Academic literature on the topic 'Coal-fired power plant; biomass'

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.

Coal-fired power plants’ typically large capacity and relatively low electricity generation costs in the Chinese power market can be compared with their typically low specific thermal efficiency and older age on average. At the same time, the environment pollution caused by local coal-fired power plants has started to receive due attention. Sustainable renewable energy sources and the application of effective conversion technologies for those has become a top priority of China's current energy strategy. Biomass in general and anaerobic biogas in particular can be regarded as clean, locally available renewable energy resources. Replacing coal with biomass-derived energy is especially relevant for certain locations in China. For the case of Henan province, work has already been undertaken by the local authorities for the proper estimation of the biomass potential and the selection of most applicable energy conversion technologies with the lowest environmental footprint to replace aging coal-fired plants with various biomass-based power generation facilities.<br>Kolkraftverkens typiska stora kapacitet och relativt låga elproduktionskostnader på den kinesiska elmarknaden kan jämföras med deras typiskt låga specifika verkningsgrader och äldre ålder i genomsnitt. Samtidigt har miljöföroreningarna som orsakas av lokala kolkraftverk börjat uppmärksammas på riktigt i Kina. Hållbara förnybara energikällor och tillämpningen av effektiv konverteringsteknik för dessa har blivit en topprioritet för Kinas nuvarande energistrategi. Biomassa i allmänhet och anaerobisk biogas (rötgas) i synnerhet kan betraktas som rena och lokalt tillgängliga förnybara energiresurser. Byte av kol mot biobränslen blir särskilt relevant för vissa platser i Kina. När det gäller Henanprovinsen har en del arbete redan gjorts av de lokala myndigheterna för en korrekt uppskattning av biomasspotentialen och en analys av de mest tillämpliga teknologier för omvandling av bioenergi med lägsta miljöpåverkan som ersätter åldrande koleldade anläggningar med olika biobränslen.

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.

The use of waste (or recycled) wood as a fuel in heat and power stations is becoming more widespread in Sweden (and Europe), because it is CO2 neutral with a lower cost than forest fuel. However, it is a heterogeneous fuel with a high amount of chlorine, alkali and heavy metals which causes more corrosion than fossil fuels or forest fuel. A part of the boiler which is subjected to a high corrosion risk is the furnace wall (or waterwall) which is formed of tubes welded together. Waterwalls are made of ferritic low-alloyed steels, due to their low price, low stress corrosion cracking risk, high heat transfer properties and low thermal expansion. However, ferritic low alloy steels corrode quickly when burning waste wood in a low NOx environment (i.e. an environment with low oxygen levels to limit the formation of NOx). Apart from pure oxidation two important forms of corrosion mechanisms are thought to occur in waste environments: chlorine corrosion and alkali corrosion. Although there is a great interest from plant owners to reduce the costs associated with furnace wall corrosion very little has been reported on wall corrosion in biomass boilers. Also corrosion mechanisms on furnace walls are usually investigated in laboratories, where interpretation of the results is easier. In power plants the interpretation is more complicated. Difficulties in the study of corrosion mechanisms are caused by several factors such as deposit composition, flue gas flow, boiler design, combustion characteristics and flue gas composition. Therefore, the corrosion varies from plant to plant and the laboratory experiments should be complemented with field tests. The present project may thus contribute to fill the power plant corrosion research gap. In this work, different kinds of samples (wall deposits, test panel tubes and corrosion probes) from Vattenfall’s Heat and Power plant in Nyköping were analysed. Coated and uncoated samples with different alloys and different times of exposure were studied by scanning electron microscopy (SEM), energy dispersive x-ray analysis (EDX), X-ray diffraction (XRD) and light optical microscopy (LOM). The corrosive environment was also simulated by Thermo-Calc software. The results showed that a nickel alloy coating can dramatically reduce the corrosion rate. The corrosion rate of the low alloy steel tubes, steel 16Mo3, was linear and the oxide scale non-protective, but the corrosion rate of the nickel-based alloy was probably parabolic and the oxide much more protective. The nickel alloy and stainless steels showed good corrosion protection behavior in the boiler. This indicates that stainless steels could be a good (and less expensive) alternative to nickel-based alloys for protecting furnace walls. The nickel alloy coated tubes (and probe samples) were attacked by a potassium-lead combination leading to the formation of non-protective potassium lead chromate. The low alloy steel tubes corroded by chloride attack. Stainless steels were attacked by a combination of chlorides and potassium-lead. The Thermo-Calc modelling showed chlorine gas exists at extremely low levels (less than 0.1 ppm) at the tube surface; instead the hydrated form is thermodynamically favoured, i.e. gaseous hydrogen chloride. Consequently chlorine can attack low alloy steels by gaseous hydrogen chloride rather than chlorine gas as previously proposed. This is a smaller molecule than chlorine which could easily diffuse through a defect oxide of the type formed on the steel.<br><p>QC 20130423</p>

The first detailed systematic investigation of a cement plant with various carbon capture technologies has been performed. The calcium looping (Ca-looping) process has emerged as a leading option for this purpose, since this process applied to a cement plant provides an opportunity to use the CaO purge for clinker production. The Ca-looping process is comprised of two interconnected reactors where the carbonator captures CO2 from flue gases and the calciner regenerates the CaCO3 into CaO by oxy-combustion. Fully integrated process flowsheets have been developed and simulated in UniSim Design Suite from Honeywell. The detailed carbonator model has been implemented using Matlab and incorporated into UniSim to provide a full flowsheet simulation for an exemplary dry-feed cement plant as a user-defined operation. The base cement plant simulation was also modified to integrate three different carbon capture processes: membrane; indirect calcination; and amine-scrubbing. Furthermore, an advanced configuration of Ca-looping process has been investigated where the energy intensive air separation unit was replaced with a chemical looping combustion (CLC) cycle. Each case has been optimised to minimise its energy consumption and compared in terms of levelised cost of cement and its resulting cost of CO2 avoided at the same CO2 avoidance rate. The proposed integration of the Ca-looping process is capable of achieving over 90% CO2 avoidance with additional fuel consumption of 2.5 to 3.0 GJth/ton CO2 avoided. By using an advanced configuration of the Ca-looping process with a CLC cycle, the additional fuel consumption can be reduced to 1.7 GJth/ton CO2 avoided, but the cost of the oxygen carrier is the major concern for this system. Among the other CO2 capture options, the membrane process is a promising alternative for the Ca-looping process since it has a potential of achieving the target CO2 avoidance rate and purity requiring lower energy consumption. The indirect calcination process provides moderate levels of CO2 avoidance (up to 56%) without a need of an external capture process whereas the integration of the amine process in a cement plant is challenging as a result of the requirement of steam for solvent regeneration. Furthermore, considering zero net CO2 emissions associated with biomass combustion systems, a novel concept has been analysed to capture of CO2 in-situ with the Ca-looping process while operating the combustor of a dedicated biomass power plant at sufficiently low temperature. This process is capable of achieving 84% overall CO2 capture rate with an energy penalty of 5.2% when a proper heat exchanger network is designed with the support of a pinch analysis. The techno-economic performance of the biomass power plant with in-situ Ca-looping CO2 capture process was compared with that of the alternative biomass-air-fired and biomass-oxy-fired power plants.

Hemp, eucalyptus, coal, hemp and coal blended fuel, and eucalyptus and coal blended fuel were ashed and then heat treated for 1 hour at temperatures from 600-1100°C. X-ray diffraction analysis indicated reactions between the phases present after initial ashing of the fuel showed biomass-biomass, biomass-coal and coal-coal interactions. Two phase systems were identified as dominant in the biomass and coal ash blends, these were CaO-MgO-SiO2 and CaO-Al2O3-SiO2. The phases identified in these systems have also been identified in ceramics produced at high temperatures which have similar compositions to the ash matrix of the laboratory synthesised ash; this indicates that phase diagrams can be powerful tools in phase formation prediction. Structures identified as trichomes (phosphate-silicate structures with melting points above 1100°C) from the hemp fuel which had not decomposed were present in both the hemp ash and the hemp and coal ash. The composition determined by Energy-dispersive X-ray spectroscopy analysis of laboratory synthesised ashes was also in agreement with the phases identified through X-ray diffraction. Hemp and coal, eucalyptus and coal, and eucalyptus ash samples (deposited, quenched, cyclone, and bottom ash) removed from a full scale 1MWth combustion rig were analysed. Phase composition of the fly ash samples are similar to those identified in the analagous samples produced in the laboratory with several of the same phases present; confirming that laboratory testing is useful for the predictions of phases present on the industrial scale combustion rig. Particle morphology is one of the largest differences between the laboratory scale tests and combustion rig samples. The dominant particle shape of fly ash particles removed from the combustion rig is spherical. These particles of characteristic shape are often referred to as plerospheres and cenospheres and were first identified in coal fly ash. The presence of the spheres in the combustion rig when only biomass (eucalyptus) is present indicates the formation mechanism of the particles is similar to that of coal. There are similarities between the chemical composition of the spheres which are solely of biomass origin and co-fired; it is likely that phase composition of the sphere and not the fuel origin contributes to the formation of the spheres. Phases identified in the bottom ash are similar to those identified in the fly ash. High temperature phases such as (e.g. Ca9MgK(PO4)7) ocur in the bottom ash suggesting that higher temperatures are reached in the bottom of the rig than in the flue gas. Analysis of 15Mo3 alloy corrosion coupons with fly ash deposited onto the surface, alongside the interactions between gas phases and coupons, deposits and coupons, and gas phases and deposits, showed that some oxidation/reduction of the metal had occurred. The presence vi of metal oxide flakes indicated corrosion. Oxidation of 15Mo3 alloy was observed in hemp and coal, and eucalyptus and coal combustion trials, likely due to the observed deposition of potassium chloride which has caused detachment of several scales. Between the metal-deposit interface, hematite whiskers were observed; magnetite octahedra were also present on the surface of scales. The phases present in the coupon deposit ash differ from those observed in the laboratory and fly ash due to the length of time spent in the high temperature environment. This indicates that some phases will not form until the deposits have built up and are in the furnace for an extended period of time. When the coupon samples were coated, fewer metal scales were observed meaning that the coatings are an affective method of corrosion reduction leading to an increased lifetime of boiler components. The dominant particle morphology present in the combustion rig is the cenospheres and plerospheres. The phases formed can be broadly catergorised into CaO-MgO-SiO2, CaO-Al2O3-SiO2, and K2O-Al2O3-SiO2 phases. Potassium chloride is observed in the laboratory ash and combustion rig ash indicating, alongside the presence of metal oxide scales, that the fuel blends are likely to lead to corrosion during combustion.

ABSTRACT EVALUATION OF METAL CONCENTRATIONS IN GROUNDWATER NEARBY SOMA COAL FIRED POWER PLANT Giuma Sasi M.S., Department of Chmistry Supervisor: Prof. Dr. Semra G. Tuncel December 2005, 95 Pages In this work, metal pollution in groundwater near by Soma coal-fired power plant was invistigated. Coal combustion results in huge amounts of bottom ash from which metals can originate and migrate to groundwater and pollute it. Forty groundwater samples were collected from water wells in an area near by the power plant to determine 14 metals namely<br>Na, Ca, K, Mg, Al, Ba, Fe, Zn, Cu, Pb, Cr, Cd, Ni and V. Samples were collected in polyethylene bottles, the pH of the water was measured. Then, the samples were acidified and stored to be analyzed. FAAS, FAES, GFAAS and ICP-AES were used to determine the elements. The results were compared with the WHO, the Turkish and EC guidelines for drinking water quality. Fe concentrations in 12 wells were higher the three guidelines. Zn concentrations in 5 wells were higher than the EC guidelines, but not higher than the Turkish guidelines. Pb concentrations was less than all guilelines but it was relatively high in 8 wells. The other anthropogenic elements were lower than all guidelines but these metals tend to accumulate and they will exceed the guildlines overtime. Enrichment factor calculations showed that the anthropogenic elements were enriched in the regions close to the ash piles pointing out that the ash piles are the main source of these elements. Factor analysis was applied and four main factors of the determined metals were found indicating that the power plant and the ash piles are the main source for the anthropogenic elements.

The fast depletion of fossil fuel has increased the havoc and need of finding an alternative for the existing fossil fuel based energy industry. As a result, many renewable energy sources such as Solar, Wind, Geo Thermal, Bio mass, etc... are being looked in to. One of the major sources of renewable energy is our sun. There are two methods of tapping the energy from the sun. 1. Solar Thermal It involves using the sun’s heat directly in some processes or indirectly to produce electricity. 2. Photo Voltaic It involves using the light to produce electricity using Photo Voltaic cells. This report involves only the Solar Thermal part where the sun’s heat is indirectly used to produce electricity. This report focuses mainly on a method known as Compact Linear Fresnel Reflectors (CLFR). This method involves the focusing of sun’s energy to an over head tube through mirrors arranged to form the shape similar to that of a Fresnel lens and hence the name. Water runs in the over head tube, the focused energy from the sun, heats up the over head tube and produces steam which in turn runs a steam turbine which in turn produces electricity. This report focuses mainly the potential of using CLFR technology to be augmented in to existing coal fired power plants in India. India has a solar reception of 5 Peta watt hours per year with an average of 4 – 7 kW/m2 DNI. One of National Thermal Power Corporation’s Coal fired thermal power station, Dadri Thermal Power Station, has been chosen for the purpose of case study for this particular thesis. Since there is coal shortage at the power plant location and the plant is not able to produce the peak load, our primary objective was to achieve the production of peak load. The existing power cycle and the solar steam augmented power cycles have been simulated using Thermoflow software and the results have been tabulated.

In order to mitigate climate change, there is a desperate need to reduce CO2 emissionsfrom different sources. CO2 capture and sequestration will play an important role in thesereductions. This report is focused on the capture of CO2 from flue gas emitted by a coalfired power plant, which is also described in this report. From the available technologies,post combustion capture with chemical absorption is chosen. It is already been shown byprevious work that it is possible to capture CO2 by this method; this report goes a stepahead to simulate this process. Various methods available are described briefly alongwith the justification why 30% (wt) MEA is used as solvent for this kind of process. Afirst approach is made towards the simulation of the process using Aspen Plus 2006. Themass balance and the energy required for the process have been calculated. Forsimulation the help was taken from Aspen Plus 2006 documentation, also previous workassisted in performing it. The results obtained can be used as the base for optimizing thesimulation.<br>Uppsatsnivå: D