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Tesi sul tema "Coal-fired power plants"

Autore: Grafiati

Pubblicato: 4 giugno 2021

Ultima modifica: 1 agosto 2024

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1

Moumakwa, Donald Omphemetse. "Tribology in coal-fired power plants". Master's thesis, University of Cape Town, 2005. http://hdl.handle.net/11427/16616.

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Includes bibliographical references (pages 90-94).
A series of alumina ceramics and silicon carbide (SiC) particulate composites were evaluated in terms of their erosive and abrasive wear behaviour under different conditions, with the aim of reducing wear damage in power plants. The alumina ceramics tested ranged in composition from 90% alumina to 97% alumina content. A nitride fired and an oxide fired SiC particulate composites were also tested for comparison. The impact angle, impact velocity, as well as particle size and type were varied for solid-partide erosion, whereas effects of the applied load, abrasive speed and type of abrasive were studied for abrasive wear. The target materials were also evaluated in terms of morphology and mechanical properties including hardness, flexural modulus and flexural strengths. The erosion rates of the tested alumina ceramics increase with an increase in the impact angle, reaching a maximum at 90°. The high purity 96% alumina dry-pressed body has the best erosion resistance at most impact angles, while the 92% alumina dry pressed body has the worst erosion resistance. The erosion rates also increased with an increase in particle impact velocity, resulting in a velocity exponent (n) value of 1.5. A decrease in the erosion rate was observed for both an increase in particle size range and a decrease in erodent partide hardness. At all angles of impact, solid partide erosion of the target materials is dominated by intergranular fracture and surfaces are typically characterized by erosion pits. The five alumina target materials also show a marked increase in erosion rates when the test temperature is increased from ambient to 150°C. The abrasive wear rates for the materials increased with both applied load and abrasive speed, owing to increased tribological stresses at the contacting asperities. There is also a general trend of increasing abrasion resistance with increasing alumina content. Severe wear, characterized by fracture and grain pullout, is the dominant mechanism of material removal during abrasive wear. This was accompanied by the formation of grooves on the wear surfaces. Although this study was successful in terms of material selection for wear damage reduction in power plants, it also highlighted significant factors and modifications that might need to be considered in future studies.

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2

Dugstad, Tore, e Esben Tonning Jensen. "CO2 Capture from Coal fired Power Plants". Thesis, Norwegian University of Science and Technology, Department of Energy and Process Engineering, 2008. http://urn.kb.se/resolve?urn=urn:nbn:no:ntnu:diva-9770.

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Coal is the most common fossil resource for power production worldwide and generates 40% of the worlds total electricity production. Even though coal is considered a pollutive resource, the great amounts and the increasing power demand leads to extensive use even in new developed power plants. To cover the world's future energy demand and at the same time limit our effect on global warming, coal fired power plants with CO2 capture is probably a necessity. An Integrated Gasification Combined Cycle (IGCC) Power Plant is a utilization of coal which gives incentives for CO2 capture. Coal is partially combusted in a reaction with steam and pure oxygen. The oxygen is produced in an air separation process and the steam is generated in the Power Island. Out of the gasifier comes a mixture of mainly H2 and CO. In a shift reactor the CO and additional steam are converted to CO2 and more H2. Carbon dioxide is separated from the hydrogen in a physical absorption process and compressed for storage. Hydrogen diluted with nitrogen from the air separation process is used as fuel in a combined cycle similar to NGCC. A complete IGCC Power Plant is described in this report. The air separation unit is modeled as a Linde two column process. Ambient air is compressed and cooled to dew point before it is separated into oxygen and nitrogen in a cryogenic distillation process. Out of the island oxygen is at a purity level of 95.6% and the nitrogen has a purity of 99.6%. The production cost of oxygen is 0.238 kWh per kilogram of oxygen delivered at 25°C and 1.4bar. The oxygen is then compressed to a gasification pressure of 42bar. In the gasification unit the oxygen together with steam is used to gasify the coal. On molar basis the coal composition is 73.5% C, 22.8% H2, 3.1% O2, 0.3% N2 and 0.3% S. The gasification temperature is at 1571°C and out of the unit comes syngas consisting of 66.9% CO, 31.1% H2, 1.4% H2O, 0.3% N2, 0.2% H2S and 0.1% CO2. The syngas is cooled and fed to a water gas shift reactor. Here the carbon monoxide is reacted with steam forming carbon dioxide and additional hydrogen. The gas composition of the gas out of the shift reactor is on dry basis 58.2% H2, 39.0% CO2, 2.4% CO, 0.2% N2 and 0.1% H2S. Both the gasification process and shift reactor is exothermal and there is no need of external heating. This leads to an exothermal heat loss, but parts of this heat is recovered. The gasifier has a Cold Gas Efficiency (CGE) of 84.0%. With a partial pressure of CO2 at 15.7 bar the carbon dioxide is easily removed by physical absorption. After separation the solvent is regenerated by expansion and CO2 is pressurized to 110bar to be stored. This process is not modeled, but for the scrubbing part an energy consumption of 0.08kWh per kilogram CO2 removed is assumed. For the compression of CO2, it is calculated with an energy consumption of 0.11kWh per kilogram CO2 removed. Removal of H2S and other pollutive unwanted substances is also removed in the CO2 scrubber. Between the CO2 removal and the combustion chamber is the H2 rich fuel gas is diluted with nitrogen from the air separation unit. This is done to increase the mass flow through the turbine. The amount of nitrogen available is decided by the amount of oxygen produced to the gasification process. Almost all the nitrogen produced may be utilized as diluter except from a few percent used in the coal feeding procedure to the gasifier. The diluted fuel gas has a composition of 50.4% H2, 46.1% N2, 2.1% CO and 1.4% CO2. In the Power Island a combined cycle with a gas turbine able to handle large H2 amounts is used. The use of steam in the gasifier and shift reactor are integrated in the heat recovery steam generator (HRSG) in the steam cycle. The heat removed from the syngas cooler is also recovered in the HRSG. The overall efficiency of the IGCC plant modeled is 36.8%. This includes oxygen and nitrogen production and compression, production of high pressure steam used in the Gasification Island, coal feeding costs, CO2 removal and compression and pressure losses through the processes. Other losses are not implemented and will probably reduce the efficiency.

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3

Eastwick, Carol Norma. "Mathematical modelling of pulverised coal-fired burners". Thesis, University of Nottingham, 1995. http://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.283535.

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4

Edge, Penelope Jayne. "Modelling and simulation of oxy-coal fired power plants". Thesis, University of Leeds, 2011. http://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.550804.

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Meeting energy demand while mitigating catastrophic climate change is a serious challenge faced by governments around the globe. The role of coal in the energy mix is integral to this problem: coal is a relatively cheap, flexible and plentiful energy resource; however it is also one of the most polluting. CO2 emissions from coal-fired power plants contribute to global warming. Development and deployment of carbon capture and sequestration (CCS) technology is vital in order to reduce the environmental impact of burning coal. CCS involves capturing and purifying C02 from the emission source and then sequestering it safely and securely to avoid emission to the atmosphere. Oxyfuel combustion, in which the fuel is burnt in a mixture of pure oxygen and recycled flue gas instead of air, is a viable option for CCS from coal-fired power plants. The subject of this discourse is modelling and simulation of oxy-coal combustion. Accurate prediction of the operating characteristics of oxy-coal plants is a vital step towards deployment of the technology. This requires a fundamental understanding of the processes involved and how they might differ from conventional air-firing operation. The distribution of the furnace heat transfer determines the integration between the gas and the water/steam cycles. In order for existing boiler technology to be converted to oxyfuel operation, heat transfer in an oxy-coal furnace should be very similar to air-firing. A combination of fundamental modelling, fluid dynamics, and process simulation have been applied in order to study the impact of oxyfuel combustion on electricity generation. Effectively, nitrogen is replaced with CO2 in the combustion gases and this will affect the gas specific heat capacity, thermal conductivity, diffusivity and absorptivity/emissivity and hence change the rate of convective and radiative heat transfer. The gas-side heat transfer processes are intrinsically linked to chemical reactions and turbulence, and these are accounted for using a CFD model of the furnace. The CFD-generated data are then linked to a full plant simulation in order to investigate the impact of oxyfuel combustion on plant operation. The heat transfer components in the full plant model are developed specifically for detailed prediction of heat transfer and account for changes in composition and mass flow of the flue gases. A range of inlet oxygen concentrations varying from 21-35 vol-% and recycle ratios varying from 80-65% are investigated and the combined simulations reveal a 'working range' of approximately 30-33% inlet oxygen and 72-68% recycle ratio where the distribution of heat transfer is sufficiently similar to allow the plant to operate within the given set- points for air-firing.

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5

Arcot, Vijayasarathy Udayasarathy. "Mercury emission control for coal fired power plants using coal and biomass". [College Station, Tex. : Texas A&M University, 2007. http://hdl.handle.net/1969.1/ETD-TAMU-2535.

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6

Guler, Mehmet. "Evaluation Of State Owned Indigenous Coal Fired Power Plants Including Coal Reserves". Master's thesis, METU, 2010. http://etd.lib.metu.edu.tr/upload/12611591/index.pdf.

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Fossil fuels has preserved their importance in gradually increasing production and consumption of both energy and electricity of the world. Asia, especially China and India, has arisen new actors of the sector. Energy and electricity consumption of Turkey has also increased in parallel with her economic development, but due to her limited resources, she has become more and more energy dependent in order to meet her growing demand. Although hard coal is only found around Zonguldak region, with its abundant and widely spread reserves, Turkey ranked world&rsquo
s third place in lignite production in 2008. Having low calorific value together with high ash and moisture content, most of lignites extracted is being consumed in thermic power plants located near those reserves. In the first two chapters of this study, energy in the world and Turkey will be considered seperately, then coal resources in Turkey will be analysed in the next coming chapter. Indirect and direct greenhouse emissions presented to the UNFCCC will be handled in the fifth chapter In the last chapter, first past and present performances of all indigenous coal fired power plants will be analysed, then after projecting their generation and fuel needs, they are evaluated considering with the reserves they are located. Finally, at the end of decomissioning of those power plants, remaining reserves will be re-evaluated and additional new units will be proposed accordingly.

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7

Peng, J. X. "NOx emission modelling from coal-fired power generation boilers". Thesis, Queen's University Belfast, 2003. http://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.273143.

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8

Berry, David A. "Investigation of hot gas desulfurization utilizing a transport reactor". Morgantown, W. Va. : [West Virginia University Libraries], 1999. http://etd.wvu.edu/templates/showETD.cfm?recnum=500.

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Thesis (M.S.)--West Virginia University, 1999.
Title from document title page. Document formatted into pages; contains vi, 101 p. : ill. (some col.) Includes abstract. Includes bibliographical references (p. 82-85).

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9

Baziotopoulos, Con, e mikewood@deakin edu au. "Utilising solar energy within conventional coal fired power stations". Deakin University. School of Engineering and Technology, 2002. http://tux.lib.deakin.edu.au./adt-VDU/public/adt-VDU20060817.145445.

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Although the thermodynamic advantages of using solar energy to replace the bled off steam in the regeneration system of Rankine cycle coal fired power stations has been proven theoretically, the practical techno/economic feasibility of the concept has yet to be confirmed relative to real power station applications. To investigate this concept further, computer modelling software THERMSOLV was specifically developed for this project at Deakin University, together with the support of the Victorian power industry and Australian Research Council (ARC). This newly developed software simulates the steam cycle to assess the techno/economic merit of the solar aided concept for various power station structures, locations and local electricity market conditions. Two case studies, one in Victoria Australia and one in Yunnan Province, China, have been carried out with the software. Chapter one of this thesis defines the aims and scope of this study. Chapter two details the literature search in the related areas for this study. The thermodynamic concept of solar aid power generation technology has been described in chapter three. In addition, thermodynamic analysis i.e. exergy/availability has been described in this chapter. The Thermosolv software developed in this study is detailed in chapter four with its structure, functions and operation manual included. In chapter five the outcomes of two case studies using the Thermosolv software are presented, with discussions and conclusions about the study in chapters 6 and 7 respectfully. The relevant recommendations are then made in chapter eight.

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10

Cantrell, Corey L. "Performance modeling of a pulverized coal boiler : a dissertation presented to the faculty of the Graduate School, Tennessee Technological University /". Click to access online version, 2007. http://proquest.umi.com/pqdweb?index=78&did=1445047991&SrchMode=1&sid=1&Fmt=6&VInst=PROD&VType=PQD&RQT=309&VName=PQD&TS=1255119231&clientId=28564.

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11

Furl, Chad Van Lehr Larry L. Van Walsum G. Peter White Joseph Daniel. "A baseline assessment of local mercury deposition from coal-fired power plants in Central Texas". Waco, Tex. : Baylor University, 2006. http://hdl.handle.net/2104/4741.

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12

Fay, James A., e Dan S. Golomb. "Economics of seasonal gas substitution in coal- and oil-fired power plants". MIT Energy Lab, 1987. http://hdl.handle.net/1721.1/18199.

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13

Sekar, Ram Chandra. "Carbon dioxide capture from coal-fired power plants : a real potions analysis". Thesis, Massachusetts Institute of Technology, 2005. http://hdl.handle.net/1721.1/32292.

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Thesis (S.M.)--Massachusetts Institute of Technology, Engineering Systems Division, Technology and Policy Program; and, (S.M.)--Massachusetts Institute of Technology, Dept. of Mechanical Engineering, 2005.
Includes bibliographical references.
Investments in three coal-fired power generation technologies are valued using the "real options" valuation methodology in an uncertain carbon dioxide (CO2) price environment. The technologies evaluated are pulverized coal (PC), integrated coal gasification combined cycle (baseline IGCC), and IGCC with pre-investments that make future retrofit for CO2 capture less expensive (pre-investment IGCC). All coal-fired power plants can be retrofitted to capture CO2 and can be considered "capture-capable", even though the cost and technical difficulty to retrofit may vary greatly. However, initial design and investment that take into consideration such future retrofit, makes the transition easier and less expensive to accomplish. Plants that have such an initial design can be considered to be "capture-ready". Pre-investment IGCC can be considered to be "capture-ready" in comparison to PC and baseline IGCC on this basis. Furthermore, baseline IGCC could be taken as "capture-ready" in comparison to PC. Cash flow models for specific cases of these three technologies were developed based on literature studies. The problem was formulated such that CO2 price is the only uncertain cash flow variable. All cases were designed to have a constant net electric output before and after CO2 retrofit. As a result, electricity price uncertainty had no differential impact on the competitive positions of the different technologies. While coal price was taken to be constant, sensitivity analysis were conducted to show the impact of varying coal prices. Investment valuation was done using the "real options" approach.
(cont.) This approach combines (i) Market Based Valuation (MBV) to valuing cash flow uncertainty, with (ii) Dynamic quantitative modeling of uncertainty, which helps model dynamic retrofit decision making. The thesis addresses three research questions: (i) What is the economic value of temporal flexibility in making the decision to retrofit CO2 capture equipment? (ii) How does the choice of valuation methodology (DCF v. MBV) impact the investment decision to become "capture-ready"? (iii) Among the coal-fired power plant technologies, which should a firm choose to invest in, given an uncertain CO2 policy? What are the economic factors that influence this choice? The answers to the research questions strongly depend on the input assumptions to the cash flow and CO2 price models, and the choice of representative cases of the technologies. For the specific cases analyzed in this thesis, it was found that investing in "capture-ready" power plants was not economically attractive.
by Ram Chandra Sekar.
S.M.

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14

Weir, Scott M. "Mercury concentrations in wetlands associated with coal-fired power plants in Illinois /". Available to subscribers only, 2009. http://proquest.umi.com/pqdweb?did=1796120981&sid=2&Fmt=2&clientId=1509&RQT=309&VName=PQD.

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15

Weir, Scott. "Mercury concentrations in wetlands associated with coal-fired power plants in Illinois". OpenSIUC, 2009. https://opensiuc.lib.siu.edu/theses/540.

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Burning of fossil fuels by coal-fired power plants (CFPPs) is one of the largest sources of environmental mercury in the United States and there have been conflicting reports of local impacts due to CFPPs in the US. Illinois has 23 coal-fired electrical generating plants that may be contributing to elevated environmental mercury concentrations that have contributed to mercury advisories for 13 bodies of water located throughout the state. The objective of the current study is to determine if there is a pattern of total mercury concentrations in sediment and tadpoles collected from ponds located upwind and downwind of 4 coal-fired electrical generating plants in Illinois. Baldwin, Joppa, Newton, and Southern Illinois Power Cooperative (SIPC) coal-fired power plants were chosen for study. Three sediment samples were collected from ponds located 3-5, 8-10, and 13-15 km downwind and from ponds located 3-5 km upwind of each power plant and analyzed for total mercury concentration. Temperature of overlying water (C), pH, oxidation-reduction potential (mV), and texture were determined for each sediment sample. Bullfrog (Lithobates catesbeiana) or Green frog (Lithobates clamitans) tadpoles were collected opportunistically from 29 of the 44 ponds chosen for study. Each tadpole was identified to species and Gosner stage, and then weighed and measured for total length prior to total mercury analysis. For Baldwin, Joppa, and SIPC power plants, no significant pattern of total mercury could be determined from either sediment or tadpole data. For Newton power plant, total mercury concentrations were significantly greater 3-5 km downwind for sediment, and 8-15 km downwind for tadpoles compared to concentrations at upwind locations. Sediment total mercury concentrations were not significantly correlated with any of the characteristic variables (e.g. pH). Tadpole total mercury was significantly negatively correlated with length and weight, but not significantly correlated with any of the sediment variables. Sediment and tadpole concentrations were not significantly correlated.

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16

Lange, Ian. "Investigating the effects of the 1990 Clean Air Act Amendments on inputs to coal-fired power plants /". Thesis, Connect to this title online; UW restricted, 2005. http://hdl.handle.net/1773/7421.

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17

Arumugam, Senthilvasan. "Nitrogen oxides emission control through reburning with biomass in coal-fired power plants". Thesis, Texas A&M University, 2004. http://hdl.handle.net/1969.1/1508.

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Oxides of nitrogen from coal-fired power stations are considered to be major pollutants, and there is increasing concern for regulating air quality and offsetting the emissions generated from the use of energy. Reburning is an in-furnace, combustion control technology for NOx reduction. Another environmental issue that needs to be addressed is the rapidly growing feedlot industry in the United States. The production of biomass from one or more animal species is in excess of what can safely be applied to farmland in accordance with nutrient management plans and stockpiled waste poses economic and environmental liabilities. In the present study, the feasibility of using biomass as a reburn fuel in existing coal-fired power plants is considered. It is expected to utilize biomass as a low-cost, substitute fuel and an agent to control emission. The successful development of this technology will create environment-friendly, low cost fuel source for the power industry, provide means for an alternate method of disposal of biomass, and generate a possible revenue source for feedlot operators. In the present study, the effect of coal, cattle manure or feedlot biomass, and blends of biomass with coal on the ability to reduce NOx were investigated in the Texas A&M University 29.31 kW (100,000 Btu/h) reburning facility. The facility used a mixture of propane and ammonia to generate the 600 ppm NOx in the primary zone. The reburn fuel was injected using air. The stoichiometry tested were 1.00 to 1.20 in the reburn zone. Two types of injectors, circular jet and fan spray injectors, which produce different types of mixing within the reburn zone, were studied to find their effect on NOx emissions reduction. The flat spray injector performed better in all cases. With the injection of biomass as reburn fuel with circular jet injector the maximum NOx reduction was 29.9 % and with flat spray injector was 62.2 %. The mixing time was estimated in model set up as 936 and 407 ms. The maximum NOx reduction observed with coal was 14.4 % and with biomass it was 62.2 % and the reduction with blends lay between that of coal and biomass.

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18

Cheng, Lei. "CO2 Separation from Coal-Fired Power Plants by Regenerable Mg(OH)2 Solutions". University of Cincinnati / OhioLINK, 2013. http://rave.ohiolink.edu/etdc/view?acc_num=ucin1378216250.

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19

Arzuman, Anry Misra Anil. "Fate and aqueous transport of mercury in light of the Clean Air Mercury Rule of coal-fired electric power plants". Diss., UMK access, 2006.

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Thesis (Ph. D.)--School of Computing and Engineering and Dept. of Geosciences. University of Missouri--Kansas City, 2006.
"A dissertation in engineering and geosciences." Advisor: Anil Misra. Typescript. Vita. Title from "catalog record" of the print edition Description based on contents viewed Oct. 30, 2007. Includes bibliographical references (leaves 210-220 ). Online version of the print edition.

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20

Sliger, Rebecca North. "Development of a chemical kinetic model for the homogeneous oxidation of mercury by chlorine species : a tool for mercury emissions control /". Thesis, Connect to this title online; UW restricted, 2001. http://hdl.handle.net/1773/7102.

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Paredez, Jose Miguel. "Coal-fired power plant flue gas desulfurization wastewater treatment using constructed wetlands". Thesis, Kansas State University, 2014. http://hdl.handle.net/2097/18255.

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Master of Science
Department of Civil Engineering
Natalie Mladenov
In the United States approximately 37% of the 4 trillion kWh of electricity is generated annually by combusting coal (USEPA, 2013). The abundance of coal, ease of storage, and transportation makes it affordable at a global scale (Ghose, 2009). However, the flue gas produced by combusting coal affects human health and the environment (USEPA, 2013). To comply with federal regulations coal-fired power plants have been implementing sulfur dioxide scrubbing systems such as flue gas desulfurization (FGD) systems (Alvarez-Ayuso et al., 2006). Although FGD systems have proven to reduce atmospheric emissions they create wastewater containing harmful pollutants. Constructed wetlands are increasingly being employed for the removal of these toxic trace elements from FGD wastewater. In this study the effectiveness of using a constructed wetland treatment system was explored as a possible remediation technology to treat FGD wastewater from a coal-fired power plant in Kansas. To simulate constructed wetlands, a continuous flow-through column experiment was conducted with undiluted FGD wastewater and surface sediment from a power plant in Kansas. To optimize the performance of a CWTS the following hypotheses were tested: 1) decreasing the flow rate improves the performance of the treatment wetlands due to an increase in reaction time, 2) the introduction of microbial cultures (inoculum) will increase the retention capacity of the columns since constructed wetlands improve water quality through biological process, 3) the introduction of a labile carbon source will improve the retention capacity of the columns since microorganisms require an electron donor to perform life functions such as cell maintenance and synthesis. Although the FGD wastewater collected possessed a negligible concentration of arsenic, the mobilization of arsenic has been observed in reducing sediments of wetland environments. Therefore, constructed wetlands may also represent an environment where the mobilization of arsenic is possible. This led us to test the following hypothesis: 4) Reducing environments will cause arsenic desorption and dissolution causing the mobilization of arsenic. As far as removal of the constituents of concern (arsenic, selenium, nitrate, and sulfate) in the column experiments, only sulfate removal increased as a result of decreasing the flow rate by half (1/2Q). In addition, sulfate-S exhibited greater removal as a result of adding organic carbon to the FGD solution when compared to the control (at 1/2Q). Moderate selenium removal was observed; over 60% of selenium in the influent was found to accumulate in the soil. By contrast, arsenic concentrations increased in the effluent of the 1/2Q columns, most likely by dissolution and release of sorbed arsenic. When compared to the control (at 1/2Q), arsenic dissolution decreased as a result of adding inoculum to the columns. Dissolved arsenic concentrations in the effluent of columns with FGD solution amended with organic carbon reached 168 mg/L. These results suggest that native Kansas soils placed in a constructed wetland configuration and amended with labile carbon do possess an environment where the mobilization of arsenic is possible.

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Xu, Jiangang Chemical Sciences &amp Engineering Faculty of Engineering UNSW. "Coal related bed material agglomeration in pressurized fluidized bed combustion". Awarded by:University of New South Wales. School of Chemical Sciences and Engineering, 2006. http://handle.unsw.edu.au/1959.4/25131.

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The thermodynamic behaviours in a PFBC combustor were simulated for the ash from all of the six coals with sand and limestone as bed material. Ash components determined the ash thermodynamic behaviour at high temperature, and each component had different effects. For assessment of the potential for bed material agglomeration, the temperature at which 15% of the ash would become liquid (T15) was calculated with the coal ash, the cyclone ash and the cyclone ash mixed with varying amounts of limestone. Both the bed ash and fly ash, collected from an industrial PFBC plant, consisted of limestone/lime particles with different extent of sulphation, and coal ash particles. The calcium aluminosilicate material formed on the coal ash particles but not on the limestone particles. The aluminosilicate materials appeared to be formed from fine ash and lime particles at some local hot zones in the boiler. The melted materials may glue ash and bed material particle into large particles leading to bed agglomeration and defluidization. Four mechanisms were proposed for the formation of bed material agglomeration in PFBC, which may occur under different conditions. One mechanism explains the bed material agglomeration with the high localized high temperature zone due to the improper design or operation, while the bed agglomeration through the other three mechanisms results from the unsuitable coals burnt in the PFBC combustor. The maximum char temperature and the minimum T15 were used simultaneously to predict the tendency towards bed material agglomeration in PFBC burning different coals. Both char properties and ash properties should be considered during coal selection process for PFBC, to ameliorate the potential problem of bed agglomeration.

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Tolvanen, Merja. "Mass balance determination for trace elements at coal-, peat- and bark-fired power plants /". Espoo [Finland] : VTT Technical Research Centre of Finland, 2004. http://www.vtt.fi/inf/pdf/publications/2004/P524.pdf.

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Chalmers, Hannah. "Flexible operation of coal-fired power plants with post-combustion capture of carbon dioxide". Thesis, University of Surrey, 2010. http://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.521724.

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Akpan, Patrick Udeme-Obong. "Impact on heat rate and subsequent emissions due to varying operation of coal fired power plants". Doctoral thesis, Faculty of Engineering and the Built Environment, 2019. https://hdl.handle.net/11427/31647.

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Energy mix modellers often use a constant emissions factor model, which more or less implies a constant heat rate, when trying to show the emissions reduction benefits of integrating renewable power generation system on the grid. This approach does not consider the fact that there is a deterioration in the heat rate with load for the Coal Fired Power Plants that need to accommodate the additional renewable supply. If varying heat rate were to be included in a study, it is often limited to plant specific cases. This PhD presents a novel Variable Turbine Cycle Heat Rate (V-TCHR) model for predicting the part load Turbine cycle heat rate (TCHR) response of various Coal Fired Power Plant (CFPP) architectures, without detail knowledge of the entire steam cycle parameters. A total of 192 process models of representative CFPP architectures were developed using a Virtual Plant software. The models had different combinations of the degree of reheat; the throttle temperature; throttle pressure; and condenser cooling technology. The part load response of all the models were simulated using the software.

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Bouzguenda, Mounir. "Study of the combined cycle power plant as a generation expansion alternative". Thesis, Virginia Polytechnic Institute and State University, 1987. http://hdl.handle.net/10919/101165.

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Analysis of future alternatives for US utilities is needed as a part of evaluating the impact of combined cycle and phased-construction of integrated coal gasifier power plants on generation expansion. The study encompassed both large and small electric utilities and long-run, least-cost expansion plan for the generating system and studies of the short-run production cost of electrical generation for selected years. The long-run studies were carried out using the Wien Automatic System Planning Package (WASP-II). The optimal combined cycle penetration level was determined for a set of assumptions that involve economics, new technology trends, and feasibility as well as the utility's existing capacity and load forecast. Additional cases were run to account for phased construction and coal gasification. Two electric utilities were selected in this study. These are a U.S. southeastern utility the Bangladesh Electric Utility. The former was chosen as the large utility. The latter was considered a small size utility. WASP-II enhancements enabled us to run cases using IBM-RT and to account for phased construction. The sensitivity studies involved the penetration levels, the fuel supply (oil and natural gas), and economic dispatch of coal gasifiers in particular, and combined cycle power plants in general. Load forecast, and availability of hydroelectric energy were kept uniform. However, adding new power plants and retiring old ones were considered to achieve a more economical and reliable planning strategy while considering issues of technical feasibility.
M.S.

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27

Lesley, Michael Patrick. "The fluxes and fates of arsenic, selenium, and antimony from coal fired power plants to rivers". Thesis, Available online, Georgia Institute of Technology, 2004:, 2003. http://etd.gatech.edu/theses/available/etd-04082004-180307/unrestricted/lesley%5fmichael%5fp%5f200312%5fms.pdf.

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28

Li, Jia. "Options for introducing CO₂ capture and capture readiness for coal fired power plants in China". Thesis, Imperial College London, 2010. http://hdl.handle.net/10044/1/6393.

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China has been building at least 50GW of new coal‐fired power plants every year since 2004. Previous carbon capture and storage (CCS) research has mainly focussed on technology improvements or stakeholder opinion surveys, without picturing the overall concerns and barriers for deploying such technology in China. This thesis therefore explores the engineering and policy requirements to implement CCS and CO2 Capture Ready (CCR) in Chinese coal‐fired power plants, key enablers for future deployment. A preliminary study of the Chinese gasification industry shows there are early opportunities to capture carbon dioxide from gasification plants. However, as power from conventional pulverised coal (PC) accounts for the majority of electricity generated in China, the most promising emission reduction method for China could be through implementation of CCS technology in large PC plants. An investigation of the current PC plant layouts and operating parameters has been carried out during the course of the study. The results show that, in the absence of CCR designs, a large fraction of such new coal power plants built within the next decade could face ‘carbon lock-in’. A site specific system model using ASPEN Plus to demonstrate the possible changes that could be applied to an existing power plant and a retrofit plant is included in the study. A capture ready power plant site selection method has also been developed, to identify possible sites and to aid understanding of the criteria that should be considered when planning a capture ready plant. A case study of a capture ready power plant in Guangdong province, China shows the benefit of regional planning. Finally, the result of the first stakeholder perception survey on making new coal‐fired plants CCR, conducted in early 2010, are presented and analysed. Evidence for a supportive attitude towards CCR could indicate that this may be a route to early commercial demonstration of CCS in China.

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29

Xin, Mei. "Interaction of atmospheric elemental mercury with natural, synthetic, and anthropogenically derived substrates". abstract and full text PDF (free order & download UNR users only), 2007. http://0-gateway.proquest.com.innopac.library.unr.edu/openurl?url_ver=Z39.88-2004&rft_val_fmt=info:ofi/fmt:kev:mtx:dissertation&res_dat=xri:pqdiss&rft_dat=xri:pqdiss:3289450.

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30

Khobo, Rendani Yaw-Boateng Sean. "A modelling methodology to quantify the impact of plant anomalies on ID fan capacity in coal fired power plants". Master's thesis, Faculty of Engineering and the Built Environment, 2020. http://hdl.handle.net/11427/32244.

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In South Africa, nearly 80 % of electricity is generated from coal fired power plants. Due to the complexity of the interconnected systems that make up a typical power plant, analysis of the root causes of load losses is not a straightforward process. This often leads to losses incorrectly being ascribed to the Induced Draught (ID) fan, where detection occurs, while the problem actually originates elsewhere in the plant. The focus of this study was to develop and demonstrate a modelling methodology to quantify the effects of major plant anomalies on the capacity of ID fans in coal fired power plants. The ensuing model calculates the operating point of the ID fan that is a result of anomalies experienced elsewhere in the plant. This model can be applied in conjunction with performance test data as part of a root cause analysis procedure. The model has three main sections that are integrated to determine the ID fan operating point. The first section is a water/steam cycle model that was pre-configured in VirtualPlantTM. The steam plant model was verified via energy balance calculations and validated against original heat balance diagrams. The second is a draught group model developed using FlownexSETM. This onedimensional network is a simplification of the flue gas side of the five main draught group components, from the furnace inlet to the chimney exit, characterising only the aggregate heat transfer and pressure loss in the system. The designated ID fan model is based on the original fan performance curves. The third section is a Boiler Mass and Energy Balance (BMEB) specifically created for this purpose to: (1) translate the VirtualPlant results for the steam cycle into applicable boundary conditions for the Flownex draught group model; and (2) to calculate the fluid properties applicable to the draught group based on the coal characteristics and combustion process. The integrated modelling methodology was applied to a 600 MW class coal fired power plant to investigate the impact of six major anomalies that are typically encountered. These are: changes in coal quality; increased boiler flue gas exit temperatures; air ingress into the boiler; air heater inleakage to the flue gas stream; feed water heaters out-of-service; and condenser backpressure degradation. It was inter alia found that a low calorific value (CV) coal of 14 MJ/kg compared to a typical 17 MJ/kg reduced the fan's capacity by 2.1 %. Also, having both HP FWH out of service decreased the fan's capacity by 16.2 %.

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31

Hanak, Dawid Piotr. "Evaluation of efficiency improvements and performance of coal-fired power plants with post-combustion CO2 capture". Thesis, Cranfield University, 2016. http://dspace.lib.cranfield.ac.uk/handle/1826/10239.

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The power sector needs to be decarbonised by 2050 to meet the global target for greenhouse gas emission reduction and prevent climate change. With fossil fuels expected to play a vital role in the future energy portfolio and high efficiency penalties related to mature CO2 capture technologies, this research aimed at evaluating the efficiency improvements and alternate operating modes of the coal-fired power plants (CFPP) retrofitted with post-combustion CO2 capture. To meet this aim, process models of the CFPPs, chilled ammonia process (CAP) and calcium looping (CaL) were developed in Aspen Plus® and benchmarked against data available in the literature. Also, the process model of chemical solvent scrubbing using monoethanolamine (MEA) was adapted from previous studies. Base-load analysis of the 580 MWel CFPP retrofits revealed that if novel CAP retrofit configurations were employed, in which a new auxiliary steam turbine was coupled with the boiler feedwater pump for extracted steam pressure control, the net efficiency penalty was 8.7–8.8% points. This was close to the 9.5% points in the MEA retrofit scenario. Conversely, CaL retrofit resulted in a net efficiency penalty of 6.7–7.9% points, depending on the fuel used in the calciner. Importantly, when the optimised supercritical CO2 cycle was used instead of the steam cycle for heat recovery, this figure was reduced to 5.8% points. Considering part-load operation of the 660 MWel CFPP and uncertainty in the process model inputs, the most probable net efficiency penalties of the CaL and MEA retrofits were 9.5% and 11.5% points, respectively. Importantly, in the CaL retrofit scenarios, the net power output was found to be around 40% higher than that of the CFPP without CO2 capture and double than that for the MEA retrofit scenario. Such performance of the CaL retrofit scenario led to higher profit than that of the 660 MWel CFPP without CO2 capture, especially if its inherent energy storage capability was utilised. Hence, this study revealed that CaL has the potential to significantly reduce the efficiency and economic penalties associated with mature CO2 capture technologies.

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32

Almås, Karen. "Coal-fired Power Plants based on Oxy-combustion with Carbon Capture: Combustion Conditions and Water Consumption". Thesis, Norges teknisk-naturvitenskapelige universitet, Institutt for energi- og prosessteknikk, 2012. http://urn.kb.se/resolve?urn=urn:nbn:no:ntnu:diva-19371.

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Nesten all konvensjonell dampkraftproduksjon er avhengig av vann for kjøling. Tilgang til vann er også nødvendig i drift av flere andre delsystemer i et slikt kraftverk. I tillegg medfører integrasjon av CO2 fangst ofte at vannforbruk i et kraftverk går opp. Deler av verden har stor vannmangel og vann bør derfor brukes med omhu. Samtidig med en stadig økende verdensbefolkning, skjerpes fokuset på CO2 utslipp. Det forekommer at den lovende CO2 fangstteknologien basert på oksy-forbrenning, er mindre avhengig av vann sammenlignet med CO2 fangst basert på etterrensing av eksosgassen via kjemisk absorpsjon. To liknende kraftverk med ulik fangstprosess er studert i denne oppgaven. Vannforbruket i et 561 MW oksy-forbrenningskraftverk og et 550 MW kraftverk med etterrensing av eksosgassen, er henholdsvis blitt beregnet. De to kraftverkene sammenlignes deretter opp mot hverandre med hensyn på vannforbruk. Resultatene viser at kjøletårnet utgjør det desidert største vannforbruket i begge kraftverk. Vanntap grunnet fordamping er dominant, men nedblåsing av urenheter er også en betydelig årsak til vanntap når en middelmådig vannkvalitet brukes. CO2 fangst basert på etterrensing av eksosgass har et betraktelig større kjølevannsbehov, noe som resulterer i 17,8% høyere vanntap i kjøletårnet sammenlignet med oksy-forbrenningskraftverket. Det nest største vanntapet skjer ved fjerning av SOx fra eksosgassen (FGD). I luft-fyrte kraftverk er fordamping av vann hovedårsaken til vanntap i FDG-systemer. Andre vanntap er knyttet til produksjon av gips og til nedblåsing av urenheter. En høy vanndampandel i røykgassen fra oksy-forbrenning eliminerer fordampingstap, fordi røykgassens duggpunkt ofte ligger under driftstemperatur til FGD systemet. I denne studien, utgjorde vanntapet i FGD prosessen i etterrensing kraftverket åtte ganger mer enn i oksy-forbrenningskraftverket. Et scenario hvor kraftverkene er lokalisert nært havet og sjøvann brukes som kjøling er også studert. Beregningene viser at oksy-forbrenningsanlegget bare bruker 17% av det vannet som forbrukes i etterrensingskraftverket. Denne trenden er også synlig i noe mindre grad, i tilfellet hvor kjøletårn er brukt. En betydelig mengde kondensat er tilgjengelig i oksygenproduksjonen og CO2 utvinningsprosessen, fordi vann tilføres systemet via inntak av fuktig luft, fukt i brenselet og via hydrogen bundet i brenselet. Gjenvinning av vann kan bidra til betraktelig reduksjon det totale vannforbruket i begge kraftverkene.

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33

Glier, Justin C. "Assessment of Solid Sorbent Systems for Post - Combustion Carbon Dioxide Capture at Coal - Fired Power Plants". Research Showcase @ CMU, 2015. http://repository.cmu.edu/dissertations/741.

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In an effort to lower future CO2 emissions, a wide range of technologies are being developed to scrub CO2 from the flue gases of fossil fuel-based electric power and industrial plants. This thesis models one of several early-stage post-combustion CO2 capture technologies, solid sorbent-based CO2 capture process, and presents performance and cost estimates of this system on pulverized coal power plants. The spreadsheet-based software package Microsoft Excel was used in conjunction with AspenPlus modelling results and the Integrated Environmental Control Model to develop performance and cost estimates for the solid sorbent-based CO2 capture technology. A reduced order model also was created to facilitate comparisons among multiple design scenarios. Assumptions about plant financing and utilization, as well as uncertainties in heat transfer and material design that affect heat exchanger and reactor design were found to produce a wide range of cost estimates for solid sorbent-based systems. With uncertainties included, costs for a supercritical power plant with solid sorbent-based CO2 capture ranged from $167 to $533 per megawatt hour for a first-of-a-kind installation (with all costs in constant 2011 US dollars) based on a 90% confidence interval. The median cost was $209/MWh. Post-combustion solid sorbent-based CO2 capture technology is then evaluated in terms of the potential cost for a mature system based on historic experience as technologies are improved with sequential iterations of the currently available system. The range costs for a supercritical power plant with solid sorbent-based CO2 capture was found to be $118 to $189 per megawatt hour with a nominal value of $163 per megawatt hour given the expected range of technological improvement in the capital and operating costs and efficiency of the power plant after 100 GW of cumulative worldwide experience. These results suggest that the solid sorbent-based system will not be competitive with currently available liquid amine-systems in the absence of significant new improvements in solid sorbent properties and process system design to reduce the heat exchange surface area in the regenerator and cross-flow heat exchanger. Finally, the importance of these estimates for policy makers is discussed.

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34

Bocciardo, Davide. "Optimisation and integration of membrane processes in coal-fired power plants with carbon capture and storage". Thesis, University of Edinburgh, 2015. http://hdl.handle.net/1842/10560.

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This thesis investigates membrane gas separation and its application to post-combustion carbon capture from coal-fired power plants as alternative to the conventional amine absorption technology. The attention is initially focused on membrane module modelling, with the aim of obtaining more detailed predictions of the behaviour of the separation though spiral-wound and hollow-fibre modules. Both one- and bi-dimensional models are implemented, compared and tested for different separations. Module geometry is investigated as well as the effect on the performances due to possible fabrication defects. A key part of the work involves the integration of the customised models into UniSim® Design, the Honeywell process simulator. Thanks to the developed interface, multi-stage process designs are developed, compared with the available literature and linked to a rigorous economic analysis. In particular, a long-term indicator such as the Levelised Cost Of Electricity (LCOE) is evaluated and parametric analyses are conducted with respect to both material and process parameters.

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35

Asgaryan, Mohammad. "Prediciton of the remaining service life of superheater and reheater tubes in coal-biomass fired power plants". Thesis, Cranfield University, 2013. http://dspace.lib.cranfield.ac.uk/handle/1826/8278.

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As a result of concern about the effects of CO2 emssions on the global warming, there is increasing pressure to reduce such emissions from power generation systems. The use of biomass co-firing with coal in conventional pulverised fuel power plants has provided the most immediate route to introduce a class of fuel that is regarded as both sustainable and carbon neutral as it produces less net CO2 emissions. In the future it is anticipated that increased levels of biomass will be required to use in such systems to accomplish the desired CO2 emissions targets. The use of biomass, however, is believed to result in severe fireside corrosion of superheater and reheater tubing and cause unexpected early failures of tubes, which can lead to significant economic penalties. Moreover, future pulverised fuel power systems will need to use much higher steam temeptures and pressures to increase the boiler efficiency. Higher operating temperatures and pressures will also increase the risk of fireside corrosion damage to the boiler tubing and lead to shorter component life. Predicting the remaining service life of superheater and reheater tubes in coal-biomass fired power plants is therefore an important aspect of managing such power plants. The path to this type of failure of heat exchangers involves five processes: combustion, deposition, fireside corrosion, steam-side oxidation, and creep. Various models or partial models each of these processes are available from existing research, but to fully understand the impact of new fuel mixtures (i.e. biomass and coal) and changing operating conditions on such failures, an integrated model of all of these processes is required. This work has produced an integrated set of models and so predicted the remaining service life of superheater/reheater tubes based on the three frameworks which have been developed by analysing those models used in depicting the five processes: one was conceptual and the other two were based on mathematical model. In addition, the outputs of the integrated mathematical models were compared with the laboratory generated data from Cranfield University as well as historical data from Central Electricity Research Laboratories. Furthermore, alternative models for each process were applied in the model and the results were compared with other models results as well as with the experimental data. Based on these comparisons and the availability of models constants the best models were chosen in the integrated model. Finally, a sensitivity analysis was performed to assess the effect of different model input values on the residual life superheater and reheater tubing. Mid-wall metal temperature of tubes was found to be the most important factor affecting the remaining service life of boiler tubing. Tubing wall thickness and outer diameter were another critical input in the model. Significant differences were observed between the residual life of thin-walled and thick-walled tubes.

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36

Oexmann, Jochen [Verfasser]. "Post-combustion CO2 capture : energetic evaluation of chemical absorption processes in coal-fired steam power plants / Jochen Oexmann". Hamburg : Universitätsbibliothek der TU Hamburg-Harburg, 2011. http://d-nb.info/1012653196/34.

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37

Gil-García, Álvaro Antonio. "Thermodynamic behaviour of supercritical water as working fluid in advanced coal-fired power plants : simulation and design study". Thesis, University of Birmingham, 2017. http://etheses.bham.ac.uk//id/eprint/7734/.

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The UK is facing an energy crisis due to the closure of old nuclear power plants which will not be replaced until Generation III nuclear reactors are built. Coal is a realistic option to fill the gap, although there is a need to use cleaner and efficient technologies as a means to comply with global environmental regulations. Supercritical coal-fired power is a viable clean coal technology; however the UK National Grid Code is built around conventional power plants, and thus compliance is uncertain. Modelling the thermal behaviour of the supercritical boiler water cycle using computational fluid dynamics is a practical method to approach compliance. The CFD models developed with the software Comsol Multiphysics were validated and verified using experimental and numerical data, respectively. Subsequently, a test-element representing one pipe from the water wall was scaled-down to match computational requirements, and tested at two different thermal boundary conditions. A strong, forcedconvective flow was revealed, with buoyancy effects at the inlet and a considerable influence of thermal acceleration. The sharp changes of the thermo-physical properties were the most influential hydrothermal factor. Heat transfer coefficient peaked near the pipe inlet, and the outlet section showed mild hydro-thermal performance, impaired by the acceleration effects.

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38

Sosa, Pieroni Jhosmar L. "Estimation of water footprints and review of water-saving/recovery approaches in coal-fired power plants' cooling systems". University of Cincinnati / OhioLINK, 2013. http://rave.ohiolink.edu/etdc/view?acc_num=ucin1367938141.

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39

Hutchens, Steven Jason. "Modeled sulfur dioxide exposure from a proposed coal fired power plant, using geographic information systems and air dispersion modeling". Morgantown, W. Va. : [West Virginia University Libraries], 2004. https://etd.wvu.edu/etd/controller.jsp?moduleName=documentdata&jsp%5FetdId=3376.

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Thesis (M.S.)--West Virginia University, 2004.
Title from document title page. Document formatted into pages; contains xii, 161 p. : ill. (some col.), maps (some col.). Includes abstract. Includes bibliographical references (p. 132-137).

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40

Attili, Viswatej. "Capture and mineralization of carbon dioxide from coal combustion flue gas emissions". Laramie, Wyo. : University of Wyoming, 2009. http://proquest.umi.com/pqdweb?did=1939354121&sid=1&Fmt=2&clientId=18949&RQT=309&VName=PQD.

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41

Li, Junru. "Computational and experimental studies of mercury homogeneous and heterogeneous oxidation in flue gases derived form coal-fired power plants". Thesis, University of Nottingham, 2010. http://ethos.bl.uk/OrderDetails.do?uin=uk.bl.ethos.537623.

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42

Wang, Yuan Verfasser], Detlef [Akademischer Betreuer] [Stolten e Manfred [Akademischer Betreuer] Wirsum. "Techno-economic assessment of hybrid post-combustion carbon capture systems in coal-fired power plants and steel plants / Yuan Wang ; Detlef Stolten, Manfred Wirsum". Aachen : Universitätsbibliothek der RWTH Aachen, 2020. http://d-nb.info/1240838603/34.

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43

Alvarez-Dalama, Alina 1960. "CALCIUM-SULFITE HEMIHYDRATE CRYSTALLIZATION IN LIQUORS WITH HIGH TOTAL DISSOLVED SOLIDS (GROWTH, SIZE DISTRIBUTION, NUCLEATION, HABIT)". Thesis, The University of Arizona, 1986. http://hdl.handle.net/10150/275528.

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44

BARUA, SUKHENDU LAL. "APPLICATION OF CONDITIONAL SIMULATION MODEL TO RUN-OF-MINE COAL SAMPLING FREQUENCY DETERMINATION AND COAL QUALITY CONTROL AT THE POWER PLANT (BLENDING, GOAL PROGRAMMING, MICROCOMPUTER)". Diss., The University of Arizona, 1985. http://hdl.handle.net/10150/187940.

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Run-of-mine (ROM) coal sampling is one of the most important factors in determining the disposition of ROM coal for an overall emission control strategy. Determination of the amount of sample, or still better, the frequency of ROM coal sampling is thus essential to the analysis of overall emission control strategies. A simulation model of a portion of the Upper Freeport coal seam in western Pennsylvania was developed employing conditional simulation. On the simulated deposit, different mining methods were simulated to generate ROM coal data. ROM coal data was statistically analyzed to determine the sampling frequency. Two schemes were suggested: (1) the use of geostatistical techniques if there is spatial correlation in ROM coal quality, and (2) the use of classical statistics if the spatial correlation in ROM coal quality is not present. Conditions under which spatial correlation in ROM coal quality can be expected are also examined. To link the ROM coal and coals from other sources to coal stockpiles and subsequently to solve coal blending problems, where varying qualities of stockpiled coals are normally used, an interactive computer program was developed. Simple file-handling, for stockpiling problems, and multi-objective goal programming technique, for blending problems, provided their solutions. The computer program was made suitable for use on both minicomputer and microcomputer. Menu-driven and interactive capabilities give this program a high level of flexibility that is needed to analyze and solve stockpiling and blending problems at the power plant.

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45

Schmidt, Douglas Stephen. "Electrochemical removal of SOx from flue gas". Diss., Georgia Institute of Technology, 1997. http://hdl.handle.net/1853/10235.

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46

Córdoba, Solà Patricia. "Partitioning and speciation of trace elements at two coal-fired power plants equipped with a wet limestone flue gas desulphurisation (FGD) system". Doctoral thesis, Universitat Politècnica de Catalunya, 2013. http://hdl.handle.net/10803/116331.

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Abstract (sommario):

Coal-fired power plants are a major source of emissions for a number of air pollutants including SO2, NOx, particulate matter (PM), HCl, HF, and Hg amongst. In this work, intensive sampling campaigns were carried out at two power plants in Spain in 2007 and 2008 to study the fate of trace elements. Input and output flows were sampled in the coal combustion unit (boiler and Electrostatic Precipitator (ESP)) and in the Flue Gas Desulphurisation (FGD) system. Analyses of solid, water, gaseous, and PM samples, mass balance calculations and studies on partitioning for trace elements were conducted for the Pulverised Coal Combustion, FGD systems, and for the whole installation (PCC+FGD). Desulphurisation efficiency and emission abatement capacity for inorganic trace pollutants at both power plants was also assessed on the basis of these results. Results revealed (1) an unusual speciation of Hg in the outgoing gaseous stream of the flue gas desulphurisation (OUT-FGD) system at the two power plants: Hg0 was the dominant Hg OUT-FGD species at PP1, and Hg2+ at PP2; (2) a different retention of gaseous Hg between the two sampling campaigns at the coal-fired power plant under co-combustion conditions: a higher retention of Hg2+ in 2007 (73%) than in 2008 (24%) at PP2; (3) a high concentration of trace pollutants and a distinctive behaviour of some elements in the waters of re-circulation to the scrubber at both power plants: Al, F, and SO42 presented a higher concentration in the 2007 gypsum slurry than at PP2 in 2008 and that at PP1; and (4) a characteristic leaching behaviour of some elements from FGD-gypsum: insignificant leaching of heavy metals from FGD-gypsums was found at PP2. The behaviour of Se proved to be the inverse. Laboratory experiments were conducted to reproduce the differences in speciation of gaseous Hg OUT-FGD with respect to that detected at industrial scale. Thermodynamic modelling tools were employed to study the causes of the different retention and speciation of gaseous Hg OUT-FGD and causes and effects of the high concentration of elements in the waters of re-circulation. Potentiometric titration experiments for FGD-gypsum samples were conducted to study the leaching behaviour of some elements from FGD-gypsum. Laboratory experiments confirmed Hg0 as the dominant species in the OUT-FGD gas at PP1, and Hg2+ at PP2. The gaseous speciation of Hg2+ OUT-FGD at PP2 in 2007 and in 2008 was caused by the high concentration of HCl and Hg in the IN-FGD gaseous stream. The unusual speciation of Hg2+ OUT-FGD at PP2 was probably due to the evaporation of HgCl2 particles from the gypsum slurry in the OUT-FGD gas. The Al-additive used at PP2 was responsible for the higher retention of gaseous Hg in 2007 than in 2008. The enrichment of inorganic trace pollutants in the re-circulated water streams at PP1 and PP2 resulted from the continuous re-circulation of filtered water to the scrubber. The emission of the enriched elements by entraining particles and droplets of gypsum slurry OUT-FGD was the most significant consequence of such a fact. Thermodynamic modelling revealed that the Al-additive i) increased the concentration of F- in filtered waters at PP2 in 2007, ii) gave rise to the differential behaviour and enrichment of Al, F, SO42-, Mg, and U in gypsum slurries and filtered waters, iii) led to the formation of SO42- complexes with metals increasing their concentrations in the gypsum slurry from PP1 to PP2-2008 and 2007, iv) caused the acidification of gypsum slurry from PP2 via aluminium hydrolysis, and v) induced the protonation of the PP2 FGD-gypsum surfaces. The relatively high leaching values of Se and the absence of significant leaching of heavy metals from the PP2 FGD-gypsums resulted from the protonation of the surface of the FGD-gypsum and the formation of SO4-complexes.

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47

Hansen, John Barrett. "Assessing the Effectiveness of Scrubber Installation on Air Pollution Emissions Reductions Among Coal-Fired Power Plants: Application of Statistical Methods for Causal Inference". Thesis, Harvard University, 2015. http://nrs.harvard.edu/urn-3:HUL.InstRepos:14398549.

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Abstract (sommario):

The 1990 amendment to the Clean Air Act implemented a cap-and-trade system that required electricity-generating power plants to dramatically reduce Sulfur Dioxide (SO2) and Nitrogen Oxide (NOx) emissions. Plants impacted by this legislation had a variety of compliance options, including decreasing factory operation, purchasing carbon credits, installing scrubbers, and changing fuel inputs. Using data from 1997-2012 of 995 coal-burning power plants, we examine the effectiveness of scrubber installation in reducing SO2 and NOx emissions. Specifically, we employ two methods—a propensity score algorithm and a matching algorithm—to estimate: 1) the causal effect of scrubber installation prior 1997 on the emissions during 1997; and 2) the causal effect of scrubber installation at any time during the period 1997-2012 on emissions two months following scrubber installation. Using a propensity score method, we found that pre-1997 SO2 scrubbers reduced 1997 SO2 emissions by 68% (95% CI 58% to 76%), and pre-1997 NOx scrubbers reduced 1997 NOx emissions by 28% (16%, 38%). Additionally, installing SO2 and NOx scrubbers at any time during the period 1997-2012 reduces SO2 and NOx emissions by 89% (88%, 90%) and 21% (19%, 24%) two months following installation, respectively. These final two results are corroborated by a matching algorithm, which finds scrubbers cause SO2 and NOx emissions decline by 88% (87%, 89%) and by 20%. (17%, 22%) two months following installation, respectively.

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48

Garg, Bharti. "Regeneration of sulfur rich amines in a combined capture system aimed to lower the cost of PCC in Australian coal fired power plants". Thesis, Federation University Australia, 2019. http://researchonline.federation.edu.au/vital/access/HandleResolver/1959.17/175529.

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Coal is the dominant and most reliable source of energy in Australia. However, the increasing global temperatures and its impact on the climate raises concerns on the use of coal worldwide. Due to availability of abundant, cheap quality coals, Australia is researching how it and its international customers can continue to use its abundant coal resources whilst limiting greenhouse emissions. Hence, low CO2 emitting energy technologies like carbon capture and storage (CCS) have an important role to play not only in power but also the cement and steel industries Post-combustion CO2 capture (PCC), the most developed technology in CCS using aqueous amines to capture CO2, still face challenges for its large-scale commercialisation. The cost of electricity with PCC rises to almost double that produced without integrating PCC technology in new power stations. The retrofit of PCC technology into existing power stations is very site specific and costs can be around half of the cost of building a new power plant. Apart from this, the implementation of PCC poses an energy penalty to the power station as the efficiency of the plant can drop almost by 10-11% due to the increased solvent heating and CO2 compression loads. Particularly with the nations like Australia, the cost of PCC installation is even higher as there are no flue gas desulfurisation (FGD) units in Australian power stations. The presence of harmful gases like SO2 in coal-fired power plant flue gases affect CO2 capture performance during PCC due to the higher affinity of amines to absorb stronger acidic gases against CO2 which is a weaker acid gas than SO2. These stronger acidic gases tend to form heat stable salts with the absorbent amines used to capture CO2 . Heat stable salts refer to the thermally non-regenerable protonated amines which are usually produced when the amine solution is contaminated by organic acids (Weiland et al., 2004). Hence, the bonded amine is not available for CO2 capture, increasing the requirement for makeup amine resulting in higher operating cost. Therefore, FGD units are an essential requirement before the installation of PCC facilities in a coal-fired power station. This results in a levelised cost of electricity in Australian power plants that is high compared to nations which have FGD installed in their power stations. CSIRO has developed a combined capture process to simultaneously capture CO2 and SO2 from Australian power plant flue gases using a single amine absorbent in order to lower the cost of PCC installation in Australia. The process generates a unique sulfur rich amine absorbent which needs regeneration. This thesis investigates various amine regeneration processes, using MEA as a reference, and their commercial viability to the CS-Cap process. Due to the unique nature of the sulfur rich absorbent generated in the CS-Cap process, its amine is recoverable through many other regeneration processes besides standard thermal reclamation. My thesis investigates the effectiveness of regeneration techniques like Ion exchange, Electro-dialysis, Crystallisation, Nano-filtration in regenerating the sulfur rich amine. Initially the theoretical investigation was carried as a part of literature review and further a brief exploratory laboratory scale evaluation of the most suited technologies was carried out. The results obtained from laboratory scale experimentation were fed to an Aspen Plus simulation model in order to understand the behaviour of the system under various operating conditions. Further a cost estimation was carried out in order to produce a high level cost for the selected regeneration technologies in the CS-Cap process. The cost of the regeneration technologies were further integrated into the overall CO2 capture process in order to compare the cost of standard FGD + PCC process against the CS-Cap process which answers the broader research question whether the CS-Cap process will be economical for Australian coal power plants. Overall this thesis reveals the effectiveness of various technologies in regenerating sulfur rich amines. It suggests CSIRO’s patented CS-Cap process is a cost-effective approach for capturing CO2 from Australian coal fired power plants despite its sensitivity to regeneration cost.
Doctor of Philosophy

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Vijapur, Santosh H. "Design optimization and experimental study of a wet laminar electrostatic precipitator for enchancing collection efficiency of aerosols". Ohio : Ohio University, 2008. http://www.ohiolink.edu/etd/view.cgi?ohiou1227020758.

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Du, Sart Colin F. "Design and prototyping of a test facility to investigate the transport properties of dilute phase gas-particle flows applicable to coal-fired power plants". Master's thesis, University of Cape Town, 2017. http://hdl.handle.net/11427/24889.

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Understanding the properties of dilute phase gas-particle transport and the applicability of the different empirical correlations found in literature for these properties are crucial in the study of Pulverized Fuel conveying applicable to South African coal-fired power plants. Having access to a test facility in which empirical data can be generated under controlled operating conditions would enhance this understanding and will allow more informed application of these correlations. The aim of this thesis was to develop a concept design and prototype of a pneumatic conveying test facility that can be used to evaluate these empirical correlations and property relationships. A comprehensive literature review was conducted of the empirical correlations available and a study was conducted to determine the scaling required to achieve similarity. A theoretical process model was also developed together with a methodology to determine the operating envelope of the blower. The model and methodology were subsequently used in the design of a prototype test facility that would demonstrate the critical particle feed and extraction processes, and to derive suitable specifications for the blower. The prototype, including a complete data acquisition and control system, was developed, constructed and commissioned in cooperation with a commercial engineering company. The facility allows for the control, online measurement and recording of the gas and particle mass flow rates. Practical tests were then conducted with Fly Ash, as a substitute for Pulverized Coal, to demonstrate the particle feed and extraction processes and to evaluate the accuracy of control of the gas and particle mass flow rates. Tests were conducted for loadings (particle to gas mass flow ratios) between 0.988 and 6.860 at gas mass flow rates between 0.051 and 0.115kg/s and particle mass flow rates between 0.077 and 0.600kg/s. A methodology to determine the particle mass flow rate and its associated uncertainty from the Loss In Weight and Gain In Weight systems was developed from basic principles and demonstrated. The relative uncertainties calculated for the measured particle mass flow rates are less than ±1% for all tests. The maximum relative uncertainties calculated for the measured gas mass flow rates and loadings are ±6%. The conceptual overall system layout for the final test facility, including the instrumentation design, was then refined based on the experience gained and recommendations are made for consideration in the detail design. The conceptual design allows for the control of the gas and particle mass flow rates as well as the gas temperature and pressure level. The final test facility will be suitable to conduct pressure drop tests, saltation and choking tests, as well as mass balances and visual observations. The process model and methodologies developed here may now be applied in the detail design and operation of such a final test facility.

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