Category Archives: Technologies for Converting Biomass to Useful Energy

Shiliquan power plant

In China, the first co-combustion coal and straw system was operated successfully in Shiliquan power plant ofHuadian Power International Co. LTD. inDecember 16,2005. This was a important breakthrough in the field of biomass power generation in China.

The straw power generation technology of the Shiliquan power plant was introduced from Denmark, with which the number 5 boiler (140 MW) was optimized and integrated a 30 MW straw combustion system. In the system, purchase, stockpile, pulverization and conveying equipment for straw have been added, and at the same time two straw burners have been installed at the left and the right wall of the boiler. The air feed system and the associated control system have also been remolded, but the original boiler combustion system has not been altered. Keeping the performances and the parameters of the original boiler constant, the improved boiler can combust the mixture of pulverized coal and straw, also it could combust the pulverized coal alone. This is the first combustion for a power generation project using the mixture of straw and pulverized coal that is remolded on an old generating unit in China. If the generation unit runs for 7236 hours per year, it will consume more than 1.05 million tonnes of straw, which means 7.56 million tonnes of raw coal can be saved, whose thermal value is 5000 kcal/kg. This will bring the local peasants more than 30 million RMB per year. Compared with the coal power, the generating unit remolded by the straw power generation can reduce the sulfur dioxide exhaust by 1500 tonnes per year, it can also lighten the atmospheric pollution of harmful gas like carbon dioxide, carbon monoxide and the suspended particulate effectively, which are produced through combusting the straw by the peasants.

Chemical looping processes

Chemical looping processes are still under development to reach full scale and commercial opera­tion and availability. This is due to the fact that conventional processes, such as those described in the previous chapters, are efficient from an energy conversion point of view, are well known and are based on simple technical components that have been constantly improved over the centuries.

Now that the focus is shifted to environmental performance of combustion processes and greenhouse gases mitigation, the conventional technologies are showing their limits in allowing an efficient and cost effective separation of pollutants and greenhouse gases from the flue gases.

The irreversibility of the chemical reactions processes is so high that inverting the process requires a large amount of energy and complex technologies.

Most chemical looping processes currently studied and under development use a solid medium to perform the reactions.

The first chemical looping processes were developed in the early 20th century to produce hydrogen from carbonaceous fuels, using steam: the so-called steam-iron process. The global reaction is the following:

CO + H2O ^ CO2 + H2 (5.34)

The following reactions take place in two different reactors, using as looping medium iron and iron oxide:

Fe3O4 + 4CO ^ 3Fe + 4CO2


3Fe + 4H2O ^ 4H2 + Fe3O4

In the second reaction iron is oxidized by steam producing hydrogen and in the first reaction the iron oxide is reduced by CO to regenerate the oxide to Fe and produce CO2. This process was abandoned when more efficient systems based on natural gas and oil reforming was being developed to produce hydrogen. However, a similar system was later developed to produce CO2 from solid carbonaceous fuels. This process was based on two fluidized bed reactors using a metal oxide as medium. The process is depicted in Figure 5.24 and either iron or copper oxides may be used. The development of these early chemical looping processes to produce technical gases was prompted by the need of separating gases at a time when no other separation technologies were available.

More recently a renewed interest was raised by the need of separating gases from mixtures in much more efficient systems. In a process developed at Ohio State University (Fig. 5.25) Fe2O3 particles are introduced into the reducer with pulverized coal, which is gasified producing CO and H2. Since the syngas has reducing properties, Fe2O3 is converted to Fe and FeO, while producing CO2 and H2O. Steam can be easily condensed and CO2 can be therefore removed from the flue

image278 image279
Подпись: MeO, Hopper
Подпись: MeO,
Подпись: Metal
Подпись: Generator

image284image285Recycle CO.-

Figure 5.24. Chemical looping process for CO2 production (Fan, 2010; Lewis and Gilliland, 1954).





Подпись: Oxidizer Подпись: @ ►H, Подпись: /Steam) turtone



Fe C

Figure 5.25. Coal-Direct Chemical Looping Process (Rizeq et al., 2002; Gupta et al., 2006).

gases. The Fe and FeO particles are introduced into the oxidizer where they react with steam to produce H2 and Fe3O4. While being conveyed to the reducer Fe3O4 will be oxidized to the original Fe2O3.

The use of chemical looping processes is possible with any carbonaceous fuel, including biomass, and can include gasification processes in the whole power plant.

A second process which is quite interesting for hydrogen production and CO2 separation is the HyPr-Ring Process which was developed in Japan in the 1960s and 1970s (Fig. 5.26). This process includes a gasifier, fed with coal, CaO, steam and oxygen, where the excess steam increases the


formation of H2, whereas CaO reacts with carbon dioxide generated in the water-gas shift reactor. The solid medium consists of CaCO3 and carbon which is burnt in the regenerator calcinating the calcium components to CaO and allowing the extraction of CO2.

General Electric has developed a chemical looping process where coal or biomass may be used to produce hydrogen and power. The technology is quite similar to the HyPr-Ring Process, but three fluidized beds are necessary to complete the reactions. In the first reactor, coal is partially gasified with steam producing a syngas rich in H2, CO and CO2. The latter reacts with calcium sorbents. The solids in the first reactor are calcium carbonate and sulfate and unburned carbon and are introduced in the second reactor where they are reduced by Fe2O3 entering from the third reactor. The flue gas from the second reactor is mainly composed by CO2 and SO2. The third reactor is used to regenerate the iron oxide with air. The heat of all reactors is used to generate steam and the hot air exiting the third reactor may be used in a gas turbine for power generation. In the end the GE CLC process produced power, hydrogen and allows separating CO2 for capture or any industrial use; the scheme of this process is depicted in Figure 5.27.

Alstom has developed a combustion-gasification process based on chemical looping where three different configurations are possible: (i) coal combustion; (ii) coal gasification for syngas production and (iii) coal gasification to produce hydrogen (Fig. 5.27).

When used as a coal combustion process, the calcium sulfate is reduced to calcium sulfide, which is then burnt in the second reactor with air. Heat is transferred from the combustor to the gasifier and to a lesser extent to a steam generator to produce high temperature steam. In the second configuration more coal and more sorbents are used and hydrogen and carbon monoxide, without any CO2. In the third configuration, pure hydrogen is produced by adding a third reactor where a calcination reaction occurs. Calcium oxide captures CO2 in the first reactor, separating H2. Calcium carbonate is calcinated by burning calcium sulfate, producing CO2 in the third reactor. The process is shown in Figure 5.28.

. Non-premixed and partially premixed syngas flames

Combustion in many practical devices involves non-premixed (diffusion) and partially premixed flames (Bozzeli etal., 1995). While there exist numerous studies of such flames with hydrocarbon fuels, relatively few investigations have appeared with syngas fuels. Giles etal. (2006) numerically studied the effects of N2, CO2, H2O, and CH4 addition on the structure and NOX characteristics of syngas diffusion flames in a counter flow burner. A diffusion flame in this burner is established by having two opposing jets being issued from two coaxial nozzles that are placed one above the other. Fuel is supplied from the bottom jet and air from the top jet, and the flame is established near the stagnation plane formed by the two jets. Diluents can be introduced through either or both the

Подпись: Figure 2.10.


Effect of adding N2, H2O, and CO2 in the airstream on the peak NO mole fraction and flame temperature for a syngas (50%H2/50%CO)-air diffusion flame (Giles et al., 2006).

jets. Simulations were performed using the OPPDIF algorithm and the GRI-3.0 mechanism. The algorithm computes the flow field and flame by solving the governing equations for temperature, species mass fraction, and velocity field. The 2-D axisymmetric flow field is transformed into a 1-D problem by employing a similarity transformation. Results indicated that syngas non­premixed flames are characterized by relatively high temperatures and NOX concentrations, and require diluents to control NOX emissions. Figure 2.10 from Giles etal. (2006) depicts the effects of three diluents (N2, H2O, and CO2) added to the airstream on the peak flame temperature and NO mole fraction for a 50%H2/50%CO syngas flame.

As the amount of dilution is increased, the flame temperature decreases with a corresponding reduction in the peak NO, indicating that NO formation in these flames is primarily be due to the thermal mechanism. CO2 and H2O are more effective than N2 in reducing NO, with CO2 being the most effective diluent on a mole basis. Giles et al. (2006) also observed that the presence of methane in syngas even in small amounts opens the prompt NO route, and decreases the diluent effectiveness in reducing NOX. Other studies on non-premixed syngas flames include those reported by Hui et al. (2007) and Park et al. (2004).

There have also been few investigations on syngas partially premixed flames (Hui etal., 2007). A partially premixed flame (PPF) in a counter-flow burner is established by introducing air from the top nozzle and a fuel rich mixture from the bottom jet. The important parameters characterizing a counter-flow PPF include the strain rate, equivalence ratio (Ф), and fuel composition. Som et al. (2010) investigated experimentally and numerically the influence of pressure and fuel composition on the combustion and NOX emissions in syngas PPFs. Figure 2.11 from this study depicts images oftwoPPFs established at Ф = 6 and 16, and strain rate as = 35 s-1. For Ф = 6, which is just above the rich flammability limit of 50%H2/50%CO syngas-air mixture, the flame exhibits a typical double flame structure with a weak rich premixed reaction zone (RPZ) established very close to the fuel nozzle and a non-premixed reaction zone (NPZ) on the oxidizer side near the stagnation plane.

As Ф is increased, the RPZ moves away from the fuel nozzle. Consequently, for Ф = 16, the RPZ and NPZ are much closer to each other. The computed structures of four syngas PPFs in terms of the profiles of temperature and heat release rate are shown in Figure 2.12. Two of these flames correspond to the same conditions as those for flames depicted in Figure 2.11. Again, for Ф = 6.0, the flame structure is characterized by two spatially separated reaction zones, namely the RPZ


Figure 2.11. Images of syngas (50%H2/50%CO)-air partially premixed flames established at Ф = 6 (Flame a) and Ф = 16 (Flame b) in a counter flow burner. The strain rate is 35s-1(Som etal, 2010).


Figure 2.12. Computed flame structure in terms of temperature and heat release rate profiles for four syngas (50%H2/50%CO)-air partially premixed flames. The two flames at strain rate as = 35 s-1 are the same as those depicted in Figure 2.13, while the other two flames are at as = 50 s-1 and Ф = 6 and 16.

and NPZ, which are easily located by the two heat release rate peaks. The RPZ is very close to the fuel nozzle, which is in agreement with the digital images presented in Figure 2.11. For Ф = 16, the temperature peaks indicate a nearly merged flame structure. However, the corresponding heat release rate profiles indicate two distinct peaks that are close to each other. This is again consistent with the digital images in Figure 2.11. At lower strain rates (as = 35 s-1), flame temperatures are slightly higher due to longer residence time.

Подпись: Figure 2.13.


Peak NO mole fraction plotted versus CO fraction in syngas for partially premixed flames established at Ф = 6 and different pressures (Som et al., 2010).

Som et al. (2010) further observed that for the conditions investigated, the RPZ is characterized by H2 oxidation, while the NPZ is characterized by the oxidation of both H2 and CO. This is in contrast to hydrocarbon PPFs, in which the fuel is partially oxidized to produce H2 and CO in the RPZ, and the oxidation of H2 and CO occurs in the NPZ. However, similar to hydrocarbon PPFs, as the pressure is increased, the distance between the two reaction zones decreases, while the flame temperature increases. The reader is referred to Figure 8 in Som etal. (2010) for further discussion of the flame structure at different pressures and syngas compositions. With regards to NO emission, results indicated that as the pressure is increased, the amount of NO formed first increases rapidly with pressure, but then levels off at higher pressures. This can mainly be attributed to the increase in flame temperature with pressure, which increases the thermal NO. In addition, the peak NO exhibits a non-monotonic variation with the H2 fraction in syngas, as shown in Figure 2.13. As the H2 fraction is increased, the peak NO first decreases and then increases. This can be attributed to the combined effects of thermal and re-burn mechanisms, as the syngas composition is changed.

The re-burn mechanism consumes NO through reactions NO + H + M ^ HNO + M and NO + O + M ^ NO2 + M, which become important at higher pressures and as the H2 fraction in syngas increases. However, when the H2 fraction exceeds a certain value, the peak NO starts increasing with the increase in H2 fraction, which is due to the effect of higher flame temperature, which increases thermal NO. The contributions of various NO formation routes are depicted in Figure 2.14 from Som et al. (2010) which plots the NO emission index with respect to pressure for two different syngas mixtures. The emission index is defined as the ratio of NO production rate to fuel consumption rate. As indicated in the figure, the N2H, NNH, and re-burn mechanisms become important at high pressures.

Ouimette and Seers (2009) reported an experimental investigation on syngas partially premixed jet flames. The effects of Ф, CO2 dilution, and H2/CO ratio on the flame structure and NOX were reported. Figure 2.15 from this reference presents images of syngas jet flames at different Ф. As expected, the flame length is strongly influenced by the level of partial premixing.

As Ф decreases from the non-premixed to premixed regime, the flame length decreases mono — tonically. This has important consequences for the emissions of NOX, greenhouse gases, and


Figure 2.14. Variation of emission indices of total, thermal, prompt, N2O, NNH and reburn NO mechanisms with pressure for syngas partially premixed flames (Som et al., 2010).

other pollutants, since the flame length directly influences the reacting volume and residence time. In addition, images at 2.0 and 1.6 indicate the existence of two reaction zones, with the NPZ enveloping the RZP Regarding NOX, results indicated that EINOX first increases as Ф is increased from 1.0 to 1.6, then remains nearly constant for 1.6 < Ф < 3.85, and subsequently decreases slowly as Ф is increased to the diffusion limit (Ф ^ X). In addition, results indicated that increasing CO2 dilution reduces EINOX in the entire range of Ф, consistent with previous studies while increasing the H2/CO ratio reduces EINOX for Ф < 2.0, and has negligible effect for richer mixtures.


In previous experiments the effects of blending coal with relatively high-ash/low energy content cattle

(plenum). The steam is generated by a steam generator built with a cylindrical 4-inch internal diameter vessel heated by a (1.2 kW) type tape heating element rolled around of the vessel with variable power output (0.1 to 1.2 kW); thus, the steam production rate can be controlled from 0.1 to 1.5 kg/h by changing the power supplied to the heater element. The sampling unit is composed of two condensers cooled with ice-cold water (0°C) to condense out the tar and the H2O in the products and a filter system to retain the particulate material. The temperature of the bed is measured every 60 seconds using K-type thermocouples (Cr-Al) placed at 8 locations along the gasifier axis. The gas samples are analyzed by a mass spectrometer (MS) continuously at real time (Gordillo, 2009).

3.13.1 Experimentation

The gasification experiments were performed for the following cases:

(a) Base case

• Bed height at 17 cm (~6%")

• Fuel: low ash separated solids dairy biomass (LA-PC-sepsol-DB).

• Particulate size, dp = ~6.25 cm (1/4") for DB and ~3 mm (~1/8") for coal

• Fuel flow rate 1 kg/h (2.2046 lbm/h)

• Air flow ~ 1.13 normal m3/h (40 SCFH) at 298 K (536 R)

• Steam flow rate at 0.3 kg/h (~0.66 lb/h)

• Equivalence ratio (ER) at 3.18

• Steam to fuel ratio (S:F) at 0.68

(b) Parametric cases

• Fuel: LA-PC-Sepsol-DB, Coal-LA-PC-Sepsol-DB blend (90% LA-PC-Spsol-DB, 10% coal), and Ash — LA-PC-Sepsol-DB blend (90% LA-PC-Sepsol-DB, 10% ash)

• Air flow between 0.57 and 2.26 normal m3/h (20 and 80 SCFH) at 298 K (536.4 R)

• Steam flow rate between 0.18 and 0.5 kg/h (0.4 and 1.1 lb/h) at 373 K (671.4 R)

• Equivalence ratio (ER) between 1.59 and 6.36

• Steam to fuel ratio (S:F) between 0.35 and 0.8

• Experiments with (i) DB-coal blends (90% DB-10% Coal) (ii) DB-ash blends (90% DB — 10% ash) were used in order to determine catalytic effect if any on gasification.

Biomass combustion and chemical looping for carbon capture and storage

Umberto Desideri & Francesco Fantozzi


5.1.1 Biomass and biofuels definition and classification

According to a general definition biomass may be considered as animal and plant resources and the wastes deriving from their treatment, which could be used, directly or after a pretreatment as a source of energy. It is therefore a resource directly or indirectly resulting from the photosynthesis process, represented by the following equation (Klass, 1998):

Living plant + CO2 + H2O + SunlightСЛl—^yU (CHmOn) + O2 — 480kJ/mol

For every mole of CO2 absorbed 1 mole of oxygen is released. Zhu etal. (2008) have shown that the maximum conversion efficiency of solar energy to biomass is 4.6% for C3 photosynthesis at 30°C and today’s 380 ppm atmospheric concentration of CO2, while C4 plants have an efficiency of about 6%. Losses are distributed thus: loss by reflectance of photo-synthetically active light (4.9% for example); loss in rapid relaxation of higher excited states of chlorophyll (6.6% for example); loss between the reaction center and carbohydrate synthesis (24.6% for C3 plants and 28.7% for C4 plants, for example); loss due to photorespiration (around 6.1% for C3 plants and 0% for C4 plants); loss due to respiration (1.9% for C3 plants and 2.5% for C4 plants). Figure 5.1 shows the minimum energy losses calculated for 1000 kJ of incident solar radiation.

Подпись: Sun Подпись: Energy loss Outside photosynthetically Active spectrum Reflected and transmitted Photochemical Inefficiency Carbohydrate synthesis Photorespiration Respiration

When considering its use as a fuel the interest is focused on combustible materials result­ing directly from silviculture, agriculture, aquaculture, farming, and the related transformation

Biomass 46 kJ Biomass 60 kJ

Подпись: Figure 5.1Minimum energy losses calculated for 1000 kJ of incident solar radiation (Zhu et al, 2008)

industries (e. g. wood and food industries), or indirectly through their preprocessing to obtain better performing fuels (biofuels) with respect to the initial state (Williams et al., 2012; Tillman, 1991).

Different classifications of biomass are possible according to their origin, characteristics or use; however from an energy point of view its importance is linked to its potential to yield a competitive biofuel that may replace a fossil fuel, therefore a useful classification should consider the environmental and economic effectiveness of its energy conversion. From this point view, since the primal transformation is photosynthesis, biomass energy content is somehow deriving from low density solar energy and, most important, biomass is a geographically distributed resource scattered on a wide area, as it is solar radiation.

This turns into a low energy content per volume product which needs to be produced, collected and transported hence its economic and environmental competitiveness is strongly dependent on the overall balance resulting from the different phases (supply chain).

According to this view, a possible general classification of biomasses (and/or biofuels) could consider different categories as a function of how many phases (and their resulting economic and environmental burden) are necessary to obtain available biomass as a fuel or as a feedstock to obtain a biofuel. Three categories therefore can be identified as follows.

(a) Energy crops: They are dedicated crops specifically cultivated for energy purposes. This is the worst performing category since the economic-environmental burden of the production phase and of the gathering-transportation phase is totally allocated to the final product. However these biomasses may provide a useful (sometimes unique) solution for agriculture revival in depressed or contaminated areas.

They can be divided into no-food crops and food crops depending on their possible competition as a raw material for the food industry.

Among the no-food crops short rotation crops such as woody (poplar, black locust, eucalyptus, etc.) and herbaceous crops (miscanthus, giant reed, kenaf, sorghum, etc.) are utilized for direct combustion or for second-generation bioethanol production as a source of cellulose. There is also an increasing interest in algae for biomass and oil production.

Among the food crops the main interest is in high sugar or starch content crops, for bioethanol production (corn, sugarcane, sugar beet, etc.) or oily fruits for oil extraction to use directly as a fuel or for the production of biodiesel (sunflower, rapeseed, palm and soybean).

(b) Residual biomasses: They are residues of agricultural crops and forestry maintenance. These biomasses do not comprehend the economic-environmental burden of the production phase, since its cost is allocated on the primary product (vegetables or wood) while still comprehending the burden of the gathering-transportation phase. The gathering in particular may still be an issue if the harvesting of the primary product does not consider a proper handling of the byproduct.

Residual biomasses comprise:

• Agricultural residues (pruning, straw, corn/sunflower/tobacco stovers, etc.);

• Forestry residues (pruning, branches, tops, sawdust etc.);

• Urban green residues (pruning, branches, sawdust, etc.).

(c) Agro industrial and farming residues: They represent the byproducts of the food, wood, pulp and paper, and animal farming industry. This is the best performing category since the economic- environmental burden of the production phase and of the gathering-transportation phase is totally allocated to the final product, leaving a cost free biomass available in a single site. Moreover these residues are often to be disposed of therefore their energy conversion could also represent an avoided cost.

They can be divided into: [5]


Figure 5.2. Reference base for solid fuel main components.

• urban and industrial residues (organic fraction of MSW (Municipal Solid Waste), sewage sludge, pallets and packaging residues, paper and cardboard, etc.).

With some notable exceptions (waste frying oils, cereal husks, paper and cardboard, etc.) most of agro-industrial residues have a very high humidity content which is not suitable for direct combustion application, while biological treatment such as anaerobic digestion is preferable.

A general classification of biomass can be found in UNI-EN 14961-1 “Solid biofuels: Fuel specifications and classes — Part 1: General requirements (EN 14961-1, 2010)”.

Cross-draft gasifers

A cross-draft fixed bed gasifier variant of a so-called co-current fixed bed gasifier where the fuel is fed from the top and the air from the side. The difference from the downdraft version is the product gas outlet on the side opposite of the air inlet. A schematic is shown in Figure 6.6.

The air is introduced in the reactor at high velocity creating a hot zone, also called the hearth, with a temperature above 1500°C due to combustion of part of the char. The remaining char is gasified to CO in the subsequent zone. The heat from the combustion is conducted to the pyrolysis zone where the fresh biomass is pyrolyzed when passing. The cross-draft is generally used for small-scale units and allows for a simple reactor construction due to the small combustion zone and the insulating effect of the fuel and the ash. Due to the high temperature, the concentration of tar in the product gas is low, as shown in Table 6.2, and therefore a fairly simple gas cleaning system can be used after the reactor.

Proximate and ultimate analyses

The results of the proximate, ultimate (or elemental), and heat value analyses of the fossil and various animal waste based biomass fuels and coals are presented in Table 3.3. In general, the cattle biomass fuels are higher in ash, lower in heat content, higher in moisture, and higher in nitrogen and sulfur (which can cause air pollution) compared to the Texas and Wyoming coals. The HV of a fuel is the amount of heat released when a unit (mass or volume) of the fuel is burned. Typically, bomb calorimeters are used to determine the HV. Table 3.3 tabulates the higher or gross heat values of animal-waste-biomass (AWB) (Table 3.3). Generally, the HHV of CB on a dry, ash-free basis (DAF) tends to be between 18,000 and 22,000 kJ/kg (average about 20,000 kJ/kg) depending on the animal’s feed ration (Sweeten et al., 2003) while coals on DAF basis yield about

30,0 kJ/kg. Since DAF HHV is almost constant, it is the moisture and ash, which reduce the heat value and affect the flame temperatures as shown in Figure 3.5.

Using ultimate analyses, one can determine the empirical chemical formula. If the overall carbon content of gasoline is 82.6% (by mass) and hydrogen is 17.4%, then the empirical formula is given as C = (82.6/12.01) = 6.88, H = 17.23 or the empirical formula is C6.88H17.23 or after normalization with C atoms, CH2.5. Since AnB and AgB contain C, H, O, N and S, the empirical formulae contain all these 5 atoms. Table 3.3 lists the empirical chemical formula for AgB and AnB fuels. The feedlot manure is collected from pens using wheel loaders, and is composted in windrows with composting unit. Manure is termed as raw if samples were collected from each windrow on day 1 (raw FB or unprocessed manure), partially composted, (or PC) if collected on day 31 and finished-composted, or FiC if collected on day 125. The composting helps in improving the homogeneity of the biomass.

Cattle biomass typically contains 1-3% nitrogen depending on the type of biomass, while coals generally contain up to 1% nitrogen, which is called fuel nitrogen depending on the rank of coal (Annamalai et al., 2003a). The N content in fuels is of extreme importance since typically higher fuel N results in higher NOX. Fuel nitrogen is released as a mixture of HCN, NH3 and N2 from coal and biomass. The NOX generated from fuel N compounds is termed as fuel NOX while the NOX from atmospheric N2 is referred to as thermal NOX. For most coal-fired units, thermal NOX contributes about 25% of the total NOX emission, and fuel NOX contributes the other 75% of the total (Annamalai et al., 2003b). The AgB fuels contain a lower amount of N compared to coals. The reduction in NOX when agricultural biomass (typically lower N content) is blended with coal occurs due to the following reasons: (i) lowerN inAgB, (ii) reduced local O2% due to higher VM,

(iii) more N in the form of NH3 than HCN since reduction via NH3 + NOX is more rapid compared to HCN + NOX but it is noted that the lower N content in biomass will produce a lower amount of NH3. Thus Tillman et al. (2000) examined co-fired coal with low nitrogen AgB and showed that NOX can be reduced by co-firing due to reduced N in blend; thus, NOX was reduced simply by reducing the nitrogen loading to the furnace. However the reported amount of NOX reduction (measured trend line) was greater than expected based on theoretical data (Fig. 3.6) since higher volatile matter in AgB (almost 80%) depletes the local O2 rapidly resulting in lesser availability of O2 for fuel N oxidation to NO. Thus Figure 3.6 shows that lower N in blend, the greater the NOX reduction in kg/GJ of heat released. However, since AnB contains more N compared to coal, there is a concern for increased NOx emission during direct combustion. As seen later the N in AnB is mostly of urea type, which may help in better reduction of NOx under appropriate temperature and oxygen %.

In Figure 3.7 it may be seen that raw FB, partially composted (PC) FB, fully/finished composted (FiC) FB, and cattle ration (cattle feed) all fall under this DAF HHV range. Similar results are also found when blending 5% crop residues with each FB fuel (Sweeten et al, 2006).

Methods and technologies

Biomass co-combustion is known as the ‘partial substitution of coal (or other fossil fuel)’ with biomass in one process. Typical co-combustion power plant capacity is in the electrical output range of 50 MW to 700 MW in Denmark, Belgium, Poland, UK, etc. Co-combustion can be applied in existing coal equipped with pulverized coal firing systems or fluidized bed combustion systems or a gas fired power station where the fraction of biomass is up to 20% of the total fuel weight or energy consumption (VGB, 2008). Biomass co-combustion offers renewable energy with the lowest capital cost.

There are six types of biomass co-combustion methods as listed in Figure 4.1 (Livingston etal., 2011). Number 1 is the milling of biomass (pellets) through modified coal mills, number 2 is the pre-mixing of the biomass with the coal, then the mixed fuel is milled and fired through the existing coal firing system, number 3 is the direct injection of pre-milled biomass into the pulverized coal running piping, number 4 is the direct injection of pre-milled biomass into modified coal burners or directly into the furnace, number 5 is the direct injection of the pre-milled biomass through dedicated biomass burners and number 6 is the biomass gasification gas, which is burned with coal in the boiler.

In summary, it is possible to distinguish the application of biomass in coal-fired power plants with three different biomass co-combustion concepts, which are shown as following (EUBIA, 2007; VGB, 2008; Tillman et al., 2000; Brouwer et al., 1995; Swanekamp etal., 1995; Surmen et al., 2003; Hunt et al., 1997) [2]

steam generation. The steam is used in the power plant together with the main steam. Parallel co-combustion is very popular in the pulp and paper industries as dedicated biomass boilers are used for the utilization of bark and waste wood. These industries economize and increase their energy efficiency by using the bio-residues and by-products from their main focus, the production of paper.

Char oxidation (glowing or smoldering combustion)

The products of pyrolysis that come in contact with oxygen will undergo two kinds of combustion: glowing combustion (char oxidation) and flaming combustion (volatiles oxidation).


Figure 5.7. Schematization of char oxidation (Spliethoff, 2010).

Char oxidation is based on the reaction scheme shown in Figure 5.7.

Inside the particle or in the surface, oxygen, carbon dioxide and water vapor act as oxidants in the heterogeneous oxidation reactions:

C + 1 /2O2 ^ 2CO

C + CO2 ^ 2CO (Bouduard reaction)

C + H2O ^ CO + H2 (heterogeneous water-gas reaction)

In the gaseous phase the following homogeneous reactions happen:

CO + 1 /2O2 ^ CO2 H2 + 1 /2O2 ^ H2O

Char combustion reaction is influenced both by combustion kinetics and mass transport processes in which the limiting process depends essentially on temperature. As a function of temperature three areas can be distinguished (Fig. 5.8):

• chemical reactions (low temperature);

• pore diffusion (temperature rises);

• boundary film diffusion (high temperatures).

Combustion reactions generate very high temperatures on the surface of char particles (1370- 1650°C). With increasing temperatures the production of CO overcomes the production of CO2. For example at 1027°C the ratio between the production of CO and CO2 ranges from 5:1 to 21:1 (Matsui et al., 1986). The cause of the increase in production of CO is the limiting step in char oxidation represented by oxygen diffusion to the char particle surface. Carbon oxidation becomes a two-step reaction: first CO is produced and then it is oxidized away from the char particle.

Char combustion is exothermic (AH ~ 32kJ/kg), the activation energy is around 180kJ/mol and the frequency factor is around 1.4 x 1011 s-1. Char combustion results to be slower than volatiles combustion, which is why much of the char oxidation occurs after flaming combustion.

The overall reaction rate of char oxidation depends on oxygen partial pressure, expressed at atmospheric pressure, and the reaction order with respect to oxygen (nO2) (Anca-Couce et al.,



Подпись: k-T Подпись: к-exp Подпись: “-n JT )


Figure 5.8. Schematization of char combustion areas (Spliethoff, 2010).

Подпись: da = A exp dt image229 Подпись: n Подпись: (5.17)

2012; Janse etal., 1998):


A = frequency factor [s-1]

E = activation energy [kJ/mol]

R = gas constant [J/K mol]

T = temperature [K] a = biomass conversion rate [—]

Xo2 = partial oxygen pressure [Pa] n = reaction order with respect to oxygen [—].

Figure 5.9 shows a thermogravimetry for a generic biomass. The peaks d1, d2 and ch represent respectively the devolatilization step (d1 and d2) and the char oxidation step (ch), obtained through deconvolution of thermogravimetric data (Fig. 5.9). The activation energy and frequency factor reported in Table 5.4 can be used for SFOR models (single first order reaction models).

Removal of other impurities found in the product gas Alkali metal compounds

Alkali metal compounds may be found in the vapor phase at high temperatures and will therefore pass through particulate removal devices unless the gas is cooled. The maximum temperature considered to be effective for condensing alkali metal species is around 600°C. Tests have shown that their gaseous concentrations fall with temperature so much that the concentrations are close to turbine specifications at temperatures 500-600°C. Thus, gas cooling down to these temperatures may result in condensation of the alkali metals on the entrained solids and thus be removed with the overall particulate removal.

Alkali metal vapors may damage ceramic filters at high temperatures, and the gas thus has to be cooled before passing though the hot gas filter. Alkali metals may cause high-temperature corrosion of turbine blades, stripping off their protective oxide layer and for this reason, it is believed that the alkali concentration should not exceed 0.1 ppm at entry to the turbine. There is no experience with modern coated blades in such an environment. Alternatively, or additionally, water scrubbing can be employed for alkali removal.