Thursday, January 23, 2020

The New Generation of Coal-fired Power Stations With High Thermodynamic Efficiency

2.1 Introduction

Energy drives human life and is crucial for continued human development. It is the convertible currency of technology. Without energy the whole fabric of society would crumble. Global demand for energy is rapidly increasing with increasing human population, urbanization, and modernization. This growth is projected to rise sharply over the coming years in developing countries. The world heavily relies on fossil fuels to meet its energy requirements – oil, gas, and coal are providing almost 80% of the global energy demands. Oil and natural gas prices are continuously rising, due to the rapid worldwide increase in their consumption. Coals, covering about 65% of the proven fossil fuel reserves and being widely distributed throughout the world, provide stability in price and availability and will therefore play a major role in the global energy system in the coming decades. Furthermore, given the energy crisis, the development and use of renewable energy sources is one of the key challenges in the shorter and medium term to substitute fossil fuels, to provide commercially attractive options for meeting specific energy service needs, and to mitigate green- house gas emissions. Biomass, including all kinds of materials that were directly or indirectly derived not too long ago from contemporary photosynthesis reactions, such as vegetable matter and its derivatives, is a widely dispersed, naturally occurring carbon resource with great energy potential. It is also considered as a CO2-neutral energy source. The simple act of burning biomass to obtain heat and often light is one of the oldest biomass conversion processes known to mankind.

Thus, the study of coal and biomass combustion for power generation or heating processes is of extreme importance, if we are to conserve our sources of energy, while achieving the required environmental goal efficiently and reliably in a world of increasing population and energy needs. This chapter provides a survey of the technologies that are either available or are being developed to enable all solid fuels to be used cleanly and with greater amenity.

The chapter begins with a discussion of the physical and chemical properties    of coals, which influence the design and the performance of combustion processes. The conventional methods of combustion – stoker firing, pulverized coal firing, and cyclone firing – are then considered in some detail. However, emphasis is given to emerging clean coal technologies with higher thermodynamic efficiency and inherent emission control for reducing oxides of nitrogen and sulfur, or the greenhouse gas CO2. The most promising of these technologies include fluidized bed combustion, both atmospheric and pressurized, supercritical pulverized-coal combustion, low NOx burners and near-zero emission technologies. For each process, key issues, current status with technical and environmental performance data, as well as future technological developments are discussed.

Following the presentation of coal combustion technologies, this chapter also focuses on biomass, which requires specialized combustion techniques, as it differs from coal in many important ways, including the organic, inorganic, and energy content and physical properties. Thus, the influence of the physical and chemical parameters of biomass fuels on the combustion process is firstly explained. Currently available or under development biomass combustion technologies for industrial utilization, such as grate furnaces, underfeed stokers, fluidized bed systems, and dust combustion systems, are described. Improved processes for conversion of virgin biomass and complex waste biomass feedstocks into heat, steam, and electric power, such as large incinerators with heat recovery and modern boiler systems with minimal emissions, are all comprehensively reviewed. Examples and experience from several countries around the world are presented.

Finally, this chapter concludes with an outlook and a summary, highlighting the most promising technologies for the near future and the role of solid fuels in providing international energy security and sustainable development.

2.2 Coal Characteristics Affecting Combustion Processes

The composition and properties of a coal influence all aspects of the combustion process, from the milling to the design and performance of the boilers and the  environmental control systems.

2.2.1 Coal Structure and Petrographic Composition

The macropore structure of the coal becomes a major factor in determining char reactivity at the elevated temperatures of combustion, because of limited diffusional access to smaller pores. Thus, chars from low-rank coals are generally more reactive than chars from higher rank coals, due to their increased porosity. Furthermore, the role of coal structure on char reactivity is related through the variations in active sites, surface area, and pore structure, which result from devolatilization processes [1].

The petrographic constituents of coal are known to behave differently during combustion. Vitrinite-rich particles expand to form cellular structures, whereas  fusinite-rich particles show little or no expansion. Expansion is greatest for medium volatile coals, but the extent of expansion is influenced by the rate of heating. Vitrinite-rich particles have a higher burn-off rate than fusinite-rich particles [2].

2.2.2 Organic Elements and Sulfur Content

The level of organic oxygen in coals affects the degree of reactivity for combustion. As the coal is heated, dissociation of this oxygen from the organic matrix occurs, leaving reactive sites for combustion. On the other hand, oxygen functional groups can bind inorganic cations, such as Na, Mg, Ca, and K, which affects the behavior of ash- forming elements during combustion.

The nitrogen content of low-rank coals is not considered a significant factor in determining NOx emission levels during combustion, where the flame temperatures are also low [3].

The sulfur in coal can cause corrosion on the surfaces of the economizers, the air heaters and other ducts of the boiler unit, through sulfuric acid that is generated from the organic and inorganic sulfur-bearing compounds via reaction of sulfur trioxide with water vapor. Even low levels of sulfuric acid in the flue gas (10–50 ppm) will raise the dew point from a water dew point of 38–49 ℃C to an acid dew point of 120–175 ℃.

If the surface temperature of a boiler section is below the dew point, relatively strong sulfuric acid (70–90%) can then condense and seriously corrode these surfaces. The sulfuric acid can also interact with fly ash in the furnace to form sulfates of sodium, potassium, aluminium and/or iron, which promote corrosion even at temperatures higher than the acid dew point. The production of sulfur trioxide, and therefore of sulfuric acid, can be reduced by the presence of water vapor, addition of compounds capable of removing the oxygen atoms, or injection of fly ash to coat the superheater tubes [4, 5].

2.2.3 Moisture and Volatile Matter Contents

The high moisture content of coals, apart from causing problems in delivery, storage, handling, pulverization, and drying systems, lowers the flue gas temperature during combustion and carries sensible heat out with the flue gases. In the case of low-rank coals, it demands a larger furnace size, to maintain the same energy output as higher rank coals and therefore increases the CO2 emissions per kWh.

Volatile matter is important for the control of smoke and ignition. Coals with a lower content of volatiles burn slowly and the use of auxiliary fuel, or finely ground material, is often needed. Volatiles yield is important in determining flame stabilization. Coals that provide a high volatile yield allow use of a smaller burner to  achieve the same throughput, when compared to coals of lower volatile yields.

Furthermore, the high volatile yield coals allow greater flexibility in burner design and operating conditions [3, 6].

2.2.4 Calorific Value

Alowcalorificvalueincreasestoagreatextentthequantityoffuelrequiredforburning, for a given steam or electric power production rate. The number and size of the mills, the size of the furnace, and all auxiliary equipment must also be larger, to handle the derived throughput and generate the same amount of steam. The increase in coal feeding rate could wear out the mechanical parts of the system and produce higher amounts of fly ash, thus reducing the efficiency of particulate control equipment.

2.2.5 Agglomeration Properties

Some bituminous coals agglomerate during heat up, since they go through a softening and melting stage. For low rank coals, in comparison to bituminous coals, the same degree of fineness is not required to assure burnout, because particle surface area will not tend to increase due to agglomeration.

In fluidized beds, agglomeration can take place where low melting point components or ash particles are present on the particle surface, where there are localized hot spots and the temperature exceeds 900 ℃, or a combination of sintered fly ash and fine sorbent [7, 8].

2.2.6 Ash Content and Composition

Coal ash and inorganic volatile matter, generated by thermal alteration of mineral matter, is of great concern for the combustion process in pulverized fuel boilers. This material not only contributes heavily to stack emissions but also reduces the heat transfer in the furnace, alters the flow of the gases, and deposits on heat transfer surfaces, threatening the integrity of the combustion system by severe corrosion. These deposits reduce the power of the unit and thus increase the cost of the energy produced. Therefore, large installations must provide for effective countering of these hazards.

The extent of ash-related problems depends upon the quantity and association of inorganic constituents in the coal, the combustion conditions and the system  geometry [9, 10]. The composition of ash affects its softening temperature, its viscosity, and ash fouling, fusion characteristics that also determine the mode of its removal, either as dry ash or as slag.

2.2.6.1 Effect on Ash Softening Temperature

Among the various constituents of coal ash, the oxides of Al, Si, Ti, Ca, Mg, Na, and K and especially Fe2O3 are responsible for its fusion.

When the ash fusion temperature is lower than the furnace temperature, the  retained ash melts. If the design of the system does not allow for the drainage of the ash as a slag, then severe clinkering may occur, causing a lot of problems in its removal, particularly in the lower parts of the furnace where the use of side fans is not possible.

2.2.6.2 Effect on Slag Viscosity

Even if two coal ashes have the same softening temperature they may have widely different flow characteristics. The relevant property of the ash, which represents better its fluidity at a stated temperature, is the viscosity. In boiler practice, tapping of the slag in the liquid state is readily accomplished at slag viscosities ranging from 50–150 poise [3].

For fixed furnace temperatures, the slag viscosity varies with the chemical composition of the ash. The relationship between slag viscosity and ash chemical composition may be correlated in many ways, the best known of which are the equivalent silica percentage and the base-to-acid-ratio of ash constituents [11, 12]. Slags having similar equivalent silica percentages have a similar viscosity–temperature relationship. The constituents of coal ash can be classified as either acidic or basic. The acidic constituents are silica, alumina, and titania, while the basic constituents are iron, calcium, and alkalis. The viscosity of a coal ash decreases as the base-to-acid ratio increases to one.

2.2.6.3 Effect on Fouling

During combustion, the inorganic coal components undergo complex physical and chemical transformation stop roduce intermediate ash species, which consist of gases, liquids, and solids. In low-rank coals, mineral grains also interact with organically associated elements. The size and composition of all these intermediate species directly influence slagging and fouling problems in combustion systems [13, 14].

Fouling is any form of ash deposit that retards heat transfer, or obstructs the flow of gases through the unit. It is classified as [5, 15]:

1) Fused-slag deposits, which develop principally on surfaces exposed to radiant heat transfer, such as on the furnace walls and the first few rows of boiler or superheater tubes. These form by impaction of superficially sticky gas-entrained particles on solid surfaces and can cause extensive erosion. The severity of this problem depends mostly on the size, shape, hardness, and velocity of the particles, but also appears to vary with the angle of impact.

2) High-temperature bonded deposits, which develop on convection-heating surfaces in regions of moderately high-gas temperature, principally in the super- heater. These deposits typically consist of a strongly adhering dense core, surrounded by a fly-ash-like layer and they are mainly derived from alkali metals, such as sodium and potassium chloride, sulfate, calcium chloride, fluorapatite [Ca10F2(PO4)6], silica, and sintered ash. The mechanism by which high- temperature deposits build up is evidently connected with the volatility of alkali metal chlorides and sulfates.

3) Low-temperature deposits, which develop on connection heating surfaces of the economizer and the air heater. These are formed by condensation of aqueous vapors and entrapment of fly ash and thus are primarily sulfate-based [4]. Fly ash can cause severe corrosion. Its composition as well as the size and the shape of the particles are the main factors that influence this type of corrosion.

High-temperature bonded deposits occur with most low-rank coals, due to their high content in alkali constituents, which volatilize during combustion. The alkalis are also responsible for external corrosion through formation of the alkali iron trisulfates [Na3Fe(SO4)3 and K3Fe(SO4)3], which melt below 600 ℃ [16]. As a result of the low fusion temperature ash of low-rank coals, boiler furnaces must be larger, tube spacing must be more generous, more wall and soot blowers must be provided, and larger fans must be available to allow for the added draft loss caused by deposits in the convective tube banks, compared with furnaces burning bituminous coals.

Organically bound calcium reacts extensively with quartz and clay minerals to give both amorphous and crystalline calcium silicates and aluminosilicates. The products of reaction have lowered melting points; hence their formation may favor enhanced deposit formation [17]. However, large grains of calcite could "dilute" deposit strength [18].

The silica content of ash, despite its strong influence on the viscosity of the slag, can cause several problems, too. High silica ash is very abrasive and can erode the coal feeding systems and burners. When high silica content is coupled with high sodium content, massive deposits can form on heat transfer surfaces.

The basic approaches for controlling fouling are: (i) conservative design of furnace height and area, to allow ample time for burnout, thereby minimizing the furnace exit temperature; (ii) installation of an adequate number of sootblowers at spots likely to be troublesome; (iii) use of fuel additives containing calcium or magnesium to reduce the fluxing ability of any molten ash phases, or containing aluminium to form high-melting point materials; (iv) to limit the sodium content of the coal by selective mining, blending, or ion-exchange; (v) to micronize the coal to produce smaller and weaker deposits; and (vi) to co-fire the coal with other fuels to produce deposits that contain primarily silicon, iron, and aluminium and less than 0.8% sodium [4, 19].

2.3 Conventional Coal Combustion Technologies

Direct coal combustion is a widely used technology for power production or heating processes. There are two principal modes of burning coal: in a fuel bed or in suspension. In fuel bed combustion, relatively coarse coal is fed onto a grate and the type of burning is determined by the direction of flow of the fuel and air. This type of firing system is known as a stoker. Fuel bed appliances can be economically used for heat rates up to 135 tonnes of steam per hour. For higher steam rates recourse is made to suspension firing.

In suspension firing, fine coal is thoroughly mixed with air in pulverized-coal furnaces, or in cyclone furnaces. In a pulverized-coal furnace the coal is fully entrained by the stream of air. In a cyclone furnace the coal is swirled by the stream of air into cylindrical burners and only small particles burn by entrainment. Pulverized-coal furnaces are in widest use among utilities.

2.3.1 Stokers

Industrial stokers are the oldest and most common devices used for combustion of coal in fuel-beds. They were used to burn coal as early as the 1700s. Recently, stokers have lost a great part of their traditional market to fluidized beds.

In a stoker, the crushed coal (typically 95% less than 32 mm and 20–60% less than 6 mm) is fed on the grate, through which primary air flows upward and through the bed of particles. The raw coal is heated, dried, devolatilized, and burned, leaving ash material at the bottom of the bed. The layer of ash formed on the grate protects it from excessive heat. The temperature in the fuel-bed is determined by the rate of burning, which in turn is determined by the relative velocity between the fuel and the gases, the rank and size of the coal, as well as the height of the bed. The volatile constituents and the carbon monoxide produced by partial combustion of the coal char are burned above the fuel bed, where secondary air is injected to facilitate the burning.

The power requirements of stokers are low. However, coal losses are considerable in such units. When selecting a stoker, the heat demands, the fluctuations in feed, and the availability of suitable fuels must be taken into account [3].

Stokers have evolved over the years from a simple design to quite sophisticated devices to burn various fuels, including coal. Depending on the different techniques for feeding coal to the grate, they are classified as overfeeds and underfeeds. The overfeed group includes spreader, chain, and vibrating grate stokers, while the  underfeed group includes single and multiple retort stokers. Table 2.1 summarizes the basic characteristics of the various types of stokers.

Table 2.1 Stoker characteristics [20].

Figure 2.1 Spreader (a), chain grate (b), vibrating grate (c), and multiple retort underfeed (d) stokers.

2.3.1.1 Spreader Stokers

Spreader stokers are the most commonly used type of stokers, because they can burn a wide range of coals, from bituminous to lignite, and they can accommodate a wide range of boiler sizes [21]. In these stokers, the coal is thrown and spread over the entire grate surface, by mechanical feeders (Figure 2.1a). Some burning of the suspended coal fines occurs above the bed, which coupled with a very thin coal bed allows fast response to load changes.

A typical installation consists of feeder-distribution units, air metering grates, forced draft fans for both undergrate and overfire air, dust collecting and re-injecting equipment, and combustion controls to co-ordinate fuel and air supply with load demand. Smaller units use dumping grates, while larger units use continuous discharge grates.

The spreader stoker is usually employed in a capacity range up to 45 tons of steam per hour. It has high availability, simplicity of operation, and high operating efficiency. However, is has high fly-ash carry-over and combustible heat loss. Reinjection of the unburned fuel to the furnace can increase the efficiency by 2–3%. Also, size segregation can be a problem, when fine and coarse coals are not distributed evenly over the grate, producing a ragged fire and poor efficiency. A coal size ranging from 0 to 20 mm is generally recommended, when boiler load is relatively constant [3, 22]. Although operation is very sensitive to the size distribution in the feed, a given spreader stoker will burn almost any kind of coal, provided that the appropriate size distribution is used. This makes the spreader stoker an attractive option for small installations that might be using coal from several sources.

2.3.1.2 Chain Grate Stokers

In a chain-grate stoker, coal is fed from hoppers to a grate, which consists of an endless chain extending into the furnace (Figure 2.1b). The horizontal movement of the grate carries the coal into the combustion chamber, where its top surface is ignited by radiation from a hot refractory arch. The flame front then travels down through the coal bed, while the air comes up through it. The bed grows progressively thinner, as combustion continues, and as the grate turns for the return journey the residual ash is dropped into a container. Heat release rates higher than is permissible with an arch can be achieved if overfire air jets are used to complete the combustion of the volatile gases.
Chain grate stokers are characterized by low fly ash carry-over. They burn most coals, but high coking coals can be a problem. Their response time is longer than that of the spreader stokers [22]. Whilst the top size of the coal should preferably be about 30–50 mm, a somewhat larger size can be used in the case of low-rank coals with moisture content below 35%, since they ignite easily and burn freely.

2.3.1.3 Vibrating Grate Stokers

In a vibrating grate stoker (Figure 2.1c) the entire structure is supported by several flexure plates, allowing the grid and its grate to move freely in a vibrating action that conveys coal from the feeding hopper onto the grate and gradually to the rear of the stoker. Ashes are automatically discharged to a shallow or basement ash pit. The use of high pressure air jets through the front arch provides turbulent gas mixing and promotes combustion.

The grates are water-cooled and vibration is intermittent. The frequency of vibration is adjusted by a timing device, which is regulated by the automatic combustion control system to conform to load variations, synchronizing the fuel feeding rate with the air supply.

The water-cooled vibrating grate stoker is preferred for its simplicity, low fly ash carry-over, very low maintenance, suitability for burning multiple-fuels and a wide range of coals from bituminous to lignite. It can also successfully burn coals with a high free-swelling index, because the gentle agitation of the grate keeps the bed porous, without the formation of large agglomerates. The stability of air and fuel distribution, in this type of stoker, guarantees a good response of the system to load fluctuations and operation, without smoke production [3].

2.3.1.4 Underfeed Stokers

Underfeed stokers have been widely used in small industrial boilers with outputs of approximately 0.5–3 MW. The coal is introduced through long retorts below the level of air tuyeres (Figure 2.1d). Thus, the raw coal is at the bottom, the ash moves away from the retort at the top, and combustion takes place in between. The flame  front tends to move downwards, its speed being matched by the rising flow of coal.

The system hence fulfils the requirement of the flame front, traveling in the opposite direction to the primary air.

The smallest underfeed stokers use the single and the double retort. In these, the coal is fed by a screw or a ram and the ash is usually discharged with the side-dumping grates. These types are suited for steady load operation, due to their ability to maintain ignition over a part of the grate area, then automatically expanding the active burning

area as the controls call for more fuel and air [23]. Larger underfeed stokers use multiple retorts, inclined at an angle of 25–30° to aid the flow of coal and ash. The ash is discharged either intermittently or continuously.

The size of the coal furnished to underfeed stokers should be in the range of 30 mm to zero. A reduction in the percentage of fines helps to keep the fuel bed porous and extends the range of use to coals with a high free-swelling index.

Underfeed stokers operate with very thick coal beds, causing a high thermal inertia and a slow response to load changes. Lignites, however, do not agglomerate and tend to burn in a thin layer of independent particles. The air draft, supplied through  tuyeres in the side of the unit, or mechanical agitators, used to keep a thick bed of bituminous coal moving, are likely to cause the lignite to accumulate in drifts, with the consequence that burning is uneven across the area of the stoker [18]. Underfeed stokers have trouble burning strongly coking coals, low ash bituminous, and loose ash sub-bituminous coals because of the grate overheating. On the other hand, they have a clean smokeless combustion and low fly ash carry-over. The smokeless combustion comes from feeding the coal under the combustion zone. The volatiles escape from the raw coal, flow upward through the combustion zone and burn almost completely while passing through the zone [3].

Underfeed stokers are gradually being displaced by the spreader and vibrating grate types. There has been little research or development of fixed bed combustion technologies in recent years. In addition to furnace development and fuel improvement for these systems, the focus has been on reduction of emissions and improvement of stokers efficiency. Guidelines for clean and efficient operation of stoker boilers have been prepared. Improved overfire air systems and flue gas recirculation systems for controlling nitric oxides have been developed [22]. Methods of choosing the optimal rate of travel of the grid and height of the fuel layer for increased thermal efficiency have been suggested [24].

2.3.2 Pulverized-Coal Furnaces

Suspension firing concerns combustion of air-entrained pulverized coal as it passes through a furnace. This technique, which is by far the most common method of coal use, obviates the need for a supporting grate, eliminating restrictions on equipment size and allows satisfactory combustion of virtually any kind of non-caking coal. In addition, since it releases substantially more heat per unit volume of combustion space firing, it is used for steam generation at rates >135 t h—1. Pulverized-coal furnaces can be built to match steam turbines, which have outputs between 50 and 1300 MWe [25].

In most power station boilers, coal must be pulverized, so that 70–80% passes a 75 mm screen. This requires the use of high capacity pulverizers, the operating costs of which make a significant contribution to the cost of electricity generation. The size and the number of the mills increase in the case of lower rank coals, due to their lower heating value. Furthermore, to produce the desired heat input to the furnace, the mills must deliver the coal at the proper moisture condition. Excessive moisture can limit the throughput of the pulverizers.

After the coal is pulverized, it is transported with primary air to a burner into the furnace, while secondary air is heated and introduced through the burner ports to ensure complete combustion. To maintain a stable intense flame and avoid flashback through the burner, the coal must be injected at a relatively high velocity, typically 15 m s—1.  Efficient  combustion,  with  no  significant  loss  of  unburned carbon, demands some care in matching burner configurations and furnace dimensions,   as well as longer residence time than in a fuel-bed, since combustion of the char occurs in an atmosphere of decreasing oxygen concentration. The residence time in the furnace is typically 1–2 s, while the combustion temperature is 1300–1700 ℃. A large portion of the ash leaves the furnace as fly-ash, some of which deposits on the tubes, causing slagging and fouling, and the remaining falls to the bottom of the furnace and is removed [21, 22, 26].

Most conventional pulverized-coal fired boiler systems use subcritical pressure steam cycles (<22.1 MPa at 540 ℃) with superheated and single reheated steam. This results, depending on feedstock, steam conditions, condensing pressure, and plant size, in thermal efficiencies in the range of 35–38% (based on LHV) [5]. Boiler designs of two kinds are usually used. In the traditional two-pass layout the furnace is topped by some heat transfer tubing. Then, the flue gas is turned through 180° and passes downwards through the main heat transfer and economizer sections. The other design uses a tower boiler, where virtually all the heat transfer sections are mounted vertically above the combustion chamber [25].

The main advantages of pulverized-coal combustion are the high reliability, adaptability to all coal ranks, full automation, and excellent capacity for increasing unit size. The main disadvantages are the high energy consumption for pulverizing coal, high particulate emissions, and high SO2 and NOx emissions.

Most pulverized-coal combustion technologies developed up to 2000, classified as clean coal technologies, are concerned with controlling and reducing pollution. Some of these technologies, being developed and demonstrated in the USA under the "Clean Coal Technologies Demonstration Program," are: the LIMB demonstration project extension and cool-side demonstration; the 180 MWe demonstration of advanced tangentially fired combustion techniques for reduction of NOx emissions
from coal-fired boilers; the full scale demonstration of low-NOx Cell™ burner retrofit; and the micronized coal reburning demonstration for NOx control on a 175 MWe wall-fired unit [3, 27]. Future developments, including improvements in efficiency, boiler design, materials of construction, and environmental performance, are presented in Section 2.4.

Pulverized coal-fired furnaces are usually classified according to the method of ash removal into "dry-bottom" and "wet-bottom" furnaces. The "dry-bottom" furnaces are simpler, more flexible with regard to load range and fuel properties, and more reliable than "wet-bottom" furnaces. However, they are larger for the same capacity (and thus more costly) and 80–90% of the ash leaves the furnace as fly-ash, which must be removed in the electrostatic precipitator. The interest in developing "wet- bottom" units was to avoid this problem of dust disposal as much as possible. The molten ash flowing from the furnace is quenched by water and reduced to a coarse, granular solid. Ash retention of more than 80% has been achieved with some designs. At the same time, higher heat release rates are used, in an effort to reduce equipment size [22, 23].

2.3.2.1 Dry-Bottom Furnaces

In dry-bottom firing, the ideal furnace is so designed that the flames clear the walls, at most lightly brushing them. The temperatures developed near the walls produce little or no ash melting and the products of combustion are cooled sufficiently before leaving the furnace to prevent troublesome ash adherence in the convection banks. This ideal is rarely achieved, and most actual units experience some slagging and/or fouling of heat transfer furnaces. Figure 2.2 shows the most frequently used furnace and burner configurations. These arrangements cover firing systems suitable for all ranks of coal.

In horizontal and opposed horizontal furnace types, coal–air mixtures are blown in on opposite sides of the firebox and impinge on one another near the center of the furnace. These configurations are usually fired by circular turbulent burners, spaced uniformly across the width of the furnace, in either the front- or rear-wall or both. Each burner has its own relatively independent flame envelope and ignition point and the firing system may be designed so that an individual burner can be placed in  service, adjusted, or removed independently of the other burners. This type of combustion produces high flue gas temperatures and carbon burnout, but has the disadvantage of producing high NOx levels, too [23].

In tangential and opposite inclined firing furnace types, jet burners project the streams of coal and air along a line tangential to a small circle, lying in a horizontal plane, at the center of the furnace. The burner turbulence ranges from nil to moderate, according to the designer's intent and is replaced by the overall furnace turbulence. In such furnaces there is a single overall flame envelope. Flame length is long and combustion of coal is rapid. These characteristics give the designer a degree of control over the peak flame temperature, which can form low levels of NOx formation, although care must be taken to avoid flame instability at partial loads, when the individual burners tend to assume their own identity. It has also been  argued that such firing arrangements are less vulnerable to unequal proportioning of air and fuel to the burners, but this can cause imbalance of the superheater, or reheater element temperatures [26, 28].

Single U-flame and double U-flame furnaces are used for firing fuels that are hard to ignite. The fuel with its transport air and a portion of the necessary combustion air is fired vertically downward through a burner arch, located about halfway up the furnace. The remaining air required for combustion is admitted through the vertical walls below the arches. Radiation from the rising portion of the coal flames and from the burners in the opposite arch (in double U-flame units) helps to assure stable ignition over a good load range. Experience has shown that the important variables for the design of such configurations are the proportioning of furnace volume between lower and upper parts, the furnace shape, and the amount and velocity of combustion air.

Figure 2.2 Dry bottom furnace and burner configurations: (a) horizontal, (b) opposed horizontal,
(c) tangential, (d) opposed inclined, (e) single U-flame, (f) double U-flame, and (g) vertical.

Vertical firing is not frequently used, but it has been applied to units below ~150MW. Above this size, an uneconomically large furnace cross section would be needed for the required burners to be placed in the roof. Although downward firing is inherently stable, it has several disadvantages, such as a tendency toward burner overheating damage from slag falls and the difficulty of purging combustibles from the top of the furnace [3, 21].

2.3.2.2 Wet-Bottom Furnaces

Early wet-bottom furnaces were simply open, single-stage furnaces. The high temperature necessary for ash melting and retention was produced by locating burners close together, near the furnace bottom, and using high coal fineness and highly preheated air.

For coal ash that is difficult to melt and when a load range of 4 : 1 (or greater) is essential, more sophisticated designs of the closed type have been developed, several of which are shown in Figure 2.3. All these later furnaces are two-stage combustion chambers. In the first stage, the temperature is sustained above the ash flow temperature, while in the second stage the gases and the entrained ash are cooled below the point of troublesome adherence to convention surfaces in boiler, super- heater, and reheater [23].

In favorable circumstances, the collected ash may be reinjected into the furnace to reduce particulate emissions and combustible loss. The operation of a reinjection system involves additional equipment, auxiliary power, and maintenance costs and frequently results in erosion of boiler tubes, fans, and collectors. Thus, many such installations have been abandoned as uneconomical.

Figure 2.3 Wet bottom, two-stage furnaces.

Wet-bottom firing is purely an expedient, aimed at easing the problem of ash disposal. It may also result in a slightly higher boiler efficiency with fuels containing less than 20% ash, because of the lower combustible loss incurred and the lower excess air that may be tolerated. With higher ash contents, the losses caused by fusion and sensible heat of the slag generally outweigh any gains and a net decrease in  efficiency results. Other disadvantages, compared with dry-bottom firing, are less flexibility of fuel selection, higher incidence of fouling and corrosion, higher levels of NOx formation, and lower average steam generator availability [3, 21].

2.3.3 Cyclone Furnaces

The cyclone furnace was developed in the mid-1940s by Babcock and Wilcox Company, as a high-temperature, high-turbulence combustion device that operates separately from the heat transfer sections of the boiler. Although the furnace was originally developed for low fusion temperature coals, it has been applied successfully to all coal ranks.

The cyclone furnace can burn relatively coarse coal ( 6 mm) and slurried fuel. In addition, it generates heat releases up to 20000 MJ hm—3 of combustion space, as compared to at best 5800 and 15 600 MJ hm—3 in dry- and wet-bottom boilers, respectively, and its size is reduced. Furthermore, owing to the centrifugal forces and to the presence of molten slag on the walls, the caustic carry-over of fly ash is considerably lower in the cyclone furnace than is in the other combustion systems. However, this type of firing favors excessive NOx formation [3, 20, 23].

A cyclone furnace is a water-cooled, refractory-lined horizontal cylinder, in which air enters tangentially and imparts a whirling motion. Coal and primary air are introduced at the burner end of the cylinder. The furnace temperature, in the 1650 ℃ range, is sufficient to fuse most coal ash on the refractory walls.  The coal particles are entrained in the high velocity stream and thrown against the furnace wall by centrifugal force, where they are held in the slag layer. Molten slag drains to the bottom of the furnace and is discharged, while gaseous products flow from  the discharge and directly into the radiant heat transfer section of the boiler (Figure 2.4).

In cyclone firing, the fuel characteristics are of greatest importance for the design of the furnace. The ash should be of low to moderate fusion temperature and the viscosity of the slag must be sufficiently low (250 P at 1425 ℃), so as to permit slag flow at normal furnace operating temperatures. Coals high in sulfur, or having a high ratio of iron to calcium plus magnesium, are unsuitable for the cyclone furnace. In addition, the moisture content per unit heating value should be limited to that producing a calculated adiabatic cyclone temperature above 1870 ℃. Fuels, that cannot produce such a temperature can be assisted by supplementary firing [3, 21].

The use of cyclone furnaces in future applications does not appear likely, due to the excessive amounts of NOx they generate.

Figure 2.4 Operating principle of cyclone furnaces.

2.4 Advanced Clean Coal Technologies

2.4.1 Fluidized-Bed Combustion

Fluidized-bed technologies are among the most important recent development in coal combustion. Nowadays, they compete with the stoker boilers in small sizes and with the pulverized-coal fired boilers in large sizes.

The fluidized-bed consists of a bed of solid particles suspended through the turbulent motion of combustion air distributed from below. The solid particles are mostly inert particles, such as sand, coal ash, or sulfur sorbents, such as limestone and dolomite. Coal particles make up only around 1% of the bed mass. At low velocities, the air passes through the spaces between the solid particles and the bed remains fixed. At high velocities, the air flows through the bed in bubbles and the system behaves similarly to an agitated fluid, hence the name "fluidized." At velocities approaching or greater than the free fall velocity of the particles, the particles are entrained out of the furnace, collected in cyclones, and circulated back to the bed (Figure 2.5).

The principal advantages of fluidized-bed combustion over the conventional pulverized coal approach are: (i) high heat transfer rates in the bed, resulting in compact units and thus lower capital and maintenance costs, (ii) increased combustion efficiency and heat release rates, up to 3 MW m—2 of bed area, (iii) less fouling and corrosion of furnaces, because combustion temperatures are well below the fusion temperatures of the ashes, (iv) combustion at substantially lower (below 1000 ℃) and more evenly distributed temperatures, resulting in reduced NOx emissions, (v) substantial reduction of SOx emissions, due to the use of sulfur sorbents in the bed, (vi) easy to handle and usefully employed by-product material, and (vii) fuel flexibility and ability to use low-grade coals, including those with high ash, as they operate with a low inventory of combustibles in the bed [22, 29].

Figure 2.5 Coal and gas velocities versus bed expansion for fixed bed, bubbling and circulating fluidized bed and transport reactors.

However, there are also some disadvantages: (i) commercially proven at smaller scales, compared with pulverized-coal combustion, (ii) relatively large amounts of solid residues generated, some of which require special measures for disposal, (iii) higher carbon-in-ash levels than those from pulverized-coal combustion, and (iv) increased N2O formation, due to the lower combustion temperatures [30].

Depending on system pressure, fluidized-bed coal technology consists of two broad categories of processes: the atmospheric fluidized-bed combustion (AFBC) and the pressurized fluidized-bed combustion (PFBC).

2.4.1.1 AFBC Process

2.4.1.1.1 Process and Key Issues The AFBC process is typically applied to large industrial boilers (90 t h—1 of steam or greater) and utility boilers for the production of steam for process needs, heating needs, and/or electricity generation. The combustor utilizes a bubbling bed or circulating bed configuration.

In the bubbling fluidized bed (BFBC), the crushed coal (particle size 1–40 mm) and limestone are fed to the bed, which is preheated to 430–540 ℃, depending on the particular coal properties (Figure 2.5). The stoichiometric feed rate for limestone is 3.1% of the coal feed rate for every 1% of sulfur in the coal [5]. An upward air flow is introduced into the bed via a distributor plate. When the gas velocity exceeds the minimum fluidizing velocity, the excess gas passes through the bed as bubbles and the remainder of the gas leaks through the bed material. The bed is then considered to be bubbling. In practice, BFBCs are operated at gas velocities several times higher than the minimum fluidizing velocity.

When the coal particles burn, the bed attains its operating temperature, usually 800–900 ℃, which is maintained uniform due to the high heat transfer rates in the bed and the removal of heat with an in-bed heat exchanger. The low bed temperature reduces slagging, fouling, and NOx formation, while the limestone after calcination reacts with SO2 to form calcium sulfate. The residence time in the bed is about 1 min, which is usually sufficient for 80–90% burnout.

In the freeboard zone an additional 10–20% of coal burnout is achieved, where secondary air is often introduced. However, the small particles are entrained and must be removed in a cyclone. The unburned carbon and the unreacted limestone contents in the separated particles, are quite high and justify recycling in the bed. The fly ash is retained in either an electrostatic precipitator or a fabric bag filter. The flue gases, after exiting the combustor, pass into a convective section where heat is further recovered and they are cooled and cleaned [3, 22].

For a BFBC, the fluidizing velocity typically ranges from 1 to 3 m s—1. The actual value reflects a compromise between the capital cost, bed pressure drop, and efficiencies of combustion and sulfur retention. The mean bed particle diameter typically ranges from 0.5 to 1.5 mm and depends mainly on the choice of fluidizing velocity. Fine beds require less heat transfer surface than coarse beds. The bed depth is typically between 0.3 and 1 m when fluidized. A minimum bed depth should be met, to provide sufficient free space in the bed for lateral mixing to occur, thus avoiding temperature gradients and to accommodate the tube bundle. Shallow beds help to reduce the fluidizing air fan power consumption; however, they decrease the combustion and sulfur capture efficiencies. In BFBC, it is desirable to operate at the highest possible temperatures, while avoiding ash sintering and alkali volatilization, which can cause corrosion. The 800–900 ℃ bed temperature favors sulfur retention.

High excess air levels increase the mass flow rate of hot combustion gases emitted to the atmosphere and thus reduce the boiler efficiency. However, low excess air levels result in reduced combustion efficiencies. Depending on other design parameters, the optimum value can vary from 10 to 50% [5, 30, 31].

The circulating fluidized-bed combustion  (CFBC)  boilers  are  similar in  many respects to BFBC boilers. The differences stem from smaller coal and limestone particle sizes (mean values 100–300 mm) and higher gas velocities (4–6m s—1) [21]. Thus, the boilers are taller with a smaller cross section and usually they do not include in-bed heat exchanges, because of potential high velocity erosion. As convective heat transfer coefficients are increased, due to the use of smaller particles, less heat  transfer tubing is required in the fluid bed cooler than in the bed of a BFBC [30]. The feeding system requires an order of magnitude fewer feed points, because of enhanced solids mixing, while the cyclone is located before the convection pass  to protect the convection surfaces from erosion, due to high solids loading and velocity, and operates at high temperatures [22].

As schematically shown in Figure 2.5, the bed fills the entire furnace volume, although most of the mass is still in the lowest third of the bed. A large portion of the solids is carried out of the furnace, separated in the cyclone and returned to the furnace. The recycling solids act as a heat carrier to remove the heat generated in the combustor, which generally operates at a low excess air level. Combustion takes place both in the furnace and in the cyclone. In some designs, the recirculated solids are fed to an external heat exchanger, where part of the evaporation, superheat, or reheat duties may be carried out, prior to return of the solids to the combustor [32].

Among the advantages of the CFBC are the ability to burn low calorific value fuels containing a high proportion of incombustible matter and the high heat transfer rates, allowing for better load capabilities. In addition, due to staged combustion, NOx formation is reduced. Furthermore, due to the use of finer particles, turbulent gas–particle mixing, and a high recycle rate, the desulfurization occurs at faster  reaction rates, greater limestone utilization, and higher overall sulfur capture, so that
high sulfur retention efficiencies with low Ca/S (<1.5) can be expected [33].

Despite the above attractions, there are some areas of concern with CFBC technology. Firstly, the pressure drop is generally greater than with a BFBC, which results in increased fan power requirements. Secondly, the large recycle rates require high efficiencies of cyclone, and the high gas velocities combined with high particulate loadings may lead to system erosion [30, 31].

2.4.1.1.2 Current Status and Experience

Though fluidized bed combustion boilers first appeared in the 1920s, their use for power generation was developed in the 1960s and the 1970s, both in USA and in Europe, and there was further rapid growth between 1985 and 1995 [25].

Commercial development of BFBC for power generation began in the mid-1970s, when European companies installed the first BFBC boiler burning coal in Scotland. After that several plants were constructed in the USA and Japan. In 2000, the total installed capacity of BFBC power plants larger than 50 MWth worldwide reached about 8000 MWth. However, the capacity growth has slowed in recent years, partially because of increased competition from CFBC. Several companies have supplied or continue to supply BFBC boilers on a worldwide basis. The major suppliers appear to be Foster Wheeler, Kvaerner, Lurgi, and Mitsui Babcock. Two large-scale demonstrations on retrofit applications have been carried out: the 160 MWe TVAs Shawnee plant Unit 10 in the USA, which started up in 1988, and the 350 MWe EPDCs Takehara plant Unit 2 in Japan, which started up in 1995. For industrial applications, most installations fall in the size range 30–100 MWth, with a few in the range 150–280 MWth. The latter have been introduced in Japan, Finland, and Thailand, mostly using Kvaerner technology. However, a maximum size of 300 MWth has also been claimed [8, 30, 32, 34].

BFBC plants can have a typical availability exceeding 94% and an efficiency of around 30%. Experience has shown that they can achieve NOx emissions of 250–400 mg m—3, N2O emissions of 50–200 ppm, SOx emissions of 200 mg m—3, and particulate emissions of 20–25 mg m—3 [34–36].

Table 2.2 Steam conditions for large circulating fluidized-bed combustion (CFBC) plants [30].

The first commercial CFBC unit was started up in Finland in 1979. Following this successful installation, the number of installations has increased rapidly in the last few decades and CFBC has by far overtaken BFBC, in terms of installed capacity (Table 2.2). The total installed capacity worldwide is about 65 GWth. Asia (mainly China) represents about 52%, North America 26% and Europe 22% of the total installed capacity. The market leaders are Foster Wheeler, Alstrom Power, Kvaerner, and Lurgi-Lentjes-Babcock [8, 30, 32, 37].

To date, CFBC units in operation range in size from a few MWth to 300 MWe. The first-generation technology reached its peak size with two 300 MWe boilers at Jackson Energy Authority’s Northside plant in Florida, USA. The largest second-generation CFBC units are the 265 MWe units at the Turów plant in Poland. A 460 MWe boiler, which is under construction at Lagisza (Poland), will be the world’s largest CFBC unit. Multiple units have also been adopted. With a subcritical cycle, the plant efficiency is normally between 38 and 40% on a LHV basis, while the availability is in excess of 90%. CFBC has proved to be able to utilize all types of coal, even those with high ash and sulfur contents. The NOx emissions are only around 1/5 of those produced by uncontrolled pulverized-coal combustion (Table 2.3). For most plants, uncontrolled NOx emissions are less than 400 mg m—3, while if controlled they can be below 130 mg m—3 (300 MWe JEA plant designed by Foster Wheeler and funded by DOE, USA [29]). The level of SO2 emissions is generally below 400 mg m—3 without flue gas scrubbing and particulate emissions of 20–50 mg m—3 have been achieved by using bag filters or electrostatic precipitators [30, 32, 39–44].

2.4.1.1.3 Future Developments

A key area for future development of BFBC technology is further increasing fuel flexibility, to extend the range of biomass and waste being utilized. BFBCrequires much higher Ca/S ratios for sulfur retention compared with CFBC, thus increasing the sorbent cost. Any improvements in sorbent utilization efficiency are therefore desirable. As erosion and corrosion of the boiler tubes remain an important issue, work will continue to further improve materials of construction, for example, improved and/or new refractory and alloy coatings. With regard  to  the  technology  size,  there  is  little  expectation  of  further significant increases. With a size range of 3 to ~300 MWth, BFBC will continue to be used for industrial boilers and small power units.

Table 2.3 CFBC versus PC typical emissions [38].

For CFBC, improvements that could still be made include reducing carbon losses with solids discharge and improving fuel flexibility for co-firing with non-coal fuels. Thermal cracking of refractories remains an issue, in CFBC plant, especially cyclones. Recent designs employing thinner refractories are being used to combat this [8, 25, 32]. CFBC boilers without external cyclones and with a reduced refractory inventory are also being offered by some manufacturers [45]. Several market leaders have been actively developing ultra-large-scale CFBC boilers. Lurgi has recently launched the 500 MWe class of subcritical CFBC boilers on the market. Designs of bigger capacity (Figure 2.6) and near-zero CO2 CFBC are supercritical units and are discussed in Sections 2.4.2 and 2.4.3.

CFBC can be used as part of advanced cycles, based on both combustion and partial gasification of coal. This concept has led to the development of the air blown gasification cycle (ABGC) in the UK. In the ABGC, coal is gasified in an air-blown pressurized fluid bed gasifier to produce fuel gas for a gas turbine and the residual char is transferred to a CFBC combustor, where it is burned with additional coal to raise steam for a steam turbine. Preliminary studies have indicated that an efficiency of over 50% is possible [30, 32, 46].

Figure 2.6    Scale-up of Foster Wheeler’s circulating fluidized-bed combustion (CFBC) boiler [30].

2.4.1.2 PFBC Process

2.4.1.2.1 Process and Key Issues

Pressurized fluidized bed combustion is based on combustion of coal under pressure, in a deep (3–4 m) bubbling fluidized bed at 800–900 ℃ and 1–1.5 MPa (Figure 2.7) [32]. In addition to retaining all of the  advantages of AFBC operation, PFBC also offers: (i) a smaller combustion chamber for a given heat duty, because the reaction rate is increased with operating pressure – thus, PFBC is particularly suitable for retrofit applications; (ii) a combustion efficiency such that a properly designed unit should eliminate the need for solids recycle; (iii) increased fuel flexibility – practically all types of fuel, including high ash or high moisture coals, can be burned; (iv) improved sulfur retention with pressure, using dolomite rather than limestone; and (v) NOx emissions that are significantly lower than at atmospheric pressure [3, 8, 45].

Figure 2.7 Pressurized bubbling fluidized bed combustion system [47].

PFBC has a relatively high heat release per unit of bed area, due to the higher pressure. As a result, adequately high throughput can be obtained at lower fluidizing velocities of about 1 m s—1, compared with 2–3m s—1 for BFBC. The area of heat transfer surface must be increased in proportion to the pressure and the bed is consequently deeper than in combustion at atmospheric pressure, to submerge the extra tubes. Although deep beds need high fan power, at elevated pressures the additional pressure drop has less effect on the compression energy requirements. However, the operating temperature is limited by the ash fusion temperature of the coal and the vapor point of the alkali in the coal [31, 40, 48, 49].

Two basic approaches are being pursued to attain improved thermal efficiency. One uses a combined steam–gas turbine cycle. The heat extracted from the fluid- bed serves to generate steam for driving a steam turbine and the combustion gas is expanded  through  a  gas  turbine.  The  exhaust  gas  then  passes  through  a  heat exchanger to generate more steam. In this combined cycle, the gas turbine provides typically 20% of the total power generated, while the steam turbine contributes the balance (80%) [50]. The other approach uses an inert gas or air in  a closed cycle for bed heat extraction. To reduce stack gas temperature, however, steam still must be generated downstream of the combustion gas turbine, as well as in the interstage coolers of the closed cycle turbine. The use of combined gas and steam cycles provides the PFBC power generation system with a 3–4% efficiency advantage over AFBC systems (Figures 2.8 and 2.9) [3]. Through different process variants,  in  particular  flue  gas  re-heating,  it  is  possible  to  effectively  raise  the mean process temperature and thereby the efficiency of the plant above 45%. Intense work is in progress to ensure that the exhaust gases exiting the pressurized boiler are sufficiently clean, so as not to cause erosion or build up on the gas turbine blades.

Figure 2.8 Coal-fired combined-cycle power plant.

If PFBC is of a circulating type, then the heat release level is particularly high (up to 40 MW m—2) and capital and operating costs are reduced [30, 35].

2.4.1.2.2 Current Status and Experience

PFBC was developed in the late-1960s in the UK. Today, ABB Carbon is the leading supplier of PFBC technology. Other suppliers include Foster Wheeler in Finland, Lurgi-Lentjes-Babcock in Germany, Babcock and Wilcox in the USA, and Ishikawajimma Heavy Industries (IHI), Mitsubishi Heavy

Figure 2.9 Alternate cycle efficiency versus fluidized bed combustor temperature.

Figure 2.10 ABB P200 PFBC system [8].

Industries (MHI), and Hitachi in Japan. The installed capacity worldwide is about 1125 MWe. The first commercial boilers were installed at V€artan in Sweden (135 MWe, 1990). Further plants have been built in Spain (Escatrón 79.5 MWe, 1991), USA (Tidd 73 MWe, 1991), Japan (Wakamatsu 71 MWe, 1995; Tomatoh-Azuma 85 MWe, 1996; Karita 360 MWe, 1999; Osaki 250 MWe, 2000), and Germany (Cottbus 70 MWe, 1999). The Karita plant, the largest unit in the world, operates at supercritical steam conditions (Figure 2.10) [8, 25, 45].

PFBC has performed satisfactory with a wide range of fuels. However, there is a greater efficiency penalty associated with the use of high ash or high sulfur coals, due to the increased pressure. The uncontrolled NOx emissions are generally less than 200 ppm [51]. Depending on the Ca/S ratio, sulfur retention efficiencies of 90–98% have been achieved. SO2 emissions vary from 5 to 350 ppm, while particulate emissions are also low (3.5–76 mg m—3) (Table 2.4).

All the PFBC demonstration plants have suffered from various problems since start-up, such as the failure of materials of construction. Most of these problems have subsequently been resolved.

PFBC technology remains in the early stages of development. A series of tests with different coals and limestones has shown that the technology can achieve extremely low levels of emissions [30, 32, 52].

2.4.1.2.3 Future Developments

As a relatively new technology, PFBC has considerable scope for future technological improvements and developments. There have been various R&D activities addressing the following issues: (i) freeboard firing to maintain a constant flue gas temperature. In this way, the inlet temperature to the expander section of the gas turbine increases, thus improving the plant's efficiency.
(ii) Fly ash recirculation to improve both sorbent utilization and combustion efficiency. This in turn improves environmental performance, plant efficiency, and economics. (iii) Advanced cycle with an enhanced gas turbine inlet temperature. A concept has been developed to feed the vitiated air from the PFBC combustor, after removing particulates, to a topping combustor located at the inlet to the gas turbine, fuelled by natural gas. Alternatively, because natural gas represents a higher cost, coal can be gasified in a fluid bed to provide fuel gas as a topping fuel, resulting in a gas turbine inlet temperature of 1300 ℃. (iv) Further demonstration of hot gas filtration. The filter materials must have a sufficient resistance to high temperatures under either oxidizing or reducing conditions [27, 30, 32, 45, 53–57].

Table 2.4 Emissions achieved at PFBC demonstration plants [30].

For pressurized circulating fluidized bed combustion (PCFBC), gas turbine operation in a "high dust" environment requires further research. As with advanced PFBC, hot fuel gas and flue gas cleanup remains a critical development area.

2.4.2 Supercritical Coal Combustion

2.4.2.1 Process and Key Issues

The principal interest in using supercritical steam conditions is the potential increase in thermal efficiency. Higher steam conditions allow higher thermal efficiencies, through higher pressure ratio turbines and larger temperature differences between the hottest and coolest parts of the thermodynamic cycle. The choice of steam pressure determines whether the boiler is subcritical or supercritical. The latter  appertains to pressures above 22.1 MPa, when vapor and liquid are not distinguishable and the water exists as a supercritical fluid. Supercritical conditions require changes in furnace tube configurations and design, as well as  the  use  of  different alloys in key areas [57]. Boilers of once-through forced flow are necessary (Figure 2.11). In current plants, double reheat may be used to take full efficiency advantage of the high main steam conditions, although the associated capital cost increases may be justifiable only where low condenser pressures are usable at cold seawater sites.

Figure 2.11 Once-through supercritical boiler type.

Supercritical pulverized-coal combustion plants currently operate at up to 30 MPa and 600 ℃ with net efficiencies of around 43–45% (LHV), depending on coal type and plant location. Efficiencies reaching 50–55%, with steam temperature above 700 ℃ and pressure in the region of 30–40 MPa, are possible provided that new materials adequate for these conditions are developed. The higher thermal efficiency offered by supercritical plants reduces all specific emissions in comparison with
subcritical units, as less fuel needs to be burnt for each mist generated [32, 57, 58]. However, the higher surface temperature of the superheater and reheater tubes may cause an increased tendency for coal ash deposition [54, 59].

2.4.2.2 Current Status and Experience

Supercritical pulverized-coal combustion is a well-proven technology with several decades of experience and operation, including some with low value coals. Recent developments in alloy steels have facilitated the flexible operating conditions required for modern plants. Substantial improvements in pollution control technology mean that emissions can be controlled within acceptable limits. Unit sizes to 1000 MWe exist. Such units have been built in China, Denmark, Finland, Germany, Japan, The Netherlands, Republic of Korea, and Taiwan.

Capital costs of supercritical plants are 2–3% higher than subcritical plants, but these costs are offset by lower fuel costs and lower emissions. Developments are ongoing, including improvements in the materials of construction and in the design of the boilers and turbines. Spiral mound furnace tube designs, in the zone near the pulverized coal burners, have commonly been adopted to give a longer path for the fluid within the furnace wall tubes, to prevent tube damage arising from overheating. In recent years, rifled tube designs have been available (e.g., the 1000 MWe Misumi power station, Japan), that give improved heat transfer and allow vertical tubing to be used throughout the furnace and give greater operating flexibility. Current materials based on ferritic/martensitic alloys permit steam temperatures up to around 600 ℃ [60].

There are more than 520 supercritical units in operation worldwide, with about 60 in Western Europe. These show an efficiency advantage of up to 3% compared with subcritical units and have comparable outage rates. The double reheat thermodynamic cycles of the Skaerbaeck and Nordjylland units in Denmark achieve net efficiencies approaching 50% [25, 32, 60–62].

Recently, Foster Wheeler designed the 460 MWe Lagisza unit in Poland, which will be the world’s first CFBC boiler to incorporate supercritical steam parameters. It will operate at 27.5 MPa and 560 ℃ main steam, with 580 ℃ reheat steam. A net plant efficiency of greater than 43% is expected. Commercial operation started in 2009 [63]. In addition, the ABB Carbon P800 module Karita plant has advanced supercritical steam  conditions  of  241  bar,  570/595 ℃, and  a  net  thermal  efficiency ~44% (LHV) [30, 32].

2.4.2.3 Future Developments

Pressures to reduce environmental impacts will continue to drive advances in flue gas treatment technologies for conventional pollutants from supercritical pulverized- coal combustion, while recent heightened interest in developing near-zero emission technologies will accelerate such programs and means of achieving low CO2. In the UK, according to the UK Joint Energy Security of Supply Working Group, there are three utilities (E.ON, Scottish-Southern Energy, and RWE npower) considering replacing existing coal-fired plants that are due to close with supercritical technology, with the option of adding carbon capture capability later [58].

The properties of iron-based alloys will probably be inadequate to allow the efficiency of the supercritical steam cycle to be extended much above 50%. Beyond 2015, efficiencies approaching 60% are envisaged using nickel-based "superalloys," which were developed for use in gas turbines and fast breeder nuclear reactors. The European Union is supporting the development of a power plant (commissioned for 2013) that will rely on the use of superalloys for the most highly stressed components. The main steam pressure would be approximately 37.5 MPa with a steam temperature around 700 ℃ and the expected efficiency is over 55% (LHV). The use of nickel alloys has cost implications that have still to be resolved. In the USA, materials for steam temperatures up to 870 ℃ are also being considered [32, 45, 64].

2.4.3 In Situ Emissions Control Technologies

2.4.3.1 SOx Control Technologies

In-furnace desulfurization is a competitive technology for controlling the SOx pollutants derived from coal combustion, due to the low capital and operating costs, in contrast to flue gas desulfurization techniques. It is suitable when a moderate (30–70%) SOx removal efficiency is acceptable, especially for old boilers, small boilers, or retrofit applications. A sorbent injection system is easy to install, operate, and maintain, eliminating the problems of plugging, scaling, and corrosion found in slurry handling and no wastewater is generated. Hybrid systems may combine furnace and duct sorbent injection, or introduce a humidification step to reach removal efficiencies of up to 80–95%. However, these are considered here as post- combustion control technologies [21, 33].

Sorbents include calcium, sodium or magnesium-based compounds, calcium  organic salts, and metal oxides of zinc, iron, and titanium. However, calcium-based sorbents, such as limestone and calcium hydroxide, are particularly attractive, due to their low cost and the inertness of the calcium sulfate or calcium sulfide by-  product [65].

For pulverized coal furnaces, where temperatures are high, CaSO4 decomposes over 1200 ℃ and therefore it is promising to utilize the temperature and burning gas distribution to produce a-CaSO4 phase and CaS as sulfation products in furnaces. Also, the staged desulfurization process combined with an air-staged combustion pattern, in which sorbents are injected into the primary air field and the upper furnace to capture SO2 under reducing and oxidizing atmospheres, is promising for pulverized-coal combustion, as is the desulfurization process by flue gas recirculation under O2/CO2 conditions. It is valuable to study further these two advanced processes, which can give efficiencies of about 80% in furnaces [66].

The development of FBC provided the opportunity to effectively retain sulfur in the combustion process, because CaSO4 is stable at the FBC operating temperature of 800–900 ℃. Generally, the sulfur removal efficiency is increased by increasing the rate of sorbent injection. The theoretical addition retains about 80% of the sulfur, while double the theoretical rate retains about 95% of the sulfur. This process has the potential to generate large quantities of solid by-products, which can present a significant disposal problem, and hence it is desirable to ensure that the sorbent is used as efficiently as possible. In CFBC, where the gas velocities are higher, the number of feed points is smaller, which is an operational convenience. Also, smaller size limestone particles can be used in the feed, which improves the sulfur capture and reduces the Ca/S mole ratio necessary to reach a target value [3, 5, 45, 59]. Results from PFBC demonstration plants have confirmed that sorbents can perform significantly better under pressurized conditions than at atmospheric pressure. Table 2.4 gives the environmental performance of selected PFBC plants.

2.4.3.2 NOx Control Technologies

The need to reduce NOx emissions from coal-fired boilers has gained increased attention in recent years, as more is learnt about the environmental impact of toxic NOx in the form of acid rain, smog, visibility impairment, and climatic warming. NOx are formed in fuel-lean flames by the attack of an O atom on molecular nitrogen (thermal), in fuel-rich flames via capture of nitrogen by hydrocarbon radicals (prompt), and by the pyrolysis and oxidation of heterocyclic nitrogen compounds in coals (fuel). Factors that influence NOx emissions in coal-fired boilers are coal properties, boiler design, and operation. The relative inertness and insolubility of NOx makes flue gas treatment more difficult than for SOx removal.

Consequently, it is often easier to intervene right at the point of fuel combustion to avoid the formation of NOx and their precursors. The principles of the various in situ control methods include reducing peak flame temperatures, reducing the residence time at peak flame temperatures, chemically reducing NOx, oxidizing NOx with subsequent absorption, removing nitrogen, or a combination of these methods. NOx is reduced chemically by reducing the valence level of nitrogen to zero, after it has become higher. Oxidizing NOx intentionally raises the valence of the nitrogen ion to allow water to absorb to it. This is accomplished by using a catalyst, injecting hydrogen peroxide, creating ozone within the air flow, or injecting ozone into the air flow. Nitrogen is removed from combustion as a reactant by using either low nitrogen content fuels or oxygen instead of air. The simplest and least expensive techniques that can reduce NOx emissions by 50–80% are: (i) low excess air, (ii) flue gas recirculation, (iii) staged air combustion, (iv) staged fuel combustion, and (v) burner design [3].

Maximum combustion efficiency normally requires 20–30% more air than the stoichiometric amount, depending on the boiler type and the properties of the coal burned. If the excess air is reduced from 25 to 15%, NOx emissions will generally be reduced by approximately 20% [67]. However, as excess air levels decrease, carbon monoxide, hydrocarbon, and particulate concentrations will increase. The trade-offs in these emissions, nitrogen oxide reductions, and combustion efficiency must be monitored to achieve the best air-to-fuel ratio.

Recirculation of flue gas dilutes the inlet oxygen concentration and lowers the combustion zone temperature, thus primarily affecting thermal NOx [5, 68]. In  pulverized-coal boilers, reductions in NOx concentration of up to 30% have been obtained. Flue gas recirculation has been used commercially for many years. However, the high cost of equipment and the energy penalty attributed to recirculation fans make this modification generally unattractive.

In staged air combustion, the amount of air introduced into the burner is less than stoichiometric and the remainder of the air is added into the boiler through separate ports. The advantage is that the reduced amount of oxygen in the burner tends to react more with the fuel than with nitrogen in the air and the remainder of the oxygen reacts in an area where the temperature is lower. As a result, there is an overall  reduction in NOx formation. This technique is effective in reducing NOx emissions by 30–70% [36, 69], it is inexpensive, and does not affect boiler efficiency, but can also produce reducing conditions on the tube walls, with the resulting danger of slagging. This can be limited by introducing some air near the walls. In addition, unburned carbon levels in the ash may increase and a loss in steam temperature might occur. Nevertheless, the use of staged air combustion has been regarded as the most successful method for NOx control and overfire air systems have been included in the design of new coal-fired boilers, to meet current NOx emission standards.

Staged fuel combustion involves injecting fuel into more than one combustion zone in the boiler. The objective is to inject a sub-stoichiometric part of the fuel with the bulk of the combustion air in the primary combustion zone. This produces a very fuel-lean zone, which reduces the formation of thermal NO, by lowering the peak temperature. However, the potential for formation of fuel NO may be increased. In the secondary combustion zone, where re-burning fuel is added, the overall air-to- fuel ratio is maintained fuel-rich. Fuel fragments are produced, which react with NO to produce HCN. Subsequently, HCN favors reduction to N2 under the prevailing fuel-rich conditions. Final air addition is then employed, to burn out the unoxidized hydrocarbons at lower temperatures that do not favor thermal NO formation. The most effective re-burning fuels are volatile, low-nitrogen containing fuel oils and natural gas, although coal has been successfully applied in some pilot-scale tests. The use of natural gas offers the advantage of additionally reducing SO2, CO2, and particulate emissions. A 40–70% reduction in NOx emissions can be achieved by staged fuel combustion, which is a comparatively new technology. Concerns regarding this technique are similar to those for other combustion modification processes, such as changes in slagging and fouling characteristics, corrosion of tubes in reducing atmospheres, and higher fan power consumption [3].

Burner design is an alternative approach to reducing formation of both thermal and fuel NOx, by means of controlling mixing of the fuel and air. The major objective, in burner tune-up, is to alter the fuel and air mixing patterns to provide as much aerodynamically staged mixing as possible, without additional air injection down- flame. The low NOx configuration, which one hopes to achieve, is a long narrow flame, where the fuel and air mix gradually over the entire flame length. Such flames can be achieved by reducing the swirl of the secondary air and by changing the angle at which the fuel is injected into the secondary air stream (Figure 2.12) [5, 21]. Low NOx burners are designed to (i) maximize the rate of volatiles evolution and total volatile yield from the fuel, with the fuel nitrogen evolving in the reducing part of the flame; (ii) provide an O2-deficient zone where the fuel nitrogen is evolved to minimize its conversion into NOx, but sufficient O2 is available to maintain a stable flame; (iii) optimize the residence time and temperature in the reducing zone to minimize conversion of the fuel nitrogen to NOx; (iv) maximize the char residence time under fuel-rich conditions to reduce the potential for NOx formation from the N2 remaining in the char after devolatilization; and (v) add sufficient air to complete combustion. The major concern with low-NOx burners is the potential for reducing combustion efficiency and thereby increasing the unburned carbon level in the fly ash. An example of a low-NOx burner is the radially stratified flame core burner, which has been scaled up and commercialized by ABB under license from MIT [59, 71]. Over 370 units worldwide, with a total capacity more than 125 GW, were fitted with low-NOx burners prior to 1998. Foster Wheeler has been a leading supplier of low-NOx burners [72]. The number of units installing such burners is continuously increasing. DOE reports that they are currently found on more than 75% of US coal- fired power capacity [21, 73, 74].

Figure 2.12 Schematic diagram of radially stratified flame core (RSFC) burner [70].

2.4.3.3 Near-Zero CO2 Emissions Technologies

The awareness of the increase in greenhouse gas emissions has resulted in the development of new technologies with lower emissions, which can accommodate capture and sequestration of carbon dioxide. An approach suited to combustion- based processes would be oxy-coal combustion (Figure 2.13). The coal would be burnt in an oxygen/recycled flue gas mixture containing ~35% oxygen instead of air. The CO2-rich gases from the boiler would be cooled, condensate removed, the recycle stream returned and the balance of CO2 taken off for storage. The cost of the air separation system might be counterbalanced by the savings in capital cost for a new installation, due to the high heat transfer within the boiler, as compared to a conventional pulverized-coal combustion system. Boiler efficiency may also be improved, but it is not certain what the overall cycle net thermal efficiency would be compared with scrubbing systems and otherwise similar conditions, as oxygen production and CO2 compression and liquefaction would still consume considerable quantities of power. Use of an air heater is not necessary in flue gas recycle systems and changes to heat recovery balances within the boiler economizer would need to be calculated and flows adjusted accordingly to maintain boiler efficiency [30, 32, 45, 57, 59, 76, 77].

Figure 2.13 Oxy-coal combustion [75].

The system may be suitable for retrofits of pulverized-coal combustion units, but there would be more flexibility in cycle design in a new installation. Theoretical studies combined with laboratory- and pilot-scale studies have provided an under- standing of the relevant design parameters and operational issues and have indicated that oxy-fuel combustion is technically feasible with current technologies, reducing the risks associated with implementation of new technologies [68, 78–82]. Work is required to determine the effects of the unconventional atmosphere on corrosion of boiler heat transfer surfaces, slagging, and fouling, as well as component development and demonstration of the system at a commercial scale. In applying oxy-coal combustion to CFBC, materials issues and fluidization behavior would require  investigation and development. Lower cost, less energy-consuming oxygen production in thermally integrated high-temperature membrane separation equipment  would improve the efficiency and economics of oxy-coal combustion [32].

The chemical looping combustion concept utilizes a solid oxygen carrier (such as NiO/Ni) to provide oxygen for the combustion of coal [83–85]. The CO2-rich flue gases would be processed into a high purity CO2 end product for various uses or sequestration. The concept avoids the large efficiency penalty associated with cryogenic type air separation units (ASUs). Additionally, the high costs associated with both cryogenic-type ASU, or oxygen transport membrane type oxygen supply systems, are avoided. The trade-off is a more complex boiler process [30, 32, 86].

2.5 Biomass Characteristics Affecting Combustion Processes

2.5.1 Moisture Content

The moisture content of green biomass can be quite high and can adversely affect the combustion process. If the moisture content is excessive, the combustion process may not be self-sustaining and supplemental fuel must be used, which could defeat the objective of producing energy by biomass combustion for captive use or market. Similarly to coal combustion, high moisture can cause incomplete combustion, low overall thermal efficiencies, excessive emissions (CO2, CO, and so forth), and the formation of products, such as tars, that interfere with operation of the system [87].

Woody biomass fuels containing 10–20% wt moisture are generally preferred for conventional biomass combustion systems, allowing temperatures of 750–1000 ℃, without incurring the costs of further biomass drying.

2.5.2 Ash Content and Composition

The effects of biomass mineral matter on plant efficiency and pollutant emissions are the same as those previously discussed for coal combustion. However, the amount and composition of biomass ash are different [88].

Herbaceous fuels contain silicon and potassium as their principal ash-forming constituents. They are also commonly high in chlorine relative to other biomass fuels.

Chlorine is shown to be a major factor in deposit formation. Chlorine facilitates the mobility of many inorganic compounds, in particular potassium. These properties portend potentially severe ash deposition problems at high or moderate combustion temperatures, due to formation of low melting point alkali silicates or alkali  sulfates [89–95].

Many of agricultural by-products also contain high potassium concentrations. Some woods, in contrast, contain far less ash overall. In addition, the ash-forming constituents contain greater amounts of calcium and less silicon, which forms sulfate deposits more favorable to sustained furnace operation [96–98].

Furnace-boiler systems for solid biomass fuels are often designed to keep the temperature in the combustor below about 900 ℃, to reduce slagging and formation of molten agglomerates.

Leaching of inorganic constituents prior to combustion has been shown to be an efficient, fast, and low cost way to significantly reduce fireside fouling, by extracting large amounts of alkali metals and chlorine, variable amounts of sulfur, phosphorous and total ash, and other elements [91, 96, 99–101]. Furthermore, chemical additives – such as kaolin, dolomite, calcite, bauxite, emalthite, gibbsite, mullite, ammonium sulfate, clinochlore, ankerite, aluminium-iron silicates, and oxides of calcium, magnesium, aluminium, and iron – can be used for alkali sorption, or for obstructing reactions with troublesome elements, which lead to eutectic mixtures [102–108].

2.5.3 Particle Size

Another factor in biomass combustion is fuel particle size and particle size distribution. The furnace design often determines the optimum ranges of these parameters. But, in general, the smaller the fuel particles the more rapid and complete the combustion process. Attrition and fragmentation in fluidized beds are important, due to their impact on char burn-off and particle time–temperature history [109]. In commercial systems, the capital and operating costs of fuel particle size reduction and pre-drying are weighed against their beneficial effects on combustion and furnace design and costs [110].

2.6 Industrial Biomass Combustion Systems

The differences in furnaces suitable for biomass combustion reside mainly in the design of the combustion chambers, the operating temperatures, and the heat transfer mechanisms. Considerable advancements have been made in ancillary hardware design to control the combustion process, to pre-dry the fuel, to remove ash, to reduce emissions, and to recover sensible heat from the stack gases, the condensate, and boiler blowdown.

Industrial combustion systems of a nominal thermal capacity exceeding 100 kW can be distinguished in fixed-bed, fluidized-bed, and dust systems. The basic principles of  these  are  described  below.  Residential  and  small  commercial  systems  are reviewed in the Handbook of Biomass Combustion and Co-Firing [111].

2.6.1 Fixed Bed Systems

2.6.1.1 Grate Furnaces [111–114]

For grate furnaces various technologies are available, such as fixed, moving, traveling, rotating, and vibrating grates, as well as cigar burners. Careful selection and planning are considered necessary, as all the above-mentioned technologies have certain advantages and disadvantages, depending of fuel properties.

Grate furnaces are suitable for biomass fuels with high moisture and ash contents and varying particle sizes. A well planned, well-constructed and well-controlled grate guarantees a homogeneous distribution of the fuel, as well as an equal primary air supply over its various grate areas. Fuel transport over the grate has to be as quite smooth and homogeneous, so as to prevent, if possible, the creation of "holes" and the elutriation of fly ash and unburned particles. In addition, a non-homogeneous air supply may result in slagging, higher fly-ash amounts, and a possible increase of excess oxygen, which is needed for complete combustion. Continuously moving grates, a height control system of the bed of embers, and frequency-controlled  primary air fans for the various grate sections (a reducing atmosphere in the primary combustion chamber is necessary for low NOx operation) is the technology needed to achieve these goals. Furthermore, to avoid slagging and to extend the lifetime of the materials, grate systems can be water-cooled.

Stage combustion should also be obtained, as this is another important aspect of grate furnaces; this can be achieved by separating primary and secondary combustion chambers, so as to avoid back-mixing of the secondary air and to separate gasification and oxidation zones. The better the mixing of flue gas and air, the lower the excess oxygen, and the higher the efficiency. The mixing effect can also be ameliorated  by using relatively small channels, or combustion chambers with a vortex or cyclone flow.

The various systems for grate combustion plants based on the flow directions of fuel and the flue gas are shown in Figure 2.14: co-current flow systems (flame in the same direction as the fuel), cross-current flow systems (flue gas removal in the middle of the furnace), and counter-current flow systems (flame in the opposite direction of the fuel).

Figure 2.14 Various arrangements for gas flow in furnaces.

Counter-current combustion is most suitable for fuels with low heating values (such as wet bark, wood chips, or sawdust). Drying and water vapor transport from the fuel bed is increased by convection – in addition to the dominating radiant heat transfer to the fuel surface – because the hot flue gas passes over the fresh and wet biomass fuel entering the furnace. To avoid the formation of strains enriched with unburned gases entering the boiler, as well as avoiding increasing emissions, this system requires a good mixing of the gas and secondary air in the combustion chamber.

Co-current combustion is applied for dry fuels, like waste wood or straw, or in systems where pre-heated primary air is used. The residence time of unburned gases released from the fuel bed can be increased by this system and NOx reduction can be improved, due to enhanced contact of the flue gas with the charcoal bed on the backward grate sections. Higher fly-ash entrainment can occur and should be impeded by appropriate flow conditions.

Cross-current systems are a combination of co-current and counter-current units and are also especially applied in combustion plants with vertical secondary combustion chambers. Flue gas recirculation and water-cooled combustion chambers are used, to achieve adequate temperature control. Combinations of these techniques are also possible. The mixing of combustible gases and air can be improved by flue gas recirculation and can be regulated more accurately than water-cooled surfaces. However, it has the disadvantage of increasing the flue gas volume in the furnace and the boiler section [115]. Water-cooling has the advantage of reducing the flue gas volume, impeding ash sintering on the furnace walls, and usually extends the lifetime of insulation bricks.

Fixed grate systems are only used in small-scale applications. As fuel transport and distribution among the grate cannot be controlled well, this technology is no longer applied in modern combustion plants.

In inclined moving grates (Figure 2.15), the fuel is transported along the grate by alternating horizontal forward and backward movements. In this way, both unburned and burned fuel particles are mixed, the surfaces of the fuel bed are renewed, and a more even distribution of the fuel over the grate surface can be achieved. Usually, the whole grate is divided into several sections, which can move at  various  speeds, depending on the different stages of combustion. The grate bars are made of heat-resistant steel alloys. What is more, they are equipped with small channels at their side-walls, for primary air supply. Additionally, they should be as narrow as possible, so that the primary air across the fuel bed is distributed in the most effective way
.
If the moving frequencies are too high, high concentrations of unburned carbon in the ash, or insufficient coverage of the grate, will result. Infrared beams situated over the various grate sections allow for adequate control of the moving frequencies, by checking the height of the bed. Ash is removed under the grate in dry or wet form. What is common in this case is the fully automatic operation of the whole system.

Figure 2.15 Modern grate furnace with infrared control system and section separated primary air control. (1) Drying zone, (2) gasification zone, and (3) charcoal combustion zone [114].

In moving grate furnaces a wide variety of biofuels can be burned. Primary air for cooling the grate is used in air-cooled units. These furnaces are also suitable for wet bark, sawdust, and wood chips. Water-cooled moving grate systems are recommended for dry fuels, or biofuels with low ash-sintering temperatures.

In horizontally moving grates, the horizontal bed is achieved by placing the grate bars in a diagonal position. Advantages of this technology include: (i) the impediment of uncontrolled fuel movements over the grate because of gravity and (ii) the stoking effect by the grate movements is increased, thus leading to a very homogeneous distribution of material on the grate surface and impeding slag formation as a result of hot spots. An additional advantage is that the overall height can be reduced. These systems should be pre-loaded – so that there is no free space between the bars – to avoid ash and fuel particles falling through the grate bars.

Applications of this technology are a 10 MW Russian boiler at Jõ,geva Heat Company burning wood chips, a 10 MW Swedish boiler at Viisnurk Ltd. burning wood chips and wood waste, 100 MW boilers in Denmark burning straw, two 93.3 MW boilers in Holland at Afval Enrgie Bedrijt burning wastes and a 10 MW boiler in Austria at St. Andr€a for the co-firing of bark, wood, and forest residues [116–119]. Travelling grate furnaces are built of grate bars, forming an endless band that moves through the combustion chamber. Screw  conveyors  or  spreader  stokers  supply the fuel onto the grate. The fuel bed itself does not move but is transported through the combustion chamber by the grate. The grate is cleaned of ash and dirt at the end of the combustion chamber, while the band turns around. On the way back, the grate bars are cooled by primary air, to avoid overheating and to minimize wear-out. To achieve complete charcoal burnout the speed of the traveling grate is continuously adjustable.

Uniform combustion conditions for wood chips and pellets and low dust emissions are the advantages of these systems, due to the stable and almost unmoving bed of embers. What is more, the maintenance or replacement of grate bars is easy. However, the fact that the bed of embers is not stoked results in a longer burn-out time, as compared to moving grate furnaces. For complete combustion a higher primary air input is needed (which leads to a lower NOx reduction potential by  primary measures). Moreover, non-homogeneous biomass fuels imply the danger of bridging and uneven distribution among the grate surface, because no mixing occurs. This disadvantage can be avoided by spreader stokers.

The combination of wet-chemical fuel analysis, in situ flue gas measurements, and simulation tools can make it possible to define the optimum temperature profile and air staging conditions for test results concerning NOx reduction [120].

Underfeed rotating grate combustion is a new Finnish biomass combustion technology. This technology uses conical grate sections, which rotate in opposite directions. These sections are supplied with primary air from below (Figure 2.16). As a result, wet and burning fuels are well mixed. In this way, the system becomes adequate for burning very wet fuels, such as bark, sawdust, and wood chips, with moisture content up to 65%. The combustible gases are then burned out with secondary air, which takes place in a separate horizontal or vertical combustion chamber. The horizontal version is suitable for generating hot water or steam in boilers, with a nominal capacity between 1 and 10 MW. The vertical version is applied for hot water boilers, with a capacity of 1–4 MW. The fuel is fed to the grate from below with screw conveyors, which makes it necessary to keep the average particle size below 50 mm [111, 121].

Figure 2.16 Underfeed rotating grate: (A) fuel feed, (B) primary combustion chamber, (C) secondary combustion chamber, (D) boiler, (E) flue gas cleaner, (F) ash removal, and (G) stack [121].

Underfeed rotating grate combustion plants can also burn mixtures of solid wood fuels and biological sludge. The system is computer-controlled and allows fully automatic operation.

Vibrating grate furnaces consist of a declined finned tube wall placed on springs.

Spreaders, screw conveyors, or hydraulic feeders feed the fuel into the combustion chamber. Two or more vibrators transport fuel and ash towards the ash removal. Primary air is fed through the fuel bed from below, through holes located in the ribs of the finned tube walls. Owing to the vibrating movement of the grate, at short periodic intervals, the formation of larger slag particles is inhibited. For this reason, this  technique is especially applicable to fuels having sintering and slagging tendencies (e.g., straw, waste wood). The high fly ash emissions caused by the vibrations, the higher CO emissions due to the periodic disturbances of the fuel bed, and the incomplete burnout of the bottom ash are the disadvantages of vibrating grate furnaces [111].

Ansaldo Vølund A/S has recently commissioned a wood chips vibrating grate boiler, for heat and power generation. The boiler operates with high steam data, 525 ℃ and 70–92 bar pressure. At SH Energi A/S, in Aabenraa, Denmark, a biomass fired boiler plant started commercial operation in 1988. The plant consists of a Benson-type boiler, with a screw stoker/vibration grate combustion system generating 120 t h—1 of steam, which is finally superheated to 542 ℃ in a separate wood chip fired superheater. The plant is coupled to the 660 MW power plant EV3 and it generates  41  MW,  at  a  wet  electrical  efficiency  of  39%  [122,  123]. EHN-Energia Hidroel´ectrica de Navarra has recently installed the first straw-fired plant of 25 MWe in Sangu€esa, Spain, consuming 160 000 tons of straw per year [124].

In Denmark, cigar burners have been developed for straw and cereal bale combustion (Figure 2.17); the fuel is delivered in a continuous  process,  by  a  hydraulic  piston, through a feeding tunnel on a water-cooled moving grate. Upon entering the combustion chamber, the fuel begins to  gasify  and  combustion  of  the  charcoal  follows, while the unburned material is moved over the grate. Grate and furnace temperature control are very important for straw and  cereal  combustion, due  to their  low ash sintering and melting  points  and  the  high  adiabatic  temperature  of combustion, caused by their low moisture  content.  Therefore,  the  combustion  chambers  have  to  be  cooled  by  water-cooled  walls,  or  by  flue  gas  recirculation,  or both. Furnace temperatures should not exceed 900 ℃ for normal operation. Furthermore, in straw and cereal combustion, very fine and light fly ash particles, as well as aerosols, are formed from condensed alkali vapors. An automatic heat exchanger cleaning system is required to prevent ash deposit formation and corrosion. Systems for shredded or cut straw also exist and operate in a similar way to the technology described – only the fuel preparation and feeding are different [111, 122, 126].

2.6.1.2 Underfeed Stokers

Underfeed stokers (Figure 2.18) represent an economical and operationally safe technology, which is suitable for small- and medium-scale systems, up to a nominal boiler capacity of 6 MW. Screw conveyors from below feed the fuel into the combustion chamber and they transport it upwards, on an inner and outer grate.

Figure 2.17 Cigar burner for straw and cereal combustion [114, 125].

In modern combustion plants outer grates are more common. This is because they allow for more flexible operation and their automatic ash-removing system can be attained easier. Primary air is supplied through the grate, while secondary air is usually supplied at the entrance to the secondary combustion chamber. A new

Figure 2.18 Underfeed stoker for wood chips and sawdust: (1) ash hopper, (2) grate, (3) refractory and radiation wall, (4) air fans, (5) insulation, (6) fire tube boiler, (7) multicyclone, and (8) flue gas fan [114].

Austrian development is an underfeed stoker with a rotational post-combustion. In this new development, a strong vortex flow is achieved, by a specially designed  secondary air fan equipped with a rotating chain.

Underfeed stokers are suitable for biomass fuels with low ash content (such as wood chips, sawdust, pellets) and small particle sizes ( 50 mm). Ash-rich biomass fuels like bark, straw, and cereals need more efficient ash removal systems. Moreover, problems in underfeed stokers can be caused by sintered or melted ash particles, which cover the upper surface of the fuel bed. This happens when the fuel and the air are breaking through the ash-covered surface, thus resulting in unstable combustion conditions. On the other hand, their good partial-load behavior and their simple load control are the advantages of underfeed stokers. Additionally, because the fuel supply can be controlled more easily, load changes can be achieved more easily and quickly than in grate combustion plants [111].

Advanced combustion control techniques of low cost maximize the efficiency with respect to the emissions of unburnt pollutants. Measurements on a 1 MW under- stoker furnace showed that the efficiency was above 90%, for the whole range of the heat output, and at part load it was improved by up to 5%. CO emissions were below 50 mg Nm—3, which represents a reduction by a factor of five compared to flame temperature control [127].

2.6.2 Fluidized Bed Systems

Fluid-bed (FB) combustion systems have been applied since 1960 for combustion of municipal and industrial wastes. Since then, over 300 commercial installations have been built worldwide. Regarding technological applications, bubbling fluidized beds (BFBs) and circulating fluidized beds (CFBs) have to be distinguished. Process  principles have been discussed above. Regarding gaseous and solid emissions, BFB and CFB furnaces normally show lower CO and NOx emissions, due to more homogeneous and therefore more controllable combustion conditions. Fixed bed furnaces, in turn, usually emit fewer dust particles and show a better burnout of the fly ash [88].

2.6.2.1 Bubbling Fluidized Bed

For plants with a nominal boiler capacity of over 20 MW, BFB furnaces start to be of interest, since the low excess air quantities necessary increase combustion efficiency and reduce the flue gas volume flow. In contrast to coal-fired BFB furnaces, the biomass fuel should not be fed onto but into the bed, by inclined chutes from fuel hoppers, because of the higher reactivity of biomass in comparison to coal.

The advantage of BFB furnaces is their flexibility concerning particle size and moisture content of the biomass fuels. Furthermore, it is also possible to use mixtures of different kinds of biomass, or to co-fire them with other fuels. One big disadvantage of BFB furnaces, the difficulties they have at partial load operation, is solved in modern furnaces by splitting, or staging, the bed [111, 114].

Industrial-scale fluidized bed reactors are used for the combustion of several types of biomass in many countries. For example, in Finland over 30 BFB systems are installed and the largest boiler is 500 MW. The optimal mixing ratios for commonly used forest chip qualities, as well as mixtures of chips and other fuels, the combustion and co-firing properties, emissions, and boiler fouling, are being studied [113, 128]. A hot-water BFB plant, developed by Motala Energi AB, has been built in Gothenburg, Sweden, giving a thermal output of 27 MW with flue-gas heat recovery. Austrian Energy's “ECOFLUID” bubbling fluidized bed has been applied in the Westfield plant in FIFE/Scotland, Langerbrugge plant for Stora Euso in Belgium, Stendal plant for ZSG in Germany, and Timelkam plant for Energie AG in Austria, with steam generating capacities from 9 to 290 t h—1 and a fuel range from wood, bark, harvesting residues, sewage sludge, and organic waste resulting from agricultural industry. The applied staged combustion concept resulted in a homogeneous temperature profile in the furnace and first pass of the boiler and thus low NOx emission. By using refractory lined superheaters, corrosion problems could be minimized, although high steam parameters could be obtained [129]. In Spain, comparative studies have been carried out for different biomass types (forestry, herbaceous, cork sawdust, and so forth) in an atmospheric BFB pilot plant of 1 MW by the CIEMAT Group [130]. Combustion parameters were optimized, to obtain a clean process for each type of fuel used. Polyaromatic hydrocarbon emissions were found to be higher in herbaceous than in wood biomass, when particulate emissions were increased and combustion efficiency decreased. No slagging or ash sintering problems were found during the combustion tests, mainly due to the low alkali content in the ash of the considered biomasses. The type of fuel feeding affected the temperature distribution inside the combustor and therefore the erosion caused to the internal parts of the equipment. Furthermore, the feasibility of the fluidized bed combustion of energy crop biomasses was demonstrated in this plant, since over 99% efficiency was obtained in the different experiments [131].

2.6.2.2 Circulating Fluidized Bed

In view of their high specific heat transfer capacity, CFB furnaces start to be of interest for plants of more than 30 MW, due to their higher combustion efficiencies and the lower flue gas flow produced (boiler and flue gas cleaning units can be designed smaller).

An example of this technology is the Alholmens kraft plant, in Pietarsaari of  Finland, with an electrical output of 240 MW. The plant produces steam for the adjacent paper mill and for a utility generating electricity and heat. AUPM-Kymmene Pulp and Paper Mill nearby supplies the power plant with wood and bark residues. Since the plant is of giant scale, special attention has been paid to the logistics of fuel procurement. Table 2.5 gives technical, fuel, and boiler data for this plant.

Another example is the 110 MW CFB boiler at Lenzing AG in Austria. The CFB uses the waste air stream for the combustion of various waste materials, including wood wastes, RDF, waste packaging material, screenings from municipal waste, and sewage sludge. The waste air stream is pre-heated before entering the CFB combustor as primary and secondary air, while also being used to pneumatically transport the solid feed into the combustor (Figure 2.19). Partial capture of the sulfur is achieved by adding limestone to the CFB. The boiler generates 129 t h—1 of steam at 80 bar and 500 ℃. The steam is used in the Lenzing works to generate electric power and provide process heating. Through combining the two problems of contaminated air and solid wastes, the company has gained important benefits through the generation of supplementary steam and reducing the demand for conventional fuels within their existing plant [133].

Table 2.5 Technical, fuel and boiler data of Alholmens Kraft plant [132].

Figure 2.19 Circulating fluidized bed combustor, Lenzing AG, Austria [133].

CFB combustion is used in the USA to combust automobile tires, 200 million per year of which are either disposed of in some form or recycled for retreating or reuse. Emissions of metal oxides, volatile organic compounds, and sulfur oxides from the tires have precluded the use of high ratios of tire fuel in conventional combustors. A CFB system, however, can combust tires with nearly 100% conversion of the carbon, good emission characteristics, and the capability of separating the wire. Carbon  monoxide levels of 25 ppm in the flue gases have been readily maintained with excess air. Sulfur oxide capture with limestone in the fluidized bed and ash recycle can be as high as 80%. The sand is dewired and screened to remove any oversized particles before return to the combustor [134].

2.6.3 Dust Combustion Systems

In dust combustion systems, fine fuels, like sawdust, are pneumatically injected into the furnace. An auxiliary burner is used for starting-up; when the combustion temperature reaches a certain value, this burner is shut down and biomass injection begins. Fuel feeding must be controlled very carefully due to the explosion-like gasification of the fine and small biomass particles. The feeding system consists of a key technological unit within the overall system. The particle size and the moisture content of the fuel should not exceed 10–20 mm and 20% wt, respectively. Fuel/air mixtures are usually injected tangentially into the cylindrical furnace muffle, to establish a rotational flow (usually a vortex flow). The rotational motion can be supported by the flue gas recirculation in the combustion chamber. Because of the small particle sizes used, gasification and char-coal combustion occur simultaneously, so that rapid load changes and efficient load control can be achieved. Owing to the high flue gas velocities, the ash is carried with the flue gas and is partly precipitated in the post-combustion chamber. Air staging and low excess air amounts could lead to reduced NOx emissions. The muffle should be water-cooled, because of the high energy density at the furnace walls and the high combustion temperature.

Muffle dust furnaces are being used more and more for fine wood wastes, originating from the chipboard industry.

Besides muffle furnaces, cyclone burners for wood dust combustion are also in use (Figure 2.20). Depending on the design of the cyclone and the location of fuel injection, the residence time of the fuel particles in the furnace can be controlled well [135]. A disadvantage of muffle furnaces and cyclone burners is that insulation bricks wear out quickly, due to thermal stress and erosion. Therefore, other dust combustion systems are being built without rotational flow, where dust injection takes place, as in a fuel oil-or natural gas-fired furnace [111].

Other advanced combustion systems for solid biomass fuels also offer consider- able advantages over conventional designs and are in commercial use or under development. Some of them are [134, 136]: two-stage systems combining fluidized- bed technology and cyclonic combustion for disposal of waste biomass with heat recovery; combustion of thickened municipal biosolids dewatered to about 38% solids in a six-hearth incinerator at 700–900 ℃; the Whole Tree Energy concept developed in the USA and patented in 30 countries; and direct-fired gas turbines that are suitable for small- and medium-sized industrial and commercial applications, up to 5 MW in capacity.

Figure 2.20 Schematic diagram of a two-stage cyclone burner.

2.7 Outlook

The outlook for the major clean coal technologies depends on several factors,including projected future electricity requirements and the attitudes and policies of government, industry, and the general public worldwide. In Europe, it is estimated that by 2020 the combination of increased electricity demand and the need for power plant replacement will amount to a requirement for 300 GWe of new power capacity. Russia, a major coal-consuming country, is projected to increase its consumption from about 250 Mt to almost 400 Mt by 2030. In the USA, where there is substantial government and private investment into RD&D for clean coal technologies, 170 GW of new coal-fired capacity will be required prior to 2030. In China, coal-based power generation is expected to increase from an estimated 250 to 800 GW, and in India to 161 GW, by 2030. China is the world's largest market for supercritical pulverized-coal combustion. In South Africa, 18 GWofcoal-firedplantsareprojectedby 2015. Australia, whichproduces 80% of its electricityfrom coal, isdevelopingthe near-zero emissiontechnologieswithinits Coal21 National Action Plan [25, 58]. Generally, CFBC seems to be the preferred technology worldwide and several large units are under construction.

In various markets, the average scale of biomass combustion schemes rapidly increases, due to improved availability of biomass resources and the economic  advantages of economies of scale of conversion technology. It is also in this field that competitive performance, compared to fossil fuels, is possible, where lower cost residues are available. All over Europe, most notably in Scandinavia, biomass markets are developing from purely regional to international markets, with growing international trade of biomass and biomass-derived energy carriers. Major markets for heat production are in Finland, Sweden, Denmark, Austria, Germany, and France, while for electricity production they are in Finland, Denmark, Spain, Germany, and The Netherlands. Finland is at the cutting edge of the field with development and deployment of BFBC and CFBC boilers with high fuel flexibility, lower specific investment costs, and high efficiency. The largest boiler is 500 MW. Apart from Europe and the USA, the main growth market is South East Asia, especially with respect to efficient power generation from biomass wastes and residues.

2.8 Summary

Coal, being an economic, reliable, and readily available source of energy, will remain the fuel of choice for power generation worldwide. Coal is projected to play a major role in the global energy system, with more than a 20% share in primary energy and up to 40% in electricity production in 2030. However, due to coal’s pollution and limitations on CO2 emissions, clean coal technologies with high thermodynamic efficiency must be applied in the new generation of coal-fired power stations.

Stokers, the oldest devices used for combustion of coal in fuel beds, have lost a great part of their traditional market to advanced clean coal technologies, due to their low efficiency and ash clinkering problems.

Pulverized-coal combustion systems are the best-proven technologies and have evolved over several decades, accounting for well over 90% of world power plants. The average efficiency of larger subcritical plants is in the range 35–36%. Energy  consumption is high and so are the emissions, if uncontrolled. Supercritical units take advantage of higher steam temperatures and pressures to achieve higher efficiencies and thus lower specific emissions than subcritical units. Efficiencies of recent plants approach 50%. Several data show no increase in specific capital cost, and unit sizes up to 1000 MWe exist. There are more than 520 supercritical plants in operation worldwide. Long-term programs in progress, to achieve efficiencies over 50%, involve materials developments, including the use of superalloys.

Fluidized bed technologies have good fuel flexibility and lower emissions than conventional combustion systems. In recent decades they have undergone considerable development towards improved performance and lower costs. Nowadays, they compete with small stoker boilers and with large pulverized-coal fired boilers. BFBC is and will be mainly used for small units up to 300 MW, having efficiencies around 30% and availabilities over 90%. A key area for future development is extending the range of biomass and waste fired, improving the control of heavy metals, and materials of construction. CFBC subcritical units in operation range in size from a few MW to 300 MWe. Plant efficiencies are 38–40% and availabilities 90–98%. A 460 MWe boiler with an efficiency of >43%, at Lagisza plant in Poland, will be the world's largest CFBC unit with a supercritical cycle. Larger supercritical boilers are under development and research on advanced alloys for heat exchangers is continuing. One potential development area might be the use of CFBC as part of advanced cycles, based on both combustion and partial gasification of fuel. Coal remains the dominant fuel, but biomass and waste are likely to be increasingly used. PFBC is a relatively new technology. The largest plant is the 360 MWe Karita supercritical unit, in Japan. Plant efficiencies of up to 44% and very low emission levels have been achieved. When used in the circulating mode, it has potential for providing better performance than other forms of FBC. The use of a topping combustor, to increase the gas turbine inlet temperature, and flue gas cleanup remain critical development areas.

In-furnace desulfurization, mainly using calcium-based sorbents, is a competitive technology for controlling the SOx pollutants derived from combustion, due to low overall costs. Staged processes and flue gas recirculation offer improved efficiencies. In situ techniques that can reduce NOx emissions achieve efficiencies between 50 and 80%. Staged air combustion and low-NOx burners are considered to be the most successful methods for NOx control.

Technologies for near-zero CO2 emissions are also under investigation, including oxy-fuel combustion and chemical looping combustion. Flexibility will be greater in new installations.

Combustion of biomass, which is a naturally occurring carbon resource with great energy potential and is considered CO2 neutral, is of extreme importance, if we are to conserve our sources of energy while achieving our environmental goals efficiently. More than 95% of all biomass energy utilized today is obtained by direct combustion. Improved processes are available for conversion of virgin biomass and complex waste biomass feedstocks into heat, steam, and electric power in advanced combustion systems. Basic concepts include fixed bed, fluidized bed, and dust firing.

Fixed bed furnaces are appropriate for biomass fuels with high moisture content, varying particle sizes, and high ash content. Typical plant capacities range between 20 and 50 MWe with related electrical efficiencies in the 25–30% range; however, larger plants up to 100 MWalready exist. Moving grate boilers are the preferred technology. In recent years, the application of fluid-bed combustion allows for efficient production of heat and electricity from biomass. On a scale of about 50–100 MWe, electrical efficiencies of 30–40% are possible.

Although major technological developments have already been achieved, biomass is generally not yet commercially competitive, except for some niche applications. Policy support in the fields of research, development, and demonstration and the creation of conductive market mechanisms and legislation are essential for a more widespread introduction of biomass energy systems.

Source: Despina Vamvuka

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The 10 largest coal producers and exporters in Indonesia:

  1. Bumi Resouces
  2. Adaro Energy
  3. Indo Tambangraya Megah
  4. Bukit Asam
  5. Baramulti Sukses Sarana
  6. Harum Energy
  7. Mitrabara Adiperdana 
  8. Samindo Resources
  9. United Tractors
  10. Berau Coal


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