• ‘Bioenergy’: the general term for energy derived from biomass;

• ‘Biofuel’: a solid, gaseous, or liquid fuel produced from biomass;

• ‘Biogas’: a medium-energy-content gaseous fuel, generally containing 40-80 vol% methane, produced from biomass by anaerobic digestion;

• ‘Landfill gas’: a medium-energy-content fuel gas, rich in methane and carbon dioxide produced by landfills that contain municipal solid wastes and other waste biomass;

• ‘Energy crops’: plants grown specifically for energy use.

5.1.1 Biomass – a renewable energy resource

Both burning biomass and burning fossil fuels release carbon dioxide (CO₂) to the atmosphere. However, there is a vital difference between the two cases: burning fossil fuels releases CO₂ that has been locked up for millions of years in the ground, affecting the natural CO₂ cycle and resulting in an increase in the CO₂ concentration in the atmosphere. By contrast, burning biomass simply returns to the atmosphere the CO₂ that was absorbed as the plants grew over a relatively short period of time (a few years to ca. a decade). The same amount of CO₂ which was absorbed from the air via the photosynthesis process while the biomass plant was growing is released back into the air when biomass is burned and there is no net release of CO₂ to the atmosphere, i.e. it is CO₂-neutral, if the cycle of growth and harvest is sustained. Therefore, biomass can be considered as a renewable energy resource (Fig. 5.1). Some net release of CO₂ would take place if the production (planting, harvesting, processing) or transportation of the biomass fuel involved the use of fossil fuels. This part of CO₂ can be significant for some biofuels which have low energy ratios (Hoefnagels et al. 2010, Cherubini 2010).

There are many types of biomass and they can be grouped by different methods in different countries. The IEA Bioenergy Education Website on Biomass and Bioenergy (IEA Bioenergy 2010a) groups biomass into categories of woody biomass, non-woody biomass and organic wastes.

Woody biomass mainly includes:

Non-woody biomass mainly includes:

Organic waste biomass mainly includes:

5.1.2 Biomass potential to the world energy supply

At the present time, the world is heavily reliant on fossil fuels for energy supply - over 80% of the current annual world energy consumption (~500 Exajoules) comes from coal, petroleum oil and natural gas (EIA IEO 2010). However, the reserves of fossil fuels are finite and subject to depletion as they are consumed - millions of years are required to form fossil fuels in the earth.

Currently, biomass is the fourth largest energy resources after coal, oil and natural gas - the current rate of the world biomass energy consumption is estimated to be in the region of 50 EJ/y which is about 10% of the world total primary energy consumption (IEA Bioenergy 2009). Biomass is the only natural, renewable carbon resource known that is large enough to be used as a substitute for fossil fuels. Some projections have shown that the world’s bioenergy potential seems to be large enough to meet global energy demand in 2050 (Ladanai and Vinterbäck 2009). The annual global primary production of biomass is equivalent to the 4,500 EJ of solar energy captured each year (Ladanai and Vinterbäck 2009) and the rate of energy storage by land biomass is in the order of 3000 EJ/y (Larkin et al. 2004). However, only a small portion of the global energy stored by biomass can be considered as sustainable biomass resources, which is generally believed to be in the region of 250 EJ/y, being equivalent to about 50% of the current global energy consumption (Ladanai and Vinterbäck 2009, European Biomass Industry Association 2010).

The future potential of the global biomass energy depends on many factors, such as land availability and productivity, and the advancement of biomass conversion technologies (Fischer and Schrattenholzer 2001, Hoogwijk et al. 2003, Demirbas et al. 2009, Ladanai and Vinterbäck 2009). But it is reasonable to assume that biomass could sustainably contribute between a quarter and a third of the future global energy mix (IEA Bioenergy 2009).

5.2.1 Proximate analysis

Since an appreciable amount of water vapour is released when a solid biomass fuel is heated to above the boiling temperature of water, the first parameter of a proximate analysis is the moisture content of the fuel. The moisture content is determined by drying solid biomass samples at 105 °C in air atmosphere until constant mass is achieved and percentage moisture calculated from the loss in mass of the sample. Standard procedures for the determination of moisture content of solid biomass fuels are specified by three British/European standards BS EN 14774-1:2009, BS EN 14774-2:2009 and BS EN 14774-3:2009.

Another major loss occurs when a solid biomass fuel is heated in a covered crucible or in other apparatus which prevents the oxidation of the carbon residue. This loss is referred to as the volatile matter and constitutes the second parameter of the proximate analysis. Volatile matter is determined with the sample being heated out of contact with ambient air at 900 °C for 7 minutes. Standard procedures for the determination of volatile matter of solid biomass fuels are specified by the British/European standard BS EN 15148:2009.

If the remaining residue is further combusted, the residue left after the combustion is called ash, and the weight loss on combustion is referred to as ‘fixed carbon’. Fixed carbon and ash contents constitute the third and fourth parameters of the proximate analysis. This part of proximate analysis, i.e. the combustion of the residue, is carried out in a furnace at 550 °C and the standard procedures are specified by the British/European standard BS EN 14775:2009.

It is not always practical to conduct the above various determinations stepwise. Therefore, one set of samples could be used for the moisture content determination, and another set of samples for the combined moisture and volatile matter loss, and still another set of samples for ash determination.

5.2.2 Ultimate analysis

The main purpose of ultimate analysis is to determine the elemental composition of a solid biomass fuel. The main elements of solid biomass fuels include carbon (C), hydrogen (H), nitrogen (N), sulphur (S) and oxygen (O) but for some solid biomass fuels chlorine (Cl) and other elements may also be of interest. Nowadays, the ultimate analyses of sold biomass fuels are usually carried out with fully automated instruments. The instrumental method for the determination of total carbon, hydrogen and nitrogen contents in solid biomass fuels is described by the British/European standard CEN/TS 15104:2005, whereas the methods for the determination of the total sulphur and total chlorine content in solid biomass fuels are specified by the British/European standard CEN/TS 15289:2006. Sometimes, the determinations of the major elements (Al, Ca, Fe, Mg, P, K, Si, Na and Ti) and the minor elements (As, Cd, Co, Cr, Cu etc.) of solid biomass fuels are also necessary and required. The British/European standards CEN/TS 15290:2006 and CEN/TS15297:2006 describe and specify the corresponding methods and procedures.

5.2.3 Calorific value

The calorific value of a fuel is the number of heat units evolved when unit mass (or unit volume in the case of a gas) of a fuel is completely burned and the combustion products are cooled to 298 K. This definition of calorific value includes the provision that the products of combustion are cooled to 298 K which means the sensible heat and the latent heat of condensation of the water produced during combustion are included in the heat liberated. Therefore, the calorific value of the fuel is designated as ‘ gross calorific value (GCV)’ or ‘high heating values (HHV)’. However, with many industrial applications, the latent heat of condensation is not given up and the total heat liberated per unit mass (or volume) of the fuel is less. The calorific value in the case where the water remains as vapour is designated as ‘net calorific value (NCV)’ or ‘low heating value (LHV)’.

The gross calorific value of a solid biomass fuel is usually determined experimentally by a bomb calorimeter, whereas the net calorific value of the fuel is usually calculated from the gross calorific value and the ultimate analysis of the fuel. Specific experimental procedures and calculation formulae are detailed by the British/European standard BS EN 14918:2009. Many solid biomass fuels contain high moisture content which greatly affects the net calorific value as illustrated by Fig. 5.2 and Table 5.1 (Larkin et al. 2004).

5.2.4 Calculation of analyses to different bases

The analytical data of solid biomass fuels may be reported on different bases including as analysed (air-dried, ad), as-received (ar), dry basis (db) and dry and ash-free (daf). Most analytical values on a particular basis may be converted to any other basis by multiplying it by the appropriate formula given in Table 5.2, after insertion of the numerical values for the symbols. However, for some parameters (H, O and net calorific value) there is a direct involvement of the moisture content. Further details on the calculation of analyses to different bases are described by the British/International standard CEN/TS 15296:2006.

Table 5.3 shows the proximate, ultimate analyses and gross calorific values of selected solid biomass fuels (Gaur and Reed 1995). The proximate and ultimate analyses of more solid biomass fuels can be found in many references such as Gaur and Reed (1995), Annalmalai and Puri (2007), and biomass databases such as Phyllis (2010).

Biomass energy conversion technologies can be classified in terms of either the conversion process they use or their end product. The following biomass conversion processes will be briefly discussed:

5.3.1 Combustion of solid biomass fuels

Direct combustion is the most common way of converting biomass to energy - both heat and electricity - and worldwide it already provides over 90% of the energy generated from biomass (Van Loo and Koppejan 2007). Direct combustion of solid biomass fuels is well understood, relatively straightforward, commercially available, and can be regarded as a proven technology. Biomass combustion systems can be easily integrated with existing infrastructure. In theory, it is possible to burn any type of biomass but in practice combustion is feasible only for biomass with moisture content of lower than ca. 50% (Goyal et al. 2008).

Combustion of a solid biomass fuel can be characterised by a three-stage process (Fig. 5.3). The first stage is drying, i.e. the evaporation of any water in the fuel. This stage does not produce energy but consumes energy. Then in the combustion process itself, there are two further stages: the volatile release (devolatisation) and combustion stage - the volatile matter is released as a mixture of vapours (CO, CO₂, H₂, H₂O, C_xH_y, etc.) as the temperature of the fuel rises, the combustion of volatile matter produces the flame seen around the burning solid fuel; and the char combustion stage - the solid which remains consists of char together with any inert matter and the char (mainly carbon) burns to produce CO₂, whilst the inert matter becomes clinker, slag or bottom ash.

A feature of solid biomass fuels is that three-quarters or more of their energy is in the volatile matter (unlike coal, where the fraction is usually less than half). The design of any biomass combustion facility should ensure that the volatile matter of the fuel is burnt to completion. The heterogeneous chemical reactions of biomass char with oxygen from air are also important - the char combustion stage is the slowest of the three stages described above. To achieve overall high combustion efficiency, a sufficient combustion time has to be provided for the char combustion stage.

Most solid biomass materials can be burnt to produce heat for use in situ or at not too great a distance. However, simple physical processing, involving sorting, chipping, compressing, air-drying, etc., is usually necessary for most solid biomass materials to be used in efficient combustion processes. Some raw solid biomass materials require further pre-treatment before they can be used in conventional combustion plants. For example, household waste, as collected, is not an ideal fuel for combustion because of its variable contents, high moisture content and low calorific value. But it can be burned in specially designed MSW (municipal solid waste) combustion (incineration) plants or converted to RDF (refuse-derived fuel) or d-RDF (densified refuse-derived fuel) to be burned alone or co-fired with coal in conventional combustion plants (Larkin et al. 2004).

Modern systems for burning solid biomass fuels are as varied as the solid biomass fuels themselves, ranging in size from small stoves through domestic space and water heating systems to large boilers producing megawatts of heat and/or electricity (Figs 5.4 and 5.5). Van Loo and Koppejan (2007) provide a comprehensive review of biomass combustion basic principles and industrial applications and therefore it is an indispensible reference for biomass combustion researchers and practitioners.

Biomass combustion produces a range of pollutants including carbon monoxide, nitrogen oxides, particulates, smoke, etc., and can have potential operational problems whether burning in dedicated combustion plants or co-firing with coal (Demirbas 2005, Van Loo and Koppejan 2007, Khan et al. 2009, H. Liu et al. 2010a). However, biomass combustion can be CO₂- neutral if the cycle of biomass growth and harvest is sustained.

5.3.2 Biomass gasification

Thermochemical gasification is the conversion by partial oxidation at elevated temperature of a carbonaceous feedstock such as biomass into a gaseous energy carrier (Liu and Neubauer 2010). This gas contains carbon monoxide, carbon dioxide, hydrogen, methane, higher hydrocarbons such as ethane and ethene, water, nitrogen (if air is used as the oxidising agent) and various contaminants such as small char particles, ash, tars and oils. The partial oxidation can be carried out using air, oxygen, steam or a mixture of them.

Air is a cheap and widely used gasification agent but air gasification of biomass produces a low calorific value gas (ca. 3-6 MJ/Nm³) which is suitable for boiler, engine and turbine operation but not for pipeline transportation due to its low energy density (Wang et al. 2008). Oxygen gasification of biomass produces a medium calorific value gas (ca. 10-15 MJ/m³) suitable for limited pipeline distribution and as synthesis gas for conversion, for example, to methanol and gasoline. Such a medium calorific value gas can also be produced by steam gasification.

Gasification is not a new process and has been around for over a century (BEF 2010, Liu and Neubauer 2010). ‘Coal gas’, the product of coal gasification, was widely used in the UK and elsewhere for many decades. ‘Wood gas’, the product of wood gasification, was used for heating, lighting and even as vehicle fuel. Both ‘coal gas’ and ‘wood gas’ were gradually superseded by natural gas from around 1930. But during the Second World War, over a million biomass gasifiers were built for the civilian sector while the military used up all the gasoline. The oil crisis of the 1970s also sparked a renewed interest in biomass gasification systems all over the world (BEF 2010).

There are many different designs of gasifiers (Basu 2010), but with the same set of main gasification reactions: those of hot steam and oxygen interacting with the solid fuel (Liu and Neubauer 2010). The gasification reactions can only proceed at elevated temperatures (a few hundred to over a thousand degrees Celsius) and pressures (from a little above atmospheric pressure to 30 times this). Similar to the combustion stages shown in Fig. 5.3 the gasification process begins with the drying of the solid fuel to evaporate moisture, followed by the release of the volatiles from the heated solid, leaving the char. Volatiles and char in turn undergo partial oxidation reactions with steam and oxygen, resulting in the combustible gas. Figure 5.6 compares the three thermochemical conversion processes of biomass: combustion, gasification and pyrolysis.

Although biomass gasification has been practised for over 100 years, so far it has had a very limited commercial impact on the energy market due to competition from other fuel sources and other energy forms. The past decade has seen a major resurgence of interest in biomass gasification processes mostly due to environmental and political pressures required of CO₂ mitigation measures. Very few biomass gasification processes have proved economically viable, although the technology has progressed steadily. However, there is sufficient expertise and knowledge now available to have a high level of confidence in modern gasification processes. Small gasification plants (< 300 kW) are now available commercially, often combined with gas engines driving small generators, and demonstration plants in the range 10-30 MW have been in operation since the mid-1990s (Reed and Gaur 2001, Knoef 2005, Wu et al. 2008, Liu and Neubauer 2010, Alauddin et al. 2010). The overall conversion efficiency from the energy of the solid biomass fuel to that of the resulting gas varies widely, from as little as 40% in relatively simple systems, to 70% or more in the most sophisticated plants (Liu and Neubauer 2010).

5.3.3 Biomass pyrolysis

Pyrolysis is the thermal decomposition occurring in the absence of oxygen, and it is also the initial step in combustion and gasification processes where it is followed by total or partial oxidation of the primary products. For many centuries, charcoal has been produced by pyrolysis of wood. The process of charcoal making involves slowly heating wood in the near absence of air, typically at 300-500 °C, until the volatile matter has been driven off. The residue is the charcoal - a fuel which has about twice the energy density of the original and burns at a much higher temperature. Depending on the moisture content and the efficiency of the process, 4-10 tonnes of wood are required to produce one tonne of charcoal, and if no attempt is made to collect the volatile matter, up to three-quarters of the original energy content can be lost (Larkin et al. 2004). Today this conventional pyrolysis process to produce charcoal is termed as ‘slow pyrolysis’. Slow pyrolysis of biomass leads to less liquid and gaseous product and greater char production (Goyal et al. 2008).

The term pyrolysis is now normally applied to the processes where the aim is to collect the volatile components and condense them to produce a liquid fuel or bio-oil. Bio-oil is composed of a very complex mixture of oxygenated hydrocarbons, and like crude fossil oil can be used for heat production, power generation and synthesis gas production as well as the production of a range of chemicals (Mohan et al. 2006, Goyal et al. 2008). Bio-oil can also be upgraded to transportation fuels (Balat et al. 2009). The main benefit of the pyrolysis process, when compared to combustion and gasification, is that a liquid fuel is easier to transport than either solid or gaseous fuels (Goyal et al. 2008). This means that the pyrolysis plant does not have to be located near the end-use point of the bio-oil, but can instead be located near the biomass resource supply, which results in considerably lower fuel transportation costs. High transportation costs are one of the limiting factors for the construction of large-scale biomass power plants, which have higher efficiencies and lower emissions than small-scale plants.

The pyrolysis reaction is relatively complex and results in non-equilibrium products, making their properties hard to predict. The products and their properties are dependent on the process temperature, the period of heating, ambient conditions, the presence of oxygen, water and other gases, and the nature of the feedstock. In general, lower process temperature and longer heating periods result in the production of charcoal, high temperature and longer heating periods increase the biomass conversion to gas, and moderate temperature and short heating periods are optimum for producing liquids (Bridgwater et al. 1999, IEA Bioenergy 2010a, 2010b). Figure 5.7 shows a widely accepted simplified model of the principal pyrolysis pathways (Bridgwater et al. 1999).

Current trends in the research and development of pyrolysis are focused on the so-called ‘ fast pyrolysis’. Fast pyrolysis is a thermal decomposition process that occurs in the absence of oxygen, at moderate temperatures with a high heat transfer rate to the biomass particles and a short hot vapour residence time (in the order of a few seconds) in the reaction zone. In fast pyrolysis biomass decomposes to generate mostly vapours and aerosols and some charcoal. After cooling and condensation, a dark brown mobile liquid is formed which has a heating value about half that of conventional fuel oil. The essential features of a fast pyrolysis process for producing liquids are (Bridgwater et al. 1999):

In comparison with combustion and gasification, biomass pyrolysis is in the early state of development. Although biomass fast pyrolysis technologies for liquid fuel production have been successfully demonstrated at small scale, and several large pilot plants or demonstration projects (up to 200 ton/day biomass feed design capacity) are in operation or at an advanced stage of construction, they are still relatively expensive compared to fossil-fuel-based energy technologies and thus face economic and other non-technical barriers when trying to penetrate the energy markets (IEA Bioenergy 2010b).

5.3.4 Biomass fermentation to produce ethanol

Fermentation is an anaerobic biological process in which sugars (e.g. C₆H₁₂O₆) are converted to alcohol by the action of micro-organisms, usually yeast. The required product, ethanol (C₂H₅OH) is separated from other components by distillation. Figure 5.8 shows the block diagram of the basic steps involved with biomass fermentation (DOE 2010).

Fermentation requires sugar, so the obvious source is sugar-cane. Brazil’s PRO ALCOOL programme - producing ethanol from sugar residues - was the world’s largest commercial biomass programme in the twentieth century (Larkin et al. 2004). Plants whose main carbohydrate is starch (for example, potatoes, corn and wheat) require initial processing to convert the starch to sugar. This route is followed in the US where the main feedstock is corn. The US ethanol industry relies almost exclusively on corn, consuming 20% of the available corn supply in 2006 (EIA ISA-Biomass 2010). Other types of plant matter, called cellulosic biomass and made up of very complex sugar polymers, are under research and development as a feedstock for bioethanol production. Specific feedstocks of cellulosic biomass currently under research and development for bio-ethanol production include: agricultural residues, forestry wastes, municipal solid waste, food processing and other industrial wastes, and energy crops. The main components of these types of biomass are 40-60 wt% of cellulose, 20-40 wt% of semi-cellulose and 10-24% of lignin, depending on the biomass sources. The lignin part remains as residual material after the sugars in the biomass have been converted to ethanol. It contains a lot of energy and can be burned to produce steam and/or electricity for the biomass-to-ethanol process. Despite various efforts to develop cellulosic ethanol in many parts of the world, further significant progress in terms of both technologies and energy policies are needed to commercialise and make cellulosic ethanol a viable economic option in the future (EIA ISA-Biomass 2010, Gnansounou and Dauriat 2010, Talebnia et al. 2010, Binod et al. 2010, Fang et al. 2010, Gnansounou 2010, Alvira et al. 2010).

The liquid resulting from fermentation contains about 10% ethanol, which is distilled off. The heating value of bio-ethanol is about 27 MJ/kg, which is about 70% of the heating value of normal petrol (~40 MJ/kg). Unlike methanol, ethanol cannot simply substitute for petrol, but it can be used as a gasoline extender in gasohol which is a mixture of petrol (gasoline) and ethanol. A few years ago, cars without engine modification could use the gasohol containing ethanol up to 26%. But now many cars have been equipped to enable them to run on E85, a mixture of 85% ethanol and 15% gasoline (WhatGreenCar 2010). With suitable engine modifications (retuning, etc.), ethanol can also be used directly.

A complete process of fermentation requires a considerable heat input but this can usually be supplied by biomass residues. The conversion efficiency of fermentation is low, but the technology is comparatively simple and the plant cost is low. When the inputs are residues or surpluses and the output is a desirable product, low efficiency of fermentation may be a price worth paying (Larkin et al. 2004). Ethanol production from biomass fermentation has been commercially available for over a decade and widely practised all over the world (Nigam and Singh 2011). World production of ethanol increased from ca. 37 billion litres in 2005 to 73.9 billion litres in 2009 (Bioethanol 2010). The world’s top five bioethanol producers in 2009 were:

However, present world-wide bio-ethanol production relies heavily on food crops such as corn, grain and sugarcane, but the limited supply of these crops can lead to competition between their use in bio-ethanol production and food provision. Cellulosic biomass is the most promising feedstock considering its great availability and low cost, but the large-scale production of bio-ethanol from cellulosic feedstock is yet to be demonstrated and commercialised (Balat 2011, Nigam and Singh 2011).

5.3.5 Anaerobic digestion

Anaerobic digestion, like pyrolysis, occurs in the absence of air; but in this case the decomposition is caused by bacterial action rather than high temperatures. It is a biochemical process which takes place in almost any biological material, but is favoured by warm, wet and airless conditions. It occurs naturally in decaying vegetation on the bottom of ponds, producing the marsh gas which bubbles to the surface and can catch fire. It also occurs in landfill sites of municipal solid wastes and purpose-built anaerobic digesters of wet wastes. Landfill gas is produced in a landfill site due to anaerobic digestion taking place over a period of years. The landfill site itself acts as the digester and the operator has very limited control of the digestion process (Larkin et al. 2004). The gas generated in purpose-built anaerobic digesters of wastes is specifically termed as ‘biogas’ which is a result of anaerobic digestion of wastes taking place over a period of days to weeks in the digesters. With the purpose-built digesters, the anaerobic digestion process can be carefully controlled by the operation temperature of the digester (Larkin et al. 2004). Both landfill gas and biogas contain a mixture of mainly methane and carbon dioxide and can be used to produce heat or electric power, or in many cases both. Biogas can also be upgraded as transport fuel as demonstrated in Switzerland and Sweden (Börjesson and Mattiasson 2007, Poeschl et al. 2010).

The basic steps of anaerobic digestion are illustrated in Fig. 5.9 (Appels et al. 2008). Despite the successive steps, the hydrolysis step, which degrades both insoluble organic material and high molecular weight compounds such as lipids, polysaccharides, proteins and nucleic acids, into soluble organic substances (e.g. amino acids and fatty acids), is generally considered as the rate limiting step. The overall rate of digestion, the composition of the final gas and residuals are affected by various parameters including pH, alkalinity, temperature, retention times and the design of the digester as well as the nature of the feedstock (Appels et al. 2008, Ward et al. 2008).

Wet biomass wastes, such as dung and sewage, are especially well suited for the anaerobic digestion process. However, some organic materials, such as lignin, cannot be effectively digested by the anaerobic digestion process. Therefore, woody biomass wastes which contain a significant amount of lignin should not be used in an anaerobic digester - gasification is a better option to convert woody biomass to a gaseous fuel. The advantages of anaerobic digestion when compared to thermochemical processes are that as a by-product it also produces a concentrated nitrogen fertiliser, and serves as a means of waste neutralisation, which would otherwise be dumped in the environment. Because of this, small-scale digesters are well suited for integration in small rural farms, and have been used extensively in several developing countries like China (Jiang et al. 2007) and India (Rao et al. 2010).

The technology of using anaerobic digestion to produce biogas is well developed and the last decade has brought about huge steps forward, in terms of maturation of biogas technologies and economic sustainability for both small- and large-scale biogas plants (Holm-Nielsen et al. 2009). Now there are a range of digesters commercially available. However, the capital cost of a digester may be out of reach for a typical small farmer in some developing countries (Larkin et al. 2004). Nevertheless, there is considerable potential for biogas production from anaerobic digestion in Europe, as well as in many other parts of the world (Holm-Nielsen et al. 2009, Jiang et al. 2007, Rao et al. 2010).

5.3.6 Biodiesel production

Biodiesel production from oilseed crops such as soya, rapeseed, sunflower, corn, etc., involves chemical and/or physical processes. The first step of biodiesel production from oilseed crops is to produce vegetable oils from the feedstock and the second step is to produce the biodiesel from the vegetable oils. The direct use of vegetable oils as fuel in compression ignition engines is problematic due to their high viscosity (about 11-17 times greater than petroleum diesel fuel) and low volatility (Atadashi et al. 2010). Vegetable oils do not burn completely and form carbon deposits in the fuel injectors of diesel engines and therefore conversion of the vegetable oils to biodiesel is preferred.

There are two main processes for extracting oil from biomass seed feedstock: mechanical press extraction and solvent extraction. In mechanical press extraction, the oil seed feedstock is first heated to about 40-50 °C. The oil seed is then crushed manually or automatically (e.g. in a screw press). After most of the oil is removed, the remaining seed meal can be used as an animal feed. The solvent process extracts more of the oil contained in the oil seed feedstock but requires more costly equipment. The process uses a solvent (most commonly hexane) to dissolve the oil. After extraction, a distillation process separates the oil from the solvent. The solvent condenses and can be recycled and reused in the process. Solvent extraction produces vegetable oil with a higher degree of purity than the mechanical press process.

Several methods are available for producing biodiesel from vegetable oils but currently the method of choice is a chemical process, called ‘transesterification’ (Ma and Hanna 1999, Singh and Singh 2010). The main purpose of the transesterification process is to lower the viscosity of the oil. In the transesterification process, vegetable oil reacts with an alcohol (methanol or ethanol), usually in the presence of a catalyst, and reduces its viscosity, resulting in a higher quality fuel, biodiesel.

Biodiesel can also be produced from recycled oil or fat (Enweremadu and Mbarawa 2009). It is estimated that about half of the biodiesel industry can use recycled oil or fat. Biodiesel production from waste oils from chip shops is already a reality in the UK. Argent Energy (UK) Limited operates the UK’s first large-scale biodiesel plant which started the production of biodiesel in March 2005 using recycling tallow and used cooking oil (Argent Energy Limited 2010).

The energy content of biodiesel is 10-12% lower than petroleum diesel (~38 GJ/tonne vs. ~42 GJ/tonne). Biodiesel has many advantages, including (EBB 2010):

Biodiesel production has increased dramatically over the past few years. Biodiesel is now widely available in many countries. The top five biodiesel producers in 2009 were (Biodiesel 2010):

5.4.1 Introduction of biomass CHP technologies

Biomass CHP technologies can be grouped in different ways such as by the biomass conversion technology or by the prime mover. In this chapter, they are grouped by the biomass conversion technology.

Various combinations of biomass conversion technologies and prime movers have been used with biomass-fuelled CHP systems as shown in Table 5.4. The biomass conversion technologies, namely combustion, gasification, pyrolysis, fermentation, anaerobic digestion and biodiesel production were discussed in the Section 5.3, whereas the prime movers, namely steam turbines, steam engines, Stirling engines, organic Rankine cycle turbines, gas turbines and internal combustion engines, are characterised in other chapters of this book, and therefore, the following discussion on the biomass CHP technologies will focus only on the specific features of the combinations of the biomass conversion technologies and the prime movers.

5.4.2 Combustion-based biomass CHP technologies

Combustion-based biomass CHP technologies are the dominant ones that are used from large-scale power plants to micro-scale CHP systems. The heat released from biomass combustion is used to produce steam, hot air or organic working fluid vapour which can drive a steam turbine, a steam engine, a hot air gas turbine or an ORC turbine to generate electricity.

5.4.3 Gasification-based biomass CHP technologies

Gasification-based biomass CHP technologies are probably the second most popular category of technologies for large- to micro-scale biomass CHP systems. For large-scale CHP systems, such as power plants, biomass gasification can be combined with gas turbines and/or steam turbines (integrated gasification combined cycle - IGCC) as adopted by some global manufacturers of power generation units/components such as General Electric (GE Power 2010). For small- and micro-scale biomass CHP systems, when gasification is adopted as the biomass conversion technology, there are three main choices for the prime mover: gas turbines, internal combustion engines and fuel cells. The success of the small- and micro-scale gasification-based CHP systems will depend largely on the quality of the combustible gases produced by biomass gasification - there are specific requirements for each prime mover in terms of gas quality and cleanliness (Liu and Neubauer 2010). Gas cleaning and conditioning of the combustible gases produced by biomass gasification can be very costly and energy intensive for small- and micro-scale gasification-based CHP units (Liu and Neubauer 2010).

Community Power Corporation (CPC), the Modular Bioenergy Company of the United States, has developed and commercialised biomass CHP systems which are based on the technologies of gasification and internal combustion engine with capacity ranging from 25 kWe to 75kWe (CPC 2010). Each of CPC’s CHP systems consists of a gas production module which contains a downdraft gasifier and gas cleaning equipment, etc., and a power generation engine which is either a spark ignition engine or a compression ignition engine. Schmitt Enertec GmbH of Germany (Schmitt Enertec 2010) commercially supplies biomass gasification and internal combustion engine-based CHP systems with capacity between 250 kWe and 1000 kWe. The specification of these CHP systems indicates that the electric power generation efficiency is ca. 26%, whereas the overall CHP efficiency is ca. 80% (Schmitt Enertec 2010). The combination of biomass gasification with a solid oxide fuel cell (SOFC) and/or micro gas turbine for small-scale CHP was assessed using Aspenplus™ process simulation software by Fryda et al. (2008). Karellas et al. (2008) investigated an innovative allothermal biomass gasification process - the Biomass Heatpipe Reformer (BioHPR), and its coupling with micro turbine and SOFC systems. M. Liu et al. (2010) carried out the feasibility study of applying biomass gasification to a SOFC system for distributed power/CHP generation in rural areas of China. Their preliminary system calculations indicated that an electrical efficiency of 32% and an overall CHP system efficiency of 59% were achievable with a 100 kWe biomass gasification-SOFC CHP system.

The development of biomass gasification-based micro-scale CHP systems is less advanced in comparison to the development of biomass combustion- based micro-scale CHP systems. This is partly due to developers’ and the general public’s perceptions and concerns about the safety issues of biomass gasification. The technical and economic challenges of biomass gasification may also have contributed to this phenomenon, considering that biomass combustion is a mature and well-developed biomass conversion technology.

5.4.4 Other biomass CHP technologies

There are various other technologies available for biomass combined heat and power generation, such as using bio-ethanol/bio-oil/biodiesel and biogas to fuel internal combustion engines and gas turbines/micro-turbines. As pointed out in Section 5.3, many internal combustion engines can burn a blend of gasoline and bio-ethanol, a blend of petroleum diesel and biodiesel, and biogas, and hence internal combustion engine-based CHP systems can be fuelled by liquid biofuels and biogas. A UK-based company, Ener-G Combined Power, commercially supplies biogas-fuelled CHP units within the size range of 30 kWe to 1950 kWe and biodiesel-fuelled CHP units with the size range of 130 kWe to 385 kWe (Ener-G 2010). Two 385 kWe biodiesel CHP systems are to be installed in the Museum of Liverpool and expected to be in operation in summer 2011 (CHPA 2010). Over the past decade, many turbine/micro-turbine manufacturers have developed gas turbines and microgas turbines which can successfully burn biogas such as the micro-turbines made by the Capstone Turbine Corporation of the United States (Capstone 2010). Capstone now commercially supplies biogas-fuelled micro-turbine power generating units within the size range of 30 kWe to 1000 kWe.

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