S. Rezvani

University of Ulster, Derry, NIR, United Kingdom

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Publications (31)25.32 Total impact

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    ABSTRACT: Biomass fuelled trigeneration is the term given to the system which is the on-site generation of electricity, heat and cooling simultaneously, using biomass as the fuel source. As a form of the renewable energy sources biomass is not intermittent, location-dependent or very difficult to store. If grown sustainably, biomass can be considered to be CO2 neutral. Biomass, therefore, would be a promising option for the future to contribute both to the reduction of greenhouse gases and to the solution of replacing fossil fuels in power plants. For a wide range of commercial buildings, biomass trigeneration offers an economical solution of providing power, heat and cooling which is more environmentally friendly than conventional methods.This work focuses on the modelling, simulation and techno-economic analysis of small scale biomass trigeneration applications. The Organic Rankine Cycle (ORC) integrated with conventional combustion provides electricity for building use. The waste heat recovered from the ORC system and exhaust gases is used to supply hot water to space heating and excess heat is also used to drive an absorption cooling system. In order to use energy resources most efficiently, the proposed process is modelled and simulated using the ECLIPSE process simulation package. Based on the results achieved, the key technical and environmental issues have been examined. The study also investigates the impact of different biomass feedstock on the performance of trigeneration plant, biomass ash content ranges from 0.57 to 14.26% ash and a range of moisture content 10.6–33.51%. The calorific value across the biomass sources ranges between 16.56 and 17.97 MJ/kg daf. Finally, an economic evaluation of the system is performed along with sensitivity analyses such as capital investments, plant load factors and fuel costs. The results show that the maximum efficiencies and the best breakeven electricity selling price for the cases considered in this study are as follows: 11.1% and 221 £/MWh for power only, 85.0% and 87 £/MWh for combined heat and power and 71.7% and 103 £/kWh for trigeneration respectively.
    Applied Thermal Engineering 05/2013; 53(2):325–331. · 2.13 Impact Factor
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    ABSTRACT: The techno-economic characteristics of macro-algae utilisation from European temperate zones was evaluated in a selected Anaerobic Digester (AD) using the chemical process modelling software ECLIPSE. The assessment covered the mass and energy balance of the entire process followed by the economic feasibility study, which included the total cost estimation, net present value calculation, and sensitivity analysis. The selected plant size corresponded to a community based AD of 1.6MWth with a macro-algae feed rate of 8.64tonnes per day (dry basis). The produced biogas was utilised in a combined heat and power plant generating 237kWenet electricity and 367kWth heat. The breakeven electricity-selling price in this study was estimated at around €120/MWh. On the ground of different national and regional policies, this study did not account for any government incentives. However, different support mechanisms such as Feed-in-Tariffs or Renewable Obligation Certificates can significantly improve the project viability.
    Bioresource Technology 01/2013; · 4.75 Impact Factor
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    ABSTRACT: Pulverized coal-fired (PC) power plants are the major technology used to generate electricity for power generation around the world. These processes are generally considered to make a significant contribution to global climate change since they have high CO2 emissions, with the exception of those coal-fired power plants that employ CO2 capture and storage (CCS) technology.With regard to coal-fired power plants, two main options for capturing CO2 from flue gases can be adopted, namely post-combustion and oxy-fuel combustion systems. The former technology option separates CO2 from the flue gas generated by the combustion of coal with air. For chemical absorption, generally a solvent such as MEA is used. However, there is a serious concern about the energy consumption required for regeneration of the solvent MEA. Oxy-fuel combustion systems, on the other hand, involve separating the oxygen from air and then burning the coal in a mixture of pure oxygen and recycled flue gas. This approach reduces the amount of flue gas substantially and simplifies the separation process due to the absence of nitrogen and argon in the stream. However there are some drawbacks in connection with some components, such as air separation units (ASU), which require high capital and operating costs and are energy intensive.A new idea was proposed by Zanganeh et al. [1]. This was a hybrid of oxy-combustion and post-combustion capture and would use air with O2 enrichment. Such PC power stations would use an ASU plant to obtain O2 enrichment and would still require the CO2 purification and compression processes. The ASU plant would be smaller than for oxy-fuel and the CO2 purification and compression systems would be smaller than for air-firing. This paper is to evaluate the proposed process technically and economically based on detailed simulation. The hybrid coal-fired power plant with CO2 capture system has the potential advantage of reducing energy consumption and costs. To explore the advantages and disadvantages of the hybrid process with CO2 capture, a comparative analysis of the supercritical PC power plant is carried out. The technical design and the mass and energy balances are implemented by using the ECLIPSE simulation package.
    Fuel. 02/2012;
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    ABSTRACT: Using sustainably-grown biomass as the sole fuel, or co-fired with coal, is an effective way of reducing the net CO2 emissions from a combustion power plant. There may be a reduction in efficiency from the use of biomass, mainly as a result of its relatively high moisture content, and the system economics may also be adversely affected. The economic cost of reducing CO2 emissions through the replacement of coal with biomass can be identified by analysing the system when fuelled solely by biomass, solely by coal and when a coal-biomass mixture is used. The technical feasibility of burning biomass or certain wastes with pulverised coal in utility boilers has been well established. Cofiring had also been found to have little effect on efficiency or flame stability, and pilot plant studies had shown that cofiring could reduce NOx and SOx emissions. Several technologies could be applied to the co-combustion of biomass or waste and coal. The assessment studies here examine the potential for co-combustion of (a) a 600 MWe pulverised fuel (PF) power plant, (i) cofiring coal with straw and sewage sludge and (ii) using straw derived fuel gas as return fuel; (b) a 350 MWe pressurised fluidised bed combustion (PFBC) system cofiring coal with sewage sludge; (c) 250 and 125 MWe circulating fluidised bed combustion (CFBC) plants cofiring coal with straw and sewage sludge; (d) 25 MWe CFBC systems cofiring low and high sulphur content coal with straw, wood and woody matter pressed from olive stones (WPOS); and (e) 12 MWe CFBC cofiring low and high sulphur content coal with straw.
    Fuel 01/2011; 90(1):11-18. · 3.36 Impact Factor
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    ABSTRACT: Export Date: 30 August 2011, Source: Scopus, Article in Press
    International Journal of Energy Research 01/2011; · 1.99 Impact Factor
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    ABSTRACT: Many buildings require simultaneous electricity, heating and cooling. Biomass is one of the renewable energy sources which is not intermittent, location-dependent or very difficult to store. If grown sustainably, biomass can be considered to be CO2 neutral. A trigeneration system consisting of an internal combustion (IC) engine integrated with biomass gasification may offer a combination for delivering heat, electricity and cooling cleanly and economically. The producer gas generated by the gasifier is used to provide electricity for building use via the IC engine. The waste heat is recovered from the engine cooling system and exhaust gases to supply hot water to space heating, excess heat is also used to drive an absorption cooling system. The proposed system is designed to meet the energy requirements for selected commercial buildings and district heating/cooling applications. This work focuses on the modeling and simulation of a commercial building scale trigeneration plant fuelled by a biomass downdraft gasifier. In order to use both energy and financial resources most efficiently, technical and economic analyses were carried out, using the ECLIPSE process simulation package. The study also looks at the impact of different biomass feedstock (willow, rice husk and miscanthus) on the performance of a trigeneration plant.Highlights► We model a commercial building scale biomass fuelled trigeneration plant. ► It is economically feasible to use willow chips, miscanthus and rice husk as the fuel to operate the trigeneration system. ► The efficiency of TG is much higher than that of PO, but is lower than that of the combined heat and power (CHP) configuration. ► The breakeven electricity selling price (BESP) of the TG system is better than that of the PO option with the CHP option producing the cheapest electricity.
    Energy Conversion and Management 01/2011; 52(6):2448-2454. · 2.78 Impact Factor
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    ABSTRACT: Using sustainably-grown biomass as the sole fuel, or co-fired with coal, is an effective way of reducing the net CO2 emissions from a combustion power plant. There may be a reduction in efficiency from the use of biomass, mainly as a result of its relatively high moisture content, and the system economics may also be adversely affected.The economic cost of reducing CO2 emissions through the replacement of coal with biomass can be identified by analysing the system when fuelled solely by biomass, solely by coal and when a coal-biomass mixture is used.The technical feasibility of burning biomass or certain wastes with pulverised coal in utility boilers has been well established. Cofiring had also been found to have little effect on efficiency or flame stability, and pilot plant studies had shown that cofiring could reduce NOx and SOx emissions.Several technologies could be applied to the co-combustion of biomass or waste and coal. The assessment studies here examine the potential for co-combustion of (a) a 600 MWe pulverised fuel (PF) power plant, (i) cofiring coal with straw and sewage sludge and (ii) using straw derived fuel gas as return fuel; (b) a 350 MWe pressurised fluidised bed combustion (PFBC) system cofiring coal with sewage sludge; (c) 250 and 125 MWe circulating fluidised bed combustion (CFBC) plants cofiring coal with straw and sewage sludge; (d) 25 MWe CFBC systems cofiring low and high sulphur content coal with straw, wood and woody matter pressed from olive stones (WPOS); and (e) 12 MWe CFBC cofiring low and high sulphur content coal with straw.The technical, environmental and economic analysis of such technologies, using the ECLIPSE suite of process simulation software, is the subject of this study. System efficiencies for generating electricity are evaluated and compared for the different technologies and system scales. The capital costs of systems are estimated for coal-firing and also any additional costs introduced when biomass is used. The Break-even electricity selling price is calculated for each technology, taking into account the system scale and fuel used.Since net CO2 emissions are reduced when biomass is used, the effect of the use of biomass on the electricity selling price can be found and the premium required for emissions reduction assessed. Consideration is also given to the level of subvention required, either as a Carbon dioxide Credit or as a Renewable Credit, to make the systems using biomass competitive with those fuelled only with coal.It would appear that a Renewable Credit (RC) is a more transparent and cost-effective mechanism to support the use of biomass in such power plants than a Carbon dioxide Credit (CC).
    Fuel. 10/2010;
  • 8th European Conference on Coal Research and Its Applications, Leeds, UK; 09/2010
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    ABSTRACT: A large number of research undertakings and system modelling works study different coal fired Integrated Gasification Combined Cycle (IGCC) configurations, mostly with the conflicting purposes and aims, to increase system efficiencies, to reduce costs and to diminish environmental impacts. The increased penetration levels of intermittent renewable energy systems experienced in many parts of the world, however, makes the establishment of flexible power generation systems to be a more challenging task. The integration of a diurnal syngas storage system as a means to increase system flexibility is investigated in this work with reference to different syngas qualities. All the systems are based on a reference coal-fired IGCC power plant. The system modification is limited to the gas processing units including a CO2 removal option allowing for different syngas compositions. Apart from the reference syngas, four further options are proposed here: hydrogen rich syngas with and without a carbon capture, a scenario with a partial carbon capture and finally a Synthetic Natural Gas (SNG) production case. The techno-economic analysis is implemented in connection with a short-term geological syngas/hydrogen rich gas storage reservoir. The results show that a hydrogen rich gas generation without a carbon capture will be techno-economically less attractive and requires a relatively large reservoir volume. A methanation process towards a SNG production adds significantly to the overall cost and reduces the cold gas efficiency. The storage volume requirement is however considerably reduced. Finally, a short comparison will be drawn to a potential case configuration with a compressed air energy storage system.
    8th European Conference on Coal Research and Its Applications, Leeds, UK.; 09/2010
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    Energy Policy. 01/2010; 38(1):689-689.
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    ABSTRACT: The techno-economic evaluation of four novel integrated gasification combined cycle (IGCC) power plants fuelled with low rank lignite coal with CO2 capture facility has been investigated using ECLIPSE process simulator. The performance of the proposed plants was compared with two conventional IGCC plants with and without CO2 capture. The proposed plants include an advanced CO2 capturing process based on the Absorption Enhanced Reforming (AER) reaction and the regeneration of sorbent materials avoiding the need for sulphur removal component, shift reactor and/or a high temperature gas cleaning process. The results show that the proposed CO2 capture plants efficiencies were 18.5–21% higher than the conventional IGCC CO2 capture plant. For the proposed plants, the CO2 capture efficiencies were found to be within 95.8–97%. The CO2 capture efficiency for the conventional IGCC plant was 87.7%. The specific investment costs for the proposed plants were between 1207 and 1479 €/kWe and 1620 €/kWe and 1134 €/kWe for the conventional plants with and without CO2 capture respectively. Overall the proposed IGCC plants are cleaner, more efficient and produce electricity at cheaper price than the conventional IGCC process.
    Fuel 12/2009; 88(12). · 3.36 Impact Factor
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    ABSTRACT: The integrated gasification combined cycle (IGCC) as an efficient power generation technology with lowest specific carbon dioxide emissions among coal power plants is a very good candidate for CO2 capture resulting in low energy penalties and minimised CO2 avoidance costs. In this paper, the techno-economic characteristics of four different capture technologies, which are built upon a conventional reference case, are studied using the chemical process simulation package “ECLIPSE”. The technology options considered are: physical absorption, water gas shift reactor membranes and two chemical looping combustion cycles (CLC), which employ single and double stage reactors. The latter system was devised to achieve a more balanced distribution of temperatures across the reactors and to counteract hot spots which lead to the agglomeration and the sintering of oxygen carriers. Despite the lowest efficiency loss among the studied systems, the economic performance of the double stage CLC was outperformed by systems employing physical absorption and water gas shift reactor membranes. Slightly higher efficiencies and lower costs were associated with systems with integrated air separation units. The estimation of the overall capital costs was carried out using a bottom-up approach. Finally, the CO2 avoidance costs of individual technologies were calculated based on the techno-economic data.
    Fuel 05/2009; 88:2463-2472. · 3.36 Impact Factor
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    ABSTRACT: Power generation from biomass is a sustainable energy technology which can contribute to substantial reductions in greenhouse gas emissions, but with greater potential for environmental, economic and social impacts than most other renewable energy technologies. It is important therefore in assessing bioenergy systems to take account of not only technical, but also environmental, economic and social parameters on a common basis. This work addresses the challenge of analysing, quantifying and comparing these factors for bioenergy power generation systems. A life-cycle approach is used to analyse the technical, environmental, economic and social impacts of entire bioelectricity systems, with a number of life-cycle indicators as outputs to facilitate cross-comparison. The results show that similar greenhouse gas savings are achieved with the wide variety of technologies and scales studied, but land-use efficiency of greenhouse gas savings and specific airborne emissions varied substantially. Also, while specific investment costs and electricity costs vary substantially from one system to another the number of jobs created per unit of electricity delivered remains roughly constant. Recorded views of stakeholders illustrate that diverging priorities exist for different stakeholder groups and this will influence appropriate choice of bioenergy systems for different applications.
    Energy Policy. 01/2009;
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    ABSTRACT: As part of the sixth European framework project on enhanced capture of CO2 (ENCAP), several novel power generation cycles with CO2 pre-capture methods are identified and the promising technologies are selected for a techno-economic assessment. For this analysis, the chemical process simulation package ECLIPSE is utilised. Following a detailed mass and energy balance calculation, the economic assessments of the Semi-close Oxygen Combustion (SCOC), Water Cycle and Graz as well as S-Graz Cycles is performed in reference to year 2004. The total capital cost estimation of the studied cycles is implemented in a bottom-up approach. Subsequently, the breakeven electricity selling price (BESP) is determined according to the net present value. Through the modification of parameters such as fuel price or capacity factor, the sensitivity analysis is carried out to assess the effect of endogenous or exogenous changes on the economic viability of the cycles. Among the systems, the S-Graz Cycle is the most cost intensive process. Yet, due to its high plant efficiency, it delivers the lowest electricity price and the lowest CO2-avoidance costs. The Water Cycle is the least capital intensive technology in this study. Due to its poorer plant efficiency however, the economics of this cycle scored third on the list.
    Energy Procedia 01/2009; 1(1):565-572.
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    ABSTRACT: The attractiveness of fossil fuel as a feedstock for power generation depends on the development of energy conversion systems that are efficient, clean and economical. Coal fired power plants are generally considered to be “dirty” since they have high CO2 emissions, with the exception of those coal fired power plants that employ CO2 capture technology. Among the coal fired options, Integrated Gasification Combined Cycle (IGCC) systems have the best environmental performance and are potentially suitable candidates. The objective of this work is to provide an assessment and analysis of the potential for reduction of the output of greenhouse gas from the oxygen fed entrained flow gasifier systems, including the cost and cost-effectiveness of each likely conceptual scheme.The ECLIPSE process simulator was used successfully to perform technical, environmental and economic assessment studies for a wide range of IGCC power generation systems. Two IGCC power generation designs were selected, the Shell dry feed and GE (previously called Texaco) wet feed entrained flow gasifiers. As a reference fuel input, the American Federal coal was also used in IGCC systems. The performance of two IGCC systems was optimised within the constraint of being based on one particular advanced gas turbine and using a subcritical steam system.In this work, several IGCC plant attributes such as the fuel consumption, utility usages, plant performance as well as the specific CO2 generation and capture rates were simulated and weighed against each other. Factors affecting the IGCC plant performance, specifically net power output, process efficiency, power consumption coming from the Air Separation Unit (ASU) and CO2 removal and overall emissions were also evaluated and discussed. Finally, an economic evaluation of the system was conducted and the costs of CO2 capture plus transport are illustrated. This case study shows that the option of using IGCC for capturing CO2 could be technically feasible and cost-effective.
    Fuel Processing Technology. 01/2008;
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    ABSTRACT: Medium density fibreboard (MDF) processing in Northern Ireland generates about 40 tonnes of MDF dust per week, which gives significant disposal problems and costs. The overall aim of this project was to develop an environmentally friendly, energy efficient and economically acceptable means of generating “green” electricity from MDF dust.The project is based on using a down draught fixed bed gasifier with a modified diesel engine generator. Before MDF dust can be used in the gasifier it must first be briquetted. Although many equipment manufacturers claim to be able to briquette MDF dust, only two were able to prove this capability, PLC Products and Kahl. Trials were arranged and as a result a B10 Bio-Compactor was purchased and installed. However, good quality briquettes could not be produced reliably due in part to a lack of experience in operating the B10 Bio-Compactor and in part to mechanical failures. Changes were made to the B10 Bio-Compactor to improve its mechanical integrity and further trials will be performed to establish the conditions required to make MDF briquettes reliably.In order to provide MDF briquettes for the gasification trials it was decided to use MDF off-cuts sawn to the correct size. The project team was happy that these off-cuts possess very similar properties to the briquettes produced by the B10 Bio-Compactor and would therefore give very similar gasification behaviour. The gasification trials were very successful, with 8 hours continuous operation without problems. The calorific value of the fuel gas produced was 4.8 MJ/nm3, which is almost identical to that obtained from normal hardwood chip fuel. From the gasifier a mixture of diesel and MDF fuel gas was fed to the diesel engine generator. This is the normal practice for these types of engines in order to maintain smooth and efficient combustion. No problems were experienced when changing over from diesel to the fuel gas mixture
    Asia-Pacific Journal of Chemical Engineering 01/2008; 11:55-66. · 0.80 Impact Factor
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    ABSTRACT: The use of biomass, which is considered to produce no net CO2 emissions in its life cycle, can reduce the effective CO2 emissions of a coal-fired power generation system, when co-fired with the coal, but may also reduce system efficiency.The technical and environmental analysis of fluidised bed technologies, using the ECLIPSE suite of process simulation software, is the subject of this study. System efficiencies for generating electricity are evaluated and compared for the different technologies and system scales.Several technologies could be applied to the co-combustion of biomass or waste and coal. The assessment studies here examine the potential for co-combustion of (a) a 600 MWe pulverised fuel (PF) power plant (as a reference system), (i) co-firing coal with straw and sewage sludge and (ii) using straw derived fuel gas as return fuel; (b) a 350 MWe pressurised fluidised bed combustion (PFBC) system co-firing coal with sewage sludge; (c) 250 MWe and 125 MWe circulating fluidised bed combustion (CFBC) plants co-firing coal with straw and sewage sludge; (d) 25 MWe CFBC systems co-firing low and high sulphur content coal with straw, wood and woody matter pressed from olive stones (WPOS); (e) 12 MWe CFBC co-firing low and high sulphur content coal with straw or wood; and (f) 12 MWe bubbling fluidised bed combustion (BFBC), also co-firing low and high sulphur content coal with straw or wood.In the large systems the use of both straw and sewage sludge resulted in a small reduction in efficiency (compared with systems using only coal as fuel).In the small-scale systems the high moisture content of the wood chips chosen caused a significant efficiency reduction.Net CO2 emissions are reduced when biomass is used, and these are compared for the different types and scales of fluidised bed technologies. NOx emissions were affected by a number of factors, such as bed temperature, amount of sorbent used for SO2 capture and HCl emitted.
    Fuel. 09/2007;
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    ABSTRACT: This work focuses on the techno-economic assessment of bituminous coal fired sub- and super-critical pulverised fuel boilers from an oxyfuel based CO2 capture point of view. At the initial stage, two conventional power plants with a nominal power output of above 600MWe based on the above steam cycles are designed, simulated and optimised. Built upon these technologies, CO2 capture facilities are incorporated within the base plants resulting in a nominal power output of 500MWe. In this manner, some sensible heat generated in the air separation unit and the CO2 capture train can be redirected to the steam cycle resulting in a higher plant efficiency. The simulation results of conventional sub- and super-critical plants are compared with their CO2 capture counterparts to disclose the effect of sequestration on the overall system performance attributes. This systematic approach allows the investigation of the effects of the CO2 capture on both cycles. In the literature, super-critical plants are often considered for a CO2 capture option. These, however, are not based on a systematic evaluation of these technologies and concentrate mainly on one or two key features. In this work several techno-economic plant attributes such as the fuel consumptions, the utility usages, the plant performance parameters as well as the specific CO2 generation and capture rates are calculated and weighed against each other. Finally, an economic evaluation of the system is conducted along with sensitivity analyses in connection with some key features such as discounted cash flow rates, capital investments and plant efficiencies as well as fuel and operating costs.
    Fuel. 01/2007; 86(14):2134-2143.
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    ABSTRACT: Biomass is one of the renewable energy sources which is not intermittent, location-dependent or very difficult to store. If grown sustainably, biomass can be considered to be CO2 neutral.The use of biomass for power generation is also considered to be important in increasing the electricity output from renewable energy sources.However, power plants dedicated to the use of biomass fuel are not in widespread use and the acceptance of this fuel and development of the infrastructure for biomass production and transportation remain in their infancy. If small ratios of biomass can be co-fired with coal in large-scale conventional power plants, without significant technical, environmental or economic penalties, it could lead to a greater demand for biomass and so stimulate the industry.In this study a 80 MWth Circulating Fluidised Bed Combustion (CFBC) plant, fuelled by biomass only, and a large-scale 1000 MWth CFBC, co-fired with coal and 8% biomass, and the same large CFBC system, fired only with coal, are modelled using the ECLIPSE process simulation package and their technical, environmental and economic properties analysed and compared.The co-firing of biomass with coal was found to have little effect on the large-scale CFBC system, when a small ratio of biomass is used. The large scale system was found to have higher efficiency, lower CO2 emissions and lower breakeven electricity selling price than the small biomass-fuelled CFBC.Co-firing of biomass with coal could be a promising way of promoting the production, use and acceptance of biomass as a fuel in electricity generation.
    International Journal of Ambient Energy 01/2007; 28(3):143-150.
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    ABSTRACT: Nitrogen oxides (NOx) is one of the harmful emissions from power plants. Efforts are made to reduce NOx emissions by researchers and engineers all the times. NOx emissions are from three resources during the combustion: prompt NO, fuel NO and thermal NO. The last one – thermal NO, which is described by ‘Zeldovich-mechanism’, is the main source for NOx emissions. The thermal NO emission mainly results from the high combustion temperature in the combustion process. In order to control the NO formation, the control of peak combustion temperature is the key factor, as well as the oxygen concentration in the combustion areas. Flameless oxidation (FLOX) and continuous staged air combustion (COSTAIR) are two relatively new technologies to control the combustion temperature and the reaction rate and consequently to control the NOx emissions.In this study both FLOX and COSTAIR technologies are assessed based on a 12MWe, coal-fired, circulating fluidised bed combustion (CFBC) power plant by using ECLIPSE simulation software, together with a circulating fluidised bed gasification (CFBG) plus normal burner plant. Two different fuels – coal and biomass (straw) are used for the simulation. The technical results from the study show that the application of FLOX technology to the plant may reduce NOx emissions by 90% and the application of COSTAIR technology can reduce NOx emissions by 80–85% from the power plant. The emissions from the straw-fuelled plants are all lower than that of coal-fuelled ones although with less plant efficiencies.
    Fuel. 01/2007; 86(14):2101-2108.