WORLD BANK TECHNICAL PAPER NO. 387 m1\ÅT p 3 Work in progress for pubic dscussion Nov. A Planner's Guide for Selecting Clean-Coal Ichnolo(ics for Power Plants \I//ÄY// - '-/ //// inl- / ) disposal - exclusion of 'foreign' - gte dust matenial by good design and maintenance of - acid run-off STORAGE stodcyard and transport ifeased use of water HOMOGENSATION systems (eg covered o analysis slurry AND/OR -- ~storage, concrete waste TRANSPORT hardstands,good apoundmens T O housekeeping) ...PREPARATION sprto n eoa - sizing of inpurities prior to use W main path - cleaning f sprto n eoa I Power production Source: Singer (1991). COAL QUALITY Coal in India Coal has been produced in India for over 200 years. Output has been accelerating since independence, particularly since the formation of the nationalized coal company in the early 1970s. Annual production is over 225 Mt from coal fields that are located mainly in the east of the country in the states of Assam, Bihar, Uttar Pradesh, Madhya Pradesh, Andhra Pradesh, Orissa and West Bengal. India's total coal reserve base is estimated to be near 160 Gt (gigaton). Coal ranks range from lignites to bituminous coals with most being in the bituminous category. There are no anthracite or peat reserves. India has little good quality coal. Some 60% of the reserves have an in situ ash content of 25-45%. As most of this ash is embedded dirt, coal cleaning is often difficult. As a result calorific values of the coal are low; for saleable coal averaging is under 20 GJ (gigajoule) per ton, or about two thirds that of a good quality internationally traded coal. Sulfur contents are comparatively low by international standards, typically under 1%, but are not so good when expressed per unit of energy. Inherent moisture contents are unexceptional: typically 8-15%. The coal, which is hard, generally has a low swelling index and low volatile content. Much of the coal has a crushing strength of 200-300 kg/cm . Compared to other countries only a small part of Indian coal is screened or washed for impurities. Chapter 2. Coal Quality and Coal Cleaning Technologies 8 An unenforced Indian government policy states that coal should be washed whenever the distance between the mine and the end-user is greater than 1,000 kilometers. An attainable and reasonable goal for the washing of Indian raw coal is to reduce the ash content from as high as 50% to at least 30%-40% ash or even down to 25%. Table 2.1 presents examples of typical coals from several areas in India. Table 2.1: Analyses of typica Indian coals from several re lions Jharia Jharia Uttar Pradesh Renusagar Singrauli Neyveli Rank Medium High volatile High volatile volatile Sub- Sub- Lignite bituminous bituminous bituminous bituminous bituminous As received Ash, % 38.9 31.6 28.0 28.6 31.5 4.5 Moisture, % 1.1 6.9 10.0 14.9 7.9 53.1 Moisture & ash free Volatile, % 25.3 37.2 41.0 45.1 47.4 57.1 Carbon, % 83.6 74.1 71.9 70.3 Hydrogen, % 4.5 4.8 5.0 5.2 Oxygen, % 9.9 18.6 20.3 23.1 Nitrogen, % 1.3 1.4 2.0 0.5 Sulphur, % 0.7 1.8 0.8 1.1 0.8 0.9 Lower heating 33.0 30.4 30.7 28.4 27.3 26.4 value, MJ/kg Hardgrove 63 60 50 56 50 95+ grindability, H Source: Singer (1981). Coal in China China is the world's largest hard coal producer with an annual production over 1,100 Mt. Chinese coal resources are vast. Official Chinese figures suggest a total geological resource of over 770,000 Mt. The coals range from hard anthracite to lignite with ash contents between 10 and 40%. The bituminous coals are of medium and high volatile rank; the medium volatile being rather high in ash. The sulfur content is low in many coals, less than 1%, but there are also areas with over 2% sulfur. Compared to other countries, a small proportion of Chinese coal is screened or washed for impurities. Table 2.2 presents examples of some typical Chinese coals. A Planner's Guide for Selecting Clean-Coal Technologies for Power Plants 9 Table 2.2: Analysis of Chinese coals High volatile Medium volatile Low volatile Rank Sub-bituminous bituminous bituminous bituminous As received Ash, % 32.8 37.0 29.7 27.7 Moisture, % 22.6 3.3 10.3 9.6 Moisture and ash free Volatile, % 46.8 39.3 22.7 17.0 Carbon, % 74.7 79.6 80.8 83.9 Hydrogen, % 4.8 5.4 6.0 4.5 Oxygen, % 18.6 12.4 10.7 5.1 Nitrogen, % 1.3 1.7 1.4 1.4 Sulphur, % 0.6 0.9 1.1 5.1 Lower heating value, 24.2 29.2 30.8 31.6 MJ/kg Hardgrove grindability, oH 52 45 50 48 Source: Singer (1981). COSTS Cost of coal cleaning Coal cleaning plants are commonly located close to the mine and the cost of cleaning is included in the coal price. The costs for coal cleaning vary from case to case, as does the impact on coal quality. Therefore there are hardly any published costs specific to different cleaning methods, however some are shown in Table 2.3. Table 2.3 Examples of published costs for coal cleaning Cleaning method Cleaning costs US$/ton Conventional cleaning * coarse fraction 2-3 * fine fraction 3-10 * jig, dense-medium or froth (for the US) 4-8 Advanced physical separation 15-30 Source: Couch (1995a) and Sachdev (1992). Coal quality impact on power generation cost The degree of coal cleaning (e.g. ash content) has an impact on power plant economics. The investment cost and the O&M costs are affected by the coal quality. In India and China, there would be an economic advantage in many existing plants for firing washed coal. This has been proven by calculations made for specific Indian power stations using two American state-of-the-art computer models (Ref 9). Using data from four representative Indian units in three power stations and typical coal data, a substantial economic incentive for firing washed coals in these power plants was identified. A break-even cost analysis established the following: Chapter 2. Coal Quality and Coal Cleaning Technologies 10 * premium of about $0.55/ton could be paid for each percentage point reduction in the ash content of the typical high ash bituminous coals fired in older, existing power plants (Ref. 9). * Cleaning high ash coals for use in newer plants that were designed for high ash coals was projected to be somewhat less attractive. A premium of about $0.40/ton for each percentage point reduction in a coal's ash content could be paid (Ref. 9). Projected savings derive mainly, from reduced maintenance costswithin the power plant, increased plant availability, and reduced fuel transportation costs. Figure 2.3 shows the results of the ash sensitivity analysis for the four different power plants in India on the break-even free on board mine fuel cost. When the coal is purchased at a price following the slopes in Figure 2.3, the electricity production cost is constant. If the coal can be obtained at a lower cost than its break- even cost, then the power plant's electricity production cost can be reduced. Figure 2.3: Ash sensitivity analysis for four different power plants (A-D) 32- C304 S0 --..A, od .r --g-B, nemw o 28 4-C, old -.-44. D, od u. 26 24 -- 0 m241 low 20 1 18 20 22 24 26 28 30 32 34 36 38 40 As-Received Ash Content % Note: The figure shows the coal price that can be paid as a function of ash content in the coal in order to reach the same cost for electricity production. The figure is based on model calculations made for four Indian power plants. Source: Sachev (1992). Production cost savings when reducing the ash content are illustrated by the break-even fuel costs in Figure 2.3. Savings are split into different parts; fuel-related costs (e.g. more fuel needed), transportation costs, operation costs, maintenance costs, derate (e.g. high ash content may result in restricted mill throughput and higher energy consumption in mills) and increase in overall plant availability. Table 2.4 presents the savings due to reduced ash content split into these areas for the different plants presented in Figure 2.3. A Planner's Guide for Selecting Clean-Coal Technologies for Power Plants 11 Table 2.4: Savings due to reduced ash content split into different power plants A, old B, newer C, old D, old Fuel (free on board) 2 6 2 4 Transportation 49 27 19 68 Operation 0 0 11 0 Maintenance 39 27 14 23 Derate 0 22 34 0 Availability 10 18 20 5 Total 100 100 100 100 Note: Based on Figure 2.3. Source: Sachdev (1992). As shown in Table 2.4, the ash content of the coal has an effect on: * fuel costs, * fuel transportation costs, * operational costs (e.g. ash handling, operation of pulverisers), * maintenance costs, * generation capacity, and * availability and forced outage rate. When deciding which coal quality to purchase, all the savings should be added and calculated per ton coal. The savings should be compared to the costs for cleaned or cleaner coal. This was done in Figure 2.3 and Table 2.4. An example from an Indian mine with an annual capacity run-of-mine of 6.5 million tons shows the following: the specific investment cost for coal cleaning was $24/ton, the ash content in washed coal was 34% and the moisture content was 8% (Ref 8). The effect of using washed coal (with a reduction in ash content from about 40 to 34 %), compared to run-of-mine coal, was evaluated. The plant load factor was anticipated to increase in the order of 5-10% when the ash content was reduced from 40 to 34%. Data relating to the improvement in plant performance, distance from the mine and the cost of generation was analyzed. Figure 2.4 shows the decrease in operation costs with the increase in the plant load factor (PLF), due to the use of washed coal, for a given transportation distance from the mine. This is another proof of the importance coal quality has on operating costs. Chapter 2. Coal Quality and Coal Cleaning Technologies 12 Figure 2.4: Operational cost decrease with PLF increase Operation cost USC/kWh 4,2- 4 3,-8 800 km -43- 1000 km -.--1200 km 3,-*- 1800 km 3.24 3,2 61 63 65 67 69 71 73 Plant load factor, % Note: Decrease in the generation cost with the improvement in the PLF due to the use of washed coal. Operational cost data are calculated for different distances between power plant and mine, $1=Rs35. Source: Quingru et al (1991). Significant investment cost savings can also be realized for new plants if they are designed for firing washed coal. The equipment affected by the ash content includes: * coal receiving, preparation, handling and storage equipment; * steam generation; * combustion air and flue gas systems; * particulate removal system; * flue gas desulfurization system; * bottom ash system; and * waste disposal system including transportation system and disposal area requirements. When designing a plant for lower ash content or for washed coal, the reliability of the coal washing plant has to be close to 100%. For as long as coal cleaning technology is not widespread in India and China, and in cases where 100% coal cleaning cannot be guaranteed, it is recommended that power plant is designed in anticipation of there being no positive influence frorh coal cleaning. It is also important to strive for a correlation between the contracted coal price and the quality of the coal. A Planner's Guide for Selecting Clean-Coal Technologies for Power Plants 13 COAL CLEANING METHODS Conventional preparation/cleaning involves the separation of coal-rich from mineral-matter rich particles in different size ranges. A simple plant will only separate the coarse sizes, while more complex operations undertake separations of coarse, intermediate and fine. Different levels of cleaning involve progressively separating finer size ranges. The physical methods are based on the differences in either density or surface properties between the organic matter and the minerals it contains. A few separation methods which are under development depend on differences between the magnetic or electrostatic properties of the materials. Chemical and biological methods have been tested on a small scale, but are not seen as having economic potential over the next 5-10 years in connection with power generation and they are not covered by this guide. Physical coal cleaning may consist of the following stages: * size reducing (crushing, <50 mm), * sizing (coarse, 10-150 mm; intermediate, 0.5-10 mm; fine < 0.5 mm), * cleaning, * dewatering, and * drying. Most methods are water-based, either by gravity or by surface property. The water-based processes may increase the moisture content in the treated coal, the rate depending on the dewatering and drying processes used. All cleaning processes produce a reject consisting of the inert material but also a certain content of carbon. The cleaning methods will cause some losses in carbon and may increase the water content of the coal. The environmental problems connected with coal cleaning are briefly described in Appendix 1. Proven, simple technologies for coal cleaning are recommended to be used. The following methods for coal cleaning are considered as commercial and are further discussed in this technical guide. The methods themselves are described in Appendix 1: Gravity based: * Jigs, * Dense-medium separators, * Hydrocyclone, * Flowing film, and * Concentration table. Surface property based: * Froth flotation. Dry methods: * Cleaning coarse coal with a fluidized air dense-medium. Chapter 2. Coal Quality and Coal Cleaning Technologies 14 Cleaning processes produce effluents such as wastewater and solid residues. Figure 2.5 gives an example of how quantities and concentrations of effluents vary for different methods. igure 2.5: Effluent from coal cleaning Particulates Water evaporalion 200 kit Coal 146 kt Surfac coal cleaning. cleaned coal mining73% yield 400 kt D-orige water coal Solid waste Licuid ov burden Claing -50 kt Waste 3 6t storage Transport 0.1% loss Undergrou.id water 200 kt coai. mining -1 Solid waste Drainage water 346 Xt coal storage Source: Couch (1995a). Different coal cleaning methods (described in the Appendix) are compared regarding the state of technology, performance, advantages and disadvantages, costs and suitability in Tables 2.4 and 2.5. Table 2.4: Corn rison of different coal cleaning method Methods Jigs Dense-medium separators Hydrocyclones State of technology * Commercial * Commercial * Commercial Advantages * Large capacity * Good separation * Inexpensive * Second most common * Most common type world method wide Disadvantages * Lower separation than * Small capacities * Water consumption dense-medium Costs * Inexpensive * Expensive Suitability * Intermediate efficiency * For difficult or most * For coarse to device. For moderately difficult to clean coal. intermediate difficult to clean coal * Specific gravity >1.3-1.9 particles. * Specific gravity >1.5-1.6 * Size: 0.5-150 mm * Size: 0.5-150 mm * Size: 0.5-150 mm A Planner's Guide for Selecting Clean-Coal Technologies for Power Plants 15 Table 2.5: Comparison of different coal cleaning methods Methods Concentration tables Froth flotation Dry cleaning State of technology * Commercial * Commercial * Close to commercial Advantages * Inexpensive * Good results on fines * No water required * Good pyrite separation Disadvantages * Quite small capacities * Complex * Not for difficult to clean of 10-15 tons/hr; * Poor pyrite separation coal * Poor dewatering characteristics Costs * Inexpensive * Expensive * Lower than wet processes Suitability * Used for fine coal * Used for fines. Mainly * Requires easy coal.; containing a great deal used for metallurgical size >10 mm of pyrite. coals * Rough separation * Specific gravity >1.5 * Size: <0.5 mm * For coal tending to * Size: 0.0-15 mm form slimes in wet I I_ processes ALTERNATIVE LOCATIONS FOR CLEANING Coal cleaning can either be located near the mine, at the stockyard or at the power plant. The predominant choice is cleaning near the mine. Disposal costs at the mine site will almost certainly be much lower than those near a power plant, possibly by a factor as large as 10:1. Transport costs are proportionately reduced and the process results in a more consistent product. Coal cleaning at. the power plant is not a traditional location. Most commonly the utilities have preferred to let the coal producers prepare/clean the coal. On-site cleaning would not be possible at some existing sites due to lack of space. A major disadvantage is that the coal cleaning plant would need to be used most of the time. In addition to capital investment, an infrastructure and a team of skilled management and operators are required. REFERENCES 1. Singer, J. G. 1981. Combustion -- Fossil Power Systems. Combustion Engineering, Inc., Windsor, Connecticut. 2. Couch, G. 1991. Advanced Coal Cleaning Technology. IEA Coal Research. IEACR/44. International Energy Association. London, UK. 3. Couch, G. 1995a. Power from Coal - Where to Remove Impurities. LEA Coal Research. IEACR/82. International Energy Association. London, UK. Chapter 2. Coal Quality and Coal Cleaning Technologies 16 4. Couch, G. 1995b. Private communication. IEA Coal Research. International Energy Agency. London, UK. 5. Derickson, K. Technological, Economic And Environmental Considerations of Coal Development and Utilisation, An Overview Prepared for the Agency for International Development. U. S. Department of Energy. Washington D.C. 6. Lall, S. K. 1992. "Coal Washing - Indian Scenario." Cleaner Coal for Power, vol.32, no.1. URJA. Bombay, India. 7. Langer, Kenneth. 1994. "Fact Finding Report: to Assess the Opportunity for an Indo-US Coal Preparation Program for the Power Sector in India." US-AEP. Washington, DC. 8. Quingru, C., Y. Yi, Y. Zhimin, and W. Tingjie. 1991. "Dry Cleaning Of Coarse Coal With an Air Dense Medium Fluidized at 10 Tons Per Hour." In Proceedings of the Eighth International Pittsburgh Coal Conference, pp 266-271. October 14-18 1991. Pittsburgh, Pennsylvania. 9 Sachdev, R. K. 1992. "Benefication of Power Grade Coals: Its Relevance to Future Coal Use in India." Cleaner Coal for Power, vol.32, no.1. URJA. Bombay, India. 10. Smouse, S. M., W. C. Peters, R. W. Reed and K. P. Krishnan. 1994. "Economic Analysis of Coal Cleaning in India Using State-of-the-Art Computer Models." In: Solihill. 1994. Proceedings of the Engineering Foundation Conference on the Impact of Coal-fired Plants, pp 189-217. United Kingdom, June 20-25,1993. Washington, DC:Taylor & Francis. 11. Zhenshen, W. 1985. "The Correlation between Raw Coal Washability, The Selection of Coal Separation Processes and Coal Preparation Flowsheet." Proceedings of the International Symposium on Mining Technology and Science. September 18, 1985. Xuzhou, China. A Planner's Guide for Selecting Clean-Coal Technologies for Power Plants 3. COMBUSTION TECHNOLOGIES The rapid growth of electric power consumption in India and China calls for planning and building of cost-efficient power plants. Available combustion technologies include conventional PC-fired units, with subcritical steam data and, hence, moderate efficiencies and supercritical PC units with higher efficiencies. Pulverized coal-fired technology is the most widely used coal combustion technology for boiler sizes up to 1000 MWe. Atmospheric circulating fluidized bed combustion (ACFB) is a relatively mature technology which will likely contribute to new coal-fired units. There are also several new coal combustion technologies i.e. pressurized fluidized bed combustion (PFBC) and integrated gasification combined cycle (IGCC). In order to be cost-effective, new plants should have high efficiencies, high availability, low emissions, and produce a by-product that can be utilized, avoiding the need for disposal. As discussed in Chapter 2, the use of washed coal is a first cost-efficient step towards increased plant efficiency and availability, reduced investment and O&M costs. The use of washed coal with low ash content also reduces the amount of solid waste disposal at the plant. This is further discussed in Chapter 7. A major concern in both India and China is the inefficient use of coal in the power industry due to low plant efficiencies (33 to 36%). Older power plants might have efficiencies as low as 25%. Higher plant efficiencies will reduce the emissions of SO, NO. and particulates and the waste production per MWhe. In addition to these advantages, coal consumption is reduced per MWhe produced. This is illustrated in Figure 3.1 where the hard coal consumption per kWh of electricity produced is shown as a function of unit efficiency. For example, the figure shows that when the efficiency of a hard coal-fired power plant is increased from 34-42%, coal consumption is decreased from 0.42-0.34 kg/kWh of electricity produced, or around 20%, if the hard coal has a lower heating value (LHV) of 25 MJ/kg. Not only the coal consumption is decreased, but emissions and waste are also reduced by 20%. Another consequence of reduced consuption is the lessened amount of coal being transported on the already overloaded railways. Internationally the current trend in base load PC-fired power plants is to build large, supercritical plants with efficiencies around 42%, which could be the high efficiency technology alternative for India and China. This calls for transfer of technology know-how to manufacturers and utilities in India and China. As mentioned above, supercritical boilers with increased steam parameters are very competitive on the international market for large PC plants. Most large PC boilers built in Western Europe are supercritical. Although the investment cost is higher for a supercritical boiler, the gains in reduced power generation costs and decreased emissions are obvious. Until recently, steam temperatures have been limited to 5400C since high temperature steels, normally used in boilers and turbines, do not allow for higher temperatures. Today, there are materials available at acceptable costs which permit higher steam temperatures. In the future, efficiencies of around 50% will be possible with ultra supercritical steam parameters. 17 18 Figure 3.1 Hard coal consumption per kWh of electricity produced for three different coals with LHV 20, 25 and 30 MJ/kg 800 700 - - 600 - - 500 20 MJ/kg 400- - 25 MJ/kg 300 - - - 30 MJ/kg 200 . " * 100- 20% 30% 40% 50% 60% Net efficiency based on LHV Pulverized coal-fired units cannot meet moderate emission standards without pollution control equipment. Since reducing emissions from a PC unit is not without cost, other technologies have been developed. The ACFB technology has a low-cost advantage of a wide fuel flexibility and low emissions of both NO. and SO2. Sulfur is captured directly in the boiler bed and NO,, formation is low due to the low combustion temperature. The drawbacks of today's ACFB technology is that its waste of mixed ash and desulfirization products is difficult to utilize. An ACFB plant also emits significant amounts of N20 which has a potential for global warming. The efficiency is relatively low due to the use of subcritical steam parameters. Currently subcritical ACFB boilers are commercial in sizes up to approximately 100 MW.. Developmental work is underway on larger size units, with possibilities for waste utilization and even increasing steam parameters. Market prices are difficult to predict, but a cost comparison between a PC plant equipped with wet FGD and an ACFB plant usually shows a lower investment cost for the ACFB plant. Offering high efficiencies and low emissions, PFBC and IGCC are technologies under development with few or no commercial plants in the world. Further demonstration is needed before they reach commercial status. Improving efficiency in existing power plants must be considered as an important, achievable first step to increased, cost-effective power generation. Since plants in India and China currently operate mainly at low efficiencies, there is substantial potential for improvement. Some of these efficiency improving measures are discussed in Chapter 8 on Low Cost Refurbishment. A Planner's Guide for Selecting Clean-Coal Technologies for Power Plants 19 PULVERIZED COAL COMBUSTION Pulverized coal technology is the oldest and most commonly used technology for thermal power generation worldwide. It can be used for boiler sizes up to and above 1,000 MWe. Pulverized coal technology requires flue gas cleaning in order to be environmentally friendly, since the emissions of SO2 and NOx become unacceptably high. Fly ash and bottom ash from PC firing can be used in the building industry. Pulverized coal boilers can be divided into two groups based on steam data: subcritical PC boilers, where the live steam pressure and temperature are below the critical values 221.2 bar absolute pressure and 374.15'C; and supercritical PC boilers with steam data above the critical values. The current trend is to increase the steam data in order to increase plant efficiency. Figure 3.2: A typical PC boiler system FURNANCE HP REHEAT EXIT STEAM STEAM COAL SIO r BUIRNERS FUPONANCE19.A JLVEIZE9AIR PEHEATER FLY ASH FD FAN Suitability Both sub- and supercritical PC boilers can be used for all boiler sizes up to 1,000 MW,. They can be designed for any coal from lignite to anthracite, but a given boiler must be designed for one type of coal (lignite, bituminous or anthracite). This means that once designed for a specific coal, PC units are somewhat more sensitive to changes in fuel quality than fluidized bed combustion technology. Uncontrolled emissions from PC firing are high compared to other technologies, which means that emission reduction equipment is necessary and can be rather expensive. Chapter 3. Combustion Technologies 20 Subcritical PC boilers The moderate steam data used in subcritical PC boilers results in rather low plant efficiencies. The advantage of subcritical boilers is that they are fairly simple to operate and maintain, relative to other combustion technologies. The availability of subcritical PC-boiler plants is very high as a result of the simple design and long time experience. Supercritical PC boilers Supercritical technology is newer than subcritical. In the industrialized world, there are now many supercritical PC plants in operation, and most plants that are under construction will also be supercritical. There are no supercritical boilers in operation in India and just a few in China, so there is limited practical experience in supercritical PC firing in both countries. Currently, no supercritical boilers are manufactured in either India or China. The efficiencies of supercritical PC plants are higher than those of subcritical ones and of ACFB plants. When plants with high efficiency are wanted, supercritical boilers should be selected. The higher efficiency has major advantages such as reduced coal consumption and reduced emissions of NO., S02, particulates and waste per MWhoC produced. In boilers operating at high steam temperatures (above 540*C), corrosion becomes more of an issue. When high steam temperatures are used, coals with a high corrosion potential are less suited and should be avoided. Due to the more complex design of supercritical boilers, the requirements on O&M routines are higher than those for a subcritical boiler. Also the demands on water quality and instrumentation and controls (I&C) equipment are high. State of technology Subcritical boilers Subcritical PC boilers have been used for more than 50 years. Unit sizes vary from less than 100 to above 1,000 MW. The technology is well proven and hur.dreds of units are in operation in India and China. Supercritical boilers The technology is well-proven in the industrialized world with more than 200 units in operation. There are no supercritical boilers in operation in India today (Ref 1). In China there are only a small number of supercritical plants; they include Shanghai (2x600 MW,); Liaoning (2x500 MW.), and Hebei (2x500 MW.), all built in the 1990s (Ref. 2). Future development The major future technical development will be to increase efficiencies and improve the environmental performance of PC boilers. Improvement in efficiency is achieved by increasing steam conditions and potentially by the introduction of double reheat. To date, the use of ferritic materials has limited steam temperatures to 5400C. Higher steam temperatures used to require austenitic materials. Development of new ferritic material now allows steam conditions up to 248 bar and 5930C. Plants with steam data of 300 bar and 580-6000C are currently planned. A Planner's Guide for Selecting Clean-Coal Technologies for Power Plants 21 Plant size Unit sizes over 1,000 MWe are possible. Normal sizes for new units are 250-600 MWe. Currently, all units being installed in India are either of 210-250 MW, or 500 MW, capacity. In China, large boilers of 300 MW, and 600 MW, are projected. Fuel flexibility Pulverized coal-firing technology can handle a wide range of coals, from anthracite to lignite. However, combustion stability problems might occur if high ash and moisture coals are fired. Anthracite firing requires special boiler design due to the very low volatile compound content. For a particular plant, the boiler and auxiliary equipment must be optimized for its design-specific coal. The flexibility for each PC boiler to handle a range of coal qualities is limited. Table 3.1 below shows the limits for some coal parameters for a normal PC boiler. Table 3.1: Limits for coal parameters for PC boiler designed for normal bituminous coal Coal parameter Limit (approximate values) Lower Heating Value >20 MJ/kg Ash content <10% Initial Deformation Temperature (IDT) >1,100 0C Moisture <10% Chlorides <0.3% Volatile Matters (VM) >25 % Sodium+Potassium (Na+K) <2.5% A PC boiler can be designed for wider variations in coal parameters than indicated in Table 3.1, but this generally results in increased capital cost and lower efficiency during off-design operation. Operational flexibility, such as turn down, can also be compromised if the plant is designed for too wide a range of coal qualities. Performance Efficiency Table 3.2 summarizes steam parameters and efficiency data for typical PC plants. Table 3.2 Efficiency data for PC boilers Subcritical Supercritical Supercritical high Ultra supercritical boilers boilers temperature boilers boilers- future potential Steam pressure (bar) 140 240 300 350 Steam temperature ('C) 540/540 540/540 590 650 Unit net efficiency (%) 36-38 40-42 45 close to 50 Note: Unit net efficiency based on LHV of coal, includes wet FGD with condenser pressure. The increase in plant net efficiency achieved by increasing steam parameters is shown in Figure 3.3 (Ref 6). Conventional subcritical PC plants are shown to the left, followed by supercritical plants with efficiencies above 42%, and slightly higher steam parameters than shown in Table 3.2. Increasing steam data and the introduction of double reheat can increase efficiency still further. The future potential for an ultra supercritical boiler is shown to the right. Chapter 3. Combustion Technologies 22 Figure 3.3: Plant net efficiency increase achieved by increasing steam parameters Net efficiency 50- 49Steam data 48- ~ ~+3,2%7Ot2* 4/ 46- 45- - _+____I+10% Improved turlne 4 +1.2% Double reheat 43 +1 % incrOAsed steam data 270 bar 42- 5&5/M*C 41uis critical 41- 6 a +4,5% 545545-C 38I Sub critical 37 40 br o 36 delsor pressure 0.05 bar Conventional coal fired Supercritical high temperature power plants Ultra super critical power Plants pnr plantk Note: This diagram shows normal net efficiencies in conventional power plants (left), the efficiencies in supercritical high temperature plants (middle) and future efficiencies of ultra supercritical power plants (right). Source: VGB Kraftwerkstecknik (1996). Load range The minimum load is in the range of 25-40% of maximum continuous rating. However, oil or gas might be required as a support fuel in this low load range. The practical limit for commercial part load operation is usually at a load determined by the need to introduce oil or gas firing to maintain PC combustion stability. This boundary is determined by the fuel composition and boiler island design, but normally occurs between 40 and 60% of maximum continuous rating. Load change rate Changes of load (ramping) can be extremely rapid at up to 8% per minute. However, a normal load change rate required by the grid for coal-fired plants is circa 4% per minute within the whole load range. Start- up time Cold start: 4-8 hours depending on type of circulation; once through is the fastest; natural circulation requires the longest time. Restart of a hot unit: 1-1.5 hours. A Planner's Guide for Selecting Clean-Coal Technologies for Power Plants 23 Environmental performance Sulfur: Corresponds to the sulfur content of the coal. Particulates: 10-25 mg/Nm3 using ESP or bag filter. NOx: New bituminous coal-fired boilers can be designed for NOx emissions from 150-250 mg/MJk,l if the boiler is equipped with low NOx burners; anthracite-fired boilers may produce emissions around 500 mg/MJf.i. Fig 3.4 below shows the uncontrolled NOx emission from coal combustion depending on firing technique and boiler size. Note that burners with new source performance standards (NSPS) for wall-fired boilers, using staged combustion which produces lower NOx emissions than pre- NSPS burners, have been developed. Figure 3.4: Effect of boiler firing types and unit size on uncontrolled NOx emission from coal-fired plants NOx emiss ons, mg/MJ 1000 wall-fired wet bottom cyclone pre-NSPS 750.- wall-fired dry Ootto roof-fired 500- tro-fired tangentially fired 250- 0 100 200 300 400 500 600 700 800 Unit capacity, MWe Source: Takeshita (1995). Waste production PC-firing produces fly ash (80-95% of the total ash flow) and bottom ash (5-20%). The ash is producable without further treatment and can be used in the building or cement industry. Chapter 3. Combustion Technologies 24 However, it is important that the content of unburnt carbon in the ash is low (normally less than 5%). Ash utilization is further developed in Chapter 7. Availability Availability figures are high both for subcritical and supercritical plants. The availability is in the range of 86-92%, including planned outages of 4 weeks per year. Construction issues Construction time The normal construction time is 36 months from contract award to commercial operation. Because of the large boiler sizes, most of the plant has to be erected on site. Possibilities for domestic manufacturing! licensing agreements for subcritical boilers Both India and China have very experienced manufacturers of subcritical PC boilers. There are also some licensing agreements between large boiler manufacturers in industrialized countries and domestic manufacturers in China and India (Ref. I and 2). Possibilities for domestic manufacturing/ licensing agreements for supercritical boilers. Chinese boiler manufacturers do not currently have the capability to design and manufacture supercritical boilers. Cooperation activities between international and Chinese manufacturers are underway and local manufacturing will be possible in the near future (Ref 2). Supercritical boilers cannot be manufactured currently in India, but international companies are investing in local manufacturing (Ref. 1). Already, part of a PC plant with a supercritical boiler can be manufactured locally if the design is carried out by an international manufacturer. Maintenance Normally, a yearly overhaul period of four to five weeks is required. Equipment that needs more frequent maintenance due to excessive wear and tear, such as coal pulverizers, must be made redundant. Units with drum boilers can be maintained by ordinary maintenance personnel. Some parts in supercritical once through boilers require maintenance by specially trained staff. Complexity of technology The design of a power plant with PC boilers has a low degree of complexity. A unit consists of boiler, turbine, fuel and ash handling equipment and flue gas cleaning equipment. A subcritical PC unit with a drum boiler is fairly simple to operate because the drum serves as a water magazine and compensates for deviations between the firing rate and the feedwater supply. This makes load changes fairly easy to control. In a once-through supercritical boiler, the firing rate must always be in balance with the feedwater supply. Evaporation surfaces and superheaters might otherwise become dry with no water or steam in them. This kind of drying damages the surfaces. That makes the operation of once- through boilers more complex than that of drum boilers. A Planner's Guide for Selecting Clean-Coal Technologies for Power Plants 25 Costs Investment costs The investment cost ranges from 1,000-1,600 USD/kWe for subcritical boiler plants for unit sizes between 75 and 600 MW,. In Figure 3.5, the cost is given for a complete one-unit plant that includes everything from fuel storage to waste handling. No emission reduction equipment is included with the exception of low NOx burners. The investment cost for a boiler only amounts to approximately 30% of the investment cost for a complete plant. Supercritical boiler plants are only slightly more expensive (around 5%) than subcritical, if steam temperatures are kept at ordinary levels. The cost is highly dependent on the state of the market, the size of the plant, number of units, the extent to which manufacturing can be carried out in low wage rate areas etc. Figure 3.5: Investment costs for PC-boiler plants 1600- * 1500- 4 1400- 2 1300- c 1200- 0 E 1100- 1000- 900- Z 800- JL 700- 600 0 100 200 300 400 500 600 Unit net electric output MWe Note: Investment costs for PC boiler plants including everything from coal storage and handling to waste handling except emission reduction equipment. Source: US Dept. of Energy (1994). Operation and maintenance costs In Table 3.3, O&M costs for various sizes of PC boiler units are listed (Ref 5). The costs include the boiler system, steam turbine system and auxiliary systems. Chapter 3. Combustion Technologies 26 Table 3.3 O& M costs for PC boiler units including steam turbine system and balance of plant Unit size Fixed O&M costs Variable O&M costs MWO USDIkW/yr UScents/kWh 500 27 0.2 150 36 0.5 75 53 0.6 Source: US Dept of Energy (1994). A 200-MW, PC plant Figure 3.6 shows a 200-MW subcritical power plant without any flue gas cleaning equipment and Figure 3.7 shows a supercritical PC plant. The reduction in waste production, emissions and coal consumption that are achieved by increasing plant efficiency are shown by comparing Figure 3.6 and Figure 3.7. Figure 3.6: 200-MW subcritical plant without any pollution control equipment Coal: 80 t/h 200 MWe Bottom ash: 2.6 t/h NOx: 0.6 t/h Dust: 24 t/h CO2: 220 t/h Cooling water: 30 000 t/h Note: Data used -- efficiency = 37%; sulfur content, S= 2%; ash content= 32.8%. A Planner's Guide for Selecting Clean-Coal Technologies for Power Plants 27 Figure 3.7: 200-MW, supercritical plant without any pollution control equipment zCoal: 73 t/h 200 MWe SO2: 2.9 t/h Bottom ash: 2.4 t/h NOx: 0.5 t/h 4 1 :; Dust: 21 t/h CO2: 200 t/h Note: Data used -- efficiency = 41%; sulfur content, S= 2%; ash content= 32.8 %. Screening criteria Tables 3.4 and 3.5 are used for the technology screening in Chapter 9. Table 3.4: Screening criteria for subcritical boiler units Maturity of technology * More than 100 units in operation in India and China, respectively Max unit size * Over 1,000-MWe net Waste product * Possible to use without processing Table 3.5: Screening criteria for supercrtical boiler units Maturity of technology * More than 100 units in operation in the world; none in India and less than 5 in China. Max unit size * Over 1,000- MW, net Waste product * Possible to use without processing Chapter 3. Combustion Technologies 28 ATMOSPHERIC CIRCULATING FLUIDIZED BED COMBUSTION Atmospheric circulating fluidized bed combustion is a relatively new combustion technology which has been used most commonly in small-scale plants of less than 100 MW. The technology has some major advantages including low emissions of SO. and NO,. Sulfur can be captured cost- effectively and directly in the furnace by limestone injection. Suitability ACFB boilers have an extremely high fuel flexibility and will accept a very wide range of different fuels including low grade fuels. SO, emissions are low since sulfur can be captured directly in the furnace by limestone injection. Because of the low combustion temperatures (circa 850oC) the NOx emissions are comparatively low. However, significant amounts of N20 emissions have been detected from ACFB boilers. Currently, all ACFB plants use subcritical steam data which means that plant net efficiencies are relatively low compared to those of supercritical PC boiler plants. The amount of waste is larger than for PC boiler units and a major drawback is that with current standards, there are only limited means to utilize the waste produced. Normally the investment cost for a ACFB plant is lower than that of a PC boiler plant equipped with wet scrubber for flue gas desulfurization. There are only a few companies in the world supplying large ACFB boilers today. The technology is commercially viable for boiler sizes up to 100 MW. State of technology During the past ten years, fluidized bed technology has been extensively used for burning low- grade fuels in small plants. ACFB plants are commercially viable in sizes up to 100 MWe. Its use at a utility scale to date is limited. Currently, the largest plant in operation is rated at 250 MW., although plants in sizes up to 350 MW. are under construction. There are less than 10 ACFB boilers with an output of 100 MW. or more in operation in the world. There are numerous small-scale fluidized bed boilers in operation in India today, but no large ACFBs (Ref 1). In China, there are numerous small-scale fluidized bed boilers, but almost no large-scale units. In Neijang Power Station, Sichuan Province, a ACFB boiler with a capacity of 100 MW, supplied by an international supplier was commissioned in 1996 (Ref 2). There are also a number of ongoing projects in China for 50-MW. ACFBs. Today's ACFB boilers use subcritical steam data and, hence, plant efficiencies are moderate. Future development A major future development of ACFB technology is scaling up to larger unit sizes in order to provide utilities with a complete range of unit sizes. Sizes up to 650 MW, are currently planned. By-product utilization and N20 emissions are other issues that are being investigated. The use of higher steam data to compete with PC plant efficiencies lies in the future. A Planner's Guide for Selecting Clean-Coal Technologies for Power Plants Figure 3.8: Typical ACFB boiler plant Feed-water Cyclonesp . Turbine-generator imt*so*" Ai h 4:::' "Filter .FD fan '"" Steam boiler .. Flyash removal ID fan Coal silo Limestone silo TertiaryaltFyshrcrclto Spread n Conveying-ai fans Secondrai feeder f. Coal Colarecircuati or : Flyash Auxiliar gas- silo fired burnersa . e Trampmateria Fluidized-bed chamber Bed-ash es.... . .. BedashDry-ash a reinjection removal Wet-ash , .Bed-ash removal '""? removal Coal crusher Source: Coal Industry Advisory Board (1995). Co 30 Plant size Today, ACFB boilers are common in sizes below 100 MW.. Unit sizes up to 250 MWe are in operation. However, the major international ACFB supplier will offer commercial guarantees for units up to 400 MW,. In the future, unit sizes up to 650 MW. will be available. Fuel flexibility The fuel flexibility of ACFB boilers is extremely wide, probably the widest of any power generation technology. One single boiler can be designed for a wide range of fuels. Various types of fuels such as biomass, peat, lignite, and hard coal can be burned in the same ACFB boiler together or separately. Even coal cleaning wastes can be fired in a ACFB boiler. Table 3.6 shows the possible variations in some chosen coal parameters for a normal ACFB boiler equipped with fluegas recirculation. Table 3.6 Acceptable values for some coal parameters for normal ACFB boiler with flue gas recirculation Coal parameter Limit (approximate values) Lower Heating Value >5 MJ/Kg Ash content <60% Initial Deformation Temperature (IDT) >900*C Moisture <55% Chlorides <0.5% Volatile Matters (VM) >10% Sodium+Potassium (Na+K) <3.5% Performance Efficiency Today, ACFB efficiency is more or less the same as for subcritical PC fired plants, as shown in Table 3.7. In the future, if supercritical ACFB boilers are built, the efficiency will increase. Table 3.7 Performance data ACFB boiler plants Parameter Today Future Potential Steam pressure (bar) 140 240 Steam temperature (OC) 540/540 540/540 Unit net efficiency (%) 36-38 1 40-41 Note: Unit efficiency data based on condenser pressure 50 mbar and LHV of the fuels. Source: Takeshita (1995). Load range and load change rate Minimum load is in the range of 30-40% of maximum continuous rating. Changes of load (ramping) can be 5-7% per minute. A normal load change rate required by the grid for coal-fired plants is usually 4% per minute. A Planner's Guide for Selecting Clean-Coal Technologies for Power Plants 31 Start-up time Cold start: 8 - 12 hours depending on type of circulation. Restart of a hot unit: I - 1.5 hours. Restart after a weekend shut-down: 2 - 3 hours. Environmentalperformance NO,: 80-150 mg/MJfuel for bituminous coal without NO, reduction equipment. N20: significant emissions of N20 have been observed. Particulates: 10-25 mg/Nm3 with ESP or bag filter. Sulfur: 90-95% removal of sulfur. Sulfur is captured in the bed by the injection of limestone. The sulfur removal rate is highly dependent on the sorbent to sulfur ratio (Ca/S). Increased sorbent to sulfur ratio improves the S02-removal. At a Ca/S ratio of 2, a 90% sulfur removal is possible. At a slightly higher Ca/S ratio, 95% sulfur removal is feasible. However, at higher sorbent ratios the sorbent utilization decreases, resulting in increased sorbent consumption and higher operating costs. Figure 3.9 shows the cost for the last ton of sulfur removed in a ACFB boiler. The molar ratio between calcium and sulfur increases drastically with increasing sulfur removal efficiency. Figure 3.9 Costs for last ton of sulfur removed as a function of the sulfur removal efficiency 1600 1400 g 1200 1000 800 o 600 400 200 011 0% 20% 40% 60% 80% 100% Sulfur removal efficiency Note: The limestone cost used is 20 USD per ton. Chapter 3. Combustion Technologies 32 Waste production Solid residues from ACFB combustion using limestone injection for SO2 control consist of a mixture of coal ash oxides, calcium sulfate, high levels of lime (CaO) and low levels of carbonates. Of the residues, 80-90% are removed as fly ash and the rest as bottom ash. Today, ACFB wastes normally are landfilled. Development work on the use of ACFB wastes is ongoing. Availability Availability data is limited, but a sample of five fluidized bed boilers in the size range 80-160 MW including both bubbling and circulating beds, all less than six years old, shows an average availability between 87-88% with planned outages of 4 weeks per year. Construction issues Construction time The construction time for a ACFB plant is 36 months - from contract award to commercial operation. Because of the large boiler sizes, most of the plant has to be erected on site. The possibilities for domestic manufacturing Today, BHEL in India manufactures ACFB boilers with an output of 30 MW,. Some Chinese boiler manufacturers cooperate with foreign companies in order to implement the ACFB technology in China. Complexity of technology The complexity of the design of a power plant with ACFB boilers is low compared to that of, for example, an IGCC plant. A unit consists of a boiler, a turbine, fuel and ash handling equipment and flue gas cleaning. The operation of a ACFB boiler plant is more complex than that of a PC boiler plant. The temperature in the furnace must be kept within a narrow span in order to ensure as efficient sulfur reduction. The distribution of air to the furnace must be well controlled. Maintenance Normally, a yearly overhaul period of four to five weeks is required. The manufacturing companies provide regular inspection and maintenance services to their clients. Costs Investment cost The investment cost for a ACFB boiler plant lies in the range of 1,300-1,800 USD/kWe for unit sizes 50-200 MWe. Figure 3.10 shows the estimated investment costs depending on the unit sizes for plants firing medium sulfur (2.1%) bituminous coal. The cost is given for a complete plant with one unit and includes everything except dust cleaning (ESP or bag filter) from fuel storage to waste handling. The cost for a boiler only amounts to approximately 30% of the investment cost for a complete plant. The cost is highly dependent on the state of the market, the size of the plant, number of units, the extent of manufacture in low-wage rate areas, etc. A Planner's Guide for Selecting Clean-Coal Technologies for Power Plants 33 Figure 3.10: Investment cost per kWe for ACFB boiler plants 2000-- 1900 - - 1600-- 1400 1200 1000 I I I 0 50 100 150 200 Net electric output MW Source: Forsberg (1996). Operation and maintenance costs The O&M costs are shown in Table 3.8. Fuel costs are not included. Table 3.8: Operation and maintenance costs for a ACFB plant Unit size Fixed O&M costs Variable O&M costs MW. USD/kW/yr UScents/kWh 150 44 0.85 75 64 1.04 Source: US Dept. of Energy (1994). Chapter 3. Combustion Technologies 34 A 200-MW, ACFB plant Figure 3.11 shows a 200-MW, ACFB plant using limestone injection for SO2 control. Figure 3.11 200-MW, ACFB plant using limestone injection for SO2 control; no particulate removal equipment included Coal: 80 t/h limestone: 10 t/h 200 MWe SO2: 0.3 t/h Bottom ash and NOx: 0.2 t/h bed off take: 4 t/h Dust: 35 t/h C02: 220 t/h Note: Data used -- efficiency = 37%, sulfur content, S= 2%, ash content = 32.8 %. Screening criteria The table below is used for technology screening in Chapter 9. Table 3.9: Screening criteria for ACFB plants Maturity of technology * Commercial in industrialized countries for sizes <100 MWe. There are less than 10 units with an electric output above 100 MWe in operation in the world today. No units with an output above 100 MWe are in operation in India and one 100 MWe unit is under construction in China. Maximum unit size * Up to 250-MWe net Waste products * Not possible to use today. A Planner's Guide for Selecting Clean-Coal Technologies for Power Plants 35 PRESSURIZED FLUIDIZED BED COMBUSTION Pressurized fluidized bed combustion is an even newer technology than ACFB with only a few plants in operation worldwide. In a PFBC plant as illustrated in Figure 3.12, Dower is generated in an integrated combined cycle with the hot gas from the combustor driving the gas turbine. Steam generated mostly in the combustor powers a steam turbine. The main advantages of the PFBC technology are the low emissions and the high efficiency. Suitability The technology is new with limited operational experience. There is only one commercial plant in operation today and only one company in the world supplying PFBC plants. The efficiency is high and the environmental performance is good with low emissions of SOx and NOx. Sulfur can be captured directly in the combustor by limestone or dolomite injection. Because of the low combustion temperatures ,-850 oC, the NOx emissions are low. PFBC units can be designed for a wide range of fuels including low grade. The drawbacks are high investment costs, shortage of experience of the technology and the waste product which as of today is still difficult to use. State of technology The PFBC technology is new with only one commercial plant in operation in the world (P200 in Virtan, Stockholm, Sweden) and a few others under construction. There are plans to build one PFBC plant in Dalean in China. Plant size Currently only two sizes of PFBC plants are available, the P200 and the P800. The P200 produces approximately 80 MWe with a fuel input of 200 MW, and P800 produces approximately 340 MWe with a fuel input of 800 MW. No P800 plant is in operation, but one unit is under construction in Japan. Fuel flexibility The fuel flexibility of PFBC technology is extremely wide. However, for a specific plant the combustor and auxiliary equipment must be optimized for its design coal. The flexibility is therefore limited for each PFBC unit to handle a range of coal qualities. Performance Table 3.10 below summarizes the performance of PFBC plants. The efficiencies are higher than those of ACFB boiler plants. Chapter 3. Combustion Technologies igure 3.12: A typical PFBC plant Steam turbine vessel Sorbent Coal Bed . reinjection --- Condenser Water Cyclonesu Gase turbinen conoe Mixere Pat up-Ash cooler Lowh pressureFedar prehepreheaters source. Economiser. 37 Table 3.10: PFBC performance b IStart-up time Start-up time Efficiency P200 a Efficiency P800 b Load range hot cold 42% 45% 40-100% of MCR 3 hours 15 hours b condensing mode, subcritical steam parameters condenser pressure of 50 mbar. condensing mode, supercritical steam parameters condenser pressure of 50 mbar. Source: Takeshita (1995). Environmental performance Sulfur is removed by limestone or dolomite injection. At a Ca/S ratio of 2, a 90% sulfur removal is reached. Environmental performance is shown in Table 3.11. Table 3.11: PFBC environmental performance NO. Sulfur removal Particulates mg/MJ % mg/Nm 70 - 110 90-99 10-25 with ESP or bag filter Source: Coal Industry Advisory Board (1995). Waste production Solid residues from PFBC combustion consist of a mixture of coal ash oxides, calcium sulfate and carbonates. The content of lime is low (Ref 8). Due to the low lime content, the PFBC waste is expected to have a higher potential for utilization than ACFB waste. However, today no area of utilization exists, but the wastes are disposed. Construction issues The possibilities for domestic manufacturing With only one supplier in the world for PFBC plants today, the possibilities for manufacturing in India and China are limited. However, if the design and the critical parts, such as the gas turbine and combustion equipment are manufactured abroad, the rest of a plant can be made domestically. The construction time for PFBC is approximately 42 months. Complexity of technology Since this is a combined cycle consisting of a gas turbine operating together with a steam turbine and the combustion process is pressurized, the complexity of the design is high. Operation of a PFBC plant is complex and requires skilled personnel. Maintenance Normally a yearly overhaul period of four to five weeks is required. Costs The investment ranges from 1,100-1,500 USD/kW. Chapter 3. Combustion Technologies 38 Screening criteria The table below is used for technology screening in Chapter 9. Table 3.12: Screening criteria PFBC plants Maturity of technology * With only one plant in the world in commercial operation the technology is new with limited operational experience Unit sizes * P200: 80 MWe, P800: 340 MWe Waste products * Disposal INTEGRATED GASIFICATION COMBINED CYCLE Integrated gasification combined cycle is a technology under development with only one commercial plant in operation; Buggenum in The Netherlands. A few plants are presently under construction. In Madras, India, work is under way to build a 60-MW IGCC plant fueled with lignite. The operating principle of an IGCC plant is illustrated in Figure 3.13. In a gasification process, electricity is produced in a gas turbine fueled by a synthetic gas produced by the partial oxidation of coal in a gasifier. Steam, produced by synthetic gas cooling, drives a steam turbine. Sulfur is removed from the syngas before combustion. Removed sulfur is converted to elemental sulfur which can be sold. Coal ash is removed as slag from the gasifier. The main advantages of the gasification process are the very low emissions and the high plant efficiency, as shown in Table 3.13. The major drawbacks are that the process is very complex, it requires a large surface area and there is very little commercial experience of operation. The investment cost is high, approximately 1,500-1,600 USD/kW,. The construction time is expected to be four years. Performance data available for IGCC plants presented below are relatively uncertain since there are only a few IGCC plants in operation in the world today. Table 3.13: Performance data IGCC Net efficiency Unit size Based on LHV of NOx emission SOx removal Particulate MWe the fuel mg/MJ rate, % emission, mg/Nm3 100-350 42-45 35-50 98 10 Source: Takeshita (1995). A Planner's Guide for Selecting Clean-Coal Technologies for Power Plants FIgure 3.13: Principle of an IGCC plant Oxygen Pulverized coal Convection- ooer water Combustion chamber Clean gas Gasifying reactorGas turbine reactor t ~* , pressor Generator Radiation Steam turbine cooler Generator Dust Pure sulfur Stack Cooling water Slag Feed water CO) 40 Screening criteria Screening criteria to be used in Chapter 9 are presented in Table 3.14. Table 3.14: Screening criteria IGCC Maturity of technology * With only one commercial plant in operation in the world, the technology is in the development phase. Unit sizes * 100-350 MWe Waste products * Ash and bottom slag. Elemental sulfur that can be sold. REFERENCES 1. Mathur, Ajay. 1996 (May). Personal communication. Dean, Energy Engineering & Technology Division, TERI. New Delhi, India. 2. Li, Zhang. 1996 (April). Personal communication. Hunan Electric Power Design Institute. Changsha, China. 3. Takeshita, Mitsusu. 1995. Air Pollution Control Costs for Coal-fired Power Stations. IEA Coal Research, IEAPER/17. International Energy Agency. London, UK. 4. Coal Industry Advisory Board. 1995. Factors Affecting the Take Up of Clean Coal Technology. Climate Committee. International Energy Agency. London, UK. 5. U.S. Department of Energy. 1994. Foreign Markets for U.S. Clean-Coal Technologies. Report to the United State Congress. May 2, 1994. Washington, DC. 6. Pruschek, R., G. Oeljeklaus, and V. Brand. 1996. Zukiinftige Kohlekraftwerksysteme. nr 76 Heft 6 page 441-448. VGB Kraftwerkstechnik. Universitat - GH, Essen, Germany. 7. ABB Carbon AB. "PFBC Clean Coal Technology. A New Generation of Combined Cycle Plants to Meet the Growing World Need for Clean and Cost Effective Power." Brochure. Finspong, Sweden. 8. Bland, A.E., D.N Georgiou., and M.B Ashbaugh. 1995. "Use Potential of Ash from Circulating Pressurized Fluidized Bed Combustion Using Low-sulfur Sub-bituminous Coal." Proceedings of the 13th International Conference on Fluidized Bed Combustion, vol 2, 1995. Orlando, Florida. 9. Forsberg, Nils. 1996 (September). Personal communication. SK Power Company. Copenhagen, Denmark. A Planner's Guide for Selecting Clean-Coal Technologies for Power Plants 4. SO2 EMISSION CONTROL TECHNOLOGIES Since the sulfur content of coal can vary considerably, the simplest way to reduce SO2 emissions in industrializing countries is to switch to a coal with a lower sulfur content. The benefits are obvious: it requires no change in operating procedures, and no additional by-products are generated. The capital investment can range from none to considerable. In some cases, modification to coal-handling equipment is necessary. Switching to low sulfur coal alone is rarely sufficient to meet regulatory requirements, but it can be a first step in an emission reduction program, reducing the cost of following control technologies. For large power plants tied to local suppliers for political or economic reasons, fuel switching may be difficult. In such cases an alternative is coal cleaning by physical separation, described in detail in Chapter 3. Although sulfur removal is not the primary aim, physical coal cleaning techniques remove inorganic sulfur compounds in the coal, resulting in a SO2 removal of 10 - 40%. Obvious benefits come from reduced ash content and improved heat value of the coal. Coal cleaning at the mine site also reduces the cost of transportation and has the advantage of reducing the amount of by-products generated at the power plant; less sorbent is needed for S02 removal, hence reducing the cost of waste disposal. The major drawback is that with a lower sulfur content, the fly ash resistivity may increase. This affects the ESP performance. ESP modifications may be necessary. Nonetheless, coal cleaning remains the most cost-effective route to reduce SO2 emissions. When fuel switching and coal cleaning are not possible or not sufficient to meet desired emission levels, an S02 removal technology must be introduced. The choice of SO2 removal technology depends on a number of factors: emission requirements, plant size and operating conditions, sulfur content in the fuel(s), and the cost of various technology options, all of which are unique to each site. This chapter presents basic technical and economical information important for selection between different SO2 removal technologies. The technologies discussed in this section include sorbent injection processes, wet scrubbers, and spray dry scrubbers. Advanced combined SOx/NO,.-removal is discussed briefly in the section, Combined SO,/NOX Control (page 62.) Wet scrubbing has become the most commonly used technology for large base load, coal-fired power plants. It has a market share of 85% of the installed capacity. The capital cost and the rate of SO2 removal varies considerably between different technologies. Figure 4.1 illustrates the capital cost for three different sulfur removal methods in USD/kWe as a function of the sulfur removal efficiency. The figures in the diagram give an indication of the cost level, but the absolute levels of the costs should be considered with care. The diagram shows that wet scrubbing is the most efficient method, but it is also the most expensive one. Sorbent injection requires a lower investment, but gives a lower removal. Generally, the capital cost for SO2 removal per kW is higher for a specific technology for smaller boilers than for larger plants. 41 42 Flgure 4.1: Capital costs for different sulfur removal methods Capital costs USD/kW E Wet scrubbers Hybrid sorbent injection Furnance and duct sorbent injection 250-- Spray dry scrubbers 200-- 150-- 100- MM 50- I I I I I I 1 0 20 40 60 80 100 Removal efficiency, % Source: lEA (1995), Holme and Darnell (1996), and Smith (1996). In commercial applications, technologies with lower capital costs, such as sorbent injection processes and spray dry scrubbers, are used mainly in relatively small plants burning low sulfur coal and in plants at peak load operation. They are also installed in retrofit application in plants with a short remaining lifetime. Capital costs for FGD have come down in the last few years due to improved design and simplified processes and they can be expected to decrease firther in the next decade as a result of a greater demand in the emerging markets of Asia and Eastern Europe. The increase in electricity production costs for different methods is illustrated in Figure 4.2. It shows the estimated levelized costs per kWh of electricity produced as a function of sulfur removal efficiency. Coal cleaning followed by sorbent injection gives the lowest increase in production costs, but the sulfur removal capability is limited. Wet scrubbing gives the highest increase in electricity production cost. A Planner's Guide for Selecting Clean-Coal Technologies for Power Plants 43 Figure 4.2 Levelized costs in UScents/kWh of electricity produced for different SO, removal technologies coal cleaning dry sorbent injection wet scrubbers 0.70- SO2 0.60- 0.50 - 0 0.- 0 050.400 4) 24 b)0.30- -J 0.20- 0.10- 0 10 20 30 40 50 60 70 80 90 100 Removal efficiency, % Source: IEA (1995). High capital costs result in high overall costs for smaller boilers and boilers with few operating hours due to peak load operation. The most economical choice for these boilers is either fuel switching, coal cleaning or a sorbent injection method with low capital requirements. This is also true for boilers with short residual lifetime. Therefore, when choosing a sulfur removal system, it is important to have realistic assumptions about annual operating hours and the lifetime of the plant. Assumptions which are too optimistic may result in incorrect conclusions. Despite the considerable variations in capital cost and increased electricity production cost, the actual dollar costs per ton of SO2 removed do not vary much for different methods. This can be seen in Figure 4.3. Coal cleaning is the most cost-efficient route to reduce SO2 emissions. Sorbent injection processes, which have lower capital costs than wet scrubbers, require larger quantities of sorbent resulting in higher overall costs. The relatively low operating costs of wet scrubbers, combined with high sulfur removal efficiency, makes the overall sulfur removal cost lower than for sorbent injection processes despite the higher investment. Chapter 4. SO2 Emission Control Technologies 44 Figure 4.3: Levelized costs in USD/ton of S02 separated for different sulfur removal technologies coal cleaning dry sorbent injection wet scrubbers 3000- -2000- 0 1000 - SO2 *0 S1110 I 10 20 30 40 50 60 70 80 90 100 Removal efficiency, % Source: IEA (1995). In countries with a need for immediate removal of SO2 emissions under tight economical constraints, a stepwise approach can be considered. Low-cost sorbent injection is an appropriate first step that can be implemented rapidly. It can be followed later by further upgrading to a hybrid system with higher removal efficiencies. Another option is to upgrade by adding a conventional wet scrubber, with the sorbent injection process and the scrubber sharing the same limestone storage and transport system. When evaluating sulfur removal methods, it is important to use the actual average sulfur content of the coal for the estimation of the required S02-removal. If the maximum sulfur content is used in the evaluation, the result may be totally misleading. Figure 4.4 shows the SO,, removal efficiency which is required in order to obtain specific SO2 emissions when the sulfur content varies between 0.5 and 4.0% in the coal as fired. It can be used as assistance when an appropriate sulfur removal method is chosen. A Planner's Guide for Selecting Clean-Coal Technologies for Power Plants 45 Figure 4.4: Required SO2 removal efficiency for coals with a LHV of 24 MJ/kg 1.00- 0.80 0.70 --, c 0.60-. .' Emission 0.5o - mg So2iMJ 0.40 100 I * ----200 0.30 -- I '--- 0 -300 0.20-- -----400 0.10- 1 II 0.00 I 0 1 2 3 4 Sulfur Content in the Coal, % One important aspect to be considered, particularly in the case of countries with a shortfall in power capacity, is the parasitic power consumption required by the S02-removal process. As shown in Figure 4.5, sorbent injection systems have the lowest parasitic power demand (up to 0.5% of the electricity production). Spray dry scrubbers have a higher power demand, but only about half of that of wet scrubbers. Figure 4.5: Parasitic power demand for different SO2 removal methods 2 4a 1,5- E -0 cL 0,5- 0I Sorbent Injection Spray dryers Wet scrubbers Chapter 4. SO2 Emission Control Technologies 46 SORBENT INJECTION PROCESSES For PC boilers, injection of a sorbent is a simple technology for SO2 removal. This chapter deals with three categories of sorbent injection processes: furnace sorbent injection, duct sorbent injection, and hybrid sorbent injection. The processes are illustrated in figure 4.6. In the first two processes, the sorbent is injected directly into the boiler furnace or duct. Hybrid sorbent injection is a combination of furnace and duct sorbent injection, as injection of sorbent into the furnace is followed by either: * downstream sorbent injection into the duct, * reactivation of the sorbent by humidification in a reactor, or * separation of unreacted sorbent removed along with ash from the ESP followed by reactivation and recycling of the unreacted sorbent. Figure 4.6: Sorbent infection systems Furnace Injection Duct Injection boiler lie 2 air ESP or CaCO3 or Ca(OH)2 ater fabric filter coal recycle . - _ conditioning/ _ disposal reactivation recycle wateror steam )o material flow ---> options A Planner's Guide for Selecting Clean-Coal Technologies for Power Plants 47 Suitability Sorbent injection is a simple process with low capital and maintenance costs and low power consumption (<0.5% of electricity produced) compared to a wet FGD process. It is suitable when a moderate (30-70%) S02 removal efficiency is acceptable. Due to their low capital cost, but relatively high operational costs, sorbent injection processes are especially suitable for old boilers with limited remaining lifetime, and for peak load boilers with short annual operating time. For the same reasons, they are also suitable for small boilers. The system is easy to install, operate and maintain, and no wastewater is generated. It is particularly suitable for retrofit applications as it has very low space requirements. It is suitable for low sulfur coals, due to the moderate sulfur removal rate. Furnace sorbent injection, representing the simplest, lowest-cost process for SO2 removal, is suitable in industrializing countries as a first step towards an immediate reduction in S02 emissions. It can be followed by further upgrading to a hybrid system with higher removal efficiencies. For example, a humidification step could be added. Hybrid systems can, depending upon technology, reach removal efficiencies up to 80-95% at relatively low operating costs. One important aspect of sorbent injection is that the waste production increases considerably. The effect on precipitator performance and ash handling cannot be neglected. In retrofit installations, modifications to the existing ESP or installation of baghouse filter may be required. State of technology Since it has been in use for several years, furnace sorbent injection can be considered commercially proven for small plants. For large plants, several demonstration projects have been completed in the United States and some are under construction. In China, furnace limestone injection is being tested in a 1-MW pilot plant. The system is developed by the Thermal Power Research Institute (TPRI) and it has reached an efficiency of 80-85%. Duct sorbent injection is in the demonstration and early commercialization phase. Two large scale pre-ESP sorbent injection plants are in operation in the United States: Pennsylvania Electric's 140-MWe plant, Seward; and Ohio Edison's 104-MWe plant, Edgewater (Ref. 7). Approximately 40 plants worldwide have duct injection of some type installed today, most of them are small units retrofitted with sorbent injection. Further demonstration on larger units is needed. Hybrid sorbent injection includes several different processes, some of which are commercial and some of which are in the demonstration phase. The Tampella LIFAC process can be considered commercial with eight reference plants in the world. The process will be installed in two new 125- MWe units which are under construction in the Xiaguan power plant in the Nanjing province in China (Ref. 2). Presently, there are no large power plants in operation in China equipped with sorbent injection systems for sulfur removal. In India, there are no sorbent injection installations. Chapter 4. SO2 Emission Control Technologies 48 Plant size Sorbent injection processes are mostly used in smaller units and in retrofit applications, but they can be installed on any unit. The largest new installation today is 600 MW,. Retrofit installations up to 300 MW. exist. Fuel flexibility Because of a low sulfur removal efficiency, furnace or duct sorbent injection processes are most suitable for low sulfur coals or where the emission requirements are less strict. Hybrid processes, with higher sulfur removal, are suitable for coals with higher sulfur content. Performance Efficiency The sulfur removal efficiency is normally 30-60% for furnace sorbent injection and somewhat higher, 50-70%, for duct sorbent injection. Hybrid sorbent injection processes using additives, sorbent recirculation etc., normally reach higher desulfurization efficiencies in the 80-90% range. With some processes, even higher efficiencies up to 95% can be achieved. The SO2 removal efficiency is highly dependent on the sorbent to sulfur ratio (Ca/S molar ratio). The relationship between the removal efficiency and the sorbent ratio for a duct sorbent injection process is shown schematically in Figure 4.7. An increased sorbent to sulfur ratio improves the SO2 removal. However, at higher sorbent ratios the sorbent utilization, i.e. the fraction of reacted sorbent, decreases. This leads to increased sorbent consumption and higher operating costs. In some cases, it may not be economically justifiable with a large increase in sorbent consumption, to achieve only a small improvement in S02-removal. After the Ca/S ratio, the single most important factor affecting sorbent injection efficiency is the approach-to-adiabatic-saturation temperature. The SO2 removal increases with decreased approach temperature. The efficiency can also be raised by reactivating excess sorbent through humidification of the flue gas, by recycling unreacted sorbent, and by the use of additives. Pilot tests indicate that these methods can raise the removal efficiency to 90-95%. Humidification also serves another purpose as it improves the ESP performance. Power consumption The power consumption is low; 0.5% of the unit's generating capacity is consumed by the sorbent injection. A Planner's Guide for Selecting Clean-Coal Technologies for Power Plants 49 Figure 4.7: The effect of increased sorbent ratio on the SO2 removal 100 90 80 70 0 ESP contribution 0- E 60 '50- 0 duct contribution 40 1 1,2 1,4 1,6 1,8 2 2,2 2,4 Ca/S ratio Source: lEA (1993). Sorbent Furnace sorbent injection typically uses sorbents which include pulverized limestone (CaCO3), hydrated lime [Ca(OH)2], and dolomite (MgCO3 x CaCO3). In duct sorbent injection processes, Ca(OH)2, sodium bicarbonate [Na(C03)2] or lime slurry are used as sorbents. A Ca/S ratio of 2 is common. Waste production Waste production increases considerably when using sorbent injection processes and the increase depends on the sulfur content in the coal and the Ca/S ratio. A Ca/S ratio of 2 can triple the ash production rate for a high sulfur coal. The waste, normally consisting of a mixture of calcium or sodium sulfates, unreacted sorbent and fly ash is non-usable and must be disposed of In post- ESP duct sorbent injection, the fly ash is separated before the injection of sorbents and can therefore be used in the usual way. Availability Since the process is relatively simple, the availability will most probably be close to 100%; but, since up to this date the technology is relatively unproved, the availability value is still relatively uncertain. Chapter 4. SO2 Emission Control Technologies 50 Construction issues Construction time If space is available for the installation of sorbent injection equipment, the downtime required for retrofit of an existing unit is 3 to 6 weeks. Area requirements The installation has very small space requirements. This is an advantage in retrofit installations. For post-ESP sorbent injection processes an extra filter is required. The area required for post- ESP sorbent injection will therefore be larger than for pre-ESP sorbent injection. The possibilities for domestic manufacturing, licensing agreements Currently, there are no Chinese manufacturers of sorbent injection systems for sulfur removal for large power plants. The technologies are still in the small-scale research and testing phase. Consequently, there are no license agreements between Chinese and international manufacturers for sorbent injection processes (Ref. 2). However, since the manufacturing for the technology is fairly simple, Chinese manufacturers will be able to supply sorbent injection systems as soon as the market requires. In India, there are no power plants equipped with sorbent injection systems. Since the sulfur content in Indian coals is normally very low, less than 1% (see Section 2), the interest in sulfur removal is low. Complexity of the technology The design of this type of system is relatively simple and has a low complexity. Costs Investment Furnace and duct sorbent injection: 75- 00 USD/kW (developed from Ref. 5) Hybrid systems: 100-140 USD/kW (Ref. 3 and 9) New installations will fall in the lower range whereas retrofit installations can be expected to fall in the upper range. Operation and maintenance fixed = 6.0 USD/kW/year variable = 0.3 UScent/kWh (Ref. 3) Total levelized costs typically range from 0.2-0.75 UScent/kWh or 500-750 USD/ton of SO2 removed (Ref 3 and 9). 200-MWe PC plant equipped with sorbent injection Figure 4.8 shows a 200-MW subcritical PC plant equipped with a sorbent injection system for SO2 removal. The reduction in SO2 emission achieved can be compared with Figure 3.6. A Planner's Guide for Selecting Clean-Coal Technologies for Power Plants 51 Figure 4.8 200-NW, subcritical PC plant equipped with sorbent injection system for SO2 removal Coal: 80 t/h - - ev~ t lime: 7.5 t/h \Tf SO2: 1.6 t/h Bottom ash: 3 t/h NOx: 0.6 t/h Dust: 30 t/h* CO2: 220 t/h Note: Data used -- plant efficiency = 37%, sulfur content, S= 2%, ash content = 32.8 %. * No dust removal equipment Screening criteria Table 4.1 is used for technology screening in Chapter 9. Table 4.1: Screening criteria sorbent injection processes Maturity of technology * Furnace sorbent injection is commercial for small plants. It is being demonstrated for large plants. Duct sorbent injection is in the early commercialization stage. More than 10 reference plants exist worldwide, however few are commercial. Hybrid sorbent injection includes several different processes, some of which are commercial and some are in the demonstration phase. There are no plants using sorbent injection in India or China. Maximum unit size * Mostly used for smaller units or retrofit of existing boilers. The largest new plant is 600 MWe, the largest retrofit 300 MWe. Waste product * Not possible to use. No wastewater. Chapter 4. SO2 Emission Control Technologies 52 SPRAY DRY SCRUBBERS Spray dry scrubbers were developed as a cheaper alternative to wet scrubbers in the early to mid- 1970s. Presently, they have a market share of about 10 %, but the demand has fallen recently due to difficulties with utilization of the by-product. The by-product, which consists of a mixture of unreacted lime, fly ash, and calcium sulfite/sulfate, must be disposed of Suitability Dry scrubbers have lower capital costs than wet scrubbers because there is no need for waste sludge handling and processing, and because cheaper material can be used in the absorber etc. The spray dryer absorber, which operates at 10-200C above dew point of the flue gas, can be constructed of carbon steel; whereas wet scrubbers operate below the dew point and therefore require rubber lining or stainless steel. But the drawback of spray dry scrubbers is the four to five times higher cost for lime sorbent compared to the limestone used in wet scrubbers. This is why spray dry scrubbers are used mostly in small boilers burning low to medium sulfur coals, i.e. less than 2.5% sulfur, and for large plants in peak load operation. For the same reasons, the system is suitable for retrofit on plants with a limited remaining lifetime. Due to their low capital requirements, spray dryers are suitable for developing countries. However, a significant percentage of the capital requirements (at least during the first 3 to 7 years of technology deployment) will be in foreign exchange. Demonstration may be needed for high ash Indian coals and high sulfur coals generally. An important feature of spray dry scrubbers compared with wet scrubbers is that no waste water is produced. Therefore, they are suitable for sites where there is no space for waste water handling. Because they normally are more compact than wet systems, they are also advantageous in retrofit applications where there are often space constraints. The process has a high efficiency for SO3 and HCl removal, which makes it suitable for plants with such requirements. A critical aspect of spray dry scrubbers is the increase in waste production. The effect on precipitator performance and ash handling cannot be neglected. In retrofit installations, modifications to the existing ESP may be required. State of technology Dry scrubbers are used commercially with low sulfur coals in Europe, Japan and the United States. In China, a spray dryer absorption system developed by the Southwest Electric Power Design Institute, in cooperation with other institutions, is in commercial operation in the Sichuan province. The system operates with an efficiency in the 80-90% range (Ref 7). Two demonstration projects for dry FGD are currently operating on in China. In the Huangdao 2x210-MW plant in the Shangdong province, a simplified dry FGD device is being tested. The equipment, which was supplied by Japan, has been in operation since 1995. The other project is a half-dry FGD method which is tested in the Taiyuan power plant in the Shanxi province. The goal is to find a method with lower investment cost -- at least half that of wet FGD. The equipment was supplied by Mitsubishi and was sponsored by the Chinese Ministry of Electric Power (Ref 2). A Planner's Guide for Selecting Clean-Coal Technologies for Power Plants 53 The effective performance of spray dryers with high sulfur coals needs to be proven. Specific issues that require further demonstration include impact of chloride contained in the coal on spray dryer performance, and ability of existing ESPs, if downstream from the spray dryer, to handle the increased particulate loading and achieve the required efficiency. Plant size One scrubber can treat flue gas from boilers up to 200 MWe. For larger boilers, several scrubbers are installed in parallel. Fuel flexibility Spray dry scrubbers are most suitable for low to medium sulfur coals, i.e. less than 2.5% sulfur, because there is limit to the amount of lime slurry that can be injected into the reactor without causing condensation problems, which constrains the achievable level of SO2 removal. For plants burning higher sulfur coal, spray dry scrubbers can be used if a lower sulfur removal efficiency can be accepted. Just as in wet scrubber systems, the presence of chlorine in the coal enhances the SO2 removal or reduces the sorbent need at constant removal level. Performance Efficiency Spray dry scrubbers can be designed for up to 99% SO2 removal, but normally they are designed for 70-95% efficiency. In practice, the design efficiency depends on emission limits and sulfur content in the coal. For low sulfur coal, a lower efficiency can be sufficient to meet regulations. The efficiency increases with increasing lime to S02 ratio, increasing flue gas inlet temperature and decreasing approach-to-saturation temperature. Recirculation of the reaction product containing unreacted lime is used to enhance SO2 removal and improve lime utilization. The efficiency is improved by the presence of chloride either from the coal or from additives such as CaCl2 or sea water. Preliminary laboratory and large scale testing indicate that similar efficiency of SO2 removal can be achieved with high sulfur coals (up to 4.5 percent by weight). Power consumption The power consumption is low. It ranges from 0.5-1.0% of the unit's generating capacity. Sorbent Lime is used as sorbent. The lime to SO2 ratio is typically between 1.1 and 1.6. Waste production Non-productable solid waste consisting of a mixture of fly ash, calcium sulfite (CaSO3), calcium sulfate (CaSO4) and unreacted sorbent is produced. The content of unreacted lime and calcium sulfite and calcium sulfate may cause leaching of hazardous components. The waste needs conditioning with water to avoid problems with dust and leaching before disposal. The problems Chapter 4. SO2 Emission Control Technologies 54 of disposing of the waste product at a reasonable cost is one of the major drawbacks with the technology. Various utilization options are being investigated. No waste water is produced. Availability Most existing plants achieve a reliability above 97%, many reach 99-100% availability. Construction issues Construction time Retrofit: 3 to 6 weeks is needed to connect a spray dryer in an existing power plant Area requirements Typical absorber size is 15 meters diameter by 12 meters height of cylindrical form for a boiler of 100 - 150 MWe capacity. Thepossibilitiesfor local manufacturing, licensing agreements At present, there are no Chinese manufacturers of spray dry scrubbers and there are no licensing agreements between Chinese and international manufacturers (Ref. 2). The situation in India is similar (Ref. 1). Complexity of the technology Spray dryer systems have fewer components than a wet FGD process and the design of the process is therefore less complex than that of a wet FGD process. The construction of the absorber is easier as the absorber operates above the dew point of the flue gas which means that cheaper material can be used. There is no need for rubber lining, stainless steel or nickel alloys required by a wet scrubber. Costs Investment and operation and maintenance Table 4.2 shows estimates of capital and O&M costs for spray dryers. The capital requirement for installation of a spray dryer plant depends on many site specific conditions, which explains the wide range on the figures in table 4.2. For example, in some plants a pre-collector is installed between the air heater and the absorber. The pre-collector removes most of the fly ash before the absorber. This prevents erosion, decreases the amount of waste that has to be disposed of, and separates the salable fly ash. Installation of a pre-collector will, of course, increase the capital cost. A requirement to reheat the cleaned flue gas before it enters the stack also increases the capital cost. Capital costs for plants that do not require these additional installations will fall in the lower range of the numbers in Table 4.2. If there are requirements for a pre-collector, a spare absorber and reheat devise, the capital cost will end up in the upper range. The operating cost depends on coal sulfur content and desired removal levels. A Planner's Guide for Selecting Clean-Coal Technologies for Power Plants 55 Table 4.2: Capital and O&M costs for spray dryers Cost factor Capital costs 110 - 170 USD/kW Variable O&M 0.25 - 0.3 UScents/kWh: Fixed O&M 8.5 - 9.5 USD/kW per year Source: lEA (1995). For retrofit installations, several site specific factors affect the capital cost. Such factors include ease of access and ducting distance. The capital cost requirements for spray dryers are lower than those for wet scrubbers mainly because there is no need for waste sludge handling and processing. Cheaper material can be used in the scrubber. The dry scrubber can be constructed of carbon steel since it operates at 10-200C above the flue gas dew point, whereas a wet scrubber operates below the dew point and therefore requires rubber lining or stainless steel. However, the operating costs of a dry scrubber are higher, because of the four to five times higher cost for lime reagent compared to limestone. Spray dryer systems are simpler and easier to operate and maintain than wet scrubbers. A 200-MWe PC plant equipped with spray dry scrubber Figure 4.9 shows a 200-MW subcritical PC plant equipped with a spray dry scrubber for SO2 removal. The reduction in SO2 emission achieved can be seen by comparison with Figure 3.6. Figure 4.9: 200-MW, subcritical PC plant equipped with spray dry scrubber for S02 removal lime: 5.2 t/h Coal: 80 t/h spray dry 200 Mwe scrubber SO2: 0.6 t/h NOx: 0.6 t/h Bottom ash: 3 thDust: 30 t/h* CO2: 220 t/h Note: Data used -- plant efficiency = 37%, sulfur content, S= 2%, ash content = 32.8%. *No dust removal equipment. Chapter 4. S02 Emission Control Technologies 56 Screening criteria Table 4.3 is used for technology screening in Chapter 9. Table 4.3: Screening criteria for spray dry scrubbers Maturity of technology * Commercial for low sulfur coals in Europe, Japan and the United states. One reference plant in the Sichuan province in China. No reference plant in India. Maximum unit size * One scrubber can be used for boilers up to 200-MWe. For greater boiler, several scrubbers are installed in parallel. Waste product * Not possible to use. WET SCRUBBERS/WET FLUE GAS DESULFURIZATION Wet scrubbers or wet flue gas desulfurization (FGD) have 85% of the market for processes capable of removing S02 from flue gases in thermal power plants. Wet scrubbers include a large number of processes based on gas/liquid reactions which occur when the sorbent is sprayed over the flue gas in an absorber. The sulfur oxides in the flue gas react with the sorbent and form a wet by-product. The wet lime/limestone process is the single most popular wet scrubber process having a market share of 70%. In most industrialized countries wet scrubbing is a well-established process for removing S02. Suitability Wet scrubbing is the technology of choice for new and retrofit applications that require more than 80-90% SO2 removal. The investment is higher than for sorbent injection systems and spray dry scrubbers, but due to the lower sorbent demand they are more cost-effective than sorbent injection systems and spray dry scrubbers for coals with high sulfur content and for large boilers. The drawback relative to sorbent injection is that wet FGD systems require a larger surface area. There is a lot of chemistry involved in a wet scrubbing process. Chemical engineers, chemical laboratories and revised O&M procedures will be needed in order to achieve a properly functioning plant with both minimal emissions and material corrosion. Since there are only a few installations in China and India, demonstration and adaptation may be required for Indian and Chinese coals. As the wet scrubbing process is sensitive to high fly ash inlet concentrations, high efficiency, reliable precipitators, well adapted to Indian and Chinese coals, will be needed for successful wet scrubbing operation (Ref 5). A Planner's Guide for Selecting Clean-Coal Technologies for Power Plants 57 State of technology Wet scrubbing is by far the most proven and commercially established SO2 removal process. In 1994, there were 136 GW of installed electrical capacity worldwide (Ref 6). Eighty percent of installed FGD systems are wet scrubbers. The wet lime/limestone scrubber process alone has a market share of 70%. China has only one large-scale wet scrubber in commercial operation. In the Luohuang power plant (2x360 MW) in Sichuan province, the Huaneng International Power Development Corporation (HIPDC) has installed two limestone/lime-gypsum wet scrubbers. The equipment was manufactured by Mitsubishi Heavy Industries (Ref 2). The fuel is 3.5-5% sulfur coal, and the efficiency of the FGD is 95% (Ref 7). India has one wet scrubber in the Trombay plant, operated by the Tata Electric Company (TEC) in Bombay. This uses sea water to scrub the flue gas (Ref 1). In this process, the natural alkalinity of sea water is used to absorb S02 from the flue gas under formation of sulfate ions, which is a natural constituent of sea water. After neutralization with sea water from the cooling water heat exchanger, the effluent is discharged into the sea. The unit is installed in a 500-MWe boiler which can operate on coal, oil or gas. The coal sulfur content is 0.35%. The name of the process is Flakt Hydro and the technology was supplied by ABB Environmental, Norsk Viftefabrikk. The engineering and manufacturing was carried out in India, largely with domestic components. Less than 20% of the components were imported. Operation started in 1988. Two thirds of the flue gas flow from the boiler is treated in the scrubber. The plant operates with a removal efficiency of 85- 87%, and its availability has been higher than that of the boiler. The sea water scrubbing process has the advantage of design simplicity. No sorbent is needed. There is no waste disposal cost and it has low capital and operating costs. A disadvantage is that the pollution is transferred to the sea which in the long run will lead to contamination. However, monitoring to date indicates that no harm has been caused to marine life (Ref 8). Plant size Wet FGD installations are available for all boiler sizes. In large plants two lines can be used. Fuel flexibility The fuel flexibility is high. The technology has a high sulfur removal efficiency and is suitable for both high and low sulfur coal qualities. The presence of chlorine in the coal enhances the SO2 removal or reduces the sorbent need at constant removal level. The choice of coal affects the quality of the gypsum by-product. Changes in coal quality in an existing plant can affect the gypsum quality. Installation of a prescrubber upstream from the absorber improves the gypsum quality and makes the system less sensitive to changes in ash characteristics. Chapter 4. SO2 Emission Control Technologies 58 Performance Efficiency The sulfur removal efficiency is very high. The removal efficiency can be improved still further by the use of additives. These performance levels have been proven for both high and low sulfur coals in many commercial applications: * Efficiency without additives: 80-90% SO2 removal. * Efficiency with additives: 95-99% S02 removal. Power consumption Approximately 1.0-1.5% of a unit's total generating capacity is consumed by the scrubber. Sorbent Both lime and limestone can be used, but limestone is the most popular sorbent mainly because it is cheaper than lime. Additives such as magnesium or adipic acid are sometimes used to improve removal efficiency or to reduce sorbent to sulfur ratio for a given efficiency. In a new installation, a reduced sorbent need significantly reduces the size of the scrubber and the sorbent handling system. This decreases the investment cost. Waste production Wet lime/limestone scrubber systems produce either commercial grade gypsum, gypsum slurry or stabilizate as by-product. The favored wet limestone scrubbing process is the one producing commercial grade gypsum. Calcium sulfite produced during flue gas scrubbing is oxidized to calcium sulfate bihydrate, gypsum, either in the scrubber or in a separate vessel. The gypsum slurry is washed and dewatered to produce commercial grade gypsum containing less than 10% water. A bleed stream from the process is required to ensure a high quality gypsum. The bleed stream is led to a wastewater treatment plant. Coal quality and ESP performance have a large impact on gypsum quality. In some applications, a prescrubber is installed upstream from the absorber to improve gypsum quality and ensure a constant quality. When gypsum slurry or stabilizate are chosen as final by-products from wet scrubbers, the need for dewatering and washing of the by-products is reduced. The water content in the gypsum slurry from the scrubber is approximately 50%. When a gypsum slurry is the final by-product, the slurry is pounded. After settling in the gypsum slurry pond, water should be recycled to the scrubber system. Fixation of the slurry can be done by adding fly ash and/or lime. The resulting by-product is a stabilizate with a low permeability coefficient. When stabilizate is produced, no wastewater is produced. Utilization of the by-products is further described in Chapter 7. Availability The wet FGD process can be designed for availability up to 99.9%, but the availability depends not only on design but also on the sulfur content of the coal and the availability of spare parts. The availability for existing installations has increased considerably over the years with increased A Planner's Guide for Selecting Clean-Coal Technologies for Power Plants 59 experience and knowledge about operation and maintenance of the FGD process. New scrubber installations normally have an availability between 98 and 100%. Construction issues Construction time * Retrofit: 3 to 6 weeks of outage to connect the FGD with the boiler piping. * New plant: Scrubbers don't affect the construction time of a new coal fired plant. Area requirements A wet FGD plant requires a relatively large area which may be a problem in retrofit applications. For example, a wet FGD plant with a flue gas volume flow of approximately 1,050 Nm3/h has an area requirement of approximately 2,000 m2 (sulfur content 2.5%, requirement on SO2 max. 350 mg/Nm3, dry 6% 02). Possibilities for local manufacturing, licensing agreements Chinese manufacturers have not yet manufactured wet scrubbers for coal-fired power plant applications and there are no licensing agreements between Chinese and international manufacturers (Ref 2). However, if the market so requires, technology will be transferred and it will be possible to manufacture wet FGD systems in China in the future. Since the sulfur content in Indian coals is very low (<1%), the demand for wet scrubbers is low. With an increasing demand for wet scrubbers, license agreements between international suppliers and Indian manufacturers can be developed, so that local manufacturing can take place. Even now parts of the wet FGD equipment can be manufactured locally if the design is undertaken by an international supplier. Complexity of technology and design If the equipment exposed to corrosive media is rubber lined, additional skills are required for maintenance and construction of the rubber lining: alternatively, stainless steel can be used. Since complex chemistry is involved, wet scrubbers require revised O&M routines and skilled personnel in chemical engineering. Costs The investment cost and the total cost for SO2 removal depends on a number of site-specific technical conditions such as plant size, sulfur content of the coal, residual lifetime of the plant, etc. and on certain economic criteria chosen for the project, such as discount rate and estimated annual inflation. Other factors which influence the cost are the choice of FGD process and the type of by-product. Chapter 4. SO2 Emission Control Technologies 60 Investment Generally, investment costs have gone down over the years due to simplification of the design and improvements in the FGD process. Therefore, advanced wet limestone FGD processes can often be more cost-effective than conventional wet scrubbers. The capital cost for a 300-MWe unit typically ranges from 160 to 240 USD/kW, for 90-95% SO2 removal, depending on the type of process. The influence of plant size on the investment cost is shown in Figure 4.10. The capital cost per kWe installed decreases with increased plant size up to around 300-400 MW where the curve flattens. The retrofit cost is approximately 30% higher than the cost of installing a scrubber on a new plant. Figure 4.10: Investment for a wet FGD plant depending on plant size 260 u) 200- 0 i150- 100- 100 200 300 400 500 Plant size, MWe Source: lEA (1995). The investment cost for the FGD plant does not depend as much on the sulfur content of the coal as on boiler size. The boiler size and the flue gas flow determine the scrubber size. The only parts of the total process that depend on the sulfur content are the sorbent and waste product handling equipment. To maintain the same emission level when the sulfur amount in the coal increases from 1 to 2%, the investment cost increases approximately 10% as shown in Figure 4.11. Figure 4.11 Investment cost variation as a function of sulfur content in the coal Marginal Cost for Wet FGD I, 12 0 1,08 1,06 1,04- 1,02 1 1,5 2 Sulfur Content, % Source: Holme and Damell (1996). A Planner's Guide for Selecting Clean-Coal Technologies for Power Plants 61 Operation and maintenance costs The variable O&M cost is highly dependent on the sulfur content. The amount of sorbent needed to reach a specific emission level is always proportional to the sulfur content. This means that if the sulfur content is doubled, the amount of sorbent required to reach the desired emission level is approximately doubled. Table 4.4 shows typical O&M costs for wet FGD installations. Table 4.4 O&M costs for wet FGD plants Variable O&M Fixed O&M 0.15-0.20 UScents/kWh 12 - 13 USD/kW per year Source: lEA (1995). Levelized costs in USD per ton of S02 removed typically range from 280 USD/ton for a 600- MW, plant firing high (4.5%) sulfur coal to around 500-630 USD/ton for a 300-MW. plant firing a medium (2.6%) sulfur coal. If there is a market for the by-product, income from by-product sales can reduce the levelized cost considerably. A 200-MW PC plant equipped with wet scrubber Figure 4.12 shows a 200-MWe subcritical PC plant equipped with a wet scrubber for SO2 removal. The reduction in SO2 emission achieved can be seen by comparison with Figure 3.6. Figure 4.12 A 200-NWe subcritical PC plant equipped with wet scrubber for SO2 removal limestone: 5 t/h Coal: 80 t/h 4 Vv wet 200 MWeFG SO2: 0.3 t/h NOx: 0.6 t/h Bottom ash: 2.6 t/h Gypsum: Dust: 24 t/h* C02: 220 t/h Note: Data used -- plant efficiency 37%, sulfur content, S= 2%, ash content = 32.8 %. *No dust removal equipment Chapter 4. SO2 Emission Control Technologies 62 Screening criteria Table 4.5 is used for technology screening in Chapter 9. Table 4.5: Screening criteria for wet FGD Maturity of technology * Commercial in Europe, USA, Japan. One wet limestone/lime reference plant in China and one sea water scrubber plant in India. Maximum unit size * Suitable for any boiler size. Waste product * Possible to use without processing. COMBINED SO2 / NOx CONTROL There are a number of processes for combined SO2/NO. removal which have the potential to reduce SO2 and NO. emissions simultaneously at a lower cost than the total cost for conventional FGD and SCR. The processes can be divided into the following categories: * solid adsorption/regeneration, * gas/solid catalytic operation, * electron beam irradiation, * duct alkali injection, and * wet scrubbing. At present, combined SO2/NO. removal processes are generally considered to be too complex and expensive to be used in developing countries. They will need to be demonstrated and commercialized before they are suitable. This could take some 5 to 10 years. However, looking at emission removal from the point of view of the positive perspective of the production of useable by-products, an advanced SO2/NOx removal plant can be seen as a chemical factory producing useful goods such as gypsum, sulfuric acid, elemental sulfur or fertilizer, all goods that may be in short supply in developing countries. Therefore, despite the high capital costs and in many cases unproven technology, advanced combined SO2/NOx removal can, under some circumstances, be considered suitable in developing countries for large power stations burning high sulfur coal. These new processes aim at achieving higher efficiencies compared with conventional FGD and SCR. The reported efficiencies are 95-99% SO2 removal and more than 90% NO. removal. Most combined SO2/NOx processes are still only at laboratory scale or in the developmental stage. Only a few processes for low sulfur coals are in commercial operation. These include activated carbon, WSA-SNOX, DESONOX, and duct sorbent injection. The main features of these four processes are listed in Table 4.6. As a result of the limited commercial experience, there is still little information available on the costs of the processes. It is believed that they require higher capital and levelized costs than A Planner's Guide for Selecting Clean-Coal Technologies for Power Plants 63 conventional or advanced FGD in combination with SCR. Reported actual and estimated capital costs range from 190 to 625 USD/kW. Levelized costs range 0.35-2.0 UScents/kWh (Ref. 6). Table 4.6: Comparison of commercial combined SO/NOx control processes Process/ Features Removal Process Type rates SO2 /NOx Activated Activated carbon adsorbs SO2, and sulfuric acid or elemental sulfur is carbonl produced. Simultaneous NOx removal by addition of ammonia. Commercial 98/80 solid adsorption/ operation in 1 power plant in Japan and 2 in Germany. Largest unit 350 MWe, regeneration total 664 MWe. High removal of S03, hydrocarbons, heavy metals and other toxic material. No wastewater is produced. WSA-SNOX/ Two catalysts are used to remove NOx by SCR and to oxidize S02 to SO3. gas/solid catalytic The latter is condensed to sulfuric acid. One commercial installation in a 300- >95/95 operation MWe plant in Denmark and one 30-MW unit in Italy. No wastewater or waste products are produced, and no chemical other than ammonia is consumed. Very low energy consumption. No NH3 slip. DESONOXI Similar to WSA-SNOX in that two sequential catalysts are used to reduce gas/solid catalytic NOx and to oxidize SO2 to S03. 2 units in commercial operation: 98 + 31 90/90 operation MWe at Hafen, Munster in Germany. High removal of HCI and HF Duct sorbent Pulverized sodium bicarbonate is injected into the duct after the economizer injection/ but before the ESP. Sodium sulfate is produced and collected with the fly ash. <90/<40 alkali injection 8 commercial installations on coal fired plants, all in the USA. The largest is Monticello 575 MWe. Source: Holme and DameI (1996). REFERENCES 1. Mathur, Ajay. 1996 (May, Sept). Personal communication. Dean, Energy Engineering & Technology Division, TERI. New Delhi, India. 2. Li, Zhang. 1996 (April, Sept.). Personal communication. Hunan Electric Power Design Institute. Changsha, China. 3. Takeshita, Mitsusu. 1995. Air Pollution Control Costs for Coal-fired Power Stations. IEA Coal Research, IEAPER/17. International Energy Agency. London, UK. 4. Porle, K., S. Bengtsson. 1996 (May). Personal communication. ABB Flakt. 5. Holme, V. and P. Darnell. 1996 (May). FLS Milj6 a/s, Personal communication. 6. Takeshita, M. and H. Soud. 1993. FGD Performance and Experience on Coal-Fired Power Stations. IEA Coal Research, IEACR/58. International Energy Agency. London, UK. Chapter 4. SO2 Emission Control Technologies 64 7. Coal Industry Advisory Board. 1995. "Report from China Committee." Presented at WEC, Tokyo. September 1995. IEA Coal Research. International Energy Agency. London., UK. 8. Soud, H. and M. Takeshita. 1994. FGD Handbook. IEA Coal Research, IEACR/65. International Energy Agency. London, UK. 9. Smith, I. 1996 (May). Personal communication. IEA Coal Research. International Energy Agency. London, UK. A Planner's Guide for Selecting Clean-Coal Technologies for Power Plants 5. NOx EMISSION CONTROL TECHNOLOGIES The first step in any NO, emission reduction strategy is to optimize plant operation. Operational changes should be made prior to implementation of any NO. reduction technology or installation of additional equipment. For example, low excess air and boiler fine tuning can be regarded as methods of reducing NO, formation significantly at little or no extra cost. Both methods are easy to implement and require no boiler modifications. Minimizing excess air may also lead to increased boiler efficiency. This is discussed further in Chapter 8, Instrumentation and Control Systems (page 110). As every boiler is more or less unique, each must be tested to find the optimum level of excess air at which the boiler can be operated without risking corrosion or high rates of unburned coal. Upgrading or replacing coal pulverizers to maintain coal fineness, and balancing fuel and air flows to the various burners to create a staged combustion are other low cost routes to the reduction of NOx emissions. The staged combustion is accomplished by withdrawing a portion of the total air required to achieve complete combustion from the early stage of combustion in order to create a combustion zone with lack of oxygen, which oppresses the NO, formation. The air is added-in at a later burner stage to ensure complete combustion. The NOx emission reductions which can be achieved by these methods may not be sufficient to reach the required emission level, but they are extremely cost-effective. These methods can also be combined with other low-cost modifications. Optimizing operational performance should not only involve individual component elements. The entire fuel preparation and furnace system must be optimized if NOx formation is to be effectively minimized. A reliable system for continuous monitoring of 02 and NOx concentrations in the flue gas can assist in defining the optimum operational parameters. After optimizing plant operation, in-furnace NO_ reducing equipment should be applied on PC boilers. In-furnace NOx reducing equipment involves modification of the combustion process, e.g. low NOx burners (LNB), OFA, flue gas recirculation and gas or coal reburning. After this type of in-furnace NOx control has been implemented, post-combustion measures must be installed to reduce NOx emissions further. Post-combustion NO. removal equipment includes: selective non catalytic NOx reduction, selective catalytic reduction, and combined SO2/NOx removal. Such methods are the only available options for reduction of NOx emissions from fluidized bed boilers, however, uncontrolled NO, emissions tend to be quite low from fluidized bed boilers. This chapter presents basic information to enable selection between different NOx reduction technologies. Figure 5.1 shows estimated levelized costs per kWh of electricity produced for various removal efficiencies (Ref. 3). The figure shows that combustion modifications such as LNB and OFA give the lowest increase in production cost but they can only reduce the emissions up to 60%. SCR is the most efficient way to reduce NOx emissions, but it is also the most expensive technology. Combustion modifications require a lower capital cost than SCR, and they 65 66 have very low, if any, O&M costs. The variable O&M cost for SCR represents up to 50% of the total levelized cost. Figure 5.1. Levelized costs in UScents/kWh electdcity for different NOx reduction technologies OFA LNB+OFA SCA 1 I I- 0.70 0.60 - 0.50 - NOx o40 0- 0 OAO- 0.30 - _J 0.20- 0.10 - 0 0 10 20 30 40 50 60 70 80 90 100 Removal efficiency. % Source: Takeshita (1955). Low NOx COMBUSTION TECHNOLOGIES Low NO, combustion modifications include LNB, OFA, flue gas recirculation and gas or coal reburning. These measures can be implemented on PC-boilers to reduce NOx emissions. In low NOx burners, air staging is achieved within the flame to prevent NOx formation. Today, almost all boiler and burner manufacturers supply low NOx burners, and they are routinely installed in new boilers. OFA is a type of air staging in which a portion, typically 10-30%, of the combustion air is withdrawn from the combustion zone. This stream of air is added through special OFA ports situated higher up in the furnace to complete combustion. Reburning is another name for fuel staging. A portion of fuel is injected in a second combustion zone, the reburning zone, situated over the primary combustion zone in the furnace. The reburning fuel can be a portion of the primary coal fuel or another type of fuel such as natural gas or oil. A Planner's Guide for Selecting Clean-Coal Technologies for Power Plants 67 Suitability Low NO. burner technologies are very suitable for developing countries due to their low investment cost compared to other more efficient techniques. Minor adaptations may be required for Chinese and Indian coals. New boilers should be equipped with low NOx burners and OFA. The use of low NOx burners and the installation of OFA will hardly affect the cost of new boilers. If a new boiler is not equipped with OFA, the boiler should still be designed for future installation of OFA. Different low NO. combustion measures can be used in combination to reduce NO, emissions. LNB, for example, are commonly used in combination with OFA. These methods are also suitable to use in combination with other NOx control technologies. Reburning is an attractive option where natural gas is available at the power plant site and required NOx emissions are below 800 mg/Nm3. Reburning gives a NOx reduction in the same range as SNCR but gives no ammonia slip. LNB are not easily used on wet bottom boilers because the temperature in the furnace changes, which may cause problems with slag drainage. For such boilers, natural gas reburning may be the only available NOx control technology. Due to their low capital cost, low NO. combustion measures are suitable for retrofit of old boilers with a limited remaining lifetime. However, in retrofit applications these techniques may lead to unwanted changes in the boiler operation. Combustion efficiency can decrease due to a higher level of unburned carbon in the fly ash, and due to change in temperature profile in heat exchanging parts. Also, LNB with a higher pressure drop and flue gas recirculation consume more power for the flue gas fans, which reduces the plant efficiency. Operating with low excess air, LNB and OFA create zones with reducing atmosphere, which may cause corrosion on the boiler tubes. Furthermore, there are often physical limitations for installation of low NO, combustion measures on existing boilers, e.g. limited space around the furnace and duct, and limited area in the furnace for installation of OFA ports or burners for the reburning fuel. State of technology LNB and LNB plus OFA are being used commercially in Europe, Japan, and the United States. New PC boilers in industrialized countries all use low NO. burners, and retrofits of old boilers are common. Reburning using a separate reburning fuel on coal-fired boilers is only in commercial operation in the USA. The technique is in the large-scale test and demonstration stage. Reburning using fine pulverized coal as reburning fuel is in commercial operation in the Federal Republic of Germany. In India typical burners for coal-fired power plants are designed for NOx emissions of 600 ppm. However, burners with NO, emissions less than 400 ppm have been introduced recently (Ref 1). In China, more than 20% of the power plants use some type of low NO. combustion technology; low NOx burners are the most common. Some plants have a simplified form of OFA installation, in which the exhaust air from the coal pulverizing system is injected into the furnace above the primary air. A technology similar to SGR burners is used for retrofitting boilers in old power plants. This technology has lower NOx emissions than conventional burners (Ref 2). Chapter 5. NO, Emission Control Technologies 68 Fuel flexibility The content of nitrogen and volatiles in the coal is highly significant when choosing low NO. combustion technology. As most combustion modifications aim at suppressing thermal NO. formation, it is difficult to achieve low NO, emissions through combustion measures with coals with a high nitrogen content. For low volatile coals and anthracite, special low NOx burners have been developed. As reducing conditions are created in the combustion zone with low NO. technologies, coals with high sulfur or chlorine content may cause problems with corrosion. A high iron content can also cause problems in low NO. combustion applications. Plant size Combustion modifications are suitable for all plant sizes, but the most suitable choice of modification depends on boiler type and size. The total investment cost for installation of low NOx burners, for example, depends largely on boiler size, whereas the investment cost for installation of OFA can be considered independently from boiler size. Performance Efficiency Reduction efficiencies typically achieved by different combustion modifications are listed in Table 5.1. The efficiency achieved when retrofitting an existing plant is generally lower than that of a new plant because of plant specific limitations. Table 5.1 NOx reduction efficiency for various technologies Measure NOx reduction low excess air 15-25 flue gas recirculation 15 - 20 OFA 12-250 LNB 30-55 LNB + OFA 30-55 Natural gas reburning 45 - 60 Source: Takeshita (1995). Low excess air and flue gas recirculation achieve NOx reduction levels only up to around 20% as stand alone measures, but the techniques are often used in combination with other primary measures such as OFA or reburning to achieve higher removal efficiencies. Effect on load regulation When introducing combustion modifications in an existing boiler, it is important to avoid negative impact on the operational safety. Calculations must be made before to ensure that stable ignition can be secured over the whole load range. A Planner's Guide for Selecting Clean-Coal Technologies for Power Plants 69 The use of low NO. burners can cause decreased flame stability at reduced loads, which may limit the boiler minimum load. On the other hand, new Mitsubishi SGR burners or similar local technologies which are installed in many old power plant boilers in China in order to stabilize the low load flame have lower NOx emissions than conventional burners (Ref. 2). The NO,, emissions are more independent of the load in a boiler with combustion modifications than is the case in a conventional boiler. Reagent None Availability Very high availability (98-99%). Low NOx combustion measures do not affect the availability of the boiler and they do not require any extra overhaul time. Construction issues Construction time Low NO,, combustion measures do not require any extra construction time for a new plant. The estimated outage times for retrofit of LNB, OFA and natural gas reburning are in Table 5.2. Table 5.2. Outage time for retrofit for various NOx reduction technologies Measure Outage time for retrofit (weeks) LNB 3-5 LNB + OFA 4-9 Natural gas rebuming 5 - 10 Source: Tavoulareas (1995). The possibilities for local manufacturing, licensing agreements In India, one manufacturer, BHEL, offers burners with NO,, emissions less than 400 ppm. These burners are developed by BHEL; and there are no international license agreements (Ref. 1). Low NO, burners and the simplified form of OFA installation mentioned in section 5.2.1 can be manufactured in China. There is no license agreement between any Chinese manufacturer and international manufacturers, but one Chinese boiler manufacturer, the Dongfang boiler plant, cooperates with Foster Wheeler and imports their low NO. burners (Ref. 2). Area requirements For new plants, combustion measures for low NO,. operation require no additional space. Installation of low NOx burners on an existing boiler requires no extra space. Introduction of OFA and reburning on an existing boiler requires available area over the burners in the furnace for installation of OFA ports and additional burners for the reburning fuel. It also requires appropriate space around the boiler and duct for OFA air tubes. Chapter 5. NO, Emission Control Technologies 70 Costs The investment cost for combustion modifications depends on technology, boiler size and type and space available for retrofit. An overview of capital costs for retrofit installations is presented in Table 5.3. For OFA installation, the total capital cost is relatively independent of boiler size. Therefore, small boilers require a much higher capital cost per kW, for OFA installation than large boilers. For low NOx burners the total capital cost is highly dependent on boiler size, but the lowest specific capital costs occur in large sized plants due to the economies of scale. Capital costs for reburning are somewhat higher than those of low NO, burners combined with OFA. Reburning with natural gas is less costly to install than reburning with pulverized coal. Table 5.3 Investment costs for retrofit installation of NOx reduction technologies Technology Capital Costs (USD/kW} Boiler size, MW, >300 <300 OFA 7-9 30-40 LNB 10-40 20-45 LNB + OFA 8-30 30-40 Natural gas rebuming 14-30 35-45 Source: Takeshita (1995). Capital costs for equipping new boilers with LNB or OFA are very low, around 1-3 USD/kW. The capital cost for natural gas reburning on new boilers are in the 10-30 USD/kW range. The O&M costs for OFA and low NO, burners are very low and are the same as for boilers with conventional burners. The operating cost for natural gas reburning is higher due to the higher cost of the natural gas fuel compared to coal. Reburning with pulverized coal instead of natural gas has significantly lower operating cost and a lower levelized cost in UScents/kWh despite the higher capital cost (Ref. 3). The cost effectiveness of the different combustion modifications depends largely on the type of boiler and its uncontrolled NO, emissions. Modifications to boilers with high uncontrolled emissions, e.g. wall-fired wet bottom boilers or cyclone boilers, are more cost-effective than modifications to boilers with lower NOx emissions such as tangentially fired boilers. This is illustrated in Table 5.3, which lists typical ranges of cost effectiveness in USD/ton of NO, removed of combustion modifications on wall fired and tangentially fired boilers (Ref. 3). Table 5.3: Cost efficiency for NOx reduction technologies Type of boiler Wall fired Tangential fired modification USO/t NO, USD/t NOx OFA 440 LNB 175-250 540-700 LNB + OFA 300 -450 460-900 Natural gas rebuming 780 - 960 1,200 - 1,800 Source: Takeshita (1995). A Planner's Guide for Selecting Clean-Coal Technologies for Power Plants 71 The coal-to-natural gas price difference has a major impact on the cost-effectiveness of natural gas reburning. An increase in price difference by 50%, increases the NO. removal cost by nearly 50%. The use of LNB and OFA in a 200-MW, PC plant Figure 5.2 shows a 200-MW, subcritical PC plant using LNB and OFA. The reduction in NO. emission achieved can be seen by comparison with Figure 3.6. Figure 5.2 200-MW, subcritical PC plant using LNB and OFA Coal: 80 t/h 200 MWeM LNB + OFA SO2: 3.2 t/h Bottom ash: 2.6 t/h NOx: 0.4 t/h Dust: 24 t/h CO2: 220 t/h Note:: Data used -- plant efficiency = 37%, sulfur content, S= 2%, ash content = 32.8 %. Screening criteria Table 5.4 is to be used for technology screening as in Chapter 9. Table 5.4: Screening criteria for low NOx combustion technologies Maturity of technology * Low NOx burners are commercial in India and PR China. OFA installations are commercial in Europe, Japan and the US. Rebuming is in commercial operation in Unit size * all plant sizes Waste product * none Chapter 5. NO, Emission Control Technologies 72 SELECTIVE NON-CATALYTIC REDUCTION In a selective non-catalytic reduction system, ammonia or urea is injected into the high- temperature zones of the boiler to reduce formed NOx to nitrogen and water without the use of a downstream catalyst. The temperature window for efficient operation occurs between 900 and 1,1000C. At higher temperatures, ammonia decomposes to N2, and at lower temperatures, the rate of the reaction between ammonia and NO, is slow and a high ammonia slip occurs, (i.e. the release of unreacted ammonia). Suitability SNCR is suitable when reduction rates up to 50% is sufficient, for example, when NOx reduction above what is achieved by low NO. burners and other combustion modifications is required. The process is also suitable for use in combination with combustion modifications to reach higher NO, removal levels. SNCR is also suitable for fluidized bed boilers, where the combustion conditions already result in low NOx emissions and the need for further NOx reduction is limited. The higher ammonia slip from SNCR, that results in ammonia contamination of the fly ash, can be acceptable in the case of fluidized bed boilers since the by-products are generally disposed of The performance depends, to a high degree, on boiler-specific conditions such as the mixing conditions of the reagent and the flue gas temperature and residence time. Because of the low NO, reduction and the difficulty of maintaining the NOx reduction over the whole range of boiler load, SNCR is not often used in large coal-fired boilers. State of technology The technology has been demonstrated in 15 utility-scale boilers in the United States and Europe. Commercial operation has started during the past few years in several countries, but most SNCR installations in commercial operation are in small boilers and in fluidized bed boilers. Experience of SNCR in large coal-fired plants is limited. In Europe, four large coal-fired plants have been equipped with SNCR. Today there are no SNCR installations in India or China. SNCR is under research in some combustion research institutes in China. A number of technical issues remain to be solved, the major concern being the ammonia slip which is much higher for SNCR than for SCR. A high ammonia slip leads to ammonia contamination of the ash which reduces the possibility of selling the fly ash. There is also a risk of the formation of ammonium bisulfate from unreacted ammonia and SO3 in the flue gas, and deposition and plugging of ammonium bisulfate on the air heater baskets. A further issue is the increased generation of N20, which is an ozone depleting greenhouse gas. Fuel flexibility For high sulfur coals, there is a potential risk of reaction between the unreacted ammonia and SO3 in the flue gas to form ammonium bisulfate. The ammonium bisulfate can precipitate onto and cause plugging of the air heater. A Planner's Guide for Selecting Clean-Coal Technologies for Power Plants 73 Plant size Most SNCR installations in commercial operation are in small boilers and fluidized bed boilers. Experience with SNCR in large plants is limited, although commercial SNCR installations in coal- fired plants up to 500 MW, do exist. Performance Efficiency The reduction efficiency depends on many site-specific conditions. NO. reduction efficiencies normally range from 30 to 70%, but reduction levels up to and over 80% have been reported. If SNCR is used in combination with low NO, combustion modifications, NOx emissions reduction levels, comparable to those of SCR as a stand alone measure, can be achieved. Effect on load regulation The physical position of the suitable temperature window in the furnace for reagent injection shifts with the boiler load. Therefore, it can be difficult to find reagent entry areas where the No. reduction efficiency is maintained over the whole boiler load without increasing the ammonia slip. Reagent Urea or ammonia, concentrated or in a 25% water solution, is used as the reagent, normally in a stoichiometric ratio of around 2. In some plants, the use of urea as the reagent has resulted in increased N20 emissions. Construction issues Construction time For a new plant, the installation of an SNCR system does not affect the construction time. In retrofit installation, an outage of two to five weeks can be expected. The possibilities for local manufacturing, licensing agreements There is no SNCR manufacturer in China or India today. There are no license agreements between Chinese or Indian manufacturers and international manufacturers. Area requirements The process itself has no area requirement, but some space is required for storage of reagent. Costs Investment Capital costs for SNCR are generally much lower than those of SCR as no catalyst is used. For boiler sizes of 100-500 MW, capital costs fall in the range of 10-25 USD/kW (Ref 3). The specific capital cost per kW depends highly on boiler size. For larger boiler sizes the capital cost decreases rapidly due to economies of scale and fall in the lower cost range. However, today there is still only limited experience of SNCR installations in large plants. For small boilers the costs fall Chapter 5. NOx Emission Control Technologies 74 in the upper range. The cost also depends on whether it is a new plant or a retrofit. The cost for retrofit installation is higher and will fall in the upper cost range. Operation & maintenance O&M costs are highly dependent on the cost of the reagent due to the high rate of consumption. Normally they range from 0.1-0.2 UScent/kWh (Ref. 5). Contamination of the fly ash by ammonia can reduce the possibility of selling the fly ash; instead there will be a cost for fly ash landfill. Also, a high ammonia slip can cause plugging and corrosion problems on the air heater, resulting in lower boiler availability which has a negative effect on the O&M costs. Levelized costs for 50% reduction at a urea price of 300 USD/ton have been estimated to range from 0.2 UScents/kWh or 1,100 USD/ton NO. removed for a 100-MW unit to 0.15 UScents/kWh or 900 USD/ton NO, removed for a 500-MW unit (Ref 3). At higher reagent costs the levelized cost increases. If a lower reduction is sufficient, the levelized cost decreases as a result of lower reagent consumption. The use of SNCR in a 200-MW PC plant Figure 5.3 shows a 200-MW subcritical PC plant using SNCR. The reduction in NOx emission achieved can be seen by comparison with Figure 3.6. Figure 5.3 A 200-MW. subcritical PC plant using SNCR Coal: 80t/ 200 MWe 25% NH3: S02: 3.2 t/h 1.7 t/h NOx: 0.4 t/h Bottom ash: 2.6 t/h Dust: 24 t/h CO2: 220 t/h Note: Data are used -- plant efficiency = 37%, sulfur content, S= 2%, ash content = 32.6 %. A Planner's Guide for Selecting Clean-Coal Technologies for Power Plants 75 Screening criteria Table 5.5 is to be used for technology screening according to Chapter 9. Table 5.5: Screening criteria for SNCR Maturity of technology * SNCR is used commercially in coal fired plants in Western Europe and in the USA. There are no SNCR installations in India or China. In China SNCR is being researched. Unit size * all plant sizes Waste product * none SELECTIVE CATALYTIC REDUCTION In the SCR process, the NOx in the flue gas is reduced by the addition of ammonia in the presence of a catalyst. The SCR reactor can be placed in three different locations: * high dust - at the outlet of the economizer before the ESP, * low dust - after the ESP before the air preheater, or * tail end - after the particulate filter and the FGD system. Suitability SCR is suitable for use in developing countries when combustion modifications are not sufficient to meet the emission limits. It is suitable for coal-fired power plants when the required NOx emission limits are less than 100 ppm, and 80 to 90% NOx reduction is required, for example in power plants located in heavily populated areas. Technology demonstration and some adaptation may be required in the case of possible use with high sulfur and high ash coal types. Installation of a high dust SCR system in an existing boiler requires extensive modification of the boiler backpass. Lack of available space for retrofitting is often a constraint. State of technology Since the mid-1960s more than 200 SCR units have been installed and are operating in coal-fired power stations with a total capacity of more than 65 GWe (Ref 3). SCR is mainly used in Austria, Germany and Japan when combustion modifications are not sufficient to meet stringent NO, requirements. The technology is not yet demonstrated in India or China. In China, research and small-scale tests are being carried out in combustion research institutes (Ref. 2). SCR is commercially available for low to medium sulfur coals (<1.5%), and the method has also been demonstrated for most types of coals on the free market. The high dust location type is the most widespread worldwide. The low dust location variant is used in some plants in Japan as it gives a greater fuel flexibility, but it requires expensive high- Chapter 5. NOx Emission Control Technologies 76 temperature ESP. The tail-end location type is used mainly in Germany and in retrofit cases where space is restricted, and for wet bottom boilers. The tail-end location requires a gas-reheater in order to reheat the flue gas after the FGD to the SCR operating temperature of 300-4000C. Fuel flexibility The SCR technology works best with low and medium sulfur coals with a low ash content. There is not much experience of SCR with high sulfur coals. The catalyst can be deactivated by high levels of arsenic. A high ash content can lead to erosion of the catalyst, but on the other hand, SCR may not be necessary for high ash coals as they tend to give lower NO. levels due to a lower flame temperature (Ref 4). A tail-end catalyst is more flexible when using different types of coals than is a high dust catalyst. Plant size SCR technology can be applied to a wide range of boiler sizes. In retrofit applications, however, space constraints may limit the physical size and capacity of the system. Performance Efficiency The NOx reduction efficiency of an SCR system depends on the NH3/NO. molar ratio and the catalyst volume. The efficiency for low to medium sulfur coals is usually 70-90% at a NH3/NOx molar ratio of 0.7-0.9 (Ref. 3). Similar NO. reduction is expected with high sulfur coals, but such performance has not been demonstrated in utility-scale boilers. The pressure drop over the catalyst is not negligible, which means that the overall plant efficiency decreases somewhat. Load regulation effects The SCR process can be operated in a wide-load range and at fluctuating load. Reagent Ammonia, concentrated or in aqueous solution, is used as the reagent. A 150-MW plant will consume approximately 250 lb/h (115 kg/h) of concentrated ammonia. Availability The availability of the catalyst is normally high due to its modular design. The SCR unit will not affect the yearly overhaul time for a plant. A Planner's Guide for Selecting Clean-Coal Technologies for Power Plants 77 Construction issues Construction time The SCR unit will not affect the construction time for a new plant. For retrofit applications the estimated outage times are (Ref 5): * high dust SCR retrofits: 2 to 3 months outage. * tail-end SCR retrofits: 3 to 6 weeks outage. The possibilities for local manufacturing, licensing agreements It is not possible to manufacture the SCR catalyst in India or China today (Refs. 1 and 2), and there is no license agreement between Chinese or Indian manufacturers and international manufacturers. Other parts of the SCR unit, other than the catalyst can be manufactured locally. Area requirements The area requirement is higher for SCR than for SNCR or low NOx combustion measures. In retrofit applications, space constraints may limit the physical size and capacity of the system. A tail-end catalyst location is used when available space in the boiler duct system is restricted. Costs Investment The cost for installation of SCR on a new plant is around 50-90 USD/kWe, and the cost for retrofit is 90-150 USD/kW, (Ref 3). Installing SCR on a new plant costs less than retrofitting an existing plant, because in existing plants, space is limited and retrofitting requires considerable modification of existing equipment such as air heater and fans. The investment cost depends on the required catalyst volume. Minimizing the catalyst volume is important in order to keep down investment as well as maintenance costs. The location of the SCR affects the capital cost considerably. A low dust location requires a high temperature ESP. A tail-end location requires a smaller catalyst than a hot side location since the dust load on the catalyst is lower in the tail-end position; but, in addition, it requires a gas-gas reheater with supplementary gas- or oil-firing in order to reheat the flue gas to SCR reaction temperature. Operation and maintenance O&M costs for SCR are expected to add 0.2 to 0.4 UScents/kWh, depending on the catalyst life (typically 5-7 years) and the catalyst cost, typically 16,000-20,000 USD/m' (Ref 3). Chapter 5. NO, Emission Control Technologies 78 A 200-MWe PC plant equipped with SCR Figure 5.4 shows a 200-MW. subcritical power plant using SCR. The reduction in NOx emission achieved can be seen by comparison with Figure 3.6. igure 5.4 200-MW, subcritical plant equipped with SCR NH3: 0.2 t/h SCR Coal: 80 t/h 4; v 7 + 200 MWe U SO2: 3.2 t/h Bottom ash: 2.6 t/h NOx: 0.1 t/h Dust: 24 t/h C02: 220 t/h Note: Data used - plant efficiency = 37%, sulfur content, S= 2%, ash content = 32.8 %. Screening criteria In Table 5.6 screening criteria will be used for technology screening in Section 9. Table 5.6: Screening criteria for the SCR technology Maturity of technology * Commercial in Europe and Japan but not in India or China. No reference plant in India or China. Unit size * Suitable. for any boiler size. Waste product * none A Planner's Guide for Selecting Clean-Coal Technologies for Power Plants 79 REFERENCES 1. Mathur, Ajay. 1996 (May). Personal communication. Dean, Energy Engineering & Technology Division, TERI. New Delhi, India. 2. Li, Zhang. 1996 (April). Personal communication. Hunan Electric Power Design Institute. Changsha, China. 3. Takeshita, Mitsusu. 1995. Air Pollution Control Costs for Coal-fired Power Stations. IEA Coal Research, IEAPER/17. International Energy Agency. London, UK. 4. Porle, K. and S. Bengtsson. 1996 (May). Personal communication. ABB Flakt. Vaxj, Sweden. 5. Tavoulareas, E. S. and J. P. Charpentier. 1995. Clean Coal Technologies for Developing Countries. World Bank Technical Paper Number 286. Washington, DC. Chapter 5. NOx Emission Control Technologies t 6. PARTICULATE EMISSION CONTROL TECHNOLOGIES There are two main types of particulate emission control technology: fabric filters (baghouse filters) and ESPs. Fabric filter technology is the most widely used particulate control device in industry, but ESPs is by far the most commonly used technology in power plants worldwide. Both technologies are capable of meeting very low emission limits. The choice of particulate control technology depends upon several site-specific conditions such as ash and fuel characteristics, environmental requirements and operational factors. The influence of an outlet emission limit and fly ash resistivity on the choice of particulate collector is illustrated in Figure 6.1. The figure shows the capital cost for different types filters per kW of electricity installed as a function of the particulate emission limit. The figure shows that ESPs require a lower capital cost than baghouse filters for particulate emission limits higher than 30 mg/M3 when firing coals with low fly ash resistivity (Ref 3). For coals with high fly ash resistivity, baghouse filters are more economical. Pulse jet baghouse filters have lower capital cost when stringent emission limits are required. Figure 6.1 Capital cost per kW electricity installed for ESPs and baghouse filters 130- 120- 110- ESP (high resisitivity coal) 100- go- reverse air baghouse \pulse jet baghouse 40 - (air to cloth ratio=4.0) 30- ESP (low resisitivity coal) 0 20 20 50 100 Particulate emission limits, mg/M3 Source: Sloat et al (1993). 81 82 Looking at the levelized cost gives a somewhat different picture. ESPs have a lower O&M cost than fabric filters because they have a lower pressure drop over the filter, and because fabric filters require an annual cost for bag replacement. The pulse-jet baghouse filters have the highest O&M cost of the three filter types. Figure 6.2 shows the levelized cost for the three filter types per kWh of electricity produced depending on the particulate emission limit (Ref 3). The figure shows that ESPs are competitive for low resistivity coals at the whole range of emission limits. They are also competitive for coals with medium to high fly ash resistivity at less stringent emission limits. When firing coals with high fly ash resistivity, baghouse filters gives a smaller increase in production cost. Figure 6.2: Levelized cost per kWh of electricity produced for ESPs and baghouse filters 0.56- 0.52- ~0.48- 3104 ESP (high resisitivity coal) 0.44 reverse air baghouse 00. 40 - (air to cloth rato=2.0) 0. 3 6 > 0.32 \pulse jet baghouse 0.28 (air to cloth ratio=4.0) 0.24 0 20 ESP (low resisitivity coal) 20 50 100 Particulate emission limits, mg/M3 Source: Sloat et al (1993). Another important aspect in the selection of particulate control equipment is the power consumption of the process. Despite the power consumption required by the ESPs in order to create the electric field, ESPs normally have a significantly lower total power consumption than fabric filters. This is because ESPs have a lower pressure drop than fabric filters, approximately 0.2-0.3 kPa versus 1-2 kPa, resulting in lower power consumption by the flue gas fans. The total power consumption of ESPs is approximately 60-70% of that of baghouses (Ref 6). ELECTROSTATIC PRECIPITATOR TECHNOLOGY The electrostatic precipitator is the single most used emission control equipment in thermal power plants. The principle of operation is based on the creation of an electrostatic field. Emitted particulates are charged when they pass through the electrostatic field and are attracted to the A Planner's Guide for Selecting Clean-Coal Technologies for Power Plants 83 electrodes, where they are collected. ESPs have a lower pressure drop than fabric filters and can operate at higher temperatures. They are relatively insensitive to disturbance. Suitability Electrostatic precipitators are competitive for medium and high sulfur coals with low to medium ash resistivity (<1,012 Ohm-cm). For these coals, they are suitable for particulate removal efficiencies up to above 99.5%. They have lower capital and levelized costs in this area than baghouse filters. They are also cost-effective for low sulfur coals and coals with a high fly ash resistivity when lower emissions are required. Due to their robust design, ESPs can normally endure tough conditions. This is an attractive characteristic when firing coals with a high ash content and with an erosive ash such as Indian coals (Ref 4). In cases where more than 99.5% collection efficiency is required, especially for low sulfur, high resistivity coals, reverse air or pulse-jet fabric filters are normally more cost-effective than ESPs. A number of options exist to enhance the performance of ESPs, especially suitable in developing countries. In India, the high volume, high ash resistivity coals place large demands on ESPs. Replacing existing ESP systems with new ones when environmental regulations become stricter will require a considerable capital investment. Therefore, improvements of existing ESPs may present a cost-effective option. When some clean coal technologies are used (specifically spray dryers, sorbent injection, and fluidized bed combustion) improvements of ESPs may be needed. If a market develops for such improved ESP features, supply should not be a problem. State of technology Electrostatic precipitators are commercially available worldwide and are installed in most coal fired power plants in China (Ref. 2). In India, all power plants greater than 100 MW are equipped with ESPs. The major Indian manufacturer of ESPs, BHEL, has developed an ESP technology that can achieve the required collection efficiency for the high resistivity, high volume ash of Indian coals. In several plants, ammonia injection systems have been installed upstream of the ESP to enhance conductivity and ESP clean-up efficiency (Ref. 1). Plant size Electrostatic precipitators have been operating for many years on coal-fired units with sizes up to and above 1,000-MW output. Fuel flexibility The quality of the coal has a great impact on the size and the cost of a new ESP. The most important parameter regarding coal quality is the fly ash electrical resistivity. A high content of alumina and silica (>95% of the ash) increases the precipitator area significantly as alumina and silica in the ash form an electrical insulator. A high sodium content has a positive effect as an electrical leader, resulting in a reduced precipitating area. Chapter 6. Particulate Emission Control Technologies 84 Switching from high to low sulfur coal may have a negative impact on the ESP performance. As low sulfur coals normally have higher fly ash resistivity, the existing ESPs may operate at reduced removal efficiency. Performance Efficiency Normally, ESP efficiency is above 99.5% for hard coal and higher for lignite. However, ESPs can be sized for extremely high efficiencies up to 99.99% with dust emissions as low as 5 mg/m'(n) guaranteed (Ref. 7). In India, ESPs in large plants typically have efficiencies greater than 99.7%. ESPs installed in smaller plants with boilers with a capacity of less than 200 MW located in rural areas have lower efficiencies, typically around 99.1%. Approximately 140 ESPs have an efficiency in the 99.5-99.8% range and the rest have efficiencies in the 99.0-99.2% range. At several units in India, an ammonia injection system has been added upstream of the ESP in order to enhance ESP conductivity and clean-up efficiency (Ref. 1). Many flue gas and ash characteristics have an impact on the ESP cleaning efficiency. Such flue gas characteristics include flue gas flow, temperature, concentration of unburned material and particulate content. Ash characteristics of special importance are electrical resistivity and sulfur content. The prediction of the impact of these characteristics is based more on experience than on theory. ESP manufacturers differ in their opinion regarding the influence of different parameters. There are several options for improving the performance of an existing ESP, if it is required by stricter environmental laws. Efficiency can be enhanced by increasing the size of the ESP and by wider plate spacing. Conditioning of the flue gas with moisture, SO3 or NH3 can have a positive impact on collection efficiency. Finally, increased efficiency can be achieved by replacing conventional DC-generators with high pulse-generators (Ref 7). The quality and status of the ash removal system has a major impact on the flue gas cleaning efficiency of an installed ESP. An ESP can never reach a high efficiency if the ash removal system is not functioning (Ref 4). Availability If the instructions of the manufacturers for operation and maintenance are followed, the availability for this type of well-proven technology should be high, approximately 99% or more. Construction issues Time * Installing a new ESP: 2 to 3 month outage * Increasing the size of existing ESP: 2 to 3 month outage * Retrofitting of ESP: 2 to 6 weeks of unit outage (Ref. 5) A Planner's Guide for Selecting Clean-Coal Technologies for Power Plants 85 The possibilities for domestic manufacturing, licensing agreements In China, there are at least three ESP manufacturers for plants up to 600-MW electric output (Ref. 2). In India, there is one manufacturer, BHEL, which has the major part of the ESP market (Ref. 1). BHEL previously had a license agreement with ABB Flakt and adapted their technology to Indian coal types with high ash content and high ash resistivity. Currently, there is no agreement and ABB FlAkt has a subsidiary in India called ABB India (Ref 4). Costs Investment The investment cost for an ESP is determined by its specific collection area (SCA), which in turn depends on fly ash resistivity, flue gas temperature and outlet emission limit. Low sulfur, high fly ash resistivity coals require a higher SCA than do high sulfur coals and coals with low fly ash resistivity to reach the same reduction, so consequently the ESP cost becomes higher. The influence of outlet particulate emission limit and fly ash resistivity on the investment cost is shown in Figure 6.1. The investment cost for a new ESP ranges from 30 USD/kW, for a coal with a fly ash resistivity of 1010 Ohm-cm, to 80 USD/kWe for a coal with a fly ash resistivity of 10" Ohm-cm (Ref. 7). This includes also costs for fans, ductwork and fly ash handling. ESPs with very high collection efficiencies (>99.7%) may cost up to 100 USD/kWe (Ref. 5). Costs for ESP improvements range from 1-20 USD/kW. (Ref. 5). Operation and maintenance The pressure drop over the ESP is normally very low, approximately 15-30 mmWC, resulting in low power consumption and thereby, a low operation cost (Ref. 7). ESPs normally require very little maintenance. Total O&M costs of conventional ESPs range from 0.15-0.4 USc/kWh (Ref 5 and 6) or around 5 USD/kW per year (Ref. 3). A 200-MW PC plant equipped with ESP Figure 6.3 shows a 200-MW subcritical PC plant equipped with ESP. The reduction in dust emission achieved can be seen by comparison with Figure 3.6. Chapter 6. Particulate Emission Control Technologies 86 Figure 6.3 A 200-MW, subcritical plant equipped with ESP Coal: 80 t/h - 4 A/ t 4 L ESP 200 MWe SO2: 3.2 tth NOx: 0.6 t/h Bottom ash: 2.6 t/h fly ash: Dust: 0.1 t/h 24th CO2: 220 t/h Note: Data used - plant efficiency = 37%, sulfur content, S= 2%, ash content = 32.8 %. Screening criteria Table 6.1 lists criteria to be used for technology screening as described in Chapter 9. Table 6.1: Screening criteria for ESPs Maturity of technology * ESPs are commercially available world wide and are installed in most coal fired power plants in India and China. Unit size * all plant sizes Waste product * none FABRIC FILTER (BAGHOUSE) For a long time fabric or baghouse filters have been the most widely used particulate control device in industry. Their application potential has been increased by the introduction of new materials capable of withstanding higher temperatures. They are popularly used in thermal power plants, especially in the United States. A feature of baghouses is their relative insensitivity to gas stream fluctuations and to changes in inlet dust loading. In fact, outlet emission becomes almost independent of inlet particulate concentration. Another advantage is that they can enhance SO2 capture in combination with upstream sorbent injection and dry scrubbing systems. A Planner's Guide for Selecting Clean-Coal Technologies for Power Plants 87 Suitability Baghouse filters are normally more cost effective than ESPs when firing low-sulfur or high fly ash resistivity coals, and when more than 99.5 % collection efficiency is required. Pulse-jet fabric filters are a newer type of baghouse filter which has a lower capital and levelized cost than the more widely used reverse air fabric filters. Baghouse technologies can be used in combination with sulfur removal technologies such as sorbent injection and dry scrubbing systems. In installations downstream spray dryers or sorbent injection systems, fabric filters can enhance S02 capture because chemical reactions between particulates and gases can also occur in the filter system. The filters collect unused reagent from the process and absorb more SO2. Pulse-jet fabric filters are being applied with increasing frequency at utilities equipped with spray dryer systems. SO2 removal performance may be enhanced by 25% with a baghouse in combination with the spray dryer. Baghouse filters are not commonly used in developing countries as the current emission limits favor ESPs. With the advance of more stringent emission limits, baghouse filters may be further introduced in the power sector. State of technology Baghouse technologies are commercially available throughout the world. However, they are not used widely in power plants in developing countries. Baghouse filters are used for air treatment in industry in China, but there are only a few coal plants operating with baghouse filters. In India, there is only one power plant using baghouse filters. Plant size The filter type is used in units up to and above 300-MW electric output. Fuel flexibility Baghouse filters can be designed for any type of coal from lignite to anthracite. Their efficiency is independent on the sulfur content. Flue gases with presence of acid or alkaline will reduce the fabric lifetime. Hygroscopic material, tarry adhesive components, moisture condensate can all produce problems such as filter plugging. Performance Very high collection efficiencies, above 99.5%, can be achieved, even with very small particles in the 0.5-1.0 micron range. The performance does not deteriorate with low SO2 content in the flue gas as it does in an ESP. The performance of the fabric filter is determined by the filter material. Chapter 6. Particulate Emission Control Technologies 88 Traditional materials are semi-permeable and woven, often fiber glass, capable of withstanding maximum 2600C. New materials have recently been developed to withstand much higher temperatures, in the range of 4800C, for use in hot side units and with fluidized beds. These materials are made of ceramic fibers and achieve collection efficiencies of 99.99%, but they are very costly. A vailability If the instructions of the manufacturers for O&M are followed, the availability for this type of well-proven technology should be high, 99% or more. Construction issues The possibilities for local manufacturing, licensing agreements There are manufacturers of baghouse filters in China, but the normal use is for air treatment. Baghouse filters for power plants will probably need to be imported. In India, there is currently no domestic manufacturing of baghouse filters, but it should be possible to manufacture more than 99% domestically. Costs In general, baghouses are more cost effective than ESPs in cases where high cleaning efficiencies (>99.5%) are required and when firing low-sulfur coals or coals with high fly ash resistivity. Investment The investment cost of baghouse filters does not depend as much on the coal quality or the emission limit as do ESPs. For baghouse filters, the filter cleaning method is important; fabric filters with pulse jet cleaning have normally a lower investment cost than fabric filters with reverse air cleaning. Other important parameters include the air-to-cloth ratio and the bag material. As was shown in Figure 6.1, typical capital costs for baghouses range from 50 USD/kW for pulse jet fabric filters to 70-75 USD/kW for reverse air fabric filters (Ref. 6). Levelized costs range from 0.32-0.4 UScents/kWh for pulse-jet and reverse air fabric filters, respectively (Ref. 3). Operation and maintenance Operating costs are normally 20-35% higher for baghouse filters than for ESPs due to a high pressure drop over the filter resulting in a significantly higher power consumption. The pressure drop is typically in the range of 100-250 mm water column. Also, maintenance costs are higher than for ESPs because the bags have to be replaced and the valves need to be controlled regularly. Total O&M cost is around 0.18-0.2 UScent/kWh or 6-7 USD/kW per year (Ref 6). A Planner's Guide for Selecting Clean-Coal Technologies for Power Plants 89 A 200-MW PC plant equipped with baghouse filter Figure 6.4 shows a 200-MW subcritical PC plant equipped with baghouse filter. The reduction in dust emission achieved can be seen by comparison with Figure 3.6. Figure 6.4 A 200-MW, subcritical plant equipped with bag house filter Coal: 80 t/h2u0 4 W - - + 4 2--bag 200 MWehos IV SO2: 3.2 t/h Bottom ash: 2.6 t/h fly ash: NOx: 0.6 t/h 24 t/h Dust: 0.1 t/h C02: 220 t/h Note: Data used -- plant efficiency = 37%, sulfur content, S= 2%, ash content = 32.8 %. Screening criteria Table 6.2 lists criteria to be used for technology screening as described in Chapter 9. Table 6.2: Screening criteria for baghouse filters Maturity of technology * Baghouse filters are widely used in industries world wide and they are popular in thermal power plants in the United States. In China there are a few coal plants using baghouse filters and in India there is one plant. Unit size * all plant sizes Waste product * none Chapter 6. Particulate Emission Control Technologies 90 REFERENCES 1. Mathur, Ajay. 1996 (May). Personal communication. Dean, Energy Engineering & Technology Division, TERI. New Delhi, India. 2. Li, Zhang. 1996. Personal communication. Hunan Electric Power Design Institute. Changsha, China. 3. Takeshita, Mitsusu. 1995. Air Pollution Control Costs for Coal-fired Power Stations. IEA Coal Research, IEAPER/17. International Energy Agency. London, UK. 4. Porle, K. and S. Bengtsson. 1996 (May). Personal communication. ABB Flkt. Vaxjo, Sweden. 5. Tavoulareas, E. S. and J. P. Charpentier. 1995. Clean Coal Technologies for Developing Countries. World Bank Technical Paper Number 286. Washington, DC. 6. Sloat, D.G., R.P. Gaikwad, and R.L. Chang. 1993. "The Potential of Pulse-Jet Baghouses for Utility Boiler Part 3: Comparative Economics of Pulse-Jet Baghouse, Precipitators and Reverse-Gas Baghouses," Air & Waste. Vol 43. Air & Waste Management Association. Pittsburgh, Pennsylvania. 7. Holme, V. and P. Darnell. 1996 (May). Personal communication. FLS Miljo a/s. Copenhagen, Denmark. A Planner's Guide for Selecting Clean-Coal Technologies for Power Plants 7. BY- PRODUCTS AND WASTE HANDLING Coal-use for power generation produces large quantities of wastewater and solid residues such as fly ash, bottom ash, FGD residues, ACFB residues etc. Currently, solid residues from coal-based power generation in India and China are limited to fly ash and bottom ash from PC boilers since FGD and large ACFB boilers are hardly used. Management of coal-use residues concerns their handling, transport and utilization or disposal. A first step in a successful management strategy for coal-use residues is to minimize the quantity of by-products produced. Possible routes for achieving this are to increase the use of washed coal and to strive for higher plant efficiencies. The benefits of using washed coal, in addition to minimizing the amount of solid residues that need to be taken care of at the power plant, are described in Chapter 2. By increasing plant efficiency, the amount of solid residues produced per MWh, is reduced. An increase in plant efficiency from 34% to 42% reduces the amount of waste produced per MWhe by 20%, as shown in Chapter 3. A second step in a successful environmental management strategy, which embraces the concept of sustainable development, is the maximum utilization of the residues. Utilization of residues has the advantage of making land available for other non-disposal purposes. Since both India and China are undergoing rapid industrialization, there is a great demand for large quantities of building and construction materials. This demand is expected to continue to increase over the decade. Some residues from coal-based power have properties already being asked for by the construction industry. Fly ash can be used for land and mine reclamations and as a substitute for Portland cement in concrete. Gypsum from a wet scrubbing system can be an adequate substitute for natural gypsum. Whether utilization of the residue is possible or not is dependent on the initial selection of combustion and flue gas cleaning technology. Not all types of residues can currently be utilized. Hence, residue use should remain a focus when selecting combustion and flue gas cleaning technology for a proposed power plant. Before deciding on utilization or disposal, the characteristics of the residue should be examined to determine the suitability of either solution. If the by-product is of too low quality to be utilized; if utilization of the by-product is not economically feasible, or if the by-product generation is larger than the market demand, disposal of the by-product will be necessary. In such a case, it is important to assure safe, environmentally acceptable disposal. However, disposal should be looked on as the last resort in residue management. Waste from coal-based power production is not restricted to solid waste. A large amount of wastewater is produced which needs proper treatment. Treatment methods are summarized in this chapter. 91 92 UTILIZATION Today only a small portion of the fly ash and slag residue produced in power plants in India and China is utilized leaving the major part for disposal. Internationally, utilization of residues is a well-established technology. These facts are illustrated in Table 7.1 where it can be seen that the ash utilization rates in India and China are very low compared to the ash utilization rate in Germany which is close to 100%. Not shown in the table is gypsum from FGD plants which also has a high rate of utilization internationally. The high utilization rate in Germany is achieved by a comprehensive program for the standardization of by-products and construction materials and active marketing of construction materials produced from by-products. Co-operation between the power industry and the construction materials industry in Germany also contributes to the high utilization rate. Table 7.1 Coal ash production and use in India, China and Germany Country Fly and bottom ash Utilization Year (kt/year (kt/year % China 110,000 34,000 30 1995 India 40,000 8,000 2 1992 Germany 20,000 19,800 99 1992 Source: Zhang et al (1996), Sloss et all (1996). With the huge quantity of ash being generated, as shown in Table 7.1, it is essential that the question of utilization be addressed. Increased utilization of residues, for example as building materials and for civil engineering purposes, is therefore to be promoted both in India and China. In China, a feasibility study for ash and slag utilization will be required as part of new power plant feasibility studies in the near future (Ref 4). As per the latest stipulations by the Indian authorities, an ash utilization plan is required for new power plant projects (Ref 2). It should be concluded that utilization will be a high priority in the future. There will be demand for high utilization rates in new power plants and increased utilization at existing plants. Requirements on utilization affects the selection of combustion, ash handling and flue gas cleaning technologies, and thereby promotes technologies that produce solid residue that can be utilized easily, e.g. wet scrubbers producing gypsum, dry ash handling systems, etc. A range of technical and economic considerations influence the feasibility of utilization. Residue should be utilized as close to the power plant as possible, avoiding long distance transportation. This could be achieved by reserving land for construction material production near the power plant. Other factors affecting the feasibility for utilization are land availability near the power station for a disposal site and regulations on solid waste disposal; availability of natural competing materials; existing commercial experience in using the by-product; promotion of cooperation between utilities and industries using the by-product, and the quality of the by-product. A Planner's Guide for Selecting Clean-Coal Technologies for Power Plants 93 There is an environmental concern related to utilization with the risk of the spread of potential contaminants widely in the environment without control. Hence, before deciding on utilization or not, the suitability to use the actual by-product has to be examined. Generally the suitability depends on: * the physical and chemical properties of the by-product; * the risk for leaching of trace elements; and * the environment the by-product will be used in; depending on leaching characteristics, restrictions for by-product utilization may apply in ecologically sensitive areas, applications above ground water level and wetland areas etc. Requirements for fly ash and bottom ash utilization Fly ash characteristics vary considerably with parameters such as coal type and combustion conditions. Both the physical and chemical properties of the fly ash are important when determining the suitability for use in specific areas. Chemical properties are pozzolanicity, i.e. the ability to combine with CaO in the presence of water to form cementitious compounds, and reactivity. A physical property of fly ash is its fineness. Classification systems and specifications are used to ensure that the correct fly ash is used for a specific purpose. For example, both India and China have country specific specifications for coal fly ash for use in Portland cement (Ref. 3) where unburned content, SO2 content, specific surface, etc. are specified. Evaluation of by- products for use includes leaching tests for different trace elements such as As, Cd, Cr, Cu, Hg, Ni, Pb, Zn, Cl, SO4. Tests include initial and long-term leaching properties of material. Requirements for FGD gypsum utilization In order to be able to utilize the gypsum produced in a FGD plant, the quality of the gypsum has to be controlled. The most important parameters to control include: * free moisture content, * quantity of solid impurities, * chemical composition, * color, and * crystal shape and particle size. Internationally, commercial grade FGD gypsum is often required to have a purity greater than 95%, a free moisture content of maximum 10%, a chlorine content of less than 400 ppm and a whiteness of 80%. Areas of utilization Fly and bottom ash from PC firing and FGD gypsum can be used commercially in many applications. Fly ash can be used either as an active pozzolanic agent or simply as a cheap admixture to provide bulk in engineering materials and FGD gypsum can replace natural gypsum. Chapter 7. By-Products and Waste Handling 94 Currently, other solid residues are disposed of, since there are limited means of utilizing them commercially. Table 7.2 summarizes the areas of utilization for different solid residues. Table 7.2: Areas of utilization for coal-use residues By-product Utilization areas/ disposal State of utilization Fly ash * cement industry * commercial * concrete and construction materials * commercial * structural fill * commercial soil stabilization * commercial Bottom ash * cement industry * commercial * concrete and construction materials * commercial * structural fill commercial Fluidized bed residues * disposal * R&D * some utilization areas are studied; processing and mixing in one or another way is required Spray dry scrubber * disposal * R&D residues * some utilization areas are studied; processing and mixing in one or another way is required Sorbent injection * disposal * R&D residues * some utilization areas are studied; processing and mixing in one or another way is required Wet scrubbing: * gypsum * building materials; * commercial - wallboards - plasterboards - mortars - floor screeds - cement * civil engineering * commercial - mining applications - roadbase and structural fill * agriculture * R&D - conditioning alkaline soils * stabilizate * disposal * gypsum slurry * disposal PFBC * potential use as * R&D - structural fill - road base construction etc. IGCC * R&D A Planner's Guide for Selecting Clean-Coal Technologies for Power Plants 95 DISPOSAL Disposal methods can be divided into two categories: wet and dry disposal. Wet disposal involves the handling of the by-product as a slurry or in liquid form. The disposal site is usually referred to as a pond, impoundment or reservoir. In dry disposal systems, or landfills, the by-product is handled as a solid. Wet disposal ponds are used in most plants in India. Wet disposal is also the predominant technology in the southern part of China. Presently, dry disposal is becoming the most popular in new disposal facilities over the world. The choice between dry or wet disposal must correspond to the waste collection method employed in the power plant. Otherwise, the disposal system must include means to convert the waste to either the wet or dry disposal method. The latter is actually common in many power plants. Many power plants with wet waste collection systems have a process to convert to dry disposal. Three such treatments include dewatering processes in which the water is physically separated from the solid; stabilizing processes which include addition of dry solids, and fixating processes which involve the addition of a compound that reacts chemically and binds the water into the product. FGD slurries often require more than one such process prior to disposal. The major environmental concern connected to disposal is the potential short- or long- term risk of leaching of inorganic salts and trace element into surrounding water systems. The disposal strategy must assure that the concentrations at the site and its surroundings are not elevated to unacceptable levels. Possible routes for impact of disposal on the environment are illustrated in Figure 7.1. Leaching of material as well as surface run-off of material from the disposal site can lead to contamination of soil, ground water, fresh water systems, and sea. When designing a disposal system a major concern will be to prevent this contamination in order to protect the environment and human health. Other factors that can affect the choice of disposal strategy and method include the properties of the residues, applicable methods, costs and conditions at the disposal site. Requirements for disposal With prevention of water contamination becoming an increasingly important issue associated with residues from coal-fired plants, the environmental consequences must be found out before disposal. A method for determining the suitability of the waste material for disposal is to investigate the potential for leaching from the residue. Leachate tests can give information about which components in the material are readily released in water and the consequences for the water quality. Furthermore, they can give an indication of hazardous materials unsuitable for disposal. Basically, three types of leachate tests are employed: * shake tests, * column tests, and * field tests. Chapter 7. By-Products and Waste Handling 96 Figure 7.1: Impact of disposal on the environment LOCAL RECIPIENT RAIN MAN SEA (FRESHWATER) GROUND-WATER *ca Shake tests are made batchwise and are the most simple and inexpensive; however the drawback is that the batch situation does not a give an accurate simulation of the natural situation. Column tests provide representative conditions in nature while still at a laboratory scale; the material is placed in a column and a liquid flow percolates through it. The leaching media used in these laboratory tests can be distilled, de-ionized or demineralized water, acetic acid or a buffer. In a field test, a large sample of material is used and exposed to natural conditions, while leachate is collected and analyzed over a long period of time. Field tests give the most accurate reproduction of field conditions as they simultaneously account for chemical and microbiological reactions. Once the potential for leaching to the environment has been tested and estimated, the suitability and the precautions disposal can be determined. The legislative and regulatory guidelines for disposal of coal-use residues vary from country to country. Generally the regulations include limit values for concentrations of trace elements, such as arsenic, cadmium, chromium, copper, mercury, lead, etc., in the leachate. Dry disposal The trend today is toward increasing use of dry disposal in landfills. Dry disposal has the advantage of requiring a smaller site area than wet disposal and is therefore an attractive option for plants with wet waste collection systems. In such cases, an intermediate wet pond can be used for sedimentation of the residues prior to disposal. Furthermore, problems like water pollution and consumption are minimized using dry disposal. There are some important considerations for dry disposal in landfills. The landfill must be designed to be stable in all weather conditions during its entire lifecycle from construction through operation, to its final closure and after. Site selection and design should prevent influx of A Planner's Guide for Selecting Clean-Coal Technologies for Power Plants 97 groundwater. In order to protect groundwater quality, a water management system must be included, filtration must be prevented and leachate must be collected and treated. A vital element in landfill design is to estimate the potential for surface runoff Both runoff from the area above and from the landfill itself should be considered. Runoff from above can be led around the landfill to avoid contamination. Runoff from the landfill itself should be collected and treated, as an example by sedimentation prior to release to the recipient (see Figure 7.2.) The system must be capable of handling runoff in all weather conditions, including heavy rainfall and storms. A leachate collection system should be installed under the whole landfill to protect the groundwater system and preserve the landfill stability. Collection can consist of a network of perforated pipes or a blanket of granular material, e.g. sand, gravel, or bottom ash. A system for monitoring of all wastewater streams and the groundwater is necessary to ensure protection from groundwater contamination. Both pollutant concentrations and water flows should be monitored. With such a system in operation, any malfunctions of the leachate collection system will be discovered before severe damage has occurred. Many landfill sites are isolated with liners in order to reduce permeability at the deposit boundaries. The liners are constructed so as to control the direction of the leachate and route it toward the drainage system. Figure 7.2 illustrates the principles of landfill disposal. When closing, the landfill should be sealed by a soil or clay cap in order to minimize infiltration of water. Leachate production can only be limited by reducing the amount of water entering a residue deposit. The cap design should be impermeable. Rain and water falling on it should not be captured but routed through collecting channels off the cap to a sedimentation pond before it is discharged to the recipient. For power plants located close to the coal mine, backfilling the mine with coal ash is an attractive option from an environmental, as well as an economical point of view. For power plants located at a distance from the coal mine, ash disposal in the mine will require high transportation costs. For such plants, dry ash disposal must be made in natural low lands or in mounds. Disposal in mounds is a more efficient land use than disposal in low lands, but the costs are higher. Land reclamation, after the disposal site closes, is easier for a low land site. Estimated capital and O&M costs for dry disposal methods are listed in Table 7.3. Table 7.3: Estimated capital and O&M costs for dry ash disposal methods Estimated Disposal Costs Method Capital Annual O&M (USD/m) (USD/mn) Mine backfilling 0.3 1.2 Lowlands 0.3 1.0 Mounds 1.4 3.1 Source: WESA (1996). Chapter 7. By-Products and Waste Handling 98 Figure 7.2 Landfill disposal site for coal-use residues Active landfill ZZX 105 .2~ 100 0 0 > 95 8 90 95 % Availability 90 I I I I 36 38 40 42 44 % Electrical efficiency Note: The diagram can be used to estimate the impact of changes in efficiency and availability on relative cost of electricity. used to quickly translate changes in availability and efficiency given in this chapter into impact on electricity production cost. It shows the relative cost of electricity as a function of availability and as a function of plant efficiency. The effects of changes in efficiency are of roughly the same magnitude as changes in availability. For example, increasing plant availability from 90 to 91% reduces the production cost by about 1%, as does increasing the efficiency from 40% to about 41%. Finally, the improvement achieved by refurbishment does not just depend on the actual refurbishment concept, but also on the existing plant and its built-in possibilities and limitations. Therefore, the performance improvements are unique for each concept. The data given in this chapter is intended to give an indication of possible improvement rates. It is, of course, necessary to make an economic evaluation for each individual concept. INSTRUMENTATION AND CONTROL SYSTEMS Combustion control by 02 measurement A reliable system for 02 control and monitoring is important for obtaining maximum plant efficiency. With such equipment, the combustion process can be controlled properly and optimum parameters of operation can be determined. The result is more efficient combustion, which not only gives higher plant efficiency, but also controlled CO and NO, emissions, as well as minimized content of unburned fuel in the ash. A Planner's Guide for Selecting Clean-Coal Technologies for Power Plants 111 Excess air is the most important parameter for control of the combustion process and the largest factor affecting boiler efficiency. Excess air can be expressed in percentage of theoretical need for air or as 02 content in flue gas at economizer outlet. For an efficient combustion process the 02 content in the flue gas must be high enough to maintain the desired steam temperature and to assure complete combustion and a minimum of losses of unburned fuel in the ash. However, there are several reasons to control and minimize the excess air. Large amounts of excess air leads to unwanted extra heat losses when the flue gas leaves the stack and higher flue gas exit temperature, both of which result in decreased boiler efficiency. Minimizing excess air also decreases the parasitic power demand for the air fans. Another reason to control excess air is that a high amount of excess air and a resulting high firing temperature are the two most important parameters for formation of NOx. Over the load range, the need for excess air varies. Higher amounts are necessary at lower loads. The optimum 02 content in flue gases depends on the coal and the combustion system. For a given coal and boiler the optimum curve of 02 content in the flue gases versus boiler load can be defined. In order to maintain operation close to the optimum 02 curve, a reliable control system, including 02 measurement instruments, is necessary. Normal values of 02 content in flue gases when firing coal are 4.3 % by volume dry gas at full load and 5% by volume dry gas at half load. Steam temperature control to increase plant lifetime and efficiency By controlling steam temperatures in a plant, the lifetime and the efficiency of the plant are increased. The use of boiler and turbine in an optimal manner means that the live and reheat steam temperatures should be close to the actual maximum allowed values. For a plant in good condition, that corresponds to the nominal contract values. If the plant is in bad condition, relevant reduced steam temperatures should be determined and used as modified set values. The main reason for a reduction in the steam temperature levels is poor condition material in the superheater surfaces and in the turbine. Instead of reducing steam temperatures, a check should be made as to whether a more optimal solution would be to replace a superheater surface section, reconstruct the turbine etc. and operate with normal temperatures. If the steam temperature control system is out of order or performing badly this could result in consciously reduced set values for the steam temperatures. Such reduction in set values creates safety margins during static operation, and thus prevents exceeding the critical temperature levels for the plant during load variations and when fuels with non-homogenous heat values are fired. Every lost degree Centigrade in steam temperature corresponds to a reduction of 0.02% in electrical efficiency. The corresponding impact on the relative electricity production cost can be estimated by the use of Figure 8.1. Pump and fan control to reduce operating costs Auxiliary power consumption amounts to 7-12% of the electric output in a normal coal-fired power plant. Pumps and fans represent a major part of this consumption. Worn equipment, poor maintenance and outdated equipment can result in high auxiliary power consumption figures. New technologies and equipment provide for improvements in reduced auxiliary power consumption Chapter 8. Low Cost Refurbishment including O&M Improvements 112 and hence reduced operating costs. The potential for the reduction of auxiliary power consumption by fans and pumps depends on: * the status of the plant (simple existing equipment and bad maintenance indicate a high potential for improvement); * the load profile of the plant (the potential is better in plants with a significant operating time on part load); improvements mostly affect part-load characteristics, with reduced auxiliary power consumption at part load; and * the configuration of the fans/pumps (1 x 100%, 2 x 50%, etc.); when fans and pumps are installed in parallel (2 x 50%), the potential for improvement is lower. The profitability has to be analyzed for each individual plant. Capital costs have to be balanced against reductions in operating costs. A summary of possibilities for fans and pumps is given below. Fans Normally there are flue gas fans and primary and secondary air fans in a plant. Air and flue gas fans use between 25-35% of the total auxiliary power consumed in a plant. Where possible, modem plants are equipped with axial fans. Radial fans are only used when high pressure drops have to be overcome, such as within primary air fans. However, in older plants radial fans are still common. If plants are already equipped with axial air and flue gas fans using adjustable control vanes then the potential for improvement is low. Theoretically, variable speed control can be introduced, but this change is not common. If the plant is equipped with radial fans then the potential for improvement is higher. Depending on conditions at the actual plant, the following can be done to improve part load characteristics: * improve existing guide vane control; * change from guide vane control to variable speed control; and * change fan - install axial fan. Boiler-feed water pump Feedwater pumps use 40-50% of the total auxiliary power consumed in a plant, depending on feedwater pressure. There is potential for reducing the maintenance costs and auxiliary power consumption at part load by changing the control method. Feedwater pump controls exist at constant speed where excess head is reduced by throttling in a control valve, and at variable speed where pump speed governs flow and head. The type of feedwater pump drive used effects the O&M costs of the pump system. Compared with a constant speed drive, a variable speed drive has lower operating costs, especially at part load. The savings in operating costs depend on the cost of auxiliary power and the operating time on part load. Variable speed drive also has lower maintenance costs. High pressure drop control valves necessary in constant speed systems are frequently high maintenance components. A Planner's Guide for Selecting Clean-Coal Technologies for Power Plants 113 In new installations, the investment is higher for variable speed drive than for constant speed drive. BOILER SYSTEMS Reduction of air preheater leakage Plants with an electric output above 50 MW are often designed with recuperative air preheaters of the rotating type, such as the Ljungstrom. In such air preheaters there is an inevitable leakage from the combustion air side to the flue gas side. This air leakage must be kept carefully under control since the leakage air has the following effects: * increased power consumption in the combustion air and flue gas fans; * load reduction due to mechanical or electrical overload of the fan systems, in particular when the preheater is in a poor condition; and * extra cooling when mixed into the flue gases which can result either in low temperature corrosion, or in increased "true" flue gas temperature at preheater outlet, i.e. lowered boiler efficiency. Keeping the leakage under control requires the sealing system to be included in the maintenance routine for regular control and adjustments. Information on the air leakage value is given by the 02 content in the flue gas at the preheater outlet and inlet. Differences of around 1.5-percentage units 02 (dry gas) corresponds to an air leakage of 10%. Correspondingly, a 3-percentage units 02 difference corresponds to an air leakage of 20%, which gives a poor economy of operation. Seal adjustments should be made to keep the leakage value around 10% at full load. Steam air preheater to reduce maintenance costs To protect an air preheater of the recuperative type, like the Ljungstrom, its inlet air should be heated. Heating is done to increase the material temperatures on the "cold side" of the Ljungstrom air preheater. This way corrosion from low temperature operation and thereby high maintenance costs can be avoided. The most critical situations for low temperature corrosion are the start up and low load operation periods. Preheating is achieved by installing a steam air preheater upstream from the Ljungstrom air preheater. Temperatures on the "cold side" of the Ljungstrom preheater, above the acid dew point, will be reached with a steam air preheater. Using a steam air preheater affects the design of the Ljungstrom preheater. A somewhat larger surface is needed to achieve the same flue gas outlet temperature since the air inlet temperature is slightly higher. Steam needed in the steam air preheater is often available from external sources, such as other boilers in the plant during a start up. If this is not the case a service boiler is needed. During normal operation steam is bled off from the process. Chapter 8. Low Cost Refurbishment including O&M Improvements 114 Cleaning of convective heating surfaces to increase efficiency It is necessary to keep convective heating surfaces in the boiler clean in order to achieve steam temperature set values. In the boiler back pass, economizer and air preheater sections, deposition of coal ash will result in increased flue gas outlet temperature. Coal ash deposited on the surfaces can be removed by soot blowers. The amount of ash and its characteristics determines the number of soot blowers and the frequency of use needed to maintain effective heat transfer. The cleaning medium is usually normal steam, bled off from a superheater section which can achieve suitable steam data over the load range. It is important to keep the soot blowing system in good condition and use it in accordance with operating manuals. If any of the soot blowers are out of order, a buildup of ash might result in surface damages. Super heater cleaning is important to achieve steam temperature set values. Every lost degree Centigrade in steam temperature corresponds to a reduction in plant efficiency of roughly 0.02 percentage units. Ash deposition in the economizer and air preheater section causes increased outlet flue gas temperatures. An increase of 200C corresponds to a change in boiler efficiency from 90% to about 89%, or plant efficiency from 30% to 29.7%. COOLING WATER SYSTEMS Condenser cleaning system to increase efficiency Depending on cooling water source; the cooling water system (once-through or closed circuit); the season; water level in rivers; and type, mesh size and performance of pre-screening, the cooling water will carry various quantities and kinds of floating and suspended substances, which may cause failures in heat exchangers and condensers. Fouling, scaling and clogging in tubes and tube sheets are typical examples of such failures. Effects of microfouling and scaling on cooling surfaces include: * reduced heat transfer coefficient; * reduced turbine generator output; * increase in heat consumption, and * tube corrosion. Effects of macrofouling in the cooling water circuit if caused by tube sheet and tube clogging include: * reduction of cooling surfaces available and thus lower output; * erosion corrosion due to destroyed protective film around a wedged particle in the tube, by turbulence and increased water velocity; * increased corrosion by anaerobic decay of organic substances in clogged tubes yielding of sulfides and ammonia; and * increased pressure drop in the condenser. A Planner's Guide for Selecting Clean-Coal Technologies for Power Plants 115 The installation of a tube cleaning system with recirculating cleaning balls is an effective way to minimize these problems. In the case of sea water cooling or cooling water with coarse debris, some kind of debris filter should also be installed upstream from the condenser and/or the heat exchangers. The goal should be to achieve the design value of the condenser pressure at a given cooling water temperature. A loss in electric efficiency of about 0.35-2.4%, at a cooling water temperature level of 180C, may occur due to fouling in the condenser and the resulting increase in back-pressure. The sensitivity of turbine efficiency to fouling impact varies between turbine types and therefore a general relationship cannot be given. AUXILIARY SYSTEMS Water chemistry control to increase plant lifetime In order to extend the lifetime of boiler and turbine components, a proper water chemistry regime must be sustained. Guidelines from different countries and organizations are available. Widely used guidelines are the "Interim Consensus Guidelines for Fossil Plant Cycle Chemistry" from EPRI (USA) and "VGB-Richtlinie fur Kesselspeisewasser..." VGB-R 450 L (Germany). The need for surveillance is related to the steam pressure and to boiler construction. Generally, the higher the pressure, the greater the concern about water chemistry. Water Chemistry Control can be divided into hardware (i.e. analyzers, instrumentation, computers etc.) and instructions. Hardware As the guidelines indicate, many of the parameters should be continuously monitored to ensure a good water quality. Commonly, the analyzers are connected to the main computer in the control room but the chemical analysis system can also run on a PC as a stand-alone chemistry system. Alarms, transient trends, etc. can be tracked easily with this arrangement. This will also simplify trouble-shooting and enhance the ability to see long-term changes in the cycle chemistry. Instructions As for all power plant operation tasks, water chemistry has to be organized in a well-defined fashion to maintain the overall goals. This includes well educated and motivated personnel. To achieve this goal the power company management has to set up a strategy. In this strategy instructions for chemistry control have to be formalized. The instructions have to be developed and anchored in consensus with the operators that will be responsible for the water chemistry. The implementation of the instructions includes formal training, so a profound understanding of cycle chemistry must be obtained. Great concern should be taken to establish good contact between chemical staff and the O&M personnel. Chapter 8. Low Cost Refurbishment including O&M Improvements 116 OPERATION AND MAINTENANCE Computerized maintenance management system to increase availability A computerized maintenance management system may be a useful tool to increase the availability of a power plant and to minimize cost. The maintenance management system should comprise: * a planning system where all maintenance activities of the plant will be planned; * a work order system which will be used for preparation, planning and time scheduling for each individual maintenance work; * a preventive maintenance system which includes programs for regular inspection, testing, lubrication and inspection; and * a spare parts storing system containing documentation of available spare parts. The preventive maintenance should be based on real knowledge of every major object. This implies that important apparatus and components in the plant should be equipped with measuring points for continuous control. A Planner's Guide for Selecting Clean-Coal Technologies for Power Plants 9. TECHNOLOGY SELECTION MODEL The selection of technology for a coal-fired power plant is a complex task. It involves the evaluation and optimization of a large number of technical, environmental and economic considerations. This chapter presents a model which can be used to help select environmentally friendly technologies for coal-fired power plants. It is simply called the Fast Track Model. FAST TRACK MODEL The Fast Track Model is built up by four logical steps. Each step has a clearly defined scope and result. An overview of the model is given in Figure 9.1 showing the results of each step. This step design provides a tool which will enable the user to handle the large amounts of information that have to be considered in power plant projects. Step 1 handles project definition. To facilitate the forthcoming studies, a rough screening is done in Step 2 resulting in a description of applicable technologies within different technology areas. In Step 3, a number of power plant concepts are stated, corresponding to different environmental requirements; ranging from very stringent to less stringent. These concepts are then evaluated against the prerequisites given in Step 1. The result will be a list of possible useful power plant concepts. In Step 4, the cost calculations can be made for the possible power plant concepts. This will determine the possible investment cost, the electricity production cost and the cost of reducing emissions. Finally, on the basis of the cost calculations, a recommendation can be made as to which alternatives should be subjected to a more detailed feasibility study. Figure 9.1: Steps and results in the Fast Track Model Step I Step 2 Step 3 Step 4 Project definition Technology Possible Cost calculation and screening alternatives recommendation Type of project. Technologies (combustion, Technical and Power plant concepts SO2, NOx, & particulate environmental evaluation of presented with: Prerequisites: emissions) that meet 3-5 power plant concepts. * investment cost, * general, requirements regarding: * electricity production * economic, * maturity of Evaluation against cost, * environmental, technology, prerequisites. * cost/ton emission * operational. * unit size, removed, * waste product. * emissions of SOx, NOx and particulates, * utilization of by- products/ waste production. Result: Project Result: Applicable Result: Possible power Result: Recommended definition statement. technologies. plant concepts. alternatives for a feasibility study. 117 118 The purpose of the Fast Track Model is to enable the user to make a recommendation on the most suitable technology combination for a power plant, taking into account aspects such as environmental impact and costs. A planner gets answers to the following questions: * possible power plant concepts? * investment cost? * electricity production cost? * flue gas cleaning cost? * cost/ton SO. removed? * cost/ton NOx removed? The Fast Track Model is meant to be used early in the project during the prefeasibility phase, when the first technology selections are made. During the prefeasibility phase, alternative power plant concepts are studied to find the most suitable concept for each specific project. In the feasibility phase, concepts that proved successful in the prefeasibility study are examined in more detail. The Fast Track Model only deals with the technology selection part of the prefeasibility study based on technical, environmental and some economic requirements. However, there are a lot of other activities that have to be begun during the prefeasibility phase, besides selection of technology. These include, for example, power delivery and fuel supply agreements, governmental support, environmental requirements, financing and purchasing policy. Some of these also have an effect on technology selection. Technology areas covered by the Fast Track Model are coal quality; combustion technologies; emission control technologies for SO2, NO. and particulates; and by-products and waste handling, as illustrated in Figure 9.2 below. Technical, environmental and economic data regarding these areas is given in Chapters 2-7. The World Bank guidelines and guidance on environmental requirements in India and China are found in Chapter 11. Figure 9.2: Technology areas covered by the Fast Track Model Combustion Coal Quality Technologies By-products Clean Coal Fired SO2 Emission nd Waste "---_Power Plant Control Handling Control Particulate Emission NOx Emission Control Control A Planner's Guide for Selecting Clean-Coal Technologies for Power Plants 119 STEP 1. PROJECT DEFINITION The aim of Step 1 is to document non-changeable project data. Use of the project definition data by all members of the project group is vital. It ensures that everyone in the project group uses the same input data and works towards the same goal. A well-defined project forms the basis for all related work and provides the foundation for progress. Project definition data that need to be settled are: * type of project whether a greenfield power plant or retrofit of an existing power plant, * type and amount of products produced at the plant, * objectives of a retrofit, and * prerequisites. The work procedure for project definition is illustrated below in figure 9.3. Figure 9.3: Project definition - flow diagram Project Definition Greenfield Type of Retrofit Project Products Objectives Table 9.1 Table 9.2 Prerequisites Table 9.13-9.6Prjc Definiltion The project definition starts by answering simple questions. Is it a greenfield plant or a retrofit? What are the main objectives and needs? For a greenfield power plant, you have to define what type of products are going to be produced, as shown in Table 9.1. For a retrofit project you have to define the objectives with the retrofit, as shown in Table 9.2. Chapter 9. Technology Selection Model 120 Table 9.1: Products produced at the power plant * electricity; * steam; * oxygen, nitrogen etc. generated, for example, in an IGCC plant; * district heating; * others. Table 9.2: Objectives for the retrofit * reduce operating and maintenance costs; * increase plant efficiency; * increase availability; * reduce environmental impact, such as waste, emissions of SOx, NOx and particulates; * increase unit lifetime; * increase electricity production; * other products, see table 9.1. After defining the type of project, the prerequisites listed in Tables 9.3-9.6 should be considered to make the frames and objectives of the project more clear. Some of these prerequisites will then be used to evaluate different plant concepts technically, environmentally and economically. The prerequisites are divided into four categories: general, economic, environmental and operational. Table 9.3: General prerequisites * type of project - commercial or development. * power plant - size, - number of units, - site, - location, - available space. * coal - domestic/ imported/ both domestic and imported, - distance from domestic mine to power plant, - coal type, - value & range of main characteristics * ash content, " sulfur content, * heating value. * date of commissioning A Planner's Guide for Selecting Clean-Coal Technologies for Power Plants 121 Table 9.4: Economic prerequisites * project economy - rate of return, - economic lifetime. * financing policy - project financing, - equity, - World Bank loans. * purchasing policy - turn key, - split procurement. * demands on local manufacturing Table 9.5 Environmental prerequisites * sox - National/ local requirements, - World Bank requirements. * NOx - National/ local requirements, - World Bank requirements. * particulates - National/ local requirements, - World Bank requirements. * waste water - National/ local requirements, - World Bank requirements. * other environmental policy - sox, - NOx, - particulates, - waste water. * requirements on solid by products/waste - utilization, - utilization after processing, - disposal. Table 9.6: Operational prerequisites * operation time, * base load or peak load, * availability factor, * efficiency, * load change rate * minimum load. 122 STEP 2. TECHNOLOGY SCREENING The technology screening procedure is illustrated by a flow chart in Figure 9.4. Screening is done to quickly find which technologies do or do not meet overall requirements. Those that do not can be quickly eliminated. The applicable technologies which meet the overall project requirements will be used in Step 3, when the alternative power plant concepts are stated. The screening should be carried out for four of the technology areas: combustion technologies, S02-emission control technologies, NOx-emission control technologies and particulate emission control technologies. Screening is carried out against three criteria: required maturity of technology, maximum number of units accepted and by-product/waste-related requirements. Figure 9.4: Technology screening Powver Plant Com SO .No .P s Technology areas II I I : Your choice of requirements on Maturity Screening, Not applicable screening criteria requirements chapters 3-6 shall be set in accordance with table 9.7. nurnit capersng )0 Not applicable Waste product Screening,) Not applicable requirements chapters 3-6 Applicab le Technologies The screening criteria can be used for all projects, but the requirements on the criteria are project specific. Requirements are chosen from the ones given in Table 9.7. The required maturity of technology is set by the type of project. When the project is commercial and the requirements on availability are high, the requirements on maturity of technology can be high. In a development A Planner's Guide for Selecting Clean-Coal Technologies for Power Plants 123 project, the requirements on maturity of technology can be lower. Other factors than just type of project affect the requirements on maturity of technology, such as financing policy. Plant size and maximum number of units required were also determined in Step I and will be used when screening each technology area against number of units required. The final screening criterion is the requirement on solid by-product/waste. Technologies that do not meet the requirements on these criteria can be eliminated. Technologies that meet the requirements are applicable technologies and can be used in the next phase. Different combustion and flue gas cleaning technologies produce different types of solid by- products/waste. Screening should be made against the requirements on the waste product defined in Step 1. Should it be possible to use the by-product, for example in the building industry, or should it just be disposed of? Table 9.7: Screening criteria and choice of requirements Screening criteria for Choice of Choice of Choice of requirements each technology area requirements requirements Maturity of technology > 10 commercial reference < 10 commercial < 10 commercial reference plants in India/ China reference plants in India/ plants worldwide China and > 10 commercial reference plants worldwide Required number of units total plant size is 1- 2 units total plant size is 3- 4 total plant size is >4 units units Waste product possible to use without possible to use after disposal processing processing The screening criteria can be applied for each technology and compared with the data and information given in the screening criteria tables from Chapters 3-6: * Table 3.4 Subcritical PC * Table 4.5 Wet FGD * Table 3.5 Supercritical PC * Table 5.4 Low-NOx combustion * Table 3.9 ACFB technologies * Table 3.12 PFBC * Table 5.5 SNCR * Table 3.14 IGCC * Table 5.6 SCR * Table 4.1 Sorbent injection * Table 6.1 ESP * Table 4.3 Spray dry scrubbers * Table 6.2 Baghouse filters The screening results in Step 2 gives the applicable technologies which meet the overall requirements of the project, in terms of required maturity of technology, number of units accepted and the requirements for the by-product/waste. These technologies will be used for stating possible power plant concepts in Step 3. Chapter 9. Technology Selection Model 124 STEP 3. POSSIBLE ALTERNATIVES Now applicable technologies from Step 2 can be used to find possible power plant concepts. The alternatives represent technical solutions for the whole power plant. Figure 9.5 shows the different parts of Step 3. Figure 9.5: LogIcal sequence in developing project specific power plant alternatives Applicable Technologies Coal Quality Alt Alt Alt Alt State new alternatives No Yes Possible 'Alterntives Coal quality As shown in Figure 9.5, the first question to deal with is which quality of coal should be purchased since coal quality has a major effect on the economics of power plant operation, as discussed in Chapter 2. The available coal qualities were defined in the general prerequisites (Table 9.3) and now it is time to ask: Which is the best coal to use considering both environmental and economic impacts? If it is a high ash, non-washed coal, it is important to find out whether it would be better to purchase coal with a lower ash content. Use the section on Costs in Chapter 2 as a first point of reference to help to find out the impact coal quality has on the costs of electricity production. Consider the environmental issues: reduced transportation, minimized handling of residues, O&M impacts, etc. Information on how much it is worth paying for a coal with a lower ash content is given for some specific plants in Chapter 2. Locate available coals, their quality and price to find the coal which is the most economical for each project. A Planner's Guide for Selecting Clean-Coal Technologies for Power Plants 125 Stating the possible alternatives After deciding which coal quality should be purchased, a number of alternatives regarding the power plant configuration can be stated. * Use the result from the technology screening (Step 2) to eliminate unsuitable technologies. * Use information in chapters 3-7, especially the paragraphs "Suitability" and "Fuel flexibility" to find which technologies are suitable for your choice of coal quality. * State a number of alternatives that represent technical solutions for the whole power plant. * Use cost data, performance diagrams and other technical information from Chapters 3-7 to find the technologies that are most likely to be successful for your project. Alternatives should always include at least one configuration which complies with each of the following: - national or local requirements (Chapter 11), - World Bank environmental guidelines (Chapter 11), and - more stringent environmental requirements. Evaluation of alternatives Now the alternatives need to be evaluated. The results of the technical evaluation are alternatives that correspond with the prerequisites. Start by gathering facts, contact suppliers for current data regarding investment costs. Then check that the alternatives comply with the prerequisites in Table 9.3-9.6: general, environmental, operational and some economic prerequisites. Most of the economic evaluation is done in the final Step 4. Step 3 results in possible power plant alternatives that meet the main prerequisites. If there is no alternative which complies with the prerequisites, then state new alternatives, and loosen the requirements of the prerequisites. If the latter is necessary, the Fast Track Model steps must be reapplied from the beginning. STEP 4. COST CALCULATION AND RECOMMENDATION The aim of Step 4 is to make an economic evaluation of the alternatives that comply with the main prerequisites. In an economic evaluation, two parameters are usually important: investment (USD millions) and electricity production cost (USD/MWhe). When evaluating different emission reduction technologies, a third parameter is equally important. This is the cost/ton emission removed: for example USD/ton sulfur removed and USD/ton NOx removed. An overview of the cost calculation recommendation step is given in Figure 9.6. Chapter 9. Technology Selection Model 126 Figure 9.6: Cost calculation recommendation - flow diagram Possible Alternatives Al Alt 2 At 3 etc. Investment Investment Investment Electricity Electricity Electricity production production production cost cost cost CostAonne Cost/tonne Cost/tonne emission emission emission removed removed removed Consider more Consider more Consider more stringent environ- stringent environ- stringent environ- mental require- mental require- mental require- ments ments ments Not recommended Recornrendationi Investment Data for estimating the investment for different alternatives is found in Chapters 2 to 6. The investment cost is a very important factor in the decision as to whether a project will be carried through. After filling in Table 9.8, the total investment for each alternative can be calculated. A Planner's Guide for Selecting Clean-Coal Technologies for Power Plants 127 Table 9.8: Sample table used for investment cost calculation Technology area Investment (MUSD) Alt. I Alt. 2 Alt.3 Alt.4 Alt.5 Combustion technology * SOx emission reduction NO, emission reduction Particulate emission reduction Total investment * Costs for a complete power plant except flue gas cleaning equipment. Electricity production cost The electricity production cost (USD/MWhe) is the price of electricity that is needed to achieve the required profit and is the sum of capital costs + variable operating costs + fixed operating costs + fuel costs. The electricity production cost also depends on economic assumptions that have to be stated for each project. Economic assumptions include rate of return, estimated inflation and economic lifetime. The production cost is just as important as the investment when deciding which process alternative to choose. The lower the production cost the better. Low variable costs are important when the plant has been built, since a plant with low variable costs can have a longer yearly operating time than one with high variable costs. Country specific taxes can also have a great impact on the electricity production cost but are not considered in this report. Operation and maintenance costs Table 9.9 can be used to calculate the total O&M cost for the alternatives. O&M cost data for the different technologies is found in Chapters 3 to 7. Table 9.9: Sample table used to calculate total O&M costs fixed (MUSD/yr) and Technology area variable (USc/kWh) O&M cost Alt. 1 Alt. 2 Alt.3 Alt.4 Alt.5 Combustion technology* SO, emission reduction NOx emission reduction Particulate emission reduction Waste handling Total O&M: fixed variable * Costs for a complete power plant except flue gas cleaning equipment. Table 9.10 lists data required for the calculation of electricity production cost. Typical economic data used for the calculation of production costs can be found in the case studies in Chapter 10. Chapter 9. Technology Selection Model 128 The availability factor for the combustion technology chosen (Chapter 3) can be used as the availability factor for the whole plant. Efficiency data for whole power plants can be found in Chapter 3 under each combustion technology. Table 9.10: Sample table used to calculate electicity production cost Data needed to calculate the electricity production cost Alt. I Alt. 2 Alt. 3 Alt. 4 Alt. 5 Construction period months Operating time hours/year Availability factor* % Coal price USD/MWh Electricity production MWe Plant net efficiency % Investment MUSD O&M costs fixed USD/ kWe variable USD/MWhe Rate of return % Economic lifetime years * Use data from Chapter 3 for whole plant. Calculate the yearly costs for fixed O&M, variable O&M and coal, and the investment. An example of the cost calculation is shown in Figure 9.7 below. In Figure 9.7, the calculation has been done in real terms, without inflation. Figure 9.7: Example: Investment, yearly costs of O&M and fuel cost 500- ce 00&M variable g O&M fixed 300 -- gcoal 200 - in\estment *0 Eu S100-E .S 0 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 Year A Planner's Guide for Selecting Clean-Coal Technologies for Power Plants 129 Next, estimate the average yearly electricity production volume considering annual operation time and the availability factor. Use the required rate of return and the economic lifetime defined in the project definition phase to: A. calculate the sum of the net present values of the investment, O&M costs, and fuel costs in USD: B. calculate the sum of the net present values of the amount of electricity produced during the economic lifetime of the plant in MWh; and C. obtain required levelized electricity price by dividing A by B. To find out how big portion of the electricity production cost that derives from fixed O&M, variable O&M, fuel and capital costs, respectively: calculate the sum of the net present value of each individual item (fixed O&M, variable O&M, fuel and capital cost) in USD. Divide each sum by B above. An example of how the total electricity production cost can be divided into these four types of costs is shown in Figure 9.8 below. Figure 9.8 Example: Contribution from fuel, O&M and capital cost to the total production cost 60-- 50-- 40-- o capital & 30-- IMMMMM&M variable DO&M fixed . 20g Coal 20-- 10- 0-1 Cost per ton emission removed To compare the cost-effectiveness of different emission reduction technologies, calculate the cost for each emission reduction technology/ton emission removed. For example, the cost of sulfur removal equipment/ton sulfur removed is derived by: Chapter 9. Technology Selection Model 130 A. calculating the sum of the net present values of the investment in SO, removal equipment and O&M costs related to SO. removal in USD; B. calculating the sum of the net present values of the yearly removed amounts of SO. from the plant in tons; and C. divide A by B to get the cost/ton sulfur removed. Recommendation The Fast Track Model produces a range of alternatives, each presented with information on investment (USD millions); electricity production cost (UScents/kWh ); flue gas cleaning cost (USD/ton SO. and NOx removed); emissions of SO., NO., and particulates, and by-products and waste. The two alternatives that are best from an economic and environmental standpoint should be recommended for further examination in a feasibility study. Although the current state of the law in India and China does not require the installation of flue gas cleaning equipment or the utilization of by-products, the emergence of environmental problems is changing the opinion of the authorities regarding these questions. More stringent environmental requirements can be expected to be imposed in the near future. When selecting technologies, it is essential to plan to meet increasingly strict pollution control legislation. It has to be possible to add pollution control equipment to a plant, and to have strategies available for the utilization of by-product. For example, space should always be set aside for the installation of additional equipment, such as wet FGD and SCR. A Planner's Guide for Selecting Clean-Coal Technologies for Power Plants 10. CASE STUDIES USING FAST TRACK MODEL This chapter presents two case studies: a greenfield plant and a boiler retrofit, where the Fast Track Model for technology selection is applied. Both cases focus on how the most suitable technologies are selected for the individual plant, depending on factors such as unit size, maturity of technology, requirements on waste product, annual operating hours, emissions, costs etc. GREENFIELD PLANT Step 1. Project definition The project presented below was initiated as a result of an increased demand for power and because new clean coal-fired power plants have become necessary. To meet up with the demand for power, a new plant with an electric output of 600-700 MW. will be built. The questions regarding which technologies to choose for this new plant are solved using the Fast Track Model. This is a greenfield coal fired plant located in China that will produce electricity only. The plant will have a base load function and use domestic anthracite as fuel. It is a commercial project meaning that only mature technologies will be used and the demands on availability are high. Although the environmental requirements applicable for this project are not very stringent, solutions with low emissions should be achieved to minimize the environmental impact of such a large new power plant. Tables 10.1-10.3 summarize the prerequisites that are valid for this project. Table 10.1: General prerequisites Type of project: commercial Plant * size: 600 MWe * number of units: 1-2 Coal * type: domestic anthracite * distance from domestic mine to power plant: approximately 1,200 km * value & range of main characteristics - ash content: 19-20% - sulfur content: 1% - heating value: 22.9- 24.4 MJ/ kg Date of commissioning: January 1, 2000 131 132 Table 10.2: Economic prerequisites Project economy * rate of return: 7% * economic lifetime: 20 years Financing policy: project financed Purchasing policy: turn-key Requirements on domestic as much as possible should manufacturing: manufactured domestically Table 10.3: Environmental prerequisites SO2: 2,500 Mg SO2/MJfuei stack height 240 m NOx: no requirements Particulate: 280 mg/Nm* stack height 240 m Other environmental policy: strive for low emissions Solid by-products/waste: solid waste will be disposed Table 10.4: Operational prerequisites Operation time: 6,000 hr/year Availability factor: 80% including overhaul Load change rate: 5% per minute Minimum load: 50% Step 2. Technology screening Technology screening is done using the criteria requirements found in Table 9.7 in Chapter 9. Screening is done to find applicable combustion technologies, S02, NO,, and particulate emission reduction technologies. Since this is a commercial project the requirements on maturity of technology are high. The size of the plant shall be such that the total plant size can be accommodated in one or two units. The waste products will be disposed. Table 10.5: Screening criteria for a greenfield coal fired power plant in China Technology Maturity of technology Required number Waste area of units product Combustion >10 commercial reference plants in China total plant size in 1-2 disposal units SO2 emission <10 commercial reference plants in China & - disposal control >10 reference plants worldwide NOx emission <10 commercial reference plants in China & - control >10 commercial reference plants worldwide Particulate >10 commercial reference plants in China - emission control I A Planner's Guide for Selecting Clean Coal Technologies for Power Plants 133 Applicable technologies The screening to find applicable technologies is done by comparing the requirements defined in Table 10.5 above with information in Chapters 3 to 6. This results in applicable technologies for this project according to Table 10.6. Note that sorbent injection, spray dry scrubbers and SNCR have mostly been used on smaller scale plants. Table 10.6: Applicable technologies for a 600-MW greenfield power plant in China Applicable Applicable combustion Applicable SO2 Applicable NO, particulate technologies emission control emission control emission control technologies technologies technologies * sub critical PC boilers * sorbent injection * low NOx burners * ESP * spray dry scrubbers * OFA * wet FGD * SNCR * SCR Step 3. Possible alternatives Coal quality The coal that will be used in this plant is a domestic anthracite. The ash content is low (19-20%). To purchase a coal with a higher quality to an additional price less than 0.4-0.55 USD/ton per lower ash content percentage, as stated in Chapter 2, Coal quality impact on power generation cost (page 9), is not possible. This means that the coal originally planned for this project will be used. Stating the possible alternatives Applicable technologies found in the technology screening step are used to find suitable power plant concepts. Four alternatives using different kinds of emission control equipment will be evaluated from a technical, environmental and economical point of view. The alternatives are presented in Table 10.7. Table 10.7: Possible alternative configurations of a greenfield 600-MWe power plant Technology Alternative 1 Alternative 2 Alternative 3 Alternative 4 Area * combustion * sub-critical PC * sub-critical PC * sub-critical PC * sub-critical PC technology * SOx emission * none * sorbent * wet FGD * wet FGD control injection * NOx emission * Iow-NOx * low-NOx * Iow-NOx * low-NOx burners, control burners & OFA burners & OFA burners & OFA OFA & SCR * particulate * ESP * ESP * ESP * ESP emission control Chapter 10. Case Studies Using Fast Track Model 134 Technical evaluation The alternatives that will be evaluated have to fulfill the prerequisites stated in Tables 10.1-10.4. Some of these prerequisites are gathered in Table 10.8 that shows how each alternative complies with the prerequisites. To find the outcome for each alternative, tables and information in Chapters 3 to 6 are used. As shown in Table 10.8, the NO, emissions are very high. This is a result of using anthracite as fuel. Anthracite is difficult to burn due to a very low content of volatile matter. To achieve stable and complete combustion, high temperatures in the combustion zone are necessary. As a result the NO, emissions become very high. Table 10.8: Evaluation of different alternatives against selected prerequisites Pre- Unit Altemative I Altemative 2 Altemative 3 Altemative 4 requisites S02 mg/mJ 850 430 100 100 NOx m_/MJ 300-400 300-400 300-400 80 Particulate m9yNmi 50 50 50 50 Solid Waste can be utilized disposal only can be utilized can be utlilized Domestic All parts can be Most parts can be Most parts can be Most parts can be manufacturing manufactured manufactured manufactured manufactured domesticaly domestically. domestically. domestically. Design of soren Design and Design and injection system manufacturing of manufacturing of will be iimported. FGD equipment FGD and SCR will be imported equipment will be imported. Note: Prerequisites defined in Tables 10.1-10.4. Alternatives are described in Table 10.7. Step 4. Cost calculation Investment cost calculation The investment cost for all alternatives is calculated by adding the cost for the different technology areas (Table 10.9). Electricity production cost O&M data necessary to calculate the electricity production cost for all alternatives are gathered in Table 10.10. These data are found in Chapters 3-6. A Planner's Guide for Selecting Clean Coal Technologies for Power Plants 135 Table 10.9: Investment cost calculation for a 600-MW greenfield power plant Investment Technology area MUSD Alt. 1 Alt. 2 Alt. 3 Alt. 4 Combustion technology* 650 650 650 650 SO, emission reduction - 45 90 90 NOx emission reduction - - - 45 Particulate emission reduction 30 30 30 30 Total investment 680 725 770 815 Note: (*)includes costs for complete power plant except flue gas cleaning equipment. Alternatives are described in Table 10.7. Table 10.10: Calculation of fixed and variable O&M costs for the different alternatives O&M Costs: Technology area Fixed (MUSD/year) Variable (UScents/kWh) Alt. 1 Alt. 2 Alt. 3 Alt. 4 Combustion technology * 16 16 16 16 0.2 0.2 0.2 0.2 SOx emission reduction - 3.6 7.5 7.5 0.3 0.17 0.17 NOx emission reduction - - - - - 0.35 Particulate emission reduction - - - 0.3 0.3 0.3 0.3 Total O&M: fixed 16 19.6 23.5 23.5 variable 0.5 0.8 0.67 1.02 Note: (*)includes costs for complete power plant except flue gas cleaning equipment. Alternatives are described in Table 10.7. The economical presumptions that are necessary to calculate the electricity production cost were stated in Tables 10.1-10.4. These economic presumptions and all other data necessary for the calculations are gathered in Table 10.11 below. Chapter 10. Case Studies Using Fast Track Model 136 Table 10.11: Data for calculating the electricity production cost for the different alternatives unit Alt. i Alt. 2 Alt. 3 Alt. 4 Construction period months 36 36 36 36 Operating time hours/year 6,000 6,000 6,000 6,000 Availability, incl. overhaul % 90 90 90 90 Coal price USD/MWh 7.2 7.2 7.2 7.2 Electricity production MWe 600 600 600 600 Plant net efficiency % 37 37 36.6 36.6 Investment MUSD 680 725 770 815 O&M costs: fixed MUSD/year 16 19.6 23.5 23.5 variable USclkWho 0.5 0.8 0.67 1.02 Rate of return % 7 7 7 7 Economic lifetime years 20 20 20 20 Based on information above the electricity production cost is calculated. As shown in Figure 10.1, alternative 4 results in the highest electricity production cost and alternative 1 the lowest. This is natural, since alternative 4 includes the most sophisticated emission control equipment. The figure shows that the electricity production cost varies between 55 USD/MWh and 67 USD/MWh depending on the extent of emission control equipment included. The emissions connected to each alternative are shown graphically in Figure 10.2. Figure 10.1: Calculated electricity production cost for the different alternatives 45-- 40-- 35-- 30-- *capital I25 --DO&M, 0 Wriable 2O&M, fixed "15 *Coal 10_ 5 -- 0 alt. 1 alt. 2 alt. 3 alt. 4 Note: Alternatives are described in Table 10.7. A Planner's Guide for Selecting Clean Coal Technologies for Power Plants 137 Figure 10.2: Emissions of SO2, NOx and particulate associated with each alternative 1000 - 800 - - 0 600 --SOx (mg SO2/MJ) ; NOx (mg N02/MJ) .- 400 - -- LU E particulate (mg/nm3) 200 0 alt.1 alt.2 alt.3 alt.4 Technology recommendation Result The result of the technical and economic evaluation is shown in Table 10.12 below. Both the investment and the electricity production cost increase with decreasing emissions. The table shows that the cost of sorbent injection in this case is 0.5 UScents/kWh, the cost of wet FGD is 0.7 UScents/kWh and the cost of SCR is 0.5 UScents/kWh. Table 10.12: Result of environmental, technical, and economic evaluation of different alternatives Unit Alt. I Alt. 2 Alt. 3 Alt. 4 Investment MUSD 680 725 770 815 Electricity production cost USc/kWh 5.5 6.0 6.2 6.7 Emissions SO2 Mg/MJfuel 850 430 100 100 NOx mg/MJfu,t 300 - 400 300 - 400 300 -400 80 particulate mg/nm 50 50 50 50 Note: Alternatives are described in Table 10.7. When the cost/ton of SO2 removed is calculated, sorbent injection removes sulfur at a cost of almost 1,400 USD/ton and wet FGD removes sulfur at a cost of 1,000 USD/ton. The cost of NOx reduced by the SCR in this case is 2,000 USD/ton NO2. Recommendation The recommendation is to followup with feasibility studies for alternative 2 and 3. Alternative I which is a plain plant without any emission control equipment except for an ESP, is eliminated due to higher emissions. Alternative 4 which includes a SCR system is eliminated due to higher costs. At this stage it is considered sufficient to use primary measures to reduce NOx emissions. Chapter 10. Case Studies Using Fast Track Model 138 Alternatives 2 and 3 both include sulfur emission control equipment. The difference is to what extent the SO2 is removed. A wet FGD plant is included in alternative 3 and sorbent injection in alternative 2. Comparison between alternatives 2 and 3 shows that wet FGD has the following advantages and disadvantages in comparison with a sorbent injection process: * higher removal efficiency, * higher investment and electricity production cost, and * lower cost/ton SO2 removed. When a high degree of desulfurization is needed, a wet system is more cost efficient. Both these alternatives shall be studied in more detail in the feasibility study. Special emphasis will then be made on the maturity of the sorbent injection technology. Possibility to comply with future more stringent environmental requirement. It is possible that the environmental requirements will become more stringent in the future. This means that if the plant will be built without a SCR system and without a wet FGD system, the layout of the plant shall be such that a future installation of a SCR system and a wet FGD is possible. BOILER RETROFIT Step 1. Project definition This project concerns retrofit of a 100-MWe oil-fired peak load power plant. The task is to upgrade the plant to a coal-fired base load plant. Due to high oil prices, the plant operating cost is very high, and therefore the acquired number of operating hours of the plant are few. The existing turbine and generator are in good condition and can be reused. After the retrofit, the plant must be able to meet more stringent emission requirements. The reconstruction work will include demolition of the existing oil-fired boilers and installation of a new coal-fired boiler in a new boiler house. The new boiler will be equipped with modern flue gas cleaning equipment. The major benefit of this project is that the capital cost for converting the existing plant to a base load plant is lower than building a new plant. This retrofit is project financed. In concern of a good project economy, the financing parties have posed high environmental requirements as to assure a long annual operation time and to avoid further refurbishment for environmental upgrade in the near future. The high environmental requirements are posed also for goodwill reasons. Therefore, in this project the environmental performance are more important than the maturity of technology. To summarize, the objectives for retrofit of the plant, as defined in Table 9.2, are reduced operating costs, increased unit availability, increased unit lifetime, and reduced environmental impact. A Planner's Guide for Selecting Clean Coal Technologies for Power Plants 139 The main prerequisites from Tables 9.3 through 9.6 are determined and the result is shown in Tables 10.13 through 10.16. These prerequisites will be used for technical and economical evaluation of different possible boiler and flue gas cleaning concepts. Table 10.13: General prerequisites Type of project: commercial Plant: * size: 100 MWe * number of units: 1 Coal: * type: domestic high volatile bituminous coal * ash content: 29.6 % * sulfur content: 1.8 % * heating value: 30.4 MJ/kg Date of commissioning: January 2000 Table 10.14: Economic prerequisites Project economy * rate of return: 7% * economic lifetime: 20 years Financing policy: project financing Purchasing policy: turn key Requirements on local as much as possible manufacturing: Table 10.15: Environmental prerequisites SO2: 160 mg/MJ (requirements of financing parties) NOx: 250 mg/MJ (requirements of financing parties) Particulate: 90 mg/MJ (requirements of financing parties) Wastewater: comply with World Bank requirements Solid by products/waste: wet or dry disposal Table 10.16: Operational prerequisites Operation time: 7,200 hr/yr Availability factor: 88% including overhaul period Load change rate: 4% per minute Minimum load: 40% Chapter 10. Case Studies Using Fast Track Model 140 Step 2. Technology screening Technology screening is done against criteria and selected requirements from Table 9.7. The screening is done in combustion technologies, SOx, NOx, and particulate emission reduction technologies (Table 10.17). Although this is a project-financed commercial project, the requirements on low investment cost combined with acceptable environmental performance are higher than the requirement on maturity of technology. The waste products will be used for landfill only. Table 10.17: Screening criteria for the retrofit of an oil-fired power plant Technology area Maturity of technology Waste product Combustion low requirements disposal SO, emission low requirements disposal NO, emission low requirements Particulate emission low requirements Applicable technologies The screening is done by comparing the requirements defined in Table 10.17 with the information in Chapters 3 to 7. The existing steam turbine is not designed for supercritical temperatures and pressure levels, which is why supercritical PC boiler technology is omitted. The following technologies are applicable in this case: Table 10.18: Applicable technologies for retrofit of a 100-MWe oil-fired boiler Applicable reduction technologies Applicable combustion SO, NO. Particulate technologies * Subcritical PC * sorbent injection * low NO, burners + OFA * ESP boiler * ACFB boiler * spray dry scrubber * SNCR * wet FGD * SCR Step 3. Possible alternatives Coal quality The coal that will be used in this plant is a domestic high volatile bituminous coal. The coal quality as defined in Table 10.13 is not very high. Although the ash and sulfur contents are high at 30- 31% and 1.8%, respectively, it is not possible to purchase a coal in the region with a higher quality at an additional price less than 0.4-0.55 USD/ton per lower ash content percentage, as stated in Chapter 2, Coal quality impact on power generation cost (page 9). This means that the coal originally planned for this project will be used. A Planner's Guide for Selecting Clean Coal Technologies for Power Plants 141 Stating possible alternatives Applicable technologies from the technology screening step are now combined to alternatives. In this step, SNCR and SCR are omitted as the requirements on NO. reduction are not high enough to justify the high investment and O&M cost of these technologies. Four alternatives with different kinds of emission reduction equipment and thereby different emissions and costs remain to be evaluated from a technical, economic and environmental point of view. The possible alternatives are described in table 10.16. Table 10.19: Different alternatives for retrofit of a 100-MWe oil-fired boiler Alt. I Alt. 2 Alt. 3 Alt. 4 Alt. 5 Combustion * ACFB * sub-critical PC * sub-critical PC * sub-critical PC * sub-critical PC technology SOx emission * none * wet FGD * spray dry * hybrid sorbent * furnace or reduction scrubber injection duct sorbent injection NOx emission * none * low-NO, * Iow-NO, burners * low-NOx * low-NO, reduction burners & OFA & OFA burners & OFA burners & OFA Particulate * ESP * ESP * ESP * ESP * ESP emission reduction Technical evaluation The alternatives have to fulfill the main prerequisites of the project as stated in Tables 10.13 through 10.16. Some of theses prerequisites and the outcome for each alternative are shown in Table 10.20 below. To find the outcome, tables and information in Chapters 3 to 6 are used. Table 10.20 shows that alternative 5 with furnace or duct sorbent injection will not comply with the SO2 emission requirement specified in Table 10.15. Alternative 5 will therefore be omitted from further investigation. Alternatives 3 and 4 using hybrid sorbent injection and a spray dryer will comply with the SO2 emission requirement only if these systems are designed for very high removal efficiencies. Chapter 10. Case Studies Using Fast Track Model 142 Table 10.20: Evaluation of the alternatives against certain main prerequisites Evaluation ag inst certain prerequisites Prerequisite Unit Alt. 1 Alt. 2 Alt. 3 Alt. 4 Alt. 5 SO2 mg SO2MJ fuel 120-60 120-60 120-355 240-120 590-355 NO, mg NOJMJ fuel 80-150 115-175 115-175 115-175 115-175 Particulate mg/Nm3 10-25 10-25 10-25 10-25 10-25 Solid waste can only be can only be can be utilized can be utilized can only be landfilled landfilled or landfilled landfilled Local Design of Most parts can Most parts Most parts All parts can manufacturing ACFB boiler be can be can be be must be manufactured manufactured manufactured manufactured imported but locally. Design locally. locally. locally. most parts and some Design of can be manu- manufacturing FGD factured of FGD equipment will locally. Design equipment will be imported. and some be imported. manufacturing of FGD equipment will be imported. Note: Main prerequisites defined in Tables 10.13-10.16. Alternatives are described in Table 10.19. Step 4. Cost calculation Investment cost calculation The investment cost for all remaining alternatives is calculated by adding the cost for the different technology areas (Table 10.21). For the hybrid sorbent injection system and the spray dryer in alternatives 3 and 4, respectively, a cost in the upper range is chosen as these SO2 removal systems have to be designed for very high removal efficiencies. Table 10.21 Investment cost calculation for retrofit of a 100-MWe oil-fired boiler Technology area Investment (MUSD) Alt. I Alt. 2 Alt. 3 Alt. 4 Combustion technology * 45 45 45 45 SO2 emission reduction 30 17 14 NO, emission reduction 3 3 3 Particulate emission reduction 5 5 5 5 Total investment 50 83 70 67 * Includes the cost for the boiler only, which is about 30% of the cost for a entirely new plant. Alternatives are described in Table 10. 19. A Planner's Guide for Selecting Clean Coal Technologies for Power Plants 143 Electricity production cost In order to calculate the electricity production cost for all remaining alternatives, O&M data and project specific economical data need to be found. Table 9.9 in chapter 9 is used to calculate the total O&M costs for the alternatives, as shown in table 10.22. Table 10.22: Calculation of fixed and variable O&M costs for the different alternatives. O&M cost Technology area fixed (MUSD/year) and variable (USckW) Alt. 1 Alt. 2 Alt. 3 Alt. 4 Combustion technology * 5.7 4.3 4.3 4.3 0.97 0.56 0.56 0.56 SO2 emission reduction - 1.2 0.9 0.6 - 0.15 0.3 0.3 NOx emission reduction - - - - Particulate emission reduction 0.5 0.5 0.5 0.5 Total O&M: fixed 6.2 6.0 5.7 5.4 variable 0.97 0.71 0.86 0.86 * Includes cost for combustion system, steam cycle and balance of plant. The economical presumptions that are necessary to calculate the electricity production cost were stated in Tables 10.13-10.16. These economic presumptions are listed in Table 10.23 along with other economic data for each specific case from Tables 10.21-10.22. Table 10.23: Data for calculating the electricity production cost for different alternatives Data needed to calculate the electricity production cost unit Alt. I Alt. 2 Alt. 3 Alt. 4 Construction period months 36 36 36 36 Operating time hours/year 7,200 7,200 7,200 7,200 Availability factor % 88 88 88 88 Coal price USDMWh 7.2 7.2 7.2 7.2 Electricity production MW. 100 98.5 99.25 99.75 Plant net efficiency % 37.5 37 37.3 37.5 Investment MUSD 50 83 70 67 O&M costs fixed USDIyear 6.2 6.0 5.7 5.4 variable USclkWh,o 0.97 0.71 0.86 0.86 Interest rate % 7 7 7 7 Economic lifetime years 20 20 20 20 Chapter 10. Case Studies Using Fast Track Model 144 With data from Table 10.23, the electricity production cost is calculated. As shown in Figure 10.3, production costs are highest for alternative 2 and lowest for alternative 1, although all alternatives are fairly close. It is natural that alternative 2 results in a higher production cost than alternatives 3 and 4 since it includes more advanced sulfur removal equipment. Clearly, such an advanced system is not economical for a boiler of this size. However, it is interesting to note that alternative 1 with a ACFB boiler, results in lower production cost that any alternative with a PC boiler. The figure shows that electricity production cost varies between 35 USD/MWh and 41 USD/MWh. Figure 10.3: Calculated electricity production cost in USD/MWh for the different alternatives 45-- 40-- 35 -_- 30-- M capital 3 25 0O&M, wriable 20 -O&M,liixed 15 Coal 10 5- 0- alt. 1 alt. 2 alt. 3 alt. 4 Note: Alternatives are described in Table 10.19. The emissions corresponding to each alternative are shown graphically in Figure 10.4. All alternatives can comply with the environmental requirements specified in Table 10.15, but alternative 1 results in the lowest emissions. A Planner's Guide for Selecting Clean Coal Technologies for Power Plants 145 Figure 10.4: Emissions of SO,, NOx and particulate for each alternative 160 - 1 40 --g 120 - 10__ MSOx (mgSO2/MJ) o 'NOx (mg N02/MJ) a80 - .T) N particulate (mg/nm3) E 60 -- 4 40- 20- alt. 1 alt. 2 alt. 3 alt. 4 Technology recommendation Result The result of the technical and economical evaluation is shown in Table 10.24. For the PC boiler options, both investment and electricity production costs increase with decreasing emissions. An interesting result is that the ACFB boiler, which has the lowest emissions, appears to be the most economical choice. Table 10.24: Result of the technical and economical evaluation for the different alternatives Unit Alt. 1 Alt. 2 Alt. 3 Alt. 4 Investment MUSD 50 84 68 64 Electricity production cost USc/kWh 3.5 4.1 3.8 3.7 Emissions SO2 mg/MJ 90 90 160 160 NO, mg/MJ 115 145 145 145 particulate mg/Nm3 25 25 25 25 Note: Alternatives are described in Table 10.19. When the cost/ton of S02 removed is calculated, hybrid sorbent injection removes sulfur at a cost of almost 370 USD/ton. The cost with a spray dryer is 470 USD/ton and wet FGD removes sulfur at a cost of 680 USD/ton. The nature of the ACFB alternative is such that the cost for SO2 reduction can not be separated from the total cost. Recommendation The first recommendation is to study alternative 1, a ACFB boiler, more in a detailed feasibility study. The technology is not yet mature in India and China, but the process has the best Chapter 10. Case Studies Using Fast Track Model 146 environmental performance at the lowest cost. These characteristics are more important to the financing parties than maturity of technology. Alternatives 2, 3 and 4 all include a PC boiler with sulfur emission reduction equipment. The recommendation at this point, is to further investigate alternative 3, with a spray dry scrubber. A wet FGD plant as included in alternative 2 can easily be designed to comply with the sulfur removal requirement. However, this alternative has the highest investment and electricity production cost and should therefore be eliminated. The wet FGD technology is not competitive for such small boilers. The sulfur removal systems of alternatives 3 and 4 both have to be designed for very high efficiencies if they are to comply with the sulfur removal requirement. Alternative 4 with a hybrid sorbent injection system has the lowest investment and results in the second lowest electricity production cost. If a hybrid sorbent injection system of satisfying efficiency can be designed, this alternative could be interesting to study further, but since there are very few reference plants, this technology represents many uncertain parameters. The cost difference between spray dry scrubber and hybrid sorbent injection is very small and the spray dry scrubber technology is more proven. Therefore, alternative 3, a PC boiler with a spray dry scrubber, is recommended for a feasibility study along with alternative 1. Possibility to comply with future more stringent environmental requirements It is possible that the requirements on NO. reduction will become more stringent in the future. Therefore the layout of the plant shall be such that a future installation of a SCR system is possible. A Planner's Guide for Selecting Clean Coal Technologies for Power Plants 11. ENVIRONMENTAL GUIDELINES AND REQUIREMENTS PROPOSED WORLD BANK REQUIREMENTS The proposed guidelines from the World Bank (Ref 1) apply to fossil fuel-based thermal power plants or units of 50 MWe or larger. In these guidelines, primary attention is focused on emissions of particulates less than 10 microns (pim) in size (PM10), on sulfur dioxide and on nitrogen oxides. It is also stated that in order to minimize the emission of greenhouse gases, preference may be given to the use of natural gas as a fuel. Air pollution The levels set in the guidelines on air pollution can be achieved by adopting a variety of low-cost options or technologies, including the use of clean fuel. In general, the following measures should be seen as the minimum that need to be taken: * dust control capable of 98-99% removal efficiency, such as fabric filters or electrostatic precipitators should always be installed; * low NO,, burners combined with other combustion modifications should be standard practice; * the range of options for control of SO2 is greater depending largely on the sulfur content in each specific fuel: - below 1% sulfur, no control measures are required; - between 1 and 3% sulfur, coal cleaning and sorbent injection or fluidized bed combustion may be adequate; and - above 3% sulfur, flue-gas desulfurisation or other clean coal technologies should be considered. The limit values set shown in Table 11.1 represent a basic minimum standard; more stringent emission requirements will be appropiate if the environmental assessment (EA) indicates that the benefits of additional pollution controls, as reflected by ambient exposure levels and by other indicators of environmental damage, outweigh the additional costs. All emission requirements should be achieved for at least 95% of plant operation time, averaged over monthly periods. Though metals are not listed in the emission requirements below, they should be addressed in the EA when burning some types of coal or heavy fuel oil which may contain cadmium, mercury etc. 147 148 Table 11.1: Maximum emission limits for coal-fired thermal power plant set by World Bank Pollutant Removal Concentration Specific emission levels effiency mgrn3 (ndg) tons/day/MW PM10 99% 50 - NOx 40% 750 (6% excess 02 - assumes 350 Nm3/GJ) SO2 2,000 0.20 (0.1 recommended for incremental above 1,000 MWe). Source: World Bank (1996) Ambient air The World Bank also states that, in the long-term, countries should ensure that ambient exposure to particulates (especially to PM10), nitrogen oxides and sulfur dioxide should not exceed the WHO recommended guidelines. These recommendations are summarized in Table 11.2. Table 11.2: WHO recommendations for ambient air quality Pollutant Max. emission increment, Max. emission increment, 24-hour mean value [mg/mn] annual average [mg/m] S02 100-500* 10-50* NO 500 100 Particulates 100-150* - * Actual values depend on background levels of sulfur and dust. Maximum allowable incremental emission is low in higly polluted areas and vice versa. Source: WHO (1987). However, in the interim, countries should set ambient standards which take into account benefits to human health of reducing exposure to particulates, NOx and SO2, concentration levels achievable by pollution prevention and control measures, and costs involved in meeting the standards. For the purpose of carrying out EAs, countries should establish a trigger value for ambient exposure to particulates. This trigger value is not an ambient air quality standard, but is simply a threshold which, if it is exceeded in the area affected by the project, will mean that a regional and/or sectoral EA should be carried out. The trigger value may be equal to or lower than the country's ambient standard for particulates, nitrogen oxides and sulfur dioxide, respectively. Water pollution For liquid effluents from thermal power plants (both direct and indirect waste or cooling water) the following levels should be achieved, shown in Table 11.3. A Planner's Guide for Selecting Clean-Coal Technologies for Power Plants 149 Table 11.3: Emission limit values for some parameters in effluents from thermal power plants. Parameter Maximum value pH 6-9 Suspended solids 50 mg/I Oil and grease 10 mg/I Total residual chlorine 0.2 mg/I Chromium, total 0.5 mg/I Chromium, hexavalent 0.1 mg/I Copper 0.5 mg/I Iron 1.0 mg/I Nickel 0.5 mg/1 Zinc 1.0 mg/ Temperature increase < 30C* * This should be considered at the edge of the zone where initial mixing and dilution takes place. If the zone is not defined, 100 meters from the point of discharge should be used. Source: World Bank (1996). CHINESE REQUIREMENTS There is a national standard in China that regulates emissions from coal-fired power plants. This standard is called "Emission standards of air pollutants for coal-fired power plants" and it regulates emissions of S02 and particulates, but does not yet include standards for NOx emissions. There is also a standard on ambient air quality which regulates both SO2 and NOx concentrations, which is described below. China has a standard regulating water pollution in integrated wastewater discharges and a standard on how to secure surface water quality in water bodies with variable sensitivity. These Chinese standards are listed in Ref 2. Air pollution The Chinese standard on air pollutants only depends on the height of the emission source using the dispersal ability of the atmosphere to secure ambient air quality. This means wind speed at the outlet of the emission is taken into account when deciding the neccesary stack height. The characteristics of the area (urban or rural, hilly or plain) are also taken into account. Boiler type, type of cleaning devices and ash content in coal also have an impact on the limit values as does whether it is an existing plant or a new installation. If the Chinese regulations are translated into emissions per energy input or volume of flue gas, the following (Table 11.4) emission limit values are allowed for a new installation with a stack height of 240 meters. There are also provincial standards in China concerning air pollution which are sometimes more stringent than the national standards. Chapter 11. Environmental Guidelines and Requirements 150 Table 11.4: Emission limit values for coal-fired power plants Emission per net energy Emission per m3 (ndg) Parameter Tons per hour input if 6% 02 content mg/MJ mg/m3 SO2 14.6 2,500 6,800 Particulates 0.56 100 273 Source: Chinese standards listed in Ref. 2. Ambient air quality The standard for ambient air quality is divided into three different levels. There are both 24 hour mean limit values and momentary limit values, for dust (PM,o), SO2 and NOx. The different levels are described in Table 11.5. Table 11.5: Ambient air quality levels. Level I The air does not effect the nature or the health of humans even after long-term exposure. Level 2 The air does not have a harmful effect on the health of humans or the environment, in cities or in the countryside no matter what length of time of exposure. Level 3 The air is not acute or chronically toxic for humans and admits a normal variety of flora and fauna in cities. Source: Chinese standards listed in Ref. 2. Linked to the different levels, land areas are divided into three categories with respect to geography, climate, ecosystem, politics, economy and air quality. Category 1 includes national nature reserves, tourist areas, historical localities and recreational resorts. Category 2 includes cities and the countryside and Category 3 includes localities or industrial sites where the level of air pollutants is high, or areas with heavy traffic. The ambient air quality for some pollutants can be seen in Table 11.6. Table 11.6: Ambient air quality standard for dust, SO2 and NOx. Normal dry gas Level I Level 2 Level 3 (gm J [MgIrn37 [Mg#n3] PM10 24-hour mean value 0.05 0.15 0.25 Occasional basis* 0.15 0.50 0.70 SO2 24-hour mean value 0.05 0.15 0.25 Occasional basis* 0.15 0.50 0.70 NOx 24-hour mean value 0.05 0.10 0.15 Occasional basis* 0.10 0.15 0.30 * Limit values should not be exceeded at any time. Source: Chinese standards listed in Ref. 2. A Planner's Guide for Selecting Clean-Coal Technologies for Power Plants 151 Water pollution There is one standard for integrated wastewater discharge which is linked to a standard on environmental quality for surface water. Depending on the characteristics of the intake water as well as those of the water body receiving the wastewater, the standard is divided into three levels with different limit values for pollutants. However, the limit values of some serious pollutants in wastewater are the same for all levels. In Table 11.7 below, the substances which are not included have been added and given as an interval depending on the level as described above. The highest values represent the limit values for level 3 which represents wastewater sent to a sewage treatment plant or for biological treatment. The interval for pH is valid for all levels. Table 11.7: General limit values for certain parameters in wastewater Parameter Limit value pH 6-9 Suspended solids 70 - 400 mg/1 Oil and grease 10 - 30 mg/I Chromium, total 1.5 mg/I Chromium, hexavalent 0.5 mg/I Copper 0.5 - 2.0 mg/1 Nickel 1.0 mg/ Zinc 2.0 - 5.0 mg/1 Source: Chinese standards listed in Ref. 2. For some industries, specific limit values are valid, according to the integrated wastewater standard. Power plants are not included in this list. The discharge of water used for cooling purposes is restricted according to the environmental quality standard for surface water, where all kinds of influence by human is included. No specification is connected with the limit values. The maximum increase in temperature is 1oC in summer and the maximum decrease of temperature in winter is 20C, as weekly mean values. INDIAN REQUIREMENTS The Government of India has issued guidelines which require all thermal power plants to obtain a "No objection Certificate" from the relevant State Pollution Control Board before a "Letter of Intent" is converted into a license. The Ministry of Environment and Forests has to give the statutory clearance for setting up the power plant. Documents that describe Indian requirements are listed in Reference 3. Air pollution In India there are only standards on dust emission from power plants and no general emission levels given on NOx or SO2 The dust emission standard adopted for thermal power plants in India is described in the Table 11.8. Chapter 11. Environmental Guidelines and Requirements 152 Table 11.8: Dust limit values for power plants Boiler size Emission standards in India MW mgrn3 (ndg) Old* New Protected area <210 600 350 150 L210 - 150 150 * Boilers with electrostatic precipitators installed before December 31, 1979. Source: Central Pollution Control Board (1984, 1986). However, to secure an acceptable ambient air quality with respect to SO2 the power plant has to fulfill the following demands on stack heights, shown in Table 11.9. In general, Indian coal is characterized by high ash content (more than 40%) and a low sulfur content (well below 1%). The effort to limit environmental impact has, thus, been mainly addressed to particulate emissions. Table 11.9: Requirements on stack height due to boiler size Boiler size Stack height MW m < 200/210 H=14 x Qu-" 200/210-500 220 2 500 275 Note: Q = SO2 emission in kg per hour. Source: Central Pollutinn Control Board (1984, 1986). Ambient air quality The national ambient air quality standard in India defines ambient air quality requirements in different areas, as shown in Table 11.10. Water pollution India also has standards for liquid effluents from thermal power plants, shown in Table 11.11. The limit values are set for parameters that are applicable to each effluent, eg. condenser cooling water, boiler blowdown, and cooling tower blowdown. Table 11.10: Ambient air quality for different locations Category Particulates S02 NO, pg/M3 Pgm3 Industrial area * annual average 360 80 80 * 24 hours 500 120 120 Residential and rural * annual average 140 60 60 * 24 hours 200 80 80 Sensitive * annual average 70 15 15 * 24 hours 100 30 30 Source: Central Pollution Control Board (1994). A Planner's Guide for Selecting Clean-Coal Technologies for Power Plants 153 Table 11.11: Limit values for parameters in wastewater discharges Parameter Limit values pH 6.5-8.5 Temperature increase* 50C Free available chlorine 0.5 mg/I Suspended solids 100 mg/1 Oil and grease 20 mg/I Copper 1.0 mg/I Iron 1.0 mg/1 Zinc 1.0 mg/1 Chromium , total 0.2 mg/1 Phosphate 5 mg/I Note: (*) Compared with intake water temperature. Source: Central Pollution Control Board (1986). SUMMARY OF ENVIRONMENTAL REQUIREMENTS The environmental requirements on power plants are less strigent in China and India compared with the World Bank guidelines. Neither India or China stipulates the reduction of NOx emissions and both rely on stack height and dispersion effects to a large extent in the case of emissions of particulates and SO2. The ambient air quality standards in China and India are in the same range as the WHO recommendations as referred to by the World Bank. Regulations on water pollution in China and India are less stringent than those of the World Bank concerning suspended solids and oil and grease. On heavy metals the limit values are less stringent in China, but in India the limit values are rather more stringent than the World Bank requirements. Chapter 11. Environmental Guidelines and Requirements 154 REFERENCES 1. World Bank. 1996. "Proposed Guidelines for New Fossil Fuel-based Plants." Pollution Prevention and Abatement Handbook - Part III Thermal Power Plants. Washington, DC. 2. Chinese standards. Beijing, China. Ambient Air Quality Standard. GB 3095-1982. Emission Standards ofAir Pollutants for Coal-fired Power Plants. GB 13223-1991. Environmental Quality Standardfor Surface Water. GB 3838-1988 Integrated Wastewater Discharge Standard. GB 8978-1988. 3. Central Pollution Control Board. Delhi. India. 1994. Ambient air quality in India. 1984 and 1986. Emission standards for thermal power plants. 1986. Standards for liquid effluents in thermal power plants. 4. World Health Organization. 1987. Air Quality Guideliness for Europe. Regional Publications, European Series No. 23, Copenhagen, Denmark. A Planner's Guide for Selecting Clean-Coal Technologies for Power Plants APPENDIX. COAL CLEANING METHODS A coal cleaning plant may consist of different reduction, cleaning and dewatering/drying methods. Different combinations may also be used. The basic commercial cleaning methods, as well as environmental considerations in general, are described in the following section. Jigs The methods operate by differences in specific gravity. Jigs rely on stratification in a bed of coal when the carrying water is pulsed. The shale tends to sink, and the cleaner coal rises. The basic jig, Baum Jig, is suitable for larger feed sizes. Although the Baum Jig can clean a wide range of coal sizes, it is most effective at 10-35 mm. A modification of the Baum Jig is the Batac Jig which is used for cleaning fine coals. The coal is stratified by bubbling air directly through the coal- water-refuse mixture in this cleaning unit. For intermediate sizes the same principles are applied, although the pulsing may be from the side or from under the bed. In addition, a bed or hard dense mineral is used to enhance the stratification and prevent remixing. The mineral is usually feldspar, consisting of lumps of silicates of about 60 mm size. Figure Al shows a Baum Jig and a feldspar jig for finer coal. Jigs offer cost effective technology with a clean coal yield of 75-85 % at about 34 % ash content. The jigs are used more frequently than dense-medium vessels because of their larger capacities and cheaper costs. Figure Al: Baum jig and a feldspar jig for fine coal stratification zone air pulsations feldspar bed clean coal screen plate -watier Baum-type jig is used for cleaning coarse coal, Feldspar-bed jig with water as the medium is used for fine coal Source: Couch (1991). 155 156 Dense-medium separators Dense-medium vessels also operate by specific gravity difference; however, rather than using water as the separation medium, a suspension of magnetite and water is used. This suspension has a specific gravity between that of coal and the refuse and a better separation can be obtained. The slurry of fine magnetite in water can achieve relative densities up to about 1.8. Different types of vessels are used for dense-medium separators such as baths, cyclones and cylindrical centrifugal separators. For larger particle sizes, various kinds of baths are used, but these require a substantial quantity of dense-medium, and therefore of magnetite. For smaller sizes, cyclones are used where the residence time is short and throughput relatively high. Cylindrical centrifugal separators are used for coarse and intermediate coal. Dense-medium cyclones clean coal by accelerating the dense-medium, coal and refuse by centrifugal force. The coal exits the cyclone from the top and the refuse from the bottom. Better separation of smaller-sized coals can be achieved by this method. Key factors in the operation of any dense-medium system based on magnetite are the control equipment and the efficiency of magnetite recovery for recycle. There can be a build-up of other minerals in the medium, making control more difficult. Figure A2 shows example of a dense- medium bath and a dense-medium cyclone. Figure A2: Dense-medium separators 00 5XZ clean coal heavy medium .*eo plus coal feed raw coal clean coal *(. dense medium 00-~~ ~ ~~ r .,we.L0.4s ***. ***. e.refuse Dense-medium bath Dense-medium cyclone Source: Couch (1991). A Planner's Guide for Selecting Clean-Coal Technologies for Power Plants 157 Hydrocyclone Hydrocyclones are water-based cyclones where the heavier particles accumulate near the walls and are removed via the base cone. Lighter (cleaner) particles stay nearer the center and are removed at the top via the vortex finder, see Figure A3. The cyclone diameter has a significant influence on the sharpness of separation. Figure A3: Hydrocyclone clean coal 0 00 105 water slurry' oqIa I o 616 vortex * finder 4 P 0 **refuse v* Source: Couch (1991). Appendix. Coal Cleaning Methods 158 Concentration tables Concentrating tables are tilted and ribbed and they move back and forth in a horizontal direction. The lighter coal particles are carried to the bottom of the table, while the heavier refuse particles are collected in the ribs and are carried to the end of the table, see Figure A4. Fine coal can be cleaned inexpensively with this unit, however, the capacity is quite small and they are only effective on particles with specific gravities greater than 1.5. Figure A4: Concentration table near-density material shale water feed pyrite water /j riffles motion clean coal aW Source: Couch (1991) A Planner's Guide for Selecting Clean-Coal Technologies for Power Plants 159 Froth flotation Froth flotation is the most widely-used method for cleaning fines. Froth flotation cells utilize the difference in surface characteristics of coal and refuse to clean ultra fine coal. The coal-water mixture is conditioned with chemical reagents so that air bubbles will adhere only to the coal and float it to the top, while the refuse particles sink. Air is bubbled up through the slurry in the cell and clean coal is collected in the froth that forms at the top. Figure A5 shows an example of froth flotation. This type of cleaning is very complex and expensive and is principally for metallurgical coals. One of the commonest stepz to improve the performance of a flotation unit is to separate the pyrite at an earlier stage using cyclones, spirals or tables. Figure AS: Froth flotation air ~ motor driven clean coal 0 to a froth collection feed rotor t stator refuse Source: Couch (1991). Appendix. Coal Cleaning Methods 160 Dry cleaning The dry coal preparation technique uses an air dense fluidized bed which makes use of the character of an air-solid fluidized bed-like liquid. The uniform and stable air-solid suspension is formed, which processes a certain density, light and heavy feed is separated by density in suspension. The low density material floats up to the top and the high density material sinks down to the bottom. Two qualified products are obtained after separating and removing the magnetite. The separator is comprised of an air chamber, an air distributor, a separating vessel as well as a transportation scraper. In the separating process the screened (6-50 mm) coal and dense medium are fed into the separator, the compressed air from an air receiver is provided to the air-chamber, and then uniformly to the distributor which fluidize the dense- medium. The comparative stable fluidized air-solid suspension which processes a certain density is formed under certain technical conditions. The feed is stratified and separated according to its density. The separated materials are transported in counterflow. In Figure A6, the floated light product such as clean coal is discharged to the right, and the sunken heavy product to the left. Figure A6: Schematic diagram of a dry separator with an air dense medium fluidized bed Feed Dust Dust coal Dense extraction extractiont 6-50 mm mium T0 TTTTTTTT1W i W1T cean O OO coal Refuse 1FPo T TT Air from compressor Source: Couch (1995b). REFERENCES 1. Couch, G. 1991. Advanced coal cleaning technology. IEA Coal Research. International Energy Agency. London, UK. 2. Couch, G. (1995b). Personal communication. IEA Coal Research. International Energy Agency. London, UK. A Planner's Guide for Selecting Clean-Coal Technologies for Power Plants Distributors of COLOMBIA GERMANY ISRAEL NEPAL PORTUGAL SWEDEN Doiinlace LIda. UNO-Vedag Yozmot Literature Ltd. Everest Media Intemational Services (R) Ltd. LiraIa Portugal WenoergrenWilliams AB W orld Bank Carrera6No.51-21 PoppelsdorlerAslees 2. Boxan 5 GPO aonlrte Apaxdado 2681, Rua Do Camo 70-74 R Box 1305 Apartedo Aereo 34270 53115 Boon 3 Youran Hasandlar Street Kathmandu 1200 Lisbon S-171 25 Sobna Publications Santafi de Bogol, D.C. 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Plakna 31/37 10, SirChiffampalanGardinerMavaotha Harae Tel: (86 10) 6333-8257 75116 Paris 4-5 Harcourt Road Tel: (52 5) 624-2800 00-477 Warzawa ColobD2 Tel(263 4) 6216617 Fax: (86 10) 6401-7365 Tel: (33 1) 40-69-30-56/57 Dublin 2 Fax: (52 5) 624-2822 Tel: (48 2) 628-6089 Tel: (94 1) 32105 Fax: (263 4) 621670 Fax: (33 1) 40-69-30-68 Tel: (353 1) 661-3111 E-mail: infotec@tln.netimx Fax: (48 2) 621-7255 Fax: (94 1) 432104 Fax: (353 1) 475-2670 URL: httpi/rn.set.mx E-mail: books%ips@ikp.atm.com.pl E-mail: LHL@sri.lanka.net -s UAL htlpv/www pscgwaw.plipWexporV x RECENT WORLD BANK TECHNICAL PAPERS (continued) No. 345 Industry and Mining Division, Industry and Energy Department, A Mining Strategy for Latin America and the Caribbean No. 346 Psacharopoulos and Nguyen, The Role of Government and the Private Sector in Fighting Poverty No. 347 Stock and de Veen, Expanding Labor-based Methods for Road Works in Africa No. 348 Goldstein, Preker, Adeyi, and Chellaraj, Trends in Health Status, Services, and Finance: The Transition in Central and Eastern Europe, Volume II, Statistical Annex No. 349 Cummings, Dinar, and Olson, New Evaluation Procedures for a New Generation of Water-Related Projects No. 350 Buscaglia and Dakolias, Judicial Reform in Latin American Courts: The Experience in Argentina and Ecuador No. 351 Psacharopoulos, Morley, Fiszbein, Lee, and Wood, Poverty and Income Distribution in Latin America: The Story of the 1980s No. 352 Allison and Ringold, Labor Markets in Transition in Central and Eastern Europe, 1989-1995 No. 353 Ingco, Mitchell, and McCalla, Global Food Supply Prospects, A Background Paper Prepared for the World Food Summit, Rome, November 1996 No. 354 Subramanian, Jagannathan, and Meinzen-Dick, User Organizations for Sustainable Water Services No. 355 Lambert, Srivastava, and Vietmeyer, Medicinal Plants: Rescuing a Global Heritage No. 356 Aryeetey, Hettige, Nissanke, and Steel, Financial Market Fragmentation and Reforms in Sub-Saharan Africa No. 357 Adamolekun, de Lusignan, and Atomate, editors, Civil Service Reform in Francophone Africa: Proceedings of a Workshop Abidjan, January 23-26, 1996 No. 358 Ayres, Busia, Dinar, Hirji, Lintner, McCalla, and Robelus, Integrated Lake and Reservoir Management: World Bank Approach and Experience No. 360 Salman, The Legal Framework for Water Users' Associations: A Comparative Study No. 361 Laporte and Ringold. Trends in Education Access and Financing during the Transition in Central and Eastern Europe. No. 362 Foley, Floor, Madon, Lawali, Montagne, and Tounao, The Niger Household Energy Project: Promoting Rural Fuelwood Markets and Village Management of Natural Woodlands No. 364 Josling, Agricultural Trade Policies in the Andean Group: Issues and Options No. 365 Pratt, Le Gall, and de Haan, Investing in Pastoralism: Sustainable Natural Resource Use in Arid Africa and the Middle East No. 366 Carvalho and White, Combining the Quantitative and Qualitative Approaches to Poverty Measurement and Analysis: The Practice and the Potential No. 367 Colletta and Reinhold, Review of Early Childhood Policy and Programs in Sub-Saharan Africa No. 368 Pohl, Anderson, Claessens, and Djankov, Privatization and Restructuring in Central and Eastern Europe: Evidence and Policy Opiions No. 369 Costa-Pierce, From Farmers to Fishers: Developing Reservoir Aquaculture for People Displaced by Dams No. 370 Dejene, Shishira, Yanda, and Johnsen, Land Degradation in Tanzania: Perception from the Village No. 371 Essama-Nssah, Analyse d'une rpartition du niveau de vie No. 373 Onursal and Gautam, Vehicular Air Pollution: Experiences from Seven Latin American Urban Centers No. 374 Jones, Sector Investment Programs in Africa: Issues and Experiences No. 375 Francis, Milirno, Njobvo, and Tembo, Listening to Farmers: Participatory Assessment of Policy Reform in Zambia's Agriculture Sector No. 376 Tsunokawa and Hoban, Roads and the Environment: A Handbook No. 377 Walsh and Shah, Clean Fuels for Asia: Technical Options for Moving toward Unleaded Gasoline and Low-Sulfur Diesel No. 382 Barker, Tenenbaum, and Woolf, Governance and Regulation of Power Pools and System Operators: An International Comparison No. 385 Rowat, Lubrano, and Porrata, Competition Policy and MERCOSUR No. 386 Dinar and Subramanian, Water Pricing Experiences: An International Perspective No. 388 Sanjayan, Shen, and Jansen, Experiences with Integrated-Conservation Development Projects in Asia No. 389 International Commission on Irrigation and Drainage (ICID), Planning the Management, Operation, and Maintenance of Irrigation and Drainage Systems: A Guide for the Preparation of Strategies and Manuals i� ►� 1вв• �;� 1 Т Н Е W О R L D В А N К I�1� 11 �и��ь \ \1 \1,,.! �г .,1+гii, 1)ь ?ььЭ;.; 1 ~\ I.1���1i,гn�', ,_'1ь? i-; � .',;I f i���.i п�1� '!ь' 1; ьг.i+>1 1, , , Aj1 J i�Э1 {� \\� �l�1 1 �1t \\h �1г 1 .'I��'.�;A��)1i1 1�1;A\1. \\�гi1.ь1\и. \\.'� Iri!'� „„,+�,`.+i1�I!г,,ii�, , � �1г �iI 1ьп i��, . ��i�г�1+,=11�, гг1�, SWEt�POWER А8 �+�ь 1; ,.�1 � ��ь� 'и 1i,г.i.г,�,Iг,� , `.', �. , l 1 1 ����ь �'+Iп:�г�' � 11, A г+� i 1+: t111 � I , i 74065 ' i !I, � I 'i I ' I i ��� � 1 J I I� :1: 1. 1SBN 0-5213-4065-4