Ashes are defined as the residual mass obtained after combustion in air, under controlled con­ditions of time and temperature; in a similar way to moisture, ash content can be calculated on wet basis, on dry basis and on dry and ash-free basis. Usually the value referred to dry basis is used. Ashes obtained from wood combustion are composed mainly of: silicon, calcium, potas­sium, phosphorus, manganese, iron, zinc, sodium, boron, in the form of oxides, silicates and nitrates. For their composition ashes are generally alkaline, with a pH around 12; the chemical composition may also vary depending on the combustion temperature.

Table 5.2 shows a typical ash composition for different biomasses together with their melting point which constitutes a main issue to tackle during combustion. Some biomasses show ashes with a particularly low melting temperature which may adhere to surfaces inside the combustion chamber and also cause heat-exchanger fouling. To avoid ash melting, a limit on the combustion temperature should be considered hence the resulting power cycle efficiency and emission control may be affected.

5.1.3.1 Volatile matter (EN 15148, 2009)

This represents the part of biomass that is released during heating (200-450°C) without oxygen (pyrolysis). Pyrolysis process also happens during biomass combustion, because oxygen does not reach the internal layers of the fuel with the same velocity with which heat does. For this reason while the external layer of biomass burns, the internal layer decomposes due to pyrolysis. During this process biomass decomposes in non-condensable gases (syngas), condensable gases (tars) and solid carbon (char): the first two products can be grouped under the category: volatile matter (VM) (EN 15148, 2009).

(Nussbaumer, 1993; Lewandowsky, 1996; Obernberger et al., 2000; Ruckenbauer, 1996; Schmidt et al., 1994; Obernberger etal, 1996; Channiwala and Parikh, 2002).

The content of volatile matter is determined by heating the fuel in absence of oxygen and in strictly controlled conditions and it is calculated using the following relation:

where:

VM = % of volatile matter in the air-dried sample [%] m1 = sample mass before heating [g] m2 = sample mass after heating [g].

Volatile matter as well can be expressed on a wet basis, dry basis or dry and ash-free basis. The volatile matter content is important because it determines the quantity of secondary combustion air to provide inside the combustion chamber; primary air being the one necessary to oxidize solid char.

One of the major problems in air gasification is the dilution of the product gas by the nitrogen in the air. This could be overcome by using oxygen as the gasifying agent. However, the use of oxygen requires an oxygen generator and is expensive and highly energy extensive. Another route to achieve a product gas without diluting nitrogen is to separate the combustion process from the gasification process in two reactors in a so-called dual fluidized bed configuration.

A typical dual bed fluidized bed gasifier is made up of two reactor chambers, the gasifier and the so-called riser combustor. An example of this configuration is shown in Figure 6.8, where the fast internal circulating fluidized bed (FICCFB) gasifier, developed by Vienna University of Technology in Austria, is illustrated. The system combines a bubbling fluidized bed gasifier with a circulating fluidized bed combustor, where the gasifier in effect is a pyrolysis, indirectly heated with hot sand from the riser, which in turn is heated by burning the product char with air before

re-circulation back to the gasifier. Steam is also usually added for enhancing hydrogen generation via the shift reaction and to promote the carbon-steam reactions. Product quality is good from a heating value perspective, but poor in terms of the tar content. These gasification configurations normally give middle-caloric gas with the heating value (LHV) of 10-14 MJ/m3N as the resulting gas will be almost nitrogen-free.

Another concept with a combination of a gasifier and a combustor is the SilvaGas (Batelle) process shown in Figure 6.9 has been tested in several countries. The idea is that fuel is heated with solids from the combustor, and char is fed to the combustor after the gasification to get good conversion efficiency. The gasifier can in this case be operated with steam and by this achieve a richer gas.

The CO2 emission in kg/GJ of heat released is of extreme importance in ascertaining GWP of fuel particularly when fuels are switched. Based on the Boie equation, Figure 3.14 plots the CO2 in g/MJ (or kg/GJ) for C-H-O fuels. It is clear that biomass has similar CO2 emissions compared to coals even though it has less C% compared to coals but the heat value of biomass is correspondingly lower!

20 —

0 —————————————————— 1—————————————-

0 0.5 1 1.5 2 2.5 3 3.5 4 4.5

H/C

Figure 3.14. CO2 emission in g/MJ (or kg/GJ) for C-H-O fuels. Multiply ordinate by 2.326 to get lb per mm BTU.

3.2.3 Air flow rate and multi-fuels firing

Similar O2% in exhaust implies excess air% remain similar for most solid fuels (Lawrence, 2007). Since thermal output = HHVO2 x stoichiometric O2 flowrate = HHVair x stoichiometric air flow rate = HHVair x actual air flow rate/(1 + x/100) where x is% excess air; thus when actual air flow rate is maintained the same, then one may switch the fuel and adjust the fuel flow rate such that same O2% is maintained which ensures similar thermal output. In automobiles, when alternate fuels are used for combustion, same thermal energy input is assured when air flow is maintained the same and fuel flow is adjusted such that same O2% is maintained in exhaust.

3.2.4 CO2 and fuel substitution

Since HHVO2 is constant for most fuels, then for given thermal input, the O2 moles consumed remain the same; a fuel with higher RQ produces more CO2 for the same thermal heat input! The reader is referred to Chapter 2 in this book on the basics of thermal energy conversion, stoichiometry, air fuel ratio and flame temperatures.

Biomass gasification gas is used as a way of co-combustion so that biomass is converted into combustible gas, and then sent into the boiler. Biomass gasification gas is rich in H2, CH4 and CO etc. with low ash content, very low sulfur content. It is an ideal co-combustion fuel and effective to decrease the emissions of nitrogen oxides.

The co-combustion based biomass gasification can avoid most of the problems associated with direct co-combustion, such as boiler fouling, corrosion, and ash characteristics altering. As shown in Figure 4.3, biomass was gasified in a gasifier and the product gas was fed into a coal fired boiler for co-combustion. The technical economical feasibility of co-combustion with biomass gasification has been verified. The most important thing was to make clear the possible effect of co-combustion on burnout, emissions and what retrofit work should be done. Therefore, a CFD modeling study of coal and product gas (from biomass gasification) co-combustion was carried out Dong et al. (2010).

In the study, 14% by heat basis of product gas from biomass gasification was injected from the lowest layer burner and co-fired with coal in a 600 MW tangential PC boiler in Yuan Baoshan power plant (China). Figure 4.4 shows a sketch of the Yuan Baoshan Boiler. The size of the boiler is 20.1 m (deep) x 20 m (wide) x 73.9m (high). The burner is a tangential swinging burner with size of 0.747m (wide) x0.838m (high). There were eight layers of burners and six layers of secondary air inlets. The designed coal was Yuanbaoshan lignite.

The simulation results showed that: (1) The combustion temperature in the furnace was lower and the flue gas volume was higher for co-combustion cases. The convection heat transfer area should be increased or the co-combustion ratio of product gas to coal should be limited to keep the rated capacity. (2) NO emission was reduced about 50-70% when the product gas was injected

7400mm

Figure 4.4. A sketch of the Yuan Baoshan Boiler.

through the lowest layer burner. The NO emission also depended on the burner design and oper­ation level. (3) The fouling problem caused by high temperatures can be reduced for the lower co-combustion temperature.

The biomass gasification and co-combustion process has been studied by Huang (2011). A model of co-combustion of coal and biomass-gas was established focusing on the research of co-combustion power generation of corn stalk gasification gas and coal. Based on the first and the second law of thermodynamics, co-combustion with corn stalk gasification gas 5% was analyzed. In the research process, an exergy flow graph of the boiler in co-combustion is shown in Figure 4.5. Comparing with pure coal burning, the research of co-combustion (5-30%

Figure 4.5. Exergy flow graph of boiler in co-combustion.

biomass-gas) shows that the theoretical burned gas mass flow will reduce and the theoretical air mass flow will increase and both boiler heat efficiency and exergy efficiency will decrease when there is more biomass gas co-combustion, which was shown at Table 4.5.

Dong (2011) modeled the co-combustion integrated system, which combined a biomass gasi­fication system and a 300 MW circulating fluidized bed boiler system, as shown in Figure 4.6. The optimized gasification gas is sent into the boiler with the temperature 598°C heating value 5401 kJ/Nm3 and gasification efficiency 72.25%. The results reveal that with increase of the co-combustion rate, theoretical air volume decreases, fuel gas volume increases, combustion temperature and exhaust gas temperature increase, boiler efficiency decreases. Adding some heating surfaces at backpass should be used to improve boiler efficiency. The simulation results are shown in Figure 4.7.

Figure 4.7 shows the influence of reburning ratio on furnace temperature, flue gas temperature and boiler efficiency. The average temperature of the furnace was proportional to the biomass gasification gas. When the reburning ratio was increased from 0 to 20%, the furnace temper­ature went up from 840 to 872°C. Given that the total heat value of biomass gas and coal is invariable, the average furnace temperature was rising because the temperature of biomass gas injected was 598°C. When the reburning ratio was increased from 0 to 20%, exhaust temperature also grew from 137.2 to 176.2°C, which agreed with the change of furnace temperature.

When the reburning ratio was increased from 0 to 20%, boiler efficiency reduced from 93.8 to 91.3%. It can be inferred from Figure 4.7 that the flue gas temperature and heat losses of exhaust were proportional to the biomass reburning ratio. The boiler efficiency was inversely proportional to the biomass reburning ratio.

The technology of large coal-fired units is mature and it has a high power generation efficiency, so the integration of straw gasification and coal-fired power generation can take the advantage of increasing the efficiency and reducing cost of electricity. In Europe and United States, the technology has some commercial applications, and has become a new efficient way of reducing greenhouse gas emissions. The gasifier is the key equipment for straw gasification and coal — fired power generation, which at the operating level has a large impact on the effect of straw utilization.

Combustion is an exothermic reaction that releases the chemical energy (HHV) of a fuel trans­forming it into heat that is transferred to the surrounding environment (combustion chamber) and to the combustion products (flue gases and ashes) (Obernberger, 1998). Combustion of a solid fuel is actually carried out as the exothermic release of the chemical energy contained in two different fuels: a volatile fuel mixture of permanent gases (syngas) and vapors (tars) which burns rapidly in the gaseous phases (volatile matter) and a carbonaceous solid fuel (char) which burns slowly in the solid-gas interface. However these two different fuels must be extracted from the original solid fuel and this is accomplished in the preliminary phases (heating, drying and pyrolysis) providing thermal energy (heat) to the feedstock.

A combustor device for solid fuels must then be designed to guarantee an adequate heat exchange between the feedstock and the reactor in order to allow drying and extraction of volatile matter within the residence time. Since the two fuels obtained have different combustion behavior being respectively a gas (volatiles) and a solid (char) the oxidant (usually air) must be provided in different quantities and in different places inside the reactor to guarantee complete combustion.

Char glowing combustion is carried out in the boundary layer between the solid surface and the gaseous phase and therefore it requires an active surface available for oxygen to combine with carbon. The external layer of each particle is burnt leaving an ash deposit which partly shields the new active layer of carbon from further oxidation. Char combustion is then slowed by the incomplete availability of new active layers of carbon due to its solid geometry and ash deposits. Combustion air to oxidize char is called primary air or underfire air because it must be provided within the feedstock bed with an adequate velocity to optimize turbulence and mechanical stress on the particle for ashremoval. It will also be provided in high excess with respect to stoichiometric conditions given the disadvantaged mixing conditions between fuel and oxidant.

Considering the previous general mass composition of biomass and a generic content x [kgC/kgbio, db] of fixed carbon in the dry feedstock the following equation provides the primary air mass flow:

Rp x x x 32/12 x 100/23.3 [kg air/kg fixed carbon] (5.24)

where Rp [kgalr/kgalr st] is the ratio between the mass of primary combustion air provided and the theoretical stoichiometric primary combustion air.

Volatiles flaming combustion, on the other hand, takes place in the gaseous phase above the solid fuel bed and it is fairly more advantaged with respect to char combustion, given the high miscibility of fuel gases and gaseous oxidant. Combustion air to oxidize volatile products is called secondary air or overfire air because it must be provided above the solid fuel bed with an adequate turbulence to guarantee adequate mixing with the gaseous fuel.

As considered in section 5.2, given the generic biomass mass composition CpHqOr, the following quantity represents the stoichiometric amount of air needed to oxidize hydrogen:

(8q — r) x 100/23.3 [kg air/kg H] (5.25)

While the following quantity represents the stoichiometric amount of air needed to oxidize volatile carbon:

(p — x) x 32/12 x 100/23.3 [kg air/kg volatile carbon] (5.26)

Therefore the following equation provides the secondary air mass flow:

Rs x ((8q — r) x 100/23.3 + (p — x) x 32/12 x 100/23.3) [kg air/kg volatile matter]

(5.27)

where (kgair/kgairst) is the ratio between the mass of secondary combustion air provided and the theoretical stoichiometric secondary combustion air.

The sum of primary air and secondary air mass flows represents the total combustion air:

Rs x 100/23.3 x ((8q — r) x p x 32/12) + x x (Rp — Rs)

x 32/12 x 100/23.3 [kg air/kg biomass] (5.28)

which was already determined in 5.2 for stoichiometric conditions, and which can be easily obtained from the previous when considering Rp = Rs = 1.

Combustion performance depends strongly on the geometry of the reactor, on the air and fuel inlet and resulting turbulence inside the reactor and also on the size of the solid fuel given that the ratio between external surface of the particles, which determines the heat exchange rate and char oxidation rate and the particle volume increase with decreasing particle size. Adequate heat transfer to the solid fuel and char/volatiles mixing with air is also guaranteed by an adequate movement of the fuel inside the reactor, which must also provide a pathway for ash removal from the combustion chamber.

Biomass combustion may be used in a power cycle for CHP application or to provide process heat in a boiler or for heating and air conditioning for households or larger scale applications. Whatever the application the general process scheme would be the one in (Figure 5.11) where a generic feedstock is burnt, flue gases are cleaned of particulates in a dedicated device (e. g. cyclone) and flow into a heat exchanger providing heat to a working fluid which runs a power cycle for CHP or is conveyed directly to a thermal user. Given the relatively high biomass ash content and their possible low melting point, usually the heat exchanger is not installed directly inside the combustion chamber and it is not directly exposed to the flame to avoid high temperature corrosion and fouling of the tubes. Cooled gases are then conveyed to the emission abatement section, which can be as simple as a filter for particulate matter, and eventually reach the stack.

As described by various authors (Baukal, 2004), there are four mainly diffused typologies of biomass combustors: pile burners, grate burners, suspension burners and fluidized bed burners; depending on the application (industrial or household) the concept may be modified to fit the different size of the combustion chamber.

Pile and grate burners are often referred to as fixed bed combustors while suspension and fluidized bed burners are often referred to moving bed combustors. Their different concept and performance will be described in the following sections.

5.3.2 Fixed bed combustion

As mentioned above, fixed bed combustion is one of the most used technologies in biomass combustion thanks to the following advantages: it can fire a wide range of fuels (of varying moisture content, particle size and ash content) and requires less fuel preparation and handling. Fixed bed combustors usually consist of a two-stage combustion chamber with a separate furnace and boiler located above the secondary chamber where the oxidation of volatilized products is completed. They can be divided into pile burners and grate burners.

Erik Dahlquist with a TPV module for combined heat and electric power in small biomass fired boilers

Erik Dahlquist is currently Professor in Energy Technology at Malardalen University (MDU) in Vasteras, Sweden. His focus is on biomass utilization and process efficiency improvements. He started working atASEA Research in 1975 as engineer in analytical chemistry related to nuclear power, trouble shooting of electrical equipment and manufacturing processes. In 1982 he started with energy tech­nology within the pulp and paper industry and participated in the development of year-around fuel production from peat. In 1984 ASEA started a company ASEA Oil and Gas with a focus on off-shore production systems. One area was waste water treatment and separation of oil and water. He then became technical project manager for development of a Cross Flow Membrane filter. This led to the formation of ABB Membrane Filtration. The filter is now a commercial product at Finnish Metso Oy under the name Optifilter. As part of this development work he started as an industrial PhD student at KTH and received his doctorate in 1991. In 1989 he became project leader for ABB’s Black Liquor Gasification project, which resulted in a number of patents. From 1992 to 1995 he was department manager for Combustion and Process Industry Technology at ABB Corporate Research. He was also at that time member of the board of directors for ABB Corporate Research in Sweden. From January 1996 to 2002 he was General Manager for the Product Responsible Unit “Pulp Applications” worldwide within ABB Automation Systems. The product area was Advanced Control, Diagnostics, Optimiza­tion, Process Simulation and Special Sensors within the pulp and paper industry. During 1997-2000 he was part time adjunct professor at KTH and from 2000 to 2002 part time professor at MDU. He has been responsible for research in Environmental, Energy and Resource Optimization at MDU since 2000. During 2001-2007 he was first deputy dean and later dean of the faculty of Natural Science and Technology. He has been a member of the board of the Swedish Thermal Engineering Research

Institute division for Process Control systems since 1999. He received the ABB Corporate Research Award 1989. He has been a member of the board of SIMS (Scandinavian Simulation and Modeling Society) since 2003 and deputy member of the board of Eurosim since 2009. He has been a member of the editorial board of the Journal of Applied Energy, Elsevier since 2007. He is also a member of the Swedish Royal Academy of Engineering (IVA) since 2011. He has 21 (different) patents and approximately 170 scientific publications in refereed journals or conference proceedings with referee procedure to his name. He has published seven books, either as editor or author.

Acknowledgements

I would like to thank all contributing authors to this book. Without you this book would not have been written! Many thanks also to the Series Editor Jochen Bundschuh for checking and editing the final version of the manuscript. I would also like to thank the Swedish Energy Agency, and especially Sven Risberg, for strongly supporting our biomass research. I would also like to thank our partners at Malarenergi, Eskilstuna Energy and Environment, Vafab Miljo, ABB, SHEAB and ENA Energy for a lot of very important input on both biomass conversion and how to optimize systems.

Erik Dahlquist January 2013

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Figure 3.23 and Figure 3.24 present the CO2 and CO exhaust concentrations for TXL andTXL:DB blended fuels, respectively. Very little CO was formed in the lean regime. In lean combustion, there

is sufficient oxygen for all the carbon to fully oxidize to CO2. However, once combustion became oxygen deficient CO begins to be formed. In general, the blended fuels produced more CO because the DB fuels contained more oxygen and they release more CO during pyrolysis.

The equivalence ratio was based upon measured air and calibrated fuel flow rates. It is apparent that CO2 peaked at approximately the stoichiometric condition. As air flow was increased from

the stoichiometric point, the excess air diluted the flue gas concentrations. This dilution effect decreased the CO2 percentage. On the other hand, if air flow was decreased below the stoichio­metric air flow rate, less CO2 was formed due to insufficient O2 to oxidize fuel-bound carbon. This explains why the peak in CO2 was at approximately stoichiometric.

WYO presented trends similar to those ofTXL:DB blends. Figure 3.25 and Figure 3.26 present the CO2 and CO concentrations for WYO and WYO:DB blended fuels. The wider uncertainty bands for CO were due to the uncertainty in CO measurements being a percentage of the reading. The uncertainty bands overlap too much to draw any conclusions about the effect of blending coal with DB on CO production. The equivalence ratio was based upon air and fuel flow rates.

Combustible components of biomass gases mainly contain hydrogen, carbon monoxide and methane. They could be used for combustion and providing heat for power plant or for driv­ing pyrolysis. Biomass gases can also be used for drying instead of flue gas (Yuan et al., 2005). Thus, it is a convenient method for self-sufficiency. When the biomass gases can be used for drying agriculture and forestry products, it does not rigidly require the purity of exhaust gases after combustion. With air, the gases can be burned in all kinds of fireboxes continually and the equipment does not require cleaning and transportation long distance, and simply gives a short payback time. Compared to burning directly for heat, the efficiency is higher and it is valuable for small-scale companies and private business. Besides, biomass gasification gas can be used for drying of wood, grain, tobacco and tea directly at the same time.

4.3.4 Biomass gasification power generation

In recent years, biomass power generation technology research has progressed significantly in China. Experts predict that it will be mature in 2010 to 2020. The development direction of biomass power generation is combining cycle power generation (BIGCC) with advanced gas turbine power generation.

Biomass gasification power generation needs the following components: combustible gas is formed in a gasifier; the gas is purified and then burned in an internal combustion engine or combusted in a gas turbine to drive the generator to generate power. China has a good biomass gasification foundation, in the early nineteenth century; with charcoal gasification furnace gas, many cities in China used gas as a fuel for cars and other vehicles. In the energy shortage in the 1950s, China developed technology for rural irrigation and drainage machinery to provide power through firewood gasification furnaces, which has formed a series of product prototypes. Biomass gasification technology in the 1980s had more rapid development. In 1981 the first rice husk gasification power generation device was designed by Jiangsu Provincial Grain Bureau and a machine factory. This resulted in a 160 kW, downdraft gasifier with a Diesel Engine in Jiangsu. Later it was developed into a series of low heat value gas generators of 60, 160 and 200 kW

The Tenth Five Year’s Research Project of China is ‘160 kW fluidized bed biomass gasification generator technology industrialization research’, and a demonstration unit was built in grain processing factories in Anhui Lianhe Rice Industry Co., Ltd. Using straw, such as wheat straw and soft rice shell etc. as raw materials, with gas calorific value changing from 5200 kJ/m3 to 5800 kJ/m3, with tar content was less than 20 mg/m3, the unit has already been put into operation and gained obvious economic benefits. In Anhui Lianhe Rice Industry Co., Ltd, a set of 400 kW biomass gasification generators were established. Since then, more and more biomass gasification generators have been built in China.

In the 20th century, the Academy of Sciences Guangzhou Energy Institute has studied the circulating fluidized bed of biomass gasification power generation technology. They had a lot of achievements and experience in development and commercialization. In 1991, the first circulating fluidized bed gasification device with diameter of 400 mm, height of 4 m, and feeding quantity 200-300 kg/h has been successfully developed by the Chinese Academy of Sciences Guangzhou Institute of Energy Development in Zhanjiang City, By making use of the wood powder waste, factory products convert into fuel gas as the fuel of boilers, and coal co-firing, each year replacing more than 3000 tonnes of coal. It obtained apparent social benefit and economic benefit. In 1998, the first circulating fluidized bed gasification device and internal combustion engine generator set, 1000 kW power rice husk gasification and power generation units in Fujian run successfully. Subsequently, in Hainan, a 1000 kW biomass demonstration power plant has run successfully for more than 3 years, and has promoted the foundation of more than 20 sets.

Below are some case studies of biomass power plant projects in China.

Case 1

A demonstration construction project of 2 x 12 MW biomass power plant in QuYang city of Shanxi Province, is a renewable energy project through combusting straw directly in the boiler generation. It is an effective way to implement the law of the People’s Republic on renewable energy and the law of the People’s Republic on saving energy, which is in accordance with the renewable energy management regulations and other related policies. Implementation of the project sets an example for effective utilization of renewable resources and the development of biomass power plant in the city and province.

Crop stalks (CSS) is a rich, clean, renewable and sustainable energy. Its development and utilization can not only reduce the sulfur dioxide emissions, solve the energy related problems of environmental pollution, and promote sustainable economic and social development, but also improve the coal-dominant energy structure and layout gradually in the province. The imple­mentation of 2 x 12 MW biomass power plant demonstration project in QuYang city of Shanxi province, provide electricity safeguard for local power for local enterprise development, realize the economic and reasonable utilization of local abandoned straw, increase the farmers’ income and improve the planting industry benefit; increase the fiscal revenue and local employment opportunities, and promote the development of the local economy. Using waste heat for central heating could save energy consumption, reduce environmental pollution and improve the quality of the urban life in many aspects.

With mature technologies, the demonstration project biomass power plant in QuYang city of Shanxi province has reliable economic benefit and significant social, ecological and environmen­tal benefits. The scale of the project is 2 x 12 MW, matching 2 x 75 t/h biomass (straw) circulating fluidized bed boiler. The total investment is 181.29 million Yuan; static investment is 172.38 mil­lion Yuan. With an annual consumption of 180,000 tonnes, the annual power generation is about 150 x 106 kWh/y at full load operation. With a price of 0.51651 Yuan/kWh (including taxes), the annual income is 78.96 million Yuan, while with a price of0.44188 Yuan/kWh (not including tax), the annual income is 67.55 million Yuan. As a by-product, the annual output of chemical fertilizer is 9000 tonnes, increasing a value of 4.5 million Yuan. Using waste heat can create considerable income.

Using straw can solve three problems: energy shortage, environment protection, and addition to farmers’ incomes. If 180,000 tonnes of straw are burnt in a year, it can save about 90,000 tonnes of standard coal, reduce sulfur dioxide emissions by 900 tonnes, smoke and dust emissions by 600 tonnes. If the price of straw is 60 Yuan per tonne, the project increases local farmers’ income by more than 1000 Yuan per year.

Case 2

In Lishui city of Zhejiang province, an effective utilization of biomass gasification power of 10 MW has been built. Lishui city has a bamboo forest area of 1333.4 million m2, occupying 15.6% of the area in Zhejiang province, which is a good resource base for developing biomass power. In this project, the produced gas is directly used in a gas engine for generating power. The single-machine capacity of the electric generator is 1000 kW and the project has a total of 10 units. As a by-product, the carbon product is 80 tonnes, the bamboo vinegar fluid product is 27 tonnes, and the wood tar product is 8 tonnes every day.

This project has a 10 MW generator production with a recovery bamboo charcoal and a bamboo vinegar fluid device. Its main components are raw material field, conveying system, bunker, drying, biomass gasifier, gas cooling and purification devise, vinegar recycling equipment, carbon powder collection devices, gas generating sets, condensed water device and pipelines connecting the workshop etc.

The project’s total investment is 110 million Yuan, of which the main equipment cost is 50 million Yuan, the cost of the carbon processing equipment is 2 million Yuan, the cost of electric Internet system is 10 million Yuan, the cost of land and building construction is 20 million Yuan, the technological cost is 7.5 million Yuan, the cost of the earlier stage is 5.5 million Yuan, the current fund is 15 millionYuan. After operating, the project income is 133.728 millionYuan, after tax is 18.2216 millionYuan.

Case 3

The project of biomass gasification power in Qing Yuan city of Zhejiang province, with an investment of 110 millionYuan, is one of the first biomass gasification power projects of the east China area, which is invested in by the China Forest Energy Corporation.

The poly-generation technology, using the principle of carbon, gas, liquid and hot water are produced during the biomass processing simultaneously. The combustible gas is injected into the generator power, and hot water will be used for heating, bamboo vinegar and bamboo charcoal are collected respectively for comprehensive utilization. This biomass gasification power generation technology is realizing straw and forest tree remains high efficiency and high added value using, which is in international leading level.

The biomass gasification power project consumes remains of bamboo processing and logging

80,0 tonnes to 100,000 tonnes, generating 72 million kWh power per year, producing 24,000 tonnes of bamboo charcoal, 8000 tonnes of bamboo vinegar fluid, and providing 3000 jobs, achieving an output of more than 130 million Yuan/year.

This section describes some important properties of significance for the product composition after gasification.

6.3.1 Fuel types and properties

The performance and the selection of gasification technology are dependent on the characteristics of the fuel used. Therefore is a proper understanding of the characteristics of biomass and black liquor fuels important for a reliable selection and design of a gasifier. This chapter will briefly describe the different fuels and fuel properties of importance for gasification.

6.3.1.1 Biomass

Biomass is a diversified source and refers to any organic materials that are derived from plants or animals (Loppinet-Serani, 2008). Its diversity may be classified in a variety of ways depending on the origin and structure. One example is the division into two groups as proposed by Basu (2010):

• Virgin biomass, including ligno-cellulosic biomass in the form of wood, plants, and leaves; carbohydrate-based biomass such as crops and vegetables.

• Waste, including solid and liquid municipal solid waste (MSW), sewage, animal and human waste, gases derived from landfilling, as well as agricultural wastes.

Ligno-cellulosic biomass is the major source of biomass and will be briefly described below. This form of biomass can be divided into two types. Herbaceous plants are plants that have leaves and stems and die at the end of the growing season. Examples are wheat, rice, grasses, and oats. Non-herbaceous plants, which are non-seasonal remaining alive during the dormant season, including woody, plants, such as trees, shrubs and vines. Figure 6.3 shows the main components of woody biomass, consisting of extractives, cell wall components and ash. The cell wall compo­nents can in turn be divided into cellulose, lignin and hemi-cellulose. Extractives can basically be removed from the biomass by extraction with neutral solvents, including compounds, such as gums, fats, resins, sugars, oils, starches, tannins and alkaloids. The cell wall components are the polysaccharides, cellulose, linkage of glucose molecules in long chains form the structural framework of plant cell walls, and different types of hemi-celluloses, also chain-like and com­posed of several kinds of monosaccharides, and the complex aromatic polymer lignin. Ash is the inorganic part of the plant with the main components Si, K, Ca, S and Cl. The proportions of the main constituents are, as exemplified for wood, as follows (in percent of dry biomass): cellulose 40-45% (about the same in so-called softwoods and hardwoods); lignin 25-35% in softwoods and 17-25% in hardwoods; hemicelluloses 20% in softwoods and 15-35% in hardwoods, while the amount of extractives varies from 1 to more than 10% and ash 1-3%.

6.3.1.2 Black liquor

Black liquor is the residue extracted from sulfite or kraft processes after the cook in a batch or continuous digester. It contains a mixture of organics, inorganics and water. The inorganics consist of Na2CO3/K2CO3, NaCl/KCl, Na K2SO4/K2SO4, and some residual NaOH/KOH, NaHS/KHS and non-process elements like silica, phosphate and metal ions. The organics consist mostly of lignins, but also some hemicellulose and a little cellulose. Due to the composition of the organics

some liquors are swelling rapidly when heated, while others do not. Because of this, different liquors can behave quite differently when gasified. The water content can vary from 50% moisture down to close to 0% moisture if dried in a last step of processing, but the moisture content (MC) typically is 20-30%.

Biomass pyrolysis and gasification processes have been sufficiently developed to play a signifi­cant role in our sustainable energy future, especially as part of a biorefinery. While these processes can yield a number of gaseous and liquid fuels, this chapter provides a review of studies on the combustion and emission characteristics of syngas and biogas. There are notable differences between the combustion behavior of these two fuels and that of hydrocarbon fuels. While the syngas composition can vary widely, it generally has lower heating value, higher flame speeds, wider flammability limits, lower density, and higher mass diffusivity. Similarly biogas has lower heating value compared to natural gas, and significant variation in its composition. Such differ­ences imply different optimum operating conditions for combustion devices using these fuels, and thus significant opportunities for fundamental and applied research on both the production and utilization of such fuels. Fundamental combustion aspects requiring further research include

Flame structures in temperature, velocity, and species profiles for methane-air and biogas-air partially premixed flames at Ф = 1.4, pressure = 1 atm, and strain rate = 200 s-1.

cellular instabilities, flame stabilization and blowout behavior, turbulent flames, and emission characteristics. Such efforts would lead to the development of optimized systems for producing these fuels, and provide general guidelines for optimizing their composition for a given set of operating conditions.