Combustion fired power plants, conventional

Coal Conventional Coal-fired Power Plant NG Advanced Namral Gas Power Planl DC Direct Combustion... 

This work by Heidelberg has been significant in that it demonstrated for the first time that TDL sensors can provide temporally resolved in situ measurements of temperature and species concentrations in the combustion zone of a coal-fired power plant. These measurements are not attainable using conventional sensors. Perhaps even more importantly, the body of work by Heidelberg demonstrates that TDL sensors can be made rugged enough to survive harsh industrial environments, including waste incinerators and power plants. 

The United States Department of Energy sponsors many research projects, particularly into next-generation pressurized fluid bed combustion combined-cycle power plants. The goal is to design plants with a net system efficiency of more than 50 percent, extremely low sulfur and nitrogen oxide emissions well below 2010 emission limits, and at a power-generation cost of three-quarters by a conventional coal-fired power plant. The European Union similarly sponsors research in this area, as does Japan and other developed or developing countries. 

An IGCC plant generally produces fewer water effluents than a conventional coal-fired power plant does. The amount of process water blowdown is about the same for both gasification and direct coal combustion. However, the steam cycle in IGCC power plants produces much smaller amounts of wastewater blowdown because less than 40% of the total power generated comes from the steam cycle. 

A conventional power plant fired by fossil fuels converts the chemical energy of combustion of the fuel first to heat, which is used to raise steam, which in turn is used to drive the turbines that turn the electrical generators. Quite apart from the mechanical and thermal energy losses in this sequence, the maximum thermodynamic efficiency e for any heat engine is limited by the relative temperatures of the heat source (That) and heat sink (Tcoid) ... 

More efficient coal utilization can be realized with combined power plant cycles. For instance, the post combustion gases of a conventional combustor or an advanced MHD system can be further utilized to drive a gas or steam turbine. However, the sustained durability of downstream turbine or heat exchanger components requires minimal transport of corrosive fuel impurities. Control of mineral-derived impurities is also required for environmental protection. For the special case of open cycle-coal fired MHD systems, the thermodynamic activity of potassium is much higher in the seeded combustion gas (plasma) than in common coal minerals and slags. This results in the loss of plasma seed by slag absorption and is of critical concern to the economic feasibility of MHD. 

Because of the growing importance of carbon dioxide sequestration, there is currently a lively debate as to whether future coal-fired power stations should be conventional pulverized fuel, oxy-fuel or gasification designs. This is by no means a straightforward choice and involves considerations of overall fuel efficiency, engineering complexity and capital and operating costs. In addition, there are many types of coal (anthracite, bituminous coal, brown coal) with possibly dissimilar impurity contents, each of which may dictate a different plant design. The jury is still out on whether future coal-fired power stations will employ post-combustion or pre-combustion capture of carbon dioxide this is a crucial issue to decide as the plants have a life of 40—50 years. 

The most aggressive component is SO2, 90% of which is a result of the combustion of sulfurous fossil energy carriers (coal, coke, oil), especially from coal fired stoves, conventional power plants, and other furnaces and which, by oxidation into sulfuric acid, essentially hastens the corrosion of metallic materials. SO2 becomes especially noxious the moment it is... 

With modifications, IGCC power plant designs could recover CO2. The CO in the coal gas can convert to hydrogen (H2) and CO2 by reaction with H2O. This so-called shift reaction is common in the manufacture of ammonia and hydrogen gas. Modified IGCC could remove COj at pressure by conventional acid gas removal technology and then fire the remaining H2-rich fuel gas in a combustion turbine. 

Modification of direct coal combustion for CO2 removal would be more difficult. CO2 could be removed from the flue gas after conventional combustion by acid gas removal technology. Although this approach has found some commercial application, the low pressure and low concentration of the CO2 in the flue gas makes it a relatively expensive method. Removing 90% of the CO2 from flue gas of a conventional coal-fired boiler would increase the capital cost by a factor of 3.0 and thermal efficiency drops by 12% compared to a conventional direct coal combustion power plant. The larger capital increase and efficiency loss with CO2 recovery is principally due to recovery at low pressure which requires a larger flue gas compression, CO2 absorbers, and increased steam requirements. Depending on the cost of coal and capital, the increased electric cost for CO2 removal with a direct coal combustion power plant is 2.0-3.0 times that of a conventional direct coal combustion power plant. 

Pressurized fluidized bed combustion (in a coal-fired thermal plant) offers efficiency and reduction in environmental loads. The coal ash produced in this process is a consequence of firing a mixture of pulverized limestone and coal. In this process, the mixes are burned at a lower temperature than that carried out in the conventional power plant which produces fly ash. There is a possibility of utilizing coal ash as an admixture in concrete. Thermal analysis of the hydration products obtained at different w/s ratios fi om coal ash-cement pastes indicated substantially lower amounts of lime than that estimated in pure cement pastes, This indicates... 

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