming air or oxygen. Steam may also be added to provide a higher level of hydrogen in the gas. The sensible heat of the product gas is recovered by direct heat exchange with the entering fuel feed, which thus is dried, preheated and pyrolyzed before entering the gasifier. The product gas temperatures are relatively low, 300-600°C, since the heat is used for preheating, drying and pyrolysis of the incoming fuel.

The tars in the pyrolysis vapor will either condense on the cool descending fuel particles or be carried out of the reactor with the product gas, thus contributing to its high tar content. The extent of this tar bypassing may be up to 20% of the pyrolysis products. The condensed tars are recycled back to the reaction zones, where they are further cracked to gas and char. The product gas from an updraft gasifier contains a significant proportion of tars and hydrocarbons, and these contribute to the relatively high heating value of the gas. The product gas requires substantial clean-up if further processing of the product gas is to be performed.

The dust content of the gas is, however, relatively low because of the filtering effect of the drying and pyrolysis zones and the moderate gas velocities.

Updraft gasifiers can handle fuels with moisture contents up to 60 wt% and particle sizes between 5 and 100 mm, thus covering a wide span of fuels and fuel sizes. In principle is there no upper limitation with respect to size, this in contrast to the downdraft gasifier. The principal advantages of updraft gasifiers are their simple construction and high thermal efficiency.

Although it may be a seemingly unrelated sector of American industry, researchers at Texas A&M have contended that energy production facilities, particularly coal-fired power plants, can benefit from co-firing of animal-wastes based biomass with coal. It can also minimize the CO2

emissions by reducing the amount of fossil fuels used for heat and energy and the resulting emissions from fossil fuel power plants. Nitrogen oxides (NOX), sulfur oxides (SOX), mercury (Hg), and particulates have all been scrutinized emissions from coal-fired power plants, and restrictions on these products of combustion will probably continue to rise. Of course, animal biomass combustion will not solve global climate change alone; however, as discussed by (Pacala et al., 2004), biomass combustion can be one of many wedges of advancement that can create an energy economy capable of sustaining our climate and our way of life. Direct combustion of biomass, combustion basics including stoichiometry, excess air, underfire and over fire air are dealt in Chapter 5 of this book (Desideri and Fantozzi, 2013).

There is also a great potential in the European Union (EU) to use animal waste based biomass to co-fire in existing coal-fired power plants. In 2011, the 27 EU member countries had a total cattle livestock of over 87 million with more than 23 million dairy cows. The animal numbers are projected to shrink because cattle herds are getting more productive. Annual reductions are estimated at 1.1% in 2012 to an 84.4 million head (TX PEER, 1998). The corresponding manure produced by cattle in 2009 was nearly 1300 million tonnes (Osei etal., 2000). Five different paths for energy production from cattle biomass (CB) or any suitable animal wastes are illustrated in Figure 3.5 (Carlin et al, 2007):

• Biological conversion

1. Biogas and bio-liquid fuels

• Thermal conversion

2. Direct slurry combustion (Carlin et al., 2007)

3. Co-firing of dried solids with coal

4. Reburn

5. Gasification.

The utilization of animal manure in combustion/gasification facilities can help ease the impacts large CAFOs, including dairies, have on the environment.

The municipal solid waste (MSW) in China has increased at a rate of 8-10% in recent years (Bie et al., 2007) due to the fast growth of the economy. It is expected by the REDP project (2005) that 210 million tonnes of MSW can be used in 2020 for methane production. Recently, the use of waste oil for biodiesel is very popular especially in south China. However, lack of accessible resources significantly blocks the further development of the biodiesel industry. Meanwhile, some other ways of using MSW for energy were analyzed in 2005 (Li et al., 2005) and using MSW for landfill gas (LFG) was considered as having great potential.

China Industrial Waste Management, Inc. is well positioned to serve this market need as a comprehensive environmental services and solutions provider. For example, recently an energy efficiency center has been established in Dalian to provide our customers with consulting ser­vices, such as energy auditing of buildings and industrial plants, energy management programs, municipal energy efficiency planning, and other related services.

China Industrial Waste Management, Inc. is engaged in the collection, treatment, disposal and recycling of industrial wastes principally in Dalian and surrounding areas in Liaoning Province, People’s Republic of China through its 90%-owned subsidiary Dalian Dongtai Industrial Waste Treatment Co., Ltd. (“Dongtai”) and other indirect subsidiaries. Dongtai treats, disposes of and/or recycles many types of industrial wastes, and recycled waste products used by customers as raw material to produce chemical and metallurgy products. In addition, Dongtai treats or disposes of industrial waste through incineration, burial or water treatment, and provides environmental protection services, technology consultation, pollution treatment services, waste management design processing services, waste disposal solutions, waste transportation services, onsite waste management services, and environmental pollution remediation services.

China is the world’s largest producer of MSW, producing over 223 million tonnes in 2008, and this is growing by 8-10% annually. The country produced 1.9 billion tonnes of industrial waste in 2008, an 8.3% increase from 2007, and of which 13.6 million tonnes were classified as hazardous waste. The predominant method of treatment is disposal by landfill, which accounts for about 80% of total treated MSW, followed by incineration and composting. However, faced with problems with upgrading landfills, most cities’ landfills in China are not categorized as sanitary, with less than 10% meeting international standards. Thus, the key direction for many cities is incineration, especially for cities, which are more economically developed and have more capital to build incineration facilities, especially on the east coast.

4.1.1 Wood processing remainders

Currently, over 3 million hectares of firewood forest is available in China, thus acquiring 80 to 100 million tonnes biomass with high heating value. As for shrub forest, it covers the area of over 45 million hectares. Firewood forest, shrub harvest and forest greenery may produce 0.1 billion tonnes biomass, thus offering 0.3 billion tonne biomass fuel in the forest industry alone.

The fuel particle can be simplified as a sphere that undergoes an endothermic process that is regulated by the equation of thermal exchange (Tillman, 1991):

Q = (A x A)/r x (T1 — T2) (5.13)

where:

A = thermal conductivity [W/mK]

A = area [m2] r = radius [m].

The temperature of the process varies, as a function of three steps:

(i) heating from ambient temperature to 105°C, to reach evaporation temperature that is higher than 100°C because of inter-molecular forces that bind water inside the woody cell;

(ii) drying at 105°C: this is an isothermal phase in which water leaves the woody particle, the evaporation front moves to the center of the particle generating a series of pores through which water and volatiles produced by pyrolysis will pass. The drying will continue until all the water contained in the biomass will evaporate. It is not a simultaneous process for all the layers of the sphere; in particular the external layer undergoes an immediate drying and it is not affected by pyrolysis but undergoes immediate combustion generating a layer of ashes that isolates from oxygen and heats the particle; the steam escaping from the particle contributes to the evacuation of ashes from the particle.

(iii) heating at temperatures higher than 105°C. The heat is exchanged to particles through:

• Radiation: from the flame and from the walls of the combustion chamber;

• Conduction: from adjacent particles and from the walls of the combustion chamber;

• Convection: due to turbulence and convective motions inside the combustion chamber.

As a result of this phase:

(i) the wood particle shrinks by 7-17% in volume (Haygreen and Bowyer, 1982) and the material begins to crumble and crack; this produces an important reduction of the size (shrinkage) of the fuel;

(ii) the diameter of the fuel pores also decreases reaching even 5-10 A (Skaar, 1972).

The governing equation of the drying phenomenon is Ficks second law of diffusion (Chen et al., 2012):

V( Deff(V MR))

where:

MR represents the moisture ratio of biomass (Vega-Galvez et al., 2011), expressed by the following equation: MR = (M — Me)/(M0 — Me) where M0 is the initial moisture content of the sample and Me is the equilibrium moisture content of the sample Deff represents effective diffusivity of moisture [m2/s] (Vega-Galvez et al., 2010).

Effective diffusivity (Deff) is generally determined using experimental drying curves; on the other hand the temperature dependence of the effective moisture diffusivity can be represented by an Arrhenius relationship and derived using TGA analysis:

where:

D0 = pre-exponential factor of the Arrhenius equation [m2/s]

Ea = activation energy for the moisture diffusion [kJ/mol]

R = ideal gas constant [J/mol x K]

T = drying temperature [°С].

The activation energy can be calculated by plotting ln(Deff) vs. the reciprocal of the temperature 1/(T + 273.15).

Most of the available literature on catalytic gas cleaning for biomass gasification involves nickel catalysts. The nickel catalysts are typically supported on materials such as a-alumina, magnesia, magnesium aluminum spinel and calcined zirconia. They perform best as secondary catalysts located in a separate reactor downstream, which can be operated under different conditions than those of the gasifier. Tar contents of 4mg/m3N and less have been reported (Aznar, 1993). The Ni-based catalysts designed for steam reforming of heavy hydrocarbons seems to be active for tar removal (Arauza, 1997).

In principle no tar is formed as long as the Ni-catalyst is active, deactivation is due to sulfur poisoning, carbon fouling and (thermal) sintering of the nickel particles. The problem with sulfur poisoning increases with pressure and secondary Ni-based fixed beds tends to deactivate easier than the secondary fluidized ones.

Carbon deposition, and hence, catalyst deactivation may be reduced by introducing a guard bed of dolomite or by adding dopants to the catalyst, such as lanthanum (Sutton, 2001). By using a guard bed of dolomite, the removal of tar up to 95% can be achieved, followed by the adjustment of the gas composition and final tar cracking using a second catalytic nickel bed.

The nickel-based catalysts are commercially available and effective in the removal of hydro­carbons and adjustment of the gas composition to syngas quality. However, the nickel catalysts have potential drawbacks vis-a-vis cost, intolerance to oxygen breakthrough and disposal.

By applying a parallel reaction model the activation energies of different types fuel such as DB, sorghum, LARM, LAPC, HARM, HAPC, and TXL can be determined (as Table 3.5).

3.7 IGNITION

3.9.1 Ignition temperature

TGA analysis can also be used to determine the ignition temperature of a fuel when experiments are performed in an air environment. Each fuel was first analyzed in a nitrogen environment and then analyzed again in an air environment. The TGA traces of the two fuels began similarly, but upon ignition, the fuel would oxidize if air was present. Ignition caused the two TGA traces to

deviate. The temperature at which this deviation occurred was defined as the ignition temperature (Fig. 3.18). For the mass loss traces obtained during testing, ignition is defined as the point at which the difference between the moisture normalized traces begin to deviate by more than 5% of the average value at that point and continue to deviate thereafter (Lawrence, 2007):

(m%)N2 — (m%)air

(m%)N2 + (m%)air
2

This is best illustrated graphically as in Figure 3.18.

The ignition behavior of the biomass fuels was analyzed with similar independent variables as those used to analyze the activation energy behavior (Table 3.6). Figure 3.18 gives the temperature [K] at which ignition of the fuel sample is said to have occurred according to the definition.

The results show that the fixed carbon content of the fuel, particle size, and coal: FB blend ratio had very little effect on the ignition temperature of the fuel. The fixed carbon content for all the fuels tested is given in Table 3.7.

*Computed from HHVdaf & VMdaf *HHVvm + FCdaf *HVfc where HVfc & 32765 kJ/kg of carbon (Chapter 4, Annamalai and Puri, 2007).

Boie basedHHVVM in kJ/kg ofVM released & [35160 YC + 116225 YH — 11090 YO + 6280 YN + 10465 YSFC * HVfc]/VM], where VM, FC… Yc, Yh. .. are either in mass fractions as received or %.

The type of FB used also had little effect on the ignition behavior of the fuel. The overall average ignition temperature for those fuels, which had coal present, is 566 K with a standard deviation of only 2.9%. The only appreciable difference in ignition point temperature is for those fuels that were pure biomass. For the pure biomass fuels, no matter the particle size, the average ignition temperature is 747 K with a standard deviation of 2.7%, probably due to lower quality of volatiles from biomass fuels.

It can be seen from Table 3.8 that coal volatiles are of high quality compared to volatiles from biomass.

Baoying Xiexin Biomass Power Co., Ltd was put into operation in 2005. Baoying Xiexin Biomass Power Co., Ltd (hereinafter referred to as Baoying Xiexin) is located in Anyi industrial zone in Anyi town, of Baoying coutry in Yangzhou. It is an environmental Combined Heat and Power (CHP) enterprise invested to build by Hong Kong Xiexing group (Holding) Limited Company.

Main equipments (boiler, steam turbine unit, etc.) of the plant have been running steadily without any serious failures since units 1 and 2 were put into operation in 2005. There were some problems in unit 3 about the feed system and combustion system in the initial operation period. But through technicians’ repeated debugging and exploration, the problems had been solved preliminarily and the plant could operate normally, which is a successful case of the co-combustion model.

Fuel is the key to ensure power plants operate continuously and steadily. The plant uses two different kinds of fuels, biomass (renewable) and coal (non-renewable). Non-renewable fuels include coal, peat and low quality coal.

The biomass used is not only the rice husk but also a large number of crop straws, rice straw, wheat straw and so on. It is worth noting that distribution and collection of rice husk and straw are completely different.

The mixed fuels are not only rice husk but also a large amount of rice straw, wheat straw and other soft straw in Baoying Xiexin. Fuel feeding is distinctive and the plant owns two sets of feeding systems, one of co-combustion and the other of direct combustion.

The feeding process of co-combustion is as follows: Boilers 1 and 2 share the same feed­ing system. Then the biomass fuels (mainly rice husk) are sent to respective feeding pipes by scraper conveyor and electric three-way valve, which can control the amount of feeding biomass simultaneously, and finally biomass together with coal are sent into the furnace.

Similar to the power plant in XinYuan Fengxian, this plant also adopts Combined Heat and Power, with power generation mainly and heating supplement secondly. In 2006, total power generation was 2.24 billion kWh and net generation to grid was 206 million kWh. Grid electricity price (tax included) was 0.646 Yuan/kWh and the plant sold the power to Jiangsu Electric Power Company.

Because mixing ratio of the plant satisfies the requirements, the plant received electricity price subsidy of 0.25 Yuan/kWh inNovember 2007. Net power price, including tax, is 0.646 Yuan/kWh at present, which was 0.469 Yuan/kWh before. At the same time, the name of the plant was changed from Baoying Xiexin Biomass Environmental Protection Thermoelectric Co., Ltd. to Baoying Xiexin Biomass Power Co., Ltd.