Global ETD Search

1	Thermo-economic Analysis of Retrofitting an Existing Coal-Fired Power Plant with Solar Heat Shimeles, Surafel January 2014 (has links) At a time when global environmental change is posing a growing challenge to the world’s economy and creating uncertainties to livelihood of its inhabitants, Coal thermal power plants are under pressure to meet stringent environmental regulations into achieving worldwide set millennial goals for mitigating the effect of emission gases on the atmosphere. Owing to its abundance, it is unlikely to see the use of coal completely missing from the global energy mix within the next hundred years to come. While innovative emission reduction technologies are evolving for the better, trendy technological solutions which require reintegration of these coal plants with alternative greener fuels are growing at the moment. Among these solutions, the following paper investigates possible means for repowering a coal steam power plant with indirect solar heating solutions to boost its annual outputs. Two widely deployable solar thermal technologies, parabolic trough and Central tower receiver systems, are introduced at different locations in the steam plant to heat working fluid thereby enhancing the thermodynamic quality of steam being generated. Potential annual energy output was estimated using commercially available TRNSYS software upon mass and heat balance to every component of solar and steam plant. The annual energy outputs are weighed against their plant erecting and running costs to evaluate the economic vitality of the proposed repowering options. The results show that parabolic trough heating method could serve as the most cost effective method generating electricity at competitive prices than solar only powered SEGS plants. While cost may be acceptable in the unit of energy sense, the scale of implementation has been proven to be technically limited. / Kriel Power Plant Hybrid coal power plant solar thermal system Thermo-economic analysis
2	CO<sub>2</sub> Capture With MEA: Integrating the Absorption Process and Steam Cycle of an Existing Coal-Fired Power Plant Alie, Colin January 2004 (has links) In Canada, coal-fired power plants are the largest anthropogenic point sources of atmospheric CO<sub>2</sub>. The most promising near-term strategy for mitigating CO<sub>2</sub> emissions from these facilities is the post-combustion capture of CO<sub>2</sub> using MEA (monoethanolamine) with subsequent geologic sequestration. While MEA absorption of CO<sub>2</sub> from coal-derived flue gases on the scale proposed above is technologically feasible, MEA absorption is an energy intensive process and especially requires large quantities of low-pressure steam. It is the magnitude of the cost of providing this supplemental energy that is currently inhibiting the deployment of CO<sub>2</sub> capture with MEA absorption as means of combatting global warming. The steam cycle of a power plant ejects large quantities of low-quality heat to the surroundings. Traditionally, this waste has had no economic value. However, at different times and in different places, it has been recognized that the diversion of lower quality streams could be beneficial, for example, as an energy carrier for district heating systems. In a similar vein, using the waste heat from the power plant steam cycle to satisfy the heat requirements of a proposed CO<sub>2</sub> capture plant would reduce the required outlay for supplemental utilities; the economic barrier to MEA absorption could be removed. In this thesis, state-of-the-art process simulation tools are used to model coal combustion, steam cycle, and MEA absorption processes. These disparate models are then combined to create a model of a coal-fired power plant with integrated CO<sub>2</sub> capture. A sensitivity analysis on the integrated model is performed to ascertain the process variables which most strongly influence the CO<sub>2</sub> energy penalty. From the simulation results with this integrated model, it is clear that there is a substantial thermodynamic advantage to diverting low-pressure steam from the steam cycle for use in the CO<sub>2</sub> capture plant. During the course of the investigation, methodologies for using Aspen Plus?? to predict column pressure profiles and for converging the MEA absorption process flowsheet were developed and are herein presented. Chemical Engineering CO2 capture MEA monoethanolamine process integration steam cycle coal power plant
3	CO<sub>2</sub> Capture With MEA: Integrating the Absorption Process and Steam Cycle of an Existing Coal-Fired Power Plant Alie, Colin January 2004 (has links) In Canada, coal-fired power plants are the largest anthropogenic point sources of atmospheric CO<sub>2</sub>. The most promising near-term strategy for mitigating CO<sub>2</sub> emissions from these facilities is the post-combustion capture of CO<sub>2</sub> using MEA (monoethanolamine) with subsequent geologic sequestration. While MEA absorption of CO<sub>2</sub> from coal-derived flue gases on the scale proposed above is technologically feasible, MEA absorption is an energy intensive process and especially requires large quantities of low-pressure steam. It is the magnitude of the cost of providing this supplemental energy that is currently inhibiting the deployment of CO<sub>2</sub> capture with MEA absorption as means of combatting global warming. The steam cycle of a power plant ejects large quantities of low-quality heat to the surroundings. Traditionally, this waste has had no economic value. However, at different times and in different places, it has been recognized that the diversion of lower quality streams could be beneficial, for example, as an energy carrier for district heating systems. In a similar vein, using the waste heat from the power plant steam cycle to satisfy the heat requirements of a proposed CO<sub>2</sub> capture plant would reduce the required outlay for supplemental utilities; the economic barrier to MEA absorption could be removed. In this thesis, state-of-the-art process simulation tools are used to model coal combustion, steam cycle, and MEA absorption processes. These disparate models are then combined to create a model of a coal-fired power plant with integrated CO<sub>2</sub> capture. A sensitivity analysis on the integrated model is performed to ascertain the process variables which most strongly influence the CO<sub>2</sub> energy penalty. From the simulation results with this integrated model, it is clear that there is a substantial thermodynamic advantage to diverting low-pressure steam from the steam cycle for use in the CO<sub>2</sub> capture plant. During the course of the investigation, methodologies for using Aspen Plus® to predict column pressure profiles and for converging the MEA absorption process flowsheet were developed and are herein presented. Chemical Engineering CO2 capture MEA monoethanolamine process integration steam cycle coal power plant
4	Optimum usage and economic feasibility of animal manure-based biomass in combustion systems Carlin, Nicholas T. 2009 May 1900 (has links) Manure-based biomass (MBB) has the potential to be a source of green energy at large coal-fired power plants and on smaller-scale combustion systems at or near confined animal feeding operations. Although MBB is a low quality fuel with an inferior heat value compared to coal and other fossil fuels, the concentration of it at large animal feeding operations can make it a viable source of fuel. Mathematical models were developed to portray the economics of co-firing and reburning coal with MBB. A base case run of the co-fire model in which a 95:5 blend of coal to low-ash MBB was burned at an existing 300-MWe coal-fired power plant was found to have an overall net present cost of $22.6 million. The most significant cost that hindered the profitability of the co-fire project was the cost of operating gas boilers for biomass dryers that were required to reduce the MBB's moisture content before transportation and combustion. However, a higher dollar value on avoided nonrenewable CO2 emissions could overrule exorbitant costs of drying and transporting the MBB to power plants. A CO2 value of $17/metric ton was found to be enough for the MBB co-fire project to reach an economic break-even point. Reburning coal with MBB to reduce NOx emissions can theoretically be more profitable than a co-fire project, due to the value of avoided NOx emissions. However, the issue of finding enough suitable low-ash biomass becomes problematic for reburn systems since the reburn fuel must supply 10 to 25% of the power plant?s heat rate in order to achieve the desired NOx level. A NOx emission value over $2500/metric ton would justify installing a MBB reburn system. A base case run of a mathematical model describing a small-scale, on-the-farm MBB combustion system that can completely incinerate high-moisture (over 90%) manure biomass was developed and completed. If all of the energy or steam produced by the MBB combustion system were to bring revenue to the animal feeding operation either by avoided fueling costs or by sales, the conceptualized MBB combustion system has the potential to be a profitable venture. Cattle Manure Biomass Combustion Engineering Economics Coal Power Plant Co-firing and Reburning Waste Disposal
5	Economic Evaluation of an Advanced Super Critical Oxy-Coal Power Plant with CO2 Capture Beigzadeh, Ashkan January 2009 (has links) Today’s carbon constrained world with its increasing demand for cheap energy and a fossil fuel intensive fleet of power producers is making carbon capture and storage (CCS) desirable. Several CCS technologies are under investigation by various research and development groups globally. One of the more promising technologies is oxy-fuel combustion, since it produces a CO2 rich flue gas which requires minor processing to meet storage condition requirements. In this study the economics of an advanced super critical oxy-coal power plant burning lignite, simulated in-house was assessed. A robust and user-friendly financial tool box has been developed with commonly acceptable default parameter settings. Capital, operation and maintenance costs were estimated along with corresponding levelized cost of electricity and CO2 avoidance costs calculated using the detailed financial model developed. A levelized cost of electricity of 131 $/MWhrnet along with a levelized CO2 avoidance cost of 64 $/tonne was estimated for an ASC oxy-coal power plant with CO2 capture. Also a levelized cost of electricity of 83 $/MWhrnet was estimated for an ASC air-fired coal power plant without CO2 capture capabilities as the base plant. The price of electricity was observed to increase from 83 $/MWhrnet to 131 $/MWhrnet translating into a 57% increase. The sensitivity of the overall economics of the process was assessed to several parameters. The overall economics was found sensitive to the choice chemical engineering plant cost index (CEPCI), capacity factor, size of power plant, debt ratio, fuel price, interest rate, and construction duration. CO2 capture oxy-fuel advanced super critical Carbon capture coal power plant levelized cost of electricity financial modelling LCOE avoidance cost oxy-coal CCS ASC CANMET Emission GHG Greenhouse gas Chemical Engineering
6	Economic Evaluation of an Advanced Super Critical Oxy-Coal Power Plant with CO2 Capture Beigzadeh, Ashkan January 2009 (has links) Today???s carbon constrained world with its increasing demand for cheap energy and a fossil fuel intensive fleet of power producers is making carbon capture and storage (CCS) desirable. Several CCS technologies are under investigation by various research and development groups globally. One of the more promising technologies is oxy-fuel combustion, since it produces a CO2 rich flue gas which requires minor processing to meet storage condition requirements. In this study the economics of an advanced super critical oxy-coal power plant burning lignite, simulated in-house was assessed. A robust and user-friendly financial tool box has been developed with commonly acceptable default parameter settings. Capital, operation and maintenance costs were estimated along with corresponding levelized cost of electricity and CO2 avoidance costs calculated using the detailed financial model developed. A levelized cost of electricity of 131 $/MWhrnet along with a levelized CO2 avoidance cost of 64 $/tonne was estimated for an ASC oxy-coal power plant with CO2 capture. Also a levelized cost of electricity of 83 $/MWhrnet was estimated for an ASC air-fired coal power plant without CO2 capture capabilities as the base plant. The price of electricity was observed to increase from 83 $/MWhrnet to 131 $/MWhrnet translating into a 57% increase. The sensitivity of the overall economics of the process was assessed to several parameters. The overall economics was found sensitive to the choice chemical engineering plant cost index (CEPCI), capacity factor, size of power plant, debt ratio, fuel price, interest rate, and construction duration. CO2 capture oxy-fuel advanced super critical Carbon capture coal power plant levelized cost of electricity financial modelling LCOE avoidance cost oxy-coal CCS ASC CANMET Emission GHG Greenhouse gas
7	Dynamische Modellierung des Gaspfades eines Gesamt-IGCC-Kraftwerkes auf Basis des SFG-Verfahrens Bauersfeld, Sindy 08 August 2014 (has links) (PDF) Im Rahmen der vorliegenden Arbeit werden dynamische Modelle eines IGCC-Kraftwerkes mit CO2-Abtrennung unter Verwendung des Modellierungstools Modelica/Dymola entwickelt. Dabei liegt der Schwerpunkt auf dem Gaspfad der Gasreinigung. Es ist vorteilhaft, für verschiedene Aufgaben, Modelle mit unterschiedlicher Tiefe zu verwenden. Mit den detaillierten Modellen werden Simulationen der Teilprozesse durchgeführt. Für den Aufbau eines Gesamtsystems werden vereinfachte Modelle verwendet. Anhand des Gesamtsystems werden drei Regelkonzepte (Gleitdruckregelung, Leistungsregelung der Gasturbine, Leistungsregelung des Vergasers) untersucht und bewertet. Des Weiteren werden drei Störfallszenarien (Ausfall des Sättigers im Brennstoffsystem, Betriebsstörung in der Vergaserinsel, Unterbrechung der Stickstoffzumischung im Brennstoffsystem) getestet. IGCC SFG Vergaser Störfall Gleitdruckregelung Leistungsregelung Modelica Dymola Dynamische Modellierung Regelkonzept Kohlekraftwerk CCS IGCC CCS control trip Modelica Dymola dynamic modelling coal power plant SFG gasifier ddc:620 Kombinationskraftwerk Kohlevergasung Kohlekraftwerk Dynamische Modellierung Carbon dioxide capture and storage Leistungsregelung Regelungssystem Störfall Druckregelung Modelica
8	Dynamische Modellierung des Gaspfades eines Gesamt-IGCC-Kraftwerkes auf Basis des SFG-Verfahrens Bauersfeld, Sindy 17 June 2014 (has links) Im Rahmen der vorliegenden Arbeit werden dynamische Modelle eines IGCC-Kraftwerkes mit CO2-Abtrennung unter Verwendung des Modellierungstools Modelica/Dymola entwickelt. Dabei liegt der Schwerpunkt auf dem Gaspfad der Gasreinigung. Es ist vorteilhaft, für verschiedene Aufgaben, Modelle mit unterschiedlicher Tiefe zu verwenden. Mit den detaillierten Modellen werden Simulationen der Teilprozesse durchgeführt. Für den Aufbau eines Gesamtsystems werden vereinfachte Modelle verwendet. Anhand des Gesamtsystems werden drei Regelkonzepte (Gleitdruckregelung, Leistungsregelung der Gasturbine, Leistungsregelung des Vergasers) untersucht und bewertet. Des Weiteren werden drei Störfallszenarien (Ausfall des Sättigers im Brennstoffsystem, Betriebsstörung in der Vergaserinsel, Unterbrechung der Stickstoffzumischung im Brennstoffsystem) getestet. info:eu-repo/classification/ddc/620 ddc:620

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