schematic pulverized coal fire power triturador 100 tph

schematic pulverized coal fire power triturador 100 tph

schematic pulverized coal fire power. Given complete mixing, a precise or stoichiometric amount of air is required to completely react with a given quantity of fuel In practice, combustion conditions are never ideal,, The boiler system in consideration is a 500MW pulverized coal fired utility boiler Schematic diagram of the boiler is shown in Figure 1 The boiler is of drum

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power plant schematic coal crusher - coal mill. schematic figure of coal mill in a .... schematic pulvuriser for coal - Newest Crusher, Grinding Mill, Mobile Crusher. schematic pulverized coal fire power - ROYAL TELE SHOPPING. THERMAL POWER PLANT SCHEMATIC DIAGRAM How a Coal-fired Power Plant works: . (2 inches) in size. ...

schematic diagram of coal power plant . Coal Power Plant Schematic Diagram ~ Coal Energy Apr 08 2010 This entry was posted on October 4 2009 at 12 14 pm and is filed under Coal Power Plant Schematic Diagram Follow any responses to this post through RSS You can leave a response or. A Coal-Fired Thermoelectric Power Plant USGS

Pulverised Coal Combustion. Pulverized coal combustion takes place within the vertical vortex system as depicted in sixteen pulverized-coal burners with an opposite-fired shifted arrangement are located at two levels. From: Power Plant Instrumentation and Control Handbook (Second Edition), 2019. Related terms: Energy Engineering; Boiler ...

2020-10-15Coals ability to supply power during peak power demand either as base power or as off-peak power is greatly valued as a power plant fuel. It is with this fact that advanced pulverized coal fired power plants are designed to support the grid system in avoiding blackouts.

A coal-fired thermal power station is a power plant in which the prime mover is steam driven. Water is heated, turns into steam, and spins a steam turbine, which drives an electrical generator, as schematically shown in Fig. 1.9.After it passes through the turbine (one to three stage), the steam is condensed in a condenser and recycled to where it was heated; this is known as a Rankine cycle.

2017-2-11Pulverized coal fired boilers use coal of several tens of micrometers in size and then fire such pulverized coal in a suspended state inside the boiler furnace. Roller mills are commonly used as pulverizers due to their low power consumption. They pulverize coal between a roller and a rotating pulverizing table. To meet societys needs for

2019-12-10The schematic of the reference PF power plant repowered with pressurized pulverized coal combustion is shown in Fig. 9 and the corresponding stream data is presented in Table 4. The combustion pressure in PPCC power plant is assumed to be 15 bar and the isentropic efficiency of the compressor is taken as 85 per cent.

2019-8-1A number of CCS burners (based on unit requirements) fire pulverized coal and powdered limestone with very little hot combustion air into the GCs, creating a hot, very-fuel-rich gas as required ...

2020-10-15Coals ability to supply power during peak power demand either as base power or as off-peak power is greatly valued as a power plant fuel. It is with this fact that advanced pulverized coal fired power plants are designed to support the grid system in avoiding blackouts.

power plant schematic coal crusher - coal mill. schematic figure of coal mill in a .... schematic pulvuriser for coal - Newest Crusher, Grinding Mill, Mobile Crusher. schematic pulverized coal fire power - ROYAL TELE SHOPPING. THERMAL POWER PLANT SCHEMATIC DIAGRAM How a Coal-fired Power Plant works: . (2 inches) in size. ...

coal crusher schematic Grinding Mill China. schematic of a coal crusher sizer schematic pulverized coal fire power . This page is provide professional coal fired boiler diagrams information for you, we have livechat to answer you coal fired. coal crusher technical specification of tph - techstal

ULTRA-SUPERCRITICAL PULVERIZED COAL FIRED POWER PLANTS COALGEN 2006 CINCINNATI USA AUGUST 16 - 18, 2006 MIRO R. SUSTA, IMTE AG, POWER CONSULTING ENGINEERS, SWITZERLAND WWW.MTEAG.COM [emailprotected] ...

Pulverized Coal Fired Boiler Manufacturers In Kenya. ZOZEN Boiler Group as a Class-A boiler manufacturer, which has been specializing in oil and gas fired boiler, biomass fired boiler, chain grate boiler, circulating fluidized bed boiler, waste heat boiler, steam and hot water boiler, water and fire tube boiler, aac plant for three decades.

2018-2-2Riley Power Inc., 5 Neponset Street, Worcester, MA 01606 Phone-508 854 3899 Fax-508 854 4670 [emailprotected] ABSTRACT The need to develop cost effective combustion controlled solutions for reducing NOX emissions in coal fired utility boilers has been a high priority for many years at Riley Power Inc., a Babcock Power Company.

2017-2-11Pulverized coal fired boilers use coal of several tens of micrometers in size and then fire such pulverized coal in a suspended state inside the boiler furnace. Roller mills are commonly used as pulverizers due to their low power consumption. They pulverize coal between a roller and a rotating pulverizing table. To meet societys needs for

2020-4-13Supercritical coal plants are a type of coal-fired power plant used in more modern designs. They differ from traditional coal power plants because the water running through it works as a supercritical fluid, meaning it is neither a liquid or a gas.This occurs when water reaches its critical point under high pressures and temperatures, specifically at 22 MPa and 374 o C.

2017-2-11Pulverized coal fired boilers use coal of several tens of micrometers in size and then fire such pulverized coal in a suspended state inside the boiler furnace. Roller mills are commonly used as pulverizers due to their low power consumption. They pulverize coal between a roller and a rotating pulverizing table. To meet societys needs for

coal crusher schematic Grinding Mill China. schematic of a coal crusher sizer schematic pulverized coal fire power . This page is provide professional coal fired boiler diagrams information for you, we have livechat to answer you coal fired. coal crusher technical specification of tph - techstal

Pulverized Coal Fired Boiler Manufacturers In Kenya. ZOZEN Boiler Group as a Class-A boiler manufacturer, which has been specializing in oil and gas fired boiler, biomass fired boiler, chain grate boiler, circulating fluidized bed boiler, waste heat boiler, steam and hot water boiler, water and fire tube boiler, aac plant for three decades.

2019-8-1A number of CCS burners (based on unit requirements) fire pulverized coal and powdered limestone with very little hot combustion air into the GCs, creating a hot, very-fuel-rich gas as required ...

Coal-fired industrial boilers should operate across a wide range of loads and with a higher reduction of pollutant emission in China. In order to achieve these tasks, a physical model including two swirling burners on the front wall and boiler furnace was established for a 35 t/h pulverized coal-fired boiler. Based on Computational Fluid Dynamics (CFD) theory and the commercial software ANSYS ...

2020-4-13Coal fired power plants are a type of power plant that make use of the combustion of coal in order to generate electricity.Their use provides around 40% of the world's electricity and they are primarily used in developing countries. Countries such as South Africa use coal for 94% of their electricity and China and India use coal for 70-75% of their electricity needs, however the amount of coal ...

Schematic Diagram of Diesel Power Station. Although steam power stations and hydro-electric plants are invariably used to generate bulk power at cheaper cost, yet diesel power stations are finding favour at places where the demand for power is less, sufficient quantity of coal and water is not available and the transportation facilities are inadequate.These plants are also used as standby sets ...

2017-12-21A fire ball is created when the coal is fired inside the furnace where the temperature rises up to 13001700 C. About 90% of the coal power plants use these types of boilers for power generation [4, 23]. Small proportion of wood, biomass and agricultural materials can also be used as fuel in pulverized fuel boilers .

2020-4-13Supercritical coal plants are a type of coal-fired power plant used in more modern designs. They differ from traditional coal power plants because the water running through it works as a supercritical fluid, meaning it is neither a liquid or a gas.This occurs when water reaches its critical point under high pressures and temperatures, specifically at 22 MPa and 374 o C.

For more than 30 years, we have accumulated rich practical experience, and have established cooperative relations with more than 10,000 customers in more than 130 countries and regions, providing them with complete solutions and services covering the entire life cycle of products.

pulverised coal combustion - an overview | sciencedirect topics

pulverised coal combustion - an overview | sciencedirect topics

PCC technology is a widely utilized technology to generate energy from fossil fuel, especially coal [15]. In this technology, pulverized coal is injected to combust in a furnace in the presence of a controlled level of air. The heat generated is used to produce high-pressure steam driving a steam turbine to generate electrical power. The average efficiency for such plants is about 36% in the OECD (Organisation for Economic Co-operation and Development) countries and 30% in China [16]. The concept of PCC has been enhanced to operate at higher temperatures and pressures to produce supercritical (SC) steam and also ultra-supercritical (USC) steam (>374C and 218atm). These two advanced technologies have efficiencies far greater than PCC, with efficiency ranging between 40% and 55%. However, the full commercialization of SC technology has been limited by the need for materials that can withstand high temperatures and pressures. These technologies are seen as a major carbon mitigation route, as it is estimated that a percentage point increase in plant thermal efficiency can lead to a double reduction in CO2 emissions [17]. Therefore, replacing old pulverized fuel (PF) plants with SC pulverized coal plants has the potential of reducing emissions by 1025% [15].

Pulverized coal (PC) combustion is presently the system of choice for coal-fired power-generating plants. In PC combustion, the coal is dried and is ground to a specified fineness, with a maximum particle size of 250300 m, depending on the reactivity of the coal. Coal preparation, which involves feeding, drying, and grinding of the coal, and the pneumatic transport of the pulverized coal to the burners, is fully integrated with the boiler. For lower reactivity coals, the fineness of grind is increased to create a larger specific surface area so as to improve conditions for ignition and combustion. The powdered coal is pneumatically transported to burners and injected via particle-laden jets into the combustion chamber. The transport air that carries the coal from the mill to the burners is a small fraction of the total combustion air. It is kept at low temperature, limited to about 373 K, for reasons of safety against ignition and explosion in the mill and in the powdered coal transport pipeline between the mill and the burners. The rest of the combustion air, which can be preheated to higher temperatures, is injected separately and admixed with the already ignited coal particle-laden jet in the combustion chamber. A schematic illustration of a PC combustion boiler is shown in Fig. 3. The combustion chamber is typically of parallelepiped shape; the dimensions of a 300-MW coal-fired boiler would be approximately be 1515 m2 of cross-sectional area and 4550 m in height. The combustion chamber walls are completely cooled by steam-generating tubes. As the pulverized coal particles burn, the flame transfers heat, mainly by thermal radiation, to the steam-cooled tube walls of the boiler. The design of the combustion chamber has to provide for sufficient residence time of the burning particle to complete combustion, and for the cooling of the residual fly ash particles to below their softening temperature before entry to narrow convective heat exchanger passages, to prevent the buildup of sticky ash deposits. At regular intervals, friable deposits are removed by soot blowing using steam.

Although there are a great variety of burners in PC combustion boilers, the most widespread types are the circular burners and the vertical nozzle arrays. Circular burners are usually positioned perpendicularly to the combustion chamber walls, whereas vertical nozzle arrays are in the corners, firing tangentially onto the circumference of an imaginary cylinder in the middle of the combustion chamber. Designs utilizing circular burners are more concerned with the tailoring of the individual burner flame, whereas vertical nozzle arrays in tangentially fired furnaces are designed to rely more on the furnace volume for the mixing of the fuel and air streams. Complete combustion with a minimum (typically less than 15%) of excess air is a challenging task for a coal combustion system. The excess air, usually expressed as the percentage of the theoretically required combustion air, is the additional air needed for complete burnout of the fuel. The significance of the excess air is that the heat carried by the stack gases into the atmosphere, the largest heat loss (about 10%) of boiler operation, is directly proportional to the volume of the flue gas and, hence, to the excess air.

The fly ash formed in pulverized coal combustion is removed from the flue gas in the form of dry particulate matter; a small proportion (10%) of the coal ash that falls off the tube walls as semimolten agglomerated ash is collected from the bottom hopper of the combustion chamber (bottom ash). Ash particles are molten in the high-temperature regions of the flame, but cool and solidify as they reach heat exchange surfaces of the boiler, forming friable deposits that are easily removed by soot blowing.

Pulverised coal (PC) combustion is the most widely used technology for utility-scale power generation in the world. In PC boilers, coal is ground into fine particles (100m) and then injected with heated combustion air through a number of burners into the lower part of the furnace. Particles burn in suspension and release heat which is transferred into the steam cycle.

Based on burner arrangement, PC boilers can be divided into horizontally fired, tangentially fired and down-shot boilers. In horizontally fired boilers, burners are typically located on one (Figure7.8) or two opposite walls and each burner produces an independent flame zone requiring a correct amount of secondary air supply foreach burner. A high-turbulence swirl is created in the burners for efficient combustion.

In tangentially fired boilers, burners are located on the corners of the furnace. Together the flames produce a single cylindrical combustion zone in the centre of the furnace. Thus, the adjustment of secondary air for each burner separately is not so sensitive.

In down-shot boilers, coal is injected downwards into the refractory-lined lower furnace (Figure7.9). This promotes complete combustion of low-volatile content coals such as anthracite. Nowadays, down-shot boilers are not common as boilers have become larger and other burner configurations can thus offer adequate flame lengths.

Compared to grate and especially fluidised-bed boilers, PC boilers have significantly stringent requirements for the fuels especially with respect to particle size and moisture content. Drying and milling consumes a lot of energy, reducing the overall efficiency of the plant.

The combustion temperature in PC boilers is high, some 13001700C and residence time is approximately 12s. The high combustion temperature promotes good burnout but causes high NO and NO2 emissions. So-called low-NOx burners, which operate at 0.850.95 air ratio, and over-fire air supply are used for primary control of NOx emissions. Reduction is limited by the high temperature needed to ensure ignition with low-NOx burners (Jalovaara etal., 2003).

Pressurised pulverised coal combustion (PPCC) is another coal-fired combined cycle concept which is able to achieve efficiencies in excess of 50% [97Han]. A schematic flow diagram is given in Fig II.19.4. Combustion of pulverised coal takes place at temperatures of about 1600 C under a total pressure of about 15 bar. The produced flue gas is routed through a column of ceramic balls as a liquid-slag separation unit at an average temperature of 1450 C. A separate alkali removal (T 1400 C) is the last clean-up step before the flue gas enters the gas turbine. Here too, the residual thermal energy of the gas stream leaving the turbine is finally transferred to a steam cycle.

Laboratory investigations were conducted to find a sorbent material for alkali removal at 1400 C under PPCC conditions sufficient to fulfil the demands of the gas turbine manufacturers [005Esc]. In laboratory-scale flow channel and HPMS experiments at 1400 C, similar to those mentioned above, kaolin- and silica-enriched bauxite have shown the best ability to remove the alkalis sufficiently. The alkalis are bound in a meltglass phase formed during alkali sorption. The total NaCl concentration can be reduced to values less than 30 vol. ppb.

Based on the experimental results, the thermodynamic stability of the sulphates and other species in the gas turbine was calculated using a three-stage reactor model. The calculations were performed for a typical hard coal (79% C, 5% H, 2% H2O, 7% O2, 1% S, 6% ashes and 0.1% Cl). Figure II.19.5 shows a schematic diagram of the reactor model. Thermodynamic equilibrium was calculated for the reactors labelled Combustion chamber, Hot-gas cleaning and Gas turbine. The boundary conditions for the calculations are given in the scheme. First of all, in the Combustion chamber the equilibrium between coal and synthetic air (79 vol.% N2 and 21 vol.% O2) was calculated to obtain an idea of the hot-flue-gas composition leaving the combustion chamber. Both the gas phase and the condensed phase from the Combustion chamber were taken as input for the following calculations. In Hot-gas cleaning, thermodynamic equilibrium was calculated using the corresponding boundary conditions. The alkali partial pressure in the resulting gas phase was manually set to 2.4E-8 bar according to the experimentally obtained values. Since all particles and slag droplets should be removed by the liquid-slag separators, only the gas phase was used for the subsequent calculations. Since, in the process, cooling air is added at the entrance of the gas turbine, synthetic air (79 vol.% N2 and 21 vol.% O2) was added to the gas stream entering the Gas turbine to reach an overall value of 2. Finally, the thermodynamic stability of the sulphates results from equilibrium calculations for the Gas turbine. The same target calculations were performed as for second-generation CPFBC.

The results of the thermodynamic calculations are shown in Fig. II.19.6. The dew point curve of Na2SO4 is similar to that for second-generation CPFBC and much lower than that for a gas turbine burning fuel oil. The dew point curve for K3Na(SO4)2, which is the thermodynamically stable sulphate containing potassium, is about 20 K lower. For the same reasons explained for second-generation CPFBC, no hot corrosion should take place in the case of PPCC.

In the pulverized coal combustion system, coal ground to a very fine size (7080% passing through a 200-mesh screen or 75m) is blown into a furnace. Approximately about 10% of the total air required for combustion is used to transport the coal. This primary air, preheated in the airheater, is used to drive out the moisture in the coal and transport the coal to the furnace. A majority of the combustion air is admitted into the furnace as secondary air, which is also preheated in the air preheater. The particles are heated at 105106C/sec, and it takes about 11.5sec for complete combustion. This increases the throughput to furnace and, hence, it is the most preferred form of combustion method by electric utilities. Based on the burner configuration, pulverized coal combustion systems can be divided into wall-fired, tangentially fired, and down-fired systems. In wall-fired units the burners are mounted on a single wall or two opposite walls. Wall-fired systems with single wall burners are easy to design. However, due to uneven heat distribution, the flame stability and combustion efficiency are poor compared to the opposed wall-fired system. Because of the possibility of flame impingement on the opposite wall, this system may lead to ash slagging problems. An opposite wall-fired boiler avoids most of these problems by providing even heat distribution and better flame stability. A diagram of the opposed firing system is shown inFig. 5. However, the heat release rate can be higher than single wall burner systems and could lead to slagging and fouling problems. A tangential firing system has burners installed in all four corners of the boiler (as shown inFig. 6). The coal and primary air jets are issued at an angle, which is tangent to an imaginary circle at the center of the furnace. The four jets from four corners create a fireball at the center. A top view of the furnace is provided inFig. 6. The swirling flame then travels up to the furnace outlet. This method provides the highest even heating flame stability. The temperature in the fireball can reach as high as 17001800C. The burner is a key component in the design of the combustion system. It also determines the flow and mixing patterns, ignition of volatiles, flame stability, temperature, and generation of pollutants. Burners can be classified into two typesswirl and nonswirl. Primary air transports coal at velocities exceeding 15meters/sec (the flame velocity) of the fuel. The flame velocity is a function of volatile matter. Secondary air ignites the fuel, determines the mixing pattern, and also determines the NOx formation. High volatile bituminous coals tend to have higher flame velocities compared to low volatile coals. Swirling flows promote mixing and esatablish recirculation zones. In swirling flows, the axial flux of angular momentum G and the axial flux of axial momentum Gx are conserved.

where u and w are the axial and tangential components of the velocity at radius r, p is the static gage pressure, and r1 and r2 are radial limits of the burner. Swirl number is a measure of swirl intensity

Data for validating pulverized coal combustion predictions requires accurate information for the reactor parameters shown inTable VI. Data measured in the combustion chamber typically include (1) locally measured values of the gaseous flow field velocity, temperature, and species composition, (2) coal particle burnout, number density, velocity, temperature, and composition, and (3) wall temperatures and heat fluxes. Evaluation should include comparisons with measurements from a wide variety of combustors and furnaces that range in scale from very small laboratory combustors (0.010.5MW) and industrial furnaces (110MW) to large utility boilers (up to 1000MW).

Laboratory-scale data are very important to comprehensive model validation for several reasons. First, the nonintrusive, laser-based instrumentation needed to characterize the turbulent behavior in a flame is used more conveniently in smaller laboratory reactors. Second, a wider range and better control of reactor operating conditions are possible for a smaller facility. Third, the entire reactor volume can be traversed with small incremental steps, so that much more detailed datasets can be obtained. Other advantages of small laboratory facilities are relatively low operating cost, flexibility and accessibility, and ability to control and to define carefully the boundary and inlet conditions. They can be large enough to give sufficient spatial resolution and to create a near-burner furnace environment, and small enough to utilize the advanced measurement techniques which are essential to providing accurate and complete data for model evaluation and for detailed understanding of combustion processes.

In large-scale facilities, detailed measurements are difficult to make, inlet conditions are often not well defined, operating costs for obtaining data can be high, and the facility may have instrumentation limitations. For example, detailed model evaluation measurements of species and temperature within or across large flames cannot easily be made, although such spatially resolved profile data are often best for comparing flame characteristics, near-field burner performance, and jet mixing behavior with predictions. Such measurements are essential for the evaluation of comprehensive combustion models. These detailed measurements provide important information concerning flame response to parametric variation. Effluent measurements (measurements at the outlet of the system or process) can be useful, particularly when effects of key system variables, such as excess air percentage, firing rate, or burner tilt angle, are measured. In some facilities, effluent data are the only kind available because of furnace size or access constraints, or because that was the only objective for making the measurements. Three-dimensional data at the utility furnace scale obtained with the specific intent of evaluating and validating model predictions have been collected at large-scale 85-MWe and 160-MWe corner-fired boilers of one U.S. utility.

Worldwide research efforts in advanced pulverized coal (pc) combustion technologies are currently focused on USC and advanced USC (A-USC) steam technology. By increasing pressures and temperatures in traditional pc supercritical (SC) power steam boilers and turbines from 540585 C and 2428MPa toward A-USC steam conditions of 760C and 35MPa, energy conversion efficiencies over 45% higher heating value (HHV) can be achieved. Despite extensive steel research, 912wt% chromium martensitic steels appear limited to ~620C (Masuyama, 2001) and high-chromium austenitic steels workable to ~675 C, with limitations for thick-section application because of a high coefficient of thermal expansion combined with low thermal conductivity (Shingledecker and Wright, 2006). Above 675 C, nickel-based alloys are recommended (Blum and Vanstone, 2003; Viswanathan et al., 2007), although some new austenitic alumina scale-forming dispersion-strengthened steels are under development that may also reach 750 C, with both creep and oxidation resistance (Yamamoto et al., 2007).

IGCC fly ash is similar to PCC fly ash in its applicability to structural fill and sometimes it shows self-hardening properties, which would be beneficial in many applications (Sloss, 1996). Fly ash without pozzolanic activity can be used to replace earthen fills. The American Society for Testing and Materials standard ASTM E 1861 was issued in 1997 in the US for guidance on the use of coal conversion by-products in fills.

IGCC technology offers clear advantages over pulverized coal combustion, especially for achieving higher net efficiency, lower emissions (e.g., dust, heavy metals, hazardous compounds, CO2, and gaseous pollutants) and comparatively lower efficiency penalty for CCS. The effort required for this, and the fact, that in lack of standardized solutions, current IGCC projects are characterized by customized plant designs (first-of-kind), lead to higher CAPEX, which is the main reason for the currently limited commercial deployment of IGCC power plants. Hence, broader commercialization can be expected rather for IGCC-CCS than for non-capture IGCC power plants. A major challenge is the technological and economic demonstration of IGCC-CCS power plants featuring high efficiency and high availability.

Polygeneration plants, which combine both syngas-based power generation and the production of chemicals or fuels, are similarly characterized by high CAPEX and related challenges for future deployment. However, major advantages of this system are the increase in product flexibility and feedstock utilization, resulting in higher total efficiencies, lower CO2 emissions, and improved economics of the overall plant. In addition, polygeneration concepts are suitable for the integration of intermittent renewable power. Because of the anticipated increase in coal-based production of chemicals and fuels, the potential for polygeneration plants can be considered higher than for syngas-based mono-electricity generation. A promising approach is the Annex concept, which links an existing PCPP with a small-scale CTX plant. Heat and power integration, as well as the integration of waste streams such as carbonaceous residues, waste water, off gases, and purge gases from the Annex into the power plant, result in a significant CAPEX reduction. For this Annex concept better chances of implementation are expected in the short term.

The microstructure of FBC-FA and PCC-FA blended geopolymer paste was studied by Chindaprasirt et al. [110]. The geopolymer paste was activated using the NaOH to Na2SiO3 ratio of 1.5 and was oven cured at 65C for 48h, followed by subsequent curing at a controlled temperature of 25C. The morphology of the blended geopolymer paste was examined at the age of 7 days. Fig. 11.11A and B show the morphology of 60:40 PCC-FA: FBC-FA blend and its geopolymer paste counterpart. The spherical shape of PCC-FA induced the ball-bearing effect and improved the workability of the resultant paste as compared with FBC-FA, which consisted of irregular and porous particles. The morphology of the 60:40 blended geopolymer paste, PCC-FA geopolymer paste (Fig. 11.11C), and FBC-geopolymer (Fig. 11.11D) paste show continuous mass of aluminosilicate, indicating a relatively well-developed geopolymer network. However, the unreacted/partially reacted grains of irregular FBC-FA are much more porous than PCC-FA, which culminated in a lower strength of blended geopolymer paste with higher FBC-FA content. In the same study, XRD results indicated that at the age of 7 days, blended geopolymer pastes with a high amount of PCC-FA (60%, 80%, and 100% PCC-FA) showed a high amount of amorphous phases and trace amount of crystalline products. Meanwhile geopolymer pastes with a high amount of FBC-FA (60%, 80%, and 100% FBC-FA) exhibited intense peaks of crystalline phases with a reduced amount of amorphous gel. Calcium silicate similar to the hydration product of Portland cement was detected in all the blended hardened geopolymer pastes.

The pore size of POFA/FA geopolymer mortars significantly increased upon being subjected to elevated temperature beyond 800C. High POFA content in the blended geopolymer mortar mixes deformed at 800C while FA-based geopolymer mortars maintain their structural integrity up to a temperature of 1000C, suggesting lower thermal stability upon addition of POFA in FA-based geopolymer mortars [46]. In a separate study, the addition of POFA in a FA geopolymer system increases the porosity in the resultant blended geopolymer matrix [24]. This is due to the unreacted POFA particles having the tendency to trap air because of their inherent crumbled shape.

coal-fired power station - an overview | sciencedirect topics

coal-fired power station - an overview | sciencedirect topics

Coal-fired power stations are burning an increasingly varied range of fuels and fuel blends, including sub-bituminous and lower volatile coals and biomass of varying composition and combustion properties, under tight economic and environmental constraints. Since existing coal-fired plants are not designed to burn such a diverse range of fuels, the power generation industry has to overcome a range of technological problems such as poor combustion efficiency, increased pollutant emissions and other operational issues such as poor flame stability and slagging and fouling. The recent trend in operating power plants in variable load in response to changes in electricity demand has exacerbated the aforesaid problems. To meet the increasingly stringent standards on combustion efficiency, pollutant emissions and renewables obligations and to maintain fuel flexibility, advanced monitoring and control techniques have become highly desirable in the power generation industry.

In electrical power generation solids fuel is supplied from a bunker into a pulverising mill and the pulverised fuel is then pneumatically conveyed towards the furnace by splitting a larger fuel pipe into smaller ones through bifurcations and/or trifurcations. The fuel distribution network feeds a matrix of burners on a wall-fired or a tangentially fired furnace. Each power generation unit at a coal-fired power station can have typically 20, 24 or 32 or 48 burners. A simplified example of the fuel supply and distribution system is illustrated in Fig.10.1.

Advanced sensors and process control techniques to permit on-line measurement and subsequent control of the fuel/air flows in individual pipes, the flames of individual burners, and the optimised operation of fuel bunkers and pulverising mills have been regarded as a priority technological development by many leading power generation organisations and government departments (CRF/BCURA, 2004). This trend is further enhanced by the increasingly stringent emissions legislation, better plant maintainability, increased fuel flexibility and the progressive implementation of the carbon capture and storage strategy (APGTF, 2009). The successful development of advanced sensors and control systems will lead to increased fuel flexibility and better control of emissions, which will ultimately improve plant economical performance and viability. For instance, better monitoring and control of the combustion process will result in low carbon levels in ash, allowing ash residue to be used in cement manufacture (because of a low and controlled carbon content), thereby giving revenue instead of disposal costs.

This chapter describes the current state in the development of monitoring and control technologies for applications in coal-fired power stations. Monitoring issues that are covered in this chapter are concerned with fuel bunkers, pulverising mills, pulverised fuel injection systems, and furnaces. Other measurement issues such as on-line particle size measurement, flame stability monitoring, on-line fuel tracking, and flame imaging are also included. Control techniques associated with pulverising mills, pulverised fuel splitting, and furnace and boiler operations are described and discussed. The monitoring and control techniques are aimed not only to achieve the optimisation of existing plants but also to provide a useful reference for the specification and design of efficient new-build installations. Some topics such as continuous level monitoring of fly ash and continuous emissions monitoring, although very relevant to the scope of this chapter, are excluded because of length restrictions. Many of the measurement and monitoring techniques described in this chapter are at the stage of being trialled on power stations but are not yet established practice.

Coal-fired power stations are relatively expensive to build since their construction involves both large quantities of expensive materials, such as iron and steel, and large volumes of labor. While some parts of a coal-fired power plant such as its steam turbines can be assembled in a factory and then delivered to the site, much of the assembly of the boiler and flue-gas cleaning systems must take place at the site itself. As a consequence, the cost of a coal-fired power plant will be vulnerable to changing commodity costs and generally increasing labor costs.

Against this the fuel (coal) is generally the cheapest of fossil fuels and this will normally outweigh the high capital cost so that the cost of electricity from a coal-fired power station will be among the most competitive available. Currently, coal-fired power stations are built without carbon capture facilities but this is likely to be required at some point during the third decade of the 21st century. It is also likely that plants built before that time will be required to be carbon-capture ready so that post-carbon-capture technology can be fitted at a later stage. All this needs to be taken into account when considering construction of a coal-fired power generating facility.

Table 3.6 shows the estimated 2011 cost of coal-fired power plants in the United States in 2010 dollar prices based on data from the U.S. governments Energy Information Administration. This analysis suggests that the capital cost of an advanced PC power plant is $3167/kW. When carbon capture and storage is added to this, based on post-combustion capture, the cost rises to $5099/kW, an increase of 60%.

An integrated gasification combined cycle power plant without carbon capture and storage would, on the same basis, have cost $3565/kW in 2011. However, when carbon capture and storage is added to this plant, based on the type of system discussed before, the price would rise to $5348/kW. The cost of an oxy-fuel combustion plant was not included in the analysis but other analyzes suggest that the cost is likely to be similar to those in Table 3.6 for the other technologies with carbon capture.

Other analyses suggest that future costs will be lower than this. Table 3.7 shows another set of figures for the cost of future coal-fired power plants, in this case as estimated by the U.S. Electric Power Research Institute (EPRI). This analysis is based on the assumption that carbon dioxide capture will not be deployed by 2015. The cost of a PC power plant in that year, again calculated in 2010 U.S. dollars, is estimated to be between $2000/kW and $2300/kW. At the same time, the cost of an integrated gasification combined cycle plant is put at between $3150/kW and $3450/kW.

EPRI has assumed that carbon capture and storage will be necessary in 2025. By then the cost of a PC plant with carbon capture and storage is estimated to be $26002850/kW. For an integrated gasification combined cycle power plant the cost range is $31003800/kW. As before, there is no consideration of an oxy-fuel combustion plant, but the cost of this can be expected to fall somewhere within the cost range of the two other technologies, $26003800/kW.

All these costs are for power plants built in the United States. While costs are likely to be similar in Europe, commodity prices and especially labor costs are likely to differ widely in other parts of the world and this can affect the capital cost significantly. Costs in countries like China and India are consistently much lower than in the United States and Europe.

Coal-fired power stations consume pulverised coal which is injected into furnaces. Around 80% of the ash produced from combustion of the coal is carried by the exhaust gases and precipitated to form fly ash. The other 20% of the ash condenses within the furnace, falls to the bottom and agglomerates, forming furnace bottom ash.

Furnace bottom ash is typically a coarse granular material. The apparent density can approach that of normal weight aggregates, but since the particles are very porous, the bulk density is much lower. Furnace bottom ash is crushed and screened to produce a range of size gradings. Coarser material typically has a bulk density in the range 700900kg/m3, while fine material is around 1000kg/m3. Furnace bottom ash is widely used in the manufacture of precast lightweight concrete blocks.

Clinker from industrial furnaces burning lump coal was probably the first manufactured aggregate to be used. Production has now ceased in the United Kingdom as modern furnaces use oil, gas, pulverised coal or biomass. Clinker was frequently and variably contaminated with unburned coal, sulfurous compounds, hard-burned quicklime, periclase, iron pyrites and other compounds. This led to unsoundness (Fig. 15.38). Reviews of the unsoundness of some clinker aggregates are included in Short and Kinniburgh295 and Crammond and Currie.296 As recently as the 1980s, structural damage was occurring in concrete blockwork due to the unsoundness of clinker aggregates. The corrosion threat posed by sulfurous compounds generally precluded the use of clinker in reinforced concrete, although it was frequently used in buildings for lightweight infill concrete between steel joists or for encasement concrete around steel stanchions.

Fig. 15.38. Expansion and cracking of a flat concrete roof slab caused by unsound clinker aggregate. The view shows the ceiling on the underside of the recently water-penetrated roof slab in an early 20th century warehouse building in London, United Kingdom.

For a coal-fired power station the cost of the fuel is probably the most important factor affecting its economics. Coal has traditionally been considered a cheap source of electricity and its ready availability has made it popular in many parts of the world. Most coal is consumed locally and so unlike oil or natural gas the price is normally set locally. In addition, the cost of coal has traditionally be quite stable, although the recent global economic cycle saw an unusually dramatic rise in the cost.

As an illustration of coal costs, Figure 8.1 show the cost of a ton of US Central Appalachian coal, a coal suitable for power generation, between 1990 and 2013. In 1990 one ton cost $31.6 and although there were fluctuations, the cost remained relatively stable throughout the succeeding decade. However, from 2000 costs started to rise significantly, reaching a peak of $118.8/ton in 2008 before falling back to around $70/ton in the middle of the second decade of the twenty-first century.

This unusually sharp peak in coal prices was a global phenomenon with prices in Europe and Asia exhibiting a similar trend. However the prices of a ton of coal in different parts of the world still vary significantly with local conditions having an important effect on the overall cost. In general, countries that import coal for power generation pay the highest price, a reflection of the high cost of transporting the fuel.

The ash from coal-fired power stations has had many uses over the years. One of the latest in the United Kingdom was in the reshaping of Celtic Manor Golf course in southern Wales. It has been used as cement replacement in concrete. The ash from pure biomass plants is completely different in nature and will be unsuitable for any of these uses. This is an important area that needs to be developed; otherwise, it may restrict the use of biomass in power generation.

An 1800 MW coal-fired power station fitted with the limestone-gypsum type of flue gas desulphurisation (FGD) plant will produce about 500 000 tonnes of gypsum per year. This gypsum could be used to make building materials such as wallboard. The amount produced would be sufficient to supply an average size wallboard factory, and it is therefore possible that such a facility could be built adjacent to the site, otherwise the gypsum would be removed from site for use elsewhere or disposal.

The byproducts produced by regenerative processes would have to be transported to a suitable chemical works for use. It is difficult and undesirable to store large quantities of products such as sulphuric acid or elemental sulphur and therefore a regenerative process would only be used where a reliable market for such products existed.

In most large coal-fired power stations a large part of the ash residue from coal combustion is carried away with the flue gases, entrained in the form of fine particles. If allowed to escape into the atmosphere these will create a plume of smoke before eventually falling to earth as a layer of fine dust. Modern emission regulations require that this material be captured before flue gases are allowed to exit the stack of the power plant.

There are two principal systems that are used for removing particulates from the flue gas of a coal-fired power station, electrostatic precipitators (ESPs) and fabric (baghouse) filters. Cyclones can also be used to capture particulate material but they tend to be used on smaller plants.

The ESP was invented by the American scientist Frederick Cottrell. It utilizes a system of plates and wires to apply a large voltage across the flue gas as it passes through the precipitator chamber. The flue gases, when they enter the ESP, pass through an array of wires that are held at a high negative voltage relative to ground so that they generate a corona of ionized gas around them. As the particles pass through this corona they become charged. Once charged they are attracted to large vertical plates that are held at ground voltage. This is shown in Figure 6.5. Periodically the plates are vibrated or rapped causing the layer of charged particles that has built up on the surface of each to fall into a collector at the bottom of the ESP.

ESPs are extremely efficient. A new ESP will remove between 99.0% and 99.7% of the particulates from flue gas. However, it must be tuned to the particular coal being burned in the power plant. Where coals of different types and from various sources are to be burnt, the alternative may be more effective. The ESP can handle both dry and wet particles but it is less effective when the ash has a high electrical resistivity.

Bag filters, or baghouses, are tube-shaped filter bags through which the flue gas passes on its way to the power plant stack. Particles in the gas stream are trapped in the fabric of the bags from which they are removed using one of a variety of bag-cleaning procedures. These include using supersonic blasts of air to dislodge particles so that they fall to the base of the unit and can be removed. These filters can be extremely effective, removing over 99% of particulate material. They are generally less cost-effective than ESPs for collection efficiencies up to 99.5%. Above this, they are more cost-effective. A system that combines a baghouse-style filtration system with an ESP is under development too. This aims to provide a cost-effective high removal efficiency system, but has not yet been extensively demonstrated.

Cyclone filters, which capture particles by imparting a centrifugal force on them, are used in CFB boilers to trap particles escaping the combustion zone but they are not usually used to capture particles in large power plants. They are relatively cheap to build, are able to operate at high temperatures and have low maintenance costs. However, they are only effective with dry particles and they are not efficient at removing small particles from flue gases.

Mercury emissions from coal-fired power stations are coming under increasing scrutiny in Europe. In 2005, the Community Strategy Concerning Mercury was drawn up by the European Union and aims at a reduction of emissions by member states. Germany became the first European country to regulate mercury emissions from power plants (0.03 mg/m3STP).

During coal combustion, mercury is vaporised and released to the gas-phase in its elemental form (Hg0). Hg0 can be converted to oxidised mercury (Hg2+) where reaction with chlorine compounds present in coal to form HgCl2 is the predominant channel under normal power plant operation. In addition, particulate bound mercury (HgP) can be formed by adsorption onto fly ash or activated carbon. Unburned carbon particles in fly ash are believed to provide reactive sites for mercury adsorption and also heterogeneous oxidation. Hg2+ can easily be removed by flue gas desulphurisation scrubbers where HgP can be removed by electrostatic precipitators or other particle separation methods. Mercury transformation is extremely complicated and can depend on a variety of factors such as coals chemical and mineralogical composition, combustion conditions, plant configuration, flue gas composition and temperature-time history from combustion zone to stack.

Bromine compounds are strong oxidisers of mercury so there is a strong interest in using them as additives in the form of Br2, HBr, bromine salts or impregnated activated carbons. A number of pilot scale and industrial demonstrations have been reported [1,2]. In addition, a few kinetic modelling studies of mercury oxidation by bromine species have been reported [3,4] but there is still a significant lack of fundamental understanding of the associated physical and chemical interactions.

This paper presents a homogeneous mechanism for mercury oxidation by chlorine and bromine species, consolidating previous work on the development of Hg-Cl [5] and Hg-Br [6] mechanisms. The impact of different halogen mixtures on mercury oxidation is assessed by numerical simulation and comparison to experimental data. The interactions of Hg/Cl/Br are analysed and discussed.

Fly ash is another material that can come in a very wide range of sizes, depending on both the size distribution of the coal generated by the pulverizing mills for combustion in the boiler, and the location of collection hoppers within the boiler plant. The material is essentially the same, wherever it is collected, but the conveying capability of the different grades thus generated can be considerable.

Conveying characteristics for a sample of coarse fly ash from an economizer hopper and those for a sample of fine fly ash from the second field of an electrostatic precipitator hopper were shown in Fig.13.23 and are reproduced here in Fig.22.10. Both materials were conveyed through the same pipeline.

A high-pressure top-discharge blow tank was used for the conveying of these materials, but the pipeline used was of a larger bore and significantly longer that those used for the two previous sets of materials. The conveying characteristics are shown side by side once again so that a direct visual comparison of the two materials can be made. On these conveying characteristics lines of constant conveying-line inlet air velocity have also been added for reference.

For the coarse grade of fly ash, the minimum conveying air velocity was about 13m/s and this did not vary with air supply pressure or solids loading ratio. For the fine grade of the fly ash, the minimum value of conveying air velocity was about 3m/s. For the coarse fly ash, the maximum value of solids loading ratio was about 15 and for the fine fly ash it was about 160.

Once again these values are dictated by a combination of air supply pressure, minimum conveying air velocity, and conveying distance. The main operating area on the conveying characteristics for the fine fly ash occurs in the no-go area for the coarse fly ash, and so the design of a common system for the conveying of both grades of the material may not be immediately obvious, particularly for a vacuum conveying system. Vacuum conveying systems are often used for the transferring of fly ash from the boiler hoppers to intermediate hoppers for onward transfer.

At a typical coal-fired power station, only about 15% of the ash to be removed from the multitude of ash collection hoppers is coarse ash. A system is ideally required where this can be removed by any of the conveying systems used for removing the fine ash. A means of achieving a higher conveying-line inlet air velocity, however, is required for the coarse ash hoppers. A convenient method of achieving this is to use a smaller bore pipeline through which to convey the material.

If there is, for example, a 4:1 difference in conveying-line inlet air velocities between the coarse and fine grades of fly ash, then a 2:1 difference in pipeline bores will be required, and with this combination, there need be no change in volumetric flow rate of air used. As the high-velocity air used for the coarse ash expands, the diameter of the pipeline can be increased. This may need to be done once or twice until the same bore as the fine ash pipeline is achieved. A sketch of a typical arrangement is given in Fig.22.11. This is a vacuum conveying system, whereas the previous cases have been positive-pressure systems. Both are possible. Vacuum conveying, however, is commonly used in thermal power plant for the off-loading of fly ash from collection hoppers.

There need be no change in diameter of the fine ash pipeline as the conveying air velocity in this line is very low. Indeed it might be advisable not to step the fine ash pipeline because of the problems of purging the pipeline clear of material, should this be necessary at any time. Typical velocity profiles for the combined system are shown in Fig.22.12. Although a vacuum conveying system is illustrated in Fig.22.12, a similar arrangement can be devised for positive-pressure conveying systems, as shown in Fig.22.6.

Figure22.12 shows that the value of the conveying air velocity for the conveying of the coarse fly ash does not fall below a minimum value of about 16m/s anywhere along the length of the pipeline. Care must be taken in locating the steps in the coarse ash pipeline, however, to ensure that this is always the case, otherwise the pipeline is liable to block at a step.

To avoid confusion an isothermal case has been considered with all temperatures at 300 K, as with the alumina considered earlier. For the coarse ash a minimum value of conveying air velocity of 16m/s has been taken, and for the fine ash a value of 6m/s has been used. Care must be taken in evaluating air velocities, however, for in most cases, it is hot ash that has to be conveyed and this can have a significant effect on conveying air velocity values.

Once again a common pipeline bore has been used for entry to the reception silo, but as with the positive-pressure conveying system considered for the alumina, this is not necessary for negative-pressure conveying systems either. Two steps have been recommended for the coarse ash pipeline and this illustrates the general need for stepping pipelines to a larger bore in high vacuum conveying systems. Salient conveying parameters for the two pipelines at the material feed and discharge points are presented in Table22.2.

A given pneumatic conveying system can be adapted to convey different materials, having widely differing conveying capabilities, quite simply by selecting an appropriate bore of pipeline to meet the minimum conveying air velocity requirements for the material, and for the given volumetric flow rate of air available. This will involve the use of different pipeline bores at the material feed point, but it will mean that it will be possible to convey the material.

By this means it will also be possible to convey each material at its optimum conveying conditions, and so convey materials in both dilute and dense phase with the same conveying system. With high-pressure or high vacuum conveying systems, it will be possible to step the pipelines to a larger bore along their length, and in these cases it may be possible to merge the pipelines into one and use a common section of pipeline at entry to the reception vessel.

The use of the smaller bore pipeline for the off-loading of the coarse ash hoppers will necessarily mean that a lower flow rate of fly ash will be achieved through these coarse ash pipelines. As the coarse ash only represents some 15% of the total ash, the increase in flow rate to be achieved in the fine ash lines to compensate will only be marginal, and for the convenience in pipeline routings and operation, it is generally well worthwhile considering.

The availability of biomass and waste fuels, as well as the significant differences in both their physical and chemical properties, has guided their use as single fuels towards dedicated power plants. Many new biomass and waste-to-energy power plants have been built during the last decade and the numbers of these plants are expected to increase significantly in the immediate future as increasing emphasis is placed on switching to renewable and more sustainable fuels.

However, for old coal-fired power stations that are being decommissioned as part of current environmental initiatives, one interesting alternative idea to just scrapping them is to adapt them in such a way that biomass could be used to fire one of the boilers (500600 MWe units) that make up the overall station. To make this viable several issues would need to be addressed, including:

There is a need to improve the efficiencies of power plants firing biomass and waste fuels. One of the key limiting factors in restricting their efficiencies is deposit formation and corrosion on the final superheater. Deposit formation restricts the heat transfer to this heat exchanger and also provides a chemically aggressive environment that rapidly corrodes the heat exchanger materials (Chapter 4). New boilers are designed to try to partially counter these effects, but one new technology developed by Vattenfall is targeted at altering the environments generated in the boilers when using these fuels. The ChlorOut process sprays a sulphur rich compound (ammonium sulphate) into the gas stream and controls this on the basis of minimising the alkali metal chlorides that are present in the gas stream (Vattenfall Research and Development, 2005). Initial trials have shown this to be effective in reducing both deposition and fireside corrosion with fuels rich in alkali chlorides (Vattenfall Research and Development, 2005).

coal fired power station schematic

coal fired power station schematic

For each project scheme design, we will use professional knowledge to help you, carefully listen to your demands, respect your opinions, and use our professional teams and exert our greatest efforts to create a more suitable project scheme for you and realize the project investment value and profit more quickly.

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A fossil fuel power station is a thermal power station which burns a fossil fuel, such as coal or natural gas, to produce electricity.Fossil fuel power stations have machinery to convert the heat energy of combustion into mechanical energy, which then operates an electrical generator..

The 1,320MW Jamshoro coal-fired power plant located in the city of Jamshoro city in Sindh Province, will be the first supercritical coal-fired power plant in Pakistan, once operational in 2023. The project is being developed by Jamshoro Power Company Limited (JPCL) with an estimated investment of $1.5bn.

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Thermal Power Plant Schematic Diagram: Typical diagram of a coal-fired thermal power station 1. Cooling tower 10. Steam Control valve 19. Superheater 2. Cooling water pump 11. High pressure steam turbine 20. Forced draught (draft) fan 3. transmission line ...

IMPROVEMENT OF COAL-FIRED GENERATION UNITS FOR NOx CONTROL In 2009 and 2010, two 350MW coal-fired generation units L4 and L5 in Lamma Power Station were retrofitted with low NOx combustion system. In addition to reducing NOx

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IMPROVEMENT OF COAL-FIRED GENERATION UNITS FOR NOx CONTROL In 2009 and 2010, two 350MW coal-fired generation units L4 and L5 in Lamma Power Station were retrofitted with low NOx combustion system. In addition to reducing NOx

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power plants of the future: 21st century coal-fired steam generator

power plants of the future: 21st century coal-fired steam generator

Coal-fired plants have been powering the electric grid for more than a hundred years, but the technology being used in them is not stagnant, as many advancements have been made. One new designthe Clean Combustion System Steam Generatorhas been proven in pilot testing to increase efficiency while reducing emission control costs. It could be a game-changer for the industry.

The markets for new coal-fired steam generators will be driven by 21st century technologies that provide high-efficiency, low-pollutant emissions, and low-cost electricity. CastleLight Energy is a technology management firm that proposes a new CCS Steam Generator (CCS-SG) design incorporating the field-demonstrated Clean Combustion System (CCS). The CCS technology evolved from fundamental combustion research developed at Rockwell International for NASAs large moon-rocket engines.

The proposed CCS-SG features a compact furnace design with a small footprint per MWth and a large MW-per-ton-of-steel steam capacity. These fundamental characteristics are found in the 1950s Babcock & Wilcox cyclone wet-bottom electric generating units (EGUs)a low-cost steam generator design that, in its time, captured a large U.S. EGU market. As important, the CCS-SG uses equipment, steels, refractories, and instrumentation in commercial use today on coal-fired EGUs and which are very familiar to most plant operators.

Figure 1 illustrates todays coal-fired EGU steam generator and the back-end emissions control equipment used to meet U.S. Environmental Protection Agency (EPA) air quality regulations, such as SO3 (Trona injection), NOx (selective catalytic reduction [SCR] and ammonia), mercury (activated carbon injection), particulate (electrostatic precipitator [ESP] or baghouse), and SO2 (wet flue gas desulfurization [FGD] and limestone). This equipment comprises a significant portion (about 35%) of an EGUs cost, including a higher operating cost, a roughly 2% loss of efficiency (CO2 increase), and reduced electricity delivered.

The EPA, through its management of the 1990 Clean Air Act Amendments (CAAAs), has set strict emissions performance limits for new coal-fired EGUs. Table 1 summarizes these emissions based on best available control technology (BACT).

The EPAs recent Affordable Clean Energy Rule also proposes to limit CO2 emissions from new EGUs. Table 2 summarizes the proposed efficiency targets, corresponding CO2 emissions, and unit heat rate equivalents.

Figure 2 illustrates a coal-fired EGU with the CCS-SG. It includes a coal-drying step coupled with a coal-gasification hybrid providing SO2 and NOx control to meet EPA air quality regulations. Limestone is added to the coal to provide the calcium necessary for sulfur capture. Particulate control is furnished with an ESP or baghouse. The CCS-SG reports improved combustion efficiency of about 6% and delivers about 10% more electricity for the same amount of coal fired, at one-third the cost of conventional FGD and SCR systems.

The Figure 3 schematic illustrates the CCS process for SO2 and NOx control. It is a rather simple coal gasification hybrid (replacing conventional coal burners) and in-furnace air-staged combustion. The gasification chambers (GCs) are fabricated as studded, refractory-lined waterwalls mounted in the boiler furnace. The water-cooled refractory surfaces become coated with coal slag to provide a reliable, renewable, protective surface from the coal gasification products.

A number of CCS burners (based on unit requirements) fire pulverized coal and powdered limestone with very little hot combustion air into the GCs, creating a hot, very-fuel-rich gas as required for the CCS sulfur capture and NOx destruction processes described below. The high gasification temperatures melt the coal ash, which then drains from the GC as a slag product. The hot, fuel-rich gases of nitrogen, carbon monoxide, and hydrogen exit the GC into the furnace. A clear, bright-orange gas fills the furnace to generate steam. The furnace walls remain clean, free of slagging, fouling, and corrosive sulfur deposits.

As the gases cool in the furnace (to less than 2,300F to avoid any thermal NOx formation), over-fire air (OFA) is staged through multiple ports to complete the combustion of carbon monoxide to CO2 and hydrogen to water. The gases then exit the furnace into the boilers back-pass superheater section. Figure 4 shows a CCS-GC installed on a 30-MWth industrial stoker boiler.

Engineers are aware that the sulfur in coal can be captured in the initial combustion step. For example, commercial circulating fluidized-bed (CFB) furnaces burn coal in a bed of sand and limestone (at about 1,600F), fluidized with hot combustion air. The CFB combustion process is fairly slowseveral secondsand requires high-horsepower, high-pressure air blowers to circulate the fluid bed.

By comparison, the CCS combustion process is fastfractions of a second. As the carbon is oxidized, the sulfur is released from the coal into the hot gases. The calcium (from limestone) reacts with the sulfur to form calcium sulfide (CaS), a solid particle at these temperatures.

The gasification temperatures are sufficiently hot to melt the coal ash (silica and alumina) along with the CaS, creating a liquid-glass slag product. Recall that bottle glass is a melt of silica, alumina, and calcium oxide (CaO). However, because CaS has replaced CaO in the process, the sulfur is encapsulated and bound in the slag; it cannot leach out in water. About half of the melted coal ash contacts the walls of the GC and drains into a water-quench tank as bottom ash for disposal. The remaining fine ash droplets that carry into the furnace section solidify as fly ash particulate (about 10 micron) as the gases cool to make steam.

The nitrogen in the coal (about 1%) is the major source of NOx (about 85%) from coal combustion. Thermal NOx, formed from oxidation of nitrogen at high temperatures (above 2,300F) in the furnace, comprise the balance of NOx emissions.

In the late 1970s, combustion research by Dr. A.E. Axworthy, principal scientist at Rocketdyne, confirmed that the nitrogen in coal forms NOx, or the precursors of NOx such as ammonia (NH3) and cyanide, at the same time and place as the carbon is oxidized. Further, he demonstrated that this fuel-NOx formation process cannot be avoided when firing coal, as compared to thermal NOx formation when firing natural gas.

A theory evolved to look for a process to reduce (destroy) NOx to nitrogen. A lab furnace was set up and it was determined that the CaS compound was a gangbuster NOx-destruct catalysis, especially under fuel-rich, high-temperature conditions, such as found in the CCS. This was a remarkable discovery.

Rockwells new burner concept provided sulfur capture with synergistic NOx destruction all within the combustion step. An SCR catalysis and NH3 are not needed for NOx control. As important, follow-on CCS programs have demonstrated the CCS NOx control process operates reliably from initial startup to full-load operation (Figure 5), generally reporting about 50 ppm, to meet a strict less than 0.07 lb NOx/MMBtu emission rate.

5. This chart is from a Low NOx/SOx Coal Applications Pilot (LNS-CAP) project, which demonstrated emissions performance of this hybrid gasification scheme while firing Western low-sulfur Powder River Basin-type coals. It achieved SO2 of less than 0.2 lb/MMBtu (about 100 ppm), NOx of less than 0.15 lb/MMBtu (about 110 ppm), high efficiency (loss on ignition of less than 0.1%), and near-zero SO3. Courtesy: CastleLight Energy

Raw Powder River Basin (PRB) coal quality is about 8,560 Btu/lb and includes about 30% water. This moisture carried through the furnace results in a significant latent-heat-of-water energy loss. However, with a simple coal-drying step, PRB quality is improved by about 25% to roughly 10,700 Btu/lb, resulting in about 3% higher combustion efficiency, reduced coal consumption, lower operating costs, and lower CO2 emissions.

Typical large (500-MW) coal-fired EGUs consume about 10,000 tons of coal per day. Coal drying programs such as dry fining require time (about 30 minutes) to dry the coal, resulting in very large equipment investments necessary to supply sufficient coal. Further, dried PRB coal cannot be storedit is a very reactive fuel, and for safety must be consumed immediately.

Conventional direct-fired EGUs use coal mills to grind the coal to a talcum-like powder using hot (about 600F) primary air from the air preheater as a sweep-gas to convey the powdered coal from the mill to the coal burners on the furnace. As noted, the CCS gasification process uses very little combustion air as compared to typical coal burners, so an indirect coal-fired system is used, directing the coal from the mill to a small baghouse to remove the sweep-gas and collect the powdered coal in a hopper.

Rather than use hot primary air for the sweep-gas, the CCS uses hot (about 600F) inert flue gas (oxygen less than 10%) drawn from the EGUs exhaust, which is possible because the CCS exhaust gases have near-zero SO3. As the coal is pulverized, the hot sweep-gas evaporates the coals surface moisture (from about 30% to about 7%), safely drying the coal particles in about one second (Figure 6).

The sweep-gas conveys the pulverized coal and limestone from the mill to a small baghouse (Figure 7) added to each coal mill. In the baghouse, the powdered coal is separated from the wet sweep-gas. The dry powdered coal is then collected in the baghouse hopper, and directly metered and conveyed to the CCS burners as required to meet EGU firing loads. The now cool and wet sweep-gas from the baghouse is rerouted around the furnace to the EGUs exhaust.

It is generally accepted by the utility industry that the best Rankine Cycle heat rates (Btu/kWh) for EGUs require supercritical, high-temperature, high-pressure steam boilers. These units operate best at full loads, are limited in turn-down, and require expensive, exotic steels to survive the high temperatures. Also, todays electric grid requires EGUs that are capable of rapid response to match loads that meet load variation from renewable solar and wind generation.

However, the proposed CCS-SG is a subcritical boiler design, featuring supercritical heat-rate performance (in excess of 42% efficiency, better than 8,100 Btu/kWh). This design can provide wide load followingfrom low-load, overnight operation at about 25% of maximum continuous rating (MCR) with the ability to ramp up at about 4% MCR per minute to 100% MCR operation.

The subcritical CCS-SG is sized for about 350 MWe and operates from 2,400 psig to 2,520 psig, or as close to these pressures as can be done safely. The CCS-SG includes one or two reheat steam cycles to the turbine and an efficient feedwater heater system, for example, a total of eight feedwater heaters, one being the deaerator. Natural gas, supplemented with coal co-firing, is used for startup and warmup duty in about five hours.

The CCS-SG is a compact heat-recovery furnace/steam generation section that includes multiple stages of OFA. There are six 50 ton/hr coal pulverizers and coal-drying systemsone for each GC and its CCS burners. Near the furnace bottom are six CCS GCs (three located on each side of the furnace), each GC directs its hot gases into the furnace section and each has four down-fired, entrained-flow, CCS burners, for a total of 24 CCS burners. Each CCS burner is sized for about 150 MMBtu/hr.

The hot gases from the GC must make a 180-degree turn to enter the furnace. Each GC includes water-cooled slag screens that remove half of the liquid ash, which then drains into a water-quench tank under the GC. A wet-drag-link system conveys the ash/slag into a dumpster for disposal. This slag product has commercial value of about $3/ton for roof grit, and it is suitable for grit-blasting metal, as it doesnt cause silicosis.

The CCS-SG can fire PRB subbituminous and lignitelow-sodium coalsto meet the strict EPA air quality regulations for a new coal-fired EGU, that is, SO2 emissions of less than 0.13 lb/MMBtu or about 66 ppm and NOx emissions of less than 0.07 lb/MMBtu or about 50 ppm. A baghouse is required for fly ash particulate control (less than 0.13 lb/MMBtu).

To optimize the EGU efficiency objectives, the steam turbine generator and other large rotating equipment is designed for high-efficiency service. CastleLight recommends the design criteria presented in the report titled Program for Coal-fired Electrical Generation Units to Maximize these Objectives: Boiler Efficiency Electrical Generation (kW) for a Given Fuel Rate (Btu/hr), Reliability and Availability, as well as Operability, written by Dr. Melvin Giberson, president of TRI Transmission and Bearing Corp.

As mentioned, the cost for a coal-fired EGU includes FGD and SCR pollution emissions control. As the 21st century CCS-SG does not require this equipment, it is expected to save an EGU about 35% compared to conventional boiler technology.

For commercialization, CastleLight recommends forming an investor group to acquire a PRB coal-fired power plant (100 MW to 200 MW with its Title V permit current). This organization can then re-engineer the plant with CCS technology. As an emissions reduction program, the CAAAs provide construction permits with waivers of New Source Performance Standards (NSPS) and Prevention of Significant Deterioration (PSD) with no New Source Review (NSR) trigger. Table 3 shows that such a CCS re-engineering project can make a coal-fired EGU competitive with that of a new natural gas-fired combustion turbine in combined cycle mode with gas at $3.00/MMBtu or higher.

With commissioning, testing, and tuning for optimum performance, and a few years of operation, the first CCS-SG EGU may then be sold to recover the investment. Thus, proving CSS-SG as a commercial system for use worldwide.

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