13.1 Introduction

As a key technology for the conversion of lignocellulosic biomass into useable renewable energy, gasification technologies have been investigated for several years. With regard to fuel quality, biomass could be classified as a low rank fuel in terms of energy density, heating value, and moisture content. Moreover, the inherent property differences of each plant species and changes in physicochemical properties due to the external environment (weather, seasonal variation, and storage) make it difficult to develop a universal energy conversion system with different feedstocks.

Together with pyrolysis and combustion, gasification is a very efficient thermochemical conversion method for solid fuels with high volatile matter like biomass. There have been various approaches used in the gasification of biomass including pretreatment of feedstock and product gas treatment. They are, however, rather young technologies, and large commercial biomass gasification plants have only recently become available. Moreover, detailed data from large plants is not open to the public at this time, making it difficult to find vital information for future studies. In this chapter, the performance of various gasification technologies for lignocellulosic biomass was investigated based on the literature survey. Analysis of relevant biomass gasification system was conducted in a quantitative manner. Therefore, in order to verify the results from small gasifiers, the results from large gasifiers were compared, even though the available data is very limited.

13.2 Gasification of Lignocellulosic Biomass

As an endothermic process, the gasification reaction requires gasifying agents, heat, and fuels that are subjected to various steps such as drying, devolatilization, reduction or gasification, and partial oxidation or controlled combustion. With single particle biomass, the sequential reaction occurs as the particle temperature increases with an adequate oxidizing agent and heat. Partial oxidation plays an important role in providing the necessary heat for the endothermic reaction. The thermal energy leads to the evaporation of moisture in the fuel particle, and various light and heavy hydrocarbons are ejected from the fuel particle through pyrolysis. At the same time, the remaining char and undegradable tar react with high temperature steam and carbon dioxide, generated from the partial oxidation process, via a heterogeneous reaction. Subsequently, additional gaseous products such as H₂ and CO are also produced via heterogeneous reactions. These reactions take place simultaneously in the actual gasification process. The chemical reactions and reaction enthalpies, related to the main gasification processes, are shown in Table 13.1.

In general, the main components of product gas consist of hydrogen, carbon monoxide, carbon dioxide, methane, and some C₂⁺ hydrocarbons along with tar, ash, H₂S, COS, NH₃, and so on. For the gasification system, cold gas efficiency, product gas composition and calorific value, and impurities are important parameters in performance evaluation. Furthermore, the composition and gas yield can be manipulated by changing the operating conditions or adding gas reforming or treatment processes. The product gas can be directly used as an alternative fuel to replace fossil fuels in a conventional energy system or can be transformed into high value-added chemicals or transportation fuels through various synthetic chemical processes.

13.3 Overview of Gasification Technologies of Lignocellulosic Biomass

In order to build a gasification system, along with a gasifier, a wide range of assistive technologies are necessary such as fuel handling and storage, pretreatment of feedstock, fuel feeding, product gas cleaning, ash treatment, and control of the plant. The gasification technology is, however, essential, and many physicochemical phenomena are involved, and associated technologies are so diverse that it is impossible to describe them in a single chapter. In this section, the current state of technologies will be introduced by presenting recent review papers regarding biomass gasification.

Regarding the design of gasification plants, Ruiz et al. [1] investigated gasification techniques and operation parameters. The gasifier temperature and equivalence ratio (ER) greatly affect the product gas quality, and the high moisture content of biomass and tar in the product gas represented the main technology barriers to be solved. Han and Kim [2] evaluated the literature regarding tar reduction and reported that about 40–99% tar can be reduced by physical approaches using scrubbers, cyclones, and electrostatic precipitators at the expense of tar energy. For tar reduction with self-modification, methods such as reaction temperature control (within moderate ranges), feedstock, pressure, residence time, gasifying agent, and ER were investigated, but they were not very effective. In addition, very recent technologies for gasification were reviewed by Pereira et al. [3]. They focused on the role of the technologies as novel energy systems for sustainable energy sources and greenhouse gas reduction. The effects of size, shape, structure, environment (gasifying agent), temperature, heating rate, and chemical composition of biomass on the gasification process were investigated by Kirubakaran et al. [4]. Notably, the auto-gasification of biomass into gaseous fuel by bio-oxygen, implying that the oxygen available in the biomass can be converted into CO during the gasification process, and using ash as a catalyst was reported to be feasible. For fluidized bed systems, Alauddin et al. [5] investigated various types of fluidized bed gasifiers to obtain optimum outputs such as gas composition, heating value, and tar content of the product gas, and several successful industrial plants in developed countries were introduced. For integration of the gasification system with downstream synthetic processes, Göransson et al. [6] reviewed the gasification technologies focused on the dual fluidized bed gasifiers (DFBGs) for high value-added products including transportation fuels. They reported that the reduction of tar is a crucial parameter to obtain clean syngas for automotive fuels, which can be solved by the primary method (in situ) plus secondary method (ex situ) like hot gas cleaning combined with a catalysts.

Recently, the co-gasification of coal and biomass was shown to be a very practical approach in terms of enlarging plant capacity or using limited biomass resources in a conventional coal gasifier. The co-combustion of coal and biomass has been widely applied by power plants to reduce emission of harmful gases from conventional coal power plants (i.e., NOx or SOx) while using biomass as a renewable fuel. Co-gasification has many advantages by the same reason, and many issues related to biomass supply can be solved by this approach including product gas quality control, seasonal variation of supply, and price control of feedstock. Emami-Taba et al. [7, 8] investigated the effect of fuel blending on the co-gasification of coal and biomass. They reported that the complex structure of biomass led to a higher tar production by adding more biomass to the fuel blend and less H₂S and NH₃ produced due to lower nitrogen and sulfur contents in biomass. In addition, E4Tech [9] reviewed various gasification technologies suitable for liquid fuel production from syngas in terms of suitable feedstocks and scales in the United Kingdom. Toward this end, they assessed the requirements of syngas-using technologies to establish which gasifier was suitable for liquid production and provided a review of current and emerging specific gasifier technologies. Finally, they compared the generic types of gasifiers. Though the report is focused on liquid fuel production with gasification, a detailed analysis was conducted, and some useful information was presented.

13.4 Classification of Gasification Technologies

Gasification systems are highly influenced by reaction conditions and parameters such as fuel characteristics, kinds of gasifying agent, reaction temperature, residence time, catalysts, and so on. Gasification technologies can be classified by the different approaches utilized to achieve the aforementioned conditions and parameters. In regard to heat supply, it can be classified as direct gasification (or autothermal) or indirect gasification (or allo-thermal). For direct gasifiers, the reaction heat is provided by the partial oxidation of the fuel in the same reactor, thereby implying fewer combustibles in the product gas because of the dilution of combustion gases from partial oxidation. In indirect gasifiers, the reaction heat is supplied from another reactor or energy source so that the heating value of the product gas is relatively higher than the direct gasifier since there is no dilution of combustion gases from partial oxidation.

On the other hand, gasification systems can be classified by gasifying agents such as air, steam, oxygen, carbon dioxide, and so on. Basically, any reactive gas can be used as the gasifying agent, but air, steam, and oxygen or mixtures of the same are the most common gasifying agents due to economic reasons and local supply. The composition and heating value of the product gas depend on the gasifying agent, and the selection of the gasifying agent is closely related to the downstream application of the product gas. Needless to say, as the most general agent, air has been used for gasification for a long time. With air-blown gasification, low heating value gas (4–7 MJ/Nm³) can be obtained because half of the product gas is nitrogen from air. It can be used in direct combustion or co-combustion in boilers, engines, or gas turbines. In steam-blown or oxygen-blown gasification, medium heating value gases (10–16 MJ/Nm³) are produced and can be used for combustion fuels as well as feedstock for further chemical synthesis processes such as valuable chemicals and alternative transportation fuels such as substitute natural gas (SNG), dimethyl ether(DME), Fischer–Tropsch (FT ) diesel, or gasoline.

Table 13.2 shows the average heating values and compositions of product gases according to the gasifying agents. The specific heating value of the steam and oxygen-blown cases are much higher than that of air-blown. In steam-blown gasification, the hydrogen, methane, and carbon dioxide contents are higher than in oxygen-blown gasification, while the carbon monoxide content is less. As shown in Table 13.2, gasification systems are highly influenced by gasifying agent, and the proper choice of target fuels, gasifying agent, gasifier design, and operating conditions is very important.

Source: Bridgwater et al. 2009 [110]. Reproduced with permission of CPL Scientific Publishing Services Ltd (CPL Press).

13.5 Types of Gasification Systems

Table 13.3 shows various gasifiers with different reactor designs and operating principles. Each type of gasifier has specific requirements of reactants and operating conditions, and heat and mass transfers of the reactors are quite different because the optimum fuel size, feeding methods, relevant gasifying agent, operating temperature, and residence time are different. The distinct features yield pros and cons for specific applications, leading to different characteristics in terms of fuel availability, product gas composition, tar and dust, and optimum plant size. Even for the same type of gasifier, different setups are possible. This section will briefly describe each type of gasifier.

13.6 Performance Evaluation of Biomass Gasifiers

In this section, four representative biomass gasifiers will be evaluated based on performance. The gas composition and influence of operating conditions (i.e., ER or steam to biomass ratio) on the product gas were collected based on previous reports. Notably, the kind of feedstock, gasifying agent, size of the gasifier, operating temperature and pressure, and catalyst significantly affect the final product of the gasifier, and the performance is quite different even among the same types of gasifiers. Moreover, throughout the literature, detailed information for parametric analysis is very limited for small-scale experiments, not to mention commercial plants. However, an analysis of relevant biomass gasification systems was conducted quantitatively. In order to verify the results from small gasifiers, those from large gasifiers were compared. Table 13.9 shows the representative demonstration and commercial biomass gasification plants.

13.6.1 Fixed (Moving) Bed Gasifiers

The ER, defined as the actual fed air during gasification divided by the stoichiometric air, is the most important factor in air-blown gasification. Generally, there is an optimum ER for each gasification system, and a higher ER than the optimum condition implies further oxidation reactions, which lead to the increase of carbon dioxide and decrease of combustible gases such as hydrogen, carbon monoxide, and methane.

Figure 13.1 shows the comparison of product gas composition of various fixed bed gasifiers. The results were sorted by gasifying agent and hydrogen content. The product composition is significantly affected by the gasifying agent. For oxygen-blown or steam-blown cases, the product composition is superior to air-blown cases. On the other hand, steam can be added to air-blown systems, but the addition of steam has no significant influence. In order to reform the product gas with steam, appropriate temperatures and residence times are required [15]. For most air-blown cases, the total amount of product gas, except nitrogen, is in between 40% and 50%. The Viking gasifier exhibits high hydrogen content, and the production of fuel gas is the largest due to its high carbon conversion rate arising from two-stage gasification. Notably, the main gas contents are different for each gasifier, but the deviations of the product gas in the fixed bed gasifiers are relatively small regardless of the physicochemical properties of the feedstock or operating conditions.

Figure 13.2 shows the influence of ER on the H₂, CO, and CH₄ contents in fixed bed systems with air as the gasifying agent. The H₂, CO, and CH₄ contents were observed in the ranges of 7–16, 11–25, and 1–5 vol.%, respectively. As the ER increases, the H₂ and CO contents increase until the ER reaches 0.3, and then the H₂ and CO contents gradually decrease as the ER increases. It is well know that the average ER for autothermal gasifiers is around 0.3. If the ER is less than the optimum value, the carbon conversion rate decreases, leading to the decrease of the combustible gas. If the ER is more than the optimum value, CO₂ increases due to the excessive partial oxidation. In most cases, the CH₄ content decreases as the ER increases. The results reported by Ouadi et al. [16] did not show any trends because a different feedstock was used in each run in their study. According to the data collected, the optimum ER values were between 0.25 and 0.35.

In Figure 13.2, the dotted line represents the product gas components obtained from commercial plants such as Beltran Technologies [17] and Harboore Technology [18]. The product gas quality from the commercial plants is better than that from small and medium-sized plants, especially for H₂ and CH₄. Hydrogen comes from devolatilization, char gasification, and water–gas shift reaction, and larger reactors have decided advantages in enhancing these reactions. Methane is produced from devolatilization, and it can be easily reformed under high temperature conditions (750–800 °C). Therefore, if the devolatilized gas does not pass the partial oxidation zone or if the gas residence time is short, more methane can be obtained from air-blown gasifiers. For top feeding systems, methane content can be higher since the devolatilization gas leaves the gasifier as soon as it is generated. Notably, the hydrogen and carbon monoxide trend is inversed for each gasifier. This feature can be also observed in BFBs and DFBs, and it can be clearly seen for commercial plants. As mentioned previously, this is related to char gasification and the water–gas shift reaction, which affect the production and consumption of hydrogen and carbon monoxide, respectively.

13.6.2 Bubbling Fluidized Bed (BFB) Gasifiers

Figure 13.3 shows a schematic diagram and direct photo of a BFB gasifier. In BFBs, air is supplied from the bottom, and fuel can be supplied from above the bed surface or into the bed directly. Inside the bed, char combustion and gasification occurs, and the gaseous products undergo homogeneous reactions in the freeboard. Fuel mixing and bubble control in the bed are very important for syngas composition and plant efficiency. Figure 13.4 shows the comparison of product gas composition of BFB gasifiers. The results were sorted by gasifying agent, which significantly affects the product composition. As discussed in the fixed bed cases, oxygen-blown, steam-blown, or a mixture of the two are not common for BFB systems. For steam-blown BFBs, it is not a stand-alone system since autothermal reforming is impossible with steam only. Moreover, unreacted char accumulates in the steam-blown reactor with long-term operation. Some investigations focused on steam-blown BFB gasification as a subsystem of a DFB gasifier, with an example being the work of Kim et al. [19]. ThermoChem Recovery International, Inc. (TRI) [105] is based on BFBs, but the reaction heat is provided by a pulse combustor installed inside the BFB, which can be classified as an indirect gasifier. In BFB systems, steam can be added to the air-blown system, and notably, the addition of steam significantly affects the product gas in some BFB cases, which were not in the fixed bed.

For most air-blown cases, the total amount of product gas, except nitrogen, is between 40% and 60%. The variation in the product gas composition is more diverse than that of the fixed bed cases. For example, the hydrogen content varies from 3% to 25%, and the ranges of CO, CH₄, and CO₂ content are wide considering differences of feedstock properties, because the product gas yield and gas composition can be significantly altered by the bed material in fluidized bed gasifiers. For example, Mun et al. [20] added activated carbon (AC) and olivine to silica sand, and the amount of product gas increased: 25.3% of H₂, 21.6% of CO, 10.4% of CO₂, and 4.9% of CH₄. In order to reduce tar and increase gas yield, various additives have been studied including olivine, dolomite, ilmenite, AC, nickel catalysts, and so on. Most additives were studied in small-scale experiments, and additional research is necessary regarding additive use in commercial plants. If silica sand is used as the bed material, the characteristics of the product gas are similar to that of fixed bed gasifiers with the same gasifying agent.

Figure 13.5 shows the influence of ER on H₂, CO, and CH₄ contents in air-blown BFB gasification. The H₂, CO, and CH₄ contents were in the ranges of 3–33, 6–25, and 1.5–9 vol.%, respectively. Most studies have shown that the H₂ and CO contents are maximized near ER = 0.25 and decrease as the ER increases because of the excessive oxidation reaction. CH₄ decreases as ER increases in most studies. The optimum ER for combustible gases was between 0.25 and 0.3. The highest H₂ content (about 33 vol.%) that was obtained by Esfahani et al. [21] determined the optimal hydrogen production from palm kernel shells by air gasification. The hydrogen content might be attributed to the high reactor temperature (>900 °C) and the glass bead fluidized bed material used, which included 69.3% of SiO₂, 26.5% CaO, and 1.7% Fe₂O₃. The CaO and Fe₂O₃ could play a catalytic role in converting the tar (heavier hydrocarbon) into H₂ and light hydrocarbons such as CH₄. Corella et al. [123] conducted the air gasification of pine wood chips in a BFB reactor coupled with a catalytic reactor, and they reported that a high tar conversion rate of 98% could be achieved using a nickel-based catalyst without the deactivation of the catalyst for up to 65 h. Besides air, a steam–oxygen mixture has been used as gasifying agent. Pinto et al. [124] carried out the gasification of torrefied rice husk in a bench-scale BFB reactor, and higher H₂, CO, and CH₄ contents were obtained from the torrefied fuel compared with raw rice husk. Bronson et al. [125] investigated the gasification of Canadian forest residue in a pilot-scale BFB reactor and found the average combustible gas composition to be 20–22 vol.% of CO, 17–22 vol.% of H₂ and 7–11 vol.% of CH₄ under steam–oxygen gasification. Delgado et al. [126] conducted the steam gasification of biomass in a BFB reactor to investigate the effect of dolomite (MgO–CaO), calcite (CaO), and magnesite (MgO) on tar reduction and product gas composition and found the dolomite to be the most effective although the gas compositions in each case were similar.

In Figure 13.5, the results of alternate gas [22] and Skive plant [23] are depicted as dotted lines as a reference for commercial plants. The capacity of the former is 200 ton/day and the latter is 110 ton/day. Although the exact operating conditions were not provided for the commercial cases, the gas compositions of various studies are in between the two commercial plants, if the ER was between 0.2 and 0.3, common in autothermal BFB operations. CO content distributions of many studies are more like the results of commercial plants as compared with those of H₂ and CH₄. In the case of alternate gas, the H₂, CO, and CH₄ contents were 12.7, 15.5, and 5.7 vol.%, respectively, while for the Skive plant, the gas composition was H₂: 15–16 vol.%, CO: 20 vol.%, and CH₄: 4–5 vol.%. The difference between commercial plants and other plants could be attributed to operating conditions such as fuel properties, reactor temperature, bed material, ER, gasifier scale, and resultant gas analysis method. The H₂ content of Skive was relatively higher than that of alternate gas because a calcium-based material, which can perform a role in the absorption of CO₂ during gasification, was used as the fluidized bed material. On the other hand, the Skive plant operated in a pressurized mode of up to 200 kPa with wood pellets being used as the feedstock.

In Figure 13.5, the solid symbols represent the results of silica sand, and the open symbols represent those of catalyst addition in the bed. The graph shows the effect of catalysts on the gasification process, namely, the increase of hydrogen and methane content. Markedly, the data from the literature is diverse even under similar experimental conditions. Therefore, careful consideration is necessary to select appropriate data for a specific objective. The results of commercial plants could be a good reference for evaluating the results from small-scale experiments. In other words, experiments should be designed in a practical point of view. For small-scale experimental setup, electrical heaters have been widely used but can mislead the experiment if the boundary conditions are unrealistic for certain cases. For example, for ERs less than 0.2, gasification reactions cannot be maintained in the autothermal mode without the addition of external heat.

13.6.3 Circulating Fluidized Bed (CFB) Gasifier

Figure 13.6 shows a schematic diagram and direct photo of a CFB gasifier. It is based on a FFB system that circulates most of the particles in the reactor with the momentum of the fluidizing gas. Therefore, CFB gasifiers are composed of a riser, cyclone, and solid recirculation valve, and comparing with the similar size of BFBs, much more gas is supplied to the reactor for particle circulation, and the capacity of CFB gasifiers is much larger than that of BFB gasifiers. Unlike BFBs, all necessary reactions occur at the same time in the whole CFB system, and this can lead to different product gas compositions for the same kinds of fuel and gasifying agent. Figure 13.7 shows the comparison of product gas composition of CFB gasifiers. The results were sorted by a gasifying agent, which significantly affects the product composition. As aforementioned, oxygen-blown, steam-blown, or a mixture of the two are special cases, and air-blown is the most relevant for CFB gasifiers.

The plant sizes of CFB gasifiers are much larger than those of fixed bed or BFB cases. For air-blown CFB gasifiers, the total amount of product gas except nitrogen is between 30% and 50%, and the variation in the product gas composition is less than that of the fixed bed or BFB cases. In most air-blown cases, the amount of combustible gases tends to increase as the plant size increases. Note that the total combustibles in the product gas of average CFB gasifiers are less than the other types of gasifiers. For example, hydrogen contents of most CFB gasifiers are less than 10%, and this is because partial oxidation occurs at the same location of gasification and pyrolysis reaction in a CFB system. During the partial oxidation, the product gas can be combusted, and raw biomass leads to less hydrogen, which is easy to burn. For fixed bed and BFB cases, the reduction zone is separated from the partial oxidation zone, and the combustibles can avoid oxidation process until leaving the gasifier. In addition, most CFB gasifiers use silica sand as a bed material, which has no catalytic effects. This is because most CFBs are larger than BFBs, which means that it is commercially difficult to use expensive catalytic bed materials in CFBs. Recent investigations have focused on the use of catalytic bed materials in CFBs [24].

Figure 13.8 shows the influence of ER on H₂, CO, and CH₄ contents of air-blown CFB gasification. The H₂, CO, and CH₄ contents were in the ranges of 3–17, 5–22, and 1.5–9.5 vol.%, respectively. Most studies have shown that the H₂ and CO contents become maximized near ER = 0.25 and thereafter decrease as ER increases. Except for the result of Bingyan et al. [90], the combustibles decrease as ER increases. In Figure 13.8, the results of Foster Wheeler [9], Värö [25], and Värnamo [26] are depicted as dotted lines as a reference of commercial or pilot plants. Note that the results from large plants are better than those of small plants. This can be explained by the fuel residence time of most small CFB systems, which is not enough for perfect carbon conversion. The larger plants are advantageous in having longer residence times compared with the small plants. However the height should not be scaled from pilot to demonstration scale.

13.6.4 Dual Fluidized Bed (DFB) Gasifiers

Figure 13.9 shows a schematic diagram and direct photo of the pilot-scale DFB gasifiers. The DFB of this figure is the combination of a BFB gasifier and FFB combustor. This configuration is one of the representative options of DFB that was adopted in many commercial plants such as Güssing [27], Oberwart [106], and Götenborg [107] in Austria. As alternative options, the combination of a FFB gasifier and FFB combustor or the combination of a FFB gasifier and BFB combustor is possible, and the Silva gas system and ECN gasifier [9] are the representative examples, respectively. Figure 13.10 shows the concept of a DFB gasification system. As shown in Figure 13.10, solid bed materials are circulating in the interconnected fluidized beds as heat carriers, and they transfer heat from the combustor to the gasifier. The unburned char of the gasifier is used as a fuel for combustion, and additional fuel can be provided into the combustor if necessary. In general, superheated steam was used as a gasifying agent as well as a fluidization gas in the gasifier. Air is used as an oxidizer in the combustor, and heat of the combustion gas is used for steam generation. In order to avoid mixing of product gas from combustion gas, loop seals have been used between the two reactors.

Figure 13.11 shows the comparison of product gas composition of various DFB gasifiers. For all cases, the gasifying agent is steam, most of the product gas is combustible, and inert gas in the product gas is significantly less than the other gasifier types. The inert gases like nitrogen come from bypassing of combustion gas or entrainment during fuel feeding. The syngas from DFB has been used as a feedstock of catalytic synthesis process as well as power generation. Note that the hydrogen content of DFB is very high, ranging from 20% to 70%, which is mainly contributed by steam–char gasification and water–gas shift reaction (Table 13.1). In the configuration of a BFB gasifier and FFB combustor, the hydrogen content can be obtained up to 40%, and with specific bed materials, it can be increased more. For the case of Pfeifer et al. [28], the AER process was used, and the hydrogen content was increased up to 72%. High hydrogen content is preferred for chemical synthesis such as FT synthesis and SNG synthesis that need H₂/CO = 2 or 3, respectively.

Figure 13.12 shows the influence of steam to biomass ratio (S/B) on H₂, CO, and CH₄ contents of steam-blown DFB gasification. As shown in the figure, the gas composition is dependent on S/B, and above a certain range of steam (i.e., S/B = 1.4), the increase of steam has no effect on the product gas composition. In general, the conversion efficiency of steam is relatively lower than the other gasifying agents, and it was known that only 10–15% of steam is converted into product gas [28]. As mentioned before, nitrogen content in the product gas is less than 5%, and H₂, CO, and CH₄ contents were in the ranges of 10–60, 15–40, and 7–17%, respectively. The hydrogen content is very sensitive S/B ratio, and its mole fraction is directly proportional to S/B. The mole fraction of carbon monoxide is inversely proportional to S/B, and methane content has weak correlation with S/B. In Figure 13.12, the results of Repotec and Silva Gas & Taylor [9] are depicted as dotted lines as a reference of commercial plants. Both plants have the same type of combustor, but the configuration of gasifier is different. The former is the combination of BFB gasifier and FFB combustor, while the latter is FFB gasifier and FFB combustor. Note that the two gasifiers have very different gas composition because of the gasifier configurations.

In Repotec case, hydrogen content is much higher than the other case because BFB gasifier provides enough time for char–steam gasification and homogeneous reactions for enhancing hydrogen production: water–gas shift reaction and steam methane reforming (Table 13.1). The carbon monoxide and methane contents decrease due to the aforementioned reactions. In Silva Gas & Taylor case, the hydrogen content is low, and carbon monoxide and methane contents are high because the residence time of FFB gasifier is short, which leads to less char–steam gasification and steam reforming reactions. Therefore, hydrogen yield is less than the other case, and the carbon monoxide and methane contents are high. Note that most results from small plants are between the results of two commercial plants when S/B is less than one, which is a common gasification condition. In Figure 13.12, the result of ECN pilot plant was also depicted. The ECN DFB gasifier is a combination of FFB gasifier and BFB combustor. As shown in Figure 13.12, the results are very similar to those of Silva Gas & Taylor case because the gasifier is the same type of Silva Gas & Taylor. In the ECN DFB gasifier, the FFB gasifier is inside the BFB combustor where it is expected to receive heat transferred from the combustor to gasifier wall boundaries. Note that configuration of the gasifier is more dominant than that of the combustor in DFB systems. In addition to the product gas composition, different combinations of BFB and FFB for gasifier or combustor affect the performances of the DFB gasifiers such as operating characteristics, syngas yield, tar generation, and scale-up characteristics. Therefore, appropriate design selection is necessary for DFB systems considering gas cleaning process and end use of the product gas.

13.7 Industrial Biomass Gasification Plants

All over the world, especially in developed countries such as the EU, North America, and Japan, biomass gasification and its technologies have been widely studied, and many biomass gasification plants have been commercialized. In North America, there are many fixed bed gasifier manufacturers that have experience with commercial technologies such as Nexterra [29], Plasco [30], Beltran [17], and Community Power [11]. In fluidized bed systems, the gasification of black liquor was developed by TRI [105], and a Silva gas system [9] represented by a DFB system was successfully operated in a commercial plant at 200 ton/day. America secured cheap natural gas through commercial shale gas in recent years. Nevertheless, the development of renewable energy including biomass is in progress to achieve energy independency. For example, ethanol production from lignocellulosic biomass has gained renewed interest to reduce the consumption of corn-based biomass and to meet the demands of the rapidly growing ethanol market.

In the EU, many fluidized bed gasification systems have been commercialized, and the size of the plant is increasing. For BFBs, the Skive gasifier [23] is a representative example. The nominal thermal output is 19.5 MW_th (maximum capacity: 28 MW_th) under the system pressure of 0.5–2 bar. Wood pellets are used as the feedstock, and the plant produces 6 MW_e of electric power and 11.5 MW_th of heat in the CHP mode. In addition, the product gas can be burned in gas boilers, and the biomass to electric power efficiency is 31%, while the overall efficiency is up to 90%. In CFBs, the Varö gasifier [25] in Sweden and Lahti gasifier [112] in Finland have been successfully operated. The former has been used for supplying product gas into rotary kiln for cement production. The feedstock is dried wood bark from nearby pulp mills, and the thermal capacity is 35 MW_th. Since the product gas is supplied to the combustor of the kiln, gas cleaning is not necessary. The Lahti gasifier is another example of using gasification technology with a conventional energy system. In the first phase, which began in 1998, the thermal capacity was over 45 MW_th, and the product gas was used for the co-combustion of coal in a PC boiler of 360 MW_th. This process replaces 15% of coal, and the SOx, NOx, and CO₂ emissions of the PC boiler were reduced by employing reburning technology with syngas from the gasifier. In the second phase, which was initiated in 2012, the entire system was repowered to use municipal waste together with biomass. Moreover, the capacity of the gasifier was increased up to 160 MW_th (2 × 80 MW_th), which is equivalent to 250 000 ton/a solid recovered fuel (SRF) gasification. The product gas is currently burned in a gas boiler to produce 50 MW_e of electricity and 90 MW_th of district heating. In order to prevent high temperature corrosion with alkali chloride from municipal solid waste (MSW), a hot gas cleaning process was introduced in between the gasifier and boiler. Also, a new line was built in 2012. The CFB gasifier in Vaskiluodon Voima Oy in Finland is the world's largest biomass gasification plant with a capacity of 140 MW_th, and the gasifier is connected to an existing 560 MW power plant for topping the product gas to a coal-fired boiler [127]. The Värnamo gasifier [26] in Sweden is another interesting CFB gasification system. It is a pressurized fluidized bed gasifier, and the syngas was used as fuel for a gas turbine. After successful operation with the gas turbine, the plant was redesigned into a synthetic liquid fuel production system integrated with biomass gasification under the name of CHRIS project. The project, however, was discontinued several years ago.

Recently, indirect gasification systems with DFB technologies have been introduced in the market. The Güssing gasifier [27] in Austria is representative of DFB gasifiers that have been successfully operated since 2001. The original technology was developed at the Technical University of Wien (TU Wien), and the gasifier has been used for many research projects as well as for commercial purposes. The Oberwart gasifier [106] is a 10 MW_th commercial gasifier of the same design as the Güssing, which uses wood chips as feedstock. Recently, the size of DFB gasifiers has increased, and the Götenborg SNG plant [107], which includes a DFB biomass gasifier using the Austrian DFB gasification technology, has been fully operational since 2014. For the first phase, a 32 MW_th gasification plant has been operated for a 20 MW_th SNG synthesis process, and an 80 MW SNG plant is planned for phase 2 [51].

As an industrial entrained flow gasifier for biomass, the Choren gasifier [108] in Germany is the largest. This 45 MW_th plant was designed to supply bio-syngas for FT synthesis of liquid fuel. In order to meet the requirements of entrained flow gasification systems, pyrolysis oil and ground char were used as the feedstock. Unfortunately, the project was discontinued because of many obstacles. As discussed previously, various gasifiers have been developed on the industrial scale, and plant size is growing steadily. Some projects were successful, while others were not. In commercial projects, the economic feasibility of the plant is very important, in addition to technological obstacles. The market for renewable energy is so volatile that many external environments can affect the project management such as feedstock price, governmental subsidies, and price of conventional fossil fuels.

13.8 Conclusion

The objective of this paper was to evaluate the performance of various technologies used for the gasification of lignocellulosic biomass. The investigation is based on a literature survey that provides detailed information for quantitative comparison. The analysis focused on fixed bed and fluidized bed gasifiers, which are the most relevant gasification systems for lignocellulosic biomass. Notably, the quality of the product gas was significantly affected by fuel properties, gasifying agents, gasifier size, and operating conditions, even if the same type of gasifier was used. Considerable differences were observed between the results from commercial plants and those from small plants, with the extent of these differences being even higher for the fixed bed and CFB gasifiers. These results imply that detailed verifications of experimental conditions and careful interpretations of results are necessary for small-scale gasifiers, especially for fixed bed and CFB gasifiers. Regarding the comparison between gas compositions of commercial and research plants, the larger differences were observed in the hydrogen and methane contents, while the difference in carbon monoxide content was relatively small. These results might be attributed to the residence time difference caused by the size of the reactor. Overall, these results could be used as a platform on which to design and model future experiments as well as an appropriate selection guide for gasification technologies targeted for specific fuels and applications.

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